CA2969796C

CA2969796C - Methods and systems for automated process control for in situ hydrocarbon recovery

Info

Publication number: CA2969796C
Application number: CA2969796A
Authority: CA
Inventors: Ramesh Kadali; Bruce James; Eliyya Shukeir; Fei QI; Leon Fedenczuk; Trent Pehlke
Original assignee: Suncor Energy Inc
Current assignee: Suncor Energy Inc
Priority date: 2016-06-06
Filing date: 2017-06-06
Publication date: 2023-12-05
Anticipated expiration: 2037-06-06
Also published as: CA3215666A1; CA2969796A1

Abstract

Methods and systems for managing operation of well pairs in a well pad are provided. The method includes collecting measurements from one or more sensors monitoring the plurality of SAGD well pairs; providing the measurements to a well pad controller; generating a series of calculated value from the measurements using the well pad controller; using the series of calculated values in a model to predict a future calculated value; comparison the future calculated value and a target value; and automatically issuing instructions to adjust a condition of at least one of the SAGD well pairs based on the comparison. The system includes a central pad controller for the well pad and subcontrollers for specific well pairs.

Description

METHODS AND SYSTEMS FOR AUTOMATED PROCESS CONTROL FOR IN SITU
HYDROCARBON RECOVERY
[0001] This application claims priority to U.S. Provisional Patent Application Serial No.
62/346,529.
TECHNICAL FIELD

[0002] The technical field relates to recovery of hydrocarbons from hydrocarbon formations.
BACKGROUND

[0003] Bitumen or heavy oil is abundant in different parts of the world, including Canada, the United States, Venezuela, and Brazil. However, the oil is highly viscous at reservoir temperatures and does not flow readily. Therefore, bitumen cannot be produced by conventional methods. However, the reservoir can be thermally treated to reduce the hydrocarbon viscosity and this makes it flow more easily.

[0004] Currently, the most common thermal-recovery processes are steam-based technologies, such as steam-assisted gravity drainage (SAGD) and cyclic-steam stimulation (CSS). In these processes, bitumen reservoirs are heated by steam injection;
the mobilized bitumen is brought to the surface and later diluted with condensates for pipeline transportation.

[0005] In a typical SAGD operation, the hydrocarbon-bearing formation is heated by injecting steam into an injection well and a paired underlying production well. Through convective and conductive heating, the injected steam reduces the viscosity of the hydrocarbons in the hydrocarbon-bearing formation to establish fluid communication between the injection well and the production well. A water and hydrocarbon emulsion can then be produced from the production well while steam injection into the injection well continues.
During continued SAGD
operation, a steam chamber develops around the well pair, and mobilized hydrocarbons continue to be mobilized into the formation and produced to surface.

[0006] A significant challenge of SAGD operations is reliable and consistent operation of the well pairs to establish a consistent emulsion stream from the wells for processing at a central Date recue/Date Received 2023-10-06 facility. Because of the size of hydrocarbon bearing formations and the depths at which production wells are placed, the well dynamics are slow. For example, any change in the downhole pump speed or steam rate will take several hours to stabilize and be reflected in an adjusted operating condition of the reservoir. Furthermore, multiple adjacent well pairs extending into the formation are typically operated from a single well pad, and a change in operating condition, such as temperature, at one well pair can affect the temperature of the other adjacent wells. Proportional-integral-derivative (PID) controllers that can be used for process control cannot be used for managing the long time delay, large time constant and multiple interactions between well pairs in a reservoir. Controlling the production wells manually by operators and production engineers can consume significant time and effort.

[0007] Accordingly, there still exists a need for improved methods and solutions for managing a well pad in a SAGD operation in a hydrocarbon-bearing formation.
SUMMARY

[0008] In general, the present specification describes methods to produce hydrocarbons from a hydrocarbon-bearing formation.

[0009] According to one implementation, there is provided a method of managing operation of a well pad at a hydrocarbon-bearing formation, the well pad having a plurality of SAGD well pairs operatively connected to common surface equipment. The method includes the steps of:
collecting measurements from one or more sensors monitoring the plurality of SAGD well pairs;
providing the measurements to a well pad controller; generating a series of calculated values from the measurements using the well pad controller; the well pad controller using the series of calculated values in a model to predict a well pad related future calculated value; comparing the well pad related future calculated value and a well pad related target value using the well pad controller; and the well pad controller automatically issuing instructions to adjust a condition of at least one of the SAGD well pairs based on the comparison.

[0010] In some aspects of the method, the method includes the step of pre-processing the measurements after they have been collected. In some aspects of the method, pre-processing the measurements includes applying a gain multiplier, bias correction, or filtering to the measurements.
100111 In some aspects of the method, the well pad related future calculated value is a total production rate of the well pad. In some aspects of the method, the measurements comprise one or more of bottom-hole pressure, well pair casing temperature, well pair surface temperature, steam quality, chamber grade, and subcool temperature, steam-to-oil ratio, produced water-to-oil ratio, a flow-device ratio, electrical submersible pump current, a production wellhead pressure, a production wellhead temperature, steam injection pressure, and steam injection rate.
100121 In some aspects of the method, the well pad related target value is a defined steady state value or a range having a minimum and maximum value.
[0013] In some aspects of the method, the conditions adjusted for each of the SAGD well pairs include pump speed, steam injection rate, steam injection pressure, tubing discharge pressure, and hydrocarbon production rate.
100141 In some aspects of the method, the steam-to-oil ratio is an instantaneous steam-to-oil ratio or a moving window average of either measured or estimated steam-to-oil ratio. In some aspects of the method, the produced water-to-oil ratio is an instantaneous water-to-oil ratio or a moving window average of either measured or estimated water-to-oil ratio. In some aspects of the method, the flow-device ratio is defined as a AP/QL2 ratio of a flow control device installed in at least one production well of the SAGD well pair. In some aspects of the method, the calculated value comprises a volatility of the steam-to-oil ratio, produced water-to-oil ratio, or the flow-device ratio.
10015j In some aspects of the method, the well pad related future calculated value is higher than the well pad related target value and adjusting the condition comprises decreasing a steam injection pressure or rate into at least one SAGD well pair in the well pad.
In some aspects of the method, the well pad related future calculated value is lower than the well pad related target value and adjusting the condition comprises decreasing a steam injection pressure or rate into at least one SAGD well pair in the well pad.

[0016] In some aspects of the method, the step of adjusting the condition is performed based on pre-determined parameters.
[0017] In some aspects of the method, the measurements are collected in real-time.
[0018] In some aspects of the method, the method includes increasing an injection pressure or rate into at least one SAGD well pair in the well pad when the well pad related future calculated value is within a range of the well pad related target value. In some aspects of the method, the method includes the step of classifying the plurality of SAGD well pairs into low priority and high priority based on one or more of production rate, chamber maturity, well pair sensitivity, water content, and plant conditions.
[0019] In some aspects of the method, the well pad related future calculated value is a predicted total production rate from the well pad, the well pad related target value is a desired total production rate, the predicted total production rate being lower than the desired production rate, and the adjustment of the conditions comprises increasing production rates of the low priority SAGD well pairs and maintaining production rates of the high priority SAGD well pairs.
[0020] In some aspects of the method, the well pad related future calculated value is a predicted total production rate from the well pad, the well pad related target value is a desired total production rate, the predicted total production rate being higher than the desired production rate, and the adjustment of the conditions comprise decreasing production rates of the low priority SAGD well pairs and maintaining production rates of the high priority SAGD
well pairs.
[0021] In some aspects of the method, the method includes the step of classifying the plurality of SAGD well pairs based on sensitivity. In some aspects of the method, the SAGD well pairs classified as sensitive are not adjusted.
[0022] In some aspects of the method, the model is generated using historical data of the well pad.
[0023] In some aspects of the method, the AP/QL2 ratio for at least one SAGD well pair is declining over a time period and adjusting the condition comprises reducing steam injection pressure or rate to the SAGD well pair.

[0024] According to another implementation, there is provided a method for managing operation of a well pad at a hydrocarbon-bearing formation, the well pad having a plurality of SAGD well pairs operatively connected to common surface equipment. The method includes the steps of: collecting measurements from one or more sensors monitoring the plurality of SAGD
well pairs; providing the measurements to a controller; calculating a steam-to-oil ratio from the measurements, related parameters based on the steam-to-oil ratio; a produced water-to-oil ratio from the measurements; and related parameters based on the produced water-to-oil ratio using the controller; determining whether any of the steam-to-oil ratio, produced water-to-steam ratio, and the related parameters are outside of pre-determined optimal ranges using the controller; and the controller automatically issuing instructions to adjust a condition of at least one of the SAGD well pairs based on the determination.
[0025] In some aspects of the method, the adjustment of the condition comprises reducing ESP speed, gas lift, or producer choke size wherein at least one of the steam-to-oil ratio, produced water-to-oil ratio, and the related parameters are outside the pre-determined optimal ranges.
[0026] In some aspects of the method, the adjustment of the condition comprises increasing steam injection pressure or rate wherein at least one of the steam-to-oil ratio, produced water-to-oil ratio, and the related parameters are within the pre-determined optimal ranges.
[0027] According to another implementation, there is provided a method for managing operation of a well pad at a hydrocarbon-bearing formation, the well pad having a plurality of SAGD well pairs operatively connected to common surface equipment. The method includes the steps of: collecting measurements from one or more sensors monitoring the plurality of SAGD
well pairs; providing the measurements to a controller; calculating a flow device ratio from the measurements using the controller; calculating related parameters based on the flow device ratio using the controller; determining whether any of the flow device ratio and the related parameters is outside of pre-determined optimal ranges using the controller; and the controller automatically issuing instructions to adjust a condition of at least one of the SAGD well pairs based on the determination.
[0028] In some aspects of the method, the flow device ratio comprises the AP/Qi 2 ratio.

