Carbon capture study

Carbon Sequestration Study
Prepared for: The Board of Directors
Prepared by:
Alexander Lee
Alexander Rojas
Pooyan Khajavi
Sarim Shah
Siddharth Dev
Taylor Schulz
February 19, 2012
Project Number: 1.00
Olin Hall Ithaca, NY 14850

Executive Summary
Objective
This report consists of our design to separate and sequester the CO2 in the flue gas from Cornell’s Combined
Heat and Power Plant. The major units in our process consist of a water spray cooler that will cool the flue
gas from the plant, a series of MEA columns to separate the CO2 from the flue gas, and a pipeline that will
transport the CO2 to the sequestration site near the Cayuga power plant. Included in the report are details
unit design. Lastly, we have included a plot plan to detail where the new process could be constructed. This
report will be of use in evaluating the feasibility of pursuing and completing this project.
Feasibility Study
Using the FACT Costing Method the total estimated project cost is $80,000,000 to capture 65,000 lbs/hr of
carbon dioxide in a well near the AES Cayuga Power Plant 16.5 miles away. The sequestration project would
take about 5.5 years to construct and sequestration would last for approximately125 years.
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1

Carbon Capture
& Sequestration
We were tasked with designed a process flow diagram to illustrate how carbon dioxide can potentially be
removed from the flue gas being emitted by the Cornell power plant. Carbon sequestration, as explained
earlier in the introduction is primarily to reduce the negative impact of increased carbon dioxide emissions on
the environment. However it is important to note that once removed from the stream of flue gas, this carbon
needs to be stored safely without detriment to society and the environment. This section describes the ap-
proach we have taken to achieve CCS for this power plant.
MEA Carbon Dioxide Capture Process
The amine we will use is monoethanolamine (MEA), which acts as a weak base in an aqueous solution and
neutralizes acidic molecules (CO2) in a gas. This process is performed through an absorber. Figure 1 shows
the proposed mechanism for CO2 absorption by MEA. Once the CO2` is absorbed the “rich” amine is then
regenerated through regenerator column. In the regenerator column, MEA is exposed to heat at low pressure
so its bonds to the acid gas breaks and is allowed to rise out of the distillation column while the “lean” MEA
is re-circulated back to the contactor column. The CO2 is then compressed and dried for preparation for in-
jection.
Aspen HYSYS was used to model this process. First it was necessary to find the amine loading required to
be able to absorb all of the CO2 out of the flue gas. It was determined that this would require 2 contactors
instead of 1, which would be in series. This would remove almost all of the 64,000 lb/hr of CO2 from the gas.
Using GPSA as a guideline and being a bit more conservative we find that we need about 650 GPM of amine
solution (30 wt% MEA) through each of the two columns. The most expensive parts of the process turned
out to be the condenser and the reboiler of the regeneration column due to the fact that its duty was very
large (on the order of 108 Btu/hr). This makes sense because a large amount of water is circulating and to
reboil and condense it, is going to take a fair amount of energy.
2

Figure 1: Reaction Mechanism for MEA-CO2
3

Carbon Sequestration
Carbon sequestration is an important phase after the carbon dioxide has successfully been removed from
ﬂue gas leaving the power plant. Studies have shown that there are 3 key ways carbon can successfully be
stored. These are a) ocean storage, b) geological storage and c) mineral storage. Figure 2 shows a sche-
matic of how this can be done.

Figure 2: Carbon can be stored in various ways once it has been captured
Source: http://www.ornl.gov/info/ornlreview/v33_2_00/research.htm
While these forms of storage are the ones that have been researched, it is important to study what is relevant
to Ithaca and the Cornell power plant. The two useful ways to store the carbon that our team has thought of
include the storage in the Marcellus shale as well as depleted natural gas reservoirs that might be available in
the region. Carbon dioxide can also successfully be utilized in open algal ponds that require CO2 for energy
storage. The possible solutions will be explored as we progress into the latter stages of this project.
4

