On deciding to upgrade and expand its Ruwais refinery, the Abu Dhabi National Oil Company realized that an increase in power and water supply would be needed. The solution is to build a power and desalination plant at the refinery`s general utilities plant, adding 500 MW of power and 30 000 m3 per day of water to the site`s current capabilities, enabling throughput at the refinery to be more than doubled.
ABB Power Generation Ltd.,
Paolo Trabucchi, Paolo Guizzetti,
ABB Sadelmi Spa,
In 1995 the Abu Dhabi National Oil Company Ltd. (Adnoc) initiated the front end engineering and design of its Ruwais Refinery Expansion project at the Ruwais Industrial Complex in Abu Dhabi. It needed to expand all areas of the complex, including shipping facilities and the General Utilities Plant (GUP), in order to increase refinery throughput, and also wanted to install an advanced control system to integrate the separate parts of the system.
The expansion project includes the construction of a condensate processing facility, an ethylene dichloride plant and further projects to enhance the refining and petrochemical capacities of the refinery. An essential part of this expansion scheme, for which electrical power and water is needed, involves the addition of a gas-fired power and desalination plant to the refinery`s General Utilities Plant.
On March 24 1998, Adnoc awarded ABB a $600 million turnkey order for the GUP expansion project. ABB will add a 500 MW cogeneration plant to the complex and desalination units totalling 30 000 m3/day in capacity. The project will expand power generating capacity at the site to 700 MW, and full commercial operation is scheduled for the end of 2000.
The Ruwais Refinery, one of the two large national refineries, is part of the Ruwais Industrial Complex located on the Arabian Gulf in the Emirate of Abu Dhabi approximately 250 km west of Abu Dhabi City. The existing refinery consists of a combination of hydroskimmer and hydrocracker facilities processing Abu Dhabi crude oils to produce conventional products to meet some of the United Arab Emirates` (UAE) local demand and refined product exports. The refinery was designed to process around 120 000 barrels per day of crude oil, and currently operates at a throughput of 133 000 barrels per day.
ABB will supply four GT13E2 gas turbines and generators along with the associated heat recovery steam generators (HRSGs) and the desalination plant. It will also provide the overall power plant control system, the balance of plant equipment and complete engineering, installation and commissioning work. When complete late next year, the power and desalination plant will allow throughput at the refinery to be increased to 550 000 barrels per day.
The new power and desalination plant will be arranged around four ABB 13E2 gas turbines rated at 160 MW at ISO conditions with 210 MVA ABB air-cooled generators, and two 15 000 m3/day desalination trains. The gas turbines are composed of 21-stage subsonic compressors with variable inlet guide vanes mounted on single welded shafts with the turbine stages. They are equipped with ABB`s clean combustion EV burners placed in single annular combustion chambers. The gas turbine will run on natural gas as main fuel and on oil No.2 as a backup fuel. In the latter case water injection to obtain low NOx emission levels is likely.
A new gas receipt and pressure regulation station will lead the fuel gas from the refinery to the gas turbines, while the back-up diesel oil is stored in a new tank and forwarded to the generators when needed. The gas turbines will be controlled by ABB`s Advant-based Egatrol gas turbine control system.
Three single pressure, horizontal gas path, natural circulation, top-supported HRSGs will be connected to the gas turbine exhaust systems over diverter dampers. Thus three of the four gas turbines will be able to run in combined cycle mode, while one gas turbine is foreseen to run in simple cycle mode. The ABB Combustion Engineering HRSGs are designed to produce superheated steam at 60 kg/s at 20 bar[a] and 235 degreesC for the desalination units.
The diverter damper positions will be adjustable and controlled in order to maintain the steam pressure level in the headers within a desired range. Thus the thermal process will be, to a certain extent, de-coupled from the electrical process. Note that in conventional combined cycle power plants the diverter damper positions are either open or closed and no modulating facilities on the intermediate position are foreseen during normal operation.
