US20140196949A1 - Autodriller system - Google Patents

Autodriller system Download PDF

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Publication number
US20140196949A1
US20140196949A1 US14/124,699 US201214124699A US2014196949A1 US 20140196949 A1 US20140196949 A1 US 20140196949A1 US 201214124699 A US201214124699 A US 201214124699A US 2014196949 A1 US2014196949 A1 US 2014196949A1
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Prior art keywords
bit
drillstring
drilling
weight
downhole
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US14/124,699
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English (en)
Inventor
Geir Hareland
Mohammad Fazaelizadeh
Zebing Wu
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UTI LP
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University of Calgary
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Priority to US14/124,699 priority Critical patent/US20140196949A1/en
Assigned to UNIVERSITY OF CALGARY reassignment UNIVERSITY OF CALGARY ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: FAZAELIZADEH, Mohammad, HARELAND, GEIR, WU, Zebing
Assigned to UTI LIMITED PARTNERSHIP reassignment UTI LIMITED PARTNERSHIP ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: UNIVERSITY OF CALGARY
Publication of US20140196949A1 publication Critical patent/US20140196949A1/en
Abandoned legal-status Critical Current

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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
    • E21B44/02—Automatic control of the tool feed
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/007—Measuring stresses in a pipe string or casing

Definitions

  • the invention is related to a controlling system for directional drilling of oil and gas wells.
  • the hookload and surface torque measurements are used to calculate weight on the bit and the bit torque.
  • To apply weight on the bit it is required to apply some portion of drillstring weight on the bit.
  • the weight on the bit is calculated based on the difference between the hookload values when drillstring is off and on bottom.
  • the surface weight on the bit could be the true value, if the well is vertical and the axial friction force between drillstring and the wellbore is negligible.
  • the surface and downhole weight on the bit may not be the same due to axial friction force between drillstring and the wellbore. The same happens for bit torque calculation.
  • the bit torque is estimated from difference between surface torque measurements while drilling bit is off and on bottom. An improved method of calculating downhole weight on bit and using this information in the drilling process is required.
  • a method of drilling or fracturing a formation comprising drilling the formation with a drilling system that includes a drillstring and a bit, estimating a friction force on the drillstring, estimating a downhole weight on bit using a surface measurement and the estimated friction force and taking an action to change drilling of the formation based on estimated downhole weight on bit.
  • a method of drilling for a drilling system having a drillstring and a bit.
  • the method comprises estimating friction force on a drillstring using a friction model, estimating a downhole weight on bit and/or bit torque using surface measurements, and modifying drilling operation by modifying drilling parameters according to the estimated downhole weight on bit and/or bit torque.
  • the friction force is estimated according to the friction model and according to surface measurement conducted while the bit is off bottom.
  • the surface measurement may be, for example, a hook load measurement.
  • the surface measurements used to estimate the downhole weight on bit and/or bit torque are hook load surface torque measurements.
  • the drilling parameter is one or more of surface torque, drillstring rotation rate or hook load.
  • the downhole weight on the bit may be estimated through steps comprising of: determining the static weight of drillstring; determining an axial friction coefficient including pipe rotation effect; determining the effect of downhole weight on the bit on value of axial friction force during drilling; and determining downhole weight on the bit using axial friction coefficient and surface hookload measurements.
  • a founder point may be identified if estimated weight on bit is non-zero and rate of penetration is not increasing.
  • downhole torque on bit may be determined by determining the rotational friction force while drilling bit is off bottom; determining the rotational friction coefficient including axial pipe movement effect from surface torque measurements while bit is off bottom; determining the effect of downhole weight on the bit on value of rotational friction force during drilling; and determining downhole bit torque by using rotational friction coefficient and estimated downhole weight.
  • the rotational coefficient including the drillstring axial movement effect may for example be estimated while the bit is off bottom and there is no torque at the bit.
  • Surface torque for example, may be measured while the bit is moving downwardly and sufficiently close to bottom that the drillstring rotation at the point of measurement is the same as drillstring rotation in the formation to be drilled.
  • Rotational friction force may be, for example, determined while bit is on bottom by using rotational friction coefficient and downhole weight on the bit. The estimated rotational friction force will be deducted from measured surface torque to find the downhole bit torque. The changes in downhole weight on the bit may change the rotational friction force which affects the value of the bit torque.
  • the static weight of drillstring may be calculated from a mud logging unit's data, the mud logging unit's data comprising survey data, drillstring specification, and local buoyancy factor at any bit depth.
  • the axial friction coefficient including the drillstring rotation effect may be estimated using surface measured hookload determined when the bit is off bottom.
