chilled ammonia process scale-up and lessons learned

Available online at www.sciencedirect.com

ScienceDirect

Energy Procedia 00 (2017) 000–000

www.elsevier.com/locate/procedia

1876-6102 © 2017 The Authors. Published by Elsevier Ltd.

Peer-review under responsibility of the organizing committee of GHGT-13.

13th

International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14-18 November 2016, Lausanne, Switzerland

Chilled Ammonia Process Scale-up and Lessons Learned

Ola Augustsson a, Barath Baburao, Sanjay Dube, Steve Bedell

b, Peter Strunz, Michael

Balfe, Olaf Stallmann*c

aGE Power, Växjö, Sweden bGE Power Ltd., Knoxville, TN, USA

cGE Carbon Capture GmbH, Wiesbaden, Germany

Abstract

The GE Chilled Ammonia Process (CAP) is a post combustion CO2 capture technology that produces a high purity CO2 product

stream that can be utilized in the existing and new markets. The development of the CAP technology began with laboratory

bench-scale experiments to confirm that aqueous ammonia solution effectively absorbs CO2 with sufficiently low vapor phase

ammonia emissions at reduced temperatures. From these results, a technology development program was initiated to scale-up and

validate the process for commercialization.

The approach taken here is illustrative of industrial scale process development and improvement. For the CAP CO2 capture

technology, the development effort involved an iterative approach as information from the different development stages was

obtained to set environmental & economic targets, develop predictive tools and models for process optimization, and to support

validation efforts at operating facilities. Over the course of the program, the technology was successfully tested on flue gasses

produced from coal, oil, and natural gas combustion, in addition to flue gas produced from refinery applications. Process know-

how and operational experience was gained and together with validated data from bench-scale and pilot plant facilities was

returned to push process design improvement and the development of predictive models. Currently, the CAP design is also

modified and extended into applications involving Urea, Methanol, and Soda Ash Production.

While many lessons learned and process improvement opportunities have been extracted from pilot plant and other test facilities,

pilot plant results and process modeling studies are still unveiling potential for further improvement. Optimization and integration

with the power generation facility occurred in the development phases of several FEED studies for large CCS plants. The CAP

* Corresponding author. Tel.: +49 6134 712 472; fax: +49 6134 712 590.

E-mail address: [email protected]

http://www.sciencedirect.com/science/journal/22126716

2 Author name / Energy Procedia 00 (2017) 000–000

design is ready for a demonstration-scale project and now is much improved from the design that was tested originally at

laboratory bench-scale. For example, the CAP scrubbing solution is now operated in a non-solids mode where precipitation is not

a part of the overall operational strategy and the process flow scheme is now modified and improved from original flow schemes

implemented at early pilot facilities to improve performance at reduced cost.

This work summarizes the bench-scale, pilot-scale, and validation facility results and offers insights into the lessons learned and

effort required bringing the technology into commercialization at an industrial scale. The lessons learned from each of the pilot

plants at different sizes are illustrated and the associated impact of the results from each pilot plant in the current CAP product

offering is also discussed. A summary of the important results from CAP test facilities including Stanford Research International

(SRI), WE energies, EONCAP-Karlshamm, AEP Mountaineer, TCM and GE’s pilot facility in Vaxjo, Sweden are presented.

Distinguishing features of the GE CAP are provided drawing comparison to open literature versions of ammonia based CO2

capture processes. Evolution of key performance parameters such as energy demand, product quality, solvent strength, process

flow scheme, etc., at the different plant sizes are also discussed. In addition, the current state of development for extending the

technology into areas where CO2 may be utilized productively are also be addressed in addition to the latest improvement

concepts currently being studied on CAP. Finally, the paper will also summarize the advantages of CAP as compared to

conventional amine based processes.

© 2017 The Authors. Published by Elsevier Ltd.

Peer-review under responsibility of the organizing committee of GHGT-13.

Keywords: GE; CO2; Capture Process; Post Combustion; CAP; Chilled Ammonia Process; Lessons Learned; Status; Scale-up; SRI; WE-Energy;

EONCAP-Karlshamn; AEP Mountaineer; TCM; Technology Center Mongstad; Thermal Energy Demand

1. Introduction

The GE Chilled Ammonia Process (CAP) is a post combustion CO2 capture technology that produces a high

purity CO2 product stream that can be utilized in the existing and new markets. Primary objective of this CCS

technology is to address GE’s installed base of power plants but also new build and industrial emitters.

The approach taken by GE is illustrative of industrial scale process development and improvement. For the CAP

CO2 capture technology, the development effort involved an iterative approach as information from the different

development stages was obtained to set environmental & economic targets, develop predictive tools and models for

process optimization, and to support validation efforts at operating facilities.

Development of CAP technology began with laboratory bench-scale experiments to confirm that aqueous

ammonia solution effectively absorbs CO2 with sufficiently low vapor phase ammonia emissions at reduced

temperatures. From these results, a technology development program was initiated to scale-up and validate the

process for commercialization. Several pilot and validation facilities using the Chilled Ammonia Process with

increasing capacity per evolution step have been built and tested. The CAP plants treated combustion flue gases

from both power and industrial boilers using several different fuels. In combination, pilot plant and validation

facilities have operated for over 22,000 hours.

Optimization and integration with the power generation facility occurred in the development phases of several

FEED studies for large CCS plants. The CAP design is ready for a demonstration-scale project and now is much

improved from the design that was tested originally in the lab at bench-scale.

2. Nomenclature

CAP Chilled Ammonia Process PVF Product Validation Facility

CCS Carbon Capture and Storage RFCC Refinery Fluidized Catalytic Cracker

CHP Combined Heat and Power (Plant) SAFS Single Absorber Flow Scheme

FEED Front End Engineering and Design SRI Stanford Research International

MEA Methyl-Ethanol-Amine TCM Technology Centre Mongstad, Norway

PCC Post Combustion Capture VP Verification Plant

Author name / Energy Procedia 00 (2017) 000–000 3

3. Technology

GE’s CAP is a wet-regenerable solvent process using ammonia-carbon dioxide based salts as the solvent. CO2 is

captured in an absorber and then cycled through a regeneration tower to drive off a concentrated stream of CO2.

Traditionally water washing steps were also employed to recover ammonia.

The reaction mechanism of carbon-dioxide absorption with ammoniated solution has been reviewed in the

scientific community for many years. The following set of reactions, Equation 1 through 6, was used to describe the

chemical equilibrium.

OHOHOH 322 (1)

3322 2 HCOOHOHCO (2)

OHCOOHHCO 3

2

323 (3)

OHNHOHNH 423

(4)

COONHOHHCONH 2233 (5)

4334 )( NHHCOsHCONH (6)

In the CAP absorber system, the reaction of gaseous carbon dioxide into the liquid phase results in reactions with

water and ammonia along with weak acid dissociation to form a temperature and concentration dependent

speciation, which after sufficient time approaches chemical equilibrium. The chilled ammonia process operating

with precipitated solids is designed around the reaction of flue gas CO2 with an aqueous ammonia solution to

precipitate ammonium bicarbonate NH4HCO3. The overall reversible chemical process is shown simplified in

Equations 7 and 8.

