Patent Application
20170145811
This disclosure relates generally to equipment utilized and operations performed in conjunction with a subterranean well and, in one example described below, more particularly provides a well pumping system and associated method.
Reservoir fluids can sometimes flow to the earth's surface when a well has been completed. However, with some wells, reservoir pressure may be insufficient (at the time of well completion or thereafter) to lift the fluids (in particular, liquids) to the surface. In those circumstances, technology known as “artificial lift” can be employed to bring the fluids to or near the surface (such as a subsea production facility or pipeline, a floating rig, etc.).
Various types of artificial lift technology are known to those skilled in the art. In one type of artificial lift, a downhole pump is operated by reciprocating a string of “sucker” rods deployed in a well. An apparatus (such as, a walking beam-type pump jack or a hydraulic actuator) located at the surface can be used to reciprocate the rod string.
Therefore, it will be readily appreciated that improvements are continually needed in the arts of constructing and operating artificial lift systems. Such improvements may be useful for lifting oil, water, gas condensate or other liquids from wells, may be useful with various types of wells (such as, gas production wells, oil production wells, water or steam flooded oil wells, geothermal wells, etc.), and may be useful for any other application where reciprocating motion is desired. Improvements are also continually needed in the art of reservoir analysis.
Representatively illustrated in
In the
The rod string 18 may be made up of individual sucker rods connected to each other, although other types of rods or tubes may be used, the rod string 18 may be continuous or segmented, a material of the rod string 18 may comprise steel, composites or other materials, and elements other than rods may be included in the string. Thus, the scope of this disclosure is not limited to use of any particular type of rod string, or to use of a rod string at all. It is only necessary for purposes of this disclosure to communicate reciprocating motion of the actuator 14 to the downhole pump 20, and it is therefore within the scope of this disclosure to use any structure capable of such transmission.
The downhole pump 20 is depicted in
The wellbore 28 is depicted in
In the
As depicted in
In the
The stuffing box 44 includes an annular seal (not visible in
The power source 12 may be connected directly to the actuator 14, or it may be positioned remotely from the actuator 14 and connected with, for example, suitable electrical cables, mechanical linkages, hydraulic hoses or pipes. Operation of the power source 12 is controlled by a control system 46.
The control system 46 may allow for manual or automatic operation of the actuator 14 via the power source 12, based on operator inputs and measurements taken by various sensors. The control system 46 may be separate from, or incorporated into, the actuator 14 or the power source 12. In one example, at least part of the control system 46 could be remotely located or web-based, with two-way communication between the actuator 14, the power source 12 and the control system 46 being via, for example, satellite, wireless or wired transmission.
The control system 46 can include various components, such as a programmable controller, input devices (e.g., a keyboard, a touchpad, a data port, etc.), output devices (e.g., a monitor, a printer, a recorder, a data port, indicator lights, alert or alarm devices, etc.), a processor, software (e.g., an automation program, customized programs or routines, etc.) or any other components suitable for use in controlling operation of the actuator 14 and the power source 12. The scope of this disclosure is not limited to any particular type or configuration of a control system.
In operation of the well pumping system 10 of
It can be advantageous to control a reciprocation speed of the rod string 18, instead of reciprocating the rod string as fast as possible. For example, a fluid interface 48 in the wellbore 28 can be affected by the flow rate of the fluid 26 from the well. The fluid interface 48 could be an interface between oil and water, gas and water, gas and gas condensate, gas and oil, steam and water, or any other fluids or combination of fluids.
If the flow rate is too great, the fluid interface 48 may descend in the wellbore 28, so that eventually the pump 20 will no longer be able to pump the fluid 26 (a condition known to those skilled in the art as “pump-off”). On the other hand, it is typically desirable for the flow rate of the fluid 26 to be at a maximum level that does not result in pump-off. In addition, a desired flow rate of the fluid 26 may change over time (for example, due to depletion of a reservoir, changed offset well conditions, water or steam flooding characteristics, etc.).
A “gas-locked” downhole pump 20 can result from a pump-off condition, whereby gas is received into the downhole pump 20. The gas is alternately expanded and compressed in the downhole pump 20 as the traveling valve 24 reciprocates, but the fluid 26 cannot flow into the downhole pump 20, due to the gas therein.
In the
As mentioned above, the power source 12 is used to variably supply energy to the actuator 14, so that the rod string 18 is displaced alternately to its upper and lower stroke extents. These extents do not necessarily correspond to maximum possible upper and lower displacement limits of the rod string 18 or the pump 20.
For example, it is typically undesirable for a valve rod bushing 25 above the traveling valve 24 to impact a valve rod guide 23 above the standing valve 22 when the rod string 18 displaces downward (a condition known to those skilled in the art as “pump-pound”). Thus, it is preferred that the rod string 18 be displaced downward only until the valve rod bushing 25 is near its maximum possible lower displacement limit, so that it does not impact the valve rod guide 23.
