WO2014018003A1 - Well drilling methods with audio and video inputs for event detection - Google Patents
Well drilling methods with audio and video inputs for event detection Download PDFInfo
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- WO2014018003A1 WO2014018003A1 PCT/US2012/047891 US2012047891W WO2014018003A1 WO 2014018003 A1 WO2014018003 A1 WO 2014018003A1 US 2012047891 W US2012047891 W US 2012047891W WO 2014018003 A1 WO2014018003 A1 WO 2014018003A1
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- 238000005553 drilling Methods 0.000 title claims abstract description 144
- 238000000034 method Methods 0.000 title claims abstract description 75
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Classifications
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
- E21B44/02—Automatic control of the tool feed
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B19/00—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables
- E21B19/16—Connecting or disconnecting pipe couplings or joints
- E21B19/165—Control or monitoring arrangements therefor
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/002—Survey of boreholes or wells by visual inspection
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
- E21B21/08—Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
Definitions
- the present disclosure relates generally to equipment utilized and operations performed in conjunction with a subterranean well and, in an embodiment described herein, more particularly provides well drilling methods with event detection audio and video inputs.
- Events can also be normal, expected events, in which case it would be desirable to be able to control the drilling operations based on identification of such events.
- FIG. 1 is a schematic view of a well system which can embody principles of the present disclosure.
- FIG. 2 is a flowchart representing a method which embodies principles of this disclosure.
- FIG. 3 is a flowchart of an example of a parameter signature generation process which may be used in the method of FIG. 2.
- FIG. 4 is a flowchart of an example of an event
- FIG. 5 is a listing of events and corresponding event signatures which may be used in the method of FIG. 2.
- FIG. 1 Representatively illustrated in FIG. 1 is a well drilling system 10 and associated method which can embody principles of this disclosure. However, it should be clearly understood that the system 10 and method are merely one example of an application of the principles of this disclosure.
- a wellbore 12 is drilled by rotating a drill bit 14 on an end of a drill string 16.
- Drilling fluid 18 commonly known as mud, is circulated downward through the drill string 16, out the drill bit 14 and upward through an annulus 20 formed between the drill string and the wellbore 12, in order to cool the drill bit, lubricate the drill string, remove cuttings and provide a measure of bottom hole pressure control.
- a non-return valve A non-return valve
- Control of wellbore pressure is very important in managed pressure drilling, and in other types of drilling operations.
- the wellbore pressure is accurately controlled to prevent excessive loss of fluid into the earth formation surrounding the wellbore 12, undesired fracturing of the formation, undesired influx of formation fluids into the wellbore, etc.
- typical underbalanced drilling it is desired to maintain the wellbore pressure somewhat less than the pore pressure, thereby obtaining a controlled influx of fluid from the formation.
- Nitrogen or another gas, or another lighter weight fluid may be added to the drilling fluid 18 for pressure control. This technique is useful, for example, in
- RCD rotating control device 22
- the drill string 16 would extend upwardly through the RCD 22 for connection to, for example, a rotary table (not shown), a standpipe line 26, kelly (not shown), a top drive and/or other conventional drilling equipment.
- the drilling fluid 18 exits the wellhead 24 via a wing valve 28 in communication with the annulus 20 below the RCD 22.
- the fluid 18 then flows through drilling fluid return lines 30, 73 to a choke manifold 32, which includes
- redundant chokes 34 (one or more of which may be used at a time). Backpressure is applied to the annulus 20 by variably restricting flow of the fluid 18 through the operative choke(s) 34.
- wellbore pressure can be conveniently regulated by varying the backpressure applied to the annulus 20.
- a hydraulics model can be used to determine a pressure applied to the annulus 20 at or near the surface which will result in a desired bottom hole pressure, so that an operator (or an automated control system) can readily determine how to regulate the pressure applied to the annulus at or near the surface (which can be conveniently measured) in order to obtain the desired wellbore pressure.
- Pressure applied to the annulus 20 can be measured at or near the surface via a variety of pressure sensors 36, 38, 40, each of which is in communication with the annulus.
- Pressure sensor 36 senses pressure below the RCD 22, but above a blowout preventer (BOP) stack 42.
- Pressure sensor 38 senses pressure in the wellhead below the BOP stack 42.
- Pressure sensor 40 senses pressure in the drilling fluid return lines 30, 73 upstream of the choke manifold 32.
- Another pressure sensor 44 senses pressure in the drilling fluid injection (standpipe) line 26. Yet another pressure sensor 46 senses pressure downstream of the choke manifold 32, but upstream of a separator 48, shaker 50 and mud pit 52. Additional sensors include temperature sensors 54, 56, Coriolis flowmeter 58, and flowmeters 62, 64, 66.
