Patent Application
20180230798
The present invention relates to methods for testing failure of well equipment, and specifically failure of tubing strings and downhole pumps.
In the art of pumping fluids to surface from downhole reservoirs, it is well known to employ a type of positive displacement pump called a progressing cavity pump (PCP), also known as a “Moineau pump” after its inventor René Moineau. A PCP conventionally comprises a stator and a rotor, the rotor in the form of a single helix (normally composed of metal) eccentrically located within an elastomeric stator inner cavity which cavity takes the form of a double helix, although other arrangements are known in the art. When the stator and rotor are mated together, they thus form a plurality of cavities which progress axially in response to rotation of the rotor. The rotor is normally rotated by means of a rod string from which the rotor depends from surface (the rod string and rotor being components of the rod string assembly), with the rotor capable of operation as a pump when rotated by the rod string which is typically driven by a motor on surface. The rod string assembly may comprise various components, including the rod box connection, sucker or continuous rod, connector rod, rod shear, rod centralizer and the rotor. The stator is conventionally connected to the downhole end of a tubing string with a pump intake end typically located at the bottom of the stator. The tubing string may comprise various components, including tubing joints, tubing pup joints, tubing collars, a tubing drain and the stator. The stator is normally secured to the downstream end of the tubing string and run into the hole to the desired depth, and the rotor is then run into the tubing string interior at the end of a rod string, the rotor then threaded into the stator at depth. When the pump is operated, fluid production can then be undertaken through the pump and upwards through the tubing string and into surface facilities.
However, it is also known that downhole equipment failures may occur with time, either in the tubing string or in the PCP. For example, the rotor rotates in an eccentric manner within the stator, and this eccentricity is imparted to the rod string, such that the rod string may repeatedly contact the tubing string inner wall and result in wear and leakage through the tubing string. In a further example, the components of a PCP are known to wear with use, often the elastomeric inner walls of the stator, with the result that the rotor and stator do not properly seal and there is leakage and loss of pumping efficiency.
Where reduced production indicates a possible downhole equipment failure, various methods and techniques have been developed to assess the downhole situation. One commonly employed technique is pressure testing, in which the pump action is halted and a fluid is injected into the tubing string using a flush-by unit to pressurize the tubing string contents. The flush-by unit is used to pull the rotor out of and above the stator to perform a flush of the tubing string, followed by replacement of the rotor within the stator and then injection of the pressurization fluid. If, after injection, there is more rapid depressurization or pressure release than would normally be expected, or a desired maximum pressurization level cannot be achieved, that is considered to be an indication that there is a failure somewhere in the string—including the pump. The tubing string may have a hole or a break, or there may be a problem at a connection point between tubing string segments. Alternatively, the pump components may have worn down or even become broken. A failure appears to have taken place, but there is no efficient way to confirm where the failure occurred, and thus proper corrective action is difficult to assess.
One technique involves pulling the rod string and rotor and then inserting a “dart” or plug down the tubing string to seat and seal above the pump, in which case the tubing string can be pressure-tested in isolation from the pump, but this involves the expense and costly well down-time involved in running out the rod string and then removing the dart. Electro-magnetic scanning of the tubing string for wear is also technically feasible, but it is generally recognized as being a relatively expensive option, has a significant margin of error and requires removal of the tubing string. As should be clear, then, some testing methods cannot differentiate between tubing string and pump failures, and those that may be able to are generally expensive or undesirably time-consuming.
What is needed, therefore, is a technique that can differentiate between potential tubing string and pump failures without requiring undesirable equipment expense and while reducing well down-time.
The present invention therefore seeks to provide an apparatus and method for selectively sealing off the PCP to allow tubing string pressure testing, while allowing the rod string to remain in place within the tubing string.
According to a first broad aspect of the present invention, there is provided an apparatus for selectively plugging a tubing string of a fluid producing well above a downhole progressing cavity pump, the pump comprising a rod string assembly comprising a rotor of the pump and a rod string, the rotor depending directly or indirectly from the rod string, the rod string assembly axially moveable within the tubing string, to isolate the pump during tubing string pressure testing, the apparatus comprising:
In some exemplary embodiments of the first aspect, the fluid producing well is an oil producing well, but it may be another type of fluid producing well such as for example a water producing well. The pump preferably comprises a stator connected to a downhole end of the tubing string, and isolating the pump preferably comprises restricting impingement of pressure testing fluid on the pump.
