List of figureChapterNo.ContentsPage No.

1.INTRODUCTION TO ONGC

1.1 Introduction3

1.2 History of the ONGC4

1.3 ONGC Network

5

2.INTRODUCTION TO SCADA PROJECT OF ONGC

2.1 Introduction6

2.2 Structure of SCADA Project8

2.3 Project Objective9

2.4 Unique Features of SCADA project ONGC9

2.5 Terminologies10

2.6 Other application of SCADA

12

3.SCADA FUNCTION

3.1 Introduction 14

3.2 Data acquisition 15

3.3 Networked and Data communication15

3.4 Data presentation16

3.5 Control 16

3.6 Block Diagram17

3.7 Configuration

18

4.INSTRUMENTS

4.1 Introduction20

4.3 Types Of Instruments21

4.4 FF Protocol21

4.5 ModBus Protocol22

4.6 HART Protocol23

5.RTU(REMOTE TERMINAL UNIT)

5.1 Introduction24

5.2 Introduction to AC800F Controller25

5.3 Features of AC800F26

5.4 Architecture of AC800F

27

6HMI(HUMAN MACHINE INTERFACE)

6.1 Introduction28

6.2 Features of HMI29

6.3 Function of HMI29

6.4 Layout of HMI29

6.5 Basic Navigation

31

7KU & C BAND

7.1 Introduction36

7.2 Ku band36

7.3 Difficulties of Ku Band37

7.4 C band

38

INTRODUCTION TO ONGC

1.1 Introduction1.2 History of the ONGC ONGC network

Introduction

ONGC (Oil and Natural Gas Corporation Limited) is India's leading oil & gas exploration company. ONGC has produced more than 600 million metric tonnes of crude oil and supplied more than 200 billion cubic metres of gas since its inception. Today, ONGC is India's highest profit making corporate. It has a share of 77 percent in India's crude oil production and 81 per cent in India's natural gas production. The origins of ONGC can be traced to the Industrial Policy Statement of 1948, which called for the development of petroleum industry in India. Until 1955, private oil companies such as Assam Oil Company at Digboi, Oil India Ltd at Naharkatiya and Moran in Assam, and Indo-Stanvac Petroleum project at West Bengal, were engaged in exploration work. The vast sedimentary tract in other parts of India and adjoining offshore were largely unexplored. In 1955, Government of India decided to develop the oil and natural gas resources in the various regions of the country as part of the Public Sector development. To achieve this objective an Oil and Natural Gas Directorate was set up in1955, as a subordinate office under the then Ministry of Natural Resources and Scientific Research.Today, ONGC has grown into a full-fledged horizontally integrated petroleum company. Recently, ONGC has made six new discoveries, at Vasai West (oil and gas) in Western Offshore, GS-49 (gas) and GS-KW (oil and gas) in Krishna-Godavari Offshore, Chinnewala Tibba (gas) in Rajasthan, and Laipling-gaon (oil and gas) and Banamali (oil), both in Assam.

ONGC has a fully owned subsidiary, ONGC Videsh Ltd (OVL) that looks for exploration opportunities in other parts of the world. OVL is pursuing exploration of oil and gas in Russia, Iran, Iraq, Libya Myanmar and other countries. ONGC has also acquired 72% stake in MRPL with full management control of the 9.69 tonne, state-of-the-art refinery. History of ONGC

1947 1960During the pre-independence period, the Assam Oil Company in the northeastern and Attock Oil company in northwestern part of the undivided India were the only oil companies producing oil in the country, with minimal exploration input. The major part of Indian sedimentary basins was deemed to be unfit for development of oil and gas resources. After independence, the national Government realized the importance oil and gas for rapid industrial development and its strategic role in defense. Consequently, while framing the Industrial Policy Statement of 1948, the development of petroleum industry in the country was considered to be of utmost necessity. In 1955, Government of India decided to develop the oil and natural gas resources in the various regions of the country as part of the Public Sector development. With this objective, an Oil and Natural Gas Directorate was set up towards the end of 1955, as a subordinate office under the then Ministry of Natural Resources and Scientific Research. In April 1956, the Government of India adopted the Industrial Policy Resolution, which placed mineral oil industry among the schedule 'A' industries, the future development of which was to be the sole and exclusive responsibility of the state.The main functions of the Oil and Natural Gas Commission subject to the provisions of the Act, were "to plan, promote, organize and implement programmes for development of Petroleum Resources and the production and sale of petroleum and petroleum products produced by it, and to perform such other functions as the Central Government may, from time to time, assign to it ". 1961 - 1990 Since its inception, ONGC has been instrumental in transforming the country's limited upstream sector into a large viable playing field, with its activities spread throughout India and significantly in overseas territories. In the inland areas, ONGC not only found new resources in Assam but also established new oil province in Cambay basin (Gujarat), while adding new petroliferous areas in the Assam-Arakan Fold Belt and East coast basins (both inland and offshore). ONGC went offshore in early 70's and discovered a giant oil field in the form of Bombay High, now known as Mumbai High. Subsequently, over 5 billion tonnes of hydrocarbons, which were present in the country, were discovered. The most important contribution of ONGC, however, is its self-reliance and development of core competence in E&P activities at a globally competitive level.After 1990During March 1999, ONGC, Indian Oil Corporation (IOC) - a downstream giant and Gas Authority of India Limited (GAIL) - the only gas marketing company, agreed to have cross holding in each other's stock. Consequent to this the Government sold off 10 per cent of its share holding in ONGC to IOC and 2.5 per cent to GAIL.In the year 2002-03, after taking over MRPL from the A V Birla Group, ONGC diversified into the downstream sector. ONGC will soon be entering into the retailing business. ONGC has also entered the global field through its subsidiary, ONGC Videsh Ltd. (OVL). ONGC has made major investments in Vietnam, Sakhalin and Sudan and earned its first hydrocarbon revenue from its investment in Vietnam. ONGC network network is divide in five parts as shown in Fig. 1.1. Fig. 1.1 ONGC NetworkINTRODUCTION TO SCADA PROJECT OF ONGC

