The Electric Submersible Pumps (ESP) is an efficient artificial lift method for lifting liquids from wells. The topology of the typical ESP with a pump, protector, and a motor has been fixed for many decades. The protector plays a critical role in the ESP to ensure that the electrical motor can function in the downhole environment. However, the protector's failure-prone components limit the ESP's reliability. To take the reliability of the ESP to the next level, the best approach is to eliminate the protector and thus all the associated failure modes. The new topology of the protector-less technology for downhole rotary machinery is enabled by several magnetic technology building blocks. To eliminate the protector from an artificial lift device, the motor section is completely hermetically sealed from the downhole fluids by an isolation can. A set of magnetic couplings transmits torque from the motor to the hydraulic section via magnetic forces through the isolation can to replace the solid shaft between the motor and pump in the case of the ESP. When there is no solid shaft to transmit torque, thus no shaft seal required to prevent downhole fluids from leaking into the motor, there is no need for a protector. The thrust and radial loads from the hydraulic section are supported by magnetic bearings, which completely levitate the shafts and prevent any physical contacts between the rotating and stationary parts. The architecture and its associated magnetic building blocks of protector-less technology are engineered into the subsurface compressor to ensure its reliability at high speed. The subsurface compressor provides both suction effects to lower intake pressure near producing zones and boosting effects to increase discharge pressure downstream of the compressor. With the lower downhole pressures and higher wellhead pressures generated by the subsurface compressor in a gas well, the gas production and recoverable reserve will increase due to higher drawdown and lower abandonment pressures. In the meantime, more liquids will be carried uphole due to higher gas velocity in the wellbore, lower intake pressure, and higher discharge temperature. The gas production in the proof-of-concept field trials of a subsurface compressor increased by 12 to 58%. The implementations of the protector-less technology and its associated magnetic technology building blocks into the subsurface compressor are discussed in detail. The successful implementation of the protector-less technology into subsurface compressor demonstrates the ease of applying protector-less technology to the ESP. With the advantages of reliability and the ease of implementation to ESPs, protector-less technology provides a solution to ESPs when their applications require high reliability.

It is well known that liquid loading in unconventional gas wells can dramatically reduce production and lead to premature abandonment. Liquid loading creates a “vicious cycle” that occurs when liquid blockage creates backpressure in the wellbore or pore space in the formation, resulting in reduced gas velocity and leading to more liquid accumulation over time. Electrical submersible pumps (ESPs) and other artificial lift technologies are typically unable to remove liquids in both the vertical and horizontal sections of the well. A new downhole compressor solution, based on advanced magnetic technologies, was developed by Upwing Energy and recently completed its first field trials in an unconventional gas well operated by Riverside Petroleum. Analysis of results during the trial revealed a 62% increase in gas production and significant increase in liquid production over its steady­state performance using a rod pump prior to the subsurface compressor system (SCS) installation. Subsurface Compressor System The SCS is designed to provide reliable performance in the downhole environment by eliminating the common points of failure in conventional ESPs. It is based on proven magnetic technologies used in topside and subsea oil and gas applications (Fig. 1), which were deployed downhole successfully for the first time during the Riverside trial, including: A high­speed permanent magnet (PM) motor A shaftless magnetic coupling between the motor and compressor Passive noncontact magnetic bearings with electronic dampers A sensorless wide­frequency variable speed drive at the surface controls the motor at speeds up to 50,000 rpm via a long stepout. The hybrid axial wet­gas compressor is driven by the hermetically sealed high­speed PM motor. Torque is conveyed from the motor to the compressor with no mechanical shaft or seals, eliminating the need for a motor protector to isolate the motor from downhole fluids. This “protector­less” architecture eliminates a frequent source of vulnerability for conventional downhole artificial lift systems. The SCS lowers the bottomhole well pressure, increasing the velocity of the gas stream, removing liquids from the vertical and horizontal sections of the well, and preventing vapor condensation by increasing the temperature of the gas when exiting the compressor. Decreased backpressure from liquid loading results in increased gas production, which in turn accelerates liquid unloading. Once the liquid is carried by the gas stream, the lower pressure at the compressor intake and the higher temperature at the compressor discharge prevents vapor condensation and enhances the carryover of liquids to the surface by the gas stream.  Field Trial The SCS was deployed in an unconventional shale gas well owned by Riverside Petroleum in Indiana. The trial period started at the end of October 2019, and the SCS was removed in early December. The well has a 2,000-ft vertical wellbore and a 5,000-ft horizontal wellbore, where liquid had accumulated (Fig. 2). The compressor was installed at the bottom of the vertical section with a tail pipe extending approximately 1,000 ft into the horizontal section to provide sufficient velocity to carry liquids while minimizing friction losses. A shroud was used to be able to carry the extended length of the tail pipe.

