Implementation of an extended NMPC controller integrated with nonlinear state estimators in an oil well pilot plant with electrical submersible pump installations

This paper presents an innovative solution to mitigate the risk of unintended lifting clamp selection in Electrical Submersible Pump (ESP) installations by implementing the Poka-Yoke methodology. The potential for accidents in oilfield operations can be grave, so proactive measures must be taken. Through a thorough case study investigating a dropped ESP seal, an integrated approach to safety and quality risk analysis led to the implementation of Poka-Yoke for continuous improvement to minimize risks and improve process reliability. The implementation of a Standard Operating Procedure (SOP) infused with the ingenious Poka-Yoke tool from Lean Manufacturing Methodology was initiated to curtail potential hazards in ESP installations. The following steps were taken: (1) Creation of a Multidisciplinary Team, including those who work directly in the process; (2) Route Cause Analysis and Hazard Assessment; (3) Brainstorming Sessions to fortify ideas and procedures for the detection and eradication of threats using the Poka-Yoke concept; (4) Implementation of a Pilot-Scale Solution; (5) follow-up meetings for Process Revision, (6) Improvement process lead by process revision, and (7) dissemination of knowledge to the entire company through workshops and pre-job meetings. The Poka-Yoke system employs a color code system that matches the lifting clamps with their corresponding ESP equipment. Furthermore, a custom colored-scale caliper was implemented to check the diameters of the equipment and their respective lifting clamps, ensuring that they are correctly matched. The use of visual signals instead of texts in this system greatly simplifies the information conveyed, making it more accessible and understandable to all stakeholders involved in the operation. The article introduces a Lean Manufacturing Methodology concept adapted for service delivery, emphasizing the reduction of operational risks. By utilizing the Poka-Yoke tool to detect and prevent errors, it is possible to enhance the reliability of a process. This is achieved by reducing the probability of errors resulting from human error or other factors, which in turn can minimize the occurrence of defects, rework, and other quality-related concerns that could compromise the process's reliability.

Electric Submersible Pumps (ESPs) is very popular artificial lift systems to boost oil production now days. Home ofmany ESP installations, with high frequency of change outs per year and with the harsh production environment, a development of ESP technologies to reduce change-out time and improve run life is keep ongoing. These technologies address business challenges timely in a proactive approach. Currently deployed ESPs require a time-consuming rig installation on jointed tubing. With several factors such as: an average run life of three years for ESPs, a rig-based change-out time of up to two weeks offshore, and an uncertainty of when a rig can be scheduled; the need for a more rapid rigless solution is critical for future operations. Majority of the ESP installation are completed as part of tubing completion and deployed by drilling rig which requires high spending to recover the well during ESP replacement. Several types of technologies to deploy ESP rig-lessly were introduced into industry to optimize the retrieval and deployment cost during ESP replacement. Limited success story was recorded and open more thought to overcome the challenges. The first worldwide new reliable cable rigless deployed electrical submersible pumping (ESP) system was successfully installed and put on production. What makes this system unique concept and the first worldwide of its kind are two main components. The first component is the innovative cable hanger design that insures total cable isolation while providing a non-restricted flow through the tubes that are built into the body of the spool. The second component is the specially designed and manufactured CT from selected material that has high resistance to H2S and CO2 and it was made exactly fit the ESP cable providing full protection from corrosive wellbore fluid. This design aimed to boost production of oil wells with lower ESPs installation and replacement cost. The new system eliminates the need for and expensive rig to replace the ESP and accelerate production restoration. This system will be a great addition especially for offshore environments where not only the rig intervention costs are expensive, but also limited rig availability can delay ESP replacement. This paper will share the concept, design, field implementation planning and technical challenges, lesson learnt during preparation and installation of this first of kind system.

Excessive gas production from high gas-oil-ratio (HGOR) wells imposes multiple challenges on the Electrical Submersible Pump (ESP) systems. The light gassy fluid can compromise both the ESP mechanical and electrical integrity through severe degradation due to operating in upthrust position and through the extreme motor overheating caused by the repetitive gas-locking events. This paper discusses procedures that result in significant improvements in ESP operation in HGOR environments. The procedures targeted the three main stages of ESP life cycle, namely: ESP design and planning phase, ESP installation and function test phase, and ESP operation phase. The developed procedures are applied for all new and current ESP installations and are continuously updated based on new results obtained through performance and data analysis. These procedures can have a major positive impact on the ESP mechanical and electrical health. Gas-locking related trips are some of the most challenging trips as they require extensive troubleshooting and analysis to prevent re-occurrence. They also require keeping the ESP and well shut-in for pressure build-up. All of this tremendously affects the field production strategy and hence the reduction of gas-locking trips through these procedures not only improves the ESP health but also ensures the field production is maintained. Through the aid of such procedures, the run-life of failed ESP can exhibit a significant increase. In addition, gas-locking related trips per well can be significantly reduced after successful implementation of these procedures. The reduction in ESP downtime is key in aiding companies achieve their production strategy. Implementation of the procedures that are discussed in this paper can be utilized for all HGOR fields where ESP installations are planned as the main artificial lift method to reduce gas-locking related trips and improve the run-life.

