Automated analysis of pressure data
A method to offer insight on reservoir compartmentalization through the automation of single- and multi-well formation pressure analysis. The method specifically accounts for the measurement uncertainty and any prior information about the reservoir to draw evidence on at least one of a fluid type, a locating feature of the at least one fluid body, vertical compartmentalization, and lateral compartmentalization.
1. A method for delineating and interpreting a spatial distribution of fluid bodies within a reservoir that combines domain expert knowledge and knowledge of measurement uncertainties with pressure measurement data, the method comprising:
constructing a pressure model of pressure, at a given depth in a given well, as a function of a pressure gradient at the given depth, an in-well depth measurement uncertainty, a between-well depth measurement uncertainty, an in-well pressure measurement uncertainty, and a between-well pressure measurement uncertainty;
choosing a prior distribution of the pressure gradient, the between-well pressure measurement uncertainty, and the between-well depth measurement uncertainty, wherein the choosing is based on the domain expert knowledge associated with the reservoir and the knowledge of the measurement uncertainties;
measuring the pressure measurement data, wherein the measuring includes, for each well of a plurality of wells associated with the reservoir, measuring pressure at a plurality of depths using a plurality of pressure gauges;
fitting the pressure measurement data to the pressure model to produce a fitted model, wherein the fitting the pressure measurement data includes adjusting one or more of the pressure gradient, the between-well pressure measurement uncertainty, or the between-well depth measurement uncertainty;
using, by one or more processors, the fitted model to predict one or more pressure differences of one or more pairs of wells, of the plurality of wells, at one or more depths; and
automatically determining, by the one or more processors, lateral compartmentalization associated with the one or more pairs of wells based on the predicted one or more pressure differences.
2. The method of claim 1 , wherein the knowledge of the measurement uncertainties comprises a likelihood function relating the pressure model and the measurement uncertainties.
3. The method of claim 1 , wherein the in-well depth measurement uncertainty and the in-well pressure measurement uncertainty account for precision for repeated measurements by an instrument in a same well, and wherein the between-well depth uncertainty and the between-well pressure measurement uncertainty account for accuracy for comparison of measurements by different instrument in different wells.
4. The method of claim 1 , further comprising:
constructing a second pressure model of pressure, at a given depth in a single well, as a function of the pressure gradient at the given depth, the in-well depth measurement uncertainty, and the in-well pressure measurement uncertainty; and
automatically determining, by the one or more processors, vertical compartmentalization based on the second pressure model.
5. The method of claim 4 , wherein the automatically determining vertical compartmentalization is based on a fitted model of the second pressure model and on logic rules.
6. The method of claim 5 , wherein the pressure model uses fluid densities.
7. The method of claim 1 , further comprising comparing pressure among selected zones for the plurality of wells.
8. The method of claim 1 , wherein one or more parameters of the pressure model are indicative of a fluid type.
9. The method of claim 1 , wherein one or more parameters of the pressure model include at least one of: a location of changepoints in the pressure measurement data, a delineation of hydraulic zones, or a location of fluid contacts.
10. The method of claim 1 , wherein the automatically determining lateral compartmentalization is interpreted based on the fitted model, logic rules, and an assumption that the reservoir has not been disturbed by any production or injection of fluids.
11. The method of claim 1 , wherein the automatically determining lateral compartmentalization is interpreted based on the fitted model, logic rules, and an assumption that production or injection of fluids in the reservoir has already begun.
12. The method of claim 1 , wherein the fitting the pressure model is further based on other physical measurements, including at least one of: fluid density data, fluid mobility data, fluid compositional analysis data, gas-oil ratio data, or optical density data of one or more formation fluids.
13. The method of claim 12 , wherein the pressure measurement data and the other physical measurements are associated with a delineation of hydraulic zones, a location of fluid contacts, and a location of changepoints.
14. The method of claim 12 , wherein pressure measurement data and the other physical measurements are acquired as at least one of: stationary measurements, continuous downhole logs, or measurements on core samples.
15. The method of claim 1 , further comprising recommending acquisition of new pressure measurements in at least one specific range of location based on the fitted model.