HeatHCONHCONHOHCO 3432422 2)( (7)

2324234 )(2 COCONHOHHeatHCONH (8)

The capture reaction (Equation 7) is optimal at a temperature between 40ºF and 59ºF (5ºC and 15ºC); to which

the flue gas must be chilled. Regeneration of the capture solution (Equation 8) and recovery of the captured CO2 is

optimal at a higher temperatures and moderate pressure. The regenerated solution, lean in ammonium bicarbonate, is

returned to the absorber system where it is re-used to capture CO2.

The process was originally conceived to operate the absorption at a temperature and ammonium bicarbonate

concentration such that a freely-suspended ammonium bicarbonate precipitate would form. Concentrated,

precipitated ammonium bicarbonate solids could then be used for regeneration. The increased CO2 loading (per unit

water) in the rich solution would reduce the sensible heat load needed for regeneration that is strongly influenced by

the carrier water. Later, pilot operations indicated that the presumed net energy benefit of precipitating solids was

marginal at best and in conjunction with operational stability issues. As a result, current designs foresee operation in

non-solids mode.

More details on the rationale for switching to non-solids mode will be described in subsequent sections of this

article. Nevertheless, still some investigations for solids operation are undertaken in the scientific community, e.g.

by Mazzotti et al. [1], which are also partnered by GE.


The decision to further explore the potential of the CAP was also driven by its advantages over other solvent

based CO2 removal systems and features that differentiate it from those.

Lower heat of regeneration (than MEA)

Use of a low-cost commodity solvent known to utility operators

Solvent which resists degradation from elevated temperature and exposure to O2, SOX and NOX

Use of a higher stripping temperature allows CAP to release CO2 at a higher pressure leading to lower

downstream compression costs, compared to Amine Systems.

Higher stripping temperature also increases the window of opportunity to integrate higher grade waste heat

directly, without the problems of degradation and the work-around by degrading the quality of heat.

A potential reduction in the amount of energy required to capture CO2, particularly in locations with lower-

temperature cooling water available.

3.1. Process

While the following process description assumes application on a coal-fired utility boiler, the CAP can be

modified, as required, for post-combustion CO2 removal from many different utility and industrial combustion

processes.

A schematic of the CAP is shown in Figure 1 below:

The CO2 capture system has the following main subsystems:

Figure 1: Initial solid mode CAP process


1. Flue Gas Cooling.

2. CO2 absorption.

3. High-Pressure Regeneration.

3.1.1. Flue Gas Cooling.

The flue gas exiting the coal power plants flue gas desulfurization plant (FGD) is typically between 120-140°F

(50-60°C). The gas is water saturated and it contains residual contaminants such as SO2, NOx, HCl, sulfuric acid

mist and filterable and condensable particulate matter (PM). In order to cool the saturated flue gas, both sensible

heat and latent heat for water vapor condensation has to be removed. Direct cooling without heat exchangers using

a combination of cooling towers and mechanical chillers is an efficient and low cost method that results in

condensation of water and the capture of residual emissions from the flue gas. The pH of the water in the flue gas

cooling subsystem is controlled using an alkaline reagent.

The net water balance around the flue gas coolers, with moisture condensing in the direct cooler (DCC1) and

evaporating in the direct contact heater (DCH or DCC2) is balanced considering also a bleed of ammonium sulfate

bi-product solution.

The reduction in volume and mass of the flue gas has the benefit of reducing the size of the downstream

equipment. Likewise, the ID fan is positioned downstream of the cooling subsystem, minimizing its size and power

consumption.

3.1.2. CO2 Absorption

Traditionally the flue gas entering the CO2 absorber is cooled. The gas is relatively dry with less than 1%

moisture and contains very low concentrations of SOx, HCl and PM.

The CO2 absorber is designed to operate with a solution containing a dissolved and suspended mix of ammonium

carbonate and ammonium bicarbonate. The flue gas flows upwards against the falling solution in counter current

flow. Up to 90% of the CO2 from the flue gas can be captured in the absorber. The low concentration of ammonia

in the clean flue gas exiting the absorber system is captured by cold-water wash and returned to the absorber. The

clean flue gas, containing mainly nitrogen, excess oxygen and residual CO2 flows to the chimney for venting to the

atmosphere.

3.1.3. High-Pressure Regeneration.

After solids separation from the bulk CO2-rich solution from the absorber, the stream routed to the Regenerator

contains mainly ammonium bicarbonate. The CO2 rich slurry is pumped through a heat exchanger, and enters the

high-pressure Regenerator. The pressure required for the CO2 gas at the plant battery limit is typically 1,500 psi

(100 bar). This represents a compression ratio of around 100, relative to ambient conditions. In contrast, the

proposed process regenerates CO2 at 300 psi (20 bar). This reduces the required compression ratio from 100 to 5,

resulting in a compression train that has fewer stages and consumes less power.

The ammonium bicarbonate in the CO2 rich slurry dissolves as the temperature increases in the heat exchanger

and turns into a clear solution at temperatures above 175°F (80°C). The hot solution is injected into the Regenerator

which is a high-pressure CO2 stripping vessel. Additional heat for stripping the CO2 is provided from a reboiler that

consumes low pressure steam. Bench scale testing has demonstrated that the CO2 gas from the regenerator and

resulting wash system is extremely pure, containing more than 99% CO2 and extremely low residual concentrations

of ammonia and water.


3.1.4. Non solid mode process

Over the development phase the CAP process changed operation from solid mode, that is operating the rich

solvent loading beyond the solubility limit of ammonium salts to form slurry, to non-solids mode, where the solvent

CO2 loading is below the crystallization point.

The changes in the process can be seen in Figure 2.

The obvious difference to non-solid mode is the omission of the solid handling equipment, like the hydrocyclone

used to concentrate the slurry from the absorber.

4. Industrial scale process development and improvement

GE has established a general approach in the development of new products and processes in the Environmental

Control Systems Sector. This approach formalizes the steps to be taken during the R&D phase.

For any process development, there is certain minimum information that is needed to allow a reliable design and

performance estimation for the commercial product or process. This typically includes:

1. Boundary Conditions (Design Envelope) for the targeted application

2. Thermodynamic base information covering the full range of compositions and operating conditions of the process

3. Calculation models for all relevant chemical reactions

Figure 2: Non-solids flow scheme


4. Calculation methods and/or specification guidelines for equipment

5. Information on process specific aspects not covered by standard estimation methods (Simulation tools, etc.):

5.1. Fouling / scaling behavior of the fluids used.

5.2. Unit operation specific features (e.g. heat leaks or ingresses)

5.3. Operations feedback on process / equipment design and flexibility requirements

Where no other sources of information (such as existing simulators, plants etc.) are available, the following

methods are generally used to obtain necessary data:

Literature data (satisfy information requirements of items 1-3)

Experiments at Laboratory or Bench scale (satisfy information requirements of items 1-3)

Lab pilot plant tests (satisfy information requirements of items 1-4; 5.1; 5.2)

Field pilot plant tests (satisfy information requirements of items 1-5 all)

Demonstration plant operation (To confirm underlying assessments at full scale and further detail / optimize

items 1-5 all)

Already existing knowledge of certain aspects of a technology in a company may allow shortcuts in the

development to be taken without increasing the risk position. In such cases the development comprises an adaptation

of an existing process or process modules to new boundary conditions rather than a full-fledged new development.

