EP3175081A1 - Procédé et système de mesure de temps excluant le forage et leur application en vue d'améliorer l'efficacité d'une installation de forage - Google Patents

Procédé et système de mesure de temps excluant le forage et leur application en vue d'améliorer l'efficacité d'une installation de forage

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Publication number
EP3175081A1
EP3175081A1 EP15826823.5A EP15826823A EP3175081A1 EP 3175081 A1 EP3175081 A1 EP 3175081A1 EP 15826823 A EP15826823 A EP 15826823A EP 3175081 A1 EP3175081 A1 EP 3175081A1
Authority
EP
European Patent Office
Prior art keywords
drilling
time
activity
well
elapsed time
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Withdrawn
Application number
EP15826823.5A
Other languages
German (de)
English (en)
Other versions
EP3175081A4 (fr
Inventor
Charles H. King
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Nexen Data Solutions Inc
Original Assignee
Nexen Data Solutions Inc
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Nexen Data Solutions Inc filed Critical Nexen Data Solutions Inc
Publication of EP3175081A1 publication Critical patent/EP3175081A1/fr
Publication of EP3175081A4 publication Critical patent/EP3175081A4/fr
Withdrawn legal-status Critical Current

Links

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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
    • G—PHYSICS
    • G07—CHECKING-DEVICES
    • G07C—TIME OR ATTENDANCE REGISTERS; REGISTERING OR INDICATING THE WORKING OF MACHINES; GENERATING RANDOM NUMBERS; VOTING OR LOTTERY APPARATUS; ARRANGEMENTS, SYSTEMS OR APPARATUS FOR CHECKING NOT PROVIDED FOR ELSEWHERE
    • G07C3/00—Registering or indicating the condition or the working of machines or other apparatus, other than vehicles
    • G07C3/02—Registering or indicating working or idle time only
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/02—Surface sealing or packing
    • E21B33/03—Well heads; Setting-up thereof
    • E21B33/06—Blow-out preventers, i.e. apparatus closing around a drill pipe, e.g. annular blow-out preventers
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
    • E21B33/14—Methods or devices for cementing, for plugging holes, crevices or the like for cementing casings into boreholes
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
    • E21B41/0007—Equipment or details not covered by groups E21B15/00 - E21B40/00 for underwater installations
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B15/00—Supports for the drilling machine, e.g. derricks or masts
    • E21B15/003—Supports for the drilling machine, e.g. derricks or masts adapted to be moved on their substructure, e.g. with skidding means; adapted to drill a plurality of wells
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B15/00—Supports for the drilling machine, e.g. derricks or masts
    • E21B15/02—Supports for the drilling machine, e.g. derricks or masts specially adapted for underwater drilling

Definitions

  • This disclosure is related to the field of subsurface well construction. More specifically, the disclosure relates to methods for measuring times of specific well construction activities to evaluate performance of individual drilling units and/or operating personnel in comparison to other drilling units and personnel.
  • drilling times the time spent with the bit on bottom while drilling/sliding, tubular tripping times, conditioning the hole and responding to downhole conditions. Efforts are often focused on measuring and improving these operations with efficiency efforts. For convenience these will be referred to as "drilling times”.
  • drilling unit also undergoes "non- drilling times" such as mooring/jacking up, preloading/ballasting, skidding drilling package, nippling up/testing blowout preventer equipment (BOPE), running/testing riser and choke and kill lines (C&K), installing slip joint/diverter, rigging up to cement/run casing, among other non-drilling operations.
  • “non- drilling times” such as mooring/jacking up, preloading/ballasting, skidding drilling package, nippling up/testing blowout preventer equipment (BOPE), running/testing riser and choke and kill lines (C&K), installing slip joint/diverter, rigging up to cement/run casing, among other non-drilling operations.
  • Non-drilling times have proven more difficult to measure because of relatively unavailable sensors/automatic detection technology to facilitate measurement. The lack of easily identified and measured "start/stop" points of a function hampers measurement of non-drilling times.
  • U.S. Patent No. 7,886,845 B2 issued to King et al. describes a method that identifies these "non-drilling times” or “auxiliary times”, and detects, measures, and records their duration. The described method requires the use of additional sensors and a recording device to gather and display the sensor readings.
  • FIG. 1 shows an example mobile drilling unit and placement of sensors on the unit that are used in connection with a system and method according to the disclosure.
