METHODS AND APPARATUS FOR ENHANCING FLUID PRODUCTION FROM A WELL

A method of enhancing fluid production from a well is provided. A downhole plunger having the maximum permissible outer diameter for the well is installed in the well. Methods and apparatus for determining the maximum permissible outer diameter for a downhole plunger for use in the well are provided.

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Description
REFERENCE TO RELATED APPLICATIONS

This application claims priority to Canadian patent application No. 2966899 filed 10 May 2017, the entirety of which is incorporated by reference herein for all purposes.

TECHNICAL FIELD

Some embodiments of the present invention relate to methods for improving fluid production from oil and gas wells. Some embodiments of the present invention relate to apparatus for improving fluid production from oil and gas wells. Some embodiments of the present invention relate to downhole plungers having a variety of different diameters that can be used to improve fluid production from oil and gas wells.

BACKGROUND

In an oil or gas well, the bottom hole pressure and the gas to liquid ratio will eventually not support a natural flow therefrom. The well operator at that time must select an artificial lift to remove fluid from the well so as to resume production. A plunger lift is a form of artificial lift which may be utilized in maintaining production levels and stabilizing the rate of decline of production of oil and gas from a well.

Plunger lift is an established method for enhancing the removal of liquids from a well that is producing at least some natural gas. The liquids may be oil, hydrocarbon condensates, water, or any combination thereof. If permitted to accumulate in a well bore, these liquids build up to create a hydrostatic back pressure against the formation, which in turn reduces production and may ultimately stop production completely.

As the oil or gas flow rate and pressure decline in a well, the lifting efficiency declines. The well then may begin to “load up” and “log off”. This means that gas being produced into the well bore can no longer carry the fluid produced to the surface. One reason for this is that, as liquid comes in contact with the wall of the production string or tubing, friction will occur. The velocity of that liquid is thus reduced and some of the liquid adheres to the tubing wall, creating a film of liquid on that tubing wall. Thus, that liquid does not reach the well head at the surface.

Additionally, as the flow continues to slow, the gas phase can no longer support liquid in either slug form or droplet form. This liquid along with the liquid film on the sides of the tubing begins to fall back to the bottom of the well. In a very aggravated situation there will be liquid in the bottom of the well with only a small amount of gas being produced at the surface. The produced gas must bubble through the liquid at the bottom of the well and then flow to the surface. Because of the low velocity, very little liquid if any is carried to the surface of the well by the gas.

The corresponding head of liquid in the bottom of the well exerts a back pressure against the producing formation, with a value corresponding to the vertical elevation of the liquid in the well, effectively terminating the well's ability to produce. A properly applied plunger lift system is able to bring such a well back to life and make it profitable.

A plunger lift system permits the well to be opened and closed so as to generate a sufficient pressure permitting the well to flow into the flow line. The plunger travels freely back and forth within the vertical tubing string, from the bottom of the well to the surface and back to the bottom. The plunger is used as a mechanical interface between the gas phase and the fluid phase in the well. When the well is closed at the surface, the plunger rests at the bottom of the well on top of a spring assembly. Pressure within the well rises as gas enters the well. When the well is opened at the surface, with all production being through the tubing, the well begins to flow and the pressure in the tubing decreases. Because the trapped gas in the casing/tubing annulus remains at a higher pressure than the tubing, the differential pressure between the two increases. The liquid level in the annulus decreases as the liquid is pushed downward where it “U tubes” into the tubing.

The mechanical tolerance between the outside diameter of the plunger and the inside of the tubing leaves sufficient space for the liquid to bypass the plunger, allowing the plunger to remain initially resting on the bottom. Eventually gas within the tubing causes the plunger to move up the tubing string carrying the fluid load on top. A small amount of gas will bypass the plunger. This is useful as it scours the plunger and the tubing wall of fluid keeping all the fluid on top of the plunger. If the system has been properly engineered, most of the liquid can be removed from the well to permit the well to flow at the lowest production pressure possible. The use of such a plunger in the tubing minimizes any fluid fallback over the entire length of the tubing, irrespective of the depth of the well. Such a well may be operated at a lower bottom hole pressure since substantially all the liquid is removed from the well bore, thus enhancing its production.

The operation of a plunger within a well is carefully controlled. With too much pressure, the plunger ascends too quickly (>1000 ft/min), potentially damaging surface equipment upon impact. With too little pressure (<500 ft/min), fluid slips around the plunger, preventing it from rising. According to accepted practice, an ideal lift speed is around 750 ft/min. A goal of utilizing plunger lift systems is generally to start the well as soon as enough energy/pressure is available.

There should be a sufficiently tight fit of the plunger within the tubing to afford a sufficiently effective seal during lifting. However, the mechanical tolerance between the outside diameter of the plunger and the inside diameter of the tubing must leave sufficient space to allow descent of the plunger through the tubing string at a practical rate and to avoid the plunger becoming lodged in the tubing.

Pad plungers are known for use in wells with tubing deviations. A pad plunger incorporates a body having metal pads, such as spring-loaded metal pads, that expand or contract to compensate for tubing irregularities and to keep the outside diameter of the plunger in contact with the tubing walls. This allows the plunger to maintain its seal with the tubing walls during lifting in order to reduce fluid fallback over the entire length of the tubing. However, spring-loaded metal pads wear and are prone to mechanical failure.

Under ever changing well conditions, the inside diameter of a well's tubing may vary throughout the life cycle of the well. As the well conditions change, the fit of the plunger within the tubing may change, potentially affecting the seal between the plunger and the tubing walls.

Conventional thinking in the field of gas well plunger lift systems has historically assumed the maximum outer diameter of plunger tools to be a fixed value based on tubular tables supplied by tubing manufacturers. The conventional maximum diameter for a downhole plunger was thought to be smaller than the actual internal diameter of the tubing of the well. For example, for a well having a tubing with an internal diameter of 2″, conventional thinking is that the largest outer diameter for a plunger suitable for use in the well is 1.90″. This suggests that downhole plungers having larger diameters could potentially be used within the tubing. However, due to inconsistencies introduced during the completion part of the well process, this is not the case. For example, when the tubing strings are torqued together with service rigs, connections are sometimes overtightened resulting in “tight” spots. Features such as this make it impossible to predict what the maximum diameter for a downhole plunger in any given well would be. The inventor has even encountered wells in which downhole plungers having a conventional “normal” size would not fully travel the entire length of the tubing string.

There remains a need to optimize plunger fit within the tubing of a well to maintain sealing tolerances over extended periods of use of the plunger.

The foregoing examples of the related art and limitations related thereto are intended to be illustrative and not exclusive. Other limitations of the related art will become apparent to those of skill in the art upon a reading of the specification and a study of the drawings.

SUMMARY

The following embodiments and aspects thereof are described and illustrated in conjunction with systems, tools and methods which are meant to be exemplary and illustrative, not limiting in scope. In various embodiments, one or more of the above-described problems have been reduced or eliminated, while other embodiments are directed to other improvements.

One aspect of the invention provides a method of enhancing fluid production from a well by installing a plunger having the maximum permissible outer diameter for the well in the well.

One aspect of the invention provides a method of enhancing fluid production from a well, the method having the steps of evaluating whether a downhole plunger having a first outer diameter can travel freely within a tubing of the well; if the downhole plunger having the first outer diameter can travel freely within the tubing of the well, evaluating whether a downhole plunger having a second outer diameter that is larger than the first outer diameter can travel freely within the tubing of the well; and if the downhole plunger having the second outer diameter cannot travel freely within the tubing of the well, installing a downhole plunger having the first outer diameter in the well and performing artificial lift using the downhole plunger having the first outer diameter.

One aspect of the invention provides a method of enhancing fluid production from a well, the method having the steps of evaluating whether a downhole plunger having a first outer diameter can travel freely within a tubing of the well, if the downhole plunger having the first outer diameter cannot travel freely within the tubing of the well, evaluating whether a downhole plunger having a second outer diameter that is smaller than the first outer diameter can travel freely within the tubing of the well; and, if the downhole plunger having the second outer diameter can travel freely within the tubing of the well, installing a downhole plunger having the second outer diameter in the well and performing artificial lift using the downhole plunger having the second outer diameter.

One aspect of the invention provides a method of determining the maximum permissible diameter for a downhole plunger that can be used in a well, the method having the steps of evaluating a plurality of different plunger outer diameters to determine whether plungers having at least two of the plurality of different plunger outer diameters can travel freely in a tubing of the well; and concluding that the maximum permissible diameter for a downhole plunger that can be used in the well is equal to the largest one of the plurality of different plunger outer diameters that will still allow a plunger to travel freely in the well.

One aspect of the invention provides a method of determining whether a downhole plunger having a first outer diameter can travel freely within a well, the method having the steps of dropping a drive plunger in a tubing of the well below a measuring sleeve, the measuring sleeve having an outer diameter equal to the first outer diameter; allowing the drive plunger and the measuring sleeve to fall in the tubing; and if the measuring sleeve becomes lodged in the tubing, concluding that a downhole plunger having the first outer diameter cannot travel freely within the well; or if the measuring sleeve does not become lodged in the tubing, concluding that a downhole plunger having the first outer diameter can travel freely within the well.

One aspect of the invention provides an apparatus for determining the maximum permissible outer diameter of downhole plunger that can be used in a well, the apparatus having a measuring sleeve comprising a generally cylindrical outer shell defining an outer diameter and a hollow interior defining a fluid path through the measuring sleeve.

