Cycle Modifications

The most common cycle modifications are:

Regeneration ⇒ internal exchange of heat within the cycle. Note the regenerator or recuperator in Figure 3–11. Regenerator effectiveness or efficiency is less than 100%. If the compressor outlet is heated to T₂′, then regenerator effectiveness is:

${\text{ε}}_{\text{R}}=\frac{T_{2^{\prime }}-T_4}{T_4-T_2}$

Let’s say that = 75%.

The rise in efficiency is notes in Figure 3–10. However, the optimum pressure ratio for an efficiency value drops,

$\because PR\downarrow \Rightarrow (T_4-T_2)\uparrow$

Cycle heat input drops further.

At some point, the temperature of exhaust gases < post-compression air, or the regenerator is ineffective.

Intercooling involves taking compressed air at a given stage of compression, cooling it (which increases its density and therefore the mass of air that can be compressed) and leading the cooled air back to the next stage of compression. There may be more than one stage of intercooling (see Figure 3–12).

In Figure 3–12, the increase of work provided by intercooling is 21′2′1′2′ × 2. More heat had to be added to get this work increase. Per unit mass that additional heat is:

$h_x-h_{2^{″}}$

However, a net efficiency increases results.

Reheat involves taking gas from an interim stage in the turbine, adding heat to the gas and then leading it back to the turbine (see Figure 3–12). One stage of reheat is shown.

Water injection increases power output significantly and efficiency slightly. Water is injected into the compressor and vaporizes as the air temperature increases. The heat of vaporization reduces the compressed air temperature. This lowers compressor work (see Figure 3–13).

Combined Cycles

The most common types are:

Figure 3–14 illustrates the first kind (HRB).

$\text{HRB}=\text{EC}\left(\text{economizer}\right)+\text{B}\left(\text{boiler}\right)+\text{SU}\left(\text{superheater}\right)$

To increase output through limited duration peaks, SF (supplementary fuel) is used.

STAG CC

In Figure 3–15, 4 GE Frame 7s exhaust to air or produce steam in 4 HRBs that send steam to one ST. The combination can provide 600, 800, 1000, or 1250 psi steam.

CC with Multipressure Steam

In Figure 3–16, the HRB has two steam circuits:

In Figure 3–17,

Steam-Only (Coal-Fired) Power Plants

The forecast projects 10% of the new orders will be steam power plants in 60 Hz market from 1999 to 2003 (Figure 3–19). In the 50 Hz market, the key ranges are 300–500 MW and 500–700 MW. Above 700 MW, supercritical technology represents a small but growing market share.

OEM Modular Strategy

As previously discussed, to save on costs to both OEMs and end-users, OEMs developed modular plants. Siemens has 12 basic power plant combinations (Table 3–2): four for open cycle gas turbine plants, six for combined-cycle plants, and two for coal-fired steam power plants (with sub- and supercritical technology). Each combination covers a specific power range, efficiency, and fuel specification, with allowance for cogeneration system additions.

For design flexibility, options to the reference version for each major functional unit (Figure 3–20) are provided. For example, via ship is the reference for the functional unit coal supply with delivery via rail as an option. Flexible design requires breaking down the power plant into functional units, each of which directly affects only one or two other modules. For a combined-cycle plant, the functional units are arranged around the gas turbine and steam turbine. With the gas turbine, as we saw earlier, OEMs strive to maintain core feature commonalities.

Fuels for Combined Cycles

Gas turbine operators prefer to burn natural gas and light oil (diesel, No. 2). As we saw previously, crude oil, residuals, and “bunker” fuel contain corrosive components. They require fuel treatment equipment. Also, ash deposits from these fuels can result in gas turbine derating of up to 15%. As we also saw previously (in the case of the Shunde plant in south China), they still may be economically attractive fuels, particularly in combined-cycle plants.

Sodium and potassium are removed from residual, crude, and heavy distillates by a water-washing procedure. A simpler and less-expensive purification system does the same job for light crude and light distillates. A magnesium additive system reduces vanadium.

Note that reduced availability results, due to water cleaning shutdowns to remove blade deposits, as online washing, even at reduced speeds, is not effective. A shutdown with a crank soak every 100–120 hours is required. Reduced component life due to hot gas path corrosion caused by vanadium deposits and other corrosion is another factor to consider.

Table 3–3 provides a sample of naphtha- and heavy oil-fired power plants in operation and in the planning stage. As this table shows, some plants (e.g., Kot Addu and Valladolid) accumulated 30–60,000 hrs of successful operation over their first five years plus.

Design and operation of these plants requires more attention than natural gas-fired plants, particularly in relation to fuel variables such as calorific content, density, composition, concentration of contaminants and emissions, as well as different burning behaviors (e.g., ignitability, flame velocity, and stability).

To overcome these difficult fuel properties, technological adaptation, additional equipment, and operational requirements are necessary. These include GT layout (compressor, turbine) for the changed mass flows, different burner technology (burner design, burner nozzles), and additional startup/shutdown fuel system and safety measures. Performance, availability, and operation and maintenance (O&M) expenses can be affected. To illustrate this, Table 3–4 shows some key non-standard fuels and their effect on a standard fuel system.

An example of a gas turbine combined-cycle plant burning a nonconventional fuel is the 220 MW Valladolid plant in Mexico. This plant, commissioned in 1994, burns heavily contaminated fuel oil, containing 4.2% sodium and up to 300 ppm vanadium. Fuel impurities (sodium, potassium, and vanadium) tend to form ash particles in the combustion process, form deposits, and corrode the gas turbine blades. In the case of the Valladolid plant, “Epsom salts,” consisting mainly of magnesium sulfate (MgSO₄ 7H₂O), are dissolved in water injected into the gas turbine combustor through special orifices. This converts the vanadium into a stable water-soluble product (magnesium vanadate), which is deposited downstream of the combustor on the gas turbine blades, and causes only minor blade corrosion. To prevent major performance loss with salt buildup (as with the Shunde, China, plant that we read about previously), washing every 150 hours was necessary to restore aerodynamic performance and plant efficiency. Good manhole access was a critical success factor for this project, as servicing and maintenance during turbine washing shutdowns are simplified. (The plan is to eventually convert the Valladolid plant to natural gas operation.)

