This chapter contains an overview of the various systems that provide utilities or supports for the main process.
A process control system is used to monitor data and control equipment on the plant. Very small installations may use hydraulic or pneumatic control systems, but larger plants with up to 250,000 signals to and from the process require a dedicated distributed control system. The purpose of this system is to read values from a large number of sensors, run programs to monitor the process and control valves, switches etc. to control the process. Values, alarms, reports and other information are also presented to the operator and command inputs accepted.
Process control systems consist of the following components:
- Field instrumentation: sensors and switches that sense process conditions such as temperature, pressure or flow. These are connected over single and multiple pair electrical cables (hardwired) or communication bus systems called fieldbus.
- Control devices, such as actuators for valves, electrical switchgear and drives or indicators are also hardwired or connected over fieldbus.
- Controllers execute the control algorithms so that the desired actions can be taken. The controllers also generate events and alarms based on changes of state and alarm conditions, and prepare data for operators and information systems.
- A number of servers perform the data processing required for data presentation, historical archiving, alarm processing and engineering changes.
- Clients, such as operator stations and engineering stations, are provided for human interfaces to the control system.
- The communication can be laid out in many different configurations, often including connections to remote facilities, remote operations support and other similar environments.
The main function of the control system is to make sure the production, processing and utility systems operate efficiently within design constraints and alarm limits. The control system is typically specified in programs as a combination of logic and control function blocks, such as AND, ADD and PID. For a particular system, a library of standard solutions such as level control loops and motor control blocks are defined. This means that the system can be specified with combinations of typical loop templates, consisting of one or more input devices, function blocks and output devices. This allows much if not all of the application to be defined based on engineering databases and templates rather than formal programming.
The system is operated from a central control room (CCR) with a combination of graphical process displays, alarm lists, reports and historical data curves. Smaller personal screens are often used in combination with large wall screens as shown on the right. With modern systems, the same information is available to remote locations such as onshore corporate operations support centers.
Field devices in most process areas must be protected to prevent them from becoming ignition sources for potential hydrocarbon leaks. Equipment is explosive hazard classified, e.g., as safe by pressurization (Ex.p), safe by explosive proof encapsulation (Ex.d) or intrinsically safe (Ex.i). All areas are mapped into explosive hazard zones from Zone 0 (inside vessels and pipes), Zone 1 (risk of hydrocarbons), Zone 2 (low risk of hydrocarbons) and Safe Area.
Beyond the basic functionality, the control system can be used for more advanced control and optimization functions. Some examples are:
- Well control may include automatic startup and shutdown of a well and/or a set of wells. Applications can include optimization and stabilization of artificial lift, such as pump off control and gas lift optimization.
- Flow assurance ensures that the flow from wells and in pipelines and risers is stable and maximized under varying pressure, flow and temperatures. Unstable flow can result in slug formation, hydrates, etc.
- Optimization of various processes to increase capacity or reduce energy costs.
- Pipeline management modeling, leak detection and pig tracking.
- Support for remote operations, in which facility data is available to company specialists located at a central support center.
- Support for remote operations where the entire facility is unmanned or without local operators full or part time, and is operated from a remote location.
The function of safety systems is to take control and prevent an undesirable event when the process and the facility are no longer operating within normal operating conditions. Functional safety is the part of the overall safety of a system that depends on the correct response of the safety system response to its inputs, including safe handling of operator errors, hardware failures and environmental changes (fires, lightning, etc.).
The definition of safety is “freedom from unacceptable risk” of physical injury or of damage to the health of people, either directly or indirectly. It requires a definition of what is acceptable risk, and who should define acceptable risk levels. This involves several concepts, including:
- Identifying what the required safety functions are, meaning that hazards and safety functions have to be known. A process of function reviews, formal hazard identification studies (HAZID), hazard and operability (HAZOP) studies and accident reviews are applied to identify the risks and failure modes.
