MX2015000951A - Well drilling methods with audio and video inputs for event detection. - Google Patents

Abstract

A well drilling method can include sensing at least one of audio 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. A well drilling system can include a control system which compares a parameter signature for a drilling operation to an event signature indicative of a drilling event, the parameter signature being based at least in part on an output of at least one audio and/or optical sensor, and a controller 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.

Description

METHODS OF DRILLING WELLS WITH AUDIO INPUTS AND VIDEO FOR EVENT DETECTION FIELD OF THE INVENTION The present disclosure generally relates to the equipment used and the operations carried out in conjunction with an underground well and, in a manner described herein, more particularly provides well drilling methods with audio and video event detection inputs.

BACKGROUND OF THE INVENTION It is desirable in drilling operations that certain events are identified as soon as they occur, so that any necessary corrective action is taken as soon as possible. Events can also be normal, expected events, in which case it would be desirable to be able to control drilling operations based on the identification of such events.

Therefore, it will be appreciated that improvements in the subject matter of event detection in drilling operations would be desirable.

BRIEF DESCRIPTION OF THE DRAWINGS Figure 1 is a schematic view of a well system that can incorporate the principles of the present disclosure.

Figure 2 is a flowchart representing a method that incorporates the principles of this disclosure.

Figure 3 is a flowchart of an example of a parameter signature generation process that can be used in the method of Figure 2.

Figure 4 is a flow diagram of an example of an event signature generating and event identification process that can be used in the method of Figure 2.

Figure 5 is a list of corresponding events and signatures that can be used in the method of the Figure 2 DETAILED DESCRIPTION OF THE INVENTION A well drilling system 10 and associated method that can incorporate the principles of this disclosure is representatively illustrated in Figure 1. However, it should be clearly understood that the system 10 and the method are only one example of an application of the principles of this disclosure in practice, and that a wide variety of other examples are possible. Therefore, the scope of this disclosure is not entirely limited to the details of the system 10 and method described in this document and / or which are depicted in the drawings.

In the example of Figure 1, a well 12 is drilled by rotating a drill bit 14 at one end of a drill string 16. Drill fluid 18, commonly referred to as mud, is circulated down through the hole. drill string 16, outside the drill bit 14 and upwards through a ring 20 that is formed between the drill string and the well 12, in order to cool the drill bit, lubricate the drill string, remove sediments and provide a pressure control measure at the bottom of the well. A non-return valve 21 (usually a butterfly-type check valve) prevents the flow of the drilling fluid 18 upwards through the drill string 16 (eg, when connections are being made in the chain of drilling).

Control of well pressure is very important in controlled pressure drilling, and in other types of drilling operations. Preferably, the well pressure is precisely controlled to prevent excessive fluid loss within the soil formation surrounding the well 12, undesired fracturing of the formation, unwanted influx of fluids from the formation into the well, etc. In the typical controlled pressure drilling, it is desired to maintain the pressure at the bottom of the well only slightly higher than the pore pressure of the formation, without exceeding a fracture pressure of the formation. In typical low-bore drilling, it is desired to maintain the pressure at the bottom of the well somewhat lower than the pore pressure, thereby obtaining a controlled inflow of fluid from the formation.

Nitrogen or other gas, or other fluid of lighter weight, can be added to the drilling fluid 18 for pressure control. This technique is useful, for example, in low-balance drilling operations.

In system 10, additional control over the well pressure is obtained by closing the ring 20 (eg, isolating it from communication with the atmosphere and enabling the ring to be pressurized at or near the surface) using a device Rotary Control Device (RCD) 22. RCD 22 seals around drill string 16 above a wellhead 24. Although not shown in Figure 1, drill string 16 would extend upward to through the RCD 22 for connection with, for example, a rotating platform (not shown), a stabilizing tube line 26, kellcy (not shown), a engine in the top and / or other conventional drilling equipment.

The drilling fluid 18 leaves the wellhead 24 through a wing valve 28 in communication with the ring 20 below the RCD 22. The fluid 18 then flows through the fluid return lines 30, 73 to a shutter collector 32, which includes redundant shutters 34 (one or more of which can be used at the same time). Back pressure is applied to the ring 20 by varyingly restricting the flow of fluid 18 through the operative shutter (s) 34. ? greater restriction to the flow through the plug 34, the greater the back pressure applied to the ring 20. Therefore, the pressure of the well can be regulated conveniently by varying the back pressure applied to the ring 20. A hydraulic model can be used to determine a pressure applied to the ring 20 at or near the surface that will result in a desired downhole pressure, so that an operator (or an automated control system) can easily determine how to regulate the pressure applied to the ring at or near the surface (which can be conveniently measured) in order to obtain the desired well pressure.

The pressure applied to the ring 20 can be measured at or near the surface by means of a variety of sensors of pressure 36, 38, 40 each of which is in communication with the ring. The pressure sensor 36 detects the pressure below the RCD 22, but above a stack of burst preventer (BOP, Blowout Preventer) 42. The pressure sensor 38 detects the pressure in the wellhead below the stack BOP 42. The pressure sensor 40 detects the pressure in the fluid return lines 30, 73 upstream of the seal collector 32.

Another pressure sensor 44 detects the pressure in the drilling fluid injection line (stabilizing tube) 26. Still another pressure sensor 46 detects the pressure downstream of the sealing manifold 32, but upstream of a separator 48, a shaker 50 and mud pit 52. Additional sensors include the temperature sensors 54, 56, the Coriolis 58 flowmeter, and the flow meters 62, 64, 66.

Not all of these sensors are necessary. For example, the system 10 could include only two of the three flow meters 62, 64, 66. However, the input of the sensors is useful for the hydraulic model in determining what the pressure applied to the ring 20 should be during the operation of drilling.

