Well drilling methods with automated response to event detection.

(54) Title: WELL DRILLING METHODS WITH AUTOMATIC RESPONSE TO EVENT DETECTION. (54) Title: WELL DRILLING METHODS WITH AUTOMATED RESPONSE TO EVENT DETECTION.

(57) Summary

A well drilling method may include detecting a drilling event by comparing a parameter signature generated during drilling with an event signature indicative of a drilling event, and automatically controlling a drilling operation in response to at least a partial match which results from comparing the parameter signature with the event signature. A well drilling system may include a control system which compares a parameter signature for a drilling operation with an event signature indicative of a drilling event, and a controller which controls the drilling operation automatically in response to the drill event that is indicated by at least a partial match between the parameter signature and the event signature.

(57) Abstract

A well drilling method can inelude detecting a drilling event by comparing a parameter signature generated during drilling to an event signature indicative of the drilling event, and automatically controlling a drilling operation in response to at least a partial match resulting from comparing the parameter signature to the event signature. A well drilling system can inelude a control system which compares a parameter signature for a drilling operation to an event signature indicative of a drilling event, and a controller which Controls the drilling operation automatically in response to the drilling event being indicated by at least a partial match between the parameter signature and the event signature.

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PATENT TITLE No. 358802

Holders): HALLIBURTON ENERGY SERVICES, INC.

Address: 10200 Bellaire Boulevard, Houston, Texas, 77072, USA

Name: WELL DRILLING METHODS WITH AUTOMATIC RESPONSE TO EVENT DETECTION.

Classification: CIP: E21B47 / 12; € ^ B47 / | C | E21847 / 06,

CPC: E21B47 / 12; E21B21 / 10; E21B44 / 00; E21B47 / 06

Inventor (s): NANCY DAVIS; CODY BUTLER; CHARLES M. POOL; RYAN HOURD; Aaron

REYNOLDS; CRAIG W. GODFftEY; FRANK URIAS; SAAD SAEED; EMAD BARKI; JAMES R. LOVORN

Number:. Feeta 4 &lt;rPi $ tWntación lfttemacional:

MX / a / 2013/014841 July 05, 2011

Validity: Twenty years

Expiration Date: July 5, 2031

Issue Date: August 27, 2018

The reference patent is granted based on articles 1. 2 * fraction V, 6 'paragraph III, and 59 of the Industrial Property Law.

In accordance with article 23 of the Industrial Property Law, this patent is valid for non-derogatory terms, counted from the date of filing of the international application and will be subject to the payment of the fee to keep it in force. the rights.

Whoever subscribes to this title does so based on the provisions of (6s afliculós 6 ° fraccionéis III and 7 ° bis 2 of the Industrial Property Law (Official Gazette of the Federation (DOF) 27 / 06Λ99Τ, amended on 028) 8 / 1994, ^ / 10 / (996, 12/26/1897, 05/17/1999 01/26/2004, 06/16/2005, 01/25/2006, 05/06/2009, 01/06/2010 , 06/18/2010, ^ 8/06/2010, 01/27/2012,, 09/04/2012, 08/01/2019 «and 03/13/2Q18), articles 1», 3'fraction V subsection to), 4th and 12th fractions I and III of the Regulations of the Nleeaeariff Institute of Industrial Property (ΰ.Ο.-F. 144) 2/1898, amended on 07/01/2002, 07/15/2004, 07/28/2004 2004 and 7/09/2007): articles 1 ° 3 °. '4^#, 5 · fraction V item a). 16 fcaefiMnes I y III y 80 del BatatutaríJrganico of the Mexican Institute of Industrial Property (DOF 12/27/1999. Reformed et 10/10/2002, 2 ^ / 07/2004, 04/08/2004 γ 13/69/2007 ) ;, °. 3 ° and 5 “clause a) of the Agreement that delegates powers to the Deputy Directors General, Coonffinadop. Diip ^ reaQjiviatoñpteeii ^ pufarqai.de ​​tas Regional Offices, Divisional Deputy Directors, Departmental Coordinators and other subordinates WeluXartiXUB Mexicano de ia'PrppiédqpjBtjuatrlBl. (DOF 12/15/1999, amended on 02/04/2000, 07/29/2004, 08/04/2004 and 09/13/2007)

This letter is signed with an advanced electronic signature (FIEL), based on articles 7 BIS 2 of the Industrial Property Law; 3 of its Regulations, and 1 section III, 2 section V, 26 BIS and 26 TER of the Agreement establishing the guidelines for the use of the Electronic Payment and Services Portal (PASE) of the Mexican Institute of Industrial Property, in the procedures indicated.

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DIVISIONAL DIRECTOR OF PATENTS NAHANNY CANAL REYES

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NAHANNY MARISOL CANAL REYES | 00001000000403252793 | Tax Administration Service | 1695 || MX / 2018/76632 | MX / a / 2013/014841 | Patent title PCT | 1223 | GAGV | Pág (s) 1 | UY6ozmbZrbuvNuU1qDfX4CCt

Digital stamp:

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WELL DRILLING METHODS WITH RESPONSE

- 'INJUMWAL

DETECTION OF EVENTS

TECHNICAL FIELD

The present disclosure relates generally to equipment used and operations performed in conjunction with an underground well and, in an embodiment described herein, more particularly provides well drilling methods with automatic re-detection of events.

FIELD OF THE INVENTION

It is desirable in drilling operations for certain events to be identified as soon as they occur, so that any necessary corrective action can be taken as soon as possible. Events can also be normal, expected events, in which case it would be desirable to be able to control drilling operations based on the identification of such events.

Therefore, it will be appreciated that improvements in the art are desirable.

BRIEF DESCRIPTION OF THE FIGURES

FIGURE 1 is a schematic view of a well system which represents principles of the present disclosure.

IMPI iNSTmrro mfxicano

OF THE PROPERTY

INDUSTRIAL

FIGURE 2 is a flow chart representing a method which represents principles of this description.

FIGURE 3 is a flow chart of an example of a parameter signature generation process which can be used in the method of FIGURE 2.

FIGURE 4 is a flow chart of an example of an event identification and event signature generation process which can be used in the method of FIGURE 2.

FIGURE 5 is a listing of events and corresponding event signatures that can be used in the

FIGURE 2.

DETAILED DESCRIPTION OF THE INVENTION

A well drilling system 10 and the associated method that may incorporate principles of the present disclosure is illustrated representatively and schematically in FIGURE 1. In system 10, a bore 12 is drilled by turning a drill bit 14 at one end of a drill string 16. A drilling fluid 18, commonly known as mud, is circulated down through the drill string 16, out of the drill bit 14, and upward through an annular zone 20 formed between the drill string and the Drill 12, to cool the drill bit, lubricate the drill string, remove

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<img file="MX358802B_D0006.tif" />

sediments and provide a measure of downhole pressure control. A 2'T check valve (typically a flapper type check valve) prevents the flow of drilling fluid 18 upward through drill string 16 (for example, when connections are made to drill string).