One aspect of the invention provides a kit having a drive plunger and a plurality of measuring sleeves, each one of the plurality of measuring sleeves having a different outer diameter.

One aspect of the invention provides a plunger lift gauging tool for determining a maximum diameter of a plunger that can be used in a gas-producing well, the tool having a pad plunger body having compressible pads; and a plurality of radially outwardly extending tabs made from a material that retains its shape after deformation, the radially outwardly extending tabs extending outwardly to define a predetermined outer diameter.

One aspect of the invention provides a plunger lift gauging tool for determining a maximum diameter of a plunger that can be used in a gas-producing well, the tool having a central shaft; a pad comprising a plurality of spring-loaded pad sections mounted on the central shaft to maintain an approximately even degree of contact with an inside surface of a tubing of the well when the tool is in use; and a measuring ring having at least one radially outwardly extending tab, the tab protruding outwardly to define a predetermined outer diameter.

In addition to the exemplary aspects and embodiments described above, further aspects and embodiments will become apparent by reference to the drawings and by study of the following detailed descriptions.

BRIEF DESCRIPTION OF THE DRAWINGS

Exemplary embodiments are illustrated in referenced figures of the drawings. Like reference numerals have been used to refer to the components of the various embodiments that perform a similar function. It is intended that the embodiments and figures disclosed herein are to be considered illustrative rather than restrictive.

FIG. 1 shows an example of a typical prior art gas-producing well incorporating a plunger lift system.

FIG. 2 shows an example embodiment of a method of enhancing fluid production from a gas-producing well.

FIG. 3 shows an example embodiment of an apparatus for determining the maximum permissible diameter of plunger that can be used to enhance production of fluid from a well.

FIG. 4A shows a side view of an example embodiment of a measuring sleeve for use in the embodiment of FIG. 3, and FIG. 4B shows a cross-sectional view thereof.

FIG. 5 shows a flowchart illustrating an exemplary method of enhancing fluid production from a well.

FIG. 6 shows a side view of an example embodiment of a plunger lift gauging tool.

FIG. 7 shows a perspective view of an example embodiment of a plunger lift gauging tool, in which no springs are provided under the pads of the plunger (i.e. showing the pads in the equivalent position of their fully compressed state).

FIG. 8 is a sketch showing an example embodiment of a plunger lift gauging tool with the pads and measuring rings removed.

FIG. 9 is a sketch showing an example embodiment of a plunger lift gauging tool with the pads and measuring rings inserted over the central shaft thereof.

FIG. 10A is a side view and FIG. 10B is a top view of a pad used in some example embodiments.

FIG. 11 is a top view of a measuring ring according to an example embodiment.

FIG. 12 is a top view of an example embodiment of a plunger lift gauging tool, in which no springs are provided under the pads of the plunger (i.e. showing the pads in the equivalent position of their fully compressed state so that the measuring rings extend beyond the outer diameter of the pads).

FIG. 13 shows a partial side view of an example embodiment of a plunger lift gauging tool, in which one of the collars and one of the pad sections has been removed from the tool.

FIG. 14 shows a partial side view of an example embodiment of a plunger lift gauging tool, in which the pad sections have been manually forced radially outwardly.

FIG. 15A shows an example embodiment of a plunger lift gauging tool in its assembled configuration, with the springs beneath the pads in their uncompressed (i.e. default) position. FIG. 15B shows the embodiment of FIG. 15A, in which the pads have been manually pressed to compress the springs beneath the pads.

FIG. 16 shows a side view of the example embodiment of FIG. 15A, with the springs beneath the pads in their uncompressed (i.e. default) position.

 DESCRIPTION

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. Accordingly, the description and drawings are to be regarded in an illustrative, rather than a restrictive, sense.

The inventor has now surprisingly determined that it is possible in at least some wells to use a plunger having a diameter larger than was thought possible according to conventional thinking in the field of plunger lift systems. The inventor has also found that the use of a plunger having a larger diameter can in some wells increase the production of gas from the well.

One aspect of the invention provides a method of enhancing fluid production from a well by selecting and using a downhole plunger having a maximum permissible diameter for a given well. As used herein, the term “maximum permissible diameter” of a plunger for a given well means a plunger having the largest outer diameter that can fit into the well while still allowing the plunger to travel freely through the entire length of the tubing of the well.

One aspect of the invention provides a method of enhancing fluid production from a well by analyzing the internal diameter of a tubing of the well to determine the maximum permissible diameter for a downhole plunger for use in the well. In some embodiments, the plunger is a Venturi plunger, for example as described in U.S. Pat. Nos. 8,464,798 and 8,627,892 to Nadkrynechny, both of which are incorporated herein by reference.

One aspect of the invention provides a method for determining what diameter of plunger should be used to maximize the efficiency of plunger lift in a well. In some embodiments, maximizing the efficiency of plunger lift in a well comprises analyzing the internal diameter of the tubing of the well, and using the results of that analysis to select a plunger having the widest possible diameter, without an unacceptably high risk that the plunger will become stuck in the tubing of the well. In some embodiments, the plunger is a venturi plunger such as that described in U.S. Pat. No. 8,464,798 or U.S. Pat. No. 8,627,892 to Nadkrynechny.

One aspect of the invention provides a method of enhancing fluid production from a well by installing in the well a downhole plunger having the maximum permissible diameter for the well.

In some embodiments, a gauging tool is used to determine what diameter of plunger should be used to maximize the beneficial effect of gas flowing through the aperture of a venturi plunger. In some embodiments, the gauging tool has a plunger body that is configured to allow the gauging tool to move up and down inside a well and a plurality of radially outwardly extending deformable tabs. In some embodiments, the deformation of the radially extending deformable tabs after the gauging tool has been run inside a well is used to determine what diameter of plunger should be used in the well. Methods of using the gauging tool to determine what diameter of plunger should be used in a given well are provided.

Another aspect of the invention provides a method of determining what diameter of plunger should be used to optimize the production of fluid from a given well.

As used in this specification, “upper” means in the direction of the surface of a well when a tool is in use and “lower” means in the direction towards the bottom of the well when the tool is in use. It will be appreciated that the tools described herein could have other orientations when not in use.

As used in this specification, “inwardly” means a direction towards the central axis of the plunger lift gauging tool, and “outwardly” means a direction towards the outer edge of the plunger lift gauging tool.

As used herein, the concept that a plunger can “travel freely in a well” means that the plunger can rise and fall within the well under a range of ordinary expected operating conditions, and not have a high likelihood of becoming stuck or lodged in the tubing during ordinary operation.

As used herein, the term “enhancing the production of fluids from a well” means that an improvement in at least one aspect of the operation of the well is observed. In some embodiments, the aspect of the operation of the well that is improved is gas production. In some embodiments, gas production is increased by at least 5%. In some embodiments, the aspect of the operation of the well that is improved is that the lift pressure required to carry out artificial lift in the well using a downhole plunger is reduced. In some embodiments, the lift pressure required to carry out artificial lift in the well using a plunger is reduced by at least 5%. In some embodiments, even if the gas production of the well at a single point in time is not increased, the production of fluids from the well can be said to be enhanced if the performance of the well is enhanced in other ways, for example, the plunger becoming stuck within the tubing less frequently so that well shut-in times are reduced.

A typical prior art well arrangement incorporating a plunger lift system is shown in FIG. 1. A well 20 is drilled into the ground from the surface 22 to any producing underground formation 24. A production casing 26 is placed into the well bore, and perforations 28 are created in the casing at the level of formation 24 to allow gas and liquid to enter the well bore. A production tubing 30 is placed inside casing 26 and forms a continuous conduit for producing gas and liquid up through to a wellhead lubricator 32. Lubricator 32 is arranged to place a conventional plunger 46 in well 20 and to retrieve plunger 46 from well 20 without having to kill well 20. The lubricator 32 may have a sensor, shown schematically as 98, to detect the arrival of plunger 46 at the surface 22, sending a signal to a control system 42 for various controller functions to help optimize production. Sensor 98 may comprise a magnetic sensor. The produced fluid exits through exit tubing 34 via a control valve 36 to move on to the next stage of collection, as indicated by arrow 38.

Well 20 includes a master valve 40, which can be used to stop the flow from well 20. Control valve 36 is regulated based on inputs from control system 42, which signals a valve actuator 44 configured to regulate control valve 36.

In operation, a plunger 46 is inserted into well 20 as follows. Well 20 is prevented from flowing by closing master valve 40. A plunger 46 is inserted into lubricator 32 by removing a cap 43, inserting plunger 46 into lubricator 32, and replacing cap 43. Control valve 36 is kept in the closed position by valve actuator 44, which is controlled by input from control system 42. Master valve 40 is then opened, and typically control system 42 is then set to proceed with an operating mode and allowed to operate the well.

In the operating mode, when control valve 36 is in the closed position so that well 20 is shut in, plunger 46 free falls by gravity for a period of time, to allow plunger 46 to arrive at the bottom of well 20, contacting a bottom-hole stop 48, which may incorporate a spring 50. Bottom-hole stop 48 absorbs impact and prevents plunger 46 from passing through the bottom of production tubing 30.

After a period of time in the operating mode, control system 42 will signal valve actuator 44 to open control valve 36. This time period may be an established set time; a time calculated from other parameters such as plunger arrival time; a time calculated from pressure readings from casing 28, tubing 34, or a downstream collection system; or some combination of the foregoing; or, the time frame may be established in any other suitable manner. Control system 42 may also be manually operated to open control valve 36.