In addition, the drill string 16 may include its own sensors 60, for example, to directly measure the pressure at the bottom of the well. Such sensors 60 may be of the type known to those skilled in the art as pressure systems during drilling (PWD, Pressure While Drilling), measurement during drilling (MWD, Measurement While Drilling) and / or recording during drilling (LWD, Logging While Drilling). These drill string sensor systems generally provide at least the measurement of pressure, and can also provide temperature measurement, detection of characteristics of the drill string (such as vibration, torque, rpm, weight on the drill bit , stick-slip, etc.), characteristics of the formation (such as resistivity, density, etc.), fluid characteristics and / or other measurements. Different forms of telemetry (acoustics, pulse pressure, electromagnetic, etc.) can be used to transmit the sensor measurements from the well to the surface.

Additional sensors could be included in the system 10 if desired. For example, another flow meter 67 could be used to measure the flow rate of the fluid 18 leaving the wellhead 24, another Coriolis flowmeter (not shown) could be interconnected directly upstream or downstream of a mud pump of the equipment 68, etc. pressure and level sensors could be used with the separator 48, it could be use level sensors to indicate a volume of the drilling fluid in the mud pit 52, etc.

Less sensors could be included in the system 10, if desired. For example, the output of the mud pump of the equipment 68 could be determined by counting activations of the pump, instead of using the flow meter 62 or any other flowmeter.

Note that the separator 48 could be a 3 or 4 phase separator, or a sludge 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 stabilizer tube line 26 and into the drill string 16 by the mud pump of the equipment 68. The pump 68 receives the fluid 18 from the mud pit 52 and makes it flow through a manifold of the stabilizer tube 70 to the stabilizer tube line 26. Then, the fluid flows down through the perforation chain 16, up through the ring 20, through the fluid return line. 30, 73 through the seal collector 32, and then through the separator 48 and the shaker 50 to the mud pit 52 for conditioning and recirculation.

Audio sensors 57 can be used to detect audio at any location. For example, the audio sensors 57 could be positioned in close proximity to the drilling equipment, so that the audio signals provided by the drilling equipment can be detected by the audio sensors.

A microphone could be placed near the mud pump of equipment 68, for example, to detect changes in the operation of mud pumps due to certain events (such as an influx or loss of fluid, the start or end of a drill pipe connection, etc.). As another example, a microphone could be placed near the shutter collector 32 to detect changes in the audio signals produced by different fluids flowing at different flow rates through the operative shutter (s) 34. Any type, number or combination of audio sensors 57 could be used at any location (eg, on the surface drilling platform, inside the well, in an underwater location, etc.) to detect signals from Audio is from any source, within the scope of this disclosure.

Optical sensors 59 can be used to detect optical signals at any location. For example, optical sensors 59 could be positioned in front of a certain drilling equipment, in such a way that the optical signals produced or reflected by the drilling equipment can be detected by the optical sensors.

A video camera could be directed to the stabilizer tube 26, for example, to detect movements of a Kelly hose connected thereto. As another example, a video camera (or simply a photodiode, etc.) could be directed to a torch or the separator 48 to detect optical changes due to different fluids leaving the well head 24. Any type, number can be used or combination of optical sensors 59 in any location (eg, on a surface drilling platform, in the interior of the well, in an underwater location, etc.) to detect optical signals from any of the sources, within the scope of this disclosure.

Note that, in the system 10 as described hereinabove, the shutter 34 can not be used to control the back pressure applied to the ring 20 for control of the downhole pressure, unless the fluid 18 is flowing through the shutter. In conventional balanced drilling operations, such a situation can occur whenever a connection is made in the drill string 16 (eg, to add another length of the drill pipe to the drill string while the well 12 is drilled deeper), and the lack of circulation will require that the pressure at the bottom of the well be regulated only by the density of the fluid 18.

In system 10, however, fluid flow 18 can be maintained through plug 34, although fluid does not circulate through drill string 16 and ring 20, while a connection is made in the chain of drilling. Therefore, the pressure can still be applied to the ring 20 by restricting the flow of the fluid 18 through the plug 34, although a separate back pressure pump may not be used.

Instead, the fluid 18 is flowed from the pump 68 to the seal collector 32 by means of a bypass line 72, 75 when a connection is made in the drill string 16. Therefore, the fluid 18 may exceed the stabilizer tube line 26, the drill string 16 and the ring 20, and can flow directly from the pump 68 to the mud return line 30, which remains in communication with the ring 20. The restriction of this flow by the shutter 34 will thus cause pressure to be applied to ring 20.

As shown in Figure 1, both the bypass line 75 and the mud return line 30 are in communication with ring 20 through a single line 73.

However, bypass line 75 and sludge return line 30 could instead be connected separately to wellhead 24, for example, using an additional wing valve (eg, below RCD 22). ), in which case each of the lines 30, 75 would be directly in communication with the ring 20. Although this might require some additional piping at the drilling rig site, the effect on the ring pressure would be essentially the same as connect the branch line 75 and the mud return line 30 to the common line 73. Therefore, it should be appreciated that different configurations of the components of the system 10 can be used, without departing from the principles of this disclosure.

The flow of the fluid 18 through the branch line 72, 75 is regulated by means of a plug or other type of flow control device 74. The line 72 is upstream of the bypass flow control device 74, and line 75 is downstream of the bypass flow control device.

Fluid flow 18 through stabilizer tube line 26 is substantially controlled by means of a valve or other type of flow control device 76. Note that flow control devices 74, 76 are independently controllable, which provides substantial benefits to system 10, as described more fully below.

Since the flow rate of the fluid 18 through each of the lines of stabilizer and bypass tube 26, 72 is useful in determining how the pressure is affected to the bottom of the well by means of these flows, the flow meters 64, 66 they are represented in Figure 1 as interconnected in these lines. However, the flow rate through the stabilizer tube line 26 could be determined even if only the flow meters 62, 64 are used, and the flow rate through the bypass line 72 could be determined even if only the flow meters 62 were used. , 66. Therefore, it should be understood that it is not necessary for the system 10 to include all the sensors that are represented in Figure 1 and are described in this document, and the system could rather include sensors, different combinations and / or types of additional sensors, etc.

