Report of Scada Group

BY Abhinav Prateek

Gaurav NarangPeeyush Dang Anshu

ShokeenAjay Naithani Nitin Agarwal

A project submitted in partial fulfillment of the requirement for

Summer Training Programme

Of Oil & Natural Gas Cooperation Ltd .

Oil & Natural Gas Cooperation Ltd.Geopic, ONGC Academy Building,KDIMPE Campus, Dehradun-248001

PREFACE

The objective of the current study on “PROCESS CONTROL IN UPSTREAM OIL INDUSTRY” is basically to orient the students on Process Control Systems in general and on the instrumentation and controls used in Up-stream Oil & Gas in specific keeping ONGC as a case. ONGC is totally integrated OIL & Gas Company from Exploration to Production to Refining & Dispensing of Petroleum & Petroleum Products.

The project was undertaken at GEOPIC- a premier Seismic Data Processing and Interpretation Centre, which plays vital role in the Oil Exploration in ONGC. Hence it is considered appropriate to start the project with a brief introduction to GEOPIC and its activities. This is followed by topics which deal with the subject of the project from Chapter 1 to 5.

GEOPIC

The Geodata Processing and Interpretation Centre (GEOPIC) located at Dehra Dun was established in 1987. It is ONGC's largest computing facility and one of the few centres around the world where integrated processing and interpretation of different geo-scientific data from seismic to petro-physical, geological and reservoir engineering are carried out.

Over 60 per cent of the seismic data acquired by ONGC is processed at GEOPIC, which includes all the 3-D seismic data acquired so far over 69 prospects/fields. About 68 billion bits of data are processed here every day.

These 3-D data are interpreted synergistically to unravel the structural and stratigraphic complexities of the sub-surface in search for hydrocarbons. Over the years, 65 3-D prospects have been interpreted.

Interpretation capabilities of GEOPIC can be assessed from its success rate of 54 per cent for the exploratory locations proposed by the Institute, in contrast to the global average of 25 per cent. These capabilities have fetched processing and interpretation contracts both for Indian and Foreign basins.

GEOPIC is a member of 'Consortium of Research on Elastic Wave Exploration Seismology (CREWES)', University of Calgary, Canada; SRB Project, University of Stanford and

International Association of Geophysical Contractors.

Seismic Data Processing

GEOPIC is the largest 2D and 3D seismic data processing centre in India, with a proven capacity for processing over 75,000 line kilometers of seismic data annually.

The explorations goals are achieved by high quality of 3D processing, customized reprocessing tuned to meet interpretation objectives, optimal utilization of resources and special processing and creative techniques.

The services offered are:

High resolution 2D, 3D & 4D seismic data processing Amplitude variation with offset (AVO) Seismic inversion Prestack time and depth migration Velocity depth modeling

VSP data processing Seismolithological modeling Subsurface imaging in geologically complex setting

The facilities available are: Hardware

      Origin 2000 server; 20 CPU’s; 512 MB/CPU RAM, 1080 GB Hard Disk       IBM 3083 Jx3 computer system       Robotic tape library       11 processing workstations       4 Inversion/Interpretation workstations       4 Inversion/Interpretation client nodes      3 Archival workstations       60 X-stations 3590, 3490B, 3480 cartridge drives, DLT drive, 9-track round cape drives

B&W and colour laser printers, scanners, digitizers

Software     WGC processing software       Promax processing software       Time domain processing - FOCUS 2D & 3D

     Inversion - Geodepth products - Power (2D and 3D); Earth model, Geosec (2D and 3D) Probe

     Interpretation - Seisx, Voxelgeo, Geolog and Welltie Reservoir modelling - IRAP RMS, IRAP Mapping, STORM and Voxelgeo

     Powerful velocity model building      Amplitude and AVO inversion

Major jobs completed are:

Volume of data processed:     2,30,000 LKM of 2D data onland and offshore     54,000 LKM of 3D data onland and 31,000 LKM of 3D data offshore

Processed data for:     Sixty nine 3D projects      Hilly terrain, deserts, offshore, land marine ties and deep waters   Western India onland for Selan Exploration      Vietnam offshore for British Petroleum     Basins in Iraq and Kazakhstan      Western India offshore for Essar Oil Ltd.

Seismic and Log Data Interpretation

Computer aided interpretation is the mainstay of 3D seismic interpretation as the amount of data used is voluminous. Interactive interpretation techniques on workstations are being used in GEOPIC for all geoscientific data.

The services offered are:

IIWS based interpretation of 2D, 3D data Structural mapping Integrating seismic attributes with wire line, core and reservoir data for reservoir characterization Seismic modeling 3D visualization and animation Palinspastic restoration AVO analysis Formulation of geological models for exploration and development Reservoir characterization

The facilities available are:

Hardware

     SUN workstations      Silicon graphic workstations      Micro VAX workstations      Digitizers      Scanners      Colour and B/W plotters

Software

     Landmark software on SUN workstations and Geoquest- Schlumberger software on SUN / Silicon      Graphics workstations for the following interpretative activities:      Structural interpretation      Stratigraphic interpretation     Attribute analysis      Seismic modeling      Wireline log evaluation      Petrophysical interpretation      3D animation and visualisation      Palinspastic restoration

Major projects completed are:

Projects Interpreted

    Sixty five 3D projects      Twenty seven 2D projects      Review of nineteen 3D projects based on drilling results

Interpretation of:

     Vietnam offshore 2D data for British Petroleum

     3D data for Selan Exploration

     2D data from basins of Egypt, Iraq and Kazakhstan      3D data for limits of carbonate reservoir and average porosity distribution

Seismic Software Development

Options in the programmes of standard processing software are optimized, modified and generated to meet the requirement of processing groups in solving the data dependent problems. New techniques are also inducted both for processing and interpretation.

