565521

Investigation of Recovery Boiler Superheater Design and Performance Part 1

John L. Clement Thomas M. Grace Clement Consulting Inc. T.M. Grace Company, Inc. ABSTRACT

The paper is one of two that summarizes the results of a study of recovery boiler superheater experience, performance and problems in North America that was carried out for the AF&PA Recovery Boiler Committee.[1] This first paper focuses on the history of superheater development, design issues and the role of metallurgy. The history of superheater development over 50 years and events and conditions leading to poor performance are described. Important considerations are highlighted and issues identified to apply the experience for the design of a superheater to successfully operate at high temperature, including the corrosion resistant materials available. The second paper focuses on operational aspects.

INTRODUCTION

The value of the recovered energy is the main driver for a worldwide trend to high temperature and pressure recovery boilers. The USA industry was the early leader in the development of recovery boilers to operate at high steam temperature. Because of the age of the recovery boiler population in North America, the majority of boilers (and superheaters) are not designed for high steam temperature. However, most newer boilers are designed to operate at high temperature and pressure. The greatest experience with high temperature and pressure recovery boilers is in Finland and Japan, who have done the most to advance the trend to higher steam temperatures.

This investigation of recovery boiler superheaters was designed to review the experience, understand the causes or conditions that can result in failure of a superheater tube or attachments, or result in operation that affects the boiler availability and maintainability. A primary objective was to identify methods and practices in design, operation and maintenance to permit extending the final superheated steam temperature to higher values. Another focus was to provide guidance in how to operate the boiler in ways that would minimize the development of problems in the superheater that would affect performance and reliability. The overall historical considerations for superheater design methods and practices are discussed. The mechanical design issues and operational aspects are subjects of the second paper.[2]

This superheater study is the fourth in a series of studies reported to the industry at Tappi conferences with the objective of improving recovery boiler design, safety, operation and maintenance.[3,4,5] HISTORY OF SUPERHEATERS ON RECOVERY BOILERS There was a marked interest on the part of engineers in superheated steam and its use after 1850 and continuing for about twenty years. Boilers to which superheaters were attached were all operating at pressures less than 50 psig. A very large portion of these were installed on marine boilers. Development in the 19th century was retarded by the strong stand of the British Board of Trade on the grounds that there was a danger of superheated steam breaking into its constituent elements and becoming dangerous.[6] There was economic competition from triple expansion engines using increased pressure and where the gains in superheat were not beneficial. In 1883, a marine engineering manual is quoted as saying the use of superheated steam has been discontinued since the pressure has gone beyond 60 pounds per square inch, partly in consequence of the increase in steam temperature beyond that due to .

Interest in superheated steam revived when positive test results were reported in Europe for a boiler and engine especially designed and built for use with superheated steam. The first commercially marketed superheater in the USA began with The Babcock & Wilcox Company in 1898. These were essentially of tubular type located within the boiler setting with gas passing over the outside of the tubes to heat the steam inside. It was soon apparent that a 40 year old assumption, that the specific heat (Cp) of superheated steam was a constant, was invalid. Cp was

TAPPI Engineering, Pulping & Environmental Conference, October 11-14, 2009, Memphis, Tennessee 1 of 27

determined to vary with both pressure and temperature. A table of Properties of Superheated Steam was published in 1909, removing another obstacle.[6]

In the first decade of the 20th Century, the U-shaped tube was adopted for the superheater as the best shape for expansion. Tube banks were being placed with tubes in the direct path of gases to heat the steam inside the tubes. In the 1920s, the superheater temperature was limited by the materials available and the allowable tube metal temperatures for these materials.[7] The generally accepted steam temperature was 343C (650F); developments in materials moved this up to 385-400C (725750F) in the 1930s. Many of the fossil fuel fired boilers built during this period incorporated both a superheater and reheat-superheater to improve station economy at the temperatures restricted by metallurgy. Development of alloys that could be used in the manufacturing of tubing resulted in fossil fuel fired boilers about 1937 being placed in operation at 482C (900F).. The availability of these alloy tubes advanced the consideration of operating recovery boilers at the higher temperature for power generation.

Recovery Boiler Application High Temperature Superheater

The history of superheater development and application on a recovery boiler has been one of overcoming obstacles to design and increasing the steam temperature. The availability of corrosion resistant tube material has always been an obstacle. Several conditions are believed to have come together by the middle of the 1950s to result in recovery boilers in the USA being installed to operate at 482C (900F).

1. The recovery boiler capacity of 454 t/d (1.0 million lb/d) of black liquor solids provided a boiler geometry into which there was sufficient volume to install the superheater surface required. That is, the boiler got large enough that a 482C superheater would fit inside.

2. Kilowatt generation in excess of mill requirements could be sold to the utility at an attractive price. The Babcock & Wilcox and Combustion Engineering recovery boilers supplied in North America to operate at 482C (900 F) and at 496C (925F), and being operated currently, are listed in Table I. Boilers no longer in operation, and boilers designed for future conversion to high steam temperature are not included. The year is the year the boiler was placed in service. Names of operating companies reflect current ownership.[8] The reader should take note that values in SI units are metric for mass flow and pressure is absolute unless noted otherwise.

The first recovery boiler to operate at 482C (900 F) in the USA was contracted in 1955 by Babcock & Wilcox with Continental Can Co. at Hodge, LA. The original rating was 408 t/d (900,000 lb/d) solids burned to generate steam at 8.7.MPa (1250 psig} and 482C (900 F). In the same year, the West Virginia Pulp & Paper Co. in Charleston, SC, contracted for a boiler to operate at 105 MPa (1525 psig) and 471C (880 F). One year later, a second, larger boiler for the mill at Luke, MD, was selected to operate at the same pressure and temperature-capacity 680 t/h (1.5 million lb/h) solids. These two pioneer boilers were the highest pressure recovery boilers in the USA for 20 years, and not exceeded for 35 years. The boiler at Luke continues to this day to be operated one week per year.

The recovery boilers at the mill in Pine Bluff, AR, were installed 50 years ago by International Paper to operate at 480C (900F). Three (3) Babcock & Wilcox recovery boilers equipped with continuous, horizontal tube economizers were designed to each process 531 t/d (1.17 million lb/d) of black liquor solids and produce 95 t/h (209,800 lb/h) of steam at 88.9 MPa (1275 psig) and 482C (900F). The first two boilers were contracted in 1956 and the third in 1959. The No. 1 boiler was converted to a power boiler about 1966 when a fourth recovery boiler rated at 1497 t/d (3.3 million t/d) solids was placed in operation. The No. 2 boiler went into operation in 1958; the No. 3 in 1960. The mill currently rates the two older boilers at 680 t/d (1.5 million lb/h) solids. The fourth boiler was designed to operate at a higher temperature of 496C (925F). The three boilers burning black liquor are currently operated by Evergreen Packaging.


TableIRecoveryBoilersinNorthAmericaOperatingin2008thatwereRatedatSteamTemperaturesof482C(900F)andAbove

Babcock & Wilcox Alstom Power (CE and ABB)

1958 Evergreen Packaging Pine Bluff, AR 1960 Evergreen Packaging Pine Bluff, AR 1966 International Paper Augusta, GA 1966 International Paper Bastrop, LA 1967 NewPage Wisconsin Rapids, WI 1967 Evergreen Packaging Pine Bluff, AR 1967 International Paper Vicksburg, MS 1972 NewPage Escanaba, MI 1973 Smurfit-Stone Hodge, LA 1974 Georgia-Pacific Cedar Springs, GA 1976 NewPage Wisconsin Rapids, WI 1976 Georgia-Pacific Palatka, GA 1977 Smurfit-Stone West Point, VA 1978 Alabama River Pulp Perdue Hill, AL 1980 Smurfit-Stone Hopewell, VA 1980 International Paper Prattville, AL 1981 International Paper Riverdale, AL 1981 Rayonier Jesup, GA 1981 International Paper Mansfield, LA 1981 International Paper Mansfield, LA 1982 International Paper Pine Hill, AL 1983 Abitibi-Bowater Catawba, SC 1984 International Paper Eastover, SC 1989 NewPage Wisconsin Rapids, WI 1990 Weyerhaeuser Columbus, MS 1991 Domtar Nekoosa, WI 1991 Georgia-Pacific

(Rebuild 1963 Boiler) Cedar Springs, GA

1991 Georgia-Pacific (Rebuild 1966 Boiler)

Cedar Springs, GA

1991 International Paper Courtland, AL 1992 Alabama Pine Pulp Perdue Hill, AL 1993 Georgia-Pacific Naheola, AL

Obstacle to Progress Superheaters Deficient in Design Steam Temperature

A large number of the boilers in Table I, as well as some that have been retired, did not have sufficient superheater surface installed to achieve the design steam temperature. Many recovery boilers were sized using a standard elemental analysis and heating value of the solids that served the buyer focus on installing a conservative furnace and insufficient superheater surface. An example the affect of this is determined using the liquor analyses in Table II.