  • FIG. 2 shows an example time recoding sequence for various drilling unit operations.
  • FIG. 3 shows an example data display of recorded times according to an example data recording sequence.
  • FIG. 4 shows an example of a floating mobile drilling unit that may be used with other examples of a system and method according to the disclosure.
  • FIG. 5 shows a table of MKPI broken down into KPI subsections.
  • FIG. 6 shows a table of normalized activity times.
  • FIG. 7 shows a measurement sequencer logic table. Detailed Description
  • FIG. 1 An example bottom supported mobile offshore drilling unit is shown in FIG. 1 at 10.
  • the drilling unit 10 in the present example is called a "jackup" drilling unit.
  • Such drilling units are supported by the water bottom 20 by legs 12 that can be moved along their longitudinal direction with respect to a hull 16 of the drilling unit 10 by operating jacking motors 12B.
  • the jacking motors 12B may each turn a respective gear unit (not shown) the output of which is in contact with a rack 12A or similar linear gear-toothed structure on each leg 12.
  • Other types of jackup drilling units may use a pinhole/hydraulic jacking system to move the legs, for example.
  • the legs 12 may each include a "spud can" 12C at a bottom end thereof for contacting the water bottom 20 and supporting the weight of the drilling unit 10.
  • the hull 16 floats and is moved in to the selected location by tug boats or similar towing vessels as the legs 12 are maintained substantially in their uppermost position with respect to the hull 16.
  • the hull 16 When the drilling unit 10 is disposed at the selected location, the hull 16 is positioned both geodetically and with the hull 16 in a preferred geodetic orientation.
  • the legs 12 are moved longitudinally (called “jacking") using the jacking motors 12B (or hydraulic motors in hydraulically jacked leg examples). Downward movement of the legs 12 with respect to the hull 16 eventually causes the spud cans 12C to contact the water bottom 20.
  • the spud cans 12C contact the water bottom 20, continued jacking of the legs 12 causes the hull 16 to move upwardly out of the water.
  • the jacking continues until the hull 16 is positioned at a selected height ("air gap") 22 above the mean water surface 18.
  • a cantilever structure (“cantilever") 14 may be laterally displaced from its transport position (generally entirely over the hull 16). Such lateral displacement, called “skidding out” the cantilever 14, may be performed by a cantilever skid motor 14B that rotates a gear (not shown) in contact with a cantilever skid rack 14 A.
  • a cantilever may use a pinhole/hydraulic skidding unit in contact with the cantilever skid rack 14 A. The skidding out continues until a drilling rig 29, supported generally near the outward end of the cantilever 14, is positioned over a proposed well location 31 on the water bottom 20.
  • the drilling rig 29 may include pipe lifting, supporting and rotating devices familiar to those skilled in the art, for example, a derrick 24 in which is included a tubular or pipe rack 32 to vertically support assembled "stands" of tubulars 34 used in wellbore drilling, testing and completion operations.
  • the rig 29 may include a winch called a drawworks 26 that spools and unspools wire rope or cable, called “drill line" 27, for raising and lowering a traveling block and hook 28.
  • the hook 28 may support a top drive 30 or similar device for applying rotational energy to the pipe for various drilling and well completion operations.
  • sensors may be associated with some of the foregoing drilling unit components to measure one or more parameters used in various aspects of methods according to the present disclosure.
  • auxiliary operations is intended to mean any function or operation on the drilling unit 10 that is not related to equipment or devices being inserted into or removed from a wellbore (including the active drilling of such wellbore), but is nonetheless essential to enabling the drilling unit 10 to perform intended drilling operations.
  • auxiliary operations are two of such auxiliary operations.
  • Other examples of auxiliary operations and their use in methods according to the present disclosure will be further explained below.
  • each jacking motor 12B may include a sensor and an associated wireless data transceiver (shown at 11 collectively) for measuring electric current drawn by the respective jacking motor 12B.
  • a similar wireless transceiver/sensor combination 11 may be associated with the cantilever skid motor 14B.
  • a transponder such as an acoustic or laser range finder, or a global positioning system receiver, shown at 36, may be disposed proximate a bottom surface of the hull 16 in order to measure the air gap 22.
  • Such sensor 36 may also include an associated wireless transceiver 11.