The services offered are:

The following software packages have been developed and offered for sale/use:

3D Dip and Azimuth Transformation Software (DATS) Design of shot-receiver layouts for 3D data acquisition through simulation of coverage Post stack 3D cross line statics estimation and application PC/Workstation based software under UNIX and Windows environment for processing seismic data     in the field for QC

The facilities available are:

Rolta 6000/300 Workstation

All the other hardware/software available for processing and interpretation are also being used for seismic software development

Chapter 1

Introduction to Oil Industry

1.1 Oil Industry: the backbone of modern economy

In the present era, the entire world economy, international relationships etc revolve around “Petroleum” because it is typically is the main source of energy and energy is the very basis of modern lifestyle, industry and everything. Crude oil plays the pivotal role in development of any nation, hence its production, safe transporation, refining and marketing become very importatnt to the well being of people of a country. Crude oil industry is mainly devided into two streams; upstream and down stream. The upstream deals with Expolration and Exploitation of reserves in the earth’s crest and transporation of crude oil to refineries. In contrast; the down stream deals with refining, transporation of crude oil products such as petrol, diesal, kerocene, LPG and various other products. In India we traditionallly have ONGC and Oil India Limited as two major companies in the upstream and IOL, HPCL, BPCL etc in the downstream. After openeing up of Indian economy, many companies in private sector and many multinationals have also entered, both in up stream as well as down stream sectors Some of them are Reliance, Cairns Energy and Gujarat Petroleum in Upstream sector and M/s Reliance in Downstream.

1.2 Upstream Oil Industry

The activities of an Upstream Oil Industry can be classified into three major functions namely oil & gas exploration, drilling and production, which also includes transporation of crude from one production installtion to other and / or refinery.

1.2.1 Exploration

Initially oil and natural gas exploration was as simple as Oil & Gas reserves could be easily located using surface seeps or using wild-cat drilling using very minimal data. Today, easy reserves have already been found and now Oil exploration is highly probabilistic, complex and hence a very challenging activity. Presence of the following is necessary for finding oil & gas in the sub-surface

a) Presence of rocks which can be potential source of oil & gas also called source rocks b) Presence of Rocks with proper porosity and permeability so as to contain and also allow

the free movement of oil & gas, called reservoir rocks c) Presence of appropriate structure of reservoir and cap rocks to hold oil & gas.

Exploration deals with delineating all the above conditions before deciding to go for drilling, because the later is a very expensive activity.

Oil Exploration deals with delineating these suitable conditions by direct and indirect methods. The most common indirect methods are Seismic methods. It has following three components:

1.2.1.1 Data Acquisition

Seismic methods are relatively accurate and cost-effective way of modeling the earth’s subsurface. The seismic method involves transmitting acoustic energy into the earth and recording the energy reflected back from subsurface geological boundaries. The source of the acoustic energy can be dynamite detonated in a shallow drill hole, or vibrations generated by fibroses trucks or, in the case of offshore seismic, by air guns towed behind a ship. The returning energy is collected by a series of geophones, or listening devices. By measuring the

two-way travel time of the acoustic energy, a reasonable model of the subsurface can be defined.

1.2.1.2 Data Processing

The Seismic data acquired as mentioned above is collected on Magnetic Media and brought to Data Processing Centre. The volume and complexities of algorithms and processing involved in seismic data processing necessitates use of most powerful computing resources in Seismic Data Processing. The output of the Data processing is “seismic sections’ which aims at providing the picture of structure of the rocks in the earth’s crest.

1.2.1.3 Data Interpretation The seismic sections along with other Geological and Geochemical inputs are interpreted by teams for establishing potential / probable oil & gas reserves of expert scientists for releasing the locations for drilling.

GEOPIC is one of the major Seismic Data Processing and Interpretation Centre as mentioned above.

1.2.2 Drilling

Drilling is one of most difficult and challenging activity in the oil sector. It requires high level of skills and hi tech machinery. This is mainly because of its sensitive nature, the oil and natural gas beneath the crust of the earth is at very high pressure and each and every step in drilling has to be taken with utmost care.

There are two types of drilling1. Exploratory drilling2. Developmental Drilling

As the name suggests that in exploratory drilling is carried out in the new and virgin area after Geological & Geophysical exploration. All sorts of geographical, seismic, magneto-gravitational data related to the crust of earth is collected and then processed.The place where there is no oil production is called as virgin site. But soon after when oil production starts then the site is upgraded to as a basin.During drilling there are various parameters that have to be constantly monitored so that oil is drilled in controlled manner.

1.2.3 Production

The oil & gas is found on land as well as in the offshore accordingly all the above activities are carried out both, in onshore as well as offshore. The complexities, requirements and operations of offshore production installations are very different from those in onshore. However both deal with receiving the produce from the different wells in that area. This produce from wells is also called ‘well fluid’. It contains combination of Oil, Gas, Water and other impurities. In production installations, these constituents are separated and then pumped into pipelines / filled into tanks for transportation to refineries or other customers. The Onshore Oil installations are GGS (Group Gathering Station), CTF (Central tank farm), GCS (Gas Compression Station) etc. In case of offshore production/ processing of Crude Oil is done in offshore installations called Production Well Platform and Process Platforms. From Offshore the oil & gas are transported separately to shore through pipelines or filled into oil tankers.

1.3 Downstream Oil Industry

1.3.1 Refining

Crude oil consists of many different hydrocarbon molecules, from relatively simple short single carbon and hydrogen strings to long, complicated chains and rings.

Refining sorts splits and reassembles the molecules into a variety of usable forms. The first step in the refining process is fractional distillation which separates the oil into its component parts or fractions. The crude oil is first vaporized and the vapour is piped into a tall tower divided by a series of perforated horizontal trays. As the vapour rises through the tower via the perforations on each tray, the heavier fractions condense first and settle out on the lower trays. The perforations are fitted bubble caps that force the vapour to bubble through a previously liquefied fraction on the tray. This bubbling cools the vapour slightly, which causes that fraction to condense out of the vapour while the remaining vapour, consisting of lighter fractions, continues to move upward in the distillation tower. The process is repeated at each tray, with each fraction condensing at the tray where the temperature is slightly below that fraction’s boiling point. Several trays collect each fraction, and the fractions are piped off for further processing into diesel, furnace fuels, stove oil, gasoline and petrochemicals.

1.3.2 Transportation and distribution

Once the oil has been refined and is ready for consumption the next task is safe transportation and easy availability of the refined products for commercial as well as industrial purpose.

The refined oil is transported from refineries situated in places like Mathura, Jamnagar, Assam etc. to all over the country using railways and also through road. For efficient distribution of petrol, diesel, kerosene companies like HPCL, BPCL, and IOCL have their petrol pump outlets in almost all parts of the country. The petroleum products are sold here at predefined rates.