[0029] In some aspects of the method, the adjustment of the condition comprises reducing ESP speed, gas lift, or producer choke size wherein at least one of the flow device ratio and the related parameters are outside the pre-determined optimal ranges.
[0030] In some aspects of the method, the adjustment of the condition comprises increasing steam injection pressure or rate wherein at least one of the flow device ratio and the related parameters are within the pre-determined optimal ranges. In some aspects of the method, the pre-determined optimal ranges are developed based on a model.
[0031] According to another implementation, there is provided a system for managing operations of a well pad at a hydrocarbon-bearing formation, the well pad having a plurality of SAGD well pairs operatively connected to common surface equipment. The system includes: a plurality of sensors to monitor the SAGD well pairs; a plurality of subcontrollers configured to receive a plurality of measurements from the plurality of sensors; and a well pad controller configured to: generate a series of calculated values from the measurements;
use the series of calculated values in a model to predict a well pad related future calculated value, comparing the well pad related future calculated value and a well pad related target value;
and automatically issue instructions to adjust a condition of at least one of the SAGD well pairs based on the comparison.
[0032] In some aspects of the system, the measurements are pre-processed after they have been collected. In some aspects of the method, the measurements are pre-processed by applying a gain multiplier, bias correction, or filtering to the measurements.
[0033] In some aspects of the system, the well pad related future calculated value is a total production rate of the well pad.
[0034] In some aspects of the system, the measurements comprise one or more of bottom-hole pressure, well pair casing temperature, well pair surface temperature, steam quality, chamber grade, and subcool temperature, steam-to-oil ratio, produced water-to-oil ratio, a flow-device ratio, electrical submersible pump current, a production wellhead pressure, a production wellhead temperature, steam injection pressure, and steam injection rate. In some aspects of the method, the well pad related target value is a defined steady state value or a range having a minimum and maximum value.
[0035] In some aspects of the system, the conditions adjusted for each of the at least a portion of the SAGD well pairs comprise the pump speed, steam injection rate, tubing discharge pressure, and hydrocarbon production rate.
[0036] In some aspects of the system, the steam-to-oil ratio is an instantaneous steam-to-oil ratio or a moving window average of either measured or estimated steam-to-oil ratio. In some aspects of the system, the produced water-to-oil ratio is an instantaneous water-to-oil ratio or a moving window average of either measured or estimated water-to-oil ratio. In some aspects of the system, the flow-device ratio is defined as a AP/QL2 ratio of a flow control device installed in a production well. In some aspects of the system, the calculated value comprises a volatility of the steam-to-oil ratio, produced water-to-oil ratio, or the flow-device ratio.
[0037] In some aspects of the system, the well pad related future calculated value is higher than the well pad related target value and the adjustment of the condition comprises decreasing a steam injection pressure or rate. In some aspects of the method, the well pad related future calculated value is lower than the well pad related target value and the adjustment of condition comprises reducing the steam injection pressure or rate.
[0038] In some aspects of the system, the change in steam injection pressure is based on pre-determined parameters.
[0039] In some aspects of the system, the measurements are collected in real-time.
[0040] In some aspects of the system, the well pad controller is configured to classify the plurality of well pairs into low priority and high priority based on one or more of production rate, chamber maturity, well pair sensitivity, water content, and plant conditions.
[0041] In some aspects of the system, the well pad related future calculated value is the predicted total production rate from the well pad, the well pad related target value is a desired total production rate, the predicted total production rate being lower than the desired production rate, and the adjustment of the conditions comprises increasing production rates of the low priority well pairs and maintaining production rates of the high priority well pairs.

[0042] In some aspects of the system, the well pad related future calculated value is the predicted total production rate from the well pad, the well pad related target value is a desired total production rate, the predicted total production rate being higher than the desired production rate, and the adjustment of the conditions comprise decreasing production rates of the low priority SAGD well pairs and maintaining production rates of the high priority SAGD
well pairs.
[0043] In some aspects of the system, the system includes the step of classifying the plurality of SAGD well pairs based on sensitivity. In some aspects of the method, the SAGD well pairs classified as sensitive are not adjusted.
[0044] In some aspects of the system, the model is generated using historical data of the well pad.
[0045] In some aspects of the system, the controller is configured to issue instructions to reduce steam injection pressure or rate to the SAGD well pair and send an alert to an operator wherein the AP/QL2 ratio is declining over a time period.
[0046] According to another implementation, there is provided a method for managing operations of a well pad at a hydrocarbon-bearing formation, the well pad having a plurality of wells operatively connected to common surface equipment. The method includes the steps of:
collecting measurements from one or more sensors monitoring the plurality of wells; providing the measurements to a well pad controller; generating a series of calculated values from the measurements using the well pad controller; the well pad controller using the series of calculated values in a model to predict a well pad related future calculated value;
comparing the well pad related future calculated value and a well pad related target value using the well pad controller;
and the well pad controller automatically issuing instructions to adjust a condition of at least one of wells based on the comparison.
[0047] In some aspects of the method, the method includes the step of pre-processing the measurements after they have been collected. In some aspects of the method, the step of pre-processing the measurements includes applying a gain multiplier, bias correction, or filtering to the measurements.

[0048] In some aspects of the method, the well pad related future calculated value is a total production rate of the well pad.
[0049] In some aspects of the method, the measurements comprise one or more of bottom-hole pressure, well casing temperature, well surface temperature, steam quality, chamber grade, and subcool temperature, steam-to-oil ratio, produced water-to-oil ratio, a flow-device ratio, electrical submersible pump current, a production wellhead pressure, a production wellhead temperature, steam injection pressure, and steam injection rate.
[0050] In some aspects of the method, the well pad related target value is a defined steady state value or a range having a minimum and maximum value.
[0051] In some aspects of the method, the conditions adjusted for at least one of the wells comprise pump speed, steam injection rate, steam injection pressure, tubing discharge pressure, and hydrocarbon production rate.
[0052] In some aspects of the method, the steam-to-oil ratio is an instantaneous steam-to-oil ratio or a moving window average of either measured or estimated steam-to-oil ratio. In some aspects of the method, the produced water-to-oil ratio is an instantaneous water-to-oil ratio or a moving window average of either measured or estimated water-to-oil ratio. In some aspects of the method, the flow-device ratio is defined as a AP/QL2 ratio of a flow control device installed in at least one of the plurality of wells. In some aspects of the method, the calculated value comprises a volatility of the steam-to-oil ratio, produced water-to-oil ratio, or the flow-device ratio.
[0053] In some aspects of the method, the well pad related future calculated value is higher than the well pad related target value and adjusting the condition comprises decreasing a steam injection pressure or rate into at least one of the wells in the well pad. In some aspects of the method, the well pad related future calculated value is lower than the well pad related target value and adjusting the condition comprises decreasing a steam injection pressure or rate into at least one of the wells in the well pad.
[0054] In some aspects of the method, the step of adjusting the condition is performed based on pre-determined parameters.

100551 In some aspects of the method, the measurements are collected in real-time.
100561 In some aspects of the method, the method includes increasing an injection pressure or rate when the future calculated value is within a range of the target value.
100571 In some aspects of the method, the method includes the step of classifying the plurality of wells into low priority and high priority based on one or more of production rate, chamber maturity, well sensitivity, water content, and plant conditions.
10058] In some aspects of the method, the well pad related future calculated value is a predicted total production rate from the well pad, the well pad related target value is a desired total production rate, the predicted total production rate being lower than the desired production rate, and the adjustment of the conditions comprises increasing production rates of the low priority wells and maintaining production rates of the high priority wells. In some aspects of the method, the well pad related future calculated value is a predicted total production rate from the well pad, the well pad related target value is a desired total production rate, the predicted total production rate being higher than the desired production rate, and the adjustment of the conditions comprise decreasing production rates of the low priority wells and maintaining production rates of the high priority wells.
10059] In some aspects of the method, the method includes the step of classifying the plurality of wells based on sensitivity. In some aspects of the method, at least one of the wells classified as sensitive are not adjusted.
10060] In some aspects of the method, the model is generated using historical data of the well pad.
[0061] In some aspects of the method, the AP/QL2 ratio for at least one of the wells is declining over a time period and adjusting the condition comprises reducing steam injection pressure or rate to the at least one well in the well pad.
[0062] According to another implementation, there is provided a method for managing operations of a well pad at a hydrocarbon-bearing formation, the well pad having a plurality of well pairs operatively connected to common surface equipment. The method includes the steps of:

collecting measurements from one or more sensors monitoring the plurality of well pairs;
providing the measurements to a well pad controller; generating a series of calculated values from the measurements using the well pad controller; the well pad controller using the series of calculated values in a model to predict a future calculated value; comparing the well pad related future calculated value and a well pad related target value using the well pad controller; and the well pad controller automatically issuing instructions to adjust a condition of at least one of well pairs based on the comparison.
[0063] In some aspects of the method, the method includes the step of pre-processing the measurements after they have been collected. In some aspects of the method, pre-processing the measurements comprises applying a gain multiplier, bias correction, or filtering to the measurements.
[0064] In some aspects of the method, the well pad related future calculated value is a total production rate of the well pad.
[0065] In some aspects of the method, the measurements include one or more of bottom-hole pressure, well pair casing temperature, well pair surface temperature, steam quality, chamber grade, and subcool temperature, steam-to-oil ratio, produced water-to-oil ratio, a flow-device ratio, electrical submersible pump current, a production wellhead pressure, a production wellhead temperature, steam injection pressure, and steam injection rate.
[0066] In some aspects of the method, the well pad related target value is a defined steady state value or a range having a minimum and maximum value.
[0067] In some aspects of the method, the conditions adjusted for at least one of the well pairs comprise pump speed, steam injection rate, steam injection pressure, tubing discharge pressure, and hydrocarbon production rate.
[0068] In some aspects of the method, the steam-to-oil ratio is an instantaneous steam-to-oil ratio or a moving window average of either measured or estimated steam-to-oil ratio. In some aspects of the method, the produced water-to-oil ratio is an instantaneous water-to-oil ratio or a moving window average of either measured or estimated water-to-oil ratio. In some aspects of the

11 method, the flow-device ratio is defined as a AP/QL2 ratio of a flow control device installed in at least one production well of the well pair. In some aspects of the method, the calculated value comprises a volatility of the steam-to-oil ratio, produced water-to-oil ratio, or the flow-device ratio.
[0069] In some aspects of the method, the well pad related future calculated value is higher than the well pad related target value and adjusting the condition comprises decreasing a steam injection pressure or rate into the at least one well pair in the well pad.
[0070] In some aspects of the method, the well pad related future calculated value is lower than the well pad related target value and adjusting the condition comprises decreasing a steam injection pressure or rate into the at least one well pair in the well pad.
[0071] In some aspects of the method, the step of adjusting the condition is performed based on pre-determined parameters.
[0072] In some aspects of the method, the measurements are collected in real-time.
[0073] In some aspects of the method, the method includes increasing an injection pressure or rate when the well pad related future calculated value is within a range of the well pad related target value.
[0074] In some aspects of the method, the method includes the step of classifying the plurality of well pairs into low priority and high priority based on one or more of production rate, chamber maturity, well pair sensitivity, water content, and plant conditions.
[0075] In some aspects of the method, the well pad related future calculated value is a predicted total production rate from the well pad, the well pad related target value is a desired total production rate, the predicted total production rate being lower than the desired production rate, and the adjustment of the conditions comprises increasing production rates of the low priority well pairs and maintaining production rates of the high priority well pairs.
[0076] In some aspects of the method, the well pad related future calculated value is a predicted total production rate from the well pad, the well pad related target value is a desired

12 total production rate, the predicted total production rate being higher than the desired production rate, and the adjustment of the conditions comprise decreasing production rates of the low priority well pairs and maintaining production rates of the high priority well pairs.
[0077] In some aspects of the method, the method includes the step of classifying the plurality of well pairs based on sensitivity. In some aspects of the method, the at least one well pair classified as sensitive are not adjusted.
[0078] In some aspects of the method, the model is generated using historical data of the well pad.
[0079] 2 In some aspects of the method, the AP/QL ratio for at least one well pair is declining over a time period and adjusting the condition comprises reducing steam injection pressure or rate to the at least one well pairs in the well pad.
[0080] In some aspects of the method, the well pair comprises a solvent injection well and a production well. In some aspects of the method, the well pair comprises a steam/solvent co-injection well and a production well. In some aspects of the method, the well pair comprises a solvent injection well including an antenna to generate radio frequency (RF) heating of connate water in situ, and a production well.
[0081] The details of one or more implementations are set forth in the description below.
Other features and advantages will be apparent from the specification and the claims.
BRIEF DESCRIPTION OF THE DRAWINGS
100821 Features and advantages of implementations of the present application will become apparent from the following detailed description and the appended drawings, in which:
100831 FIG. 1 is a schematic illustration of a well pad.
[0084] FIG. 2 is a block diagram illustrating a system for managing hydrocarbon production from a well pad according to one implementation.
[0085] FIG. 3 is a flow chart illustrating the steps for managing total production of

