Patent Application
20100032155
The present invention relates to a formation saver sub and method for sealing well tubing so that pump out pressure may be achieved to actuate a well tool, and more particularly to a formation saver sub that incorporates an anti-surge feature.
In oil or gas wells, well tools, such as hydraulic packers, are manipulated by fluid pressure in the well tubing. To obtain increased pressures in the well tubing, a pump out sub is used that plugs the well tubing so that pressure may be increased to actuate the well tool. The pump out sub contains a seat that receives a plug, such as a ball or dart, which is dropped down the well tubing. After actuation of the well tool, the plug is dislodged from the seat by increasing fluid pressure to a level that a shear pin holding the seat in place is sheared. The seat moves downward within the well tubing and the plug is disassociated therefrom passing downward through and out of the well tubing. An example of a pump out sub is described in U.S. Pat. No. 4,510,994, issued Apr. 16, 1985, which is incorporated herein by reference.
Conventional pump out subs are susceptible to formation surge because of the differential pressures that must be used to release the plug. Accordingly, there is a need for an improved pump out sub that reduces or eliminates formation surge.
It is an object of the present invention to provide a pump out sub that contains an anti-surge feature.
It is a further object of the present invention to provide a pump out sub with the capability of bleeding off well tubing pressure before releasing the plug and seat.
It is a further object of the present invention to provide a pump out sub with a backup contingency feature that permits the shearing of the dog system to release the plug and seat.
It is a further object of the present invention to provide a pump out sub with a small outer diameter capable of accommodating dual packer applications.
It is a further object of the present invention to provide a pump out sub capable of using both a ball or dart system for plugging the well tubing.
It is a further object of the present invention to provide a pump out sub capable of causing multiple pressure increases within the well tubing to actuate a well tool or tools.
It is a further object of the present invention to provide a pump out sub capable of causing different pressure increases within the well tubing to manipulate a well tool or tools.
The objects of the present invention are achieved by the novel formation saver sub of the present invention that has a tubular body including an upper section, a middle section, a lower section, an outer surface, and an inner surface. The upper section of the body is adapted for connection to the well tubing. The upper section of the body may be threadedly connected to the well tubing. The well tubing has a well bore.
The sub also includes a mandrel having an upper section, a middle section, a lower section, an outer surface and an inner surface defining a mandrel bore. The upper section of the mandrel is adapted for connection to the well tubing. The upper section of the mandrel may be threadedly connected to the well tubing. The mandrel is positioned interior of the body. When the sub is assembled and connected to the well tubing, the well bore and the mandrel bore are in alignment.
The sub further includes a piston having an upper section, a middle section, a lower section, an outer surface, and an inner surface. The piston is positioned between the inner surface of the body and the outer surface of the mandrel. The piston may include a fluid chamber. The mandrel may also include a passage for fluid communication between the mandrel bore and the fluid chamber of the piston.
Also included in the sub is a sleeve having an upper section, a middle section, a lower section, an outer surface and an inner surface. The sleeve is connected to the piston. The sleeve may be threadedly connected to the piston. The sleeve is positioned between the inner surface of the body and the outer surface of the mandrel.
The sub further has a shear means detachably affixing the sleeve to the mandrel. The shear means may be one or more shear pins, screws, or rings.
A seat is also part of the sub and includes an upper section, a middle section, a lower section, an outer surface, and an inner surface defining a seat bore. The seat is releasably positioned in the mandrel bore. The upper section of the seat is adapted to receive a plug. The plug may be a ball or dart.
The sub further includes a spring means positioned between the inner surface of the body and the outer surface of the mandrel. The spring means cooperatively engages with the piston.
The formation saver sub of the present invention is used in a method of actuating a well tool connected to the well tubing. The process includes connecting the formation saver sub to the well tubing below the well tool. The well bore above the seat of the sub is plugged or sealed by dropping the plug through the well bore to the mandrel bore where the plug seats in the upper section of the seat. The well tool can be manipulated by increasing fluid pressure in the well bore to activate and deactivate the well tool. After operations involving the well tool are completed, it is desirable to unplug or unseal the well bore by removing the plug and seat.
Unplugging is accomplished by activating the piston of the sub by increasing the fluid pressure in the well bore to a level that causes: (1) the shearing of the shear means to detach the sleeve from the mandrel; and (2) upward movement of the piston and sleeve resulting in the compression of the spring means. Thereafter, the process involves deactivating the piston by bleeding off the fluid pressure in the well bore to a level that causes: (1) expansion of the spring means; and (2) downward movement of the piston and sleeve to a position that results in the release of the seat from the mandrel bore.
