METHOD AND SYSTEM FOR HEAT MANAGEMENT OF AN OIL FIELD

Abstract

The present invention includes a method and system for heat management in an oil field, the method including the steps of, on a first time interval: determine a thermal maturity for each subsurface region associated with a pattern of oil wells in the oil field, input the thermal maturity output from step (a)(i) and determine a latent heat target and steam injection target for each subsurface region; and input the latent heat target and steam injection target output from step (a)(ii) and a subsurface region development plan and recalibrate a steam optimizer policy engine, on a second time interval: using the recalibrated steam optimizer policy engine from step (a)(iii) and operating data, determine steam injection schedules; and collect operating data; and on a third time interval: input the thermal maturity output from step (i) and perform a periodic look-back process, thereby producing deviations from latent heat targets; and input the deviations from latent heat targets from step (c)(i) and re-determine the subsurface region development plan.

Description

I. COPYRIGHT NOTICE AND AUTHORIZATION

This patent document contains material which is subject to copyright protection.

(C) Copyright 2007. Chevron U.S.A. Inc. All rights reserved,

With respect to this material which is subject to copyright protection. The 8 owner, Chevron U.S.A, Inc., has no objection to the facsimile reproduction by any one of the patent disclosure, as it appears in the Patent and Trademark Office patent files or records of any country, but otherwise reserves all rights whatsoever.

II. FIELD OF THE INVENTION

The present invention relates to heat management of an oil field,

III. BACKGROUND OF THE INVENTION

Steam flooding is a method of increasing oil recovery from an oil field where the oil has a high viscosity. The high viscosity slows or prevents flow of oil thus inhibiting its recovery. Steam flooding greatly reduces the viscosity of the crude oil so that it can flow from the reservoir into the production wells.

Typically, in steam flood operations the steam generators are not completely automated. Additionally, there is no steam flood operation where the latent heat targets are used for the control of steam generation or steam distribution, and there is no place where steam generation and distribution controls are integrated. In summary, a need exists for complete integration and automation of the controls of steam generation and distribution driven by heat management design. Throughout the life of a steam flood project, steam generation and distribution need to be optimized to ensure that each injection well rate (and cyclic heat delivered to the reservoir to promote production) proceeds along the trajectory necessary to provide the appropriate latent heat to each part of the reservoir. Executing this reliably and efficiently, day in and day out, will increase the probability that a steam flood project achieves its planned operational efficiency and production.

This invention overcomes the above-described shortcomings of known methods and systems.

IV. SUMMARY OF THE INVENTION

In one aspect, the present invention is a method for heat management in an oil field, the method including the steps of, on a first time interval: determine a thermal maturity for each subsurface region associated with a pattern of oil wells in the oil field; input the thermal maturity output and determine a latent heat target and steam injection target for each subsurface region; and input the latent heat target and steam injection target output and a subsurface region development plan and recalibrate a steam optimizer policy engine on a second time interval: using the recalibrated steam optimizer policy engine and operating data, determine steam injection schedules; and collect operating data, and on a third time interval: input the thermal maturity output and perform a periodic look-back process thereby producing, deviations from latent heat targets; and input the deviations from latent heat targets and re-determine the subsurface region development plan,

In another aspect, the invention provides A system for heat management in an oil field, the method including a CPU; a memory operatively connected to the CPU, the memory containing a program adapted to be executed by the CPU and the CPU and memory cooperatively adapted for heat management of an oil field; the program including a first code segment configured and adapted for, upon a first pre-determined time interval: determining a thermal maturity for a subsurface region associated with a pattern of oil wells in the oil field; inputting the thermal maturity output from step (a)(i) and determining a latent heat target and steam injection target for each subsurface region; and inputting the latent heat target and steam injection target output from and a subsurface region development plan and recalibrate a steam optimizer policy engine, the program including a second code segment configured and adapted for upon on a second pre-determined time interval; using the recalibrated steam optimizer policy engine and operating data, determining steam injection schedules; and collecting operating data, and the program including a third code segment configured and adapted for upon on a third pre-determined time interval; inputting the thermal maturity output and performing a periodic look-back process including comparing latent heat target and steam injection target outputs to collected operating and calculating deviations of actual heat delivery results from scheduled heat delivery results; and inputting the deviations from latent heat targets and re-determining the subsurface region development plan, wherein the re-determined subsurface region development plan is sufficient to overcome the latent heat target deficiencies output

So that the above recited features and advantages of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to the embodiments thereof that are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.

V. BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 depicts a schematic block system level 0 data flow diagram of one embodiment of the invention showing the major processes, decision timing loops, and logical data flow between the major processes.

FIG. 2 depicts a schematic level 1 data flow diagram (a first decomposition of one process in the level 0 data flow diagram in FIG. 1) of the processes and logical data flow for the Periodic Look-Back Review process 1.0.

FIG. 3 depicts a schematic level 1 data flow diagram of the processes and logical data flow for the Determine Subsurface Region Development process 2.0.

FIGS. 4-10 depict schematic level 1 data flow diagrams of the processes and logical data flow for the Determine Thermal Maturity process 3.0.

FIG. 11 depicts a schematic level 1 data flow diagram of the processes and logical data flow for the Apply Policy Engine to Determine Steam Requirements to Support Subsurface region process 6.0 and Apply Policy Engine to Set Steam System and Water Delivery Schedules process 7.0.

VI. DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

A. Overview

The major components (also interchangeably called aspects, subsystems, modules, functions, services) of the system and method of the invention, and examples of advantages they provide, are described below with reference to the figures. For figures including process/means blocks, each block, separately or in combination, is alternatively computer implemented, computer assisted, and/or human implemented Computer implementation optionally includes one or more conventional general purpose computers having a processor, memory, storage, input devices, output devices and/or conventional networking devices, protocols, and/or conventional client-server hardware and software. Where any block or combination of blocks is computer implemented, it is done optional[y by conventional means, whereby one skilled in the art of computer implementation could utilize conventional algorithms, components, and devices to implement the requirements and design of the invention provided herein. However, the invention also includes any new unconventional implementation means.

B. The System/Method

FIG. 1 depicts a schematic block system level 0 data flow diagram of one embodiment of the invention showing the major process and logical data flow between the major processes. Three levels of heat management are Steam Management Level One 105, Steam Management Level Two 110, and Steam Management Level Three 115. Each level has an associated time interval associated with it. In one embodiments the time cycles are pre-determined intervals with Steam Management Level One 105 having the longest interval; Steam Management Level Three 115 having the shortest interval; and Steam Management Level Two 110 having an interval between the two other intervals In a preferred embodiment, the first time interval is from about nine months to fifteen months, the second time interval is from about one month to six months, and third time interval is from about one hour to one week. In another preferred embodiment, the first time interval is about one year, the second time interval is three months, and third time interval is about one day.

The process of the invention in one embodiment is a continuous process having a closed loop. The process of the invention can be viewed as beginning at Determine Subsurface region Development Plan 125. A development plan is output and consists of a set of subsurface regions to be developed over the next planning time period and a set of decision policies, i.e., rules for the policy engine to apply, for carrying out the development plan. The schedule for development includes overall system constraints, e.g., of steam availability or rig availability. The development plan is passed to Recalibrate Steam Optimizer Policy Engine process 140 which also uses input of the latent heat target and steam injection schedule from step 135 to recalibrate the Policy Engine. Control then passes to step 150 where the Policy Engine is applied to determine steam plant delivery schedules, water plant delivery schedules, and injection schedules, both continuous and cyclic injection schedules, and data collection schedules, or any individual or subset of the above schedules.

Application of the Policy Engine 150 is as follows: The Policy Engine extracts a large amount of information about the current state of operations from Collect Operating Data process 155. This information (collected operating data) includes current and historic production rates and accumulated production rates, current and historic injection rates and accumulated infection rates, facility value such a steam generator status and availability, fresh water delivery capability, and well status information such as thermal maturity state and availability status.

