US20170101827A1

US20170101827A1 - Integrated skidding rig system

Info

Publication number: US20170101827A1
Application number: US14/983,332
Authority: US
Inventors: Jacques Orban
Original assignee: Schlumberger Technology Corp
Current assignee: Schlumberger Technology Corp
Priority date: 2015-10-07
Filing date: 2015-12-29
Publication date: 2017-04-13
Also published as: WO2017062213A1

Abstract

A rig system and a method for drilling a well. The rig system includes a movable central package including one or more devices to drill a well using a drill pipe, a mud pump coupled with the movable central package and configured to pump mud thereto, and a cement pump coupled with the movable central package. The cement pump is operable in a first mode in which the cement pump pumps cement to the well, and a second mode in which the cement pump pumps mud to the well.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Patent Application having Ser. No. 62/238,508, which was filed on Oct. 7, 2015 and is incorporated by reference herein in its entirety.

BACKGROUND

A drilling rig may be used to drill wellbores into the Earth in order to recover fluid, such as hydrocarbons, therefrom. Generally, drilling rigs are relatively large structures, which include a rig floor with a rotary table or bushing therein that provides access through the rig floor to the top of the well (“well head”). The rig may also include a drilling assembly, which may include a top drive suspended from a travelling block and supported by a mast. An elevator, pipe manipulator, or another type of hoisting structure may be attached to a stand of tubulars (e.g., one or more joints of drill pipe), lifting the stand into position above the well. Each successive stand is threaded (“made-up”) to the previously-run joint, and then the string is lowered generally by the length of the new stand. This process is repeated for potentially hundreds of stands of pipe, until the well reaches a desired depth. During the drilling process, the well is typically cased and cemented after sections of the well are drilled. During such casing and cementing, the drilling process stops and restarts after the cement has sufficiently set in the well.
Multiple wells may be drilled over one pad. This is a convenient method to limit the number of times that well equipment may be accessed during drilling and production. In such application, the drilling rig may complete one well, then it may be skidded (moved) to the next well location with minimum disassembly, and then the next well of the pad can be drilled and completed.
Recently, a batch drilling concept has been identified as a way to reduce delays due to the staged drilling, casing, and cementing operations. Basically, several wells in an identified location (“pad”) are drilled in parallel using a single, movable rig. Thus, for example, a top section of a first well may be drilled, and then the rig may move to a second location on the pad, and drill a top section of a second well. Meanwhile, the top section of the first well is cased and cemented. After a certain number of top sections of different wells are drilled, the rig returns to the first well and drills the next section, and the process repeats.
Movable (“skiddable”) rigs, however, present a host of challenges, since most rig technology is designed for generally stationary rigs meant to complete one well at a time. Moreover, the complexity introduced by the movable rigs may call for additional personnel and/or more-qualified personnel at the rig site, and additional hydraulic and electrical connections between the stationary components and the movable components, which may at least partially negate cost savings realized by greater efficiency using batch drilling techniques.
Furthermore, in many drilling operations, different service companies provide various different components of the drilling rig system. For example, one company might provide the managed pressure drilling system, while another might provide cement pumps, and a third provides mud pumps. Each time a service is completed, the associated service provider may remove its equipment and move to another job or location.

SUMMARY

Embodiments of the disclosure may provide a rig system. The rig system includes a movable central package including one or more devices to drill a well using a drill pipe, a mud pump coupled with the movable central package and configured to pump mud thereto, and a cement pump coupled with the movable central package. The cement pump is operable in a first mode in which the cement pump pumps cement to the well, and a second mode in which the cement pump pumps mud to the well.
Embodiments of the disclosure may further provide a method for drilling a well using a movable rig. The method includes pumping a mud into a wellbore using at least one mud pump while drilling the wellbore, pumping the mud into the wellbore using at least one cement pump in a first mode, while drilling the wellbore and while pumping mud into the wellbore using the at least one mud pump, and pumping cement into the wellbore using the at least one cement pump in a second mode.
Embodiments of the disclosure may also provide a rig system. The rig system includes a movable central package comprising one or more devices to drill a well using a drill pipe, and a mud pump coupled with the movable central package and configured to pump mud thereto. The mud pump is configured to pump the mud in a first mode, and wherein the mud pump is configured to pump cement to the central package in a second mode. The system further includes a cement pump coupled with the movable central package, with the cement pump being operable in a first mode in which the cement pump pumps cement to the well, and a second mode in which the cement pump pumps mud to the well. The system also includes a combined skid that is movable along with the movable central package, with the combined skid including a managed pressure drilling system and a shaker assembly. The system additionally includes a plurality of variable frequency drives (VFDs), with individual VFDs being separately coupled to the central package, the mud pump, and the cement pump. The system further includes a plurality of controllers, with individual controllers of the plurality of controllers being separately coupled to the central package, the mud pump, and the cement pump, to provide quasi-independent control thereof. Further, the movable central package is movable relative to the mud pump and the cement pump, and wherein the movable central package is configured for batch drilling.
It will be appreciated that the foregoing summary is intended merely to introduce a subset of the features described in greater detail below, and is not intended to be exhaustive or to limit the scope of the disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate embodiments of the present teachings and together with the description, serve to explain the principles of the present teachings. In the figures:

FIG. 1 illustrates a schematic view of a drilling rig and a control system, according to an embodiment.

FIG. 2 illustrates a schematic view of a drilling rig and a remote computing resource environment, according to an embodiment.

FIG. 3 illustrates a plan, schematic view of a drilling rig system, according to an embodiment.

FIG. 4 illustrates a conceptual, schematic view of a portion of the drilling rig system, according to an embodiment.

FIG. 5 illustrates a conceptual, schematic view of electrical connections between a generator and several example subsystems of the drilling rig, according to an embodiment.

FIG. 6 illustrates a schematic view of a computing system, according to an embodiment.

