Well drilling methods with event detection.

(54) Title: WELL DRILLING METHODS WITH EVENT DETECTION.

(54) Title: WELL DRILLING METHODS WITH EVENT DETECTION.

(57) Summary

A piercing method that includes defining an event signature that comprises a unique combination of a behavior of each of the multiple piercing parameters, the event signature is indicative of a piercing event; access data from each of the multiple sensors which detect the respective drilling parameters during a drilling operation; define multiple parameter signature segments from the respective detected drilling parameters; combine the parameter signature segments, thereby forming a parameter signature; and compare the parameter signature with the event signature.

(57) Abstract

A drilling method includes assigning values ​​to behaviors of drilling parameters during a drilling operation; forming multiple parameter signatures, each of the parameter signatures comprising a respective combination of the values; comparing the parameter signatures to multiple event signatures, each of the event signatures being indicative of a respective drilling event; and controlling the drilling operation in response to at least a partial match resulting from comparing the parameter signatures to the event signatures. Another method includes defining an event signature comprising a unique combination of a behavior of each of multiple drilling parameters, the event signature being indicative of a drilling event; accessing data from each of multiple sensors which sense the respective drilling parameters during a drilling operation; determining multiple parameter signature segments from the respective sensed drilling parameters; combining the parameter signature segments, thereby forming a parameter signature; and comparing the parameter signature to the event signature.

<img file="MX359083B_D0001.tif" />

I Μ Ρ 1

PATENT TITLE No. 359083

Owner (s): HALLIBURTON ENERGY SERVICES, INC.

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

Name: WELL DRILLING METHODS WITH EVENT DETECTION.

Classification: CIP: E21B44 / 00; E21B21 / 08; E21B47 / 00

CPC: E21B44 / OQ; E21B21 / 08; E21B47 / 00

Inventors): SAAD SAEED; CHARLES M. POOL; FRANK URIAS; JAMES R. LOVORN; EMAD

BAKRI

REQUEST

Number: International Presentation Date:

MX / a / 2014/009591 July 3, 2009

Divisional Patent Number: 325019 / P JT. · | Ρ ΜΓ: O -P 'Ú'Pp' V 'HP&gt; PV p

Validity: Twenty years

Expiration Date: July 30, 2029

Issue Date: September 7, 2018 _t

The reference patent is granted based on ice articles V, H fracpon V. Smwcciupill, and 59 of the Industrial Property Law.

In accordance with article 23 of the Industrial Property Law, this patent has a validity of twenty non-expendable articles, counted from the date of filing of the international application and will be subject to the payment of the fee to keep the rights in force.

Whoever subscribes to this title does so based on the provisions of faith&gt; aiifcujo^s fractions IB and 7 ° bis 2 of the Industrial Property Law (Official Gazette of the Federation (OO, F.) 27/0 «, 1991, amended on 06/02/1994, 10/26/1996, 12/26 / 1997, 17/0571999 01/26/2004, 06/16/2005, 01/25/2006, 05/06/2009, 06/01/2010, 08/09/2010, 28/06/2010, 27 / 91 / 2012.0 ^ / 04/2012, 06/01/2016 and 03/13/2018), articles 1, 3, section V, subsection a), 4^orand 12 sections I and III of the Mexican Dollnstiuito Regulation of Industrial Property (pjO / E. 4/12 / 199Θ, amended on 07/01/2002, 07/15/2004, 07/28/2004 and 07/09 / 2007); Articles 1 ·, 3, 4 ', 5th fraction V subsection p), 16 Iracctones I and III and 90 of the Organic Statute of the Mexican Institute of Industrial Property (DOF 12/27/1999, amended on 10/1 QZ2002, 07/29/2004, 04/08/2004 and 09/13/2007); 1, 3 »and 5» subsection a) of the Agreement that delegates powers to the Deputy Directors General, Coordinator, Divisional Qifqqtopas, TitularqMe the Regional Offices, Divisional Deputy Directors, Departmental Coordinators and other subalteAoS óe | | nst | Ujto.líféxican &lt;) dé ia Prapyedad | qdtáffrial. (DOF 12/15/1999, amended on 02/04/2000, 07/29/2004, 04/08/2004 and 09/13/2007). '·' ”&gt;

This letter is signed with an advanced electronic signature (FIEL), based on articles 7 BIS 2 of the Industrial Property Law; 3rd 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.

THE DIVISIONAL DIRECTOR OF PATENTS

NAHANNY CANAL REYES

<img file="MX359083B_D0002.tif" />

Original string:

NAHANNY MARISOL CANAL REYES | 00001000000403252793 | Administration Service

Tax | 1695 || MX / 2018/78979 | MXja / 2014/009591 [Normal patent title with divisional PCT | 1223 | GAGVjPág (s) | y5íB8í9mjfPVmiej5KB4b4AYa¿Y =