On the road to building full scale carbon capture facilities for power utilities, increasing capacities of pilot and

demonstration plants are necessary to minimize the risk associated with the knowledge available at the time of their

construction and use. The utility of new concepts is generally required to be proven, first in laboratory tests or at

bench scale, before a further development effort is initiated.

The development plan of the CAP technology as shown in Figure 3 shall serve as an illustrative example of this

approach. The program objectives at the start in 2004 were to provide a commercial product for CO2 capture using

the CAP technology by the end of 2015.

Figure 3: Initial CAP technology development plan


In order to reach this time-to-market requirement a rather tight schedule for the execution of the different test

phases was defined. This resulted in some overlap in the execution of the different test programs and required

proactive management of the knowledge transfer from one test program to the other.

Several pilot and validation facilities using the Chilled Ammonia Process have been completed to date. The CAP

plants treated combustion flue gases from both power and industrial boilers using several different fuels. In

combination, the pilot plant and validation facilities have operated for over 22,000 hours. A summary of the plants is

provided in Table 1.

Table 1. CAP Pilot and Validation Facility Summary.

Plant Operating

Period

Size Fuel

MWel TPY

SRI International

Bench-Scale and Pilot Plant

2005-2008 0.25 NA Synthetic gas

WE Energies Pilot Plant 2008-2009 1.7 13,000 Coal

EONCAP Karlshamn Pilot Plant 2009-2010 1.7 11,000 Heavy oil

GE Laboratory Facility 2009- present 0.25 NA Synthetic gas

AEP Mountaineer Product

Validation Facility

2009-2011 20 100,000 Coal

Technology Centre Mongstad

Validation Facility

2012-2014 16 RFCC 80000

CHP 22000

Refinery Residue Fluid

Catalytic Cracker

(RFCC) off-gas and

natural gas combined

heat and power (CHP)

5. The different test facilities and lessons learned

After initial tests to show the principle of CO2 capture using Ammonia-salt based solvents, a small scale bench pilot

plant was used at SRI to further evaluate the chemistry and define the technical hypothesis for further investigations.

5.1. SRI / Växjö facility

The objectives for the SRI facility were focused on proving the

chemistry concept in a CAP batch mode setup. The facility proved that the

CAP process is able to capture CO2 in solid and non-solid mode. Test

results provided the preliminary mass and energy balances, which were

used to build the WE CAP pilot in Wisconsin.

The large bench scale pilot became operational at SRI in November

2006. Validation activities at SRI were conducted according to the test plan

that was outlined by the field validation team. The primary objectives of

this pilot were:

Investigating the performance of the chilled ammonia process (CAP) for

capturing CO2 from power plant flue gases;

Obtaining relevant design data for a pilot scale (1 to 5 MW) system;

Evaluate absorption solvent regeneration conditions with a batch

regenerator;

Create an inventory of regenerated solvent for injection in the absorber

system.

Picture 1: SRI Absorber Pilot


The construction comprised an 18” diameter large-scale bench absorber system and its auxiliary equipment (gas

and system coolers and water-wash). The batch testing of the absorber system started on November 9, 2006 when

the first test run was performed. Different rates of inlet CO2 concentration, molarity of the solvent system, absorber

temperature and a wide-range of gas velocities to provide adequate residence time, L/G ratios, and sustained and

varying solvent loading were a few of the parameters that were used to get the data to enable more detailed

evaluations of the process.

Also, over time, many changes have been incorporated in the system to

determine the effect of the following on the CO2 capture efficiency:

Absorber Packing, Contactor Mechanism, conical/cylindrical shape change of

absorber bottom – To determine the best gas-liquid contacting device for the

required duty.

Alternative NH3 dosing methods

Injection of promoters such as Piperazine or MEA.

Most of the runs were basically scouting experiments to understand the effect

various parameters have on the process and to help in preparing a reliable and less-

time consuming strategy for subsequent parametric tests.

Furthermore these tests helped to define the operating conditions for later plant

designs. Particularly the next level pilot design was based on the findings of these

SRI tests.

The following results from the large bench scale tests were applied to the design

of the WE Energies field pilot:

A multiple stage, two temperature CO2 absorber design to minimize packing volume to achieve 90 percent

removal, form ammoniumbicarbonate solids and manage ammonia slip to acceptable levels

Structured packing definition

Pressure criteria in the regenerator for producing required quality CO2

Water wash design

Process logic and control mechanisms

Use of lean solution in scrubbing CO2 from flue gas

Baseline operating envelope for all key process parameters

Due to the small size it was not possible to resolute the behavior of the CAP process with regards to operational

issues. The formation of solids out of the gas phase containing NH3, CO2 and H2O on cold surfaces was detected and

first recommendations for design given. At this time operation in solids mode, having precipitated Ammonium salts

in the solution, was considered also for the next phase of the development.

After the test program at SRI was completed, the test plant was moved to GE’s Växjö laboratories in Sweden and

modified to reflect the latest findings also from the other pilot plants. For example, the operation in non-solid mode

was brought to the drawing board. Prior to the TCM Mongstad Verification Plant engineering a new idea for a

refinement of the non-solids operating mode, the single absorber flow scheme (SAFS), was evaluated and refined in

the Växjö Pilot.

Picture 2: SRI Regenerator Pilot


5.2. WE Energies

GE, EPRI and WE Energies announced in 2007 the development of a CO2 capture, pilot system to be installed

and operated at the WE Energies Pleasant Prairie Power Plant (P4), located in Pleasant Prairie, Wisconsin, US.

Picture 3 shows a picture of the P4 pilot. The P4 power plant was retrofitted with new wet FGD systems for control

of SO2 emissions and the retrofit included the construction of a new chimney.

As the technology developer, GE designed, constructed

and operated the pilot system. The pilot system captured

CO2 emissions from a slipstream of less than one percent of

the Unit 2 design gas flow. At 100% capacity, the pilot

system was designed to capture up to 15,000 tons of CO2

per year.

The field pilot at WE Energies was designed as a ‘proof

of concept’ facility with considerable operating flexibility to

test the different unit operations. The four key criteria,

necessary to validate the technical feasibility of the chilled

ammonia process include the following:

CO2 removal efficiency (90%);

Low ammonia slip from DCC2 overhead;

High CO2 quality (with low ammonia slip and low moisture content);

Low system pressure drop.