  • the surface measured hookload may be determined while the bit is off bottom and has a drillstring rotation, and the bit is sufficiently close to bottom that the drillstring rotation is the same as the expected drillstring rotation in the formation to be drilled.
  • hookload may be calculated by using axial friction coefficient and estimating the weight on the bit; comparing calculated hookload with measured hookload value; and, if the difference between calculated hookload and measured hookload value is negligible, the estimated downhole weight on the bit is taken as downhole weight on the bit. If the difference is not negligible, another value may be estimated for downhole weight on the bit. This procedure may repeated to determine the downhole weight on the bit.
  • a drilling problem may be identified.
  • the drilling problem may be one or more of string sticking, and insufficient hole cleaning.
  • the method described herein may be incorporated in an autodrilling system in which the autodrilling system automatically adjusts surface weight on bit utilized by the autodrilling system.
  • the autodrilling system may display surface weight on bit from hook load measurements and estimated downhole weight on bit.
  • an action may be taken, for example determining when to pull the bit off the bottom, and pulling the bit off bottom.
  • different equations are used, during drilling, to determine the downhole weight on bit depending on whether a part of the drillstring in a curved section is in compression or in tension.
  • the method described herein may be used in sliding drilling employing a mud driven motor.
  • the estimated downhole weight on bit divided by pressure differential across the mud driven motor given for example by the variable K, may be estimated.
  • K may be used to improve drilling performance.
  • the friction force is equal to the friction coefficient multiplied by the normal force which applies on contact surface area of the wellbore.
  • the normal force may be a function of the buoyed unit weight of drillstring components, well geometry and the tensile force at the bottom of each drillstring element. For straight section such as inclined and horizontal sections, the normal force only depends on the buoyed unit weight of drillstring components, but in curved sections such as build-up, drop-off, the normal force depends on the buoyed unit weight of drillstring component and the tensile force which applies at the bottom of each drillstring element.
  • an autodriller tool is used to calculate downhole weight on the bit and/or bit torque from surface hookload and/or torque measurements and use this information in the drilling process.
  • time based hookload and surface torque data the static weight of drillstring, SWDS, which can be calculated from vertical projection of drillstring at each measured depth and a three dimensional friction model to calculate friction forces and coefficients along drillstring may be programmed and integrated in a real-time autodriller controlling system and downhole weight on the bit and/or bit torque can be updated as long as surface data is being generated.
  • the disclosed methods may be incorporated into a drilling system comprising a rig, a drill string connected downwardly into a borehole, and an autodriller system, the autodriller system being configured to carry out any one of the disclosed methods.
  • Computer readable media, in non-transient form, and an autodriller system are configured to carry out the disclosed methods.
  • FIG. 1 is a schematic illustration of drilling rig that shows the block and tackle system.
  • the autodriller system is connected to deadline or any other hookload measurement system to estimate downhole weight on the bit.
  • FIG. 2 is the schematic description of drillstring moving downwardly in a vertical well while the bit is off and on bottom respectively.
  • the axial and rotational friction forces between drillstring and the wellbore while bit is off and on bottom are negligible.
  • FIG. 3 shows the schematic of drillstring moving downwardly in a well with the geometry of vertical, build-up and the straight inclined sections. The axial and rotational friction forces in the build-up section will be decreased applying some weight on the bit.
  • FIG. 4 illustrates the drillstring along a horizontal well which is pushing toward the bottom.
  • the axial and rotational friction forces in the curved section will be decreased while applying some weight on the bit.
  • FIG. 5 is a flowchart showing exemplary steps for calculation of downhole weight on the bit by using hookload measurements.
  • FIG. 6 is a flowchart showing exemplary steps for calculation of downhole bit torque by using the surface torque measurements.
  • FIG. 7 shows geometry of a drilled well which includes vertical, build-up, straight inclined and horizontal sections. The horizontal departure and measured depth have been plotted versus true vertical depth.
  • FIG. 8 compares tension and compression along drillstring when 11 kdaN weight applies on the bit.
  • FIG. 9 shows reduction in axial friction force along drillstring when 11 kdaN weight applies on the bit.
  • FIG. 10 shows the surface and downhole weight on the bit for 1 m drilled interval.
  • the downhole weight on the bit is calculated as disclosed.
  • FIG. 11 shows the surface and downhole bit torque for 1 m drilled interval.
  • the downhole torque at the bit is calculated as disclosed.
  • FIG. 12 shows geometry of a short bend horizontal well which include vertical, build-up and horizontal sections. The horizontal departure and measured depth have been plotted versus true vertical depth.