Digital Seal: lEbcPQ + QKXdqdSfxA8TqdMnmqSKEzxc08T30eeEc / ppQpx9l1T + X3tDNdOntk1CDuRJrFFQAoewFJRGYtpC7VahHIS yGmS1GMFrsHFFzo1NNeGHUV9EUAKQNg / f ++ nZFCyAs2mxfMvxab / eBetB5VMqj5V67UJGgpkA8vTkHILbil2kVV6F DFLe2jOQYzT2h065PNfwJJ / kmCKIAAhgKyg9 + 6p8wuPBX812IEzplbNBhwDc5KhvwkAPbgBIJORNOp1PlnODFLbGDh v0R24Xgwhse34GdjW8CE0yhs1yXuDBRvv7AIKCvD01ZbhyehRL4NEDuyClqUaTOEhzyKK7Cg = "&gt; í t ' ^F * μ * i child. 16020 &lt;- '*^{* 1} I i; 7.7Λ · íM Ίΐχ / ίίΤψι

<img file="MX359083B_D0003.tif" />

Hxlcjxoiwiooqsq /

WELL DRILLING METHODS WITH f

<img file="MX359083B_D0004.tif" />

MEXICAN INSTITUTE 74—

OF INDUSTRIAL PROPERTY

FIELD OF THE INVENTION

The present disclosure generally relates to the equipment used and the operations carried out in conjunction with an underground well and, in an embodiment described herein, drilling more particularly provides event detection well methods.

BACKGROUND OF THE INVENTION

It is desirable in drilling operations that certain events be identified as soon as they occur, so that any necessary corrective action is taken as soon as possible. The events may 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 of detecting events that occur during drilling operations would be desirable.

BRIEF DESCRIPTION OF THE DRAWINGS

Figure 1 is a schematic view of a well system incorporating the principles of the present disclosure.

Figure 2 is a flow chart representing a

<img file="MX359083B_D0005.tif" />

IMPIf,. ,._n ... MEXICAN INSTITUTE f method that incorporates the principles of disclosure.

Figure 3 is a flow chart of an example of a parameter signature generation process that can be used in the method of Figure

2.

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

DETAILED DESCRIPTION OF THE INVENTION

Representatively and schematically it is illustrated in

FIG. 1 a well drilling system 10 and associated method which may incorporate principles of the present disclosure. In system 10, an L2 well is drilled by rotating a bit 14 at one end of a drill column 16. Drilling fluid 18, commonly known as sludge, is circulated downward through drill column 16, out of bit 14, and upward through a ring 20 that is formed between drill string 20 and the well 12, in order to cool the bit, lubricate the drill column, remove cuttings and provide a measure of downhole pressure control. A non-return valve 21 (typically a reverse flow check valve (flapper type)) that prevents

IMPI

M EX ICAN INSTITUTE '&gt; Ί

FROM! TO PR &lt;ΡΙΕ'ΛΑΙ 'flow of drilling fluid 18 upward through drilling column 16 (eg, cuaridóTe ”estah ..... ñ'a'fi 1 éñdó connections in the drill column).

Downhole pressure control is very important in pressure controlled drilling and other types of drilling operations. Preferably, the downhole pressure is precisely controlled to prevent excessive loss of fluid in the soil formation surrounding well 12, unwanted fracturing of the formation, unwanted influx of fluids from the formation into the wellbore, etc. In typical controlled pressure drills, it is desirable to maintain the downhole pressure just above a formation pore pressure, without exceeding a formation fracture pressure. In typical low-balance drilling, it is desirable to keep the downhole pressure slightly less than the pore pressure, thereby obtaining a controlled influx of formation 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 low-balance drilling operations.

In system 10, additional control over downhole pressure is obtained by closing ring 20 (eg, isolating it to the ring

IMPI

JA MEXICAN INSTITUTE

FROM FKWt £ t&gt; AO CSia -Yes, &amp; J from communicating with the atmosphere By pressing to press on or off using a rotary control device 22 (RCD). RCD 22 seals around drill column 16 above a wellhead 24. Although not shown in Figure 1, drill string 16 would extend upward through RCD 22 for connection to, for example, a turntable (not shown), a line of stabilizer tube 26, stem (not shown ), a motor in the top drive and / or other conventional drilling equipment.

Drilling fluid 18 leaves wellhead 24 through a wing valve 28 in communication with ring 20 below RCD 22. Fluid 18 then flows through drilling fluid return lines.

30, 73 to a multiple choke 32, which includes redundant choke 34 (only one of which can be used at a time). Back pressure is applied to ring 20 by variably restricting fluid flow 18 through throttle (s) 34.

The greater the restriction to flow through the choke 34, the greater the back pressure applied to the ring 20. Consequently, the pressure at the bottom of the well can be conveniently regulated by varying the back pressure applied to the

<img file="MX359083B_D0006.tif" />

ring 20. A hydraulic model will determine a pressure applied to the surface which will result in a desired downhole pressure so that an operator (or an automated control system) can easily determine how to regulate the pressure applied to the o-ring. close to the surface (which can be conveniently measured) in order to obtain the desired downhole pressure.

The pressure applied to 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. Pressure sensor 36 detects pressure below RCD 22, but above a Blowout Preventer (BOP) block 42. Pressure sensor 38 holds pressure at the wellhead below BOP block 42. The pressure sensor 40 detects the pressure in the drilling fluid return lines 30, 73 upstream of the throttle manifold 32.

Another pressure sensor 44 detects the pressure in the injection line (pressure stabilizing tube) 26 of the drilling fluid. Still another pressure sensor 46 detects the pressure downstream of the manifold throttle 32, but upstream of a separator 48, agitator 50, and sludge tank 52.