Additional objectives of the project included:

Demonstrate full system operation on actual flue gas, including but not limited to: flue gas cooling using heat

recovery/exchange and chilling, removal of residual pollutants, CO2 absorption and regeneration;

Evaluate energy consumption relative to calculated values and to other CO2 capture technologies;

Operate the system long-term to identify O&M issues and establish system reliability;

Conduct field tests to gather operating data from the system and develop objective, third-party techno-economic

analyses to refine current estimates for the performance and lifetime costs of a commercial system;

The pilot logged over 7,000 operating hours and, from January 2009 till October 2009, the pilot reliably operated

24 hours per day, 7 days per week. There had been a total of nine outages, described as follows:

Two forced outages of the power plant (unrelated to the field pilot);

One planned outage to provide the pilot operations and validation teams a break over the Christmas and New

Year holiday;

Three planned outages to support additional modifications to the pilot plant; and

Three forced outages to: a) to perform maintenance on the mechanical chiller; b) inspect and troubleshoot a

malfunctioning electric heater for the ammonia stripper; and c) replace a gasket on the regenerator column.

The experience in operating the field pilot was invaluable, as the operations and validation teams refined start-up

and shutdown procedures and troubleshooted issues with process operation.

The WE Energies pilot was a first of a kind pilot designed for continuous operation. During the initial months of

operation, the validation team identified a number of issues that required design modifications. As these

Picture 3: WE Energy CAP pilot, Pleasant Prairie Power Plant


modifications were implemented, pilot performance steadily improved to the point that stable absorber operation at

100% of design flue gas flow was established in April 2009. From this point, the pilot demonstrated the ability to

meet the key performance objectives, defined earlier. [6]

In 2009, parametric tests were performed on the various pilot sub-systems, including: the ammonia stripper, the

CO2 regenerator, the water-wash column and the CO2 absorber column. As parametric testing was performed,

operating parameters were intentionally adjusted to generate empirical data to be used to predict performance as a

function of these parameters. While this testing provided a deeper understanding of the process, the unit did not

always operate at optimized conditions. WE Energies operation subsequently showed that the energy benefit for

regeneration was offset by increased chilling in absorption.

It must be said that the problems encountered during operation of the pilot, mainly with the formation of solids

outside the absorber were simply categorized as initial operational problems. As a result these problems were not

analyzed into a depth that would have revealed that also some technological issues were involved as root cause.

After review of the development program history this subject is one of the major lessons learned from these early

days.

5.3. EONCAP Karlshamn

The EONCAP pilot was in operation from 2009-04-17 to

2010-01-13, which are ~9⅔ months. During this time the

operation was handled by EON via the local operator KKAB,

to target both a lean operational budget and fulfill KKAB’s

demand that the Pilot be operated accordingly to their standards

& routines. However, test planning, validation and management

was organized by GE.

Initially EONCAP’s operation was focused on energy flow

and efficiency, during the autumn it received requests from the

WE pilot to validate their data and the planned validation

program was aborted and work redirected to what became

called the WE-tests.

From the start of operation, EONCAP focused first on

operational issues that had been experienced in the past, getting

the water balance in control & avoiding issues with plugging. It

did well to avoid plugging as the plant was completely housed, and implemented strategies were successful for

achieving a stable water inventory. With increased operational stability, the issue of ionic buildups and its handling

strategies were started.

During the complete operational time of the CAP, only one truckload of process fluids were shipped out and this

seems to have been caused by a mal operated manual DI-water valve. For the rest of the operational period all

operational wastewater, spills and any rain that entered the containment were handled internally.

For the ionic buildups and the resulting problems with low pH due to ammonium bisulfate that formed at

elevated temperatures, EONCAP started to plan for an appendix stripper to control the ionic balance in the system.

This system was not installed before EONCAP was mothballed.

During the operation of the pilot it became clear that operation in solids mode sets extraordinary requirements

towards process monitoring, control and operation to prevent solid formation in areas, such as accumulations in the

absorber packing, where it would result in transients and eventually process upsets. Furthermore, the formation of

Ammonium carbamate and its effect on materials of construction had been underestimated. In the end increased

corrosion and equipment tightness was affected. The Karlshamn pilot was dismantled after the test program.

Therefore further measures were developed to address these challenges in the almost parallel executed project for

the Mountaineer PVF facility and any other subsequent CAP installation. As deposition of solids was experienced in

piping elements that were normally not in operation, tracing at adequate temperatures was foreseen to ensure

decomposition and avoid precipitation of ammonium salts.

Picture 4: EONCAP Karlshamn Pilot Facility


Aerosols became early on an issue that launched a special program at EONCAP, since this Pilot was the only one

which at this time had both adjustable flue gases and a dedicated stack where aerosols could observed. The aerosol

program included documentation, sampling procedure development, and parametric testing campaigns. Several

strategies and designs to handle aerosols, and circumvent potential plugging from process fluids were started. Since

this program grew and evolved it was not completed within the EONCAP’s operational period.

5.4. AEP Mountaineer Product Validation Facility

A CO2 capture and storage (CCS) pilot plant was constructed at American Electric Power’s (AEP) 1300 MWel

Mountaineer station in New Haven, West Virginia, employing GE Power’s Chilled Ammonia Process (CAP). The

CAP Product Validation Facility (PVF) is approximately a 12-fold scale-up from the 1.7-MW research and

development pilot tested during 2008-9 at WE Energies’ P4 in Wisconsin. The AEP unit was designed to provide

about 110,000 tons CO2/year (100,000 metric tons CO2/year) for injection into geological strata under the

Mountaineer station.

Approximately 1.5% of the full load flue gas flow

leaving the Mountaineer station wet scrubber

(corresponding to approximately 20 MWel) is extracted

and sent to the PVF for CO2 capture and compression.

The product CO2 is then provided to an on-site

injection, storage, and monitoring program. Treated

flue gas, less the captured CO2, is returned to the

Mountaineer station stack. The Mountaineer wet

scrubber, stack, flue gas supply and return ductwork

and the PVF plant are shown in Picture 5.

The captured CO2 was injected into two different

geologic formations via two wells located within the

plant boundary: Rose Run at ~7800 ft. (2380 m) and

Copper Ridge at ~8200 ft. (2500 m). The Copper

Ridge formation performance has exceeded

expectations, accepting the CO2 at relatively low

injection pressures (~76 bar) with little increase in the

formation pressure (~4 bar increase). The Rose Run formation was initially more resistant to injection than was

expected, but its performance has improved over time, with injection pressures around 76 bar and formation

pressure increases around 13 bar. Three deep monitoring wells were drilled and equipped to monitor CO2

containment, track carbon storage footprint, and measure downhole properties. [6]

The post-combustion-capture (PCC) retrofit demonstration using GE’s CAP operated for 7900 hours from

September 2009 to May 2011 on the 20-MW equivalent slipstream. During the demonstration, CO2 capture reached

the designed potential of up to 100,000 metric tons/year. Having been designed for 75% CO2 capture efficiency, the

CAP achieved capture efficiency between 75%–90% at purity of more than 99.9% during the demonstration. Over

50,000 metric tons of CO2 were captured and 37,000 metric tons were injected into permanent storage.