- Assessment of the risk-reduction required by the safety function. This will involve a safety integrity level (SIL) assessment. A SIL applies to an end-to-end safety function of the safety-related system, not just to a component or part of the system.
- Ensuring the safety function performs to the design intent, including under conditions of incorrect operator input and failure modes. Functional safety management defines all technical and management activities during the lifecycle of the safety system. The safety lifecycle is a systematic way to ensure that all the necessary activities to achieve functional safety are carried out, and also to demonstrate that the activities have been carried out in the right order. Safety needs to be documented in order to pass information to different engineering disciplines.
For the oil and gas industry, safety standards comprise a set of corporate, national and international laws, guidelines and standards. Some of the primary international standards are:
- IEC 61508 Functional safety of electrical/electronic/programmable electronic safety-related systems
- IEC 61511 Functional safety - Safety instrumented systems for the process industry sector
A safety integrity level is not directly applicable to individual subsystems or components. It applies to a safety function carried out by the safety instrumented system (end-to-end: sensor, controller and final element).
IEC 61508 covers all components of the E/E/PE safety-related system, including field equipment and specific project application logic. All these subsystems and components, when combined to implement the safety function (or functions), are required to meet the safety integrity level target of the relevant functions. Any design using supplied subsystems and components that are all quoted as suitable for the required safety integrity level target of the relevant functions will not necessarily comply with the requirements for that safety integrity level target.
Suppliers of products intended for use in E/E/PE safety-related systems should provide sufficient information to facilitate a demonstration that the E/E/PE safety-related system complies with IEC 61508. This often requires that the functional safety for the system be independently certified.
Suppliers of products intended for use in E/E/PE safety-related systems should provide sufficient information to facilitate a demonstration that the E/E/PE safety-related system complies with IEC 61508. This often requires that the functional safety for the system be independently certified.
There is never one single action that leads to a large accident. It is often a chain of activities. There are many layers to protect against an accident, and these are grouped two different categories:
- Protection layers – to prevent an incident from happening. Example: rupture disk, relief valve, dike.
- Mitigation layers – to minimize the consequence of an incident.
Example: Operator intervention or safety instrumented system (SIS) An SIS is a collection of sensors, controllers and actuators that execute one or more SIFs/safety loops that are implemented for a common purpose. Each SIF has its own safety integrity level (SIL) and all sensors, controllers and final elements in one SIF must comply with the same SIL, i.e., the end-to-end safety integrity level. The SIS is typically divided into the following subsystems:
- Emergency shutdown system (ESD) to handle emergency conditions (high criticality shutdown levels)
- Process shutdown system (PSD) to handle non-normal but less critical shutdown levels
- Fire and gas systems to detect fire, gas leakage and initiate firefighting, shutdown and isolation of ignition sources
The purpose of an SIS is to reduce the risk that a process may become hazardous to a tolerable level. The SIS does this by decreasing the frequency of unwanted accidents:
-SIS senses hazardous conditions and takes action to move the process to a safe state, preventing an accident from occurring.
-The amount of risk reduction that an SIS can provide is represented by its SIL, which is a measure of the risk reduction factor provided by a safety function. IEC 61508 defines four levels, SIL 1-4, and the corresponding requirements for the risk reduction factor (RFF) and probability of failure on demand (PFD):
The SIL for a component is given by its PFD, safe failure fraction and design to avoid influence of systematic errors.
The emergency shutdown (ESD) and process shutdown (PSD) systems will take action when the process goes into a malfunction or dangerous state. For this purpose, the system maintains four sets of limits for a process value, Low-Low (LL), Low (L), High (H) and High-High (HH). L and H are process warning limits which alert to process disturbances. LL and HH are alarm conditions and detect that the process is operating out of range and there is a chance of undesirable events and malfunction.
