Heavy-duty gas turbines can enable CHP plants to burn process by-products that might otherwise be a liability. Yoon-Ho Lee, Michel Moliere and Heung-Yub Ahn describe the design and operational experience of one such cogeneration facility at a petrochemical complex in South Korea.

South Korea’s decades long economic development has created a great need in the country for the products of petrochemical plants. One such facility is the $7.5 billion, 1.9 km2 plant in the city of Yeosu in South Jeolla province, owned by Lotte Chemical (formerly Honam Petrochemical Company).

In a drive to help maintain its business competitiveness, Lotte modernized the facility’s energy generation equipment, a move in which cogeneration plays a pivotal role.

CHP at the complex produces power and steam for internal petrochemical processes, but it does so by burning an alternative fuel, the use of which has saved energy, improved operational flexibility and optimized the facility’s energy balance. This is despite the huge financial stake in the correct, uninterrupted operation of Yeosu’s petrochemical processes, which run 24/7 all year round, which mean that that part of the complex that manages the supply of power and heat to processes has key responsibilities.

Figure 1. The Yeosu plant’s cogeneration unit, which is based on the Frame 6B gas turbine

Yeosu has been running since 1976. Its operations revolve around an olefins plant that cracks naphtha to make chemicals such as ethylene – its 1000 ktonnes/y output is part of the 3600 ktonnes/y total petrochemicals output of the complex.

Modern petrochemical plants use large amounts of energy, with a heat/power ratio that is high and variable. Gas turbine-based cogeneration units are well suited to such plants because of their efficiency, emissions controls and operational versatility.

Cogeneration at the Yeosu complex comes from its utilities facility, to which Lotte added an efficient CHP unit of 190 MWth in 2002. It includes a 40 MW Frame 6B or MS 6001B heavy-duty gas turbine from GE, made in Belfort, France. This E-class machine helps create steam at a rate of 75 tonnes/h, rising to a peak rate of 170 tonnes/h.

Thermal demand from the complex’s various processes totals 275 MW. This includes self-generated process heat and the 63 MWth delivered by cogeneration. Average power consumption at the complex is 150 MWe, of which Lotte self-generates 67 MWe, and the grid supplies 85 MWe.

As indicated above, the petrochemical units absorb a large amount of heat and generate their own. Much of the generated heat feeds steam pressure networks. Among the 275 MWth of steam consumed by the complex, 8% is at the very high pressure of 12,400 kPa and at 525°C, 40% is high-pressure steam at 4100 kPa and 375°C, 22% is medium-pressure steam at 1600 kPa and 275°C, and 30% is low-pressure steam at 450 kPa and 185°C.

The complex’s requirement for high-pressure steam made gas turbine cogeneration options all the more attractive.

Figure 1 is a schematic of the Frame 6B-based cogeneration unit at Yeosu. These steam and power facilities let the complex operate at a large fraction of full capacity autonomously even when grid power is lost.

The Frame 6B has been running at the complex’s utilities facility since 2003. This turbine and its heat recovery steam generator (HRSG) raised power generated there from 25 MWe to 67 MWe, which brought the self-production ratio to nearly 45% in 2012. It also added the peak steam-generation capacity.

Figure 2. Range of liquid and gaseous fuels for GE gas turbines

Between March 2003 and June 2013, the turbine clocked 87,000 hours of operation and accommodated a projected shutdown schedule. Over that time it burnt 888,000 tonnes of C9+ hydrocarbons as fuel and only circa (c.a.) 270 tonnes of gasoil. It also generated 3000 GWhe and, through its HRSG, some c.a. 7,200,000 tonnes of steam.

The turbine usually runs continuously all year. Its availability was 96% and 98% in 2009 and 2010, respectively; years when combustion inspections occurred. A major inspection in April and May 2011 meant availability was 92% in that year. As far as trouble-shooting is concerned, there has been no operational combustion issue to-date.

Table 1 summarizes the main operational data of the plant from 2003 to 2012. The operation time on backup fuel was less than 0.1%.

Fuel flexibility

But where Yeosu’s CHP facility leads the world is in its commercial use of C9+ aromatics by-products as fuel

Petrochemical plants employ large cracking units that require significant volumes of noble hydrocarbons as feedstocks. The crackers convert these costly compounds into olefins, which are the raw materials for organic synthesis and polymerization. A major strategy of the Yeosu complex was to use the C9+ aromatics by-products of this process as the primary energy source for cogeneration and thereby maximize their use.

The economics of using these secondary energy resources and to strictly limit the use of any other commercial fuel are favourable, a general rule that applies to all CHP projects in petrochemicals aaplications.

