Oxy Combustion Boiler Material Development

Transcription

1 Oxy Combustion Boiler Material Development Archie Robertson Hans Agarwal Michael Gagliano Andrew Seltzer Foster Wheeler North America Corp 53 Frontage Road Hampton, NJ Presented at the 37th International Technical Conference on Clean Coal & Fuel Systems Clearwater, Florida June 3, 2012

2 ABSTRACT Foster Wheeler North America Corp. has conducted a laboratory test program under U.S. Department of Energy Cooperative Agreement No. DE NT to determine the effect of oxy combustion on boiler tube corrosion. The objective of the program was to determine what fire side corrosion mechanisms occur and what their impact will be on boiler tube life when oxy combustion is retrofitted to an existing pulverized coal fired (PC) boiler to facilitate CO2 capture and sequestration. Computational fluid dynamic (CFD) modeling was conducted to predict the gas compositions that will exist throughout and along the walls of oxy fired PC boilers operating with high, medium, and low sulfur coals. Test coupons of conventional and advanced boiler tube materials were coated with deposits representative of those coals and exposed to the CFD predicted oxy combustion flue gases for up to 1000 hours. The tests were conducted in electric furnaces using oxy combustion and air fired flue gases synthesized from pressurized cylinders. After exposure, the test coupons were removed and analyzed to determine the metal wastage experienced and the corrosion mechanisms involved. Based on the data collected, the corrosiveness of oxy combustion flue gas relative to air fired flue gas was determined; analyses of the data suggests that, over the range of variables tested, oxycombustion corrosion will be similar to, if not less than, that of air fired operation. This paper describes the test program and summarizes its findings. INTRODUCTION In an oxy combustion system, the combustion air is replaced by oxygen, and flue gas is recycled to the boiler at a value that enables the boiler to maintain its original/air fired heat absorption; this eliminates the need to de rate the boiler or make major changes to its heat transfer surfaces. Since the recycled flue gas will be mostly CO2 and with air associated nitrogen eliminated, the boiler CO2 and corresponding CO levels are greatly increased. CO is a corrosive reducing gas and, with the recycled flue gas also containing such corrosive gases as SO2, HCl, etc., corrosive conditions are expected to increase throughout the boiler as well as in localized furnace wall zones. The objectives of Foster Wheeler s program were to assess the corrosion characteristics of oxy combustion relative to air based combustion, identify the corrosion mechanisms involved, determine their effects on conventional PC boiler tube materials, and evaluate the suitability of alternative/advanced materials for this new mode of combustion. IDENTIFICATION OF GAS COMPOSITIONS FOR CORROSION TESTING Although the U.S. electric utility fleet uses a variety of boiler configurations to burn a wide range of coals, wall and tangential fired units operating with low NOx burner systems constitute the bulk of the PC fleet. As a result, these two boiler configurations were subjected to CFD analyses to predict the flue gas compositions that will exist throughout them and along their furnace walls, first under air firing and then when retrofitted with oxy firing. The analyses were performed at a nominal 500 MWe size with the units operating with high sulfur (2.5%), medium sulfur (0.7%), and low sulfur (0.3%) coals. 2