13 hydrocarbons from a well pad according to one implementation.
[0086] FIG. 4 is a flow chart illustrating the sensitivity flag functionality according to one implementation.
[0087] FIG. 5 is a flow chart illustrating the freeze warning functionality according to one implementation.
[0088] FIG. 6 is a flow chart illustrating management of production output based on priority of well pairs according to one implementation.
[0089] FIG. 7 is a flow chart illustrating well pair optimization by adjusting steam injection pressure according to one implementation.
[0090] FIG. 8 is a flow chart illustrating well pair optimization by adjusting ESP, gas lifl rate, or producer choke size according to one implementation.
[0091] FIG. 9 is a flow chart illustrating a method for testing erosion of a flow control device according to one implementation.
[0092] FIG. 10 is an exemplary graphical user interface (GUI) illustrating site data and processing data that can be provided to an operator of a well pad.
DETAILED DESCRIPTION
[0093] Throughout this specification, numerous terms and expressions are used in accordance with their ordinary meanings. Provided below are definitions of some additional terms and expressions that are used in the description that follows.
100941 A "formation" or "geological formation" is a fundamental unit of lithostratigraphic classification. A formation includes rock strata that have comparable lithologies, facies, or other similar properties. Formations can be defined on the basis of the thickness of the rock strata of which they consist, and the thickness of different formations can vary widely.
A given stratigraphic column can include a number of formations. In the oil sands area of Northeastern Alberta, for example, the stratigraphic column consists of the following major formations (from

14 basement to surface): Pre-Cambrian (basement), Devonian carbonates, McMurray oil sands, Wabiskaw sands and mudstones, Clearwater shales, Grand Rapids sandstones, and Quaternary sediments.
[0095] The "McMurray formation" or "McMurray sands" is a stratigraphic unit of Early Cretaceous age in the Western Canada Sedimentary Basin of Northeastern Alberta. It lies unconformably on Pre-Cretaceous erosion surfaces that generally comprise Devonian limestone, which is mainly carbonate rock. The McMurray sands are largely unconsolidated and the sand grains that form the formation are mostly held together by very viscous crude oil. The McMurray formation holds most of the vast hydrocarbon resources of the Athabasca bituminous sand deposit.
[0096] "Reservoir" refers to a subsurface formation containing one or more natural accumulations of hydrocarbons, which are generally confined by relatively impermeable rock or other geological layers of materials, including subsurface formations that are primarily composed of a matrix of unconsolidated sand, with hydrocarbons occurring in the porous matrix.
[0097] "Hydrocarbons" refer to a combination of different hydrocarbons or a combination of various types of molecules that contain carbon atoms and attached hydrogen atoms.
Hydrocarbons include a large number of different molecules in gaseous, liquid, or solid phase having a wide range of molecular weights, and can include bitumen, heavy oil, lighter grades of oil, and natural gas. Elements (e.g., sulphur, nitrogen, oxygen), metals (e.g., iron, nickel, vanadium), and compounds (e.g., carbon dioxide, hydrogen sulphide) are sometimes present in the form of impurities in a desired hydrocarbon mixture.
[0098] The term "drilling" refers to the creation of a borehole in a formation by rotating a drill bit and simultaneously applying an axial load to the bit.
[0099] An "injection well" or "injector" includes a well into which a fluid is injected into a formation.
[00100] A "production well" or "producer" includes any well or wellbore from which hydrocarbons can be produced, regardless of its configuration or arrangement.
The production well can be configured vertically, horizontally, or at any angle from vertical to horizontal or beyond horizontal, in any portion thereof.
[00101] "Bitumen" and "heavy oil" are normally distinguished from other petroleums based on their relative densities and/or viscosities, which often depend on context.
Commonly-accepted definitions classify "heavy oil" as petroleum (the density of which is between 920 and 1,000 kg/m3) and "bitumen" as oil produced from bituminous sand formations (the density of which is greater than 1,000 kg/m3). For purposes of this specification, the terms "bitumen" and "heavy oil" are used interchangeably such that each one includes the other. For example, where the term "bitumen" is used alone, it includes within its scope "heavy oil".
[00102] The "natural reservoir temperature" or "reservoir temperature" is an ambient temperature of a cold or unheated reservoir.
[00103] A "chamber" within a reservoir or formation includes a region that is in fluid communication with a particular well or wells, such as an injection or production well. For example, in a SAGD process, a steam chamber is the region of the reservoir in fluid communication with a steam injection well; this is also the region that is subject to depletion, primarily by gravity drainage, into a production well. Thus, a chamber can be a depleted region.
[00104] A "well pad" includes a collection of wells (which can be arranged in well pairs) drilled into a hydrocarbon formation and associated process equipment, which can include piping (e.g., steam lines, gas lines, solvent lines, and the like), instrumentation, electricity supply, testing equipment, and/or other equipment, positioned at the surface generally above the hydrocarbon bearing formation, and operatively connected, directly or indirectly, to a plurality of the wells or at least one well in a plurality of the well pairs. In some implementations, the well pairs include an injection well and a production well configured to provide a SAGD
operation.
1001051 "Subcool" is the difference between the saturation temperature (boiling point) of water and the actual temperature at the same place where the pressure is measured. The higher the liquid level is above the producer, the temperature is lower and the subcool is higher.
[00106] "Sensor" includes any device, including electronic devices, that detects or measures a physical property and records, indicates, and/or responses to the measurement. Sensors can include multiphase meter, water cut meter, test separator, and other devices used to measure temperature, pressure, water level, near-infrared sensors, infrared sensors, ultrasound sensors, and the like.
[00107] Specific examples of the present methods and systems are described below with reference to the drawings. Details are provided for the purpose of illustration, and the methods and systems can be practiced without some or all of the features discussed herein. For clarity, technical materials that are known in the fields relevant to the present methods and systems are not discussed in detail.
[00108] Some of the drawings and implementations described herein refer to a SAGD
operation. However, it should be understood that other configurations can be used that may or may not involve the use of steam. For example, an injection well may be used to inject a solvent or other chemical that can be used to modify the viscosity of the hydrocarbons in the formation, so that the hydrocarbons can be produced by gravity to flow to the production well. In other configurations, a source of thermal energy other than steam, such as in-situ combustion, electric heat, radio frequency energy, and the like, or a combination of any of the foregoing, can be used to heat the formation and again modify the viscosity of the hydrocarbons to cause production of hydrocarbons by gravity drainage. The implementations described below are considered in the exemplary context of SAGD, but are not intended to be limited to SAGD
applications.
[00109] The present description relates to methods and systems for managing hydrocarbon production from a well pad. In some implementations, there is provided a method for managing operation of a plurality of SAGD well pairs in a well pad of a hydrocarbon-bearing formation.
The method includes the steps of collecting measurements from one or more sensors monitoring the plurality of SAGD well pairs; providing the measurements to a well pad controller; generating a calculated value from the measurements using the well pad controller;
comparing the calculated value to a target value; and automatically issuing instructions to adjust a condition of at least one of the SAGD well pairs based on the comparison and a predicted impact on the well pad by the adjustment.

[00110] In another aspect, there is provided a system for managing operations of a plurality of well pairs in a well pad of a hydrocarbon bearing formation. The system includes a plurality of sensors to monitor the SAGD well pairs; a plurality of subcontrollers configured to receive a plurality of measurements from the plurality of sensors; and a pad controller configured to:
generate a series of calculated values from the measurements; use the series of calculated values in a model to predict a future calculated value; comparing the future calculated value and a target value; and automatically issue instructions to adjust a condition of at least one of the SAGD well pairs based on the comparison.
1001111 The individual control of production wells, which can number in the hundreds, significantly affects the plant production rate, as plant efficiency is optimized based on an expected feedstream. Therefore, the plant is consistent in volume and composition. However, due to the size of hydrocarbon reservoirs, the well dynamics are very slow. Any change in the downhole pump speed or steam rate to a well, can take over 10 hours to be reflected in the reservoir condition. Changes in temperature in, or operation of, one well can also affect all adjacent wells. Manual control or univariate controllers are not capable to manage such a large time constant or the interactions between wells. To achieve steady production from a well pad, which combines the production rate from all of the well pairs in the well pad, the multiple wells have to be controlled and adjusted in a coordinated fashion. Manual control or univariate control algorithms cannot handle such coordination. Because of the above challenges, the manual control of well pads and production wells by operators and production engineers not only consumes significant effort but also results in inefficient usage of produced steam.
[00112] Generally, the systems and methods use model predictive control ("MPC") to manage and optimize in situ hydrocarbon recovery operations, and more particularly, well pair control across a well pad in SAGD operations.
1001131 Broadly described, MPC techniques use multi-variable mathematical models, in conjunction with measurement data, to establish dynamic relationships between the variables of the modeled system that are adjusted (the "Manipulated Variables" or "MV") and the variables that are monitored and/or measured (the "Control Variables" or "CV"). MPC-based systems can predict changes in CV's (i.e., a predicted future calculated value) that will result from changes in the MV's and, in turn, initiate actions to keep the CV's within a target range or value, including pre-determined limits and optimal ranges.
[00114] The systems and methods described herein allow production from well pairs to be controlled by monitoring the CV's and manipulating or changing the MV's to control the monitored CV's. The control variables can thus be defined as the parameters (or a subset of the parameters) of the system which are monitored and/or measured.
[00115] Use of the systems and methods described herein allows the well pairs (injection and production) across a well pad to be operated in a consistent way. For example, measurements and models are used to predict future well and reservoir behaviour and optimize the changes on the manipulated variables to keep the controlled variables at their target values or within given constraints.
[00116] In some implementations, the CV has a target value that is a steady state value. In some implementations, the CV is a range having a minimum and a maximum value.
These values can be defined by an operator of the well pad or a well pair. In some implementations, these values are determined based on prior operational data of the well pad. In some implementations, the CV has a predicted value calculated using measurements inputted into one or more models.
[00117] FIG. I is a schematic view illustrating an exemplary SAGD well pad.
A central processing plant 2 provides steam generation and water processing and bitumen processing facilities at a location above a known buried oil sand deposit 4 shown in dashed lines. Plant 2 also serves as a distribution hub for electrical power which is brought to the plant via powerline 5. A
main access road 7 provides worker access. Positioned about the central processing plant 2 is a plurality of well pads 6. Well pads 6 are located as necessary to access zones of the buried oil sand deposit 4. Each pad 6 is connected to the central processing plant 2 by a steam line 8, a bitumen product line 9, and a power line 10. A pad access road (not shown) extends from the plant to each well pad to facilitate movement of equipment to and from the well pads.
[00118] At each well pad 6, well pairs 12 are installed to inject steam into the deposit and extract bitumen from the site according to the SAGD process. Each well pad 6 has at least one injection wellhead for application of steam into the site and at least one extraction wellhead for receiving bitumen from the area. Injection wells 30 and production wells 40 are grouped in well pairs 12. The number and positioning of well pairs 12 will depend on geology of the deposit in the vicinity of the well pad 6. High pressure steam is injected into the underground formation to heat the bitumen and reduce its viscosity. The bitumen product extracted from the deposit via the extraction wellhead is a mixture of water, bitumen, and gas which is delivered by pumping back to central plant 2 via bitumen product line 9. At central plant 2, the bitumen product is processed to remove water and gas and stored, and/or pumped, to an upgrader facility (not shown) via plant pipeline 14 for conversion into petroleum products. The emulsion from the wells is processed in the central plant, where oil is separated from water for further refining and upgrading. The recovered water is cleaned, recycled and used for making steam.
[00119] FIG. 2 illustrates one implementation of a system 90 for managing hydrocarbon production from a well pad 6. In this implementation, the system includes a well pad controller 102 that is operatively connected to subcontrollers 104 for each well pair 12.
While this implementation includes one subcontroller 104 for each well pair 12, in some implementations, each well pair 12 can be controlled by multiple subcontrollers 104.
Alternatively, one subcontroller 104 can control more than one well pair 12. Subcontrollers 104 are operatively connected to different SAGD related equipment to issue instructions to them to adjust one or more conditions of one or more SAGD well pairs.
[00120] In the illustrated implementation of system 90, the subcontrollers 104 are operatively connected to different sensors 20 that are installed in well pad 6 to monitor and measure different characteristics of injector 30, producer 40, the formation, and the steam chamber 50 around each well pair 12. Sensors 20 can include pressure and temperature sensors at both the toe and heel of a well and along the length of a well. There can also be sensors 20 at pumps, including electric submersible pumps and pumps used for injecting steam into the injectors 30 or the pumps used for drawing fluids out of the producer 40. Sensors 20 at pumps can include temperature sensors, current sensors, voltage sensors, variable frequency drive sensors, and pressure sensors. Sensors 20 can also include water cut meters and temperature and flow rate sensors at the output from the producer or downstream from the output, such as at surface facilities. Sensors 20 can also include infrared, near-infrared, ultrasonic sensors, and the like.

