WO2013103561A1 - Ségrégation de matériaux pouvant s'écouler dans un puits - Google Patents

Ségrégation de matériaux pouvant s'écouler dans un puits Download PDF

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Publication number
WO2013103561A1
WO2013103561A1 PCT/US2012/071574 US2012071574W WO2013103561A1 WO 2013103561 A1 WO2013103561 A1 WO 2013103561A1 US 2012071574 W US2012071574 W US 2012071574W WO 2013103561 A1 WO2013103561 A1 WO 2013103561A1
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WO
WIPO (PCT)
Prior art keywords
fluid
barrier substance
cement
wellbore
pressure
Prior art date
Application number
PCT/US2012/071574
Other languages
English (en)
Inventor
Jay K. Turner
James R. Lovorn
Original Assignee
Halliburton Energy Services. Inc.
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
Priority claimed from US13/345,546 external-priority patent/US8820405B2/en
Application filed by Halliburton Energy Services. Inc. filed Critical Halliburton Energy Services. Inc.
Priority to CA2858842A priority Critical patent/CA2858842C/fr
Priority to AU2012363682A priority patent/AU2012363682C1/en
Priority to MX2014008281A priority patent/MX2014008281A/es
Priority to BR112014016663A priority patent/BR112014016663A8/pt
Priority to EA201491331A priority patent/EA201491331A1/ru
Priority to EP12864148.7A priority patent/EP2800864A4/fr
Publication of WO2013103561A1 publication Critical patent/WO2013103561A1/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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 boreholes or wells
    • E21B23/06—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for setting packers
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/08—Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
    • C09K8/424—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells using "spacer" compositions
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
    • E21B33/134—Bridging plugs
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
    • E21B33/14—Methods or devices for cementing, for plugging holes, crevices or the like for cementing casings into boreholes
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
    • E21B33/14—Methods or devices for cementing, for plugging holes, crevices or the like for cementing casings into boreholes
    • E21B33/16—Methods or devices for cementing, for plugging holes, crevices or the like for cementing casings into boreholes using plugs for isolating cement charge; Plugs therefor