- the system 10 could include only two of the three flowmeters 62, 64, 66. However, input from the sensors is useful to the hydraulics model in determining what the pressure applied to the annulus 20 should be during the drilling operation.
- the drill string 16 may include its own sensors 60, for example, to directly measure bottom hole pressure.
- sensors 60 may be of the type known to those skilled in the art as pressure while drilling (PWD), measurement while drilling (MWD) and/or logging while drilling (LWD) systems.
- PWD pressure while drilling
- MWD measurement while drilling
- LWD logging while drilling
- These drill string sensor systems generally provide at least pressure measurement, and may also provide temperature measurement, detection of drill string characteristics (such as vibration, torque, rpm, weight on bit, stick-slip, etc.), formation characteristics (such as resistivity, density, etc.), fluid characteristics and/or other measurements.
- acoustic, pressure pulse, electromagnetic, etc. may be used to transmit the downhole sensor measurements to the surface .
- Additional sensors could be included in the system 10, if desired.
- another flowmeter 67 could be used to measure the rate of flow of the fluid 18 exiting the wellhead 24, another Coriolis flowmeter (not shown) could be interconnected directly upstream or downstream of a rig mud pump 68, etc.
- Pressure and level sensors could be used with the separator 48, level sensors could be used to indicate a volume of drilling fluid in the mud pit 52, etc. Fewer sensors could be included in the system 10, if desired.
- the output of the rig mud pump 68 could be determined by counting pump strokes, instead of by using flowmeter 62 or any other flowmeters.
- separator 48 could be a 3 or 4 phase separator, or a mud gas separator (sometimes referred to as a "poor boy degasser"). However, the separator 48 is not necessarily used in the system 10.
- the drilling fluid 18 is pumped through the standpipe line 26 and into the interior of the drill string 16 by the rig mud pump 68.
- the pump 68 receives the fluid 18 from the mud pit 52 and flows it via a standpipe manifold 70 to the standpipe 26, the fluid then circulates downward through the drill string 16, upward through the annulus 20, through the drilling fluid return lines 30, 73, through the choke manifold 32, and then via the separator 48 and shaker 50 to the mud pit 52 for conditioning and recirculation.
- Audio sensors 57 can be used to detect audio at any location.
- the audio sensors 57 could be
- a microphone could be placed near the rig mud pump 68, for example, to detect changes in the mud pumps' operation due to certain events (such as a fluid influx or loss, the beginning or end of a drill pipe connection, etc.).
- a microphone could be placed near the choke manifold 32 to detect changes in audio signals produced by different fluids flowing at different flow rates through the operative choke(s) 34.
- Any type, number or combination of audio sensors 57 may be used in any locations (e.g., on a rig at the surface, downhole, at a subsea location, etc.) to detect audio signals from any sources, within the scope of this disclosure.
- Optical sensors 59 can be used to detect optical signals at any location.
- the optical sensors 59 could be positioned facing certain rig equipment, so that optical signals output or reflected by the rig equipment can be detected by the optical sensors.
- a video camera could be directed at the standpipe 26, for example, to detect movements of a kelly hose connected thereto.
- a video camera (or merely a photodiode, etc.) could be directed at a flare or the separator 48 to detect optical changes due to different fluids exiting the wellhead 24. Any type, number or
- optical sensors 59 may be used in any combination of optical sensors 59.
- the choke 34 cannot be used to control backpressure applied to the annulus 20 for control of the bottom hole pressure, unless the fluid 18 is flowing through the choke.
- the fluid 18 is flowed from the pump 68 to the choke manifold 32 via a bypass line 72, 75 when a connection is made in the drill string 16.
- the fluid 18 can bypass the standpipe line 26, drill string 16 and annulus 20, and can flow directly from the pump 68 to the mud return line 30, which remains in communication with the annulus 20. Restriction of this flow by the choke 34 will thereby cause pressure to be applied to the annulus 20.
- both of the bypass line 75 and the mud return line 30 are in communication with the annulus 20 via a single line 73.
- the bypass line 75 and the mud return line 30 could instead be separately connected to the wellhead 24, for example, using an additional wing valve (e.g., below the RCD 22), in which case each of the lines 30, 75 would be directly in communication with the annulus 20.
- an additional wing valve e.g., below the RCD 22
- each of the lines 30, 75 would be directly in communication with the annulus 20.
- this might require some additional plumbing at the rig site, the effect on the annulus pressure would be essentially the same as connecting the bypass line 75 and the mud return line 30 to the common line 73.
- Flow of the fluid 18 through the bypass line 72, 75 is regulated by a choke or other type of flow control device 74.
- Line 72 is upstream of the bypass flow control device 74, and line 75 is downstream of the bypass flow control device .
- Flow of the fluid 18 through the standpipe line 26 is substantially controlled by a valve or other type of flow control device 76.
- the flow control devices 74, 76 are independently controllable, which provides substantial benefits to the system 10, as described more fully below.
