A downhole-type device includes a fluid-end with a fluid rotor configured to move or be rotated by wellbore fluids. A fluid stator surrounds and supports the fluid rotor. A first bearing couples the fluid rotor to the fluid stator. A second bearing couples the fluid rotor to the fluid stator. An electric machine includes an electrical rotor rotably coupled to the fluid rotor. The electric rotor is configured to rotate in unison with the fluid rotor. An electrical stator surrounds and supports the electric rotor. A lubrication system is fluidically coupled to the downhole-type device. The lubrication system includes a topside pressure pump. A downhole-type distribution manifold is within a wellbore. The distribution manifold fluidically connects to the topside pressure pump, the first bearing, and the second bearing.

TECHNICAL FIELD

This disclosure relates to lubrication systems for downhole-type rotating machines, including downhole compressors, blowers, pumps, and generators.

BACKGROUND

Most wells behave characteristically different over time due to geophysical, physical, and chemical changes in the subterranean reservoir that feeds the well. For example, it is common for well production to decline. This decline in production can occur due to declining pressures in the reservoir, and can eventually reach a point where there is not enough pressure in the reservoir to economically realize production through the well to the surface. Downhole pumps and/or compressors can be deployed into the well to increase production. Additionally or alternatively, a top side compressor and/or pump are sometimes used to extend the life of the well by decreasing pressure at the top of the well.

SUMMARY

This disclosure relates to lubricating downhole type rotating machines.

An example implementation of the subject matter described within this disclosure is a well system with the following features. A downhole-type device includes a fluid-end with a fluid rotor configured to move or be rotated by wellbore fluids. A fluid stator surrounds and supports the fluid rotor. A first bearing couples the fluid rotor to the fluid stator. A second bearing couples the fluid rotor to the fluid stator. An electric machine includes an electrical rotor rotably coupled to the fluid rotor. The electric rotor is configured to rotate in unison with the fluid rotor. An electrical stator surrounds and supports the electric rotor. A lubrication system is fluidically coupled to the downhole-type device. The lubrication system includes a topside pressure pump. A downhole-type distribution manifold is within a wellbore. The distribution manifold fluidically connects to the topside pressure pump, the first bearing, and the second bearing.

Aspects of the example implementation, which can be combined with the example implementation alone or in combination, include the following. The first bearing includes a radial ball bearing.

Aspects of the example implementation, which can be combined with the example implementation alone or in combination, include the following. The second bearing includes a thrust bearing.

Aspects of the example implementation, which can be combined with the example implementation alone or in combination, include the following. The first bearing includes a radial bearing and a thrust bearing.

Aspects of the example implementation, which can be combined with the example implementation alone or in combination, include the following. The distribution manifold includes a first flow restriction between the topside pressure pump and the first bearing, and a second flow restriction, different from the first flow restriction, between the topside pressure pump and the second bearing.

Aspects of the example implementation, which can be combined with the example implementation alone or in combination, include the following. The first flow restriction or the second flow restriction include a restriction orifice.

Aspects of the example implementation, which can be combined with the example implementation alone or in combination, include the following. A controller is configured to measure a parameter of the downhole-type device, and, change a rate of lubrication to the first bearing or the second bearing in response to the measured parameter.

An example implementation of the subject matter described within this disclosure is a method of lubricating a downhole-type rotating machine with the following features. A rotor is rotated within a stator. The rotor is supported to the stator by a bearing. The rotor and the stator are positioned entirely within a wellbore. Lubrication is provided to a bearing at a specified rate from a topside facility.

Aspects of the example implementation, which can be combined with the example implementation alone or in combination, include the following. The bearing is a first bearing and the specified rate is a first specified rate. The method further includes providing lubrication to a second bearing at a second specified rate from a topside facility. The second specified rate is different from the first specified rate.

Aspects of the example implementation, which can be combined with the example implementation alone or in combination, include the following. Providing lubrication to a bearing at a specified rate includes flowing lubrication through a pre-sized flow restriction within a lubrication line.

Aspects of the example implementation, which can be combined with the example implementation alone or in combination, include the following. Providing lubrication to a bearing at a specified rate includes adjusting a flowrate from the topside facility.

Aspects of the example implementation, which can be combined with the example implementation alone or in combination, include the following. The specified rate is a first specified rate. The method further includes providing lubrication to the bearing at a second specified rate from a topside facility in response to a changed rotor load.

Aspects of the example implementation, which can be combined with the example implementation alone or in combination, include the following. The provided lubrication includes a well treatment chemical.

Aspects of the example implementation, which can be combined with the example implementation alone or in combination, include the following. The well treatment chemicals include a corrosion inhibitor, a defoamer, a paraffin inhibitor, a wetting agent, or a hydrate inhibitor.

An example implementation of the subject matter described within this disclosure is a lubrication system with the following features. A downhole-type distribution manifold is within a wellbore. The distribution manifold fluidically connects to a topside pressure pump, a first bearing within a downhole pump positioned within a wellbore, and a second bearing within the downhole pump positioned within a wellbore.

Aspects of the example implementation, which can be combined with the example implementation alone or in combination, include the following. The first bearing includes a thrust bearing.

Aspects of the example implementation, which can be combined with the example implementation alone or in combination, include the following. The second bearing includes a radial bearing.

Aspects of the example implementation, which can be combined with the example implementation alone or in combination, include the following. The distribution manifold includes a first flow restriction between the topside pressure pump and the first bearing, and a second flow restriction between the topside pressure pump and the second bearing.

Aspects of the example implementation, which can be combined with the example implementation alone or in combination, include the following. The first flow restriction or the second flow restriction include a restriction orifice.

Aspects of the example implementation, which can be combined with the example implementation alone or in combination, include the following. The first flow restriction and the second flow restriction are sized to provide different flow rates.

Aspects of the example implementation, which can be combined with the example implementation alone or in combination, include the following. The topside pressure pump includes a variable speed pump.

Other features, objects, and advantages of the subject matter will be apparent from the description and drawings, and from the claims.

