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Pre‐Feasibility Study for Establishing a Carbon Capture Pilot Plant in Mexico (World Bank Contract 7175527)

Final Report

by Nexant, Inc.

In partnership with: Bechtel Corporation

May 18, 2016

Final Report: Pre‐Feasibility Study for Establishing a Carbon Capture Pilot Plant in Mexico 2

Disclaimer

This study report was prepared by Nexant under a contract with the World Bank. Neither Nexant nor any of its employees or team members make any warranty, express or implied, or assume any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represent that its use would not infringe upon privately own rights. Reference herein to any specific commercial process, product or service by trade name, trademark, manufacturer, or otherwise, does not necessarily constitute or imply its endorsement, recommendation, or favoring by any entity identified herein.

Task 1, the Technology Evaluation Study, was performed, in part, based on information that was provided to Nexant under the terms of Non-Disclosure Agreements with several technology licensors. No third-party proprietary information and/or data are directly revealed in the report. In performing the study, Nexant had to adjust some of the data and fill in any missing information, thus rendering the study results and conclusions as only Nexant’s interpretation of the technologies.

While it is believed that the information contained in this report will be reliable under the conditions and subject to the limitations set forth herein, Nexant cannot guarantee the accuracy thereof. The views and opinions expressed herein and, in particular, in the documentation that constitute this study are specifically those of the authors of this study. The use of this report or any information contained therein shall be at the user’s own risk.

Executive Summary


EXECUTIVE SUMMARY

E.1 PROJECT BACKGROUND

The subject study was performed as part of an ongoing World Bank funded project to develop

capacity for carbon capture, utilization and storage technology (CCUS) in Mexico. This project has

the overall objective of supporting Mexico’s Secretaria de Energia (SENER) and other Government of

Mexico (GoM) stakeholders with the implementation of the Mexican CCUS roadmap. The ultimate

goal is to successfully develop and deploy CCUS in the electricity and oil and gas industries in Mexico

as well as in others, such as iron and steel, cement and chemical industries.

An integral and critical part of this Mexican CCUS roadmap is the design, construction, and operation

of a CO2 capture pilot plant, which would demonstrate the potential and feasibility of capturing CO2

from natural gas combined cycle (NGCC) power plants in Mexico. This endeavor will create a

knowledge base for the various stakeholders and the experience gained from this study will

hopefully allow them to develop larger projects in the future and further advance the application of

CCUS in Mexico.

E.2 STUDY OBJECTIVES

The Nexant team was tasked to carry out a pre‐feasibility study to: 1) assess and recommend the

most appropriate commercially‐available post‐combustion capture technology for NGCC power

plants in Mexico, and 2) develop a conceptual design of a capture pilot plant to be located at the

250 MW Poza Rica NGCC generating station in the State of Veracruz. The pilot plant conceptual

design was to be developed with sufficient process details in order to enable the preparation of a

front end engineering design (FEED) package as part of a Phase II activity for the project. The FEED

preparation is not part of the current pre‐feasibility study.

It should be noted that initially another power plant, Dos Bocas, which is also located in the state of

Veracruz, was identified as a potential site for the study as well. However, the project team was

later informed that Dos Bocas would not be a suitable site, as the power plant is scheduled to be

shut down in 2018.

E.3 WORK SCOPE AND DELIVERABLES

The project work scope consists of five major tasks as follows:

Task 1 – Technology Selection, Evaluation and Recommendation of Best Available NGCC Post‐

Combustion CO2 Capture (PCC) Technologies

Subtask 1.1 ‐ Plant and Site Data Requisition and Preparation of a Study Design Basis

Subtask 1.2 – Project Kickoff Meeting and Site Visit

Subtask 1.3 – Technology Survey Questionnaire Preparation

Subtask 1.4 – Technology Screening, Evaluation and Selection

Task 2: Interim Report Meeting with Recommendations

Task 3: Pilot Plant Feasibility Design

Executive Summary


Subtask 3.1 – CO2 Capture Pilot Plant Process Design

Subtask 3.2 – NGCC/PCC Integration

Task 4: Final Report

Task 5: Workshop

A copy of the Project Work Scope/Terms of Reference, as amended on September 25, 2015, is

included in Appendix B.

The Task 1 Report (delivered as part of Task 2) summarizes all work performed under Task 1. The

Task 1 results were presented at a project review meeting and workshop, which were organized by

the World Bank and SENER on January 27‐29, 2016.

The Task 3 report describes the work performed under Task 3 ‐ Pilot Plant Feasibility Design.

A final Workshop for the project, as Task 5 activity, was given to the World Bank and the GoM

stakeholders on May 11, 2016.

E.4 TASK 1 – TECHNOLOGY SELECTION, EVALUATION AND RECOMMENDATION OF BEST AVAILABLE PCC TECHNOLOGIES

E.4.1 Pre‐Screening and Selection of PCC Technologies

Based on previous work conducted by the US Department of Energy (USDOE) and Electric Power

Research Institute (EPRI) assessing the technology readiness level (TRL) of different types of PCC

technologies, as well as Nexant’s own assessment of current state‐of‐the‐art PCC technologies, the

Nexant team recommended to the World Bank that the pre‐feasibility design should be focused on

solvent‐based absorption processes. This recommendation was made in order to meet the World

Bank and the GoM team’s desire to build and complete operation of the Poza Rica NGCC pilot plant

by 2019, based on commercially‐available PCC technology for near term deployment. This

recommendation was discussed and accepted by the World Bank, SENER and the Comisión Federal

de Electricidad (CFE) representatives at the Project Kickoff (KO) meeting in the CFE office on October

27, 2015. A list of ten potential advanced solvent‐based absorption PCC technology

developers/licensors were collectively identified, selected and asked to participate in the study. Of

the ten PCC licensors contacted, six responded positively and were willing to participate while four

declined, for various reasons. Table E‐1 summarizes the PCC licensors’ responses.

Nexant developed a study Design Basis, based in part on the Poza Rica plant data that were provided

by CFE. Based on the study Design Basis, a Technology Survey Questionnaire was prepared to

collect process information from the six PCC technology developers. The responses received from

the questionnaire, supplemented with Nexant team’s in‐house knowledge, formed the basis for the

technology screening, evaluation and comparison of the processes.

Table E‐1 List of PCC Licensors Participation Responses

Executive Summary


Accepted to Participate Declined to Participate

Alstom (Advanced Amine Process)

BASF

Fluor

HTC

MHI

Shell Cansolv

Aker Solutions

CO2 Solutions

Hitachi

Siemens

E.4.2 Overall NGCC Performance Before and After Full‐Scale PCC Retrofit

Nexant developed a reference generic 30% MEA‐based PCC process design to serve as a benchmark

for comparing the performance of the six PCC technologies participated in the study, assessing their

claimed improvement and filling in any missed data that are needed for their full‐scale Poza Rica

retrofit analysis. A companion power train model was also developed for the Poza Rica NGCC plant

to estimate its performance before and after full‐scale PCC retrofit. Figure E‐1 shows a simplified

flow scheme of the retrofitted plant and its PCC interfacing requirements.

Table E‐2 summarizes the overall Poza Rica plant performance and power balance before and after

PCC retrofitting, for the generic 30% MEA design, as well as the six proprietary PCC technologies. All

six of the proprietary amine‐based PCC technologies show a lower heat of regeneration compared

to generic 30% MEA, by about 20 to 25%. Within the group, however, the difference is rather small,

only ± 3%. As a result, all six technologies show an improvement in overall efficiency over the

generic 30% MEA based retrofitted Poza Rica plant – a loss of plant efficiency ranging from 8.4 to 9.3

percentage points instead of 9.9 percentage points.

E.4.3 Poza Rica NGCC PCC Retrofit Economic Evaluation Results

The six PCC technologies were compared and ranked using the Cost of Electricity (COE) as the figure‐

of‐merit to estimate Poza Rica’s potential economic penalty with CO2 capture. COE is a measure of

the revenue received per net MWh that provides the stipulated internal rate of return on equity

over the entire economic analysis period.

Table E‐3 shows the incremental COE for each of the PCC technologies retrofitted into the Poza Rica

NGCC plant. The various PCC licensors’ technologies were ranked for comparative purposes

according to their incremental COEs; the lower the incremental COE, the higher the ranking.

Executive Summary


Figure E‐1 Post‐PCC Retrofit Poza Rica NGCC Simplified BFD

Existing NGCC, No Change Design & Cost by Nexant Design & Cost by PCC Licensor Design & Cost by Others

3 IdenticalSteam Turbines

Single GT/HRSG

HP SH Steam

CO2-Rich Flue Gas

Post-PCC Retrofit Poza Rica NGCC

GT/HRSG:1. 163 MW Siemen/Westinghouse GT2. 1,595 MMBtu(LHV)/Hr NG Firing3. 900 MMBtu/Hr HRSG Abs Duty4. 580,000 #/Hr HP Stm

Three Identical Siemen Stm Turb:1. 192,000 #/Hr HP SH Stm Each2. 1,100 psig/975 F HP SH Stm3. 27 MW Gross Pre-PCC Each

PCC Plant CO2 Recovery

PCC Plant CO2

Compression

LP CO2

S/CCO2

CO2-Lean Flue Gas Vent from Absorber top

Flue Gas Booster Blower

Other NGCC Plant Modifications:1. CW/CT Systems2. Raw & Filtered Water Systems3. RO/De-Ionized Water System 4. Electrical Distribution Systems5. Inter-Connecting Pipings

Super-CriticalCO2 to EOR Via

Pipeline

BP Power Recovery Turbine

LP Sat SteamCondensat

De-Superheater

Executive Summary


Table E‐2 Poza Rica NGCC Pre‐PCC vs Post‐PCC Retrofit Performance Summary

See Note 1 Pre‐PCCGeneric 30%

MEA PCCAlstom BASF Fluor

HTC

PurenergyMHI Shell CanSolv

NGCC CO2 Emissions, MTPD (STPD) 2297 (2532) 345 (380) 328 (362) 344 (379) 229 (252) 346 (381) 346 (381) 342 (377)

Recovered CO2 Product, MTPD (STPD) 0 (0) 1952 (2152) 1969 (2170) 1953 (2153) 2068 (2280) 1951 (2151) 1951 (2151) 1955 (2155)

% CO2 Capture 0 85% 86% 85% 90% 85% 85% 85%

Power Balance, MW

Generation

Gas Turbine Gross Output 166.6 166.6 166.6 166.6 166.6 166.6 166.6 166.6

Steam Turbine Gross Output 82.5 39.6 49.6 49.4 46.0 46.7 49.2 49.4

Back Pressure Turbine 0 21.6 17 17 18 18 17 16.7

Total Gross Output 249.1 227.8 232.8 232.7 231.0 231.3 232.6 232.7

Auxiliary Consumption

Existing NGCC Plant Parasitic Loads 7.2 7.2 7.2 7.2 7.2 7.2 7.2 7.2

Flue Gas Blower 0 8.8 8.8 8.8 8.8 8.8 8.8 8.8

PCC + CO2 Compression + Plant Mods 0 16.1 17.3 14.1 16.6 14.0 15.7 14.2

Total New PCC Parasitic Load 7.2 32.0 33.3 30.1 32.5 29.9 31.7 30.1

Net Power Plant Export, MW 241.9 195.8 199.5 202.6 198.4 201.4 200.9 202.5

Delta Plant Export, MW ‐46.1 ‐42.4 ‐39.3 ‐43.4 ‐40.5 ‐41.0 ‐39.3

% Plant Export Reduction ‐19% ‐18% ‐16% ‐18% ‐17% ‐17% ‐16%

Net Plant Heat Rate, MJ/kWh (Btu/kWh) 6.94 (6584) 8.57 (8134) 8.42 (7984) 8.28 (7860) 8.46 (8025) 8.33 (7907) 8.35 (7926) 8.29 (7862)

Net Plant Efficiency, % LHV 51.8 42.0 42.7 43.4 42.5 43.2 43.1 43.4

Delta Plant Efficiency, percentage pt ‐9.9 ‐9.1 ‐8.4 ‐9.3 ‐8.7 ‐8.8 ‐8.4

Incremental Water Import, lpm (gpm) 0 (0) 1537 (406) 3058 (808) 1718 (454) 1618 (427) 1328 (351) 2561 (676) 1580 (417) Note 1: Values presented here are Nexant’s interpretation of the data provided by the PCC licensors.

Executive Summary


Table E‐3 Incremental PCC Costs for Various Licensors

Generic

30% MEA

PCC Design Alstom

BASF /

Linde Fluor

HTC

Purenergy MHI

Shell

CanSolvCAPEX Estimate, $MM US USGCPCC Plant + CO2 Compression

[Note 2] 181.4 234.7 187.7 181.9 194.5 178.8 194.9

Flue Gas Blower 14.2 14.2 14.2 14.2 14.2 14.2 14.2

Poza Rica Plant Modifications 32.8 32.4 30.4 31.9 29.1 30.9 30.4

TOTAL 228.4 281.4 232.3 228.0 237.8 223.9 239.5

O&M Estimate, $MM US

Variable Costs [Note 3] 7.6 7.6 7.6 7.5 7.3 7.5 7.5

Fixed Costs 11.0 13.3 11.1 10.9 11.4 10.8 11.6

TOTAL 18.5 21.0 18.7 18.5 18.7 18.3 19.1

37.6 41.4 35.3 36.5 36.2 35.1 36.0N/A 6 2 5 4 1 3Ranking based on COE

Estimated Post‐Combustion CO2 Capture Costs

Incremental Costs to Poza Rica

NGCC without CO2 Capture

[Note 1]

Estimated Cost of Electricity

(COE), $/MWh [Note 4]

Note 1 ‐ Values presented here are Nexant’s interpretation of the data provided by the PCC licensors.

