Onshore
Production

Artificial Lift for Natural Gas

For many years, multiple methods have existed to artificially lift oil from reservoirs, including electric submersible pumps (ESPs), plunger lift, sucker rod pumps, gas lift systems, hydraulic pumping systems and progressive cavity pumps. However, until now, there were no artificial recovery methods for natural gas. Why is that?

Oil vs. Gas

Historically, significant investments were made to recover oil, and gas was simply a byproduct of those investments. However, a shift is underway in favor of natural gas, primarily due to its cleaner burn profile, its ability to meet 2025 emissions standards and its abundance in the United States and other energy producing countries. Natural gas is replacing coal in power plants globally. Technologies are being developed to convert natural gas to liquefied natural gas (LNG), and ports are being developed to handle and transport gas products around the world.

Market Shift Meets Technological Advancement

As market dynamics are shifting, technologies are advancing, opening up new opportunities in areas once considered out of reach, including the work done by our Parent Company, Calnetix Technologies. Prior to Upwing Energy’s formation, over three years have been spent on the development of an economical subsurface compressor system for the artificial lift of natural gas.

Previously, only about 60 percent of the natural gas from reservoirs could be recovered from conventional wells and only about 10 percent from unconventional wells. When the natural pressure of the gas below the earth diminished, there was no other option but to cap the well. Now, our Upwing Subsurface Compressor Systems (SCS) can be utilized to increase the rate of production from existing gas wells, and to deplete the natural gas reservoir down to unprecedented levels cost effectively.

Business Value

Increased Production

Upwing Subsurface Compressor Systems (SCS) increase gas production by decreasing bottom hole flowing pressure and causing higher reservoir drawdown. Effective drawdown can only be achieved by downhole compression near the perforations, where the gas is denser due to the higher downhole pressure. The effective drawdown increases the production rate significantly, which increases cash flow and net present value.

Gas well simulations with SCS installations have shown gas production increases ranging from 20% to 150%. In addition to better gas production, analysis shows that the SCS increases condensate production rates and improves condensate yield, particularly in horizontal liquid rich formations, which positively impacts well performance and value.

Increased Reserves

The subsurface compressor aids in the delivery of proven developed reserves and increases the size of undeveloped reserves. The increased reserves by the SCS are accomplished by arresting the production decline rate, postponing liquid loading, and providing lower abandonment pressure.

  • Stop production decline - The controlled drawdown by the SCS will stabilize the pressure oscillations, which facilitate the slowdown of production declines due to phenomenon like annular heading.
  • Postpone liquid loading - The increased gas velocity produced by the SCS can decrease the minimum critical rate required to lift liquids to the surface in the vertical portion of a gas well so the well produces longer.
  • Lower abandonment pressure - The increased gas velocity in the horizontal portion of the well can improve the effectiveness of liquid sweeping to prevent premature well abandonment caused by excess viscous losses.

In parametric studies conducted, the SCS increased recoverable reserves from 10 to 70%.

Delayed Abandonment

The SCS can delay the abandonment of gas wells by lowering the abandonment pressure. The delayed abandonment has a direct impact on recoverable reserves. The SCS will provide suction effects at the intake and boosting effects at the discharge.

  • Suction effects - The suction effects with the lower intake pressure will lower the downhole flowing pressure to facilitate the flow of more gas from the formation into the wellbore.
  • Boosting effects - The boosting effects with the higher discharge pressure from the SCS will increase the wellhead pressure to facilitate the flow of gas into the surface gathering system.

With both the suction effects and the boosting effects of the SCS at work, the gas well can still produce gas from the formation under the lowest possible downhole pressure or even vacuum, while forcing the produced gas uphole.

With the SCS, downhole pressure does not need to be higher than the wellhead pressure as long as the SCS discharge pressure is high enough to push gas upward. In this case, the effective abandonment pressure is dropped significantly by the SCS, thus delaying abandonment.

The SCS also can avoid the premature abandonment of gas wells by eliminating or postponing liquid loading, which interrupts gas production or makes it uneconomical to produce. The SCS can reverse a vicious cycle of liquid loading into a virtuous cycle of increased gas production.