- the flowmeters 64, 66 are depicted in FIG. 1 as being interconnected in these lines. However, the rate of flow through the standpipe line 26 could be determined even if only the flowmeters 62, 64 were used, and the rate of flow through the bypass line 72 could be determined even if only the flowmeters 62, 66 were used. Thus, it should be
- system 10 it is not necessary for the system 10 to include all of the sensors depicted in FIG. 1 and described herein, and the system could instead include additional sensors, different combinations and/or types of sensors, etc .
- a bypass flow control device 78 and flow restrictor 80 may be used for filling the standpipe line 26 and drill string 16 after a connection is made, and equalizing
- the fluid 18 is permitted to fill the standpipe line 26 and drill string 16 while a substantial majority of the fluid continues to flow through the bypass line 72, thereby enabling continued controlled application of pressure to the annulus 20.
- the flow control device 76 can be opened, and then the flow control device 74 can be closed to slowly divert a greater proportion of the fluid 18 from the bypass line 72 to the standpipe line 26.
- a similar process can be performed, except in reverse, to gradually divert flow of the fluid 18 from the standpipe line 26 to the bypass line 72 in preparation for adding more drill pipe to the drill string 16. That is, the flow control device 74 can be gradually opened to slowly divert a greater proportion of the fluid 18 from the standpipe line 26 to the bypass line 72, and then the flow control device 76 can be closed.
- restrictor 80 could be integrated into a single element (e.g., a flow control device having a flow restriction therein), and the flow control devices 76, 78 could be integrated into a single flow control device 81 (e.g., a single choke which can gradually open to slowly fill and pressurize the standpipe line 26 and drill string 16 after a drill pipe connection is made, and then open fully to allow maximum flow while drilling) .
- a single element e.g., a flow control device having a flow restriction therein
- the flow control devices 76, 78 could be integrated into a single flow control device 81 (e.g., a single choke which can gradually open to slowly fill and pressurize the standpipe line 26 and drill string 16 after a drill pipe connection is made, and then open fully to allow maximum flow while drilling) .
- the individually operable flow control devices 76, 78 are presently preferred.
- the flow control devices 76, 78 are at times referred to collectively below as though they are the single flow control device 81, but it should be understood that the flow control device 81 can include the individual flow control devices 76, 78.
- the system 10 could include a backpressure pump (not shown) for applying pressure to the annulus 20 and drilling fluid return line 30 upstream of the choke manifold 32, if desired.
- the backpressure pump could be used instead of, or in addition to, the bypass line 72 and flow control device 74 to ensure that fluid continues to flow through the choke manifold 32 during events such as making connections in the drill string 16.
- additional sensors may be used to, for example, monitor the pressure and flow rate output of the backpressure pump.
- connections may not be made in the drill string 16 during drilling, for example, if the drill string comprises a coiled tubing.
- the drill string 16 could be provided with conductors and/other lines (e.g., in a sidewall or interior of the drill string) for transmitting data, commands, pressure, etc. between downhole and the surface (e.g., for communication with the sensors 60).
- FIG. 2 a well drilling method 90 which may be used with the system 10 of FIG. 1 is schematically illustrated. However, it should be clearly understood that the method 90 could be used in conjunction with other systems in keeping with the principles of this disclosure .
- the method 90 includes an event detection process which can be used to alert an operator if an event occurs, such as, by triggering an alarm or displaying a warning if the event is an undesired event (e.g., unacceptable fluid loss to the formation, unacceptable fluid influx from the
- An event can be a precursor to another event happening, in which case detection of the first event can be used as an indication that the second event is about to happen or is in process of occurring.
- a series of events can also provide an indication that another event is about to happen.
- one or more prior events can be used as a source of data for determining if another event will occur.
- events and types of events can be detected in the method 90. These events can include, but are not limited to, a kick (influx), partial fluid loss, total fluid loss, standpipe bleed down, plugged choke, washed out choke, poor hole cleaning (wellbore packed off about drill string), downhole crossflow, wellbore washout, under gauged wellbore, drilling break, ballooning while circulating, ballooning while mud pump is off, stuck pipe, twisted off pipe, back off, plugging of bit nozzle, bit nozzle washed out, leak in surface processing equipment, rig pump failure, backpressure pump failure, downhole sensor 60 failure, washed out drill string, non-return valve failure, start of drill pipe connection, drill pipe connection finished, etc.
- kick influx
- partial fluid loss partial fluid loss
- total fluid loss standpipe bleed down
- washed out choke washed out choke
- poor hole cleaning wellbore packed off about drill string
- downhole crossflow wellbore washout
- drilling break ballooning while circulating, ballooning while mud pump is
- Drilling properties e.g., pressure temperature, flow rate, etc.