Definitions

  • the present disclosure relates generally to equipment and flowable materials utilized, and operations performed, in conjunction with a subterranean well and, in one example described below, more particularly provides for wellbore pressure control with segregated fluid columns.
  • FIG. 1 is a representative partially cross-sectional view of a system and associated method which can embody principles of the present disclosure.
  • FIG. 2 is a representative view of a pressure and flow control system which may be used with the system and method of FIG. 1.
  • FIG. 3 is a representative cross-sectional view of the system in which initial steps of the method have been performed.
  • FIG. 4 is a representative cross-sectional view of the well system in which further steps of the method have been performed.
  • FIG. 5 is a representative view of a flowchart for the method.
  • FIG. 6 is a representative cross-sectional view of another example of the system and method.
  • FIG. 1 Representatively and schematically illustrated in FIG. 1
  • FIG. 1 is a system 10 for use with a well, and an associated method, which system and method can embody principles of this disclosure.
  • the FIG. 1 example is configured for underbalanced or managed pressure drilling, but it should be clearly understood that this is merely one example of a well operation which can embody principles of this disclosure.
  • a wellbore 12 is drilled by rotating a drill bit 14 on an end of a tubular string 16.
  • Drilling fluid commonly known as mud
  • a non-return valve 21 (typically a flapper-type check valve) prevents flow of the drilling fluid 18 upward through the tubular string 16 (e.g., when connections are being made in the tubular string) .
  • Control of bottom hole pressure is very important in managed pressure and underbalanced drilling, and in other types of well operations.
  • the bottom hole pressure is accurately controlled to prevent excessive loss of fluid into an earth formation 64 surrounding the wellbore 12, undesired fracturing of the formation, undesired influx of formation fluids into the wellbore, etc.
  • Nitrogen or another gas, or another lighter weight fluid may be added to the drilling fluid 18 for pressure control. This technique is especially useful, for example, in underbalanced drilling operations.
  • RCD rotating control device 22
  • the RCD 22 seals about the tubular string 16 above a wellhead 24.
  • the tubular string 16 would extend upwardly through the RCD 22 for connection to, for example, a rotary table (not shown), a standpipe line 26, kelley (not shown), a top drive and/or other conventional drilling equipment.
  • the drilling fluid 18 exits the wellhead 24 via a wing valve 28 in communication with the annulus 20 below the RCD 22.
  • the fluid 18 then flows through fluid return line 30 to a choke manifold 32, which includes redundant chokes 34. Backpressure is applied to the annulus 20 by variably restricting flow of the fluid 18 through the operative choke(s) 34.
  • bottom hole pressure can be conveniently regulated by varying the backpressure applied to the annulus 20.
  • a hydraulics model can be used, as described more fully below, to determine a pressure applied to the annulus 20 at or near the surface which will result in a desired bottom hole pressure, so that an operator (or an automated control system) can readily determine how to regulate the pressure applied to the annulus at or near the surface (which can be conveniently measured) in order to obtain the desired bottom hole pressure.
  • Pressure applied to the annulus 20 can be measured at or near the surface via a variety of pressure sensors 36, 38, 40, each of which is in communication with the annulus.
  • Pressure sensor 36 senses pressure below the RCD 22, but above a blowout preventer (BOP) stack 42.
  • Pressure sensor 38 senses pressure in the wellhead below the BOP stack 42.
  • Pressure sensor 40 senses pressure in the fluid return line 30 upstream of the choke manifold 32.
  • Another pressure sensor 44 senses pressure in the standpipe line 26.
  • Yet another pressure sensor 46 senses pressure downstream of the choke manifold 32, but upstream of a separator 48, shaker 50 and mud pit 52. Additional sensors include temperature sensors 54, 56, Coriolis flowmeter 58, and flowmeters 62, 66.
  • the system 10 could include only one of the flowmeters 62, 66. However, input from the sensors is useful to the
  • tubular string 16 may include its own sensors 60, for example, to directly measure bottom hole pressure.
  • sensors 60 may be of the type known to those skilled in the art as pressure while drilling (PWD), measurement while drilling (MWD) and/or logging while drilling (LWD) sensor systems.
  • PWD pressure while drilling
  • MWD measurement while drilling
  • LWD logging while drilling
  • tubular string sensor systems generally provide at least pressure measurement, and may also provide temperature measurement, detection of tubular string characteristics (such as vibration, weight on bit, stick-slip, etc.), formation characteristics (such as resistivity, density, etc.) and/or other measurements.
  • Various forms of telemetry may be used to transmit the downhole sensor measurements to the surface.
  • Additional sensors could be included in the system 10, if desired.
  • another flowmeter 67 could be used to measure the rate of flow of the fluid 18 exiting the wellhead 24, another Coriolis flowmeter (not shown) could be interconnected directly upstream or downstream of a rig mud pump 68, etc.
  • Fewer sensors could be included in the system 10, if desired.
  • the output of the rig mud pump 68 could be determined by counting pump strokes, instead of by using flowmeter 62 or any other flowmeters.
  • separator 48 could be a 3 or 4 phase separator, or a mud gas separator (sometimes referred to as a "poor boy degasser"). However, the separator 48 is not necessarily used in the system 10.
  • the drilling fluid 18 is pumped through the standpipe line 26 and into the interior of the tubular string 16 by the rig mud pump 68.
  • the pump 68 receives the fluid 18 from the mud pit 52 and flows it via a standpipe manifold (not shown) to the standpipe line 26, the fluid then circulates downward through the tubular string 16, upward through the annulus 20, through the mud return line 30, through the choke manifold 32, and then via the separator 48 and shaker 50 to the mud pit 52 for conditioning and recirculation.
