Automatic controlling of drilling weight on bit
A method for automatically controlling drilling weight-on-bit for using a drill-string to drill along a wellbore includes establishing a drill-string model and a wellbore model, wherein the drill-string has a plurality of components along the length thereof, and the wellbore has a plurality of sections. A surface tension data of the drill-string can be acquired, and a friction coefficient-depth distribution can be obtained by calibrating the surface tension data in the drill-string model and wellbore model, and the drilling weight-on-bit can be predicted according to the calibrated drill-string and wellbore models.
1. A method of automatically controlling a drilling weight-on-bit (DWOB) for using a drill-string to drill along a wellbore, the method comprising:
establishing a drill-string model and a wellbore model, wherein the drill-string has a plurality of components along a length thereof, and the wellbore has a plurality of sections;
acquiring surface tension data of the drill-string;
obtaining a friction coefficient-depth distribution by calibrating the surface tension data in the drill-string model and the wellbore model, wherein calibrating the surface tension data in the drill-string model and the wellbore model produces a calibrated drill string model and a calibrated wellbore model;
generating a prediction of the (DWOB) according to the calibrated drill-string model and the calibrated wellbore model; and
controlling the DWOB by adjusting a surface weight-on-bit (SWOB) based on the prediction,
wherein the surface tension data is acquired when the drill-string is out of slips; a drill bit disposed on the drill-string is off bottom near a bottom hole; the drill-string is rotating at drilling rates for rotatory drilling; a pump pressure is pumping at drilling rates for rotary and slide drilling; the drill-string has been stationary for a predetermined period of time; and/or after the predetermined period of time the drill-string begins to move downward and rotate.
2. The method of claim 1 , wherein the wellbore model is established according to a list of the plurality of sections, with each of the plurality of sections having a specified diameter, depth, length, heading and friction coefficient.
3. The method of claim 1 , wherein the drill-string model is established according to a list of the plurality of components along the drill-string, each one of the plurality of components having a specified diameter, length, weight, density and moment of inertia.
4. The method of claim 1 , wherein when additional components are added to the drill-string so as to lower the drill bit within the wellbore, the drill-string model is automatically updated for depth, location, and contact points of each of the additional components.
5. The method of claim 1 , wherein the surface tension data is acquired from at least one of a hookload at a surface or a high sampling rate sensor below a top drive that provides torque to the drill-string.
6. The method of claim 1 , wherein acquiring the surface tension data further comprises acquiring at least one of a rotary speed (RPM) of the drill bit, the pump pressure, or a bit depth.
7. The method of claim 1 , wherein the surface tension data is checked by confirming that:
the drill-string is rotating at drilling rates for rotary drilling;
the drill-string begins to move downwards after having been stationary for the predetermined period of time, while excluding upwards movements; and
set-point changes exceeding a weight of added drill-string components are ignored.
8. The method of claim 1 , wherein the friction coefficient-depth distribution is obtained by:
calculating a drill-string bottom tension at a bottom of the drill-string using the following Equations:
F T k =F k-1 T +w k cos(θ k )+μ k F N k
F N k =( F k-1 T δα sin θ k ){circumflex over ( )}2+( F k-1 T δθ+w k sin θ k ){circumflex over ( )}2 (1)
wherein F K T is a k th component top tension at a top of a k th drill-string component, F N k is a normal force, w k is a buoyant weight, θ k is inclination, μ k is an effective friction coefficient of the k th drill-string component, and δα and δθ are a difference in azimuth and inclination between the k th drill-string component and a k-1 th drill-string component;
calculating a lower component bottom tension at a bottom of a lower drill-string component using an upper component bottom tension of an upper drill-string component as a lower component top tension at the top of the lower drill-string component, until obtaining a deepest component top tension at a top of a deepest drill-string component F T 1 ;
calculating μ k by using F T 1 in Equation (1) and assuming the drill bit is off bottom;
attributing the drill-string friction coefficient depth distribution to the wellbore of a corresponding depth; and
repeating calculation of the drill-string bottom tension at the bottom of the drill string using Equation (1), calculation of the lower component bottom tension at the bottom of the lower drill-string component, calculation of μ k by using F T 1 in Equation (1), and attribution of the drill-string friction coefficient depth distribution to the wellbore of the corresponding depth when a new drill-string component is added.