The plug member is preferably configured for connection to the rod string assembly by means selected from the group consisting of clamping, welding, threading and integral manufacturing, and the seat member is preferably configured for connection to the tubing string by means selected from the group consisting of welding, threading and integral manufacturing. The seal between the plug member and the seat member is preferably selected from the group consisting of metal on metal, metal on a readily deformable material, and metal on a composite material. In some exemplary embodiments the deformable surface may comprise a gasket or seating cup.
The peripheral protuberance may comprise any number of specific forms allowing for the desired seal, but in some exemplary embodiments comprises a tapered face for sealing against a corresponding surface of the plug member, or a rounded face for sealing against a corresponding surface of the plug member.
In some embodiments, the apparatus comprises a connector rod for flexibly connecting the plug member and the rotor, to allow the seal despite eccentricity of the rotor central axis relative to the stator central axis.
According to a second broad aspect of the present invention, there is provided a progressing cavity pump isolation assembly for use in a tubing string of a fluid producing well, the assembly comprising:
In some exemplary embodiments of the second aspect, the fluid producing well is an oil producing well, but it may be another type of fluid producing well such as for example a water producing well. The pump preferably comprises a stator connected to a downhole end of the tubing string, and isolating the pump preferably comprises restricting impingement of injected fluid on the pump.
The plug member is preferably configured for connection to the rod string assembly by means selected from the group consisting of clamping, welding, threading and integral manufacturing, and the seat member is preferably configured for connection to the tubing string by means selected from the group consisting of welding, threading and integral manufacturing. The seal between the plug member and the seat member is preferably selected from the group consisting of metal on metal, metal on a readily deformable material, and metal on a composite material.
The peripheral protuberance may comprise any number of specific forms allowing for the desired seal, but in some exemplary embodiments comprises a tapered face for sealing against a corresponding surface of the plug member, or a rounded face for sealing against a corresponding surface of the plug member.
In some embodiments, the assembly comprises a connector rod for flexibly connecting the plug member and the rotor, to allow the seal despite eccentricity of the rotor central axis relative to the stator central axis.
According to a third broad aspect of the present invention, there is provided a progressing cavity pump isolation system for use in tubing string pressure testing, the system comprising:
In some exemplary embodiments of the third aspect, the fluid producing well is an oil producing well, but it may be another type of fluid producing well such as for example a water producing well. The pump preferably comprises a stator connected to a downhole end of the tubing string, and isolating the pump preferably comprises restricting impingement of injected fluid on the pump.
The plug member is preferably configured for connection to the rod string assembly by means selected from the group consisting of clamping, welding, threading and integral manufacturing, and the seat member is preferably configured for connection to the tubing string by means selected from the group consisting of welding, threading and integral manufacturing. The seal between the plug member and the seat member is preferably selected from the group consisting of metal on metal, metal on a readily deformable material, and metal on a composite material.
The peripheral protuberance may comprise any number of specific forms allowing for the desired seal, but in some exemplary embodiments comprises a tapered face for sealing against a corresponding surface of the plug member, or a rounded face for sealing against a corresponding surface of the plug member.
In some embodiments, the system comprises a connector rod for flexibly connecting the plug member and the rotor, to allow the seal despite eccentricity of the rotor central axis relative to the stator central axis.
According to a fourth broad aspect of the present invention, there is provided a method for pressure testing a tubing string in a fluid production well, the tubing string comprising a downhole progressing cavity pump, the pump comprising a rotor, the rotor part of an axially moveable rod string assembly within the tubing string, the method comprising the steps of:
In some exemplary embodiments of the fourth aspect, the method further comprises the following steps between steps d. and e.: injecting a well pressure testing fluid from surface down the tubing string; allowing pressurization of the well pressure testing fluid within the tubing string and the pump; and measuring the pressurization.
Exemplary methods may further comprise, between steps b. and c., the step of lowering the rod string assembly until the plug member engages the seat member, thus locating the rotor at a desired location within the pump.