  • a data acquisition system (“DAQ") 33 may be disposed at a convenient position on the drilling unit 10 and include a wireless transceiver 11A for receiving data from the various sensors, such as those described above.
  • the various sensors include wireless transceivers 11 to communicate with the DAQ 33, it should be clearly understood that “wired” sensors may also be used in accordance with the disclosure.
  • the drilling rig 29 may also include sensors for measuring various parameters related to operation of the drilling rig 29.
  • sensors for measuring various parameters related to operation of the drilling rig 29 An example of such sensors and methods for validating and interpreting the measurements made by the rig sensors to automatically determine what drilling unit operation is underway at any time are described in U.S. Patent No. 6,892,812 issued to Niedermayr et al.
  • one such sensor is may be a load cell 27A arranged to determine the total axial force (weight) supported by the drilling unit 29.
  • the load cell 27 A may be coupled wirelessly through a transceiver 1 1 to the DAQ 33.
  • Such load cell is generally known in the art as a "weight indicator.”
  • Another sensor may be a pressure/volume sensor 126 associated with pumps (not shown) configured to move fluid through appropriate rotary seals in the top drive 30 and into any pipe coupled to the top drive, such as a drill string or casing.
  • the pressure/volume sensor 126 may include a pressure transducer (not shown separately) and a device known in the art as a "stroke counter” or similar device that measures a parameter related to the volume displacement of pistons within cylinders in a "mud pump.”
  • the pressure volume sensor 126 may also be wirelessly coupled to the DAQ 33.
  • the weight indicator (load cell 27 A) and the pressure/volume sensor 126 may be used to make measurements related to the start and stop times of various operations as will be described below in more detail.
  • non-drilling operations performed prior to starting drilling of a wellbore are typically performed in a certain sequence.
  • An example of such a sequence would include the following.
  • Drilling unit is moved to selected location.
  • Drilling location is surveyed for positional accuracy and for presence of subsurface and water bottom hazards.
  • Hull is moved to five foot (1.6 meter) air gap.
  • the cantilever is skidded to its selected lateral position. Drilling fluid, air and hydraulic hoses, and electrical cable are connected between the drilling rig and equipment disposed in the hull.
  • Ropes are installed and equipment disposed on a supply vessel is unloaded.
  • auxiliary operations certain ones may be described as “critical path” operations because they must be performed in a particular sequence in order for the drilling unit 10 to be capable of commencing drilling operations.
  • the other auxiliary operations may be referred to as “off critical path” because they may be done concurrently with certain other operations (auxiliary and/or drilling) and/or out of sequence to some extent.
  • the critical path and off critical path operations from the above example, and additional off critical path operations typically performed during set up of the drilling unit may include the following:
  • the various sensors described with reference to FIG. 1 may be interrogated at selected intervals automatically by the DAQ (33in FIG. 1).
  • the DAQ 33 may include a programmable microprocessor (not shown separately) or similar programmable computing device capable of executing program instructions.
  • the program instructions may be preloaded onto the processor or may be stored in a computer readable medium for loading at the system operator's convenience.
  • FIG. 2 An example of elapsed time recording and characterization within the DAQ 33 is shown in a flow chart in FIG. 2.
  • the DAQ 33 may be initialized.
  • current drawn by the jacking motors (12B in FIG. 1) is measured, using sensors as explained above.
  • the DAQ 33 may be programmed to begin recording time when the motor current increases over an amount associated with the legs moving through the water, as shown at 52. Such current amount may be associated with the legs (12 in FIG. 1) contacting the water bottom (20 in FIG. 1) so as to begin lifting the hull (16 in FIG. 1).
  • the recording time may be stopped when the jacking motor current returns to zero, at 54.
  • the elapsed time measured between the above start and stop times may be characterized as the amount of time performing the "jack to initial air gap" critical path operation, as shown at 51.
  • the DAQ 33 may be programmed to query the various sensors on the drilling unit, and determine a start time for pumping preload from the measurements made by certain of the sensors. For example, a pump used to pump preload (not shown in the figures) may have its current measured. When the pump current is switched on as measured by the associated sensor, the DAQ 33 may be programmed to begin recording elapsed time, as shown at 56. When the pump current is switched off, recording of elapsed time may stop, as shown at 58. Elapsed time recorded by the DAQ 33 may be characterized as the "pump preload" critical path operation, as shown at 53.