Factors that Affect Costs per Fired Hour

Fuel type and mode of operation (steady load/partial load) determine the maintenance intervals and work items required. Some estimate that burning residual or crude oil increases maintenance costs by a factor of 3 (assuming a base of 1 for natural gas and by a factor of 1.5 for distillate fuel) and those costs are three times higher for the same number of fired hours if the unit is started every fired hour, instead of starting once very 1000 fired hours. “Peaking” at a 110% rating increases maintenance costs by a factor of 3 relative to base-load operation at rated capacity, for any given period.

The control system on combined-cycle units is automatic. When an operator starts the unit, it accelerates, synchronizes, and loads “by itself.” Fewer operators are required than in a steam plant.

Trends in Global Combined-Cycle Installations

A few hundred power generation plants are ordered from about a dozen OEMs every year. This means the market is exceptionally competitive. Given that most of the new plants are going into newly developing countries, the biggest factor in determining the winner of each project (bid on by several OEMs or not) is the financial deal the OEM can put together for the end-user.

As one might expect, maintenance costs are higher for any type of plant in countries that have not had as much exposure to the OEMs’ technology. As a significant extension of their revenue, OEMs offer overall “power by the hour” maintenance contracts. These costs vary, even for the same basic modular configuration and mechanical design, depending on the location’s demographics. So then will the actual and contractually set “cost per fired hour” figures. There is a significant difference between what actual operational costs are for the same OEM’s CC block in a well-developed area of the United States and a remote area in Azerbaijan, for instance. Demographics also alter construction costs. (As an illustration, in 1990s figures, costs varied from $592/kW for a new 1080 MW combined-cycle plant in Egypt to $875/kW for a steam addition to convert four gas turbines in Pakistan to a combined-cycle plant, according to World Bank data.) OEMs are aware that end-users compare cost data at various meetings and forums and that price variations are a sore and much negotiated point. Therefore, OEMs continually strive to optimize designs and assembly methods to minimize the steepness of new operators’ learning curve.

“Modularization” (for instance, the Siemens Westinghouse GUD block, which is two V94.3 gas turbines, their HRSG boiler capacity, and a steam turbine) reduces construction costs. Compared with the customized design and construction, modularization can reduce project costs of detailed engineering, material price contingencies, and financial loan interest during construction.

Downsizing power delivery (to the grid) requirements changes overall operational cost figures. “Repowering” changes operational statistics significantly. Repowering is a term used to define the reconfiguration of a power station. It may mean replacing a steam turbine with a gas turbine or combined-cycle unit. One example of a repowering option offered by an OEM is Alstom combining its 181 MW GT24 gas turbine with a dual pressure reheat cycle consisting of a 70 MW LP/IP steam turbine and a 20 MW HP steam turbine, to generate a total of 270 MW.

The most common configuration (Figure 3–21) is called parallel powering, where the gas turbine exhausts are used in the existing steam cycle. This is achieved by feeding the exhausts into a heat-recovery steam generator, which provides additional steam to the existing steam turbine. Typically, parallel powering requires the addition of a gas turbine, associated electrical and instrumentation and control equipment, civil engineering, HRSG, additional piping, and pumps, as well upgrading the steam turbine. Generally, parallel powering can be undertaken separately from the existing part of the plant, with a final integration phase and a plant downtime of 1.5–2 months. The typical cost range is $300–500/kW.

In some cases, national or international markets alter a power plant’s budget by changing available fuels. An example would be the United Kingdom’s temporary moratorium on their indigenous natural gas (which promoted coal for that period). When the decision was made to allow North Sea petrochemical liquid deposits to vaporize and be delivered as gas instead, that move created operational ripples in all industries that used petrochemical fuel, including power generation.

Since the late 1980s, market growth in plant additions and optimization technology retrofits has shifted, in part, from Europe, North America, and Japan to newly industrializing countries in Asia and Latin America. Financial means keep many of the end-users in these regions from using newer technologies that would extend their power generation capacity and reduce their costs per fired hour. Nevertheless, they are becoming increasingly aware of these design developments and seek to incorporate them where and when possible.

For the OEM, the main challenges are minimizing project cost, construction time, and risk guarantees (Figure 3–22). Between the 1980s and 2000, project cost and construction time of coal- and gas-fired units dropped by 50%. However, to compete, OEMs must offer better warranty packages. So the standardization of core design to minimize spare costs and make factory assembly methods and repair and overhaul methods “foolproof” increases in importance.

Table 3–5 shows the cost breakdown for combined-cycle plants (350–700 MW capacity) based on Siemens experience in the following categories: integrated services (project management or subcontracting; plant and project engineering or project management software, plant erection, commissioning, and training; transport and insurance) and lots (civil works, gas- and steam-turbine and generator sets, balance of plant, electrical systems, instrumentation and control systems, and the boiler island).

Trends in the Power Generation Market

From 1994 to 1999, power plant contract awards for fossil fuel-fired power plants (above 50 MW) averaged 63 GW per year. In 1999, sales were forecasted to average about 67 GW per year over the period 1999–2004. The market in the Asia Pacific Basin was declining, while showing a moderate growth in Europe and (starting from a low level) strong growth in North America.

In comparison with coal-fueled power plants, open and closed cycle power plants are characterized by lower investment costs. However, US fuel-related costs (i.e., fuel price and plant efficiency) have changed with the rise in oil and gas prices in the United States, which was precipitated by the Iraq War and Hurricane Katrina. At the turn of the century, gas prices ranged from about US$2.0/GJ to US$4.5/GJ, with the North American prices being at the lower end of the range.