Separate transmitters are provided for safety systems. One example is the LTLL (level transmitter Low-Low) or LSLL (level switch Low-Low) alarm for the oil level. When this condition is triggered, there is a risk of blow-by, which means gas leaks out of the oil output and causes high pressure in the next separation stage or other following process equipment, such as a desalter. Transmitters are preferred over switches because of better diagnostic capabilities.
Emergency shutdown actions are defined in a cause-and-effect chart based on a HAZOP of the process. This study identifies possible malfunctions and how they should be handled. On the left of the chart, we have possible emergency scenarios. On top, we find possible shutdown actions. At an oil and gas facility, the primary response is to isolate and depressurize. In this case, the typical action would be to close the inlet and outlet sectioning valves (EV 0153 20, EV 0108 20 and EV 0102 20 in the diagram), and open the blow-down valve (EV 0114 20). This will isolate the malfunctioning unit and reduce pressure by flaring of the gas.
Events are classified on a scale, e.g., 0 to 5, where a full abandon platform/facility shutdown (APS – ESD 0) as the highest level means a complete shutdown and evacuation of the facility. The next levels (ESD1, ESD2), define emergency complete shutdown. The lower levels (e.g., PSD 3, PSD 4 and PSD 5) represent single equipment or process section shutdowns. A split between APS/ESD and PSD is done in large installations because most signals are PSD and can be handled with less strict requirements.
These actions are handled by the emergency shut down system (ESD) and process shut down system (PSD) according to functional safety requirements and standards. Thus, a typical ESD function might require a SIL 3 or even SIL 4 level, while PSD loops could be SIL 2 or SIL 3. Smaller ESD systems, e.g., on wellhead platforms, can be hydraulic or hardwired (non-programmable).
The fire and gas system is not generally related to any particular process. Instead, it divides into fire areas by geographical location. Each fire area should be designed to be self-contained, in that it should detect fire and gas by several types of sensors, and control fire protection and firefighting devices to contain and fight fire within the fire area. In the event of fire, the area will be partially shut off through closure of ventilation fire dampers. A fire area protection data sheet typically shows what detection exists for each fire area, and which fire protection action should be taken in case of an incident.
The type and number of the detection, protection and fighting devices depends on the type of equipment and size of the fire area and will vary for different process areas, e.g., electrical rooms and accommodation rooms.
- Gas detection: Combustible and toxic gas, electro-catalytic or optical (IR) detector
- Flame detection: Ultraviolet (UV) or infra red (IR) optical detectors
- Fire detection: Heat and ionic smoke detectors
- Manual pushbuttons
- Gas-based firefighting, such as CO2
- Foam-based firefighting
- Water-based firefighting: sprinklers, mist (water spray) and deluge
- Protection: Interface to emergency shutdown and HVAC fire dampers.
- Warning and escape: PA systems, beacons/lights, fire door and damper release
A separate package related to fire and gas is the diesel- or electrically-driven fire water pumps for the sprinkler and deluge ring systems.
For fire detection, coincidence and logic are often used to identify false alarms. In such schemes, several detectors in the same area are required to detect a fire condition or gas leakage for automatic reaction. This will include different detection principles, e.g., a fire, but not welding or lightning strike.
Action is controlled by a fire and gas system (F&G). Like the ESD system, F&G action is specified in a cause and action chart called the Fire Area Protection Datasheet. This chart shows all detectors and fire protection systems in a fire area and how the system will operate.
The F&G system often provides supervisory functions, either in the F&G or the information management system (IMS) to handle such tasks as maintenance, calibration or replacement and hot work permits, e.g., welding. Such actions may require that one or more fire and gas detectors or systems are overridden or bypassed. Specific work procedures should be enforced, such as a placing fire guards on duty, to make sure all devices are reenabled when the work permit expires or work is complete.
Piping and instrumentation diagrams (P&ID) show the process. Additional information is needed for the specification of the process control and safety systems design and their control logic. These include: Loop diagram, Instrument datasheet, Cable schedule and Termination list.
