John V. Albano, Edward F. Olszewski
ABB Lummus Crest Inc.
Bloomfield, N.J.
Toshiyuki Fukushima
Osaka Petrochemical Industries Ltd.
Osaka, Japan
The use of gas turbines to produce power while using their hot, oxygen-rich exhaust gas as combustion air in the cracking furnaces is an attractive means of reducing energy requirements per unit of ethylene production.
At Osaka Petrochemical's (OPC) plant in Japan, ABB Lummus Crest Inc.'s turbine integration system was retrofitted. A Korean plant was newly constructed to utilize the system. The two plants have been operating successfully for approximately 2 years.
Two new plants based on Lummus technology started up last year, one is scheduled for start-up in early 1992, and four are in various stages of design and construction.
BACKGROUND
Turbine exhaust gas (TEG) effectively provides high-level air preheat, thus lowering the heaters' fuel requirements.
However, unlike air preheat systems, because of the reduced oxygen content of TEG, the total mass flow of flue gas passing through the furnaces is increased. This increases steam production in the convection (heat recovery section of the pyrolysis module.
The power produced by the gas turbine can be used either for mechanical drives or to produce electric power for in-plant use or export.
At an ethylene plant in Northern Europe, a heavy-duty industrial gas turbine is used to drive the charge gas compressor while the exhaust provides oxygen for combustion in the cracking furnaces.
With this arrangement, plant operation is dependent on the availability of the gas turbine. Trip of the gas turbine will result in a plant shutdown.
In all gas turbine integration systems recently designed by ABB Lummus Crest, the gas turbine is used to drive a generator, producing electric power. The systems are designed to safely switch the cracking heaters from combustion (using hot TEG) to ambient air without shutdown.
This renders plant operation independent of gas turbine availability. Conversely, electric power can be generated when the plant is shut down.
Key technical considerations which must be addressed to successfully apply gas turbine integration in an ethylene plant are as follows:
- Process/economic optimization
- Gas turbine selection
- Integration system design/control philosophy
- System dynamic response.
ECONOMIC OPTIMIZATION
The driving force for applying gas turbine integration in an olefins plant is higher profits. For a 750,000 metric tons/year liquids cracker applying two Frame 5 gas turbines, the relative economics, with typical utility costs, are:
- Operating cost savings = $14,770,000/year
- Investment cost = $32,000,000
- Simple payout = 2.2 years.
This generates 42 mw of power.
The furnace area fits particularly well with a gas turbine because substantial amounts of hot combustion air are required. In fact, the cracking furnace area is the largest energy consumer in an olefins plant.
Significant improvements in energy efficiency in the furnace area have been incorporated in the years following the oil crisis of the early 1970s:
- Improved furnace thermal efficiency to values approaching 95% by convection section design
- Enhanced waste heat recovery by applying higher-pressure steam Generation system up to 125 bar.
Gas turbine integration, like air preheat, improves overall efficiency by providing hot combustion air to the furnace. However, the gas turbine is particularly attractive when the following criteria are met:
- High energy costs
- Available sink for both steam and power export outside the olefins plant
- Highly valued steam and power relative to fuel.
Most olefins complexes meet these criteria, especially if the ethylene plant is part of a major petrochemical complex, or if available electric power tends to be unreliable.
Fig. 1 illustrates the integration of a gas turbine with the pyrolysis furnaces in an ethylene plant. The hot exhaust gases from the gas turbine are directed to the burners via suitably designed duct systems. The exhaust is typically 15-17% oxygen, at about 580 C.
Fig. 2 summarizes the heat balance for the system. Essentially all the energy input as fuel is converted to power and useful heat, and backs out fuel fired in the furnaces. Additional steam is raised in the convection section of the furnaces.
Table 1 compares the heat balance for a system with a gas turbine to one where no integration is applied. The plant specific energy improves by 15%. All utilities in this comparison have been converted to fuel equivalents.
Table 2 further illustrates comparative economics. The gas turbine saves an estimated $1,850/hr with the utility values indicated. The economics can be improved, if power is valued higher than fuel.