- sensors are sensed by sensors, and output from the sensors is used to supply data indicative of the drilling properties.
- This drilling property data is used to determine drilling parameters of interest.
- Data can also be in the form of data from offset wells (e.g., other wells drilled nearby or in similar lithologies, conditions, etc.). Previous experience of drillers can also serve as a source for the data. Data can also be entered by an operator prior to or during the drilling operation.
- a drilling parameter can comprise data related to a single drilling property, or a parameter can comprise a ratio, product, difference, sum or other function of data related to multiple drilling properties. For example, it is useful in drilling operations to monitor the difference between the flow rate of drilling fluid injected into the well (e.g., via the standpipe line 26 as sensed by flowmeter 66) and the flow rate of drilling fluid returned from the well (e.g., via the drilling fluid return line 30 as sensed by the flowmeter 67).
- a parameter of interest which can be used to define a part or segment of a signature can be this difference in drilling properties (flow rate in - flow rate out ) .
- the drilling properties are sensed over time, either continuously or intermittently.
- data related to the drilling properties is available over time, and the behavior of each drilling parameter can be evaluated in real time.
- the drilling parameters change over time, that is, whether each parameter is increasing, decreasing, remaining substantially the same, remaining within a certain range, exceeding a maximum, falling below a minimum, etc.
- parameter behaviors are given appropriate values, and the values are combined to generate parameter signatures indicative of what is occurring in real time during the drilling operation.
- one segment of a parameter signature could indicate that standpipe pressure (e.g., as measured by sensor 44) is increasing
- another segment of the parameter signature could indicate that pressure upstream of the choke manifold (e.g., as measured by sensor 40) is decreasing
- another segment could indicate that the
- amplitude of an audio signal detected by an audio sensor 57 is increasing, and another segment could indicate that the wavelength of an optical signal detected by an optical sensor 59 is within a certain range.
- a parameter signature can include many (perhaps 20 or more) of these segments. Thus, a parameter signature can provide a "snapshot" of what is happening in real time during the drilling operation.
- an event signature is representative of what the drilling parameter behaviors will be when the corresponding event does happen.
- Each event signature is distinctive, because each event is indicated by a
- an event can be a precursor to another event.
- the event signature for the first event can be a distinctive combination of parameter behaviors which indicate that the second event is about to (or at least is eventually going to) happen.
- the corresponding parameter behavior can be whether or not the precursor event (s) have happened.
- Event signatures can be generated prior to commencing a drilling operation, and can be based on experience gained from drilling similar wells under similar conditions, etc. Event signatures can also be refined as a drilling operation progresses and more experience is gained on the well being drilled.
- sensors are used to sense drilling properties during a drilling operation, data relating to the sensed properties are used to determine drilling parameters of interest, values indicative of the behaviors of these parameters are combined to form parameter signatures, and the parameter signatures are compared to pre-defined event signatures to detect whether any of the corresponding events is occurring, or is substantially likely to occur.
- Steps in an example of the event detection process are schematically represented in FIG. 2 in flowchart form.
- the method 90 can include additional, alternative or optional steps as well, and it is not necessary for all of the depicted steps to be performed in keeping with the principles of this disclosure.
- the method 90 may be performed with the system 10 , or it may be performed with any other well drilling system.
- a first step 92 depicted in the FIG. 2 example data is received.
- the data in this example is received from a central database, such as an INSITE(TM) database utilized by Halliburton Energy Services, Inc. of Houston, Texas USA, although other databases may be used if desired.
- INSITE(TM) database utilized by Halliburton Energy Services, Inc. of Houston, Texas USA, although other databases may be used if desired.
- the data typically is in the form of measurements of drilling properties as sensed by various sensors during a drilling operation.
- the sensors 36 , 38 , 40 , 44 , 46 , 54 , 56 , 57 , 58 , 59 , 60 , 62 , 64 , 66 , 67 will produce indications of various properties (such as pressure, temperature, mass or volumetric flow rate, density, resistivity, rpm, torque, weight, position, audio, video, etc.), which will be stored as data in the database. Calibration, conversion and/or other operations may be performed for the data prior to the data being received from the database.
- the data may also be entered manually by an operator.
- data can be received directly from one or more sensors, or from another data acquisition system, whether or not the data originates from sensor measurements, and without first being stored in a separate database.
- the data can be derived from an offset well, previous experience, etc. Any source for the data may be used, in keeping with the
- step 94 various parameter values are calculated for later use in the method 90 .
- the value of the data itself is used as is, without any further calculation.
- step 96 the parameter values are validated and smoothing techniques may be used to ensure that meaningful parameter values are utilized in the later steps of the method 90. For example, a parameter value may be excluded if it represents an unreasonably high or low value for that parameter, and the smoothing techniques may be used to prevent unacceptably large parameter value transitions from distorting later analysis.
