# US 10,865,636 B2 · Fiber optic measurements to evaluate fluid flow > Agents: this data is available as JSON from the patentgrep API and MCP server — see https://patentgrep.com/llms.txt - Number: US 10,865,636 B2 - Document ID: US10865636B2 - Status: Granted - Kind: B2 - Application number: 16/340,825 - Filed: 2017-10-10 - Published: 2019-08-29 - Granted: 2020-12-15 - Earliest claimed: 2016-10-10 - Assignees: Schlumberger Technology Corporation - Applicants: Schlumberger Technology Corporation - Inventors: Colin Allan Wilson; Joel Herve Le Calvez; Brian D. Clark - Web page: https://patentgrep.com/patent/US10865636B2 ## CPC - E21B 47/103: using thermal measurements - E21B 47/04: Measuring depth or liquid level - E21B 47/06: Measuring temperature or pressure - E21B 47/07: Temperature - E21B 43/27: by use of eroding chemicals, e.g. acids - E21B: EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS ## Abstract A method includes varying a temperature of a treatment fluid. The treatment fluid is pumped into the first wellbore as part of a fluid diversion process or a fluid treatment process after the temperature of the treatment fluid is varied. A first downhole measurement is obtained in the first wellbore using a cable in the first wellbore or a first sensor coupled to the cable concurrently with or after the fluid diversion process or the fluid treatment process. An additional measurement is obtained concurrently with obtaining the first downhole measurement. The first downhole measurement and the additional measurement are combined or compared. A location where the treatment fluid is flowing through perforations in the first wellbore is determined based upon the combining or comparing the first downhole measurement and the additional measurement. ## Claims ### Claim 1 A method, comprising: pumping a treatment fluid into a first wellbore as part of a fluid diversion process or a fluid treatment process, wherein a temperature of the treatment fluid causes deformation of an object in the first wellbore; obtaining a first downhole measurement in the first wellbore using a cable in the first wellbore or a first sensor coupled to the cable concurrently with or after the fluid diversion process or the fluid treatment process, wherein the first downhole measurement comprises a strain measurement, a vibration measurement, or a pressure measurement at a plurality of locations in the first wellbore related to the deformation; obtaining one or more additional measurements concurrently with obtaining the first downhole measurement; combining or comparing the first downhole measurement and the one or more additional measurements; and determining a location where the treatment fluid is flowing through perforations in the first wellbore based upon the combining or comparing the first downhole measurement and the one or more additional measurements. ### Claim 2 (depends on 1) The method of claim 1, wherein the cable is positioned in a tubular in the first wellbore. ### Claim 3 (depends on 1) The method of claim 1, wherein the cable is positioned in an annulus between a tubular in the first wellbore and a wall of the first wellbore. ### Claim 4 (depends on 1) The method of claim 1, wherein the cable is positioned outside a casing in the first wellbore. ### Claim 5 (depends on 1) The method of claim 1, wherein the cable comprises a fiber-optic cable that is configured to obtain the first downhole measurement at a plurality of locations along the fiber-optic cable. ### Claim 6 (depends on 1) The method of claim 1, further comprising cooling the treatment fluid by adding solid carbon dioxide, liquid carbon dioxide, liquid nitrogen, or water ice to the treatment fluid prior to pumping the treatment fluid into the first wellbore. ### Claim 7 (depends on 1) The method of claim 1, further comprising heating the treatment fluid using a boiler or by adding a chemical that generates an exothermic reaction in the treatment fluid prior to pumping the treatment fluid into the first wellbore. ### Claim 8 (depends on 1) The method of claim 1, further comprising reducing a temperature of the treatment fluid by adding solid carbon dioxide into the treatment fluid, wherein the solid carbon dioxide generates gas that causes a cavitation noise in the first wellbore, and wherein the first downhole measurement comprises a pressure or vibration measurement in response to the cavitation noise. ### Claim 9 (depends on 1) The method of claim 1, wherein the one or more additional measurements comprise a first surface measurement obtained by a second sensor at the surface, and wherein the first surface measurement comprises pressure, flow rate, or a combination thereof. ### Claim 10 (depends on 9) The method of claim 9, wherein the one or more additional measurements also comprise a second surface measurement obtained by a third sensor at the surface, and wherein the second surface measurement comprises a pressure wave, a shear wave, or a combination thereof. ### Claim 11 (depends on 1) The method of claim 1, wherein the one or more additional measurements comprise a second downhole measurement obtained by a downhole tool in a second wellbore, and wherein the second downhole measurement comprises a pressure wave, a shear wave, or both. ### Claim 12 (depends on 1) The method of claim 1, further comprising varying a parameter of the treatment fluid being pumped into the first wellbore in response to determining the location where the treatment fluid is flowing, wherein the parameter comprises a pressure, a flow rate, a composition, or a combination thereof. ### Claim 13 A method, comprising: running a first downhole