CASING ANNULUS TESTER FOR DIAGNOSTICS AND TESTING OF A WELLBORE
Embodiments of the present invention generally relate to a casing tester for plugging and abandoning a wellbore. In one embodiment, a method of testing an annulus defined between a first tubular string and a second tubular string includes engaging a first annular packer with an outer surface of the first tubular string and engaging a second annular packer with an outer surface of the second tubular string. The tubular strings extend into a wellbore. The method further includes injecting a test fluid between the packers until a predetermined pressure is exerted on the annulus.
This application is a divisional of U.S. patent application Ser. No. 12/268,748 (Atty. Dock. No. WWCl/0002), filed Nov. 11, 2008, which is hereby incorporated by reference in its entirety.
BACKGROUND OF THE INVENTION1. Field of the Invention
Embodiments of the present invention generally relate to a casing tester for plugging and abandoning a wellbore.
2. Description of the Related Art
Once the conductor casing 10 has been set and cemented 35 into the wellbore 5, the wellbore 5 may be drilled to a deeper depth. A second string of casing, known as surface casing 40, may then be run-in and cemented 45 into place. As the wellbore 5 approaches a hydrocarbon-bearing formation 50, i.e., crude oil and/or natural gas, a third string of casing, known as production casing 55, may be run-into the wellbore 5 and cemented 60 into place. Thereafter, the production casing 55 may be perforated 65 to permit the fluid hydrocarbons 70 to flow into the interior of the casing. The hydrocarbons 70 may be transported from the production zone 50 of the wellbore 5 through a production tubing string 75 run into the wellbore 5. An annulus 80 defined between the production casing 55 and the production tubing 75 may be isolated from the producing formation 50 with a packer 85.
Additionally, a stove or drive pipe may be jetted, driven, or drilled in before the conductor casing 10 and/or one or more intermediate casing strings may be run-in and cemented between the surface 40 and production 55 casing strings. The stove or drive pipe may or may not be cemented.
Embodiments of the present invention generally relate to a casing tester for plugging and abandoning a wellbore. In one embodiment, a method of testing an annulus defined between a first tubular string and a second tubular string includes engaging a first annular packer with an outer surface of the first tubular string and engaging a second annular packer with an outer surface of the second tubular string. The tubular strings extend into a wellbore. The method further includes injecting a test fluid between the packers until a predetermined pressure is exerted on the annulus.
In another embodiment, a method of plugging a subsea wellbore having a damaged land-type completion includes cutting a horizontal portion of the completion from a vertical portion of the completion. The completion includes a production casing string, a second casing string adjacent the production casing string, and an annulus defined between the casing strings. The method further includes tier-cutting the vertical portion of the completion into a wedding cake configuration and clamping a casing tester on the wedding cake configuration. The casing tester includes: a first annular blowout preventer (BOP), a second annular BOP, an inlet, a valve, and a pressure gage. The method further includes engaging the annular BOPs with respective casing strings, thereby isolating the annulus; injecting a test fluid into the inlet; closing the valve; and monitoring the pressure gage.
In another embodiment, a method of working over, abandoning, or regaining control over a wellbore includes clamping a wellhead on a casing string extending into the wellbore and cemented to the wellbore. The wellhead includes a first annular blowout preventer (BOP), a second annular BOP, and an outlet. The method further includes engaging the first annular BOP with the casing string; running a work string through the second annular BOP into the wellbore; engaging the second annular BOP with the workstring; injecting fluid into the wellbore through the work string; and returning fluid from the wellbore through the outlet.
In another embodiment, a method of working over, abandoning, or regaining control over a wellbore includes clamping a wellhead on a casing string extending into the wellbore and cemented to the wellbore, wherein the wellhead comprises a first annular blowout preventer (BOP), a second annular BOP, and an outlet. The method further includes engaging the first annular BOP with the casing string; engaging the second annular BOP with a tubular string extending into the wellbore; injecting fluid into the wellbore; and returning fluid from the wellbore through the outlet.
So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.