[00121] In some implementations, measurements that can be made by sensors 20 in well pad 6 can include bottom-hole pressure, well pair casing temperature, well pair surface temperature, electrical submersible pump (ESP) current, ESP voltage, ESP winding temperature, intake temperature, a production wellhead pressure, steam injection rate, steam injection pressure, and/or a production wellhead temperature, all at different wells throughout well pad 6. In some embodiments, measurements by sensors 20 can be used to calculate parameters (i.e., values) such as steam quality, chamber grade, subcool temperature, steam-to-oil ratio, produced water-to-oil ratio, produced oil rate, and flow-device ratio.
[00122] In some implementations, different sensors 20 are used to make each of these measurements. In some implementations, one sensor 20 can be used to make multiple measurements in well pad 6.
[00123] Measurements can be made directly using sensors 20 or inferred using soft sensors.
[00124] Soft sensors are mathematic models based on first principle and/or statistical analysis used for real-time estimation of unmeasured process properties such as steam quality and the like using the process measurements, such as temperature, flow, and pressure and the like.
The values outputted by the soft sensors are generated using calculated values from measurements obtained from physical sensors 20. The performance of the soft sensors was compared with lab samples in all steam generators for evaluating the suitability of using soft sensors for real-time control. For example, with respect to subcool temperature in a production well in the well pad 6, a "chamber grade" parameter can be used to estimate the fluid level above the production well using chamber pressure measurements and a reduced number of temperature measurements (e.g., at the toe, heel, and midpoint of the horizontal section of the well).
[00125] In some implementations, measurements made by sensors 20 are pre-processed. The pre-processing can include application of a gain multiplier, bias correction, filtering, or a combination of any of the foregoing.
[00126] In one implementation of system 90, each subcontroller 104 manages 2 MVs (variable frequency drive (VFD) of the ESP and pressure drop (developed through a production choke provided at the wellhead of a production well)) and 4 associated CV's (reservoir subcool, production well subcool, pump curve flow estimation, and DykstraParsons (DP) coefficients) and well pad controller 102 monitors total hydrocarbon production from the entire well pad 6 as a CV.
Some of these CV's are calculated values generated using measurements received from sensors 20.
[00127] In some implementations, the MV being manipulated for one or more of the well pairs 12 include the pump speed, tubing discharge pressure, steam injection rate, and hydrocarbon production rate.
[00128] In one implementation, well pad controller 102 is programmed to maintain total hydrocarbon production from the well pad 6 at a well pad related target value that is entered by the operator of well pad 6. In some implementations, the well pad related target value is based on historical operational data of the well pad 6. In some implementations, the well pad related target value is a steady state value. In some implementations, the well pad related target value is a range having a minimum value and a maximum value. In some implementations, the total production from the well pad 6 is predicted based on calculated values generated from measurements from one or more sensors monitoring the SAGD well pairs. The controller then compares the well pad related predicted value with the well pad related target value.
[00129] In some implementations, well pad controller 102 is programmed to balance well pair reservoir subcool temperatures evenly with respect to specific targets or to maximize production wells 40 which have a higher or lower water cut or which have a higher oil cut. In some implementations, well pad controller 102 is programmed to reduce production from some well pairs 12 relative to others where there is a need to scale back total production from the well pad 6 on a temporary basis. In some implementations, well pad controller 102 is programmed to do one or more of any of the foregoing.
[00130] Although a high value of subcool is desirable from a thermal efficiency standpoint as it generally includes reduction of steam injection rates, it also results in slightly reduced production due to a corresponding higher viscosity and lower mobility of bitumen caused by lower temperature. Another drawback of very high value of subcool is the possibility of steam pressure eventually not being enough to sustain steam chamber development above the injector.

This can sometimes result in collapsed steam chambers where condensed steam floods the injector and precludes further development of the chamber.
[00131] FIG. 3 is a flow chart that illustrates a functionality of the system 90 according to an implementation. At step 300, the subcontrollers 104 receive hydrocarbon production-related measurements from sensors 20 for some or all of the well pairs 12 in well pad 6. Subcontrollers 104 communicate the hydrocarbon production-related measurements from sensor 20 to well pad controller 102 in step 302. The well pad controller 102 then calculates total hydrocarbon production output of all of the producers 40 in well pad 6 at step 304. The total hydrocarbon production output can be calculated based on measurements from sensor 20. In step 306, well pad controller 102 determines whether the total hydrocarbon production from well pad 6 is lower than the target production rate. If the production rate of the well pad 6 is lower than the target hydrocarbon production rate, then well pad controller 102 automatically instructs subcontroller 104 (which in turn instructs applicable equipment for the well pair 12) to increase hydrocarbon production from well pairs 12. In some implementations, production is increased in well pairs 12 that have a low water cut. If the target production rate of well pad 6 is at or higher than the target hydrocarbon production rate, then well pad controller 102 instructs subcontroller 104 (which in turn instruct applicable equipment for the well pair 12) to maintain subcool temperature in the well pairs in view of the target subcool temperature at step 310. In this implementation, the reservoir subcool temperature is generally set as low as possible while avoiding steam in the production well 40 of well pair 12. In some implementations, the well pad controller 102 uses the production-related measurements to predict a future production rate based on a model and the predicted production rate and the target production rate are compared. Well pad controller 102 then instructs one or more subcontrollers 104 to adjust a condition of at least one of the SAGD
well pairs based on the comparison.
[00132] In some implementations, the target hydrocarbon production rate is a range of production rates, rather than a specific value, and well pad controller 102 is configured to maintain the target production rate within the range.
[00133] In some implementations, well pad controller 102 receives measurements from sensors 20 to calculate the bore level CV from the well bore. The bore level is the level of the emulsion above the pump that is estimated by calculating the pressure differential between the downhole suction pressure and discharge tubing pressure for the well bore.
Where the bore level CV of the well bore exceeds optimal parameters (i.e., there is too much liquid in the well bore), well pad controller 102 instructs subcontroller 104 (which in turn instructs applicable equipment for the well pair 12) to increase production from well pairs having a high water cut in order to reduce the amount of liquid within the well bore.
[00134] FIG. 4 is a flow chart that illustrates a functionality of the system 90 according to one implementation. In this implementation, well pairs 12 that are designated by the operator as sensitive are treated differently from other well pairs 12. Sensitivity of a well pair 12 is determined based on the response by the well pair 12 to changes in the operating parameters (e.g., injection rate, ESP pump speed, and the like). Typically, newer well pairs are classified as sensitive because the behaviour of the well pairs can be more erratic as compared to more mature well pairs. Mature well pairs (i.e., those that have been producing hydrocarbons for longer periods of time, such as more than 3 years) tend to have more predictable behaviour.
At step 400, subcontroller 104 of a specific well pair 12 communicates measurements from sensors 20 to well pad controller 102. At step 402, well pad controller 102 determines whether the specific well pair 12 has been flagged as sensitive. If the specific well pair 12 has been flagged as sensitive, then at step 406, well pad controller 102 sets the gain multiplier for the measurements from the well pair 12 to 0, effectively negating the measurements from an overall management perspective of well pad 6. If the well pair 12 has not been flagged as sensitive, then well pad controller 102 takes the well pair 12 into consideration as part of its management of the well pad 6.
In some implementations, as part of management of the well pad 6, when system 90 looks to decrease steam injection rate, well pad controller 102 issues instructions to subcontroller 104 for mature well pairs 12 to decrease steam rate and not issue instructions to subcontroller 104 for sensitive well pairs.
[00135] In some implementations, operational data of a well pad 6 can be used for developing a model for use by system 90. The model can also use data obtained from step testing of the well pairs in well pad 6 or from other well pads having similar characteristics. The model can be used to predict conditions of well pad 6 (i.e., a well pad related future calculated value for the condition). In some implementations, the model is developed using production data from the well pad 6 collected when ESP pump speed at the different well pairs 12 are increased or decreased deliberately by the operator.
[00136] In some implementations, well pad controller 102 and subcontroller 104 can input calculations which are processed using the model before well pad controller 102 implements the well pad control algorithms. In some implementations, these input calculations include well pair sensitivity, subcool and level CV input free check, well pair reservoir subcool equal concern error (ECE), move suppression switching, and well pair target rank.
[00137] FIG. 5 is a flow chart that illustrates a functionality of the system 90 according to one implementation. In this implementation, subcontroller 104 of a well pair 12 in well pad 6 communicates measurements from sensors 20 relating to subcool CV or the bore level CV (e.g., the bore level, which is the level of the emulsion above the pump, is estimated by calculating the pressure differential between the downhole suction pressure and discharge tubing pressure) to well pad controller 102 at step 500. At step 502, well pad controller 102 determines whether the current value of these measurements fall within the defined deadband relative to the previously stored value for these measurements. Deadbands are thresholds that are determined based on the instrumentation noise in a particular measurement. Before system 90 would consider a change in the measurement to be an actual change, and not just changes caused by instrumentation noise, the change has to be greater than the threshold value of the deadband.
Therefore, system 90 would only respond to actual changes in the measurement, rather than changes caused by instrumentation noise. If the measurements do not fall within the deadband, then, at step 504, well pad controller 102 takes no further action and the previous steps are repeated. If the measurements fall within the deadband, then well pad controller 102 determines whether the counter for such occurrence has reached its maximum limit (which can be set by the operator or preprogrammed) at step 506. If the maximum limit has not been reached, then the counter is iterated at step 508 and the previous steps are repeated. If the maximum limit has been reached, then well pad controller 102 will notify the operator of the subcool and level CV freezing. In one implementation, the notification is a flag on the control console visible to the operator. In some implementations, the notification is an audible signal communicated to the operator. In some implementations, the notification is shown on a display.

