US20220081993A1

US20220081993A1 - Single-Trip Deployment And Isolation Using Flapper Valve

Info

Publication number: US20220081993A1
Application number: US17/022,670
Authority: US
Inventors: Francois Chevallier; Ibrahim El Mallawany
Original assignee: Halliburton Energy Services Inc
Current assignee: Halliburton Energy Services Inc
Priority date: 2020-09-16
Filing date: 2020-09-16
Publication date: 2022-03-17
Also published as: GB202301405D0; GB2612241B; NO20230097A1; GB2612241A; WO2022060384A1; GB2628743A; GB202409711D0; BR112022023869A2

Abstract

A downhole deployment and isolation system may be used to deploy a completion string, service the well, and isolate the lower completion string, optionally in a single trip. The lower completion string may be run into the well with a valve in an open condition, such as a flapper valve propped open by a mandrel. The mandrel may be operable to both disconnect the work string from the lower completion string and to close the valve upon disconnecting such as by removing the mandrel from the flapper. The valve may be remotely reopened with fluid pressure form surface.

Description

BACKGROUND

Wells are often constructed for the potential recovery of hydrocarbons such as oil and gas. Constructing a productive well with the potential for economic recovery is challenging, time-consuming, and expensive. Typically, a well may be drilled with a drill bit at the lower end of a string of tubular drill pipe that is progressively assembled to reach the desired well depth, which may be thousands of feet deep and follow a complex well plan. After drilling, a string of relatively large diameter tubular casing may be lowered into the wellbore and secured by circulating cement downhole and through an annulus between the casing and formation. This casing string reinforces the wellbore and may be perforated at selected depths and intervals for extracting hydrocarbon fluids from a production zone(s) of the formation. The well may be stimulated by sealing off and delivering fluid to selected production zones. Then, a production tubing string may be run into the well to the production zone, protecting the casing and providing a flow path to a wellhead through which the oil and gas can be produced.
Although summarized succinctly, each of these stages of well construction can be very complex, costly, and involve a great deal of effort and energy, with no guarantee of economic recovery of hydrocarbons. Much of the cost of drilling and maintaining a well is related to the amount of time and equipment involved. Each trip to deploy or retrieve equipment from the wellbore, or to service, replace, or repair downhole equipment, can significantly increase the overall cost. Additionally, each time downhole equipment is placed into service in the wellbore or retrieved from the wellbore, there is potential for the wellbore and/or the equipment to be damaged, with the costs for repairing such damage increasing due to the downtime of the wellbore. Thus, one of the myriad aspects of ongoing innovation in the field is directed to minimizing trips, minimizing downtime between trips, and maximizing productivity of the well.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is an elevation view of an example well system setting forth the general environment and context in which a deployment and isolation system of the present disclosure may be implemented.

FIG. 2 is a side view of a system for deploying and isolating a lower completion string in a single-trip according to aspects of this disclosure.

FIG. 3A is an enlarged, detailed view of the connector of FIG. 2 oriented ninety degrees counterclockwise with respect to the orientation of FIG. 2.

FIG. 3B is a detail view of the connector taken at section “3B” of FIG. 3A illustrating example features of the releasable connection mechanism according to one or more embodiments.

FIG. 4 is an enlarged, detailed view of an embodiment of the flapper valve connected downhole of the connector, oriented ninety degrees counterclockwise with respect to the orientation of FIG. 2.

FIG. 5 is a detailed view of the flapper valve of FIG. 4, with the flapper pivoted to the closed position after the work string has been retrieved.

FIG. 6 is a detailed view of the flapper valve after the flapper actuator has been moved to the extended position to reopen the flapper.

FIG. 7 is a schematic diagram of the valve of FIG. 2 wherein the flapper valve is substituted with a bidirectional valve and valve controller.

