EP2867439B1 - Régulation de la pression dans les opérations de forage avec application d'un décalage en réaction à des conditions prédéterminées - Google Patents

Régulation de la pression dans les opérations de forage avec application d'un décalage en réaction à des conditions prédéterminées Download PDF

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Publication number
EP2867439B1
EP2867439B1 EP12880400.2A EP12880400A EP2867439B1 EP 2867439 B1 EP2867439 B1 EP 2867439B1 EP 12880400 A EP12880400 A EP 12880400A EP 2867439 B1 EP2867439 B1 EP 2867439B1
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EP
European Patent Office
Prior art keywords
pressure
well pressure
flow
setpoint
offset
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German (de)
English (en)
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EP2867439A4 (fr
EP2867439A1 (fr
Inventor
James R. Lovorn
Nancy S. Davis
Cody N. Butler
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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
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/06—Valve arrangements for boreholes or wells in wells
    • E21B34/10—Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole
    • 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

Definitions

  • This disclosure relates generally to equipment utilized and operations performed in conjunction with a subterranean well and, in one example described below, more particularly provides for pressure control in drilling operations, with an offset being applied to a pressure setpoint in response to certain predetermined conditions.
  • This applied pressure can be from one or more of a variety of sources, such as, backpressure applied by a choke in a mud return line, pressure applied by a dedicated backpressure pump, and/or pressure diverted from a standpipe line to the mud return line.
  • EP 1 898 044 relates to a prior art method for drilling a wellbore which includes an act of drilling the wellbore by injecting drilling fluid through a tubular string disposed in the wellbore, the tubular string comprising a drill bit disposed on a bottom thereof.
  • the drilling fluid exits the drill bit and carries cuttings from the drill bit.
  • the drilling fluid and cuttings flow to a surface of the wellbore via an annulus defined by an outer surface of the tubular string and an inner surface of the wellbore.
  • the method further includes an act performed while drilling the wellbore of measuring a first annulus pressure (FAP) using a pressure sensor attached to a casing string hung from a wellhead of the wellbore.
  • the method further includes an act performed while drilling the wellbore of controlling a second annulus pressure (SAP) exerted on a formation exposed to the annulus.
  • FAP first annulus pressure
  • SAP second annulus pressure
  • FIG. 1 Representatively illustrated in FIG. 1 is a well drilling system 10 and associated method which can embody principles of this disclosure.
  • system 10 and method are merely one example of an application of the principles of this disclosure in practice, and a wide variety of other examples are possible. Therefore, the scope of this disclosure is not limited at all to the details of the system 10 and method described herein and/or depicted in the drawings.
  • a wellbore 12 is drilled by rotating a drill bit 14 on an end of a drill string 16.
  • Drilling fluid commonly known as mud
  • Drilling fluid is circulated downward through the drill string 16, out the drill bit 14 and upward through an annulus 20 formed between the drill string and the wellbore 12, in order to cool the drill bit, lubricate the drill string, remove cuttings and provide a measure of wellbore pressure control.
  • a non-return valve 21 typically a flapper-type check valve
  • Control of wellbore pressure is very important in managed pressure drilling, and in other types of drilling operations.
  • the wellbore pressure is precisely controlled to prevent excessive loss of fluid into the earth formation 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 useful, for example, in underbalanced drilling operations.
  • RCD rotating control device 22
  • the RCD 22 seals about the drill string 16 above a wellhead 24.
  • the drill string 16 would extend upwardly through the RCD 22 for connection to, for example, a rotary table (not shown), a standpipe line 26, kelly (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 mud return lines 30, 73 to a choke manifold 32, which includes redundant chokes 34 (only one of which might be used at a time).
  • Backpressure is applied to the annulus 20 by variably restricting flow of the fluid 18 through the operative choke(s) 34.
  • downhole pressure e.g., pressure at the bottom of the wellbore 12, pressure at a downhole casing shoe, pressure at a particular formation or zone, etc.
  • 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 downhole 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 downhole 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 mud return lines 30, 73 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, 64, 66.
  • the system 10 could include only two of the three flowmeters 62, 64, 66.
  • input from all available sensors can be useful to the hydraulics model in determining what the pressure applied to the annulus 20 should be during the drilling operation.
