Patent Grant
10494885
1. Field of the Disclosure
This disclosure relates generally to mud pulse telemetry systems for oilfield systems.
2. Background of the Art
To obtain hydrocarbons such as oil and gas, boreholes or wellbores are drilled by rotating a drill bit attached to the bottom of a drilling assembly (also referred to herein as a “Bottom Hole Assembly” or (“BHA”). The drilling assembly is attached to the bottom of a tubing, which is usually either a jointed rigid pipe or a relatively flexible spoolable tubing commonly referred to in the art as “coiled tubing.” The string comprising the tubing and the drilling assembly is usually referred to as the “drill string.” During drilling, surface personnel may “break” the drill in order to add or remove a joint or other piece of equipment. The process of breaking and making-up the drill string may interrupt communication links used by conventional drilling systems.
In aspects, the present disclosure provides communication links and telemetry systems that provide communication even during such interruptions.
In aspects, the present disclosure provides a system for performing a wellbore operation while a fluid circulates in a wellbore. The system may include a string comprising at least a first tubular section and a second tubular section, each tubular section configured to be disconnected from the string; a fluid circulating system circulating fluid through at least a part of the string; a continuous circulation device comprising at least a first fluid path and a second fluid path, wherein only one of the first fluid path and the second fluid path circulate the fluid into the string at a specified time; a control device configured to select one of the first and second fluid path through which to convey the fluid into the string; at least one signal generator in hydraulic communication with the circulating fluid, the at least one signal generator configured to impart at least one pressure signal into the circulating fluid; and at least one pressure transducer in pressure communication with the circulating fluid and configured to detect the imparted at least one pressure signal. The at least one signal generator and the at least one pressure transducer form a communication link, the communication link being configured to convey information between at least two locations along a flow path of the circulating drilling fluid, irrespective whether the first fluid path or the second fluid path is selected by the control device to convey the fluid into the drill string.
In aspects, the present disclosure provides a method for performing a wellbore operation while a fluid circulates in a wellbore. The method includes conveying a string into the wellbore, the string comprising at least a first tubular section and a second tubular section, each tubular section configured to be disconnected from the string; circulating fluid through at least a part of the string using a fluid circulating system, wherein the fluid circulation system includes a continuous circulation device comprising at least a first fluid path and a second fluid path, wherein only one of the first fluid path and the second fluid path circulate the fluid into the string at a specified time; selecting one of the first and second fluid path through which to convey the fluid into the string using a control device; imparting at least one pressure signal into the circulating fluid using at least one signal generator in hydraulic communication with the circulating fluid; and detecting the imparted at least one pressure signal using at least one pressure transducer in pressure communication with the circulating fluid. The at least one signal generator and the at least one pressure transducer form a communication link, the communication link being configured to convey information between at least two locations along a flow path of the circulating drilling fluid, irrespective whether the first fluid path or the second fluid path is selected by the control device to convey the fluid into the drill string.
Examples of certain features of the disclosure have been summarized in order that the detailed description thereof that follows may be better understood and in order that the contributions they represent to the art may be appreciated. There are, of course, additional features of the disclosure that will be described hereinafter and which will form the subject of the claims appended hereto.
For a detailed understanding of the present disclosure, reference should be made to the following detailed description of the embodiments, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals, wherein:
As will be appreciated from the discussion below, aspects of the present disclosure provide a mud pulse telemetry system that can function continuously even when a drill string is “broken” to add or remove equipment. Generally, a mud pulse communication system uses pressure pulses transmitted along a column of drilling fluid (or “mud”) to transmit data. The pressure pulses may be generated by a signal generator such as a valve, pulser, or pulse wave generator. Conventionally, an encoder generates a signal, e.g., by either restricting mud flow or venting drilling fluid, and a decoder detects the signal.
Illustrative embodiments of the present disclosure use a mud pulse telemetry system in conjunction with a continuous circulation system in order to provide continuous or “real time” signal communication between the surface and one or more downhole locations. The system may use a drill string that includes one or more signal conveying and pressure sensitive devices that cooperate with corresponding devices on the surface to continuously detect transmitted pressure pulses. In one embodiment, at least a part of the signal conveying and pressure sensitive devices may be integrated into the flow diverters used with a continuous circulation system that circulates drilling fluid in the well. These and other embodiments are discussed in greater detail below.