DETAILED DESCRIPTION

This disclosure describes a control system of an artificial lift system that includes a downhole-type rotating machine, such as a compressor, blower, pump, or generator. Use of such artificial lift systems can increase production from wells. In some implementations, the bearing lubrication system of the artificial lift system are isolated from the production fluid via seal chambers or zones, typically flooded in the lubrication fluid and pressure compensated to the downhole environment to minimize leakage and contamination with the production fluid. While this approach offers use in low speed applications, higher speed applications suffer from the high windage losses from this flooded approach. The artificial lift systems described herein can be more reliable than comparable artificial lift systems with the elimination of a fixed lubrication reservoir located downhole that uses seals that wear and slowly leak, resulting in lower total capital costs over the life of a well. The artificial lift systems described herein also offer improved performance by being able to achieve higher operating speeds, all while using conventional lubricated bearing systems. The downhole-type rotating machine is provided lubrication by an adjustable topside pressure source that is renewed/refilled as needed, where lubrication used in the device is ultimately recovered in the production flow that comes to the surface. The modular characteristic of the artificial systems described herein allows for variability in design and customization to cater to a wide range of operating conditions and applications, including wells producing liquid, gas, and combinations of both.

FIG. 1depicts an example well system100constructed in accordance with the concepts herein. The well system100includes a well102having a wellbore104that extends from the terranean surface106through the earth108to one or more subterranean zones of interest110(one shown). The well system100enables access to the subterranean zones of interest110to allow recovery, i.e., production, of fluids to the terranean surface106and, in certain instances, additionally or alternatively allows fluids to be placed in the earth108. In certain instances, the subterranean zone of interest110is a formation within the Earth defining a reservoir, but in other instances, the subterranean zone of interest110can be multiple formations or a portion of a formation. For the sake of simplicity, the well102is shown as a vertical well with a vertical wellbore104, but in other instances, the well102could be a deviated well with the wellbore104deviated from vertical (e.g., horizontal or slanted) and/or the wellbore104could be one of the multiple bores of a multilateral well (i.e., a well having multiple lateral wells branching off another well or wells).

In certain instances, the well system100is a well that is used in producing hydrocarbon production fluid from the subterranean zones of interest110to the terranean surface106. The well may produce only dry gas, liquid hydrocarbons, and/or water. In certain instances, the production from the well102can be multiphase in any ratio. The well can produce mostly or entirely liquid at certain times and mostly or entirely gas at other times. For example, in certain types of wells, it is common to produce water for a period of time to gain access to the gas in the subterranean zone. The concepts herein, though, are not limited in applicability to gas wells or even production wells, and could be used in wells for producing liquid resources such as oil, water or other liquid resources, and/or could be used in injection wells, disposal wells, or other types of wells used in placing fluids into the Earth.

The wellbore104is typically, although not necessarily, cylindrical. All or a portion of the wellbore104is lined with a tubing, i.e., casing112. The casing112connects with a wellhead118at the terranean surface106and extends downhole into the wellbore104. The casing112operates to isolate the bore of the well102, defined in the cased portion of the well102by the inner bore116of the casing112, from the surrounding earth108. The casing112can be formed of a single continuous tubing or multiple lengths of tubing joined (e.g., threaded and/or otherwise) end-to-end. InFIG. 1, the casing112is perforated (i.e., having perforations114) in the subterranean zone of interest110to allow fluid communication between the subterranean zone of interest110and the inner bore116of the casing112. In other instances, the casing112is omitted or ceases in the region of the subterranean zone of interest110. This portion of the wellbore104without casing is often referred to as “open hole.”

The wellhead118defines an attachment point for other equipment of the well system100to be attached to the well102. For example,FIG. 1shows well102being produced with a Christmas tree120attached to the wellhead118. The Christmas tree120includes valves used to regulate flow into or out of the well102.

FIG. 1shows a surface compressor122residing on the terranean surface106and fluidly coupled to the well102through the Christmas tree120. The surface compressor122can include a variable speed or fixed speed compressor. The well system100also includes a downhole-type artificial lift system124residing in the wellbore104, for example, at a depth that is at or nearer to subterranean zone of interest110than the terranean surface106. The surface compressor122operates to draw down the pressure inside the well102at the terranean surface106to facilitate production of fluids to the terranean surface106and out of the well102. The downhole-type artificial lift system124, being of a type configured in size and robust construction for installation within a well102, assists by creating an additional pressure differential within the well102. In particular, casing112is commercially produced in a number of common sizes specified by the American Petroleum Institute (the “API”), including 4½, 5, 5½, 6, 6⅝, 7, 7⅝, 16/8, 9⅝, 10¾, 11¾, 13⅜, 16, 18⅝ and 20 inches, and the API specifies internal diameters for each casing size. The downhole-type artificial lift system124can be configured to fit in and, (as discussed in more detail below) in certain instances, seal to the inner diameter of one of the specified API casing sizes. Of course, the downhole-type artificial lift system124can be made to fit in and, in certain instances, seal to other sizes of casing or tubing or otherwise seal to the wall of the wellbore104.

Additionally, as a downhole-type artificial lift system124or any other downhole system configuration such as a pump, compressor, or multi-phase fluid flow aid that can be envisioned, the construction of its components is configured to withstand the impacts, scraping, and other physical challenges that the downhole-type artificial lift system124will encounter while being passed hundreds of feet/meters or even multiple miles/kilometers into and out of the wellbore104. For example, the downhole-type artificial lift system124can be disposed in the wellbore104at a depth of up to 15,000 feet (4,572 meters). Beyond just a rugged exterior, this encompasses having certain portions of any electronics be ruggedized to be shock resistant and remain fluid tight during such physical challenges and during operation. Additionally, the downhole-type artificial lift system124is configured to withstand and operate for extended periods of time (e.g., multiple weeks, months, or years) at the pressures and temperatures experienced in the wellbore104, temperatures which can exceed 400° F./205° C. and pressures over 2,000 pounds per square inch, and while submerged in the well fluids (gas, water, or oil as examples). Finally, as a downhole-type artificial lift system124, the downhole-type artificial lift system124can be configured to interface with one or more of the common deployment systems, such as jointed tubing (i.e., lengths of tubing joined end-to-end, threaded and/or otherwise), a sucker rod, coiled tubing (i.e., not-jointed tubing, but rather a continuous, unbroken and flexible tubing formed as a single piece of material), or wireline with an electrical conductor (i.e., a monofilament or multifilament wire rope with one or more electrical conductors, sometimes called e-line) and thus have a corresponding connector (e.g., coupling220discussed below, which can be a jointed tubing connector, coiled tubing connector, or wireline connector). InFIG. 1, the downhole-type artificial lift system124is shown deployed on wireline128.

