# US 8,788,209 B2 · Determining fluid rate and phase information for a hydrocarbon well using predictive models > Agents: this data is available as JSON from the patentgrep API and MCP server — see https://patentgrep.com/llms.txt - Number: US 8,788,209 B2 - Document ID: US8788209B2 - Status: Granted - Kind: B2 - Application number: 13/772,655 - Filed: 2013-02-21 - Published: 2013-06-27 - Granted: 2014-07-22 - Earliest claimed: 2007-02-26 - Assignees: BP Exploration Operating Company Limited - Applicants: BP Exploration Operating Company Limited - Inventors: John Foot; Richard Geoffrey Heddle; Michael James Webster - Web page: https://patentgrep.com/patent/US8788209B2 ## CPC - G01V 11/00: Prospecting or detecting by methods combining techniques covered by two or more of main groups G01V1/00 - G01V9/00 - E21B 43/00: Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells (applicable only to water E03B) - E21B 47/06: Measuring temperature or pressure - E21B 47/10: Locating fluid leaks, intrusions or movements - G05B 17/02: electric - G06F 17/00: Digital computing or data processing equipment or methods, specially adapted for specific functions (information retrieval, database structures or file system structures therefor G06F16/00) - G01V: GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS (means for indicating the location of accidentally buried, e.g. snow-buried, persons A63B29/02) - E21B: EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS - G05B: CONTROL OR REGULATING SYSTEMS IN GENERAL; FUNCTIONAL ELEMENTS OF SUCH SYSTEMS; MONITORING OR TESTING ARRANGEMENTS FOR SUCH SYSTEMS OR ELEMENTS (systems for controlling or regulating non-electric variables G05D; systems for regulating electric or magnetic variables G05F; control devices or systems insofar as characterised by mechanical features only G05G) - G06F: ELECTRIC DIGITAL DATA PROCESSING (computer systems based on specific computational models G06N) ## Abstract A method of determining rate and phase of fluid produced from or injected into a hydrocarbon well includes obtaining first temperature and pressure measurements from sensors at the well. The first temperature and pressure measurements are applied to a plurality of predictive well models to calculate an estimated value of fluid rate and phase composition from each of the predictive well models responsive to the temperature and pressure measurements. A first fluid rate and phase composition result is derived from the estimate value of fluid rate and phase composition from each of the predictive well models. ## Claims ### Claim 1 A method of determining rate and phase composition of fluid produced from or injected into a well, the method comprising: obtaining first temperature and pressure measurements from sensors at the well; obtaining indicators of valve and choke positions from the sensors at the well and at a flowline coupled to the well; applying, by a processor, the first temperature and pressure measurements to a plurality of predictive well models to calculate an estimated value of fluid rate and phase composition from each of the predictive well models responsive to the temperature and pressure measurements; selecting at least one of the predictive well models based on the indicators of valve and choke positions; deriving a first fluid rate and phase composition result from the estimate value of fluid rate and phase composition from the at least one of the predictive well models that was selected; storing, in a memory, the first fluid rate and phase composition result and a time indicator associated with a time the first temperature and pressure measurements were obtained; obtaining second temperature and pressure measurements from the sensors at the well; comparing the second temperature and pressure measurements with the first temperature and pressure measurements; and responsive to the second temperature and pressure measurements matching the first temperature and pressure measurements within a tolerance limit, storing, in the memory, the first fluid rate and phase composition result associated with a second time indicator associated with a time the second temperature and pressure measurements were obtained. ### Claim 2 (depends on 1) The method of claim 1, the method further comprising: obtaining first temperature and pressure measurements from sensors at an additional well in a production field including the well; applying, by a processor, the first temperature and pressure measurements to a plurality of predictive well models to calculate an estimated value of fluid rate and phase composition from each of the predictive well models responsive to the temperature and pressure measurements; deriving a first fluid rate and phase composition result from the estimate value of fluid rate and phase composition from each of the predictive well models; storing, in a memory, the first fluid rate and phase composition result and a time indicator associated with a time the first temperature and pressure measurements were obtained; obtaining second temperature and pressure measurements from the sensors at the additional well; comparing the second temperature and pressure measurements with the first temperature and pressure measurements; and responsive to the second temperature and pressure measurements matching the first temperature and pressure measurements within a tolerance limit, storing, in the memory, the first fluid rate and phase composition result associated with a second time indicator associated with a time the second temperature and pressure measurements were obtained. ### Claim 3 A system for determining rate and phase composition of fluid produced from or injected into a well, the system comprising: one or more sensors located at the well; and a processing system configured to perform a method comprising; obtaining first temperature and pressure measurements from the one or more sensors at the well; obtaining indicators of valve and choke positions from the sensors at the well and at a flowline coupled to the well; applying, by a processor, the first temperature and pressure measurements to a plurality of predictive well models to calculate an estimated value of fluid rate and phase composition from each of the predictive well models responsive to the temperature and pressure measurements; selecting at least one of the predictive well models based on the indicators of valve and choke positions; deriving a first fluid rate and phase composition result from the estimate value of fluid rate and phase composition from the at least one