GAS TURBINE SELECTION
Selection of the gas turbine for a given application is a complex optimization process. Factors which must be considered include:
- Process
Impact on the plant energy balance
Type and quantity of fuel available
Demand for electricity
Match between exhaust gas oxygen flow and heater demand
Compatibility with existing furnaces in retrofit applications
- Mechanical
Single shaft vs. split shaft
Heavy-duty industrial
Aero-derivative
Maintenance
Available operating experience
- Operational
Rate of airflow decay after trip
NOx production
- Economic.
Split-shaft gas turbines are best suited to mechanical drive applications where the load varies substantially. Single-shaft heavy duty industrial machines are best suited to electric power generation where load variations are small. They are also the most flexible in terms of the type of fuels which can be used.
Aero-derivative machines offer high efficiency (low fuel consumption), high output per unit mass of airflow, and compactness. These must be of the split-shaft type because an aircraft engine (gas generator) is mated to an industrial heavy-duty power turbine.
These have been refined and are now comparable to heavy-duty industrial machines in terms of reliability and maintenance requirements.
In plants in which cracking furnace operation continues upon a trip of the gas turbine, the rate of airflow decay after a trip is an important consideration. It has significant impact on the design of the integration system.
Typical airflow decay rates for heavy-duty single shaft, split-shaft, and aero-derivative gas turbines are shown in Fig. 3. Because of the split-shaft design and low rotational inertia of the gas generator section, aero-derivative gas turbines have the fastest airflow decay rate (Fig. 3). Within 5 sec of trip, airflow decreases to approximately 15% less than its initial rated flow, or less.
Heavy-duty, single-shaft turbogenerators provide the slowest rate of air loss. The high rotational inertia of the gas turbine and generator maintain substantial airflow long after a trip. Airflow is still approximately 40% of its initial value 30 sec after a trip (Fig. 3).
Split-shaft industrial machines lie between the two extremes, but are closer to the single-shaft machine.
ABB Lummus Crest has designed systems utilizing both heavy-duty, single-shaft and aero-derivative gas turbines. Although the rapid airflow decay rate of the aero-derivative adds some complications, these problems have been solved.
The longest operating plant in Korea and OPC in Japan both utilize aero-derivative gas turbines.
INTEGRATION SYSTEMS
Three integration system designs and control concepts are shown in Figs. 4, 3, and 6.
Fig. 4 is the system used in Korea. The turbogenerator is an aero-derivative machine producing approximately 12 mw of power.
Fig. 5 is a second-generation improved design developed for use with a heavy-duty industrial gas turbine.
An extension of this system, modified to be more compatible with aero-derivative gas turbines, was used by OPC in Japan. The modified system is shown in Fig. 6.
All three designs provide the following key features:
- Operation of the plant independent of gas turbine availability. (The heaters can operate satisfactorily on either gas turbine exhaust or forced ambient air.)
- Sufficient redundancy, to assure a reliable source of combustion oxygen.
- "Lead/lag" air-to-fuel ratio control for safe operation.
Fuel flow is not permitted to increase until airflow is first increased to provide sufficient air for complete combustion, i.e., air leads fuel. Conversely, when fuel demand decreases, the fuel flow is first reduced, then air is reduced, i.e., air lags fuel.
- Independent start-up of the heaters and gas turbine.
- Means for safe transition from heater operation on hot turbine exhaust to forced ambient air without heater shutdown, should the gas turbine trip.
ORIGINAL DESIGN
In the system shown in Fig. 4, gas turbine exhaust mixed with makeup air enters the main air duct leading to the cracking heaters.
During normal operation, the oxygen in the TEG provides about two thirds of the hearth burner requirements. The remaining one third is provided by a continuously running makeup air fan which is spared.
To avoid thermal stratification of the hot and cold streams, a specially designed mixer is provided. To maximize the utilization of hot TEG, the pressure in the main supply duct is controlled by means of a split-range system.
On rising pressure within one range of signals, the makeup air fan suction damper closes to a minimum position. If the pressure continues to rise within a second range of signals, excess TEG is vented to atmosphere by means of a pressure control louver.
Standby forced-draft fans discharging into the main duct supplement the normal makeup airflow for cold air operation if the gas turbine is not available or if the gas turbine and furnaces are operated separately.
During normal operation of the furnaces using mixed TEG and ambient air, these fans are shut down. In the event of a turbine trip, the standby fans are started. These fans are designed to accelerate rapidly to operating speed to provide sufficient air delivery in minimum time.