TableIIComparisonofLiquorAnalysisUsedinExampleofDesignImpact

Elemental Analysis Standard Liquor % Dry Solids

Unless Otherwise Noted

Performance Liquor % Dry Solids

Unless Otherwise Noted Carbon 42.6 35.54 Hydrogen 3.6 3.85 Sodium 18.4 20.16 Sulfur 3.6 4.15 Potassium -- 1.38 Chloride -- 0.77 Inert 0.2 0.77 Oxygen (by difference) 31.6 33.38 Total 100.0 100.00 High Heating Value, Btu/lb solids 6600 6100 kcal/kg 3667 3389 Dry Flue Gas, lb/lb solids 5.96 5.03 Air, lb/lb solids 5.67 4.84

The standard analysis is compared to an analysis more representative of a kraft pulping operation. The standard analysis was widely used for sizing the furnace and convection surfaces. When applied, a second analysis, similar to that above, would generally be referenced as the performance analysis. With surfaces fixed by the standard analysis, a set of performance numbers would be determined for the performance analysis. Boiler operation with the performance liquor would result in:

1. Operating with a dry gas weight at 84% of the design value. 2. Operating with a dry air weight of 85% of the design value. 3. Operating at 92% of the design heat input in solids. 4. A steam flow rate about proportional to the decrease in input.

The effect was to

1. operate with a lower average furnace exit gas temperature (FEGT) because of the lower input - about 22 to 28 C (40 to 50 F).

2. decrease in the radiation heat flow because of the lower gas temperature; a decrease in gas temperature of 28 C (50 F) will reduce the heat flow 10%.

3. decrease convection heat flow because gas flow is reduced to 84% of full load. 4. increased steam film resistance because of lower velocity in the tube. 5. and the net effect is that the heat transfer coefficient decreases at a more rapid rate than the steam flow

causing the temperature to be less than desired (surface is insufficient). Other factors could also affect the design. One industry buyer could be expected to insist the furnace height be increased by 10 feet, regardless of the proposed initial height. Through all this, the superheater surface and attemperator spray system were not adjusted upward to the conditions at which the boiler would actually operate.

The result of installing boilers with insufficient superheater surface has been an industry perception that recovery boiler designers were deficient in the ability to install a superheater with adequate surface to achieve the desired steam temperature. During this superheater study, the investigators determined there are recovery boilers that do operate at their design steam temperature. These are reviewed in Part 2.[2] There is a larger number that are deficient..


Furnace Screen

The furnace screen became suspect and fell into disfavor during the 1980s because of concern about potential recovery boiler explosions from furnace screen tube failures. Recovery boilers without furnace screens subsequently became prevalent in the USA. The exceptions were smaller boilers and boilers producing steam at the lower temperatures where a screen was required to reduce the gas temperature entering the superheater, and then, the generating bank. No subsequent explosions have been attributed to a screen failure, mostly because of widespread acceptance of low drum level trips.

The hazards of a screen in a recovery boiler include the potentially severe damage caused to a furnace screen when a large buildup of ash and slag breaks loose in the upper furnace and falls on the screen. Screen platens that bridge the furnace from the front wall across to the nose are most vulnerable. An investigation to examine the cause of severe screen tube damage in a CBC-Mitsubishi recovery boiler in Brazil was reported at the 2004 International Chemical Recovery Conference.[9]. The damage was caused by large pieces of ash deposits falling from the furnace roof.

A recent example of this hazard occurred in 2008; the incident was reported at the Spring 2009 BLRBAC meeting.[10] The CE boiler was designed with a row of screen platens at the superheater flue gas inlet, with the vertical section of the platen located at one-half of the furnace depth. Every other platen was routed from the center to the front furnace wall and the other half to the rear wall. Salt cake ash accumulated at the junction of roof and front wall until the buildup mass fell about 40 feet onto the target screen platen, resulting in a crack in one of the tubes releasing water into the furnace. An Emergency Shutdown Procedure (ESP) was initiated.. The top three tubes of the platen were flattened and three more bent in a platen that was deflected by 8-12 inches Two adjacent platens were damaged as well.

Introduction of Technology from Finland and Sweden The first recovery boiler in the USA delivered by a Nordic supplier was a Gtaverken boiler placed in operation in 1984 at the Leaf River mill in New Augusta, MS.[11] Since then, a number of units have been delivered for operation at high temperature. The company names reflect current ownership. The temperatures in Tables III and Table IV are design values and may not be representative of the actual operating temperature.

TableIVMetsoPower(formerlyKvaerner,TampellaandGotaverken)RecoveryBoilersinNorthAmerica

Company Location By * Start-up Year

Steam Pressure

psig

Steam Temperature F

Georgia-Pacific Corp. New Augusta, MS GV 1984 1225 900 Potlatch Corp. Lewiston, ID GV 1987 1250 900 International Paper Co. Augusta, GA GV 1988 900 900 Smurfit-Stone Corp. Hodge, LA GV 1991 1275 900 MeadWestvaco Covington, VA GV 1991 1580 925 International Paper Co. Eastover, SC TP 1991 1500 900 International Paper Co. Bastrop, LA TP 1993 1275 900 Domtar Corp. Johnsonburg, PA TP 1993 1275 900 International Paper Co. Savannah, GA TP 1994 1400 910 Domtar Corp Dryden, Ontario KV 2003 1262 900 Weyerhaeuser Co. Grande Prairie, Alberta MP 2007 1514 950

* GV Gtaverken KV Kvaerner TP - Tampella MP Metso Power


TableIIIAndritz(formerlyAhlstrom)RecoveryBoilersinNorthAmerica

Company Location Start-up

Year Steam

Pressure, psig Steam

Temperature, F Domtar Corp. Hawesville, KY 1986 1262 896 Domtar Corp. Bennettsville, SC 1989 1247 900 International Paper Co. Albany, OR 1999 1247 900 Bowater Pulp & Paper Canada Thunder Bay, Ontario 2001 899 900 Bowater Pulp & Paper Canada Thunder Bay, Ontario 2001 899 896 International Paper Co. Valiant, OK 2006 1494 925 International Paper Co. Campti, LA 2008 1494 950

An Invitation to Corrosion - One More Obstacle to Progress

In 1987 an incident occurred that may have negatively influenced the desire for high steam temperatures in the USA. In retrospect, the superheater was designed with an arrangement that was in fact an invitation to corrosion. Although there was experience with high temperature superheaters at that time, (there were at least six boilers in Finland that had been commissioned for the same operating pressure and temperature of 480C (896F) and 8.7 MPa (1250 psig), the design did not properly take into account the experience nor the high levels of potassium in the black liquor at that mill.

This No. 3 recovery boiler in Hawesville, KY, shown in Figure 1, started up in 1986 [12] The superheater was arranged in three banks in the direction of gas flow, a parallel flow secondary bank (III), a countercurrent primary-2 bank (II), followed by a countercurrent primary-1 bank (I). The attemperator was located between the second bank and the third bank. The third bank platens were located forward of the nose arch as was also the front loops of the second bank, that is, the primary superheater outlet upstream of the attemperator. These loops in front of the nose were not shielded from direct radiation from the furnace; a furnace screen of a few tubes afforded minimal shielding. There was severe corrosion attack of the second and third loops of bank III and the outlet loops of bank II. Materials installed were the best available at that time two score years ago.

An extensive corrosion investigation and measurement of tube temperatures culminated with total superheater replacement and a new 50 % nose arch. Potassium was found to be higher than 7 mole % (K/K+Na) in the deposit contributing to a first melting temperature (FMT) of 520C (970F). Thermocouple measurements of the surface temperature of the third loops of bank III operating at a final steam temperature of 440 C (825 F)

were very high values. Tube temperatures at the lower bend averaged 590C (1100F) and maximum 650C (1200F). These temperatures reflect starting up with a clean superheater and receiving direct radiation from the furnace.

Many of the conclusions and the final surface arrangement support the recommendations of the investigators in this superheater study. About 30% of the surface was removed and the final superheat temperature was degraded to

Primary Outlet Secondary

Figure1No.3RecoveryBoiler


465C (870 F) instead of 480 C. Nevertheless, the investigators claim The rebuild was a success and the boiler has since performed as predicted.

The experience appears to have affected two other projects for which the owner had purchased recovery boilers. The boilers had superheaters designed for 482C (900 F) and were operated at 454C (850 F).

Superheater Material

The earliest known testing of materials for a recovery boiler superheater was conducted at the International Paper mill in Natchez, MS, during 1953-54. Three single tube elements were fabricated from short sections of inch OD (outside diameter) tube representing tube materials available. The test probes were designed, using functional heat transfer methods, to place all the materials to be tested in three gas temperature zones to function at the desired metal temperatures. Steam supply was from the boiler steam drum. Timed visits were made to the mill by research engineers to measure OD metal loss using micrometers.