Downhole pressure control is very important in pressure controlled drilling and other types of drilling operations. Preferably, the downhole pressure is precisely controlled to avoid excessive fluid loss in the onshore reservoir surrounding well 12, unwanted fracture of the reservoir, unwanted influx of reservoir fluids into the well, etc. In typical controlled pressure drilling, it is desired to maintain the downhole pressure just above a reservoir interstitial pressure, without exceeding a reservoir fracture pressure. In typical unbalanced drilling, it is desired to maintain the downhole pressure somewhat less than the interstitial pressure, thereby obtaining a controlled inflow of reservoir fluid.

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

<img file="MX358802B_D0007.tif" />

₄ IMPI

MEXiCAN INSTITUTE ». ·

OF. THE PROPERTY

INDUSTRIAL unbalanced drilling.

In system 10, additional control over downhole pressure is obtained by closing annular zone 20 (for example, isolating it from communication with the atmosphere and 5 allowing the annular zone to be pressurized at or near the surface) using a rotation control device (RCD). RCD 22 seals around drill string 16 over a wellhead 24.

Although not shown in FIGURE 1, drill string 16 may extend upwardly through RCD 22 for connection to, for example, a rotary table (not shown), riser 26, a transmission stem (not shown), a rotary motorized unit and / or other conventional drilling equipment.

Drilling fluid 18 exits wellhead 24 via a butterfly valve 28 in communication with annular zone 20 below RCD 22. Fluid 18 then flows through drilling fluid return lines 30, 73 to a regulator manifold 32, which includes redundant regulators 34 (only one of which can be used at a time). Back pressure is applied to annular zone 20 by variably restricting fluid flow 18 through operating regulators 34.

The greater the flow restriction through the

IMPI

...... OF THE PROPERTY Ο »™//

INDUSTRIAL regulator 34, the greater the back pressure applied to annular zone 20. Thus, the downhole pressure can be conveniently regulated by varying the back pressure applied to annular zone 20. A hydraulic model can be used to determine the pressure applied to annular zone 20 at or near the surface which can result in a desired downhole pressure, so that an operator (or automatic control system) can easily determine how regulate the pressure applied to the annular zone at or near the surface (which can be conveniently measured) to obtain the desired downhole pressure.

The pressure applied to the annular zone 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 annular zone. The pressure sensor 36 detects the pressure below the RCD 22, above an explosion prevention assembly (BOP) 42. The pressure sensor 38 detects the pressure at the wellhead below the BOP assembly 42. The pressure sensor 40 detects the pressure in the drilling fluid return lines 30, upstream of the regulator manifold 32.

Another pressure sensor 44 detects the pressure in the drilling fluid injection line (riser) 26.

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IMPI „MEXICAN INSTITUTE

SAY THE FROM AGE

INDUSTRIAL

Some other pressure sensor 46 detects the pressure downstream of the regulator manifold 32, but upstream of a separator 48, agitator 50 and mud pit 52. Additional sensors include temperature sensors 54, 56, Coriolis flow meter 58, and flow meters 62, 64, 66.

Not all of these sensors are necessary. For example, system 10 may include only two of the three flow meters 62, 64, 66. However, input from the sensors is useful for the hydraulic model in determining what pressure would be applied to annular zone 20 during drilling operation.

In addition, drill string 16 may include its own sensors 60, for example, to directly measure downhole pressure. Such sensors 60 may be of the type known to those of skill in the art as Pressure While Drilling (PWD), Measurement While Drilling (MWD) and / or Diagram While Drilling (LWD) systems. These drill string sensor systems generally provide at least pressure measurement, and can also provide temperature measurement, detection of characteristics of the drill string (such as vibration, torsion, rpm, weight in the auger, jam-slip, etc.), reservoir characteristics (such as resistivity, density, etc.), characteristics of

<img file="MX358802B_D0009.tif" />

fluid and / or other measurements. Various telemetry formats (acoustic, pressure pulse, electromagnetic, etc.) can be used to transmit the measurements from the downhole sensor to the surface.

Additional sensors can be included in system 10, if desired. For example, another flow meter 67 could be used to measure the flow rate of fluid 18 leaving wellhead 24, another Coriolis flow meter (not shown) could be interconnected directly upstream or downstream of a mud pump team 68, etc. The pressure and level sensors could be used with the separator 48, the level sensors could be used to indicate a volume of drilling fluid in the mud pit 52, etc.

Fewer sensors could be included in system 10, if desired. For example, the output of the mud pump from the rig 68 could be determined by counting the strokes of the pump, rather than by using flow meter 62 or any other flow meters.

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

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Drilling fluid 18 is pumped through the vertical pipeline 26 and into the interior of drill string 16 by drilling equipment mud pump 68. Pump 68 receives fluid 18 from mud pit 52 and flows through a vertical pipe manifold 70 to vertical pipe line 26, the fluid then circulates downward through drill string 16, upward through the annular zone 20, through the drilling fluid return lines 30, 73, through the regulator manifold 32, and then through the separator 48 and the agitator 50 towards the mud pit 52 for conditioning and recirculation.

Note that, in system 10 to the extent described above, regulator 34 cannot be used to control back pressure applied to annular zone 20 for control of downhole pressure, unless fluid 18 flows to through the regulator. In conventional overbalanced drilling operations, such a situation will arise when a connection is made to drill string 16 (for example, to add another length of drill pipe to the drill string while drill 12 is drilled deeper), and lack of circulation will require that the downhole pressure be regulated simply by the density of the fluid 18.

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ΙΜΡΪ

In system 10, however, the fluid flow — L £ —a ~~. Through regulator 34 it can be maintained, even if fluid does not circulate through drill string 16 and annular zone 20, while making a connection in the drill string. In this way, pressure can still be applied to annular zone 20 by restricting fluid flow 18 through regulator 34, although a separate back pressure pump may not be used.

Instead, fluid 18 is flowed from the pump to regulator manifold 32 via bypass lines 72,75 when a connection is made to drill string 16. In this way, fluid 18 can pass the line of riser 26, drill string 16, and annular zone 20, and can flow directly from pump 68 into sludge return line 30, which remains in communication with annular zone 20. The restriction of this

<td>flow through the</td><td>regulator 34 will trigger</td><td>by</td><td>the</td><td>so much that</td><td>I know</td>

<td>apply pressure</td><td>to the annular zone 20.</td><td></td><td></td><td></td><td></td>

<td>How I know</td><td colspan="2">depicted in FIGURE</td><td> 1,</td><td>the line</td><td>of</td>

<td>lead 75</td><td>and the return line</td><td>of</td><td>mud</td><td>30 are</td><td>in</td>

communication with annular zone 20 via a single line

73. However, the bypass line 75 and the mud return line 30 could instead be connected separately to the wellhead 24, for example, using a relief valve.