A seal system126integrated or provided separately with a downhole system, as shown with the downhole-type artificial lift system124, divides the well102into an uphole zone130above the seal system126and a downhole zone132below the seal system126.FIG. 1shows the downhole-type artificial lift system124positioned in the open volume of the inner bore116of the casing112, and not within or a part of another string of tubing in the well102. The wall of the wellbore104includes the interior wall of the casing112in portions of the wellbore104having the casing112, and includes the open-hole wellbore wall in uncased portions of the wellbore104. Thus, the seal system126is configured to seal against the wall of the wellbore104, for example, against the interior wall of the casing112in the cased portions of the wellbore104or against the interior wall of the wellbore104in the uncased, open-hole portions of the wellbore104. In certain instances, the seal system126can form a gas and liquid tight seal at the pressure differential that the downhole-type artificial lift system124creates in the well102. In some instances, the seal system126of the downhole-type artificial lift system124seals against the interior wall of the casing112or the open-hole portion of the wellbore104. For example, the seal system126can be configured to at least partially seal against an interior wall of the wellbore104to separate (completely or substantially) a pressure in the wellbore104downhole of the seal system126of the downhole-type artificial lift system124from a pressure in the wellbore104uphole of the seal system126of the downhole-type artificial lift system124. AlthoughFIG. 1includes both the surface compressor122and the downhole-type artificial lift system124, in other instances, the surface compressor122can be omitted and the downhole-type artificial lift system124can provide the entire pressure boost in the well102. While illustrated with the seal system126, such a seal system can be eliminated in some instances. For example, when a packer and production tubing are used with the downhole-type artificial lift system124.

In some implementations, the downhole-type artificial lift system124can be implemented to alter characteristics of a wellbore by a mechanical intervention at the source. Alternatively or in addition to any of the other implementations described in this specification, the downhole-type artificial lift system124can be implemented as a high flow, low pressure rotary device for gas flow in sub-atmospheric wells. Alternatively or in addition to any of the other implementations described in this specification, the downhole-type artificial lift system124can be implemented as a high pressure, low flow rotary device for gas flow in sub-atmospheric wells. Alternatively or in addition to any of the other implementations described in this specification, the downhole-type artificial lift system124can be implemented in a direct well-casing deployment for production through the wellbore. While the downhole-type artificial lift system124is described in detail as an example implementation of the downhole system, alternative implementations of the downhole system as a pump, compressor, or multiphase combination of these can be utilized in the well bore to effect increased well production.

The downhole system, as shown as the downhole-type artificial lift system124, locally alters the pressure, temperature, and/or flow rate conditions of the fluid in the wellbore104proximate the downhole-type artificial lift system124(e.g., at the base of the wellbore104). In certain instances, the alteration performed by the downhole-type artificial lift system124can optimize or help in optimizing fluid flow through the wellbore104. As described above, the downhole-type artificial lift system124creates a pressure differential within the well102, for example, particularly within the wellbore104the downhole-type artificial lift system124resides in. In some instances, a pressure at the base of the wellbore104is a low pressure (e.g., sub-atmospheric or insufficient to overcome the static head and friction losses of the well), so unassisted fluid flow in the wellbore can be slow or stagnant. In these and other instances, the downhole-type artificial lift system124introduced to the wellbore104adjacent the perforations114can reduce the pressure in the wellbore104near the perforations114to induce greater fluid flow from the subterranean zone of interest110, increase a temperature of the fluid entering the downhole-type artificial lift system124to reduce condensation from limiting production, and increase a pressure in the wellbore104uphole of the downhole-type artificial lift system124to increase fluid flow to the terranean surface106.

The downhole system, as shown as the downhole-type artificial lift system124, moves the fluid at a first pressure downhole of the fluid module200to a second, higher pressure uphole of the downhole-type artificial lift system124. The downhole-type artificial lift system124can operate at and maintain a pressure ratio across the downhole-type artificial lift system124between the second, higher uphole pressure and the first, downhole pressure in the wellbore. The pressure ratio of the second pressure to the first pressure can also vary, for example, based on an operating speed of the downhole-type artificial lift system124, as described in more detail below. In some instances, the pressure ratio across the downhole-type artificial lift system124is less than 2:1, where a pressure of the fluid uphole of the downhole-type artificial lift system124(i.e., the second, higher pressure) is at or below twice the pressure of the fluid downhole of the downhole-type artificial lift system124(i.e., the first pressure). For example, the pressure ratio across the downhole-type artificial lift system124can be about 1.125:1, 1.5:1, 1.75:1, 2:1, or another pressure ratio between 1:1 and 2:1. In certain instances, the downhole-type artificial lift system124is configured to operate at a pressure ratio of greater than 2:1.