Upon control valve 36 opening, gas pressure which has accumulated in the annulus 52 between casing 26 and tubing 30 will flow through bottom-hole stop 48. Plunger 46 acts like a piston, providing a seal between the gas and liquid entering from below plunger 46 and the gas and liquid above plunger 46. Plunger 46 pushes liquid that has accumulated above plunger 46 to the surface 22, where it exits the pumping system, as shown by arrow 38, and is transported to a downstream separation and gathering apparatus.

Plunger 46 may remain in well 20 for a period of operation which may be from days or weeks up to several years depending on performance, well conditions, and the nature of plunger 46 or other well components used.

Conventional thinking in the field of gas well plunger lift systems has historically assumed the maximum outer diameter of plunger tools to be a fixed value based on tubular tables supplied by tubing manufacturers. The conventional maximum diameter for a downhole plunger such as plunger 46 was thought to be smaller than the actual internal diameter of the tubing 30 of the well. For example, for a well 20 having a tubing 30 with an internal diameter of 2″, conventional thinking is that the largest outer diameter for a plunger 46 suitable for use in the well is 1.90″.

However, the inventor has now found that selection of a downhole plunger having the largest diameter that reasonably will not become lodged within the tubing 30 (referred to herein as “the maximum permissible diameter”) for use in a given well can allow reductions in flowing bottom hole pressures in producing wells, which can increase production. Use of a plunger having the maximum permissible diameter for use in the given well can also minimize risk of damage to surface equipment. For example, a first plunger having a relatively larger diameter than a second plunger will tend to travel more slowly within tubing 30 of the well than the second plunger, and therefore enters lubricator 32 at a lower speed than the second plunger.

The examples described herein establish that plungers having relatively larger outer diameters can be supported by less flow than a corresponding plunger having a narrower outer diameter. The examples further establish that the use of a plunger having the maximum permissible outer diameter can considerably enhance the production of fluid from a well in the field.

With reference to FIG. 2, a method 100 of enhancing fluid production from a well is illustrated schematically. At 102, an evaluation of whether a plunger having a first outer diameter (“OD”) can travel freely within the well is made. At 104, an evaluation of whether a plunger having a second outer diameter (“OD”) can travel freely within the well is made. The outer diameter selected for evaluation at step 104 is determined based on the outcome of the evaluation of the first outer diameter at step 102. For example, if it is determined at step 102 that a plunger having the first outer diameter can travel freely in the well, then the second outer diameter selected for evaluation at step 104 will be larger than the first outer diameter. On the other hand, if it is determined at step 102 that a plunger having the first outer diameter cannot travel freely in the well, then the second outer diameter selected for evaluation at step 104 will be smaller than the first outer diameter.

At step 106, steps 102 and 104 are repeated again as necessary with plungers having different outer diameters, to determine the maximum permissible diameter of plunger that can travel freely within the well. In some cases, step 106 is not carried out. For example, if at step 102 it is determined that a plunger having the first outer diameter can travel freely within the well, and at step 104 it is determined that a plunger having the second outer diameter cannot travel freely within the well, and the second outer diameter is larger than the first outer diameter by an amount that represents the next available plunger size, then it is concluded that the maximum permissible diameter for a plunger for use in that well is equal to the first outer diameter, and step 106 is not needed. On the other hand, if at step 102 it is determined that a plunger having the second outer diameter can travel freely within the well, then at step 106 it is determined whether a plunger having a third outer diameter that is larger than the first and second outer diameters can travel freely within the well, and step 106 is repeated as necessary until the maximum permissible diameter for the well has been determined.

One skilled in the art would be able to carry out steps 102, 104, 106 using plungers having a plurality of different diameters or using any of the apparatus described in this specification in any order to determine the maximum permissible diameter of plunger that can be used with that particular well.

As a specific and non-limiting example, if the available plunger outer diameters are 1.90″, 1.91″, 1.92″, 1.93″, 1.94″ and 1.95″ and at step 102 it is determined that a plunger having an outer diameter of 1.91″ will be able to travel freely within the well, and at step 104 it is determined that a plunger having an outer diameter of 1.92″ will not be able to travel freely within the well, then at step 108 it is determined that the maximum permissible diameter of plunger for that well has an outer diameter of 1.91″, and at step 110 a new downhole plunger having an outer diameter of 1.91″ is installed in the well.

As another specific and non-limiting example using the same available plunger outer diameters, if at step 102 it is determined that a plunger having an outer diameter of 1.91″ will be able to travel freely within the well, and at step 104 it is determined that a plunger having an outer diameter of 1.93″ will not be able to travel freely within the well, then step 106 is carried out to determine if a plunger having an outer diameter of 1.92″ will be able to travel freely within the well. If the outcome of step 106 is that a plunger having an outer diameter of 1.92″ will be able to travel freely in within the well, then at step 108 it is determined that the maximum permissible diameter of plunger for use with that well has an outer diameter of 1.92″, and at step 110, a new plunger having an outer diameter of 1.92″ is installed in the well. On the other hand, if the outcome of step 106 is that a plunger having an outer diameter of 1.92″ will not be able to travel freely within the well, then at step 108 it is determined that the maximum permissible diameter of plunger for use in that well has an outer diameter of 1.91″, and at step 110, a new plunger having an outer diameter of 1.91″ will be installed in the well.

In alternative embodiments, other plunger outer diameters could be selected for use as appropriate depending on the diameter of the tubing string in which the downhole plunger is to travel. For example, in wells using larger tubing strings, for example, having a 73 mm tubing string (approximately 2.87″), a typical plunger outer diameter for use for artificial lift in such a well would be 2.34″. In such embodiments, the maximum permissible diameter of plunger for use in that well would be determined by evaluating whether plungers having an outer diameter of 2.35″, 2.36″, 2.37″, 2.38″, 2.39″, 2.40″ or larger could freely travel in the well.

In one example embodiment, as illustrated with reference to FIGS. 3, 4A and 4B, a drive plunger 120 and a measuring sleeve 122 are used to carry out method 100. As illustrated schematically in FIG. 3, in use, the drive plunger 120 is dropped in well 20 below measuring sleeve 122. Drive plunger 120 is used to both limit the fall rate of measuring sleeve 122 in the well, and to dislodge measuring sleeve 122 upwardly if measuring sleeve 122 becomes lodged in tubing 30, so that measuring sleeve 122 can be returned to the surface without the need to invoke conventional wireline plunger retrieval techniques ordinarily used to dislodge plungers that become stuck in wells.

Any type of known plunger can be used to provide drive plunger 120, including for example a venturi plunger, a pad plunger, a brush plunger, a bar stock plunger, a bypass plunger, a ball and sleeve plunger, a sand plunger, or the like. In some embodiments, drive plunger 120 is a plunger that seals well within tubing 30, so that plunger 120 will maintain a relatively low velocity when moving within tubing 30. In some embodiments, drive plunger 120 is a venturi plunger or a pad plunger. Example embodiments of suitable venturi plungers for use as drive plunger 120 are described in U.S. Pat. Nos. 8,464,798 and 8,627,892 to Nadkrynechny, which are both incorporated by reference herein for all purposes.

With reference to FIGS. 4A and 4B, in the illustrated embodiment measuring sleeve 122 is a generally cylindrical tubular structure having an outer shell 124 and a hollow interior region 126. In the illustrated embodiment, the outer surface of outer shell 124 is provided with a plurality of ribs 125, as are commonly used on the outer surfaces of several different types of downhole plungers. In alternative embodiments, ribs 125 are omitted and outer shell 124 is provided with a plain external surface, or with any other configuration as may be used for the external surface of a downhole plunger.

In the illustrated embodiment, measuring sleeve 122 is also provided with an internal fishneck 127, to facilitate removal of sleeve 122 by wireline tools should that become necessary. In other embodiments, internal fishneck 127 is omitted.

The outer circumference of outer shell 124 defines an outer diameter 128 of the measuring sleeve 122. While in the illustrated embodiment, outer shell 124 has been illustrated as having a generally cylindrical shape and therefore a generally uniform outer circumference, in embodiments in which the outer shell is not generally cylindrical in shape, the largest external diameter at any given longitudinal cross-section of measuring sleeve would provide the outer diameter of that particular measuring sleeve.

The inner circumference of outer shell 124 defines an inner diameter 129 of measuring sleeve 122, and provides a fluid path through measuring sleeve 122. As can be seen in the illustrated embodiment, the inner diameter 129 of measuring sleeve 122 can vary somewhat along the length of measuring sleeve 122. However, significant constrictions or solid points that would significantly inhibit or block the flow of fluid through measuring sleeve 122 should be avoided. As described below, when measuring sleeve 122 becomes lodged in tubing 30, drive plunger 120 can be surfaced to dislodge and thereby surface measuring sleeve 122. However, if the flow of fluid within the tubing 30 is significantly inhibited by measuring sleeve 122 (when in its stuck configuration), then drive plunger 120 will not be able to rise within tubing 30, and measuring sleeve 122 will need to be removed from its stuck configuration by conventional plunger removal techniques, e.g. wireline retrieval.

In one example non-limiting embodiment, the outer diameter of measuring sleeve 122 is 2.35″, and the minimum inner diameter 129 of the measuring sleeve at any point along its length is approximately 1″. However, any desired inner diameter 129 could be used, so long as contact surface 132 is sufficiently large to contact contact surface 134 of drive plunger 120, and so long as inner diameter 129 is not so narrow as to prevent or significantly inhibit drive plunger 120 from rising within tubing 30 when measuring sleeve 122 becomes lodged in tubing 30.