  • a valve (not shown) used to dump preload may include a position sensor to determine when the valve is open or closed.
  • the DAQ 33 may be programmed to start recording time, at 58, when the preload valve is opened.
  • the recording may be stopped, at 60, when the jacking motor current is greater than zero, shown at 62, indicating that the preload has been dumped sufficiently to enable jacking the hull to the final air gap.
  • the foregoing elapsed time may be characterized as the "dump preload" critical path operation, as shown at 55.
  • the DAQ 33 Concurrently with the stop time of the "dump preload” operation, the DAQ 33 may be programmed to initialize elapsed time for the "jack to final air gap” operation when the jacking motor current is switched on.
  • the stop time of the jack to final air gap operation may be triggered in the DAQ 33 by, for example, when the jacking motor current is switched off, or when the sensor (36 in FIG. 1) detects that the selected air gap has been obtained.
  • the DAQ 33 may be programmed to begin recording elapsed time. The recording may be stopped when the skid motor current is switched off, at 68.
  • the recorded elapsed time, at 59 may be characterized in the DAQ 33 as for the "skid out cantilever" operation, at 59.
  • the DAQ 33 may begin recording elapsed time. Recording may be stopped when a first hammer strike is detected. Such strike detection may be obtained by measuring, for example, air or hydraulic pressure used to operate various components on the rig (29 in FIG. 1) or by including a vibration sensor (not shown) in the pneumatic or hydraulic power unit of the hammer. The recorded elapsed time may be characterized in the DAQ 33 as the operation "pick up hammer" at 61.
  • the DAQ 33 may be programmed to begin recording elapsed time until, for example, drawworks motor current measurements or hookload indications correspond to having laid the hammer down out of the rig, as shown at 74.
  • the elapsed time may be characterized in the DAQ 33 as the operation "run drive pipe.”
  • the DAQ 33 may be programmed so that notwithstanding measurements made by the various sensors as being indicative of a start or stop time of a particular operation, the determined start and stop times of certain auxiliary operations must take place in a predefined sequence.
  • the DAQ 33 By programming the DAQ 33 to determine start times and stop times of certain events in a predefined sequence, and thus to record elapsed times in a predefined sequence, the possibility of false time recording (time allocated to an operation not consistent with the actual operation underway) will be reduced.
  • An example of such a predefined sequence includes the events shown in their respective order in Table 1. Sensor measurements made by the various sensors may be used to determine start time of a particular operation only when all prior operations in the predefined sequence have been determined to be completed.
  • the time recording programming instructions for the DAQ 33 may also include recording elapsed time between the end or stop time of one of the above operations and the start time (where not concurrent therewith) of the succeeding operation in the predefined sequence. Such times are shown in FIG. 2 as "hidden times" 65, and in some cases such hidden times may be associated with activities on the drilling unit that require human activity or require intervention by personnel on the drilling unit.
  • the hidden times 65 each may be further characterized with respect to the two operations that are adjacent thereto in the drilling unit set up sequence (the predefined sequence for programming the DAQ 33).
  • Time recordings made and characterized as explained above may be displayed in various formats for evaluation by the system operator.
  • the time recording display may be made on any suitable computer display, including a cathode ray tube or liquid crystal display, a printer, or any similar display device.
  • An example display format is shown in FIG. 3.
  • the upper bar graph in FIG. 3 may represent elapsed times recorded for various operations described above.
  • the size of each bar 80 may represent time for each of the operations (1 through 6) on the coordinate axis of the graph.
  • the hidden times between successive operations may be displayed on the same or a different graph. In FIG. 3, the hidden times are shown at 65.
  • the upper bar graph may represent, for example, operations conducted on a first well in a particular operating area.
  • a lower graph in FIG. 3 may represent corresponding operations for a different well in the same or a different operating area.
  • the operating times are shown at 80A and the hidden times are shown at 65A in FIG. 3 for such subsequent well.
  • the system operator may use the displayed times to evaluate a number of different performance criteria.
  • the hidden times may be used to evaluate the efficiency of different personnel on the drilling unit.
  • the operating times may be used to evaluate whether the equipment associated with each particular operation is functioning properly, and/or whether the particular personnel operating such equipment are doing so correctly and/or efficiently.
