Carbon Sequestration Study

Prepared for: The Board of Directors

Prepared by:

Alexander Lee Alexander Rojas Pooyan KhajaviSarim Shah Siddharth DevTaylor Schulz

February 19, 2012

Project Number: 1.00

Olin Hall Ithaca, NY 14850

Executive Summary

ObjectiveThis 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 StudyUsing 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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Carbon Sequestration Study 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 ProcessThe 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.

Carbon Sequestration Study 2

Figure 1: Reaction Mechanism for MEA-CO2

Carbon Sequestration Study 3

Carbon SequestrationCarbon 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.

Carbon Sequestration Study 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 AssessmentCarbon 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.

Carbon Sequestration Study 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.

Carbon Sequestration Study 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 2Spray  Cooling  Tower 2Tube  Axial  Fan 1MEA  Regenerator   1Pumps 2Compressors 3Heat  Exchangers 7

Figure  1.  Number  of  units  in  the  process.

Major  Equipment  Costs $8,172,706Total  Equipment  Costs $15,037,779Total  InstallaPon  Costs $17,293,445Total  Capital  Cost $32,331,224Total  Installed  ISBL  Cost  of  ISBL $34,917,722OSBL  Costs $12,221,203CO2  Pipeline  Costs $13,300,000Total  Project  Cost  (with  40%  conPngency) $79,300,000

Carbon Sequestration Study 7

Figure  2.  Major  project  costs.

SPRAY COOLER TECHNICAL CALCULATIONSThe 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.

Carbon Sequestration Study 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.

Carbon Sequestration Study 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/m2KLiquid to gas ratio 0.006 gallons/ft3

Radius of droplet 250µmEntry temperature of flue gas 272 °FExit temperature of flue gas 150 °FEntry 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 ftHeight of spray cooler 50 ftExit temperature of water stream 120°FResidence time of flue gas 7.9sFlow rate of water 110 lb/s

Carbon Sequestration Study 10

Sequestration StateThe 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 LocationFor 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

Carbon Sequestration Study 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

Carbon Sequestration Study 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.

Carbon Sequestration Study 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.

Carbon Sequestration Study 14

2 Jordan, et al.

Carbon Dioxide Transport Route

CompressionThe 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 3Compression RatioCompression Ratio 3.33Suction Temperature in all stagesSuction Temperature in all stages 110 FDischarge Temperature in all stagesDischarge Temperature in all stages 290 FCompressor Power of Each StageCompressor Power of Each Stage 336 hp (250 kW)Total Compressor Power Total Compressor Power 1010 hp (750 kW)

Carbon Sequestration Study 15

Stage 1Suction Pressure, Stage 1 27 psi

Stage 1 Discharge Pressure, Stage 1 90 psi

Stage 2Suction Pressure, Stage 2 90 psi

Stage 2 Discharge Pressure, Stage 2 300 psi

Stage 3Suction Pressure, Stage 3 300 psi

Stage 3 Discharge Pressure, Stage 3 1000 psi

The calculations are as follows:

The calculation of temperature rise in each stage of compression is as follows:

Carbon Sequestration Study 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

Carbon Sequestration Study 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.

Carbon Sequestration Study 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.

Carbon Sequestration Study 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 ChartOur 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

Carbon Sequestration Study 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.

Carbon Sequestration Study 21