Generally the requirements for an ideal alternative fuel for captive generation are exacting: low, ideally negative commercial value; characteristics outside normal commercial specifications; and unfeasibility of sale. But technical and environmental aspects are important too.

There must be compatibility between the fuel and the prime mover, the available volume of fuel must match the targeted CHP capacity and the prime mover must be capable of mixed-fuel operation. Also data on emissions of pollutants must be acceptable. Heavy-duty gas turbines have many advantages here.

In the case of GE’s E-class units, which include the Frame 6B, 7E and 125 MWe ISO 9E, they have demonstrated the ability to accommodate a wide range of gas and liquid fuels, a quality allowed by the physics of combustion in gas turbines. These fuels vary from LPG1 to distillates2,3, ash-forming fuels4 and fuels that are by-products of industrial processes. Figure 2 shows how heavy-duty gas turbines can burn a wide range of fuels2.

Gas turbines are continuous-flow, steady-flame machines that create no special ignition requirements on, for example, the octane and cetane indexes. They also emit negligible amounts of volatile organic compounds (VOCs), unburned hydrocarbons (UHC) and soot over a wide load range. They can also use the universal de-NOx method of the injection of steam and water, and their dual-fuel capability is unprecedented because fuel transfers can be automatic and virtually transparent.

However, in practice the range of alternative fuels that are accessible depends on combustion designs, the experience of the OEM and its commitment to tackling challenging applications.

At Yeosu the challenge was to make the complex’s exotic C9+ aromatics by-product the main fuel, while using gasoil only for startups and shutdowns.

C9+ aromatics are blends of liquid hydrocarbons, 80% of which are aromatics. Heavy-duty gas turbines burn aromatic fuels cleanly thanks to their steady combustion regime, their hot and lean diffusion flames and their very oxidizing combustion zones5. These fractions are not suitable for other prime movers such as reciprocating engines.

Fuels may be classified as gaseous, with high, medium or low BTU properties, and liquids, with the C9+ aromatics lying in the region of naphtha fuels.

Although the Frame 6B is a heavy-duty gas turbine with can-annular combustors that have combustion traits favourable to burning highly aromatic fractions, such fuels do pose certain challenges. The mixed fuel oil that the Frame 6B uses at Yeosu comprises C9+ mono-aromatics and C6-C8 non-aromatics.

Figure 3. The competing oxidation and pyrolysis reaction routes

Mono-aromatics are volatile and non-lubricious and require similar engineering measures as naphtha3,6,7. They also have higher auto-ignition temperatures and worse smoke numbers than homologous paraffinic compounds.

Petrochemical plants use by-product mono-aromatics as feedstocks. But fluctuating demand for petrochemical products can lead to excesses of these fractions. Export of these surpluses can be costly or a logistical problem, so their use in on-site power generation is helpful.

But the flames of liquid fuels, aromatics in particular, make combustion more complicated compared with gas. Although aromatic fuels are very fluid, which means they do not suffer from incomplete vaporization during combustion – unlike viscous fuels – and the resulting soot when unburned droplets leave the combustors, a chemical limitation to their combustion is still likely.

Combustion of liquid fuel comprises two competing main mechanisms: repetitive cracking-oxidation that leads to the formation of CO2 and H2O, and pyrolysis, in which polycyclic structures form, followed by soot in the micron-range size. This second mechanism is favoured in oxygen-depleted zones of the combustion zone. Figure 3 illustrates what happens in the case of three types of C10 hydrocarbon chains.

Table 2 summarises the influence of the properties of liquid fuels on gas turbine combustion and emissions.

A field test using a so-called benzene heart cut was performed in a Frame 6B to assess the feasibility of burning mono-aromatic hydrocarbons. It showed that burning mono-aromatic fuels cleanly is possible. Table 3 displays the analysis8.

Another major benefit of burning C9+ aromatics is that combustion leads to emissions of only moderate amounts of CO2. At Yeosu it has also cut SO2 emissions by 750 tonnes ,compared with 0.1% sulphur diesel oil since the commissioning of the turbine.

Prime mover selection

The Frame 6B has also demonstrated its ability to match the stringent expectations of the petrochemical community in terms of efficiency, availability and reliability.

The turbine has its own control system, which is integrated into the DCS, and the unit reacts more quickly to restarts or load changes than steam-based units. Also the loading of the supplementary firing in the HRSG is much faster compared with a conventional oil-fired boiler. Finally the petrochemical complex has also become less vulnerable to disconnection from the electricity grid or boiler trips.

