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Part 1: System Overview 1.1. System Design Description The development of an oil field automation information system primarily includes four components: remote monitoring of oil wells, an automated distribution line system, leakage detection in oil transport pipelines, and automated monitoring of collection and storage stations. The aim is to utilize on-site monitoring systems to enable automatic data collection at the source, and to load this data automatically into the plant-level real-time database using the existing network resources in the oil field. This provides an open data platform for use by management teams at all levels, allowing them to monitor and control production activities in a timely manner, thereby achieving automation of the entire production process； It is also possible to perform statistics, analysis, and optimization on the collected real-time data, thereby providing an important basis for ensuring the proper operation of production equipment and reducing production costs. Next, we will discuss the remote oil well monitoring system. 1.2. Review of the Current Situation Pilot projects for well monitoring have been carried out to varying degrees in oil production plants across the country. At present, a considerable number of manufacturers are involved, but their capabilities vary; all of them are conducting pilot projects, with a few having begun large-scale implementation. It also exposes many problems, mainly manifested in the poor reliability and maintainability of equipment at oil wells, as well as their inability to withstand the harsh working conditions at these sites (including high temperatures, low temperatures, humidity, and dust). The lack of data openness often results in incompatibility among different manufacturers, preventing the sharing of software data and creating isolated automated systems. Of the over a hundred thousand oil wells across the country, less than ten thousand are equipped with well monitoring systems, which represents less than 10% of the total. 1.3. Design Concept and Purpose: The remote well monitoring system primarily involves real-time detection of parameters at the wellhead. Using a polling-response communication method, the detected status of the well is transmitted wirelessly to the production plant’s real-time database server. Through C/S or B/S architectures, various departments responsible for production management can obtain timely information on the well’s operating status, thereby reducing the time required to address well failures, increasing the rate of well operation, boosting crude oil production, and enhancing work efficiency. In addition, the controller at the oil well head has a power calculation function, which can provide basic calculation data for the distribution automation system of 6kV power lines. Principle: Automation projects must be developed in accordance with the principles of \"unified planning, unified standards, and a unified database.\" System designs must take into account issues such as network communication and system security as a whole, ensuring that the standards for real-time databases are open, thereby granting the entire system extremely high reliability and practicality. System design follows the basic principles of \"practicality, openness, reliability, advancement, scalability, and maintainability\", with easy operation and reliable performance as its fundamental goals ； The plan design is based on reality to ensure ease of implementation, while also looking ahead to leave room for future development. Technical solutions generally employ new technologies, new equipment, and new systems that have been developed and improved in recent years; all of their hardware and software must have been tested in actual production environments and proven to be advanced and reliable. The entire oilfield automation system operates on a local area network; based on regional characteristics, a real-time data transmission and control center is established at each oil production plant (comprising communication processors, real-time database servers, and application servers). These centers are used for the centralized management and storage of real-time field data from the production wells, 6KV distribution lines, combined stations, and oil pipelines within each plant’s jurisdiction, adhering to the principle of an open real-time database. The overall system structure is as follows: Description of the solution: The wellhead controller collects parameters such as the well’s performance diagram, electrical power consumption, backpressure, and temperature. These data are transmitted via CDMA/GPRS networks or radio communication devices, either through dedicated CDMA/GPRS connections or via the RS232 interface of those devices, to the communication unit at the oil production facility as well as to the real-time database server. Computers in the facility’s teams can access the real-time database using a browser or a client application. The wellhead controller abandons the previous approach of only measuring the effective values of voltage and current, and instead collects and calculates electrical parameters of the motor in real time, thereby providing the data required by the distribution line automation system. Remote terminals for 6kV distribution lines, communication devices in oil production plants, real-time databases, SCADA application servers for distribution systems, workstations, etc., utilize CDMA/GPRS networks to form an automation system for distribution lines, enabling real-time monitoring and management of their operational status. Both the automation system for gathering and transporting oil at stations and warehouses, and the leak detection system for oil pipelines are relatively independent systems; the production data collected by these systems is uploaded to the refinery’s real-time database via a local area network, enabling data sharing over the network. Through the B/S mode, managers can view and query real-time data from the entire plant, enabling them to stay informed about production conditions on site in a timely manner. Production data can also be statistically analyzed through the C/S mode. To