The illustration shows one typical format. This is the common format for the NORSOK SCD standard. (Example for the Njord Separator 1 and 2 systems control diagram). Essentially, the P&ID mechanical information has been removed, and control loops and safety interlocks drawn in with references to typical loops.
Supervisory control and data acquisition (SCADA) is normally associated with telemetry and wide area communications, for data gathering and control over large production sites, pipelines, or corporate data from multiple facilities. With telemetry, the bandwidth is often quite low and based on telephone or local radio systems. SCADA systems are often optimized for efficient use of the available bandwidth. Wide area communication operates with wideband services, such as optical fibers and broadband internet.
Remote terminal units (RTU) or local controls systems on wells, wellhead platforms, compressor and pump stations, are connected to the SCADA system by means of the available communication media. SCADA systems have many of the same functions as the control system, and the difference between them is mainly their data architecture and use of communications.
In the oil and gas industry digital oilfield (DOF) is a generic term for new solutions and technologies for operation, work processes and methods that are being made possible by adopting innovations in information technology. Other names such as Integrated Operations (IO), E-Field, Smart Fields, i-Field and Integrated Asset Management are used for the same concept. Intelligent Energy is a general umbrella term adopted by Society of Petroleum Engineers (SPE).
Central to this concept is collaboration between people; where data, information, knowledge shared between a number of parties in digital form. This often supported by technologies such as video conferencing and augmented reality for personnel in remote locations or in the field. In this environment we add solutions for optimal performance, security, maintenance.
Optimal production targets and maximum utilization of production resources are achieved through the use of several sources of information, such as reservoir mass balance calculations and depletion strategies, well test results and use of simulation models. This is made possible by linking skills, data and tools together in real time – independent of location.
Some of the enabler technology areas are:
- A system and communication IT infrastructure
- Applications for remote operations and remote operations support
- Reservoir management and drilling operations
- Production optimization
- Information management systems
- Operation support and maintenance
Solution for data acquisition, modeling and visualization between facility operators and central company experts to provide:
- Drilling simulation and visualization, automatic diagnostics and decision support, real-time measurements while drilling in order to locate the best targets
- Reservoir models based on real-time reservoir data, analysis of 4D seismic, in-situ measurements of changes. On-line integration with well-serviced company data
- Optimization models for increased production, based on in-reservoir properties during production, with decision support incorporated to improve productivity
Optimizing the production or improving productivity is a complex problem. In addition to the production optimization of the downhole, subsea and topside process, one has to consider operational costs, hardware damage, reservoir performance, environmental requirements and operational difficulties within each well and/or topside. To further complicate optimization, the individual challenges will change over time, e.g., reservoir behavior changes as an effect of depletion, shutdown of wells due to slugging, failed sensors and the change of efficiencies within the topside process system. Some of the applications included in production optimization are:
- Flowline control to stabilize multiphase flow in gathering systems, risers and flow lines.
- Well control that will stabilize and optimize gas lift and naturally flowing wells. This application should prevent flow and pressure surges while maintaining minimal backpressure and maintain maximum production as well as continuing production at the optimum lift gas rate.
- Gas-lift optimization is provided to ensure the best possible distribution of lift-gas between gas lifted wells.
- Slug management helps mitigate variations in inflow impact. The separation and hydrocarbon processing during startup, upset and normal operation.
- Well monitoring systems (WMS) are used to estimate the flow rates of oil, gas and water from all the individual wells in an oil field. The real-time evaluation is based on data from available sensors in the wells and flow lines.
- Hydrate prediction tools help to avoid hydrate formation, which may occur if a subsea gathering system is allowed to cool down too much before the necessary hydrate preventive actions are performed.
- Optimal operation is defined by a set of constraints in the wells and production facilities. A constraint monitoring tool monitors the closeness to all constraints. This provides decision support for corrective actions needed to move current operation closer to its true potential.
