Apparatus and method for monitoring a geothermal environment

Abstract

The embodiments of the present disclosure relate to an apparatus and a method for monitoring a feature of a downhole environment. The apparatus and the method translate a change in amplitude of the feature into a mechanical movement that causes a reporting event. Some embodiments of the present disclosure relate to an apparatus that comprises a body that is positionable within a wellbore, a marker carrier that is operatively coupled to one end of the body, the marker carrier is configured to carry multiple markers; and a moveable component that is operatively coupled to the body and to the marker carrier, the moveable component is moveable under an influence of a feature of the wellbore environment such that when the moveable body moves a predetermined distance, a first marker is released from the carrier.

Description

APPARATUS AND METHOD FOR MONITORING A GEOTHERMAL ENVIRONMENT TECHNICAL FIELD

[0001] This disclosure generally relates to operations that occur within a geothermal well. In particular, this disclosure relates to an apparatus and a method of monitoring operating conditions within a geothermal well.BACKGROUND

[0002] Wells are drilled into subterranean geologic formations to access and produce a desired product from the geologic formation. The life of a well includes various stages, such as: exploration for geologic formations that contain the desired product, planning a well, drilling the well, working over the well, producing the desired products and abandoning the well. Non-limiting examples of such desired products include: oil, gas, geothermally-heated fluids and the like.

[0003] Inter-connected tubulars can be inserted into the drilled well. Each tubular may be referred to as pipe, tubing, casing and / or liner and the inter-connected tubulars may be referred to as a pipe string, a tubing string, a casing string and / or a liner string. Sections of tubulars can be secured in place within the well, for example by cement. Once secured, portions of the tubulars can optionally be perforated in order to establish fluid communication between inside the tubular and the geological formation that contains the desired product. In some instances, portions of the tubular are inserted into the well already perforated.

[0004] Once drilled, a well may require one or more downhole components in order to facilitate and / or enhance further well operations, such as devices for monitoring the operating conditions within one or more sections of the well.

[0005] Within geothermal wells, the operating conditions include very high temperatures, sometimes reaching 400°C, 500°C or higher. These operating conditions can be monitored using fiber-optic cables connected to downhole sensors or other electronic -based downhole devices.

[0006] Fiber-optic cables can conduct sensory information from the downhole environment back to the users at the surface. However, fiber-optic cables are very expensive and they can be cut or otherwise damaged during well operations, which can leave the downhole sensors without power and without the ability to transmit sensory information back to the surface.

[0007] Other downhole devices, such as battery powered sensors are also known and used to monitor the downhole environment in a well. However, the downhole environment has very high temperatures, which can cause an issue with electronic devices. Commercially available electronic devices typically do not work as intended above 250°C. Furthermore, when batteries are used as a power source, the batteries often have a maximum temperature range in which they operate as intended. For example, typical commercially available batteries do not operate properly (or at all) above about 180°C. As such, many downhole environments are at temperatures that exceed the working range of typical batteries.

[0008] Some known approaches for addressing the discrepancy between the high temperature environment found downhole in well and the thermal limits of electronic devices and battery power sources include using chilled drilling mud and insulated drill pipe to cool and insulate the electronic devices used during drilling operations. This approach is not applicable once drilling of the geothermal well is completed when the drilling mud, chilled or otherwise, and the insulated drill pipe are no longer available.

[0009] A further known approach for addressing the thermal limits of electronic devices and battery power sources is to insulate the electronic devices and the battery -for example, within a vacuum flask, also known as a Dewar flask. However, when an electronic device is desired to be used downhole for an extended time period, such as many months or years, the thermal insulation provided by vacuum flask is insufficient as thermal energy generated while operating the electronic device and the battery will accumulate in the flask over the extended time periods.

[0010] As such, it may be desirable to provide alternatives for monitoring the operating conditions of a geothermal well that will function as intended even when exposed to a high-temperature downhole environment for extended time periods.SUMMARY

[0011] The embodiments of the present disclosure relate to an apparatus and a method of monitoring the operating conditions of a geothermal well for extended periods of time at high temperatures.

[0012] Some embodiments of the present disclosure relate to an apparatus for monitoring a wellbore environment. The apparatus comprises: a body that is positionable within a wellbore, a marker carrier that is operatively coupled to one end of the body, the marker carrier is configured to carry multiple markers; and a moveable component that is operatively coupled to the body and to the marker carrier, the moveable component is moveable under an influence of a feature of the wellbore environment such that when the moveable body moves a predetermined distance, a first marker is released from the carrier.