Generally, drive plunger 120 is provided with an outer diameter 130 (FIG. 3) that is smaller than the outer diameter 128 of measuring sleeve 122. In this way, the chances that drive plunger 120 will become lodged within tubing 30 are minimized. Also, generally the outer diameter of drive plunger 120 is not varied, while a plurality of different measuring sleeves 122 having a plurality of different outer diameters are tested in well 20.

In one exemplary embodiment, both drive plunger 120 and measuring sleeve 122 are provided with a longitudinal length of 10″, although other lengths could be used and this example is not limiting.

The thickness of outer shell 124 of measuring sleeve 122 is sufficiently large that the bottom surface of measuring sleeve 122 can be supported on the top surface of drive plunger 120 by respective contact surfaces 132, 134 when measuring sleeve 122 and drive plunger 120 are falling in the well, and so that the upper surface of drive plunger 120 will contact measuring sleeve 122 when drive plunger 120 is rising in the well, including to dislodge measuring sleeve 122 if measuring sleeve 122 has become lodged in tubing 30.

In use, well 20 is shut in, and drive plunger 120 is dropped into well 20 below measuring sleeve 122. Once drive plunger 120 and measuring sleeve 122 have reached the bottom of well 20, production is resumed and measuring sleeve 122 and drive plunger 120 return to the surface.

If a first measuring sleeve 122 is able to travel freely within tubing 30 without becoming stuck, then this is a good indication that a plunger having an outer diameter equal to the first outer diameter 128 of first measuring sleeve 120 will be able to freely travel within tubing 30 of well 20. Accordingly, to determine the maximum permissible diameter of plunger that can be used with well 20, the first measuring sleeve 122 is removed from the well, and a second measuring sleeve 122 having a second outer diameter 128 that is larger than the first outer diameter of the first measuring sleeve is dropped into well 20 above drive plunger 120. If the second measuring sleeve 122 similarly does not become lodged within tubing 30, then this is a good indication that a plunger having an outer diameter equal to the second, larger outer diameter 128 will be able to freely travel within well 20. The testing process can therefore be repeated using a third measuring sleeve 122 having a third outer diameter 128 that is larger than the second outer diameter tested.

On the other hand, if the second measuring sleeve 122 becomes lodged in tubing 30, then this is a good indication that a plunger having an outer diameter equal to the second, larger outer diameter 128 is likely to become lodged within tubing 30. Accordingly, the testing process can be repeated with a third measuring sleeve 122 having a third outer diameter 128 that is intermediate between the first and second outer diameters tested. Alternatively, where the diameter of the second measuring sleeve 122 is larger than the first measuring sleeve 122 by only the smallest size increment available, it can be concluded that the maximum permissible diameter of plunger that can be used in well 20 has an outer diameter equal to the first outer diameter 128 tested.

Thus, generally speaking, the maximum permissible diameter of plunger that can be used in a given well 20 can be determined by dropping drive plunger 120 in turn with a plurality of different measuring sleeves 122 having a plurality of different outer diameters 128. The outer diameter 128 of the largest (i.e. largest outer diameter) measuring sleeve 122 that can freely travel within tubing 30 without becoming lodged therein can be concluded to be the maximum permissible diameter of plunger for use in well 20, and a plunger having that maximum permissible diameter as its outer diameter can be installed in well 20 to enhance the production of fluids therefrom.

In some embodiments, as illustrated with reference to the method of FIG. 5, tools are used to track the movement of drive plunger 120 and measuring sleeve 122 within tubing 30. In the exemplary method 200 illustrated in FIG. 5, an echometer is used to monitor the movement of drive plunger 120 and/or measuring sleeve 122 within tubing 130.

At step 202, a tubing shot is optionally performed by introducing compressed carbon dioxide (CO2) or other suitable gas into the well to produce an acoustic wave that travels down the well and is monitored by the echometer. The tubing shot carried out at step 202 provides a baseline image of the internal configuration of the tubing of the well in the form of an acoustic trace pattern (showing, for example, tubing collars and other structures present in the well).

At step 204, the well is shut in for a suitable period (which can be 1-2 days in some embodiments, but could be longer or shorter depending on the prevailing conditions at the particular well), and a drive tool, e.g. drive plunger 120, and a sizing tool, e.g. measuring sleeve 122, are dropped into the tubing of the well. The well head valves are opened and drive plunger 120 and measuring sleeve 122 are permitted to fall together in the well, drive plunger 120 being positioned below measuring sleeve 122 as shown in FIG. 3. The movement of the drive plunger 120 and the measuring sleeve 122 are tracked using the echometer in a manner similar to that known in the art for monitoring plunger lift.

Because drive plunger 120 has an internal orifice 138 which is narrower than the hollow internal region 126 of measuring sleeve 122, drive plunger 120 falls more slowly in well 20 than measuring sleeve 122. Since measuring sleeve 122 is supported above drive plunger 120 by the contact of contact surface 132 of measuring sleeve 122 on contact surface 134 of drive plunger 120, measuring sleeve 122 and drive plunger 120 fall together to the bottom of well 20.

Once the drive plunger 120 and measuring sleeve 122 are at the bottom of the well, a second tubing shot is optionally carried out at step 206 to confirm that the real-time tracking data obtained as the drive plunger 120 and measuring sleeve 122 are falling is correct. At step 208, the drive plunger 120 and measuring sleeve 122 are surfaced. At step 210, steps 204, 206 and 208 are repeated again, but using a measuring sleeve 122 having a larger outer diameter. Steps 204, 206, 208 and 210 are repeated as many times as desired, until the measuring sleeve 122 becomes stuck in the well.

Without being bound by theory because measuring sleeve 122 is supported by drive plunger 120 while the two are falling within well 20, measuring sleeve 122 is falling with a relatively low velocity within tubing 30, and will only become gently stuck in tubing 30.

When measuring sleeve 122 becomes stuck in the tubing, the method proceeds to step 212. The data obtained by the echometer can be used as a second means to determine that measuring sleeve 122 has become stuck in the tubing. When measuring sleeve 122 becomes stuck, drive plunger 120 continues to fall to the bottom of the well. The data obtained by the echometer can be used to confirm that drive plunger 120 is still falling within well 20 while measuring sleeve 122 has stopped.

Once drive plunger 120 reaches the bottom of well 20, control valve 36 can be opened to surface drive plunger 120. At step 214, drive plunger 120 is used to dislodge measuring sleeve 122 from tubing 30 so that both drive plunger 120 and measuring sleeve 122 are returned to the surface and removed from well 20 at step 216.

Based on the fact that measuring sleeve 122 having a given outer diameter 128 became stuck in tubing 30, it can be concluded that the maximum permissible diameter of plunger for use in well 20 is narrower than that outer diameter 128. Thus, at step 218, a new plunger having the maximum permissible diameter as determined by carrying out steps 202 to 216 can be installed in well 20. In some embodiments, the new plunger having the maximum permissible diameter comprises a venturi plunger, a brush plunger, a bar stock plunger, a bypass plunger, a ball and sleeve plunger, or a sand plunger.

At step 220, the well settings are optionally adjusted and/or documented based on the new plunger having the maximum permissible diameter. At step 222, applicable well head tags are optionally hung on the head of the well to confirm what type of plunger has been installed and/or the maximum permissible diameter of plunger that can be used in that well. In some embodiments, data logging equipment is optionally left in place for a period of time, e.g. about one week, to monitor performance of the well and ensure the new plunger having the maximum permissible diameter is functioning properly.

In some embodiments, well 20 is shut in for 1-2 days prior to carrying out method 100 or 200, to allow buildup of sufficient pressure so that drive plunger 120 and measuring sleeve 122 will fall as slowly as possible. Without being bound by theory, it is believed that if measuring sleeve 122 falls more slowly and becomes lodged in tubing 30, less upward force will need to be applied by drive plunger 120 to dislodge measuring sleeve 122 than if measuring sleeve 122 was permitted to fall rapidly within tubing 30.

In some embodiments, a kit for optimizing the production of fluid from a well is provided that includes a drive plunger 120 and a plurality of measuring sleeves 122, each one of the plurality of measuring sleeves 122 having a different outer diameter 128. In one example embodiment, such a kit includes a drive plunger having an outer diameter of 1.90″ and a plurality of measuring sleeves having outer diameters of 1.91″, 1.92″, and 1.93″, respectively, and optionally further includes measuring sleeves having larger outer diameters, e.g. 1.94″ and 1.95″. In one example embodiment, such a kit includes a drive plunger having an outer diameter of 2.34″ and a plurality of measuring sleeves having outer diameters of 2.35″, 2.36″, and 2.37″, respectively, and optionally further includes measuring sleeves having larger outer diameters, e.g. 2.38″, 2.39″ and 2.40″.

In alternative embodiments, a plunger lift gauging tool is used to carry out method 100. With reference to FIG. 6, an example embodiment of a plunger lift gauging tool 1000 is shown. Plunger lift gauging tool 1000 has an upper portion 1002. In the illustrated embodiment, upper portion 1002 is formed as external fishneck 1004, to allow retrieval and removal of plunger lift gauging tool 1000 by wireline or other conventional plunger retrieval methods in the event tool 1000 becomes stuck in a well. In alternative embodiments, an internal fishneck could be provided in place of external fishneck 1004, or an upper end with no fishneck could be used.