  • FIG. 13 illustrates friction coefficient versus measured depth during drilling operation for the interval between 3070 m to 3420 m.
  • the estimated friction coefficients include effect of drillstring rotation.
  • FIG. 14 compares the surface and downhole WOBs for the drilled interval from 3070 m to 3420 m.
  • FIG. 15 shows surface WOB values versus measured depth during drilling operation when keeping 10 kdaN downhole weight on the bit.
  • FIG. 16 compares surface and downhole WOBs for a drilled interval from 2534 m to 2538 m.
  • the downhole WOB was estimated using “K” value multiplication into differential pressure across downhole motor.
  • the embodiments disclosed here provide mechanisms for improvement of drilling underground formations.
  • the mechanisms are implemented at least partially through an autodriller that controls drilling system components and that receives information on drilling conditions from drilling system components.
  • the autodriller includes a processor that may be configured, by various means such as software, firmware and hardware, to calculate or estimate true downhole weight on bit (DWOB) by for example a) determining the static weight of drillstring; b) determining the axial friction coefficient including pipe rotation effect; c) determining the effect of downhole weight on the bit on value of axial friction force during drilling; d) determining downhole weight on the bit using axial friction coefficient and surface hookload measurements.
  • DWOB true downhole weight on bit
  • any of the various embodiments of the autodriller disclosed in this document may use finite element or difference methods or an analytical solution to do the calculations.
  • the estimated DWOB may be used in a drilling simulation tool such as the OptimizerTM of Pason Systems Inc. to improve drilling performance.
  • the true DWOB produces the required or manufacturer recommended and/or simulated optimum or near optimum DWOB which may be used to produce improved rate of penetration (ROP).
  • ROP rate of penetration
  • the autodriller may be configured to calculate downhole torque on bit (DTOB) a) determining the rotational friction force while drilling bit is off bottom; b) determining the rotational friction coefficient including axial pipe movement effect from surface torque measurements while bit is off bottom; c) determining the effect of downhole weight on the bit on value of rotational friction force during drilling; d) determining downhole bit torque by using rotational friction coefficient and estimated downhole weight on the bit.
  • DTOB downhole torque on bit
  • the approach herein can use either finite element or difference methods or an analytical solution to do the calculations in the above approach.
  • the true or estimated DTOB may be used for more accurate tooth wear prediction and used for real-time monitoring bearing wear, which gives drilling engineers reliable recommendation when to pull out the bit off the bottom and avoid bit failure and lost bearing in the hole.
  • the autodriller system may function independently of the drilling operator or driller (“black box” operation), and the driller sees the surface weight on the bit and then the system automatically adjust the surface WOB so that the down hole WOB can be accurate.
  • the correct DWOB can give the optimal or near optimal WOB desired and other operating conditions for improvement of the overall or global ROP and minimize the $/ft.
  • the autodriller may display both surface WOB (from hook load measurements) and down hole WOB (estimated from the method) for the driller. This will also benefit the driller get more accurate founder points (WOB when ROP no longer increase) when drill-off tests are being carried out.
  • the autodriller may learn from the surface measured data as a well is being drilled ahead by calibrating both axial and rotational friction coefficients.
  • the friction coefficients can in addition help drilling engineers identify if drilling problems such as string sticking or insufficient hole cleaning is present, and may enable the drilling engineers to avoid pipe sticking.
  • the autodriller system may be used in both rotating and sliding drilling mode with a mud driven motor or with a rotary steerable system.
  • the autodriller may be used to calculate the static weight of drillstring using survey data, drillstring specification and local buoyancy factor at any bit depth, for example as provided by a mud logging unit on the rig site.
  • the axial friction coefficient including the drillstring rotation effect is estimated by using the friction model from an improved surface measured hookload. For example, the last several off-bottom time based data points (excluding abnormal points) may be selected to calculate the friction coefficient using the hookload and SWOB of those points.
  • An improved measured hookload may for example be obtained while the bit is moving downwardly, and sufficiently close to the bottom that the drillstring rotation is for practical purposes the same as expected while drilling ahead in a new section.
  • different equations may be used for calculating weight on bit or bit torque depending on whether a portion or element of the drillstring in a curved section is in compression or tension.
  • the autodriller may calculate the hookload by using axial friction coefficient and estimating the weight on the bit.
  • the calculated hookload is compared with measured hookload value and if the difference between these values is negligible, the estimated value for weight on the bit is taken as downhole weight on the bit. If the difference is not negligible, another value will be estimated for weight on the bit and this procedure is repeated to get the true downhole weight on the bit.
