Patent Publication Number: US-2011067882-A1

Title: System and Method for Monitoring and Controlling Wellbore Parameters

Description:
BACKGROUND OF THE DISCLOSURE 
     1. Field of the Disclosure 
     This disclosure relates generally to well design, modeling well performance and well monitoring. 
     2. Background of the Art 
     Wellbores are drilled in subsurface formations for the production of hydrocarbons (oil and gas). Some such wells are vertical or near vertical wells that penetrate more than one reservoir or production zone. Inclined and horizontal wells are also now common, wherein the well traverses the production zone (or reservoir) substantially horizontally, i.e., substantially along the length of the reservoir. Many wells produce hydrocarbons from multiple production zones. In flow control valves are installed in the well to control the flow of the fluid from each production zone. In such multi-zone wells (production wells or injection wells) fluid from different production zones is commingled at one or more points in the well fluid flow path. The commingled fluid flows to the surface wellhead via a tubing. The flow of the fluids to the surface depends upon: properties or characteristics of the formation (such as permeability, formation pressure and temperature, etc.); fluid flow path configurations and equipment therein (such as tubing size, annulus used for flowing the fluid, gravel pack, chokes and valves, temperature and pressure profiles in the wellbore, etc.). It is desirable to monitor production parameters and control production from each zone and through the various devices in the well to maintain the production at desired levels and to shut down or reduce flow from selected zones when an adverse condition, such as water breakthrough, occurs in the well. The disclosure herein provides an improved method and system for monitoring and controlling production from wellbores. 
     SUMMARY OF THE DISCLOSURE 
     In one aspect, a method is provided for producing fluid from a well formed in a formation including the step of generating a visual display depicting a depth-based layout of a plurality of production devices, a first setting of each production device and values for at least one production parameter, wherein the visual display enables an operator to graphically input a desired value for the at least one production parameter at a selected depth of the well. The method also includes determining a second setting for at least one production device utilizing a model and the desired value, wherein the second setting is expected to provide the desired value for the at least one production parameter the second setting is implemented. 
     In one aspect, an apparatus is provided that is for use in producing a fluid from a formation, where the apparatus includes a data storage device configured to store well data, including information about settings of a plurality of production devices corresponding to depth of the production devices in a well and at least one production parameter and a model that utilizes the well data. The apparatus further includes a processor configured to generate a well display depicting status of the production devices corresponding to their respective depths in the wellbore and values of the at least one production parameter corresponding to the well display, wherein the well display enables an operator to graphically input a desired value for the at least one production parameter at a selected depth in the well. The processor is also configured to process the desired value using the model to determine a new setting of at least one production device in the plurality of production devices which setting of the at least one production device, when implemented, is expected to provide the desired value of the at least one production parameter. 
     Examples of the more important features of the apparatus and method have been summarized rather broadly in order that the detailed description thereof that follows may be better understood, and in order that the contributions to the art may be appreciated. There are, of course, additional features that will be described hereinafter and which will form the subject of the claims. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a detailed understanding of the system and methods for monitoring and controlling production wells described and claimed herein, reference should be made to the accompanying drawings and the following detailed description of the drawings wherein like elements generally have been given like numerals, and wherein: 
         FIG. 1  is a schematic diagram of an exemplary multi-zone production well system configured to monitor and control production of fluid from the wellbore, according to one embodiment; 
         FIG. 2  is a schematic diagram showing exemplary equipment used to produce fluid from the wellbore, according to one embodiment; 
         FIG. 3  is a diagram of a user interface of a program to monitor and control fluid production in a wellbore, according to one embodiment; 
         FIG. 4  is a flow chart showing a process and system for monitoring and controlling fluid production in a wellbore, according to one embodiment; 
         FIG. 5  is a schematic block diagram of components of a wellbore monitoring and control system, according to one embodiment; 
         FIG. 6  is a diagram of a user interface showing available control devices and their settings in a wellbore, according to one embodiment; 
         FIG. 7  is a diagram of a user interface of a program to control production equipment using a script communicated from a remote location to a wellsite, according to one embodiment; and 
         FIG. 8  is a diagram of a user interface of a program to control production equipment using a plurality of pre-configured scripts, according to one embodiment. 