[00138] In some implementations, well pad controller 102 or subcontroller 104 will only take action based on a change in the measurement if the change is outside of the defined deadband for such measurement.
[00139] In one implementation, well pad controller 102 is configured to manage each well pair 12 such that the steady state targets for each reservoir subcool CV will deviate from their targets by the same amount (if they are unable to match their targets exactly). To perform this functionality, steady state ECEs (equal concern errors) are calculated for each reservoir subcool CV for each well pair 12, based on control model gains, including gain multipliers which can be adjusted by the operator. The various reservoir subcool ECEs are calculated by well pad controller 102 relative to a base ECE, namely that the ECE of pump speed versus subcool temperature of a specific well pair 12 is set to 1. Well pad controller 102 then takes into account the calculated subcool ECE's when issuing instructions to subcontroller 104 of different well pairs 12 in order to maintain the steady state target changes of the subcool CV for the applicable reservoir.
[00140] FIG. 6 is a flow chart that illustrates a functionality of system 90 according to one implementation. Where it is necessary to reduce production from the well pad 6 in the short term, well pad controller 102 is configured to issue instructions that lowers production from different well pairs based on priority. For instance, where plant 2 is being slowed down by too much water in the production stream, production from specific well pairs 12 can be temporarily reduced. At step 600, operator changes the operation mode of well pad controller 102 to issue instructions to decrease production across well pad 6. Based on the priority of the well pairs 12 assigned by system 90 (for example, wells whose production has a high water content would have low priority), well pad controller 102 issues instructions to the applicable subcontrollers 104 at step 602. At step 604, subcontrollers 104 for low priority well pairs are instructed by well pad controller 102 to reduce hydrocarbon production and, at step 606, hydrocarbon production from the low priority well pair 12 is reduced. For higher priority well pairs 12, subcontroller 104 receives instruction from well pad controller 102 at step 608 to maintain hydrocarbon production, and hydrocarbon production from the high priority well pairs 12 is maintained through instructions from subcontroller 104 to applicable equipment for the well pairs 12. In some implementations, the priority of the well pairs 12 can also be determined by the sensitivity of the well pair 12.
[00141] In some implementations, well pad controller 102 classifies the well pairs 12 into lower priority and higher priority rankings based on one or more conditions of production rate, chamber maturity, well pair sensitivity, water content, plant conditions, engineering judgment, and operator discretion.
[00142] In one implementation, system 90 uses move suppressions to manage the production from hydrocarbons from a well pad 6. Move suppressions restrict the range of changes that can be made to equipment affecting a particular MV (e.g., ESP pump speed) by well pad controller 102 or subcontroller 104. The range of move suppressions can be determined by the operator of the well pad 6. In one implementation, hydrocarbon production from a well pair 12 is reduced by manipulating the move suppressions of the pump speed MV of each well pair 12, where higher move suppressions of the pump speed MV of the well pair 12 mean slower reductions in production. In one implementation, well pad controller 102 applies a 12-minute filter to the production measurement received from sensors 20 for each well pair 12 (which are received by subcontroller 104). Well pad controller 102 then detects a slowdown in production by comparing old and new production values. It stores the previous (pre-slowdown) move suppressions of the pump speed MV and then calculates new move suppressions based on the operator-defined well pair priority. Well pad controller 102 assigns higher move suppressions to well pairs 12 with the highest priority, which should be moved the slowest (i.e., not used to address immediate production slowdowns). In this implementation, the priority-based move suppressions are restricted to values between 0.05 and 0.5, to ensure controller stability. The well pad controller 102 also detects when a production cut has ended, and, if so, it can issue instructions to restore the previously-stored move suppressions.
[00143] In some implementations, well pad controller 102 is configured to allow the process model to be adjusted over time by adding or adjusting gain multipliers to individual MV-CV
relationships. In some implementations, a calculation is used to adjust one of the gain multipliers to ensure that the gain ratio between the reservoir and pump subcool CVs is always the same for the pump speed and tubing discharge (choke) pressure MV's. For instance, if the pump subcool gain is 10% higher than the reservoir subcool gain for pump speed changes, then it should also be 10% higher for choke pressure changes.
[001441 In some implementations, well pad controller 102 is programmed with a steady state program. In one implementation, the program is a combination linear program (LP) and quadratic program (QP) built into the well pad controller 102 used to optimize production from a well pad 6 within constraints. In some implementations, the LP/QP is driven by a set of external (operator entered) targets and well pad controller 102 is configured with different CV
ranks to handle situations where it is unable to find a feasible solution that satisfies all of the CV limits and targets. In such implementations, well pad controller 102 uses ranks to drop out the lower priority variables and recalculate a new solution for the remaining CVs. In one implementation, the order from highest to lowest priority is: reservoir subcool lower limit, total production lower and upper limits, total production external target, and then reservoir subcool external target. In this implementation, to fully maximize production from the well pairs 12 in well pad 6, the operator can set an unrealistically high production target. The well pad controller 102 will then issue instructions to increase well pump speed from each well pair 12 (by instructing the applicable subcontroller 104) until the lower limit for each subcool temperature is reached, or until another limit becomes an active constraint.
1001451 In some implementations, well pad controller 102 is programmed to respond to steam availability and to manage well pairs 12 having regard to steam availability at the well pad 6. Where there is an opportunity to make more steam than demanded by the well pad 6, well pad controller 102 receives such information and instructs applicable equipment (including applicable subcontroller 104) to send the excess steam to the well pairs 12 based on their priority ranking to increase production across the entire well pad 6. For example, well pad controller 102 will instruct applicable equipment (including applicable subcontroller 104) to first inject excess steam into the well pair 12 having the highest priority, followed by the well pair 12 with the second priority, and so forth. Where steam production is restricted (for example, due to extraneous reasons, including upstream water treatment process problems), well pad controller 102 is programmed to instruct applicable equipment (including applicable subcontroller 104) to send steam first to the well pairs 12 with higher priority rankings than those with lower priority rankings in order to maintain the hydrocarbon production rate or increase the hydrocarbon production rate across well pad 6. In one implementation, steam is first injected into well pair 12 with the highest priority ranking, followed by the well pair 12 with the second priority ranking, and so forth until all of the steam has been allocated.
[00146] Figures 7 and 8 illustrate functionalities of system 90 according to an implementation. In these implementations, at least one of a steam-to-oil ratio ("SOR"), produced water-to-oil ratio ("WOR"), and a flow-device ratio is used by a well pad controller 102 and/or subcontroller 104 for management of hydrocarbon production from well pairs 12 in a well pad 6.
In some implementations, the SOR or WOR measured is an instantaneous SOR or WOR. In some implementations, the SOR or WOR is a moving window average of either measured or estimated SOR or WOR.
[00147] In these implementations, the steam-to-oil ratio is an instantaneous SOR, the produced water-to-oil ratio is an instantaneous WOR, and the flow-device ratio can be the ratio of AP/Q12 of a flow control device installed in the oil-production well (AP is a pressure drop of a fluid passing through an orifice or an equivalent and QL is the total liquid rate in volume or mass per unit in time that is measured after vapor and gas has been separated from the total fluid) (the "AP/QL2 Ratio"). While the actual AP through a flow control device ("FCD") is difficult to measure, it is approximated by using the pressure difference between the 1) injector well head injection pressure, bottom hole pressure, or chamber pressure and 2) the producer bottom hole pressure or the well head pressure. Volatility (e.g., rising, oscillations, or fluctuations) in the measurements of the SOR, WOR, and the flow-device ratio can indicate onset of steam coning or steam breakthrough.
1001481 When FCD's in wells are pulled too hard, steam will start to pass through FCD's in large amounts causing oil production to be backed out and SOR to rise (i.e., steam is short-circuiting the system). Operating under these conditions increases the risk of erosion of the FCD's ¨ as steam enters the FCD at high velocity with entrained sand particles, which effectively have a sand-blasting effect and erode the FCD.
[00149] Optimal operation (i.e., for optimal production) of a well pair 12 is denoted by a low and stable SOR or WOR, while non-optimal conditions (i.e., when the well is pushed too hard resulting in steam breakthrough) is denoted by increasing instability or oscillations in the SOR or WOR.
1001501 With respect to FCD's, the basic equation governing the pressure drop of a fluid passing through an orifice is AP = (total liquid rate)2/p, where p represents the density of the fluid passing through the orifice. The AP/Q12 Ratio is constant if there is no or little vapor or steam passing through the FCD, since p will stay constant. Optimal conditions are marked by a constant ratio. A rising and oscillating ratio indicates that significant amounts of steam are passing through the FCD's and conditions are no longer optimal. This condition also indicates an elevated risk of FCD erosion. Actual erosion of the FCD is shown as a continual decrease in the ratio. The actual value of the AP/QL2 ratio will depend on the design of the flow control device and the pressure drop through the reservoir between the injector and producer. As such, different SAGD well pairs can have different values for the AP/QL2 Ratio. A well operating at optimal conditions will have a stable ratio that only changes by a few percent from well test to well test.
In some implementations, the percentage change of a stable AP/QL2 Ratio is at or less than 5%. In some implementations, the percentage change of a stable AP/QL2 Ratio is at or less than 10%. Any changes between well tests that are higher than that can indicate non-optimal conditions. The level of significance would be chosen by the asset production and reservoir engineers operating the well pad 6.
[00151] Referring to FIG. 7, subcontroller 104 receives measurements from sensors 20 in a well pair 12 at step 700. Based on previously stored information for these measurements, subcontroller 104 calculates at least one of the SOR, WOR, and the AP/QL2 Ratio at step 702. At step 704, subcontroller 104 determines if at least one of the value, average (including average from previous well tests), standard deviation or range of SOR, and/or AP/Q12 Ratio is outside of pre-determined optimal ranges. In some implementations, these ranges are determined by the operator of the well pair 12 and entered into system 90. In some implementations, these ranges are calculated by subcontroller 104 based on previous operational data for the well pair 12. In some implementations, the subcontroller 104 will calculate the subcool temperatures (bottom hole, pump, and well).
[00152] If at least one of the value, average (including average from previous well tests), standard deviation or range of SOR, WOR, and the AP/Q12 Ratio is within the pre-determined optimal ranges, subcontroller 104 proceeds to step 706 to send instructions to increase steam injection pressure or rate on a pre-determined schedule. In some implementations, subcontroller 104 assesses whether a SAGD well pair is isolated within well pad 6, if it is, then subcontroller 104 uses the SOR. If the SAGD well pair is not isolated within well pad 6, then subcontroller 104 uses WOR instead of SOR because steam can move laterally between well pairs 12 and other well pairs 12.
[00153] If none of the parameters are outside of the optimal range, then subcontroller 104 sends instructions to the applicable equipment to increase the steam injection rate or pressure after a pre-determined time that would be determined by the asset reservoir or production engineer. In some implementations, the pre-determined time will be calculated based on maturity of the well and its sensitivity to steam coning based on operational performance or past steam coning events.
If any of the parameters are outside of the optimal range, at step 708, subcontroller 104 determines whether the well pair 12 is sensitive to steam coning.
[00154] In some implementations, the well sensitivity to steam coning can be pre-determined by engineers operating well pad 6. In some implementations, the well sensitivity to steam coning can be determined by the subcontroller 104 through historical operational data. If the well is not sensitive to steam coning, then the subcontroller 104 will send instructions to reduce steam injection pressure or rate in both the long and short tubing at step 710. If the well is sensitive to steam coning, then subcontroller 104 will send instructions to the applicable equipment to reduce the steam injection pressure or rate in the pressure sensitive tubing, or part of the well pair sensitive to steam coning, at step 712. Reducing steam injection pressure or rate will be the first choice, particularly in new wells with growing steam chambers. However, instead of reducing steam injection pressure, the well ESP frequency, gas lift rate, and/or choke can be reduced instead.
[00155] After assessing whether to reduce steam injection pressure or rate in the pressure sensitive well pair at step 712, the subcontroller 104 will determine if the reservoir subcool is within operating boundaries at step 714. In some implementations, the operating boundaries are pre-determined by engineers operating well pad 6. In some implementations, the operating boundaries are automatically determined by subcontroller 104 using historical operational data. If the reservoir subcool is within operating boundaries, then subcontroller 104 goes back to step 700. If the reservoir subcool is outside of operating boundaries, the subcontroller 104 will determine whether the reservoir subcool is above or below the operating boundaries at step 716. If the reservoir subcool is below the operating boundaries, then subcontroller 104 will instruct the applicable equipment to reduce ESP speed, gas lift, or producer choke size for a specific well pair 12 at step 720. If the reservoir subcool is above the operating boundaries, then subcontroller 104 will instruct the applicable equipment to speed up the ESP, increase gas lift, increase producer choke size, or a combination of any of the foregoing at step 718. In some implementations, the steps illustrated in FIG. 7 are repeated on a periodic basis, such as every hour, by subcontroller 104. In some implementations, the steps illustrated in FIG. 7 are repeated frequently by subcontroller 104. In some implementations, well pad 6 includes well pairs 12 having different lengths and with their own respective gas lift rate and producer choke size.
Accordingly, subcontroller 104 is programmed to adjust the gas lift rate and/or the producer choke size having regard to the differences between the different well pairs 12 in well pad 6.
[00156] FIG. 8 illustrates a functionality of system 90 according to another implementation.
In the implementation illustrated by FIG. 8, steam coning or non-optimal performance is controlled by changing producer choke size, ESP speed, and/or lift rate instead of steam injection rate. Referring to FIG. 8, subcontroller 104 receives measurements from sensors 20 in a well pair 12 at step 800. Based on previously stored information for these measurements, subcontroller 104 calculates the SOR, WOR, subcool (including bottom hole subcool, pump subcool, and reservoir subcool), and the AP/QL2 Ratio at step 802. At step 804, subcontroller 104 determines if at least one of the value, average (including average from previous well tests), standard deviation or range of SOR, and/or AP/QL2 Ratio is outside of optimal ranges. In some implementations, the optimal ranges are determined by the operator of the well pair 12 and entered into system 90. In some implementations, the optimal ranges are calculated by subcontroller 104 based on previous operation data for the well pair 12. If the value, average (including average from previous well tests), standard deviation of range of SOR, WOR, and/or the AP/QL2 Ratio is not outside the optimal ranges, at step 806, subcontroller 104 sends instructions to applicable equipment to increase steam injection pressure or rate on a pre-determined schedule. If at least one of the value, average (including average from previous well tests), standard deviation of range of SOR, WOR, and/or the AP/QL2 Ratio is outside the optimal ranges, then subcontroller 104 will send instructions to applicable equipment to reduce the ESP frequency, gas lift rate, and/or choke size in step 808. Subcontroller 104 then assess whether the reservoir subcool is within operating boundaries at step 810. If the reservoir subcool is below the operating boundaries, then subcontroller 104 will instruct the applicable equipment to reduce ESP speed, gas lift, or producer choke size at step 812. If the reservoir subcool is above the operating boundaries, then subcontroller 104 will instruct the applicable equipment to increase the ESP
speed, increase gas lift, increase producer choke size, or a combination of any of the foregoing at step 816. In some implementations, the steps illustrated in FIG. 8 are repeated on a periodic basis, such as every hour, by subcontroller 104. In some implementations, the steps illustrated in FIG. 8 are repeated frequently by subcontroller 104.
[00157] In all cases, subcontroller 104 will then determine whether the subcool is within pre-determined bounds at step 810. If not, then the subcontroller 104 determines whether the subcool is above or below the pre-determined bounds in step 812. If above, then the ESP speed, gas lift or producer choke size are increased in step 814. If not, then the ESP speed, gas lift rate, or producer choke size is decreased. In some implementations, the.steps illustrated in FIG. 8 are repeated on a periodic basis, such as every hour, by subcontroller 104.
[00158] FIG. 9 illustrates a functionality of systems 90 for testing FCD
erosion according to one implementation. In this implementation, subcontroller 104 receives measurements from sensors 20 in a well pair 12 at step 900. Based on previously stored information for these measurements, subcontroller 104 calculates the AP/QL2 Ratio at step 902. At step 904, subcontroller 104 determines whether the AP/QL2 Ratio is decreasing. If the AP/QL2 Ratio is decreasing, then subcontroller 104 sends instructions to reduce the steam injection pressure or rate into the well at step 906 to reduce the risk of FCD erosion failure. An alert is also sent to operators of the well at step 908.
[00159] While the implementations illustrated in Figures 7, 8, and 9 use the SOR ratio, WOR
ratio, and the AP/QL2 Ratio, in other implementations, additional performance-related parameters can be used to optimize production of hydrocarbons from a well pair 12, including sudden changes in derivative with respect to time of the ESP current, production well head pressure, and bottom hole pressure. When the derivative suddenly increases, it can indicate that steam coning is beginning to occur, which would reduce productivity from a well pair 12.
[00160] In some implementations, the reduction or increase in gas lift includes the reduction or increase to the amount of natural gas injected into the producers of the well pair 12 to pressurize the hydrocarbon-containing emulsion and produce it to surface.
[00161] In another implementation, a derivative of the temperature subcool with respect to time at the bottom hole conditions of the production well or ESP as well as the temperature subcool at the wellhead of the producer, is used for determining whether the steam chamber operations is optimal. The temperature subcool is the number of degrees below saturation conditions, or the number of degrees that the water can be increased to until the water boils. When the derivative becomes strongly negative, conditions within the well pair 12 and the associated steam chamber are becoming suboptimal.
[00162] While the implementation described in Figures 7, 8, and 9 is controlled by a subcontroller 104, in other implementations, the control algorithms are implemented at the well pad controller 102 and well pad controller 102 assesses the conditions of different well pairs 12 across well pad 6 to optimize production of hydrocarbons, such as by reducing or increasing the steam injection pressure as necessary. This implementation can also be used to detect possible erosion of the FCD within different well pairs 12 within well pad 6.
[00163] Another implementation of the systems and methods described herein uses ESP
intake temperature to manage production of hydrocarbons from a well pair 12 in well pad 6.
[00164] In the prior art, target intake temperatures are determined and monitored manually. If downhole temperatures reach a critical temperature, typically water saturation temperatures, vapors can form at or in the ESP. This can cause the ESP to trip or fail, leading to a costly workover being required.
[00165] In this implementation, the lagged PVT-ratio model is used for prediction of ESP
intake temperature. A general form of the intake temperature ratio at time index (t) on the left side can be expressed as non-dimensional ratios of parameters on the right hand side:

T(i)/T(i-1)=Ratio (i, i-1) = (P(i) * Pr(i) * Fi * S(i-1)) / (P(i-I) * Pr(i-1) * F(i-1) * S(i) where P is pressure within the steam chamber, Pr is the pumping rate of the ESP, F is the frequency of the pump, S is the steam rate.
[00166] The intake temperature prediction is a 2-step process. In the first step, a multivariate multiplicative model was built to predict the above ratio at time (i) given all lagged ratios (at time 1-2, 1-3, 1-4, i-5), as expressed by the formula:
Ratio(0, i-I) = CO * Ratio0-1,i-2)" * Ratio 0-2,i-312 * Ratio (i-3,i-4)" *
Ratio (i-4,i-5)(4 where coefficients (CO-C4) are estimated using least squares regression after ratios are logarithmically transformed.
[00167] In the second step, the predicted ratio(i, i-1) is converted to the original scale. This ratio is equivalent to the temperature ratio T(i)/T(i-1). Thus, the intake temperature estimate can be expressed as:
Ti = Predicted Ratio (i, i-1) * T (i-1) [00168] Using data from various well pairs and well pads, a model is built that can be represented by the following formulae:
R01= 100023) * R12(""5067) * R23(-0.2776) * R34 '59 * R45 622 and TO= ROI * TI
where TO is the current estimated temperature while TI is the actual temperature from 10min back in time and the lagged ratios are based on pressure, pump rate, pump frequency, and injection rate of the well, and the ratios represent non-temperature ratios at time lags of I 0/20, 20/30, 30/40, and 40/50 minutes.
[00169] Frequent readings of appropriate parameters can allow for fast and accurate temperature predictions during sensitive well operating periods, and periods of stable production.

Accurate temperature predictions are specifically important during the initial start-up period of the well. Verification tests showed that a single equation can be used to predict the ESP's intake temperature for the well pairs 12 at different stages of the life of the well pair 12.
[00170] In one implementation, sensors 20 provide relevant measurements, such as pressure, pump rate, pump frequency, injection rate, and the like to subcontroller 104.
Subcontroller 104 communicates the measurements to well pad controller 102. Well pad controller 102 then uses the lagged PVT-ratio model as described herein to predict the ESP intake temperature for a particular well pair 12. If the ESP intake temperature in that well pair 12 is predicted to exceed optimal operational parameters (i.e., a target range), well pad controller 102 issues instructions to the applicable subcontroller 104 to reduce the temperature in the well pair 12 (e.g., by reducing steam injection rate) before the temperature actually exceeds such parameters. This would prevent the downhole temperature from reaching a critical level that would allow vapors to form at or in the ESP. Where the ESP intake temperature is predicted to be within optimal operational parameters, well pad controller 102 takes no further action.
[00171] FIG. 10 illustrates an exemplary GUI that illustrates the well pair and well pad data that can be displayed to an operator of the well pad. The GUI provides information on total production from the entire well pad 6 (which, in this implementation, includes 9 different well pairs 12). The GUI also illustrates how the sensitivity flag for a well pair 12 can be displayed to the operator (in the exemplary GUI, none of the well pairs 12 are flagged as being a sensitive well pair). The GUI is provided here for illustrative purposes, to show the nature of the site data and processing data.
[00172] In some implementations, the GUI can display individual measurements and PID
loops. Custom performance indicators can also be displayed with baseline (based on historic application data) or benchmark (industry standard or enterprise target) values being used to grade performance. Performance status is shown using color coded displays.
1001731 In some implementations, system 90 employs a master/slave controller configuration that accounts for the disparity in dynamics between the fast and slow responses required by different control variables, in which the master and slave controllers respectively control the slow variables (e.g., the reservoir and pump subcool) and the faster variables (e.g., pump curve, production discharge pressure).
[00174] In some implementations, system 90 incorporates one or more of the functionalities illustrated in FIGs. 3 to 9 and as described in the foregoing to manipulate the MV's or otherwise manage the SAGD well pairs 12 in a well pad 6, such as the total production rate of the well pad 6 and the like.
[00175] While a number of exemplary aspects and implementations have been discussed above, those skilled in the art will recognize certain modifications, permutations, additions, and sub-combinations thereof.
[00176] Implementations as described herein can include controllers implemented using specifically designed hardware, configurable hardware, programmable data processors configured by the provision of software (which can optionally comprise "firmware") capable of executing on the data processors, special purpose computers or data processors that are specifically programmed, configured, or constructed to perform one or more steps in a method as explained in detail herein and/or combinations of two or more of these. Examples of specifically designed hardware are: logic circuits, application-specific integrated circuits ("AS1Cs"), large scale integrated circuits ("LSIs"), very large scale integrated circuits ("VLSIs"), and the like. Examples of configurable hardware are: one or more programmable logic devices such as programmable array logic ("PALs"), programmable logic arrays ("PLAs"), and field programmable gate arrays ("FPGAs"). Examples of programmable data processors are: microprocessors, digital signal processors ("DSPs"), embedded processors, graphics processors, math co-processors, general purpose computers, single-chip computers, and the like. For example, one or more data processors in a control circuit for a device can implement methods as described herein by executing software instructions in a program memory accessible to the processors.
[00177] Although the present specification has described particular implementations and examples of the methods and systems discussed herein, it will be apparent to persons skilled in the art that modifications can be made to the implementations without departing from the scope of the appended claims, including:

= Inferential estimates can be used to provide input data to the system.
= Empirical models, and linear and quadratic algorithms can be used to calculate unmeasurable variables that cannot be readily measured.
= Advanced logic can be used to detect process abnormalities and inefficiencies and to allow switching between different control modes based on the detected abnormalities and inefficiencies.
= A real-time optimizer for overall plant optimization can be used between multiple plant processes such as steam producers, water treatment plant, oil treatment, capacity availability in tanks, pipelines, and the like to balance steam production with steam consumption in the wells while staying within the plant constraints.
= While the functionalities in the implementations described herein are programmed primarily in the well pad controller 102, a person skilled in the art will appreciate that more than one controller may be used to perform the functionalities of well pad controller 102.
= In some implementations, well pad controller 102 uses a model to predict conditions of the well pad and adjust the MV's based on the predicted conditions in order to match a target value.
[00178] Some advantages of the implementations described herein include:
= Advanced automation of well pads and well pairs can be used to achieve optimal energy consumption per barrel production, reduce ESP failures, operate the well pad safely, and provide steadier production rate from the well pad.
= Controllers automatically control the well pad and all of the well pairs under the well pad can achieve tighter control of subcools, distribute the steam in a steady mariner to stay within safety constraints, distribute the stem uniformly to optimize steam used per barrel produced, reduce ESP pump failures due to subcool excursions and process constraints and achieve steady production rate from the well pad.

= The systems and/or methods can be used, for example, to reduce start up time after a circulation phase and/or shut down.
= The operation can be independent of the operator and can thus be a closed-loop control system. The well pad controller 102 and/or subcontrollers 104 can be configured to iteratively repeat the receiving, predicting, determining and outputting steps. In some implementations, the operators can intervene in the more problematic cases so that the system 90 can also operate in open-loop or manual mode under the control of the operators.
[00179] Unless the context clearly requires otherwise, throughout the description and the claims: "comprise", "comprising", and the like are to be construed in an inclusive sense, as opposed to an exclusive or exhaustive sense; that is to say, in the sense of "including, but not limited to", "connected", "coupled", or any variant thereof, means any connection or coupling, either direct or indirect, between two or more elements; the coupling or connection between the elements can be physical, logical, or a combination thereof. "Herein", "above", "below", and words of similar import, when used to describe this specification shall refer to this specification as a whole and not to any particular portions of this specification. "Or" in reference to a list of two or more items, covers all of the following interpretations of the word: any of the items in the list, all of the items in the list, and any combination of the items in the list.
The singular forms "a", "an", and "the" also include the meaning of any appropriate plural forms.
[00180] Where a component is referred to above, unless otherwise indicated, reference to that component should be interpreted as including as equivalents of that component, any component which performs the function of the described component (i.e., that is functionally equivalent), including components which are not structurally equivalent to the disclosed structure which performs the function in the illustrated exemplary implementations of the invention.
[00181] Specific examples of systems, methods and apparatuses have been described herein for purposes of illustration. These are only examples. The technology provided herein can be applied to systems other than the example systems described above. Many alterations, modifications, additions, omissions and permutations are possible within the practice of this invention. This invention includes variations on described implementations that would be apparent to the skilled addressee, including variations obtained by: replacing features, elements and/or acts with equivalent features, elements and/or acts; mixing and matching of features, elements and/or acts from different implementations; combining features, elements and/or acts from implementations as described herein with features, elements and/or acts of other technology;
omitting and/or combining features, elements and/or acts from described implementations.
100182] It is therefore intended that the following appended claims and claims hereafter introduced are interpreted to include all such modifications, permutations, additions, omissions and sub-combinations as may reasonably be inferred. The scope of the claims should not be limited by the preferred implementations set forth in the examples, but should be given the broadest interpretation consistent with the description as a whole.

Claims

1. A method for managing operation of a well pad at a hydrocarbon-bearing foimation, the well pad having a plurality of SAGD well pairs operatively connected to common surface equipment, the method comprising:
collecting measurements from one or more sensors monitoring the plurality of SAGD
well pairs;
providing the measurements to a well pad controller;
generating a series of calculated values from the measurements using the well pad controller;
the well pad controller using the series of calculated values in a model to predict a well pad related future calculated value;
comparing the well pad related future calculated value and a well pad related target value using the well pad controller; and the well pad controller automatically issuing instructions to adjust a condition of at least one of the SAGD well pairs based on the comparison.

2. The method of claim 1, comprising the step of pre-processing the measurements after they have been collected.

3. The method of claim 2, wherein pre-processing the measurements comprises applying a gain multiplier, bias correction, or filtering to the measurements.

4. The method of claim 1, wherein the well pad related future calculated value is a total production rate of the well pad.

5. The method of claim 1, wherein the measurements comprise one or more of bottom-hole pressure, well pair casing temperature, well pair surface temperature, steam quality, chamber grade, and subcool temperature, steam-to-oil ratio, produced water-to-oil ratio, a flow-device ratio, electrical submersible pump current, a production wellhead pressure, a production wellhead temperature, steam injection pressure, and steam injection rate.

CPST Doc: 468541,1 Date Recue/Date Received 2023-01-17

6. The method of claim 1, wherein the well pad related target value is a defined steady state value or a range having a minimum and maximum value.

7. The method of claim 1, wherein the conditions adjusted for each of the SAGD well pairs comprise pump speed, steam injection rate, steam injection pressure, tubing discharge pressure, and hydrocarbon production rate.

8. The method of claim 5, wherein the steam-to-oil ratio is an instantaneous steam-to-oil ratio or a moving window average of either measured or estimated steam-to-oil ratio.

9. The method of claim 5, wherein the produced water-to-oil ratio is an instantaneous water-to-oil ratio or a moving window average of either measured or estimated water-to-oil ratio.

10. The method of claim 5, wherein the flow-device ratio is defined as a AP/QL2 ratio of a flow control device installed in at least one production well of the SAGD well pair.

11. The method of claim 5, wherein the calculated value comprises a volatility of the steam-to-oil ratio, produced water-to-oil ratio, or the flow-device ratio.

12. The method of claim 11, wherein the well pad related future calculated value is higher than the well pad related target value and adjusting the condition comprises decreasing a steam injection pressure or rate into at least one SAGD well pair in the well pad.

13. The method of claim 11, wherein the well pad related future calculated value is lower than the well pad related target value and adjusting the condition comprises decreasing a steam injection pressure or rate into at least one SAGD well pair in the well pad.

14. The method of claim 12 or claim 13, wherein the step of adjusting the condition is performed based on pre-determined parameters.

CPST Doc: 468541,1 Date Recue/Date Received 2023-01-17

15. The method of any one of claims 1 to 14, wherein the measurements are collected in real-time.

16. The method of any one of claims 1 to 14, comprising increasing an injection pressure or rate into at least one SAGD well pair in the well pad when the well pad related future calculated value is within a range of the well pad related target value.

17. The method of claim 1, comprising the step of classifying the plurality of SAGD well pairs into low priority and high priority based on one or more of production rate, chamber maturity, well pair sensitivity, water content, and plant conditions.

18. The method of claim 17, wherein the well pad related future calculated value is a predicted total production rate from the well pad, the well pad related target value is a desired total production rate, the predicted total production rate being lower than the desired production rate, and the adjustment of the conditions comprises increasing production rates of the low priority SAGD well pairs and maintaining production rates of the high priority SAGD well pairs.

19. The method of claim 17, wherein the well pad related future calculated value is a predicted total production rate from the well pad, the well pad related target value is a desired total production rate, the predicted total production rate being higher than the desired production rate, and the adjustment of the conditions comprise decreasing production rates of the low priority SAGD well pairs and maintaining production rates of the high priority SAGD well pairs.

20. The method of claim 1, comprising the step of classifying the plurality of SAGD well pairs based on sensitivity.

21. The method of claim 20, wherein the SAGD well pairs classified as sensitive are not adjusted.

22. The method of any one of claims 1 to 21, wherein the model is generated using historical data of the well pad.

CPST Doc: 468541,1 Date Recue/Date Received 2023-01-17

23. The method of claim 10, wherein the AP/QL2 ratio for at least one SAGD
well pair is declining over a time period and adjusting the condition comprises reducing steam injection pressure or rate to the SAGD well pair.

24. A system for managing operations of a well pad at a hydrocarbon-bearing formation, the well pad having a plurality of SAGD well pairs operatively connected to common surface equipment, the system comprising:
a plurality of sensors to monitor the SAGD well pairs;
a plurality of subcontrollers configured to receive a plurality of measurements from the plurality of sensors; and a well pad controller configured to:
generate a series of calculated values from the measurements;
use the series of calculated values in a model to predict a well pad related future calculated value, compare the well pad related future calculated value and a well pad related target value; and automatically issue instructions to adjust a condition of at least one of the SAGD
well pairs based on the comparison.

25. The system of claim 24, wherein the measurements are pre-processed after they have been collected.

26. The system of claim 25, where the measurements are pre-processed by applying a gain multiplier, bias correction, or filtering to the measurements.

27. The system of claim 24, wherein the well pad related future calculated value is a total production rate of the well pad.

28. The system of claim 24, wherein the measurements comprise one or more of bottom-hole pressure, well pair casing temperature, well pair surface temperature, steam quality, chamber grade, and subcool temperature, steam-to-oil ratio, produced water-to-oil ratio, a flow-device CPST Doc: 468541,1 Date Recue/Date Received 2023-01-17 ratio, electrical submersible pump current, a production wellhead pressure, a production wellhead temperature, steam injection pressure, and steam injection rate.

29. The system of claim 24, wherein the well pad related target value is a defined steady state value or a range having a minimum and maximum value.

30. The system of claim 24, wherein the conditions adjusted for each of the at least a portion of the SAGD well pairs comprise the pump speed, steam injection rate, tubing discharge pressure, and hydrocarbon production rate.

31. The system of claim 28, wherein the steam-to-oil ratio is an instantaneous steam-to-oil ratio or a moving window average of either measured or estimated steam-to-oil ratio.

