Methods and systems for calculating and evaluating value of information for reservoir fluid models derived from DFA tool data

Patent metadata

Field	Value
Publication number	US-10989835-B2
Application number	US-201414762828-A
Country	US
Kind code	B2
Filing date	Jan 13, 2014
Priority date	Jan 25, 2013
Publication date	Apr 27, 2021
Grant date	Apr 27, 2021

Abstract

A method for deriving VOI for a hydrocarbon-bearing reservoir fluid model based on DFA data (“true fluid model”) versus an “incorrect fluid model” includes calculating first, second and third objective functions that are based on NPV(s) of simulated production by a reservoir simulator with different configurations. For the first objective function, the simulator is configured with the incorrect fluid model and control variables that are optimized to derive a first group of control variable values. For the second objective function, the simulator is configured with the true fluid model and the first group of control variable values. For the third objective function, the simulator is configured with the true fluid model and control variables that are optimized to identify a second group of control variable values. The objective functions can be deterministic, or can include statistics that account for uncertainty. A visualization of such results with uncertainty is also described.

First claim

What is claimed is:

1. A method for preparing for a hydrocarbon-recovery operation based at least in part on a derived value of a hydrocarbon-bearing reservoir fluid model, the method comprising:
obtaining a first reservoir fluid sample from a reservoir using a single station sampling methodology at a single sampling station;
performing fluid analysis at the surface on the first reservoir fluid sample to obtain a first set of one or more fluid properties;
obtaining a plurality of second fluid samples of reservoir fluid using a downhole fluid analysis tool, wherein the plurality of second fluid samples are obtained from multiple locations within the reservoir, and wherein in situ downhole fluid analysis is performed on the plurality of second fluid samples to obtain a second set of one or more fluid properties; and
using a processor to:
i) determine a first fluid model that describes properties of the reservoir as a function of location within the reservoir, wherein determining the first fluid model comprises extrapolating the first set of one or more fluid properties of the first reservoir fluid sample to generate a first fluid model that characterizes the properties of the reservoir as a function of depth;
ii) determine a second fluid model that describes the properties of the reservoir as a function of location within the reservoir, wherein determining the second fluid model comprises extrapolating the second set of one or more fluid properties obtained from the analysis of the plurality of second fluid samples to generate a second fluid model that characterizes the properties of the reservoir as a function of depth;
iii) simulate a first production of reservoir fluids from the reservoir using a reservoir simulator configured with the first fluid model of and a set of control variables, and calculate at least one first net present value (NPV 1 ) of the first production of the reservoir fluids simulated by the reservoir simulator;
iv) derive optimal values for the set of control variables of iii) by maximizing a first objective function associated with the first fluid model;
v) simulate a second production of the reservoir fluids from the reservoir using the reservoir simulator configured with the second fluid model and the optimal values of the set of control variables as derived in iv), and calculate at least one second net present value (NPV C ) of the second production of the reservoir fluids simulated by the reservoir simulator; and
vi) output information that characterizes value of the second fluid model based at least in part on the at least one second NPV C and calculations involving a second objective function associated with the second fluid model.

2. The method according to claim 1 , wherein the calculations involving the second objective function comprise:
vii) simulating a third production of the reservoir fluids from the reservoir based on the reservoir simulator configured with the second fluid model and the set of control variables of iii), and calculating at least one third net present value NPV 3 of the third production of the reservoir fluids simulated by the reservoir simulator; and
viii) derive second optimal values for the set of control variables of vii) by maximizing the second objective function associated with the second fluid model.

3. The method according to claim 2 , wherein the first objective function and the second objective function are deterministic in nature and do not take into account uncertainty.

4. The method according to claim 3 , wherein:
the first objective function is based, at least in part, on the at least one first NPV 1 of the first production of the reservoir fluids simulated by the reservoir simulator in iii); and
the second objective function is based, at least in part, on the at least one second NPV C of the second production of reservoir fluids simulated by the reservoir simulator in v.

5. The method according to claim 2 , wherein the first objective function and the second objective function take into account uncertainty.

6. The method according to claim 5 , further comprising:
defining a set of uncertainty parameters and corresponding values for use in the reservoir simulations of iii), v), and vii).

7. The method according to claim 6 , wherein:
the at least one first NPV 1 comprises a first plurality of net present values, and the first objective function is based on a first portion of the first plurality of net present values of the first production simulated by the reservoir simulator in iii) for a number of different combinations of values of the set of uncertainty parameters;
the at least one second NPV C comprises a second plurality of net present values, and the second objective function is based on a second portion of the second plurality of net present values of the second production simulated by the reservoir simulator in v) for the number of different combinations of values of the set of uncertainty parameters.

8. The method according to claim 7 , wherein the calculations involving the second objective function comprise calculating a figure of merit based on results of the second objective function and the at least one second NPV C .

9. The method according to claim 7 , wherein:
the first objective function is based on first statistics of the first portion of the first plurality of net present values of the first production simulated by the reservoir simulator in iii); and
the second objective function is based on second statistics of the second portion of the second plurality of net present values of the second production simulated by the reservoir simulator in v.

10. The method according to claim 9 , wherein:
the first statistics of the first objective function are selected from a first group comprising a first mean and a first standard deviation of the first portion of the first plurality of net present values of the first production simulated by the reservoir simulator in iii); and
the second statistics of the second objective function are selected from a second group comprising a second mean and a second standard deviation of the second portion of the second plurality of net present values of the second production simulated by the reservoir simulator in v.

11. The method according to claim 7 , wherein:
the first objective function and the second objective function each have multiple instances based on different values of a risk aversion factor.

12. The method according to claim 11 , wherein:
the first objective function and the second objective function each have the form
F λ =μ λ −λσ λ ,

where F λ is the objective function for the different values of the risk aversion factor, λ, and μ λ and σ λ are means and standard deviations of the objective function, respectively, for the different values of the risk aversion factor, λ.

13. A method for preparing for a hydrocarbon-recovery operation, the method comprising:
obtaining a plurality of first fluid samples from within a wellbore of a reservoir at a single measuring station;
performing a first fluid analysis outside the wellbore on the plurality of fluid samples to determine a first set of one or more fluid properties;
obtaining a plurality of second fluid samples using a downhole fluid analysis tool, wherein the plurality of second fluid samples are obtained from multiple locations with the reservoir, and wherein in situ downhole fluid analysis is performed on the plurality of second fluid samples to determine a second set of one or more fluid properties; and
using a processor to:
i) determine a first fluid model that describes properties of the reservoir as a function of location withi

Assignees

• Schlumberger Technology Corp

Inventors

• Bailey William J
• Couet Benoit
• Kaufman Peter
• Mullins Oliver C

Classifications

• E21B49/00 Primary

  Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells · CPC title

• E21B49/087

  Well testing, e.g. testing for reservoir productivity or formation parameters · CPC title

• E21B49/10

  using side-wall fluid samplers or testers · CPC title

• E21B2200/20

  Computer models or simulations, e.g. for reservoirs under production, drill bits · CPC title

• E21B49/08

  Obtaining fluid samples or testing fluids, in boreholes or wells · CPC title