  • flowmeter 58 may be a Coriolis flowmeter, since a turbine flowmeter, acoustic flowmeter, or another type of flowmeter could be used instead.
  • the drill string 16 may include its own sensors 60, for example, to directly measure downhole 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).
  • PWD pressure while drilling
  • MWD measurement while drilling
  • LWD logging while drilling
  • These drill string sensor systems generally provide at least pressure measurement, and may also provide temperature measurement, detection of drill 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 wired or wireless telemetry acoustic, pressure pulse, electromagnetic, 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 the 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 drill 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 70 to the standpipe 26.
  • the fluid 18 then circulates downward through the drill string 16, upward through the annulus 20, through the mud return lines 30, 73, 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 downhole pressure, unless the fluid 18 is flowing through the choke.
  • a lack of fluid 18 flow will occur, for example, whenever a connection is made in the drill string 16 (e.g., to add another length of drill pipe to the drill string as the wellbore 12 is drilled deeper), and the lack of circulation will require that downhole pressure be regulated solely by the density of the fluid 18.
  • fluid 18 When fluid 18 is not circulating through drill string 16 and annulus 20 (e.g., when a connection is made in the drill string), the fluid is flowed from the pump 68 to the choke manifold 32 via a bypass line 72, 75.
  • the fluid 18 can bypass the standpipe line 26, drill string 16 and annulus 20, and can flow directly from the pump 68 to the mud return line 30, which remains in communication with the annulus 20. Restriction of this flow by the choke 34 will thereby cause pressure to be applied to the annulus 20 (for example, in typical managed pressure drilling).
  • both of the bypass line 75 and the mud return line 30 are in communication with the annulus 20 via a single line 73.
  • the bypass line 75 and the mud return line 30 could instead be separately connected to the wellhead 24, for example, using an additional wing valve (e.g., below the RCD 22), in which case each of the lines 30, 75 would be directly in communication with the annulus 20.
  • Flow of the fluid 18 through the bypass line 72, 75 is regulated by a choke or other type of flow control device 74.
  • Line 72 is upstream of the bypass flow control device 74, and line 75 is downstream of the bypass flow control device.
  • Flow of the fluid 18 through the standpipe line 26 is substantially controlled by a valve or other type of flow control device 76. Since the rate of flow of the fluid 18 through each of the standpipe and bypass lines 26, 72 is useful in determining how wellbore pressure is affected by these flows, the flowmeters 64, 66 are depicted in FIG. 1 as being interconnected in these lines.
  • the rate of flow through the standpipe line 26 could be determined even if only the flowmeters 62, 64 were used, and the rate of flow through the bypass line 72 could be determined even if only the flowmeters 62, 66 were used.
  • the system 10 it should be understood that it is not necessary for the system 10 to include all of the sensors depicted in FIG. 1 and described herein, and the system could instead include additional sensors, different combinations and/or types of sensors, etc.
  • a bypass flow control device 78 and flow restrictor 80 may be used for filling the standpipe line 26 and drill string 16 after a connection is made in the drill string, and for equalizing pressure between the standpipe line and mud return lines 30, 73 prior to opening the flow control device 76. Otherwise, sudden opening of the flow control device 76 prior to the standpipe line 26 and drill string 16 being filled and pressurized with the fluid 18 could cause an undesirable pressure transient in the annulus 20 (e.g., due to flow to the choke manifold 32 temporarily being lost while the standpipe line and drill string fill with fluid, etc.).
  • the standpipe bypass flow control device 78 By opening the standpipe bypass flow control device 78 after a connection is made, the fluid 18 is permitted to fill the standpipe line 26 and drill string 16 while a substantial majority of the fluid continues to flow through the bypass line 72, thereby enabling continued controlled application of pressure to the annulus 20.
  • the flow control device 76 can be opened, and then the flow control device 74 can be closed to slowly divert a greater proportion of the fluid 18 from the bypass line 72 to the standpipe line 26.
  • a similar process can be performed, except in reverse, to gradually divert flow of the fluid 18 from the standpipe line 26 to the bypass line 72 in preparation for adding more drill pipe to the drill string 16. That is, the flow control device 74 can be gradually opened to slowly divert a greater proportion of the fluid 18 from the standpipe line 26 to the bypass line 72, and then the flow control device 76 can be closed.