[0013] In some embodiments of the present disclosure that relate to the apparatus, the feature of the wellbore environment is a temperature of wellbore fluids. In these embodiments the moveable component is a first chamber and a second chamber, with a chemical component housed within the first chamber and a second chemical component that is housed in the second chamber. The first chemical component will expand or contract at a given wellbore fluid temperature differently than the second chemical component within the second chamber.

[0014] In some embodiments of the present disclosure that relate to the apparatus, the feature of the wellbore environment is a pressure of wellbore fluids. In these embodiments, the moveable component is a piston assembly that moves when the pressure of the wellbore fluid exceeds a biasing force of a biasing member that is positioned between a piston housing and a portion of the body.

[0015] In some embodiments of the present disclosure that relate to the apparatus, the feature of the wellbore environment is a fluid flow rate of wellbore fluids. In these embodiments, the moveable component is a shiftable sleeve that defines a shaped orifice at a first end of the shiftable sleeve. The shiftable sleeve moves when the wellbore fluids flowing through the shaped orifice establish a pressure differential that exceeds a biasing force of a biasing member positioned between a second end of the shiftable sleeve and a shoulder of the body.

[0016] Some embodiments of the present disclosure relate to a method for monitoring a wellbore environment. The method comprises the steps of: providing an apparatus within a wellbore, where the apparatus comprises a moveable component that is operatively coupled to a marker carrier that carries multiple markers and a moveable component; configuring the moveable component to move a predetermined distance based upon a predetermined change in a feature of the wellbore environment; and releasing a predetermined number and / or type of markers into the wellbore based upon the predetermined distance that the moveable component moved.

[0017] Without being bound by any particular theory, the embodiments of the present disclosure relate to an apparatus and method for monitoring the operating conditions - such as temperature, fluid pressure or flow rates - of a geothermal well by non-electronic approaches (i.e. avoiding electronic devices), which in turn avoids reliance on electronic components and power sources that are susceptible to failure when exposed to the high operating temperatures of a geothermal well for extended periods of time.

[0018] Some embodiments of the present disclosure relate to an apparatus and a method that translates a change in an amplitude of a feature of an operational environment of a wellbore into a predetermined mechanical change, where such predetermined mechanical changes cause a specific reporting event to occur. The specific reporting event is retrievable at or near the surface of the wellbore and can be interpreted to indicate the amplitude of the change in the feature being monitored downhole within the wellbore.BRIEF DESCRIPTION OF THE DRAWINGS

[0019] These and other features of the present disclosure will become more apparent in the following detailed description in which reference is made to the appended drawings.

[0020] FIG. 1 shows a side elevation, mid-line cross-sectional view of an apparatus in a first operational position, according to embodiments of the present disclosure.

[0021] FIG. 2 shows a side elevation, mid-line cross-sectional view of the apparatus of FIG. 1 in a second operational position, according to embodiments of the present disclosure.

[0022] FIG. 3 shows a side elevation, mid-line cross-sectional view of the apparatus of FIG. 1 in a further operational position, according to embodiments of the present disclosure.

[0023] FIG. 4 shows a side elevation, mid-line cross-sectional view of the apparatus of FIG. 1 in a further operational position, according to embodiments of the present disclosure.

[0024] FIG. 5 shows a side elevation, mid-line cross-sectional view of the apparatus of FIG. 1 in a further operational position, according to embodiments of the present disclosure.

[0025] FIG. 6 shows a side elevation, mid-line cross-sectional view of the apparatus of FIG. 1 in a further operational position, according to embodiments of the present disclosure.

[0026] FIG. 7 shows a side elevation, mid-line cross-sectional view of a marker housing and release mechanism of another apparatus in a first operational position, according to embodiments of the present disclosure.

[0027] FIG. 8 shows a side elevation, mid-line cross-sectional view of the mechanism of FIG. 7 in a further operational position, according to embodiments of the present disclosure.

[0028] FIG. 9 shows a side elevation, mid-line cross-sectional view of the mechanism of FIG. 7 in a further operational position, according to embodiments of the present disclosure.

[0029] FIG. 10 shows a side elevation, mid-line cross-sectional view of an anchor mechanism and a seal mechanism for use with the apparatus of FIG. 1 in a first operational position, according to embodiments of the present disclosure.

[0030] FIG. 11 shows a side elevation view of the anchor mechanism and the seal mechanism of FIG. 10 in a further operational position, according to embodiments of the present disclosure.

[0031] FIG. 12 shows a side elevation view of the anchor mechanism and the seal mechanism of FIG. 10 in a further operational position, according to embodiments of the present disclosure.

