Progress Towards Cost-Competitive Solar Power Tower Plants

Technical Paper BR-1921 Progress Towards Cost-Competitive Solar Power Tower Plants Authors: K.L. Santelmann, D.T. Wasyluk, and B. Sakadjian Babcock & Wilcox Power Generation Group, Inc. Barberton, Ohio, U.S.A. R. Huibregtse esolar, Burbank, California, U.S.A. Z. Ma National Renewable Energy Laboratory, Golden, Colorado, U.S.A. Presented to: Power-Gen Middle East Date: October 12-14, 2014 Location: Abu Dhabi, United Arab Emirates

Progress Towards Cost-Competitive Solar Power Tower Plants K.L. Santelmann, D.T. Wasyluk, and B. Sakadjian Babcock & Wilcox Power Generation Group, Inc., Barberton, Ohio, U.S.A. R. Huibregtse esolar, Burbank, California, U.S.A. Z. Ma National Renewable Energy Laboratory, Golden, Colorado, U.S.A. BR-1921 Presented to: Power-Gen Middle East October 12-14, 2014 Abu Dhabi, United Arab Emirates Abstract Babcock & Wilcox Power Generation Group, Inc. (B&W PGG) has collaborated with esolar, Inc. (esolar) to develop concentrating solar power (CSP) tower technologies which harness the power of the sun to provide a clean source of power generation. This paper offers an overview of progress which includes a direct-steam power tower demonstration and preliminary design of a molten salt reference plant with thermal storage. The paper also describes the initial development of an advanced high temperature system with the National Renewable Energy Laboratory (NREL) to further increase efficiency and reduce the levelized cost of electricity (LCOE). In 2009, B&W PGG delivered a 10 MW t shop-assembled water/steam solar receiver for esolar s Sierra SunTower Demonstration Plant. The receiver design was based on esolar s modular-scalable plant architecture consisting of standard thermal modules (heliostat field and receiver/tower) to create customized plant sizes. Alternately, modules can be added to existing fossil or combined cycle plants to reduce fuel consumption. This experience led to the completion of a preliminary design of a 100 MW e baseload molten salt reference plant for the U.S. Department of Energy in 2012. The plant configuration is also based on esolar s modular architecture consisting of 14 towers with 13 hours of thermal storage to achieve a 75% capacity factor. Other plant sizes and capacity factors are possible by adjusting the number of standard thermal modules and storage size. In 2013, B&W PGG began collaborating with the National Renewable Energy Laboratory (NREL) under the U.S. Department of Energy s SunShot Initiative to develop an advanced, nearblackbody enclosed particle receiver and power cycle. The receiver will operate at much higher temperatures and use an advanced power cycle with working fluids other than steam resulting in higher efficiency, smaller heliostat fields, lower plant cost, and lower LCOE than current technologies. 1

Introduction Solar energy offers the opportunity for clean renewable electrical power production from a free and effectively inexhaustible source. While the total available solar resource is huge (more energy reaches the earth in one hour than global human activities consume in a year), the challenge is to economically and reliably harness even part of this resource. The U.S. Department of Energy recognized this and launched a number of programs, including the SunShot Initiative, a national collaborative effort aimed at achieving a levelized cost of electricity (LCOE) target of $0.06/kWh (without subsidies) by 2020 to make concentrating solar power (CSP) cost competitive with fossil fuels. This paper highlights our progress towards cost-competitive solar power tower plants. Efforts to drive down LCOE have resulted in a focus on component cost reduction, the addition of thermal storage to increase plant capacity factor, and the development of an advanced technology that uses higher working fluid temperatures to drive higher efficiency power cycles. Nomenclature B&W B&W PGG CSP EOR esolar FB FBHX HTM HX LCOE NREL PFB-HX s-co 2 SCS SGS SH SPR SRS TES TSS Babcock & Wilcox Babcock & Wilcox Power Generation Group Concentrating Solar Power Enhanced Oil Recovery esolar, Inc. Fluidized Bed Fluidized-Bed Heat Exchanger Heat Transfer Medium Heat Exchanger Levelized cost of electricity National Renewable Energy Laboratory Pressurized Fluidized-Bed Heat Exchanger Supercritical Carbon Dioxide Solar Collector System (heliostat fields and field controls) Steam Generation System Superheater Solar Particle Receiver Solar Receiver System (molten salt receiver, tower, field piping, cold salt pumps) Thermal Energy Storage Thermal Storage System (hot and cold salt storage tanks and molten salt inventory) CSP Systems The two most common types of CSP technologies currently in use for electrical power generation are central receivers (also known as power towers) and parabolic troughs, the most mature CSP technology. Central receivers use a field of dual axis sun tracking mirrors to reflect and concentrate sunlight on a tower-mounted receiver using water-steam or molten nitrate salts as the heat transfer medium (fluid). Troughs are linear concentrators that use parabolic shaped mirrors to concentrate sunlight onto a single continuous receiver pipe (typically flowing oil). 2