  • flow control device 78 and flow restrictor 80 could be integrated into a single element (e.g., a flow control device having a flow restriction therein), and the flow control devices 76, 78 could be integrated into a single flow control device 81 (e.g., a single choke which can gradually open to slowly fill and pressurize the standpipe line 26 and drill string 16 after a drill pipe connection is made, and then open fully to allow maximum flow while drilling).
  • a single element e.g., a flow control device having a flow restriction therein
  • flow control devices 76, 78 could be integrated into a single flow control device 81 (e.g., a single choke which can gradually open to slowly fill and pressurize the standpipe line 26 and drill string 16 after a drill pipe connection is made, and then open fully to allow maximum flow while drilling).
  • the individually operable flow control devices 76, 78 preserve the use of the flow control device 76.
  • the flow control devices 76, 78 are at times referred to collectively below as though they are the single flow control device 81, but it should be understood that the flow control device 81 can include the individual flow control devices 76, 78.
  • FIG. 2 Another example is representatively illustrated in FIG. 2 .
  • the flow control device 76 is connected upstream of the rig's standpipe manifold 70.
  • This arrangement has certain benefits, such as, no modifications are needed to the rig's standpipe manifold 70 or the line between the manifold and the kelly, the rig's standpipe bleed valve 82 can be used to vent the standpipe 26 as in normal drilling operations (no need to change procedure by the rig's crew), etc.
  • the flow control device 76 can be interconnected between the rig pump 68 and the standpipe manifold 70 using, for example, quick connectors 84 (such as, hammer unions, etc.). This will allow the flow control device 76 to be conveniently adapted for interconnection in various rigs' pump lines.
  • a specially adapted fully automated flow control device 76 (e.g., controlled automatically by the controller 96 depicted in FIG. 3 ) can be used for controlling flow through the standpipe line 26, instead of using the conventional standpipe valve in a rig's standpipe manifold 70.
  • the entire flow control device 81 can be customized for use as described herein (e.g., for controlling flow through the standpipe line 26 in conjunction with diversion of fluid 18 between the standpipe line and the bypass line 72 to thereby control pressure in the annulus 20, etc.), rather than for conventional drilling purposes.
  • a remotely controllable valve or other flow control device 160 is optionally used to divert flow of the fluid 18 from the standpipe line 26 to the mud return line 30 downstream of the choke manifold 32, in order to transmit signals, data, commands, etc. to downhole tools (such as the FIG. 1 bottom hole assembly including the sensors 60, other equipment, including mud motors, deflection devices, steering controls, etc.).
  • the device 160 is controlled by a telemetry controller 162, which can encode information as a sequence of flow diversions detectable by the downhole tools (e.g., a certain decrease in flow through a downhole tool will result from a corresponding diversion of flow by the device 160 from the standpipe line 26 to the mud return line 30).
  • a suitable telemetry controller and a suitable remotely operable flow control device are provided in the GEO-SPAN(TM) system marketed by Halliburton Energy Services, Inc.
  • the telemetry controller 162 can be connected to the INSITE(TM) system or other acquisition and control interface 94 in the control system 90.
  • INSITE(TM) acquisition and control interface 94 in the control system 90.
  • other types of telemetry controllers and flow control devices may be used in keeping with the scope of this disclosure.
  • each of the flow control devices 74, 76, 78 and chokes 34 are preferably remotely and automatically controllable to maintain a desired downhole pressure by maintaining a desired annulus pressure at or near the surface.
  • any one or more of these flow control devices 74, 76, 78 and chokes 34 could be manually controlled, in keeping with the scope of this disclosure.
  • a pressure and flow control system 90 which may be used in conjunction with the system 10 and associated methods of FIGS. 1 & 2 is representatively illustrated in FIG. 3 .
  • 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. 3 , 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 a desired annulus pressure at or near the surface to achieve a desired downhole 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 hydraulics model 92 operates to maintain a substantially continuous flow of real-time data from the sensors 44, 54, 66, 62, 64, 60, 58, 46, 36, 38, 40, 56, 67 to the hydraulics model 92, so that the hydraulics model has the information they need to adapt to changing circumstances and to update the desired annulus pressure, and the hydraulics model operates to supply the data acquisition and control interface substantially continuously with a value for the desired annulus pressure.
  • a suitable hydraulics model for use as the hydraulics model 92 in the control system 90 is REAL TIME HYDRAULICS (TM) or GB SETPOINT (TM) marketed 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) marketed 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 mud return choke 34 and other devices.
