EP0489816A1 - Appareil et methode de flottation pour colonnes de cuvelage - Google Patents

Appareil et methode de flottation pour colonnes de cuvelage

Info

Publication number
EP0489816A1
EP0489816A1 EP90913295A EP90913295A EP0489816A1 EP 0489816 A1 EP0489816 A1 EP 0489816A1 EP 90913295 A EP90913295 A EP 90913295A EP 90913295 A EP90913295 A EP 90913295A EP 0489816 A1 EP0489816 A1 EP 0489816A1
Authority
EP
European Patent Office
Prior art keywords
fluid
duct
cavity
flotation
plug
Prior art date
Legal status (The legal status 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 status listed.)
Withdrawn
Application number
EP90913295A
Other languages
German (de)
English (en)
Inventor
Mark David Mueller
Frank Leroy Unocal Indonesia Inc. Jones
Julio Manuel Quintana
Kenneth Edward Ruddy
Michael Gene Mims
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Union Oil Company of California
Original Assignee
Union Oil Company of California
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 US07/401,086 external-priority patent/US4986361A/en
Priority claimed from US07/560,389 external-priority patent/US5113411A/en
Application filed by Union Oil Company of California filed Critical Union Oil Company of California
Publication of EP0489816A1 publication Critical patent/EP0489816A1/fr
Withdrawn legal-status Critical Current

Links

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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
    • E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
    • E21B33/14—Methods or devices for cementing, for plugging holes, crevices or the like for cementing casings into boreholes
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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
    • E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
    • E21B33/14—Methods or devices for cementing, for plugging holes, crevices or the like for cementing casings into boreholes
    • E21B33/16—Methods or devices for cementing, for plugging holes, crevices or the like for cementing casings into boreholes using plugs for isolating cement charge; Plugs therefor
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B31/00—Fishing for or freeing objects in boreholes or wells
    • E21B31/035—Fishing for or freeing objects in boreholes or wells controlling differential pipe sticking
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/02—Subsoil filtering
    • E21B43/10—Setting of casings, screens, liners or the like in wells
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B7/00—Special methods or apparatus for drilling
    • E21B7/04—Directional drilling