Unconventional oil and gas development revolutionized the energy sector in North America and has been transforming the world's energy markets. Notwithstanding the enormous potential, unconventional resource development presents unique challenges to production and long-term hydrocarbon recoveries. As market dynamics are shifting, technologies are advancing, opening up new opportunities in areas once considered out of reach. This paper describes a new technology, a subsurface compressor system, which simultaneously removes liquids, increases gas production, and improves recoverable reserves in gas wells. The subsurface compressor can reverse the vicious cycle of liquid loading, which decreases gas production from a gas well and leads to premature abandonment, by creating a virtuous cycle of increased gas and condensate production. The complete process from well analysis, performance projection, deployment, commissioning to operation are discussed. A recently completed the world's very first field trial in an unconventional shale gas well supports the mechanism of subsurface gas compression and its impacts and benefits on unconventional gas production.

This development is the result of a DeepStar program to build and test a new radial passive magnetic bearing system (PMB) for downhole tools. While slated for the Magnetic Drive System (MDS) ESP, an advanced high-speed ESP that uses magnetic fields to increase performance, reliability and retrievability, this technology is applicable to conventional ESPs. The PMB supports the motor rotor across large clearances with no physical contact via magnetic fields in the ESP. An MDS ESP preliminary design was developed, from which the size and integration requirements of the PMB were defined. These requirements guided the analysis, design and testing of the full-scale components. Empirical analysis tools were used for initial iterations in size and performance of the PMB, followed by detailed magnetic finite element analysis (FEA) using commercial validated tools for the final performance prediction. With analytical validation of performance, detail designs were developed and hardware fabricated. Hardware testing was done to validate performance predictions and alignment with system requirements. The feasibility, preliminary design and analysis of the PMB were conducted in Phase 1 of the DeepStar Program and has continued with the full-scale design, build and test results of Phase 2. PMB performance results include load capability and deflection during static load events, all in relation to validating performance for use in the MDS system. This test data is used to validate the analysis approach used as well as to finalize the integration size of the PMB to meet the performance requirements of the MDS system. With the PMB large (>14mm) clearance between rotor and stator magnets, testing also includes variations in axial and radial position of the rotor in relation to the stator to account for installation variations in the MDS as well as use of sealing materials on both the rotor and stator. Integration is planned for use of the PMB in the MDS, so integration testing is planned to validate performance for each of these areas. This technology offers a radial bearing that can greatly enhance ESP performance and reliability. The PMB is a contact-less bearing system that does not require lubrication, can operate with large clearances to allow free fluid flow, is easily fully sealed from the environment, has virtually no bearing rotating losses, and has no operating life limits.

This effort designs, builds and tests key enabling technology components of the magnetic drive system (MDS) electric submersible pump (ESP) concept, an advanced high speed ESP that differs from conventional ESP topologies in using magnetic technologies to increase reliability and retrievability. The enabling components include a radial passive magnetic bearing (PMB) system, allowing for a contact-less bearing system and remote removal of rotating components, and magnetic vibration sensors (MVS), enabling prognostics for higher reliability. An MDS ESP preliminary design has been developed through a DeepStar program, from which the size and integration requirements of the PMB and MVS have been defined. These requirements guide the analysis, design and testing of the full-scale components. Empirical analysis tools are used for initial iterations in size and performance of the PMB and MVS, followed by detailed magnetic finite element analysis (FEA) using commercial validated tools for the final performance prediction. With analytical validation of performance, detail designs are developed and hardware fabricated. Hardware testing is done to validate performance predictions and alignment with system requirements. The PMB performance results include testing of stiffness capability. These characteristics are used to validate the integration requirements for load capability and deflection during static load events, all in relation to validating performance for use in the MDS system. This test data is used to validate the analysis approach used as well as to finalize the integration size of the PMB to meet the performance requirements of the MDS system. To identify rotor operating speed and rotor vibration magnitude and frequencies, the MVS is tested for sensing rotor motion rate and frequency, including sub-synchronous and super synchronous frequencies. Identifying data reduction needs, i.e. how data is compiled and presented to focus on specific areas of interest, is also critical to determine the vibration characteristic of specific events happening in the ESP, such as bearing wear or dynamic fluid changes. Testing also includes variations in tubing materials to assess performance impact. These technologies offer bearing and sensor technologies that enhance ESP reliability and active performance monitoring. The PMBs offer a contact-less bearing system that does not require lubrication, can operate with large clearances to allow free fluid flow, and has no operating life limits. The compact MVS offers rotor vibration diagnostics throughout the ESP, including between pump stages, for monitoring performance, detecting ESP mechanical issues or process fluid variations allowing immediately response to increase operational life.