JP2002155694A - Method and system for predicting performance of drilling system in fixed formation - Google Patents

Abstract

PROBLEM TO BE SOLVED: To provide a method and a system for predicting the performance of a drilling system for drilling a drill hole in a fixed formation more simply and more accurately by generating the geology characteristics of the formation per unit depth and outputting a signal displaying the generation. SOLUTION: The method contains a step for generating the geology characteristics of the formation per unit depth according to a prescribed geology model, a step for obtaining specifications of proposed drilling equipment for use in the drilling of the drill hole and a step for determining a predicted drilling mechanics in response to the specifications of the proposed drilling equipment as a function of the geology characteristics per unit depth according to the prescribed drilling mechanics model. A controller controls a parameter during the drilling of the drill hole in response to the predicted drilling mechanics. The geology characteristics contain at least rock strength. The specifications contain at least one bit specifications of a recommended drill bit. The predicted drilling mechanics comprise at least one of bit wear, mechanical efficiency, power and operating parameters.

Description

DETAILED DESCRIPTION OF THE INVENTION

[0001]

BACKGROUND OF THE INVENTION This application is hereby incorporated by reference.
No. 720, which is a continuation-in-part of US patent application Ser. No. 08 / 621,411, filed Mar. 25, 1996.
U.S. Patent No. 09/04, filed March 26, 998
This is a continuation-in-part of U.S. patent application Ser. No. 09 / 192,389, filed Nov. 13, 1998, which is a continuation-in-part of U.S. Pat. The pending applications and issued patents are hereby incorporated by reference in their entirety.

[0002] The present invention relates to drilling of the ground.
It relates to operations, and more particularly to a method and system apparatus for predicting the performance of a drilling system for a given formation.

[0003]

As you know, from the very beginning of the oil and gas well drilling industry, one of the biggest challenges is to figure out what is going on in the downhole. It was the fact that it was impossible to see. There are any number of downhole conditions and / or events that can be very important in deciding how to proceed with the operation. It goes without saying that all methods of attempting to analyze the condition and / or occurrence of such underground holes are indirect. Because it ’s that much
All of them are by no means ideal, and there is a constant effort in the industry to develop simpler and / or more accurate methods.

[0004] In general, the approach to the technology has been to focus on the condition or event of a particular downhole and develop a direction to analyze and test that particular condition or event. For example, U.S. Pat. No. 5,305,836 discloses a method in which the wear of a bit currently in use can be modeled electronically based on the lithology of the hole being drilled with the bit. This helps the drill operator determine when to change bits.

[0005]

The process of determining which type of bit should be used in a given portion of a given formation is traditionally, at best, very rough and general considerations. Only on the basis of what is worse, it is done by skill and speculation rather than science.

[0006] Other examples can be given for other types of conditions and / or events. In addition, there are other conditions and / or events that would be useful if known. However, they are not so necessary, and it is a priority to develop better methods for analyzing more important things, so there is little or no way to evaluate these other conditions. Attention has not been paid.

[0007]

SUMMARY OF THE INVENTION According to one embodiment of the present disclosure, an apparatus for predicting the performance of a drilling system for drilling a drill hole in a predetermined formation comprises a unit according to a defined geological model. Means for generating a geological feature of the formation per depth. The means for generating a geological feature is for outputting a signal representing the geological feature, wherein the geological feature further includes at least rock strength. The apparatus further comprises means for inputting the specifications of the proposed drilling equipment for use in drilling a drill hole. The specifications include at least one bit specification of the recommended drill bit. Finally, the device is a means for determining the predicted drilling mechanics according to the specified drilling mechanics model and according to the proposed drilling equipment specifications as a function of the geological features per unit depth. Further included. The means for determining the predicted drilling mechanics is further for outputting a signal representative of the predicted drilling mechanics. The predicted drilling mechanics includes at least one selected from the group consisting of bit wear, mechanical efficiency, power, and operating parameters.

In another embodiment, the apparatus further comprises an output signal of the geological feature and the predicted drilling mechanics for generating an indication of the geological feature per unit depth and the predicted drilling mechanics. Includes means responsive to the output signal. The means for generating the display includes either a display monitor or a printer. In the example of a printer, the display of geological features and predicted drilling mechanics per unit depth includes a printout.

In another embodiment, a method for predicting the performance of a drilling system for drilling a drill hole in a predetermined formation includes the steps of: a) geological formation of a formation per unit depth according to a defined geological model; Generating a feature and outputting a signal representative of the geological feature, wherein the geological feature includes at least rock strength; b) using a drilling facility proposed for use in drilling a drill hole. Obtaining a specification, the specification including at least one bit specification of the recommended drill bit;
c) determining the predicted drilling mechanics according to the proposed drilling equipment specifications as a function of the geological features per unit depth according to the defined drilling mechanics model, Outputting a signal representative of the drilling mechanics, wherein the predicted drilling mechanics is at least one selected from the group consisting of bit wear, mechanical efficiency, power, and operating parameters.
One step, including one step.

In yet another embodiment, a computer program stored on a computer readable medium for execution by a computer for predicting the performance of a drilling system for drilling a drill hole in a predetermined formation. A) generating geological features of the formation per unit depth according to a prescribed geological model, and outputting a signal representing the geological features, wherein the geological features include at least rock strength B) an instruction for obtaining a proposed drilling equipment specification for use in drilling a drill hole, the specification comprising at least one bit specification of a recommended drill bit. , C)
According to the prescribed drilling mechanics model, determine the predicted drilling mechanics according to the proposed drilling equipment specifications as a function of the geological features per unit depth, and calculate the predicted drilling mechanics. Instructions for outputting a representative signal, the predicted drilling mechanics including at least one selected from the group consisting of bit wear, mechanical efficiency, power, and operating parameters. .

In yet another embodiment, an indication of the predicted performance of a drilling system suitable for use as an indicator in drilling a drill hole in a given formation is disclosed. The representation includes geological features of the formation per unit depth, and the geological features are obtained according to a defined geological model and include at least rock strength. The indication further includes the specifications of the drilling equipment proposed for use in drilling a drill hole. The specifications include at least one bit specification of the recommended drill bit. Finally, the display includes the predicted drilling mechanics, and the predicted drilling mechanics is according to a defined drilling mechanics model.
As a function of the geological features per unit depth, it is determined according to said specifications of the proposed drilling equipment. The predicted drilling mechanics includes at least one selected from the group consisting of bit wear, mechanical efficiency, power, and operating parameters.

Further, regarding the indication of the expected performance,
The geological feature further includes at least one graphical display selected from the group consisting of a curved display, a percentage graphical display, and a band display, and the predicted drilling mechanics display includes a curved display, a percentage graphical display, and At least one selected from the group consisting of band displays
Includes one graphical representation.

The present embodiment advantageously provides an evaluation of various proposed drilling equipment before and during the actual drilling of a drill hole in a given formation, and its use in connection with a drilling program. I do. Drilling equipment, its selection, and usage can be optimized for a particular section (s) of drill holes in a given formation.
The drilling mechanics model advantageously takes into account the effects of bit wear progressing through lithological changes. The recommended operating parameters reflect the wear state of the bit in the particular lithology and also take into account the operational constraints of the particular drilling equipment used. The printout or display of geological features per unit depth and predicted drilling mechanics for a given formation is important for drilling operators, especially in optimizing the drilling process. Provide information. The printout or display also advantageously provides a head-up view of expected drilling conditions and recommended operating parameters.

[0014] The foregoing description of the invention, as well as other teachings and advantages, will become more apparent in the detailed description of the best mode for carrying out the invention, as set forth hereinafter. In the following detailed description, reference will be made to the following accompanying drawings.

[0015]

DETAILED DESCRIPTION OF THE INVENTION Referring now to FIG. 1, a drilling system 10 includes a drilling device 12 disposed over a borehole 14. Logging tool
l) 16 is carried by a sub 18, typically a drill collar, assembled into a drill string 20 and placed in borehole 14. The drill bit 22 is located at the lower end of the drill string 20 and carves the borehole 14 in the formation 24. Drilling drilling water 26 is pumped from a mud reservoir 28 near the wellhead 30, down a central shaft passage (not shown) in the drill string 20, exiting the opening in the bit 22 and through an annular region 32. Return to the surface. A metal casing 34 is placed in the borehole 14 above the drill bit 22 to maintain the integrity of the top of the borehole 14.

Still referring to FIG.
The annular space 32 between the 0, the sub 18 and the side wall 36 of the borehole 14 forms a return channel for the drilling fluid. Mud is pumped from a storage well near the wellhead 30 by a pump system 38. The mud travels through a mud supply line 40 that connects to a central passage extending the entire length of the drill string 20. The drilling mud is thus pushed down in the drill string 20 to cool and smooth the drill bit and to carry drilling debris of the formation produced during the drilling operation back to the surface. Exit through the opening in the borehole. A fluid discharge duct 42 is connected to the annular passage 32 at the drill hole head to handle the flow of mud from the borehole 14 back to the mud reservoir 28. Drilling mud is typically operated and treated by various devices (not shown) such as degassing devices and circulation tanks to maintain a preselected mud viscosity and concentration.

The logging tool or instrument 16 may include sound waves (sometimes called acoustics), neutrons, gamma rays, densities, photoelectrons,
Any conventional logging instrument, such as nuclear magnetic resonance or other conventional logging instrument, or a combination thereof;
Used to measure the lithology or porosity of the formation surrounding the borehole in the ground.

Since the logging instrument is embodied in the drill string 20 of FIG. 1, the system is capable of measuring between drillings (M
WD: measurement while drill
ling) system, i.e., a system in which the perforation process is recorded as it proceeds. The logging data can be stored on a conventional downhole recorder (not shown), which is accessed at the surface when the drill string 20 is removed, or a conventional mud pulse remote. It can be transmitted to the surface using telemetry such as a measurement system. In any event, the logging data from the logging instrument 16 may be processed so that the data may be processed for use in accordance with embodiments of the present disclosure as described herein.
Finally reach. That is, processor 44 processes the logging data as suitable for use in embodiments of the present disclosure.

In addition to the MWD meter, a wireline logging meter may be used. That is, wireline logging instruments can also be used for logging the formation surrounding the borehole as a function of depth. A wireline track (not shown), along with a wireline instrument, is typically placed at the surface of the drill hole. Wireline logging instruments are suspended in boreholes with logging cables passing over pulleys and depth measurement sleeves. The logging instrument records the formation surrounding the borehole as a function of depth as it moves along the borehole. The logging data is transmitted through a logging cable to a logging track or a processor located near the track for processing the logging data for use in embodiments of the present disclosure. Similar to the MWD embodiment of FIG. 1, wireline instruments can be used to measure rock quality, such as acoustic waves, neutrons, gamma rays, density,
Any conventional logging that can be used to measure the lithology and / or porosity of the formation surrounding the borehole in the ground, such as photoelectron, nuclear magnetic resonance, or other conventional logging instruments, or a combination thereof. A layer instrument may also be included.

Still referring to FIG. 1 again, there is shown an apparatus 50 for predicting the performance of a drilling system 10 for drilling a series of drill holes, such as drill holes 14, in a given formation 24. The prediction device 50 includes a defined set of geological and drilling mechanics models, and further operates in an optimization mode, a prediction mode, and a calibration mode (see further below with reference to FIG. 3). )including. The prediction device 50 further includes a device 52 that includes any suitable commercially available computer, controller or data processing device, and is further programmed to perform the methods and apparatus as described herein. Computer / controller 52 includes at least one input for receiving input information and / or commands, for example, from any suitable input device (s) 58. The input device (device) 58 includes a keyboard, a keypad,
It includes a pointing device, or the like, and further includes a network interface or other communication interface for receiving input information from a remote computer or database. Furthermore, the computer / controller 52 includes at least one output for outputting information signals and / or device control commands. The output signal is a display device 6 for use in generating a representation of the information contained in the output signal.
0 can be output through the signal line 54.
The output signal is a printer device 6 for use in generating a printout 64 of information included in the output signal.
2 can be output. Also, the information and / or control signals may optionally be used, for example, as described herein, for remote control for use in controlling one or more various drilling operating parameters for drilling device 12. It can be output to the device through signal line 66. In other words, a suitable device or means responsive to the predicted drilling mechanics output signal is provided on the drilling system to control parameters in actually drilling a drill hole (or section) in the drilling system. Is done. For example, the drilling system includes a device such as one of a controllable motor selected from a downhole motor 70, a top drive motor 72, or a rotary table motor 74, and further includes the respective motors. The predetermined revolutions per minute can be remotely controlled. The parameters may also include one or more selected from the group of weight-on-bit, revolutions per minute, mud pump flow, water pressure, or other appropriate drilling system control parameters. .

The computer / controller 52 provides a means for generating geological features of the formation per unit depth according to a defined geological model. In addition, computer / controller 52 provides an output of signals representing geological features on signal lines 54,56. The input device 58 can be used to input the proposed drilling equipment specifications for drilling a drill hole (or section of a drill hole). The specifications include at least one bit specification of the recommended drill bit. Further, the computer / controller 52 determines a predicted drilling mechanics according to the proposed drilling equipment specifications as a function of the geological features per unit depth according to a further defined drilling mechanics model. Means are provided. Furthermore, the computer / controller 52 provides, on signal lines 54, 56, an output of a signal representative of the predicted drilling mechanics.

Computer / controller 52 is programmed to perform the functions as described herein using programming techniques well known in the art. In one embodiment, a computer readable medium is included, and the computer readable medium has a computer program stored thereon. The computer program executed by the computer / controller 52 is for predicting the performance of a drilling system for drilling a drill hole in a given formation. The computer program is
Includes instructions for generating a geological feature of the formation per unit depth according to a defined geological model and outputting a signal representative of the geological feature. However, the geological features include at least rock strength. The computer program also includes instructions for obtaining the proposed drilling equipment specifications for use in drilling a drill hole. However,
The specifications include at least one bit specification for a recommended drill bit. Finally, the computer
The program determines the predicted drilling mechanics according to the specified drilling mechanics model, according to the proposed drilling equipment specifications as a function of the geological features per unit depth, And an instruction for outputting a signal representing the signal. However, the predicted drilling mechanics includes at least one selected from the group consisting of bit wear, mechanical efficiency, power, and operating parameters. Computer /
Programming of the computer program to be executed by the controller 52 is accomplished using well-known programming techniques to implement the embodiments as described and described herein. In this way, the geology of a given formation per unit depth can be generated, and the predicted drilling mechanics performance of the drilling system is determined. Furthermore, the drilling operation can be advantageously optimized while recognizing its expected performance, as described further below in the text.

