ANNULAR FRACTURING CLEANOUT APPARATUS AND METHOD

Abstract

An annular fracturing cleanout apparatus includes: a main section including an upper connection end, a lower connection end and a main bore extending through the main section from the upper connection end to the lower connection end; a lateral section connected in a wye configuration with the main section, the lateral section defining a lateral bore therein, the lateral bore opening at an upper end of the lateral section and converging at a lower end with the main bore; and a bore control mechanism for the bore in the lateral section. A wellbore stack configuration includes the annular fracturing cleanout apparatus coupled above a fracturing wellhead assembly and below a blow out preventer assembly.

Description

FIELD OF THE INVENTION

The invention is directed to a wellhead apparatus and, in particular, to a wellhead apparatus for annular fracturing cleanout.

BACKGROUND

Hydraulic fracturing is a well stimulation technique where frac fluid and proppant is pumped into targeted formation zones with the end goal of improving (increasing) the rate at which fluids, such as oil and gas, can be recovered. Annular fracturing is a technique where the frac fluid and proppant is delivered in the space between a work string, such as coiled tubing, and the well casing.

During proppant delivery into the fissures, the zone of interest, and shortly thereafter, the annulus may begin to choke with proppant sand. When this occurs, adequate rate and pressure cannot be safely maintained, and the consequence is called “sanding off.” Remedying a “sand off” can be time consuming, as an adequate flow rate must be regained prior to commencing the job.

SUMMARY OF INVENTION

An annular fracturing cleanout apparatus has been invented. A method and wellhead apparatus have also been invented.

In accordance with one aspect of the present invention, there is provided: an annulus cleanout apparatus comprising: a main section including an upper connection end, a lower connection end and a main bore extending through the main section from the upper connection end to the lower connection end; a lateral section connected in a wye configuration with the main section, the lateral section defining a lateral bore therein, the lateral bore opening at an upper end of the lateral section and converging at a lower end with the main bore; and a bore control mechanism in the lateral section, the bore control mechanism being actuatable to: (i) create a seal in the lateral bore and/or (ii) shear a coil tubing extending through the lateral bore, wherein the upper connection end and the lower connection end are configured for connection in line to components of a wellhead stack assembly.

In accordance with another aspect of the present invention, there is provided: a method for intervention in a wellbore, the method comprising: running a secondary coil tubing string into an annulus between a primary tubing string in the wellbore, the running operation including: inserting the secondary coiled tubing string through a lateral section connected in a wye configuration with a main section of an annulus cleanout apparatus; inserting the secondary coiled tubing string into the main section and into the annulus around the primary tubing string in the wellbore; and circulating fluid through the secondary coiled tubing string to remove sand from the annulus.

In accordance with another aspect of the present invention, there is provided: a wellhead stack for well servicing with multiple work strings, the wellhead stack comprising: a lowermost end configured for connection to a wellhead of a well; a fracturing wellhead assembly coupled above the lowermost end; a blow out preventer assembly including at least a blow out preventer; and an annular fracturing cleanout apparatus installed above the fracturing wellhead assembly and below the blow out preventer assembly, the annular fracturing cleanout apparatus including: a main section including an upper connection end, a lower connection end and a main bore extending through the main section from the upper connection end to the lower connection end; and a lateral section connected in a wye configuration with the main section, the lateral section defining a lateral bore therein, the lateral bore opening at an upper end of the lateral section and converging at a lower end with the main bore.

Other aspects and features of the present invention will become apparent to those ordinarily skilled in the art upon review of the following description of embodiments of the invention in conjunction with the accompanying figures.

BRIEF DESCRIPTION OF THE DRAWINGS

Reference will now be made to the accompanying drawings which show, by way of example, embodiments according to the present invention, and in which:

FIG. 1—Example side elevation of a wellhead stack during operation including an annular fracturing cleanout apparatus and workstrings.

FIG. 2—Cross Section View of an annular fracturing cleanout apparatus with two shear/blind combination rams in the lateral.