2.1 Introduction Structure of SCADA project Project Objective Unique features of SCADA project of ONGC Terminologies Other application of SCADA

2.1 Introduction Oil and Natural Gas Corporation Limited (ONGC) is Indias premier Organization engaged in exploration and exploitation of hydrocarbons and makes Significant contributions to the industrial and economic growth of the country. The operations of ONGC in India are organized and managed through geographically distinct Assets, Basins, Forward Base, Regional & Corporate office listed. ONGCs production facilities are spread throughout India from East to West; from North to South both On-shore as well as Offshore ONGCs operations are divided into different Assets, Basins, Forward bases and Project Offices. Apart from these, ONGC has some Refining and Processing facilities such as Tatipaka Mini Refinery near Rajahmundry, Uran plant near Mumbai and Hazira Plant near Surat. ONGC owns several Offshore and Onshore drilling rigs, which are used for drilling developmental and exploratory locations. ONGC has been deploying SCADA systems for monitoring and controlling its production operations since late seventies in Offshore. ONGC aims at revamping of these existing systems in Offshore; deploy new systems in all onshore production & drilling facilities and Plants and developing an integrated Enterprise Wide SCADA system for Production and Drilling facilities. This integrated system shall acquire Real-time Production and Drilling data, which, apart from efficient day-to-day operations, shall also be used for supporting scientific and business decisions.Enterprise Wide SCADA for all Production and Drilling Facility of ONGC Spread across India and in Arabian Sea. This project is handle by ABB(Asea brown boveri). Supply of Three Tier SCADA Architecture as Production SCADA and Drilling SCADA spread across 19 Assets/252 Locations in India. The Production SCADA is ABB SCADA Vision and Drilling SCADA is NOV solution.

Major ONGC work center where SCADA is being proposed is shown in Fig. 2.1

Fig. 2.1 Major ONGC work center 2.2 Structure of SCADA project Three-tier system architecture is proposed with Tier-1 at different Production and Drilling Installations, Tier-2 at Different Asset Head Quarters and Tier-3 at corporate level. As shown in below Fig.2.2.

Fig. 2.2 Structure of SCADA project

Tier-1 shall be SCADA Systems, which shall acquire data from Field Instruments, store Real-time and Historical data and process the data for generating Alarms, Events and Reports. Tier-2 shall have a Data Center, which shall acquire data from all the production, & Drilling installations of that Asset have GUI, Alarming and Reporting functionalities and Interface with various Applications. Key Performance Indicators shall be sent to Corporate Layer Tier-3 for presenting it to corporate level users with the facility to drill down to the Installation / rig level if required.Production and Drilling information is required by different organizational scientific as well as business functional groups and managers in respective Assets and Basins. This information is vital for planning and coordination of all E&P activities. Efficient real-time monitoring of this production and drilling operations shall contribute greatly in efficient and cost effective operations. Availability of on-line information shall result in timely and informed scientific and business decisions.

The Tier 1 SCADA will be used for following facilities with in the asset. Group Gathering Stations (GGS) Gas Collecting Station (GCS) Central Tank Farm (CTF) Central Processing Facility (CPF) Early Production System (EPS) Gas Compressor Plant (GCP) Effluent Treatment Plant (ETP)Water Injection Plant (WIP)

2.3 Project Objective

Efficient Real time Monitoring of the Production and Drilling Parameters across all the assets in India. Remote control of the production well in case of Offshore platform. Facilitate offline analysis of the Valuable/ High Producing Wells through third party E&P Applications. Provide summarized information to the management for effective decision making. Total Facelift in the day to day operation of ONGC Production and Drilling facility to improve the efficiency.

2.4 Unique Features of SCADA project

Single Largest Instrumentation- Automation IT Solution project finalised in India The order value is 95 musd Largest three tier network of Near real time process data monitoring. The no of HMI Station in a single largest Network - 1300 Plus HMI Stations and 600 Plus Servers Largest Project in term of the FF based Instrumentations and automation solution 7500 FF instrument and 850 FFH1 segments First Ever project with FF and Hart based RTU and Asset Management. Largest project in terms of Field Instrumentation scope of supply Largest Oil and Gas producing wells connected to the SCADA system 7000 Wells Single largest contract to build 179 Control rooms, 16 Data centres and 75 Mobile Control rooms at 250 plus locations.

2.5 Terminologies

AssetAsset is an independent organizational entity. It has the assets in terms of the productive properties i.e. the Oil & Gas producing Fields and is responsible for all activities related to production and development of the field. Asset operation is managed by Asset Manager.

Basin Basin is an exploration-oriented organizational entity, which caters to exploration and reservoir management. The Exploratory Drilling is monitored and governed by Basin Manager.

ForwardBase/Project Forward Base/Projects are organizational unit, which are producing oil & gas but they are in those petroliferous basins where the presence of oil & gas is established and presently in a preliminary stage of development.Cambay, Cachar-Silchar, Rajasthan, Coal bed methane fall in this category.