This information is gathered into a field model. The various wells and equipment are aggregated into separate clusters, each cluster having a distinct operational strategy and corresponding set of policies. For each cluster:

• • 1. Override policies are triggered by the high level heat management strategies. These in turn set initial action, constraint, and priority policies generating one possible solution.
  • 2. A simulation of this operational solution is performed and a steam supply/demand balance is established at each step across the active field.
  • 3. Conflicts within this solution are identified during the simulation, thus triggering hierarchy policies that attempt to resolve the conflicts.
  • 4. Unresolved conflicts are passed through a user interface to a modeling expert to resolve.
  • 5. The modeler changes the existing policies or creates new policies to resolve the conflicts.
  • 6. Steps 2-5 above are repeated until all conflicts have been resolved.
  • 7. A series of schedules are generated and output from process 150 to operations for implementation. The output includes the steam system and water plant delivery schedules.

Collect Operating Data Process 7.0 (155) collects operational data, including but not limited to steam injection rates, production rates, and steam generation rates as well has historical data and current and historical capacities. The data collected is combined with the schedule information and reconciliation is performed to set either new system constraints or to adjust schedule targets to realistically achievable rates. The new rates are fed back into the Apply Policy Engine step 6.0 (150) during its next run. The operational data is also fed to the Determine Thermal Maturity process 3.0 and to Periodic Look-back Review process 1.0.

FIG. 2 depicts a schematic level 1 data flow diagram (a first decomposition of one process in the level 0 data flow diagram in FIG. 1) of the processes and logical data flow for the Periodic Look-Back Review process 1.0. The Periodic Look-Back Review process 1.0 uses the data and lessons from the recent past to recalibrate inputs that are used for production (also referenced herein as “depletion” planning. In step 1.1 the previous production plan is reviewed capturing subsurface regions that were to be developed and their schedule of including scheduled steam rate cuts.

Actual development rates are then gathered from the field data in step 1.2. This data includes the time series of injection and production and maintenance activity done to wells or the distribution system that may have impacted the development schedules Then in step 1.3 the data is analyzed to determine actual steam rate cuts from noise in the injection system. The plan data is then reconciled in step 1.4 against the actual field performances. Then the planning inputs are adjusted to describe the target reservoir until the plan would have matched the field actual. Then these planning inputs are used for future planning in step 1.5.

FIG, 3 depicts a schematic level I data flow diagram of the processes and logical data flow for the Determine Subsurface region Development process 2.0. First, in step 2.1, inputs are gathered describing the target reservoir. These include area and volume of pattern/region, initial reservoir temperature, reservoir pressure, dip of overburden and parameters related to water scavenging. Initially these inputs are developed by the field geologist or reservoir engineer. Later these inputs are taken from the look-back process (FIG. 2). In step 2.2, parameters are input that describe development phase by phase inputs include the target reservoir or zone, the number of subsurface regions, and the subsurface region size as well as the initial and final reservoir temperatures. In step 2.3, then the subsurface region level injection and production rates are set. This is done by calculating Nuemann rates. The initial assumptions about the injection rates, heat loss, and production per year are set. These values in particular will be enhanced through the look-back process (FIG. 2). In step 2.4, then the heat management plan is set consisting of the rate of steam cuts, the frequency of cuts, and a cut safety factor. These are input into the model.

If the look-back process has been conducted the above values should be adjusted to create more realistic inputs based upon actual field responses (step 2.5). Finally, in step 2.6, the new development plan is published. The plan consists of a set of subsurface regions along with the start up dates and initial injection rates. A schedule for steam cuts is also included in the development plan.

FIGS. 4-10 depict schematic level 1 data flow diagrams of the processes and logical data flow for the Determine Thermal Maturity process 3.0 (FIG. 1). FIG. 4a depicts a preferred embodiment of the overall Determine Thermal Maturity Process 205. First (process 4001) determine in steps 405 and 415 the reservoir type, i.e., if a single or multi-zone reservoir (step 405) and whether the reservoir is flat or dipping (step 415). This output will be used (step 417) in assigning weighting to thermal maturity indicators in step 460.

