DOWNHOLE HYDRAULIC COUPLING ASSEMBLY
A completions system utilizing a unique hydraulic coupling. The system includes an upper completion stinger configured for coupling to a lower completion tubular. Both the stinger and the tubular are outfitted with hydraulic lines therethrough. Thus, as the stinger is coupled to the tubular, hydraulic lines are also coupled. However, the termination of each line is sealingly covered by a slidable sleeve in advance of attaining the coupling between the stinger and tubular. Therefore, the lines are protected from contamination during potentially significant periods of well deployment that may occur in advance of completed coupling and system installation. Furthermore, the manner of hydraulic coupling between the stinger and tubular reduces the likelihood of damage to the hydraulic lines during the installation process.
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This Patent Document claims priority under 35 U.S.C. §119 to U.S. Provisional App. Ser. No. 61/294,330, filed on Jan. 12, 2010, and entitled, “Downhole Equipment and Method of Use” incorporated herein by reference in its entirety. This Patent Document also claims priority under 35 U.S.C. §120 to U.S. patent application Ser. No. 12/056,643, filed on Mar. 27, 2008, entitled, “System and Method for Engaging Well Equipment in a Wellbore” and to U.S. patent application Ser. No. 11/850,243, filed on Sep. 5, 2007, entitled, “System and Method for Engaging Completions in a Wellbore”, both of which are also incorporated herein by reference in their entireties.
FIELDEmbodiments described relate to tools and techniques for coupling hydraulic lines to one another. In particular, embodiments of hydraulic line running through walls of downhole tubing segments are detailed.
BACKGROUNDExploring, drilling and completing hydrocarbon wells are generally complicated, time consuming and ultimately very expensive endeavors. As a result, over the years increased attention has been paid to monitoring and maintaining the health of such wells. Significant premiums are placed on maximizing the total hydrocarbon recovery, recovery rate, and extending the overall life of the well as much as possible. Thus, logging applications for monitoring of well conditions play a significant role in the life of the well. Similarly, significant importance is placed on well intervention applications, such as clean-out techniques which may be utilized to remove debris from the well so as to ensure unobstructed hydrocarbon recovery.
As with monitoring and interventional applications, the initial well design and architecture also plays a significant role in maximizing efficient recovery from the well. For example, most of the well is generally defined by a smooth steel casing that is configured for the rapid uphole transfer of hydrocarbons and other fluids from a formation. However, a buildup of irregular occlusive scale, wax and other debris may occur at the inner surface of the casing or tubing and other architecture restricting flow there-through. Such debris may even form over perforations in the casing, screen, or slotted pipe thereby also hampering hydrocarbon flow into the main borehole of the well from the surrounding formation.
In order to address scale buildup as noted above, a variety of interventional techniques are available. For example, an inexpensive gravity fed wireline technique may be employed wherein chemical cleaners such as hydrochloric acid are delivered to downhole sites of buildup. Alternatively, for more sizeable buildups, particularly of calcium carbonate, barium sulfate and other crystalline scale deposits, less passive techniques may be utilized. These may include the use of explosive percussion, impact bits, and milling. Further, for less hazardous and more complete clean-outs, techniques employing mechanical fluid jetting tools are generally the most common form of interventions. Such tools may be conveyed into the well via coiled tubing and include a head for jetting pressurized fluids, chemicals, solutions, beads, particles, or penetrants toward the well wall in order to fracture and dislodge scale and other debris.
Unfortunately, running interventional applications involves the delivery of footspace eating clean-out equipment to the oilfield and requires that production from the well be halted. So, for example, a day's time and upwards of several hundred thousand dollars may be spent on rig-up, running and disengaging coiled tubing clean-out equipment, not to mention lost production time. Therefore, as alluded to above, the initial well design and architecture may call for the completions structure to be outfitted with hydraulics capable of accommodating a circulating chemical injection system. This is particularly the case where the likelihood of buildup is accounted for up front, as is often the case in deep water wells. Regardless, with such systems in place, a metered amount of chemical mixture, such as the above noted hydrochloric acid mix, may be near continuously circulated downhole from the oilfield surface. That is, an injection line may be run from surface to downhole points of interest for delivery of chemical mix thereat. Upon delivery, the mix may be produced along with the ongoing production of the well. Thus, the need to halt production or run expensive interventions in order to address undesirable buildup is eliminated.
