Over the last two decades, South Korea achieved rapid development due to growth in the industrial sector and sustained activity in both residential and commercial sectors. Companies like Samsung are typical of large industrial concerns where investment in modern production has been the cornerstone of success.
Power generation is key to growth, and many industrial complexes in South Korea employ their own generating units to improve economic viability. Cogeneration has advantages due to flexibility and efficiency. As a result, cogeneration in South Korea increased by 1400MWe between 1985 and 1997.
The petrochemical plant at Daesan, owned and operated by Samsung General Chemicals (SGC), contributed to this growth in cogeneration capacity with two cogeneration units:
- Daesan I, driven by an MS5001P and commissioned in 1990.
- Daesan II, driven by an MS6001B and commissioned in 1997.
Both units use gas turbines supplied by GE Energy Products – Europe (GEEPE), a GE Power Systems business. These units have matched the requirements of the petrochemical plant, particularly with regard to adaptation to different fuels. The MS6001B has routinely operated with a wide range of petrochemical by-product gases containing over 95 per cent hydrogen as the main fuel.
Project history
The petrochemical arm of the Samsung Chemicals Group comprises six units, of which SGC, founded in 1988 is the first and strategically the most important. In 1990, SGC commissioned its Daesan I petrochemical complex, a 344 ha plant on the west coast of Korea, 150km south of Seoul. The project represented an investment of $13 billion.
Daesan I started operating with a naphtha cracking centre that could handle 1500 t/day and producing olefin feedstocks. This was followed by a C4-refinates unit producing liquid propane gas (LPG) and butadiene.
To supply Daesan I with power and heat, SGC initially installed an MS5001P gas turbine unit with a generating capacity of 25MWe, together with a number of boilers. The gas turbine has successfully operated on the by-product of the naphtha cracker, with its exhaust suppling heat for the cracking process.
In 1997, SGC commissioned Daesan II, an extension to the original plant utilising an aromatic complex. To power this extension, and to burn the hydrogen-rich fuel gas called net-gas, a 40MWe MS6001B was installed. The unit was provided with LPG as backup fuel, adding complexity to the installation.
In 1999, SGC utility management requested from GEEPE a broadening of the range of process gases handled by the MS6001B to include combustion of an additional by-product gas called ULM-gas. The upgrade work was successfully completed in November 1999.
Cogeneration economics at Daesan
Petrochemical plants are large consumers of heat and power. At Daesan, the average energy consumption is 110MWe and 350MWth, the latter in the form of steam and fuel directly supplied to the processes. This gives a heat:power ratio of 3.18.
A large part of the heat requirement at Daesan must be met with high pressure, high temperature steam. Of the total requirement of 350MWth, around 50 per cent is for high pressure (HP) steam (400°C, 45 bar) and 33 per cent is for medium pressure steam (300°C, 17 bar). This makes use of a gas turbine cogeneration unit extremely attractive. The naphtha cracking plant at Daesan I uses all the heat output from the 490°C exhaust gas of the MS5001P, around 62MWth.
Primary energy strategy
Petrochemical plants use large volumes of costly hydrocarbons such as naphtha and gas condensate to feed cracking units with raw feed. The crackers convert these primary hydrocarbon sources into various olefins which are the universal feedstock for the organic synthesis and polymer processes. Each of these processes generates combustible by-products including hydrogen-rich, olefin-rich and LPG-rich gas fuels; each is a potential fuel for power generation, and economics demand that they be used in preference to other fuels.
In industrial cogeneration, fuel meets one or more of a number of criteria:
- Zero or low commercial value.
- Fuel is outside normal specifications.
- External trading is not feasible due to lack of demand or transportation difficulty.
In addition to these economic criteria, a by-product fuel must be compatible with other potential fuels and with the prime mover, it must be available in suitable quantities and it must be capable of meeting acceptable emission standards.
A heavy-duty gas turbine can play an essential role in utilising by-product fuels. It is less sensitive to the fuel properties than a reciprocating engine. Being a continuous flow, steady-flame machine, a gas turbine does not create any special ignition requirements (such as Octane and Cetane Index), it emits negligible quantities of volatile organic compounds (VOC), unburned hydrocarbons (UHC) and soot over a wide load range, it benefits from NOx control using steam/water injection and it is capable of dual-fuel capability with virtually transparent fuel transfer sequences.