  • the controller 96 may also be used to control operation of the standpipe flow control devices 76, 78 and the bypass flow control device 74.
  • the controller 96 can, thus, be used to automate the processes of diverting flow of the fluid 18 from the standpipe line 26 to the bypass line 72 prior to making a connection in the drill string 16, then diverting flow from the bypass line to the standpipe line after the connection is made, and then resuming normal circulation of the fluid 18 for drilling. Again, no human intervention may be required in these automated processes, although human intervention may be used if desired, for example, to initiate each process in turn, to manually operate a component of the system, etc.
  • Data validation and prediction techniques may be used in the system 90 to guard against erroneous data being used, to ensure that determined values are in line with predicted values, etc. Suitable data validation and prediction techniques are described in International Application No. PCT/US11/59743 , although other techniques may be used, if desired.
  • the controller used the desired annulus pressure as a setpoint and controlled operation of the choke 34 in a manner (e.g., increasing or decreasing flow resistance through the choke as needed) to maintain the setpoint pressure in the annulus 20.
  • the choke 34 was closed more to increase flow resistance, or opened more to decrease flow resistance.
  • the setpoint pressure was accomplished by comparing the setpoint pressure to a measured annulus pressure (such as the pressure sensed by any of the sensors 36, 38, 40), and decreasing flow resistance through the choke 34 if the measured pressure is greater than the setpoint pressure, and increasing flow resistance through the choke if the measured pressure is less than the setpoint pressure.
  • a measured annulus pressure such as the pressure sensed by any of the sensors 36, 38, 40
  • the adjustment of the choke was typically determined by a proportional integral derivative (PID) controller, and so (depending on the coefficients input to the PID controller) the choke could easily be over- or under-adjusted, or it could take an extended length of time to progress through a number of increments needed to finally position the choke where it should be positioned to maintain the desired annulus pressure.
  • such rapidly changing drilling conditions can be more quickly responded to by adding an offset to the pressure setpoint. Adding the offset to the pressure setpoint will result in the choke 34 more rapidly being adjusted to a position appropriate for controlling the changed drilling conditions. When relatively steady state conditions have resumed, the offset can be removed, so that the controller 96 will adjust the choke 34 to maintain the desired pressure setpoint in the well.
  • a method 100 of controlling pressure in a wellbore is representatively illustrated in simplified flowchart form.
  • the method 100 may be used with the system 10 described above, or it may be used with other systems.
  • a desired setpoint pressure is determined.
  • the setpoint pressure corresponds to a pressure in the annulus 20 at or near the wellhead 24.
  • the pressure may be measured at any point upstream of the choke manifold 32.
  • the pressure setpoint could be for a location other than at the wellhead 24.
  • the pressure setpoint could be for a downhole location (such as, at a casing shoe, at a sensitive formation, at a bottom of the wellbore 12, etc.).
  • a surface or downhole actual pressure measurement may be used for comparison to the pressure setpoint by the controller 96.
  • an actual well pressure is measured.
  • the pressure measurement can be made at any well location.
  • surface pressure sensors 36, 38, 40 or downhole sensors 60 (or subsea sensors) may be used for the pressure measurement.
  • step 106 the actual well pressure deviates from the desired pressure setpoint.
  • the comparison between the actual and desired well pressures is performed by the controller 96.
  • the choke 34 is automatically adjusted by the controller 96 as needed to minimize (or, ideally, to eliminate) this deviation.
  • the method 100 provides an added "boost" to the pressure setpoint (in a direction in which the actual pressure needs to change in order to move toward the desired pressure), so that the controller 96 will more rapidly adjust the choke 34 to a position in which the actual pressure will be at or near the desired pressure.
  • an offset is added to the desired pressure setpoint, if a difference between the actual and desired pressures is more than a predetermined amount.
  • the predetermined amount is chosen so that, during relatively steady state drilling operations, the offset will not be added to the pressure setpoint.
  • the offset is only added if the difference between the actual and desired pressures is sufficiently large.