The tracking of the internal states of a battery such as the state-of-charge (SoC) is a substantive task in battery management systems. In general, batteries are represented as linear or non-linear mathematical models. The extended Kalman filter (EKF) and the unscented Kalman filter (UKF) are widely used for the non-linear battery state estimation but their efficiency is limited. Recently, more efficient non-linear state estimation methods such as the cubature Kalman filter (CKF) and the particle filters (PF) have been developed. In this paper, we compare the efficiency and the complexity of different non-linear battery internal state estimation methods based on the EKF, the UKF, the CKF, and the PF. In addition to the SoC, the transient response of the battery is also estimated. The experimental results show that the PF- and the CKF-based methods perform best. Under the chosen conditions, the PF-based method achieves the root mean square error of approximately 3% of the SoC. Although, the efficiency of the PF is slightly better than the CKF, it is computationally more complex.

Chapter 3 - ESP Components and their Operational Features

Chapter 3 - Electrical Submersible Pump Components and Their Operational Features

Chapter 6 - Analysis and Optimization

Inducers, which are classified as axial flow pumps with helical path blades, are used within rotary gas separators commonly used in electrical submersible pump installations. A two-phase flow model has been developed to study the inducer performance, focusing on head generation. The proposed model is based on a meridional flow solution technique and utilizes a two-fluid approach. The model indicates that head degradation due to gas presence is a function of flow pattern. The effect of flow pattern diminishes when the void fraction is greater than 15 percent since the centrifugal force dominates the interfacial drag force. In this case, the two-phase flow can be approximated as a homogeneous mixture. The model also suggests that a liquid displacement correction is needed when phase segregation occurs inside the inducer. The new model significantly improves the ability to predict separation efficiency of a rotary gas separator over existing models. Hydrocarbon-air and water-air experimental data were gathered to validate the new model.

ln the event wellhead integrity is lost, the uncontrolled flow of hydrocarbons could risk life, property and the environment. To prevent this risk subsurface safety valves can be used to control the well below the wellhead. Conventional surface controlled subsurface safety valves (SCSSV) are used to control the production tubing. However, often the annular space between the tubing and casing contains large quantities of gas directly below the wellhead. An annular control (AC) safety valve is a surface controlled subsurface safety valve which allows annular flow when open but provides a barrier below the wellhead when closed. When the AC safety valve is used with a conventional SCSSV it can provide overall well safety. The scope of this paper is to identify, review the design and summarize testing of the components that comprise an annular control safety system. INTRODUCTION Annular control safety systems have been used since the early 1970s. Initial applications utilized wireline retrievable valves packed off through shallow-set production packers. As tubing retrievable safety valve installations increased, tubing retrievable annular control (TRAC) safety valves were also developed. Similar to the wireline retrievable annular control safety valve, the TRAC valve packed-off through a shallow-set production packer. Typical applications included: gas lift, gas storage and electrical submersible pump installations. The majority of these installations involved small tubing sizes which did not present any significant design concerns such as casing deformation. However, after the Piper Alpha disaster, the philosophy of isolating all hydrocarbons, tubing and annular, from the surface was adopted. Consequently, this meant a broader application for annular control technology, Utilizing annular control in installations with large diameter tubing presented new concerns and the need for new design criteria. Annular control installations usually require a shallow setting depth. Because the casing is unsupported by cement at this location, maximizing the weight hanging capability of the hanger packer while minimizing the possibility of permanent casing deformation is the primary concern. Development of an annular control (AC) system that satisfies this concern has been accomplished by carefully evaluating operator needs and developing an effective design. The basic AC system, whether a single or dual completion, is designed around a shallow set packer which supports or hangs the tubing string. In a single (or concentric) completion, the TRAC safety valve is controlled from the surface hydraulically and allows the annulus to be isolated when closed. An annular control nipple is installed directly below the packer to provide a seal bore for the lower pack off on the TRAC safety valve to bypass the packer element. DESIGN CRITERIA A majority of annular control installations will be at shailow setting depths and will use the annulus as an injection path for gas lift operations. With this in mind, the following design parameters were used to develop the annular control safety system: Minimize casing deformation/stress Reduce the number of seals between tubing and annulus Maximize tubing and annular flow areas Design for failsafe operation Provide installation flexibility Utilize field proven technology.

The types of well that can benefit from downhole annulus safety systems (DBASS) are discussed. Platform gas lifted wells are treated in more detail because this technology is particularly appropriate to them. The DHASS completion equipment that was available when Elf Enterprise Caledonia Ltd.(formerly Occidental Petroleum Caledonia Ltd.) first investigated its use is presented. The drawbacks of this equipment and the developments that have taken place since then due to cooperation between users and suppliers are discussed in relation to their desired features. The types of equipment that have been selected by Elf Enterprise for its existing and new North Sea fields and some early operating history are discussed. Recommendations for additional work to further develop the systems are made.

