US20120292108A1 - Mobile pressure optimization unit for drilling operations - Google Patents

Abstract

A well drilling method can include transporting a pressure optimization unit to a rig site, the pressure optimization unit including a choke manifold, a control system which automatically controls operation of the choke manifold, and a flowmeter which measures flow of drilling fluid through the choke manifold, and then interconnecting the pressure optimization unit to rig drilling equipment. A pressure optimization unit for use with a well drilling system can include a choke manifold, a control system which automatically controls operation of the choke manifold, and a flowmeter which measures flow of drilling fluid through the choke manifold. The choke manifold, control system and flowmeter may be incorporated into a same conveyance which transports the pressure optimization unit to a rig site.

Description

CROSS-REFERENCE TO RELATED APPLICATION
• This application claims the benefit under 35 USC §119 of the filing date of International Application Serial No. PCT/US11/036616, filed 16 May 2011. The entire disclosure of this prior application is incorporated herein by this reference.
BACKGROUND
• 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. 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.
BRIEF DESCRIPTION OF THE DRAWINGS
• 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 configuration of the well drilling system.
• 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.
DETAILED DESCRIPTION
• Representatively and schematically illustrated inFIG. 1 is a welldrilling system10 and associated method which can embody principles of the present disclosure. In thesystem10, awellbore12 is drilled by rotating adrill bit14 on an end of adrill string16. Drillingfluid18, commonly known as mud, is circulated downward through thedrill string16, out thedrill bit14 and upward through anannulus20 formed between the drill string and thewellbore12, in order to cool the drill bit, lubricate the drill string, remove cuttings and provide a measure of wellbore pressure control. A non-return valve21 (typically a flapper or plunger-type check valve) prevents flow of thedrilling fluid18 upward through the drill string16 (e.g., when connections are being made in the drill string).
• Control of wellbore pressure is very important in optimized pressure drilling (e.g., managed pressure drilling, underbalanced drilling and overbalanced drilling). Preferably, the wellbore pressure is precisely controlled to prevent excessive loss of fluid into the earth formation surrounding thewellbore12, undesired fracturing of the formation, excessive influx of formation fluids into the wellbore, etc.
• In typical managed pressure drilling, it is desired to maintain bottom hole pressure somewhat greater than a pore pressure of the formation being penetrated by thewellbore12, without exceeding a fracture pressure of the formation. This technique is especially useful in situations where the margin between pore pressure and fracture pressure is relatively small.
• In typical underbalanced drilling, it is desired to maintain the bottom hole pressure somewhat less than the pore pressure of the formation, thereby obtaining a controlled influx of fluid from the formation. In typical overbalanced drilling, it is desired to maintain the bottom hole pressure somewhat greater than the pore pressure, thereby preventing (or at least mitigating) influx of fluid from the formation.
• Nitrogen or another gas, or another lighter weight fluid, may be added to thedrilling fluid18 for pressure control. This technique is useful, for example, in underbalanced drilling operations.
• In thesystem10, additional control over the wellbore pressure is obtained by closing off the annulus20 (e.g., isolating it from communication with the atmosphere and enabling the annulus to be pressurized at or near the surface) using a rotating control device22 (RCD). The RCD22 seals about thedrill string16 above awellhead24. Thedrill string16 extending upwardly through theRCD22 would connect to, for example, a rotary table (not shown), astandpipe26, a kelly (not shown), a top drive and/or other conventional drilling equipment.
• In one unique feature of thesystem10, wellbore pressure is optimized through use of apressure optimization unit11. Thepressure optimization unit11 can be conveniently transported to a well site and interconnected with rig drilling equipment, with minimal disruption of a drilling operation, and with reduced time, expense and effort needed for such interconnection.
• In the example depicted inFIG. 1, thepressure optimization unit11 includes achoke manifold32, a flow diverter84 and abackpressure pump86. Each of these is automatically controllable by acontrol system90, in a manner more fully described below.
• Thepressure optimization unit11 may also include anRCD clamp control98, anRCD lubricant supply100 and afluid analysis system102. However, note that it is not necessary for thepressure optimization unit11 to include all of these elements. For example, it is contemplated that thepressure optimization unit11 will preferably include either the flow diverter84 or thebackpressure pump86, but not both. Of course, thepressure optimization unit11 can include additional elements, in keeping with the scope of this disclosure.
