HYDROCARBON RECOVERY CONTROL SYSTEM AND METHOD

Info

Publication number: 20140216732
Type: Application
Filed: Nov 11, 2013
Publication Date: Aug 7, 2014
Applicant: Schlumberger Technology Corporation (Sugar Land, TX)
Inventors: Terry Wayne Stone (Kings Worthy), Carlos Emilio Perez Damas (Calgary)
Application Number: 14/076,411

Abstract

The present disclosure describes a system, method and computer readable medium capable of dynamically managing a hydrocarbon recovery operation. The hydrocarbon recovery operation may utilize an injection well and a production well. Proportional integral derivative controller(s) may be utilized to control injection processes (for the injection well) and/or production processes (for the production well) using temperature and/or pressure data obtained from the formation. One or more production tubulars may be equipped with inflow control devices capable of controlling the flow of hydrocarbons from the formation into the production well. In one embodiment, the PID controller(s) may adjust the positioning of the injection tubing strings and/or production tubulars within their respective wells. A graphic user interface may be provided to allow users to adjust and/or customize recovery operation parameters.

Description

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This patent application claims priority upon and incorporates by reference herein, a first provisional patent application entitled “Advanced Wellbore Simulation of Flow Control Devices with Feedback Control for Thermal Operations,” filed on Nov. 12, 2012, Ser. No. 61/725,346; and a second provisional application entitled “PID Controlled SAGD Injection and Production Wells For Efficient Steam,” filed on Jun. 7, 2013, Ser. No. 61/832,260.

BACKGROUND

High viscosity hydrocarbons may present a challenge during oilfield recovery operations. Such hydrocarbons may be so viscous under the prevailing conditions within a formation that they flow very slowly (or not at all) in response to the force of gravity. Example formations containing high viscosity hydrocarbons include bitumen deposits in Canada and the United States and heavy oil deposits in Canada, the United States, and Venezuela.

Steam Assisted Gravity Drainage (SAGD) may be utilized to assist in the recovery of viscous hydrocarbons from a subterranean formation. One or more horizontal injection wells may be utilized in order to inject stimulating fluid, e.g., saturated steam, into the formation. Saturated steam may be used to decrease the viscosity of the hydrocarbons by increasing the temperature of the surrounding formation. The reduced viscosity encourages the hydrocarbons to move downwardly through the formation (via gravity drainage) into one or more production wells positioned underneath the injection well(s).

It may be necessary to adjust SAGD process variables, such as injection rates, production rates, etc., in order to facilitate optimal hydrocarbon production from the formation. As such, there remains a need for a hydrocarbon recovery control system and method capable of dynamically managing process variables in a SAGD hydrocarbon recovery process.

SUMMARY

Accordingly, the present disclosure describes a system, method and computer readable medium capable of dynamically managing process variables in a SAGD hydrocarbon recovery process.

In one embodiment, the SAGD process may utilize an injection well and a production well. The injection well may utilize a plurality of tubing strings to deliver saturated steam to the formation. In one embodiment, the injection well may utilize a short tubing string that terminates at or near the heel portion of the injection well and long tubing string that terminates at or near the toe portion of the injection well.

In one embodiment, the production well may be located below and generally parallel to the injection well in order to facilitate the collection of hydrocarbons via gravity drainage. In one embodiment, the production well may be equipped with one or more production tubulars for collecting hydrocarbons from the formation. In one embodiment, the operation of one or more tubing strings and/or one or more of the production tubulars may be controlled by Proportional Integral Derivative (PID) controller(s).

In one embodiment, one or more of the production tubulars may be equipped with a plurality of inflow control devices (ICDs) capable of controlling the flow of hydrocarbons from the formation into the production well. In one embodiment, the ICDs may be utilized in conjunction with one or more of the Proportional Integral Derivative (PID) controller(s) in order to improve the efficiency and performance of the SAGD process.

In one embodiment, the PID controller(s) may receive and process temperature data pertaining to one or more sections of a well pair. In one embodiment, temperature data may be obtained from an array of temperature sensors and/or fiber optic distributed temperature sensors positioned in and/or around the well pair. Temperature data may also be derived from pressure data, if necessary. Pressure measurements may be obtained by a bubble tube pressure gauge, quartz pressure transducer, or other pressure suitable sensors.

In one embodiment, temperature and/or pressure data may be gathered from various sections of the well pair and/or the surrounding formation and used in order to determine a temperature difference between selected section(s) of the well pair. In one embodiment, each section of the formation (including sections of the well pair) may be illustrated to the user via a graphic user interface so that he or she may select which sections of the formation will be used to determine the measured temperature difference. In one embodiment, sections of the formation may be delineated on the graphic user interface by a grid arrangement, by broken lines, or any other suitable audio/visual convention.

In one embodiment, the determined temperature difference may pertain to a temperature difference between a section of the injection well and a section of the production well. In one embodiment, the measured temperature difference between a section of the injection well and a section of the production well may be referred to as an interwell subcool.

