MX2013013366A

MX2013013366A - Mobile pressure optimization unit for drilling operations.

Info

Publication number: MX2013013366A
Application number: MX2013013366A
Authority: MX
Inventors: James R Lovorn; Malcolm E Whittaker; Derrick W Lewis
Original assignee: Halliburton Energy Serv Inc
Priority date: 2011-05-16
Filing date: 2011-05-16
Publication date: 2014-01-08
Also published as: US20120292109A1; US20120292108A1; EP2710216A4; WO2012158155A1; EP2710216A1

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

MOBILE PRESS OPTIMIZATION UNIT FOR OPERATIONS OF DRILLING FIELD OF THE INVENTION The present description relates in general terms to the equipment used and the operations performed in conjunction with the well drilling operations and, in a manner described herein, more particularly provides a mobile pressure optimization unit for use in the operations of drilling.

BACKGROUND OF THE INVENTION Optimized pressure drilling is the technique of precisely controlling the pressure of the wellbore during drilling by using a closed ring and a means to regulate the pressure in the ring. Typically, the ring closes during drilling through the use of a rotating control device (RCD), which seals around the drilled drill pipe, also known as rotary control head or rotary blowout preventer. that rotates. Accurate control of well pressure is important to avoid formation damage, avoid drilling fluids loss, control or avoid flow of formation fluids towards well drilling, etc.

Therefore, it will be noted that the improvements would be beneficial in the technique of controlling the pressure and flow in drilling operations.

BRIEF DESCRIPTION OF THE DRAWINGS Figure 1 is a representative view of a well drilling system and the method embodying the principles of the present disclosure.

Figure 1A is a view representative of another configuration of the well drilling system.

Figure 2 is a block diagram representative of a control system that can be used in the well drilling system.

Figure 3 is a representative side view of a mobile pressure optimization unit, which may incorporate principles of this description, incorporated in a wheeled vehicle.

Figure 4 is a representative side view of the mobile pressure optimization unit incorporated in a floating vessel.

Figure 5 is a representative plan view of the mobile pressure optimization unit.

Figure 6 is a representative side view of the mobile pressure optimization unit, integrated with a transport frame used to transport the unit.

DETAILED DESCRIPTION OF THE INVENTION Representative and schematically illustrated in Figure 1 illustrates a well drilling system 10 and the associated method which may incorporate principles of the present disclosure. In system 10, a well bore 12 is made by rotating an auger 14 at one end of a drill string 16. Drilling fluid 18, commonly known as slurry, is circulated downwardly through drill string 16, outside the auger 14 and ascendingly through a ring 20 formed between the drill string and the well bore 12, in order to cool the drill bit, lubricate the drill string, extract cuts and provide a control measurement of the pressure of the well drilling. A non-return valve 21 (typically a plunger-type flap or check valve) prevents the flow of drilling fluid 18 up through the drill string 16 (e.g., when the connections are made in the drill string). perforation).

The control of the pressure of the well drilling is very important in optimized pressure drilling (eg, controlled pressure drilling, unbalanced drilling and overbalanced drilling).

Preferably, the wellbore pressure is precisely controlled to avoid excessive loss of fluid in the earth formation surrounding the well bore 12, fracturing of the undesired formation, excessive inflow of forming fluids within the borehole. Well drilling, etc.

In the typical controlled pressure drilling, it is desired to maintain the downhole pressure somewhat higher than an interstitial pressure of the formation which is penetrated by the wellbore 12, without exceeding a fracture pressure of the formation. This technique is especially useful in situations where the margin between the interstitial pressure and the fracture pressure is relatively small.

In typical unbalanced drilling, it is desired to maintain the downhole pressure somewhat lower than the interstitial pressure of the formation, thus obtaining a controlled influx of fluid from the formation. In the typical overbalanced borehole, it is desired to maintain the downhole pressure somewhat higher than the interstitial pressure, thus avoiding (or at least attenuating) the inflow of fluid from the formation.

Nitrogen or other gas, or other lighter weight fluid, may be added to the drilling fluid 18 for pressure control. This technique is useful, for example, in unbalanced drilling operations.

In system 10, additional control over pressure is obtained. of the well drilling by closing the ring 20 (for example, isolating it from communication with the atmosphere and allowing the ring to be pressurized at or near the surface) using a rotary control device 22 (RCD). The RCD 22 is sealed on the drill string 16 over a wellhead 24. The drill string 16 extending upwardly through the RCD 22 would be connected, for example, to a rotary table (not shown), a feeder tube 26, a stop valve (not shown), an upper unit and / or other conventional drilling equipment.