ensure clock consistency across the system, a dedicated GPS clock is installed to synchronize the system clocks throughout the network, including setting times in coordination with remote FTUs and SUs. Important nodes in the system, such as communication devices, real-time database servers, and application servers, are configured with dual-machine hot standby to maintain data consistency between the primary and backup machines, enabling them to switch roles promptly in the event of a failure. The data center features a dual-network redundant configuration and is isolated from the oil field LAN; in the event of a failure in the primary network, the backup network can take over immediately. Network security design: Technologies and methods such as firewalls, data encryption, network isolation, and user permission management are employed to ensure the security of networks and information. User permission management includes key tasks such as system user database management, user registration, user level setting, and user permission configuration. A virus prevention and control system has been established across the entire oil field network; therefore, virus prevention and control in this system is carried out in accordance with the unified standards of the oil field. 1.4. Remote well monitoring system: Based on the geographical distribution of oil wells and the level of development in wireless communication technology, the remote well monitoring system employs CDMA/GPRS or radio communication modes. The system consists mainly of sensors, a wellhead controller SU, a CDMA/GPRS (radio) communication module DTU, a communication device for the oil production facility, a real-time database server, a WEB server, and monitoring terminals. The system block diagram is as shown in the overall diagram above. The sensors and transmitters used to monitor the operating conditions of oil wells include temperature sensors and transmitters, pressure sensors and transmitters, current transformers, load sensors and transmitters for pumping units, displacement sensors and transmitters, as well as current transformers on the primary side of transformers. These devices convert the operating conditions of the oil well into corresponding voltage or current values, which are then sent to the wellhead controller SU. Then, via a CDMA/GPRS network or a digital radio, it is connected to the communication device at the oil production plant. The data communication device collects data from the wellhead controllers using a polling method; after analysis and processing, the data is fed into the real-time database of the oil production plant. The computers in factory and mine teams can access the real-time database in C/S or B/S mode, depending on their respective permissions. Functions implemented by the system: The electric pump well SU is primarily used for measuring parameters such as voltage, current, well backpressure, and wellhead temperature. The SU for pumpjack wells is primarily used for measuring parameters such as performance curves, voltage, current, well backpressure, and wellhead temperature, and it also retains the function of remotely starting and stopping the well. The wellhead controller has the capability to calculate parameters such as the motor’s active power, reactive power, power factor, and daily power consumption. Detection and alarm for abnormal conditions such as shutdown of submersible pump wells, overvoltage, undervoltage, overcurrent, underload, excessively high or low backpressure at the wellhead ； It detects and alerts for abnormal conditions such as pump well shutdown, overvoltage, undervoltage, overcurrent, underload, excessively high or low backpressure at the wellhead, and insufficient load. When power is supplied to the line, it is also reported as an abnormal condition. The monitoring unit of the oil production team can, in accordance with its authorized access rights, only query the operating status of the wells under its responsibility, real-time receipts, as well as the operating status of related communication modules and power distribution circuits. The performance diagrams and current diagrams (or power diagrams) of pumpjack wells are not only collected and saved at regular intervals, but the production team can also manually select the well number as needed, and retrieve the performance diagrams and current diagrams (or power diagrams) in real time, depending on the production conditions. When an overload shutdown occurs in an electric submersible pump well, the data on the three-phase currents (Ia, Ib, Ic) and line voltage (such as Uab) from the minute before the shutdown are uploaded to the database, providing analysis data for diagnosing pump failures. The monitoring system for oil production teams has functions such as viewing and editing static data: it includes information on pump models, motor types, well numbers, stroke length, line names, upper and lower range limits, upper and lower alarm limits, as well as the condition of each well. It also allows for adding new wells, deleting wells that are no longer in use, and modifying the basic data of operational wells. The system provides functions for monitoring real-time and historical trends of parameters such as indicator diagrams, current diagrams (or power diagrams), current, and voltage, enabling easy understanding of parameter changes over extended periods and facilitating rapid analysis. The system can consider integrating geographic graphics systems, allowing the graphics to reflect geographical information and providing a very intuitive representation of the operational status of the entire oil field. Oil production plants, mines, and related departments can use a browser to check the operating status and real-time data of wells within the plant, mine, or team, as well as information on wells that were shut down on that day, statistics on the startup rate, along with historical data and records. Data to be transmitted: The main data that needs to be uploaded from pump wells include load (maximum and minimum values), backpressure, wellhead temperature, currents (Ia, Ib, Ic) (maximum and minimum values), effective values of voltages (Ua, Ub, Uc), active power, reactive