Risk Analysis
Notice
This study only took into account of building the pipeline and units. Maintenance, insurance, and extended
liability are of concern and should also be considered after sequestration.
Risk Assessment
Carbon Dioxide, CO2, has a multitude of risks involved. This carbon sequestration project has several risk
factors that must be mitigate and manage. The current pipeline set up transports liquid CO2 close to the
supercritical area but is purely a liquid. The inlet pressure is pressurized by the pump to about 135 atm and
exits the pipe at 95 atm. The primary risks are as follows:
• Fluid Flow Corrosion
• Pipeline Failures
• CO2 and CH4 Leaks Out of the Well
• Displacement of Saline Groundwater
Concern – Fluid Flow
Transporting CO2 as liquid is possible but difficult. This is due to CO2 chemical properties. Its high density
and high viscosity make it challenging tasks. By calculating the Reynolds Number we find it high at about
5200 and therefore it will experience turbulent flow. The potential risks include CO2 pipeline ware that could
damage pipeline due to the high drag coefficient and potential pressure losses.
Solution – Fluid Flow
One can manage this risk with extensive and thorough pipe lubrication to reduce the drag coefficient and
assist fluid flow in the pipeline. To accomplish this a small pigging device will be sent down the pipeline
occasionally to increase fluid flow and reduce the chance of corrosion and blockages. We will use the
industry standard lubrication system and use carboxymethyl cellulose as lubricant.
5

Concern – Pipeline Failures
Hot tapping by utility works, corrosion, construction defects and ground movement can cause CO2 pipeline
failures. Fatalities and injuries from a ruptured CO2 can happen.
Solution – Pipeline Failures
The accident record for CO2 pipelines in the USA shows eight accidents from 1968 to 2000 without any
injuries or fatalities. This statistically means approximately 3.10-4 incidents per km year. The risk of a pipeline
incident is low mostly due to CO2 is not explosive or inflammable. There is a chance of asphyxiation as CO2
is denser than air. To mitigate this chance there will be a safety distance of 150 meters at which
concentration of CO2 will be within a safety and healthy standards.
Concern – CO2 and CH4 Leaks Out of the Well
CO2 and CH4 mitigate out of the reservoir to the atmosphere.
Solution - CO2 and CH4 Leaks Out of the Well
When it is injected into the well, it will be a supercritical fluid. In this stake the buoyancy effects will make CO2
rise until it hits the cap rock where it will stay. There is always a chance of CO2 or CH4 leakage. Careful
pressure and temperature sensors must be used to detect any disturbances. Safety valves to stop fluid flow
and ceals are in place.
Concern – Displacement of Saline Groundwater
CO2 in the well might cause displacement of saline groundwater also know as brine. This could cause the
rise of the water table and an increase in salinity of drinking water in extraction wells.
Solution – Displacement of Saline Groundwater
Water concentration levels will be measured to monitor the ground water levels. However, if we have good pipe encasing
and pressure control, the CO2 should drop into the well without displacing the brine. The depth and geological formations
are significant enough that this risk is minimized.
6

Economic Analysis
To cost most of our CO2 separation process including both ISBL and OSBL, we used the First Approximation
Costing Technique (FACT) method. The only exception was costing the fan for which we used the McGraw
Hill’s equipment cost estimator1 based on the fan’s ﬂow rate capacity. We estimated the CO2 transportation
cost separately and added it to our ISBL and OSBL costs to calculate the total project cost.2 Below are ta-
bles summarizing the major unit and major costs of our process. Detailed calculations of each part of the
process (spray tower, distillation column, compressors, etc.) can be found in the Appendix.
Units Number
of

Units
MEA
Contactor
Columns 2
Spray
Cooling
Tower 2
Tube
Axial
Fan 1
MEA
Regenerator
1
Pumps 2
Compressors 3
Heat
Exchangers 7
Figure
1.
Number
of
units
in
the
process.
Major
Equipment
Costs $8,172,706
Total
Equipment
Costs $15,037,779
Total
InstallaPon
Costs $17,293,445
Total
Capital
Cost $32,331,224
Total
Installed
ISBL
Cost
of
ISBL $34,917,722
OSBL
Costs $12,221,203
CO2
Pipeline
Costs $13,300,000
Total
Project
Cost
(with
40%
conPngency) $79,300,000
7

