Multi-zone completion assembly installation and testing

A method of deploying a multi-zone completion assembly in a wellbore is disclosed. The method includes: placing an outer assembly below a surface location, wherein the outer assembly includes an activation device. The method further includes placing an inner assembly in the outer assembly, the inner assembly including a lower opening tool spaced from an upper opening tool. The method further includes activating the lower opening tool using the activation device The method further includes activating the upper opening tool independent of the lower opening tool using the activation device.

BACKGROUND

1. Field of the Disclosure

This disclosure relates generally to apparatus and methods for completing a multi-zone wellbore for the production of hydrocarbons from subsurface formations, including fracturing, sand packing and flooding the zones.

2. Background of the Art

In wellbores that include multiple production zones, a multi-zone completion assembly that includes an outer multi-zone assembly (hereinafter the outer assembly or string) with an inner assembly inside the outer assembly are used in the wellbore for fracturing and gravel packing (frac/packing) of each zone before producing the hydrocarbons (oil and gas) from such zones. The outer assembly typically includes a top packer, a bottom packer and an isolation packer for each zone. To treat a particular zone, such zone is isolated from other zones by setting the packers. A cross-over (also referred to as frac port) in the inner assembly is aligned with a flow port (also referred to as a “frac sleeve”) in the outer assembly. A treatment fluid (typically a mixture of water, proppant and additives) is supplied under pressure into the inner string, which treatment fluid flows form the frac port to the formation via the flow port. Some multi-zone completion assemblies may include 5 or more spaced apart sections, each section exceeding 500 feet in length and several hundred feet apart.

The disclosure herein provides a method and tools to assemble and test a multi-zone outer completion assembly on the rig floor and running of multiple deactivated opening or shifting tools on an inner assembly through the outer assembly and then activating such tools once such tools reach a specific location in the outer assembly before placing the outer assembly with the inner assembly therein in the wellbore for performing any treatment operations.

SUMMARY

In one aspect, a method of deploying a multi-zone completion assembly in a wellbore is disclosed. In one non-limiting embodiment, the method includes: placing an outer assembly below a surface location, wherein the outer assembly includes an activation device; placing an inner assembly in the outer assembly, the inner assembly including a lower opening tool spaced from an upper opening tool; activating the lower opening tool using the activation device; and activating the upper opening tool independent of the lower opening tool using the activation device.

In another aspect, a multi-zone completion assembly is disclosed that in one embodiment includes: an outer assembly for placement in a wellbore; and an inner assembly for placement in the outer assembly, wherein: the outer assembly includes an activation device; the inner assembly includes a lower opening tool spaced from an upper opening tool; and wherein the lower opening tool is activated from a deactivated position using the activation device and the upper opening tool is activated from a deactivated position independently of the activation of the lower opening tool using the activation device.

Examples of the more important features of a well completion system and methods have been summarized rather broadly in order that the detailed description thereof that follows may be better understood, and in order that the contributions to the art may be appreciated. There are, of course, additional features that will be described hereinafter and which will form the subject of the claims.

DETAILED DESCRIPTION OF THE DRAWINGS

FIGS. 1 and 2show placement (or deployment) of an outer assembly (or outer string) of a completion assembly into a wellbore from a rig floor104. In one aspect, the rig may be an offshore rig wherein a riser runs from the rig to the top of a wellbore formed from the sea floor. In another aspect, the wellbore may be drilled from an earth surface. The wellbore is a multi-zone well that has been configured for treatment of and production from a number of zones. The outer assembly includes serially connected multiple sections, each section including a number of devices, such as packers, sand screen, fluid flow devices and devices or profiles that interact with a service assembly for performing various downhole operations. The outer assembly is permanently placed in the wellbore. In general, each outer assembly section is assembled at the surface, sequentially placed or hung from the rig floor inside the riser or the wellbore, as the case may be, and pressure tested to ensure that various flow devices in each such section are operating correctly. Once the outer string has been assembled and tested, service assembly (also referred to as the “inner assembly”) is placed inside the outer assembly to perform a variety of operations relating to the various devices in the outer assembly for treatment of the zones.