[0032] FIG. 13 shows a marker carrier, according to embodiments of the present disclosure, wherein FIG. 13A is an upper panel that provides an isometric view, FIG.13B is a middle panel that provides a side elevation view; and, FIG. 13C is a lower panel that provides a mid-line cross-sectional view taken along line A-A of FIG. 13B.

[0033] FIG. 14 is a schematic that represents the steps of a method for translating a change of a monitored feature of a downhole environment into a mechanical change and the release of a predetermined marker or markers.DETAILED DESCRIPTION

[0034] The embodiments of the present disclosure relate to an apparatus and a method for monitoring operating conditions within a well.

[0035] Some embodiments of the present disclosure relate to an apparatus that is configured to physically respond to one or more features of the operating conditions inthe well, where such physical response is a mechanical change in an operating position of the apparatus and the change in operating position results in the apparatus initiating a reporting event that is detectible at or near the surface of the well. The apparatus does not include (i.e. is without) any electronic components or any power supply that is susceptible to the high temperature environment present downhole in a well.

[0036] Some embodiments of the present disclosure relate to a method that comprises the steps of: physically responding to one or more features of the operating conditions; altering the operating position of an apparatus; and, initiating a reporting event, where such reporting event is detectable at or near the surface of the well. The method does not rely on any electronic components or any power supply that is susceptible to the high temperature environment present downhole in a well.

[0037] As used herein, the term “about” when used in reference to a given value refers to an approximately + / -10% variation from a given value. It is to be understood that such a variation is always included in any given value provided herein, whether or not it is specifically referred to.

[0038] Embodiments of the present disclosure will now be described by reference to the figures, which show representations of the apparatus, systems and methods according to the present disclosure.

[0039] Referring to FIG. 1, an apparatus 10 is shown installed in a wellbore 2 that is either open hole or lined with string of tubulars, such as casing or liner. The wellbore 2 may be of an oil well, a gas well, a geothermal well, or any other well for the purpose of injecting or producing (i.e. recovering) desired products. The apparatus 10 is generally tubular with a central bore 4 through which fluids may flow between a second end 10A and a first end 10B, where the ends 10A, 10B define a longitudinal axis of the apparatus 10 therebetween. As will be appreciated by those skilled in the art, the first end 10A may be the end from which fluid flows towards the apparatus 10 or not. The apparatus 10 comprises an inner body 12, a lower chamber wall 24, an upper chamber wall 26 and an outer body 13. For clarity, the term “wall” may be used herein interchangeably with the term “barrier”. The apparatus 10 also comprises a centralizer16 that is operatively coupled to the second end of the inner body 12 and a top adapter assembly 14 that is operatively coupled to the first end of the inner body 12. The apparatus 10 comprises a marker carrier 20 that is operatively coupled about the inner body 12 proximal the second end. Together the lower chamber wall 24, a central wall 32 and the outer body 13 define a first chamber 28. The first chamber 28 contains a first chemical composition that may be in a fluid phase when the apparatus 10 is in a downhole environment. Together the upper chamber wall 26, the central wall 32 and the outer body 13 define a second chamber 30. The second chamber 30 contains a second chemical composition that may be in a fluid phase when the apparatus 10 is in a downhole environment. The first and second chemicals are contained within their respective chambers 28, 30 by a series of seals 34 positioned between the walls 24, 26, 32 and the outer body 13. The initial volumes and pressures of the chambers may or may not be equal to provide the desired mechanical movement characteristics. The initial geometry of the chambers may or may not be symmetrical to provide the desired mechanical movement characteristics.

[0040] The optional centralizer 16 is configured to centralize at least the second end 10A of the apparatus within the wellbore 2 so that the marker carrier 20 is distanced from the inner surface of the wellbore 2. As shown in FIG. 1, a first end of the centralizer 16 is operatively coupled to the second end of the inner body 12, for example by a threaded connection or any other connector arrangement that is suitable for the downhole environment where the apparatus 10 is deployed. The person skilled in the art will appreciate that while the figures depict the centralizer 16 as being a bow spring centralizer, any component that maintains a distance between the inner surface of the wellbore 2 and the marker carrier 20 is also contemplated. Additionally, while the first end of the centralizer 16 is shown as being operatively coupled within the inner body 12, it is understood that these relative positions may be reversed, provided the centralizer 16 does not interfere with the release of markers 22 from the marker carrier 20.