Asset/Baseoffice These are project offices, which are responsible for E&P activities of their respective areas. These offices have offices of Asset/ Basin managers, senior managers of respective functions, domain experts and planning & coordination cells of Production & Drilling functions.

Group Gathering Station (GGS)GGS shown in Fig. 2.5. GGS stands for Group Gathering Station which collects crude oil from wells / EPS / ETP. The well fluid is separated into oil /gas and effluent. The crude oil / emulsion is dispatched to CTF/ CPF and natural gas is dispatched to GCS / consumers. GGS is primarily used for oil wells.

Fig. 2.5 GGS

Central Tank Farm (CTF)CTF shown in Fig. 2.6.CTF stands for Central Tank Farm which collects crude oil from GGS / EPS / ETP. The crude oil / emulsion received at CTF is given chemical, heat and electrostatic treatment to break the emulsion of crude oil & effluent. The crude oil is dispatched to Refinery and the effluent is sent to Effluent Treatment Plant (ETP). The CTF has many tanks to store the untreated / intermediate and treated crude oil.

Fig. 2.6 CTF/CPF Central Production Facility (CPF)The CPF Gandhar the biggest Onshore Production facility. It is in Gandhar field in Ankaleshwar Asset. It is spread around 5 Sq. Km area. It receives well fluid from nearby GGSs and processes them. Different processing facilities are available within this complex, such as CSU, GCP, ETP and a Gas based Captive Power Plant (CPP). The well fluid from nearby GGSs is received in Headers. Oil is processed at Crude Stabilization Unit (CSU), and then stored in Intermediate Tanks and then Transferred to Main Tanks. From Main Tanks, oil is pumped to KT terminal in Koyali Refinery, Vadodara. High Pressure (HP) and Medium Pressure (MP) Gas from GGS are processed and dispatched to GAIL. Lean gas from GAIL is received back and compressed and sent to for Gas Lift wells. It is further compressed for Gas Injection wells. Effluent from different separators are sent to ETP.

Captive Power Plant (CPP)ONGC generates Electrical Power through Gas Turbines and Combined Cycle Power Plants for internal use at various locations. Natural gas is used as fuel for CPP.

Gas Collecting Station (GCS)Gas Collection Station collects gas from wells / GGS / EPS / EPT. The well fluid is separated into gas and liquid / condensate / emulsion. The gas is dispatched to Gas compressor plant / consumers. GCS is primarily used for gas wells.

Gas Compression Plant (GCP)GCP is an Onshore installation where the Gas from nearby GGS and GCS is received and compressed into pipelines for dispatch to Consumers. It also has compressors for Gas Lift and Gas Injection depending upon requirements of the field.

2.6 Other application of SCADA

You can use SCADA to manage any kind of equipment. Typically, SCADA systems are used to automate complex industrial processes where human control is impractical systems where there are more control factors, and more fast-moving control factors, than human beings can comfortably manage.Around the world, SCADA systems control: Electric power generation, transmission and distribution: Electric utilities use SCADA systems to detect current flow and line voltage, to monitor the operation of circuit breakers, and to take sections of the power grid online or offline.Water and sewage: State and municipal water utilities use SCADA to monitor and regulate water flow, reservoir levels, pipe pressure and other factors.Buildings, facilities and environments: Facility managers use SCADA to control HVAC, refrigeration units, lighting and entry systems.Manufacturing: SCADA systems manage parts inventories for just-in-time manufacturing, regulate industrial automation and robots, and monitor process and quality control.Mass transit: Transit authorities use SCADA to regulate electricity to subways, trams and trolley buses; to automate traffic signals for rail systems; to track and locate trains and buses; and to control railroad crossing gates. Traffic signals: SCADA regulates traffic lights, controls traffic flow and detects out-of-order signals.

SCADA FUNCTION 3.1 Introduction3.2 Data acquisition3.3 Network &Data communication3.4 Data presentation3.5 Control3.6 Block diagram3.7 Configuration

3.1 IntroductionA SCADA system performs four function Data acquisition Networked data communication Data presentation Control These functions are performed by four kinds of SCADA components: Sensors (either digital or analog) and control relays that directly interface with the managed system. Remote telemetry units (RTUs). These are small computerized units deployed in the field at specific sites and locations. RTUs serve as local collection points for gathering reports from sensors and delivering commands to control relays. SCADA master units. These are larger computer consoles that serve as the central processor for the SCADA system. Master units provide a human interface to the system and automatically regulate the managed system in response to sensor inputs. The communications network that connects the SCADA master unit to the RTUs in the field

3.2 Data acquisitionFirst, the systems you need to monitor are much more complex than just one machine with one output. So a real-life SCADA system needs to monitor hundreds or thousands of sensors. Some sensors measure inputs into the system (for example, water flowing into a reservoir), and some sensors measure outputs (like valve pressure as water is released from the reservoir). Some of those sensors measure simple events that can be detected by a straightforward on/off switch, called a discrete input (or digital input). For example, in our simple model of the widget fabricator, the switch that turns on the light would be a discrete input. In real life, discrete inputs are used to measure simple states, like whether equipment is on or off, or tripwire alarms, like a power failure at a critical facility. Some sensors measure more complex situations where exact measurement is important. These are analog sensors, which can detect continuous changes in a voltage or current input. Analog sensors are used to track fluid levels in tanks, voltage levels in batteries, temperature and other factors that can be measured in a continuous range of input. For most analog factors, there is a normal range defined by a bottom and top level. For example, you may want the temperature in a server room to stay between 60 and 85 degrees Fahrenheit. If the temperature goes above or below this range, it will trigger a threshold alarm. In more advanced systems, there are four threshold alarms for analog sensors, defining Major Under, Minor Under, Minor Over and Major Over alarms.