FIG. 3—Cross Section View of an annular fracturing cleanout apparatus with one shear/blind combination ram in the lateral.

FIG. 4—Cross Section View of an annular fracturing cleanout apparatus with one shear and one valve in the lateral.

Like reference numerals indicate like or corresponding elements or components in the drawings.

DETAILED DESCRIPTION OF THE DRAWINGS

The detailed description set forth below in connection with the appended drawings is intended as a description of various embodiments of the present invention and is not intended to represent the only embodiments contemplated by the inventor. The detailed description includes specific details for the purpose of providing a comprehensive understanding of the present invention. However, it will be apparent to those skilled in the art that the present invention may be practiced without these specific details.

A stimulation wellhead stack that includes an annular fracturing cleanout apparatus makes it possible for two strings to be safely used on the same well, with a potential for use simultaneously. Deploying a second work string into the annulus alongside a main work string, allows for work in the annulus to regain fluid circulation. The fluid circulation can have an adequate rate to lift the sand from the annulus, for example, from an annular “sand off”, and circulate it out of the well. The annular fracturing cleanout apparatus is located, generally above the frac stack and below the main work string's blow out preventer (BOP).

FIG. 1 depicts a possible wellhead stack apparatus installed utilizing an embodiment of an annulus cleanout apparatus 9. Various aspects of apparatus 9 are further described below with reference to FIGS. 2 to 4. While any of the various embodiments can be employed in a wellhead stack, the apparatus actually illustrated in FIG. 1 is shown in greater detail in FIG. 2. Regardless, apparatus 9 is a wye (“Y”) type wellhead tubular, sometimes called a flow spool, including a main section 9a with an upper connection end and a lower connection end. Upper connection end and lower connection end can be configured, for example flanged or threaded, to permit coupling to other wellstack components. A main bore 9a′ is defined extending through the main section from the upper end to the lower end.

The apparatus further includes a lateral section 9b defining a lateral bore 9b′ therein. Lateral bore 9b′ is open at an upper end 9b″ of the lateral section.

The main section 9a and the lateral section 9b are coupled to define a Y shape, wherein the lateral section is coupled to the side wall of the main section and the lateral bore 9b′ converges at its lower end with the main bore 9a′. In other words, a lower end of the lateral bore joins and opens into the main bore at an intersection 9c near the lower end connection. The main bore 9a′ is installed via the end connections in communication and aligned with the inner diameters of the wellhead stack assemblies, through which the well's main work string extends.

A wellhead stack is installed on top of the wellhead 12. In a typical wellhead installation according to the present invention, such as is illustrated in FIG. 1, apparatus 9 is located above a frac stack 100, also known as a fracturing wellhead assembly, and below the main work string's BOP assembly 103.

A fracturing wellhead assembly 100 includes gate valves 8, a frac manifold 10 and flow cross 11 on top of the wellhead 12. The fracturing wellhead assembly includes an inner diameter that extends through the parts and is openable to and in communication with the inner diameter of the wellhead 12, below which is the wellbore or hole. The components in fracturing wellhead assembly 100 are utilized to handle high pressure fluids during stimulation operations. For example, frac manifold 10 is a flow diverter cross utilized for diverting the fracturing sand into the wellbore. Frac manifold 10 ensures that annular fracturing methodologies can be carried out through the wellhead stack.

BOP assembly 103 includes at least a BOP 4. A BOP is a tubular structure including a bore defining an inner diameter through which a wellbore work string can pass. A BOP also includes a radially, inwardly drivable annular seal that encircles the inner diameter of the BOP. BOP assembly 103 may also include a stripper 2, a lubricator 3 and various valves. In this illustrated embodiment, BOP assembly 103 is a quad BOP assembly, with four BOP seals in BOP 4, and is configured for handling coiled tubing. In other words, the radially, inwardly drivable annular seal of the BOP is configured to close around a coil tubing. BOP assembly 103, as illustrated, further includes a flow tee flanged valve 5, a flow valve 6, a flow cross 7 and a gate valve 8.