  • Vicious Cycle - When the gas well is liquid loaded, the back pressure generated by the liquid blockage will reduce gas production. The reduced gas flow will reduce gas velocity, which in turn reduces liquid sweeping capability, and allows more liquid accumulation in the gas well or formation.
  • Virtuous Cycle - With the installation of the SCS, the gas velocity at both the intake and discharge of the SCS will increase. The increased gas velocity can sweep more liquid to reduce the back pressure caused by the liquid blockage. Once the liquids are removed, and the liquid loading is abated, the gas production will increase. The increased gas production will further increase the gas velocity to sweep more liquids, thus enacting the virtuous cycle of increased gas production.

The cycle reversal will extend the wells economic life and result in delayed well abandonment.

Technical Value

Increased Reliability

The Upwing Subsurface Compressor Systems (SCS) are engineered with a “protector-less” and “no-physical-contact” architecture, which offers extremely high reliability in the downhole environment.

It is well known that the motor protector of an electric submersible pump (ESP) is one of the major failure modes of downhole artificial lift devices. To eliminate the protector from the SCS, the motor section is completely hermetically isolated from the downhole fluids by a sealing can with conventional non-rotating seals and welds.

To transmit the torque from the motor to the hydraulics section, a magnetic coupling, which can transmit torque via magnetic forces, is placed on the motor and hydraulics shaft and acts through the sealing can, replacing the solid shaft between the motor and the pump, in the case of an ESP. When there is no direct connection from the motor to the pump or compressor and the motor can be completely isolated from the environment, there is no need to have rotary seals and dielectric oil to isolate the motor from downhole fluids, thus there is no need for a protector. The thrust and radial loads from the pump or compressor are supported by magnetic bearings, which completely levitate the bearing rotors and prevent any physical contact between the rotating and stationary parts.

Liquid Loading Abatement

Liquid loading in horizontal wells. Images source: Colorado School of Mines and the University of Tulsa.

The subsurface compressor can reverse the vicious cycle of liquid loading, which causes decreased gas production from gas wells prematurely into a virtuous cycle of increased gas production.

When the gas well is liquid loaded, the back pressure generated by the liquid blockage in the wellbore or pore space in the formation will reduce gas production. The reduced gas flow will reduce gas velocity, which in turn reduces liquid sweeping capability, and allows more liquid accumulation in the gas well or formation.

With the installation of the SCS, the gas velocity at both the intake and discharge of the subsurface compressor will increase. The increased gas velocity can carry more liquid out of the wellbore and reduce the back pressure on the formation caused by the liquid blockage. Once the liquids are removed and the liquid loading is abated, the gas production will increase. The increased gas production will further increase the gas velocity to carry more liquids, thus the virtuous cycle of increased gas production is enacted. Increased gas velocity will improve vertical and horizontal holdup profiles by altering flow behavior and fluid flow distribution, thus enhancing liquid lift efficiency in gas wells.

Besides the higher gas velocity, the temperature of the discharged gas from the SCS will increase due to the gas compression. The injected thermal energy into the gas stream will promote the evaporation of the liquids, which also increases liquid lifting and reduces liquid loading.

The increased gas velocity and increased temperature allows more gas and liquids to flow freely, which in turn further increases the ability of the gas to carry more liquids to the surface.

Abandonment Pressure Drop

The SCS will provide suction effects to lower intake pressure near producing zones and boosting effects to increase discharge pressure downstream of the SCS.

  • The suction effects with the lower intake pressure will lower the downhole flowing pressure and increase drawdown to flow more gas from the formation into the wellbore.
  • The boosting effects with the higher discharge pressure from the SCS will overcome the pressure losses along the pipe and increase the wellhead pressure to flow the gas into the surface gathering system.

With both the suction effects and the boosting effects of the SCS at work, the gas well can still produce gas from the formation under the lowest possible downhole pressure or even vacuum, while forcing the produced gas uphole.

  • Without the SCS, for the gas to flow from the formation to the wellhead, the formation pressure needs to be higher than the downhole pressure, which in turn needs to be higher than the wellhead pressure to push the gas upward.
  • With the SCS, the downhole pressure does not need to be higher than the wellhead pressure as long as the SCS discharge pressure is high enough to push gas upward.