     
    
    
     DETAILED DESCRIPTION OF THE DRAWINGS 
       FIG. 1  is a schematic diagram of an exemplary multi-zone production wellbore system  100 . The system  100  is shown to include a wellbore  160  drilled in a formation  155  that produces formation fluid  156   a  and  156   b  from exemplary production zones  152   a  (upper production zone or reservoir) and  152   b  (lower production zone or reservoir) respectively. The wellbore  160  is shown lined with a casing  157  containing perforations  154   a  adjacent the upper production zone  152   a  and perforations  154   b  adjacent the lower production zone  152   b . A packer  164 , which may be a retrievable packer, positioned above or uphole of the lower production zone perforations  154   a  isolates fluid flowing from the lower production zone  152   b  from the fluid flowing from the upper production zone  152   a . A sand screen  159   b  adjacent the perforations  154   b  may be installed to prevent or inhibit solids, such as sand, from entering into the wellbore  160  from the lower production zone  154   b . Similarly, a sand screen  159   a  may be used adjacent the upper production zone perforations  159   a  to prevent or inhibit solids from entering into the well  150  from the upper production zone  152   a.    
     The formation fluid  156   b  from the lower production zone  152   b  enters the annulus  151   a  of the wellbore  160  through the perforations  154   b  and into a tubing  153  via a flow control device  167 . The flow control device  167  (or flow device) may be a remotely-controlled sliding sleeve valve or any other suitable valve or choke configured to regulate the flow of the fluid from the annulus  151   a  into the production tubing  153 . The formation fluid  156   a  from the upper production zone  152   a  enters the annulus  151   b  (the annulus above the packer  164 ) via perforations  154   a . The formation fluid  156   a  enters into the tubing  153  at a location  170 , referred to herein as the commingle point. The fluids  156   a  and  156   b  commingle at the commingle point. An adjustable fluid flow control device  144  (upper control valve) associated with the tubing  153  above the commingle point  170  may be used to regulate the fluid flow from the commingle point  170  to a wellhead  150 . A packer  165  above the commingle point  170  prevents the fluid in the annulus  151   b  from flowing to the surface. The wellhead  150  at the surface controls the pressure of the outgoing fluid at a desired level. Various sensors  145  may be deployed in the system  100  for providing information about a number of downhole parameters of interest. 
     In addition, a well site control unit  146  may be utilized to control fluid flow and log data acquired from sensors  145  within the wellbore  160  and sensors  175  at the surface. For example, the well site control unit  146  may include one or more processors, programs and software to acquire and log production parameters data and also to control the state of flow devices, such as upper control valve  144  and flow control device  167 . The well site control unit  146  may also include memory, an operating system, and other hardware and software configured to execute instructions contained in the program(s) to monitor and control various devices of the system  100 . The well site control unit  146  may be located at the surface or a remote location and may be configured to control treatment control unit  172  for injecting additives or chemicals in the well  160  at selected location and a device control unit  174  to set the devices in the well at desired settings. The device control unit  174  may communicate with and control the flow control devices downhole, including sensors, valves, sliding sleeves, and chokes. The device control unit  174  may use wireless, wired, or other signals to communicate with and control the plurality of downhole devices, as shown by line  147 . In an aspect, the treatment control unit  172  may include a storage tank for housing treatment chemicals as well as various fluid control and communication lines. In an aspect, a variety of fluid ( 149 ) communication lines are run in the wellbore to injected fluids into the wellbore. Also, a variety of electrical and data ( 147 ) communication lines are run inside the wellbore  160  to control the various devices in the well system  100  and to obtain measurements and other data from the various sensors in the wellbore  160 . As an example, the fluid communication line  149  may supply a selected chemical from the treatment control equipment  172  that is injected into the upper production zone  156   a  to improve production fluid flow from the formation  155 . Similarly, the data communication line  147  may operate flow devices while controlling and receiving data from wellbore sensors. In addition, the data communication line  147  may provide electrical power to certain devices downhole from a suitable surface power source. 
