EP2564016B1 - Régulation de la pression dans un puits de forage avec colonnes de fluide séparées - Google Patents

Régulation de la pression dans un puits de forage avec colonnes de fluide séparées Download PDF

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Publication number
EP2564016B1
EP2564016B1 EP10850856.5A EP10850856A EP2564016B1 EP 2564016 B1 EP2564016 B1 EP 2564016B1 EP 10850856 A EP10850856 A EP 10850856A EP 2564016 B1 EP2564016 B1 EP 2564016B1
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EP
European Patent Office
Prior art keywords
fluid
wellbore
pressure
barrier substance
fluids
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Legal status (The legal status 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 status listed.)
Not-in-force
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EP10850856.5A
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German (de)
English (en)
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EP2564016A4 (fr
EP2564016A1 (fr
Inventor
James R. Lovorn
Emad Barki
Jay K. Turner
Ryan G. Ezell
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Halliburton Energy Services Inc
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Halliburton Energy Services Inc
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    • 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
    • E21B21/082—Dual gradient systems, i.e. using two hydrostatic gradients or drilling fluid densities
    • 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
    • E21B21/085—Underbalanced techniques, i.e. where borehole fluid pressure is below formation pressure

Definitions

  • the present disclosure relates generally to equipment and fluids utilized and operations performed in conjunction with a subterranean well and, in an embodiment described herein, more particularly provides for wellbore pressure control with segregated fluid columns.
  • FIG. 1 Representatively and schematically illustrated in FIG. 1 is a well system 10 and associated method which can embody principles of the present disclosure.
  • a wellbore 12 is drilled by rotating a drill bit 14 on an end of a tubular string 16.
  • Drilling fluid 18 commonly known as mud, is circulated downward through the tubular string 16, out the drill bit 14 and upward through an annulus 20 formed between the tubular string and the wellbore 12, in order to cool the drill bit, lubricate the tubular string, remove cuttings and provide a measure of bottom hole pressure control.
  • a non-return valve 21 typically a flapper-type check valve
  • 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 hydraulics model in determining what the pressure applied to the annulus 20 should be during the drilling operation.
  • 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 acoustic, pressure pulse, electromagnetic, optical, wired, etc. 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.
  • 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 manifold to the return line 30 when needed, as described in International Application Serial No. PCT/US08/87686 , and in US Application Serial No. 12/638,012 . Restriction by the choke 34 of such fluid flow from the rig pump 68 and/or the backpressure pump 70 will thereby cause pressure to be applied to the annulus 20.
  • FIG. 1 Although the example of 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.
  • such other well operations could include completion operations, logging operations, casing operations, etc.
  • 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 completion fluid or any other type of fluid.
  • 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 functions of the elements could be separated into additional elements, other additional elements and/or functions could be provided, etc.
  • 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 Houston, Texas USA. Another suitable hydraulics model is provided under the trade name IRIS (TM), and yet another is available from SINTEF of Trondheim, Norway. Any suitable hydraulics model may be used in the control system 90 in keeping with the principles of this disclosure.
  • 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
  • the setpoint and measured pressures are the same, then no adjustment of the choke 34 is required.
  • 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 .
  • both cased 12a and uncased 12b portions 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.
  • 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 portion 12a and uncased portion 12b of the wellbore (i.e., at a casing shoe 76).
  • the barrier substance 74 could be placed entirely in the cased portion 12a or entirely in the uncased portion 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 thixotropic gel or a high strength gel which sets in the wellbore.
  • the barrier substance 74 could be (or comprise) other types of materials in keeping with the principles of this disclosure.
  • N-SOLATE TM
  • a suitable preparation is as follows:
  • 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 wellbore from the barrier substance 74 to the surface), 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 approximately 689475 N/m 2 (100 psi) greater than), pore pressure in the formation 64.
  • other pressures in the fluid 18 may be used in other examples.
  • the control system 90 preferably maintains the pressure in the fluid 18 exposed to the formation 64 substantially constant (e.g., varying no more than a few psi).
  • the 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. Consequently, excessively increased pressure in the uncased portion 12b of the wellbore exposed to the formation 64 (which could otherwise result from opening a downhole deployment valve, etc.) can be prevented, excessively reduced pressure can be prevented from being exposed to the uncased portion of the wellbore, gas in the fluid 18 can be prevented from migrating upwardly through the wellbore to the surface, and fluids (such as higher density fluids) other than the fluid 18 can be prevented from contacting the exposed formation.
  • fluids such as higher density 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) is present in the wellbore 12.
  • 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 fluids.
  • 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.
  • “partially withdrawing” can be taken to mean, “positioning a lower end of the tubular string at a desired lower extent of the fluid 78.”
  • 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, etc.
  • drilling operation(s) drilling operation(s), completion operation(s), logging operation(s), installation of casing, etc.
  • completion operation completion operation(s)
  • logging operation(s) installation of casing, etc.
  • installation of casing etc.
  • 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 automatically adjusts the choke 34 as needed to achieve the surface annulus pressure setpoint.
  • 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 12 was previously being drilled underbalanced, and it is now desired to increase the pressure in the fluid 18 exposed to the formation 64, so that it is equal to or marginally greater than pressure in the formation.
  • 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 segregate any number of fluids.
  • the above disclosure describes a method 100 of controlling pressure in a wellbore 12.
  • 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.
  • the barrier substance 74 may comprises 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.
  • 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 substantially constant.
  • flowing the second fluid 78 into the wellbore 12 can include automatically controlling the fluid return choke 34, whereby pressure in the first fluid 18 is maintained substantially constant.
  • 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.
  • a method 100 of controlling pressure in a wellbore 12 including: circulating a first fluid 18 through a tubular string 16 and an annulus 20 formed between the tubular string 16 and the wellbore 12; then partially withdrawing the tubular string 16 from the wellbore 12; then placing a barrier substance 74 in the wellbore 12; then further partially withdrawing the tubular string 16 from the wellbore 12; and then flowing a second fluid 78 into the wellbore 12.
  • Pressure in the first fluid 18 may be maintained substantially constant during placing the barrier substance 74 in the wellbore 12 and/or during flowing the second fluid 78 into the wellbore.
  • the method 100 can include, prior to placing the barrier substance 74 in the wellbore 12, adjusting a pressure in the first fluid 18 exposed to a formation 64 intersected by the wellbore 12, whereby the pressure in the first fluid 18 at a selected location is approximately the same as, or marginally greater than, a pore pressure of the formation 64 at the selected location.
  • 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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  • Mining & Mineral Resources (AREA)
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Claims (11)