- a parameter value can correspond to whether or not another event has occurred, as discussed above .
- step 98 the parameter signature segments are determined. This step can include calculating values
- a value of 1 may be assigned to the corresponding parameter signature segment
- a value of 2 may be assigned to the segment
- a value of 0 may be assigned to the segment
- Comparisons between parameters may also be made to determine a particular signature segment. For example, if one parameter is greater than another parameter, a value of 1 may be assigned to the signature segment, if the first parameter is less than the second parameter, a value of 2 may be assigned, if the parameters are substantially equal, a value of 0 may be assigned, etc.
- the parameter signature segments are combined to make up the parameter signatures. Each parameter signature is a combination of parameter signature segments and represents what is happening in real time in the
- step 102 the parameter signatures are compared to the previously defined event signatures to see if there is a match. Since data is continuously (or at least
- corresponding parameter signatures can also be generated in the method 90 in real time for
- Step 104 represents defining of the event signatures which, as described above, can be performed prior to and/or during the drilling operation.
- Example event signatures are provided in FIG. 5, and are discussed in further detail below.
- an event is indicated if there is a match between an event signature and a parameter signature.
- An indication can be provided to an operator, for example, by displaying on a computer screen information relating to the event, displaying an alert, sounding an alarm, etc.
- Indications can also take the form of recording the
- a control system can also, or alternatively, respond to an indication of an event, as described more fully below.
- a probability of an event occurring is indicated if there is a partial match between an event signature and a parameter signature. For example, if an event signature comprises a combination of 30 parameter behaviors, and a parameter signature is generated in which 28 or 29 of the parameter behaviors match those of the event signature, there may be a high probability that the event is occurring, even though there may not be a complete match between the parameter signature and the event signature. It could be useful to provide an indication to an operator in this circumstance that the probability that the event is occurring is high.
- Another useful indication would be of the probability of the event occurring in the future. For example if, as in the example discussed above, a substantial majority of the parameter behaviors match between the parameter signature and the event signature, and the unmatched parameter
- FIG. 3 a flowchart of another example of the process of generating the parameter signatures in the method 90 is representatively illustrated.
- the process begins with receiving the data as in step 92 described above. Parameter value calculations are then performed as in step 94 described above.
- preprocessing operations are performed for the parameter values.
- maximum and minimum limits may be used for particular parameters, in order to exclude erroneously high or low values of the parameters.
- step 112 the preprocessed parameter values are stored in a data buffer.
- the data buffer is used to queue up the parameter values for subsequent processing.
- step 114 conditioning calculations are performed for the parameter values. For example, smoothing may be used (such as, moving window average, Savitzky-Golay smoothing, etc.) as discussed above in relation to step 96 .
- step 116 the conditioned parameter values are stored in a data buffer.
- step 118 statistical calculations are performed for the parameter values. For example, trend analysis (such as, straight line fit, determination of trend direction over time, first and second order derivatives, etc.) may be used to characterize the behavior of a parameter. Values assigned to the parameter behaviors become segments of the resulting parameter signatures, as discussed above for step 98 .
- trend analysis such as, straight line fit, determination of trend direction over time, first and second order derivatives, etc.
- step 120 the parameter signature segments are output to the database for storage, subsequent analysis, etc.
- the parameter signature segments become part of the INSITE(TM) database for the drilling operation .
- step 100 as discussed above, the parameter
- signature segments are combined to form the parameter signatures .
- an event signature database is configured.
- the database can be configured to include any number of event signatures to enable any number of corresponding events to be identified during a drilling operation.
- the event signature database can be separately configured for different types of drilling operations, such as underbalanced drilling, overbalanced drilling, drilling in particular lithologies, etc.
- step 124 a desired set of event signatures are loaded into the event signature database.
- any number, type and/or combination of event are loaded into the event signature database.
- signatures may be used in the method 90 .
- step 126 the event signature database is queried to see if there are any matches to the parameter signatures generated in step 100 . As discussed above, partial matches may optionally be identified, as well.
- step 128 events are identified which correspond to event signatures that match (or at least partially match) any parameter signatures.
- the output in step 130 can take various different forms, which may depend upon the
- An alarm, alert, warning, display of information, etc. may be provided as discussed above for step 106 .
- occurrence of the event could be recorded, and in this example preferably is recorded, as part of the INSITE(TM) database for the drilling operation.
- event signatures are representatively tabulated, along with parameter behaviors which correspond to the segments of the signatures.
- parameter behaviors which correspond to the segments of the signatures.
- many more event signatures may be provided, and more or less parameter behaviors may be used for determining the signature segments.
- signature segments and different combinations of segments, etc. may be used in other examples within the scope of this disclosure .
- each event signature is distinctive.
- a kick (influx) event is indicated by a particular combination of parameter behaviors
- a fluid loss event is indicated by another particular combination of parameter behaviors .