The program came to an untimely end when the three sections were destroyed. The operators had closed the valve at the inlet of each of the sections in order to conduct a hydrostatic test of the boiler at the end of an outage. The valves were not opened when the boiler started up, resulting in destruction of the elements. The couple of sets of valid measurements that had been obtained were of little value.

Figure 2 shows one of the test elements from a second test site at Continental Cans Hodge mill that went into operation in 1957 with four of the secondary superheater elements (or platens) designated as test elements. [13] The objective was to determine new oxidation limits for materials in a high temperature recovery boiler superheater. Increased metal temperatures were achieved by orifices at the outlet of each test element to reduce steam flow. Two of the elements were subsequently selected for metallurgical analysis.

First in 1962 which led to increasing metal temperature limits.

Second in 1973 that operated until 1969 (12 years) at 593-607C (1100-1125F). All orifices were removed in 1969. This element is shown at a research center in the photograph (Figure 2).

Each element had tubes of the following three materials. After each was metallurgically analyzed, results were used to adjust the limits for spot metal temperatures used in design Carbon steel SA 178 Grade A 2 Cr Mo SA 213 Grade T14 Stainless steel SA 213 Type 321H The status of materials for superheater design in 1985 is reported in the results of a survey of over 100 recovery boilers in North America.[14] The materials reported to be available for superheater tubes were SA209 T1, and SA 213 T11 and T22. The summary goes on to say Among the current problems of major consequence in recovery boiler corrosion, the limitations of superheater tube material were frequently mentioned in the visitation program. Steam superheat is limited to 480C (896F) for conventional low alloy steels, but even then severe wastage occurs

Figure2ElementRemovedin1973TheUltimateCorrosionProbe


in some units, especially those exposed to high SO2 gases, chloride/potassium laden dusts, and/or liquor carry over conditions. Some of these problems may be due to exceeding the 480C temperature, but even the stainless steels, such as, TP 304, TP 347 superheater bends, which should withstand these temperature upsets, corrode at a high rate (5-year replacements).

A Department of Energy funded project Materials for Industrial Heat Recovery Systems that was completed in 2006 addressed superheater tube corrosion and cracking. An interim report was presented at the 7th International Colloquium on Black Liquor Combustion and Gasification in Finland.[15] The ongoing work included laboratory corrosion studies and corrosion probes to be inserted in a recovery boiler testing alternative tube materials. A final report of the studies of superheater materials for high temperature was presented at the 2007 International Chemical Recovery Conference in Quebec City.[16] The study evaluated and ranked the behavior of six alternative alloys T91 alloy steel, stainless steel grades 310H and 347H, Alloy 28 and Alloy 33, and aluminum containing Alloy 693. The selection of a material for the superheater tubes is suggested to depend on whether a superheater will be at metal temperatures above or below the FMT. The study results rank Alloy 28 as most suitable of the materials tested to provide corrosion resistance above and below FMT of the ash deposit. The report stresses the importance of removing chlorine and potassium from the process to assure the tube temperature is below the ash FMT and that the addition of sulfur and oxygen with the chlorine is very detrimental.

A second paper at the conference in Quebec City reported a laboratory investigation in Finland exposing samples of six different steel materials to alkali salt mixtures above and below the melting temperature.[17] Three of the materials were also tested using air-cooled probes in two recovery boilers. There was corrosion of all six materials. Corrosion is reported to have occurred at temperatures where there was no melt in the ash and increased with the amount of melt. The report strongly supports the importance of chlorine and potassium removal from the mill cycle to avoid corrosion with the higher steam temperatures.

There have been no reports from Finland or North America of testing a material reported to be used successfully in Japan for superheater tubes in recovery boilers operating at high temperature. A Japanese report at the 1998 International Chemical Recovery Conference claimed a 25Cr-14Ni material in operation over 10 years.[18]

Japans Experience with High Temperature Superheat The Mitsubishi Heavy Industries (MHI) contract list and a series of technical papers from 1986 through 2007 describe a history of development of recovery boiler technology to support operation at high pressure and high temperature. A significant number of their contracts operate at 9.9 to 10.9 MPa (1420 to 1565 psig) and temperatures up to 515C (959F). The experience in Japan is reviewed extensively in this report. MHI has not been contacted.

The recovery boilers operating in Japan place MHI in the position of being the leader in high temperature superheater design and operation. A list of high pressure and high temperature recovery boilers in Japan shows 17 MHI boilers delivered from 1983 to1998. Kawasaki Heavy Industries (KWI) boilers add 5 more to the total. The combined list is included as Table V.


TableVListofHighPressureandTemperatureRecoveryboilersinJapan

Year of Delivery

Customer Mill Dry Solids

Capacity, t/d

Steam Capacity

t/h

Steam Pressure

MPa

Steam Temp.

C

Supplier (*)

1983 Oji Paper Co.,Ltd. Yonago 525 90 9.9 500 MHI

1984 Nippon Paper Ind. Co. Ltd. Yatsushiro 770 120 10.3 500 KHI

1985 Daio Paper Corp Mishima 1750 258 9.9 500 MHI

1985 Oji Paper Co. Ltd. Nichinan 960 175 11.3 505 MHI

1986 Oji Paper Co. Ltd. Tomakomai 960 175 10.9 500 MHI

1986 Taiko Paper Mfg. Co. Ltd. Fuji 630 96.3 9.8 500 MHI

1986 Nippon Paper Ind. Co. Ltd. Asahikawa 900 170 10.2 510 KHI

1987 Tokai Pulp Co. Ltd. Shimada 1115 170 10.0 500 MHI

1987 Mitsubishi Paper Mills Lrd.. Hachinohe 1635 253 10.3 515 MHI

1987 Hokuetsu Paper Mills Ltd. Niigata 1000 162 10.9 505 MHI

1990 Oji Paper Co. Ltd. Tomioka 1775 270 10.3 515 MHI

1990 Nagoya Pulp Co. Ltd. Honsha 900 150 10.3 503 MHI

1990 Chuetsu Pulp & Paper Co. Ltd. Noumachi 1530 260 10.4 505 KHI

1990 Oji Paper Co. Ltd. Kasugai 2400 410 10.9 515 MHI

1990 Hyogo Pulp Industries Co. Ltd. Tanigawa 1000 155 10.4 505 MHI

1993 Daio Paper Corp. Mishima 1750 260 13.3 515 MHI

1996 Oji Paper Co. Ltd. Kure 1900 330 10.9 515 MHI

1996 Hokuetsu Paper Mills Ltd. Niigata 1900 310 10.9 515 MHI

1997 Chuetsu Pulp & Paper Co. Ltd. Sendai 1530 260 10.9 515 MHI

1997 Nippon Paper Ind. Co. Ltd. l Iwakuni 2700 425 10.4 505 KHI

1998 Oji Paper Co. Ltd. Yonago 2400 410 10.9 515 MHI

2005 Hokuetsu Paper Mills Ltd. Niigata 2700 475 10.3 505 KHI

* MHI: Mitsubishi Heavy Industries KHI Kawasaki Heavy Industries

Mitsubishi Heavy Industries, Ltd. Experience


The contract list for sodium base recovery boilers published by Mitsubishi Heavy Industries, Ltd. (MHI) tells the story of the evolution in Japan of superheaters installed for producing steam at ever increasing temperatures. MHI delivered their first recovery boiler in 1951. MHI had an arrangement with Jonkopings Mekaniska Werkstads AB (J.M.W.) for technology transfer at least until 1957 when they delivered their first boiler designed for a steam temperature of 480C (896F) to Chuetsu Pulp Industry Co. Ltd.; the design pressure was 7.0 MPa (1010 psig). Subsequent installations for increasing pressure and temperature centered on Oji Paper Co., Ltd., primarily at their mill in Kasugai.

A boiler designed for 10.1 MPa (1450 psig) and 480C (896F) was delivered in 1961 to the Kasugai Mill, the first at that pressure level. A second boiler was delivered to the mill in 1966. Both were relatively small boilers, the largest having a steam generation of 80 t/h (176,400 lb/h). In 1983, Oji Paper had delivered to their Yonago Works (Table V) a MHI boiler for a design pressure of 11.9 MPa (1706 psig)) and operating conditions of 10.0 MPa (1435 psig) and 500C (932F).[19] It was not until 1985 that another paper company in Japan moved up to the higher pressure and temperature operating level when a boiler was delivered to Daio Paper Corp for their mill in Mishima designed for 11.9 MPa (1706 psig) and operating at 10.0 MPa (1435 psig) and 500C (932F). This No. 17 boiler at Daio Paper was the largest recovery boiler in Japan at that time with a dry solids rating of 1665 t/d (3.67 million lb/d) and steam generation of 243 t/h (536,800 lb/h). The boiler was subsequently upgraded to 1750 t/d (3.86 million lb/d) and steam generation of 258 t/h (569,000 lb/h). From that time, the ordering of high pressure and temperature recovery boilers in Japan has been the common practice.