     As will be discussed in detail below, in an aspect, the well site control unit  146  is configured to enable an operator to graphically observe the current conditions of the well system  100  based on the sensor measure measurements and/or information received from a remote unit  176 . The remote unit  176  may include a controller and programs that enable an operator to communicate, control and monitor information via links  178  to the well site controller  146 . The communication links  178  may utilize any suitable reliable and robust data transmission technique, such as radio frequency (RF) signal communication, networks (the internet, cell phone, wi-fi, etc.) or cabled communication (Ethernet, serial links, etc.). In general, controllers, such as well site controller  146  and remote controller  176 , may include one or more processors, suitable memory devices, programs, and associated circuitry that are configured to perform various functions and methods described herein. Although only two flow control devices are shown in  FIG. 1 , the wellbore system may include multiple flow control and other devices along the length of the well  160  as discussed below in reference to  FIG. 2 . 
     As discussed in more detail below, the well site controller  146  enables the operator to manipulate the displayed information and data to adjust the levels of one or more parameters to a desired level, resulting in a set of instructions to achieve the desired result (value or level). In one aspect, the user interface enables an operator to implement a system change using an input in a graphical form. In other embodiments, system changes may be may be made using a relatively complex procedure that includes managing numerous devices, settings, inputs, and the corresponding sequence of events within a wellbore fluid production system. 
       FIG. 2  is a schematic diagram of a well system  200  including a well  202  configured to control and monitor production of fluid from a formation  203 . The well  202  includes flow devices  204   a - n , which may be placed at various locations (or depths) within the well  202  to control flow of formation fluid at each location. The flow devices  204   a - n  may each have an associated sensor  206   a - n , which are configured to measure parameters at each position. As discussed herein, the system  200  includes a plurality of flow devices ( 204 ) and sensors ( 206 ), wherein the total number of devices is represented by “n” and each device/sensor is denoted by the associated letter in the diagram (a, b, c, etc.) As depicted, each associated letter in the diagram may correspond to a position within the well  202 . Further, each flow device  204   a - n  may include one or more mechanisms to control and/or effect fluid flow, such as a choke or valve. The flow devices  204   a - n  may also include systems to provide chemical treatment and/or injections to locations within the well  202 , to improve fluid flow and extraction. Similarly, each sensor  206   a - n  may include one or more sensors to monitor one or more parameters, including, but not limited to, flow rate, pressure, temperature, water cut, fluid composition (oil, gas and water) porosity, permeability, resistivity, and skin factor.  FIG. 2  is an exemplary schematic representations of a certain number of devices and sensors in the well, however, actual applications may include a large number of devices and sensors located throughout the well  202 . For example, a system with a wellbore that is over 6000 feet deep may include several thousand flow devices and sensors. 
     As depicted in  FIG. 2 , the formation  203  may include one or more perforations  208 , which produce formation fluid within the well  202 . A plurality of perforations  208  are located in a first production zone  210  and a second production zone  212 . Each of the production zones  210  and  212  may have one or more flow devices  204   a - n  positioned near the production zones to control a flow of formation fluid from the perforations  208  into the wellbore  200 . In addition, one or more sensors  206   a - n  may also be positioned to monitor parameters within the production zones  210  and  212 . As discussed below with reference to  FIGS. 3-5 , the system  200  may interface with a controller, such as well site controller  146  to enable an operator to monitor and control a production fluid flow  214  in the well  202 . 
     As illustrated in  FIG. 2 , the fluid flow  214  may be a combination of fluid flows from the plurality of flow devices  204   a - n  and production zones ( 210 ,  212 ) in the wellbore, wherein each flow device is controlled to produce the desired fluid flow  214  output. A production tubular 216 routes the production fluid flow  214  to a wellhead (not shown) for analysis and treatment. In an aspect, the production fluid is analyzed (e.g. for composition, temperature, flow rates, etc.) at the surface to provide an operator and/or program with more information about the production fluid downhole. 