Definitions

  • This invention relates to well drilling and well completion devices and processes. More specifically, the invention relates to an apparatus and method of setting liner or casing strings in an extended reach well, during oil, gas or other well completions.
  • a string In some extended reach wells, such as wells drilled from platform or "islands," a string must be set in a slant drilled (i.e., inclined angle) portion of a deviated hole.
  • the inclined portion is located below an initial (top) portio of a lesser inclined angle.
  • the angle (from vertical) of these inclined holes frequently approaches 90 degrees (i.e., the horizontal) and sometimes exceeds 90 degrees. The result is a well bottom laterally offset from the top by a significant distance.
  • a deviated hole portion is defined as one having an axis in a direction at a significant incline angle to the vertical or gravity direction.
  • a casing or liner pipe string may become differentially stuck before reaching the desired setting depth during running into a deviated or high drag hole, especially if the incline angle exceeds a critical angle where the weight of the casing or liner in the wellbore produces more drag force than the component of weight tending to slide the casing or liner down the hole. If sufficient additional force (up or down) cannot be applied, the result will be stuck pipe string and possible effective loss of the well. Even if a stuck string is avoided, the forces needed to overcome high drag may cause serious damage to the pipe.
  • the plugable portion After providing a means to plug the ends of a pipe string portion, the plugable portion is filled with a low density, miscible fluid to provide a buoyant force.
  • the low density fluid must be miscible with the well bore fluids and the formation. Miscibility is required to avoid a burp or "kick" to or from the formation outside the pipe string when plugged portion fluid is discharged to the formation/well bore. Circulation of drilling mud is also not possible during running or feeding the plugged string into the wellbore. After feeding the plugged string into the well bore, the plugs are drilled out and the low density miscible fluid is forced into the well bore/pipe annulus. Further casing operations, if any,
  • cementing are accomplished without the assistance of a low density miscible fluid providing a buoyant force.
  • the known string flotation method requires added risk and well completion steps, especially if cementing is required.
  • the low density fluids compatible with the formation and bore fluid must be circulated out ahead of a cement slurry. This requires drilling out the plug(s) prior to cementing of the casing or liner string. Subsequent to the cementing, a second drilling out (of hardened residual cement) is frequently also required.
  • a simplified flotation device and method are needed to allow the placement and completion of long pipe strings in extended reach well bores.
  • the method and device should also be safe, reliable, and cost effective.
  • the invention provides a flotation plug device and process for running a casing or liner into a high drag inclined hole without the need to remove the plug device prior to cementing.
  • a float shoe/float collar and a shear-pinned plug insert trap air (or other low density fluids, not necessarily miscible with the formation or well bore fluids) within a portion of the casing string being run in a deviated hole.
  • a sealed port in the insert is opened to allow the air to be vented to the surface.
  • a cementing bottom wiper plug induced by applied pressure, forces the plug and insert to slide piston-like within the string to land and latch into a landing collar during normal cementing procedures.
  • the latched plug/insert/landing collar forms a single drillable assemblage. The assemblage is removed during normal post-cementing drilling out, avoiding multiple drilling steps.
  • the process of using this first embodiment attaches a float shoe and/or float collar (having a flapper or check valve) and a landing collar at one end of an air filled flotation portion of the casing.
  • the float shoe or collar prevents fluid inflow as the casing is lowered into the initial low angle portions of the fluid filled well bore.
  • An insert attached to an upper portion of the casing forms the other end of the "floating" portion.
  • the insert includes a releasable plug (attached by a first set of shear pins) to block a passageway in the body of the insert and contain the air.
  • the plug insert is attached within and pinned to the string with a second set of shear pins. This seals the air to form a flotation cavity, creating an increased buoyant force on the pipe string when the string is submerged in the fluid filled well bore.
  • the buoyant forces reduce effective weight, assisting the running of the string to the setting depth by reducing drag forces generated by the effective weight.
  • increased internal string pressure shears the first set of shear pins, opening the passageway. This allows air to vent up the string while mud flows down.
  • a cement slurry is then pumped down-hole separated from the mud by a bottom wiper plug.
  • the bottom wiper plug mates with the open ported insert and shears the second set of shear pins. Shearing releases the mated wiper plug and insert combination to move down-hole. The combination then latches to the landing collar, forming a single driliable assemblage.
  • a top wiper (segregating cement slurry from fluid above the cement slurry) may also be used. A differential pressure across the top wiper forces the cement slurry out and up the bore/string annulus. The assemblage (and top wiper, if used) is drilled out during normal post-cementing procedures.
  • the ported and slidable air trapping insert allows simplified running of long strings in inclined holes by controlled reduction of effective string weight, not by adding weight or reducing the coefficient of friction. Flotation is achieved without the need to 1) use a miscible low density fluid or 2) separately remove plugs prior to cementing the string.
  • Another embodiment also forms a flotation cavity in a portion of a tubular string between two ends (e.g., between a shoe and an insert/plug) to be set into a borehole, but adds a conduit between the flotation cavity ends.
  • This embodiment is preferred when sufficient buoyant forces can be obtained when the added space and weight of the conduit within the flotation cavity is considered.
  • the conduit and tubular string now form an annular shaped flotation cavity where the lower density fluid is contained outside the conduit to provide the increased buoyant forces.
  • the conduit (surrounded by the flotation cavity) allows drilling mud and other fluids to circulate during running or other following operations, specifically including cementing.
  • Figure 1 shows a schematic cross sectional view of one flotation device used to provide buoyant liner or casing forces during running operations
  • FIG. 2 shows a schematic side view of an alternative embodiment of the flotation device during installation
  • Figures 3a through 3f show simplified representations of the alternative device during well completion activities
  • Figure 4 shows a side and partial cross sectional view of an air trapping device portion of the engaged assemblage
  • Figure 5 shows a side cross-sectional view of another alternative embodiment
  • Figure 6 is a graphical representation of the results of a test of the flotation device.
  • Figure 7 shows a schematic side view, similar to Figure 2, of an alternative air annulus embodiment during installation.
  • FIG. 1 shows a schematic cross-sectional view of one embodiment for running a casing string (or liner or other duct) into a fluid filled bore hole (or cavity) 2.
