Development of a Pilot Scale Coal Powered Oxy

Power-Gen Europe Conference, June 9-11 2015
Development of a Pilot Scale Coal Powered
Oxy-fired Pressurized Fluidized Bed
Combustor with CO2 Capture
William W. Follett IV – Aerojet Rocketdyne, USA
Mark A. Fitzsimmons – Aerojet Rocketdyne, USA
Sarma V. Pisupati – Pennsylvania State University, USA
Chandrashekhar G. Sonwane – Aerojet Rocketdyne, USA
Stevan Jovanovic – Linde LLC, USA
Tyler W. Manley – Aerojet Rocketdyne, USA
Daisuke Hiraoka – Aerojet Rocketdyne, USA
Stephen A. Yows – Aerojet Rocketdyne, USA
Abstract
A pilot scale Oxy-fired Pressurized Fluidized Bed Combustor (Oxy-PFBC) is under development
as a method to enable the use of coal for electricity generation while capturing the CO2 and other
emissions at a cost that is significantly less than the current state of the art post-combustion
capture technologies. This paper discusses the features of the Oxy-PFBC, component test results,
techno-economic analysis results, and development and commercialization plans. Technoeconomic analysis indicates the Oxy-PFBC system exceeds the United States Department of
Energy goals of less than 35% increase in the cost of electricity while capturing at least 90% of
the CO2 emissions. Predictions show 90-98% capture with an 18-31% increase in cost of
electricity. The largest increase here (31%) is based on 98% capture with use of existing
technology wherever possible, while insertion of other advanced technologies, such as air
separation units (ASUs) expected to be available in the next 3-5 years, and supercritical CO2
Brayton cycles available in the longer term can reduce the cost of electricity to only an 18%
increase. These results assume no economic benefit of the captured CO2. The system could
achieve no net increase in electricity cost through the sale of CO2 at $18/ton to offset the 18%
cost increase. Key risk mitigation testing conducted prior to pilot scale testing includes kinetics
testing for coal and limestone particles, and cold flow combustor testing. These tests validate key
assumptions regarding particle residence times and expected pilot scale efficiencies for the
elutriated bed combustor. The current development plans include completion of pilot scale
testing by early to mid-2017, with demo plant operation by 2020.
Introduction
Aerojet Rocketdyne (AR) is developing an oxygen-fired pressurized fluidized bed combustor
(Oxy-PFBC) 1 MWth pilot scale plant to demonstrate technologies required to produce
affordable electricity with carbon capture.1,2
1
AR and the United States
Department of Energy
(DOE) are interested in this
technology because it
provides an opportunity to
reduce CO2 emissions in the
United States and elsewhere.
Coal power plants generated
33% of total energy related
CO2 emissions, and 82% of
the electric power related
CO2 emissions in the US in
2005.3 Coal is expected to
continue to produce
significant amounts of power
for the foreseeable future,
with the US EIA projecting
Figure 1. The need for clean coal power is highlighted by the US
that coal will continue to
EIA projections that coal will continue to provide roughly one
produce 32% of the U.S.’s
third of electrical power in the United States for the next
electricity in 2040 compared
several decades.
to 36% today,3 with slight
growth in generation
capacity from 1.5 trillion kWh in 2012 to 1.7 trillion kWh in 2040 as shown in Figure 1. In order
to meet the aggressive greenhouse gas reduction goals identified by the IPCC4 and others5
necessary to mitigate climate change, no single technology, including renewable energy
technologies, is sufficient. Coal combustion with carbon capture technology and sequestration
(CCS) can play an important role in contributing to the atmospheric CO2 reduction goals.
The DOE has identified goals for advanced coal combustion technologies that can provide
affordable electricity by capturing >90% of the CO2 with <35% increase in LCOE. AR is
developing an oxy-combustion approach that is predicted to exceed these goals. This is a
significant improvement over the current post-combustion capture amine systems that increase
LCOE by 75-85%.
The AR Oxy-PFBC concept leverages previously developed technology in the areas of air-fired
pressurized fluidized bed combustors (PFBC), and oxy-fired atmospheric pressure combustors.