An interesting historical first was the delivery in 1986 to Oji Paper for their Tomakomai Mill of a boiler designed (MAWP) for 13.1 MPa (1891 psig) and superheater outlet conditions of 10.9 MPa (1567 psig) and 500C (932F)with a reheat superheater design pressure and temperature of 3.9 MPa (555 psig) and 395C (743F). The high pressure steam flow is given as 146 t/h (324,000 lb/h, which by North American standards is very small for a reheat design.

By 1996, boilers designed to generate steam at 11.0 MPa (1580 psig) and 500C (932F) were well accepted. The boiler with the highest pressure presented in the experience list is a 1993 recovery boiler for Daio Paper Corp for their Mishima Mill having a design pressure of 15.9 MPa (2300 psig) and operating pressure of 13.3 MPa (1914 psig).

The boiler delivered in 1983 to Oji Paper for their Yonago Mill was at that time claimed to be the highest pressure and temperature in the world [19]. No recovery boiler in North America reached that level until 1990 when the Babcock & Wilcox boiler was started up at the Weyerhaeuser Company mill at Columbus, MS. MHI placed in operation in October 1990 a single, large recovery boiler in the Kasugai Mill to replace the three boilers delivered in earlier years. The Kasugai mill boiler is rated at 2400 t/d (5.292 million lb/d) dry solids and generating 410 t/h (904,000 lb/h) of steam at 10.9 MPa (1435 psig) and 500C (932F); the design pressure is 13.3 MPa (1920 psig). A technical paper was presented at the 1992 International Chemical Recovery Conference in Seattle, WA, pronouncing the boiler at Kasugai to be the worlds largest high pressure and temperature recovery boiler.[20] By comparison, the boiler at Weyerhaeusers Columbus mill is actually larger. It has a dry solids rating of 2700 t/d (5.85 million lb/h) with 408 t/h (900,300 lb/hr) of steam being generated at 10.8 MPa (1550 psig) and 496 C ( 925 F); the design pressure is 12.7 MPa (1825 psig).[8]

The 1992 paper describes some of the considerations in superheater design to provide for the Oji Paper recovery boiler selected material that will eliminate the repair of superheater tubes for about 20 years.[21] Materials were selected that had a safety factor of about 30 C (54 F) below the upper limit for temperature at the design pressure. Some considerations in selection of materials for the superheater tubes were:

1. Operation with low SO2. 2. The melting point temperature of deposits to be greater than the tube temperature. 3. Knowledge that the corrosion is strongly affected by chromium content of the steel 4. Knowledge that molten ash deposits containing chloride subject austenitic steel to intergranular corrosion.

Sumitomo Metal Industries in 1986 reported the results of extensive tests to understand the high temperature corrosion behavior of recovery boiler ash on superheater tube materials.[21] The researchers evaluated corrosion


rate using average thickness loss and penetration depth in the grain-boundary of samples. Their conclusions appear to reflect the direction taken by MHI in the selection of tube composition for increasing temperature.

1. Reducing the carbon content of the metal reduces the penetration depth in grain boundaries. 2. Increase in Cr content from 18 to 25% by weight decreased total penetration depth. 3. Below 3%, Mn decreases the penetration depth. 4. The addition of Mo above 0.5% Mo decreased the total penetration depth up to a Mo content in the range

of 1 to 2%

MHIs continuing search for a superheater material resistant to corrosion is reflected in a paper presented in 1998 at the International Chemical Recovery Conference in Tampa, Fl .[18] Mitsubishi reported development of a special tube material, reducing by approximately one-half the carbon and silicon concentration of the conventional 25Cr-14Ni material. Reported test results compare the corrosion resistance and allowable stress of the special new low C-low Si-25Cr-14Ni to the conventional 25Cr-14Ni steel and to Type 321 stainless steel. The special steel compared favorably by both measures, about a 45% higher allowable stress than the type 321 steel. The subsequent operating experience with the low C-low Si-25Cr-14Ni steel is highlighted in a report in 2004 for a second generation recovery boiler delivered to a Japanese mill designed to produce steam at a temperature of 515C (959F) and a pressure of 10.9 MPa (1566 psig). [22]

MHI summarized 20 years of high pressure and high temperature recovery boilers in the paper presented at the 2004 International Chemical Recovery Conference in Charleston, SC.[22] The paper describes this second generation design in more detail. The 1998 boiler is a single drum design to burn 2400 t/d (5.292 million lb/h ) of black liquor solids at a concentration of 75% solids and to generate 410 t/h (904,000 lb/hr) of steam. The special superheater tube material is designated MN25R. A freeze crystallization system with a capacity to process 700 kg/h (1544 lb/h) of ash controls the potassium and chloride liquor in the black liquor. Information about the resulting Cl and K in the precipitator ash is given in an earlier paper to be 2% Cl and 4 % K.[23] A trend chart of steam temperature shows an average of 505C (941F) and 10.7 MPa being maintained for about 8 months between scheduled outages; 6 months is understood to be a performance guarantee.

Superheater tubes of the MN25R material are reported to show no indication of corrosion after 5 years of operation; the claim is supported by a photograph. The paper emphasizes that the control of flue gas composition is important for corrosion control. SO2 can accelerate corrosion by chloride in the ash. CO can result in carbonization, accelerating corrosion. At 75% solids, it should be possible to operate with no SO2 in the gas.

In summary, MHI for over 20 years have had a concerted effort to develop and test the steel materials that make it possible to establish reliable operation of recovery boilers at high pressure and high temperature. They have considerable experience and developed the MN25R material with the objective to operate a recovery boiler at 540C (1004F).[22] The information available suggests MHI is content to hold the design pressure in the range of 128 to133 MPa (1850 to1920 psig). The corresponding operating pressure is 10.9 MPa (1580 psig).

High Pressure and Temperature Recovery Boilers in Finland and Sweden

The mills in Sweden and Finland have been installing large recovery boilers at increased pressure and temperature to modernize and increase the heat recovery efficiency of equipment.

Sweden

Development in Sweden of boilers to operate at higher pressure and temperature steam conditions was definitely restrained by corrosion experience. A report of survey results covering forty years experience in fighting recovery boiler corrosion in Sweden was presented at the 1985 international Chemical Recovery Conference.[24] One conclusion of the report is Superheater corrosion seems at a glance to be rather infrequent in Sweden. The first reason is that our most used superheater steam temperature is moderate. The survey further quotes a study reported in 1968 at a Recovery Boiler Conference in Stockholm recommending the boiler pressure should not exceed 6 MPa (850 psig). The report did not mention temperature, notwithstanding, there was a recommendation that steam temperature not exceed 450 C (842 F).


The discovery in 1964 of external corrosion on secondary superheater loops immediately upstream of the outlet after six (6) years of operation in a Billeruds recovery boiler is believed to be an example of incidents that contributed to the recommendation to limit pressure and temperature.[25] The material was analyzed to be the equivalent of SA213 T12 (1Cr 1/2 Mo). The boiler operated at a relatively low secondary superheater outlet temperature of 425C (797F). The black liquor fired in the boiler was reported to be from a sulphite pulping process. This incident is illustrated in Figure 3 with corrosion highlighted on all three bends of the secondary auperheater outlet.

The bends showed no evidence of overheating. Corrosion occurred on the underside of the outer loops, intermediate loops and the inner loops of bends on every element across the boiler width. Ash deposits on the loops were exposed to direct furnace radiation. It was thought that the corrosion products spalled off as they formed exposing fresh metal for corrosion attack.

Experience parallels that of superheaters in USA boilers. Survey reports in this study appear to show the lower steam temperature boilers have a greater prevalence of corrosion. Factors are counterflow of steam and flue gas instead of parallel flow, not shielding the higher temperature loops with the nose arch, and hanging elements for the higher steam temperatures forward of the end of the arch.

The Swedish pulp and paper industry has recently started up four boilers operating at high pressure and temperature. (see Table VI)

TableVIHighPressureandTemperatureRecoveryBoilersinSweden

Mill Vr Skoghall strand Obbola

Owner Sdra Cell Stora Enso SCA SCA

Location Vrbacka Skoghall Timr Obbola

Design solids, metric ton/day 2100 2200 3300 1000

Dry solids concentration, % 75 80 80 80

Design steam generation, t/h 320 318 524 173

Pressure, MPa 8.6 10.8 10.6 11.0

Temperature, C / F 485 / 905 500 / 932 515 / 959 505 / 941

Startup May 2007 Sept 2005 Oct 2006 2009

Figure3 SuperheaterCorrosionExternalWastageonUndersideofBend


Notes:

1. The boiler at Vr started up in May 2002 at 6.1 MPa and 450C; pressure and temperature raised May 2007. Mill has Swedens first ash leaching system delivered by Metso Power.