• Thepressure optimization unit11 can be conveniently interconnected to a rig's drilling system using flexible lines104a-g. Rigid lines may also (or alternatively) be used for this purpose, if desired. Preferably, thepressure optimization unit11 is equipped with hydraulically powered reels106 (not shown inFIG. 1, seeFIG. 5) for storing and deploying the lines104a-g.
• During drilling, thedrilling fluid18 exits thewellhead24 via awing valve28 in communication with theannulus20 below the RCD22. Thefluid18 then flows throughmud return lines30,73 to thechoke manifold32, which includes redundant chokes34 (only one of which might be used at a time). Backpressure is applied to theannulus20 by variably restricting flow of thefluid18 through the operative choke(s)34.
• The greater the restriction to flow through thechoke34, the greater the backpressure applied to theannulus20. Thus, downhole pressure (e.g., pressure at the bottom of thewellbore12, pressure at a downhole casing shoe, pressure at a particular formation or zone, etc.) can be conveniently regulated by varying the backpressure applied to theannulus20. A hydraulics model can be used, as described more fully below, to determine a pressure applied to theannulus20 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 theannulus20 can be measured at or near the surface via a variety ofpressure sensors36,38,40, each of which is in communication with the annulus.Pressure sensor36 senses pressure below theRCD22, but above a blowout preventer (BOP)stack42.Pressure sensor38 senses pressure in the wellhead below theBOP stack42.Pressure sensor40 senses pressure in themud return lines30,73 upstream of thechoke manifold32.
• Anotherpressure sensor44 senses pressure in thestandpipe26. Yet anotherpressure sensor46 senses pressure downstream of thechoke manifold32, but upstream of aseparator48,shaker50 andmud pit52. Additional sensors includetemperature sensors54,56, Coriolisflowmeter58, andflowmeters62,64,66,88.
• Not all of these sensors are necessary. For example, thesystem10 could include only two of the threeflowmeters62,64,66. However, input from all available sensors is useful to the hydraulics model in determining what the pressure applied to theannulus20 should be during the drilling operation.
• Other sensor types may be used, if desired. For example, it is not necessary for theflowmeter58 to be a Coriolis flowmeter, since a turbine flowmeter, acoustic flowmeter, or another type of flowmeter could be used instead.
• In addition, thedrill string16 may include itsown sensors60, for example, to directly measure downhole pressure.Such sensors60 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). 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 thesystem10, if desired. For example, anotherflowmeter67 could be used to measure the rate of flow of the fluid18 exiting thewellhead24, another Coriolis flowmeter (not shown) could be interconnected directly upstream or downstream of arig mud pump68, etc.
• Fewer sensors could be included in thesystem10, if desired. For example, the output of therig mud pump68 could be determined by counting pump strokes, instead of by using theflowmeter62 or any other flowmeter(s).
• Note that theseparator48 could be a 3 or 4 phase separator, or a mud gas separator (sometimes referred to as a “poor boy degasser”). However, theseparator48 is not necessarily used in thesystem10.
• Thedrilling fluid18 is pumped through thestandpipe26 and into the interior of thedrill string16 by therig mud pump68. Thepump68 receives the fluid18 from themud pit52 and flows it via astandpipe manifold70 to thestandpipe26. The fluid18 then circulates downward through thedrill string16, upward through theannulus20, through themud return lines30,73, through thechoke manifold32, and then via theseparator48 andshaker50 to themud pit52 for conditioning and recirculation.
• Note that, in thesystem10 as so far described above, thechoke34 cannot be used to control backpressure applied to theannulus20 for control of the downhole pressure, unless the fluid18 is flowing through the choke. In conventional overbalanced drilling operations, a lack offluid18 flow will occur, for example, whenever a connection is made in the drill string16 (e.g., to add another length of drill pipe to the drill string as thewellbore12 is drilled deeper), and the lack of circulation will require that downhole pressure be regulated solely by the density of the fluid18.
• In thesystem10, however, flow of the fluid18 through thechoke34 can be maintained, even though the fluid does not circulate through thedrill string16 andannulus20, while a connection is being made in the drill string, and/or while the drill string is being tripped into or out of thewellbore12. Specifically, aflow diverter84 may be used to divert flow from therig mud pump68 to themud return line30, or abackpressure pump86 may be used to supply flow through thechoke manifold32, and thereby enable precise control over pressure in thewellbore12. Thus, pressure can still be applied to theannulus20 by restricting flow of the fluid18 through thechoke34, even while the fluid does not circulate through thedrill string16.