Referring initially to
Referring now to
For example, during drilling, the manifold 102 directs drilling fluid into the top drive 24. To add a pipe stand 12a, drilling is stopped and the arm 34 moves the flow diverter control device 32 into engagement with a flow diverter 30 on top of the drill string 11. Valves are activated internal to the flow diverter 30 that block axial flow from top drive 24 and allow radial flow from and to the flow diverter control device 32. Thereafter, the manifold 102 switches drilling fluid flow from the top drive 24 to the fluid line 36, which flows drilling fluid from the source 38 to the flow diverter control device 32. The flow diverter control device 32 supplies the flow diverter 30 with pressurized fluid. The top drive 24 (
Referring now to
In one non-limiting embodiment, the flow diverter 30 may also be configured to convey signals along the wellbore 13 (
Transmission of pressure waves as arrays enables communication with all signal relay devices 30 and BHA modules along the entire drill-string at different points of time. Generation, repeating or magnification of the pulse pressure waves can be performed with positive or negative fluid displacement values. Some embodiments use battery or energy harvesting systems to drive pressure wave generating modules like piezo actuated pistons or membranes, or mud sirens, which are embedded in or connected to flow diverters 30 that include signal relay devices 60.
The transmission of magnified pressure signal arrays, utilizing interference with other signal relay devices along the entire drill-string at about the same point of time forms an Interference Magnified Array System (IMARYS). U.S. Pat. No. 7,230,880 shows an independent working power and communication module that may be used as an interfering device and link between the pressure wave generator on surface 262 and other modules of the BHA.
Time synchronization of modules may be achieved by the atomic clock utilization. Generation or disturbance of interference may be used to transmit information. Some embodiments use switching between signal downlink and signal uplink transmission frequency at interference points to simplify the system. Another arrangement involves working with interfering pressure wave pairs (or triples, or more) traveling along the drill string, repeating signal to transmit at different point of times (repeating signal at least ones while traveling DH or UpHole). Built-in pressure sensors receiving signal close by interfering pair and generating an interfering pair with the next reachable signal relay device unit (s) after a “hand shake.”
Referring back to
In some embodiments, signal exchange speed and bandwidth can be enhanced by continuous system analysis and consequent shift to the best fit configuration channel selection by the system (pre-programmed and autonomous) and the use of Ultimate Radio System Extension Lines (URSEL). An illustrative URSEL system may be already installed at the rig site and/or installed into the wellbore. For example, a signal carrier such as a fiber optic wire may be embedded in the cement used to set casing 17. The wellbore construction equipped with signal exchange equipment/modules as mentioned may use the embedded signal carrier to transmit and receive information-bearing signals. In embodiments, radio over fiber (RoF) technology may be used to transmit information. RoF technology modulates light by radio signal and transmits the modulated light over an optical fiber. Thus, RF signals may be converted to light signals that are conveyed over fiber optic wires for a distance and then converted back to RF signals.
At the surface, the communication system 200 includes a controller 202 in signal communication with the signal relay devices 60. The controller 202 may include suitable equipment such as a transceiver 204 to wirelessly communicate with the signal relay devices 60 using EM or RF waves 206. This system 200 allows continuous communication while drilling and making and breaking jointed connections. The same RF transmitter or transceiver might be used for rig site and down hole transmission of the signals to reduce the complexity of the used equipment. Signal shape and strength might be adjusted depending on operational environment only.
The communication system 200 may be used to exchange information with the sensors and devices at the BHA 20 or positioned elsewhere on the string 11. Illustrative sensors include, but are not limited to, sensors for estimating: annulus pressure, drill string bore pressure, flow rate, near-bit direction (e.g., BHA azimuth and inclination, BHA coordinates, etc.), temperature, vibration/dynamics, RPM, weight on bit, whirl, radial displacement, stick-slip, torque, shock, strain, stress, bending moment, bit bounce, axial thrust, friction and radial thrust as well as formation evaluation sensors such as gamma radiation sensors, acoustic sensors, resistivity or permittivity sensors, NMR sensors, pressure testing tools and sampling or coring tools. Illustrative devices include, but are not limited to, the following: one or memory modules and a battery pack module to store and provide back-up electric power, an information processing device that processes the data collected by the sensors, and a bidirectional data communication and power module (“BCPM”) that transmits control signals between the BHA 20 and the surface as well as supplies electrical power to the BHA 20. The BHA 20 may also include processors programmed with instructions that can generate command signals to operate other downhole wellbore equipment. The commands may be generated using the measurements from downhole sensors such as pressure sensors.
Based on information obtained using the communication system 200, the system 10 may be used to control out-of-norm wellbore conditions using well control equipment positioned in the wellbore 13. The well control equipment may include an annulus flow restriction device 222 that hydraulically isolates one or more sections of a wellbore by selectively blocking fluid flow in the annulus 37, a bore flow restriction device 224 that selectively blocks fluid flow along a bore 15 of the drill string 11, and a bypass valve 250.