The above noted chemical injection hydraulics may be provided through a production tubing wall or other available structure. However, the production tubing may be provided in segmented form. As each tubing segment is installed, a challenge is presented in physically coupling the segment to a previously installed segment. In a well where the tubing is to accommodate a hydraulic line as noted above, the challenge of coupling the segments is exacerbated by the requirement of ensuring that hydraulic terminations for each of the segments are also mated with one another during the coupling. In this way, a continuous hydraulic line may be incorporated throughout the completed tubing wall. Indeed, even where the tubing is not segmented, its coupling to an open lower completion may involve mating terminations should the lower completion be outfitted with a chemical injection line.
Unfortunately, the mating of hydraulic terminations slows down the installation process. Perhaps more significantly, however, the likelihood of improperly mated hydraulic terminations during installation is substantial. Even though the hydraulic terminations are generally high dollar, robust fittings, they are often damaged during in the installation process. Thus, dollars are lost to replacement of the terminations and even more so to the time lost in the form of the added runs now required for installation or re-installation of the tubing segments with the damaged terminations.
Even more problematic than damaged terminations requiring replacement is the high likelihood of operators being unaware of damaged terminations in the first place. That is to say, improperly connected terminations may not be learned of during the installation process. Thus, where a fully functional hydraulic line is essential to well operations, the results may be catastrophic, particularly where the line is accommodated through well casing as opposed to production tubing. To date, efforts have been directed at aiding segment orientation during installation through the use of certain swivel devices that may improve the likelihood of proper hydraulic termination mating to a degree. However, there remains no manner of guaranteeing that one termination is perfectly aligned with another for mating during installation of completions structure.
SUMMARYA completions assembly is provided which includes an upper completions stinger for connection to a lower completion tubular. Both the tubular and the stinger are outfitted with hydraulic lines that are configured for coupling to one another as the noted connection between the tubular and stinger. Additionally, the line of the stinger terminates at a seal that is isolated by a first slidable sleeve relative the stinger. Similarly, the line of the tubular terminates at a port that is isolated by a slidable sleeve relative the tubular. Thus, the lines may be protected by the sleeves until the connection is made.
Embodiments are described with reference to certain downhole completions systems. In particular, a production assembly is detailed throughout with production tubing running through a cased well to a generally uncased production region. However, a variety of different types of completions may utilize hydraulic coupling tools and techniques as detailed herein. Indeed, any downhole segmented tubulars equipped with hydraulics for coupling to one another may take advantage of the embodiments described herein.
As used herein, terms such as “upper completion stinger” or “lower completion tubular” are meant only to distinguish adjacent downhole tubular structures for coupling to one another. So, for example, no particular structural stinger features are meant to be required due to use of the term “stinger”. Further, even the term “upper” is only utilized to distinguish the tubular that is meant for positioning closer to the oilfield surface as measured through the well. That is to say, the term “upper” does not to require that the tubular literally be at a higher elevation than the adjacent tubular. Indeed, in a horizontal well section the upper completion stinger may not be above the lower completion tubular in terms of elevation.