     In general, sufficient devices and sensors may be suitably placed in the well  202  to obtain measurements relating to each desired parameter of interest. Such sensors may include, but are not limited to, sensors for measuring pressures corresponding to each production zone, pressure along the wellbore, pressure inside the tubing carrying the formation fluid, pressure in the annulus, temperatures at selected places along the wellbore, fluid flow rates corresponding to each of the production zones, total flow rate, flow through an electric submersible pump (ESP), ESP temperature and pressure, chemical sensors, acoustic or seismic sensors, optical sensors, etc. The sensors may be of any suitable type, including electrical sensors, mechanical sensors, piezoelectric sensors, fiber optic sensors, optical sensors, etc. The signals from the downhole sensors may be partially or fully processed downhole (such as by a microprocessor and associated electronic circuitry that is in signal or data communication with the downhole sensors and devices) and communicated to the surface controller via a signal/data link. The signals from downhole sensors may be sent directly to the controller as described in more detail herein. 
       FIG. 3  is an illustration of a user interface  300  that displays information relating to the extraction and flow of production fluid from the wellbore. In one aspect, the user interface  300  may be a computer display and associated program which acquires and presents the system status/control information, production parameters, formation parameters, and other system information. As depicted, the user interface  300  includes an upper chart  301  that includes data plots of measured parameters, such as flow rate  302  and pressure  304 . In chart  301  measured values and data are shown along the y-axis  306  and the depth along the x-axis  308 , where the data is plotted against the effective depth or location within the wellbore at a selected time. In an aspect, the data measured by the downhole sensors (as previously discussed with reference to  FIG. 2 ) is positioned at various locations in the wellbore to measure production and formation parameters. 
     The upper chart  301  also includes a status indicator  310 , which shows graphical representation of the status or setting of each device in the well corresponding to its depth along the x-axis  308 . A legend  312  may also be included to define each of the status indicator  310  symbols. For example, the status indicator  310  may show the status of each of the flow control devices ( 204  in  FIG. 2 ) at various positions within the wellbore. As depicted, the status indicator  310  graphically shows that the F 2  flow device is open while the F 3  flow device is closed and the F 5  flow device is partially open. Referencing the x-axis  308 , as well as  FIG. 2 , the F 2  flow device is located at a greater depth than the F 3  flow device. Moreover, the upper chart  301  displays the measured parameters ( 302 ,  304 ) that correspond to the location (depth  308 ) and status ( 310 ) of each flow device. The upper chart  301  also includes data for formation parameters, such as permeability  314  and porosity  316 , which are also plotted against depth of the well. As discussed below with reference to  FIGS. 4 and 5 , the user interface  300  may enable an operator to graphically input desired values for one or more parameters so that the system computers and programs automatically generate new settings for the downhole devices that, when implemented, will or likely will provide the desired result. 
     The user interface  300  also is shown to include a lower chart  318 , which may show additional parameters and information pertaining to the well and production fluid. As depicted, the lower chart  318  plots measured data  320  (y-axis) over time  322  (x-axis). The chart  318  includes flow rate  324  and permeability  326  plotted over time, where the data is taken at a selected position (e.g. S 3 ) within the well and logged over time. 
       FIG. 4  is a functional diagram of a process and system  400  for monitoring and controlling the flow of production fluid from a well. The system  400  includes the upper chart (or display)  301  of the user interface ( 300 ,  FIG. 3 ) which has a control cursor  401  that is configured to enable an operator to graphically manipulate the plots of data. In an embodiment, the control cursor  401  may be used to set a flow rate  302  by dragging an existing plot line  402  to a desired value  404  for the flow rate. The desired value  404  is graphically input by moving or dragging ( 408 ) the control cursor  401  to a second location  406 , thereby indicating the desired flow rate ( 404 ) at that well depth. The control cursor  401  may be any suitable computer pointing device, which may be controlled by any suitable method, including, but not limited to, a keyboard, mouse and a touch screen monitor. As shown, the control cursor  401  may drag  408  a data plot  402 , based on the operator&#39;s movement of the pointing device. As described herein, a graphical element is one that may use diagrams, graphs, mathematical curves, visual representations, displays or the like to input and/or illustrate information. 
