US20110079382A1

US20110079382A1 - Chemical injection of lower completions

Info

Publication number: US20110079382A1
Application number: US12/897,877
Authority: US
Inventors: Dinesh R. Patel
Original assignee: Schlumberger Technology Corp
Current assignee: Schlumberger Technology Corp
Priority date: 2009-10-05
Filing date: 2010-10-05
Publication date: 2011-04-07
Also published as: WO2011044078A3; WO2011044078A2; GB201205976D0; GB2486382A; GB2486382B; NO20120434A1

Abstract

A chemical injection system directed at lower completions. The system includes a tubular stinger that is anchored within a upper region of a well but traverses into the lower completion. Thus, a platform is provided for a chemical injection line running from surface to the lower completion. As a result, chemical injection may be directed right at a sand screen and other scale prone features of lower completions.

Description

PRIORITY CLAIM/CROSS REFERENCE TO RELATED APPLICATION(S)

This Patent Document claims priority under 35 U.S.C. §119 to U.S. Provisional App. Ser. No. 61/248,772, filed on Oct. 5, 2009, and entitled, “Chemical Injection System for Injecting in Sand Face Completions” incorporated herein by reference in its entirety. This Patent Document also claims priority under 35 U.S.C. §119 to U.S. Provisional App. Ser. No. 61/386,797, filed on Sep. 27, 2010, and entitled, “Chemical Injection of an Uncased Completion” incorporated herein by reference in its entirety.

FIELD

Embodiments described relate to chemical injection assemblies for completions systems. In particular, embodiments of injection assemblies which access both upper completions and lower completions are detailed.

BACKGROUND

Exploring, 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.
Most of the well may be 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 conventional 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.
In order to avoid the cost of lost time on interventions as described above, completions assemblies are often outfitted with 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.
Unfortunately, chemical injection systems as described above may fail to reach all points of interest in the well. For example, the well is often a cased well which terminates in a generally open hole, often laterally oriented, leg. This leg and accompanying architecture may be referred to as the lower completion assembly which seamlessly emanates from the noted upper cased completion assembly. Barring significant buildup, this generally uncased portion of the well is often quite effective in terms of production. Nevertheless, the chemical injection system fails to access the lower assembly. That is, in light of the open hole nature of the lower assembly, installation of the chemical injection system is generally preceded by placement of a packer or plug in the upper assembly near the lower completion assembly. While this maintains flow control for system installation, it leaves continuous cleanout unavailable to the lower completion assembly. As a result, chemical injection, and even continued production, from the lower completion assembly continues to require follow-on high cost intervention.

SUMMARY

A completions system is provided for delivering chemical injection in a well. The system includes an upper completion assembly disposed in the well adjacent a lower completion assembly. A tubular stinger is anchored to the upper assembly and configured to provide fluid communication to the lower assembly for the delivering of chemical injection thereto.
The stinger itself may be retrievable in nature so as to allow its removal for the running of various intervention tools to the lower completion, generally without the requirement of upper completion removal. Thus, intervention tools such as logging tools may be run to the lower completion and later withdrawn followed by reinstallation of the stinger.
The noted tubular stinger may be anchored to production tubing of the upper assembly. Additionally, a flow regulating mechanism may be provided about the production tubing. The mechanism may also be anchored to the lower completion and configured to maintain control over flow between the production tubing and the lower assembly.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a side view of an embodiment of a chemical injection system directed at a lower completion.

FIG. 2 is an enlarged view of the system taken from 2-2 of FIG. 1, revealing hydrocarbon and chemical injection flow.

FIG. 3 is an enlarged view of an embodiment of a chemical injection system employing isolated intelligent hydrocarbon and injection flow management.

FIG. 4A is a side view of an embodiment of a chemical injection system for directing exterior of the sand screen of a lower completion.

FIG. 4B is a top view of the chemical injection system of FIG. 4A revealing a shroud recess for accommodating a chemical injection line.

FIG. 5A is an enlarged view of an alternate embodiment of the system directed at a lower completion and accommodating an electronic submersible pump.

FIG. 5B is a schematic view of the system of FIG. 5A, highlighting production flow management.

FIG. 6 is a flow-chart summarizing an embodiment of installing and employing a chemical injection system directed at a lower completion.