Note 2 ‐ All figures except Nexant’s 'Generic 30% MEA Design' are based on vendor‐provided data, which are considered proprietary.

Note 3 ‐ Major component is the amine replacement costs, which are considered proprietary.

Note 4 ‐ Incremental to estimated existing Poza Rica NGCC COE of $40.69/MWh

Executive Summary


Figure E‐2 Incremental COEs for Various Licensors after CO2 Capture Rate Adjustment for Fluor

36.5

35.1 35.3 36.0 36.2

41.4

35.0

25

30

35

40

45

Fluor MHI BASF Shell CanSolv HTC Purenergy Alstom

Increm

ental COE, $/M

Wh

Incremental COE based on Licensors' DataIncremental COE Adjusted for 85% CO2 Capture for Fluor

Executive Summary


E.4.4 Economic Evaluation Results after CO2 Capture Rate Adjustments

Table E‐2 shows the comparison of the six PCC technologies against 30% MEA, all at about 85% CO2

capture – except for Fluor. While Nexant’s questionnaire specified for a PCC design from the six

developers to capture 85% of the CO2 from Poza Rica plant flue gas, Fluor provided data based on a

capture rate of 90%. Nexant made the adjustments by pro‐rating Fluor’s total CO2 regeneration duty

from 90% to 85%; revising the PCC auxiliary power consumption, CO2 compression power

requirements and cooling duty; and reducing its costs accordingly. Figure E‐2 presents the revised

COEs graphically, before and after the CO2 capture rate adjustment for Fluor. With the adjustment,

the estimated COE is lower for Fluor compared to the other five PCC developers.

E.4.5 Conclusions and Recommendations

Within the level of data accuracy for the study, it would be reasonable to conclude that the top five

proprietary PCC technologies all have similar economic performance and it cannot be determined,

with certainty, that one is clearly superior to the others. If three ‘top of class’ candidates must be

chosen from the list based on their COE results, then these would have to be Fluor, MHI, and BASF,

as shown in Figure E‐2. However, final technology selection for future Poza Rica PCC implementation

would most likely need to take into other factors for consideration, such as process guarantee,

technology licensing fee, willingness to work with the GoM stakeholders to take on an active role in

the project, etc., as required.

The original Task 1 PCC technology evaluation objective was to select the best technology and then

have the technology licensor design and build a pilot plant to test the selected PCC process. This

means that only the selected amine technology can be tested due its proprietary nature. The Task 1

study results showed that it is not possible to choose the best PCC technology with any certainty

because there is very little performance and cost differences among the top few technologies. In

addition, there are almost no data regarding trace contaminant emissions, which can potentially

shut down a PCC process regardless of its performance or economic advantages.

Since none of the top proprietary PCC technologies stands out among the rest, and all of them are

amine‐based technologies that operate along the same basic principles as an MEA plant, therefore,

in order to proceed with the pilot plant design in Task 3, Nexant proposed that it be designed for

generic MEA, but with additional design features that grants it flexibility to allow for the testing and

validation of other amine‐based technologies. This recommendation was accepted by the World

Bank team, which subsequently amended the Terms of Reference (TOR) to accept a pilot plant

process design package based on generic MEA for Task 3, as shown in Appendix B.

E.5 TASK 3 – CO2 CAPTURE PILOT PLANT FEASIBILITY STUDY

E.5.1 Pilot Plant Size Selection

In order to proceed with the pilot plant design, an initial project task was to come up with a pilot

plant size agreeable to all parties. To facilitate that effort, Nexant performed an analysis and

presented the results showing the impacts of PCC pilot plant size on the Poza Rica NGCC plant

Executive Summary


performance and its various support facility demands, at the Oct 5, 2015 meeting at CFE’s office in

Mexico City. Since the general consensus is that MEA‐based PCC is the least efficient option out of

the six near‐commercial PCC technologies which are all amine‐based, a pilot plant designed for MEA

should be able to accommodate testing the other technologies with minimal pre‐investment

modifications to the capture plant design.

After reviewing the integration requirement for PCC pilot plant sizes ranging from treating 1% to up

to 25% of the flue gas from the Poza Rica NGCC gas turbine (GT), Nexant recommended that the PCC

pilot plant be sized to treat no more than 5% of the GT flue gas flow based on maximum utilization

of existing NGCC support facilities without adding new capacities.

Nexant provided its recommendation and rationale for the 5% pilot plant size selection to the World

Bank on January 27, 2016. Because actual pilot plant capital cost can only be developed after pilot

plant size is defined and its design is carried out, only an estimated relative capital cost curve was

provided during the preliminary size selection evaluation. In addition, since pilot plant funding and

operational length were not defined at the January 27 meeting, Nexant’s 5% pilot plant size

recommendation was based only on the plant’s technical viability and its potential impacts on the

Poza Rica plant operations. While it is desirable to have a relatively large pilot plant with the ability

to better assess technology scale up, it was also recognized that costs (both CAPEX and O&M) can

be prohibitive with a large scale pilot plant.

After the January meeting, subsequent discussions between the World Bank and the Mexican

entities consisting of Instituto de Investigaciones Eléctricas (IIE), SENER, and CFE were held and, with

potential project funding constraints in mind, a decision was made to size the PCC pilot plant to

treat 1% of the Poza Rica plant flue gas.

E.5.2 MEA PCC Pilot Plant System Design

A PCC pilot plant for Poza Rica was designed as a Task 3 activity. The design is fully integrated into

the Poza Rica plant operations. The pilot plant process design package contains sufficient definition

to facilitate FEED preparation during Phase II of this project by an experienced engineering,

procurement, and construction (EPC) company to validate the feasibility of the pilot facility. The

pilot plant design includes only the CO2 capture facility, plus support facilities and modifications

needed for the existing Poza Rica NGCC plant to support the PCC pilot plant operations. Captured

CO2 is to be vented, so a CO2 compression facility is not included.

The PCC pilot plant is designed to treat 1% of the Poza Rica NGCC flue gas and recover 85% of the

contained CO2. A feasibility study process design package was developed containing the following:

Simplified process flow diagram and description

Major stream flow heat, material and utility balances

Preliminary plot plan

Major equipment list and preliminary datasheets

Executive Summary


Specification of effluents

Description of integration requirements into the Poza Rica NGCC plant, and

Preliminary capital and operating cost estimates, including all catalysts and chemicals and utility

consumption estimates.

The pilot plant process scheme consists of three major processing steps: (1) Flue Gas Feed

Scrubbing, (2) Flue Gas CO2 Absorption, and (3) Amine Solution Regeneration. A total of three

operating scenarios were carried out. These were:

Design Case (Des) to size almost all pilot plant equipment. This represents an easily achievable

MEA operation that results in conservative equipment sizes.

Expected Operation Case (Exp) for expected pilot plant performances. This represents a

projected best achievable MEA operation based on Nexant’s past experiences with commercial

amine plants.

Absorber Inter‐Cooled Operation Case (IC) to size absorber inter‐cooling equipment. This

represents a projected achievable MEA operation based on a colder absorber bottom

temperature due to absorber interstage cooling.

The pilot plant process design details are summarized in the Task 3 Report and presented in Sections

8 through 13 of this Final Report.

E.5.3 Overall NGCC Performance Before and After PCC Pilot Plant Operation

The overall power balance, CW and CT loads of the Poza Rica NGCC with the PCC pilot plant design

case are summarized in Table E‐4. The existing pre‐PCC performance is shown for comparison

purposes. As can be seen from the summary table, due to the small size (1% flue gas slipstream) of

the pilot plant, the impact on overall NGCC plant operation is minimal.

Executive Summary


Table E‐4 Overall NGCC Balance and Performance

Pre PCC

Post-PCC (Design

Operation)Flue Gas Feed and CO2 Recovery Rates: Flue Gas Feed Rate, mTPD (STPD) N/A 387 (427) CO2 in Pilot PCC Feed Gas, mTPD (STPD) N/A 23 (25) CO2 in Recovered, mTPD (STPD) N/A 20 (22) CO2 Recovery Rate, % 0 85%Steam Consumption Rates: Reboiler Steam (4.1bara/151°C), mTPD (STPD) N/A 40 (45) Reboiler Steam, ton/ton CO2 Recovered N/A 2.07Output at Generator Outlet, kW: Existing Siemens/Westinghouse GT 166,570 166,570 Existing Siemens Steam Turbine (Total for 3 operating) 82,500 82,272 Total Gross Generation 249,070 248,842Parasitic Loads, kW: Existing NGCC Loads 7,213 7,213 PCC Pilot Plant CO2 Capture Loads 0 162Total NGCC/PCC Electrical Loads 7,213 7,375

Net Poza Rica Power Export, kW 241,857 241,467 Power Export, kW -- -391

Poza Rica CW/CT Duty Breakdown: MEA PCC Pilot Plant Pre PCC

Post-PCC (Design

Operation)Existing NGCC CW/CT Duty, GJ/hr (MMBtu/hr) 666 (631) 662 (628)New PCC CW/CT Duty, GJ/hr (MMBtu/hr) 0 6 (5)Total Poza Rica CW/CT Duty, GJ/hr (MMBtu/hr) 666 (631) 668 (633)

Overall Poza Rica NGCC Performance: MEA PCC Pilot Plant

E.5.4 Emissions and Discharges

Air Emissions

The PCC pilot plant will emit treated flue gas from the top of the absorber column and separated

CO2 from the stripper overhead drum. Both of these gases may potentially contain VOC emissions,

stemming from the amine and its degradation products. A water wash section was designed at the

top of the absorber using all the recycled reboiler condensate as the washing medium to reduce the

amine content of the treated flue gas to less than 1 ppmV. The PCC pilot plant is designed to be able

to reduce the wash water flow in order to test the minimum wash water quantity required to meet

the amine emissions limit.

Executive Summary


Nitrosamines and nitramines, both degradation products, are known carcinogens. The exact

concentrations of these degradation products in the emissions are unknown due to the lack of

published data. However, the pilot plant is set up to test for their concentrations in the treated flue

gas and CO2 vent with systems in place where gas samples can be taken for analytical measurement

to determine the emission levels.

Liquid Discharges

The PCC pilot plant uses steam from the NGCC plant to provide the reboiling duty to strip off the CO2

from the rich amine solution in the stripper column. The reboiler steam condensate is not returned

to the power plant, but rather used as wash water for the absorber and ultimately purged to the

waste water treatment facility. To operate the pilot plant, additional makeup water is required and

it has to go through the NGCC plant’s existing filtration and electrodialysis (ED) water treatment

systems, generating incremental waste that is also purged to the existing waste water facility for

treatment.

The reboiler condensate that is used for water wash removes most of the volatile and entrained

MEA in the treated flue gas. The wash water is expected to contain about 8 kg/h (18 lb/h) of MEA.

This water, depending on the power plant operator’s willingness, can be used as water makeup to

the MEA storage tank and/or as makeup water to the CT.

Solid Waste Discharge

The solid waste generated by the PCC pilot plant consists of reclaimer waste, spent activated carbon

and the spent filter media. These waste products are assumed to be hazardous and have to be

disposed of appropriately, most likely via incineration. A hazardous waste disposal company can be

contracted to collect and transport the solid waste to an incineration facility. It is recommended that

the PCC pilot plant operator approach PEMEX, which most likely has experience hiring waste

disposal companies to remove hazardous waste from their refineries, to gain access to such disposal

companies.

E.5.5 Poza Rica NGCC PCC Pilot Plant Cost Estimation

The capital cost of the MEA‐based PCC pilot plant is estimated, with a target accuracy of +/‐ 30

percent, using a major equipment (ME) factored estimation approach. Table E‐5 summarizes the

estimated capital cost for the PCC pilot plant.

The total capital cost includes cost allowances for the associated NGCC plant modifications and pilot

plant support facilities, which include the control and laboratory testing equipment plus trailer

costs. These are reported as single line cost items in in the cost estimate. Factoring in all of the

above‐mentioned costs, the estimated total plant cost (TPC) for the PCC pilot plant is about $22.1

million.