Air-fired PFBCs have been operating at commercial scale since the plant in Vartan, Sweden
started in 1989 producing 135 MWe and 225 MWth for district heating. The 1990’s saw
additional commercial scale PFBC’s become operational in Spain (Escatron), Japan (Wakamatsu
and Karita), Germany (Cottbus) and the United States (Tidd). The AR Oxy-PFBC design was
informed by visits to the PFBC plants in Cottbus and Vartan, published reports from others, as
well as direct experience during the Atmospheric Fluidized Bed (AFB)6 program in the 1980s,
where an AR heat exchanger and coal-fired fluidized bed combustor were developed and tested
to demonstrate life.
2
Oxy-fired combustors
are a relatively recent
development with 2030 MWth pilot scale
plants becoming
operational between
2008 and 2012 in
Germany (Schwarze
Pumpe), Australia
(Callide) and Spain
(Ciuden). The
developments in air
separation units (ASU)
and CO2 purification
units (CPUs) for these
projects can be utilized
directly by the OxyPFBC system.
The AR Oxy-PFBC
Figure 2. Oxy-PFBC technology is a logical evolution of proven
concept is a logical
systems that provides the economic benefits of pressurized combustion
evolution of proven
with the CO2 emissions benefits of Oxy-combustion
commercial PFBC and
oxy-combustion
systems. It builds on the previous history to combine the oxy-combustion and PFBC concepts to
get the benefits of both, with reduced size and cost associated with pressurized operation, and
reduced gas cleanup cost enabled by oxy-combustion, to provide affordable electricity generation
with carbon capture. This evolution is illustrated in Figure 2, which plots the size vs.
commissioning dates for past and future PFBC, Oxy-combustion and Oxy-PFBC plants.
Objectives
The vision for this effort is to develop a commercial scale Oxy-PFBC system for electricity
and/or once through steam generation with a supercritical CO2 Brayton cycle for up to 98% CO2
capture and no net increase in the cost of electricity assuming the sale of CO2 offsets the modest
15-20% increase in electricity generation costs (see Figure 3). The system is also envisioned to
include an option for steam Rankine cycle capability to enable boiler retrofits into existing plants
with steam turbines.
The Oxy-PFBC Rankine cycle system is currently under development as described within this
paper, while the supercritical CO2 (SCO2) system is being developed in parallel under separate
funding.7,8
The objective of the current Phase II program is to demonstrate the technology at pilot scale (1
MWth) and reduce risks sufficiently to enable scale up to a demonstration scale (10 – 50 MWth)
steam Rankine system starting in 2017.
3
Figure 3. The vision for the Oxy-PFBC system, called ZEPS (Zero Emissions Power and
Steam), was originally conceived with both a PFBC and supercritical CO2 Brayton cycle
for best performance.
The objectives of the Phase I effort, completed in 2013, were to perform design, bench scale
testing and technoeconomic analysis of an Oxy-PFBC system that can meet or exceed the U.S.
DOE goals of >90% capture with <35% increase in COE compared to supercritical steam,
pulverized coal (SCPC) plant without CO2 capture as defined in DOE Case 11.9
The current team includes Aerojet Rocketdyne, Linde, Canmet, Pennsylvania State University,
EPRI, and Alstom. Funding is provided by the US Department of Energy, Alberta Innovates, and
each of the team members.
Approach
This section provides an overview of the Oxy-PFBC system, the analysis and test approaches
taken in Phase I, and the planned approach for Phase II. The Phase I results are provided in the
“Results” section.
System Overview
The Oxy-PFBC system (see Figure 4) utilizes a high aspect ratio bubbling fluidized bed. Within
the bed there are two classes of particles: larger inert particles that make up the fluidized bed,
and smaller pulverized coal and limestone particles that are elutriated, or carried up, through the
bed by the gas flow that fluidizes the bed particles. The fluidizing gas is composed of oxygen
mixed with recycled CO2. The air separation unit (ASU), which supplies oxygen from air, is
thermally integrated so that waste heat is utilized to improve plant efficiency. In-bed and
convective heat exchangers remove heat from the PFBC and are used to drive a supercritical
steam power generation cycle (or an optional supercritical CO2 Brayton cycle.) Sulfur capture is
largely achieved (up to 98% capture) by the limestone elutriated through the bed. As a result, the
flue gas desulfurization unit can be eliminated, thus reducing cost. The remaining gas cleanup
4
Figure 4. The current program is developing a steam Rankine cycle for
nearer term retrofit applications.
system utilizes candle filters for ash removal, condensing heat exchangers for water separation,
and Linde LICONOX® and DEOXO systems for NOx/SOx polishing and oxygen removal.
