PRESSURE TESTING A WELLHEAD

Description

TECHNICAL FIELD

The present disclosure describes systems and methods for pressure testing a wellhead.

BACKGROUND

During a well's exploitation period, wellheads are exposed to extreme conditions, such as high pressure, exposure to abrasive and corrosive fluids that will adversely impact the well integrity by the reduction of wall thickness, weakening connection area, and effects on sealing systems. Additionally, extreme changes of temperature, pressure, and loads on wellhead equipment and an upper part of a tubing casing can adversely impact and weaken the whole wellhead system over time. In cases of planned applications of high pressure operations on the well through the wellhead, it may be required to test the system prior to the operations to ensure that the wellhead condition is acceptable for the planned operations ratings. The use of cup type testers with drilling or workover rigs are common in such operations. However, cup type testers cannot be applied without the drilling or workover rig.

SUMMARY

In an example implementation, a wellhead isolation tool includes a hydraulic assembly including at least one hydraulic line fluidly and a setting tool hydraulic ram that includes a mandrel head; a mandrel coupled to the hydraulic ram, the mandrel including an uphole end coupled to the mandrel head and a downhole end configured to sting into a wellhead; a packing assembly including a bore that is configured to receive the mandrel; and a pack-off cup assembly coupled to the downhole end of the mandrel. The pack-off cup assembly includes at least one cup mounted on the mandrel and including a circular frustum that includes an uphole end defined by a first diameter; a downhole end opposite the uphole end and defined by a second diameter less than the first diameter; a bore that extends between the uphole end and the downhole end and is configured to receive a least a portion of the mandrel therethrough; and a radial surface between the uphole and downhole ends.

In an aspect combinable with the example implementation, the at least one cup is a first cup, and the pack-off cup assembly includes a second cup mounted on the mandrel and including a circular frustum that includes an uphole end defined by a third diameter; a downhole end opposite the uphole end and defined by a fourth diameter less than the third diameter; a bore that extends between the uphole end and the downhole end and is configured to receive a least another portion of the mandrel therethrough; and a radial surface between the uphole and downhole ends.

In another aspect combinable with any of the previous aspects, the first and third diameters are substantially equal, and the second and fourth diameters are substantially equal.

In another aspect combinable with any of the previous aspects, the at least one cup is formed of a sealing material configured to fluidly seal against a portion of the wellhead.

In another aspect combinable with any of the previous aspects, the sealing material includes at least one elastomer.

In another aspect combinable with any of the previous aspects, the at least one cup is configured to compress in response to circulation of a pressurized fluid in an annulus between the mandrel and the wellhead when the mandrel is stung into the wellhead.

In another aspect combinable with any of the previous aspects, the pressurized fluid is at about 15,000 psi.

In another aspect combinable with any of the previous aspects, the mandrel includes at least one seat, the at least one cup positioned on the mandrel such that the downhole end abuts the at least one seat.

In another aspect combinable with any of the previous aspects, the at least one cup is configured to compress against the at least one seat in response to circulation of the pressurized fluid in the annulus between the mandrel and the wellhead when the mandrel is stung into the wellhead.

In another aspect combinable with any of the previous aspects, the at least one cup is a first cup, and the tool further includes a first seat positioned on the mandrel, the first cup positioned on the mandrel such that the downhole end of the first cup abuts the first seat; a second cup mounted on the mandrel and including a circular frustum that includes an uphole end defined by a third diameter; a downhole end opposite the uphole end and defined by a fourth diameter less than the third diameter; a bore that extends between the uphole end and the downhole end and is configured to receive a least another portion of the mandrel therethrough; and a radial surface between the uphole and downhole ends; and a second seat positioned on the mandrel and spaced apart from the first seat, the second cup positioned on the mandrel such that the downhole end of the second cup abuts the second seat.

