The present disclosure generally relates to multi-stage completions and downhole connectors for use in oil and gas wells, and more particularly, to systems and methods for connecting multi-stage completions, for example, including, but not limited to, multi-stage completions including optical fibers.
Many types of wells, e.g., oil and gas wells, are completed in multiple stages. For example, a lower stage of the completion, or lower completion assembly, is moved downhole on a running string. After deployment of the lower completion assembly at a desired location in the wellbore, an upper stage of the completion, or upper completion assembly, is deployed downhole and engaged with the lower completion assembly.
In many applications, it is desirable to instrument the lower completion with electrical or optical sensors or to provide for transmission of fluids to devices in the lower completion. For example, a fiber optic cable can be placed in the annulus between the screen and the open or cased hole. To enable communication of signals between the sensor in the lower completion and the surface or seabed, a wet-mate connection is needed between the upper and lower completion equipment.
In some configurations, a downhole completion system includes an upper completion stage comprising at least one first communication line connector; a lower completion stage comprising at least one second communication line connector, the first communication line connector configured to couple to the second communication line connector; and an orientation device configured to help determine and/or control orientation of the second communication line connector relative to a well during or prior to installation.
The lower completion stage can include two second communication line connectors. The orientation device can be configured to help center the second communication line connectors about the top of the well. The orientation device can be configured to help position the second communication line connector(s) at or centered about a top of a deviated or horizontal well during installation. In some configurations, the upper completion stage includes a stinger, the lower completion stage includes a receptacle, and the stinger is configured to engage the receptacle. The stinger can include the at least one first communication line connector, the receptacle can include the at least one second communication line connector, and engagement of the stinger with the receptacle can engage the first communication line connector with the second communication line connector.
The orientation device can include accelerometers and/or gyrometers configured to provide data to determine orientation of the second communication line connector. The orientation device can further include a telemetry module configured to transmit data from the accelerometers and/or gyrometers to the surface to determine orientation of the second communication line connector. The downhole completion system can include a service string comprising the orientation device, the service string coupled to the lower completion stage for deployment of the lower completion stage in a well.
The orientation device can include an index casing coupling incorporated into a casing string deployed in a well, the index casing coupling comprising an orientation feature. The downhole completion system can further include a service tool including an orientation measurement tool and an orientation key. The orientation measurement tool is configured to provide data to determine the orientation of the index casing coupling when the service tool is run in hole in the casing string and the orientation key of the service tool is engaged with the orientation feature of the index casing coupling.
In some configurations, a method of forming a completion in a wellbore includes deploying a lower completion stage in a wellbore, the lower completion stage comprising at least one first communication line connector; determining an orientation of the at least one first communication line connector with respect to the wellbore; deploying an upper completion stage in the wellbore, the upper completion stage comprising at least one second communication line connector; and coupling the first and second communication line connectors.
Determining an orientation of the at least one first communication line connector can include transmitting data from an orientation device located on or connected to the lower completion to the surface via an electrical cable or wireless telemetry. In some configurations, the method further includes rotating the lower completion if needed to orient the at least one first communication line connector in a desired orientation or position. The wellbore can be a deviated or horizontal wellbore. In such configurations, the desired orientation or position can be at, near, or centered on or about a top of the wellbore.
In some configurations, a method of forming a completion in a wellbore includes: incorporating a casing orientation device into a casing string; deploying the casing string in a wellbore; running a service tool in hole within the casing string; measuring an orientation of the casing orientation device using an orientation measurement tool of the service tool; deploying a lower completion stage in the wellbore such that one or more first communication line connectors of the lower completion stage are positioned in a desired orientation based on the orientation of the casing orientation device measured by the service tool; deploying an upper completion stage in the wellbore, the upper completion stage comprising at least one second communication line connector; and coupling the first and second communication line connectors.
The casing orientation device can include an orientation feature, the service tool can include a corresponding orientation features, and running the service tool in hole can include engaging the orientation feature of the service tool with the orientation feature of the casing orientation device. Measuring an orientation of the casing orientation device can include determining an orientation of the orientation feature relative to a desired orientation of the one or more first communication line connectors when deployed in the wellbore. The method can further include, prior to deploying the lower completion stage in the wellbore, coupling an orientation landing tool comprising an orientation feature to the lower completion stage, and orienting the orientation landing tool and lower completion stage relative to each other such that when the orientation feature of the orientation landing tool is positioned at the orientation of the orientation feature of the casing orientation device as measured by the service tool, the one or more first communication line connectors are positioned at the desired orientation. The wellbore can be a deviated or horizontal wellbore and the desired orientation or position can be at, near, or centered on or about a top of the wellbore.
Certain embodiments, features, aspects, and advantages of the disclosure will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements. It should be understood that the accompanying figures illustrate the various implementations described herein and are not meant to limit the scope of various technologies described herein.
