WO2012158155A1 - Unité mobile d'optimisation de pression pour des opérations de forage - Google Patents

Unité mobile d'optimisation de pression pour des opérations de forage Download PDF

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Publication number
WO2012158155A1
WO2012158155A1 PCT/US2011/036616 US2011036616W WO2012158155A1 WO 2012158155 A1 WO2012158155 A1 WO 2012158155A1 US 2011036616 W US2011036616 W US 2011036616W WO 2012158155 A1 WO2012158155 A1 WO 2012158155A1
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WO
WIPO (PCT)
Prior art keywords
optimization unit
pressure optimization
pressure
conveyance
drilling
Prior art date
Application number
PCT/US2011/036616
Other languages
English (en)
Inventor
James R. Lovorn
Malcolm E. WHITTAKER
Derrick W. Lewis
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
Application filed by Halliburton Energy Services, Inc. filed Critical Halliburton Energy Services, Inc.
Priority to PCT/US2011/036616 priority Critical patent/WO2012158155A1/fr
Priority to EP11865460.7A priority patent/EP2710216A4/fr
Priority to MX2013013366A priority patent/MX2013013366A/es
Priority to US13/406,730 priority patent/US20120292108A1/en
Priority to US13/422,666 priority patent/US20120292109A1/en
Publication of WO2012158155A1 publication Critical patent/WO2012158155A1/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
    • 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
    • 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
    • E21B2200/00—Special features related to earth drilling for obtaining oil, gas or water
    • E21B2200/22—Fuzzy logic, artificial intelligence, neural networks or the like

