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Mwaku W.M., Kornilov V.Y.
APPLICATION OF AUTOMATIC CONTROL SYSTEM ENGINEERING PRINCIPLES IN THE CRUDE OIL PREPARATION AND TRANSPORTATION
В статье анализируется возможность применения инженерных решении системы автоматического управления подготовки и транспортировки сырой нефти. Показаны сильные и слабые стороны имеющихся продуктов, их перспективы и вектор дальнейшего развития технологий переработки, хранения и транспортировки сырой нефти и ее фракции с целью наиболее эффективного использования.
Ключевые слова: сырая нефть, подготовка и транспорт, системы автоматического управления, нефтеперерабатывающая промышленность.
Petroleum is composed of alkanes, naphthenes and aromatic compounds. Figure 1 presents a model of the distribution of various compounds in petroleum. Alkanes, or paraffins, (CnH2n+2) are saturated hydrocarbons composed entirely of straight or branched alkyl chains. Naphthenes are saturated hydrocarbons ring structures that may have varying degrees of alkyl substitution. Aromatic hydrocarbons contain one or more conjugated five - to six-carbon member rings, such as benzene or naphthalene and may be bonded to naphthenic rings and alkyl side chains. Heteroatoms are atoms other than carbon and hydrogen found in crude oil, such as nitrogen, oxygen, sulfur and met-als, such as nickel and vanadium [1].
1. CRUDE OIL COMPOSITION
Vacuum
Residue
Boiling Point
Fig.1. Distribution of different compound types found in petroleum. The proportion of saturated hydrocarbons (paraffins) decreases as the molecular weight increases or at higher boiling point
2. CRUDE OIL REFINING
Refinery processes can be classified into three general types: separation, where the feedstock is divided into various fractions; conversion, where economically viable products are produced through alteration of the feedstock constituent molecules; and finishing, where product stream are purified. Figure 2 shows a schematic flow diagram of a typical oil refinery. Crude oil is first sent to a desalter where clean water removes any dissolved salts. Distillation separates crude oil is then separated by distillation into straight-run fractions which are then characterized based on boiling point [2].
Fig.2. Schematic flow diagram of a typical oil refinery (Wikipedia 2010)
3. DISTILLATION
Heteroatom composition varies greatly between fractions and determines the amount and severity of conversion that is required for each distillate cut. Distillation limits the molecular-weight range of each compound type and therefore can contain only a limited range of chemical species. First, crude oil is heated in a distillation column at atmospheric pressure and different products boil off at different temperatures. Light fractions such as naphtha and liquid petroleum gases are removed at the lowest temperatures and collect at the top of the column and higher boiling species, such as heavy fuel oil and residues, are recovered at high temperatures (< 1000 °F) and settle to the bottom. The residue from the atmospheric distillation is then sent to a vacuum distillation unit for increased recovery of lighter fractions. Vacuum is pulled from the top of the tower through a steam ejector or by vacuum steam. The overhead stream, called light vacuum gas oil, consists of lube base, heavy fuel or can be fed into a conversion unit; heavy vacuum gas oil is pulled from a side unit on the tower and the vacuum residue can be sent to a coker or visbreaking unit for further processing or left simply as asphalt. Figure 3 shows a general schematic of a typical crude oil distillation [3].
Fig.3. Distillation unit of a typical oil refinery. Further separation, such as cokers, hydrocrackers of fluid catalytic cracking units (FCC) is often performed downstream in separate conversion units
4. TRANSPORTATION AND STORAGE
4.1. CONTROL AND MONITORING OF PUMPS FOR SEPARATION
STATIONS
After a successful drilling, crude oil springs up from an underground reservoir and is immediately transported by pipeline to a 3-phase separation station. The separation station works like a front-end processor that separates the crude oil into oil, gas, and water before forwarding the fluids downstream to the next processing station [1].
Data from numerous valves and separation devices in the station must be collected and monitored over the network. One option is to daisy chain different devices in separate sectors to a fiber redundant ring topology, and use PLCs or remote I/Os to collect data.
Wireless Ethernet is an alternative to a wired network. By installing an AP (Access Point) at a high elevation at each station, data can be broadcasted over the wireless network to the control site. Wireless transmission efficiently eliminates cabling hassles. However, bandwidth is a critical factor that needs to be taken into careful consideration when deploying a wireless infrastructure [2].
Using low bandwidth or transmitting video data can slow down your transmissions, and as a result affect the accuracy of data and make real-time control impossible [1].
Fig.4. Station Wireless Network
5. PIPELINE MONITORING
When oil and gas are separated, the crude oil is transported to remote storage sites or the nearest harbour area by pipelines or tankers. Pipelines can cover enormous distances and sometimes even cross the borders between countries. “Pipeline monitoring” now means providing easy-to-use and real-time management systems to decrease the risk of explosion, leaking, and sabotage, and as such is now an extremely critical issue in the oil and gas industry.