9. The method of claim 8 , wherein if the drill-string is under a compression force F cr ,
F
cr
≥
(
4
2
-
2
)
(
EI
β
w
sin
θ
r
)
1
/
2
(
2
)
wherein E is Young's modulus, I is a polar moment, β is a buoyancy factor, w is a linear density, θ is an inclination of the wellbore, and r is a radius of the wellbore, then the surface tension data is calibrated by the following equation:
F
T
k
=
-
2
(
EI
β
w
sin
θ
r
)
1
/
2
tan
(
μ
k
Δ
L
[
r
β
w
sin
θ
4
EI
]
1
2
-
tan
-
1
{
F
T
k
-
1
[
r
4
EI
β
w
sin
θ
]
1
/
2
}
)
(
3
)
wherein F T k is the k th component top tension at the top of the k th drill-string component, μ k is the effective friction coefficient of the k th drill-string component, and ΔL is a change of length for a joint.
10. The method of claim 9 , wherein the friction coefficient-depth distribution is obtained by:
measuring and storing off-bottom tension at the top of the drill-string after adding the new drill-string component while also storing drill-string parameters, wherein the drill-string parameters include wellbore geometry, drill-string length, and drill-string tension at a time of storing;
selecting a friction coefficient at each corresponding depth that minimizes an objective function J({right arrow over (μ)}), wherein the objective function J({right arrow over (μ)}) is a total sum of a norm of differences between a measured surface tension and a predicted off-bottom surface tension under the corresponding drill-string parameters according to the following equation:
J ({right arrow over (μ)})=Σ i n |d i −F i ({right arrow over (μ)})| m (4)
wherein n is a number of off-bottom tension stored, d i is an i th measured off-bottom surface tension, F i ({right arrow over (μ)}) is a model predicted surface tension when the drill bit is off bottom for a friction coefficient profile {right arrow over (μ)}; m is a positive number, and ∥ denotes absolute value; wherein F i ({right arrow over (μ)}) equals F T k in Equation (1);
storing all or part of the coefficients to the drill-string model and the wellbore model; and
deleting an oldest stored off-bottom tension and an oldest stored of each of the drill-string parameters when the number of the stored off-bottom tension and the stored drill-string parameters exceeds a predetermined value.
11. The method of claim 10 , wherein m=2 and n=10.
12. The method of claim 10 , wherein the predetermined value is 10.
13. The method of claim 1 , wherein generating a prediction of the DWOB further comprises:
selecting, by a user, the SWOB as differences between a first surface tension used for drilling and a second surface tension of rotating off-bottom when lowering the drill-string inside the wellbore; and
using the SWOB to calculate a third surface tension and a tension at each lower drill-string component and the drill bit by using the calibrated drill-string and wellbore models, wherein DWOB is taken as a negative of the tension at the drill bit.
14. The method of claim 13 , wherein generating a prediction of the DWOB further comprises:
calculating a transfer ratio as DWOB/SWOB.
15. The method of claim 1 , wherein controlling the DWOB further comprises:
selecting, by a user, a DWOB value,
inputting the DWOB value into the calibrated drill-string model and the calibrated wellbore model, wherein a tension at the drill bit is set as a negative value of the DWOB, and
calculating a surface tension using the calibrated drill-string model and the calibrated wellbore model to obtain a SWOB value; and
automatically adjusting the SWOB based on the SWOB value.
16. A system for automatically controlling DWOB to drill along a wellbore, the system comprising:
a drill-string having at least a bottom hole assembly (BHA), transition pipes, and drill pipes, and the BHA comprising a drill bit, drill collars, and drilling stabilizers;
a sensor for measuring surface tension data of the drill-string;
a computer having a processor and a memory;
an algorithm stored in the memory to be executed by the processor, the algorithm comprising:
establishing a drill-string model for the drill-string and a wellbore model for the wellbore, wherein the wellbore includes a plurality of sections;
acquiring the surface tension data of the drill-string, wherein the surface tension data is acquired when the drill-string is out of slips; the drill bit is off bottom near a bottom hole; the drill-string is rotating at drilling rates for rotatory drilling; a pump pressure is pumping at drilling rates for rotary and slide drilling; the drill-string has been stationary for a predetermined period of time; and/or after the predetermined period of time the drill-string begins to move downward and rotate;
obtaining a friction coefficient-depth distribution by calibrating the surface tension data;
generating a prediction of the DWOB according to a calibrated drill-string and wellbore model, the DWOB being controlled by adjusting a SWOB.
17. The system of claim 16 , wherein the surface tension data is further checked by confirming that:
the drill-string is rotating at drilling rates;
the drill-string begins to move downwards while excluding upwards movements; and
set-point changes exceeding a weight of added drill-string components are ignored.