Definitions

  • the present disclosure relates generally to equipment utilized and operations performed in conjunction with well drilling operations and, in an embodiment described herein, more particularly provides a mobile pressure optimization unit for use in drilling operations.
  • Optimized pressure drilling is the art of precisely controlling wellbore pressure during drilling by utilizing a closed annulus and a means for regulating pressure in the annulus.
  • the annulus is typically closed during drilling through use of a rotating control device (RCD, also known as a rotating control head or rotating blowout preventer) which seals about the drill pipe as it rotates.
  • RCD rotating control device
  • Precise control of wellbore pressure is important for preventing formation damage, preventing loss of drilling fluids, controlling or preventing flow of formation fluids into the wellbore, etc. It will, therefore, be appreciated that improvements would be beneficial in the art of controlling pressure and flow in drilling operations.
  • FIG. 1 is a representative view of a well drilling system and method embodying principles of this disclosure.
  • FIG. 1A is a representative view of another
  • FIG. 2 is a representative block diagram of a control system which may be used in the well drilling system.
  • FIG. 3 is a representative side view of a mobile pressure optimization unit, which can embody principles of this disclosure, incorporated into a wheeled vehicle.
  • FIG. 4 is a representative side view of the mobile pressure optimization unit incorporated into a floating vessel .
  • FIG. 5 is a representative plan view of the mobile pressure optimization unit.
  • FIG. 6 is a representative side view of the mobile pressure optimization unit, integrated with a frame of a conveyance used to transport the unit.
  • FIG. 1 Representatively and schematically illustrated in FIG. 1
  • a well drilling 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 drill string 16.
  • Drilling fluid 18, commonly known as mud 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 or plunger-type check valve
  • Control of wellbore pressure is very important in optimized pressure drilling (e.g., managed pressure
  • 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, excessive 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
  • RCD rotating control device 22
  • the RCD 22 seals about the drill string 16 above a wellhead 24.
  • the drill string 16 extending upwardly through the RCD 22 would connect to, for example, a rotary table (not shown), a standpipe 26, a kelly (not shown), a top drive and/or other conventional drilling equipment.
  • wellbore pressure is optimized through use of a pressure optimization unit 11.
  • the pressure optimization unit 11 can be
  • optimization unit 11 includes a choke manifold 32, a flow diverter 84 and a backpressure pump 86. Each of these is automatically controllable by a control system 90, in a manner more fully described below.
  • the pressure optimization unit 11 may also include an RCD clamp control 98, an RCD lubricant supply 100 and a fluid analysis system 102. However, note that it is not necessary for the pressure optimization unit 11 to include all of these elements. For example, it is contemplated that the pressure optimization unit 11 will preferably include either the flow diverter 84 or the backpressure pump 86, but not both. Of course, the pressure optimization unit 11 can include additional elements, in keeping with the scope of this disclosure.
  • the pressure optimization unit 11 can be conveniently interconnected to a rig's drilling system using flexible lines 104a-g. Rigid lines may also (or alternatively) be used for this purpose, if desired.
  • the pressure optimization unit 11 is equipped with hydraulically powered reels 106 (not shown in FIG. 1, see FIG. 5) for storing and deploying the lines 104a-g.
  • 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 the 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 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 , 88 .
  • the system 10 could include only two of the three flowmeters 62 , 64 , 66 .
  • input from all available sensors is useful to the hydraulics model in determining what the pressure applied to the annulus 20 should be during the drilling operation.
  • the flowmeter 58 it is not necessary for the flowmeter 58 to 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
  • Various forms of wired or wireless 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.
  • 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 flowmeter ( s ) .
  • 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 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.
  • flow of the fluid 18 through the choke 34 can be maintained, even though the fluid does not circulate through the drill string 16 and annulus 20, while a connection is being made in the drill string, and/or while the drill string is being tripped into or out of the wellbore 12.
  • a flow diverter 84 may be used to divert flow from the rig mud pump 68 to the mud return line 30, or a backpressure pump 86 may be used to supply flow through the choke manifold 32, and thereby enable precise control over pressure in the wellbore 12.
  • pressure can still be applied to the annulus 20 by restricting flow of the fluid 18 through the choke 34, even while the fluid does not circulate through the drill string 16.
  • the fluid 18 can be flowed from the rig mud pump 68 to the choke manifold 32 via a bypass line 72, 75 when fluid 18 does not flow through the drill string 16.
  • the fluid 18 can bypass the standpipe 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) .
  • the fluid 18 can be flowed from the backpressure pump 86 to the annulus 20 and, since the annulus is connected to the choke manifold 32 via the return line 73, 30, this will supply flow through the choke 34, so that wellbore pressure can be controlled by variably
  • 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 26 is substantially controlled by a valve or other type of flow control device 76.
