The present application relates to a wellbore plug for use in an oil or gas well, in order to control the flow of fluid through the wellbore. Wellbore plugs are conventionally used in wellbore tubulars such as production tubing, frequently when a tubing string pressure test is to be performed, after the tubing string has been assembled in the well, usually after cementing has been completed, and typically before production of hydrocarbons through e.g. the production string. Pressure testing at this stage often identifies leaks in the production string which can therefore be addressed before production starts. Suitable pressure tests are therefore good practice, especially before high pressure wellbore operations such as fracking, and are often mandated by drilling regulations in most territories.

During conventional pressure testing, a wellbore tubing plug is normally dropped from the surface into a production string, usually during cementing operations, and is usually landed in or near a section of the well known as the toe or foot above the formation being produced, typically seating on a shoulder within the well, and occluding the bore of the tubing above it, permitting pressure testing above the seated plug. After pressure testing, the plug can be drilled out, or in other cases, the plug can be formed from soluble material which dissolves after a predetermined time.

Summary

According to the present invention there is provided a wellbore plug comprising: a body having an axis and a bore adapted to transmit fluid between a first end of the body and a second end of the body, the body being adapted to be received within a tubular in an oil or gas well, and being adapted to engage a seat within the oil or gas well tubular to seal an annulus between the outer surface of the body and an inner surface of the tubular;

a sealing member adapted to occlude the bore through the body to resist fluid flow through the bore of the body when the wellbore plug is in a first configuration; a resilient device adapted to urge the sealing member towards one end of the body when the wellbore plug is in the first configuration; a locking member adapted to lock the sealing member in the first configuration, and adapted to be unlocked in response to pressure within the bore above a pressure threshold;

wherein unlocking of the locking member permits movement of the sealing member within the bore to shift the wellbore plug from the first configuration to a second configuration;

wherein movement of the sealing member in response to expansion of the resilient device when pressure within the bore is reduced below the threshold shifts the wellbore plug from the second configuration to a third configuration; and

wherein in the third configuration, the sealing member permits fluid passage through the bore between the first and second ends of the body.

The invention also provides a method of pressure testing a well, comprising:

plugging a tubular in the well by seating a wellbore plug in the tubular, the wellbore plug comprising a body having an axis and a bore adapted to transmit fluid between a first end of the body and a second end of the body, the wellbore plug having a sealing member occluding the bore through the body to resist fluid flow through the bore of the body when the wellbore plug is in a first configuration, a resilient device adapted to urge the sealing member towards one end of the body when the wellbore plug is in the first configuration, and a locking member adapted to lock the sealing member in the first configuration, and adapted to be unlocked in response to pressure within the bore above a pressure threshold;

applying a pressure differential across the locked sealing member by pressurising the bore above the sealing member and unlocking the locking member; moving the unlocked sealing member within the bore to shift the wellbore plug from the first configuration to a second configuration;

reducing the pressure differential across the sealing member and moving the sealing member within the bore in response to expansion of the resilient device to shift the wellbore plug from the second configuration to a third configuration; and permitting fluid passage through the bore between the first and second ends of the body when the wellbore plug is in the third configuration.

Optionally the locking member is a frangible member such as one or more pins adapted to shear above a threshold shearing force, applied by the pressure acting on the sealing member in the bore. Instead of pins, the locking member could be a ring or collet or split ring etc. Optionally the sealing member is axially restrained within the bore by the locking member (e.g. one or more shear pins). Optionally, in the first configuration, axial movement of the sealing member is resisted in both directions of the bore by the locking member when the locking member is locked. Optionally the sealing member is able to move from the first configuration in both axial directions within the bore after the locking member is unlocked. Optionally a seal is compressed between the outer surface of the sealing member and the inner surface of the bore in the first and second configurations, to occlude the bore and to resist or prevent fluid flow in the bore past the sealing member in the first and second configurations. Optionally the sealing member moves in one direction when the wellbore plug shifts from the first to the second configuration, and in the opposite direction when the wellbore plug shifts from the second configuration to the third configuration.

Optionally the wellbore plug comprises a dart with a hydrodynamic profile adapted to flow through a fluid column in the well in a single direction (i.e. down the string).

In some examples, the arrangement of features permits pressure testing while avoiding or minimising trips through the well before operations commence after the test. Some examples permit re-establishment of fluid circulation through the well after pressure testing concludes, simply by reducing the pressure differential above the seated wellbore plug. Some examples avoid the need for separate frangible valve members, such as rupture discs.

Optionally the bore has a catching chamber having a larger inner diameter than the sealing member, optionally disposed above the location of the sealing member in the first configuration, providing a clearance permitting fluid flow between the inner surface of the bore of the first portion and the outer surface of the sealing member. Hence the sealing member optionally does not seal the bore in the catching chamber. Optionally the catching chamber retains the sealing member in the third configuration, and permits fluid flow around the sealing member within the catching chamber.

Optionally the bore has a seal housing having an inner diameter in which the sealing member is received in a sliding fit. The seal housing optionally has a smaller diameter than the catching chamber. Optionally a first shoulder restricts axial movement of the sealing member within the seal housing. Optionally the shoulder is disposed in the seal housing. Optionally the sealing member has a shoulder facing in a first direction and the seal housing has a shoulder facing in the opposite direction. Optionally the two shoulders engage to limit axial movement of the sealing member within the seal housing. Optionally the seal housing is radially stepped, with a larger diameter portion and a smaller diameter portion and the first shoulder is disposed between the two portions. Optionally a seal is compressed between the inner surface of the seal housing and the outer surface of the sealing member. Optionally the seal is a resilient seal. Optionally the seal is an annular seal such as an O-ring, T-seal, P-seal or the like. Optionally the seal is adapted to seal the bore in both directions when the seal is compressed between the sealing member and the seal housing. Optionally the seal is a dynamic seal, adapted to resist fluid passage while the seal is sliding relative to the one of the sealing member and the seal housing. Optionally the seal is disposed on the sealing member, but could be disposed on the seal housing, e.g. in a groove on either component.