A hydraulically-powered cutting tool, such as a port-a-lathe, may then be secured to the conductor casing 10 by the diver at or near the top of the vertical portion 1v. The diver may operate the port-a-lathe to radially cut through the conductor casing 10. The diver may then re-position the port-a-lathe near the top of the conductor casing shown in
The annular BOP 410a′ may include a housing 411. The housing 411 may be made from a metal or alloy and include a flange 412 welded thereto. The housing 411 may include upper and lower portions fastened together, such as with a flanged connection or locking segments and a locking ring. A piston 415 may be disposed in the housing 411 and movable upwardly in chamber 416 in response to fluid pressure exertion upwardly against piston face 417 via hydraulic port 430a. Movement of the piston 415 may constrict an annular packer 418 via engagement of an inner cam surface 422 of the piston with an outer surface of the packer 418. The engaging piston and packer surfaces may be frusto-conical and flared upwardly. The packer 418, when sufficiently radially inwardly displaced, may sealingly engage an outer surface of a respective one of the casings 40, 55 extending longitudinally through the housing 411. In the absence of any casing disposed through the housing 411, the packer 418 may completely close off the longitudinal passage 420 through the housing 410, when the packer 418 is sufficiently constricted by piston 415. Upon downward movement of the piston 416 in response to fluid pressure exertion against face 424 via hydraulic port 430b, the packer 418 may expand radially outwardly to the open position (as shown). An outer surface 425 of the piston 416 may be annular and may move along a corresponding annular inner surface 426 of the housing 416. The packer 418 may be longitudinally confined by an end surface 427 of the housing 411.
The packer 418 may be made from a polymer, such as an elastomer, such as natural or nitrile rubber. Additionally, the packer 418 may include metal or alloy inserts (not shown) generally circularly spaced about the longitudinal axis 440. The inserts may include webs that extend longitudinally through the elastomeric material. The webs may anchor the elastomeric material during inward compressive displacement or constriction of the packer 418.
Returning to
Eccentricity of the casings 40, 60, discussed above, does not affect engagement of the pliant packers 418. Testing fluid, such as seawater, may then be injected from the salvage vessel into the inlet 407 until the annulus between the surface 40 and production 55 casing strings is at a predetermined test pressure, such as 500 psi. The valve 406 may be closed by the diver and the diver may monitor the pressure for a predetermined amount of time, such as fifteen minutes, to test the integrity of the cement 60. If the cement 60 is acceptable, the P&A operation may proceed. Alternatively, the valve 406 may be a solenoid valve operable from the salvage vessel and the pressure gage may be a pressure sensor in data communication with the salvage vessel so that the test may be monitored and controlled from the salvage vessel.
If the cement 60 is unacceptable, then remedial action may be taken, such as injecting sealant from the salvage vessel into the annulus via the inlet 407, and then the annulus may be re-tested. The sealant may be cement or a thermoset polymer, such as epoxy or polyurethane.
Alternatively, the casing tester 400 may remain on the wedding cake 1w while sealant is injected into the wellbore 5 and up the annulus and then the annulus may be retested. The production tubing 75 may be used to inject the sealant.
Alternatively, the production tubing 75 may be removed and a temporary wellhead installed on the wedding cake 1w for injecting the sealant into the wellbore and up the annulus. Fluid from the remedial operation may be returned to the salvage vessel via the inlet 407 (would now be an outlet). A second casing tester may be used as the temporary wellhead for repairing the annulus. The second lower BOP may seal against the production casing 55 while the second upper BOP may be used to seal against a work string run into the wellbore from the salvage vessel, thereby isolating the wellbore. The work string may be may be coiled tubing or drill pipe. The sealant may be injected from the salvage vessel into the wellbore via the workstring.
Alternatively, the casing tester 400 may be adapted to be used on any casing annulus of the completion 1, such as the conductor casing-surface casing annulus. For example, if conductor casing-surface casing annulus is leaking, a larger casing tester may be deployed and installed on the wedding cake 1w to inject sealant into the annulus and then test the annulus. Alternatively, the leak could be contained and/or discharged to the salvage vessel via the inlet 407 (would now be an outlet) while the annulus is remedied.