  • step 110 the controller 96 adjusts the choke 34 as needed to influence the actual pressure toward the pressure setpoint plus the offset added in step 108. For example, if the actual pressure is sufficiently less than the pressure setpoint, a positive offset could be added to the setpoint, so that the controller 96 operates the choke 34 to initially restrict the flow of the fluid 18 from the annulus 20 more than it would if only the pressure setpoint were used by the controller to control operation of the choke. Conversely, if the actual pressure is sufficiently greater than the pressure setpoint, a negative offset could be added to the setpoint, so that the controller 96 operates the choke 34 to initially restrict the flow of the fluid 18 from the annulus 20 less than it would if only the pressure setpoint were used by the controller to control operation of the choke.
  • step 112 the offset is no longer used when the relatively steady state drilling operations resume. If the large deviation which triggered use of the offset is not present, then the offset is removed, so that the controller 96 again operates the choke 34 to maintain the actual pressure at the desired pressure setpoint (without the offset).
  • FIGS. 5A & B a more detailed example of the method 100 is representatively illustrated in flowchart form.
  • the FIGS. 5A & B example is merely one application of the principles of this disclosure to a particular drilling situation, but a wide variety of other drilling situations can benefit from this disclosure's principles, and so it should be clearly understood that the scope of this disclosure is not limited at all to any of the details of the system 10 or method 100 depicted in the drawings or described herein.
  • FIGS. 5A & B flowchart is for a routine named "Lead Chokes" to indicate its use in more rapidly advancing the choke(s) 34 toward their appropriate position for maintaining the actual pressure at the desired pressure setpoint.
  • the drilling situation addressed by the routine is one in which a sudden decrease in flow through the choke 34 causes a sudden large drop in pressure upstream of the choke. Such a situation could occur, for example, if the flow rate from the mud pump 68 suddenly decreases, if another flow control device malfunctions or is improperly operated, a large fluid loss is experienced downhole, etc.
  • the offset can be the preselected offset ( Pumps_Down_Offset ) for this particular drilling situation.
  • the pressure setpoint plus the offset would be greater than the desired pressure at the control depth ( CD_Target ) minus the hydrostatic pressure at that depth ( CD_Hydrostatic )
  • the offset can be reduced to the difference between the desired pressure at the control depth minus the hydrostatic pressure at that depth. This is to mitigate the possibility that the choke 34 could restrict flow too much with the addition of the offset to the pressure setpoint, so that excess pressure is applied at the control depth.
  • the method 100 can be used to control the choke 34 as needed to quickly restore a desired wellbore pressure.
  • an offset can be added to a desired wellbore 12 pressure setpoint, so that the choke 34 is more rapidly adjusted as needed to maintain the desired pressure in the wellbore.
  • a method 100 of controlling pressure in a wellbore 12 in a well drilling operation comprises: determining a desired well pressure setpoint; adding an offset to the well pressure setpoint in response to an actual well pressure deviating from the well pressure setpoint by a predetermined amount; and adjusting a flow control device (e.g., the choke 34), thereby influencing the actual well pressure toward the well pressure setpoint plus the offset.
  • a flow control device e.g., the choke 34
  • the desired well pressure setpoint can be output by a hydraulics model 92.
  • the offset adding may also be performed in response to a predetermined level of change in flow.
  • the predetermined level of change in flow may comprise a decrease in flow through the flow control device (e.g., the choke 34).
  • the method can also include removing the offset in response to the actual well pressure deviating from the well pressure setpoint by less than the predetermined amount.
  • the flow control device may comprise a choke 34 which restricts flow of fluid from the wellbore 12.
  • the method can also include controlling the flow control device, thereby influencing the actual well pressure toward the well pressure setpoint without the offset, prior to adding the offset to the setpoint.
  • the well system 10 can include a flow control device which variably restricts flow from a wellbore 12, and a control system 90 which determines a desired well pressure setpoint, compares the well pressure setpoint to an actual well pressure, and adds an offset to the desired well pressure setpoint in response to a predetermined amount of deviation between the well pressure setpoint and the actual well pressure.
  • the control system 90 adjusts the flow control device, and thereby influences the actual well pressure toward the well pressure setpoint plus the offset.
  • Another example of the method 100 of controlling pressure in a wellbore 12 in a well drilling operation can comprise: operating a flow control device, thereby influencing an actual well pressure toward a desired well pressure setpoint; then adding an offset to the well pressure setpoint in response to an actual well pressure deviating from the well pressure setpoint by a predetermined amount; and then adjusting the flow control device, thereby influencing the actual well pressure toward the well pressure setpoint plus the offset.