Our present study is confined to the instrumentation and controls systems in used in Up-stream Oil Industry citing specific examples from the installations from ONGC. The project work deals with some basics on Process Control, Control System Theory, Control System Elements, ISA Conventions on Instrumentation Symbology before going into the specifics on the different types of Drilling and Production Installations and instrumentation & controls used in them.

Chapter 2

PROCESS INSTRUMENTATION AND CONTROL

1. Process

Methods of changing or refining raw materials to create end products.

2. Process Control.

Tool that enables manufacturers to keep their operations running within specified limits and to set more precise limits to maximize profitability, ensure quality and safety.

3. Types of Process.

a) Discrete

b) Continuous

c) Batch

2.1.1 Communication Channel 2.1.1.1 Signals

Pneumatic Signal: Pneumatic signals are signals produced by changing the air pressure in a signal pipe in proportion to the measured change in a process Variable.

Analog Signal: Analog signals are continuous levels or values that are combined in specific ways to represent process variables.

Digital Signal: Digital signals are discrete levels or values that are Combined in specific ways to represent process variables and also carry other information, such as diagnostic information. The methodology used to combine the digital signals is referred to as protocol.

Different types of digital signal protocols used are for signal transmission between Instrumentation and amongst different Control Systems and DCS/ SCADA. Instrumentation to PLC/ RTU popular digital signal protocols HART (Highway Addressable Remote Transducer), Foundation Field bus. Between the Control System and DCS/ SCADA protocols such as MODBUS, Profibus, DNP-3.0 and OPC (OLE for Process Control) and between two SCADA systems or DCS protocols such as OPC and ICCP (Inter Control Communication Protocol) are used.

2.1.2 Control Room Equipmets:

Indicators: An indicator is a human-readable device that displays information about the process. Indicators may be as simple as a pressure or temperaturegauge or more complex, such as a digital read-out device.

Recorders: A recorder is a device that records the output of a measurement devices.

Chapter 3

Instruments and Measuements used in Oil Industry

The instruments and Systems which are normally outside the Control Room comprise of Transmitters, Gauges and cables because they have to be kept nearer to the process. The types of instruments vary depending upon the parameter to be measured. Accordingly we have different systems used in oil industry for measurement of pressure, flow, level, temperature etc. Following sections deal with measurement of these parameters.

3.1 Pressure Measurement : Pressure is the most important parameter in both drilling as well as production in up-stream oil industry. It is required to be monitored and controlled on continuous basis for safety of the process and plants as the material being handled are highly inflammable. The pressure is monitored through devices such as Pressure Transmitters and Pressure Switches.

3.1.1 Pressure Transmitter: A pressure transmitter basically has a transducer that converts pressure into an analog electrical signal and signal conditioner which converts the electrical signal to 4-20 mA Analog or Digital signal for transferring the measured pressure values through cables to Central Monitoring & Control System. Although there are various types of pressure transducers, one of the most common is the strain-gage base transducer. The conversion of pressure into an electrical signal is achieved by the physical deformation of strain gages which are bonded into the diaphragm of the pressure transducer and wired into a Wheatstone bridge configuration.

3.1.2 Pressure Switches: Pressure switches are among the most often used instruments in a plant. They are used for indication of presence or otherwise of the pressure beyond a specific calibrated value.

3.2 Temperature Measurement Temperature can be measured via a diverse array of sensors. All of them infer temperature by sensing some change in a physical characteristic. Six types with which the engineer is likely to come into contact are: thermocouples, resistive temperature devices (RTDs and thermistors), infrared radiators, bimetallic devices, liquid expansion devices, and change-of-state devices. Depending upon application and process any one of the above is used in Oil & Gas industry.

3.3 Flow Measurement : A flow meter is an instrument used to measure linear, nonlinear, mass or volumetric flow rate of a liquid or a gas.Different types of flow measurement techniques are used for measurement of Oil and Gas flow in up stream oil industry depending upon the composition, density and viscosity of the oil. The methodology also depends on the quantity of the flow and pressure. The flow measurement can be Mechanical, Ultrasonic, Coriolis or Magnetic. Magnetic Flow meters are also used in some case of Water Flow measurement.

3.3.1 Mass Flow Meter Mass flow meter, also known as inertial flow meter and coriolis flow meter, is a device that measures how much liquid is flowing through a tube. It does not measure the volume of the liquid passing through the tube; it measures the amount of mass flowing through the device.

Volumetric flow metering is proportional to mass flow rate only when the density of the fluid is constant. If the fluid has varying density, or contains bubbles, then the volume flow rate multiplied by the density is not an accurate measure of the mass flow rate.

3.3.1.1 Venturi Flowmeter

The venturi flow meter is installed as a section of pipe or tubing and is used to measure the flow of fluids, either gaseous or liquid. The meter consists of a converging inlet section, a short straight throat section, and a diverging section.

As the fluid enters the converging section, its velocity begins to increase, reaching a maximum value at the throat. The diverging section then slows the fluid to approximately its original value. At the point of maximum velocity, the static pressure has decreased to a value less than the inlet static pressure. The difference between these two pressures along with the inlet pressure and temperature is an extremely accurate and simple indication of the mass rate of flow through the instrument.

3.3.2 Gas flow meters (Differential Pressure Transmitters)

A gas meter is used to measure the flow of fuel gases such as natural gas and propane. Gas meters are used at residential, commercial, and industrial a building that consumes fuel gas supplied by a gas utility. Gases are more difficult to measure than liquids, as measured volumes are highly affected by temperature and pressure. Gas meters measure a defined volume, regardless of the pressurized quantity or quality of the gas flowing through the meter. Various types of techniques are employed depending upon the application. Say in case of the flare gas flow the challenges are sudden flow of high volume of gas and is different from the gas output from process.

3.4 Level Measurement Level is required to be measured at Storage tanks at production installations. Level measurement sensors fall into two main types, Point level measurement sensors and Continuous Level Measurement. Point level Sensors functions as a high alarm, signaling an overfill condition, or as a marker for a low alarm condition. Continuous level sensors are more sophisticated and can provide level monitoring of an entire system. They measure fluid level within a range, rather than at a one point, producing an analog output that directly correlates to the level in the vessel. Both the above types are used in Oil industries depending upon the application. Different types of transducers are used including capacitive and Ultra-sonic type. To create a level management system, the output signal is linked to a process control loop and to a visual indicator.