  • the rotational friction coefficient including the drillstring axial movement effect may be estimated by using the friction model from an improved measured surface torque while bit is off bottom and there is no torque at the bit.
  • An improved measured surface torque may be found while the bit is moving downwardly and sufficiently close to the bottom that the drillstring rotation is the same as expected when drilling ahead in the next section.
  • the estimated rotational friction force may be deducted from measured surface torque to find the downhole bit torque. The changes in downhole weight on the bit will change the rotational friction force which affects the value of the bit torque.
  • Use of the autodriller may provide an early real-time detection of the predicted trends (DWOB, friction factor) associated with some drilling dysfunctions (bit bouncing, stick-slip, lateral vibration, pipe sticking), which may enable the driller to take early corrective action to minimize escalation of the issue and therefore minimize the potential to induce coupling and catastrophic drill string integrity failures.
  • DWOB predicted trends
  • friction factor friction factor
  • FIG. 1 shows the schematic diagram of a drilling rig.
  • the drilling rig includes a derrick 10 , drillstring 12 , hoisting system, rotating system 16 , circulating system (not shown) and power system (not shown).
  • Derrick 10 supports hoisting system and rotating system 16 which operate by power system (not shown).
  • a drillstring 12 includes a series of drill pipe joints which connected downwardly from surface into the borehole 18 .
  • a drilling bit 20 is attached to the end of drillstring that is called bottom hole assembly, BHA, 22 .
  • the BHA does many functions such as providing weight on the bit, torque at the bit by downhole motor etc.
  • the rotating system 16 may include the rotary table 16 or top drive (not shown) to rotate drillstring 12 at the surface to rotate drilling bit 20 at the bottom where it impacts the formation being drilled.
  • the hoisting system includes drawworks 24 and block and tackle system 14 .
  • the drawworks 24 control the weight on the drilling bit 20 during drilling operation and raise and lower drillstring 12 through the wellbore.
  • the block and tackle system 14 comprised of crown block 26 , travelling block 28 and drilling line 30 . If the number of drilling lines in the block and tackle system 14 increase, the tension in drilling lines 28 will decrease which provide the higher load capacity for the hoisting system.
  • the drilling line 30 is connected to drawworks 24 from one end which is called fast line 32 and from other end connected to deadline anchor or wheel 34 which is called the dead line 36 .
  • the hydraulic cell 40 is connected to deadline 36 to measure the tension in drilling line 30 .
  • the measured tension in the deadline should be multiplied by the number of drilling line 30 between the sheaves 42 in block and tackle system 14 .
  • the tension in the deadline 36 is not true value due to friction between the drilling line 30 and the sheaves 42 .
  • the true value can be calculated by considering the friction in block and tackle system 14 .
  • this reduction is considered as surface weight on the bit which is not usually equal to downhole weight on the bit.
  • the real-time hookload data should be transferred into autodriller system 44 for further treatment to obtain the downhole weight on the bit.
  • autodriller can calculate the downhole bit torque which results from surface rotation.
  • the real time surface torque should be sent to autodriller system 44 for calculating downhole torque at the bit. After calculating downhole weight on the bit and bit torque, they will be available for users 46 for different purposes such as drilling optimization and real-time drilling analysis.
  • FIG. 2 a illustrates in schematic way a drillstring 12 in a vertical wellbore 46 with a hook 38 at the top.
  • the drillstring is hung from the hook 38 which mostly consists of drillpipe 48 and the lower end of the drillstring called bottom hole assembly 50 that carries a drilling bit 20 .
  • the borehole is being drilled and extends downwardly from the surface.
  • the drilling bit is off bottom and entire load of drillstring applies on the hook 38 .
  • the entire drillstring will be in tension 52
  • the minimum tension is at the drilling bit and maximum tension will be at the surface.
  • friction force can be neglected.
  • the tension force balance can be written as follow:
  • drillstring 12 is divided to n number of elements and calculation starts from drilling bit 20 to the surface.
  • the buoyancy factor is dynamic parameter which will vary along the drillstring 12 by changing the pressure, temperature, drilling cutting rate and gas influx etc.
  • FIG. 2 b shows the drillstring in on bottom position.
  • FIG. 3 a shows a drillstring in a deviated wellbore which consist of vertical 72 , build-up 74 and straight inclined 76 sections.
  • a drillstring in a deviated wellbore which consist of vertical 72 , build-up 74 and straight inclined 76 sections, there is contact between drillstring and the wellbore which results in friction force 78 & 80 against the pipe movement.