2. Due to limitations in pulp production, the boiler at strand presently operates at 2500 t/d firing 73% solids liquor to produce 386 t/h of steam.

3. The boiler at Obbola started up in October 2007 with black liquor solids at 74% A new evaporator plant was operational in 2009 at 80% product solids.

Finland

Table VII is a list of recovery boilers in Finland operating at steam temperatures of 480C (896F) and above.

TableVIIOperatingRecoveryBoilersinFinlandwithHighSteamTemperature

Mill

Original Manufacturer

Start Up

Capacity Dry Solids

t/d

Steam Capacity

t/h

Temperature C

Pressure MPa

Stora Enso Enocell Oy Uimaharju

Tampella 1992 3000 460 480 8.4

Stora Enso Oy Imatran tehtaat

Ahlstrom Tampella

1987 1992

1700 3300

237 504

480 480

7.1 8.5

Stora Enso Fine Papers Oy Varkauden Sellutehdas

Ahlstrom 1980 1150 151 480 8.4

Stora Enso Fine Papers Oy Oulu Mills

Ahlstrom 1988 1600 253 480 8.2

Stora Enso Fines Papers Oy Veitsiluoto Mill

Tampella 1977 2000 234 480 8.2

Stora Enso Laminating Papers Kotka Mill

CE 1959 700 108 482 8.3

Oy Mets-Botnia Ab Joutseno Pulp

Ahlstrom 1998 4000 540 490 9.3

Oy Mets-Botnia Ab Kemi Mill

Tampella 1990 3400 428 480 8.5

Oy Mets-Botnia Ab nekoski

Ahlstrom 1985 2700 335 480 8.2

Oy Mets-Botnia Ab Rauma

Tampella 1996 3500 425 490 9.2

Sunila Oy Kotka

Tampella Tampella

1965 1988

950 1300

121 130

460 480

7.6 6.5

UPM-Kymmene Oy Kaukas

Ahlstrom 1991 3780 580 480 8.4

Kymi Paper Oy Kymi

Metso Power 2008 3600 608 505 10.2

UPM-Kymmene Oy Pietasaari

Andritz 2004 4450 666 505 10.2

Some observations can be made from the information in Table VII.

1. The oldest listed high pressure and temperature recovery boiler started up in 1959 was delivered by Combustion Engineering to operate at 8.4 MPa and 482C (1200 psig and 900F), The capacity was 700 mt/day (1.544 million lb/day) solids.


2. The two boiler manufacturers in Finland have experience from 1964 in the design of superheaters to operate at a steam temperature of 480C ( 896F). The boiler started up in 1964 was supplied by Tampella. Ahlstroms first boiler was in 1977.

3. Most of these boilers were designed with a pressure at the superheater outlet of 8.2 to 8.5 MPa ( 1190 to 1234 psig).

4. The next higher level of steam conditions was realized in the startup in 2004 of a boiler to operate at 10.2 MPa and 505C (1479 psig and 940F).

TableVIIIBoilersShutdowninFinlandinthePeriod2008throughApril2009

Stora Enso Kemjrven Sellu Oy Kemjrvi Shutdown April 2008

Tampella 1964 1200 160 480 8.4

Oy Mets-Botnia Ab Kaskinen Mill Shutdown March 2009

Ahlstrom 1977 2000 250 480 8.2

Kymi Paper Oy Kymi Shutdown

Gtaverken Gtaverken

1964 1977

800 1800

120 280

480 480

8.4 8.4

UPM-Kymmene Oy Tervasaari Shutdown December 2008

Tampella 1975 1150 160

The recovery boiler manufacturers in Finland have a close association with users and research institutions. Much of the research appears to focus on knowledge to improve the product. The title of a paper presented in 2004 at an International Chemical Recovery Conference in Porvoo, Finland, says it all - Forty years of recovery boiler cooperation in Finland.[26] The paper specifically chronicled superheater corrosion in modern recovery boilers. Dr. Salmenoja defines a normal rate of corrosion that typically results in a superheater life of 20 years.

Dr. Keijo Salmenoja has for a number of years displayed a keen interest in the subject of superheater corrosion. A paper presented at the 2001 Tappi Engineering/Finishing & Converting Conference in San Antonio, TX, reviewed knowledge of combustion process and corrosion mechanisms required to control superheater corrosion. The paper further develops the importance of the arrangement of the surface.[27] He coauthored a paper for the 2007 Conference in Quebec City that described a corrosion investigation of superheater materials. [17]

SUPERHEATER DESIGN

Introduction

This overview of how a superheater is designed is intended to guide the reader through the process of design and to identify design issues that require assessment when preparing a specification or procuring a superheater.

There are several specific tasks that have to be integrated together to achieve the operating objectives and an acceptable life:

provide sufficient heat transfer surface to cool the combustion gases and reach the desired final steam temperature,

select tube material that will minimize corrosion and oxidation rates, arrange the superheater surface to control metal temperature which affects corrosion rates, control deposits to minimize plugging and fouling to permit operation for a one year period without

shutdowns for cleaning, provide means for control of final steam temperature with various degrees of fouling, provide for the mechanical integrity of the unit.


The designer must maintain an awareness that, for any given tube material, tube wall corrosion rate is a function of temperature and hotter potentially means more corrosion. Appropriate selection lf tube material requires arranging the surface and determining the tube wall metal temperature throughout the superheater to establish suitable temperatures for the material and the environment. The design of a superheater depends on the designer having in place valid procedures to determine the temperature of the tube wall for the conditions of operation for the boiler.

Heat Transfer

To start with the basics, consider the elements that govern the heat transfer from the flue gas to the steam flowing inside of a tube. [7]

1. Convective heat transfer to the tube wall, which depends on local gas temperature and the gas film resistance.

2. Radiation heat flow, which depends on the broader temperature field, view factors, and absorbtivity and emissivity.

3. Resistance of the tube wall to conduction heat flow. 4. Resistance of the steam film to convection heat flow.

The tube wall resistance is very small compared to the other resistances and the conventional approach is to not consider the wall resistance.

The major resistance to overall heat flow is on the gas side. However, the steam film is the most important in determining the metal temperature. There is considerable gain to be realized for reducing tube wall metal temperature by maximizing steam flow velocity at the expense of pressure drop. It is a common practice of some manufacturers to design a high temperature superheater for a pressure drop in the range of 10 to 17 MPa (150 to 250 psi).

Absent from the above list is the resistance of the ash deposit. This resistance is very important as it ultimately determines the final heat transfer surface required for sustained operation at the final steam temperature. The designer generally handles this in one of two ways. One way is to introduce into the equation:

Q = U*S*Tm

an experience factor (multiplier) that is characteristic of the ash in a recovery boiler. The second is to allow for a resistance of ash to conduction heat flow [28] Both methods are ways to correlate observed results to classical heat transfer correlations and both achieve the same result. In the above equation:

U = combined conductance as described in the above list, Kcal/m2-hr-C or Btu/ ft- hr- F Q = heat transfer, Kcal/hr or Btu/hr S= superheater surface, m2 or ft Tm = log mean temperature difference steam and flue gas, C or F , Furnace Exit Gas Temperature The superheater design is strongly influenced by the temperature of flue gas leaving the furnace and entering the convection surface. This furnace exit gas temperature (FEGT) is calculated by empirical methods taking into account test results and data accumulated from operating experience. Each supplier has used recovery boiler test data to establish for their respective boiler design a graphical relationship of FEGT and related furnace heat release rate. Gas temperature in the zone of the furnace outlet through to the superheater outlet is measured with a high velocity thermocouple (HVT) probe. .The FEGT can be expressed in different furnace geometries, depending on the location of temperature test measurements.. For example, as an average temperature of a horizontal plane at the tip of the nose arch or as an average temperature over the vertical plane at the inlet to the furnace screen, or in the absence of a screen, the inlet to the superheater.

The thermocouple element in the water-cooled HVT probe is shielded to minimize the effect of radiation on the measured temperature. However, the HVT temperature deviates from the true gas temperature above 649C (1200F) and a correction factor needs to be applied. The correction is the difference of the temperature if measured


with a MHVT (multiple high velocity thermocouple) probe, which is accepted as measuring true gas temperature. A MHVT probe is highly shielded to reduce the radiation to the thermocouple to a negligible level. If used in routine recovery boiler testing, it will plug quickly with ash and is not practical for testing. The curve for correcting the HVT temperature measurement follows. The curve also shows the degree of error that can be expected using gas temperatures measured with a bare thermocouple.