In a preferred embodiment, the geological features include at least the strength of the rock. In alternative embodiments, the geological features further include any one or more of log data, lithology, porosity, and shale plasticity.

As described above, the input device 58
It can be used to enter the specifications of the drilling equipment proposed for drilling a drill hole (or section of a drill hole). In a preferred embodiment, the specifications include at least one bit specification of the recommended drill bit. In an alternative embodiment, the specification is
Includes specifications for one or more of the following: equipment including motors, top drive motors, rotary table motors, mud systems, and mud pumps. Corresponding specifications include, for example, maximum torque output, mud type, or mud pump output rating as appropriate for the particular drilling facility.

In a preferred embodiment, the predicted drilling mechanics comprises at least one of the drilling mechanics selected from the group consisting of bit wear, mechanical efficiency, power and operating parameters. In another embodiment,
Operating parameters can include weight on bit, rotational rpm (revolutions per minute), cost, drilling speed, and torque, which are described further below. Drilling speed further includes the instantaneous speed of drilling (ROP) and the average speed of drilling (ROP-AVG).

Referring now to FIG. 2, a flow chart illustrating a method for drilling a series of drill holes in a given formation using an apparatus 50 for predicting the performance of a drilling system will now be described. . The method further relates to drilling one or more drill holes (or sections of drill holes) in a given formation to optimize both the drilling system and its use in a drilling program. It is for. The method includes, in step 100, starting a particular drilling program for a given formation or continuing with the drilling program. As regards the continuation of the drilling program, for some reason, for example due to equipment failure or downtime, the drilling program is interrupted, so that the drilling program is only partially completed. In the case of repair or replacement of a failed facility, the method of the present disclosure can be resumed at step 100. Preferably, the method is implemented from the start of a given drilling program, but from any point in the given drilling program to optimize the particular drilling system and its use It should be noted that it is possible to

At step 102, predicted drilling performance for a drilling system for drilling a drill hole in a predetermined formation is generated according to the present disclosure. further,
The predicted drilling performance for a given drill hole is determined according to a defined set of geological and drilling mechanics prediction models using at least one mode selected from the group consisting of an optimization mode and a prediction mode. Generated. In other words, when generating the predicted drilling performance for the drilling system, the optimization mode and / or
Alternatively, either the prediction mode is used. The predicted drilling performance includes predicted drilling mechanics measurements.
The optimization mode and the prediction mode are described further below in connection with FIG.

In step 104, the drilling operator determines whether actual drilling mechanics measurements should be obtained during drilling of a given drill hole (or section of a drill hole). If actual drilling mechanics measurements (eg, operating parameters) are to be obtained at step 106, the given drill hole (or section) is drilled with a drilling system that uses predicted drilling performance as an indicator. Is done. Further, at step 106, during drilling of the drill hole (or section), actual drilling mechanics measurements are obtained. Alternatively, if the determination does not result in a measurement of an operating parameter during drilling of a given drill hole (or section of a drill hole), the method may be further described below. Moves to step 132.

At step 108, the predicted drilling performance is compared to the actual drilling performance using a calibration mode of operation. The calibration mode of its operation is further explained in the text with reference to FIG. The comparison compares the actual drilling mechanics measurements with the predicted drilling mechanics measurements. In the comparing step, it is preferred to overlay the plot of the actual performance on the predicted performance (or vice versa) to visually determine any deviation between the actual performance and the predicted performance. It is. The comparison may also be realized with the aid of a computer for comparing appropriate data.

Referring to step 110 of FIG. 2, step 110 is defined as having a defined geology and drilling mechanics.
Includes a query as to whether the model is optimized for a particular geology and drilling system. In other words, if the model is optimized for a particular geology and a particular drilling system, the comparison between the predicted drilling mechanics measurements and the actual drilling mechanics measurements is acceptable. It is. Thereafter, the method moves to step 112 in connection with drilling of a subsequent one of the series of drill holes. On the other hand, if the model is not optimized for the particular geology and drilling system, the method moves from step 110 to step 114. If the comparison between the predicted drilling mechanics measurements and the actual drilling mechanics measurements at step 108 is not acceptable, the geology and drilling mechanics
At least one of the models is fine-tuned using a calibration mode of operation. At step 114, the geology and drilling mechanics model is fine-tuned (all or partially) using a calibration mode. Using the calibration mode, all or some of the geological and drilling mechanics models are determined from a comparison of actual and predicted drilling performance and fine-tuned to be appropriate. Once the model has been fine-tuned in step 114, the method includes:
Moving to step 112, relating to the drilling of subsequent drill holes in the series of drill holes.

At step 112, the actual drilling performance of the current drill hole is compared to the actual performance of the previous drill hole (s). Such a comparison can determine whether any improvement in performance has occurred. For example,
The comparison reveals that the current drill hole was drilled in 18 days versus the previous 20 days. Step 116 following step 112
A query is made as to whether the geology and drilling mechanics model has been optimized for the previous drill hole (s). If the model was optimized,
The method moves to step 118. Alternatively, if the model has not been optimized for the previous drill hole (s), the method moves to step 120.

At step 118, the values of the operating parameters optimized for drilling performance are documented. Further, the values of the operating parameters optimized for drilling performance may be documented and / or recorded in any suitable manner that can be easily accessed and retrieved. Documents and / or
Or the record may include, for example, a progress report, a computer file, or a database. Thus, step 118 facilitates the collection of values that optimize operating parameters on drilling performance. Examples of optimization values include, for example, the economic benefits of optimized drilling, reduced travel to the specific site being drilled, reduction of the time required to drill a drill hole, or measurement of other appropriate values. And so on. As a simpler example, running an offshore drilling program could cost as much as $ 150,000 per day. A savings or reduction of two days per drill hole (as a result of optimization of the drilling system and its use) would equate to a savings of $ 300,000 per drill hole. For a drilling program of 30 drill holes, the savings when combining the results of the optimizations are potentially 900 for a given drilling program.
It can be a million dollars.

At step 120, an inquiry is made as to whether any design changes have been made to the previous drill hole (s). If a design change has been made, the method moves to step 122. At step 122, in a manner similar to step 118, the value of the design change for drilling performance is documented. That is, it is documented and / or recorded in any suitable manner that can be easily accessed and retrieved. Documents and / or records may include, for example, progress reports, computer files, or databases. Step 122 thus facilitates the collection of design change values for drilling performance. Alternatively, if no design changes have been made to the previous drill hole (s), the method proceeds to step 124.

At step 124, an inquiry is made as to whether the drilling system is optimized for that particular geology. For example, in the current drill hole, if the drilling system is not optimized for specific geology,
Specific drilling equipment constraints may severely affect drilling performance. For example, if the mud pump is inadequate for a given geology, the resulting hydraulic power will be inadequate and will not be able to adequately clean the holes, which will result in the drilling performance of a drilling system for a particular geology. Adversely affect If the drilling system has not been optimized for the particular geology, the method proceeds to step 126; otherwise, the method proceeds to step 128. Step 1
At 26, appropriate design changes are implemented or made to the drilling system. The design changes may include equipment replacements, modernization and / or modifications, or other design changes as deemed appropriate for the particular geology. In this way, the equipment of the drilling system and its use can be optimized for drilling a given geology. Thereafter, the method proceeds to step 128.

At step 128, an inquiry is made as to whether the last drill hole of the drilling program has been drilled. If the last drill hole was drilled,
The method ends at step 130. If the last drill hole has not yet been drilled, the method proceeds to step 102 again and the process continues as described above in the text.

At step 132, if the parameters for operating the drilling system are not likely to be obtained, the given drill hole (or section) is taken with the drilling system using the predicted drilling performance as a guide without taking any measurements. It is pierced. In step 132, no drilling mechanics measurements are obtained during drilling of the drill hole (or section). Upon completion of the drilling of the current drill hole (or section) in step 132, the method proceeds to step 128 and the process continues as described above in the text.

The method and apparatus of the present disclosure advantageously optimize the drilling system and its use in a drilling program.
Be available early within a given drilling program. For example, using the method and apparatus, optimization may be 3
Without the present method or apparatus, the optimization would be achieved by 15 out of 30 drill hole programs, although it could be obtained by the first few drill holes of 0 drill hole programs. It may not be possible to get to the first drill hole. Further, the method facilitates making appropriate improvements early in the drilling program.
Any economic benefits resulting from the improvements made earlier in the drilling program are multiplied by the number of remaining drill holes drilled in the drilling program to provide a benefit. As a result, significant and meaningful savings are advantageously achieved for the company delegating the drilling program. Measurements are taken during the drilling of each drill hole throughout the drilling program using the present method and apparatus to verify that a particular drilling system equipment is being optimized and used. Further, the performance of drilling system equipment can be more easily monitored using the methods and apparatus of the present disclosure, and also to identify potential adverse conditions before they actually occur. Can be done.

Referring to FIG. 3, a model of the overall drilling system is provided by a predictive model 140. The prediction model further includes a geological model 142 and a drilling mechanics model 144 according to the method and apparatus.
FIG. 3 shows an overview of the various prediction models 140 and how they are linked together. As described further herein, the prediction model 140 is stored and executed by the computer / controller 52 of FIG.

The geological model 142 includes a rock model 146,
A rock strength model 148 and a shale plasticity model 150 are included. The lithology model was published on March 28, 2000 in "METHOD FOR QUANTIFYIN.
G THE LITHOLOGIC COMPOSIT
ION OF FORMATIONS SURROUN
It is preferred to include a rock model as described in US Pat. No. 6,044,327 entitled "DING EARTH BOREHOLES". It is. The patent is incorporated herein by reference. The lithology model provides a way to quantify the lithological component ratio of a given formation, including lithology and porosity. The lithology model is a log suite (l) that is susceptible to any lithology or porosity, including, for example, nuclear magnetic resonance, photoelectrons, neutron density, acoustics, gamma rays, and spectral gamma rays.
og suite). In addition, the rocky model
Provide improved multi-composition analysis. For example, the lithic row of FIG. 4 shows four compositions, including sandstone, limestone, dolomite, and shale, at a depth of 575 feet. The composition can weight a particular log or group of logs. The lithology model recognizes that certain logs are superior to others in elucidating a given lithology composition. For example, it is generally well known that gamma log is the best shale indicator. Coal deposits can be clearly elucidated by neutron logs, but by acoustic logs they will be completely overlooked. A weighting factor is applied so that a given rock quality can be resolved by a log or group of logs that can most accurately resolve it. Furthermore, the lithology model shows that the maximum concentration of any lithology composition can be from zero to one.
To be able to change up to 00 percent,
Calibration of the model for the core analysis becomes possible. The lithology model also takes into account the limited abundance for each lithology composition and can be further based on core analysis.
The lithology model may also include any other model suitable for predicting lithology and porosity.

The rock strength model 148 is “METHODO ASSAYI published on June 16, 1998.
NG COMPRESSIVE STRENGTH O
FROCK (method for testing the compressive strength of rocks) "
It is preferred to include a rock strength model as described in US Pat. No. 5,767,399 entitled, US Pat. The patent is incorporated herein by reference. The rock strength model provides a method for determining confinement stress and rock strength in a given formation. The rock strength model is
Any other model suitable for predicting confinement stress and rock strength can be included.

The shale plastic model 150 is described in “METHOD AND AP” published on April 18, 2000.
PARATUS FOR QUANTIFYING S
HALE PLASTICITY FROM WELL
Preferably, it includes a shale plasticity model described in US Pat. No. 6,052,649, entitled "LOGS (Method and Apparatus for Quantifying Shale Plasticity from Drill Hole Logs)". The patent is incorporated herein by reference. The shale plastic model is
A method is provided for quantifying shale plasticity of a given formation. Also, the shale plasticity model can include any other model suitable for predicting shale plasticity. Thus, the geological model is ready to generate a model of a particular geological application for a given formation.

The drilling mechanics model 144 includes a mechanical efficiency model 152 and a hole cleaning efficiency model
4. Bit wear model 156 and drilling speed model 15
8 inclusive. The mechanical efficiency model 152 was submitted on March 26, 1998, and was published in “METHOD OF ASSA.
YING DOWNHOLE OCCURRENCES
No. 09 / 048,360, entitled "AND CONDITIONS". It is preferable to include such a mechanical efficiency model. The patent application is incorporated herein by reference. The mechanical efficiency model provides a method for determining the mechanical efficiency of a bit.
In the mechanical efficiency model, mechanical efficiency is defined as a percentage of the torque to cut. The remaining torque is distributed as friction. The mechanical efficiency model reflects a) the 3D bit shape, and b) cutting torque.
torque), c) taking into account the effects of work constraints, and d) torque and drag (dr
Ag) analysis is used.

With respect to the Hole Cleaning Efficiency (HCE) model 154, the model is a drilling fluidity type, hydraulic (hy
draulics), lithology and shale plasticity. The hole cleaning efficiency model is a measure of the effectiveness of drilling fluidity and hydraulic pressure. If the hole cleaning efficiency is low, drilling debris that is not removed or that is removed slowly will adversely affect the drilling mechanics.

The bit wear model 156 was manufactured in August 1998.
"METHOD OF ASSAYI
NG DOWNHOLE OCCURRENCES A
It is preferred to include the bit wear model described in U.S. Pat. No. 5,794,720, entitled "ND CONDITIONS". The patent is incorporated herein by reference. The bit wear model provides a method for determining bit wear, i.e., predicting bit life and formation abrasivity. In addition, the bit wear model is used to apply work rating to a given bit.

The excavation speed model 158 is issued on January 16, 1998 and is referred to as “METHODO REGULAT”.
ING DRILLING CONDITIONS A
Including a drilling speed model as described in US Pat. No. 5,704,436 entitled "PPLIED TO A WELL BIT" (a method for adjusting drilling conditions applied to drill hole bits). It is suitable. The patent is incorporated herein by reference. The drilling speed model provides a method for optimizing operating parameters and predicting the drilling speed of the bit and drilling system. The ROP model maximizes the drilling speed, limits the output to avoid impact damage to the bit, takes into account all operational constraints, optimizes operating parameters , Minimizing bit induced vibration.

The drilling mechanics model 144 as described herein may be used to drill a drill hole, a section of a drill hole, or a series of drill holes that are placed in a predetermined drilling operation, or Provides the generation of a comprehensive model of a particular drilling system proposed for use. The drilling mechanics model 144
A drilling mechanics performance prediction of a drilling system for a given geology is generated. Comparison of the actual performance with the predicted performance is used to match the history with the drilling mechanics model and, if required, to optimize the respective drilling mechanics model be able to.