3.5 Calibrator : Most instruments and sensors are designed to meet certain accuracy specifications; the process of adjusting an instrument to meet those specifications is referred to as calibration. The device used to calibrate other instruments is known as a calibrator. Calibrators vary in form and function depending on the instruments with which they are designed to work. Several different types of calibrators are described below. Calibrators are extensively used by the Instrumentation & Process engineers in Oil Industry for maintaining the accuracy of the measurement.

3.6 ISA Sybology

The Instrumentation, Systems, and Automation Society (ISA) is one of the leading process control trade and standards organizations. The ISA has developed a set of symbols for use in engineering drawings and designs of control loops. Drawings which depict the process flow using the instruments and pipelines based on ISA symbology are known as piping and instrumentation drawings (P&ID). The conventions follwed in the ISA Symbology for depicting the pipeline & instruments are depicted at Annexure-I. A typical P&ID Diagram of an Oil & Gas production installation using ISA notations is placed at Annexure-II. The salient features of ISA Sybmology are as follows:a) In a P&ID, a circle represents individual measurement instruments, such as

transmitters, sensors, and detectors. A single horizontal line running across the center of the shape indicates that the instrument or function is located in a primary location (e.g., a control room). A double line indicates that the function is in an auxiliary location (e.g., an instrument rack). The absence of a line indicates that the function is field mounted, and a dotted line indicates that the function or instrument is inaccessible (e.g., located behind a panel board).

b) A square with a circle inside represents instruments that both display measurement readings and perform some control function. Many modern transmitters are

equipped with microprocessors that perform control calculations and send control output signals to final control elements.

c) A hexagon represents computer functions, such as those carried out by a controller.d) A square with a diamond inside represents PLCs.e) Two triangles with their apexes contacting each other (a “bow tie” shape) represent

a valve in the piping. An actuator is always drawn above the valve.f) Directional arrows showing the flow direction represent a pump.g) Piping and connections are represented with several different symbols.

A heavy solid line represents piping. A thin solid line represents process connections to instruments (e.g., impulse

piping). A dashed line represents electrical signals (e.g., 4–20 mA connections). A slashed line represents pneumatic signal tubes. A line with circles on it represents data links

Other connection symbols include capillary tubing for filled systems(e.g., remote diaphragm seals), hydraulic signal lines, and guided.

h) Identification Letters

Identification letters on the ISA symbols (e.g., TT for temperature transmitter) indicate: The variable being measured (e.g., flow, pressure, temperature). The device’s function (e.g., transmitter, switch, valve, sensor, indicator). Some modifiers (e.g., high, low, multifunction)

i) Tag Numbers

Numbers on P&ID symbols represent instrument tag numbers. Often these numbers are associated with a particular control loop (e.g., flow transmitter 123).

3.7 Typical Control Loops used in Oil & Gas Installations

A feedback loop measures a process variable and sends the measurement to a controller for comparison to set-point. If the process variable is not at set-point, control action is taken to return the process variable to set point. The figure below illustrates a feedback loop in which a transmitter measures the temperature of a fluid and, if necessary, opens or closes a hot steam valve to adjust the fluid’s temperature.

Feedback loops are commonly used in the process control industry. The advantage of a feedback loop is that it directly controls the desired process variable. The disadvantage to feedback loops is that the process variable must leave set-point for action to be taken.

Control loops can be divided into two categories: Single variable loops and multi-variable loops. While each application has its own characteristics, in up-stream Oil & Gas industry pressure, flow, level, and temperature controls loops are very commonly used and described below.

3.7.1 Level Control LoopsThe speed of changes in a level control loop largely depends on the size and shape of the process vessel (e.g., larger vessels take longer to fill than smaller ones) and the low rate of the input and outflow pipes. Manufacturers may use one of many different measurement technologies to determine level, including radar, ultrasonic, float gauge, and pressure measurement. The final control element in a level control loop is usually a valve on the input and/or outflow connections to the tank (Figure below). Because it is often critical to avoid tank overflow, redundant level control systems are sometimes employed.

3.7.2 Flow Control LoopsGenerally, flow control loops are regarded as fast loops that respond to changes quickly. Therefore, flow control equipment must have fast sampling and response times. Because flow transmitters tend to be rather sensitive devices, they can produce rapid fluctuations or noise in the control signal. To compensate for noise, many flow transmitters have a damping function that filters out noise. Sometimes, filters are added between the transmitter and the control system. Because the temperature of the process fluid affects its density, temperature measurements are often taken with flow measurements and compensation for temperature is accounted for in the flow calculation. Typically, a flow sensor, a transmitter, a controller, and a valve or pumps are used in flow control loops (Figure below).

3.7.3 Pressure Control LoopsPressure control loops vary in speed—that is, they can respond to changes in load or to control action slowly or quickly. The speed required in a pressure control loop may be dictated by the volume of the process fluid. High-volume systems (e.g., large natural gas storage facilities) tend to change more slowly than low-volume systems.

3.7.4 Temperature Control LoopBecause of the time required to change the temperature of a process fluid, temperature loops tend to be relatively slow. Feed-forward control strategies are often used to increase the speed of the temperature loop response. RTDs or thermocouples are typical temperature sensors. Temperature transmitters and controllers are used, although it is not uncommon to see temperature sensors wired directly to the input interface of a controller. The final control element for a temperature loop is usually the fuel valve to a burner or a valve to some kind of heat exchanger. Sometimes, cool process fluid is added to the mix to maintain temperature (Figure below).

Chapter 4

Control-Room Systems

4.1 Programmable Logic Controller (PLC) : Programmable Logic Controller (PLC) or Logic Box is an electronic device used for automation of industrial processes, such as control of machinery on factory assembly lines. PLCs were invented as replacements for automated systems that would use hundreds or thousands of relays, cam timers, and drum sequencers till late 70s.

4.1.1 Ladder logic:Ladder logic is the main programming method used for PLCs. As mentioned before, ladder logic has been developed to mimic relay logic. The decision to use the relay logic diagrams was a strategic one. By selecting ladder logic as the main programming method, the amount of retraining needed for engineers and trades people was greatly reduced.

4.2 Remote Terminal Unit (RTU): An RTU, or Remote Terminal Unit is a microprocessor controlled electronic device which interfaces objects in the physical world to a distributed control system or SCADA system by transmitting telemetry data to the system and/or altering the state of connected objects based on requests received from the system.