Additional sensors include temperature sensors 54, 56,

<img file="MX359083B_D0007.tif" />

IMPI INSTITUTO MEXICANi) DE LA MONEDA.) Coriolis flowmeter 58, and flowmeters 62,

Not all of these sensors are required. For example, the eT system 10 may include only two of the three flowmeters 62, 64, 66. However, the input of these sensors is useful for the hydraulic model in determining what the pressure should be. applied to ring 20 during drilling operation.

In addition, drill column 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 ordinary skill in the art as Pressure While Drilling (PWD), Measurement While Drilling (MWD) and / or Drilling Log (LWD, Logging While Drilling). These drill string sensor systems generally provide at least pressure measurement, and can also provide temperature measurement, detection of drill string characteristics (such as vibration, torque, revolutions per minute, bit weight). , stick slip, etc.), fluid characteristics and / or other measurements. Various forms of telemetry (acoustic, pressure pulse, electromagnetic, etc.) can be used to transmit sensor measurements in the background

<img file="MX359083B_D0008.tif" />

from the well to the surface.

Additional sensors could be included '' éiFer sistema

10, if desired. For example, another flowmeter 67 could be used to measure the flow rate of the fluid leaving wellhead 24, another flowmeter could be interconnected upstream or downstream of a drilling rig mud pump

Pressure and level sensors could be used

68, etc.

with separator 48, level sensors could be used to indicate a volume of drilling fluid in mud tank 52, etc.

<td colspan="2">They could include</td><td>fewer sensors in system 10,</td><td>yes</td>

<td>is desired.</td><td>For example,</td><td>the output of the mud pump</td><td>of the</td>

<td>team of</td><td>drilling</td><td>68 could be determined by</td><td>the</td>

<td>count of</td><td>racing</td><td>the pump, instead of using</td><td>a</td>

flowmeter 62 or any of the other flowmeters.

Note that separator 48 can be a 3 or 4 phase separator, or a sludge gas separator (sometimes referred to as a poor boy degasser sludge degasser). However, separator 48 does not necessarily use system 10.

Drilling fluid 18 is pumped through the line of stabilizer tube 26 and into drill pipe 16 by drill rig mud pump 68. Pump 68 receives ^^ * '^ j ^^ o '^ 0 ^^^ INDUSTRIAL sludge tank 52 and flows it through a stabilizer tube manifold 70 to the stabilizer tube line

26, the fluid column then flows downward through bore 16, upward through the ring

20, through the drilling fluid return lines 30,

73, through multiple choke 32, then through separator 48 and agitator 50 to the mud tank for conditioning and recirculation.

Note that, in the system as described so far, the choke cannot be used to control back pressure applied to the downhole pressure control ring, unless fluid 18 flows through the choke . In conventional overbalanced drilling operations such a situation will arise whenever a connection is made in the column, adding another length of drill pipe to the drill column as well 12 is drilled deeper), and the lack of circulation will require that the pressure at the bottom of the well is regulated only by the density of the fluid 18.

In system 10, however, fluid flow 18 can be maintained through throttle 34, even though fluid does not circulate through drill column 16

<img file="MX359083B_D0009.tif" />

and ring 20, while the drilling column is being made &amp; SH &amp; ^ 'SiS &amp; eWX INDUSTRIAL. Consequently, pressure can still be applied to ring 20 by restricting fluid flow 18 through throttle 34, even though a separate back pressure pump cannot be used.

Instead, fluid 18 flows from pump 68 to manifold 32 through a bypass line.

72, 75 when a connection is being made in drill column 16. Accordingly, fluid 18 can avoid the line of stabilizer tube 26, drill column 16 and ring 20, and can flow directly from pump 68 to the sludge return line 30, which is maintained in communication with ring 20. Restriction of this flow by throttle 34 will thereby cause pressure to be applied to ring 20.

As shown in Figure 1, both the bypass line 75 and the mud return line 30 are in communication with ring 20 via a single line 73. However, bypass line 75 and the mud return line 30 could be separately connected to wellhead 24, for example, using an additional wing valve (eg, below RCD 22), in which case each of lines 30, 75 would be directly in communication with ring 20. Although this may require some additional pumping

<img file="MX359083B_D0010.tif" />

in the place

Drilling Team PC^N,^ST,^^ oVéí £ éc ^ ™ ^ g ^ the INDUSTRIAL - ring pressure would be essentially the same as connecting the bypass line 65 and the mud return line 30 to the common line 73. Consequently, it should be appreciated that they can be utilizing several different configurations of system components 10, without departing from the principles of this disclosure.

Fluid flow 18 through bypass line 72, 75 is regulated by a choke or other type of bypass 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 stabilizer tube line 26 is substantially controlled by a valve other type of flow control device 76. Note that flow control devices 74, 76 are independently controlled, providing substantial benefits to system 10, as described in greater detail below.

Since the flow rate of flow 18 through each of the stabilizer and bypass tube lines 26, 72 is useful in determining how pressure to the bottom of the well is affected by these flows, flowmeters 64, 66 are plotted in Figure 1 as

<img file="MX359083B_D0011.tif" />

lines. However, the flow through the line

<img file="MX359083B_D0012.tif" />

Stabilizer 26 could still be determined if only flowmeters 62, 64 were used, and the flow rate across bypass line 72 could still be determined if only flowmeters 62, 66 would be used. Consequently, it should be understood that no it is necessary for system 10 to include all of the sensors depicted in Figure 1 and described herein, and the system could instead include additional sensors, combinations and / or different types of sensors, etc.

