Backup steam supply critical for merchant generators with thermal hosts

2004 case study from Combined Cycle Journal

Mitigation of risk in the ruthlessly competitive merchant power business demands innovation and creative thinking in both equipment design and plant operation. To be successful, a generating company must have capable, determined, dedicated employees from the top to bottom of the organizational ladder.

In some areas of the country — the Gulf Coast, for example — a merchant plant capable of generating and selling only electricity can have difficulty turning a profit. Add a thermal contract and the revenue stream can change dramatically — both because of the additional product and the more efficient cycle. Last is conducive to a higher capacity factor and increased sales of electricity.

No pain, no gain
However, a thermal contract means that you must supply steam even when the gas turbine (GT) portion of the combined-cycle or cogeneration plant is forced out of service. Many large industrial plants have entered into thermal contracts to focus resources on the product side of their facilities. Contracting for steam has enabled some refineries to dismantle old boilers; others have been able to mothball units and avoid having to upgrade or replace them to meet the latest environmental regulations.

When investigating opportunities in the merchant steam business, remember that industrial processes rarely shut down gracefully when the header empties. This means you must design, operate and maintain facilities to ensure that there always is steam in the pipe.

One way to mitigate risk is to design the heat recovery steam generator (HRSG) to operate as a fired boiler in the event its GT is forced out of service. This requires an oversize duct burner and a forced-draft (FD) fan to supply combustion air. The HRSGs at one refinery in France that employs this scheme can produce up to half of its capacity with the GT out of service. Another option is to install packaged boilers for use in the event of a GT outage.

To learn how best to design and operate a facility capable of providing electricity and thermal energy reliably, the Journal visited the Calpine Corp. of San Jose, Calif., perhaps North America’s largest merchant generator in GT capacity. Calpine operates more than a half-dozen facilities that have thermal contracts.

The company’s risk-mitigation strategy is to install large gas-fired packaged boilers at generating plants with a thermal host and to integrate the operation of these units into the facility’s control system to the extent necessary.

Calpine technical advisor Bill Stecker says that each packaged-boiler specification has unique design features to satisfy customer-specific requirements. To ensure success, Calpine works closely with its boiler suppliers. The first units installed for this purpose were three 200,000-lb/hr boilers manufactured by ABCO Industries, Inc. of Abilene, Texas, (no longer in business) for the Pasadena (Texas) Cogeneration Plant managed by Jim Bagley. Since that time, Calpine has purchased several boilers from Rentech Boiler Systems, Inc. of Abilene and from Foster Wheeler North America Corp. of Clinton, N.J.

Calpine favors the largest boilers that can be shipped completely assembled. That’s generally about 250,000 lb/hr. However, the company did install two preassembled 375,000-lb/hr units at its Baytown (Texas) Energy Center because they could be delivered by barge. Calpine opted for a 350,000-lb/hr Rentech boiler for its Columbia (S.C.) Energy Center, but that unit was prefabricated and shipped in sections (for example, the convection section was transported as one piece) and assembled at the job site.

The ABCO units were designed for service at a nominal 475 psig — the lowest-pressure packaged boilers installed by Calpine. Technical advisor Stan Kee says these were the first units in the fleet with seal-welded tubes (tubes were rolled, seal welded and re-rolled).

Now boilers typically are specified with welded tubes. Stecker says that rolled joints are more susceptible to leakage, primarily because of the rapid-ramp service conditions. The relatively small premium you pay for a quality welded joint certainly is worth the investment and the peace of mind that it brings, he added.

An advantage of the Rentech design, according to Stecker, is that it has minimal refractory — just for gas seals, drums and superheater header protection. This is more amenable to Calpine’s rapid-start requirements than a unit of conventional design with refractory in the floor and front wall. Thermal transients can hasten refractory deterioration and raise maintenance cost.

Materials specifications are industry standards for the pressures and temperatures characteristic of each installation. The highest steam conditions to date are the 1,500 psig and 950F required for four 250,000-lb/hr Rentech boilers being installed at Calpine’s Freeport (Texas) Energy Center at Dow Chemical’s Freeport works.

Calpine writes a challenging spec, one requiring that boilers be designed for a 30-year life with 20 rapid starts annually. The units must produce rated output from a hot start in less than five minutes and from a warm start in 30 minutes. Startup from a cold start is based on standard saturation pressure/ temperature curves supplied by the OEM.

The hot standby condition is maintained by operating the boiler with a fire in the center gas spud only. The heat input required depends on the particular unit, but it generally is less than about 13 million Btu/hr.