Technoeconomics Analysis Approach
The technoeconomic analysis approach included performance calculations using Aspen, and cost
evaluations using vendor quotes, cost scaling, and use of DOE/NETL’s Power Systems Financial
Model (PSFM) tool according to the NETL Quality Guidelines for Energy System Studies
(QGESS) document.10 The NETL guidelines for computing the cost of electricity include
impacts from both operational and capital costs.
The capital cost for the AR PFBC unit was derived from a combination of three methodologies.
“Similar-to” analysis using equipment contained in previous DOE/NETL reports is the preferred
approach for equipment that is the same or similar to what the Oxy-PFBC system includes. For
equipment that must be specifically tailored to AR needs, estimates from suppliers were
obtained. If estimates were unavailable, then the ASPEN Capital Cost Estimation program
was used.
The goal of the TEA is to be as consistent as possible with the standard DOE cases9,11, to enable
a quality comparison. The Oxy-PFBC capital cost model was based on Case 5A (Oxycombustion
Supercritical PC with CO2 capture) from the Oxygen-Fired Pulverized Coal Rankine Cycle
Plants using Cryogenic Air Separation Units section of the report.11 This case was chosen
because the capital equipment in this case has the most similarity to the Oxy-PFBC system. The
costs were scaled from 2007 dollars used in Case 5A to 2011 dollars.
5
Operations and Maintenance (O&M) costs consists of labor and non-labor costs. The same level
of O&M staffing as seen in Cases 11 and 5A was assumed for the AR cases. The taxes and
insurance costs were scaled based on total plant cost.
Cold Flow Testing Approach
The objectives of cold flow testing approach are to determine coal and limestone particle
residence time, heat transfer to the heat exchanger tubes, and demonstrate stable bed operation.
Residence time, heat transfer and bed stability are all configuration dependent, so it is important
to test with realistic geometries to determine which correlations best predict the actual
combustor behavior.
The cold flow experimental rig was built at full pilot scale with multiple tube packing fractions
representative of the range that is anticipated at commercial scale. The cold flow rig included
polyvinyl chloride (PVC) tubes to simulate the heat exchanger tubes, although the PVC tubes
were hollow with no flow through tubes. Testing was conducted at atmospheric pressure.
Heat transfer was measured by replacing two of the empty PVC tubes in the simulated heat
exchanger tube bundle with metal tubes which include embedded heaters and thermocouples.
The heaters in the tubes had 0-3000 watt heating capacity and were cast into the tubes using
silicon carbide (SiC). Thermocouples were placed at multiple circumferential and axial locations
on the exterior of the tube. Thermal analysis was then used to derive heat transfer coefficient
from the tube temperatures and heating rate data.
The objective of the stability testing is to achieve stable bed operation by quantifying the
dynamic loads on the hardware and determining the major contributing design and operational
factors necessary to improve stability. Stability was quantified by using pressure transducers
strategically placed below the bed, isolated within the wind box, to record pressure versus time.
The variation in pressure data was calculated by computing the standard deviation of the pressure
values over a given time span, typically 30 seconds.
Coal Kinetics Testing Approach
The primary objective of the coal testing approach is to determine the burning rate of pulverized
coal particles in the oxy-combustion environment as a function of temperature, pressure and
oxygen level. It is important to characterize the burning rate at high pressure to validate that
there is sufficient combustion residence time and heat removal capability within the bed. Testing
by Penn State University (PSU) during Phase I was conducted by generating a burning profile by
combusting a solid fuel sample and measuring the change in weight as a function of temperature,
when heated at a constant rate in a thermogravimetric analyzer (TGA). Detailed discussion of
this testing conducted by Pennsylvania State University (PSU) is included in Fitzsimmons,
Mohan, et. al.12
Phase II Approach
The Phase II program started in July, 2014 and will conduct component and pilot scale (1 MWth)
testing to demonstrate performance and reduce risk sufficiently to progress to a demo scale plant
in 2017 (see the schedule in Figure 5). The pilot and demo plants are part of the
6
commercialization plan shown in Figure 6 that will lead to construction of a commercial scale
plant in 2020.