The goal of the capture part of this project was to be able to better judge the adequacy of the design and

performance objectives for the chilled ammonia process through the information obtained on:

Emissions of all media and pollutants and consumables

Energy demand, in what form and possibilities for thermal integration into a given power plant

Trade-offs between emission reductions and energy/reagent consumption

Finally, plant operability and reliability.

Picture 5: AEP Mountaineer PVF


The following key features/modifications were incorporated into the plant to accomplish these goals:

The PVF design was adjusted to operate in non-solids mode (Based on the experiences from WE Energy

and EONCAP Karlshamn pilots).

A two absorber system to capture 75% of the flue gas CO2 achieving the total objective of 100,000

tonnes/yr was installed.

The Water Wash was reduced from three recirculated beds in series at WE Energies to two beds. The top

bed is once through and serves as a polishing stage. The lower bed is a re-circulated system where the

primary amount of NH3 is absorbed

The refrigeration system includes direct gas cooling with Refrigerant and free cooling during the months

with lower ambient temperatures. Two R-410a refrigeration systems are provided, Low Temperature for

NH3 capture and High Temperature to remove heat of reaction. This configuration improves refrigeration

system efficiency.

CO2 exits the top of the regenerator at 21 barg with less than 50 ppmv NH3. Moisture in this stream is

reduced to less than 600 ppmv in a CO2 chiller prior to compression. Dry CO2 product is pressured up to

100 barg in a reciprocating compressor.

The impact on energy penalty in non-solids operation mode was found to be minor and partly to be compensated

by proper process operation and heat integration system design. As Ammonia slip into both flue gas and CO2

product was properly addressed through process design, other routes for Ammonia losses came into focus.

Ammonium bisulphate forms in the CAP solution as heat stable salt solvent withdrawn from regenerator to balance

accumulation of impurities SOx slipping DCC and being captured in the Absorber. The continuous accumulation of

this heat stable salt becomes considerable in the amount of ammonia bound, and requires continuous purging.

Therefore another stripper, the appendix stripper, was developed. The use of the appendix stripper was realized in

Figure 4: Flow diagram of AEP Mountaineer PVF facility


this pilot plant allowing reliable main stripper operation and further decreased ammonia emissions and reduced

losses into the ammonium bi-sulfate by-product solvent draw.

Furthermore, conclusions from material tests conducted at the before mentioned pilots found way into the PVF

design increasing reliability and availability.

5.5. CAP Plant at Mongstad TCM

GE has installed its CAP system at another CO2 capture validation

facility, Technology Centre Mongstad (TCM). TCM, which is owned by

Gassnova, Statoil, Shell and Sasol, was the world’s largest facility for

testing of Carbon Capture technologies at its start. The center is located

next to the Mongstad Refinery on the west coast of Norway. The

commissioning of the CAP CO2 Capture validation plant (VP)

commenced in early 2012 with initial start-up in October, 2012. The CO2

capture plant completed its operation and test campaign in August, 2014

with over 6000 hours of operation. A picture of the CAP facility at TCM

is shown in Picture 6.

The unique location of TCM, next to the refinery, provided interesting

opportunities in terms of gases the availability of gas sources to be treated

by the installed CO2 capture plants. The CAP plant at TCM was designed

to treat both refinery off-gas from a cracker operation as well as the

exhaust from a gas turbine based combined heat and power plant.

The plant, which initially was designed in 2008, captured over

39,500 tons of CO2 and achieved capture efficiencies of 85-87% at design

conditions. [8]

The initial test period foreseen covered 13 months, with an extension

option for additional 6 months, based on the test program developed by

GE.

The test program focus was on:

Process optimization, including: energy efficiency, ammonia consumption and low emissions

Steady state and transient operations

Impact of flue gas impurities.

The goal of this pilot plant was to establish an energy efficient process and mitigate risks when implementing a

full-scale Carbon Capture Unit. This unit furthermore was able to show performance of the CAP technology for

industrial applications and flue gases from gas firing.

The TCM Verification Plant design was based on preliminary results obtained from the large bench scale pilot

that was operated at SRI International and later re-located to Växjö. This design included the solids operating

concept that the WE Energies operation subsequently showed that the energy benefit for regeneration was offset by

increased chilling in absorption. Residual elements of this design carried an energy penalty for the TCM

Verification Plant, which were reduced but not eliminated with the modifications implemented.

The TCM Plant was also designed to consider two flue gas sources RFCC flue gas from the refinery with

relatively high concentrations of CO2 and CHP gas with relatively low concentrations of CO2. An emphasis on

obtaining the capture rate and capacity for the RFCC case provided oversized refrigeration and regeneration systems

which reduced the efficiency of the CHP operation. However, by providing the unit with the ability to operate

Picture 6: TCM Mongstad CAP Pilot


significantly above design margins, the need for operator intervention was minimized. An optimization program

identified the areas where such margins are not needed and reduce them where possible.

During initial operation solid formation was discovered in stagnant piping systems and safety devices which were

relics of an obsolete solids-operation mode. Based on better understanding of the mechanism of solid formation in

different solution and vapor locations with the CAP solution, a solids formation mitigation plan was implemented

successfully to control the temperature in stagnant pipe sections. The required countermeasures were taken and

incorporated into the design standard.

During operation of the Mongstad CAP plant the unit demonstrated to be very robust and forgiving of upsets

including:

Unit trips at the refinery

Loss of electrical power

Control system communication failure

Flue gas fan trips

Wide variations in flue gas composition from the RFCC flue gas

The CAP plant normally recovered from significant operating upsets within a matter of one to a few hours. In the

case of substantial RFCC flue gas composition variations, the CAP pilot proved it could continue to operate with no

significant aerosol based environmental emissions and capture CO2 efficiently.

Finally, there was the finding from the AEP MTN PVF facility during which the simulation model was validated

and optimization studies were undertaken leading to an improved absorber design, this improved SAFS design, was

finally validated at the Växjö laboratories in a dedicated test campaign as previously discussed.

6. Test Results

In the following chapters key results that have been retrieved from the pilot operation shall be presented. These

results led a good portion of the decision making in the program execution.

6.1. Results from SRI Large Bench Scale implemented In the WE Energies Design

One of the main questions to be answered already in the initial phase was the behavior of the Ammonia and its

potential losses into the flue gas.

Therefore a parametric test at different operating

temperatures varying the loading of the solvent was

executed. Here the loading is the molar ratio of CO2 to

Ammonia species in the solution

The test results in Figure 5 show that with decreasing

loading, which is also associated with increasing free

Ammonia in solution, emissions into the vapor phase are

increasing. A single absorption system will thus not be

able to meet the required emission limits while having a

sufficient high capture rate within feasible limits. Based

on these findings a dual absorber system was planned for

the next bigger pilot plant size.

