In-line methods and apparatuses for determining the composition of an emulsified drilling fluid

Patent metadata

Field	Value
Publication number	US-10309173-B2
Application number	US-201615319561-A
Country	US
Kind code	B2
Filing date	Feb 2, 2016
Priority date	Feb 2, 2016
Publication date	Jun 4, 2019
Grant date	Jun 4, 2019

Abstract

Methods and apparatuses that measure thermal conductivity and electrical conductivity of a emulsified drilling fluid may be used to indirectly measure the salinity and the average specific gravity of the solids in the emulsified drilling fluid. For example, a drilling assembly may comprise a drill string extending into a wellbore penetrating a subterranean formation; a pump configured to circulate a drilling fluid through the drilling assembly; a first flow line fluidly coupling the wellbore to a retention pit; a second flow line fluidly coupling the retention pit to the pump; a third flow line fluidly coupling the pump to the drill string; and an in-line analysis system fluidly coupled to the retention pit, fluidly coupled to the second flow line, or fluidly coupled to the third flow line, the in-line analysis system comprising a thermal conductivity meter and/or an electrical conductivity meter to a sample container.

First claim

The invention claimed is:

1. A method comprising:
drilling a wellbore penetrating a subterranean formation while circulating an emulsified drilling fluid through the wellbore to surface treatment systems and back to the wellbore, the emulsified drilling fluid comprising an oil phase, a water phase, and solids;
measuring a thermal conductivity of the emulsified drilling fluid in at least one location along the surface treatment systems and before circulating back into the wellbore;
calculating an oil phase volume and a water phase volume for the emulsified drilling fluid based on the thermal conductivity and an oil-to-water ratio of the emulsified drilling fluid;
calculating an average specific gravity of the solids based on the oil phase volume, water phase volume, and a density of the emulsified drilling fluid; and
changing at least one selected from the group consisting of a drilling parameter, a composition of the emulsified drilling fluid, a solids removal treatment, and a combination thereof based on the average specific gravity of the solids.

2. The method of claim 1 , wherein measuring the thermal conductivity of the emulsified drilling fluid is at a plurality of fluid pressures; wherein calculating the oil phase volume and the water phase volume is based on the thermal conductivity at the plurality of fluid pressures and an oil-to-water ratio of the emulsified drilling fluid.

3. The method of claim 1 , wherein the emulsified drilling fluid is at an elevated temperature relative to ambient temperature when measuring the thermal conductivity of the emulsified drilling fluid.

4. The method of claim 1 , wherein the emulsified drilling fluid is at a reduced temperature relative to ambient temperature when measuring the thermal conductivity of the emulsified drilling fluid.

5. The method of claim 1 , wherein the surface treatment systems include a fluid processing unit upstream of a retention pit, and wherein measuring the thermal conductivity is at the fluid processing unit.

6. The method of claim 5 , wherein the fluid processing unit comprises a centrifuge, wherein the thermal conductivity is a first thermal conductivity and the average specific gravity of the solids is the first average specific gravity of the solids, and wherein measuring the first thermal conductivity immediately before the centrifuge and the method further includes measuring a second thermal conductivity immediately after the centrifuge, and calculating a second average specific gravity of the solids based on the second thermal conductivity.

7. The method of claim 1 , wherein the surface treatment systems include a fluid processing unit upstream of a retention pit, and wherein measuring the thermal conductivity is at the retention pit.

8. The method of claim 1 , wherein the surface treatment systems include a retention pit upstream of a mixer, and wherein measuring the thermal conductivity is downstream of the mixer.

9. An in-line analysis system comprising:
an analysis unit selected from the group consisting of a thermal conductivity meter, an electrical conductivity meter, and any combination thereof; and
a processor communicably coupled to the analysis unit and including a non- transitory, tangible, computer-readable storage medium containing a program of instructions that cause a computer system running the program of instructions to:
receive one selected from the group consisting of a thermal conductivity of an emulsified drilling fluid from the thermal conductivity meter, an electrical conductivity of the emulsified drilling fluid from the electrical conductivity meter, an electrical conductivity of a broken emulsified drilling fluid from the electrical conductivity meter, and any combination thereof;
perform at least one selected from the group consisting of:
(A) calculate an oil phase volume and a water phase volume for the emulsified drilling fluid based on the thermal conductivity and an oil-to-water ratio of the emulsified drilling fluid; calculate an average specific gravity of the solids based on the oil phase volume, water phase volume, and a density of the emulsified drilling fluid;
(B) calculate a salinity of the water phase of the emulsified drilling fluid based on the thermal conductivity of the emulsified drilling fluid and an oil-to-water ratio of the emulsified drilling fluid; and
(C) calculating a salinity of the water phase of the emulsified drilling fluid based on the electrical conductivity of the broken emulsified drilling fluid;

change at least one selected from the group consisting of a drilling parameter, a composition of the emulsified drilling fluid, a solids removal treatment, and any combination thereof based on one selected from the group consisting of the average specific gravity of the solids, the salinity of the water phase of the emulsified drilling fluid, and any combination thereof.

10. A drilling assembly comprising:
a drill string extending into a wellbore penetrating a subterranean formation;
a pump configured to circulate a drilling fluid through the drilling assembly;
a first flow line fluidly coupling the wellbore to a retention pit;
a second flow line fluidly coupling the retention pit to the pump;
a third flow line fluidly coupling the pump to the drill string; and
an in-line analysis system of claim 9 fluidly coupled to the retention pit, fluidly coupled to the second flow line, or fluidly coupled to the third flow line, the in-line analysis system comprising a thermal conductivity meter, an electrical conductivity meter, or both coupled to a sample container.

Assignees

• Halliburton Energy Services Inc

Inventors

• Kleinguetl Kevin Gregory
• Jamison Dale E
• Fowler Drew A
• Jackson Brice Aaron

Classifications

• G01N33/2823

  Raw oil, drilling fluid or polyphasic mixtures · CPC title

• C09K8/02 Primary

  Well-drilling compositions · CPC title

• G01F1/712

  using auto-correlation or cross-correlation detection means · CPC title

• E21B21/068 Primary

  using chemical treatment · CPC title

• G01N29/222

  Constructional or flow details for analysing fluids (optoacoustic fluid cells G01N29/2425) · CPC title