Optionally the sealing member resists or prevents fluid flow in the first and second configurations; for example, the seal can be compressed between the outer surface of the sealing member and the inner surface of the seal housing in both the first and the second configurations. Optionally a first force urging the sealing member in one direction as a result of fluid pressure in the bore at the fluid pressure threshold is higher than a second force urging the sealing member in the opposite direction as a result of the resilient device. Optionally the wellbore plug remains in the second configuration when the first force is greater than the second force. When the fluid pressure declines and the first force drops below the second force, the resilient member optionally urges the sealing member from the second configuration into the third configuration (optionally in the opposite direction). Thus, the sealing member is fixed in the first configuration by the locking device, which must be unlocked before the wellbore plug can shift from the first configuration to the second configuration, but after unlocking, the sealing member is held in the second configuration by a force imbalance between the first force and second force, and is free to move axially after within the bore during the shift from second to third configuration after the force imbalance is removed. After unlocking, the sealing member is optionally free to move axially while still holding pressure, and is moved under pressure differential in an axial direction within the bore as the wellbore plug shifts from the first to the second configuration.

Optionally the seal housing contains the resilient device. Optionally the resilient device is adapted to be energised (e.g. compressed) between the sealing member and a shoulder in the seal housing.

Optionally the seal housing extends axially further than the axial length of the sealing member, so that the sealing member is axially shorter than the second portion, and can slide axially within it while sealing the bore in different axial positions within the seal housing. In the first configuration the sealing member is optionally locked in the seal housing, and in the first configuration, a stop member of the sealing member (e.g. a shoulder) is optionally axially spaced from the first shoulder on the seal housing.

Optionally in the second configuration the movement of the sealing member relative to the seal housing is arrested by the first shoulder. For example, the stop member on the sealing member abuts the first shoulder on the seal housing. Optionally the movement of the sealing member as the wellbore plug shifts from the first to the second configuration from compresses the resilient device. Optionally the resilient device comprises a spring. Optionally the resilient device is held in compression in the first and second configurations. Optionally the resilient device stores energy (e.g. a spring is compressed further) when the wellbore plug shifts from the first to the second configuration. Optionally the resilient device releases energy when the wellbore plug shifts from the second configuration to the third configuration.

Optionally the sealing member and the body are separate. Optionally the body and the sealing member are run into the well separately. Optionally the sealing member can latch onto the body and can optionally form a seal with the body e.g. by compressing resilient seals between the sealing member and the body. Optionally the sealing member has wiper vanes. Optionally the body has wiper vanes. Optionally the vanes on the sealing member have a different (e.g. smaller) diameter than the vanes on the body; optionally the body and sealing member wipe different parts of the tubular. Optionally the body is pinned in place and run into the well with the tubular (e.g. string). Optionally the sealing member is run into the tubular, and lands in the body that is pinned in place.

Optionally the tubular includes a landing sub having a bore (optionally with a seat) adapted to receive the plug following axial movement of the plug in the string. Optionally the seat comprises at least one cylindrical portion, and optionally at least one tapered portion. Optionally the plug comprises at least one cylindrical portion and optionally at least one tapered portion. Optionally when the plug is seated in the landing sub, the axial distance of penetration through the bore of the landing sub is limited by the abutment of the tapered portions of the landing sub and the plug.

Optionally the landing sub contains at least one port permitting fluid communication between the bore of the landing sub and the outer surface of the string. Optionally the port is adapted to be closed by a sleeve that slides axially within the bore, optionally in response to a pressure differential or to a flow rate minimum. Optionally the body of the plug is adapted to urge the movement of the sleeve when the plug lands in the landing sub. Optionally the sleeve is secured to the landing sub by a latch e.g. by a frangible member such as a shear pin, although other latch devices could be used, e.g. collets, split rings etc. Optionally the latch is released by the movement of the plug through the landing sub, optionally by force applied to the plug by fluid pressure above the seated plug being transmitted to the sleeve through the body of the plug, optionally while the bore is sealed.

Optionally the plug can move axially with respect to the landing sub while the bore is sealed through the landing sub and the plug. Optionally the cylindrical sections of the landing sub and plug permit axial movement of the two while sealing is maintained.

Optionally the port is below the axial position in the landing sub where the plug seats in the landing sub.

Optionally the method of the invention includes injecting fluid into the well through the plug e.g. to fracture or otherwise treat the formation. Optionally the plug can be latched or locked to the tubular (e.g. in a landing sub) by a latch device. Optionally the latch device resists movement of the plug in one direction but not in the other direction. Optionally, the latch device permits movement of the plug into the well, but resists movement towards the surface. Optionally the latch device retains the plug and the tubular in a sealed relationship.

Optionally the sealing member incorporates a channel permitting selective fluid communication across the sealing member when seated in the body, and wherein the channel incorporates a seal preventing fluid communication through the channel below a pressure differential above a burst pressure, and wherein the seal is adapted to be disrupted by a pressure differential above the burst pressure to permit fluid communication through the channel.

The invention also provides a method of injecting fluid into a well, comprising:

plugging a tubular in the well by seating a wellbore plug in the tubular, the wellbore plug comprising a body having an axis and a bore adapted to transmit fluid between a first end of the body and a second end of the body, the wellbore plug having a sealing member occluding the bore through the body to resist fluid flow through the bore of the body when the wellbore plug is in a first configuration, a resilient device adapted to urge the sealing member towards one end of the body when the wellbore plug is in the first configuration, and a locking member adapted to lock the sealing member in the first configuration, and adapted to be unlocked in response to pressure within the bore above a pressure threshold;

applying a pressure differential across the locked sealing member by pressurising the bore above the sealing member and unlocking the locking member; moving the unlocked sealing member within the bore to shift the wellbore plug from the first configuration to a second configuration;

reducing the pressure differential across the sealing member and moving the sealing member within the bore in response to expansion of the resilient device to shift the wellbore plug from the second configuration to a third configuration;

injecting fluid through the bore between the first and second ends of the body when the wellbore plug is in the third configuration; and

flowing the injected fluid through a radial port in the tubular located below the seated plug. The various aspects of the present invention can be practiced alone or in combination with one or more of the other aspects, as will be appreciated by those skilled in the relevant arts. The various aspects of the invention can optionally be provided in combination with one or more of the optional features of the other aspects of the invention. Also, optional features described in relation to one aspect can typically be combined alone or together with other features in different aspects of the invention. Any subject matter described in this specification can be combined with any other subject matter in the specification to form a novel combination.

Optionally the wellbore plug can incorporate a centraliser device, such as a cup or an array of fins.