4.1.2 Architecture and Communications : A typical RTU has a communications interface (usually serial (RS232, RS485, RS422), Ethernet, Modbus, proprietary, or any combination), a simple microprocessor, some form of non volatile memory, some environmental sensors, some override switches, and a bus which it uses to communicate with devices and/or interface boards.

4.1.3 I /O Interfaces : Interface boards come in analog and digital flavors, and are typically designed for input only, output only, or both. These main types of interface boards are often abbreviated as “AI” (Analog Input), "DI" (digital input), "AO" (analog output), "DI" (digital output), Pulse Output and boards interfacting with specicic signal protocols such as MODBUS, Fieldnus, DNP-3.0, OPC etc.

4.1.4 Software and Logic Control : Modern RTUs are usually capable of executing simple programs autonomously without involving the host computers of the DCS or SCADA system to simplify deployment, and to provide redundancy for safety reasons. A RTU in a modern water management system will typically have code to modify its behavior when physical override switches on the RTU are toggled during maintenance by maintenance personnel.

4.1.5 Use in Oil & Gas Applications :RTUs are extensively used in Up-stream Oil and Gas industry for remote instrumentation monitoring, (offshore platforms, onshore oilwells and installations). They are also used in Hydro-graphic monitoring and control, (water supply, reservoirs, sewerage systems) and Environmental monitoring systems (pollution, air quality).Earlier the functionality of RTU was limited to scanning the instrumentation inputs and forwarding data to SCADA or DCS. However of late they are incorporating lot of logic

and computational functionalities which existed in PLCs. The distiction between the PLC and RTU is getting vanished.

4.2 Distributed Control System A distributed control system (DCS) refers to a control system usually of a manufacturing system, process or any kind of dynamic system, in which the controller elements are not central in location (like the brain) but are distributed throughout the system with each component sub-system controlled by one or more controllers. The entire system may be networked for communication and monitoring.Input & output modules form component parts of the DCS. The processor receives information from input modules and sends information to output modules. DCS is a very broad term that describes solutions across a large variety of industries, including:

1) Electrical power grids and electrical generation plants.2) Environmental control systems3) Traffic signals.4) Water management systems.5) Refining and chemical plants6) Pharmaceutical manufacturing.7) Sensor Networks

A DCS solution does not require operator intervention for its normal operation, but with the line between SCADA and DCS merging, systems claiming to offer DCS may actually permit operator interaction via a SCADA system.

Distributed Control Systems (DCSs) are dedicated systems used to control manufacturing processes that are continuous or batch-oriented.A typical DCS consists of functionally and/or geographically distributed digital controllers capable of executing from 1 to 256 or more regulatory control loops in one control box. The input/output devices (I/O) can be integral with the controller or located remotely via a field network.

4.3 SCADA SCADA is any system that performs Supervisory Control And Data Acquisition, SCADA systems are typically used to perform data collection and control at the supervisory level. Some SCADA systems only monitor without doing control, these systems are still referred to as SCADA systems

4.3.1 Systems concepts : A SCADA system includes input/output signal hardware, controllers, HMI, networks, communication, database and software. It mainly comes in the branch of Instrumentation Engineering.The term SCADA usually refers to a central system that monitors and controls a complete site or a system spread out over a long distance (kilometres/miles). The bulk of the site control is actually performed automatically by a Remote Terminal Unit (RTU) or by a Programmable Logic Controller (PLC).

4.3.2 Human Machine Interface : A Human-Machine Interface or HMI is the apparatus which presents process data to a human operator, and through which the human operator controls the process.The HMI industry was essentially born out of a need for a standardized way to monitor and to control multiple remote controllers, PLCs and other control devices.An HMI may also be linked to a database, to provide trending, diagnostic data, and management information such as scheduled maintenance procedures, logistic information, detailed schematics for a particular sensor or machine, and expert-system troubleshooting guides.

4.3.3 Hardware solutions : SCADA solutions often have Distributed Control System (DCS) components. Use of "smart" RTUs or PLCs, which are capable of autonomously executing simple logic processes without involving the master computer, is increasing. A functional block programming language, IEC 61131-3, is frequently used to create programs which run on these RTUs and PLCs.

4.3.4 System components :a) Remote Terminal Unit (RTU) : The RTU connects to physical equipment, and

reads status data such as the open/closed status from a switch or a valve, reads measurements such as pressure, flow, voltage or current.

b) Master Station: The term "Master Station" refers to the servers and software responsible for communicating with the field equipment (RTUs, PLCs, etc), and then to the HMI software running on workstations in the control room, or elsewhere.

4.3.5 Operational philosophy : Eventhough traditionally SCADA was designated to facilitate remote operations of installations i.e. monitoring and controls where RTUs performed the task of store & forward only but of late instead of relying on operator intervention, or master station automation, RTUs may now be required to operate on their own to control tunnel fires or perform other safety-related tasks. The master station software is required to do more analysis of data before presenting it to operators including historical analysis and analysis associated with particular industry requirements.

4.3.6 Communication infrastructure and methods : SCADA systems have traditionally used combinations of radio and direct serial or modem connections to meet communication requirements, although Ethernet and IP over SONET is also frequently used at large sites such as railways and power stations.

4.3.7 Features of SCADA :SCADA systems are of different in terms of applications and number of I/O channels. They can be simple PC based system directly attached to an RTU or a large system comprining of several RTUs/ PLCs. Eventhough SCADA refers to the entire system comprising of RTUs and Master Station the main task is carried out by the SCADA Software in SCADA Master Station. The typical features/ tasks performed are:a) Scanning RTUs for getting the data and status Field Instrumentaion. The data

can be Raw or computed. For obtatining the data from RTUs, either Request-response or Report–by-exception techniqes are followed.

b) Maintaining Histories of the field data and that od Alarms and Events.c) HMI, Human Machine Interface which includes

MIMIC Diagrams which provides the GUI based view of the plane/ installaion with instauemts and the parameter valus. Mimics are interactive with zoom-in and zoom-out facilities.

Display of Trends. Display of Alarms and Events. Historical data and logs (Operator actions, equipment and instrumnent

configurations etc). d) User authentication and security: It maintains multi-level user authentication and

permissions and allocates different functionalities of monitoring and controls yo users.

e) Initiation of Supervisory Controls and transferring them to RTUs for implementing at Field level.