The troughs are linked to form several long parallel rows which are oriented in a north-south direction and are equipped with single axis drives to track the sun s movement from east to west. To avoid decomposition of the oil, trough outlet temperature is normally limited to approximately 400 ºC. The power cycle efficiency of trough systems is therefore generally lower than central receiver systems which can be operated at significantly higher temperatures. Two other CSP technologies, linear Fresnel collectors which use a series of slightly curved mirrors (instead of parabolic mirrors) with a stationary receiver pipe, and parabolic dish engines which use a parabolic dish mirror to concentrate sunlight into a heat engine using hydrogen or helium to drive an integral electric generator, are also used. These systems are less common and plant sizes are generally smaller compared to central receiver and parabolic trough plants. For power generation, central receivers, parabolic troughs and linear Fresnel systems provide thermal energy to generate steam directly or indirectly (through additional heat exchangers) to drive a Rankine power cycle that uses conventional steam turbine and generator technology. CSP Central Receiver Direct-Steam Plant Figure 1 is a schematic diagram of a CSP central receiver direct-steam plant without thermal storage. In this arrangement, solar energy is concentrated by a field of heliostats (mirror assemblies) onto one or more tower-mounted solar receivers which absorb the energy and convert feedwater into superheated steam. The superheated steam, at high temperature and pressure, is piped directly to a steam turbine-generator to produce electrical power. Figure 1 - Schematic diagram of CSP direct-steam plant without thermal storage In 2009, esolar began operation of the Sierra SunTower plant in Lancaster, California. As shown in Figure 2, this is a direct-steam plant with two power towers capable of supplying up to 5 MW of clean, renewable energy to the grid. This full-scale power plant, the first commercial CSP tower facility in the United States, is based on esolar s modular-scalable plant architecture consisting of standard thermal modules (heliostat field and receiver/tower) to create customized plant sizes. The basic thermal module can be replicated, without scaling or redesign, to match a broad range of customer requirements. 3

A large cost component of tower-based CSP plants is the solar collector system (SCS), also known as the heliostats. The function of the SCS is to collect and transfer solar energy to the solar receiver system (SRS). The esolar design changes the cost structure dramatically via thousands of independently controlled heliostats organized into modular collector fields. The use of small, close-packed heliostats reduces wind loads, simplifies design and installation, and takes advantage of mass production. In addition, the modular design allows for flexible site layouts for the plant. esolar s proprietary software system automatically calibrates and controls the heliostats. Figure 2 - esolar 5 MWe Sierra SunTower direct-steam plant The plant incorporates a B&W PGG SunSpire TM direct-steam solar receiver as shown in Figure 3. This receiver is a 10 MWt natural circulation boiler designed to produce a steam flow of 4.4 kg/s at 6.2 MPa and 441ºC. The receiver is an external type whereby the heat absorbing surface is on the exterior faces of the receiver and the interior faces are insulated. The receiver is a shop-assembled design weighing less than 45,260 kg empty, is truck shippable, and is designed to be lifted by a crane to the top of a 60 m tall steel monopole tower similar in design to those used with wind turbines. The patent pending design features a vertical steam separator (in lieu of a horizontal steam drum) for faster startups. By adjusting panel width and/or height, the directsteam receiver can be scaled to higher capacities with steam flows approaching 6.3 kg/s, 4