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Claims (8)

  1. Procédé de commande de pression dans un puits de forage dans une opération de forage de puits, le procédé comprenant :
    la détermination d'un point de consigne de pression de puits souhaité ;
    la comparaison du point de consigne de pression de puits avec une pression de puits réelle mesurée et l'ajustement d'un dispositif de commande d'écoulement, orientant ainsi la pression de puits réelle vers le point de consigne de pression de puits ;
    en réponse à une pression de puits réelle mesurée s'écartant du point de consigne de pression de puits d'une quantité prédéterminée :
    l'ajout d'un décalage au point de consigne de pression de puits ;
    l'ajustement d'un dispositif de commande d'écoulement, orientant ainsi la pression de puits réelle vers le point de consigne de pression de puits ainsi que le décalage ; et
    le retrait du décalage en réponse à la pression de puits réelle s'écartant du point de consigne de pression de puits d'une quantité inférieure à la quantité prédéterminée.
  2. Procédé selon la revendication 1, dans lequel le point de consigne de pression de puits souhaité est délivré par un modèle hydraulique (92).
  3. Procédé selon la revendication 1, dans lequel l'ajout est en outre réalisé en réponse à un niveau de changement d'écoulement prédéterminé, de préférence dans lequel le niveau de changement d'écoulement prédéterminé comprend une diminution de l'écoulement à travers le dispositif de commande d'écoulement.
  4. Procédé selon la revendication 1, dans lequel le dispositif de commande d'écoulement comprend un étranglement (34) qui limite l'écoulement de fluide depuis le puits de forage (12).
  5. Système de puits (10) comprenant :
    un dispositif de commande d'écoulement conçu pour limiter l'écoulement de manière variable depuis un puits de forage (12) ; et
    un système de commande (90) conçu pour déterminer un point de consigne de pression de puits souhaité, compare le point de consigne de pression de puits avec une pression de puits réelle mesurée et ajuste le dispositif de commande d'écoulement pour orienter la pression de puits réelle vers le point de consigne de pression de puits, et
    en réponse à une quantité d'écart prédéterminée entre le point de consigne de pression de puits et la pression de puits réelle mesurée :
    ajoute un décalage au point de consigne de pression de puits souhaité ;
    ajuste le dispositif de commande d'écoulement pour orienter la pression de puits réelle vers le point de consigne de pression de puits ainsi que le décalage ; et
    retire le décalage en réponse à l'écart entre la pression de puits réelle et le point de consigne de pression de puits étant inférieur à la quantité prédéterminée.
  6. Système selon la revendication 5, dans lequel le système de commande (90) comprend un modèle hydraulique (92) et dans lequel le point de consigne de pression de puits est délivré par le modèle hydraulique.
  7. Système selon la revendication 5, dans lequel le système de commande (90) est conçu pour ajouter le décalage au point de consigne de pression de puits en réponse à un niveau de changement d'écoulement prédéterminé, de préférence dans lequel le niveau de changement d'écoulement prédéterminé comprend une diminution de l'écoulement à travers le dispositif de commande d'écoulement.
  8. Système selon la revendication 5, dans lequel le dispositif de commande d'écoulement comprend un étranglement automatiquement ajustable.
EP12880400.2A 2012-07-02 2012-07-02 Régulation de la pression dans les opérations de forage avec application d'un décalage en réaction à des conditions prédéterminées Active EP2867439B1 (fr)