4.3.8 Future trends in SCADA : The trend is for PLC and HMI/SCADA software to be more "mix-and-match". In the mid 1990s, the typical DAQ I/O manufacturer offered their own proprietary communications protocols over a suitable-distance carrier like RS-485. Towards the late 1990s, the shift towards open communications continued with I/O manufacturers offering support of open message structures like Modicon MODBUS over RS-485, and by 2000 most I/O makers offered completely open interfacing such as Modicon MODBUS over TCP/IP. Further Ethernet and TCP/IP based protocols such as ICCP and OPC are already becoming defacto standards and more and more manufactureres of PLC, RTUs, DCS and SCADA systems are adopting to these communication standards. On Instrumentation side also standard protocaol sych as HART and Foundation Field bus in becoming common.

MODBUS

MODBUS protocol is a messaging structure widely used to establish Master Slave communication between intelligent devices. It is independent of underlying physical layers. It is traditionally implemented using RS232, RS 422 or RS485 over a variety of media (eg. Fiber, radio). MODBUS TCP/IP was recently developed to provide a faster interface and uses TCP/IP and Ethernet to carry the MODBUS messaging structure. It requires a license but all specifications are public and open so there is no royalty paid for the license.

DNP-3 (Distributed Network Protocol)

DNP was originally created by Westronic in 1990. DNP 3.0 is an open, intelligent,robust and efficient modern SCADA protocol. It is based on the standards of the INTERNATIONAL ELECTROTECHNICAL COMMISSION(IEC) Technical Committee. It is used to exchange data between RTUs and Remote central points DNP3 is an open and public protocol.

ICCP(Inter-center Control Protocol)

ICCP maximizes the use of existing standard protocols in all layers up to and includingthe lower layers of layer 7 in the OSI reference model. This has the benefit of requiring new protocol development for ICCP only in the upper sub-layer of layer 7.

ICCP utilizes the services of the Application Control Service Element(ACSE) in layer 7 to establish and manage logical associations and connections between sites.

It relies on the ISO Presentation Layer 6 and Session Layer 5 as well.

OPC(OLE For Process Control)

OPC(OLE for Process Control) is a software standard for open software application interoperability between automation/control application, field systems/devices and business/office applications.

OPC defines a common, high performance interface based on Microsoft’s COM/DCOM technology. COM(Microsoft’s Component Object Model) enables the definition of standard objects, methods and properties for servers of real time information such as DCS, PLCs, I/O systems and smart field devices. DCOM(Distributed Component Object Model) is the network-aware version of Com technology, providing data via LANs, remote sites or the internet.

4.3.9 APPLICATIONS OF SCADA

SCADA From the cold of Siberia to the heat, salt and moisture of offshore oil platforms, SCADA (Supervisory Control and Data) systems are proven performers in a wide variety of industries and applications.

• Oil & Gas Production & Drilling.• Oil refineries

• Electrical Generation, Transmission & Distribution

• Chemicals & Petrochemicals

• Fertilizers

• Water Distribution

• Sewerage

CHAPTER 5

Process Control / SCADA in ONGC

In ONGC, being an Up-stream Oil Major, its processes are very comlex and employ Process Control both in Drilling and Production functions. While as in case of drilling, safety is the main concern, in case of production, maintaining product quality and cost optimization also become additional concerns. ONGC has all along been using instrumentation and control systems in both these functions but these systems were obsolete, heterogenous, scattered and not integrated to each other and to MIS (Management Information Systems). ONGC has embarked upon a major initiative of implemeting “Enterprise Wide SCADA System for Drilling and Production”.

The objective of this project is not only to provide comrehensive opeartions control but also provide real-time, on-line process data to business systems such as SAP and to Scientific Systems for generating greater value out of the process data. The proposed SCADA is based on Stae-of-the-art technology, based on open signal/ communication protocols. It is spread across all the drilling & production installaion of ONGC throughout India and is based on three tier architecture (At installations, Operations Mangers and Corporate Level MIS). Following sections describe the processes at different types of installations in drilling & production and also indicate different parameters monitored and controlled in these installations.

5.1 Drilling Process and SCADA:

Oil well drilling is a complex activity because it has to cater to the unknown behaviour and pressure encountered from the Oil & Gas in the crest of the earth. To counterbalance this pressure, ‘Drilling Mud’ is pumped into the well thorugh drill string. Drilling is carried out using ‘drill bit’ as with increase in depth, more and more drill strings are attached to it. The oil well drilling may go upto a depth of from few hundren meters to 5000 meters. The drill strings are hollow and through them mud is pumped into the well.

Drilling Mud is a slurry of specialised chemicals. The mud serves several purposes such as removal of the rock cuttings, cooling and lubrication of the drill-bit and most importatntly maitain hydrostatic pressure to counterbalace the reservoir pressure of oil & gas (in case oil / gas carrying rocks are encountered). To provide a return path to the mud there is a coincentric Annulus around drill string. The mud coming out of the well is an indicator of the presence of oil/ gas through its density in contrast with the mud pumped in. It is also analysed using Gas Chromatographs for gas-shows. Other mud parameters are also significantly importatnt.

The instrumetation and monitoring play vital role in carrying out the drilling activity safely and as per the schedule (maintaining required penetration rates). Different subsets of the total parameters are relevant to different functions; Drilling, Geology and Chemistry. These parameters are described below.

5.1.1 Drilling Parameters monitored using SCADAFor monitoring & control of drilling operations inputs are taken from Drill floor as well as Mud Logging. They may be taken from the Rotary strokes per minute, Mud tanks, Trip Tanks, Hookload at Kelly, and Blow Out Preventer. Follwing parameters are monitored:

Hook load, bit weight, lines strung, bit position In slips

Rate of penetration ,depth of hole, bit depth

Drill pipe rotary rate and torque

Active mud tank volume, trip tank volume, gain/loss

Return mud flow

Pump rate, total strokes,

Mud pressure, temperature, flow rate and density in and out.

5.1.2 The SCADA LayoutThe signals from all these Sensors are brought and acquired into a Data Acquisition System (DAS) which is not part of SCADA system. The A/D converted / stored data is then transferred to SCADA system through Ethernet Rig LAN on WITS/ WITSML protocol. (Well Information Transfer System on XML) a protocol standard in logging/ drilling SCADA industry. There are separate sets of screens for Tool pusher (Drilling), Geology and Chemistry only showing relevant information on GUI.