power, power factor, maximum current values during upward and downward strokes, power during those strokes, balance ratio, daily energy consumption, cumulative energy consumption, number of strokes, system status, and data on the timing of data collection. Piston diagram and current diagram (or power diagram) require all the measurements of load and current (or power) over one stroke; each diagram needs approximately 200 data points. Therefore, the total number of data points is approximately 430, of which 30 are basic data points. The data that needs to be uploaded from submersible pump wells includes: back pressure, wellhead temperature, current (Ia, Ib, Ic), voltage (Ua, Ub, Uc), active power, reactive power, power factor, daily electricity consumption, cumulative electricity consumption, system status, and data on the time of collection. The total amount of data is about 20 items. The oil well production monitoring system for the oil production team’s main station consists of five components: monitoring terminals installed on the oil wells, communication and data servers located at the oil production plant level, monitoring interfaces used by users such as the oil production team, a field communication system, and a management communication system. The system architecture is shown in the figure below: The oil well monitoring system software consists of communication software, data processing software, command processing software, alarm and event handling software, safety control software, graphical interface software, and graphic creation software. Communication software is primarily responsible for communicating with field devices through established communication protocols and interfaces, in order to retrieve data collected by those devices or send data and commands to them. Data processing software is primarily responsible for converting the raw data obtained by communication software according to the type of field acquisition points, determining whether alerts are needed, and managing data storage. Command processing software is primarily responsible for handling commands sent by users, converting these commands into control instructions for the communication server, and coordinating the interactions when multiple users send commands simultaneously. The alarm and event handling software is responsible for achieving the desired alarm effects, as well as recording and storing alarms and events. The security control software is responsible for managing the authentication and authorization information of system users, carrying out identity verification and permission checks on them. Graphical interface software and graphic creation software are used to generate and display user graphical interfaces. The basic processing flow of the system is as follows: The data from the oil wells is collected by the well terminals, which are equipped with communication modules; the data collected is then sent by these communication modules to the communication server located in the information center of the oil production facility. The processed data is stored in a real-time database. Oilfield users obtain system services through the application server, which in turn accesses the real-time database to retrieve data. Operations initiated by the user, such as manually requesting data or changing configurations, are processed by the application server, which then notifies the communication server to carry out the corresponding actions. Functions The system mainly has the following functions: (1) Data acquisition function Timed data collection: It is capable of collecting various types of measurement data, such as telemetry, telesignaling, power consumption, and other data that can be transmitted to the main station via channels. The system periodically retrieves data from the well terminal; the retrieval interval can be set in minutes for power diagrams, current diagrams, and other parameters, with a minimum of 1 minute and a maximum of 255 minutes ； On-demand data collection: The user terminals at the oil production plant can request data from one or more wells at any time ； Communication control functions: Start/stop data collection from the well terminal, switch the channels used by the terminal, etc ； Channel quality monitoring and fault diagnosis, communication traffic calculation ； GPS time synchronization: Connect to the GPS clock signal to synchronize the clocks across the entire system, and send time synchronization commands to each oil well terminal ； Can support multiple communication protocols and various communication channels ； Add/delete well terminals, and modify terminal communication parameters such as address, communication protocol, and data retrieval cycle ； Modify the parameters of the well terminal, such as various alarm thresholds, the stroke and frequency of the pump, as well as the measurement ranges of various sensors, and send the necessary parameters to the well terminal ； (2) Data processing functions Item alarm handling function: The system allows separate setting of upper and lower alarm limits as well as effective upper and lower limits for analog values; an alarm record is generated when the data exceeds these limits. The audio effect for alarms can be defined, allowing for voice-based alarm alerts ； Event logging: The system records all user actions, communication events, and terminal alarms ； The data retention period can be set, depending on the data type, to be saved whenever there is a change, every 10 minutes, every 30 minutes, or every 60 minutes (the retention period must be equal to or longer than the data collection interval) ； Permission management. All system operations are under authorized control ； (3) Human-machine interface functions Interface cycling display: Authorized users can select oil wells, allowing the basic information interface to be displayed in a cyclic manner; the display time can be set in seconds, ranging from 5 seconds to 30 seconds ； When an alarm occurs, the alarm screen is automatically displayed, accompanied by audio or voice alerts ； Display well information such as open/closed status and basic operational data in conjunction with a geographic map ； Display power line operation information related