Applications Claiming Priority (1)

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PCT/US2012/045239 WO2014007798A1 (fr) 2012-07-02 2012-07-02 Régulation de la pression dans les opérations de forage avec application d'un décalage en réaction à des conditions prédéterminées

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EP2867439B1 true EP2867439B1 (fr) 2018-03-14

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US (1) US20140290964A1 (fr)
EP (1) EP2867439B1 (fr)
AU (1) AU2012384530B2 (fr)
BR (1) BR112014032853B8 (fr)
CA (1) CA2877702A1 (fr)
DK (1) DK2867439T3 (fr)
MX (1) MX359485B (fr)
NO (1) NO2867439T3 (fr)
RU (1) RU2598661C2 (fr)
SA (1) SA113340678B1 (fr)
WO (1) WO2014007798A1 (fr)

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CA3072992A1 (fr) * 2017-11-29 2019-06-06 Halliburton Energy Services, Inc. Systeme de commande de pression automatise

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US5273112A (en) * 1992-12-18 1993-12-28 Halliburton Company Surface control of well annulus pressure
US20020112888A1 (en) * 2000-12-18 2002-08-22 Christian Leuchtenberg Drilling system and method
US6484816B1 (en) * 2001-01-26 2002-11-26 Martin-Decker Totco, Inc. Method and system for controlling well bore pressure
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WO2003071091A1 (fr) * 2002-02-20 2003-08-28 Shell Internationale Research Maatschappij B.V. Appareil et procede de regulation de pression dynamique annulaire
MXPA06001754A (es) * 2003-08-19 2006-05-12 Shell Int Research Sistema y metodo de perforacion.
US20050092523A1 (en) * 2003-10-30 2005-05-05 Power Chokes, L.P. Well pressure control system
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GB2477880B (en) * 2008-12-19 2012-12-19 Halliburton Energy Serv Inc Pressure and flow control in drilling operations
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BR112014032853A2 (pt) 2017-06-27
US20140290964A1 (en) 2014-10-02
BR112014032853B8 (pt) 2021-03-30
AU2012384530A1 (en) 2015-02-26
DK2867439T3 (en) 2018-06-14
RU2598661C2 (ru) 2016-09-27
EP2867439A4 (fr) 2016-04-27
MX2014015369A (es) 2015-07-06
MX359485B (es) 2018-09-07
CA2877702A1 (fr) 2014-01-09
AU2012384530B2 (en) 2016-09-22
BR112014032853B1 (pt) 2021-01-26
NO2867439T3 (fr) 2018-08-11
SA113340678B1 (ar) 2016-01-27
EP2867439A1 (fr) 2015-05-06
RU2015102060A (ru) 2016-08-20
WO2014007798A1 (fr) 2014-01-09

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