Still referring to FIG. 3, the method and apparatus include several modes of operation. The operation modes include an optimization mode, a prediction mode, and a calibration mode. Includes predictive economics to provide a measure of the number of days per drill hole achieved when the drilling system is optimized using the methods and apparatus of the present disclosure for various modes of operation. Optimization mode In the optimization mode, the purpose is to optimize the operating parameters of the drilling system. The optimization criteria are: 1) maximizing the drilling speed, 2) avoiding impact damage to the bit, 3) taking into account all operational constraints, and 4) minimizing bit induced vibration. It is to limit.

In the optimization mode, the lithology model 146
Receives on input 160 data from porosity logs, lithology logs, and / or mud logs. The porosity or lithology log can include nuclear magnetic resonance (NMR), photoelectron, neutron density, acoustic, gamma, and spectral gamma radiation, or any other log susceptible to porosity or lithology. Mud logs are used to identify non-shale lithological compositions. In response to the log input, the lithology model 146 provides on output 162 a measure of the lithology and porosity of a given formation per unit depth. Regarding lithology,
The output 162 preferably includes the volume ratio of the lithological composition of each of the formations per unit depth. With respect to porosity, the output 162 preferably includes the volume ratio of porosity in the formation rock per unit depth. Measures for rock quality and porosity on output 162 include rock strength model 148, shale plasticity model 150, and mechanical efficiency model 15
2. Hole cleaning efficiency model 154, bit wear model 1
62 and the excavation speed model 158.

For the rock strength model 148, in addition to receiving a measure of the lithology and porosity output 162, the rock strength model 148 also receives mud weight and pore pressure data at input 164. Mud weight is used to calculate overbalance. Pore pressure is used to calculate overbalance, but alternatively, design overbalance may be used to estimate pore pressure. In response to the input, the rock strength model 148 produces on output 166 a measure for the confinement stress and rock strength of a given formation per unit depth. Among other things, the rock strength model produces measures of overbalance, effective pore water pressure, confining stress, unconfined rock strength, and confined rock strength. Overbalance is defined as the mud weight minus pore water pressure. Effective pore pressure is similar to pore pressure, but
Reflects the reduction in transmission in shale and low porosity non-shale. Confinement stress is an estimate of the in situ confinement stress of a rock. Unconfined rock strength is the rock strength at the Earth's surface. Finally, the confined rock strength is the rock strength in a state where the stress is confined at the original position. As shown, the rock strength output 166 includes a mechanical efficiency model 152, a bit wear model 162,
And the digging speed model 158.

Regarding the mechanical efficiency model 152,
In addition to receiving the lithology and porosity output 162, and the confinement stress and rock strength output 166, the mechanical efficiency model 152 has on input 168 operational constraints, a 3D bit model, all related to the drilling system. ,
And input data on torque and drag. Operational constraints include maximum torque, maximum weight on bit (WOB), maximum and minimum RPM, and maximum drilling speed. In particular, with regard to mechanical efficiency, operational constraints in the drilling system are: maximum torque, maximum weight on bit (W
OB), minimum RPM, and maximum drilling speed. Operational constraints limit the amount of optimization that can be achieved with a particular drilling system. In addition, with respect to assessing the impact of operational constraints on mechanical efficiency, not all constraints affect both mechanical efficiency and output, but those that affect either mechanical efficiency or output. To quantify the effect of a constraint, it is necessary to know all of the constraints. 3D bit
Model inputs include bit work rating and torque-WOB signature. Finally, the torque and drag analysis includes directional planning, casing and drill string geometry, mud weight and flow, coefficient of friction, or torque and drag measurements. Torque and drag analysis is needed to determine how much surface torque is actually transmitted to the bit. Alternatively, instead of torque and drag analysis, off-bottom and on-bottom torque measurements can be used. Further, a near bit measurement system from between drilling (MWD) measurements can be used instead of torque and drag analysis. In response to the input information, a mechanical efficiency model 152 may output, at output 170, an analysis of mechanical efficiency, constraints, predicted torque, for a drilling system in a given formation per unit depth.
And an optimal weight-on-bit (WOB) measure is created.
Among other things, the mechanical efficiency model 152 provides a measure of total torque, cutting torque, friction torque, mechanical efficiency, constraints analysis, and optimal WOB. The total torque represents the sum of the torque applied to the bit. Cutting torque represents the cutting component of the total torque. Friction torque is the friction component of the total torque. With respect to the mechanical efficiency model 152, mechanical efficiency is defined as a percentage of the total torque to cut.
Constraint analysis quantifies the reduction in mechanical efficiency from the theoretical maximum caused by each operational constraint. Finally, the optimal WOB that maximizes the drilling speed is determined, taking into account all operational constraints. The optimal WOB is used by the digging speed model 158 to calculate the optimal RPM. Further, the mechanical efficiency model 152 has a
As described further below, it also utilizes a measure of bit wear from a previous iteration as input.

Referring now to the bit wear model 156, the bit wear model receives input from the rocky model via output 162, input from the rock strength model via output 166, and output 170. Receive input from mechanical efficiency model. In addition, bit wear model 15
6 receives 3D bit model data on input 172. The 3D bit model inputs include bit work rating and torque-WOB signature. Depending on the lithology, porosity, mechanical efficiency, rock strength, and input of the 3D bit model, the bit wear model 156 may output
Create a measure of specific energy, cumulative work, formation abrasion, and bit wear for bits in a given formation per unit depth. Specific energy is the total energy applied to the bit and is equivalent to the bit force divided by the bit cross-sectional area. The cumulative work performed by the bit reflects both rock strength and mechanical efficiency. A measure of formation polishing models the wear accelerated by formation polishing. Finally, a measure of bit wear corresponds to wear conditions linked to bit axial contact area and mechanical efficiency. In addition to output 174, bit wear model 1
56 includes providing, on output 176, a measure of bit wear from a previous iteration to mechanical efficiency model 152, where mechanical efficiency model 152 further calculates its mechanical efficiency output data on output 170. In doing so, a measure of bit wear from the previous iteration is used.

Prior to describing the digging speed model 158, first return to the shale plasticity model 150. As shown in FIG. 3, the shale plastic model 150 receives input from a lithologic model. In particular, the shale volume is provided from the lithology model 146. The shale plastic model 150 is
In addition to receiving the lithology and porosity output 162, it receives log data from a drill hole log defined on input 178, which is sensitive to clay type, clay moisture, and clay volume. Including any logs. Such logs include nuclear magnetic resonance (NMR), neutron density, acoustic density, spectral gamma rays, gamma rays, and cation exchange capacity (CEC). In response to the input, the shale plastic model 150 outputs on the output 180:
Create a measure of shale plasticity of the formation per unit depth. In particular, shale plasticity model 150 provides measures of standard clay type, standard clay moisture, standard clay volume, and shale plasticity. The standard clay type defines the maximum concentration of smectite, which is the clay type that is most likely to cause clay swelling. Standard clay moisture content describes the moisture content at which maximum shale plasticity occurs. Standard clay volume defines the range of clay volumes in which plasticity can occur. Finally,
Shale plasticity is a weighted average of the properties of a standard clay and reflects overall plasticity.

With respect to the hole cleaning efficiency model 154, the model 154 receives shale plastic input from the shale plastic model 150 and lithological input from the lithological model 146. In addition to receiving the lithologic model output 162 and the shale plastic model output 180, the hole cleaning efficiency model 154 receives hydraulic and drilling fluid data on inputs 182. In particular, the hydraulic input may include any standard measure of hydraulic efficiency, such as hydraulic horsepower per square inch of bit diameter. In addition, drilling mud types are water-based mud, oil-based mud, polymer,
Or other well-known mud types. In response to the input, the hall cleaning efficiency model 154 outputs
Create a measure of the expected hole cleaning efficiency for the bit and drilling system when drilling drill holes (or sections) in the formation per unit depth. The hole cleaning efficiency is defined here as the predicted drilling speed divided by the actual drilling speed. While other drilling mechanics models assume complete hole cleaning, the hole cleaning efficiency (HCE) model predicts drilling speed to compensate for hole cleaning that deviates from ideal motion. Is a measure for correcting. Therefore, the measure of hole cleaning efficiency (HCE) is lithological, shale plastic,
The effects of water pressure and drilling fluid type are reflected on the drilling speed.

Referring to the excavation speed model 158, the excavation speed model 158 receives the mechanical efficiency, the predicted torque, and the optimal WOB via the output 170 of the mechanical efficiency model 152. Model 158 further provides for bit wear via output 174 of bit wear model 156,
Predicting the rock strength via output 166 of the rock strength model 148 and predicting HC via output 184 of the HCE model 154
Receive E. Further, the digging speed model 158 receives, on an input 186, operational constraint information. In particular, operational constraints include maximum torque, maximum weight on bit (WO
B), including maximum and minimum RPM, and maximum drilling speed. In addition, regarding the evaluation of the effects of operational constraints on output,
Not all constraints affect both mechanical efficiency and power, but knowing all of the constraints to quantify the impact of these constraints that affects either mechanical efficiency or power It is necessary to put.
In response to the input, the drilling speed model 158 outputs on the output 188 a power level analysis and a constraint analysis of the bits and drilling system when drilling a drill hole (or section) in the formation per unit depth. And, in addition, measures of optimal RPM, drilling speed, and economy. In particular, power level analysis involves determining the maximum power limit. The maximum power limit maximizes the drilling speed without causing impact damage to the bit. The operational output level is less than the maximum output due to operational constraints. Constraint analysis involves quantifying the reduction in operating power level from the maximum power output caused by each operational constraint. The optimal RPM is the RPM that maximizes the drilling speed, taking into account all operational constraints. The drilling speed is the predicted drilling speed at optimal WOB and optimal RPM. Finally, economy can be described as an industry standard cost analysis per foot. Prediction Mode In the prediction mode, the target or purpose is to predict the perforation performance in the case where a user-specified operation parameter is not always optimal. Operational constraints do not apply to this mode. As described later in the text, the prediction mode is based on the mechanical efficiency model 1
52, bit wear model 156, and permeability model 15
8, with an exception, but essentially similar to the optimization mode. The hole cleaning efficiency model 154 is the same for both the optimization mode and the prediction mode because the hole cleaning efficiency does not depend on the mechanical operating parameters (ie, the user-specified WOB and the user-specified RPM).

With respect to the mechanical efficiency model 152 in the predictive mode, in addition to receiving the lithology and porosity output 162, and the confinement stress and rock strength output 166, the mechanical efficiency model 152 also includes an input 168 to the drilling system. Receives relevant user-specified operating parameters and input data for the 3D bit model. User-specified operating parameters for the drilling system can include a user-specified weight on bit (WOB) and a user-specified RPM. This option is used to evaluate the "what if" scenario. The 3D bit model inputs include bit work rating and torque-WOB signature.
In response to that input, the mechanical efficiency model 152 produces at output 170 a measure of mechanical efficiency for the drilling system in a given formation per unit depth. In particular, the mechanical efficiency model 152 has a total torque,
Provides a measure of cutting torque, friction torque, and mechanical efficiency. The total torque represents the sum of the torque applied to the bit. In the prediction mode, the total torque is
It corresponds to the weight on the bit specified by the user. The cutting torque is
Represents the cutting component of the total torque on that bit. Friction torque is the friction component of the total torque on that bit.

With respect to the mechanical efficiency model 152, mechanical efficiency is defined as a percentage of the total cutting torque. The prediction mode also includes analysis of mechanical efficiency by range, that is, by mechanical efficiency range for the mechanical efficiency torque-WOB signature of the bit.
The first range of mechanical efficiency is from zero WOB to threshold W
The threshold WOB is defined by the range of the first weight on the bit (WOB) up to the OB, where the threshold WOB corresponds to the predetermined WOB just needed to excavate the rock, and just excavating means Corresponds to zero (or negligible). Further, a first range of mechanical efficiencies is that of efficient grinding.
ing). The second range of the mechanical efficiency is the second range from the threshold WOB to the optimal WOB.
The optimum WOB is defined by the range of weight on the bit, just before the bit body contacts the formation, just before reaching the maximum depth of cut at the bit.
OB. Further, a second range of mechanical efficiencies is that of efficient cutting.
g). The third range of mechanical efficiency is defined by a third range of weight on the bit from the optimal WOB to the grinding WOB, where the grinding WO
B corresponds to the predetermined WOB required to be reduced until the cutting torque of the bit is essentially just zero or negligible. A third range of mechanical efficiencies is the inefficient cutting.
This corresponds to a perforation efficiency such as t cutting. Finally, a fourth range of mechanical efficiency is defined by the range from the grinding WOB to the fourth weight above the bit. Further, a fourth range of mechanical efficiency corresponds to perforation efficiency such as inefficient grinding. For the third and fourth ranges, although the bit achieves the maximum depth of cut, as the WOB increases, the frictional contact of the bit body with the rock formation also increases.

Further, the mechanical efficiency model 152 is
As described further below with respect to the bit wear model, it also utilizes a measure of bit wear from a previous iteration as input.

In connection with the bit wear model 156 in the prediction mode, the bit wear model has an output 162
, The input from the rock strength model via output 166, and the input from the mechanical efficiency model via output 170. Further, bit wear model 156 receives 3D bit model data on input 172. The 3D bit model input is
Includes bit work rating and torque-WOB signature. Bit wear model 156 depending on lithology, porosity, mechanical efficiency, rock strength, and 3D bit model input
Produces on output 174 a measure of specific energy, cumulative work, formation abrasion, and bit wear for bits in a given formation per unit depth. Specific energy is the total energy applied to the bit and is equivalent to the bit force divided by the bit cross-sectional area. further,
The calculation of the specific energy is based on operating parameters specified by the user. The cumulative work performed by the bit reflects both rock strength and mechanical efficiency. The cumulative work performed by the bits is also based on user-specified operating parameters. The formation polishing measure models the wear accelerated due to formation polishing. Finally, a measure of bit wear corresponds to wear conditions linked to bit axial contact area and mechanical efficiency. Like the calculation of the specific energy and the cumulative work, the calculation of the bit wear is also based on user-specified operating parameters. In addition to the output 174, the bit wear model 156 includes, on output 176, providing a measure of bit wear from a previous iteration to the mechanical efficiency model 152, where the mechanical efficiency model 152 further includes Utilizes the bit wear measure from the previous iteration in calculating its mechanical efficiency output data.