Optionally the bore can incorporate a seat or latch device permitting the connection and optionally sealing of a second wellbore plug, optionally at an upper end of the bore. Thus in one example, the invention provides a wellbore plugging system comprising two or more wellbore plugs as herein defined, connected in sequence.

Various aspects of the invention will now be described in detail with reference to the accompanying figures. Still other aspects, features, and advantages of the present invention are readily apparent from the entire description thereof, including the figures, which illustrates a number of exemplary aspects and implementations. The invention is also capable of other and different examples and aspects, and its several details can be modified in various respects, all without departing from the spirit and scope of the present invention. Accordingly, each example herein should be understood to have broad application, and is meant to illustrate one possible way of carrying out the invention, without intending to suggest that the scope of this disclosure, including the claims, is limited to that example. Furthermore, the terminology and phraseology used herein is solely used for descriptive purposes and should not be construed as limiting in scope. In particular, unless otherwise stated, dimensions and numerical values included herein are presented as examples illustrating one possible aspect of the claimed subject matter, without limiting the disclosure to the particular dimensions or values recited. All numerical values in this disclosure are understood as being modified by "about". All singular forms of elements, or any other components described herein are understood to include plural forms thereof and vice versa. Language such as "including", "comprising", "having", "containing", or "involving" and variations thereof, is intended to be broad and encompass the subject matter listed thereafter, equivalents, and additional subject matter not recited, and is not intended to exclude other additives, components, integers or steps. Likewise, the term "comprising" is considered synonymous with the terms "including" or "containing" for applicable legal purposes. Thus, throughout the specification and claims unless the context requires otherwise, the word “comprise” or variations thereof such as “comprises” or“comprising” will be understood to imply the inclusion of a stated integer or group of integers but not the exclusion of any other integer or group of integers.

Any discussion of documents, acts, materials, devices, articles and the like is included in the specification solely for the purpose of providing a context for the present invention. It is not suggested or represented that any or all of these matters formed part of the prior art base or were common general knowledge in the field relevant to the present invention.

In this disclosure, whenever a composition, an element or a group of elements is preceded with the transitional phrase "comprising", it is understood that we also contemplate the same composition, element or group of elements with transitional phrases "consisting essentially of”, "consisting", "selected from the group of consisting of”,“including”, or "is" preceding the recitation of the composition, element or group of elements and vice versa. In this disclosure, the words“typically” or “optionally” are to be understood as being intended to indicate optional or non- essential features of the invention which are present in certain examples but which can be omitted in others without departing from the scope of the invention.

References to directional and positional descriptions such as upper and lower and directions e.g. “up”, “down” etc. are to be interpreted by a skilled reader in the context of the examples described to refer to the orientation of features shown in the drawings, and are not to be interpreted as limiting the invention to the literal interpretation of the term, but instead should be as understood by the skilled addressee. In particular, positional references in relation to the well such as“up” and similar terms will be interpreted to refer to a direction toward the point of entry of the borehole into the ground or the seabed, and“down” and similar terms will be interpreted to refer to a direction away from the point of entry, whether the well being referred to is a conventional vertical well or a deviated well.

Brief description of the drawings

In the accompanying drawings:

Figure 1 shows a side view of a plug device according to an example of the invention;

Figure 2 shows a sectional view through line A-A of the Fig 1 plug device in a first configuration;

Figure 3 shows a sectional view of the Fig 1 plug device in a second configuration; Figure 4 shows a sectional view of the Fig 1 plug device in a third configuration; Figure 5 shows a side view of a second example of a plug device before wiping a payzone;

Figure 6 shows a section view of the Figure 5 arrangement after landing in a sub following the wiping of the payzone;

Figures 7 to 10 show views of a third example of a wellbore plug landing in a shoe landing sub above a float shoe showing sequential steps of landing (Figure 8), pressure testing (Figure 9), and permitting communication between the bore of the well and side ports in the landing sub following the pressure test (Figure 10);

Figure 11 shows a perspective view of a landing sub for the Fig 7 wellbore plug; and Figure 12 shows a detailed view of one optional modification to the Figs 7-11 plug.

Referring now to the drawings, figure 1 to 4 show side and sectional views through a typical example of a wellbore plug according to the invention. The wellbore plug has a body 10 comprising generally cylindrical sections which can optionally be screwed together, or otherwise attached. In this example, the wellbore plug comprises an upper section comprising a seal catcher 20, a middle section comprising a seal housing 50, and a lower section comprising a nose 80. The components are provided with a common central bore 10b extending from one end of the body 10 to the other. More or less than three sections can be provided in other examples. In one particular example, the nose 80 and seal housing 50 can optionally be integral. The outer surface of the body 10 is generally consistent between the seal catcher 20 and the seal housing 50, but the nose 80 generally has a smaller OD with optional drogue fins 82 extending radially from its outer surface in a generally conical arrangement, and expanding radially outward in an angle towards the upper end of the wellbore plug 1 beyond the OD of the upper sections 20, 50. In this example, the upper end of the wellbore plug 1 is shown at the left-hand side of the drawings, and the lower end is shown at the right hand side of the drawings. In operation, the wellbore plug 1 is launched into a tubing string forming part of the wellbore with the nose 80 offered into the bore of the tubing first (e.g. nose down), and with the fins 82 extending radially outward, optionally contacting the inner surface of the tubular being plugged. The fins 82 are optionally formed from a resilient polymeric material, and so optionally deform radially inward when compressed against the inner surface of the wellbore tubular in which the wellbore plug 1 is being deployed, although this is not necessary in all examples, and the wellbore plug 1 can be used in tubing strings that have a larger ID than the OD of the fins 82, as the function of the fins 82 is mainly to help the wellbore plug 1 to flow with the fluid through the tubing. The wellbore plug 1 is pumped towards a seat (not shown) in the tubing at which a lower sealing arrangement 85 which in this example comprises a pair of annular seals such as o-rings on the outer surface of the lower part of the nose 80 seats within a suitable seat on the inner surface of the tubing, thereby plugging the annulus between the wellbore plug 1 and the tubing and resisting further fluid passage past the seated wellbore plug 1. Optionally the nose 80 has a retaining device (in this example comprising a ratchet mechanism 90) which retains the nose 80 on the seat once seated.

