The present invention relates to the field of prevention and protection against hazardous situations, particularly in a downhole network integrated into a drill string used in oil and gas exploration, or along the casings and other equipment used in oil and gas production.
Blowouts, high pressure kicks, and loss of circulation are a few of the dangers involved in exploration and production of oil and gas. Many systems have been developed to detect and control these dangers.
U.S. Pat. No. 4,377,206 discloses a device for preventing well blowouts in sucker rod pumping systems and particularly for sensing the parting of a polish rod from a stuffing box and preventing fluid flow through the stuffing box to the atmosphere. The device includes a wear block abutting against a polish rod for sensing when the polish rod parts from the stuffing box. When the polish rod parts from the stuffing box, a lever automatically causes a valve to rapidly close to prevent blowout of the fluid in the well bore.
U.S. Pat. No. 5,006,845 discloses methods for the early detection of gas kicks in marine risers which include monitoring a downhole absolute pressure and a downhole differential pressure of a riser section positioned just above a blowout preventor. Also disclosed is an apparatus comprising a means for telemetering said absolute pressure measurement and said differential pressure measurement from sensors connected to said instrumented riser section to control instrumentation positioned at said sea surface. Said means for telemetering may be an acoustic beacon.
U.S. Pat. Application No. 20040124009, to Hoteit et al., discloses a method and system for averting or mitigating undesirable drilling events during a drilling process. The state of the drilling rig is detected, preferably automatically, based on surface and/or downhole measurement data. One or more undesirable drilling events are detected by correlating the acquired measurement data with the detected state. A drilling rig action is determined which averts or mitigates a detected undesirable drilling event. Finally, the drilling process is overridden by commanding performance of the action.
U.S. application Ser. No. 10/878,243 filed Jun. 28, 2004 in the name of Hall, et al discloses a method and apparatus for use in assessing down-hole drilling conditions. The apparatus includes a drill string, a plurality of sensors, a computing device, and a down-hole network. The sensors are distributed along the length of the drill string and are capable of sensing localized down-hole conditions while drilling. The computing device analyzes data output by the sensors and representative of the sensed localized conditions to assess the down-hole drilling conditions. The method includes sensing localized drilling conditions at a plurality of points distributed along the length of a drill string during drilling operations; transmitting data representative of the sensed localized conditions to a predetermined location; and analyzing the transmitted data to assess the adverse down-hole drilling conditions. An application is also disclosed which may display a notice when some adverse drilling condition is about to occur and corrective or preventative action needs to be taken.
A method of responding to an anomalous change in downhole pressure in a downhole tool string comprises detecting the anomalous change in downhole pressure, sending a signal along the segmented electromagnetic transmission path, receiving the signal, and performing an automated response. The anomalous change in downhole pressure is detected at a first location along a segmented electromagnetic transmission path, and the segmented electromagnetic transmission path is integrated into the tool string. The signal is received by at least one receiver in communication with the segmented electromagnetic transmission path. The automated response is performed along the tool string. The automated response is actuated at a second location on the tool string. Typically, the segmented electromagnetic transmission path comprises inductive couplers. Alternatively, the electromagnetic transmission path may comprise direct electrical contacts or optical couplers.
It should be noted that an integrated tool refers to a tool which comprises node circuitry, and a non-integrated tool refers to a tool that does not comprise node circuitry, but is in communication with a node.
The anomalous change in downhole pressure may be a pressure kick, a blowout, or loss of circulation, and is typically detected by at least one pressure sensor. Downhole pressure may be more than 15,000 psi in deep wells. Small changes of pressure may be a result of normal operation of the drilling rig, such as starting or stopping the flow of drilling fluid or tripping the drill string into or out of the hole. These normal changes in pressure may not cause a problem. An anomalous change in downhole pressure is therefore considered to be a significant change in downhole pressure such that the pressure may damage the drill string, endanger the safety of a surface crew, harm natural resources, or waste drilling fluid. The pressure sensor may be associated with a downhole node, an integrated tool, a non-integrated tool, or a bottom-hole assembly. Typically, the at least one pressure sensor is located near the bottom of the downhole tool string. Alternatively, the pressure sensors may be distributed along the tool string.
In general, the receiver may be a blowout preventor, a drilling fluid flow regulator, a computer, a router, a node, an actuator, or an alarm. The automated response may be actuating a blowout preventor, adjusting the flow of drilling fluid, or broadcasting an alarm. Typically the automated response is performed immediately upon receiving the signal. The automated response may be performed by the receiver.
