Directional drilling control.

(54) Title: DIRECTIONAL PERFORATION CONTROL. (54) Title: DIRECTIONAL DRILLING CONTROL.

(57) Summary

Methods and apparatus for using a hollow shaft to drive a hydraulic motor when elongating a well hole in a direction that has a horizontal component, where the hollow shaft and hydraulic motor are coupled to opposite ends of a drill string, by monitoring an actual tool orientation of a hydraulic motor driven tool by monitoring a drilling operation parameter that indicates a difference between the actual tool orientation and a desired tool orientation, and then adjusting a hollow shaft position by an amount which depends on the monitored drilling operation parameter.

(57) Abstract

Methods and apparatus for using a quill to steer a hydraulic motor when elongating a wellbore in a direction having a horizontal component, where the quill and the hydraulic motor are coupled to opposing ends of a drill string, by monitoring an actual toolface orientation of a tool driven by the hydraulic motor via monitoring a drilling operation parameter indicative of a difference between the actual toolface orientation and a desired toolface orientation, and then adjusting a position of the quill by an amount that is dependent upon the monitored drilling operation parameter. Methods and apparatus for using a quill to steer a hydraulic motor when elongating a wellbore in a direction having a horizontal component, where the quill and the hydraulic motor are coupled to opposing ends of a drill string, by monitoring an actual toolface orientation of a tool driven by the hydraulic motor via monitoring a drilling operation parameter indicative of a difference between the actual toolface orientation and a desired toolface orientation, and then adjusting a position of the quill by an amount that is dependent upon the monitored drilling operation parameter. Methods and systems for drilling to a target location inelude a control system that receives an input comprising a planned drilling path to a target location and determines a projected location of a bottom hole assembly of a drilling system. The projected location of the bottom hole assembly is compared to the planned drilling path to determine a deviation amount. A modified drilling path is created to the target location as selected based on the amount of deviation from the planned drilling path, and drilling rig control signáis that steer the bottom hole assembly or f the drilling system to the target location along the modified drilling path are generated.

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PATENT TITLE NO. 337489 _SE_

SeCROWHA D (M »t! MÍA

Institute

Mexican Property

Industrial

I

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Owner (s): NABORS GLOBAL HOLDINGS, LTD.

Address: Canon's Court, Hamilton, BERMUDAS,

Name: DIRECTIONAL DRILLING CONTROL

Classification:

Inventor (s):

lnt.CI.8: E21B44 / 02

SCOTT BOONE; BRIAN ELLIS; BEAT KUTTEL; JOHN THOMAS SCARBOROUGH; CHRIS PAPOURAS

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Inff presentation PRIORITY September 2008

Date:

September 2 November 2 December 'December 1 February 2001

Igency: Twenty years

L &lt;reference asteote

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s I and III d

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Number:

11/859,378 ‘

60/985,869

11/952,511

61/016,093

61 / 026,321 «ha do Vencí lienta

D in accordance with artfc to 23 of Ii c &lt;tada from the date of presi d &lt;schos.

Q in subscribes to this P Industrial piety (Daily

2I 91/2004, 06/16/2005, 1/25/2006, orga with

6'fraoció ”III and 80 detiLe / lfe ^ k Property

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based on the Federation (DOF) 27/06 / idustrial.

unprofessional years - extendable,

III and 7 ° bis 2 of l &amp; ey de la _ 25/10/1896, 26/12/1997, / 05/1999,

5 / 2009.06 / 01/2010, 06/18/2010, 06/28/2010, 01/27/2012 and 04/09/2012); articles 1, 3 ration V w ---- signed on

07/01/2002, 07/15/2004, 07/28/2004 and 09/07/2007); articles 1®, 3®, 4 °, 5 ° fraction V Clause a), 16 fractions I and III and 30 of the Organic Statute of the Mexican Institute of Industrial Property (DOF 12/27/1999, amended on 10/10/2002, 07/29/2004, 08/04/2004 and 09/13/2007); 1®, 3 ° and 5 ° Subsection a) of the Agreement that delegates powers to the Deputy Directors General, Coordinator, Divisional Directors, Holders of the Regional Offices, Divisional Deputy Directors, Departmental Coordinators and other subordinates of the Mexican Institute of Industrial Property. (DOF 12/15/1999, amended on 02/04/2000, 07/29/2004, 08/04/2004 and 09/13/2007).

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Arenal No. 550, Floor 1,

Col. Pueblo Santa María Tepepan, Xochimilco, ZIP 16020.

Mexico City

Tel. (55) 53 34 07 00 www.impi.gob.mx

Issue Date: March 8, 2016

DIVISIONAL DIRECTOR OF PATENTS

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NAHANNY CANAL REYES

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MX / 2016/18391

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ΓΙΤΙ / ΤΟ MEXICAN INDUSTRIAL PROPERTY

DIRECTION DRILL CONTROL

BACKGROUND OF THE INVENTION

At the beginning of a drilling operation, drillers typically establish a drilling plan that includes a target location and a drilling route to the target location. Once drilling begins, the downhole assembly is steered or "guided" from a vertical drill path in any number of directions, to follow the proposed drill plan. For example, to recover an underground hydrocarbon deposit, a drilling plan could include a vertical well up to a point above the deposit, then a directional or horizontal well that penetrates the deposit. The operator can then guide the bit through both vertical and horizontal aspects according to the plan.

In some embodiments, this directional drilling requires the precise orientation of a bent downhole motor segment driving the bit. In such embodiments, the rotation of the drill string changes the orientation of the bent segment and the tool face. To efficiently guide the assembly, the operator must first determine the current orientation of the tool face, for example by means of a Drilling Measuring Apparatus (MWD). Subsequently, if the direction of drilling requires adjustment, the

ΓΙ

MEXICAN INSTIWTO OF INDUSTRIAL PROPERTY

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operator must rotate drill string to change orientation of tool face. In other modes, such as rotary steerable systems, the operator still has to determine the current orientation of the tool face.

During drilling an “inspection is obtained that identifies location and direction data of a BHA in a well at various intervals or other times. Each inspection produces a measurement of the inclination and azimuth (or compass heading) of a location in a well (typically the total depth at the time of measurement). In directional holes, in particular, the position of the hole must be known with reasonable accuracy to ensure the correct route of the hole. Measurements themselves include vertical tilt and hole azimuth. In addition to the tool face, and tilt and azimuth data, the data obtained during each inspection may also include, for example, hole depth data, pipe rotation data, hook load data, delta data pressure (via downhole drill motor), and modeled dog paw data.

These measurements can be made at different points in the hole and the approximate trajectory of the hole can be calculated from these different points. Conventionally, a standard inspection is made at each drill pipe connection to obtain an accurate measurement of inclination and azimuth for the new inspection position. However, if directional drilling operations require one or more transitions

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Between slip and rotation within the span of a single drill pipe connection or drill pipe, the driller cannot rely on the most recent inspection to accurately determine the progress or efficiency of the operation. For example, the driller cannot use the latest inspection data to assess the efficiency or accuracy of a "slip" that begins after the inspection has been obtained. Conventional use of inspections does not provide the directional driller with any feedback on the progress or efficiency of operations performed after obtaining measurements from the most recent inspection.

When deviation from the planned drilling path occurs, drillers should consider the factors available to them in attempting to direct drilling back to the original route. This typically requires the operator to manipulate the winch brake and rotate the rotary table or top drive shaft to find the precise combinations of hook load, mud motor differential pressure, and torque of the drill string to properly position the tool face. This can be difficult, time consuming and complex. Each adjustment has different effects on the orientation of the tool face, and each must be considered in combination with other drilling requirements to drill the hole. In this way, the reorientation of the tool face in a hole is very complex, labor intensive and often inexact. A more efficient, reliable method of guiding a BHA is required.

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BRIEF DESCRIPTION OF THE INVENTION

In an exemplary aspect, the description herein encompasses a method of using a shaft to guide a hydraulic motor when enlarging a hole in a direction that has a horizontal component, where the shaft and hydraulic motor are coupled at opposite ends of a drill string, method includes: monitoring a true tool face orientation of a hydraulic motor driven tool by monitoring a drilling operation parameter indicative of a difference between the actual tool face orientation and a desired tool face orientation, and adjusting an axis position by an amount that depends on the monitored drilling operation parameter.

In one embodiment, the amount of shaft position adjustment is sufficient to compensate for the difference between the actual and desired tool face orientations. In another embodiment, adjusting the shaft position includes adjusting a rotational position of the shaft relative to the hole. In yet another embodiment, adjusting the shaft position includes adjusting a vertical shaft position relative to the hole. In even a further embodiment, adjusting the shaft position includes having a winch adjust a tool applied weight (WOB) by an amount that depends on the monitored drilling operation parameter. The

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MEXICAN INSTITUTE OF PROPERTY

INDUSTRIAL

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Axis position adjustment may include more than one, or all, of these different modalities.

In another embodiment, monitoring the drilling operation parameter indicative of the difference between the actual and desired tool face orientations includes monitoring a plurality of drilling operation parameters each indicative of the difference between the actual and desired drilling orientation. the tool face, and where the amount of the shaft position adjustment further depends on each of the plurality of drilling operation parameters. In yet another embodiment, drilling operation parameter monitoring includes monitoring data received from a tool face orientation sensor, and where the amount of the axis position adjustment depends on the data from the face orientation sensor. of tool. In a preferred embodiment, the tool face sensor includes at least one of a tool face gravity sensor and a magnetic tool face sensor.

In different modalities, the drilling operation parameter includes a weight applied to the tool (WOB), a depth of the tool inside the hole, a speed of penetration of the tool into the hole (ROP), a hydraulic differential pressure through of the hydraulic motor (ΔΡ), or a combination thereof. In a preferred embodiment, the drilling operation parameter is ΔΡ and is

IMPI

MEXICAN INSTITUTE ȣ THE INDUSTRIAL PROPERTY

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a corrected ΔΡ based on a monitored fluid pressure that exists in a defined ring between the hole and the drill string.

In one embodiment, monitoring of the drilling operation parameter indicative of the difference between the actual and desired tool face orientations includes: monitor data received from a tool face orientation sensor, monitor a tool applied weight (WOB), monitor a tool depth within the hole, monitor a tool penetration speed into the hole (ROP) , and monitor a hydraulic differential pressure through the hydraulic motor (ΔΡ). In a preferred embodiment, adjusting the axis position includes adjusting the axis position an amount that depends on at least two, preferably three, or even all of the following: the monitored data from the tool face orientation sensor, the monitored WOB, the monitored tool depth within the hole, the monitored ROP, and the monitored ΔΡ. In another preferred embodiment, monitoring of the drilling operation parameter and adjustment of the shaft position are performed simultaneously with the operation of the hydraulic motor.

In another embodiment, adjusting the axis position includes adjusting a neutral rotational position of the axis, and wherein the method further includes oscillating the axis by rotating the axis through a predetermined angle beyond the neutral position in the direction. clockwise and counterclockwise.

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INSTITU TO MEXICANO DE EA PROPIEDAD

INDUSTRIAL

The invention also encompasses a system for using a nail to guide a hydraulic motor when it enlarges a hole in a direction that has a horizontal component, where the shaft and hydraulic motor are coupled to opposite ends of a drill string, the system includes :

a monitoring device adapted to monitor a true tool face orientation of a hydraulic motor driven tool, including a monitoring device adapted to monitor a drilling operation parameter indicative of a difference between the actual face orientation of tool and a desired orientation of the tool face, and an adjusting device adapted to adjust an axis position an amount depending on the monitored drilling operation parameter.

The invention further encompasses an apparatus for using a shaft to guide a hydraulic motor when enlarging a hole in a direction having a horizontal component, where the shaft and hydraulic motor are coupled to opposite ends of a drill string, the apparatus includes : a sensor configured to detect a drilling operation parameter indicative of a difference between an actual orientation of the tool face of a tool driven by the hydraulic motor and a desired orientation of the tool face of the tool, and a tool face controller configured to adjust the actual orientation of the tool face by generating an axis drive control signal directing an axis drive mechanism to adjust a position

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MEXICAN INSTITUTE OF PROPERTY

INDUSTRIAL rotational shaft based on monitored drilling operation parameter ™.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with normal industry practice, various features are not drawn to scale. In fact, the dimensions of the various features can be arbitrarily increased or decreased to clarify the exposition.

FIG. 1 is a schematic diagram of a drilling equipment apparatus in accordance with one or more aspects of the present disclosure.

Figures 2A and 2B are flow charts of methods according to one or more aspects of the present description.

Figure 3 is a schematic diagram of an apparatus according to one or more aspects of the present description.

Figures 4A-4C are schematic diagrams of apparatus according to one or more aspects of the present description.

Figure 5A is a flow chart of a method according to one or more aspects of the present description.

Figure 5B is an illustration of a tolerance cylinder at νί Ρϊ

MEXICAN INSTITUTE OF PROFICIENCY

INDUSTRIAL

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around the drill route. . ...................

Figure 6A is a flow chart of a method according to one or more aspects of the present description.

FIG. 6B is a schematic diagram of an apparatus in accordance with one or more aspects of the present disclosure.

Figures 6C-6D are flow charts of methods according to one or more aspects of the present description.

Figures 7A-7C are flow charts of methods according to one or more aspects of the present description.

Figures 8A-8B are schematic diagrams of apparatus according to one or more aspects of the present description.

Figure 8C is a flow chart of a method according to one or more aspects of the present description.

Figures 9A-9B are flow charts of methods according to one or more aspects of the present description.

Figures 10A-10B are schematic diagrams of a display apparatus in accordance with one or more aspects of the present disclosure.

Fig. 11 is a schematic diagram of an apparatus according to one or more aspects of the present description.

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DETAILED DESCRIPTION OF THE INVENTION

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Mexican Institute of Industrial Property

It is understood that the present description provides many different modalities or examples for practicing different characteristics of various modalities. Specific examples of components and arrangements are described below to simplify the present description. Of course, these are only examples and are not considered limiting. Furthermore, the present description may repeat reference numbers and / or letters in the various examples. This repetition is for the purpose of simplicity and clarity, and by itself does not dictate a relationship between the various modalities or configurations exposed. Furthermore, the formation of a first characteristic on a second characteristic in the description that follows can include modalities in which the first and second characteristic are formed in direct contact, and can also include modalities in which additional characteristics can be formed between the first and second feature, such that the first and second feature may not be in direct contact.

The systems and methods described herein improve BHA control, resulting in increased BHA sensitivity and faster BHA operations compared to conventional systems that require significantly more manual input or pauses to provide input. Advantageously, the invention can achieve this using data feedback and location detection,

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processing of received data, and optimization of a drill rat · based on the actual projected location of the bit. Before drilling, a target location is typically identified and an optimal hole profile or planned route established. Such proposed drilling routes are generally based on the most efficient or effective route to the target location (s). As drilling proceeds, the BHA may begin to deviate from the previously planned optimal drilling path due to one or more of a variety of factors. The systems and methods described herein are adapted to detect deviation from the planned route and to generate corrections to return the BHA to the drilling route or, if more effective, generate an alternative drilling route to the target location, preferably in the most efficient way possible, but preferably avoiding overcorrection.

Referring to Figure 1, a schematic view of apparatus 100 is illustrated showing one or more aspects of the present disclosure. Apparatus 100 is, or includes, land based drilling equipment. However, one or more aspects of the present description are applicable or easily adaptable to any type of drilling equipment, such as lifting jack equipment, semi-submersible, drilling rigs, reel pipe equipment, well service equipment adapted for drilling and / or reentry operations, and casing pipe drilling equipment, among others, within the scope of this description.

IMPI

MEXICAN INSTITUTE Say THE INDUSTRIAL PROPERTY

The apparatus 100 includes a mast 105 that rises above an equipment floor, 110. The lifting system includes a crown block, 115, and a traveling block, 120. The crown block 115 engages in, at or near the top of the 105th mast, and the traveling block

120 hangs from crown block 115 by means of a drill wire,

125. One end of drill cable 125 extends from the hoist to winch 130, which is configured to wind and unwind drill cable 125 to raise and lower traveler block 120 relative to equipment floor 110. The other end drill cable

125, known as a deadline anchor, is anchored in a fixed position, possibly near winch 130 or anywhere on the equipment.

A hook 135 is coupled to the bottom of the traveling block 120. An upper drive mechanism, 140, is suspended from the hook 135. An axis 145 extending from the upper drive mechanism 140 is attached to a sub saver 150, which it is engaged in a drill string 155 suspended within a bore 160. Alternatively, shaft 145 may be coupled directly to drill string 155.

The term "shaft, as used herein, is not limited to a component that extends directly from the top drive, or is otherwise conventionally referred to as a shaft. For example, within the scope of the present description, additionally or alternatively, the "shaft may include a main shaft, a drive shaft, an output shaft, and / or other

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MEXICAN INSTITUTE OF PROPERTY

INDUSTRIAL

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component that transfers torque, position and / or rotation dasde-ek .. upper drive mechanism or other Rotary drive element to the drill string, at least indirectly. However, although solely for the purposes of clarity and consistency, these components may be collectively referred to herein as "hub."

Drill string 155 includes interconnected drill pipe sections 165, a downhole assembly (BHA) 170, and a drill bit 175. Downhole assembly 170 may include stabilizers, drill bits and / or drilling instruments. measurement during drilling (MWD) or transported by cable, among other components. Drill bit 175, which may also be referred to herein as a tool, is connected to the Bottom of BHA 170 or is otherwise coupled to drill string 155. One or more pumps 180 can supply drilling fluid to the drill string

155 through a hose or other conduit 185, which may be connected to the upper control mechanism 140.

Downhole downhole or wireline instruments can be configured to assess physical properties such as pressure, temperature, torque, weight over auger (WOB), vibration, tilt, azimuth, tool face orientation in three-dimensional space, and / or other downhole parameters. These measurements can be made at the bottom of the well, stored in solid state memory for some time, and downloaded from the Instruments at

IMPI

INSTITUTO A4EXICANO DÍ THE PROPERTY INDUSTIGAL

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the surface and / or transmitted to the surface at r ^ ai i ng Hp data transmission may include, for example, digitally encoding data and transmitting the encoded data to the surface, possibly as pressure pulses in the drilling fluid or system sludge, acoustic transmission through drill string 155, electronic transmission through a wired cable or tube, and / or transmissions such as electromagnetic pulses. MWD tools and / or other portions of the BHA 170 may have the ability to store measurements for later retrieval via cable and / or when the BHA 170 is removed from hole 160.

In an exemplary embodiment, apparatus 100 may also include a rotary blowout preventer (BOP), 158, for example if well 160 is drilled using insufficiently balanced or managed pressure drilling methods. In such an embodiment, the annular sludge and cuts can be pressurized at the surface, with the actual desired flow and pressure possibly being controlled by a throttle system, and the fluid and pressure being retained at the wellhead and directed down the line flow to the choke via rotary BOP 158. Apparatus 100 may also include an annular surface pressure sensor, 159, of the casing, configured to detect the pressure in the ring defined between, for example, bore 160 (or casing therein) and the drill string 155.

In the exemplary embodiment depicted in FIG. 1, the upper drive mechanism 140 is used to impart movement

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MEXICAN INSTITUTE OF PROPERTY

INDUSTRIAL

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rotary to the drill string 155. However, the blades of the present description are also applicable or easily adaptable to embodiments using other control systems, such as a swivel, a rotary table, a coiled pipe unit, a downhole motor, and / or conventional rotary equipment, among others.

Apparatus 100 also includes a controller 190 configured to control or assist in controlling one or more components of apparatus 100. For example, controller 190 may be configured to transmit operation control signals to winch 130, upper drive 140, BHA 170 and / or pump 180. Controller 190 may be a self-supporting component installed near mast 105 and / or other components of apparatus 100. In an exemplary embodiment, controller 190 includes one or more systems located in a control room near apparatus 100, such as the general-purpose guard frequently referred to as the "doghouse serving as a combination tool guard, office , communications center and general meeting place. Controller 190 may be configured to transmit operational control signals to winch 130, upper control mechanism 140, BHA 170, and / or pump 180, via wired or wireless transmission means which, for clarity purposes , are not represented in figure 1.

Controller 190 is also configured to receive electronic signals by wired or wireless transmission means (also not shown in Figure 1) from a variety of sensors included in the

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MEXICAN INSTITUTE OF PROPERTY

INDUSTRIAL

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apparatus 100, wherein each sensor is configured to detect an operational characteristic or parameter. One such sensor is the liner pipe surface annular pressure sensor 159, described above. Apparatus 100 may include a downhole annular pressure sensor 170a, coupled or otherwise associated with BHA 170. The downhole annular pressure sensor 170a can be configured to detect a pressure or scale of the ring-shaped region defined between the external surface of the BHA 170 and the internal diameter of the bore 160, which can also be referred to as liner pipe pressure, downhole casing pressure, MWD liner pressure, or downhole annular pressure. These measurements can include both static annular pressure (pumps off) and active annular pressure (pumps on).

It is to be noted that the meaning of the word "detection", in the context of the present description, may include detection, perception, measurement, calculation and / or obtaining of data in another way. Similarly, the meaning of the word "detect", in the context of the present description, can include detect, perceive, measure, calculate and / or obtain data in another way.

Additionally or alternatively, apparatus 100 may include a shock / vibration sensor, 170b, which is configured to detect shock and / or vibration in BHA 170. Additionally or alternatively, the apparatus

100 may include a delta pressure sensor (ΔΡ), 172a, from the mud motor, '«« Bx'juac ^ NC'aiBn'avsv ^

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• «MEXICAN TITUTO Dfc LA« HOmCAD

INDUSTRIAL

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which is configured to detect a differential pressure value or scale across one or more BHA 170 motors 172. Each motor 172 may be or include a positive displacement drill motor that uses hydraulic energy from the drilling fluid to drive the bit. 175, also known as the mud engine. One or more torque sensors, 172b, may also be included in the BHA 170 to send data to controller 190 that is indicative of torque applied to bit 175 by one or more motors 172.

Additionally or alternatively, apparatus 100 may include a tool face sensor, 170c, configured to detect the current orientation of the tool face. Tool face sensor 170c may be or include a conventional or future developed tool face magnetic sensor that detects the orientation of the tool face with respect to magnetic north or

True north. Alternatively or additionally, the tool face sensor 170c may be or include a conventional or future developed tool face gravity sensor that detects the orientation of the tool face with respect to the Earth's gravitational field. Tool face sensor 170c may also alternatively be a conventional or future developed gyro sensor. Additionally or alternatively, apparatus 100 may include a WOB sensor, 170d, integral with BHA 170 and configured to detect the WOB at or near BHA 170.

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Additionally or alternatively, the apparatus · &lt;nn pnn.ia include a torque sensor, 140a, coupled or otherwise associated with the upper drive 140. The torque sensor 140a may alternatively be located or associated with the BHA 170. Torque sensor 140a can be configured to detect a torque value or scale for shaft 145 and / or drill string 155 (eg, in response to operational forces acting on the drill string). Additionally or alternatively, the upper drive mechanism 140 may include or be otherwise associated with a speed sensor, 140b, configured to detect a value or scale of rotational speed of axis 145.

Additionally or alternatively, the upper drive mechanism 140, winch 130, crown block or traveling block, drill wire or deadline anchor, may include or be otherwise associated with a WOB sensor, 140c (WOB calculated from a hook load sensor that may be based on active and static hook load) (for example, one or more sensors installed somewhere in the load path mechanisms to detect and calculate the WOB, which may vary from one equipment to another), different from the WOB 170d sensor. The WOB sensor 140c can be configured to detect a WOB value or scale, where said detection can be performed on the upper control mechanism 140, winch 130, or another component of the apparatus 100.

Detection by the sensors described here can be

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INSTITUTO M £ XIC? NÜ Dt LA PKOPJÜDAP

INDUSTRIAL

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performed once, continuously, periodically, and / or at random intervals. Detection can be manually activated by an operator or other person who has access to a human-machine interface (HMI), or be activated automatically, for example, by means of an activation feature or parameter that satisfies a predetermined condition (for example, the expiration of a period, the advance of drilling that reaches a predetermined depth, the use of the drilling bit that reaches a predetermined amount, etc.). Such sensors and / or other detection means may include one or more interfaces that may be local to the well / equipment site, or may be located at another remote site with a network link to the system.

Referring to Figure 2A, the flow chart of a method 200a of manipulating the orientation of a tool face to a desired orientation is illustrated in accordance with one or more aspects of the present disclosure. Method 200a can be performed in association with one or more components of apparatus 100 shown in Figure 1 during operation of apparatus 100. For example, method 200a may be performed for orientation of the tool face during drilling operations performed by apparatus 100.

Method 200a includes a step 210 during which the current orientation of the tool face, TF, is measured_M. The TF_M can be measured using a conventional or future developed tool face magnetic sensor, which detects the orientation of the tool face

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·»'

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INJ7! Ϊ́ UTO Μ ί Λ7ΓΛ ΝΟ i'i-L, ·: ΝϊΟΡϋΛ '-. Ρ CWWjiíM with respect to the magnetic North or the vercJáCÍSTg North. AlléiiraLiv¿r'O · additionally, the TF_M It can be measured using a conventional or future developed tool face gravity sensor, which detects the orientation of the tool face with respect to Earth's gravitational field. In an exemplary modality, the TF_M It can be measured using a magnetic tool face sensor when the end of the hole is less than about 7 ° from vertical, and can subsequently be measured using a tool face gravity sensor when the end of the hole is greater than about 7 ° from the vertical. However, gyroscopes and / or other means of determining TF are also within the scope of the present description._M.

In a subsequent step 220, the TFm is compared to a desired orientation TFd of the tool face. If the TF_M is sufficiently equal to TF_D determined during decision step 230, method 200a is iterated and step 210 is repeated. "Sufficiently equal" can mean substantially the same, for example varying no more than a few percentage points, or alternatively can mean varying no more than a predetermined angle, for example approximately 5 °. Furthermore, the iteration of method 200a may be substantially immediate, or there may be a delay period before method 200a is iterated and step 210 is repeated.

If the TF_m not equal enough to TF_D, determined during decision step 230, method 200a continues to step 240 during

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which the axis is rotated by the control system, by éleniute-wtguxantidad approximately equal to the difference between the TF_M and the TF₀. However, other amounts of rotational adjustment performed during step 240 are also within the scope of the present description. After step 240 is performed, method 200a is iterated and step 210 is repeated. Said iteration may be substantially Immediate, or there may be a delay period before method 200a is Iterated and step 210 is repeated.

Referring to Figure 2B, a flow chart of another embodiment of method 200a shown in Figure 2A is illustrated, designated herein with reference number 200b. Method 200b includes an information gathering step when the orientation of the tool face is in the desired orientation, and can be performed in association with one or more components of the apparatus 100 shown in Figure 1 during the operation of the apparatus 100. For example, method 200b can be performed to orient the tool face during drilling operations performed by apparatus 100.