  • the flow control devices 74, 76 are independently controllable, which provides substantial benefits to the system 10, as described more fully below. Since the rate of flow of the fluid 18 through each of the standpipe 26 and bypass line 72 is useful in determining how bottom hole pressure is affected by these flows, the flowmeters 64, 66 are depicted in FIG. 1 as being
  • the rate of flow through the standpipe 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.
  • system 10 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 26 and drill string 16 after a connection is made in the drill string, and for equalizing pressure between the standpipe 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 and drill string fill with fluid, etc.).
  • the fluid 18 is permitted to fill the standpipe 26 and drill string 16 while a
  • the flow control device 76 can be opened, and then the flow control device 74 can be closed to slowly divert a greater
  • a similar process can be performed, except in reverse, to gradually divert flow of the fluid 18 from the standpipe 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 26 to the bypass line 72, and then the flow control device 76 can be closed.
  • the flow control device 76 can be part of a flow diversion manifold 81 interconnected between the rig mud pump 68 and the rig standpipe manifold 70.
  • the RCD clamp control 98 is used to remotely operate a clamp (not visible in FIG. 1) of the RCD 22.
  • the clamp is for permitting access to a seal and a bearing assembly of the RCD 22. Examples of electrical and hydraulic remote control of RCD clamps are described in International
  • hydraulic pressure may be supplied to the RCD clamp control 98 from a conveyance (e.g., vehicle, vessel, etc.) which transports the pressure optimization unit 11 to the rig site.
  • the fluid analysis system 102 is used to determine properties of the fluid 18 which flows from the annulus 20 to the pressure optimization unit 11.
  • the fluid analysis system 102 may include, for example, a gas analyzer which extracts gas from the fluid 18 and determines its
  • composition a gas spectrometer, a densitometer, a
  • the gas analyzer may be similar to an
  • the fluid analysis system 102 may include a real time rheology analyzer, which continuously monitors rheological properties of the fluid 18 and transmits this data to the hydraulics model 92.
  • a suitable rheology analyzer for use in the fluid analysis system 102 is described in U.S.
  • bypass line 75 is connected to a third choke 82.
  • the bypass line 75 remains connected to the return line 30 also, but the choke 82 provides for convenient regulation of the amount of fluid 18 discharged from the flow diverter 84.
  • a pressure and flow control system 90 which may be used in conjunction with the system 10 and associated method of FIGS. 1 & 1A 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 downhole pressure.
  • Data such as well geometry, fluid properties and offset well
  • 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 44 , 54 , 66 , 62 , 64 , 60 , 58 , 46 , 36 , 38 , 40 , 56 , 67 , 88 and fluid analysis system 102 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 20 pressure.
  • 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, in part by controlling operation of the mud return choke 34 .
  • 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 resistance through the choke as needed) to maintain the setpoint pressure in the annulus 20 .
  • the choke 34 can be closed more to increase flow resistance, or opened more to decrease flow resistance.
  • Maintenance of the setpoint pressure is 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
  • 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 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 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 after the connection is made, and then resuming normal circulation of the fluid 18 for drilling. Again, no human intervention may be
  • the control system 90 also preferably includes a predictive device 148 and a data validator 150.
  • predictive device 148 preferably comprises one or more neural network models for predicting various well
  • parameters could include outputs of any of the sensors 36, 38, 40, 44, 46, 54, 56, 58, 60, 62, 64, 66, 67, 88, 102, the annulus pressure setpoint output from the hydraulics model 92, positions of flow control devices 34, 74, 76, 78, drilling fluid 18 density, etc. Any well
  • parameter may be predicted by the predictive device 148.
  • the predictive device 148 is preferably "trained” by inputting present and past actual values for the parameters to the predictive device. Terms or “weights" in the predictive device 148 may be adjusted based on derivatives of output of the predictive device with respect to the terms .
  • the predictive device 148 may be trained by inputting to the predictive device data obtained during drilling, while making connections in the drill string 16, and/or during other stages of an overall drilling operation.
  • the predictive device 148 may be trained by inputting to the predictive device data obtained while drilling at least one prior wellbore.
  • the training may include inputting to the predictive device 148 data indicative of past errors in predictions produced by the predictive device.
  • the predictive device 148 may be trained by inputting data generated by a computer simulation of the well drilling system 10 (including the drilling rig, the well, equipment utilized, etc.).
  • the predictive device 148 can accurately predict or estimate what value one or more parameters should have in the present and/or future.
  • the predicted parameter values can be supplied to the data validator 150 for use in its data validation processes.
  • the predictive device 148 does not necessarily comprise one or more neural network models.
  • Other types of predictive devices which may be used include an artificial intelligence device, an adaptive model, a nonlinear function which generalizes for real systems, a genetic algorithm, a linear system model, and/or a nonlinear system model, combinations of these, etc.