  • One procedure on a floating drilling structure is "Mooring/Anchoring up.” Such procedure includes deployment of mooring lines to a device that fixes their position with respect to the water bottom so that the floating drilling structure will remain substantially fixed during drilling operations. Measurements made for such time interval includes the time to moor up each individual mooring line and the efficiency of each of the Anchor Handling Vessels ("AHV"). Such time interval may be measured, for example, beginning when an AHV begins to pull on is respective mooring line.
  • a record of the tension exerted on a tension measuring device associated with the mooring line maybe used to start and stop recording the mooring line deployment time.
  • the time period may end when the AHV releases the mooring, and tension is released as indicated by the mooring line tension indicator.
  • the time interval measured may be that needed for the AHV to reposition and rig up onto another mooring. Such time period may begin when the mooring tension is released from the previous mooring, as indicated by the tension indicator. The time period may end when tensioning begins on the subsequent mooring as indicated by the tension indicator. A total time for setting and testing all anchors may be recorded from the above time periods.
  • the time required to tension the moorings to the required tension after setting all moorings may also be recorded. Such time may be the sum of the individual mooring line times as explained above, the switching/hookup times and bringing moorings to final required tensions. Such time interval may begin when the AHV begins to tension the first mooring and may end when final tensions on all moorings are completed.
  • Another time interval that may be measured includes an AHV retrieval wire line speed. Such interval may includes the time required to retrieve the AHVs retrieval wire after setting the anchor so as to begin the next anchor deployment and setting. The interval may begin when the anchor is on bottom and the floating drilling platform begins to tension up on the mooring line. The interval may end when the AHV is connected to subsequent mooring and begins apply tension on the next mooring as indicated by the mooring tensioning device. [0039] Other examples of floating drilling platform procedures and time interval measurements may be found in the table below.
  • FIG. 4 An example floating mobile offshore drilling unit is shown in FIG. 4 at 10A.
  • the unit 10A shown in FIG. 4 is known as a "semisubmersible" drilling unit. The following description is equally applicable to other types of floating drilling units, such as drill ships.
  • the unit 10A includes a drilling deck 90 that may be supported above the surface of the water 18 by floatation devices such as pontoons 92.
  • the drilling deck 90 is coupled to the pontoons 92 by columns 91 such that when the pontoons 92 are submerged to a selected depth below the water surface 18, the drilling deck is supported at a selected height above the water surface 18.
  • the mooring system includes winches 104 that retrievably deploy mooring lines 106 through fairleads 103 to anchors 108 fixed on the water bottom 20.
  • the winches 104 may each include a motor current sensor, hydraulic pressure sensor or other device, shown generally at 111, that detects operation of the respective winches 104. Output from the winch sensors 111 may be wirelessly (see 11) communicated to the DAQ (see 33 in FIG. 1).
  • the drilling deck 90 may support a drilling rig 29.
  • the drilling rig 29 may be configured substantially as explained with reference to FIG. 1. For purposes of the invention, sensors and equipment associated with the drilling rig 29 will be substantially the same irrespective of whether the drilling unit is a floating structure as in FIG. 4, or is a bottom supported structure as shown in FIG. 1.
  • Floating drilling units typically provide that a marine riser 94 is coupled between the unit 10A and a subsea BOP stack 100.
  • the BOP stack is typically coupled to the upper end of a surface casing 102 placed in the well immediately below the water bottom 20.
  • Various operations related to assembling the marine riser 94 and BOP 100, including testing choke and kill lines 96 and multiplex cables 98 are explained above.
  • Testing the BOP 100 is typically performed on a suitable fixture (called a "stump"- not shown) disposed on the drilling deck 90.
  • the drilling rig 29 in FIG. 4 may include similar equipment and sensors as the drilling rig shown in FIG. 1. Accordingly, certain operations for which start and stop times make use of measurements made by the various sensors associated with the drilling rig 29 are equally applicable to both the bottom supported drilling unit shown in FIG. 1 and the floating drilling unit shown in FIG. 4.
  • completion of a wellbore is generally understood to mean placing a pipe or casing in the well and installing particular equipment used to move fluids, or assist in such motion, from within a subsurface Earth formation to the Earth's surface.
  • completion related actions and their corresponding time intervals may include the following:
  • auxiliary operation (non-drilling) times as described in U.S. Patent No. 7,886,845 B2
  • most of a drilling unit's non-drilling times may be categorized into segments generally centered around and just after running casing and/or liner (casing being a conduit extending from a selected depth in the well to the well surface; liner being a conduit extending from a selected depth in the well to the bottom of a previously installed casing).