  • the choke 34 cannot be used to control backpressure applied to the annulus 20 for control of the bottom hole pressure, unless the fluid 18 is flowing through the choke.
  • a lack of circulation can occur whenever a connection is made in the tubular string 16 (e.g., to add another length of drill pipe to the tubular string as the wellbore 12 is drilled deeper), and the lack of circulation will require that bottom hole pressure be regulated solely by the density of the fluid 18.
  • a backpressure pump 70 can be used to supply a flow of fluid to the return line 30 upstream of the choke manifold 32 by pumping fluid into the annulus 20 when needed.
  • fluid could be diverted from the standpipe
  • FIG. 1 is depicted as if a drilling operation is being performed, it should be clearly understood that the principles of this disclosure may be utilized in a variety of other well operations. For example, such other well operations could include completion
  • tubular string 16 it is not necessary for the tubular string 16 to be a drill string, or for the fluid 18 to be a drilling fluid.
  • the fluid 18 could instead be a
  • a pressure and flow control system 90 which may be used in conjunction with the system 10 and method of FIG. 1 is representatively illustrated in FIG. 2.
  • the control system 90 is preferably fully automated, although some human intervention may be used, for example, to safeguard against improper operation, initiate certain routines, update parameters, etc.
  • the control system 90 includes a hydraulics model 92 , a data acquisition and control interface 94 and a controller 96 (such as, a programmable logic controller or PLC, a suitably programmed computer, etc.). Although these elements 92 , 94 , 96 are depicted separately in FIG. 2 , any or all of them could be combined into a single element, or the
  • the hydraulics model 92 is used in the control system 90 to determine the desired annulus pressure at or near the surface to achieve the desired bottom hole pressure.
  • Data such as well geometry, fluid properties and offset well information (such as geothermal gradient and pore pressure gradient, etc.) are utilized by the hydraulics model 92 in making this determination, as well as real-time sensor data acquired by the data acquisition and control interface 94 .
  • the data acquisition and control interface 94 operates to maintain a substantially continuous flow of real-time data from the sensors 36 , 38 , 40 , 44 , 46 , 54 , 56 , 58 , 60 , 62 , 64 , 66 , 67 to the hydraulics model 92 , so that the hydraulics model has the information it needs to adapt to changing circumstances and to update the desired annulus pressure.
  • the hydraulics model 92 operates to supply the data acquisition and control interface 94 substantially continuously with a value for the desired annulus pressure.
  • a greater or lesser number of sensors may provide data to the interface 94 , in keeping with the principles of this disclosure.
  • flow rate data from a flowmeter 72 which measures an output of the backpressure pump 70 may be input to the interface 94 for use in the hydraulics model 92 .
  • a suitable hydraulics model for use as the hydraulics model 92 in the control system 90 is REAL TIME HYDRAULICS (TM) provided by Halliburton Energy Services, Inc. of
  • a suitable data acquisition and control interface for use as the data acquisition and control interface 94 in the control system 90 are SENTRY (TM) and INSITE (TM) provided by Halliburton Energy Services, Inc. Any suitable data acquisition and control interface may be used in the control system 90 in keeping with the principles of this disclosure.
  • the controller 96 operates to maintain a desired setpoint annulus pressure by controlling operation of the fluid return choke 34 and/or the backpressure pump 70 .
  • the controller uses the desired annulus pressure as a setpoint and controls operation of the choke 34 in a manner (e.g., increasing or decreasing flow through the choke as needed) to maintain the setpoint pressure in the annulus 20 .
  • a measured annulus pressure such as the pressure sensed by any of the sensors 36 , 38 , 40
  • This process is preferably automated, so that no human intervention is required, although human intervention may be used if desired.
  • the controller 96 may also be used to control operation of the backpressure pump 70.
  • the controller 96 can, thus, be used to automate the process of supplying fluid flow to the return line 30 when needed. Again, no human intervention may be required for this process.
  • FIG. 3 a somewhat enlarged scale view of a portion of the well system 10 is representatively illustrated apart from the remainder of the system depicted in FIG. 1. In the FIG. 3 illustration, both cased 12a and uncased 12b sections of the wellbore 12 are visible .
  • the tubular string 16 is partially withdrawn from the wellbore 12 (e.g., raised in the vertical wellbore shown in FIG. 3) and a barrier substance 74 is placed in the wellbore 12 (e.g., raised in the vertical wellbore shown in FIG. 3) and a barrier substance 74 is placed in the wellbore 12 (e.g., raised in the vertical wellbore shown in FIG. 3) and a barrier substance 74 is placed in the
  • the barrier substance 74 may be flowed into the wellbore 12 by circulating it through the tubular string 16 and into the annulus 20, or the barrier substance could be placed in the wellbore by other means (such as, via another tubular string installed in the wellbore, by circulating the barrier substance downward through the annulus, etc.).
  • the barrier substance 74 is placed in the wellbore 12 so that it traverses the junction between the cased section 12a and uncased section 12b of the wellbore (i.e., at a casing shoe 76).
  • the barrier substance 74 could be placed entirely in the cased section 12a or entirely in the uncased section 12b of the wellbore 12.
  • the barrier substance 74 is preferably of a type which can isolate the fluid 18 exposed to the formation 64 from other fluids in the wellbore 12. However, the barrier substance 74 also preferably transmits pressure, so that control over pressure in the fluid 18 exposed to the
  • formation 64 can be accomplished using the control system 90.
  • the barrier substance 74 is preferably a highly viscous fluid, a highly
  • the barrier substance 74 could be (or comprise) other types of materials in keeping with the principles of this disclosure.
