WO2011085215A2 - Module de réglage hydrostatique actionné sans fil - Google Patents

Module de réglage hydrostatique actionné sans fil Download PDF

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Publication number
WO2011085215A2
WO2011085215A2 PCT/US2011/020538 US2011020538W WO2011085215A2 WO 2011085215 A2 WO2011085215 A2 WO 2011085215A2 US 2011020538 W US2011020538 W US 2011020538W WO 2011085215 A2 WO2011085215 A2 WO 2011085215A2
Authority
WO
WIPO (PCT)
Prior art keywords
assembly
well
module
oilfield
wireless communications
Prior art date
Application number
PCT/US2011/020538
Other languages
English (en)
Other versions
WO2011085215A3 (fr
Inventor
Dinesh R. Patel
Original Assignee
Schlumberger Canada Limited
Services Petroliers Schlumberger
Schlumberger Holdings Limited
Schlumberger Technology B.V.
Prad Research And Development Limited
Schlumberger Technology Corporation
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Schlumberger Canada Limited, Services Petroliers Schlumberger, Schlumberger Holdings Limited, Schlumberger Technology B.V., Prad Research And Development Limited, Schlumberger Technology Corporation filed Critical Schlumberger Canada Limited
Priority to EP11732214.9A priority Critical patent/EP2510190B1/fr
Publication of WO2011085215A2 publication Critical patent/WO2011085215A2/fr
Publication of WO2011085215A3 publication Critical patent/WO2011085215A3/fr

Links

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B23/00—Apparatus for displacing, setting, locking, releasing, or removing tools, packers or the like in the boreholes or wells
    • E21B23/06—Apparatus for displacing, setting, locking, releasing, or removing tools, packers or the like in the boreholes or wells for setting packers
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B23/00—Apparatus for displacing, setting, locking, releasing, or removing tools, packers or the like in the boreholes or wells
    • E21B23/06—Apparatus for displacing, setting, locking, releasing, or removing tools, packers or the like in the boreholes or wells for setting packers
    • E21B23/065—Apparatus for displacing, setting, locking, releasing, or removing tools, packers or the like in the boreholes or wells for setting packers setting tool actuated by explosion or gas generating means
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/06—Valve arrangements for boreholes or wells in wells
    • E21B34/08—Valve arrangements for boreholes or wells in wells responsive to flow or pressure of the fluid obtained
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling

Definitions

  • Embodiments described relate to hydrostatic setting modules for use in downhole environments.
  • equipment and techniques for triggering a hydrostatic setting module are described. More specifically, wireless equipment and techniques may be utilized for such triggering without reliance on potentially more costly or stressful hydraulic triggering modes.
  • the well may be of a fairly sophisticated architecture.
  • the well may be tens of thousands of feet deep, traversing various formation layers, and zonally isolated throughout. That is to say, packers may be intermittently disposed about production tubing which runs through the well so as to isolate various well regions or zones from one another. Thus, production may be extracted from certain zones through the production tubing, but not others.
  • production tubing that terminates adjacent a production region is generally anchored or immobilized in place thereat by a mechanical packer, irrespective of any zonal isolation.
  • a packer such as the noted mechanical packer, may be secured near the terminal end of the production tubing and equipped with a setting mechanism.
  • the setting mechanism may be configured to drive the packer from a lower profile to a radially enlarged profile.
  • the tubing may be advanced within the well and into position with the packer in a reduced or lower profile. Subsequently, the packer may be enlarged to secure the tubing in place adjacent the production region.
  • the mechanism may be equipped with a trigger that is responsive to a given degree of pressure induced within the production tubing. So, for example, surface equipment and pumps adjacent the well head may be employed to induce a pressure differential of between about 3,000 and 4,000 PSI into the well. Depending on the location of the trigger for the setting mechanism, this driving up of pressure may take place through the bore of the production tubing or through the annulus between the tubing and the wall of the well.
  • the noted hydraulic manner of driving up pressure for triggering of the setting mechanism may place significant stress on the production tubing.
  • the strain on the tubing may lead to ballooning.
  • the strain on the tubing may have long term effects. That is to say, even long after setting the packer, strain placed on the tubing during the hydraulic setting of the packer may result in failure, for example, during production operations.
  • the entire production tubing string and packer assembly may be removed, examined, and another deployment of production equipment undertaken. Ultimately, this may eat up a couple of days' time and upwards of $100,000 in expenses.
  • pressurization of the annulus as a means to trigger the setting mechanism requires that the lower, generally open-hole, completions assembly be isolated. Generally this would involve the closing of a formation isolation valve or other barrier valve above the lower completions. Unfortunately, such a valve may not always be present. Once more, such valves come with their own inherent expense, installation cost, and failure modes, not to mention the activation time and techniques which must be dedicated to operation of the valve.
  • a setting mechanism may be employed that is hydraulically wired to the surface.
  • a hydrostatic set module may be utilized that includes a dedicated hydraulic control line run all the way to surface.
  • a dedicated hydraulic line for the setting mechanism only shifts the concerns over hydraulic deployment from potential production tubing stressors, plug placements, or barrier valve issues to issues with other downhole production equipment.
  • a dedicated hydraulic line is itself an added piece of production equipment.
  • a new piece of equipment is introduced, the possibility of defective production string equipment is inherently increased even before a setting application is run. Once more, where such defectiveness results in a failure, the same amount of time and expenses may be lost in removal and re-deployment of the production string.
  • the advantages obtained from protecting the production tubing by utilization of a dedicated hydraulic line for the setting mechanism may be negligible at best.
  • a downhole system includes a hydraulically actuated mechanism along with a hydrostatic set module.
  • the module is hydraulically coupled to the mechanism for its actuation. Additionally, the module is outfitted with a wireless trigger to initiate its own activation to attain the noted actuation of the mechanism.
  • FIG. 1 depicts a front view of an embodiment of a wirelessly triggered hydrostatic set module in conjunction with a packer assembly.
  • Fig. 2 is an overview of an oilfield accommodating a well with the module and assembly of Fig. 1 disposed therein.
  • Fig. 3 A is an enlarged view of the module and assembly taken from 3-3 of Fig. 2 and revealing wireless pressure pulse communication through the well.
  • Fig. 3B reveals the module and assembly of Fig. 3A with the packer of the assembly set in the well by the module in response to the wireless communication.
  • FIG. 4A is a schematic view of an embodiment of a wirelessly triggered hydrostatic set module and downhole actuatable tool such as a packer assembly.
  • Fig. 4B is a schematic view of the module and assembly of Fig 4B following wireless actuation of the module.
  • Fig. 5 is a schematic view of an alternate embodiment of a wirelessly triggered hydrostatic set module employing redundant wireless triggering.
  • FIG. 6 is a flow-chart summarizing an embodiment of employing a wirelessly triggered hydrostatic set module.
  • Embodiments herein are described with reference to certain downhole setting applications.
  • embodiments depicted herein are of a packer being set downhole as part of a production assembly.
  • a variety of alternate applications utilizing a hydrostatic set module may employ wireless triggering and techniques as detailed herein.
  • wireless is meant to refer to any communication that takes place without the requirement of an optical or electrical wire, hydraulic line, or any other form of hard line substantially dedicated to supporting communications.
  • a downhole system 100 which includes an embodiment of a wirelessly triggered hydrostatic set module 150.