The annulus flow restriction device 222 may be positioned along an uphole section of a non-rigid section 16 or anywhere else along the drill string 11. In one embodiment, the annulus flow restriction device 222 may form a continuous circumferential seal against a wellbore wall that controls flow in the well annulus 37. The terms seals, packers and valves are used herein interchangeably to refer to flow control devices that can selectively control flow across a fluid path by increasing or decreasing a cross-sectional flow area. The control can include providing substantially unrestricted flow, substantially blocked flow, and providing an intermediate flow regime. The intermediate flow regimes are often referred to as “choking” or “throttling,” which can vary pressure in the annulus downhole of the annulus flow restriction device 222. The fluid barrier provided by these devices can be “zero leakage” or allow some controlled fluid leakage. In some embodiments, the seals and valves may include suitable electronics in order to be responsive to control signals. Suitable flow control devices include packer-type devices, expandable seals, solenoid operated valves, hydraulically actuated devices, and electrically activated devices.
Referring to
The signal responsive actuator 234 allows the bore flow restriction device 224 to be remotely actuated with a control signal. The signal may be transmitted from the surface and/or from a device located in the wellbore 13 (e.g., the BHA 20). For instance, the controller 202 (
The closure member 230 may be a bypass valve that is configured to direct flow between the annulus 37 and the bore 15 of the drill string 11. Like the flow restriction devices 222, 224, the closure member 230 may include a signal response actuator 234 that can shift the closure member 230 between an open position, a closed position, and/or an intermediate position. The signal response actuator 234 may include suitable electronics to receive and process the control signals and to initiate the desired actions.
In embodiments, communication using mud pulses may be enabled by distributing pressure sensors at selected surface locations within the continuous circulation system 100 and/or downhole locations; e.g., at the signal relay device 60 or in the bottomhole assembly 20. The communication may be in one direction or bi-directional. Such a system allows continuous communication while drilling and making and breaking jointed connections. Non-limiting embodiments having such functionality are described below.
Referring to
Referring to
Referring to
In one arrangement, at the surface, a pulse wave generator 260 may be used to impart pressure pulses 262 into the drilling fluid flowing in the annulus 37. In other embodiments, the signal generator may be a valve (not shown) at the manifold 102 that imparts pressure pulses into the fluid flowing through the bore of the drill string 11. A signal generator (not shown) could also be positioned at the top drive 24, the pump (not shown) flowing fluid from the mud source 38, or any location along the mud flow path. At a downhole location, pressure pulses may be generated by the upper or lower circulation valves 114, 116 of one or more signal relay devices 60, the annulus flow restriction device 222, and/or the bore flow restriction devices 224. Downhole pressure pulses may also be generated using signal generators (not shown) such as bypass valves, mud pulser, or sirens in the BHA 20.
Referring to
Referring now to
As drilling progresses, the signal generator(s) and pressure transducer(s) cooperate to form communication links that operate even when the drill string 11 is broken; i.e., a pipe stand 12 is physically separated from the drill string 11. For example, the signal generators downhole and/or at the surface may transmit pressure pulses that flow along the fluid column inside the drill string 11 and/or in the annulus 37.
Communication uplinks, i.e., transmitting information to the surface, may be accomplished by using the pressure transducers 251, 252, 253 to detect pressure pulses generated by downhole signal generators.
Communication downlinks, i.e., transmitting information to a downhole location, may be accomplished by using the pressure transducers 254, 256 to detect pressure pulses generated by surface signal generators. In embodiments where the flow diverters 30 may not include pressure transducers, communication downlinks can be sent to pressure transducers (not shown) in the BHA 20 or elsewhere in the drill string 11.
Communication between two downhole locations may be accomplished by using the pressure transducers 254, 256 of one signal relay device 60 and a signal generator of another signal relay device or a signal generator or pressure transducer located elsewhere along the drill string 11 (e.g., a mud pulser, a bypass valve, a siren, or a pressure transducer at the BHA 20).
It should be appreciated that the mud pulse signal communication is not interrupted when pipe 12a is added to or removed from the drill string 11. During such disconnections, drilling mud is still circulating even though a pipe stand is physically decoupled from the drill string 11, which enables mud pulse signals to be conveyed between the surface and downhole. Therefore, the pressure transducers 251-254, 256, which are in communication with the circulating mud, can detect pressure signals imparted to the flowing fluid. As a result, communication uplinks and downlinks are maintained throughout the disconnections. Stated differently, the communication links convey information between at least two locations along a flow path of the circulating drilling fluid irrespective whether the CCS 100 selects a first fluid path through the top drive the drill string or a second fluid path through the flow diverter to convey the fluid into the drill string.
In one variant, the system 10 may utilize reverse circulation. During reverse circulation, the drilling mud is pumped into the annulus 37. The drilling mud and entrained cuttings return via a bore of the drill string 11. In this mode of circulation also, the instrumentation described above enables uninterrupted uni-directional or bi-direction communication via mud pulses. It should be understood that reverse circulation itself may have variants. For example, crossover subs may divert annulus flow into the drill string bore 15 while diverting drill string flow into the annulus. Thus, flow may be “reverse” in some sections of the well but “conventional” in other parts of the well.
