Patent Application
20220136360
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.
According to the present invention there is provided a wellbore plug comprising:
The invention also provides a method of pressure testing a well, comprising:
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;
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.
In the accompanying drawings:
Referring now to the drawings,
As can be seen in the sectional view of
Referring now to
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
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
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
In the
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
In the second configuration as shown in
The second configuration shown in
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
The wellbore plug 101 of
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
As shown in
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
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
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
The wellbore plug 201 of
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
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
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
Typically the pressure sufficient to shear the pins 265, 246 is less than full pressure test values which could be around 10 kpsi (approx. 68.9 MPa). 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
The
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
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
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.
| Number | Date | Country | Kind |
|---|---|---|---|
| 1905704.1 | Apr 2019 | GB | national |
| 1916743.6 | Nov 2019 | GB | national |
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/GB2020/050997 | 4/22/2020 | WO | 00 |