DETAILED DESCRIPTION

Embodiments are described with reference to certain configurations of downhole chemical injection systems. In particular, systems are depicted and described which involve a conventionally cased well terminating in a primarily open-hole lateral leg as is fairly common. However, a variety of other well configurations may benefit from utilization of chemical injection systems as detailed herein. For example, the uncased region of the well may be vertical or at a non-terminal region of the well. In fact, as employed herein, the terms ‘upper’ and ‘lower’ are used in the conventional sense. That is, the term upper completion is meant to refer to that well section that is comparatively more cased than the lower completion which is comparatively more productive. These terms are not meant to require any particular orientation, elevation, or degree of openness to the formation. Regardless, embodiments described herein include systems which allow for chemical injection directed at the lower completion without the requirement of a separate dedicated intervention following completions installation.
Referring now to FIG. 1, a side view of an embodiment of a chemical injection system 100 is shown disposed within a well 180 traversing an oilfield formation 190. The system 100 includes an upper completion assembly 150 which is substantially cased and a lower completion assembly 175 that is substantially uncased. While adjacently disposed and continuous, the assemblies 150, 175 are distinguished by the presence of a casing 160 defining the upper completion assembly 150 which terminates at a sand face, in this case a screen 177, which defines the lower completion assembly 175. Of course, other sand faces such as slotted liners, perforated casings and the like may also be utilized. In one embodiment a liner structure with interventional components for encouraging production from the formation 190 may even be employed.
In the embodiment shown, the lower assembly 175 is oriented as a conventional lateral leg 185. However, a variety of architectural configurations may be employed. Regardless, in spite of the differing characteristics of the assemblies 150, 175, the system 100 is configured to encompass both for providing a chemical injection mixture 101 thereto.
Continuing with reference to FIG. 1, a tubular stinger 130 is provided which is anchored within the upper assembly 150 and traverses to within the lower assembly 175. The stinger 130 may be of jointed pipe, coiled tubing, a porous shroud or any other appropriate tubular mechanism. Indeed, a straddle seal assembly, wet connect features, and other jointed structure may combine to form a stinger 130 providing a platform for chemical injection as detailed herein. In the particular embodiment shown, the stinger 130 is anchored within a production tubular 120 of the upper assembly 150 which provides a conduit to surface for hydrocarbon production as described further below. A chemical injection line 125 is also provided which rides along the production tubular 120, eventually terminating in a deviation 127. As shown in FIG. 2, this deviation may be in fluid communication with the stinger 130 for providing chemical injection mix 101 to the lower completion assembly 175.
Depending on the span of the lower completion assembly 175 and the targeted location of chemical injection delivery, the stinger 130 may exceed ten to a hundred feet or more. Nevertheless, installation of the stinger 130 for delivery of the chemical injection mix 101 as shown may be achieved without significant compromise to flow control. That is, in advance of installation of the stinger 130, a formation isolation valve 140 may be used to close off flow and access to the lower assembly 175. However, unlike a conventional injection system, where the mix 101 is subsequently delivered above the valve 140, measures may be taken to allow the valve 140 to be re-opened and the stinger 130 advanced to a target location in the lower assembly 175. Indeed, as noted, this may be achieved without concern over the length of the stinger 130.
Installation of the stinger 130 as described may be rendered practical by the prior installation of a flow-regulating mechanism disposed between the production tubing 120 and the isolation valve 140. This may take a variety of forms. However, in the embodiment shown, a tubular shroud 115 is disposed about the terminal end of the production tubing 120. The shroud 115 is coupled to a joint structure 117 which leads to a gravel pack packer 145, all of which together provide a controlled pathway between the production tubing 120 and the lower completion 175 (at the valve 140). Thus, flow control between these features is not sacrificed in order to achieve installation of the stinger 130. As a result, the stinger 130 may be advanced downhole within the production tubing 120. A shifting tool 135 at the end of the stinger 130 may then be utilized to open the valve 140 and allow for continued advancement into the lower assembly 175. As such, chemical injection means is now available within this assembly 175.
Referring now to FIG. 2, an enlarged view of the system taken from 2-2 of FIG. 1 is shown. In this depiction, hydrocarbon flow 275 from the surrounding formation 190, across the sand screen 177 and into the lower completion assembly 175 is readily visible. Indeed, with added reference to FIG. 1, chemical injection mix 101 is made available to the terminal end of the assembly 175. Thus, as the mix 101 is produced uphole with the remainder of the flow 275, the sand screen 177 is exposed thereto. As a result, scale buildup at the screen 177 may be discouraged and hydrocarbon flow 275 enhanced thereacross.