In FIG. 4b , then (process 407) retrieves the latest neutron density (“ND”). Neutron density is dimensionless. If the ND is less than a predetermined threshold (step 430), then get temperature data (step 440). If the ND is not less then the predetermined threshold then this indicates more liquid is present and there is no steam chest, thus the subsurface region is not thermally mature (step 435). The pre-determined threshold temperature is determined, e.g., by identifying the saturation temperature of steam at the prevailing reservoir pressure. The temperature is retrieved via a query to a temperature survey database.

After getting the temperature data from well logging data (step 440), determine if the temperature is above a pre-determined threshold (step 445). If not, then this indicates pores are filled with air and there is no steam chest, thus the subsurface region is not thermally mature (step 450). If the temperature is above a pre-determined threshold (step 445), then the subsurface region potentially thermally mature and the indicator status should be identified (step 445) and combined (step 450) by averaging them with appropriate weights. “Indicator status” refers to the indicator supporting the pattern being mature or immature.

Then determine if the combined indicator value is at least at a pre-determined threshold (step 465). If not, then this indicates there is not enough evidence of a steam chest and the subsurface region is at most of mixed maturity (step 470). If yes, the there is sufficient evidence of thermal maturity (step 475).

FIG. 5 provides a preferred embodiment of a first deconstruction view determining the combined indicator value (step 455) showing specific indicators. FIGS. 6-11 provide a preferred embodiment of a second deconstriuction view of the individual indicators in FIG. 5. Five indicator categories are shown in FIG. 5. The first one listed is to determine if high temperature and low saturation or flat temperature for thick sands (step 515).

If yes, this indicates thermal maturity 505. If not then determine if low temperature and high saturation or not flat temperature for thick sands (step 520). If yes, then this indicates a mixed maturity 510. The determination of whether there is a high temperature and low saturation is by user specified thresholds. “High” temperature means higher than the user specified threshold. “Low” saturation means lower than the user specified threshold.

The next listed indicator is to determine if the flow line or wellhead temperature is elevated (step 525). This is determined by measuring the temperature of flowing fluid at the wellhead. An “elevated” wellhead temperature in this context means higher than the user specified threshold. If yes, this indicates thermal maturity 505. If not, this indicates mixed thermal maturity 510. The next listed indicator is to determine if production has peaked (step 530). If yes, this indicates thermal maturity 505, if not, this indicates mixed thermal maturity 510. The next listed indicator is to determine if case vent rates are high (step 540). This is determined by user specified thresholds. “High” case vent rates in this context means higher than the user specified threshold. If yes, this indicates thermal maturity 505. If not, this indicates mixed thermal maturity 510. The next listed indicator is to determine if a steam chest has developed (step 545). This is determined by the earth model. A “developed” steam chest means presence of steam at the top of the zone of consideration. If yes, this indicates thermal maturity 505. If not, then check if there are pockets in the steam chest (step 550). If not, this indicates mixed thermal maturity 510.

FIG. 6 depicts in one embodiment a further decomposition 600 of the Determine if Flow line or Wellhead Temperature is Elevated indicator 525 (FIG. 5). This is applicable in single-reservoir projects. First, for a given subsurface region retrieve the flow line temperature for associated wells and determine if it is high (step 605). This is determined by user specified thresholds. A “high” flow line temperature in this context means higher than specified threshold. If not, this indicates not thermal mature (step 610). If yes, validate whether the temperature can be used by determining if the well has not been recently steamed (step 615). If it has been recently steamed, then the temperature data cannot be used to indicate thermal maturity, so there is not a clear indicator of thermal maturity (step 620). If not recently steamed, determine if the flow rate is high (step 625), i.e., is it adequate when compared to the predicted production rate. If the flow rate is high (step 625), then this indicates thermal maturity (step 630). If not, there is no clear indicator of thermal maturity (step 625). As a follow-up it is recommended to look for FOP (fluid over pump) conditions.