The downhole system, as shown as the downhole-type artificial lift system124, can operate in a variety of downhole conditions of the wellbore104. For example, the initial pressure within the wellbore104can vary based on the type of well, depth of the well102, production flow from the perforations into the wellbore104, and/or other factors. In some examples, the pressure in the wellbore104proximate a bottomhole location is sub-atmospheric, where the pressure in the wellbore104is at or below about 14.7 pounds per square inch absolute (psia), or about 101.3 kiloPascal (kPa). The downhole-type artificial lift system124can operate in sub-atmospheric wellbore pressures, for example, at wellbore pressure between 2 psia (13.8 kPa) and 14.7 psia (101.3 kPa). In some examples, the pressure in the wellbore104proximate a bottomhole location is much higher than atmospheric, where the pressure in the wellbore104is above about 14.7 pounds per square inch absolute (psia), or about 101.3 kiloPascal (kPa). The downhole-type artificial lift system124can operate in above atmospheric wellbore pressures, for example, at wellbore pressure between 14.7 psia (101.3 kPa) and 15,000 psia (103,421 kPa).

A controller150for a downhole system, shown as the downhole-type artificial lift system124, is in some implementations, located topside to maximize reliability and serviceability. Details about the controller150are described later within this disclosure. A controller150, in some implementations, receives signals from well instrumentation (pressure, flow, temperature), the topside motor VSD (speed, power, torque), the topside oil supply system (lubrication flow, pressure, temperature), and any sensor and/or sensor electronics within the downhole-type artificial lift system124, and uses this for input as part of its operation and control algorithm. This algorithm output includes a current command to regulate rotor speed and lubrication rates within the downhole-type artificial lift system124(details are explained in greater detail later within the disclosure). This loop typically happens very fast, on the order of 1,000-20,000 times a second depending on the system control requirements. This control system is also capable of determining the bearing lubrication requirements based on speed, power, fluid flow, and fluid pressures in the well. Analog circuit based controllers can also perform this function. Having this controller150topside allows for easy communication, service, and improved up-time for the system, as any issues can be resolved immediately via local or remote support. Downhole electronics are also an option either proximate to the device or at a location more thermally suitable. In a downhole implementation, the electronics are packaged to isolate them from direct contact with the downhole environment. Downhole electronics, in certain instances, offer better control since they do not suffer with long cable delay and response issues.

Lubrication is provided with a topside pressure source154. The topside pressure source can include a pump, a flow regulator, a pressure regulator, a pressurized vessel, valving, and any other equipment to provide lubrication to the artificial lift system124. The topside pressure source154is fluidically connected to the artificial lift system124by a main lubrication line152. In addition to standard lubrication, the topside pressure source can provide well treatment chemicals to the artificial lift system. Such chemicals can include corrosion inhibitors, defoamers, such as alkoxylated alcohol, paraffin inhibitors, such as xylene, toluene and benzene, wetting agents, such as certain soaps, and hydrate inhibitors, such as methanol or monoethylene glycol (MEG). For especially corrosive chemicals, different metallurgy could be utilized for bearing systems or coatings applied. These could include nickel and chromium based surface applications, as well as nickel based or super alloys. In addition, ceramic roller elements could be selected for use in more aggressive fluid. The bearing cage material would have to be selected with the chemical constituents in mind whether they be metallic or thermoplastic. More details on the lubrication system are described throughout this disclosure.

An example downhole system, shown as the downhole-type artificial lift system124, is depicted schematically inFIG. 1.FIG. 2Ais a half side cross-sectional view of the example downhole-type artificial lift system124. Referring toFIGS. 1-2C, the example downhole-type artificial lift system124includes a fluid module200and an electric machine204. In the context of this disclosure, an uphole end or direction is an end nearer or moving in a direction towards the terranean surface106. A downhole end or direction is an end nearer of moving in a direction away from the terranean surface106. An implementation of the fluid module200within the well is described and the description is applicable even if the fluid module200is positioned outside of the wellbore104. A coupling220is positioned at an uphole-end of the fluid module200. The coupling can be of a type used for a wireline connection, a tubing connection, or any other connection configured to support the weight of the downhole-type artificial lift system124. The coupling220, in certain instances, can include a standard attachment method to attach the downhole-type artificial lift system124to a support system. For example, a threaded interface can be used for sucker rod, or a set of bolts can be used to attach two flanges together for production tubing.

The fluid module200includes an inlet206to receive a fluid at the first pressure downhole of the fluid module200and an outlet208to output the fluid at the second, higher pressure uphole of the fluid module200. The inlet206can include a filter to limit particle sizes above a certain threshold from entering the downhole-type artificial lift system124. A cylindrical outer housing210houses an impeller in fluid communication with the inlet206to receive the fluid from the wellbore104at the first pressure downhole of the fluid module200and to drive the fluid to the outlet208at the second, higher pressure uphole of the fluid module200. The inlet206includes a series of holes evenly spaced around the circumference of the outer housing210and oriented in a downhole trajectory. The outlet208includes a series of holes evenly spaced around the circumference of the outer housing210and oriented in an uphole trajectory. With the downhole-type artificial lift system124residing in the wellbore104, the inlet206is at a downhole end of the fluid module200and the outlet208is at an uphole end of the fluid module200.

At a downhole end of the downhole-type artificial lift system124is a conical tip225. The conical tip225reduces the pressure drop across the downhole-type artificial lift system124. In some implementations, the conical tip225can house electronics that can be used in aspects of operation of the downhole-type artificial lift system124or for sensors.

In some instances, the downhole-type artificial lift system124can be positioned in the well with the downhole inlet206positioned adjacent to the perforations114in the wellbore104. For example, the fluid module200can be positioned in the wellbore104such that the inlet206is disposed next to and immediately uphole of the perforations114to maximize or improve the fluid flow from the perforations into the fluid module200. In some examples, the inlet206may not be adjacent to perforations114, such as the inlet206being positioned greater than about twenty feet away from the perforations114. In some instances, a speed of the fluid module200is adjusted based on the fluid flow from the subterranean zone into the wellbore104(e.g., via perforations114). For example, as the fluid flow from the subterranean zone into the wellbore104decreases, a speed of the fluid module200can increase to draw more fluid flow from the subterranean zone into the wellbore104.