In one embodiment, the interwell subcool may be compared to a target temperature difference and expressed as an error term e(t) which may then be incorporated into a control function utilized by the PID controller(s). In one embodiment, the PID controller(s) may calculate the error term and attempt to achieve the calculated error by adjusting one or more control variables of the control function. In one embodiment, the PID controller(s) may generate electrical control signal(s) based on the adjusted control variables in order to vary the steam injection rate, the production rate and/or other hydrocarbon recovery operation parameters.

In one embodiment, the PID controller(s) may be utilized to adjust the positioning of the injection tubing strings and/or production tubulars within their respective wells. This may be accomplished by pushing or pulling the tubing string or tubular to be relocated. In one embodiment, the relocation of tubing strings and/or production tubulars may be conducted automatically or manually at the direction of the user. For example, relocation may be triggered automatically if the error term is determined to be higher or lower than a threshold temperature value.

In one embodiment, the error term may be altered by selectively omitting temperature data from the temperature difference calculation. In one embodiment, the system may provide a graphic user interface through which the user may select and de-select sections of the formation/well pair that will be excluded from the temperature difference comparison. This may also be accomplished by automatically omitting temperature data that falls below a given threshold.

The control function utilized by one or more PID controllers may have one or more adjustable control variables that, in conjunction with the error term, may be used to control injection processes (for the injection well) and/or production processes (for the production well) during SAGD operations. In one embodiment, control operations for the well pair may be controller specific such that control variables may be adjusted for each control function for each PID controller.

In one embodiment, a graphic user interface may provide data entry field(s) or other suitable data entry functionality to allow the user to enter customized control variables for each controller. In one embodiment, this may involve customizing the value of the time constant and/or the value of the proportionality constant for the PID controller(s).

This summary is provided to introduce a selection of concepts in a simplified form that are further described herein. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in determining the scope of the claimed subject matter.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete appreciation of the present disclosure and many of the attendant advantages thereof will be readily obtained as the same becomes better understood by reference to the following detailed description when considered in connection with the accompanying drawings; it being understood that the drawings contained herein are not necessarily drawn to scale and that the accompanying drawings provide illustrative implementations and are not meant to limit the scope of various technologies described herein; wherein:

FIG. 1 is a schematic diagram of an example SAGD system for recovering hydrocarbons from a subterranean formation in one embodiment.

FIG. 2 is a schematic illustration of a computer system of one example embodiment.

DETAILED DESCRIPTION

In the following description, numerous details are set forth to provide an understanding of various embodiments of the invention. However, it will be understood by those skilled in the art that the invention may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.

The present disclosure describes embodiments of a method of controlling a hydrocarbon recovery operation, a computer readable medium for controlling a hydrocarbon recovery operation and a hydrocarbon recovery control system. FIG. 1 illustrates an example embodiment of a SAGD system (10) for facilitating hydrocarbon production from a subterranean formation (12) using a well pair (13). FIG. 1 illustrates a single well pair for case of illustration only. The system may utilize multiple well pairs according to any number of configurations.

In this example, the well pair (13) includes an injection well (14) having a substantially vertical portion (14V), a substantially curved heel portion (14HE), a substantially horizontal portion (14H) and a toe portion (14T). In one embodiment, the term “horizontal” as used herein may refer to a portion of a well that undulates with an axial angular deviation. In one embodiment, the axial angular deviation may vary between +/−5 degrees.

One or more portions of the injection well (14) may be completed with a slotted liner (not shown). The slotted liner may be machined with multiple longitudinal slots distributed across its length and/or circumference. The slots may provide for fluid communication between the inside of the injection well (14) and the formation (12). The slotted liner may be put in place without any cement if desired.

In one embodiment, a screen (such as gravel or mesh backed by a grid) (not shown) may be placed between the slotted liner and the borehole wall of the injection well to provide a sand filter therebetween. The substantially horizontal portion (14H) of the injection well may be isolated from other parts of the injection well (14) by any suitable completion equipment, such as a packer (16).

The injection well (14) may utilize a plurality of tubing strings to deliver saturated steam to the formation. In one embodiment, the injection well (14) may utilize a dual tubing string arrangement. In one embodiment, the dual tubing string arrangement in the injection well may utilize a short tubing string (14A) that terminates at or near the heel portion (14HE) of the injection well and long tubing string (14B) that terminates at or near the toe portion (14T) of the injection well. In one embodiment, the short tubing string (14A) may have a larger or smaller diameter than the long tubing string (14B).

The well pair (13) of the SAGD system (10) may also include a production well (18) having a substantially vertical portion (18V), a substantially curved heel portion (18HE), a substantially horizontal portion (18H) and a toe portion (18T). The substantially horizontal portion (18H) of the production well (18) may be completed with a slotted liner in the same manner as with the injection well. In one embodiment, one or more portions of the production well (18) may be located below the injection well (14) to facilitate collection of hydrocarbons via gravity drainage. In one embodiment, the production well may be generally parallel to the injection well.