  • the nature of friction in these two sections is different.
  • the bit is off bottom and entire drillstring is in tension 82 .
  • the tension will not have any contribution in axial friction force 78 . But when build up section 74 begins, the tension at this point will have great contribution in the friction force 80 .
  • the friction force 78 only depends on the weight of element which applies normally on the contact area but in the build-up section 74 , the friction force 80 mostly depends on the tension at the bottom of the element and also the normal weight of drillstring element. The following is the general force balance for each element along drillstring.
  • F top ( F bottom ) DWOB + ⁇ SW ⁇ Friction weight ⁇ [(Friction tension ) DWOB or 0] (4)
  • Equation (5) shows the torque for an element in drillstring while bit is off bottom and there is no weight on the bit 90 .
  • Torque top Torque bottom +Torque weight +[Torque tension or 0] (5)
  • drillstring is divided to many numbers of elements and calculation starts from drilling bit to the surface.
  • the torque will be the function of element weight only.
  • the torque will depend on mostly tension 82 and less on weight.
  • the tension 84 along drillstring will change which affects the value of rotational friction force 102 in the curved section 74 as well.
  • the value of torque on the bit 106 will be added as shown in equation (6).
  • the rotational friction force 104 in the straight inclined section 76 will not change.
  • Torque top Torque bottom +Torque bit +Torque weight +[(Torque tension ) DWOB or 0] (6)
  • FIG. 4 a shows a horizontal well which includes vertical 108 , build-up 110 and horizontal 112 sections.
  • the drillstring is off bottom and pushing toward the bottom.
  • the axial friction force 114 is acting against the drillstring movement tendency.
  • To push the pipe in the horizontal section 112 it is necessary to have some heavy drillpipes 118 in vertical 108 and build-up 110 sections for providing sufficient drive to push drillstring in the horizontal 112 section.
  • the axial friction force 116 in horizontal section 112 is function of the weight of drillstring which normally applied on wellbore contact area. When drilling bit is off bottom and drillstring is pushing toward the bottom, some part of heavy drillpipe 118 will be in compression 120 due to axial friction force 116 in the horizontal 112 section.
  • the axial friction force 114 in the curved section which is in compression 120 is only function of weight of drillstring element.
  • the drillstring will be in tension 124 and axial friction force 114 will be depends on the normal force and tension force for each element. If the element is in horizontal 112 section, the axial friction force 116 will depend only to weight of the element.
  • the equation (3) can be applied for the horizontal well drilling for hookload calculation 126 when drilling bit is off bottom and moving toward the bottom.
  • the friction force may be estimated according to a friction model using surface measurements conducted while the bit is off bottom.
  • the rotational friction force is related to build-up 110 and horizontal 112 sections.
  • the rotational friction force 138 is the function of normal force which is applied by the weight of drillstring element.
  • the rotational friction force 140 is only the function of weight but if drillstring is in tension 124 the rotational friction force 140 is the function tension and weight. That is, different equations are employed to determine the downhole weight on bit depending on whether a part of the drillstring in a curved section is in compression or tension.
  • FIG. 5 is a general flowchart showing the steps how “autodriller” can estimate downhole weight on the bit from surface measurements.
  • the first step is determining the static weight of drillstring, SWDS 146 .
  • To calculate the SWDS 146 the following information are required at any measured depth:
  • the second step is determining when the bit is off or on bottom 148 .
  • the mud logging unit records all necessary field data.
  • the measured depth and bit depth data will be used to know when the bit is off and on bottom 148 and also bit is moving upward or downward.
  • the measured depth corresponds to final drilled depth at any time of calculations.
  • the measured hookload 150 should be compared with SWDS. If difference between values 152 is negligible, it means there is no axial friction force and the well geometry is vertical 154 .
  • the reduction in the hookload is taken as downhole weight on the bit, DWOB 156 . Therefore the DWOB can be calculated directly from surface hookload measurements for a vertical well when drilling bit is off and on bottom.
  • the surface measured hookload may be determined while the bit is off bottom and has a drillstring rotation and when the bit is sufficiently close to the bottom that the drillstring rotation is the same as the expected drillstring rotation in the formation to be drilled. Therefore the followings conditions are considered to select the best measured hookload value while the bit is off bottom:
  • the axial friction coefficient 160 which includes the drillstring rotation effect will be estimated. This axial friction coefficient 160 will be used for DWOB 162 calculation when the bit goes on bottom for further drilling.
  • the next step is when the bit depth and the measured depth 164 are equal which means the bit is on bottom.