As can be seen in the sectional view of figure 2, an upper end of the nose 80 has a retaining mechanism which can be a thread adapted to engage with a thread on the lower end of the seal housing 50 but which in this example comprises a ratchet mechanism 52 similar to ratchet mechanism 90, and the upper end of the seal housing 50 likewise has a male thread adapted to be engaged by a female thread on the inner surface of the lower end of the upper portion 20. The components 20, 50 80 can be connected in different ways. Suitable seals can be incorporated to seal the body components 20, 50, 80 together.

Figure 2 shows the internal details of the wellbore plug 1 in the first configuration, which is the default configuration when running into the hole to land at the desired depth on the seat, whereas figures 3 and 4 show second and third configurations of the plug during and after a pressure test operation respectively, which will be explained below.

Referring now to figure 2, the seal housing 50 has a radially stepped internal bore with a narrow diameter lower section stabbed into the upper end of the nose 80 so as to permit fluid communication between the bore of the seal housing 50 and the bore of the nose 80, and a wider diameter section above it, with an upwardly facing shoulder 55 which extends radially into the bore between the two sections of the seal housing 50. In this example, the resilient device takes the form of a coiled spring 70, which is housed within a spring cavity 57 within the wider diameter bore above the shoulder 55. Fig 2 shows the first configuration with the spring 70 in compression between the shoulder 55 and the lower surface of a sealing member which in this example takes the form of a piston 60, the lower end of which is a sliding fit in the spring cavity 57. The piston 60 has a top hat structure, with an upper flange 62 extending radially outwards from a body that is generally cylindrical. The lower body has a close tolerance between the outer diameter of the piston 60 and the inner diameter of the spring cavity 57. At least one seal which in this example takes the form of an annular T-shaped seal 61 extends around the outer surface of the lower body of the piston 60, and in this example is housed in a groove therein, such that the seal 61 is held in compression between the outer surface of the lower body of the piston 60 and the inner surface of the seal housing 50, thereby preventing fluid flow within the bore 10b past the sealed lower body of the piston 60.

Above the spring cavity 57, the seal housing 50 is counter-bored to a wider diameter in a locking cavity 59 in which the flange 62 of the piston 60 is a sliding fit. The locking cavity therefore has a larger outer diameter than the spring cavity 57. A radially inwardly extending shoulder 58 divides the locking cavity 59 from the spring cavity 57.

In this example, the flange 62 of the piston 60 extending radially outward from the upper end of the lower body of the piston 60 is axially shorter than the axial distance of the locking cavity 59, measured from the end of the locking cavity to the shoulder 58. Hence, the piston 60 can slide axially within the bore of the seal housing 50 for a distance before hitting the shoulder 58, while the body of the piston 60 is disposed within the spring cavity 57, causing the lower body of the piston 60 to extend further into the spring cavity 57 from the Fig 1 position as the piston 60 slides down the bore 10b.

The piston 60 in this example is adapted to be locked to the seal housing 50. In this example, the flange 62 has radial bores to receive the inner ends of shear pins 65, which extend radially through a circumferential array of pin holes arranged at the same radial position on the counter-bored upper end of the seal housing 50, optionally in this case, above the screw thread and seal between the seal catcher 20 and the seal housing 50. Optionally 12 pins are provided, but at least one is sufficient. The pins 65 connect the flange 62 to the seal housing 50 at or near to the upper end of the counter-bored locking cavity 59, so that the lower end of the flange 62 is spaced axially away from the shoulder as best seen in Fig 2, and in fact, the upper end of the flange 62 extends slightly proud of the upper end of the locking cavity 59 as best seen in Fig 2. The pins 65 lock the piston 60 to the seal housing 50 and hold the spring 70 in compression between the end of the lower body of the piston 60 and the shoulder 55 at the bottom of the spring cavity 57.

The seal catcher 20 has a large diameter seal catching chamber 21 above the piston 60, which has a larger diameter than the OD of the piston 60, so that fluid can flow past the piston 60 in the chamber 21 , even past the flange 62, when the piston 60 is located in the seal catching chamber 21. The seal catcher 20 is optionally connected to the seal housing 50 by means of a threaded connection and optionally a seal (not shown).

In operation, the wellbore plug 1 is launched into the bore of the tubing in the figure 2 configuration, nose down, so that the lower end of the nose 80 engages the seat in the tubing (not shown), and so that in this example, the retaining mechanism 90 engages to lock the wellbore plug 1 in that axial position. The bore 10b in the nose 80 is open to the bore below the seat through the outlet of the nose, but the annulus outside the nose 80 is sealed by the seals 85 and fluid cannot pass through the seat via the annulus. Thus, the only available fluid conduit for communication past the seated nose 80 is through the bore 10b.

In the Fig 2 configuration (the first configuration) the pins 65 lock the piston 60 axially within the seal housing 50, axially compressing the spring 70 between the lower end of the piston 60 and the upwardly facing shoulder 55, and radially compressing the annular seal 61 between the radially outermost surface of the piston 60 and the radially innermost surface of the spring cavity 57, thereby preventing the passage of fluid through the bore 10b while the piston is in the first configuration shown in figure 2. In this same first configuration, the lower end of the flange 62 on the piston 60 is axially spaced from the upwardly facing shoulder 58 on the seal housing 50. The pins 65 prevent axial movement of the piston 60 relative to the seal housing 50 at pressures below the unlocking threshold (to be explained below).

When the wellbore plug 1 is seated within the bore, and fluid flow past the outer surface of the wellbore plugging 1 is prevented by the interaction between the seal 85 and the seat, the locked piston 60 and seal 61 prevents the passage of fluid through the bore 10b, thereby closing off the bore 10b when the wellbore plug 1 is seated.

At this stage, a pressure test can be conducted, to pressure up the bore 10b above the seated wellbore plug 1 and check for leaks in the tubing string. In the pressure test, typically a pressure is maintained within the bore above the seated plug, and this high pressure is optionally held for a predetermined time period, in order to verify that the pressure can be held over time.