3 The amount of sulfur in the flue gas recycled to the boiler under oxy firing affects boiler sulfur levels and can increase the potential for corrosion. The New Source Performance Standards (NSPS) promulgated by the U.S. Environmental Protection Agency (EPA) in 1979 established minimum sulfur removal requirements, and a not to exceed limit of 1.2 pounds of SO2 per million BTUs for all new boilers. For the high sulfur (Illinois No. 6) and low sulfur (Eagle Butte) coals used in this study, the NSPS regulation requires minimum sulfur capture efficiencies of 86% and 70%, respectively; although flue gas desulfurization (FGD) systems are available for up to 98% sulfur capture, the lower values were used to establish an upper SO2 limit for boiler retrofits. The recycle streams were taken from the outlet of the FGD systems and then heated to 66 C (151 F) for delivery to the boilers. Iterative calculations were performed to establish a flue gas recycle rate that enabled the air fired boiler heat absorption to be maintained during oxy firing. The CFD results were post processed to identify the location of and the highest levels of H2S and CO gases along the furnace walls together with their concomitant gas species. As expected, the analyses showed that the high sulfur coal produced the highest levels of sulfur in the boilers (bulk gas SO2 level of 3200 ppmv wet). Wall fired boilers can be provided with or without air injection at the base of their furnace walls; this air supply, referred to as curtain air, flows up along the walls and prevents the formation of localized reducing zones. To provide a worst case analysis, curtain air was not considered in the CFD modeling. Comparison of furnace wall microclimates showed that this wall fired boiler had higher levels of CO and H2S than the tangentialfired boiler. Table 1 identifies the highest level of reducing gases along with some intermediate values found along the furnace walls of the nominal 500 MWe high sulfur coal, wall fired boiler under air and oxy firing. The maximum SO2 level in the superheater/reheater regions and the maximum H2S levels along the furnace walls of the wall fired boiler were observed to be about 50% higher under oxy firing than air firing. With the high sulfur coal, wall fired configuration producing the most corrosive furnace microclimates, it was established as a baseline for additional study cases; the latter investigated the effect on boiler sulfur levels of increasing the FGD sulfur capture efficiency to 98%, recycling the flue gas without sulfur removal (flue gas recycle extracted from upstream of the FGD), and finetuning/slightly reducing the flue gas recycle rate to reduce superheater spray requirements. Table 2 identifies the boiler bulk gas SO2 levels for each of the cases and reveals that recycling the flue gas to the boiler without sulfur removal can increase boiler sulfur levels by about fourfold. For the low sulfur coal case, elimination of sulfur removal from the recycle increase the boiler sulfur levels by fourfold, but they were still well below those of the high sulfur coal 3200 ppmv wet baseline. For the high sulfur coal case, elimination of sulfur removal increased the boiler sulfur levels by a factor of about 4½; the maximum H2S level along the furnace walls was observed to be about 2½ times higher and the superheater/reheater SO2 levels about 4½ times higher than with air firing. Since the latter will greatly increase boiler corrosion risks (the SA213 type T22 and T91 tubes would be especially vulnerable to attack by coal ash corrosion and would most probably require replacement with higher alloy tubing), the latter was deemed 3

4 an unacceptable arrangement for retrofit applications where the objective is to minimize the need for boiler retubing/modifications. Table 1 Gas Compositions Predicted for a High Sulfur Wall Fired 500 MWe Boiler, Vol Wet Coal Location Condition CO H2S CO2 H2O SO2 N2 O2 Misc Air High S Bit. (Illinois 6) O2 High S Bit. (Illinois 6) Lower Furnace Maximum CO H2S 9% 0.14% 11% 8% 0.16% 66% 0.5% 5.7% Lower Furnace Medium CO, H2S 5% 0.08% 13% 9% 0.19% 69% 0.9% 3.4% Lower Furnace Low CO, H2S 2% 0.03% 14% 9% 0.21% 71% 1.5% 1.4% Furnace Outlet Average 0.2% 0.00% 14% 9% 0.20% 73% 3.0% 0.2% Lower Furnace Maximum CO H2S 20% 0.26% 48% 18% 0.17% 7% 0.6% 6.8% Lower Furnace Medium CO, H2S 10% 0.13% 58% 19% 0.25% 8% 1.2% 3.7% Lower Furnace Low CO, H2S 5% 0.07% 63% 20% 0.29% 8% 1.8% 2.2% Lower Furnace Low CO, H2S 2% 0.03% 65% 20% 0.30% 8% 3.0% 0.8% Furnace Outlet Average 0.6% 0.01% 67% 21% 0.32% 8% 2.7% 0.3% Coal Sulfur Wt % Table 2 Effect of Flue Gas Recycle on Boiler Sulfur Level Firing Mode Air Oxy Oxy Flue Gas Recycle Quantity Sulfur Removal 0% NA 70% 0% 70% 70%* Boiler SO2 (ppmv wet) Air Fired 300 Oxy Fired Oxy 71% 0% Air Oxy Oxy Oxy Oxy 0% 71% 71% 71% 68% NA 0% 98% 86%* 86%* *NSPS Minimum Plant Requirement When firing high sulfur coals, the flue gas recycle should undergo sulfur removal to minimize boiler corrosion risks. As a result the 3200 ppmv wet SO2 level was accepted as a most probable upper limit for oxy combustion retrofits and it became the basis for selecting gases for laboratory corrosion testing. Comparison of the Table 1 oxy and air fired furnace wall microclimates reveals different levels of O2 despite similar levels of CO and H2S. To enable the CO and H2S effects to be more clearly seen, the small levels of O2 at the walls were ignored. Chlorine contained in the coal can increase boiler tube corrosion and, since the CFD modeling did not address this gas, a small amount of HCl was added to each test gas. At furnace over fire air ports, the gas atmosphere can oscillate between slightly oxidizing to slightly reducing and, to study this condition, a 1% O2 test condition was included in the waterwall test matrix. After air injection and mixing, the local micro climates dissipate and the superheater/reheater operates with a more uniform gas composition labeled Furnace Outlet. The 1% O2 test condition is, in 4