The SAGD system (10) may also include a steam production facility (20) capable of vaporizing water into steam and supplying the steam under pressure to one or more tubing strings in the injection well. In one embodiment, surface-located control chokes (22A & 22B, respectively) may be utilized. In one embodiment, the chokes may control the tubing head pressure in order to regulate the flow of the saturated steam into the short tubing string (14A) and the long tubing string (14B), respectively.

In one embodiment, steam may be directed to flow through one or more tubing strings of the injection well (14) such that a steam chamber (24) is created within the formation. In one embodiment, heat transfer may be accomplished in and around the steam chamber (24) via condensation of steam and conductive heat transfer, which reduces the viscosity of the hydrocarbons in the region and allows them to flow downwardly by gravity drainage into the production well (18).

In one embodiment, the production well may be equipped with a slotted liner (not shown) through which hydrocarbons may flow from the formation (12) into the production well (18). In one embodiment, the production well may be equipped with at least one production tubular (26) for collecting hydrocarbons from the formation. In one embodiment, the production tubular may take the form of a pipe running the entire length of the production well. Multiple production tubulars may be utilized as desired.

In one embodiment, the operation of one or more tubing strings and/or tubulars in the SAGD system (10) may be controlled by Proportional Integral Derivative (PID) controller. For example, the operation of the short tubing string (14A) of the injection well (14) may be controlled by a first PID controller (28A). In this example, the first PID controller (28A) may control the amount and/or location of saturated steam injected into the injection well via the short tubing string (14A). Likewise, the operation of the long tubing string (14B) in the injection well (14) may be controlled by a second PID controller (28B). In this example, the second PID controller (28B) may control the amount and/or location of saturated steam injected into the injection well via the long tubing string (14B).

In one embodiment, the PID controller(s) may receive and process temperature data pertaining to one or more sections (29) of the well pair (13) and/or the formation (12). In one embodiment, temperature data may be obtained from an array of temperature sensors and/or fiber optic distributed temperature sensors (not shown) positioned in and/or around the well pair (13).

In one embodiment, the temperature of inflowing fluids to one or more sections of the production well may be measured by averaging a plurality of temperature measurements distributed over the length of the section(s). For example, the temperature of inflowing fluids to the horizontal section (18H) of the production well (18) may be measured by averaging a number of temperature measurements distributed over the length of the horizontal section (18H). The temperature sensor(s) may be deployed near the top of a slotted liner of the production well (18) or using a buckled instrument string (not shown) in order to identify and account for any temperature gradients across the production well (18).

Temperature data may also be derived from pressure data, if necessary. For example, measured pressure values from the injector well (14) may be used as input to a look-up table (“steam table”) or other applicable reference data providing the saturation temperature of steam in the injection well as a function of pressure. Pressure measurements may be obtained by a bubble tube pressure gauge, quartz pressure transducer, or other pressure sensors suitable for the high temperate environment of the injection well (14).

The pressure for one or more sections of the injection well may be derived by averaging pressure measurements distributed over the length of the section(s). For example, the pressure of the horizontal section (14H) of the injection well (14) may be measured by averaging a number of pressure measurements distributed over the length of the horizontal section (14H).

In one embodiment, a temperature difference between a first section of the well pair and a second section of the well pair may be determined using measured and/or derived temperature data. In one embodiment, the first section of the well pair (13) may be located inside all or a part of the injection well (14) and the second section may be located inside all or a part of the production well (18). In one embodiment, an average of measured/derived temperature values taken from the horizontal portion (14H) of the injection well (14) may be compared to an average of measured/derived temperature values taken from the horizontal portion (18H) of the production well (18) in order to arrive at the measured temperature difference. In one embodiment, the measured temperature difference between a section of the injection well (14) and a section of the production well (18) may be referred to as an interwell subcool.

In one embodiment, the interwell subcool may be compared to a target temperature difference and expressed as an error term e(t) which may then be incorporated into a control function that may be utilized by one or more PID controller(s), as described in greater detail below. In one embodiment, the error term e(t) may represent the difference between the measured interwell subcool and a target temperature difference. Further, the error term e(t) may be expressed as the temperature of steam inside all or a section of the injection well (14) minus the temperature of fluids flowing into all or a section of the production well (18). The error term may vary based upon which sections of the well pair have been selected for analysis, as described further below.