A bypass flow control device 78 and flow restrictor 80 can be used to fill the line of stabilizer tube 26 and drill string 16 after a connection is made, and equalize the pressure between the line of stabilizer tube and the lines. mud return lines 30, 73 before opening the flow control device 76. On the other In this manner, the sudden opening of the flow control device 76 before the stabilizer tube line 26 and the drill string 16 are filled and pressurized with the fluid 18 could cause an undesirable transient pressure in the ring 20 (e.g. , because the flow to the seal collector 32 is temporarily lost while the line of its stabilizer and the drill string are filled with fluid, etc.).

By opening the stabilizer tube bypass flow control device 78 after a connection is made, the fluid 18 is allowed to fill the stabilizer tube line 26 and the drill string 16 while a substantial majority of the fluid continues to flow to through the branch line 72, thereby enabling continuous controlled pressure application to the ring 20. After the pressure in the stabilizing tube line 26 has been matched with the pressure in the mud return lines 30, 73 and the bypass line 75, the flow control device 76 can be opened, and then the flow control device 74 can be closed to slowly divert a larger proportion of the fluid 18 from the bypass line 72 to the line stabilizer tube 26.

Before a connection is made in the drill string 16, a similar process can be carried out, except in reverse, to gradually divert the flow of fluid 18 from the stabilizer tube line 26 to the bypass line 72 in the preparation to add more drill pipes to the drill string 16. That is, the control device of flow 74 can be opened gradually to slowly divert a greater proportion of the fluid 18 from the stabilizer tube line 26 to the bypass line 72, and then the flow control device 76 can be closed.

Note that the flow control device 78 and the flow restrictor 80 could be integrated in a single device element (eg, a flow control device having a flow restriction therein), and the devices flow control 76, 78 could be integrated into a single flow control device 81 (e.g., a single shutter that can be opened gradually to slowly fill and pressurize stabilizer tube line 26 and drill string 16 after that a drill pipe connection is made, and then fully open to allow maximum flow during drilling).

However, since typical conventional drilling rigs are equipped with the flow control device 76 in the form of a valve in the manifold of stabilizer tube 70, and the use of stabilizer tube valve is incorporated in common drilling practices, flow control devices 76, 78 individually operable are currently preferred. The flow control devices 76, 78 are sometimes collectively referred to below as being the sole flow control device 81, but it should be understood that the flow control device 81 may include the flow control devices 76, 78 individual.

Note that the system 10 could include a back pressure pump (not shown) for applying pressure to the ring 20 and the perforation fluid return line 30 upstream of the seal collector 32, if desired. The back pressure pump could be used in place of, or in addition to, the bypass line 72 and the flow control device 74 to ensure that fluid continues to flow through the shutter collector 32 during events such as when making connections in the drill string 16. In that case, additional sensors can be used to, for example, monitor the pressure output and the back pressure pump flow.

In other examples, the connections may not be made in the drill string 16 during drilling, for example, if the drill string comprises a pipeline. flexible. The drill string 16 could be provided with conductors and / or other lines (eg, on a side wall or inside the drill string) to transmit data, commands, pressure, etc. between the interior of the well and the surface (eg, for communication with the sensors 60).

Methods for controlling pressure and flow in drilling operations, including the use of data validation and a predictive device, are described in International Application No. PCT / US10 / 56433, filed on November 12, 2010.

Referring now further to Figure 2, a well-drilling method 90 that can be used with system 10 of Figure 1 is schematically illustrated. However, it should be clearly understood that method 90 could be used in conjunction with others. systems in accordance with the principles of this disclosure.

Method 90 includes an event detection process that can be used to alert an operator if an event occurs, such as by activating an alarm or displaying a warning if the event is an undesired event (eg, loss of unacceptable fluid to the formation, unacceptable fluid influx from the formation into the well, etc.), or to show information about the event if it is a normal, expected or desired event, etc. The methods of Well drilling incorporating event detection is described in International Application No. PCT / US09 / 52227, filed July 30, 2009, and well drilling methods that incorporate automated responses to event detection are described in International Application No. PCT / US11 / 42917, filed on July 5, 2011.

An event can be a precursor to another event happening, in which case the detection of the first event can be used as an indication that the second event is about to happen. Therefore, one or more previous events can be used as a data source to determine if another event will occur.

Many events and types of events can be detected in method 90. These events can include, but are not limited to, an influx (kick), partial fluid loss, total fluid loss, stabilizer tube purge, plugged shutter, shutter ruined, poor well cleaning (put full around the drill string), cross flow inside the well, collapse of the well, poorly calibrated well, rupture of drilling, ballooning during circulation, ballooning while the mud pump is off , tube stuck, twisted tube, reverse, capped bit, bit nozzle ruined, play on the surface processing equipment, pump failure of the drilling equipment, failure of the back pressure pump, failure of the sensor 60 inside the well, ruined drill string, failure in the non-return valve , beginning of the connection of the drill pipe, connection of the finished drill pipe, etc.

In order to detect events, the drilling parameter "signatures" produced in real time are compared with a set of event "signatures" in order to determine if any of the events represented by those event signatures are occurring. Therefore, what is happening now in the drilling operation (the drilling parameter signatures) is compared to a set of signatures that correspond to drilling events and, if there is a match, this is an indication of what is happening the event that corresponds to the coincident event signature.

Drilling properties (eg, pressure temperature, flow rate, etc.) are detected by means of the sensors, and the output of the sensors is used to supply data indicative of the drilling properties. These drilling properties data are used to determine the drilling parameters of interest.

The data may also be in the form of outdated well data (eg, other wells drilled near or in similar lithologies, conditions, etc.). The previous experience of drillers can also serve as a source of the data. The data can also be entered by an operator before or during the drilling operation.

A drilling parameter may comprise data related to a single drilling property, or a parameter may 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 the drilling fluid injected into the well (eg, by means of the stabilizer tube line 26 detected by means of the 66 flowmeter) and the flow rate that the drilling fluid returned from the well (e.g., by means of the drilling fluid return line 30 detected by means of the flow meter 67). Therefore, a parameter of interest, which can be used to define a part or segment of a signature, can be this difference in the perforation properties (inlet flow-outflow).