In a unique feature of the system 10, the well drilling pressure is optimized by using a pressure optimization unit 11. The pressure optimization unit 11 can be conveniently transported to a well location and interconnected with the drilling equipment , with the minimum interruption of a drilling operation, and with the reduced time, the expense and effort necessary for said interconnection.

In the example shown in Figure 1, the pressure optimization unit 11 includes a throttle manifold 32, a flow diverter 84 and a back pressure pump 86. Each of them is automatically controllable by a control system 90, a more detailed described way below.

The pressure optimization unit 11 may also include a clamp control of RCD 98, a supply of lubricant of RCD 100 and a fluid analysis system 102. However, note that it is not necessary for the pressure optimization unit 11. include all these elements. For example, it is considered that the pressure optimization unit 11 will preferably include either the flow diverter 84 or the back pressure pump 86, but not both. Of course, the pressure optimization unit 11 may include additional elements, in accordance with the scope of this description.

The pressure optimization unit 11 can be conveniently interconnected to a drilling system using the flexible lines 104a-g. Rigid lines can also (or alternatively) be used for this purpose, if desired. Preferably, the pressure optimization unit 11 is equipped with hydraulically actuated rollers 106 (not shown in Figure 1, see Figure 5) to store and display lines 104a-9 · During drilling, the drilling fluid 18 leaves the wellhead 24 through a side valve 28 in communication with the ring 20 below the RCD 22. The fluid 18 then flows through the mud return lines 30. , 73 to the choke manifold 32, which includes redundant shutters 34 (only one of which could be used at a time). The back pressure is applied to the ring 20 by varyingly restricting the flow of the fluid 18 through the operative shutter (s) 34.

The greater the restriction to flow through the plug 34, the greater the back pressure applied to the ring 20. Therefore, the downhole pressure (e.g., the pressure at the bottom of the wellbore 12, the pressure in a downhole casing shoe, pressure in a particular formation or zone, etc.) can be conveniently regulated by varying the back pressure applied to the ring 20. A hydraulic model can be used, as described in more detail then, in order to determine a pressure applied to the ring 20 at or near the surface which will cause a desired downhole pressure, such that an operator (or an automated control system) can easily determine how the pressure applied to the ring is regulated at or near the surface (which can be conveniently measured) in order to obtain the desired downhole pressure.

The pressure applied to the ring 20 can be measured at or near the surface by a variety of pressure sensors 36, 38, 40, each of which is in communication with the ring. The pressure sensor 36 detects the pressure below the RCD 22, but above a stack of blowout preventer (BOP) 42. The pressure sensor 38 detects the pressure at the wellhead below the stack BOP 42. The pressure sensor 40 detects the pressure in the mud return lines 30, 73 upstream of the throttle manifold 32.

Another pressure sensor 44 detects the pressure in the feeder tube 26. Still another pressure sensor 46 detects the pressure downstream of the restrictor manifold 32, but upstream of a separator 48, the agitator 50 and the mud pit 52. additional sensors include temperature sensors 54, 56, Coriolis flowmeter 58, and flow meters 62, 64, 66, 88.

Not all of these sensors are necessary. For example, system 10 could include only two of the three flow meters 62, 64, 66. However, the entry of all The available sensors is useful for the hydraulic model in determining what the pressure applied to the ring 20 should be during the drilling operation.

If desired, other types of sensors can be used. For example, it is not necessary for the flow meter 58 to be a Coriolis flow meter, since a turbine flowmeter, an acoustic flowmeter, or another type of flowmeter could be used instead.

In addition, the drill string 16 can include its own sensors 60, for example, to directly measure the downhole pressure. Such sensors 60 may be of the type known to those skilled in the art as pressure during drilling (PWD), measurement during drilling (MWD) and / or recording during drilling (LWD). , logging while drilling). These drill string sensor systems generally provide at least the measurement pressure, and can also provide the temperature measurement, the detection of drill string characteristics (such as vibration, weight on the drill bit, sticking and take-off movement). , etc.), training characteristics (such as resistivity, density, etc.) and / or other measurements. Various forms of cable or wireless telemetry can be used (acoustic, pressure pulse, electromagnetic, etc.) to transmit the downhole sensor measurements to the surface.

Additional sensors could be included in system 10, if desired. For example, another flowmeter 67 could be used to measure the flow velocity of the fluid 18 leaving the wellhead 24, another Coriolis flowmeter (not shown) could be interconnected directly upstream or downstream of a drilling mud pump 68, etc.

Fewer sensors could be included in system 10, if desired. For example, the output of the drilling mud pump 68 could be determined by counting the pulses of the pump, instead of using the flowmeter 62 or some other flowmeter (s).

Note that the separator 48 could be a 3 or 4 phase separator, or a mud gas separator (sometimes referred to as a "gas separator"). However, the separator 48 is not necessarily used in the system 10.