During operation, the main or primary coiled tubing string 1 stabs into the main coiled tubing stripper 2 and runs in through the aligned inner diameters of the the BOP assembly 103, fracturing wellhead assembly 100 and the wellhead 12 and into the wellbore. In so doing, an annulus is defined between the coiled tubing string and the inner wall of the wellbore. Annular fracturing operations are conducted into the annulus.

As noted above, apparatus 9 is installed between the fracturing wellhead assembly 100 and the BOP assembly 103. The main bore is aligned and in communication with inner diameters of the fracturing wellhead assembly 100 and the BOP assembly 103.

Therefore, the main coiled tubing string 1 runs through the main bore and an annulus is defined between tubing string 1 and the wall defining main bore 9a′.

The lateral section 9b of apparatus 9 permits a lateral work string, such as coiled tubing string 13, to be run into the annulus. In particular, coiled tubing string 13 can be run in through the lateral bore 9b′ into annulus in the main bore 9a′.

In a wellhead stack, a lateral coiled tubing wellhead assembly 102 can be installed on the upper end of lateral section 9b of apparatus 9. The upper end can be formed as a connection, such as a flanged or threaded connection to facilitate connections. Lateral coiled tubing wellhead assembly 102 can include a stripper 14 and one or more lubricators 15. Lateral coiled tubing wellhead assembly 102 may also include or act as a secondary BOP 19 to operate in conjunction with the main BOP assembly 103. In one embodiment, there is a BOP integral with or rigged onto upper end of lateral section 9b. One useful BOP in this location is a tandem BOP.

In operation, the lateral coiled tubing 13 is stabbed into lateral coiled tubing wellhead assembly 102 and extends down through lateral bore 9b′, into main bore 9a′ and down into the well to perform annular cleanout operations, when required.

The apparatus further includes a bore control mechanism 16 for the lateral bore 9b′. While FIG. 1 illustrates two bore control mechanisms 16 on the lateral section 9b, there may be one or more such mechanisms on the lateral section 9b, as described below. As noted, FIG. 2 is an enlarged illustration of the annular fracturing cleanout apparatus 9 of FIG. 1. FIG. 2 is a cross-section view along the long axis of main bore 9a′.

Bore control mechanism 16 can be operable to control fluid flow through the bore and/or to shear a coil passing through the bore. Therefore, the bore control mechanism can be a pressure isolating mechanism such as a valve to control fluid flow through the lateral bore, thereby offering pressure isolation from the main bore 9a′ to the upper end of the lateral section 9b. Alternately or in addition, the bore control mechanism may be a shear mechanism with a sharpened cutting edge 21 configured to move from a position retracted from the lateral bore 9b′ to an active position protruding into the lateral bore, to cut any coiled tubing in the path of the sharpened edge of the shear mechanism. To mitigate emergency situations, the apparatus may include one or more bore control mechanisms to have both coil shear and lateral bore sealing functions.

While one or more other bore control mechanisms can be employed for lateral bore 9b′, the bore control mechanisms of FIG. 2 are two shear/blind combination rams 16, each of which has an actuator system. Shear/blind combination rams 16 are operable to both shear a coiled tubing string and create pressure isolate, when moved to the active position.

The illustrated shear/blind combination ram and actuator system assembly of FIG. 2 includes a shear/blind combination ram 22, which carries the cutting edge 21. The ram is movable to drive the cutting edge between a retracted position and a position protruding into the lateral bore, which also opens and closes the lateral bore 9b′. The ram is driven by a piston rod 23 and a piston head 24 in a piston housing 27 and actuated by a drive system. The mechanism 16 also includes a manual stem 25, a manual stem guard 26, an actuator flange 28 and dismantling post and housing 29. Though not depicted, another bore control mechanism may be mounted above mechanism 16 in the lateral bore or on the lateral connection at upper end 9b″.

