Multi-Zone Single Trip Well Completion System
A well completion system having (i) a completion assembly; (ii) a service tool positioned within the completion assembly, wherein the service tool includes a substantially straight bore central passage from an upper end of the service tool to a lower end of the service tool; and (iii) a one-way valve positioned in an assembly annulus formed between the service tool and an inner surface of the completion assembly.
This application claims the benefit under 35 U.S.C. §119(e) of U.S. Provisional Application Ser. No. 61/865,206, filed Aug. 13, 2013, which is incorporated by reference herein in its entirety.
I. BACKGROUNDThe present invention relates to the field of completion assemblies for use in hydrocarbon producing wells. In particular embodiments, the invention provides a method and apparatus for completing and producing from multiple production zones, independently or in any combination. It is becoming increasingly desirable to economically complete and produce wells from different production zones at different stages in the process (and in differing combinations), while at the same time reducing the number of “trips” down the wellbore which are needed to carry out these operations. Thus, there is a continued need for improved multi-zone completion assemblies which combine simplicity, reliability, safety and economy, while also affording flexibility in use.
II. SUMMARY OF SELECTED EMBODIMENTS OF THE INVENTIONOne embodiment disclosed herein is well completion system having (i) a completion assembly; (ii) a service tool positioned within the completion assembly, wherein the service tool includes a substantially straight bore central passage from an upper end of the service tool to a lower end of the service tool; and (iii) a one-way valve positioned in an assembly annulus formed between the service tool and an inner surface of the completion assembly.
Another embodiment is a well completion system having a tubular completion assembly, including multiple production zones, where each production zone further comprising (i) a zonal isolation packer; (ii) a screen wrapped, closeable monitoring port; (iii) a closeable treating port below the monitoring port; and (iv) a screen wrapped, pressure activated valve below the treating port.
A further embodiment is a method of logging a wellbore having a completion system therein. The method includes the steps of (a) positioning a completion assembly in the wellbore, including a service tool within the completion assembly, wherein the service tool includes a substantially straight bore central passage; and (b) inserting a logging tool through the straight bore central passage and logging the wellbore at selected positions along the length of the straight bore central passage within and/or below the service tool.
Many additional embodiments will be apparent in the following description and claims and their omission from the above summary of selected embodiments should not be considered a limitation on the scope of the present invention.
One aspect of the present invention contemplates a well completion system having a completion assembly and a service tool positioned within the completion assembly. The service tool includes a substantially straight bore central passage from an upper end of the service tool to a lower end of the service tool. Additionally, a one-way valve is positioned in an assembly annulus formed between the service tool and an inner surface of the completion assembly.
As used in this disclosure, “up” means the direction along the wellbore toward the surface and “down” means in the direction toward the toe of the wellbore. Because the wellbore may often be deviated or horizontal, “up” or “down” should not be assumed to be in the vertical direction or to even have a vertical component. Likewise, describing a first tool component as “above” or “below” a second tool component means the first tool component is closer to or further from the surface, respectively, along the wellbore path (when the tool assembly is positioned in the wellbore) than the second tool component.
Viewing
The auto-locator 15 may be any conventional auto-location assembly which interacts with profiles on a service tool to positively identify the position of the service tool in the completion assembly 2. A preferred embodiment of the auto-locator serves to locate the service tool positions by using an inward facing indicating collet tied into an auto J indexing mechanism. This embodiment will include three basic positions: 1) the pick-up position which occurs when the collet is pulled to the top of its travel, 2) the set down position, which occurs when the J is at the bottom of its travel, and 3) the run through position which occurs when the J is in an intermediate position. The auto-locator is actuated by up and down movement of an auto-locater profile (on the service tool) through the auto-locater collet. The auto-locater collet moves to the pick-up position with upward movement through the collet, to the run through position. The “run through position” allows the auto-locator profile on the service tool to pass the through the auto-locator collet. The next upward movement shifts the collet back to the pick-up position, with the following downward movement placing the collet in the set down position. Repeated up and down movements of the profile through the collet will continue to cycle the collet from the set down to the run through positions. In the set down position, the profile is latched into the collet and supported to take set down loads to offset work string movement during treatments. The run through position allows the profile on the service tool to pass through the auto-locator collet with a snap indication. Normally, after performing the intended well treatment, a lockout sleeve locks out the indicating collet leaving a large ID. One example of an acceptable auto-locator is disclosed in U.S. Pat. No. 7,490,669 which is incorporated by reference herein in its entirety.