The drilling fluid 18 is pumped through the feeder tube 26 and into the interior of the drill string 16 by the drilling mud pump 68. The pump 68 receives the fluid 18 from the mud pit 52 and flows through it. a feeder tube manifold 70 towards the feeder tube 26. Then, the fluid 18 flows down through the drill string 16, asing through the ring 20, through the sludge return lines 30, 73, through the throttle manifold 32, and then via the separator 48 and the agitator 50 to the mud pit 52 for its conditioning and recirculation.

Note that, in system 10 as described so far, shutter 34 can not be used to control the back pressure applied to ring 20 for downhole pressure control, unless fluid 18 flows through the shutter . In conventional overbalanced drilling operations, a lack of fluid flow 18 will occur, e.g., each time a connection is made in drill string 16 (e.g., to add another length of drill pipe to the drill string). drilling as the wellbore is drilled deeper), and the lack of circulation will require that the downhole pressure be exclusively regulated by the density of the fluid 18.

However, in system 10, the flow of fluid 18 through plug 34 can be maintained, although fluid does not circulate through drill string 16 and ring 20, while a connection is made to the drill string. , and / or while the drill string is engaged or disengaged from the wellbore 12.

Specifically, a flow diverter 84 can be used to divert the flow from the drilling mud pump 68 to the sludge return line 30, or a back pressure pump 86 can be used to supply the flow through the throttle manifold 32. , and thus allow an accurate control of the pressure in the wellbore 12. Therefore, the pressure can still be applied to the ring 20 by restricting the flow of the fluid 18 through the plug 34, even while the fluid does not circulate through the drill string 16.

The fluid 18 can be made to flow from the drilling mud pump 68 to the choke manifold 32 through a bypass line 72, 75 when the fluid 18 does not flow through the drill string 16. Consequently, the fluid 18 it can omit the feeder tube 26, the drill string 16 and the ring 20, and it can flow directly from the pump 68 towards the mud return line 30, which is maintained in communication with the ring 20. The restriction of this flow by the plug 34 will thus cause the pressure to be applied to the ring 20 (for example, in the typical controlled pressure perforation).

Alternatively, the fluid 18 can be flowed from the back pressure pump 86 to the ring 20 and, since the ring is connected to the throttle manifold 32 through of the return line 73, 30, this will supply the flow through the plug 34, such that the pressure of the well bore can be controlled by variably restricting the flow through the choke.

As graphically depicted in Figure 1, both the bypass line 75 and the mud return line 30 are in communication with the ring 20 through a single line 73. However, the bypass line 75 and the line return sludge 30 could instead be connected separately to the wellhead 24, for example, by using an additional side valve (for example, below the RCD 22), in which case each of the lines 30, 75 would be directly in communication with ring 20.

Although this may require some additional piping at the drilling site, the effect on the ring pressure would be similar to the connection of the branch line 75 and the mud return line 30 to the common line 73. Therefore, it should be It should be noted that various different configurations of the components of the system 10 can be used, without being isolated from the principles of the present disclosure.

The flow of the fluid 18 through the bypass line 72, 75 is regulated by a choke or other type of flow control device 74. The line 72 is upstream of the flow control device. branch 74, and line 75 is downstream of the branch flow control device.

Fluid flow 18 through feeder tube 26 is substantially controlled by a valve or other type of flow control device 76. Note that flow control devices 74, 76 are independently controllable, which provides significant benefits to the flow control device. system 10, as described in more detail below.

Since the flow velocity of the fluid 18 through each feeder tube 26 and the bypass line 72 is useful in determining how wellbore pressure is affected by these flows, the flowmeters 64, 66 are graphically represented in the Figure 1 interconnected in these lines. However, the flow rate through the feeder tube 26 could be determined even if only the flow meters 62, 64 were used, and the flow rate through the bypass line 72 could be determined, even if only the flow meters 62 were used. , 66. Accordingly, it should be understood that it is not necessary for the system 10 to include all the sensors depicted graphically in Figure 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 the system 10, a bypass flow control device 78 and the flow restrictor 80 can be used to fill the feeder tube 26 and the drill string 16 after making a connection in the drill string, and for equalizing the pressure between the feeder tube and the mud return lines 30, 73 before opening the flow control device 76. Otherwise, the sudden opening of the flow control device 76 before the feeder tube line 26 and the drill string 16 which is filled and pressurized with the fluid 18 could cause undesirable momentary pressure in the ring 20 (for example, due to the flow to the choke manifold 32 which is momentarily lost when the feeder tube and the string drilling is filled with fluid, etc.) Upon opening the bypass flow control device of the feeder tube 78 after making a connection, the fluid 13 is allowed to fill the feeder tube 26 and the drill string 16, while a substantial majority of the fluid continues to flow through. the branch line 72, thus allowing the controlled and continuous application of the pressure to the ring 20. After the pressure in the feeder tube 26 has been matched with the pressure in the mud return lines 30, 73 and the line of bypass 75, the flow control device 76 can be opened, and subsequently, 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 feeder tube 26.