Referring now to
As noted above, for sake of distinction, the upper tubular is referred to as a stinger 125 and the lower tubular, merely a tubular 150. However, these tubular segments 125, 150 may have a variety of features commonly found in completions assemblies. For example, the stinger 125 may serve as the coupling end of a larger production tubing 210 as depicted in
Continuing with reference to
Prior to the above described downward movement of the slidable sleeve 155, the port 160 of the lower tubular 150 is sealingly covered by the sleeve 155. However, the noted downward movement of the sleeve 155 eventually exposes the port 160 which in turn achieves hydraulic alignment with the passage 130 as detailed above. Indeed, as detailed further below, another slidable sleeve 300 may be provided for sealingly covering the passage 130 until the noted coupling and hydraulic alignment is achieved (see
Referring now to
Following drilling and casing, installation of the completions system depicted in
With added reference to
Continuing with reference to
Referring now to
Sealingly covering the passage 130 and the port 160 in advance of the coupling of the stinger 125 to the tubular 150 may help to maintain functionality of the hydraulics. For example, the risk of contamination is not limited to altering a particular chemical mixture or other hydraulic fluid. Rather, the contamination could amount to debris and particulate with the capability of impeding or even disabling hydraulic function through the connected lines 135, 165 of
Referring now to
It is worth noting that in advance of the passage 130 and the port 160 becoming hydraulically aligned as shown in
Referring now to
With added reference to
Referring now to
In other embodiments, the port 160, rather than the passage 130, may be of a circumferential nature. Alternatively, both the port 160 and the passage 130 may be circumferential. Where circumferential configurations are utilized, so too may multiple hydraulic lines be employed. For example, multiple hydraulic lines may be run through the main body of the stinger 125 to terminate at a circumferential passage 130, or through the main body of the tubular 150 where a circumferential port 160 is utilized. Perhaps more importantly however, so long as at least one of the passage 130 or the port 160 is circumferential, the need to ensure a particular radial orientation between the stinger 125 and tubular 150 is eliminated. Indeed, the configurations detailed hereinabove, utilizing an interlocking stinger 125 and tubular 150 assembly with sliding sleeves 300, 155, avoid the likelihood of damaged hydraulic terminations during coupling. By the same token, the use of a circumferential passage 130 and/or port 160 substantially avoids the possibility of misalignment in coupling of the hydraulics. Thus, the possibility of attaining a hydraulically malfunctioning segmented assembly 100 due to improper downhole mating is virtually eliminated.
Referring now to
Referring now to
In the embodiment of
Embodiments detailed hereinabove describe a lower completion tubular 150 with an internal sleeve 155 for sealing an internally oriented port 160 and an upper completion stinger 125 with an external sleeve 300 for sealing an externally oriented passage 130. However, such orientations are relative. For example, an upper completion may utilize an externally oriented sleeve and port for coupling to an internally oriented sleeve and port for a lower completion while still falling within the scope of embodiments detailed herein.
Embodiments detailed above also focus on sleeves 300, 155 which are mechanically shifted. However in other embodiments shifting may be electrically or hydraulically aided. Furthermore, in another alternate embodiment, the sleeves 300, 155 may be configured such that rotational positioning is determinative of port 160 or passage 130 sealing, as opposed to the shifting of lateral positioning.
Referring now to
Embodiments described hereinabove include downhole tubular accommodating hydraulic lines that may be coupled together in a timely manner. At the same time the likelihood of damaging the couplings during installation is reduced. Thus, less and expense may be devoted to the installation and coupling that accompanies many downhole hydraulically equipped tubular completions. Furthermore, the odds of improper catastrophic installation in terms of hydraulics is virtually eliminated where embodiments of hydraulic coupling tools and techniques are utilized as detailed herein.
The preceding description has been presented with reference to presently preferred embodiments. Persons skilled in the art and technology to which these embodiments pertain will appreciate that alterations and changes in the described structures and methods of operation may be practiced without meaningfully departing from the principle, and scope of these embodiments. For example, installation of completions as detailed herein is described with reference to hydraulics that are utilized in conjunction with production operations. However, such hydraulics may be employed for actuation of downhole tools coupled to the lower completion or any number of alternate hydraulically supported applications. Regardless, the foregoing description should not be read as pertaining only to the precise structures described and shown in the accompanying drawings, but rather should be read as consistent with and as support for the following claims, which are to have their fullest and fairest scope.
Claims
1. A downhole hydraulic completions assembly comprising:
- an upper completion stinger with a hydraulic stinger line therethrough, the stinger line terminating at a passage isolated by a slidable stinger sleeve relative a main body of said stinger; and
- a lower completion tubular with a hydraulic tubular line therethrough, the tubular line terminating at a port isolated by a slidable tubular sleeve relative a main body of said tubular, the passage and the port for hydraulic coupling therebetween upon physical coupling of said stinger to said tubular.