depending on specific steam temperature and pressure requirements, while maintaining a shop-assembled, truck shippable design. The solar-to-electric efficiency of a standalone direct-steam solar plant with conventional turbine steam conditions is approximately 17%. Approximately half of the solar irradiance falling on the heliostat field does not reach the receiver due to heliostat field losses (cosine loss, blocking and shading, atmospheric attenuation, spillage, and reflector cleanliness). Solar receiver efficiency is approximately 86% due to tube paint reflectivity and thermal losses. The subcritical Rankine power cycle efficiency is approximately 40%. The capacity factor for a standalone direct-steam solar plant without thermal storage generally does not exceed 32%, even in an area with high solar resource. Although thermal storage can reduce the LCOE by increasing the plant s capacity factor, a disadvantage with direct-steam technology is that it is not practical or economical to directly store large volumes of high pressure steam from the receiver. Small volumes of steam can be stored in accumulators at lower pressures, but storage capacity is typically limited to a few Figure 3 - B&W PGG SunSpire TM direct-steam receiver hours. Two-tank indirect systems can be used but with reduced efficiency due to the additional heat exchange. Initially, LCOE for a 100 MWe direct-steam plant without thermal storage was estimated at $0.20/kWh with the first generation heliostats. To reduce LCOE, cost reduction efforts primarily focused on the high cost components, including the heliostats. The 2014 launch of the esolar SCS5 generation collector system (see Figure 4) is based on the significant experience gained at the Sierra plant. This two-year development effort examined hundreds of technical and cost trades-offs, both in terms of initial installed cost as well as operational costs. The result was a per-reflector area cost reduction of nearly 40% from the prior generation. Key areas of this design effort included the simplification of ground structures that do not require heavy lift equipment or fixed foundations. Wind engineering was central to the design effort, as were dramatic parts count reduction in the 2-axis drive. A 2.2 m² reflector was chosen to optimize hand assembly, optical performance and the ability to assemble the reflector module offsite. This design choice allows relocatable production equipment to be used along with returnable product shipping containers for best plant installation cost. In addition to component costs, civil and land preparation was optimized. The solar field assembly is done primarily with hands tools, 5

and no longer needs complicated site survey mapping. The high volume components take advantage of installed industry commodity capacity in areas such as die casting, injection molding and fasteners. Operational cost emphasis was key in the decision process. One example is the launch of an artificial light calibration system which performs rapid initial and refresh heliostat calibration at night so power production is not hampered. Another example is the development of a semiautonomous reflector cleaning system that dramatically reduces water consumption and labor for nighttime cleaning. These activities generated step-function LCOE reductions in direct steam and similarly in molten salt commercial plants, and additional reductions are already identified for future iterations. Since the SCS modular design is applicable to both direct steam and molten salt technologies, project volumes will further drive cost improvement. Due to the flexible design and small individually controlled reflector facet, this SCS can be also be used for advanced receiver schemes like falling particle, S-CO2 and air receivers, which takes advantage of industry cost reductions. Figure 4 - esolar SCS5 "Next Generation" heliostats Although the direct-steam system is effective for generating power when the sun is shining, the lack of storage renders direct-steam stand-alone power plants less competitive than systems with the storage component. Realizing these challenging economics, several alternative approaches have been pursued. These alternative approaches benefit from the aforementioned 6

SCS cost savings initiatives. Power generation examples include direct-steam augmentation in integrated solar combined cycle (ISCC) turbines, and integrating solar into biomass- or coal-fired generation facilities. Several commercial applications in enhanced oil recovery (EOR) and desalination of seawater are economically feasible today to reduce the consumption of fossil fuels needed to provide the thermal energy required by these processes. For direct-steam power generation on a stand-alone basis, the addition of thermal storage provides the greatest economic value potential. CSP Central Receiver Molten Salt Plant with Thermal Storage Following the successful commissioning of Sierra SunTower direct steam plant in 2009, B&W PGG collaborated with esolar, and in 2012 completed a preliminary design of a 100 MWe baseload molten salt solar reference plant with thermal storage. The majority of the project funding was provided by the U. S. Department of Energy whose goal was to drive down the LCOE to $0.08/kWh by 2020. Figure 5 is a schematic diagram of a molten salt-based solar power plant with a two tank direct thermal storage system. In this system, cold molten nitrate salt (consisting of 60% NaNO3 and 40% KNO3 by wt.) at 288ºC is pumped from the cold storage tank to the towermounted solar receiver(s) that absorbs concentrated solar energy from the heliostat field and heats the molten salt to 565ºC. Hot molten salt flows by gravity to the hot storage tank where it is pumped to the steam generation system to produce superheated and reheated steam to drive a turbine-generator and produce electrical power. Salt leaves the SGS at 288ºC and returns to the cold tank to be reused. During the day, more energy is collected than needed to drive the turbine. The excess thermal energy is stored in the hot tank in the form of hot molten salt. Thermal storage, therefore, separates solar energy collection from electrical power production and allows the plant to produce power at night and during cloudy days. This allows the plant to provide steady, dispatchable power with less disruption to the grid compared to technologies without storage. Although the molten nitrate salt mixture has low vapor pressure and high density, making it an excellent heat transfer and thermal storage fluid, the maximum operating temperature at the inside diameter of the receiver absorber tube is limited to 600ºC due to corrosion concerns. This limits the bulk salt temperature leaving the receiver(s) to 565ºC which in turn limits steam temperatures to about 540ºC, thus limiting power cycle efficiency. Molten nitrate salts also freeze solid at about 200ºC, requiring extensive heat tracing throughout the system. 7

