Bp Exploration Operating Company Limited

Bp Corporation North America Inc.

John Foot

Michael James Webster

Richard Geoffrey Heddle

Hugh Richard Rees

German Yusti

Tor Kristian Kragas

Hugh Rees

Tor Kragas

A method and system for estimating reservoir pressure in a hydrocarbon reservoir from downhole pressure measurements of producing wells is disclosed. Pressure measurements are obtained from wells in the production field over time, and communicated to a server that applies the pressure measurements for a well to a model of that well. The server operates the model using the pressure measurements to determine an operating mode of the well, such as producing or shut-in. Upon detection of a change in operating mode indicative of an abrupt change in flow at the well, such as corresponding to a shut-in event, additional downhole pressure measurement data is acquired until a steady-state condition is reached. The pressure measurements are used to determine a reservoir pressure, which is transmitted to a responsible reservoir engineer or other user. Modification of the determined reservoir pressure value by the user can be received, and the stored reservoir pressure and well model are updated accordingly.

Automated hydrocarbon reservoir pressure estimation

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.

Determining fluid rate and phase information for a hydrocarbon well using predictive models

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.

Automated monitoring and management of well tests of hydrocarbon wells in a production field. Routing of the output of a well to a flow meter, separated from the output from other wells in the field, is detected by a computer system such as a server. Measurement data including the flow as measured by the flow meter, and also other measurements such as temperatures and pressures contemporaneous with the flow meter measurements, are acquired by the computer system; a stable period is identified, over which the flow test measurement data are considered valid. Upon completion of a specified duration or upon a change in the flow environment, the computer system notifies the user of the completion of the flow test. The flow test results can be used to modify predictive well models, with the modification dependent on validation by the user. The system can also plan and schedule future flow tests.

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John Foot