- Advanced control and optimization solutions to improve the performance of product quality control, while adhering to operating constraints. This is typically done with two technologies: model predictive control to drive the process closer to operating targets, and inferential measurement to increase the frequency of product quality feedback information.
- Tuning tools are designed to optimize and properly maintain the optimal setting of control loops in the process automation system.
An asset optimization (AO) system reduces costly production disruptions by enabling predictive maintenance. It records the maintenance history of an asset and identifies potential problems to avert unscheduled shutdowns, maximize up-time and operate closer to plant production prognoses. This functionality supports maintenance workflow as the AO system communicates with a maintenance system, often denoted as a computerized maintenance management system (CMMS).
Computerized maintenance management system
Condition monitoring includes both structural monitoring and condition monitoring for process equipment such as valves and rotating machinery. For structural monitoring, the devices are corrosion meters (essentially plates that corrode, so that corrosion may be metered), tension force meters and free swinging strings. These statistics are logged to a central structure condition monitoring system, to show what forces are acting against the installation, and the effect those forces are having.
Condition monitoring of machinery is generally used for large rotating apparatus, such as turbines, compressors, generators and large pumps. Input devices are vibration meters, temperature (bearing, exhaust gases, etc.), as well as the number of start/stops, running time, lubrication intervals and over-current trip-outs. For other process equipment, such as valves, the system can register closing times, flow and torque. A valve that exhibits a negative trend in closing time or torque ("stiction") can be diagnosed. The maintenance trigger is the mechanism whereby field device or equipment monitor resident information, in the form of digital status signals or other numerical or computed variables are interpreted to trigger a maintenance request. A work order procedure is then automatically initiated in the CMMS. Maintenance support functionality will plan maintenance, based on input from condition monitoring systems, and a periodic maintenance plan. This will allow the system to schedule personnel for such tasks as lubrication or cleaning, and plan larger tasks such as turbine and compressor periodic maintenance.
A specific information management system (IMS) can be used to provide information about the operation and production of the facility. This can be a separate system, or an integral part of the control system or SCADA system.
For oil and gas, IMS functionality includes:
- Oil & gas production reporting
- Safety management
- Operator support
- Overall systems integrated and external
- Historical data, including post failure "flight recorder" data
Some of the applications provided by an IMS system may be:
- Drilling data acquisition and drilling data logging
- Electronic shift logbook
- Operator procedures
- Chemical injection
- Chemical consumption
- Laboratory analysis registration
- Alarm and incidents overview
- Alarm Statistics
- Valve leakage test
- Transmitter surveillance
- Run time monitoring
- Block log
- Production plan
- SIL statistics report
- Subsea valve signatures
- Production overview and prognosis
- Valve verification
- ESD/PSD verification, including shutdown analysis
- Data export
- Data browser tool
- Historical data and current trend
- Well test
- Daily production report with metering data
- Volumes in storage cells and consolidation of produced stored and dispatched volumes.
- Environmental reports
- Polynomial allocation (oil/gas/water) based on well test results
Training simulators are used to provide operator training in a realistic plant training environment. They use the actual control and safety applications of the plant, running on operator stations. Plant models simulate the feedback from the plant in real time, or in fast or slow motion. Training simulator applications include functions for backup and reload, including recreation of historical information and snapshots. Offsite training facilities are often connected (read only) to the live plant to provide information from the real operating situation.
Power can be provided from mains power, local gas turbines or diesel generator sets. Large facilities have high power demands, from 30 MW up to several hundred MW. There is a tendency to generate electric power centrally and use electric drives for large equipment rather than multiple gas turbines, as this decreases maintenance and increases uptime.
The power generation system on a large facility is usually several gas turbines driving electric generators, 20-40 MW each. Exhaust heat is often needed in the main process.