On the other hand, the longer the stroke distance (without impact), the greater the productivity and efficiency of the pumping operation (within practical limits), and the greater the compression of fluid between the standing and traveling valves 22, 24 (e.g., to avoid gas-lock). In addition, a desired stroke of the rod string 18 may change over time (for example, due to gradual lengthening of the rod string 18 as a result of lowering of a liquid level (such as at fluid interface 48) in the well, etc.).
In the
In the
An output of the continuous position sensor 52 can be useful to achieve a variety of objectives, such as, controlling stroke distance, speed and extents to maximize production and efficiency, minimize electrical power consumption and/or peak electrical loading, maximize useful life of the rod string 18, etc. However, the scope of this disclosure is not limited to pursuing or achieving any particular objective or combination of objectives via use of a continuous position sensor.
As used herein, the term “continuous” is used to refer to a substantially uninterrupted sensing of position by the sensor 52. For example, when used to continuously detect a position of a piston of the actuator 14 (see
Using the continuous position sensor 52, the control system 46 can be provided with an accurate measurement of a reciprocating member position at any point in the member's reciprocation, thereby dispensing with any need to perform calculations based on discrete detections of position. It will be appreciated by those skilled in the art that actual continuous position detection can be more precise than such calculations of position, since various factors (including known and unknown factors, such as, temperature, fluid compressibility, fluid leakage, etc.) can affect the calculations.
By continuously sensing the position of a reciprocating member at or near a top of the rod string 18, characteristics of the rod string's reciprocating displacement are communicated to the control system 46 at each point in the rod string's reciprocating displacement. The control system 46 can, thus, determine whether the rod string's 18 position, speed and acceleration correspond to desired preselected values.
If there is a discrepancy between the desired preselected values and the rod string's reciprocating displacement as detected by the sensor 52, the control system 46 can change how energy is supplied to the actuator 14 by the power source 12, so that the reciprocating displacement will conform to the desired preselected values. For example, the control system 46 may change a level, timing, frequency, duration, etc., of the energy input to the actuator 14, in order to change the rod string's upper or lower stroke extent, or velocity or acceleration at any point in the rod string's reciprocating displacement.
Note that the desired preselected values may change over time. As mentioned above, it may be desirable to change the upper or lower stroke extent, or the pumping rate, during the pumping operation, for example, due to the level of the fluid interface 48 changing, reservoir depletion over time, detection of a pump-off, pump-pound or gas-lock condition, etc.
Although the continuous position sensor 52 provides certain benefits in the system 10 and method example of
Referring additionally now to
In the
The power source 12 in this example comprises a hydraulic pressure source (such as, a hydraulic pump and associated equipment) for supplying energy in the form of fluid pressure to a chamber 58 in the housing 56 below the piston 54. To raise the piston 54, the piston rod 64 and the rod string 18, hydraulic fluid at increased pressure is supplied to the chamber 58 from the power source 12. To cause the piston 54, piston rod 64 and rod string 18 to descend, the pressure in the chamber 58 is reduced (with hydraulic fluid being returned from the chamber to the power source 12).
In this example, the sensor 52 is attached externally to the housing 56. In other examples, the sensor 52 could be positioned internal to (or in a wall of) the housing 56, or the sensor 52 could be associated with the stuffing box 44 to continuously detect a position of the piston rod 64 as it reciprocates. Thus, the scope of this disclosure is not limited to any particular position or orientation of the sensor 52.
A magnet 60 is attached to, and displaces with, the piston 54. A position of the magnet 60 (and, thus, of the piston 54) is continuously sensed by the sensor 52 during reciprocating displacement of the piston. A suitable magnet for use in the actuator 14 is a neodymium magnet (such as, a neodymium-iron-boron magnet) in ring form. However, other types and shapes of magnets may be used in keeping with the principles of this disclosure.
In other examples, the magnet 60 could be attached to, and displace with the piston rod 64 or another reciprocating component of the actuator 14. The scope of this disclosure is not limited to any particular position of the magnet 60, or detection of the position of any particular component of the actuator 14.
A suitable linear position sensor (or linear variable displacement transducer) for use as the sensor 52 in the system 10 is available from Rota Engineering Ltd. of Manchester, United Kingdom. Other suitable position sensors are available from Hans Turck GmbH & Co. KG of Germany, and from Balluff GmbH of Germany. However, the scope of this disclosure is not limited to use of any particular sensor with the system 10.
Referring additionally now to
In the reservoir analysis system 70 and method of
The formation 36 comprises a reservoir for the fluid 26, which is produced from the wellbore 28 as described above. In other examples, the formation 36 could comprise another type of reservoir (such as, for a geothermal well or a disposal well, etc.).
In other examples, the wellbore 72 may not penetrate the same earth formation 36 as the wellbore 28. The wellbores 28, 72 could be drilled to different depths, or in different directions. Although both wellbores 28, 72 are depicted in
Similar to the wellbore 28, the wellbore 72 is illustrated in
As depicted in
Instead of separate sensors 78, the line 80 itself may serve as a distributed sensor. For example, the line 80 could include an optical fiber or other optical waveguide, and techniques known to those skilled in the art as “distributed vibration sensing” and/or “distributed acoustic sensing” may be used. Thus, the scope of this disclosure is not limited to any particular number, type or configuration of sensor(s).