  • a portion of the casing or liner string 4 is placed in the top vertical or low angle section of drilled bore hole 2 (lower slanted or high angle portion not shown for clarity).
  • the bottom end 3 of liner or casing string 4 has a float shoe 5 attached.
  • the float shoe 5 includes an outwardly or downwardly opening flapper or check valve 6.
  • the valve 6 prevents inflow of a first or bore fluid 7 during the running or lowering of the string (see downward direction "A" shown on Figure 1) into the well bore 2.
  • the flapper (or ball) of valve 6 may be spring or otherwise biased closed to prevent inflow, but allow pressurized fluid outflow (in the downward direction "A"). Outflow occurs if the pressure force within the string 4 can overcome flap seating forces and bore fluid 7 pressure forces.
  • Figure 1 shows the bladder 10 in a fully inflated position. Inflation is achieved by applying air or other second fluid pressure through open venting ports 15 in stem 14 (source of inflation air is not shown for clarity). Inflation also pressurizes the flotation cavity 12 to prevent collapse of the string under down hole conditions. After inflation, pulling or twisting of stem 14 closes the air venting ports 15 and the source of inflation can be removed.
  • the bore fluid 7 is normally a single density drilling mud, but may also be a mixture or several layers of different density fluids.
  • the various densities within the well bore allow a single flotation cavity 12 to have different buoyant forces at different portions of the well bore proximate to different density bore fluids. This can be highly desirable in extremely high drag well bores or variable incline angle bore portions.
  • the distance between the float shoe 5 at one end of the flotation cavity 12 to the bridge plug 8 at the other end is variable to allow control of buoyant forces generated. Repositioning the bridge plug 8 changes the buoyant ' forces on the "floating" pipe string portion enclosing cavity 12.
  • the float shoe 5 is installed at the surface before entry of the casing string end into the bore hole 2.
  • the length of the flotation cavity or portion of the string is selected to control the force tending to run the casing into the hole.
  • the bridge plug 8 seals and is attached to the duct by pressurizing the bladder after installing the length of "floating" pipe string portion into the bore hole 2. Alternatively, repositioning the bridge plug when in the hole may also be possible to further adapt and change buoyant forces, if required.
  • Buoyant forces in a non-vertical borehole portion can provide bending forces (e.g., buoyant forces exceed the weight of a buoyed portion of pipe string ahead of a non-buoyed portion in an inclined borehole curving towards a horizontal orientation), and repositioning the bridge plug can adjust these bending forces to adapt to the specific incline/curvature/bending needed.
  • the diameter and cross sectional thickness (and associated weight) of the pipe string enclosing cavity 12 can be set equal to the weight of the displaced bore fluid 7. This creates a neutral buoyancy so that this "floating" section exerts no upward or downward forces on the walls of the bore hole 2, regardless of orientation or slant. Even if-,neutral buoyancy is not desired, the controlled effective (buoyed) weight of the selected casing/liner pipe string which must be supported (hung) and any resulting drag during installation operations can be significantly reduced. This reduced maximum effective weight may allow a smaller capacity derrick or rig to be used, or added safety when using a larger one.
  • the remainder of the string above the bridge plug 8 is fluid filled with a third .or heavier fluid 13, such as drilling mud.
  • a third .or heavier fluid 13 such as drilling mud.
  • the larger effective weight of the remaining non-flotation portion forces the flotation cavity pipe string portion to the other (i.e., higher incline angle) portions of the well bore 2 (see Figure 3). These other well portions may be nearly horizontal.
  • the non-flotation portion may extend to the surface, i.e, fill the remainder of the string with the heavier fluid 13.
  • string installation may require a second or multiple floating portions within the string, separated by other bridge plugs 8, especially for deviated hole portions having different angles.
  • a retrieving device is run on the end of drill pipe and latched on the retrieving stem (or fishing neck) 14.
  • the ports 15 are opened by the action of the drill pipe latching or twisting onto the retrieving dog on stem 14.
  • the ports 15 may also be remotely actuated in an alternative embodiment. These opened venting ports 15 allow the higher density fluid 13 to exchange places with the lower density fluid (air) in cavity 12.
  • the bridge plug 8 is also then deflated by twisting and/or pulling on the retrieving stem 14.
  • An alternative embodiment can separately actuate cavity pressurisation/venting and bladder inflation/ deflation. Cavity pressurization may not be required if the string can withstand the differential pressure. Fluids (water in this embodiment) used to inflate bladder and pressurize cavity can also be segregated in this alternative embodiment.
  • the latch-in collar 16 is attached to the casing or liner string 4 near the float collar/float shoe end (see Figure 1) of the cavity 12a.
  • the latch-in collar 16 includes a threaded or latching aperture 17 (shown dotted in Figure 2 for clarity) which engages a threaded or latching protrusion 18 of an air release plug holder 19 of an air trapping device (or member) 20.
  • the piston-like air trapping device 20 also includes an air release plug 22 (shown dotted for clarity).
  • a first set of (or passage) shear pins 23 attaches the release plug 22 to an internal port (or passageway) 24 (shown dotted for clarity) within the plug holder 19.
  • a second set of (or plug holder) shear pins 21 attaches the plug holder 19 to the liner/casing 4.
  • the size and shape of the plug 22 and internal port 24 allow the sheared away plug 22 to slide down (direction "A" is towards the well bottom, not necessarily vertically down) toward the protrusion 18.
  • the internal port 24 is in fluid communication with both the cavity 12a below (through slotted ports 25) and the non-flotation fluid 13 above the translated plug 22.
  • the lateral slotted ports 25 allow fluid passage to and from the lower portion of the internal port 24 and the cavity 12a (fluid flow shown as a solid and dotted arched arrow).
  • the height of plug 22 is selected to be less than height of the slotted ports 25, allowing fluid flow in this lower portion.
  • a basket 26 near the bottom of the air trapping device 20 acts as a retainer of the plug 22 within the internal port 24 when the passage shear pins 23 break and plug 22 moves downward under fluid pressure from above.
  • a cement slurry is introduced into the string above the air trapping device 20.
  • a bottom wiper plug 27 separates the cement slurry above wiper plug 27 from the drilling mud 13 above the air trapping device 20.
  • a third set of (or wiper) shear pins 30 attaches an inner wiper plug 29 to a wiper plug port 28 (shown dotted) of the wiper plug 27. The inner plug 29 prevents fluid communication above and below the wiper plug 27 until the inner plug 29 moves (i.e., is sheared away) from the plug port 28.
  • Each set of shear pins is selected to rupture at increasingly incremental pressures above normal operating hydrostatic pressure within the string.
  • This alternative embodiment uses a (differential) pressure increment of 34 atmospheres (500 psi) to prevent accidental actuation (shearing).
  • the first set of shear pins 23 rupture at approximately 34 atmospheres (500 psi) over hydrostatic (allowing air to vent and mud to circulate)