Preferably, the method further comprises the step of actuating an action performing device by the receiver. The action performing device performs the automated response. The action performing device may be selected from the group consisting of a blowout preventor, a drilling fluid flow regulator, and an alarm. The action performing device may be located on the downhole tool string, in a well bore, near a well bore, or mounted on a drilling rig. An electrical connection, such as a wire, pair of twisted wires or coaxial cable may connect an action performing device, such as a blowout preventor, mounted in the well bore. Further optical fibers or infrared technology may be used to communication with the action performing device.
Disclosed is an apparatus for responding to an anomalous change in downhole pressure in a downhole tool string, comprising a segmented electromagnetic transmission path which comprises one or more downhole nodes. The downhole nodes comprise at least one receiver, and at least one pressure sensor. The segmented electromagnetic transmission path is integrated into the tool string, and the downhole nodes are spaced along the tool string. The at least one pressure sensor is in communication with the segmented electromagnetic transmission path, and the receiver is in communication with the pressure sensor via the segmented electromagnetic transmission path. The anomalous change in pressure is detected at one or more locations along the tool string and a automated response is performed at a second location along the drill string.
The at least one receiver may be a blowout preventor, a drilling fluid flow regulator, a computer, a router, an actuator, or an alarm. The apparatus may further comprise at least one action performing device. The automated response may be actuating a blowout preventor, adjusting the flow of drilling fluid, broadcasting an alarm, or sending an electronic message.
The following detailed description of the invention and the preferred embodiment, in which like parts are labeled with like numerals, and the accompanying figures are intended to illustrate certain embodiments of the present invention and not to limit its scope in any way.
Some sensors 40 that may be used to detecting an anomalous change in downhole pressure are disclosed in U.S. Pat. Nos. 6,487,911, 4,696,192, and 4,444,060, the teachings of which are all herein incorporated by reference. Other suitable sensors may be used and may be obvious to those of ordinary skill in the art. The pressure sensor 37 further comprises a transmitter 39 for sending a signal 36 along the segmented electromagnetic transmission path 34 integrated into the downhole tool string 35. A downhole tool string 35 is preferably composed of segments of rigid pipe, but may alternately comprise sections of flexible pipe, or may be coiled tubing. A preferred system of transmitting a signal through a string of downhole components is described in U.S. Pat. No. 6,670,880 to Hall, et al., and related patents, which are herein incorporated by reference. Alternatively, the electromagnetic transmission path may comprise direct electrical contacts or optical couplers. Some other systems which may be compatible with the present invention are disclosed in U.S. Pat. No. 6,641,434, U.S. application Ser. No. 10/708,793 to Hall, et al.; U.S. Pat. No. 6,688,396 to Floerke, et al., and U.S. application Ser. No. 10/605,493 to Hall et al. which are herein incorporated by reference. The receiver 38 comprises a signal receiver 41 for receiving a signal 36. The receiver 38 also comprises an action performing device 42, which may be a blowout preventor, a drilling fluid flow regulator, a computer, a router, an actuator, or an alarm. An alarm may be a visual alarm such as a flashing light or an LED display displaying a warning message. Alternatively, an alarm may be an audio alarm, such as a buzzer, or a verbal warning message.
A blowout preventor may be ram-type blowout preventor, an annular blowout preventor, a coiled tubing blowout preventor, or a spherical blowout preventor. Some control systems which may actuate a blowout preventor are disclosed in U.S. Pat. Nos. 3,552,502, 4,614,148, 6,032,742, and 6,484,806 and are all herein incorporated by reference. These control systems typically actuate a blowout preventor in response to commands from a human operator or to conditions near the surface of the earth such as drilling fluid flowing out of the well bore. These control systems may be adapted according to the present invention to receive a signal 36 from a fluid pressure sensor 37 and actuate the blowout preventor. Alternately, these control systems may be adapted to be controlled by a receiver 38 directly. Typically, a blowout preventor may be closed by hydraulic cylinders, which may be controlled via the opening and closing of a hydraulic supply line. The opening and closing of a hydraulic supply line may be controlled using an electrically operated valve, which may be fitted with electronic circuitry. The electronic circuitry may be in electrical communication with the transmission path 34, and may be adapted to receive the signal 36 and open the hydraulic fluid supply line, thereby actuating the blowout preventor. Alternatively, the electronic circuitry may receive a command to actuate from a receiver 38 such as a node, a router or a computer. An example of a blowout preventor with hydraulic actuators is a ram-type blowout preventor. A ram-type blowout preventor may be capable of withstanding 15,000 psi, and may be installed on the casing head. The ram-type blowout preventor may be wired such that electrically operated valves respond to a signal originating downhole indicating a blowout. As the electrically operated valves open, fluid enters a chamber and pushes the hydraulic cylinders, which forces two halves of a well bore cover together to seal the well bore. These two halves may be designed to close over an open hole, close around a drill string 35, or cut through a drill string 35. A ram-type blowout preventor may be named according to the design of the two halves. A blind ram-type blowout preventor may be designed to close over an open well bore, a variable bore ram or variable bore pipe ram-type blowout preventor may be designed to close over a drill string 35 within a manufacturer specified range of diameters, and a shear ram-type blowout preventor may be designed to cut through a drill string 35.