  1. Procédé de régulation de pression dans un puits de forage (12), le procédé comprenant :
    le placement d'une substance barrière (74) dans le puits de forage (12) pendant qu'un premier fluide (18) est présent dans le puits de forage ; et
    l'écoulement d'un deuxième fluide (78) dans le puits de forage (12) pendant que le premier fluide (18) et la substance barrière (74) sont dans le puits de forage (12), caractérisé en ce que le deuxième fluide (78) remplit le puits de forage de la substance barrière (74) à la surface, la substance barrière (74) isolant le premier fluide (18) du deuxième fluide (78) une fois que la substance barrière (74) durcit dans le puits de forage (12), et où la substance de la barrière transmet la pression entre les premier et deuxième fluide après que la substance barrière (74) a durci dans le puits de forage (12), et où les premier et deuxième fluides ont des densités différentes.
  2. Procédé selon la revendication 1, dans lequel la substance barrière (74) empêche la migration de gaz vers le haut dans le puits de forage (12).
  3. Procédé selon la revendication 1, dans lequel la substance barrière (74) empêche la migration de gaz du premier fluide (18) au deuxième fluide (78).
  4. Procédé selon la revendication 1, dans lequel la substance barrière (74) comprend :
    (a) un gel thixotrope ; ou
    (b) un gel qui durcit dans le puits de forage (12).
  5. Procédé selon la revendication 1, dans lequel la substance barrière (74) a une viscosité supérieure aux viscosités des premier et deuxième fluides.
  6. Procédé selon la revendication 1, dans lequel la densité de deuxième fluide est supérieure à la densité de premier fluide, où de préférence la pression dans le premier fluide (18) reste sensiblement constante tandis le deuxième fluide de plus grande densité (78) s'écoule dans le puits de forage (12).
  7. Système de puits, comprenant :
    de premier et deuxième fluides dans un puits de forage (12), et une substance barrière (74) séparant les premier et deuxième fluides, caractérisé en ce que le deuxième fluide (78) remplit le puits de forage de la substance barrière (74) à la surface, la substance barrière (74) isolant le premier fluide (18) du deuxième fluide (78) après que la substance barrière (74) durcit dans le puits de forage (12), et où la substance barrière transmet une pression entre les premier et deuxième fluides après que la substance barrière (74) durcit dans le puits de forage (12), et où les premier et deuxième fluides ont différentes densités.
  8. Système de puits selon la revendication 7, dans lequel la substance barrière (74) empêche la migration vers le haut de gaz dans le puits de forage (12).
  9. Système de puits selon la revendication 7, dans lequel la substance barrière (74) empêche la migration de gaz du premier fluide (18) au deuxième fluide (78).
  10. Système de puits selon la revendication 7, dans lequel la substance barrière (74) comprend :
    (a) un gel thixotrope ; ou
    (b) un gel qui durcit dans le puits de forage (12).
  11. Système de puits selon la revendication 7, dans lequel la substance barrière (74) a une viscosité supérieure aux viscosités des premier et deuxième fluides.
EP10850856.5A 2010-04-27 2010-04-27 Régulation de la pression dans un puits de forage avec colonnes de fluide séparées Not-in-force EP2564016B1 (fr)

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EP2564016A1 EP2564016A1 (fr) 2013-03-06
EP2564016A4 EP2564016A4 (fr) 2013-06-26
EP2564016B1 true EP2564016B1 (fr) 2016-06-08

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EP (1) EP2564016B1 (fr)
AU (1) AU2010352027B2 (fr)
BR (1) BR112012026845B1 (fr)
CA (1) CA2795910C (fr)
MX (1) MX2012012385A (fr)
SG (1) SG184922A1 (fr)
WO (1) WO2011136761A1 (fr)

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CN102828712B (zh) * 2012-09-13 2014-02-19 中国石油大学(华东) 用于施加井口回压的双节流控制泥浆泵分流管汇及其方法
US10077647B2 (en) 2014-07-24 2018-09-18 Schlumberger Technology Corporation Control of a managed pressure drilling system

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EP2564016A4 (fr) 2013-06-26
SG184922A1 (en) 2012-11-29
WO2011136761A1 (fr) 2011-11-03
BR112012026845A2 (pt) 2016-07-12
CA2795910C (fr) 2015-01-20
AU2010352027A1 (en) 2012-10-25
CA2795910A1 (fr) 2011-11-03
EP2564016A1 (fr) 2013-03-06
MX2012012385A (es) 2013-05-30
BR112012026845B1 (pt) 2019-09-17
AU2010352027B2 (en) 2013-08-01

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