Executive Summary


Table E‐5 MEA PCC Pilot Plant Estimated Total Plant Cost

Costs, $1,000 Total

Major Equipment Costs

Columns and Internals 1,794Vessels and Tanks 78Heat Exchangers 233Blowers 522Pumps and Drivers 234Others – MEA Filter Package 78Others – Soda Ash Package 10Others – Ductwork 194Freight 125

Total Major Equipment Costs 3,268Bulk Material Costs 5,938Total Direct Costs 9,206Construction Indirect Costs 1,818Total Field Costs 11,025

Startup Vendor Repre 272Home Office Costs 2,288Plant Mod Allowance 400Control, Lab and Admin Trailer Allowance 3,000

Total Constructed Cost w/o Contingency 16,985Contingency (30%) 5,096Total Plant Cost 22,081

The operating and maintenance (O&M) costs for the MEA PCC pilot plant are allocated as either

fixed or variable operating costs. Fixed O&M costs are essentially independent of the actual capacity

factor, number of hours of plant operation or amount of kilowatts produced. They consist mainly of

costs of employee salaries, taxes and insurances. Variable O&M costs are directly proportional to

the PCC pilot plant throughputs and include the purchase costs of the pilot plant’s process

consumables, catalysts and chemicals. Table E‐6 summarizes the estimated annual O&M costs and

percentage breakdown MEA PCC pilot plant.

The PCC pilot plant’s annual O&M cost is $2.5 million. The fixed O&M costs, at $2.1 million, make up

the bulk of these costs, at 84% of the total O&M costs. About half of the fixed O&M costs stem from

the operating labor and overhead costs, consisting of the wages paid to the PCC plant operators and

other staff. These costs total $1.1 million, equivalent to 53% of the total fixed O&M costs. The

remaining 47% of the fixed O&M costs consist of the maintenance labor and material, insurance and

property taxes, which are estimated based on a percentage of the PCC pilot plant’s capital cost.

The variable O&M costs make up the remaining 16% of the total incremental O&M costs, at about

$0.41 million. The process consumables total $0.16 million, while the catalysts and chemicals cost

$0.25 million. The export power losses make up almost all (98.5%) of the process consumables

costs. The costs of the other process consumables, i.e. the raw water import and waste water

Executive Summary


disposal costs, are minimal (1.5%) compared to the export power losses. Similarly, the bulk of the

catalysts and chemicals costs consist of amine/additive makeup and disposal costs (89%), while the

water treatment chemicals and filter replacements are relatively minor costs (11%).

Table E‐6 Estimated O&M Costs for PCC Pilot Plant Operation

$1,000/year %

PROCESS CONSUMABLE COSTS (VARIABLE):

River Water Import 2.2 0.1

Process Waste Water Disposal 0.1 0.0

CO2 Product Export - -

Export Power Losses 156.2 6.1

TOTAL PROCESS CONSUMABLES 158.5 6.2

CATALYSTS & CHEMICAL COSTS (VARIABLE):

Water Treating Chemicals 18.7 0.7

PCC Amine/Additives Makeup & Disposal 223.1 8.8

PCC Carbon/Filters/Dessicant Replace & Disposal 7.4 0.3

TOTAL CAT & CHEMICALS 249.3 9.8

FIXED COSTS:

Operating Labor 744.0 29.2

Maintenance Labor 331.2 13.0

Maintenance Material 220.8 8.7

Overhead Charges 400.0 15.7

Insurance & Property Tax 441.6 17.3

TOTAL FIXED COSTS 2,137.6 84.0

TOTAL OPERATING & MAINTENANCE COST 2,545.4 100.0

Post-PCC (Design Operation)

Annual Operating Cost: MEA PCC Pilot Plant

Table of Contents


EXECUTIVE SUMMARY ................................................................................................................... 3

E.1 PROJECT BACKGROUND .................................................................................................................. 3 E.2 STUDY OBJECTIVES ........................................................................................................................ 3 E.3 WORK SCOPE AND DELIVERABLES ............................................................................................... 3 E.4 TASK 1 – TECHNOLOGY SELECTION, EVALUATION AND RECOMMENDATION OF BEST AVAILABLE PCC TECHNOLOGIES ........................................................................................................... 4

E.4.1 Pre‐Screening and Selection of PCC Technologies ......................................................... 4 E.4.2 Overall NGCC Performance Before and After Full‐Scale PCC Retrofit ............................ 5 E.4.3 Poza Rica NGCC PCC Retrofit Economic Evaluation Results .......................................... 5 E.4.4 Economic Evaluation Results after CO2 Capture Rate Adjustments ............................ 10 E.4.5 Conclusions and Recommendations ............................................................................ 10

E.5 TASK 3 – CO2 CAPTURE PILOT PLANT FEASIBILITY STUDY ......................................................... 10 E.5.1 Pilot Plant Size Selection .............................................................................................. 10 E.5.2 MEA PCC Pilot Plant System Design ............................................................................ 11 E.5.3 Overall NGCC Performance Before and After PCC Pilot Plant Operation .................... 12 E.5.4 Emissions and Discharges ............................................................................................ 13 E.5.5 Poza Rica NGCC PCC Pilot Plant Cost Estimation ......................................................... 14

TASK 1 – TECHNOLOGY SELECTION, EVALUATION AND RECOMMENDATION OF BEST AVAILABLE PCC TECHNOLOGIES

1. INTRODUCTION ............................................................................................................ 26

1.1 PROJECT BACKGROUND ................................................................................................................ 26 1.2 STUDY OBJECTIVES ...................................................................................................................... 26 1.3 WORK SCOPE ............................................................................................................................. 26

2. PRE‐SCREENING OF CO2 CAPTURE TECHNOLOGIES ........................................................ 28

2.1 OVERVIEW OF CO2 CAPTURE TECHNOLOGY DEVELOPMENT ................................................................. 28 2.2 PRE‐SCREENING PCC TECHNOLOGIES .............................................................................................. 28 2.3 SELECTION OF PCC TECHNOLOGIES FOR DETAILED PROCESS EVALUATION ............................................... 32 2.4 PARTICIPATING PCC TECHNOLOGY LICENSORS .................................................................................. 33 2.5 QUESTIONNAIRE TO PARTICIPATING PCC LICENSORS .......................................................................... 33 2.6 QUESTIONNAIRE RESPONSES BY PCC LICENSORS ............................................................................... 34

3. DESIGN BASIS ............................................................................................................... 35

3.1 OBJECTIVE ................................................................................................................................. 35 3.2 OVERVIEW OF RETROFITTING POZA RICA NGCC FOR PCC .................................................................. 35 3.3 SITE‐RELATED CONDITIONS ........................................................................................................... 37 3.4 METEOROLOGICAL DATA .............................................................................................................. 37 3.5 PCC FEED AND PRODUCT PROPERTIES ............................................................................................ 37 3.6 PCC UTILITY REQUIREMENTS ........................................................................................................ 39 3.7 PROCESS WASTE STREAMS ........................................................................................................... 42 3.8 ENVIRONMENTAL AND EMISSIONS REQUIREMENTS ............................................................................ 42

4. TECHNOLOGY DESCRIPTION OF INTERESTED PCC LICENSORS ........................................ 43

4.1 ALSTOM ADVANCED AMINE PROCESS (AAP) ................................................................................... 43 4.2 BASF OASE® BLUE PROCESS ........................................................................................................ 46 4.3 FLUOR ECONAMINE FG PLUSSM ..................................................................................................... 50 4.4 HTC PURENERGY ........................................................................................................................ 53 4.5 MHI KM‐CDR PROCESS .............................................................................................................. 56 4.6 SHELL CANSOLV CO2 CAPTURE TECHNOLOGY ................................................................................... 59

Table of Contents


5. INTEGRATION METHODOLOGY FOR FULL‐SCALE PCC WITH POZA RICA NGCC ............... 63

5.1 INTRODUCTION ........................................................................................................................... 63 5.2 EVALUATION METHODOLOGY ........................................................................................................ 65 5.3 EXISTING (PRE‐PCC RETROFIT) POZA RICA NGCC MODEL PERFORMANCE ............................................ 66

5.3.1 Steam Cycle Performance ............................................................................................ 66 5.3.2 Overall NGCC Balance and Performance ..................................................................... 68

5.4 PCC DESIGN BASIS AND QUESTIONNAIRE TO SELECTED LICENSORS ....................................................... 69 5.5 FULL‐SIZE 30% GENERIC MEA‐BASED PCC AND CO2 COMPRESSION DESIGN ........................................ 69 5.6 POST‐PCC RETROFIT POZA RICA NGCC MODEL PERFORMANCE .......................................................... 70

5.6.1 Steam Cycle Performance ............................................................................................ 70 5.6.2 Overall NGCC Balance and Performance ..................................................................... 72

5.7 NGCC PLANT MODIFICATIONS REQUIRED FOR PCC RETROFIT ............................................................. 73 5.8 PRELIMINARY POST‐30% MEA PCC RETROFIT PLOT LAYOUTS ............................................................ 74

5.8.1 Preliminary PCC Plot Layouts ....................................................................................... 74 5.8.2 PCC Equipment Placement/Integration Guidelines ..................................................... 75

5.9 POZA RICA NGCC PCC RETROFIT ECONOMIC EVALUATION BASIS ........................................................ 79 5.9.1 Incremental Capital Cost ............................................................................................. 79 5.9.2 Incremental Operating Cost ........................................................................................ 80 5.9.3 Economic Evaluation Figure‐of‐Merit .......................................................................... 82 5.9.4 Poza Rica NGCC Economics for Full‐Size Licensor PCC Retrofit .................................... 84

6. RESULTS OF FULL‐SCALE PCC INTEGRATION WITH POZA RICA NGCC ............................. 85

6.1 POZA RICA NGCC PRE‐ AND POST‐30% MEA PCC RETROFIT PERFORMANCE ....................................... 85 6.2 POZA LICENSOR RESPONSES CHECK AGAINST GENERIC 30% MEA ....................................................... 86 6.3 POZA RICA NGCC POST‐PCC RETROFIT PERFORMANCE EVALUATION FOR ALL LICENSORS ........................ 87 6.4 POZA RICA NGCC PCC RETROFIT ECONOMIC EVALUATION RESULTS .................................................... 90 6.5 ECONOMIC EVALUATION RESULTS AFTER CO2 CAPTURE RATE ADJUSTMENTS ......................................... 93 6.6 ECONOMIC EVALUATION RESULTS SENSITIVITY TO PCC CAPEX ........................................................... 96 6.7 ECONOMIC EVALUATION RESULTS SENSITIVITY TO REBOILING DUTY ...................................................... 98 6.8 ECONOMIC EVALUATION RESULTS SENSITIVITY TO NATURAL GAS PRICES ............................................. 100 6.9 ECONOMIC EVALUATION RESULTS SENSITIVITY TO ANNUAL ON‐STREAM FACTOR (AOF) ........................ 100 6.10 ESTIMATED PCC PLOT SPACE REQUIREMENTS ................................................................................ 103

7. SUMMARY AND CONCLUSIONS .................................................................................. 104

7.1 SUMMARY AND CONCLUSIONS ................................................................................................... 104 7.1.1 Design Analysis of Retrofitting Poza Rica Plant for Generic 30% MEA‐Based PCC .... 104 7.1.2 Comparison of Six Advanced Amine‐based PCC Technologies .................................. 105

7.2 PCC TECHNOLOGY LICENSORS’ REVIEW AND COMMENT .................................................... 106

TASK 3 – PILOT PLANT FEASIBILITY DESIGN

8. INTRODUCTION .......................................................................................................... 108

8.1 PROJECT BACKGROUND .............................................................................................................. 108 8.2 STUDY OBJECTIVES .................................................................................................................... 108 8.3 WORK SCOPE ........................................................................................................................... 108

9. DELIVERABLES ............................................................................................................ 110

10. PILOT PLANT DESIGN BASIS ........................................................................................ 111

10.1 OBJECTIVE ............................................................................................................................... 111 10.2 OVERVIEW OF RETROFITTING POZA RICA NGCC FOR PCC ................................................................ 111

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10.3 SITE‐RELATED CONDITIONS ......................................................................................................... 113 10.4 METEOROLOGICAL DATA ............................................................................................................ 113 10.5 PCC FEED AND PRODUCT PROPERTIES .......................................................................................... 113 10.6 PCC UTILITY REQUIREMENTS ...................................................................................................... 115 10.7 PROCESS WASTE STREAMS ......................................................................................................... 118 10.8 ENVIRONMENTAL AND EMISSIONS REQUIREMENTS .......................................................................... 119

11. PILOT PLANT SIZE RECOMMENDATION ....................................................................... 121

11.1 INTRODUCTION .................................................................................................................... 121 11.2 PILOT PLANT INTEGRATION ARRANGEMENT AND SIZE SELECTION CRITERIA ........................ 121 11.3 DISCUSSIONS ........................................................................................................................ 123

11.3.1 Pilot Reboiler Steam Demands vs. HRSG IP and LP Steam Generation Capacity Consideration ....................................................................................................................... 123 11.3.2 Incremental Pilot PCC CW Loads vs. Existing NGCC CW/CT Capacity Consideration . 124 11.3.3 Net Power Export Loss ............................................................................................... 125 11.3.4 Incremental Raw Water Import Consideration ......................................................... 126 11.3.5 Pilot Plant Absorber Diameter vs. Transportation Limitation Consideration ............ 127 11.3.6 Relative Pilot Plant Capital Cost ................................................................................ 128 11.3.7 Pilot‐to‐Full Size PCC Plant Scale‐Up Factor Consideration ....................................... 129 11.3.8 Power and Potential CO2 Product Off‐take Option .................................................... 129