  • the predictive device 148 may perform a regression analysis, perform regression on a nonlinear function and may utilize granular computing.
  • An output of a first principle model may be input to the predictive device 148 and/or a first principle model may be included in the predictive device .
  • the predictive device 148 receives the actual parameter values from the data validator 150, which can include one or more digital programmable processors, memory, etc.
  • the data validator 150 uses various pre-programmed algorithms to determine whether sensor measurements, flow control device positions, etc., received from the data acquisition & control interface 94 are valid.
  • a received actual parameter value is outside of an acceptable range, unavailable (e.g., due to a non-functioning sensor) or differs by more than a
  • the data validator 150 may flag that actual parameter value as being "invalid.” Invalid parameter values may not be used for training the predictive device 148, or for determining the desired annulus pressure setpoint by the hydraulics model 92. Valid parameter values would be used for training the predictive device 148, for updating the hydraulics model 92, for recording to the data acquisition & control
  • the desired annulus pressure setpoint may be
  • the desired annulus pressure setpoint is communicated from the hydraulics model 92 to the data acquisition & control interface 94 for recording in its database, and for relaying to the data validator 150 with the other actual parameter values.
  • the desired annulus pressure setpoint is communicated from the hydraulics model 92 to the predictive device 148 for use in predicting future annulus pressure setpoints.
  • the predictive device 148 could receive the desired annulus pressure setpoint (along with the other actual parameter values) from the data validator 150 in other examples .
  • the desired annulus pressure setpoint is communicated from the hydraulics model 92 to the controller 96 for use in case the data acquisition & control interface 94 or data validator 150 malfunctions, or output from these other devices is otherwise unavailable. In that circumstance, the controller 96 could continue to control operation of the various flow control devices 34, 74, 76, 78 to
  • the predictive device 148 is trained in real time, and is capable of predicting current values of one or more sensor measurements based on the outputs of at least some of the other sensors. Thus, if a sensor output becomes
  • the predictive device 148 can supply the missing sensor measurement values to the data validator 150, at least temporarily, until the sensor output again becomes available .
  • the data validator 150 can substitute the predicted flowmeter output for the actual (or nonexistent) flowmeter output. It is contemplated that, in actual practice, only one or two of the flowmeters 62, 64, 66 may be used. Thus, if the data validator 150 ceases to receive valid output from one of those flowmeters, determination of the proportions of fluid 18 flowing through the standpipe 26 and bypass line 72 could not be readily accomplished, if not for the predicted parameter values output by the predictive device 148. It will be appreciated that measurements of the proportions of fluid 18 flowing through the standpipe 26 and bypass line 72 are very useful, for example, in calculating equivalent circulating density and/or friction pressure by the hydraulics model 92 during the drill string connection process .
  • Validated parameter values are communicated from the data validator 150 to the hydraulics model 92 and to the controller 96.
  • the hydraulics model 92 utilizes the
  • the data validator 150 is programmed to examine the individual parameter values received from the data
  • the data validator 150 may send a signal to the predictive device 148 to stop training the neural network model for the faulty sensor, and to stop training the other models which rely upon parameter values from the faulty sensor to train.
  • the predictive device 148 may stop training one or more neural network models when a sensor fails, it can continue to generate predictions for output of the faulty sensor or sensors based on other, still functioning sensor inputs to the predictive device.
  • the data validator 150 can substitute the predicted sensor parameter values from the predictive device 148 to the controller 96 and the hydraulics model 92. Additionally, when the data validator 150 determines that a sensor is malfunctioning or its output is unavailable, the data validator can generate an alarm and/or post a warning, identifying the malfunctioning sensor, so that an operator can take corrective action.
  • the predictive device 148 is preferably also able to train a neural network model representing the output of the hydraulics model 92.
  • a predicted value for the desired annulus pressure setpoint is communicated to the data validator 150. If the hydraulics model 92 has difficulties in generating proper values or is unavailable, the data validator 150 can substitute the predicted desired annulus pressure setpoint to the controller 96.
  • the pressure optimization unit 11 is representatively illustrated as being incorporated into a conveyance 110.
  • the conveyance 110 comprises a wheeled vehicle 108 on which the pressure optimization unit 11 is transported, but in other examples the conveyance is not necessarily a wheeled vehicle.
  • the vehicle 108 illustrated in FIG. 3 is a tractor- trailer, with the pressure optimization unit 11 being incorporated into the trailer portion of the vehicle.
  • the vehicle 108 could be a bobtail truck (i.e., without a trailer being towed behind the truck) or another type of wheeled vehicle.
  • the pressure optimization unit 11 is incorporated into the conveyance 110, so that it is part of the conveyance, and is not a separately transportable element.
  • the pressure optimization unit 11 is incorporated into the conveyance 110, so that it is part of the conveyance, and is not a separately transportable element.