As previously described, the downhole-type artificial lift system124moves the fluid from the downhole inlet206at the first pressure to the uphole outlet208at the second, higher pressure. This pressure differential promotes the fluid flow to move uphole of the downhole-type artificial lift system124, for example, at a higher flow rate compared to a flow rate in a wellbore without a downhole-type artificial lift system124. The fluid module200can operate at a variety of speeds, for example, where operating at higher speeds increases fluid flow, and operating at lower speeds reduces fluid flow. In some instances, the fluid rotor216aand/or the electric machine rotor216ccan operate at speeds between 600-3,600 revolutions per minute (rpm). In some instances, the fluid rotor216aand/or the electric machine rotor216ccan operate at speeds between 3,600-5,000 rpm. In some instances, the fluid rotor216aand/or the electric machine rotor216ccan operate at high-speeds, for example, 5,000-120,000 rpm. For the downhole-type artificial lift system124illustrated, the maximum operating speed is 60,000 rpm. Specific operating speeds for the downhole system are defined based on the fluid, pressures and flows for the well parameters and desired performance. Speeds may be as low as 5,000 rpm or as high as 120,000 rpm. Special design considerations are made to rotate at such speeds. For example, a high-speed machine (e.g., 5,000-120,000 rpm machine) can include higher strength materials for rotating components than a similarly sized low-speed machine (e.g., 600-3,600 rpm machine). Balancing requirements are more stringent for a high-speed machine as well. In general, a high-speed machine is arranged to reduce the radius of the spinning components. Such a task can be done by elongating the topology of the machine so that there is no need for component radial overlap. For example, a stator coil can be longitudinally separated from a coupling so that there is no radial overlap between the coupling and the stator coil. Such separation allows the stator coils and rotor to have a smaller diameter and tighter clearances as they do not have to surround a large coupling. In some implementations, the downhole-type artificial lift system124rotates the central shaft216, which includes the fluid rotor216aand the electric machine rotor216c, to rotate in unison. That is, the central shaft216rotates as a direct drive system. Having separate components of the central shaft that are coupled, but rotodynamically isolated (e.g. entirely isolated, substantially isolated, or reduce the transmission of rotodynamic forces) from one-another, allows the downhole-type artificial lift system124to rotate at high speeds while maintaining rotodynamic stability. This is because the first critical speed (first harmonic) of the individual component shafts is higher than a single shaft of equivalent total length to the smaller components. While the downhole system has an optimal speed range at which it is most efficient, this does not prevent the downhole system from running at less efficient speeds to achieve a specified flow for a particular well, as well characteristics change over time.

FIG. 2Afurther illustrates an example downhole-type artificial lift system124athat can be used as the downhole-type artificial lift system124previously described. An electric machine212and the fluid module200are coupled together on a central shaft216. The electric machine212is configured to rotatably drive or be driven to generate electricity by the fluid module200. That is, the electric machine212can be configured to act as a motor and/or generator. Throughout this description, electric machine, generator, and motor may be used interchangeably. The central shaft216is axially supported by a bearing assembly222located at a downhole end of the downhole-type artificial lift system124. As illustrated, the mechanical ball bearing222can support both the radial load at the bottom-end of the rotor216cand the thrust load of the motor rotor216c. There is no specific thrust bearing assembly shown, though such an implementation can be done without departing from this disclosure. In such an implementation, a pin bearing, fluid film bearing, hydrostatic bearing, or tilting pad bearing can be used. An example mechanical bearing222that can support both radial and axial loads is an angular contact ball bearing. One or more angular contact ball bearings can be used in series to reduce the specific axial and radial load that each bearing needs to support. Similarly in the fluid module200, where axial loads are not transmitted through the coupling224, connecting the motor and compressor rotors. The bearings in the fluid module200support the axial loads of the compressor module shaft in the same manner as the motor axial bearing. Also, the location of the one or more thrust bearing assemblies218can differ in different implementations of the downhole-type artificial lift system. The thrust bearing218can include any mechanical bearing, such as a tilted pad bearing, a pin bearing, ball bearing or an anti-friction bearing. The thrust bearing218is provided lubrication at a specified rate from a lubrication line252(shown as a passageway in fluid communication with line152). In some implementations, the lubrication line252supplying the thrust bearing218includes a flow restriction258to regulate the lubrication rate. In some implementations, the flow restrictions258can include passive components, such as a restriction orifice, a metering valve, or a piece of porous media. In some implementations, the flow restrictions258can include active components, such as active control valves. More details on the lubrication system are provided throughout this disclosure.

One or more radial bearing assemblies222(four shown) radially support the central shaft216. Fewer or more radial bearing assemblies222can be provided. Also, the location of the one or more radial bearing assemblies222can differ in different implementations of the downhole-type artificial lift system. The radial bearing assemblies222can include any mechanical bearing, such as a tilted pad bearing, a journal bearing, a pin bearing, ball bearing, or an anti-friction bearing. The radial bearing assembly is provided lubrication at a specified rate from a manifold lubrication line252(shown as a passageway in fluid communication with line152) that is separate from the manifold lubrication line252supplying the thrust bearing218. In some implementations, the lubrication line252to the radial bearing assemblies222includes a flow restriction258to regulate the lubrication rate, such as those described above. In certain instances, the flow restriction258is provided on both lubrication lines252, and in other instances, the flow restriction258is included on one or the other of the lubrication lines252. More details on the lubrication system are provided throughout this disclosure.

While one of each electric machine212and fluid module200modules are shown, more than one of each or all are practical in this configuration, thus allowing for additional motor power, additional thrust load support, and additional flow or pressure capacity to be added independently of each other to best produce the specific well performance. The bearing assemblies of such additional electric machines and fluid modules can include lubrication lines with or without flow restrictions. In addition, while the order of electric machine212and fluid module200module from downhole to uphole is shown, each module functions independently and can be placed in other orders that best suit the operation and integration of each module. Additionally, the fluid module200can be a compressor, a liquid pump, a multiphase pump, or a combination thereof that best suits the fluids and conditions of the well to maximize well performance. In some implementation, the fluid module200can be a turbine. In addition, passive magnetic radial bearing assemblies, passive magnetic thrust bearing assemblies, active magnetic radial bearing assemblies and active magnetic thrust bearing assemblies can be used to reduce bearing load on the thrust bearing218, and/or the radial bearings222. Passive magnetic thrust bearings can include permanent magnet passive thrust bearings and electro-magnet thrust bearing assemblies, where the latter can be powered via a local downhole generated constant or speed dependent current, or a topside generated constant or speed, motor drive power, fluid flow or other as an individual determinant or any combination of these as the determinant of current.