Voltage levels for high, medium and low voltage distribution boards are 13-130 kV, 2-8 kV and 300-600 V respectively. Power is generated and exchanged with mains or other facilities on the HV distribution board. Relays are used for protection functions.
|Electrical Single Line Diagram|
A separate emergency power switchboard provides power for critical equipment. It can be powered from a local emergency generator if main power is lost. Computer systems are fed from an uninterruptible power system (UPS) with batteries, connected to the main or emergency switchboard.
A power management system is used for control of electrical switchgear and equipment. Its function is to optimize electricity generation and usage and to prevent major disturbances and plant outages (blackouts). The power management system includes HV, MV and LV low voltage switchgear plus MCCs and emergency generator sets. Functions include prioritization of loads, emergency load shedding (closing down of nonessential equipment) and prestart of generator sets (e.g., when additional power to start a big crude pump is required).
Large rotating equipment and generators are driven by gas turbines or large drives. Gas turbines for oil and gas production are generally modified aviation turbines in the 10-25 MW range. These require quite extensive maintenance and have a relatively low overall efficiency (20-27%, depending on application). Also, while a turbine is relatively small and light, it will usually require large and heavy support equipment such as large gears, air coolers/filters, exhaust units, and sound damping and lubrication units.
Therefore use of large variable speed drives is becoming more common. For pumps on subsea facilities, this is the only option. For use on remote facilities, High voltage DC transmission and HV motors can be used, from a main facility or power from shore. This avoids local power generation at each facility and contributes to low manning or remote operation.
Flare subsystems include flare, atmospheric ventilation and blow-down. The purpose of the flare and vent systems is to provide safe discharge and disposal of gases and liquids resulting from:
- Spill-off flaring from the product stabilization system. (oil, condensate, etc.)
- Production testing
- Relief of excess pressure caused by process upset conditions and thermal expansion
- Depressurization, either in response to an emergency situation or as part of a normal procedure
- Planned depressurization of subsea production flowlines and export pipelines
- Venting from equipment operating close to atmospheric pressure (e.g., tanks)
The systems are typically divided into a high pressure (HP) flare and a low pressure (LP) flare system. The LP system is operated slightly above atmospheric pressure to prevent atmospheric gases such as oxygen flowing back into the vent and flare system and generating a combustible mixture. With low gas flow, inert gas is injected at the flare nozzle to prevent air ingress.
Traditionally, considerable amounts of hydrocarbons have been more or less continuously flared. In these cases, a continuously burning pilot is used to ensure ignition of hydrocarbons in the flare.
Stronger environmental focus has eliminated continuous flaring and the pilot in many areas. Vapors and flare gas are normally recovered, and only in exceptional situations does flaring occur. To avoid the pilot flame, an ignition system is used to ensure safe ignition, even when large volumes are discharged. One patented solution is a "ballistic ignition" system which fires burning pellets into the flare gas flow.
A large volume of compressed air is required for control of pneumatic valves and actuators, tools and purging of cabinets. It is produced by electrically-driven screw compressors and further treated to be free of particles, oil and water.
The heat, ventilation and air conditioning system (HVAC) feeds conditioned air to the equipment and accommodation rooms, etc. Cooling and heating is achieved by water-cooled or water/steam-heated heat exchangers. Heat may also be taken from gas turbine exhaust. In tropical and sub-tropical areas, cooling is achieved by compressor refrigeration units. In tropical areas, gas turbine inlet air must be cooled to achieve sufficient efficiency and performance. The HVAC system is usually delivered as one package, and may also include air emissions cleaning. Some HVAC subsystems include:
- Cool: cooling medium, refrigeration system, freezing system
- Heat: heat medium system, hot oil system
One function is to provide air to equipment rooms that are secured by positive pressure. This prevents potential influx of explosive gases in case of a leak.
8.7 Water systems
For smaller installations, potable water can be brought in by supply vessels or tank trucks.
For larger facilities, it is provided on site by desalination of seawater though distillation or reverse filtering. Onshore potable water is provided by purification of water from above or below ground reservoirs.