  • the second set of shear pins 21 (allowing the piston-like trapping device to translate) are set at approximately 68 atmospheres (1000 psi) over hydrostatic
  • the third set of shear pins 30 (allowing cement slurry flow) are set at approximately 102 atmospheres (1500 psi) over hydrostatic.
  • FIGS 3a through 3f show simplified representations of the alternative apparatus shown in Figure 2 during well completion activities in the deviated well bore 2.
  • the inclined angle "i" angle between the center line of the slanted well portion and the vertical shown in Figure 3a
  • a positive means to prevent fluid inflow to the bottom of the air filled cavity is needed, i.e., float shoe 5.
  • Lower incline angle holes may avoid using a float shoe, depending upon density differences and the lack of fluid miscibility to limit inflow to the flotation portion.
  • Large incline angles "i” can also indicate the need for a flotation method of running the casing into the hole.
  • FIG 3a shows the initial apparatus positions after installing the string 4 in the deviated well bore 2.
  • the cavity 12a includes landing collar 16 between the float shoe 5 and air trapping device 20.
  • the air release plug 22 (shown darkened for clarity) is shear pin attached to air trapping device 20 (see Figure 2).
  • Cavity 12a contains trapped air or other low density fluid, creating buoyancy during the (just completed) insertion of the string portion into the bore hole 2 containing drilling mud 7.
  • drilling mud 7 is also the non-flotation fluid (see item 13 in Figure 1) present above the air trapping device 20 in a non-flotation (or high density fluid filled) cavity portion 31.
  • the apparatus geometry and mud density can be adjusted to control buoyancy and the effective weight of the casing 4 proximate to the cavity 12a.
  • Figure 3b shows the apparatus of Figure 3a after rupturing the first set of shear pins 23 (see Figure 2) and movement of the air release plug 22.
  • An increased pressure above the air trapping device 20 sheared the first set of pins.
  • the positions of the elements are unchanged except for the release plug 22.
  • the sheared-away release plug 22 may be biased and/or pressure actuated to slide towards the cavity 12a to open ports 25 (see Figure 2). Opening ports 25 allow fluid communication between the air cavity 12a and non-flotation (i.e., filled with a higher density fluid) cavity portion 31.
  • the air from cavity 12a migrates upward in the casing ox liner 4 so that it may be then vented at the surface. In wells that have an incline angle of greater than 90 degrees, it may be necessary to positively vent air from cavity 12a.
  • the drilling mud 7 and displaced air form a mud-air interface 32 in the previously weighted cavity 31.
  • the previously buoyant cavity 12a is now full of drilling mud 7.
  • Another alternative embodiment can provide a plurality of internal ports 24 and release plugs 22. This embodiment would assure migration/displacement of fluids in various orientations, e.g., at least one internal port primarily for venting air towards the surface, another for flowing drilling mud into cavity 12a.
  • FIG 3d shows the devices after installing and pumping a bottom wiper 27 (i.e., a plug wiping the interior surface of the string as it moves) to mate with the air trapping device 20.
  • a bottom wiper 27 i.e., a plug wiping the interior surface of the string as it moves
  • Above the bottom wiper 27 is a cement slurry 33.
  • Drilling mud 7 within the casing 4 above air trapping device 20 has been displaced through passage 24 (See Figure 2) in the air trapping device 20, landing collar 16, and flapper valve 6 of the float shoe 5 (see Figure 1).
  • a top wiper 34 contains the cement slurry 33 between the two sliding and sealing wipers.
  • Wiper plug 29 contains the cement 33 between the landed assemblage at the landing collar 16 and the top wiper 34.
  • the drilling mud 7 previously contained in cavity 12a has been displaced and flowed though the landing collar 16 and flapper valve 6 of float shoe 5 into the annular space between well bore 2 and casing/liner 4. Displaced drilling mud continues to flow through the float shoe 5 until the top wiper 34 joins the assemblage. Applying another pressure increment tends to shear the third shear pin set 30 (see Figure 2) holding the wiper plug 29.
  • Figure 3f shows the top wiper plug 34 joined to the assemblage and cement slurry 33 nearly fully displaced out of the string ' 4 to the annulus between the casing/liner 4 and well bore 2. Shearing and displacing the wiper plug allows the cement to flow through the bottom wiper plug 27 and the slotted ports 25 (see Figure 2) to the annulus between the casing 4 and well bore 2 through flapper valve 6. The pressurized cement flow also causes the top wiper 34 to slide and contact the bottom wiper plug 27. The cement-mud interface 35 (previously separated by bottom wiper 27) is now in the annulus between the well bore 2 and casing 4. A portion of the cement slurry 33 remains between the assemblage and float shoe 5. This residual cement is drilled out (after setting) in normal post cementing operations (not shown).
  • FIG. 4 shows a side and partial cross sectional view of the engaged bottom wiper 27 and pinned air trapping device 20 assemblage within a joint in the casing string 4.
  • the casing string 4 (shown quarter sectioned) in hole 2 is composed of many sections of pipe segments 36 joined by a drift (or piping) collar 37 at each end.
  • the piping collar 37 is internally threaded to join the external threaded ends of pipe segments 36.
  • the illustrated pipe string joint is typical of the string of joined pipe segments.
  • An alternative pipe string can used without interconnecting pipe segments, avoiding the need for a piping or drift collar 37.
  • the piping shown is attached to the air release plug holder 19 portion of the air trapping device 20 (shown in cross section) by the second set of shear pins 21.
  • the air trapping device 20 also includes a pair of holder O-ring seals 38 forming a fluid tight sliding connection to the interior of the string 4.
  • the internal port 24 is attached to the air release plug holder 19 portion of the air trap
  • FIG. 2 (see Figure 2) includes an initial threaded portion 39, a cylindrical wiper plug mating portion 40 and a release plug cylindrical portion 41.
  • the plug 22 was retained by the first set of shear pins 23 (shown sheared in Figure 4). A pressure differential was applied sufficient to break the plug shear pins 23 and translate the plug 22 to rest against the perforated basket 42 (similar to basket 26 shown in Figure 2).
  • The-.plug 22 also includes a plug O-ring seal 43 which, when plug 22 is pinned in the initial position, formed a fluid tight sliding seal to the plug cylindrical portion 41 of the internal port 24 (see Figure 2).
  • the perforated basket 42 catches and prevents further translation or loss of the plug 22.
  • the perforations of basket 42 and ports 25a allow fluids to pass around the displaced plug 22.
  • the air trapping device 20 also includes a latch protrusion 18 which attaches to the landing collar 16 (see Figure 3) after the second set of shear pins 21 are broken and the assemblage has been displaced to landing collar 16.
  • the protrusion 18 and latch or threaded portion 39 prevent rotation of the assemblage (wiper plugs, air trapping device and landing collar) when the assemblage is being drilled out.