In the following description, numerous details are set forth to provide an understanding of some embodiments of the present disclosure. It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the disclosure. These are, of course, merely examples and are not intended to be limiting. However, it will be understood by those of ordinary skill in the art that the system and/or methodology may be practiced without these details and that numerous variations or modifications from the described embodiments are possible. This description is not to be taken in a limiting sense, but rather made merely for the purpose of describing general principles of the implementations. The scope of the described implementations should be ascertained with reference to the issued claims.
As used herein, the terms “connect”, “connection”, “connected”, “in connection with”, and “connecting” are used to mean “in direct connection with” or “in connection with via one or more elements”; and the term “set” is used to mean “one element” or “more than one element”. Further, the terms “couple”, “coupling”, “coupled”, “coupled together”, and “coupled with” are used to mean “directly coupled together” or “coupled together via one or more elements”. As used herein, the terms “up” and “down”; “upper” and “lower”; “top” and “bottom”; and other like terms indicating relative positions to a given point or element are utilized to more clearly describe some elements. Commonly, these terms relate to a reference point at the surface from which drilling operations are initiated as being the top point and the total depth being the lowest point, wherein the well (e.g., wellbore, borehole) is vertical, horizontal or slanted relative to the surface.
Many types of wells, e.g., oil and gas wells, are completed in multiple stages. For example, a lower stage of the completion, or lower completion assembly, is moved downhole on a running string. After deployment of the lower completion assembly at a desired location in the wellbore, an upper stage of the completion, or upper completion assembly, is deployed downhole and engaged with the lower completion assembly.
Many well completions incorporate one or more control lines, such as optical, electrical, and/or hydraulic control lines, to carry signals to or from components of the downhole completion. For example, in many applications, it is desirable to instrument the lower completion with hydraulic, electrical, or optical sensors or to provide for transmission of fluids to devices in the lower completion. To enable communication of signals between the sensor(s) in the lower completion and the surface or seabed, a wet-mate connection is needed between the upper and lower completion equipment. The completion of wells in two or more stages, however, can create difficulties in forming dependable and repeatable control line connections between adjacent completion assemblies.
The present disclosure provides systems and methods for connecting and providing communication between an upper completion and a lower completion. In some configurations, the present disclosure provides various systems and methods for debris prevention, mitigation, and/or management. As used herein, “lower” can refer to a first or lead equipment/assembly moved downhole. “Upper” can refer to a second or later equipment/assembly moved downhole into engagement with the lower unit. In a horizontal wellbore, for example, the lower equipment/assembly is run downhole first prior to the upper equipment/assembly.
Such systems and methods allow for various types of connections and/or communication between the upper and lower completion, for example, control line communication and/or connection, fiber optic communication and/or connection, electrical connection and/or communication, etc. For example, some fiber optic electric wet mate systems and methods according to the present disclosure advantageously establish a fiber optic connection and electrical connection, and allow for fiber optic and electrical signal communication.
Systems and methods according to the present disclosure can advantageously allow for monitoring, e.g. continuous real time monitoring, or temperature (or other data) along the entire length of the upper and lower completion, for example, using an optical fiber deployed or housed within a control line. Additionally or alternatively, systems and methods according to the present disclosure can advantageously allow for water injection and/or hydraulic communication to or with the lower completion. In some configurations, systems and methods according to the present disclosure advantageously allow for transmission of signals, e.g., electrical and/or hydraulic signals, to actuate various devices along the lower completion string, such as flow control devices and/or isolation valves. Additionally or alternatively, such signals, e.g., electrical and/or hydraulic signals, can be used to actuate setting sequence(s) for packer(s).
In some configurations, systems and methods according to the present disclosure allow for deploying and connecting a fiber optic sensor network in a two-stage completion. In some configurations, the lower completion can be run with fiber, then the upper completion can be run with fiber, and the fiber of the upper completion and fiber of the lower completion can be mated via a connector. This can advantageously save time during deployment and installation as the fiber does not need to be pumped from the surface once a wetmate connection has been established. Such a configuration can also allow for use in wells in which fiber cannot be pumped, for example, in wells with subsea trees. Once the connection is established, a continuous optical path is established from a surface location to the bottom of an open hole formation. In some configurations, systems and methods according to the present disclosure also allow for connecting other types of control lines and/or connectors, such as electrical control lines or connectors or fluid control lines or connectors. Different types of control lines and/or connectors, including fiber optic, electrical, and/or hydraulic control lines and/or connections, can be included in various combinations. The connections may be established, broken, and reestablished repeatedly.
Connection systems and methods according to the present disclosure may be used for land applications, offshore platform applications, or subsea deployments in a variety of environments and with a variety of downhole components. The systems and methods can be used to connect a variety of downhole control lines, including communication lines, power lines, electrical lines, fiber optic lines, hydraulic conduits, fluid communication lines, and other control lines. The connections can allow for the deployment of sensors, e.g., fiber optic sensors, in sand control components, perforating components, formation fracturing components, flow control components, or other components used in various well operations including well drilling operations, completion operations, maintenance operations, and/or production operations.