2. The assembly of claim 1 wherein the physical coupling provides shifting of the sleeves to expose the passage to the port.
3. The assembly of claim 1 wherein said upper completion stinger further comprises a mule shoe with collets for interlocking with a surface of the tubular sleeve.
4. The assembly of claim 1 wherein at least one of said passage and said port is of a circumferential configuration.
5. The assembly of claim 4 wherein the stinger line is a first hydraulic line of said stinger, the circumferential passage configured to accommodate a second hydraulic line of said stinger.
6. The assembly of claim 4 wherein the tubular line is a first hydraulic line of said tubular, the circumferential port configured to accommodate a second hydraulic line of said tubular.
7. The assembly of claim 1 wherein the stinger sleeve is disposed about the main body of said stinger and the tubular sleeve is disposed adjacent an inner wall of said tubular.
8. The assembly of claim 7 wherein the tubular sleeve is equipped with a scraper ring for interfacing the inner wall.
9. The assembly of claim 1 wherein the stinger sleeve is interiorly disposed relative the main body of said stinger and the tubular sleeve is disposed about a main body of said tubular.
10. A hydraulically outfitted downhole completions system comprising:
- upper completions disposed in a cased portion of a well, said upper completions having a stinger with a hydraulic line therethrough and terminating at a passage isolated by a slidable sleeve relative a main body of the stinger; and
- lower completions disposed in an at least partially open portion of the well adjacent the cased portion, said lower completions having a tubular coupling to the stinger and equipped with a hydraulic line therethrough, the line of the tubular terminating at a port isolated by a slidable sleeve relative a main body of the tubular.
11. The system of claim 10 wherein the coupling aligns the passage and the port for hydraulic communication there between.
12. The system of claim 11 wherein the coupling provides shifting of the sleeves to expose the passage to the port for the communication.
13. The system of claim 10 wherein said upper completions further comprises production tubing coupled to the stinger to provide a conduit for production fluid flow to a surface of an oilfield adjacent the well.
14. The system of claim 13 wherein said lower completions further comprises production intake equipment in fluid communication with the hydraulic line through the tubular, the system further comprising chemical injection equipment disposed at the oilfield surface and hydraulically coupled to the hydraulic line through the tubular via the hydraulic line through the stinger.
15. A method comprising:
- installing a lower completion tubular in a well, the tubular accommodating a hydraulic line through a main body thereof and a slidable sleeve for sealing off a port at a terminal end of the line; and
- deploying an upper completion stinger to a location adjacently uphole of the tubular, the stinger accommodating a hydraulic line through a main body thereof and a slidable sleeve for sealing off a passage at a terminal end of the line through the stinger.
16. The method of claim 15 further comprising:
- initiating coupling of the stinger to the tubular; and
- maintaining the sealing with the sleeves during said initiating.
17. The method of claim 16 further comprising:
- aligning the passage with the port; and
- shifting the sleeves away from the passage and the port during said aligning to allow for hydraulic coupling between the lines.
18. The method of claim 17 further comprising performing a hydraulically actuated application in the well through the lines.
19. The method of claim 18 wherein the application is one of chemical injection and operation of a hydraulically actuatable downhole tool.
20. The method of claim 17 further comprising:
- decoupling the stinger from the tubular:
- resealing the passage and the port with the sleeves during the decoupling; and
- withdrawing the stinger from the well.
Type: Application
Filed: Jan 11, 2011
Publication Date: Jul 14, 2011
Applicant: SCHLUMBERGER TECHNOLOGY CORPORATION (Sugar Land, TX)
Inventors: Michael Hui Du (Pearland, TX), Gary Rytlewski (League City, TX), David Wei Wang (Sugar Land, TX)
Application Number: 13/004,237
International Classification: E21B 19/16 (20060101); E21B 19/18 (20060101); E21B 19/00 (20060101);