During a drilling operation, drilling properties are detected over time, either continuously or intermittently. Therefore, data related to drilling properties are available over time, and the behavior of each drilling parameter can be evaluated in real time. Of particular interest in the method is how the drilling parameters change over time, that is, if each parameter is increasing, decreasing, remaining substantially the same, remaining within a certain range, exceeding a maximum, falling below a minimum. , etc.

These parameter behaviors are provided with appropriate values, and the values are combined to generate parameter signatures indicative of what is occurring in real time during the drilling operation. For example, a segment of a parameter signature could indicate that the stabilizer tube pressure (eg, measured by sensor 44) is increasing, other segments of the parameter signature could indicate that the pressure upstream of the manifold of shutter (eg, measured by sensor 40) is decreasing, another segment could indicate that the amplitude of an audio signal detected by means of an audio sensor 57 is increasing, and another segment could indicate that the The wavelength of an optical signal detected by means of an optical sensor 59 is within a certain range.

A parameter signature can include many (perhaps 20 or more) of these segments. Therefore, a parameter signature can provide a "snapshot" of what is happening in real time during the drilling operation.

An event signature, on the other hand, does not represent what is happening in real time during a drilling operation. Instead, an event signature is representative of how the drilling parameter behavior will be when the corresponding event does not occur. The event signature is distinctive, because each event is indicated by a distinctive combination of parameter behaviors.

As discussed above, an event can be a precursor to another event. In that case, the event signature for the first event can be a distinctive combination of parameter behaviors that indicate that the second event is by (or at least will eventually) happen.

Events can be parameters, for example, in the circumstance discussed above in which a series of events can indicate that another event will happen. In that case, the corresponding parameter behavior can be if the precursor event (s) has or has not happened.

Event signatures can be generated before starting 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 the drilling operation progresses and more experience is gained in the well being drilled.

In basic terms, sensors are used to detect the properties of drilling during a drilling operation, the data related to the detected properties are used to determine the drilling parameters of interest, the values indicative of the behaviors of these parameters combine to form parameter signatures, and parameter signatures are compared with predefined event signatures to detect if any of the corresponding events are occurring, or is substantially likely to occur.

The steps in an example of the event detection process are schematically represented in Figure 2 in the form of a flowchart. However, it should be understood that the method 90 may also include additional, alternative or optional steps, and it is not necessary that all the steps that are represented be carried out in accordance with the principles of this disclosure. Method 90 can be carried performed with the system 10, or it can be carried out with any other well drilling system.

In a first step 92 that is represented in the example of Figure 2, the data is received. The data in this example is received from a central database, such as an INSITE ™ database that is used by Halliburton Energy Services, Inc. of Houston, Texas, United States, although other databases may be used if you want The data is usually in the form of drilling properties measurements detected by means of different sensors during a drilling operation. For example, sensors 36, 38, 40, 44, 46, 54, 56, 57, 58, 59, 60, 62, 64, 66, 67, as well as other sensors, will produce indications of different properties (such as pressure, temperature, mass or volumetric flow, density, resistivity, rpm, torque, weight, position, audio, video, etc.), which will be stored as data in the database. Calibration, conversion and / or other operations can be carried out for the data before the data is received from the database.

The data can also be entered manually by an operator. As another alternative, the data can be received directly from one or more sensors, or from another data acquisition system, whether the data is originate from sensor measurements or not, and without first being stored in a separate database. In addition, as discussed above, the data can be derived from an outdated well, previous experience, etc. Any source can be used for the data, in accordance with the principles of this disclosure.

In step 94, different parameter values are calculated for later use in method 90. For example, it may be desirable to calculate a ratio of data values, a sum of data values, a difference between data values, a product of data values, etc. In some cases, however, the value of the data itself is used as it is, without any additional calculation.

In step 96, the parameter values are validated and smoothing techniques can be used to ensure that the values of significant parameters are used in the subsequent steps of method 90. For example, a parameter value can be excluded if it represents a value excessively high or low for that parameter, and smoothing techniques can be used to prevent excessively large parameter value transitions from distorting the subsequent analysis. A parameter value may correspond to whether another event has occurred or not, as discussed above.

In step 98, the parameter signature segments are determined. This step may include calculating values indicative of the behaviors of the parameters. For example, if a parameter has an upward trend, a value of 1 can be assigned to the corresponding parameter signature segment, if a parameter has a downward trend, a value of 2 can be assigned to the segment, if the parameter is unchanged. , a value of 0 can be assigned to the segment, etc. To determine the behavior of a parameter, statistical calculations (algorithms) can be applied to the parameter values resulting from step 96.

You can also make comparisons between parameters to determine a particular signature segment. For example, if a parameter is greater than another parameter, a value of 1 can be assigned to the signature segment, if the first parameter is smaller than the second parameter, a value of 2 can be assigned, if the parameters are substantially equal, You can assign a value of 0, etc.

In step 100, the parameter signature segments are combined to make the parameter signatures. Each parameter signature is a combination of parameter signature segments and represents what is happening in real time in the drilling operation.

In step 102, the parameter signatures are compared with the previously defined event signatures to see if there is a match. Because the data is generated continuously (or at least intermittently) in real time during a drilling operation, the corresponding parameter signatures in the method 90 can also be generated in real time for comparison with the event signatures. Therefore, an operator can be informed immediately during the drilling operation if the event is occurring.

Step 104 represents defining the event signatures which, as described above, can be carried out before and / or during the drilling operation. Exemplary event signatures are provided in Figure 5, and are discussed in more detail later.

In step 106 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 related to the event, displaying an alert, sounding an alarm, etc. The indications can also take the form of recording the occurrence of the event in a database, computer memory, etc. A control system can also, or alternatively, respond to an indication of an event, as described more fully below.