     The user interface  300  ( FIG. 3 ) may transmit or communicate the desired value  404  to an analysis unit  410  that may include a computer or processor  409  that has access to a simulation software  411  that includes programs, algorithms and data relating to the well, current settings of devices, sensor measurements, historical data, well parameters, etc. (collectively denoted by numeral  410 ). The computer  409  analyzes and processes the inputs from the operator (e.g. graphically input desired settings) utilizing the information and simulation software  411  to determine the wellbore equipment settings and conditions, which settings when implemented are likely to attain or provide the desired results for the value  404  and other flow rates as shown by curves  302  and  404 . The simulation software  411  may utilize a mathematical model, algorithms, simulation methods (iterative, non-iterative, curve fitting techniques) to determine the instructions and settings, that when implemented, will or likely will provide the desired value (or result)  404 . For example, the simulation software  411  may process a plurality of inputs, including measured, calculated, operator, and controlled inputs (e.g. equipment status/settings), to calculate the changes needed for the downhole equipment to attain the desired value  404 . Further, the software model of the system  400  may be continuously refined and updated by utilizing logged data and other system information. In an aspect, the software model utilizes one of: a simulation; an iterative process; a nodal analysis to determine settings for the system  400 . 
     As shown in  FIG. 4 , the computer  409  utilizing the simulation software  411 , may generate one or more settings and/or instructions  412  to attain the desired value  404 . As an example, the instructions  412  provided by the computer may include commands: “1) Open flow device #7; 2) Choke device #8; 3) open device #9; and 4) close device #10 and further the actual setting values for each such device. In another example, the instructions  412  could include commands and settings including choking flow devices F 2  and F 4  to achieve the desired value  404  for flow rate. Further, the simulation software  411  may also determine that injecting an additive (chemical or another material) at F 3  location will aid in attaining the desired value  404 . In one aspect, the desired value  404  may not be possible to attain. For example, a user may input a desired value  404  that cannot be produced with the equipment in the system and the current system parameters. Accordingly, the program may instruct the user why the desired value  404  is impossible to attain and provide the user with instructions and a predicted output that is as close as possible to the desired value  404 . In some cases, the instructions  412  may be a sequence of commands and settings that may include a relatively large number of entries that an operator at the well site is expected to initiate to achieve the desired result  404 . 
     The instructions  412  may be communicated via e-mail, text, intranet/internet web page, voice message, or other suitable message to an operator  414 , such as a reservoir engineer. In a manual process for managing the wellbore equipment, the operator  414  may be given the option to approve, deny or delay the implementation of the proposed instructions  412 . If approved by the operator  414 , the instructions  412  are entered manually into the well site control unit  146  ( FIG. 1 ) (Block  416 ) resulting in one or more altered settings for the wellbore equipment. Manual entry of instructions at the well site can be time consuming and result in errors. Accordingly, the system  400  may be configured to execute the instructions automatically. In one embodiment, with an automated process, the control unit  410  may be configured to send such instructions (Block  418 ) to the well site controller ( 146  of  FIG. 1 ). The controller  146  may receive the instructions and apply new equipment settings automatically (Block  420 ). After applying the new equipment settings (step  416  or  420 ), the instructions and equipment settings are communicated via feedback loop  422  to the control unit  410 . The control unit also may be provided with the measured values after the new setting to update the system programs and information  414 . 
     In another aspect, the analysis unit  410  may be configured to generate a script file (also referred to herein as “macro” or “macro file”)  424 . In one aspect, a script file may include all proposed setting that may be implemented by an operator using a single command or automatically by the well site control unit. In another aspect, a script file may include a sequence of commands, which may be timed, where delays may be implemented between commands. As depicted, the script file may be submitted to the operator  414  for review and approval. In another aspect, the script file may be a set of instructions and settings that enable the operator to review the sequence of commands and implement the script with a simple start command. Further, the operator may be restricted from editing the script file, thereby preventing implementation errors. The operator, however, may be given the option to approve, deny or delay the implementation of the script file. In another aspect, the script file generated at Block  424  may be sent to the well site controller  418  to execute the script file automatically. Such a method is useful when well site personnel are not available to review the instructions or the well site personnel may lack the expertise to review and implement the instructions, which is often the case in remotely located well sites. In other aspects, the controller may generate a plurality of script files from the model and operator input, wherein each of the script files may correspond to a particular time or condition at the rig site. In such a case, the rig site personnel may select the appropriate script file for the conditions and time. 