This paper presents, for the first time, a theoretical model for the bottomhole gas separation efficiency in Electrical Submersible Pump Installations. The model is based only on fundamental physical principles. New experimental data, collected in a field scale apparatus, and covering a wide range of liquid flow rates, GLRs, pressures and rotational speeds, are also presented. Predictions of the model are verified against the experimental data and limited published field data. It was detected that, when rotary separators are used, two possible operating regions exist on a map of separation efficiency versus liquid flow rate and pressure. In one region the separator is quite effective and in the other the separator is not effective at all. The transition from the high efficiency zone to the low efficiency zone, in terms of liquid flow rate, is sharp. This behavior has never been reported in the literature before. The model is simple enough that a small subroutine can be easily written, from the equations presented in the paper, to be included in design and troubleshooting programs for ESP installations. Overall agreement of the model’s predictions with the experimental and field data was good in both high and low efficiency zones.

The oilfields in Colombia where Ecopetrol operates are mostly mature fields that, by presenting a decline in production, energy consumption and limitations in electrical infrastructure represent one of the most relevant aspects in lifting costs greater than 50% and the challenge in reducing the carbon footprint. For this reason, energy consumption, environmental impact and lifting costs are being analyzed in depth to achieve and increase efficiencies through the oil production process. In response to cost and carbon footprint reductions and efficiencies goals, as new global trend, since 2020, Ecopetrol has promoted the implementation of new technologies in significant points through the oil production process. It is the case of the Electric Submersible Pumps Systems (ESP) which produces the oil from the well to the surface, and their Permanent Magnet Motor (PMM) technology as an alternative and complement to reduce energy consumption of the current Artificial Lift Systems (ALS) installed. The Lutz methodology was applied, incorporating advanced techniques to simulate consumption per well groups by flow rates, the data from the ESP installations with PMM and IM motors were analysed and through lutz, flow rates and different data fittings and data regression. The application of the Lutz measurement methodology proves to be an effective tool for evaluating and optimizing the energy performance of permanent magnet motors in an oil field, especially in well clusters with varying flow rates. This methodology enables detailed monitoring of key parameters, such as system efficiency and energy consumption, facilitating the identification of opportunities for improving energy efficiency for the customer. On the other hand, a comparative analysis between IM and PMM ESP applications is presented to enhancing energy efficiency in oil wells through the implementation of Permanent Magnet Electrical Submersible Pump (ESP) systems in different regions and wells where the customer operates. The results show significant improvements in ESP equipment efficiencies and great energy savings compared to having IM instead of PMM. After 3 years of operation, significant data has been gathered, revealing stable equipment operation and fluid production meeting expectations. Some relevant ESP performance parameters achieved so far: the pump and motor work within recommended operating range with better system efficiency (+12%) and less power consumption compared with the correlations wells (-14%) and the kilowatts billed has been reduced by 14%. Moreover, by implementing adjustments based on the collected data, such as speed modulation and precise fluid production control, significant energy savings can be achieved and motor operation in the field optimized, thereby contributing to a more profitable and sustainable operation. Based on the analysis results, accurate recommendations could be given to the customer to improve the ESP systems in different fields and contribute to achieve efficiencies and reduce costs related to power consumption, resulting in important oil production process optimizations.

Optimizing the operating conditions for an ESP (Electrical Submersible Pump) does not need to be a complicated process. The Petroleum Engineers typically analyse the wells using the charts provided by the vendors, where the pump performance is expressed in terms of Head vs In-Situ Rate. However, field engineers and operators usually control the wells by adjusting choke opening - thus the THP (Tubing Head Pressure) - and Frequency. This logical gap can often cause delays and difficulties in performing a continuous optimization. The paper presents a tool to close that gap, based on automated workflows; it enabled the direct use of familiar variables so that all teams involved can interact smoothly. The tool generates clear visualizations, combining all the system constraints and operating limits, so that the engineers can visualize the Operating Envelope for each ESP well. This approach drastically decreased the time spent analysing the operability of the ESP and consequently improved the actions implementation speed. The primary benefit is the time saved by engineers, especially important for a giant oilfield where relatively few engineers oversee up to 100 wells each. Additionally, it helped junior and senior engineers alike to quickly identify problematic ESPs, elaborate remedial actions, and propose new optimized setpoints. The novelty of the tool is the ability to simplify an industry-standard process, offering a straightforward alternative. It can be adapted and scaled to any field with ESP installations, while it only requires simple programming skills.

Chapter 5 - Design of ESP Installations

Development of a non-linear state estimator for advanced control of an ORC test rig for geothermal application