While FIG. 1 depicts delivery of the mix 101 at the most terminal end of the stinger 130, ports 200 for mix delivery may also be provided at other locations of the stinger 130. In one embodiment, these ports may be equipped with a flow metering valve such as that detailed in U.S. application Ser. No. 12/576,417, entitled Multi-Point Chemical Injection System, filed Oct. 9, 2009 and incorporated herein by reference in its entirety. Such metering may help ensure constant flow and rate of the injection mix 101 into the lower assembly 175. This may be achieved namely by a variable orifice and pressure responsive features incorporated into the valve as detailed in the '417 application.
Regardless the manner of release, the mix 101, perhaps primarily hydrochloric acid, may contact the screen 177 and other surface features as it makes its way uphole joining hydrocarbon production flow 275. As shown, this flow 275 continues from the lower assembly 175 into the joint structure 117 and above described shroud 115. The shroud 115 then guides the flow 275 into the production tubing 120 around an anchoring head 250 therein for the stinger 130. Thus, regulated production flow 275 from the lower assembly 175 to the production tubing 120 and back to surface is achieved.
Referring now to FIG. 3, an enlarged view of an embodiment of a chemical injection system is shown where the lower completion assembly 175 may be zonally isolated. Additionally, the assembly 175 may be intelligent in terms of hydrocarbon 275 and injection mix 101 flow management. As shown in FIG. 3, separate well regions 385, 386 are isolated from one another by packers 300. Thus, the flow of hydrocarbon production 275 takes place through the ports 200 in the stinger 130. As a result, an injection line extension 325 is run in parallel with the stinger 130 for ported delivery of the mix 101 through outlets 301. In this manner, the downhole flow of injection mix 101 is isolated from the uphole hydrocarbon flow 275. In one embodiment the line extension 325 may even be secured at the interior of the stinger 130 with the outlets 301 traversing the extension 325 as well as the stinger 130 to allow mix release.
The isolation depicted in FIG. 3 provides a platform for intelligent flow management. So, for example, where communicative capacity is provided, such as through fiber optics or electrical cable, release of the mix 101 may be determined from region 385 to region 386. That is to say, where surface communications are afforded to each region 385, 386 and/or valves at outlet 301, surface determinations may be carried out downhole. Thus, one region 385 may receive more mix 101 than another 386. Indeed, in one embodiment, such isolation may even allow for unintelligent disparity in regional mix delivery. For example, this may be achieved where valves such as those of the noted '417 application are preset at different metering rates from region 385 to region 386.
Referring now to FIG. 4A, with added reference to FIGS. 1-3, a side view of an alternate embodiment of a lower assembly 475 for a chemical injection system is depicted. In this embodiment a chemical injection line 425 is kept at the exterior of the sand screen 177. Thus, the chemical injection mix 101 of FIGS. 1-3 may be delivered right at the interface of the formation 190 and the screen 177. So, for example, the mix 101 may contact the screen 177 more directly to discourage scale buildup. That is, the mix 101 need not compete with any incoming production flow 275 to reach the screen 177, but rather may cross the screen 177 toward the interior of the screen bore in the same manner as the flow 275 (see FIGS. 2 and 3).
Given the intended location and orientation of the line extension 425 for the embodiment of FIG. 4A, a porous shroud 400 may be provided about the screen 177 to accommodate the line 425. In such an embodiment the shroud may run the length of the screen 177 immediately adjacent thereto. Of course, additional or alternative line securing features may be utilized. For example, in one embodiment collars with channels for accommodating the line 425 may be disposed at various junctions about the screen 177. Furthermore, in the case of intelligent completions, fiber optics, electrical or other communicative means may be accommodated through use of a porous shroud 400, channeled collars and other appropriate support structure.
Referring now to FIG. 4B, a top view of the lower assembly 475 of the chemical injection system of FIG. 4A is shown. In this view, the shroud 400 is visible with an elongated recess 450 for accommodating of the line 425 as noted above. While providing structural support between the sand screen 177 and the line 425, it is also worth recalling the porous nature of the shroud 400. Thus, the shroud 400 poses no substantial impediment to the release of chemical injection mix 101 and the formation fluid or gas as depicted in FIGS. 1-3, or its ability to reach the screen 177 for discouraging buildup thereat.
Referring now to FIG. 5A, an enlarged view of an alternate embodiment of the system 500 is shown. In this embodiment, a stinger 530 is again provided for delivery of chemical injection mix 101 to a lower completion assembly 575. However, in this embodiment an impediment or obstruction in the form of an electronic submersible pump 502 (ESP) is present at the terminal end of the production tubular 525. Therefore use of a tubular shroud 115 as depicted in FIGS. 1-3 is rendered less practical. Nevertheless, as described below, a flow-regulating mechanism may still be effectively provided between the production tubing 120 and the lower completion 175. Thus, with flow regulating maintenance available, the stinger 530 may be installed for supporting chemical injection at the lower assembly 575.