  • MKPI Major Key Performance Indicators
  • KPI Key Performance Indicator
  • the MKPI "Drill, Log, Run Surface Casing, Run and Test Blowout Preventer Equipment may be separated into KPI sub sections as shown in the table in FIG. 5.
  • Each measured MKPI time cannot be compared to the corresponding MKPI on other drilling units or with other operating personnel on the same drilling unit without further processing the measured MKPI times according to the present disclosure.
  • Such inability to compare raw measured MKPI times is due to the fact that the elapsed time of each MKPI includes well depth or water depth related KPIs such as running casing, riser, and drill pipe.
  • the MKPI times may be modified (normalized) to adjust for water or well depth related elapsed time. This adjustment will enable the same modified MKPI time to be measured and compared the corresponding MKPI time for different drilling units and/or drilling personnel ("drilling crews") on the same drilling unit.
  • the adjustment to the raw measured MKPI times may be performed by eliminating MKPI sub sections (e.g., KPIs) that pertain to water depth, well depth or depth-dependent operation times such as tripping pipe, running riser and cementing.
  • MKPI sub sections e.g., KPIs
  • KPIs water depth
  • depth-dependent operation times such as tripping pipe, running riser and cementing.
  • different drilling crews and/or different drilling units' non-drilling operations may be compared on an equal basis as the modified measured time segments now allow comparison of identical drilling unit activities. This is a fast and inexpensive way to measure non-drilling times as there is no need for additional sensors and recording devices.
  • the drilling unit's existing sensors and recorders e.g., the DAQ 33 in FIG. 2 may be used to record the modified MKPIs.
  • measurements made by various sensors ordinarily disposed on the drilling unit for measuring e.g., hookload, top drive elevation, mud pump flow rate and/or pressure, tubular rotation speed
  • the data recording unit may be programmed to determine automatically which activity is being undertaken at any time using the sensor measurements.
  • KPIs may comprise the MKPI "Log, Run Surface Casing, Run and Test Blowout Preventer" (MKPI number 7 in Table 5). Those KPIs identified with an asterisk in FIG. 6 depend on water depth and on well depth. Such KPIs may be omitted from the total measured time of the MKPI.
  • a comparison of elapsed times for the same MKPI between different drilling units or between different drilling crews on the same drilling unit may be made on equal bases as elapsed times related to well depth and water depth in each non-drilling operation are eliminated from the total time measured.
  • Measuring such depth-normalized non-drilling times may provide a benchmark of a particular drilling unit's or drilling crew's operating efficiency. Normalized MKPI times may be compared with the same normalized MKPIs of other drilling units or drilling crews for efficiency comparison.
  • the DAQ (33 in FIG. 1) may be programmed to compare measured MKPI elapsed times between different drilling crews on the same drilling unit and record and/or display the comparison in any convenient form.
  • the DAQ (33 in FIG. 1) may receive data communicated from other drilling units to compare corresponding MKPIs and to record and/or display the comparison results.
  • drilling units are equipped with two separate hoisting units and tubular lifting and rotating equipment, e.g., top drives (called “dual activity” drilling units).
  • Such drilling units may provide "off line” (meaning the hoisting and rotation system used to drill the well is not used for tubular assembly/disassembly) drilling/casing stand make up capabilities that have been shown to provide increased efficiency in non-drilling activities.
  • the advantages of such drilling units' capabilities have been difficult to measure in the past, but could be easily measured and compared using a method according to the present disclosure.
  • each lifting and rotating equipment arrangement's non-drilling times may be measured and recorded so to be able to easily compare non-drilling MKPIs between different "dual activity" drilling units.
  • the MKPI times may contain considerable non-drilling time as it would contain many sub section KPIs as those shown without an asterisk in FIG. 6. However, if additional "drill down" into the sub section of a MKPI is needed for further efficiency improvements then the process described in U.S. Patent No. 7,886,845 B2, for example, may be used.
  • Well data such as casing sizes and casing shoe depths along with hole (drill bit) sizes may be entered into the well program operating logic (e.g., in the DAQ 33 in FIG. 1) as input parameters. Additionally it is possible to include logic into the program that would track the well construction progress.