InFIG. 2A, the central shaft216comprises multiple sub-sections coupled together: a fluid rotor216aand an electric rotor216c. Each sub-section is joined together by a coupling224. The coupling224can be a bellows, quill, diaphragm, or other coupling type that provides axial stiffness and radial compliance. A bellows-style coupling includes a spring positioned between two shafts. The spring has a high radial torsional stiffness allowing for torque transmission, but a low lateral stiffness and a low lateral moment stiffness that allows for rotodynamic “play” between the shafts during operation. A bellows-style coupling can be attached to each shaft in a variety of ways, such as with a clamping hub located on either end of the bellows-style coupling. A quill-style coupling includes a shaft with a significantly greater length to diameter ratio than either shaft that is being coupled. The thinner cross-section allows for a high radial torsional stiffness and a high axial stiffness. The thinner cross-section also allows for a low lateral moment stiffness that allows for rotodynamic “play” between the shafts during operation. Dimensions and stiffnesses are specific for each application. In certain instances, the coupling224can allow for angular misalignment of 0.30-2.0 degrees, and a lateral misalignment of 0.01 inches. Variation in thermal growth can be designed to be accepted in the compressor and motor clearances, though the coupling can tolerate about 0.03 inches of axial misalignment. In some implementations, the central shaft216can include a single, unitary shaft that runs through the fluid module200, and the electric machine212.

Each of the radial bearing assemblies222can be protected from produced fluids by a seal256. The seal256can include a carbon ring seal, a labyrinth seal, or another type of seal. Each of the seals is configured to provide a leak path from the bearing to the produced fluid. Ingress by the production fluid can be prevented or reduced by a lubrication line252that provides lubrication to each of the radial bearing assemblies222. The lubrication line can provide lubrication at a positive rate, meaning that lubrication flows through the bearing assembly222, through the seal256, and into the production fluid. In other words, lubrication can be provided at a higher pressure than the production fluid in any given section of the artificial lift system124. Such pressure reduces the risk of ingress from the production fluid or particulates within the production fluid. Lubrication is provided to each of the individual lubrication lines252by a lubrication manifold254. In some implementations the lubrication manifold254can be inside the pump housing210. Alternatively or in addition, the lubrication manifold254can be outside the artificial lift system124and mounted to the outer housing210. In some implementations, the lubrication manifold254can separate from the outer housing210only connected at fluid injection points (lubrication lines252). The lubrication manifold254can be a rigid structure, coupled to the pump with flexible couplings. The lubrication manifold254can be integrated with the line152or be separate from the line152and coupled by a rigid or a flexible coupling. In some implementations, the lubrication manifold254can have a port for each line252or can gang lines252together. The lubrication manifold254fluidically connects the individual lubrication lines252to the main lubrication line152. The main lubrication line is provided lubrication from the topside pressure source154. Flow is regulated in each of the individual lines252by a flow restriction258within each line252. Each flow restriction can be sized for individual bearings, for example, sizing can be based on the type of bearing. A thrust bearing may require a different lubrication rate than a radial bearing. Alternatively or in addition, the style of bearing can have an effect on restriction sizing. For example, a ball bearing may require a different restriction size than a fluid film bearing. Other factors that can be taken into account in sizing the each flow restriction can include bearing size, rotational speed, radial or axial loads on the bearings, or location within the downhole-type lifting device124. For example, a bearing assembly222at a discharge end of the artificial lift system124may include a flow restriction258in the supply line252configured such that more pressure is supplied in comparison to a bearing assembly222positioned at an inlet206of the artificial lift system124due to pressure differences across the fluid end200.

Lubrication flow can be controlled to optimize bearing performance and operating life. A number of factors can be used to determine and optimize the level of lubrication flow, including the equipment, lubrication, installation specifics, downhole device and the operational characteristics of the downhole device. Lubrication characteristics can include lubricity and viscosity of the lubrication. Equipment can include the lubrication pump and its pressure, flow, and temperature rise. Installation specifics can include the depth of the device for lubrication deployment and pipe size, both used to determine the static pressure for the oil at the device as well as the flow rates achievable. The downhole pressure and temperature can also factor into the necessary fluid being pumped and its impact on the lubrication. In addition, if the lubrication is also intended to or includes cleaner for the device it must be factored into determining the level of flow needed. Device characteristics can include manifold distribution characteristics, local bearing orifices, piping within the device, operating speed, and radial and axial loads on the bearings.

Sensitive electronic and magnetic components can be “canned” or otherwise isolated from the downhole environment without affecting their electromagnetic characteristics. In some implementations, a magnetic coupling can be used to isolate certain modules from one another. For example, a magnetic coupling can be used between the electric machine module212the fluid module200. In such an implementation, the electric machine212is hermetically sealed from the environment of the wellbore104. In such an implementation, lubrication may not be provided from the lubrication manifold254to the isolated bearings.

FIG. 2Billustrates an example downhole-type artificial lift system124bthat can be used as the downhole-type artificial lift system124previously described. The downhole-type artificial lift system124bis substantially similar to the downhole-type artificial lift system124with the exception of any differences described herein. As illustrated, the downhole-type artificial lift system124bincludes a first fluid module200aand a second fluid module200b. Each fluid module is substantially similar to the fluid module200previously described with the exception of any differences described herein. The first fluid module200aand the second fluid module200bare rotably coupled together by a coupling224to rotate in unison with one another. The discharge of the second fluid module200bdischarges directly into the intake of the first fluid module200a. Both the first fluid module200aand the second fluid module200bare driven by the electric machine212. Each of the described modules can include mechanical bearings that are fluidically coupled to the lubrication manifold as previously described.