The step of measuring the pressurization preferably comprises measuring the quantum of the pressurization of the tubing string pressure testing fluid and/or measuring the period and rate over which the pressurization releases.
According to a fifth broad aspect of the present invention, there is provided a method for isolating a downhole progressing cavity pump for a tubing string pressure test, the pump comprising a rotor, the rotor part of an axially moveable rod string assembly within the tubing string, the method comprising the steps of:
In some exemplary embodiments of the fifth aspect, the method further comprises the following steps between steps d. and e.: injecting a well pressure testing fluid from surface down the tubing string; allowing pressurization of the well pressure testing fluid within the tubing string and the pump; and measuring the pressurization.
Some exemplary methods further comprise, between steps b. and c., the step of lowering the rod string assembly until the plug member engages the seat member, thus locating the rotor at a desired location within the pump.
The step of measuring the pressurization preferably comprises measuring the quantum of the pressurization of the tubing string pressure testing fluid and/or measuring the period and rate over which the pressurization releases.
Isolating the pump preferably comprises restricting impingement of the tubing string pressure testing fluid on the pump.
According to a sixth broad aspect of the present invention, there is provided a method for progressing cavity pump failure testing, the pump located at a downhole end of a tubing string within a fluid production well, the pump comprising a rotor, the rotor part of an axially moveable rod string assembly within the tubing string, the method comprising the steps of:
In some exemplary embodiments of the sixth aspect, the method further comprises the following steps between steps e. and f.: injecting a well pressure testing fluid from surface down the tubing string; allowing pressurization of the well pressure testing fluid within the tubing string and the pump; and measuring the pressurization.
Exemplary methods may further comprise, between steps b. and c., the steps of lowering the rod string assembly until the plug member engages the seat member, thus locating the rotor at a desired location within the pump, and raising the rod string assembly to the raised position.
The step of measuring the pressurization preferably comprises measuring the quantum of the pressurization of the tubing string pressure testing fluid and/or measuring the period and rate over which the pressurization releases.
Isolating the pump preferably comprises restricting impingement of the tubing string pressure testing fluid on the pump.
The step of determining whether the pressurization indicates a potential tubing string failure or a potential pump failure preferably comprises determining whether the pressurization is within normal parameters, pressurization within normal parameters indicating a potential failure of the pump that was isolated during pressurization.
A detailed description of exemplary embodiments of the present invention is given in the following. It is to be understood, however, that the invention is not to be construed as being limited to these embodiments. The exemplary embodiments are directed to particular applications of the present invention, while it will be clear to those skilled in the art that the present invention has applicability beyond the exemplary embodiments set forth herein.
In the accompanying drawings, which illustrate exemplary embodiments of the present invention:
Exemplary embodiments of the present invention will now be described with reference to the accompanying drawings.
Throughout the following description specific details are set forth in order to provide a more thorough understanding to persons skilled in the art. However, well known elements may not have been shown or described in detail to avoid unnecessarily obscuring the disclosure. The following description of examples of the technology is not intended to be exhaustive or to limit the invention to the precise forms of any exemplary embodiment. Accordingly, the description and drawings are to be regarded in an illustrative, rather than a restrictive, sense.
The present invention relates to techniques and apparatuses for pressure testing a tubing string of a fluid production well, the tubing string being provided with a progressing cavity pump at a downhole end, to help determine whether the tubing string has failed or the pump has failed. Apparatuses according to the present invention comprise a plug member connected to the rod string assembly that comprises the pump rotor, such that the rod string assembly can be lowered to seat the plug member in a seat member within the tubing string above the pump, thus sealing off and isolating the pump from the rest of the tubing string, allowing pressure testing of the tubing string above the pump.
Turning to
A plug member 18 is connected to the rod string 16 at a location upwardly spaced from the rotor 24. The rod string 16 connects to a top end of the plug member 18, while a connector rod 20 connects to a bottom end of the plug member 18. As the central axis of the rotor 24 is eccentric or offset from the central axis of the stator 14, the connector rod 20 may be required in the view of a skilled person to provide a flexible connection to ensure that the seal between the plug member 18 and the seat member 26 is possible. The connector rod 20 in turn connects to a rod box connection 22 which connects to the rotor 24 to impart the rotation from the rod string 16.