• The fluid18 can be flowed from therig mud pump68 to thechoke manifold32 via abypass line72,75 whenfluid18 does not flow through thedrill string16. Thus, the fluid18 can bypass thestandpipe26,drill string16 andannulus20, and can flow directly from thepump68 to themud return line30, which remains in communication with theannulus20. Restriction of this flow by thechoke34 will thereby cause pressure to be applied to the annulus20 (for example, in typical managed pressure drilling).
• Alternatively, the fluid18 can be flowed from thebackpressure pump86 to theannulus20 and, since the annulus is connected to thechoke manifold32 via thereturn line73,30, this will supply flow through thechoke34, so that wellbore pressure can be controlled by variably restricting the flow through the choke.
• As depicted inFIG. 1, both of thebypass line75 and themud return line30 are in communication with theannulus20 via asingle line73. However, thebypass line75 and themud return line30 could instead be separately connected to thewellhead24, for example, using an additional wing valve (e.g., below the RCD22), in which case each of thelines30,75 would be directly in communication with theannulus20.
• Although this might require some additional piping at the rig site, the effect on the annulus pressure would be similar to connecting thebypass line75 and themud return line30 to thecommon line73. Thus, it should be appreciated that various different configurations of the components of thesystem10 may be used, without departing from the principles of this disclosure.
• Flow of the fluid18 through thebypass line72,75 is regulated by a choke or other type offlow control device74.Line72 is upstream of the bypassflow control device74, andline75 is downstream of the bypass flow control device.
• Flow of the fluid18 through thestandpipe26 is substantially controlled by a valve or other type offlow control device76. Note that theflow control devices74,76 are independently controllable, which provides substantial benefits to thesystem10, as described more fully below.
• Since the rate of flow of the fluid18 through each of thestandpipe26 andbypass line72 is useful in determining how bottom hole pressure is affected by these flows, theflowmeters64,66 are depicted inFIG. 1 as being interconnected in these lines. However, the rate of flow through thestandpipe26 could be determined even if only theflowmeters62,64 were used, and the rate of flow through thebypass line72 could be determined even if only theflowmeters62,66 were used. Thus, it should be understood that it is not necessary for thesystem10 to include all of the sensors depicted inFIG. 1 and described herein, and the system could instead include additional sensors, different combinations and/or types of sensors, etc.
• In another beneficial feature of thesystem10, a bypassflow control device78 and flowrestrictor80 may be used for filling thestandpipe26 anddrill string16 after a connection is made in the drill string, and for equalizing pressure between the standpipe andmud return lines30,73 prior to opening theflow control device76. Otherwise, sudden opening of theflow control device76 prior to thestandpipe line26 anddrill string16 being filled and pressurized with the fluid18 could cause an undesirable pressure transient in the annulus20 (e.g., due to flow to thechoke manifold32 temporarily being lost while the standpipe and drill string fill with fluid, etc.).
• By opening the standpipe bypassflow control device78 after a connection is made, the fluid18 is permitted to fill thestandpipe26 anddrill string16 while a substantial majority of the fluid continues to flow through thebypass line72, thereby enabling continued controlled application of pressure to theannulus20. After the pressure in thestandpipe26 has equalized with the pressure in themud return lines30,73 andbypass line75, theflow control device76 can be opened, and then theflow control device74 can be closed to slowly divert a greater proportion of the fluid18 from thebypass line72 to thestandpipe26.
• Before a connection is made in thedrill string16, a similar process can be performed, except in reverse, to gradually divert flow of the fluid18 from thestandpipe26 to thebypass line72 in preparation for adding more drill pipe to thedrill string16. That is, theflow control device74 can be gradually opened to slowly divert a greater proportion of the fluid18 from thestandpipe26 to thebypass line72, and then theflow control device76 can be closed.
• Note that theflow control device78 and flowrestrictor80 could be integrated into a single element (e.g., a flow control device having a flow restriction therein), if desired. Theflow control device76 can be part of aflow diversion manifold81 interconnected between therig mud pump68 and therig standpipe manifold70.
• TheRCD clamp control98 is used to remotely operate a clamp (not visible inFIG. 1) of theRCD22. The clamp is for permitting access to a seal and a bearing assembly of theRCD22. Examples of electrical and hydraulic remote control of RCD clamps are described in International Application No. PCT/US11/28384, filed 14 Mar. 2011, and in International Application No. PCT/US10/57540, filed 20 Nov. 2010. If a hydraulically operated RCD clamp is used, hydraulic pressure may be supplied to theRCD clamp control98 from a conveyance (e.g., vehicle, vessel, etc.) which transports thepressure optimization unit11 to the rig site.