In this example, the locking member comprising the shear pins 65 is selected to unlock at a pressure threshold below the pressure test threshold, so that once the pressure test threshold is reached to conduct the pressure test, the shear pins 65 have been ruptured, and the piston 60 is no longer locked to the seal housing 50. The strength of the spring 70 in this example is selected to be relatively weak, typically weaker than the force exerted on the piston 60 at the pressure threshold for disrupting the locking device, so when the shear pins 65 rupture, and the piston 60 is unlocked from the figure 2 position, the pressure differential across the piston 60 pushes the piston 60 further into the bore to the position shown in figure 3 thereby compressing the spring 70 further within the spring cavity 57 until the lower surface of the flange 62 hits the upper surface of the shoulder 58 on the seal housing 50 which arrests the axial travel of the piston 60. At this stage, the wellbore plug 1 is in the configuration shown in figure 3, which is the second configuration. In this configuration (in this example) the piston 60 is unlocked since the pins 65 have sheared, but the piston 60 is still held in the second configuration as long as the pressure differential across the piston urging the piston 60 downwards is sufficiently high to overcome the force of the spring 70 held in compression between the piston 60 and the shoulder 55. In this example, the strength of the spring 70 can be selected to be relatively weak, and optionally the shear pins can be adapted to rupture at a relatively low pressure, which can for example be some way below the pressure test value. This provides the operator with some assurance that once the pressure within the bore 10b above the piston 60 passes the relatively low unlocking threshold, the shear pins 65 will be ruptured, and the piston 60 will be in the second configuration shown in figure 3. In practice, the unlocking threshold can be set at any desired pressure, by varying the strength of the resilient device and the locking device.

In the second configuration as shown in figure 3, the seals 61 are still radially compressed between the outer surface of the lower body of the piston 60 and the inner surface of the spring cavity 57, so despite the fact that the shear pins 65 have ruptured, and the piston 60 has moved down the bore 10b, the sealing member still seals the bore, preventing fluid passage through the bore between the two ends of the wellbore plug 1 as long as the pressure is high enough to overcome the force of the resilient device in the form of the spring 70.

The second configuration shown in figure 3 can be held as long as the pressure test endures, since the relatively high pressure in the bore 10b above the sealed piston 60 is sufficient to compress the relatively weak spring 70 in this case. After the pressure test has been concluded, the pressure can be released within the bore 10b, until the pressure differential applied to the unlocked piston 60 is no longer sufficient to compress the spring 70, at which point, the spring 70 expands, pushing the piston 60 upwards out of the spring cavity 57 (i.e. in the opposite direction to the movement of the piston 60 from the first configuration to the second configuration) and into the larger diameter seal catching cavity 21 within the seal catcher 20. This configuration is the third configuration, and is shown in figure 4. As shown in figure 4, the inner diameter of the seal catching cavity 21 within the seal catcher 20 is larger (optionally very much larger) than the maximum outer diameter of even the flange 62 on the piston 60, and once in the third configuration, the piston 60 does not substantially restrict fluid flow. Optionally the area of the cavity 21 when the sealing member in the form of the piston 60 is within the seal catching cavity 21 is no less (i.e. at least the same as or greater than) the area of the bore 10b at its narrowest. Fluid is therefore free to flow through the bore 10b past the piston 60 in the seal catching cavity 21 , through the spring cavity 57, through the narrow bore at the lower end of the seal housing 50, and into the nose 80, to the outlet thereof thereby re establishing fluid communication through the bore after the pressure test.

Optionally a head 11 at the upper end of the body 10 can incorporate a sealing bore 11b can incorporate a seat or latching profile permitting the connection and/or sealing of a second wellbore plug (not shown) above the wellbore plug 1 in a stacked array, connected in sequence. Optionally therefore, the wellbore plug 1 can land out on top of other plugs or darts or cementing equipment already pre-seated or“run” ahead, during for example, a“wet shoe” cementing operation.

In the above described example, during the pressure test, wellbore pressure in the string above the seated wellbore plug 1 is in communication with the bore 10b through the open upper end of the head 11. In one possible modified example, the head 11 and/or the seal catcher 20 can optionally incorporate additional ports to facilitate communication of pressure from the string above the seated plug 1 into the bore 10b, for example, radial ports disposed above the seated piston 60 (and typically above the screw thread connecting the seal catcher 20 with the seal housing 50) can optionally extend through the side walls of the seal catcher 20 or head 11 connecting the annulus outside the wellbore plug 1 with the bore 10b inside. This can facilitate the application of the pressure differential across the piston 60 in the first configuration, and can allow annular communication with the bore 10b when the plug 1 is in the third configuration.

Referring now to figures 5 and 6, a second example of a wellbore plug has similar components to the wellbore plug described in figures 1 to 4, but with reference numbers increased by 100. Components that are similar between the two examples will not all be described in detail for brevity, but the skilled reader will understand that the second example can incorporate any one or more or all of the features and functions of the first example. Likewise, any one or more or all of the features of the second example can be incorporated within the first example. The wellbore plug 101 of figures 5 and 6 has a body 110, a middle section comprising a seal housing 150 and a nose 180. A common central bore 110b extends from one end of the body to the other. In this example, there is no seal capture 20 equivalent component, and the seal housing 150 receives a piston 160 which is pinned by shear pins 165 to the seal body 150, and is sealed thereto by an O-ring between the two components. In this example, the sealing member comprising the piston 160 is simply pushed out of the body 110 and remains in the tubular above the body.

The piston 160 optionally has a flange 162 which limits the axial travel of the piston 160 within the seal housing 150, and is biased by the spring 170 which is optionally held in compression between the inner surface of the piston 160 and a shoulder within the spring cavity 157, urging the piston upwards. In this example, the piston 160 optionally has a tapered bore 160b, which has a narrower inner diameter than the coiled spring 170, and which has a seat that is adapted to receive a surface release plug 168, which has a nose section that lands within the bore 160b and seals therein as shown in figure 6, thereby closing the bore through the body 110 and denying fluid passage through the bore 110 when the surface release plug is seated in the body 110.

As shown in figure 5, the surface release plug 168 has a number of external vanes above the nose which are adapted to wipe the inner surface of a narrow diameter line running string above a running tool in which the body 110 of the wellbore plug of this example is pinned.

In this example, when a cement job is to be run, the string is assembled during insertion typically including casing shoe and float valves at the lower end of the string, followed by a landing sub 140, followed by a section of payzone liner with a large internal diameter that is hung below a running tool 141 in which is pinned the body 110 of the wellbore plug. The body 110 is optionally pinned at a transition point between the larger lower diameter of the liner, and the relatively smaller inner diameter of the liner running string above the running tool (shown at the left-hand side of figure 5). Once the string has been run into the hole cement is pumped through the string. The cement typically flows easily through the wide bore 110b in the plug 101 , which remains pinned at the transition between the narrow and wide inner diameters in the liner during the injection of cement. The pins or other locking means holding the plug 101 in place in the running tool can optionally have a relatively low shear rating, since the cement can typically flow through the internal bore 110b of the body 110, through the open internal bore 160b of the piston 160 which is in turn pinned within the seal housing 150 in the bore.