Figure 5 - Schematic diagram of a molten salt-based power plant with a two tank direct thermal storage system The molten salt system is based on a 50 MWt (absorbed power) module comprised of a tower-mounted molten salt receiver surrounded by a heliostat field utilizing esolar s small heliostat technology. Similar to the direct steam concept, the basic thermal module can be replicated, without scaling or redesign, as many times as required (typically 2 to 14) to create plant sizes from 50 to 200 MW with capacity factors ranging from 20 to 75%. For example, Figure 6b illustrates 10 modules in a base 100 MW commercial configuration with 50% capacity factor. Examples of alternative configurations include 5 modules powering a 50 MW plant with 50% capacity factor, and 14 modules powering a baseload 100 MW plant with a 75% capacity factor. Figure 6 - Molten salt plant modular arrangement 8

The system uses the B&W PGG SunSpire TM molten salt solar receiver as shown in Figure 7. The receiver is a 50 MWt external, saltin-tube design consisting of vertical tube panels arranged for serpentine salt flow in a box configuration. It is a shop-assembled, truck shippable design ensuring a highquality finished product with minimal field assembly. It is also designed to be lifted by a crane and mounted on top of a 100 m tall steel monopole tower similar in design to those used with wind turbines. The hexagonal heliostat field surrounding the receiver and tower is comprised of about 47,000 of esolar s newest 2.2 m² SCS5 heliostats, calibrated and controlled by esolar s proprietary software system. Unique to the modular plant design is the requirement for a field piping system to deliver 288ºC cold molten nitrate salt from the centrally located storage system to the receivers, and return 565ºC hot salt to the storage system. As shown in Figure 8, the thermal storage system, comprised of large cold and hot salt storage tanks, is located in the power block, along with the molten salt steam generation system (SGS) and a conventional superheat/reheat steam turbine/generator system. The SGS includes a preheater, natural circulation evaporator, superheater and reheater heat exchangers, all designed with the intent to accommodate rapid daily startup and dynamic stability in all operating conditions. Figure 7 - B&W PGG SunSpire TM molten salt solar receiver 9

Figure 8 Power block layout includes turbine/generator building (left), SGS heat exchangers (center) and thermal storage tanks (right) The U.S. Department of Energy Office of Energy Efficiency and Renewable Energy has reported that LCOE for the CSP industry in 2013 had fallen to approximately $0.13/kWh. This is consistent with current day estimates for this technology without subsidies or credits. The esolar/b&w PGG molten salt LCOE may be capable of reaching $0.11/kWh due to the SCS and other cost reduction efforts before the SunShot target of 2020. This aggressive cost reduction trend shows continued promise as many hardware, control and installation ideas are already identified for subsequent product releases. In addition to these efforts, investment tax credits and other incentives aimed at promoting renewable energy may help to drive down the LCOE for CSP molten salt systems to as low as $0.08 /kwh. Fluidized-Bed CSP Thermal System Using Solid Particles as Heat Transfer and Storage Medium Increasing the overall system efficiency of the plant will also reduce LCOE. Realizing this, a more efficient receiver that uses substantially higher temperature heat transfer fluid, beyond molten salt technology, is needed along with thermal storage and higher power cycle efficiency. B&W PGG is collaborating with the National Renewable Energy Laboratory (NREL) under the U.S. Department of Energy SunShot Initiative to develop a high-performance, low-cost, solid-particle-based CSP system with economic thermal energy storage (TES) for continuous, dispatchable, grid-scale electric generation. The system uses solid particles as the heat transfer medium (HTM), based on gas/solid, two-phase fluidization engineering principles and experience. The solid particles also act as the TES medium. Figure 9 and Figure 10 are schematic diagrams depicting CSP systems which incorporate an advanced receiver and a FB heat exchanger. As seen in the figures, the HTM is first conveyed from the cold storage silo to the solid particle receiver (SPR). This near-blackbody enclosed SPR is where the concentrated solar energy from the heliostat field is transferred to the particles. The hot particles from the SPR are collected in the TES hot silo. The particles from the hot silo are then dispatched at the desired rate to the fluidized-bed heat exchanger (FBHX) which allows the transfer of thermal energy to the power cycle working fluid. The higher temperatures of the 10