In one embodiment, the control function utilized by the PID controller(s) described herein may be based upon the following formulation:

$\begin{matrix} {IR}_{1} = {IR}_{1 t_{s}} + K_{p} (e_{1} (t) + \frac{\int_{t_{s}}^{t_{e}} e_{1} (t) \partial t}{T_{i}} - T_{d} \frac{\partial}{\partial t} e_{1} (t)) & Eqn . 1 \end{matrix}$

where IR₁, the adjusted control variable, is the injection rate into one of the tubing strings (14A or 14B) of the injection well (14), which may be dictated by operation of control chokes (22A or 22B);

where IR_M_ris the initial injection rate into one of the tubing strings of the injection well (14) (when the algorithm is started or reset), which is dictated by the initial state of control chokes (22A or 22B);

where K_pis a proportionality constant for all of the terms of the controller;

where K_pe₁(t) is the proportional term, which produces an output value that is proportional to the current error value;

where T_iis an integral time constant for the integral term

$\frac{K_{p} \int_{t_{s}}^{t_{e}} e_{1} (t) \partial t}{T_{i}},$

which is proportional to the integral of the error value over time;

where T_dis a derivative constant for the derivative term

$- K_{p} T_{d} \frac{\partial}{\partial t} e_{1} (t),$

which is proportional to the derivative of the error value at a given time and may be used to slow the rate of change of the controller output; particularly, the derivative time constant may be used to reduce the magnitude of the overshoot produced by the integral term and improve stability of the control system when multiple PID controllers are utilized in combination; and

where e₁(t) is an error term representing the difference between the interwell subcool temperature for selected section(s) of the well pair and a given target subcool value at a given time.

In one embodiment, each PID controller may calculate an error term as the difference between a measured process variable (in this case, the interwell subcool temperature for selected sections of the well pair) and a desired set point (in this case, the target subcool value for the selected sections of the well pair), and attempt to achieve the calculated error by adjusting one or more control variables of the control function.

In one embodiment, each of the PID controllers may employ a control function having a proportional term and associated proportional constant, an integral term and associated integral time constant, and a derivative term and an associated derivative time constant.

The above example may be applied to additional tubing strings as desired. For example, a first PID controller (28A) may be utilized in connection with the short tubing string (14A) of the injection well (14) while a second PID controller (28B) may be utilized in connection with the long tubing string (14B) of the injection well (14).

In the above example, the PID controller may generate an electrical control signal based on the adjusted control variable IR and may output the electrical control signal for communication to the control chokes. This electrical control signal may be utilized to dictate operation of control choke of tubing strings (14A or (14B) in order to vary the steam injection rate.

In one embodiment, the PID controller may be utilized to adjust the positioning of one or more injection tubing strings (or production tubulars) within their respective wells. For example, if the subcool value for a compared section of the well pair is too high (meaning that the temperature in a section of the production well is lower than desired), the system may relocate one or more of the tubing strings in the injection well and/or one or more of the tubulars in the production well in an effort to compensate. This may be accomplished by pushing or pulling the tubing string or tubular to be relocated, illustrated by arrows (30), using surface relocation equipment (not shown).

For example, a tubing string or tubular may be moved from the toe portion of its respective well to the heel portion of its respective well via a pulling operation executed by surface equipment. Likewise, a tubing string or tubular may be moved from the heel portion (14HE, 18HE) within its respective well to the toe portion (14T, 18T) within its respective well via a pushing operation executed by surface equipment. In one embodiment, the relocation of tubing strings and/or production tubulars may be executed automatically by the system or manually at the direction of the user. For example, relocation may be triggered automatically if the error term is determined to be higher or lower than a threshold value.

In one embodiment, the error term e(t) utilized by one or more of the PID controllers may be adjusted and/or altered to improve efficiency of the SAGD system (10). In one embodiment, each section (29) of the formation (including sections of the well pair) may be illustrated to the user via a graphic user interface (not shown) so that he or she may select which sections of the formation will be used to determine the measured temperature difference using any suitable input device. In one embodiment, sections of the formation may be delineated on the graphic user interface by a grid arrangement, by broken lines, or any other suitable audio/visual convention.

The graphic user interface may provide a 2D, 3D and/or 4D image of the formation and the well pair. Other data concerning the condition of the formation and/or well pair may also be displayed via the graphic user interface, such as temperature, pressure, porosity, permeability, etc., to assist the user in selecting/deselecting section(s) of the formation/well pair for comparison.

In one embodiment, a data visualization application capable of accessing, processing and displaying data pertaining to the formation (including the well pair) upon one or more graphic user interfaces may be utilized. The data visualization application may be a stand-alone application, such as the Petrel® system offered by Schlumberger, or a proprietary data visualization package.

In one embodiment, the system may include an automatic section delineation feature whereby section boundaries (29B) are determined using measured or derived temperature values obtained therefrom. For example, a section boundary may be delineated when a measured or derived change in temperature between one section of the formation and another section of the formation is found to be greater than a threshold number of degrees. In this example, the user may select which sections of the well pair and/or formation are to be subjected to the temperature difference calculation and thus included in the error term, as discussed in greater detail below.

In one embodiment, the graphic user interface may provide a number of default options for the user's convenience. For example, the system may provide a default temperature difference calculation option by which the entire horizontal section of the injection well (14) is set to be the first section and the entire horizontal section of the production well (18) is set to be the second section for the purpose of the temperature difference calculation.