5 essence, the furnace outlet condition but with the oxygen reduced to 1%. Table 3 presents the gas compositions that were used in the corrosion tests; as shown in this table, the oxycombustion tests involved one superheater/reheater and four furnace gas compositions (Test Series 1A through 5A), whereas, the air combustion tests involved one superheater/reheater and three furnace gas compositions (Test Series 1B through 4B). Table 3 Gas Compositions Selected for Electric Furnace Corrosion Tests, Vol Wet Gas Tes t Series 1A Waterwall: Oxy Com bus tion Waterwall: Air Fired SH/RH Tes t Tes t Test Test Test Tes t Tes t Series 2A Series 3A Series 4A Series 1B Series 2B Series 3B Series 5A Test Series 4B 1% O2 2% CO 5% CO 20% CO 1% O2 2% CO 5% CO Oxy Air N 2 8% 8% 8% 7% 76% 74% 73% 8% 74% CO 2 70% 69% 67% 55% 14% 14% 13% 69% 14% CO 0% 2% 5% 20% 0% 2% 5% 0% 0% H 2 S 0.00% 0.03% 0.07% 0.26% 0.00% 0.03% 0.08% 0.00% 0.00% H 2 O 21% 20% 20% 18% 9% 9% 9% 21% 9% O 2 1% 0% 0% 0% 1% 0% 0% 2% 3% SO % 0.30% 0.29% 0.17% 0.20% 0.21% 0.19% 0.32% 0.20% HCl 0.02% 0.02% 0.02% 0.02% 0.02% 0.02% 0.02% 0.02% 0.02% Total 100% 100% 100% 100% 100% 100% 100% 100% 100% BOILER MATERIALS SELECTED FOR CORROSION TESTS The furnace walls of coal fired boilers are fabricated from ferritic steel tubes because they are relatively low in cost, easy to fabricate, and have relatively high thermal conductivities with low coefficients of expansion; SA210 Type A1 and SA213 Types T2, T11, and T22 steels are some of the more frequently used tube materials. In a subcritical pressure boiler the furnace walls are cooled with boiling water and, with heat absorption rates varying with furnace location, a 16.7 MPa (2415 psia) natural circulation boiler can have furnace nominal outside tube wall temperatures of 427 C (800 F). In supercritical pressure boilers the temperature of the supercritical fluid cooling the furnace tubes steadily increases as it sweeps the walls, and the outside tube metal temperatures are typically 55 C (100 F) hotter than subcritical pressure units. As steam flows through boiler superheaters and reheaters, steam and tube metal temperatures increase and the outside tube metal temperature can be up to 55 C to 110 C (100 F to 200 F) hotter than the steam. With tube strength decreasing and corrosion rates increasing with increased temperatures, different metallurgies are often used in superheaters/reheaters progressing from lower to higher alloying, especially higher levels of chromium. The superheater/reheater tube materials typically used in 538 C (1000 F) boilers are SA213 ferritic 5

