Application of State-of-the-Art Supercritical Boiler Experience to U.S. Coals Corrosion Considerations Edward S. Sadlon ALSTOM abcd
Introduction Advanced rankine cycle pulverized coal-firing has returned to North America. A combination of operational cost, environmental and political drivers have led to a resurgence of increased steam pressure and temperature conditions in today s power plant applications. Supercritical pressure, i.e. >3205 psia cycles are at the forefront of this movement, but increased temperatures above the traditional 1000 F / 1000 F superheat/reheat conditions are being assigned to subcritical pressure (typically 2400-2500 psig at turbine inlet) drum-type boiler applications as an intermediate cycle advancement (see Figure 1). 2x 800 MW Supercritical PC Design Figure 1 640 MW Subcritical PC Design The responsibility of the boiler designer, for any cycle case, is to produce a reliable steam generation solution. As the design considerations for the boiler non-pressure part equipment are generally independent of the steam cycle, differentiating design criteria is limited to pressure parts including the start-up system and their attachments. Superheat, reheat and economizer surface location and arrangement for the respective cycle duty as well as element geometry and material selection must be evaluated for each cycle. For many international project situations, the above stated technology drivers, in combination with good quality (often imported), non-corrosive coal, result in a highly advanced cycle decision. In a number of these instances, supercritical pressure operation is a governmental mandate. Generally speaking, U.S. projects do not experience the same level of external scrutiny with regard to advancing plant efficiency. However, proposed environmental legislation, including that for CO 2 emissions, has resulted in a renewed focus on steam cycle advancement. While the cycle does not impact the traditional industry heat input emission rates, i.e. lb/10 6 Btu, it does impact the output emission rates, i.e. lb/kw-hr (see Figure 2). 1 abcd
Efficiency Impact on Steam Generator Emissions Plant Efficiency, %* Subcritical 34-37 Supercritical 37-41 Plant Efficiency, % 34% 37% 41% Fuel Consumption/CO 2 Emissions Base Base-8% Base-17% Emissions: Boiler Emissions Rate (10-4 lb/kwh) CO 3.4 3.12 2.82 NO x 6.8 6.25 5.64 SO x 82 75.4 68 Particulate 218 200 181 * HHV Figure 2 To make the correct cycle decision, all project criteria, especially the fuel(s) to be fired, must be assessed. More than any geographic area in the world, the United States experiences the greatest variability in grade and rank (see Figure 3), i.e. classification in its coal reserves. Each fuel brings its own set of boiler design issues. Figure 3 With respect to coal and coal ash makeup, alkali, alkaline-earth, sulfur and iron content have been identified as the most significant constituents impacting high temperature corrosion. If these constituents co-exist in a potentially corrosive combination, the solution may require circuitry redesign and/or use of high alloy clad materials. 2 abcd
Furnace Design Once the overall fuel, ash, air and energy input criteria are established, the physical dimensioning of the furnace, i.e. height, width, depth, nozzle spacing and coutant hopper arrangement is determined independent of water/steam parameters. However, the water/steam conditions do impact the furnace tube wall temperatures, such that ash/gas species interaction with the bounding metal surfaces can vary with cycle. Subcritical, drum-type designs with saturated fluid conditions in the evaporator circuits yield the highest furnace tube wall metal temperatures just above the firing zone. The exact value and location are a function of heat release rate, firing system stoichiometry, tube dimensions, etc., but in general, the average outside tube wall temperature for a 2400 psig cycle will be 800 to 850 F in this region. Carbon steel is typically sufficient as a pressure part material for subcritical (drum) furnace wall designs. Once-through supercritical designs yield a completely different metal temperature profile. Furnace metal temperatures are highest in the upper furnace regions even though the heat flux is reduced compared to the lower furnace. Low-alloy ferritic materials provide sufficient strength and oxidation resistance for all furnace wall sections. There are applications with advanced cycles where 1-1.25% Cr materials are used in the lower furnace and 2.25% Cr materials in the upper furnace (see Figure 4). 1 1/4 in. on 1 5/8 in. centers (FRONT & SIDE WALLS) SCREEN TUBES SMOOTH TUBING HANGER TUBES SMOOTH TUBING 1-1/4 O.D. Rifled Tubing 8.0 ft. SA213 T23 1 1/8 in. on 1 5/8 in. centers (FRONT, REAR & SIDE WALLS) ARCH RIFLED TUBING SA213 T12 SIDE WALL RIFLED TUBING 1-1/8 O.D. Rifled Tubing FRONT WALL RIFLED TUBING REAR WALL RIFLED TUBING. 3.0 ft. max. SMOOTH TUBING FROM THIS ELEVATION ALL WALLS Figure 4 In general, field experience with operating supercritical units have not shown any higher slagging or corrosive tendencies in the furnace versus subcritical unit designs. 3 abcd