Because the temperature in the main duct can vary from ambient to full TEG exhaust temperature (which effects pressure drop), the duct pressure set point is adjusted to compensate for this.
Set point pressure increases as temperature increases. This minimizes the throttling required to control the airflow at each furnace.
A pair of dampers at the exhaust of the gas turbine allows the TEG to be directed either to the main duct or to atmosphere through a dump stack. The dampers also enable isolation of the gas turbine from the heaters, permitting independent operation of the two.
If the gas turbine is not available, the furnaces can be operated using the ambient air fans. Overpressure protection is provided at the turbine outlet upstream of these dampers.
A flow-control damper at the takeoff of the branch duct to each furnace from the main air-supply duct controls combustion airflow to each furnace. Airflow is measured by means of a venturi compensated for temperature and composition.
The air requirement is set by the firing demand of the cracking furnace under air-to-fuel ratio control, and the flow-control damper is adjusted as needed to provide the required oxygen. The air-to-fuel ratio control is a lead/lag system, as previously described.
The ability to switch furnace operation from TEG to ambient air in the event of a trip of the gas turbine is strongly dependent on the system dynamics. The flow of oxygen to the furnaces is a complex function of the oxygen decay rate from the turbine, the rate of oxygen supply from the fans, and the response of the control system.
To assure a safe transition, a detailed computer model of the system was created to study the dynamic response of the system during the turbine trip transient. This is discussed in greater detail later.
The analysis showed that the system in Fig. 4 was capable of switching from TEG to ambient air operation without heater trip, provided that the firing in the furnaces was reduced to about one third of normal for approximately 10 sec immediately following turbine trip. Because of the thermal inertia of the furnaces, this brief reduction in firing has little effect on cracking conditions.
The rapid decay of airflow from the aero-derivative gas turbine and the time required to fill the large main duct with cold air were the main factors necessitating the temporary reduction in firing.
SECOND GENERATION
Fig. 5 shows an improved system designed to avoid the reduction in firing immediately following a gas turbine trip that had been necessary to avoid substoichiometric combustion.
A standby air fan is provided in the immediate vicinity of each heater. Other features are similar to Fig. 4.
With this system, the rate of air delivery following a gas turbine trip is improved significantly. The individual fans are much smaller and can therefore accelerate faster.
The duct volume downstream of the fan is substantially reduced, decreasing fill time and improving response. In addition to faster response to loss of combustion air during a turbine trip transient, the system offers other advantages which include the following:
- Easier start-up and shutdown.
- Greater flexibility. Some heaters can be operated on TEG with others on ambient air.
- Temperature compensation of main duct pressure set point is not required.
- Direct separate measure of O2 flow in hot and cold streams.
Calibration of flowmeters is simplified because density variation is small.
- Loss of standby fan will only shut down one heater, not the entire plant.
- A diverter rather than louvers can be used at the turbine exit. This is mechanically better.
Two plants using this system based on heavy-duty industrial gas turbines started up last year. Another in South America based on this design is scheduled for startup in January or February of 1992.
All plants currently in design use this system.
In the system in Fig. 5, it is extremely difficult to avoid substoichiometric combustion in the heaters without reducing firing. This is because of the very rapid airflow decay rate following a trip with these machines.
MODIFIED DESIGN
To overcome this, with the modifications shown in Fig. 6, the forced-draft fans at each heater run continuously.
During normal operation they provide makeup air as required; under trip conditions the suction louvers open and they provide sufficient air to allow operation to continue at normal firing levels.
With this system, mixers are located at each heater, and the makeup air fan discharging into the main duct is eliminated.
The system at Osaka Petrochemicals in Japan uses a Cooper Rolls Coberra 6462 gas turbine producing approximately 25 mw of electricity. The gas generator is derived from a Rolls Royce RB211 aircraft engine.
Several gas turbine trips have occurred with the system behaving as intended. Operating experience in this plant is discussed in some detail later in this article.
DYNAMIC RESPONSE
The primary feature that distinguishes these integration systems is the ability to safely switch the operation of the cracking furnaces from turbine exhaust gas to ambient air in case of turbine trip.
To provide this capability, the systems must be carefully engineered to avoid substoichiometric combustion during the transient. This requires a thorough evaluation of the dynamic response of the system through the transient.
An integral part of this evaluation is a digital computer simulation. The simulation provides the variation of pressure, temperature, and mass flow at key points in the system as a function of time following trip of the gas turbine.
