By Steven E. Kuehn, Senior Editor
Before specifying a gas turbine for that next combined-cycle plant, take a closer look at diesels
Ironically, the role of the piston in power production seems to be expanding. The irony lies in the fact that technology developed at the turn of the last century is poised to take on an even greater portion of electric power generation at the turn of this century, despite advances in other, more contemporary prime movers such as gas turbines.
In their paper ODiesel Combined Cycles Using Fired Boilers,O (POWER-GEN Americas ?94, Orlando, Fla.) authors Thomas Davis, Sandwell Energy, and
F. Mack Shelor, Wartsila Diesel U.S., presented a compelling case why the diesel engine is a very attractive choice for
producing power in the combined-cycle configuration.
Davis and Shelor said the power industry is fast becoming aware of the pitfalls of designing power plants that rely solely on a premium fuel such as natural gas. Even though environmental regulations push plant developers towards gas turbines, there are drawbacks to consider. For example, gas turbine power plants often have to be built around available turbine frame sizes with a more narrow range of application than other prime movers. The authors claim that these facilities often have to operate at efficiencies far lower than originally anticipated because of extreme dispatching requirements that appear after the plant has been built. Moreover, some projects just won?t be built because the long-term fuel economics of the gas turbine combined cycle can make the choice unattractive.
Power plant developers are now faced with a challenge: How does one design a power plant that is as clean and efficient as natural gas-fired plant, uses proven components, has better wide-range performance and dispatching characteristics than gas turbines, and is more economically competitive than integrated coal gasification combined cycle technology? Diesels in a combined cycle (DCC), that?s how.
Their position rests on the fact that the medium-speed diesel is already one of the most efficient simple cycle sources of electricity, especially with lower grade fuels. Large units, said Davis and Shelor, have heat-rate efficiencies as high as 45 percent, equating to a heat rate of 7,580 Btu/kWhr, and no other power production prime mover can match this efficiency. Diesels also offer designers fuel flexibility and can burn an extreme variety of fuels without sacrificing many of its positive operating attributes.
Diesels are the first building block in a highly efficient combined cycle system that relies on the hot gas and oxygen in the diesel?s exhaust to combust either natural gas, light distillate oil, heavy oil or coal, in a boiler. Although the concept of recovering diesel exhaust heat and cooling water heat is not new, said Davis and Shelor, using diesels to help fire a boiler is. By using a fired boiler, steam can be generated at sufficient temperature and pressure to operate a Rankine steam cycle efficiently.
Diesel combined-cycle plants can be configured in much the same way a gas turbine plant would be. However, the diesel combined-cycle scheme requires supplemental firing to generate appropriate steam conditions. The most efficient cycle, therefore, would not be achieved until combustion air and supplemental fuel are minimized to levels that satisfy steam conditions, steam generation and power generation constraints.
Flexibility is the key to the DCC, and it can be tailored to meet specific steam and power needs. Davis and Shelor detailed several of the possible configurations in their paper. In a simple natural gas-fired scheme, supplemental combustion air is not required and the burner operates totally on the oxygen contained in the diesel?s exhaust and the burner?s fuel. Boiler temperature is controlled by the amount fuel gas added to the exhaust flow and is similar to firing a duct burner with supplemental fuel in a gas turbine combined cycle. However, unlike the gas turbine, the diesel cycle will always require some supplemental fuel to boost exhaust temperatures high enough to attain efficient steam conditions.
When heavier supplemental fuels are specified, some supplemental combustion air is required to attain stable combustion. When air is added, however, burner exit gas temperatures become too high for optimal heat recovery in the boiler. To dampen gas temperatures, a burner bypass system is fitted. The bypass redirects a portion of the exhaust gas so it can be injected into the boiler as overfire air. This allows sufficient oxygen to support stable lower-grade fuel combustion in the diesel exhaust stream while bringing down overall gas temperatures entering the superheater to a point just high enough to overcome boiler pinch points?the minimum differential between the gas temperature and the boiler saturated water temperature. Remember, for any given set of steam conditions and exhaust heat conditions, as the temperature differential increases, combined-cycle plant output will decrease and heat rate will increase.
Controlling the firing rate and burner bypass flow are features not commonly found on gas turbine combined-cycle plants. One plus of this feature is that
it allows a wide range of steam power demands to be met for applications such as industrial cogeneration where steam and power demand swings widely and independently.