to oil wells in conjunction with geographical maps, such as whether there is a power outage or not ； Generate time curves for various acquisition parameters ； Display the power diagram: superimposed and side-by-side comparison of power diagrams ； Calculation functions: Supports common function features ； Comprehensive query of historical data and report generation ； Remote start/stop of wells (reserved function) (4) System maintenance function: Provides handheld terminals for well terminal maintenance personnel to facilitate on-site maintenance, and enables them to receive alarm signals from the field in case of failures in the local information network ； (5) Report function: Allow customizing report formats to generate EXCEL reports. Application server: The application server is responsible for receiving requests from user terminals, retrieving the required data by accessing real-time databases, and sending commands to the communication server when necessary. The oil well application server includes data processing software, command processing software, alarm and event handling software, security control software, and graphic creation software. The server software for oil wells should provide at least the following basic functions: (1) Generating a display screen for customer terminals. This screen should use a map of the oil production facility as a background, and show the basic operating status of each well based on its approximate geographical location, such as whether the well is in operation or if there are any alerts ； Moving the mouse over a well location will display an information box showing the basic operational data of that well, such as current, voltage, backpressure, temperature, etc ； By clicking on the well with the mouse, one can access a detailed screen showing information about that well; this screen provides options such as displaying the performance diagram, viewing historical records, and comparing different performance diagrams. Images with a map as the background can be easily zoomed in, zoomed out, and panned, with the graphics remaining distortion-free within the normal zoom range. (2) Security control ① The system should be able to use group-based permission control for users, and area-based control for terminals ； ② The system provides users with the following permissions: system management, terminal management, control, and browsing; it allows control over each user’s access rights to each terminal ； ③ System administrators are responsible for registering (modifying) new users and assigning permissions to them ； Responsible for maintaining system-level parameters, including: default polling interval for production wells, default retention period for production wells ； ④ Regularly authorized users can add (modify) the configuration parameters of the terminals under their jurisdiction. (3) By querying the real-time distribution database, real-time data on the distribution lines is displayed on the map background, allowing team members to keep track of the power supply situation for oil wells in real time, and to better analyze the reasons for any interruptions in power supply when they occur ； (4) Data processing: It receives the data collected by the communication server, converts the raw data into engineering values using the transformation parameters and alarm thresholds defined in the configuration database, compares these values with the alarm thresholds, and if an alarm is required, passes the information to the alarm and incident handling software. (5) Historical data storage: A historical storage period can be configured for each data collection point. The historical storage period can be set to at least one of the following two options: storing data whenever there is a change, or setting the storage period in minutes. (6) Alarm control: The system can define alarm levels for each type of alarm, providing different alarm effects for each level, such as color, sound, flashing, etc. Automatic confirmation as well as time-based or manual confirmation can be defined for each alarm level. It supports various alarm sound effects, including at least the following two: using the PC’s buzzer as the sound effect, and utilizing custom WAV files. (7) Graphic tools: Provide graphic tools for designing the user interface. The generated graphical interface can be automatically delivered to the user’s terminal. (8) Maintenance of the dual-machine backup system: While the system is operating normally, it is possible to shut down either machine in the dual-machine backup system at any time without affecting the system’s operation ； It is possible to manually switch between the master and slave nodes. (9) Real-time/historical database maintenance: Tools are provided for maintaining real-time/historical databases, primarily for data backup. Generally, the tools built into the database can be used. Communication server: The communication server is primarily used to communicate with field devices, handle issues that arise during communication, and provide effective data to the system. Communication server software should possess the following basic functions: (1) Adding/removing terminals – The system can support various types of terminals. At least the following two types are supported: pumpjack well terminals and electric pump well terminals. (2) Configure terminal communication parameters, including communication protocols and attributes ； The system can support multiple communication protocols. At least MODBUS and DNP3.0/UDP/IP protocols are supported. (3) Distribute terminal acquisition parameters ； (4) Execute the communication process with the terminals and handle the relevant protocols according to the terminal configurations. The system groups the terminals based on their communication channels and manufacturers; terminals in one group should be products of the same manufacturer using the same communication method. A group can hold up to 20 terminals (this depends on the polling cycle for communication). When the scheduled inspection time arrives, the communication server creates a communication thread for each group based on the grouping of terminals, with each field location being responsible for the communication of all