HTM provide the ability to yield the higher working fluid temperatures in the FBHX to help drive advanced, more efficient power cycles. The cooler particles leaving the FBHX are conveyed back to the cold storage silo for reuse. System efficiency gains that would result from the use of advanced power cycles, coupled with cost reduction efforts on components (including the heliostat field), are all aimed at significantly reducing the LCOE of CSP tower plants. Figure 9 - Schematic of a fluidized-bed CSP system with a near-blackbody enclosed particle receiver, integrated fluidized-bed heat exchanger and solid-particle thermal energy storage. Hopper Bucket Elevator Receiver Superheater Reheater Cold Silo Hot Silo Preheater Evaporator HP IP/LP ACC FWH1 FWH2 DA FWH3 Feed Pump FWH4 FWH5 Condensate Pump Figure 10 - The SPR system: receiver, hot/cold particle storage silos, bucket elevator, B&W PGG FBHX and power cycle (steam Rankine cycle shown). The heart of the system is the solid particle receiver (SPR). The SPR is designed to heat the HTM (solid particles) to 800 C or higher to support high efficiency power cycles. The particles are stable and non-corrosive at these high temperatures, are readily available and cost less than 11

molten nitrate salt. In addition, the particles will not freeze like molten salt, thereby eliminating the cost of heat tracing and the associated cost of maintenance and parasitic power. All of these factors reduce plant cost and LCOE. Another key aspect of the SPR design is that it is arranged to achieve a significantly higher thermal efficiency compared to a molten salt receiver, thereby reducing the size and cost of the heliostat field. The SPR is designed as a near-blackbody absorber which significantly reduces thermal losses despite much higher receiver operating temperatures than molten salt. To evaluate the cost of various power cycles and determine the overall impact on plant cost and LCOE, preliminary FBHX designs for several power cycles and working fluids have been completed, including subcritical and supercritical steam cycles, as well as advanced cycles including supercritical CO2 (s-co2) and air Brayton combined cycles. Figure 11 shows the preliminary designs of two of the FB heat exchangers for subcritical and supercritical steam power cycle applications, including the arrangement of the various heat transfer surfaces. Initial cost evaluation efforts for the various FBHX designs have also considered the impact on operating costs, plant layout and arrangement costs. Generating Bank Steam Drum Generating Bank Division Wall Reheater Superheater Preheater Generating Bank Reheater Preheater / and Sidewalls Economizer Superheater Figure 11 (a) FBHX design: subcritical steam Rankine cycle; (b) FBHX design: supercritical steam Rankine cycle. The FBHX technology is based on B&W PGG s expertise in gas-solid two-phase flow and heat transfer and experience in fluidized-bed boiler design and was developed with the following characteristics in mind: Suitable for particle sizes desired by the receiver High heat transfer with low sensible heat loss Lower parasitic power consumption than alternative designs Potential for lowest cost design In addition to the core systems which include the SPR, TES, FBHX and the power generation system, the CSP plant requires a number of components associated with solids handling, storage and control as shown in Figure 12. A bucket elevator or alternate solids conveying systems can be used to move the HTM back to the SPR. 12