In another example implementation, a method of pressure testing a wellhead includes installing a wellhead isolation tool on a wellhead. The wellhead isolation tool includes a hydraulic assembly including at least one hydraulic line fluidly and a setting tool hydraulic ram that includes a mandrel head; a mandrel coupled to the hydraulic ram, the mandrel including an uphole end coupled to the mandrel head and a downhole end; a packing assembly including a bore that is configured to receive the mandrel; and a pack-off cup assembly coupled to the downhole end of the mandrel. The pack-off cup assembly includes at least one cup mounted on the mandrel and including a circular frustum that includes an uphole end defined by a first diameter; a downhole end opposite the uphole end and defined by a second diameter less than the first diameter; a bore that extends between the uphole end and the downhole end and is configured to receive a least a portion of the mandrel therethrough; and a radial surface between the uphole and downhole ends. The method includes operating the hydraulic assembly to insert the mandrel into the wellhead to sting the pack-off cup assembly into a wellbore tubing; sealing a portion of an annulus between the mandrel and the wellbore tubing with the at least one cup; circulating a pressurized fluid into the annulus between the mandrel and the wellbore tubing; and pressure testing the wellhead with the pressurized fluid.

Another aspect combinable with any of the previous aspects includes sealing another portion of the annulus between the mandrel and the wellbore tubing with the second cup.

Another aspect combinable with any of the previous aspects includes compressing the at least one cup in response to circulating the pressurized fluid in the annulus between the mandrel and the wellbore tubing.

In another aspect combinable with any of the previous aspects, compressing the at least one cup includes flattening the at least one cup to increase the first diameter to further seal the portion of the annulus between the mandrel and the wellbore tubing.

In another aspect combinable with any of the previous aspects, compressing the at least one cup includes the mandrel includes compressing the at least one cup against a seat positioned on the mandrel downhole of the at least one cup and abutting the downhole end of the at least one cup.

In another aspect combinable with any of the previous aspects, circulating the pressurized fluid includes circulating the pressurized fluid at about 15,000 psi.

Another aspect combinable with any of the previous aspects includes sealing at least a portion of the wellbore tubing downhole of the at least one cup against circulation of the pressurized fluid into the wellbore tubing with the at least one cup.

Another aspect combinable with any of the previous aspects includes circulating the pressurized fluid into the wellhead through a hydraulic secondary wing valve that includes an inlet oriented orthogonally to the annulus.

In another aspect combinable with any of the previous aspects, the at least one cup is a first cup, and the pack-off cup assembly includes a second cup mounted on the mandrel and including a circular frustum that includes an uphole end defined by a third diameter; a downhole end opposite the uphole end and defined by a fourth diameter less than the third diameter; a bore that extends between the uphole end and the downhole end and is configured to receive a least another portion of the mandrel therethrough; and a radial surface between the uphole and downhole ends.

Another aspect combinable with any of the previous aspects includes sealing the portion of the annulus by compressing the first cup against a first seat positioned on the mandrel downhole of the first cup and abutting the downhole end of the first cup; and sealing another portion of the annulus by compressing the second cup against a second seat positioned on the mandrel downhole of the second cup and abutting the downhole end of the second cup.

In another aspect combinable with any of the previous aspects, the first and third diameters are substantially equal, and the second and fourth diameters are substantially equal.

In another aspect combinable with any of the previous aspects, installing the wellhead isolation tool on the wellhead includes installing the wellhead isolation tool on the wellhead exclusive of the wellhead having a back pressure valve profile, a two way check valve profile, a test plug profile, or a tubing hanger landing profile.

In another aspect combinable with any of the previous aspects, installing the wellhead isolation tool on the wellhead includes installing the wellhead isolation tool on the wellhead exclusive of a drilling rig, a coil tubing unit, a snubbing unit, or a workover rig.

The details of one or more implementations of the subject matter described in this disclosure are set forth in the accompanying drawings and the description below. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A is a schematic drawing of an example implementation of a wellhead isolation tool according to the present disclosure.