DETAILED DESCRIPTION

Reference will now be made in detail to specific embodiments illustrated in the accompanying drawings and figures. In the following detailed description, numerous specific details are set forth in order to provide a thorough understanding of the invention. However, it will be apparent to one of ordinary skill in the art that embodiments may be practiced without these specific details. In other instances, well-known methods, procedures, components, circuits, and networks have not been described in detail so as not to unnecessarily obscure aspects of the embodiments.
It will also be understood that, although the terms first, second, etc. may be used herein to describe various elements, these elements should not be limited by these terms. These terms are only used to distinguish one element from another. For example, a first object could be termed a second object or step, and, similarly, a second object could be termed a first object or step, without departing from the scope of the present disclosure.
The terminology used in the description of the invention herein is for the purpose of describing particular embodiments only and is not intended to be limiting. As used in the description of the invention and the appended claims, the singular forms “a,” “an” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will also be understood that the term “and/or” as used herein refers to and encompasses any and all possible combinations of one or more of the associated listed items. It will be further understood that the terms “includes,” “including,” “comprises” and/or “comprising,” when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof. Further, as used herein, the term “if” may be construed to mean “when” or “upon” or “in response to determining” or “in response to detecting,” depending on the context.
FIG. 1 illustrates a conceptual, schematic view of a control system 100 for a drilling rig 102, according to an embodiment. The control system 100 may include a rig computing resource environment 105, which may be located onsite at the drilling rig 102 and, in some embodiments, may have a coordinated control device 104. The control system 100 may also provide a supervisory control system 107. In some embodiments, the control system 100 may include a remote computing resource environment 106, which may be located offsite from the drilling rig 102.
The remote computing resource environment 106 may include computing resources locating offsite from the drilling rig 102 and accessible over a network. A “cloud” computing environment is one example of a remote computing resource. The cloud computing environment may communicate with the rig computing resource environment 105 via a network connection (e.g., a WAN or LAN connection). In some embodiments, the remote computing resource environment 106 may be at least partially located onsite, e.g., allowing control of various aspects of the drilling rig 102 onsite through the remote computing resource environment 105 (e.g., via mobile devices). Accordingly, “remote” should not be limited to any particular distance away from the drilling rig 102.
Further, the drilling rig 102 may include various systems with different sensors and equipment for performing operations of the drilling rig 102, and may be monitored and controlled via the control system 100, e.g., the rig computing resource environment 105. Additionally, the rig computing resource environment 105 may provide for secured access to rig data to facilitate onsite and offsite user devices monitoring the rig, sending control processes to the rig, and the like.
Various example systems of the drilling rig 102 are depicted in FIG. 1. For example, the drilling rig 102 may include a downhole system 110, a fluid system 112, and a central system 114. These systems 110, 112, 114 may also be examples of “subsystems” of the drilling rig 102, as described herein. In some embodiments, the drilling rig 102 may include an information technology (IT) system 116. The downhole system 110 may include, for example, a bottomhole assembly (BHA), mud motors, sensors, etc. disposed along the drill string, and/or other drilling equipment configured to be deployed into the wellbore. Accordingly, the downhole system 110 may refer to tools disposed in the wellbore, e.g., as part of the drill string used to drill the well.
The fluid system 112 may include, for example, drilling mud, pumps, valves, cement, mud-loading equipment, mud-management equipment, pressure-management equipment, separators, and other fluids equipment. Accordingly, the fluid system 112 may perform fluid operations of the drilling rig 102.
The central system 114 may include a hoisting and rotating platform, top drives, rotary tables, kellys, drawworks, pumps, generators, tubular handling equipment, derricks, masts, substructures, and other suitable equipment. Accordingly, the central system 114 may perform power generation, hoisting, and rotating operations of the drilling rig 102, and serve as a support platform for drilling equipment and staging ground for rig operation, such as connection make up, etc. The IT system 116 may include software, computers, and other IT equipment for implementing IT operations of the drilling rig 102.
The control system 100, e.g., via the coordinated control device 104 of the rig computing resource environment 105, may monitor sensors from multiple systems of the drilling rig 102 and provide control commands to multiple systems of the drilling rig 102, such that sensor data from multiple systems may be used to provide control commands to the different systems of the drilling rig 102. For example, the system 100 may collect temporally and depth aligned surface data and downhole data from the drilling rig 102 and store the collected data for access onsite at the drilling rig 102 or offsite via the rig computing resource environment 105. Thus, the system 100 may provide monitoring capability. Additionally, the control system 100 may include supervisory control via the supervisory control system 107.
In some embodiments, one or more of the downhole system 110, fluid system 112, and/or central system 114 may be manufactured and/or operated by different vendors. In such an embodiment, certain systems may not be capable of unified control (e.g., due to different protocols, restrictions on control permissions, safety concerns for different control systems, etc.). An embodiment of the control system 100 that is unified, may, however, provide control over the drilling rig 102 and its related systems (e.g., the downhole system 110, fluid system 112, and/or central system 114, etc.). Further, the downhole system 110 may include one or a plurality of downhole systems. Likewise, fluid system 112, and central system 114 may contain one or a plurality of fluid systems and central systems, respectively.
In addition, the coordinated control device 104 may interact with the user device(s) (e.g., human-machine interface(s)) 118, 120. For example, the coordinated control device 104 may receive commands from the user devices 118, 120 and may execute the commands using two or more of the rig systems 110, 112, 114, e.g., such that the operation of the two or more rig systems 110, 112, 114 act in concert and/or off-design conditions in the rig systems 110, 112, 114 may be avoided.
FIG. 2 illustrates a conceptual, schematic view of the control system 100, according to an embodiment. The rig computing resource environment 105 may communicate with offsite devices and systems using a network 108 (e.g., a wide area network (WAN) such as the internet). Further, the rig computing resource environment 105 may communicate with the remote computing resource environment 106 via the network 108. FIG. 2 also depicts the aforementioned example systems of the drilling rig 102, such as the downhole system 110, the fluid system 112, the central system 114, and the IT system 116. In some embodiments, one or more onsite user devices 118 may also be included on the drilling rig 102. The onsite user devices 118 may interact with the IT system 116. The onsite user devices 118 may include any number of user devices, for example, stationary user devices intended to be stationed at the drilling rig 102 and/or portable user devices. In some embodiments, the onsite user devices 118 may include a desktop, a laptop, a smartphone, a personal data assistant (PDA), a tablet component, a wearable computer, or other suitable devices. In some embodiments, the onsite user devices 118 may communicate with the rig computing resource environment 105 of the drilling rig 102, the remote computing resource environment 106, or both.
