A computer implemented 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; characterised in that the method further comprises: 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 the temperature and pressure measurements relative to previous temperature and pressure measurements over time; responsive to the comparing, determining that one or more of the temperature and pressure measurements are varying and therefore unstable; downgrading corresponding ones of the predictive well models in the hierarchy based on the one or more varying and therefore unstable 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, according to the hierarchy. obtaining temperature and pressure measurements from sensors at the well; characterised in that the method further comprises: 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 the temperature and pressure measurements relative to previous temperature and pressure measurements over time; responsive to the comparing, determining that one or more of the temperature and pressure measurements are varying and therefore unstable; downgrading corresponding ones of the predictive well models in the hierarchy based on the one or more varying and therefore unstable 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, according to the hierarchy. 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 the temperature and pressure measurements relative to previous temperature and pressure measurements over time; responsive to the comparing, determining that one or more of the temperature and pressure measurements are varying and therefore unstable; downgrading corresponding ones of the predictive well models in the hierarchy based on the one or more varying and therefore unstable 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, according to the hierarchy.