3.3 Networked data communicationIn our simple model of the widget fabricator, the network is just the wire leading from the switch to the panel light. In real life, you want to be able to monitor multiple systems from a central location, so you need a communications network to transport all the data collected from your sensors. Early SCADA networks communicated over radio, modem or dedicated serial lines. Today the trend is to put SCADA data on Ethernet and IP over SONET. For security reasons, SCADA data should be kept on closed LAN/WANs without exposing sensitive data to the open Internet. Real SCADA systems dont communicate with just simple electrical signals, either. SCADA data is encoded in protocol format. Older SCADA systems depended on closed proprietary protocols, but today the trend is to open, standard protocols and protocol mediation. Sensors and control relays are very simple electric devices that cant generate or interpret protocol communication on their own. Therefore the remote telemetry unit (RTU) is needed to provide an interface between the sensors and the SCADA network. The RTU encodes sensor inputs into protocol format and forwards them to the SCADA master; in turn, the RTU receives control commands in protocol format from the master and transmits electrical signals to the appropriate control relays.

3.4 Data presentationThe only display element in our model SCADA system is the light that comes on when the switch is activated. This obviously wont do on a large scale you cant track a lightboard of a thousand separate lights, and you dont want to pay someone simply to watch a lightboard, either. A real SCADA system reports to human operators over a specialized computer that is variously called a master station, an HMI (Human-Machine Interface) or an HCI (Human-Computer Interface). The SCADA master station has several different functions. Themaster continuously monitors all sensors and alerts the operator when there is an alarm that is, when a control factor is operating outside what is defined as its normal operation. The master presents a comprehensive view of the entire managed system, and presents more detail in response to user requests. The master also performs data processing on information gathered from sensors it maintains report logs and summarizes historical trends. An advanced SCADA master can add a great deal of intelligence and automation to your systems management, making your job much easier.

3.5 ControlUnfortunately, our miniature SCADA system monitoring the widget fabricator doesnt include any control elements. So lets add one. Lets say the human operator also has a button on his control panel. When he presses the button, it activates a switch on the widget fabricator that brings more widget parts into the fabricator. Now lets add the full computerized control of a SCADA master unit that controls the entire factory. You now have a control system that responds to inputs elsewhere in the system. If the machines that make widget parts break down, you can slow down or stop the widget fabricator. If the part fabricators are running efficiently, you can speed up the widget fabricator. If you have a sufficiently sophisticated master unit, these controls can run completely automatically, without the need for human intervention. Of course, you can still manually override the automatic controls from the master station In real life, SCADA systems automatically regulate all kinds of industrial processes. For example, if too much pressure is building up in a gas pipeline, the SCADA system can automatically open a release valve. Electricity production can be adjusted to meet demands on the power grid. Even these real-world examples are simplified; a full-scale SCADA system can adjust the managed system in response to multiple inputs.

3.6 Block diagramBlock diagram is shown in Fig. 3.1. It shows four stage structures.

Fig. 3.1 Block Diagram of SCADA function

3.7 ConfigurationTypical Tier 1 Production & drilling SCADA Configuration contain following parts. Measurement instruments RTU( Remote Terminal Unit) HMI( Human machine interface) L2(layer-2) Switch SCADA server Converter.

Tier-2 SCADA contain following Parts. Servers Redundant Production SCADA Server Redundant Drilling SCADA Server Dual Redundant Common Database Server Application Server (Production) Application Server (Drilling) Web server HMIs Projection display system.

Typical Tier 3 SCADA (Corporate Office) ConfigurationTier-3 SCADA at Delhi have large memory servers for store data coming from Tier-2.Its have SCADA server(Production) SCADA server(Drilling) Web server Networkmanagement server Conman Database(on ORACLE) Colobration server HMIs, Projection display system

INSTRUMENTS

4.1 Introduction 4.2 Types of instrument 4.3 FF Protocol 4.4 Modbus Protocol 4.5 HART Protocol

4.1 Introduction A basic instrument system consists of three elements: SENSOR or INPUT DEVICE SIGNAL PROCESSOR RECEIVER or OUTPUT DEVICEA block diagram of abasic system is shown but they are usually more complex.

Fig. 4.1 Basic block diagram of instrument

Most modern analogue equipment works on the following standard signal ranges. Electric 4 to 20 mA Pneumatic 0.2 to 1.0 barOlder electrical equipment use 0 to 10 V. Increasingly the instruments are digital with a binary digital encoder built in to give a binary digital output. Pneumatic signals are commonly used in process industries for safety especially when there is a risk of fire or explosion. The advantage of having a standard range or using digital signals is that all equipment may be purchased ready calibrated. For analogue systems the minimum signal (Temperature, speed, force, pressure and so on ) is represented by 4 mA or 0.2 bar and the maximum signal is represented by 20 mA or 1.0 bar. This tutorial is an attempt to familiarise you with the many types of input sensors on the market today. Usually such sensors are called PRIMARY TRANSDUCERS.

The block diagram of a sensor is shown below.

Fig. 4.2 B/D of sensor 4.2 Types of instrument In SCADA project of ONGC following Instruments is used for measure different quantity. In bracket shows protocol used for that instruments.