While the embodiment illustrated in the Figures has a single auto-locator collet near the top of the completion assembly and multiple auto-locator profiles on the service tool, this is merely one alternative. Other embodiments of the invention could have a single auto-locator profile on the service tool and multiple auto-locator collets in the completion assembly (e.g., an auto-locator in each zone of the completion assembly). Still further embodiments might position the auto-locator collet on the service tool and auto-locator profiles in different zones of the completion assembly. All such variations are within the scope of the present invention.
Non-rotational connector 19 is a conventional assembly that allows connection of tubular components without threads and relative rotation of the components. Non-rotational connectors enable more efficient makeup of the retrievable sealbore packer (and other components) and reduces failure risks associated with a long heavy assembly make-up in the rotary table. The completion assembly make up may be accomplished without assembly rotation and may be secured by rotating a retainer nut. Connector 19 incorporates a spline to ensure engagement and to allow locked rotation across the connector assembly after make-up.
The additional components of the completion assembly 2 seen in
The screen wrapped monitoring sleeves 20 are shown in more detail in
In one preferred embodiment, the monitoring sleeve 20 is a Type O sliding sleeve designed (i.e., downward movement to open the sleeve and upward movement to close the sleeve), which in a multi-zone completion system allows monitoring of a dead string while treating the zone by reading annulus pressure. Also, closing the sleeve prior to treating allows treatments to be performed in the squeeze position. This embodiment of the sleeve valve may include a high performance equalizing seal, which allows communication control between the tubing and annulus. An internal screen filtering section may be incorporated to prevent treating proppant from entering into the sleeve sealing areas and allows the valve to be opened and closed multiple times without loss of seal integrity. This preferred embodiment further includes an inside shifting profile which is approximately equal to the treating sleeve internal diameter in order to allow optimal ID clearances for service tool operations.
As used herein, the term “sleeve” may be used to indicate a sleeve assembly such as described above which includes a sleeve member which can selectively cover and uncover a port to allow fluid flow through the port. This sleeve assembly may also be referred to as a valve (e.g., a sliding sleeve valve) since the sleeve assembly functions to open and close a fluid flow passage.
The illustrated embodiment of treating sleeve 30 seen in
In general, the treating sleeve assembly provides an isolation sleeve which can be opened to provide treating ports for high pump rates and large volumes of proppant while minimizing erosion on the treating sleeve assembly, service tool, and casing. The length of the treating sleeve should permit it to be opened and remain opened while manipulating the service tool (e.g., upwards/downwards movement to establish the auto-locator set-down position). Too short of a sleeve length increases the possibility of a tool profile unintentionally engaging and moving the sleeve from its fully open position.
From the above description, it will be recognized that monitoring sleeve 20 and treating sleeve 30 operate on the “down-to-open”, “up-to-close” convention. While this is often preferred, other embodiments could operate under the opposite convention.
Although not specifically shown in the drawings, the completion assembly 2 may also contain one or more sections of centralizer blank pipe. These are essentially sections of pipe that are made up above the screen joint and provide annular clearance and volume space for proppant pumping operations. Centralizer blank pipe may also be used to adjust the spacing distance of the isolation packers that are positioned between sand control intervals.
The hydraulically activated shear subs 36 will operate to provide a release point for all components in the string below shear sub 36 when certain conditions occur. In a preferred embodiment, this shear sub contains a hydraulic release mechanism which is utilized to carry the full load of the assembly into the wellbore. This prevents the load from being carried by the shear joint shear screws, thereby allowing long, heavy assemblies to be run without fear of premature release. The hydraulic actuation feature is initiated by applying a sufficient tubing-to-annulus differential pressure. Once actuated, the load is relieved from the hydraulic locking mechanism and transferred to the shear screws. A preferred embodiment of the shear joint allows up to 24″ of travel prior to seal release. One example of such a hydraulically activated shear sub is seen in U.S. Pat. No. 7,490,669. The hydraulically activated shear subs 36 also allow for staged removal of packers and screen assemblies if needed.