FIG. 1B is a schematic drawing of a pack-off cup assembly of an example implementation of a wellhead isolation tool according to the present disclosure

FIG. 2A is a schematic drawing of an example implementation of a wellhead isolation tool installed on a wellhead with the wellhead in a sting-out position according to the present disclosure.

FIG. 2B is a schematic drawing of an example implementation of a wellhead isolation tool stung into a wellhead with the wellhead in a sting-in position according to the present disclosure.

FIG. 3 is a schematic drawing of a portion of a pressurized wellhead section that includes an example implementation of a wellhead isolation tool during a wellhead pressure test according to the present disclosure can be positioned.

FIG. 4 is a schematic drawing of a portion of wellhead and wellhead test ports into which an example implementation of a wellhead isolation tool is stung according to the present disclosure can be positioned without use of a tubing hanger type wellhead in an emergency slip system.

DETAILED DESCRIPTION

FIG. 1A is a schematic drawing of an example implementation of a wellhead isolation tool 100 according to the present disclosure. Generally, the example implementation of the wellhead isolation tool 100 can be operated to pump a pressurized fluid into a wellhead to pressure test the wellhead itself, rather than, for instance, components installed in a production wellbore (for example, tubings, casings, valves etc.) that are generally considered to be downhole of the wellhead.

The illustrated wellhead isolation tool 100 can be installed (“stung”) into a production tree and wellhead to protect the wellhead against high pressures and/or abrasive fluids during pressure pumping operations. For example, oil and gas wells often require fracturing operations (or other secondary or enhanced recovery operations) in which a pressurized liquid is pumped into a subterranean zone at high pressures in order to break up rock formation in the zone. Abrasive materials, such as sand or bauxite (in other words, proppants) are also pumped through the wellhead and into fractures created in the rock formation to prop the fractures open to allow an increase in hydrocarbon fluid flow into the wellbore.

However, while the wellhead is usually rated to handle anticipated pressures that might be produced by the well when it first enters production, wellhead pressures encountered during a fracturing process can be considerably higher than those of the producing well. For the sake of economy, it is desirable to have equipment on the well rated for the normal pressures to be encountered. In order to safely fracture the well, equipment must be provided whereby the elevated pressures are safely contained and well pressures are controlled. The wellhead isolation tool 100 can accomplish these requirements and can be rated for the pressures to be encountered, whether in production operations or completion operations, such as high pressure fracture operations or operations with erosive/corrosive stimulation fluids.

The wellhead isolation tool 100 can be operated in a wellhead to pressure test the wellhead (rather than just bypass the production tree and wellhead section) with test fluid pressures, for example, up to 15,000 psi, while still being operable in the case of secondary operations, such as fracturing, thereby eliminating the need to upgrade the wellhead to account for formation breakdown pressures during completion operations. The use of the wellhead isolation tool 100 can also enhance safety at the well site, extend the life of wellhead equipment and eliminate damage to valves. Further, the wellhead isolation tool 100 can extend a life of the wellhead and valves utilized during completion operations and reduces the need to kill the well for equipment changes. The use of the wellhead isolation tool 100 can also eliminate unnecessary damages to valves during high pressure pumping.

As shown in FIG. 1A, the wellhead isolation tool 100 is an example of a single cylinder isolation tool. However, wellhead isolation tool 100 can also represent a dual cylinder isolation tool (and example of which is shown in FIGS. 2A and 2B as well as representing the wellhead isolation tool 100). Thus, wellhead isolation tool 100 can represent both types of isolation tools.

The example implementation of the wellhead isolation tool 100 includes a hydraulic assembly 101 that is operable to urge a mandrel 118 into a wellhead to sting a pack-off cup assembly 124 into at least a portion of a wellbore tubular (a casing or tubing) on which the wellhead is installed. While some components of the wellhead isolation tool 100 are not delineated in FIG. 1A for simplicity, the hydraulic assembly 101 includes a hydraulic line 102, a hydraulic cylinder 104, a stay rod 106, and a hydraulic ram 108. Further components of the wellhead isolation tool 100 include an equalizing hood 110, an equalizing line 112, and a hydraulic actuated valve 114.

