Wells – Submerged well – Means removably connected to permanent well structure
Reexamination Certificate
2001-10-24
2003-04-01
Bagnell, David (Department: 3673)
Wells
Submerged well
Means removably connected to permanent well structure
C166S338000
Reexamination Certificate
active
06540025
ABSTRACT:
BACKGROUND OF THE INVENTION
1. Technical Field
The present invention relates to travel joints used in subterranean wells. More particularly, the present invention related to reusable travel joints. Still more particularly, the present invention relates to a reusable travel joint able to be reliably activated in highly deviated wellbores.
2. Description of the Related Art
Drilling rigs supported by floating drill ships or floating platforms are often used for offshore well development. These rigs present a problem for the rig operators in that ocean waves and tidal forces cause the drilling rig to rise and fall with respect to the sea floor and the subterranean well. This vertical motion must be either controlled or compensated while operating the well.
FIG. 1A
depicts a typical offshore rig operation involving ship
102
, which supports rig
104
. Without compensation, such vertical movement would transmit undesirable axial loads on a rigid tubing string within well casing string
106
, which is extended downwardly from ship
102
. This problem becomes particularly acute in well operations involving fixed bottom hole assemblies, such as the packers depicted in box
110
and further depicted in
FIGS. 1B and 1C
.
In the depicted example, packer
112
has been previously set in casing string
106
. As is known in the art, packer
112
includes a receiving orifice for connection with a packer stinger located at the bottom of tubing
114
. The connecting operation, or “stinging in” requires that tubing
114
apply an amount of force for makeup depending on the particular packer. Different mechanisms exist for stinging in, such as a “J-latch” connection, which requires rotational force to latch the “J” or a force actuated latch which uses vertical force from tubing
114
. When seals within the packer are in place against the stinger, the stinger is fixed in place.
Once the stinger is in place, any vertical movement from the ship or platform will create undesirable downward and upward forces on packer
112
or may cause premature failure of components or may sting out the stinger from packer
112
. What is needed is a means to compensate for the movement of the drilling ship or platform. Normally, the solution has been to place a travel joint in the tubing string, which compensates for the movement of rig
104
by axial telescoping action, as depicted in
FIGS. 1B and 1C
.
FIG. 1B
illustrates travel joint
116
in the latched or locked position, that is a position that allows the rig operators to apply the force needed to sting in packer
112
. Travel joint
116
is unlocked by different means, depending on the type of locking mechanism. One type of locking mechanism uses a shear pin that is forcibly sheared when the travel joint is unlocked. The shear pin is used to prevent the travel joint from inadvertently unlocking. One problem with this design is that the travel joint can only be unlocked once and then must be re-dressed with a new shear pin prior to subsequent use. Another type of locking mechanism uses a “J-latch” similar to that described above, is used for stinging into a packer. While this mechanism allows travel joint
112
to be locked and unlocked a number of times without re-dressing the travel joint, it has the disadvantage in that the type of packer must be considered prior to using a J-latch type travel joint. This is so because of the possibility of inadvertently stinging out of the J-latch packer that requires a similar rotational force as unlocking the travel joint. In a related packer consideration problem, certain packers allow the stinger to freely rotate within the packer, and those packers may not transmit the needed rotational resistance for unlocking or locking the J-latch on the travel joint. Therefore, the travel joint may not unlock, or worse, may not lock back in position. The benefits derived from having a travel joint in a tubing string can only be realized if the travel joint can be reliably unlocked from the surface.
FIG. 1C
illustrates travel joint
116
in the unlocked position with tubing
114
telescoping into both travel joint
116
and upper tubing
118
. After travel joint
116
is unlocked, the travel joint and upper tubing
118
may be telescoped over tubing
114
. Lower tubing
114
may be a lighter weight than upper tubing
118
and use flush joint connections
120
which do not increase the exterior diameter of tubing
114
, allowing travel joint
116
and tubing
118
to be telescoped over more than a single joint of tubing. However, as a general rule, the first joint of lower tubing
114
will be a machined joint custom manufactured for use with travel joint
116
.
Another problem common to both of the above-described locking mechanisms is premature unlocking in highly deviated wellbores. In offshore drilling operations it is routine to drill a number of wells from a single platform. Each well is directionally drilled to a target location in the zone of interest, which may be a lengthy horizontal distance from the platform itself. Therefore, during a trip into the well, the wellbore string slides, or is pushed, along the inner wall of casing
106
rather than merely being lowered in the center of casing
106
. Significant forces build up, which oppose the wellbore string's being lowered into the wellbore, which may unlock travel joint
116
prior to the stinger being seated in packer
112
. Once unlocked, it is virtually impossible to sting into packer
112
without re-locking the travel joint. This may require an additional trip out of the well to re-dress the travel joint.
Still another problem is the uncertainty as to whether a premature unlocking has taken place. Using a prior art type travel joint, no accurate means is available for gauging whether a travel joint has become unlocked. Often the first indication that the travel joint is in the unlocked position manifests itself when the stinger will not sting into the packer. At that point, the entire well string must be completely removed from the wellbore, reset or re-dressed, and then run in again with the hope that the travel joint will not unlock again. Therefore, a wireline collar locator is often run into the wellbore to confirm that the travel joint is locked and the lower tubing is in place.
Still another problem with prior art travel joints involves the hard release inherent in the shear pin locking means. Conventionally, after a bottom hole assembly is first stung into a packer, tubing weight is applied across the travel joint, severing the shear pin, and unlocking the travel joint. Prior art shear pin-type travel joints unlock hard due to the energy stored in the tubing being released when the shear pin severs. In highly deviated wells, or wells with known tight spots, higher shear pin strengths are necessary because of the possibility of premature pin breakage. The higher the shear rating on the pin, the more stored up energy in the tubing to be released when the pin shears. This may cause damage to the tubing hanger or seat if the two make contact when the travel joint unlocks. A collar locator is often run on wireline prior to stinging into the packer to conform tubing spacing and lessen the chance of hanger or seat damage.
Further, by eliminating the wireline intervention to verify the travel joint location there is a significant reduction in the risk associated with such operations, namely the breakage of the wireline, the risk of fishing in the wellbore, and damage to the seal bore, nipple seal, nipple bore, and other inner diameter restrictions in the wellbore.
It would be advantageous to provide a smooth release travel joint which eliminated the need for a wireline depth determination. It would be advantageous to provide a travel joint with a reliable re-locking means. It would also be advantageous to provide a travel joint with a reliable locking and unlocking means for highly deviated wells. It would be further advantageous to provide the operator with an indication that the travel joint has become unlocked.
SUMMARY OF THE INVENTION
In accordance wi
Echols, III Ralph H.
Scott Gordon K.
Thomas Phillip T.
Bagnell David
Carstens David W.
Halliburton Energy Service,s Inc.
Kreck John
LandOfFree
Hydraulically metered travel joint method does not yet have a rating. At this time, there are no reviews or comments for this patent.
If you have personal experience with Hydraulically metered travel joint method, we encourage you to share that experience with our LandOfFree.com community. Your opinion is very important and Hydraulically metered travel joint method will most certainly appreciate the feedback.
Profile ID: LFUS-PAI-O-3035675