7/1/2014
Tasks
Key program milestones
7/1/2015
7/1/2016
Year 1
Year 2
Kickoff Briefing
Demo Plant
Pre-FEED
Component Design
Tests
Component
Test Plans
AI funding decision
Pilot
Pilot Fab
Design
Year 3
Pilot
Test
Plan
WBS 10000 Program Management
Quarterly Reporting, Annual presentations
Cold Flow Test
Component Tests
WBS 20000 Component testing
Pilot
Design
Demo Plant Permit
Risk Assessment
Final
Report
Pilot
Testing
Pilot
Operation
Report
Final Report
Complete
Demo Plant
Pre-FEED Design
WBS 30000 Design
Physics model MFIX
upgrades Modeling
Material & TRL
Evaluation
WBS 40000 Analysis
WBS 50000 Pilot Test
Pilot Fab
Pilot Testing
Demo and
Commercial Plant
Economics
WBS 60000 Commercialization Plan
TRL 6
Demonstrated
Commercial Plant
Market Dev't
Permit Risk
Assessment
Complete
Figure 5. Phase II Program Schedule
Component testing includes coal reaction testing and limestone sulfation testing at PSU. The data
from these tests will address risks associated with coal burning too quickly or too slowly, while
the limestone testing addresses sulfur capture performance. Cold flow testing was conducted at
pilot scale and atmospheric pressure, with heat exchanger pipe spacing at commercial scale. Cold
flow testing, conducted in 2014, provides additional data on bed stability, particle elutriation
rates, and heat transfer.
The pilot scale testing will be conducted at Canmet in 2016 and will include pressurized
operation with oxy-firing and a gas cleanup skid supplied by Linde. This testing will demonstrate
operational stability, performance, CO2 capture, and gas cleanup capability.
7
Figure 6. Commercialization Plan leads to commercial scale demonstration by 2025.
Results
Results from Phase I of the program are presented in this section, including technoeconomic
analysis, coal kinetics testing, and cold flow test results.
Technoeconomic Analysis Results
The team evaluated a number of different options and compared them to DOE Case 11
(supercritical pulverized coal (SCPC) without carbon capture) and documented them in a report
to the DOE.13
The AR PFBC baseline is predicted to achieve a COE increase of 31% over the DOE reference
cases with 98.3% CO2 capture (maximum CO2 capture). The COE increase is reduced to 29.9%
over the DOE reference if only 90% of the CO2 is captured. Further COE improvements to the
baseline are possible, as shown in Figure 7 by replacing: (1) the Air Separation Unit (ASU) with
a near-term, high efficiency ASU from Linde, and (2) the Rankine cycle steam electrical power
generation system with AR’s supercritical CO2 (SCO2) Brayton cycle. The AR SCO2 technology
is being developed under separate funding.
These results indicate that the Oxy-PFBC system can exceed the DOE goals of less than 35%
increase in cost of electricity while capturing at least 90% of the CO2. AR has also defined a path
to only an 18% increase in COE through advanced technology insertion using SCO2. If the
benefits of revenue or tax credits for captured CO2 are factored in, the AR baseline system with
90% CO2 capture is predicted to break even with the no-capture case at a CO2 price of $30/ton,
while the AR baseline with supercritical CO2 breaks even at a price of $18/ton. To put this in
perspective, the proposed carbon capture and sequestration tax credits proposed in the United
8
Percent Change in COE Relative to Case 11
AR PFBC System COE Relative to Case 11
35.0
31%
30.0
DOE Goal (<35% increase)
29.9%
27.5%
25.0
20.0
States president’s 2016
budget provides tax
credits of $10 or $50 per
metric ton of CO2
sequestered depending on
if the CO2 has beneficial
or non-beneficial re-use,
respectively.