Continuing with reference to FIG. 5A, the flow-regulating mechanism between the tubing 120 and the valve 140 again includes joint structure 517, now coupled to the valve 140. However, whereas the tubular shroud 115 of FIGS. 1-3 is rendered less practical due to the presence of the pump 502, alternate packer and casing-based structure may nevertheless be provided for a controlled flow path between the joint structure 517 and the production tubular 120.
In the embodiment shown, the joint structure 517 terminates at a hanger packer 550 positioned below the pump 502. By the same token, a feed through packer 537 is positioned above the pump 502 and at the terminal end of the production tubing 120. Further, pump support 535 suspends the pump 502 from the feed through packer 537 and into a space between the feed through 537 and hanger 550 packers. Thus, as detailed further below, the flow control provided by the tubular shroud 115 of FIGS. 1-3 has been replaced by the noted packers 537, 550 in combination with the casing 160 of the upper completion assembly 550.
Continuing with reference to FIG. 5A, a chemical injection line 525 is provided which is configured for traversing the feed through packer 537 and terminating in a deviation 527 in fluid communication with the stinger 530. Thus, chemical injection mix 101 may be directed to the lower completion assembly 575.
The produced flow 275 depicted in FIG. 5A reaches the interior of the joint structure 517 and is emptied into the location between the feed through 537 and hangar 550 packers. Thus, the electronic submersible pump 502 pulls the flow 275 to the interior of the production tubular 120 where it may be directed to surface. Due to the noted architecture of these packers 537, 550 in combination with the casing 160, such flow control is available irrespective of the presence of the stinger 130, thus allowing for its reliable installation.
In the embodiment of FIG. 5A, the chemical injection line 525 is depicted as terminating in the upper completion 555. However, the line 525 may extend into the lower completion 575 for ported site specific delivery of the chemical mix 101 as similarly detailed in reference to the embodiment of FIG. 3. Such delivery may be intelligent, for example by way of accompanying fiber optic control as also described hereinabove. Furthermore, such a line 525 may be provided in a segmented fashion with separate portions at the stinger 530, pump support 535, production tubing 120, and other appropriate structure, adjoiningly mating upon coupling. Such segmentation of the line 525 may allow for greater ease of installation. By the same token accompanying electrical, optical or other suitable control may similarly be provided in a segmented fashion through inductive coupling of the control line at the mating points. Such is detailed in U.S. application Ser. No. 12/728,018 entitled, “Measuring a Characteristic of a Well Proximate a Region to be Gravel Packed”, incorporated by reference herein in its entirety.
Referring now to FIG. 5B a schematic view of the system 500 of FIG. 5A is shown. In this depiction the above noted flow management is highlighted with focus on the flow path boundaries presented by the embodiment of FIG. 5A. For example, upon moving from the lower completion 575 at one side of the valve 140 to the upper completion 555 at the other, the flow path becomes defined by the joint structure 517. Continuing uphole, flow regulation is maintained by the above noted packers 550, 537 and casing 160 which provide a defined space for locating of the pump 502 which directs the flow 275 into the production tubing 120.
Referring now to FIG. 6, a flow-chart summarizing an embodiment of installing and employing a chemical injection system is shown. More specifically, directed at lower completion assemblies as indicated at 695. In order to allow for such treatments, a chemical injection stinger may be utilized which is advanced into the lower completion assembly as indicated at 675. Thus a platform is provided for chemical injection. The positioning of the stinger follows installation of the lower completion assembly and the opening of a formation isolation valve entry to the lower completion as indicated at 615 and 655 respectively.
In order to provide an adequate flow path for the noted stinger positioning, the installation of the upper completion assembly as indicated at 635 may be accompanied by the providing of a flow regulation mechanism as detailed hereinabove. This mechanism may be a shroud-based means of providing a flow path or of a combination packer and casing-based construction. Furthermore, depending on the overall architectural layout, the upper completion may be installed before or after advancing of the stinger into the lower completion. For example, in an embodiment where an obstruction such as an ESP is employed, the stinger may be placed prior to the upper completion. However, where no such obstruction is present, the stinger may be positioned following installation of the upper completion assembly. Indeed, in this latter embodiment, the removable nature of the stinger may be taken advantage of in that it may subsequently be removed through the upper completion assembly itself.
Embodiments described hereinabove include systems which allow for chemical injection to reach both upper and lower assemblies thereof. This is achieved without the requirement of follow-on dedicated interventions, particularly those directed at the lower completion assembly. Furthermore, these systems allow for the maintenance of flow-management throughout installation. Thus, a chemical injection system directed at the lower completion assembly may be realized in a practical manner.
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, architecture detailed hereinabove for use with an electronic submersible pump may be employed with or without such a pump in place. Further, such embodiments may make use of a multiple injection point line. 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 chemical injection system comprising:

an upper completion assembly disposed in a well;

a lower completion assembly adjacent said upper assembly in the well; and

a tubular stinger anchored in said upper assembly and providing fluid communication to said lower assembly for delivering chemical injection thereto.

2. The system of claim 1 further comprising:

a formation isolation valve at an uphole end of said lower completion assembly; and

a flow-regulating mechanism coupled to said upper and lower completion assemblies for maintaining flow regulation therebetween when said valve is open.

3. The system of claim 1 wherein said lower assembly is defined by one of a sand screen, a slotted liner, a liner structure with interventional components for encouraging hydrocarbon production, and perforated casing.

4. The system of claim 1 wherein said stinger is one of jointed pipe, coiled tubing, a porous shroud, and a straddle seal assembly.

5. The system of claim 1 wherein said stinger is retrievable.

6. The system of claim 1 further comprising:

a production tubular of said upper assembly; and

a chemical injection line for delivering chemical injection mix to said lower assembly, said line disposed adjacent said production tubular and running to said stinger.

7. The system of claim 6 wherein said tubular stinger is configured for release of the mix from one of a terminal end thereof and ports along a body thereof.

8. The system of claim 7 further comprising flow metering valves disposed at the ports.

9. The system of claim 6 further comprising a line extension running from said line along said stinger for release of the mix from outlets thereof, the stinger equipped with ports for uptake of hydrocarbon flow from said lower completion assembly.

10. The system of claim 9 further comprising zonal isolation packers disposed in said lower assembly.

11. The system of claim 10 further comprising flow metering valves disposed in said outlets for intelligent zonal release of the mix.

12. The system of claim 6 wherein said line runs exteriorly along said stinger for release of the mix from outlets thereof.

13. The system of claim 12 further comprising a sand screen disposed interior of said line.

14. The system of claim 13 further comprising a porous shroud disposed exterior of screen with an elongated recess for accommodation of said line.

15. The system of claim 13 further comprising channelized collars to secure the line about said screen.

16. A chemical injection system comprising:

an upper completion assembly disposed in a well and accommodating a production tubular;

a lower completion disposed adjacent said upper assembly in the well;

a shroud about the production tubular and coupled to said lower completion for maintaining flow management between the production tubular and said lower completion assembly; and

17. The system of claim 16 wherein said shroud is coupled to said lower completion assembly via joint structure, a formation isolation valve, and a gravel pack packer.

18. The system of claim 16 further comprising:

casing running downhole of said feed through packer;

a hanger packer coupled to said casing downhole of said feed through packer; and

joint structure running downhole of said hanger packer, each of said casing, hanger packer and said joint structure furthering defining the path to said lower completion assembly.

19. The system of claim 18 wherein said stinger includes an end disposed between said packers.

20. The system of claim 19 further comprising an impediment disposed adjacent the stinger end.

21. The system of claim 20 wherein said impediment is an electronic submersible pump.

22. A method of chemical injection in a well comprising:

installing a lower completion assembly in a well;

installing an upper completion assembly adjacent the lower assembly;

advancing a chemical injection stinger support into the lower assembly; and

performing a chemical injection in the lower assembly of the well.

23. The method of claim 22 wherein said advancing of the stinger further comprises utilizing a shifting tool thereof for opening a formation isolation valve of the lower completion assembly.

24. The method of claim 22 wherein said installing of the upper completion assembly further comprises placing a flow regulation mechanism between the upper and lower completions to provide a flow path therebetween.

25. The method of claim 24 wherein the flow regulation mechanism is one of a shroud based configuration and a packer and casing-based configuration.

26. The method of claim 25 wherein the upper completion includes an impediment, the flow-regulation mechanism is of the packer and casing-based configuration, and said installing of the upper completion follows said advancing.