Reduced-physics, data-driven secondary recovery optimization

• US 10,458,207 B1
• Filed: 06/09/2017
• Issued: 10/29/2019
• Est. Priority Date: 06/09/2016
• Status: Active Grant

• Current Assignee: QRI Group, LLC
• Original Assignee: QRI Group, LLC
• Inventors: Matringe, Sebastien, Wen, Tailai, Zhai, Xiang
• Primary Examiner(s): Harcourt, Brad
• Application Number:
  US15/618,890
• Time in Patent Office: 872 Days
• CPC Class Codes: E21B 43/16 Enhanced recovery methods for obtaining hydrocarbons
• CPC Class Codes: E21B 43/168 Injecting a gaseous medium
• CPC Class Codes: E21B 43/17 Interconnecting two or more wells by fracturing or otherwise attacking the formation E21B43/2405, E21B43/247 take precedence
• CPC Class Codes: E21B 43/20 Displacing by water
• CPC Class Codes: E21B 47/06 Measuring temperature or pressure
• CPC Class Codes: E21B 47/07 Temperature
• CPC Class Codes: E21B 47/11 using tracers; using radioactivity
• CPC Class Codes: E21B 49/00 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

Abstract

Embodiments are directed to modeling physical material flow relationships between injector wells and producer wells in a reservoir and to quantifying a level of uncertainty in a connection-based model. In one scenario, a computer system calculates pressure distribution within the reservoir using sensor data. Next, the computer system applies the calculated pressure distribution as an input to a tracer algorithm for an injector well and for a producer well to identify tracer flow values for materials flowing from the injector well to the producer well. The computer system further combines the identified tracer flow values to generate well allocation factors representing relationships in material flow. The computer system then determines the efficiency of each inter-well connection using a fractional flow model that incorporates the determined material flow strength measurement, and provides the inter-well connection efficiencies to a controller for controlling material flow through the injector and/or the producer well.

Claims

1. A method, implemented at a computer system that includes at least one processor, for modeling and controlling physical material flow relationships between injector wells and producer wells in a reservoir to improve performance of the reservoir, the method comprising:

receiving, from one or more hardware-based sensors distributed in one or more locations within the reservoir, sensor data indicating a material flow rate currently present at each sensor location;

calculating pressure distribution within the reservoir using a stationary pressure algorithm to identify variations of pressure at the one or more locations within the reservoir using the received sensor data;

applying the calculated pressure distribution as an input to a tracer algorithm for at least one injector well and for at least one producer well to identify tracer flow values for materials flowing from a seed point in the injector well to the producer well, the tracer flow values providing an indication of material flow volume attributable to the seed point;

combining the identified tracer flow values to generate one or more well allocation factors representing relationships in material flow through inter-well connections between the injector well and the producer well, the well allocation factors providing a material flow strength measurement;

determining a current material flow efficiency level of each inter-well connection using a fractional flow model that incorporates as input the determined material flow strength measurement, the fractional flow model specifying the fraction of material flow in the producer well that originated from the injector well and traveled through a specified inter-well connection;

providing the determined current material flow efficiency levels of the inter-well connections to an injection and/or production controller, which regulates material flow through the injector well and/or the producer well according to the determined current material flow efficiency levels; and

controlling material flow through the injector well based on the determined current material flow efficiency levels of the inter-well connections to thereby improve performance of the reservoir,

wherein if the determined current efficiency is above a determined efficiency measurement, controlling material flow through the injector well comprises increasing an amount of flow material injected through the injector well, and

wherein if the determined current efficiency is below the determined efficiency measurement, controlling material flow through the injector well comprises decreasing the amount of flow material injected through the injector well.

2. The method of claim 1, wherein the reservoir is under secondary recovery.

3. The method of claim 2, further comprising forecasting production-injection behavior for the reservoir under secondary recovery for a specified period of time in the future.

4. The method of claim 3, wherein forecasting production-injection behavior for the reservoir under secondary recovery for a specified period of time in the future comprises the following:

accessing the determined efficiency indication for each inter-well connection;

estimating the future oil, water or gas rates of the producer well and the injector well based on target liquid flow rates obtained by;

setting a target liquid flow rate for each producer well and injector well for a desired forecast time;

updating the strength and efficiencies of inter-well connections using the determined efficiency indication; and

estimating one or more new oil, water and gas rates of the producer wells and the injector wells using the material flow strength measurement, the determined efficiency indication and the liquid rate target.

5. The method of claim 2, further comprising optimizing production-injection strategy for the reservoir, including performing the following:

accessing the determined efficiency indication for each inter-well connection;

accessing a set of production and/or injection constraints including well or well group constraints that are applied to flow rates for oil, water, or gas;

identifying an objective function for the optimization, which depends on the liquid, oil, water or gas production or injection rates of the wells or well groups; and

generating an optimized set of target liquid flow rates for each producer well and injector well obtained by;

estimating a set of target liquid flow rates for each producer well and injector well in the reservoir;

calculating a corresponding forecasted production and injection rate;

calculating a corresponding value for the identified objective function; and

using an optimization algorithm to update the set of target liquid flow rates for each producer well and injector well until at least one of the following has occurred;

the desired objective has been reached or a stopping criterion has been reached.

6. The method of claim 5, wherein optimizing production-injection strategy for the reservoir includes an optimization engine evaluating different values against the well constraints to determine optimal operational changes for each well.