The level of fluid pressure in the well bore sufficient to shear the shear means is in the range of 500 PSI to 15,000 PSI, and more particularly, in the range of 1,500 PSI to 10,000 PSI. The bleed off level of fluid pressure in the well bore sufficient to deactivate the piston is in the range of 100 PSI to 1,000 PSI, and more particularly, is about 500 PSI.
In a further embodiment of the present invention, at least one retractable dog is supported in the mandrel. The dog includes a first end and a second end. The first end of the dog releasably engages the seat to position the seat in the mandrel bore prior to deactivation of the piston as described above. The deactivation of the piston causes the first end of the dog to disengage from the seat to release the seat from the mandrel bore.
In this further embodiment, the mandrel may include a bore-hole with an inner-surface opening and an outer-surface opening. The bore-hole supports the retractable dog. A portion of the inner surface of the sleeve covers the outer-surface opening of the bore-hole in the mandrel prior to deactivation of the piston.
The mandrel may also include biasing means (e.g., springs) positioned in the bore-hole of the mandrel. The biasing means bias the second end of the dog against the portion of the inner surface of the sleeve covering the outer-surface opening of the bore-hole in the mandrel prior to deactivation of the piston. Deactivation of the piston by bleeding off the fluid pressure in the well bore causes expansion of the spring means and downward movement of the piston and sleeve to a position wherein the portion of the inner surface of the sleeve no longer covers the outer-surface opening of the bore-hole in the mandrel; instead, the fluid chamber in the piston now sets adjacent the outer-surface opening of the bore-hole in the mandrel. The biasing means causes the second end of the dog to enter into the chamber of the piston through the outer-surface opening of the bore-hole in the mandrel and the first end of the dog to disengage from the seat and retract into the bore-hole of the mandrel, which releases the seat from the mandrel bore.
The outer surface of the seat in this further embodiment of the present invention may include a recess for engagement of the first end of the dog when the seat is releasably positioned in the mandrel bore. Also, the inner surface of the seat in the upper section may be tapered to accommodate the plug. The seat bore may further include a first bore section and a second bore section. The first bore section may have a larger bore diameter than the second bore section. Seating of the plug in the larger bore section plugs, seals, or blocks the smaller second bore section effectively plugging or sealing the well bore above the seat.
In an alternative embodiment, the formation saver sub has a tubular body including an upper section, a middle section, a lower section, an outer surface, and an inner surface. The sub also includes a mandrel with an upper section, a middle section, a lower section, an outer surface and an inner surface defining a mandrel bore. The mandrel is positioned interior of the body. The sub contains a piston including an upper section, a middle section, a lower section, an outer surface, and an inner surface. The piston is positioned between the inner surface of the body and the outer surface of the mandrel. The sub also has a seat including an upper section, a middle section, a lower section, an outer surface, and an inner surface defining a seat bore. The seat is releasably positioned in the mandrel bore. The upper section of the seat adapted to receive a plug.
In this alternative embodiment, the piston is actuated in a first direction in response to an increase in fluid pressure (e.g., well tubing pressure). Actuation of the piston in the first direction maintains the positioning of the seat in the mandrel bore. The piston is also actuated in a second direction in response to a bleed off of the fluid pressure. Actuation of the piston in the second direction releases the seat from the mandrel bore.
Also in the alternative embodiment the upper section of the tubular body is adapted for connection to well tubing. The well tubing includes a well bore. The upper section of the mandrel is also adapted for connection to the well tubing.
The alternative embodiment may contain an annulus port in the tubular body. The annulus port is fluidly connected to an annulus pressure chamber. The annulus pressure chamber is positioned between the inner surface of the body and the outer surface of the mandrel. An atmospheric pressure chamber is positioned between the inner surface of the body and the outer surface of the mandrel.
The piston is the alternative embodiment may have a tubing pressure chamber. In addition, the sub may include a sleeve having an upper section, a middle section, a lower section, an outer surface and an inner surface. The sleeve is connected to the piston. The sleeve is positioned between the inner surface of the body and the outer surface of the mandrel. The sub may further contain a shear means detachably affixing the sleeve to the mandrel. The annulus pressure chamber and the atmospheric pressure chamber are separated by the piston and sleeve.
In the alternative embodiment, the piston is actuated by increasing tubing pressure in the tubing pressure chamber to a predetermined level that exerts sufficient force on the piston to shear the shear means. Once the shear means are sheared, the sleeve is detached from the mandrel. The increased tubing pressure forces the piston and sleeve to move upward into the annulus pressure chamber. The bleed off of tubing pressure to a level less than the annulus pressure level causes actuation of the piston in a second direction. The annulus pressure in the annulus chamber forces the piston and sleeve to move downward to a position that results in the release of the seat from the mandrel bore.