For each cycle, according to Davis and Shelor, there is an optimum point of bypass flow where both the steam conditions and steam flow are achieved at maximum efficiency. As the efficiency of heat recovery increases, the amount of bypass flow will increase. OIn general, single pressure non-reheat cycles will have optimum efficiency at lower bypass flows such as 0 percent to 50 percent of the total diesel exhaust flow,O the authors explained, and that Osingle pressure cycles will optimize at approximately 50 percent to 70 percent bypass flow.O
Natural gas diesels
Natural gas-fired diesels are an established technology, have been available for years and have achieved efficiencies as high as 45 percent in the simple cycle. In the case of a DCC, a critical consideration for burner design is the level of oxygen in the exhaust gas leaving the engine. According to Davis and Shelor, large, medium-speed, four-stroke diesels injecting natural gas directly into the cylinder will have an exhaust gas oxygen level between 12.5 percent and 13 percent, and that is plenty to fire the supplemental natural gas.
Emissions from a natural-gas fired DCC are low to begin with and NOx reduction is an inherent part of the process. The combustion of the exhaust gas reduces NOx in two ways: first by reburning and second by dilution. This reduces NOx levels by as much as 50 percent to 70 percent when compared to the usual levels found in the diesel?s exhaust. It is likely small-scale DCCs will not require any NOx reduction, but larger units might need selective catalytic reduction (SCR) to meet very stringent control regulations.
Heavy fuel oil
Although combustion turbines are limited when it comes to fuel choice, diesels are not. Diesels have been designed to burn all grades of heavy fuel oil (HFO). Davis and Shelor noted that refiners are finding a weak market for HFO and that is favoring long term fuel contracts because high-sulfur HFO is in abundant supply.
Unfortunately, a diesel?s NOx and SO2 emissions are relatively high when operating in a simple-cycle arrangement. Several developments, including injector design, combustion chamber and piston design, and electronic engine controls, are being applied to help reduce emissions. After treatment strategies including SCR and scrubbers have also proven effective with high-sulfur HFO.
The DCC system takes advantage of these technology improvements and adds the effect of dilution from reburning to the equation, but there are some noteworthy differences, said Davis and Shelor. When HFO is used as a supplemental fuel to fire the boiler, special burners that supply a small amount of extra air are needed to achieve complete combustion. The increased oxygen allows more fuel to be burned and increases the effect of dilution. Babcock & Wilcox recently developed a proprietary burner design for DCC boilers optimized to maintain low oxygen levels in the windbox. Pilot testing was completed in 1994 and proved the unit was capable of stable and efficient combustion at the low oxygen levels needed to achieve optimum DCC performance.
Diesel and coal
Public Law 102-154 provides funds to the U.S. Department of Energy (DOE) to conduct cost-shared Clean Coal Technology (CCT) projects for the design, construction and operation of facilities that O. . . shall advance significantly the efficiency and environmental performance of coal-using technologies and be applicable to either new or existing facilities.O According to the executive summary at the beginning of the OComprehensive Report to Congress Clean Coal Technology Program, Coal Diesel Combined Cycle Project,O this act, together with Public Law 101-512, made a total of $600 million available for the fifth round of general requests for proposals under the CCT program.
Among the 24 proposals received by the DOE, five were selected for funding. One of the five was a coal diesel combined-cycle (CDCC) project proposed by a team consisting of Eaton Utilities Commission, Cooper-Bessemer Recip-rocating Products Div., Cooper Industries Inc., and Arthur D. Little Inc., with additional support from the Ohio Coal Development Office.
The DOE will provide funding assistance for the design, construction and operation of a 90-ton-per-day 14-MWe, diesel engine-based, combined-cycle demonstration plant using coal water fuels (CWF). The plant will be located at a power generation facility at Easton Utilities Commission?s Plant No. 2 in Easton, Md. The project, including the demonstration phase, is set to last 79 months and will cost $38.3 million. According to the report, the DOE will fund 50 percent of the project and with Arthur D. Little acting as the prime contractor.
Demonstrating the concept
The CDCC project will demonstrate an advanced CDCC system based on two Cooper-Bessemer 20-cylinder diesel engines. The demonstration is designed to provide critical data on the performance, reliability and component life information for all major subsystems, including the CWF metering and injection system, medium speed diesels, lube oil systems, exhaust cyclones, turbochargers, heat recovery steam boilers, steam turbines and exhaust emissions aftertreatment. The plant will be installed as a two-diesel extension of the existing 25-MWe generating plant and a total of 6,000 engine hours of testing is planned using CWF fuel.