Reverse filtering or osmosis requires a membrane driving pressure of about 7000 kPa/1 PSI of pressure per 100 ppm of solids dissolved in the water. For seawater with 3.5% salt, 2.5 MPa, 350 PSI is required.
Seawater is used extensively for cooling purposes. Cold water is provided to air compressor coolers, gas coolers, main generators and HVAC. In addition, seawater is used for the production of hypochlorite (see chemicals) and for fire water. Seawater is treated with hypochlorite to prevent microbiological growth in process equipment and piping.
Seawater is sometimes used for reservoir water injection. In this case, a deaerator is used to reduce oxygen in the water before injection. Oxygen can cause microbiological growth in the reservoir. The deaerator is designed to use strip gas and vacuum.
Ballast systems are found on drilling rigs, floating production ships, rigs and tension leg platforms (TLP). The object is to keep the platform level at a certain depth under varying conditions, such as mode of operation (stationary drilling, movement), climatic conditions (elevation of rig during storms), amount of product in storage tanks, and to adjust loading on TLP tension members.
Ballasting is accomplished by means of ballast tanks, pumps and valves, which are used in combination with position measuring instruments and tension force meters (TLP) to achieve the desired ballasting.
If fresh water is produced, it can be used as ballast to avoid salt water. Additionally, if ballast water has become contaminated from oil tanks, it must be cleaned before discharge at sea.
A wide range of chemical additives are used in the main process. Some of these are marked in the process diagram. The cost of process chemical additives is considerable. A typical example is antifoam, where a concentration of about 150 ppm is used. With a production of 40,000 bpd, about 2,000 liters (500 gallons) of antifoam can be used. At a cost of 2 € per liter, ($10 per gallon) in bulk, antifoam alone will cost some 4,000 € or $5,000 per day.
The most common chemicals and their uses are:
Scale inhibitor - The well flow contains several different contaminants, such as salts, chalk and traces of radioactive materials. As pressure and temperature change, these may precipitate and deposit in pipes, heat exchangers, valves and tanks. As a result, they may clog up or become stuck. The scale inhibitor prevents the contaminants from separating out. Scale or sediment inhibitor is applied to wellheads and production equipment.
Emulsion breaker - Water and oil cannot mix to form a true solution. However, small drops of oil can disperse in water and small water drops can disperse in oil. Such systems are called emulsions; oil-in-water (o/w) and water-in-oil (w/o), respectively. The drops are held suspended by electrostatic repulsion, and will form a distinct layer between the oil and water. Sand and particles are normally carried out by the water extracted in water treatment. However, the emulsion can trap these particles and sink to the bottom as a sticky sludge that is difficult to remove during operation. Although the emulsion layer will eventually break down naturally, it takes time, too much time. An emulsion breaker is added to prevent formation and promote breakdown of the emulsion layer by causing the droplets to merge and grow.
Antifoam - The sloshing motion inside a separator causes foaming. This foam covers the fluid surface and prevents gas from escaping. Foam also reduces the gas space inside the separator, and can pass the demister and escape to the gas outlet in the form of mist and liquid drops. An antifoam agent is introduced upstream of the separator to prevent or break down foam formation by reducing liquid surface tension.
Polyelectrolyte - Polyelectrolyte is added before the hydrocyclones and causes oil droplets to merge. This works by reducing surface tension and water polarity. This is also called flocculation, and polyelectrolyte flocculants allow emissions to reach 40 ppm or less.
Methanol (MEG) - Methanol or monoethylene glycol (MEG) is injected in flowlines to prevent hydrate formation and prevent corrosion. Hydrates are crystalline compounds that form in water crystalline structures as a function of composition, temperature and pressure. Hydrates appear and freeze to hydrate ice that may damage equipment and pipelines.
For normal risers, hydrates form only when production stops and the temperature starts to drop. Hydrate formation can be prevented by depressurization which adds to startup time, or by methanol injection.