The body 110 optionally has external vanes along the outside of the central section, which deform against the inner surface of the large diameter casing below the running tool 141 , and are adapted to wipe the large diameter lining following the injection of the cement from the surface.

Above the running tool, the inner diameter of the liner running string is narrower than the payzone liner, and is too narrow to accept the body 110 of the wellbore plug. Hence the body 110 is run into the hole already pinned in place within the running tool 141.

After injection of the cement through the liner running string, liner, body 110 and landing sub 140 through the casing shoes at the foot of the string, the entire liner must then be wiped of cement before the cement dries. This is optionally achieved by chasing the cement into the hole with the surface release plug 168, which typically has smaller vanes than those of the body, and is adapted to wipe cement from the smaller inner diameter of the liner running string between the surface and the running tool 141. Once the surface release plug 168 reaches the body 110 pinned in place within the running tool 141 at the transition between the two diameters of liner, it typically seats and optionally seals in the central bore 160b of the piston 160. Optionally the surface release plug can latch onto the body, e.g. inside the bore 160b. Continued pressure above the surface release plug typically applies a pressure differential that is sufficient to shear the relatively weak pins holding the body 110 within the running tool 141. These pins can optionally be sheared at a relatively low force, since they only need to hold the body 110 within the running tool 141 and resist the flow of cement until all the cement is below the body 110.

Once the surface released plug 168 lands within the piston bore 160b and the weak pins are sheared, the assembled plug as shown in figure 6 comprising the surface release plug 168 and the body 110 is released from the running tool 141 and travels down the larger diameter liner, chasing the cement and wiping the larger inner diameter of the payzone liner as it travels. When the assembled plug reaches the landing sub 140, the nose 180 of the plug lands in a seat and seals in the shoe landing sub 140, thereby closing the bore as previously described for the first example, and permitting a pressure test to be completed as previously described for the first example.

The force applied by the pressure test shears the pins 165 holding the piston 160 within the seal housing 150, and the piston 160 is then free to move downwards in the body 110 under the pressure differential, to compress the coiled spring 170 within the spring cavity 157 until the flange 162 on the piston tops out on the seal housing 150, essentially as previously described for the first example. Since the spring 170 typically has a larger diameter than the nose of the surface release plug 168, the spring only applies a force to the piston 160 and not to the surface release plug 168. Once the pressure test is concluded, the pressure above the sealed piston 160 is bled off until the downward force applied by the pressure differential acting on the sealed piston 160 is less than the upward force applied by the coiled spring 170 held in compression below the piston 160, at which point the coiled spring 170 expands and pushes the piston 160 out of the seal housing 150. At this point communication through the bore 110b is re-established again, essentially as previously described. The ejected piston 160 is not retained in any kind of catching chamber, but instead simply remains in the tubing above the seated body 110.

While not every aspect of the first example has been described with respect to the second example, all of the features of the first example could be incorporated within the second example, and vice versa.

Referring now to figures 7-10, a third example of a wellbore plug has similar components to the wellbore plugs described in figures 1 to 4, but with reference numbers increased by 200. Components that are similar in this example to features described in the two earlier examples will not all be described in detail for brevity, but the skilled reader will understand that the third example can incorporate any one or more or all of the features and functions of the first or second examples. Likewise, any one or more or all of the features of the third example can be incorporated within the first or second examples.

The wellbore plug 201 of figures 7-10 has a body 210, a middle section comprising a seal housing 250 and a nose 280. A common central bore 210b extends from one end of the body to the other. In this example, there is no seal capture 20 equivalent component, and the seal housing 250 receives a piston 260 which is pinned by shear pins 265 to the seal body 250, and is sealed thereto by an O-ring. The piston 260 has a flange 262 which limits the axial travel of the piston 260 within the seal housing 250, and is biased by the spring 270 which is held in compression between the inner surface of the piston 260 and a shoulder within the spring cavity 257, urging the piston upwards.

In this example, when a cement job is to be run, the string is assembled during insertion typically including casing shoe and float valves at the lower end of the string, followed by a shoe landing sub 240. The shoe landing sub 240 has a tapered seat 241 above a cylindrical section 242 adapted to receive the nose 280 of the plug 201. Once the string has been run into the hole cement is pumped through the string, and is chased by the plug 201 to wipe the casing and liner of cement. The body 210 has external vanes along the outside of the central section, which deform against the inner surface of the liner or casing, and are adapted to wipe the inner surface of the liner following the injection of the cement from the surface.

When the plug 201 reaches the shoe landing sub 240 the nose 280 of the plug 201 lands in cylindrical section 242 below the tapered seat 241 and seals the bore 240b of the shoe landing sub 240 as previously described for earlier examples. The sealed position is shown in Figure 8, in which the seals on the nose 280 are compressed between the nose 280 and the cylindrical section, but the plug 201 has not yet fully engaged the tapered seat 241 , because the lower end of the nose 280 has landed on the upper end of a port sleeve 300 which is pinned to the landing sub 240. The port sleeve 300 is sealed within the bore 240b of the landing sub 240, and seals off radial ports 245 connecting the bore 240b with the external surface of the landing sub 240. When pinned in position as shown in Figure 8, the port sleeve 300 denies fluid passage through the radial ports 245. The pins 246 holding the port sleeve 300 are typically rated at a similar strength to the pins 265 holding the piston 260 in the seal housing 250, but they could be different.

Optionally the plug can be latched or locked to the body by a latch device. In this case a latch secures the plug in one direction i.e. from drifting back in the reverse (upward) direction, stopping the seals from coming back out of the landing sub 240 but optionally not restricting the space in the forward direction that is later required to shift the port sleeve 300.