The data from SCADA System on Rigs shall then be transferred to the SCADA system at respective Asset HQs on WITSML protocol for sismilar displays there. At Asset dtat from all the rigs in that asset shall be collected and any of them can be monitored remotely. From there the data shall be transferred to Institue of Drilling Technology, Dehradun. The system also fecilitates automatic Daily Progress Reports/ MIS generation and feeding of data into the ONGC’s Business system on SAP.

In the Enterprise Wide SCADA under implematation, all the 75 Onland Rigs and 10 Ofshore Rigs are covered. Also there is provision to inegrate the Contractual Rigs on Open Protocols.

5.2 Production Installations and processesThe oil & gas from the producing wells are brought into production installations. The fluid from well contains a combination of Crude Oil, Natural Gas, Water and other Impurities. These constituents are required to be separated before the Oil & gas is sent to Refineries or to nearby gas consumers such as Power Plants, Chemical Industries etc.

The production systems in ONGC can be grouped into two categories “Onshore” and “Offshore” production installations. Depending upon the input being processed, these insallation are further classified into Oil & Gas proce installation or only Gas installation. A wide range of processes are involved and accordingly every installtion has a specific process. Following sections deal with these installations in ONGC and the parameters being monitored and other instrumentation and processes involved there in.

5.2.1 Offshore Production Installtion: In Offshore Production Installions are are Platforms which very huge in size and are erected in the sea. They can be categorised into Production Well Platfrom and Process Platforms. The well platform is a stand alone un-manned installation in offshore hence it is also known as “Remote Well Platform” or “Unmenned Platform”, where the produce from oil & gas wells are brought. There is no or minimum processing involved and the produce is sent as it to Process Paltform. The Process Platform is a very huge structure where the raw pruduce from many nearby production well platforms are brought through under sea pipelines also called “Raiser Lines”. and which then undergoes verious stages of processing / refinement. Oil, Gas and Effluent are separated. Oil & gas are sent to

shore facility through under sea “Trunk pipe lines”. Water in sent to a separate facility called “Water Injection Platfrom” where the water is pumped back to the subsurface through separate Water Injection Wells for enhancement of oil & gas production from that field.

5.2.1.1 Production Well Platform

As described above, the well platform is the installation in offshore, where the produce from oil & gas wells are brought. A well platform caters to 10 to 30 nearby Oil & Gas wells. It has facility to jack up the Offshore Drilling Rigs, from where drilling is carried out. In case of a success in drilling, those wells can be added into the platform.

The well has many coincentric tubings comrising of ‘Main Production Tubing’ and upto three numbers of ‘Annulus’. The Annulus are also used for injecting gas in case of Gas-lift wells. In the production tubing there is a Safety Valve (SSV) which is situated on the upper part of well above the floor of the platform and Sub-Surface Safety Valve (SSSV) which lies below. They are used for shutting down the well in case of any exegency. They are also controlled by Fire Shutdown and Emergency Shutdown panels. The other well platform monitored are as follows:

PER WELL1. WELL HEAD PRESSURE. : Indicates health of each well2. FLOW ARM TEMPERATURE : Indicates health of each well3. SSSV STATUS. : Sub-surface safety valve 4. SSV STATUS. : Surface safety valve Status

SSV

PT

TT

SSV PT Switch

Pr Switch

Shut- down Panel

Flow Arm to Main Header

Flow Arm from other wells

PTTT

Signals from other well Heads

PTTo other Gas Lift Wells

PTDPT

TIJBPT

TT

SSV Status

SSV Control

SSSV Status

RTU

To Master Telemetry units at Process

Complexes

TDMA Radio Link

OFC Link to Process Complex

Flow to Process Complex

Process and Parameters in a Offshore Production Well Platform

SSSV

Lift Gas from Process Complex

5. SSV CONTROL. : 6. ANNULUS-A PRESSURE. : To monitor leakage from any of 7. ANNULUS-B PRESSURE. : these casings.

8. ANNULUS-C PRESSURE. :

PER PLATFORM1. ESD STATUS : Status of Emergency Shutdown2. FSD STATUS : Status of fire shutdown3. ESD CONTROL(OPTIONAL) : Remote operation of ESD 4. MAIN LINE PRESSURE : Outgoing5. MAIN LINE TEPERATURE : Outgoing

The produce from all the wells of a platform are combined into the Main Line which is taken to Process Complex where it is known as Raiser Line. These Parameters are taken into an RTU at Well platform and through radio taken to SCADA system at Process Platfrom.

5.2.1.2 Process Complex:The Process platform where produce from well platforms is taken and processed for separating Oil, Gas & water is a major structure in the offshore and is manned. It also has residential facilities, offices and maintenance functionalities. The complete facility is known as “Process Complex”. It has series of “Three Phase Separators” followed by Compressors for pumping separated oil & gas to shore directly or via nearby process complex. The water is pumped to Water Injection Platform. In some cases Water Injection Platforms are attached to the main Process Complex itself.

Typical Layout of a Process Complex

Well Platform

Well Platform

Well Platform

Process Platform-1 Process Platform-2

Process Platform-3

TDMA Radio

SCADA Server

SatelliteEarth Station/Micro-wave

DCS for LocalProcess Control

Bridge

OPC Link with DCS SystemV.35 Link with Router through OFC

RS-232 Link through OFC

SCADA HMI Work Stations

Remote ProcessPlatformSCA/WIN

Ethernet LAN through OFC

TDMA Radio

Router

The Process Complex contains the SCADA System which acquires the data from well platform RTUs through TDMA radio by polling or Report by exception. The SCADA data is in turn taken to Asset Office at Shore through Satellite Communication. Apart from the well data from well platfroms some of the information form process with process complex are also acquired from the DCS of the Process Complex as depicted above. Following is the list of such parameters.

1. Raiser Line Pressure at Process Complex : Pressure of line coming from each Remote Well Platform

2. Raiser Line Temperature at Process Complex: Temperature of line coming from Remote Well Platform

3. Main Oil Line Pressure : Main Oil Line going from one Process 4. Main Oil Line Temperature : Complex to other process Complex 5. Main Oil Line Flow Rate : or to the shore 6. Main Gas Line Pressure : Main Gas line going from one 7. Main Gas Line Temperature : Process Complex to other Process 8. Main Gas Line Flow Rate : Complex or the shore 9. Total Oil Pumped Into Main Line : (Volume) 10. Total Gas Pumped Into Main Line (Volume)

5.2.2 Onshore Production Installations: Onshore has many Production Installations such as GGS, CTF, ETP, etc. They are described below.