The only fact that anyone can attest to, in terms of oil and gas prices in 2006, is that they will go up. One Canadian forecast agency suggests that gas prices in 2006 in Canada will stay at about C$8/GJ. This then means that the fierce inter-OEM rivalry with respect to fuel efficiency will escalate.

Three major infrastructure changes continue to drastically alter the face of the power generation industry and directly or indirectly promote technological innovation. They are:

Integrated Gasification Combined-Cycle (IGCC) Plants Integrated gasification combined-cycle (IGCC) plants consist of three main sections:

IGCC is a combination of two proven technologies; however, proper integration depends on using the lessons learned from several demonstration projects in Europe and the United States. Currently, more than 350 gasifiers are operating commercially worldwide and there are at least seven technology suppliers. About 100 CC unit plants are ordered per year, but there is limited experience in IGCC commercial operation. Currently, we refer to operating experience at five IGCC plants: the 261 MW Wabash River plant, the 248.5 MW Tampa plant, the 253 MW Buggenum plant, the 99.7 MW Pinon Pine plant, and the 318 to 300 MW Puertollano plant. IGCC will see commercial application in developed countries, such as Italy, for residual refinery fuels and gasified coal. However, great care needs to be taken in implementing a commercialization strategy for developing countries.

Through 2015, the potential for refinery-based integrated coal gasification combined-cycle plants is estimated to be 135 GW. Currently, over 6 GW of coal- and refinery residue-based IGCC projects are either under construction or planned.

Technology, Performance, Environment, and Demand Trends

Figure 3–23 compares the supply flows, emissions, and by-products of different 600 MW-class plants. With environmental emissions (including greenhouse gases, GHG), IGCC plants compare well with pulverized coal-fired steam power plants.

Depending on the degree of integration between the gas turbine and the air separation unit (ASU), either standard gas turbine or compressor configurations can be applied. If not, the mismatch between turbine and compressor mass flows, which results from the application of gases with low heating values, requires limited modifications to compensate.

Three options are available. The selection of the appropriate air and nitrogen integration concept depends on a number of factors, to be considered on a case-by-case basis. A summary of the important criteria is provided in Figures 3–24 and 3–25.

Figure 3–23 sets out the principal criteria for selection of the different IGCC integration concepts. The “fully integrated approach” (selected for the European coal-based demonstration plants) results in the highest efficiency potential, but it can prove more difficult to operate. Nevertheless, after some initial operational problems, the Buggenum IGCC facility demonstrated that the design can provide good availability.

The nonintegrated concept with a completely independent ASU is simpler in terms of plant operation and possibly in achievable availability. However, the loss in overall IGCC net plant efficiency compared with the fully integrated concept is 1.5–2.5%. So this concept is of interest for applications where efficiency is not the key factor (e.g., for the gasification of refinery residues).

The concept with partial air-side integration is a compromise, with only a moderate loss in efficiency but improved plant flexibility, when compared with the fully integrated concept.

What follows are some examples of gas turbines that can be incorporated into combined-cycle packages. The Siemens SGT6-5000F (198 MW, 60 Hz) operates under simple cycle, combined-cycle, and other cogeneration applications. The SGT6-5000F gas turbine has more than 1 million hours of fleet operation. It can be used in either simple cycle or heat recovery applications, including cogeneration, combined cycle, and repowering.

The SGT6-5000F provides online generation for peaking duty, intermediate operation, or continuous service.

The SGT6 5000F’s technical features include:

The Siemens SGT5-2000E (163 MW, 50 Hz) operates under simple or combined cycle and other cogeneration applications. The SGT5-2000E is used for simple or combined-cycle processes with or without combined heat and power and for all load ranges, particularly peak-load operation. For integrated coal gasification combined-cycle applications, Siemens provides the SGT5-2000E (LCG) machine, a 2-type machine with modified compressor. The SGT5-2000E has more than 120 units in operation, accounting for approximately 70,000 starts and more than 4 million operating hours.

The SGT5 2000E’s technical features include:

Brand New Models

In recent years, the heavy-duty GT industry made important technical strides to cater to the all-important combined-cycle power plants market. The introduction of the “G” and “H” technologies, offered currently by manufacturers, creates an inseparable thermodynamic and physical link between the primary and secondary power generation systems by using steam (in lieu of air) in a closed loop to perform most, if not all, GT cooling.

These new GT designs rely on an evolutionary process using a proven existing design base and manufacturers’ accumulated expertise. However, to achieve substantial performance improvements and meet stringent low-emissions requirements, major design changes or even new designs must be implemented.

Note the “cross pollination” between stationary and aeroengine designs. The aeroengine manufacturers, such as Pratt & Whitney and Rolls Royce, entered into commercial agreements with heavy-duty GT manufacturers, such as Siemens-Westinghouse and Alstom. The GE R&D group and Aero-Engine Division likewise played an important role in GE Power Systems’ heavy-duty GT development. Compressor and turbine aero-design, air and steam cooling, combustors, and intake and exhaust systems are just a few examples of this type of technology transfer.

The development process requires individual component testing for all major GT features, including the compressor, combustion system, and turbine. Despite extensive multiphase validation and integration programs, all new GTs have exhibited many “first of a kind” technical challenges in the field. Table 3–6 summarizes some of the issues publicly acknowledged by the manufacturers. OEMs, EPC contractors, and insurance carriers all paid a hefty price to correct these problems in the field.

Manufacturers (including Alstom, Siemens, and MHI) established their own in-house (load) test facilities to evaluate equipment performance in a completely controlled environment and identify potential problems earlier. Others selected the alternative approach of using power plants as validation sites, where plant owner(s) allow the OEM to conduct tests using additional instrumentation and to implement changes in exchange for special commercial arrangement. Table 3–7 lists test facilities for major manufacturers.