One or more offsite user devices 120 may also be included in the system 100. The offsite user devices 120 may include a desktop, a laptop, a smartphone, a personal data assistant (PDA), a tablet component, a wearable computer, or other suitable devices. The offsite user devices 120 may be configured to receive and/or transmit information (e.g., monitoring functionality) from and/or to the drilling rig 102 via communication with the rig computing resource environment 105. In some embodiments, the offsite user devices 120 may provide control processes for controlling operation of the various systems of the drilling rig 102. In some embodiments, the offsite user devices 120 may communicate with the remote computing resource environment 106 via the network 108.
The user devices 118 and/or 120 may be examples of a human-machine interface. These devices 118, 120 may allow feedback from the various rig subsystems to be displayed and allow commands to be entered by the user. In various embodiments, such human-machine interfaces may be onsite or offsite, or both.
The systems of the drilling rig 102 may include various sensors, actuators, and controllers (e.g., programmable logic controllers (PLCs)), which may provide feedback for use in the rig computing resource environment 105. For example, the downhole system 110 may include sensors 122, actuators 124, and controllers 126. The fluid system 112 may include sensors 128, actuators 130, and controllers 132. Additionally, the central system 114 may include sensors 134, actuators 136, and controllers 138. The sensors 122, 128, and 134 may include any suitable sensors for operation of the drilling rig 102. In some embodiments, the sensors 122, 128, and 134 may include a camera, a pressure sensor, a temperature sensor, a flow rate sensor, a vibration sensor, a current sensor, a voltage sensor, a resistance sensor, a gesture detection sensor or device, a voice actuated or recognition device or sensor, or other suitable sensors.
The sensors described above may provide sensor data feedback to the rig computing resource environment 105 (e.g., to the coordinated control device 104). For example, downhole system sensors 122 may provide sensor data 140, the fluid system sensors 128 may provide sensor data 142, and the central system sensors 134 may provide sensor data 144. The sensor data 140, 142, and 144 may include, for example, equipment operation status (e.g., on or off, up or down, set or release, etc.), drilling parameters (e.g., depth, hook load, torque, etc.), auxiliary parameters (e.g., vibration data of a pump) and other suitable data. In some embodiments, the acquired sensor data may include or be associated with a timestamp (e.g., a date, time or both) indicating when the sensor data was acquired. Further, the sensor data may be aligned with a depth or other drilling parameter.
Acquiring the sensor data into the coordinated control device 104 may facilitate measurement of the same physical properties at different locations of the drilling rig 102. In some embodiments, measurement of the same physical properties may be used for measurement redundancy to enable continued operation of the well. In yet another embodiment, measurements of the same physical properties at different locations may be used for detecting equipment conditions among different physical locations. In yet another embodiment, measurements of the same physical properties using different sensors may provide information about the relative quality of each measurement, resulting in a “higher” quality measurement being used for rig control, and process applications. The variation in measurements at different locations over time may be used to determine equipment performance, system performance, scheduled maintenance due dates, and the like. Furthermore, aggregating sensor data from each subsystem into a centralized environment may enhance drilling process and efficiency. For example, slip status (e.g., in or out) may be acquired from the sensors and provided to the rig computing resource environment 105, which may be used to define a rig state for automated control. In another example, acquisition of fluid samples may be measured by a sensor and related with bit depth and time measured by other sensors. Acquisition of data from a camera sensor may facilitate detection of arrival and/or installation of materials or equipment in the drilling rig 102. The time of arrival and/or installation of materials or equipment may be used to evaluate degradation of a material, scheduled maintenance of equipment, and other evaluations.
The coordinated control device 104 may facilitate control of individual systems (e.g., the central system 114, the downhole system, or fluid system 112, etc.) at the level of each individual system. For example, in the fluid system 112, sensor data 128 may be fed into the controller 132, which may respond to control the actuators 130. However, for control operations that involve multiple systems, the control may be coordinated through the coordinated control device 104. Examples of such coordinated control operations include the control of downhole pressure during tripping. The downhole pressure may be affected by both the fluid system 112 (e.g., pump rate and choke position) and the central system 114 (e.g. tripping speed). When it is desired to maintain certain downhole pressure during tripping, the coordinated control device 104 may be used to direct the appropriate control commands. Furthermore, for mode based controllers which employ complex computation to reach a control setpoint, which are typically not implemented in the subsystem PLC controllers due to complexity and high computing power demands, the coordinated control device 104 may provide the adequate computing environment for implementing these controllers.
In some embodiments, control of the various systems of the drilling rig 102 may be provided via a multi-tier (e.g., three-tier) control system that includes a first tier of the controllers 126, 132, and 138, a second tier of the coordinated control device 104, and a third tier of the supervisory control system 107. The first tier of the controllers may be responsible for safety critical control operation, or fast loop feedback control. The second tier of the controllers may be responsible for coordinated controls of multiple equipment or subsystems, and/or responsible for complex model based controllers. The third tier of the controllers may be responsible for high level task planning, such as to command the rig system to maintain certain bottom hole pressure. In other embodiments, coordinated control may be provided by one or more controllers of one or more of the drilling rig systems 110, 112, and 114 without the use of a coordinated control device 104. In such embodiments, the rig computing resource environment 105 may provide control processes directly to these controllers for coordinated control. For example, in some embodiments, the controllers 126 and the controllers 132 may be used for coordinated control of multiple systems of the drilling rig 102.
The sensor data 140, 142, and 144 may be received by the coordinated control device 104 and used for control of the drilling rig 102 and the drilling rig systems 110, 112, and 114. In some embodiments, the sensor data 140, 142, and 144 may be encrypted to produce encrypted sensor data 146. For example, in some embodiments, the rig computing resource environment 105 may encrypt sensor data from different types of sensors and systems to produce a set of encrypted sensor data 146. Thus, the encrypted sensor data 146 may not be viewable by unauthorized user devices (either offsite or onsite user device) if such devices gain access to one or more networks of the drilling rig 102. The sensor data 140, 142, 144 may include a timestamp and an aligned drilling parameter (e.g., depth) as discussed above. The encrypted sensor data 146 may be sent to the remote computing resource environment 106 via the network 108 and stored as encrypted sensor data 148.