A bypass flow control device 78 and a flow regulator can be used to fill the stabilizer tube line 26 and the drill column 16 after a connection is made, and equalize the pressure between the tube line stabilizer and mud return lines 30, 73 before opening flow control device 76. Otherwise, the sudden opening of flow control device 76 before the stabilizer tube line 26 and drill column 16 are filled and pressurized with fluid 18 could cause undesirable transient pressure in ring 20 (p , eg, because flow to manifold manifold 32 is temporarily lost while stabilizer tube line

<img file="MX359083B_D0013.tif" />

<img file="MX359083B_D0014.tif" />

and the drill column are filled with

When you open the device from conTTü! ' de --- ftü'Ju --de-— · bypass 78 of the stabilizer tube after a connection is made, fluid 18 is allowed to fill the line of the stabilizer tube 26 and drill column 16 while a substantial majority of fluid continues to flow through bypass line 72, thereby enabling continuous and controlled application of pressure to ring 20. After the pressure in the stabilizer tube line 26 has equalized the pressure in the mud return lines 30, 73 and bypass line 75, the flow control device 76 can be opened, and then the flow control device 74 to slowly divert a larger proportion of fluid 18 from bypass line 72 to stabilizer tube line 26.

Before a connection is made to drill column 16, a similar process can be carried out, except in reverse, to gradually divert fluid flow 18 from stabilizer tube line 26 to bypass line 72 in preparation for add more drill pipe to drill column 16. That is, flow control device 74 can be gradually opened to slowly divert a greater proportion of fluid 18 from stabilizer tube line 26 to bypass line 72, and can then be closed.

<img file="MX359083B_D0015.tif" />

flow control 76.

Note that flow control device 78 and regulator 80 could be integrated into a single element (eg, a flow control device that has a flow restriction on it), and flow control devices. flow 7 6, 78 could be integrated into a single flow control device 81 (eg, a single choke that can be gradually opened to slowly fill and pressurize the stabilizer tube line 26 and drill column 16 after a drill pipe connection is made, and then fully open to allow maximum flow during drilling) .

However, since conventional conventional drilling rigs are equipped with the flow control device 7 6 in the form of a valve in the stabilizer tube manifold 70, and the use of the stabilizer tube valve is incorporated in the As usual drilling practices, individually operable flow control devices 76, 78 are currently preferred. Flow control devices 76, 78 are sometimes referred to collectively as below as being in a single flow control device 81, but it should be noted that flow control device 81 ¹⁴

INSTITUTO MU IC.AN-&gt; may include control devices^DFWL&gt; ®Uj'® ^^! P^lIndividual HO. .

Note that system 10 could include a back pressure pump (not shown) to apply pressure to ring 20 and to the drilling fluid return line 30 upstream of manifold throttle 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 manifold throttle 32 during events such as making connections to the column. 16. In this case, additional sensors can be used, for example, to monitor the pressure and the outflow of the back pressure pump.

In other examples, connections could not be made to drill string 16 during drilling, for example, if the drill string comprises flexible tubing. Drill column 16 could be provided with conductors and / or other lines (eg, on a side or interior wall of the drill column) to transmit data, commands, pressure, etc. between the bottom of the well and the surface (eg, for communication with sensors 60).

Referring now further to Figure 2, a well drilling method is schematically illustrated.

MUICaH INSTITUTE.

which can be used with system 10

However, it must be clearly understood that qu-o · - o 1 -metodo -9- ^ &lt;?? You could use it in conjunction with other systems to stick to the principles of this disclosure.

Method 90 includes an event detection process that 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 unacceptable fluid in the formation, unacceptable flow of fluid from the formation into the wellbore, etc.), or by displaying information about the event if this is a normal, expected or desired event, etc. Additionally, an event may be a precursor to another event that occurs, in which case the detection of the first event can be used as an indication that the second event is about to happen or is in the process of happening.

Furthermore, a series of events may also provide an indication that another event is about to happen. Consequently, 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 can include, but are not limited to, a kick, partial fluid loss, total fluid loss, pressure loss from the

<img file="MX359083B_D0016.tif" />

stabilizer tube, ruined choke, poor hole cleaning (full well around drill column), downhole cross flow, for your ruined, underrated well, drilling interruption, baloning during circulation, balinging while mud pump is turned off, pipe is stuck, pipe is kinked, reverse, bit nozzle plugging, bit nozzle failure, back pressure pump failure, downhole sensor failure 60, ruined drill column, non-return valve failure, start of drill pipe connection, termination of drill pipe connection, etc.

In order to detect the events, the signature drilling parameters produced in real time are compared to a set of signature events in order to determine if any of the events represented by those event signatures are occurring. Consequently what is happening now in the drilling operation (the drilling parameter signatures) is compared to a set of signatures corresponding to drilling events and if there is a match this is an indication that the event that corresponds to a matching event signature.

Drilling properties (eg, pressure,

<img file="MX359083B_D0017.tif" />

IMPI

INSTITUTO MÜXICANC DE LA nODEDAtINDUSTRIAL (temperature, flow, etc.) are detected by sensors and the output of the sensors is used to supply data indicative of drilling properties. These drilling property data is used to determine the drilling parameters of interest.