[0041] The top adapter assembly 14 comprises an adapter body 15 that is connectible at one end to the inner body 12, for example by way of a threaded connection or other connector arrangement that is suitable for the downhole environment where the apparatus 10 is deployed. Additionally, while the second end of the top adapter 14 isshown as being operatively coupled within the inner body 12, it is understood that these relative positions may be reversed. The top adapter assembly 14 also comprises a shear ring retainer 40, a slip backup 44, an anchor slip 46 and slip cone 48. Together the slip cone 48, the anchor slips 46 and the slip backup 44 are configured to engage with the inner surface of the wellbore 2 to releasably fix the first end 10B of the apparatus 10 at a desired location within the wellbore 2. The slip cone 48, the anchor slips 46 and the slip backup 44 are configured to expand and releasably fix the apparatus 10 according to methods known to those skilled in the art. In some embodiments of the present disclosure, the anchor slips 46 may be segmented to permit a large flow area to pass. Together the shear ring retainer 40, an outer surface of the adapter body 15, the slip backup 44 and the upper chamber wall 26 define a shear ring chamber in which a removable ring 42 is housed. When the ring 42 is present, the distance between a first shoulder 36 (which may also be referred to as shoulder A) and a second shoulder 38 (which may also be referred to as shoulder B) cannot change. The first shoulder 36 is defined by a first end of the upper chamber wall 26. The second shoulder 38 is defined by a first end of the shear ring retainer 40. When the ring 42 is present in the shear ring chamber the apparatus 10 is in a first operational position. The apparatus 10 cannot move from the first operational position until the ring 42 is removed. FIG. 2 through FIG. 6 show the apparatus 10 moving through a second, third, fourth, fifth and sixth operational position, respectively. As the apparatus 10 moves through these operational positions, one or more markers 22 are released from the marker carrier 20 into the wellbore 2.

[0042] FIG. 2 shows the apparatus 10 after having been exposed to a downhole environment where the fluids and / or the temperatures therein cause the ring 42 to dissolve, degrade or otherwise be removed from the shear ring chamber. As will be appreciated by those skilled in the art, the ring 42 may be removed by various approaches, including but not limited to providing the ring 42 as a burst disc that will burst at a predetermined hydrostatic pressure within the downhole temperature environment, providing the ring 42 as one or more mechanically failing shear pins, to provide the ring 42 as a shear ring and any combination thereof. With the ring 42 removed (which may also be referred to as disengaged) the apparatus 10 is now armed and able to move from the first operational position (i.e. when the ring 42 is present) to further operationalpositions. Movement of the apparatus 10 from the first operational position to further operational positions is based upon the temperature of the downhole environment within the wellbore 2, whereby the volume of the first chamber 28 and the second chamber 30 can change, which then changes the distance between the first shoulder 36 and the second shoulder 38 can change, which results in the marker carrier 20 releasing one or more markers 22 into the wellbore 2 for capture at the surface.

[0043] In some embodiments of the present disclosure, the one or more markers 22 are physical markers. Each physical marker may have a unique and predetermined engraving or predetermined geometry that identifies the mechanical position each marker 22 was housed in and released from the retainer 20. Other embodiments may relate to other types of markers 22, non-limiting examples may include: chemical markers, radioactive markers, engineered molecule markers, engineered particle markers, radiofrequency identification markers, or any coded combination of unique markers either of the same group or different groups. In some embodiments of the present disclosure, the carrier 20 may be re-filled with new markers so that the same mechanical position can be identified multiple times as the apparatus moves bi-directionally through the life-cycle of the well.

[0044] As will be appreciated by the skilled reader, the one or more markers 22 may also be physical carriers of a chemical signature, a radioactive signature, an engineered particle / molecule or any combination thereof and the physical carrier may dissolve in the wellbore fluids, such that the contents of the physical carrier are released when the physical carrier dissolves and the contents are then able to be detected at surface (or elsewhere in the wellbore), rather than the physical marker being captured at surface.

[0045] As will be appreciated by the skilled reader, the one or more markers 22 may be physical containers of a chemical signature, a radioactive signature, an engineered particle / molecule or any combination thereof and as the mechanical position of the apparatus changes one of the markers 22 may move into a position to release its contents into the fluids of the wellbore for the contents to be detected at surface (or elsewhere in the wellbore).

[0046] For example, when the temperature of the wellbore environment reaches a first predetermined level, the second chemical in the second chamber 30 will expand, which then compresses the first chemical in the first fluid chamber 30 until the pressure between the chambers 28, 30 equalizes. The expansion and compression of the chambers 28, 30 results in a mechanical movement of the apparatus to a further operational position that causes a first marker to be released into the wellbore fluid flowing through the bore 4 of the apparatus 10 and / or into the annular space defined between the apparatus 10 and the inner surface of the wellbore 2. The marker will travel with the wellbore fluid to the surface and be detectable / recordable. The apparatus 10 is configured so that when a specific temperature range is established in the wellbore 2 where the apparatus 10 is deployed, there will be a predetermined expansion / compression of the chambers 28, 30 that will result in a position of the marker carrier 22 that correlates to a specific marker 20 being released.