  • the measured hookload 166 is known, as it is measured from the surface, and the hookload 168 could be calculated as well.
  • the SWDS 146 axial friction force and DWOB should be known.
  • the SWDS 146 is obtained directly from aforementioned standard equations.
  • the DWOB 162 is estimated and the axial friction force will be calculated based on estimated DWOB.
  • some value should be estimated close to surface weight on the bit and applies in friction model to see its effect on value of axial friction force. If the difference between measured and calculated hookload is negligible 170 then the value is taken as DWOB 162 . Otherwise another value is chosen and repeat the calculation. This loop will be continued until the difference between calculated and measured values becomes negligible.
  • the estimate of downhole weight on bit and bit torque can be used to modify drilling process. This may comprise taking an action to change drilling of the formation based on the estimate of DWOB or bit torque.
  • the modification of the drilling parameter during drilling is carried out by the autodriller system 44 and thus modifies the drilling process according to the modification of the drilling parameter.
  • the autodriller displays surface WOB from hook load measurements and estimated downhole weight on bit.
  • the auto-driller may identify a founder-point.
  • the autodriller may learn from surface measured data during drilling by calibrating both axial and rotational friction coefficients from the surface measurement.
  • the axial and rotational friction coefficients may be used to identify a drilling problem.
  • the friction coefficients may additionally help identification of drilling problems such as string sticking or insufficient hole cleaning, and may be used in avoiding pipe sticking.
  • the action taken by the autodriller may be determining when to pull the bit off the bottom and then pulling the bit off the bottom.
  • the instructions for carrying out the processes described here may be contained in non-transient form on computer readable media. When saved to a computer forming part of the autodriller system, the instructions configure the autodriller system to carry out the instructions.
  • the drilling system may comprise a rig, a drill string connected downwardly into a borehole, an autodriller system, the autodriller system being configured to carry out instructions of the processes described herein.
  • FIG. 6 is a general flowchart showing the steps how “Autodriller” can estimate bit torque 172 when rotating from the surface.
  • the procedure is mostly similar to downhole weight on the bit 162 . That is, in a preferred embodiment, the process is similar to calculating downhole weight on a bit: determine the rotational friction force while the drilling bit is off bottom; determine the rotational friction coefficient including axial pipe movement effect from surface torque measurements while bit is off bottom; determining the effect of downhole weight on the bit on value of rotational friction force during drilling; and determining downhole bit torque by using rotational friction coefficient and estimated downhole weight. An estimate of rotational friction force while the bit is on bottom is estimated by using the rotational friction coefficient and downhole weight on the bit.
  • the estimated rotational friction force will be deducted from measured surface torque to find the downhole bit torque.
  • the changes in downhole weight on the bit will change the rotational friction force which affects the value of the bit torque.
  • the rotational friction coefficient including the drillstring axial movement effect may be estimated while the bit is off bottom and there is no torque at the bit. Note that different equations may be used when determining downhole torque on bit depending on whether a part of the drillstring in a curved section is in compression or tension.
  • the estimated downhole weight on the bit 162 in previous section is used for downhole bit torque calculation 172 .
  • the bit depth should be compared with measured depth 174 to see the drilling bit is on bottom or off bottom.
  • the value of the measured surface torque is negligible 176 , it means the drilling well is vertical and there is negligible rotational friction force 178 .
  • the measured surface torque almost corresponds to downhole bit torque 172 . If the measured surface torque is not negligible while bit is off bottom, it means the well is not vertical and there is rotational friction force against drillstring rotation 180 .
  • the best selected data is when the bit is off bottom and is moving downwardly close to the bottom with the same pipe rotation as planned for drilling. From the rotational friction force 180 while bit is off bottom and using a reliable friction model, the rotational friction coefficient 182 may be estimated for next steps.
  • the measured surface torque 184 can be read.
  • the downhole weight on drilling bit, DWOB 162 will affect value of rotation friction force 186 due to changes in tension along drillstring.
  • DWOB 162 and rotational friction coefficient 182 in a reliable friction model yields the rotational friction force during drilling operation which changes whit the changes in DWOB 186 .
  • the final step is calculating the downhole bit torque due to surface rotation by subtracting the rotational friction force from surface torque measurements 172 .
  • a friction model is applied to estimate DWOB and bit torque during drilling operations.
  • survey data and friction coefficient are specified, the calculation begins at the bottom of drillstring and continues stepwise upwardly.
  • Each drillstring element contributes small load on hookload and surface torque.