Tool 1000 has a base portion 1006. Interposing upper portion 1002 and base portion 1006 is at least one pad 1008. Pad 1008 comprises a spring-mounted pad typical of those used in pad plungers. The embodiment of plunger lift gauging tool 1000 illustrated in FIGS. 6 and 7 has one pad 1008, which is formed of a plurality of longitudinally aligned pad sections 1012.

In the illustrated embodiment of FIGS. 6 and 7, each pad 1008 comprises a plurality of longitudinally aligned pad sections 1012 and a pair of collars 1014. Pad sections 1012 have a curved outer circumference and a curved inner circumference, so that the plurality of longitudinally aligned pad sections 1012 define a generally cylindrical structure. Collars 1014 are provided at each of the top and bottom ends of pad 1008, to retain pad 1008 in place.

With reference to FIG. 8, which shows a side view of a plunger lift gauging tool 1000 in a disassembled configuration with the pad 1008 and measuring rings 1020 removed, the illustrated example plunger lift gauging tool 1000 has a central shaft 1010. The bottom end of central shaft 1010 has a threaded region 1018, for receiving a correspondingly threaded surface provided on the interior of base portion 1006.

With reference to FIG. 9, in the assembled configuration one or more pads 1008 (three in the illustrated embodiment, although the number could be varied, e.g. one, two, four or five) are provided on central shaft 1010. The pad sections 1012 project radially outwardly from central shaft 1010, and together provide tool 1000 with a cylindrical outer diameter, so that tool 1000 can be run in a well in the same manner as a conventional plunger. Central shaft 1010 assembled together with pads 1008 is generally similar to a typical pad plunger, which is referred to herein as a “pad plunger body”.

FIG. 10A shows a side view and FIG. 10B shows a top view of a pad 1008. As best shown in FIG. 10B, a plurality of pad sections 1012 are longitudinally aligned so that their curved outer perimeters define an outer pad perimeter 1034. Each pad 1008 also has a generally cylindrical central aperture 1036 having a generally circular cross-section, to facilitate inserting each pad 1008 onto central shaft 1010. While central shaft 1010 has been described as generally cylindrical and central aperture 1036 has been described as having a generally circular cross-section, it will be appreciated by one skilled in the art that these shapes could be varied (e.g. central shaft 1010 could have a generally triangular or square cross-section and central aperture 1036 of each pad 1008 could be provided with a corresponding generally triangular or square cross-section, respectively), so long as pads 1008 and (measuring rings 1020 as described below) can be slid onto central shaft 1010.

In the illustrated embodiment of FIGS. 6 and 7, a pair of measuring rings 1020 are provided for mounting on tool 1000. With reference to FIG. 11, an example embodiment of a measuring ring 1020 has a plurality of radially outwardly projecting tabs 1022 formed thereon. In the illustrated embodiment, measuring ring 1020 is shown as having six approximately equidistantly spaced projecting tabs 1022. However, in alternative embodiments, measuring ring 1020 could be provided with any desired number of projecting tabs, e.g. 1, 2, 3, 4, 5, 6, 7, 8, 9, 10 or more, and the projecting tabs need not be spaced equally or positioned symmetrically.

Projecting tabs 1022 extend radially outwardly from a main body 1024 of measuring ring 1020. Main body 1024 has a central aperture 1026 formed therethrough, so that measuring rings 1020 can be inserted over central shaft 1010 in use. The internal diameter 1028 of main body 1024 is shaped and configured to fit around central shaft 1010. In the illustrated embodiment, central shaft 1010 is generally cylindrical and measuring ring 1020 is formed as a generally circular disc with a circular central aperture 1026, so that measuring ring 1020 can be aligned concentrically with central shaft 1010. In some embodiments, the fit between internal diameter 1028 of measuring rings 1020 and central shaft 1010 is very tight, so that measuring rings 1020 do not easily wiggle or move with respect to central shaft 1010. In some embodiments, the internal diameter 1028 of measuring rings 1020 is sufficiently small that measuring rings 1020 effectively have to be threaded onto central shaft 1010. As outlined above with respect to central aperture 1036 of pads 1008, changes could be made to the cross-sectional shape of central shaft 1010 and central aperture 1026 of measuring ring 1020 (e.g. triangular, square, asymmetrical, etc.) so long as measuring ring 1020 can be slid onto central shaft 1010.

The outer diameter 1032 of measuring ring 1020 is defined by the outermost portions of two opposed projecting tabs 1022, as illustrated in FIG. 11. While in the illustrated embodiment, projecting tabs 1022 are illustrated as being provided in opposed pairs to define the outer diameter 1032, because the plunger lift gauging tool 1000 is positioned within the well tubing by pads 1008 as described in more detail below, it is not necessary that projecting tabs 1022 be provided as opposed pairs. That is, while the outer diameter 1032 of measuring ring 1020 is notionally defined by the distance between two opposed projecting tabs 1022 as illustrated in FIG. 11, the tabs themselves could be offset with respect to one another and still provide the same effective outer diameter 1032 by projecting outwardly with the same radius but at different locations around measuring ring 1020. Thus, in embodiments in which projecting tabs 1022 are not provided as opposed pairs, the effective outer diameter 1032 of measuring ring 1020 would be twice the value of the radius measured from the axial centre of tool 1000 to the outside edge of one projecting tab 1022. This value is included within the meaning of the term “outer diameter” as used herein.

To install pads 1008 and measuring rings 1020 on plunger lift gauging tool 1000, base portion 1006 is removed from central shaft 1010. The central aperture 1026 of each measuring ring is inserted over central shaft 1010, and the central aperture 1036 of each pad 1008 is inserted over central shaft 1010. The pads 1008 and measuring rings 1020 can be inserted in any desired number and orientation. At least one pad 1008 and one measuring ring 1020 must be provided. However, more reliable results may be achieved by using more than one measuring ring. For example, the example embodiment illustrated in FIGS. 6 and 7 has two measuring rings 1020, with one pad 1008 interposing the two measuring rings. The example embodiment illustrated in FIG. 9 has four measuring rings 1020 and three pads 1008, with one pad 1008 interposing each pair of adjacent measuring rings 1020. In alternative embodiments, one or more of the measuring rings 1020 illustrated in FIG. 6 could be omitted, to a minimum of one measuring ring 1020.

In the illustrated embodiment, at least one measuring ring 1020 is required to provide at least one projecting tab 1022. However, if projecting tab 1022 was secured to central shaft 1010 in some other manner (for example by being integrally formed therewith or directly coupled thereto), use of a measuring ring 1020 would not be required.

To maintain the positioning of plunger lift gauging tool 1000 within a tubing of a well, each pad section 1012 is spring-loaded as in a conventional pad plunger. The springs bias pad sections 1012 outwardly with respect to central shaft 1010, but also allow pad sections 1012 to be compressed inwardly towards central shaft 1010, for example if that pad section 1012 is contacted by a portion of tubing with a narrower diameter than the rest of the tubing. In this manner, pad sections 1012 can move inwardly and outwardly in response to changes in the internal diameter of the downhole tubing in which tool 1000 is operated. Pad sections 1012 are generally forced outwardly away from central shaft 1010 by the springs, so that good contact is maintained between pad sections 1012 and the tubing of the well. The outer edges of pad sections 1012 define an outside diameter of the pads (i.e. pad outer perimeter 1034) when pad sections 1012 are fully extended outwardly by the springs to their fully extended state.

This contact maintains a generally consistent vertical orientation of tool 1000 within the tubing. Maintaining a generally consistent vertical orientation of tool 1000 within the tubing helps to prevent tool 1000 from bumping laterally within the tubing, which might cause projecting tabs 1022 to be deflected even though the internal diameter of the tubing is sufficiently large to accommodate the full outer diameter 1032 of projecting tabs 1022.

FIGS. 6 and 7 show an example embodiment of a plunger lift gauging tool 1000 in which no springs are fitted inside pad 1008 (i.e. in which pad sections 1012 are in a position equivalent to their fully compressed position) for the purpose of better showing how rings 1020 are placed on tool 1000. FIG. 12 illustrates a top view of this configuration to more clearly show this configuration. In this fully compressed position, the outer diameter 1032 of projecting tabs 1022 of measuring ring 1020 is larger than the diameter of outer pad perimeter 1034. In this configuration, tabs 1022 are exposed to contact with the tubing of a well in which plunger lift gauging tool 1000 is cycled, and tabs 1022 will be deflected if they make contact with a region of the tubing.

FIGS. 13 and 14 show how pad sections 1012 are secured on central shaft 1010 in a manner known in the art. Central shaft 1010 has a plurality of radially inwardly extending depressions 1038. A corresponding plurality of radially outwardly extending depressions 1040 are provided on the inside surface of pad sections 1012, so that depressions 1038, 1040 are aligned when pad sections 1012 are assembled onto central shaft 1010. A plurality of springs 1042 are inserted within the depressions 1038, 1040, so that a spring 1042 is secured in place between central shaft 110 and pad sections 1012 within a pair of corresponding depressions 1038, 1040. Springs 1042 apply a radially outward biasing force against pad sections 1012, so that pad sections 1012 are biased to move radially outwardly in portions of the tubing that have a wider internal diameter, to thereby maintain a generally consistent orientation of plunger lift gauging tool 1000 within the tubing.