6 Types T22 (2 1/4 % Cr) and T91 (9% Cr) followed by austenitic 304H (18% Cr) and 347H (17% Cr) stainless steels. When boilers were modified to incorporate staged combustion for NOx reduction, the combustion air stoichiometries of their burner zones were typically reduced to approximately 0.9. Under substoichiometric/reducing conditions, and with unburned coal depositing on tube walls, significant increases in waterwall corrosion rates have been encountered. Since supercritical pressure boilers operate with higher tube metal temperatures, they have experienced the largest increase in corrosion rates, especially those firing high sulfur coals. To protect boiler tubes from the increased corrosive conditions, thermal spray coatings and weld overlays are frequently employed. Both can be applied in the field and require meticulous cleaning of tube surfaces and strict adherence to application procedures to insure quality control. Thermal spray coatings only provide protection for a limited time, however, as they typically contain some porosity and can be prone to cracking and spalling that allows the substrate to be attacked. For longer lasting protection, highly alloyed weld overlays (WO) are most often employed. With corrosion resistance generally increasing with increased levels of chromium (Cr) and nickel (Ni), and by the addition of alloying elements such as aluminum (Al), a wide variety of weld overlays have been utilized. Type 309 stainless steel (24% Cr 13% Ni), Inconel 622 (21% Cr 55% Ni), and Alloy 33 (33% Cr 31% Ni) are three of the more promising waterwall weld overlays, whereas, Inconel 622 (21% Cr 58% Ni) and Inconel 72 (44% Cr 55% Ni) are currently being investigated/evaluated for use on superheater/reheater tubing. Ten waterwall and ten superheater/reheater materials were selected for corrosion testing and are shown in Tables 4 and 5. The first seven waterwall materials are tube, tube weld, and tube weld overlays that are typical of the U.S. electric utility boiler fleet. Several different thermal spray coatings have been installed in boilers for test/evaluation purposes and materials 8, 9, and 10 are thermal spray coatings that are showing promise. The first four superheater/reheater materials are frequently used tubes (T22, 304H, and 347H) and tube welds (T22 to 304H). T91/92 is a high strength ferritic steel that began to be used in utility boiler superheaters/reheaters during the 1990s, whereas, NF709 and HR3C are high creep strength alloys being developed as lower cost alternatives to high nickel alloys such as Incoloy 800. Although NF709 and HR3C are envisioned for use in future ultra supercritical pressure boilers, their higher chromium and nickel concentrations make them suitable alternatives to 304H and 347H, should the latter prove vulnerable to oxy combustion environments. Weld overlays made from Inconel 622, Alloy 33, and Inconel 72 are candidates for protecting the lower chromium steels from corrosion. The Table 4 and 5 materials were purchased, machined into corrosion coupons, and, where applicable, spray coated. Most of the coupons were rectangular in shape (see Figure 1), approximately 19.1 mm (3/4 inch) wide by 25.4 mm (1 inch) high by 3.2 mm (1/8 inch) thick, and contained a 2.78 mm (0.109 inch) diameter hole to facilitate hanging from alumina rods 6

7 that spanned U shaped racks in the furnaces (see Figure 2). Since corners are points of weakness for coatings, the coated coupons were tested in a bullet shape 19.1 mm (3/4 inch) in diameter by 38.1 mm (1 1/2 inch) high with their top end machined to a 9.05 mm radius (3/8 inch) and are also shown in Figure 1. Their bottom ends were flat to facilitate setting them in 6.4 mm (1/4 inch) deep recesses drilled in the floors of the U shaped racks. Table 4 Boiler Waterwall Corrosion Test Materials Coupon Material Description Boiler Use Composition Weld Weld Overlay Weld Overlay Weld Overlay Thermal Spray Thermal Spray Thermal Spray SA210 A1 SA213 T2 SA213 T11 T11 to T11 309L StnStl Inconel 622 VDM Alloy 33 IGS UTEx IGS UTEx IGS UTEx Relatively New Relatively New Relatively New 0.27%Carbon 1/2 Cr 1/2Mo 1 1/4Cr 1/2Mo 1 1/4Cr 1/2Mo 24Cr 13Ni 21Cr 58Ni 33Cr 31Ni 15Cr 80Fe 25Cr 60Ni 40Cr 55Ni Table 5 Boiler Superheater/Reheater Corrosion Test Materials Coupon Material Description Boiler Use Composition Weld Weld Overlay Weld Overlay Weld Overlay SA213 T22 SA H SA H T22 to 304H SA213 T91 NF709 HR3C Inconel 622 VDM Alloy 33 Inconel 72 Newer Boilers Newer Boilers Newer Boilers 2 1/4Cr 1Mo 18Cr 8Ni 18Cr 9Ni 1 1/4 Cr to 18 Cr 9Cr 20Cr 25Ni 25Cr 20Ni 21Cr 58Ni 33Cr 31Ni 44Cr 55Ni TEST DEPOSITS The composition of the deposits that collect on boiler tubes can influence the amount of corrosion experienced. Waterwall deposits typically contain varying concentrations of iron sulfide, alkali chlorides, and carbon, while superheater/reheater deposits are characterized by differing levels of alkali sulfates, chlorides and carbon. The concentrations of these components vary along the flue gas path and especially along the furnace walls where variations in coal 7