  • the force and torque balance on drillstring element when the bit is off bottom can be written as follows:
  • F top ⁇ ⁇ ⁇ w ⁇ ⁇ ⁇ ⁇ L ⁇ ( cos ⁇ ⁇ ⁇ ⁇ ⁇ or ⁇ ⁇ sin ⁇ ⁇ ⁇ top - sin ⁇ ⁇ ⁇ bottom ⁇ top - ⁇ bottom ) - ⁇ ⁇ ⁇ ⁇ ⁇ w ⁇ ⁇ ⁇ ⁇ ⁇ L ⁇ ( sin ⁇ ⁇ ⁇ ⁇ ⁇ or ⁇ ⁇ - cos ⁇ ⁇ ⁇ top + cos ⁇ ⁇ ⁇ bottom ⁇ top - ⁇ bottom ) + ( F bottom ⁇ ⁇ or ⁇ ⁇ F bottom ⁇ ⁇ - ⁇ ⁇ ⁇ ⁇ ⁇ ) ( 7 )
  • F top ⁇ ⁇ ⁇ w ⁇ ⁇ ⁇ ⁇ L ⁇ ⁇ cos ⁇ ( ⁇ top + ⁇ bottom 2 ) + ⁇ ⁇ [ ( F bottom ⁇ ( ⁇ top - ⁇ bottom ) ⁇ sin ⁇ ( ⁇ top + ⁇ bottom 2 ) ) 2 + ( F botom ⁇ ( ⁇ top - ⁇ bottom ) + ⁇ ⁇ ⁇ w ⁇ ⁇ ⁇ ⁇ L ⁇ ⁇ sin ⁇ ( ⁇ top + ⁇ bottom 2 ) ) 2 ] 0.5 + F bottom ( 8 )
  • T top T bottom + ⁇ ⁇ r ⁇ ⁇ ⁇ ⁇ w ⁇ ⁇ ⁇ ⁇ L ⁇ ( sin ⁇ ⁇ ⁇ ⁇ ⁇ or ⁇ ⁇ - cos ⁇ ⁇ ⁇ top + cos ⁇ ⁇ ⁇ bottom ⁇ top - ⁇ bottom ) + ( 0 ⁇ ⁇ or ⁇ ⁇ ⁇ ⁇ r ⁇ F bottom ⁇ ⁇ ⁇ ⁇ ) ( 9 )
  • T top ⁇ ⁇ r ⁇ [ ( F bottom ⁇ ( ⁇ top - ⁇ bottom ) ⁇ sin ⁇ ( ⁇ top + ⁇ bottom 2 ) ) 2 + ( F botom ⁇ ( ⁇ top - ⁇ bottom ) + ⁇ ⁇ w ⁇ ⁇ ⁇ ⁇ L ⁇ sin ⁇ ( ⁇ top + ⁇ bottom 2 ) ) 2 ] 0.5 + T bottom ( 10 )
  • Equation (8) is for compressed drillstring in the curved section
  • equations (9) (10) are used.
  • a drilled well was selected as shown in FIG. 7 to illustrate how autodriller can estimate the downhole weight on the bit and bit torque.
  • the well geometry includes two build-up sections, straight and horizontal sections.
  • Applying 11 kdaN weight on the bit causes some portion of drillstring starting from bit to go in compression and reduce the tensile force for the rest as shown in FIG. 8 .
  • This reduction in tension along drillstring has effect on value of friction force as shown in FIG. 9 as much as 2.15 kdaN.
  • the downhole weight on the bit has effects only on the friction forces in those build-up sections.
  • the weight on the bit will reduce the friction force in the curved sections which affect axial and rotational friction force as well.
  • the sample calculation has been shown as follow:
  • the axial friction coefficient including the pipe rotation effect will be used when drillstring goes on bottom for drilling.
  • the axial friction coefficient can be updated for each wiper trip periodically and used for upcoming sections.
  • the estimated axial friction coefficient is used in a friction model to calculate the hookload.
  • the different values for downhole weight on the bit should be estimated until the difference between the measured and calculated hookloads become negligible. When the difference is acceptable, the final estimated value for downhole weight on the bit will be chosen.
  • the FIG. 10 compares surface and downhole weight on the bit values for one meter drilled interval using the present invention method.
  • bit torque For surface torque measurement, the increment in surface torque when drilling bit goes on bottom for drilling consider as bit torque. The reduction in tension has a considerable impact on value of rotational friction force which should be counted for bit torque calculations.
  • the measured surface torque is as follow:
  • the Measured surface torque is equal to rotational friction force.
  • the rotational friction coefficient can be estimated:
  • the downhole torque at the bit can be estimated as follow:
  • the estimate of bit torque can be used to modify a drilling parameter.