The rig computing resource environment 105 may provide the encrypted sensor data 148 available for viewing and processing offsite, such as via offsite user devices 120. Access to the encrypted sensor data 148 may be restricted via access control implemented in the rig computing resource environment 105. In some embodiments, the encrypted sensor data 148 may be provided in real-time to offsite user devices 120 such that offsite personnel may view real-time status of the drilling rig 102 and provide feedback based on the real-time sensor data. For example, different portions of the encrypted sensor data 146 may be sent to offsite user devices 120. In some embodiments, encrypted sensor data may be decrypted by the rig computing resource environment 105 before transmission or decrypted on an offsite user device after encrypted sensor data is received.
The offsite user device 120 may include a client (e.g., a thin client) configured to display data received from the rig computing resource environment 105 and/or the remote computing resource environment 106. For example, multiple types of thin clients (e.g., devices with display capability and minimal processing capability) may be used for certain functions or for viewing various sensor data.
The rig computing resource environment 105 may include various computing resources used for monitoring and controlling operations such as one or more computers having a processor and a memory. For example, the coordinated control device 104 may include a computer having a processor and memory for processing sensor data, storing sensor data, and issuing control commands responsive to sensor data. As noted above, the coordinated control device 104 may control various operations of the various systems of the drilling rig 102 via analysis of sensor data from one or more drilling rig systems (e.g. 110, 112, 114) to enable coordinated control between each system of the drilling rig 102. The coordinated control device 104 may execute control commands 150 for control of the various systems of the drilling rig 102 (e.g., drilling rig systems 110, 112, 114). The coordinated control device 104 may send control data determined by the execution of the control commands 150 to one or more systems of the drilling rig 102. For example, control data 152 may be sent to the downhole system 110, control data 154 may be sent to the fluid system 112, and control data 154 may be sent to the central system 114. The control data may include, for example, operator commands (e.g., turn on or off a pump, switch on or off a valve, update a physical property setpoint, etc.). In some embodiments, the coordinated control device 104 may include a fast control loop that directly obtains sensor data 140, 142, and 144 and executes, for example, a control algorithm. In some embodiments, the coordinated control device 104 may include a slow control loop that obtains data via the rig computing resource environment 105 to generate control commands.
In some embodiments, the coordinated control device 104 may intermediate between the supervisory control system 107 and the controllers 126, 132, and 138 of the systems 110, 112, and 114. For example, in such embodiments, a supervisory control system 107 may be used to control systems of the drilling rig 102. The supervisory control system 107 may include, for example, devices for entering control commands to perform operations of systems of the drilling rig 102. In some embodiments, the coordinated control device 104 may receive commands from the supervisory control system 107, process the commands according to a rule (e.g., an algorithm based upon the laws of physics for drilling operations), and/or control processes received from the rig computing resource environment 105, and provides control data to one or more systems of the drilling rig 102. In some embodiments, the supervisory control system 107 may be provided by and/or controlled by a third party. In such embodiments, the coordinated control device 104 may coordinate control between discrete supervisory control systems and the systems 110, 112, and 114 while using control commands that may be optimized from the sensor data received from the systems 110 112, and 114 and analyzed via the rig computing resource environment 105.
The rig computing resource environment 105 may include a monitoring process 141 that may use sensor data to determine information about the drilling rig 102. For example, in some embodiments the monitoring process 141 may determine a drilling state, equipment health, system health, a maintenance schedule, or any combination thereof. Furthermore, the monitoring process 141 may monitor sensor data and determine the quality of one or a plurality of sensor data. In some embodiments, the rig computing resource environment 105 may include control processes 143 that may use the sensor data 146 to optimize drilling operations, such as, for example, the control of drilling equipment to improve drilling efficiency, equipment reliability, and the like. For example, in some embodiments the acquired sensor data may be used to derive a noise cancellation scheme to improve electromagnetic and mud pulse telemetry signal processing. The control processes 143 may be implemented via, for example, a control algorithm, a computer program, firmware, or other suitable hardware and/or software. In some embodiments, the remote computing resource environment 106 may include a control process 145 that may be provided to the rig computing resource environment 105.
The rig computing resource environment 105 may include various computing resources, such as, for example, a single computer or multiple computers. In some embodiments, the rig computing resource environment 105 may include a virtual computer system and a virtual database or other virtual structure for collected data. The virtual computer system and virtual database may include one or more resource interfaces (e.g., web interfaces) that enable the submission of application programming interface (API) calls to the various resources through a request. In addition, each of the resources may include one or more resource interfaces that enable the resources to access each other (e.g., to enable a virtual computer system of the computing resource environment to store data in or retrieve data from the database or other structure for collected data).
The virtual computer system may include a collection of computing resources configured to instantiate virtual machine instances. The virtual computing system and/or computers may provide a human-machine interface through which a user may interface with the virtual computer system via the offsite user device or, in some embodiments, the onsite user device. In some embodiments, other computer systems or computer system services may be utilized in the rig computing resource environment 105, such as a computer system or computer system service that provisions computing resources on dedicated or shared computers/servers and/or other physical devices. In some embodiments, the rig computing resource environment 105 may include a single server (in a discrete hardware component or as a virtual server) or multiple servers (e.g., web servers, application servers, or other servers). The servers may be, for example, computers arranged in any physical and/or virtual configuration
In some embodiments, the rig computing resource environment 105 may include a database that may be a collection of computing resources that run one or more data collections. Such data collections may be operated and managed by utilizing API calls. The data collections, such as sensor data, may be made available to other resources in the rig computing resource environment or to user devices (e.g., onsite user device 118 and/or offsite user device 120) accessing the rig computing resource environment 105. In some embodiments, the remote computing resource environment 106 may include similar computing resources to those described above, such as a single computer or multiple computers (in discrete hardware components or virtual computer systems).