In step 108, 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 of that the event is happening, although there may not be a complete match between the parameter signature and the event signature. It may 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 the probability that the event will occur in the future. For example, as in the example discussed above, a substantial majority of the behavior of the parameter matches between the parameter signature and the event signature, and the unmatched parameter behaviors are tending to coincide, so it would be useful (particularly if the event is an unwanted event) warn an operator that the event is likely to occur, so that corrective action is taken if necessary (for example, to prevent an undesired event occurs).

Referring now further to Figure 3, a flow chart of another example of the process for generating the parameter signatures in method 90 is representatively illustrated. The process begins with the reception of the data as in step 92 described above. The parameter value calculations are then carried out as in step 94 described above.

In step 110, the pre-processing operations for the parameter values are carried out. For example, the maximum and minimum limits can be used for particular parameters, in order to erroneously exclude high or low values of the parameters.

In step 112, the pre-processed parameter values are stored in a data buffer. The data buffer is used to queue the parameter values for subsequent processing.

In step 114, conditioning calculations are performed for the parameter values. For example, smoothing can be used (such as moving window average, Savitzky-Golay smoothing, etc.) as discussed above in relation to step 96.

In step 116, the conditioned parameter values are stored in a data buffer.

In step 118, statistical calculations are performed for the parameter values. For example, trend analysis (such as straight line adjustment, trend direction determination in time, first and second order derivatives, etc.) can be used to characterize the behavior of a parameter. The values assigned to the parameter behaviors become segments of the resulting parameter signatures, as discussed above for step 98.

In step 120, the parameter signature segments are provided to the database for storage, subsequent analysis, etc. In this example, the parameter signature segments become part of the INSITE ™ database for the drilling operation.

In step 100, as discussed above, the parameter signature segments are combined to form the parameter signatures.

Referring now further to Figure 4, an example of a flowchart for a process of identifying which an event has occurred is illustrated representatively in method 90. The process starts with step 122, in which a basis is configured of event signature data. The database can be configured to include any number of event signatures to enable identification any number of corresponding events during a drilling operation. Preferably, the database of event signatures can be configured separately for different types of drilling operations, such as low-balance drilling, over-bore drilling, drilling in particular lithologies, etc.

In step 124, a desired set of event signatures is loaded into the event signature database. As discussed above, any number, type and / or combination of event signatures can be used in method 90.

In step 126, the event signature database is queried to see if there are matches to the parameter signatures generated in step 100. As discussed above, partial matches can also be optionally identified.

In step 128, the events that correspond to the event signatures that match (or match at least partially) to any parameter signature are identified. The output in step 130 can take different forms, which may depend on the event that is identified. An alarm, alert, warning, information display, etc. can be provided, as discussed above for step 106. At a minimum, the occurrence of the event could be recorded, and in this example it is preferably recorded as part of the INSITE ™ database for the drilling operation.

Referring now further to Figure 5, four exemplary event signatures are tabulated representatively, along with the behaviors corresponding to the signature segments. In practice, many more event signatures can be provided, and more or less parameter behaviors can be used to determine the signature segments.

It should be clearly understood that the event signatures depicted in Figure 5 and the parameter behaviors listed therein are only to present examples of how the principles of this disclosure could be used in actual practice. The scope of this disclosure is not limited to the event signatures, or segments of those event signatures, as is representatively listed in Figure 5. Different event signatures, different parameter behaviors, different signature segments and different signatures may be used. combinations of segments, etc. in other examples within the scope of this disclosure.

Observe that each event signature is distinctive. Therefore, an influx event (kick is indicated by a particular combination of parameter behaviors, while a fluid loss event is indicated by another particular combination of parameter behaviors.

If, during a drilling operation, a parameter signature is generated that matches (or coincides at least partially) with any of the event signatures shown in Figure 5, an indication that the corresponding event is occurring will be provided. If a parameter signature is generated that matches an event signature at a predetermined level, or if the parameter signature segments are tending to match, then an indication may be provided that the corresponding event is substantially likely to occur. This can happen to one without any human intervention, which results in a more automated, accurate and safe drilling environment.

With respect to the audio sensors 57, it is contemplated that a general increase in volume would be expected if an influx is occurring (eg, due to the torch combustion rate, the mud pump 68 pumping more ø hard, increased flow, etc.). A general decrease in volume (at least initially) if a loss of fluid is occurring is expected.

As another example, a general increase in volume is expected when a process of connection, and that there will be a general decrease in volume when the connection process is complete.

Changes in the pitch (frequency) of audio signals received in, for example, pumps, motors, torches, etc., also or alternatively can be used as parameter behaviors in the event signatures. For example, it is expected that the passage of an audio signal received in a mud pump motor will increase when an influx is occurring.

With respect to the optical sensors 59, it is expected that there will be more inconsistencies between, for example, actual flow control device positions and those positions as predicted by means of a hydraulic model, or as manual input, when the flow is occurring . As another example, the volume of the mud pit 52 detected by means of an optical sensor 59 is expected to differ from the volume predicted by the hydraulic model if an influx or loss is occurring. Inconsistencies can also be used in value positions leading to the mud pit 52 (as detected by an optical sensor 59) as an indicator of an influx or loss.

The levels of particular light frequencies (eg, infrared and / or ultraviolet, etc.) detected in a torch can be used to detect the presence of influx and influx size. In low-balance drilling operations, a gas production rate can be determined using such light frequency detection by means of optical sensors 59.

Increased physical activity and movement of objects (such as, a Kelly hose connected in the stabilizer tube line 26, etc.) is expected to occur when a drill pipe connection is initiated. This activity (and movement, valve positions, etc.) can be detected by means of the optical sensors 59. The decreased activity and movement, and certain positions of elements such as valves, are expected with the termination of the connection process.

The event indications that are provided by method 90 can be used to control the drilling operation. For example, if an influx event is indicated, the operative shutter (s) 34 may be adjusted in response to the pressure increase applied to the ring 20 in the system 10. If loss of fluid, the shutter (s) 34 can be adjusted to decrease the pressure applied to the ring 20. If a drill pipe connection is initiated, the flow control devices 81, 74 can be adjusted appropriately to maintaining a desired pressure in the ring 20 during the connection process, and When the termination of the drill pipe connection is detected, the flow control devices can be properly adjusted to restore circulation flow through the drill string 16 in preparation for drilling ahead.