As shown in FIG. 1A, an uphole end 117 of the mandrel 118 is coupled to a mandrel head 116. The mandrel 118 extends through a packing assembly 120 (a portion which is shown in an enhanced view) and is coupled to the pack-off cup assembly 124 at a downhole end 119. An equalizing valve 122 is fluidly coupled to the equalizing line 112.

In operation, the hydraulic assembly 101 of the wellhead isolation tool 100 controls stroke penetration of the mandrel 118 into a wellhead. A piston movement length of the hydraulic ram 108 allows the mandrel 118 to be inserted into the wellhead to sting the pack-off cup assembly 124 inside of the wellhead and be positioned within a wellbore tubular below the wellhead, itself.

The pressure equalizing components of the wellhead isolation tool 100 allow oil and gas operators to have precise control over the flow and pressure in the wellhead during insertion and retraction of the mandrel 118 into the wellbore tubular. For example, during insertion, pressure can be equalized below and above a wellhead master valve without opening the master valve. This gives operators additional flexibility during installation of a tree saver on the wellhead. When retracting the mandrel 118, a pressure differential is created between a bore or interior of the mandrel 118 that is open to the wellbore tubular and an annulus between the mandrel 118 and the wellhead and wellbore tubular. Using the equalizing components of the wellhead isolation tool 100, operators can equalize this differential pressure in order to safely unseal pack-off nipples from the wellbore tubular, thereby protecting the wellhead and tree saver from dangerous hydraulic shock loads.

As shown in FIG. 1A (and in an enhanced view), the pack-off cup assembly 124 includes one or more seals 126, also referred to as cups 126. Although two cups 126 are shown as mounted to the mandrel 118, there can be fewer or more cups 126 mounted on the mandrel 118 in alternative implementations of the wellhead isolation tool 100.

With particular attention to the enhanced view of the pack-off cup assembly 124 in FIG. 1A as well as FIG. 1B, each cup 126 is positioned on the mandrel 118 in an inverted position and takes the shape of a frustum. As shown with reference to FIGS. 1A and 1B, the frustum of each cup 126 includes an uphole end 132 and a downhole end 130 and is positioned on the mandrel 118 by sliding the mandrel 118 through a bore 136 of the cup 126 that extends between the uphole end 132 and the downhole end 130. Generally, as a circular frustum, the cup 126 includes a radial surface 134 that extends between the uphole end 132 and the downhole end 130 that, in operation, sealingly contacts a wellbore tubular when the pack-off cup assembly 124 is stung into the wellhead tubular.

As further shown in the enhanced view of the pack-off cup assembly 124 in FIG. 1A, and consistent with the shape of each cup 126 being a circular frustum, the uphole end 132 is defined by a diameter, D1, while the downhole end 130 is defined by a diameter, D2, that is smaller than D1. Although in this example, both cups 126 (or each cup of more than two cups) has the same or substantially similar dimensions, D1 and D2, in alternative implementations, the dimensions D1 and/or D2, can differ from cup 126 to cup 126 on the mandrel 118. However, for each cup 126, D2 is smaller than D1.

Thus, in this example implementation, the cups 126 are installed on the mandrel 118 in an inverted fashion as compared to conventional seals or cups on conventional wellbore isolation tools. This is because, for example, wellhead isolation tool 100 is operable to be installed in a wellhead and operated to pressure test the wellhead with a flow of pressurized fluid that flows into an annulus between the mandrel 118 and the wellhead (and a wellbore tubular) in a downhole direction (in other words, in a direction from the uphole ends 132 of the cups 126 toward the downhole ends 130 of the cups 126). This differs from conventional wellhead isolation tools designed to pressure test wellbore components downhole (for example, only downhole) of the wellhead in which a flow of pressurized fluid flows out of a mandrel and returns in an uphole direction in an annulus between the mandrel and the wellhead (and a wellbore tubular).