Figure
2.
Major
project
costs.
SPRAY COOLER TECHNICAL CALCULATIONS
The spray cooler was sized for the flue gas flow rate from one HRSG. To account for the second HRSG we
will install a second cooler with the same dimensions. Once we obtained the dimensions of one spray cooler,
we were able to approximate the exit temperature of the water stream as well as the residence time for the
flue gas.
Sizing: To obtain the dimensions of the spray cooler, we used the Brown-Souders equation shown below.
The sizing factor was calculated using the graph in Figure 5. Although our spray cooler has not been de-
signed with trays, we used an average value for tray spacing based on a literature search and a surface ten-
sion for water of 72 dynes/cm to obtain an approximate value.
Figure 5: Sizing factor was calculated using tray spacing and surface tension of water.
8

Once we obtained values for the maximum velocity of flue gas within the spray cooler, we were able to obtain
the base area of our spray cooler. To calculate this value, we divided the volumetric flow rate by the maxi-
mum vapor velocity as shown in Equation 2.
The height of the spray cooler was then calculated by multiplying the diameter of the base by a factor of 2.5.
The final dimensions we obtained are shown in Table 3.
As mentioned earlier, this capacity has been designed for the flue gas output of one HRSG. We will install
two coolers of these dimensions to cope with the output of both HRSGs.
Validation of Design: To validate the spray cooler size we obtained, we needed to find the exit temperature of
the water from the spray cooler. Having set the inlet and outlet temperature for the flue gas at the spray
cooler and the inlet temperature of the water, we were able to use a log mean temperature difference to find
the desired value. Equation 3 shows how we calculated the exit temperature for the water stream.
9

Where U is the energy to be removed from the gas per second, h is the heat transfer coefﬁcient, and A is the
base area of the cooler to calculate log mean temperature difference at the entry and exit points of the
cooler.
Table 4: Key design variables that were considered in our calculations.
Heat transfer coefficient 40W/m2K
Liquid to gas ratio 0.006 gallons/ft3
Radius of droplet 250µm
Entry temperature of flue gas 272 °F
Exit temperature of flue gas 150 °F
Entry temperature of water 90°F
The exit temperature of the water stream was calculated to be around 120°F. To calculate the residence time
of the ﬂue gas, we used Equation 4 as shown below.
Table 5: Final values obtained from all calculations
Diameter of Spray Cooler 20 ft
Height of spray cooler 50 ft
Exit temperature of water stream 120°F
Residence time of flue gas 7.9s
Flow rate of water 110 lb/s
10

Sequestration State
The CO2 could be sequestered in its liquid, gas, or supercritical phase, and there are advantages and disad-
vantages to each. Sequestration as a liquid or gas would allow the CO2 to be sequestered in shallower wells,
but volume that could be stored there would be greatly reduced because of the CO2’s much lower density in
these phases. The CO2 is best sequestered in its supercritical state since up to 260 times more CO2 can be
stored in the same well in its supercritical state than as a gas or liquid. The supercritical state also allows the
CO2 to reach into cracks that it may not have penetrated otherwise. The CO2 phase diagram in Figure 6
shows that the CO2 must be kept above 31.1 degrees C and 73 atm in order to keep it supercritical. In order
to satisfy these characteristics and ensure that the CO2 remains supercritical once it has been sequestered,
the well depth needs to be a minimum of about 2,600 feet.
Figure 6: CO2 Phase Diagram
Site Location
For this study, potential CO2 sequestration locations were conﬁned to geological formations, which include
deep saline aquifers and depleted oil and gas reservoirs. The most feasible location for sequestering gas
from the Cornell Power Plant seems to be the property surrounding AES Cayuga Power Plant. The well is
about 16.5 miles from the Cornell plant and, as shown in Figure 7 below, sits south of the 3,000 foot contour
line, providing an adequate depth for maintaining the CO2 in supercritical state. The minimum depth of the
11

well for this location was set at about 3,000 feet for this case in order to allow placement of the seals some-
where in the remaining 400 feet.1
Figure 7
12
1 Jordan, Teresa E., Brian Slater, and Kathryn L. Tamulonis. “Carbon dioxide storage potential for the Queenston
Formation near the AES Cayuga coal-fired power plant in Tompkins County, New York.”