At Daesan, the challenge was to use two completely different by-product gases:
- Net-gas, a hydrogen-rich by-product of the aromatic plant, to be used as the main fuel
- LPG, a butane-rich gas from the C4-refinates unit, to be used as the backup fuel.
The situation has been further complicated with the addition of a third butane-rich fuel, ULM-gas, as an alternative main fuel.
Main plant components
Gas turbine
The MS6001B is a 40MWe heavy-duty gas turbine manufactured by GEEPE at its Belfort and Essen facilities in France and Germany. The single-shaft machine has a 17-stage axial compressor, a combustion system comprising ten can annular chambers and a three-stage expansion turbine. The E-class turbine segment can use a wide range of gas and liquid fuels.
When fitted with dry low-NOx, the unit can achieve NOx emission levels of 25ppm when fired with natural gas. Wet control is also available, using steam or water injection.
Heat recovery steam generator
The heat recovery steam generator (HRSG) is a horizontal, natural-circulation two-pressure boiler manufactured and installed by Babcock France. It produces 74 t/h of steam from the 80MWth released by the gas turbine exhaust.
The boiler is equipped with duct burners to provide additional output, to a maximum of 150 t/h. Continuous steam production of 140 t/h can be achieved without the gas turbine, in the event of its failure. For this purpose, the system is equipped with a by-pass stack, a gas diverter and a fresh-air blower.
Hydrogen as a fuel
Thermodynamic performance
Hydrogen-containing by-products are produced by several processes in the refining, chemical and petrochemical industries. Hydrogen also offers a potential fuel for the future with several attractions, particularly in CO2-free combustion.
Hydrogen benefits from the advantages of a high calorific value (HCV) on a mass-basis fuel with the thermal properties of its single combustion product, water. Taking methane as a point of reference, the power output and efficiency of hydrogen is summarised in the box left. This performance analysis using a simplified differential approach shows hydrogen produces around 4 per cent more power than methane, and is 2 per cent more efficient.
Such gains in performance, at constant power output, represent a reduction of 2.5MWth in gas turbine heat consumption, leading to long-term operations benefits. For annual generation of 350GWh (equivalent to one year’s base load generation in simple cycle mode), the combustion of hydrogen instead of natural gas save of 72 000 GJth, or 2 million m3 of natural gas. The residual heat content of the exhaust gas is 0.8 per cent lower when the unit burns hydrogen instead of methane.
Combustion performance
Hydrogen presents two facets from a combustion perspective. With a lower heating value (LHV) of 10 770 kJ/Nm3 (by volume) and 120 650 kJ/kg (by mass), the fuel has a mixture of low calorific value (LCV) and HCV properties. The HCV properties determine its energy performance while the LCV is vital in sizing the fuel system.
The very fast combustion kinetics of hydrogen and its unique flammability range (lower flammability limit and upper flammability limit of 4 per cent and 75 per cent vol/vol respectively) distinguishes hydrogen from classic syngas in which a high percentage of carbon monoxide or inert gas degrades combustion performance.
Hydrogen develops short and robust diffusion flames. As a result of its particularly high speed of turbulent combustion, its low ignition energy and its tendency to deflagration-to-detonation transitions, hydrogen or any hydrogen-rich gas cannot be burnt within a premixed-flame combustion system but requires a diffusion flame system.
Table 1 shows characteristics of various laminar, premixed flames (methane, butane, carbon monoxide and hydrogen). Although the behaviour of laminar, atmospheric flames is different to that of the turbulent pressurised flame of a gas turbine, this data gives a reasonable idea of the reactivity of hydrogen.
Environmental performance
Hydrogen flames generate high levels of NOx. Therefore a wet deNOx strategy, achieved by injecting water or steam, is necessary. At Daesan II, steam injection was chosen. In addition, precautionary design and operational measures must be taken during start-up, shutdown and fuel changeover sequences to prevent undesirable ignition events.
In contrast to its NOx behaviour, hydrogen has the major advantage of zero CO2 and zero SO2 emissions. At Daesan, net-gas reduces CO2 emissions by 163 000 t/year when compared with natural gas combustion; in comparison with the use of 0.2 per cent sulphur gasoil, annual sulphur emissions are reduced by 375 t.