<img file="MX358802B_D0012.tif" />

additional butterfly (for example, below RCD 22), in which case each of lines 30, 75 would be in direct communication with annular zone 20. Although some additional plumbing may be required at the equipment site, the effect The pressure in the annular zone could be essentially the same as connecting the bypass line and the mud return line 30 to the common line 73. Thus, it should be appreciated that various different configurations and components of system 10 can be used, without departing from the principles of this description.

Fluid flow 18 through bypass lines 72, 75 is regulated by a regulator or other type of flow control device 74. Line 72 is upstream of bypass flow control device 74, and line 75 is downstream of the bypass flow control device.

Fluid flow 18 through riser 26 is substantially controlled by a valve or other type of flow control device 76. Note that flow control devices 74, 76 can be independently controlled, providing benefits substantial to system 10, as described in greater detail below.

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INSTITUTO MEXICANc BE LA mOHEOAD indwstbiai

Since the flow rate of the fluid is 10 u? dr .. each of the riser and bypass lines 26, 72 is useful in determining how downhole pressure is affected by these flows, flow meters

64, 66 are shown in FIGURE 1 interconnecting on those lines. However, the flow rate through vertical pipeline 26 could be determined even if only flow meters 62, 64 were used, and the flow rate through bypass lines 72 could be determined even if only flow meters

62, 66 will be used. Thus, it should be understood that it is not necessary for the system 10 to include all of the sensors depicted in FIGURE 1 and described herein, and the system could instead include additional sensors, different combinations and / or types of sensors, etc. .

A bypass flow control device 78 and a flow restrictor 80 can be used to fill the vertical pipe line 26 and the drill string 16 after a connection is made, and the pressure between the vertical pipe line is equalized and sludge return lines 30, 73 before opening flow control device 76. Otherwise, the sudden opening of flow control device 76 before riser line 26 and drill string 16 are filled and pressurized with fluid.

<img file="MX358802B_D0014.tif" />

IMPI can cause undesirable 7nnA and annular pressure 20 (for example, due to flow to regulator manifold 32 that is temporarily lost while riser and drill string are filled with fluid, etc.).

By opening the vertical pipeline bypass flow control device 78 after a connection is made, fluid 18 is allowed to fill vertical pipeline 26 and drill string 16 while a substantial majority of the fluid continues to flow to through bypass line 72, thereby allowing continuous controlled application of pressure to the annular zone

twenty. After the pressure in the standpipe line has been equalized with the pressure in the mud return lines 30, 73 and the bypass line 75, the flow control device 76 can be opened, and then the control device Flow 74 can be closed to slowly divert increased fluid pressure 18 from bypass line 72 to vertical pipeline 26.

Before a connection is made to drill string 16, a similar process can be performed, except in reverse, to gradually divert fluid flow from riser line 26 to bypass line 72 in preparation for adding more pipe

<img file="MX358802B_D0015.tif" />

drilling to drill string 16. lis say, eT flow control device 74 can be gradually opened to slowly divert a greater portion of fluid 18 from riser line 26 to bypass line 72, and then the control device Flow 76 can be closed.

Note that flow control device 78 and flow restrictor 80 could be integrated into a single element (for example, a flow control device that has a flow restriction therein), and flow control devices 76 , 78 could be integrated into a single flow control device 81 (for example, a single regulator which can be gradually opened to slowly fill and pressurize riser line 26 and drill string 16 after a drill pipe connection is made, and then fully open to allow maximum flow while drilling) .

However, because typical conventional drill rigs are equipped with the flow control device 76 in the form of a valve on the vertical pipe manifold 70, and the use of the vertical pipe valve is incorporated into practices For conventional piercing, individually operable flow control devices 76, 78 are currently preferred.

IMPIOUS

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<img file="MX358802B_D0017.tif" />

collectively referred to below as if they were the sole flow control device 81, but it should be understood that the flow control device 81 may include the individual flow control devices 76,

78.

Note that system 10 could include a back pressure pump (not shown) to apply pressure to annular zone 20 and the drilling fluid return line 30 upstream of regulator manifold 32, if desired.

The back pressure pump could be used in place of, or in addition to, bypass line 72 and flow control device 74 to ensure that fluid continues to flow through regulator manifold 32 during events such as making connections to the string 16. In this case, additional sensors can be used, for example, to monitor the pressure and the outflow rate of the back pressure pump.

The use of a back pressure pump is described in

International Application No. PCT / US10 / 38586, filed June 15, 2010. The international application also describes a method of correcting a pressure set point of the annular zone during drilling.

In other examples, connections may not be made in

<img file="MX358802B_D0018.tif" />

IMPI the drill string 16 during drilling, for example, if the drill string comprises a spiral pipe. Drill string 16 could be provided with conductors and / or other lines (eg, on a side or interior wall of the drill string) to transmit data, commands, pressure, etc. between the bottom of the well and the surface (for example, for communication with the sensors

60) .

Methods for controlling pressure and flow in drilling operations are described, including the use of data validation and a prediction device in the

International Application No. PCT / US10 / 56433, filed on November 12, 2010.

With further reference now to FIGURE 2, a well drilling method 90 is schematically illustrated which can be used with system 10 of FIGURE 1. However, it should be clearly understood that method 90 could be used in conjunction with other systems while maintaining the principles of this description.

Method 90 includes an event detection process which can be used to alert an operator if an event occurs, such as triggering an alarm or displaying a warning if the event is an unwanted event (eg loss of fluid unacceptable towards the deposit,

<img file="MX358802B_D0019.tif" />

IMPI unacceptable flow of fluid from yaciijp pntn would do _ &lt;al · --------- probe, etc.), or when displaying information about the event if it is a normal, expected or desired event, etc. Well drilling methods incorporate event detection described in International Application No.

PCT / US09 / 52227, filed on July 30, 2009.

An event may be a precursor to another event occurring, in which case the detection of the first event may be used as an indication that a second event is about to or is in the process of occurring. Furthermore, a series of events can also provide an indication that another event is about to occur. In this way, one or more previous events can be used as a data source to determine if another event will occur.