of the predictive well models that was selected; storing, in a memory, the first fluid rate and phase composition result and a time indicator associated with a time the first temperature and pressure measurements were obtained; obtaining second temperature and pressure measurements from the one or more sensors at the well; comparing the second temperature and pressure measurements with the first temperature and pressure measurements; and responsive to the second temperature and pressure measurements matching the first temperature and pressure measurements within a tolerance limit, storing, in the memory, the first fluid rate and phase composition result associated with a second time indicator associated with a time the second temperature and pressure measurements were obtained. ### Claim 4 (depends on 3) The system of claim 3, wherein the processing system is configured to perform the method further comprising: obtaining first temperature and pressure measurements from one or more sensors at an additional well in a production field including the well; applying, by a processor, the first temperature and pressure measurements to a plurality of predictive well models to calculate an estimated value of fluid rate and phase composition from each of the predictive well models responsive to the temperature and pressure measurements; deriving a first fluid rate and phase composition result from the estimate value of fluid rate and phase composition from each of the predictive well models; storing, in a memory, the first fluid rate and phase composition result and a time indicator associated with a time the first temperature and pressure measurements were obtained; obtaining second temperature and pressure measurements from the one or more sensors at the additional well; comparing the second temperature and pressure measurements with the first temperature and pressure measurements; and responsive to the second temperature and pressure measurements matching the first temperature and pressure measurements within a tolerance limit, storing, in the memory, the first fluid rate and phase composition result associated with a second time indicator associated with a time the second temperature and pressure measurements were obtained. ### Claim 5 A non-transitory computer readable medium comprising instructions for causing one or more processors to perform a method of determining rate and phase composition of fluid produced from or injected into a well, the method comprising: obtaining first temperature and pressure measurements from sensors at the well; obtaining indicators of valve and choke positions from the sensors at the well and at a flowline coupled to the well; applying, by a processor, the first temperature and pressure measurements to a plurality of predictive well models to calculate an estimated value of fluid rate and phase composition from each of the predictive well models responsive to the temperature and pressure measurements; selecting at least one of the predictive well models based on the indicators of valve and choke positions; deriving a first fluid rate and phase composition result from the estimate value of fluid rate and phase composition from the at least one of the predictive well models that was selected; storing, in a memory, the first fluid rate and phase composition result and a time indicator associated with a time the first temperature and pressure measurements were obtained; obtaining second temperature and pressure measurements from the sensors at the well; comparing the second temperature and pressure measurements with the first temperature and pressure measurements; and responsive to the second temperature and pressure measurements matching the first temperature and pressure measurements within a tolerance limit, storing, in the memory, the first fluid rate and phase composition result associated with a second time indicator associated with a time the second temperature and pressure measurements were obtained. ### Claim 6 (depends on 5) The non-transitory computer readable medium of claim 5, the method further comprising: obtaining first temperature and pressure measurements from sensors at an additional well in a production field including the well; applying, by a processor, the first temperature and pressure measurements to a plurality of predictive well models to calculate an estimated value of fluid rate and phase composition from each of the predictive well models responsive to the temperature and pressure measurements; deriving a first fluid rate and phase composition result from the estimate value of fluid rate and phase composition from each of the predictive well models; storing, in a memory, the first fluid rate and phase composition result and a time indicator associated with a time the first temperature and pressure measurements were obtained; obtaining second temperature and pressure measurements from the sensors at the additional well; comparing the second temperature and pressure measurements with the first temperature and pressure measurements; and responsive to the second temperature and pressure measurements matching the first temperature and pressure measurements within a tolerance limit, storing, in the memory, the first fluid rate and phase composition result associated with a second time indicator associated with a time the second temperature and pressure measurements were obtained. ### Claim 7 A method of determining rate and phase composition of fluid produced from or injected into a well, the method comprising: obtaining temperature and pressure measurements from sensors at the well; obtaining indicators of valve and choke positions from the sensors at the well and at a flowline coupled to the well; applying, by a processor, the temperature and pressure measurements to a plurality of predictive well models to calculate an estimated value of fluid rate and phase composition from each of the predictive well models responsive to the temperature and pressure measurements; selecting one of the predictive well models based on the indicators of valve and choke positions; and deriving a fluid rate and phase composition result using the estimated value of fluid rate and phase composition from the one of the predictive well models that was selected. ### Claim 8 (depends on 7) The method of claim 7, the method further comprising: repeating the obtaining step for additional temperature and pressure measurements at the well, and then repeating the applying, selecting, and deriving steps, on a near real time and continuous basis.