- a parameter signature is generated which matches (or at least partially matches) any of the event signatures shown in FIG. 5, an indication will be provided that the corresponding event is occurring. If a parameter signature is generated which matches an event signature to a predetermined level, or if the parameter signature's segments are trending toward matching, then an indication may be provided that the corresponding event is substantially likely to occur. This can happen even without any human intervention, resulting in a more automated, precise and safe drilling environment.
- a general increase in volume would be expected if a kick is occurring (e.g., due to increased flare burn rate, mud pump 68 pumping harder, increased flow, etc.).
- a general decrease in volume may be expected (at least initially) if a fluid loss is occurring.
- Changes in pitch (frequency) of audio signals received at, for example, pumps, motors, flares, etc. may also or alternatively be used as parameter behaviors in event signatures. For example, it is expected that the pitch of an audio signal received at a mud pump motor will increase when a kick is occurring.
- mud pit 52 volume as detected by an optical sensor 59 is expected to differ from that volume as predicted by the hydraulics model if a kick or loss is occurring. Inconsistencies in positions of valves leading to the mud pit 52 (as detected by an optical sensor 59) can also be used as an indicator of a kick or loss.
- Levels of particular light frequencies (e.g., infrared and/or ultraviolet, etc.) detected at a flare can be used for kick presence and kick size detection.
- a rate of gas production can be used for underbalanced drilling operations.
- optical sensors 59 determined using such light frequency detection by optical sensors 59.
- Increased physical activity and movement of objects is expected to occur when a drill pipe connection is started.
- This activity (and movement, positions of valves, etc.) can be detected by the optical sensors 59. Decreased activity and movement, and certain positions of elements such as valves, are expected upon completion of the
- the event indications provided by the method 90 can be used to control the drilling operation. For example, if a kick event is indicated, the operative choke(s) 34 can be adjusted in response to increase pressure applied to the annulus 20 in the system 10. If fluid loss is detected, the choke(s) 34 can be adjusted to decrease pressure applied to the annulus 20. If a drill pipe connection is starting, the flow control devices 81, 74 can be appropriately adjusted to maintain a desired pressure in the annulus 20 during the connection process, and when completion of the drill pipe connection is detected, the flow control devices can be appropriately adjusted to restore circulation flow through the drill string 16 in preparation for drilling ahead.
- control over the drilling operation can be implemented based on detection of the corresponding events using the method 90 automatically and without human intervention, if desired.
- a control system such as that described in International
- PCT/US08/87686 may be used for implementing the control over the drilling operation.
- human intervention could be used, for example, to determine whether the control over the drilling operation should be implemented in response to detection of events in the method 90. Thus, if an event is detected (or if the event is indicated as being likely to happen), a human's authorization may be required before the drilling operation is automatically controlled in response.
- a controller 84 (such as a programmable logic controller or another type of controller capable of controlling operation of drilling equipment) is connected to a control system 86 (such as the control system described in International Application No. PCT/US08/87686 , or as described in International Application No.
- the controller 84 is also connected to the flow control devices 34, 74, 81 for regulating flow injected into the drill string 16, flow through the drilling fluid return line 30, and flow between the standpipe injection line 26 and the return line 30.
- the control system 86 can include various elements, such as one or more computing devices/processors , a
- hydraulic model a wellbore model, a database, software in various formats, memory, machine-readable code, etc.
- a wellbore model a database
- software in various formats, memory, machine-readable code, etc.
- the control system 86 is connected to the sensors 36, 38, 40, 44, 46, 54, 56, 57, 58, 59, 60, 62, 64, 66, 67 which sense respective drilling properties during the drilling operation. As discussed above, offset well data, previous operator experience, other operator input, etc., may also be input to the control system 86.
- the control system 86 can include software, programmable and preprogrammed memory, machine-readable code, etc. for carrying out the steps of the method 90 described above.
- the control system 86 may be located at the wellsite, in which case the sensors 36, 38, 40, 44, 46, 54, 56, 57, 58, 59, 60, 62, 64, 66, 67 could be connected to the control system by wires or wirelessly. Alternatively, the control system 86 could be located at a remote location, in which case the control system could receive data via satellite transmission, the Internet, wirelessly, or by any other appropriate means.
- the controller 84 can also be connected to the control system 86 in various ways, whether the control system is locally or remotely located.
- control system 86 can cause one or any number of the chokes 34 to close (e.g., increasingly restrict flow of the fluid 18 through the return line 30) by a predetermined amount automatically in response to the step 130 output indicating that a kick (influx) has occurred, or is substantially likely to occur. For example, if the parameter signature matches (or substantially matches) the event signature for a kick, then the control system 86 will operate the controller 84 to close the operative choke(s) 34 by the predetermined amount (e.g., a percentage of the choke's operating range, such as 1%-10% of that range).