11.4 NEXANT’S RECOMMENDATIONS ................................................................................................... 129 11.5 FINAL PILOT PLANT SIZE ............................................................................................................. 130

12. PCC PILOT PLANT INTEGRATION METHODOLOGY AND EXISTING POZA RICA NGCC PERFORMANCE .......................................................................................................................... 131

12.1 INTRODUCTION ......................................................................................................................... 131 12.2 METHODOLOGY ........................................................................................................................ 131 12.3 EXISTING (PRE‐PCC RETROFIT) POZA RICA NGCC MODEL PERFORMANCE .......................................... 132

12.3.1 Steam Cycle Performance .......................................................................................... 132 12.3.2 Overall NGCC Balance and Performance ................................................................... 134

13. MEA PCC PILOT PLANT SYSTEM DESIGN ..................................................................... 136

13.1 INTRODUCTION ......................................................................................................................... 136 13.2 PCC PILOT PLANT OBJECTIVE ...................................................................................................... 136 13.3 PCC PILOT PLANT DESIGN CRITERIA AND ASSUMPTIONS .................................................................. 137 13.4 PCC PILOT PLANT RETROFIT ARRANGEMENT .................................................................................. 138 13.5 PCC PILOT PLANT PROCESS DESIGN METHODOLOGY ....................................................................... 140

13.5.1 Design (Des) Case Pilot Plant Operation .................................................................... 140 13.5.2 Expected (Exp) Case Pilot Plant Operation ................................................................ 146 13.5.3 Absorber Inter‐cooled (IC) Case Pilot Operation ........................................................ 152

13.6 PCC PILOT PLANT PROCESS FLOW DESCRIPTION ............................................................................. 158 13.7 DESIGN CASE EQUIPMENT DESCRIPTION ........................................................................................ 161 13.8 PROCESS DATA SHEETS FOR DESIGN CASE OPERATION ..................................................................... 171 13.9 PRELIMINARY PILOT PLANT SUPPORT FACILITY DESIGN ..................................................................... 171

13.9.1 Conceptual Pilot Plant Control Center ....................................................................... 171 13.9.2 Conceptual Pilot Plant Laboratory Facility ................................................................ 173

13.10 NGCC PLANT MODIFICATIONS REQUIRED FOR PCC PILOT PLANT INSTALLATION ................................... 174 13.11 PRELIMINARY PCC PILOT PLANT PLOT PLAN .................................................................................. 175

13.11.1 PCC Equipment Placement/Integration Guidelines .............................................. 175 13.11.2 Preliminary PCC Pilot Plant Layout ...................................................................... 175

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14. OVERALL PILOT PLANT PERFORMANCE AND COST ESTIMATES ................................... 179

14.1 POZA RICA NGCC PERFORMANCE WITH PCC PILOT PLANT OPERATION .............................................. 179 14.1.1 Steam Cycle Performance .......................................................................................... 179 14.1.2 Overall NGCC Balance and Performance ................................................................... 181 14.1.3 Overall Water Balances ............................................................................................. 182 14.1.4 Emissions and Discharges .......................................................................................... 182

14.2 POZA RICA NGCC PCC PILOT PLANT COST ESTIMATION .................................................................. 183 14.2.1 Cost Estimation Basis ................................................................................................. 183 14.2.2 Capital Cost................................................................................................................ 184 14.2.3 Operating and Maintenance Costs ............................................................................ 187

14.3 PRELIMINARY ASSESSMENT OF SOCIAL, ENVIRONMENTAL AND HEALTH IMPACTS OF THE PCC PILOT PLANT 189 14.3.1 Operational and Social Impacts ................................................................................. 189 14.3.2 Environmental Impacts .............................................................................................. 190

15. PCC PILOT PLANT SPECIAL OPERATIONS DESCRIPTIONS .............................................. 192

15.1 STARTUP ................................................................................................................................. 192 15.2 HOT STANDBY OPERATION.......................................................................................................... 193 15.3 COLD STANDBY OPERATION ........................................................................................................ 194 15.4 SHUTDOWN ............................................................................................................................. 194

APPENDIX A ACRONYMS AND ABBREVIATIONS ...................................................................... 199

APPENDIX B PROJECT WORK SCOPE AND TERMS OF REFERENCE ............................................ 203

APPENDIX C QUESTIONNAIRE TO PCC LICENSORS ................................................................... 211

APPENDIX D DESIGN BASIS DOCUMENT .................................................................................. 223

APPENDIX E SUMMARY OF PCC LICENSORS’ QUESTIONNAIRE RESPONSES ............................. 271

APPENDIX F 30% MEA‐BASED PCC PLANT DESIGN FOR POZA RICA NGCC ................................ 285

APPENDIX G ALSTOM’S COMMENTS ....................................................................................... 291

APPENDIX H EQUIPMENT DATASHEETS ................................................................................... 292

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FIGURES AND TABLES List of Tables Table E‐1 List of PCC Licensors Participation Responses .............................................................................. 4 Table E‐2 Poza Rica NGCC Pre‐PCC vs Post‐PCC Retrofit Performance Summary ........................................ 7 Table E‐3 Incremental PCC Costs for Various Licensors ................................................................................ 8 Table E‐4 Overall NGCC Balance and Performance .................................................................................... 13 Table E‐5 MEA PCC Pilot Plant Estimated Total Plant Cost ......................................................................... 15 Table E‐6 Estimated O&M Costs for PCC Pilot Plant Operation ................................................................. 16 Table 2‐1 DOE Technology Readiness Level (TRL) and Descriptions .......................................................... 29 Table 2‐2 List of PCC Licensors Participation Responses ............................................................................ 33 Table 3‐1 Site Conditions ............................................................................................................................ 37 Table 3‐2 Meteorological Data ................................................................................................................... 37 Table 3‐3 Poza Rica NGCC Flue Gas Composition and Flow Rate ............................................................... 38 Table 3‐4 Recovered CO2 Properties ........................................................................................................... 38 Table 3‐5 Poza Rica NGCC Plant Steam Conditions .................................................................................... 40 Table 3‐6 Poza Rica Cooling Tower Design Conditions ............................................................................... 41 Table 3‐7 Poza Rica Process Water Supply Conditions ............................................................................... 42 Table 3‐8 Environmental Targets ................................................................................................................ 42 Table 4‐1 Alstom AAP Operating Experience .............................................................................................. 44 Table 4‐2 BASF OASE® blue Operating Experience ..................................................................................... 47 Table 4‐3 Fluor’s Econamine FG PlusSM Operating Experience ................................................................... 50 Table 4‐4 HTC Purenergy PCC Operating Experience ................................................................................. 53 Table 4‐5 MHI KM‐CDR Process Operating Experience .............................................................................. 57 Table 4‐6 Shell Cansolv CO2 Capture Technology Operating Experience ................................................... 60 Table 5‐1 Existing Poza Rica NGCC Overall Balance and Performance ....................................................... 68 Table 5‐2 Post‐PCC Retrofit Poza Rica NGCC Overall Balance and Performance ....................................... 72 Table 5‐3 Generic 30% MEA‐based PCC Retrofit Capital Costs................................................................... 80 Table 5‐4 Generic 30% MEA‐based PCC Operating Costs ........................................................................... 81 Table 5‐5 Generic 30% MEA‐based PCC Retrofit CAPEX + 7 Year OPEX BEP .............................................. 82 Table 5‐6 Generic 30% MEA‐based PCC Retrofit COE ................................................................................. 83 Table 5‐7 Economic Assumptions Used to Determine CCF ........................................................................ 84 Table 6‐1 Poza Rica NGCC Pre‐PCC vs Post‐30% MEA PCC Retrofit Performance Summary ...................... 86 Table 6‐2 Selected Summary of PCC Licensor Responses Relative to Nexant 30% MEA PCC Case ............ 87 Table 6‐3 Poza Rica NGCC Pre‐PCC vs Post‐PCC Retrofit Performance Summary ...................................... 89 Table 6‐4 Incremental PCC Costs for Various Licensors .............................................................................. 91 Table 6‐5 Incremental PCC Costs for Various Licensors after CO2 Capture Rate Adjustment for Fluor ..... 94 Table 6‐6 Estimated PCC Plot Space Requirements .................................................................................. 103 Table 10‐1 Site Conditions ........................................................................................................................ 113 Table 10‐2 Meteorological Data ............................................................................................................... 113 Table 10‐3 Poza Rica NGCC Flue Gas Slipstream Composition and Flow Rate ......................................... 114 Table 10‐4 Recovered CO2 Properties ....................................................................................................... 115 Table 10‐5 Poza Rica NGCC Plant Steam Conditions ................................................................................ 117

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Table 10‐6 Poza Rica Cooling Tower Design Conditions ........................................................................... 118 Table 10‐7 Poza Rica Process Water Supply Conditions ........................................................................... 118 Table 10‐8 Environmental Targets ............................................................................................................ 119 Table 12‐1 Existing Poza Rica NGCC Overall Balance and Performance ................................................... 134 Table 13‐1 Poza Rica NGCC MEA‐Based PCC Pilot Plant H&MB Table – Design Case Operation ............. 142 Table 13‐2 Poza Rica NGCC MEA‐Based PCC Pilot Plant Utility Consumption Summary Table – Design Case Operation ......................................................................................................................................... 144 Table 13‐3 Poza Rica NGCC MEA‐Based PCC Pilot Plant Catalysts and Chemicals Consumption Summary – Design Case Operation .............................................................................................................................. 145 Table 13‐4 Poza Rica NGCC MEA‐Based PCC Pilot Plant H&MB Table – Expected Case Operation ......... 148 Table 13‐5 Poza Rica NGCC MEA‐Based PCC Pilot Plant Utility Consumption Summary Table – Expected Case Operation ......................................................................................................................................... 150 Table 13‐6 Poza Rica NGCC MEA‐Based PCC Pilot Plant Catalysts and Chemicals Consumption Summary – Expected Case Operation .......................................................................................................................... 151 Table 13‐7 Poza Rica NGCC MEA‐Based PCC Pilot Plant HMB Table ‐ Absorber Inter‐Cooled Operation 154 Table 13‐8 Poza Rica NGCC MEA‐Based PCC Pilot Plant Utility Consumption Summary Table – Absorber Inter‐Cooled Operation ............................................................................................................................. 156 Table 13‐9 Poza Rica NGCC MEA‐Based PCC Pilot Plant Catalysts and Chemicals Consumption Summary – Absorber Inter‐Cooled Operation ............................................................................................................. 157 Table 13‐10 PCC Pilot Plant Major Equipment List ................................................................................... 162 Table 14‐1 Post‐PCC Pilot Plant Poza Rica NGCC Overall Balance and Performance ............................... 181 Table 14‐2 MEA PCC Pilot Plant Estimated Total Plant Cost ..................................................................... 186 Table 14‐3 Estimated O&M Costs for PCC Pilot Plant Operation ............................................................. 189