FIG. 3 illustrates a schematic plan view of a drilling rig system 300, according to an embodiment. The system 300 may include a central package 302 that may perform the actual drilling operations. For example, the central package 302 may include a rig floor 304, from which a mast 306 may extend upward. The mast 306 may support rotating drilling equipment, such as a top drive, kelly, or the like, which may be operable to rotate drill pipe in at least some situations. Such rotation may be converted into drilling operations through the use of a bottomhole assembly, including a drill bit, which is run into the wellbore along with the drill string.
The central package 302 may also include a catwalk 308 and a pipe rack 310, which may be configured to hold pipe joints and/or stands of two or three pipe joints, for example, horizontally. The catwalk 308 may move with the central package 302. The pipe rack 310 may be configured to facilitate moving each stand onto the catwalk 308. Once at the catwalk 308, hoisting equipment may be employed to raise the stand to a vertical orientation above the well. The stand may then be made up to the most-recently run stand, e.g., using tongs or the top drive. A drawworks system may then lower the stand, along with the rest of the string, e.g., as the top drive rotates the string thereby advancing the bit into the well.
The central package 302 may further include an electrical power control 312. The control 312 may include a variable frequency drive (VFD) which may facilitate modulation of power, speed, etc., to the various motors on the central package 302 (e.g., the top drive motor, drawworks motor, etc.). Further, the central package 302 may be configured to be mobile so as to move from well to well in a predefined region or “pad” and conduct batch drilling operations. The central package 302 may move using wheels, rails, rollers, stompers, or other devices.
The system 300 may further include a combined managed pressure and shaker skid 314 (hereinafter, “combined skid” 314). The combined skid 314 may include as one to three, or more, skids depending on the size of individual components and/or any other factor. The combined skid 314 may include a well choke manifold, a managed pressure drilling (MPD) choke manifold, a gas separator, and a trip tank The well choke manifold may be coupled with the blowout preventer (BOP) of the central package 302, and may be used to close the well, bleed gas from the well, etc. The MPD choke manifold may be coupled with a rotary control device (RCD) mounted on top of the BOP. Further, the MPD choke manifold may serve to control fluid pressure in the well. The combined skid 314 may thus be configured to control the fluid as it exits the well during circulation of mud during drilling operations. The combined skid 314 may also include a shale shaker, a degasser, a hydrocyclone, and a centrifuge for removing drill cuttings from the mud as it is returned. The combined skid 314 may be moved relative to the central package 302. Further, the combined skid 314 may move synchronously with the central package 302.
In some embodiments, the mud deployed into and circulated out of the well may be water based. Accordingly, sedimentary separation of the mud may additionally or instead be employed, e.g., using a sedimentary separation structure 316. The sedimentary separation structure 316 may be a lined, earthen pit or hole, which may be generally horseshoe-shaped. Mud received from the well or otherwise containing suspended solids (e.g., concrete or cuttings) may be deposited into one side of the structure 316, and circulated out of another side of the structure 316, giving the mud sufficient time to allow the suspended solids to sink out of suspension. Although the sedimentary separation structure 316 is illustrated as a single pit, it will be appreciated that two pits may be used: one for fresh water and one for brine. In other embodiments, any other number of pits may be employed.
The system 300 may also include liquid storage 318, e.g., tanks. For example, the liquid storage 318 may include one or more tanks for water and/or oil-based mud. The storage 318 may be provided for when changing between different types of drilling fluid.
The system 300 may further include one or more main tanks 320. At least one of the main tanks 320 may contain mud currently or to be circulated into the well, and may contain roughly the same volume as will be used in the well. At least another one of the main tanks 320 may contain water or premixed cement slurry for use in cementing operations. Dry chemicals 322 may be positioned in proximity to the main tanks 320, and the system 300 may include one or more jet mixers to mix the dry chemicals 322 into the main tanks 320. In some embodiments, mud cleaning devices (such as shale shakers, hydrocyclones and centrifuges) may be mounted in the proximity of the main tanks 320. This may provide for additional cleaning of the mud.
The system 300 may further include silos 323. The silos 323 may be employed to store and/or deliver dry additives to well fluids such as mud and cement. For example, four silos may be employed for cement, two for bentonite and baride, although this is but one specific example among many contemplated.
The system 300 may further include one or more mud pumps 324, which may each, or as a group, include a variable frequency drive (VFD) to control the speed thereof. These pumps 324 may each be a three-piston reciprocating pump, and thus may sometimes be referred to as a “triplex”; however, it will be appreciated that any suitable type of pump may be employed. Further, the system 300 may include a cement unit 326 including a cement mixing system and cement pump. The cement pump may be a triplex pump. As the names suggest, the mud pumps 324 may be configured primarily to pump mud through the well, while the cement pump of the cement unit 326 may be configured primarily to pump cement into the well. However, either or both of these functions may be changed, e.g., on demand, as will be described in greater detail below. Thus, unlike other systems in which the cement unit 326 is removed during mudding operations, and/or the mud pumps 324 are removed during cementing operations, the present system 300 may combine the resources of the two different types of pumps (e.g., cement and mud).
The system 300 may be powered by the generator units 330. For example, several individual generators units 330 may operate in parallel to handle the power load of the system 300 during drilling and skidding operations. Each generator unit 330 may include an alternator driven by a diesel engine, with an electronic controller to ensure speed control (frequency output) as well as phase control between the generator units 330. In some embodiments, the generator units 330 may not be moved with the central package 302. The generator units 330 may be installed in the proximity of the static mud system 320, the pump 324, and/or the cement unit 326.
Furthermore, one or more drive motors may be installed in the system 300, e.g., as part of the central package 302. In a specific embodiment, one such motor may operate the drawworks of the central package 302, and another may be employed to rotate a drill string supported by and run into the well by the central package 302. Further, the mud pump 324 and the cement unit 326 may also be provided with power via an electric motor. Smaller motors may be installed to drive a blower for large motor(s), one or more centrifugal pumps to move fluids between tanks and to feed the pump 324 and the cement pump, and agitators in the main tanks 320. These electrical motors may be powered via a VFD or soft-start.
Such components may be installed in a power house (not shown). These power houses may protect the high-power electronics from the environment. As the VFD may be positioned a relatively short distance away from the motor associated therewith, several power houses may be employed in the system 300; in particular, one power house may be located near the pump 324 and the cement unit 326, and one near the rig floor of the central package 302 to control the motors of the drawworks and top drive.