[0047] FIG. 4 shows the apparatus 10 in a predetermined temperature range so that the expansion / compression of the chambers 28, 30 are just about to cause the release of a 7th row of markers with rows 2-6 already released.

[0048] FIG. 5 shows the apparatus 10 after the 7th row of markers released is already released.

[0049] FIG. 6 shows the apparatus 10 at an operational position defined by a minimum temperature position that it can measure with all 108 rows of markers released. As will be appreciated by those skilled in the art, the number of rows of markers within the marker carrier 20 is not limited to 108 rows, there may be more or less rows of markers.

[0050] FIG. 7 shows another apparatus 100 according to embodiments of the present disclosure. As compared to the apparatus 10 that translates changes in the temperature of the downhole environment to mechanical changes in operational position for releasing markers 22, the apparatus 100 is configured to translate changes in the pressure of the fluid within the wellbore 2 into mechanical changes of an operationalposition of the apparatus 100, which results in a release of specific markers into the wellbore 2.

[0051] The apparatus 100 is shown installed in a wellbore 2 that is either open hole or lined with string of tubulars, such as casing or liner. The wellbore 2 may be of an oil well, a gas well, a geothermal well, or any other well for the purpose injecting, producing or recovering desired products. The apparatus 100 is generally tubular with a second end 100A and a first end 100B, where the ends 100A, 100B define a longitudinal axis of the apparatus 100 therebetween. The apparatus 100 further comprises a mandrel 104, in which the piston assembly 102 is operatively coupled. The apparatus 100 further comprises an anchor assembly 106 and a marker carrier 120 that carries multiple markers 122. The carrier 120 and the markers 122 may be substantially the same as described herein above for the carrier 20 and the markers 22.

[0052] The anchor assembly 106 may be operatively coupled to the first end of the mandrel 104. The anchor assembly 106 comprises a slip cone 108 and an anchor slip 110. The anchor assembly 106 is configured to releasably fix the apparatus 100 within the wellbore 2 with the anchor slips 110 configured to expand due to movement relative to the anchor cone 108 to releasably fix the apparatus 100 according to methods known to those skilled in the art. In some embodiments of the present disclosure, the anchor assembly 106 may be substantially similar or the same as anchor assemblies described herein for use with other embodiments of the apparatus.

[0053] The marker carrier 122 is operatively coupled to the piston assembly 102 and the operational position of the piston assembly 102 is based upon a predetermined pressure of the fluid flowing through the bore 40. For example, the piston assembly 102 comprises a piston sleeve 112 that is at least partially housed within a piston chamber 116 that is defined by a piston housing 114. Optionally, the piston chamber 116 may be a vacuum or it may be filled with a fluid with predetermined physical properties. The first end of the piston sleeve 112 is in a fixed position relative to the anchor assembly 116. The piston assembly 102 further comprises a biasing member 118 that is positioned between a second end of the piston sleeve 112 and an inner surface of the second end of the piston housing 114.

[0054] In FIG. 7 through FIG. 9, the apparatus 100 is shown in the wellbore 2. As such the pressure of the wellbore fluid will act against a face 114A of the piston housing 114 to generate a piston force that acts to move the piston housing 114 towards the first end 100B of the apparatus 100. Because it is the absolute pressure of the wellbore fluids that acts against the face 114A, the apparatus 100 agnostic to its orientation within the wellbore relative to the flow direction of the wellbore fluids. The movement of the piston housing 114 is countered by the biasing force generated by the biasing member 118 that is being compressed between the moving piston housing 114 and the fixed piston sleeve 112. As shown in FIG. 7, if the piston force is insufficient to overcome the biasing force the position of the piston housing 114 relative to the marker carrier 120 is unchanged. However, as shown in FIG. 8, the pressure of the fluid flowing through the wellbore 2 is higher than it was in FIG. 7. The increased pressure of the flowing fluid has overcome the biasing force so that the piston housing 114 moves relative to the marker carrier 120 a first predetermined distance. The first predetermined distance is based upon a known piston force relative to the biasing force to correlate to the pressure of the fluid. As such, when the piston housing 114 moves the first predetermined distance shown in FIG. 8, a first row of markers of the marker carrier 120 is now exposed to the wellbore and a predetermined number and type of markers are released into the wellbore. When retrieved at surface, the markers will report the pressure of the fluid within the wellbore 2 at the apparatus 100.