The screen wrapped PAC valves 40 may be any number of conventional or future develop valves, whether sliding sleeve valves or other valve types. In a preferred embodiment, valves 40 comprise a screen joint incorporating a PAC valve with a lock out mechanism. The screen joints may be wire wrap (or mesh type) sand exclusion screens designed to be used in high-rate water packs (HRWP), fracturing and open-hole environments. These joints allow easy spacing for either short or long intervals within a multi-zone completions system. The screen joints may also be incorporated with a special high rib design to provide strength and optimize flow area under the screen wrap. The base pipe is preferably non-perforated with the PAC valve(s) positioned as needed. In this embodiment of the valves 40, actuation is initiated by first running a mechanical unlocking tool through the valve to unlock the sleeve, and then applying differential pressure from valve ID to OD. The mechanical unlocking tool may be a separate profile (i.e., a profile that will not shift the monitoring and treating sleeves) which is positioned on the service tool. Alternatively this separate profile may be positioned on a different production tool employed in later stages of production. Initial actuation pressure further activates the valves for opening while maintaining pressure integrity. Reducing the actuation pressure to equal the annular pressure then allows the valve to cycle to the full open position.
This PAC valve actuation method allows multiple valves to be used and opened in the same interval. These preferred valves provide complete isolation of the productive interval during all phases of completion operations; require no well intervention to be actuated for production operations; and provide a full open-flow path through the screen-base pipe assembly. As a contingency, the valves can be opened mechanically with wireline or colleted type shifting tools. In preferred embodiments, the valves 40 are of the type which unlocked mechanically and then may be hydraulically activated. Nevertheless, it is not necessary for all embodiments of valves 40 to be mechanically unlocked and then pressure activated. For example, the valves 40 could alternatively be purely mechanically activated (i.e., both unlocked and opened mechanically) or purely pressure activated, Although generally preferred, it may not be necessary in all embodiments for the valves to be “lockable.”
The structure and operation of lock/release mechanism 190 is shown in more detail in
To begin the process of unlocking lock/release mechanism 190, a conventional tool with opening collet (not shown) may be conveyed downhole to PAC valve 40 via coil tubing or another conventional means for mechanically manipulating tools within a wellbore. The opening tool will engage the profile 196 on locking sleeve 195 and apply sufficient downward force to fail shear pin 205B and move locking sleeve 195 downward (i.e., toward the right in the figures) until locking sleeve threads 208 engage the bottom sub threads 209 as suggested in
Next in the opening sequence, fluid pressure is applied to the central passage of valve 40. As suggested in
Now, when the pressure in the valve central passage is relieved and downward force from piston surface 184 is removed, spring 179 will tend to force lower piston 183 upward (leftward in
In the illustrated embodiment, testable isolation packer 46A is dual element packer with a self-contained setting tool having bi-directional slips. The setting tool is integrated between the two elements and is actuated with tubing pressure through the ID of the packer mandrel. The isolation packer contains a rupture disc which is actuated by applying pressure greater than the required packer setting pressure. Once the disc is ruptured, pressure is applied between the two elements of the packer and the casing ID giving a positive indication of packer setting. This packer may be retrieved by a straight upward pull by a conventional retrieval tool. While many other conventional or future developed packer systems could be utilized, one acceptable isolation packer is the ComPlete™ MST System Isolation Packer available from the Completion Services division of Superior Energy Services, LLC located in Houston, Tex. While the above described embodiment employs a “testable” isolation packer, it will be obvious that alternative embodiments could employ a non-testable type of packer. Likewise, many conventional in-string packers with bidirectional slips could also be employed.