NOx emissions are of concern when on hot standby, and Calpine is pushing burner manufacturers — it relies on Coen Company of Burlingame, Calif., most often — to continually improve the emissions profiles of its firing equipment. Kee says that testing of a new Coen burner is ongoing, with the goal of achieving lower emissions. Work also is underway to reduce the amount of fuel needed to maintain a boiler in hot standby.

Warm standby is maintained by a steam coil, or a sparger, in the mud drum. Steam is supplied from the process header for this purpose.

The degree of automated control for the packaged boilers, according to Stecker, varies from job to job and depends, in large part, on contractual requirements. A typical control scheme used by Calpine provides for automatic ramp-up of auxiliary boilers on a digital signal from the GTs indicating a trip. The ramp-up sequence is started before instrumentation senses pressure decay in the steam header.

The startup philosophy employed for any given packaged boiler is influenced by steam production resources at the host’s facility. Some customers have boilers available for standby service; others have none. Typically, the controls on Calpine’s packaged boilers rapidly ramp a unit on hot standby to a part-load operating point; operator intervention (go/no go) is needed to continue the ramp up to full load.

Other design highlights of recent packaged boilers include:

  • Combustion control system has its own PLC (programmable logic controller). This permits boiler operation in the unlikely event that the plant DCS (distributed control system) fails.
  • Redundant instrumentation and control elements. Calpine factors into its design evaluation single-point failure reviews. The company does not want its boilers at risk to be shut down in a must-run situation by the failure of any given component. Design philosophy is “two out of three” logic schemes. This means that two of three flame scanners, pressure switches, etc., must signal for a shutdown for that to happen. Safety, therefore, is not compromised.

Selection of auxiliaries for packaged boilers also gets a thorough review. Cycle efficiency, turndown and blackouts all are factored into the decision-making process. Calpine generally opts for dual steam and electric drives when blackouts are a possibility.

FD fans often are steam-driven because of their wide operating range and higher efficiency than an electric motor for hot-standby service — the predominant operating condition. Exhaust from the turbine drive is used as pegging steam for the deaerator.

The packaged boilers at a couple of plants can burn refinery gas alone or in combination with natural gas. Coen burners usually are specified for multiple-fuel applications. Hydrogen is burned at another plant when available.

Plant operations
Stecker and Kee agree that the packaged boilers have met expectations and worked reliably. Their physical condition is excellent, as annual inspections attest.

Bagley manages two plants with thermal hosts — the 750-MW Pasadena facility noted earlier and the 560-MW Channel Energy Center. Pasadena is actually two separate plants connected only by an emergency steam line. Pasadena I, which went commercial in 1998, has one combined-cycle unit and three packaged boilers. This facility is the primary source for steam and electricity supplied to the host plant. Pasadena II, which went commercial in 2000, has two combined-cycle units. Channel has two combined-cycle units and three packaged boilers.

Pasadena I is a 1x1x1 combined cycle powered by a Model 501F GT from Siemens Westinghouse Power Corp. of Orlando, Fla. The condensing steam turbine is an extraction machine that supplies steam to a nearby refinery under normal operating conditions. Note that the HRSG is not equipped for duct firing.

Pasadena II, a 2x2x1 arrangement also incorporating 501F GTs, can supply the host if Pasadena I is forced out of service and the auxiliary boilers cannot completely satisfy customer requirements. In such an unlikely situation, Pasadena II would match process requirements by reducing the pressure of steam from its high-pressure (h-p) header.

The triple-pressure (1850/300/60 psig) HRSG for Pasadena I is equipped with an oversize h-p drum that can satisfy normal process requirements for 19 minutes in the event the GT is forced out of service. This is one of Calpine’s first plants with a thermal contract, and designers considered such conservatism appropriate at the time.

Maximum reliability was a design objective because the host has access to no other steam supply. Boiler auxiliaries offer further evidence of this. When Pasadena I was built, two of the auxiliary boilers were equipped with steam drivers for the FD fans and the feedwater pumps. These two boilers also have pneumatic controls. The third packaged boiler has motor-driven auxiliaries and electric controls. The controls for the third boiler can be powered from an emergency diesel/generator set that is used strictly for control power and telephones. The remainder of the plant could go black with no outside electrical supply, and the host would still get its steam.