The steam distribution system ensures the supply and distribution of the steam on three pressure levels: 20 bar[a] header, 13 bar[a] medium pressure (MP) header and 3.5 bar[a] low pressure (LP) header. The main 20 bar[a] header is connected and fed directly by the main steam line coming from the three HRSGs. It provides the stripping steam for the boiler feedwater deaerator tower and feeds the MP and LP steam headers. The MP steam header feeds the vacuum system ejectors of the desalination units, and the LP steam header feeds the heat input sections (brine heaters) of the desalination units.
The desalination units are based on the principle of multi-stage flash evaporation (MSFE) with brine recirculation. Seawater is preheated in the heat reject sections of the desalination units and then mixed to the recirculating brine.
The brine-seawater mix flows through the condensing tubes of the heat recovery flash chambers, heating up until reaching the top brine temperature. The brine then enters the first of 12 heat recovery flash chambers. A fraction of the brine flashes to vapour, while the remaining part is cooled down to the saturation temperature prevailing in the chamber.
The vapour condenses at the condensing tubes, and the distilled water is led away over trays. The brine enters the next flash chamber, where the pressure is slightly lower, thus flashing at progressively lower temperature, until the concentrated brine reaches the heat reject stages, terminating the cycle by being mixed to fresh seawater.
The two desalination trains provide the distilled water according to the consumption foreseen. Each train is designed to operate with brine recirculation at a top brine temperature (TBT) of 105 degreesC and with a distillate water production of 15 000 m3/day. Part of the water is stored in two new 25 000 m3 distilled water tanks, which are added to three existing ones of the same storage capacity.
The seawater required for the desalination process is forwarded by three 50 per cent seawater centrifugal pumps of vertical, wet pit type, driven by 11 kV electric motors. Each of these pumps has a design flow rate of 13 000 m3/h at a design head of 32 m. Further seawater pumps will be installed to cover additional needs of future projects.
The scope of the plant also covers a pump house placed at the end of a sea water intake channel which will be protected by a breakwater structure. The shape of the breakwater has been designed based on extensive scaled model tests, confirming the adequate hydraulic behaviour of the new structure. For seawater return a new outfall channel will be constructed. ABB`s turnkey contract also includes the necessary balance of plant equipment such as water treatment plant and tankage, chlorination and dosing, instrument/service air plant and oily water treatment facility.
The expansion project also includes the electrical system of the Ruwais Refinery Complex, which is an electric island grid disconnected from the national grid. A new 132 kV double busbar system with two sections of ABB Calor Emag Gas Insulated Switchboards (GIS), each fed by two generators over corresponding step-up transformers, will feed two double bus bar 33 kV systems and various new 11 kV systems. The 132 kV GIS will be placed indoors. The new bus bars systems will be connected to existing ones, which in turn will be fed by existing gas turbine and steam turbine generators.
Existing and new generators are to be centrally controlled by the Network Control System (NCS). The fact that the electrical grid operates as an island grid, and thus is sensitive to the loss of power generating units that could affect the frequency and voltage grid behaviour, represents the most important operational constraint which had to be considered when elaborating possible operational modes.
When the new plant was designed, the base criteria was to match power capacity with the expansion plan of the refinery. The power coverage had to be such that the total installed power of the GUP plant would always be sufficient even if the largest of the existing and one of the new generators were out of order. Furthermore the new plant has to be able to provide sufficient distilled water in the desalination units to cover predicted future needs.
The way to run these units is, however, strongly influenced by the necessity of net stability. Sound frequency and voltage levels must always be maintained without foreseeing load shedding.
To determine possible operational modes, state-of-the-art engineering tools were applied for calculating grid stability. The grid stability studies identified from the electrical point of view which combination of generators and load could allow safe operation, guaranteeing sufficient spinning reserves, meaning that the island net would remain in safe operation even when one generator would trip.
Water production capacities were then estimated based on the given generator loads, diverter damper characteristics, HRSG performance curves and MSFE (desalinators) steam demand curves. A steam system pressure controller was developed which uses instantaneous steam header pressure, actual steam generation and theoretical steam generation as input variables to determine the required diverter damper position. Dynamic steam system calculation verified stable transient behaviours of the steam system in case of upset situations. Combining the information from the stability studies and from the thermal process analysis a recommended operation strategy has been identified.