FIG. 1shows placement of the first or lowermost section110afrom the rig floor104into a riser or wellbore. The section110aincludes a sand screen S1that includes a fluid flow device or port, such as a sliding sleeve valve and other flow devices generally denoted as122a. An isolation packer124aabove screen S1is used to isolate the first section110afrom other sections, as described later in reference toFIG. 2. A packer activation device125ais provides to activate or set the packer124ainside the well. A fluid flow device (referred to herein as ‘frac sleeve”)140a, such as a sliding sleeve valve, when open allows a treatment fluid to flow from inside the section110ato a zone in the formation. The section110afurther includes an activation device or profile132and an opening tool test device or profile134above the activation device, each such device configured to interact with an opening tool, described later in reference toFIGS. 3-5. A plug145below the screen S1is provided to block fluid flow past the plug. A test plug147is placed at the surface to facilitate pressure testing of the section110a. In aspects, the plug145may be configured to break when pushed downward or to move it from a closed position to an open position. The plug145may then be closed at a later time. A seal149may be provided below or above the activation device132for sealing an inner assembly to the outer assembly110aas described in reference toFIG. 7. Seals, such as inverted seals142aand142b, are provided to seal an area around the frac sleeve140abetween the outer section110aand the inner string (described later). In addition, the section110aincludes a locating profile146afor locating that position on the section110aand a set down profile144afor setting the inner assembly to perform a treatment operation. The first section110ais assembled with the screen S1, flow devices120a,122a,140a, activation and test devices132,134, and the plug145. All flow devices are installed in the section110ain their closed position. The section110ais then run into the riser or the wellbore and hung from the rig floor104. A fluid150under pressure is supplied into the section110ato determine presence of any leaks. No pressure drop at the surface indicates that all flow devices in section110aare in their respective closed positions, while a drop in pressure indicates a leak.

Referring toFIG. 2, once the lowermost section110ahas been pressure tested, a second or next upper section110bis installed above the section110a. The section110bincludes the components and devices described in reference to section110a, except section110bdoes not include the activation profile132or the test device134. The second section110bis then pressure tested. Similarly, all other sections (through110n), each corresponding to a zone, are sequentially placed above the previously placed section and pressure tested.FIG. 2shows the entire outer assembly110assembled and hung from the rig floor104, wherein each section110a-110nhas been pressure tested and wherein all flow devices in the outer assembly110are in their respective closed positions.

Referring toFIG. 3, once all sections110a-110nof the outer assembly110have been assembled and tested, an inner assembly210(also referred to as the “service assembly” or the “inner assembly”) is run inside the outer assembly110. In aspects, the inner assembly210includes a lower opening tool220spaced apart from an upper opening tool230, wherein each opening tool is configured to open one or more devices in the outer string110. Additional spaced apart opening tools may also be provided. The inner assembly210further includes a lower closing tool222and an upper closing tool232, each configured to close one or more devices in the outer assembly110. The inner assembly also includes a set down tool266to set the inner assembly210in the outer assembly110at a setting profile190at each section of the outer assembly. The inner assembly further includes an up-strain locating device268to locate a profile192in each of the sections110a-110n. The inner assembly220further may include a mandrel270, such as slick line at the bottom end of the inner string220to provide a seal between the inner assembly210and the seal149on the outer assembly110as described in reference toFIG. 7. The inner string also includes a cross-over port (also referred to as the “frac-port”)275having a flow path276to supply a fluid from the inner assembly201to each of the frac sleeves140a-140n, The inner string210is run in the outer assembly110until the lower opening tool220is at or below the activation device132as shown inFIG. 3, while the mandrel270remains above the plug145.

In one non-limiting embodiment, each opening tool220and230includes a shifting collet that is initially collapsed to a diameter less than the diameter needed to engage any corresponding profiles in the outer assembly110. In one configuration, the shifting collet is collapsed by a sleeve installed over the shifting collet. The sleeve may be a part of a mechanism (sleeve mechanism) that includes a shear pin or shear screw that prevents the shifting collet from moving axially. In one aspect, the sleeve mechanism can only transmit load onto the shear pin in one direction. This sleeve mechanism engages with the opening tool activation profile132(FIG. 1) in the uphole direction only, such that after the sleeve mechanism passes the activation profile132, movement of the sleeve mechanism in the reverse direction (uphole) will cause the sleeve mechanism to engage the activation profile132, allowing force to be transferred to the shear pin holding the sleeve in place over the collet. Any other type of an opening tool available in the art, including one containing dogs, may be utilized for the purpose of this disclosure. Such tools and mechanisms are known in the art and are thus not described in detail herein.