The system 300 may also include a trunk line 328, which may include several electrical and/or hydraulic lines extending from the generally stationary equipment, such as the mud pumps 324 and tanks 320 to the mobile combined skid 314 and/or the mobile central package 302. Furthermore, since the cement unit 326 may kept with the system 300 during multiple operations, rather than just during cementing, the trunk line 328 may be employed to connect the cement unit 326 with the combined skid 314 and/or the central package 302, which may reduce the number of separate lines between the mobile central package 302 and combined skid 314, and the other, relatively stationary components.
In an embodiment, the trunk line 328 may include a mud pump discharge line, a high-pressure cementing line, a cement return line, and a hydraulic line from the combined skid 314 to the mud tank 320. The mud pump discharge line may be coupled with the mud pumps 324 and selectively coupled with the cement unit 326 and may receive mud at pressure therefrom and route such pressurized mud to the rig floor. Similarly, the cementing line may receive pressurized cement slurry from the cement unit 326 and provide the cement to a manifold, which may connect with a well kill assembly, the MPD choke manifold, and the well, for delivery of cement thereto. The low-pressure cement return line may extend from the rig floor to the cement unit 326. The trunk line 328 may also include a high-power electrical line, which may route power from stationary generators 330 to the combined skid 314 and/or the central package 302.
The trunk line 328 may be contained in a “suitcase” assembly of several articulating joints which are pivotable with respect to one another. This may facilitate the central package 302 and/or the combined skid 314 moving relative to the mud pump 324 and cement unit 326 and tanks 320, etc., while protecting the lines contained within the trunk line 328. The pivots allow the suitcase assembly to be extended or contacted as an accordion, allowing the change of length between the stationary equipment and the mobile equipment.
The system 300 may also include pipe storage “tubs” 350, which may store pipe prior to the pipe being loaded into the rack 310. Further, the system 300 may include offices or other personnel facilities 352, such as living quarters.
In some embodiments, the system 300 may also include a fluid-residue skid 360. The fluid-residue skid 360 may move along with the central package 302 and with respect to the tanks 320, mud pump 324, and cement unit 326, etc. The fluid skid may be configured to contain at least some of the fluid received from the well, e.g., from the shale-shaker or centrifuge of the combined skid 314
FIG. 4 illustrates a schematic of a configuration of the cement unit 326 and two mud pumps 324(1), 324(2), according to an embodiment. As noted above, the cement unit 326 may be or include at least one cement pump, and is thus schematically illustrated as such in FIG. 4, with it being appreciated that the cement unit 326 may include additional components (e.g., mixers). FIG. 4 also shows a partial view of the trunk line 328, in which a high-pressure mud line 400 and a high-pressure cement line 402 are disposed. One of ordinary skill in the art will recognize that this figure is intended merely to illustrate the concept of the flows reaching different locations in an integrated system and thus the particular arrangement of pumps, valves, etc., as described below, is not to be considered limiting.
The cement unit 326 and associated main tank 320(2), being an integral part of the system 300, may allow for the cement unit 326 to perform as a back-up mud pump, for example, when one of the mud pumps 324(1), 324(2) is to be shut down for maintenance, etc. Accordingly, the cement unit 326 may be operable in a first mode, in which the cement unit 326 pumps cement, as well as in a second mode, in which the cement unit 326 pumps mud. During a shutdown of one of the mud pumps 324(1), 324(2) (and/or if additional mud pumping capabilities are otherwise called for), the position of a valve 404, 406 upstream of an associated one of the mud pumps 324(1), 324(2) may be adjusted, causing mud to be directed to the cement unit 326 instead of the associated mud pump 324(1), 324(2). It will be appreciated that a mixing system may be employed in-line, e.g., between the tanks 320(1), 320(2), and the associated pumps 324(1), 324(2) and the cement unit 326, but is omitted for purposes of simplicity herein. When mud is routed to the cement unit 326, a second valve 408 may be modulated downstream of the cement unit 326, directing the fluid pumped by the cement unit 326 to the mud line 400 instead of the cement line 402.
Similarly, in some cases, a secondary cement pump may be called for, e.g., in high flow situations, such as during cementing a top section of a well. Thus, one or both of the mud pumps 324(1), 324(2) may be operable in a first mode, in which the mud pumps 324(1), 324(2) pump mud, and a second mode, in which the mud pump(s) 324(1), 324(2) pump cement. In the second mode, one of the valves 204, 206 may be opened, allowing cement slurry to be introduced to at least one of the mud pumps 324(1), 324(2) (e.g., after flushing or otherwise cleaning any remaining mud from the mud pump 324(1) and any active fluid lines). Further, a third valve 210, downstream from either or both of the mud pumps 324(1), 324(2) may be modulated to direct fluid to the cement line 202 rather than the mud line 200.
In some embodiments, a pulse dampener may be provided on the downstream side of the mud pumps 324(1) and 324(2). Another type of pulse dampener, which may not be harmed by a flow of cement during cementing operations, or a selectively-active pulse dampener (e.g., isolated from cement flow by a valve), may be positioned downstream of the cement unit 326, and may be employed for use when the cement unit 326 is pumping mud.
In addition, the tank 320(2) may include two or more sections, e.g., separated by a baffle, a diaphragm, or any other structure. The sections may be premixed with different amounts of dry additives (e.g., cement components). As such, a lead-in slurry and a tail slurry of different compositions may be premixed in the tank 320(2) and pumped into the cement line 202 at the appropriate times during the drilling process.
Referring now to FIGS. 3 and 4, in a situation in which the cement unit 326 pumps mud, the cement unit 326 may be controlled along with the mud pumps 324(1), 324(2). Accordingly, a first control panel may be provided at the cement unit 326, and a second control panel may be provided at the central package 302, with both panels being capable of controlling the operation of the cement unit 326, e.g., by setting the speed using the VFD of the cement unit 326. Accordingly, during drilling operations, when the cement unit 326 is switched to pumping mud (i.e., switched to the second mode), the second panel may control operation of the cement unit 326. During cementing operations (i.e., when the cement unit 326 operates in the first mode), however, control of the operation of the cement unit 326 may be switched to the first panel, e.g., to the exclusion of the second panel at the central package 302. This may done because the central package 302 may be moved away from the wellhead (to another wellhead) during cementing operations, and thus control of the cementing process therefrom may be inconvenient.