5.2.2.1 Group Gathering Station (G.G.S.):GGS is the installation where the produce from wells are taken first. It caters to large neumber of wells in the vicinity. Many production well lines enter into the GGS and each may be combining produce from more than one well along the way. They are connected to the Group Header. However any of them may be diverted to Test Header also. From Group Header the well fluid is taken to a Group Separator, which allows the Oil, Gas and Effluent to get separated under static conditions at some pressure. After this the Oil separated is sent to Heater Treater where it is heated to remove the desolved gas further. Then the Oil is stored in tank and either pumped to CTF or to consumers as the case may be. Gas from all these stages is combined and pumped to GCS. Some quantity of Gas is always sent to Flare Line so as to maintain the flame.

The diagram below depicts the process at GGS and also the parameters being monitored.

5.2.2.2 Gas Collecting Stations (G.C.S.): In contarst with GGS, GCS caters only to gas wells. Number of Gas wells are connected to it

through pipelines. The pipelines may attach to single or multiple oilwells through branches from the surrounding areas, the gas from the well entered in to two headers namely GROUP HEADER and TEST HEADER through on-off valves.

PUMPS

Crude Oil Dispatched

to CTF

Process and Parameters to be monitored at GGS

Separator

Heater Treater

Tanks

WellStatus

HeaderPressure

Gas FlowTo GCS

Gas FlowTo Consumer

Gas FlowTo Flare

HT Temp EffluentDrained

TankLevel

Mass Flow

Meter for Crude

Gro

up

Hea

der

OI L

WELLS

The gas from Group Header is taken to Separator where the Gas is separated from Emulsion and the Gas is then comressed to CTF/ GCP or consumers. The following diagram depices the process at GCS and the parameters being monitored in GCS

5.2.2.3 Early Production System (EPS):

Before the field is completely develop the production from few oil wells started by collecting there produce in to an installation called EPS. It is not so elaborated in terms of facilities lesser functionality compared to G.G.S.

5.2.2.4 Centarl Tank Farm (CTF)

Central Tank Farm is a bigger installation where the Oil from GGS are brought before being pumpud to refineries through pipelines or through tankers. The diagram indicates the process and Parameters to be monitored in CTF.

Group Header

Test HeaderTest

Separator

Process Parameters

Proposed to be Monitored

In a Typical GCS

GroupSeparator

Gas Wells

Gas

Gas

Test Gas Qty

Test Pressure

Total Qty of Gas Supplied to Consumers

Pressure, Temp & Total Qty of Gas Dispatched to GCP

Total Qty of Gas Received from GGS

Radio /Router

PC

InstallationSCADA

R T U

To AssetHQ

TESTTANK

Qty of Gas Flared

Emulsion

Qty of Emulsion

MFM

Flowing Status of High

Producers

Header Pressure

Tank Level

5.2.2.5 Gas Compressor Plant

The gas collected form one or more GCS is compressed and sent to Refineries / LPG plant etc.

Process Parameters Proposed to be Monitored

In a Typical GCP

Total Qty & Pressure ofGas Received from GCS

Total Qty & Pressure of Gas Compressed by GCP

L.P. GAS H.P. GAS

GasCompressor

Plant

No. of COMPRESSORS& On / Off STATUS

FQ

Existing

FQ

Existing

Note : GCP Data is to be taken to nearest GGS/CTF by Cable.

Process Parameters Proposed to be Monitored

In a Typical CTF

Crude Oil from GGSs

HeaterTreater

HeaterTreater

PUMP

PUMP

Qty of Crude Oil & WC Received from each GGS

H/T Pr. & Temp

Qty of Effluent to ETP

Oil Level , Temp of Each Tank With Hi-Low Alarms & Volume / Mass of Crude Oil

Total Qty of Oil Dispatched & Water Cut

Radio /Router

PC

InstallationSCADA

R T U

To AssetHQ

Pump Status

5.2.2.6 Effluent Treatment PlantThe effulent from varies GGS is taken to ETF where remainning oil is taken out and water is seperated . The water is taken out and is used to inject water in wells. Water is further treated by water treated plant.

Process Parameters Proposed to be monitored

In a Typical ETP

Total Qty of Treated EffluentPumped to WIP / Disposal Wells

TREATEDEFFLUENTETP

PUMP

EFFLUENTFQ

Existing

To nearby GGS / Production Installation

Note : ETP Data is to be taken to nearest GGS by Cable.

5.2.2.7 Water Treatment Plant

The Water from Effluent Treatment Plant is brought to Water Traetment Plant. The Water is then pumped tp GGS / CTF for pumping into Water Injection wells.

Process Parameters Proposed to be monitored

In a Typical WIP

Total Qty of Injection Water

Pumped to GGSs / Wells

INJECTIONWATER

WATERTREATMENT

PLANTPUMP

Injection Pressure

Treated Effluent / Tube well Water

FQ

Existing

Note : WIP Data is to be taken to nearest GGS by Cable.

To nearby GGS / Production Installation

In all these Installations mentioned above, the parameters indicated there are recorded into suitably sized RTUs. SCADA is normally at GGS and CTF only and parameters from RTUs of other smaller installations in the vicinity are brought to this SCADA.

5.3 Benefits from SCADA1) Support efficient monitoring of the operational productional & drilling parameters.

2) Automatic generation of Logs, Reports and DPRs.

3) Better accounting of the products and stricter control wastages etc.

4) The data can be provided to other Production and Drilling Appliocations for more purposeful information. The application such as Mass balancing, Leakage Detection, Gas Lift Optimization add value to the organization.

5) Seamless flow of Realtime Online information into business and scienftific systems increasing authenticity due to avoiding manual errors.

5.4 Conclusion

The study provides a detailed account of the process control in general and then specific to Up-Straem Oil & Gas Industry. This study has not only provided the exposure to the Process Control in general and to the terminologies, symbologies therein but also to its specialized applications in UP-stream Oil Industry with illustartion. This shall go long way in shaping our career as budding Instrumentation Engineers.