Differential Pressure Transmitter (FF) Pressure Transmitter (FF) Temperature Transmitter (FF) Coriolis Mass Flow Meters-Oil Despatch (Modbus) Ultrasonic Clamp-on Flow Meter-Water Injection Header (Modbus) Thermal Mass Flow Meter-Flare Line (HART) Level Transmitters- Storage & Test Tanks (FF,HART) Magnetic Flow Meters-Effluent Line (FF) Turbidity Meters-Effluent Line (Modbus) Total Flow RTU-Custody Transfer for Gas (Modbus)

4.3 FF(Field Foundation)

Fieldbus is a generic-term which describes a new digital communications network which will be used in industry to replace the existing 4 - 20mA analogue signal. The network is a digital, bi-directional, multidrop, and serial-bus communications network used to link isolated field devices, such as controllers, transducers, actuators and sensors. Each field device has low cost computing power installed in it, making each device a smart device. Each device will be able to execute simple functions on its own such as diagnostic, control, and maintenance functions as well as providing bi-directional communication capabilities. With these devices not only will the engineer be able to access the field devices, but they are also able to communicate with other field devices. In essence fieldbus will replace centralized control networks with distributed-control networks. Therefore fieldbus is much more than a replacement for the 4 - 20mA analogue standard. The fieldbus technology promises to improve quality, reduce costs and boost efficiency. These promises made by the fieldbus technology are derived partly from the fact that information which a field device is required to transmit or receive can be transmitted digitally. This is a great deal more accurate than transmitting using analogue methods which were used previously. Each field device is also a smart device and can carry out its own control, maintenance and diagnostic functions. As a result it can report if there is a failure of the device or manual calibration is required, this increases the efficiency of the system and reduces the amount of maintenance required.

Each field device will be more flexible as they will have computing power. One fieldbus device could be used to replace a number of devices using the 4 - 20mA analogue standard. Other major cost savings from using fieldbus are due to wiring and installation - the existing 4 - 20mA analogue signal standard requires each device to have is own set of wires and its own connection point. Fieldbus eliminates this need so only a single twisted pair wiring scheme is required.

4.4 Modbus

The Modbus protocol provides an industry standard method that Modbus devices use for parsing messages. This protocol was developed by Modicon, Incorporated, for industrial automation systems and Modicon programmable controllers. Modbus devices communicate using a master-slave technique in which only one device (the master) can initiate transactions (called queries). The other devices (slaves) respond by supplying the requested data to the master, or by taking the action requested in the query. A slave is any peripheral device (I/O transducer, valve, network drive, or other measuring device) which processes information and sends its output to the master using Modbus. Acromag Series 900MB I/O Modules are slave devices, while a typical master device is a host computer running appropriate application software. Masters can address individual slaves, or can initiate a broadcast message to all slaves. Slaves return a response to all queries addressed to them individually, but do not respond to broadcast queries.

A master's query consists of a slave address (or broadcast address), a function code defining the requested action, any required data, and an error checking field. A slave's response consists of fields confirming the action taken, any data to be returned, and an error checking field. Note that the query and response both include a device address, plus a function code, plus applicable data, and an error checking field. If no error occurs, the slave's response contains the data requested. If an error occurs in the query received, or if the slave is unable to perform the action requested, the slave will return an exception message as its response (see Modbus Exceptions). The error check field of the message frame allows the master to confirm that the contents of the message are valid. Additionally, parity checking is also applied to each transmitted character in its data frame.

In RTU (Remote Terminal Unit) Mode, each 8-bit message byte contains two 4-bit hexadecimal characters, and the message is transmitted in a continuous stream. The greater effective character density increases throughput over ASCII mode at the same baud rate.

4.5 HART

Field networks are not the only solution when plant operators want to use the advantages of smart field devices. The HART protocol provides many possibilities even for installations that are equipped with the conventional 4 to 20 mA technique.HART devices communicate their data over the transmission lines of the 4 to 20 mA system. This enables the field devices to be parameterized and started up in a flexible manner or to read measured and stored data (records). All these tasks require field devices based on microprocessor technology. These devices are frequently called smart devices.Introduced in 1989, this protocol has proven successful in many industrial applications and enables bidirectional communication even in hazardous environments. HART allows the use of up to two masters: the engineering console in the control room and a second device for operation on site, e.g. a PC laptop or a handheld terminal.The most important performance features of the HART protocol include: proven in practice, simple design, easy to maintain and operate compatible with conventional analog instrumentation simultaneous analog and digital communication option of point-to-point or multidrop operation flexible data access via up to two master devices supports multivariable field devices sufficient response time of approx. 500 ms open de-facto standard freely available to any manufacturer or user

RTU (Remote Terminal Unit)

5.1 Introduction5.2 Introduction to AC800 F Controller5.3 Features of AC800F5.4 Architecture of AC800F

5.1 IntroductionSCADA RTUs need to communicate with all your on-site equipment and survive under the harsh conditions of an industrial environment. RTU functionality is Collects all analog & digital field signals (FF,Modbus,Hart,4-20 mA,On- Off States) .Digitize the Field Signal. Load the data into OPC serverSo RTU required Sufficient capacity to support the equipment at your site but not more capacity than you actually will use. At every site, you want an RTU that can support your expected growth over a reasonable period of time, but its simply wasteful to spend your budget on excess capacity that you wont use.

Rugged construction and ability to withstand extremes of temperature and humidity. You know how punishing on equipment your sites can be. Keep in mind that your SCADA system needs to be the most reliable element in your facility.

Secure, redundant power supply. You need your SCADA system up and working 24/7, no excuses. Your RTU should support battery power and, ideally, two power inputs.

Redundant communication ports. Network connectivity is as important to SCADA operations as a power supply. A secondary serial port or internal modem will keep your RTU online even if the LAN fails. Plus, RTUs with multiple communication ports easily support a LAN migration strategy.