In one modification applicable to this example, the nose of the body of the plug can optionally incorporate one or more radial ports or flowpaths to permit fluid communication across the interface between the plug and the sleeve 300 in the event that the sleeve 300 remains in abutment with the plug after uncovering the radial ports 245. The sleeve 300 is typically moved from its initial position by the axial urging of the nose 280 of the plug 201 when the pins 246 and 265 shear. Sometimes, momentum from the shear might act on the plug 300 such that it continues moving down the bore 240b after the plug 201 is arrested in the positions shown in Figs 8-10, for example, the sleeve 300 might continue to move under momentum to the position shown in Fig 10, thereby coming to rest in a position that is spaced axially away from the nose of the plug 201 , below the axial position of the ports 245. However, in some cases, the sleeve 300 might remain in contact with the nose 280 of the plug 201 during the shear. The optional feature of the radial flowpaths in the nose shown in Fig 12 permit fluid communication between the bore of the plug 20T and the radial ports 245’ even in the event that the sleeve 300’ remains in abutment with the nose. The ports in the nose in this modification are optionally provided by extensions of the nose with flowpaths between nose prongs 281 shown in Fig 12. Fig 12 also shows a further optional modification according to this example, in which the nose is tapered to be partially received in the bore of the sleeve 300’. Optionally the ports are disposed below the seals in the nose 280. Optionally the ports are disposed above the seals on the sleeve 300, i.e. between the two sets of seals. Optionally, when the plug is fully seated and has been arrested in the seat, the nose (e.g. the nose prongs) pushes the port sleeve axially downwards in the bore of the landing sub until the seals on the port sleeve clear the radial port in the tubular (e.g. the landing sub). The ports can facilitate fluid transfer between the bore of the plug and the radial ports in the landing sub (in either direction).

The well is conveniently shut in from both directions during this phase and can optionally be left for any period of time - during which time the cement is able to dry.

In the Figure 8 position, although the body 210 is held up by the pinned port sleeve 300 and the bore 240b of the landing sub 240 is closed by the seals of the nose 280 of the plug 201 which are compressed within the cylindrical section, the tapered section 281 on the body 210 has not yet fully engaged with the tapered seat 241 on the landing sub 241 , although in some examples, the remaining distance to travel before full engagement is achieved is optionally very small, e.g. a matter of millimetres, so in some examples, movement of the body 210 between the Fig 9 and 10 positions does not substantially change the volume of the string before the plug 201. Optionally only the pins 246 are holding the body 210 in the Figure 8 position. So higher pressure applied above the seated plug 201 eventually shears both the pins 265 and 246, causing the plug 201 to move down the bore of the landing sub 240 from the position in Fig 8 to the position in Fig 9, until tapered section 281 on the body 210 is fully seated on the tapered seat 241 on the landing sub 240, and the port sleeve 300 has moved down the bore of the landing sub 240. The distance moved by the sleeve 300 is un-important (as communication is not yet established through the plug above. The travel of the sleeve 300 can optionally be short enough to only shear the pins or long enough to fully or partially expose the ports below and is initially controlled by the length of the protruding nose of the plug below the seal(s) and the available space between the (optionally tapered) faces of the plug and landing sub 240. At this stage, although the ports may be exposed, they do not yet transmit fluid because the plug above has not yet opened and so there is no meaningful communication.

Typically the pressure sufficient to shear the pins 265, 246 is less than full pressure test values which could be around 10kpsi (approx. 68.9MPa). It does not particularly matter which of the pins 265, 246 shear first. Optionally the pressure required to shear the pins 265, 246 is similar, and is also optionally sufficient to maintain compression of the spring 270 by the piston 260, thereby keeping the bore 210b closed. This position as shown in Figure 8 can be held with the plug forming a temporary barrier, closing the bore 240b since the nose 280 is sealed in the cylindrical section, and keeping the bore 240b sealed off from the radial ports 245, since the port sleeve 300 has not moved down far enough to uncover them. The position can be held by the latching device without necessarily requiring pressure to be applied from the surface, although this remains an option. This position can therefore be held for an indefinite period until the cement dries. The well is conveniently shut in from both directions during this phase.

The Fig 9 position shows the configuration of the plug during a pressure test, with a higher pressure of around 10kpsi (approx. 68.9MPa) being applied from the surface, sufficient to shear the pins 265 and 246. While the plug 201 is fully seated and cannot move any further down the bore 240b, the port sleeve 300 is typically not exposed to any direct pressure and is typically only moved down the bore 240b because it is being urged by the lower end of the plug 201 landed on the upper end of the port sleeve 300, so when the plug 201 reaches its final position shown in Fig 9, the port sleeve 300 typically stops moving, optionally in a position in which the ports 245 are still sealed off from the bore 240b. Thus optionally in the full pressure test position shown in Fig 9, the well is still closed in from both directions.

The force applied by the pressure test shears the pins 265 holding the piston 260 within the seal housing 250, and the piston 260 therefore is free to move downwards in the body 210 under the pressure differential, to compress the coiled spring 270 within the spring cavity 257 until the flange 262 on the piston tops out on the seal housing 250, essentially as previously described for the first example. Once the pressure test is concluded, the pressure above the sealed piston 260 is bled off as previously described until the downward force applied by the pressure differential acting on the sealed piston 260 is less than the upward force applied by the coiled spring 270 held in compression below the piston 260, at which point the coiled spring 270 expands and pushes the piston 260 out of the seal housing 250. At this point communication through the bore 210b is re-established again, essentially as previously described.

When the piston 260 is ejected from the body 210, the higher flow rates through the bore 210b of the plug 201 urges the port sleeve 300 down the bore to fully uncover the radial ports 245, permitting communication between the bore of the string and the radial ports to permit production of hydrocarbons, or if required, fracturing etc.

While not every aspect of the first and second examples has been described with respect to the second example, any or all of the features of the first and second examples could be incorporated within the third example, and vice versa.

In use, the string is assembled from the surface and run into the hole commencing with the shoe and optionally the float valves run immediately below the landing sub 240, followed by the remainder of the liner and casing above it. The volume of the string below the pinned sleeve 300 can be accurately measured, and can be kept relatively small. The position of the radial ports 245 can be accurately established, and the cross-sectional area of the ports 245 can likewise be accurately established (e.g. at the surface) for the appropriate job, be it frac, well stimulating or hydrocarbon production or influx. The string is run into the hole with the port sleeve 300 in place to close the radial ports 245 as previously described, and with the landing sub 240 near to the bottom of the string. Optionally, the ports 245 can be circular in cross- section, but this can be varied, and in different examples, the ports 245 can optionally comprise slots which can optionally extend circumferentially around the landing sub for at least a short distance. In some examples, the slots 245 can be arranged in axially spaced rows which are offset and which overlap, permitting at some point influx of oil or gas and /or also if required injection of fluid through the ports around the full diameter of the landing sub 240, as shown, for example, in figure 11.