The testing of the equipment at these facilities is useful in identifying short-term issues for validating compatibility of various components and optimizing performance. Many solutions for the dry low-NO_x (DLN) combustor problems were worked out at these sites, where complete combustion systems could be tested.

Testing of the complete GT (compressor, combustor, and turbine) is necessary to validate the combustion system design, since rig tests alone are not sufficient to determine the interaction between individual components. Note that the test facility cannot replicate the actual operating condition(s) (fuel variability, load following requirements, and extreme ambience) of other locations and the machine’s long-term behavior.

Existing Model Upgrades

It is typical of OEMs to upgrade and improve the thermal or mechanical performance of their existing models. This, however, poses a very interesting question—should these upgrades be treated as “tweaks” or as brand new models? A good example involves the GE 7FB and Siemens-Westinghouse 501 FD models, which provide thermal performance far superior to that of the original “F” models.

The evolutionary process for the GE “F” technology class is illustrated in Figure 3–26. The power output increased from 150 MW to 174 MW and the heat rate improved by about 7% over a period of 10 years. The major changes include increased airflow and pressure through the compressor and higher firing temperature resulting from use of better materials for the turbine blades and nozzles (single crystal).

The two tracks of performance betterment—brand new models and existing model upgrades—interact. Many of the improvements from the “H” class of GT are flowing back to the “F” and “G” class equipment.

The most recent examples include the GE 9FB’s implementation of many GE “H” system features, and the MHI M701G2’s superior performance over that of the original M701G GT, based on M501H technological enhancements.

When GT development work had to be carried out in the field, the manufacturers stood behind their products and provided the needed support until the issues were solved. Performance shortfalls and schedule were dealt with through the contractual commercial agreements.

Equipment Selection

An experienced EPC contractor remains technology neutral but proactive in identifying the best available technology meeting owner requirements. Therefore, before selecting the equipment, the EPC contractor must understand the owner’s pro forma objectives for plant output, heat rate, reliability, availability, and emissions requirements.

The process entails a comprehensive technology assessment with the supplier and other previous users of this technology. The performance offered by the OEMs for a specific project must be normalized and correlated with the performance of the same GT, achieved at other executed projects. The analysis should also include a comparison with other OEMs’ competitive products.

The EPC contractor creates an in-house database for field test data. Figure 3–27 summarizes test data from 29 units recently completed by Bechtel and includes all major manufacturers.

In addition to the power output and heat rate, the major issue related to evaluation of GT performance in combined-cycle applications is quantification of the GT exhaust flow and temperature. All four of these parameters for a GT are heavily interdependent. For example, a GT that exceeds the guaranteed power output usually has a better-than-expected component efficiency, particularly for the turbine section. As a result, the exhaust temperature is lower. A lower turbine exhaust temperature has a negative impact on the heat recovery steam generator’s steam production and steam turbine output. Conversely, higher GT exhaust energy has a positive impact on ST output.

No GT meets all four guarantees concurrently. When establishing the HRSG and ST design conditions, it is good engineering practice to allow for some variability of GT exhaust flow and temperature. This way, the design could accommodate either shortfalls or better-than-guaranteed exhaust energy (flow and temperature) of the GT.

Figure 3–28 quantifies the effect on the combined-cycle heat rate, due to a 5°F lower exhaust temperature and a 1% better turbine section efficiency. Figure 3–28 also shows that, for the same firing temperature, a 1% improvement in GT performance overcomes the performance loss due to a 5°F shortfall in exhaust temperature and still results in 11 Btu/kWh (0.16%) improvement in combined cycle heat rate. These numbers may vary for different GT makes and models.

To properly assess the impact, owners or operators need to either hire an EPC contractor experienced in purchase, have a reservation agreement for a GT or power island (PI), or have the appropriate skills secured from a different source. The EPC contractor can verify:

They can also assist by:

Table 3–8 lists technologies and locations for various projects around the globe involving GTs from three major suppliers.

Emissions

GT designers have to balance two contradictory requirements: better performance and lower plant emissions. On the one hand, to achieve higher output and better heat rate, OEMs have to increase the firing temperature or the airflow through the machine, thus leading to higher amounts of pollutants. On the other hand, regulatory agencies in the United States require ultra-low emissions of less than 2.5 ppm for NO_x, CO, and ammonia slip.

Power plants based on either “F” or “G” technology cannot meet the ultra-low emission level without postcombustion emissions control methods. Figure 3–29 depicts the history of tightening NO_x emissions requirements at the stack in the United States.

Post-combustion devices, such as selective catalytic reduction (SCR) for NO_x and CO oxidizer for CO and volatile organic compounds (VOCs), are commonly used. They add complexity and cost and lengthen the startup schedule. In some “G” class machines, the effectiveness of the SCR must be over 90% to meet the 2.5 ppm NO_x stack emissions limit.

Fuel

Due to the higher cycle pressure ratio, the “G” GT needs higher fuel pressure at the GT interface flange. Because the gas pipeline pressure typically is lower, a suitable fuel compression system with associated interfacing controls is required. A filtration and purification system also is necessary to avoid entraining droplets of liquid lubrication oil (heavy hydrocarbons) in the gas. Premix combustion systems are very sensitive to the presence of heavy hydrocarbons in the fuel, causing premature ignition “flashback.” From a reliability viewpoint, fuel system redundancy is an important consideration in selecting the fuel gas compressors.

In combined-cycle applications, it is common to preheat the fuel with hot water or steam to improve the plant heat rate. However, the fuel preheating system has been an issue for some new GTs, mainly due to combustion oscillations.