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List of Figures

Figure E‐1 Post‐PCC Retrofit Poza Rica NGCC Simplified BFD ....................................................................... 6 Figure E‐2 Incremental COEs for Various Licensors after CO2 Capture Rate Adjustment for Fluor.............. 9 Figure 2‐1 EPRI Assessment of PCC Technologies....................................................................................... 31 Figure 2‐2 EPRI’s PCC TRL Ranking .............................................................................................................. 32 Figure 3‐1 Poza Rica NGCC Flow Configuration (with PCC and CO2 Compression/Dehydration) ............... 36 Figure 3‐2 Poza Rica NGCC HRSG/Steam Turbine Configuration ................................................................ 39 Figure 3‐3 Poza Rica NGCC Plant Existing Cooling Tower Arrangement ..................................................... 41 Figure 4‐1 Simplified Process Schematic of the Alstom AAP ...................................................................... 45 Figure 4‐2 Simplified Process Schematic of the BASF OASE® blue Process ................................................ 48 Figure 4‐3 Simplified Process Schematic of the Fluor Econamine FG PlusSM Process................................. 51 Figure 4‐4 Simplified Process Schematic of the HTC LCDesignTM ............................................................... 54 Figure 4‐5 Simplified Process Schematic of the HTC delta Reclaimer System ............................................ 56 Figure 4‐6 Simplified Process Schematic of the MHI KM‐CDR Process® ..................................................... 58 Figure 4‐7 Simplified Process Schematic of the Shell Cansolv PCC Plant ................................................... 61 Figure 5‐1 Post‐PCC Retrofit Poza Rica NGCC Simplified BFD ..................................................................... 64 Figure 5‐2 Existing Poza Rica NGCC Operation ........................................................................................... 67 Figure 5‐3 Existing Poza Rica NGCC Overall Water Balance ....................................................................... 69 Figure 5‐4 Post‐PCC Retrofit Poza Rica NGCC Operation ............................................................................ 71 Figure 5‐5 Post‐PCC Retrofit Poza Rica NGCC Overall Water Balance ........................................................ 73 Figure 5‐6 30% MEA PCC Plot Layout – Flue Gas Blower, MEA Tankage and CO2 Absorption Sections .... 76 Figure 5‐7 30% MEA PCC Plot Layout – CO2 Regeneration and Compression/Dehydration Section ......... 77 Figure 5‐8 Retrofitted Poza Rica NGCC with 30% MEA PCC Plot Plan ........................................................ 78 Figure 6‐1 Incremental PCC COEs for Various Licensors ............................................................................. 92 Figure 6‐2 Incremental COEs for Various Licensors after CO2 Capture Rate Adjustment for Fluor ........... 95 Figure 6‐3 Incremental COEs for Various Licensors with ±10% PCC CAPEX ............................................... 97 Figure 6‐4 Incremental COEs for Various Licensors after CO2 Regeneration Duty Adjustments ................ 99 Figure 6‐5 COE Sensitivity to Natural Gas Prices for Various PCC Licensors ............................................. 101 Figure 6‐6 COE Sensitivity to Annual On‐Stream Factor for Various PCC Licensors ................................. 102 Figure 10‐1 Poza Rica NGCC Flow Configuration (with PCC Pilot Plant) ................................................... 112 Figure 10‐2 Poza Rica NGCC HRSG/Steam Turbine Configuration ............................................................ 116 Figure 10‐3 Poza Rica NGCC Plant Existing Cooling Tower Arrangement ................................................. 118 Figure 11‐1 Conceptual PCC/NGCC Integration Scheme .......................................................................... 122 Figure 11‐2 CO2 Recovery vs Pilot Plant Size ............................................................................................ 123 Figure 11‐3 Reboiler Steam Extraction vs Pilot Plant Size ........................................................................ 124 Figure 11‐4 CW Loads vs Pilot Plant Size .................................................................................................. 125 Figure 11‐5 NGCC Export Power Loss vs. Pilot Plant Size ......................................................................... 126 Figure 11‐6 Incremental Raw Water Import vs Pilot Plant Size ................................................................ 127 Figure 11‐7 Absorber Diameter vs Pilot Plant Size ................................................................................... 128 Figure 11‐8 Relative Capital Cost vs Pilot Plant Size ................................................................................. 129 Figure 12‐1 Existing Poza Rica NGCC Operation ....................................................................................... 133 Figure 12‐2 Existing Poza Rica NGCC Overall Water Balance ................................................................... 135 Figure 13‐1 Post‐PCC Retrofit Poza Rica NGCC Simplified BFD ................................................................. 139 Figure 13‐2 Poza Rica NGCC MEA‐Based PCC Pilot Plant PFD – Design Case Operation .......................... 141 Figure 13‐3 Poza Rica NGCC MEA‐Based PCC Pilot Plant PFD – Expected Case Operation ...................... 147

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Figure 13‐4 Poza Rica NGCC MEA‐Based PCC Pilot Plant PFD – Absorber Inter‐Cooled Operation ......... 153 Figure 13‐5 PCC Pilot Plant Control Room and Administration Trailers ................................................... 172 Figure 13‐6 PCC Pilot Plant Laboratory Trailers ........................................................................................ 174 Figure 13‐7 PCC Pilot Plant Layout ............................................................................................................ 177 Figure 13‐8 Aerial View of Poza Rica NGCC with PCC Pilot Plant .............................................................. 178 Figure 14‐1 Poza Rica NGCC Steam Cycle Performance with MEA PCC Pilot Plant in Operation (Design Case) .......................................................................................................................................................... 180 Figure 14‐2 Post‐PCC Retrofit Poza Rica NGCC Overall Water Balance .................................................... 182 Figure 15‐1 PCC Pilot Plant Startup Flow Diagram ................................................................................... 196 Figure 15‐2 PCC Pilot Plant Hot Standby Flow Diagram ........................................................................... 197 Figure 15‐3 PCC Pilot Plant Shutdown Flow Diagram ............................................................................... 198


Task 1 – Technology Selection, Evaluation and

Recommendation of Best Available PCC Technologies

Task 1 Technology Selection and Evaluation


1. INTRODUCTION

1.1 PROJECT BACKGROUND

The subject study is being performed as part of an ongoing World Bank funded project to develop

capacity for the carbon capture, utilization and storage technology (CCUS) in Mexico. The project

has the overall objective of supporting Mexico’s Secretaria de Energia (SENER) and other

Government of Mexico (GoM) stakeholders with implementation of the Mexican CCUS roadmap.

The ultimate goal is to successfully develop and deploy CCUS in the electricity, and oil and gas

industries in Mexico. An integral part of this Mexican CCUS roadmap is the design, construction, and

operation of a CO2 capture pilot plant, which would demonstrate the potential and feasibility of

capturing CO2 from natural gas combined cycle (NGCC) power plants in Mexico. This endeavor will

create a knowledge base for the various stakeholders and the experience gained from this study will

hopefully allow them to develop larger projects in the future and further advance the application of

CCUS in the Mexico.

1.2 STUDY OBJECTIVES

The Nexant team is tasked to carry out a pre‐feasibility study 1) to assess and recommend the most

appropriate commercially‐available post‐combustion capture technology for NGCC power plants in

Mexico, and 2) to develop a conceptual design of a capture pilot plant to be located at the 250 MW

Poza Rica NGCC generating station in the State of Veracruz. The pilot plant conceptual design is to

be developed with sufficient process details in order to enable the preparation of a front end

engineering design (FEED) package as a Phase II activity for the project. The FEED preparation is not

part of the current pre‐feasibility study.

It should be noted that initially, another power plant located in the State of Veracruz, Dos Bocas,

was also identified as a potential site for the study. However, the project team was later informed

that it would not be a suitable site, as it is scheduled to be shut down in 2018.

1.3 WORK SCOPE

The project work scope consists of the 4 major tasks. This report covers work completed under Task

1 and 2. To facilitate ease of reading, the report is structured differently from the task/subtask

orders. However, the section in the report that addresses each task/subtask is stated in parentheses

below:

Task 1 – Technology Selection, Evaluation and Recommendation of Best Available NGCC Post‐

Combustion CO2 Capture (PCC) Technologies

Subtask 1.1 ‐ Plant & Site Data Requisition and Preparation of a Study Design Basis

(Section 3)

Subtask 1.2 – Project Kickoff Meeting and Site Visit



Subtask 1.3 – Technology Survey Questionnaire Preparation (Section 2 and Appendix C)

Subtask 1.4 – Technology Screening, Evaluation and Selection (Section 4, Section 5, Section 6,

Appendix D and Appendix E)

Task 2: Interim Report Meeting with Recommendation

Task 3: Pilot Plant Feasibility Study

Subtask 3.1 – CO2 Capture Pilot Plant Process Design

Subtask 3.2 – NGCC/PCC Integration

Task 4: Final Report

Task 5: Workshop



2. PRE‐SCREENING OF CO2 CAPTURE TECHNOLOGIES

2.1 OVERVIEW OF CO2 CAPTURE TECHNOLOGY DEVELOPMENT

Over the last decade, there have been significant carbon capture and storage activities being

undertaken worldwide in both government and private sectors, with major programs taking place in

North America and Europe. A great deal of research and development (R&D) efforts have been

spent on developing advanced post‐combustion capture (PCC) technologies with the promise of

reducing the overall capture energy penalty and costs in comparison to the current state‐of‐the‐art

amine‐based 30% MEA (monoethanolamine) absorption technology.

In the U.S., for example, the Department of Energy (DOE) has a very active Carbon Capture Program

with the goals to develop second‐generation capture technologies that are ready for large‐scale

testing in 2020 and transformational technologies that are ready for large‐scale testing in 2030. A

good source of information regarding the current status of these R&D efforts can be found in a

recent U.S. DOE report1. Technologies that have been or are currently being investigated include not

only PCC processes, but CO2 capture processes associated with pre‐combustion and oxy‐combustion

systems as well. The knowledge gained and lessons learned from these findings could serve as a

valuable source of information, for both the World Bank and the GoM, to help with implementation

of the Mexican CCUS roadmap.

Electric Power Research Institute (EPRI), in close cooperation with U.S. DOE, is also very active in

PCC technologies, especially with the evaluation and status monitoring of various technologies that

were/are under development. EPRI published a report in 2007 entitled “Assessment of Post‐

Combustion Carbon Capture Technology Developments”2 in which it assessed the various PCC

technologies and processes that were under development. The technologies investigated included

absorption, adsorption, membrane, mineralization and biological capture. These assessments are

updated on a regular basis, the latest being a 2014 report3. This report is available at no cost to

EPRI’s funding members, or for a fee to the general public. Throughout the years, EPRI has also

reported their findings in various workshops and conferences4,5.

2.2 PRE‐SCREENING PCC TECHNOLOGIES

In their PCC technology development and evaluation, both the U.S. DOE and EPRI use the

Technology Readiness Level (TRL) as a scale to gauge a technology’s maturity and readiness for

1 Brickett, L., Shailesh, V., Indrikanti, P., et al. DOE/NETL Advanced Carbon Dioxide Capture R&D Program: Technology Update. May 2013 2 Freeman, B. Assessment of Post‐Combustion Carbon Capture Technology Developments, EPRI Report 1012796, Technical Update. February 2007 3 Post Combustion CO2 Capture Technology Development: 2014 Update, EPRI Report 002004592. October 2014 4 Rhudy, R. CO2 Capture Primer and Industry/EPRI Initiatives, SECARB Annual Meeting at Atlanta, GA, March 2009 5 Bhown, A. Carbon Capture R&D at EPRI. Carbon Capture Workshop, Stanford University, May 2011



potential commercial deployment. In their 2012 Technology Readiness Assessment6, the U.S. DOE

defined the TRL methodology as a “systematic metric/measurement system that supports

assessments of the maturity of a particular technology and the consistent comparison of maturity

between different types of technology”. TRLs do not establish a pass/fail grade, but rather yield an

assessment of the technology development spanning progress from early research on basic

principles through service conditions and size needed for the technology to perform when it is

deployed or put into use. TRLs are particularly useful in establishing a consistent set of terminology

and a supporting evaluation process that can be used to benchmark a technology’s current state of

progress. By more clearly understanding the current state and assessing the degree of development,

the TRL methodology emerges as a useful tool in the planning of future research and development

activities.

The TRL approach was originally developed by the U.S. National Aeronautics and Space

Administration (NASA) for its Space Shuttle program and later adapted by the U.S. Department of

Defense (DoD) for use in its defense systems acquisition. Similarly, the U.S. DOE adapted the TRL

methodology to provide a comprehensive and consistent process for assessing the maturity of the

diverse portfolio of technologies currently under development. Table 2‐1 provides the TRL

definitions and descriptions used in the assessment.

Table 2‐1 DOE Technology Readiness Level (TRL) and Descriptions

TRL DOE Definition DOE Description 1 Basic principles observed and

reported

Lowest level of technology readiness. Scientific research begins to be

translated into applied R&D. Examples include paper studies of a

technology’s basic properties.

2 Technology concept and/or

application formulated

Invention begins. Once basic principles are observed, practical applications

can be invented. Applications are speculative and there may be no proof

or detailed analysis to support the assumptions. Examples are still limited

to analytic studies.

3 Analytical and experimental critical

function and/or characteristic proof

of concept

Active R&D is initiated. This includes analytical and laboratory‐scale

studies to physically validate the analytical predictions of separate

elements of the technology (e.g., individual technology components have

undergone laboratory‐scale testing using bottled gases to simulate major

flue gas species at a scale of less than 1 scfm).

4 Component and/or system

validation in a laboratory

environment

Bench‐scale prototype has been developed and validated in the laboratory

environment. Prototype is defined as less than 5% final scale (e.g.,

complete technology process has undergone bench‐scale testing using

synthetic flue gas composition at a scale of approximately 1–100 scfm).

5 Laboratory‐scale similar‐system

validation in a relevant environment

Basic technological components are integrated so that the system

configuration is matches the final application in almost all respects.

Prototype is defined as less than 5% final scale (e.g., complete technology

has undergone bench‐scale testing using actual flue gas composition at a

6 US DOE Office of Fossil Energy Clean Coal Research Program. 2012 Technology Readiness Assessment. December 2013



scale of approximately 1–100 scfm).

6 Engineering/pilot‐scale prototypical

system demonstrated in a relevant

environment

Engineering‐scale models or prototypes are tested in a relevant

environment. Pilot or process‐development‐unit scale is defined as being

between 0 and 5% final scale (e.g., complete technology has undergone

small pilot‐scale testing using actual flue gas composition at a scale

equivalent to approximately 1,250–12,500 scfm)

7 System prototype demonstrated in

a plant environment

This represents a major step up from TRL 6, requiring demonstration of an

actual system prototype in a relevant environment. Final design is virtually

complete. Pilot or process‐development‐unit demonstration of a 5–25%

final scale or design and development of a 200–600 MW plant (e.g.,

complete technology has undergone large pilot‐scale testing using actual

flue gas composition at a scale equivalent to approximately 25,000–62,500

scfm).