  • the module 150 is provided in conjunction with a packer 175 which may be utilized in sealing and anchoring production tubing 110 at a downhole location (see Fig. 2).
  • the packer 175 is outfitted with sealing elements 177 which may be hydraulically set via a hydraulic line 160 running from the module 150. In alternate embodiments, however, this line 160 may lead to hydraulically set devices other than packers.
  • the module 150 is wireless in nature. As shown in Fig. 1, the module 150 is equipped with a wireless trigger mechanism 130. With added reference to Fig. 2, the trigger 130 is configured to detect a wireless communication from surface 200. The communication may be in the form of a pressure pulse 201 or other signal emanating from surface 201 and transmitted downhole through the well 280. Regardless, the trigger mechanism 130 is configured to actuate the hydrostatic set module 150 in response to the detection of the wireless signal.
  • the trigger mechanism 130 may include a pressure sensor 480 as depicted in Figs. 4A and 4B.
  • a host of different signature types may be utilized in communicating with a processor 470 of the trigger mechanism 130 as described below.
  • a low pressure signature may be most suitable for communications.
  • the trigger mechanism 130 may be equipped with different types of sensors. For example, an acoustic sensor, flow meter or strain gauge may be utilized for respective detection of sonic transmission, fluid flow, or physical tension directed at the system 100 from the oilfield surface 200.
  • a radio frequency identification (RFID) or pip tag detector may be utilized for detection of an RFID or radioactively marked projectile, respectively.
  • RFID radio frequency identification
  • pip tag detector may be utilized for detection of an RFID or radioactively marked projectile, respectively.
  • a projectile may be dropped downhole from the oilfield surface 201 for activation of the trigger mechanism 130, once detected by the sensor thereof.
  • FIG. 2 an overview of an oilfield 201 accommodating a well 280 is shown.
  • the above noted system 100 with module 150 and packer 175, is disposed within the well 280 providing isolation above a production region 287.
  • the well 280 is defined by a casing 285 traversing various formation layers 290, 295 eventually reaching an uncased production region 287 with perforations 289 to encourage production therefrom.
  • the production region 287 may be cased, for example with casing perforations also present.
  • a hydrocarbon production flow may ultimately be directed through production tubing 110 of the system 100 and diverted through a line 255 at the well head 250.
  • a host of surface equipment 225 is disposed at the oilfield surface 200.
  • a rig 230 is even provided to support additional equipment for well interventions or other applications beyond the packer setting described herein.
  • a control unit 260 is provided along with a pulse generator 265 to direct communications with the triggering mechanism 130 as described below.
  • the pulse generator may be a pump. In other embodiments, however, alternate forms of wireless signal regulators may be employed as alluded to above.
  • the sealing elements 177 of the packer 175 are shown in an expanded state as directed by the hydrostatic set module 150 in response to actuation by the trigger mechanism 130.
  • the trigger mechanism 130 may be responsive to a wireless signal such as the noted pressure pulses 201, thereby actuating the module 150 until the packer 175 is set. Indeed, as the packer 175 is set, wireless communication with the trigger mechanism 130 are eventually cut off. Of course, this only takes place once the trigger mechanism 130 and module 150 are no longer needed due to the completion of the setting application.
  • the wireless communication signal may be sent through casing annulus as depicted between tubing 110 outside diameter and casing 285 inside diameter or alternately through the bore of the tubing 110 itself.
  • FIG. 3A an enlarged view of the system 100 is shown taken from 3-3 of Fig. 2 with focus on the hydrostatic set module 150 and packer 175.
  • the packer 175 is not yet set by the module 150. This is apparent as the sealing elements 177 of the packer 175 are shown in an undeployed state and displaying no sealing engagement with the casing 285 of the well 280.
  • the noted lack of sealing engagement means that wireless communications from the oilfield surface 200 may reach the trigger mechanism 130 of the module 150 for actuation. More specifically, the pulse generator 265 may be directed by the control unit 260 to transmit a particular signature of pressure pulses 201 downhole. These pulses 201 may be detected and evaluated by the pressure sensor 480 and processor 470 of the trigger mechanism 130, respectively (see Fig. 4A). Thus, once the proper signature is detected, the module 150 may be triggered as described above.
  • Fig. 3B the system 100 is now shown with the packer 175 set following the above-noted activation of the module 150 by the trigger mechanism 130. As shown, the sealing elements 177 are now in full sealing engagement with the well casing 285 and the pulses 201 apparent in Fig. 3A have ceased. In an alternate embodiment the triggering mechanism 130 may be located uphole of the isolated location, perhaps along with the module 150 as well.
  • a wirelessly triggered hydrostatic set module 150 may be utilized for shifting sliding sleeves. For example, this may be done to expose or close perforations 289 such as those shown in Fig. 2. or for opening and/or closing of a circulating valve for displacement of fluids.
  • multiple modules 150 may be employed such that shifting open or closed may be undertaken, for example, depending upon the particular wireless signature employed by the regulator as directed by the control unit 260.
  • a valve such as a formation isolation valve, may be linked to wirelessly triggered hydrostatic set modules 150 for opening or closing thereof according to the techniques described hereinabove.
  • Fig. 4 A a schematic view of the system 100 detailed hereinabove is shown.
  • the hydraulic connection 420 to the hydrostatic set module 150 is also shown along with the hydraulic line 160 disposed between the module 150 and the packer 175 as referenced above.