Cooling Steam Quality and Blowdown Design

In “G” technology, intermediate pressure steam cools combustion transition ducts. The use of steam as a cooling medium calls for special attention to achieving and maintaining the specified steam quality. While the steam quality requirements (silica, sodium, chlorides, and total organic compounds, or TOCs) for advanced GTs using steam cooling are no more stringent than the normal steam quality requirements of a combined cycle, deviations or excursions from the requirements can lead to serious consequences.

To avoid such situations, state-of-the-art reverse osmosis or electrodialysis ion exchange demineralizer water treatment systems have been used. Special attention should be given to the transient conditions during startup and power ramping. In these modes of operation, drum water characteristics, especially pH, are difficult to control.

As a result, passivity films can be removed, corrosion products can be displaced, internal treatment chemicals can be over- or underfed, and finally, steam purity can be compromised. Exceeding equipment manufacturers’ limits poses a significant risk to the owner-operator.

Balance of Plant Issues

Proper system integration is vital to achieving guaranteed performance. System integration via balance of plant (BOP) equipment and interconnecting or support systems is the key that enables the GT, HRSG, and ST to operate smoothly and efficiently at all design loads and configurations.

While the BOP requirements for the new generation of GTs are no different than earlier GT designs, the larger size of BOP systems (amount of circulating water, steam, air, and fuel) warrants careful attention.

In several GT models, the cooling air circuits include external heat exchangers. This process increases the overall efficiency of the plant by utilizing the rejected heat in the steam cycle rather than dissipating it in the atmosphere. However, the mechanical layout design and control of the associated piping for air and steam are challenging tasks.

A majority of the recently completed plants using advanced GTs are merchant plants (MPPs) and dispatch only when competitive. Accordingly, the BOP design should respond to cycling operation requirements.

The selection of an optimum heat sink is site specific, since it is based on many variables, such as site configuration, water availability, water disposal, ambient conditions, level of target power output, anticipated hours of operation, the power purchase agreement structure, and the owner’s economic evaluation factors. Table 3–9 lists the heat sinks selected by Bechtel for some recent projects.

Startup

EPC contractors generally are responsible for plant startup. Significant penalties are assigned if timely operation is not achieved.

Dual-Fuel Operation

Typically, advanced GTs use natural gas as the primary fuel. Duel-fuel capability, using distillate oil, is attractive to many customers with interruptible gas supply contracts. However, dual-fuel capability adds complexity to already very complicated combustion systems and controls. A difficult challenge is to achieve switchover from one fuel to another at a reasonably high GT power level.

Implementation of Modifications in the Field

One of the most critical challenges to erection of advanced GTs has been implementation of field modifications. On many occasions, the OEMs used unscheduled outages, not only to correct a problem but also to implement a number of design changes based on lessons learned on other sites. This process created a “ripple effect” requiring additional changes in the plant control software and start sequences.

Combustion System Commissioning and Tuning

To meet strict emissions requirements, all advanced GT combustion systems operate with DLN combustion systems. The combustion process between 70% and 100% load takes place in premix mode with a lean equivalence ratio, which creates a lower localized flame temperature and therefore lower NO_x.

The premix combustion operation, in which fuel and air are mixed in advance of the combustion process, is less stable than diffusion flame. It is common practice to use a pilot operating in diffusion mode to provide stability and inhibit the excessive combustion-related pressure fluctuations inherent in the lean premix operation.

The combustion system operation from diffusion mode at low loads to full premix mode at base load takes place in several complicated steps and stages, requiring very close control of fuel flow and exhaust temperature. The process is sensitive to ambient conditions, combustion-associated instabilities, and even physical combustor dimensions, due to manufacturing or assembly tolerances.

Currently, each GT is individually adjusted to meet the performance guarantees and emissions requirements without combustion oscillations. This practice has become a standard feature of the GT commissioning. However, this activity has an adverse impact on the EPC contractor.

The execution schedule is extended to perform a water wash of the compressor prior to the tuning process and to install and remove temporary instrumentation for full-blown GT performance testing. Because emissions limits must be met at all ambient conditions, adjustments made in the field might modify the performance correction curves for ambient temperature.

Introduction

The SGT6-5000F (formerly known as W501F) engine has demonstrated an exceptional operational record over the 16-year, 5.7 million fleet hour operational history. Since its introduction in 1993, this F-class gas turbine has undergone continuous development to improve performance, reliability, and operational flexibility and to reduce emissions and life cycle costs. This gas turbine, which was designed for both simple-cycle and combined-cycle (CC) power generation in utility and industrial applications, represented the next model in the successful W501 family. Its design was based on fundamental, time-proven design concepts as well as new concepts and technologies incorporated to increase efficiency, reduce NO_x and CO emissions, and enhance reliability. It was designed to operate on all conventional fuels, as well as coal-derived low Btu gas. New technologies were validated for engine application by extensive rig and two full-load engine shop tests, as well as field tests in the initial installation.

Figure 3–30 shows the latest evolution of the SGT6-5000F(4) engine. The 13-stage compressor is connected to the 4-stage turbine by a single tie bolt, and the Ultra Low NOx combustion system employs 16 can-annular baskets. The 213 SGT6-5000F engines currently in service are employed in peaking, intermediate, and continuous duty operation. The fleet has amassed more than 5.7 million operating hours and has demonstrated excellent reliability, availability, and starting reliability.

Due to design enhancements, development efforts and technology cross-flow from other Siemens’ advanced gas turbines, the rated simple cycle output has increased from 150 MW to 208 MW and its rated efficiency from 35% to 38+%. In 1×1 CC applications, the rated net plant output and efficiency can now be more than 300 MW and 57.5%, respectively.