Before making a connection in the drill string 16, a similar process may be applied, except in the reverse direction, in order to gradually divert the flow of fluid 18 from the feeder tube 26 to the bypass line 72 when preparing to add more pipe. perforation string 16. That is, the flow control device 74 can be gradually opened to slowly divert a larger proportion of the fluid 18 from the feeder tube 26 to the bypass line 72, and then the device can be closed of flow control 76.

Note that the flow control devices 78 and the flow restrictor 80 could be integrated into a single element (e.g., a flow control device having a flow restriction therein), if desired. The flow control device 76 may be part of a flow diversion manifold 81 interconnected between the drilling mud pump 68 and the drilling feeder tube manifold 70.

The clamp control of RCD 98 is used to remotely operate a clamp (not visible in Figure 1) of the RCD 22. The clamp serves to allow access to a joint and a bearing assembly of the RCD 22. The examples of Electric and hydraulic remote control of RCD clamps are described in International Application no. PCT / US11 / 28384, filed on March 14, 2011, and in International Application no. PCT / US10 / 57540, filed on November 20, 2010. If a hydraulically operated RCD clamp is used, the hydraulic pressure can be supplied to the RCD 98 clamp control from a transport (eg, vehicles, boats, etc.). ) which transports the pressure optimization unit 11 to the drilling location.

The fluid analysis system 102 is used to determine the properties of the fluid 18 flowing from the ring 20 to the pressure optimization unit 11. The fluid analysis system 102 may include, for example, a gas analyzer that extracts the gas of the fluid 18 and determines its composition, a gas spectrometer, a densitometer, a flow meter, etc. The gas analyzer can be similar to an EAGLE (TM) gas extraction system and a DQ1000 (TM) mass spectrometer marketed by Halliburton Energy Services, Inc.

The fluid analysis system 102 may include a real-time rheology analyzer, which continuously monitors the rheological properties of the fluid 18 and transmits this data to the hydraulic model 92. A rheological analyzer suitable for use in the fluid analysis system 102 is described in the US patent application no. 61/377164, filed on August 26, 2010.

Referring now to Figure 1A, a somewhat different configuration of system 10 is representatively illustrated. In this configuration, the branch line 75 is connected to a third plug 82. The branch line 75 is also kept connected to the return line 30, but the plug 82 provides adequate regulation of the amount of fluid 18 discharged from the diverter of flow 84.

Therefore, when the flow resistance is increased through the shutter 82, more fluid 18 flows to the mud return line 30. When the flow resistance through the shutter 82 decreases, more fluid 18 flows to a water part. below the choke manifold 32 (and not through the shutters 34).

A pressure and flow control system 90 that can be used in conjunction with the system 10 and the associated method of FIGS. 1 and 1A is representatively illustrated in FIG.

Figure 2. Preferably, the control system 90 is fully automated, although some type of human intervention may be used, for example, to protect against inappropriate handling, initiate certain routines, update the parameters, etc.

The control system 90 includes a hydraulic 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 graphically represented separately in Figure 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, additional elements and / or functions could be provided. , etc.

The hydraulic model 92 is used in the control system 90 to determine the desired pressure of the ring at or near the surface to achieve the desired downhole pressure. Data such as well geometry, fluid properties and compensation well information (such as the geothermal gradient and interstitial pressure gradient, etc.) are used by the hydraulic model 92 during this determination, as well as Real-time sensor data acquired by the data acquisition and control interface 94.

Therefore, there is a continuous bidirectional transfer of data and information between the hydraulic model 92 and the data acquisition and control interface 94. It is important to note that the data acquisition and control interface 94 operates to maintain a data flow practically continuous in real time from the sensors 44, 54, 66, 62, 64, 60, 58, 46, 36, 38, 40, 56, 67, 88 and the fluid analysis system 102 to the hydraulic model 92, so such that the hydraulic model has the information it needs to adapt to changing circumstances and to update the desired pressure of the ring. The hydraulic model 92 serves to supply the data acquisition and control interface 94 substantially continuously with a value for the desired pressure of the ring 20.

A hydraulic model suitable for use as a hydraulic model 92 in control system 90 is REAL TIME HYDRAULICS (TM) provided by Halliburton Energy Services, Inc. of Houston, Texas, E.U.A. Another suitable hydraulic model is provided under the IRIS (TM) brand, and yet another is available from SINTEF of Trondheim, Norway. Any suitable hydraulic model can be used in the control system 90 according to the principles of this description.