• Thefluid analysis system102 is used to determine properties of the fluid18 which flows from theannulus20 to thepressure optimization unit11. Thefluid analysis system102 may include, for example, a gas analyzer which extracts gas from the fluid18 and determines its composition, a gas spectrometer, a densitometer, a flowmeter, etc. The gas analyzer may be similar to an EAGLE™ gas extraction system and a DQ1000™ mass spectrometer marketed by Halliburton Energy Services, Inc.
• Thefluid analysis system102 may include a real time rheology analyzer, which continuously monitors rheological properties of the fluid18 and transmits this data to thehydraulics model92. A suitable rheology analyzer for use in thefluid analysis system102 is described in U.S. Application No. 61/377164, filed 26 Aug. 2010.
• Referring additionally now toFIG. 1A, a somewhat different configuration of thesystem10 is representatively illustrated. In this configuration, thebypass line75 is connected to athird choke82. Thebypass line75 remains connected to thereturn line30 also, but thechoke82 provides for convenient regulation of the amount offluid18 discharged from theflow diverter84.
• Thus, when resistance to flow through thechoke82 is increased, more of the fluid18 flows to themud return line30. When resistance to flow through thechoke82 is decreased, more of the fluid18 flows to a downstream side of the choke manifold32 (and not through the chokes34).
• A pressure and flowcontrol system90 which may be used in conjunction with thesystem10 and associated method ofFIGS. 1 & 1A is representatively illustrated in
• FIG. 2. Thecontrol system90 is preferably fully automated, although some human intervention may be used, for example, to safeguard against improper operation, initiate certain routines, update parameters, etc.
• Thecontrol system90 includes ahydraulics model92, a data acquisition andcontrol interface94 and a controller96 (such as a programmable logic controller or PLC, a suitably programmed computer, etc.). Although theseelements92,94,96 are depicted separately inFIG. 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.
• Thehydraulics model92 is used in thecontrol system90 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 information (such as geothermal gradient and pore pressure gradient, etc.) are utilized by thehydraulics model92 in making this determination, as well as real-time sensor data acquired by the data acquisition andcontrol interface94.
• Thus, there is a continual two-way transfer of data and information between thehydraulics model92 and the data acquisition andcontrol interface94. It is important to appreciate that the data acquisition andcontrol interface94 operates to maintain a substantially continuous flow of real-time data from thesensors44,54,66,62,64,60,58,46,36,38,40,56,67,88 andfluid analysis system102 to thehydraulics model92, so that the hydraulics model has the information it needs to adapt to changing circumstances and to update the desired annulus pressure. Thehydraulics model92 operates to supply the data acquisition andcontrol interface94 substantially continuously with a value for the desiredannulus20 pressure.
• A suitable hydraulics model for use as thehydraulics model92 in thecontrol system90 is REAL TIME HYDRAULICS™ provided by Halliburton Energy Services, Inc. of Houston, Tex. USA. Another suitable hydraulics model is provided under the trade name IRIS™, and yet another is available from SINTEF of Trondheim, Norway. Any suitable hydraulics model may be used in thecontrol system90 in keeping with the principles of this disclosure.
• A suitable data acquisition and control interface for use as the data acquisition andcontrol interface94 in thecontrol system90 are SENTRY198 and INSITE™ provided by Halliburton Energy Services, Inc. Any suitable data acquisition and control interface may be used in thecontrol system90 in keeping with the principles of this disclosure.
• Thecontroller96 operates to maintain a desired setpoint annulus pressure, in part by controlling operation of themud return choke34. When an updated desired annulus pressure is transmitted from the data acquisition andcontrol interface94 to thecontroller96, the controller uses the desired annulus pressure as a setpoint and controls operation of thechoke34 in a manner (e.g., increasing or decreasing flow resistance through the choke as needed) to maintain the setpoint pressure in theannulus20. Thechoke34 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 thesensors36,38,40), and decreasing flow resistance through thechoke34 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. Of course, if the setpoint and measured pressures are the same, then no adjustment of thechoke34 is required. This process is preferably automated, so that no human intervention is required, although human intervention may be used, if desired.
• Thecontroller96 may also be used to control operation of the standpipeflow control devices76,78 and the bypassflow control device74. Thecontroller96 can, thus, be used to automate the processes of diverting flow of the fluid18 from thestandpipe26 to thebypass line72 prior to making a connection in thedrill string16, then diverting flow from the bypass line to the standpipe after the connection is made, and then resuming normal circulation of the fluid18 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.