In this example, the average temperature of the horizontal section of the injection well may be compared to the average temperature of the horizontal section of the production well in order to arrive at the measured temperature difference. The measured temperature difference may then be compared to a target value and used to generate the error term e(t). The target value may be set as a default by the system or entered by the user via the graphic user interface. Target temperature difference values may vary depending on the application, number of wells, etc. In one embodiment, the default target temperature difference may be between about 2° Celsius and about 5° Celsius.

In one embodiment, the error term may be altered by selectively omitting temperature data from one or more sections of the formation from the temperature difference calculation. For example, low temperature situations may be caused by solid rock protrusions which may act as a heat sink, and/or heterogeneity conditions of the formation. In one embodiment, the system may provide a graphic user interface through which the user may select and de-select sections of the formation/well pair that will be included or excluded from the temperature difference comparison. This may also be accomplished by providing an entry field through which the user may enter threshold temperature value(s).

For example, if the user wishes to exclude sections of the formation where the measured or derived temperature (or average temperature) is less than a threshold value of 10° Celsius, he or she may enter the value “10” into the data entry field provided by the system. In this example, temperature from sections of the formation having a temperature of less than 10 degrees Celsius would be excluded from the temperature difference calculation and thus excluded from the error term e(t) in the control function.

In one embodiment, the error term may be automatically adjusted to exclude low temperature sections of the formation using a temperature sort algorithm. In one embodiment, the temperature sort algorithm may: (1) arrange temperature data in a hierarchy from lowest temperature to highest temperature; (2) beginning with the highest temperature value and working downward, calculate a moving average of the temperatures while noting the cumulative Kh (completion permeability multiplied by completion length) for all temperatures involved in the moving average; and (3) if the cumulative value exceeds a specified minimum fraction (⅔ for example) of the total, and the moving average using the next coolest temperature is more than a specified temperature difference that is lower than the moving average, the temperature difference calculation may be halted and the moving average temperature may be used as the “average” temperature for selected sections of the formation.

In one embodiment, the average temperature used in the temperature difference (subcool) calculation may reflect most, but not necessarily all, of the temperatures of inflowing fluids into the producer well (18). The section with the coolest temperatures in each well may be ignored if they are significantly lower than the hottest temperatures in the corresponding well (or outside of a threshold value), and provided their cumulative Kh is less than ⅓ of the total for the corresponding well.

In one embodiment, a uniformity feature may be utilized to determine the uniformity of temperature values for one or more sections of the injection well and/or for one or more sections of the production well. A threshold uniformity value may be entered by the user or set by the system as a default. For example, if the user enters a uniformity threshold of 10° Celsius, and the measured/derived temperature values for selected sections of the injection well range from 12° to 22° Celsius (22°−12°=a ΔT of 10° Celsius), the temperature values for the injection well would be found to fall within the uniformity range such that none of the sections would be automatically excluded from the temperature difference calculation.

In one embodiment, the production tubular of the production well (18) may be equipped with a plurality of inflow control devices (ICDs) (32) capable of controlling the flow of hydrocarbons into the production well (18). In one embodiment, the ICDs may be utilized in conjunction with one or more of the Proportional Integral Derivative (PID) controllers in order to improve the efficiency and performance of the SAGD process.

In one embodiment, the operation of each ICD in the production well may be controlled (directly or indirectly) by a PID controller (26A). Further, each production tubular in the production well may be controlled by an independent PID controller and equipped with ICDs. For example, the production well may have a first production tubular (26) controlled by a first PID controller (26A) and a second production tubular controlled by a second PID controller.

In one embodiment, the ICDs may be utilized to regulate the pressure drop between the formation (12) and the inside of the production well (18). In one embodiment, the orientation of ICDs within the production well (alone or in combination) may be manipulated in order to generate a substantially uniform pressure profile between the formation and the inside of the production. Generating a substantially uniform pressure profile around the production well (18) may incentivize the hydrocarbons to flow into the entire length of the production well (thus improving overall production) instead of into low pressure areas in the production well that may be created by a non-uniform pressure profile.

The ICDs may be mounted on an outer edge (26E) of the production tubular (26) at various locations along the length of the production well (18). In one embodiment, ICDs may be mounted in discrete segments along the entire length of the horizontal portion (18H) of the production well (18). For example, if the horizontal portion of the production well has a length of 100 meters, ICDs may be mounted every 5 meters along the length of the substantially horizontal portion of the production well so as to provide control over various sections of the well.

In one embodiment, each ICD may be equipped with one or more nozzles (not shown) capable of manipulating the flow of hydrocarbons from the formation into the production well. In one embodiment, one or more of the ICD nozzles may be adjusted (directly or indirectly) by a PID controller (26A) in order to selectively control the inflow of production fluids into the production well and, in turn, create a more uniform pressure profile around the production well. An ICD controller (32C) may be utilized to facilitate control of the ICD's by the PID controller (26A). In one embodiment, the diameter of one or more ICD nozzles may be adjusted in order to selectively control the inflow of production fluids into the production well.