The integrated gas turbine/cracking furnace system is modeled as a large number of interconnected subvolumes or nodes. The time-dependent equations of mass, energy, and momentum conservation are solved simultaneously to provide pressure, temperature, mass flow, and composition at each node as a function of time.
The interaction of the dampers and controllers must be considered in the analysis. The time delays associated with the transient phenomena in the ducting, the sensor response, and the damper motions are modeled to determine if the control systems can react fast enough to prevent an unstable condition.
The computer model calculates the hydraulic response of the ducting network caused by a system perturbation; e.g., a sudden change in flow caused by gas turbine trip.
Computations of fluid conditions are made for a large number of discrete points throughout the fluid network.
Boundary conditions for the computer analysis are provided by models representing the gas turbine, fans, dampers, valves, controllers, and cracking heaters. These data are supplied as input from the equipment manufacturers.
The analyses are carried out by ABB Combustion Engineering Nuclear Power Systems in Windsor, Conn. A detailed review of the results of these studies for the systems described above is too lengthy to be presented here.
Fig. 7 illustrates the results of the transient analyses for the OPC system, showing that substoichiometric combustion after a turbine trip is not a problem.
OPERATING EXPERIENCE
The integration systems of the Korean and OPC plants are performing satisfactorily.
The Korean plant has experienced several gas turbine trips. In all instances, the system responded as intended. The standby forced-draft fans started automatically, firing was reduced for approximately 10 sec, and the heaters returned to normal operation without incident.
EXPERIENCE AT OPC
The OPC system was designed to eliminate the need for any reduction in firing following a trip of the gas turbine. Prior to full-scale operation with TEG, tests were run to check the response of the control system and verify the results of the transient analysis.
The gas turbine was tripped under the most severe operating mode, one furnace in operation on TEG with the remainder being vented to atmosphere through the pressure-control damper. The results of the test were satisfactory; the system responded as intended.
Fig. 8 compares the oxygen flowrates determined from TEG and air flowmeter measurements during the trip test with the results calculated by the computer simulation of the test case. The data compare favorably.
It should be noted that the comparison is based on measured flowrates, i.e., flowrates at the flowmeter locations. It is not practical to measure total flow into the furnace during the transient because of the large number of wall burners.
SYSTEM OPERATION
In order to maintain stable trip operation of the cracking heaters on hot TEG, ambient air, and through a turbine trip transient, OPC has applied a number of improved control systems and interlock functions. These include:
- Lead/lag air-to-fuel ratio control
- Pass balance control to maintain coil outlet temperature uniformity
- Safety system to protect against malfunction of the TEG control damper(s) during trip conditions.
OPC's system is able to maintain stable operation at full firing through a gas turbine trip transient, largely due to the implementation of the above additional control loops.
To date, OPC has experienced three gas turbine trips. These were caused by controller malfunctions and problems of the electric power company. In all cases the system performed as expected with the furnaces operating continuously through the transient.
Fig. 9 shows the variation in coil outlet temperature through the transient. The variation is small-less than 10 C.
GAS TURBINE RELIABILITY
At the design stage, OPC had some concerns about the capability of the aero-derivative gas turbine to operate continuously without excessive maintenance. Operating experience, however, has demonstrated that the reliability of this machine is very good.
At OPC, soak crank wash is carried out every 2,000 hr to clean the compressor blades. Borescopic inspection is performed at the same time. No problems have been detected through these inspections and scheduled maintenances to date.
NOX EMISSIONS
NOx emissions from the cracking heaters operating on TEG are lower than before installation of the integration system, although the NOx content in the TEG combustion air is higher.
Typical NOx concentrations in the heater effluent are 70 ppm with TEG and 95 ppm without TEG. These figures are on a dry basis and 0% oxygen content.
ENERGY IMPROVEMENT
The overall energy improvement achieved by integrating the cracking heaters with the gas turbine is shown in Table 3. With the integrated system, fuel fired in the cracking heaters decreases significantly while steam production increases. Overall, 30.41 MMkcal/hr of energy are saved.
This translates to a specific energy saving of approximately 800 kcal/kg of ethylene, which compares favorably with the estimated savings (775 kcal/kg) given in Table 1.
Copyright 1992 Oil & Gas Journal. All Rights Reserved.