FIG. 2Cillustrates an example downhole-type artificial lift system124cthat can be used as the downhole-type artificial lift system124previously described. The downhole-type artificial lift system124cis substantially similar to the downhole-type artificial lift system124with the exception of any differences described herein. As illustrated, the downhole-type artificial lift system124bincludes a first fluid module200a, a second fluid module200b, and a third fluid module200c. Each fluid module is substantially similar to the fluid module200previously described with the exception of any differences described herein. The first fluid module200aand the second fluid module200bare rotably coupled together by a coupling224to rotate in unison with one another. The third fluid module200cand the second fluid module200bare rotably coupled together by a coupling224to rotate in unison with one another. The discharge of the second fluid module200bdischarges directly into the intake of the first fluid module200a. The discharge of the third fluid module200cdischarges directly into the intake of the second fluid module200b. The downhole-type electric machine is illustrated having both a first electric machine212aand a second electric machine212b. The first electric machine212aand a second electric machine212bare coupled together with a coupling224to rotate in unison with one another. The first fluid module200a, the second fluid module200b, the third fluid module200c, the first electric machine212a, and the second electric machine212bare rotably coupled to one-another to rotate in unison. Each of the described modules can include mechanical bearings that are fluidically coupled to the lubrication manifold as previously described.

While several implementations of example downhole-type artificial lifts systems124have been described, other implementations can be used without departing from this disclosure. For example, greater or fewer fluid modules can be used depending upon the gas production rate for a specific well. Similarly, greater or fewer electric machines can be combined depending upon power requirements.

As shown inFIG. 3, the controller150can include a one or more processors402and non-transitory memory404containing instructions to facilitate sending and receiving signals through an input/output (I/O) interface406. The controller can communicate with any aspect of the downhole-type artificial lift system124(FIG. 1), or topside components, for example, the topside pressure source154. In some implementations, the controller150can be entirely located at the surface outside the wellbore104. In some implementations, the controller150can be located within the wellbore104. In some implementations, the controller can be a distributed controller; for example, a portion of the controller150can be located within the wellbore104, while another portion of the controller150can be located at the surface outside the wellbore104. In some implementations, the controller150can be only or in part an analog circuit based control.

The present disclosure is also directed to a method of monitoring, controlling, and using the downhole-type artificial lift system124. To monitor and control downhole-type artificial lift system124, the controller150is used in conjunction with sensors (e.g., velocity sensors, transducers, thermocouples, flow sensors, fluid composition sensors) to measure parameters of the production fluid and the downhole-type artificial lift system124at various positions within the wellbore104and the downhole-type artificial lift system124. Input and output signals, including the data from the sensors, controlled and monitored by the controller150, can be logged continuously by the controller150and stored in a memory404coupled to the controller150. The input and output signals can be logged at any rate desirable by the operator of the downhole-type artificial lift system124. The controller150can also be used to operate and control any motors, bearings, valves, or flow control devices disclosed herein. Furthermore, the controller150can be used with the downhole-type artificial lift system124to operate the downhole-type artificial lift system124in any matter described herein. In some implementations, the controller150can be used to operate other devices, such as a topside pump, compressor, or separator in conjunction with the downhole-type artificial lift system124.

The memory404can store programming instructions for execution by the one or more processors402. For example, the processors can execute programming instructions to measure and/or monitor a parameter detected by various sensors. The controller150interprets the signal from sensors and directs the topside pressure source to provide lubrication to the bearings at a specified rate. In another example, the controller can take a measured parameter of the artificial lift system124, and change a rate of lubrication to the bearings in response to the measured parameter. Alternatively or in addition, the one or more processors can execute programming instructions to determine future well-flow characteristics based on a flow assurance model and control a speed of the rotor based on the future well-flow characteristics. Further details on this process are described later in this disclosure.

FIG. 4is a table500describing potential operating modes that can be used by the controller150to operate the downhole-type artificial lift system124. The table is divided into four sections or modes. For each mode, the system is in either an active or a reactive state. An active state for the system is where the system is not in a fully autonomous mode. For example, the system may maintain a pressure ratio or speed, but it will not alter set-points to compensate for outside environmental changes without external input to do so. An example outside environmental change can include a slugging event. A reactive state for the system is where the system will react to or compensate for outside environmental changes, for example, by adjusting a set-point. For example, during a slugging event, the system can change the motor speed and adjust lubrication rates to compensate for the change in load automatically and without external intervention. The environment is in a reactive state during steady state operation. For example, after start-up procedures have been conducted and the well is producing a steady flow without slugging. The environment is in an active state during non-steady state operation, for example, during start-up or during a slugging event. In general, “active” and “reactive” are indicative of a leading change and a following change, that is, an “active” component is an independent variable that changes, and the “reactive” component is a dependent variable that changes in response to the active component.

The first mode502occurs when the downhole-type artificial lift system acts in an active mode while the environment is in a reactive mode. This operation mode is often used to help characterize or test the well. During steady state operations, changing a set-point of the system, such as RPM or target pressure ratio, and measuring how the well reacts can result in useful information about the well. Such information can be used in a reservoir or well model. For example, one can both increase and decrease the flow rate on demand. Such a capability can provide more information of the reservoir. Example of this mode in operation are described later within this disclosure.

The second mode504occurs when the downhole-type artificial lift system acts in an active mode while the environment is in an active mode. This operation mode is often used to help characterize the well. During steady state operations, set-points of the system, such as RPM or target pressure ratio, are held at a steady state while the well operates in an unsteady state, such as start-up or a slugging event. By isolating one set of variables, namely the system operation, the characteristics of the well can be determined and predicted in the future. In the same operating mode, after the well has been characterized, a timed start-up procedure, with pre-set changes to RPMs, pressure ratios, and other variables, may be used to account for predictable non-steady state well behaviors. In general, an understanding of the reservoir (environment) is sufficient such that the compressor (system) can predict the change of the reservoir. For example, a compressor can predict and proactively shift its operating conditions “actively” so as to accommodating the predicted changes of the reservoir. Note that the reservoir is not reacting to the compressor, but changing by itself. Therefore both the compressor (system) and the reservoir (environment) are in the active mode. Example of this mode in operation are described later within this disclosure.

