WO2020217051A1 - Bouchon de puits de forage - Google Patents

Bouchon de puits de forage Download PDF

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Publication number
WO2020217051A1
WO2020217051A1 PCT/GB2020/050997 GB2020050997W WO2020217051A1 WO 2020217051 A1 WO2020217051 A1 WO 2020217051A1 GB 2020050997 W GB2020050997 W GB 2020050997W WO 2020217051 A1 WO2020217051 A1 WO 2020217051A1
Authority
WO
WIPO (PCT)
Prior art keywords
sealing member
configuration
bore
plug
wellbore plug
Prior art date
Application number
PCT/GB2020/050997
Other languages
English (en)
Inventor
Jonathan Peter BUCKLAND
Original Assignee
Westfield Engineering & Technology Ltd
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority claimed from GBGB1905704.1A external-priority patent/GB201905704D0/en
Priority claimed from GBGB1916743.6A external-priority patent/GB201916743D0/en
Application filed by Westfield Engineering & Technology Ltd filed Critical Westfield Engineering & Technology Ltd
Priority to GB2115437.2A priority Critical patent/GB2597016A/en
Priority to US17/594,606 priority patent/US20220136360A1/en
Priority to CA3134677A priority patent/CA3134677A1/fr
Publication of WO2020217051A1 publication Critical patent/WO2020217051A1/fr

Links

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/12—Packers; Plugs
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/06—Valve arrangements for boreholes or wells in wells
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/06—Valve arrangements for boreholes or wells in wells
    • E21B34/10—Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole

Definitions

  • 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.
  • 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.
  • the plug can be drilled out, or in other cases, the plug can be formed from soluble material which dissolves after a predetermined time.
  • 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;
  • 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
  • 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:
  • 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 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.
  • the locking member could be a ring or collet or split ring etc.
  • the sealing member is axially restrained within the bore by the locking member (e.g. one or more shear pins).
  • the sealing member 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.
  • the sealing member is able to move from the first configuration in both axial directions within the bore after the locking member is unlocked.
  • 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.
  • 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.
  • 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).
  • 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.
  • 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.
  • the sealing member optionally does not seal the bore in the catching chamber.
  • the catching chamber retains the sealing member in the third configuration, and permits fluid flow around the sealing member within the catching chamber.
  • 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.
  • a first shoulder restricts axial movement of the sealing member within the seal housing.
  • the shoulder is disposed in the seal housing.
  • the sealing member has a shoulder facing in a first direction and the seal housing has a shoulder facing in the opposite direction.
  • the two shoulders engage to limit axial movement of the sealing member within the seal housing.
  • 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.
  • a seal is compressed between the inner surface of the seal housing and the outer surface of the sealing member.
  • the seal is a resilient seal.
  • the seal is an annular seal such as an O-ring, T-seal, P-seal or the like.
  • the seal is adapted to seal the bore in both directions when the seal is compressed between the sealing member and the seal housing.
  • 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.
  • the seal is disposed on the sealing member, but could be disposed on the seal housing, e.g. in a groove on either component.
  • 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.
  • 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.
  • the wellbore plug remains in the second configuration when the first force is greater than the second force.
  • the resilient member optionally urges the sealing member from the second configuration into the third configuration (optionally in the opposite direction).
  • 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.
  • 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.
  • the seal housing contains the resilient device.
  • the resilient device is adapted to be energised (e.g. compressed) between the sealing member and a shoulder in the seal housing.
  • 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.
  • 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.
  • the movement of the sealing member relative to the seal housing is arrested by the first shoulder.
  • the stop member on the sealing member abuts the first shoulder on the seal housing.
  • the movement of the sealing member as the wellbore plug shifts from the first to the second configuration from compresses the resilient device.
  • the resilient device comprises a spring.
  • the resilient device is held in compression in the first and second configurations.
  • the resilient device stores energy (e.g. a spring is compressed further) when the wellbore plug shifts from the first to the second configuration.
  • the resilient device releases energy when the wellbore plug shifts from the second configuration to the third configuration.
  • the sealing member and the body are separate.
  • the body and the sealing member are run into the well separately.
  • 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.
  • the sealing member has wiper vanes.
  • the body has wiper vanes.
  • 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.
  • the body is pinned in place and run into the well with the tubular (e.g. string).
  • the sealing member is run into the tubular, and lands in the body that is pinned in place.
  • 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.
  • the seat comprises at least one cylindrical portion, and optionally at least one tapered portion.
  • the plug comprises at least one cylindrical portion and optionally at least one tapered portion.
  • 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.
  • 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.
  • the body of the plug is adapted to urge the movement of the sleeve when the plug lands in the landing sub.
  • 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.
  • 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.
  • the plug can move axially with respect to the landing sub while the bore is sealed through the landing sub and the plug.
  • the cylindrical sections of the landing sub and plug permit axial movement of the two while sealing is maintained.
  • the port is below the axial position in the landing sub where the plug seats in the landing sub.
  • the method of the invention includes injecting fluid into the well through the plug e.g. to fracture or otherwise treat the formation.
  • the plug can be latched or locked to the tubular (e.g. in a landing sub) by a latch device.
  • the latch device resists movement of the plug in one direction but not in the other direction.
  • the latch device permits movement of the plug into the well, but resists movement towards the surface.
  • the latch device retains the plug and the tubular in a sealed relationship.
  • 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:
  • 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 wellbore plug can incorporate a centraliser device, such as a cup or an array of fins.
  • a centraliser device such as a cup or an array of fins.
  • 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.
  • the invention provides a wellbore plugging system comprising two or more wellbore plugs as herein defined, connected in sequence.
  • compositions, an element or a group of elements are 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.
  • 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.
  • 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
  • “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.
  • 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.
  • FIG. 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • a retaining device in this example comprising a ratchet mechanism 90 which retains the nose 80 on the seat once seated.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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).
  • 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.
  • the only available fluid conduit for communication past the seated nose 80 is through the bore 10b.
  • 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.
  • 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).
  • 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.
  • 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.
  • 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.
  • the wellbore plug 1 is in the configuration shown in figure 3, which is the second configuration.
  • 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.
  • 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.
  • the unlocking threshold can be set at any desired pressure, by varying the strength of the resilient device and the locking device.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • the string 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).
  • 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.
  • 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.
  • 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.
  • the surface release plug 168 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.
  • the surface release plug can latch onto the body, e.g. inside the bore 160b.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • the string 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.
  • 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.
  • 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.
  • 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.
  • the plug can be latched or locked to the body by a latch device.
  • 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.
  • 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.
  • 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.
  • the sleeve 300 might remain in contact with the nose 280 of the plug 201 during the shear.
  • Fig 12 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’.
  • the ports are disposed below the seals in the nose 280.
  • the ports are disposed above the seals on the sleeve 300, i.e. between the two sets of seals.
  • the nose e.g. the nose prongs
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • first and second examples 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.
  • 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.
  • 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.
  • 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.
  • 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).
  • 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.
  • 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.
  • 1000 psi for example 6.89 MPa
  • 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 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • the rating of the burst disc can be significantly higher than the planned test pressure.
  • 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.
  • the burst disc 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.
  • 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).
  • 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.
  • 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.