Nonvolatile memory (NVRAM) for storing software and/or firmware. NVRAM retains data even when power is lost. New firmware can be easily downloaded to NVRAM storage, often over LAN so you can keep your RTUs capabilities up to date without excessive site visits.

Intelligent control. As I noted above, sophisticated SCADA remotes can control local systems by themselves according to programmed responses to sensor inputs. This isnt necessary for every application, but it does come in handy for some users.

Real-time clock for accurate date/time stamping of reports.

Watchdog timer to ensure that the RTU restarts after a power failure.

5.2 Introduction toAC800F ControllerIn Fig. 5.1 show the AC800F controller which is use in the our RTU.

Fig. 5.1 AC800F Controller

AC 800F opens up the flexibility of Fieldbus technology to the user. The AC 800F collects and processes diagnostic and process data from four Fieldbus lines, which may be of different types. It does this in addition to the tasks of a conventional process station. Up to 4 (different) fieldbus modules can be plugged into the AC 800F. The communication with other controllers runs via Ethernet.

The basic unit, PM 802F, cyclically scans signals from the fieldbus sensors via the corresponding fieldbus modules, processes these signals according the application programs installed by the user and sends appropriate signals to the fieldbus actuators via the fieldbus modules.Controller redundancy can be achieved by installing two AC 800F. To ensure quick and smooth takeover by the secondary AC 800F in case the primary AC 800F fails, a dedicated redundancy communications link through the second Ethernet module makes sure that both AC 800F are always synchronized.All inputs and outputs are designed to support redundant operation.

Data communication between AC 800F, process and operator stations runs over the Ethernet system bus on the first Ethernet module. Data exchange with the engineering station is also carried via the system bus. engineering station communications can involve new or updated configuration files being downloaded to the process stations, or information about the connected modules being reported back. When fieldbus modules are installed or exchanged, the required configuration information is automatically updated. Configuration and real-time process data is stored in RAM. To safeguard this data in case of power loss, the RAM power is backed up with batteries located either on the Ethernet modules or on battery modules.

The AC 800F optionally provides several levels of redundancy: device redundancy with 2 AC 800F power supply redundancy (24 V DC) Ehernet communication redundancy (standard) Cable redundancy for Profibus DP, requiresexternal equipment (RLM 01)

5.3 Features of AC800F Superscalar RISC microprocessor (up to 150 MIPS) 16 K internal CPU cache RAM 4 MB FLASH EPROM 4 MB SRAM with error detection and correction (patent pending) Battery backup incl. battery watchdog EEPROM, serial, 16 Kbit Monitoring of the temperature inside the device Watchdog 4 slots for fieldbus modules 2 slots for Ethernet communications modules, 32-bit data bus, 100 MBytes

5.4 Architecture of AC800F

Architecture of the AC800f RTU shown in Fig.5.2.

Fig. 5.2 Architecture of RTU

HMI (Human Machine Interface)

6.1 Introduction6.2 Features of HMI6.3 Function of HMI6.4 HMI layout6.5 Basic Navigation

6.1 Introduction

Servers (Databases)

* ODBC Open Database Connectivity

A HMI is the apparatus which presents process data to a human operator, and through this, the human operator, monitors and controls the process. A supervisory (computer) system, gathering (acquiring) data on the process and sending commands (control) to the process.

6.2 Features of HMI

It contains two touches Screen Panasonic Monitor. Windows Server 2003 installed Open database connectivity Contain SCADA vantage software.

6.3 Function

Monitoring real data from the field. For see replication from all the RTU. If we dont get of replication of any reading there is some problem. STORE day to Day information accordance to RTU reading.

6.4 HMI Layout

After logging in, the HMI will launch. Fig. 7.2 gives an example of how the HMI will look at a Tier 1 Facility; in this case ANKGDRGGS03. The layout of the HMI is summarized as follows:

The top left corner of HMI contains buttons for selecting active Alarm Group Alarm Lists. The color of the button show the alarm color of the highest priority alarm in the respective group and the number shows the number of active alarms.

The top right area contains a summary of recent unacknowledged alarms. Refer to the alarms section for details about alarms and alarm groups (Section Error! Reference source not found.).

Navigation is facilitated by the Navigation Menu and shortcut navigation buttons.

The Display Cycler allows the user to view a slide show of predefined screens. More information on the Display Cycler is provided in the navigation section (Section ). The main area is used as a space to display site graphics, lists, applications, and other important screens. In this example, it is opened to a graphical site overview of ANKGDRGGS03. The status bar shows present system information, including the username of the user currently logged in, the server being used, the date and time, and the server status (RTRDB, APPRDB). Alarms can be silenced and the checking of the CAM server can be enabled or disabled. On each graphic is a navigation toolbar to allow the user to move to the next display, go back one display, go to the overview display, pin the display and show the previous display. There are also buttons for moving the objects on the graphics (left, right, up and down). If the operator shrinks the form, he can move the objects he is interested into view. There is also a reset button to return the objects to their original position.

Fig. 7.2 HMI Overview

6.5 Basic Navigation

For most Tier 1 facilities, the HMI will open to the site overview screen by default. The site overview screen is displayed in the main area of Error! Reference source not found., shows a graphical representation of the site, however, it contains only a minimum amount of dynamic I/O in order to prevent overcrowding. The user can obtain more information about particular sections using various navigation methods which are described below. Incase of Tier-2 a screen displaying the consolidated list of all the Tier 1 is displayed. On a single click on any of the button, the graphic will open the corresponding Tier 1 graphics (like Fig. 7.2). Alternatively, a map opens along with the consolidated list, displaying the summary of production of the Asset and also displays the Tier-1 sites as per Latitude and Longitude mapping, double clicking on a particular site icon opens up the Graphic of the particular site showing the various details corresponding to the location.