To hold pad sections 1012 in place, each pad section contains a locking receptacle 1044 on a first longitudinal edge thereof, and a locking tongue 1046 on the opposite longitudinal edge thereof. The locking tongue 1046 of a first pad section 1012 is inserted into the locking receptacle 1044 of an adjacent pad section 1012 to thereby secure pad sections 1012 onto central shaft 1010. Pad sections 1012 are further secured on central shaft 1010 by engagement of axially extending indentations 1048 formed at the transverse ends of pad sections 1012 with axially extending projections 1050 formed on collars 1014 that secure pad sections 1012 in place. FIG. 14 shows an example embodiment of a plunger lift gauging tool in which the pad sections 1012 have been pulled back from the central shaft 1010 to better illustrate how springs 1042 function to apply a radially outward biasing force against pad sections 1012.

As described above, however, in normal use, pad sections 1012 are forced outwardly by springs 1042 provided within pad 1008. The default or fully expanded state of plunger lift gauging tool, i.e. when springs 1042 are fully extended to their default position, is illustrated in FIGS. 15A and 16, where it can be seen that outer pad perimeter 1034 extends radially outwardly to a greater extent than measuring rings 1022.

In this way, the pad sections 1012 (not projecting tabs 1022) are generally in contact with the inner diameter of the tubing in which tool 1000 is run, so that inward and outward movement of spring-loaded pad sections 1012 can compensate for any changes in internal diameter of the tubing and maintain a generally vertical orientation of tool 1000. However, as pad sections 1012 are compressed inwardly by any decreases in internal diameter of the tubing, projecting tabs 1022 will become exposed to contact with the tubing, and will be deflected (i.e. bent) by making contact with the internal diameter of the tubing. That is, as pad sections 1012 move inwardly to a sufficient extent due to compression within any narrowed regions of the tubing of the well, projecting tabs 1022 will be exposed to contact with that narrowed region of tubing, and will be deflected if the outer diameter 1032 of the projecting tabs 1022 is greater than the diameter of that narrowed region of tubing. This is illustrated more clearly in FIG. 15B, in which manual pressure has been applied to compress springs 1042, so that the outer edges of the pad sections 1012 are radially inward of projecting tabs 1022. Thus, as the internal diameter of the tubing narrows, pad sections 1012 are compressed radially inwardly, and projecting tabs 1022 become exposed to contact with the internal diameter of the tubing, which causes projecting tabs 1022 to be bent or deflected.

In use, a user inserts plunger lift gauging tool 1000 into the tubing of a gas producing well when the well is shut-in, as is conventional in the operation of plunger lift tools. When the well is shut-in, plunger lift gauging tool 1000 falls to the bottom of the well under the force of gravity. When the well is moved to the open configuration, plunger lift gauging tool 100 is lifted back to the surface under the force of sufficient gas pressure, in the same manner as a conventional plunger. Unlike a conventional plunger, which is cycled repeatedly within a well, typically plunger lift gauging tool 1000 is cycled only once within the well.

As plunger lift gauging tool 1000 travels through the tubing of the well, projecting tabs 1022 contact and are bent by any regions of the tubing that have a narrower diameter than the outer diameter 1032 of measuring ring 1020. Thus, after plunger lift gauging tool 100 has been cycled through the well, manual inspection of projecting tabs 1022 provides a visual indication of whether a plunger having a diameter corresponding to the outer diameter 1032 of measuring ring 1020 can be used in that particular well.

In particular, if none of projecting tabs 1022 are bent or deformed after plunger lift gauging tool 1000 has been cycled through the well, a plunger having a diameter at least as large as the outer diameter 1032 of measuring ring 1020 can be used in that well. If one or more of projecting tabs 1022 are bent or deformed after plunger lift gauging tool 1000 has been cycled through the well, a plunger having a diameter as large as the outer diameter 1032 of measuring ring 1020 cannot be used in that well, and is likely to become stuck in the tubing if used. In such a situation, an operator may choose to mount a measuring ring 1020 having a smaller outer diameter 1032 on plunger lift gauging tool 1000 and cycle the tool 1000 through the well again, to see if the well will accommodate a plunger having the same diameter as the measuring ring 1020 with the smaller outer diameter 1032.

Suitable outer diameters 1032 of the measuring rings 1020 to be selected for use with tool 1000 depend on the anticipated diameter of the tubing of the well into which tool 1000 is to be inserted. A typical well tubing has a diameter of 2″, although drifting of the tubing (i.e. flaring of the ends of the tubing at the joints during construction of the well) and buildup of waxes or other substances within the tubing can result in local variations in the diameter of the tubing of any given well. In a typical well, the tubing will have an internal diameter of at least 1.90″ but less than 1.995″. In some embodiments of plunger lift gauging tool 1000 intended for use with such wells, measuring rings 1020 are provided with a range of outer diameters 1032 in the range of 1.91″ to 1.95″, including any value therebetween, e.g. 1.92″, 1.93″ or 1.94″. Such measuring rings 1020 are useful for wells having tubing with an internal diameter of 2″. It will be appreciated that measuring rings 1020 having different ranges of outer diameters 1032 should be used for wells having a tubing with an internal diameter other than 2″, and such measuring rings 1020 fall within the scope of some embodiments of the present invention. Also, in some embodiments intended for use in wells with tubing having an internal diameter of 2″, smaller diameters could be used, e.g. 1.85″, 1.86″, 1.87″, 1.88″, 1.89″ or 1.90″, so e.g. any range between 1.85″ and 1.94″.

In some embodiments, plunger lift gauging tool 1000 is cycled within a given well multiple times, and the outer diameter 1032 of the measuring ring or rings 1020 provided on plunger lift gauging tool is changed between each cycle in order to determine the maximum permissible diameter of plunger that can be used in that given well with a minimal likelihood that the plunger will become trapped in a region of the tubing with a lower effective diameter than the remainder of the tubing. This is the diameter of plunger that is likely to provide the most efficient plunger lift for that particular well. For example, a user may initially provide a plunger lift gauging tool 1000 with one or more measuring rings 1020 having an outer diameter 1032 of 1.94″. If one or more projecting tabs 1022 is deflected after that tool 1000 has been cycled through the well once on this first cycle, a user may remove the pads 1008 and measuring rings 1020 from tool 1000 by unthreading base portion 1006 and sliding pads 1008 and measuring rings 1020 off of central shaft 1010.

A user may then insert one or more measuring rings 1020 having a narrower outer diameter 1032, for example 1.92″, onto central shaft 1010 and insert one or more pads 1008 onto central shaft 1010, threadably engage base portion 1006 onto threaded region 1018 of central shaft 1010 so that tool 1000 is in the assembled configuration, and cycle the tool 1000 through the well again for a second cycle. If none of the projecting tabs 1022 are deflected on the second cycle of tool 1000, a user may repeat this process of disassembling and reassembling tool 1000 using one or more measuring rings 1020 having an outside diameter 1032 intermediate between that used in the first and second cycle, for example 1.93″ in this example embodiment.

The user may then cycle tool 1000 through the well again for a third cycle. If any of the projecting tabs 1022 are deflected on the third cycle, a user would know that the largest diameter of plunger that should be used in the well is 1.92″. In contrast, if none of the projecting tabs 1022 are deflected on the third cycle, a user would know that the largest diameter of plunger that should be used in the well is 1.93″. Selection of the largest possible plunger diameter in this manner can help a user select a plunger diameter that is likely to give the most effective artificial lift within the well, particularly in the case of venturi plungers which have an internal orifice through which gas and fluid can pass (in addition to the passage of gas and fluid past the outside diameter of the plunger, as occurs to some extent for all plungers).

It will be clear to those skilled in the art that the exact order in which the outer diameter 1032 of measuring ring(s) 1020 on plunger lift gauging tool 1000 is varied is not critical. Also, the number of different outer diameters 1032 that are tested is not critical, although testing a wider range of diameters will allow a user to make a more precise determination of the maximum permissible diameter of plunger that should be used in a particular well. For example, a user could carry out only one cycle of plunger lift gauging tool 1000 having a first outer diameter 1032. If none of the projecting tabs 1022 are deflected, a user will know that a plunger having a diameter generally the same as the first outer diameter 1032 can be used in the well with a low likelihood of becoming stuck in the tubing, although it would be possible that a larger diameter plunger could be used. By conducting additional measurements using a plurality of different outer diameters 1032, a better assessment of the maximum diameter of plunger that can be used in the well can be made.

In some embodiments, the determination of what size of outer diameter 1032 of measuring ring 1020 to use initially within a given well is made based on an objective evaluation of the likely internal diameter of the tubing of that given well. For example, an older well is likely to have a narrower internal diameter of the tubing. A well with known issues (i.e. known narrow regions of tubing discovered in previous operations) will also be likely to have a narrower internal diameter of the tubing.

In some embodiments, two or more measuring rings 1020 having different outer diameters 1032 could be installed on a single plunger lift gauging tool 1000. In some cases, the projecting tabs 1022 on the measuring ring 1020 having the larger outer diameter 1032 might be deflected, while the projecting tabs 1022 on the measuring ring having the smaller outer diameter 1032 might not be deflected. This would tell the user of tool 1000 that a plunger having a diameter smaller than the outer diameter 1032 of the measuring ring 1020 but at least as large as the smaller outer diameter 1032 should be used in the well. While such an approach might allow a user to determine with only one cycle of tool 1000 what diameter of plunger can be used within the well, it is believed that more reliable results may be obtained by conducting multiple cycles of a plunger lift gauging tool 1000 having one or more measuring rings 1020 having the same outer diameter 1032 on each individual cycle, as in the example embodiment described above.