Many different events and types of events can be detected in method 90. These events may include, but are not limited to, an onslaught (influx), partial fluid loss, total fluid loss, vertical pipeline bleed, regulator clogged, regulator empty, poor well cleaning (full bore around the string of borehole), downhole cross flow, borehole drift, low calibrated borehole, borehole rupture, dilation while running, dilation while mud pump is off, pipeline clogged, twisted pipe,

<img file="MX358802B_D0020.tif" />

IMPI

MEXICAN INSTITUTE

OE LA WtOMKHAO and IW5TMA1.

recoil, clogged auger nozzle, boqTrftTa ~ 7Sg^,K'á empty, surface processing equipment leaks, drilling equipment pump failure, back pressure pump failure, downhole sensor 60 failure, empty drill string, non-return valve failure , start of the drill pipe connection, connection of the finished drill pipe, etc.

To detect the events, the drilling parameter signatures produced in real time are compared to a set of event signatures to determine if any of the events represented by those event signatures are occurring. In this way, what happens now in the

<td>operation</td><td>drilling</td><td>(The signatures</td><td>of</td><td colspan="2">parameters</td><td>of</td>

<td>drilling)</td><td>are compared</td><td colspan="2">with a set</td><td>of</td><td>firms</td><td>than</td>

<td>correspond</td><td>to events of</td><td>drilling</td><td></td><td>yes</td><td>exists</td><td>a</td>

<td>coincidence,</td><td colspan="2">is an indication of</td><td>than</td><td>the</td><td>event</td><td>than</td>

<td>corresponds</td><td>to the signature</td><td>of event</td><td>than</td><td colspan="2">match</td><td>this</td>

happening.

Drilling properties (eg, pressure temperature, flow rate, etc.) are sensed by sensors, and the output from the sensors is used to supply data indicative of drilling properties. This drilling property data is used to determine

<img file="MX358802B_D0021.tif" />

drilling parameters of interest.

The data may also be in the form of data from deviated wells (for example, other wells drilled nearby or in similar lithologies, conditions, etc.). Previous drilling experience can also serve as a data source. Data can also be entered by an operator prior to or during the drilling operation.

A drilling parameter may comprise data related to a single drilling property, or a parameter may comprise a ratio, product, difference, sum or other data function related to the multiple drilling properties. For example, it is useful in drilling operations to monitor the difference between the flow rate of the drilling fluid injected into the well (for example, by the vertical pipe line 26 as detected by the flow meter 66) and the flow rate. of drilling fluid flow back from the well (eg, through drilling fluid return line 30 as detected by flow meter 67).

Thus, a parameter of interest, which can be used to define a part or segment of a signature, can be this difference in piercing properties (inbound flow rate-outflow rate).

During a drilling operation, the properties of

<img file="MX358802B_D0022.tif" />

Perforation were detected over time, since soa - oonbÍm.Tra '^^ · intermittently. In this way, the data related to drilling properties are available over time, and the behavior of each drilling parameter can be evaluated in real time. Of particular interest in Method 90 is how drilling parameters change over time, i.e. whether each parameter increases, decreases, remains substantially the same, stays within a certain range, exceeds a maximum, falls below a minimum etc.

These parameter behaviors are given appropriate values, and the values ​​are combined to generate parameter signatures indicative of what happens in real time during the drilling operation. For example, one segment of a parameter signature may indicate that riser pressure (for example, as measured by sensor 44) is increasing, and another segment of the parameter signature may indicate that the pressure upstream of the regulating manifold ( for example, as measured by sensor 40) decreases.

A parameter signature can include many (perhaps 20 or more) of these segments. In this way, a parameter signature can provide a snapshot of what is happening in real time during the drilling operation.

<img file="MX358802B_D0023.tif" />

IMPI

MtiUCAHO SMIWSnHAL INSTITUTE

An event signature, on the other hand, w rcpr eüélit'a ~ T? O that occurs in real time during a drilling operation. Instead, an event signature represents what the behaviors of the drill parameter will be when the corresponding event occurs. Each event signature is distinctive, because each event is indicated by a distinctive combination of parameter behaviors.

As discussed in the above, an event can be a precursor to another event. In that case, the event signature for the first event can be a distinctive combination of parameter behaviors which indicate that the second event is about to (or at least eventually goes

to happen.

Events may be parameters, for example, in the circumstance discussed above in which a series of events may indicate that another event is to occur. In that case, the behavior of the corresponding parameter may or may not be the precursor event that has occurred.

Event signatures can be generated prior to initiating a drilling operation, and can be based on experience gained from drilling similar wells under similar conditions, etc. Event signatures can also be refined as progress of the drilling operation and more experience is gained in the well than

<img file="MX358802B_D0024.tif" />

pierces.

In basic terms, sensors are used to detect drilling properties during a drilling operation, data related to detected properties are used to determine parameters of drilling interest, values ​​indicative of the behaviors of these parameters are combined to form parameter signatures, and the parameter signatures are compared for predefined event signatures, to detect if any of the corresponding events are occurring, or if it is substantially likely to occur.

The stages in the event detection process are schematically represented in FIGURE 2 in flowchart form. However, it should be understood that the method may additionally, alternatively, or optionally include the steps as well, and it is not necessary that all of the steps depicted be performed in accordance with the principles of this disclosure.

In a first step 92 represented in FIGURE 2, data is received. The data in this example is received from a central database, such as an INSITE ™ database used by Halliburton Energy Services, Inc. of Houston,

Texas USA, although other databases can be used if desired.

<img file="MX358802B_D0025.tif" />

IMPI

INSTITUTO MEXICAIW

Βί IA PUOWilwU)

2 INDUSTRIAL

The data is typically in the form of ite »nted-rc best drilling properties as it is detected from various sensors during a drilling operation. For example, sensors 36, 38, 40, 44, 46, 54, 56, 58, 60, 62,

64, 66, 67, as well as other sensors, will produce indications of various properties (such as pressure, temperature, mass or volumetric flow rate, density, resistivity, rpm, torque, weight, position, etc.), which are they will store as data in the database. Calibration, conversion and / or other operations can be performed by pre-data data to be received from the database.

Data can also be entered manually by an operator. As another alternative, the data may be received directly from one or more sensors, or from another data acquisition system, whether or not the data originates from sensor measurements, and without the former having been stored in a database. separate data. Furthermore, as discussed in the above, the data can be derived from a deviated well, previous experience, etc. Any source of the data can be used, in keeping with the principles of this description.

In step 94, various parameter values ​​are calculated for later use in method 90. By

<img file="MX358802B_D0026.tif" />

For example, you may want to compute a relationship — rcc dcdata, a sum of data values, a difference between data values, a product of data values, and so on. In some cases, however, the value of the data itself is used as is, without further calculation.

In step 96, the parameter values ​​are validated and approximation techniques can be used to ensure that meaningful parameter values ​​are used in the subsequent steps of method 90. For example, a parameter value may be excluded if it represents an excessively high value or Low for that parameter, and approximation techniques can be used to avoid excessively large parameter value transitions by distorting the subsequent analysis. A parameter value may correspond to whether or not another event has occurred, as discussed above.