18%
The predicted capital
expenditures (CAPEX)
were broken down by
10.0
component to better
understand how the AR
5.0
concepts compare to other
systems. The systems
0.0
AR Baseline
AR Baseline
AR Baseline
AR Baseline
presented in Figure 8
– 90% CO2
– 98% CO2
with near term with supercritical
below include AR
capture
capture
high efficiency CO2 Brayton cycle
Option 1 (AR Baseline
ASU
13PD-207-013
Configuration
with 90% capture from
Figure 7 above), AR
Figure 7. AR Oxy-PFBC has a path to further COE reduction using Option 2 (AR Baseline
near-term Linde ASU improvements and a supercritical CO2
with 98.3% capture from
Brayton cycle
Figure 7 above), NETL
Case 5A (Oxycombustion
Supercritical Pulverized Coal [SCPC] with CO2 capture), NETL Case 11 (SCPC without CO2
capture), NETL Case S12F (similar to Case 5A but with lower purity oxygen supply), NETL
Case 12 (Same as Case 11, but with Amine CO2 capture system).
15.0
The CAPEX comparison illustrates that the major capital cost savings for the AR system,
compared to cases 5A and 12, is due to the more compact boiler. Relative to case 12, additional
cost benefit is predicted due to lower CO2 removal and compression equipment costs as a result
of using oxy-combustion rather than post combustion capture.
A significant amount of design effort was spent attempting to reduce operational expense
(OPEX) costs by focusing on components that consume the most auxiliary power. The major
OPEX drivers, as seen in Figure 9, are the ASU, CPU and Recycle blowers or fans. A significant
amount of effort was spent attempting to understand how these costs might be reduced. The
recycle blower power is significantly higher than the atmospheric pressure cases, but is more
than offset by the decreased CPU power (comparing Case 5A) and the use of ASU waste heat to
dry reactants. As a result, auxiliary energy loads are reduced, making the AR system more
efficient than Case S12F. Specifically, integration between the condensing heat exchanger and
the boiler feedwater improves system performance by almost 2%. Additional efficiencies from
using partially dried coal further reduces coal and oxygen consumption in the PFBC cases.
9
Figure 8: Total Plant Cost Comparison in Millions of Dollars
Figure 9: Auxiliary Loads Comparing AR to Similar NETL Cases
10
Impact of the Supercritical CO2 Brayton Cycle
AR has investigated the use of SCO2 for power generation from a variety of heat sources,
including nuclear, solar, and fossil fuels. The use of CO2 as a working fluid in a coal fired plant
was originally investigated by AR in the 1970’s and was revisited in the 2000’s with more focus
on maintaining supercritical CO2 throughout the cycle to obtain the cost benefits of compact
turbomachinery.
The current Oxy-PFBC concept using SCO2 as the working fluid is shown in Figure 3, and
operates as described previously for the steam cycle, except that the SCO2 is used as the working
fluid in place of supercritical steam. The SCO2 circulates in a closed loop through the PFBC inbed and convective heat exchangers and the power island.
The SCO2 Brayton cycle provides efficiency benefits over the steam Rankine cycle for turbine
inlet temperatures that are greater than 540C (1000 F)7. Benefits of the Brayton cycle include
smaller and less expensive turbomachinery and lower compression costs due primarily to the
higher density of SCO2 relative to steam and its liquid like behavior at supercritical conditions.
Higher efficiency and lower capital cost for turbomachinery equipment translate to lower cost of
electricity. SCO2 cycles can also take advantage of higher turbine inlet temperatures for higher
efficiency. Steam Rankine cycles are typically limited to turbine inlet temperatures of
approximately 593C (1100F) with existing materials due to concerns with embrittlement and
corrosion, compared to 704C (1300F) for SCO2 applications. Comparing the steam Rankine
cycle at 593C turbine inlet temperature with the SCO2 Brayton cycle at 704C, the SCO2 Brayton
cycle has about five percentage points higher efficiency.14 The efficiency gain comes from the
higher inherent cycle efficiency of the Brayton cycle and the higher turbine inlet temperature.
Additional details are provided comparing total plant cost, operations and maintenance (O&M)
costs, cost of electricity (COE) and technology readiness levels (TRL) in Table 1. All costs are in
2011 dollars.