A data acquisition and control interface suitable 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 interface can be used. of acquisition and control of adequate data in the control system 90 in accordance with the principles of this description.

The controller 96 operates to maintain a desired set point ring pressure, partially controlling the operation of the mud return plug 34. When a desired and updated ring pressure is transmitted from the data acquisition and control interface 94 to the controller 96, the controller uses the desired pressure of the ring as a reference point and controls the operation of the shutter 34 in such a manner (for example, increasing or decreasing the resistance to flow through the plug as required) that the reference point pressure is maintained in the ring 20. The plug 34 can be closed further to increase the flow resistance, or opened further to decrease the resistance to the flow. flow.

Maintaining the reference point pressure is carried out by comparing the reference point pressure with a measured ring pressure (such as the pressure detected by any of the sensors 36, 38, 40), and decreasing the flow resistance through the plug 34 if the measured pressure is greater than the reference point pressure, and increasing the flow resistance through the choke if the measured pressure is less than the reference point pressure. Of course, if the pressures of the reference point and measurement are equal, then no adjustment of the obturator 34 is required. Preferably, this process is automated, so no human intervention is required, although human intervention can be used, if is desired The controller 96 can also be used to control the operation of the feeder tube flow control devices 76, 78 and the bypass flow control device 74. Consequently, the controller 96 can be used to automate the process of flow deflection of the fluid 18 from the feeder tube 26 to the branch line 72 before making a connection in the drill string 16, then diverting the flow from the branch line to the feeder tube after making a connection and subsequently resuming the normal circulation of 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 start each process, in turn, in order to manually handle a component of the system, etc.

The control system 90 also preferably includes a prediction device 148 and a data validator 150. The prediction device 148 preferably comprises one or more models of neural networks for predicting various well parameters. These 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 output of the pressure reference point of the ring coming from the hydraulic model 92, the positions of the flow control devices 34, 74, 76, 78, the density of the drilling fluid 18, etc. The prediction device 148 can predict any well parameter, and any combination of well parameters.

Preferably, the prediction device 148 is "trained" by entering the current and past actual values for the parameters to the prediction device. The terms or "weights" in the prediction device 148 may be adjusted based on the output derivatives of the prediction device with respect to the terms.

The prediction device 148 can be trained by entering the prediction device data obtained during drilling, simultaneously performing the connections in drilling string 16, and / or during other stages of a general drilling operation. The prediction device 148 can be trained by entering the prediction device data obtained during the drilling of at least one previous well bore.

The training may include the introduction to the predictive device 148 of the data indicative of the above errors in the predictions produced by the prediction device. The prediction device 148 can be trained by entering data generated by a computer simulation of the well drilling system 10 (including the drilling platform, the well, the equipment used, etc.).

Once trained, the prediction device 148 can predict or calculate the value that one or more parameters must 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 prediction device 148 does not necessarily include one or more models of neural networks. Other types of prediction devices that can be used include an artificial intelligence device, an adaptive model, a nonlinear function that generalizes to real systems, a genetic algorithm, a linear system model, and / or a non-linear system model, combinations of these, etc.

The prediction device 148 can perform a regression analysis, perform the regression in a non-linear function and can use granular computing. An output of a first principle model can be input to the prediction device 148 and / or a first principle model can be included in the prediction device.

The prediction device 148 receives the actual parameter values of the data validator 150, which may include one or more programmable digital processors, memory, etc. The data validator 150 uses various preprogrammed algorithms to determine whether the sensor measurements, the positions of the flow control device, etc., received from the data acquisition and control interface 94 are valid.

For example, if a received actual parameter value is outside an acceptable range, it is not available (for example, due to a sensor out of service) or differs by more than a predetermined maximum amount from a predicted value for that parameter (for example, due to a malfunction of the sensor), subsequently the data validator 150 may signal the actual parameter value as "invalid". Invalid parameter values should not be used to train the prediction device 148, or to determine the reference point of the desired pressure of the ring by the hydraulic model 92. Valid parameter values would be used to train the prediction device 148, to update the hydraulic model 92, to register in the database of the data acquisition and control interface 94 and, in the case of the reference point of the desired pressure of the ring, transmitted to the controller 96 to control the operation of the flow control devices 34, 74, 76, 78 The reference point of the desired pressure of the ring can be communicated from the hydraulic model 92 to each of the data acquisition and control interface 94, the prediction device 148 and the controller 96. The reference point of the desired pressure of the ring is communicated from the hydraulic model 92 to the data acquisition and control interface ¾ 4 to register in its database, and to be retransmitted to the data validator 150 with the other actual parameter values.