Profile of Gas Flow and Temperature Entering Convection Surface

The challenge to the designer is to distribute the flue gas flow and the gas temperature over the convection surface beyond the plane. This is a critical input for calculating the metal temperatures. The addition of superheater surface in an existing furnace frequently results in furnace screen and/or superheater surface coming in close proximity to the front furnace wall. High temperature recovery boilers have superheater elements reaching lengths of 14 to 21 meter (46 to 69 feet) from roof down to the lower loops. With superheater elements reaching lengths of 21m, well beyond the lengths having years of experience, the potential for considerable top to bottom temperature variation is increased. Consider two different superheater lengths between the nose tip and the furnace roof 14m and 21m, and that each has the same FEGT at the horizontal plane at the tip of the nose. There is a considerable difference in upper furnace wall surface between the two. Therefore, the average FEGT entering the vertical plane at the superheater inlet will be quite different, that is, much higher for the shorter superheater.

In large units, depths from furnace front wall to nose arch tip are reaching 7.6 meter (25 feet) with furnace widths in the order of 15 meter (50 feet). As the size of recovery boilers has increased, so has the availability of sophisticated and realistic computer models that can provide a profile of temperature and flow distribution. Computational fluid dynamics (CFD) models have the potential to provide detailed gas temperature and flow distribution predictions. The issue is always model validity. The model must be validated to actual performance; the model results can be misleading if not validated. All CFD models are highly dependent on the boundary condition assumptions.

The final calculation depends on the designer using experience to designate upset and unbalance factors to be applied to determine the worst case tube metal temperatures. The tube temperature determination for the selection of superheater materials is affected by the assumption of the potential upset (deviation from the average) in steam temperature. The steam temperature upset is a function of the cumulative effect of a gas side unbalance creating at a selected spot maximum heat absorption with a minimum steam flow reflecting an assumption of steam side unbalance. It is not uncommon for a designer to assume a deviation of +/- 150C (300 F) top to bottom. The superheater design is also very dependent upon the boiler operation to provide favorable gas composition and ash characteristics.[22, 27] That is, gas free of CO, for example, and ash at a composition and temperature that is not corrosive and can be easily removed by the sootblowers

Each boiler supplier can present gas temperature values and flow distribution for establishing tube thickness and metallurgy that can be very different depending on the individual supplier assumptions on the range of operating conditions to account for off-design conditions. The arrangement of superheater surface and the nose profile also contribute to differences.

A CFD model is recommended to be considered each time a new recovery boiler is designed, or an existing boiler significantly altered. There are situations where the designer will have performance information from a similar unit and feel confident to proceed without modeling. Modeling should be recognized as an important design tool, one of several. It is important to realize that the defined boundary condition can influence the results in a desired direction.

Figure4CurveforCorrectingHVTTemperature[29]


The impact of the lower furnace black liquor combustion system arrangement of air and liquor introduction affects the flue gas flow and temperature distribution at the furnace outlet. This pattern can be optimized and extremes reduced. The designer strives to most efficiently transfer heat uniformly from the bottom to the top of the superheater elements.

Furnace Nose Arch

The Furnace Nose Arch profile has a significant impact on the distribution of flue gas through the superheater banks. The extent of penetration of the nose into the furnace, the shape of the end of the nose, the slopes of the upper and lower sides of the arch, all have an impact. Suppliers have different opinions about the flow pattern of gas they want the nose to create. There is general consensus, however, on one aspect of the nose. This is that the nose penetration of the furnace depth should not exceed about 50 percent. Further penetration results in a significant misdistribution with a large portion of the flue gas flowing through the upper portion of the superheater. One supplier has published the testing of several degrees of penetration.[30]

Different suppliers have different preferences.

Preference to maintain the tip of the nose at the location of the first row of tubes in the superheater, but not to exceed a nose length of about 50 percent. Before extending the superheater into the furnace beyond 50 percent on a single drum boiler, consider extending the superheater to the rear by increasing the distance between the furnace rear wall and the generating bank.

In contrast, to use a nose that penetrates about one-third of the furnace depth with significant surface in front of the nose (Some replacement superheaters go most of the way across furnace)

End of nose profile to create a small circulation of gas above the nose so that a reverse flow between superheater loops and nose tubes prevents any hot gas bypassing surface, that is, sneaking up the nose slope to cause a pocket of hot gas and sticky ash at the generating bank inlet. In this arrangement, an inspector could pass between the arch and ends of loops from one sootblower cavity to the next.

In contrast, designing the superheater so the clearance between superheater and arch tubes is very small when the superheater is hot. It is intended that gas flow has no circulation above the nose.

Furnace Screen

The amount of surface in the furnace screen is directly determined by the gas temperature limit for flue gas entering the boiler screen and the generating bank and the superheater heat pickup. The temperature limit at this location should be determined from the ash melting characteristics and the sintering characteristics. The difference between boiler inlet temperature, or superheater outlet temperature, and FEGT must be heat absorbed by the superheater and furnace screen surfaces. Accordingly, the required screen surface decreases with increasing design steam temperature to the extent that the higher steam temperatures require no screen.

History has proven that substituting screen surface for furnace height can result in a recovery boiler that has insufficient furnace surface to cool the gases and entrained particulate. Units with large screens and a calculated moderate average FEGT entering the superheater often have a high gas temperature at the plane below the screen; the top to bottom variation can be considerable. There is further very little cooling of the gas entering the bottom of those superheater designs with elements hanging out in front of the nose. In addition, the particulate has cooled at a slower rate than the gas and large particulate can have a higher temperature than the gas at the superheater inlet. During the late 1950s and first half of the 1960s in North America, a large number of short furnace boilers were placed in operation. They continue to plague the industry with increased downtime to this day.

The tall furnace trend was further boosted in the late 1970s with demand by operating companies that there be no furnace screen in a recovery boiler. This requirement had its advent in the perception that leaving out the screen provided a safer operation in that the potential of a leak from falling slag breaking a tube was eliminated. However, the safety benefits of eliminating the screen may be overrated. The engineer should carefully consider the pro and con of installing a screen.

The data from this study does not show any benefit in the screen reducing corrosion of the superheater elements being shielded. The screen at this location was having little effect on reducing gas temperature. .


A screen when installed should have tubes aligned with the superheater tubes. There should be sufficient tubes, that when bent from the vertical to bridge a section of the furnace, are aligned tangentially and fastened together to effect a beam with strength to resist falling chunks of ash. The upper tube of the bridging section should have a vertical, longitudinal fin on top to function as a breaker of falling deposits.

Heat Flow and Tube Wall Temperature in a Superheater

A technical paper published in 1991 describes a program for comprehensive computer-based heat transfer analysis of the superheater to determine row-by-row the steam, tube wall and gas temperature.[28] The authors indicate basing their computer program on heat transfer equations from STEAM, a publication of The Babcock & Wilcox Company.[7] Babcock & Wilcox and other boiler manufacturers had realized the importance of a row-by-row analysis long before the advent of the computer. The general data from STEAM was adapted to develop a similar program in 1991 for private use for a recovery boiler. Engineers interested in a more comprehensive description of heat flux calculations to define tube metal temperatures are referred to these literature sources.

The heat flux in each tube row is a summation of convection and radiation heat flow. The superheater bank tubes and lower loops facing the furnace can receive a significant increase in heat flux contributed by radiation. With the juxtaposition of a furnace screen, the furnace radiation is filtered by the water cooled screen tubes and makes a lesser contribution to superheater heat flux. Each sootblower cavity contributes radiation to the adjacent tubes, including the water wall tubes. A superheater tube row bounding the cavity is generally an inlet or outlet tube. The heat flux to the bounding tube does increase the tube wall delta T resulting in elevating the steam temperature. Where superheater elements are in front of the nose, bounding surface is also the lower loops of the elements.

The tubes in a superheater that data supports to be most susceptible to corrosion are:

1. Lower superheater loops of tube rows hanging in front of the nose arch. 2. The front row of the first bank of superheater tubes. 3. The tubes with the highest steam temperature, and hence, higher tube temperatures, are the final row of the

final bank of superheater tubes producing the terminal steam temperature and the steam outlet tubes of a superheater bank immediately upstream of a spray water attemperator.

The calculated tube metal temperature is used to determine the allowable stress value of the appropriate material that complies with the latest edition of the ASME Code. The minimum tube thickness for the location is then calculated using the pressure vessel equation. The design calculation for composite tubes is based on the inner, load-carrying material and the cladding considered as only corrosion protection.

Tubing Material for Superheaters

Metallurgical issues in recovery boilers were discussed in considerable detail in the history of recovery boiler superheaters earlier in this report and will not be repeated here.

The information acquired directly from mills during the course of this study indicated that carbon steel, T11 and T22 were the most commonly used materials in the superheaters. The data further showed that a superheater containing T22 could be operated at a steam temperatures of 496C (925F) without significant corrosion when chloride (and probably potassium) levels were kept low and steam temperature was closely monitored and controlled. The view might be adopted that more exotic materials are only needed if steam temperatures are to be increased above 496C and/or to provide greater flexibility in operating the boiler.