The W501G (also known as SGT6-6000G) gas turbine (Figure 3–31) design concept was driven by the changing power market. Between 1993 and 1995, the power market was moving toward deregulation and replacement of aging base load plants, such as coal-based power plants. The market was demanding clean and highly efficient combined cycle plants. Expectations of deregulation in the North American electricity market caused prospective plant buyers to turn to cleaner plants with shorter installation and commissioning times compared to traditional coal plants which had a six year (or more) lead time to permit and build. The belief, expressed by many of them, at that time was that the new high-efficiency, low emissions, clean fuel plants would be the economic and environmental choice and displace coal plants. Because the W501G had a high rated efficiency, it was intended to be operated primarily at base load.

In the late 1990s there was an increased demand for electric power and a relatively low price for natural gas, at one point about $2.50/MMBtu, causing an increased demand for gas turbines for simple- and combined-cycle operation. By 2002, the demand for power was subsiding and some areas were over capacity. Natural gas had increased to above $6/MMBtu and the price for electricity had decreased causing gas turbine combined cycle plants to be operated on the average (based on reported information) at only 30% capacity (higher utilization was reported for advanced frames including the Siemens F & G fleet). The increased natural gas price caused some combined-cycle plants to move lower in the dispatch order causing them to operate in cycling duty mode. In this context, the amount of time some merchant plants can operate profitably may be significantly reduced. In response to the change in market demand for more cyclic operation, design changes and improvements are regularly being incorporated into the SGT6-5000F and the W501G engines.

Introduction

The unique challenges involved in designing a power generating station to support the special needs of an industrial processing facility are discussed. A conventional combined-cycle (CC) power plant has one basic goal: to produce electricity at a minimal cost for sale to the grid. In industrial facilities (e.g., oil refineries, smelters, and chemical and desalinization plants), electricity and steam produced are for internal use rather than export. Since power and/or steam supply interruptions might have catastrophic effects on facility processes, the paramount requirements for this type of dedicated plant or captive power plant (CPP) are availability and reliability rather than high thermal performance.

In recent years, the advanced H- and G-class GTs, which use steam to perform GT cooling duty, have successfully demonstrated close to 60% efficiency in CC applications and accumulated thousands of operating hours. Many improvements in the G and H class were integrated into the FB and FD class of aircooled GTs. However, industrial applications commonly use older D- and E-class medium GTs as the prime mover. Given that the fundamental purpose of a CPP is different than a traditional power station, this case covers CPP application requirements and the means to optimize these requirements in key areas to support required industrial processes. To illustrate the design methodology, three cases (a refinery, a cogeneration facility, and a smelter) are presented, describing an engineering, procurement, and construction (EPC) contractor’s perspective on the unique industrial application constraints and proposed solutions to meet owner requirements. It also identifies the specific applications in which use of advanced classes of GTs might be suitable.

Captive Power Plant Concept

A CPP uses same major components as a traditional CC power plant; however, it is designed to achieve a different objective: the production of power and steam is “captured” for industrial use and is only sold to the grid when applicable. The differences between the two types of plants in an oil refinery environment are described below.

Assume a CPP is being constructed to support a new refinery crude train (RCT), which will produce 1 million barrels of oil/day. The oil refining process will require a constant supply of high pressure (HP) steam and electricity. If the steam or power supplies are interrupted or fall outside the narrow band of specified supply conditions, the associated processes could be ruined. As a result, a batch of products will be disposed of, leading to heavy financial penalties. Refer to Table 3–10 for typical CPP requirements. In this case, in addition to using GTs as prime movers, the critical demand for steam will require that additional conventional boilers be incorporated.

Key CPP Design Criteria

Major design areas to be analyzed include:

Power Demand

Early in the evaluation process, it was determined that the refinery electricity requirements could be met by CC components only (GTs and back-pressure steam turbines [BPSTs]). Several combinations were considered to meet the 650 MW power demand. Various GT and BPST candidates and their MW ratings are listed in Table 3–11. The selection of larger frame GTs can decrease equipment quantity, but do not meet the N-2 criteria (minimum number of operating GTs necessary to meet the power demand).

Due to the large oil production rate (1 million barrels/day) and associated power requirements (650 MW) of the RCT, as shown in Table 3–10, six GT Model 3 units were selected for this application. Ultimately, their relatively large unit power output and operational track record made them the most suitable choice for this application. It is worth noting that GT Models 4 and 5 would also be good candidates. These six Frame E class GTs can produce a maximum of 690 MW of power. An additional 60 MW can be generated by two BPSTs using HP to intermediate pressure (IP) letdown steam. A maximum of 750 MW can be generated, which is far above the required 450 MW power demand for normal operation.

Steam Demand

The high efficiency CC designs incorporate heat recovery steam generators (HRSGs) with either two or three pressure and reheat levels. However, in this case, only single-pressure HRSGs were selected to be coupled with the six GTs for steam production. Each HRSG produces approximately 300 tons per hour (tph) of HP steam at GT base load. Additionally, moderate supplemental firing can increase steam production and add system controllability. If there are minor fluctuations in RCT steam conditions, duct firing can rapidly be adjusted to match the demand.

However, the six GT/HRSG trains do not provide enough steam to meet all RCT demands. Four single-pressure conventional boilers were selected to augment steam production. Each of the four boilers is rated at approximately 300 tph of HP steam. The boilers were sized to match the steam output of a GT/HRSG train. When a GT/HRSG train is down because of a failure or a planned maintenance outage, a boiler can be ramped up to take its place. By producing HP steam at the same pressure and temperature, the HRSG and boilers could be fed into a single common header. HP steam is the primary supply stream to the refinery, but additional low pressure (LP) steam is also needed. To maximize use of the HP stream, HP steam is let down to an IP steam header through two BPSTs, as described above. HP steam is also used for other auxiliary power users (e.g., fan drivers, steam tracing). The steam is then discharged to an LP steam header that is shared with the refinery. See Figure 3–36 for a simplified CPP layout diagram. The use of steam in BPSTs and for other local balance of plant (BOP) customers is more efficient than using pressure relieving desuperheating stations (PRDSs) to let down the pressure.