• Thecontrol system90 also preferably includes apredictive device148 and adata validator150. Thepredictive device148 preferably comprises one or more neural network models for predicting various well parameters. These parameters could include outputs of any of thesensors36,38,40,44,46,54,56,58,60,62,64,66,67,88,102, the annulus pressure setpoint output from thehydraulics model92, positions offlow control devices34,74,76,78,drilling fluid18 density, etc. Any well parameter, and any combination of well parameters, may be predicted by thepredictive device148.
• Thepredictive device148 is preferably “trained” by inputting present and past actual values for the parameters to the predictive device. Terms or “weights” in thepredictive device148 may be adjusted based on derivatives of output of the predictive device with respect to the terms.
• Thepredictive device148 may be trained by inputting to the predictive device data obtained during drilling, while making connections in thedrill string16, and/or during other stages of an overall drilling operation. Thepredictive device148 may be trained by inputting to the predictive device data obtained while drilling at least one prior wellbore.
• The training may include inputting to thepredictive device148 data indicative of past errors in predictions produced by the predictive device. Thepredictive device148 may be trained by inputting data generated by a computer simulation of the well drilling system10 (including the drilling rig, the well, equipment utilized, etc.).
• Once trained, thepredictive device148 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 validator150 for use in its data validation processes.
• Thepredictive device148 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.
• Thepredictive device148 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 thepredictive device148 and/or a first principle model may be included in the predictive device.
• Thepredictive device148 receives the actual parameter values from the data validator150, which can include one or more digital programmable processors, memory, etc. The data validator150 uses various pre-programmed algorithms to determine whether sensor measurements, flow control device positions, etc., received from the data acquisition &control interface94 are valid.
• For example, if 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 predetermined maximum amount from a predicted value for that parameter (e.g., due to a malfunctioning sensor), then the data validator150 may flag that actual parameter value as being “invalid.” Invalid parameter values may not be used for training thepredictive device148, or for determining the desired annulus pressure setpoint by thehydraulics model92. Valid parameter values would be used for training thepredictive device148, for updating thehydraulics model92, for recording to the data acquisition &control interface94 database and, in the case of the desired annulus pressure setpoint, transmitted to thecontroller96 for controlling operation of theflow control devices34,74,76,78.
• The desired annulus pressure setpoint may be communicated from thehydraulics model92 to each of the data acquisition &control interface94, thepredictive device148 and thecontroller96. The desired annulus pressure setpoint is communicated from thehydraulics model92 to the data acquisition &control interface94 for recording in its database, and for relaying to the data validator150 with the other actual parameter values.
• The desired annulus pressure setpoint is communicated from thehydraulics model92 to thepredictive device148 for use in predicting future annulus pressure setpoints. However, thepredictive device148 could receive the desired annulus pressure setpoint (along with the other actual parameter values) from the data validator150 in other examples.
• The desired annulus pressure setpoint is communicated from thehydraulics model92 to thecontroller96 for use in case the data acquisition &control interface94 ordata validator150 malfunctions, or output from these other devices is otherwise unavailable. In that circumstance, thecontroller96 could continue to control operation of the variousflow control devices34,74,76,78 to maintain/achieve the desired pressure in theannulus20 near the surface.
• Thepredictive device148 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 unavailable, thepredictive device148 can supply the missing sensor measurement values to the data validator150, at least temporarily, until the sensor output again becomes available.
• If, for example, during the drill string connection process described above, one of theflowmeters62,64,66 malfunctions, or its output is otherwise unavailable or invalid, then the data validator150 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 theflowmeters62,64,66 may be used. Thus, if the data validator150 ceases to receive valid output from one of those flowmeters, determination of the proportions offluid18 flowing through thestandpipe26 andbypass line72 could not be readily accomplished, if not for the predicted parameter values output by thepredictive device148. It will be appreciated that measurements of the proportions offluid18 flowing through thestandpipe26 andbypass line72 are very useful, for example, in calculating equivalent circulating density and/or friction pressure by thehydraulics model92 during the drill string connection process.