In one non-limiting embodiment, the testing device134includes a sliding sleeve with a collet engaged in a detent in a sliding sleeve housing. This collet creates a mechanical force which holds the sliding sleeve in place until sufficient force has been generated to snap the collet out of the detent. To test the opening tool220or230, the shifting collet on the opening tool is positioned above the sliding sleeve of device132and then moved downward to engage the collet in the sliding sleeve. Once the collet engages the sliding sleeve, the inner assembly220will stop moving until the collet snap force on the sliding sleeve has exceeded a threshold. At this point, the inner assembly210continues to move down and the shifting collet disengages from the sliding sleeve. After the shifting collet has disengaged from the sliding sleeve, a spring resets the sliding sleeve to its original position allowing it to function again. Such mechanisms are known in the art and are thus not described herein in detail. Any other device may be utilized as the opening tool with a corresponding activation device. In general, an increased amount of force is required to move the opening tool past the test device, which provides a verification indication or confirmation.

Until this point, the opening tools are disabled or deactivated. Prior to performing any treatment operation, the opening tools220and230are first activated from their deactivated positions. Referring toFIG. 3, to activate the lower opening tool220, the inner assembly210is lowered to cause the lower opening tool220to pass the activation device132. The inner assembly210is then picked up (moved uphole) to engage or interact with the lower opening tool220with the activation device132. Moving uphole the opening tool220past the activation device132will require a force F1that provides an indication to an operator that the opening tool has been activated. To confirm or verify that the opening tool220has been activated, the inner assembly210is moved uphole further to move the lower opening tool220past that testing or verification device134on the outer assembly110as shown inFIG. 4. Setting the opening tool220past the testing device134will cause the opening tool220to stop and then an increased force F2downward will cause the opening tool220to continue to move downward with the opening tool activated, as shown inFIG. 5. At this stage, the lower opening tool220is confirmed as being activated. In aspects, the verification device is multi-acting and thus the verification process may be repeated.

To activate the upper opening tool230, the inner assembly110is moved down to cause the device270at the bottom of the inner assembly110to remove or deactivate the plug145and to move the upper opening tool230past the activation device132, as shown inFIG. 6. The upper opening tool230is then activated and such activation verified or confirmed, as described above in reference to the lower opening tool220andFIGS. 3-5. If the inner string110includes additional opening tools, such tools are activated in the manner described above in reference to the upper opening tool230.

Referring toFIG. 7, after all the opening tools220and230have been activated and verified, the inner string110is moved uphole to reestablish a seal between the inner assembly210and the outer assembly110, which may be accomplished by establishing a seal between a device, such as mandrel270, on the inner assembly and seal149on the outer string210, as shown inFIG. 7. At this stage, a fluid350may be supplied under pressure to the inner assembly110to pressure test the outer assembly210to ensure that all flow devices in the outer assembly210are closed. The inner assembly110is then moved uphole to disengage the seal between the mandrel270and seal148as shown inFIG. 8. This step enables the system to establish forward circulation path while running tools in the wellbore101. The inner assembly110is now assembled or deployed in the outer assembly210. The outer assembly220, with the inner assembly110with the opening tools220and230activated may now be lowered into the wellbore101.FIG. 8shows the outer assembly220with the inner assembly110placed at the bottom101aof the wellbore101formed in a formation102. In a multi-zone wellbore, a casing106is placed in the wellbore101and cement108placed in the annulus between the casing106and the wellbore101. Perforations118a-118ncorresponding to zones Z1-Zn establish fluid communication between each zone and the outside of the section110a. Sections110a-110nin the outer string210align with their corresponding zones Z1-Zn. Screen S1is placed across from zone Z1, screen S2from across zone Z2and screen Sn from across from zone Zn. The wellbore101is now ready for treatment. To treat a particular zone, such as zone Z1, it is isolated from the other zones by setting packer124a, frac sleeve140ais opened and the frac port275aligned with the frac sleeve140a. The area around the frac sleeve140between the inner assembly210and the outer assembly110is sealed with seals144aand146a. A treatment supplied into the inner string110awill move to the zone Z1via the frac port275and the frac sleeve140a. Other zones may be treated in the manner described above. Depending upon the depth of the zones, the opening tools220and230may be several hundred feet apart. The lower opening tool220may be used to open ports, such as port180at or near the bottom of the screen while the upper opening tool230may be used to open the frac sleeve140a. This avoids moving the entire inner assembly210great distances inside the outer string assembly110for performing downhole operations.

The foregoing disclosure is directed to the certain exemplary embodiments and methods of the present disclosure. Various modifications will be apparent to those skilled in the art. It is intended that all such modifications within the scope of the appended claims be embraced by the foregoing disclosure. The words “comprising” and “comprises” as used in the claims are to be interpreted to mean “including but not limited to”. Also, the abstract is not to be used to limit the scope of the claims.