       FIG. 5  is a schematic diagram of a wellbore monitoring and control system  500 . The system  500 , in aspects, may include a simulation software or model  411 , which may include one or more models composed of one or more simulation and analysis programs which may include commands, code, functions, and algorithms embedded in one or more computer-readable media accessible to one or more computer processors  506  that executes instructions contained in the programs  516  perform the methods described herein. The program  411  may utilize inputs from a variety of sources, including, but not limited to, formation parameters  508 , wellbore completion parameters  510 , downhole production parameters  512 , surface parameters  509 , and information from other sources and programs  513 . The formation parameters  508  may include, but are not limited to, porosity, permeability, resistivity and skin factor. Well completion parameters  510  may include, but are not limited to, information about the various flow and other devices in the well (such as available settings for each device and current settings of such devices) and chemical treatment information. Downhole production parameters  512 , acquired from wellbore sensors, by calculation or from another sources, may include, but are not limited to, water cut, pressure, flow rate (volume or mass), temperature, corrosion, asphaltene, composition of production fluid and other parameters. 
     In aspects, the processor  506  may utilize the inputs, including the settings, to update the simulation program. As previously discussed with reference to  FIG. 4 , an operator may graphically input the desired values or changes, as shown by input  514 . In one exemplary embodiment, the simulation and analysis program  504  may be stored in any suitable machine readable medium. The processor  514  also has access to programmed instructions  516 , which may include operating systems, other application programs and hardware/firmware management services. The programmed instructions  516  manage system resources, including memory and processors, and may enable communication of data, inputs, and commands between the user inputs  514 , programs  411 ), memory and programs  516 . The processor  506  may utilize programs or algorithms, including the simulation and analysis program  411  to process the desired values  514  and generate the instructions  518  to achieve the desired values  514 . The instructions  518  may be communicated to an operator for approval and implementation  520  or may be executed directly by a rig site controller in an automated system. Further, if the operator is given permission to edit the instructions, the operator may modify the instructions as shown by block  520 . 
     In one aspect, the programs  411  may be in the form of a well performance analyzer (WPA), which is a program that is used by the processor  506  to analyze some or all of the formation parameters  508 , wellbore completion parameters  510 , downhole production parameters  512 , desired values from an operator  514 , logged information in a database, and any other desired information made available to the processor  506  to determine the set of instructions to be applied, monitor the effects of the actions taken and perform an analysis. The well performance analyzer may use a forward looking model that may be utilize a nodal analysis, a neural network, an iterative process or another algorithm to generate the instructions. The controller  506  may update such models based on the measured data and results of the implemented instructions. 
     The well performance analyzer may utilize current measurements of pressure, flow rates, temperature, historical, laboratory or other synthetic data to establish a model of the wellbore and the wellbore equipment. The models may utilize or take into account any number of factors, such as the: amount or percent of pressure in the wellbore that is above the formation pressure and the length of time for which such a pressure condition has been present; rate of change of the pressures; actual pressure values; difference between the pressures; actual temperatures of the upper and lower production zones; difference in the temperatures between the upper and lower production zones; annulus (upper zone) being greater than the pressure in the tubing (lower zone) while the lower zone is open for producing fluids; flow measurements from each of the production zones; a fluid flow downhole approaching a cross flow condition; and other desired factors. The programs may also generate inferred parameters, which may be calculated based on related actual measurements, logged data, and algorithms. For example, referring to the system of  FIG. 2 , a sensor  206  may include a temperature and flow rate sensor, to save system costs. Accordingly, a system controller may calculate other parameters, such as temperature, based on these measurements. Another example may be a water production parameter that is calculated based on other inputs. The water production parameter may be another input to the programs  411 , wherein the calculated water production parameter is a curve used to predict water flow into the well. The water production curve may be an input that helps prevent excessive water inflow (“water breakthrough”), which can be detrimental to the operation of the well. The system  500  may use the water production parameter to configure instructions that prevent unwanted water inflow for the well. 