  • the pressure optimization unit 11 is incorporated into the conveyance 110, so that it is part of the conveyance, and is not a separately transportable element.
  • the pressure optimization unit 11 is incorporated into the conveyance 110, so that it is part of the conveyance, and is not a separately transportable element.
  • the pressure optimization unit 11 is incorporated into the conveyance 110, so that it is part of the conveyance, and is not a separately transportable element.
  • optimization unit 11 could be separately transported (such as, on a flat bed trailer, etc.).
  • optimization unit 11 is incorporated into a floating vessel 112 (such as a barge, a ship, a floating production, storage and offloading (FPSO) vessel, etc.).
  • a floating vessel 112 such as a barge, a ship, a floating production, storage and offloading (FPSO) vessel, etc.
  • the pressure optimization unit 11 is preferably incorporated into the conveyance 110, so that it is part of the conveyance, and is not an element separately
  • pressure optimization unit 11 could be any pressure optimization unit 11.
  • the pressure optimization unit 11 includes the choke manifold 32, the Coriolis flowmeter 58, the flow diverter 84, the control system 90, the fluid analysis system 102 and the reels 106, along with a command center 114 for human
  • the command center 114 can include workstations 116 for human-machine
  • the fluid analysis system 102 in this example includes both a gas analysis system 120 and a rheology measurement system 122.
  • the gas analysis system 120 may be similar to the EAGLE (TM) system marketed by Halliburton Energy
  • Rheological properties measured by the system 122 can include density, oil/water ratio, specific gravity, chloride amount, electric stability, shear stress, gel strength, viscosity and/or yield point.
  • Pipe racks 124 may be provided for storing rigid lines. Electrical power, as well as hydraulic and pneumatic
  • pressure may be supplied to the pressure optimization unit 11 via lines 126 from the vehicle 108 or vessel 112.
  • FIG. 6 one manner in which the pressure optimization unit 11 can be integrated into the conveyance 110 is representatively illustrated.
  • the choke 34 is rigidly attached to a frame 128 of the vehicle 108 or vessel 112.
  • FIG. 6 it will be appreciated that any or all of the elements of the pressure optimization unit 11 can be integrated into the vehicle 108 or vessel 112 in keeping with the scope of this disclosure.
  • the pressure optimization unit 11 By rigidly attaching the choke 34 and/or other elements of the pressure optimization unit 11 to the frame 128 of the vehicle 108 or vessel 112, the pressure optimization unit is incorporated into, and becomes a part of, the conveyance 110. However, in other examples, the pressure optimization unit 11 may not be incorporated into the conveyance 110 (such as, if the pressure optimization unit is transported to the rig site on a flat bed trailer or on a work boat, etc . ) . In practice, the pressure optimization unit 11 is preferably transported to the rig site as part of the conveyance 110. Without offloading the pressure optimization unit 11 from the vehicle 108 or vessel 112, the pressure optimization unit is interconnected to the various items of drilling equipment using the lines 104a-g, and is
  • the pressure optimization unit 11 may be offloaded at the rig site. In these situations, the process of
  • Trains and aircraft are additional examples of suitable conveyances whereby the pressure optimization unit 11 can be made mobile.
  • the pressure optimization unit 11 described above can be conveniently transported to a rig site, and can be interconnected to rig drilling
  • the above disclosure describes a well drilling method.
  • the method can include transporting a pressure optimization unit 11 to a rig site, the pressure optimization unit 11 including a choke manifold 32, a control system 90 which automatically controls operation of the choke manifold 32, and a flowmeter 58 which measures flow of drilling fluid 18 through the choke manifold 32, and then interconnecting the pressure optimization unit 11 to rig drilling equipment (e.g., the wellhead 24, standpipe 26, separator 48, shaker 50, mud pit 52, etc.).
  • rig drilling equipment e.g., the wellhead 24, standpipe 26, separator 48, shaker 50, mud pit 52, etc.
  • the method can also include integrating the pressure optimization unit 11 into a conveyance 110.
  • the conveyance 110 may comprise a wheeled vehicle 108 or a floating vessel 112.
  • the integrating step may include rigidly attaching the pressure optimization unit 11 to a frame 128 of the
  • the interconnecting step may include
  • the pressure optimization unit 11 may include a flow diverter 84 which diverts flow of the drilling fluid 18 from a standpipe 26 to the choke manifold 32, a backpressure pump 86 which pressurizes a well annulus 20, a fluid analysis system 102 which comprises a gas analysis system 120 and/or a rheology measurement system 122, a rotating control device clamp control 98 and/or a rotating control device lubricant supply 100.
  • a pressure optimization unit 11 for use with a well drilling system 10. The pressure
  • optimization unit 11 can include a choke manifold 32, a control system 90 which automatically controls operation of the choke manifold 32, and a flowmeter 58 which measures flow of drilling fluid 18 through the choke manifold 32.
  • the choke manifold 32, control system 90 and flowmeter 58 can each be incorporated into a same conveyance 110 which transports the pressure optimization unit 11 to a rig site.
  • the pressure optimization unit 11 may also include a powered reel 106 which stores line 104a-g that connects the pressure optimization unit 11 to rig drilling equipment (e.g., the wellhead 24, standpipe 26, separator 48, shaker 50, mud pit 52, etc.).
  • rig drilling equipment e.g., the wellhead 24, standpipe 26, separator 48, shaker 50, mud pit 52, etc.
  • the pressure optimization unit 11 can be interconnected to rig drilling equipment concurrently with the pressure optimization unit 11 being incorporated into the conveyance 110.

