Determining fluid rate and phase information for a hydrocarbon well using predictive models
AssigneeBP Exploration Operating Company Limited
InventorsJohn Foot, Richard Heddle, Michael James Webster
Life of this patent
Estimating the term…
Abstract
Physical models of wells are used to determine rate and phase composition for fluid produced from or injected into the wells on a near real time and continuous basis. The method can be used to alert operators or others of conditions in a well or field to permit more immediate response. The method can be more tolerant of sensor faults, sensor drift, anomalous data or other occurrences which could otherwise lead to incorrect output. More than one model can be used to permit a hierarchy of calculation such that the rate and phase determination is more tolerant of anomalous data. The calculated rate and phase values from one or more wells can be reconciled against facility data.
Claims15
A method of determining rate and phase of fluid produced from or injected into a hydrocarbon well, the method comprising:
- obtaining temperature and pressure measurements from sensors at 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;
- and
- deriving a fluid rate and phase composition result from the estimated value of fluid rate and phase composition from each of the predictive well models by:
- ranking the plurality of predictive well models;
- responsive to the temperature and pressure measurements not including a measurement from a sensor from the sensors necessary to a highest-ranked one of the plurality of predictive well models, selecting a next-lower ranked one of the predictive well models;
- and
- deriving fluid rate and phase composition result using the selected predictive well model.
A method of determining rate and phase of fluid produced from or injected into a hydrocarbon well, the method comprising:
- obtaining temperature and pressure measurements from a plurality of sensors at 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;
- comparing changes in the temperature and pressure measurements relative to previously obtained temperature and pressure measurements;
- selecting one of the predictive well models based on one of the plurality of sensors identified, during comparing changes in the temperature and pressure measurements, as exhibiting a greater change in measurements than others of the plurality of sensors by more than a predetermined amount;
- and
- deriving the fluid rate and phase composition result using the estimated value of fluid rate and phase composition from the one of the predictive well model that was selected.
A method of determining rate and phase of fluid produced from or injected into a hydrocarbon well, the method comprising:
- obtaining temperature and pressure measurements from sensors at the well;
- applying 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;
- assigning a hierarchy among the plurality of predictive well models;
- statistically comparing changes in the temperature and pressure measurements relative to previously obtained temperature and pressure measurements from the sensors;
- responsive to the comparing, determining that one or more of the sensors is exhibiting instability;
- downgrading corresponding ones of the predictive well models in the hierarchy based on the one or more sensors that is exhibiting instability;
- and
- deriving a fluid rate and phase composition result from the estimated value of fluid rate and phase composition from at least one of the predictive well models based on the hierarchy.
A method of determining rate and phase of fluid produced from or injected into a hydrocarbon well, the method comprising:
- obtaining temperature and pressure measurements from sensors at 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;
- calculating, using at least a subset of the plurality of predictive well models, an expected measurement value for one of the sensors, assuming current measurements from others of the sensors to be accurate;
- deriving a fluid rate and phase composition result from the estimated value of fluid rate and phase composition from each of the predictive well models;
- and
- identifying the one of the sensors as being improperly calibrated in response to the expected measurement value for the one of the sensors substantially differing from the temperature and pressure measurements obtained from the one of the sensors.
A method of determining rate and phase of fluid produced from or injected into a hydrocarbon well, the method comprising:
- obtaining temperature and pressure measurements from sensors at the well;
- applying 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;
- assigning a hierarchy among the plurality of predictive well models;
- and
- selecting the estimated value of fluid rate and phase composition calculated for a highest-ranked one of the predictive well models in the hierarchy as the fluid rate and phase composition result, in response to the estimated value from the highest-ranked one of the predictive well models being close to the estimated value of fluid rate and phase composition calculated for at least one of a next-most-highest ranked predictive well models in the hierarchy.
Dependencies are inferred from the claim text.