[0055] As shown in FIG. 9, the fluid pressure is higher than in FIG. 8. As such, the piston housing 114 has moved a second predetermined distance that is greater than the first predetermined distance of FIG. 8. Because the piston housing 114 has moved a greater distance, more markers and different markers are released from the marker carrier 120. When retrieved at surface, the markers will report the pressure of the fluid within the wellbore 2 at the apparatus 100.

[0056] Table 1 below provides a set of physical data for piston diameter, piston area, piston travel length, initial pressures, fully stoked pressures, force at initial pressure, force at final pressure and spring ratings for one example scenario regarding use of the apparatus 100.

[0057] Table 1. Example Physical Dataimperial metricPiston Diameter 2.500 in 63.50 mmPiston Area 4.909 in23,166.92 mm2Piston Travel 10.000 in 254.00 mmInitial Pressure 500 psi 3,447 kPaFully Stroked Pressure 5,000 psi 34,474 kPaForce at Initial Pressure 2,454 lbs 1,092 daNForce at Final Pressure 24,544 lbs 10,918 daNSpring Rate 2,209 Ibs / in 38.68 daN / mm

[0058] FIG. 10 shows another apparatus 200 according to embodiments of the present disclosure. As compared to the apparatus 10 that translates changes in the temperature of the downhole environment to mechanical changes in operational position for releasing markers 22 and as compared to the apparatus 100 that translates changes in fluid pressure into mechanical changes of a piston assembly for releasing markers 122, the apparatus 200 is configured to translate changes in the flow rate of the fluid within the wellbore 2 into mechanical changes of an operational position of the apparatus 200, which results in a release of specific markers 222 into the wellbore 2.

[0059] The apparatus 200 is shown installed in a wellbore 2 that is either open hole or lined with string of tubulars, such as casing or liner. The wellbore 2 may be of an oil well, a gas well, a geothermal well, or any other well for the purpose injecting, producing or recovering desired products. The apparatus 200 is generally tubular with a second end 200A and a first end 200B, where the ends 200A, 200B define a longitudinal axis of the apparatus 200 therebetween. The apparatus 200 defines a central bore 240 through which fluids may flow through the apparatus 200 from the first end 200B to the second end 200A (see arrow F).

[0060] The apparatus 200 comprises a mandrel 202, an anchor assembly 204, a marker carrier 220 that carries multiple markers 222, a shift sleeve 206 and an end plate 208. The carrier 220 and the markers 222 may be substantially the same as described herein above for the carriers 20, 120 and the markers 22, 122.

[0061] The anchor assembly 204 may be operatively coupled about the first end of the mandrel 202. The anchor assembly 106 comprises a slip cone 220, an anchor slip 222, a backup slip 224, 228 and a sealing element 226. The anchor assembly 106 is configured to releasably fix the apparatus 200 within the wellbore 2 and to establish a fluid tight seal between the apparatus 200 and the inner surface of the wellbore 2. That fluid tight seal directs the fluid flowing through the wellbore 2 through the bore 240. The anchor slips 222 are configured to expand due to movement relative to the anchor cone 220 to releasably fix and seal the apparatus 200 according to methods known to those skilled in the art.

[0062] The shift sleeve 206 is operatively coupled to the inner surface of the mandrel 202 and the inner surface of the marker carrier 220. The shift sleeve 206 can shift along the longitudinal axis of the apparatus 200 between the end plate 208 and a biasing force generated by compression of a biasing member 210. The biasing member 210 is positioned between a shoulder 210 of the mandrel 202 and the end of the shift sleeve 206 that is opposite to the end plate 208.

[0063] The inner surface of the shift sleeve 206 defines a first portion of the central bore 240 and a shaped orifice 206A. For example, the shaped orifice may be shaped with a converging and diverging shape so that as fluid flows into the apparatus 200 and through the orifice 206A the flowing fluid will experience a pressure drop and, therefore, a pressure differential between the fluid ahead of the shaped orifice 206A and the fluid behind the shaped orifice 206A. This pressure differential will exert a force on the shift sleeve 206 to move away from the end plate 208 towards the anchor assembly 204. As shown in FIG. 10, the shift sleeve 206 is in a first operational position where the first end of the shift sleeve 206 abuts or is proximal to the end plate 208. As such, the first operational position is achieved because the pressure drop caused by the fluid flowing through the shaped orifice 206A causes a pressure differential that is insufficient to overcome the biasing force of the biasing member 210 (or there is no fluid flowing through the apparatus). As such, the position of the shift sleeve 206 relative to the marker carrier 220 prevents any markers 222 from being released into the wellbore 2.