FIG. 7 depicts in one embodiment a further decomposition 700 of the Determine if Casing Vent Rates are High indicator 540 (FIG. 5). This is applicable in single-reservoir projects. If the casing vent rate is not high when compared to the well baseline value (step 705), then there is no clear indicator of thermal maturity (step 710). If the casing vent rate is high, then this indicates thermal maturity (step 715).

FIG. 8 depicts in one embodiment a further decomposition 800 of the Determine if the Production has Peaked indicator 530 (FIG. 5). First, determine if the barrels of production per day per well is declining (step 805). This is determined by applying change point analysis to monthly production data. If no, then there is no clear indicator of thermal maturity (step 810). If it is declining (step 805), then determine if the recommended heat is being provided (step 815), i.e., enough heat to reach thermal maturity. “Recommended heat” in this context means targeted pattern level injection rate. If no, then low heat may be the reason production is low and there is no clear indicator of thermal maturity (step 820). If the recommended heat is being provided (step 815), then validate the heat measurement to ensure the correct physical conditions are being met by determining if the injectors are in critical flow (step 825). If no, then there is not enough steam being injected and there is no clear indicator of thermal maturity (step 830). If the injectors are in critical flow (step 825), this indicates thermal maturity (step 835). This is determined by comparing the pressures upstream and downstream of the orifices, “Critical” flow in this context means fluid is flowing at sonic velocity.

FIG. 9 depicts in one embodiment a further decomposition 900 of the step of determining if high temperature and low saturation or flat temperature for thick sands (step 515). First, determine if the target sands are thick (step 905), This is determined by interpretation of geologic parameters. “Thick” target sands in this context means thicker than a user specified threshold. If yes, then determine if the temperature is greater than a pre determined threshold temperature (step 910), typically measured in an observation well. This is determined by see above. The pre-determined threshold temperature is determined by user specified parameters. If not, then this measurement is not valid and there is no clear indicator of a steam chest and thermal maturity (step 915). If yes, then this indicates thermal maturity (step 920). The pre-determined threshold temperature is derived from the known reservoir pressure at the observation well.

FIG. 10 depicts in one embodiment a further decomposition 1000 of the Determine if a Steam Chest has Developed indicator 545 (FIG. 5). First, determine if an Earth Model, e.g., GOCAD™ brand Earth Model is available (step 1010), i.e., whether an earth model is available that can accept the thermal data. If yes, then visualize or interpret the Earth Model output and determine if visualizations provide evidence of a steam chest (step 1020). This is determined, e.g., by model observation. If not, there is no clear indicator of a steam chest and thermal maturity (step 1030). If yes, then this indicates thermal maturity (step 1040).

FIG. 11 depicts a schematic level I data flow diagram of the processes and logical data flow for the Apply Policy Engine to Determine Steam Requirements to Support Subsurface region process 6.0 and Apply Policy Engine to Set Steam System and Water Delivery Schedules process 7.0. The diagram depicts the process 1100 as it is carried out for a stage and then how each stage follows in succession. The objective of the Policy Engine is to create a series of schedules that best utilizes the limited resources, such as steam and distribution piping, while conforming to all constraints. The Policy Engine's goal or objective function is to maximize the likelihood of meeting the Development Plan (FIG. 3).

Prior to entering the process 1100 the Policy Engine retrieves a large block Of data called the Field Model. The Field Model contains information about the current state of field operations that could influence the policy decisions. The Field Model includes information about the current status of subsurface regions associated with a pattern of wells such as their thermal maturity and availability for steam. The subsurface regions' current and historic production rates are gathered. For any injection wells associated with a subsurface region, the current and historic injection rates are retrieved along with cumulative injected heat values for every well that has been used to inject steam into the reservoir. The Field Model information is separated into Clusters (1125), each Cluster representing a separate collection of wells and field equipment. The planning period can be divided into separate Stages, if desired. In the most complex application, the modeler can set different strategies for each Cluster and Stage of the planning period.

The Policy Engine consists of a set of rules called Policies, unlike a typical rules engine the Policy Engine has several different types of rules.