The data may also be in the form of data from independent wells (eg, other wells drilled nearby or in lithologies, similar conditions, etc.). Previous drilling experience can also serve as a source for the data. Data can also be entered by an operator before 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 there was another function of data related to multiple drilling properties. For example, it is useful in drilling operations to monitor the difference between the flow of drilling fluid injected into the wellbore (eg, through the line of stabilizer tube 26 detected by flowmeter 66) and the flow rate of drilling fluid. drilling returning from the well (eg, through the drilling fluid return line 30 detected by flowmeter 67). Consequently, a parameter of interest, which can be used to define a part or segment of

<img file="MX359083B_D0018.tif" />

IMPLW

INSTITUTO MEXICANO, DE LA FROTIEPAD ·, difference in flow rate que-gafrefr ·?

perforation, the properties of either continuously or a signature can be this perforation (flow that enters

During a drilling operation they are detected intermittently. Consequently, data related to drilling properties are available over time, and the behavior of each drilling parameter can be evaluated in real time. It is of particular interest in Method 90 how drilling parameters change over time, that is, if each parameter is increasing, decreasing, remains substantially the same, stays within a certain range, exceeds a maximum, falls below the minimum etc.

These parameter behaviors have appropriate values, and the values ​​are combined to generate parameter signatures indicative of what is happening in real time during the drill operation. For example, one segment of a parameter signature could indicate that the stabilizer tube pressure (eg, measured by sensor 44) is increasing, and another segment of the parameter signature could indicate that the pressure upstream of the manifold Choke (eg, measured by sensor 40) is decreasing.

A parameter signature can include many (maybe 20

<img file="MX359083B_D0019.tif" />

IMPI iiicnTVTO Mexican ^lH DF LA PtOPtWAF or more) of these segments. Consequently, parameter signature can provide a snapshot of what is happening in real time during the drilling operation.

An event signature, on the other hand, does not represent what is happening in real time during a drilling operation. Instead, an event signature is representative of what the drill parameter behaviors will be when the corresponding event occurs. Each event signature is unique, as each event is indicative by a unique combination of parameter behaviors.

As previously discussed, an event can be a precursor to another event. In this case, the event signature for the first event can be a unique combination of parameter behaviors which indicates that the second event is about to (or at least eventually will) happen.

Events can be parameters, for example in the circumstance discussed above where a series of events can indicate that another event is going to happen. In that case, the corresponding parameter behavior can be whether the precursor event (s) happened (eron) or not.

Event signatures can be generated before starting a drilling operation, and can be passed in

<img file="MX359083B_D0020.tif" />

IMPb

MMICANi INSTITUTE

Df LA PKOriEDAI drilling'SW^T^l'' of experience gained from similar under similar conditions, event etffTTK — event fíTiuas — can also be refined as a drilling operation progresses and more experience is gained in the well being drilled.

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

The steps in the event detection process are schematically represented in the

Figure 2 in the form of a flow chart. However, it should be understood that method 90 may also include additional, alternative, or optional steps, and that it is not necessary that all of the steps depicted be performed to maintain the principles of this disclosure.

In a first step 92 represented in the

Figure 2, the data is received.

The data in this example is received from a central database, such as an INSITE ™ database used by Halliburton Energy Services,

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

The data is typically in the form of drilling property measurements that are detected by 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 volume flow, density, resistivity, revolutions per minute, torque, weight, position, etc.), which will be stored as data in the database. Calibration, conversion and / or other operations can be carried out for the data before the data is received from the database.

The data can also be entered manually by an operator. As another alternative, data can 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 first being stored in a database. separately. Also, as discussed above, the data can be derived from an independent well, previous experience, etc. Any source can be used for the data, keeping the

<img file="MX359083B_D0021.tif" />

<img file="MX359083B_D0022.tif" />

principles of this disclosure.

In step 94, it is calculated in several jza-bax cu? ...., - ¼ parameter ·· for later use in method 90. For example, it may be desirable to compute a ratio of data values, a sum of values data, a difference between data values, a product of data values, etc. In some cases, however, the same data value is used as is, without any additional calculation.

In step 96, the parameter values ​​are validated, and smoothing techniques can be used to ensure that significant parameter values ​​are used in subsequent steps of method 90. For example, a parameter value can be excluded if it represents a Excessively high or low value for the parameter, and smoothing techniques can be used to prevent unacceptably large parameter value transitions that distort subsequent analysis. A parameter value can 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 values ​​indicative of the behaviors of the parameters. For example, if a parameter has a growth trend, you can assign a value of 1 to the signature segment of

INSTITUTO MEXlCAN *. DE LA PRCFIEDAÍ) corresponding parameter, if a parameter ''^T’‘‘^ltierré '^' ^ ina decreasing trend, you can assign Y 'üñ a value of 2 to the segment, if the parameter has no changes, you can assign a value of 0 to the segment, etc. To determine the behavior of a parameter, statistical calculations (algorithms) can be applied to the parameter values ​​resulting from step 96.

Comparisons can also be made between parameters to determine a particular signature segment. For example, if a parameter is larger 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 make 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 the data is being generated continuously (or at least intermittently) in real time during a drill operation, the parameter signatures

<img file="MX359083B_D0023.tif" />

corresponding

IMPI

INSTITUTO MEXICANO DE LA PROrlEDAL?