  • the bottom wiper plug 27 (shown in side view for clarity within sectioned casing string 4) includes a series of elastomeric cup shaped wipers 44, an external threaded or latch portion 45 (threadably mating with the internal threaded or latch portion 39 of the air trapping device 20), a pair of elastomeric wiper O-rings 46 (shown darkened for clarity and bearing against the interfacing passageway portion 40), and (hidden from view) an inner plug 29 held in place within wiper port 28 by a third set of shear pins 30 (see Figure 2).
  • An alternative embodiment can extend the bottom wiper dimensions to positively displace the plug 22 when bottom wiper contacts and mates with air trapping device 20 (see Figure 2).
  • Other types and locations of elastomeric seals, and other mating shapes and dimensions may also be provided for other alternative embodiments.
  • Solid materials of construction of the air trapping device 20 are primarily 6061 aluminum, but various other materials of construction-,can be used, as long as they are drillable or otherwise removable.
  • the bottom wiper 27 acts as a sliding and wiping seal or separator along the interior of the casing.
  • the bottom wiper 27 separates cement on the upstream side from fluid on the downstream side during certain fluid movements, i.e., slurry cement pumping down-well (direction "A").
  • the orientation (right hand engaging) of the external and internal threads shown in Figure 4 are selected to tighten or engage the air trapping device during drilling and prevent unlimited rotation.
  • a further advantage of this embodiment is the use of existing components, simple fabrication and design.
  • the top and bottom wiper plugs can be produced by modifying a commercially available liner wiper plug.
  • the use of 6061 aluminum results in light weight and easily machinable components of the device.
  • FIG 5 shows a side cross-sectional view of another alternative embodiment of an air trapping device or an air plug 20a.
  • a second set of shear pins 21 attaches the air plug 20a to the casing pipe string 4.
  • the air plug 20a is similar in construction to a conventional bottom cementing plug.
  • the air plug 20a includes an aluminum insert 48 covered by rubber wipers 44.
  • a rupture diaphragm 49 separates the flotation cavity 12b, retaining air (or other low density fluid such as nitrogen or light hydrocarbon fluids) from the higher density fluid filled cavity 31a.
  • the rupture diaphragm 49 replaces the releasable plug 22 and shear pins 23 of this alternative embodiment (see Figure 2).
  • the rupture diaphragm 49 has the advantage of simplicity, but may not be capable of withstanding the down hole pressures and forces or be removable without difficulty. Still other alternative embodiments could replace other slidable plugs and inserts with rupture or burst diaphragms. Once the casing or liner string is run to the total or desired depth, increased pressure is applied to burst the diaphragm 49. Similar to the previous discussion, the ruptured diaphragm allows the trapped air from cavity 12b to migrate to the top of the well and be replaced by drilling mud. The air is again vented at the surface (not shown for clarity). Circulation of the drilling muds can now be accomplished in this embodiment, if required. Near normal cementing operations can now be accomplished.
  • Figure 6 is a graphical representation of the results of a test of the flotation method in a deviated underground well bore. The devices and methods used were similar to those shown and described in Figure 1.
  • Figure 6 shows the actual and expected indicator (or slack-off) weight supported during installation of the casing pipe string 4 (see Figure 1). The string was installed by sections from a derrick at the surface.
  • the remaining string portion above the air filled cavity was filled with drilling mud.
  • the actual and flotation expected curve shape (dotted and associated dashed line portion “D"), are similar to, but displaced from, the expected non-flotation curve shape (solid line “B”). This displacement allows the string to be placed to a greater depth (depth increment "E") before the supported weight becomes insufficient to move the string into the bore hole.
  • the dotted and dashed curve shape (and ability to install casing or liner) can be altered by changing the number and length of the floated sections as well as by using a flotation fluid other than air or changing the density of the mud in the borehole or the mud above the flotation device.
  • the prior art non-flotation method (shown as a solid curve) was expected to produce a larger maximum force (or indicator weight as shown at point "F") to overcome the later developed frictional drag when compared to the flotation method maximum indicator weight (point "G") .
  • the mud filled sections generate more drag (shown by the indicator weight declining with depth) than can be overcome by weight (i.e., exceeds critical incline angle). If the particular well included an even higher incline angle section, the decline in indicator weight would be even more severe.
  • results of this test example show that flotation of the casing displaced and maintained a controlled margin of supported weight during the entire installation procedure, avoiding a stuck casing.
  • results also show that a reduced maximum indicator weight was achieved while allowing a deeper installation and avoiding multiple drilling out procedures.
  • Figure 7 shows a schematic side view, similar to
  • FIG 2 of another alternative embodiment (i.e., an air annulus embodiment) of the apparatus when near the location where the casing is to be set (i.e., one end of a casing string 4 ⁇ is near the bottom of the wellbore 2).
  • the extended reach wellbore 2 contains one or more drilling muds 7 having densities greater than air (or other fluid in cavity 12b) and a casing string 4.
  • a portion of the casing string 4 and ported packers/ retainers 55 and 56 forms the exterior surfaces of a modified "flotation" cavity 12b, similar to the cavity 12a shown in. Figure 2a.
  • the casing string 4 also contains drilling mud 1 , similar to Figure 2a.
  • the pipe string 4 has a float shoe 5 and float collar 16 attached proximate to one end of the pipe string similar to Figure 2, but the ends of the modified cavity 12b within the pipe string 4 is defined by a pair of inflatable packers/retainers 55 and 56, similar to the bridge plug 8 shown in Figure 1.
  • the air annulus embodiment also contains a conduit 60 forming the interior surface of (i.e., is surrounded by) cavity 12b.
  • the conduit 60 provides a passageway for fluids from one end of the modified cavity 12b to another (i.e., conduit 60 is attached to ports in the upper inflatable packer 55 and lower cement retainer 56).
  • the conduit 60 is attached in this embodiment to a surface connecting conduit 61 (typically a string of smaller diameter drill pipe sections) within the remainder of the casing string 4.
  • the fluid shown within conduits 60 and 61 is drilling mud 7, allowing drilling mud 7 to be circulated during running or other operations, but a cement slurry or other fluid may also be conducted.
  • Mud circulation i.e., pumping drilling mud at the surface through the casing string 4, surface connecting string 61, and conduit 60 to the borehole 2 through float collar 16 and float shoe 5 to the annular space between the casing string 4 and borehole- 2, then screened or filtered to remove particles (e.g. cuttings or other formation solids) prior to returning to the surface pump) allows lubrication and other fluid properties to assist in the running operations, while the casing string is buoyed within the drilling muds in the borehole 2.
  • a wire-line plug is then set in a fitting (e.g., an XN nipple) in conduit 60 and tested.
  • Packer 55 is then inflated and tested.
  • Plug 63 is then pulled and conduit 60 is filled with mud 7.
  • the remaining portions of the casing 4 are run in hole while circulating mud 7.