[0064] The specific shape of the shaped orifice 206A (e.g. the slope and length of the converging portion, the length and diameter of a constant diameter portion and the slope and length of the diverging section) is predetermined so as to cause a predetermined pressure drop at a predetermined flow rate. Additionally, the biasing force of the biasing member 210 can be predetermined so that it will take a predetermined flow rate of the fluid flowing through the shaped orifice 206A to overcome the biasing force. As such, incremental changes in the operational position of the shift sleeve 206A are based upon predetermined flow rates inducing a predetermined pressure differential across the shaped orifice 206A, which will then cause a predetermined compression of the biasing member 210 and a predetermined movement of the shifting sleeve 206 from the first operational position. As shown in FIG. 11 the flow rate is higher, as compared to the flow rate shown in FIG 10. The higher flow rate has induced a greater pressure loss of the fluid downstream of the shaped orifice 206A and, therefore, the greater pressure differential has overcome the biasing force of the biasing member 210 to allow the shift sleeve 206 to move a first predetermined distance. The change in position of the shift sleeve 206 is indicative of the apparatus 200 translating a mechanical change in response to the fluid rate of the fluid flowing through the apparatus 200. The first predetermined distance that the shift sleeve 206 has moved has exposed a predetermined number of markers 222 to be released into the fluid flow of the wellbore 2.

[0065] As shown in FIG. 12, the fluid flow rate is again higher than in FIG. 10 and in FIG. 11. As such, the higher flow rate has induced a greater pressure loss of the fluid downstream of the shaped orifice 206A than in FIG. 11 and, therefore, the greater pressure differential has overcome the biasing force of the biasing member 210 to allow the shift sleeve 206 to move a second predetermined distance. The second predetermined distance is greater than the first predetermined distance. The second predetermined distance that the shift sleeve 206 has moved has exposed a further predetermined number of markers 222 to be released into the fluid flow of the wellbore 2.

[0066] Because the shift sleeve 206 has moved a greater distance, more markers and different markers are released from the marker carrier 220. When retrieved at surface, the markers will report the rate of the fluid flowing within the wellbore 2 at the apparatus 200.

[0067] Table 2 below provides a set of physical data for piston diameter, piston area, piston travel length, initial pressures, fully stoked pressures, force at initial pressure, force at final pressure and spring ratings for one example scenario regarding use of the apparatus 200.

[0068] Table 2. Example Physical Dataimperial metricPiston Area 4.909 in23166.92 mm2Piston Travel 10.000 in 254.00 mmOrifice Diameter 0.500 in 12.70 mmOrifice Area 0.196 in2126.68 mm2Fluid Density 8.35 ppg 1,000 kg / m3Initial Flow Rate 0.629 bbl / min 0.100 m3 / minF u Uy Stroked Flow Rate 3.145 bbl / min 0.500 m3 / minForce At Initial Flow Rate 139 lbs 62 daNForce At Final Flow Rate 1,702 lbs 757 daNSpring Rate 156 Ibs / in 2.74 daN / mm

[0069] Table 3 below provides a range of flow rate and pressure drops that are contemplated to occur in use of the apparatus 200.

[0070] Table 3. Example Range of Flow Rate and Pressure DropFlow Rate Pressure Dropbbl / min m3 / min psi kPa0.629 0.100 13.87 95.610.692 0.110 16.78 115.690.755 0.120 19.97 137.670.818 0.130 23.43 161.580.881 0.140 27.18 187.390.943 0.150 31.20 215.121.006 0.160 35.50 244.761.069 0.170 40.07 276.311.132 0.180 44.93 309.771.195 0.190 50.06 345.141.258 0.200 55.47 382.431.321 0.210 61.15 421.631.384 0.220 67.11 462.741.447 0.230 73.35 505.761.510 0.240 79.87 550.701.572 0.250 86.67 597.551.635 0.260 93.74 646.311.698 0.270 101.09 696.981.761 0.280 108.71 749.561.824 0.290 116.62 804.061.887 0.300 124.80 860.471.950 0.310 133.26 918.792.013 0.320 141.99 979.022.076 0.330 151.01 1041.172.139 0.340 160.30 1105.222.201 0.350 169.87 1171.192.264 0.360 179.71 1239.072.327 0.370 189.83 1308.872.390 0.380 200.23 1380.572.453 0.390 210.91 1454.192.516 0.400 221.87 1529.722.579 0.410 233.10 1607.162.642 0.420 244.61 1686.522.705 0.430 256.40 1767.782.768 0.440 268.46 1850.962.830 0.450 280.80 1936.052.893 0.460 293.42 2023.052.956 0.470 306.32 2111.973.019 0.480 319.49 2202.803.082 0.490 332.94 2295.543.145 0.500 346.67 2390.19

[0071] FIG. 13 shows a non-limiting example of a marker carrier 20, 120, 220 that has 108 rows of markers with 4 markers per row.