32. The system of claim 28, wherein the produced water-to-oil ratio is an instantaneous water- to-oil ratio or a moving window average of either measured or estimated water- to-oil ratio.

33. The system of claim 28, wherein the flow-device ratio is defined as a AP/QL2 ratio of a flow control device installed in a production well.

34. The system of claim 24, wherein the calculated value comprises a volatility of the steam-to-oil ratio, produced water-to-oil ratio, or the flow-device ratio.

35. The system of claim 34, wherein the well pad related future calculated value is higher than the well pad related target value and the adjustment of the condition comprises decreasing a steam injection pressure or rate.

36. The system of claim 34, wherein the well pad related future calculated value is lower than the well pad related target value and the adjustment of condition comprises reducing the steam injection pressure or rate.
CPST Doc: 468541,1 Date Recue/Date Received 2023-01-17

37. The system of claim 35 or claim 36, wherein the change in steam injection pressure is based on pre-determined parameters.

38. The system of any one of claims 24 to 28, wherein the measurements are collected in real-time.

39. The system of any one of claims 24 to 28, wherein the well pad controller is configured to classify the plurality of well pairs into low priority and high priority based on one or more of production rate, chamber maturity, well pair sensitivity, water content, and plant conditions.

40. The system of claim 39, wherein the well pad related future calculated value is the predicted total production rate from the well pad, the well pad related target value is a desired total production rate, the predicted total production rate being lower than the desired production rate, and the adjustment of the conditions comprises increasing production rates of the low priority well pairs and maintaining production rates of the high priority well pairs.

41. The system of claim 39, wherein the well pad related future calculated value is the predicted total production rate from the well pad, the well pad related target value is a desired total production rate, the predicted total production rate being higher than the desired production rate, and the adjustment of the conditions comprise decreasing production rates of the low priority SAGD well pairs and maintaining production rates of the high priority SAGD well pairs.

42. The system of claim 24, comprising the step of classifying the plurality of SAGD well pairs based on sensitivity.

43. The system of claim 42, wherein the SAGD well pairs classified as sensitive are not adjusted.

44. The system of any one of claims 24 to 43, wherein the model is generated using historical data of the well pad.

CPST Doc: 468541,1 Date Recue/Date Received 2023-01-17

45. The system of claim 33, wherein the controller is configured to issue instructions to reduce steam injection pressure or rate to the SAGD well pair and send an alert to an operator wherein the AP/QL2 ratio is declining over a time period.

46. A method for managing operations of a well pad at a hydrocarbon-bearing formation, the well pad having a plurality of wells operatively connected to common surface equipment, the method comprising:
collecting measurements from one or more sensors monitoring the plurality of wells;
providing the measurements to a well pad controller;
generating a series of calculated values from the measurements using the well pad controller;
the well pad controller using the series of calculated values in a model to predict a well pad related future calculated value;
comparing the well pad related future calculated value and a well pad related target value using the well pad controller; and the well pad controller automatically issuing instructions to adjust a condition of at least one of wells based on the comparison.

47. The method of claim 46, comprising the step of pre-processing the measurements after they have been collected.

48. The method of claim 47, wherein pre-processing the measurements comprises applying a gain multiplier, bias correction, or filtering to the measurements.

49. The method of claim 46, wherein the well pad related future calculated value is a total production rate of the well pad.

50. The method of claim 46, wherein the measurements comprise one or more of bottom-hole pressure, well casing temperature, well surface temperature, steam quality, chamber grade, and subcool temperature, steam-to-oil ratio, produced water-to-oil ratio, a flow-device ratio, electrical submersible pump current, a production wellhead pressure, a production wellhead temperature, steam injection pressure, and steam injection rate.

CPST Doc: 468541,1 Date Recue/Date Received 2023-01-17

51. The method of claim 46, wherein the well pad related target value is a defined steady state value or a range having a minimum and maximum value.

52. The method of claim 46, wherein the conditions adjusted for at least one of the wells comprise pump speed, steam injection rate, steam injection pressure, tubing discharge pressure, and hydrocarbon production rate.

53. The method of claim 50, wherein the steam-to-oil ratio is an instantaneous steam-to-oil ratio or a moving window average of either measured or estimated steam-to-oil ratio.

54. The method of claim 50, wherein the produced water-to-oil ratio is an instantaneous water-to-oil ratio or a moving window average of either measured or estimated water-to-oil ratio.

55. The method of claim 50, wherein the flow-device ratio is defined as a AP/QL2 ratio of a flow control device installed in at least one of the plurality of wells.

56. The method of claim 50, wherein the calculated value comprises a volatility of the steam-to-oil ratio, produced water-to-oil ratio, or the flow-device ratio.

57. The method of claim 56, wherein the well pad related future calculated value is higher than the well pad related target value and adjusting the condition comprises decreasing a steam injection pressure or rate into at least one of the wells in the well pad.

58. The method of claim 56, wherein the well pad related future calculated value is lower than the well pad related target value and adjusting the condition comprises decreasing a steam injection pressure or rate into at least one of the wells in the well pad.

59. The method of claim 57 or claim 58, wherein the step of adjusting the condition is performed based on pre-determined parameters.

CPST Doc: 468541,1 Date Recue/Date Received 2023-01-17

60. The method of any one of claims 46 to 59, wherein the measurements are collected in real- time.

61. The method of any one of claims 46 to 59, comprising increasing an injection pressure or rate when the future calculated value is within a range of the target value.

62. The method of claim 46, comprising the step of classifying the plurality of wells into low priority and high priority based on one or more of production rate, chamber maturity, well sensitivity, water content, and plant conditions.

63. The method of claim 62, wherein the well pad related future calculated value is a predicted total production rate from the well pad, the well pad related target value is a desired total production rate, the predicted total production rate being lower than the desired production rate, and the adjustment of the conditions comprises increasing production rates of the low priority wells and maintaining production rates of the high priority wells.

64. The method of claim 62, wherein the well pad related future calculated value is a predicted total production rate from the well pad, the well pad related target value is a desired total production rate, the predicted total production rate being higher than the desired production rate, and the adjustment of the conditions comprise decreasing production rates of the low priority wells and maintaining production rates of the high priority wells.

65. The method of claim 46, comprising the step of classifying the plurality of wells based on sensitivity.

66. The method of claim 65, wherein at least one of the wells classified as sensitive are not adjusted.

67. The method of any one of claims 46 to 66, wherein the model is generated using historical data of the well pad.

CPST Doc: 468541,1 Date Recue/Date Received 2023-01-17

68. The method of claim 55, wherein the AP/QL2 ratio for at least one of the wells is declining over a time period and adjusting the condition comprises reducing steam injection pressure or rate to the at least one well in the well pad.

69. A method for managing operations of a well pad at a hydrocarbon-bearing formation, the well pad having a plurality of well pairs operatively connected to common surface equipment, the method comprising:
collecting measurements from one or more sensors monitoring the plurality of well pairs;
providing the measurements to a well pad controller;
generating a series of calculated values from the measurements using the well pad controller;
the well pad controller using the series of calculated values in a model to predict a future calculated value;
comparing the well pad related future calculated value and a well pad related target value using the well pad controller; and the well pad controller automatically issuing instructions to adjust a condition of at least one of well pairs based on the comparison.

70. The method of claim 69, comprising the step of pre-processing the measurements after they have been collected.

71. The method of claim 70, wherein pre-processing the measurements comprises applying a gain multiplier, bias correction, or filtering to the measurements.

72. The method of claim 69, wherein the well pad related future calculated value is a total production rate of the well pad.

73. The method of claim 69, wherein the measurements comprise one or more of bottom-hole pressure, well pair casing temperature, well pair surface temperature, steam quality, chamber grade, and subcool temperature, steam-to-oil ratio, produced water-to-oil ratio, a flow-device CPST Doc: 468541,1 Date Recue/Date Received 2023-01-17 ratio, electrical submersible pump current, a production wellhead pressure, a production wellhead temperature, steam injection pressure, and steam injection rate.

74. The method of claim 69, wherein the well pad related target value is a defined steady state value or a range having a minimum and maximum value.

75. The method of claim 69, wherein the conditions adjusted for at least one of the well pairs comprise pump speed, steam injection rate, steam injection pressure, tubing discharge pressure, and hydrocarbon production rate.

76. The method of claim 73, wherein the steam-to-oil ratio is an instantaneous steam-to-oil ratio or a moving window average of either measured or estimated steam-to-oil ratio.

77. The method of claim 73, wherein the produced water-to-oil ratio is an instantaneous water-to-oil ratio or a moving window average of either measured or estimated water-to-oil ratio.

78. The method of claim 73, wherein the flow-device ratio is defined as a AP/QL2 ratio of a flow control device installed in at least one production well of the well pair.

79. The method of claim 73, wherein the calculated value comprises a volatility of the steam-to-oil ratio, produced water-to-oil ratio, or the flow-device ratio.

80. The method of claim 79, wherein the well pad related future calculated value is higher than the well pad related target value and adjusting the condition comprises decreasing a steam injection pressure or rate into the at least one well pair in the well pad.

81. The method of claim 79, wherein the well pad related future calculated value is lower than the well pad related target value and adjusting the condition comprises decreasing a steam injection pressure or rate into the at least one well pair in the well pad.

CPST Doc: 468541,1 Date Recue/Date Received 2023-01-17

82. The method of claim 80 or claim 81, wherein the step of adjusting the condition is performed based on pre-determined parameters.

83. The method of any one of claims 69 to 82, wherein the measurements are collected in real- time.

84. The method of any one of claims 69 to 83, comprising increasing an injection pressure or rate when the well pad related future calculated value is within a range of the well pad related target value.

85. The method of claim 69, comprising the step of classifying the plurality of well pairs into low priority and high priority based on one or more of production rate, chamber maturity, well pair sensitivity, water content, and plant conditions.

86. The method of claim 85, wherein the well pad related future calculated value is a predicted total production rate from the well pad, the well pad related target value is a desired total production rate, the predicted total production rate being lower than the desired production rate, and the adjustment of the conditions comprises increasing production rates of the low priority well pairs and maintaining production rates of the high priority well pairs.

87. The method of claim 85, wherein the well pad related future calculated value is a predicted total production rate from the well pad, the well pad related target value is a desired total production rate, the predicted total production rate being higher than the desired production rate, and the adjustment of the conditions comprise decreasing production rates of the low priority well pairs and maintaining production rates of the high priority well pairs.

88. The method of claim 69, comprising the step of classifying the plurality of well pairs based on sensitivity.

89. The method of claim 88, wherein the at least one well pair classified as sensitive are not adjusted.

CPST Doc: 468541,1 Date Recue/Date Received 2023-01-17

90. The method of any one of claims 69 to 89, wherein the model is generated using historical data of the well pad.

91. The method of claim 78, wherein the AP/QL2 ratio for at least one well pair is declining over a time period and adjusting the condition comprises reducing steam injection pressure or rate to the at least one well pairs in the well pad.

92. The method of claim 69, wherein the well pair comprises a solvent injection well and a production well.

93. The method of claim 69, wherein the well pair comprises a steam/solvent co-injection well and a production well.

94. The method of claim 69, wherein the well pair comprises a solvent injection well including an antenna to generate radio frequency (RF) heating of connate water in situ, and a production well.

CPST Doc: 468541,1 Date Recue/Date Received 2023-01-17