INDUSTRIAL can also be generated in method 90 in real time for comparison with event signatures. Consequently, an operator can be informed immediately during the drilling operation if an event is occurring.

Step 104 represents defining event signatures which, as described above, can be performed before and / or during the drilling operation. The following table provides exemplary event signatures, 10 and are discussed in more detail later.

EVENT SIGNATURES

<td>PARAMETERS Eistabiliradcr tube pressure</td><td>INFLUX Decreasing</td><td>LOST ; Growing</td><td>CONNECTION INITIATED Decreasing</td><td>CONNECTION I FINISHED Growing</td>

<td>................... water ettanguiadtor above</td><td>Decreasing</td><td>Growing</td><td>Decreasing</td><td>Growing</td>

<td>Pressure of the esttengul «lüf downstream</td><td>Without Hffltóes</td><td>SüionMt i</td><td>Decreasing</td><td>Growing</td>

<td>Due to I »pressure of ΘΟΡ</td><td>Decreasing</td><td>Growing</td><td>Decreasing</td><td>Growing</td>

<td>Ring pressure</td><td>Decreasing</td><td>Growing</td><td>Decreasing</td><td>Growing</td>

<td>Bottom pressure dd sin</td><td>Decreasing</td><td>ErtetW</td><td>Decreasing</td><td>Growing</td>

<td>Prison d # separator</td><td>Sm wmbot</td><td>sm changes =</td><td>Without change *</td><td>Sm changes</td>

<td>Pump pressure counter-session</td><td>Decreasing</td><td>Growing</td><td>Growing</td><td>Decreasing</td>

<td>Upstream throttle temperature Downstream iKMrarguladcr dat temperature</td><td>Decreasing Decreasing ................................................</td><td>Stn changes Sm changes</td><td>Decreasing Decreasing</td><td>Growing Growing</td>

<td>Tempei atura al praised pcwro</td><td>Decreasing</td><td>Sm cambras</td><td>Without change *</td><td>GfWGÍlüJOt.®¹</td>

<img file="MX359083B_D0024.tif" />

<img file="MX359083B_D0025.tif" />

<td>Flqo qwe enters</td><td>-Without change</td><td>Stn changes</td><td>_r_... ......... ............ saw Decreasing</td><td></td>

<td rowspan="2">flow coming out</td><td rowspan="2">Growing</td><td rowspan="2">Decreasing</td><td>Dpcrwypnta.</td><td>ΟπΚΓΙήΛΐβ ..</td>

<td></td><td></td>

<td>Back pressure bemba rate</td><td>Decreasing</td><td>Growing</td><td>Crescent '</td><td>Decrease</td>

<td>Bit depth</td><td>M / A</td><td></td><td>Erratic</td><td>Erratic</td>

<td>Penetration rate</td><td>N / A</td><td>Ν / Λ</td><td>Growing</td><td>Growing</td>

<td>Hook load</td><td>Growing</td><td>ΙΨΑ</td><td>Erratic</td><td>Erratic</td>

<td>Bit weight</td><td>Growing</td><td>ΗΆ</td><td>Decreasing</td><td>Growing</td>

<td>PPM</td><td>cambo »</td><td>NA</td><td>Decreasing</td><td>Growing</td>

<td>Torque</td><td>EmMioo</td><td>MA </td><td>Decreasing</td><td>Growing</td>

<td>Strangler Tamsite</td><td>Growing</td><td>Decroctenle 1</td><td>Decreasing</td><td>Growing</td>

<td>Tank volume</td><td>Growing</td><td>Decreasing</td><td>Without changes</td><td>Without cambra</td>

<td>Deposit da vuje</td><td>Growing</td><td>Dacreótert *</td><td>Without change »</td><td>Without cambe®</td>

<td>Otl weight harmful sludge</td><td>Without changes</td><td>S® change * í</td><td>Without changes</td><td>Without cambe®</td>

<td>Pe »del todo out</td><td>Decreasing</td><td>S »n changes</td><td>Without changes</td><td>Without cambe®</td>

<td>FMóctue enters «Flw0 leaving</td><td>Growing</td><td>Decreasing</td><td>Decreasing</td><td>Growing</td>

In step 106, an event is indicated if there is a match between an event signature and a parameter signature. An indication can be provided to an operator, for example, by displaying information related to the event on a computer screen, displaying an alert, sounding an 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 of an event occurring is indicated if there is a partial match between a signature of

<img file="MX359083B_D0026.tif" />

<img file="MX359083B_D0027.tif" />

ΡΪ event a parameter signature.

I

MEXICAN INSTITUTE OF PROPERTY _. ,, INDUSTUlAI. _, ~

For example, if an event signature comprises a combination of 30 parameter behaviors, and a parameter signature is generated in that 28 or 29 of the parameter behaviors match those of the event signature, there may be a high probability that the event is occurring, although there may not be a complete match between the parameter signature and the event signature. It might be useful to provide an indication to an operator in this circumstance that the probability that the event is occurring is high.

Another useful indication would be the probability that the event is occurring in the future. For example if, as in the example discussed above, 28 or 29 of the 30 parameter behaviors match between the parameter signature and the event signature, and the mismatched parameter behaviors tend to match, then it would be useful ( particularly if the event is an unwanted event) warn an operator that the event is likely to occur, so that corrective action is taken if necessary (for example, to prevent an unwanted event from happening).