True pipeline monitoring is much easier to attain if it is possible to set up an optical fiber network infrastructure. In this case, monitoring devices can be installed directly alongside the pipeline. However, using long distance wireless transmission, such as GSM/GPRS, is a viable alternative if it is not feasible to set up a fiber infrastructure. In this case, the monitoring system connects directly to serial-based or Ethernet-based devices and data is transmitted through the GSM/GPRS network [5].
Fig.5. Pipeline monitoring
6. TANK/STORAGE MONITORING
Crude oil and natural gas are transported downstream for storage and further processing. Crude oil is often stored in either subterranean or harbour area storage tanks; natural gas is either liquefied for storage or transported to mid or downstream plants. These storage utilities or transport pipelines need to be monitored cautiously to prevent leaks and excessive gas tank pressure, which endanger the plant’s safety.
Data including fluid volume, pipe pressure and temperature are critical information. Tanks, valve and pressure pumps in the storage sites are frequently connected and monitored through fiber mode or Ethernet switches to the central management systems [5].
Fig.7. Oil Tank
7. OIL REFINERIES
7.1. DISTRIBUTED CONTROL SYSTEMS
Suffice it to say that the refining process, which converts complex molecules into substances with simpler chemical structures, is extremely complicated, in part because a variety of different processes are required to refine the different end-substances. The distributed control system, or DCS for short, is the main control system used in the refining process to manage a plant’s output and performance. The DCS is a vital part of the plant’s architecture, and as such the system cannot be allowed to shut down unexpectedly during operation. The boiler, for example is a typical DCS application that creates heat and steam, and also handles the processing and draining of water. The complete production process cannot be interrupted requires extremely stable operation— 24 hours a day, 7 days a week.
One of the biggest fears of plant managers is that the plant’s DCS will
shut down because of a failure at a single seemingly inconsequential point in the system. For this reason, redundant systems are an essential part of the design of any DCS. All devices and facilities (including the main and backup control stations, main and backup controllers, hot and hot standby devices, dual LANs, dual communication modules and interfaces, and dual detecting devices) must be backed up by a redundant system. In some cases, multi-redundant systems are required to realize higher system reliability. For example, when Ethernet is used as the communication backbone, it is common to set up two independent networks, which we could call LAN 1 and LAN 2. When the default network crashes, devices can continue to transmit data through the backup network. In the same respect, all controllers, servers and HMI/SCADA systems are always equipped with dual communication interfaces, and data is transmitted simultaneously through both interfaces to prevent data loss if one of the networks goes offline [2].
8. METERING SYSTEM
A metering or valuation system controls a refinery’s performance and the use of materials. Flow rate, flow speed, and flow density measurements are critical to maintaining the safety and efficiency of the plant. All of this data is collected and transmitted through the metering system to the server host where it is compiled and analyzed. The data must be available to the DCS in real-time (keep in mind that for Ethernet networks, “real-time” implies a small time delay) to optimize the output and operation of the plant.
As with the DCS, the metering system also requires a redundant backup architecture to ensure that cost calculations for the refinery are accurate. Refinery costs are based on data collected by the metering system. The system is normally equipped with at least two redundant backup solutions to guarantee 100% data accuracy and prevent unexpected errors. The flow computer is one of the system’s essential components. It can be regarded as a DCS sub-system that intercepts fluid data and transmits the data to a DCS centre to facilitate the operation of the plant [3].
Fig.8. Metering System
9. DETECTING GAS AND LIQUID LEAKS
An auxiliary system in refinery plants is used to detect gas and liquid
leaks.
Although the auxiliary system is not directly involved with production, it forewarns plant and field operators of potentially unsafe leaks in the pipes used to transport gases and liquids. The leak detection system is simpler than the DCS. Leak detectors are connected by a multi-mode fiber optic network, whereas a SCADA system at the control center monitors devices through the Modbus protocol. When a leak is detected, the central control system immediately notifies field operators to take precautions, and may even shut down the system. To ensure the quickest possible response, it is essential to use appropriate real-time monitoring and management devices [5].
Active alarm systems have emerged as the newest trend for providing comprehensive and critical data for leak detection management. Active Ethernet I/O products can instantly report events via e-mail, SMS, or real-time messages. By informing operators of the situation in the field in real-time, the response time can be cut substantially [1].
Fig.9. Gas and Liquid Leak Detection
10. CONCLUSION
The reliable procurement and delivery to market of oil and natural gas is a critical issue given the global economy’s continued dependence on these resources. Oil and gas operations are highly complex and often take place under harsh environmental conditions. Each stage of oil and gas production involves a great deal of industrial automation and requires reliable networks to provide data collection, PLC monitoring, and environmental control. Industrial Ethernet can play an important role in oil and gas automation during the drilling, transporting, storing, refining, and even exporting phases of production [4].
References
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