  • Suitable highly thixotropic gels for use as the barrier substance 74 include N-SOLATE (TM) and CFS-538 (TM) marketed by Halliburton Energy Services, Inc.
  • TM N-SOLATE
  • TM CFS-538
  • One suitable high strength gel for use as the barrier substance 74 may be prepared as follows:
  • barrier substance 74 Of course, a wide variety of different formulations may be used for the barrier substance 74. The above are only two such formulations, and it should be clearly understood that the principles of this disclosure are not limited at all to these formulations.
  • the system 10 is representatively illustrated after the barrier substance 74 has been placed in the wellbore 12 and the tubular string 16 has been further partially withdrawn from the wellbore.
  • Another fluid 78 is then flowed into the wellbore 12 on an opposite side of the barrier substance 74 from the fluid 18.
  • the fluid 78 preferably has a density greater than a density of the fluid 18.
  • the density of the fluid 78 is selected so that, after it is flowed into the wellbore 12 (e.g., filling the
  • an appropriate hydrostatic pressure will be thereby applied to the fluid 18 exposed to the formation 64.
  • the pressure in the fluid 18 will be equal to, or only marginally greater than (e.g., no more than
  • control system 90 preferably maintains the pressure in the fluid 18 exposed to the formation 64
  • control system 90 can achieve this result by automatically adjusting the choke 34 as fluid exits the annulus 20 at the surface, as described above, so that an appropriate backpressure is applied to the annulus at the surface to maintain a desired pressure in the fluid 18 exposed to the formation 64.
  • the annulus pressure setpoint will vary as the substances are introduced into the wellbore.
  • the density of the fluid 78 is selected so that, upon completion of the step of flowing the fluid 78 into the wellbore 12, no pressure will need to be applied to the annulus 20 at the surface in order to maintain the desired pressure in the fluid 18 exposed to the formation 64.
  • a snubbing unit will not be necessary for subsequent well operations (such as, running casing, installing a completion assembly, wireline or coiled tubing logging, etc.). However, a snubbing unit may be used, if desired.
  • the barrier fluid 74 will prevent mixing of the fluids 18, 78, will isolate the fluids from each other, will prevent migration of gas 80 upward through the wellbore 12, and will transmit pressure between the fluids.
  • a flowchart for one example of a method 100 of controlling pressure in the wellbore 12 is representatively illustrated.
  • the method 100 may be used in conjunction with the well system 10 described above, or the method may be used with other well systems.
  • a first fluid such as the fluid 18
  • the fluid 18 could be a drilling fluid which is specially formulated to exert a desired hydrostatic pressure, prevent fluid loss to the formation 64, lubricate the bit 14, enhance wellbore stability, etc.
  • the fluid 18 could be a completion fluid or another type of fluid.
  • the fluid 18 may be circulated through the wellbore 12 during drilling or other operations.
  • Various means e.g., tubular string 16, a coiled tubing string, etc. may be used to introduce the fluid 18 into the wellbore, in keeping with the principles of this disclosure.
  • pressure in the fluid 18 exposed to the formation 64 is adjusted, if desired. For example, if prior to beginning the procedure depicted in FIG. 5, an underbalanced drilling operation was being performed, then it may be desirable to increase the pressure in the fluid 18 exposed to the formation 64, so that the pressure in the fluid is equal to, or marginally greater than, pore pressure in the formation.
  • step 106 of the method 100 the tubular string 16 is partially withdrawn from the wellbore 12. This places a lower end of the tubular string 16 at a desired lower extent of the barrier substance 74, as depicted in FIG. 3.
  • tubular string 16 or another tubular string used to place the barrier substance 74
  • "partially withdrawing" the tubular string can be taken to mean, “placing the lower end of the tubular string at a desired lower extent of the barrier substance 74.”
  • a coiled tubing string could be installed in the wellbore 12 for the purpose of placing the barrier substance 74 above the fluid 18 exposed to the formation 64, in which case the coiled tubing string could be considered “partially withdrawn” from the wellbore, in that its lower end would be positioned at a desired lower extent of the barrier substance.
  • step 108 of the method 100 the barrier substance 74 is placed in the wellbore 12.
  • the barrier substance could be flowed through the tubular string 16, flowed through the annulus 20 or placed in the wellbore by any other means .
  • step 110 of the method 100 the tubular string 16 is again partially withdrawn from the wellbore 12. This time, the lower end of the tubular string 16 is positioned at a desired lower extent of the fluid 78. In this step 110,
  • the second fluid 78 is flowed into the wellbore 12.
  • the fluid 78 has a selected density, so that a desired pressure is applied to the fluid 18 by the column of the fluid 78 thereabove. It is envisioned that, in most circumstances of underbalanced and managed pressure drilling, the density of the fluid 78 will be greater than the density of the fluid 18 (so that the pressure in the fluid 18 is equal to or marginally greater than the pressure in the formation 64), but in other examples the density of the fluid 78 could be equal to, or less than, the density of the fluid 18.
  • a well operation is performed at the conclusion of the procedure depicted in FIG. 5.
  • the well operation could be any type, number and/or combination of well operation(s) including, but not limited to, drilling operation ( s ) , completion operation ( s ) , logging operation ( s ) , installation of casing, cementing operations, abandonment operations, etc. It is not necessary for the well operation to be managed or underbalanced drilling, or drilling of any type, in keeping with the scope of this disclosure.
  • such operation(s) can be performed without use of a downhole deployment valve or a surface snubbing unit, but those types of equipment may be used, if desired, in keeping with the principles of this disclosure .
  • the hydraulics model 92 produces a desired surface annulus pressure setpoint as needed to maintain a desired pressure in the fluid 18 exposed to the formation 64, and the controller 96