In some embodiments, a kit for determining what size of plunger should be used in a well is provided. The kit has a plunger lift gauging tool 1000 with removable measuring rings 1020 and pads 1008 as described above. The kit includes a plurality of different measuring rings 1020 having a plurality of different outer diameters 1032, so that an operator can iteratively mount different-sized measuring rings 1020 on plunger lift gauging tool 1000 to determine the maximum size of plunger that can likely be used within a given well.

While in the example embodiments described herein projecting tabs 1022 have been described as being provided on measuring rings 1020 to facilitate easily changing the outer diameter 1032 thereof, projecting tabs extending outwardly to a desired outer diameter 1032 can be provided affixed to any suitable component of a pad plunger body. For example, one or more projecting tabs 1022 could be mounted to upper portion 1002 or base portion 1006 of plunger lift gauging tool 1000, or one or more projecting tabs 1022 could be affixed to central shaft 1010 and pads 1008 clamped around central shaft 1010, rather than being slid thereon.

Suitable materials for the manufacture of plunger lift gauging tool 1000 can be selected by those skilled in the art. Central shaft 1010 and pad sections 1012 are typically made from a rigid metallic material, as is known in the art of plunger construction. In some embodiments, measuring rings 1020 are made from a malleable material having good mechanical strength so that measuring rings 1020 can be deflected or otherwise bent by contact with a tubing of a well and retain that deflection or bend so that it can be identified by a visual inspection when tool 1000 is removed from the well. In some embodiments, measuring rings 1020 are made from a metallic material, for example aluminum or brass. The materials used in the construction of plunger lift gauging tool 1000 should be resistant to corrosion and any chemicals or fluids with which tool 1000 may come into contact with in a well.

EXAMPLES

Some embodiments of the present invention are further described with reference to the following examples, which are intended to be illustrative and not limiting in nature.

Example 1.0 Lab Well Test Model

The first phase of work done involved a laboratory well test model. Testing was carried out using plungers having varying outer diameters to better understand how the tools behaved in the well model. Data was collected with various outer diameter sizes of downhole plungers. To test the plungers with the larger diameters, the inventor used a full scale well model which consists of conventionally sized tubing having an inner diameter of 2″, a water pump and an air compressor. The amount of water pumped into the well model can be adjusted, and the air flow can be adjusted to simulate real life situations in gas wells. Four different Venturi plungers were used for testing: a conventional Venturi plunger having an outer diameter of 1.90″, and three Venturi plungers having larger outer diameters of 1.91″, 1.92″ and 1.93″, respectively.

The plungers were floated at three different heights (1.0 m, 2.0 m and 3.0 m) in the tubing, and the flow rate, pressure and temperature were recorded. The effect of the different outer diameters of the plungers on the amount of flow and pressure it took to hold it in one position was recorded. Three trials were conducted for each plunger.

The results were quite similar at all three heights, giving a consistent result for the flow required to support each plunger. At all three heights it took approximately 13% less flow to float a plunger having an outer diameter of 1.91″, 21% less flow to float a plunger having an outer diameter of 1.92″, and 32% less flow to float a plunger having an outer diameter of 1.93″, as compared with a standard reference plunger having an outer diameter of 1.94″. Results of these experiments are shown in Table 1.

TABLE 1 Results for Lab Testing of Different Plunger Outer Diameters. Flow Rate: MCF Pressure: kpa 1.00 m 2.00 m 3.00 m Temp: deg celsius Flow Rate Pressure Temp Flow Rate Pressure Temp Flow Rate Pressure Temp Trial 1 New Venturi 1.93″ short 28.5 17.6 19.1 32.7 17.6 19.1 35.4 18 19 New Venturi 1.92″ short 33.3 17.2 19.5 57.9 17.8 19.6 41.3 18.6 19.0 New Venturi 1.91″ short 39.5 19.3 20.8 41.8 18.4 20.5 44.7 20.2 20 New Venturi 1.90″ short 45.3 19.7 20.1 49.1 19.7 20.2 51.6 19.6 20.1 Trial 2 New Venturi 1.93″ short 30.8 17.2 18.8 32.9 10 18.8 37.1 17.6 18.5 New Venturi 1.92″ short 36.7 15.4 19.5 39.4 17.2 19.1 42 18.0 19.3 New Venturi 1.91″ short 39.3 18.2 19.5 43.4 18.8 19.1 45.1 19.6 19.1 New Venturi 1.90″ short 45.8 19.8 20 48.9 19.8 20.1 51.5 19.7 20.1 Trial 3 New Venturi 1.93″ short 30.1 15.1 18.3 32.8 16.3 18.3 37.2 10.8 18.2 New Venturi 1.92″ short 35.4 18.8 19.6 39.1 17.2 19.4 41.9 18.2 19.4 New Venturi 1.91″ short 39.3 18.3 19.6 43.3 18.9 19.3 43.2 19.5 19.5 New Venturi 1.90″ short 45.6 19.6 19.9 48.7 19.8 20.2 51.4 19.8 19.9

Example 2.0 Field Testing

Following completion of lab tests, field tests were conducted on producing gas wells. The procedure on plunger lift wells in the field was as follows:

    • Remove existing plunger;
    • Perform acoustic fluid test to establish baseline parameters;
    • Drop and track drive plunger and measuring sleeve starting with the smallest diameter measuring sleeve;
    • Perform acoustic fluid test after each measuring sleeve run;
    • Continue sizing process with larger plunger outer diameter intervals;
    • Hang applicable well head tags confirming the well has been gauged to run a specific plunger size;
    • Adjust and document new well control system parameters based on tool selection;
    • Completion of well follow up process.

TABLE 2 Results of Field Testing of Maximum Plunger Outer Diameter. Previous New Daily Daily Gas Gas Increased Original Oversize Prod. Prod. Gas Prod. Increased Lift Venturi Lift Lift 10″ Long Well e3m3/ e3m3/ e3m3/ Gas Pressure Pressure Pressure Original Plunger Venturi Location Day Day Day Prod. % (Kpa) (Kpa) Decrease % Type O.D. 1 1.850 2.340 0.49 26% 360 330 8% Venturi Steel 1.920 4.7 mm 2 2.400 2.660 0.26 11% 425 310 27% Solid Ring 1.910 3 2.940 2.940 0.00 0% 460 400 13% Fishbone 1.920 4 2.620 2.870 0.25 10% 390 310 21% Solid Ring 1.900 5 2.410 3.000 0.59 24% 450 400 11% Solid Ring 1.920 6 3.970 5.010 1.04 26% 510 460 10% Solid Ring 1.910 7 1.580 1.710 0.13 8% 490 400 18% Venturi Steel 1.910 4.7 mm 8 1.770 2.330 0.56 32% 480 300 38% 12″ Solid Ring 1.900 9 1.470 1.490 0.02 1% 470 400 15% Dual Pad 1.910 10 0.830 1.050 0.22 27% 520 400 23% Solid Ring 1.910 11 4.110 4.550 0.44 11% 490 300 39% Solid Ring 1.920 12 2.750 4.600 1.85 67% 510 400 22% Venturi Long Steel 1.930 L80 4.7 mm 13 4.040 6.500 2.46 61% 500 400 20% Venturi Steel L80 1.930 4.7 mm 14 5.230 5.800 0.57 11% 520 400 23% Venturi Steel L80 1.930 4.7 mm 15 1.630 2.000 0.37 23% 560 500 11% Venturi Steel L80 1.910 4.7 mm 16 4.380 5.600 1.22 28% 490 400 18% Venturi Steel L80 1.920 4.7 mm 17 5.820 6.200 0.38 7% 590 500 15% Venturi Long Steel 1.930 L80 4.7 mm 18 2.190 3.000 0.81 37% 470 400 15% Venturi Long Steel 1.920 L80 4.7 mm 19 3.400 3.400 0.00 0% 490 280 43% Venturi Steel L80 1.930 4.7 mm 20 5.470 6.100 0.63 12% 500 435 13% Venturi Long Steel 1.910 L80 4.7 mm 21 1.860 2.100 0.24 13% 550 360 35% Venturi Long Steel 1.910 L80 4.7 mm 22 1.350 1.500 0.15 11% 550 295 46% Venturi Steel L80 1.920 4.7 mm 23 4.180 4.700 0.52 12% 450 405 10% Venturi Steel L80 1.930 4.7 mm 24 1.130 1.300 0.17 15% 420 290 31% Venturi Long Steel 1.920 L80 4.7 mm 25 4.300 5.180 0.88 20% 420 290 31% Venturi Long Steel 1.930 L80 4.7 mm

The results of this experiment demonstrate that the use of a plunger having the maximum permissible diameter can potentially considerably enhance the production of fluid from a well.

While a number of exemplary aspects and embodiments are discussed herein, those of skill in the art will recognize certain modifications, permutations, additions and sub-combinations thereof. To the extent that they are not mutually exclusive, features of the embodiments described herein can be combined with features of other embodiments to yield additional embodiments of the invention. It is therefore intended that the following appended aspects and claims and claims hereafter introduced are to be given the broadest interpretation consistent with the specification as a whole.