Note that while the plug member 18 is shown as connected to the rod string 16 in the illustrated embodiment, it could be connected to another component of the rod string assembly where appropriate and desirable. For example, the rod string assembly may comprise a rod box connection (for connecting rods and the rotor or other components together), a sucker rod (a single segment of a rod string), a connector rod (a shorter version of a sucker rod), a rod shear (a component designed to break under a certain defined tension), a rod centralizer (which centralizes a rod string within a tubing string), and a rotor, and the plug member can be connected or integral to any of these where determined to be appropriate and desirable by a person skilled in the art having reference to the within teaching.
Note that while the seat member 26 is shown as connected to the inner wall 28 of the tubing string 10 in the illustrated embodiment, it could be connected to another component of the tubing string where appropriate and desirable. For example, the seat member could be connected to a joint of tubing, a tubing pup joint (a shorter version of a standard tubing joint), a tubing drain (a component designed to burst open when enough hydraulic pressure is applied to allow fluid to drain from the tubing above the pump), or the stator itself, where determined to be appropriate and desirable by a person skilled in the art having reference to the within teaching.
The peripheral protuberance 30 defines an internally disposed aperture 32, through which fluids may pass when unobstructed.
The sealing interface between the plug member 18 and the seat member 26 can take various forms. For the purposes of illustration, four alternative embodiments are shown and described below. Note that the illustrated plug member designs incorporate an uphole tapered surface, which is intended for ease of rod string retrieval. Also, plug members according to the present invention could incorporate a combination of the sealing interfaces described below and illustrated herein.
Turning now to
Turning now to
The plug member 18 comprises the rounded sealing surface 50, and also an inner bore 54 for receiving the rod string 16 in an upper end and the connector rod 20 in a lower end.
Turning now to
The plug member 18 comprises the downwardly facing sealing surface 58, and also an inner bore 62 as can be seen in
Turning now to
The plug member 18 comprises the sealing surface 66, and also an inner bore 70 as can be seen in
While the illustrated embodiments show the plug member receiving the rod string and connector rod within bores in the plug member, other connection means can be used and would be clear to those skilled in the art having recourse to the within teaching. Also, the plug member may be positioned at other points on the rod string, for example connecting two rod ends. In further examples, the plug member could connect the rod string to a shear coupling or could be integral to the shear coupling in the rod string. The plug member integral to any appropriate rod component including centralizers, and it could even be integral to the rotor in appropriate designs.
Further, while the illustrated embodiments show the seat member connected to an inner surface of the tubing string at a point above the pump, the seat member can be connected to or integral with a tubing joint, a tubing collar, a drain or the stator.
Having described exemplary embodiments of an apparatus, assembly and system in accordance with the present invention, exemplary embodiments of methods according to the present invention will now be described with reference to the accompanying drawings.
Turning now to
When it is desired to pressure test the tubing string or isolate the pump for any reason, the method 200 continues by ceasing operation of the pump and flushing the pump (pulling the rotor from the stator and allowing fluid to drain through the stator) at step 214, and running an initial pressurization test using a flush-by unit in an effort to pressurize the system. This initial pressurization test involves injecting a pressure testing fluid down the tubing string to the pump at step 216, and allowing pressurization within the tubing string and pump at step 218. Note that at this stage the pump has not been isolated. The quantum of pressurization can be measured, as can the time it takes for the pressurization to decline after injection ceases. If the pressurization is measured to be less than should be expected under normal circumstances with the downhole equipment in good operating condition, or the pressurization declines more rapidly than should be the case, this indicates a potential failure somewhere in the tubing string or the pump.
At step 220, isolation of the pump is undertaken as a way to clarify the location of the potential failure. The rod string is lowered to the pressure testing position such that the plug member engages and seals the aperture, thus fully obstructing flow downwardly through the aperture. To lower the rod string, it first needs to be released at surface, where a clamp conventionally secures the topmost section called the polished rod. At this point the pump is isolated from the test environment. Once again, at step 222, a pressure testing fluid is injected from surface down the tubing string, and at step 224 pressurization of the tubing string commences, with measurement of the pressurization as described above. Identification of the failed component can then be undertaken based on the two pressure tests.
