System and method for real-time monitoring and estimation of intelligent well system production performance

Patent metadata

Field	Value
Publication number	US-10280722-B2
Application number	US-201514728271-A
Country	US
Kind code	B2
Filing date	Jun 2, 2015
Priority date	Jun 2, 2015
Publication date	May 7, 2019
Grant date	May 7, 2019

Abstract

A method of online real-time estimation of production performance properties includes receiving real-time field data taken by downhole sensors, and estimating formation properties and production performance properties by applying the field data to a two or three-dimensional numerical transient thermal multiphase reservoir flow model, and automatically calibrating the model. Calibrating includes: selecting calibration parameters corresponding to values of selected model parameters, and applying the calibration parameters to the model to generate predicted properties that correlate with the selected model parameters, the predicted properties including flow rates and/or formation properties; automatically calculating a difference between the predicted properties and measured properties that correlate with the selected model parameters, and calculating an objective function value; performing an inversion that includes iteratively adjusting the selected model parameters until the objective function reaches a selected minimum value; and automatically updating the model by applying the selected model parameters associated with the minimum value.

First claim

The invention claimed is:

1. A method for online real-time modeling, estimation and forecasting of production performance properties of one or more hydrocarbon production operations, the method comprising:
receiving, by a data aggregation module, real-time field data from a field source at a processor that stores and displays information, the field data including at least one of operational parameters and measurements taken by one or more downhole sensors during the one or more production operations;
estimating, by a modelling module, formation properties and production performance properties associated with the field source by applying the field data to a two or three-dimensional numerical transient thermal multiphase reservoir flow model; and
automatically calibrating the numerical transient thermal multiphase reservoir flow model by a calibration module, wherein calibrating includes:
selecting calibration parameters corresponding to values of selected model parameters, and applying the calibration parameters to the reservoir flow model to generate a solution that includes predicted properties that correlate with the selected model parameters, the predicted properties including at least one of flow rates and formation properties;
in response to receiving real time measurement data from the field source, automatically calculating a difference between the predicted properties and measured properties obtained from the real time measurement data that correlate with the selected model parameters, and calculating an objective function value based on the difference;
performing, by an inversion module, an inversion that includes iteratively adjusting the selected model parameters until the objective function reaches a selected minimum value; and
automatically updating the transient thermal multiphase reservoir flow model by the inversion module, by applying the selected model parameters associated with the minimum objective function value; and
using the automatically calibrated transient thermal multiphase reservoir flow model to forecast at least one of: short-term reservoir parameters, long-term reservoir parameters, near-wellbore reservoir features and production performance properties.

2. The method of claim 1 , further comprising, prior to calibrating, comparing a value of one or more of the estimated formation properties and production properties to a pre-selected tolerance, wherein the calibrating is performed only if the value is outside of the tolerance.

3. The method of claim 1 , wherein the field source includes a plurality of producing zones, and the formation properties and production properties are estimated for each zone.

4. The method of claim 1 , wherein the field source includes a plurality of production boreholes, and receiving the field data includes receiving individual field data from each of the plurality of field sources and transforming the individual field data into a single data format for use in estimating the formation properties and the production properties, wherein estimating includes generating a separate model for one or more of the plurality of production boreholes, and calibrating is performed at least substantially in real-time.

5. The method of claim 1 , further comprising controlling at least one flow control device based on the forecast, to control a parameter of fluid flow in a hydrocarbon production system.

6. The method of claim 1 , wherein the thermal reservoir model is a forward model that includes coupled partial differential equations derived from mass continuity equations for multi-phase production fluids and reservoir energy equations.

7. The method of claim 1 , further comprising filtering the field data by comparing each data point in the field data to an expected uncertainty.

8. The method of claim 1 , further comprising generating a probabilistic forecast of future production properties.

9. The method of claim 8 , wherein generating the probabilistic forecast includes perturbing model parameters used to build the thermal reservoir model to produce multiple scenarios for the forward model, and inputting the multiple initial states to an uncertainty model to generate the probabilistic forecast that indicates the probability of future production properties in response to the scenarios.

10. The method of claim 1 , wherein the field source includes at least one intelligent well system with single and/or multiple zones, and the one or more downhole sensors are selected from at least one of a production logging tool (PLT), a distributed temperature sensing (DTS) system, and a permanent downhole gauge (PDG).

11. A system for estimating and forecasting production properties of one or more hydrocarbon production operations, the system including:
a data aggregation module configured to communicate with a field source via a web-based network and receive field data therefrom, the field data including at least one of operational parameters and measurements taken by one or more downhole sensors;
a transformation module configured to transform field data into an industry data format for use by at least the modeling module;
a modelling module configured to automatically input the field data into a numerical transient thermal multiphase reservoir flow model available to a plurality of users, and estimate formation properties and production properties associated with the field source based on the reservoir flow model;
a calibration module configured to receive calibration parameters corresponding to values of selected model parameters, apply the calibration parameters to the reservoir flow model to generate a solution that includes predicted properties that correlate with the selected model parameters, the predicted properties including at least one of flow rates and formation properties, the calibration module configured to automatically calculate a difference between the predicted properties and measured properties obtained from the field source that correlate with the selected model parameters, and calculate an objective function value based on the difference; and
an inversion module configured to perform an inversion that includes iteratively adjusting the selected model parameters until the objective function reaches a selected minimum value, and automatically update the reservoir flow model by applying the selected model parameters associated with the minimum objective function value.

12. The system of claim 11 , wherein the calibration module is configured to compare a value of one or more of the estimated formation properties and production properties to a pre-selected tolerance, and apply the calibration parameters only if the value is outside of the tolerance.

13. The system of claim 11 , wherein the field source includes a plurality of producing zones, and the formation properties and production properties are estimated for each zone.

14. The system of claim 11 , wherein the field source includes a plurality of production zones and/or boreholes, and the data aggregation module is configured to receive individual field data from each of the plurality of field sources and transform the individual field data into a single data format for use in estimating the formation properties and the production properties.

15. The system of claim 14 , wherein the modelling module is configured to generate a separate model for one or more of the plurality of production zones and/or boreholes and calibrating the production zones and boreholes for the seperate flow model.

16. The system of claim 11 , wherein the thermal reservoir model is a forward model that includes coupled par

Assignees

• Bello Oladele
• Denney Stanley T
• Baker Hughes A Ge Co Llc

Inventors

• Bello Oladele
• Denney Stanley T

Classifications

• G01F1/74

  Devices for measuring flow of a fluid or flow of a fluent solid material in suspension in another fluid · CPC title

• E21B43/14 Primary

  Obtaining from a multiple-zone well · CPC title

• G06Q10/04 Primary

  Forecasting or optimisation specially adapted for administrative or management purposes, e.g. linear programming or "cutting stock problem" (market predictions or forecasting for commercial activities G06Q30/0202) · CPC title

• G06Q50/02

  Agriculture; Fishing; Forestry; Mining · CPC title

• G06Q10/067

  Enterprise or organisation modelling · CPC title