  • the surface annulus pressure setpoint can change during the method 100.
  • the surface annulus pressure setpoint may decrease as the fluid 78 is flowed into the wellbore 12.
  • the surface annulus pressure setpoint may be increased if the wellbore
  • barrier substance 74 can separate fluids or other flowable substances in any type of well operation .
  • the fluids 18, 78 are indicated as being segregated by the barrier substance 74, in other examples more than one fluid could be exposed to the formation 64 below the barrier substance and/or more than one fluid may be positioned between the barrier substance and the surface. In addition, more than one barrier substance 74 and/or barrier substance location could be used in the wellbore 12 to thereby
  • the barrier substance 74 isolates the fluid 18 from cement 120 placed in the uncased section 12b of the wellbore 12.
  • the cement 120 is likely more dense than the fluid 18, but the barrier substance 74 prevents the cement 120 from penetrating the barrier substance and thereby flowing away from its intended location.
  • cement 120 it may be intended to place the cement 120 in a particularly stable and relatively impermeable zone, so that the cement will form an effective plug in the wellbore 12 (e.g., for abandonment of the well, for isolating a water-producing zone, for segregating zones, etc.).
  • the effectiveness of the cement 120 as a plug could be
  • the barrier substance 74 beneficially accomplishes the desired functions of preventing the cement 120 from falling through the fluid 18, preventing mixing of the cement and fluid 18, and maintaining the placement of the cement.
  • the barrier substance 74 transmits
  • the fluid 78 placed above the cement 120 could be the same as the fluid 18 below the barrier substance 74, and/or it could comprise another fluid having a density selected so that pressure in the wellbore 12 is maintained at a desired level.
  • the fluid 78 can be selected so that sufficient hydrostatic pressure in the wellbore 12 is maintained for well control (e.g., hydrostatic pressure in the wellbore is greater than pressure in the formation 64 all along the wellbore).
  • the fluid 78 can be selected so that hydrostatic pressures at certain locations along the wellbore 12 are less than respective predetermined maximum levels (e.g., less than a pressure rating of the casing shoe 76, less than a fracture pressure of the formation 64, etc.).
  • the fluid 78 may be more dense or less dense as compared to the fluid 18. It is contemplated that, in most actual circumstances, the fluid 78 will be less dense as compared to the cement 120, but this is not necessary in keeping with the scope of this disclosure.
  • cement is used to indicate a substance which is initially flowable, but which will harden into a rigid structure having compressive strength after being flowed into a well, thereby forming a barrier to fluid.
  • Cement is not necessarily cementitious , and does not necessarily harden via hydration.
  • Cement can comprise polymers (such as epoxies, etc.) and/or other materials.
  • cement could extend above the casing shoe 76, or could be placed entirely in the cased section 12a.
  • scope of this disclosure is not limited to any
  • cement 120 can be prevented from flowing downward through another, lighter fluid 18.
  • the method can include segregating flowable cement 120 from a first fluid 18 by placing a flowable barrier substance 74 between the cement 120 and the first fluid 18.
  • the barrier substance 74 substantially prevents displacement of the cement 120 by force of gravity through the barrier substance 74 and into the first fluid 18.
  • the placing step can comprise flowing the barrier substance 74 into the well while the first fluid 18 is already present in the well.
  • the placing step can also comprise flowing the cement 120 into the well after the step of flowing the barrier substance 74 into the well.
  • the placing step can also comprise flowing the barrier substance 74 to a position above the first fluid 18.
  • the method may include placing a second fluid 78 above the cement 120.
  • the second fluid 78 can have a density greater than, or less than, a density of the first fluid 18.
  • the barrier substance 74 may comprise a thixotropic gel and/or a gel which sets in the wellbore 12.
  • the barrier substance 74 may have a viscosity greater than viscosities of the first and second fluids 18, 78.
  • the cement 120 can have a density greater than a density of the first fluid 18.
  • the method can include flowing a barrier substance 74 into the wellbore 12 above a first fluid 18 already in the wellbore 12, and then flowing cement 120 into the wellbore 12 above the barrier substance 74.
  • the system 10 may include a flowable cement 120 isolated from a first fluid 18 by a flowable barrier substance 74 positioned between the cement 120 and the first fluid 18, whereby the barrier substance 74 substantially prevents displacement of the cement by force of gravity through the barrier substance 74 and into the first fluid 18.
  • the above disclosure describes a method 100 of
  • the method 100 can include placing a barrier substance 74 in the wellbore 12 while a first fluid 18 is present in the wellbore, and flowing a second fluid 78 into the wellbore 12 while the first fluid 18 and the barrier substance 74 are in the wellbore.
  • the first and second fluids 18, 78 may have different densities.
  • the barrier substance 74 may isolate the first fluid 18 from the second fluid 78, may prevent upward migration of gas 80 in the wellbore and/or may prevent migration of gas 80 from the first fluid 18 to the second fluid 78.
  • Placing the barrier substance 74 in the wellbore 12 can include automatically controlling a fluid return choke 34, whereby pressure in the first fluid 18 is maintained
  • flowing the second fluid 78 into the wellbore 12 can include automatically
  • the second fluid 78 density may be greater than the first fluid 18 density. Pressure in the first fluid 18 may remain substantially constant while the greater density second fluid 78 is flowed into the wellbore 12.
  • the above disclosure also provides to the art a well system 10.
  • the well system 10 can include first and second fluids 18, 78 in a wellbore 12, the first and second fluids having different densities, and a barrier substance 74 separating the first and second fluids.