Waterwall Boundary Conditions Physical and chemical conditions at the furnace side of the tube waterwall, particularly with respect to corrosion potential, are impacted by many factors including: 1. Quantity and chemical form of potential corrosive agents, e.g. sulfur. 2. Constituents of ash deposition. 3. Furnace aerodynamics. 4. Combustion air management. 5. Temperature at the boundary surface. For certain coals, coal cleaning techniques have been demonstrated to remove significant fractions of mineral matter and sulfur from the raw feed stock leaving an improved product for suspension firing. While these methods benefit a number of equipment systems in a coal-fired power station, they cannot appreciably alter the boiler designer s approach to furnace selection. Despite the recent gains in understanding of fireside corrosion mechanisms by Kung (1) and others, there still is not a complete and thorough understanding such that waterwall corrosion potential is consistently predictable. What has been established is the linkage between corrosion and the presence of sodium-potassium-iron trisulfates, especially in a molten state. However, as many demonstrated in the 60 s and 70 s and later summarized by Ohtomo et al (2), waterwall corrosion is infrequent because the trisulfate compounds exist in a solid state at the wall boundary (see Figure 5). Effect of steam temperature on deposit structure Figure 5 Both subcritical and supercritical waterwall temperatures are below the threshold of accelerated corrosion rates from molten salt attack. Gas mixture constituency (namely H 2 S and CO) and deposits containing FeS in variable oxidizing reducing environments are shown to have an impact, but cannot solely explain the propensity towards waterwall corrosion. Stress corrosion (circumferential) cracking in furnace waterwalls is a phenomenon that is due to two inter-related effects. A local reducing environment at the furnace wall promotes accelerated wastage of tube metal by an oxidation-sulfation reaction. Compounding this are thermal stresses 4 abcd
generated by the rapid change in metal surface temperature which causes circumferential cracking in the protective oxide layer on the metal surface. Both of these effects are evident in subcritical and supercritical pressure boilers. Because the occurrence of the circumferential cracking is dominated by the corrosion reaction, the principal factors that will influence the rate of attack include the relative amount of oxygen and sulfur (especially pyritic sulfur) present in the environment at the tube wall surface and the mean tube metal temperature. In addition, thermal stresses at the tube surface develop due to the periodic shedding of the deposit layer, either naturally, due to accumulated weight of the layer, or artificially, due to the action of wall blowers or unit load reduction. When the layer of deposit is removed, the temperature at the newly exposed surface of the tube rises sharply, in some cases by as much as 200 F. The stresses generated by this temperature spike cause the protective oxide layer on the surface of the tubing to crack, which then permits a cycle of accelerated corrosion to occur where the bare tube metal is exposed. Over the course of a number of such cycles, cracks with the characteristic carrot shape form at the surface of the tube and begin to propagate through the wall. Regardless of fuel and/or cycle, emission requirements, including NOx, will continue to be mandated at very low levels. Thus, to combat the compromised performance and, in some cases, increased fireside corrosion potential due to the attendant substoichiometric gas environment, the following should be incorporated, independent of steam cycle: Means to insure complete combustion of the fuel, including minimizing of carbon content in wall deposits. This often translates to high pulverized coal fineness, optimized fuel jet momentum and orientation and considerations for maintaining proper oxygen environment at the furnace wall boundary (see Figure 6). The Concentric Firing System (CFS ) is an ALSTOM patented horizontal staging technique that reduces local firing stoichiometry during the initial combustion stages, while providing an oxidizing boundary layer for decreased lower furnace waterwall slagging and corrosion. Air management design that allows for 3-dimensional stoichiometric variability. For high potential corrosive situations this includes designing for increased SCR capability to allow for less aggressive NOx conditions in the furnace. Optional Where experience or technology capability does not allow for the above, incorporation of a protective material, usually in the form of a cladding or weld overlay and usually of high chromium nickel content as a means of corrosion resistance. 5 abcd
Oxygen Distribution Oxygen Distribution Without Concentric Firing System (CFS TM ) With Concentric Firing System (CFS TM ) Superheater / Reheater Design Considerations Figure 6 Gas conditions entering the superheater/reheater region of the steam generator are considerably different from those in the furnace. Coal combustion is essentially complete, stoichiometric conditions have been restored and ash particles are drier in the lower temperature environment. Conversely, many of the pressure part areas carry higher metal temperatures promoting an increase in corrosion potential. While all coals do not yield corrosive ash, those that do see a significant wastage rate impact on traditional ferritic and austenitic boiler materials when rising through the 1000-1300 F range. The impact of complex sulfate molten ash on austenitic materials is demonstrated in Figure 7 (3). Figure 7 Figure 7 Figure 7 6 abcd
With fluid-outside metal temperature rise commonly ranging from 50 F to 150 F in superheat/reheat finishing sections, advancing the steam cycle to higher temperatures can push the corresponding metal temperatures into the range of maximum wastage potential. The boiler designer does have a number of temperature limiting techniques he can employ, including: location, arrangement and duty of high temperature section, imbalance minimization, tube diameter selection, tube mass flow, etc. However, the steam temperature is still the predominant influence on superheat/reheat metal temperature. In addition to employing the above design/arrangement techniques, tube material selection and the shielding thereof are additional measures of corrosion inhibition to be considered. In general terms, superheat/reheat material selection with regard to high temperature corrosion resistance is