terminals in that group. A group should use interface modules from the same manufacturer. (5) Perform time synchronization on the terminal ； (6) Perform a scaling transformation on the received analog values to convert them into engineering values ； (7) Store the processed data in a real-time database ； (8) Channel quality monitoring: Monitors indicators such as the channel’s rate and bit error rate, and generates statistical results at any time. (9) Dual-machine hot standby to ensure system reliability ； (10) Accept commands sent by the application server ； Technical requirements for communication DTU devices: a. Basic functions – Achieve data flow and command communication by directly connecting to the SU oil well data acquisition unit via RS485. Reserve an RS232 port or RJ45 interface for configuring the DTU via a PDA or laptop. It features a bidirectional protocol to enable two-way data transmission. It features CRC error correction and retransmission mechanisms to enable resuming transmission from where it was interrupted; it provides a backup channel for short message data, as well as self-diagnosis and alarm functions. Its anti-interference design makes it suitable for applications in harsh electromagnetic environments, while its waterproof design is appropriate for outdoor use. b. Power supply and power consumption: Voltage: 5VDC 1A; average power during communication: <350mA (0% DTX, Pmax); power consumption when idle: <5mA. c. Operating temperature range: –40°C to +85°C. d. Requirements for the DTU device’s software: The link layer uses the PPP protocol, the network layer uses the IP protocol, and the transport layer uses the UDP protocol; no processing is done on the application layer data. Alternatively, a digital radio can be used, eliminating the need for DTU-based data traffic calculation. Table 3-1 shows the calculations for data traffic and operating costs. These figures are based on the assumption of 1,800 oil wells, 200 electric pump wells per oil production facility, 500 monitoring points in the power distribution system, and 500 meters. The basic data related to the oil wells is checked every two minutes, while the data from the power distribution FTUs is checked every minute. Regarding the header data: it refers to the amount of data that conforms to the TCP/IP protocol during each data upload; as for downstream data, it refers to the amount of data transmitted during software-based monitoring. Operating costs are calculated at 0.03 yuan per K. Data format: Figure 3-6 shows the data format – DNP3.0, IP, UDP, PPP: 5 bytes, 20 bytes, 8 bytes, 4 bytes; DATA: 3 bytes. Application layer, Network layer, Transport layer, Link layer. Functions of the wellhead controller and oil well controller: Detecting parameters such as the load on the sucker rod, displacement, voltage and current of the motor, backpressure at the wellhead, and wellhead temperature; also providing remote control functionality for starting and stopping the pumping unit. It is capable of calculating parameters such as motor power and battery charge. It has remote setup or configuration capabilities. It can be connected to communication devices via RS232 or RS485 interfaces, using a polling-response communication mode. Provides an RS232 field maintenance interface. Depending on the power supply at the wellhead, the controller is suitable for voltage levels of 110/380/660/1140 VAC±25%. Provides a backup power source to ensure that communication with the monitoring center can take place once in the event of a power outage, allowing data to be sent. It is recommended to use a capacitor as a backup power source. Features of the oil well controller: Made using industrial-grade components, ensuring high reliability. Operating temperature range: -40～85℃, capable of operating in harsh outdoor conditions. When installing controllers and sensing elements, measures to prevent theft and damage should be taken into account. Part Two: Equipment Description. The principle for selecting computer hardware and software is to ensure they are sufficient and will not fall behind over time. The principles for selecting an oil well controller are reasonable price and high reliability. 2.1. Master station software and hardware at the plant/site 2.1.1. Hardware Personal computers and servers are configured according to the implementation requirements, including monitoring workstations, communication servers, and database servers. Popular personal computers or industrial computers are used as monitoring workstations. P4 2.0GHz, 512M RAM, 80G hard drive, 20-inch monitor or 17-inch LCD monitor, keyboard, mouse, and multimedia kit. Equipped with one printer. For communication services, servers or industrial computers can be chosen; the requirements for the hardware are not very high, allowing for flexible configuration. For the database server, a small workgroup server will suffice. 2.1.2. Software The software mainly includes: IO communication software, real-time database software, alarm and event handling software, security control software, graphical interface software and graphics development software, as well as high-level application software. Since the specifications of different oilfield manufacturers are not entirely consistent, the software corresponding to a particular wellhead controller must be chosen based on that manufacturer’s standards, and there is no universal standard. We advocate the use of open specifications and open software. We use the standard MODBUS protocol, and for software, we employ a professional configuration tool available in China, namely PCAUTO 3.62 from 3D Force Control. The software includes a support software platform, a user interface, and high-level application software. The support software platform comprises IO communication software, real-time database software, alarm and event handling software, security control software, and graphic creation software. The user interface refers to the configuration of IO communications, human-machine interfaces, real-time databases, alarm events, historical data, and historical trends on the support platform. High-level application software includes: historical data analysis, indicator diagram display, current diagram display, power diagrams, reactive power diagrams, power factor diagrams, theoretical indicator diagrams for pumping units, pump efficiency analysis, etc. Software generally includes requirements for software installation, software configuration and debugging, as well as customization. Software installation, configuration, and debugging generally take 2 to 4 weeks, while the time required for customization depends on the user’s requirements and the amount of work involved. 