DETAILED DESCRIPTION

The present disclosure provides systems and methods for deploying a lower completion string, servicing the well with a treatment fluid down the work string into the completion string, and then fluidically isolating the lower completion string when retrieving the work string. This sequence may now be performed in a single trip, without requiring a further trip with this or another work string to close or reopen the valve. The valve may also include a remote reopening feature to reopen the valve, also without an additional trip, such as to commence production after landing a final completion. An example system includes a connector for releasably connecting the work string with the lower completion string with a flapper valve propped open by a mandrel. The flapper remains open while delivering a fluid downhole through the work string and mandrel to service the well. The mandrel is then manipulated to close the flapper valve, such as by axially removing the mandrel from the flapper, and to disconnect from the lower completion string. Although embodiments are disclosed using the example of a flapper valve, other types of valves including bi-directional valves are also within the scope of this disclosure.
FIG. 1 is an elevation view of an example well system 100 setting forth the general environment and context in which a deployment and isolation system of the present disclosure may be implemented. The well system 100 may include an oil and gas rig 102 arranged at the earth's surface 104 and a wellbore 106 extending therefrom and penetrating a subterranean earth formation 108. The rig 102 may include a large support structure such as a derrick 110, erected over the wellbore 106 on a support foundation or platform, such as a rig floor 112. Even though certain drawing features of FIG. 1 depict a land-based oil and gas rig 102, it will be appreciated that the embodiments of the present disclosure are useful with other types of rigs, such as offshore platforms or floating rigs used for subsea wells, and in any other geographical location. For example, in a subsea context, the earth's surface 104 may be the floor of a seabed, and the rig floor 112 may be on the offshore platform or floating rig over the water above the seabed. A subsea wellhead may be installed on the seabed and accessed via a riser from the platform or vessel.
The derrick 110 or other support structure may be used to help support and manipulate the axial position of a work string 114 such as to raise and lower it within the wellbore 106. The work string (referred to in the art as a landing string in certain contexts) is a tubular string made up of drill pipe, casing, production tubing, or other tubular segments, and having any of a variety of tools for performing wellbore operations, such as drilling, completion, stimulation, or production. The work string 114 may serve various functions, such as to lower and retrieve tools, to convey fluids, and to support the conveyance of communication and/or power during wellbore operations. When a wellbore operation is to be performed, the work string 114 may be progressively assembled on site and lowered into the wellbore 106, i.e. run/tripped into the hole. When a wellbore operation is complete, or when it becomes necessary to exchange or replace tools or components of the work string 114, the work string 114 may be raised or fully removed from the wellbore 106, i.e., tripped out of the hole. In an example of a drilling operation, a drill string may be used to drive rotation of a drill bit, while circulating drilling fluid (“mud”) and conveying signals via mud pulse or wired telemetry. In an example of a completion operation, the work string 114 may be used to lower a completion string into the wellbore 106, including intervals of casing, and cement the casing in place. In an example of a formation stimulation operation, proppant-laden fluids used in hydraulically fracturing the formation, or other treatment fluids and/or chemicals such as an acidizing treatment, may be circulated downhole through a tubular member, such as through a hydraulic fracturing tubing string (i.e. frac tubing string) to stimulate the flow of hydrocarbons from the formation. In an example of a production operation, production tubing may be lowered into the wellbore 106 and coupled to the lower completion string above a production zone, so formation fluids such as oil and gas may be produced to surface.
The wellbore 106 may be drilled according to a wellbore plan and along a desired wellbore path to reach a target formation, to avoid non-desirable formation features, to minimize footprint of the well at the surface, and to achieve any other objectives for the well. The wellbore 106 extends from the heel 103 at surface, where drilling commences, to the toe 125, and may follow any path (the wellbore path) in between. The initial portion of the wellbore 106 is typically vertically downward as the drill string would generally be suspended vertically from the rig 102. Thereafter the wellbore 106 may deviate in any direction as measured by azimuth or inclination, which may result in sections that are vertical, horizontal, angled up or down, and/or curved. The term uphole generally refers to a direction along the wellbore path toward the heel 103 and the term downhole generally refers to a direction toward the toe 125, without regard to whether a feature is vertically upward or vertically downward with respect to a reference point. In the example of FIG. 1, the wellbore path includes an initial vertical section 105, followed by a curved section 115 downhole of the vertical section 105 that transitions from the vertical section 105 to a horizontal or lateral section 120 downhole of the curved section 115. Thus, the vertical section 105 is uphole of the curved section 115 and lateral section 120.
In an embodiment, the wellbore 106 may be at least partially cased with a casing string 116 or may otherwise remain at least partially uncased. The casing string 116 may be secured within the wellbore 106 using, for example, cement 118. In other embodiments, the casing string 116 may be only partially cemented within the wellbore 106 or, alternatively, the casing string 116 may be entirely un-cemented. The work string 114 may be coupled to a completion assembly 119 that extends into a generally horizontal branch referred to as a lateral section 120 of the wellbore 106. As illustrated, the lateral section 120 may be an uncased or “open hole” section of the wellbore 106.
There are specific reasons why the lateral section 120 may be formed. For example, in a multilateral application, a vertical wellbore may first be drilled traversing multiple productive zones at different vertical depths, and a lateral section may be drilled to each productive zone to maximize production. Another example is steam-assisted gravity drainage (SAGD) applications, in which two parallel lateral sections are drilled, one below the other, and steam is injected into the upper lateral to stimulate the flow of hydrocarbons, assisted by gravity, into the lateral below it. It is noted that although FIG. 1 depicts horizontal and vertical portions of the wellbore 106, the principles of the apparatus, systems, and methods disclosed herein may be similarly applicable to or otherwise suitable for use in wholly horizontal or vertical wellbore configurations. Consequently, the horizontal or vertical nature of the wellbore 106 should not be construed as limiting the present disclosure to any particular wellbore 106 configuration.