  • production tubing 110 is centrally disposed relative to the overall system 100.
  • the entire system 100 is disposed within a well 280 such as that of Fig. 2 which is defined by casing 285.
  • illustration of the casing 285 is limited to portions located adjacent the packer 175.
  • the casing 285 defines a substantial majority of the well 280 as shown in Fig. 2.
  • the trigger mechanism 130 includes a sensor 480.
  • the sensor 480 may be a pressure sensor configured to detect pressure pulses directed from an oilfield surface 201 and/or pressure pulse generator 265.
  • a variety of alternate sensor types may be utilized for detection of surface directed communications. These may include acoustic sensors, flow meters, strain gauges, and RFID or pip tag detectors, to name a few.
  • a pH or more chemical specific detector may even be employed for detection of an introduced fluid of a given characteristic. Such detectable fluid may even consist of the present wellbore fluid that is altered by the introduction of a pH altering or chemical presentation slug.
  • the processor 470 may immediately initiate triggering as described below upon detection of any surface directed communication. However, the processor 470 may also be programmed to initiate triggering upon the detection of a particular pattern or signature of surface communications. Thus, the odds of accidental triggering, for example, due to a false positive detection, may be reduced. Furthermore, the processor 470 may be employed to record and store data from the sensor 480 for later usage, perhaps unrelated to the triggering detailed below.
  • the processor 470 and any other electronics of the trigger mechanism 130 are powered by a conventional power source 460 such as an encapsulated lithium battery suitable for downhole use.
  • the processor 470 is ultimately wired to a charge 400 that may be fired by the processor 470 as a means of triggering.
  • the charge 400 remains unfired and isolated at one side of charge barrier 450.
  • the charge 400 is configured to break this barrier 450 along with a chamber barrier 440, ultimately exposing a chamber 430 to wellbore pressure thereby actuating the hydrostatic set module 150 as described below.
  • FIG. 4B a schematic view of the system 100 is shown in which the charge 400 of Fig. 4A has been set off.
  • the trigger of the trigger mechanism 130 has been pulled, so to speak. That is, based on analysis by the processor 470 of data obtained from the sensor 480, the charge 400 of Fig. 4A has been directed to go off, either upon being obtained or perhaps following a predetermined period of time.
  • this data obtained by the processor 470 relates to wireless surface communications detected by the sensor 480.
  • the setting mechanism 150 is that of an intensifier as would likely be the case for a conventional packer setting assembly. That is, aside from modifications for accommodating and coupling to the wireless trigger mechanism 130, as described above, the setting mechanism 150 may othemise be a conventional off-the-shelf hydrostatic set module, for example. Such a module is detailed in U.S. Pat. No. 7,562,712, Setting Tool for Hydraulically Actuated Devices, to Cho, et al., incorporated herein by reference in its entirety.
  • FIG. 5 an alternate embodiment of a wirelessly triggered HSM system 100 is shown in schematic form.
  • redundancy has been built into the system 100 with the addition of a second trigger mechanism 535, a second hydraulic connection 520 to the HSM 150 and perhaps even a second line 560 therefrom to the packer 175.
  • This added redundancy may be employed to help ensure that complete triggering and packer setting takes place.
  • wireless communications through the wellbore may face interference challenges such as the presence of air in the case of pressure pulses 201 (see Fig. 2). Nevertheless, the presence of multiple trigger mechanisms 130, 530 increases the likelihood of wireless communication detection.
  • wireless communications may take the form of different signature patterns, independently tailored to each of the mechanisms 130, 530 to further increase the likelihood of processed detection. That is to say, the initial sensor 480 and processor 470 may be tuned to pick up a particular signature of wireless communications for analysis that differs from another signature geared toward the second sensor 580 and processor 575. Thus, where the initial signature fails to fully propagate downhole to its respective sensor 480 and processor 470, the other signature may nevertheless reach the second sensor 580 and processor 575 (or vice versa). Thus, another port 590 may be formed, chamber 530 exposed and the HSM 150 actuated.
  • a flow-chart summarizing an embodiment of employing a wirelessly triggered hydrostatic set module is shown.
  • a downhole system may be deployed into a well.
  • a production tubing system is described.
  • other types of systems may utilize wirelessly triggered hydrostatic set modules, such as completion systems utilizing sliding sleeves.
  • wireless communication signatures such as pressure pulses, may be directed downhole as indicated at 635 and 655.
  • a sensor of a trigger mechanism incorporated into the system may detect downhole communications as indicated at 675.
  • a hydrostatic set module of the system may be triggered by the mechanism based on processing of the wireless detection (see 695). This in turn may result in setting of a packer, shifting of a sliding sleeve or any number of downhole actuations as detailed herein.
  • Embodiments described hereinabove reduce the likelihood of having to remove and re-deploy an entire production string as a result of hydraulic strain induced on tubing due to packer setting. This is achieved in a manner that does not require the presence of a dedicated hydraulic line ran from surface to the hydrostatic set module. As a result, concern over the introduction of new failure modes is eliminated. Furthermore, techniques detailed herein utilize wireless communications in conjunction with a hydrostatic set module that may be employed for a variety of applications beyond packer setting. Therefore, the value of the systems and techniques detailed herein may be appreciated across a variety of different downhole application settings.