FIG. 5 illustrates a simplified, conceptual view of the system 300, according to an embodiment. As shown, the generators 330 are coupled to at least some of the various subsystems (e.g., the central package 302, the mud pumps 324, and the cement unit 326, the tanks 320, and the combined skid 314) via electrical lines. Any of the system 300 components discussed above may be similarly coupled with the generator 330, with those illustrated merely being one example among many contemplated. Between the generators 330 and the subsystems are electrical circuit breakers 500, which may be located physically proximal to the individual subsystems. By employing such local breakers 500, the number of lines to the central package 302 and/or the combined skid 314 may be reduced, as the breakers 500 may allow for power received by the subsystems to be routed to the appropriate locations. It will be appreciated that additional components may be interposed between any of the subsystems and the generators 330, including without limitation one or more VFDs, batteries, etc.
Further, each of the subsystems may include an individual programmable logic controller (PLC) 502, while the system 300 may be controlled by a central controller 503, which may be generally similar to, combined with, or provided by the rig control system discussed above. The PLCs 502 provided for each of the subsystems may allow the individual subsystems to be quasi-autonomous, e.g., able to perform certain operations without command from the central controller 503. Further, the PLCs 502 may be in communication with individual human-machine interfaces. This autonomy may facilitate adding and/or removing subsystems, as the removal or addition of one may not affect the control of the other subsystems. Further, the PLCs 502 may be able to receive and implement relatively simple (e.g., deterministic or quasi-deterministic) commands from the central controller 503.
In some embodiments, one or some of the subsystems may include multiple sensors or other controllable elements or elements that provide feedback. Each of these may include a power line, signal line, or both. By providing a breaker 500 and a PLC 502 for each subsystem, the number of connections running between a centralized control system (and/or between the movable central package 302 and one or more stationary elements) may be reduced, as the breakers 500 and the PLCs 502 may each be configured to couple with multiple of these lines and reduce the lines extending from an individual one of the subsystems to one each for power and signals. That is, the PLC 502 for one of the subsystems may couple with multiple (e.g., dozens or more) sensors, and multiplex or otherwise package the signal data and send the data via a single (or, in some cases, multiple) line, such as an Ethernet line, to one or more other PLCs 502 and/or to the centralized controller. Similarly, the breaker 500 may receive a single power line and transmit power to multiple components of the subsystem. Thus, the number of connections, wires, etc., that may be disconnected, moved, present safety risks, or otherwise be affected by the relative movement of the central package 302 may be minimized.
In some embodiments, the methods of the present disclosure may be executed by a computing system. FIG. 6 illustrates an example of such a computing system 600, in accordance with some embodiments. The computing system 600 may include a computer or computer system 601A, which may be an individual computer system 601A or an arrangement of distributed computer systems. The computer system 601A includes one or more analysis modules 602 that are configured to perform various tasks according to some embodiments, such as one or more methods disclosed herein. To perform these various tasks, the analysis module 602 executes independently, or in coordination with, one or more processors 604, which is (or are) connected to one or more storage media 606. The processor(s) 604 is (or are) also connected to a network interface 607 to allow the computer system 601A to communicate over a data network 609 with one or more additional computer systems and/or computing systems, such as 601B, 601C, and/or 601D (note that computer systems 601B, 601C and/or 601D may or may not share the same architecture as computer system 601A, and may be located in different physical locations, e.g., computer systems 601A and 601B may be located in a processing facility, while in communication with one or more computer systems such as 601C and/or 601D that are located in one or more data centers, and/or located in varying countries on different continents).
A processor may include a microprocessor, microcontroller, processor module or subsystem, programmable integrated circuit, programmable gate array, or another control or computing device.
The storage media 606 may be implemented as one or more computer-readable or machine-readable storage media. Note that while in the example embodiment of FIG. 6 storage media 606 is depicted as within computer system 601A, in some embodiments, storage media 606 may be distributed within and/or across multiple internal and/or external enclosures of computing system 601A and/or additional computing systems. Storage media 606 may include one or more different forms of memory including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories, magnetic disks such as fixed, floppy and removable disks, other magnetic media including tape, optical media such as compact disks (CDs) or digital video disks (DVDs), BLURRY® disks, or other types of optical storage, or other types of storage devices. Note that the instructions discussed above may be provided on one computer-readable or machine-readable storage medium, or alternatively, may be provided on multiple computer-readable or machine-readable storage media distributed in a large system having possibly plural nodes. Such computer-readable or machine-readable storage medium or media is (are) considered to be part of an article (or article of manufacture). An article or article of manufacture may refer to any manufactured single component or multiple components. The storage medium or media may be located either in the machine running the machine-readable instructions, or located at a remote site from which machine-readable instructions may be downloaded over a network for execution.
In some embodiments, the computing system 600 contains one or more rig control module(s) 608. In the example of computing system 600, computer system 601A includes the rig control module 608. In some embodiments, a single rig control module may be used to perform some or all aspects of one or more embodiments of the methods disclosed herein. In alternate embodiments, a plurality of rig control modules may be used to perform some or all aspects of methods herein.
It should be appreciated that computing system 600 is only one example of a computing system, and that computing system 600 may have more or fewer components than shown, may combine additional components not depicted in the example embodiment of FIG. 6, and/or computing system 600 may have a different configuration or arrangement of the components depicted in FIG. 6. The various components shown in FIG. 6 may be implemented in hardware, software, or a combination of both hardware and software, including one or more signal processing and/or application specific integrated circuits.
Further, the steps in the processing methods described herein may be implemented by running one or more functional modules in information processing apparatus such as general purpose processors or application specific chips, such as ASICs, FPGAs, PLDs, or other appropriate devices. These modules, combinations of these modules, and/or their combination with general hardware are all included within the scope of protection of the invention.
The foregoing description, for purpose of explanation, has been described with reference to specific embodiments. However, the illustrative discussions above are not intended to be exhaustive or to limit the disclosure to the precise forms disclosed. Many modifications and variations are possible in view of the above teachings. Moreover, the order in which the elements of the methods described herein are illustrate and described may be re-arranged, and/or two or more elements may occur simultaneously. The embodiments were chosen and described in order to explain at least some of the principals of the disclosure and their practical applications, to thereby enable others skilled in the art to utilize the disclosed methods and systems and various embodiments with various modifications as are suited to the particular use contemplated.