As further shown in FIG. 1B, for example, each cup 126 is positioned on the mandrel 118 so that the downhole end 130 abuts (and can be in contact with) a seat 138 that is formed on or installed on the mandrel 118. An outer diameter of the seat 138 can be the same or substantially similar to D2 (the diameter of the downhole end 130 of the cup 126). In some aspects, the seat 138 provides a barrier to downward movement of the cup 126 on the mandrel 118 during a flow of pressurized fluid (during wellhead testing) that acts in a downhole direction on the uphole end 132 of the cup 126. Thus, during the flow of pressurized fluid that acts in the downhole direction on the uphole end 132 of the cup 126, the cup 126 (which can be made from a deformable material such as an elastomer material) will compress downward as the uphole end 132 is urged toward the downhole end 130. In doing so, the cup 126 can expand radially away from the mandrel 118 (as the downhole end 130 remains abutted to the seat 138), thereby providing even more sealing contact between the radial surface 134 and the wellbore tubular.

As shown in FIG. 1B, the mandrel 118 comprises a tubular member with a wall thickness 128. In some aspects, the wall thickness 128 can be selected or formed such that the mandrel 118 can withstand (and not buckle or fail) a highly pressurized fluid (such as up to 15,000 psi) that flows along an outer surface of the mandrel 118 in an annulus between the mandrel 118 and the wellhead and wellbore tubular. The wall thickness 128 can be thicker than conventional mandrel wall thicknesses, as in the present disclosure, a test fluid rate is relatively low and mandrel inner diameter is not a restriction point for this test.

FIG. 2A is a schematic drawing of an example implementation of a wellhead isolation tool installed on a wellhead with the wellhead in a sting-out position according to the present disclosure. FIG. 2B is a schematic drawing of an example implementation of a wellhead isolation tool stung into a wellhead with the wellhead in a sting-in position according to the present disclosure. Collectively, FIGS. 2A and 2B show an installation and stinging in operation of the wellhead isolation tool 100 into a wellhead 200. As shown in these figures, the wellhead isolation tool 100 is represented in this example by a dual cylinder isolation tool (rather than single). But a single cylinder wellhead isolation tool 200 can also be used. Further components of the example implementation of the wellhead isolation tool 100 are shown in these figures as well, including a frac iron connection 140, a remote operated master valve 142, and a manual operated master valve 144.

As shown in FIG. 2A, the wellhead isolation tool 100 is installed on the wellhead 200, with the mandrel 118 still not stung into the wellhead 200. Wellhead valves 202 are closed in this state, and a wellbore tubular 204 extends into a lower portion of the wellhead 200. The equalizing valve 122 is also closed in this state. In normal operations, at this step, a wellhead isolation tool flange connection pressure test against the wellhead valve for an integrity test can be performed to ensure the wellhead isolation tool 100 has good connection in the wellhead 200.

As shown in FIG. 2B, the wellhead valves 202 are opened, as is the equalizing valve 122. In this state, the mandrel 118 can be inserted into the wellhead 200 (for example, by the hydraulic assembly 101) until the pack-off cup assembly 124 is stung into the wellbore tubular 204. In this state, the cups 126 are inserted into an uphole portion (for example, 1-3 feet) of the wellbore tubular 204 to create an annulus 206 between the mandrel 118 and the wellbore tubular 204.

FIG. 3 is a schematic drawing of a portion of a wellhead that includes an example implementation of a wellhead isolation tool during a wellhead pressure test 300 according to the present disclosure can be positioned. For example, FIG. 3 shows an example wellhead test operation in which a pressurized fluid 308 is introduced into a wellhead 302 on which the wellhead isolation tool 100 has been installed. As shown, this figure illustrates a state in which the mandrel 118 has been inserted into the wellhead 302 and stung into a wellbore tubular 304 such that the cups 126 are sealingly installed in a portion of the wellbore tubular 304. In this example, an annulus 306 is created between the mandrel 118 and the wellbore tubular 304 (and the entire wellhead 200).