8 Actual system completed and

qualified through test and

demonstration in a plant

environment

The technology has been proven to work in its final form and under

expected conditions. In almost all cases, this TRL represents the end of

true system development. Examples include startup, testing, and

evaluation of the system within a 200–600 MW plant CCS/CCUS operation

(e.g., complete and fully integrated technology has been initiated at full‐

scale demonstration including startup, testing, and evaluation of the

system using actual flue gas composition at a scale equivalent to

approximately 200 MW or greater).

9 Actual system operated over the full

range of expected conditions

The technology is in its final form and operated under the full range of

operating conditions. The scale of this technology is expected to be 200–

600 MW plant CCS/CCUS operations (e.g., complete and fully integrated

technology has undergone full‐scale demonstration testing using actual

flue gas composition at a scale equivalent to approximately 200 MW or

greater).

In their PCC technology assessment efforts, EPRI uses a virtually identical TRL methodology to rank

the commercial deployment readiness of a technology, also using a scale of 1 to 9. As illustrated in

Figure 2‐1 a TRL of 1 to 3 is indicative that the technology is only at its infancy, i.e., concept

development and laboratory testing; with a TRL of 4 to 7, it may have gone through bench‐scale

testing; and only at a TRL of 8 to 9 has the technology proved itself with a large‐scale pilot plant

testing and is deemed commercially deployable.



Figure 2‐1 EPRI Assessment of PCC Technologies

In its assessment of over 129 PCC technologies, at various levels of development, EPRI concluded

that: (a) most of the technologies are only at a TRL scale of 2 to 4, and (b) only a handful of the

technologies evaluated are ranked at a TRL 7, meaning that these are potentially deployable in the

near‐term. As shown in Figure 2‐2, the higher TRL ranked technologies are predominantly advanced

amine‐based absorption processes. In their assessment, it is noted that few mineralization and

biofixation technologies also have a TRL of 7; but it is Nexant’s opinion that these technologies are

not ready for near‐term commercial deployment.



Figure 2‐2 EPRI’s PCC TRL Ranking

In their 2012 report7, the Global CCS Institute (GCCSI) defined near‐term PCC technologies as those

that have been tested at scale of slip streams no larger than 5‐25 MWe. It reported that all near‐

term PCC technologies are predominantly solvent‐based absorption processes involving either

ammonia or proprietary amines. The distinction between these technologies is specific capture

chemistry and, to some extent, the process configuration and integration into the power plant. It

specifically pointed out Fluor’s Econamine FG+, Mitsubishi Heavy Industries KS solvent, Shell Cansolv

Technologies, Aker Clean Carbon, and Alstom’s Chilled Ammonia Process (CAP) as near‐term

technologies. All of these use either aqueous pure amines or amine blends, with the exception of

Alstom’s CAP, which uses aqueous ammonia.

2.3 SELECTION OF PCC TECHNOLOGIES FOR DETAILED PROCESS EVALUATION

On the basis of (a) Section 2.2’s technology assessment and pre‐screening background, (b) Nexant’s

own assessment of the current state‐of‐the‐art PCC technologies, and (c) the interest of the World

Bank and the GoM team to build and complete operation of the Poza Rica NGCC pilot plant by 2019,

based on commercially‐available PCC technology for near‐term deployment, the Nexant team

recommended to the World Bank that the pre‐feasibility design should be focused on solvent‐based

absorption processes. This recommendation was discussed and accepted by the World Bank, SENER

and Comisión Federal de Electricidad (CFE) representatives at the Project Kickoff meeting in June

2015. Potential advanced solvent‐based absorption PCC technology developers/licensors were

collectively identified, selected and asked to participate in the study. These included:

7 Global CCS Institute. CO2 Capture Technologies, Post Combustion Capture (PCC), January 2012



Alstom

Aker Solutions

BASF/Linde

CO2 Solutions

Fluor

Hitachi

HTC Purenergy

MHI

Shell Cansolv

Siemens

2.4 PARTICIPATING PCC TECHNOLOGY LICENSORS

Of the ten PCC licensors contacted, six responded positively and were willing to participate, while

four declined, for various reasons. Table 2‐2 summarizes the PCC licensors’ responses:

All of the licensors who indicated interest in participating represented amine‐based PCC

technologies. It should be noted that although Alstom does offer the CAP technology for PCC, which

uses ammonia as the solvent instead of amines, it also offers an advanced amine‐based PCC

technology (Alstom AAP). For the particular PCC application at the Poza Rica NGCC, Alstom proposed

using the amine‐based AAP technology over its chilled ammonia process.

Table 2‐2 List of PCC Licensors Participation Responses

Accepted to Participate Declined to Participate

Alstom (Advanced Amine Process)

BASF

Fluor

HTC

MHI

Shell Cansolv

Aker Solutions

CO2 Solutions

Hitachi

Siemens

2.5 QUESTIONNAIRE TO PARTICIPATING PCC LICENSORS

To obtain data from the PCC licensors on their technologies so that Nexant could proceed with the

integration of the full‐scale PCC into the Poza Rica plant to assess its potential impact, a

questionnaire was created requesting information from each of the technology providers. The

information requested includes:



Commercial, demonstration, and pilot plant operating experience

Treated gas and CO2 product gas flow rates, conditions and composition

PCC reboiling steam import and cooling duty requirements

PCC auxiliary power consumption

Makeup and waste water demands/production

Plot area requirements

Solvent makeup costs

Estimated capital costs

The full list of questions can be found in Appendix C.

A design basis document was also issued as part of the questionnaire to the PCC technology

licensors interested in participating in the study. This document contained key Poza Rica NGCC

battery limit (B/L) interface information, which defined the feed and product specifications, utility

and offsite interface commodity specifications. The purpose of issuing a design basis with B/L

information to the PCC licensors was to ensure that these licensors designed their systems

consistently and specifically to the Poza Rica NGCC for integration into the retrofit design.

Information on the design basis can be found in Section 3 and Appendix D.

2.6 QUESTIONNAIRE RESPONSES BY PCC LICENSORS

Nexant is grateful to all the participating PCC licensors for taking time out of their schedules to

respond to the Nexant’s questionnaire, providing information on their technology at no cost.

The PCC licensors indicated to Nexant that their questionnaire responses were proprietary and

confidential, and Nexant had to sign a non‐disclosure agreement (NDA) with each of the licensors in

order to have access to their data. However, the World Bank and the Mexican entities involved in

this project do not have any NDAs in effect with the licensors. Thus, only limited information (e.g.

information from open publications and/or conference presentations that the licensors presented as

their questionnaire responses) can be divulged in this report.

A summary of the various licensors’ responses is shown in Appendix E. None of the data from the

licensors is reported directly due to the confidentiality issues stated above. Any responses, if

provided by the licensors, are stated as “Y”, indicating they have disclosed information to a

particular question. If the opposite is true i.e. the licensors did not provide an answer to the

question, then an “N” is indicated.

Furthermore, Nexant had to interpret the data provided by the licensors for consistency in order to

use it in the integration exercise to evaluate the overall cost and performance of retrofitting the

Poza Rica plant with PCC. Thus, the results are only Nexant’s “interpretation” of the various

technologies’ performances and are reported in a format such that no confidential information

directly from the questionnaire is divulged.



3. DESIGN BASIS

3.1 OBJECTIVE

The design basis pulls together information on a variety of project parameters. Its objective is to

establish the criteria which the retrofitted Poza Rica NGCC with PCC should be designed to.

Nexant generated an overall design basis document based on the design and operating data of the

Poza Rica NGCC plant provided by CFE. The initial draft of this document was submitted to CFE for

review prior to Nexant’s visit of the Poza Rica NGCC plant in October 2015. Following Nexant’s visit

to the Poza Rica plant, the design basis was updated based on Nexant’s better understanding of the

plant’s operation. Information from the overall design basis was used to model the existing Poza

Rica NGCC performance and subsequently the integration of the various PCC technologies into the

retrofitted Poza Rica NGCC to determine their overall performances.

A separate design basis document was issued as part of the questionnaire to the PCC technology

licensors interested in participating in the study. This document is a subset of the overall design

basis and contains key Poza Rica NGCC B/L interface information, which defined the feed and

product specifications, utility and offsite interface commodity specifications. This was to ensure that

the PCC licensors designed their systems consistently and specifically to the Poza Rica NGCC for

integration into the retrofit design.

This section lists some of the key design basis information used in the study. The full design basis

document and its list of references can be found in Appendix D.

3.2 OVERVIEW OF RETROFITTING POZA RICA NGCC FOR PCC

The existing Poza Rica NGCC plant consists of one natural gas‐fired Siemens/Westinghouse model

W501F gas turbine (GT) producing a nominal 160 MWe of electricity. It is equipped with a heat

recovery steam generator (HRSG) to recover waste heat from the GT exhaust and generate

superheated steam feeding three 27 MWe steam turbines to produce additional power. The power

plant’s total generating capacity is 243 MWe nominal.

The PCC plant was designed as an add‐on to the Poza Rica NGCC power plant. New process/utilities

tie‐ins and retrofit to the NGCC power plant were added as required. Projected largest‐single train

size equipment was used to maximize economy‐of‐scale. Equipment was designed for a 30‐year

plant life. Rotating equipment critical to the continuous plant operation was spared to support the

high availability required of the NGCC operations. Where sparing was not feasible, alternate PCC

operation was identified to maintain continuous NGCC power plant operation. Figure 3‐1 shows the

interface between the existing NGCC power plant and the add‐on PCC and CO2

compression/dehydration plants.



Figure 3‐1 Poza Rica NGCC Flow Configuration (with PCC and CO2 Compression/Dehydration)

W501F Gas Turbine160 MWe Nominal

Siemens Steam Turbine No. 1

( 27 MWe Nominal )

Hear Recovery Steam

Generator (HRSG)

HP SH Steam

IP SH Steam

LP SH Steam

BFW

Natural Gas

Air

Stack

POZA RICA NGCC Plant

PCC Plant

Condensate

CO2 Absorber

Solvent Regen‐eration

FG Fans

To CO2 Compression

NNF

LP Steam

Cooling Water

Steam Condensate Return

Cooling Water Return

Treated Flue Gas Vent

CO2

Waste Water

Solid Waste

Power

LP Steam


( 27 MWe Nominal )


( 27 MWe Nominal )

louvers(added)

CO2 Compression & Dehydration

CO2

CompressionCondensate

Return

To Interstage Cooling

IP Steam

Compressed

CO2 to EOR Pipeline

CO2

Purification Vent



3.3 SITE‐RELATED CONDITIONS

Table 3‐1 lists the site‐related conditions of the Poza Rica NGCC plant for retrofit with PCC.

Table 3‐1 Site Conditions

Location Poza Rica, Veracruz, Mexico

Elevation above sea level

50 m (164 ft)

Topography Level

Seismic Zone 0

Transportation Road and Rail

Water From Canal de Llamada

Access Access by road and rail

CO2 Specification 85% recovery and compressed to 152.7 bara (2,215 psia) for Enhanced Oil Recovery (EOR). (Study scope limited to delivery at compression system battery limit only)

3.4 METEOROLOGICAL DATA

Summer design ambient conditions were used for the NGCC and PCC design and performance

evaluation. These conditions were provided by CFE and are shown in Table 3‐2.

Table 3‐2 Meteorological Data

Description Summer Design

Barometric Pressure 1.013 bara (14.69 psia)

Dry Bulb Temperature 32 °C (90 °F)

Wet Bulb Temperature 25.3 °C (77.5 °F)

Relative Humidity, % 57%

3.5 PCC FEED AND PRODUCT PROPERTIES

3.5.1 PCC Feed (NGCC Flue Gas) Properties

Flue gas from the Poza Rica NGCC power plant HRSG outlet is routed through a blower to boost its

pressure before delivering to the new PCC plant. The estimated PCC flue gas feed composition and

flow rate for the nominal 160 MWe gas turbine gross outputs operating at 32 °C (90 °F) ambient

temperature and 57% relative humidity are shown in Table 3‐3.

The flue gas composition and conditions shown are at the NGCC HRSG outlet for delivery to the PCC

battery limit. This is after the flue gas has undergone a pressure boost through the new blower. Any

additional flue gas conditioning required by the PCC licensor, such as feed temperature, sulfur and

moisture control to meet PCC process requirements, are to be provided by the PCC licensor, as

needed.

For the purpose of absorbent or solvent degradation estimation, the NOx concentration shown is

assumed to be 95% NO and 5% NO2.



Table 3‐3 Poza Rica NGCC Flue Gas Composition and Flow Rate

PCC Design Flue Gas composition, mole %

CO2 3.81

O2 12.32

N2 73.26

Ar 0.89

H2O 9.72

SO2 11 ppmv

NOx 60 ppmv

Total 100.00

Conditions:

Pressure at PCC B/L, bara (psia) 1.15 (16.7)

Temperature at PCC B/L, °C (°F) 107.8 (226)

Mass Flow, kg/s (lb/hr) 447.9 (3,554,770)

Molar Flow, kgmol/hr (lbmol/hr) 57,080 (125,828)

3.5.2 Recovered CO2 Properties

The full‐scale PCC plant is designed to recover 85% of CO2 in the NGCC flue gas. Recovered CO2 from

the PCC unit is sent to a separate CO2 compression unit, where it is compressed and dehydrated

before being delivered to the NGCC/PCC plant battery limit for EOR applications. CO2 gas pipeline

specifications are shown in Table 3‐4 and are based on U.S. NETL/DOE EOR specifications.