predicated on high chrome/nickel content. Experience has shown that the actual content is best assigned per the degree of ash deposit corrosivity. Viswanathan and Bakker (4) have concluded that increasing the Cr content of the alloy from 18-20% to 23-25% will have a major impact on corrosion resistance when the corrosivity of the deposits is moderate, i.e. < 20 mils/year for 18%-8% stainless steels. Beyond this rate, they advocate the utilization of > 40% Cr material in the form of co-extruded tubes or weld overlay claddings. Tube shielding is a sacrificial mechanical approach that protects the mother tube by limiting its metal temperature and exposure to gas/ash deposits (see Figure 8). It can also elevate the outer tube shield metal temperature in certain applications beyond the high-end corrosion threshold in the case of austenitic materials. Figure 8: Typical Arrangement of Tube Protection Shields Field / Shop Application 7 abcd
Advanced Cycle Boiler Design for U.S. Coals Accounting for the above corrosive mechanisms, material resistance, and operational experience, ALSTOM categorizes U.S. coal application to advanced cycle designs in a geographically regional manner. The majority of western U.S. coals, ranging from high-volatile bituminous to sub-bituminous C (PRB coals) are treated as benign such that no special design considerations are normally undertaken when advancing the cycle. All of these fuels have low to very low sulfur content and have lignitic-type ash, i.e., the CaO and MgO content is > Fe 2 O 3 content (sometimes much higher). One known exception to this generalization are Texas lignites which have been attached to some low to moderate levels of stress corrosion cracking. Certain Texas lignites have demonstrated alkali in ash content that is equally distributed between sodium and potassium which likley contributes to these occurrences. Eastern coals are primarily bituminous in classification and generally exhibit higher iron and sulfur content and lower alkaline-earth content than western coals. There are many examples of eastern bituminous coals that have very low corrosive potential and thus no special design actions are required. Conversely, there are other eastern bituminous as well as most mid-western bituminous coals where the generated corrosive agents mandate modifications to the standard design. Typical of these fuels include western Kentucky and southern Illinois coals, having high sulfur, high iron and moderate alkali /alkaline-earth ash constituents. Alternate Technology In its different forms, PC suspension firing generates combustion by-products, i.e. gas and ash that, in some instances, can lead to accelerated corrosion wastage. The emerging technology of Advanced Cycle CFB (Circulating Fluidized Bed) Combustion (including supercritical pressure) may lend itself to mitigating this corrosion potential (see Figure 9). The CFB process is characterized by simultaneously combusting the fuel at relatively low temperatures and capturing any released sulfur compounds via sorbent introduction. The effectiveness of these co-processes is made possible by a mass of solid material circulating through the primary loop (furnace and cyclone) which provides the necessary ignition energy for stable combustion. The early capture of sulfur in the process limits the opportunity for corrosive agents to form. Secondly, the low combustion temperature allows for the retention of the mineral matter content in its stable form such that ash deposits remain dry and alkali release (vaporization) is minimized. Comparing a CFB application with a PC unit, the corrosion potential of the air and gas species interfacing with high temperature pressure parts is minimized. As we continue to advance CFB steam cycles, experience will tell us the extent of this corrosionfavorable process. 8 abcd
Cyclone overflow duct Cyclones Backpass Furnace Coal Silos FBHEs Elevator / Staircase Figure 9: Supercritical Circulating Fluidized Bed Summary Market interest in advanced cycles has returned to the U.S. for a number of reasons. Combined with ever-more aggressive emission requirements and variety of coals to be dealt with, today s steam generator design takes on added complexity. The added considerations reside in the pressure part area, as the non-pressure part areas are independent of cycle from a design philosophy standpoint. The predominant issue is the increased corrosion potential attributed to metal temperatures with cycle advancement, primarily with respect to superheat/reheat outlet temperature increase. With fuels categorized as noncorrosive (of which there are many in the U.S.) no special design considerations need to be entertained. For those fuels labeled corrosive (smaller, but significant portion of U.S. coals), steam generator design modifications may be required. As a boiler designer, ALSTOM cannot conclude the appropriate cycle selection for a given project. However, we can contribute an awareness of the consequences of advancing a cycle which should be included in the cycle decision process. And, regardless of the final decision, ALSTOM s technical knowledge and experience with high temperature corrosion phenomena enable us to provide an optimum boiler design for the project conditions at hand. 9 abcd
References 1. S. K. Kung, Prediction of Corrosion Rate for Alloys Exposed to Reducing/Sulfidizing Combustion Gases, Corrosion 97, NACE 1997, 97-136. 2. Ohtomo et al, High Temperature Corrosion Characteristics of Superheater Tubes, Engg. Rev., Vol. 16 (No. 4), Oct 1983. 3. A.L. Plumley, Predicting and Assessing Tube Metal Wastage in Boilers Fired with Low- Rank Coal, C-E Power Systems TIS 6948, p. 2. 4. R. Viswanathan and W. T. Bakker, Materials for Boilers in Ultra Supercritical Power Plants, in Proceedings of 2000 International Joint Power Generation Conference, p.7., 2000. 10 abcd