Referring now further to Figure 3, a flow diagram of another example of the parameter signature generation process in method 90 is representatively illustrated. The process begins with receiving the data as

<img file="MX359083B_D0028.tif" />

IMPI,, INDUSTRIAL in step 92 described above. Parameter value calculations are then carried out in step 94 as described above.

In step 110, the processing operations for the parameter values ​​are carried out. For example, maximum and minimum limits are used for particular parameters, in order to exclude erroneously high or low values ​​from the parameters.

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

In step 114, the conditioning calculations for the parameter values ​​are performed. For example, smoothing (such as moving the media window, Savitzky-Golay smoothing, 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, determination of trend direction over time, first and second order derivatives, etc.) can be used to characterize

MEXICAN INSTITUTE

OF THE «OPIEDAl.

the behavior of a parameter. The values' assigned to the parameter behaviors become segments of the resulting parameter signatures, as discussed above for step 98.

At step 120, the parameter signature segments are output to the database for storage, further 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.

Referring now further to Figure 4, a flow diagram of another example of the event signature generation process in method 90 is representatively illustrated. The process begins with step 122, in which a database of event signature. The database can be configured to include any number of event signatures to enable 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 underbalanced drilling, overbalanced drilling,

<img file="MX359083B_D0029.tif" />

<img file="MX359083B_D0030.tif" />

INSTITUTO MEXICANO drilling in private lithologies, etc. ^{d, the}in ^ t «Íaí

At step 124, a desired event-of-Eipmaa set is loaded into the event signature database. As discussed above, any number, type, and / or combination of event signatures can be used in method 90.

In step 126, the event signature database is queried for any matches to the parameter signatures generated in step 100. As discussed above, partial matches can also be optionally identified.

In step 128, events corresponding to event signatures which match (or at least partially match) any of the parameter signatures are identified. The output in 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, as preferably logged in this example, as part of the INSITE ™ database for the operation operation.

Referring further now to the EVENT SIGNATURES table above, four exemplary event signatures are tabulated, along with behaviors.

<img file="MX359083B_D0031.tif" />

IMPI

MEXICANC INSTITUTE

DK THE PROtlFDAr parameter segments that correspond to the

In practice, many more can be provided — event signatures, and more or fewer parameter behaviors can be used to determine signature segments.

Keep in mind that each event signature is unique. Consequently, a kick event is indicated by a particular combination of parameter behaviors, while a fluid loss event is indicated by another particular combination of parameter behaviors.

If, during a drill operation, a parameter signature is generated that matches (or at least partially matches) any of the event signatures shown in the EVENT SIGNATURES table, an indication will be provided that a corresponding event is occurring. This can happen even without human intervention, resulting in a more automated, accurate, and safe drilling environment.

The event indications provided by method 90 can also be used to control the drilling operation. For example, if an inflow event is indicated, the operating choke (s) 34 may be adjusted in response to the pressure increase applied to ring 20 in system 10. If loss of fluid, the choke (s)

TTSTITVTC MEXICANO

DE LA FROHEDAÜ you can *) to decrease the pressure applied to the anl-Mt) ”20.-^,,'S'i — is starting a drill pipe connection, the flow control devices 81, 74 can be appropriately adjusted to maintain a desired pressure in the ring during the connection process, and when termination of the connection of the drill pipe, the flow control devices can be appropriately adjusted to restore flow circulation through drill column 16 in preparation for drilling ahead.

These and other types of control in the drilling operation can be implemented based on the 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 Document Serial No. PCT / US08 / 87686 can be used to implement such control in the drilling operation.

As depicted 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 the control system 86 (such as the control system described in application document

<img file="MX359083B_D0032.tif" />

IMPI) international with serial number controller 84 is also connected

PC to devices ...... from.

flow control 34, 74, 81 to regulate the flow that is injected into the drill column 16, the flow through the drill fluid return line 30, and the flow between the stabilizer tube injection line 26 and return line 30.

Control system 86 may include various elements, such as one or more computing devices / processors, a hydraulic model, a well 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 is connected to sensors

36, 38, 40, 44, 46, 54, 56, 58, 60, 62, 64, 66, 67 which detect respective drilling properties during the drilling operation. As previously discussed, independent well data, previous operator experience, other operator inputs, etc. they may also be inputs to control system 86. Control system 86 may include software, programmable and pre-programmed memory, machine-readable code, etc. to carry out the steps of method 90 described above.

The control system

6 can

INDUSTRIAL -of the well, in which case sensors 36, 38, 40, 44, __54L.

56, 58, 60, 62, 64, control system

66, 67 could be wired or wirelessly connected.

Alternatively, the control system 86 could be located at a remote location, in which case the control system could receive data by satellite transmission, the Internet, wirelessly, or by other appropriate means. Controller 84 may also be connected to control system 86 in various ways, whether the control system is located locally or remotely.

It can be fully appreciated that the above disclosure provides many benefits in the field of well drilling and event detection during drilling operations. The methods described above enable accurate detection of drilling events in real time, so that appropriate actions are taken if necessary.