The overall plant control system is composed of two basic systems dedicated to the electrical and process side of the plant. The existing NCS controls the electrical part of the plant and will be extended to include the new generators. The existing distributed control system (DCS) is dedicated to the control and monitoring of the thermo-hydraulic process and will be extended to include the new plant.
Furthermore each new gas turbine will be controlled by its own control system which will interface with the DCS to allow gas turbine operation from the central control room. The hierarchy of these different control systems can be represented as follows:
Electrical: On the electrical system, the main variables to be kept under control are the frequency and the main bus voltage (mainly 132 kV, 33 kV, 11 kV). Once the frequency is constant there is a proper balance between produced power and consumed MW. A disturbance to the frequency is an indication of a power imbalance and has to be rectified by the control system. Similarly, voltage control ensures a balance between generated and consumed reactive power.
Two different kinds of frequency controls will be combined to achieve the frequency control in all conditions at Ruwais: `primary` and `secondary` control.
The primary control will be implemented in each machine governor. Its purpose is to rapidly adjust the generated power when major frequency upsets take place. The secondary control will be implemented in the NCS, which is connected to all the machine governors. The NCS will keep the frequency modulating of the loads of the connected machinery constant, balancing the generated power with the power demand and ensuring frequency stable conditions.
Each governor will receive the desired power set point from the NCS and will perform the control action throttling its control devices (e.g. inlet guide vane and fuel control valve). Additionally, in case of a large frequency upset, the governors will react immediately to change the turbine load. The NCS, via these functions, will keep constant the frequency net modulating the load of the connected generators. The Ruwais complex is considered as one unique island and the load modulation will be performed according to a strategy fixed by the operators.
The voltage control on the main busses of the new system (132 kV, 33 kV, 11kV) will be performed using the AVR/exciter of synchronous generators (new units) and on load tap changers of transformers (new units).
Process: On the thermo-hydraulic process side, the main variables to be kept under control are the header steam pressures, HRSG drum level, deareator and feedwater tank pressure, feedwater tank level and brine heater temperatures.
The pressure control will be achieved by a master controller which, according to the pressure error on the steam header, will modulate the flue gas through the HRSG by means of diverter dampers. Each damper can be connected and disconnected to the master. In order to anticipate steam pressure variation due to disturbances, two additional parameters will be used as a feedforward by the master to generate the position demand:
Steam produced by the HRSG, (based on the gas turbines` load and damper positions) to anticipate disturbances on the steam generation side.
Actual value of total generated steam to react in advance to the disturbances on the steam consumption side (e.g. distiller fast unloading).
The control loop can be summarized as follows: the steam header pressure (process variable) is compared to the set point in order to calculate the pressure error that is used by the Pressure Master Controller to compute the pressure contribution. The complete demand is computed adding the actual steam flow produced by the HRSG and subtracting the forecast of the actual producible steam flow. This last flow is computed on line, and represents the expected amount of steam which are producible by all the HRSGs at the actual condition of gas turbine load and diverter damper position. This obtained value is fed to a cascaded PI control that will generate finally the damper position demand.
In order to minimize the disturbances induced by the electrical load of the gas turbine in combined cycle (GTCC) on the HRSG steam production, the GTCC will normally be set at the NCS level as `not regulating`, which means that they will not participate on the secondary frequency control level.
In addition, an abnormal condition manager controller has been designed, which will minimize the pressure upset in case of a trip of a major component. A dynamic simulation model of plant and control functions has been used to analyse the whole process response in normal and abnormal conditions, verifying the plant control behaviour.
In contrast to the increasing tendency to build completely standardized power plants set on greenfield sites, the Ruwais power plant is a custom designed and built power and desalination plant. The plant is fully integrated into an existing technological environment, from the process point of view as well as from the electrical and control point of view.
Figure 3. Multi-stage flash evaporation desalination units
Figure 4. When complete at the end of 2000, the expansion project will expand power generating capacity at the Ruwais site to 700 MW