If grid power fails, the Frame 6B goes from ‘droop’ mode to ‘island’ mode, while other generators would stay in the droop mode. The complex also protects vital upstream units by automatically changnig its electricity frequency reference from the grid to the main generator.

Experience with the Frame 6B has showed that it would meet the requirements of the plant designers. The prime mover had to be of a reliable and robust technology, with an H/P ratio of 1.5:1, operational flexibility that allowed fast starts and load changes, highly standardized maintenance, and a large fuel experience base.

This single-shaft machine features a 17-stage axial compressor, a robust and versatile combustion system, with 10 can-annular chambers and a three-stage expansion turbine. Regular performance upgrades have increased its output from 36 MW to the 42 MW of the latest PG 6581B model. It has also had gradual upgrades to its hardware.

The turbine can operate in a wide spectrum of power generation configurations – in simple and combined cycles. Each turbine generation set constitutes an individual module that has the qualities of start-up agility, rapid installation indoors or outdoors, a low footprint and a simple maintenance programme.

The fast start-up sequence enables synchronization with the grid within 12 minutes and access to full load after a further 4 minutes. This capability is paramount in peak-shaving, but also valuable in cogeneration when provision has been made for a bypass stack.

Concerning emissions performance, the Frame 6B can achieve very low NOX emissions5 – 25 ppmV of NOx either via a dry low NOx system (natural gas firing) or by ‘wet control’ consisting of the injection of a diluent, usually steam or liquid water, into the gas turbine combustors.

At Lotte, the combustion of C9+ aromatics required the use of diffusion flame combustors for which the usual NOx abatement technique is by the injection of water or steam.

NOx emissions of the Frame 6B while burning C9+ aromatics and running at baseload are around 300 ppmV. Yeosu had used a steam injection system since the first operation of the turbine in 2003 to cut NOx to 55 ppmV, in line with the Korean limit. However, in 2008 Lotte changed the diluent to water to improve energy effectiveness. NOx emissions are now 40 ppmV (at 15% O2 in the exhaust gas).

To maintain performance over time, the Frame 6B has an online/offline water washing skid. Off-line washing occurs only during scheduled shutdowns as this minimizes costly downtime. On-line washing is performed every day.

The HRSG used in the CHP plant is a horizontal, natural circulation boiler from Daekyung Machinery & Engineering that produces 75 tonnes/h of steam from the average 95 MW of heat captured from the gas turbine. It is equipped with duct burners to provide additional and automatic firing to more than double its output to 170 tonnes/h of steam in 5 minutes.

Trailblazing alternative fuel use

The cogeneration unit’s results are mainly down to four converging factors. The first is a relevant, maintenance-based operational policy. Second and third are the potential of the Frame 6B and the intensive exploitation of this potential by experienced engineering teams that have regularly embarked on challenging applications in new and upgrade projects. Fourth is the pro-active plant management that has anticipated seasonal and long-term changes in demand for heat and power.

More than 60% of aromatics at the complex are used routinely and reliably. Yeosu represents an inroad into the general use of such fuels and another milestone on the way to adapting power generation to the fuel mixes of the future.

References

1. A. Olbes, M. Pujol et al, High compatibility between gas turbines and refinery utilities, POWER-GEN Europe, Madrid, Spain, June 1997.

2. M. Moliere, Alternative Fuels: Industry Perspective Worldwide, ASME Turbo Expo Fuel Panel session, 11-15 June 2012, Copenhagen, Denmark.

3. M. Moliere, F. Geiger et al, Volatile, low lubricity fuels in gas turbine plants: A review of main fuel options and their respective merits, ASME Turbo Expo 1998, Delhi, India, Paper GT 231.

4. N. Marikkar, D. Nanayakkara et al, Heavy fuelled gas turbines in power generation: the LTL CCGT at Kerawalapitiya, Sri Lanka, as a paradigmatic plant, PowerGen Asia, Singapore, 2-4 November, 2010.

5. M. Moliere, Stationary gas turbines and Primary Energies: A review of fuel influence on energy and combustion performances; International J. Thermal Science, 2000, 39, 141-172.

6. J. P. Stalder and P. Roberts, Firing low-viscosity fuels in gas turbines, ASME Turbo Expo 2003, Atlanta, USA, 16-19 June.

7. Turbotect Pamphlet ER 517 & ER 18 Technical data sheets, 2003.

8. M. Moliere and F. Geiger, Gas turbines in alternative fuel application: The utilization of highly aromatic fuels in power generation, paper GT 53272, ASME Turbo Expo 2004, Vienna, 14–17 June.

Yoon-Ho Lee is from Honam Petrochemical Company and Michel Moliere and Heung-Yub Ahn are from GE Energy. www.ge.com

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