In step 98, the parameter signature segments are determined. This step may include calculating the values ​​indicative of the behaviors of the parameters. For example, if a parameter has an increasing trend, a value of 1 can be assigned to the parameter signature segment of the corresponding parameter, if a parameter has a decreasing trend, a value of 2 can be assigned to the segment, if the parameter does not has changed, a

IMPI

MEXICAN INSTITUTE

OE IHfKCTIUAl PROPERTY

<img file="MX358802B_D0027.tif" />

value of 0 to segment, etc. For dét'éfrillñát-5T behavior of a parameter, statistical calculations (algorithms) can be applied to the parameter values ​​resulting from step 96.

Comparisons between parameters can also be made to determine a particular signature segment. For example, if only one parameter is greater than another parameter, a value of 1 can be assigned to the signature segment, if the first parameter is less than the second parameter, a value of 2 can be assigned, if the parameters are substantially the same, a value of 0 can be assigned etc.

In step 100, the parameter signature segments are combined to compose the parameter signatures. Each parameter signature is a combination of parameter signature segments and represents what is happening in real time in the drilling operation.

In step 102, the parameter signatures are compared to previously defined event signatures to see if there is a match. Since data is generated continuously (or at least intermittently) in real time during a drill operation, corresponding parameter signatures can also be generated in method 90 in real time for comparison with event signatures. In this way, an operator can be informed • ϊ

<img file="MX358802B_D0028.tif" />

immediately during the operation of pe rf σι a'C 1 ú'li 'SlTW event is occurring.

Step 104 represents the definition of the event signatures which, as described above, can be performed prior to and / or during the drilling operation.

Exemplary event signatures are provided in FIGURE 5, and are discussed in greater detail below.

In step 106, an event is indicated if there is a match between an event signature and a parameter signature. An indication may be provided to an operator, for example, by displaying information related to the event on a computer screen, displaying an alert, a sound alarm, etc. Indications can also take the form of recording the occurrence of the event in a database, computer memory, etc. A control system may also, or alternatively, respond to an indication of an event, as described in greater detail below.

In step 108, a probability that an event is occurring is indicated if there is a partial match between an event signature and a parameter signature. For example, if an event signature comprises a combination of 30 parameter behaviors, and a parameter signature is generated in which 28 or 29 of the parameter behaviors

<img file="MX358802B_D0029.tif" />

match those of the event signature) d'é'bé éXlSTlr some high probability that the event is occurring, although there may not be a complete match between the parameter signature and the event signature. It may be useful to provide an indication to an operator in this circumstance that the probability of the event occurring is high.

Another useful indication may be the probability that the event will occur in the future. For example if, as in the example discussed above, a substantial majority of parameter behaviors match between parameter signature and event signature, and parameter behaviors that do not match tend to match, then it can be useful ( particularly if the event is an unwanted event) warn an operator that the event is likely to occur, so that corrective action will be taken if needed (for example, to prevent an unwanted event from happening).

With further reference now to FIGURE 3, a flowchart of another example of the process of generating parameter signatures in method 90 is representatively illustrated. The process begins with receiving the data as in step 92 described above. . Parameter value calculations are then performed in step 94 described in .a

IMPI

ΙΗίΤΓΠΙΤΟ MEXICANO and LA ΡΑΟΛΕΟΑΓ INOUSTWAL

<img file="MX358802B_D0030.tif" />

previous. _

In step 110, preprocessing operations are performed for the parameter values. For example, maximum and minimum limits can be used for particular parameters, to erroneously exclude high and low parameter values.

In step 112, the preprocessed parameter values ​​are stored in a data buffer. The data buffer is used to hold the parameter values ​​for further processing.

In step 114, conditioning calculations are performed for the parameter values. For example, approximation (such as moving window average, Savitzky-Golay approximation, etc.) can be used as discussed above in relation to step 96.

In step 116, the conditioned parameter values ​​are stored in a data buffer.

In step 118, statistical calculations are performed for the parameter values. For example, trend analysis (such as, straight line fit, trend direction determination over time, first and second degree derivatives, etc.) can be used to characterize the behavior of a parameter. The values ​​assigned to the parameter behaviors become

<img file="MX358802B_D0031.tif" />

IMPT segments of the resulting parameter signatures', as — SB ~ -'—— »discussed above for step 98.

In step 120, the parameter signature segments are produced towards the database for storage, subsequent analysis, etc. In this example, the parameter signature segments become part of the INSITE ™ database for the drill operation.

In step 100, as discussed above, the parameter signature segments are combined to form the parameter signatures.

With further reference now to FIGURE 4, a flowchart of a process for identifying an event has occurred, or will occur, in method 90 representatively illustrated. The process begins with step 122, in which a event signature database. The database can be configured to include any number of event signatures to allow any number of corresponding events to be identified during a drill operation. Preferably, the event signature database can be configured separately for different types of drilling operations, such as unbalanced drilling, overbalanced drilling, drilling in particular lithologies, etc.

At step 124, a desired set of signatures is loaded

<img file="MX358802B_D0032.tif" />

IMPI institute Mtxjcu *) IX IA MIOfmMit IMKlOTMAL of events in the event signature database. As discussed above, any number, type, and / or combination of event signatures can be used in method 90.

At step 12-6, the event signature database is queried to see if there is any match with the parameter signatures generated in step 100. As discussed above, partial matches can optionally be identified, too.

In step 128, events are identified which correspond to event signatures that match (or at least partially match) with any parameter signatures.

The output at step 130 can take several different forms, which may depend on the identified event. An alarm, alert, warning, information display, etc. can be provided as discussed above for step 106. At a minimum, the occurrence of the event should be logged and in this example it is preferably logged, as part of the INSITE ™ database for the drilling operation.

With further reference now to FIGURE 5, four exemplary event signatures are tabulated representatively, along with parameter behaviors which correspond to the signature segments. In practice,

<img file="MX358802B_D0033.tif" />

IMPI can provide many more signatures of * '"events /^r and more 'or fewer parameter behaviors can be used to determine signature segments.

Notice that each event signature is distinctive. Thus, a lunge (inflow) event is indicated by a particular combination of parameter behaviors, where the fluid loss event is indicated by another particular combination of parameter behaviors.

If, during a drill operation, a parameter signature is generated which matches (or at least partially matches) any of the event signatures shown in FIGURE 5, they will be provided with an indication that a corresponding event is occurring. If a parameter signature is generated which matches an event signature at a predetermined level, or if the parameter signature segment tends to match, then an indication could be provided that the corresponding event is substantially likely to occur. This can happen even without any human intervention, resulting in a more automatic, accurate, and safe drilling environment.