The completion assembly 119 may be arranged or otherwise seated within the lateral section 120 of the wellbore 106 using one or more packers 122 or other wellbore isolation devices known to those skilled in the art. The packers 122 may be configured to seal off an annulus 124 defined between the completion assembly 119 and the walls of the wellbore 106. As a result, the subterranean formation 108 may be effectively divided into at least one interval 126 such as a pay zone. Additional pay zones (not shown) downhole of the at least one interval 126 may also be isolated by packers, and each pay zone may be stimulated and/or produced independently via isolated portions of the annulus 124 defined between adjacent pairs of packers 122. While only one interval is shown in FIG. 1, those skilled in the art will readily recognize that any number of intervals may be defined or otherwise used in the well system 100, without departing from the scope of the disclosure.
The completion assembly 119 may include one or more downhole tools schematically depicted at 128 as arranged in, coupled to, or otherwise forming an integral part of the work string 114. The downhole tools 128 may include, for example, an inflow control device (ICD) for controlling the flow of formation fluids into the lower completion string and uphole through a valve, a frac string for delivering a stimulation fluid downhole through the valve to one or more formation zones to be stimulated, or other tools for servicing the wellbore 106 or lower completion string.
As illustrated, at least one downhole tool 128 may be arranged in the completion assembly 119 in each interval 126, but those skilled in the art will readily appreciate that more than one downhole tool 128 may be arranged therein, without departing from the scope of the disclosure. The downhole tool(s) 128 may include a variety of tools, devices, or machines known to those skilled in the art used in the preparation, stimulation, and production of the subterranean formation 108.
While the downhole tool 128 is shown in FIG. 1 as being employed in an open hole section of the wellbore 106, the principles of the present disclosure are equally applicable to completed or cased sections of the wellbore 106. In such embodiments, the cased wellbore 106 may be perforated at predetermined locations in each interval 126 using any known methods (e.g., explosives, hydrajetting, etc.) in the art. Such perforations serve to facilitate fluid conductivity between the interior of the work string 114 and the surrounding interval 126 of the formation 108.
In order to actuate, trigger, or manipulate the downhole tool 128, one or more wellbore projectile(s) 134 may be introduced into the wellbore 106 and conveyed to the downhole tools 128 to engage or otherwise interact therewith. The wellbore projectiles 134 may include, but are not limited to balls (e.g., “frac” balls), darts, wipers, plugs, or any combination thereof. The wellbore projectiles 134 may be conveyed through the work string 114 and to the completion assembly 119 by any known technique. For example, the wellbore projectiles 134 can be dropped through the work string 114 from the surface 104, pumped by flowing fluid through the interior of the work string 114, self-propelled, conveyed by wireline, slickline, coiled tubing, etc.
FIG. 2 is a side view of a system for deploying a lower completion string 130, servicing the well, and then fluidically isolating the lower completion string 130, optionally in a single-trip, according to some aspects of this disclosure. The lower completion string 130 may be deployed into the wellbore 106 on the work string 114 of FIG. 1 and landed at a desired location within the wellbore 106. The lower completion string 130 is shown oriented in FIG. 2 as if in a vertical wellbore section, such as when lowering or landing the lower completion string 130 in the vertical section 105 of the wellbore 106 in FIG. 1. However, the lower completion string 130 may be run further downhole and landed in the lateral section 120 of FIG. 1.
A connector is outlined in dashed line type at 140. The connector 140 and its operation are further discussed below in relation to FIG. 3A. Below the connector 140 is a valve, which in this example is a flapper valve, outlined in dashed line type at 180. The flapper valve 180 and its operation are further discussed below in relation to FIGS. 4-6. The connector 140 is used in tripping and deploying the lower completion string 130 downhole on the work string 114, and subsequently disconnecting from the lower completion string 130. The flapper valve 180 is closed upon disconnect from the lower completion string 130, to fluidically isolate the lower completion string 130 from the wellbore 106 above the lower completion string 130.
More particularly, the flapper valve 180 includes a flapper 184, which may be biased toward a closed position, such as by a spring (e.g., a flapper close spring 181 of FIG. 4) or other biasing member. The flapper 184 is initially propped open by a lower end of the mandrel 142 while connected to the connector 140 as it would be while the lower completion string 130 is run into the wellbore 106 (i.e. as run in hole). The mandrel 142 may be manipulated, such as moved axially or rotationally according to any of a variety of connection types discussed below, to both disconnect from the lower completion string 130 and allow the flapper 184 to close. Thus, movement of the mandrel, such as to axially reciprocate with respect to other components or relative to the flapper valve 180 may result in both disconnection from the lower completion string 130 and removal of the mandrel 142 from the valve bore to close the flapper valve 180, which may at least partially due to the biasing action of the spring or other biasing member and thereby isolate the lower completion system 130. This allows for a single-trip deployment and isolation of the lower completion string 130, i.e., without having to trip the work string 114 out of the wellbore 106 or trip some other tool on coil tubing or wireline to isolate the lower completion string 130.
FIG. 3A is an enlarged, detailed view of the connector 140 of FIG. 2 according to some aspects of the disclosure. The connector 140 is oriented ninety degrees counter-clockwise in FIG. 3A with respect to its orientation in FIG. 2, corresponding with the orientation of the connector 140 when positioned in a horizontal, lateral section as described in FIG. 1. For reference, a small portion of the work string 114 is shown extending to the left (uphole of) the connector 140, and of the lower completion string 130 extending to the right (downhole of) the connector 140. The connector 140 comprises a releasable connection mechanism for initially supporting the weight of the lower completion string 130 on the work string 114 when tripping and deploying the lower completion string 130 in hole, and subsequently disconnecting from the lower completion string 130 to release the work string 114 and then trip the work string 114 out of the hole.
Any suitable connection type may be used for supporting the lower completion string 130 on the work string 114 when tripping downhole and subsequently releasing from the lower completion string 130, and the specific details that follow are provided merely by way of example. The releasable connection mechanism in FIG. 3A includes an uphole portion 150 releasably connected with a downhole portion 160. The uphole portion 150 is uphole of the downhole portion 160, such that on separation, the uphole portion 150 would be retrieved with the rest of the work string 114 and the downhole portion 160 would remain downhole with the lower completion string 130. The mandrel 142 of the connector 140 has a flow passage (mandrel bore) 143 that, while connected, allows for conveying fluids downhole through the work string to the lower completion string 130, and for conveying any fluids uphole from the lower completion string 130 to surface.