  • the drilling parameter can be, for example, surface torque, drillstring rotation rate or hookload.
  • FIG. 11 compares the surface and downhole bit torque for one meter interval by considering effect of downhole weight on the bit on rotational friction force.
  • FIG. 12 is well geometry of another example which verifies the application of the current method.
  • 350 m drilled interval has been selected to estimate downhole weight on the bit from hookload measurements.
  • the friction coefficient should be estimated and updated during drilling operation.
  • FIG. 13 illustrates the plot of friction coefficient including drillstring rotation effect versus measured depth for this 350 m drilled interval to use for downhole weight on the bit estimation.
  • FIG. 14 compares the surface and downhole weight on the bit which estimated by using autodriller system. To apply a constant weight on the bit as much as 10 kdaN, the autodriller estimate the value of surface weight on the bit versus measured depth as shown in FIG. 15 .
  • this autodriller system can be used for sliding drilling which is used for directional or horizontal drilling.
  • This autodriller system may be used in sliding drilling using a mud driven motor, where the drilling bit rotated by mud motor instead of rotating the drillstring from surface.
  • the mud motor is powered by the fluid differential pressure.
  • differential pressure There is a certain relationship between differential pressure and DWOB which can be found by using present system.
  • K value is used to represent the ratio of DWOB to differential pressure which can be found during rotating time.
  • a new DWOB can be predicted with the product of K and differential pressure.
  • the average value for “K” is estimated during rotating time as much as
  • the differential pressure was multiplied by “K” value to estimate DWOB as shown in FIG. 16 .
  • the autodriller may use K to improve drilling performance.
  • a newly developed analytical model was used to calculate the axial and rotational frictions between drillstring and the wellbore.
  • This model can be replaced by any other analytical and numerical models to calculate axial and rotational friction forces for downhole weight on the bit and bit torque estimation.
  • vectors ⁇ U ⁇ , ⁇ dot over (U) ⁇ , ⁇ Ü ⁇ and ⁇ F ⁇ represent generalized displacements, velocities, accelerations and forces, respectively.
  • matrixes M, C and K represent mass, damping and stiffness respectively.
  • the forces include gravity, unbalanced mass and frictions with the wellbore.
  • Wilson- ⁇ a kind of numerical method, is used to get the solution to the above equation. Based on the equation, numerical solution method and appropriate boundaries, a finite element analysis (FEA) program is developed to do the calculation and analysis of torque and drag under different drilling modes with vertical, directional and horizontal wells.
  • FEA finite element analysis

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WO2023022747A1 (fr) * 2021-08-20 2023-02-23 Landmark Graphics Corporation Étalonnage d'un poids de train de tiges de forage avec traînée pour estimation de facteur de frottement
WO2023022746A1 (fr) * 2021-08-20 2023-02-23 Landmark Graphics Corporation Étalonnage du poids d'un train de tiges de forage pour une estimation de facteur de frottement
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US11916507B2 (en) 2020-03-03 2024-02-27 Schlumberger Technology Corporation Motor angular position control
US11933156B2 (en) 2020-04-28 2024-03-19 Schlumberger Technology Corporation Controller augmenting existing control system
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US10393107B2 (en) 2015-08-03 2019-08-27 General Electric Company Pumping control unit and method of computing a time-varying downhole parameter
US10746008B2 (en) * 2015-11-24 2020-08-18 Saudi Arabian Oil Company Weight on bit calculations with automatic calibration
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US20180283157A1 (en) * 2017-04-04 2018-10-04 Nabors Drilling Technologies Usa, Inc. Surface Control System Adaptive Downhole Weight on Bit/Torque on Bit Estimation and Utilization
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US11282011B2 (en) * 2020-04-01 2022-03-22 Chevron U.S.A. Inc. Task management interface for well operations
US11933156B2 (en) 2020-04-28 2024-03-19 Schlumberger Technology Corporation Controller augmenting existing control system
US11655701B2 (en) * 2020-05-01 2023-05-23 Baker Hughes Oilfield Operations Llc Autonomous torque and drag monitoring
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US12338725B2 (en) 2020-09-16 2025-06-24 Baker Hughes Oilfield Operations Llc System to model distributed torque, drag and friction along a string
WO2022060719A1 (fr) * 2020-09-16 2022-03-24 Baker Hughes Oilfield Operations Llc Système pour modéliser le couple, la traînée et le frottement distribués le long d'un train de tiges
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US12271957B2 (en) 2022-07-29 2025-04-08 Chevron U.S.A. Inc. Well operation task management interface
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