Event indications provided by the method can also be used to control the drilling operation. For example, if an onslaught event is indicated, the operational regulators 34 can be set to

<img file="MX358802B_D0034.tif" />

response to the pressure increase applied to annular zone 20 in system 10. If fluid loss is detected, regulators 34 can be adjusted to decrease the pressure applied to annular zone 20. If a drill pipe connection is starting, the flow control devices 81, 74 can be appropriately adjusted to maintain a desired pressure in the annular zone 20 during the connection process, and when the drill pipe connection is detected is complete, the flow control devices can be appropriately adjusted to restore circulation flow through drill string 16 in preparation for the next drill.

These and other types of control over the drilling operation can be implemented based on detection of corresponding events using method 90 automatically and without human intervention, if desired. In one example, a control system such as that described in

International Application No. PCT / US08 / 87686 can be used to implement control over the drilling operation.

In some modalities, human intervention could be used, for example, to determine whether control over the drilling operation should be implemented in response to event detection in method 90. From i

<img file="MX358802B_D0035.tif" />

IMPI this mode, if an event is detected (or if the event is indicated as likely to occur), a human authorization may be required before the drilling operation is automatically controlled in response.

As shown in FIGURE 1, a controller 84 (such as a programmable logic controller or other type of controller capable of controlling the operation of the drill rig) is connected to a control system 86 (such as the described control system in the International Application

No. PCT / US08 / 87686, or as described in the Application

International No. PCT / US10 / 56433). Controller 84 is also connected to flow control devices 34, 74, 81 to regulate flow injected into the drill string

16, the flow through the drilling fluid return line 30, and the flow between the vertical pipe injection line 26 and the return line 30.

Control system 86 may include various elements, such as one or more computational devices / processors, a hydraulic model, a probe model, a database, software in various formats, memory, machine-readable code, etc. These elements and others can be included in a single structure or location, or can be distributed among multiple structures or locations.

Control system 86 connects to sensors 36,

<img file="MX358802B_D0036.tif" />

38, 40, 44, 46, 54, 56, 58, 60, 62, 64, 66, 67 which detect the respective drilling properties during the drilling operation. As discussed in the foregoing, deviated well data, previous operator experience, other operator input, etc., may also be entered into control system 86. Control system 86 may include software, programmable and preprogrammed memory, machine readable code etc. to carry out the steps of method 90 described above.

Control system 86 can be located at the well site, in which case sensors 36, 38, 40, 44, 46, 54, 56,

58, 60, 62, 64, 66, 67 could be connected to the control system by cables or wireless connection.

Alternatively, the control system 86 could be located in a remote location, in which case the control system may receive the data by satellite transmission, the

Internet, wireless connection, or by any other appropriate means. Controller 84 can also be connected to control system 86 in various ways, whether the control system is located locally or remotely.

In one example, control system 86 can cause one or any number of regulators 34 to shut down (eg, increasingly restricting fluid flow 18 through return line 30) by means of a quantity

<img file="MX358802B_D0037.tif" />

IMPL automatically predetermined in response to output stage 130 indicating that an onslaught (influx) has occurred, or is substantially likely to occur. For example, if the parameter signature matches (or substantially matches) the event signature for an onslaught, then control system 86 will operate controller 84 to close operational regulators 34 by the predetermined amount (for example, a percentage of the margin of the regulator, such as l% -10% of that margin).

The predetermined quantity could be preprogrammed in the control system 86, and / or the predetermined quantity could be entered, for example, by means of a human-machine interconnection. After regulators 34 have closed, the predetermined amount, control over the operation of regulators 34 can be returned to an automated system where a probing pressure set point or riser is maintained (whose set point it can be obtained, for example, from a hydraulic model or manual input), the regulators can be operated manually, or another way of controlling the regulators can be implemented.

In another example, control system 86 may cause one or any number of regulators 34 to open (eg, decrease the restriction of fluid flow 18 through return line 30) by an amount

ΙΜΡΙ

MEXICAN INSTITUTE '* 2 * £ ί? · Ϊ? ··, &lt;ί r&gt; F LA PROPIE1MI' NCIKTWIAI. «An ·· '-' automatically predetermined in response to — the · output of step 130 indicating that a fluid loss has occurred, or is substantially likely to occur. For example, if the parameter signature matches (or substantially matches) the event signature for a fluid leak, then control system 86 will operate controller 84 to open operating regulators 34 by the predetermined amount (eg, a percentage of the regulator's operating margin, such as l% -10% of that margin).

The predetermined quantity could be preprogrammed in the control system 86, and / or the predetermined quantity could be entered, for example, by means of a human-machine intercom. After regulators 34 have been opened the predetermined amount, control over the operation of regulators 34 can be returned to the automated system where a probe pressure set point or riser is maintained (whose set point can be obtained (for example, from a hydraulic model or manual input), the regulators can be operated manually, or another way to control the regulators can be implemented.

In another example, control system 86 may provide an alert or alarm to an operator that a particular event has occurred, or is substantially likely

<img file="MX358802B_D0038.tif" />

it happen. The operator can then take any necessary corrective action based on the alert / alarm, or can override any action taken by the control system 86 automatically in response to the output of step 130. If it has already been taken some action by the control system 8 6, the operator can undo or revert such actions, if he wishes.

In another example, control system 86 may switch from maintaining a desired sounding pressure to maintaining a desired vertical pipeline pressure in response to the output of step 130 indicating that an event has occurred, or is substantially likely to occur. A technique by which a control system can maintain sounding pressure is described in International Applications Nos.

PCT / US10 / 38586 and PCT / US10 / 56433, and a technique by which a control system can maintain a vertical pipeline pressure is described in International Application No.

PCT / US11 / 31767.

Control system 86 can switch between such sounding pressure set point and vertical pipeline pressure set point 26 modes automatically in response to the output of step 130 indicating that an event has occurred, or is substantially likely it happen. For example, if an onslaught event (influx) is detected,

<img file="MX358802B_D0039.tif" />

the control system 86 can change dy'fnánLélitü * —tme&gt; desired drilling pressure 12 to maintain a desired vertical pipe pressure 26. This de facto change can be made after verifying that the conditions are acceptable for making the change, and after providing an operator with an option (such as through a deployed alert) to initiate the change.

In another example, control system 86 may automatically provide an operator (such as a driller) with instructions or guidance for corrective action to be taken in response to the output of step 130 indicating that an event has occurred or is substantially likely to occur. Instructions or guidance may be provided via a local well site display screen, and / or may be transmitted between the site

<td colspan="2">well and remote location etc.</td><td></td><td></td><td></td>

<td>In another example,</td><td>the system</td><td>of</td><td colspan="2">control 86 can</td>

<td>implement a process</td><td>of control of</td><td>water well</td><td>automatically</td><td>in</td>

<td>exit response</td><td>of the stage</td><td> 130</td><td>which indicates that</td><td>he has</td>

an event has occurred, or is substantially likely to occur.