• • Action Policies (1145)—Do This or Don't Do This statements that tend to have starts and endpoints
  • Constraint Policies (1145)—Deal with limits on resources (steam) or equipment and tend to be long standing
  • Priority Policies (1145)—help focus the allocation of steam when supply is less than demand by prioritizing its distribution.
  • Hierarchy Policies (1155)—State that Activity A is more important than Activity B. These are useful to resolve other conflicting policies
  • Override Policies (1140)—State that under certain conditions, other policies may be activated or deactivated

At the outset, a number of policies will be provided to the modeler. Modelers can build their own policies by specifying policies categories and the appropriate poll elements. For any run of the Policy Engine, the user updates the Field Model and identifies the active policies and the time frame and supplies the constants required by the policies. The Policy Engine determines which Override policies (1140) are in effect for which time periods resolves resource conflicts, and calculates the appropriate set points. Any unresolved conflicts are highlighted for the modeler. The modeler can easily visualize the results and change the policy list to improve the next run.

For any given stage the following steps are preformed.

• • The current selected Strategy (1130 or 1135) triggers Override policies (1140) which set the initial list of active Action and Constraint policies (1145).
  • The simulation is performed and a steam supply/demand balance is established at each time step.
  • Hierarchy policies (1155) are used to resolve as many conflicts (1150) as possible. Any unresolved conflicts are passed through the user interface to a modeler for resolution (1165).
  • The modeler resolves conflicts by changing or creating new policies (1165).
  • The process steps are repeated until all conflicts are resolved for every stage.

Finally all system schedules are published to operations for implementation (1170).

B. Other Implementations

Other embodiments of the present invention and its individual components will become readily apparent to those skilled in the art from the foregoing detailed description. As will be realized, the invention is capable of other and different embodiments and its several details are capable of modifications in various obvious respects, all without departing from the spirit and the scope of the present invention. Accordingly the drawings and detailed description are to be regarded as illustrative in nature and not as restrictive. It is therefore not intended that the invention be limited except as indicated by the appended claims.

Claims

1. A method for heat managements in an oil field, the method comprising the steps of:

(a) on a first time interval: i) determine a thermal maturity for each subsurface region associated with a pattern of oil wells in the oil field; ii) input the thermal maturity output from step (a)(i) and determine a latent heat target and steam injection target for each oil well in the subsurface region; and iii) input the latent heat target and steam injection target output from step (a)(ii) and a subsurface region development plan and recalibrate a steam optimizer policy engine,

(b) on a second time interval: i) using the recalibrated steam optimizer policy engine from step (a)(iii) and operating data, determine steam injection schedules; and ii) collect operating data; and

(c) on a third time interval: i) input the thermal maturity output from step (i) and perform a periodic look-back process, thereby producing deviations from latent heat targets; and ii) input the deviations from latent heat targets from step (c)(i) and re-determine the subsurface region development plan.

2. The method of claim 1 wherein the periodic look-back process in step (c)(i) comprises comparing latent heat target and steam injection target outputs from step (a)(ii) above to collected operating data from step (b)(ii) above, calculate deviations of actual heat delivery results from scheduled heat delivery results.

3. The method of claim 1, wherein the re-determined subsurface region development plan from step (c)(ii) is sufficient to overcome the latent heat target deficiencies output from step (c)(i).

4. The method of claim 1, whereby the revised subsurface region development plan from step (c)(ii) is used in step (a)(iii) upon its next execution on the first pre-determined time interval.

5. The method of claim 1, wherein the collected operating data from step (b)(ii) comprises injection rates, steam generation rates, steam generation capacity production rates and water delivery capacity.

6. The method of claim 1, wherein steam injection schedules determined in step (b)(i) comprise continuous steam injection schedules and cyclic steam injection schedules.

7. The method of claim 1, wherein the first time interval, second time interval, and third time interval are pre-determined.

8. The method of claim 1, wherein the first time interval is from about nine months to fifteen months, the second time interval is from about one month to six months, and third time interval is from about one hour to one week.

9. The method of claim 1, wherein the first time interval is about one year, the second time interval is three months, and third time interval is about one day.