Here, referring to the excavation speed model 158,
The drilling speed model 158 is a mechanical efficiency model 152
Receive the mechanical efficiency and the predicted torque via the output 170 of. Model 158 also receives bit wear via output 174 of bit wear model 156, rock strength via output 166 of rock strength model 148, and predicted HCE via output 184 of HCE model 154. Further, the digging speed model 158 receives a user-specified operation parameter on the input 186. In particular,
The user-specified operation parameters include a user-specified on-bit weight (WOB) and a user-specified RPM. As described above, the prediction mode of this operation is used to evaluate the "what if" scenario. In response to the input, the drilling speed model 158
On output 188, power level analysis and, in addition, drilling speed, and economy for bits and drilling systems in predicting and drilling drill holes (or sections) in the formation per unit depth. Create a measure for.
In particular, power level analysis involves determining the maximum power limit. The maximum output limit, when applied to bits,
This corresponds to a defined output that maximizes the drilling speed without causing impact damage to the bit. The operation output level resulting from the user-specified operation parameters is less than or greater than the maximum output limit. Operating power levels that exceed the maximum power limit on the bit are automatically flagged, for example by appropriate programming, to indicate or reveal sections of the drill hole where impact damage to the bit is likely. be able to. Power level analysis applies to a particular drilling system and its use in drilling a drill hole (or section) in a given formation. Further, the digging speed is a digging speed predicted when the user-specified WOB and the user-specified RPM are used. Finally, economy is an industry standard cost analysis per foot. Calibration Mode Finally, in the calibration mode, the object or purpose is to calibrate the drilling mechanics model to the measured operating parameters. Further, the geological model can also be calibrated to the measured core data. Any model or group of models can be partially or fully calibrated. As in the prediction mode, operational constraints do not apply to the calibration mode.

Beginning with the geological model 142, the measured core data is used to calibrate the geological model. Regarding the lithology model, the lithology model 146 is:
On input 160, data from porosity logs, lithology logs and / or mud logs, and core data is received. As mentioned above, the porosity or lithology log can be nuclear magnetic resonance (NMR), photoelectron, neutron density, acoustic, gamma, and spectral gamma, or any other susceptibility to porosity or lithology. Can be included. Mud logs are used to identify non-shale lithic components. The core data includes measured core data that can be used to calibrate the lithology model. By calibrating the lithology model with the measured core data, the predicted lithology composition will better match the measured core composition. Also, the measured core porosity is used to calibrate any porosity drawn from the log. According to the input, the rocky model 1
46 provides on output 162 a measure of the lithology and porosity of a given formation per unit depth. For the lithology to be calibrated, the output 162 is preferred for each formation per unit depth. It is preferable to include the volume ratio of the lithological composition. For the porosity to be calibrated, the output 162 derived from the log is preferably calibrated to the measured core porosity. Also, less accurate logs can be calibrated to more accurate logs. Calibration for rock quality and porosity on output 162 is based on Rock Strength Model 1
48, a shale plasticity model 150, a mechanical efficiency model 152, a hole cleaning efficiency model 154, a bit wear model 152, and a digging speed model 158.

For the rock strength model 148, the inputs and outputs are very similar to those described above for the optimization mode. However, in the calibration mode, input 164 further includes core data. core·
The data includes measured core data used to calibrate the rock strength model. Calibration allows the expected rock strength to better match the measured core strength. In addition, the measured pore water pressure data
It can be used to calibrate confinement stress calculations.

For the shale plastic model 150, the inputs and outputs are very similar to those described above for the optimization mode. However, in the calibration mode, input 178 further includes core data. The core data includes measured core data used to calibrate the shale plastic model. Calibration allows the predicted plasticity to better match the measured core plasticity. In response to that input, shale plasticity model 150 provides on output 180 a measure of shale plasticity for a given formation per unit depth. For shale plasticity to be calibrated, output 180 preferably includes a weighted average of standard clay properties, reflecting the overall plasticity calibrated to the core analysis.

With respect to the mechanical efficiency model 152, the inputs and outputs are very similar to those described above with respect to the optimization mode, with the following exceptions. In the calibration mode, the input 168 includes measured operating parameters, but does not include operational constraints or torque and drag analysis. The measured operating parameters include weight-on-bit (WOB), RPM, drilling speed, and torque (optional), which are used to calibrate the mechanical efficiency model. In response to that input, the mechanical efficiency model 152 outputs to the output 170 the total torque, cutting torque, friction torque, and the mechanical efficiency to be calibrated,
Provides a measure of Regarding total torque, total torque is
The sum of the torque applied to the bit, which is calibrated to the measured torque, if data is available. Cutting torque refers to the cutting component of the total torque on the bit and is calibrated to actual mechanical efficiency. Friction torque refers to the friction component of the total torque on that bit and is calibrated to actual mechanical efficiency. For the mechanical efficiency model 152 to be calibrated, mechanical efficiency is defined as a percentage of the total torque to cut. The predicted mechanical efficiency is calibrated to the actual mechanical efficiency. The calibration will be more accurate if the measured torque data is available. However, even if torque data is not available, it is possible to partially calibrate the mechanical efficiency by using the torque predicted by other measured operating parameters.

The calibration mode also includes analysis of mechanical efficiency by range, that is, by mechanical efficiency range with respect to the torque-WOB signature of the mechanical efficiency of the bit. As shown above, the first range of mechanical efficiency is the first range from zero WOB to the threshold WOB.
Is defined by the range of the weight on the bit (WOB), where the threshold WOB corresponds to the predetermined WOB required for just digging rock, and furthermore, just digging means that the depth of cut is zero. (Or negligible). Further, the first range of the mechanical efficiency corresponds to the drilling efficiency such as efficient grinding. The second range of mechanical efficiency is defined by the range of weight on the second bit from the threshold WOB to the optimal WOB, where the optimal WO
B is the predetermined WOB required just to achieve the maximum depth of cut at the bit before the bit body contacts the formation.
Is equivalent to Further, the second range of the mechanical efficiency corresponds to the drilling efficiency such as efficient cutting. A third range of mechanical efficiency is defined by a third range of weight on the bit from the optimal WOB to the grinding WOB, where the grinding WOB is such that the cutting torque of the bit is essentially just zero or negligible. , Which corresponds to the predetermined WOB required to be reduced. Further, the third range of the mechanical efficiency corresponds to the drilling efficiency such as inefficient cutting. Finally, the fourth range of mechanical efficiency is:
It is defined by the range from the grinding WOB to the fourth weight above the bit. Further, the fourth range of the mechanical efficiency corresponds to the drilling efficiency such as inefficient grinding. Third
And for the fourth range, although the bit achieves a maximum depth of cut, as the WOB increases, the frictional contact of the bit body with the rock formation also increases.

For the bit wear model 156, the inputs and outputs are similar to those described above for the optimization mode. However, in the calibration mode, input 172 further includes a bit wear measurement. The bit wear measurement includes a measure of the current axial contact area of the bit. Further, the bit wear measurement correlates with the cumulative work performed by the bit based on the measured operating parameters. In response to that input, the bit wear model 156 provides on output 174, for a given drilling system and formation per unit depth, specific energy, cumulative work, formation polishing to be calibrated, and bit work rating to be calibrated. Provide a measure. With respect to the specific energy, the specific energy corresponds to the total energy applied to the bit. Furthermore, the specific energy is equivalent to the bit force divided by the bit cross-section, the calculation being further based on the measured operating parameters. Regarding cumulative work,
The cumulative work performed by the bit reflects both rock strength and mechanical efficiency. Further, the calculation of the cumulative work is based on the measured operating parameters. With respect to the calculated formation abrasion, the bit wear model has accelerated wear due to formation abrasion. In addition, the bit wear measurements and the cumulative work performed can be used to calibrate the formation abrasion. Finally, with respect to the calibrated bit work rating, the blunt bit wear condition is linked to the cumulative work done. In the calibration mode, the bit work rating of a given bit is calibrated to the bit wear measurement and calibration work performed.

For the hole cleaning efficiency model 154, the inputs and outputs are very similar to those described above for the optimization mode. However, in the calibration mode, the hole cleaning efficiency is calibrated by correlating with the HCE measured in the drilling speed model, as further described below.

For the drilling speed model 158, the inputs and outputs are very similar to those described above with respect to the optimization mode. However, in the calibration mode, input 186 does not include operational constraints, but rather
Includes measured operating parameters and bit wear measurements. The measured operating parameter is the weight on the bit (W
OB), RPM, drilling speed, and torque (optional). The bit wear measurement is a measure of the current axial contact area of the bit and identifies the predominant wear type of uniform and uneven wear. For example, impact damage is a non-uniform form of wear. The measured operating parameters and bit wear measurements are used to calibrate the drilling speed model. In response to the input, the drilling speed model 158
Provides a measure of calibrated drilling speed, calibrated HCE, and calibrated power limit. With respect to the calibrated drilling speed, the calibrated drilling speed is the expected drilling speed using the measured operating parameters. The predicted drilling speed is calibrated to the measured drilling speed using HCE as a correction factor. For the HCE to be calibrated, the HCE is defined as the actual drilling speed divided by the actual drilling speed. The HCE predicted from the HCE model is calibrated to the HCE calculated in the drilling speed model. Finally, with respect to the power limit being calibrated, the maximum power limit maximizes the drilling speed without causing impact damage to the bit. If the operating power level resulting from the measured operating parameters exceeds the power limit, impact damage can occur. Software or computer programs for implementing the performance prediction of the drilling system can be set to automatically flag all operating power levels that exceed the power limit. Furthermore, the power limit is adjusted to reflect the type of wear actually found on the dull bits. For example, the program will flag sections where impact damage is likely, but will be raised because the wear seen on the dull bits is largely non-uniform and the power limit is probably too modest. Should.

Further, performance analysis including analysis of operation parameters may be executed. The operating parameters to be measured are WOB, TOB (optional), RPM, and ROP
including. In order to obtain a more accurate performance analysis result, measurement near a bit is preferable. Other performance analysis measurements include bit wear measurements, drilling fluid type and water pressure, and economy. Overview Referring again to FIG. 1, an apparatus 50 for predicting the performance of a drilling system 10 for drilling a drill hole 14 in a given formation 24 will now be further described. The prediction device 50 includes a computer / controller 52 for generating a geological feature of the formation per unit depth according to a defined geological model and for outputting a signal representing the geological feature. Preferably, the geological features include at least rock strength. Further, the geological feature generator 52 generates at least one of the additional features selected from the group consisting of log data, lithology, porosity, and shale plasticity.

An input device 58 is provided for inputting the proposed drilling equipment specifications for drilling a drill hole,
The specifications therein include at least one bit specification of the recommended drill bit. In addition, input device (s)
58 may further include at least one additional specification of a proposed drilling facility selected from the group consisting of a downhole motor, a top drive motor, a rotary table motor, a mud system, and a mud pump. Used to enter additional drilling equipment input specifications.

Finally, the computer / controller 52
Is to determine the predicted drilling mechanics according to the proposed drilling equipment specifications as a function of the geological features per unit depth according to a defined drilling mechanics model. Further, the computer / controller 52 is for outputting a signal representative of the predicted drilling mechanics, including at least one selected from the group consisting of bit wear, mechanical efficiency, power, and operating parameters. . The operating parameters include at least one selected from the group consisting of weight on bit, rotary rpm (revolutions per minute), cost, drilling speed, and torque. Further, the drilling speed is determined by the instantaneous speed of drilling (ROP) and the average speed of drilling (ROP-
AVG).

