# US 11,111,783 B2 · Estimating formation properties from drill bit motion

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- Number: US 11,111,783 B2
- Document ID: US11111783B2
- Status: Granted
- Kind: B2
- Application number: 16/533,121
- Filed: 2019-08-06
- Published: 2021-02-11
- Granted: 2021-09-07
- Earliest claimed: 2019-08-06
- Assignees: Halliburton Energy Services, Inc.
- Applicants: Halliburton Energy Services, Inc.
- Inventors: John Leslie Wisinger, Jr.
- Web page: https://patentgrep.com/patent/US11111783B2

## CPC

- E21B 49/003: {by analysing drilling variables or conditions (E21B49/005 takes precedence; systems specially adapted for monitoring a plurality of drilling variables or conditions E21B44/00)}
- E21B 45/00: Measuring the drilling time or rate of penetration
- E21B 47/013: Devices specially adapted for supporting measuring instruments on drill bits
- E21B 47/024: of devices in the borehole (determining slope or direction of the borehole E21B47/022)
- G01V 1/40: specially adapted for well-logging
- G01V 9/00: Prospecting or detecting by methods not provided for in groups G01V1/00 - G01V8/00
- E21B 2200/20: Computer models or simulations, e.g. for reservoirs under production, drill bits
- E21B: EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- G01V: GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS (means for indicating the location of accidentally buried, e.g. snow-buried, persons A63B29/02)

## Abstract

A method for formation property prediction may comprise drilling a borehole into a formation using a drill bit, measuring one or more parameters of drill bit motion, and inputting the one or more parameters of the drill bit motion into a formation property prediction model which outputs one or more properties of the formation. Another method may for forming a formation property model may comprise acquiring one or more formation properties and one or more parameters of drill bit motion, forming one or more data packets, and correlating the one or more data packets in the database to form the formation property prediction model that predicts a formation property based at least in part on drill bit measurements. A system may comprise a drill bit, gyroscope unit coupled to the drill bit in a known positional relationship, a magnetometer unit coupled to the drill bit, and an information handling system.

## Claims

### Claim 1

A method for formation property prediction, comprising:
drilling a borehole into a formation using a drill bit, wherein the drill bit comprises a shank, a bit body, and a through bore that traverses through the shank and the bit body:
measuring one or more parameters of drill bit motion with one or more sensors disposed on an outer surface and within the shank or the bit body, wherein the one or more sensors are connected to a sensor subassembly by one or more channels that are inside the bit body, wherein the sensor subassembly is attached to an inner surface of the through bore adjacent to the one or more sensors; and
inputting the one or more para meters of the drill bit motion into a formation property prediction model which outputs one or more properties of the formation.

### Claim 2 (depends on 1)

The method of claim 1, further including altering the drilling of the borehole based at least in part on the outputs of the one or more properties of the formation.

### Claim 3 (depends on 1)

The method of claim 1, wherein the formation property prediction model outputs gamma concentration, wherein the one or more parameters of the drill bit motion include at least one a bit wobble, a bit whirl, or revolutions-per-minute.

### Claim 4 (depends on 1)

The method of claim 1, wherein the formation property prediction model outputs hole shape, wherein the one or more parameters include at least one of a bit whirl or a bit wobble.

### Claim 5 (depends on 1)

The method of claim 1, further including updating the formation property prediction model with one or more additional drill bit measurements.

### Claim 6 (depends on 5)

The method of claim 5, wherein the one or more parameters of the drill bit motion are measured with the one or more sensors that include at least one of an accelerometer, a magnetometer unit, or a gyroscope unit.

### Claim 7 (depends on 1)

The method of claim 1, wherein the one or more parameters of the drill bit motion are measured with the one or more sensors that include a gyroscope unit configured to measure pitch and yaw of the drill bit.

### Claim 8

A method for forming a formation property model, comprising: acquiring one or more formation properties and one or more parameters of drill bit motion using one or more sensors disposed on an outer surface and within a shank or a bit body of a drill bit, the drill bit comprising a through bore that traverses through the shank and the bit body, wherein the one or more sensors are connected to a sensor subassembly by one or more channels that are inside the bit body, wherein the sensor subassembly is attached to an inner surface of the through bore adjacent to the one or more sensors;
forming one or more data packets that comprise the one or more formation properties and the one or more parameters of drill bit motion;
storing the one or more data packets in a database; and
correlating the one or more data packets in the database to form the formation property prediction model that predicts a formation property based at least in part on drill bit measurements.

### Claim 9 (depends on 8)

The method of claim 8, further comprising updating the data packets with the drill bit measurements.

### Claim 10 (depends on 8)

The method of claim 8, wherein the formation property prediction model predicts gamma concentration in response to an input of at least one a bit wobble, a bit whirl, or revolutions-per-minute.

### Claim 11 (depends on 8)

The method of claim 8, wherein the formation property prediction model outputs hole shape in response to an input of at least one of a bit whirl or a bit wobble.

### Claim 12

A system comprising:
a drill bit, wherein the drill bit comprises a shank, a bit body, and a through bore that traverses through the shank and the bit body;
one or more sensors disposed on an outer surface and within the shank or the bit body are connected to a sensor subassembly by one or more channels that are inside the bit body, wherein the sensor subassembly is attached to an inner surface of the through bore;
a gyroscope unit coupled to the drill bit in a known positional relationship;
a magnetometer unit coupled to the drill bit; and
an information handling system configured to:
record one or more parameters of a drill bit motion from at least the gyroscope unit and the magnetometer unit;
input the one or more parameters of the drill bit motion into a formation property prediction model; and
output one or more properties of the formation.

### Claim 13 (depends on 12)

The system of claim 12, wherein the information handling system is further configured to update the formation property prediction model based at least in part on the output of the one or more properties of the formation.

### Claim 14 (depends on 12)

The system of claim 12, wherein the formation property prediction model is configured to output gamma concentration in response to an input of at least one a bit wobble, a bit whirl, or revolutions-per-minute.

### Claim 15 (depends on 12)

The system of claim 12, wherein the formation property prediction model is configured to output hole shape in response to an input of at least one of a bit whirl or a bit wobble.

### Claim 16 (depends on 12)

The system of claim 12, wherein the gyroscope unit, the magnetometer unit, or an accelerometer measure angular velocity about at least two axes of the drill bit.

### Claim 17 (depends on 12)

The system of claim 12, wherein the gyroscope unit, the magnetometer unit, or an accelerometer measure a bit wobble and the gyroscope unit is configured to measure pitch and yaw of the drill bit.

### Claim 18 (depends on 12)

The system of claim 12, wherein the gyroscope unit, the magnetometer unit, or an accelerometer measure revolutions-per-minute and wherein the gyroscope unit is configured to measure roll of the drill bit.

### Claim 19 (depends on 18)

The system of claim 18, wherein the information handling system is further configured to calculate stick slip from the revolutions-per-minute measurements.

### Claim 20 (depends on 12)

The system of claim 12, wherein the gyroscope unit, the magnetometer unit, or an accelerometer measure a bit wobble.