During the wellhead pressure test 300 and contrary to conventional testing of components downhole of the wellhead 302, the pressurized fluid 308 is not introduced into the wellhead isolation tool 100 and through the mandrel 118 to portions of the well downhole of the wellhead 302. Instead, the pressurized fluid 308 is introduced into the wellhead 302, in this example, through a secondary wing valve 310 to flow in the annulus 306. Due to the sealing operability of the cups 126 against an inner wall of the wellbore tubular 304, the pressurized fluid 308 is not circulated (or not significantly circulated) downhole of the cups 126 in the annulus 306. Indeed, as described, as the pressurized fluid 308 acts on the cups 126, the cups 126 (as inverted frustums) compress and expand to create even more sealing contact with the wellbore tubular 304 (as compared to contact with no pressurized fluid 308 being applied).

FIG. 4 is a schematic drawing of a portion of a wellhead into which an example implementation of a wellhead isolation tool is stung according to the present disclosure can be positioned (for example, without a tubing hanger type wellhead if emergency slip system used). Like FIG. 3, FIG. 4 shows an example wellhead test operation in which a pressurized fluid 401 is introduced into a wellhead 400 on which the wellhead isolation tool 100 has been installed. Further components of the wellhead 400 are shown in this example, including monitoring ports 406, a lower master valve 402, a SBSM seal 404, an adapter assembly 408, and a tubing head 414.

As shown, this figure illustrates a state in which the mandrel 118 has been inserted into the wellhead 400 and stung into a wellbore tubular 412 such that the cup 126 (one shown here) is sealingly installed in a portion of the wellbore tubular 412. In this example, an annulus 410 is created between the mandrel 118 and the wellbore tubular 412.

During the wellhead pressure test, the pressurized fluid 401 is introduced into the wellhead 400 and flows in the annulus 410 until it contacts the cup 126. Due to the sealing operability of the cups 12 against an inner wall of the wellbore tubular 412, the pressurized fluid 401 is not circulated (or not significantly circulated) downhole of the cup 126 in the annulus 410. Indeed, as the pressurized fluid 401 builds to pressure test the wellhead 400, it acts on the cup 126, and the cup 126 (as inverted frustums) compresses and expands to create even more sealing contact with the wellbore tubular 412.

The example implementation of the wellhead isolation tool 100 can be installed and used as described in a variety of wellheads. For example, the wellhead isolation tool 100 can be used in a wellhead seal integrity test even if there is no back pressure valve profile or two-way check valve profile in the wellhead (or tubing hanger section). The wellhead isolation tool 100 can be used in a wellhead seal integrity test even without a drilling rig or a workover rig, or even downhole or bridge plugs or packers to be installed. The wellhead isolation tool 100 can be used for wellhead pressure rating and testing for old wells, re-frac wells, and corroded wells after long production. The wellhead isolation tool 100 can also be used as a cup type tester if there is no test plug profile or BPV profile in a wellhead without a drilling rig or a workover rig.

The wellhead isolation tool 100 also allows the evaluation and testing of an upper tubing/casing portion right below a tubing hanger in the wellhead (such as the top 1-3 feet and without removing a production tree). This testing can be important, as the upper section can face relatively more corrosion due to a higher exposure to oxygen. If a wellhead section or the upper part of the tubing is not strong enough, by operating the wellhead isolation tool 100 in a wellhead pressure test, safe implementation of an operation to initially pump a very low rate of pressurized fluid and apply the pressure gradually can be accomplished. In contrast, without the wellhead pressure test with the wellhead isolation tool 100, during a fracturing operation, if the wellhead fails, it may not be possible to immediately stop pumping 60-120 bbl/min of fracturing fluid.