Table 1. Comparison of AR SCO2 Brayton Cycle Performance with DOE Steam Rankine Cycle
Cases
Air Fired Coal, SC
Steam (Case 11)
No
1,981
Air Fired Coal, SC
Steam (Case 12)
Yes. 90%
3,563
Oxy Coal, SC
Steam (Case 5A)
Yes, 90%
3,158
AR Baseline
with SCO2
90%
2,417
CO2 capture
Total Plant Cost $/kWe
O & M Cost
Fixed $/kW
70.6
116.6
95.0
81.1
Variable $/MWh
7.7
13.2
7.9
7.5
COE $/MWh
81.0
137.3
119.2
95.9
TRL Level*
9
7-8
4-5
3-4
*
US Department of Energy, DOE G 413.3-4A, 9-15-11, ”Technology Readiness Assessment Guide”
The SCO2 turbomachinery technology is currently under parallel development at AR and is
partially funded by the DOE. The technology is still in the early stages of development with a
commercial plant scale demonstration projected in the 2030 time frame. The primary technical
challenge is to develop turbomachinery with the long life and serviceability of commercial steam
turbines while achieving the compactness and high power density more typical of rocket engine
technology currently produced by AR.
11
Coal Kinetics
Testing Results
Coal kinetics
testing was
conducted across a
variety of oxygen
concentration
conditions and are
discussed in greater
detail in
Fitzsimmons,
Mohan, et. al.12
Illinois #6 coal was
tested at PSU by
heating the coal in a
reactor vessel. A
sample of the
results is shown in
Figure 10. In this
figure, the vertical
axis is the change in
weight per unit time
divided by the
initial weight of the
sample.
Figure 10. Burning Profile for Illinois No 6 coal Under Oxy Combustion
Conditions
All three profiles in Figure 10 below showed an initial negative weight change rate around
100 °C, due to loss of moisture. The first peak in the negative region of the graph for each test
run is the devolatilization peak and indicates early decomposition of carbon-oxygen complex and
devolatilization of the coal. The next peak is the char burning peak and is due to oxidation of
char. The height of the peak is proportional to the rate of char oxidation and hence, the heat
release rate. The devolatilization peak for atmospheric pressure 50% oxygen is as high as the
char burning peak. As oxygen concentration is reduced and pressure is increased the first peak
becomes more subdued, and at 7% oxygen, the devolatilization peak is nonexistent.
The data clearly show that with increased CO2 and reduced O2 concentrations, the peak
temperature shifts to higher temperatures and the peak height is reduced. This suggests a
decrease of reactivity and lower rate of char oxidation. It also is likely to produce lower particle
temperatures.
Concurrently, AR conducted particle velocity and bed hold-up tests to determine average particle
velocities and residence time. The combination of these efforts with the heat transfer coefficient
work previously mentioned has validated the most important basic principles of the technology
being discussed here.
Nevertheless, this data illustrates that if the reaction rates are an order of magnitude faster than
the particle residence time, coal particles may overheat and cause agglomeration, but this can be
12
mitigated by staging the oxygen injection. This strategy is substantiated in commercial fluidized
bed literature. It certainly indicates that very high carbon utility is likely as long as the particle
temperatures can be maintained below the ash fusion temperature.
Cold Flow Testing Results
The cold flow test results conducted at pilot scale include heat transfer data, stability data and
elutriation rate data. Accurate predictions of combustor performance depend on heat transfer data
to determine heat removal rates, while elutriation data combined with kinetics data are used to
determine heat release rates. This helps to establish design parameters that will insure good
operability of the pilot rig.
Arguably the most important
risk is the uncertainty
surrounding the heat transfer
coefficient (HTC) of an inbed heat exchanger, which
must be known so that the
heat removal can be balanced
with the heat release in a
PFBC. This is shown in
Figure 11. Gas molecules are
flowing upward, carrying
coal, ash and limestone, while
the coarser inert particles are
enhancing turbulent mixing
and heat transfer.
Figure 11. Accurate understanding of heat transfer is important
Simultaneously, reactions
to minimize ash agglomeration and maximize
taking place in the gaseous
combustor performance
phase are constantly changing
the chemical environment. If
the heat transfer coefficient is predictable, the reaction rates (which depend on temperature) are
more easily calculated, tube temperature is predictable, and the maximum particle temperature
can be estimated.
