Combined cycle to replace fired boilers, bring NOx emissions within limits for nonattainment area
2006 case study from Combined Cycle Journal
Industrial plants in non-attainment areas are under tremendous pressure to reduce pollutant emissions in timely fashion. At many facilities, the process and power generation infrastructure is decades old and refurbishment and upgrade of combustion and emissions-control systems are not practical or economical.
Basically, this leaves you two alternatives: shut down or install new equipment.
The latter was the option selected recently by a Texas chemical plant. This particular facility was typical for its day-fired boilers and extraction turbine to produce electricity and process steam. It is being replaced with a new cogeneration system consisting of a 501FD2 gas turbine (GT) from Siemens Power Generation Inc., Orlando, a supplementary fired heat-recovery steam generator (HRSG), and non-reheat steam turbine/generator (ST).
In the process world, redundant energy systems are required to avoid costly upsets. At this facility, four 250,000-lb/hr packaged steam generators are being installed as part of the repowering project to back-up the cogen system (figure 1). These units, built by Rentech Boiler Systems Inc., Abilene, are designed with minimal refractory to enable rapid startups over their design lifetime without incurring a maintenance penalty (figure 2). Boilers are designed to deliver 1300-psig/950F steam (figure 3) from 20% to 100% of the full-load rating and go from hot standby to full load in less than five minutes (30 minutes from a warm start). Another special feature: selective catalytic reduction systems (SCR) to assure emissions compliance.
At full load, the ST receives about 750,000 lb/hr of 1300-psig steam from the HRSG, packaged boilers, or a combination of both. The double-extraction turbine has take-offs at 475 and 235 psig. In the unlikely event that the ST is forced out of service, boiler steam flows through reducing stations designed to match extraction conditions.
The project is being built in phases. The Rentech boilers were installed in late 2005 so the chemical plant could retire the old steam generators and meet its compliance schedule; the more complex GT-based power block is scheduled for service in the fall of 2006. The generator serving the DLN (dry, low NOx)-equipped GT is expected to generate about 170 MW at 18 kV when operating at full load; the 80-MW (nominal) generator for the new steam turbine is rated at 15 kV. The transformer serving the GT is configured to deliver power at both 138 kV and 15 kV. Note that the cogen system can operate as an island if necessary.
One of the challenges facing the design/construct team was a site so small it was measured in square feet. Another, and perhaps the biggest, challenge was to incorporate into the GT, HRSG, and packaged boilers the capability to burn natural gas, residual cracker gas, two separate process off-gas streams containing varying amounts of hydrogen; plus syngas in the future.
To burn the process fuels and natural gas efficiently and safely, the chemical plant creates what it calls LP gas by blending cracker off-gas — it varies in hydrogen content from 35% to 65% — with natural gas. The gases are combined into a homogeneous product by a mechanical mixer; hydrogen content of the mixture is 8.5% or less. Pressure of the mixture is boosted to the 500 psig required for the GT by a new compressor installed at the process unit.
To insure proper operation of the GT, the Modified Wobbe Index of the mixture is monitored constantly by redundant gravitometers. They are integrated into the control system so the gas mixture can be changed as needed to hold the MWI within the specified range of values.
Design details for the control and burner management systems supplied with the Rentech boilers are of interest because of the wide range of fuels burned and the operational demands on the units. Definition of requirements, logic, and design of these systems represented a collaborative effort among engineers from the owner, EPC contractor, Rentech, and the burner and controls supplier, Coen Co. of Woodland, Calif.
The primary job of the boiler control system (BCS) is to regulate the flow of air and fuel into the steam generator; it is incorporated into the plant’s distributed control system (DCS). The burner management system (BMS) controls the sequencing of the boiler pre-purge, light-off, and shutdown cycles separately from the BCS. All boiler safety shutdown functions are handled through the BMS.
There are two primary modes of boiler operation and both can be accomplished using the main or auxiliary fans:
- Hot standby, using the 18-million-btu/hr centerfire gas burner only and firing LP gas.
- Normal operation, firing the main gas burner on LP gas with the ability to co-fire hydrogen in another array of spuds incorporated into the combustion system (figure 4).
The main fan, a 1000-hp constant-speed centrifugal, is required for operation above 30% of the full-load rating. It also is required for the furnace pre-purge cycle. The 125-hp auxiliary fan is equipped with a variable-speed drive (VSD) and normally used in standby service only. However, it can deliver sufficient air to accommodate loads up to 30%. Note that while VSDs are more efficient than constant-speed fans when operating over a range of loads, economic analysis did not support a VSD on the main fan for the operating regimen expected. Small VSDs are far more affordable on a first-cost basis than large ones, according to engineers close to the project.
The BCS is a fully metered, cross-limited combustion control system. The plant master controller in the DCS generates the demand, a boiler master provides local automatic/manual control of firing rate.
The demand is then used to develop individual air- and fuel-flow setpoints for the center-fire and main LP gas burners. The total air-flow setpoint is cross limited with the measured total fuel flow. Similarly, the total fuel-flow setpoint is cross limited with the measured total air flow. Hydrogenheader- pressure demand logic determines whether (1) the DCS hydrogen header pressure controller, (2) hydrogen overfire constraint, (3) air available for hydrogen combustion, or (4) total heat inputfrom hydrogen becomes the hydrogen gas-flow setpoint. The DCS operator enters the total heat input from hydrogen.
The main air-flow controller develops an output signal that positions the inlet-vane, discharge, inlet-box, and FGR (flue-gas recirculation) dampers on the main fan to hold air flow at the setpoint. Any difference between measured air flow and the setpoint — called the error — causes the controller to change its output signal to bring air flow back to the setpoint value.
The auxiliary air-flow controller performs the same functions for the auxiliary fan except that VFD speed is controlled in place of inlet-vane position. Each of the gas-flow controllers operates similarly, positioning its own control valve to maintain gas flow at the setpoint.
The boiler master accepts a remote firing-rate signal — so-called demand — from the plant master controller in the DCS. In automatic operation, the plant master demand is used as the demand for the boiler. When operating in the manual mode, however, the operator can adjust the output of the boiler master, which is then used as the demand for the boiler.
In both the automatic and manual modes, the master controller’s output passes through a rate limiter — it prevents the burner firing rate from modulating so rapidly as to create unstable combustion — to become demand. The demand, in turn, generates setpoints for air- and fuel-flow controls. The controller is output-limited to prevent it from causing total fuel demand to fall outside minimum and maximum limits.
Highlights of the BMS include:
- A flame must be sighted by at least one of the flame scanners within the 10-second trial period for pilot ignition. Likewise, a flame must be sighted by at least two of the three flame scanners within the 10-second trial for burner ignition. Loss of flame detection by any two scanners (so-called two of three voting) will cause all burners to shut down.
- The BMS supports combustion of hydrogen provided at least 10% of the rated heat input to the boiler is produced by LP gas fired in the main burner.
- After a trip or operator-initiated shutdown of the hydrogen burner, a nitrogen purge of the hydrogen system is required.
- To ensure high reliability and availability, two of three field devices must be “off normal” before a burner trip will be initiated because of flame failure, high/low drum level, high steam pressure, low instrument air pressure, low air flow, high furnace pressure, combustion control system failure, and high/low gas pressure.