Further Reading
6.2 Case Study Details
6.2.1 Initial Block Flow Diagram
The initial block flow diagram for the CHP plant associated with the LNG regasification terminal is shown in Figure 6.6. Here there are three gas turbine/HRSG trains, each providing an equal portion of the power output and half of the steam required for the heat needed to vaporize the LNG. Supplemental firing in the HRSGs allows for higher steam temperatures and enables the units to maintain a constant steam‐turbine output throughout the year as ambient temperatures affect the flow through the gas turbines.
Steam from each HRSG combines and enters a single steam‐turbine generator. The latent heat of the steam‐turbine exhaust, normally discarded to the atmosphere, provides useful energy to vaporize LNG. Only two gas turbines are required to vaporize the LNG flow rate, so
Gas turbine a P 33% / H 50%
Reliability = 97%
Gas turbine b P 33% / H 50%
Reliability = 97%
Power output
Gas turbine c P 33% / H 50%
Reliability = 97%
Heat output HRSG a
P 33% / H 50%
Reliability = 99%
HRSG b P 33% / H 50%
Reliability = 99%
HRSG c P 33% / H 50%
Reliability = 99%
Steam turbine P 100% / H 100%
Reliability = 99%
Fuel
Heat to LNG H 0% to 67%
Reliability = 98%
Aux cooling H 100%–33%
Reliability = 99%
Figure 6.6 Initial CHP block flow diagram with power (P) and heat (H) outputs.
an auxiliary cooling system supplements the cooling capability for the steam‐turbine exhaust provided by vaporizing LNG.
Under normal operation, one‐third of the total heat rejection from the steam turbines is provided by the auxiliary cooling system. The auxiliary cooling system is capable of providing the full heat rejection requirement when the LNG regasification terminal is out of service.
Normal full‐load operation of the LNG regasification terminal requires only two gas tur- bine/HRSG trains to be in service. A single gas turbine provides enough steam to the steam turbine generator for half of the design LNG flow.
Power output is the sum of the gas‐turbine and steam‐turbine outputs. If a gas turbine is out of service, the steam turbine output will drop by one‐third.
For the project, the gas turbines would be aero‐derivative units that require a maintenance outage every 4200 equivalent operating hours. After 29 400 equivalent hours, each gas turbine requires a major inspection. The outage durations can be reduced significantly with a rotor subscription service provided by the manufacturer. In such services, the entire rotor is swapped for a subscription rotor during the outage. The manufacturer repairs the rotor in its shop and makes it available to another service subscriber.
The outage pattern repeats until the end of the project life. In addition to the gas‐turbine maintenance, there are four 8‐hour, offline water washes conducted on each gas turbine com- pressor each year. Once every 6 years, the steam turbine must be removed from service for 4 weeks for a maintenance inspection. HRSG inspections are conducted with the gas‐turbine outages.
On average, the gas‐turbine planned outage rate (POR) is 1.837%. The reliability of a gas turbine is expected to be 97% and the reliabilities of an HRSG and the steam turbine are expected to be 99%.
Exercise
1. To meet the project requirement of 98% availability of heat supplied to the LNG regasifica- tion terminal, what must the availability of the block of three gas turbine / HRSG trains be?
2. How can the availability of heat supply be improved?
The information in Table 6.1 is available regarding the thermal performance and integration with the LNG terminal.
6.2.2 Business Structure
The structure of the combined LNG terminal and CHP plant business assumes the CHP plant will operate as an independent provider of electricity and heat energy required for vaporiza- tion of LNG. The CHP plant will be reimbursed for the heat energy provided at the current cost of pipeline quality natural gas. Under these terms, the LNG facility receives energy as if natural gas were combusted and used at 100% thermal efficiency for vaporization without emissions. The CHP facility, receives the price of natural gas for low‐level waste heat. An added secondary benefit to the CHP facility is that the steam cycle heat rejection occurs at a constant temperature throughout the year.
Additionally, the CHP plant receives a price for electricity from the LNG terminal that is above the market rate. The higher than market rate is necessary to:
• compensate the CHP plant for maintaining a high electrical output in all market conditions, even when the retail price for power is below its cost;
• compensate the CHP plant for providing the equipment and systems that deliver the hot water supply to the LNG facility for vaporization; and
• amortize the capital cost for extra redundancy inside the CHP plant required to achieve high availability of the heat supply.
Together, the price for the heat and power supplied to the LNG regasification terminal benefits both parties. The LNG terminal pays a reasonable price for heat and power without having to finance capital investments, and avoids environmental emissions. The LNG terminal owner is provided with highly reliable utilities and can concentrate on its primary business without having to develop talent in a noncore business venture. The CHP plant sells waste heat at the value of natural gas and receives payment for additional capital investments that were necessary over and above that which is normally required by a typical power generator.
Given the foregoing, the net effective heat rate (NEHR) of the CHP plant is given by equation (6.13)
NEHR Q LNG
Net electric output
0 8791. * (6.13)
where:
NEHR: net effective heat rate (GJ/MWh);
Q: total fuel requirement for the CHP plant (HHV) GJ/h;
LNG: Vaporized LNG flow rate (te/h);
Net electric output: net electric output from the CHP plant (MWh).
The NEHR may be calculated hourly as shown in equation (6.13) or on a monthly basis with Q, LNG, and electric output determined for the entire month. Further negotiations will deter- mine the exact methods and calculations. Bonuses and penalties for availability guarantees
Table 6.1 CHP/LNG terminal integration.