As shown in FIG. 1, the display 60
And the printer 62 provide a means responsive to the geological feature output signal and the predicted drilling mechanics output signal to generate an indication of the geological feature per unit depth and the predicted drilling mechanics, respectively. provide. For the printer 62, an indication of the geological features per unit depth and the predicted drilling mechanics is provided in a printout 64.
including. Further, the computer / controller 52
For a given predicted drilling mechanics output signal,
A drilling operation control signal is provided on line 66. In such instances, the drilling system may further be responsive to one or more drilling operation control signals based on the predicted drilling mechanics output signal to control parameters in actually drilling the drill hole in the drilling system. Including devices. Typical parameters are weight on bit, rp
m, at least one selected from the group consisting of: pump flow, and water pressure. Display of Predicted Performance Referring now to FIG. 4, a display 200 of the predicted performance of the drilling system 50 (FIG. 1) for a given formation 24 (FIG. 1).
Is described in more detail. The display 200 includes a display of a geological feature 202 and a predicted drilling mechanics 20.
4 is included. The display of the geological feature 202 includes at least one graphical display selected from the group consisting of a curve display, a percentage graph display, and a band display. Further, the display of predicted drilling mechanics 204 includes at least one graphical display selected from the group consisting of a curve display, a percentage graph display, and a band display. In a preferred embodiment, at least one graphical representation for the geological feature 202 and at least one graphical representation for the predicted drilling mechanics 204 are color coded. Header Description The following relates to the various columns of information shown in FIG.
A list of various symbols, corresponding brief descriptions, units, and data ranges. It should be noted that this list is merely exemplary and not limiting. This list is incorporated herein to provide a thorough understanding of the illustration of FIG. Other symbols, descriptions, units, and data ranges are possible. Header symbol Description Unit Data range Log data column (208) GR (API) Gamma ray log API 0-150 RHOB (g / cc) Bulk density g / cc 2-3 Log DT (μs / ft) Sound wave or microsecond / Ft 40-140 Acoustic log CAL (in) Caliper log in 6-16 Depth row (206) MD (ft) Measurement depth ft (or meter) 200-1700 Rocky row (210) SS Sandstone concentration % 0-100 LS Limestone concentration% 0-100 DOL Dolomite concentration% 0-100 COAL Coal concentration% 0-100 SH Shell concentration% 0-100 Porosity column (212) ND-POR Neutron density porosity% ( Fraction) 0-1 N-POR Neutron porosity% (fraction) 0-1 D-POR Density porosity% (fraction) 0-1 SP OR Acoustic porosity% (fraction) 0-1 Rock strength row (216) CRS (psi) Confined rock strength psi 0-50,000 URS (psi) Unconfined rock psi 0-50,000 CORE (psi) Measured Core strength psi 0-50,000 Rock strength column (218) Rock CRS Confinement rock strength psi 0-50,000 Shale plasticity column (230) Plasticity Shale plasticity% (fraction) 0-1 CEC-N standard cation Exchange capacity% (fraction) 0-1 CBW-N Standard viscosity bound water% (fraction) 0-1 Vsh-N Standard shale volume% (fraction) 0-1 Shell plasticity row (232) Plasticity shale plasticity% 0 -100 Bit wear line (236) Grinding (t ・ mi) Formation grinding Ton mile 0-10,000 work (t ・ mi) Cumulative work Ton ・Yl 0k-10k SP energy - specific energy ksi 0-1,000 (ksi) (1,000psi) bit wear string (238) Red ¹ consumed bit life% 0-100 Green ¹ remaining bit life% 0 -100 Mechanical efficiency column (246) Cutting torque on TOB-CUT bit ft · lb 0-4,000 (ft · lb) Total torque on TOB bit ft · lb 0-4,000 (ft · lb) Mechanical Efficiency column (248) Cyan ¹ cutting torque% 0-100 Yellow ¹ friction torque-Unconstrained% 0-100 Red ¹ friction torque-Constraint% 0-100 Mechanical efficiency constraint column (256) Cyan ¹ maximum TOB constraint% 0-100 red ¹ maximum WOB constraints% 0-100 yellow ¹ minimum RPM constraints% 0-100 green ¹ up to ROP constraints% 0-100 blue ¹ unconstrained% 0 100 output of the column (260) POB-LIM (hp) output limit hp 0-100 POB (hp) Operation output level hp 0-100 output constraint columns (262) Cyan ¹ up RPM constraint% 0-100 Red ¹ maximum ROP Constraint% 0-100 Blue ¹ No constraint% 0-100 Row of operating parameters (266) RPM Rotary RPM rpm 50-150 WOB (lb) Weight on bit lb 0-50,000 Cost ($ / ft) ) Per foot $ / ft 0-100 Drilling cost ROP (ft / hr) Instantaneous drilling speed ft / hr 0-200 ROP-AVG Average drilling speed ft / hr 0-200 (ft / hr) Notes ¹ : The colors shown for the columns are represented by their respective shadings, as shown in FIG. Depth, log data, lithology, porosity As shown in FIG. 4, the depth of the formation 206 is represented in numerical form. The log data 208 is represented in the form of a curve and includes any log data that is sensitive to lithology and porosity.
Including suites. The lithology 210 is represented in the form of a percentage graph for use in identifying different types of rock in a given formation, wherein the percentage graph is derived from any log suite that is sensitive to lithology. FIG. 5 illustrates the percentage of each type of rock at a given depth, as determined. In one embodiment, the lithology percentage graph is color coded. Porosity 212 is represented in the form of a curve and is determined from any log suite that is responsive to porosity. On the display 200 of the rock strength diagram 4, the rock strength 214 is represented by a curve display 2.
16, represented by at least one form selected from the group consisting of a percentage graph display (not shown, but similar to 210), and a band display 218.
The curve display 216 of the rock strength indicates the confined rock strength 220
And unconfined rock strength 222. The area 224 between the respective curves of the confined rock strength 220 and the unconfined rock strength 222 is shown graphically, which represents an increase in rock strength as a result of the confining stress. The rock strength band display 218 displays a discrete range of rock strength at a given depth.
e) providing a graphical illustration showing e), and more generally showing various discrete ranges of rock strength along a given drill hole; In a preferred embodiment, the rock strength band indicator 218 is color coded, a first color representing a soft rock strength range, a second color representing a hard rock strength range, and an additional representing one or more neutral rock strength ranges. Including the color. Furthermore, blue can be used to indicate soft rock strength ranges, red to hard rocky strength ranges, and yellow to neutral rock strength ranges. Legend 226 is provided on the display to help interpret the various displayed geological features and predicted drilling mechanics. On the display 200 of FIG. 5, the shale plasticity 228 is represented by a curve display 230, a percentage graph display (not shown,
0) and at least one display form selected from the group consisting of the band display 232. The curve display 230 of the shale plasticity 228 shows the moisture content,
It includes at least two curves of shale plasticity parameters selected from the group consisting of clay type and clay volume, wherein shale plasticity is determined according to a defined shale plasticity model 150 (FIG. 3), moisture content, clay type, and Determined from clay volume. Further, it is preferable that the display of the shale plasticity is color-coded. The band representation 232 of shale plasticity 228 provides a graphical illustration showing the individual extent of shale plasticity at a given depth, and more generally, various individual shale plasticity along a given drill hole. Indicates the range. In a preferred embodiment, band representation 232 of shale plasticity 228 is color coded to represent a first color representing a low shale plasticity range, a second color representing a high shale plasticity range, and one or more intermediate shale plasticity ranges. Includes additional colors. Furthermore, blue can be used to indicate a low shale plastic range, red to indicate a high shale plastic range, and yellow to indicate an intermediate shale plastic range. As described above, legend 226 on display 200 is provided to assist in interpreting the various displayed geological features and predicted drilling mechanics. Bit Work / Wear Related Bit wear 234 is defined bit wear model 15
6 (FIG. 3) as a function of the cumulative work performed. The bit wear 234 on the display 200 of FIG.
Is represented in at least one display form selected from the group consisting of a curve display 236 and a percentage graph display 238. Bit wear curve representation 236 includes bit work, expressed as a specific energy level at the bit,
Includes the cumulative work done by the bit and any work losses due to grinding. With respect to the percentage graph representation, the bit wear 234 can be represented as a percentage graph 238 that is graphically illustrated to indicate the bit wear state at a given depth. In the preferred embodiment, the percentage graph 238, which is illustrated graphically in bit wear, is color coded and includes a first color 240 representing expired bit life and a second color 242 representing remaining bit life. Furthermore, the first
Is preferably red, and the second color is preferably green. Mechanical Efficiency Bit mechanical efficiency is determined as a function of torque / weight on bit sine for a given bit, according to a prescribed mechanical efficiency model 152 (FIG. 3).
On the display 200 of FIG. 5, the bit mechanical efficiency 244
Is represented in at least one display form selected from the group consisting of a curve display 246 and a percentage graph display 248. Curve display of bit mechanical efficiency 246
Includes the total torque (TOB (ft · lb)) and the cutting torque (TOB-CUT (ft · lb)) at the bit.
Bit mechanical efficiency 244 percentage graph display 24
8 graphically illustrates the total torque, where the total torque includes the cutting torque and friction torque components. In a preferred embodiment, the percentage graph 248 illustrated graphically in mechanical efficiency is color coded, a first color illustrating cutting torque 250, a second color illustrating non-frictional unlimited torque 252, and a friction color. Includes a third color to illustrate the limited torque 254. Legend 226
Are provided to help interpret the various torque components of mechanical efficiency. Furthermore, it is preferable that the first color is blue, the second color is yellow, and the third color is red.

In addition to the curve representation 246 and the percentage graph 248, the mechanical efficiency 244 is further represented in the form of a percentage graph 256 illustrating constraints on the drilling system operation that adversely affect the mechanical efficiency. Drilling system operational constraints include friction limited torque (eg, as illustrated by reference numeral 254 in percentage graph 248).
Corresponding to the constraint that causes the occurrence of
56 shows the corresponding percentage of impact each constraint exerts on the torque limited component of mechanical efficiency friction at a given depth. Drilling system operational constraints include maximum torque on bit (TOB), maximum weight on bit (WOB), minimum number of revolutions per minute (RPM), maximum drilling speed (ROP), any combination thereof. And unrestricted states. In a preferred embodiment, the percentage graphical representation 256 for drilling system operational constraints related to mechanical efficiency is color coded and includes different colors to identify different constraints. Additionally, a legend 226 is provided to help interpret various drilling system operational constraints on mechanical efficiency with respect to the percentage graph display 256. Output On the display 200 of FIG.
And at least one display form selected from the group consisting of the percentage graph display 262. Output 2
Curve display 260 for 58 is output limit (POB-L
IM (hp)) and operation output level (POB (hp))
including. The power limit (POB-LIM (hp)) corresponds to the maximum power to be applied to a bit. The operation output level (POB (hp)) is a restricted operation output level,
It includes at least one selected from the group consisting of a recommended operation output level and a predicted operation output level. Regarding the curve display 260, the output restriction (POB-L
IM (hp)) and operation output level (POB (hp))
The difference between the curves indicates the constraint.

The output 258 is further represented in the form of a percentage graph display 262 illustrating constraints on the drilling system operation that adversely affect the output. The operational constraints of the drilling system correspond to the constraints that result in power loss. The output constraint percentage graph 262 shows the percentage of corresponding impact each constraint has on the output at a given depth. In a preferred embodiment, the percentage graphical representation 262 of the drilling system operational constraints on output are color coded and include different colors to identify different constraints. In addition, red is the maximum ROP
Blue to identify the maximum RPM,
Preferably, dark blue is used to identify unrestricted conditions. Further, a legend 226 is provided to help interpret various drilling system operational constraints on output with respect to the percentage graph display 262. Operation Parameters As shown in FIG. 6, the operation parameters 264 are represented in the form of a curve display 266. As described above, the operating parameters are weight on bit, rotary rp
m (the number of revolutions per minute), cost, drilling speed, and torque.
Further, the excavation speed includes an instantaneous excavation speed (ROP) and an average excavation speed (ROP-AVG). The bit selection / recommendation display 200 also provides a means for generating a display 268 for details of a proposed or recommended drilling facility. That is, the details of the proposed or recommended drilling equipment are:
Geological features 202 and predicted drilling mechanics 20
4 is displayed on the display 200. The proposed or recommended drilling equipment preferably comprises at least one bit used to predict the performance of the drilling system. Furthermore, it is recommended that first and second bit selections, indicated by reference numerals 270 and 272, respectively, be used with the expected performance for drilling a drill hole. The first and second bit selections are identified by first and second identifiers 276 and 278, respectively. Also, the first and second identifiers 276 and 278 are displayed in addition to the geological feature 202 and the predicted drilling mechanics 204, respectively, where the first and second identifiers are positioned on the display 200. Is selected to match the portion of expected performance to which the first and second bit selections respectively apply. Furthermore, the display may include an illustration of each recommended bit selection and corresponding bit specification. Dashed Line Referring still to FIG. 6, the display 200 further includes a change bit selection indicator 280. A bit selection change indicator 280 is provided to indicate that a change in bit selection from the first recommended bit selection 270 to the second recommended bit selection 272 is required at a predetermined depth. You. The change bit selection indicator 280 is preferably displayed on the display 200 in addition to the geological feature 202 and the predicted drilling mechanics 204.

Thus, the method and apparatus of the present disclosure advantageously allow optimization of the drilling system and its use within the drilling program to be obtained early in the drilling program. Further, the method and apparatus facilitate early and appropriate improvements in the drilling program. Any economic benefits resulting from improvements made early in the drilling program are multiplied by the number of remaining drill holes drilled in the drilling program to provide a benefit. Significant and substantial savings are advantageously achieved for the company commissioning the drilling program. In addition, measurements are made during the drilling of each drill hole throughout the drilling program by the method and apparatus of the present invention to verify that the particular drilling system equipment is being optimized and used. Further, the performance of drilling system equipment can be more easily monitored using the methods and apparatus of the present disclosure, and also to identify potential adverse conditions before they actually occur. Can be done.

Furthermore, the use of the present method and apparatus advantageously reduces the time required to obtain a successful drilling operation in which a given oil production drill hole of a plurality of wells is provided online. Thus, the method and apparatus of the present disclosure increase work efficiency. Furthermore, the use of the present method and apparatus is particularly advantageous for development projects, for example establishing 100 wells over a three year period at a given geographical location. In the present method and apparatus, for example, a predetermined oil well can be completed and placed on a line in about 30 days, compared to 60 days (or longer) if the previous method is used. It can be a product with. The increased efficiency of the drilling performance of the drilling system in accordance with the present disclosure allows for time gains on oil production, which in turn translates into millions of dollars of oil products that can be marketed earlier. . Alternatively, using the method and apparatus, one or more additional wells can be completed in a given time period, more than the number of oil wells that would be completed using the previous method in the same time period. . In other words, drilling a new well in less time is advantageously converted to a marketable product earlier.

The present embodiment provides an evaluation of various proposed drilling equipment, as well as the use of a drilling program, before and during the actual drilling of a drill hole in a given formation. The selection and use of drilling equipment can be optimized for a particular section or sections of drill holes (or sections) within a given formation. The drilling mechanics model takes into account the effect of progressive bit wear due to changes in rock quality,
Benefit. The recommended operating parameters reflect the state of wear of the bit in the particular lithology and also take into account the operational constraints of the particular drilling equipment used. The geological features per unit depth and the predicted drilling mechanics printout or display for a given formation may be:
It is very useful for drilling operators and provides important information that is used in particular for optimizing the drilling process of the drilling program. The printout or display further advantageously provides a head-up view of expected drilling conditions and recommended operating parameters.

The present embodiment provides a number of complex and critical information to be communicated in a clear form, for example in the form of a graph as illustrated and described herein with reference to FIG. In addition, the use of colors in the form of graphs emphasizes important information. Furthermore, display 200
Advantageously provides a roadmap for the piercer. For example, having the display as a guide helps the driller decide when to pull a given bit. The display also provides information regarding the impact of operational constraints on performance and drilling mechanics. Furthermore,
The display assists in selecting recommended operating parameters. The use of indications results in a more efficient and safe perforation. The most useful thing is that important information is clearly communicated. Real-Time Aspects According to another embodiment of the present disclosure, the device 50 (FIG. 1) includes a real-time aspect as described above in the text and as described further below. In particular, computers
The controller 52 is responsive to a predicted drilling mechanics output signal for controlling control parameters in drilling a drill hole in the drilling system. The control parameters include at least one of the following parameters: weight on bit, rpm, pump flow, and water pressure. Further, as described herein, the controller 52, the logging instrument 16, the measurement device processor 44, and other suitable devices may be used to obtain at least one measurement parameter in real time during drilling of a drill hole. used.

The computer controller 52 further includes means for comparing the back calculated value of the measurement parameter with the measurement parameter. In particular, the back-calculated value of the measurement parameter is a function of the drilling mechanics model and at least one control parameter. In response to the defined deviation between the measured parameter and the back-calculated value of the measured parameter, the controller 52 may: a) adjust the drilling mechanics model; b) modify the control of the control parameter; Alternatively, at least one of c) performing a warning operation is performed.

According to another embodiment of the present disclosure, a method and apparatus for predicting the performance of a drilling system measures defined real-time drilling parameters during drilling of a drill hole in a given formation. Means. The drilling parameters can be obtained during drilling of the drill hole using a commercially available measuring device (such as a MWD device) suitable for obtaining predetermined real-time parameters. Further, the drilling system device operates in a defined real-time mode for comparing predetermined real-time drilling parameters with corresponding predicted parameters. Therefore, this embodiment can be used only once, repeatedly,
Or, in a periodic manner, facilitate one or more modes of operation, either alone or in combination. The operation mode is
For example, it includes a prediction mode, a calibration mode, an optimization mode, and a real-time control mode.

In yet another embodiment of the present disclosure, computer controller 52 is programmed to perform real-time functions as described herein using programming techniques well known in the art. Computer disk or other medium for transmitting computer readable code (e.g., worldwide computer
(Eg, network, satellite communications, etc.), including computer-readable media having stored thereon computer-readable media.
Have a program. The computer program for execution by computer controller 52 is similar to that disclosed earlier and has the capability of additional real-time capabilities.