The alternative embodiment may also include at least one retractable dog supported in the mandrel. The dog includes a first end and a second end. The first end of the dog releasably engages the seat to position the seat in the mandrel bore prior to the actuation of the piston in the second direction. Actuation of the piston in the second direction causes the first end of the dog to disengage from the seat to release the seat from the mandrel bore to eliminate obstruction of the well bore caused by the seat and plug. The well bore obstruction is eliminated when the seat and plug fall down the well bore after being released.
The mandrel in the alternative embodiment may further include a bore-hole having an inner-surface opening and an outer-surface opening. The bore-hole supports the retractable dog. A portion of the inner surface of the sleeve covers the outer-surface opening of the bore-hole in the mandrel prior to the actuation of the piston in the second direction. The mandrel may include biasing means positioned in the bore-hole of the mandrel. The biasing means bias the second end of the dog against a portion of the inner surface of the sleeve prior to actuation of the piston in the second direction. Actuation of the piston in the second direction moves the piston and sleeve downward to a position wherein the portion of the inner surface of the sleeve no longer covers the outer-surface opening of the bore-hole in the mandrel and wherein the tubing pressure chamber in the piston sets adjacent to the outer-surface opening of the bore-hole in the mandrel. The biasing means causes the second end of the dog to enter the tubing pressure chamber of the piston through the outer-surface opening of the bore-hole in the mandrel. The first end of the dog then disengages from the seat and retracts into the bore-hole of the mandrel thereby releasing the seat from the mandrel bore. The obstruction of the well bore caused by the seat and plug is eliminated; the seat and plug fall down the well bore.
The present invention is also directed to a unique method of actuating a well tool connected to well tubing. The method involves connecting a formation saver sub to the well tubing below the well tool. The formation saver sub includes a tubular body including an upper section, a middle section, a lower section, an outer surface, and an inner surface. The sub also includes a mandrel having an upper section, a middle section, a lower section, an outer surface and an inner surface defining a mandrel bore. The mandrel is positioned interior of the body. The sub has a piston including an upper section, a middle section, a lower section, an outer surface, and an inner surface. The piston is positioned between the inner surface of the body and the outer surface of the mandrel. The sub also includes a seat with an upper section, a middle section, a lower section, an outer surface, and an inner surface defining a seat bore. The seat is releasably positioned in the mandrel bore. The upper section of the seat is adapted to receive a plug.
The method includes the step of sealing the well bore above the seat by dropping the plug through the well bore to the mandrel bore. The plug will seat in the upper section of the seat and obstruct or plug the well bore. The method further includes manipulating the well tool. Also included in the method is the step of increasing the fluid pressure in the well bore to a first level. The first level of fluid pressure causes the piston to move in a first direction while maintaining the positioning of the seat in the mandrel bore. The method further includes the step of bleeding off the fluid pressure in the well bore to a second level. The second level of fluid pressure causes the piston to move in a second direction that releases the seat from the mandrel bore thereby eliminating the well bore obstruction.
The fluid pressure may be tubing pressure. The first level of tubing pressure may be in the range of 1500 PSI to 10000 PSI (or 5000 PSI). The second level of tubing pressure may be in the range of 100 PSI to 1000 PSI. The second level of tubing pressure is preferably about 500 PSI.
In the method of the present invention, the sub may further include at least one retractable dog supported in the mandrel. The dog includes a first end and a second end. The first end of the dog releasably engages the seat to position the seat in the mandrel bore.
The method of the present invention is also drawn to an embodiment wherein in the event the seat is not released from the mandrel bore by deactivation of the piston or by actuation of the piston in the second direction (all as described above), the plug and seat may be displaced from the mandrel bore by increasing fluid pressure in the well bore to a level that causes the seat to disengage from the mandrel bore or by setting a tool down on the seat with sufficient force to disengage the seat and plug.
In the event the seat is not released from the mandrel bore as described above, the method may further include the step of increasing the fluid pressure in the well bore to a third level. The third level of fluid pressure is capable of shearing the dog. By shearing the dog, the seat is released from the mandrel bore and together with the plug, drops down the well bore eliminating any obstruction. Alternatively, the method may include the step of setting a tool down on the seat with sufficient force to shear the dog. Again, shearing the dog releases the seat from the mandrel bore. The seat and plug fall down the well bore. Obstruction of the well bore is eliminated.