Alternatively, the casing tester 400 may be modified for use on the production casing-production tubing annulus 80. The casing tester 400 may be used to test the packer 85 or may be used as a temporary wellhead for conducting remedial operations using the production tubing 75 if the packer 85 is damaged. The lower BOP 410b may seal against the production casing 55 while the upper BOP 410a may be used to seal against the production tubing 75, thereby isolating the annulus 80. Using the casing tester 400 to seal the annulus 80 may also be beneficial in an emergency, such as breach of the packer 85. The casing tester 400 may be more quickly installed to contain leakage than a subsea wellhead.
Alternatively, instead of plugging and abandoning the wellbore 5, a permanent subsea wellhead may be installed on the wedding cake 1w and a production line run from the wellhead to a new production platform. The production tubing 75 may be left in the wellbore and engaged by the new wellhead or a new string of production tubing and a new packer 85 installed.
Alternatively, instead of plugging and abandoning the wellbore 5, a temporary wellhead may be installed on the wedding cake 1w for working over or re-completing the wellbore 5, such as perforating another hydrocarbon-bearing zone or formation. The casing tester 400 may be used as the temporary wellhead.
Alternatively, the casing tester 400 may be used on land-based wellbores and other types of sub-sea completions, such as subsea-wellhead type completions.
While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.
Claims
1. A method of regaining control over a subsea wellbore, comprising:
- deploying a remotely operated vehicle (ROV) to a wellhead of the subsea wellbore, wherein a first tubular string extends from the wellhead;
- severing an upper portion of the first tubular string from a lower portion of the first tubular string, wherein the first tubular string is severed above the wellbore;
- clamping a temporary wellhead to an outer surface of the first tubular string, wherein: the temporary wellhead comprises a first annular blowout preventer (ABOP), a clamp connected to the first ABOP by a flanged connection, and a spool connected to the first ABOP by a flanged connection, and the temporary wellhead is clamped on the first tubular string above the subsea wellbore and adjacent to a sea-floor; and
- engaging the first annular BOP with the first tubular string outer surface, thereby containing leakage from the subsea wellbore.
2. The method of claim 1, wherein:
- the first tubular string is an outer tubular string,
- the temporary wellhead further comprises a second ABOP connected to the spool by a flanged connection, and
- the method further comprises engaging the second ABOP with an outer surface of an inner tubular string, and
- the inner tubular string extends into the wellbore.
3. The method of claim 2, wherein:
- an upper portion of the inner tubular string is also severed when the outer string upper portion is severed,
- the method further comprises cutting and removing a portion of the lower outer tubular string portion to expose a corresponding portion of the inner tubular string lower portion, thereby forming a wedding cake configuration, and
- the second ABOP is engaged with the exposed portion of the inner tubular string.
4. The method of claim 2, further comprising removing the inner tubular string from the wellbore.
5. The method of claim 2, further comprising:
- injecting sealant into the wellbore, thereby plugging the wellbore; and
- removing the temporary wellhead from the wellbore.
6. The method of claim 1, wherein:
- the temporary wellhead has an outlet, and
- the method further comprises discharging fluid from the wellbore through the outlet.
7. The method of claim 1, wherein:
- the temporary wellhead further comprises a valve and a pressure gage, and
- the method further comprises closing the valve and monitoring the pressure gage.
8. The method of claim 1, wherein:
- the temporary wellhead has an inlet, and
- the method further comprises injecting fluid into the subsea wellbore via the inlet.
9. The method of claim 8, wherein the fluid is sealant.
10. The method of claim 9, wherein the sealant is cement.
11. The method of claim 1, wherein:
- the wellbore extends into a hydrocarbon bearing formation, and
- the method further comprises injecting sealant into the subsea wellbore to seal the formation.
12. The method of claim 11, further comprising:
- setting a bridge plug in the wellbore; and
- injecting the sealant above the bridge plug.
13. The method of claim 1, wherein the first tubular string is severed adjacent to the sea-floor.
14. The method of claim 1, wherein the wellhead is a subsea wellhead.
15. The method of claim 1, wherein the first tubular string is severed using the ROV.
Type: Application
Filed: Jul 11, 2012
Publication Date: Nov 1, 2012
Inventors: Corey Eugene Hoffman (Magnolia, TX), Dolphus C. Green, III (Spring, TX)
Application Number: 13/546,377
International Classification: E21B 33/035 (20060101); E21B 33/13 (20060101); E21B 33/064 (20060101);