Particle Receiver and Distribution System Vertical Bucket Elevators Cold Particle Silo Hot Particle Silo Particle Make - up Silo L - valves Fluidized - bed Heat Exchanger Horizontal Conveyor Figure 12 - General arrangement of receiver, tower and FBHX The use of fluidized particles as the HTM in CSP plants offers several benefits relative to conventional liquid heat transfer fluids. Fluidized particles are thermally stable at temperatures well above 1,000 C while also eliminating the risk of fluid freezing. In addition, the cost of particles that are used for heat transfer and thermal energy storage offer a significant cost benefit relative to state-of-the-art fluids. The challenge and current focus of this technology development is to design and fabricate a particle receiver that will operate at these high temperatures and be able to meet the desirable performance and reliability requirements. Although pricing efforts for this technology are based on preliminary information, initial LCOE for the SPR system is very encouraging. Taking advantage of the anticipated further heliostat cost savings, preliminary LCOE forecasts for the Brayton cycle and supercritical steam cycle are as low as $0.08/kWh when this technology matures. Tax credits and other incentives could help drive LCOE down further. 13

Summary Solar power tower plants must be cost competitive with other forms of electrical power generation. After completing our first direct-steam plant, our mission has been to reduce cost by focusing on component optimization and exploring innovative technology. From an initial LCOE for a direct steam plant approaching $0.20/kWh, progress has been made towards further development of cost-competitive solar power tower plants. Acknowledgements We acknowledge the U.S. Department of Energy for providing support, guidance and funding to the research and development projects. NOTICE This report was prepared as an account of work sponsored by an agency of United States government. Neither the United States government nor any agency thereof, nor any of their employees, nor any of the participating contractors, including Babcock & Wilcox Power Generation Group, Inc., nor any person acting on their behalf, makes any warranty, expressed 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 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 implied its endorsement, recommendation, or favoring 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. References Ma, Z., Glatzmaier, G., and Mehos, M., Fluidized Bed Technology for Concentrating Solar Power with Thermal Energy Storage, doi: 10.1115/1.4027262, ASME Journal of Solar Energy Engineering, Vol 136, August 2014. Ricklin, P., Slack, M., Rogers, D., and Huibregtse, R., Commercial Readiness of esolar Next Generation Heliostat, Elsevier Ltd., SolarPACES Proceedings, 2013. Ricklin, P., Smith, C., and Rogers, D., Current Status and Future Plans for esolar's Small Heliostat Based Solar Collection System, SolarPACES Proceedings, Granada, 2011. Ma, Z., Glatzmaier, G., and Mehos, M., Development of solid particle thermal energy storage for concentrating solar power plants that use fluidized-bed technology, SolarPACES 2013, Las Vegas, Nevada, 2013. Ho, C., Technology Advancements for Next Generation Falling Particle Receivers, SolarPACES 2013, Las Vegas, Nevada, 2013. 14

Neises, T., A comparison of supercritical carbon dioxide power cycle configurations with an emphasis on CSP applications, SolarPACES 2013, Las Vegas, Nevada, 2013. Tyner, C, and Wasyluk, D., esolar s modular, scalable molten salt power tower reference plant design, SolarPACES 2013, Las Vegas, Nevada, 2013. U.S. Department of Energy Office of Energy Efficiency and Renewable Energy, SunShot Concentrating Solar Power Newsletter, 6 February 2014. Copyright 2014 by Babcock & Wilcox Power Generation Group, Inc. All rights reserved. No part of this work may be published, translated or reproduced in any form or by any means, or incorporated into any information retrieval system, without the written permission of the copyright holder. Permission requests should be addressed to: Marketing Communications, Babcock & Wilcox Power Generation Group, P.O. Box 351, Barberton, Ohio, U.S.A. 44203-0351, or, contact us from our website at www.babcock.com. Disclaimer Although the information presented in this work is believed to be reliable, this work is published with the understanding that Babcock & Wilcox Power Generation Group, Inc. (B&W PGG) and the authors and contributors to this work are supplying general information and are not attempting to render or provide engineering or professional services. Neither B&W PGG nor any of its employees make any warranty, guarantee or representation, whether expressed or implied, with respect to the accuracy, completeness or usefulness of any information, product, process, method or apparatus discussed in this work, including warranties of merchantability and fitness for a particular or intended purpose. Neither B&W PGG nor any of its officers, directors or employees shall be liable for any losses or damages with respect to or resulting from the use of, or the inability to use, any information, product, process, method or apparatus discussed in this work. 15