For real-time capabilities, the computer program includes instructions for controlling control parameters in drilling a drill hole in a drilling system in response to an expected drilling mechanics output signal, and the control parameters. Includes at least one selected from the group consisting of weight on bit, rpm, pump flow rate, and water pressure. The computer program also includes instructions for obtaining measurement parameters in real time during drilling of a drill hole. Finally, the computer program includes instructions for performing a historical match between the measured parameter and the back calculated value of the measured parameter, wherein the back calculated value of the measured parameter includes the drilling mechanics model and at least one control parameter. And at least one function selected from the group consisting of: Further instructions for controlling the control parameters include: a) adjusting the drilling mechanics model according to the defined deviation between the measured parameters and the back-calculated values of the measured parameters; b) controlling the control parameters. Modifying, or c) performing an alert operation.

In one embodiment of the drilling prediction analysis system, the system looks at the actual data accumulated during drilling of the drill hole and compares the predictions and actual data produced in the corresponding planning stages. To perform history matching. Depending on the results of the history matching, some factors (eg, basic assumptions) of the drilling mechanics prediction model need to be adjusted to better match the predicted performance to the actual performance. These adjustments can be attributed to various factors relating to the geological environment specific to a particular geographic region, and how that environment interfaces with a particular bit design.

As mentioned, the real-time aspects of this embodiment include performing a comparison of predicted performance with actual parameters while a drill hole is being drilled. By having a real-time aspect, this embodiment has one drawback of end-of-job analysis, namely that, along with end-of-job analysis, "learned lessons" can only be applied to subsequent drill holes. Overcome the shortcomings. In contrast,
By having the real-time aspects of this embodiment, any adjustments required for the drilling mechanics prediction model (applicable to drilled holes) can be made and the drilling process for a particular drill hole Other adjustments may be made as appropriate to better optimize.
Further, the real-time aspect accelerates the learning curve for the drill hole (s) at a given site, and the optimization process corresponding to each drill hole. All of these advantages do not rely on using bits as a measurement tool, as described further below in the text. Real-Time Optimization Referring now to FIG. 7, a display 300 for the prediction performance of a drilling system for a given formation, in accordance with an embodiment of the present disclosure, includes the drilling prediction analysis and control of FIG. 1 previously described herein. Shown in connection with system 50. Display 300 includes a plot of data against depth,
The data includes depth 302, log data 304, lithology 306, porosity 308, rock strength 310, bit wear 3
12 and operation parameters 314. The data displayed for each respective plot is obtained as described earlier in the text with respect to FIGS. 1-6 and as described below.

The first area 316 of the display 300
Is characterized by information and data relating to each depth above the depth position of the MWD sensor. First
Such information in the region 316 is considered to be essentially accurate as if the data was collected and analyzed after the work was completed. Therefore, the first area 3
The 16 data often looks like a "calibration mode" for the end-of-job case. The solid line 318 in the operational parameters column 314 shows the actual ROP, and the dashed line 320 shows the ROP Represents what was predicted for

In the “end-of-job” mode, the drilling prediction analysis and control system needs to evaluate the accuracy of the prediction model for a given drill hole and to make adjustments to subsequent drill holes at a particular site or area. To do so, the predicted RO
Compare P with the actual ROP. Real-time (RT)
Because of the job, close history matching is achieved and the drilling prediction analysis and control system 50 until the predictive model indicates that it is working well in the given environment.
(FIG. 1) makes adjustments in the initial drilling stage for the bit operating in a given drill hole. Therefore, the drilling prediction analysis and control system is in a position to successfully predict future ROP, assuming that there is good offset information. A better predicted future ROP will help the drill prediction analysis and control system determine when a bit becomes dull and should be withdrawn in subsequent drill holes at a particular site. be able to. Bit as a Measurement Tool The following example deals with backcalculation of rock strength, but it is possible to perform backcalculations on different parameters as disclosed herein. Referring again to FIG. 7, the second region 326
Are characterized by information and data corresponding to respective depths in the area between the bit and the MWD sensor. Drilling parameter data (eg, WOB, RPM,
And ROP) can be measured almost instantaneously, so their data at bit depth is known. The drilling prediction analysis and control system 50 (FIG. 1) obtains a good ROP history match in the region 316 above the MWD sensor. Thus, the drilling prediction analysis and control system 50 can back-calculate any "suggested" measurement parameters from the actual drilling parameters and the resulting ROP at a given depth (s).

The "suggested" parameter is the parameter (s) that occurs in region 326, which is the interval between the depth corresponding to the bit and the depth corresponding to the MWD sensor, and thus the measurement device Has not yet traversed the interval in a given time, a "suggested" parameter cannot be calculated from the measured data. After the relevant MWD sensor data becomes available, the drilling prediction analysis and control system 50 can determine lithology and rock strength parameters therefrom. Thus, for example, the drilling prediction analysis and control system 5
A 0 can compare the log strength calculated with the log to the "indicated" rock strength. In FIG. 7, the rock strength calculated in the log is illustrated as a solid line 328. Also, the “indicated” rock strength is illustrated as dotted line 330.

The following description describes how the drilling prediction analysis and control system 50 utilizes the techniques described above to determine “hinted” parameters.
If the “bit” measurement begins to deviate from the “verify” measurement, the drilling prediction analysis and control system indicates that something went wrong in the downhole. Bits were broken or balled up, pit cleaning efficiency was problematic, drilling efficiency changed, etc. For example, until a corresponding actually measured parameter value can be derived from the log data, as available in region 316, drilling prediction analysis and control system 50 may perform any other computation. , The suggested parameter value will be used.

If good offset data is available,
The drilling prediction analysis and control system 50 can rely on it to facilitate optimization of the drilled hole being drilled. However, when drilling a survey well without any offset information, the drilling prediction analysis and control system uses "suggested" data from the drilled drill hole to optimize the drill hole.

In other words, the value of the back calculated measurement parameter is compared with the history of the measurement parameter or compared with the value of the measurement parameter. In a first example, the back-calculated measurement parameter corresponds to a value in a first section of the drill hole above the level of the MWD sensor (such as region 316 in FIG. 7). The drilling prediction analysis and control system performs history matching on the value calculated back in this first interval. This first
One reason for performing history matching in the interval is to allow the drilling prediction analysis and control system to determine whether the drilling mechanics model (s) is operating properly.

In the first interval, for any deviation greater than the specified amount in the history matching comparison, the drilling analysis and control system may determine whether the drilling mechanics model is suitable for generating predicted drilling mechanics. Make the necessary adjustments. In particular,
Until an acceptable level of deviation is achieved (i.e., the historical collation deviation between the measured parameter and the back-calculated value of the measured parameter is within the acceptable level of deviation), the drilling prediction analysis and control system relies on the respective model. Adjust the assumptions underlying

Further, with respect to the first section, by making appropriate adjustments to one or more respective drilling mechanics models, the drilling analysis and control system can provide a drilling hole for drilling further drill holes. Improve the corresponding predictions about mechanics. In other words, the drilling analysis and control system fine-tunes the drilling mechanics model during the drilling process. In response, the drilling system modifies control of one or more control parameters based on the fine-tuned drilling mechanics model. Fine tuning helps to optimize drilling parameters as the drilling of the drill hole advances.

In a second example, in a second section of the drill hole between the MWD measuring device and the drill bit (such as area 326 in FIG. 7), the drilling prediction analysis and control system performs the first In a manner slightly different from the interval, a history comparison between the measured parameter and the back-calculated value of the measured parameter is used. One reason for performing history matching in this second section is that
This is to allow the drilling prediction analysis and control system to see the state of the bit and how the bit is interacting with the formation.

If, within the second interval, the history comparison reveals that there is a deviation greater than the specified limit, the deviation of the history comparison indicates that there is a potential problem in drilling holes by the drilling system. (Eg a bit)
Is shown. Rather, a deviation in the historical match within an acceptable range indicates that the drilling of the drill hole by the drilling system has been performed as expected. Regarding the back calculated values of the measured parameters in the second section, the back calculated values are indicated by the actual parameters (lack of geological values) in drilling a drill hole for each section.

The real-time capabilities as described herein provide a powerful addition to the capabilities of drilling prediction analysis and control systems. Accordingly, the drilling system methods and apparatus of the present disclosure operate in a defined manner to achieve a prediction mode followed by a drilling mode. The comparison between the parameters obtained in the prediction mode and the parameters obtained in the drilling mode may be modified with respect to the drilling and prediction model and drilling of a given drill hole or subsequent drill holes.
Provide valuable insight into making adjustments. The drilling system method and apparatus also examines real-time parameters against predicted parameters per unit depth (eg, predicted rock strength) and (eg, based on the underlying assumptions used in the drilling mechanics model). B) Perform drilling optimization by making appropriate adjustments.

The drilling prediction device can be placed at a different location from the actual drilling site. That is, the prediction device may be at a remote location and interface with the actual drilling site via a worldwide communication network such as the Internet or the like. The prediction device may also be at a real-time operations center (ROC), where the ROC has a satellite link or other suitable communication link to the drilling site and drilling device.

This embodiment also facilitates the use of a defined bit as a measuring device while drilling a drill hole. Such as the occurrence of changes in the compressive strength of rocks,
Along with the formation change during drilling, a corresponding change occurs in the reaction of the bit during drilling.
For example, a change in formation may cause a bit to become unbalanced, oscillate, or undergo other similar changes. The drilling system equipment monitors such changes in bit performance using an appropriate measurement device.
For example, one method for monitoring bit performance is:
Via a suitable sensor of the bit.

The bit sensor can also provide a means for mapping certain parameters of the borehole. For example, during drilling of a drill hole, the drilling system equipment can compare the measured (or actual) rock quality with the predicted rock quality as a function of the measured parameters. A suitable sensor located within the bit or closest to the bit along the drill string may be used.

[0098] The drilling system apparatus also includes a typical interdrilling measurement (MWD) sensor in which the drilling sensor is located on the drill string behind the bit. For example, MWD
The sensor is approximately 50 to 100 feet away from the bit. As a result, the measurements made by the MWD sensor are delayed behind the bit in real time during drilling of the drill hole. With respect to the parameters of bit wear, the method of the present embodiment comprises the steps of drilling a drill hole and, while drilling, the predicted bit wear parameter and the back calculated bit wear parameter (as determined from MWD measurements). Comparing. In addition, the method further comprises periodically updating the measured bit wear in relation to the expected wear and recommending appropriate adjustments to achieve overall best drilling performance. Such as strengthening of the bit wear state.
In other words, the predicted wear performance can be compared to a real-time measured parameter representing the measured bit wear performance.

The present embodiment further facilitates "real-time" optimization and calibration of virtually the same day, as compared to post-optimization and calibration for a week or more. Optimization and calibration in real time advantageously provides a positive effect on the drilling performance of the bit during drilling.
Therefore, the drilling system and method of the present embodiment is based on the comparison of the predicted drilling parameters and performance with the actual ones (or history matching), so that appropriate parameter adjustments can be made to better fit real-world scenarios. To promote.

If the difference between the actual parameter and the predicted parameter is no longer covered (ie, exceeds the specified maximum), the drilling system method and apparatus of the present embodiment operates accordingly according to the specified response. I do.
For example, in response to assessing that there is any deviation in the history match that exceeds a predetermined limit, the drilling system and method may use various parameters as a function of the result of a comparison between predicted drilling performance and actual drilling performance. To adjust. Comparison of the predicted drilling parameters with the actual ones may indicate an adverse or undesirable bit wear. Further assessment can also indicate whether the deviation is due to bit wear or some other adverse condition.

In a typical scenario, the drilling system
It operates between an automatic drilling control mode and a manual control mode. Depending on differences in history matching that exceed defined limits, embodiments of the present disclosure may perform an alert operation. The warning action includes providing an indication that something is wrong and needs attention. The system and method also cease the automatic drilling control mode and place itself in the manual control mode until the corresponding difference is resolved.

[0102] The drilling system apparatus and method may also perform an alarm operation including a suitable alarm indicator, such as a color coded indicator or other suitable indicator suitable for a given display and / or field application. . In certain warning operations, the prescribed information held on the display may be highlighted or moved in a manner that draws attention to the corresponding information.

A red indicator may be provided, for example, to indicate a possible early bit failure. Such an initial bit failure may be caused if the difference between the predicted and actual parameters is greater than a specified maximum difference. A yellow indicator may indicate a warning condition, where the difference between the predicted and actual parameters is greater than a specified minimum difference but less than a maximum difference. Finally, a green indicator may indicate an overall acceptable condition,
There, the difference between the predicted parameter and the actual parameter is less than a specified minimum difference. In a later example, the difference between the prediction and the actual is as expected, and the drilling may proceed relatively undisturbed.

The present embodiment provides a form of an alarm or an initial warning as appropriate. Thus, a real-time decision to adjust or not adjust can be made in a more informed manner than was previously possible. In addition, this embodiment provides real-time observation of drill hole drilling, for example, using a display.

The difference between the actual performance and the predicted performance of a drill bit for drilling a drill hole will be further described.
It is noted that the bit is initially in the borehole prior to the logging tool. Real-time parameters in bits are ahead of the logging tool by a predetermined amount. It is in terms of time and distance that the real-time parameters at the bit precede it, such that the time and distance correspond to the corresponding distance at which the logging tool is located away from the bit along the drill string. To
It corresponds to the time required for the logging tool to pass. In connection with an appropriate drilling mechanics model, certain measurements, such as the compressive strength of the rock being drilled by the bit, can be suggested with these real-time parameters. Other typical real-time parameters in bits include WOB, RPM, and torque.

Along with the real-time parameters and measurement information, the drilling system equipment (such as an MWD facility) can verify the bit suggestions, ie, whether the suggestions were actually there. ) Use a measuring instrument that logs while drilling. The MWD logging tool can be used to continuously verify what the bits suggest, as given by the predicted parameters and actual performance. For example, if the logging tool is sensing a parameter that is proportional to rock strength, that parameter information is sent to the drilling system predictor and analyzer for processing. The predictor and analyzer processes the pressure information by creating an indication of the true condition of the rock being drilled. If the true condition of the rock is as expected, the drilling process is allowed to proceed. If not, the drilling process is changed or modified as appropriate. Thus, the drilling prediction and analysis system can control drilling of a drill hole in a defined manner. One defined manner involves alternation between an automatic drilling control mode and a manual drilling control mode.