The CO2 product leaving the PCC plant battery limit is expected to meet all specifications in Table 3‐4

except for H2O content, pressure and temperature. These are adjusted in an external CO2

compression unit based on Nexant’s design.

Table 3‐4 Recovered CO2 Properties

Product CO2 Specification (for EOR, NETL/DOE)

CO2 95.0 wt% (min)

N2 1.0 vol% (max)

O2 100 ppmV (max)

H2O* 800 ppmV (max)

Ar 1.0 vol% (max)

CH4 1.0 vol% (max)

CO 35 ppmV (max)

H2 1.0 vol% (max)

Pressure, bara (psia)* 152.8 (2215)

Temperature, oC (oF)* 37.8 (100)

* The H2O content and the recovered CO2 pressure and temperature shown in Table 3‐4 are the CO2 product conditions

exiting the CO2 compression/dehydration unit.



3.6 PCC UTILITY REQUIREMENTS

3.6.1 Poza Rica NGCC Plant Steam Pressure Levels

The Poza Rica NGCC plant uses three (3) Siemens steam turbines, each nominally generating 27

MWe of power for a total of 81 MWe nominal. It has a single HRSG that generates steam at three

pressure levels, high pressure (HP), intermediate pressure (IP), and low pressure (LP). The saturated

steam from the HRSG evaporators is superheated and distributed to the three steam turbines for

power production. Figure 3‐2 shows a simplified process flow diagram (PFD), which illustrates the

configuration of the Poza Rica NGCC plant’s HRSG and steam turbine arrangement.

Figure 3‐2 Poza Rica NGCC HRSG/Steam Turbine Configuration

Hot Flue Gas

HP Steam

IP Steam LP Steam

CW

CW

CW

Condensate

IP LP

IP LP

HRSG

Stack

VentedFlue Gas

STG #1

STG #2

STG #3

Table 3‐5 shows the conditions of the steam generation levels in the Poza Rica NGCC plant’s HRSG

unit.



Table 3‐5 Poza Rica NGCC Plant Steam Conditions

Case Design

Power Plant Type NGCC

Steam Turbine Siemens (3x27 MWe nominal)

HRSG Saturated Steam Conditions From HRSG Evaporators

HP Steam, bara/°C (psia/°F) 90.0/303 (1,305/578)

IP Steam, bara/°C (psia/°F) 14.6/197 (212/387)

LP Steam, bara/°C (psia/°F) 6.0/159 (86.5/318)

Deaerator Operating Pressure, bara (psia) 6.1 (88.6)

Boiler Feed Water Supply Temperature, °C (°F) 159 (318)

Superheated Steam to STG

HP Steam, bara/°C (psia/°F) 78.4/523 (1,137/973)

IP Steam, bara/°C (psia/°F) 12.8/296 (185/564)

LP Steam, bara/°C (psia/°F) 4.8/178 (69/352)

Condenser Pressure, psia (range) 1.3 (0.8 to 1.3)

3.6.2 Low Pressure Steam

LP steam conditions from the NGCC plant are shown in Table 3‐5. The PCC licensors were asked to

specify their LP steam demands (quantity and battery limit conditions such as pressure and

temperature) to meet their specific process requirements. Nexant was responsible for determining

how the PCC LP steam demand at the required conditions was met.

3.6.3 Intermediate Pressure Steam

IP steam conditions from the NGCC plant are shown in Table 3‐5. The PCC licensors were asked to

specify their IP steam demands (quantity and battery limit conditions such as pressure and

temperature) to meet their specific process requirements. Nexant was responsible for determining

how the PCC IP steam demand at the required conditions was met.

3.6.4 High Pressure Steam

HP steam conditions from the NGCC plant are shown in Table 3‐5. Typically, amine‐based PCC

operation does not require the use of HP steam. However, due to the limited availability of LP and IP

steam in the Poza Rica NGCC plant’s HRSG unit, it may be necessary to withdraw a portion of the

main HP steam, let down its pressure through a back pressure turbine (BPT) to recover power,

before sending the now low pressure steam to the PCC.

3.6.5 Steam Condensate Return

The PCC reboiler and reclaimer steam condensate is pumped back to the power plant hot at the following PCC B/L conditions:



Min Pressure, bara (psia) 9.0 (130) ** Temperature, °C (°F) PCC Licensor to Specify

** Based on deaerator pressure of 89 psia + 40 psi ∆P allowance for head and line drops

3.6.6 Cooling Water

The Poza Rica NGCC plant utilizes three mechanical draft and evaporative recirculating wet cooling

towers (CT). Each CT, which consists of three cooling cells, is dedicated to one of the three steam

turbine surface condensers, as illustrated in Figure 3‐3. The cooling water (CW) supply and return

conditions at the PCC B/L conditions are shown in Table 3‐6.

Figure 3‐3 Poza Rica NGCC Plant Existing Cooling Tower Arrangement

STG #1Surface Condenser

Existing Cooling Tower #1





Table 3‐6 Poza Rica Cooling Tower Design Conditions

Maximum CW Supply Temperature, oC (oF) 27.5 (81.5)

Water Circulation Rate, gpm (lpm) 11,000 (41,600)/cell 33,000 (124,800)/tower

CT Design Duty, GJ/hr (MMBtu/hr) 311.8 (295.5)

Estimated Maximum CW Return Temperature, oC (oF) 37.5 (99.5)

There is a configuration for the post‐PCC retrofit Poza Rica NGCC plant operation, whereby it is

possible to shut off one of the three steam turbines due to a large quantity of HP steam being

extracted for PCC, leaving only the other two steam turbines in operation. This could potentially free

up one of the three existing CTs to provide some of the PCC cooling duty.

However, after Nexant’s visit to the Poza Rica NGCC plant, it was understood that CFE would like to

retain maximum operational flexibility after PCC retrofit by keeping all three steam turbines and



their respective CTs available. It is therefore established that the PCC cooling duty will be supplied

by new CTs similar in design to that described in Table 3‐6.

3.6.7 Process Water

Process water for PCC water wash and solvent reclamation is available from the NGCC plant steam

condensate system at the following conditions shown in Table 3‐7.

Table 3‐7 Poza Rica Process Water Supply Conditions

Temperature, oC (oF) 43.3 (110)

Pressure, bara (psia) 13.2 (191.7)

Quantity Licensor to Specify

3.7 PROCESS WASTE STREAMS

3.7.1 Process Condensates

The PCC plant is designed to minimize purging of solvent‐containing process condensates. Any

solvent‐containing process condensate is recycled within the PCC as makeup water for replacement

solvent solutions. Non‐solvent containing purge water is used as makeup to the CT.

3.7.2 Reclaimer Byproducts

Amine‐based PCC plants sometimes produce a sludge byproduct from the amine reclaimer. The

material is considered hazardous, and is assumed that it is trucked offsite for incineration by a third

party. An allowance is used to account for the cost of disposing the reclaiming waste.

3.8 ENVIRONMENTAL AND EMISSIONS REQUIREMENTS

Table 3‐8 lists the assumed emissions limits for the Poza Rica NGCC plant. PCC Licensors were asked

if they could meet these emissions criteria.

Table 3‐8 Environmental Targets

Pollutant NOM‐085‐SEMARNAT Limit (Mexico)

NOx 110 µmole/mole (ppmV)

SO2 N/A

Particulate Matter (PM) N/A

VOC 0.0025lb/MMBtu (0.0011gm/MJ) [EPA limits for PC Boilers]



4. TECHNOLOGY DESCRIPTION OF INTERESTED PCC LICENSORS

As stated in Section 2.5, each of the six interested PCC licensors were issued a questionnaire, shown

in Appendix C, requesting information pertaining to their PCC technology. The licensors were also

provided a copy of the Design Basis, similar to that presented in Section 3, in which the feed and

product specifications, utilities and other B/L interface specifications were clearly defined. This was

done to ensure that all licensors would provide the necessary process design information in

accordance to the Poza Rica NGCC’s specifications and minimize any inconsistencies among them.

Within the questionnaire, Nexant also requested the PCC licensors to provide published articles on

their technology, complete with process descriptions, in order to better understand their design

operation. A separate section of the questionnaire also asked the PCC licensors to list their

technology’s operating experience, ranging from process design package preparation to actual

commercial operation. The licensors were also asked specifically to provide operating experience, if

any, of capturing CO2 from NGCC flue gas.

This section provides a brief description of each participating PCC licensor’s technology, based on

publicly available articles published by the licensor. Also shown in this section is a summary of the

operating experience achieved by each technology.

4.1 ALSTOM ADVANCED AMINE PROCESS (AAP)

4.1.1 Introduction

Alstom Power and The Dow Chemical Company have jointly developed an Advanced Amine Process

(AAP)8,9 ,10 with UCARSOLTM FGC‐3000 amine solvent for the capture of CO2 from fossil fuel power

plant‐generated flue gas. The AAP has been optimized for application towards combustion flue gas

under atmospheric pressure from power plant operations. Alstom claims that its process presents

less solvent degradation compared to conventional MEA and is designed for stringent emissions

mitigation and control.

4.1.2 Operating Experience

Note: ND = Not Disclosed by licensor other than citing the total packages referenced below.

8 Baburao, B., et al. Advanced Amine Process Technology Operations and Results from Demonstration Facility at EDF Le Havre. Greenhouse Gas Control Technologies (GHGT)‐12 9 Chopin, F. Results of the CO2 Capture Demonstration Facility at EDF’s Le Havre Power Plant: Status of ALSTOM’s Advanced Amines Process. PowerGen Europe 2014, Cologne, Germany 10 Vitse, F., Baburao, B., et al. Technology and pilot plant results of the advanced amine process. GHGT‐10



Table 4‐1 Alstom AAP Operating Experience

NGCC Coal‐Fired Others Total

Commercial Plants 0 0 0 0

Demonstration Plants 0 0 0 0

Pilot Plants 0 2 2 4

FEED Packages Prepared ND ND ND 2

Process Design Packages Prepared ND ND ND 6

Largest Pilot Plant Operating Experience

Location: Le Havre, France

Flue gas source: Coal

CO2 recovery rate: 90%

CO2 recovered, Nm3/hr: 0.75

Current operating status: Shutdown

Largest FEED Package Prepared

Location: Belchatow, Poland

Flue gas source: Lignite coal


CO2 recovered, Nm3/hr 117,000

Current status: FEED completed; Project terminated by client

Largest Process Design Package Prepared

4.1.3 Process Description

Alstom’s Advanced Flow Scheme (AFS) process configuration tested at the CO2 Capture

Demonstration Facility at Électricité de France’s (EDF) Le Havre Power Plant is a proprietary design,

developed to provide minimal energy consumption leading to reduced operating costs. The carbon

capture facility is based on Alstom’s AAP technology, which Alstom has jointly developed with The

Dow Chemical Company. The process uses UCARSOL™ FGC 3000, an amine based solvent supplied

by Dow. Alstom plans to offer the AAP technology for large scale commercial fossil fuel power

plants, based upon successfully demonstrated experience at the Charleston pilot plant in West

Virginia, USA and the current Le Havre project in France.

Location: Karlsruhe, Germany




Current status: Package completed; No actual project



The process features an absorber column equipped with an integrated water wash section, a

regeneration column equipped with an integrated direct contact cooler (DCC), associated heat

management equipment, an oxygen stripper and an electrodialysis reclaimer unit. Figure 4‐1 shows

a simplified schematic of the AAP process.

Figure 4‐1 Simplified Process Schematic of the Alstom AAP

Exhaust gas after flue gas conditioning to reduce the SOx content below 20 ppmv and cooling is

introduced to the absorber column at below 40 °C. A booster fan (not shown in Figure 4‐1) provides

the pressure necessary to drive the gas through the CO2 absorber. In the absorber, the CO2 in the

flue gas reacts with the lean amine solution flowing counter‐current from the top. The treated gas

exits the top of the column after flowing through a water wash section to minimize amine vapor

losses. The absorber columns contain structured packing layered in several beds and selected for

optimal mass transfer and hydraulic characteristics. Within the absorber section, there is heat

management equipment in place to control the temperature to maximize the CO2 loading in the rich

solvent, hence reducing solvent flow rate.

The rich amine exiting the CO2 absorber is sent to the regenerator column via a heat exchanger

network. In the regenerator column, the CO2 is desorbed and the amine is regenerated to be sent

back to the absorber for further absorption. The regenerator is a packed column and is thermally

driven with stripping steam. The rich solution flows down the regenerator counter‐currently to

rising steam produced by boiling the lean solution exiting the bottom of the column in a reboiler



unit fed with saturated steam. The regenerator includes heat integration features that minimize

saturated steam consumption.

After flowing through the rich‐lean solvent cross heat exchanger, the lean solution returning from

the bottom of the regenerator is further cooled in a lean cooler before it is introduced to the top of

the absorber.

The exiting CO2 gas product is saturated with water and is cooled in a top section located in the

regenerator where most of the water is condensed. The condensed water is then sent back to the

amine loop or to the make‐up water system to ensure neutral water balance. The CO2 product is

suitable for further compression and pipeline transportation.