The uphole portion 150 in this example is a male connector and the downhole portion 160 is a female connector. A collet 144 on the uphole portion 150 is disposed around the mandrel 142. The collet 144 includes an outer engagement structure 152 to releasably engage with a corresponding inner engagement structure 162 on the downhole portion 160. One of the engagement structures 152 and 162 may include teeth, and the other one of the engagement structures 152 and 162 may include corresponding teeth or a threaded surface. In this example, the outer engagement structure 152 comprises teeth formed on an outer surface at an end of the collet 144, and the inner engagement structure 162 comprises threads formed on an inner surface of the downhole portion 160. The collet 144 is radially flexible, though certain features of the connector 140 are designed to prevent the collet 144 from flexing inwardly when connected to prevent inadvertent disconnection.
This arrangement of cooperating teeth on one member with teeth and/or threads on the other member optionally provides a ratchet-latch (“ratch-latch”) type of engagement, whereby as the uphole portion 150 is gradually moved axially into the downhole portion 160 to reach the position shown in FIG. 3A, the teeth on one may advance one-by-one past the individual threads or teeth on the other. When advancing to each successive tooth position, the collet 144 radially flexes inward for the teeth on the outer engagement structure 152 to advance past the crests of respective teeth on the inner engagement structure 162, and back outward into the roots (recesses between teeth) in order for the teeth to re-engage so the uphole portion 150 remains connected to the downhole portion 160.
Any of a variety of release structures or operations may be used to separate the uphole portion 150 from the downhole portion 160, such as to disconnect the work string 114 after landing the lower completion string 130. In this ratch-latch connection example, such a release mechanism may be used to flex the collet 144 radially inwardly for the engagement structures 152 and 162 to disengage from each other. The collet 144 may include a plurality of fingers not shown to facilitate flexing. One or more recess 146 may be formed between the collet 144 and the mandrel 142, such as by having the recess 146 formed on an outer surface of the mandrel 142, to provide clearance for the collet 144 to deflect and bend radially inwardly. When the collet 144 is flexed inwardly sufficiently that the teeth or threads on the outer engagement structure 152 clear the teeth or threads on the inner engagement structure 162 the collet 144 may be able to move axially with respect to the mandrel 142. This may allow the uphole portion 150 to be separated from the downhole portion 160, subject to other optional retention features such as shear members.
Shear members may also be implemented in various functionality of this system, such as part of a release mechanism for disconnecting the uphole portion 150 from the downhole portion 160. A shear member is a sacrificial member designed to fail above a threshold level of force. Shear members are typically sheared in response to an applied tensile load, but could be alternatively configured to fail in response to an applied torque. The tensile force and/or torque may be applied to or by the mandrel or by the work string, for example. Generally, shear members are used to prevent some function until the shear member has first been failed. In the case of the connector 140, shear members may be used to enable operation of the release mechanism, as also described below.
FIG. 3B is a detail view of the connector 140 taken at section “3B” of FIG. 3A illustrating example features of the releasable connection mechanism according to one or more embodiments. The connector 140 includes a ring housing 164 positioned about the mandrel 142. A ramped surface 165 at the end of the ring housing 164 initially engages a corresponding ramped surface 145 on an abutting edge of the collet 144, to urge or otherwise retains the collet 144 radially outwardly, thereby restricting movement of the collet 144 radially inwardly. A shear member, such as a shear ring 166, is positioned between the mandrel 142 and the ring housing 164 and prevents, up to a certain threshold force, axial movement between mandrel 142 and the ring housing 164. Through any of a variety of mechanisms such as mechanical or hydraulic actuators within the work string or the connector itself, the mandrel 142 may be actuated to apply an axial force to the ring housing 164, in excess of a threshold axial force, to shear the shear ring 166 and thereby enable the ring housing 164 to move axially with respect to the mandrel 142. With the ring housing 164 moved downwardly, the collet 144 then has clearance to move radially inwardly and disconnect the work string, via the uphole portion 150 of the connector 140 in FIG. 3A from the lower completion string 130, via the downhole portion 160 of the connector 140.
A “pull to release” operation is one way a connector may be configured to disconnect, to release the work string 114 from the lower completion string 130. The release operation described in FIG. 3B is an example of a pull to release mechanism wherein a tensile load is applied to shear one or more shear members before the work string 114 is pulled upward to fully disconnect. However, a pull to release is not limited to the specific structure in FIG. 3B. An alternative example is having one or more shear members (e.g. between the mandrel 142 and downhole portion 160 of the connector 140) configured to support the weight of the lower completion string 130, and release by pulling up on the work string 114 with some threshold level of force required to fail the shear member(s). A pull to release operation is desirable in that it may be performed with a relatively simple motion by manipulation of the work string, mandrel, or other axially-movable member.
An alternative, “rotate to release” operation is also enabled by the example connector in FIGS. 3A and 3B. A rotate to release operation generally involves rotating some member relative to another in order to release the work string 114 from the lower completion string 130. Specifically in FIGS. 3A and 3B, the work string 114 may be rotated to unthread the teeth on the outer engagement structure 152 on the collet 144 from the threads on the inner engagement structure 162 of the connector's downhole portion 160. This rotation is to the left so as not to break apart tubing connections. The lower string is anchored by packers, so the mating teeth and threads will thread apart. A rotate to release operation is desirable in that it may also be performed with a relatively simple motion, e.g. by rotation of the work string 114.
A “soft release” mechanism is yet another type of release operation enabled by the example connector in FIGS. 3A and 3B. Referring again to FIG. 3A, an internal ball seat 148 is optionally defined in the mandrel bore 143 for capturing a drop ball 149 (see also FIG. 1) to block flow through the mandrel bore 143. Thereafter, pressure may be applied from surface to release the uphole portion 150 of the connector 140 from the downhole portion 160. In this example, the pressure will move a piston 154 to the left. This will lock the collet 144 in place and will not allow it to shoulder on the shear ring 166 anymore. Then, pulling the work string 114 from surface will allow the collet 144 to disengage with relatively little force. In the illustrated examples, all three of these release methods (pull to release, rotate to release, and soft release) are redundant to each other, in case one fails.