While this specification contains many specific implementation details, these should not be construed as limitations on the scope of any inventions or of what may be claimed, but rather as descriptions of features specific to particular implementations of particular inventions. Certain features that are described in this specification in the context of separate implementations can also be implemented in combination in a single implementation. Conversely, various features that are described in the context of a single implementation can also be implemented in multiple implementations separately or in any suitable subcombination. Moreover, although features may be described above as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination can in some cases be excised from the combination, and the claimed combination may be directed to a subcombination or variation of a subcombination.

Similarly, while operations are depicted in the drawings in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed, to achieve desirable results.

A number of implementations have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the disclosure. For example, example operations, methods, or processes described herein may include more steps or fewer steps than those described. Further, the steps in such example operations, methods, or processes may be performed in different successions than that described or illustrated in the figures. Accordingly, other implementations are within the scope of the following claims.

Claims

1. A wellhead isolation tool, comprising: a hydraulic assembly comprising at least one hydraulic line fluidly and a setting tool hydraulic ram that comprises a mandrel head;a mandrel coupled to the hydraulic ram, the mandrel comprising an uphole end coupled to the mandrel head and a downhole end configured to sting into a wellhead;a packing assembly comprising a bore that is configured to receive the mandrel; anda pack-off cup assembly coupled to the downhole end of the mandrel, the pack-off cup assembly comprising at least one cup mounted on the mandrel and comprising a circular frustum that includes: an uphole end defined by a first diameter;a downhole end opposite the uphole end and defined by a second diameter less than the first diameter;a bore that extends between the uphole end and the downhole end and is configured to receive a least a portion of the mandrel therethrough; anda radial surface between the uphole and downhole ends.
2. The wellhead isolation tool of claim 1, wherein the at least one cup is a first cup, the pack-off cup assembly comprising a second cup mounted on the mandrel and comprising a circular frustum that includes: an uphole end defined by a third diameter;a downhole end opposite the uphole end and defined by a fourth diameter less than the third diameter;a bore that extends between the uphole end and the downhole end and is configured to receive a least another portion of the mandrel therethrough; anda radial surface between the uphole and downhole ends.
3. The wellhead isolation tool of claim 2, wherein the first and third diameters are substantially equal, and the second and fourth diameters are substantially equal.
4. The wellhead isolation tool of claim 1, wherein the at least one cup is formed of a sealing material configured to fluidly seal against a portion of the wellhead.
5. The wellhead isolation tool of claim 4, wherein the sealing material comprises at least one elastomer.
6. The wellhead isolation tool of claim 1, wherein the at least one cup is configured to compress in response to circulation of a pressurized fluid in an annulus between the mandrel and the wellhead when the mandrel is stung into the wellhead.
7. The wellhead isolation tool of claim 6, wherein the pressurized fluid is at about 15,000 psi.
8. The wellhead isolation tool of claim 6, wherein the mandrel comprises at least one seat, the at least one cup positioned on the mandrel such that the downhole end abuts the at least one seat.
9. The wellhead isolation tool of claim 8, wherein the at least one cup is configured to compress against the at least one seat in response to circulation of the pressurized fluid in the annulus between the mandrel and the wellhead when the mandrel is stung into the wellhead.
10. The wellhead isolation tool of claim 1, wherein the at least one cup is a first cup, the tool further comprising: a first seat positioned on the mandrel, the first cup positioned on the mandrel such that the downhole end of the first cup abuts the first seat;a second cup mounted on the mandrel and comprising a circular frustum that includes: an uphole end defined by a third diameter;a downhole end opposite the uphole end and defined by a fourth diameter less than the third diameter;a bore that extends between the uphole end and the downhole end and is configured to receive a least another portion of the mandrel therethrough; anda radial surface between the uphole and downhole ends; anda second seat positioned on the mandrel and spaced apart from the first seat, the second cup positioned on the mandrel such that the downhole end of the second cup abuts the second seat.