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  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Fluid Mechanics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Physics & Mathematics (AREA)
  • Mechanical Engineering (AREA)
  • Chemical & Material Sciences (AREA)
  • Materials Engineering (AREA)
  • Organic Chemistry (AREA)
  • Earth Drilling (AREA)
  • Processing Of Solid Wastes (AREA)
  • Consolidation Of Soil By Introduction Of Solidifying Substances Into Soil (AREA)
  • Preparation Of Clay, And Manufacture Of Mixtures Containing Clay Or Cement (AREA)

Abstract

L'invention porte sur un procédé de ségrégation de matériaux pouvant s'écouler en association avec un puits souterrain, lequel procédé peut mettre en œuvre la ségrégation d'un ciment pouvant s'écouler à partir d'un fluide par disposition d'une substance de barrière pouvant s'écouler entre le ciment et le fluide, et la substance de barrière empêchant sensiblement un déplacement du ciment par la force de gravité à travers la substance de barrière et dans le fluide. L'invention porte également sur un autre procédé de ségrégation de matériaux pouvant s'écouler, lequel procédé peut mettre en œuvre l'écoulement d'une substance de barrière dans un puits de forage au-dessus d'un fluide déjà dans le puits de forage, puis l'écoulement de ciment dans le puits de forage au-dessus de la substance de barrière. L'invention porte également sur un système pour l'utilisation en association avec un puits souterrain, lequel système peut comprendre un ciment pouvant s'écouler isolé vis-à-vis d'un fluide par une substance de barrière pouvant s'écouler positionnée entre le ciment et le fluide, ce par quoi la substance de barrière empêche sensiblement un déplacement du ciment par la force de gravité à travers la substance de barrière et dans le fluide.
PCT/US2012/071574 2012-01-06 2012-12-24 Ségrégation de matériaux pouvant s'écouler dans un puits WO2013103561A1 (fr)