The third mode506occurs when the downhole-type artificial lift system acts in a reactive mode while the environment is also in a reactive mode. Such an operating mode can be used for diagnostic purposes. For example, actively changing the RPMs after an unexpected change in pressure ratio can be used to determine if a gas pocket is trapped in the fluid module200. Such an operation mode can be used to determine if parts of the compressor are degraded or damaged. For example, after constant attack by solids in the flow streams, the compressor blades may be eroded, and the performance characteristic of the compressor is not the same as before and the flow from the reservoir is lowered. When this happens, neither the compressor (controller) nor the environment is taking the lead to change, but both reactive to the change of damaged parts. Thus, the diagnostic capability of the compressor controller should identify the need of maintenance. Example of this mode in operation are described later within this disclosure.

The fourth mode508occurs when the downhole-type artificial lift system acts in a reactive mode while the environment is also in a reactive mode. Such an operating mode can be used to allow the downhole-type lift device124to react to changes in the outside environment, such as during a slugging event, with no operator intervention. For example, actively changing the RPMs and lubrication rates during a slugging event and returning to steady state operation after the slugging event has passed.

The following paragraphs describe specific scenarios that the control system150can experience and react to with no operator intervention. The following scenarios are only examples. The autonomous features described herein can be applied to a number of site-specific scenarios without operator intervention. The following scenarios should not be considered a complete list of the capabilities of the controller150or the downhole-type artificial lift system124.

FIG. 5is a flowchart of an example method600that can be used with aspects of this disclosure. At602, a rotor is rotated within a stator. The rotor is supported to the stator by a bearing. The rotor and the stator are positioned entirely within a wellbore. At604, lubrication is provided to a bearing at a specified rate from a topside facility.

In some implementations, as in any of the examples inFIGS. 2A-2C, more than one bearing can be used. In such an instance, the first bearing is provided lubrication at a first specified rate from a topside facility, and the second bearing is provided lubrication at a second specified rate from a topside facility. In some implementations and/or situations, the second specified rate can be different from the first specified rate. In some instances, the second specified rate can be the same as the first specified rate. As illustrated, a third bearing and a fourth bearing are provided. Each bearing is provided its own specified rate of lubrication from a topside facility. A topside pressure source154provides the lubrication to the first, second, third, and fourth bearings through the main lubrication line152, the manifold254, and the individual lubrication lines252to their individual bearings. The controller150determines the specified lubrication rates depending on current operation conditions. For example, the controller150can determine a specified lubrication rate, and set a discharge pressure of the topside pressure source to supply the specified rate. In some implementations, the controller150can regulate active downhole components to regulate flow to individual bearings. In some implementations, additional lubrication lines can be run to each line. In such implementations, the bearings receive lubrication in the event that one of the lines becomes plugged.

Lubrication rates to each bearing can be regulated in several ways, for example, lubrication can be provided through a pre-sized flow restriction within a lubrication line. Lubrication pressures required for each application are also dependent on the depth of the device, i.e. the static head pressure resulting from the column of oil in the line, the downhole pressure of the well, the size of the oil line, and the size of any flow orifices, distribution lines or other restrictions local in the device. In some implementations, a lubrication rate can be changed. In such implementations, the flowrate can be adjusted from the topside facility. For example, a regulating valve on the discharge of a pump can be adjusted to change the flow rate of lubrication. Other flow adjustment methods can be used, for example, changing a speed of a pressure pump, changing a stroke length of a pressure pump, changing a pressure within a lubrication reservoir, or any other method that can be used modulate a flowrate of a lubricant.

In some implementations, the lubrication rate can be changed in response to a change in a downhole operation parameter. For example, responsive to a changed rotor load or RPM, lubrication can be provided to the bearing at a different rate from a topside facility than initially provided. In such an example, during a slugging event, radial and thrust loads can increase on the bearings. In such a situation, the controller150can recognize a slugging event and increase a lubrication rate to all bearings. In some implementations, a lubrication rate can be increased to a specific bearing. For example, a lubrication rate can be increased for the thrust bearing alone. For example, under conditions where the thrust load is at or nearer its maximum level due to a high-pressure ratio across the device, high fluid pressure at the outlet of the device, high fluid flow rate thrust the device, or high inlet pressure in the device, higher oil can be used to lubricate and cool the bearing for high load conditions. Alternatively or in addition, additional lubrication can be provided to a single radial bearing. For example, increased unbalance levels in the compressor due to material buildup on the compressor blades can cause higher radial loads on the bearings. Increased oil to the compressor radial bearings can reduce bearing heating to increase the bearing life in such higher load conditions. Such changes responsive to a changed parameter can be carried out by the controller150.

Alternatively or in addition, the lubrication provided to the bearings can also be used to treat a producing well or an injection well. That is, the bearing lubricant can include a well treatment chemical. Well treatment chemicals can include corrosion inhibitors, defoamers, such as alkoxylated alcohol, paraffin inhibitors, such as xylene, toluene and benzene, wetting agents, such as certain soaps, and hydrate inhibitors, such as methanol or MEG. Such well treatment chemicals can be used consistently during operation, or as needed in response to changes in downhole operating parameters.

A number of implementations of the subject matter have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the subject matter. For example, aspects of this disclosure are applicable to downhole turbine generators as well. Accordingly, other implementations are within the scope of the following claims. Thus, particular implementations of the subject matter have been described. Other implementations are within the scope of the following claims. In some cases, the actions recited in the claims can be performed in a different order and still achieve desirable results. In addition, the processes depicted in the accompanying figures do not necessarily require the particular order shown, or sequential order, to achieve desirable results.