• Validated parameter values are communicated from the data validator150 to thehydraulics model92 and to thecontroller96. Thehydraulics model92 utilizes the validated parameter values, and possibly other data streams, to compute the pressure currently present downhole at the point of interest (e.g., at the bottom of thewellbore12, at a problematic zone, at a casing shoe, etc.), and the desired pressure in theannulus20 near the surface needed to achieve a desired downhole pressure.
• The data validator150 is programmed to examine the individual parameter values received from the data acquisition &control interface94 and determine if each falls into a predetermined range of expected values. If thedata validator150 detects that one or more parameter values it received from the data acquisition &control interface94 is invalid, it may send a signal to thepredictive device148 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.
• Although thepredictive device148 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. Upon identification of a faulty sensor, the data validator150 can substitute the predicted sensor parameter values from thepredictive device148 to thecontroller96 and thehydraulics model92. Additionally, when thedata validator150 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.
• Thepredictive device148 is preferably also able to train a neural network model representing the output of thehydraulics model92. A predicted value for the desired annulus pressure setpoint is communicated to thedata validator150. If thehydraulics model92 has difficulties in generating proper values or is unavailable, the data validator150 can substitute the predicted desired annulus pressure setpoint to thecontroller96.
• Referring additionally now toFIG. 3, thepressure optimization unit11 is representatively illustrated as being incorporated into aconveyance110. As depicted inFIG. 3, theconveyance110 comprises awheeled vehicle108 on which thepressure optimization unit11 is transported, but in other examples the conveyance is not necessarily a wheeled vehicle.
• Thevehicle108 illustrated inFIG. 3 is a tractor-trailer, with thepressure optimization unit11 being incorporated into the trailer portion of the vehicle. In other examples, thevehicle108 could be a bobtail truck (i.e., without a trailer being towed behind the truck) or another type of wheeled vehicle.
• Preferably, thepressure optimization unit11 is incorporated into theconveyance110, so that it is part of the conveyance, and is not a separately transportable element. However, in other examples thepressure optimization unit11 could be separately transported (such as, on a flat bed trailer, etc.).
• Referring additionally now toFIG. 4, another configuration of theconveyance110 is representatively illustrated. In this configuration, thepressure optimization unit11 is incorporated into a floating vessel112 (such as a barge, a ship, a floating production, storage and offloading (FPSO) vessel, etc.).
• Again, thepressure optimization unit11 is preferably incorporated into theconveyance110, so that it is part of the conveyance, and is not an element separately transportable from thevessel112. However, in other examples thepressure optimization unit11 could be separately transported (such as, on a work boat, etc.).
• Referring additionally now toFIG. 5, a plan view of one configuration of thepressure optimization unit11 is representatively illustrated. In this configuration, thepressure optimization unit11 includes thechoke manifold32, theCoriolis flowmeter58, theflow diverter84, thecontrol system90, thefluid analysis system102 and thereels106, along with acommand center114 for human interaction with the control system, etc. Thecommand center114 can include workstations116 for human-machine interaction, andcommunication equipment118 for, e.g., telephone, internet, wireless, satellite and/or internet communication with remote locations.
• Thefluid analysis system102 in this example includes both agas analysis system120 and arheology measurement system122. Thegas analysis system120 may be similar to the EAGLE™ system marketed by Halliburton Energy Services, Inc., and therheology measurement system122 may be similar to that described in U.S. Application No. 61/377164. Rheological properties measured by thesystem122 can include density, oil/water ratio, specific gravity, chloride amount, electric stability, shear stress, gel strength, viscosity and/or yield point.
• Pipe racks124 may be provided for storing rigid lines. Electrical power, as well as hydraulic and pneumatic pressure, may be supplied to thepressure optimization unit11 vialines126 from thevehicle108 orvessel112.
• Referring additionally now toFIG. 6, one manner in which thepressure optimization unit11 can be integrated into theconveyance110 is representatively illustrated. As depicted inFIG. 6, thechoke34 is rigidly attached to aframe128 of thevehicle108 orvessel112. Although only the onechoke34 is shown inFIG. 6, it will be appreciated that any or all of the elements of thepressure optimization unit11 can be integrated into thevehicle108 orvessel112 in keeping with the scope of this disclosure.