Combining CC and boilers provides the client with the system flexibility necessary to further optimize CPP operation during all possible processing scenarios demanded by the refinery.

Reliability and Redundancy

Reliability is a refinery owner’s highest priority. If the CPP trips, the RCT that it supports shuts down. In this case, the RCT produces 1 million barrels of oil/day, which amounts to substantial financial losses for every day that the unit is not operating. To meet reliability requirements, it is recommended that the CPP be designed for normal operation and have two spares (N-2 concept). This N-2 concept allows for normal operation if two components generating steam or power are down for maintenance or fail simultaneously.

Under normal operating conditions, the power load is 450 MW. Four GTs operating at base load produce 460 MW, which is more than needed. Therefore, the other two GTs can be considered as the spares in the N-2 philosophy. One of the most critical system requirements is the capability to respond rapidly to changes in RCT electric load and steam demand. For this reason, all six GTs run at 60% part load instead of running four at base load and having two shut down. In this scenario, each GT can be quickly ramped up or down to meet the process controllability and responsiveness requirements. Similarly, during normal operation all six HRSGs operate at 90% load and all four boilers operate at 30% load.

Fuel System Design

The fuel system must be able to combust an assortment of liquid and gaseous fuels available in the refinery: natural gas (NG), diesel, distillate fuel oil (e.g., naphtha, light slurry oil, kerosene, etc.), heavy fuel oil, waste fuel oil (WFO) (a bottom distillation column fuel), and refinery fuel gas (RFG). Coal is not included due to economics and availability constraints. Designing the CPP to use fuel oil and RFG decreases operational costs. However, refinery production changes constantly and is not a reliable fuel source. For this reason, fuel supplied to the CPP is stored in large fuel tanks. Once enough fuel has accumulated, it is burned and the tanks are refilled. See Table 3–12 for a list of possible fuels and their selected CPP users.

TABLE 3–12

Possible CPP Fuels and Their Selected Users [3-7]

		GT		HRSG		Boiler
Fuel Source	Cost at LHV	Primary Source	Secondary Source	Primary Source	Secondary Source	Primary Source	Secondary Source
NG		X		X		X
RFG			X		X		X
Diesel			X		X
Distillate			X		X
WFO							X

The GT/HRSG trains are designed to fire a different secondary fuel than the boilers. If NG (primary fuel) is unavailable, the equipment switches to secondary fuels. This approach is tied to the N-2 redundancy concept and reliability design requirements.

Auxiliary Equipment Design Considerations

All auxiliary equipment such as fans, pumps, and deaerators is designed in accordance with the N-2 concept. The reliability requirements often drive the CPP components to be redundant (compared to traditional power plants) so that the CPP never experiences total failure. As a result, the cost to build a CPP could be considerably higher than that of a conventional power plant. The additional capital cost associated with the N-2 concept is justified when compared with the penalties related to a refinery shutdown. To minimize the price of the plant, experienced designers must use simulation tools to conduct detailed risk assessments for each component and its integration with other systems. For process optimization, the CPP is designed to use steam, which is an abundant and cost-effective alternative to electricity. Because of the N-2 requirement, a minimum of three pumps or fans is provided for every application. Whenever possible, at least one of these pumps or fans is built with a steam turbine (ST) driver instead of a motor driver. If, for example, there are five feedwater pumps with three normally in operation (N-2 philosophy), then three pumps should be designed with ST drivers and two with motor drivers. By using both streams of energy, the system is controllable, reliable, and does not fully depend on either steam or electricity.

Off-Design Case Operation

The CPP must be able to adapt to (and continuously operate at) 15 off-design cases. For the application defined in this section, the minimum power requirement is 300 MW (corresponding to 1500 tph of steam) and the maximum power requirement is 650 MW (corresponding to 3000 tph of steam).

Unique Control Systems

The CPP DCS must be linked to the refinery DCS. It is imperative that these two control systems be fully integrated and closely coordinated. Instrumentation redundancy is also important. For example, a high temperature element (TE)/temperature transmitter (TT) reading can trigger major CPP operation changes, which could disrupt refinery production. To avoid errors, two-out-of-three logic is used extensively to discriminate between real upsets and false signals.

Transient Behavior

The transient behavior of the entire system, including the steam host and the CPP, must be modeled in an early plant design stage.

Cogeneration Case

Cogeneration facilities pose significant up-front design challenges. The design must balance the requirements of two different customers with dissimilar sets of priorities—one entity demanding electricity and the other needing steam. For the steam host, steam supply reliability at specific flow, temperature, and pressure conditions is of paramount importance. Therefore, process steam requirements need to be identified early, not only for one condition, but for the entire allowable range of operation (nominal, maximum, and minimum). Since the steam production will affect the amount of available electrical power, it is also appropriate to define the number of short- and long-term steam demand changes.

To further complicate the matter, in many cases, the steam demand has more than one pressure level. In the design optimization process, all power and steam requirements must be superimposed to ensure that any predefined steam demand will be met at all operating conditions.

Supplementary Firing

Similar to industrial applications, a popular cogeneration feature is the use of supplementary firing (duct firing) within the HRSG. The reduction in electric power that occurs when process steam demand is increased can be easily overcome by duct firing in the HRSG to generate more steam. Hence, the plant can meet the increased steam demand without reducing the power output. The availability of an additional source of unconventional off-gas fuel (often used by chemical plants for duct firing) would be an ideal application.

Low-Pressure Turbine Sizing

The design team and the owner should size the ST and associated equipment based on the “zero export steam” case. An ST passing all the steam generated will have a larger LP section, larger electrical equipment (generator, transformer, etc.), and a higher electrical output. Economic and thermal performance considerations must be part of the decision-making process.