- the predetermined amount e.g., a percentage of the choke's operating range, such as 1%-10% of that range.
- the predetermined amount could be preprogrammed into the control system 86, and/or the predetermined amount could be input, for example, via a human-machine interface.
- control over operation of the choke(s) 34 can be returned to an automated system whereby a wellbore or standpipe pressure set point is maintained (which set point may be obtained, e.g., from a hydraulics model or manual input), the choke(s) can be manually operated, or another manner of controlling the choke(s) can be implemented.
- control system 86 can cause one or any number of the chokes 34 to open (e.g., decrease restriction to flow of the fluid 18 through the return line 30) by a predetermined amount automatically in response to the step 130 output indicating that a fluid loss has
- control system 86 will operate the controller 84 to open the operative choke(s) 34 by the predetermined amount (e.g., a percentage of the choke's operating range, such as 1%-10% of that range ) .
- the predetermined amount could be preprogrammed into the control system 86, and/or the predetermined amount could be input, for example, via a human-machine interface.
- control over operation of the choke(s) 34 can be returned to the automated system whereby the wellbore or standpipe pressure set point is maintained (which set point may be obtained, e.g., from a hydraulics model or manual input), the choke(s) can be manually operated, or another manner of controlling the choke(s) can be implemented.
- control system 86 can provide an alert or an alarm to an operator that a particular event has occurred, or is substantially likely to occur. The operator can then take any needed remedial actions based on the alert/alarm, or can override any actions taken by the control system 86 automatically in response to the step 130 output. If action has already been taken by the control system 86, the operator can undo or reverse such actions, if desired.
- control system 86 can switch between maintaining a desired wellbore pressure to
- the control system 86 can switch between such wellbore pressure set point and standpipe 26 pressure set point modes automatically in response to the step 130 output indicating that an event has occurred, or is substantially likely to occur. For example, if a kick (influx) event is detected, the control system 86 can switch from maintaining a desired wellbore 12 pressure to maintaining a desired standpipe 26 pressure. This switch may actually be performed after verifying that conditions are acceptable for making the switch, and after providing an operator with an option (such as, via a displayed alert) to initiate the switch.
- control system 86 can
- the instructions or guidance may be provided by a local well site display, and/or may be transmitted between the well site and a remote location, etc.
- control system 86 can implement a well control procedure automatically in response to the step 130 output indicating that an event has occurred, or is substantially likely to occur.
- the well control procedure could include routing return flow of the fluid 18 to a conventional rig choke manifold 82 and gas buster 88 (see FIG. 1) designed for handling well control situations.
- the well control procedure could include the control system 86 automatically operating the choke manifold 32 to optimally circulate out an undesired influx.
- control system 86 automatically operating the choke manifold 32 to optimally circulate out an undesired influx.
- control system 86 can
- the choke 34 plugging event can be represented by an event signature which, for example, includes a parameter segment indicating increasing pressure differential across the choke.
- the manipulation of the choke 34 automatically in response to the step 130 output can potentially dislodge whatever has plugged or is increasingly plugging the choke.
- control system 86 can switch flow of the fluid 18 from one of the chokes 34 to another of the chokes automatically in response to the step 130 output indicating that one of the chokes has become plugged, washed out, locked or otherwise compromised, or is substantially likely to become so compromised.
- the switching from one choke 34 to another can be performed progressively and automatically, so that a desired wellbore pressure or standpipe pressure can also be maintained by the control system 86 during the switching.
- the control system 86 can switch flow of the fluid 18 from one of the chokes 34 to another of the chokes
- the chokes 34 can have different trim sizes, so that the chokes have different optimum operating ranges. When the flow of the fluid 18 is outside of the optimum operating range of the choke 34 being used to variably restrict the flow, it can be beneficial to switch the flow to another of the chokes having an optimum operating range which better matches the flow.
- the control system 86 can open an additional choke 34 automatically in response to the step 130 output indicating that an operating range of the operative choke is exceeded, or is substantially likely to be exceeded, by the flow of the fluid 18.
- control system 86 can modify or correct a pressure set point (e.g., received from a
- a sensor such as the sensor 60, a pressure while drilling (PWD) tool, etc.
- PWD pressure while drilling
- the control system 86 can operate the controller 84 using the modified/corrected set point, instead of the set point received from, e.g., the hydraulics model.
- the control system 86 can update the hydraulics and/or well model(s) with revised fluid 18 density based on the detection of the fluid influx or loss event.
- control system 86 can
- the control system 86 can automatically communicate this to the hydraulics model, which will cease correcting the pressure set point based on actual
- control system 86 can automatically communicate this to the hydraulics and/or well model(s), which will adjust a volume of the annulus 20 and/or other parameters in the model(s).
