# US 10,370,952 B2 · Drilling operations that use compositional properties of fluids derived from measured physical properties

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- Number: US 10,370,952 B2
- Document ID: US10370952B2
- Status: Granted
- Kind: B2
- Application number: 14/419,267
- Filed: 2014-01-09
- Published: 2016-01-28
- Granted: 2019-08-06
- Earliest claimed: 2014-01-09
- Assignees: Halliburton Energy Services, Inc.
- Applicants: Halliburton Energy Services, Inc.
- Inventors: Dale E. Jamison; Cato Russell McDaniel; Shawn L. Broussard
- Web page: https://patentgrep.com/patent/US10370952B2

## CPC

- E21B 44/00: 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
- E21B 47/10: Locating fluid leaks, intrusions or movements
- E21B 44/02: Automatic control of the tool feed ({E21B44/005,} E21B44/10 take precedence)
- E21B 21/08: Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure (valve arrangements therefor E21B21/10)
- E21B: EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS

## Abstract

The physical properties of a fluid may be used in deriving the compositional properties of the fluid, which may, in turn, be used to influence an operational parameters of a drilling operation. For example, a method may include drilling a wellbore penetrating a subterranean formation with a drilling fluid as part of a drilling operation; circulating or otherwise containing the drilling fluid in a flow path that comprises the wellbore; measuring at least one physical property of the drilling fluid at a first location and a second location along the flow path; deriving a compositional property of the drilling fluid at the first location and the second location based on the at least one physical property that was measured; comparing the compositional property of the drilling fluid at the first location and the second location; and changing an operational parameter of the drilling operation based on the comparison.

## Claims

### Claim 1

A method comprising:
drilling a wellbore penetrating a subterranean formation with a drilling fluid as part of a drilling operation, the drilling fluid comprising at least two components;
circulating or otherwise containing the drilling fluid in a flow path that comprises the wellbore;
measuring the thermal conductivity of the drilling fluid at a first location and a second location along the flow path, wherein the flow path further comprises a centrifuge, and wherein the first location is immediately before the centrifuge and the second location is immediately after the centrifuge;
deriving a volume fraction for each of the at least two components of the drilling fluid at the first location and the second location based on the thermal conductivity measured at leach location;
comparing the volume fraction of each of the at least two components of the drilling fluid at the first location and the second location; and
changing an operational parameter of the drilling operation based on the comparison.

### Claim 2 (depends on 1)

The method of claim 1, wherein the operational parameter is at least one selected from the group consisting of a flow rate of the drilling fluid, a revolutions per minute of a drill bit, a rate of penetration of a drill bit into the subterranean formation, a torque applied to a drill string, a trajectory of a drill bit, a weight on a drill bit, a wellbore pressure, an equivalent circulating density, a concentration of a component of the drilling fluid, a weight of the drilling fluid, a viscosity of the drilling fluid, and any combination thereof.

### Claim 3 (depends on 1)

The method of claim 1, wherein the flow path further comprises a tubular extending from outside the wellbore to inside the wellbore, and wherein the thermal conductivity of the drilling fluid is further measured at an entrance to the tubular outside the wellbore and an exit from the tubular inside the wellbore.

### Claim 4 (depends on 1)

The method of claim 1, wherein the flow path further comprises a shaker, and wherein the thermal conductivity of the drilling fluid is further measured immediately before the shaker and is immediately after the shaker.

### Claim 5 (depends on 1)

The method of claim 1, wherein the flow path further comprises a retention pit, and wherein the thermal conductivity of the drilling fluid is further measured immediately before the retention pit and immediately after the retention pit.

### Claim 6 (depends on 1)

The method of claim 1, wherein the flow path further comprises a mixer, and wherein the first location is before the mixer and the second location is after the mixer.

### Claim 7 (depends on 1)

The method of claim 1, wherein the steps of measuring, deriving, and comparing are performed over a period of time.

### Claim 8 (depends on 1)

The method of claim 1, wherein the at least two components are selected from the group consisting of a continuous phase of the drilling fluid, a discontinuous phase of the drilling fluid, cuttings, gas, low gravity solids, high gravity solids, contaminants, and lost circulation materials.

### Claim 9 (depends on 8)

The method of claim 8, wherein at least one of the at least two components are the low gravity solids, and wherein the low gravity solids are one or more solids selected from the group consisting of calcium carbonate, marble, polyethylene, polypropylene, graphitic materials, silica, limestone, dolomite, salt crystals, shale, bentonite, kaolinite, sepiolite, illite, hectorite, insoluble polymeric materials, and organoclays.

### Claim 10 (depends on 8)

The method of claim 8, wherein at least one of the at least two components are the high gravity solids, and wherein the high gravity solids are one or more solids selected from the group consisting of barite, hematite, ilmenite, galena, manganese oxide, iron oxide, magnesium tetroxide, magnetite, siderite, celestite, dolomite, manganese carbonate, and insoluble polymeric materials.

### Claim 11 (depends on 8)

The method of claim 8, wherein at least one of the at least two components are the lost circulation materials, and wherein the lost circulation materials are one or more materials selected from the group consisting of sand, shale, ground marble, bauxite, ceramic materials, glass materials, metal pellets, silica, alumina, fumed carbon, carbon black, graphite, mica, titanium dioxide, meta-silicate, calcium silicate, kaolin, talc, zirconia, boron, fly ash, hollow glass microspheres, solid glass, synthetic fibers, resilient graphitic carbon, cellulose flakes, wood, resins, uncrosslinked polymer materials, crosslinked polymer materials, polytetrafluoroethylene materials, nut shell pieces, cured resinous particulates comprising nut shell pieces and seed shell pieces, cured resinous particulates comprising seed shell pieces and fruit pit pieces, cured resinous particulates comprising fruit pit pieces, composite materials, basalt fibers, woolastonite fibers, non-amorphous metallic fibers, metal oxide fibers, mixed metal oxide fibers, ceramic fibers, glass fibers, polymeric fibers, and cellulosic fibers.

### Claim 12 (depends on 1)

The method of claim 1, wherein the drilling fluid comprises a base fluid and m components, and the volume fraction of each component is determined using Formula I and Formula II:
βi=ki/k0 Formula I
k
m
k
0
=
[
1
+
∑
i
=
1
m
⁢
(
β
i
1
3
-
1
)
⁢
φ
i
]
3
Formula
⁢
⁢
II
wherein,
ki is the thermal conductivity of an ith component;
k0 is the thermal conductivity of the base fluid;
φi is the volume fraction of the ith component;
km is the thermal conductivity of the drilling fluid; and
m is greater than or equal to 2.