• By rigidly attaching thechoke34 and/or other elements of thepressure optimization unit11 to theframe128 of thevehicle108 orvessel112, the pressure optimization unit is incorporated into, and becomes a part of, theconveyance110. However, in other examples, thepressure optimization unit11 may not be incorporated into the conveyance110 (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, thepressure optimization unit11 is preferably transported to the rig site as part of theconveyance110. Without offloading thepressure optimization unit11 from thevehicle108 orvessel112, the pressure optimization unit is interconnected to the various items of drilling equipment using the lines104a-g, and is operational (ready for use in a drilling operation) in a relatively short period of time. In this manner, incorporation of thepressure optimization unit11 into the drilling operation is convenient, efficient and economical, thereby saving time, money and manpower.
• Of course, if thepressure optimization unit11 is transported to the rig site on a flat bed trailer or a work boat, the pressure optimization unit may be offloaded at the rig site. In these situations, the process of interconnecting thepressure optimization unit11 to the rig's drilling equipment via the lines104a-gwill still be relatively convenient, efficient and economical.
• Although only thewheeled vehicle108 and floatingvessel112 are illustrated in the drawings, any type of conveyance may be used to transport thepressure optimization unit11 to and from the rig site. Trains and aircraft (e.g., a hovercraft) are additional examples of suitable conveyances whereby thepressure optimization unit11 can be made mobile.
• It may now be fully appreciated that the above disclosure provides significant advances to the art of well drilling equipment construction. Thepressure optimization unit11 described above can be conveniently transported to a rig site, and can be interconnected to rig drilling equipment in a convenient, efficient and economical manner.
• The above disclosure describes a well drilling method. The method can include transporting apressure optimization unit11 to a rig site, thepressure optimization unit11 including achoke manifold32, acontrol system90 which automatically controls operation of thechoke manifold32, and aflowmeter58 which measures flow ofdrilling fluid18 through thechoke manifold32, and then interconnecting thepressure optimization unit11 to rig drilling equipment (e.g., thewellhead24,standpipe26,separator48,shaker50,mud pit52, etc.).
• The method can also include integrating thepressure optimization unit11 into aconveyance110. Theconveyance110 may comprise awheeled vehicle108 or a floatingvessel112.
• The integrating step may include rigidly attaching thepressure optimization unit11 to aframe128 of theconveyance110. The interconnecting step may include interconnecting thepressure optimization unit11 to the rig drilling equipment, without prior offloading of thepressure optimization unit11 from theconveyance110.
• Thepressure optimization unit11 may include aflow diverter84 which diverts flow of thedrilling fluid18 from astandpipe26 to thechoke manifold32, abackpressure pump86 which pressurizes awell annulus20, afluid analysis system102 which comprises agas analysis system120 and/or arheology measurement system122, a rotating controldevice clamp control98 and/or a rotating controldevice lubricant supply100.
• Also described above is apressure optimization unit11 for use with awell drilling system10. Thepressure optimization unit11 can include achoke manifold32, acontrol system90 which automatically controls operation of thechoke manifold32, and aflowmeter58 which measures flow ofdrilling fluid18 through thechoke manifold32. Thechoke manifold32,control system90 andflowmeter58 can each be incorporated into asame conveyance110 which transports thepressure optimization unit11 to a rig site.
• Thepressure optimization unit11 may also include apowered reel106 which stores line104a-gthat connects thepressure optimization unit11 to rig drilling equipment (e.g., thewellhead24,standpipe26,separator48,shaker50,mud pit52, etc.).
• Thepressure optimization unit11 can be interconnected to rig drilling equipment concurrently with thepressure optimization unit11 being incorporated into theconveyance110.
• It is to be understood that the various embodiments of the present disclosure described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of this disclosure. The embodiments are described merely as examples of useful applications of the principles of the disclosure, which is not limited to any specific details of these embodiments.
• Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the disclosure, readily appreciate that many modifications, additions, substitutions, deletions, and other changes may be made to the specific embodiments, and such changes are contemplated by the principles of this disclosure. Accordingly, the foregoing detailed description is to be clearly understood as being given by way of illustration and example only, the spirit and scope of the invention being limited solely by the appended claims and their equivalents.