These and other types of control over the drilling operation can be implemented based on the detection of the corresponding events using method 90 automatically and without human intervention, if desired. In one example, a control system such as the one described in International Application No. PCT / US08 / 87686 can be used to implement control over the drilling operation.

In some embodiments, human intervention could be used, for example, to determine whether control over the drilling operation should be implemented in response to the detection of events in method 90. Therefore, if an event is detected (or if the event is indicated as likely to occur), a human authorization may be required before the drilling operation is automatically controlled in response.

As shown in Figure 1, a controller 84 (such as a programmable logic controller or other type of controller capable of controlling the operation of the perforation) 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. PCT / US10 / 56433). The controller 84 is also connected to the flow control devices 34, 74, 81 to regulate the flow that is injected into the drill string 16, the flow through the drilling fluid return line 30, and the flow between the stabilizer tube injection line 26 and the return line 30.

The control system 86 may include different elements, such as one or more computing devices / processors, a hydraulic model, a well model, a database, software in different formats, memory, machine-readable code, etc. These and other elements can be included in a single structure or location, or they can be distributed among multiple structures or locations.

The control system 86 is connected to sensors 36, 38, 40, 44, 46, 54, 56, 57, 58, 59, 60, 62, 64, 66, 67 which detect respective drilling properties during the operation of drilling. As discussed above, the outdated well data, prior operator experience, or other operator input, etc., can also be entered into the control system 86. The control system 86 may include software, programmable and pre-programmed memory, machine-readable code, etc. to carry out the steps of method 90 described above.

The control system 86 can be located at the well site, in which case the sensors 36, 38, 40, 44, 46, 54, 56, 57, 58, 59, 60, 62, 64, 66, 67 could be Connect to the control system by means of 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 may also be connected to the control system 86 in different ways, whether the control system is located locally or remotely.

In one example, the control system 86 can cause one or any number of the shutters 34 to close (eg, incrementally restrict the flow of fluid 18 through the return line 30) by a predetermined amount automatically in response to the output of step 130 indicating that an influx has occurred (kick, or is substantially likely to occur.) For example, if the parameter signature matches (or substantially matches) the event signature for an influx, then the control system 86 will operate the controller 84 to close the operative shutter (s) 34 for the predetermined amount (eg, a percentage of the shutter operating range, such as 1% -10% of that range).

The predetermined amount could be pre-programmed in the control system 86, and / or the predetermined amount could be entered, for example, by means of a human-machine interface. After the shutter (s) 34 has been closed by the predetermined amount, control over the operation of the shutter (s) 34 can be returned to an automated system whereby a point is maintained of pressure adjustment of the well or stabilizing tube (whose set point can be obtained, eg, from a hydraulic or manual input model), the shutter (s) can be operated manually, or another way of controlling the shutter (s) may be implemented.

In another example, the control system 86 can cause one or any number of the shutters 34 to be opened (eg, decrease the restriction to the flow of the fluid 18 through the return line 30) by a predetermined amount automatically in response to the output of step 130 which indicates that a fluid loss has occurred, or is substantially likely to occur. For example, if the parameter signature matches (or substantially coincides) with the event signature for a fluid loss, then control system 86 will operate controller 84 to open the operative shutter (s) 34 by the predetermined amount ( eg, a percentage of the shutter's operating range, such as 1% -10% of that range).

The predetermined amount could be pre-programmed in the control system 86, and / or the predetermined amount could be entered, for example, by means of a human-machine interface. After the shutter (s) 34 has been opened by the predetermined amount, control over the operation of the shutter (s) 34 can be returned to the automated system whereby a point of pressure adjustment of the well or stabilizing tube (whose set point can be obtained, eg, from a hydraulic or manual input), the shutter (s) can be operated manually, or another way of controlling the shutter (s) can be implemented.

In another example, the control system 86 may provide an alert or alarm to an operator that a particular event has occurred, or is substantially likely to occur. The operator can then take any corrective action based on the alert / alarm, or can override any action taken by the control system 86 automatically in response to the output of step 130. If action has already been taken by control system 86, the operator may undo or reverse such actions, if desired.

In another example, the control system 86 may change between maintaining a desired pressure in the well to maintain a desired pressure of the stabilizing tube in response to the output of step 130 indicating that an event has occurred, or is substantially likely to occur. A technique by means of which a control system can maintain a well pressure is described in International Applications Nos. PCT / US10 / 38586 and PCT / US10 / 56433, and a technique by means of which a control system can maintaining a stabilizer tube pressure is described in International Application No. PCT / US11 / 31767.

The control system 86 can switch between such pressure set point modes of the well and pressure set point of the stabilizing tube 26 automatically in response to the output of step 130 indicating that an event has occurred, or is substantially likely to occur. happen For example, if an influx event (kick) is detected, the control system 86 can change from maintaining a desired pressure in the well 12 to maintaining a desired pressure in the stabilizing tube 26. This change can actually be carried out after checking that the conditions are acceptable to make the change, and after providing an operator with an option (such as, by means of a displayed alert) to initiate the change.

In another example, the control system 86 can automatically provide an operator (such as a driller) with instructions or guidance of what corrective measures to take in response to the output of step 130 indicating that an event has occurred or is substantially likely to occur. . The instructions or guidance can be provided by means of a local screen of the well site, and / or can be transmitted between the well site and a remote location, etc.

In another example, the control system 86 may implement a well control procedure automatically in response to the output of step 130 indicating that an event has occurred, or is substantially likely to occur. The well control procedure could include rotating the return flow of fluid 18 to a conventional drilling rig 82 sewer collector and gas rover 88 (see Figure 1) designed to handle well control situations.