       FIG. 6  is an illustration of a user interface  600  that may be used to manually control one or more wellbore devices. The user interface  600  may be a part of a computer program that utilizes hardware and software to communicate information with and to control wellbore devices, such as valves, chokes, sliding sleeves, and fluid injection devices. An operator may operate the user interface  600  to view and manually configure settings for a plurality of devices in a wellbore. In an aspect, a first set of controls  602  and a second set of controls  612  may be used to individually set a state for each device. A device label ( 604 ,  608 ,  614 ) and status selector ( 606 ,  610 ,  616 ) correspond to the wellbore device and state for each device, respectively. 
     The operator may use the user interface  600  to a view a current state for each device, which may be displayed by the selector ( 606 ,  610 ,  616 ). Referring also to  FIG. 4 , the operator ( 414 ) may receive instructions ( 412 ) to change the device settings by selecting a state ( 606 ,  610 ,  616 ) for each device, wherein the user interface  600  ( FIG. 6 ) runs on a computer ( 416 ) to apply the desired changes in the settings. Referring to  FIG. 6 , in an aspect, label  604  enables an operator to select “State  1 ” ( 606 ) for “Device  1 .” Further, a label  608  enables an operator to select “State  5 ” ( 610 ) for “Device  2 .” The selectors  606  and  610  enable different state choices for an operator, depending on the device the label corresponds to. For example, a sliding sleeve may provide more state choices for the corresponding selector ( 606 ,  610 ,  616 ) than a traditional valve would. As depicted, the operator may select one of five states (1-5) that correspond to a particular setting for each device. In an aspect, the “State  1 ” selector status may correspond to any suitable operating state for each device, such as open, choked, or closed. 
     The user interface  600  may also have a set of operation buttons  617 . The operation buttons  617  may enable a user to perform actions pertaining the plurality of equipment settings selected in control sets  602  and  612 . For instance, the operator may select to execute the setting changes by pressing or selecting an execute button  618 . Alternatively, the operator may cancel the proposed setting changes by selecting a cancel button  620 . In another embodiment, various other buttons, such as delay or review, may be included in operation buttons ( 617 ). In addition, more controls and corresponding labels may be included to enable additional modifications by the operator to the equipment settings. In the manual operation of  FIG. 6 , when an operator implements a set of settings for a desired task, such as production from only a selected zone, the number of settings and number of devices may lead to operator errors. In addition, specific tasks may include instructions incorporating delays between implementing various device settings, further complicating the process and increases incidence of error. The user interface  600  may require a plurality individual settings for each device for a simple task, such as maintenance. Accordingly, the operator may spend a significant amount of time performing the input changes for the task. 
       FIG. 7  is a diagram of user interfaces  700  and  702  of a program which enables an operator or automated program at a remote location to transmit a script or macro to a well site operator. The script may be a file generated by a software program. The script may include a list and/or sequence of settings, commands, and other instructions for the wellbore equipment. The user interface  702  enables the rig site operator to receive the script file transmitted from a portable memory device, such as a universal serial bus (USB) device. In an aspect, a remotely-located engineer may use a software program, a wellbore model, and an associated computer to generate the script file which, when implemented, will provide a desired level for one or more parameters relating to the wellbore production. The user interface  700  enables the operator to receive the script file from a remote central office, via a network transmission, radio signal, or other suitable communication method. An operator may use interface  700  to view or apply a script file that has been emailed or placed on a network drive that is accessible to the well site and remote office. A controller computer may be configured to detect that a script file has been received from the USB device or via the network. The controller may then provide the operator with the appropriate interface and options. For the purposes of this embodiment, each of the interfaces includes the same command buttons. In other embodiments, the controller may provide different options for an operator based on the source of the script or other inputs. 
     As depicted, the user interfaces  700 ,  702  include a plurality of operation buttons  706  to locally control implementation of the script. The operation buttons may include a review changes button  704 , accept button  710 , reject button  712 , delay button  714 , and cancel button  716 . The operator may review the settings and instructions in the script file by selecting the review changes button  704 . The operator may initiate the instructions in the script file by selecting the accept button  710  and may reject the proposed changes by selecting reject  712 . In addition, the operator may select delay  714  if maintenance needs to be finished or the operator has questions for the remote office before applying the proposed changes. In an aspect, the script file and user interface  700 ,  702  restrict the operator&#39;s options after presentation of the script file from the remote office, thereby reducing errors from implementation and communication of the instructions. For example, the operator may be restricted from editing the script file and may only be presented with the review ( 704 ), accept ( 710 ), reject ( 712 ), and delay ( 714 ) options, as illustrated. 
