Switched Reluctance Motor for Electric Submersible Pump

Switched reluctance motors may be advantageous when used as the primary motor for an electric submersible pump system. They are less susceptible to jamming failures due to their high starting torque and ability to reverse direction. Driving these motors requires well-timed pulse waveforms and precise control of the motor based on its rotational position. In general, voltage-based sensing and control systems at the surface see highly unpredictable waveforms with excessive ringing behaviour due to the impedance characteristics of the long cabling between the surface controller and the downhole motor system. In this work, a system is detailed which monitors the current waveforms on the motor coil excitation conductors at the surface as a source of motor performance feedback and control. State-space modelling of the system shows stable current waveforms at the surface controller for both short and long interconnect cable systems. A laboratory demonstration of the surface controller, interconnect cabling, and motor system is shows excellent agreement with the current and voltage waveforms predicted by the state-space system model.

Switched Reluctance Motor for Electric Submersible Pump

Switched reluctance motors may be advantageous when used as the primary motor for an electric submersible pump system. They are less susceptible to jamming failures due to their high starting torque and ability to reverse direction. Driving these motors requires well-timed pulse waveforms and precise control of the motor based on its rotational position. It is demonstrated that the pulses required to drive switched reluctance motors can still be applied over along cable lengths. Additionally, the current at the surface can be used to monitor and control the operation of the motor downhole, even with long cable lengths separating the surface power source and downhole motor.

Autonomous Corrosion and Scale Management in Electric Submersible Pump Wells

Producers find a considerable amount of their operating expense (OPEX) comes from managing risks associated with corrosion and scale. Monitoring and chemical adjustment workflows are typically manual, and performed at low frequencies, leading to delays in event detection. As a result, the potential for negative events such as production shutdowns and well failures increase. This project's scope integrates chemistry domain experience with edge analytics, machine learning models, and intelligent equipment, to transform manual processes into an autonomous solution. The goal is to optimize operations, reduce well failures and workover costs, and maximize production. This solution is currently deployed in an oilfield, that has been historically challenged with a high number of electric submersible pump (ESP) failures due to corrosion and scale that resulted in significant production losses and unforeseen workover costs. The designed digital architecture supports autonomous management of scale and corrosion through remote monitoring and automated chemical injection. Real-time data is acquired from connected equipment, processed in an edge device running artificial intelligence, and autonomously sent to chemical pumps. Data from sensors, connected devices, and models are visualized in cloud applications, or integrated into existing client systems for end user analysis and full visibility of the entire process. The results show highly accurate models, precise chemical injection, and a reduction of well failures.

Submersible Pump with Line Shaft Pump in Shallow Water, Optimum Selection for Offshore Application in the Oil & Gas Industry

Seawater is an essential fluid used in various process circuits, such as cooling, reinjection into the wells and utilities, etc., in the offshore oil and gas industry. Vertical pumps facilitates with lifting seawater to the platform. This study investigates and compares two pump alternatives that has been widely used in oil and gas industry for seawater lift application: Vertical line-shaft pump and Electrical submersible pump. Existing seawater lift pump operating parameters are used as the basis of this study. The pump that is considered for the study has a flow rate of 3415 US GPM (776 m3/hr.) with a total head of 250 ft. The motor rating is 350 HP. The overall length of the pump is 21 meters. The main methodology used is a Life Cycle Cost Analysis (LCC) where the total cost of ownership of the vertical line-shaft pump and electrical submersible pump were analyzed for a period of 30 years. Furthermore, this research also addresses the operational drawbacks associated with both the pumps. Submersible pumps have higher initial capital investment cost when compared to line-shaft pump of similar capacity and size. The energy consumption cost of submersible pumps are higher mainly owing to lower efficiencies of the motors. The power factor for submersible pumps are lower in relation to line- shaft pumps. One of the main benefits of submersible pumps are their less installation and pump pullout time. Submersible pumps occupies lower space above ground when compared to line-shaft pumps. Additionally, submersible pumps are less noisy and have lower vibration in comparison to line-shaft pumps. This paper aims to provide key information and knowledge for engineers to make prudent decision regarding selection of the most cost effective pump for the seawater lift application with a tangible added cost value to both Capital Expenditures (CAPEX) and Operational Expenditure (OPEX).

First Retrieval and Redeployment of a Novel Rigless Electrical Submersible Pump System Via Coiled Tubing in Kuwait: A Story of Success

With the continuous production from Kuwait oil reservoirs, a clear decline in reservoir pressure is observed. Subsequently, the demand for artificial lift is increasing to sustain production. Maintenance of those wells requires frequent interventions and continuous presence of workover rigs, which affects overall cost of production. Change of the electrical submersible pump (ESP) deployment method represents one of the cost reduction initiatives undertaken by the operator to reduce well intervention time and improve asset utilization. To minimize deferred production generated by the ESP replacement operation, a novel rigless approach leveraging coiled tubing (CT) was introduced in southeast and west Kuwait. It reduces operating costs and eliminates disruptions to operations by enabling rigless retrieval and redeployment of a standard ESP assembly. To evaluate the efficiency of using CT as rigless ESP retrieval and conveyance method, two candidate wells were selected to recover and redeploy a 108-ft-long ESP system. The intervention methodology relied on CT equipped with optical line and real-time downhole telemetry, a high-pressure rotary jetting tool, and a specific ESP deployment assembly. The retrieval and redeployment of the ESP was executed in a single rigless intervention, averaging less than 72 hours of operational time per well. This represents five times improvement over the standard practice using a workover rig. The intervention was executed in several stages, according to the well intervention program, and included tubing drift and cleanout runs, retrieval, inspection, and redress of the ESP assembly, followed by its successful redeployment. The high-pressure rotary jetting tool was used to condition the wellbore tubulars across the fishing area, while downhole real-time data enabled by the 1 3/4-in. CT equipped with optical telemetry were instrumental to eliminate uncertainties associated with changing downhole conditions. The casing collar locator allowed live depth control and ensured accurate positioning of the ESP. Its careful retrieval and redeployment were monitored thanks to the downhole axial force readings, which allowed controlling the weight applied on the fishing assembly. Internal and external downhole pressure data, along with downhole temperature, helped in controlling actuation and use of the high-pressure rotary jetting nozzle under nominal conditions for maximum efficiency. This enhanced rigless ESP replacement technique, made possible by the joint use of CT and real-time downhole measurements, was confirmed as a robust workover method for retrieval and redeployment of rigless ESPs in southeast and west Kuwait. The experience gained in the first two wells brings a new level of confidence to Kuwait operators about this technique, which certainly can be expanded to other fields in the Middle East and elsewhere.