The fuel system
Heavy-duty gas turbines can use a range of gaseous fuels which may be classified as HCV (LHV ranging from 50 000 to 120 000 kJ/Nm3), medium calorific value (LHV from 10 000 to 50 000 kJ/Nm3) or LCV (LHV ranging from 3000 to 10 000 kJ/Nm3).
An essential property of a fuel gas is its Wobbe Index (WI) which controls the sizing of the gas fuel system. The index is defined as:
WI=LHV/SG0.5 x T0.5
where SG is the specific gravity of the fuel and T is the absolute temperature.
When two different fuel gases with the same WI pass through identical nozzles, they will transport the same heat flow if they generate the same nozzle pressure drop.
Nozzle pressure drop is proportional to kinetic energy of the injected gas, so setting WI to a precise value enables the flame to be kept a suitable distance from the nozzle tip. It is sound practice to restrict variation in WI with the same gas injector set to ±5 per cent. When WI conditions of two gas fuels differ by more than 5 per cent, their combustion in the same gas turbine requires a dual-gas system, implying the need for two gas manifolds, dual gas nozzles and possibly two sets of gas valves.
The Daesan II fuel system
Table 2 shows composition, LHV and WI for the gases used in the Daesan II cogeneration unit. The large WI difference meant that GEEPE had to devise a dual-fuel system. The dangers associated with hydrogen-rich gas made it unsafe to start the unit with net-gas, and the presence of a higher fraction of heavier hydrocarbons in the net-gas meant that the temperature had to be maintained at 45°C. Gas heating takes place in a steam exchanger.
It is necessary to take into account the need to heat the LPG to avoid condensation of higher hydrocarbons in the system (with potentially damaging consequences for combustion hardware and hot turbine parts) and account for the high density of LPG vapour. The LPG is heated to 145°C. Feed pressure for the GT system is 25 bar for net-gas and 23 bar for LPG.
Each gas subsystem was equipped with two regulation valves (one stop-ratio valve and one gas-control valve) and a manifold. Each manifold is connected to the ten gas fuel nozzles of the MS6001B. Each nozzle has two different internal gas fuel pathways ending in two different injection orifices. The primary orifices are drilled on the nozzle tip face and their overall area is sized for LPG. The secondary orifices are drilled near the gas swirler and their overall area has been sized for net-gas.
It was impractical to control gas flow rates with the same valves over the entire power range, as the overall flow range developed by the LPG and the net-gas was incompatible under current flow control technologies. Selecting two sets of valves allowed the flow from both fuels to be accurately controlled.
Startup
The system has a purge system using air discharged from the gas turbine compressor, with the manifolds purged during operation. A nitrogen purge is used during startup and shutdown to flush fuel gas from the circuits.
The system is started up using LPG. After system load has been taken up, fuel changeover is permitted. Fuel swapping requires a two-phase purge process. The first involves nitrogen buffering to avoid fuel-air mixture and prevent inflammation. Then turbine compressor air purges the inactive manifold. A similar sequence is required during shutdown before switching back to LPG.
Operation
The MS6001B gas turbine has generated about 530 000GWh since September 1997. The steam generator produced 900 000 t of steam. The 1998 service factor was 94 per cent.
Abnormal formation of polymers was experienced in the net-gas during initial operation, caused by polymerisation of diolefins contained in minute amounts in the gas. This was traced to conditions in the aromatic plant. Corrective steps were implemented.
In February 1999, SGC requested GEEPE to add a further process fuel, ULM-gas. The gas properties are included in Table 2. A study concluded that it was feasible, and implementation was underway by mid-1999.
| Simplified differential approach for the estimation of fuel performance |
equations-giving-the-relative-changes-in-power-output-efficiency-and-exhaust-gas-heat-948-w-w-k-sub-1-sub-948-sgf-sub-f-sub-sgf-sub-f-sub-k-sub-1-sub-948-tf-tf-k-sub-3-sub-948-968-960-cp-k-sub-3-sub-948-ln-960-ln-960-e-sub-1-sub-951-c-951-t-948-951-951-k-sub-1-sub-1-948-sgf-sub-f-sub-sgf-sub-f-sub-k-sub-1-sub-8217-948-tf-tf-k-sub-2-sub-8217-948-cp-cp-k-sub-3-sub-8217-948-ln-960-ln-960TablesTable 1 Characteristics of laminar, premixed atmospheric flames for various fuels Table 2: Typical analyses of the NET-gas, C4-LPG and ULM gas
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