  • An example of such logic for a jack up rig is shown in FIG. 7.
  • the logic algorithm may be configured to anticipate successive actions in constructing the well and thus may be programmed to interrogate the proper sensors for each such action.
  • a data recording sequencer may be programmed to measure elapsed time for both drilling operations and non-drilling (auxiliary) operations described above with reference to FIGS. 1 through 4.
  • the data recoding sequencer described herein may be modified to use sensor measurements related to drilling activity as well as non-drilling (auxiliary) activity.
  • auxiliary activity auxiliary activity
  • the system is configured, it is within the scope of the present disclosure to record non-drilling activity in a predetermined sequence, and to generate a record of the non-drilling activity times specifically unrelated to water depth or well depth as explained with reference to FIG. 6.
  • all the recorded non-drilling activity times may be normalized by dividing the measured non-drilling activity times by the well depth or the water depth, whichever is related to the particular non-drilling activity time being recorded.
  • the KPIs identified with an asterisk in FIG. 6 may have their measured elapsed time divided by the well depth or water depth existing at the time the KPI elapsed times are measured. Either non-evaluation of the depth related non-drilling activity times or dividing by the well depth or water depth may be considered forms of normalizing the measured non-drilling activity times for the relevant depth.
  • a method according to the present disclosure may provide a quick and effective method for measuring gross non-drilling times and as such, may provide a method for improving efficiency in drilling unit non-drilling times.
  • a drilling unit using a system and methods according to the various aspects of the disclosure may provide improved efficiency with respect to auxiliary operations than drilling units that do not use such system and methods.
  • a system and methods according to the invention may provide operators of such drilling units with diagnostic capability to determine sources of inefficiency in auxiliary operations and suggest corrective action or actions to improve efficiency. 8] While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.

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Abstract

La présente invention concerne un procédé de mesure de temps excluant le forage lors d'opérations de construction de puits, ledit procédé consistant à déterminer automatiquement un temps de départ et un temps d'arrêt d'au moins une activité excluant le forage. Un temps écoulé entre le temps de départ et le temps d'arrêt de l'activité est enregistré. Le temps enregistré est normalisé pour une profondeur de puits et/ou une profondeur d'eau.
EP15826823.5A 2014-08-01 2015-07-30 Procédé et système de mesure de temps excluant le forage et leur application en vue d'améliorer l'efficacité d'une installation de forage Withdrawn EP3175081A4 (fr)

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US201462031920P 2014-08-01 2014-08-01
PCT/US2015/042763 WO2016019077A1 (fr) 2014-08-01 2015-07-30 Procédé et système de mesure de temps excluant le forage et leur application en vue d'améliorer l'efficacité d'une installation de forage

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WO2016209230A1 (fr) * 2015-06-25 2016-12-29 Tde Petroleum Data Solutions, Inc. Procédé permettant une évaluation standardisée de la performance d'une unité de forage
US10387023B2 (en) * 2015-08-25 2019-08-20 Ensco Services Limited Going on location feasibility
EP3698177B1 (fr) * 2017-10-20 2023-09-27 National Oilwell Varco, L.P. Procédé d'optimisation des performances d'un système de commande automatisé destiné au forage
IT201900001761A1 (fr) * 2019-02-07 2019-02-07
US11066902B2 (en) 2019-05-16 2021-07-20 Caterpillar Inc. Power management system for a drilling rig
WO2020242907A1 (fr) * 2019-05-24 2020-12-03 National Oilwell Varco. L.P. Système et procédé de surveillance de site de forage
US11255142B2 (en) 2019-08-13 2022-02-22 Noetic Technologies Inc. Systems and methods for detecting steps in tubular connection processes
US11466559B2 (en) 2020-07-31 2022-10-11 Baker Hughes Oilfield Operations Llc Downhole tool sensor arrangements and associated methods and systems

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WO1999000575A2 (fr) * 1997-06-27 1999-01-07 Baker Hughes Incorporated Dispositifs de forage munis de capteurs permettant de mesurer les proprietes des boues de forage en fond de puits
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US7886845B2 (en) * 2007-05-25 2011-02-15 Nexen Data Solutions, Inc. Method and system for monitoring auxiliary operations on mobile drilling units and their application to improving drilling unit efficiency
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US20170204705A1 (en) 2017-07-20
MX2017001447A (es) 2017-10-20

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