  • the surface connecting conduit 61 is run in hole, latching and sealing at overshot connector 62 to conduit 60.
  • the casing 4 is reciprocated (i.e., translated in an oscillating manner along the borehole axis) and drilling mud 7 is circulated until clean (free of filterable solids).
  • a cement slurry is then pumped down the surface connecting conduit 61 and conduit 60 while the casing is reciprocated.
  • Inflatable packer 55 can be deflated before or after cement setting, along with the venting of air in cavity 12b and pulling out surface connecting conduit 61, conduit 60, inflatable packers/retainers 55 & 56.
  • a similar procedure is used to run, rotate and cement a liner (not shown, but similar to casing 4 shown in Figure 7).
  • the liner is a tubular string to be contained in a lower portion of the borehole 2 and attached or hung from a larger diameter up-hole casing section. At least a first portion of a liner is run into the borehole 2.
  • the lower cement retainer 56, plug 63 and upper inflatable packer 55 are similarly set and tested in the liner. Plug 63 is removed and the assembly is filled with drilling mud 7 except for cavity 12b.
  • the surface connecting conduit 61 is similarly latched and sealed to connector 62, followed by running the liner and surface connecting conduit 61 in hole.
  • the liner is then rotated (in an oscillating or continuous manner) and drilling mud is circulated clean.
  • a cement slurry is pumped down the conduits out to the borehole/liner annulus while the liner continues to be rotated, again improving distribution and bond strength.
  • the liner is released (hung on casing), the packer is deflated, and surface connecting conduit (drill pipe), packer(s) and conduit are pulled out.
  • a modified air trapping device similar to the device 20 shown in Figure 2 may be used in place of the upper inflatable packer 55.
  • the modified device includes another port for connecting to conduit 60.
  • conduit 60 may be directly connected to a modified float shoe or float collar, similar to the shoe 5 and collar 16 shown in Figure 2.
  • a 17.8 cm (7 inch) nominal diameter, 129 newtons (29 pound) nominal weight liner string approximately 1676.4 meters (5,500 feet) long is to be run to 4572 meters
  • the well path after an initial near vertical section of approximately 304.8 meters (1000 feet) is planned to include a build section where an incline angle build rate of approximately 3.5 degrees per 30.48 meters (100 feet) is maintained until an incline angle of 80.88 degrees is reached at approximately 1009.2 meters (3311 feet) measured depth.
  • the incline angle of approximately 80.88 degrees is to be held until a measured depth of4572 meters (15,000 feet) is reached.
  • a 9 5/8 inch (24.45 cm) nominal diameter casing is planned to extend to 3048 meters (10,000 feet), with an expected friction factor during running of the liner within the casing of 0.35.
  • the expected friction factor in the nominal 21.59 cm (8 1/2 inch) diameter hole extending from 3048 meters (10,000 feet) to 4572 meters (15,000 feet) is 0.50.
  • the planned mud has a density of approximately 1121 kilograms per cubic meter (70 pounds per cubic foot).
  • 1.814 kilogram (4 pound) tubing i.e., conduit 60 shown in Figure 7 within the liner, a buoyed weight of approximately 24.40 newtons/meter (18.00 pounds/foot) compared to a flotation cavity 12a (see Figure 2) within a liner buoyed weight (without tubing) of 33.69 newtons/meter (24.85 pounds/foot) .
  • shear pins placement of cylindrical or otherwise ported solid inserts (e.g., foam) or higher density fluid into the flotation cavity 12 in addition to lower density (flotation) fluids (to improve the control of buoyant forces); combining the float shoe, float collar, and/or the landing collar in a single component; combining centralizing (outward radial) protrusions on the string (to create a string stand off annulus within the well bore) with multiple trapping devices at pipe joints; replacing the float shoe valve with a float type trap or other back-flow preventer; and having translating components, conduits, and piping strings primarily composed of flexible material (to more easily navigate deviated sections and alter buoyant forces).
  • cylindrical or otherwise ported solid inserts e.g., foam
  • lower density (flotation) fluids to improve the control of buoyant forces
  • combining the float shoe, float collar, and/or the landing collar in a single component combining centralizing (outward radial) protrusions on the string (to create
  • a still further alternative embodiment is to make portions of the devices such as plugs from materials which are dissolvable, thermally degradable or fluid reactive/decomposing (avoiding pressure increments or drilling out procedures). Although no longer required, lubricants can also be used in conjunction with these flotation methods and devices to further control or reduce the running coefficient of friction.
  • opening a circulation and cementing path can be accomplished by a simple increase ⁇ in pressure and translation of insert/plug devices without entirely removing the devices. This embodiment also allows circulation during buoyant operations and reciprocating/rotation during cementing. Devices are finally removed by normal post-cementing drilling out techniques, avoiding the need for a separate removal step.
  • the use of air and lightweight materials minimizes storage and other related requirements.
  • the present invention also reduces the maximum capability of the drill rig needed to accomplish the setting of the casing/liner string and extended reach well could theoretically have an infinite length (i.e., total measured depth) if flotation cavity sections are at neutral buoyancy. More typically, the invention provides major advantages for higher than critical incline angle (e.g., nearly horizontal) well portions (to be lined or cased) of at least 914 meters (3,000 feet) in length , more preferably at least 1524 meters (5,000 feet), and still more preferably at least 1828 meters (6,000 feet) in length.
  • the buoyancy forces also allow a high build rate, limited only by the flexibility of the liner or casing tubular members.
  • the buoyant forces can theoretically provide a bending force without scraping (and possibly damaging or excessively opening) the build portion of the wellbore. More typically, the invention provides major advantages for build rates of at least approximately 2.0 degrees per 30.48 meters (100 feet), more preferably a build rate of at least approximately 3.5 degrees per 30.48 meters (100 feet). Further advantages of the device include: increased safety (avoiding large casing running loads at the drilling platform), reliability (reducing the likelihood of stuck casing), maintenance (single use, drillable compo ents), efficiency (full flow production/ injection capability), and reduced cost (no separate removal step or need to recover items from great depth).
  • Flotation devices for and methods of accomplishing drilling and completion of extended reach wells are also disclosed in paper entitled "Extended Reach Drilling From Platform Irene," by M.D. Mueller, J.M. Quintana, and M.J. Bunyak, presented to the 22 Annual Offshore Technology Conference in Houston, Texas, May 7 - 10, 1990, the teaching of which are incorporated herein by reference.
  • a hydraulic release oil tool which may be used advantageously with the present invention is disclosed in U.S. Patent Application Serial No. 07/418,510, filed on October 9, 1990, the teachings which are incorporated in their entirety by reference.
  • the release tool may be used to removably attach a drill string to a liner having a flotation cavity and being run into an extended reach wellbore.
  • the release tool allows bidirectional rotation and high torque, combined with ease of release and removal.