In this case, the effective abandonment pressure when the gas cannot move from the formation to the wellhead is dropped significantly by the SCS. In addition, high velocity gas flowing in low pressure wells is very sensitive to viscous and kinetic pressure effects. A small drop in pressure can significantly decrease the velocity of the gas and the ability to lift liquids, therefore causing premature well abandonment.


Field Trials and Testing

Case Study: Subsurface Compressor System Increases Gas Production in Wells by as High as 58%

Concept Proven on Multiple Conventional Wells in Texas

Challenge

Increase gas production from wells with drawdowns created by a downhole compressor, which has never been done before.

Solution

Deploy the Upwing Subsurface Compressor System (SCS) experimental prototype in a total of four gas wells in Texas, USA to prove the application.

Results

The SCS proof-of-concept field trials demonstrated an increase of gas production ranging from 30 to 58%.

The compressor system helped to lower the wells’ bottom hole pressure and increased the direct drawdown on the reservoir completions, thus increasing the gas flow rate and significantly increasing the recovery rate.

Lessons learned from the proof-of-concept trials have served as the foundation for the design of the SCS commercial units.

Proof-of-Concept Experimental Prototype

The SCS proof-of-concept prototype is composed of two main sections: the compressor and motor sections. The compressor section is a multi-stage axial compressor. The motor section is a high-speed permanent magnet motor (PMM). The compressor rotor is connected via a mechanical coupling to and driven by the permanent magnet motor rotor. Both the motor rotor and compressor rotor are supported by traditional ball bearings. Ball bearings were used for fast prototyping, with the understanding that ball bearings might not last long in the downhole environment and might not be the final solution for either the motor or compressor section.

Proof-of-concept experimental prototype

Cross-section view of the proof-of-concept experimental prototype with identified components. (1) Compressor Top Bearing End-Plate, (2) Compressor Top Ball Bearing, (3) Compressor Bottom Ball Bearing, (4) Compressor Pre-Load Springs, (5) Motor Top End Bell, (6) Motor Stator, (7) Motor Pre-Load Springs, (8) Motor Bottom End Bell, (9) Motor Bottom End Plate

Deployment of the Prototype

The experimental prototype was deployed into the 7-inch casings by sucker rods for fast prototyping with the understanding that sucker rod deployment may not be the best approach for deployment. The power cables were strapped to the sucker rods.

SCS proof-of-concept trials sucker rod deployment

Proof-of-Concept Trial Results

At the intake of the SCS, downhole flowing pressure decreases, thus the gas production increases. Simulations demonstrate that the higher gas temperatures and higher kinetic energy of gas flow at the discharge side of the SCS could carry more liquid to surface to mitigate or remove completely the risk of liquid loading in gas wells.

The SCS proof-of-concept field trials demonstrated an increase of gas production ranging from 30 to 58%. The horizontal axis is time, and the vertical axis is thousand standard cubic feet per day (mscfd) for the first graph and gas flow rate percentage gain for the second graph.

Lessons Learned

After conducting the field trials, Upwing engineers identified opportunities to modify the SCS design for future commercial units.

  1. The ingress of downhole fluids damages the motor - A canned motor design and hermetically sealed, downhole rated electrical connections are required to withstand the harsh downhole environments.
  2. Conventional bearings do not work - This observation validates the need to use magnetic bearings to eliminate the physical contact between the rotors and stators that occurs with traditional contact bearings. Since there is no physical contact between the rotors and stators of magnetic bearings, there will be no failures caused by the introduction of foreign debris on the contact surfaces or efficiency loss due to friction.
  3. Poor rotor axial positioning - For the purposes of compressor reliability and performance, there is a need to use an active magnetic thrust bearing to ensure real-time closed loop controls of axial thrust loads and positions.
  4. Sucker rod deployment risky - Sucker rod deployment was deemed unreliable in terms of rod connections and electrical cable attachments. The SCS will be deployed with more reliable tubing hung geometry and alternative deployment methods will be evaluated for future use.

Commercial Unit Design

Based on the lessons learned from the proof-of-concept field trials, Upwing engineers have applied proprietary and proven technologies developed and used by parent company Calnetix Technologies in other industrial applications to the design of the commercial unit, which is set to launch in 2019. The commercial SCS unit will be composed mainly of three technology parts – a hydraulic unit, a bearing unit, and a motor unit, from top (uphole) to bottom (downhole). Click here for more information on the commercial unit – Upwing SCS 425.