The availability of materials for superheaters has never been better, especially new materials for superheaters to operate at 900 F and above. The traditional tube materials that have resulted in successful superheater installations in the 20th Century are various welded and seamless carbon steel materials, SA213 T11, SA213 T12, SA213 T22 and several of the austenitic stainless steels, such as SA213 TP347H (18Cr-10Ni), SA213 TP310H (25Cr-20Ni). T12 is similar to T11, and much more available on the world market and has been used on newer boilers. There are older boilers still operating with SA213 TP304H. A boiler with TP 347H material in the superheater tubes has operated for almost 25 years without incident in a South Carolina mill at 1500 psig and 880 F.

Four of the newer materials for the 21st Century include:


Sandvik 310/T22 Sandvik 310 (25Cr-20Ni) over SA213 T22 (2 1/4Cr-1Mo) Sandvik 310//T91 Sandvik 310 (25Cr-20Ni) over SA213 T91 Sandvik Sanicro 28/T22 Sanicro 28 (27Cr-31Ni) over SA213 T22 Sandvik Sanicro 28/T91 Sanicro 28 (27Cr-31Ni) over SAA213 T91 Mitsubishi Heavy Industries have been very successful with a superheater tube material designated as MN25R developed jointly with Sumitomo. It is a 25Cr-14Ni material with low C and low Si.

Some operating companies are reluctant to use austenitic stainless steel tubes for superheaters in pulp mill service because of the potential for severe damage in the event of boiler water caustic chemicals carryover from the steam drum into the superheater tubes. The experience with the material in service is actually favorable.

Attemperation for Steam Temperature Control

Attemperators are essential for control of final steam temperature. Cooling is achieved in an attemperator by injecting a controlled amount of high purity water into the hot steam. The steam temperature is reduced by evaporation of the injected water spray. Control of final steam temperature at that desired to be maintained for steam turbine or process is made possible by installing a quantity of surface that is excessive for some operating conditions and requires spray water control.

The most significant variation for the designer to consider is the condition of startup with clean surface. During an outage, the superheater is normally water washed to provide a clean surface for inspection. During startup, and most particularly as the boiler is brought on line and the steam flow approaches design rating, the excessive heat absorption results potentially in elevated superheater bank outlet temperatures. In one case with single stage attemperation, data made available to the investigators showed a PSH steam temperature in excess of the final steam temperature. The tube metals had been selected for the normal operation with an ash coating on the tubes. There was evidence of corrosion on the PSH outlet tubes

The superheater design must provide the ability to spray water for temperature control while maintaining the final steam temperature even when changes in tube surface cleanliness, fuel heating value, fuel moisture content, boiler firing rate and ash buildup on the surface result in changes in heat absorption by the superheater.

Attemperators can be located after the superheater (terminal) or they can be located between banks within the superheater (interstage). A terminal atttemperator only benefits turbine protection. The advantage of interstage attemperation is that it can keep the steam and tube metal temperatures down within the superheater as well as providing for temperature control.


A superheater designed with single stage attemperation divides the surface into primary superheater (PSH) and secondary superheater (SSH). With two-stage attemperation, the surface is divided into one additional section referred to as the tertiary superheater (TSH). The temperature profile of these two attemperator arrangements is reflected in Figure 5. Each arrangement must reduce the total temperature of steam to the same degree.

The spray water flow to the single stage attemperator is controlled to maintain the final steam temperature leaving the SSH. When the surface is clean, there may be insufficient spray water available to prevent this temperature rising above design. Operators use various approaches to avoid these startup conditions of excessive temperature. They include operating at decreased load until there is an ash layer on the tubes to not operating the sootblowers in the superheater for some days. One operation requires two weeks without sootblower operation to limit the steam temperature. Two stages avoid extremes and provides the margins for control.

Designer considerations: The investigators strongly recommend that any superheater designed to operate at 482C (900 F) and above incorporate two stages of attemperation. Further, that two stages be considered for any superheater above 450C (842F). The two stages of attemperation provides steam temperature control in two steps rather than one resulting in lower overall steam and metal temperatures

The installed superheater surface should at boiler rating provide the design steam temperature 12 months after water washing and startup. The attemperation system capacity should provide steam temperature control in the clean surface condition.

The impact of requiring a design to provide the maximum steam temperature be reached at a reduced load; or control load; 70% is a common load specified. The impact is considerable to surface, attemperator spay water flow required and metals. Metal temperatures will increase, requiring alloy tube material with higher use limits.

The engineer preparing a specification should consider the load at which the boiler will normally operate. Most recovery boilers operate at or near rating. In most situations, there is little if any justification to over surface the superheater by specifying a control load.

Condense steam from the steam drum to provide spray water. A shell and tube heat exchanger (sweetwater condenser) is used to condense steam from th0e steam drum, using feedwater inside the tubes as the coolant. The condensate is injected directly into the attemperator without using a pump. The pressure drop across the PSH provides the head required to atomize the condensate in the attemperator spray nozzle

The design needs to also take into consideration that the spray water flow is steam that bypasses the superheater bank elements, and that the tube metal temperatures increase proportionately because of the reduced steam flow.

It is recommended to limit the flow to the condenser to 10% of the total full load steam flow. Tube metallurgy required should be determined for clean superheater tube surface and the maximum flow to the condenser.

The supply of spray water, during the critical period of startup and initial operation with clean superheater surface, can be extended using demineralized feedwater. When the spray flow is reduced to the extent that the control can be accomplished with only the condensate, the feedwater is isolated and valved out to positively prevent water entering the superheater.

System to limit the desuperheater outlet steam temperature from approaching too close to the saturation temperature, e.g., 28C (50F) above the saturation temperature. The major consideration is to prevent un-evaporated water being carried into the tubes of the superheater.

There are a number of recovery boilers operating in the USA with two stage attemperation. These generally include four banks of tubes two primary, one secondary and one tertiary bank. Two stages have an obvious benefit where the superheater surface condition of cleanliness results in excess heat absorption. The temperature data and corrosion experience for superheaters included in the study shows the benefit of two-stage attemperation - lower steam temperatures exiting the banks and thereby avoiding excessive metal temperature under some operating conditions.

Application and Features of Connecting Pipe and Attemperators

A schematic arrangement of a simple, single stage attemperator controlled by final steam temperature is shown in Figure 6. A tube bank is depicted as a square with a cross and on each side narrow rectangles represent headers. The


single connecting pipe discharges fully mixed steam from the PSH at the average temperature; a single attemperator assures a uniform temperature to the SSH inlet header.

Figure 7 is an \arrangement of connecting pipes arranged to crossover from one side to the other of the superheater as shown, This design feature can compensate for a condition where the gas is hotter on one side than the other ( T1C < T1H). In the second bank, crossover exposes the cooler steam (tC) to the hotter gas (T2H} to achieve a more uniform distribution across the boiler width. Further balance is provided by spraying heavier on the side with the higher steam temperature.

With two stages of attemperation, the crossover arrangement is repeated for the tertiary bank. In a practical sense, the crossover arrangement very much simplifies the piping because the long crossover provides the necessary

length for the attemperator. If the designer were to arrange to locate the attemperator with the header outlet and header inlet on the same side, the close proximity of the two would make pipe routing difficult.

Spray Water Source and Quality

If at all possible, no water from a source other than condensed steam from the boiler drum should be used for the attemperator. Feedwater is less preferable for this purpose. It is important that the spray water be of highest purity , since solids entrained in the spray water enter the steam, and if excessive, can cause troublesome deposits in superheater tubes, steam piping or turbine blades. [7] Feedwater and/or steam condensate returns in pulp and paper mills are unlikely to be consistently of a purity to be sprayed into a superheater. Confining their use to startup only minimizes the risk. The risk can be further minimized by not introducing steam condensate into the deaerater during this period of time.

Superheater Design Details

Arrangement of Superheater Surface

Before the designer can establish tube material requirements, the tubes must be arranged in banks, the banks must be preliminarily sequenced for the gas flow and the steam routed through the bank in parallel or countercurrent heat exchange.

The superheater tubes used in a recovery boiler generally range from 44.5 to 63.5 mm (1.75 to 2.5 in.) outside diameter (OD) - larger sizes on larger boilers. Tubes are bent 180 (U-bends) to form elements that are welded into inlet and outlet headers. The number of tubes in an element that individually terminate in headers can be 1 to 6. These would respectively be referred to as single flow to six flow to designate the number of steam flow paths. Use of single flow would be highly unusual because of excessive pressure drop. The designer adjusts the tube diameter

Figure 6 Single Stage Steam Temperature Control

Figure 7 Crossover with Parallel Attemperators


and number of flow paths to obtain a desired steam flow velocity and pressure drop. The tubes with U-bends are assembled into elements with a prescribed back pitch, or centerline to centerline spacing. The back pitch for elements with spaced tubes has steadily decreased over the years to increase tie life by shortening the span for better cooling. Today, the space between tubes can be expected to range from 25.4 mm down to about 0.8 mm (1 in. down to 1/32 in.) for tangent tube elements The convection heat transfer for tubes in an element is decreased as the tubes are placed closer together. The effect is to require more meters of tubes, that is, more surface.