8 fineness, burner imbalance, and air flow distributions can markedly affect the trajectories, burn Figure 1 Typical Corrosion Coupons Rectangular Coupon Bullet Shaped Coupon Figure 2 Typical Corrosion Coupon Test Rack out, and accumulation of coal, char, and ash particles. As a result, there is no one deposit composition for waterwall or superheater/reheater tubes but rather ranges of compositions. 8

9 Coals high in sulfur, such as Illinois No. 6, are typically high in pyritic sulfur and chlorine, whereas, coals low in sulfur, such as Eagle Butte subbituminous coal, are typically low in both pyrites and chlorides. Medium sulfur coals, such as Pittsburgh No. 8, have values that typically fall between these two. The amount of iron sulfides and chlorides present in a deposit are related to the levels of pyritic sulfur and chlorides present in the coal. Table 6 presents the deposit compositions selected for the corrosion tests. In this table LS, MS, and HS designate low, medium, and high sulfur and W and S designate waterwall and superheater/reheater deposits. Table 6 Deposit Compositions Used In Corrosion Tests, Wt % Waterwalls* Superheater/Reheater* Compound LSW MSW HSW LSS MSS HSS Fe 3 O Fe 2 O FeS C SiO Al 2 O NaCl KCl CaSO NaSO K 2 SO Total * W= Waterwall Deposit S= Superheater/Reheater Deposit LS= Low Sulfur, MS= Medium Sulfur, and HS= High Sulfur The proposed deposits collectively bracket the range of corrosive species typically found in the furnace and superheater/reheater sections of pulverized coal fired boilers. The deposits were produced by mixing reagent grade powders, grinding the mixture to a uniform size, adding an organic binder to make a paste, and applying the paste to the sides of the coupons. CORROSION TEST The corrosion test program utilized six electric furnaces divided into two groups (Group A and Group B) each consisting of three furnaces. In each group, each furnace operated at a different temperature; but each of the three furnaces received the same gas composition/blend and contained the same material coupons and deposits (see Figure 3 for a simplified schematic). The test program involved a total of five test series, encompassing 27 test runs; in each of the tests, material coupons were coated with deposits and exposed to either oxy fired (Series A tests) or air fired gases (Series B tests) for 1000 hours. Twenty one of the runs investigated 9

10 furnace gas conditions; those runs utilized four oxy fired and three air fired micro climates, each at waterwall metal temperatures of 399ºC, 468ºC, and 538ºC (750ºF, 875ºF, and 1000ºF), temperatures that span the range of subcritical and supercritical waterwalls. The remaining six runs investigated superheater conditions, one oxy fired and one air fired each at superheater/reheater metal temperatures of 538C, 593ºC, and 649ºC (1000ºF, 1100ºF, and 1200ºF), temperatures that span the range of conventional boilers. An electric furnace test investigated only one material application at a time (either waterwall or superheater/reheater), and it contained a total of 30 material test coupons (ten coated with high sulfur deposits, ten coated with medium sulfur deposits, and ten coated with low sulfur deposits). A gas, blended from gas cylinders, was passed over the specimens with the furnace operating at the boiler material test temperature. At 100 hour intervals, the electric furnaces were shut down under an argon atmosphere, the specimens removed, gently cleaned with a nylon brush, inspected, Figure 3 Simplified Schematic of Electric Furnace Test Facility recoated with fresh deposits, returned to the furnace, and the test resumed; this procedure was repeated until a total exposure time of 1000 hours was achieved. At the completion of each 1000 hour run, the material coupons were removed from the furnace, their condition recorded, and post test evaluations performed. Select coupons were photographed and all coupons were evaluated both macroscopically and microscopically for evidence of gross wall loss and subsurface penetration, the combination of which were reported as the total metal wastage. With the coupons having been indexed and their thicknesses measured prior to testing, the macroscopic evaluation involved re measurement of those thicknesses. The average and maximum wall loss resulting from corrosion was determined based upon the differences between the pre test and post test thickness measurements. Optical microscopy was used to evaluate the corrosion morphology, quantify the depth of intergrannular sulfidation, oxidation and/or carburization, and assess other micro structural alterations. Further evaluation of the ash morphology, compositional makeup of the 10