Further tests included the CO2 capture efficiency in

dependence of the loading, residence time, packing

height and some other parameters which in the end gave Figure 5: Ammonia slip in relation to solvent loading

Loading 0.5 1.0 0.83 0.71 0.63 0.56

NH

3(g

), vo

l%

0.0

0.5

1.0

1.5

2.0

2.5

3.0


a good starting point for the planning of the next phase in the CAP development program – the field pilot test

program.

The regenerator tests were done in a batch and semi-continuous column system. Objective was to study the

temperature dependency of CO2 and Ammonia release during regeneration. Therefore the test program did not

include the measurement of the required regeneration energy demand. With this in mind one of the immediate areas

of focus for the development team at the time (2007-2008) was to understand and validate the CAP solution/slurry

heat capacities and heat of reaction aspects of the process. Academic collaboration with several groups were

engaged to investigate details of speciation and energy, leading to an early internal energy target for total heating

requirements of 1.9 GJ/ t CO2.

After installation of the system in Växjö also regenerator and stripper energy demand were measured. The system

required about 7 GJ/tCO2.

6.2. Results from WE Energies Design

Despite the operational experiences gained, as

described earlier, the test campaigns conducted also gave

insight into various process parameters effects.

One of the most important results was the capture

efficiency in comparison to the design value.

The WE Energy pilot plant was designed to capture

about 90% of the incoming CO2 in solids mode. During

transformation to non-solids mode this design value

dropped to 80% because of limitations in some of the

existing equipment. As can be seen in Figure 6 this latter

value could be confirmed during the test campaigns. It

was found that the capture efficiency is not so much

depending on the recirculation rate of the solvent but on

the loading of the solution.

Based on these results the simulation model could be

validated and its predictive capabilities improved.

Another question to be answered was the behavior of the Ammonia and its losses into the flue gas based on the

previous test program at SRI.

The design anticipated an Ammonia slip in the flue gas at the battery limit of less than 10 ppmv which could be

proven during plant operation. As shown in Figure 7 the Ammonia concentration in the flue gas leaving the DCC2

could be kept between 5 ppmv to 8 ppmv.

The thermal energy demand for the regenerator and

the stripper during solid mode operation of the pilot plant

with flue gas from a coal fired source was determined to

be at 2.5 GJ/tCO2, having an average CO2 capture

efficiency of 82%. This was substantially higher than the

expected 1.9 GJ/tCO2 based on internal theoretical

evaluations.

Based on test results and application of an updated

simulation model, an evaluation of a CAP system for a

reference 800 MW nominal power plant was made. Due

to various limiting factors during scale-up multiple

process trains were considered. Some of the more

obvious limiting factors identified at that time are listed

below:

Figure 7: Ammonia emissions via flue gas

Figure 6: CO2 capture efficiency and absorber B recycle variation


Absorber vessel Diameters – There exist practical limitations on the largest diameter mass transfer devices that

can be cost effectively fabricated; this can be limited by: gas flow distribution issues, structural requirements

with spanning the vessels to support the internal mass transfer devices and other issues.

Chiller Sizes – Larger chillers are custom designed and assembled; the largest chiller that is currently

manufactured is roughly 40,000 tons.

Pumps and heat exchangers – There might exist size limitations with some of the high pressure slurry pumps and

heat exchangers

Scale-Up methodology – Program management would ideally scale up the maximum train size on a gradual basis

to minimize the risk exposure on commercial projects. This would suggest initial commercial projects would be

limited to smaller train sizes.

Based upon the above, it was expected that the maximum size of a CO2 train for initial commercial projects

would be limited to around 200-400 MW in size. The various issues mentioned above were addressed after the pilot

operation and gradually the maximum size of a train rose to 400 MW and higher. The development for Wet Flue

Gas Desulphurization systems was a precedent for this approach.

Later process design work and system analysis eventual progressed the capacity of a single train to be suitable for

an 800 MW coal power plant. Nevertheless some of the equipment still required parallel installation.

6.3. Results from EONCAP Karlshamn

EONCAP Karlshamn pilot plant was designed to

remove at least 90% of the CO2 from the flue gas. The

limited raw data was considered to plot CO2 capture

efficiency as function of flue gas flow rate. The pilot

plant demonstrated that at steady state conditions, the

average overall CO2 efficiency is between 81 and 96%

depending on the operating variables established during

test operation. As a result of achieving CO2 removal

efficiencies, EONCAP Karlshamn project demonstrated

the fundamental viability of the carbon capture

technology in real world conditions such as the inevitable

starts and stops of a large power plant, changes in

temperature and humidity and the environmental hurdles

that go along with using any chemical process

EONCAP Karlshamn operation confirmed that the

ammonia slip from water wash system and direct contact cooler system is controllable. Ammonia emissions from

the direct contact cooler (DCC2) are a strong function of pH, temperature and L/G ratio. At Karlshamn, the gas

analyzer system was not able to produce reliable results because of fog formation in the system. Due to the difficulty

of measuring this parameter, no reproducible emission measurement out of the DCC2 system was possible.

In the Chilled Ammonia Process, there was no sign of solvent degradation after regenerating CO2 loaded rich

solvent at high temperatures and operating more than 2,000 hours. The testing at different CAP plants confirmed

that the typical gas contaminants (SOX, HCL, HF and NOX) do not degrade the CAP solvent.

The CAP solvent showed higher CO2 absorption capacity, high degradation resistance and lower corrosion rate

than MEA. As the solvent capacity establishes the solvent circulation rate, it has a major impact on the absorber

size, piping system, pumps and size of the regenerator system.

The thermal energy demand for the regenerator and the stripper during operation of the pilot plant in non-solids

mode and processing flue gas from an oil fired source was determined to be at 3.9 GJ/tCO2, having an average CO2

capture efficiency of 89%.

70

75

80

85

90

95

100

4000 5000 6000 7000 8000

Over

all

CO

2 C

ap

ture

Eff

icie

ncy

(%

)

Flue Gas Flow Rate (m3/hr)

Design: 90%

Removal

Figure 8: Overall CO2 Capture Efficiency


6.4. Results from AEP Mountaineer

American Electric Power (AEP) and GE Power

successfully operated the CCS validation project at

AEP’s Mountaineer Plant in New Haven, WV. The

project, the world’s first facility to both capture and store

carbon dioxide (CO2) from a coal-fired power plant,

represents a successful scale-up of ten times the size of

previous field pilots (WE Energies Pleasant Prairie,

EONCAP Karlshamn).

All the achievements listed below were confirmed

during steady-state operation of the CCS validation plant.

The Availability was measured during 30 days in March

of 2011. The correction of the energy penalty numbers

are based on project specific abnormalities (includes

agreed upon adjustments for heat exchanger

modifications, expected temperature approach) and were

reviewed and approved by the owner, American Electric

Power, AEP.