Abstract

L'invention concerne un bouchon de puits de forage comprenant un corps reçu à l'intérieur d'un élément tubulaire d'un puits de pétrole ou de gaz, et venant en prise avec un siège pour étanchéifier un espace annulaire. Un élément d'étanchéité obture le trou dans une première configuration. Un ressort pousse l'élément d'étanchéité vers une extrémité du corps dans la première configuration. Un élément de verrouillage verrouille l'élément d'étanchéité dans la première configuration, et peut être déverrouillé en réponse à une pression, à l'intérieur du trou, supérieure à un seuil de pression, qui permet à l'élément d'étanchéité de se déplacer dans une deuxième configuration. Le ressort se détend lorsque la pression à l'intérieur du trou est réduite à une valeur inférieure au seuil pour pousser l'élément d'étanchéité dans une troisième configuration, qui permet au fluide de traverser le trou. L'invention concerne également un procédé de test de pression et un procédé d'injection de fluide dans un puits à l'aide du bouchon de puits de forage.
PCT/GB2020/050997 2019-04-24 2020-04-22 Bouchon de puits de forage WO2020217051A1 (fr)

Priority Applications (3)

Application Number Priority Date Filing Date Title
GB2115437.2A GB2597016A (en) 2019-04-24 2020-04-22 Wellbore plug
US17/594,606 US20220136360A1 (en) 2019-04-24 2020-04-22 Wellbore plug
CA3134677A CA3134677A1 (fr) 2019-04-24 2020-04-22 Bouchon de puits de forage

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
GBGB1905704.1A GB201905704D0 (en) 2019-04-24 2019-04-24 Wellbore plug
GB1905704.1 2019-04-24
GBGB1916743.6A GB201916743D0 (en) 2019-11-18 2019-11-18 Wellbore plug
GB1916743.6 2019-11-18

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WO2020217051A1 true WO2020217051A1 (fr) 2020-10-29

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CA (1) CA3134677A1 (fr)
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Publication number Priority date Publication date Assignee Title
WO2022006075A1 (fr) * 2020-06-30 2022-01-06 Advanced Oil Tools, LLC Navette de régulation d'écoulement
CA3207526A1 (fr) 2021-02-05 2022-08-11 Chad Michael Erick Gibson Systemes et procedes de fracturation en plusieurs etapes

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US20130199800A1 (en) * 2012-02-03 2013-08-08 Justin C. Kellner Wiper plug elements and methods of stimulating a wellbore environment
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US8584746B2 (en) * 2010-02-01 2013-11-19 Schlumberger Technology Corporation Oilfield isolation element and method
MX369816B (es) * 2013-11-22 2019-11-22 Halliburton Energy Services Inc Obturador de separacion para herramientas de fondo de pozo.
CA2940852A1 (fr) * 2014-04-01 2015-10-08 Completions Research Ag Systeme de fracturation a haute pression multi-etages initiee par projectile
US10494892B2 (en) * 2015-03-26 2019-12-03 Halliburton Energy Services, Inc. Multifunction downhole plug
WO2018035149A1 (fr) * 2016-08-15 2018-02-22 Janus Tech Services, Llc Structure de bouchon de puits de forage et procédé de test de pression d'un puits de forage
US10648272B2 (en) * 2016-10-26 2020-05-12 Weatherford Technology Holdings, Llc Casing floatation system with latch-in-plugs
US10954740B2 (en) * 2016-10-26 2021-03-23 Weatherford Netherlands, B.V. Top plug with transitionable seal
US10132139B1 (en) * 2017-10-13 2018-11-20 Gryphon Oilfield Solutions, Llc Mid-string wiper plug and carrier

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US6427773B1 (en) * 2000-06-12 2002-08-06 Lonkar Services Ltd. Flow through bypass tubing plug
US20130199800A1 (en) * 2012-02-03 2013-08-08 Justin C. Kellner Wiper plug elements and methods of stimulating a wellbore environment
US20130292119A1 (en) * 2012-04-11 2013-11-07 Welltools Limited Downhole plug

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CA3134677A1 (fr) 2020-10-29
US20220136360A1 (en) 2022-05-05
GB2597016A (en) 2022-01-12
GB202115437D0 (en) 2021-12-08

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