Abstract

L'invention porte sur un module de réglage hydrostatique configuré avec un mécanisme de déclenchement sans fil pour permettre son activation sans fil depuis une surface de champ pétrolifère. Le mécanisme de déclenchement comprend une charge pour exposer le module à des pressions de fond de puits et lui permettre de se comporter comme un intensificateur pour l'actionnement d'un dispositif de fond de puits tel qu'une garniture de production. Le mécanisme comprend également un capteur pour détecter les communications sans fil conjointement avec un processeur pour analyser celles-ci et pour diriger l'emploi de la charge. Une impulsion de pression ou d'autres formes de communication sans fil qui sont appropriées pour l'environnement de fond de puis peuvent être envoyées depuis la surface dans une variété de motifs de signature différents en vue d'une analyse réactive par le mécanisme de déclenchement.
PCT/US2011/020538 2010-01-08 2011-01-07 Module de réglage hydrostatique actionné sans fil WO2011085215A2 (fr)

Priority Applications (1)

Application Number Priority Date Filing Date Title
EP11732214.9A EP2510190B1 (fr) 2010-01-08 2011-01-07 Module de reglage hydrostatique actionne sans fil

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US29335510P 2010-01-08 2010-01-08
US61/293,355 2010-01-08

Publications (2)

Publication Number Publication Date
WO2011085215A2 true WO2011085215A2 (fr) 2011-07-14
WO2011085215A3 WO2011085215A3 (fr) 2011-10-06

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US (1) US20110168403A1 (fr)
EP (1) EP2510190B1 (fr)
WO (1) WO2011085215A2 (fr)

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EP2510190A4 (fr) 2017-10-11
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EP2510190A2 (fr) 2012-10-17
US20110168403A1 (en) 2011-07-14

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