Having discussed a relatively complex connector with redundant release mechanisms, it should be appreciated that alternate connectors including simpler designs are also within the present scope. For example, an alternative and potentially simpler connector type may use a polished bore seal assembly (PSA) in combination with a polished bore receptacle (PBR). In comparison with the connector of FIGS. 3 and 3A, the PSA may have a collet only (besides the seals). The PSA may shoulder on something solid (not shearable) if implemented as a rotate to release type mechanism. If implemented as a shear to release mechanism, the connector may have shear screws or other shear member between mandrel and receptacle.
It should be understood, again, that the foregoing connector details and discussion are merely an example of a releasable connection that can support the weight of the lower completion string 130 when tripped into hole, and that has a mandrel that initially props open a valve and is removed from the valve upon disconnect. This connector may comprise any other suitable connector that is releasable but can support the weight of the lower completion string 130 when tripped into hole, and that has a mandrel that initially props open a valve closure element and can be removed from the valve upon disconnect.
In any of the various embodiments according to this disclosure, regardless of the specific connector or release mechanism chosen, a mandrel included with the connector may prop open a valve closure element of a valve connected below the connector. Upon release, the mandrel is removed from the valve along with the work string and portion of the connector above the valve, leaving the valve downhole with the lower completion string and allowing the valve closure element to close. The valve is thereby used to fluidically isolate the lower completion string from the wellbore above the valve after the work string is retrieved. The valve serves as a fluid loss device in that aspect, to prevent fluid loss downhole, which may avoid the need for a fluid loss control material downhole, such as marbles or calcium carbonate (CaCO3), which materials are generally understood in the art apart from the specific teachings of this disclosure. A further aspect is that the valve can later be reopened from the surface, such as by application of fluid pressure downhole without the need for intervention via coil tubing or wireline to reopen the valve. In examples discussed herein, the valve is a flapper-style valve, and the closure element is a flapper pivotally coupled to the valve body. However, any type of valve having a moveable closure element that can be propped open by the mandrel may be used.
FIG. 4 is an enlarged, detailed view of an embodiment of the flapper valve 180 as connected downhole of the connector 140 of FIGS. 2 and 3. For ease of illustration, the flapper valve 180 is oriented ninety degrees counter-clockwise in FIG. 4 with respect to its orientation in FIG. 2, corresponding with the orientation of the flapper valve 180 when positioned in a horizontal, lateral section as described in FIG. 1. The flapper valve 180 includes a valve bore 182 in fluid communication with the mandrel bore 143, a valve seat 183, and a flapper 184. The flapper 184 is an example of a valve closure element that is pivotable between an open position as shown in FIG. 4, allowing flow through the valve bore 182, and a closed position against the valve seat 183, that closes flow through the valve bore 182. The flapper valve 180 in this example pivots upwardly to open and downwardly to close. The flapper 184 is in the open position in FIG. 4 but is biased toward the closed position by a flapper close spring 181. With the flapper valve 180 connected below the connector 140, the mandrel 142 props the flapper 184 open against the biasing action of the flapper close spring 181. Propping the flapper 184 open while the work string is connected allows fluids such as stimulation treatments to be supplied downhole through the work string into the lower completion string, and formation fluids to be produced from the lower completion string and up through the work string to surface. When the connector 140 is disconnected and the mandrel 142 is removed, the flapper 184 is pivotable to a closed position, such as illustrated in FIG. 5, to isolate the wellbore below the flapper valve 180 from the rest of the wellbore above it.
FIG. 5 is a detailed view of the flapper valve 180 of FIG. 4, with the flapper 184 pivoted to the closed position against the valve seat 183 after the work string has been retrieved. The closed flapper valve 180 fluidically isolates the lower completion string 130 from the wellbore 106 above the lower completion string 130. The flapper valve 180 generally operates as a check valve that primarily blocks flow in one direction, which in this case is to block the flow of fluid above the closed flapper 184 from flowing downhole through the flapper valve 180. A certain amount of overbalance, i.e., pressure above flapper higher than pressure below the flapper, may be intentionally applied to prevent production fluids from flowing uphole until the well is ready.
Still referring to FIG. 5, the flapper valve 180 further includes a flapper remote reopening mechanism for remotely urging the flapper back to an open position, at some later point in time after the work string has been retrieved to surface, such as after a final completion is landed. In particular, the flapper 184 may be reopened by application of a threshold fluid pressure downhole. The remote reopening mechanism is remote in that it allows the flapper valve 180 to be reopened after the work string has been retrieved, and without necessarily tripping another tool such as a wireline or coiled tubing downhole. The remote reopening mechanism in this embodiment includes a flapper actuator 186 disposed inside the lower completion string 130 below the valve seat 183. The flapper actuator 186 may be comprise a sleeve or partial sleeve that does not significantly impede fluid flow when the flapper valve 180 is opened. The flapper actuator 186 is axially moveable from a retracted position (FIG. 5) to an extended position (FIG. 6) past the valve seat 183 to urge the flapper 184 from the closed position (FIG. 5) to the open position (FIG. 6). The remote reopening mechanism further includes an actuator spring 190 that biases the flapper actuator toward the extended position and one or more shear members 192, such as shear screws, that retain the flapper actuator in the retracted position against the biasing action of the actuator spring 190. The one or more shear members 192 are shearable in response to fluid pressure applied to the closed flapper valve 180, upon which the flapper actuator 186 is urged to the extended position to open the flapper 184. The particular fluid-responsive mechanism employed in this example uses a plurality of locking balls 193 initially locking the flapper actuator 186 with the flapper seat 183. When the flapper 184 is closed and pressure is applied, the shear members 192 shear and a piston embodied here as a sleeve 194 then moves to the right. This positions a recess or groove 195 above the locking balls 193 and allows them to move outwards to release the flapper actuator 186. This is but one example.
Any other fluid-responsive release mechanism for releasing a flapper actuator is considered within the scope of this disclosure. For example, in an alternate embodiment, locking balls might be omitted and shear members may be used to hold a flapper actuator in place to resist movement toward the extended position. Fluid pressure may be applied downhole until the shear members fail, thereby releasing the flapper actuator to move toward the extended position. For example, the flapper actuator may be provided with sufficient travel to move slightly downward axially (i.e. further away from the extended position) in response to the fluid pressure, at which point the pressure may be released so the flapper actuator is free to move in the opposite direction to the extended position.
FIG. 6 is a detailed view of the flapper valve 180 after the flapper actuator 186 has been moved to the extended position to reopen the flapper 184. In particular, shear members 192 have been sheared, and the sleeve 194 is moved to the right so that the balls 193 have moved outwardly into the recess or groove 195. The actuator spring 190 has a limited amount of biasing force to overcome any pressure forces applied above the flapper 184 in order to reopen the flapper 184. Therefore, it may be necessary or useful to bleed off the fluid pressure applied to the closed flapper 184 from above until the biasing force provided by the actuator spring 190 are sufficient to overcome the fluid pressure to urge the flapper 184 from the closed position of FIG. 5 to the open position of FIG. 6. The force in the spring 190 can only shift the flapper actuator 186 below a certain limit of overbalance pressure across the flapper 184. Alternatively, a rupture disk (not shown) can be used so that when burst, pressure can equalize across flapper, allowing the prong to reopen the flapper 184. To confirm the flapper actuator 184 has shifted, an operator may attempt to inject fluid into the well. A pressure rise at the same rate as when the flapper 184 was closed indicates the prong 186 has not been shifted. Once it has been confirmed the prong 186 has shifted, the well may be ready for production.
Having discussed flapper valve embodiments by way of example, it should be recognized this disclosure is not limited to use of a flapper valve, nor to a one-way valve more generally. Alternative types of valves may be configured for use with a system, including bidirectional valves, such as a ball valve. FIG. 7 is a schematic diagram of a system with a generalized valve 200 and valve controller 210 wherein the mandrel 142 is operable both to disconnect from the lower completion string 130 and close the valve 200 upon disconnection. The valve 200 is generalized in FIG. 7 to encompass any of a variety of different valve types, including but not limited to a one-way valve, such as a flapper valve, or a two-way valve, such as a ball valve.
The valve controller 210 may be used to selectively open and close the valve 200 in response to the manipulation of the mandrel 142. For example, the valve 200 may comprise a flapper, and the valve controller 210 may comprise a pivot mechanism that allows the flapper to move between an open position and a closed position in relation to axial position of the mandrel 142. Alternatively, the valve 200 may comprise a ball valve, and the valve controller 210 may comprise a rotational mechanism to selectively open and close the ball valve by rotation or other manipulation of the mandrel. The mandrel 142 is operable to disconnect from the lower completion string 130 such as by axial, rotational, or other combination of mandrel movement. The mandrel 142 is also operatively coupled to the valve controller 210 to selectively close the valve 200 upon disconnection, either with the same mandrel movement or another mandrel movement. The bidirectional valve 200 may be run into the well in an opened position, such as to land the completion string 130 and perform a service operation while the valve 200 is opened. The mandrel 142 may then be manipulated to close the bidirectional valve 200 when releasing the work string from the lower completion string 130. For example, the mandrel 142 could be rotated to close a ball valve when disconnected. Then, the bidirectional valve 200 can be remotely opened later, after the work string 114 has been retrieved to surface, such as through application of a pressure sequence.
Having set forth the various features of the connector and valve and how they cooperate, it can be seen that the principles of this disclosure now make it possible for a lower completion system to be deployed and isolated in a single trip. In particular, the lower completion string can be deployed on a work string, landed downhole, with the valve in an open position, so that service operations can be performed by the work string. The service operations may involve the delivery of fluids to or from the lower completion string. Then, in the same trip, the valve may be closed upon removal of the work string and the mandrel to isolate the wellbore below the valve. This enables a variety of wellbore operations to be performed in a single trip, without a subsequent trip with coiled tubing, wireline, or another work string to close or reopen the valve.
In various wellbore services, tripping the work string downhole to land the lower completion string with the valve initially open facilitates the delivery of fluids while performing the service. In one example application, the lower completion string comprises tools for stimulating the formation via delivery of stimulation fluids such as a proppant-laden fracturing fluid or an acidizing treatment downhole. In the example of a flapper valve, the flapper may be propped open by the mandrel when tripping downhole. The work string may be used, among other things, to deliver the stimulation fluids through the open valve and perform other functions used during fracturing and other stimulation services. In another example application, the lower completion string comprises an ICD used to help to preferentially produce certain fluids like oil over other fluids like entrapped water out of the formation. The work string may be used, among other things, to apply fluid pressure down through the open flapper valve to activate certain tools or processes, such as setting a packer.
After performing the wellbore services, the valve may be automatically closed upon manipulation of the mandrel to remove the work string, to isolate the formation and prevent unwanted migration of fluids. Having the valve close upon removal of the mandrel facilitates isolating the formation to prevent unwanted migration of fluids uphole and/or downhole through the closed valve. A closed flapper valve, for example, may prevent the flow of fluids downhole past the flapper valve. The closed flapper valve may also have some capacity to prevent unwanted flow of fluids uphole via flapper close spring, although pressure may be applied above the closed flapper valve (but below the threshold required to trigger the remote reopening mechanism) to supplement the action of the flapper close spring and help maintain the flapper in the closed position. In the case of a two-way valve, such as a ball valve, the valve may limit the migration of fluids uphole and downhole, without needing to apply pressure above the closed ball valve.
The systems and methods may include any of the various features of the systems and methods disclosed herein, including one or more of the following statements.