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  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
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  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Marine Sciences & Fisheries (AREA)
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Abstract

Un sabot à clapet inverse à orifices (5) et un collier d'ancrage (16) sont fixés à une première extrêmité d'une partie d'une colonne de cuvelage (4) et un élément rapporté coulissant pour piéger l'air (20) est fixé à l'autre extrêmité. L'élément rapporté piégeant l'air (20) comprend un passage pour le flux de liquide (24) bloqué par un dispositif (22) fixé par des broches de cisaillement à l'élément rapporté (20) ou bien l'élément rapporté piégeant l'air est un élément rapporté expansible (55) dont une conduite (60) offre un passage au liquide vers la première extrêmité. L'élément rapporté piégeant l'air et le sabot à clapet inverse forment une cavité d'air (12a ou 12b) à l'intérieur de la partie de colonnes (4). La cavité d'air crée des forces de flottations au cours des opérations de descente dans la colonne, de cimentation, ou au cours d'autres opérations de cuvelage dans un puits de forage (2) réduisant la probalité d'avoir un écoulement de retroussement et la probalitité correspondante d'avoir un cuvelage calé différemment (4). Cette cavité d'air permet aussi le mouvement alternatif et la rotation au cours de la cimentation et elle évite les étapes de démontage distinctes.
EP90913295A 1989-08-31 1990-08-22 Appareil et methode de flottation pour colonnes de cuvelage Withdrawn EP0489816A1 (fr)