Although
Below the lowest zone, completion assembly 2 comprises several further components. These include a sealbore sub 26, a hydraulic tubing release 50, a scrapper 54, a collet activator 58, a test assembly 64, and a fixed ball seat 70. Generally, the sealbore subs are internally honed, reduced inner diameter, sections of pipe that provide a seal with the reverse bypass tool (explained below) when the latter is positioned within the sealbore subs. However, the sealbore subs can also be utilized to isolate a treating sleeve in the event that concentrically run production seals are traversed across the section. The lower sealbore sub 26 seen in
Collet activator 58 is one example of an activating mechanism employed to activate a de-activated opening tool and is described in more detail below in reference to the opening tool on service tool 100. The test assembly 64 is a tubular sub on the end of completion assembly 2 which includes the breakable plate 68 positioned across the inner diameter to form a seal and allow fluid to be pressurized (for leak integrity testing purposes) above breakable plate 68. Test assembly 64 also includes a one-way valve 64 which allows fluid from the wellbore into the test assembly, but prevents the exiting of fluid and thereby allows pressurization to occur. In the illustrated embodiment, one-way valve 67 is a rubber bladder covering a series of apertures in the test assembly body. Higher pressure outside the test assembly tends to push the bladder aside and allow fluid inflow. Higher pressure inside the test assembly tends to press the bladder against the apertures and block fluid outflow. One example of such a valve is seen in
A second main component of the completion system is a service tool which will be inserted into completion assembly 2 to perform various tasks.
Viewing
Additional components positioned toward the lower end of service tool 100 are seen in
Also shown in the embodiment of
One example of reverse bypass valve 115 is seen in
There may be circumstances where very high pressures occur below the particular sealbore sub 26 being engaged by the circumferential seal 120 and such high pressures may be sufficient to force reverse bypass valve 115 to move upward. The embodiment of
The completion system will typically be initially assembled by making up the individual components forming a separate completion zone and as each successive zonal assembly is made up, the completion assembly is hung off the rig floor and pressure tested for integrity. The first or lowest zone will include the components seen in
Typically, as each zone of components is made up, the completion assembly thus far connected is filled with fluid and the assembly is tested for leaks with a low volume test pump; e.g., by pressuring up to 500 psi for 5 minutes. The final or uppermost completion zone assembly may include certain components located at the upper end of completion assembly 2; e.g., in the embodiment of
Next, service tool 100 will be made up, with components positioned on the lower end of service tool 100 first being connected as suggested by the embodiment of
After all pressure integrity testing has been completed, the completion system is made ready running into the formation area of the wellbore. This combine completion assembly and service tool being running to the wellbore may sometimes be referred to as the integrated completion assembly. The service tool is temporarily extended further into completion assembly 2 (i.e., by adding addition lengths of tubing) such that mule shoe 131 ruptures breakable seal plate 68 and opening tool profile 124 is brought into engagement with the activating mechanism (e.g., collet activator 58) in order to activate the opening tool profile such that it will now engage sleeves as it moves past. Service tool 100 is then positioned at its lowermost run in position within completion assembly 2 and sealbore packer setting tool 102 engages and locks into the top of completion assembly 2 as seen in
Typically, the straight central passage of the service tool 100 is open and unobstructed at the time the completion assembly is run into the wellbore. However, there may be specialized embodiments where the central passage of the service tool initially has some mechanism for closing or blocking the service tool's central passage during run-in and that mechanism is opened or removed before the start of operations with the completion assembly.
One aspect of the present invention is a method of washing out a the wellbore while running in the completion system 1. The well may contain debris from various earlier activities, including perforating the casing with perforating guns. The scrapper 54 on completion assembly 2 will tend to push such debris below the completion system as it is run downhole. However, it may often be advantageous to wash such debris completely out of the wellbore as the completion system is run in. This operation also acts to remove gas or liquid hydrocarbons from the wellbore prior to setting the packers. As seen in
This “reverse washing” process being performed as the completion system 1 is lowered to its final position in the wellbore allows a debris removing washing operation to be carried out with no addition use of other tools (i.e., additional trips down hole) or by any special positioning/repositioning of the completion system 1. Rather, this useful washing operation can be carried out simultaneously with positioning the completion system at its final depth. Nonlimiting examples of debris which may be removed using this technique include pill remnants, gun debris, and formation solids.