Figure 8
The 25 square mile area outlined in red in Figure 8 has a minimum thickness of about 500 feet and a maxi-
mum of about 700 feet. Using this data in conjunction with the density, porosity, and storage efﬁciency, the
capacity for sequestration can be estimated using Equation 1 below.
13

Based on the estimated reservoir temperatures and pressures, as well as the fact that the CO2 will be in its
supercritical phase, the density is estimated to be in the range of 42 to 50 lb/ft3. Given the composition of the
Queenston Formation on which the well would be placed, the porosity is estimated to be about 10%, with a
margin of error of 25%. The reservoir storage efﬁciency factor encompasses the uncertainty surrounding how
much of the formation water the CO2 will be able to replace. It has a range of 1% to 4%, with an average
estimated at 2.5% for this formation.2
These values indicate that somewhere in the range of 7 to 29 million metric tons (with an average of about 18
million metric tons) of CO2 could be sequestered in this location. Given that the Cornell Power Plant outputs
about 182,000 tons of CO2 every year, the Queenston Formation can probably provide storage for about 98
years. Using the most conservative estimates of the formation’s storage capacity and considering the plant
to be operating at maximum output, the location should still be able to sequester all of the Cornell plant’s
CO2 output for a minimum of 28 years.
14
2 Jordan, et al.

Carbon Dioxide Transport Route
Compression
The CO2 is going to be transferred to the site as liquid. Reciprocating compression is chosen due to ﬂow rate
per minute (ACFM) and the ﬁnal pressure. Reciprocating compressors can have compression ratios of up to
4. After each stage the CO2 is cooled to 110 F. The data about the compressors are shown in Table 6 below.
Table 6 : Compressor stage calculations
Number of Compressor stagesNumber of Compressor stages 3
Compression RatioCompression Ratio 3.33
Suction Temperature in all stagesSuction Temperature in all stages 110 F
Discharge Temperature in all stagesDischarge Temperature in all stages 290 F
Compressor Power of Each StageCompressor Power of Each Stage 336 hp (250 kW)
Total Compressor PowerTotal Compressor Power 1010 hp (750 kW)
15

Stage 1
Suction Pressure, Stage 1 27 psi
Stage 1
Discharge Pressure, Stage 1 90 psi
Stage 2
Stage 2
Stage 3
Stage 3
The calculations are as follows:
The calculation of temperature rise in each stage of compression is as follows:
16

Since the Compressor cannot handle phase change, the CO2 is compressed up to 1000 psi and then
cooled. At 1000 psi the CO2 becomes liquid in temperatures less than 28 Celsius. The CO2 is cooled to 20 C
and then pumped up to a certain pressure in order to have the required head for the pipeline and the se-
questration site.
Piping: The CO2 will be piped from the Cornell power plant to the sequestration location. Studies suggest
that the CO2 ought to be piped at a pressure of around 95 atm, which indicates that the CO2 will be piped as
a liquid.3
Should the temperature inside the pipe rise to above 31.1 degrees Celsius, the liquid CO2 would change
phases to supercritical. Since the pipe will be a minimum of 2 feet underground and probably will be closer to
5 feet underground, however, this should not much of a concern. The highest temperatures that the pipeline
can expect to experience are anywhere from 22 degrees C to 27 degrees C.4 Given that the data was col-
lected in Virginia, where the highest ever recorded temperature was 43 degrees C, it should serve as a rea-
sonable conservative estimate for the Ithaca area, where the highest recorded temperature was 37 degrees
C.5 More importantly, perhaps, a report by Siemens AG indicates that pumping liquid or supercritical CO2 is
interchangeable, alleviating any concerns about the CO2 changing phases while being pumped and piped to
the site.6
17
3 Carbon Management GIS: CO2 Pipeline Transport Cost Estimation, MIT, June 2009.
http://sequestration.mit.edu/energylab/uploads/MIT/Transport_June_2009.doc
4 “Earth Temperature and Site Geology.” Virginia Tech. http://www.geo4va.vt.edu/A1/A1.htm
5 “Ithaca, NY.” Weatherbase. Canty and Associates LLC. 2012.
http://qwikcast.weatherbase.com/weather/weather.php3?s=056937&refer=qk
6 Jockenhövel, Tobias, Michael Sandell, Rüdinger Schneider, and Lars Schlüter. “Optimal Power Plant Integration of
Post-Combustion CO2 Capture.” Siemens. 26 May 2009.

