System and method for surface steerable drilling.
Abstract
A system and method for surface-orientated drilling is provided; In one example, the system receives feedback information from a drilling machine and calculates an estimated position of a drill in a formation based on the feedback information; the system compares the estimated position with a desired position along a planned course of a drilling well; the system calculates multiple solutions if the comparison indicates that the estimated position is outside a defined margin of error with respect to the desired position; each solution defines a course from the estimated position towards the planned course; the system calculates a cost for each solution and selects one of the solutions based at least partially on the cost;

Term
6.2 yearsleft in the term
Expires 10 December 2032.
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30 claims: 4 independent, 26 dependent
- 1NOVEDAD DE LA INVENCIÓN REIVINDICACIONES 5 1,- Un método de perforación que comprende:recibir, mediante un sistema dirigible de superficie acoplado a un equipo de perforación, una pluralidad de entradas que incluyen una trayectoria planificada para un agujero, información de formación para el agujero, información de accesorios de equipo de perforación para el equipo de 10 perforación, información de accesorios para arreglo de fondo de pozo (BHA) para un BHA acoplado al equipo de perforación, un conjunto de parámetros de costos financieros, y un conjunto de parámetros de confiabilidad;procesar, mediante el sistema dirigible de superficie, la trayectoria planificada, la información de formación, la información de accesorios de equipo de 15 perforación, la información de accesorios de BHA, el conjunto de parámetros de costos financieros, y el conjunto de parámetros de confiabilidad para producir un conjunto de parámetros de control para el equipo de perforación, en donde los parámetros de control definen una pluralidad de operaciones de perforación para ser ejecutadas por el equipo de perforación para formar el 20 agujero;sacar, mediante el sistema dirigible de superficie, el conjunto de parámetros de control para el equipo de perforación;procesar, mediante el sistema dirigible de superficie, información de retroalimentación recibida desde el equipo de perforación para determinar si una posición estimada de INSTITUTO MWGTNO Ot LA INOUmui una barrena de perforación acoplada al equipo de ce onm^ntra dentro de un margen definido de error de un punto deseado a lo largo de la trayectoria planificada;calcular, mediante el sistema dirigible de superficie, una primera pluralidad de planes de convergencia si la posición estimada de 5 la barrena de perforación no se encuentra dentro del margen de error, en donde cada uno de la primera pluralidad de planes de convergencia define un vector de solución para realinear la barrena de perforación con la trayectoria planificada desde la posición estimada con base en la información de retroalimentación y la información de formación;calcular, mediante el sistema 10 dirigible de superficie, una segunda pluralidad de planes de convergencia si la posición estimada de la barrena de perforación no se encuentra dentro del margen de error, en donde cada uno de la segunda pluralidad de planes de convergencia define un vector de solución para realinear la barrena de perforación con la trayectoria planificada desde una posición proyectada con 15 base en la información de retroalimentación y la información de formación, en donde la posición proyectada se determina extendiendo una trayectoria actual de la barrena desde la posición estimada;seleccionar, mediante el sistema dirigible de superficie, un plan de convergencia que satisface mejor un conjunto de parámetros objetivo de la primera y de la segunda pluralidades de 20 planes de convergencia;producir, mediante el sistema dirigible de superficie, un conjunto de parámetros de control revisados que representan el plan de convergencia seleccionado;y sacar, mediante el sistema dirigible de superficie, el conjunto de parámetros de control revisados para el equipo de 100 IMPI INSTITUTO MEXICANO DE LA PROPIEDAD INDUSTRIAL perforación.
- 22,- El método de conformidad con la reivindicación 1, caracterizado además porque calcular cada uno de la primera pluralidad de planes de convergencia incluye calcular un desfasamiento de la barrena de perforación con base en por lo menos uno de la información de formación y la información de retroalimentación.
- 3- El método de conformidad con la reivindicación 1, caracterizado además porque el conjunto de parámetros de costos financieros incluye un intervalo de parámetros de costos financieros y un intervalo de parámetros de tiempo, y en donde calcular cada uno de la primera y de la segunda pluralidades de planes de convergencia incluye identificar un valor óptimo del costo financiero versus tiempo.
- 44,- El método de conformidad con la reivindicación3, caracterizado además porque uno del costo financiero y del tiempose pondera mucho más que el otro.
- 5- El método de conformidad con la reivindicación3, caracterizado además porque el valor óptimo tiene un límite superior definido mediante un retraso de convergencia máximo.
- 6- El método de conformidad con la reivindicación5, caracterizado además porque el valor óptimo tiene un límite inferior definido mediante una corrección lo más agresiva posible.
- 77,- El método de conformidad con la reivindicación 6, caracterizado además porque la corrección lo más agresiva posible está 101 limitada mediante un radio máximo de curvatura posible en una trayectoria para realinear la barrena de perforación con la trayectoria planificada definida mediante un vector de solución que representa la corrección más agresiva.
- 88,- El método de conformidad con la reivindicación 1, caracterizado además porque comprende adicionalmente perforar, mediante el equipo de perforación, por lo menos una porción del agujero con base en los parámetros de control.
- 9- El método de conformidad con la reivindicación 8, caracterizado además porque comprende adicionalmente perforar, mediante el equipo de perforación, por lo menos una porción del agujero con base en los parámetros de control revisados.
- 10- El método de conformidad con la reivindicación 1, caracterizado además porque sacar el conjunto de parámetros de control para el equipo de perforación incluye manipular directamente, mediante el sistema dirigible de superficie, por lo menos un sistema de control de equipo de perforación.
- 1111,- El método de conformidad con la reivindicación 10, caracterizado además porque el por lo menos un sistema de control de equipo de perforación es uno de un sistema de control de presión diferencial, un sistema de control de posición, y un sistema de control de circulación de fluido.
- 1212,- El método de conformidad con la reivindicación 1, caracterizado además porque el conjunto de parámetros objetivo incluye un 102 INSTITUTO mexicano DE LA PROPIEDAD industrial radio máximo de curvatura posible en una trayectoria definida mediante un vector de solución.
- 13- El método de conformidad con la reivindicación 1, caracterizado además porque el conjunto de parámetros objetivo incluye un costo financiero, un costo de tiempo, y un costo de confiabilidad.
- 14- El método de conformidad con la reivindicación 1, caracterizado además porque calcular la segunda pluralidad de planes de convergencia incluye calcular un retraso que define un período durante el cual se permite que la barrena de perforación continúe a lo largo de la trayectoria actual desde la posición estimada antes de que la trayectoria sea alterada por el plan de convergencia.
- 1515,- El método de conformidad con la reivindicación 1, caracterizado además porque calcular la segunda pluralidad de planes de convergencia incluye calcular un retraso que define un período durante el cual se permite que la barrena de perforación continúe a lo largo de una trayectoria en línea recta después de que la trayectoria es alterada por el plan de convergencia.
- 1616,- Un método para perforar un agujero, que comprende, recibir, mediante un sistema dirigible de superficie, información de retroalimentación procedente de un equipo de perforación acoplado en utilizando una barrena de perforación para perforar un agujero en una formación;calcular, mediante el sistema dirigible de superficie, una posición estimada de la barrena de perforación en la formación con base en la 103 INSTITUTO MEXICANO DE LA FROflEDAD INDUSTRIAL información de retroalimentación;comparar, mediante el sistema diriyibte^te· superficie, la posición estimada de la barrena de perforación con una posición deseada de la barrena de perforación a lo largo de una trayectoria planificada del agujero;calcular, mediante el sistema dirigible de superficie, una pluralidad de soluciones si la comparación indica que la posición estimada está fuera de un margen de error definido con respecto a la posición deseada, en donde cada una de la pluralidad de soluciones define una trayectoria desde la posición estimada a la trayectoria planificada;calcular, mediante el sistema dirigible de superficie, un costo de cada una de la pluralidad de soluciones;seleccionar, mediante el sistema dirigible de superficie, una primera solución a partir de la pluralidad de soluciones con base en por lo menos parcialmente el costo de la primera solución;producir, mediante el sistema dirigible de superficie, información de control que representa la primera solución;y sacar, mediante el sistema dirigible de superficie, la información de control para el equipo de perforación.
- 17- El método de conformidad con la reivindicación 16, caracterizado además porque calcular el costo de cada una de la pluralidad de soluciones incluye identificar una pluralidad de elementos de costos aplicables a cada solución, y aplicar un factor de ponderación a por lo menos uno de los elementos de costo.
- 18- El método de conformidad con la reivindicación 17, caracterizado además porque seleccionar la primera solución incluye identificar el costo de la primera solución como un mínimo de los costos de la 104 pluralidad de soluciones.
- 19- El método de conformidad con la reivindicación 17, caracterizado además porque uno de la pluralidad de elementos de costos es el tiempo y el otro de la pluralidad de elementos de costos es un costo financiero.
- 20- El método de conformidad con la reivindicación 16, caracterizado además porque calcular la pluralidad de soluciones incluye calcular un desfasamiento de la barrena de perforación con base en información acerca de la formación.
- 2121,- El método de conformidad con la reivindicación 16, caracterizado además porque calcular la pluralidad de soluciones incluye calcular un tiempo de inicio de deslizamiento y un tiempo de finalización de deslizamiento para cada una de las soluciones.
- 2222,- El método de conformidad con la reivindicación 21, caracterizado además porque calcular la pluralidad de soluciones incluye adicionalmente calcular un tiempo de inicio y un tiempo de finalización para el bombeo de lubricantes dentro del agujero antes del tiempo de inicio de deslizamiento para cada una de las soluciones.
- 23- El método de conformidad con la reivindicación 16, caracterizado además porque comprende adicionalmente calcular, mediante el sistema dirigible de superficie, una segunda pluralidad de soluciones si la comparación indica que la posición estimada está fuera de un margen definido de error con respecto a la posición deseada, en donde cada una de la 105 pluralidad de soluciones define una trayectoria desde una posición proyectada a la trayectoria planificada, y en donde cada posición proyectada se determina extendiendo una trayectoria actual de la barrena desde la posición estimada.
- 2424,- El método de conformidad con la reivindicación 23, caracterizado además porque calcular la segunda pluralidad de soluciones incluye calcular un retraso que define un período durante el cual se permite que la barrena de perforación continúe a lo largo de la trayectoria actual desde la posición estimada antes de que la trayectoria sea alterada de conformidad con la primera solución.
- 25- El método de conformidad con la reivindicación 16, caracterizado además porque calcular la segunda pluralidad de soluciones incluye calcular un retraso que define un período durante el cual se permite que la barrena de perforación continúe a lo largo de una trayectoria en línea recta después de que la trayectoria es alterada por la primera solución.
- 26- Un sistema dirigible de superficie para usarse con un equipo de perforación, que comprende:una interfaz de red;y un procesador acoplado a la interfaz de red, dicho procesador configurado para: recibir una pluralidad de entradas que incluyen una trayectoria planificada para un agujero, información de formación para el agujero, información de accesorios de equipo de perforación para el equipo de perforación, información de accesorios para arreglo de fondo de pozo (BHA) para un BHA acoplado al equipo de perforación, un conjunto de parámetros de costos financieros, y un conjunto de parámetros de confiabilidad;procesar la trayectoria planificada, la información de formación, la información de IMPI 63 Ί Uo INSTITUTO MEXICANO DE LA PROPIEDAD O^i INDUSTRIAL accesorios de equipo de perforación, la información de accesorios do BHA, ol conjunto de parámetros de costos financieros, y el conjunto de parámetros de confiabilidad para producir un conjunto de parámetros de control para el equipo de perforación, en donde los parámetros de control definen una pluralidad de operaciones de perforación para ser ejecutadas por el equipo de perforación para formar el agujero;sacar el conjunto de parámetros de control para el equipo de perforación;procesar información de retroalimentación proveniente del equipo de perforación para determinar si una posición estimada de una barrena de perforación acoplada al equipo de perforación se encuentra dentro de un margen definido de error de un punto deseado a lo largo de la trayectoria planificada;calcular una pluralidad de planes de convergencia si la posición estimada de la barrena de perforación no coincide con el punto deseado, en donde cada uno de la pluralidad de planes de convergencia define un vector de solución para realinear la barrena de perforación con la trayectoria planificada con base en la información de retroalimentación y un conjunto de parámetros objetivo;seleccionar uno de la pluralidad de planes de convergencia;producir un conjunto de parámetros de control revisados que representan el plan de convergencia sacar el conjunto de parámetros de control revisados para el equipo de perforación;y proporcionar a una base de datos local configurada para almacenar datos que representan la trayectoria planificada, la información de formación, la información de accesorios de equipo de perforación, la información de accesorios de BHA, el conjunto de parámetros de costos financieros, y el conjunto de parámetros de confiabilidad. IMPI 1 n 7 iNStlWrÓ MEXICANO lU/ ^“¿UAVtónsnAD iHCUSTAlAl
- 2727,- El sistema dirigible de superficie de reivindicación 26, caracterizado además porque comprende adicionalmente una base de datos regional acoplada a la interfaz de red, en donde la base de datos incluye datos que representan una pluralidad de trayectorias planificadas, información de formación para una pluralidad de regiones geográficas, información de accesorios de equipo de perforación para una pluralidad de equipos de perforación, información de accesorios de BHA para una pluralidad de BHAs, el conjunto de parámetros de costos financieros, y el conjunto de parámetros de confiabilidad.
- 28- El sistema dirigible de superficie de conformidad con la reivindicación 26, caracterizado además porque comprende adicionalmente dentro del procesador un bucle de control de orientación y un bucle de control autónomo, en donde el bucle de control de orientación calcula la pluralidad de planes de convergencia y el bucle de control autónomo saca el conjunto de parámetros de control revisados para el equipo de perforación.
- 2929,- El sistema dirigible de superficie de conformidad con la reivindicación 26, caracterizado además porque el procesador adicionalmente optimiza los parámetros de control.
- 3030,- El sistema dirigible de superficie de conformidad con la reivindicación 29, caracterizado además porque el procesador adicionalmente modifica de forma iterativa los parámetros de control mientras que se mantiene un parámetro objetivo. 1M IMPI W8 INSTITUTO MEXICANO Di LA PROME0AO industrial
Independent claims30
431 paragraphs in 84 sections, as filed
(54) Title: DIRIGIBLE SURFACE DRILLING SYSTEM AND METHOD.
(54) Title: SYSTEM AND METHOD FOR SURFACE STEERABLE DRILLING.
(57) Summary
A system and method for surface orlentable drilling is provided; In one example, the system receives feedback information from a drilling machine and calculates an estimated position of a bit in a formation based on the feedback information; the system compares the estimated position with a desired position along a planned bearing of a borehole; the system calculates multiple solutions if the comparison indicates that the estimated position is outside a defined margin of error with respect to the desired position; each solution defines a heading from the estimated position towards the planned heading; the system calculates a cost for each solution and selects one of the solutions based at least partially on cost; the system produces control information representing the selected solution and outputs the control information for the drilling machine.
(57) Abstract
A system and method for surface steerable drilling are provided. In one example, the system receives feedback Information from a drilling rig and calculates an estimated position of a drill bit in a formation based on the feedback Information. The system compares the estimated position to a desired position along a planned path of a borehole. The system calculates multiple Solutions if the comparison indicates that the estimated position is outside a defined margin of error relative to the desired position. Each solution defines a path from the estimated position to the planned path. The system calculates a cost of each solution and selects one of the Solutions based at least partly on the cost. The system produces control Information representing the selected solution and outputs the control Information for the drilling rig.
<img file="MX351981B_D0001.tif" />
PATENT TITLE No. 351981
Owner * ·· ): HUNT ADVANCED DRILLING TECHNOLOGIES, L.LC.
Or hometown: 1900 Akard Street, Dallas, Texas, 75201-2300, USA
D nomination: DIRIGIBLE SURFACE DRILLING SYSTEM AND METHOD.
Classificationi
CIP:
E21B44 / 00; E21BJ / Q6; E21B7 / 10
E21B47 / R ''
CPC:
45/00
ALL W. BEN ^ ON AEDDY C CHEN Inventor (s) i
The patent of refere
In accordance with the as of the date of pn
<img file="MX351981B_D0002.tif" />
Industrial.
9/3/20 sorrogables, counted to Ichos.
/2012
F. 1 tfi99 „r
This document is signed with an advanced electronic signature (FIEL), based on articles 7 BIS 2 of the Industrial Property Law; 3rd of
Number
MX / a / 2014/0 © 7743 n International;
of 2012 '
PaUí
US
Number:
13/334,370
Validity: V ^ ji F cha de Veh ιιβι ^ ΙΟ ^ ΐΜ ^^
Date of Ex ^^ ktion: deí ^ UM lo fixes the Law of lustriat) the p
Who signs this t (Official Gazette of the Federation 01/25/2006, 05/06/2009, 01/06/2010) Regulations of the Mexican Institute Articles 1 ”, 3 °, 4<sup>or</sup>, 5<sup>or</sup> fraction V subsection 12/27/1999, amended on 10/10/2002. 29/0 Deputy Generals, Coordinator, Departmental Director and other subordinates of the Institute 08/04/2004 and 09/13/2007).
Bnto e
27 / / ^ 4/2012 ^ arti wg ^ ndürcie twenty "vipers" of Industrial Property 01/26/2004, 06/16/2005,
3<sup>or</sup> fraeooM V¿ * kpeo a), 4<sup>or</sup> and 12th fractions I and III of 2007 «M> * ÍSW72004, 07/28/2004 and 09/07/2007);
of Industrial Property (DOF qwrdo that delegates powers to the Directors, Divisional Subdirectors, Coordinators 2/1999. amended on 02/04/2000. 07/29/2004, its Regulations, and 1 section III, 2 section V, 26 BIS and 26 TER of the Agreement establishing the guidelines for the use of the Electronic Payment and Services Portal (PASE) of the Mexican Institute of Industrial Property, in the procedures indicated.
THE DIVISIONAL DIRECTOR OF PATENTS
NAHANNY CANAL REYES
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<img file="MX351981B_D0004.tif" />
MX / 2017/90119
W 4 Η3
IMPI ^
MEXICAN INSTITUTE
Ί OF THE PROPERTY v <n3L
INDUSTRIAL - -ü
DIRIGIBLE DRILLING SYSTEM AND METHOD DÉSÜPÉkFICIÉ
CROSS REFERENCE TO RELATED REQUESTS
This application claims the benefit of US Patent Application No. 13 / 334,370, filed December 22, 2011, now US Patent No. 8,210,283, published July 3, 2012, and entitled SYSTEM AND METHOD FOR SURFACE STEERABLE DRILLING.
TECHNICAL FIELD OF THE INVENTION
This application is directed to the creation of wells, such as oil wells, and more particularly to the planning and drilling of such wells.
BACKGROUND OF THE INVENTION
Drilling a hole for mineral extraction has become an increasingly complicated operation due to the greater depth and complexity of many holes, including the added complexity of directional drilling. Drilling is a costly operation and drilling mistakes increase cost and in some cases drilling mistakes can permanently reduce production
<img file="MX351981B_D0005.tif" />
IMPI
MEXICAN INSTITUTE
OF INDUSTRIAL PROPERTY from a well for years to come. Technologies and methods do not adequately address the complicated nature of drilling. Consequently, what is needed is a system and method to improve drilling operations and minimize drilling errors.
BRIEF DESCRIPTION OF THE DRAWINGS
For a more complete understanding, reference is now made to the following description taken in conjunction with the accompanying drawings, in which:
Figure 1A illustrates one embodiment of a drilling environment in which a surface steerable system can operate;
Figure 1B illustrates an embodiment of a more detailed portion of the drilling environment of Figure 1A;
Figure 1C illustrates an embodiment of a more detailed portion of the drilling environment of Figure 1B;
Figure 2A illustrates one embodiment of the surface steerable system of Figure 1A and how information can flow to and from the system;
Figure 2B illustrates one embodiment of a screen that can be used with the surface steerable system of Figure 2A;
Figure 3 illustrates an embodiment of a drilling environment that does not have the benefit of the surface steerable system of Figure 2A and possible communication channels within the environment;
<img file="MX351981B_D0006.tif" />
<img file="MX351981B_D0007.tif" />
MEXICAN INSTITUTE OF INDUSTRIAL PROPERTY
Figure 4 illustrates an embodiment of a drilling environment having the benefit of the surface steerable system of Figure 2A and possible communication channels within the environment;
Figure 5 illustrates a data flow mode that may be supported by the surface steerable system of Figure 2A;
Figure 6 illustrates one embodiment of a method that can be performed by the surface steerable system of Figure 2A;
Figure 7A illustrates a more detailed embodiment of the method of Figure 6;
Figure 7B illustrates a more detailed embodiment of the method of Figure 6;
FIG. 7C illustrates one embodiment of a convergence plan diagram with multiple convergence paths;
Figure 8A illustrates a more detailed embodiment of a portion of the method of Figure 7B;
Figure 8B illustrates a more detailed embodiment of a portion of the method of Figure 6;
Figure 8C illustrates a more detailed embodiment of a portion of the method of Figure 6;
Figure 8D illustrates a more detailed embodiment of a portion of the method of Figure 6;
Figure 9 illustrates one embodiment of a system architecture that can be used for the surface steerable system of Figure 2A!
<img file="MX351981B_D0008.tif" />
IMPI
MEXICAN INSTITUTE OF INDUSTRIAL PROPERTY
Figure 10 illustrates one embodiment of a more detailed view of the system architecture of Figure 9;
Figure 11 illustrates one embodiment of an orientation control loop that can be used within the system architecture of Figure 9;
Figure 12 illustrates one embodiment of a standalone control loop that can be used within the system architecture of Figure 9; Y
Figure 13 illustrates one embodiment of a computer system that can be used within the surface steerable system of Figure 2A.
DETAILED DESCRIPTION OF THE INVENTION
Referring now to the drawings, where like reference numerals are used herein to designate like elements throughout the description, the various views and embodiments of a drilling system and method are illustrated and described. surface airship, and other possible modalities are described. The figures are not necessarily drawn to scale, and in some cases the drawings have been enlarged and / or simplified in places for illustrative purposes only. One skilled in the art will appreciate the many possible applications and variations based on the following examples of possible
<img file="MX351981B_D0009.tif" />
modalities.
Referring to Figure 1A, one embodiment of an environment 100 is illustrated with multiple wells 102, 104, 106, 108, and a rig 110. In our example, wells 102 and 104 are located in a region 112, well 106 is located in region 114, well 108 is located in region 116, and rig 110 is located in region 118. Each of regions 112, 114, 116, and 118 may represent a geographic area that has similar geologic formation characteristics. For example, region 112 can include particular formation features identified by rock type, porosity, thickness, and other geological information. These formation characteristics affect the drilling of wells 102 and 104. Region 114 may have formation characteristics that are different enough to be classified as a different region for drilling purposes, and different formation characteristics affect the drilling of well 106. Likewise, formation characteristics in regions 116 and 118 affect well 108 and rig 110, respectively.
It is understood that regions 112, 114, 116 and 118 can vary in size and shape depending on the characteristics by which they are identified. Additionally, regions 112, 114, 116, and 118 can be sub-regions of a larger region. Accordingly, the criteria by which regions 112, 114, 116, and 118 are identified are less important for the purposes of the present disclosure than understanding
<img file="MX351981B_D0010.tif" />
that each of the regions 112, 114, 116, and 118 has geological influences that can be used to distinguish each region from the other regions from a drilling perspective. Such characteristics can be relatively very important (for example, the presence or absence of a complete rock layer in a given region) or they can be relatively minor (for example, variations in the thickness of a rock layer that extends across multiple regions).
Consequently, drilling a well located in the same region as other wells, such as drilling a new well in region 112 with existing wells 102 and 104, means that the drilling process is likely to face problems of drilling similar to those faced when drilling existing wells in the same region. For similar reasons, a drilling process performed in one of the regions is likely to face different problems than a drilling process performed in another region. However, even the drilling processes that created wells 102 and 104 can face different problems during actual drilling because variations in formation are likely to occur even in a single region.
Drilling a well typically involves a considerable amount of human decision making during the drilling process. For example, geologists and drilling engineers use their knowledge, experience, and available information to make decisions as to how to plan the drilling operation, how to carry out the plan, and how to handle drilling problems. However, even the best geologists and drilling engineers take some guesswork due to the unique nature of each hole. Additionally, a directional well driller directly responsible for drilling may have drilled other holes in the same region and thus may have some similar experience, but it is impossible for a human to mentally track all possible inputs and account for those inputs to time to make a decision. This can lead to costly mistakes, because drilling mistakes can increase the cost of drilling to hundreds of thousands or even millions of dollars and, in some cases, drilling errors can permanently reduce the production of a well, resulting in considerable long-term losses.
In the example at hand, to aid in the drilling process, each well 102, 104, 106, and 108 has collected data corresponding to 120, 122, 124, and 126, respectively. The data collected may include the geological characteristics of a particular formation in which the corresponding well was formed, the attributes of a particular rig, including the downhole arrangement (BHA), and drilling information such as weight on bit (WOB), drilling speed, and / or other information pertinent to the formation of that particular hole. Drilling information may be associated with a particular depth or other identifiable marker such that, by β IMPI ^ θ INSTITUTE MEXICANO
FROM THE INDUSTRIAL PftOHF.DAD example, it is recorded that the drilling of well 102 of R motmc - □ meters (1000 feet to 1200 feet) occurred at a first ROP (rate of penetration) through a first layer of rock with a first WOB, while drilling from 365.76 meters to 457.20 meters (1200 feet to 1500 feet) occurred at a second ROP through a second rock layer with a second WOB. The collected data can be used to recreate the drilling process used to create the corresponding well 102, 104, 106, or 108 in the particular formation. It is understood that the precision with which the drilling process can be recreated depends on the level of detail and accuracy of the data collected.
The collected data 120, 122, 124, and 126 can be stored in a centralized database 128 as indicated by lines 130, 132, 134, and 136, respectively, which can represent any wired communication channel (s) (s) and / or wireless (s). Database 128 can be located in a drill cube (not shown) or elsewhere. Alternatively, the data can be stored on removable storage media that is subsequently attached to database 128 in order to store the data. The collected data 120, 122, 124, and 126 can be stored in database 128 as formation data 138, accessory data 140, and drilling data 142, for example. Formation data 138 can include any formation information, such as rock type, layer thickness, layer location (e.g. depth), porosity, gamma readings, etc. *
<img file="MX351981B_D0011.tif" />
IMPI
MEXICAN INSTITUTE
Di LA PRONFOAO INDUSTRIAL accessories140 can include any information from JCttíbUiiUb, lay uuiuu configuration of drilling equipment (for example, rotary table or upper drive unit), type of bits, mud composition, etc. The drilling data 142 can include any drilling information, such as drilling speed, WOB, differential pressure, tool orientation, etc. Collected data can also be identified by well, region, and other criteria, and can be sorted to allow data to be searched and analyzed. It is understood that many different storage mechanisms can be used to store the collected data in database 128.
With further reference to Figure 1B, an environment 160 (not to scale) illustrates a more detailed embodiment of a portion of region 118, with drill rig 110 located on surface 162. A drill plan has been formulated with in order to drill a hole 164 that extends into the ground to a true vertical depth (TVD) 166. Hole 164 extends through layers 168 and 170, stopping at layer 172, and not reaching the layers underlying 174 and 176. Hole 164 can be directed to a target area 180 located on layer 172. Target 180 can be a subsurface point or points defined by coordinates or other markers that indicate where hole 164 is to end or can simply define a depth range within which hole 164 is to remain (eg, layer 172 itself). It is understood that target 180 can be any
<img file="MX351981B_D0012.tif" />
shape and size, and can be defined in any way. Consequently, the target 180 may represent an end point of the hole 164 or it may extend to the extent that it can realistically be drilled. For example, if drilling includes a horizontal component and the goal is to follow layer 172 as much as possible, the goal may simply be layer 172 itself and drilling can continue until a limit is reached, such as a boundary. property or a physical limitation to the length of the drillstring. A fault 178 has displaced a portion of each layer downward. Consequently, hole 164 is located in undisplaced layer portions 168a to 176a, while portions 168b to 176b represent the displaced layer portions.
Current drilling techniques frequently involve directional drilling to hit a target, such as target 180. The use of directional drilling generally increases the amount of reserves that can be obtained and also increases the rate of production, sometimes considerably. For example, the directional perforation used to provide the horizontal portion shown in Figure 1B increases the length of the hole in layer 172, which is the target layer in our example. Directional drilling can also be used to modify the angle of the hole to address faults, such as fault 178 that has displaced layer portion 172b. Other uses of directional drilling include deviating the trajectory of an existing well to reach a different target area or a lost target area, drilling accessories
<img file="MX351981B_D0013.tif" />
abandoned near the borehole, drilling in reach or otherwise inaccessible (for example, under populated areas or bodies of water), providing a relief well for an existing well, and increasing the capacity of a well by branching and bearing multiple holes that they extend in different directions or at different vertical positions for the same well. Directional drilling is often not limited to a straight horizontal hole, but may involve staying within a layer of rock that varies in depth and thickness as illustrated by layer 172. As such, directional drilling can involve multiple vertical adjustments that complicate the hole path.
With further reference to Figure 1C, which illustrates one embodiment of a portion of hole 164 of Figure 1B, horizontal well drilling clearly introduces significant drilling challenges that do not exist in vertical wells. For example, a substantially horizontal portion 192 of the well can be started from a vertical hole 190 and one of the drilling considerations is the transition from the vertical portion of the well to the horizontal portion. This transition is generally a curve that defines an increase section194 that begins in the vertical portion (called the kick off point and represented by line 196) and ends in the horizontal portion (represented by line 198 ). The change in inclination by the measured length drilled is normally referred to as a rate of angular increase and is often defined in degrees per hundred feet drilled. For example, the rate of angular increase can be 6730
<img file="MX351981B_D0014.tif" />
meters (67,100 feet), indicating that there is a change of six degrees · d »inclination for every thirty meters drilled. The rate of angular magnification for a particular magnification section can remain relatively constant or it can vary.
The rate of angular increase depends on factors such as the formation through which the hole 164 is to be drilled, the path of the hole 164, the tube, and the particular bit holders / BHA components used (e.g., length, diameter, flexibility , strength, mud motor deflection setting, and drill bit), mud type and flow rate, horizontal displacement, stabilization, and pitch required. Too aggressive an angular rate of increase can lead to problems such as severe doglegs (for example, sudden changes in hole direction) that can make it difficult or impossible to empty the casing or perform other necessary tasks in the hole 164 Depending on the severity of the error, the hole 164 may require elongation or it may be necessary to reverse the bit and form a new conduit. Such mistakes cost time and money. However, if the rate of angular increase is too cautious, significant additional time can be added to the drilling process because it is generally slower to drill a curve than to drill a straight. Additionally, drilling a curve is more complicated and increases the possibility of drilling errors (eg, top feed and bottom discharge that can occur trying to keep the bit on the planned path).
<img file="MX351981B_D0015.tif" />
IMPI
INSTITUTE MEXICANO DE LA «OWtOAO INDUSTRIAL
Two modes of drilling, known as -poi lotauiún and sliding, are commonly used to form hole 164. Rotary drilling, also called rotary drilling, uses a top drive unit or rotary table to rotate the drillstring. Rotary drilling is used when drilling is to occur along a straight path. Slide drilling, also called directional drilling, uses a downhole mud motor with an adjustable flex housing and does not rotate the drillstring. Instead, slide drilling uses hydraulic power to drive the downhole motor and bit. Slide drilling is used to control the direction of the well.
To perform a slide, the drillstring rotation is stopped. Based on feedback from gauge accessories such as an MWD tool, adjustments are made to the drillstring. These adjustments continue until the orientation of the downhole tool indicates that the direction of motor flex is oriented toward the direction of the desired hole deviation. Once the desired orientation is achieved, pressure is applied to the drill bit, causing the drill bit to move in the direction of deflection. Once sufficient distance and angle have been increased, a transition back to rotation mode is achieved by rotating the drillstring. This rotation of the drillstring neutralizes directional deflection caused by flex in the motor as it rotates.
<img file="MX351981B_D0016.tif" />
<img file="MX351981B_D0017.tif" />
INSTITUTE
OF THE PRÜhÚMft IN & USWAt continuously around the center line of the hole.
Referring back to Figure ^ 1A, formulating a drilling plan for rig 110 may include processing and analyzing the data collected in database 128 to create a more efficient drilling plan. Additionally, once drilling has begun, the data collected can be used in conjunction with current data from the rig 110 to improve drilling decisions. Accordingly, an on-site controller 144 is coupled to rig 110 and can also be coupled to database 128 via one or more wired and / or wireless communication channel (s) 146 Other inputs 148 may also be provided at the on-site controller 144. In some embodiments, the on-site controller 144 may function as a separate device with the rig 110. For example, on-site controller 144 cannot be communicatively coupled to database 128. Although they are shown being positioned near or on rig 110 in the example at hand, it is understood that some or all of the components of the on-site controller 144 can be distributed and located at other sites in other modes.
On-site controller 144 may be all or part of a surface steerable system. Database 128 may also be part of the surface steerable system. As will be described in greater detail below, the surface steerable system can be used to plan and control drilling operations based on information from
<img file="MX351981B_D0018.tif" />
IMPI
CNSnrUTO MEXICANO OSUPOIWAD INDUSTRIAL input, including feedback from the process itself &
Surface steerable system can be used to perform operations such as receiving drilling data representing a drilling trajectory and other drilling parameters, calculating a drilling solution for the drilling trajectory based on received data, and other available data (e.g. example, equipment characteristics), implementation of the drilling solution on the 110 drilling rig, monitor the drilling process to assess whether the drilling process is within a defined margin of error of the drilling path and / or calculate corrections for the drilling process if the drilling process is outside the margin of error.
Referring to Figure 2A, a diagram 200 illustrates one mode of information flow for a surface steerable system 201 from the perspective of the on-site controller 144 of Figure 1A. In the example at hand, the drill rig 110 in Figure 1A includes drilling accessories 216 used to drill a hole, such as a top drive unit or rotary drive accessories that are attached to the drillstring and BHA and are configured to rotate the drillstring and apply pressure to the bit. The rig 110 may include control systems such as a WOB / differential pressure control system 208, a position / rotary control system 210, and a fluid circulation control system 212. The control systems 208, 210, and 212 can be used to monitor and
<img file="MX351981B_D0019.tif" />
change rig settings, tale 'NDUJTíuV
<img file="MX351981B_D0020.tif" />
differential pressure to alter the ROP or radial orientation of the tool orientation, change the drilling mud flow rate, and perform other operations.
Drilling equipment 110 may also include a sensor system 214 to obtain sensor data about the drilling operation and drilling equipment 110, including downhole accessories. For example, the sensor system 214 may include measurement-while-drilling (MWD) and / or recording-while-drilling (LWD) components for obtaining information, such as tool orientation and / or formation of record information, that can be saved for later retrieval, transmitted with a delay or in real time using any of the various means of communication (e.g. wireless, wired, or mud pulse telemetry), or otherwise transferred to the on-site controller 144. Such information may include information related to hole depth, bit depth, inclination, azimuth, true vertical depth, gamma count, riser pressure , mud flow, rotations per minute (RPM), auger speed, ROP, WOB, and / or other information. It is understood that all or part of the sensor system 214 can be incorporated in one or more of the control systems 208, 210, and 212, and / or in the drilling accessories 216. Because the drilling equipment 110 is can be configured in many different ways, it is understood that these systems of ”IMPI MEXICAN INSTITUTE OF PROPERTY INDUSTRIAL control may be different in some modalities, and may be combined or further divided into several subsystems.
The on-site controller 144 receives input information 202. The input information 202 may include information that is preloaded, received and / or updated in real time. The input information 202 may include a well plan, regional formation history, one or more drilling engineer parameters, MWD tool orientation / slope information, LWD gamma / resistivity information, economic parameters, reliability parameters, and / or other decision guiding parameters. Some of the entries, such as the regional formation history, may be available in a drill cube 216, which may include the database 128 of Figure 1A and one or more processors (not shown), while it may have access or load other entries from other sources. For example, a network interface can be used to interact directly with the on-site controller 144 to upload the well plan and / or parameters to the drilling engineer. Input information 202 is fed into on-site controller 144 and, after processing by on-site controller 144, results in control information 204 that is output to drilling rig 110 (e.g., to control systems 208 , 210, and 212). Drill rig 110 (eg, through systems 208, 210, 212, and 214) provides feedback information 206 to on-site controller 144. The feedback information 206 subsequently serves as input to the on-site controller 144, enabling the on-site controller 144
<img file="MX351981B_D0021.tif" />
<img file="MX351981B_D0022.tif" />
IMPI
INSTITUTE MEXICO DE LA MOHEOaO to verify that current control information is producing the desired results or to produce new information on drilling equipment control 110.
The on-site controller 144 also provides output information 203. As will be described in greater detail later, the output information 203 may be stored on the on-site controller 144 and / or sent off-site (eg, to the base data 128). The output information 203 can be used to provide updates to the database 128, as well as provide alerts, request decisions, and transmit other data related to the drilling process.
Referring to Figure 2B, an embodiment of a display 250 that can be provided by the on-site controller 144 is illustrated. The display 250 provides many different types of information in an easily accessible format. For example, the presentation 250 may be a display screen (eg, a monitor) that is attached to or is part of the on-site controller 144.
The display 250 provides visual indicators such as a hole depth indicator 252, a drill depth indicator 254, a GAMMA indicator 256, a tilt indicator 258, an azimuth indicator 260, and a TVD indicator. Other indicators may also be provided, including an ROP indicator 264, a specific mechanical energy (MSE) indicator 266, a differential pressure indicator 268, a riser pressure indicator 270, an indicator
<img file="MX351981B_D0023.tif" />
IMPI
MEXICAN INSTITUTE OF PROPERTY INDUSTRIAL flow rate 272, a rotary indicator of RPM 274, an indicator, of auger speed 276, and a indicator of WOB 278.
All or some of the indicators 264, 266, 268, 270, 272, 274, 276 and / or 278 may include a marker that represents a target value. For purposes of example, the markers are set as the following values, but it is understood that any desired target value can be represented. For example, the ROP indicator 264 may include a marker 265 that indicates that the target value is 0.0042 meters / second (fifty feet / hour). The MSE indicator 266 may include a marker 267 indicating that the target value is 5.36 MPa (thirty-seven ksi). Differential pressure gauge 268 may include a marker 269 indicating that the target value is 1.38 MPa (two hundred psi). The ROP indicator 264 may include a marker 265 which indicates that the target value is 0.0042 meters / second (fifty feet / hour). The riser pressure gauge 270 may not have any markers in our example. Flow indicator 272 may include a marker 273 indicating that the target value is 1.89 cubic meters per minute (five hundred gpm). The rotary RPM indicator 274 may include a marker 275 that indicates that the target value is zero RPM (due to slip). The auger speed indicator 276 may include a marker 277 indicating that the target value is 2.5 Hz (one hundred and fifty RPM). The WOB flag 278 may include a marker 279 indicating that the target value is ten klbs. Although it is only marked with respect to indicator 264, each of the
<img file="MX351981B_D0024.tif" />
IMPI
MEXICAN INSTITUTE
INDUSTRIAL PROPERTY indicators may include a colored band or other dizziness · stop inding, for example, if the respective measurement value is within a safe range (for example, indicated by the color green), within a range of caution (for example, indicated by yellow), or within a danger range (for example, indicated by red). Although not shown, in some embodiments, multiple markers may be present in a single indicator. Markers may vary in color and / or size.
A graphical diagram 280 can visually indicate depth versus one or more measurements (eg, it can represent log entries relative to a depth of processing diagram). For example, graphical diagram 280 may have a y-axis representing depth and an x-axis representing a measurement such as GAMMA 281 count (as shown), ROP 283 (for example, empirical ROP and normalized ROP), or resistivity. An autopilot button 282 and a rocker button 284 can be used to control activity. For example, the autopilot button 282 can be used to connect or disconnect an autopilot, while the oscillation button 284 can be used to directly control the oscillation of the drillstring or connect / disconnect an external hardware device or controller through software and / or hardware.
A pie chart 286 can provide information on the orientation of the current and historical tool (for example, how
<img file="MX351981B_D0025.tif" />
points to the flex). For illustration purposes, circle diagram 286 represents three hundred and sixty degrees. A series of circles within the pie chart 286 can represent a timeline of the tool orientations, with the sizes of the circles indicating the temporal position of each circle. For example, the largest circles may be more recent than the smallest circles, so the largest circle 288 may be the most recent reading and the smallest circle 286 may be the oldest reading. In other modalities, the circles can represent energy and / or progress made through size, color, shape, a number within a circle, etc. For example, the size of a certain circle may represent an accumulation of orientation and progress for the period represented by the circle. In other embodiments, concentric circles representing time (for example, with the outer portion of pie chart 286 being the most recent time and the center point being the oldest time) can be used to indicate energy and / or progress. (for example by means of color and / or drawings such as dashes or dots, rather than a solid line).
The pie chart 286 may also be color coded, with the color coding existing in a band 290 around the pie chart 286 or positioned or represented in other ways. Color coding can use colors to indicate activity in a certain direction. For example, the color red may indicate that the level of<sup>22</sup>
INSTITUTE MEXICANO DE LA PROPERTY Owm INDUSTRIAL highest activity, while blue may indicate the lowest activity level. Also, the range of the arc in degrees of a color can indicate the amount of deviation. Consequently, a relatively narrow arc of red (for example, thirty degrees) with a relatively wide arc of blue (for example, three hundred degrees) can indicate that most of the activity is occurring in a certain orientation of the tool with little deviation. . For illustration purposes, the color blue extends from approximately 22 to 337 degrees, the green color extends from approximately 15 to 22 degrees, and 337 to 345 degrees, the yellow color extends a few degrees around the 13 and 345 degrees and the color red ranges from about 347 to 10 degrees. Transition colors or shadows can be used, for example orange marking the transition between red and yellow and / or a blue light marking the transition between blue and green.
This color coding allows the display 250 to provide an intuitive summary of how small the standard deviation is and how much energy intensity is being spent in the appropriate direction. Additionally, the energy center can be visualized with respect to the target. For example, display 250 may clearly show that the target is at ninety degrees, but the center of the energy is at forty-five degrees.
Other indicators may be present, such as a slip indicator 292 to indicate how much time remains until it occurs.
<img file="MX351981B_D0026.tif" />
IMPI
MEXICAN INSTITUTE
DE LA »-ROI> IEDAÍ> industrial a landslide and / or how much time remains for a current landslide. For example, the slip indicator can represent a time, a percentage (for example, the current slip is fifty-six percent), a distance traveled, and / or distance remaining. The slip indicator 292 may graphically display information using, for example, a colored bar 293 that increases or decreases with the progress of the slide. In some embodiments, the slip indicator may be incorporated into the pie chart 286 (for example, around the outer edge with an increase / decrease band), while in other embodiments the slip indicator may be a separate indicator such as a meter, bar, gauge, or other type of indicator.
An error flag 294 may be present to indicate a magnitude and / or direction of error. For example, the error indicator 294 may indicate that the position of the estimated drill bit is at a certain distance from the planned path, with a location of the error indicator 294 around the pie chart 286 representing direction. For example, Figure 2B illustrates an error magnitude of 4.57 meters (fifteen feet) and an error direction of fifteen degrees. Error indicator 294 can be any color, but it is red, for the purposes of the example. It is understood that the error flag 294 may represent zero if there is no error and / or it may represent that the bit is on track in other ways, such as being green. The colors of
<img file="MX351981B_D0027.tif" />
IMPI
INSTITUTE MEXICANO OS LA INDUSTRIAL PROPERTY transition, such as yellow, you can use ρ3Γ <Γ ludiudi LaiILIDADtü · error variables. In some embodiments, error flag 294 cannot appear unless a magnitude and / or direction error occurs. A marker 296 can indicate an ideal sliding direction. Although not shown, other indicators may be present, such as a bit life time indicator to indicate an estimated life time for the current bit based on a value such as time and / or distance.
It is understood that the display 250 can be arranged in many different ways. For example, colors can be used to indicate normal operation, warnings, and problems. In such cases, the numeric indicators can display numbers of one color (for example, green) for normal operation, they can use another color (for example, yellow) for warnings, and they can use yet another color (for example, red ) if a serious problem occurs. The indicators may also flash or otherwise indicate an alert. Gauge indicators can include colors (for example, green, yellow, and red) to indicate operational conditions and can also indicate the target value (for example, an ROP of 0.0084 meters / second (100 feet / hour)). For example, the ROP indicator 268 may have a green bar to indicate a normal operating level (for example, 0.00084 to 0.0254 meters / second (10 to 300 feet / hour)), a yellow bar to indicate an operating warning level (for example, 0.0254 to 0.0304 meters / second <* Ι · Α
<img file="MX351981B_D0028.tif" />
(300 to 360 feet / hour)), and a red pad inrlfr ¡ιτττπ ^ i'h dangerous operation or otherwise outside the parameter (for example, 0.0304 to 0.033 meters / second (360 to 390 feet / hour)). The 268 ROP indicator can also display a marker at 0.0084 meters / second (100 feet / hour) to indicate the desired target ROP.
In addition, the use of numerical indicators, gauges, and similar display indicators can be varied based on factors such as the information to be conveyed and the personal preference of the observer. Accordingly, display 250 can provide a customizable view of various drilling processes and information from a particular individual involved in the drilling process. For example, the surface steerable system 201 may allow a user to customize the display 250 as desired, although certain features (eg, riser pressure) can be locked to prevent removal. This lock can prevent a user from intentionally or accidentally deleting important piercing information from the presentation. Other features can be configured according to preferences. Consequently, the level of personalization and the information displayed on the presentation 250 can be controlled based on who is viewing the presentation and their role in the punching process.
Referring again to Figure 2A, it is understood that the level of integration between the on-site controller 144 and the rig 110 may depend on factors such as the configuration of the
<img file="MX351981B_D0029.tif" />
IMPI • NSTITUT<sup>0</sup> MEXICANA DI LA
INDUSTRIAL rig 110 and if the on-site controller 144 is capable of fully adjusting that configuration. One or more of the control systems 208, 210, and 212 may be part of the on-site controller 144, they may be third-party systems, and / or they may be part of the rig 110. For example, an older rig. 110 may have relatively few interfaces with which the on-site controller 144 is able to interact. For illustrative purposes, if a knob must be physically turned to adjust the WOB on rig 110, on-site controller 144 will not be able to directly manipulate the knob without a mechanical actuator. If such an actuator is not present, the on-site controller 144 can output the knob setting to a display, and an operator can subsequently rotate the knob based on the setting. Alternatively, the on-site controller 144 can be coupled directly to the knob's electrical wiring.
However, newer and more sophisticated drilling equipment 110, such as equipment having electronic control systems, may have interfaces with which the on-site controller 144 can interact for direct control. For example, an electronic control system can have a defined interface and the on-site controller 144 can be configured to interact with the defined interface. It is understood that, in some modalities, direct control cannot be allowed, even if it is possible. For example, the on-site controller 144 can be configured to display the configuration on a screen for approval, and can send
IMPI ^
MEXICAN INSTITUTE
FROM PROPERTY V> «m3S INDUSTRIAL subsequently the configuration to the appropriate control system only when the configuration has been approved.
Referring to Figure 3, one embodiment of an environment 300 illustrates multiple communication channels (indicated by arrows) that are commonly used in existing directional drilling operations that do not have the benefit of the surface steerable system 201 of Figure 2A. . The communication channels associate several individuals involved in the drilling process. Communication channels can support phone calls, emails, text messages, faxes, data transfers (for example, file transfers over networks), and other types of communications.
Individuals involved in the drilling process may include a 302 drilling engineer, 304 geologist, 306 directional well driller, 308 shift manager, 310 well driller, and 312 rig floor crew. more company representatives (eg company representative) 314 may also be involved. Individuals can be employed by different organizations, which can further complicate the communication process. For example, Drilling Engineer 302, Geologist 304, and Company Representative 314 may work for an operator, Directional Driller 306 may work for a directional drilling service provider, and Shift Manager 308, well driller 310, and drilling floor crew 312 can work to
<img file="MX351981B_D0030.tif" />
IMPI
MEXICAN INSTITUTE
I gave THE INDUSTRIAL PROPERTY an equipment service provider.
Drilling engineer 302 and geologist 304 are often located at a remote location from the drill rig (eg, a central office / drill hub). Drilling engineer 302 can develop a well 318 plan and can make drilling decisions based on information from the drill rig. The geologist 304 can perform tasks such as formation analysis based on seismic, gamma, and other data. Directional Well Driller 306 is generally located on the rig and instructs Well Driller 310 based on the current well plan and feedback from Drilling Engineer 302. Well Driller 310 manages actual drilling operations And you can depend on the 312 Rig Floor Crew for certain tasks. The shift manager 308 may be in charge of managing the entire rig and its operation.
The following is a possible example of a communication process within environment 300, although it is understood that many communication processes can be used. The use of a particular communication process may depend on factors such as the level of control maintained by various groups within the process, how closely the communication channels are strictly enforced, and similar factors. In the example at hand, Directional Driller 306 uses well plan 318 to give drilling instructions to the
<img file="MX351981B_D0031.tif" />
well driller 310. Well driller 310 controls drilling using control systems such as control systems 208, 210, and 212 of Figure 2A. During drilling, information from sensing equipment such as 316 downhole MWD rig and / or 320 rig sensors may indicate that a 6096 meter (twenty feet) larger formation layer has been reached than expected by geologist 304. This information is relayed back to Drilling Engineer 302 and / or Geologist 304 through Company Representative 314, and may be relayed through Directional Well Driller 306 prior to reaching Company Representative 314.
Drilling engineer 302 / well planner (not shown), either alone, or in conjunction with geologist 306, can modify the well 318 plan or make other decisions based on the information received. The modified well plan and / or other decisions may or may not be relayed through the company representative 314 to the 306 directional well driller, who then tells the 310 well driller how to drill. Well driller 310 can modify fixture settings (eg, tool orientation) and, if necessary, transmit commands to drill floor crew 312. For example, a change to the WOB may be made by the Well driller 310 changing a setup, while a drill maneuver may require the involvement of the 312 rig floor crew. Consequently, the level of participation of different individuals can
<img file="MX351981B_D0032.tif" />
IMPI
MEXICAN INSTITUTE OF PROPERTY INDUSTRIAL vary depending on the nature of the decision to be made and the task to be carried out. The following example may be more complex than the one described. Various intermediary individuals may be involved and, depending on the chain of communication, some of the instructions may be relayed through the 308 shift manager.
Environment 300 presents many opportunities for communication disruptions because information is transmitted through the various communication channels, in particular, due to the varying types of communication that can be used. For example, verbal communications over the phone can be misinterpreted and, unless recorded, there is no record of what was said. Additionally, accountability can be difficult or impossible to enforce, because someone may provide an authorization but deny it or claim that they meant something else. Without a record of the information that is transmitted through the various channels and the authorizations used to approve changes to the drilling process, communication disruptions can be difficult to track and address. Because many of the communication channels illustrated in Figure 3 transmit information through one individual to other individuals (for example, an individual can serve as a conduit of information between two or more individuals), the risk of disruption increases due to to the possibility that errors may be introduced into the information.
Even if everyone involved does their part, the mistakes of
<img file="MX351981B_D0033.tif" />
IMPI
MEXICAN INSTITUTE
Say LA P »OPltI> AD industrial drilling can be magnified while waiting for a response. For example, a message may be sent to geologist 306 that a formation layer appears to be larger than expected, but geologist 306 may be asleep. Drilling can continue while waiting for geologist 306 and continued drilling can amplify the error. Such mistakes can cost hundreds of thousands or millions of dollars. However, environment 300 does not provide any way to determine whether geologist 304 has received the message and there is no way to easily notify geologist 304 or contact someone when there is no response within a defined period. Even if alternate contacts are available, such communications can be cumbersome and there may be difficulties in providing all the information that the alternate would need to make a decision.
Referring to Figure 4, one embodiment of an environment 400 illustrates multiple communication channels that may exist in a directional drilling operation that has the benefit of the surface steerable system 201 of Figure 2A. In the present example, the surface steerable system 201 includes the drill cube 216, which includes the regional database 128 of Figure 1A and processing unit (s) 404 (eg, computers). Drill hub 216 also includes communication interfaces (e.g., web portals) 406 that can be accessed by computing devices capable of wireless and / or wired communications, including wireless computers.
<img file="MX351981B_D0034.tif" />
desks, laptops, tablets, telephones — TTcligaiUub, personal digital assistants (PDAs). On-site controller 144 includes one or more local databases 410 (where local is from the perspective of on-site controller 144) and processing unit (s) 412.
Drill hub 216 is located remotely from on-site controller 144, and various individuals associated with the drilling operation interact either through drill hub 216 or via on-site controller 144. In certain embodiments, an individual may access the drilling project through both drill bucket 216 and through on-site controller 144. For example, the directional well driller 306 can use the drill bucket 216 when it is not at the drilling site and can use the on-site controller 144 when it is at the drilling site.
Drilling engineer 302 and geologist 304 can access surface steerable system 201 remotely through portal 406 and adjust various parameters such as equipment limit controls. Other actions can also be supported, such as authorizing a request from Directional Driller 306 to deviate from the well plan and evaluate the performance of the drilling operation. Directional well driller 306 may be located on rig 110 or offsite. Being elsewhere outside the company (for example, in drill bucket 216 or elsewhere) allows a single directional well driller to monitor multiple
<img file="MX351981B_D0035.tif" />
IMPI
MEXICAN INSTITUTE
OF INDUSTRIAL PROPERTY drilling equipment. When located elsewhere outside the company, Directional Driller 306 may have access to Surface Steerable System 201 through Portal 406. When on site, Directional Driller 306 may have access to Steerable System through the on-site controller 144.
The well driller 310 can receive instructions through the on-site controller 144, thereby reducing the possibility of misunderstandings and ensuring that the instructions were received. Although Shift Manager 308, Rig Floor Crew 312, and Company Representative 314 are shown communicating via Driller 310, it is understood that they may also have access to on-site controller 144. Other individuals, such as a MWD technician 408, may have access to the surface steerable system 201 through the drilling hub 216, the on-site controller 144, and / or an individual such as the well driller 310.
As illustrated in Figure 4, many of the individuals involved in a drilling operation can interact through the surface steerable system 201. This allows information to be tracked as it is handled by the various individuals involved in a decision. particular. For example, the airship surface system 201 can track which individual submitted information (or if the information was presented automatically), who viewed the information, who made decisions, when events occurred, and similar information-based issues.
<img file="MX351981B_D0036.tif" />
IMPI
MEXICAN INSTITUTE
OF INDUSTRIAL PROPERTY
This provides a complete record of the way the information was effected through the surface steerable system 201 and led to a particular drilling decision. This also provides revision tracking due to changes to the well plan, which in turn allows decision chains to be examined. These reviews can lead to improved decision-making processes and more effective responses to problems as they occur.
In some embodiments, documentation produced using surface steerable system 201 can be synchronized and / or merged with other documentation, such as that produced by third party systems such as the WelIView product produced by Platoon Computer Enterprises Ltd. of Calgary, Canada. In such modes, documents, database files, and other information produced by the surface-steerable system 201 are synchronized to avoid problems such as redundancy, mismatched file versions, and other complications that can occur in files. projects where large numbers of documents are produced, edited, and transmitted by a relatively large number of people. .
The surface airship system 201 may also enforce information formats and other restrictions to ensure that predefined criteria are met. For example, an electronic format provided by surface steerable system 201 in response to an authorization request may require some γγ — TimiTMtm 11 m _ to be completed.
<img file="MX351981B_D0037.tif" />
fields before presentation. This ensures that the person who makes decisions has the relevant information before making decisions. If the information for a required field is not available, the surface steerable system 201 may require an explanation to be entered as to why the information is not available (eg, sensor failure). Therefore, a level of uniformity can be imposed by the surface steerable system 201, while exceptions can be defined to allow the surface steerable system 201 to handle various situations.
The airship surface system 201 can also send alerts (eg, email or text message alerts) to notify one or more individuals of a particular problem, and the list of recipients can be customized based on the problem. Additionally, the contact information can be time-based, so that the surface steerable system 201 can know when a particular individual is available. In such situations, the surface steerable system 201 may attempt to automatically communicate with an available contact instead of waiting for a response from a contact that is likely to be unavailable.
As described above, the surface steerable system 201 can present a customizable display of various drilling processes and information from a specific individual involved in the drilling process. For example, Drilling Engineer 302 can view a presentation displaying information
<img file="MX351981B_D0038.tif" />
IMPI
INSTITUTE .MEXICANO
OF INDUSTRIAL PROPERTY relevant to the tasks of the drilling engineer, yehgeologist 004 may · view a different presentation that includes additional and / or more detailed training information. This personalization allows each individual to receive information necessary for their specific role in the drilling process while at the same time minimizing or eliminating unnecessary information.
Referring to Figure 5, one embodiment of an environment 500 illustrates a data stream that may be supported by the surface steerable system 201 of Figure 2A. Data flow 500 starts at block 502 and can move through two branches, although some blocks on one branch cannot occur before other blocks on the other branch. One of the branches involves drill bucket 216 and the other branch involves on-site controller 144 on drill rig 110.
In block 504, a geological survey is carried out. The results of the survey are examined by geologist 304 and a formation report 506 is produced. The formation report 506 details formation layers, rock type, layer thickness, layer depth, and similar information that can be used to develop a well plan. In block 508, a well plan has been developed by a well planner 524 and / or drilling engineer 302 based on the formation report and information from regional database 128 in drill cube 216. Block 508 may include selecting a BHA and setting control limits. The well plan is stored in database 128. Drilling engineer 302 can also adjust operating parameters of
<img file="MX351981B_D0039.tif" />
drilling in step 510 which will also be stored r ^ rrlarphraseTieTta ^ 128.
On the other leg, drill rig 110 is built on block 512. At this point, as illustrated by block 526, the well plan, BHA information, control limits, drilling data historical data, and control commands can be sent from database 128 to local database 410. Using the received information, directional well driller 306 enters actual BHA parameters at block 514. The company representative 314 and / or the directional well driller 306 can verify the performance of the control limits in block 516, and the control limits are stored in local database 410 of the on-site controller 144. The Control limit performance can include multiple levels such as a warning level and a critical level corresponding to taking no action within feet / minutes.
Once drilling begins, a diagnostic logger (described in greater detail later) 520 that is part of the on-site controller 144 records drilling-related information such as sensor and maneuvering information and stores the information in the database. local data 410 in block 526. Information is sent to database 128. Alerts are also sent from on-site controller 144 to drill bucket 216. When an alert is received from drill bucket 216, an alert notification 522 is sent to specified individuals, such as drilling engineer 302, geologist 304, and
<img file="MX351981B_D0040.tif" />
IMPI
MEXICAN INSTITUTE OF PROPERTY INDUSTRIAL representative of the company 314. The actual recipient puwdtí Vclllaf COR Case 'in the content of the alert message or in other criteria. Alert notification 522 can result in well plan and BHA information, and control limits are modified in block 508 and parameters are modified in block 510. These modifications are saved in database 128 and are transferred to local database 410. The BHA can be modified by Directional Driller 306 in block 518, and the changes propagate through blocks 514 and 516 with possible updated control limits. Consequently, the surface steerable system 201 can provide a more controlled flow of information than that which can occur in an environment without such a system.
The flowcharts described herein illustrate various example functions and operations that can occur within various environments. Consequently, these flowcharts are not complete as various steps can be excluded in order to clarify the aspect being described. For example, it is understood that some actions, such as network authentication processes, notifications, and handshaking, may have been performed prior to the first stage of a flow chart. Such actions may depend on the particular type and configuration of communications initiated by the on-site controller 144 and / or the drill hub 216. Furthermore, other communication actions can occur between the illustrated stages or simultaneously with the illustrated stages.
<img file="MX351981B_D0041.tif" />
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MEXICAN INSTITUTE OF INDUSTRIAL PROPERTY
The surface steerable system 201 includes large amounts of data specifically related to various drilling operations because it is stored in databases such as databases 128 and 410. As described with respect to Figure
1A, this data can include data collected from many different locations and can correspond to many different drilling operations. The data stored in database 128 and other databases can be used for a variety of purposes, including data extraction and analysis, which can aid in such processes as equipment comparisons, drilling plan formulation, drilling planning, convergence, recalibration forecast, and automatic tuning (for example, drilling performance optimization). Some processes, such as equipment comparisons, cannot be performed in real time using input data, while others, such as automatic tuning, can be performed in real time or near real time. Consequently, some processes can be run on the drill hub 216, other processes can run on the on-site controller 144, and still other processes can run on both the drill hub 216 and the on-site controller 144 with communications that they occur before, during and / or after processes are executed. As described in several examples below, some processes can be triggered by events (eg, recalibration forecast) while others may be running (eg, automatic tuning).
<img file="MX351981B_D0042.tif" />
For example, in equipment comparison, loo date *, of * different drilling operations (for example, drilling of wells 102, 104, 106, and 108) can be normalized and used to compare equipment wear , performance and other similar factors. For example, the same bit may have been used to drill wells 102 and 106, but the drilling may have been done using different parameters (eg, rotational speed and WOB). By normalizing the data, the two bits can be compared more efficiently. Normalized data can be further processed to improve drilling efficiency by identifying which bits are most effective for particular rock layers, which drilling parameters resulted in the best ROP for a particular formation, ROP versus reliability trade-offs of various augers in various rock layers, and similar factors. Such comparisons can be used to select a bit for another drilling operation based on formation characteristics or other criteria. Accordingly, by extracting and analyzing the data available via the surface steerable system 201, an optimal equipment profile can be developed for different drilling operations. The equipment profile can later be used to plan future wells or to increase the efficiency of a well being drilled. This type of drilling optimization can become more and more precise as more data is collected and analyzed.
<img file="MX351981B_D0043.tif" />
In formulating the drilling plan, the data available through the surface steerable system 201 can be used to identify possible formation characteristics and select an appropriate equipment profile. For example, geologist 304 may use local data obtained from the planned location of drill rig 110 along with regional data from database 128 to identify possible locations of layers 168a through 176a (Figure 1B). Based on that information, the drilling engineer 302 can create a well plan that will include the rise curve in Figure 1C.
Referring to Figure 6, a method 600 illustrates one mode of an event-based process that can be executed by the on-site controller 144 of Figure 2A. For example, software instructions necessary to execute method 600 can be stored on a computer-readable storage medium of the on-site controller 144 and subsequently executed by processor 412 that is coupled to the storage medium and is also part of the on-site controller. 144.
At step 602, the on-site controller 144 receives inputs such as a planned path for a hole, formation information for the hole, accessory information for the rig, and a set of cost parameters. The cost parameters can be used to guide the decisions made by the on-site controller 144 as will be explained in more detail below. Entries can be received in many different ways, including receiving downloads from
<img file="MX351981B_D0044.tif" />
IMPI
MEXICAN INSTITUTE OF PROPERTY INDUSTRIAL documents (for example, spreadsheet), access to a database (for example, database 128 in Figure 1A), and / or receipt of manually entered data.
In step 604, the planned trajectory, training information, accessory information, and set of cost parameters are processed to produce control parameters (eg, control information 204 of Figure 2A) for the equipment. drilling 110. The control parameters can define the settings for the various drilling operations to be performed by the rig 110 to form the hole, such as WOB, mud flow, tool orientation, and the like. In some modes, the control parameters can also define specific accessory selections, such as a specific bit. In the example at hand, step 604 is directed to defining initial control parameters for drilling equipment 110 prior to the start of drilling, but it is understood that step 604 can be used to define control parameters for the equipment. drilling 110 even after drilling has started. For example, the on-site controller 144 can be put in place before drilling or it can be put in place after drilling has started, in which case the method 600 can also receive current hole information at stage 602.
In step 606, the control parameters are output for use by drilling rig 110. In modes where the controller is in · Π II ··. . .
situ 144 is directly coupled to rig 110, generating the control parameters may include sending the control parameters directly to one or more of the rig 110's control systems (for example, the control systems 210, 212, and 214). In other embodiments, the generation of the control parameters may include displaying the control parameters on a screen, printing the control parameters, and / or copying them to a storage medium (eg, a drive). Universal Serial Bus (USB)) to be transferred manually.
At step 608, feedback information received from rig 110 (eg, from one or more of control systems 208, 210, and 212 and / or sensor system 214) is processed. The feedback information can provide the on-site controller 144 with the current state of the hole (eg, depth and pitch), the drilling equipment, and the drilling process, including an estimated position of the bit in the hole. Processing may include extracting desired data from the feedback information, normalizing the data, comparing the data with desired or ideal parameters, determining whether or not the data is within a margin of error. defined, and / or any other processing steps necessary to make use of the feedback information.
At step 610, the on-site controller 144 may take actions
<img file="MX351981B_D0045.tif" />
IMPI (Mexican Institute BE LA MOPIEDaD INDUSTRIAL) based on the occurrence of one or more defined events. For example, an event may trigger a decision on how to proceed with drilling in the most profitable manner. Events can be triggered by accessory malfunctions, path differences between the measured hole and the planned hole, upcoming maintenance periods, unexpected geological readings, and any other activity or non-activity that may affect the drilling of the hole. It is understood that events can also be defined for events that have less direct impact on drilling, such as actual or anticipated labor shortages, actual or potential issues related to the licensing of mineral rights. , actual or anticipated political issues that may affect drilling, and similar actual or anticipated events. Step 610 may also result in no action being taken if, for example, drilling is proceeding without a problem and the current control parameters are satisfactory.
An event can be defined in the inputs received from step 602 or defined later. Events can also be defined on-site using on-site controller 144. For example, if rig 110 has a specific mechanical problem, one or more events can be defined to monitor that problem more thoroughly than is normally the case. could produce. In some modes, a chain of events can be implemented when the occurrence of one event triggers the monitoring of another related event. For example, a first event can trigger
<img file="MX351981B_D0046.tif" />
a notification about a potential problem with a ply¿a 'of equipment and can also activate the monitoring of a second event. In addition to triggering monitoring of the second event, triggering the first event can result in triggering additional monitoring that involves, for example, checking the piece of equipment more frequently or with a higher level of detail. If the second event occurs, the equipment can be shut down and an alarm sounds, or other actions can be taken. This allows different levels of monitoring and different levels of responses to be assigned regardless of whether they are needed.
Referring to Figure 7A, a method 700 illustrates a more detailed embodiment of the method 600 of Figure 6, particularly of step 610. Because steps 702, 704, 706, and 708 are similar or identical to steps 602 , 604, 606, and 608, respectively, of Figure 6, they are not described in detail in the present embodiment. In the example at hand, the action in step 610 of Figure 6 is based on whether an event has occurred and the action required in the event that the event has occurred.
Accordingly, at step 710, a determination I is made as to whether an event has occurred based on the inputs from steps 702 and 708. If no event has occurred, method 700 returns to step 708 If an event has occurred, method 700 moves to step 712, where calculations are performed based on information related to the event and at least one cost parameter.
<img file="MX351981B_D0047.tif" />
Industrial IMPI
It is understood that informaoinn ΐΐπΙϊοϊηη «ιΙ aiilUbW can be obtained and / or processed as part of step 712 if necessary. For example, some information can be used to determine if an event has occurred, and additional information can be retrieved and processed later to determine the specifics of the event.
In step 714, new control parameters can be produced based on the calculations in step 712. In step 716, a determination can be made as to whether or not changes to the current control parameters are necessary. For example, the calculations in step 712 may lead to a decision that the current control parameters are successful (eg, the event may not affect the control parameters). If no events are needed, method 700 returns to step 708. If changes are needed, on-site controller 144 outputs the new parameters at step 718. Method 700 may later return to step 708. In certain embodiments, the determination of step 716 may occur prior to step 714. In such embodiments, step 714 may be not executed if the current control parameters are satisfactory.
In a more detailed example of method 700, it is assumed that the on-site controller 144 is involved in drilling a hole and that approximately 182.88 meters (six hundred feet) remain to be drilled. An event has been defined that alerts on-site controller 144 when the drill bit is expected to reach a minimum level of
<img file="MX351981B_D0048.tif" />
INSTITUTE MEXICANO DE LA TROMÍDAO INDUSTRIAL
<img file="MX351981B_D0049.tif" />
efficiency due to wear and tear and this event is triggered on stage 710 at the 182.88 meter (six hundred feet) mark. The event can be triggered because the drill bit is within a certain number of revolutions before reaching the minimum level of efficiency, within a certain remaining distance (based on the type of strata, thickness, etc.) that can be drilled before reaching the minimum level of efficiency, or it can be based on some other factor or factors. Although the event in the current example is triggered before the expected minimum level of efficiency is reached in order to proactively schedule drilling changes if necessary, it is understood that the event can be triggered when the minimum level is reached. really reaches.
The on-site controller 144 can perform calculations in step 712 that take into account various factors that can be analyzed to determine how the last 182.88 meters (six hundred feet) are drilled.
These factors may include the type of rock and the thickness of the remaining 182.88 meters (six hundred feet), the expected wear of the drill bit based on similar drilling conditions, the location of the bit (e.g. depth), how much time it will take to change the bit, and a cost versus time analysis. In general, faster drilling is more profitable, but there are many trade-offs. For example, increasing the WOB or differential pressure to increase the rate of penetration can reduce the time it takes to finish the hole, but it can also wear the bit faster, which will decrease the effectiveness of the drill.
<img file="MX351981B_D0050.tif" />
IMPI
MEXICAN INSTITUTE OF PROPERTY INDUSTRIAL drilling and will reduce drilling speed. If this reduction in speed occurs too early, it may be less effective than drilling more slowly. Therefore, there are trade-offs that must be calculated. Too much WOB or differential pressure can also cause other problems, such as damage to downhole tools. If one of these problems occurs, taking time to maneuver the bit or drill a secondary hole can result in more total time to finish the hole than simply drilling slower, so faster may not be better. The advantages and disadvantages can be relatively complex, with many factors to consider.
In step 714, the on-site controller 144 produces new control parameters based on the solution calculated in step 712. In step 716, a determination is made as to whether or not the current parameters should be replaced with the new ones. parameters. For example, the new parameters can be compared with the current parameters. Whether the two sets of parameters are substantially similar (for example, as calculated based on a percentage change or margin of error of the current trajectory with a trajectory that would be created using the new control parameters) or identical to the current parameters , no change would be necessary. However, if the new control parameters require changes greater than the tolerated percentage change or are outside the margin of error, these are taken out in step 718. For example, the new control parameters can increase the WOB and also include the flow rate. from
<img file="MX351981B_D0051.tif" />
mud significantly enough to ignore the
-r -, ^ --------------... - - --previous control parameters. In other embodiments, the new control parameters can be output regardless of any difference, in which case step 716 can be skipped. In still other embodiments, the current path and the predicted path can be compared before the new ones occur. parameters, in which case step 714 may occur after step 716.
Referring to Figure 7B and with further reference to Figure 7C, a method 720 (Figure 7B) and a diagram 740 (Figure 7C) illustrate a more detailed embodiment of the method 600 of Figure 6, particularly step 610. Because of Since steps 722, 724, 726, and 728 are similar or identical to steps 602, 604, 606, and 608, respectively, of Figure 6, they are not described in detail in the present embodiment. In the example at hand, the action in step 610 of Figure 6 is based on whether or not the drilling has deviated from the planned path.
At step 730, a comparison can be performed to compare the estimated bit position and trajectory with a desired point (eg, a desired bit position) along the planned trajectory. The estimated bit position can be calculated based on information such as a survey reference point and / or represented as an output calculated by a hole estimator (as will be described later) and can include a
<img file="MX351981B_D0052.tif" />
IMPI
MEXICAN INSTITUTE OF PROPERTY INDUSTRIAL projection of the bit and / or point that represents a pinpoint of the bit if it follows its current estimated trajectory from the position of the estimated bit. Such information can be included in the inputs of step 722 and feedback information of step 728 or can be obtained in other ways. It is understood that the estimated bit position and trajectory cannot be calculated exactly, but may represent an estimate of the current location of the drill bit based on the feedback information. As illustrated in Figure 70, the estimated bit position is indicated by arrow 743 relative to the target bit position 741 along the planned path 742.
At step 732, a decision can be made as to whether the estimated bit position 743 is within a certain margin of error of the desired bit position. If the estimated bit position is within the error margin, method 720 returns to step 728. If the estimated bit position is not within the error margin, the on-site controller 144 calculates a convergence plan at step 734. Referring to Figure 7C, for the purposes of the present example, the position of the estimated bit 743 is outside the margin of error.
In some embodiments, a projected bit position (not shown) can also be used. For example, the estimated bit position 743 can be extended through calculations to determine where the bit is projected to be after a certain
<img file="MX351981B_D0053.tif" />
amount of piercing (for example, time and / or distance). This information can be used in various ways. If the estimated bit position 743 is outside the margin of error, the projected bit position 743 may indicate that the current bit trajectory will lead the bit to be within the margin of error with no action being taken. In such a scenario, action can only be taken if it will take too long to reach the projected bit position when a more optimal trajectory is available. If the estimated bit position is within the margin of error, the projected bit position can be used to determine if the current trajectory is moving the bit away from the planned trajectory. In other words, the projected boom position can be used to proactively detect that the bit is off course before the margin of error is reached. In such a scenario, action can be taken to correct the current trajectory before the margin of error is reached.
The convergence plan identifies a plan by which the bit can be moved from the estimated bit position 743 to the planned trajectory 742. It should be noted that the convergence plan can deviate the desired bit position 741 completely, since that the objective is to return the actual drill path to the planned path 742 in the most optimal manner. The most optimal way can be defined by costs, which can represent a financial value, a reliability value, a time value, and / or other values that can be defined for a trajectory of
<img file="MX351981B_D0054.tif" />
IMPI
INSTITUTE MEXICANO DE LA PROPERTY INDUSTRIAL convergence. ”~~
As illustrated in Figure 7C, an infinite number of trajectories can be selected to return the bit to the planned trajectory 742. The trajectories can start at the estimated bit position 743 or can start at other points along a projected track 752 that can be determined by calculating future bit positions based on the current bit track from the estimated bit position 752. In the example at hand, the first trajectory 744 results in the location of the bit at a position 745 (eg, a convergence point). The convergence point 745 is outside a lower limit 753 defined by a possible more aggressive correction (eg, a lower limit in a correction window). This correction represents the most aggressive possible toe path, which can be limited by factors such as a possible maximum directional change in the toe path, where any major directional change creates a dogleg that makes it difficult or impossible to empty the casing or other necessary tasks. A second trajectory 746 results in a convergence point 747, which is just at the lower limit 753. A third trajectory 748 results in a convergence point 749, which represents a mid-range convergence point. A third trajectory 750 results in a convergence point 751, which occurs at an upper limit 754 defined by a maximum convergence lag (by ~ ~<sup>η</sup> I .......... IIII · ι.
<img file="MX351981B_D0055.tif" />
MEXICAN INSTITUTE OF INDUSTRIAL RAOPIETY
<img file="MX351981B_D0056.tif" />
example, an upper limit in the correction window).
A fourth path 756 may start at a projected point or bit position 755 that is along projected path 752 and results in a point of convergence 757, which represents a mid-range point of convergence. Path 756 can be used, for example, by delaying a path change until the bit change reaches position 755. Many additional toe-in options can be opened by using projected points for the base of toe-in plans, as well as the estimated bit position.
A fifth trajectory 758 may begin at a projected point or bit position 760 that is along projected trajectory 750 and results in a convergence point 759. In such an embodiment, different convergence trajectories may include segments 15 similar or identical trajectories, such as the similar or identical trajectory shared by convergence points 751 and 759 for point 760. For example, point 760 may mark a position on path 750 where a slip segment begins (or continues from a previous slip segment) for path 758 and a straight-line path segment begins (or continues) for path 750. The surface steerable system 144 can calculate the trajectories 750 and 758 as two completely separate trajectories or it can calculate one of the trajectories as deviating from (e.g., being a daughter of) the other
<img file="MX351981B_D0057.tif" />
IMPI
INSTITUTE MEXICANO trajectory. Consequently, any path can have multiple paths that deviate from the path based on, for example, different slip points and slip times.
Each of these paths 744, 746, 748, 750, 756, and 758 can have advantages and disadvantages from the point of view of perforation. For example, one path may be longer and may require more sliding in a relatively soft rock layer, while another path may be shorter but may require more sliding through a much harder rock layer. Consequently, the trade-offs can be evaluated when selecting one of the convergence plans rather than simply selecting the most direct path for convergence. Advantages and disadvantages, for example, consider a balance between ROP, total cost, dogleg severity, and reliability. While the number of convergence plans can vary, there may be hundreds or thousands of convergence plans in some modalities and the trade-offs can be used to select one of those hundreds or thousands for implementation. The convergence plans from which the final convergence plan is selected may include plans calculated from the estimated bit position 743, as well as plans calculated from one or more projected points along the projected trajectory. .
In some modalities, straight-line projections of the convergence point vectors, after correction of the plan of the
<img file="MX351981B_D0058.tif" />
well 742, can be evaluated to predict the time and / or diaphahcia ρ3Γ35Γ following correction requirement. This assessment can be used when selecting the lowest total cost option by avoiding multiple fixes where a single more forward-looking option might be optimal. As an example, one of the solutions provided by convergence planning may result in the most profitable path to return to the 742 well plan, but may result in an almost immediate need for a second correction due to a pending deviation within the well plan. Consequently, a convergence path that merges the pending deviation with the correction by selecting a convergence point beyond the pending deviation could be selected when total costs are considered.
Diagram 740 of Figure 7C is understood to be a two-dimensional representation of a three-dimensional environment. Accordingly, the convergence paths illustrated in diagram 740 of Figure 7C can be three-dimensional. Additionally, although the illustrated convergence paths all converge with the planned path 742, it is understood that some convergence paths can be calculated away from the planned path 742 (although such paths may be rejected). However, other convergence paths may overshoot the actual path 742 and subsequently converge (for example, if there is not enough room to construct the curve). Consequently, many different structures of
<img file="MX351981B_D0059.tif" />
IMPU
INSTITUTE MEXICANO 'DE LA ΡΛΟΡΙΕΠΑΠ INDUSTRIAL convergence trajectory.
Referring again to Figure 7B, at step
736, the on-site controller 144 produces revised control parameters based on the convergence plan calculated in step 734. In step 738, the revised control parameters can be output. It is understood that the revised control parameters can be provided to return the bit to the planned trajectory 742 and the original control parameters can be used later thereafter (starting at the point of convergence). For example, if the convergence plan selected path 748, the revised control parameters can be used until the bit reaches position 749. Once the bit reaches position 749, the original control parameters can be used for drilling. additional. Alternatively, the revised control parameters can incorporate the original control parameters starting at position 749 or they can recalculate control parameters for the planned path even beyond point 749. Consequently, the convergence plan can result in control parameters from bit position 743 to position 749, and additional control parameters can be reused or calculated depending on the particular implementation of the on-site controller 144.
Referring to Figure 8A, a method 800 illustrates a more detailed embodiment of step 734 of Figure 7B. It is understood that the convergence plan of step 734 can be computed in many different ways, and that the method 800 provides a bit of focus for such a computation when the goal is to find the solution vector of lower cost. In our example, cost can include both the financial cost of a solution and the reliability of a solution. Other costs, such as time costs, can also be included. For example purposes, diagram 740 of Figure 7C is used.
In step 802, multiple solution vectors are calculated from current position 743 to planned trajectory 742. These solution vectors can include trajectories 744, 746, 748, and 750. Additional trajectories can also be calculated (not shown in Figure 7C). The number of solution vectors that are calculated can vary depending on various factors. For example, the distance available to construct a curve needed to return to the planned path 742 may vary depending on the current location and orientation of the bit with respect to the planned path. A greater number of solution vectors may be available when there is a greater distance in which a curve will be constructed than for a smaller distance since the smaller distance may require a much more aggressive rate of angular increase that excludes rates of angular increase less than can be used for the longest distance. In other words, the earlier an error is detected, the more solution vectors will generally be possible due to the greater distance by which the error can be corrected. Although the number of solution vectors that are calculated at this stage can vary, it may be that
<img file="MX351981B_D0060.tif" />
IMPI
MEXICAN INSTITUTE
OF THE INDUSTRIAL PROPERTY there are hundreds or thousands of solution vectors calculated in some modalities.
At step 804, any solution vector that falls outside the defined limits is rejected, such as solution vectors that fall outside the lower limit 753 and the upper limit 754. For example, the path 744 would be rejected because the point of convergence 745 falls outside the lower bound 753. It is understood that the 744 trajectory may be rejected for an engineering reason (for example, the trajectory would require a more severe dogleg than allowed) before cost considerations, or the engineering reason may be considered a cost.
In step 806, a cost is calculated for each remaining vector solution. As illustrated in Figure 7C, costs can be represented as a cost matrix (which may or may not be weighted) with each solution vector having corresponding costs in the cost matrix. At step 808, a minimum of the solution vectors can be taken to identify the lowest cost solution vector. It is understood that minimum cost is one way to select the desired solution vector, and that other ways can be used. Consequently, step 808 refers to the selection of an optimal solution vector based on a set of objective parameters, which may include one or more of a financial cost, a time cost, a reliability cost, and / or other factors, such as an engineering cost similar to the gravity of the
<img file="MX351981B_D0061.tif" />
<img file="MX351981B_D0062.tif" />
MEXICAN INSTITUTE.
OF INDUSTRIAL FROITTY dog, which can be used to reduce the set of solution vectors to the optimal solution vector.
By weighting the costs, the cost matrix can be customized to handle many different cost scenarios and desired outcomes. For example, if time is of primary importance, a cost of time can be weighted above financial and reliability costs in order to ensure that a solution vector that is faster will be selected over other solution vectors. which are substantially the same but slightly slower, although the other solution vectors may be more beneficial in terms of financial costs and reliability. In some embodiments, step 804 can be combined with step 808 and solution vectors that fall outside the limits can be provided with a cost that guarantees that they will not be selected. In step 810, the solution vector corresponding to the minimum cost is selected.
Referring to Figure 8B, a method 820 illustrates one embodiment of an event-based process that can be executed by the on-site controller 144 of Figure 2A. It is understood that an event can represent many different scenarios in the surface airship system 201. In the example at hand, at step 822, an event can occur that indicates that a prediction is not correct based on what is actually has occurred. For example, a formation layer is not where expected (for example, too high or low), an auger
<img file="MX351981B_D0063.tif" />
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OF SELECTED INDUSTRIAL PROPERTY did not drill as expected, or a selected mud motor did not build the curve as expected. Prediction error can be identified by comparing expected results with actual results or by using other detection methods.
At step 824, a reason for the error can be determined because the surface steerable system 201 and its data can provide an environment in which the prediction error can be evaluated. For example, if a bit did not drill as expected, the 820 method can examine many different factors, such as whether the rock formation was different than expected, whether the drilling parameters were correct, whether the drilling parameters were correct. entered correctly by the well driller, if another error and / or failure occurred that caused the bit to drill poorly, and if the bit simply failed in performance. By accessing and analyzing the available data, the reason for the failure can be determined.
In step 826, a solution can be determined by the error. For example, if the rock formation was different than expected, database 128 can be updated with the correct rock information, and new drilling parameters can be obtained for rig 110. Alternatively, the Current bit can be maneuvered and replaced with another bit more suitable for the rock. At step 828, current drilling predictions (e.g., well plan, rate of angular increase, slip estimates) can be updated based on
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INSTITUTE MEXICANO OS LA MOHEDA D INDUSTRIAL in the solution and the solution can be stored in the basC'lly UdlUS 120 'pare · -> »». be used in future predictions. Consequently, the 820 method can result in benefits for future wells as well as improve predictions of current wells.
Referring to Figure 8C, a method 830 illustrates one embodiment of an event-based process that can be executed by the on-site controller 144 of Figure 2A. Method 830 is aimed at recalibration forecasting that can be triggered by an event, such as an event detected in step 610 of Figure 6. It is understood that the recalibration described in this mode may not be the same as calculating a convergence plan, although calculating a convergence plan may be part of the recalibration. As an example of an event that triggers recalibration, a change in the ROP and / or GAMMA readings may indicate that a layer build (for example, layer 170a in Figure 1B) is actually 6.096 meters (twenty feet). greater than planned. This is very likely to impact the well plan, as it may be necessary to change the rate of increase predictions and other drilling parameters. Consequently, at step 832, this event is identified.
At step 834, a forecast can be made as to the impact of the event. For example, the surface steerable system 201 can determine whether or not the projected rate of angular increase needed to settle the curve can be met based on the difference of the 6.096
<img file="MX351981B_D0065.tif" />
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OF INDUSTRIAL PROPERTY meters (twenty feet). This determination may include examining the · current location of the bit, the projected trajectory, and similar information.
At step 836, modifications can be made based on the forecast. For example, if the projected rate of angular increase can be met, then modifications to the drilling parameters can be made to address the difference in formation depth, but the modifications can be relatively minor. However, if the projected rate of angular increase cannot be met, the surface steerable system 201 can determine how to deal with the situation, for example, by planning a drill maneuver to replace the current BHA with a BHA. capable of creating a new and more aggressive curve.
Such decisions may be automated or may require the input or approval of drilling engineer 302, geologist 304, or other individuals. For example, depending on the distance to the detour point, the surface steerable system 201 may first stop drilling and subsequently send an alert to an authorized individual, such as the drilling engineer 302 and / or the geologist 304. Drilling engineer 302 and geologist 304 may subsequently become involved in planning a solution or may approve a solution proposed by surface steerable system 201. In some embodiments, surface steerable system 201 may automatically implement its solution. calculated. Parameters can be adjusted for such self-implementing measures to ensure that drastic deviations from the • ΒΟΛπίΓΓίιϊΐΜίΐίΐ rtTtlKgl (
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original well plan does not occur automatically whereas automatic application of minor measurements is allowed.
It is understood that such recalibration forecasts can be made based on many different factors and can be triggered by many different events. The forecast portion of the process is aimed at anticipating what changes may be necessary due to recalibration and calculating how those changes can be implemented. Such a forecast provides cost advantages because more options may be available when a problem is detected earlier rather than later. Using the example above, the sooner the difference in layer depth is identified, the more likely it is that the rate of angular increase can be met without changing the BHA.
Referring to Figure 8D, a method 840 illustrates one embodiment of an event-based process that can be executed by the on-site controller 144 of Figure 2A. Method 840 is aimed at automatic tuning that can be performed by the on-site controller 144 based on factors such as ROP, total cost, and reliability. Through automatic tuning, the on-site controller 144 can run a learning process that allows it to optimize the drilling performance of the rig 110. Additionally, the automatic tuning process allows a balance to be achieved that provides reliability while also reducing costs. Reliability in drilling operations is often linked to vibration and problems that can cause
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MEXICAN INSTITUTE OF PROPERTY INDUSTRIAL vibration, such as sticking-sliding and eddies Such vibration problems can damage or destroy equipment and can also result in a very uneven surface in the hole that can cause other problems such as friction loading of future drilling operations due to casing / tubing passing through that area of the hole. Consequently, it is desirable to minimize vibration while at the same time optimizing performance, because overcorrection of vibrations can lead to slower drilling than necessary. It is understood that the optimization at hand may involve a change in any drilling parameter and is not limited to a particular piece of equipment or control system. In other words, the parameters across the entire 110 and BHA rig can be changed during the automatic tuning process. In addition, the optimization process can be applied to production by optimizing well runoff and other factors that affect production. For example, by minimizing the severity of dogleg, production can be increased over the life of the well.
Accordingly, in step 842, one or more target parameters are defined. For example, the target parameter may be a 344.73 MPa (50 ksi) MSE or a 0.0084 meter / s (100 ft / hour) ROP that the on-site controller 144 is to set and maintain. At step 844, the plurality of control parameters are identified for use in the drilling operation. Control parameters are selected in order to comply with
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Target MSE of 344.73 MPa (50 ksi) or target ROP of U.UU84 metphos / a (1UIT ft / hour). The drilling operation begins with control parameters, which can be used until the target MSE or ROP is reached. At step 846, feedback information is received from the drilling operation when the control parameters are being used, so that the feedback represents the performance of the drilling operation as controlled by the control parameters. Historical information can also be used in step 846. In step 848, an operational baseline is established based on the feedback information.
In step 850, at least one of the control parameters is changed to modify the drilling operation, although target MSE or target ROP must be maintained. For example, some or all of the control parameters can be associated with a range of values and the value of one or more of the control parameters can be changed. At step 852, more feedback information is received, but this time the feedback reflects the performance of the drilling operation with the changed control parameters. In step 854, a performance impact of the change is determined relative to the operational baseline. The performance impact can occur in a number of ways, such as a change in MSE or ROP and / or a change in vibration. At step 856, a determination is made as to whether or not the control parameters are optimized. If the parameters are not optimized
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MCXICANG INSTITUTE OF INDUSTRIAL PROPERTY control, method 840 returns to step 850. If control parameters are selected, method 840 moves to step 858. In step 858, the optimized control parameters are used to the current drilling operation with the target MSE or target ROP and stored (for example, in database 128) for use in subsequent drilling operations and operational analysis. This may include linking training information to control parameters in regional database 128.
Referring to Figure 9, one embodiment of a system architecture 900 is illustrated that can be used for the on-site controller 144 of Figure 1A. The 900 system architecture includes interfaces configured to interact with external components and internal modules configured to process information. The interfaces may include an input controller 902, a remote sync interface 904, and an output interface 918, which may include at least one of a graphical user interface (GUI) 906 and an output controller 908. The internal modules may include a 910 diagnostic logger / update engine and database query, a 912 local database (which may be similar or identical to the 410 database in Figure 4), a loopback module Orientation Control Module (LCG) 914, and an Autonomous Control Loop Module (ACL) 916. It is understood that the system architecture 900 is merely an example of a systems architecture that can be used for the on-site controller 144 and the functionality can be provided for the on-site controller 144 using many architectures.
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INSTITUTE MEXICANO D £ LA PROPERTY INDUSTRIAL different. As a result, the functionality that you need for particular modules and architecture components can be combined, further separated, and organized in many different ways.
It is understood that the computer-steerable system 144 may perform certain calculations to prevent errors or inaccuracies from accumulating and miscalculations. For example, as will be described later, the input controller 902 may receive a Well Information Transfer Specification (WITS) input representing absolute pressure, while the surface steerable system 144 needs differential pressure and needs a exact zero point for differential pressure. In general, the well driller will zero differential pressure when the drillstring is positioned with the bit being away from the bottom and all pump flow is occurring. However, this can be a relatively sporadic event. Consequently, the surface steerable system 144 can recognize when the bit is at a distance from the bottom and the flow rate has been achieved and the differential pressure has been zeroed.
Another calculation may involve the height of the block, which needs to be properly calibrated. For example, the height of the block can range over a wide range, including distances that may not even be possible for a specific drill rig. Consequently, if the reported interval is from 18.28 meters to 45.72 meters (sixty feet to one hundred fifty feet) and there should only be 30.48 meters (one hundred feet), the airship system of
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surface 144 can assign a value of zero to 18.23 "ñielio¿ lépoilddus · (sixty feet) and a value of 30.48 meters (one hundred feet) to the reported 45.72 meters (one hundred and fifty feet). Additionally, during drilling, the error gradually accumulates as the cable drifts and other events occur. The surface steerable system 144 can calculate its own block height to predict when the next connection and other related events will occur, and can also take into account any errors that may be introduced by problems with the cables.
Referring specifically to Figure 9, the input controller 902 provides output to the GUI 906, the database query and update engine / diagnostic logger 910, the GCL 914, and the ACL 916. The input controller 902 is configured to receive inputs for the on-site controller 144. It is understood that the input controller 902 may include the functionality necessary to receive various types of files, formats, and data streams. The input controller 902 can also be configured to convert formats if necessary. Consequently, the input controller 902 can be configured to provide flexibility to the on-site controller 144 by handling incoming data without the need to change internal modules. In some embodiments, for abstraction purposes, the data flow protocol may be arbitrary with an input event defined as a single change (eg, a real-time sensor change) of any of the given inputs.
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The input controller 902 can reetbii * divofooo type or input, including input from equipment sensors (for example, from sensor system 214 of Figure 2A), well plan data, and control data (for example , engineering control parameters). For example, equipment sensor input can include hole depth, bit depth, tool orientation, tilt, azimuth, true vertical depth, gamma count, riser pressure, mud flow rate, rotary RPMs, speed of auger, ROP, and WOB. Well plan data may include information such as projected start and end locations of various geologic layers at points of vertical depth along the path of the well plan. the well , and a planned hole path, presented in three-dimensional space. . Control data can be used to define maximum operating parameters and other limitations to control drilling speed, limit the amount of deviation allowed from planned trajectory, define authority levels (for example, if an on-site operator can make a particular decision or whether it is to be made by an engineer elsewhere outside the company), and similar limitations. The input controller 902 can also handle manual input, such as input from a keyboard, mouse, or touch screen. In some embodiments, the input controller 902 can also handle an input of wireless signals, such as from a cell phone, smartphone, PDA, tablet, laptop, or any other capable device.
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MEXICAN INSTITUTE OF PROPERTY INDUSTRIAL to communicate wirelessly with the on-site controller 144 over a local network and / or elsewhere outside the company.
The diagnostic logger / update engine and database query 910 receives input from the input controller 902, the GCL 914, and the ACL 916, and provides output to the local database 912 and GUI 906. The query 910 Diagnostic Logger / Update Engine and Database Engine is configured to manage archiving of data to local 912 database. The 910 Diagnostic Update / Logging Engine and Database Query can also manage some functional requirements of a Remote Synchronization Server (RSS) through the 904 Remote Synchronization Interface for archiving data to be uploaded and synchronized with a remote database, such as database 128 of Figure 1A. The 910 Diagnostic Logger / Update Engine and Database Query can also be configured to serve as a diagnostic tool for evaluating algorithm and performance behavior against raw material and rig data and sensor feedback data.
Local 912 database receives input from 910 diagnostic logger / update engine and database query and 904 remote sync interface, and provides output to GCL 914, ACL 916, and remote sync interface 904. It is understood that the local database 912 can be configured in many different ways. Such «Μ *
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As described in previous modalities, the cir dmtcp IjlliI 0 * ^ base can store both current and historical information that represents both the current drilling operation with which the on-site controller 144 is coupled as well as regional information from the database. 128.
The GCL 914 receives input from the input controller
902 and local 912 database, and provides output to the 910 diagnostic logger / update engine and database query, GUI 906, and ACL 916. Although not shown, in some modes, the GCL 906 may provide an output to the output controller 908, allowing the GCL 914 to directly control third-party systems and / or interface with the rig alone or with the ACL 916. One embodiment of the GCL 914 is discussed below with respect to Figure 11.
ACL 916 receives input from input controller 902, local database 912, and GCL 914, and provides output to the database query and update engine / diagnostic logger 910 and output controller 908. One embodiment of ACL 916 is discussed below with respect to Figure 12.
Output interface 918 receives input from input controller 902, GCL 914, and ACL 916. In the present example, GUI 906 receives input from input controller 902 and GCL 914. GUI 906 can display an output on a monitor or other visual indicator. The output controller 908 receives input from ACL 916 and is configured to provide an interface between the on-site controller 144 and
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212 of Figure 2A.
It is understood that the system architecture 900 of Figure 9 can be configured in many different ways. For example, various interfaces and modules can be combined or further separated. Accordingly, the system architecture 900 provides an example of how the functionality to provide the on-site controller 144 can be structured, but the on-site controller 144 is not limited to the illustrated structure of Figure 9.
Referring to Figure 10, one embodiment of the input controller 902 of the system architecture 900 of Figure 9 is illustrated in greater detail. In the example at hand, input controller 902 can be configured to receive input through different input interfaces, such as a serial input controller
1002 and a Transmission Control Protocol (TCP) driver 1004. Both the serial input driver 1002 and the TCP input driver 1004 can be fed into a parser 1006.
The parser 1006 in the example at hand can be configured according to a specification such as WITS and / or using a standard such as Well Information Transfer Standard Markup Language (WITSML). WITS is a specification for the transfer of rig-related data and uses a binary file format. WITS can be
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replace or complement in some ways by WITSML., which is based on XML (Extensible Markup Language) to transfer said information. The parser 1006 can be fed into the database query and update engine / diagnostic logger 910, and also into the GCL 914 and GUI 906 as illustrated in the example parameters of block 1010. The input controller 902 may also include a non-WITS input controller 1008 that provides input to ACL 916 as illustrated in block 1012.
Referring to Figure 11, one embodiment of the GCL 914 of Figure 9 is illustrated in greater detail. In the example at hand, the GCL 914 may include various functional modules, including a rate-of-increase-angle predictor 1102, a geological modified well planner 1104, a hole estimator 1106, a slip estimator 1108, a vector calculator error code 1110, a geological offset estimator 1112, a landslide planner 1114, a convergence planner 1116, and a tactical solution planner 1118. In the following description of the GCL 914, the term external input refers to an input received from the outside of the GCL 914 (for example, from the input controller 902 of Figure 9), while internal input refers to an input received by the GCL module from another GCL module.
The angular increase rate predictor 1102 receives an external input representing BHA and geological information, receives an internal input from the hole estimator 1106, and provides output to the
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geological modified well planner 1104, dcalizamionto estimator. 1108, landslide planner 1114, and convergence planner 1116. The 1102 rate of increase predictor is configured to use BHA and geological information to predict the rates of drilling angle of current and future sections of a well. For example, the angular increase rate predictor 1102 can determine how aggressively the curve will be increased for a given formation with BHA and other given equipment parameters.
The angular magnification rate predictor 1102 can use the orientation of the BHA toward the formation to determine an angle of attack for formation transitions and the angular magnification rates within a single layer of a formation. For example, if there is a rock layer with a sand layer on top of it, there is a formation transition from the sand layer to the rock layer. Approaching the rock layer at a ninety degree angle can provide a good surface and clean drilling entry, while approaching the rock layer at a forty-five degree angle can create a curve relatively quickly. An approach angle that is close to parallel can cause the bit to drop off the top surface of the rock layer. Accordingly, the angular increase rate predictor 1102 can calculate the orientation of the BHA to explain the formation transitions. Within a single layer, the 1102 angular increase rate predictor can use the BHA guidance to explain the
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MEXICAN INSTITUTE OF PROPERTY INDUSTRIAL characteristics of inner layer (eg grain) for THki'minnr Luí Inn of angular magnification of different parts of a layer.
BHA information can include bit characteristics, mud motor deflection adjustment, stabilization and mud motor bit to bend distance. Geological information can include formation data such as compressive strength, thickness, and depths of formations found at the specific drilling location. Such information allows a calculation-based prediction of the angular increase rates and ROP that can be compared both with real-time results (for example, obtained while drilling the well) and regional historical results (for example, from the base data set 128) to improve prediction accuracy as drilling progresses. Future predictions of formation angle increase rates can be used to plan convergence adjustments and confirm goals that can be achieved with current variables in advance.
The geologic modified well planner 1104 receives an external input representing a plan of the well, an internal input from the rate of increase predictor 1102 and the geologic offset estimator 1112, and provides output to the slip planner 1114 and the vector calculator. error 1110. The geologic modified well planner 1104 uses the input to determine whether or not there is a more optimal path than that provided by the external well plan while
<img file="MX351981B_D0081.tif" />
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MEXICAN INSTITUTE OF PROPERTY INDUSTRIAL which is within the limits of error of the original well plan. More specifically, the geologic modified well planner 1104 takes geologic information (eg, offset) and calculates whether or not another solution to the target may be more cost-effective and / or reliable. The outputs of the geologic modified well planner 1104 to the slip planner 1114 and the error vector calculator 1110 can be used to calculate the error vector based on the current vector for the newly calculated path and to modify slip predictions.
In certain embodiments, the geologic modified well planner 1104 (or other module) can provide the necessary functionality to track a formation trend. For example, in horizontal wells, geologist 304 may provide surface steerable system 144 with a target inclination that surface steerable system 144 will attempt to maintain. For example, geologist 304 may provide directional well driller 306 with a target of 90.5 to 91 degrees incline for a section of the well. Geologist 304 can input this information into surface steerable system 144 and directional well driller 306 can retrieve the information from surface steerable system 144. The geologic modified well planner 1104 can subsequently treat the target as a vector, for example, either by processing the information provided by geologist 304 to create the target vector or by utilizing a target vector entered by geologist 304. The
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INSTITUTE MEXICANO OS LA PROPERTY INDUSTRIAL geological modified well planner 1104 may-luyiai ethyl iYi while at the same time remaining within the error limits of the original well plan.
In certain embodiments, the geologic modified well planner 1104 may be an optional module that is not used unless the well plan must be modified. For example, if the well plan is marked on the surface steerable system 201 as unmodifiable, the geologic modified well planner 1104 can be bypassed completely or the geologic modified well planner 1104 can be configured to pass the well plan without No change.
The hole estimator 1106 receives external inputs representing BHA information, measured depth information, survey information (e.g. azimuth and tilt), and provides outputs to the rate of angular increase predictor 1102, the error vector calculator 1110 and convergence planner 1116. The hole estimator 1106 is configured to provide a real-time or near-real-time estimate of the actual position of the hole and drill bit and of the path angle. This estimate can use both straight-line projections and projections that incorporate slippage. The 1106 hole estimator can be used to compensate for the fact that a sensor is typically physically located some distance behind the bit (for example, fifty feet (15.24 meters)), which causes the sensor readings to stick. behind location
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INSTITUTE MEXICANO Dt LA l'RCPir.CAO INDUSTsUAL real bit at 15.24 meters (fifty feet). The 1106 hole estimator can also be used to compensate for the fact that sensor measurements may not be continuous (for example, a sensor measurement may occur every 30.48 meters (one hundred feet)).
The 1106 hole estimator can use two techniques to accomplish this. First, the hole estimator 1106 can provide the most accurate estimate from the surface to the last survey location based on the collection of all survey measurements. Second, the hole estimator 1106 can take the slip estimate from the slip estimator 1108 (described below) and extend this estimate from the last point of the survey to the location of the drill bit in real time. By using the combination of these two estimates, the hole estimator 1106 can provide the on-site controller 144 with an estimate of the location of the drill bit and the path angle from which the orientation and direction solutions can be derived. A new metric parameter that can be derived from the hole estimate is the effective rate of angular increase that is achieved throughout the entire drilling process. For example, the hole estimator 1106 can calculate the current position of the bit and the trajectory 743 in Figure 7C.
Slip estimator 1108 receives external inputs representing measured depth and differential pressure information, receives internal input from rate of angular increase predictor
<img file="MX351981B_D0086.tif" />
1102, and provides output to the hole estimator 1100 ·· and the plai'iintadürde<sup>1 </sup>Geologic Modified Well 1104. The 1108 slip estimator, which can operate in real time or near real time, is configured to sample tool orientation, differential pressure, measured depth (MD), incremental motion, MSE, and other feedback from sensors to quantify / estimate a deflection and advance vector while gliding.
Traditionally, a slip deviation would be predicted by a human operator based on experience. The operator, for example, would use a long slip cycle to assess what was likely done during the last slip. However, results are generally not confirmed until the MWD lift sensor point passes the slip portion of the hole, often resulting in a response lag defined by the distance of the sensor point from the tip of the bit. drilling (for example, approximately 15.24 meters (approximately fifty feet)). This delay introduces deficiencies in the slip cycles due to the over / over correction of the real trajectory with respect to the planned trajectory.
With the slip estimator 1108, each tool orientation update algorithmically converges with the period average differential pressure between the previous and current tool directions, as well as the change in MD during this period to predict the direction, angular deviation , and MD progress during that
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INSTITUTE TOXICANO DE LA Pk & HEbAD INDUSTRIAL period. As an example, the periodic rate can be «Wí W '^ tllfé' '{Jléy-y · sixty seconds per cycle depending on the degree of update of the tool orientation of the MWD tool. With a more accurate estimate of slip efficiency, slip efficiency can be improved. The output from the slip estimator 1108 is periodically provided to the hole estimator 1106 for accumulation of well deviation information, as well as the geological modified well planner 1104. Part or all of the output from the slip estimator 1108 can be output to through a display such as display 250 of Figure 2B.
The error vector calculator 1110 receives an internal input from the geological modified well planner 1104 and the hole estimator 1106. The error vector calculator 1110 is configured to compare the planned well trajectory with the trajectory of the actual hole and the estimated position of the drill bit. The error vector calculator 1110 can provide the metric parameters used to determine the error (eg, how far) the current drill bit position and trajectory are out of plan. For example, the error vector calculator 1110 can calculate the error between the current position 743 of Figure 7C to the planned trajectory 742 and the desired bit position 741. The error vector calculator 1110 can also calculate a projected bit / projected trajectory position representing the future result of a current error as described above with respect to the
<img file="MX351981B_D0088.tif" />
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Figure 7B.
The geologic offset estimator 1112 receives an external input that represents geologic information and provides outputs to the geologic modified well planner 1104, the landslide planner 1114, and the tactical solution planner 1118. During drilling, offset can occur due to that the particular characteristics of the formation affect the drilling direction. More specifically, it is possible that there is a path deviation that is contributed by the formation as a function of drilling rate and BHA. The geologic offset estimator 1112 is configured to provide a offset estimate as a vector. This vector can then be used to calculate offset compensation parameters that can be used to offset the offset in a control solution. }
The slip planner 1114 receives an internal input from the rate-of-increase predictor 1102, the geologic modified well planner 1104, the error vector calculator 1110, and the geologic phase shift estimator 1112, and provides an output to the convergence planner. 1116, as well as an estimated time for the next trip. The 1114 slip planner is configured to evaluate an advance drilling slip / cost equation and slip activity plan, which may include taking into account BHA wear, expected angular increase rates of current and expected formations, and the path of -p »™ n., go<sub>?</sub>Before drilling in advance, the landslide planner 1114 may attempt to forecast the estimated time of the next landslide to aid in planning. For example, if additional lubricants (e.g. beads) are required for the next slide and pumping of the lubricants into the drillstring is needed to start thirty minutes before the slide, the estimated time of the next slide can be calculated, and later use to program when to start pumping lubricants.
The functionality for a Lost Circulation Material (LCM) planner can be provided as part of the Slip Planner 1114 or elsewhere (eg, as a standalone module or as part of another module described herein). The LCM scheduler functionality can be configured to determine if additives need to be pumped into the hole based on prompts such as fluid versus reflux measurements. For example, if drilling through a porous rock formation, the fluid that is pumped into the hole can be lost in the rock formation. To solve this problem, the LCM planner can control the pumping of LCM into the hole to plug the holes in the porous rock surrounding the hole to establish a more closed loop control system for the fluid.
The slip planner 1114 can also be seen in the current position with respect to the next connection. A connection can
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MEXICAN INSTITUTE OF PROPERTY INDUSTRIAL occur every 27.43 to 30.48 meters (ninety to one hundred feet) (or some other distance or interval of distances based on the particularities of the drilling operation) and the landslide planner 1114 can avoid planning a landslide when is near a connection and / or when slippage would be carried through the connection. For example, if the landslide planner 1114 is planning a landslide of 15.24 meters (fifty feet) but only 6.09 meters (twenty feet) remain until the next connection, the landslide planner 1114 can calculate the landslide from the next connection and make any changes to the slip parameters that might be necessary to accommodate waiting for slip until after the next connection. This avoids inefficiencies that can be caused by starting the slide, stopping for the connection and subsequently having to reorient the tool before finishing the slide. During the slide, the slide planner 1114 may provide some feedback as to the progress toward achieving the desired goal of the current slide.
In certain embodiments, the slip planner 1114 can provide a justification for a reactive torque on the drillstring. More specifically, when rotation occurs, there is reactive torque on the drillstring. When the rotation stops, the string unwinds, which changes the tool orientation and other parameters. When the rotation starts again, the string of
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OF THE PROPERTY 0 ^ 3 INDUSTRIAL PUNCHING REWINDING. The slip planner 1114 can account for this reactive torque so that the tool orientation references are held rather than stopping the rotation, and then an attempt is made to adjust to an optimal tool orientation. While not all MWD tools can provide tool orientation when rotated, using one that provides such information for the GCL 914 can significantly reduce the transition time from rotating to sliding.
The convergence planner 1116 receives internal inputs from the angular magnification rate predictor 1102, the hole estimator 1106, and the slip planner 1114, and provides output to the tactical solution planner 1118. The convergence planner 1116 is configured to provide a convergence plan when the position of the current drill bit is not within a defined margin of error of the planned well path. The convergence plan represents a path from the current drill bit position to an achievable and optimal target point of convergence along the planned path. The convergence plan may take into account the anticipated amount of sliding / drilling that has been planned to take place by the 1114 landslide planner. The convergence planner 1116 may also use BHA guidance information for angle of attack calculations when determining convergence plans as described above with respect to the predictor of
<img file="MX351981B_D0090.tif" />
IMPI
MEXICAN INSTITUTE OF PROPERTY INDUSTRIAL angular increase rate 1102. The solution provided by the · convergence planner 1116 defines a new trajectory solution for the current situation of the drill bit. The solution can be in real time, near real time, or in the future (for example, planned for implementation at a future time). For example, the convergence-planner 1116 may calculate a convergence plan as previously described with respect to Figures 7C and 8A-8D.
The tactical solution planner 1118 receives internal inputs from the geological offset estimator 1112 and the convergence planner 1116, and provides external outputs that represent information such as tool orientation, differential pressure, and mud flow. The tactical solution planner 1118 is configured to take the trajectory solution provided by the convergence planner 1116 and translate the solution into control parameters that can be used to control the rig 110. For example, the tactical solution planner 1118 can take the solution and convert it to configurations for the 208, 210, and 212 control systems to perform the actual drilling based on the solution. The tactical solution planner 1118 can also perform performance optimization as described above. Performance optimization can be applied to optimizing the overall drilling operation as well as optimizing the drilling itself (for example, how to drill faster).
Other functionality can be provided by the GCL 914 at
<img file="MX351981B_D0091.tif" />
Additional modules or added to an existing module For example, there is a relationship between the rotational position of the drill pipe on the surface and the orientation of the downhole tool. Consequently, the GCL 914 can receive information corresponding to the rotational position of the drill pipe on the surface. The GCL 914 can use this surface position information to calculate current and desired tool orientations. These calculations can then be used to define control parameters for adjusting the upper drive unit or Kelly unit to make adjustments to the orientation of the downhole tool in order to orient the well.
For example purposes, an object-oriented software approach can be used in order to provide a class-based structure that can be used with the GCL 914 and / or other components of the on-site controller 144. In the present embodiment , a drilling model class is defined to capture and define the drilling state throughout the entire drilling process. The class can include information in real time. This class can be based on the following components and sub-models: a drill bit model, a hole model, a surface equipment gear model, a mud pump model, a WOB / differential pressure model, a rotary / position model, an MSE model, an active well plan, and control limits. The class can produce a control output solution and can be run through a
<img file="MX351981B_D0092.tif" />
MEXICAN INSTITUTE OF PROPERTY INDUSTRIAL main processing loop that rotates through the ατδΐτΤΙΐσΤΓΤΙοα ^^ LCG 914.
The drill bit model can represent the current position and status of the drill bit. This model includes a three-dimensional position, a drill bit trajectory, BHA information, bit speed, and tool orientation (eg, orientation information). The three-dimensional position can be specified in north-south (NS), east-west (EW), and true vertical depth (TVD). The trajectory of the drill bit can be specified as a slope and azimuth angle. The BHA information can be a set of dimensions that define the active BHA. The hole model can represent the current path and the size of the active hole. This model includes hole depth information, a series of survey points collected along the hole's path, a gamma log, and hole diameters. The hole depth information is for the current drilling job. Hole diameters represent the diameters of the hole as it is drilled during the current drilling job.
The equipment surface gear model can represent pipe length, block height, and other models, such as mud pump model, WOB / differential pressure model, position / rotary model, and MSE model. . The mud pump model represents a mud pump equipment and includes flow rate, pressure pipe of
<img file="MX351981B_D0093.tif" />
TI'ΟΛΝΟ INSTITUTE OF INDUSTRIAL PROPERTY
<img file="MX351981B_D0094.tif" />
rise, and differential pressure. The WOB / differential pressure model re-questions winches or other WOB / differential pressure controls and parameters, including WOB. The rotary / position model represents the upper drive unit or other rotary / position controls and parameters including rotary RPM and spindle position. The active well plan represents the path of the target hole and can include an external well plan and a modified well plan. Control limits represent defined parameters that can be set as maximum and / or minimum. For example, the control limits can be adjusted for the rotary RPM on the upper drive unit model to allow the maximum RPMs at the defined level. The control output solution represents the control parameters for rig 110.
The main processing loop can be handled in many different ways. For example, the main processing loop can function as a single sub-process in a fixed time loop to handle time propagation and equipment sensor event changes. If no equipment sensor update occurs between fixed time intervals, only time propagation can occur. In other embodiments, the main processing loop can be multiple sub-processes.
Each GCL 914 functional module can have its behavior encapsulated within its respective class definition. During their processing window, individual units may have
<img file="MX351981B_D0095.tif" />
IMPI
MEXICAN INSTITUTE OF PROPERTY INDUSTRIAL an exclusive portion in time to execute and update the drilling model. For example purposes, the processing order of the modules may be in the sequence of geological modified well planner 1104, rate of increase angle predictor 1102, slip estimator 1108, hole estimator 1106, error vector calculator 1110, landslide planner 1114, convergence planner 1116, geological offset estimator 1112, and tactical solution planner 1118. It is understood that other sequences can be used.
In the present embodiment, the GCL 914 may rely on a programmable timer module that provides a timing mechanism to provide timer event signals to drive the main processing loop. Although the on-site controller 144 may simply depend on the timer and calls by date triggered by the programming environment (eg, java), this would limit the timing by being exclusively triggered by system time. In situations where it may be advantageous to manipulate the clock (eg, for evaluation and / or testing), the programmable timer module can be used to alter the time. For example, the programmable timer module can allow a default time setting to the system time and a timescale of 1.0, it can allow the system time of the on-site controller 144 to be set manually, it can allow the scale of time relative to system time to be modified, and / or may allow periodic event time requests to escalate to the
<img file="MX351981B_D0096.tif" />
timescale are requested.
Referring to Figure 12, one mode of the ACL 916 provides different functions to the on-site controller 144. The ACL 916 can be considered a second feedback control loop that operates in conjunction with a first feedback control loop provided by the GCL 914. The ACL 916 can also provide actual instructions to drill rig 110, either directly to drill accessories 216 or through control systems 208, 210 and 212. The ACL 916 may include a position / rotary control logic block 1202, a WOB / differential pressure control logic block 1204, a fluid flow control logic block 1206, and a pattern recognition / error detection 1208.
One of the functions of ACL 916 is to establish and maintain a target parameter (for example, an ROP of a defined value of meters / sec (feet / hour)) based on input from GCL 914. This can be accomplished through of control loops using rotary / position control logic block 1202, WOB / differential pressure control logic block 1204, and fluid flow control logic block 1206. Rotary / position control logic block 1202 can receive sensor feedback information from the input controller
902 and set point information from the GCL 914 (for example, from the 1118 tactical solution planner). Differential pressure control logic block 1204 can receive feedback information from
<img file="MX351981B_D0097.tif" />
sensors from input controller 902 and tuning knob information from GCL 914 (for example, from tactical solution planner 1118). The fluid flow control logic block 1206 can receive sensor feedback information from the input controller 902 and set point information from the GCL 914 (eg, from the tactical solution planner 1118).
The ACL 916 can use the sensor feedback information and set points from the GCL 914 to try and maintain the set target parameter. More specifically, the ACL 916 can have control over various parameters through the rotary / position control logic block 1202, the WOB / differential pressure control logic block 1204, and the circulation control logic block. of 1206 fluid, and can modulate the various parameters to achieve the target parameter. The ACL 916 can also modulate parameters based on cost-driven and reliability-driven drilling targets, which can include parameters such as a target trajectory, a target cost, and / or a performance target. It is understood that the parameters can be limited (for example, by control limits set by the drilling engineer 306) and the ACL 916 can vary the parameters to achieve the target parameter without exceeding the defined limits. If this is not possible, ACL 916 may notify the on-site controller 144 or otherwise indicate that the target parameter is currently unreachable.
<img file="MX351981B_D0098.tif" />
In certain modes, ACL 916 ptredé<sup>1</sup> ooñtíh'uar by modifying the parameters to identify an optimal set of parameters with which to achieve the target parameter for the particular combination of drilling equipment and formation characteristics. In such embodiments, on-site controller 144 can export the optimal set of parameters to database 128 for use in formulating drilling plans for other drilling projects.
Another function of ACL 916 is error detection. Error detection is aimed at identifying problems in the current drilling process and can monitor for unforeseen anomalies and gradual failures. In this capacity, the pattern recognition / error detection block 1208 receives an input from the input controller 902. The input may include sensor feedback received by rotary / position control logic block 1202, WOB / differential pressure control logic block 1204, and fluid flow control logic block 1206. The block Pattern Recognition / Error Detection 1208 monitors input information for indications that a failure has occurred or for sudden changes that are illogical.
For example, failure can be indicated by a change in ROP, a radical change in the rate of angular increase, or any other significant change. As an illustration, suppose the drilling occurs with an expected ROP of 0.0084 meters / second (100 feet / hour).
<img file="MX351981B_D0099.tif" />
IMPI
MEXICAN INSTITUTE OF INDUSTRIAL PROPERTY
If the ROP suddenly drops to 0.0042 meters / second (50 feet / l iuij) uhl · no change in parameters and remains there for some defined period, there has been an equipment failure, formation change, or other event. Another error can be indicated when the MWD sensor feedback has been continuously indicating that the borehole has headed north for hours and the sensor feedback suddenly indicates that the borehole has reversed by a few meters (feet) and is heading south. This change clearly indicates that a failure has occurred. Changes can be defined and / or the pattern recognition / error detection block 1208 can be configured to monitor deviations of a certain magnitude. The pattern recognition / error detection block 1208 can also be configured to detect deviations that occur over a period of time in order to catch more gradual failures or security problems.
When an error is identified based on a significant change in the input values, the on-site controller 201 can send an alert. This allows an individual to review the error and determine if action is necessary. For example, if an error indicates that there is a significant loss of ROP and an intermittent change / rise in pressure, the individual can determine that the mud motor mount is likely to have occurred with a rubber rupture and auger clogging. In this case, the BHA can be disconnected and the damage repaired before more serious damage occurs. Consequently, error detection can be used to identify
ΙΜΡΙ<sub>(</sub> iwmjro méwcaní. '
I heard La f «pie .; A¡ INDUSTRIAL potential problems that occur before they become more serious and costly to repair.
Another function of ACL 916 is pattern recognition. Pattern recognition is aimed at identifying concerns for the safety of workers and equipment and providing warnings (for example, if a large increase in pressure is identified, the safety of personnel may be compromised), and also at identifying Issues that are not necessarily related to the current drilling process, but can affect the drilling process if ignored. In this capability, the pattern recognition / error detection block 1208 receives an input from the input controller 902. The input may include feedback from sensors received by the rotary / position control logic block 1202, the logic block WOB / Differential Pressure Control Module 1204, and Fluid Circulation Control Logic Block 1206. The pattern recognition / error detection block 1208 monitors the input information for certain defined conditions. A condition can be relatively common (for example, it can occur multiple times in a single hole) or it can be relatively rare (for example, it can occur once every two years). Differential pressure, riser pressure, and any other desired conditions can be monitored. If a condition indicates a particular recognized pattern, ACL 916 can determine how the condition is to be addressed. For example, if a pressure spike is detected, the ACL
MIXICAN INSTITUTE OF THE INDUS «tAL
916 You can determine that drilling must be stopped in a specific way to allow a safe exit. Consequently, while error detection may simply indicate that a problem has occurred, pattern recognition is aimed at identifying future problems and is intended to provide a solution to the problem before the problem occurs or becomes More serious.
Referring to Figure 13, one embodiment of a computer system 1300 is illustrated. Computer system 1300 is one of the possible examples of a system component or device such as the on-site controller 144 of Figure 1A. In situations where the 1300 computer system is on-site, such as the rig 110 location in Figure 1A, the computer system can be contained in a relatively robust, shock-resistant housing that is hardened for industrial applications. and hard work environments.
The computer system 1300 may include a central processing unit (CPU) 1302, a memory unit 1304, an input / output device (I / O) 1306, and a network interface 1308. Components 1302, 1304, 1306 , and 1308 are interconnected via a transportation system (eg, a bus) 1310. A power source (PS) 1312 can provide power to components of the computer system 1300, such as the CPU 1302 and memory unit 1304 . It is understood that the 1300 computer system can be configured differently and that each of the listed components actually
<img file="MX351981B_D0100.tif" />
IMPI
MEXICAN INSTITUTE
INDUSTRIAL PROPERTY may represent different components. For example, CPU 4802 - I can actually represent a multi-processor or a distributed processing system; memory unit 1304 can include different levels of cache memory, main memory, hard drives, and remote storage locations; I / O device 1306 can include monitors, keyboards, and the like; and network interface 1308 may include one or more network cards that provide one or more wired and / or wireless connections to a network 1314. Therefore, a wide range of flexibility is provided in the configuration of the 1300 computer system.
The 1300 computer system can use any operating system (or multiple operating systems), including the different versions of operating systems provided by Microsoft (such as WINDOWS), by Apple (such as Mac OS X), UNIX, and LINUX, and may include operating systems developed specifically for portable devices, personal computers, and servers based on use of the 1300 computer system. The operating system, as well as other instructions (eg, software instructions to perform the functionality described in the above embodiment) can be stored in memory unit 1304 and executed by processor 1302. For example, if computer system 1300 is on-site controller 144, memory unit 1304 may include instructions for performing methods such as methods 600 of Figure 6, 700 of Figure 7A, 720 of Figure 7B, 800 of Figure 8A, 820 of Figure 8B, 830 of Figure 8C, and 840 of the
<img file="MX351981B_D0101.tif" />
<img file="MX351981B_D0102.tif" />
INSTITUTE MEXICANO DE LA PROF! * DAD INDUSTRIAL
Figure 8D. ~
It will be appreciated by those skilled in the art who have the benefit of this disclosure that this surface steerable drilling system and method provides a way to plan a drilling process and correct the drilling process either when the process deviates from plan or when the plan is modified. It should be understood that the drawings and detailed description herein are to be considered in an illustrative rather than restrictive manner, and are not intended to be limited to the particular forms and examples described. Rather, any other modifications, changes, rearrangements, substitutions, alternatives, design options, and modalities apparent to those skilled in the art are included, without departing from the spirit and scope herein, as defined by the following claims . Thus, it is intended that the following claims be construed to encompass all such modifications, changes, rearrangements, substitutions, alternatives, design options, and modalities.
<img file="MX351981B_D0103.tif" />
IMPI
MEXICAN INSTITUTE
OF INDUSTRIAL PROPERTY
Contents84
130 sheets
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108 members in 6 offices
Priority claims9
| Document | Office | Kind | Date |
|---|---|---|---|
| 13334370 | United States of America | – | |
| 201113334370 | United States of America | A | |
| 201113334370 | United States of America | A | |
| 2012068785 | United States of America | W | |
| 2012068785 | United States of America | W | |
| 13334370 | – | – | – |
| PCTUS2012068785 | – | – | – |
| US201113334370 | – | – | – |
| WO2012US68785 | – | – | – |
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| EP2795058A2 | European Patent Office (EPO) | A2 | |
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1 legal event, as the office reported them to INPADOC
Events
| Event | Code | |
|---|---|---|
| Grant or registrationFG | FG |
Numbers
- Publication
- 351981
- Publication, DOCDB
- 351981
- Publication, EPODOC
- MX351981
- Application
- 2014007743
- Application, DOCDB
- 2014007743
- Application, EPODOC
- MX20140007743
Titles2
- Spanish
- SISTEMA Y MÉTODO DE PERFORACIÓN DIRIGIBLE DE SUPERFICIE.
- English
- DIRIGIBLE SURFACE DRILLING SYSTEM AND METHOD.
Classification
- CPC, 13
- E21B44/00
- E21B7/04
- E21B45/00
- E21B47/00
- E21B47/12
- E21B47/047
- E21B44/02
- E21B47/02
- E21B47/09
- E21B19/165
- E21B47/10
- E21B47/024
- E21B47/06
- IPC, 3
- E21B44 00
- E21B7 06
- E21B7 10