With reference to the figures where like elements have been given like numerical designation to facilitate an understanding of the present invention, and in particular with reference to the embodiment of the present invention illustrated in
As shown in
With reference to
Again with reference to
As seen in
To operate sub 10, sub 10 is connected to well tubing 178 and run into a well [not shown] to a desired location as depicted in
Concurrently, threads 116 on outer surface 110 of mandrel 102 are detachably mated to threads 220 on inner surface 182 on well tubing 178. Seal 214 (e.g., non-elastomeric or elastomeric seal rings or O-rings) seals the connection of mandrel 102 to well tubing 178.
When run into position in the well bore (as shown in
As seen in
Piston 42 contains recess 54 which houses seal 56 and recess 62 which houses seal 64. Seal 56 provides a seal between inner surface 52 of piston 42 and outer surface 110 of mandrel 102. Seal 64 provides a seal between inner surface 52 of piston 42 and outer surface 82 of sleeve 74. Seals 56 and 64 are each preferably non-elastomeric or elastomeric seal rings or O-rings.
As run in the well, sub 10 is configured with seat 148 detachably secured to inner surface 112 of mandrel 102 by dog 130. A portion of dog 130 (first end 230) is housed within recess 168 of seat 148 thus holding seat 148 stationary within mandrel bore 228. First end 230 of dog 130 is engaged within recess 168 of seat 148 due to the inability of dog 130 to be displaced by biasing means 132. Dog 130 is prevented from being disengaged due to the placement of a portion of sleeve 74 over bore-hole 128 in mandrel 102. Recess 170 in outer surface 156 of seat 148 contains seal 172 which may be an elastomeric seal ring or O-ring. Seal 172 forms a seal between outer surface 156 of seat 148 and inner surface 112 of mandrel 102.
When run into the well as shown in
After locating sub 10 in the well, the well operator will cause plug 174 to be placed in well bore 226 at the surface. Plug 174 will drop through well bore 226 to mandrel bore 228 where plug 174 seats in seat 148 as shown in
With plug 174 seated in seat 148, fluid pressure in well bore 226 above seat 148 may be increased by the well operator in order to actuate and operate the well tool positioned above sub 10. For example, tubing pressure may be increased to a desired pressure to actuate a hydraulic packer. Once operations involving the well tool are completed, it may be desirable to resume fluid flow down well bore 226 pass plug 174 and seat 148. Accordingly, plug 174 and/or seat 148 must be removed from mandrel bore 228. The process of dislodging plug 174 and seat 148 from mandrel bore 228 is sequentially shown in
With reference to
With no impediment to disengagement, dog 130 is forced by biasing means 132 (e.g., one or more springs) to disassociate from recess 168 of seat 148. Dog 130 moves away from seat 148 and towards piston 42. Second end 232 of dog 130 moves through outer-surface opening 236 of bore-hole 128 in mandrel 102 into chamber 60 of piston 42. Seat 148 is released and falls down mandrel bore 228, well bore 226, and out of the bottom end of the well tubing. Sub 10 no longer restricts well bore 226. Dog 130 has retracted into sub 10 without obstructing mandrel bore 228 or well bore 226 and will remain there via the spring force exerted by biasing means 132.
As shown in
When the annulus pressure is greater than the tubing pressure, the force action in piston 42 will be in the downward direction. When the operator pressures up the tubing pressure to a predetermined pressure, the force action in piston 42 will be in the upward direction causing shears pins 100 to shear thus permitting piston 42 to move upward. When the operator bleeds the tubing pressure to within 500 PSI positive tubing pressure, piston 42 will start to move downward due to the annulus pressure on piston 42 and the atmospheric chamber. When piston 42 bottoms out, dogs 130 will become unsupported and bias outward thereby releasing seat 148 and plug 174.
Sub 10 does not surge the formation when blowing out seat 148. Sub 10 is also capable of mechanical override. It has elastomeric and non-elastomeric capabilities. Connections can also be metal to metal sealing. Sub 10 has an anti-surge feature that shears up. It also is capable of bleeding tubing pressure before releasing seat 148. Dog 130 system can also be sheared out at a high shear rate as a backup. Sub 10 has a small OD to accommodate dual packer applications. Both a ball or dart plug 174 system can be used. If a dart is used, the dart will hold formation pressure from below or tubing pressure from above with a locking dart.
Sub 10 may be used below any down-hole tool to pressure up against. With sub 10, tubing pressure may be pressured up more than one time or a plurality of times on sub 10 to manipulate the well tool above sub 10. Also with sub 10, tubing pressure may be pressured up multiple times to manipulate the well tool or tools positioned above sub 10.
While preferred embodiments of the present invention have been described, it is to be understood that the embodiments described are illustrative only and that the scope of the invention is to be defined solely by the appended claims when accorded a full range of equivalents, many variations and modifications naturally occurring to those skilled in the art from a perusal hereof.