Method 200b includes steps 210, 220, 230, and 240, previously described with respect to method 200a and shown in Figure 2A. However, method 200b also includes a step 233 during which current operating parameters are measured if the TFm is sufficiently equal to the TF_D, determined during decision step 230. Alternatively or additionally, current operating parameters may be measured at periodic intervals or at scheduled times, or after the occurrence of

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MEXICAN INSTITUTE OF PROPERTY

INDUSTRIAL

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Other events. Method 200b also includes a pae &lt;-&gt; during which the operating parameters measured in step 233 are recorded. The operating parameters recorded during step 236 can be used in future calculations of the amount of shaft rotation performed during the He passed

240, as may be determined by one or more intelligent adaptive controllers, programmable logic controllers, artificial neural networks, and / or other adaptive and / or "learning" controllers or processing apparatus.

Each of the steps of methods 200a and 200b can be performed automatically. For example, controller 190 of Figure 1 can be configured to automatically perform the tool face comparison of step 230, either periodically, at random intervals, or otherwise. Controller 190 can also be configured to automatically generate and transmit control signals that direct the axis rotation of step 240, for example in response to the tool face comparison made during steps 220 and 230.

Referring to Figure 3, a block diagram of an apparatus 300 is illustrated in accordance with one or more aspects of the present disclosure. Apparatus 300 includes a user interface 305, a BHA 310, a command system 315, a winch 320, and a controller 325. Apparatus 300 can be implemented within the medium and / or apparatus shown in Figure 1. For example, BHA 310 may be substantially similar to BHA 170 shown in Figure 1, command system 315 may be "My η—,

F í Y

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INDUSTRIAL substantially similar to the upper control mechanism Τ4Ό iriootiade-eoJa. 1, winch 320 may be substantially similar to winch 130 shown in FIG. 1, and / or controller 325 may be substantially similar to controller 190 shown in FIG. 1. Apparatus 300 can also be used to perform method 200a shown in Figure 2A, and / or method 200b shown in Figure 2B, among other methods described herein or otherwise within the scope of the present description.

User interface 305 and controller 325 may be distinct components that are interconnected by wire or by wireless means. Alternatively, user interface 305 and controller 325 may be integral components of a single system or controller 327, as indicated by the dashed lines in Figure 3.

User interface 305 includes means 330 for user input of one or more tool face set points, and may also include means for user input of other set points, limits, and other input data. The data input means 330 can include a keyboard, voice recognition apparatus, dial, button, switch, slide selector, toggle lever, joystick, mouse, database, and / or other input device. conventional or future developed data. Such data entry means can support data entry from local and / or remote sites.

Alternatively or additionally, data input means 330 may include means for user selection of values ​​or scales

IMPI

MEXICAN INSTITUTE D £ THE INDUSTRIAL PROPERTY default tool face set point, eg using one or more pull-down menus. Also, or alternatively, the tool face set point data may be selected by controller 325 by executing one or more database search procedures. In general, the data entry means 330 and / or other components within the scope of the present description support the operation and / or monitoring of stations at the equipment site, and also of one or more remote locations with a communication link. to the system, network, local area network (LAN), wide area network (WAN), Internet, satellite link, and / or radio, among other means.

User interface 305 may also include a display

335 to visually present the information to the user in textual, graphic or video form. The display 335 can also be used by the user to input tool face set point data in conjunction with the data entry means 330. For example, the face set point data entry means 330 The tools can be integral with the display 335, or they can be in communication with it in another way.

The BHA 310 may include a 340 MWD casing pressure pressure sensor, which is configured to detect an annular pressure value or scale at or near the MWD portion of the BHA 310, and which may be substantially similar to the sensor pressure 170a shown in Figure 1. The casing pressure data detected by the

<img file="MX337489B_D0046.tif" />

IMPI

MEXICAN INSTITUTE OF INDUSTRIAL PROPERTY coating pipeline pressure sensor MWD 34Ό7T&gt; uéaén ”S5rei iviadus · by means of electronic signal to controller 325 by means of wired or wireless transmission.

The BHA 310 can also include a shock / vibration sensor

MWD, 345, which is configured to detect shock and / or vibration in the MWD portion of the BHA 310, and which can be substantially similar to the shock / vibration sensor 170b shown in Figure 1. The shock / vibration data detected by By means of the MWD 345 shock / vibration sensor, they can be sent by electronic signal to the 325 controller by means of wired or wireless transmission.

The BHA 310 may also include a mud motor ΔΡ, 350 sensor, which is configured to detect a differential pressure value or scale across the BHA 310 mud motor, and which can be substantially similar to the ΔΡ sensor. Mud motor 172a shown in Figure 1. Differential pressure data detected by the mud motor ΔΡ sensor 350 can be sent by electronic signal to the controller 325 through wired or wireless transmission. Alternatively or additionally, the ΔΡ of the mud motor can be calculated, detected, or otherwise determined at the surface, for example by calculating the difference between the pressure of the surface riser just off the bottom and the pressure once the auger It hits the bottom and starts drilling and experiencing torque.

The BHA 310 can also include a magnetic face sensor

I

<img file="MX337489B_D0047.tif" />

tool, 355, and a nérramiérttá face gravity sensor, 3bü; - which are cooperatively configured to detect the current tool face, and which collectively can be substantially similar to the tool face sensor 170c shown in Figure 1. The tool face magnetic sensor 355 may be, or include, a conventional or future developed tool face magnetic sensor that detects the orientation of the tool face relative to magnetic North or true North. The tool face gravity sensor 360 can also be, or include, a conventional or future developed tool face gravity sensor that detects the orientation of the tool face with respect to Earth's gravitational field. In an exemplary embodiment, the magnetic tool face sensor 355 can detect the current tool face when the end of the hole is less than about 7 ° from the vertical, and the tool face gravity sensor 360 can detect the tool face. current tool when the end of the hole is greater than approximately 7 ° from the vertical. However, other tool face sensors may also be used within the scope of the present disclosure, including non-magnetic tool face sensors and non-gravitational tilt sensors. In any case, the orientation of the tool face detected by means of one or more tool face sensors (for example, sensors 355 and / or 360), can be sent by means of an electronic signal to the controller 325 through

<img file="MX337489B_D0048.tif" />

I jLVA X

MEXICAN INSTITUTE OF INDUSTRIAL PROPERTY wired or wireless transmission. -—

The BHA 310 may also include a MWD 365 torque sensor, which is configured to detect a torque value or range of values ​​applied to the bit by the BHA motors

310, and which can be substantially similar to the torque sensor

172b shown in Figure 1. The torque data detected by means of the torque sensor MWD 365 can be sent by means of electronic signal to the controller 325 by means of wired or wireless transmission.

The BHA 310 may also include a WOB MWD sensor, 370, which is configured to detect a value or scale of values ​​for WOB at or near the BHA 310, and which may be substantially similar to the WOB 170b sensor shown in Figure 1 The WOB data detected by the WOB MWD 370 sensor can be sent by electronic signal to controller 325 by wired or wireless transmission.

Winch 320 includes a controller 390 or other means to control the forward and / or reverse of a drill cable (such as drill cable 125 shown in Figure 1). This control may include rotational control of the winch (forward vs. reverse) to control the height or position of the hook, and may also include control of the speed at which the hook is raised or lowered. However, exemplary modalities within the scope of this description include those in which the system

<img file="MX337489B_D0049.tif" />

of the winch drill string can be either a hydraulic ram or a rack and pinion type lifting system equipment, where the movement of the drill string up and down is by means of something other than a winch. The drill string can also take the form of coiled tubing, in which case the movement of the drill string in and out of the hole is controlled by an injector head that holds and pushes / pulls the pipe in / out of the hole . However, such modes may still include a version of controller 390, and controller 390 may still be configured to control the forward and / or reverse of the drill string.

Drive system 315 includes a surface torque sensor, 375, which is configured to detect a reactive torque value or scale of the drill string or shaft, much like the torque sensor 140a shown in Figure 1. The control system 315 also includes an axis position sensor, 380, which is configured to detect a value or scale of the rotational position of the axis, for example with respect to true North or other stationary reference. Shaft position and surface torque data detected by sensors 375 and 380, respectively, can be sent via electronic signal to controller 325 via wired or wireless transmission. Drive system 315 also includes a controller 385 and / or other means to control rotational position, speed and direction of the shaft or other component of the drill string.

<img file="MX337489B_D0050.tif" />

MEXICAN INSTITUTE DB LA PROPIEDAD

INDUSTRIAL

<img file="MX337489B_D0051.tif" />

coupled with control system 315 (such as axis 145 shown in figure 1).

In an exemplary embodiment, command system 315, controller 385, or another component of apparatus 300, may include means for estimating friction between the drill string and hole. For example, such friction estimating means can be configured to detect the occurrence and / or severity of friction, which can then be subtracted from the "actual reactive torque, perhaps by means of controller 385 and / or other control component. of apparatus 300.

Controller 325 is configured to receive one or more of the above-described parameters from user interface 305, BHA 310, and / or command system 315, and use those parameters to determine continuously, periodically, or otherwise way, the current orientation of the tool face. Controller 325 can be further configured to generate a control signal, for example by means of intelligent adaptive control, and supply the control signal to command system 315 and / or winch 320 to adjust and / or maintain the orientation of the tool face. For example, controller 325 may execute method 202 shown in Figure 2B to provide one or more signals to command system 315 and / or winch 320, to increase or decrease the WOB and / or the axis position, such as may be required to accurately “guide” the drilling operation.

Furthermore, as in the exemplary modality represented in the

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FIG. 3, controller 385 of command system 315, and / or the winch 320 controller, can be configured to generate and transmit a signal to controller 325. Accordingly, controller 385 of command system 315 can be configured to alter the control of the BHA 310 and / or winch 320 to help obtain and / or maintain the desired orientation of the tool face. Similarly, winch controller 390 390 can be configured to alter the control of BHA 310 and / or drive system 315 to help obtain and / or maintain the desired orientation of the tool face. Alternatively or additionally, controller 385 of command system 315 and controller 390 of winch 320 can be configured to communicate directly, as indicated by the two-way arrow, 392, depicted in FIG. 3. Consequently, controller 385 of command system 315 and controller 390 of winch 320 can be configured to cooperate in obtaining and / or maintaining the desired orientation of the tool face. Such cooperation may be independent of the control provided to or from controller 325 and / or BHA 310.

Referring to Figure 4A, a schematic view of at least a portion of an apparatus 400a is illustrated in accordance with one or more aspects of the present disclosure. Apparatus 400a is an exemplary embodiment of apparatus 100 shown in Figure 1 and / or apparatus 300 shown in Figure 3, and is an exemplary means in which method 200a shown in Figure 2A can be performed, and / or the 200b method shown in

<img file="MX337489B_D0054.tif" />

<img file="MX337489B_D0055.tif" />

figure 2B. Apparatus 400a includes a plurality of user inputs 410 and at least one main address module, 420, which may include one or more processors. User inputs 410 include a positive axle torque limit, 410a, a negative axle torque limit, 410b, a positive axle speed limit, 410c, a negative axle speed limit, 410d, a positive axis oscillation limit, 410e, a negative axis oscillation limit, 410f, an axis oscillation neutral point input, 410g, and a tool face orientation input, 410h. Some modalities include data entry from previous inspections,

410p, a planned drill route, 410q, or preferably both.

These inputs can be used to bypass the 41 Oh tool face orientation input with the intention of keeping the BHA on the planned drill path. However, in other modes, the orientation of the tool face is entered directly. Other modalities within the scope of this description may use alternative or additional user inputs, 410. User inputs 410 may be substantially similar to user input 330 or other components of user interface 305 shown in FIG. 3. Address module 420 (at least one) can form at least a portion of, or it may be formed by at least a portion of, controller 325 shown in figure 3, and / or controller 385 of control system 315 shown in figure 3. In the exemplary embodiment depicted in FIG. 4A, at least one steering module 420 includes a tool face controller, 420a, and a

<img file="MX337489B_D0056.tif" />

winch driver, 420b. In some embodiments it also includes a mud pump controller.

Apparatus 400a also includes or is otherwise associated with a plurality of sensors 430. The plurality of sensors 430 includes an auger torque sensor, 430a, a shaft torque sensor, 430b, a shaft speed, 430c, an axis position sensor, 430d, a mud motor ΔΡ sensor, 430e, and a tool face orientation sensor, 430f. However, other embodiments within the scope of the present disclosure may utilize additional or alternative sensors 430. In an exemplary embodiment, each sensor in the plurality of sensors 430 may be located on the surface of the hole, and not located at the bottom of the wellbore. next to the bit, downhole assembly, and / or any measuring tool during drilling. However, in other embodiments, one or more of the sensors 430 may not be surface sensors. For example, in an exemplary embodiment, the axis torque sensor 430b, the axis speed sensor 430c, and the axis position sensor 430b may be surface sensors, while the torque sensor of Auger 430a, Mud Motor Δe Sensor 430e, and Tool Face Orientation Sensor 430f may be downhole sensors (eg MWD sensors). Furthermore, individual sensors of sensors 430 may be substantially similar to the corresponding sensors shown in Figure 1 or Figure 3.

<img file="MX337489B_D0057.tif" />

Apparatus 400a also includes or is associated with an axis drive mechanism, 440. Axle drive mechanism 440 may form at least a portion of the upper drive mechanism or other rotary drive system, such as the drive mechanism. upper 140 shown in figure 1, and / or the control system 315 shown in figure 3. Axis drive mechanism 440 is configured to receive an axis drive control signal from at least one steering module 420, if not also from other components of apparatus 400a. The axis command control signal directs the position (eg, azimuth), direction of rotation, speed of rotation, and / or oscillation of the axis. Tool face controller 420a is configured to generate the axis drive control signal using data received from user inputs 410 and sensors

430.

Tool face controller 420a can compare the actual torque of the axis with the positive limit of torque of the axis received from the corresponding user input 410a. The actual shaft torque can be determined using the data received from the shaft torque sensor 430b. For example, if the actual torque of the axle exceeds the positive limit of the torque of the axle, then the axle drive control signal may command the axle drive mechanism 440 to reduce the torque applied to the axle. In an exemplary embodiment, the 420a tool face controller can be configured to optimize drilling operation parameters

<img file="MX337489B_D0058.tif" />

IMPI

MEXICAN INSTITUTE

SAY THE PROPERTY

INDUSTRIAL related to the actual torque of the axis, for example-maxinuzando. the actual torque of the axle without exceeding the positive torque limit of the axle.

Alternatively or additionally, the tool face controller 420a may compare the actual torque of the shaft with the negative limit of the torque of the shaft received from the corresponding user input 410b. For example, if the actual torque of the axle is less than the negative limit of the torque of axle, then the axle drive control signal may command axle drive 440 to increase the torque applied to the axle. . In the exemplary embodiment, the tool face controller 420a can be configured to optimize the drilling operation parameters related to the actual torque of the shaft, for example by minimizing the actual torque of the shaft while still exceeding the negative limit of axis torque.

Alternatively or additionally, the tool face controller 420a can compare the actual axis speed with the positive axis speed limit received from the corresponding user input 410c. The actual axis speed can be determined using the data received from the axis speed sensor 430c. For example, if the actual axis speed exceeds the positive axis speed limit, then the axis drive control signal may command the axis drive mechanism 440 to reduce the speed at which it is being

<img file="MX337489B_D0059.tif" />

institute me:

INDUSTRIAL PROPERTY driven axis. In an exemplary embodiment, the Rnntrnlarinr Ria Ria Tool 420a can be configured to optimize drilling operation parameters with respect to actual shaft speed, for example by maximizing actual shaft speed without exceeding the positive shaft speed limit.

Alternatively or additionally, the tool face controller 420a may compare the actual axis speed with the negative axis speed limit received from the corresponding user input 41 Od. For example, if the actual axis speed is less than the negative axis speed limit, then the axis command control signal may command the axis command mechanism 440 to increase the speed at which the axis is being driven . In an exemplary embodiment, the tool face controller 420a can be configured to optimize drilling operation parameters with respect to actual shaft speed, for example by minimizing actual shaft speed while still exceeding the negative speed limit of the axis.

Alternatively or additionally, the tool face controller 420a may compare the actual orientation (azimuth) of the axis with the positive axis oscillation limit received from the corresponding user input 41 Oe. The actual axis orientation can be determined using the data received from the axis position sensor 430d. For example, if the actual axis orientation exceeds the positive axis swing limit, then the axis drive control signal may command the

<img file="MX337489B_D0060.tif" />

axis drive mechanism 440 rotate the axis within the positive axis oscillation limit, or modify the axis oscillation parameters such that the actual axis oscillation in a positive direction (for example, clockwise) do not exceed the positive axis swing limit. In an exemplary embodiment, tool face controller 420a can be configured to optimize drilling operation parameters related to actual axis oscillation, for example by maximizing the amount of actual axis oscillation in the positive direction without exceeding the positive limit of axis swing.

Alternatively or additionally, the tool face controller 420a may compare the actual axis orientation with the negative axis oscillation limit received from the corresponding user input 41 Of. For example, if the actual axis orientation is less than the negative axis swing limit, then the axis drive control signal may command the axis drive mechanism 440 to rotate the shaft within the negative axis swing limit, or modify the axis oscillation parameters in such a way that the actual axis oscillation in the negative direction (for example, counterclockwise) does not exceed the negative axis oscillation limit. In an exemplary embodiment, the tool face controller 420a can be configured to optimize drilling operation parameters related to actual axis oscillation, for example by maximizing the actual amount of axis oscillation in the negative direction, without exceeding the negative limit axis oscillation.

<img file="MX337489B_D0061.tif" />

<img file="MX337489B_D0062.tif" />

Alternatively or additionally, the 'Wi ιίι uladui' of —eara -do tool 420a can compare the actual axis oscillation neutral point with the desired axis oscillation neutral point input, received from the corresponding user input 41 Og. The actual neutral point of the axis oscillation can be determined using the data received from the axis position sensor 430d. For example, if the actual axis oscillation neutral point varies from the desired axis oscillation neutral point by a predetermined amount, or falls outside a desired range of the oscillation neutral point, then the axis command control signal may command To the axis drive mechanism 440 modify the axis oscillation parameters to make the appropriate correction.

Alternatively or additionally, the tool face controller 420a can compare the actual orientation of the tool face with the tool face orientation input received from the corresponding user input 41 Oh. The tool face orientation input received from user input 41 Oh may be a single value indicative of the desired tool face orientation. This can be entered directly or derived from the inspection data files, 41 Op, and the planned drilling route, 410q, using for example the process described in Figures 4C, 5A and 5B. IF the actual orientation of the tool face differs by a predetermined amount from the entered value of the orientation of the tool face, then the axis drive control signal can command the axis drive mechanism 440

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Rotate the shaft an amount corresponding to the correctness and orientation of the tool face. However, the input of the tool face orientation received from the user input 41 Oh may alternatively be a scale within which it is desired for the orientation of the tool face to remain. For example, if the actual orientation of the tool face is outside the input orientation range of the tool face, then the axis drive control signal may command the axis drive 440 to rotate the shaft an amount required to restore the actual orientation of the tool face within the tool face orientation input scale. In an exemplary embodiment, the actual tool face orientation is compared to a tool face orientation input that is directly entered or derived from the 41 Op inspection data files and the planned drill path 410q, using a 15 automatic process. In some modalities, this is based on a predetermined and / or constantly updated well plan (for example, a “well program”), possibly taking into account the error in the drilling advance route.

In each of the aforementioned comparisons and / or calculations made by the tool face controller, the actual ΔΡ of the mud motor, and / or the actual torque of the bit, can also be used to generate the signal axis control. The actual ΔΡ of the mud motor can be determined using the data received from the ΔΡ sensor

<img file="MX337489B_D0065.tif" />

M EXÍCAT &lt;O INSTITUTE OF OWN OWNERSHIP

INDUSTRIAL

<img file="MX337489B_D0066.tif" />

Mud motor 430e, and / or measuring the pressure of the auger and bottom bit at the bottom and setting this value, and the actual torque of the auger can be determined using the data received from the torque sensor auger, 430a. Alternatively, the actual torque of the auger can be calculated using the data received from the mud motor ΔΡ sensor 430e, because the actual torque of the auger and the actual ΔΡ of the mud motor are proportional.

An example where the actual mud motor ΔΡ and / or the actual torque of the bit can be used is when the actual orientation of the tool face cannot be trusted to provide accurate or fast enough data. For example, this may be the case during “blind” drilling, or other cases in which the perforator no longer receives data from the tool face orientation sensor 430f. On such occasions, the actual torque of the bit and / or the actual ΔΡ of the mud motor can be used to determine the actual orientation of the tool face. For example, if all other drilling parameters remain the same, a change in the actual torque of the bit and / or the actual ΔΡ of the mud motor may indicate a proportional rotation of the orientation of the tool face in the direction equal to or opposite to drilling. For example, an increasing torque or ΔΡ may indicate that the tool face is changing in the opposite direction of drilling, while a reduction in torque or ΔΡ may indicate that the tool face is moving in the same direction. of

IMPI

MFXKMNO INSTITUTE OE INDUSTRIAL PROPERTY

<img file="MX337489B_D0067.tif" />

drilling. Thus, in this way, the data rprihirinR of the auger torque sensor 430a or the mud motor ΔΡ sensor

430e, can be used by tool face controller 420 in generating the axis command signal, such that the axis can be driven such that any change in the axis is corrected or otherwise taken into account. tool face, which is indicated by a change in the actual torque of the bit and / or the actual ΔΡ of the mud motor.

Furthermore, under some operating conditions, the data received by the tool face controller 420 from the tool face orientation sensor 430f may delay the actual orientation of the tool face. For example, the tool face orientation sensor 430f may determine the actual tool face only periodically, or a considerable period may be required for data transmission from the tool face to the surface. In fact, it is common for such a delay to be 30 seconds or more in prior art systems. Accordingly, in some embodiments within the scope of the present disclosure, it may be more accurate or advantageous in another way for the tool face controller 420a to use the actual torque and pressure data received from the auger torque sensor. 430a and the mud motor ΔΡ sensor 430e, in addition to, or alternatively to, the use of the actual tool face data received from the tool face orientation sensor 430f. However, in some embodiments of the present disclosure, they can be used

<img file="MX337489B_D0068.tif" />

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real-time inspection projections as revealed in Figures 9A and 9B, to provide data regarding the direction of the BHA and the orientation of the tool face.

As shown in FIG. 4A, user inputs 410 of apparatus 400a may also include a WOB overhead, 41 Oi, a mud motor ΔΡ overhead, 41 Oj, a ROP input, 41 Ok, an input of WOB 4101, a mud motor ΔΡ input, 410m, and a hook load limit, 410n; and the address module 420 may also include a winch controller 420b. The plurality of sensors 430 of apparatus 400a may also include a hook load sensor, 430g, a mud pump pressure sensor, 430h, an auger depth sensor, 430i, a liner pipe pressure sensor, 430j , and a ROP sensor,

430k. Each of the sensors of the plurality of sensors 430 may be ♦

located on the surface of the hole, at the bottom of the well (for example

MWD), or anywhere else.

As described above, tool face controller 420a is configured to generate an axis command control signal using data received from user inputs 410 and sensors 430, and subsequently to supply the axis command control signal to the axis drive mechanism 440, thereby controlling the orientation of the tool face by managing the orientation and speed of the axis. In this way, the axis command control signal is configured to control (at least partially) the axis orientation (for example

ΡI

MEXICAN INSTITUTE * OF THE PROPERTY azimuth) and also the speed and direction of rotation of the axis (if the liubteray

The winch controller 420b is configured to generate a winch drum (or brake) command control signal using data received from user inputs 410 and sensors 430. 5 Subsequently, the winch controller 420b provides the Winch drive control signal to the winch drive mechanism, 450, thereby controlling the feed direction and speed of the winch. Winch drive mechanism 450 may form at least a portion, or may consist of at least a portion of, winch 130 shown in Figure 1 and / or winch 320 shown in Figure 3. The scope of the The present description is also applicable or easily adaptable to other means for adjusting the vertical placement of the drill string. For example, winch controller 420b may be a hose controller, and winch drive 450 may be, or include, means for lifting the drill string other than or in addition to the winch apparatus (eg, a rack and pinion apparatus).

The apparatus 400a also includes a comparator 420c that compares the current hook load data with the WOB overhead to generate the current WOB. The current hook load data is received from the hook load sensor 430g, and the WOB overhead is received from the corresponding user input 4101.

The 420b winch controller compares the current data from

WOB with the WOB input data. The current WOB is received from

IMPI

Mexican Institute of Industrial Property

<img file="MX337489B_D0070.tif" />

comparator 420c, and the WOB input data are received from the corresponding user input 4101. The WOB input data received from the user input 4101 may be a single value indicative of the desired WOB. For example, if the actual WOB differs from the WOB input by a predetermined amount, then the winch drive control signal may command the winch drive 450 to pull the wire in or out, an amount corresponding to the necessary correction of the WOB . However, the WOB input data received from user input 4101, alternatively, may be a scale within which it is desired to maintain the WOB. For example, if the actual WOB is outside the WOB input range, then the winch command control signal may command the winch command mechanism to 450 pull in or pull out the cable, an amount necessary to restore the actual WOB to within of the WOB input scale. In an exemplary embodiment, the 420b winch controller can be configured to optimize the drilling operation parameters related to the WOB, for example by maximizing the actual WOB without exceeding the WOB input value or scale.

The apparatus 400a also includes a comparator 420d that compares the mud pump pressure data to the mud motor ΡΡ tare to generate an “uncorrected mud motor ΡΡ. The mud pump pressure data is received from the mud pump pressure sensor 430h, and the mud motor ΔΡ tare is received from the corresponding user input 41 Oj.

<img file="MX337489B_D0071.tif" />

The apparatus 400a also includes a comparator 420e that uses the uncorrected mud motor ΔΡ along with auger depth data and casing pressure data to generate a "corrected" or current mud motor ΔΡ. Auger depth data is received from auger depth sensor 430i, and casing pressure pressure data is received from casing pressure sensor 430j. The casing pipe pressure sensor 430j may be a surface casing pipe pressure sensor, such as sensor 159 shown in Figure 1, and / or a downhole casing pipe pressure sensor, such as the sensor 170a shown in Figure 1, and in any case can detect the pressure in the ring defined between the casing or hole diameter and a component of the drill string.

The 420b winch controller compares the current mud motor ΔΡ with input data from the mud motor ΔΡ. The current mud motor ΔΡ is received from the comparator 420e, and the mud motor ΔΡ input data is received from the corresponding user input 410m.

The mud motor ΔΡ input data received from user input 410m may be a single value indicative of the desired mud motor ΔΡ. For example, if the current mud motor ΔΡ differs from the mud motor ΔΡ input by a predetermined amount, then the winch drive control signal may command the winch drive 450 to pull in or pull out the wire, an amount corresponding to the

IMPI

MEXICAN INSTITUTE DS INDUSTRIAL PROPERTY

<img file="MX337489B_D0072.tif" />

necessary correction of the ΔΡ of the mud motor. However, the mud motor ΔΡ input data received from user input 41 Om, alternatively may be a scale within which it is desired to maintain the mud motor ΔΡ. For example, if the current mud motor ΔΡ is 5 out of this range, then the winch drive control signal may command the winch drive 450 to pull the cable in or out, an amount necessary to restore the ΔΡ of current mud motor within the input scale. In an exemplary embodiment, the 420b winch controller can be configured to optimize drilling operation parameters related to the mud motor ΔΡ, for example by maximizing the mud motor ΔΡ without exceeding the input value or scale.

Also, or alternatively, the winch driver 420b may compare the actual ROP data with the input ROP data. 15 The actual ROP data is received from the ROP sensor, 430k, and the ROP input data is received from the corresponding user input,

410k. The ROP input data received from user input 410k may be a single value indicative of the desired ROP. For example, if the actual ROP differs from the ROP input by a predetermined amount, then the winch drive control signal may command the winch drive 450 to pull the wire in or out, an amount corresponding to the necessary correction of the clothes. However, alternatively, the ROP input data received from the input of

<img file="MX337489B_D0073.tif" />

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MEXICAN INSTITUTE DS THE PROPERTY

ΙΜΠΙΚΤβΙΛΙ.

user 41 Ok, they can be a scale within which you want to keep the ROP. For example, if the actual ROP is outside the ROP input range, then the winch drive control signal may command the winch drive 450 to pull the cable in or out, an amount necessary to restore the actual ROP to within of the ROP input scale. In an exemplary mode, the 420b winch controller can be configured to optimize drilling operation parameters ¹ related to ROP, for example maximizing actual ROP without exceeding the ROP input value or scale.

The winch controller 420b may also use data received from the tool face controller 420a when the winch drive control signal is generated. Changes in actual WOB can cause changes in the actual torque of the auger, the actual ΔΡ of the mud motor, and the actual orientation of the tool face. For example, as weight is increasingly applied to the bit, the actual orientation of the tool face may rotate opposite to the direction of rotation of the bit (due to reactive torque), and the actual torque of the bit. Auger and mud motor pressure can increase proportionally. Consequently, the tool face controller

420a can supply data to the 420b winch controller indicating whether the winch cable should be pulled in or out, and perhaps a corresponding speed, as necessary so that the actual orientation of the tool face meets the input value or scale of orientation of

<img file="MX337489B_D0075.tif" />

MEXICAN INSTITUTE OF PROPERTY

INDUSTRIAL

<img file="MX337489B_D0076.tif" />

the tool face, provided by the corresponding user input 41 Oh. In an exemplary embodiment, the winch controller 420b may also provide data to the tool face controller 420a to rotate the shaft clockwise or counterclockwise by an amount and / or speed sufficient to compensate for the increase or decrease. WOB, bit depth, or casing pressure.

As shown in Figure 4A, user inputs 410 can also include a 41 On pull limit input. When the winch command control signal is generated, the winch controller 420b can be configured to ensure that the winch does not pull past the pull limit received from user input 41 On. The pull limit is also known as the hook load limit, and may depend on the particular configuration of the drill rig, among other parameters.

In an exemplary embodiment, the winch controller 420b may also supply data to the tool face controller 420a to cause the tool face controller 420a to rotate the shaft, for example a sufficient amount, direction and / or speed to compensate for the limit. Traction reached or exceeded. Tool face controller 420a can also supply data to winch controller 420b to cause winch controller 420b to increase or decrease the WOB, or adjust the power of the drill string, such as a quantity, address, and / or enough speed to properly adjust the orientation of the face of

<img file="MX337489B_D0077.tif" />

tool. ---——

Referring to FIG. 4B, a high level schematic view of at least a portion of another embodiment of apparatus 400a is illustrated, designated herein with reference number 400b. Like apparatus 400a, apparatus 400b is an exemplary embodiment of apparatus 100 shown in Figure 1, and / or apparatus 300 shown in Figure 3, and is an exemplary means in which method 200a shown in Figure 2A, and / or method 200b shown in Figure 2B.

Like apparatus 400a, apparatus 400b includes the plurality of user inputs 410 and address module 420, at least one. The steering module 420 includes the tool face controller 420a and the winch controller 420b, previously described, and also a mud pump controller 420c. Apparatus 400b also includes or is otherwise associated with the plurality of sensors 430, the shaft drive mechanism, 440, and the winch drive mechanism, 450, similarly to apparatus 400a. Apparatus 400b also includes or is otherwise associated with a mud pump drive mechanism, 460, which is configured to control the operation of a mud pump, such as the mud pump 180 shown in Figure 1. In the exemplary embodiment of apparatus 400b shown in FIG. 4B, each sensor in the plurality of sensors 430 may be located on the surface of the hole, at the bottom of the well (eg, MWD), or anywhere.

The 420c mud pump controller is configured to

<img file="MX337489B_D0078.tif" />

<img file="MX337489B_D0079.tif" />

MEXICAN INSTITUTE OF PROPERTY

INDUSTRIAL generate a mud pump command control signal using data received from user inputs 410 and sensors 430. Subsequently, the mud pump controller 420c supplies the mud pump command control signal to the mechanism. slurry pump control 460, thus controlling the speed, flow rate and / or pressure of the slurry pump. Mud pump controller 420c may form at least a portion of, or may be formed by at least a portion of, controller 190 shown in Figure 1, and / or controller 325 shown in Figure 3.

As described above, the mud motor ΔΡ may be proportional or may be otherwise related to the orientation of the tool face, the WOB, and / or the torque of the bit. Consequently, the 420c mud pump controller can be used to alter the actual ΔΡ of the mud motor to help the actual orientation of the tool face comply with the input value or orientation of the tool face orientation, provided by the corresponding user input. Such operation of mud pump controller 420c may be independent of operation of tool face controller 420a and winch controller 420b. Alternatively, as represented by the double direction arrows 462 shown in FIG. 4B, the operation of the mud pump controller 420c to obtain or maintain the desired orientation of the tool face may be in conjunction with or in cooperation with the face controller. Tool 420a and the 420b winch driver.

IMPI

<img file="MX337489B_D0080.tif" />

<img file="MX337489B_D0081.tif" />

The 420a, 420b, and 420c r controllers

4A and 4B, can be, or include, model-free or smart adaptive controllers, such as those commercially available from CyberSoft, General Cybernation Group, Inc. Also, the 420a, 420b, and 420c controllers can be implemented collectively or independently in any conventional or future developed computing device, for example one or more personal computers or servers, manual devices, PLC systems, and / or macrocomputers, among others.

FIG. 4C is another high-level block diagram identifying exemplary components of another alternative drilling control system, 400c, of apparatus 100 of FIG. 1. In this exemplary embodiment, the block diagram includes a main controller 402 that includes a tool face calculation machine, 404, a steering module, 420, including a tool face controller, 420a, a winch controller, 420b, and a mud pump controller, 420f. Furthermore, the control system includes a user input device, 470, which can receive inputs 410 in FIG. 4A, an output display 472, and sensors 430 in communication with the main controller 402. In the embodiment shown, the machine 404 tool face calculation and address module

420 they are applications that can share the same processor or can operate using separate processors to perform different but cooperative functions. Accordingly, main controller 402 is shown encompassing winch, tool face, and mud pump controllers,

<img file="MX337489B_D0082.tif" />

IMPI

INST.TUTO .MEXICANO

Dt OWNERSHIP □ J INDUSTRIAL and also the tool face calculation machine 404. However, in other embodiments, the tool face calculation machine 404 operates using a separate processor for its calculations and path determinations. User input device 470 and display 472 can include at least a portion of a user interface, such as user interface 305 shown in Figure 3. The user interface and controller may be different components but are interconnected by wire or wireless means. However, they can alternatively be integral components of a single system, for example.

As noted above, a drill plan includes a planned hole profile or drill path. This is the preselected path for the hole to be drilled, typically until conditions require a change in the drilling plan. Typically, it specifies key inflection points along the hole and optimal radii of curvature to be used to reach the hole position target or targets, referred to as target locations. To the extent possible, the main controller 402 controls the drill rig to guide the BHA to the target location along the planned drill path within a specified tolerance zone.

Calculation machine 404 is a controller or a part of a controller configured to calculate a control drill path for the BHA. This route adheres to the planned drill hole drilling route within an acceptable margin of error known as the tolerance zone.

MEXICAN INSTITUTE OF PROPERTY

INDUSTRIAL (also referred to herein as “uuicJiTieiilie tolerance cylinder for exemplary purposes). Based on location feedback and other feedback, and based on the original planned drilling path, the 404 tool face calculation machine will produce a recommended angular placement of the tool face between 0 and 360 degrees, and a distance to drill in feet or meters above this tool face placement, or it will produce a recommendation to continue drilling forwards in rotary drilling mode. Preferably, the angular placement is as minimally different from the perforated section as possible to minimize drastic bends that can complicate the insertion of casing. These recommendations ensure that the BHA travels in the desired direction to reach the target location in an efficient and effective manner.

The 404 tool face calculation machine makes its recommendations based on several factors. For example, the tool face calculation machine 404 considers the original control drilling path, considers directional trends, and considers the real-time projection for the bit depth. In some embodiments, this 404 engine considers additional information that helps identify the location and address of the BHA. In others, the 404 engine considers only directional trends and the original drilling path.

The original control drilling path can be entered directly by a user or can be calculated by the calculation machine

<img file="MX337489B_D0083.tif" />

404 tool face based on pararnetU3sJjatuuluddo &amp; 4&gt; ouei. user. Directional trends can be determined based on historical or existing location data from real-time or periodic inspection results to predict auger location. This may include, for example, radii of curvature, or dog paw severity, generated over user specified drilling intervals of measured depths. These radii can be used as Starting points for drilling the next control curve, and can be provided with an analysis of current drilling behavior from historical drilling parameters. Calculation of the normal plane distance to the target planned location can be done from a real-time projection to the bit position. This real-time projection for the bit depth can be calculated by the tool face calculation machine 404 or the steering module 420 based on static and / or dynamic information obtained from the sensors 430. If they are calculated by the module address 420, the values ​​can be fed to the tool face calculation machine 404 for further processing. These projection values ​​for the bit depth can be calculated using various methods including, for example, the minimum arc of curvature method, the directional trend method, and the straight line method. Once the position is calculated, it is used as the Start point for the normal plane gap calculation and any subsequent control path or correction path calculations.

<img file="MX337489B_D0084.tif" />

<img file="MX337489B_D0085.tif" />

Using these inputs, the machine HT ^ cf 'clé caráT3e * ^ ”“ tool 404 determines where the actual drilling path is with respect to the planned or control drilling path. Based on their findings, the tool face calculation machine 404 creates direction instructions to help keep the actual drill path aligned with the planned drill path, that is, within the tolerance zone. These instructions can be sent as tool face orientation instructions, which can be used at input 41 Oh of Figure 4A. In some embodiments, the direction instructions created are based on the deviation magnitude of the actual drill path from the planned drill path, as discussed below.

An exemplary method 500 performed by tool face calculation machine 404 is shown in FIG. 5A to determine the amount of deviation from the desired path and to determine a corrective path.

In FIG. 5A, method 500 may start at step 502, with tool face calculation machine 404 receiving a user-entered control or planned drill path. The planned or control drill route is the desired route that may be based on multiple factors, but it is often intended to provide a more efficient or effective route from the drill rig to the target location.

In step 504, the tool face calculation machine

404 consider current desired drilling path, directional trends

<img file="MX337489B_D0086.tif" />

IMPI ^ΙΝ* τπυΓ · Mixican · £ THE INDUSTtIAL MOHSDad and projection for the depth of the bit. C- »» »»^{t, M lll}| ·· _ Lr^riKa, directional trends are based on previous inspection readings, and the projection for the bit depth or bit position is determined by the tool face calculation machine 404, the 420 steering module, or another controller or module of the main controller 402. This information is conveyed from the calculation component to the tool face calculation machine 404, and includes a dog paw severity value that is used to calculate corrective curves when necessary, as discussed below. Here, as a first iteration, the current desired drill path may correspond to the control or planned drill path defined in the drill plan received in step 502.

In step 506, the tool face calculation machine 404 determines the actual drill path based on directional trends and projection for bit depth. As noted above, additional data can be used to determine the actual drill path and, in some modalities, directional trends can be used to estimate the actual drill path, if the actual drill path measurement is suspect or the input Sensory required for calculation is limited. In step 508, the tool face calculation machine 404 determines whether the actual path is within a tolerance zone defined by the current desired drill path. A tolerance zone or zone in front of the perforation is shown and described with reference to Figure 5B.

IMPI

MEXICAN INSTITUTE OF INDUSTRIAL PROPERTY

<img file="MX337489B_D0087.tif" />

Figure 5B shows a drilling path "be" q "a ^ jaaiular___i______ planned, 530, as a broken line. Planned drill path 530 forms the axis of a hypothetical tolerance cylinder 532, an intervention zone 534, and a correction zone 536. As long as the actual drill path is within tolerance cylinder 532, the actual drill path it is within an acceptable scale of deviation from the planned drilling route, and drilling can continue without direction adjustments. The tolerance cylinder can be specified within certain percentages of distance from the desired path or from the hole diameter, and may depend in part on considerations that are different for each proposed well. For example, the correction zone can alternatively be set as approximately 50% different, or approximately 20% different from the planned route, while the intervention zone can be established as approximately 25%, or approximately 10% different from the planned route. . Accordingly, returning to FIG. 5A, if in step 508 the tool face calculating machine 404 determines that the actual path is within the tolerance zone around the planned drilling path, then the process may simply return to step 504 to await receipt of the next directional trend and / or projection for the depth of the bit.

If in step 508 the tool face calculation machine

404 determines that the actual drilling path is outside of the

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INDUSTRIAL tolerance 532 shown in Figure 5B, then the tool face calculation machine 404 determines if the actual path is within the range of

Intervention 534, wherein the address module 420 can generate one or more control signals to intervene and keep the BHA front in the desired direction. Intervention zone 534 of FIG. 5B extends concentrically around tolerance cylinder 532. It includes an Internal limit defined by tolerance cylinder 532, and an external limit defined by correction zone 536. IF the actual drill path was in intervention zone 534, the actual drill path can be considered to be moderately deviated from planned drill path 530. In this mode, correction zone 536 is concentric around the drill zone. Intervention 534 and defines the entire region outside the intervention zone 534. IF the actual drill path was in correction zone 536, the actual drill path can be considered to be significantly deviated from the planned drill path 530.

Turning now to Figure 5A, if the actual drill path is within the intervention zone 534 at step 510, then in step 512 the tool face calculation machine 404 can calculate a 3D curved section path from the projected position of the bit toward planned drilling route 530. As mentioned above, this calculation can be based on data obtained from current or previous inspection files, and may include a projection of bit depth or bit position and a dog paw severity value. The curved section path

<img file="MX337489B_D0088.tif" />

<img file="MX337489B_D0089.tif" />

INSTITUTO MSaJCANO Dfc LA PUCHIEDAD

INDUSTRIAL calculated preferably includes the orientation of the hu x i di i lienta tasting, · required to follow the curved section, and the measured depth (“MD”) to drill in feet or meters, for example, to bring the BHA back to the tolerance zone as efficiently as possible, but minimizing any overcorrection.

This corrected address path, as one or more address signals, is then sent to the address module 420 in step 514. Accordingly, one or more of the controllers 420a, 420b, 420f in Figure 4C receive the orientation data. desired tool face and other convenient information that allows controllers to generate one or more command signals that guide the BHA. From the planned drilling route, the 420 steering module and / or other components of the on-site drilling control system, 400c, can control the winch, top drive and mud pump, to directionally guide the BHA according to the corrected path.

From here, the process returns to step 504 where the tool face calculation machine 404 considers the current planned path, directional trends, and projection for the bit depth. Here, the current planned route is now modified by the curved section route calculated in step 512. Therefore, during the next iteration, the drill route considered the “planned” drill route is now the corrective route.

If in step 510 the actual drilling path is not within the

IMPIO y.ux institute: CANO / ¾¾ OF PROPERTY C * daws INDUSTRIAL intervention zone 534, then the calculation machine de-oaro do tool 404 determines that the actual drilling route must then be in the correction zone 536, and determine in step 516 whether the planned route is a critical drill route. Typically, a critical drill path is one where there are reasons that limit the desirability of creating a new planned drill path to the target location. For example, a critical drill path may be one where a path is chosen to avoid underground rock formations, and the region outside intervention zone 534 includes rock formation. Of course, designating a planned drill route as a critical route can be done for any reason.

If in step 516 the planned drill path is not a critical path, then the tool face calculation machine 404 generates a new planned path from the current projected location of the bit to the target location. This new planned route may be independent of, or may not intersect with, the original planned route, and may be generated based for example on the most efficient or effective route to the target from the current location. For example, the new route may include the minimum amount of curvature required from the auger's current projected location to its target. The new planned route could display measured depth (“MD”), inclination, azimuth, north-south and east-west, tool face and dog paw severity (“DLS) or curvature, at regular station intervals of approximately 100 feet or 30 meters,

MEXICAN INSTITUTE OF THE PROPÍED / J}

INDUSTRIAL

<img file="MX337489B_D0090.tif" />

for example. The route, tool face orientation data, and other data can be output to the address module 420 such that the address module 420 can guide the BHA to follow the new route as closely as possible. This output can include the calculated consulting angle of the tool face and the distance to the hole. The process returns again to step 504 where the tool face calculation machine 404 considers the current planned route, directional trends and projection for the bit depth. Now the current planned route is the new planned route calculated in step

518.

However, if in step 516 the planned route is determined to be a critical route, the tool face calculation machine 404 creates a route that guides the bit to intersect the original planned route to continue drilling. To do this, as indicated in step

520, the tool face calculation machine 404 calculates at least a first 3D curved section path (an "intersection path") from the projected auger position to the planned drill path or to the target. Optionally, the tool face calculation machine 404 can additionally calculate a second 3D curved section route to combine the BHA on the planned route from the intersection route before reaching the target. These curved section routes can be divided by a straight or retention section, depending on how far the BHA has strayed into the correction zone. Of course, if the route of

<img file="MX337489B_D0091.tif" />

<img file="MX337489B_D0092.tif" />

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INDUSTRIAL intersection is planned without a second 3D curved section route, the revised plan will be a straight or retention section, from the deviation to the new objective, either the final objective or a location on the original planned route.

In step 514, the tool face calculation machine

404 sends the revised direction route that includes the newly generated curves as one or more direction signs to the 420 address module. As before, the revised planned route could include the measured depth (MD), tilt, azimuth, north-south, and east -West, tool face, and DLS at regular station intervals of approximately 100 feet or 30 meters, for example. During the next iteration, the tool face calculation machine 404 considers the current planned route, directional trends and projection to the bit depth, the current planned route being the corrected planned route from step 504.

Method 500 iterates through the drilling process seeking to keep the actual drilling route with the planned route and adjust the planned route as circumstances require. In some modalities, the process occurs continuously in real time. This may advantageously speed up drilling without the need for stops for human consultation of a well plan or evaluation of inspection data. In other embodiments, the process is iterated after a pre-established drilling period or interval, such as for example about 90 seconds, about 5 minutes, about 10 minutes,

<img file="MX337489B_D0093.tif" />

approximately 30 minutes or some other duration. Alternatively, the iteration may be a predetermined drilling advance depth. For example, the process can be iterated when the existing hole extends approximately 1.52 meters, approximately 3.05 meters, approximately 4.57 meters, or some other depth. The process interval can also include both a time and depth component. For example, the process may include drilling for at least approximately 30 minutes or until the hole extends approximately 3.05 meters. In another example, the interval may include drilling until the hole extends approximately 6.1 meters, but not more than approximately 90 minutes. Of course, the time and depth values ​​described above for the range are only examples, and many other values ​​are also within the scope of the present description.

Once calculated by tool face calculation machine 404, typically electronically, the correction path to the original drilling plan and the correction path to the target location are passed to the control components of the site control system of the team. After calculating a correction, the tool face calculation machine 404 or other equipment site control component, including the address module 420, makes recommendations or tool face commands that can be performed on the equipment.

In some modes, a user can control

IMPI

MEXICAN INSTITUTE Dt INDUSTRIAL PROPERTY selectively if the 404 face calculating machine creates a new planned route to the target, or creates a corrected planned route to the original plan when the actual drilling route is in correction zone 536. For example , a user can select a default function that instructs the correction option to calculate a route to the "target" or "original plan". In some modes, the default value may be active only during designated portions of the original drill path.

Since directional control decisions are based on the amount of deviation of the drill hole from the planned route, a proximity scan of the normal plan for the planned hole can be performed after each inspection. If the drilling position is in the intervention zone, an elbow of the drill hole back to the plan will typically be recommended. If the well continues to disagree with the plan and enters the correction zone, a repurposed route will typically be calculated as a correction to the target or correction to the original plan.

Some modalities consider one or more variables in addition to, or instead of, the real-time projection at the depth of the auger or directional trends. The input variables may vary for calculation. In addition, dog paw severity, or radius of curvature, can be used to calculate a suitable curve that limits the amount of oscillation and avoids overvoltage of the drilling path. Dog paw severity, or radius of curvature, can be derived by analysis using the current drilling behavior of the BHA, from the parameters of

<img file="MX337489B_D0094.tif" />

IMPI

MEXICAN INSTITUTE D £ THE PROPERTY

INDUSTRIAL

<img file="MX337489B_D0095.tif" />

historical drilling, or a combination thereof .__

When you create a modified drill plan that returns the

BHA to the original auger route, such as when the projected location of the auger is within intervention zone 534, or when the planned drill route has deviated significantly and is a critical route, the goal is to return to the drill route originally planned before reaching the target location. However, the curve profile is still a consideration, as the curve profile can alter friction, oscillation, and other factors. The dog paw severity value can be used to calculate one or both of the curves as before - the first curve returning the bit to the original planned route or target, and the optional second curve allowing the BHA to align more quickly. and follow the planned route with a limited, if any, amount of overvoltage or overcorrection. One method of determining a curve profile includes calculating a curve-hold profile or curve-hold-curve profile to the target end point or location in the original plan, and then running the calculation on the target end point -1 again, inspection period, or distance calculation, or other period. The calculation is preferably accomplished electronically. This continues, going to the end point -2, and so on until the calculation fails. The last successful calculation of the profile can be arranged to produce one or two arcs that have the smallest acceptable radii of curvature with associated perforated lengths. These values ​​determine the advisory information of the tool face for the

OSLA PROPERTY MEXICAN INSTITUTE

INDUSTRIAL

<img file="MX337489B_D0096.tif" />

first correction curve used to develop the new drill path, and used to guide the BHA. When the actual drilling path reaches the final curve to intersect the original drilling plan, in the optional mode where a second final curve is used back to the original drilling plan, this final curve is drilled at the second length and radius of calculated curvature drilled.

It should be noted that, although the tolerance cylinder 532 and the intervention zone 534 are shown as cylinders without a circular cross section, they may have other shapes, including, without limitation, oval, conical, parabolic, or other, for example, or they may not be concentric around planned drill path 530. Alternative forms, for example, may allow the bit to deviate from the planned route more in one direction than the other, for example depending on geological deposits on one side of the planned route. Furthermore, although the described example includes three zones (the tolerance zone, the intervention zone and the correction zone), this is for explanatory purposes only. Other modalities can include additional zones and additional factors can be weighed when considering whether to create a route that intersects the original planned route, whether to create a route that travels directly to the target location without intersecting the original planned drill route, or what So smooth can DLS be on corrective curves.

In some exemplary modalities, a piercer can increase or decrease the size of the flight tolerance while drilling

MEXICAN INSTITUTE DB LA PROPIEDAD

INDUSTRIAL entering data into the tool face calculation machine &lt;10d. Fetus can help minimize or avoid overcorrection or excessive oscillation in the drilling path.

Once calculated, the data output from the tool face calculating machine 404 can act as the input to the address module 420 of FIG. 4C, or the address module 420 of FIG. 4A. For example, the data output from the tool face calculation machine 404 may include, but is not limited to, the orientation of the usable tool face such as input 41 Oh of FIG. 4A. In this figure, the orientation of the tool face 41 Oh is an input to the apparatus 400a and is used by the tool face controller 420a to control the shaft drive mechanism, 440. Additional output data from the tool face calculation machine 404 as inputs to apparatus 400a. Using these inputs, the 420a tool face controller, the 420b winch controller, and the 420f mud pump controller, can control the drill rig or the BHA itself to guide the BHA along the desired drill path. .

In some modalities, an alert module can be used to alert drillers, and / or to a well monitoring station, of a drift deviation from the planned drilling path, or any potential problems with the drilling system, or other information that requires attention. When the drillers are not in the drill rig, that is, the drillers are located remotely from the

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Τ 'Λ &lt;?'

Ilvi

MEXICAN INSTITUTE

OF INDUSTRIAL PROPERTY

<img file="MX337489B_D0097.tif" />

equipment, the alert module can be associated with the cfg “tool face 404 calculating machine, in such a way that when the 404 tool face calculating machine detects a deviation of the bit from the planned drilling path, the Alert module alerts the driller, and in some cases may be arranged to await manual user intervention, such as approval, before guiding the bit along a new route. This alert can occur on the drill rig through any suitable means, and can appear on the 472 as a visual alert. Alternatively, it can be an audible alert or it can trigger the transmission of an alert signal by means of an RF signal to designated locations or individuals.

In addition to communicating the alert to the display 472 or other location about the drilling equipment, the alert module can communicate the alert to an off-site location. This can allow off-site monitoring and can allow the driller to make remote adjustments. These alerts can be communicated via any suitable transmission link. For example, in some embodiments where the alert module sends the alert signal to a remote location, the alert may be through a satellite communication system. More particularly, one or more orbital satellites (generally fixed position) can be used to transmit communication (potentially bi-directional) signals between a well monitoring station and the alert module on the offshore platform. Alternatively, methods can be used

<img file="MX337489B_D0098.tif" />

INDUSTRIAL transmission of radio, cellular, optical or cdbltiddóé signals for communication between the alert module and the drillers or the well monitoring station. In situations where the oil drilling location is an offshore platform, a satellite communication system may be used, as in some situations cellular, wired, and ship-to-shore systems are impractical or unreliable. It should be noted that off-site monitoring and adjustments can be made without specific alerts, but through the use of the remote access systems described.

A centralized well monitoring station can generally be a computer or server configured to interact with a plurality of alert modules each placed on a different platform than a plurality of well platforms. The well monitoring station can be configured to receive various types of signals (satellite, RF, cellular, wired, optical, ship-to-shore, and telephone, for example) from a plurality of well drilling locations that have a module alert on them. The well monitoring station can also be configured to transmit selected information from the alert module to a specific remote user terminal of a plurality of remote user terminals in communication with the alert module. The well monitoring station can also receive information or instructions from the remote user terminal. The remote user terminal, via the well monitoring station and alert module, is configured to

<img file="MX337489B_D0099.tif" />

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INDUSTRIAL

<img file="MX337489B_D0100.tif" />

visualize drilling or production parameters-stop-the¹ pore associated with the alert module.

Generally the well monitoring station can be located in a data center, and can be in communication with the alert module at the drilling site via a satellite communication link, for example. The monitoring station can be configured to allow users to define alerts based on the information and data that is collected from drilling sites, using various data synchronization and duplication techniques. As such, the received data may not be truly real-time in each embodiment of the invention, since alerts depend on data that has been transmitted from a drilling site to the data center through a radio communication medium or satellite (which inherently takes some time to complete).

In one embodiment, an exemplary alert module monitors one, two, or more specific applications or properties. The operation section and the actual values ​​against which the alert is set are generally also handled by databases and metadata, and therefore when the property is of a particular data type then appropriate operations may be available so that the user selects them.

Turning now to Figure 6A, a flow chart of a method 600a is illustrated in accordance with one or more aspects of the present disclosure. Method 600a can be performed in association with one or more components of apparatus 100 shown in Figure 1 during operation of the

IMPI

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INDUSTRIAL

<img file="MX337489B_D0101.tif" />

apparatus 100. For example, method 600a may be performed to optimize drilling efficiency during drilling operations performed by apparatus 100, may be performed by any of the control systems disclosed in any of the figures in the present, including Figures 3 and 4A-4C, among others.

Method 600a includes a step 602 during which parameters for calculating specific mechanical energy (MSE) are detected, collected, or otherwise obtained. These parameters can be referred to herein as MSE parameters and can be used as input in Figures 4A-4C and others. MSE parameters include static and dynamic parameters. That is, some MSE parameters change on a substantially continuous basis. These dynamic MSE parameters include the weight over the bit (WOB), the rotational speed of the drill bit (RPM), the rotational torque of the drill string (TOR), and the penetration speed (ROP) of the drill bit through the formation being drilled. Other MSE parameters change infrequently, for example after disconnection, reaching a new type of formation, and by changing the types of augers, among other events. These static MSE parameters include mechanical efficiency ratio (MER) and drill bit diameter (DIA).

MSE parameters can be obtained substantially or totally automatically, requiring little or no user input. For example, during the first iteration through the steps of method 600a,

<img file="MX337489B_D0102.tif" />

Static MSE parameters can be retrieved by TTtedlu from automatic wi isutto from a database. Consequently, during subsequent iterations, static MSE parameters may not require repeated recovery, for example when drill bit or formation type data has not changed from the previous iteration of method 600a. Therefore, the execution of step 602, in many iterations, may require only the detection of the dynamic MSE parameters. Detection of dynamic MSE parameters can be performed by, or may be in association with, a variety of sensors, such as the sensors shown in Figures 1, 3, 4A and / or 4B.

A subsequent step 604 of method 600a includes calculating the

MSE. In an exemplary mode, the MSE is calculated according to the following formula:

MSE = MER x [(4 x WOB) / (π x DAY²) + (480 x RPM x TOR) / (ROP x DAY²)] where:

MSE = specific mechanical energy (Pascals);

MER = mechanical efficiency (ratio);

WOB = weight on bit (kilograms);

DIA = diameter of the drill bit (centimeters);

RPM = rotational speed of the bit (rpm);

TOR - torque of the drill string (meterskilogram); and

<img file="MX337489B_D0103.tif" />

IMPI

MEXICAN INSTITUTE £ 1 £ THE PROPERTY

INDUSTRIAL

ROP = penetration speed (meters pof-hour). ——

The MER can also be referred to as an efficiency factor of the drill bit. In an exemplary modality, the MER equals 0.35. However, the MER can change according to one or more of several conditions, such as the type of auger, type of formation, and / or other factors.

Method 600a also includes a decision step 606, during which the MSE calculated during previous step 604 is compared to an ideal MSE. The ideal MSE used for comparison during decision step 606 may be a single value, such as 100%. Alternatively, the ideal MSE used for comparison during decision step 606 may be a target value scale, such as 90% -100%. Alternatively, the ideal MSE can be a scale of values ​​derived from advanced analysis of the drilled area representing the various formations drilled in the current operation.

If it is determined during step 606 that the MSE calculated during step 604 is equal to the ideal MSE, or is within the ideal MSE scale, method 600a can be iterated by proceeding once again to step 602. However, if during step 606 it is determined that the calculated MSE is not equal to the ideal MSE, or is not within the ideal MSE scale, an additional step 608 is performed. During step 608 one or more operating parameters are adjusted in order to bring the MSE closer to the ideal MSE value or within the ideal MSE scale. For example,

<img file="MX337489B_D0104.tif" />

<img file="MX337489B_D0105.tif" />

MEXICAN INSTITUTE OF PROPERTY

INDUSTRIAL referring to Figures 1 and 6A, collectively, execution of step 608 may include increasing or decreasing WOB, RPM, and / or TOR, transmitting a control signal from controller 190 to upper command mechanism 140 and / or winch 130 to change RPM, TOR, and / or WOB.

After step 608 has been completed, method 600a can be iterated by proceeding once again to step 602.

Each of the 600a method steps can be performed automatically. For example, automatic detection of dynamic MSE parameters and database search of static MSE parameters have already been described above with respect to step 602. Controller 190 of Figure 1 (and others described herein) can be configured to automatically perform the MSE calculation from step 604, and can also be configured to automatically perform the MSE comparison from decision step 606, where both Calculation such as MSE comparison can be performed periodically at random intervals, or otherwise. The controller can also be configured to automatically generate and transmit the control signals from step 608, for example in response to the MSE comparison from step 606.

FIG. 6B illustrates a block diagram of apparatus 690 in accordance with one more aspect of the present disclosure. Apparatus 690 includes a user interface 692, a winch 694, a command system 696, and a controller 698. Apparatus 690 can be implemented within the medium and / or apparatus shown in Figures 1, 3, and 4A- 4C. By

<img file="MX337489B_D0106.tif" />

<img file="MX337489B_D0107.tif" />

For example, winch 694 may be substantially ^ irnilai to I3C winch shown in Figure 1, control system 696 may be substantially similar to upper command mechanism 140 shown in figure 1, and / or controller 698 may be substantially similar to controller 190 shown in Figure 1. Apparatus 690 can also be used to perform method 200a shown in Figure 2A, method 200b shown in Figure 2B, method 500 in Figure 5A, and / or method 600a shown in Figure 6A.

User interface 692 and controller 698 can be distinct components that are interconnected by wired or wireless means. However, alternatively user interface 692 and controller 698, may be integral components of a single system 699, as indicated by the dashed lines of Figure 6B.

User interface 692 includes means 692a for user input of one or more values ​​and / or predetermined efficiency data scales (for example MER), and means 692b for user input of one or more values ​​and / or predetermined scales of efficiency. auger diameters (eg DIA). Each of the data input means 692a and 692b may include a keyboard, voice recognition apparatus, dial, button, switch, slide selector, toggle lever, joystick, mouse, database (for example with compensation information), and / or other conventional or future-developed data entry device. Such data entry means can support

ΜΡΪ 6

MEXICAN INSTITUTE OF PROPERTY

INDUSTRIAL

<img file="MX337489B_D0108.tif" />

data input from local locations and / or wiilutas ·. ™ AlteniátlVá'tT additionally, data input means 692a and / or 692b may include means for user selection of predetermined values ​​and scales of MER and DIA, eg via one or more dropdown menus. The MER and DIA data, also, or alternatively, may be selected by controller 698 by executing one or more database search procedures. In general, the data input means and / or other components within the scope of this description can support the operation and / or monitoring of the system from stations at the equipment site and also from one or more remote locations with a link of communication to the system, network, local area network (LAN), wide area network (WAN), Internet, or radio, among other means.

User interface 692 may also include a display 692c to visually present information to the user in textual, graphic, or video form. The display 692c can also be used by the user to enter the MER and DIA data in conjunction with the data input means 692a and 692b. For example, the predetermined auger diameter and efficiency data input means, 692a and 692b, may be integral with, or may otherwise be in communication with, the display 692c.

The 694 winch includes an ROP sensor 694a that is configured to detect an ROP value or scale, and can be substantially similar to the ROP 130a sensor shown in Figure 1. The · * · AWJL Jt £

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INDUSTRIAL ROP data detected by the rlrTQr 00 1q pnrrfpn sensor will be sent by electronic signal to the 698 controller through wired or wireless transmission. Winch 694 also includes a control circuit 694b and / or other means to control the forward and / or reverse of a drill cable (such as drill cable 125 shown in Figure 1).

The 696 command system includes a torque sensor, 696a, which is configured to detect a reactive torque value or scale of the drill string (for example TOR), much like the torque sensor 140a and string Drill 155 shown in Figure 1. The 696 command system also includes a drill speed sensor, 696b, which is configured to detect a value or scale of the rotational speed of the drill bit within the hole (for example RPM), much like the Auger 140b, Drill Auger 175 and Auger 160 shown in Figure 1. The 696 command system also includes a WOB 696c sensor that is configured to detect a WOB value or scale, much like the WOB 140c sensor shown in Figure 1. Alternatively or additionally, the WOB 696c sensor can be located separately of the 696 command system, either in another component shown in Figure 6B or anywhere. Drill string torque, auger speed and WOB data detected by sensors 696a, 696b and 696c, respectively, can be sent via electronic signal to controller 698 via

IMPI

MEXICAN INSTITUTE OF INDUSTRIAL PROPERTY

<img file="MX337489B_D0109.tif" />

wired or wireless transmission. The 696 command system also includes a 696 control circuit and / or other means for controlling the rotational position, speed and direction of the shaft or other component of the drill string coupled to the 696 command system (such as shaft 145 shown in figure 1). Control circuit 696d and / or another component of command system 696 may also include means for controlling downhole mud motors. In this way, the RPM within the scope of this description can include mud pump flow data converted to downhole mud motor RPM, which can be added to the RPM of the string to determine the total RPM. of the auger.

Controller 698 is configured to receive parameters

Previously described MSEs of user interface 692, winch 694 and command system 696, and use the MSE parameters to calculate continuously, periodically, or otherwise, the MSE. Controller 698 is also configured to provide a signal to winch 694 and / or command system 696 based on calculated MSE. For example, controller 6980 may execute method 200a shown in Figure 2A, and / or method 200b shown in Figure 2B, and consequently supply one or more signals to winch 694 and / or command system 696 to increase or decrease WOB and / or auger speed, as required to optimize drilling efficiency (based on MSE).

Referring to Figure 6C, a flow chart of a method 600b is illustrated to optimize the drilling operation based on

<img file="MX337489B_D0110.tif" />

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MEXICAN INSTITUTE OF PROPERTY

INDUSTRIAL

<img file="MX337489B_D0111.tif" />

in the MSE calculated in real time according to one or more aspects of the present description. The data obtained can be used in cooperation with any of the systems described here. Method 600b can be performed by means of apparatus 100 shown in Figure 1, apparatus 300 shown in Figure 3, apparatus 400a shown in Figure 4A, apparatus 400b shown in Figure 4B, and / or apparatus 690 shown in Figure 6B. Method 600b can also be performed in conjunction with the embodiment of method 200a shown in Figure 2A, method 200b shown in Figure 2B, and / or method 600a shown in Figure 6A. Method 600b shown in Figure 6C can include or form at least a portion of method 600a shown in Figure 6A.

During step 612 of method 600b, a baseline MSE is determined for optimization of drilling efficiency based on MSE, by varying the WOB. As the baseline MSE determined in step

612 will be used for optimization by varying the WOB, the MSEblwob convention will be used here ·

In a subsequent step 614, the WOB is changed. Such a change may include increasing or decreasing the WOB. The increase or decrease in WOB during step 614 may be within certain predefined WOB limits. For example, the WOB change may not be greater than about 10%. However, other percentages including percentages within or beyond the predefined WOB limits are also within the scope of the present disclosure. The WOB can be

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change manually by operator input, or WOÉ can be changed automatically by signals transmitted by a controller, control system, and / or other component of drilling equipment and associated apparatus. As above, such signals can be by remote control from another location.

Subsequently, during a step 616, drilling continues with the WOB changed during a predetermined AWOB drilling interval. The AWOB interval can be a predetermined period, such as five minutes, ten minutes, thirty minutes, or some other duration.

Alternatively, the AWOB interval may be a predetermined depth of drilling advance. For example, step 616 may include continuing the drilling operation with the WOB changed until the existing hole extends 1.52 meters, 3.05 meters, 15.2 meters, or some other depth. The AWOB interval can also include both a time and depth component. For example, the AWOB interval may include drilling for at least thirty minutes, or until the hole extends 3.05 meters. In another example, the AWOB interval may include drilling until the hole extends 6.1 meters but not more than ninety minutes. Of course, the time and depth values ​​described above for the AWOB interval are only examples, and many other values ​​are also within the scope of this description.

After continuing the drilling operation through the

MEXICAN INSTITUTE

Say 'THE PROPERTY

INDUSTRIAL

I.

I ·. · AWOB interval with WOB changed, step 618 is performed to determine the MSE_AWob resulting from operating with the changed WOB during the ÁWOB interval. In a subsequent decision step 620, the MSE_tochanged wob is compared to the baseline MSEblwob. If the changed MSE¿wob is desirable with respect to the MSEblwob. method 600b continues to step 622. However, if the MSE_TOChanged wob is undesirable with respect to MSEblwob. method 600b continues to a step 624 where the WOB is restored to its value before step 614 is performed, and then the method continues to step 622.

The determination made during decision step 620 can be made manually or automatically by means of a controller, control system, or other component of the drilling equipment and associated apparatus. Determination may include finding the MSE_ÁWODesirable B if it is substantially equal to and / or less than the MSEblwob · However, additional or alternative factors may also have a role in the determination made in step 620.

During step 622 of method 600b, a baseline MSE is determined to optimize drilling efficiency based on the MSE, by varying the rotational speed of the bit, RPM. Since the baseline MSE determined in step 622 will be used for optimization by varying RPM, the MSEblrpm convention will be used here ·

In a subsequent step 626, the RPM is changed. Such a change may include increasing or decreasing the RPM. The increase or decrease of

MEXICAN INSTITUTE OF PROPERTY

INDUSTRIAL

<img file="MX337489B_D0113.tif" />

RPM during step 626 may be within certain predefined limits ofRPM. For example, the RPM change may not be greater than about 10%. However, other percentages including percentages within or beyond the predefined RPM limits are also within the scope of the present disclosure. The RPM can be changed manually via operator input, or the RPM can be changed automatically via signals transmitted by a controller, control system, and / or other component of the associated drill rig and apparatus.

Subsequently, during step 628, drilling continues with the RPM changed during a predetermined drilling interval úRPM. The ARPM interval can be a predetermined period, such as five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the ARPM interval may be the predetermined depth of advance of the drill. For example, step 628 may include continuing the drilling operation with the RPM changed until the existing hole extends 1.52 meters, 3.05 meters, 15.2 meters, or some other depth. The ARPM interval can also include both a time and depth component. For example, the ARPM interval may include drilling for at least thirty minutes or until the hole extends 3.05 meters. In another example, the ARPM interval may include drilling until the hole extends 6.1 meters but not more than ninety minutes. Of course, the time and depth values ​​above

MEXICAN INSTITUTE OF THE PBOWLDAD

INDUSTRIAL

<img file="MX337489B_D0114.tif" />

Described for the ARPM interval are only exemplary TCS / 'V WTllChOS utrus values ​​are also within the scope of the present description.

After continuing the drilling operation through the ARPM interval with the RPM changed, a step 630 is performed to determine the MSE_arpm resulting from the operation with the RPM changed during the ÁRPM interval. In a subsequent decision step 632, the MSE_toChanged rpm is compared to baseline MSEblrpm. If the MSE_toChanged rpm is desirable with respect to the MSEblrpm, method 600b returns to step 612. However, if the MSE_TOChanging rpm is undesirable with respect to MSEblrpm, method 600b continues to step 634 where the RPM is restored to its value before step 626 is performed, and then the method continues to step 612.

The determination made during decision step 632 can be made manually or automatically by a controller, control system, and / or other component of the drill rig and associated apparatus. Determination may include finding the MSE_tor_P.M desirable if it is substantially equal to and / or less than the MSEblrpm · However, additional or alternative factors may also have a role in the determination made during step 632.

Furthermore, after steps 632 and / or 634 have been performed, method 600b may not immediately return to step 612 for a subsequent iteration. For example, a subsequent iteration of method 600b may be delayed by a time interval or depth of

MEXICAN INSTITUTE OF INDUSTRIAL PROPERTY predetermined drilling advance. Alternatively, method 600b may end after steps 632 and / or 634 have been completed.

Referring to Figure 6D, a flowchart of a method 600c is illustrated to optimize the drilling operation based on the MSE calculated in real time in accordance with one or more aspects of the present disclosure. Method 600c can be performed by means of apparatus 100 shown in Figure 1, apparatus 300 shown in Figure 3, apparatus 400a shown in Figure 4A, apparatus 440b shown in Figure 4B, and / or apparatus 690 shown in Figure 6B. Method 600c can also be performed in conjunction with the embodiment of method 200a shown in Figure 2A, method 200b shown in Figure 2B, method 600a shown in Figure 6A, and / or method 600b shown in Figure 6C. . Method 600c shown in Figure 6D can include or form at least a portion of method 600a shown in Figure 6A, and / or method 600b shown in Figure 6C.

During step 640 of method 600c, a baseline MSE is determined to optimize drilling efficiency based on the MSE, decreasing the WOB. Since the baseline MSE determined in step 640 will be used for optimization by decreasing WOB, the MSEbl-wob convention will be used herein. In a subsequent step 642, the WOB is decreased. The decrease in WOB during step 642 may be within certain predefined WOB limits. For example, the decrease in WOB may not be

IMPI

MEXICAN INSTITUTE OF INDUSTRIAL PROPERTY

<img file="MX337489B_D0115.tif" />

greater than about 10%. However, other poceeaiajes-tamhiéo. are within the scope of the present disclosure, including where such percentages are within or beyond the predefined WOB limits. The WOB can be manually decreased by operator input, or the WOB can be automatically decreased by signals transmitted by a controller, control system, and / or other component of the drill rig and associated apparatus.

Subsequently, during step 644, drilling continues with the WOB decreased during a predetermined AWOB drilling interval. The -AWOB interval can be a predetermined period, such as five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the interval -AWOB may be a predetermined drilling advance depth. For example, step 644 may include continuing the drilling operation with the WOB decreased until the existing hole extends 1.52 meters, 3.05 meters, 15.2 meters, or some other depth. The -AWOB interval can also include both a time and depth component. For example, the -AWOB interval may include drilling for at least thirty minutes or until the hole extends 3.05 meters. In another example, the -AWOB interval may include drilling until the hole extends 6.1 meters, but not more than ninety minutes. Of course, the time and depth values ​​described above for the interval -AWOB are only examples, and many other values ​​are also within the scope of the present description.

<img file="MX337489B_D0116.tif" />

MEXICAN INSTITUTE OC THE PROPERTY

INDUSTRIAL

<img file="MX337489B_D0117.tif" />

After continuing the drilling operation at the interval -AWOB with decreased WOB, step 646 is performed to determine the MSE-_awob resulting from operating with the WOB decreased during the -áWOB interval. In a subsequent decision step 648, the MSE__AWdecreased ob compares to baseline MSEbl-wob. If the MSE._AWODecreased b is desirable with respect to the MSEbl-wob, method 600c continues to step 652. However, if the MSE._TODecreased wob is undesirable relative to the MSEbl-wob, method 600c continues to step 650 where the WOB is restored to its value before step 642 is performed, and then the method continues to step 652.

The determination made during decision step 648 can be made manually or automatically by a controller, control system, and / or other component of the drill rig and associated apparatus. Determination may include finding the MSE__AWob desirable if it is substantially equal to and / or less than the MSEbl-wob · However, additional or alternative factors may also have a role in the determination made during step 648.

During step 652 of method 600c, a baseline MSE is determined to optimize drilling efficiency based on MSE, increasing the WOB. Since the baseline MSE determined in step 652 will be used for optimization by increasing the WOB, this convention will use the MSEbl + wob convention ·

In a subsequent step 654, the WOB is increased. Increasing

IMPI

MEXICAN INSTITUTE OF INDUSTRIAL PROPERTY

<img file="MX337489B_D0118.tif" />

of WOB during step 654 may be within the predefined WOB 1. For example, the WOB increase may be no more than about 10%. However, other percentages are also within the scope of the present disclosure, including where such percentages are within or beyond the predefined WOB limits. The WOB can be manually increased by operator input, or the WOB can be automatically increased by signals transmitted by a controller, control system, and / or other component of the associated drill rig and apparatus.

Subsequently, during step 656, drilling continues with the WOB increased during a predetermined drilling interval + AWOB. The + AWOB interval can be a predetermined period, such as five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the + AWOB interval can be a predetermined drilling advance depth. For example, step 656 may include continuing the drilling operation with the WOB increased until the existing hole extends 1.52 meters, 3.05 meters, 15.2 meters, or some other depth. The interval + ÁWOB can also include a component of both time and depth. For example, the interval + ÁW0B may include drilling for at least thirty minutes or until the hole extends 3.05 meters. In another example, the interval + ÁW0B may include drilling until the hole extends 6.1 meters, but not more than ninety minutes.

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INDUSTRIAL

After continuing the drilling operation through the interval + ÁWOB with the WOB increased, a step 658 is performed to determine the MSE_{+ AW}ob resulting from operating with the WOB increased during the + or WOB interval. In a subsequent decision step 660, the MSE_{+ AW}changed ob is compared to baseline MSEbl + wob. If the MSE +_AWChanged ob is desirable with respect to MSEbl + wob, method 600c continues to step 664. However, if the MSE_{+ A}Changed wob is undesirable with respect to MSEbl + wob, method 600c continues to step 662 where the WOB is restored to its value before step 654 is performed, and then the method continues to step 664.

The determination made during decision step 660 can be made manually or automatically by a controller, control system, and / or other component of the drill rig and associated apparatus. The determination may include finding the desirable MSE + awob if it is substantially equal to and / or less than the MSEbl + wob · However, additional or alternative factors may also have a role in the determination made during step 660.

During step 664 of method 600c, a baseline MSE is determined to optimize drilling efficiency based on MSE, decreasing the rotational speed of the bit, RPM. Since the baseline MSE determined in step 664 will be used for optimization by decreasing the RPM, the MSEbl-rpm convention will be used herein. In a subsequent step 666, the RPM is decreased. The

IMPI

Mexican Institute of Industrial Property

<img file="MX337489B_D0119.tif" />

RPM decrease during step 666 may be within certain predefined RPM limits. For example, the decrease in RPM may be not more than about 10%. However, other percentages are also within the scope of the present disclosure, including where such percentages are within or beyond predefined RPM limits. The RPM can be manually decreased by operator input, or the RPM can be automatically decreased by signals transmitted by a controller, control system and / or other component of the associated drilling equipment and apparatus.

Subsequently, during step 668, drilling continues with the decreased RPM during a predetermined drilling interval ARPM. The -ARPM Interval can be a predetermined period, such as five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the Interval -ARPM can be a predetermined drilling advance depth. For example, step 668 may include continuing the drilling operation with the RPM decreased until the existing hole extends 1.52 meters, 3.05 meters, 15.2 meters, or some other depth. The -ARPM interval can also include both a time and depth component. For example, the -ARPM interval may include drilling for at least thirty minutes or until the hole extends 3.05 meters. In another example, the -ARPM interval may include drilling until the hole extends 6.1 meters, but not more than ninety minutes.

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MEXICAN INSTITUTE OF INDUSTRIAL PROPERTY

<img file="MX337489B_D0120.tif" />

<img file="MX337489B_D0121.tif" />

After continuing the drilling operation through the -ARPM interval with the decreased RPM, a step 670 is performed to determine the MSE._ARp_M resulting from operating with the RPM decreased during the -ARPM interval. In a subsequent decision step 672, the MSE._todecreased rpm compared to MSE_blbaseline .rpm. If the changed MSE-arpm is desirable with respect to the MSEbl-rpm, method 600c continues to step 676. However, if the changed MSE.rpm is undesirable with respect to the MSEbl-rpm, method 600c continues at step 674 where the RPM is restored to its value before step 666 is performed, and then the method continues to step 676.

The determination made during decision step 672 can be made manually or automatically by a controller, control system, and / or other component of the drill rig and associated apparatus. Determination may include finding the MSE._TODesirable rpm if it is substantially equal to and / or less than the MSEbl-rpm- However, additional or alternative factors may also have a role in the determination made during step 672.

During step 600 of method 600c, a baseline MSE is determined to optimize drilling efficiency based on MSE, increasing the rotational speed of the bit, RPM. Since the baseline MSE determined in step 676 will be used for optimization by increasing the RPM, the MSE convention will be used here_Bl + rpm In a subsequent step 678, the RPM is increased. Increasing

IMPI

MEXICAN INSTITUTE OF PROPERTY

INDUSTRIAL

<img file="MX337489B_D0122.tif" />

of RPM during step 678 may be within certain RPM pléUuíiiiidusr hiiiiles. For example, the RPM increase may be no more than about 10%. However, other percentages are also within the scope of the present disclosure, including where such percentages are within or beyond predefined RPM limits. The RPM can be manually increased by operator input, or the RPM can be automatically increased by signals transmitted by a controller, control system, and / or other component of the drilling rig and associated apparatus.

Subsequently, during step 680, drilling continues with the increased RPM during a predetermined drilling interval + ARPM. The interval + ARPM can be a predetermined period, such as five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the interval + ARPM can be a predetermined drilling advance depth. For example, step 680 may include continuing the drilling operation with the RPM increased until the existing hole extends 1.52 meters, 3.05 meters, 15.2 meters, or some other depth. The + ARPM interval can also include both a time and depth component. For example, the + ARPM interval may include drilling for at least thirty minutes or until the hole extends 3.05 meters. In another example, the + ARPM interval may include drilling until the hole extends 6.1 meters, but not more than ninety minutes.

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MEXICAN INSTITUTE OE INDUSTRIAL PROPERTY

<img file="MX337489B_D0123.tif" />

After continuing the drilling operation through the interval + ARPM with the increased RPM, a step 682 is performed to determine the MSE_{+ arpm} resulting from operating with the RPM increased during the + ARPM interval. In a subsequent decision step 684, the MSE_{+ A}increased rpm compared to MSE_Bl + baseline rpm. If the MSE_{+ a}r_P.Mchanged is desirable with respect to MSE_Bl + rpm, method 600c continues to step 688. However, if the MSE_{+ arpm} changed is undesirable with respect to MSE_bl+ rpm, method 600c continues to step 686 where the RPM is restored to its value before step 678 is performed, and then the method continues to step 688.

The determination made during decision step 684 can be made manually or automatically by a controller, control system, and / or other component of the drill rig and associated apparatus. Determination may include finding the MSE_{+ arpm} desirable if it is substantially equal to and / or less than the MSEbl + rpm. However, additional or alternative factors may also have a role in the determination made during step 684.

Step 688 includes waiting a predetermined drilling depth time or interval before repeating method 600c by returning to step 640. However, in an exemplary embodiment, the interval may be as small as 0 seconds or 0 meters, such that the method returns to step 640 substantially immediately after performing steps 684 and / or 686. Alternatively, method 600c may not

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require iteration, such that the uuuu method _Pueue ieniiiuai

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substantially after the completion of steps 684 or 686.

In addition, each of the Drill Ranges -AWOB, + AWOB, -áRPM and + ÁRPM, can be substantially identical within a single Iteration of method 600c. Alternatively, one or more of the Intervals may vary in duration or depth with respect to the other Intervals. Generally speaking, the amount that the WOB decreases or increases in steps 642 and 654 can be substantially the same, or can vary from each other within a single iteration of method 600c. The amount that the RPM decreases or increases in steps 666 and 678 may be substantially the same, or may vary from one another within a single iteration of method 600c. WOB and RPM variations may also change or remain the same with respect to subsequent iterations of the method

600c.

As described above, one or more aspects of the present disclosure can be used for drilling operation or MSE based control. However, one or more aspects of the present disclosure may be used additionally or alternatively for drilling operation or control based on ΔΤ. That is, as described above, during the drilling operation a torque of the upper drive or other rotary drive is transmitted to the drill string. The torque required to drive the bit can be referred to as the torque on the bit (TOB), and can be monitored

IMPI,

MEXICAN INSTITUTE

OF THE MORSOAD Ά-

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using a sensor such as the "T40a mWiracW * '' torque sensor in FIG. 1, the torque sensor 355 shown in FIG. 3, one or more of the sensors 430 shown in FIGS. 4A and 4B, the torque sensor 696a shown in Figure 6B, and / or one or more torque sensing devices of the BHA.

The drill string experiences various types of vibrations during drilling, including axial (longitudinal) vibrations, bending (lateral) vibrations, and torsional (rotational) vibrations. Torsional vibrations are caused by nonlinear interaction between the bit, the drill string and the hole. As described above, this torsional vibration can include slip-grip vibration, characterized by alternating stops (during which the BHA remains fixed or "sticks" to the hole) and large angular velocity ranges of the BHA (during which the BHA "Slides" with respect to the hole).

The adherence-slip behavior of the BHA causes real-time vibrations of TOB, or ΔΤ. This ΔΤ can be used to withstand a slip / adhesion alarm (SSA) in accordance with one or more aspects of the present description. For example, a ΔΤ or SSA parameter can usually be displayed with a “stop light” indicator, where a green light can indicate an acceptable operating condition (for example, SSA parameter 0-15), an amber light can indicate that slip-adhesion behavior is imminent (for example, SSA parameter of 16-25), and a red light may indicate that

<img file="MX337489B_D0128.tif" />

a behavior — Hp adhprpnna slip is probably occurring (for example, SSA parameter greater than 25). However, these exemplary thresholds may be adjustable during operation as they may change with drilling conditions. The ΔΤ or SSA parameter, alternatively or additionally, can be displayed graphically (eg displaying current and historical data), audibly (eg via an annunciator), or via a meter or calibrator display. Combinations of these display options are also within the scope of this description. For example, the previously described “stoplight” indicator may continuously indicate the SSA parameter regardless of its value, and an audible alarm may be triggered if the SSA parameter exceeds a predetermined value (eg 25).

A drilling operation controller or other apparatus within the scope of the present disclosure may have one or more aspects of drilling operation or control integrated, based on the parameter ΔΤ or SSA described above. For example, a controller such as controller 190 shown in Figure 1, controller 325 shown in Figure 3, controller 420 shown in Figures 4A or 4B, and / or controller 698 shown in Figure 6B, can be configured to automatically adjust the RPM of the drill string with a short RPM boost increased or decreased (for example +/- 5 RPM) to interrupt the harmony of slip-grip vibration before sensing, or when sensing, the adhesion-slip effect, and then return

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MEXICAN INSTITUTE OF PROPERTY

INDUSTRIAL

<img file="MX337489B_D0129.tif" />

at normal RPM. The controller can be confiyuiai pjra — graflUár automatically up or down the RPM in a predetermined amount or percentage or adjustable by user, for a predetermined duration or adjustable by user, trying to get the drilling operation out of the harmonic state. Alternatively, the controller can be configured to continue to automatically adjust the RPM up or down in increments, until the ΔΤ or SSA parameter indicates that the grip-slip operation has been stopped.

In an exemplary mode, the controller enabled by ΔΤ or

SSA can be additionally configured to automatically reduce the WOB if the stick-slip effect is severe, for example due to an excessively high target WOB. Such automatic WOB reduction may include a single adjustment or incremental adjustments, either temporary or long-term, and which can be sustained until the ΔΤ or SSA parameter indicates that the stick-slip operation has been stopped.

The ΔΤ or SSA enabled controller can be further configured to automatically increase the WOB, for example to find the upper slip-adherence limit of the WOB. For example, if all other possible drilling parameters are optimized or adjusted within corresponding limits, the controller may automatically increase the WOB incrementally until the ΔΤ or SSA parameter approaches or equals its upper limit (for example 25) .

<img file="MX337489B_D0130.tif" />

MEXICAN INSTITUTE DS LA FROFTEDAD

INDUSTRIAL

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In an exemplary embodiment, the ΔΤ-based drilling operation or control in accordance with one or more aspects of the present disclosure may operate in accordance with one or more aspects of the following pseudocode:

YES (counter &lt;= ProcessTime)

YES (counter = = 1)

MinimumTorque = Realtime_Torque

PRINT (“Minimum”, Minimum Torque)

MaximumTorque = Realtime_Torque 10 PRINT (“Maximum”, Maximum Torque)

END

YES (Realtime_Torque &lt;Minimum_Torque)

MinimumTorque = RealtimeTorque

END

YES (Maximum Torque &lt;Realtime Torque)

Maximum_Torque = Realtime_Torque

END

Torquecounter = (Torquecounter + RealtimeTorque)

Average_Torque = (Torque_counter / counter) counter = counter + 1

PRINT (“Process_Time”, Process Time)

ON THE CONTRARY

SSA = ((MaximumTorque - Minimum_Torque) /

<img file="MX337489B_D0131.tif" />

MEXICAN INSTITUTE OF PROPERTY

INDUSTRIAL

<img file="MX337489B_D0132.tif" />

Average_Torque) * 100 where ProcessTime is the time elapsed since the ΔΤ or SSA parameter monitoring started, MinimumTorque is the minimum TOB that occurred during Process_Time, Maximum_Torque is the maximum TOB that occurred during Process Time, the Realtime_Torque is the current TOB , the Average_Torque is the average TOB during Process_Time, and SSA is the slip-grip alarm parameter.

As described above, the parameter ΔΤ or SSA can be used within, or in accordance with, the method 200a shown in Figure 2A, the method 200b shown in Figure 2B, the method 600a shown in Figure 6A , method 600b shown in Figure 6C, and / or method 600c shown in Figure 6D. For example, as shown in Figure 7A, the ΔΤ or SSA parameter can be replaced with the previously described MSE parameter with respect to Figure 6A. Alternatively, the ΔΤ or SSA parameter can be monitored in addition to the previously described MSE parameter with respect to Figure 6A, such that drilling operation or control is based on both the MSE and the ΔΤ or SSA parameter.

Referring to Figure 7A, a flow chart of a method 700a is illustrated in accordance with one or more aspects of the present disclosure. Method 700a can be performed in association with one or more components of apparatus 100 shown in Figure 1, apparatus 300 shown in Figure 3, apparatus 400a shown in Figure 4A, apparatus

<img file="MX337489B_D0133.tif" />

<img file="MX337489B_D0134.tif" />

400b shown in Figure 4B, and / or apparatus 690 shown in Figure 6B, during operation thereof.

Method 700a includes a step 702 during which the current ΔΤ parameters are measured. In a subsequent step 704 the ΔΤ is calculated. If the

ΔΤ is sufficiently equal to the desired or ideal ΔΤ, determined during decision step 706, method 700a is iterated, and step 702 is repeated. "Ideal" can be as described above. Iteration of method 700a may be substantially immediate, or there may be a delay period before method 700a is iterated and step 702 is repeated. If the ΔΤ is not ideal, determined during decision step 706, method 700a continues to step 708 during which one or more drilling parameters (eg WOB, RPM, etc.) are adjusted trying to improve Δ. After step 708 is performed, method 700a is iterated and step 702 is repeated. Such an iteration may be substantially immediate, or there may be a delay period before method 700a is iterated and step 702 is repeated.

Referring to Figure 7B, a flow chart of a method 700b for monitoring ΔΤ and / or SSA is illustrated in accordance with one or more aspects of the present disclosure. Method 700b can be performed by means of apparatus 100 shown in Figure 1, apparatus 300 shown in Figure 3, apparatus 400a shown in Figure 4A, apparatus 400b shown in Figure 4B, and / or apparatus 690 shown in Figure 6B. Method 700b can also be performed in conjunction with performing method 200a

<img file="MX337489B_D0135.tif" />

method 600c shown in figure 6D, and / or method 700a shown in figure 7A. Method 700b shown in Figure 7B may include or form at least a portion of method 700a shown in Figure 7A.

During step 712 of method 700b, a baseline ΔΤ is determined for optimization based on ΔΤ, varying WOB. Since the baseline ΔΤ determined in step 712 will be used for optimization by varying the WOB, the ATblwob convention will be used here ·

In a subsequent step 714, the WOB is changed. Such a change may include increasing or decreasing the WOB. The increase or decrease in WOB during step 714 may be within certain predefined WOB limits. For example, the WOB change may not be greater than about 10%. However, other percentages are also within the scope of the present disclosure, including where such percentages are within or beyond the predefined WOB limits. The WOB can be changed manually via operator input, or the WOB can be changed automatically via signals transmitted by a controller, control system, and / or other component of the associated drill rig and apparatus. As above, such signals can be by remote control from another location.

Subsequently, during step 716 drilling continues with the WOB changed during a predetermined drilling interval ÁWOB.

100

IMPI

MEXICAN INSTITUTE OF INDUSTRIAL PROPERTY

<img file="MX337489B_D0136.tif" />

The AWOB Interval can be a predetermined period, 'lili luiiiu elnuu minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the AWOB interval may be a predetermined drilling advance depth. For example, step 716 may include continuing the drilling operation with the WOB changed until the existing hole extends 1.52 meters, 3.05 meters, 15.2 meters, or some other depth. The AWOB Interval can also include both a time and depth component. For example, the AWOB interval may include drilling for at least thirty minutes, or until the hole extends 3.05 meters. In another example, the AWOB interval may Include Drilling until the hole extends 6.1 meters but not more than ninety minutes. Of course, the time and depth values ​​described above for the AWOB Interval are only examples, and many other values ​​are also within the scope of this description.

After the drilling operation continues through the AWOB interval with the WOB changed, step 718 is performed to determine the AT¿wob resulting from operating with the changed WOB during the AWOB interval. In a subsequent decision step 720, the AT_AWOb changed compared to baseline ATblwob. IF AT_AWchanged ob is desirable with respect to ATblwob, method 700b continues to step 722. However, if AT_tochanged wob is undesirable with respect to ATblwob, method 700b continues to step 724 where the WOB is restored to its

101

<img file="MX337489B_D0137.tif" />

FROM LA ΡΛΟΡιΙΧΛΟ INDUSTRIAL

<img file="MX337489B_D0138.tif" />

value before step 714 is performed, and then the method continues to step 722.

The determination made during decision step 720 can be made manually or automatically by means of a controller, control system, and / or other component of the drill rig and associated apparatus.

The determination may include finding the desirable ΔΤ ^ ννοβ if it is substantially equal to and / or less than the AT_Blwob · However, additional or alternative factors may also have a role in the determination made in step 720.

During step 722 of method 700b, a baseline ΔΤ for optimization is determined based on the ΔΤ, varying the rotational speed of the bit, RPM. Since the baseline ΔΤ determined in step 722 will be used for optimization by varying the RPM, the ATblrpm convention will be used here ·

In a subsequent step 726, the RPM is changed. Such a change may include increasing or decreasing the RPM. The increase or decrease in RPM during step 726 may be within certain predefined RPM limits. For example, the RPM change may not be greater than about 10%. However, other percentages including percentages within or beyond the predefined RPM limits are also within the scope of the present disclosure. The RPM can be changed manually via operator input, or the RPM can be changed automatically using signals transmitted by a

102

<img file="MX337489B_D0139.tif" />

.MEXICAN INSTITUTE OF THE PkOr-IHDAO

INDUSTRIAL

<img file="MX337489B_D0140.tif" />

controller, control system, and / or other component of the drilling rig · and associated apparatus.

Subsequently, during step 728, drilling continues with the RPM changed during a predetermined drilling interval ÁRPM.

The ÁRPM interval can be a predetermined period, such as five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the RPM interval may be the predetermined depth of advance of the drilling. For example, step 728 may include continuing the drilling operation with the RPM changed until the existing hole extends 1.52 meters, 3.05 meters, 15.2 meters, or some other depth. The ÁRPM interval can also include both a time and depth component. For example, the ARPM interval may include drilling for at least thirty minutes or until the hole extends 3.05 meters. In another example, the ÁRPM interval may include drilling until the hole extends 6.1 meters but not more than ninety minutes. Of course, the time and depth values ​​described above for the ÁRPM range are only examples, and many other values ​​are also within the scope of this description.

After continuing the drilling operation through the ÁRPM interval with the RPM changed, a step 730 is performed to determine the ÁTarpm that results from the operation with the RPM changed during the ARPM interval. In a subsequent decision step 732, the áT_tor_P.Mchanged is compared to baseline áTblrpm. If the AT_ARPM changed trainas », ·

<img file="MX337489B_D0141.tif" />

103

<img file="MX337489B_D0142.tif" />

is desirable with respect to ATblrpm, method 700b returns to step 712.

However, if the changed AT¿rpm is undesirable with respect to the ATblrpm, method 700b continues to step 734 where the RPM is restored to its value before step 726 is performed, and then the method continues to step 712 .

The determination made during decision step 732 can be made manually or automatically by a controller, control system, and / or other component of the drill rig and associated apparatus. Determination may include finding the AT_TODesirable rpm if it is substantially equal to and / or less than ATblrpm- However, additional or alternative factors may also have a role in the determination made during step 732.

Also, after performing steps 732 or 734, the method

700b may not immediately return to step 712 for a subsequent iteration 15. For example, a subsequent iteration of method 700b may be delayed by a predetermined time interval or drilling advance depth. Alternatively, method 700b may end after steps 732 or 734 have been completed.

Referring to FIG. 7C, a flow chart of a method 700c for optimizing the drilling operation is illustrated based on the AT calculated in real time in accordance with one or more aspects of the present disclosure. Method 700c can be performed by means of apparatus 100 shown in Figure 1, apparatus 300 shown in Figure 3, the

104

INSTn UTO Mí-Z'CAaO OF PROPERTY I MD U; T RlÁL apparatus 400a shown in figure 4A, apparatus 400b shown in figure

4B, and / or the apparatus 690 shown in Figure 6B. Method 700c may also be performed in conjunction with the embodiment of method 200a shown in Figure 2A, method 200b shown in Figure 2B, method 600a shown in Figure 6A, method 600b shown in Figure 6C, method 600c shown in Figure 6D, method 700a shown in Figure 7A, and / or method 700b shown in Figure 7B. Method 700c shown in Figure 7C, may include or form at least a portion of method 700a shown in Figure 7A, and / or method 700b shown in Figure 7B.

During step 740 of method 700c a baseline ΔΤ is determined for optimization based on the ΔΤ, decreasing the WOB. Since the baseline ΔΤ determined in step 740 will be used for optimization by decreasing the WOB, the convention áT will be used here_Bl-wob

In a subsequent step 742 the WOB is decreased. The decrease in WOB during step 742 may be within certain predefined WOB limits. For example, the decrease in WOB may not be greater than about 10%. However, other percentages that include percentages within or beyond the predefined WOB limits are also within the scope of the present disclosure. The WOB can be manually decreased via operator input, or the

WOB can be automatically decreased by means of signals transmitted by a controller, control system, and / or other component of the drill rig and associated apparatus.

<img file="MX337489B_D0143.tif" />

t »

105

<img file="MX337489B_D0144.tif" />

Subsequently, during step 744, the drilling-eootinusucxMi the WOB decreased during a predetermined Drilling Interval AWOB. The Interval -AWOB can be a predetermined period, such as five minutes, ten minutes, thirty minutes, or some other duration.

Alternatively, the Interval -AWOB can be the default drilling advance depth. For example, step 744 may include continuing the drilling operation with the WOB decreased until the existing hole extends 1.52 meters, 3.05 meters, 15.2 meters, or some other depth. The -AWOB Interval can also include both a time and depth component. For example, the -AWOB interval may include drilling for at least thirty minutes or until the hole extends 3.05 meters. In another example, the -AWOB interval may include drilling until the hole extends 6.1 meters but not more than ninety minutes. Of course, the time and depth values ​​described above for the -AWOB range are only examples, and many other values ​​are also within the scope of the present description.

After continuing the drilling operation through the -AWOB interval with the WOB decreased, a step 746 is performed to determine the aT._AWob resulting from operating with the WOB decreased during the

-AWOB interval. In a subsequent decision step 748, AT._TOdecreased wob compares to AT_BBaseline l-wob. YES AT._AWdecreased ob is desirable with respect to AT_BL-wob, method 700c returns to step 752. However, if AT._AWOdecreased b is undesirable with respect

106

<img file="MX337489B_D0145.tif" />

At áTbl-wob, method 700c continues to step 750 where the WOB is restored to its value before step 742 is performed, and then the method continues to step 752.

The determination made during decision step 748 can be made manually or automatically by a controller, control system, and / or other component of the drill rig and associated apparatus. Determination may include finding the AT-_TOwob desirable if it is substantially equal to and / or less than the áT_BL-wob · However, additional or alternative factors may also have a role in the determination made during step 748.

During step 752 of method 700c a baseline ΔΤ is determined for optimization based on the ΔΤ, increasing the WOB. Since the baseline ΔΤ determined in step 752 will be used for optimization by increasing the WOB, the AT convention will be used here_bl+ wob In a subsequent step 754 the WOB is increased. The increase in WOB during step 754 may be within certain predefined WOB limits. For example, the WOB increase may not be greater than about 10%. However, other percentages that include percentages within or beyond the predefined WOB limits are also within the scope of the present disclosure. The WOB can be manually increased by operator input, or the WOB can be automatically increased by signals transmitted by a controller, control system, and / or other component of the drill rig.

107

IMPI ^

MEXICAN INSTITUTE

Ε&gt; ϊ PROPERTY 0 * 2 «

INDUSTRIAL and associated apparatus.

Subsequently, during step 756, drilling continues with the WOB increased during a predetermined drilling interval + AWOB. The + AWOB interval can be a predetermined period, such as five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the + AWOB interval can be the default drilling advance depth. For example, step 756 may include continuing the drilling operation with the WOB increased until the existing hole extends 1.52 meters, 3.05 meters, 15.2 meters, or some other depth. The + AW0B interval can also include both a time and depth component. For example, the + AWOB interval may include drilling for at least thirty minutes or until the hole extends 3.05 meters. In another example, the + AW0B interval may include drilling until the hole extends 6.1 meters but not more than ninety minutes.

After continuing the drilling operation through the interval + AW0B with the WOB increased, a step 758 is performed to determine the AT_{+ a}wob that results from operating with the WOB increased during the interval + AW0B. In a subsequent decision step 760, the switched AT + awob is compared to the AT_bl+ baseline wob. If the AT_{+ AVV}changed ob is desirable with respect to AT_{bl +}wob, method 700c continues to step 764.

However, if the AT_{+ a}changed wob is undesirable with respect to the

AT_Bl₊wob, method 700c continues to step 762 where the WOB is

108

ΙΜ jL

INDU »» EVIL

<img file="MX337489B_D0146.tif" />

restored to its value before step 754 is performed, and then the method continues to step 764.

The determination made during decision step 760 can be made manually or automatically by a controller, control system, and / or other component of the drill rig and associated apparatus. Determination may include finding the ΔΤ_{+ Δνν}οΒ desirable if it is substantially equal to and / or less than AT_Bl + wob However, additional or alternative factors may also have a role in the determination made during step 760.

During step 764 of method 700c, a baseline ΔΤ for optimization is determined based on ΔΤ, decreasing the rotational speed of the bit, RPM. Since the baseline ΔΤ determined in step 764 will be used for optimization by decreasing the RPM, the ATbl-rpm convention will be used here ·

In a subsequent step 766, the RPM is decreased. The decrease in RPM during step 766 may be within certain predefined RPM limits. For example, the decrease in RPM may be not more than about 10%. However, other percentages are also within the scope of the present disclosure, including where such percentages are within or beyond predefined RPM limits. The RPM can be manually decreased by operator input, or the RPM can be automatically decreased by

<img file="MX337489B_D0147.tif" />

r&gt; z

109 means of signals transmitted by a controller, a control system and / or another component of the drilling equipment and associated apparatus.

Subsequently, during step 768 drilling continues with the decreased RPM during a predetermined drilling interval ARPM. The -ARPM interval can be a predetermined period, such as five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the interval -ARPM can be a predetermined drilling advance depth. For example, step 768 may include continuing the drilling operation with the RPM decreased until the existing hole extends 1.52 meters, 3.05 meters, 15.2 meters, or some other depth. The -ARPM interval can also include both a time and depth component. For example, the -ARPM interval may include drilling for at least thirty minutes or until the hole extends 3.05 meters. In another example, the -ARPM interval may include drilling until the hole extends 6.1 meters, but not more than ninety minutes.

After continuing the drilling operation through the -ARPM interval with the RPM decreased, a step 770 is performed to determine the AT._tor_P.M resulting from operating with the RPM decreased during the -ARPM interval. In a subsequent decision step 772, AT._tor_p.m decreased compared to AT_BBaseline l-rpm. If the AT._TOr_P.M changed is desirable with respect to AT_Bl-rpm, method 700c continues to step 776.

110

However, if the áT._arpm changed not desirable 'Τ · i ie) | iucF ^the rpm, method 700c continues to step 774 where the RPM is restored to its value before step 766 is performed, and then the method continues to step 776.

IMPI

MEXICAN PROPERTY

INDUSTRIAL

<img file="MX337489B_D0148.tif" />

The determination made during decision step 772 can be made manually or automatically by a controller, control system, and / or other component of the drill rig and associated apparatus. Determination may include finding the AT-_ARPm desirable if it is substantially equal to and / or less than the ATbl-rpm- However, additional or alternative factors may also have a role in the determination made during step 772.

During step 776 of method 700c, a baseline ΔΤ for optimization is determined based on ΔΤ, increasing the rotational speed of the bit, RPM. Since the baseline ΔΤ determined in step 776 will be used for optimization by increasing the RPM, the AT convention will be used here_Bi_ + rpm.

In a subsequent step 778, the RPM is increased. The RPM increase during step 778 may be within certain predefined RPM limits. For example, the RPM increase may be no more than about 10%. However, other percentages are also within the scope of the present disclosure, including where such percentages are within or beyond predefined RPM limits. The . J

<img file="MX337489B_D0149.tif" />

111

<img file="MX337489B_D0150.tif" />

RPM can be manually increased via operator input, &amp; RPM can be automatically increased by signals transmitted by a controller, control system and / or other component of the drill rig and associated apparatus.

Subsequently, during step 780 drilling continues with the increased RPM during a predetermined drilling interval + ARPM. The interval + ARPM can be a predetermined period, such as five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the interval + ARPM can be a predetermined drilling advance depth. For example, step 780 may include continuing the drilling operation with increased RPM until the existing hole extends 1.52 meters, 3.05 meters, 15.2 meters, or some other depth. The + ARPM interval can also include both a time and depth component. For example, the + ARPM interval may include drilling for at least thirty minutes or until the hole extends 3.05 meters. In another example, the interval + ARPM can Include drill until the hole extends 6.1 meters, but not more than ninety minutes.

After continuing the drilling operation through the + ARPM interval with the increased RPM, a step 782 is performed to determine the AT_{+ arpm} resulting from operating with the RPM increased during the + ARPM interval. In a subsequent decision step 784, the AT_{+ arpm} increased compared to AT_Bl + baseline rpm. IF AT_{+ arpm}

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MEXICAN INSTITUTE OF INDUSTRIAL PROPERTY

<img file="MX337489B_D0151.tif" />

changed is desirable with respect to AT_Bl + rpm, method 700c continues to step 788. However, if the AT_{+ a}r_P.M changed is undesirable with respect to ATbl + rpm, method 700c continues to step 786 where the RPM is restored to its value before step 778 is performed, and then the method continues to step 788.

The determination made during decision step 784 can be made manually or automatically by a controller, control system, and / or other component of the drill rig and associated apparatus. Determination may include finding the AT_{+ A}rp_M desirable if it is substantially equal to and / or less than AT_Bl + rpm- However, additional or alternative factors may also have a role in the determination made during step 784.

Step 788 includes waiting a predetermined drilling depth time or interval before repeating method 700c by returning to step 740. However, in an exemplary embodiment, the interval may be as small as 0 seconds or 0 meters, such that the method returns to step 740 substantially immediately after performing steps 784 or 786. Alternatively, method 700c may not require iteration, such that method 700c may end substantially after steps 784 or 786 have been completed.

In addition, each of the drilling intervals -AWOB, + AWOB, -ARPM and + AROM, can be substantially identical within one

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MEXICAN INSTITUTE OF Ι.Λ INDUSTRIAL PROPERTY

<img file="MX337489B_D0152.tif" />

single iteration of method 700c. Alternatively, one or more of the intervals ™ ^^ may vary in length or depth with respect to the other intervals. Similarly, the amount that the WOB decreases or increases in steps 742 and 754 may be substantially the same, or may vary from one another within a single iteration of method 700c. The amount that the RPM decreases or increases in steps 766 and 778 may be substantially the same, or may vary from one another within a single iteration of method 700c. WOB and RPM variations may also change or remain the same with respect to subsequent iterations of the method

700c.

Referring to Figure 8A, a schematic view of apparatus 800 is illustrated in accordance with one or more aspects of the present disclosure. Apparatus 800 may include or compose at least a portion of apparatus 100 shown in Figure 1, apparatus 300 shown in Figure 3, apparatus 400a shown in Figure 4A, apparatus 400b shown in Figure 4B, apparatus 400c shown in Figure 4C, and / or apparatus 690 shown in Figure 6B. Apparatus 800 represents an exemplary embodiment where one or more methods may be performed or practiced within the scope of the present disclosure, including method 200a shown in Figure 2A, method 200b shown in Figure

2B, method 500 of figure 5A, method 600a shown in figure 6A, method 600b shown in figure 6C, method 600c shown in figure

6D, method 700a shown in Figure 7A, method 700b shown in

114

<img file="MX337489B_D0153.tif" />

INSTITUTO MEXICANO DC LA

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<img file="MX337489B_D0154.tif" />

Figure 7B, and / or method 700c shown in Figure 7C.

Apparatus 800 includes a plurality of manual or automatic data inputs, collectively referred to herein as inputs 802. The apparatus also includes a plurality of controllers, calculators, detectors, and other processors, collectively referred to herein as processors 804. The data from the various inputs 802 is transmitted to several of the processors 804, as indicated in Figure 8A by arrow 803. Apparatus 800 also includes a plurality of sensors, encoders, actuators, controls, motors, and other detection, measurement, and actuation devices, collectively referred to herein as devices 808. Various data and signals, collectively referred to herein as data 806, are transmitted between several of the processors 804 and several of the devices 808, as indicated in Figure 8A with arrows 805.

Apparatus 800 may also include, be connected to, or otherwise be associated with, a display 810, which may be operated by, or otherwise receive data from, one or more of processors 804, or else from other components. of apparatus 800. Display 810 may also be referred to herein as a human-machine interface (HMI), although said HMI may further include one or more of inputs 802 or processors 804.

In the exemplary mode shown in Figure 8A, the inputs

802 include means to provide the following setpoints, limits,

115

IMPI

MEXICAN INSTITUTE · '. ηΓ&gt; Λ! Μεη »Λ

<img file="MX337489B_D0155.tif" />

scales, and other data:

• downhole pressure inlet, 802a;

• throttle position reference input ^ 802b;

• ΔΡ limit input, 802c;

• reference ΔΡ input, 802d;

• Winch draw limit input, 802e;

• MSE limit input, 802f;

• MSE target input, 802g;

• sludge flow setpoint input, 802h;

• pump pressure tare input, 802i;

• axis negative amplitude input, 802j;

• axis positive amplitude input, 802k;

• ROP setpoint input, 802I;

• pump inlet, 802m;

• tool face position input, 802n;

• higher command RPM input, 802o;

• upper drive torque limiting input,

802p;

• WOB reference input, 802q; and • WOB overhead input, 802r.

However, the 802 inputs may include means for providing setpoints, limits, scales, and other additional or alternative data, within the scope of the present disclosure.

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MEXICAN INSTITUTE

FROM THE PRO! '! AGE

INDUSTRIAL

<img file="MX337489B_D0156.tif" />

The downhole pressure input, 802a, can indicate the value of the desired maximum pressure of the gaseous medium and / or other medium at the bottom end of the hole. Alternatively, the downhole pressure input 802a may indicate a scale within which it is desired to maintain the downhole pressure. Such pressure can be expressed as an absolute pressure or a gauge pressure (for example with respect to atmospheric pressure or another predetermined pressure).

The throttle position reference input 802b can be a set point or value indicating the desired throttle position. Alternatively, the choke position reference input 802b may indicate a scale within which it is desired to maintain the position of the choke. The choke may be a device having a port or other means configured to control the speed and / or pressure of the fluid flow. The choke can be placed at the end of a choke line, which is a high pressure pipe that comes out of an outlet in the BOP riser, whereby fluid under pressure in the hole can flow out of the well to through the choke line to the choke, thereby reducing the fluid pressure (eg at atmospheric pressure). The choke position reference input 802b may be a binary indicator that expresses the choke position as "open" or "closed". Alternatively, the throttle position reference input 802b can be expressed as a percentage indicating the amount at which the throttle opens or partially closes.

117

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INSTITUTE ΜΕΧΙ 'Λ, ν' · DS INDUSTRIAL PROPERTY

<img file="MX337489B_D0157.tif" />

throttle. _ --The ΔΡ limit input, 802c, can be a value indicating the maximum or minimum pressure drop across the mud motor. Alternatively, the ΔΡ 802c limit input may indicate a scale within which it is desired to maintain the pressure drop across the mud motor. The 802d reference ΔΡ input can be a set point or value that indicates the desired pressure drop across the mud motor. In an exemplary embodiment, the ΔΡ 802c limit input is a value indicating the desired maximum pressure drop across the mud motor, and the reference 802d ΔΡ input is a value indicating the desired nominal pressure drop to through the mud motor.

The winch draw limit input, 802e, can be a value that indicates the maximum force to be applied to the winch via the drill wire (for example when holding the drill string out of the bottom or pulling the equipment stuck in the hole). For example, the 802e winch draw limit input may indicate the maximum hook load that must be supported by the winch during operation. The 812 winch draw limit input can be expressed as the maximum weight or tension of drill cable that can be supported by the winch without damaging the winch, drill cable, or other equipment.

The MSE limit input, 802f, can be a value that indicates the desired maximum or minimum MSE during drilling. Alternatively, «&lt;

I] \ ΐ ΡI

118

Mexican INSTITUTE and

FROM OWN OWN V * &lt;sxAW

INDUSTRIAL the MSE 802f limit entry may be a scale within which you wish to maintain the MSE during drilling. As discussed above, the actual value of the MSE depends at least partially on the WOB, bit diameter, bit speed, drill string torque, and ROP, each of which can be adjusted from in accordance with the aspects of the present description to maintain the desired MSE. The target MSE input, 802g, can be a value indicating the desired MSE, or a scale within which you want to maintain the MSE during drilling. In an exemplary embodiment, the 802f MSE limit input is a value or scale indicating the maximum and / or minimum MSE, and the 802g target MSE input is a value indicating the desired nominal MSE.

The mud flow setpoint input, 802h, can be a value that indicates the desired maximum, minimum, or nominal mud flow rate produced by the mud pump. Alternatively, the mud flow set point input 802h may be a scale within which it is desired to maintain the mud flow rate. The pumping pressure tare input, 802i, may be a value that indicates the current, desired, initial, inspected pumping pressure tare, or other mud pumping pressure tare. The mud pumping pressure tare generally estimates the difference between the mud pressure and the pressure in the casing or hole when the drill string is out of the bottom.

The axis negative amplitude input, 802j, can be a value

119

<img file="MX337489B_D0158.tif" />

MEXICAN INSTITUTE D £ LA PRCHLPAD

INDUSTRIAL

<img file="MX337489B_D0159.tif" />

indicating the desired maximum axis rotation from the axis oscillation neutral point in a first angular direction, while the axis positive amplitude input, 802k, may be a value indicating the desired maximum axis rotation from the neutral point of axis oscillation in an opposite angular direction. For example, during operation of the upper drive mechanism to oscillate the axis, the axis negative amplitude input 802j may indicate the maximum desired rotation of the axis in a clockwise direction beyond the neutral point of oscillation, and the 802k positive axis amplitude input can indicate the maximum desired axis counterclockwise ratio after the neutral point of oscillation.

The ROP setpoint input, 802I, can be a value that indicates the desired maximum, minimum, or nominal ROP. Alternatively, the ROP 802I setpoint input may be a scale within which you want to maintain the ROP.

The pump input, 802m, can be a value that indicates a flow rate, power, speed (for example strokes per minute) and / or another operating parameter related to the operation of the mud pump, which is maximum, minimum or desired nominal. For example, the mud pump may actually include more than one pump, and the 802m pump inlet may indicate an aggregate pressure, flow rate, or other desired maximum or nominal parameter of the output of the multiple mud pumps, or whether a pump system is operating a set with multiple pumps

120

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The tool face position input, 802n, can be a value that indicates the desired orientation of the tool face. Alternatively, the 802n tool face position input can be a scale within which you want to keep the tool face.

The 802n tool face position input can be expressed as one or more angles to a fixed or predetermined reference. For example, the 802n tool face position input can represent the desired azimuth orientation of the tool face with respect to True North and / or the desired inclination of the tool face with respect to vertical. As discussed above, in some modalities this is direct entry, or may be based on a planned drill path. While drilling using the method of Figure 5A, the orientation of the tool face can be calculated based on other data, such as inspection data or trend data, and the amount of deviation from a planned drill path. This can be a value considered to guide the BHA along a modified drill route .

The upper drive RPM input, 802o, can be a value indicating a desired maximum, minimum, or nominal rotational speed of the upper drive. Alternatively, the 802o upper drive RPM input can be a scale within which you want to maintain the rotational speed of the upper drive. The

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upper drive torque limit input, 802p, may be a value indicating a maximum torque to be applied by the upper drive.

The reference WOB input, 802q, may be a value indicating a desired maximum, minimum, or nominal WOB resulting from the weight of the drill string acting on the drill bit, although perhaps also taking into account other forces affecting the WOB, such as friction between the drill string and the hole. Alternatively, the 802q reference WOB input can be a scale at which you want to keep the WOB. The WOB tare input, 802r, can be a value indicating the current, desired, initial, inspection, or other WOB tare, which takes into account the hook load and weight of the drill string when it is outside the background.

One or more of the 802 inputs may include a keyboard, voice recognition apparatus, dial, joystick, mouse, database, and / or other conventional or future developed data input device. One of the 802 inputs can support data inputs from local and / or remote sites. One or more of the inputs 802 may include means for user selection of predetermined setpoints, values ​​or scales, for example by means of one or more pull-down menus.

One or more of the 802 entries, also or alternatively, may be configured to allow automatic entry of one of the more than 804 processors, such as by executing one or more database search procedures. One or

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802, possibly in conjunction with other components of apparatus 800, can support the operation and / or monitoring of stations at the equipment site and also one or more remote sites. Each of the 802 inputs may have individual means for input, although two or more of the 802 inputs may collectively have a single means for input. One or more of the 802 inputs can be configured to allow human input, although one or more of the 802 inputs can alternatively be configured for automatic data entry from a computer, software, module, routine, database search , algorithm, calculation, and / or otherwise. One or more of the 802 inputs can be configured for such automatic data input, but with an overlay function whereby a human operator can automatically approve or adjust the provided data.

In the exemplary embodiment shown in Figure 8A, devices 808 include:

• a block position sensor, 808a;

a casing pressure sensor, 808b;

a choke position sensor, 808c;

a deadline anchor load sensor, 808d;

a gravity MWD tool face sensor, 808g;

a winch encoder, 808e;

a mud pressure sensor, 808f;

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• a magnetic MWD tool face sensor, 808h;

• a return line flow sensor, 808i;

• a return line mud weight sensor, 808j;

• a top knob encoder, 808k;

• a top drive torque sensor, 808I;

• a choke actuator, 808m;

• a winch drive mechanism, 808n;

• winch motor, 808o;

• a mud pump drive mechanism, 808p;

• a superior control mechanism, 808q; and • a top drive motor, 808r;

However, devices 808 may include additional or alternative devices within the scope of the present description. Devices 808 are configured for operation in conjunction with the corresponding ones of a winch, a choke, a mud pump, a top drive, a block, a drill string, and / or other equipment components. Alternatively, 808 devices also include one or more of these kit components.

The block position sensor, 808a, may be or include an optical sensor, a radio frequency sensor, an optical encoder or other encoder, or other type of sensor configured to detect the relative or absolute vertical position of the block. Block position sensor 808a can be coupled with, or be integral with, the block, the crown, the winch, and / or other

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MEXICAN INSTITUTE OF INDUSTRIAL PROPERTY

124 appliance component 800 or equipment.

The casing pipe pressure sensor, 808b, is configured to detect the pressure in the ring defined between the drill string and casing or hole, and may be or include one more transducers, strain gauges, and / or other devices to detect pressure changes or otherwise detect pressure. The casing pressure sensor 808b can be attached to the casing, drill string and / or other component of the apparatus 800 or equipment, and can be placed on, or near, the surface of the hole, slightly down from the surface, or significantly further into the hole.

The choke position sensor, 808c, is configured to detect whether the choke opens or closes, and further can be configured to detect the degree to which the choke opens or partially closes. Choke position sensor 808c may be coupled to, or integral with, the choke, choke actuator, and / or other component of apparatus 800 or equipment. The choke, alternatively, can maintain a set pressure or stable mass flow, for example based on a casing pressure. This can be measured with an optional 808s mass flow meter.

The dead line anchor load sensor, 808d, is configured to detect tension in the drill cable at or near the anchored end. May include one or more transducers, flow meters

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deformation and / or other sensors coupled with the dowperfpra'düll cable.

The winch encoder, 808e, is configured to detect the rotational position of the winch reels around which the drill wire is wound. It may include one or more optical encoders, interferometers, and / or other sensors configured to detect the angular position of the reel and / or any change in the angular position of the reel. The 808e winch encoder may include one or more components coupled or integral with the reel and / or a stationary portion of the winch.

The mud pressure sensor, 808f, is configured to detect the outlet pressure of the mud motor hydraulic fluid, and can be or include one or more transducers, strain gauges, and / or other devices to detect fluid pressure . It may be coupled to or integral with the mud pump, and therefore may be positioned at, or near, the surface opening of the hole.

The MWD Gravity Tool Face Sensor, 808g, is configured to detect the orientation of the tool face based on gravity. The MWD Magnetic Tool Face Sensor, 808h, is configured to detect the orientation of the tool face based on the magnetic field. These 808g and 808h sensors can be attached or integral to the MWD assembly, and therefore can be placed at the bottom of the well.

The return line flow sensor, 808i, is configured to

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detect the mud flow velocity within the return line, and can be expressed in liters / minute. The return line sludge weight sensor, 808j, is configured to detect the weight of sludge flowing into the return line. These 808i and 808j sensors can be coupled with the return flow line, and thus can be placed in, or near, the hole surface opening.

The top drive encoder, 808k, is configured to detect the rotational position of the shaft. It may include one more optical encoders, interferometers, and / or other sensors configured to detect the angular position of the axis and / or any change in the angular position of the axis, with respect to the upper knob, True North, or some other reference point. permanent. The upper drive torque sensor, 808I, is configured to detect the torque applied by the upper drive mechanism, or the torque required to rotate the drill string or shaft at current speed. These 808k and 808Ι sensors can be coupled or integral with the upper drive mechanism.

The choke actuator, 808m, is configured to drive the choke to configure the choke in an open configuration, a closed configuration, and / or one or more positions between fully open and fully closed. It can be hydraulic, pneumatic, mechanical, electrical, or combinations thereof.

The 808n winch drive is configured to provide an electrical signal to the 808o winch motor for its

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drive. The 808o winch motor is configuredTpáiá yirai tH— · reel around which the drill cable is wound, pulling the drill cable in or out.

The mud pump drive mechanism, 808p, is configured to provide an electrical signal to the mud pump, thereby controlling the flow rate and / or pressure of the mud pump outlet. The upper drive mechanism, 808q, is configured to provide an electrical signal to the upper drive motor, 808r, for actuation. The upper drive motor 808r is configured to rotate the shaft, thereby rotating the drill string coupled to the shaft.

In the exemplary embodiment shown in FIG. 8A, data 806 that is transmitted between devices 808 and processors 804 includes:

• block position, 806a;

Liner pipe pressure, 806b;

• 806c choke position;

• hook load, 806d;

• mud pressure, 806e;

• blow / phase of mud pump, 806f;

· Mud weight, 806g;

• axis position, 806h;

• return flow, 806i;

• tool face, 806j;

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• upper drive torque, 806k: ____ • choke drive signal 806I;

• winch drive signal, 806m;

• mud pump drive signal, 806n;

· Upper command actuation signal, 806o; and • upper drive torque limit signal,

806p.

However, the data 806 transferred between the devices 808 and the processors 804 may include additional or alternative data within the scope of the present disclosure.

In the exemplary embodiment shown in Figure 8A, the 804 processors include:

• a choke controller, 804a;

• a drum controller, 8Ó4b;

-a mud pump controller, 804c;

• an oscillation controller, 804d;

• an axis position controller, 804e;

• a tool face controller, 804f;

• a calculator for the exponent d, 804g;

· A corrected exponent d calculator, 804h;

• an MSE calculator, 804I;

a ROP calculator, 8041;

a true depth calculator, 804m;

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• a WOB calculator, 804n; --——---- • a slip / adhesion detector, 804o; and • an inspection log, 804p.

However, processors 804 may include alternative or additional controllers, calculators, detectors, data storage devices, and / or other processors within the scope of the present disclosure.

The choke controller, 804a, is configured to receive the downhole pressure setting value from the downhole pressure input, 802a, the casing pressure, 806b, from the casing pressure sensor. , 808b, the choke position 806c of the choke position sensor, 808c, and the mud weight 806g of the return line mud weight sensor, 808j. The 804a Choke Controller can also receive downhole pressure data from the 804k Pressure Calculator. Alternatively, the 804 processors may include a comparator, adder, or other device that performs an algorithm using the downhole pressure setpoint value received from the downhole pressure input 802a, and the actual downhole pressure of the current wellbore. received from the 804k pressure calculator; the result of said algorithm being provided to the choke controller 804a instead of, or in addition to, the downhole pressure setting value and / or the current downhole pressure. Choke control 804a is configured to process the received data and generate the

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Choke Actuator, 806I, which then is rated at Choke Actuator 808.

For example, if the current downhole pressure is greater than the downhole pressure setting value, then the choke actuator signal 8061 may command the choke actuator 808m to open more, thereby increasing the flow rate of return and reducing the current pressure at the bottom of the well. Similarly, if the current downhole pressure is less than the downhole pressure setting value, then the choke actuator signal 806I can command the choke actuator 808m to close more, thus reducing the return flow rate. and increasing the current downhole pressure. The actuation of the choke actuator 808m may be in increments, such that the choke actuation signal 806I repeatedly commands the choke actuator 808m to open or close further a predetermined amount, until the current downhole pressure satisfactorily meets the downhole pressure setting value. Alternatively, the choke actuator signal 806I can command the choke actuator 808m to open or close plus an amount proportional to the current discrepancy between the current downhole pressure and the downhole pressure setpoint.

The drum controller, 804b, is configured to receive the ROP set point from the ROP set point input, 802I, as well as the current ROP from the ROP 804I calculator. The controller

131 '^ tomexicano' / ** OE LA PKOPieda f&gt; l '· ^ industrial M drum 804b is also configured to receive WOB data from a comparator, adder or other device that performs an algorithm using the WOB reference point of the WOB 802g reference input and current WOB from the WOB 804n calculator. These WOB data can be modified based on current MSE data. Alternatively, the drum controller 804b is configured to directly receive the WOB reference point from the WOB reference input, 802g, and the current WOB from the WOB calculator, 804n, and then perform the WOB comparison or add the algorithm itself. Drum controller

804b is also configured to receive ΔΡ data from a comparator, adder, or other device that performs an algorithm using the reference ΔΡ received from the reference input of ΔΡ, 802d, and a current ΔΡ received from the configured 804 processors. to determine the current ΔΡ. The current ΔΡ can be corrected to take into account the pressure of the casing, 806b.

The drum controller 804b is configured to process the received data and generate the winch drive signal, 806m, which is then transmitted to the winch command 808m. For example, if the current WOB received from the WOB 804n calculator is less than the WOB reference point received from the WOB 802q reference input, then the winch drive signal 806m may command the 808n winch drive. have the 808o winch motor pull out more drill wire. If the current WOB is less than the

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WOB reference MEXICAN INSTITUTE OF INDUSTRIAL PROPERTY, then the 806m_ winch drive signal can command the 808n winch drive to drive the 808o winch motor to feed the drill wire.

If the current ROP received from the ROP 804I calculator is less than the ROP set point received from the ROP set point input, 802I, then the 806m winch drive signal can command the 808n winch drive. have the 808o winch motor pull out more drill wire. If the current ROP is greater than the ROP set point, then the 806m winch drive signal may command the 808n winch drive to cause the 808th winch motor to feed the drill wire.

If the current ΔΡ is less than the reference ΔΡ received from the reference ΔΡ input, 802d, then the 806m winch drive signal may command the 808n winch drive to pull the 808o winch motor out more drilling. If the current ΔΡ is greater than the reference ΔΡ, then the 806m winch drive signal may command the 808n winch drive to cause the 808o winch motor to feed the drill wire.

The mud pump controller, 804c, is configured to receive the stroke / phase data, 806f, from the mud pump; mud pressure

806e of mud pressure sensor, 808f; the current ΔΡ; the current MSE from the 804i MSE calculator; the current ROP of the ROP 804I calculator; a

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133 adherence / slip indicator adherence / slip, 804o; the mud flow rate set point of the mud flow set point input 802h; and the pump data from the 802m pump input. The mud pump controller,

804c then uses this data to generate the mud pump drive signal 806n, which is then transmitted to the mud pump 808p.

The oscillation controller, 804d, is configured to receive the current axis position, 806h; the current torque 806k of the upper control; the Adhesion / Slip Indicator of the 804o Adhesion / Slip Detector; the current ROP of the ROP 804I calculator; and the axis oscillation amplitude limits of the 802j and 802k inputs. The oscillation controller 804d uses this data to generate an input for the axis position controller, 804e, for use in generating the drive signal 806o from the upper drive. For example, if the adherence / slip indicator of the adherence / slip detector 804o indicates that adherence / slip is occurring, then the signal generated by the oscillation controller 804d will indicate that it is required to start oscillation or increase its amplitude.

The axis position controller, 804e, is configured to receive the signal from the oscillation controller 804d; the setting value of the

Input upper RPM 802o of upper control RPM; a signal from the 804f tool face controller; the current WOB of the

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WOB 804n calculator; and the current tool face. 8Q6j of at least one of the MWD, 808g and 808h tool face sensors. The shaft position controller 804e can also be configured to receive the upper drive torque limit setting value from the upper drive torque limit input 802p, although this setting value can be accommodated by by means of a comparator, adder or other device, to calculate the current MSE, where the current MSE is received from the MSE 804i calculator. The shaft position controller 804e can also be configured to receive a grip / slip indicator from the grip / slip detector 804o. The axis position controller 804e then uses this data to generate the top command drive signal 806o.

For example, the top drive signal 806o causes the top drive 804q to cause the top drive motor 808r to rotate the shaft at the speed indicated by the top drive RPM input 802o. However, this can only happen when other inputs do not overlap this target. For example, if so commanded by the oscillation controller signal 804d, the upper drive signal 806o will also cause the upper drive 808q to cause the upper drive motor 808r to rotationally oscillate the shaft. Additionally, the signal from the 804d tool face controller may overlap or otherwise affect the upper command 806 drive signal to rotationally orient the axis.

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in a certain static position or set a neutral point for oscillation.

The tool face controller 804f is configured to receive the tool face position setpoint from the 802n position input of the tool face, and also the current tool face 806j from at least one of the 808g and 808h MWD tool face. The 804f tool face controller can also be configured to receive ΔΡ data. The tool face controller 804f then uses this data to generate a signal that is provided to the axis position controller, 804e.

The exponent calculator d, 804g, is configured to receive the current ROP from the ROP calculator 804I; the current ΔΡ and / or other pressure data; auger diameter; the current WOB from the WOB 804n calculator; and the current mud weight 806g from the return line mud weight 808j sensor. The d 804g exponent calculator then uses this data to calculate the exponent d, which is a factor in evaluating ROP and detecting or predicting abnormal pore pressure zones. Assuming all other parameters are constant, the exponent d should increase with depth when drilling at a normal pressure section, while an inverse of this trend is an indication of drilling at potential overpressures. The signal from the exponent calculator d 804g is optionally provided to the display 810, as well as to the tool face calculating machine 404. Consequently, the steering module 420 may stop drilling or adjusting the planned route by treating a

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area, which causes increases in the value of the expoñeñté d 804g calculator, as a deviation from the planned route outside the tolerance zone. Advantageously, this can automatically command the main controller to drill in a different direction and avoid drilling in the potential overpressure area. The d exponent calculator is simply another suitable method, or algorithm, for analyzing ROP, and it is another calculation that can be performed in a similar way to MSE.

The corrected d exponent calculator, 804h, can be configured to receive substantially the same data as received by the d exponent calculator 804g. Alternatively, the corrected d exponent calculator 804h is configured to receive the current d exponent calculated by the d exponent calculator 804. The corrected d exponent calculator 804h then uses this data to calculate the corrected d exponent, which corrects the value of the exponent d for the mud weight, and which can be directly related to the formation pressure rather than the differential pressure. The signal from the exponent calculator d 804g is provided for example to display 810.

The MSE calculator, 804¡, is configured to receive current RPM data from the 802o RPM input on the upper control; the upper drive torque 806k of the upper drive torque sensor 8081; and the current WOB from the WOB 804n calculator. The MSE 804i calculator then uses this data to calculate the current MSE, which is then transmitted to the drum controller 804b, the

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INSTITUTO MEXICANO DS LA PROPIEDAD INDUSTRIAL shaft position controller 804e, and the sludge pump controller 801c. The MSE 804i calculator can also be configured to receive the MSE limit setting value from the MSE limit input 802f, in which case the MSE 804i calculator can also be configured to compare the

Current MSE with the MSE limit setting value, and trigger an alert if the current MSE exceeds the MSE limit setting value. The MSE 804i calculator can also be configured to receive the MSE target adjustment value from the MSE target input 802g, in which case the MSE 804i calculator can also be configured to generate a signal indicating the difference between the Current MSE and the goal of MSE. This signal can be used by one or more of the 804 processors to correct and adjust various data values ​​used by them, such as the adjustment to the current or reference WOB used by the drum controller 804b, and / or the value of upper drive torque limit setting, used by the 804e axis position controller, as described above.

The pressure calculator, 804k, is configured to receive the liner pipe pressure, 806b, from the liner pipe pressure sensor 808b; the mud pressure 806e of the mud pressure sensor 808f; the mud weight 806g of the return line mud weight sensor 808j; and the true vertical depth of the 804m true depth calculator. The 804k pressure calculator then uses this data to calculate the current downhole pressure, which is then transmitted to the choke controller 804a. However, before being sent to

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Choke controller 804a, the current pressure of the 'puzu ye fOTTCfü can compare with the downhole pressure setting value, received from downhole pressure input 802a, in which case the 804a choke controller can use only the difference between the current downhole pressure and the downhole pressure setting value when the choke drive signal 806I is generated. This comparison between the current downhole pressure and the downhole pressure setting value can be made by the pressure calculator 804, the choke controller 804a, or another of the 804 processors.

The ROP calculator, 804I, is configured to receive block position 806a from block position 808a, and then use this data to calculate the current ROP. The current ROP is then transmitted to the true depth calculator, 804I, the drum controller 804b, the mud pump controller 804c, and the oscillation controller 804d.

The true depth calculator, 804m, is configured to receive the current 806j tool face from at least one of the MWD 808g and 808h tool face sensors, the 804p inspection log, and the current measured depth that is calculated from the current ROP received from the ROP 804I calculator. The 804m true depth calculator then uses this data to calculate the true vertical depth, which is then transmitted to the pressure calculator.

804k.

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The WOB calculator, 804n, is configured to receive the slip / adherence indicator from the slip / adherence detector 804o, and also the current hook load 806d from the deadline anchor load sensor 808d. The WOB 804n calculator can also be configured to receive a string weight tare out of the bottom, which can be the difference between the received WOB tare from the WOB 802r tare input, and the current 806d hook load received of the dead line anchor load sensor 808d. In either case, the WOB 804n calculator is configured to calculate the current WOB based on the current hook load, the current string weight, and the grip / slip indicator. The current WOB is then transmitted to the axis position controller 804e, the d exponent calculator 804g, the corrected d exponent calculator 804h, the MSE calculator 804i, and the drum controller 804b.

The 804o slip / adhesion detector is configured to receive the current torque 806k from the top drive, and use that data to generate the adhesion / slip indicator, which is then provided to the 804c mud pump controller, the oscillation controller 804d, and the axis position controller 804e. The 804o Adhesion / Slip Detector measures changes in the 806k upper drive torque with respect to time, indicating whether the bit may exhibit grip / slip behavior, indicating that the upper drive torque and / or WOB must be reduced, or the

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Processors 804 can be collectively realized as a single processor device, or as a plurality of processor devices. Each 804 processor may Include one or more software or other program product modules, submodules, routines, subroutines, state machines, algorithms. Each processor 804 may additionally include one or more computer memories or other means for storing digital data. The aspects of one or more of the 804 processors may be substantially similar to those described herein with respect to any controller or other data processing apparatus. Accordingly, processors 804 may include, or be comprised of, at least a portion of controller 190 of FIG. 1, controller 325 of FIG. 3, controller 420 of FIGS. 4A-4C, and controller 698 of Figure 6B, for example.

Figure 8B illustrates a system control module, 812, in accordance with one more aspect of the present disclosure. The system control module 812 is a possible embodiment of the apparatus 800 shown in Figure 8A, and can be used in conjunction with, or made within, the apparatus 100 shown in Figure 1, and any of the apparatus 300, 400a ,

400b, 400c, and 790, shown respectively in Figures 3, 4A-4C, and 7B.

The 812 system control module can also be used to perform one or more aspects of the methods shown in any of the figures.

2A, 2B, 5A, 6A, 6C, 7A, 7B and 7C.

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The 812 system control module includes-an 814 HMI module, an 816 data transmission module, and a drilling master control module, 818. The 814 HMI module includes a manual data entry module, 814a, and a display module 814b. The 818 Drill Master Control Module includes a Detected Data Module,

818a; a control signal transmission module, 818b; a BHA control module, 818c; a winch control module, 420b; a top command control module, 420a; a mud pump control module, 420f; an ROP optimization module, 818g; an auger duration optimization module, 818h; an optimization module based on MSE, 818i; an optimization module based on the exponent d, 818j; an optimization module based on the corrected d exponent, 818k; and a BHA optimization module, 818m.

The 814a manual data entry module is configured to facilitate user input of various set points, operating scales, formation conditions, equipment parameters, and / or other data including a drilling plan or data to determine a drilling plan. For example, the manual data input module 814a may allow the 802 inputs shown in Figure 8A, among others. Such data may be received by the manual data input module 814a by means of the data transmission module 816, which may include or support one or more connectors, ports and / or other means for receiving data from various data input devices. . The 814b display module is

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configured to provide an indication that user 4te-4atcodLi £ successfully completed some or all of the inputs provided by the manual data entry module 814a. Such an indication may include a visual indication of some kind, for example by means of text display or

Graphic icons or other information, the illumination of one or more lights or LEDs, or the color change of a light, LDE, graphic icon or symbol, among others.

Drill master control module 818 is configured to receive user data input from HMI module 814, which in some modes communicates via data transmission module 816 as in the exemplary mode depicted in FIG. 8B .

Detected data module 818a of drilling master module 818 also receives perceived or detected data from various sensors, detectors, encoders, and other such devices associated with the various accessories and components of the equipment. Examples of such information detection and acquisition devices include devices 430 of Figure 4A and 806 of Figure 8A, among other figures included herein. This detected data can also be received by the detected data module 818a through the data transmission module 816.

The control signal transmission module 718b interacts between the control modules of the 818 drilling master control module and the actual working system. For example, it sends and receives control signals to

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INSUSTÉIAL winch 130, upper drive 140, mud pump 180, and in some embodiments BHA 170 in Figure 1. The BHA 718c control module can be used when the BHA is configured to be bottom controlled from the well.

The winch control module, 420b, the upper command control module, 420a, and the mud pump control module, 420f, are used to generate control signals sent through the control signal transmission module, 718b, to the winch, the upper control and the mud pump. These may correspond to the drivers shown in Figure 4C.

In some embodiments, the 818 Drill Master Control Module may not include all of the 818g-m optimization modules shown, and each of the optimization modules may be purchased separately by the user. Therefore, some modes may include only one of the optimization modules, while other modes include more than one of the optimization modules. In this way, the drilling master control module 818 can be configured so that the available modules cooperate to arrive at optimization values ​​considering all available optimization modules in the drilling master control module. This is discussed further below with reference to Figure 8C.

Still referring to FIG. 8B, the ROP optimization module, 818g, determines methods or adjustments to processes that improve the ROP of the BHA. ROP 818g optimization module receives

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INDUSTRIAL module data detected data 430 and also other data, including data related to tool face orientation, among others, to determine the most effective way to maximize ROP. After considering these and / or other factors, the ROP 818g optimization module communicates with the 818c, 420a, 420b, and 420f control modules so that the control modules can determine if direction changes would optimize the ROP of a way that maximizes productivity and efficiency.

The auger duration optimization module, 818h, can consider data received from the detected data module 430 and also tool face orientation data, including azimuth, tool face tilt orientation data, time occupied in the drilling, to determine the most efficient way to conserve the bit without compromising efficiency and productivity. After considering these or other factors, the auger duration optimization module communicates with the 818c, 420a, 420b, and 420f control modules so that the control modules can determine if direction changes would preserve the duration of the Auger in a way that maximizes productivity and efficiency.

The MSE-based optimization module, 818i, performs the MSE-based optimization processes outlined above with reference to Figures 6A, 6C, and 6D. The optimization module outputs

818i can communicate with 818c, 420a, 420b and 420f control modules

145 to actually implement the changes that result in efficiency.

The d exponent-based optimization module, 818j, can include the d 804g exponent calculator to determine the exponent d and evaluate the ROP while detecting or predicting abnormal pore pressure zones. Therefore, since exponent module d detects the variation in normal pressure, exponent module d can communicate with control modules 818c, 420a, 420b, and 420f to consider making any direction changes necessary for efficient drilling and effective.

The corrected d exponent based optimization module, 818k, may include the corrected d exponent calculator, 804h. Using the data received, the optimization module 818k corrects the value of the exponent d for the mud weight that can be directly related to the formation pressure instead of the differential pressure. This corrected value can also be communicated to the 818c, 420a, 420b, and 420f control modules to consider making any direction changes necessary for efficient and effective drilling.

The BHA optimization module, 818m, may consider data received from the detected data module 430, data input into the manual data input module 714a, and other obtainable data to determine the optimization profiles for the BHA. In some embodiments, the BHA 818m Optimization Module processes the information received from other modules in the 718 Drill Master Control Module. Using

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With this information, the BHA 818m Optimization Module sends data to Jos, 818c, 420a, 420b, and 420f control modules to consider making any address changes to the BHA necessary to optimize the BHA.

As the winch control module 420b, the top drive control module 420a, and the mud pump control module 420f receive information from the optimization modules, they process the data to determine if the iteration of the Recommended changes would positively or negatively affect the overall productivity of the well system, and generate control signals that instruct winch 130, the upper drive mechanism 140 and the slurry pump 180 of FIG. 1 so that they make changes more efficiently.

Figure 8C shows an exemplary method 830 performed by the drilling master control module 818 to optimize the overall drilling operation of the drill rig. As discussed above, some embodiments of the 818 Drill Master Control Module do not include all of the optimization modules shown in Figure 8B. Accordingly, method 830 considers circumstances where the drilling master control module includes one, more than one, or not all of the optimization modules shown. It is contemplated that these modules are exemplary and that other optimization modules may be included.

Method 830 includes steps that appear in parallel, and are not necessarily serial. In some embodiments, these parallel method paths are alternative paths and can be

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<img file="MX337489B_D0190.tif" />

performed based on the module configuration gives maootro control of drilling and / or the availability of optimization modules. For example, from step 832, method 830 continues to steps 834, 840, 846, 852, and 858. Each of these is discussed below.

Referring to FIG. 8C, in one step 832 the drilling master control module 718 receives manual inputs and / or detected data from the manual data input module 814a, and / or from the detected data module 430 (input data or detected not shown). In some cases, the 718 Drill Master Control Module can access stored trend data from previous inspections.

Using this Information and data, the optimization modules of the 818 drilling master control module calculate or process the data in another way, using algorithms to determine the optimization values ​​for any number of factors that alter the efficiency or productivity of the drilling, Including ROP. In some embodiments, the alternative paths in Figure 8C depend on the availability of the optimization modules. For example, from step 832, method 830 continues to step 834 if drilling master control module 818 includes only ROP optimization module 818g of the optimization modules. Alternatively, from step 832, method 830 continues to step 840 if drilling master control module 818 includes only one of the optimization modules based on MSE 8181, the exponent-based optimization module d 818j, the optimization module based in exponent

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INDUSTRIAL

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d corrected 818k, and the BHA optimization module 818m. Again, __ alternatively, from step 832, method 830 continues to step 846 if drilling master control module 818 includes more than one optimization module. Method 832 continues to step 852 if drilling master control module 818 includes ROP optimization module 818g and one of MSE-based optimization module 8181, exponent-based optimization module d 818j, optimization-based module in corrected d exponent 818k, and the BHA optimization module 818m. Method 832 continues to step 858 if Drill Master Control Module 818 includes ROP optimization module 818g, and more than one optimization module 818i, 818j, 818k, 8181, and 818m.

In alternative modalities, the drilling master control module 818 performs all of the method steps rather than treating them as alternative steps as described above. Accordingly, although the Drill Master Control Module includes a plurality of optimization modules, it still considers the ROP 818g optimization module independently in step 834, considers one of the other optimization modules independently in step 840, and so on. successively with steps 846, 852 and 858.

In circumstances where only the ROP 818g optimization module is included in the drilling master control module

818, or the 818 master control module is configured to consider only the ROP 818g optimization module, in step 834, the

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INDUSTRIAL ROP 818g optimization determines drilling parameter changes that optimize drilling operation based on ROP using manual inputs and / or detected data. These drilling parameter changes are communicated to the BHA 818c control module, the 420b winch control module, the 420a top drive control module, and / or the 420f mud pump control module. At step 836, these control modules modify one or more control signals sent to the BHA, winch, top drive, or mud pump, to change the drilling parameters needed to optimize the drilling operation based on the ROP. .

In circumstances where only one optimization module is included in the drilling master control module 818, or the master control module 818 is configured to consider only one optimization module, in step 840, using the optimization module based in MSE 818i, the 818j exponent-based optimization module, the 818k corrected d-exponent optimization module, and the BHA 818m optimization module, the drilling master control module 818 can calculate one of the optimization values ​​of MSE, exponent d, corrected exponent d and BHA, based on the data received from the detected data module and / or the manual data entry module 814a. Based on these data, in step 842, the drilling master control module 818 can determine the drilling parameter changes necessary to optimize the drilling operation based on one of

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INDUSTRIAL

<img file="MX337489B_D0193.tif" />

the calculated optimization values ​​of MSE, exponent d, exponent d corrected, and BHA. These drilling parameter changes are communicated to the BHA 818c control module, the 420b winch control module, the 420a top drive control module, and / or the 420f mud pump control module. At step 844, these control modules modify the control signals sent to the BHA, the winch, the top drive, or the mud pump, to change the operating parameters necessary to optimize the drilling operation based on the calculated value.

In circumstances where more than one optimization module is included in the drilling master control module, in step 846 using the optimization modules 818i, 818j, 818k, 8181 and 818m, the drilling master control module 818 calculates preferably more than one of the MSE optimization values ​​(typically at least two), exponent d, exponent d corrected and BHA, based on the data received from the detected data module and / or from the manual data entry module 814a. Based on these data, in step 848, the drilling master control module 818 can determine the drilling parameter changes necessary to optimize the drilling operation based on the plurality of calculated values. These drilling parameter changes are reported to the BHA 818c control module, the 420b winch control module, the 420a upper command control module, and / or the 420f mud pump control module; and in step 850, these modules

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<img file="MX337489B_D0194.tif" />

Control modify the control signals sent to the BHA, the winch, the upper knob, and / or the mud pump, to change the drilling parameters necessary to optimize the drilling operation based on the plurality of calculated values.

In circumstances where ROP 818g optimization module is included and only one other optimization module in drilling 818 master control module, or 818 master control module is configured to consider only ROP 818g optimization module and just another optimization module, in step 854 the drilling master control module 818 preferably determines the drilling parameter changes necessary to optimize the drilling operation based on the calculated value and the ROP optimization value. These values ​​are communicated to the control modules and in step 856 these control modules can modify the control signals sent to the BHA, the winch, the upper command, or the mud pump, to change the drilling parameters necessary to optimize the drilling operation based on the calculated value.

In the circumstances where the ROP optimization module and more than one additional optimization module is included in the drilling master control module, in step 858, using the optimization modules 818i, 818j, 818k, 8181 and 818m, Drill Master Control Module 818 calculates more than one of the optimization values ​​of MSE, exponent d, exponent d corrected, and BHA, based on the data

IMPI

INSTITUTE ΜΕΧιγλν.-,

MEXICAN INSTITUTE OF INDUSTRUU PROPERTY,

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152 received from the detected data module and / or the manual data input module 814a. Here, the drilling master control module 818 considers the ROP when determining the drilling parameter changes necessary to optimize the drilling operation. Accordingly, the drilling master control module 818 can consider the plurality of calculated values ​​of the optimization modules, including the ROP, to determine the optimized drilling parameter changes. These drilling parameter changes are communicated to the 818c, 420b, 420a, and / or 420f control modules, and in step 862 these control modules modify the control signals sent to the BHA, the winch, the upper command, and / or or the mud pump, to change the drilling parameters necessary to optimize the drilling operation based on the plurality of calculated values.

Regardless of which path is used, after the modified control signals are sent from the drilling master control module, preferably in step 838 the display module 814b updates the optional but preferred HMI display to reflect these control signals. changed new. The HMI display is discussed and incorporated later.

In some cases, the drilling master control module

818 performs some or all of steps 834, 840, 846, 852, and 858 at the same time, or in succession fast enough to appear simultaneously, and the control signals are modified based on

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INSTITUTO MEXICANO DS LA PROPIEDAD INDUSTRIAL multiple system entries.

Figures 9A and 9B show flow charts detailing directional drilling precision optimization methods during drilling operations performed by the apparatus 100 of Figure 1. Any of the control systems described herein, including those from the Figures 1, 3, 4A-4C, 6B, 8A and 8B can be used to execute the methods of Figures 9A and 9B. The real-time data obtained from these methods can be configured as inputs in Figure 4A to optimize drilling operations and calculate the bit position, to identify and correct any drift deviation from the planned drilling route during operations drilling.

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Referring first to FIG. 9A, a flow chart of a method 900 is illustrated in accordance with one or more aspects of the present disclosure. Method 900 can be performed in association with one or more components of apparatus 100 shown in Figure 1 during operation of apparatus 100. For example, method 900 can be performed to optimize directional drilling precision during drilling operations performed. by means of apparatus 100._t

Method 900 includes a step 910 during which real time data of tool face, hole depth, tube rotation, hook load, pressure delta, and / or other data is received by a controller or other processing (for example, any of the 190, 325, 420, 402, 698, 804, 812 controllers, or others exposed in the

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INDUSTRIAL present). Data can be obtained from various equipment instruments and / or sensors configured for said measurement (such as the sensors shown in Figures 1, 4A, 8A, and others). Step 910 may also include receiving modeled dog paw data and / or other well plan data, taken from inspections or otherwise obtained. In a subsequent step 920, the real-time and / or modeled data received during step 910 is used to calculate a real-time inspection projection ahead of the most recent standard Inspection result. Optionally, the real-time inspection projection calculated during step 920, can be temporarily used as the next standard Inspection point during a subsequent step 930. Method 900 may also include a step 940 after step 920 and / or step 930, during which the calculated real-time inspection projection during step 920 is compared to the well plan at the corresponding hole depth. A step 950 may follow step 930 and / or step 940, during which the directional driller is given the real-time inspection projection calculated during step 920, and / or the results of the comparison performed during step 940. Consequently, the directional driller can more accurately assess the progress of the current drilling operation in the absence of any direct measurement of inclination and azimuth in hole depth.

In an exemplary embodiment within the scope of the present disclosure, method 900 is then repeated, such that the method

155 it flows back to step 910 and starts again. The iteraciorTCtef-method. 900 can be used to characterize the performance of the downhole assembly. In addition, iteration can allow the calculation model of the real-time inspection projection to refine itself each time an inspection is received. The use of method 900 in at least some embodiments can assist the directional driller in the drilling operation by applying offset and twist increase rates to the sections and slip projections through rotationally drilled sections.

As described above, the conventional approach encompasses performing a standard inspection on each drill pipe connection to obtain an inclination and azimuth measurement for the new inspection position. In this way, the prior art makes measurements after the hole is drilled. In contrast, with method 900 and others within the scope of the present disclosure, real-time measurements are made ahead of the last standard inspection, and can give the directional driller feedback on the progress and efficiency of a sliding or rotating procedure.

Referring to Fig. 9B, a flow chart of a simplified version of method 900 shown in Fig. 9A is illustrated, designated herein with reference number 900a. Method 900a includes a step 910 during which tool face and hole depth measurements are received from the equipment instruments. Step 910 also

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INDUSTRIAL may include receiving model or well plan data that corresponds to the real-time data received from the equipment instruments. Such reception of the real-time and / or model data may be at one or more controllers, processor devices, and / or other devices, such as controller 190 shown in Figure 1.

In a subsequent step 960, these measurements are used with modeled or calculated data from previous inspections (for example, including proportions of increased deviation, dog paws, etc.), to track the progress of the hole by calculating a real-time inspection projection. and comparing the projection with the well plan. Steps 910 and 960 are then repeated, perhaps at speeds or intervals that produce greater granularity. Step 960 may also include averaging the received data through depth intervals (eg, averaging the most recently received data with previously received data). Consequently, the data received during step 910 and processed during step 960 can provide accurate resolution, perhaps on a meter-by-meter basis, during a slide operation, and can show what a particular drilling operation will be like or how it is being affected by the precision in which a particular tool face is maintained.

A high resolution view of the current hole against the downhole plan is often key to tracking the efficiency of a slide operation. For example, within the span of a single joint, it may be

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<img file="MX337489B_D0197.tif" />

required (for example, by the well plan) for a .driller :, direction to perform a 6.1 meter slide, 15.2 meter rotary drilling, and then another 6.1 meter slide. Conventionally, the perforator would not know the efficiency of this section until it receives its next inspection, which is performed after attempting the slip-rotate-slip procedure. However, in accordance with one or more aspects of the present disclosure, the driller can calculate the utilization of real-time inspection projections throughout the slip-rotate-slip procedure to show the projected well path of the bit. In this way, the accuracy with which the slip-rotate-slide procedure can be performed can be greatly increased, and when used to perform the method of Figure 5A, it provides more precise directional correction than conventional systems. In addition, the Θ00 and 900a methods may include updating the deviation and model increase ratios at each real-time inspection, thereby increasing the accuracy of each subsequent inspection, inspection projection, and / or drilling stage.

Figures 10A and 10B are exemplary illustrations of user displays that convey information about the location of the bit to a user. The display of the figures can be any display shown herein, including displays 335, 472, 692c and 810. Returning to Fig. 10A, a schematic view of a human-machine interface (HMI) 1000 is illustrated in accordance

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IMPI »

MEXICAN INSTITUTE

OF THE PROPERTY QlSieáí '

INDUSTRIAL with one or more aspects of the present description. The HMI 100 can be used by a human operator during directional drilling and / or other drilling operations to monitor the relationship between the orientation of the tool face and the position of the shaft. In an exemplary embodiment, the ia HMI 1000 is one of several user-selectable display screens during drilling operations, and can be included as, or within, human-machine interfaces, drilling operations, and / or drilling apparatus described in the systems herein and the systems incorporated by reference. The HMI 100 can also be performed as a series of instructions recorded on a computer-readable medium, as described in one or more of these references.

The HMI 100 is used by the directional driller while drilling to monitor the BHA in three-dimensional space. The computer or control system that manages one or more of other human-machine interfaces during the drilling operation can be configured to also deploy the HMI 1000. Alternatively, the HMI 1000 can be managed or displayed by means of a separate computer or control system, and can be displayed on a different computer display (monitor) than where the remaining drilling operation screens are displayed.

The control or computer system that operates the HMI 1000 includes an "inspection" channel or other data channel, or otherwise includes means for receiving and / or reading sensor data transmitted from the BHA, a

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INDUSTRIAL drilling measurement assembly (MWD), and / or other means of measuring drilling parameters, where such transmission may be by means of the information transfer standard Wellsite Information Transfer Standard (WITS), WITS Markup Language (WITSML) ), and / or other data transfer protocol. Such electronic data may include gravity based tool face orientation data, magnetism based tool face orientation data, azimuth tool face orientation data, and / or tilt tool face orientation data, among others. In an exemplary embodiment, the electronic data includes magnetism-based tool face orientation data when the tool face orientation is less than about 7 ° from the vertical, and alternatively includes tool face orientation data. based on gravity when the orientation of the tool face is greater than approximately 7 ° from the vertical. In other embodiments, however, the electronic data may include tool face orientation data based on both gravity and magnetism. The azimuth tool face orientation data may refer to the azimuth direction of the remote end of the drill string relative to true north, high side of the hole, and / or other predetermined orientation. The tilt tool face orientation data can be related to the tilt of the remote end of the drill string with respect to the vertical.

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<img file="MX337489B_D0198.tif" />

As shown in FIG. 10A, the · .HMI 10Q0 can ... .SHILE depicted substantially resembling a target quadrant or shape having a plurality of concentric nested rings 1005. The tool face orientation data based on magnetism is on the HMI 1000 by means of symbols 1010, and gravity-based tool face orientation data are represented by symbols 1015. The MHI 1000 also includes symbols 1020 that represent the position of the axis. In the exemplary embodiment shown in FIG. 10A, the magnetic tool face data symbols 1010 are circular, the gravity tool face data symbols 1015 are rectangular, and the axis position data symbols 1020. , are triangular, thus distinguishing the different types of data from each other. Of course, other forms can be used within the scope of the present description. The symbols 1010, 1015, 1020 can also, or alternatively, be distinguished from one another by color, size, scintillation, scintillation rate, and / or other graphic means.

Symbols 1010, 1015, 1020 can indicate only the most recent measurements of tool face (1015,1020) and axis (120) position. However, as in the exemplary embodiment shown in Figures 10A and 10B, the HMI 1000 may include a historical representation of tool face and shaft position measurements, such that the most recent measurement and a plurality of immediately previous measurements. In this way, for example, each ring 1005 in^F20

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INDUSTRIAL the HMI 1000 can represent an iteration or count (ie measurement, 0 a predetermined time interval, or otherwise indicate the historical relationship between the most recent measurements and previous measurements. In the exemplary mode shown in Figure 10A, there are five such rings

1005 in the quadrant (the outermost ring reserved for other data indicia), each ring 1005 representing a data measurement or transmission iteration or count. Tool face symbols 1010, 1015 may each include a number indicating the relative age of each measurement. In other modes, color, shape, and / or other cues may graphically represent the relative age of the measurement. Although not represented as such in Figure 10A, this concept can also be used to historically represent axis position data.

The HMI 1000 may also include a 1025 data legend that links the shapes, colors, and / or other parameters of the data symbols

1010, 1015, 1020 with the corresponding data represented by the symbols. The HMI 1000 may also include a textual indicator and / or another type of indicator 1030 of the current setting value of the tool face mode. For example, the tool face mode can be adjusted to display only gravitational data from the tool face, only magnetic data from the tool face, or a combination thereof (perhaps based on the tool face and / or the tilt of the end of the current drill string). The 1030 indicator can also indicate the current system time. The 1030 indicator can also identify a channel or parameter

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Secondary INDUSTRIAL monitored or otherwise deployed by HMI · 1000. For example, in the exemplary mode shown in Figure 10A, indicator 1030 indicates that a tool face combination mode (“Combo” is currently selected by the user ”), That the depth of the bit is being monitored in the secondary channel, and that the current system time is 13:09:04.

The HMI 1000 can also include a textual indicator and / or another type of indicator 1035 that displays the orientation of the current or most recent tool face. Indicator 1035 can also display the current measurement mode of the tool face (eg gravitational versus magnetic). Indicator 1035 can also display the time at which the most recent measurement of the tool face was made or received, as well as the value of any parameter monitored by a second channel at that time. For example, in the exemplary embodiment shown in Figure 10A, the most recent measurement of the tool face was made by means of a gravitational tool face sensor, indicating that the orientation of the tool face was -75 ° , and this measurement was taken at 13:00:13 with respect to the system clock, at which time the most recently measured bit depth was 557.78 meters.

The HMI 1000 may also include a textual indicator and / or other type of indicator 1040 that displays the current or most recent inclination of the remote end of the drill string. The 1040 pointer can also display the time the tilt measurement was made or received&gt; * wa

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most recent, as well as the value of any patáuitíliu Nlbhiloreadoado by a second channel in that time. For example, in the exemplary mode shown in Figure 10A, the Inclination of the most recent drill string was 8 °, and this measurement was taken at 13:00:04 with respect to the system clock, at At that time, the depth of the most recently measured bit was 557.78 meters. The HMI 1000 may also include an additional graphical indicator or other type of 1040a Indicator that displays the current or most recent tilt. In this way, for example, the HMI 1000 can represent the current or most recent tilt with a textual indicator (for example indicator 1040) and a graphic indicator (for example indicator 1040a). In the embodiment shown in Figure 10A, the graphical tilt indicator 1040a represents the current or most recent tilt as an arched bar, where the length of the bar indicates the degree to which the tilt varies from vertical, and where the The direction in which the bar extends (for example clockwise or counterclockwise) can indicate a tilt direction (for example North vs. South).