In the
The sensors 78 may communicate measurements taken in real time (e.g., as an operation progresses), or the sensors may record measurements for later download. In either case, the measurements may be received onsite, and/or the measurements may be transmitted to a remote location, such as, via a satellite communications transmitter 82 or other communications equipment.
As depicted in
In the
As depicted in
It may now be fully appreciated that the above disclosure provides significant advancements to the arts of performing reservoir analysis, and monitoring and controlling operation of a well pumping system. In examples described above, the well pumping system 10 can be operated in a manner that transmits the signal 84 from the downhole pump 20 to the sensors 78, so that characteristics of a reservoir between the wellbores 28, 72 can be determined.
The above disclosure provides to the art a reservoir analysis method. In one example, the method can comprise: transmitting a signal 84 from a downhole pump 20 in a first wellbore 28; receiving the signal 84 at a second wellbore 72; and determining a reservoir characteristic from the received signal 84. Note that the signal 84 is not necessarily received in the second wellbore 72, since the sensors 78 may not be in the wellbore.
The signal 84 may comprise an acoustic signal.
The step of transmitting the signal 84 may include producing a pump-pound condition.
The step of transmitting the signal 84 may include changing a lower stroke extent of a rod string 18 connected to the downhole pump 20.
The step of transmitting the signal 84 may include at least partially withdrawing an internal structure (such as, the traveling valve 24, a pump barrel, etc.) from the downhole pump 20.
The step of transmitting the signal 84 may include changing an upper stroke extent of a rod string 18 connected to the downhole pump 20.
The step of receiving the signal 84 may include at least one sensor 78 detecting the signal in the second wellbore 72.
A reservoir analysis system 70 is also provided to the art by the above disclosure. In one example, the system 70 can include a downhole pump 20 positioned in a first wellbore 28. The downhole pump 20 selectively transmits a signal 84. At least one sensor 78 is positioned at a second wellbore 72. The sensor 78 receives the signal 84.
The system 10 may include a control system 46 that controls operation of an actuator 14 at the earth's surface 40. The actuator 14 reciprocably displaces a rod string 18 connected to the downhole pump 20.
The control system 46 may selectively change a lower stroke extent of the rod string 18. The signal 84 may be transmitted from the downhole pump 20 in response to the changed lower stroke extent. The changed lower stroke extent may produce a pump-pound condition.
The control system 46 may selectively change an upper stroke extent of the rod string 18. The signal may be transmitted from the downhole pump 20 in response to the changed upper stroke extent. The changed upper stroke extent may cause an inner structure to at least partially withdraw from the downhole pump 20.
Another reservoir analysis method is described above. In this example, the method comprises: selectively changing a reciprocating displacement of a rod string 18 connected to a downhole pump 20 in a first wellbore 28; transmitting a signal 84 from the downhole pump 20 in response to the changed reciprocating displacement; receiving the signal 84 at a second wellbore 72; and determining a reservoir characteristic from the received signal 84.
The step of changing the reciprocating displacement may be performed by a control system 46 that controls operation of an actuator 14 connected to the rod string 18. Changing the reciprocating displacement may comprise changing a lower and/or an upper stroke extent of the rod string 18.
Although various examples have been described above, with each example having certain features, it should be understood that it is not necessary for a particular feature of one example to be used exclusively with that example. Instead, any of the features described above and/or depicted in the drawings can be combined with any of the examples, in addition to or in substitution for any of the other features of those examples. One example's features are not mutually exclusive to another example's features. Instead, the scope of this disclosure encompasses any combination of any of the features.
Although each example described above includes a certain combination of features, it should be understood that it is not necessary for all features of an example to be used. Instead, any of the features described above can be used, without any other particular feature or features also being used.
It should be understood that the various embodiments described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of this disclosure. The embodiments are described merely as examples of useful applications of the principles of the disclosure, which is not limited to any specific details of these embodiments.
In the above description of the representative examples, directional terms (such as “above,” “below,” “upper,” “lower,” “raised,” “lowered,” etc.) are used for convenience in referring to the accompanying drawings. However, it should be clearly understood that the scope of this disclosure is not limited to any particular directions described herein.
The terms “including,” “includes,” “comprising,” “comprises,” and similar terms are used in a non-limiting sense in this specification. For example, if a system, method, apparatus, device, etc., is described as “including” a certain feature or element, the system, method, apparatus, device, etc., can include that feature or element, and can also include other features or elements. Similarly, the term “comprises” is considered to mean “comprises, but is not limited to.”
Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the disclosure, readily appreciate that many modifications, additions, substitutions, deletions, and other changes may be made to the specific embodiments, and such changes are contemplated by the principles of this disclosure. For example, structures disclosed as being separately formed can, in other examples, be integrally formed and vice versa. Accordingly, the foregoing detailed description is to be clearly understood as being given by way of illustration and example only, the spirit and scope of the invention being limited solely by the appended claims and their equivalents.