Alternatively, the well control method could include the control system 86 automatically operating the seal collector 32 to circulate out in an optimal way an unwanted affluence. An example of automated operation of a seal collector to circulate an undesired influx is described in International Application No. PCT / US10 / 20122, filed January 5, 2010.

In another example, the control system 86 can manipulate a shutter 34 (eg, alternately open and close the shutter a certain amount, etc.) automatically in response to the output of step 130 which indicates that the shutter is capped, or it is substantially likely to be covered. The plugging event of the plug 34 can be represented by means of an event signature which, for example, includes a parameter segment indicating increase of pressure differential across the plug. Manipulating the shutter 34 automatically in response to the output of step 130 can potentially dislodge whatever is plugged or incrementally plugging the shutter.

In another example, the control system 86 can change the flow of fluid 18 from one of the shutters 34 to another of the shutters automatically in response to the output of step 130 which indicates that one of the shutters has been plugged, ruined, blocked or otherwise committed, or is substantially likely to be committed in that way.

The change from one plug 34 to another can be carried out progressively and automatically, so that a desired pressure of the well or pressure of the stabilizing tube can also be maintained by means of the control system 86 during the changeover.

The control system 86 can change the fluid flow 18 from one of the shutters 34 to another of the shutters automatically in response to the output of the passage 130 which indicates that the flow of the fluid 18 is out of, or is substantially likely to be. outside, an optimum operating range of one of the shutters. The shutters 34 may have different cut sizes, such that the shutters have different optimum ranges of operation. When the flow of the fluid 18 is outside the optimum range of operation of the shutter 34 that is being used to variably restrict flow, it may be beneficial to change the flow of another of the shutters having an optimum operating range that better suits the flow .

The control system 86 can open an additional shutter 34 automatically in response to the output of the step 130 which indicates that an operational shutter operating range is exceeded, or is substantially likely to be exceeded, by the flow of fluid 18. By increasing the number of operating shutters 34 through which the fluid 18, the flow through each obturator is reduced, so that the range of operation of each obturator is not exceeded.

In another example, the control system 86 can modify or correct a pressure set point (e.g., received from a hydraulic model) automatically in response to the output of step 130 which indicates that: a) a sensor (such as sensor 60, a pressure tool during drilling (PWD, Pressure While Drilling), etc.) has failed or is substantially likely to fail, b) the drill string 16 has been separated (eg, twisted, disconnected, reversed, etc.) inside the well or is substantially likely to do so, and / oc) an event of influx or loss has occurred or is substantially likely to occur, making it desirable to adjust the density of the fluid 18 in the well in the models, such as the hydraulic model and / or a well model. The control system 86 can operate the controller 84 using the modified / corrected setpoint, instead of the setpoint received from, eg, the hydraulic model. The control system 86 may update the hydraulics and / or model (s) of the well with revised density of the fluid 18 in the detection of the event of influx or loss of fluid.

In another example, the control system 86 can automatically communicate to the hydraulic model (s) and / or the well that an event has been detected. For example, if the event is a failure of the sensor 60 (such as a PWD sensor, etc.), the control system 86 can automatically communicate this to the hydraulic model, which will stop the correction of the pressure set point with base in the actual measurements of the sensor. As another example, if the event is the separation of the drill string 16, the control system 86 can automatically communicate this to the hydraulic model (s) and / or the well, which will adjust a volume of the ring 20 and / or other parameters in the model (s).

In another example, the control system 86 can automatically open one or more of the previously inoperative shutters 34 in response to the output of step 130 which indicates that there is excessive pressure in the well 12, or at least upstream of the shutter reader 32 A maximum pressure can be pre-programmed in the control system 86 such that, if the maximum pressure is exceeded, one or more of the shutters 34 will be opened by means of the control 84 to release the excess pressure.

In another example, the control system 86 can divert the flow to a drilling equipment seal collector. 82, or another shutter collector similar to shutter collector 32, automatically in response to the output of step 130 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 shutter (s) 34 a desired amount, in order to relieve the pressure under the RCD 22.

In another example, the control system 86 can modify a volume of the ring 20 that is used by the hydraulic model (s) and / or the well automatically in response to the output of step 130 indicating that a Floating drilling equipment is hoisting. For example, the control system 86 could receive indications of drilling equipment that is added from a conventional movement compensation system of the floating drilling equipment. The volume of the ring 20 can be modified / corrected by means of the control system 86 automatically in response to indications that the drill rig has risen or fallen, thus enabling the pressure set point of the well or stabilizer tube is updated based on the modified / corrected volume of the ring.

It can now be fully appreciated that the previous disclosure provides many benefits to the subject of Well drilling and event detection operations during drilling. The examples of method 90 described above enable the drilling events to be detected accurately and in real time, so that appropriate actions can be taken if necessary. Audio and optical inputs can be used to the event detection process to, for example, monitor drill rig activities that produce audio and / or visual signals. Audio and / or visual signals can be included in drilling parameter signatures, which are compared with the event signatures.

An example of well drilling method 90 described above may comprise detecting at least one of audio signals and optical signals; generating a parameter signature during a drilling operation, the parameter signature is based at least in part on detection; and detecting a drilling event by comparing the parameter signature with an event signature indicative of the drilling event.

The detection step may include positioning at least one audio sensor 57 proximate to at least one source of the audio signals. The source can be a drilling rig, a drill rig slurry pump 68, and / or a shutter collector 32. Any audio source, within the scope of this disclosure.

The audio sensor 57 may cise a microphone. Any other type of audio sensor may be used, within the scope of this disclosure.

A detection step may include positioning at least one optical sensor 59 proximate to at least one source of the optical signals. The source of including information equipment, a separator 48, and / or a stabilizer tube 26.

Any optical source may be used, within the scope of this disclosure. A cnent can be an optical source, even if the optical signals are simply reflected from, or transmitted through, the cnent.

The optical sensor 59 may cise a video camera and / or a photodiode. Any other type of optical sensor may be used, within the scope of this disclosure.