7. The method of claim 6, wherein the determined optimal operational changes automatically cause an increased or decreased injection rate for at least one well in the reservoir.

8. The method of claim 1, wherein physical material flow relationships are modeled between at least one well and an aquifer in the reservoir.

9. The method of claim 1, further comprising controlling material flow through the injector well based on the determined current efficiency of the inter-well connections.

10. The method of claim 9, wherein controlling material flow through the injector well based on the determined efficiency of the inter-well connections includes varying the flow of material flow based on an identified efficiency or lack of efficiency in the specified inter-well connection.

11. The method of claim 1, further comprising:

identifying a mean reservoir pressure for a reservoir, the reservoir including at least one injector well and at least one producer well, the mean reservoir pressure being determined according to a material balance model; and

combining the identified mean reservoir pressure and the calculated pressure distribution to generate a pressure measurement representing the pressure within the reservoir.

12. A method, implemented at a computer system that includes at least one processor, for quantifying a level of uncertainty in a connection-based model to improve performance of a reservoir, the method comprising:

determining, based on received sensor data, one or more connection strength factors and one or more connection efficiency factors for each of a plurality of inter-well connections using at least one of a streamline-based estimation, a tracer-based estimation, or a heuristics-based estimation;

generating an uncertainty factor for each connection efficiency factor using an a priori probability distribution function, wherein connection parameters for each inter-well connection are described as including certain connection parameter features, such that having deterministic values for each connection parameter is avoided;

selecting a set of samples from the a priori probability distribution function to identify a set of corresponding material flow rates for the producer wells using the described connection parameters;

discarding those samples in the set of samples that correspond to material flow rates that do not sufficiently match a historical rate corresponding to the producer wells;

for remaining samples for each inter-well connection, from the a posteriori probability distribution function of the inter-well connection parameters, translating a range of parameters that lead to a specified history-match into an uncertainty range for each inter-well connection;

forming an aggregate uncertainty range by combining the translated range of parameters for each inter-well connection, per well or per well group; and

providing the formed aggregate uncertainty range to a controller and based on the aggregate uncertainty range, altering, via the controller, a flow of injection or production materials in or from a well associated with the reservoir to thereby improve performance of the reservoir,

wherein if the aggregate uncertainty range is below a threshold, altering the flow of injection or production materials in or from the well comprises increasing the flow of injection material in the well and/or increasing the flow of production material from the well, and

wherein if the aggregate uncertainty range is above a threshold, altering the flow of injection or production materials in or from the well comprises decreasing the flow of injection material in the well and/or decreasing the flow of production material from the well.

13. The method of claim 12, further comprising controlling the material flow within the producer wells in accordance with the formed aggregate uncertainty range.

14. The method of claim 12, wherein the a priori probability distribution function comprises a Markov-Chain Monte-Carlo type probability distribution.

15. The method of claim 12, wherein the aggregate uncertainty range is implemented to optimize material flow through an inter-well connection that has at least a specified level of efficiency.

16. A method, implemented at a computer system that includes at least one processor, for modeling and controlling physical material flow relationships between injector wells and producer wells in a reservoir under secondary recovery to improve performance of the reservoir, the method comprising:

receiving, from one or more sensors associated with the reservoir, sensor data indicating a material flow rate at one or more locations of the reservoir;

calculating a pressure distribution within the reservoir to identify variations of pressure between the one or more locations within the reservoir using the received sensor data;

applying the pressure distribution to identify tracer flow values for materials flowing from a seed point in an injector well to a producer well, the tracer flow values providing an indication of material flow volume attributable to the seed point;

combining the tracer flow values to generate one or more well allocation factors representing relationships in material flow through inter-well connections between the injector well and the producer well, the one or more well allocation factors providing a material flow strength measurement;

determining a current material flow efficiency level of each inter-well connection based on at least the material flow strength measurement, the current material flow efficiency level specifying a fraction or volume of material flow in the producer well that originated from the injector well and traveled through a specified inter-well connection;

optimizing a production-injection strategy for the reservoir based on at least the current material flow efficiency level of each inter-well connection, wherein optimizing the production-injection strategy comprises;

accessing an efficiency indication for each inter-well connection;

accessing a set of production and/or injection constraints including well or well group constraints that are applied to flow rates for oil, water, or gas;

identifying an objective function for the optimization, which depends on the oil, water, or gas production or injection rates of the wells or well groups; and

evaluating different values against the well constraints to determine optimal operational changes for each well; and

providing the determined optimal operational changes to an injection and/or production controller to cause an increased or decreased injection rate for at least one well in the reservoir to modify liquid production rate from the reservoir, thereby improving reservoir performance.

17. The method of claim 16, wherein optimizing the production-injection strategy for the reservoir further comprises generating an optimized set of target liquid flow rates for each producer well and injector well.

18. The method of claim 17, wherein generating the optimized set of target liquid flow rates for each producer well and injector well, comprises:

estimating a set of target liquid flow rates for each producer well and injector well in the reservoir;

calculating a corresponding forecasted production and injection rate;

calculating a corresponding value for the identified objective function; and

using an optimization algorithm to update the set of target liquid flow rates for each producer well and injector well until at least one of the following has occurred;

the desired objective has been reached or a stopping criterion has been reached.