The two bore control mechanisms are located in series in the lateral section. One or both of the shear/blind combination ram and actuator systems 16 could be replaced by other bore control mechanisms, as will be apparent from FIG. 4. For example, the bottom shear/blind combination ram, which is the one closest to the main bore 9a′, or the upper ram, could be replaced by another type of bore control mechanism. For example, the bore control mechanisms can be selected from the ram assemblies as shown in FIGS. 1 and 2 or pipe slip rams, ball valves, plug valves, flapper valves, pipe/slip combination rams, other rams, etc.

FIG. 3 illustrates a single shear/blind combination ram and actuator system assembly 16 in the lateral section of another apparatus 9.

The combination ram and actuator assemblies 16 such as those depicted in FIGS. 2 and 3, could be positioned in different orientations to accommodate manufacturing, assembly and serviceability. Depicted in these figures are single actuating rams, however, dual actuating rams are possible depending on orientation.

As noted above, other types and various combinations of bore control mechanisms can be employed in the lateral bore, as shown in FIG. 4.

As noted, the various bore control mechanisms can each be used alone, in multiples and in combinations. Some operate for sealing/pressure control, some are for coil shearing, and some can act in both ways. For example, ball valves can be opened or closed under pressure and, therefore, serve a pressure isolation function. The ball valve acts to contain wellbore pressure below it in the lateral section, for example, to stop well bore fluid from reaching the upper end 9b″ of the wye. In one embodiment, a ball valve can be selected with additional shear capabilities to operate both for sealing and for coil cutting. A plug valve can be opened and closed under pressure and its purpose also is fluid control, in particular, when closed to contain wellbore pressure below it in the wye. The ball valve and the plug valve are two examples of valves useful for installation on the lateral section.

It is useful to have one or more bore control mechanisms 16 in the lateral to function both for coil control, such as shearing, and for pressure isolation. For example, with shear-configured ball valves and/or shear/blind combination rams the operator has the option to both cut and seal the coiled tubing in the wye portion. In particular, these mechanisms have bore control functions of both sealing and coil cutting, wherein the mechanisms can be actuated to cut the coiled tubing in the wye and also to seal or close well bore fluid from reaching the upper end of the lateral section 9, when coiled tubing has been cut or removed from the wellbore.

With reference to FIG. 4, there may be a benefit to combine two types of bore control mechanisms, for example, including one 16e selected to shear a coil tubing string and another 16f acting as a valve to pressure isolate. The shear functioning mechanism 16e, such as a shear/blind ram or shear ball valve, is on the bottom, closer to the main bore 9a and the pressure isolating valve 16f, such as a ball or plug valve, is the mechanism closer to the upper end of the lateral section. The ball or plug valve is more compact option and can seal the wye with no hydraulic connections required to operate, as compared with the shear/blind. In addition, the valve 16f acts as a failsafe against fluid leaks in case sealing action of the shearing mechanism becomes compromised during operation. Regardless, both the valve and shearing bore control mechanisms can be used together advantageously in a single wye lateral.

Pressure handling ports may be provided to address pressure locks and pressure equalization below, above and/or between the bore control mechanisms 16. For example, there may be pressure handling port in the upper lateral bore between the upper end and upper system 16 and pressure handling port in the length of the lateral bore between the systems 16 and the pressure handling ports can be in communication for pressure equalization between the accessed lengths of the lateral bore. The pressure handling ports may be incorporated in the pressure mechanisms. For example, there may be equalizing valves built into a shear/blind application so pressure can be equalized prior to opening up the blades once they have been functioned. However, the pressure handling ports may not be required in some installations. For example, where mechanism 16 is a ball or plug valve, such as mechanism 16f in FIG. 4, the apparatus would not need any pressure handling ports.