The reference point of the desired pressure of the ring is communicated from the hydraulic model 92 to the prediction device 148 for use in predicting future ring pressure reference points. However, the prediction device 148 could receive the point of reference of the desired pressure of the ring (together with the other actual parameter values) from the data validator 150 in other examples.

The reference point of the desired pressure of the ring is communicated from the hydraulic model 92 to the controller 96 for use in case the data acquisition and control interface 94 or the data validator 150 does not work correctly, or that the output of these other devices is not available for some reason. In such a circumstance, the controller 96 could continue to control the handling of the various flow control devices 34, 74, 76, 78 to maintain / achieve the desired pressure of the ring 20 near the surface.

The prediction device 148 is trained in real time, and is capable of predicting the current values of one or more sensor measurements based on the outputs of at least some of the other sensors. Consequently, if a sensor output is not available, the prediction device 148 can provide the missing sensor measurement values to the data validator 150, at least momentarily, until the sensor output becomes available again.

If, for example, during the process of connecting the drill string described above, one of the flow meters 62, 64, 66 does not work properly, or its output is not available or is not valid for some reason, then the data validator 150 can replace the predicted output of the flowmeter for the actual (or non-existent) output of the flow meter. It is considered that, in actual practice, only one or two of the flow meters 62, 64, 66 can be used. Therefore, if the data validator 150 fails to receive the valid output from one of these flow meters, the determination of the proportions of the fluid 18 flowing through the feeder tube 26 and the bypass line 72 could not be easily realized, were it not for the predicted parameter values delivered by the prediction device 148. It will be noted that the measurements of the proportions of the fluid 18 flowing through feeder tube 26 and branch line 72 are very useful, for example, to calculate the equivalent circulating density and / or friction pressure by hydraulic model 92 during the drill string connection process .

Validated parameter values are communicated from data validator 150 to hydraulic model 92 and controller 96. Hydraulic model 92 uses validated parameter values, and possibly other data flows, to calculate the bottomhole pressure I presented currently at the point of interest (eg, at the bottom of the well bore 12, in a problem zone, in a liner shoe, etc.), and the desired pressure in the ring 20 near the surface necessary to achieve a desired downhole pressure.

The data validator 150 is programmed to examine the individual parameter values received from the data acquisition and control interface 94 and determine whether each of them is within a predetermined range of expected values. If the data validator 150 detects that one or more parameter values it received from the data acquisition and control interface 94 is not valid, it can send a signal to the prediction device 148 to stop the training of the neural network model for the defective sensor, and stop the formation of other models that are based on parameter values from the defective sensor to train.

Although the prediction device 148 may fail to train one or more models of neural networks when a sensor fails, it may continue to generate predictions for sensor output or defective sensors (s) or sensors based on other sensor inputs, but still in operation , to the prediction device. After the identification of a defective sensor, the data validator device 150 can replace the predicted values of sensor parameters from the prediction device 148 to the controller 96 and the hydraulic model 92. Further, when the data validator 150 determines that a sensor is malfunctioning or that its output is not available, the data validator can generate an alarm and / or generate a warning, identifying the malfunction sensor, in such a way that an operator can take a corrective action.

Preferably, the prediction device 148 is also capable of training a neural network model representing the output of the hydraulic model 92. A predicted value for the reference point of the desired pressure of the ring is communicated to the data validator 150. If the Hydraulic model 92 has difficulty generating appropriate values or is not available, the data validator 150 can replace the predicted reference point of the desired pressure of the ring in the controller 96.

Referring now further to Figure 3, the pressure optimization unit 11 is illustrated representatively incorporated into a transport 110. As graphically depicted in Figure 3, the transport 110 comprises a wheeled vehicle 108 on which it is mounted. it carries the pressure optimization unit 11, but in other examples, the transport is not necessarily a wheeled vehicle.

The vehicle 108 illustrated in Figure 3 is a box trailer, with the pressure optimization unit 11 incorporated in the vehicle body portion. In other examples, the vehicle 108 could be a short truck (ie, without a box to be towed behind the truck) or another type of vehicle with wheels.

Preferably, the pressure optimizing unit 11 is incorporated into the transport 110, such that it is part of the transport, and is not a separate transportable element. However, in other examples the pressure optimization unit 11 could be transported separately (such as, in a flatbed trailer, etc.).

Referring now further to Figure 4, another configuration of the transport 110 is representatively illustrated. In this configuration, the pressure optimization unit 11 is incorporated into a floating vessel 112 (such as a barge, a ship, a floating platform for the production, storage and discharge (FPSO), etc.).

Again, the pressure optimization unit 11 is preferably incorporated into the transport 110, so that it is part of the transport, and is not a separately transportable element from the vessel 112. However, in other examples the pressure optimization unit 11 could be transported separately (such as, in a workshop ship, etc.).

