Patent Application
20170204705
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.
The cost of wellbore construction, in particular marine drilling operations has risen substantially in recent years. Some well construction operations conducted in deep ocean water (water depth in excess of 3000 to 5000 feet) may now cost in excess of $1,000,000 per day. Land based drilling costs in excess of $50,000/day are common. These costs are driving the need for increased efficiency. The need for increased efficiency drives the need for measurement techniques to accurately determine the time used to perform well construction operations, both during active drilling (lengthening the wellbore) and auxiliary operations. Accurately measuring the time of specific activities allows review and improvement of drilling unit and operating personnel efficiency. Such improvement can result in reducing activity time and thus the cost.
Generally, when describing drilling rig operations and their related efficiency, what is meant is 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”.
Automatic measurement technology has allowed for drilling times to be calculated automatically using sensors and algorithm software to determine the drilling unit's state of operation. Examples of this automated technology are described in U.S. Pat. Nos. 6,892,812 and 6,820,702. These patents are primarily related to the automatic detection and measurement of times when the drilling unit is within “drilling times” operation, i.e., primarily using the unit's drilling equipment such as the draw works, rotary, mud pumps and tubulars. However the 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” 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. Pat. 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.
Methods and apparatus for measuring non-drilling time will be explained below with reference to specific embodiments. The described embodiments are only intended to provide the reader with examples of automatic time recording apparatus and methods for purposes of implementing methods according to the present disclosure and such apparatus and methods should in no way be considered as limiting the scope of the present disclosure.
Methods and measurement apparatus will be described below first with reference to certain types of “bottom supported” mobile offshore drilling units. Later examples will be described in terms of mobile offshore drilling units that include a floating structure or platform that supports a drilling rig and associated equipment. Accordingly, it is to be clearly understood that the scope of the present disclosure is not limited to particular types of drilling units. The principles of the disclosure are equally applicable to any type of drilling unit that is movable from one drilling location to another, including “platform” rigs (rigs that are disposed on a fixed-position, water bottom supported structure) and requires certain acts to be performed to prepare the unit for drilling and for moving to a different drilling location. The principles of this disclosure are equally applicable to drilling units deployed on the land surface; accordingly, the scope of the disclosure is not intended in any way to be limited to marine drilling units. For purposes of land based drilling units, normalization of certain performance measurements may be made with respect to depth of a wellbore; reference to normalization for water depth (as well as wellbore depth) would be applicable to marine drilling units.
An example bottom supported mobile offshore drilling unit is shown in
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. When 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.
When the selected air gap 22 is obtained, 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 14A. Other examples of a cantilever may use a pinhole/hydraulic skidding unit in contact with the cantilever skid rack 14A. 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.
In the present example, 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. The parameters measured by the various sensors described herein may be characterized as being related to the beginning and the end of one or more non-drilling operations or “auxiliary operations.” As used in the present description, the term “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. The above examples of jacking the legs 12 until the selected air gap 22 is obtained, as well as skidding the cantilever 14 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.
As an example, 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. Although in the present example 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. 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. Pat. No. 6,892,812 issued to Niedermayr et al. As shown in
Having described an example drilling unit and examples of sensors for measuring parameters related to start and stop times of non-drilling operations, a more complete description of an example method using measurements from such sensors to characterize and display elapsed times for such operations will now be explained.
For a jackup drilling unit such as shown in
Of the above listed 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:
In the present example, the various sensors described with reference to
An example of elapsed time recording and characterization within the DAQ 33 is shown in a flow chart in
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. 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
When the skid motor current is detected as having been switched on, at 66, 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.
At 70, current for a motor used to operate the drawworks (26 in
In the present example, 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. 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
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
The system operator may use the displayed times to evaluate a number of different performance criteria. For example, 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.
Having explained an example of a method according to the disclosure used on a bottom supported drilling unit (jackup), an example implementation of a method according to the disclosure on a floating drilling structure follows.
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.
Another measurement associated with a floating drilling unit is the AHV switching/hookup & tensioning efficiency. 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.
Other examples of floating drilling platform procedures and time interval measurements may be found in the table below.
An example floating mobile offshore drilling unit is shown in
In the example shown in
Although not shown separately in
It is also within the scope of the present invention to measure start and stop times of certain activities related to completion of a wellbore. “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. Examples of completion related actions and their corresponding time intervals may include the following:
It should be clearly understood that the present disclosure is not limited to the particular procedures and time intervals in the above examples. The above examples are meant only to illustrate the principle of such methods and how methods according to the present disclosure may be used to improve the efficiency with which a drilling unit operates, particularly as such efficiency relates to non-drilling operations.
Although there are a plurality of different auxiliary operation (non-drilling) times as described in U.S. Pat. No. 7,886,845 B2, for purposes of the present disclosure, 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). These time segments may be referred to as Major Key Performance Indicators (MKPI) and a substantial portion of a drilling unit's total non-drilling times may be measured using only a relatively small number of (about ten) MKPIs. For example, on a floating drilling platform some of the MKPIs are listed below in Table 5. Later it will be shows that MKPIs may have significant Key Performance Indicator (KPI) sub-sections.
For example, 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
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. In order to obtain valid comparisons, 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.
In one embodiment, 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. By eliminating the components of MKPIs related to well depth or water depth, 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
It will be necessary to be able to automatically measure the start and stop times of any MKPI. There are several systems known in the art that may provide modified MKPI start and stop times. One such system is described in U.S. Pat. No. 6,892,812 and is sold under the trademark PRONOVA, which is a registered trademark of TDE Thonhauser Data Engineering GmbH, Leoben, Austria. Similar data may also be available from systems sold by Pason, USA, Inc. or National Oilwell Varco which are in common use in the industry. In each of the foregoing example systems, 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 may be used and the data recording unit may be programmed to determine automatically which activity is being undertaken at any time using the sensor measurements. An example of the foregoing is described in the '812 patent cited above. Other systems may be substantially as explained with reference to
In one example embodiment, and referring to
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
Some 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. In one embodiment, 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
Accurately measuring the activity time in the well construction process is important. 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
In some embodiments, 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. For example, the KPIs identified with an asterisk in
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.
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.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/US2015/042763 | 7/30/2015 | WO | 00 |
| Number | Date | Country | |
|---|---|---|---|
| 62031920 | Aug 2014 | US |