In particular, the above disclosure provides the subject matter with a method of drilling wells 90 which includes the steps of: assigning a value to a behavior of each of the multiple drilling parameters during a drilling operation; form multiple parameter signatures, each of the parameter signatures comprises a

IMPI respective combination of values; Compare “rÚN &amp; ® * s&gt; * i fí? s? eSr * ae parameter with multiple event signatures / sow-ma -da-tasevent signatures being indicative of a respective drilling event; and controlling the drill operation in response to at least a partial match that results from comparing the parameter signatures with the event signatures.

Controlling the drill operation can be performed in response to a complete match that results from comparing parameter signatures with event signatures.

Method 90 may include drilling a well 12, and the drilling operation is preferably carried out in compliance with the drilling of well 12.

Method 90 may include alerting an operator in response to at least the partial match that results from comparing parameter signatures with event signatures.

At least one of the behaviors can understand an increasing trend. At least one of the behaviors can comprise an increasing trend in a greater proportion than a predetermined one.

At least one of the behaviors can comprise a decreasing trend. At least one of the behaviors can comprise a decreasing trend in a greater proportion than a predetermined one.

Control perf operation

<img file="MX359083B_D0033.tif" />

controlling the flow through a drilling fluid return line 30. Controlling the drilling operation may include controlling the flow through a drilling fluid injection line 26.

Drilling parameters can be derived at least in part from drilling properties detected by sensors during drilling operation, from data from an independent well, from operator input, from whether at least one precursor event has occurred. , and / or whether multiple precursor events have occurred.

Method 90 may include, in response to at least a partial match that results from comparing parameter signatures with event signatures, indicating that an event will occur.

Also provided in the above disclosure is a well drilling system 10 including a control system 86 including a machine readable code and a processor which a) assigns a value to a behavior of each of the multiple drilling parameters during the drilling operation, b) forms multiple parameter signatures, each of the parameter signatures comprises a respective combination of values, and c) compares the parameter signatures with multiple event signatures, each of the

<img file="MX359083B_D0034.tif" />

e event signatures being indicative

IMPH

MUICANi INSTITUTE! of * ®® ™ respective perforation. The Ha pnzíig-ui drilling system also comprises a controller 84 which controls the drilling operation in response to at least a partial match resulting from comparing the parameter signatures with the event signatures.

Controller 84 can control the drill operation in response to a complete match that results from comparing parameter signatures with event signatures.

The drilling operation may comprise drilling well 12.

Control system 86 can alert an operator in response to at least the partial match that results from comparing parameter signatures with event signatures.

At least one of the behaviors can comprise an increasing trend, an increasing trend in proportion

<td>greater than a default one</td><td>trend</td><td>decreasing, or</td><td>a</td>

<td>decreasing trend in</td><td>proportion</td><td>greater than</td><td>a</td>

<td>default.</td><td></td><td></td><td></td>

<td>Controller 84 can</td><td>control</td><td>the operation</td><td>of</td>

drilling at least in part by controlling flow through a drilling fluid return line 30, by controlling flow through an injection line of

<img file="MX359083B_D0035.tif" />

IMPI n

a parameter signature;

and compare the event signature fi.

Method 90 may include indicating the event when the parameter signature matches the event signature. Method 90 may include indicating an event probability when the parameter signature partially matches the event signature.

Determination of multiple signature segments may include determining a trend of at least one of the detected drilling parameters, determining a ratio of the detected drilling parameters being selected, determining a difference between the detected drilling parameters being selected, determining if at least one of the detected drilling parameters is within a predetermined range, determining if at least one of the detected drilling parameters is greater than a predetermined value, and / or determining if at least one of the detected drilling parameters is less than a predetermined value.

The event may comprise an undesired abnormal event. The event could alternatively comprise an expected normal event.

Method 90 may include controlling the drill operation in response to comparing the parameter signature with the event signature. Control the operation of

<img file="MX359083B_D0036.tif" />

³⁹ IMPI.,, INSTITUTO MEXICO drilling may include controlling the luxury ^ ÉfJ ^ fofté drilling fluid return line 30. .at ^ = i^TTog of a drilling fluid injection line 26 and / or a drilling fluid injection line 26 to a drilling fluid return line 30

Data access may include entering independent well data indicative of respective drilling properties, entering operator experience indicative of respective drilling properties, and / or entering if at least one previous event has occurred.

It should be understood that the different embodiments of the present disclosure described in this document can be used in different orientations, such as inclined, inverted, horizontal, vertical, configurations, without departing from the present disclosure. Modalities etc., and various principles thereof, are described only as examples of useful applications of the principles of disclosure, which is not limited to any specific detail of these modalities.

Of course, a person skilled in the art would readily appreciate, with careful consideration of the above description of representative disclosure modalities, that many modifications can be made,

<img file="MX359083B_D0037.tif" />

IMPI additions, substitutions, deletions, and oCÍ'SS.Ta ^ hÉhÍ'o

INDUSTRIAL - specific modalities, and that such changes are contemplated by the principles of this disclosure. Accordingly, it should be clearly understood that the foregoing detailed description is given by way of illustration and example only, the spirit and scope of the present invention is limited only by the appended claims or their equivalents.

NOVELTY OF THE INVENTION ^¹™

INPUüTRÍaL

Having described the present invention as above, it is considered as a novelty and, therefore, the content of the following is claimed as property: