Patent Grant
8215417
The present disclosure relates generally to devices and methods for either or both retrofitting and augmenting a traditional drilling or workover rig, and more specifically to automating the operations and control systems. In recent years, innovations that incorporate electronics and computerization have permitted the development of automated systems that can be monitored and operated remotely.
Most modern drilling and workover rigs now house a variety of these automated systems in the form of a fully integrated drilling control system, offering the operators the ability to more easily monitor, document, and control the varied systems with the assistance of computerized terminals and digital displays. Examples of these might be rigs based on the “Cyberbase” system, provided by National Oilwell Varco, Houston, Tex., or the PACE System, provided by Academy Electric, Calgary, Canada. These types of rig automation and control systems have become very popular over the last few years and are used in many of the new rig constructed. But such systems do not address the needs of the traditional aging global rig fleet base that do not have the integrated automation and control systems, referred herein as “traditional” rigs. In this disclosure a traditional rig may be any system referred to as a “rig” in the industry, including a drilling rig and a workover rig. At present, worldwide, there are in excess of 3100 Rotary Drilling Rigs, and a similar number of Workover Rigs. At the time of this disclosure, less than ten percent of these are of the type that has a fully integrated drilling control system.
Today many tools have been developed that make the task of operating the rig more automated and centralized, especially on the newer automated rigs with fully integrated control systems, where a significant set of the tools are integrated. But on traditional rigs these varied systems, developed by disparate companies, have created a complex operation area, jumbled with output displays and controls. Among other things, the systems and methods of the present disclosure helps this complexity issue by reducing the total number of individual systems, sensors, controls and display installations, by rationalizing, integrating systems and hence simplifying the operational areas and system installations for a traditional rig.
As disclosed, of the rigs in service most are traditional in type. These rigs require manual operation and monitoring of an assortment of drilling systems, unless otherwise augmented with select, discrete automation, control and reporting tools available from a wide range of individual providers. Since traditional rigs represent a sizeable capital investment, and possess valuable operational life, it is economically prudent to continue to employ the traditional rigs in drilling operations.
On a traditional rig, the driller, who is in charge of the drilling crew and operation of the rig during drilling operations, works at a primary control station. It is typical for a driller to keep a desk area from where drilling operations are coordinated and the operational documentation is maintained. The driller's desk is typically referred to as the “Knowledge Box,” and is located in a shelter, referred to as the doghouse, on or adjacent to the rig. In most instances, on traditional drilling rigs, the driller's desk has a hinged, sloped lid with a lip at its base, and holds a large International Association of Drilling Contractors (“IADC”) drilling tablet, Canadian Association of Drilling Contractors (“CAODC”) drilling tablet, or similar well site activity recording tablet. The lid is hinged so the driller can move the tablet off the desk to keep it clean. The desk is usually located under the window to give the driller a good view of the rig floor and is also near the door for quick access. The desktop is usually around forty-eight inches tall, which is a comfortable height for the driller to stand and complete reports. The desk is also frequently used as a repository for miscellaneous items, such as pens, strapping tape, small plumbing fittings, and etcetera.
Space in the doghouse is at a premium. The knowledge box made sense when the driller was tasked with keeping the IADC report current and clean, and when the freestanding mechanical drilling recorder was positioned nearby. A driller is now required to complete his reports on a computer and utilize an electronic drilling recorder, so the reporting functions and mechanical drilling recorder are now replaced by data acquisition and computer systems. Other equipment is becoming computerized, such as the pneumatic autodriller and directional steering controls, and with each new system a new set of sensors, controls is added to the rig equipment and another interface is added to the doghouse and drillers station
It would be a valuable addition to the field of art to provide a method of augmenting a traditional rig with automated systems. In order to simplify the retrofitting process, and to take advantage of automated technology, among other advantages, it would be valuable to the field of art to provide a system that may flexibly and dynamically provide such advantages as to integrate multiple automated systems, reduce sensor duplication, reduce the number of controls and control boxes, reduce the number of displays, reduce the space required over discrete automated system installations, reduce time to rig up and rig down, improve overall reliability, improve efficiency, provide more capability for less investment, reduce the controls and interface complexity, and improve standardization of interfaces for the end user.
For the purposes of promoting an understanding of the principles of the invention, reference will now be made to the embodiments, or examples, illustrated in the drawings and specific language will be used to describe the same. It will nevertheless be understood that no limitation of the scope of the invention is thereby intended. Any alterations and further modifications in the described embodiments, and any further applications of the principles of the invention as described herein are contemplated as would normally occur to one skilled in the art to which the invention relates.
Referring first to
The mud system assembly 112 is shown to have mud pits and mud pumps, and further extends onto the derrick 102 in order to supply the mud into the drill string 106. Mud pumps push the mud all the way through the drill string 106 to the drill bit 110, where the mud lubricates the bit and flushes cuttings away. As more mud is pushed through the drill string 106, the mud fills the annulus around the drill string 106, inside the drill hole 108, and is pushed to the surface. At the surface the mud system assembly 112 recovers the mud and separates out the cuttings. The condition of the mud is assessed and additives are replenished as needed to achieve the necessary mud characteristics. Also at the surface a rig has a blow out prevention system to close in the well bore and protect the well site in the event of a kick as well, and a choke manifold and control system to manage pressurized well bore fluid returns and discharges.
On traditional rig 10, the systems described above are controlled through experience and human perceptions. In this disclosure, a workover rig will in most cases be included in the term traditional rig. Automated systems are available to substantially augment the skill of the operators for many of the systems on the rig 10. Sensors and monitors required for the operation of each automated system may be added to the drill string 106, drill bit 110, mud system assembly 112, pipe handler assembly 114, drawworks, rotary table 118, top drive assembly 116, automated tubular racking system 120, casing running system, floor wrench assembly 118, blow out preventors and choke manifold systems and any other drilling equipment/system on site and in use, with the data collected by the sensors and monitors directed to the doghouse 102 for the driller to review. The separate systems generate a substantial volume of data.
The present device and system offers the driller a unitary, integrated system that has an integrated control center that fits in a convenient space within the dog house. Additional displays and interfaces may be provisioned around the rig site as necessary. Typically the convenient space within the dog house is the knowledge box. In the present system, redundant sensors and monitors are eliminated, the automated controllers are consolidated into a single computer system, and outputs are standardized, for either or both transmission locally and remotely from the rig 10. Automated controllers may include such devices as programmable logic controllers (“PLCs”), programmable automation controllers, personal computers and micro controllers. The present device offers integrated assessment, documentation and control of the systems listed above as examples, as well as other systems involved in the operation of an automated drilling rig 10.
Referring now to
The exemplary control engine 200 is comprised of a user interface 22, a processor 24 and memory 26. The user interface 22 may include either or both local and remote access, and may support audio, visual and manual interaction with a user. The user interface 22 may employ communication assets from the equipment engine 204 to maximize the ability to interact with a user anywhere that user may be, at any time. The processor 24 may comprise a ruggedized relatively standard computer, which means it has been adapted to be rugged enough to withstand conditions on a drilling rig 10. The processor 24 may comprise multiple computers that are integrated to be interoperable. The memory 26 includes both working memory used to actively operate the system, and non-volatile memory, which maintains the ordered contained information even if power is suspended. Memory 26 may be either or both local and remote, and may be either or both fixed in the control engine 200 and removable.
The sensor engine 202 may include devices such as sensors, meters, and detectors, which can detect activity, conditions and circumstances in an area to which the device has access. Components of the sensor engine 202 are deployed at any and all operational areas where information on the conditions in that area may be desired by an operator. Areas for deployment of components include at or near the drill bit 110, the drill string 106, the mud system assembly 112, the pipe handler assembly 114, the top drive assembly 116, and the floor wrench assembly 118, for examples, to detect physical properties that are used by systems to assess the drilling operations. Any other operational system that may be added to the automated system 20 may require unique sensor engine 202 components that may need to be place in positions essential to that particular added system. Readings from the sensor engine 202 is fed back to the control engine 200. The control engine 200 may send signals to the sensor engine 202 to adjust the calibration or operational parameters. The sensor engine 202 is integrated because it contains sensing function for all the systems within the automation system 20, and has the capacity to incorporate more operational systems.
The operational equipment engine 204 may include devices that function to facilitate the drilling operation. The equipment engine 204 may include hydraulic rams, rotary drives, valves, and pumps, just to name a few examples. The equipment engine 204 may be designed to exchange communication with control engine 200, so as to not only receive instructions, but to provide information on the operation of equipment engine 204 apart from any associated sensor engine 202. The equipment engine 204 is integrated because it contains operational equipment functions for all the systems within the automation system 20, and had the capacity to incorporate more operational systems.
The report engine 206 collects information about the drilling operation and make the information available for continual and periodic report, and for historic archival purposes, singly or in varied combination. The report engine 206 may interact with the operator through the control engine 200 to assist the operator in completing reports and collecting archival information in an accurate and timely manner. The report engine 206 is integrated because it contains reporting, documenting and archival functions for all the systems within the automation system 20, and had the capacity to incorporate more operational systems.
Centralizing the coordination of data with the integrated automation system 20 may reduce redundancy of various components of individual systems, including automated controller's and operational sensors, as well simplifying and organizing operational interfaces, while at the same time locating the automated systems in the same place from where the manual operations were coordinated. The integrated automation system 20 may be installed in a traditional rig that does not currently have automated systems. The integrated automation system 20 may also be installed in a traditional rig has an automated system. In the latter situation the current disclosure may be used to integrate the existing system with additional systems, or may replace some or all of the existing components with different components to accomplish the same systemic objectives.
Referring now to
The exemplary automation system 20 includes an equipment condition system 302, a directional steering system 304, an electronic choke system 306, a drilling pressure system 308, a mud pump control system 310, a kill sheet system 312, a daily reporting system 314, a safety analysis and report system 316, a traveling equipment position system 318, a top drive position system 320, a pipe handler system 322, a floor wrench system 324, a remote access system 326, an autodriller system 328, a rig drilling data system 330, a pit volume totalizer system 332, a mud gas system 334, a mud flow system 336, a mud density system 338, a rig video system 340, automated tubular racking system 342, a casing running system 344, a BOP (“blowout preventer”) control system 346, a pipe centralizing arm system 348, a drawworks system 350, a coiled tubing unit system 352, a slips system 354, and a measurement-while-drilling (“MWD”) system 356. Many of these systems are available from multiple suppliers. Though the current system provides for integrating the varied systems, it may still be more desirable to obtain as many systems as possible from the same manufacture. Nabors Industries Ltd. may provide a number of the various systems through their affiliated companies.
The exemplary equipment condition system 302 includes equipment and control modules incorporable into the automation system 20 that performs condition monitoring and alarming. Condition monitoring includes the use of advanced technologies in order to determine equipment condition, and potentially predict failure. Such advanced technologies include, but is not limited to, vibration measurement and analysis, infrared thermography, oil analysis and tribology ultrasonics, and motor current analysis. Condition monitoring is most frequently used as a predictive or condition-based maintenance technique, however, there are other predictive maintenance techniques that can also be used, including the experienced use of the human physical senses, machine performance monitoring, and statistical process control techniques. A potentially acceptable system that may be modified and incorporated into the equipment condition system 302 includes the VibeHound Kit™, available from TECHKOR™ Instrumentation. A potentially acceptable system that may be modified and incorporated into the equipment condition system 302 includes the ThermCAM™ infrared camera systems, available from FLIR Systems. A potentially acceptable system that may be modified and incorporated into the equipment condition system 302 includes the Ultraprobe® ultrasound inspection system, available from UE Systems, Inc. A potentially acceptable system that may be modified and incorporated into the equipment condition system 302 includes electrical analysis systems available from AB SKF, of Sweden. Other equipment condition systems may be seen as advantageous for incorporation into an automation system 20, given the teachings of this disclosure. Such systems may be incorporable into the automation system 20 in a similar fashion, as described in this disclosure, and achieve similar improvements in reduction in space and elimination of redundancy of component parts.
The exemplary directional steering system 304 includes components of a directional drilling system incorporable into the automation system 20 that is able to determine and control the attitude of the drill bit 110 deployed in the drill hole 108. Accurate steering control enables positioning the drill hole 108 precisely in a subterranean formation in order to better assure a highly productive well. A potentially acceptable system that may be modified and incorporated into the directional steering system 304 includes the Direction Control Steering System, available from CANRIG Drilling Technology Ltd.
The exemplary electronic choke system 306 includes components of an actuator, a control system and a communication link that may be modified and incorporated into the electronic choke system 306. The control system is integrated in the automation system 20, as may be the communication link. A potentially acceptable system that may be modified and incorporated into the electronic choke system 306 includes the Pason Electronic Choke Actuators, available from Pason Systems Corporation.
The exemplary drilling pressure system 308 includes components of a pressure control system that maintains constant bottomhole pressure (“BHP”) while drilling. Drilling operations in challenging environments can benefit from being able to overcome the pressure limitations of conventional drilling and expand prospective drillable areas. Constant bottomhole pressure is achieved through rapid, dynamic and consistent backpressure control without interruption, with or without rig pumps. A potentially acceptable system that may be modified and incorporated into the drilling pressure system 308 includes the Dynamic Annular Pressure Control (“DAPC”) System, available from At Balance Americas L.L.C. The DAPC System can achieve constant BHP using a control system integrated with real-time hydraulics modeling, and an auxiliary pump to provide backpressure when the rig pumps are off.
The exemplary mud pump control system 310 includes components of a mud supply and circulation system that may be modified and incorporated into the mud pump control system 310. Mud pumps are typically large, high-pressure reciprocating pumps used to circulate the mud on a drilling rig 10. A typical mud pump is a two or three-cylinder piston pump with replaceable pistons that travel in replaceable liners, and are driven by a crankshaft actuated by an engine or a motor. Mud pumps keep the critical supply of mud moving to the bottom of the drill string 106 and back up the drill hole 108 to the surface for reclamation. The flow of mud must be maintained at an appropriate level as dictated by the situation being experienced. A control system switches the pumps on and off, and adjusts the pumps speed of operations, in order to adjust the rate of mud flow. A potentially acceptable system that may be modified and incorporated into the mud pump control system 310 includes an electric motor control system provided by National Oilwell Varco, of Houston, Tex.
The exemplary kill sheet system 312 includes components for completing well calculations. A kill sheet system will help drilling and workover personnel calculate data to successfully control the well. The system allows personnel to enter well data at the job site and then make calculations necessary to complete planning the tasks. A system should help eliminate mathematical errors while providing simple and consistent well calculation methods. A potentially acceptable system that may be modified and incorporated into the kill sheet system 312 includes the Kill Sheet Program, available from the Well Control School, of Houston, Tex.
The exemplary daily reporting system 314 includes components of systems that assist in the preparation of the various periodic reports required during drilling operations. A system may mimic a traditional tour sheet, plus may provide additional functionality, including payroll processing, safety and incident reporting, and sophisticated database analysis, including time-breakdown, pie-charts, and days versus depth plots. A potentially acceptable system that may be modified and incorporated into the daily reporting system 314 includes RIGREPORT™, an electronic tour sheet database system available from Epoch Well Services, Inc.
The exemplary safety analysis and report system 316 includes components of a rig electronic job safety analysis and incident reporting system that may be modified and incorporated into the safety analysis and report system 316. A safety analysis and report system may be a computerized application that the driller and rig crew use to preview and review work activities, and to report any near miss or injurious incidents on a day to day basis. A potentially acceptable system that may be modified and incorporated into the safety analysis and report system 316 includes RiskSafe™ 7, a qualitative workplace risk assessment software package, provided by Dyadem International Ltd., of Richmond Hill, Ontario, Canada. An additional potentially acceptable system that may be modified and incorporated into the safety analysis and report system 316 includes AIRSWEB™ reporting software system, by Safety Management Systems, Inc., of New York City, N.Y.
The exemplary traveling equipment position system 318 includes components of systems that monitor, anticipate, alert and avoid potential equipment collisions. Anti-collision systems include points along a line of travel where the system notes the potential for danger and either or both sounds an alarm and interrupts that movement. A potentially acceptable system that may be modified and incorporated into the traveling equipment position system 318 include the Traveling Equipment Anti-Collision System, available from Canrig Drilling Technology Ltd., and the Anti Collision System, available from Bentec GmbH Drilling & Oilfield Systems, of Germany.
The exemplary top drive position system 320 includes components of an alert system that warns the driller that the elevator links are in the over drill position and at risk of contacting the racking board if hoisting of the top drive continues. Key components are designed to ensure immediate and precise feedback to the driller that may, for example, be in the form of either or both an audible and visual alarm. Through the automation system 20, the top drive position system 320 may employ components of the traveling equipment position system 318 in order to avoid redundancy. A potentially acceptable system that may be modified and incorporated into the top drive position system 320 includes the Top Drive Elevator Position Alarm System, available from Canrig Drilling Technology Ltd.
The exemplary pipe handler system 322 includes components of tubular handling systems that may be modified and incorporated into the pipe handler system 322. Pipe handlers move tubulars, such as drill collars, drill pipe, casing, subs, logging tools and other tubulars, from a storage rack to the drill floor. Remote control systems permit system operation that almost eliminates human contact with the items being moved. Through the automation system 20, the pipe handler system 322 may employ components of the traveling equipment position system 318 in order to avoid redundancy. A potentially acceptable system that may be modified and incorporated into the pipe handler system 322 includes The PowerCAT™ Automated Catwalk, available from Canrig Drilling Technology Ltd.
The exemplary floor wrench system 324 includes components of an automated floor wrench system that operates to connect segments of drill pipe into a drill string 106. As with other engines, through the automation system 20, the floor wrench system 324 may share components of automation system 20 used by other engines in order to avoid redundancy. A potentially acceptable system that may be modified and incorporated into the floor wrench system 324 includes the Torq-Matic™ Fully Automated Floor Wrenches, available from Canrig Drilling Technology Ltd. The exemplary remote access system 326 includes components of communication systems that enable remote access and control of automated electronic and computerized systems. Some systems that may be suitable include connection to a local area network, an intranet, the internet or World Wide Web, email, and wireless broadband technologies, such as satellite, microwave, cellular, PCS, GSM, and others. For portions of the remote access system that may span shorter distances technologies such as infrared, Bluetooth®, and Wi-Fi® may be appropriate. A remote access system may permit modification, trouble-shooting and updating of the automation system 20, and its incorporated engines, from a remote location. A remote access system may also enable multi-directional transmission of reports and archival data. A potentially acceptable system that may be modified, in light of the present disclosure, and incorporated into the remote access system 326 includes communication equipment available through either or both Siemens AG and Rockwell Automation, of Milwaukee, Wis.
The exemplary autodriller engine 228 includes components of an autodriller system designed to monitor and adjust the weight on bit and differential pressure with acute precision in order to maximize the rate of penetration (“ROP”) of the drill bit 110. In an exemplary system the autodriller precisely actuates the drilling rig's 10 drawworks brake handle using continuous feedback from hook load, differential pressure and drawworks drum rotation. Absolute digital settings for either or both weight on bit (“WOB”) and differential pressure parameters may be entered into the system, which then permits adding weight to the bit until either or both the desired WOB and differential pressure is reached. A potentially acceptable system that may be modified and incorporated into the autodriller engine 228 includes the Pason Electronic AutoDriller, available from Pason Systems Corporation.
The exemplary rig drilling data system 330 includes components of a computerized local area network system that may have input and output stations throughout a drilling rig 10 to provide essential data needed at a particular location for the role of the people at that location. Drilling data may be viewed at the work station on the floor, in the doghouse, and by the company man and toolpusher. Each person may be able to pull up the information at any of these workstations, and necessary data can be logged and stored on site. A system may also permit secure remote access to the network, along with data transfer to locations worldwide, through the remote access system 326. Potentially acceptable systems that may be modified and incorporated into the rig drilling data system 330 include RIGCHART™, FLOWSHOW™, and RIGWATCH™, and may be supplemented with reporting tools, such as PERC™ and RIGREPORT™, each available from Epoch Well Services, Inc. An additionally potentially acceptable system that may be modified and incorporated into the rig drilling data system 330 includes the Pason EDR, for electronic drilling recorder, available from Pason Systems Corporation.
The exemplary pit volume totalizer system 332 includes components of an integrated system for the management of mud volumes throughout the mud system. Such systems take into consideration intermittent power and the potential for a critical situation to arise quickly, and manage the positioning of mud to be able to address unfavorable situations. A potentially acceptable system that may be modified and incorporated into the pit volume totalizer system 332 includes the Pason Pit-Bull™ Pit Volume Totalizer & Flow Show, available from Pason Systems Corporation.
The exemplary mud gas system 334 includes components of a system to detect changes in relative volumes of hydrocarbon gases at the surface without complex offline analysis, delicate instrumentation, or expensive gas chromatographs. The system may send data via remote access system 326 to relevant observers wherever they may be located. Alarms can be set to notify the geologist if the gas level in the mud reaches or falls below a desired percent setting. A potentially acceptable system that may be modified and incorporated into the mud gas system 334 includes the Pason Total Gas System, available from Pason Systems Corporation.
The exemplary mud flow system 336 includes components of a system to monitor mud flow rate and velocity sensor, which has proven to be effective for early gas kick detection through recognizing changes in the flow rate. Early detection permits rig personnel extra time to mitigate an upcoming gas bubble. A potentially acceptable system that may be modified and incorporated into the mud flow system 336 includes the Rolling Float Meter, available from Epoch Well Services, Inc.
The exemplary mud density system 338 includes components of a system to monitor and maintain the density of the drilling mud. Automated sensors and the digital electronics are immersed in the mud pit in order to maintain continual monitoring. A potentially acceptable system that may be modified and incorporated into the mud density system 338 includes the Mud Density Sensor, available from Epoch Well Services, Inc.
The exemplary rig video system 340 includes components of a camera, recorder and surveillance system that typically operate within a controlled area network. Within the automation system 20, the video system may provide real-time visual monitoring and inspection of operational areas that can be done from the doghouse, or anywhere in the world. A potentially acceptable system that may be modified and incorporated into the rig video system 340 includes the HERNIS CCTV Systems, available from Hernis Scan Systems AS, of Norway.
The exemplary automated tubular racking system 342 includes components of a system to move the drilling pipe sections between a storage rack and an operational position. A potentially acceptable system that may be modified and incorporated into the automated tubular racking system 342 includes the Iron Derrickman™ racking board mounted pipe handling system, available from Iron Derrickman Ltd., of Calgary, Alberta, Canada.
The exemplary casing running system 344 includes components of a system to supply makeup, torsional and axial loads from the top drive to the drilling string. The drilling string may be comprised of a conventional drilling string or the casing. A potentially acceptable system that may be modified and incorporated into the casing running system 344 includes the Casing Drive System™, by Tesco Corporation, of Calgary, Alberta, Canada.
The exemplary BOP control system 346 includes components of a blowout preventer system at the top of a well permits the drill hole 108 to be closed if the drilling crew loses control of formation fluids. By closing the BOP, the drilling crew may regain control of the reservoir, typically by increasing the mud density until it is possible to open the BOP and retain pressure control of the formation. A potentially acceptable system that may be modified and incorporated into the BOP control system 346 includes the U-BOP™ blowout preventer, by Cameron International Corporation, of Houston, Tex.
The exemplary pipe centralizing arm system 348 includes components of a system to guide the operation of drill pipe and drill collars being handled by hoisting equipment. A pipe centralizing arm system is typically mounted on the derrick 102. A potentially acceptable system that may be modified and incorporated into the pipe centralizing arm system 348 includes the Stabber Arm™ stabilizer arm and control system available from National Oilwell Varco. An additional potentially acceptable system that may be modified and incorporated into the pipe centralizing arm system 348 includes the ODS™ stabilizer arm and control system available from ODS International Inc., Houston, Tex.
The exemplary drawworks system 350 includes components of a system to reel out and reel in the drilling line in a controlled fashion, thereby causing items hung in a well to be lowered into or raised out of the drill hole 108. A typical drawworks consists of a large-diameter steel spool, brakes, a power source and assorted auxiliary devices. A potentially acceptable system that may be modified and incorporated into the drawworks system 350 includes the IDM MAC™ modular AC drawworks, by IDM Equipment Ltd., Houston, Tex.
The exemplary coiled tubing unit system 352 includes components of a system to control, feed and withdraw coiled tubing string within a drill hole 108. A potentially acceptable system that may be modified and incorporated into the coiled tubing unit system 352 includes the Coiled Tubing Injector Head by PSL Energy Services, of Portlethen, Aberdeen, United Kingdom.
The exemplary slips system 354 includes components of a system to engage the drill string in order to perform pipe handling operations. A potentially acceptable system that may be modified and incorporated into the slips system 354 includes the PS 500 Power Slip drill floor slip, by Blohm+Voss Repair GmbH, of Hamburg, Germany.
The exemplary MWD system 356 includes components of a system to evaluate the physical properties, usually including pressure, temperature and wellbore trajectory in three-dimensional space, while extending a wellbore. Measurements are typically made downhole, stored in solid-state memory for some time and later transmitted to the surface. A potentially acceptable system that may be modified and incorporated into the MWD system 356 includes the Ryan's Measurement While Drilling (MWD) system, by Ryan Energy Technologies USA, Inc., Houston, Tex.
An assortment of operating systems, either or both including or similar to those described above may be included in the automation system 20. An administrator of the automation system 20 may dynamically activate a chosen operating system. Activation provides the operator with access to the functionality of the activated operating system. Similarly, an administrator of the automation system 20 may dynamically deactivate a chosen operating system, denying the operator the functionality of the deactivated operating system. The dynamic activation and deactivation may occur either or both locally to the automation system 20, and remotely, and may be executed by any individual or combination of techniques, including manual, electronic, automated and computerized.
Referring to
The keyboard 406 provides data entry capability to the overall user interface 22 (shown in
The video displays 412 may display an assortment of information and data, including an operational software interface for each of the automation system's 20 operational, monitoring and reporting systems 302-356, examples of which are shown in
The manual equipment engine controls 414 may be considered operational systems controls, since they permit the user of the automation system 200 to affirmatively affect the operation of particular pieces of the equipment engine 204 (shown in
The operational system control circuitry 416 may include specialized circuits essential to the operation of a particular operational engine. The circuitry is integrated into the control engine 200 to share user interface 22, the computer 410 and the displays 412, as well as any operational elements that would be duplicated in stand-alone operational systems. In an exemplary embodiment, the integration of operational systems may be accomplished through a number of various bus and interfaces configurations, including OLE for Process Control (OPC), MODBUS, Transmission Control Protocol (TCP), WITS telemetry protocol, DF-1 protocol, PROFIBUS, also known as Process Field Bus, serial bus, universal serial bus, Ethernet, 802-11x standards, and current loops, including 4-20 mA, to name a few examples.
In an exemplary embodiment, the operational system control circuitry 416 facilitates the communication of control engine 200 with the integrated sensor engine 202, the integrated equipment engine 204, and the integrated report engine 206 through electrical wiring, either wired directly or through any of a variety of bus configurations. The electronic signals may activate horn, lights for alarms, the recording of information in memory to act as a chart recorder. The electronic signals may travel through the user interface 22 to other computer systems, where additional processing and archival operations may occur. In an exemplary embodiment, the control engine 200 sends controlling outputs from its processor 24 to external devices and equipment for control purposes via electronic signals that may operate within the configurations of 4-20 mA, 0-24 V DC and 0-10 V DC.
The K-Box device 40 may serve as a platform to add new technologies to a rig 10 without having to design a new enclosure. Technologies such as joystick controls, crown floor savers, autodrillers, video monitors, and etcetera, can be added to the console without major modifications. Through the K-Box device 40, the new technology becomes integral to the rig 10. The K-Box device 40 can easily be repackaged to adapt to changes in the doghouse 104, such as the addition of a chair or complete driller's console. In an alternate embodiment, various components, such as the work surface 402, may be eliminated.
Referring to
In the exemplary embodiment, autodriller controls 418 include a ROP control knob, a WOB control knob, delta pressure control knob, an E-Stop button, a start button, a stop button, and an alarm ack button. The ROP control knob, which is similar to a potentiometer, allows for setting of the ROP set point or target, and the ROP limit or shutdown. The WOB control knob, which is similar to a potentiometer, allows for setting of the WOB set point or target, and the WOB limit or shutdown. A delta pressure control knob, which is similar to a potentiometer, allows for setting of a differential pressure set point or target, a differential pressure limit or shutdown, and a mud pump high pressure alarm point. An E-Stop or emergency stop mushroom maintained pushbutton to stop automatic driller. A start illuminated momentary pushbutton to start automatic driller and provide indication when running. A stop momentary pushbutton to stop the automatic driller. An Alarm Ack or alarm acknowledgement illuminated momentary pushbutton to provide visual indication of autodriller alarms, and a method for acknowledgement and horn silencing.
In the exemplary embodiment, console alarm control 420 includes an Off/On maintained two-position indicator that illuminates when an alarm is present and allows the DAQ alarm horn to be turned off. In the exemplary embodiment, directional steering control system control 422 includes an Off/On maintained two-position selector switch that turns the directional steering control system off and on.
In the exemplary embodiment, choke controls 424 include two Open/Close spring return-to-center three-position selectors used to open and close chokes 1 and 2, respectively, and a display momentary pushbutton used to immediately select the choke display on video display 412. In the exemplary embodiment, crown/floor saver control 426 include a Saver On indicator that provides visual indication that the crown/floor saver is active. In the exemplary embodiment, mudpump control 428 includes a Stop mushroom maintained pushbutton to stop the mud pumps. In the exemplary embodiment, keyboard control 430 includes a Left/Right maintained two-position switch that allows one keyboard to be used with two displays as video display 412.
In the exemplary embodiment, power controls 432 include a Wireless On\Off maintained two-position key switch that interrupts power to the wireless, which is typically used when perforating or completing a well, and a Console On illuminated momentary pushbutton, which performs the operations of a steady-on light to indicate UPS and conditioned power normal, a blinking light to indicate the K-Box device 40 is on UPS power, and a test lamp function when the pushbutton is depressed.
Referring to
The K-box device 40 has a desktop 402 to complete manual reports, and also has a computerized interface devices, such as keyboard 406, pointing device 408, and video displays 412 located to control and monitor all activities, as part of the automated system's 20 user interface 22. By reducing the number of independent system interfaces, which may be combined into the control engine 200, sufficient space is recovered to permit the use of standard computers and monitors ruggedized for the intended environment.
The communication links installed at 506 permits the coupled elements and engines to transfer and exchange data, and may include conventional wiring, and may incorporate wireless communication methods, such as infrared, Wi-Fi® and BlueTooth®, which are provided merely as examples. The link capacity established at 506 may connect the control engine 200 with any element of the sensor engine 202, the operational equipment engine 204, and the report engine 206. Additionally, the link capacity established at 506 may be installed in anticipation of future elements, so that, for example, a particular sensor may not be available, but the communication is put in place in anticipation of the sensor.
The sensors and equipment controls installed at 508 include the various sensors and meters to provide necessary input to the control engine 200, as well as hydraulic rams, valves, pumps and other pieces of equipment that are operable by the automated systems 20.
At 510, the functionality of a particular engine is activated within the control engine 200. In this fashion, a unitary control engine 200 can be produced by a supplier, comprising a full set of operational engines, and the functionality either needed or wanted by a user can be customized as necessary, making only those engines purchased by the user operational. The activation, or deactivation, of selected engines at 510 may occur at any time during the operation of the automation system 20, as controlled by a system administrator. With the availability of remote communication with control engine 200, the system administrator could be located anywhere in the world while modifying the functionality of the automation system 20.
Referring now to
In the exemplary embodiment, the toolbar 602 includes a button to create a “chat” or discussion group regarding information coming from the system 20, a button that initiates modification of the display screen 600 and drill mode of the system 20, a button to mute alarms, a button to open a pop-up keypad, a button to initiate help and a button to lock the click operation of display screen 600.
In the exemplary embodiment, the display area 606 includes information regarding drilling operations and the rig drilling system 330, including the ROP, gas units, hook load, WOB, pump pressure, RPM's, total pit volume, and total pump operation time. A rig drilling data system 330 may obtain information to display in display are 606 from a variety of sources, including a hookload sensor, a pump pressure sensor, a pump stroke sensor, a casing pressure sensor, a return flow sensor, a block position or ROP sensor, a pit levels sensor, a bit torque sensor, a bit RPM sensor, a top drive elevator position sensor, a MWD sensor, and an alarm system. The sensors within rig drilling system 330 may provide analog or digital signals to the automation system 200, wherein the processor 24 uses the information to render a representative image of what the data means through the user interface 22, which in this example is the display screen 600. The connection between the sensors and the automation system 200 may be made with dedicated connections or may be connected through any of a variety of shared bus configurations. An exemplary embodiment may display other information than that shown, pertaining to the rig drilling system 330.
In the exemplary embodiment, the system display area 608 includes information regarding the electronic choke system 306, and includes operational buttons to open or close the choke, as well as a button to render information regarding choke position on the video display 412. A choke control system 306 may obtain information to display in display area 608 from a variety of sources, including a pump pressure sensor, a pump stroke sensor, a casing pressure sensor, a return flow sensor, a pit levels sensor, and an alarm system. The sensors within electronic choke system 306 may provide analog or digital signals to the automation system 200, wherein the processor 24 uses the information to render a representative image of what the data means through the user interface 22, which in this example is the display screen 600. The connection between the sensors and the automation system 200 may be made with dedicated connections or may be connected through any of a variety of shared bus configurations. An exemplary embodiment may display other information obtainable than that shown pertaining to the electronic choke system 306.
In the exemplary embodiment, the paired analog and digital displays area 610 includes information regarding the drilling pressure system 308, and includes the pump pressure, the casing pressure, the strokes per minute total, and the block position. A managed pressure drilling system 308 may obtain information to display in display area 610 from a variety of sources, including a hookload sensor, a pump pressure sensor, a pump stroke sensor, a casing pressure sensor, a return flow sensor, a block position or ROP sensor, and an alarm system. The sensors within drilling pressure system 308 may provide analog or digital signals to the automation system 200, wherein the processor 24 uses the information to render a representative image of what the data means through the user interface 22, which in this example is the display screen 600. The connection between the sensors and the automation system 200 may be made with dedicated connections or may be connected through any of a variety of shared bus configurations. An exemplary embodiment may display other information than that shown pertaining to the drilling pressure system 308.
In the exemplary embodiment, the historical data display area 612 includes additional information regarding the drilling pressure system 308, and includes a historical graph that is developed in realtime of the pump pressure, the casing pressure, the strokes per minute total, and the fullup volume. The sensors within drilling pressure system 308 may provide analog or digital signals to the automation system 200, wherein the processor 24 uses the information to render a representative image of what the data means through the user interface 22, which in this example is the display screen 600. An exemplary embodiment may display other historical information pertaining to the drilling pressure system 308 that the processor 24 can render from the information obtained by various sensors.
In an exemplary embodiment, the system display area 614 includes information regarding the drilling operations and the rig drilling data system 330, including total strokes, fill up volume, gain/loss and circulating hours. An exemplary embodiment may display other information pertaining to the rig drilling data system 330.
In the exemplary embodiment, the paired analog and digital displays area 616 includes information regarding the drilling operations and the rig drilling data system 330, including the block position. An exemplary embodiment may include paired analog and digital displays of other information pertaining to the rig drilling data system 330.
The present device permits a substantial reduction in redundancy created by the prior approach of installing individual, disparate systems. A prior art auto driller system 328 may have a hookload sensor, a pump pressure sensor, a pump stroke sensor, a casing pressure sensor, a block position or ROP sensor, a bit torque sensor, a bit RPM sensor, a top drive elevator position sensor, a MWD sensor, an alarm system, a visual display, and a set of operational controls. A prior rig drilling data system 330 may have a hookload sensor, a pump pressure sensor, a pump stroke sensor, a casing pressure sensor, a return flow sensor, a block position or ROP sensor, a pit levels sensor, a bit torque sensor, a bit RPM sensor, a top drive elevator position sensor, a MWD sensor, an alarm system, and four visual displays. A prior mud logging system may have a hookload sensor, a pump pressure sensor, a pump stroke sensor, a casing pressure sensor, a return flow sensor, a block position or ROP sensor, a pit levels sensor, a MWD sensor, an alarm system, and two visual displays. A prior MWD system 356 may have a pump pressure sensor, a return flow sensor, a block position or ROP sensor, a MWD sensor, an alarm system, and two visual displays. A prior directional drilling system may have a hookload sensor, a pump pressure sensor, a pump stroke sensor, a casing pressure sensor, a return flow sensor, a block position or ROP sensor, a bit torque sensor, a bit RPM sensor, a MWD sensor, an alarm system, and a visual display. A prior directional steering control system 304 may have a bit torque sensor, a bit RPM sensor, a MWD sensor, an alarm system, a visual display, and a set of operational controls. A prior top drive position system 320 may have a block position or ROP sensor, a bit torque sensor, a bit RPM sensor, a top drive elevator position sensor, an alarm system, a visual display, and a set of operational controls. A prior equipment condition monitoring (“ECM”) system 302 may have a hookload sensor, a pump pressure sensor, a pump stroke sensor, a casing pressure sensor, a return flow sensor, a block position or ROP sensor, a pit levels sensor, a bit torque sensor, a bit RPM sensor, a top drive elevator position sensor, a MWD sensor, an alarm system, and a visual display. A prior mud pump synchronizer (“MP Sync”) may have pump stroke sensor, an alarm system, a visual display, and a set of operational controls. A prior soft torque system may have a hookload sensor, a bit torque sensor, a bit RPM sensor, an alarm system, a visual display, and a set of operational controls. A prior crown floor saver system may have a block position or ROP sensor, a top drive elevator position sensor, an alarm system, a visual display, and a set of operational controls. A prior choke control system 306 may have a pump pressure sensor, a pump stroke sensor, a casing pressure sensor, a return flow sensor, a pit levels sensor, an alarm system, a visual display, and a set of operational controls. A prior managed pressure drilling system 308 may have a hookload sensor, a pump pressure sensor, a pump stroke sensor, a casing pressure sensor, a return flow sensor, a block position or ROP sensor, an alarm system, two visual displays, and a set of operational controls. If all of these systems were to be combined in a single automation system 20, according to the current disclosure, the exemplary automation system 20 could result in a reduction of five hookload sensors, six pump pressure sensors, seven pump stroke sensors, five casing pressure sensors, five return flow sensors, seven block position or ROP sensors, three pit levels sensors, six bit torque sensors, six bit RPM sensors, four top drive elevator position sensors, six MWD sensors, twelve alarm systems, seventeen visual displays, and seven sets of operational controls.
Although only a few exemplary embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the exemplary embodiments without materially departing from the novel teachings and advantages of this disclosure. Accordingly, all such adjustments and alternatives are intended to be included within the scope of the invention, as defined exclusively in the following claims. Those skilled in the art should also realize that such modifications and equivalent constructions or methods do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions, and alternations herein without departing from the spirit and scope of the present disclosure.
This application claims the benefit of provisional Application No. 60/886,259, filed Jan. 23, 2007, entitled “Method, Device and System for Drilling Rig Modification,” which is hereby incorporated by reference.
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| Number | Date | Country | |
|---|---|---|---|
| 20080173480 A1 | Jul 2008 | US |
| Number | Date | Country | |
|---|---|---|---|
| 60886259 | Jan 2007 | US |