The annular fracturing cleanout apparatus is unique as it can have bore control mechanisms in the wye lateral portion, which can shear the secondary coil and seal the lateral bore, if required. The apparatus provides a secondary entry option below the existing coiled tubing blow-out preventor. The apparatus allows the entry of primary coil tubing string thru the main bore, and the ability to run a secondary coil tubing string entered thru the wye lateral of the apparatus. The apparatus/wellhead stack can be used for many types of well interventions such as stimulation, for example, annular fracturing. In such cases where the primary coiled tubing gets stuck/sanded off in the hole, a secondary coiled tubing string can be run through the wye portion to aid in freeing the stuck tubing. Integral valve or valves positioned in the wye lateral portion can be used to shear/seal the secondary string if required to maintain well control and ability of the secondary coil tubing to rig off of the well.

According to one method, the apparatus 9 is installed in the wellstack between the fracturing wellhead assembly 100 and the BOP assembly 103. Wellbore operations, including injecting a primary coil string down through the BOP 4, main section 9a and fracturing wellhead assembly 100, can proceed as normal.

If the job proceeds without the need for annular cleanout, for example, the primary coil does not become sanded in, the apparatus 9 is not used.

However, if wellbore clean out is required, fluid injection through the frac manifold 10 is ceased. Then, a secondary coiled tubing string is entered through the wye lateral section 9b and into the primary bore 9a′ of the side entry spool apparatus 9. The secondary coiled tubing string is then run in down the wellbore alongside the primary coil. Fluid can be circulated down the secondary coil and up the well to the wellhead, to lift sand from the wellbore. Fluid can be pumped through both the primary and secondary strings simultaneously. Sand-laden returns can exit the well through flow cross 7 in the BOP assembly 103 or through frac manifold 10.

Thus, through the use of apparatus 9, the operator is able to run in the secondary coil and clean out the fracturing sand so the operations with the primary coil can continue. When the clean out procedure is done, the secondary coil can be pulled out of the hole and the primary coil can be advanced to further designated frac sites within the well bore.

The cleanout procedure available through apparatus 9, decreases the chance of the primary coil tubing getting stuck. In particular, fluid can be circulated through the secondary coil and this circulation can help remove sand to free the primary coil or prevent the primary coil from getting physically stuck in the well bore.

When the secondary coil is not in place, the lateral bore 9b′ can be sealed off by the one or more bore control mechanisms 16. If the secondary coil becomes stuck, mechanisms 16 with a shear capability, such as the shear/seal mechanisms, allow the secondary coil to be sheared. Thus, if the secondary coils becomes stuck, the coil can be cut and lateral section 9b can be sealed off so no well bore fluids and gasses escape therethrough from the well.

In addition, because the apparatus 9 is positioned below the primary coil's main BOP 4, that main BOP is always available and fully operable for overall well control. Because the secondary string does not extend through the main BOP, it can be properly sealed around the primary coil if required.

Thus, coiled tubing well intervention such as fracturing can be completed safely and efficiently.

The previous description of the disclosed embodiments is provided to enable any person skilled in the art to make or use the present invention. Various modifications to those embodiments will be readily apparent to those skilled in the art, and the generic principles defined herein may be applied to other embodiments without departing from the spirit or scope of the invention. Thus, the present invention is not intended to be limited to the embodiments shown herein, but is to be accorded the full scope consistent with the claims, wherein reference to an element in the singular, such as by use of the article “a” or “an” is not intended to mean “one and only one” unless specifically so stated, but rather “one or more”. All structural and functional equivalents to the elements of the various embodiments described throughout the disclosure that are known or later come to be known to those of ordinary skill in the art are intended to be encompassed by the elements of the claims. Moreover, nothing disclosed herein is intended to be dedicated to the public regardless of whether such disclosure is explicitly recited in the claims. No claim element is to be construed under the provisions of 35 USC 112, sixth paragraph, unless the element is expressly recited using the phrase “means for” or “step for”.