Another typical MWD tool includes a bit vibration measurement tool. Based on the vibration data, the drilling prediction and analysis system determines whether a given bit has been bit damaged by downhole. An inflection point in the vibration measurement tool output data indicates that a vibration level calibration or update is required. Using optimization of bit parameters based on vibration data, the drilling prediction and analysis system determines how much force a given bit can withstand without causing significant or catastrophic damage. judge. Such an analysis may include the use of performance data derived from previous bit vibration / performance considerations. As described herein, a drilling prediction and analysis system includes at least one computer-readable medium having appropriate program code for performing the functions described herein.

The present invention also relates to the diagnosis of borehole stability relationships. With appropriate depiction, borehole mapping can be performed to analyze any cracks in a given formation. The placement of cracks in the formation may affect the likelihood of drilling. Fracture or crack mapping provides some indication of the extent to which the rock will be damaged. The fracture indicates the presence of a rapid decrease in rock strength.

It is also important to take care to minimize errors. There are many unknowns. If there is no direct quantization, then it is incorrect to allocate the error to some cause. This is related to the difference between the estimate and the measurement. Various log data can be sent to the ground surface using the appropriate equipment to measure while drilling. However, while downholes have many measurements, only selected ones can be sent to the surface. Such limitations are primarily due to the inability of current technology to immediately transmit all possible measurements to the surface.

The drilling system apparatus and method of the present embodiment also utilize a bit as a measurement tool. For example, the harmonics of a bit's vibrations make it possible to use the bit as a measurement tool. The shaking data proves useful for calibration purposes. In one example of drilling a drill hole,
For specific rock quality, and WOB, torque and ROP
Bits can be specified to take into account the available data for specifying various parameters of. The method includes drilling a drill hole and monitoring ROP, observing lithology, and determining WOB as part of the process. In this example, the bit is the first measurement device to start predicting what is being drilled, and various logging tools verify the bit measurement.

The method and system apparatus further include back-calculating the parameters, thus superimposing the back-calculated parameters on the predicted parameters and evaluating what is actually happening. Then the apparatus of the method and the system
Fine-tune and / or make appropriate adjustments depending on determining what is actually happening to that bit. Thus, the use of bits as a measurement tool allows for early notification (in stages) of as much as 50-100 feet to analyze what is happening to bits downhole.

Further, using the bit as a measurement tool, it is possible to analyze whether the bit is still active (ie, can continue drilling) or other appropriate evaluation. For example, a bit measurement may indicate that a bit has done something unexpected. An MWD sensor on the drill string can verify what the bit measurement indicated. MW
Was the D-sensor faster or slower than expected? What is the appropriate action to take? Are there any obstacles? By using the bit as a sensor, the prediction and analysis system can observe and / or measure vibration to indicate whether the bit is functioning as expected. Thus, the prediction and analysis system can update the recommended drilling parameters based on what is observed using the bit as a measurement tool. Prediction and analysis devices use bits as a measurement tool (eg, looking one foot ahead of the bits).
For a look-ahead application, the parameters can be adjusted to where the punch is expected to be.

By using a bit as a measurement tool,
The prediction and analysis system can analyze rock anisotropy, directional properties, compressive strength, and / or porosity. For horizontal drill holes, the drill must advance at a 90 degree angle from the vertical plane. The porosity remains the same even when the relative tilt angle changes.

In the history match mode or the optimization mode, the MWD sensor is 50-100 feet behind the bit, at the bit, or measuring ahead of the bit. In one mode of operation, the system generates a proposal and utilizes the proposal during drilling of a drill hole. For example, the proposal may include rock quality per unit depth and expected rock strength. During drilling, the system calculates the rock strength at a given depth back,
Next, the back-calculated measure of the rock strength is passed by the measurement tool across the corresponding boundary (ie, through the formation).
Compare with the information that is made available. Thereafter, the system performs a historical match with the predicted rock strength and the actual rock strength. Following the history match, the system makes the appropriate parameter adjustment (s).

The system performs a historical match to verify or determine that the drilling system is responding as expected at the bit. The system further operates in a real-time mode utilizing the display mechanics and the back-calculated (predicted) value of the available rock strength. When the sensor passes near the predetermined depth,
The system calculates the rock strength (or porosity) parameter of the compression. A mud logger is used, with a comparison between measured rock strength and predicted rock strength calibration,
The mud logger there is properly calibrated prior to use.

As described herein, the drilling prediction analysis and control system utilizes data that is close to bits. Therefore, the system and method make any previous uncertainties much smaller. This is an advance in drilling holes. Based on experience, it is common for unexpected geological scenarios to occur at offset wells.

According to this embodiment, real-time is characterized by the disappearance of the time between the time when the data is acquired downhole and the time when the data becomes available to the drilling operator at a given moment. Can be done. That is, how long it takes for the drilling operator to obtain the data (2 weeks vs. 1 day). The real-time aspects of the drilling prediction analysis and control system allow the system to determine what the bits are doing in a short amount of time, determine what needs to be adjusted, and the modified WOB , RPM, or other suitable operating parameters in real time.

Regarding bit wear, the drilling analysis and control system includes a bit wear indicator. The bit wear indicator is characterized in that as the bit wears, different signs or acoustic signals are generated for different states of bit wear. The system also includes the ability to measure, via a suitable measuring device, a sign or acoustic signal to determine a measure of the wear state of the bit.

As described herein, operating parameters include at least one predicted RPM, WOB, cost, ROP, and ROP-AVG. These predicted operating parameters are displayed on the display output of the drilling prediction analysis and control system 50 of FIG. The measurement parameters can include any parameters related to drilling of a drill hole measured in real time or obtained (eg, by appropriate calculations). The measurement parameters can include one or more operational parameters. Control parameters include any parameters that are supposed to be modified or controlled, either manually or via automatic control, to affect or change the drilling of the drill hole. be able to. For example, the control parameters include one or more operating parameters that are directly (or indirectly) controlled.

[0120] Only a few exemplary embodiments of the invention are:
Although described in detail above, those skilled in the art will readily appreciate that many modifications are possible in typical embodiments without departing significantly from the novel teachings and advantages of the present invention. Will be understood. Accordingly, all such modifications are intended to be included within the scope of the present invention as defined in the following claims. In the claims, the provisions for means and functions are intended to cover not only the structures described herein as performing the recited function, but also structural equivalents, as well as equivalent structures. You.

[Brief description of the drawings]

FIG. 1 illustrates a drilling system that includes an apparatus for predicting the performance of a drilling system for drilling drill hole (s) according to a defined drilling program in a given formation.

FIG. 2 is a drilling system for drilling drill hole (s) according to a defined drilling program in a given formation and a method for optimizing the use thereof, further comprising a drilling system. 2 illustrates a method, including prediction of the performance of

FIG. 3 illustrates a geological model and a drilling mechanics model for use in an embodiment of the method and apparatus for predicting drilling performance of the present disclosure.

FIG. 4 illustrates one example of displaying predicted performance for a drilling system for a given formation in accordance with the methods and apparatus of the present disclosure.

FIG. 5 illustrates one example of displaying predicted performance for a drilling system for a given formation in accordance with the methods and apparatus of the present disclosure.

FIG. 6 illustrates one example of displaying predicted performance for a drilling system for a given formation in accordance with the methods and apparatus of the present disclosure.

FIG. 7 illustrates an example of an exemplary display of parameters and real-time aspects of a drilling prediction analysis and control system of the present disclosure.

[Explanation of symbols]

 Reference Signs List 12 drilling device 14 borehole 16 logging tool 18 sub 20 drill string 22 drill bit 24 formation 26 drilling muddy water 28 mud reservoir 30 wellhead 32 annular space 34 metal casing 36 side wall 38 pump system 40 muddy water supply line 42 fluid discharge duct 70 down Hall motor 72 Top drive motor 74 Rotary table motor

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[Procedure amendment]

[Submission date] November 1, 2001 (2001.11.
1)

[Procedure amendment 1]

[Document name to be amended] Drawing

[Correction target item name] All figures

[Correction method] Change

[Correction contents]

FIG.

FIG. 3

FIG. 4

FIG. 5

FIG. 2

FIG. 6

FIG. 7

 ────────────────────────────────────────────────── ─── Continuation of the front page (72) Inventor Oliver Matthews, The Third 77379, Texas, USA, Spring River, Peace River Drive 6822 (72) Inventor Willium W. King, Houston 77069, Texas, USA, Houston , Paradise Valley Drive 13836 (72) Inventor Gary E. Weaver 77385, Texas, United States, Stroller, Laura Lane 315 (72) Inventor Gerald El Pruit, United States 77339, Texas, Houston, Riverlow Drive 2054

Claims (50)