Turning now to
At this point in the method 300, a determination point is reached. A determination is made as to whether fluid production is at anticipated levels, which determination can be made using any number of methods and techniques known to those skilled in the art. If fluid production is at anticipated or acceptable levels, pump operation and fluid production can continue at step 310. If, however, it is determined that the fluid production is deficient, pump operation is halted and the pump is flushed (pulling the rotor from the stator and allowing fluid to drain through the stator) at step 314, and a pressure test then commences.
An initial pressurization test occurs at steps 316 and 318, comprising injecting a pressure testing fluid down the tubing string to the pump at step 316, and allowing pressurization within the tubing string and pump at step 318. Again, at this stage the pump has not been isolated. The quantum of pressurization can be measured, as can the time it takes for the pressurization to decline after injection ceases. If the pressurization is measured to be less than should be expected under normal circumstances with the downhole equipment in good operating condition, or the pressurization declines more rapidly than should be the case, this indicates a potential failure somewhere in the tubing string or the pump.
At step 320, isolation of the pump is undertaken as a way to clarify the location of the potential failure. The rod string is lowered to the pressure testing position such that the plug member engages and seals the aperture, thus fully obstructing flow downwardly through the aperture. At this point the pump is isolated from the test environment. Once again, at step 322, a pressure testing fluid is injected from surface down the tubing string, and at step 324 pressurization of the tubing string commences, with measurement of the pressurization as described above. At this point a second determination is made, namely whether the measured pressurization with the pump isolated is within a normal or expected range. If it is determined that the measured pressurization is within a normal or expected range, this indicates that the potential failure occurred in the pump, which had been isolated for the pressure test. If it is determined that the measured pressurization is not within a normal or expected range, this indicates that the potential failure occurred in the tubing string (although it is conceivable but unlikely that a potential failure has also occurred in the pump at the same time). This allows for corrective measures to be undertaken.
As can be seen by those skilled in the art, embodiments of the present invention can provide significant advantages over the prior art, including differentiating between tubing string and pump failures without requiring undesirable equipment expense and while reducing well down-time. Unnecessary rotor pulls and swaps can be avoided, as can expensive tubing scans.
Unless the context clearly requires otherwise, throughout the description and the claims:
Words that indicate directions such as “vertical”, “transverse”, “horizontal”, “upward”, “downward”, “forward”, “backward”, “inward”, “outward”, “vertical”, “transverse”, “left”, “right”, “front”, “back”, “top”, “bottom”, “below”, “above”, “under”, and the like, used in this description and any accompanying claims (where present) depend on the specific orientation of the apparatus described and illustrated. The subject matter described herein may assume various alternative orientations. Accordingly, these directional terms are not strictly defined and should not be interpreted narrowly.
Where a component (e.g. a circuit, module, assembly, device, drill string component, drill rig system etc.) is referred to herein, unless otherwise indicated, reference to that component (including a reference to a “means”) should be interpreted as including as equivalents of that component any component which performs the function of the described component (i.e., that is functionally equivalent), including components which are not structurally equivalent to the disclosed structure which performs the function in the illustrated exemplary embodiments of the invention.
Specific examples of methods and apparatus have been described herein for purposes of illustration. These are only examples. The technology provided herein can be applied to contexts other than the exemplary contexts described above. Many alterations, modifications, additions, omissions and permutations are possible within the practice of this invention. This invention includes variations on described embodiments that would be apparent to the skilled person, including variations obtained by: replacing features, elements and/or acts with equivalent features, elements and/or acts; mixing and matching of features, elements and/or acts from different embodiments; combining features, elements and/or acts from embodiments as described herein with features, elements and/or acts of other technology; and/or omitting combining features, elements and/or acts from described embodiments.
The foregoing is considered as illustrative only of the principles of the invention. The scope of the claims should not be limited by the exemplary embodiments set forth in the foregoing, but should be given the broadest interpretation consistent with the specification as a whole.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/CA2015/000451 | 8/5/2015 | WO | 00 |