The CDCC is expected to attain efficiencies of 48 percent lower heating value for the demonstration.
Based on contemporary stationary reciprocating engine technology, the CDCC relies on a recently developed process that allows coal to be burned much like heavy fuel oil. The basic layout of the plant consists of CWF preparation, two diesel engines, a combined-cycle power generation block and an emissions control subsystems (Figure 1).
The report states that Ohio No. 4, 5 and 6 bituminous coals will be mined at Sugar Creek, Ohio, and cleaned to 2 percent ash content. The CWF will be processed near the mine site and transported to the plant via 6,500-gallon tank trucks.
Specifically, the prime movers for the project are two Cooper-Bessemer Model LSV-20 engines. The 20-cylinder 4-stroke diesels (15.5-inch bore by 22-inch stroke) are rated at 400 rpm and 208 psi brake mean effective pressure. Each engine will be coupled to a 6.3-MWe generator and will consume 7,228 pounds-per-hour (pph) of CWF and another 84 pph of diesel pilot fuel. Each cylinder is fitted with a CWF injector designed with 18 orifices to ensure thorough combustion of the fuel/air mix. To combust the coal fuel efficiently, a small portion of diesel fuel is ignited first in a pilot combustion chamber adjacent to the primary combustion chamber.
To protect the turbochargers, the system relies on cyclones designed to remove 80 percent of 20-micrometer size particles and 50 percent of 5-micrometer size particles from the exhaust gas flow. Cleaned gas flows to the turbochargers while solids are removed from the under flow by a rotary valve.
Exhaust from the turbochargers then flows through a heat recovery boiler which makes steam to spin the steam turbine. To control emissions (Table 1), an integrated process involving several subsystems is used and includes in-cylinder NOx reduction, the cyclones, a selective catalytic reduction reactors for each unit, sorbent injection, the baghouse and a flue gas sampling system.
In a recent paper titled O100-MW Diesel Combined Cycle Power Plant,O Anders Ahnger, Wartsila Diesel, detailed the conceptual design of a large-scale DCC plant (Figure 2). The 100-MW plant is based on six Wartsila Vasa 18V46 engines and a steam turbine. Each of the six generators output 15.8 MWe and the steam turbine is rated at 8 MW to 11 MWe depending on the fuel, either natural gas or heavy oil.
The plant is divided into two three-by-three separate engine rooms with a middle section including all major common equipment. The middle section includes all the electrical systems, high and low voltage, the central cooling system and water treatment.
According to Ahnger, careful consideration was given to the noise aspects of the plant and it can meet even the most stringent regulations. The design value for the plant is 45 decibels at approximately 300 feet from the plant. To achieve this, each diesel is enclosed in a separate room and sound-absorbing materials are used in
Special attention was also paid to the logistical aspects of the plant. Because some of the engine spare can weigh more than a ton, the plant is fitted with small local cranes, separate cranes in each engine room and cranes strategically located to move spares and equipment through the plant.
The plant can be fully automated depending on the operators needs and local labor costs using programmable logic controllers. The system covers engines, the steam turbine, the electrical system and emissions controls.
Because diesels in the 15-MW to 16-MW range already have gross efficiencies of 45 percent to 46 percent, 50 percent efficiencies in the combined cycle are easily attained. For the 100-MW concept, the combined cycle is based on an ordinary steam cycle. The available engine heat sources, i.gif., exhaust heat and heat rejected to the cooling system, are used to produce steam. Each engine is fitted with an exhaust gas boiler which is equipped with economizers, evaporator and superheater sections, and individual steam drums and controls. Optimal steam pressures for the condensing turbine?s cycle are 176 psi for heavy oil operation and 120 psi for natural gas operation. For back pressure applications, higher steam pressures are required and would call for a fired boiler arrangement similar to the one discussed previously in this article.
There is plenty of evidence that applying reciprocating engine technology
in a combined cycle can offer power producers efficiencies and operational flexibility. Indeed, gas turbines also poses their fair share of these same attributes, but DCC plants may have an edge when it comes to part-load conditions and when natural gas fuel supplies are questionable. Although not addressed here, maintenance and reliability issues come into play, particularly when poor quality fuels are used, and a close analysis of associated costs is advised. Nevertheless, DCC is a well-developed concept and may be an ideal way to solve often conflicting design requirements. END
NOX reductionb (%) 90