Claims

1. A method of enhancing fluid production from a well, the method comprising the steps of:

(a) evaluating whether a downhole plunger having a first outer diameter can travel freely within a tubing of the well by (i) dropping a drive plunger and a measuring sleeve within the tubing of the well, the measuring sleeve having the first diameter and the drive plunger having a diameter less than the first diameter and being positioned below the measuring sleeve in the tubing; (ii) if the measuring sleeve becomes lodged in the tubing, concluding that a downhole plunger having the first outer diameter cannot travel freely within the tubing of the well and using the drive plunger to dislodge and surface the measuring sleeve; or (iii) if the measuring sleeve does not become lodged in the tubing, concluding that a downhole plunger having the first outer diameter can travel freely within the tubing of the well;
(b) if the downhole plunger having the first outer diameter can travel freely within the tubing of the well, evaluating whether a downhole plunger having a second outer diameter that is larger than the first outer diameter can travel freely within the tubing of the well by repeating steps (i), (ii) and (iii) using a measuring sleeve having the second outer diameter; and
(c) if the downhole plunger having the second outer diameter cannot travel freely within the tubing of the well, installing a downhole plunger having the first outer diameter in the well and performing artificial lift using the downhole plunger having the first outer diameter.

2. The method as defined in claim 1, further comprising the steps of:

(d) if the downhole plunger having the second outer diameter can travel freely within the tubing of the well, evaluating whether a plunger having a third outer diameter that is larger than the second outer diameter can travel freely within the tubing of the well by repeating steps (i), (ii) and (iii) using a measuring sleeve having the third outer diameter; and
(e) if the downhole plunger having the third outer diameter cannot travel freely within the tubing of the well, installing a downhole plunger having the second outer diameter in the well and performing artificial lift using the downhole plunger having the second outer diameter.

3. The method as defined in claim 2, further comprising the steps of:

(f) if the downhole plunger having the third outer diameter can travel freely within the tubing of the well, evaluating whether a plunger having a fourth outer diameter that is larger than the third outer diameter can travel freely within the tubing of the well by repeating steps (i), (ii) and (iii) using a measuring sleeve having the fourth outer diameter; and
(g) repeating step (f) as required for downhole plungers having successively larger outer diameters until the largest plunger diameter that can travel freely in the well has been determined, and installing a downhole plunger having the largest plunger diameter that can travel freely in the well in the well and performing artificial lift using the downhole plunger having the largest plunger diameter that can travel freely in the well.

4. A method of enhancing fluid production from a well, the method comprising the steps of:

(a) evaluating whether a downhole plunger having a first outer diameter can travel freely within a tubing of the well by (i) dropping a drive plunger and a measuring sleeve within the tubing of the well, the measuring sleeve having the first diameter and the drive plunger having a diameter less than the first diameter and being positioned below the measuring sleeve in the tubing; (ii) if the measuring sleeve becomes lodged in the tubing, concluding that a downhole plunger having the first outer diameter cannot travel freely within the tubing of the well and using the drive plunger to dislodge and surface the measuring sleeve; or (iii) if the measuring sleeve does not become lodged in the tubing, concluding that a downhole plunger having the first outer diameter can travel freely within the tubing of the well;
(b) if the downhole plunger having the first outer diameter cannot travel freely within the tubing of the well, evaluating whether a downhole plunger having a second outer diameter that is smaller than the first outer diameter can travel freely within the tubing of the well by repeating steps (i), (ii) and (iii) using a measuring sleeve having the second outer diameter; and
(c) if the downhole plunger having the second outer diameter can travel freely within the tubing of the well, installing a downhole plunger having the second outer diameter in the well and performing artificial lift using the downhole plunger having the second outer diameter.

5. A method as defined in claim 4, further comprising the steps of:

(d) if the downhole plunger having the second outer diameter cannot travel freely within the tubing of the well, evaluating whether a downhole plunger having a third outer diameter that is smaller than the second outer diameter can travel freely within the tubing of the well by repeating steps (i), (ii) and (iii) using a measuring sleeve having the third outer diameter; and
(e) if the downhole plunger having the third outer diameter can travel freely within the tubing of the well, installing a plunger having the third outer diameter in the well and performing artificial lift using the downhole plunger having the third outer diameter.

6. A method as defined in claim 5, further comprising the steps of:

(f) if the downhole plunger having the third outer diameter cannot travel freely within the tubing of the well, evaluating whether a plunger having a fourth outer diameter that is smaller than the third outer diameter can travel freely within the tubing of the well by repeating steps (i), (ii) and (iii) using a measuring sleeve having the fourth outer diameter; and
(g) repeating step (f) as required for downhole plungers having successively smaller outer diameters until the largest plunger diameter that can travel freely in the well has been determined, and installing a downhole plunger having the largest plunger diameter that can travel freely in the well in the well and performing artificial lift using the downhole plunger having the largest plunger diameter that can travel freely in the well.

7. The method as defined in claim 1, wherein the movement of the drive plunger or the measuring sleeve within the tubing is monitored using an echometer.

8. A method of determining the maximum permissible diameter for a downhole plunger that can be used in a well, the method comprising the steps of:

evaluating a plurality of different plunger outer diameters to determine whether plungers having at least two of the plurality of different plunger outer diameters can travel freely in a tubing of the well by repeating, for the plurality of different plunger outer diameters, the steps of (i) selecting a first one of the plurality of different plunger outer diameters for analysis; (ii) dropping a drive plunger and a first measuring sleeve within the tubing of the well, the first measuring sleeve having the first one of the plurality of different plunger outer diameters, and the drive plunger having a diameter that is smaller than the first one of the plurality of different plunger outer diameters and being positioned below the first measuring sleeve in the tubing; (iii) if the first measuring sleeve becomes lodged in the tubing, concluding that a downhole plunger having the first one of the plurality of different plunger outer diameters cannot travel freely within the tubing of the well and using the drive plunger to dislodge and surface the first measuring sleeve; or (iv) if the first measuring sleeve does not become lodged in the tubing, concluding that a downhole plunger having the first one of the plurality of different plunger outer diameters can travel freely within the tubing of the well; and
concluding that the maximum permissible diameter for a downhole plunger that can be used in the well is equal to the largest one of the plurality of different plunger outer diameters that will still allow a plunger to travel freely in the well.

9. The method as defined in claim 8, comprising repeating the steps of dropping a drive plunger and a measuring sleeve having one of the plurality of different plunger outer diameters within the tubing of the well for as many of the plurality of different plunger outer diameters as is required to determine the maximum permissible diameter for a downhole plunger that can be used in the well.

10. The method as defined in claim 8, wherein the movement of the drive plunger or the measuring sleeve within the tubing is monitored using an echometer.

11. A method of determining whether a downhole plunger having a first outer diameter can travel freely within a well, the method comprising the steps of:

dropping a drive plunger in a tubing of the well below a measuring sleeve, the measuring sleeve having an outer diameter equal to the first outer diameter and the drive plunger having an outer diameter smaller than the first outer diameter;
allowing the drive plunger and the measuring sleeve to fall in the tubing; and
if the measuring sleeve becomes lodged in the tubing, concluding that a downhole plunger having the first outer diameter cannot travel freely within the well and using the drive plunger to dislodge and surface the measuring sleeve; or
if the measuring sleeve does not become lodged in the tubing, concluding that a downhole plunger having the first outer diameter can travel freely within the well.

12. The method as defined in claim 11, comprising surfacing both the measuring sleeve and the plunger if the measuring sleeve does not become lodged in the tubing.

13. The method as defined in claim 11, further comprising monitoring movement of the drive plunger or the measuring sleeve using an echometer.

14. An apparatus for determining the maximum permissible outer diameter of downhole plunger that can be used in a well, the apparatus comprising:

a measuring sleeve comprising a generally cylindrical outer shell defining an outer diameter and a hollow interior defining a fluid path through the measuring sleeve; and
a drive plunger having an outer diameter smaller than the measuring sleeve for surfacing the measuring sleeve if the measuring sleeve becomes lodged in the tubing.

15. An apparatus as defined in claim 14, wherein the drive plunger comprises a venturi plunger or a pad plunger.

16. A kit comprising a drive plunger and a plurality of measuring sleeves, each one of the plurality of measuring sleeves comprising a different outer diameter.

17. A kit as defined in claim 16, wherein the drive plunger has an outer diameter of 1.90″, and wherein the plurality of measuring sleeves comprise measuring sleeves having outer diameters of 1.91″, 1.92″ and 1.93″.

18. A kit as defined in claim 17, wherein the plurality of measuring sleeves further comprise measuring sleeves having outer diameters of 1.94″ and 1.95″.

19. A kit as defined in claim 16, wherein the drive plunger has an outer diameter of 2.34″, and wherein the plurality of measuring sleeves comprise measuring sleeves having outer diameters of 2.35″, 2.36″ and 2.37″.

20. A kit as defined in claim 19 wherein the plurality of measuring sleeves further comprises measuring sleeves having outer diameters of 2.38″, 2.39″ and 2.40″.

21. A kit as defined in claim 16, wherein the drive plunger comprises a venturi plunger or a pad plunger.

22. A kit as defined in claim 16, wherein a minimum internal diameter of each one of the plurality of measuring sleeves along its length comprises at least 1″.

23. A kit as defined in claim 16, further comprising an echometer.

Patent History
Publication number: 20180328166
Type: Application
Filed: May 4, 2018
Publication Date: Nov 15, 2018
Inventor: Rick NADKRYNECHNY (Grande Prairie)
Application Number: 15/971,838
Classifications
International Classification: E21B 47/08 (20060101); E21B 43/12 (20060101);