2.2. Communication Equipment: The system’s communication equipment can be a GPRS/CDMA modem or a digital radio. For GPRS/CDMA MODEMs, we can recommend products that we consider reliable based on actual usage, and they support transparent transmission. Users can also choose GPRS devices from other companies. Generally recommended manufacturers include: the MD600 series DTUs from Beijing Computing Center, the DTUs from Xiamen Sangrong, the DTUs from Beijing Jiafuxin, and the DTUs from Beijing Wanweiyingchuang Technology Development Co., Ltd. For digital radio transmitters, we can recommend products that we consider reliable based on actual usage experience. Antenna: For GPRS, a dedicated antenna is used, which is usually provided by the manufacturers of GPRS devices. For digital radio stations, omnidirectional antennas should be selected, along with appropriate elevation settings. Communication systems should pay attention to lightning protection. Recommended manufacturers for digital communication radios include Nisshin Radios, American MDS Radios, Shenzhen Goodi Radios, etc. 2.3. Wellhead controller: The MDS-104SGT wellhead control unit has the following functions: 1. Acquisition of power data and transmission of such data over long distances; 2. Measurement of wellhead pressure and temperature; 3. Standard measurement of electrical parameters: Phase voltages: UA, UB, UC; Currents: IA, IB, IC, I_average; Power: PA, PB, PC, P; Reactive power: QA, QB, QC, Q; Frequency and power factor; Active power consumed in forward direction and in reverse direction; Reactive power consumed in forward direction and in reverse direction; Daily electricity consumption. 4. Control functions: Automatic shutdown protection in case of motor phase loss or overload; Automatic delayed start-up in case of power outage; Control for empty pumping (an energy-saving controller designed for oil wells in old oil fields where there is insufficient liquid supply). Protocol used: MODBUS. Operating temperature range: –40 to 85 degrees Celsius. Power supply: 24V DC. The anti-theft function: The MDS-104SGT, equipped with an infrared proximity sensor, can serve as an anti-theft measure. For the alarm display control module, the DDM-3 module from EKW Microgrid Company can be selected. DDM-3 is a display and setup unit developed by our company to support the development of its products. The interface with our company’s products can use the MODBUS protocol in ASCII or RTU mode. Due to the limitations of the liquid crystal operating temperature, this model is not suitable for installation in the Northeast and Northwest regions. Display all basic measurements. It can display in a loop or stay displayed. 1 RS485 communication interface supporting the MODBUS protocol, and 1 RS232/infrared interface. Chinese character LCD display, 5 buttons. Field instruments for temperature and pressure: To facilitate on-site installation, and taking into account the actual conditions in various oil fields, we have developed specialized wellhead pressure and temperature sensors and transmitters. The temperature sensor uses an industrial-standard PT100 sensor. The output uses a two-wire system, with a total of 4 wires. It is powered by a 12–36V power supply. Load: We use suppliers that have been tested in China. Displacement sensors and transmitters: There are two types of displacement sensors – position sensors and absolute displacement sensors. Position sensors are inexpensive, easy to install, and highly reliable; however, their accuracy is poor, as this approach assumes that the motor’s rotational speed remains constant. Absolute displacement sensors are characterized by accurate measurement, but they are complex to install, expensive, and prone to damage. Our systems and software ensure that the position sensor can be installed in any location, as long as it is able to generate a pulse signal during each pumping cycle of the beam pump. Absolute displacement sensors use tilt sensors, which can be installed directly on the crank beam; an output proportional to displacement is obtained based on the angle of inclination of the crank beam, with an error of only 2%. Then, based on the measured stroke of the oil well, a fairly accurate displacement is obtained. This lays a solid foundation for applications such as pump efficiency calculation and production estimation from indicator diagrams. If the user wants an accurate power diagram, they should use an inclination sensor. The position switch method assumes a constant motor speed and the displacement is obtained through calculation. In practical applications, the speed of the motor is not constant but varies, which may result in significant errors in the displacement shown on the power diagram. Generally, this does not affect the shape of the power diagram, but it does lead to substantial errors when using the diagram for quantitative analysis. 