On longer flowlines in cold seawater or Arctic climates, hydrates may form under normal operating conditions and require continuous methanol injection. In this case, the methanol can be separated and recycled.
Hydrate prediction model software can be used to determine when there is a risk of hydrate formation and to reduce methanol injection or delay depressurization.
TEG - Triethyleneglycol (TEG) is used to dry gas (see the chapter on scrubbers and reboilers).
Hypochlorite - Hypochlorite is added to seawater to prevent growth of algae and bacteria, e.g., in seawater heat exchangers. Hypochlorite is produced by electrolysis of seawater to chlorine. In one variant, copper electrodes are used, which adds copper salts to the solution that improves effectiveness.
Biocides - Biocides are also preventive chemicals that are added to prevent microbiological activity in oil production systems, such as bacteria, fungus or algae growth.
Particular problems arise from the growth of sulfate reducing bacteria that produces hydrogen sulfide and clogs filters. Typical uses include diesel tanks, produced water (after hydrocyclones), and slop and ballast tanks.
Corrosion inhibitor - Corrosion inhibitor is injected in export pipelines and storage tanks. Exported oil can be highly corrosive, leading to corrosion of the inside of the pipeline or tank. The corrosion inhibitor protects by forming a thin film on metal surfaces.
Drag reducers - Drag reducers improve the flow in pipelines. Fluid near the pipe tries to stay stationary while fluid in the center region of the pipe is moving quickly. This large difference in fluid causes turbulent bursts to occur in the buffer region. Turbulent bursts propagate and form turbulent eddies, which cause drag.
Drag-reducing polymers are long-chain, ultra-high molecular weight polymers from 1 to 10 million u), with higher molecular weight polymers giving better drag reduction performance. With only parts-per-million levels in the pipeline fluid, drag-reducing polymers suppress the formation of turbulent bursts in the buffer region. The net result of using a drag-reducing polymer in turbulent flow is a decrease in the frictional pressure drop in the pipeline by as much as 70%. This can be used to lower pressure or improve throughput.
Traditionally, all electronic systems that do not fall naturally under the electrical or automation bracket are grouped as telecommunication systems. As such, the telecom system consists of a variety of subsystems for human and computer wired and wireless communications, monitoring, observation, messaging and entertainment.
Some of the main systems are:
- Public address and alarm system/F&G integration
- Access control
- Drillers talk-back system
- UHF radio network system
- Closed circuit TV system
- Mandatory radio system
- Security access control
- Meteorological system/sea wave radar
- Telecom antenna tower and antennas
- PABX telephone system
- Entertainment system
- Marine radar and vessel movement system
- Office data network and computer system
- Personnel paging system
- Platform personnel registration and tracking system
- Telecom management and monitoring system
- Ship communication system/PABX extension
- Radio link system
- Mux and fiber optical terminal equipment
- Intrusion detection
- Satellite systems
The systems are often grouped in four main areas:
1. External communication
External communication systems interconnect installations and link them to the surrounding world – carrying voice, video, process control and safety system traffic necessary to allow uninterrupted safe facility operations. With today's solutions and technologies, distance is no longer an issue and bandwidth is available as needed, either on demand or fixed. This opens up new ideas and opportunities to reduce operational costs in the industry.
2. Internal communication
Internal telecommunication systems play a major role in supporting day-to-day operations and improving the working environment. They allow any type of system or operator to communicate within the facility, enabling reliable and efficient operations.
3. Safety and Security Systems
Safety and Security Systems are used for safeguarding personnel and equipment in, on and around an installation according to international rules and standards. These systems are often adapted to meet local/company safety requirements. For best possible performance and flexibility, safety systems are closely integrated with each other, as well as to other internal and external systems.
4. Management and utility systems
System and personnel well-being are supported by a number of management and utility systems that are intended to ease and simplify telecom maintenance and operations.