In one embodiment, the ICDs may include a sand control screen and/or choke combination capable of delivering a linear production profile throughout the length of the horizontal portion of the production well. In one embodiment, each ICD may be calibrated or tuned to geological parameters of the formation, such as permeability and porosity.

Hydrocarbons collected by the production well may be drawn to the surface with the aid of artificial lift systems (e.g., gas lift, progressing cavity pump, electric submersible pump, etc). Produced hydrocarbons may be processed by a separation facility (34) capable of separating oil and water therefrom. The water recovered by the separation facility may be treated by a water treatment facility (36) (for example, involving separation/filtration of solids, de-aeration, sulfate removal, softening, etc.) and supplied to the steam production facility (20).

PID control operations may also involve control over artificial lift devices used with one or more of the production tubing strings. For example, correcting for subcool errors where the measured interwell subcool temperature for a given injector-producer section pair is greater than the target subcool can involve controlling the artificial lift device for the producing section of the corresponding injector-producer section pair to decrease the flow rate of produced fluids from the production well section, and correcting for subcool errors where the measured interwell subcool temperature for a given injector-producer section pair is less than the target subcool can involve controlling the artificial lift device for the producing section of the corresponding injector-producer section pair to increase the flow rate of produced fluids from the production well section. For example, a PID controller may be used to regulate the total production rate and/or the water production rate of one or more tubulars in the production well in order to achieve an average subcool target along the entire length of the well.

Further, the control function utilized by one or more PID controllers may have one or more adjustable control variables that, in conjunction with the error term, may be used to control injection processes (for the injection well) and/or production processes (for the production well) during SAGD operations. In one embodiment, control operations for the well pair (13) may be controller specific such that control variables may be adjusted for each control function for each PID controller.

Consider an example well pair having an injection well with a dual tubing string arrangement (long and short) and a production well having a single production tubular (26) equipped with ICDs (32). In one embodiment, control variables may be customized for each controller (a first controller (28A) for the short tubing string (14A) in the injection well (14), a second PID controller (28B) for the long tubing string (14B) in the injection well (14), and a third PID controller (26A) for the production tubular (26) in the production well (18) in this example) such that the controllers are not fighting each other during recovery operations.

In this example, the graphic user interface may provide data entry field(s) or other suitable data entry functionality to allow the user to enter customized control variables for each controller. In one embodiment, this may involve customizing the value of the time constant (T_iin the above example) and/or the value of the proportionality constant (K_pin the above example) for one or more of the PID controllers. Control variable values may vary depending on the application, number of wells, etc.

In one embodiment, the graphic user interface may provide a number of default and/or recommended options for the user's convenience. For example, the system may provide default and/or recommended value(s) for the proportionality constant and/or the time constant based upon optimal simulation results. In one embodiment, the time constant utilized by the PID controller(s) in the injection well may be between about 5 and about 10 days. In one embodiment, the time constant utilized by the PID controller(s) in the production well may be larger than the time constant utilized by the PID controller(s) for the injection well. In one embodiment, the time constant for the PID controllers in the production well may be roughly is 2-3 times the time constant value used by the injection well PID controllers. Thus, in this example, the time constant for the PID controller(s) in the production well may be in a range of between about 10 days to about 30 days.

Likewise, the proportionality constant may be varied for individual PID controllers. In one embodiment, the proportionality constant may be utilized to assign a priority to one or more of the PID controllers relative to other PID controllers in the system. Put simply, the larger the proportionality constant in the control function, the more responsive the controller will be to sudden temperature variations. Thus, the user may vary the proportionality constant for each PID controller in order to prioritize individual PIC controller functionality for the SAGD system (10). In one embodiment, the proportionality constant utilized by the PID controller(s) in the production well may be less than the proportionality constant utilized by the PID controller(s) in the injection well. In this example, the PID controllers controlling the operation of the injection well are given priority over those controlling the operation of the production well.

Other fluids (such as hydrocarbon solvents) capable of reducing the viscosity of the heavy oil of the reservoir may be injected into the injection well to enhance hydrocarbon recovery operations. Further, techniques such as in situ heating and fire flooding may be used to reduce the viscosity of the heavy oil of the reservoir in order to enhance production of fluids from the production well. In these embodiments, the independent PID control operations of the tubing strings of the injection well and/or production well can be extended to control properties of the injection well and/or production well.

Other well arrangements may be used, such as a J-well Assisted Gravity Drainage (JAGD) design. For example, the upper portion of the injection well may extend generally in a horizontal direction and the lower portion of the production well may extend in an inclined manner under the upper portion of the injection well. Further, one or more of the well(s) may contain planned or side-tracking lateral branches. Multiple tubing strings may be used in one or more of the branches/side tracks and a controller provided for one or more injector-producer sections therein.