Elements across the width of the recovery furnace are installed on 304.8 mm (12 in.) minimum side spacing. The experience with lesser spacing in the cooler banks [152.4 to 190.5 mm (6 in. to 7.5 in.) with hotter banks on 304.8 to 381 mm (12 or 15 in. centers)] has largely been unsatisfactory due to plugging propensity. Where a furnace screen is installed, the spacing and alignment should match the superheater. Banks are separated by cavities in which retractable sootblowers are located. The cavity width is to be sufficient for the sootblower steam jet not cutting adjacent tubes, lance movement at the end of travel not hitting tubes, swinging elements not hitting the lance, and personnel entre for superheater inspection and maintenance. A satisfactory distance from the face of the tube to the centerline of the lance is about 225 mm (9 in.); the boiler and sootblower suppliers should be consulted because of the differences in support design for the suppliers. The bank depth is determined by the experience of the horizontal distance between sootblowers that maintains ash removal.

The recommended selection of tubing in a superheater is that a single tube diameter be used for the complete superheater, that each bank of superheater have a single material, and that material in a bank be of a single thickness. There are practical considerations for this among them being:

The total bank has a uniform coefficient of expansion. This should extend tie life and minimize tube distortion. However, practically the difference in coefficient for alloys up to T22 is not enough to be a concern.

Tube inventory in the mill is simplified and less material required. Less possibility of installing the wrong material when making a repair.

There will be instances where it is not practical to use a single thickness of material throughout a bank. This would require using the thickness required for the highest steam temperature, which could result in an unacceptable pressure drop. Consideration in these cases should be given to changing thickness in the bank.

Tube Ties / Support

The information assembled during the study points to a significant portion of tie failures and damage occurring during startup. Instances of tubes bowing out of alignment are also related. A conservative startup program to positively clear superheater loops of water reduces tie and tie weld failures. A direct cause of failure has been ties in the back space that bottom-out, that is, tie design. The mating halves of a tie welded to two tubes expanding at a different rate move beyond the allowance of the tie design, after which the force from differential expansion can result in tie failure, or more often, weld failure.

It is incumbent upon the designer to select ties that make allowance for the worst case scenario of differential expansion of adjacent tubes. At the elevations selected for installation, they should be welded into every backspace. To maintain tube alignment, the rows of ties should be located every 3 meter (10 feet) of elevation, or less. Less is better; one owners engineer specifies every 2130 mm (7 ft). Ideally for cleaning, they would be aligned at the sootblower elevations.

From the limited information available, the most trouble free support arrangement was to support every loop above the furnace roof tubes. With total support above the roof, there is no need for support ties on the elements, and therefore, all ties can be flexible.

The use of side-to-side ties between elements across the width of the boiler can be a subject of controversy. There are designs with operating experience that have none; in every case, the arrangement of support is a high crown seal design. Each supplier of these establishes a limit on sootblower operating conditions to limit the element movement caused by the steam jet. Arrangements that incorporate an arrangement of side-to-side ties have an advantage in


controlling ash deposits on the tubes by operating the sootblowers at a higher level of steam pressure. The study had insufficient information received to make a detailed comparison.

Arrangement of Banks

There are several sequences for the banks that the study indicates can be satisfactory. For this purpose, satisfactory is defined as an arrangement where tube corrosion should not occur when the chloride and potassium levels in the recovery boiler are below a design value and the defined liquor solids input is not exceeded. This definition assumes that the modern recovery boiler superheater is expected to operate with corrosion controlled to minimize metal loss.

The four recovery boiler suppliers in the USA were unanimous in stating that a superheater can be designed with elements in front of the nose arch that is capable of meeting high steam temperature with minimal corrosion and acceptable cleanability.

One arrangement providing high temperature steam common to several boilers is shown in Figure 8.

Staged attemperation make possible control of the steam temperature entering both the secondary and tertiary tube banks. At the position of each attemperator illustrated, there are installed a second parallel unit as well as crossover pipes. The designer has latitude to set the bank locations to economize on tube material. The two stages of attemperation, coupled with the tube materials available, provides considerable flexibility for arrangement.

A low temperature superheater should be designed using the same principles as applied to a high temperature superheater. There are a surprising number of these that are installed with totally countercurrent surface placing the hottest steam in tubes at the furnace exit. In many cases, these tubes extend beyond the end of the nose where they are subject to radiation, and the lower loops waste away quickly. These boilers, many of which are designed for 400C (750F) steam temperature, usually have furnace screens.

The recommended arrangement for a low temperature superheater to have long life is totally parallel flow arrangement with all surface back of the end of the nose so that none of the surface is exposed to direct radiation from the lower furnace. The steam temperature leaving the superheater will vary from the design temperature and any downstream equipment that is temperature sensitive can be protected by a terminal attemperator.

SUMMARY

The overall, worldwide trend is toward designing and operating the kraft recovery boiler to produce steam at high temperature and pressure. The objective is to maximize the boiler thermal efficiency and the electric generation cycle efficiency. The result is to reduce the requirement for other biomass and/or fossil fuel with a reduction in carbon dioxide release to the environment. The experience and technology is available to achieve this objective.

Figure8 Example of CommonArrangementofSuperheaterBanks


Superheaters on recovery boilers designed to operate at 482C (900F) go back to the 1950s. The more recent advances in black liquor combustion technology and boiler design coupled with availability of improved tube materials have resulted in superheaters in operation to a steam temperature of 515C (959F.).

The boiler manufacturers in Japan, Mitsubishi Heavy Industries and Kawasaki Industries, have done the most to advance the operation of recovery boilers at higher steam temperatures. There are eight (8) recovery boilers in Japan designed for a steam temperature of 515C: the first was in 1987. Finland also has considerable experience with high temperature and pressure recovery boilers. The two most recent boilers in Finland are designed for 505C (941F).

In North America, the majority of recovery boilers are not designed for high steam temperature. There are in operation forty-six (46) recovery boilers designed to operate at 482C (900F) and above. About 60% are more than 20 years old; the oldest is 50 years. Many operate below design temperature for sundry reasons. There are a few known to operate at or near design temperature for 12 months; the highest steam temperature is 496C (925F). Two of the newest boilers are listed to be designed for 505C; these are the Andritz boiler at Campti, LA, and the Metso Power boiler at Grand Prairie, Alberta.

Many of the high temperature superheaters installed in North America during a period of 50 years were under surfaced. Application of an artificial (and unrealistic) black liquor analysis and high heating value (HHV) in the design was the major contributing cause. There are also boilers deliberately operated below design temperature to prevent corrosion. From a positive perspective, there are superheaters that perform up to expectations and are capable of operating at design steam temperature for up to 12 months with cleanliness maintained by sootblowing only. In all of these that the investigators are aware of, chloride levels are being controlled.

The experience and tube metallurgy available today make it possible to design with confidence a superheater to operate at 510C (950F). The engineer must arrange the surface and consider maintaining a tube temperature below the ash melting point temperature throughout the superheater. Success will require control of the chloride and potassium in the black liquor. MHI have said that their MN25R tube material may be suitable for steam temperatures to 540C. Sandvik has composite tubes that may serve for the higher temperature. Increasing pressure commensurate with temperature becomes an issue to further gains in efficiency. MHI appear to have settled on a superheater outlet steam pressure of 10.9 MPa (1566 psig) for their recovery boiler design. There is good experience in the USA with operating pressure approaching that of MHI.

The study shows that a superheater can be designed to operate at the desired temperature for twelve months reliably and with minimum maintenance.[1] The designer must follow the recommendations governing a sound design, such as, surface arrangement, construction details, appropriate metallurgy selection and control of ash chemistry. All of these are well defined.

The role of metallurgy in superheater corrosion is pretty well understood. The most commonly used materials are carbon steel, T11, and T22. There appears to be no single, simple metallurgical solution to superheater corrosion. The highest current steam temperatures in recovery boilers are in Japan and use a special alloy developed by Mitsubishi Heavy Industries. Materials may be a limiting factor in continuing to extend the operating steam temperature range of recovery boilers, but acceptable metallurgies are available now for producing steam at 510C (950F).

Attemperation is essential for control of steam temperature. Interstage attemperation is recommended as it helps keep steam and metal temperatures down within the superheater itself and is beneficial for reducing corrosion. Data obtained in this study shows the benefits of two stage attemperation in keeping metal temperatures down within the superheater. The difference in controlling tube metal temperatures is most evident when operating with a clean superheater

Furnace screens can provide some protective benefit for superheaters by shielding it from direct radiation from the hotter furnace. Although screens came into disfavor during the 1980s because of concerns about explosions following screen failures, these fears were overrated and screens are coming back into use on new units.


The nos

565521

Documents

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