The HMI 1000 may also include a textual indicator and / or other type of indicator 1045 that displays the current or most recent azimuth orientation of the remote end of the drill string. Indicator 1045 can also display the time at which the most recent azimuth measurement was made or received, as well as the value of any parameter monitored by a second channel at that time. For example in

164 : IMPIO 'Mexican institute: *! SAY THE PROPERTY V '^; ·

INDUSTRIAL the exemplary mode shown in Figure 10A, the end azimuth of the most recent drill string was 67 °, and this measurement was taken at 12:59:55 with respect to the system clock, at which time the Most recently measured bit depth was 557.78 meters.

The HMI 1000 also includes an additional Graphic Indicator or other type of 1045a indicator that displays the current or most recent tilt. In this way, for example, the HMI 1000 can represent the current or most recent Inclination with a textual Indicator (for example, Indicator 1045) and a graphic indicator (for example, Indicator 1045a). In the mode shown in Figure 10A, the graphical azimuth indicator 1045a represents the current or most recent azimuth measurement as an arched bar, where the bar length indicates the degree to which the azimuth orientation varies from true North , or some other predetermined position, and where the direction in which the bar extends (for example, clockwise or counterclockwise) can indicate an azimuth direction (eg North East vs. North West).

In some embodiments, the HMI 1000 includes data that corresponds to the planned drill path and the actual drill path described with reference to Figures 4C and 5A. These data can provide a visual indicator to a driller of the location of the drill bit.

BHA with respect to the planned drill route and / or target location. In addition, the data taken over time, displayed on the HMI

MEXICAN INSTITUTE

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1000 Figure 10A, can be considered when calculating the position of the BHA, if it is deviating from the planned drilling route, and in which area of ​​Figure 5B it is located.

Referring to Figure 10B, an enlarged view of a portion of the HMI 1000 shown in Figure 10A is illustrated. In modes where the HMI 1000 is represented as a quadrant or target shape, the most recent tool face and axis position measurements may be closest to the edge of the quadrant, so that the oldest readings may be halved. of the quadrant. For example, in the exemplary mode shown in Figures 2A-2B, the last reading was 8 minutes before the currently represented system time, the next reading was 7 minutes before that, and the oldest reading was 6 minutes before the others, for a total of 21 minutes of recorded activity. Readings that are hours or seconds old can indicate the length / unit of time with an “h or an“ s ”.

As also shown in FIG. 10B, the user's mouse pointer or other graphical user input means on one of the tool position or axis position symbols 1010, 1015, 1020 may display the time stamp of the symbol. , as well as the secondary indicator (if any), in a 1050 pop-up window. Timestamps may depend on the setting values ​​of the device at the actual time of recording the measurement. Tool face symbols

1010, 1015 can show the elapsed time since the measurement is

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<img file="MX337489B_D0201.tif" />

recorded by the detection device (for example “rLT'itlUü ul current system time). Secondary channels adjusted to display a time stamp can display a time stamp according to the device recording the measurement.

In the embodiment shown in Figures 10A and 10B, the HMI 1000 shows the absolute position of the top drive axis with respect to True North, the high side of the hole, or some other predetermined orientation. The HM11000 also displays current and historical tool face data received from downhole tools (eg MWD). The HMI 1000, or other human-machine interfaces within the scope of this description, and / or other tools within the scope of this description, may have, enable, and / or exhibit a simplified understanding of the effect of reactive torque on Tool face measurements by simultaneously monitoring and displaying both the tool face and shaft position simultaneously to the user.

In view of the foregoing, the figures and references incorporated herein, those skilled in the art will readily understand that the present disclosure introduces a method for visibly showing a relationship between the orientation of the tool face and the orientation of the axis, said method including: (1) receive electronic data on a continuous basis, where the electronic data includes axis orientation data and at least one of tool face orientation data based

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on gravity and tool face orientation data based on magnetism; and (2) displaying the electronic data on a user display in a historical format representing data resulting from a more recent measurement and a plurality of immediately preceding measurements. In addition, the electronic data may include tool-face azimuth data, which relates the azimuth orientation of the drill string near the bit. The electronic data may also include tool face inclination data related to the inclination of the drill string near the bit. Shaft position data may be related to shaft orientation, top drive, Kelly shank, and / or other rotary drive means for the bit and / or tool face. Electronic data can be received from MWD media and / or other downhole detection / measurement means.

The method may also include associating the electronic data with time indications based on the specific times at which the measurements producing the electronic data were made. In an exemplary embodiment, the most current data can be displayed verbatim and the oldest data can be displayed graphically, such as a quadrant or target representation. The graphical display may include time-dependent or time-specific symbols or other icons, which may be accessible to the user to temporarily display the associated data at that time (for

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<img file="MX337489B_D0203.tif" />

example, dropdown data). Icons can have a number, text, color, or other indication of relative age relative to other icons. Icons can be time-oriented, the newest at the edge of the quadrant, the oldest in the center of the quadrant. The icons can represent the change in time of (1) the measurement recorded by a sensor device corresponding to (2) the current time of the computer system. The display can also represent the current system time.

The present disclosure also introduces an apparatus including: (1) means for receiving electronic data in a constant rate, wherein the electronic data includes axis orientation data and at least one of. tool face orientation data based on gravity, and tool face orientation data based on magnetism; and (2) means for displaying the electronic data on a user display in a historical format representing data resulting from a more recent measurement and a plurality of immediately preceding measurements.

Modalities within the scope of the present disclosure may offer certain advantages over the prior art. For example, when tool position and axis position data are combined in a single display, this can help an operator or other human personnel understand the relationship between tool face and axis position. Combining tool face and axis position data into one

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INSTITUTO MEXfCANO DC LA PKOPJrvA.D

INDUSTRIAL display, also or alternatively, can help ~ xomprendei 4relation that has reactive torque with tool face and / or shaft position.

Referring to Figure 11, an exemplary system is illustrated.

1100 to perform one or more modalities of at least parts of the apparatus and / or methods described herein. System 1100 includes a processor 1102, an input device 1104, a storage device 1106, a video controller 1108, a memory system 1110, a display

1114, and a communication device 1116, all interconnected by one or more collectors 1112. The storage device 1106 may be a floppy disk, hard drive, CD, DVD, optical controller, or any other form of storage device. In addition, the storage device 1106 may be capable of receiving a floppy disk, CD, DVD, or any other form of computer readable medium that may contain computer executable instructions. Communication device 1116 can be a modem, network card, or any other device to allow the system

1100 communicate with other systems.

I

A computer system typically includes at least hardware, capable of executing machine-readable instructions, and also software to execute actions (typically machine-readable instructions) that produce a desired result. Additionally, a computer system may include hybrids of hardware and software, as well as computer subsystems.

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Hardware generally includes at least processing capable platforms, such as client-machine devices (also known as personal computers or servers), and manual processing devices (such as smartphones, PDAs, and personal computing devices (PCDs), for example. example). Furthermore, hardware typically includes any physical device capable of storing machine-readable instructions, such as memories or other data storage devices. Other forms of hardware Include hardware subsystems that include transfer devices such as modems, modem cards, ports, port cards, for example. Hardware may also include, at least within the scope of the present disclosure, multimodal technology, such as devices and / or systems configured to allow users to use multiple forms of input and output - including voice, keyboard, and burin - interchangeably in the same Interaction, application or interface.

The software can include any machine code stored on any memory medium, such as RAM or ROM, machine code stored on other devices (such as for example floppy disks, CDs or DVDs), and can include executable code, an operating system , as well as source code or object code, for example. Furthermore, the software can encompass any group of Instructions that can be executed on a client machine or server - and in this way, it is often called an executable program or code.

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Mexican Institute of Industrial Property

Hybrids (combinations of software and hardware) are becoming more common devices to provide more functionality and performance to computer systems. A hybrid can be created when what are traditionally software functions are manufactured directly on a silicon chip - this is possible since software can be assembled and compiled into ones and zeros, and similarly, ones and zeros can be represented directly on the silicon. Typically, hybrid functions (manufactured hardware) are designed to work seamlessly with the software. Accordingly, it should be understood that hybrids and other combinations of hardware and software are also included within the definition of a computer system herein, and are therefore contemplated by the present disclosure as possible equivalent structures and equivalent methods.

Computer readable media can include passive data storage, such as random access memory (RAM), as well as semi-permanent data storage, such as a compact disc or DVD. Furthermore, an embodiment of the present description can be performed in the RAM of a computer and efficiently transform a standard computer into a new specific computer machine.

Data structures are defined data organizations that can enable a modality of the present description. For example, a data structure can provide a data organization or a

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organization of executable code (executable software). Furthermore, data signals are carried through transmission means and store and transport various data structures, and therefore can be used to transport an embodiment of the invention. It should be noted in the disclosure herein that actions with similar names will be performed in similar ways, unless otherwise indicated.

The controllers and / or systems of the present description can be designed to work in any specific architecture. For example, controllers and / or systems can be run on one or more computers, Ethernet networks, local area networks, wide area networks, the Internet, intranet, handheld devices, and other portable and wireless devices and networks.

In view of all of the foregoing and Figures 1-11, those skilled in the art will readily recognize that the present disclosure introduces a method of directionally guiding a downhole assembly during a drilling rig drilling operation, to a location underground target. The method includes generating a drill plan that has a drill path and an acceptable margin of error as a tolerance zone; receive indicative data of directional trends and projection for bit depth; determine the actual location of the downhole assembly based on directional trends and projection for bit depth; determine if the bit is within the tolerance zone; compare the actual location of the assembly

173

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MEXICAN INSTITUTE OF INDUSTRIAL PROPERTY down the well with the planned drilling route to identify the amount of deviation of the downhole assembly from the actual drilling route; create a modified drill route based on the identified deviation amount of the planned route, including: create a modified drill route that intersects the planned drill route if the amount of deviation from the planned route is less than a threshold deviation amount, and create a modified drill route to the target location that does not intersect the drill route planned if the amount of deviation from the planned route is greater than the amount of threshold deviation; determining a desired tool face orientation to guide the downhole assembly along the modified drill path; automatically and electronically generate drilling equipment control signals on a directional controller; and sending the rig control signals to a winch and overhead control mechanism to guide the downhole assembly along the modified drill path.

The present disclosure also introduces a method of using a shaft to guide a hydraulic motor when a hole is enlarged in a direction that has a horizontal component, where the shaft and hydraulic motor are coupled with opposite ends of a drill string, the method including: monitoring a true tool face orientation of a hydraulic motor driven tool, monitoring a drilling operation parameter indicative of a

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174 '0 MEXICAN .λ PíO? IEP / íD iNDUS ΓΚίήΙ difference between the actual orientation of the tool face and orientation7i9 orientation¹desired of the tool face; and adjusting an axis position an amount that depends on the monitored drilling operation parameter. The amount of shaft position adjustment may be enough to compensate for the difference between the actual and desired tool face orientations. Adjustment of the shaft position may include adjusting a rotational position of the shaft relative to the hole, a vertical position of the shaft relative to the hole, or both. Monitoring of the drilling operation parameter indicative of the difference between the actual and desired tool face orientations may include monitoring a plurality of drilling operation parameters, each indicative of the difference between the actual and desired drilling orientation. tool face, and the amount of shaft position adjustment may also be dependent on each of the plurality of drilling operation parameters.

Monitoring of the drilling operation parameter may include monitoring data received from a tool face orientation sensor, and the amount of axis position adjustment may be dependent on the data from the tool face orientation sensor. The tool face sensor can include a gravity tool face sensor and / or a magnetic tool face sensor.

The drilling operation parameter can include the weight applied to the tool (WOB), the depth of the tool within the

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175

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hole, and / or the tool penetration speed into the hole (ROP). The drilling operation parameter may include a hydraulic differential pressure across the hydraulic motor (ΔΡ), and the ΔΡ may be a corrected ΔΡ based on the monitored fluid pressure that exists in a defined ring between the hole and the drill string. .

In an exemplary embodiment, monitoring the drilling operation parameter indicative of the difference between actual and desired tool face orientations, includes monitoring data received from a tool face orientation sensor, monitoring the weight applied to the tool (WOB), monitor the depth of the tool inside the hole, monitor the speed of penetration of the tool into the hole (ROP), and monitoring the hydraulic differential pressure through the hydraulic motor (ΔΡ). Adjusting the axis position may include adjusting the axis position an amount that is dependent on the data from the monitored tool face orientation sensor, the monitored WOB, the monitored tool depth within the hole, the monitored ROP, and the ΔΡ monitored.

Monitoring of drilling operation parameter and adjustment of shaft position can be performed simultaneously while operating hydraulic motor. Shaft potion adjustment may include having a winch adjust a tool applied weight (WOB) by an amount dependent on the monitored drilling operation parameter. Shaft position adjustment may include adjusting a rotational position

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axis neutral, and the method may also include oscillating the ojp yii ando-el · axis through a predetermined angle beyond the clockwise or counterclockwise neutral position.

The present disclosure also introduces a system for using a shaft to guide a hydraulic motor when a hole is enlarged in a direction having a horizontal component, where the shaft and hydraulic motor are coupled with opposite ends of a drill string. In an exemplary embodiment, the system includes means for monitoring the actual tool face orientation of a tool driven by the hydraulic motor, including means for monitoring a drilling operation parameter indicative of the difference between the actual orientation of the tool face. and the desired orientation of the tool face; and means for adjusting the axis position by an amount that is dependent on the monitored drilling operation parameter.

The present disclosure also provides an apparatus for using a shaft to guide a hydraulic motor when a hole is enlarged in a direction having a horizontal component, where the shaft and hydraulic motor are coupled with opposite ends of a drill string. In an exemplary embodiment, the apparatus includes a sensor configured to detect a drilling operation parameter indicative of a difference between the actual tool face orientation of a tool driven by the hydraulic motor, and the desired tool face orientation of the tool. tool; and a face controller from

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177

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Tool configured to adjust the actual orientation of the "T3Tarsp * cte" tool by generating an axis drive control signal that commands an axis drive mechanism to adjust the rotational position of the shaft based on the monitored drilling operation parameter.

The present disclosure also introduces a method of using a shaft to guide a hydraulic motor when a hole is enlarged in a direction that has a horizontal component, where the shaft and hydraulic motor are coupled with opposite ends of a drill string. In an exemplary embodiment, the method includes monitoring a differential hydraulic pressure across the hydraulic motor (ΔΡ) while simultaneously operating the hydraulic motor, and adjusting the orientation of the hydraulic motor tool face by adjusting the rotational position of the shaft based on the monitored ΔΡ. The monitored ΔΡ can be a corrected ΔΡ that is calculated using the monitored fluid pressure that exists in a defined ring between the hole and the drill string. The method may also include monitoring the existing orientation of the motor tool face while simultaneously operating the hydraulic motor, and adjusting the rotational position of the shaft based on the monitored tool face orientation. The method can also include monitoring a weight applied to a hydraulic motor auger (WOB) while simultaneously operating the hydraulic motor, and adjusting the rotational position of the shaft based on the monitored WOB. The method may also include monitoring a depth of the hydraulic motor bit within the^F20

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auger while simultaneously operating the ^mr»Tr.r hirirá ··¹* ^. and .adjusting the rotational position of the shaft based on the depth of the monitored bit. The method may also include monitoring the hydraulic motor penetration speed into the hole (ROP) while simultaneously operating the hydraulic motor, and adjusting the rotational position of the shaft based on the monitored ROP. Adjusting the orientation of the tool face may include adjusting the rotational position of the axis based on the monitored WOB and the monitored ROP. Alternatively, adjusting the tool face orientation may include adjusting the rotational position of the axis based on the monitored WOB, the monitored ROP, and the existing tool face orientation. Adjusting the orientation of the hydraulic motor tool face may also include having a winch adjust the weight applied to a hydraulic motor auger (WOB) based on the monitored ΔΡ. The rotational position of the axis may be a neutral position, and the method may also include oscillating the axis by rotating the axis through a predetermined angle beyond the neutral position in a clockwise and counterclockwise direction.

The present disclosure also introduces a system for using a shaft to guide a hydraulic motor when a hole is enlarged in a direction having a horizontal component, where the shaft and hydraulic motor are coupled with opposite ends of a drill string. In an exemplary embodiment, the system includes means for detecting differential hydraulic pressure through the hydraulic motor (ΔΡ)

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while simultaneously operating the hydraulic motor, and means for adjusting the orientation of the tool face of the hydraulic motor, wherein the tool face orientation adjusting means includes means for adjusting the rotational position of the shaft based on the detected ΔΡ . The system may also include means for detecting the orientation of the existing tool face of the motor while simultaneously operating the hydraulic motor, where the rotational position adjustment means of the shaft can also be configured to adjust the rotational position of the axis based on the monitored orientation of the tool face. The system may also include means for detecting a weight applied to a hydraulic motor bit (WOB) while simultaneously operating the hydraulic motor, where the rotational position adjustment means of the shaft can be further configured to adjust the rotational position of the shaft. based on the monitored WOB. In addition, the system may include means for detecting the depth of a hydraulic motor bit within the hole while simultaneously operating the hydraulic motor, where the rotational position adjustment means of the shaft can also be configured to adjust the rotational position of the shaft. based on the monitored depth of the bit. The system may also include means for detecting the hydraulic motor's penetration speed into the hole (ROP) while simultaneously operating the hydraulic motor, where the rotational position adjustment means of the shaft can be further configured to adjust the rotational position. of the axis based on the

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ROP monitored. The tool face orientation adjustment means may also include means for causing a winch to adjust the weight applied to a hydraulic motor bit (WOB) based on the

ΔΡ detected.

The present disclosure also introduces an apparatus for using a shaft to guide a hydraulic motor when a hole is enlarged in a direction having a horizontal component, where the shaft and hydraulic motor are coupled with opposite ends of a drill string. In an exemplary embodiment, the apparatus includes a pressure sensor configured to detect differential hydraulic pressure through the hydraulic motor (ΔΡ) during operation of the hydraulic motor, and a tool face controller configured to adjust the orientation of the face. of the hydraulic motor tool, generating an axle drive control signal instructing an axle drive mechanism to adjust the rotational position of the shaft based on the detected ΔΡ. The apparatus may also include a tool face orientation sensor configured to detect the current orientation of the tool face, wherein the tool face controller can be configured to generate the additionally based axis drive control signal. at the current detected orientation 20 of the tool face. The apparatus may further include a auger weight sensor (WOB) configured to detect data indicative of the amount of weight applied to a hydraulic motor auger, and a winch controller configured to cooperate with the t controller

• i

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tool face to adjust the orientation of the tool face, generating a winch control signal that commands the winch to operate the winch, where the winch control signal may be based on the detected WOB. The apparatus may also include a rate of penetration (ROP) sensor configured to detect the rate at which the hole is enlarging, where the winch control signal may additionally be based on the detected ROP.

Methods and apparatus within the scope of the present disclosure include those aimed at automatically obtaining and / or maintaining a desired orientation of the tool face, monitoring drilling operation parameters that had not previously been used for automatic orientation of the tool face. tool, which include one or more of

Mud Motor ΔΡ, Actual Tool Face Orientation, Actual WOB, Actual Auger Depth, Actual ROP, Actual Shaft Oscillation. Exemplary combinations of these drilling operation parameters, which can be used in accordance with one or more aspects of the present disclosure to obtain and / or maintain the desired orientation of the tool face, include:

• ΔΡ and TF;

• ΔΡ, TF and WOB;

• ΔΡ, TF, WOB and Prof;

• ΔΡ and WOB;

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• ΔΡ, TF and Prof;

• ΔΡ, TF, WOB and ROP;

• ΔΡ and ROP;

. ΔΡ, TF and ROP;

• ΔΡ, TF, WOB and Ose;

• ΔΡ and Prof;

• ΔΡ, TF and Ose;

• ΔΡ, TF, Prof and ROP;

• ΔΡ and Ose;

• ΔΡ, WOB and Prof;

• ΔΡ, TF, Prof and Ose;

. TF and ROP;

• ΔΡ, WOB and ROP;

• ΔΡ, WOB, Prof and ROP;

• TF and Prof;

• ΔΡ, WOB and Ose;

• ΔΡ, WOB, Prof and Ose;

• TF and Ose;

• ΔΡ, Prof and ROP;

• ΔΡ, Prof, ROP and Ose;

• WOB and Prof;

183

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• ΔΡ, Prof and Ose; ---— '• ΔΡ, TF, WOB, Prof and ROP;

• WOB and Ose;

• ΔΡ, ROP and Ose;

• ΔΡ, TF, WOB, Prof and Ose;

• ROP and Ose;

• ΔΡ, TF, WOB, ROP and Ose;

• ROP and Prof; and • ΔΡ, TF, WOB, Prof, ROP and Ose;

where ΔΡ is the current ΔΡ of the mud motor, TF is the actual orientation of the tool face, WOB is the actual WOB, Prof is the actual bit depth, ROP is the actual ROP, and Ose is the frequency of actual axis oscillation, speed, amplitude, neutral point and / or torque.

In an exemplary embodiment, a desired orientation of the tool face is provided (eg, by a user, computer, or computer program), and subsequently apparatuses in accordance with one or more aspects of the present disclosure will track and control the actual orientation. of the tool face, as described above. However, while tracking and controlling the actual orientation of the tool face, drilling operation parameter data can be monitored to establish, and then update in real time, the ratio

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between: (1) the mud motor ΔΡ and auger torque- (2) changes in WOB and auger torque; and (3) changes in the axis position and current orientation of the tool face; among other possible relationships within the scope of this description. The learned information can then be used to control the actual orientation of the tool face by altering a change in one or more of the monitored drilling operation parameters.

In this way, for example, the desired orientation of the tool face can be entered by a user, and a rotary drive system 10 in accordance with aspects of the present disclosure can rotate the drill string until the orientation data Monitored tool faces and / or other drilling operation parameter data indicate tool movement downhole. The automatic apparatus of the present disclosure then continues to control the rotary drive until the desired orientation of the tool face is obtained. Then directional drilling proceeds. If the actual orientation of the tool face deviates from the desired orientation of the tool face, as possibly indicated by the data of the monitored parameter of the drilling operation, the rotary drive may react by rotating the shaft and / or the drill string either clockwise or counterclockwise, according to the relationship between the monitored drilling parameter data and the orientation of the tool face. If a mode is used

185

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MEXICAN INSTITUTE OF PROPERTY

INDUSTRIAL

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For oscillation, the apparatus can alter the amplitude of the oscillation (for example by increasing or decreasing the counterclockwise part of the oscillation), to bring the true orientation of the tool face back into its path. Alternatively or additionally, a winch system can react to deflect the orientation of the tool face by inserting or removing the drill cable, and / or a mud pump system can react by increasing or decreasing the ΔΡ of the mud motor. If the actual orientation of the tool face deviates from the desired orientation beyond a preset limit (user adjustable), for a period greater than 10 a preset duration (user adjustable), then the apparatus may produce a audible and / or visual alarm. The operator may then have the opportunity to continue automatic control, or take over manual operation.

This approach can also be used to control the orientation of the tool face, knowing the axis orientation before and after a connection, to reduce the amount of time required to make a connection. For example, the axis orientation can be monitored in the background at a known tool face, WOB and / or ΔΡ mud motor orientation. Then wedges can be placed and the orientation of the B0 axis can be recorded and then it can refer to the relationships mentioned above. Then the connection can occur and the axis orientation can be recorded just before pulling the wedges. At this point, the axis orientation can be restored to what it was before connection. The operator of

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Drilling or an automatic controller may then devise a "self-orientation" procedure, and the apparatus may rotate the shaft into one position and then return to the bottom. Consequently, the drilling operator no longer needs to wait for a measurement of the orientation of the tool bit, or blindly return to the bottom. Consequently, the aspects of the present description can offer significant time savings during connections.

Furthermore, methods within the scope of the present disclosure may be local or remote in nature. These methods, and any controller discussed herein, can be performed by one or more Intelligent adaptive controllers, programmable logic controllers, artificial neural networks, and / or other adaptive and / or "learning" controllers or processing devices. For example, such methods may be deployed or performed by means of a PLC, PAC, PC, one or more servers, desktop computers, handheld devices, and / or any other form or type of computing device with adequate capacity.

As used herein, the term "substantially" means that a numerical amount is within about 20 percent, preferably within about 10 percent, and most preferably within about 5 percent of an indicated value.

In a preferred embodiment, this term refers to amounts within about 1 percent, within about 0.5 percent, or even within about 0.1 percent of an Indicated value.

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The term "approximately, as used" refers to the two numbers on a number scale. For example, "about 1 to 2" is understood as "about 1 to about 2". In addition, all present numerical scales include each complete integer or 1/10 of an integer within the scale.

The present description also incorporates in its entirety by explicit reference thereto each of the following references:

- US patent USA No. 6,050,348, to Richarson, et al.

- US patent USA No. 5,474,142, to Bowden;

- US patent USA No. 5,713,422, to Dhindsa;

- US patent USA No. 6,192,998, to Pinckard;

- US patent USA No. 6,026,912, to King, et al .;

- US patent USA No. 7,059,427, to Power, et al .;

- US patent USA No. 6,029,951 to Guggari;

- “A Real-Time Implementation of MSE, AADE-05-NTCE-66;

- "Maximizing Drill Rates with Real-Time Surveillance of Mechanical Specific Energy", SPE 92194;

- "Comprehensive Drill-Rate Management Process To Maximize Rate of Penetration", SPE 102210; and

- “Maximizing ROP With Real-Time Analysis of Digital Data and

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MSE ”, IPTC 10607.

This application relates to: (1) the US provisional patent application. USA No. 0 / 985,869, filed on November 6, 2007

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(Proxy Case No. 38496.45); (2) the US request &lt;r05paienltípiuy¡s¡urial '. USA No. 61 / 016,093, filed on December 21, 2007 (attorney's case number 38496.43); and (3) the US provisional patent application. USA No. 61 / 026,323, filed on February 5, 2008 (Proxy Case No. 38496.46); (4) US patent application. USA No. 11 / 859,378, filed on September 21, 2007 (Proxy Case No. 38296.12); (5) US patent application. USA No. 11 / 952,511, filed on December 12, 2007 (attorney's case number 38296.19); (6) US patent application. USA No. 11 / 847,048, filed on August 29, 2007 (Proxy Case No. 38296.14); (7) US patent application. USA No. 11 / 668,388, filed on January 29, 2007 (Proxy Case No. 38496.21); and (8) the US patent application. USA No. 11 / 747,110, filed on May 10, 2007 (Proxy Case No. 38496.16). The description of each of the foregoing patent applications is incorporated herein in its entirety by explicit reference thereto.

The foregoing outlines the characteristics of various modalities so that those skilled in the art can better understand the aspects of the present description. Those skilled in the art will appreciate that they can easily use the present disclosure as a basis for designing or modifying other processes and structures to effect the same purposes and / or to achieve the same advantages of the modalities introduced herein. Those skilled in the art will also realize that such equivalent constructions do not depart from the spirit and scope of this description, and that they can make various changes, substitutions, and alterations without departing from the spirit and scope of the present description.

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