The upper and lower completion assemblies can include a variety of components and assemblies for multistage well operations, including completion assemblies, drilling assemblies, well testing assemblies, well intervention assemblies, production assemblies, and other assemblies used in various well operations. The upper and lower assemblies can include a variety of components depending on the application, including tubing, casing 10, liner hangers, formation isolation valves, safety valves, other well flow/control valves, perforating and other formation fracturing tools, well sealing elements, e.g., packers, polish bore receptacles, sand control components, e.g., sand screens and gravel packing tools, artificial lift mechanisms, e.g., electric submersible pumps or other pumps/gas lift valves and related accessories, drilling tools, bottom hole assemblies, diverter tools, running tools and other downhole components.
Establishing a connection between the upper connectors 212 and lower connectors 112 downhole is often challenging due to debris particles, which can inhibit proper mating of the connectors and/or can damage the connector(s). In deviated or horizontal wells, debris can be problematic particularly based on the location of the connectors relative to the bottom of the tubing, where the debris is likely to accumulate due to gravity. The present disclosure provides systems and methods for determining and controlling the orientation of the connectors downhole to advantageously reduce the likelihood of debris particles compromising the mating of the connectors. The ability to determine the orientation of the connector(s) allows the completion string to be rotated so that the connector(s) are oriented and/or positioned in a desired orientation and/or position. For example, the connector(s) may be oriented and centered on or about the top of the hole, for example as shown in
In deviated wells, the connectors 112, 212 could become oriented to sit at or near the bottom of the hole, where debris would likely settle around the connector(s) and potentially prevent signal transmission. To avoid such an orientation and debris accumulation, an orientation device allows for determination of the location or orientation of the connector(s) relative to the hole. The connector(s) can then be installed at and centered on the top of the well, for example as shown in
During deployment, once the running assembly 300 and lower completion 100 have reached the desired depth, the orientation of the connector(s) 112 is read. In other words, data indicating the orientation of the connector(s) 112 is transmitted to the surface. As the running assembly 300 is coupled to the lower completion 100 in a known relative orientation, the orientation device 320 of the running assembly 300 can provide information regarding the orientation of the connector(s) of the lower completion 100. If the connector(s) 112 are in a risky or less desired orientation or position, for example as shown in
In some configurations, a connector orientation system 250 is integrated into or coupled to a service string 255, for example as shown in
For use, the service string 255 and connector orientation system 250 are coupled with the lower completion 100 and run in hole to the desired depth. Data from the accelerometers and/or gyrometers is transmitted to the surface by the telemetry module 254 to determine the orientation of the lower connectors 112. If needed, the service string 255 and lower completion 100 are rotated to orient the connectors 112 to a desired orientation or position, e.g., at or centered about the top of the casing.
As an alternative system and method for connector orientation control, a casing orientation control device and method can be used. For example,
As shown in
The measurement tool 382 measures the orientation of the orientation key 384 and therefore the orientation slot 360. For example, the transverse cross-section of
The orientation landing tool and lower completion 100 are then run in hole within the casing 10 string including the index casing coupling 350, as schematically shown in
Once the lower completion 100 is in place, the anchoring device 130 can be set. To verify the anchoring device 130 is set, the operator can provide overpull and release the locating dogs 386. In configurations including a locking expansion joint 390, the locking expansion joint 390 extends to allow overpull and set down weight to be applied to the anchoring device 130, as schematically shown in
Language of degree used herein, such as the terms “approximately,” “about,” “generally,” and “substantially” as used herein represent a value, amount, or characteristic close to the stated value, amount, or characteristic that still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” “generally,” and “substantially” may refer to an amount that is within less than 10% of, within less than 5% of, within less than 1% of, within less than 0.1% of, and/or within less than 0.01% of the stated amount. As another example, in certain embodiments, the terms “generally parallel” and “substantially parallel” or “generally perpendicular” and “substantially perpendicular” refer to a value, amount, or characteristic that departs from exactly parallel or perpendicular, respectively, by less than or equal to 15 degrees, 10 degrees, 5 degrees, 3 degrees, 1 degree, or 0.1 degree.
Although a few embodiments of the disclosure have been described in detail above, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the teachings of this disclosure. Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims. It is also contemplated that various combinations or sub-combinations of the specific features and aspects of the embodiments described may be made and still fall within the scope of the disclosure. It should be understood that various features and aspects of the disclosed embodiments can be combined with, or substituted for, one another in order to form varying modes of the embodiments of the disclosure. Thus, it is intended that the scope of the disclosure herein should not be limited by the particular embodiments described above.
Any and all applications for which a foreign or domestic priority claim is identified in the Application Data Sheet as filed with the present application are hereby incorporated by reference under 37 CFR 1.57. The present application claims priority benefit of U.S. Provisional Application No. 63/160,134, filed Mar. 12, 2021, the entirety of which is incorporated by reference herein and should be considered part of this specification.
Filing Document | Filing Date | Country | Kind |
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PCT/US2022/019952 | 3/11/2022 | WO |
Number | Date | Country | |
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63160134 | Mar 2021 | US |