Moreover, one or more observation wells may be used to intersect the injector well and/or the production well. The observation well(s) can be outfitted with temperature sensors for monitoring the temperature of one or more sections of the well pair (13). These temperature measurements can be part of the error term of the respective controllers and can be given a weighting factor and can be used to adjust the boundaries of the injector-producer sections. For example, if a temperature observation well observes a cooler region of the steam chamber away from the well pair, then the operator may decide to use that criterion temporarily to override the subcool target, reduce the subcool target and/or change boundaries of the injector-producer sections, in order to improve the efficiency of the hydrocarbon recovery process.

Further, the independent PID control operations of the tubing strings/tubulars of an injection well and production well can be extended to control other measured process variables of the injection well and/or production well, such as the gas-oil ratio (GOR), steam-oil ratio (SOR), or water-cut. Water-cut is the ratio of water produced compared to the volume of total liquids produced. For example, the error term of the respective controllers can be modified to include other quantities besides the difference between actual interwell subcool and target subcool. For example, if the water cut is measured by a downhole flow meter to be much higher than desired, then the water cut can be included in the error term of the PID controller with a weighting factor such that either it can be the sole error term or it can be weighted together with the subcool to calculate a mixed error term. Similar adaptations may be made for GOR and/or SOR.

The methods described herein may be implemented on any suitable computer system capable of processing electronic data. FIG. 2 illustrates one possible configuration of a computer system (38) that may be utilized. Computer system(s), such as the example system of FIG. 2, may run programs containing instructions, that, when executed, perform methods according to the principles described herein. Furthermore, the methods described herein may be fully automated and able to operate continuously, as desired.

The computer system may utilize one or more central processing units (40), memory (42), communications or I/O modules (44), graphics devices (46), a floating point accelerator (48), and mass storage devices such as tapes and discs (50). Storage device (50) may include a floppy drive, hard drive, CD-ROM, optical drive, or any other form of storage device. In addition, the storage devices may be capable of receiving a floppy disk, CD-ROM, DVD-ROM, disk, flash drive or any other form of computer-readable medium that may contain computer-executable instructions.

Further communication device (44) may be a modem, network card, or any other device to enable communication to receive and/or transmit data. It should be understood that the computer system (38) may include a plurality of interconnected (whether by intranet or Internet) computer systems, including without limitation, personal computers, mainframes, PDAs, cell phones and the like.

It should be understood that the various technologies described herein may be implemented in connection with hardware, software or a combination of both. Thus, various technologies, or certain aspects or portions thereof, may take the form of program code (i.e., instructions) embodied in tangible media, such as floppy diskettes, CD-ROMs, hard drives, or any other machine-readable storage medium wherein, when the program code is loaded into and executed by a machine, such as a computer, the machine becomes an apparatus for practicing the various technologies.

In the case of program code execution on programmable computers, the computing device may include a processor, a storage medium readable by the processor (including volatile and non-volatile memory and/or storage elements), at least one input device, and at least one output device. One or more programs that may implement or utilize the various technologies described herein may use an application programming interface (API), reusable controls, and the like.

Such programs may be implemented in a high level procedural or object oriented programming language to communicate with a computer system. However, the program(s) may be implemented in assembly or machine language, if desired. In any case, the language may be a compiled or interpreted language, and combined with hardware implementations.

The computer system (38) may include hardware capable of executing machine readable instructions, as well as the software for executing acts that produce a desired result. In addition, computer system (38) may include hybrids of hardware and software, as well as computer sub-systems.

Hardware may include at least processor-capable platforms, such as client-machines (also known as personal computers or servers), and hand-held processing devices (such as smart phones, personal digital assistants (PDAs), or personal computing devices (PCDs), for example). Further, hardware may include any physical device that is capable of storing machine-readable instructions, such as memory or other data storage devices. Other forms of hardware include hardware sub-systems, including transfer devices such as modems, modem cards, ports, and port cards, for example.

Software includes any machine code stored in any memory medium, such as RAM or ROM, and machine code stored on other devices (such as floppy disks, flash memory, or a CD ROM, for example). Software may include source or object code, for example. In addition, software encompasses any set of instructions capable of being executed in a client machine or server.

A database may be any standard or proprietary database software, such as Oracle, Microsoft Access, SyBase, or DBase II, for example. The database may have fields, records, data, and other database elements that may be associated through database specific software. Additionally, data may be mapped. Mapping is the process of associating one data entry with another data entry. For example, the data contained in the location of a character file can be mapped to a field in a second table. The physical location of the database is not limiting, and the database may be distributed. For example, the database may exist remotely from the server, and run on a separate platform.

Further, the computer system may operate in a networked environment using logical connections to one or more remote computers. The logical connections may be any connection that is commonplace in offices, enterprise-wide computer networks, intranets, and the Internet, such as local area network (LAN) and a wide area network (WAN). The remote computers may each include one or more application programs.