Bagley says the packaged boilers are placed in service every time a Pasadena I turbine (GT or ST) trips (average is twice annually) and during planned outages. However, a turbine trip is simulated monthly to ensure that the boilers are ready to respond properly when needed. Bagley has his seven-year-old, 475-psig standby boilers at Pasadena arranged so that one is hot (center fire), another is warm (pilot on) and the third is cold. Assignments are rotated weekly.

On a GT trip or decrease in steam header pressure, the center-fired boiler is placed in service automatically. If it fails to enter service, the second boiler comes on line. One boiler is all that’s needed to meet the host’s steam requirements under normal conditions.

However, to maintain its perfect record — Calpine has never had a “no steam condition” at this facility — when the Pasadena I GT is out of service, Bagley operates two boilers to serve his customer. The third boiler is maintained in a hot standby condition. Bagley stresses that 100% reliability requires that all employees be proactive in their approach to meeting the host’s steam needs, and all must pay careful attention to detail.

Channel Energy Center
The Rentech boilers at Channel Energy Center are “more robust” than the units at Pasadena, Bagley says, and they can go from hot standby on center fire to full load in less than two minutes if necessary. The control system is set to ramp up the unit in slightly less than five.

The host for Channel has a much greater steam demand than the Pasadena host. It takes all three auxiliary boilers to satisfy Channel host’s normal steam demand. With such a large amount of steam being supplied to the host, the supply header would be drawn down very rapidly in the event both GTs were to trip off-line. This makes it essential that all three packaged boilers be available immediately in the event that both GTs trip. Ramp-up tests are conducted monthly, just as they are at Pasadena.

Channel differs from Pasadena in that its HRSGs have duct burners. Under normal operating conditions, one GT can trip off and the second GT with duct burners can satisfy the host’s steam requirement. In normal operation, either a dip in header pressure or a GT trip will cause the auxiliary boilers to “fire out,” according to Bagley. Once the steam header is stable and the plant is stable from the GT trip, the duct burners on the operating GT will be fired out and the auxiliary boilers returned to hot standby.

Bagley says that the packaged boilers have met expectations and that Calpine is now working with Coen to reduce NOx emissions from the burners on the auxiliary boilers and give the facility more flexibility on run time of those units. More run time on the packaged boilers means one GT could be cycled off-line when electricity prices are low. Environmental permit gives an annual NOx emissions limit in tons.

Corpus Christi Energy Center
Plant manager Paul Ostberg’s facility is a 2x2x1 combined cycle equipped with Model 7FA GTs from GE Energy of Atlanta, Ga., HRSGs from Alstom Power of Windsor, Conn., and an Alstom ST. Corpus Christi Energy Center also has two 250,000-lb/hr Rentech packaged boilers to ensure reliable steam supply to the facility’s three thermal hosts — two essentially at the plant fence, the other nearly a mile away. All three customers receive steam at 650 psig, one also at 250. Average sendout is about 600,000 lb/hr; maximum is more than a million lb/hr.

The plant’s 650-psig header is supplied primarily by turbine extraction steam or the turbine bypass valve. The h-p drum, which operates at a nominal 1,500 psig but is designed for 1,850, is oversized to satisfy host steam requirements for five minutes should the companion GT trip unexpectedly. The combined cycle also is capable of duct firing and sliding-pressure operation to optimize steam and electric production.

Normal operating procedure with the full combined cycle in service is to have one packaged boiler on hot standby. If operating in a 1×1 configuration, both packaged boilers are brought online and operated at a nominal 20% of their full-load rating. The boilers automatically ramp to 100% load based on either a GT trip signal or pressure-sag event. The operator manually stops the ramp if process conditions are satisfied and returns the boilers to header-pressure control.

The goal is to have more steam than needed and avoid a refinery process-header upset. The plant is equipped with automatic high-pressure sky vents capable of handling 250,000 lb/hr. Condenser dumps (extraction and low-pressure header) also are used to maintain constant extraction-header pressure during a process-upset condition.

Corpus Christi is capable of burning refinery gas alone or in combination with natural gas in both the duct burners and auxiliary boilers. The generating plant receives this byproduct fuel only when its steam customer cannot use the fuel in process operations and would have to flare it.

Ostberg conducts essentially the same periodic functional tests as Bagley to ensure 100% reliability, although the Corpus Christi boilers are tested weekly. Designers had this lofty reliability goal in mind when they specified a steam-turbine drive for the FD fan on one of the auxiliary boilers, and three 50% feed pumps to serve both boilers (two with electric drives, one steam). In 2004, there were three successful boiler ramps necessitated by a 1×1 GT trip event. Steam flow to the refinery was never interrupted.

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