tool into a first wellbore; perforating the first wellbore using the first downhole tool; running a fiber-optic cable into the first wellbore after the first wellbore is perforated; varying a temperature of a treatment fluid; pumping the treatment fluid into the first wellbore as part of a fluid diversion process or a fluid treatment process after the first wellbore is perforated and after the temperature of the treatment fluid is varied; obtaining a first downhole measurement in the first wellbore using the fiber-optic cable concurrently with or after the fluid diversion process or the fluid treatment process, wherein the first downhole measurement comprises a temperature measurement at a plurality of locations along the fiber-optic cable; obtaining an additional measurement concurrently with obtaining the first downhole measurement, wherein the additional measurement comprises: a pressure measurement or a flow rate measurement obtained at a surface location; or a pressure wave measurement or a shear wave measurement obtained in a second wellbore; combining or comparing the first downhole measurement and the additional measurement; determining a location where the treatment fluid is flowing through the perforations in the first wellbore based upon the combining or comparing the first downhole measurement and the additional measurement; and varying a parameter of the treatment fluid being pumped into the first wellbore in response to determining the location where the treatment fluid is flowing, wherein the parameter comprises a pressure, a flow rate, a composition, or a combination thereof. ### Claim 14 A system, comprising: a first downhole tool configured to be run into a first wellbore and to perforate the first wellbore; a cable configured to be run into the first wellbore and to obtain a first downhole measurement concurrently with or after a fluid diversion process or a fluid treatment process in the first wellbore, wherein the fluid diversion process or the fluid treatment process takes place after the first wellbore is perforated, and wherein the fluid diversion process or the fluid treatment process comprises pumping a treatment fluid into the first wellbore after a temperature of the treatment fluid is varied; a first sensor configured to obtain an additional measurement concurrently with the cable obtaining the first downhole measurement; and a processor configured to combine or compare the first downhole measurement and the additional measurement and to determine a location where the treatment fluid is flowing through perforations based upon the combining or comparing the first downhole measurement and the additional measurement. ### Claim 15 (depends on 14) The system of claim 14, wherein the cable comprises a fiber-optic cable that is configured to obtain the first downhole measurement at a plurality of locations along the fiber-optic cable. ### Claim 16 (depends on 14) The system of claim 14, wherein the first sensor is positioned at a surface location, and wherein the additional measurement comprises pressure, flow rate, or a combination thereof. ### Claim 17 (depends on 14) The system of claim 14, wherein the first sensor is positioned in a second wellbore, and wherein the additional measurement comprises a pressure wave, a shear wave, or both. ### Claim 18 A method, comprising: pumping a treatment fluid into a first wellbore as part of a fluid diversion process or a fluid treatment process obtaining a first downhole measurement in the first wellbore using a cable in the first wellbore or a first sensor coupled to the cable concurrently with or after the fluid diversion process or the fluid treatment process; obtaining one or more additional measurements concurrently with obtaining the first downhole measurement, wherein the one or more additional measurements comprise a first surface measurement obtained by a second sensor at the surface, and wherein the first surface measurement comprises pressure, flow rate, or a combination thereof; combining or comparing the first downhole measurement and the one or more additional measurements; and determining a location where the treatment fluid is flowing through perforations in the first wellbore based upon the combining or comparing the first downhole measurement and the one or more additional measurements. ### Claim 19 A method, comprising: pumping a treatment fluid into a first wellbore as part of a fluid diversion process or a fluid treatment process obtaining a first downhole measurement in the first wellbore using a cable in the first wellbore or a first sensor coupled to the cable concurrently with or after the fluid diversion process or the fluid treatment process; obtaining one or more additional measurements concurrently with obtaining the first downhole measurement, wherein the one or more additional measurements comprise a second downhole measurement obtained by a downhole tool in a second wellbore, and wherein the second downhole measurement comprises a pressure wave, a shear wave, or both; combining or comparing the first downhole measurement and the one or more additional measurements; and determining a location where the treatment fluid is flowing through perforations in the first wellbore based upon the combining or comparing the first downhole measurement and the one or more additional measurements. ### Claim 20 (depends on 19) The method of claim 19, wherein the one or more additional measurements also comprise a second surface measurement obtained by a third sensor at the surface, and wherein the second surface measurement comprises a pressure wave, a shear wave, or a combination thereof.