Download Case Study

Conventional Formations

In a conventional gas well, the reservoir initially has enough energy to drive the gas to surface. As the well matures and the reservoir pressure depletes, it becomes more difficult for the gas to flow naturally. Our Upwing Subsurface Compressor Systems (SCS) increase gas production by decreasing bottom hole flowing pressure due to higher reservoir drawdown. This increases the production rate by up to 150%, which increases cash flow and net present value. This also improves hydrocarbon recovery significantly, extending the well life and providing a healthier balance sheet.

Advantages of the SCS for Conventional Wells

Production Gain

In conventional reservoirs, downhole compression increases gas production by increasing drawdown close to the perforations. Effective drawdown is accompanied by higher mass flow rate from the reservoir. Larger mass flow rates can only be achieved by downhole compression, where the gas is denser due to the downhole pressure. Furthermore, increasing suction pressure close to the perforation without the pipe friction loss associated with surface compression will result in even higher drawdown on the formation.

Another benefit of the SCS is the higher gas velocity due to suction. A small increase in pressure drop by suction will significantly change the velocity of the gas and the ability to lift liquids. At lower reservoir pressure and rates, a small diameter tubing is usually required for the efficient removal of produced liquids, however the higher friction loss associated with this tubing compromises its benefits. Upwing’s SCS produces gas at its maximum well flow potential by compressing the gas near the reservoir and without the increased frictional losses that result from the smaller tubing.

Liquid Loading/ Liquid Abatement

The SCS mitigates the issue of liquid loading in gas wells by increasing gas velocity at the compressor intake and by adding thermal energy to the streams at the compressor discharge. The improved liquid lift efficiency will increase the gas and condensate production rates on the surface. In the meantime, higher liquid sweeping also removes the liquid blockage of gas flows. The increased thermal energy of the compressed gas stream prevents water condensation and paraffin deposition, particularly in condensate rich formations. In gas wells with low reservoir pressure and without active aquifer presence, it is feasible to rely on the thermal energy from compression to deliquefy such wells.

Moreover, as the reservoir pressure is reduced as it matures, gas at lower pressures can hold significantly more water vapor. The net effect of producing wells at lower bottom hole pressures by the SCS could result in lower residual water saturation near the wellbore and eliminate any water invading and blocking the pores of the gas-producing formation rocks.

Recoverable Reserves

The Upwing Subsurface Compression System aids in the delivery of proven developed reserves and increases the size of undeveloped reserves by providing lower abandonment pressure that enhances hydrocarbon recovery significantly. In parametric studies conducted, the SCS increased recoverable reserves by 10 to 70%.

Unconventional Formations

In an unconventional gas well, the reservoir is hydraulically fractured and can be as far as 25,000 ft. from the wellhead. Gas production in unconventional wells declines much faster than that of conventional wells in the initial production years.

Our Upwing Subsurface Compressor Systems (SCS) are the only method of artificial lift that can increase gas, condensate, and natural gas liquids production from unconventional wells by dramatically increasing the drawdowns in the wellbore. The higher kinetic energy and fluid velocity at the intake of the compressor will eliminate liquid loading in the horizontal sections of a multi-stage fractured well. While the higher kinetic energy (pressure and velocity) and added thermal energy at the discharge of the compressor will avoid liquid loading and condensation in the vertical section of the well. The lowered downhole flowing pressure and efficient liquid unloading will enable operators to improve recoverable reserves, extend the life of gas wells, and fundamentally change the methodology of producing unconventional resources, significantly improving economics.

Coalbed Methane

Coalbed methane reservoirs are continuous unconventional hydrocarbon accumulations that contain gas entrapped by adsorption on organic macerals in coal seams. In some accumulations, a portion of the coalbed methane is stored as free gas in micropores and fractures or as solution gas in groundwater. Coalbed methane traps are regional in scale and contain giant, in place hydrocarbon volumes.

Coalbed methane reservoirs behave as dual porosity systems that have different gas storage and flow characteristics, partially dependent on varying geological parameters. Gas storage occurs by sorption, compression and solution, and mass transfer is driven by both concentration and pressure gradients. The critical desorption pressure is used to determine the amount of drawdown that is required before gas can be produced from the reservoir.