       FIG. 8  is an illustration of a user interface  800  that enables an operator to select from a plurality of pre-configured scripts that correspond to a system state. In one aspect, the pre-configured scripts may be pre-loaded onto a rig site controller before the controller is installed at a remotely located rig site, wherein the plurality of scripts are customized to control the wellbore equipment included at the site. The pre-configured scripts may be utilized in situations in which personnel and communication devices at the rig site cannot reliably or consistently communicate with remote central offices. The rig site&#39;s remote location may prevent transmission of a script via network or USB, as discussed with reference to  FIG. 7 . In these situations, a set of pre-configured scripts tailored to the application and wellbore equipment may be used to prevent production errors at the rig site. 
     The user interface  800  includes buttons corresponding to a plurality of scripts, including scripts for Alfa  802 , Bravo  804 , Charlie  806 , Delta  808 , Echo  810 , and Foxtrot  812  strategies. The operator may base selection of a pre-configured script based on certain situations and/or time schedules. For example, an operator may select the script for “Strategy Alfa”  802  based on surface measurements of production fluid, including water cut and other fluid composition information. Further, the operator may select the script for “Strategy Bravo”  804  based on a pre-determined timeline, wherein the script is configured to be executed six months after wellbore production begins. In addition, the scripts may also be configured to perform a test or maintenance routine for the wellbore equipment. In an aspect, the scripts may also correspond to strategies for production from only selected zones in the wellbore, such as lower zones ( 806 ) or upper zones ( 808 ). The user interface  800  may also include a plurality of operation buttons  814 , including a review changes button  816 , accept button  818 , and cancel button  824 . As discussed above, the operation buttons enable an operator to review the script contents, accept the script, reject the script, delay implementation, or cancel the user interface. 
     As described herein, the scripts (or macros) include a series or sequence of settings and commands to control wellbore equipment. The wellbore equipment settings may be complex. The scripts discussed above prevent errors that may otherwise occur during implementation and communication of the settings and commands. In addition, the scripts enable a skilled off-site engineer to generate a list of commands, enabling the rig-site operator to concentrate on maintenance and operational tasks. The incidence of errors is also reduced by preventing operators from editing the scripts developed by experienced engineers. The scripts may be configured to perform various operations and functions, including tests, maintenance, and production from selected zones in the wellbore. The scripts are a series of instructions in a declarative format that contain metadata to allow a program to verify the authenticity of the generator of the script. The processor used to generate the script and/or instruction file may be located at the wellsite or at a centralized location remote from the wellsite. In an aspect, the script may be developed and executed on a controller or computer that includes a processor, memory, other programs, operating systems, and hardware/firmware management services. For example, the rig site controller  146  of  FIG. 1  may be used to run the user interfaces and scripts discussed in  FIGS. 6-8 . 
     Thus, in general, the system described herein may display all relevant equipment or device information overlaid with depth-based and/or time-based graphical visualization of static and/or dynamic data regarding the well and related equipment. The user may choose to enable or disable any information overlays. The user may select one or more metrics of the well operation and performance such as measures of the sensor and depth-based or time-based trends and alter by manipulating the graphic display of those metrics (such as by dragging up or down) to desired performance or operating levels. Depending on the well conditions or the algorithm used, the software can perform several functions, including, but not limited to: (i) analyze and compute the optional optimal equipment settings to achieve as close to the desired result as possible, (ii) cycle through permutations of valid equipment settings to provide settings that will most likely achieve the desired results; and use a genetic, evolutionary or forward looking algorithm or model to perform an iterative sequence of permutations of equipment settings to provide settings most likely to achieve the desired results, in view of the result of the previous configurations. 
     While the foregoing disclosure is directed to the certain exemplary embodiments and methods, various modifications will be apparent to those skilled in the art. It is intended that all modifications within the scope of the appended claims be embraced by the foregoing disclosure.