The well control process could include routing the return flow of fluid 18 to a conventional drill rig regulator manifold 82 and a gas eliminator (see FIGURE 1) designed to handle emergency situations.

<img file="MX358802B_D0040.tif" />

well control. _——

Alternatively, the well control process could include control system 86 that automatically operates regulator manifold 32 to optimally circulate out of an unwanted influx. An example of automatic operation of the regulator collector to circulate an unwanted influx is described in International Application No.

PCT / US10 / 20122, filed on January 5, 2010.

In another example, the control system 86 may manipulate a regulator 34 (eg, alternately open and close the regulator by a certain amount, etc.) automatically in response to the output of step 130 indicating that the regulator is clogged, or it is substantially likely to become clogged. Regulator 34 clogging event can be represented by an event signature which, for example, includes a parameter segment indicating an increase in pressure differential across the regulator. Manipulation of regulator 34 automatically in response to the output of step 130 can potentially dislodge whatever has obstructed or progressively obstructs the regulator.

In another example, control system 86 can change fluid flow 18 from one of regulators 34 to another of regulators automatically in response to the output of

<img file="MX358802B_D0041.tif" />

step 130 indicating that one of the regulators has been clogged, drained, blocked or otherwise compromised, or is substantially likely to re-engage. The change from one regulator 34 to another can be done progressively and automatically, so that a desired sounding pressure or vertical pipe pressure can also be maintained by the control system 86 during the change.

Control system 86 can change fluid flow 18 from one of regulators 34 to another of regulators automatically in response to the output of step 130 indicating that fluid flow 18 is out of, or is likely to be substantially find out of, an optimal operating margin of one of the regulators. Regulators 34 can have different edge sizes, so regulators have different optimal operating ranges. When the fluid flow 18 is outside the optimum operating range of the regulator 34 being used to variably restrict the flow, it may be beneficial to change the flow to another of the regulators having an optimum operating range that best matches the flow.

Control system 86 can open an additional regulator 34 automatically in response to the output of step 130 indicating that an operating margin in the {

<img file="MX358802B_D0042.tif" />

operating regulator has been exceeded, or is likely to be exceeded, by fluid flow 18. As the number of operating regulators 34 through which fluid 18 flows increases, the flow through each regulator is reduced , so that the operating margin of each regulator is not exceeded.

In another example, control system 86 may modify or correct a pressure set point (eg, received from a hydraulic model) automatically in response to the output of step 130 indicating that: a) a sensor (such as sensor 60, a pressing tool while drilling (PWD), etc.) has failed or is substantially likely to fail, b) drill string 16 has broken (eg, twisted, disconnected, retracted, etc.) down the shaft or is substantially likely to do so, and / or c) an influx or loss event has occurred or is likely to occur, making adjustments to the density of fluid 18 in the borehole desirable in models, such as the hydraulic model and / or a well model. Control system 86 can operate controller 84 using the modified / corrected setpoint, rather than the setpoint received from, for example, the hydraulic model. Control system 86 can update hydraulic and / or

<img file="MX358802B_D0043.tif" />

IMPI well with the revised fluid density 18 based on the detection of the influx or loss of fluid event.

In another example, control system 86 can automatically communicate to hydraulic and / or well models that an event has been detected. For example, if the event is a failure of sensor 60 (such as a PDW sensor, etc.), control system 86 may automatically communicate this to the hydraulic model, which will cease correcting the pressure set point based on the measurements. actual sensor.

As another example, if the event is part of the drill string 16, the control system 86 can automatically communicate this to the hydraulic and / or well models, which will adjust an annular zone volume 20 and / or other parameters in the model.

In another example, control system 86 may automatically open one or more of the previously inoperative regulators 84 in response to the output of step 130 indicating that there is excessive pressure in probe 12, or at least upstream of the manifold. regulator 32. A maximum pressure can be preprogrammed in control system 86 so that, if the maximum pressure is exceeded, one or more of regulators 34 will be opened by controller 84 to release excess pressure.

In another example, control system 86 can bypass

<img file="MX358802B_D0044.tif" />

IMPI θΐ flow to an equipment regulator collector -cte-peYfTrrercTÓTi— 82, or another regulator collector similar to regulator collector 32, automatically in response to the output in step 130 indicating that a RCD 22 sealing element has failed, or is substantially likely to fail. Control system 86 can also automatically open regulators 34 in a desired amount, thereby releasing pressure under RCD 22.

In another example, the control system 86 can modify the volume of an annular zone 20 used by the hydraulic and / or well models automatically in response to the output of step 130 indicating that a floating rig is oscillating. For example, the control system 86 may receive oscillation indications from the drilling rig from a floating drill rig motion compensation system. The volume of the annular zone 20 can be modified / corrected by the control system 86 automatically in response to indications that the drill rig has risen or fallen, thereby allowing the pressure set point of the borehole or pipeline vertical is updated based on the volume of the modified / corrected annular zone.

It can now be fully appreciated that the above description provides various benefits to the technique of

<img file="MX358802B_D0045.tif" />

events. Described in drilling, well drilling and drilling operations detection can be taken. The above methods allow you to detect events precisely and in real time, so that appropriate actions are needed. Control system 86 can automatically perform appropriate actions (such as, providing an alert or alarm, controlling the operation of regulators 34, controlling the operation of various flow control devices, etc.) in response to an indication that a particular drilling event has occurred, or is substantially likely to occur.

In particular, the foregoing description provides the art with a well drilling method 90 which includes the steps of detecting a drilling event by comparing a parameter signature generated during drilling with an event signature indicative of the drilling event, and automatically handle a drill operation in response to at least a partial match that results from comparing the parameter signature with the event signature.

Automatically controlling may include automatically adjusting a slider 34 in response to detection.

The piercing event may comprise an inflow, and automatically controlling may include automatically closing a regulator 34 a predetermined amount.

<img file="MX358802B_D0046.tif" />

in response to detecting the influx.

The piercing event may comprise a loss of fluid 18, and automatically controlling may include automatically opening a regulator 34 a predetermined amount in response to detecting loss of fluid 18.

The detection step may include detecting that the drilling event has occurred, or is substantially likely to occur.

The drilling event may comprise the start or end of a drill pipe connection process. Automatically controlling may include automatically restoring circulation flow through a drill string 16 in response to detecting the completion of the drill pipe connection process.

Automatically controlling can include automatically switching between a) maintaining a desired sounding pressure 12, and b) maintaining a desired vertical pipeline pressure 26.

The drilling event may comprise an influx.