Parameter Value
Gas turbine net output each (MW) 49.2
Steam turbine net output (MW) 73.3
CHP auxiliary power (MW) 9.9
CHP net output (MW) 211
Steam‐turbine exhaust flow (kg/s) 60.8 Steam‐turbine exhaust enthalpy (kJ/kg) 2,239 Steam‐turbine exhaust pressure (kPa) 2.51
Gas‐turbine fuel (GJ/h) HHV 1,482
HRSG supplemental firing (GJ/h) 225.3
LNG heat requirement (kJ/kg) 879.1
will also be negotiated to ensure both parties are adequately incentivized to properly maintain the facilities throughout the economic life of the project.
An additional benefit to the CHP plant is that the NEHR is lower (the efficiency is higher) than would be possible with a pure power generating facility. This allows the facility to remain competitive in difficult economic conditions, and as advances in technology create ever more efficient power generating facilities.
6.2.3 Modified Block Flow Diagram
Evaluations of the initial block flow diagram revealed that the steam turbine was a single‐point failure of the waste heat supply to the LNG terminal. Without a backup, the steam turbine could remove the entire CHP facility and LNG regasification terminal from service. While the calcu- lated system heat‐supply availability was greater than 98% for the first five years, the sixth year would suffer due to the planned steam‐turbine maintenance. The design team had also expected a low forced outage rate for the steam turbine. If actual operation was even slightly worse, the overall LNG terminal availability could fall significantly below the target of 98%.
A steam bypass system was therefore designed around the steam turbine to permit operation of the gas turbine / HRSG trains without the steam turbine. Heat for the LNG regasification terminal would be provided by the steam generated in the HRSGs, which would be cooled with condensate to prevent systems that normally operate with steam turbine exhaust from overheating. The system included redundant pumps for cooling, highly reliable instrumenta- tion, and valves yielding a robust system with high reliability. As such, the development spon- sor agreed that it was unnecessary to consider that the bypass system would not operate in the event of an unplanned outage of the steam turbine.
In order to conduct a steam‐turbine maintenance outage, a complete shutdown of the CHP plant was required to isolate the steam turbine from the condenser. The outage was estimated at 2 days. The reverse process of removing the isolation would require another 2‐day outage of the CHP plant prior to placing the steam turbine back in service. These outages would be scheduled with the LNG facility to reduce economic penalties but the system was still required to meet an overall availability of 98% or better.
The modified block flow diagram is shown in Figure 6.7.
The auxiliary cooling system was to be a wet cooling tower comprising four parallel cells with three 50% capacity cooling water pumps, each component being highly reliable. The overall auxiliary cooling water system would therefore have a reliability of approximately 99.9%. As with the steam bypass system, the project team and sponsor agreed that it was unnecessary to consider a complete or significant failure of the auxiliary cooling system together with another simultaneous unplanned outage. The reliability impact of the auxiliary cooling system could therefore be ignored in the overall system waste heat and power avail- ability calculations.
6.2.4 Other Considerations
Natural gas from the LNG regasification terminal would be connected to multiple inter- state pipelines. In the event that the LNG terminal would be out of service, natural gas could be provided to the CHP from the interstate systems, which had established very
nearly 100% reliability. The design team therefore felt that there was no need to consider a complete fuel outage.
In the event of a failure of the local electric power grid, the CHP could operate at a reduced load to provide power for the operation of the LNG terminal and regasification facilities.
Further economic analysis would be required to determine if the CHP plant needed capabil- ities to start in the absence of the local power grid. Initial discussions and data on the grid’s reliability indicated that the “black start” capability would not be necessary.
6.2.5 Exercises
Complete the following:
1. Set up a spreadsheet to calculate the availability of power and heat provided by the CHP plant discussed above. Neglecting the sixth operating year, which includes a steam turbine outage, calculate the following for the gas turbine / HRSG block:
(a) The effective forced outage rate for one gas‐turbine / HRSG train.
(b) The system planned outage rate neglecting outages coinciding with a forced outage.
(c) The probability of a single unplanned outage.
(d) The probability of experiencing an unplanned outage during planned maintenance of a gas turbine.
(e) The probability of two simultaneous unplanned gas turbine / HRSG outages.
Gas turbine a P 33% / H 50%
Reliability = 97%
Gas turbine b P 33% / H 50%
Reliability = 97%
Power output
Gas turbine c P 33% / H 50%
Reliability = 97%
Heat output HRSG a
P 33% / H 50%
Reliability = 99%
HRSG b P 33% / H 50%
Reliability = 99%
HRSG c P 33% / H 50%
Reliability = 99%
Steam turbine P 100% / H 100%
Reliability = 99%
Steam by-pass H 100%
Reliability = 99.6%
Fuel
Heat to LNG H 0% to 67%
Reliability = 98%
Aux cooling H 100%–33%
Reliability = 99.9%
Figure 6.7 Modified CHP block flow diagram.
(f) The probability of an unplanned steam‐turbine outage.
(g) The probability of an unplanned stream turbine outage with a planned gas‐turbine maintenance outage.
(h) The probability of a simultaneous steam turbine and gas turbine / HRSG unplanned outage.
2. Determine the percentage of power output and heat supply for the scenarios outlined in items 1b. through h. above.
3. For each scenario, 1b. through 1h., multiply the lost output for power and heat by respective probability to find the availability losses for each outage scenario.
4. Sum the products for power and heat from 3. above and subtract from one to find the avail- ability of power and heat from the CHP plant.
5. Comment on the need to consider simultaneous forced outages and forced outages during the gas turbine major maintenance periods.
6. Repeat items 1. through 4. above for the sixth operating year, taking into account the steam‐turbine major maintenance outage.
7. Write a Visual Basic program for a Monte Carlo analysis of the expected availability of power and heat from the CHP plant for years 1 through 5. Compare the Monte Carlo anal- ysis and the deterministic result of item 4. above.
8. Calculate the net effective heat rate and thermal efficiency of the CHP plant.