Claims (8)

1-6. (canceled)

7. A well drilling method, comprising:

transporting a pressure optimization unit to a rig site, the pressure optimization unit including a choke manifold, a control system which automatically controls operation of the choke manifold, a flowmeter which measures flow of drilling fluid through the choke manifold, and a flow diverter which diverts flow of the drilling fluid from a standpipe to the choke manifold; and

then interconnecting the pressure optimization unit to rig drilling equipment.

8. A well drilling method, comprising:

transporting a pressure optimization unit to a rig site, the pressure optimization unit including a choke manifold, a control system which automatically controls operation of the choke manifold, a flowmeter which measures flow of drilling fluid through the choke manifold, and a backpressure pump which pressurizes a well annulus; and

then interconnecting the pressure optimization unit to rig drilling equipment.

9. A well drilling method, comprising:

transporting a pressure optimization unit to a rig site, the pressure optimization unit including a choke manifold, a control system which automatically controls operation of the choke manifold, a flowmeter which measures flow of drilling fluid through the choke manifold, and a fluid analysis system which comprises a gas analysis system; and

then interconnecting the pressure optimization unit to rig drilling equipment.

10. A well drilling method, comprising:

transporting a pressure optimization unit to a rig site, the pressure optimization unit including a choke manifold, a control system which automatically controls operation of the choke manifold, a flowmeter which measures flow of drilling fluid through the choke manifold, and a fluid analysis system which comprises a rheology measurement system; and

then interconnecting the pressure optimization unit to rig drilling equipment.

11. A well drilling method, comprising:

transporting a pressure optimization unit to a rig site, the pressure optimization unit including a choke manifold, a control system which automatically controls operation of the choke manifold, a flowmeter which measures flow of drilling fluid through the choke manifold, and a rotating control device clamp control; and

then interconnecting the pressure optimization unit to rig drilling equipment.

12. A well drilling method, comprising:

transporting a pressure optimization unit to a rig site, the pressure optimization unit including a choke manifold, a control system which automatically controls operation of the choke manifold, a flowmeter which measures flow of drilling fluid through the choke manifold, and a rotating control device lubricant supply; and

then interconnecting the pressure optimization unit to rig drilling equipment.

13-24. (canceled)

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