Reliability and Availability

Since the export steam in many cases is used as the heat source for a chemical or industrial process, its reliability is a primary consideration in equipment selection and plant design. This is a common requirement for all industrial applications. A steam outage could have a devastating effect on the host facility and cause heavy financial losses.

Plant Configuration

During transients, the host imposes other design constraints, which are dictated by the narrow allowable variability range for process steam flow, pressure, and temperature. These constraints and individual component reliability values define the plant configuration options. The first option comprises multiple identical trains (1 × 1 × 1) operating independently. The second option involves a single ST, with common steam headers fed from two or three HRSGs and their respective GTs (2 × 2 × 1 and 3 × 3 × 1).

Boiler feedwater purity and steam quality issues need to be carefully addressed throughout the range of planned operation.

Aluminum Smelter Case

Since aluminum smelting is energy intensive, most of the world's smelters are located in areas that have access to abundant power resources (hydro-electric, natural gas, coal, or nuclear). It takes 15 MWh of electric power to produce one ton of aluminum. Many locations are remote and the electricity is generated specifically for the aluminum plant by a CPP. A smelter comprises a large number of pots (steel containers with carbon lining). The product of the chemical reaction of the aluminum oxide under high temperature conditions is molten aluminum. Given that the smelting process is continuous, a smelter cannot be easily stopped and restarted. If production is interrupted by a power supply failure that lasts more than 4 hours, the metal in the pots solidifies, often requiring an expensive rebuilding process. From time to time, individual pot linings reach the end of their useful life, and the pots are taken out of service and relined. In order to avoid the grave consequences of pot solidification, redundant power must be considered.

Many of the design features for an oil refinery are also applicable to smelter applications (common steam header and supplementary firing [to compensate for power loss due to ambient conditions]) and have been addressed earlier in this section.

N-2 Criteria

Before selecting equipment from different suppliers, a thorough investigation is necessary to ensure that the special requirements of the process are met for power output, operational flexibility, reliability, and availability based on N-2 criteria, etc. The normal reliability of GTs for this application (including scheduled maintenance) is close to 96%.

The calculated reliability of multiple units indicates that a 4 × 50% configuration will yield a reliability of 0.99998%, whereas a 2 × 50% configuration will yield a reliability of only 0.97%. The high reliability does not come cheap. In order to justify backup power, many projects opt for an N-1 configuration during time periods when scheduled maintenance is not required. Given the importance of N-2 criteria, special consideration is given to selecting GT size and CC configuration. An example of the procedure is given in Figure 3–37. The Y axis represents the percentage of excess power above the target value for a given plant configuration. The target value is the minimum power requirement for the plant. The X axis represents different configurations. It can be seen that a configuration of two blocks of 2 × 1 (two GTs and one ST) plus two GTs in simple cycle will have a margin of 11.3% above minimum power in an N-2 operational scenario. The selection process must also be based on economic factors such as capital and operating and maintenance cost. While it is very difficult to generalize, the tendency is to use medium-size turbines for this type of application. In case of a trip, the loss of power is less than for a larger unit. It should be mentioned that in selecting the associated STs, the choice must account for the cycle pressures and locations of the steam extractions limited by the commercial availability of STs that can meet the specified conditions. Another decision is needed on whether to design the ST and associated steam cycle equipment for the case where no steam is required for the process.

Load Variations

Smelters present some unique load variation demands. For example, sudden changes occur due to anode effects on the pot line—gas bubbles emerge and disappear in the aluminum production process. The GT must follow with rapid changes of 10–20 MW while maintaining grid frequency stability. The selected equipment should be able to demonstrate ability to follow load accordingly. Original equipment manufacturers have incorporated special attributes such as variable inlet guide vanes (IGV) rapid adjustments, fuel system control, and other features to achieve the desired response time. The use of simple cycle GTs can provide rapid startup, load ramping, and unloading.

Equipment Selection Criteria

Early selection of major plant equipment is an important ingredient for a successful plant. The process must identify the owner’s objectives for plant output, heat rate, and reliability, availability, and emissions requirements. In addition to power output and heat rate, the major issue related to evaluating GT performance in captive applications is quantifying the GT exhaust flow and temperature as major contributors to steam production. All four parameters are heavily interdependent. For example, a GT that exceeds the guaranteed power output usually has better-than-expected component efficiency, particularly for the turbine section. As a result, the exhaust temperature is lower. A lower turbine exhaust temperature has a negative impact on HRSG steam production.

To properly assess these impacts, owners/operators are well advised to carefully evaluate the purchase or reservation agreement for the major equipment. While such evaluation is always important, it is crucial for projects involving special industrial applications. Direct experience with the equipment being considered can be brought to bear to ensure that it complies with the specific requirements of the project scope and that all interfaces are well defined. Other considerations include:

• Impact of GT performance offsets (between power output and exhaust energy) on HRSG and ST sizing

• Consistency in pollutant levels and units included in the plant permits and those guaranteed by GT suppliers. In developing CC projects for captive applications, an important aspect of equipment selection is the plant configuration. Usually, suppliers offer standardized CC plant design configurations:

• 1 × 1 (one GT, one HRSG, and one ST)

• 2 × 1 (two GTs, two HRSGs, and one ST)

• 3 × 1 (three GTs, three HRSGs, and one ST)

This approach allows the customer to choose the configuration that best meets its objectives. For multiple units or trains, a 1 × 1 configuration offers many advantages and may be more desirable in certain applications. Some of the advantages of a 1 × 1 configuration are:

• A phased construction allows greater flexibility for the future addition of units to respond to a potential plant expansion.

• Output can be more closely matched with load demand. A site with several units in a 1 × 1 layout and using supplemental duct firing can respond more effectively and economically to steam and power requirements.

• Plant redundancy (N-2 criteria) can be achieved because the units are redundant.

• Spare parts inventory can be optimized, since each component is identical for all trains.