Pipeline Diameter Calculations: The pipe diameter can be approximated using the equation and variable defi-
nitions provided below:
The input pressure is assumed to be 2000 psi to account for losses.7 This yields a pipe diameter of 24
inches.
In order to transport the liquid to the site, a pump that could provide the differential pressure was deter-
mined. The actual horse power of the motor was found using the following equation.
Considering an efficiency of 60% and differential pressure of 808 psi, the motor must be about 113 horse-
power.
To get the required pressure, the CO2 must first go through compressors before it can be pumped. This will
be a three stage process, compressing the CO2 from 27 psi to 1000 psi through three consecutive compres-
sors operating at 336 hp each.
18
7 “Carbon Management.”
http://www.canadiancleanpowercoalition.com/pdf/CO2%20Transportation%20Cost%20Calculations.pdf

Compression Process: In order to gain better insight into the process the process has been shown in the
ﬁgure below.
The CO2 pressure should be higher than 73 Atm at the sequestration site. The system has been designed to
maintain a pressure of 80 Atm at the end of the pipeline. So the Pump should provide the additional pressure
required. Table 7 below summarizes the pressures and the temperatures of the CO2 at different stages of the
process.
Table 7: Compressor calculations
Before the Compressors 27 Psi, 110 F (1.8 Atm, 43 C)
After the Compressors 1000 Psi, 290 F (65 Atm, 143 C)
At Pump inlet 1000 Psi, 68 F (65 Atm, 20 C)
At Pump outlet 1800 Psi, 70 F (120 Atm,21 C)
Piping Route: The CO2 piping regulations closely reﬂect those of piping natural gas. This means that due to
the high pressures of the pipeline, the pipe will need to avoid urban areas where possible. Since most of the
land between the power plant and the sequestration site is farmland, this should not be a problem once the
pipeline route is beyond Ithaca’s city limits.
19

Plot Plan
The flue gas will go from the roof to a raised support beam. From the supports the flue gas will go through
the entire process and carbon dioxide will exit as a liquid from the pump to travel to the sequestration site.
GANTT Chart
Our team has assigned an approximate time period of 5.5 years to complete this project. As shown in the
Gantt chart in the appendix, the initial stages will require basic engineering design as well as approval of
permits. Once these have been cleared, the most time intensive segment of the project, the construction
phase, will begin. Detailed engineering as shown in the chart will be an ongoing process and will last till the
point of actual equipment testing and the commissioning phase. The project timeline can be adjusted based
on how quickly certain tasks can get completed however we believe this is the best estimate that can be
provided at this point of planning. The Gantt chart also shows which tasks are dependent on tasks prior to
those being completed. However, it does not provide detailed specifications of what is to be completed un-
der each category because this can only be listed once the project execution plan has been finalized. The
Gantt chart is attached in the appendix at the end of this report
20

Conclusion
Our detailed technical and economic analysis of this three week project study has allowed us to gain greater
perspective of how efficient and cost effective CCS technology is. Based on our economic analysis, we have
concluded that this is not a feasible concept to incorporate into the current set up at the Cornell Combined
Heat and Power plant. While it might seem like an effective solution for carbon sequestration and the reduc-
tion of emissions of carbon dioxide into the atmosphere from a technical standpoint, the returns and poten-
tial benefit from the investment do not outweigh the lack of benefit gained from not installing this technology.
Carbon sequestration technology is making huge amounts of progress in the modern day but for the amount
of energy and costs that will go into setting this technology up for the CCHP, we do not believe it is a worthy
investment.
21

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