When using a LAN networking environment, the computer system may be connected to the local network through a network interface or adapter. When used in a WAN networking environment, the computer system may include a modem, wireless router or other means for establishing communication over a wide area network, such as the Internet.

The modem, which may be internal or external, may be connected to the system bus via the serial port interface. In a networked environment, program modules depicted relative to the computer system, or portions thereof, may be stored in a remote memory storage device.

Although the invention has been described with reference to specific embodiments, this description is not meant to be construed in a limited sense. Various modifications of the disclosed embodiments, as well as alternative embodiments of the invention, will become apparent to persons skilled in the art upon reference to the description of the invention. It is, therefore, contemplated that the appended claims will cover such modifications that fall within the scope of the invention.

Claims

1. A computer implemented method of controlling a hydrocarbon recovery operation comprising:

receiving temperature data pertaining to a well pair comprising an injection well and a production well;

utilizing the temperature data, determining a temperature difference between a first section of the well pair and a second section of the well pair;

generating an error term expressing the difference between the determined temperature difference and a target temperature difference;

incorporating the error term into a control function having one or more control variables; and

using one or more Proportional Integral Derivative (PID) controllers associated with the injection well, controlling the injection of stimulating fluid into the injection well utilizing one or more of the control variables.

2. The computer implemented method of claim 1, wherein the first section of the well pair is located inside the injection well and the second section of the well pair is located inside the production well.

3. The computer implemented method of claim 1, wherein the injection well further comprises a plurality of injection tubing strings and wherein the position of at least one of the injection tubing strings within the injection well is moved based upon one or more of the control variables.

4. The computer implemented method of claim 1, wherein the production well further comprises a plurality of inflow control devices (ICDs) operative to control the flow of production fluids into the production well.

5. The computer implemented method of claim 4, wherein the operation of one or more of the ICDs is controlled by a PID controller associated with a first production tubing string of the production well.

6. The computer implemented method of claim 5, wherein the control variables further comprise a time constant and wherein the time constant utilized by the PID controller in the first production tubing string is greater than the time constant utilized by the PID controllers associated with the injection well.

7. The computer implemented method of claim 5, wherein the control variables further comprise a proportionality constant and wherein the proportionality constant utilized by the PID controller in the first production tubing string is less than the proportionality constant utilized by the PID controllers associated with the injection well.

8. The computer implemented method of claim 1, wherein the target temperature difference is between 2° C. and 5° C.

9. The computer implemented method of claim 1, further comprising:

excluding temperature data from the error term when the temperature data is below a threshold value.

10. The computer implemented method of claim 1, wherein an average temperature is used to determine the temperature difference between the first section of the well pair and the second section of the well pair.

11. The computer implemented method of claim 1, wherein the temperature data is obtained using an array of temperature sensors or a fiber optic distributed temperature sensor.

12. The computer implemented method of claim 1, wherein the stimulating fluid comprises saturated steam.

13. A hydrocarbon recovery control system comprising:

an injection well and a production well that traverse a subterranean formation, wherein the injection well is positioned in the formation above and generally parallel to the production well;

wherein the injection well comprises a plurality of injection tubing strings operative to supply stimulating fluid to at least a portion of the injection well and wherein the production well comprises at least one production tubing string operative to collect production fluids from the production well and transport them to the surface; and

a controller for regulating the injection rate of stimulating fluid for each injection tubing string; wherein the operation of each controller is governed by a control function utilizing an error term representing the difference between a measured interwell subcool temperature and a target interwell subcool temperature.

14. The system of claim 13, wherein the measured interwell subcool temperature is determined using a plurality of temperature measurements obtained using an array of temperature sensors or a fiber optic distributed temperature sensor disposed within the production well.

15. The system of claim 13, wherein at least a portion of the injection well extends generally in a horizontal direction, and at least a portion of the production well extends in an inclined manner under the injection well.

16. The system of claim 13, wherein the production well further comprises a plurality of inflow control devices (ICDs) operative to control the flow of production fluids into the production well.

17. A computer-readable storage medium for controlling a hydrocarbon recovery operation comprising instructions which, when executed, cause a computing device to:

determine a temperature difference between a section of an injection well and a section of a production well;

generate an error term expressing the difference between the determined temperature difference and a target temperature difference;

incorporate the error term into a control function having one or more control variables; and

using one or more Proportional Integral Derivative (PID) controllers associated with the injection well, controlling the injection of stimulation fluid into the injection well utilizing one or more of the control variables.

18. The computer-readable storage medium of claim 17, wherein the stimulating fluid comprises saturated steam.

19. The computer-readable storage medium of claim 17, wherein the injection well further comprises a first injection tubing string terminating in a heel portion of the injection well and a second injection tubing string terminating in a toe portion of the injection well.

20. The computer-readable storage medium of claim 17, wherein the hydrocarbon recovery operation is a Steam Assisted Gravity Drainage (SAGD) operation.