Claims

1. An annulus cleanout apparatus comprising:

a main section including an upper connection end, a lower connection end and a main bore extending through the main section from the upper connection end to the lower connection end;

a lateral section connected in a wye configuration with the main section, the lateral section defining a lateral bore therein, the lateral bore opening at an upper end of the lateral section and converging at a lower end with the main bore; and

a bore control mechanism in the lateral section, the bore control mechanism being actuatable to: (i) create a seal in the lateral bore and/or (ii) shear a coil tubing extending through the lateral bore,

wherein the upper connection end and the lower connection end are configured for connection in line to components of a wellhead stack assembly.

2. The annulus cleanout apparatus of claim 1 wherein the bore control mechanism includes a shear configured for shearing a coil tubing passing through the bore control mechanism.

3. The annulus cleanout apparatus of claim 1 wherein the bore control mechanism includes a valve operable between an open position allowing fluid flow from the lower end to the upper end and a closed position sealing against fluid flow through the lateral section.

4. The annulus cleanout apparatus of claim 1 wherein the bore control mechanism includes a shear configured for shearing a coil tubing passing through the bore control mechanism and further comprising a second bore control mechanism positioned between the bore control mechanism and upper end and the second bore control mechanism including a valve operable between an open position allowing fluid flow from the lower end to the upper end and a closed position sealing against fluid flow through the lateral section.

5. A wellhead stack for well servicing with multiple work strings, the wellhead stack comprising:

a lowermost end configured for connection to a wellhead of a well;

a fracturing wellhead assembly coupled above the lowermost end;

a blow out preventer assembly including at least a blow out preventer; and

an annular fracturing cleanout apparatus installed above the fracturing wellhead assembly and below the blow out preventer assembly, the annular fracturing cleanout apparatus including:

a main section including an upper connection end, a lower connection end and a main bore extending through the main section from the upper connection end to the lower connection end; and

a lateral section connected in a wye configuration with the main section, the lateral section defining a lateral bore therein, the lateral bore opening at an upper end of the lateral section and converging at a lower end with the main bore.

6. The wellhead stack of claim 5 wherein the lateral section includes a bore control mechanism for the lateral bore, the bore control mechanism being actuable: (i) create a seal in the lateral bore and/or (ii) shear a coil tubing extending through the lateral bore.

7. The wellhead stack of claim 6 wherein the bore control mechanism includes a shear configured for shearing a coil tubing passing through the bore control mechanism.

8. The wellhead stack of claim 7 further comprising a pressure isolating mechanism positioned between the bore control mechanism and the upper end of the lateral bore, the pressure isolating mechanism being actuable between an open position allowing fluid flow from the lower end to the upper end and a closed position sealing against fluid flow through the lateral section.

9. The wellhead stack of claim 5 wherein the fracturing wellhead assembly includes a fracturing manifold.

10. The wellhead stack of claim 5 wherein the blow out preventer is configured for closing around a coil tubing string.

11. A method for intervention in a wellbore, the method comprising:

running a secondary coil tubing string into an annulus between a primary tubing string in the wellbore, the running operation including:

inserting the secondary coiled tubing string through a lateral section connected in a wye configuration with a main section of an annulus cleanout apparatus;

inserting the secondary coiled tubing string into the main section and into the annulus around the primary tubing string in the wellbore; and

circulating fluid through the secondary coiled tubing string to remove sand from the annulus.

12. The method of claim 11 further comprising: operating a blow out preventer to seal about the primary tubing string while the secondary coiled tubing string remains in the well.

13. The method of claim 11 wherein circulating includes releasing the primary tubing string from a stuck condition and moving the primary tubing string through the wellbore.

14. The method of claim 11, further comprising: operating a pressure isolating mechanism in the lateral section to seal pressure in the main section.

15. The method of claim 11, further comprising: operating a shear apparatus to shear the secondary coil tubing string and seal pressure in the main section.

16. The method of claim 11, wherein the method for intervention is an annular clean out operation during a coiled tubing well fracturing operation.