The piercing event may cise a beginning of a drillpipe connection, a termination of a drillpipe connection, a fluid influx, a fluid loss, and / or any of a wide variety of other events (such as , obturator plugging, tube separation, etc.). The event can 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 was also described above. In one example, the system 10 cises a control system 86 that cres a parameter signature for a drilling operation with an event signature indicative of a drilling event, the signature The parameter is based at least in part on an output of at least one sensor selected from a group cising audio and optical sensors 57, 59, and a controller 84 that controls the drilling operation in response to the drilling event indicated by at least partial coincidence between the parameter signature and the event signature.

Such at least partial coincidence may indicate that the drilling event has occurred, or that the drilling event is substantially likely to occur.

Although different examples have been described above, with each example having certain characteristics, it should be understood that it is not necessary for a particular characteristic of an example to be used exclusively with that example. Rather, any of the features described above and / or which is represented in the drawings can be combined with any of the examples, in addition to or in substitution of any of the other characteristics of those examples. The characteristics of an example are not mutually exclusive to the characteristics of another example.

Rather, the scope of this disclosure covers any combination of any of the characteristics.

Although each example described above includes a certain combination of characteristics, it should be understood that it is not necessary to use all the characteristics of an example. Rather, any of the features described above may be used, without any other characteristic or particular characteristics being used.

It should be understood that the different modalities described in this document can be used in different orientations, such as inclined, inverted, horizontal, vertical, etc., and in different configurations, without departing from the principles of this disclosure. The modalities are described only as examples of useful applications of the principles of disclosure, which is not limited to any specific detail of these modalities.

In the above description of the representative examples, the directional terms (such as "above", "below", "superior", "inferior", etc.) are used for convenience when referring to the accnying drawings. However, it should be clearly understood that the scope of this disclosure is not limited to any particular address described in this document.

The terms "including", "includes", "comprising", "comprises", and similar terms are used in a non-limiting sense in this specification. For example, if a system, method, apparatus, device, etc., is described as "including" a certain characteristic or element, the system, method, apparatus, device, etc., may include that characteristic or element, and may also include other features or elements. Similarly, the term "comprises" is considered to mean "includes, but is not limited to".

Of course, a person skilled in the art would readily appreciate, with careful consideration of the above description of the representative embodiments of the disclosure, that many modifications, additions, substitutions, omissions, and other changes can be made to the specific embodiments, and that such changes are contemplated by the principles of this disclosure. For example, structures that are disclosed as separately formed may be integrally formed, in other examples, and vice versa. Accordingly, the above detailed description should be clearly understood as being provided by way of illustration and example only, the spirit and scope of the invention being limited only by the appended claims and their equivalents.

Claims (34)

NOVELTY OF THE INVENTION Having described the present invention as above, it is considered as a novelty and, therefore, the content of the following is claimed as property: CLAIMS

1. A method of drilling wells, comprising: detecting at least one of a group comprising audio signals and optical signals; generating a parameter signature during a drilling operation, the parameter signature is based at least in part on detection; Y detect a drilling event by comparing the parameter signature with an event signature indicative of the drilling event.

2. The method according to claim 1, characterized in that the detection further comprises positioning at least one audio sensor proximate to at least one source of the audio signals.

3. The method according to claim 2, characterized in that the source comprises drilling equipment.

4. The method according to claim 2, characterized in that the source comprises a mud pump of the equipment.

5. The method according to claim 2, characterized in that the source comprises a shutter collector.

6. The method according to claim 2, characterized in that the audio sensor comprises a microphone.

7. The method according to claim 1, characterized in that the detection further comprises positioning at least one optical sensor close to at least one source of the optical signals.

8. The method according to claim 7, characterized in that the source comprises drilling equipment.

9. The method according to claim 7, characterized in that the source comprises a separator.

10. The method according to claim 7, characterized in that the source comprises a stabilizing tube.

11. The method according to claim 7, characterized in that the optical sensor comprises a video camera.

12. The method according to claim 7, characterized in that the optical sensor comprises a photodiode.

13. The method according to claim 1, characterized in that the drilling event comprises a start of a drill pipe connection.

14. The method according to claim 1, characterized in that the drilling event comprises a termination of a drill pipe connection.

15. The method according to claim 1, characterized in that the drilling event comprises an influx of fluid.

16. The method according to claim 1, characterized in that the drilling event comprises a loss of fluid.

17. A well drilling system, comprising: a control system that compares a parameter signature for a drilling operation with an event signature indicative of a drilling event, 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; Y a controller that controls the drilling operation in response to the drilling event that is indicated by at least a partial match between the parameter signature and the event signature.

18. The system according to claim 17, characterized in that said at least partial coincidence indicates that the perforation event has occurred.

19. The system according to claim 17, characterized in that said at least partial coincidence indicates that the piercing event is substantially likely to occur.

20. The system according to claim 17, characterized in that the drilling event comprises a start of a drillpipe connection.

21. The system according to claim 17, characterized in that the drilling event comprises a termination of a drill pipe connection.

22. The system according to claim 17, characterized in that the drilling event comprises an influx of fluid.

23. The system according to claim 17, characterized in that the perforation event comprises a loss of fluid.

24. The system according to claim 17, characterized in that the sensor comprises at least one audio sensor next to at least one source of audio signals.

25. The system according to claim 24, characterized in that the source comprises drilling equipment.

26. The system according to claim 24, characterized in that the source comprises a mud pump of the equipment.

27. The system according to claim 24, characterized in that the source comprises a shutter collector.

28. The system according to claim 24, characterized in that the audio sensor comprises a microphone.

29. The system according to claim 17, characterized in that the sensor comprises at least one optical sensor close to at least one source of optical signals.

30. The system according to claim 29, characterized in that the source comprises drilling equipment.

31. The system according to claim 29 characterized in that the source comprises a separator.

32. The system according to claim 29, characterized in that the source comprises a stabilizing tube.

33. The system according to claim 29, characterized in that the optical sensor comprises a video camera.

34. The system according to claim 29, characterized in that the optical sensor comprises a photodiode.