Another embodiment of the present invention is a method of logging a wellbore which has the completion system 1 positioned in the wellbore. This method employed before or after treatment. For example, logging might be performed prior to setting the packers in order to confirming the packer location. More typically, logging is performed after treating a zone. With the completion system 1 positioned at depth, a logging tool on an e-line may be run down the work string, through the service tool's straight bore central passage and to the desired depth in the formation. In certain circumstances, service tool 100 may be raised out of the zone which is being logged, but this re-positioning of service tool 100 is not always the case. It will be understood that the straight bore nature of service tool 100 allows logging without the necessity of removing service tool 100 from the wellbore. This may be distinguished from prior art completion system where obstructions in the service tool (e.g., cross-over valves) prevent the running of logging tools directly through the service tool.
After the completion of any desired logging operations and removal of the logging tool, the steps necessary to set the completion system 1 in place within the formation may be undertaken. As suggested in
The shear subs 36 are activated such that loads are now supported by their shear pins. Once all other pressure activated components change to their active state and desired pressure testing performed (for example, pressure testing of uppermost and lowermost packers), additional pressure may be applied to activate hydraulic tubing release 50 and have all components below it fall to the wellbore rathole. It will be understood that one immediate effect of this release is to remove the closed end of the completion assembly that had been formed by the ball lodged within ball seat 70. Successful release of hydraulic tubing release 50 may be confirmed at the surface by noting a pressure drop in circulating fluid.
Once the completion system is in place with the packers set and pressure tested, any number of completion (or other) operations may be carried out. Various conventional and/or future developed treating methods may be employed with completion system 1, including stimulating (e.g., acidizing), high rate water packing, frac packing, or gravel packing
While the above embodiments describe the use of the auto-locator to determine the position of the service string within the completion assembly, there may be instances where the auto-locator malfunctions, or the completion system is an alternative embodiment which does not incorporate an auto-locator. In these examples, the treating position of the service string may be determined “hydraulically” by first positioning the end of the service string below the anticipated zone treating depth and establishing forward circulation at a comparatively slow rate and low pressure (e.g., <400 psi). The service tool is then slowly raised at one foot intervals until returns stop and work string pressure increases. At this point, it may be presumed that the reverse bypass valve 115 has entered the first sealbore sub 26 in that zone, e.g., the sealbore sub 26 below the treating sleeve 30 in
It can also be understood from
When the treating operation has been completed in that zone, the service tool 100 is lowered sufficiently to place a closing tool profile beneath treating sleeve 30. Upon raising the closing tool profile, first treating sleeve 30 and ultimately monitoring sleeve 20 will be closed as the closing tool profile engages and closes those sleeves. While the service tool 100 is being raised during this closing movement, a reversing operation may take place to remove the treating fluid as suggested in
Each zone in the completion assembly 2 may be successively treated and reversed out as just described. When treatment of the uppermost zone is complete, it is often desirable to make a final wash all the way down to the lowermost zone. However, it would not be desirable to reopen all the closed sleeves as the opening profile on the service tool moves downward. One method for avoiding this undesirable effect is suggested in
The half cross-section views in
Positioned between outer sleeve 221 and housing assembly 220 is the re-crippling collet assembly 230. Re-crippling collet assembly 230 includes upper collet section 232 and lower collect section 231 which are joined by collet shear pin 233. Upper collet section 232 include the collet fingers 236 and 237, while lower collet section 231 includes outwardly facing profile 238 and inwardly facing profile 234. The shear pin 235 initially connects lower collet section 231 to housing assembly 220.
Next in
In the final operation suggested in
Claims
1. A well completion system comprising:
- a. a completion assembly;
- b. a service tool positioned within the completion assembly, wherein the service tool includes a substantially straight bore central passage from an upper end of the service tool to a lower end of the service tool; and
- c. a one-way valve positioned in an assembly annulus formed between the service tool and an inner surface of the completion assembly.