Other navigations methods which can be used by the Operator for switching between the screens are as follows:

Via buttons (linked to different screens within) on the graphics

Via the navigation toolbar on graphics

i.e. Go Back One Display, Show Overview Display, Go to the Next Display, Pin the Display.

Via the main navigation toolbar (for accessing standard tools, lists etc)

The first screen is overview (Birds View) of the entire location under consideration, in this case ANKGDRGGS03. From here the operator can go the respective locations split mainly as Separator Area, Test Separator Area, Liquid Storage, Gas Lift etc, by clicking on the buttons on the right (refer Figure 6 for better understanding).For example, in order to see additional information regarding the test separators the user would click the Test Separators button shown in Error! Reference source not found.. 7.2 to be navigated to the Test Separator screen which contains detailed process information not shown on the site overview screen

Fig.7.3 Detailed View of Test Separators

In the graphics provided, the process piping connects all the areas in a particular location, in such a case dynamic link buttons are provided. The user can click these buttons to move between connected screens. Alternatively the user can open the Navigation Bar using the Display Buttons icon (), which provides links to all areas on the site. Error! Reference source not found..7.4 shows the Navigation Bar and highlights a dynamic link button.

Fig. 7.4 Navigation Bar

Point Description

To obtain details about a specific data point, the user can move the mouse on top of that point. The fly-over shows the name, current value, and quality of the database point.

Fig.7.5 Point Details on the screen

Points on a black background are read by an RTU, points on a blue background can be set by the user. Any point that is unreliable due to communication problems, etc., will be shown with a line through the value (i.e. stroked value). The color of the point value text indicates the state of that point. In general, Green points are normal, Yellow points are points under the state warning levels, and red points are in alarm. If the point is flashing between white and black backgrounds (reverse video), it indicates that the point is currently in an alarm state and has not been acknowledged. Right clicking the point will bring up the menu shown in .7.6.

Fig. 7.6. Right-Click Menu.

Ku & C Band 7.1 Introduction 7.2 Ku Band 7.3 Difficulties of Ku Band 7.4 C band

7.1 IntroductionIn SCADA Project of ONGC communication for Tier-1 to Tier-2 Ku band in C band is used. For tier-2 to Tier-3, Delhi 2Mbps line is used.

For this communication is ONGC infocorm department of ONGC.PCS ( Patani computer system) handled total LAN network Tier-2 to Tier-3.

7.2 Ku band

The Ku band (Kurtz-under band) is primarily used for satellite communications, particularly for editing and broadcasting satellite television. This band is split into multiple segments broken down into geographical regions, as determined by the ITU (International Telecommunication Union).

The Ku band is a portion of the electromagnetic spectrum in the microwave range of frequencies ranging from 11.7 to 12.7GHz. (downlink frequencies) 14 to 14.5GHz (uplink frequencies).The most common Ku band digital reception format is DVB (main profile video format) .vs the studio profile digital video format or the full-blown Digicipher II 4DTV format.

The first commercial television network to extensively utilize the Ku Band for most of its affiliate feeds was NBC, back in 1983.

The ITU Region 2 segments covering the majority of the Americas are between 11.7 and 12.2 GHz, with over 21 FSS North American Ku-band satellites currently orbiting.

Each requires a 0.8-m to 1.5-m antenna and carries twelve to twenty four transponders, of which consume 20 to 120 watts (per transponder), for clear reception.

The 12.2 to 12.7 GHz segment of the Ku Band spectrum is allocated to the broadcasting satellite service (BSS). These direct broadcast satellites typically carry 16 to 32 transponders.

Each provides 27 MHz in bandwidth, and consumes 100 to 240 watts each, accommodating receiver antennas down to 450 mm (18 inches ).

The ITU Region 1 segments of the Ku spectrum represent Africa and Europe (11.45 to 11.7 GHz band range and 12.5 to 12.75 GHz band range) is reserved for the fixed satellite service (FSS), with the uplink frequency range between 14.0 and 14.5 GHz).

7.3 Difficulties of Ku Band

When frequencies higher than 10 GHz are transmitted and received used in a heavy rain fall area, a noticeable degradation occurs, due to the problems caused by and proportional to the amount of rain fall (commonly known as known as "rain fade" This problem can be combatted, however, by deploying an appropriate link budget strategy when designing the satellite network, and allocating a higher power consumption to overcome rain fade loss. In terms of end-viewer TV reception,It takes heavy rainfalls in excess of 100 mm per hour to have a noticeable effect. The higher frequency spectrum of the Ku band is particularly susceptible to signal degradation- considerably more so than C band satellite frequency spectrum, though the Ku band is less vulnerable to rain fade than the Ka band frequency spectrum.A similar phenomena, called "snow fade" (when snow accumulation significantly alters the focal point of your dish) can also occur during Winter Season.Also, the Ku band satellites typically require considerably more power to transmit than the C band satellites. However, both Ku and Ka band satellite dishes to be smaller (varying in size from 2' to 5' in diameter.)