18. The system of claim 16 , wherein the friction coefficient-depth distribution is obtained by:
calculating a drill-string bottom tension at a bottom of the drill-string using the following Equations:
F T k =F k-1 T +w k cos(θ k )+μ k F N k
F N k =( F k-1 T δα sin θ k ){circumflex over ( )}2+( F k-1 T δθ+w k sin θ k ){circumflex over ( )}2 (1)
wherein F T k is a k th component top tension at a top of a k th drill-string component, F N k is a normal force, w k is a buoyant weight, θ k is inclination, μ k is an effective friction coefficient of the k th drill-string component, and δα and δθ are a difference in azimuth and inclination between the k th drill-string component and a k−1 th drill-string component;
calculating a lower component bottom tension at a bottom of a lower drill-string component using an upper component bottom tension of an upper drill-string component as a lower component top tension of the lower string component, until obtaining a deepest component top tension at a top of a deepest drill-string component F T 1 ;
calculating μ k by using F T 1 in Equation (1) and assuming the drill bit is off bottom;
attributing the drill-string friction coefficient to the wellbore of a corresponding depth; and
repeating calculation of the drill-string bottom tension at the bottom of the drill string using Equation (1), calculation of the lower component bottom tension at the bottom of the lower drill-string component, calculation of μ k by using F T 1 in Equation (1), and attribution of the drill-string friction coefficient to the wellbore of the corresponding depth when a new drill-string component is added.
19. The system of claim 16 , wherein if the drill-string is under a compression force F cr ,
F
cr
≥
(
4
2
-
2
)
(
EI
β
w
sin
θ
r
)
1
/
2
(
2
)
wherein E is a Young's modulus, I is a polar moment, β is a buoyancy factor, w is a linear density, θ is an inclination of the wellbore, and r is a radius of the wellbore, then the surface tension data is calibrated by the following equation:
F
T
k
=
-
2
(
EI
β
w
sin
θ
r
)
1
/
2
tan
(
μ
k
Δ
L
[
r
β
w
sin
θ
4
EI
]
1
2
-
tan
-
1
{
F
T
k
-
1
[
r
4
EI
β
w
sin
θ
]
1
/
2
}
)
(
3
)
wherein F T k is a k th component top tension at a top of a k th drill-string component, μ k is the effective friction coefficient of the k th drill-string component, and ΔL is a change of length for a joint.
20. The system of claim 16 , wherein the friction coefficient-depth distribution is obtained by:
measuring and storing off-bottom tension at a top of the drill-string after adding a new drill-string component while also storing drill-string parameters, wherein the drill-string parameters include wellbore geometry, drill-string length, and drill-string tension according to a time of recording;
selecting a friction coefficient at each corresponding depth that minimizes an objective function J({right arrow over (μ)}), wherein the objective function J({right arrow over (μ)}) is a total sum of a norm of differences between a measured surface tension and a predicted off-bottom surface tension under the corresponding drill-string parameters according to the following equation:
J ({right arrow over (μ)})=Σ i n |d i −F i ({right arrow over (μ)})| m (4)
wherein n is a number of off-bottom tension data stored, d i is an i th measured off-bottom surface tension, F i ({right arrow over (μ)}) is a model predicted surface tension when the drill bit is off bottom for a friction coefficient profile {right arrow over (μ)}; m is a positive number, and ∥ denotes absolute value; wherein F i ({right arrow over (μ)}) equals F T k in Equation (1);
storing all or part of the friction coefficients to the drill-string model and the wellbore model; and
deleting an oldest stored off-bottom tension and an oldest of each of the drill-string parameters when the number of the stored off-bottom tension and the drill-string parameters exceeds a predetermined value.
21. The system of claim 16 , wherein generating a prediction of the DWOB further comprises:
selecting, by a user, the SWOB as differences between a first surface tension used for drilling and a second surface tension of rotating off-bottom when lowering the drill-string inside the wellbore; and
using the selected SWOB to calculate a third surface tension and a tension at each lower drill-string component and the drill bit by using the calibrated drill-string and wellbore models, wherein the DWOB is taken as a negative of the tension at the drill bit.
22. The system of claim 21 , wherein generating a prediction of the DWOB further comprises:
calculating a transfer ratio as DWOB/SWOB.
23. The system of claim 16 , wherein controlling the DWOB further comprises:
selecting, by a user, a DWOB value;
inputting the selected DWOB value into the calibrated drill-string model and the calibrated wellbore model in step iii), wherein the tension at the drill bit is set as a negative value of the selected DWOB;
calculating the surface tension using the calibrated drill string model and the calibrated wellbore model to obtain a SWOB value; and
automatically adjusting the SWOB based on the SWOB value.