Referring now further to Figure 5, a plan view of a configuration of the pressure optimization unit 11 is representatively illustrated. In this configuration, the pressure optimization unit 11 includes the choke manifold 32, the Coriolis flow meter. 58, the flow diverter 84, the control system 90, the fluid analysis system 102 and the rollers 106, together with a control center 114 for human interaction with the control system, etc. The command center 114 may include work stations 116 for human-computer interaction and communication equipment 118 for, for example, telephone, internet, radio, wireless, satellite and / or internet communication with remote locations.

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 Services, Inc., and the rheology measurement system 122 may be similar to described in the application of E.U.A. no. 61/377164. The rheological properties measured by system 122 may include density, oil / water ratio, specific gravity, chloride amount, electrical stability, shear stress, gel strength, viscosity and / or yield strength. .

The piping 124 can be provided for storing rigid lines. The electric power, as well as the hydraulic and pneumatic pressure, can be supplied to the pressure optimization unit 11 by the pipes 126 coming from the vehicle 108 or from the vessel 112.

Referring now further to Figure 6, a manner in which the pressure optimizing unit 11 can be integrated to the transport 110 is representatively illustrated. As depicted graphically in Figure 6, the shutter 34 is rigidly connected to a frame 128 of the vehicle 108 or vessel 112. Although only the plug 34 is shown in Figure 6, it will be noted that any or all of the elements of the pressure optimization unit 11 can (are) integrated into the vehicle 108 or vessel 112 according to the scope of this description.

By rigidly connecting the shutter 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 transport 110. However, in other examples, the unit of Pressure optimization 11 may not be incorporated into transport 110 (such as, if the pressure optimization unit is transported to the drilling site on a flatbed trailer or in a shipyard workshop, etc.).

In practice, the pressure optimization unit 11 is preferably conveyed to the drilling site as part of the transport 110. Without unloading the pressure optimization unit 11 of the vehicle 108 or vessel 112, the pressure optimization unit is interconnected with the various elements of the drilling equipment using the lines 104a-g, and it is operative (ready for use in a drilling operation) in a relatively short period of time. In this way, the incorporation of the pressure optimization unit 11 to the drilling operation is convenient, efficient and economical, thus saving time, money and labor.

Of course, if the pressure optimization unit 11 is transported to the drilling site in a flatbed trailer or a workshop ship, the optimization unit pressure can be discharged at the drilling site. In these situations, the process of interconnecting the pressure optimization unit 11 to the platform drilling equipment through lines 104a-g will still be relatively convenient, efficient and cost-effective.

Although only the wheeled vehicle 108 and the floating boat 112 are illustrated in the drawings, any type of transport can be used to transport the pressure optimization unit 11 to and from the drilling site. Trains and aircraft (for example, a hovercraft) are additional examples of suitable transports through which the pressure optimization unit 11 can be made mobile.

Now it can be observed in detail that the above description provides significant advances in the construction technique of well drilling equipment. The pressure optimization unit 11 described above can conveniently be transported to a drilling location, and can be interconnected to the drilling rig conveniently, efficiently and cost-effectively.

The above description describes a method of drilling wells. The method may include transporting a pressure optimization unit 11 to a drilling location, the pressure optimization unit 11 includes a choke manifold 32, a control system 90 that automatically controls the handling of the choke manifold 32, and a flow meter 58 that measures the flow of the drilling fluid 18 through the choke manifold 32, and then interconnect the optimization unit of pressure 11 to the drilling equipment (for example, the wellhead 24, the feeder tube 26, the separator 48, the agitator 50, and the mud pit 52, etc.) The method may also include the integration of the pressure optimization unit 11 to a transport 110. The transport 110 may comprise a wheeled vehicle 108 or a floating vessel 112.

The integration step may include rigidly connecting the pressure optimization unit 11 to a frame 128 of the transport 110. The interconnection stage may include the interconnection of the pressure optimization unit 11 to the drilling equipment, without prior unloading of the unit. of pressure optimization 11 of transport 110.

The pressure optimization unit 11 may include a flow diverter 84 that biases the flow of the drilling fluid 18 from a feeder tube 26 to the choke manifold 32, a back pressure pump 86 that pressurizes a borehole 20, a system of fluid analysis 102 comprising a gas analysis system 120 and / or a rheology measurement system 122, a clamp control of the rotary control device 98 and / or a lubricant supply of the rotary control device 100.

A pressure optimization unit 11 for use with a well drilling system 10 is also described above. The pressure optimization unit 11 can include a choke manifold 32, a control system 90 that automatically controls the handling of the choke manifold 32, and a flow meter 58 which measures the flow of drilling fluid 18 through choke manifold 32. Choke manifold 32, control system 90 and flowmeter 58 can each be incorporated into the same transport 110. which transports the pressure optimization unit 11 to a drilling location.