The first phase of the CO2 capture project, which

began capturing CO2 in September, 2009 and started

storing it in October, 2009, underwent mechanical and

equipment modifications in the Fall of 2010 that

contributed to the success of the project. The plant was

operated until June 30th

, 2011 with a focus on

maximizing CO2 injection.

The plant was originally designed to capture 75% of

the CO2 in the flue gas. The test results in Figure 9 show

that this value was continuously reached at design flue

gas feed flow of about 185,000 lbs/h.

Also it could be shown (see Figure 10) that the product purity can be maintained reliably to fulfill even the

strictest requirements for enhanced oil recovery applications. At the same time the Ammonia slip into the CO2

product is kept well below 20 ppmv so those unwanted losses are also minimized.

In optimization studies done during this project it was found that there is little energy advantage between

optimized CAP systems for solids versus non-solids operation. However, running a design based on solids operation

in non-solids mode significantly impacts energy consumption. For example the optimal internal heat recovery

configuration (i.e. rich/lean heat exchanger network) is different between a “solids” design and a “no-solids” design.

Therefore corrected values were determined in order to give representative figures for key performance indicators

like specific thermal energy consumption. Table 1 is giving an overview on the key performance indicators that

were accomplished. Based on the test results the potential for a CAP system, featuring a design optimized to the

Mountaineer operating scheme, was evaluated. The related expected energy consumption for such plant is listed as

“corrected” value.

An economic study was performed using the updated design basis for CAP from the work done during the

Mountaineer project. The study scaled up the technology to model its application and integration on a 750-MW net

USC PC base plant with 1100°F (593°C) steam conditions and 90% CO2 capture. Based on the study, the efficiency

loss when applying CAP was calculated to be 9.5 percentage points and the increase in LCOE compared to the base

plant was nearly doubled (the LCOE increased by 59 $/MWh). Although, through continuous improvements and

technology developments the LCOE is projected to be significantly reduced in the future.

Figure 9: CO2 capture rate at AEP Mountaineer PVF.

Figure 10: CO2 Product Quality


Table 1: PVF performance

Parameter Unit Value

CO2 purity

Availability

CO2 captured

CO2 stored

Capture rate (CR)

Specific Thermal Energy Consumption

Ammonia Emission

%

%

tons

tons

%

GJ/tCO2

ppmv

>99.9

97

51’173

37’404

65-85(designed for 75)

2.8 (measured) at 75% CR

2.2 (corrected)

<10

If the cooling requirements can be reduced for chilling the ammonia, as is the case with the SAFS and also if

lower-temperature cooling water is available, the increase in LCOE can be as low as 50$/MWh.

6.5. Results from TCM Verification Plant, Mongstad

Despite all these changes in concepts along the way, the TCM Verification Plant delivered the performance for

more than 1900 hours. Two different flue gases were tested during this period. One flue gas was generated by a CHP

plant using natural gas feed. The other flue gas was derived from the refinery fluidized catalytic cracking

regenerator (RFCC). Major difference between these two flue gases is in the CO2 concentration; the CHP flue gas

contained about 3-5% of CO2, whereas the RFCC flue gas had CO2 concentrations of 13- 15.1%. It shall be

mentioned that TCM was GE’s first installation processing CO2 from industrial sources like the RFCC flue gas.

Overall, the TCM test campaign on CAP presented excellent opportunities to demonstrate the effectiveness of

this carbon capture technology and also some of the areas of improvement. The major accomplishment from this

campaign is the demonstration of the process effectiveness on different flue gas sources. During the several months

of CAP operation, the process was very effective in capturing CO2 efficiently from both CHP as well as RFCC flue

gas. This was accomplished with no reduction in solvent quality or with no emission issues after initial start-up. The

NH3 emission from the flue gas stack as well as CO2 product was well within the environmental limits.

6.5.1. CHP gas testing

During the CHP campaign, 85% CO2 removal was

consistently achieved with the plant operating at 90%

design gas flow rate. The plant data was compared with

model predictions with some deviations observed and

reported.

Particularly mentioned should be the operating period

after week 8 of the CHP flue gas tests, where despite

significant adverse events, the unit was able to maintain

design flow rates and CO2 capture rates above 80%.

Taken together, these achievements showed the inherent

robustness and flexibility of the CAP technology in

meeting operating challenges and adjusting to changing

operating boundary conditions.

The Residual Flue Gas stream is the primary source

for NH3 discharge to the atmosphere. The level of

ammonia present in the residual flue gas returned to the

atmosphere is an indicator of the effectiveness of the flue gas systems downstream of the absorbers. The process

objective for ammonia in this stream was 2 ppmv. Once the system settled down after the initial weeks of operation,

the readings showed variance in the 2 to 4 ppmv range.

Figure 11: TCM CO2 capture efficiency


Different external events caused spikes in the

ammonia levels that can be noted from the charts. More

general fluctuations in the ammonia concentration in the

residual flue gas leaving the DCC2 correspond with

change-outs of the sulphuric acid totes.

During the CHP test program Ramboll, an analytical

company, executed an isokinetic sampling campaign. In

their report amines, nitrosamines, total N-Nitrosamine

(TONO) compounds, aldehydes, and ammonia

measurement results were given. The organic compounds

were all below the detectable limits for the instruments.

Ammonia was detected at 0.5 ppmv, which is less than

the 2 ppmv design objective.

Ammonia is also discharged with the CO2 product.

The level of ammonia in the CO2 Product is an indicator

of the effectiveness of the regenerator. During the period where data was available, the process objective of 10 ppmv

was generally met. Occasional excursions were attributed to transient operating disruptions.

For CAP solution, ammonia is diluted from its delivered concentration to 17 wt%. The literature suggests that

aqueous ammonia systems below 20% concentration require minimal special handling or permitting. As CO2 is

captured, free ammonia forms ions including ammonium, carbamate, carbonate, and bicarbonate to reduce its

concentration to less than 2 wt%.

Different CAP Unit Operations have different operating conditions. Absorbers operate at 1.1 bara and at

temperatures below 35°C. The Regenerator operates at 19.5 barg and 150°C. With the modifications in place, the

NH3 Stripper operates between 1.0 barg / 125°C and 5.0 barg / 165°C. At these conditions, the ionic solution is not

flammable.

These process conditions have been consistently demonstrated during the TCM Verification Plant operations,

without any significant degradation to the solvent in terms of capture efficiency. A higher than expected ammonia

loss from the final absorber resulted in increased sulfuric acid usage. This is expected at the partial pressure of CO2

operated at the top of the absorber column. This issue is the focus of an optimization program currently underway.

The thermal energy demand for the regenerator and the stripper during operation of the pilot plant in non-solids

mode and processing flue gas from a gas fired source was determined to be at 3.0 GJ/tCO2, having an average CO2

capture efficiency of 87.4%.

6.5.2. RFCC gas testing

From April to July, 2014, the CAP Unit at the TCM

operated a test campaign on RFCC flue gas and

demonstrated its ability to meet the design CO2 capture

efficiency of 85%. The influence of different process

parameters in the Regenerator, and Ammonia

Wash/Stripper systems was documented through a

parametric test series that focused on minimizing steam

demand and sulfuric acid usage as the primary dependent

variables.