2.4. Protocol Description MODBUS Protocol The MODBUS protocol is an open standard developed by MODICOM and supported by many manufacturers. It serves as a universal language for use in electronic controllers. Through this protocol, controllers can communicate with each other, as well as with other devices via a network (such as Ethernet). It has become a universal industrial standard. With it, control devices produced by different manufacturers can be connected into an industrial network for centralized monitoring. This protocol defines the message structures that a controller can recognize and use, regardless of the network through which communication takes place. It describes the process by which a controller requests access to other devices, how responses are sent in response to requests from those devices, and how errors are detected and recorded. It establishes a common format for the structure and content of message domains. When communicating over a Modbus network, this protocol determines that each controller must know its device address, identify messages sent by address, and decide what action to take. If a response is required, the controller will generate feedback information and send it using the Modbus protocol. On other networks, messages containing the Modbus protocol are converted into frame or packet structures used on that network. This transformation also expands the methods for resolving node addresses, routing paths, and error detection based on specific networks. The standard Modbus port uses an RS-232C compatible serial interface, which defines the pins of the connection port, the cables, the signal bits, the transmission baud rate, and parity checking. The controller can be connected directly or via a modem network. Controller communication uses master-slave technology, meaning only the device (the master device) can initiate transmission (queries). Other devices (slave devices) respond accordingly to the data provided by the master device based on its queries. Typical master devices: hosts and programmable instruments. Typical slave device: Programmable controller. The master device can communicate with slave devices individually, as well as communicate with all slave devices in a broadcast manner. If communicating individually, the slave device returns a message in response; if the query is sent in a broadcast manner, no response is given. The Modbus protocol defines the format for master devices to send requests: device (or broadcast) address, function code, all data to be sent, and error detection field. The device response message is also composed of the Modbus protocol, including the field indicating the action to be taken, any data to be returned, and an error detection field. If an error occurs during message reception, or if the slave device is unable to execute its commands, it will generate an error message and send it as a response. On other networks, controllers communicate using peer-to-peer technology, so any controller can initiate communication with other controllers. In this way, during a separate communication process, the controller can act as either a master device or a slave device. The multiple internal channels provided can allow transmission processes to occur simultaneously. In terms of messaging, the Modbus protocol still adopts a master-slave principle, although the network communication method is peer-to-peer. If the controller sends a message, it acts merely as the master device and expects a response from the slave devices. Similarly, when the controller receives a message, it will create a slave device response format and return it to the sending controller. The function code in the query message indicates what function the selected slave device is to perform. The data segment contains any additional information that the device needs to carry out its functions. For example, function code 03 requires the slave device to read the hold registers and return their contents. The data segment must contain the information to be communicated to the slave device: from which register reading should begin and how many registers need to be read. The error detection field provides a way for the slave device to verify whether the message content is correct. . Response: If a normal response is generated by the device, the function code in the response message is the response to the function code in the query message. The data segment includes data collected from the device: such as register values or status. If an error occurs, the function code will be modified to indicate that the response message is incorrect, while the data segment contains code describing this error information. The error detection field allows the master device to confirm whether the message content is available. The controller can be set to either of two transmission modes (ASCII or RTU) for standard Modbus network communication. The user selects the desired mode, including serial communication parameters (baud rate, parity, etc.). When configuring each controller, all devices on the Modbus network must use the same transmission mode and serial parameters. ASCII mode: Address, Function Code, Number of Data Points, Data1 ... Datan, LRC High Byte, LRC Low Byte, Enter, Line Feed. RTU mode: Address, Function Code, Number of Data Points, Data1 ... Datan, CRC High Byte, CRC Low Byte. The selected ASCII or RTU mode is applicable only to standard Modbus networks; it defines each bit of the message segments transmitted sequentially over these networks, as well as how information is packaged into message fields and how it is decoded. In this system, we only support the RTU frame format. Bits per byte: 1 start bit, 8 data bits, with the least significant bit sent first; 1 parity bit, using even parity; 1 stop bit. Error detection field: CRC checksum. Address field: The address field of the message frame consists of two characters (ASCII) or 8 bits (RTU). Possible slave device addresses are 0...247 (decimal). The address range for a single device is 1...247. The master device selects the slave device by placing the address of the slave device to be contacted in the address field of the message. When a slave device sends a response message, it includes its own address in the address field of the response, so that the master device knows which device has sent the response. Address 0 is used as a broadcast address so that all slave devices can recognize it. When the Modbus protocol is used on higher-level networks, broadcasting may not be allowed or may be replaced by other methods. Function field: The function code field in the message frame consists of two characters (ASCII) or 8 bits (RTU). The possible code range is 1...255 in decimal. Of course, some code is applicable to all controllers, some is intended for a specific controller, and some is reserved for future use. When a message is sent from the master device to the slave device, the function code field indicates what actions the slave device needs to perform. For example, reading the status of input switches, reading the data contents of