A drilling fluid flow regulator may be a pump, which may pump drilling fluid into or out of the well bore. A pump may be used in situations such as loss of circulation, where the flow of drilling fluid may be halted to prevent further loss of drilling fluid. Many pumps 46,
Typically, the electromagnetic transmission path comprises inductive couplers 72. The inductive couplers 72 may allow electromagnetic signals to be transmitted across joints of a segmented tool string. The transmission of electromagnetic signals may permit the signal 36 to move rapidly through the tools string, and may allow the signal 36 to reach the receiver 38 in time to react to the anomalous change in downhole pressure. For example, the signal 36 may be able to notify the receiver 38 of a blowout before the drilling fluid or tool string is ejected from the well bore. In this embodiment, a computer 31 is also in communication with the transmission path 34.
Each downhole node 32 may comprise a fluid pressure sensor 37 and a receiver 38. This may be advantageous during tripping. When the tool string 35 is first put in the well bore, it may be advantageous to have a first node 32 containing a receiver 38 near the surface of the earth where it may actuate an action performing device 42 (see
The arrangement of pressure sensors 37 and receivers 38 in the downhole tool string may depend on specific considerations. One arrangement may comprise one pressure sensor 37 in a bottom-hole assembly to detect an anomalous change in downhole pressure, and one receiver 38 in a node 32 near the top of the tool string 35. Such an arrangement may have the advantage of being simple and therefore cost effective. Another arrangement may have multiple bottom pressure sensors 37 located in a bottom-hole assembly. Such an arrangement may provide a redundant system and may protect against the failure of one or more of the sensors 37. Another arrangement may have multiple pressure sensors 37 spread along the downhole tool string 35 which may also provide redundant detection in case one or more sensors 37 fail. Such an arrangement may also be able to track the speed and progress of the anomalous change along the downhole tool string 35, and reveal the behavior of the anomalous change. The at least one pressure sensor 37 may be a downhole node 32, an integrated tool, a non-integrated tool, or a bottom-hole assembly 30, and is preferably located near the bottom of the downhole tool string 35.
The fluid pressure sensor 37 is in communication with the receiver 38 via the transmission path 34. The fluid pressure sensor 37 may send a signal 36 to the receiver 38. The at least one receiver 38 may be a blowout preventor, a drilling fluid flow regulator, a computer, a router, a node, an actuator, or an alarm.
For example, a pressure surge may be detected in the bottom-hole assembly 30. A pressure surge may increase downhole pressure over 9,000 psi.
The fluid pressure sensor 37 may send a signal 36 indicating an anomalous change to a receiver 38, such as a blowout. The receiver 38 may be a blowout preventor, and may close upon receiving the signal 36 to prevent a blowout. There may be several receivers 38 at several points on the downhole tool string 35, which may perform various functions in response to the signal 36. Continuing the example, one receiver 38 may be a drilling fluid flow regulator, which may stop the flow of drilling fluid in preparation for the blowout. Alternately, there may be one receiver 38 which may be a node 32 or a router, which may then actuate a blowout preventor and the drilling fluid flow regulator.
The fluid pressure sensor 37 may be a portion of an integrated tool 44 in a node 32 which also comprises a non-integrated tool 43 and is located near the downhole bottom-hole assembly 30. The pressure sensor 37 is adapted to detect an anomalous change in downhole pressure which may be a pressure kick, a blowout, or loss of circulation. For example, the pressure sensor 37 may detect a sudden increase in downhole pressure, which may indicate a sudden increase in overall pressure downhole and which may be a high pressure kick or a blowout. A sudden increase in downhole pressure may be caused by a pocket of highly pressurized oil or gas contacting the well bore. Alternatively, the pressure sensor 37 may detect a sudden decrease in downhole pressure, which may indicate a loss of circulation. A loss of circulation may be caused by an underground cavern, which may be formed in limestone, and may provide an area into which the drilling fluid may escape. The pressure sensor 37 is also adapted to send a signal 36 to the receiver 38 via the electromagnetic transmission path 34 as seen previously. The receiver 38 is adapted to actuate one or more of the action performing devices 31, 47, 46, 45, which may perform an automated response such as actuating a blowout preventor, adjusting the flow of drilling fluid, or broadcasting an alarm. In alternative embodiments, the receiver 38 may be a computer, an alarm, a drilling fluid flow regulator, or a blowout preventor, and may perform the automated response itself.