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  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Earth Drilling (AREA)
  • Excavating Of Shafts Or Tunnels (AREA)

Abstract

La présente invention concerne un procédé de forage de puits qui peut consister à transporter une unité d'optimisation de pression jusqu'à un site d'appareil de forage, l'unité d'optimisation de pression comprenant un collecteur de duses, un système de commande qui commande automatiquement le fonctionnement du collecteur de duses, et un débitmètre qui mesure le débit de fluide de forage à travers le collecteur de duses, et ensuite à raccorder mutuellement l'unité d'optimisation de pression et un équipement de forage d'installation de forage. Une unité d'optimisation de pression destinée à être utilisée conjointement avec un système de forage de puits peut comprendre un collecteur de duses, un système de commande, qui commande automatiquement le fonctionnement du collecteur de duses, et un débitmètre, qui mesure le débit de fluide de forage à travers le collecteur de duses. Le collecteur de duses, le système de commande et le débitmètre peuvent être incorporés dans un même transport qui transporte l'unité d'optimisation de pression jusqu'à un site d'appareil de forage.
PCT/US2011/036616 2011-05-16 2011-05-16 Unité mobile d'optimisation de pression pour des opérations de forage WO2012158155A1 (fr)

Priority Applications (5)

Application Number Priority Date Filing Date Title
PCT/US2011/036616 WO2012158155A1 (fr) 2011-05-16 2011-05-16 Unité mobile d'optimisation de pression pour des opérations de forage
EP11865460.7A EP2710216A4 (fr) 2011-05-16 2011-05-16 Unité mobile d'optimisation de pression pour des opérations de forage
MX2013013366A MX2013013366A (es) 2011-05-16 2011-05-16 Unidad movil de optimizacion de presion para operaciones de perforacion.
US13/406,730 US20120292108A1 (en) 2011-05-16 2012-02-28 Mobile pressure optimization unit for drilling operations
US13/422,666 US20120292109A1 (en) 2011-05-16 2012-03-16 Mobile pressure optimization unit for drilling operations

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PCT/US2011/036616 WO2012158155A1 (fr) 2011-05-16 2011-05-16 Unité mobile d'optimisation de pression pour des opérations de forage

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US20120292109A1 (en) 2012-11-22
MX2013013366A (es) 2014-01-08
US20120292108A1 (en) 2012-11-22
EP2710216A1 (fr) 2014-03-26
EP2710216A4 (fr) 2016-01-13

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