a set of registers, reading the diagnostic status of a slave device, and allowing the loading, recording, and verification of programs within the slave device. When the slave device responds, it uses the function code field to indicate whether it is a normal response (without errors) or if some error has occurred (referred to as an error response). For a normal response, the device only responds with the corresponding function code. In response to an exception, the device returns a code equivalent to a normal code, but the most important value is logic 1. Supported main function codes: Read Coil Status, Read Input Status, Read Holding Registers, Read Input Registers, Force Single Coil (set a single relay), Preset Single Register (set a single holding register), Force Multiple Coils (set multiple coils), Preset Multiple Registers (set multiple holding registers), Read General Reference (read a file), Write General Reference Mask, Write 4X Registers, Read/Write 4X Registers (read and write holding registers), Read FIFO Queue. We use the MODBUS protocol because it is supported by many manufacturers, is completely open, and requires no fees to be paid to third parties. For detailed information, please refer to Section 3, System Installation, of the MDS-104SGTSGT user manual. To facilitate user use and installation, we have divided the system into two parts: one of these is the connection terminal box, which is quite small and is primarily used for connecting wires. Load sensors, position switch signals (or inclination sensors), wellhead pressure, wellhead temperature, etc., are connected to the IP55-rated RTU box via an interface box. The RTU box contains an isolation transformer, a switching power supply, a communication device (such as a radio transmitter or GPRS/CDMA device), a small air switch, one MDS-104SGTSGT remote terminal (RTU), and several terminals, which are grouped according to their functions. Refer to the Wellhead Controller Diagram 0. The installation process can be divided into the following sections: Installation of the RTU chassis. The RTU chassis is usually installed near the motor control cabinet, or it can also be welded to the motor control cabinet. It is generally installed on a frame welded from angle iron, with the frame buried in the soil; the frame can have a concrete foundation as required by the user. Figure 1 Welding of the transfer box: The transfer box is welded to the derrick. Installation of load sensors: Installing load sensors requires shutting down the well and involves the cooperation of personnel. For open-type load sensors stuck on the sucker rod. For the cylindrical type, it needs to be fitted over the sucker rod. The load sensor is located between the hanger and the clip. Figure 2 Installation of position switches or tilt sensors. The installation of position switches includes welding the position switch bracket as well as welding the proximity switch protrusions. First, find a location where the pump jack’s counterweight arm can pass through, and one that is convenient for welding. Solder the position switch bracket. The distance between the edge of the bracket and the counterweight arm should be around 90 mm, with an error of no more than 10 mm. Solder the mounting screw of the protrusion at the intersection of the counterweight arm and the proximity switch, then tighten the protrusion. Figure 3 shows that the mounting base of the inclination sensor is welded to the beam, and the inclination sensor is fixed to this mounting base using screws, so that it can change along with the inclination of the beam. As shown in Figure 4 below, for some wells, it is sufficient to unscrew one of the plugs on the production tree and replace it with an integrated wellhead pressure and temperature transmitter. For some oil wells, it may be necessary to use gas cutting to cut open the oil pipe and weld on a section of pipe that can accommodate pressure and temperature transmitters. Refer to the markings on the load installation diagram. Installation of current transformers: Current transformers are compact standard models with ratings of 150A/100A.50A:5A or 150A/100A/50A:1A; all that is required is to pass the system’s incoming wires through the transformer. The reason for not choosing open-type transformers is that they have poor accuracy and angle error; moreover, when the open surface rusts, it becomes impossible to ensure accuracy. For system wiring, cables are buried underground in aluminum-plastic tubes, or armored cables are used and also buried directly underground. The wires of the load sensor need to be handled carefully, otherwise they may break over time. System wiring includes sensor wiring, power supply wiring, voltage wiring, current wiring, and communication system wiring. When making the connections, please follow the wiring diagram attached to the wellhead controller strictly. After the wiring is completed, please check it carefully; power can only be applied once everything is confirmed to be correct. Damage or failures caused by wiring errors are not covered under warranty. System debugging: After the wiring is completed, turn on the power supply. Once the system is operating properly, it can be tested and configured using our testing software or system software. It mainly includes: whether there is load data, whether it is changing, and whether it is correct. Are the temperature and pressure data available? Are they changing? Are they accurate? Check whether the proximity switch outputs correctly when the counterweight arm rotates to its position (a single flash of the indicator light is normal; no light or multiple flashes indicate a fault). Are there inclinometer data? Are they changing? Are they correct? Are the voltage data available, and are they correct? Are there current data? Is it changing? Is it correct? Are there power data available? Is it changing? Is it correct? (If the power of individual phases is negative, please carefully check the wiring.) Check whether there is negative-sequence current; if so, there is definitely an error in the wiring of the current transformer. If the data is correct and communication is working properly, then configuration can be carried out at the central station.