Determining and considering petroleum reservoir reserves and production characteristics when valuing petroleum production capital projects

• US 9,767,421 B2
• Filed: 10/26/2011
• Issued: 09/19/2017
• Est. Priority Date: 10/26/2011
• Status: Active Grant

• Current Assignee: QRI Group, LLC
• Original Assignee: QRI Group, LLC
• Inventors: Saleri, Nansen G., Toronyi, Robert M., Ault, Joseph W., Wong, Cromwell D.
• Primary Examiner(s): Gills, Kurtis
• Application Number:
  US13/282,297
• Publication Number:
  US 20130110563A1
• Time in Patent Office: 2,155 Days
• Field of Search: 705 711
• CPC Class Codes: G06Q 10/06 Resources, workflows, human or project management; Enterprise or organisation planning; Enterprise or organisation modelling

Abstract

Determining a True Value Index™ (TVI™) for a petroleum production capital project provides a novel indicator and metric that is designed to quickly assess the economics of undertaking the petroleum production capital project. The TVI™ can be determined according to the following equation:
TVI=NPV+(β*Reserves)

• • where,
    • NPV=Net present value of a project;
    • β=Reservoir Management Factor (RMF™)=absolute value (sum of Coefficient of Reserves and Coefficient of Production) derived from multivariable correlation=to reflect the market value premium on increased reserves if the producer was public; and
    • Reserves=Barrels of proven reserves to be created by the project.

Claims

1. A method for modifying production of petroleum to increase petroleum production efficiency and/or increase petroleum recovery efficiency of petroleum reservoirs of a petroleum producer, the method comprising:

measuring, using one or more sensors placed in the petroleum reservoirs, data relating to physics and geology of the petroleum reservoir relating to at least one of reservoir pressure, fluid saturations, well productivity and drawdown, fluid profile, oil production, gas production, water production, injection rate, real displacement efficiency, vertical displacement efficiency, and pore displacement efficiency;

determining type, number, location, and efficiency of wells servicing the petroleum reservoirs;

determining a coefficient of reserves based on data obtained by the one or more sensors placed in the petroleum reservoirs and the type, number, location, and efficiency of wells servicing the petroleum reservoirs, the coefficient of reserves having units of monetary amount divided by quantity of petroleum;

determining a coefficient of production based on data obtained by the one or more sensors placed in the petroleum reservoirs and the type, number, location, and efficiency of wells servicing the petroleum reservoirs, the coefficient of production having units of monetary amount divided by quantity of petroleum;

determining a reservoir management factor (β

) for the petroleum reservoirs based on the coefficient of reserves and the coefficient of production;

determining from data obtained by the one or more sensors placed in the petroleum reservoirs and the type, number, location, and efficiency of wells servicing the petroleum reservoirs an additional quantity of proven petroleum reserves (Reserves) to be created by a proposed modification to production of petroleum from the reservoirs;

determining from data obtained by the one or more sensors placed in the petroleum reservoirs and the type, number, location, and efficiency of wells servicing the petroleum reservoirs a net present value (NPV) of the proposed modification to production of petroleum from the reservoirs, the NPV having units of monetary amount;

determining a true value index (TVI) for the proposed modification to production of petroleum from the reservoirs by relating the reservoir management factor (β

), the additional quantity of proven petroleum reserves (Reserves) to be created by the proposed modification to production of petroleum from the reservoirs, and the net present value (NPV) of the proposed modification to production of petroleum from the reservoirs; and

based on the true value index (TVI), implementing the proposed modification to production of petroleum from the reservoirs, including manually or automatically modifying operation of one or more production units selected from producing oil wells, water injection wells, gas injection wells, heat injectors, or sub-components thereof, wherein adjusting the operation of the one or more production units is selected from change in volume, change in pressure, change in temperature, change in well bore path, drilling one or more new wells, stimulating one or more existing wells, and/or increasing reservoir contact of one or more existing wells.

2. The method as in claim 1, wherein the true value index (TVI) is determined according to the following equation:

TVI=NPV+(β

*Reserves).

3. The method as in claim 1, further comprising using the true value index (TVI) as part of a method for determining the economic feasibility of the proposed modification to production of petroleum from the reservoirs.

4. The method as in claim 1, wherein determining the reservoir management factor (β

) for the petroleum producer comprises determining an absolute sum of;

the coefficient of reserves; and

the coefficient of production.

5. The method as in claim 1, further comprising determining the coefficient of reserves and the coefficient of production based in part from data relating to production of petroleum by the producer included in a 10K filing.

6. The method as in claim 1, further comprising determining the coefficient of production using statistical algorithms and historically observed petroleum production data for a sample set of petroleum producers.

7. The method as in claim 1, further comprising determining the coefficient of reserves using statistical algorithms and historically observed petroleum production data for a sample set of petroleum producers.

8. The method as in claim 1, wherein determining the reservoir management factor (β

) further comprises relating the sum of the coefficient of reserves and the coefficient of production through a multivariable correlation.

9. The method as in claim 8, wherein the reservoir management factor (β

) is determined according to the following equation;

β

=the coefficient of reserves minus the coefficient of production.

19. The method as in claim 1, wherein the coefficient of reserves and the coefficient of production are regression coefficients.