The test series illuminated how each of the parameters

affected the primary objectives. At a high stripper

pressure, the final week of operation was sustained at

85% CO2 capture and a steam demand of 2.6 GJ/tCO2

Figure 12: TCM NH3 emissions via flue gas

Figure 13: RFCC Capture Efficiency


removed, without correction for heat losses. During this period, a complete set of validation data was collected for

analysis. The data was reconciled using GE’s CAP simulation model where the measured specific heat consumption

of 2.6 GJ/tCO2 compared well compares to a simulated value of 2.3 GJ/t CO2 that considered with variation attributed

to deficiencies in heat recovery from the lean solution.

Table 2: RFCC test campaign parameters

Parameter UOM Value

Flue Gas Flow Rate Sm3/hr 24800 to 38500

CO2 Concentration in Flue Gas Vol % 13.0 to 15.1

Stripper Pressure barg 0.9 to 4.9

Regenerator Pressure barg 19

CO2 purity % >99.9

Capture rate (CR) % 83-89(designed for 75)

Specific Thermal Energy Consumption GJ/tCO2 2.6 (measured) at 85% CR

Ammonia Emission ppmv <10

The operating data for all key parameters showed the general capability of the technology for conforming to the

design basis. Taken together, these findings support the design capabilities of GE, which incorporates the lessons

learned from the TCM Verification Plant that operated in situ under Mongstad conditions with a local operations

team and a design team familiar with the tenets of site protocols and guidelines.

After the simulation tools were validated against the results of the TCM tests a study was performed using the

updated design basis for CAP from the work done during the Mongstad project. The study scaled up the technology

to model its application and integration on an 800-MW net USC PC base plant with 600°C steam conditions and

90% CO2 capture. The flow scheme featured non-solids operation. Based on the study the specific heat energy

consumption was determined to be as low as 2.2 GJ/tCO2, when cooling water at adequate temperatures is available.

7. Conclusion

The development of the CAP technology began with laboratory bench-scale experiments to confirm that aqueous

ammonia solution effectively absorbs CO2 with sufficiently low vapor phase ammonia emissions at reduced

temperatures. From these results, a technology development program was initiated to scale-up and validate the

process for commercialization.

The approach outlined in this article is illustrative of industrial scale process development and improvement. The

iterations made in the development effort, as information from the different development stages was obtained to set

environmental & economic targets, develop predictive tools and models for process optimization, and to support

validation efforts at operating facilities, were described.

The CAP technology was applied to capture CO2 from different flue gas sources: SRI/Vaxjo Bench Pilot

(synthetic gas containing CO2), WE Energies industrial scale CAP facility (Coal), EONCAP Karlshamn industrial

scale CAP CO2 capture facility (High Sulfur Oil), AEP Mountaineer PVF (Coal), TCM Mongstad (Gas, Industrial

Sources).

In the SRI pilot plant the basic process concepts of CO2 capture using Ammonium carbonate, first in solid-mode,

later, after relocation to Växjö, also for non-solid mode were proven. Areas for undesired solid formation out of the

gas phase were detected. The WE Energy pilot was the first installation on real flue gas showing the capabilities of

the process with capture rates of up to 89% while having a low Ammonia slip. Solid-mode operation showed to be

challenging and induced the switch to non-solid-mode. With the EONCAP Karlshamn pilot, processing heavy oil


flue gas with high SOx and NOx concentrations, the non-solid-mode operation was proven and valuable information

about materials of construction were gained. The AEP Mountaineer pilot was the first plant in the world to feature

the whole post CCS chain and furthermore design improvements, derived from Karlshamn and WE Energy

operation, were realized and showed effective. TCM Mongstad finally proved that the CAP can be operated under

feasible boundary conditions with a competitive performance also for flue gas sources other than utility boilers.

The evolution of the thermal energy demand can be seen from Figure 14. Associated with the improvement of the

thermal energy demand over the evolution of the CAP there was also an increase in capture efficiency. In the

beginning the plants were able to achieve about 75% in non-solids mode whereas the TCM Mongstad plant achieved

up to 90% CO2 capture.

There were improvements

identified during the development

program that will be introduced in

the design for any future

demonstration project. This is only

possible because the fundamental

design tools and methods have

been validated and allow effective

implementation of new features.

Reference Plant calculations have

shown that with a dedicated CAP

system operating in non-solids

mode the specific heat

consumption for the post-

combustion capture of a coal fired

power plant is as low as

2.2 GJ/tCO2.

In comparison, conventional

amine-based solvents introduce a

variety of practical problems:

costly amine solutions, a high rate

of corrosion of the process

equipment and a high rate of amine degradation in the presence of oxygen. In general oxidative degradation mostly

occurs at short times and low temperature with contact in the absorber, but at a rather low rate and at longer and

higher temperature in the stable regenerator. The degraded solvent has to be replaced with make-up and this can be a

significant cost in the other CO2 capture processes like the amine-based ones. The degradation characteristics and

environmental impact of the CAP solvent were also investigated. Oxidative degradation does not occur due to the

presence of oxygen in the flue gas. The formation of heat stable salts leading to a loss of the solvent occurs with the

co absorption of residual SOx entering the absorber with the CO2 rich flue gas.

Several Front End Engineering & Design (FEED) efforts for larger-scale demonstrations of the CAP process

have been carried out, with significant design efforts conducted for these projects, including the 1.5 million tons per

year AEP Mountaineer II project and another 1 million tonne per year CCS project in Alberta, Canada.

Currently, GE is extending CAP technology into other applications and industries involving Urea, Methanol,

Petroleum Refineries, and Soda Ash Production where product yield is further increased when flue gas CO2 is

reused further downstream in the process. By integrating CAP technology into these processes, there is an

opportunity for improving production efficiency in a cost effective manner.

0

2

4

6

8

10

12

14

16

18

20

0

1

2

3

4

5

6

7

8

9

10

Väx

jö P

ilo

t R

egen

erat

or

(Syn

th,

no

n-s

oli

d m

od

e)

WE

En

ergy

(Co

al, so

lid

mo

de)

EO

NC

AP

Kar

lsh

amn

(Hea

vy

Oil

, no

n-s

oli

d m

ode)

AE

P M

oun

tain

eer

(Co

al, n

on

-soli

d m

od

e)

TC

M M

on

gst

ad

(RF

CC

, n

on

-soli

d m

od

e)

Lat

est

Sch

eme

(Co

al, n

on

-soli

d m

od

e)

TC

M M

on

gst

ad

(Gas

, n

on

-soli

d m

ode)

CO

2 P

rod

uct

ion

[t/

h]

En

erg

y D

eman

d [

GJ

/tC

O2]

Figure 14: Thermal Energy Demand and CO2 Production Capacity Evolution

> 20 t/h


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chilled ammonia process scale-up and lessons learned

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