[0072] Some embodiments of the present disclosure relate to a method 300 for translating a change in a feature of an operational environment of a wellbore into predetermined mechanical changes and such predetermined mechanical changes cause a reporting event to occur, where such reporting event is retrievable at or near the surface of the wellbore to indicate the amplitude of the change in the feature of the downhole wellbore environment that is being monitored.

[0073] As shown in FIG. 14, a method 300 comprises the steps of providing 302 an apparatus within a wellbore, where the apparatus comprises a marker carrier and a moveable component of the apparatus. The method further comprises a step ofconfiguring 304 the moveable component to move a predetermined distance based upon a predetermined change in the feature of the downhole wellbore environment being monitored. The method further comprises a step 306 of releasing a predetermined number and / or type of markers or the contents of a marker into the wellbore based upon the predetermined distance that the moveable component moved. The method further comprises the step of retrieving 308 the released markers and / or its contents and a step of interpreting 310 the retrieved markers or contents of markers.

[0074] As will be appreciated by those skilled in the art, the embodiments of the present disclosure relate to the apparatuses 10, 100, and 200 that may be assembled in any combination and share a single anchor and / or seal, or may be assembled in combination with another downhole component, or may be threaded onto pipe, casing, or tubing without an anchor.

Claims

I claim1. An apparatus for monitoring a wellbore environment, the apparatus comprising:(a) a body that is positionable within a wellbore,(b) a marker carrier that is operatively coupled to one end of the body, the marker carrier is configured to carry multiple markers; and (c) a moveable component that is operatively coupled to the body and to the marker carrier, the moveable component is moveable under an influence of a feature of the wellbore environment such that when the moveable body moves a predetermined distance, a first marker is released from the carrier.

2. The apparatus of claim 1, wherein the feature of the wellbore environment is a temperature of wellbore fluids and wherein the moveable component is a first chamber and a second chamber, wherein a chemical component within the first chamber will expand or contract at a given wellbore fluid temperature differently than a second chemical component within the second chamber.

3. The apparatus of claim 1, wherein the feature of the wellbore environment is a pressure of wellbore fluids and wherein the moveable component is a piston assembly that moves when the pressure of the wellbore fluid exceeds a biasing force of a biasing member that is positioned between a piston housing and a portion of the body.

4. The apparatus of claim 1, wherein the feature of the wellbore environment is a fluid flow rate of wellbore fluids and wherein the moveable component is a shiftable sleeve that defines a shaped orifice at a first end of the shiftable sleeve, wherein the shiftable sleeve moves when the wellbore fluids flowing through the shaped orifice establish a pressure differential that exceeds a biasing force of a biasing member positioned between a second end of the shiftable sleeve and a shoulder of the body.

5. The apparatus of claim 1, wherein when the moveable body moves a second predetermined distance, further or different markers are released from the marker carrier.

6. The apparatus of claim 1, wherein each of the multiple markers has a predetermined engraving or a predetermined geometry for identifying a mechanical position of each marker in the marker carrier.

7. The apparatus of claim 1, wherein each of the multiple markers is a chemical marker, a radioactive marker, an engineered molecule marker, an engineered particle marker, a radio-frequency identification marker or any combination thereof.

8. A method for monitoring a wellbore environment, the method comprising steps of:(a) providing an apparatus within a wellbore, where the apparatus comprises a moveable component that is operatively coupled to a marker carrier that carries multiple markers and a moveable component;(b) configuring the moveable component to move a predetermined distance based upon a predetermined change in a feature of the wellbore environment; and(c) releasing a predetermined number and / or type of markers or marker contents into the wellbore based upon the predetermined distance that the moveable component moved.

9. The method of claim 5, further comprising a step of retrieving the released markers or contents thereof.

10. The method of claim 6, further comprising a step of interpreting the retrieved markers or contents thereof comprises assessing a feature of each marker or contents, wherein the feature is one or more a predetermined engraving, a predetermined geometry feature, a chemical feature, a radioactive feature, anengineered molecule feature, an engineered particle feature, a radio-frequency identification feature or any combination thereof.

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