10. In a computing system having a processor and system memory, a method for modifying production of petroleum to increase petroleum production efficiency and/or increase petroleum recovery efficiency of petroleum reservoirs of a petroleum producer, the method comprising:

measuring, using one or more sensors placed in the petroleum reservoirs, data relating to physics and geology of the petroleum reservoir relating to at least one of reservoir pressure, fluid saturations, well productivity and drawdown, fluid profile, oil production, gas production, water production, injection rate, real displacement efficiency, vertical displacement efficiency, and pore displacement efficiency;

determining type, number, location, and efficiency of wells servicing the petroleum reservoirs;

inputting into the computing system data relating to the physics or geology of the petroleum reservoirs and the type, number, location, and efficiency of wells servicing the petroleum reservoirs;

the computing system determining a coefficient of reserves based on data obtained by the one or more sensors placed in the petroleum reservoirs and the type, number, location, and efficiency of wells servicing the petroleum reservoirs, the coefficient of reserves having units of monetary amount divided by quantity of petroleum;

the computing system determining a coefficient of production based on data obtained by the one or more sensors placed in the petroleum reservoirs and the type, number, location, and efficiency of wells servicing the petroleum reservoirs, the coefficient of reserves having units of monetary amount divided by quantity of petroleum;

the computing system determining a reservoir management factor (β

) for the petroleum reservoirs based on the coefficient of reserves and the coefficient of production;

the computing system determining from data obtained by the one or more sensors placed in the petroleum reservoirs and the type, number, location, and efficiency of wells servicing the petroleum reservoirs an additional quantity of proven reserves (Reserves) to be created by a proposed modification to production of petroleum from the reservoirs;

the computing system determining from data obtained by the one or more sensors placed in the petroleum reservoirs and the type, number, location, and efficiency of wells servicing the petroleum reservoirs a net present value (NPV) of the proposed modification to production of petroleum from the reservoirs, the NPV having units of monetary amount;

the computing system determining a true value index (TVI) for the proposed modification to production of petroleum from the reservoirs by relating the reservoir management factor (β

), the additional quantity of proven reserves (Reserves) to be created by the proposed modification to production of petroleum from the reservoirs, and the net present value (NPV) of the proposed modification to production of petroleum from the reservoirs;

the computing system generating and displaying one or more reports based on the true value index (TVI); and

based on the true value index (TVI), implementing the proposed modification to production of petroleum from the reservoirs, including manually or automatically modifying operation of one or more production units selected from producing oil wells, water injection wells, gas injection wells, heat injectors, or sub-components thereof, wherein adjusting the operation of the one or more production units is selected from change in volume, change in pressure, change in temperature, change in well bore path, drilling one or more new wells, stimulating one or more existing wells, and/or increasing reservoir contact of one or more existing wells.

11. The method as in claim 10, the computing system determining the true value index (TVI) according to the following equation:

TVI=NPV+(β

*Reserves).

12. The method as in claim 10, further comprising the computing system determining the coefficient of reserves and the coefficient of production at based in part from data relating to production of petroleum by the producer included in a 10K filing.

13. The method as in claim 10, further comprising the computing system determining the coefficient of production using statistical algorithms and historically observed petroleum production data for a sample set of petroleum producers.

14. The method as in claim 10, further comprising the computing system determining the coefficient of reserves using statistical algorithms and historically observed petroleum production data for a sample set of petroleum producers.

15. The method as in claim 10, the computing system determining the reservoir management factor (β

) according to the following equation;

β

=the coefficient of reserves minus the coefficient of production.

16. The method as in claim 10, wherein the petroleum producer is a publicly traded corporation and wherein the reservoir management factor (β

) reflects a market premium on increased reserves.

17. The method as in claim 10, wherein the coefficient of reserves and the coefficient of production are regression coefficients.

18. A method for implementing a new capital project to increase petroleum production efficiency and/or increase petroleum recovery efficiency of a petroleum reservoir of a petroleum producer, the method comprising:

performing detailed analyses of physics and geology of the petroleum reservoir, the detailed analyses comprising performing one or more physical processes, and using one or more machines to perform the one or more physical processes, which are selected from;

coring to obtain down-hole rock samples and performing analysis thereof,

taking down-hole fluid samples of oil, water and gas and performing analysis thereof,

measuring initial pressures from radio frequency telemetry or like devices and performing analysis thereof, and

measuring fluid saturations and performing analysis thereof;

formulating, based in part on the detailed analyses of the petroleum reservoir and in part on an analysis of petroleum production by the producer, a reservoir management factor (β

) having units of monetary amount divided by quantity of petroleum for the petroleum producer, including;

determining, based on the detailed analyses of the petroleum reservoir and the petroleum production by the producer, a coefficient of reserves for the petroleum producer having units of monetary amount divided by quantity of petroleum;

determining, based on the detailed analyses of the petroleum reservoir and the petroleum production by the producer, a coefficient of production for the petroleum producer having units of monetary amount divided by quantity of petroleum; and

relating together the coefficient of reserves and the coefficient of production to obtain the reservoir management factor (β

);

determining based in part on the detailed analyses of the petroleum reservoir and in part on an analysis of the petroleum production by the producer a new quantity of P1 reserves (Reserves) to be created by the new capital project;

determining based in part on the detailed analyses of the petroleum reservoir and in part on an analysis of the petroleum production by the producer a net present value (NPV) of the new capital project, the NPV having units of monetary amount;

determining a true value index (TVI) for the new capital project by relating the reservoir management factor (β

), the new quantity of P1 reserves (Reserves) to be created by the new capital project, and the net present value (NPV) of the new capital project, the true value index (TVI) providing an evaluation of the capital project based on both petroleum production factors and petroleum reserves factors and having units of monetary amount; and

implementing the new capital project, including manually or automatically modifying operation of one or more production units selected from producing oil wells, water injection wells, gas injection wells, heat injectors, or sub-components thereof, wherein adjusting the operation of the one or more production units is selected from change in volume, change in pressure, change in temperature, change in well bore path, drilling one or more new wells, stimulating one or more existing wells, and/or increasing reservoir contact of one or more existing wells.

20. The method as in claim 18, wherein the new capital project comprises at least one of:

(1) drilling one or more additional wells, (2) stimulating one or more existing wells, or (3) increasing reservoir contact of one or more existing wells.