11 corrosion products and nature of the subsurface penetration (oxides, sulfides, carbides) was performed on select samples using a scanning electron microscope (SEM) equipped with an energy dispersive x ray (EDX) spectrometer. TEST FINDINGS Figure 4 shows some of the coupons removed from the furnace after completing the 2% CO 1000 hour laboratory test. In Figure 5 the air fired and oxy fired T2 coupons from that test are shown side by side after thorough cleaning. Visual observation shows wastage increasing with increasing temperature and increasing deposit sulfur content and the oxy fired wastage appears less than that of air firing. With detailed wastage measurements showing minimal values at low test temperatures and high values at high test temperatures, some of the high temperature data are presented in Figures 6 and 7. Figure 6 presents wastage data for the waterwall materials exposed to the 2% CO micro climate for 1000 hours at the maximum test temperature of 538 C (1000 F). Similar data are presented in Figure 7 for the superheater/reheater materials tested for 1000 hours at the maximum test temperature of 649 C (1200 F). In both figures the wastage is plotted Figure 4 High Sulfur Deposit Coupons after 1000 Hour 2% CO Oxy Micro Climate Test 11

12 Figure 5 Cleaned SA 213 Type T2 Coupons after 1000 Hour 2% CO Oxy Micro Climate Test Figure 6 Waterwall Wastage after 1000 Hour 2% CO Micro Climate Tests at 1000 F 12

13 Figure 7 Superheater/Reheater Wastage after 1000 Hour Tests at 1200 F versus increasing material chromium content. Six bars are shown for each material: the first three present air fired data, the second three oxy fired data. The two figures show wastage tends to decrease with increasing chromium content and corrosion losses under oxy fired conditions are, for the most part, less than or similar to those of air firing. The wastages experienced by the high chromium materials are minimal/much less than the ferritic materials and it appears all of the weld overlays used to protect ferritic materials from excessive corrosion under air firing conditions will also be suitable for oxy firing conditions Analyses of all the test coupons show the effect of oxy combustion to vary with the material, deposit, temperature, and gas composition and: 1.) wastage tends to increase with increasing temperature, especially under strongly reducing conditions; 2.) wastage tends to decrease with increasing material chromium levels; 3.) the weld overlays used to protect the furnace walls of air fired boilers from excessive corrosion appear suitable for oxy fired applications; 4.) no evidence of carburization was found on the superheater/reheater coupons. Assuming boiler bulk gas SO2 levels do not exceed 3200 ppmv wet (the maximum tested in this program), the electric furnace data suggest that the corrosiveness of oxy combustion flue gas and furnace wall micro climates will be similar to, if not less than, those of air fired combustion. The laboratory data suggest that oxy combustion induced corrosion should not be a problem in 13

14 PC boiler retrofits provided bulk gas SO2 levels do not exceed 3200 ppmv wet. Although laboratory electric furnace testing, as conducted in this program, is a valuable screening tool, it is only the first step of a material development process; follow on testing, wherein the materials tested in the electric furnaces are next inserted in operating oxy fired boilers and removed and evaluated after one and two years of exposure is recommended. ACKNOWLEDGEMENT, DISCLAIMER, AND COPYRIGHT The work reported on herein was supported by the United States Department of Energy under Award Number DE NT This paper was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe upon privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof. Neither the author, nor any affiliate, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility including, but not limited to, in regard to the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe upon privately owned rights whether such liability or responsibility is of a direct, indirect, special, punitive, incidental, consequential, or other nature and whether arising in contract, warranty, tort including negligence, strict liability or other legal theory. Utilization of the information is with the above understanding. This material is declared a work of the United States Government and is not subject to copyright protection in the United States. Approved for public release; distribution is unlimited. 14