In operation, following the injection of the cement in a quantity carefully chosen to fill the annulus between the outside of the string and the inside of the bore of the well, the cement is chased with a spacer fluid such as water, followed by the plug 201. The volume of spacer fluid injected between the plug and the cement is optionally carefully calculated to be the same as or very close to the volume of the string beneath the landing shoe cylindrical portion 242 before the end of the bore of the well, so that the spacer fluid displaces substantially all of the cement ahead of it into the annulus. The plug is pumped down the well, chasing the spacer fluid and cement below it, and wiping the inner surface of the liner or surface casing as it travels, pushing the cement out of the bottom of the string and up into the annulus between the string and the bore. The operator can be confident that during the injection of the cement and until the plug 201 is seated freely and/or latched in the landing sub 240, the radial ports 245 will remain closed at the bump test pressure, and all of the cement will be injected through the float shoe. Also due to the potential access above the shoe, through the ported sleeve, the calculated amount of spacer fluid required between the cement and plug is less critical than it normally would be, thus being more desirable to the operator.

As the plug lands at the landing sub 240, and seals in the cylindrical section 242, the operator can be confident that the fluid between the landed plug and the bottom of the string is occupied by spacer fluid rather than by cement, since this has been accurately measured at the surface, and is (and is optionally a manageably small volume e.g. a few 10s of Litres). Advantageously also, the cementing has been deliberately completed as a“wet shoe” job, leaving minimal set cement within the string, and substantially all of the set cement being displaced into the annulus outside the string by the spacer fluid. Once the plug 201 has landed on the pinned port sleeve 300, a bump test can be performed to confirm that the tool has been landed, typically at a relatively low pressure of approximately 1000 psi (for example 6.89 MPa) which is insufficient to shear any of the pins within the assembly, but which is sufficient to confirm the position of the plug 201 at the landing sub 240, which thereby confirms that the cement has been pushed out of the string and is now mainly occupying the annulus.

In a first example, in a situation where the cement has dried fully outside the annulus and the string below the landing sub 240 is filled with spacer fluid only, the operator can then perform a full system pressure test at high pressure to shear both of the pins 246 and 265 so that the plug moves into the figure 9 configuration. The test pressure can be held for as long as required and after pressure is bled off, the force of the spring 270, which has been maintained in compression in the figure 9 configuration, expands to push the piston 260 out of the upper end of the body 210 of the plug 201 , thereby re-establishing fluid communication through the bore of the plug, and permitting flow therethrough. The flow rate of fluid through the now open plug (or alternatively a pressure differential across the sleeve 300) typically moves the sleeve 300 down the bore 240b to fully expose the radial ports 245 (this may not be required as the ports may already be fully exposed at the point of shearing the sleeve down), which permits hydraulic fracturing operations, if required without further intervention.

The first frac or production zone can optionally be established entirely below the wiper plug and the cement, which is of significant advantage, because the thin annular layer of cement immediately outside the ports 245 is easily fractured by the hydraulic pressures applied through the string during fracturing operations. This means that the first frac zone can be very much closer to the intended reservoir than was previously permitted.

In some situations, the miscalculation of the volume of spacer fluid within the string leads to set cement in the string either in or below the float shoe underneath the landing sub 240. In such situations, a pressure test can be conducted as previously described and held for as long as needed, and the first frac zone can then be initiated through the ports. Therefore, in some examples, even where mistakes in the cement job lead to cement plugs occurring below the string, examples of the present invention still permit hydraulic fracturing operations without mechanical intervention at the plug, simply by operating the surface pumps to induce pressure changes.

In one example, the body 10 may optionally incorporate a channel permitting selective fluid communication across the sealing member, bypassing the sealing member when seated (and sealed) in the body. The channel optionally incorporates a seal such as a burst disc or some other selectively actuable sealing device that prevents fluid communication through the channel below a burst pressure, but which is adapted to be disrupted by a pressure differential above the burst pressure to permit fluid communication through the channel. The burst disc can optionally be added as a safety precaution set to burst if the tubular above the seated plug is over pressurised. This optional modification is potentially useful if the pressure below the seated plug is unexpectedly low, such that when the sealing member has transitioned to the second position, unlocking the sealing member from the body, the pressure differential acting on the seated sealing member can be equalised by rupturing the burst disc, thereby reducing the force needed by the spring to push the sealing member from the second configuration to the third. Optionally the burst disc is rated to a pressure threshold above the intended pressure test threshold, so that the burst disc remains intact at normal operating pressure, and is only ruptured if the pressure below the seated plug is too low to push the sealing member from the second configuration to the third by the force of the spring alone. Optionally the rating of the burst disc can be significantly higher than the planned test pressure. Optionally the burst disc can be disposed in the sealing member, or optionally in another part of the body 10, such as the seal housing, for example, below the seated sealing member.

When intact, the burst disc can optionally occlude a small passageway or restriction of known (small) cross-sectional area extending through the sealing device (or optionally through the wall of the plug body) so that in the event of premature rupture of the burst disc, any drop in pressure above the plug (which can be monitored at the surface) is firstly less dramatic and secondly can be monitored over a period of time. In some cases, selecting the restriction to be suitably small can allow the pressure differential across the ruptured burst disc to be replenished to original pressure using surface pumps (because the restriction has a known small cross-sectional area providing a quantifiable maximum pressure drop). This helps the surface operator to interpret measured pressure changes above the plug resulting from the ruptured burst disc, which can more easily be attributed to the ruptured burst disc itself rather than to other losses in wellbore integrity. Suitable calculations can be based on the density of the fluid, number of passageways, flow area restriction on passageways and flow rate of the surface pumps to quantify the pressure drop across the ruptured disc.

Examples of the present invention permit several distinct advantages, namely reducing the required length of the shoe track, increasing the production zone, avoiding reliance on fluid timers or dissolving parts, reducing reliance on coiled tubing operations and perforating operations, more consistent and controllable fracturing ports which can be more accurately positioned than previously possible, and can lead to less weakening of the structural integrity of the material surrounding the ports. In addition, the claimed combination of features also permits for more accurate estimation of the required amount of space fluid to use for a given cement job, therefore leading to more consistently satisfactory cement jobs and fewer errors with that phase of the well.