10. The method for heat management in an oil field, the method comprising the steps of:

(a) on a first pre-determined time interval: i) determine a thermal maturity for each subsurface region associated with a pattern of oil wells in the oil field; ii) input the thermal maturity output from step (a)(i) and determine a latent heat target and steam injection target for each subsurface region; and iii) input the latent heat target and steam injection target output from step (a)(ii) and a subsurface region development plan and recalibrate a steam optimizer policy engine,

(b) on a second pre-determined time interval, i) using the recalibrated steam optimizer policy engine from step (a)(iii) and operating data, determine continuous and cyclic steam injection schedules; and ii) collect operating data comprising injection rates, steam generation rates, steam generation capacity, production rates, and water delivery capacity; and

(c) on a third pre-determined time interval: i) input the thermal maturity output from step (i) and perform a periodic look-back process comprising comparing latent heat target and steam injection target outputs from step (ac)(ii) above to collected operating data from step (b)(ii) above and calculating deviations of actual heat delivery results from scheduled heat delivery results, and ii) input the deviations from latent heat targets from step (c)(i) and re-determine the subsurface region development plan, wherein the re-determined subsurface region development plan is sufficient to overcome the latent heat target deficiencies outputs from step (c)(i).

11. The method of claim 10, wherein the first the interval is from about nine months to fifteen months, the second time interval is from about one month to six months, and third time interval is from about one hour to one week.

12. The method of claim 11, wherein the first time interval is about one year, the second time interval is three months, and third time interval is about one day.

13. The method of claim 11, whereby the revised subsurface region development plan from step (c)(ii) is used in step (a)(iii) upon its next execution on the first pre-determined time interval.

14. A system for heat management in an oil field, the method comprising:

(a) a CPU.

(b) a memory operatively connected to the CPU, the memory containing a program adapted to be executed by the CPU and the CPU and memory cooperatively adapted for heat management of an oil field;

(c) the program comprising a first code segment configured and adapted for, upon a first pre-determined time interval: i) determining a thermal maturity for each subsurface region associated with a pattern of oil welts in the, oil field; ii) inputting the thermal maturity output from step (a)(i) and determining a latent heat target and steam injection target for each subsurface region, and iii) inputting the latent heat target and steam injection target output from step (a)(ii) and a subsurface region development plan and recalibrate a steam optimizer policy engine,

(d) the program comprising a second code segment configured and adapted for, upon on a second pre-determined time interval: i) using the recalibrated steam optimizer policy engine from step (a)(iii) and operating data, determining steam injection schedules, and ii) collecting operating data; and

(e) the program comprising a third code segment configured and adapted for, upon on a third pre-determined time interval: i) inputting the thermal maturity output from step (i) and performing a 8 periodic look-back process comprising comparing latent heat target and steam injection target outputs from step (a)(ii) above to collected operating data from step (b)(ii) above and calculating deviations of actual heat delivery results from scheduled heat delivery results; and ii) inputting the deviations from latent heat targets from step (c)(i) and re-determining the subsurface region development plan, wherein the re-determined subsurface region development plan is sufficient to overcome the latent heat target deficiencies output from step (c)(i).

15. The system of claim 14, wherein the periodic look-back process comprises comparing latent heat target and steam injection target outputs to collected operating data, and calculating deviations of actual heat delivery results from scheduled heat delivery results.

16. The system of claim 14, wherein the re-determined subsurface region development plan is sufficient to overcome the latent heat target deficiencies.

17. The system of claim 14, wherein the collected operating data comprises injection rates, steam generation rates, steam generation capacity, production rates, and water delivery capacity.

18. The system of claim 14, wherein steam injection schedules determined comprise continuous steam injection schedules and cyclic steam injection schedules.

19. The system of claim 14, wherein the first time interval is from about nine months to fifteen months, the second time interval is from about one month to six months, and third time interval is from about one hour to one week.

20. The system of claim 14, wherein the first time interval is about one year, the second time interval is three months and third time interval is about one day.