Applications Claiming Priority (6)

Application Number Priority Date Filing Date Title
US07/401,086 US4986361A (en) 1989-08-31 1989-08-31 Well casing flotation device and method
US48631290A 1990-02-28 1990-02-28
US486312 1990-02-28
US560389 1990-07-31
US07/560,389 US5113411A (en) 1989-07-31 1990-07-31 Modulator and demodulator for data transmission systems
US401086 2003-03-27

Publications (1)

Publication Number Publication Date
EP0489816A1 true EP0489816A1 (fr) 1992-06-17

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EP90913295A Withdrawn EP0489816A1 (fr) 1989-08-31 1990-08-22 Appareil et methode de flottation pour colonnes de cuvelage

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EP (1) EP0489816A1 (fr)
JP (1) JPH05500695A (fr)
AU (1) AU6345890A (fr)
BG (1) BG95990A (fr)
BR (1) BR9007627A (fr)
CA (1) CA2065338A1 (fr)
FI (1) FI920904A0 (fr)
HU (1) HUT60362A (fr)
WO (1) WO1991003620A1 (fr)

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US9624764B2 (en) 2013-06-12 2017-04-18 Colorado School Of Mines Method and apparatus for testing a tubular annular seal

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US5174375A (en) * 1989-10-10 1992-12-29 Union Oil Company Of California Hydraulic release system
US5829526A (en) * 1996-11-12 1998-11-03 Halliburton Energy Services, Inc. Method and apparatus for placing and cementing casing in horizontal wells
US6505685B1 (en) 2000-08-31 2003-01-14 Halliburton Energy Services, Inc. Methods and apparatus for creating a downhole buoyant casing chamber
US6622798B1 (en) 2002-05-08 2003-09-23 Halliburton Energy Services, Inc. Method and apparatus for maintaining a fluid column in a wellbore annulus
CA2819681C (fr) 2013-02-05 2019-08-13 Ncs Oilfield Services Canada Inc. Outil de flottage pour tubage
WO2019067754A2 (fr) * 2017-09-29 2019-04-04 Bp Corporation North America Inc. Systèmes et procédés pour mesurer les positions de fluides dans un puits
US11125044B2 (en) 2019-03-06 2021-09-21 Saudi Arabian Oil Company Pressurized flotation for tubular installation in wellbores
CA3170864A1 (fr) * 2020-03-10 2021-09-16 Tristam Paul HORN Appareil et procedes de fond de trou
GB2592937B (en) * 2020-03-10 2024-05-08 Deltatek Oil Tools Ltd Downhole apparatus and methods
GB2601556A (en) * 2020-12-04 2022-06-08 Deltatek Oil Tools Ltd Downhole apparatus
CN118008198B (zh) * 2024-04-09 2024-06-14 山东省鲁南地质工程勘察院(山东省地质矿产勘查开发局第二地质大队) 一种用于地质抽水试验的止水设备

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US3572432A (en) * 1969-09-25 1971-03-23 Halliburton Co Apparatus for flotation completion for highly deviated wells

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Cited By (1)

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Publication number Priority date Publication date Assignee Title
US9624764B2 (en) 2013-06-12 2017-04-18 Colorado School Of Mines Method and apparatus for testing a tubular annular seal

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BR9007627A (pt) 1992-08-18
CA2065338A1 (fr) 1991-03-01
JPH05500695A (ja) 1993-02-12
FI920904A0 (fi) 1992-02-28
WO1991003620A1 (fr) 1991-03-21
BG95990A (bg) 1993-12-24
AU6345890A (en) 1991-04-08
HU9200682D0 (en) 1992-05-28
HUT60362A (en) 1992-08-28

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