Automatically controlling may include automatically implementing a well control process. The well control process may involve diverting fluid flow to a rig regulator manifold

82, automatically circulate an unwanted influx

<img file="MX358802B_D0047.tif" />

regulator 32, thereby circulating an unwanted influx out of the well.

The piercing event may comprise clogging a regulator 34, and automatically controlling may include automatically manipulating regulator 34. Manipulating regulator 34 may alternately open and close regulator 34.

Automatically controlling may include automatically changing the flow from a first regulator 34 to a second regulator 34. The piercing event may comprise that the flow through the first regulator 34 is outside an optimal operating range of the first regulator 34, compromising the first regulator 34, first regulator 34 is blocked, first regulator 34 is clogged, and / or first regulator 34 is emptied. Changing the flow may include automatically maintaining a desired pressure during the change.

The piercing event may comprise exceeding an operating range of one or more operational regulators 34, and automatically controlling may include automatically increasing a number of the operational regulators 34.

The perforation event may comprise the failure of a seal of a rotation control device 22. Control

<img file="MX358802B_D0048.tif" />

IMPI may automatically include automatically diverting the ^{1 1 11} '⁴·......

flow to a drill rig regulator manifold 82, and / or open a regulator 34 a predetermined amount, thereby progressively releasing pressure through the rotation control device 22.

Automatically controlling can include communicating drill rig oscillation information to a model.

The drilling event may comprise selection of drilling equipment.

Automatically controlling may include automatically adjusting the volume of annular zone 20, and / or automatically updating a pressure setpoint.

The drilling event may comprise a sensor failure 36, 38, 40, 44, 46, 54, 56, 58, 60, 62, 64, 66, 67.

Automatically checking can include reporting sensor failure 36, 38, 40, 44, 46, 54, 56, 58, 60, 62, 64,

66, 67 to a model.

Automatically controlling the drilling operation may further be performed in response to human authorization of such automatic control of the drilling operation.

A well drilling system 10 is also described above. Well Drilling System

IMPI

IHÍirrWtn MEXICANO / 1 T ΪΝί LA MONEDAD 'i / INDUSTRIAL may include a control system 86 el γί.ιαΊ nr._to parameter signature for a drill operation with an event signature indicative of a drill event, and a controller 84 which handles the drill operation automatically in response to the drill event indicated by at least a partial match between the signature parameter and event signature.

Controller 84 can automatically adjust a regulator 34 in response to the indicated piercing event.

The piercing event may comprise an inflow, and controller 84 may automatically shut down a regulator 34 a predetermined amount in response to the indicated inflow.

The piercing event may comprise a loss of fluid 18, and controller 84 may automatically ope n a regulator 34 a predetermined amount in response to the indicated fluid loss 18.

The at least partial match may indicate that the drilling event has occurred, or that the substantial drilling event is likely to occur.

The drilling event comprises a start or end of a drill pipe connection. Controller 84 can automatically restore circulation flow to

IMPI

INSTITUTO MEXICANO OE LA nonioAO through a drill string 16. hwwtmm.

Control system 86 can change automatically

<img file="MX358802B_D0049.tif" />

between a) maintaining a desired sounding pressure, and b) maintaining a desired vertical pipeline pressure.

The drilling event may comprise an influx.

Control system 86 can automatically implement a well control process. The well control process may comprise diverting fluid flow 18 to a drill rig regulator manifold 82, automatic circulation of an unwanted influx out of the wellbore, and / or automatic operation of a regulator manifold

32, where the unwanted influx is circulated out of the well.

Drilling event may comprise a regulator

3. 4 clogging, and controller 84 may automatically manipulate regulator 34. manipulation of regulator 34 may comprise alternately opening and closing regulator 34.

Control system 86 can automatically change the flow from a first regulator 34 to a second regulator 34.

The piercing event may comprise flow through the first regulator 34 that is outside an optimal operating range of the first regulator 34, or the first regulator 34 that is compromised, blocked, obstructed, and / or

<img file="MX358802B_D0050.tif" />

IMPI instituto mexjc *¹*’

D n Dt LA «OFIEDAO

9 INDUSTRIAL empty. The control system 8 6 pinnate 'inuiiLUHOT automatically a desired pressure while changing the flow from the first regulator 34 to the second regulator 34.

The piercing event may comprise an operating range of one or more operating regulators 34 being exceeded, and control system 86 may automatically increase a number of operating regulators 34.

The drilling event may comprise the failure of a rotation control device seal 22. Control system 86 can automatically divert flow to a drill rig regulator manifold 82, and / or automatically open a regulator 34 an amount predetermined, wherein the pressure through the rotation control device 22 is progressively released.

Control system 86 can automatically communicate drill rig oscillation information to a model.

The drilling event may comprise equipment swing. Control system 86 can automatically adjust the volume of annular zone 20, and / or automatically update a pressure set point.

The perforation event may comprise a sensor failure 36, 38, 40, 44, 46, 54, 56, 58, 60, 62, 64, 66, 67.

The control system 86 can automatically communicate the ιι «iii.« To .. '«Μλ, β

IMPI

MEXICAN INSTITUTE OF INDUSTRIAL RULE

<img file="MX358802B_D0051.tif" />

sensor failure 36, 38, 40, 44, 46, 54, 56, 58, 60, 62, 64,

66, 67 to a model.

Control system 86 may provide an alert, an alarm, guidance to an operator, and / or at least one option for responding to the indicated drilling event.

<td>The controller</td><td> 84</td><td>can</td><td>control</td><td>the</td><td>operation</td><td>of</td>

<td colspan="3">drilling automatically</td><td>also in</td><td colspan="2">answer to</td><td>the</td>

<td>human authorization</td><td>of</td><td>such</td><td>control of</td><td>the</td><td>operation</td><td>of</td>

<td>drilling.</td><td></td><td></td><td></td><td></td><td></td><td></td>

<td>It must be understood</td><td>than</td><td>the</td><td>diverse</td><td colspan="2">modalities of</td><td>the</td>

The present disclosure described herein can be used in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of this disclosure. The modalities are simply described as examples of useful applications of the principles of description, which are not limited to any specific details of these modalities.

Of course, a person skilled in the art could, after careful consideration of the foregoing description of the representative modalities of the disclosure, readily appreciate that many modifications, additions, substitutions, deletions, or other changes can be made to the specific modalities, and such changes are

<img file="MX358802B_D0052.tif" />

I

MEXICAN INSTITUTE OF THE «INDUSTRIAL OFFICE contemplated by the principles of this description. By.

Accordingly, the foregoing detailed description is to be clearly understood as given by way of illustration and example only, the spirit and scope of the present invention are limited only by the appended claims and their equivalents.

IMPig ^

IKTIIUTO HLUCAHC Dt LA ttOHÍDAC, «NOdSTWAt