One advantage of uninterrupted communication is that pressure information may be continuously transmitted by the communication system 200 or the mud pulse telemetry. Therefore, pressure adjustments may be done in real time or near-real time. Advantageously, deep drilling situations that have tight pressure windows and formations with changing formation pressure may be managed more efficiently because wellbore pressure management devices can be rapidly and accurately adjusted. Additionally, this enhanced control may enable drilling to be performed while the well is in an underbalanced pressure condition. In many instances, drilling in an underbalanced condition yields enhanced rates of penetration.
In other instances, the pressure information may indicate that corrective action may be needed to contain an undesirable condition. For example, the pressure information received may indicate that an enhanced risk for a potential “kick,” or pressure spike exists. One exemplary response may include the controller 202 transmitting a control signal using the communication system 200 to the annular flow restriction device 222. In response, the annular flow restriction device 222 may radially expand and seal against the adjacent wellbore wall. Thus, the fluid annulus 37 of the wellbore 13 downhole of the flow restriction device 222 may hydraulically isolated from the remainder of the wellbore 13. Additionally or alternatively, the controller 202 may send a control signal to the bore flow restriction device 224. In response, the bore flow restriction device 224 may seal the bore of the drill string 11. Thus, the bore of the drill string 11 downhole of the flow restriction device 224 may hydraulically isolated. The actuation of either or both of the flow restriction devices 222, 224 in this manner may isolate the downhole section of the wellbore 13 and thereby reduce the risk of the pressure kick.
After the wellbore has been isolated, remedial action may be taken such as bleeding off the pressure kick, increasing mud weight, etc. In other instances, it may be desired to isolate the wellbore either temporarily or permanently. Isolating the wellbore may be done by leaving the entire drill string 11 in the wellbore 13. Alternatively, the rigid section 14 may be disconnected from the non-rigid section 16 and pulled out the wellbore 13. Thus, the wellbore 13 is isolated by the non-rigid section 16 and the flow restriction devices 222, 224.
While the above modes have used surface initiated actions, it should be understood that the BHA 20 may use one or more downhole controllers that are programmed to also monitor pressure conditions, determine whether an undesirable condition exists, and transmit the necessary control signals to the flow restriction devices 222, 224, bypass valve 250, and/or other equipment. These actions may be taken autonomously or semi-autonomously.
The present disclosure is not limited to a particular drilling configuration. For instance, the BHA 20 may include devices that enhance drilling efficiency or allow for directional drilling. For instance, the BHA 20 may include a thruster that applies a thrust to urge the drill bit 50 against a wellbore bottom. In this instance, the thrust functions as the weight-on-bit (WOB) that would often be created by the weight of the drill string. It should be appreciated that generating the WOB using the thruster reduces the compressive forces applied to the non-rigid section 16. One or more stabilizers that may be selectively clamped to the wall may be configured to have thrust-bearing capabilities to take up the reaction forces caused by the thruster. Moreover, the thruster allows for drilling in non-vertical wellbore trajectories where there may be insufficient WOB to keep the drill bit 50 pressed against the wellbore bottom. Some embodiments of the BHA 20 may also include a steering device. Suitable steering arrangements may include, but are not limited to, bent subs, drilling motors with bent housings, selectively eccentric inflatable stabilizers, a pad-type steering devices that apply force to a wellbore wall, “point the bit” steering systems, etc. As discussed previously, stabilizers may be used to stabilize and strengthen the sections 14, 16.
In other instances, the drill string 11 may be used for non-drilling activities such as casing installation, liner installation, casing/liner expansion, well perforation, fracturing, gravel packing, acid washing, tool installation or removal, etc. In such configurations, the drill bit 50 may not be present.
From the above, it should be appreciated from the discussion below, aspects of the present disclosure provide a system for deep drilling (e.g., tight pressure windows) and drilling into formations with changing formation pressure (e.g., depleted zones). Systems according to the present disclosure provide ECD control (equivalent circulating density control) for such situations. These systems may allow the exploration and production of deep high enthalpy geothermal energy due to the ability to manage tight pressure windows in deep crystalline rock.
While the foregoing disclosure is directed to the one mode embodiments of the disclosure, various modifications will be apparent to those skilled in the art. It is intended that all variations within the scope of the appended claims be embraced by the foregoing disclosure.
This application is a continuation-in-part of U.S. application Ser. No. 13/760,817, filed Feb. 6, 2013, the entire disclosure of which is incorporated herein by reference in its entirety.
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| Number | Date | Country | |
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| Child | 14961364 | US |