- control system 86 can open one or more of the previously inoperative chokes 34
- a maximum pressure can be preprogrammed into the control system 86 so that, if the maximum pressure is exceeded, one or more of the chokes 34 will be opened by the controller 84 to relieve the excess pressure .
- control system 86 can divert flow to a rig choke manifold 82, or another choke manifold similar to the choke manifold 32, automatically in response to the step 130 output indicating that a sealing element of the RCD 22 has failed, or is substantially likely to fail.
- the control system 86 could also automatically open the choke(s) 34 a desired amount, to thereby relieve pressure under the RCD 22.
- control system 86 can modify an annulus 20 volume used by the hydraulics and/or well model(s) automatically in response to the step 130 output indicating that a floating rig is heaving.
- control system 86 could receive indications of rig heave from a conventional motion compensation system of the floating rig.
- the annulus 20 volume can be
- Audio and optical inputs to the event detection process can be used to, for example, monitor rig activities which produce audio and/or visual signals.
- the audio and/or visual signals can be included in drilling parameter signatures, which are compared to event signatures .
- a well drilling method 90 example described above can comprise sensing at least one of audio signals and optical signals; generating a parameter signature during a drilling operation, the parameter signature being based at least in part on the sensing; and detecting a drilling event by comparing the parameter signature to an event signature indicative of the drilling event.
- the sensing step can include positioning at least one audio sensor 57 proximate at least one source of the audio signals.
- the source may be rig equipment, a rig mud pump 68, and/or a choke manifold 32. Any audio source may be used, within the scope of this disclosure.
- the audio sensor 57 can comprise a microphone. Any other type of audio sensor may be used, within the scope of this disclosure.
- the sensing step may include positioning at least one optical sensor 59 proximate at least one source of the optical signals.
- the source can include rig equipment, a separator 48, and/or a standpipe 26.
- optical source Any optical source may be used, within the scope of this disclosure.
- a component can be an optical source, even if optical signals are merely reflected off of, or
- the optical sensor 59 may comprise a video camera and/or a photodiode. Any other type of optical sensor may be used, within the scope of this disclosure.
- the drilling event can comprise a start of a drill pipe connection, a completion of a drill pipe connection, a fluid influx, a fluid loss, and/or any of a wide variety of other events (such as, choke plugging, pipe separation, etc.).
- the event may be a precursor to another event. Any type of drilling event can be detected, within the scope of this disclosure .
- a well drilling system 10 is also described above.
- the system 10 comprises a control system 86 which compares a parameter signature for a drilling
- the parameter signature being based at least in part on an output of at least one sensor selected from a group comprising audio and optical sensors 57, 59, and a
- controller 84 which controls the drilling operation in response to the drilling event being indicated by at least a partial match between the parameter signature and the event signature .
- the at least partial match may indicate that the drilling event has occurred, or that the drilling event is substantially likely to occur.
- structures disclosed as being separately formed can, in other examples, be integrally formed and vice versa.
Abstract
Description
Claims
Priority Applications (8)
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MX2015000951A MX2015000951A (en) | 2012-07-23 | 2012-07-23 | Well drilling methods with audio and video inputs for event detection. |
PCT/US2012/047891 WO2014018003A1 (en) | 2012-07-23 | 2012-07-23 | Well drilling methods with audio and video inputs for event detection |
EP12881765.7A EP2855839A4 (en) | 2012-07-23 | 2012-07-23 | Well drilling methods with audio and video inputs for event detection |
US14/359,870 US20140326505A1 (en) | 2012-07-23 | 2012-07-23 | Well drilling methods with audio and video inputs for event detection |
BR112015001058A BR112015001058A2 (en) | 2012-07-23 | 2012-07-23 | well drilling method and system |
RU2015104098A RU2015104098A (en) | 2012-07-23 | 2012-07-23 | WELL DRILLING METHOD USING INPUT AUDIO AND VIDEO SIGNALS FOR EVENT DETECTION |
CA2880327A CA2880327A1 (en) | 2012-07-23 | 2012-07-23 | Well drilling methods with audio and video inputs for event detection |
AU2012385968A AU2012385968A1 (en) | 2012-07-23 | 2012-07-23 | Well drilling methods with audio and video inputs for event detection |
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US10683744B2 (en) | 2015-09-01 | 2020-06-16 | Pason Systems Corp. | Method and system for detecting at least one of an influx event and a loss event during well drilling |
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Also Published As
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CA2880327A1 (en) | 2014-01-30 |
MX2015000951A (en) | 2015-06-17 |
EP2855839A1 (en) | 2015-04-08 |
US20140326505A1 (en) | 2014-11-06 |
AU2012385968A1 (en) | 2015-01-15 |
EP2855839A4 (en) | 2016-05-11 |
BR112015001058A2 (en) | 2017-06-27 |
RU2015104098A (en) | 2016-09-10 |
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