In coalbed methane reservoirs, downhole compression increases well flow potential by increasing drawdown close to the perforations like in conventional formations. However, to maximize coalbed methane production, the non-linear relationship between pressure and molar concentration of adsorbed gas must be realized. Because of that nonlinearity, any incremental pressure decrease will result in desorption of significantly more gas than is released directly from the open pore space. Since downhole compression creates suction close to the reservoir, Upwing’s Subsurface Compressor System is the only technology that provides the lowest bottom hole flowing pressure for a given tubing head pressure.

Moreover, production of natural gas from coalbed methane reservoirs, particularly at lower reservoir pressures, causes the rock matrix to shrink with reservoir depletion, thus increasing average reservoir permeability with time. As a result, any additional reduction in bottom hole flowing pressure will extend the distance to which the drawdown can be transmitted. With larger and farther drawdown, gas production will increase and stabilize, therefore enlarging the size of the proven undeveloped reserves.

Coalbed methane desorption behavior has a major impact on ultimate hydrocarbon recovery. Absorbed gas has much greater density than associated free gas, and the volume of gas stored on the surface area is much larger than accommodated in the open pore space. Coalbed methane recovery is, therefore, primarily the recovery of desorbing gas (i.e. lowering reservoir pressure reduces molecular bonds to organics and transfers adsorbed gas into the fracture system). Therefore, the highest gas recovery from coalbed methane reservoirs can only be realized by reducing reservoir pressure to the lowest possible level. Downhole compression with Upwing’s SCS facilitates the lowest reservoir abandonment pressure, thus maximizing recoverable reserves.

Shale Gas

Coming soon.

Deployment

Deployment

The Upwing Subsurface Compression System (SCS) is designed to be flexible for both standard tubing-hung geometry as well as alternative deployment methods.

SCS deployment by standard tubing-hung geometry and alternative deployment methods

Standard Tubing-hung Deployment

Like Electrical Submersible Pumps (ESPs), the SCS can be deployed by production tubing. The SCS assembly with the motor unit at the bottom, the bearing unit in the middle, and the compressor unit at the top is connected to the bottom of a production tubing. Sections of production tubing are threaded together end-to-end from the surface and hung at the wellhead, as indicated by the name “tubing-hung.” The power cable (represented by the red lines) from the motor unit is strapped to the production tubing by cable protectors and penetrates through the wellhead with pressure seals. The compressed gas will flow from the compressor through the production tubing to the surface.

Alternative Deployment

The SCS has also been designed with alternative deployment in mind. There are several alternative deployment schemes for an SCS or an ESP.

Coiled tubing with external power cable is very similar to the standard tubing-hung geometry, except that sections of the production tubing are replaced by a single and continuous coiled tubing. The gas will be produced through the coiled tubing.

Deployment by coiled tubing with an internal power cable will require the SCS to be inverted with the compressor unit at the bottom and the motor unit at the top. The power cable from the motor unit will be located inside the coiled tubing. The weight of the SCS will be supported by the coiled tubing at the wellhead. There will need to be a seal (e.g. packer) to isolate the annulus between the intake of the compressor and the casing to prevent the recirculation of compressed gas. The produced gas will be transported through the annulus to the surface.

Deployment can be done by two spools of cables. A shroud with a packer at the bottom will be used to guide the gas flow on the side of the SCS to the intake of the compressor. A mechanical cable will support the weight of the SCS and power cable from the wellhead. A power cable is strapped to the mechanical cable.

Single cable deployment is very similar to the deployment by coiled tubing with an internal power cable. The single cable will provide both the mechanical integrity and the electrical power from the surface. The deployed SCS also needs to be inverted.

The slick line deployment is composed of a permanent completion section and a retrievable string. The power cable is fixed on the outside of the liner, which is part of the permanent completion. There is an electrical wet-mate connection at the end of the power cable to connect with another wet-mate connection on the retrievable string. The retrievable string can be deployed by a slickline into the well at the predetermined position, where the two wet-mate connections mate up. The electrical power is feed from the surface through the power cable and wet-mate connections to the motor unit of the retrievable string.