[Claims] An apparatus for predicting the performance of a drilling system for drilling a drill hole in a predetermined formation, wherein the apparatus generates geological features of the formation per unit depth according to a defined geological model. Means for outputting a signal representative of a geological feature, wherein the geological feature includes at least rock strength, and a specification of a drilling facility proposed for use in drilling a drill hole. Means for inputting, wherein the specification comprises a bit specification of at least one of the recommended drill bits, and wherein the specification is proposed as a function of a geological feature per unit depth according to a drilling mechanics model. Means for determining a predicted drilling mechanics according to the specifications of the drilling equipment, and outputting a signal representing the predicted drilling mechanics, Means, wherein the predicted drilling mechanics comprises at least one selected from the group consisting of bit wear, mechanical efficiency, power, and operating parameters; and control parameters for drilling a drill hole with a drilling system. Means responsive to a predicted drilling mechanics output signal for controlling, wherein said control parameter comprises:
Means including at least one selected from the group consisting of weight on bit, rpm, pump flow rate, and water pressure; means for obtaining a measurement parameter in real time during drilling of the drill hole; measuring the measurement parameter Means for historical matching with the back calculated value of the parameter, wherein the back calculated value of the measured parameter is a function of the drilling mechanics model and at least one control parameter, and the back calculated value of the measured parameter and the measured parameter In response to a defined deviation between the control means: a) drilling mechanics
Means for performing at least one selected from the group consisting of adjusting the model, b) modifying the control of the control parameters, and c) performing an alert operation. Equipment to do. 2. The apparatus of claim 1, further comprising: an output signal of the geological feature and a predicted drilling mechanic for generating an indication of the geological feature per unit depth and the predicted drilling mechanics. Means responsive to the output signal of the source. 3. The apparatus of claim 2, wherein the means for generating the display comprises at least one selected from the group consisting of: a) a display monitor, and b) a printer, and per unit depth. Wherein the display of the geological characteristics and the predicted drilling mechanics of the device comprises a printout. 4. The apparatus of claim 1, wherein the means for generating geological features further comprises at least one additional selected from the group consisting of log data, lithology, porosity, and shale plasticity. An apparatus for generating a feature. 5. The apparatus of claim 1, wherein the means for inputting specifications of the proposed drilling equipment further comprises a downhole motor, a top drive motor, a rotary table motor, a mud system, and a mud pump. An apparatus comprising entering additional specifications for at least one proposed drilling facility selected from the group consisting of: 6. The apparatus of claim 1, wherein the operating parameters are at least one selected from the group consisting of weight on bit, rotary rpm (rotation per minute), cost, drilling speed, and torque. An apparatus comprising: 7. The apparatus according to claim 6, further comprising:
The apparatus wherein the digging speed comprises an instantaneous digging speed (ROP) and an average digging speed (ROP-AVG). 8. The apparatus of claim 2, wherein the representation of the geological feature comprises at least one graphical representation selected from the group consisting of a curve representation, a percentage graph representation, and a band representation. The display of perforation mechanics is curved,
An apparatus comprising: a percentage graphical representation; and at least one graphical representation selected from a group consisting of a band representation. 9. The apparatus of claim 8, wherein the means for generating the display comprises: a) a display monitor and b).
At least one selected from the group consisting of printers
And an indication of geological features and predicted drilling mechanics per unit depth includes a printout. 10. The apparatus of claim 8, further comprising: at least one graphical representation of the geological feature and at least one graphical representation of the predicted drilling mechanics are color coded. 11. The apparatus of claim 8, wherein the rock strength is represented in at least one display format selected from the group consisting of a curve display, a percentage graph display, and a band display, wherein the curve display of the rock strength is , Including the confined rock strength and the unconfined rock strength, and the area between the respective curves of the confined rock strength and the unconfined rock strength is
Graphically illustrating the increase in rock strength as a result of confinement stress, wherein said band representation of rock strength provides a graphical illustration of discrete ranges of rock strength at a given depth; Further, the rock strength band representation is coded, a first code representing a soft rock strength range, a second code representing a hard rock strength range, and an additional code representing one or more neutral rock strength ranges. An apparatus comprising: 12. The apparatus of claim 8, wherein said means for generating geological features further comprises at least one additional member selected from the group consisting of log data, lithology, porosity, and shale plasticity. Generating a feature, wherein the operating parameters are weight on bit, bit rpm
An apparatus comprising at least one selected from the group consisting of (rotations per minute), cost, drilling speed, and torque. 13. The apparatus according to claim 12, wherein the log data is represented in a curve display format, and the log data is displayed.
The data includes any log suite susceptible to lithology and porosity, wherein the lithology is represented in the form of a percentage graph for use in identifying different types of rock in a given formation, wherein the percentage The graph shows the percentage of each type of rock at a given depth, the porosity is represented in the form of a curve, and the shale plasticity is at least selected from the group consisting of a curve, a percentage graph, and a band. 1
The shale plasticity curve is expressed in two display formats: moisture content, clay type,
And at least one shale plasticity parameter curve selected from the group consisting of: The band representation of the shale plastics provides a graphical illustration of a discrete range of shale plastics at a given depth, and further, the band representation of the shale plastics comprises:
A first code coded to represent a low shale plastic range, a second code representing a high shale plastic range, and 1
Apparatus characterized in that it comprises an additional code representing one or more neutral shale plastic ranges. 14. The apparatus according to claim 8, wherein the bit wear is determined as a function of the cumulative work performed according to a defined bit wear model and is selected from at least one of a group consisting of a curve representation and a percentage graphical representation. Represented in one display form, wherein the curve representation of bit wear can include bit work expressed as a specific energy level at the bit, cumulative work done by the bit, and optional work loss due to grinding; The percentage graph display indicates a bit wear condition at a predetermined depth, and a percentage graph of the bit wear is coded, wherein a first code representing expired bit life and a second code representing remaining bit life. An apparatus comprising: 15. The apparatus of claim 8, wherein the bit mechanical efficiency is determined as a function of torque / weight sine on bit for a given bit according to a defined mechanical efficiency model, and wherein the bit mechanical efficiency is determined from a curve display and a percentage graph display. Wherein the curve representation of the bit mechanical efficiency includes the total torque and the cutting torque at the bit, and the percentage graphical representation of the bit mechanical efficiency is represented by a graphical formula. Wherein the total torque includes the cutting torque and friction torque components, and wherein the percentage graph of bit mechanical efficiency is coded and the first code representing the cutting torque, friction unrestricted. A second code representing torque and a torque limited friction Apparatus characterized by comprising a third code. 16. The apparatus of claim 15, wherein the mechanical efficiency is further represented in the form of a percentage graph illustrating constraints on the drilling system operation that adversely affect the mechanical efficiency, wherein the constraint on drilling system operation is frictional. Corresponding to the constraints that cause the generation of the limited torque, the percentage graph further shows that each constraint gives the corresponding percentage of impact on the mechanically efficient friction limited torque component at a given depth. The operational constraints of the drilling system are: maximum torque on bit (TOB), maximum weight on bit (WOB), minimum and maximum bits per minute (RPM), maximum drilling speed (ROP), Any combination of these, and unrestricted conditions, can be included, as well as constraints on drilling system operation related to mechanical efficiency. Percentage graph display is coded, and wherein the including different codes for identifying different constraints. 17. The apparatus of claim 8, wherein the output is represented in at least one display format selected from the group consisting of a curve display and a percentage graph display, wherein the curve display for the output includes output limiting and manipulating. An output level, wherein the output limit corresponds to a maximum output to be applied to the bit, and the operation output level is determined from a limited operation output level, a recommended operation output level, and a predicted operation output level. The at least one selected from the group consisting of: wherein the percentage graphical representation of output illustrates a drilling system operating constraint that adversely affects the output, wherein the drilling system operating constraint results in power loss. The percentage graphs of the output constraints, which correspond to the constraints, further define the percentage of the corresponding impact that each constraint has on the output at a given depth. And, further, the percentage graphical representation of drilling system operating constraints related output is coded, characterized in that it comprises a different code to identify the different constraints device. 18. The apparatus of claim 2, further comprising: in addition to the geological features and predicted drilling mechanics,
Means for generating an indication of details of a proposed drilling facility, said proposed drilling facility comprising at least one recommended bit selection used to predict performance of a drilling system. An apparatus comprising: 19. The apparatus according to claim 18, wherein:
And the second bit selection is recommended to be used with expected performance for drilling a drill hole, and further wherein the first and second bit selections are first and second respectively.
Wherein the first and second identifiers are displayed along with geological features and predicted drilling mechanics, and further wherein positioning of the first and second identifiers on the display comprises: Apparatus characterized in that the first and second bit selections are each selected to match a portion of expected performance to which they apply. 20. The apparatus of claim 2, further comprising: changing the bit selection from the first recommended bit selection to the second recommended bit selection at a predetermined depth. A change indicator of bit selection to indicate on the display of geological features and predicted drilling mechanics. 21. A method for predicting the performance of a drilling system for drilling a drill hole in a predetermined formation, comprising: generating a geological feature of the formation per unit depth according to a defined geological model; Outputting a signal representative of a geological feature, wherein the geological feature includes at least rock strength; and obtaining specifications of a proposed drilling facility for use in drilling a drill hole. Wherein said specification comprises at least one bit specification of a recommended drill bit, wherein the step comprises: a specification of the proposed drilling equipment as a function of the geological feature per unit depth according to the drilling mechanics model. And determining a predicted drilling mechanics accordingly and outputting a signal representing said predicted drilling mechanics. Responsive to the predicted drilling mechanics output signal, wherein the predicted drilling mechanics includes at least one selected from the group consisting of bit wear, mechanical efficiency, power, and operating parameters. Controlling a control parameter when drilling a drill hole with the drilling system, wherein the control parameter includes at least one selected from the group consisting of weight on bit, rpm, pump flow rate, and water pressure. Obtaining a measurement parameter in real time during drilling of a drill hole; and comparing the measurement parameter with a back calculated value of the measurement parameter in the history, wherein the back calculated value of the measurement parameter is a drilling mechanics model and Select from a group consisting of at least one control parameter Responsive to a defined deviation between the measured parameter and the back-calculated value of the measured parameter, the controlling step further comprises: a) adjusting the drilling mechanics model; b) modifying the control of the control parameter; and c) performing an alert operation, for performing at least one selected from the group consisting of: Method. 22. The method of claim 21, further comprising the step of: determining the geological feature per unit depth and the predicted drilling mechanics in response to the output signal of the geological feature and the predicted drilling mechanics output signal. Generating a representation of the image. 23. The method of claim 22, wherein generating a display comprises using at least one selected from the group consisting of: a) a display monitor; and b) a printer, and the unit. A method wherein the display of geological features per depth and predicted drilling mechanics comprises a printout. 24. The method of claim 21, wherein the step of generating geological features comprises at least one additional feature selected from the group consisting of log data, lithology, porosity, and shale plasticity. A method comprising the step of generating. 25. The method of claim 21, wherein obtaining the input specifications of the proposed drilling equipment further comprises: a downhole motor, a top drive motor,
Obtaining a further specification of at least one proposed drilling facility selected from the group consisting of a rotary table motor, a mud system and a mud pump. 26. The method of claim 21, wherein the operating parameter is at least one selected from the group consisting of weight on bit, bit rpm (rotation per minute), cost, drilling speed, and torque. A method comprising: 27. The method of claim 26, wherein the drilling speed further comprises an instantaneous speed of drilling (ROP) and an average speed of drilling (ROP-AVG). 28. The method of claim 22, wherein displaying a geological feature includes displaying at least one graphical representation selected from the group consisting of a curve representation, a percentage graph representation, and a band representation. Displaying the predicted drilling mechanics comprises displaying at least one graphical representation selected from the group consisting of a curve representation, a percentage graphical representation, and a band representation. 29. The method of claim 28, wherein generating a display comprises using at least one selected from the group consisting of: a) a display monitor and b) a printer; A method wherein the display of the hit geological feature and the predicted drilling mechanics comprises a printout. 30. The method of claim 28, further comprising at least one graphical representation of said geological feature and at least one graphical representation of said predicted drilling mechanics being color coded. Features method. 31. The method of claim 28, wherein the rock strength is represented in at least one display format selected from the group consisting of a curve display, a percentage graph display, and a band display, wherein the curve display of rock strength is The area between the confined rock strength and the unconfined rock strength curves, including the confined rock strength and the unconfined rock strength, is graphically illustrated, representing the increase in rock strength as a result of the confined stress, and Wherein the band representation of rock strength provides a graphical illustration of a discrete range of rock strength at a given depth, and wherein the band representation of rock strength is coded to indicate a soft rock strength range. A first code representing a hard rock strength range and an additional code representing one or more neutral rock strength ranges. Law. 32. The method of claim 28, wherein the step of generating a geological feature further comprises at least one additional selected from the group consisting of log data, lithology, porosity, and shale plasticity. Generating a feature, and wherein the operating parameters are weight on bit, bit rpm
(Revolutions per minute), cost, drilling speed, and at least one selected from the group consisting of torque. 33. The method of claim 32, wherein the log data is represented in the form of a curve display, and wherein the log data is
The data includes any log suite susceptible to lithology and porosity, wherein the lithology is represented in the form of a percentage graph for use in identifying different types of rock in a given formation, wherein the percentage A graph shows the percentage of each type of rock at a given depth, the porosity is represented in the form of a curve, and the shale plasticity is selected from the group consisting of a curve, a percentage graph, and a band. At least one
The shale plasticity curve is expressed in two display formats: moisture content, clay type,
And at least one shale plasticity parameter curve selected from the group consisting of: And wherein said band representation of said shale plastics provides a graphical illustration of a discrete range of shale plasticity at a predetermined depth, and further comprising said band representation of said shale plasticity,
A first code coded to represent a low shale plastic range, a second code representing a high shale plastic range, and 1
A method comprising including an additional code representing one or more neutral shale plastic ranges. 34. The method of claim 28, wherein the bit wear is determined as a function of cumulative work performed according to a defined bit wear model and is selected from at least one of a group consisting of a curve representation and a percentage graphical representation. Represented in one display form, wherein the curve representation of bit wear can include bit work expressed as a specific energy level at the bit, cumulative work done by the bit, and optional work loss due to grinding; The percentage graph display indicates a bit wear state at a predetermined depth, and the percentage graph display of the bit wear is coded, and a first code representing an expired bit life and a second code representing a remaining bit life. 2. A method comprising: 35. The method of claim 28, wherein the bit mechanical efficiency is determined as a function of torque / weight sine on bit for a given bit according to a defined mechanical efficiency model, and from a curve display and a percentage graph display. At least one selected from the group consisting of
The curve representation of bit mechanical efficiency includes the total torque at the bit and the cutting torque, and the percentage graphical representation of bit mechanical efficiency illustrates the total torque graphically. Wherein the total torque includes the cutting torque and friction torque components, and wherein the percentage graph of bit mechanical efficiency is coded;
A method comprising: a first code representing cutting torque, a second code representing non-friction limited torque, and a third code representing friction limited torque. 36. The method of claim 35, wherein the mechanical efficiency is further represented in the form of a percentage graph illustrating constraints on the drilling system operation that adversely affect the mechanical efficiency, wherein the constraint on drilling system operation is frictional. Corresponding to the constraints that cause the generation of a limited torque, the percentage graph further shows that each constraint represents a corresponding percentage of impact on the mechanically efficient friction limited torque component at a given depth. The operational constraints of the drilling system are: maximum torque on bit (TOB), maximum weight on bit (WOB), minimum and maximum revolutions per minute (RPM), maximum drilling speed (RO).
P), any combination thereof, and unrestricted conditions;
Wherein the percentage graphical representation of drilling system operational constraints related to mechanical efficiency is coded and includes different codes to identify different constraints. 37. The method of claim 28, wherein the output is represented in at least one display format selected from the group consisting of a curve display and a percentage graph display, wherein the curve display for the output is power limiting and manipulating. An output level, wherein the output limit corresponds to a maximum output to be applied to the bit, and the operation output level is determined from a limited operation output level, a recommended operation output level, and a predicted operation output level. The at least one selected from the group consisting of: and wherein the percentage graphical representation of the output illustrates a drilling system operating constraint that adversely affects the output, wherein the drilling system operating constraint results in power loss. , And the percentage graph of the output constraints further shows the corresponding percentage that each constraint has on the dynamic output at a given depth. The method shows the impact rate, further drilling system operational percentage graph representation of constraints on output, coded, characterized in that it comprises different codes for identifying different constraints. 38. The method of claim 22, further comprising, in addition to the geological feature and the predicted drilling mechanics,
Generating an indication of the details of the proposed drilling facility, the proposed drilling facility comprising at least one recommended bit selection used to predict the performance of the drilling system. A method comprising: 39. The method of claim 38, wherein the first
And the second bit selection is recommended to be used with expected performance for drilling a drill hole, and further wherein the first and second bit selections are first and second respectively.
Wherein the first and second identifiers are displayed along with geological features and predicted drilling mechanics, and further wherein positioning of the first and second identifiers on the display comprises: The method wherein the first and second bit selections are selected to match a portion of the expected performance to which each applies. 40. The method of claim 22, further comprising: changing the bit selection from the first recommended bit selection to the second recommended bit selection at a predetermined depth. Indicating on the display of the geological features and the predicted drilling mechanics. 41. A computer program, stored on a computer readable medium, executed by a computer for predicting the performance of a drilling system in drilling a drill hole in a predetermined formation, comprising: Instructions for generating a geological feature of the formation per unit depth according to the model and outputting a signal representative of the geological feature, wherein the geological feature includes at least rock strength; and An instruction for obtaining specifications of a proposed drilling equipment for use in drilling, the instructions comprising a bit specification of at least one of the recommended drill bits; and a drilling mechanics. According to the model, according to the proposed drilling equipment specifications as a function of the geological features per unit depth, the predicted drilling An instruction for determining a canix and outputting a signal representative of the predicted drilling mechanics, wherein the predicted drilling mechanics comprises:
In response to a command and a predicted drilling mechanics output signal, the drilling system comprising at least one selected from the group consisting of bit wear, mechanical efficiency, power, and operating parameters. An instruction for controlling a control parameter, wherein the control parameter is:
Instructions including at least one selected from the group consisting of weight on bit, rpm, pump flow rate, and water pressure; instructions for obtaining measurement parameters in real time during drilling of the drill hole; Wherein the back-calculated value of the measured parameter is a function of at least one selected from the group consisting of a drilling mechanics model and at least one control parameter. The instructions for controlling a parameter further comprise: a) adjusting a drilling mechanics model in response to a defined deviation between the measured parameter and the back-calculated value of the measured parameter; b) adjusting the control parameter Modifying the control; and c) performing a warning operation. Including instructions for performing at least one selected from the loop, the computer program characterized by including the instructions. 42. The computer program according to claim 41, further comprising a geological feature per unit depth and a predicted drilling mechanic according to the output signal of the geological feature and the predicted output signal of the drilling mechanics. Instructions for generating a display of the computer program. 43. The computer program according to claim 42, wherein generating a display comprises using at least one selected from the group consisting of: a) a display monitor; and b) a printer. A computer program characterized in that the display of geological features and predicted drilling mechanics per unit depth includes a printout. 44. The computer program of claim 41, wherein the step of generating geological features comprises at least one additional feature selected from the group consisting of log data, lithology, porosity, and shale plasticity. Computer program, comprising the step of generating 45. The computer program of claim 41, wherein the step of obtaining the proposed drilling equipment input specification further comprises: downhole motor, top drive motor, rotary table motor, muddy water system, and A computer program characterized by the step of obtaining additional specifications of at least one proposed drilling facility selected from the group consisting of mud pumps. 46. The computer program according to claim 41, wherein the operating parameters include weight on bit, bit rpm (rotation per minute), cost, drilling speed,
And at least one selected from the group consisting of: torque and torque. 47. The computer program according to claim 46, wherein the digging speed further includes an instantaneous digging speed (ROP) and an average digging speed (ROP-AVG). program. 48. The computer program of claim 42, wherein displaying the geological feature comprises displaying at least one graphical display selected from the group consisting of a curve display, a percentage graph display, and a band display. Displaying the predicted drilling mechanics comprises displaying at least one graphical display selected from the group consisting of a curve display, a percentage graph display, and a band display. program. 49. The computer program according to claim 48, wherein generating the display comprises using at least one selected from the group consisting of: a) a display monitor and b) a printer. A computer program characterized in that the display of geological features and predicted drilling mechanics per unit depth includes a printout. 50. The computer program of claim 48, wherein at least one graphical representation of the geological feature and at least one graphical representation of the predicted drilling mechanics are color coded. A computer program characterized by the above-mentioned.