11. A method of pressure testing a wellhead, the method comprising: installing a wellhead isolation tool on a wellhead, the wellhead isolation tool comprising: a hydraulic assembly comprising at least one hydraulic line fluidly and a setting tool hydraulic ram that comprises a mandrel head;a mandrel coupled to the hydraulic ram, the mandrel comprising an uphole end coupled to the mandrel head and a downhole end;a packing assembly comprising a bore that is configured to receive the mandrel; anda pack-off cup assembly coupled to the downhole end of the mandrel, the pack-off cup assembly comprising at least one cup mounted on the mandrel and comprising a circular frustum that includes: an uphole end defined by a first diameter;a downhole end opposite the uphole end and defined by a second diameter less than the first diameter;a bore that extends between the uphole end and the downhole end and is configured to receive a least a portion of the mandrel therethrough; anda radial surface between the uphole and downhole ends;operating the hydraulic assembly to insert the mandrel into the wellhead to sting the pack-off cup assembly into a wellbore tubing;sealing a portion of an annulus between the mandrel and the wellbore tubing with the at least one cup;circulating a pressurized fluid into the annulus between the mandrel and the wellbore tubing; andpressure testing the wellhead with the pressurized fluid.
12. The method of claim 11, wherein the at least one cup is a first cup, the pack-off cup assembly comprising a second cup mounted on the mandrel and comprising a circular frustum that includes an uphole end defined by a third diameter; a downhole end opposite the uphole end and defined by a fourth diameter less than the third diameter; a bore that extends between the uphole end and the downhole end and is configured to receive a least another portion of the mandrel therethrough; and a radial surface between the uphole and downhole ends, the method comprising: sealing another portion of the annulus between the mandrel and the wellbore tubing with the second cup.
13. The method of claim 11, comprising compressing the at least one cup in response to circulating the pressurized fluid in the annulus between the mandrel and the wellbore tubing.
14. The method of claim 13, wherein compressing the at least one cup comprises flattening the at least one cup to increase the first diameter to further seal the portion of the annulus between the mandrel and the wellbore tubing.
15. The method of claim 13, wherein compressing the at least one cup comprises the mandrel comprises compressing the at least one cup against a seat positioned on the mandrel downhole of the at least one cup and abutting the downhole end of the at least one cup.
16. The method of claim 11, wherein circulating the pressurized fluid comprises circulating the pressurized fluid at about 15,000 psi.
17. The method of claim 11, comprising sealing at least a portion of the wellbore tubing downhole of the at least one cup against circulation of the pressurized fluid into the wellbore tubing with the at least one cup.
18. The method of claim 11, comprising circulating the pressurized fluid into the wellhead through a hydraulic secondary wing valve that comprises an inlet oriented orthogonally to the annulus.
19. The method of claim 11, wherein the at least one cup is a first cup, the pack-off cup assembly comprising a second cup mounted on the mandrel and comprising a circular frustum that includes an uphole end defined by a third diameter; a downhole end opposite the uphole end and defined by a fourth diameter less than the third diameter; a bore that extends between the uphole end and the downhole end and is configured to receive a least another portion of the mandrel therethrough; and a radial surface between the uphole and downhole ends, the method comprising: sealing the portion of the annulus by compressing the first cup against a first seat positioned on the mandrel downhole of the first cup and abutting the downhole end of the first cup; andsealing another portion of the annulus by compressing the second cup against a second seat positioned on the mandrel downhole of the second cup and abutting the downhole end of the second cup.
20. The method of claim 19, wherein the first and third diameters are substantially equal, and the second and fourth diameters are substantially equal.
21. The method of claim 19, wherein installing the wellhead isolation tool on the wellhead comprises installing the wellhead isolation tool on the wellhead exclusive of the wellhead having a back pressure valve profile, a two way check valve profile, a test plug profile, or a tubing hanger landing profile.
22. The method of claim 19, wherein installing the wellhead isolation tool on the wellhead comprises installing the wellhead isolation tool on the wellhead exclusive of a drilling rig, a coil tubing unit, a snubbing unit, or a workover rig.

PRESSURE TESTING A WELLHEAD

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