The pressure optimization unit 11 may also include a driven roller 106 storing the line 104a-g connecting the pressure optimizing unit 11 with the drilling equipment (eg, the wellhead 24, the feeder tube 26, the separator 48, the agitator 50, the mud pit 52, etc.).

The pressure optimization unit 11 can interconnecting to a rig at the same time that the pressure optimization unit 11 is incorporated into the transport 110.

It should be understood that the various embodiments of the present disclosure disclosed in this document can be used in different orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without being isolated from the principles of this description. The modalities are described merely as examples of useful applications of the principles of the description, which is not limited to the specific details of these modalities.

Of course, those skilled in the art, after careful consideration of the above description of representative embodiments of the description, will readily see that many modifications, additions, substitutions, deletions and other changes to the specific embodiments can be made, and such changes are contemplated by the principles of this description. Accordingly, the above detailed description should be understood to be clearly provided by way of illustration and example only, the essence and scope of the invention being limited only by the appended claims and their equivalents.

Claims

NOVELTY OF THE INVENTION Having described the invention as above, it is considered as a novelty and, therefore, is claimed as property contained in the following: CLAIMS

1. A well drilling method, characterized in that it comprises: transporting a pressure optimization unit to a drilling location, the pressure optimization unit includes a throttling manifold, a control system that automatically controls the handling of the throttling manifold, and a flow meter that measures the flow of the drilling fluid through the choke manifold; and then interconnect the pressure optimization unit to the drilling rig.

2. The method according to claim 1, further characterized in that it comprises the integration of the pressure optimization unit to a transport.

3. The method according to claim 2, characterized in that the transport comprises a vehicle with wheels.

4. The method according to claim 2, characterized in that the transport comprises a floating vessel.

5. The method according to claim 2, characterized in that the integration further comprises rigidly connecting the pressure optimization unit to a transport frame.

6. The method according to claim 2, characterized in that the interconnection of the pressure optimization unit to the drilling equipment is performed without prior unloading of the transport pressure optimization unit.

7. The method according to claim 1, characterized in that the pressure optimization unit further includes a flow diverter which diverts the flow of the drilling fluid from a feeder tube to the throttling manifold.

8. The method according to claim 1, characterized in that the pressure optimization unit further includes a back pressure pump which pressurizes a well ring.

9. The method according to claim 1, characterized in that the pressure optimization unit further includes a fluid analysis system comprising a gas analysis system.

10. The method according to claim 1, characterized in that the pressure optimization unit further includes a fluid analysis system comprising a system of rheology measurement.

11. The method according to claim 1, characterized in that the pressure optimization unit further includes a clamp control of the rotary control device.

12. The method according to claim 1, characterized in that the pressure optimization unit further includes a lubricant supply of the rotary control device.

13. A pressure optimization unit for use with a well drilling system, characterized the pressure optimization unit because it comprises: a multiple of strangulation; a control system that automatically controls the handling of the throttling manifold; Y a flow meter that measures the flow of the drilling fluid through the throttling manifold, wherein the choke manifold, the control system and the flowmeter are each incorporated into the same transport that transports the pressure optimization unit to a drilling location.

14. The pressure optimization unit according to claim 13, further characterized in that it comprises a flow diverter that diverts the flow of the drilling fluid from a feeder tube to the manifold of Strangulation

15. The pressure optimization unit according to claim 13, further characterized in that it comprises a back pressure pump which pressurizes a well ring.

16. The pressure optimization unit according to claim 13, further characterized in that it comprises a fluid analysis system comprising a gas analysis system.

17. The pressure optimization unit according to claim 13, further characterized in that it comprises a fluid analysis system which comprises a rheology measuring system.

18. The pressure optimization unit according to claim 13, further characterized in that it comprises an energized roller that stores the line connecting the pressure optimization unit to the drilling equipment.

19. The pressure optimization unit according to claim 13, characterized in that the transport comprises a wheeled vehicle.

20. The pressure optimization unit according to claim 13, characterized in that the transport comprises a floating vessel.

21. The pressure optimization unit according to claim 13, characterized in that the unit of Pressure optimization is rigidly connected to a transport frame.

22. The pressure optimization unit according to claim 13, characterized in that the pressure optimization unit is interconnected to the drilling equipment while the pressure optimization unit is incorporated into the transport.

23. The pressure optimization unit according to claim 13, further characterized in that it comprises a clamp control of the rotary control device.

24. The pressure optimization unit according to claim 13, further characterized in that it comprises a lubricant supply of the rotary control device.