Statement 1. A deployment and isolation system, comprising a connector for releasably connecting a work string with a lower completion string to deploy the lower completion string into a well, the connector including a mandrel operable to selectively disconnect the work string from the lower completion string; a flapper valve coupled to the lower completion string and having a valve bore and a flapper initially propped open by an end of the mandrel while the flapper valve is coupled to the connector; and wherein the mandrel is operable both to disconnect from the lower completion string and to remove the mandrel from the flapper valve for the flapper to close upon disconnection.
Statement 2. The deployment and isolation system of statement 1, further comprising a valve remote reopening mechanism for remotely urging the flapper back to an open position in response to application of a threshold fluid pressure.
Statement 3. The deployment and isolation system of statement 2, wherein the valve remote reopening mechanism further comprises an actuator moveable from a retracted position to an extended position to urge the flapper from a closed position to an open position; a spring biasing the actuator toward the extended position; and one or more shear members for initially holding the actuator in the retracted position with the spring energized, the one or more shear members shearable in response to fluid pressure applied to the flapper in the closed position.
Statement 4. The deployment and isolation system of statement 1, wherein the lower completion string comprises a frac string configured for delivering a stimulation fluid downhole through the flapper valve to one or more formation zones to be stimulated.
Statement 5. The deployment and isolation system of statement 1, wherein the lower completion string comprises an inflow control device for controlling the flow of a plurality of formation fluids into the lower completion string and uphole through the flapper valve.
Statement 6. The deployment and isolation system of statement 1, further comprising a soft-release mechanism including an internal ball seat in a bore of the mandrel configured for capturing a drop ball to block flow through the mandrel bore, and a sleeve shiftable in response to fluid pressure applied above the captured drop ball.
Statement 7. The deployment and isolation system of statement 1, further comprising a pull-to-release mechanism in the connector for disconnecting the work string from the lower completion in response to an above-threshold tensile load.
Statement 8. The deployment and isolation system of statement 1, further comprising a rotate-to-release mechanism in the connector for disconnecting from the lower completion string upon rotation of the work string.
Statement 9. A deployment and isolation system, comprising a connector for releasably deploying a lower completion string into a well on a work string, the connector including a mandrel operable to selectively disconnect the work string from the lower completion string; and a valve coupled to the lower completion string and having a valve closure element initially open while the work string is connected with the lower completion string, wherein the mandrel is operable to disconnect from the lower completion string and close the valve closure element upon disconnecting.
Statement 10. The deployment and isolation system of statement 9, wherein the valve comprises one or both of a flapper valve and a ball valve, and a valve controller operable by the mandrel to selectively open or close the valve.
Statement 11. A method of servicing and isolating a well in a single trip, comprising deploying a lower completion string with a flapper valve into a well on a work string, with a flapper of the flapper valve propped open by a mandrel on a connector; flowing a fluid through the mandrel and propped-open flapper; and operating the mandrel to disconnect and retrieve the work string from the lower completion string with the flapper valve remaining downhole, thereby removing the mandrel from the flapper valve to allow the flapper to close.
Statement 12. The method of statement 11, wherein the step of flowing a fluid comprises delivering a stimulation fluid downhole through the mandrel and propped-open flapper to the lower completion string to stimulate a formation zone.
Statement 13. The method of statement 11, wherein the lower completion string comprises an inflow control device and the step of flowing a fluid comprises receiving a formation fluid separated through the inflow control device.
Statement 14. The method of statement 11, further comprising landing a final completion; and subsequently applying a fluid pressure downhole to activate a valve remote reopening mechanism to urge the flapper back to an open position.
Statement 15. The method of statement 14, wherein activating the valve reopening mechanism comprises applying the fluid pressure to the closed flapper to shear a shear member; releasing an actuator in response to shearing the shear member; and biasing the released actuator from a retracted position to an extended position to urge the flapper from a closed position to an open position.
Statement 16. The method of statement 15, further comprising subsequently bleeding off the fluid pressure to the closed flapper until the biasing of the released actuator overcomes the fluid pressure to urge the flapper from the closed position to the open position.
Statement 17. The method of statement 11, wherein flowing a fluid through the mandrel and propped-open flapper comprises delivering a stimulation fluid downhole through the flapper valve to one or more formation zones to be stimulated.
Statement 18. The method of statement 11, wherein flowing a fluid through the mandrel and propped-open flapper comprises passing formation fluids through an inflow control device in the lower completion string and uphole through the flapper valve.
Statement 19. The method of statement 11, wherein operating the mandrel to disconnect and retrieve the work string from the lower completion string comprises capturing a drop ball to block flow through a bore of the mandrel; applying a fluid pressure above the captured drop ball; and shifting a sleeve in response to the applied fluid pressure.
Statement 20. The method of statement 11, wherein operating the mandrel to disconnect and retrieve the work string from the lower completion string comprises a pull-to-release mechanism, a rotate-to-release mechanism, a soft-release mechanism, or combination thereof.
It should be understood that, although individual examples may be discussed herein, the present disclosure covers all combinations of the disclosed examples, including, without limitation, the different component combinations, method step combinations, and properties of the system.
The compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods may also “consist essentially of” or “consist of” the various components and steps. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces.
Therefore, the present examples are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular examples disclosed above are illustrative only, and may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Although individual examples are discussed, the disclosure covers all combinations of all of the examples. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. It is therefore evident that the particular illustrative examples disclosed above may be altered or modified and all such variations are considered within the scope and spirit of those examples. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.