AR studied and measured heat transfer coefficients for in-bed heat exchangers, and developed
models and a design methodology anchored in real heat transfer measurements of full size cross
section tubes in a fluidized bed.
The test configuration includes two heated tubes, one which is in the lower portion of the rig, so
it is always submerged in the bed particles, and a second heater that is higher in the rig and does
not get covered by particles until after the fluidization velocity is high enough to achieve
sufficient bed expansion. The heat transfer test results are shown in Figure 12 for these two
heating elements. The lower heater test data corresponds fairly well with the Molerus and Yang
correlation, while the upper heater does not get submerged in the fluidized particles until the gas
velocity exceeds roughly 2.3 times the minimum fluidization velocity. After that point, the heat
transfer from the upper heater is shown to be higher than the lower heater, and is not as well
matched by the correlation.
13
Nondimensionalized
elutriation test data is
shown in Figure 13.
The data is combined
with extrapolations for
finer particles based
on public literature
measuring elutriation
rates. The line labeled,
“Extrapolated Hot
Flow Residence Time”
scales the cold flow
curve to the OxyPFBC expected
conditions. At high
pressure, the same
fluidization behavior
Figure 12. Heat transfer data shows good agreement with the Molerus will be exhibited at
and Yang correlation in the lower bed region.
lower velocities, so the
ideal injection flow
rate will be at a lower
velocity than an atmospheric bed
leading to reduced erosion of in-bed
heat exchanger tubes.
Heat Transfer
The stability testing was able to
successfully achieve stable bed
operation. By varying the geometric
and hydrodynamic characteristics of
the bed, the impact of identified key
parameters was obtained. Based on
knowledge obtained from tests,
modifications were implemented into
Figure 13. Elutriation testing demonstrates that particle the test setup. The improvement
achieved by the modifications is
residence time exceeds reaction time requirements.
shown in Figure 14 below.
From the comparison in Figure 14 it is evident that the modifications reduced the pressure
oscillations by roughly an order of magnitude. The bed velocity is similar between the
configurations. The reduction of the dynamic loading is expected to improve material life,
structural requirements and performance variability.
14
Figure 12. Cold flow testing improved bed stability and reduced pressure oscillations by an
order of magnitude.
Conclusions
The Aerojet Rocketdyne team is developing Oxy-PFBC technology with carbon capture to
enable affordable electricity generation that is projected to cost significantly less than current
post combustion capture technologies. It combines the economic advantages of air-fired PFBC
technology with the carbon capture benefits of oxy-fired boilers. Compared to no-capture cases,
the cost of electricity is projected to increase by 18% for a supercritical CO2 Brayton cycle, or
27.5-31% for a steam Rankine cycle, assuming no economic benefit for the CO2. By comparison,
post combustion technologies typically increase cost by 75-85%. Key capital cost benefits for the
steam Rankine cycle compared to other standard DOE oxy-combustion cases are due primarily
to a significantly smaller and less expensive boiler. Operational benefits are associated with
integration between the condensing heat exchanger and the boiler feedwater, and the use of ASU
waste heat to dry reactants. Atmospheric pressure cold flow testing at full pilot scale reduced
risks for pilot operation by achieving stable bed operation, characterizing heat transfer for the inbed heat exchanger, and demonstrating that coal particle residence time significantly exceeds
burnout time. The current development plans include completion of pilot scale testing by early to
mid-2017, with demo plant operation by 2020, and commercial scale operation demonstrated
by 2025.
Acknowledgements
This material is based upon work funded in-part by the United States Department of Energy
under Award Number DE-FE0009448.
This report 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 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,
recommendation, or favoring by the United States Government or any agency thereof. The views
15
and opinions of authors expressed herein do not necessarily state or reflect those of the United
States Government or any agency thereof.
References
1. Fitzsimmons, M., Hiraoka, D., Laurie, J., Manley, T., Yows, S., Sonwane, C., Follett, W.,
Kibili, M., Alekseev, A., Jovanovic, S., “Pressurized Fluidized Bed Oxy-Combustion
with Heat Integration”, 3rd Oxyfuel Combustion Conference, September 9-13, 2013,
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