Ku Band Dish Antenna Compatibility

If a solid dish is taken in use, then there should be no problem in converting from C band, to Ku band.However, with a mesh dish- if the "holes" in the mesh are greater than a quarter inch, the chances of computability are not in your favor, due to the fact that your dish won't reflect Ku-band signals properly.Therefore, strongly consider upgrading to either a solid dish, or a mesh dish in which the hole size under 1/4", and ideally a dish that is 1 piece (or at least very few pieces); as 4 section dish is more optimal than an 8 section dish.The fewer the sections, the more accurate your parabola shape is and thereby the more difficult it is for dish to become warped (the smaller the number of seams- the better). And insofar as dish mounts go, the H2H (Horizon-to-Horizon) dish mount is more desirable than a polar mount.This is due to the fact that the Ku-band demands that the dish antenna system is well-targeted and able to closely follow the orbital arc, of which the H2H mount does quite admirably, as compared to a polar mount. Also, bear in mind that you will be adjusting both the azimuth and elevation, which can be a bit tricky occasionally.

7.4 C BandC Band is the original frequency allocation for communications satellites.C-Band uses 3.7-4.2GHz for downlink and 5.925-6.425Ghz for uplink. The lower frequencies used by C Band perform better under adverse weather conditions than the Ku band or Ka band frequencies.

Uplinking and downlinking

A satellite receives television broadcast from a ground station. This is termed as Uplinking because the signals are sent up from the ground to the satellite. These signals are then broadcast down over the footprint area in a process called Downlinking.Uplinking and Downlinking are shown graphically in Figure below.

To ensure that the uplink and downlink signals do not interfere with each other, separate frequencies are used for uplinking and downlinking.

Table 2 : An Overview Of S, C, Ku & Ka Band Frequencies

DOWNLINK FREQ (GHz) UP-LINK FREQ (GHz)

S BAND2.555 to 2.6355.855 to 5.935

Extended C Band (Lower)3.4 to 3.75.725 to 5.925

C Band3.7 to 4.25.925 to 6.425

Extended C Band (Upper)4.5 to 4.86.425 to 7.075

Ku Band10.7 to 13.2512.75 to 14.25

Ka Band18.3 to 22.2027.0 to 31.00

Noise Temprature

The amount of noise added by the LNA to the received signal is indicated in terms of Noise Temperature. Noise temperature is specified in degrees Kelvin. For all practical purposes, the lower the noise temperature, the better is the LNAs performance. Approximately 10 years ago, a noise temperature of 24 degrees Kelvin was excellent performance for commercial units. However, with todays improved technology, extremely low noise units such as those from Eurostar, offer a noise temperature of 17 deg. K.

The noise performance depends on the type of amplifying device used for the LNA stages. While C Band LNBs use bipolar transistors, KU band LNBs use GaAsFET transistors for the initial amplification. While it is customary to list the noise temperature for C Band LNBs, KU Band LNBs usually specify their noise, not as a Noise Temperature, but as a Noise Figure, in dB. The dB specification helps compute the total system noise, easily, but the more widespread use of a Noise Figure in db, particularly for Ku Band LNBs probably helps in specmanship for marketing purposes. KU band LNBs have much higher noise temperatures, which would not look good on paper. Hence they are quoted in units that look deceptively low, viz dB.

The LNBAfter the C or KU band frequencies are amplified by the LNA, they need to be processed. The processing is done in the satellite receiver which is usually located 10 meter to 50 meters away from the dish antenna. Microwave signals in the S, C or KU Band would suffer very high attenuation if they were carried via coaxial cable from the LNA to the Satellite Receiver 50 meters away.To overcome this problem, the microwave signals are converted to a block of frequencies from 950 MHz to 2150 MHz. Hence, incoming signals received by the LNA at 2 GHz, 4 GHz and even 12 GHz are even block converted down to 950 MHz to 2150 MHz. This range of frequencies is referred to as Intermediate Frequencies since their range of temporary or intermediate frequencies in the chain of satellite reception which receives microwave signals and finally yields video and audio signals from the satellite receiver. This function is carried out by a Block Converter located within the LNB. A combination of Low Noise amplifier + Block converter is referred to as an LNB. A block diagram of a commercial LNB is shown in Figure below.

Mixer

The Block Converter uses the Hetrodyne principle for conversion of a block of S, C or KU Band frequencies to the IF or Intermediate Frequencies. The Hetrodyne principle mixes an external fixed frequency with the incoming frequency. The output from the mixer is a series of signals at the sum and difference of the two inputs to the mixer. Outputs are also produced at multiples of these frequencies. A simple filter is used to suppress all frequency components except those required.

Local Oscillator

The Local Oscillator (LO) is a section of the LNB and gets its name since it is present locally or within the LNB. The local oscillator produces a fixed output at a pre-determined frequency. The Local Oscillator (LO) frequencies have been standardised by LNB manufacturers worldwide for S, C, Ku and even Ka band frequencies. The LO frequencies have been selected to yield an output in the IF (950 MHz to 2150 MHz) range, for all types of LNBs. As a result, universal satellite receivers can be designed for reception of C and KU Band signals through the same satellite receiver.

FilterAs shown in the LNB Block diagram, Bandpass Filters are introduced both before and afterthe mixer. The filters after the mixer suppress or filter out all frequencies except the required frequency which is the difference between the microwave broadcast and the local oscillator frequency.

If AmplifiersThe output of the mixer is an IF signal, at a fairly low level. Since this signal is of a specific bandwidth only, it can be easily amplified, significantly. An LNB often includes atleast 2 stages of IF amplification. This amplified signal is then filtered and fed to the output via a DC blocking capacitor. The capacitor allows the signal to pass through but steers the power coming from the satellite receiver, to the LNB power supply.

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