Claims

What is claimed is:

1. A rig system, comprising:

a movable central package comprising one or more devices to drill a well using a drill pipe;

a mud pump coupled with the movable central package and configured to pump mud thereto; and

a cement pump coupled with the movable central package, wherein the cement pump is operable in a first mode in which the cement pump pumps cement to the well, and a second mode in which the cement pump pumps mud to the well.

2. The rig system of claim 1, wherein the movable central package is movable relative to the mud pump and the cement pump, and wherein the movable central package is configured for batch drilling.

3. The rig system of claim 1, wherein the mud pump is configured to pump the mud in a first mode, and wherein the mud pump is configured to pump cement to the central package in a second mode.

4. The rig system of claim 1, further comprising a combined skid that is movable along with the movable central package, wherein the combined skid comprises a managed pressure drilling system and a shaker assembly.

5. The rig system of claim 4, wherein the combined skid comprises a shale shaker configured to separate solids from liquid in drilling mud received from the well, and wherein the rig system further comprises a fluid-residue skid configured to receive a solids residue form the drilling mud.

6. The rig system of claim 1, wherein the central package, the mud pump, and the cement pump each include a programmable logic controller configured to execute one or more commands independent of a centralized control system, and wherein the programmable logic controller of each of the central package, the mud pump, and the cement pump is configured to implement one or more commands from the centralized control system.

7. The rig system of claim 1, further comprising a mud tank having a programmable logic controller coupled therewith, wherein the programmable logic controller of the mud tank is quasi-autonomous.

8. The rig system of claim 1, wherein the central package, the mud pump, and the cement pump are coupled to separate variable frequency drives (VFD) and separate electric circuit breakers.

9. The rig system of claim 8, wherein each of the VFDs is coupled to the respective electric circuit breaker of the respective one of the central package, the mud pump, and the cement pump.

10. The rig system of claim 1, further comprising a trunk line coupled on one end to the mud pump and the cement pump, and on an opposite end to the central package, the trunk line comprising a high-pressure mud line, a high-pressure cement line, a mud return line, a cement return line, and at least one high-power electrical line.

11. The rig system of claim 1, wherein the central package comprises a first panel, the rig system further comprising a second panel located proximal to the cement pump, the first panel being configured to control the cement pump when the cement pump is in the second mode, and the second panel being configured to control the cement pump at least when the cement pump is in the first mode.

12. The rig system of claim 11, wherein the first and second panels are configured to communicate with a variable frequency drive of the cement pump to adjust a speed thereof, and wherein the first and second panels are configured to avoid sending inconsistent commands to the variable frequency drive.

13. The rig system of claim 1, further comprising a cement tank coupled with the cement pump, wherein the cement tank comprises a first premixed cement for use in a first cementing operation, and a second premixed cement for use in a second cementing operation, wherein the first and second premixed cements have different compositions.

14. A method for drilling a well using a movable rig, comprising:

pumping a mud into a wellbore using at least one mud pump while drilling the wellbore;

pumping the mud into the wellbore using at least one cement pump in a first mode, while drilling the wellbore and while pumping mud into the wellbore using the at least one mud pump; and

pumping cement into the wellbore using the at least one cement pump in a second mode.

15. The method of claim 14, further comprising controlling the at least one cement pump in the first mode using a first panel positioned on a central package, the central package comprising a movable drilling rig.

16. The method of claim 15, further comprising controlling the at least one cement pump in the second mode using a second panel positioned proximal to the at least one cement pump, wherein the movable drilling rig is movable with respect to the second panel.

17. The method of claim 14, further comprising connecting a central package to the at least one mud pump and to the at least one cement pump using a trunk line, wherein the central package is movable with respect to the at least one mud pump and the at least one cement pump.

18. The method of claim 17, further comprising:

independently controlling an operation of the central package using a first controller and a first variable frequency drive, the first controller and the first variable frequency drive being coupled to the central package.

independently controlling an operation of the at least one cement pump using a second controller and a second variable frequency drive, the second controller and the second variable frequency drive being coupled to the at least one cement pump.

independently controlling an operation of the at least one mud pump using a third controller and a third variable frequency drive, the third controller and the third variable frequency drive being coupled to the at least one mud pump.

19. A rig system, comprising:

a mud pump coupled with the movable central package and configured to pump mud thereto, wherein the mud pump is configured to pump the mud in a first mode, and wherein the mud pump is configured to pump cement to the central package in a second mode;

a cement pump coupled with the movable central package, wherein the cement pump is operable in a first mode in which the cement pump pumps cement to the well, and a second mode in which the cement pump pumps mud to the well;

a combined skid that is movable along with the movable central package, wherein the combined skid comprises a managed pressure drilling system and a shaker assembly;

a plurality of variable frequency drives (VFDs), wherein individual VFDs are separately coupled to the central package, the mud pump, and the cement pump; and

a plurality of controllers, wherein individual controllers of the plurality of controllers are separately coupled to the central package, the mud pump, and the cement pump, to provide quasi-independent control thereof,

wherein the movable central package is movable relative to the mud pump and the cement pump, and wherein the movable central package is configured for batch drilling.

20. The rig system of claim 19, further comprising:

a first panel coupled to the central package and being movable therewith, the first panel being configured to control the cement pump in the first mode; and

a second panel, wherein the central package is movable with respect to the second panel, the second panel being configured to control the cement pump in the second mode.