Progress Towards Cost-Competitive Solar Power Tower Plants K

Power-Gen Middle East 2014
Progress Towards Cost-Competitive Solar
Power Tower Plants
K. Santelmanna*, D. Wasyluka, B. Sakadjiana,
R. Huibregtseb, Z. Mac
a
Babcock & Wilcox Power Generation Group, Inc., 20 S. Van Buren Avenue, Barberton, OH 44203 USA
b
eSolar, 3355 W. Empire Avenue, Suite 200, Burbank, CA 91504 USA
c
National Renewable Energy Laboratory, 15013 Denver West Parkway, Golden, CO 80401 USA
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 MWt 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 MWe 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
1
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.
2
Nomenclature
B&W
B&W PGG
CSP
EOR
eSolar
FB
FBHX
HTM
HX
LCOE
NREL
PFB-HX
s-CO2
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)
2. 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).
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
3
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.
3. 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.
4
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 SunSpireTM 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
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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,
depending on specific steam temperature and pressure requirements, while maintaining a shopassembled, 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
Figure 3 - B&W PGG SunSpireTM direct-steam receiver
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
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few 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,
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
7
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
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.
8
For direct-steam power generation on a stand-alone basis, the addition of thermal storage
provides the greatest economic value potential.
4. 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.
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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
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The system uses the B&W
PGG SunSpireTM 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.
Figure 7 - B&W PGG SunSpireTM molten salt solar receiver
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Figure 8 – Power block layout includes turbine/generator building (left), SGS heat exchangers (center)
and thermal storage tanks (right)
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.
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.
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5. 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 - 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.
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.
13
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
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.
Cold Silo
Hot Silo
Reheater
HP
Evaporator
Receiver
Preheater
Bucket
Elevator
Superheater
Hopper
IP/LP
ACC
DA
FWH3
Feed Pump
FWH1
FWH2
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
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
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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.
Steam Drum
Generating Bank
Generating Bank
Division
Wall
Generating Bank
and Sidewalls
Reheater
Preheater
Reheater
Preheater /
Economizer
Superheater
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
15
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.
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
16
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.
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 and 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.
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Concentrating Solar Power Newsletter, 6 February 2014.
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Babcock & Wilcox Power Generation Group, P.O. Box 351, Barberton, Ohio, U.S.A. 442030351, or, contact us from our website at www.babcock.com.
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