Alternatively, a mechanical device such as a pipe 82 may be bolted or otherwise attached to a hand valve 80 and rotated with an electric motor (not shown) to close the blowout preventor 75. The electric motor may then be controlled by a receiver 38 (shown previously). The pipe 82 may allow traditional blowout preventors with hand valves 80 to be used with the present invention without significant modification.
In another embodiment, an annular blowout preventor 73 may be actuated by a receiver 38 controlling a voltage supplied to an electric motor (not shown) of a fluid pump (not shown). The hydraulic fluid pump may pump fluid through a tube 83 to a blowout preventor such as an annular blowout preventor 73. Many blowout preventors commonly known in the art may be controlled via one or more tubes 83. The voltage supplied to the motor may be controlled by a receiver 38 supplying or not supplying the voltage directly. Alternatively, the voltage may be controlled by a receiving device selecting whether or not a voltage supply is connected to the electric motor. The tube 83 may be secured along the blowout preventor stack 84 or along other pipes or tubing along the blowout preventor 84 to prevent the tube 83 from being pinched, cut, or obstructing workers or equipment. Actuating blowout preventors 73, 74, 75 by controlling a voltage supplied to an electric motor of a fluid pump may be advantageous as many blowout preventors which may be controlled via one or more tubes 83, and such blowout preventors 73, 74, 75 may be used with the present invention without modifying the blowout preventors 73, 74, 75, the tubes 83, or the electric motor.
A choke line 77 and a kill line 78 may also be provided, and may allow fluid to flow out of or into the well bore respectively. These may be attached to a drilling fluid flow regulator 46 discussed in
The fluid pressure sensor 37 may be a downhole node 32, an integrated tool 44, a non-integrated tool 43, or a bottom-hole assembly 30. Typically, a fluid pressure sensor 37 may be located near the bottom of the downhole tool string 35.
In step 51 the pressure sensor 37 sends a signal 36 along the electromagnetic transmission path 34. The electromagnetic transmission path 34 is integrated into the tool string 35. The signal 36 may override any function that the transmission path 34 may be performing. Alternatively, the signal 36 may be distinguishable from other signals on the transmission path 34, or may require special handling by the transmission path 34. For example, the transmission path 34 may be a portion of a network, which may have any network protocol known in the art. The signal 36 may break network protocol and be handled to the exclusion of other network functions. Alternatively, the network may function over certain frequencies or during certain periods of time, and the signal 36 may use a dedicated or otherwise unused frequency or period of time in order to transmit. Thus, the signal 36 may be distinguished by the network and handled differently than usual signals. Preferably, the signal 36 is handled as quickly as possible so that the anomalous change also may be handled as quickly as possible. For example, a network may operate within a certain bandwidth of frequencies, and a frequency outside of the operating bandwidth of the network may be used for the signal 36.
In step 52 the receiver 38 receives the signal 36. There may be multiple receivers 38, either near the surface of the well bore 60, or distributed along the downhole tool string 35 which may allow multiple automated responses to be performed along the downhole tool string 35.
For example, in marine drilling, there may be a blowout preventor or fluid control devices located at the seabed as well as on drilling platform. Multiple receivers 38 may be near the seabed and drilling platform which may communicate with the blowout preventors and control devices. A receiver near the seabed allows a quicker response by the seabed blowout preventor yet the platform equipment may also receive the signal 36. An electrically actuated sub sea blowout preventor compatible with the present invention is disclosed in U.S. Pat. No. 6,484,806 to Childers, et al.
In step 53 the receiver 38 performs an automated response. The automated response may be actuating a blowout preventor, adjusting the flow of drilling fluid, or broadcasting an alarm. Typically the automated response is performed immediately upon receiving the signal. Performing the action immediately upon receiving the signal may have the advantage of reducing human error by eliminating the need for an operator. As previously discussed, the signal 36 may be able to notify the receiver 38 of a blowout before the drilling fluid or tool string is ejected from the well bore 60. Performing the action, such as sounding an alarm or actuating a blowout preventor may alert workers faster and may lessen damage to rig, equipment, and people.
Whereas the present invention has been described in particular relation to the drawings attached hereto, it should be understood that other and further modifications apart from those shown or suggested herein, may be made within the scope and spirit of the present invention.
The present application is a continuation of U.S. patent application Ser. No. 10/711,796 filed on Oct. 6, 2004 now abandoned, the entire disclosure of which is incorporated by reference herein. Said application Ser. No. 10/711,796 is a continuation-in-part of U.S. patent application Ser. No. 10/710,875 filed on Aug. 10, 2004, now U.S. Pat. No. 7,142,129, which was incorporated by reference into application Ser. No. 10/711,796.
This invention was made with government support under Contract No. DE-FC26-01NT41229 awarded by the U.S. Department of Energy. The government has certain rights in the invention.
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