2. The well completion system of claim 1, further comprising a work string having an inner diameter being connected to the completion system and the service tool's central passage having approximately the same diameter as the work string's inner diameter.
3. The well completion system of claim 1, wherein the one-way valve is a reverse bypass valve allowing fluid flow in an uphole to downhole direction, but substantially blocks flow in a downhole to uphole direction.
4. The well completion system of claim 3, wherein the reverse bypass valve comprises: (i) a series of apertures in a valve body; and (ii) a flexible material movable away from the apertures in response to downhole fluid flow in the assembly annulus and movable against the apertures in response to uphole fluid flow in the assembly annulus.
5. The well completion system of claim 4, wherein the valve body is substantially tubular and the apertures positioned circumferentially around the valve body.
6. The well completion system of claim 5, wherein a flow path through the tubular body transitions from an outer surface of the body, to an inner surface of the body, and back to the outer surface of the tubular body.
7. The well completion system of claim 5, wherein the tubular body has one or more seals on an outer surface sized to engage a seal bore formed on an inner surface of the completion assembly.
8. The well completion system of claim 7, wherein the inner surface of the completion assembly has at least one section comprising a seal bore and at least one section not having a seal bore, wherein fluid in the assembly annulus may flow in an uphole or downhole direction past the reverse bypass valve when the valve is in the section not having a seal bore.
9. The well completion system of claim 1, wherein the one-way valve allows fluid flow in an annulus between the completion assembly and the service tool without substantial narrowing of the central passage of the service tool.
10. The well completion system of claim 1, wherein the completion assembly includes a tubing wall and a treating aperture is formed in the tubing wall such that the treating aperture is openingly closed by a treating sleeve internal to the tubing wall.
11-19. (canceled)
20. A well completion system comprising:
- a. a tubular completion assembly including multiple production zones, each production zone further comprising: (i) a zonal isolation packer; (ii) a screen wrapped, closeable monitoring port; (iii) a closeable treating port below the monitoring port; and (iv) a screen wrapped, pressure activated valve below the treating port.
21. The well completion system of claim 20, wherein sliding sleeves are used to selectively close the treating port and the monitoring port.
22. The well completion system of claim 20, wherein each zone includes an isolation packer above the monitoring port and an isolation packer below the pressure activated valve.
23. The well completion system of claim 20, wherein each zone includes a reduced diameter seal bore.
24. The well completion system of claim 20, wherein the completion assembly further comprises (i) a shifting tool activation mechanism below a lowermost zone and (ii) a shifting tool de-activation mechanism above an uppermost zone.
25-29. (canceled)
30. A method of logging a wellbore having a completion system therein, comprising the steps of:
- a. positioning a completion assembly in the wellbore, including a service tool within the completion assembly, wherein the service tool includes a substantially straight bore central passage;
- b. inserting a logging tool through the straight bore central passage and logging the wellbore at selected positions along the length of the straight bore central passage of the service and/or below the service tool.
31. The method of logging a wellbore of claim 30, wherein a bottom of the service tool is raised at least as high as an approximate top of a zone being logged prior to logging the zone.
32. The method of logging a wellbore of claim 30, wherein the completion system further comprises a one-way valve positioned in an assembly annulus formed between the service tool and an inner surface of the completion assembly and the logging tool passes the one-way valve while traveling through the service tools central passage.
33. The method of logging a wellbore of claim 31, wherein the zone is logged after treating of the zone without moving the service tool below the zone.
34. The method of logging a wellbore of claim 32, wherein the one-way valve further comprises: (i) a series of apertures in a valve body; and (ii) a flexible material movable away from the apertures in response to downhole fluid flow in the assembly annulus and movable against the apertures in response to uphole fluid flow in the assembly annulus.
35-67. (canceled)
Type: Application
Filed: Aug 12, 2014
Publication Date: Feb 19, 2015
Inventors: Dewayne Turner (Tomball, TX), Jed Landry (Breaux Bridge, LA), Anthony Thomas (Houston, TX), David Walker (Lafayette, LA)
Application Number: 14/457,972
International Classification: E21B 47/00 (20060101); E21B 43/12 (20060101);