Claims

What is claimed is:

1. A deployment and isolation system, comprising:

a connector for releasably connecting a work string with a lower completion string to deploy the lower completion string into a well, the connector including a mandrel operable to selectively disconnect the work string from the lower completion string;

a flapper valve coupled to the lower completion string and having a valve bore and a flapper initially propped open by an end of the mandrel while the flapper valve is coupled to the connector; and

wherein the mandrel is operable both to disconnect from the lower completion string and to remove the mandrel from the flapper valve for the flapper to close upon disconnection.

2. The deployment and isolation system, further comprising:

a valve remote reopening mechanism for remotely urging the flapper back to an open position in response to application of a threshold fluid pressure.

3. The deployment and isolation system of claim 2, wherein the valve remote reopening mechanism further comprises:

an actuator moveable from a retracted position to an extended position to urge the flapper from a closed position to an open position;

a spring biasing the actuator toward the extended position; and

one or more shear members for initially holding the actuator in the retracted position with the spring energized, the one or more shear members shearable in response to fluid pressure applied to the flapper in the closed position.

4. The deployment and isolation system of claim 1, wherein the lower completion string comprises a frac string configured for delivering a stimulation fluid downhole through the flapper valve to one or more formation zones to be stimulated.

5. The deployment and isolation system of claim 1, wherein the lower completion string comprises an inflow control device for controlling the flow of a plurality of formation fluids into the lower completion string and uphole through the flapper valve.

6. The deployment and isolation system of claim 1, further comprising:

a soft-release mechanism including an internal ball seat in a bore of the mandrel configured for capturing a drop ball to block flow through the mandrel bore, and a sleeve shiftable in response to fluid pressure applied above the captured drop ball.

7. The deployment and isolation system of claim 1, further comprising:

a pull-to-release mechanism in the connector for disconnecting the work string from the lower completion in response to an above-threshold tensile load.

8. The deployment and isolation system of claim 1, further comprising:

a rotate-to-release mechanism in the connector for disconnecting from the lower completion string upon rotation of the work string.

9. A deployment and isolation system, comprising:

a connector for releasably deploying a lower completion string into a well on a work string, the connector including a mandrel operable to selectively disconnect the work string from the lower completion string; and

a valve coupled to the lower completion string and having a valve closure element initially open while the work string is connected with the lower completion string, wherein the mandrel is operable to disconnect from the lower completion string and close the valve closure element upon disconnecting.

10. The deployment and isolation system of claim 9, wherein the valve comprises one or both of a flapper valve and a ball valve, and a valve controller operable by the mandrel to selectively open or close the valve.

11. A method of servicing and isolating a well in a single trip, comprising:

deploying a lower completion string with a flapper valve into a well on a work string, with a flapper of the flapper valve propped open by a mandrel on a connector;

flowing a fluid through the mandrel and propped-open flapper; and

operating the mandrel to disconnect and retrieve the work string from the lower completion string with the flapper valve remaining downhole, thereby removing the mandrel from the flapper valve to allow the flapper to close.

12. The method of claim 11, wherein the step of flowing a fluid comprises delivering a stimulation fluid downhole through the mandrel and propped-open flapper to the lower completion string to stimulate a formation zone.

13. The method of claim 11, wherein the lower completion string comprises an inflow control device and the step of flowing a fluid comprises receiving a formation fluid separated through the inflow control device.

14. The method of claim 11, further comprising:

landing a final completion; and

subsequently applying a fluid pressure downhole to activate a valve remote reopening mechanism to urge the flapper back to an open position.

15. The method of claim 14, wherein activating the valve reopening mechanism comprises:

applying the fluid pressure to the closed flapper to shear a shear member;

releasing an actuator in response to shearing the shear member; and

biasing the released actuator from a retracted position to an extended position to urge the flapper from a closed position to an open position.

16. The method of claim 15, further comprising:

subsequently bleeding off the fluid pressure to the closed flapper until the biasing of the released actuator overcomes the fluid pressure to urge the flapper from the closed position to the open position.

17. The method of claim 11, wherein flowing a fluid through the mandrel and propped-open flapper comprises delivering a stimulation fluid downhole through the flapper valve to one or more formation zones to be stimulated.

18. The method of claim 11, wherein flowing a fluid through the mandrel and propped-open flapper comprises passing formation fluids through an inflow control device in the lower completion string and uphole through the flapper valve.

19. The method of claim 11, wherein operating the mandrel to disconnect and retrieve the work string from the lower completion string comprises:

capturing a drop ball to block flow through a bore of the mandrel;

applying a fluid pressure above the captured drop ball; and

shifting a sleeve in response to the applied fluid pressure.

20. The method of claim 11, wherein operating the mandrel to disconnect and retrieve the work string from the lower completion string comprises a pull-to-release mechanism, a rotate-to-release mechanism, a soft-release mechanism, or combination thereof.