Priority Applications (6)

Application Number Priority Date Filing Date Title
CA2858842A CA2858842C (fr) 2012-01-06 2012-12-24 Segregation de materiaux pouvant s'ecouler dans un puits
AU2012363682A AU2012363682C1 (en) 2012-01-06 2012-12-24 Segregating flowable materials in a well
MX2014008281A MX2014008281A (es) 2012-01-06 2012-12-24 Segregacion de materiales que pueden fluir en un pozo.
BR112014016663A BR112014016663A8 (pt) 2012-01-06 2012-12-24 segregar materiais fluidos em um poço
EA201491331A EA201491331A1 (ru) 2012-01-06 2012-12-24 Разобщение текучих материалов в скважине
EP12864148.7A EP2800864A4 (fr) 2012-01-06 2012-12-24 Ségrégation de matériaux pouvant s'écouler dans un puits

Applications Claiming Priority (2)

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US13/345,546 2012-01-06
US13/345,546 US8820405B2 (en) 2010-04-27 2012-01-06 Segregating flowable materials in a well

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WO2013103561A1 true WO2013103561A1 (fr) 2013-07-11

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AU (1) AU2012363682C1 (fr)
BR (1) BR112014016663A8 (fr)
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EA (2) EA201491331A1 (fr)
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EP2985408A1 (fr) * 2014-08-11 2016-02-17 Services Petroliers Schlumberger Appareil et procédés pour cimenter des puits

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US4275788A (en) * 1980-01-28 1981-06-30 Bj-Hughes Inc. Method of plugging a well
US4441556A (en) 1981-08-17 1984-04-10 Standard Oil Company Diverter tool and its use
US4627496A (en) * 1985-07-29 1986-12-09 Atlantic Richfield Company Squeeze cement method using coiled tubing
US5368103A (en) 1993-09-28 1994-11-29 Halliburton Company Method of setting a balanced cement plug in a borehole
US5529123A (en) * 1995-04-10 1996-06-25 Atlantic Richfield Company Method for controlling fluid loss from wells into high conductivity earth formations
US5697441A (en) * 1993-06-25 1997-12-16 Dowell, A Division Of Schlumberger Technology Corporation Selective zonal isolation of oil wells
US20110259612A1 (en) * 2010-04-27 2011-10-27 Halliburton Energy Services, Inc. Wellbore pressure control with segregated fluid columns

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US4275788A (en) * 1980-01-28 1981-06-30 Bj-Hughes Inc. Method of plugging a well
US4441556A (en) 1981-08-17 1984-04-10 Standard Oil Company Diverter tool and its use
US4627496A (en) * 1985-07-29 1986-12-09 Atlantic Richfield Company Squeeze cement method using coiled tubing
US5697441A (en) * 1993-06-25 1997-12-16 Dowell, A Division Of Schlumberger Technology Corporation Selective zonal isolation of oil wells
US5368103A (en) 1993-09-28 1994-11-29 Halliburton Company Method of setting a balanced cement plug in a borehole
US5529123A (en) * 1995-04-10 1996-06-25 Atlantic Richfield Company Method for controlling fluid loss from wells into high conductivity earth formations
US20110259612A1 (en) * 2010-04-27 2011-10-27 Halliburton Energy Services, Inc. Wellbore pressure control with segregated fluid columns

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Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP2985408A1 (fr) * 2014-08-11 2016-02-17 Services Petroliers Schlumberger Appareil et procédés pour cimenter des puits

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MX2014008281A (es) 2014-08-22
BR112014016663A8 (pt) 2017-07-04
CA2858842A1 (fr) 2013-07-11
CA2858842C (fr) 2016-08-23
AU2012363682A1 (en) 2014-06-26
EP2800864A4 (fr) 2016-02-24
EA201990544A1 (ru) 2019-07-31
AU2012363682C1 (en) 2015-12-03
EP2800864A1 (fr) 2014-11-12
EA201491331A1 (ru) 2014-10-30
BR112014016663A2 (pt) 2017-06-13
AU2012363682B2 (en) 2015-08-20

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