Amine solvent management is achieved via the use of mechanical filters and an activated carbon

bed filter. Heat stable salts (HSS) are formed from trace acid gas products in the flue gas and from

oxidation degradation products. These have to be removed to prevent buildup within the amine

loop. Caustic soda is used during the amine reclamation process to neutralize any heat stable salts

during the filtration process.

The amine solvent loop is also equipped with an oxygen stripper (not shown in Figure 4‐1) to reduce

amine oxidative degradation due to oxygen absorbed from the flue gas. The oxygen stripper treats

the rich amine solvent exiting the CO2 absorber, where it is exposed to a reduced pressure

environment to promote desorption of oxygen gas. The oxygen stripper is designed to extract most

of the absorbed oxygen from the amine solvent stream with minimal impacts on solvent

composition or CO2 loading of the solvent.

4.2 BASF OASE® BLUE PROCESS

4.2.1 Introduction

OASE® blue11,12,13,14,15 was jointly developed by BASF and Linde, specifically as an optimized large‐

scale PCC technology. BASF believes that its technology can offer significant benefits compared to

other solvent‐based processes as it aims to reduce the regeneration energy requirements by using

novel solvents that are very stable under coal‐fired power plant feed gas conditions. With low

11 Stoffregen, T., Rigby, S., et al. Pilot‐scale demonstration of an advanced aqueous amine‐based post‐combustion capture technology for CO2 capture from power plant flue gases. GHGT‐12 12 Krishnamurthy, K. Slipstream pilot plant demonstration of an amine‐based post‐combustion capture technology for CO2 capture from coal‐fired power plant flue gas. 2012 NETL CO2 Capture Technology Meeting, Pittsburgh, PA 13 Moser, P., Sieder, G., et al. Enabling Post Combustion Capture Optimization – The Pilot Plant Project at Niederaussem. GHGT‐09 14 Moser, P., Sieder, G., et al. The post‐combustion capture pilot plant Niederaussem – Results of the first half of the testing programme. GHGT‐10 15 Moser, P., Sieder, G., et al. Enhancement and long‐term testing of optimized post‐combustion capture technology – Results of the second phase of the testing programme at the Miederaussem pilot plant. GHGT‐11



energy consumption, low solvent losses and an exceptionally flexible operating range, BASF claims

that the OASE® blue technology is the paramount technology for use in flue gas carbon capture from

sources such as fossil power generation plants.


Note: ND = Not Disclosed by licensor

Table 4‐2 BASF OASE® blue Operating Experience





FEED Packages Prepared 0 1 0 1


Largest Demonstration Plant Operating Experience

Location: NCCC at Wilsonville, Alabama, USA


CO2 recovery rate: 80‐95%

CO2 recovered, Nm3/hr: 380‐810

Current operating status: In operation


Location: Niederaussem, Germany



CO2 recovered, Nm3/hr: 160



Location: Germany




Current status: Project cancelled


Location: Texas, USA





A simplified PFD of a PCC plant utilizing BASF OASE® blue technology is shown in Figure 4‐2. It

utilizes a series of advanced equipment and process design options incorporated into the Linde‐

BASF PCC plant design, with the ultimate goal of minimizing the energy requirements for CO2

recovery and compression. Noticeable process configuration variations and improvements include a

column that integrates the DCC, CO2 absorption, and water wash processes, as well as a flue gas

blower located downstream of the absorber and water wash units.

Figure 4‐2 Simplified Process Schematic of the BASF OASE® blue Process

As illustrated in Figure 4‐2, the novel PCC design fully integrates the DCC unit with the absorber and

water wash units within a common tower. The DCC has a dual function of: (1) cooling down the

incoming flue gas stream to a temperature suitable for efficient CO2 absorption; and (2) reduce the

SO2 concentration to as low a level as possible by utilizing an aqueous solution of sodium hydroxide

(NaOH) to neutralize the SO2. This minimizes solvent degradation due to the formation of SO2‐amine

complexes, which is more important for a coal‐fired flue gas than for NGCC application.

The flue gas feed stream to the PCC plant is typically at atmospheric pressure and water‐saturated.

An aqueous solution of NaOH is injected into the water‐NaOH circulation loop, and then sprayed at



Current status: Under evaluation by client



the top of the DCC unit. The liquid from the bottom of the DCC bed is fed to a circulating pump; the

excess water, condensed from the flue gas, and along with dissolved Na2SO3, is withdrawn from the

loop and sent to an acid neutralization and water treatment facility. It is expected that an integrated

cooling water system is used to supply cooling water to all process units, including the PCC and CO2

compression plants.

The CO2‐lean BASF OASE® blue amine‐based solvent solution flows down through the absorber bed

and absorbs CO2 from the flue gas, which flows counter‐current to the solvent flow and into the

water wash unit. The absorption process of CO2 with amine‐based solvents is exothermic and

increases the temperature of the flue gas, which consequently reduces the equilibrium content of

CO2 in the liquid‐phase. It is important to maintain a low, relatively constant temperature

throughout the entire absorber. This is achieved by cooling the CO2‐lean amine solvent solution

within an external cooler before it is injected to the top of the absorber.

Additionally, the temperature rise within the column can be suppressed via inter‐stage cooling, as

shown in Figure 4‐2. Linde has developed a patent‐protected, gravity‐driven inter‐stage cooler

design that eliminates the need for an external pump and consequently leads to a simplified design

and reduced cost for the absorber with inter‐stage cooler.

The Linde‐BASF PCC technology utilizes advanced structured packing for the absorber to promote

efficient hydraulic contact of gas and liquid phases. The packing increases CO2 reaction rates with

BASF's OASE® blue solvent, while also facilitating a fast approach to equilibrium CO2 concentration

in the liquid‐phase. The capacity of the absorber is consequently increased. In addition, the

advanced structured packing reduces the pressure drop across the column, which in turn leads to

reduced flue gas blower requirements.

The CO2‐rich solvent, heated up in the rich/lean heat exchanger, is injected at the top of the solvent

stripper column section consisting of two packed beds. The reboiler at the bottom of the stripper

column uses the heat of condensation of LP steam to vaporize CO2 and water from the concentrated

solvent, which is directed to the lean/rich solvent heat exchanger. A small fraction of carried solvent

from the top of the stripper bed is removed from the CO2 stream in the wash section above the

stripper bed. The CO2 stream leaving the top of the stripper column is saturated with water and

cooled in the condenser. The vapor phase, containing more than 95% CO2, is separated from the

liquid phase inside the separator and routed to the CO2 compression section.

The most energy intensive aspect of amine‐based CO2 capture is LP steam consumption within the

reboiler for solvent regeneration. BASF's OASE® blue solvent claims to reduce significantly the

energy demand for solvent regeneration. This minimizes power plant efficiency loss and ultimately

decreases the cost of produced electricity. The Linde‐BASF advanced PCC technology also

incorporates an option to heat the solvent within the stripper by employing an inter‐stage heater.

The heater can use lower temperature steam than the reboiler, and thus reduce LP steam demand

from the steam turbines.



4.3 FLUOR ECONAMINE FG PLUSSM

4.3.1 Introduction

As cited, Fluor has built or licensed 29 amine plants worldwide based on its proprietary Econamine

FG PlusSM (EFG+)16,17,18,19 technology. The EFG+ technology is a proven, cost‐effective process for the

removal of CO2 from low pressure gases containing oxygen, such as flue gases derived from coal,

fuel oil, natural gas boilers, and gas turbine exhaust.

The EFG+ technology was one of the first processes to gain extensive proven operating experience in

the removal of CO2 from high oxygen content flue gases. The EFG+ technology is well known from its

success at the Bellingham plant in Bellingham, Massachusetts. The Bellingham plant operated with a

90% CO2 recovery from a very challenging flue gas: 3.5 vol% (dry) CO2 and up to 15 vol% (dry) O2.



Table 4‐3 Fluor’s Econamine FG PlusSM Operating Experience


Commercial Plants ND ND ND 29

Demonstration Plants ND ND ND ND

Pilot Plants ND ND ND 2



Largest Commercial Plant Operating Experience

Location: Bellingham, Massachusetts

Flue gas source: NGCC

CO2 recovery rate: 80%‐85%

CO2 recovered, Nm3/hr: 7,000

Current operating status: Shutdown (In operation from 1991‐2005)

16 Radgen, P., Rode H., Reddy, S., Yonkoski, J.: Lessons Learned from the Operation of a 70 Tonne per Day Post Combustion Pilot Plant at the Coal Fired Power Plant in Wilhelmshaven, Germany. GHGT‐12 17 Reddy, S., Bhakta, M., Gilmartin, J., Yonkoski, J.: Cost Effective CO2 Capture from Flue Gas for Increasing Methanol Plant Production. GHGT‐12 18 Scherffius, J., Reddy, S., Klympyan, J., Armpriester, A. Large‐Scale CO2 Capture Demonstration Plant Using Fluor’s Econamine FG PlusSM Technology at NRG’s WA Parish Electric Generating Station. GHGT‐11 19 Scherffius, J., Reddy, S., Yonkoski, J., Radgen, P. Initial Results from Fluor’s CO2 Capture Demonstration Plant Using Econamine FG Plus

SM Technology at E.ON Kraftwerke’s Wilshelmshaven Power Plant. GHGT‐11




Location: Wilhelmshaven, Germany






Location: Texas, USA




Current status: Completed


A typical PFD of Fluor’s EFG+ process for CO2 capture is shown in Figure 4‐3. The flue gas enters the

DCC to reduce the water content of the flue gas and to further reduce the SO2 concentration of the

gas to protect the solvent from forming HSS. The SO2 concentration after the DCC is <5 ppm.

Figure 4‐3 Simplified Process Schematic of the Fluor Econamine FG PlusSM Process



The EFG+ technology uses a chemical solvent for the capture of the CO2 from the flue gas. In the

absorber column, CO2 is absorbed into the solvent. This is an exothermic reaction and causes the

temperature inside the column to increase as the CO2 is absorbed from the flue gas. This

temperature increase lowers the equilibrium CO2 loading in the solvent, which lowers the rich

solvent loading and increases the solvent circulation rate.

Absorber intercooling is included for solvent flow rate optimization. With the absorber intercooling

configuration, heat is removed near the bottom of the absorber column via an external cooler. The

location of the intercooler was selected to maintain high reaction rates near the top and middle of

the absorber, while maximizing the solvent CO2‐carrying capacity near the absorber bottom. By

removing much of the heat of reaction in this location, higher rich solvent loadings are achieved i.e.

the amount of CO2 carried by a given amount of solvent can be increased. This results in a lower

solvent circulation rate requirement. Besides reducing the solvent pump power demands, since

some of the regeneration energy demand for solvent stripping is the sensible heating of the

circulating solvent, a lower solvent circulation rate also results in a lower energy requirement for the

plant. The removal of the heat of reaction and the reduced solvent flow rate also mean that the size

of the absorber can be reduced, which translates to either lower capital cost for a fixed CO2 capture

rate or a higher capture rate for a fixed absorption column diameter. For absorption columns that

handle large flows from coal or NGCC based flue gas, reductions in column diameter are critical to

avoid the use of multiple absorber trains.

In the regeneration column, lean vapor compression is implemented to reduce the overall energy

demand for stripping CO2 from the rich solvent. In this configuration, lean solvent from the bottom

of the regeneration column is flashed at near atmospheric pressure. The resulting steam that is

flashed off the lean solvent is compressed by the Lean Vapor Compressor and returned to the sump

of the column as additional stripping steam. In this way, more heat is applied to the bottom of the

column, which reduces the steam extracted from the power plant’s steam system and increasing the

efficiency of the stripping process.

The EFG+ solvent, like all chemical solvents, forms HSS in the presence of strong acids, such as SO2.

When the solvent is degraded, its ability to bind CO2 from the flue gas is reduced, effectively

lowering the concentration and CO2 carrying capacity of the circulating solvent. Furthermore, high

concentrations of HSS are known to cause increased rates of corrosion in the capture plant. As such,

the HSS products must be removed from solution.

The EFG+ process achieves this by the reclaiming process, whereby the solvent is heated in the

presence of a base to free the solvent from the strong acid, thus recovering and returning to the

process a majority of the solvent. For the EFG+ solvent, it is reclaimed at a relatively low

temperature, making reclaiming a good solution for the removal of HSS. Furthermore, Fluor has

developed an advanced reclaiming configuration that reclaims at a lower pressure and lower

temperature than typical reclaiming systems. With this configuration, the solvent degradation and

losses that are associated with the reclaiming procedure are reduced, as are the waste production

and disposal costs.



4.4 HTC PURENERGY

4.4.1 Introduction

As cited, HTC Purenergy offers an advanced amine CO2 capture technology, which embraces several

new concepts in post combustion capture. The system has been engineered to reduce capital and

operating costs while at the same time delivering superior performance; reducing energy usage,

lowering emissions, and improving the quality of CO2 product captured.

HTC has taken all of its knowledge from designing large coal‐fired, medium‐sized steam generators

and smaller industrial grade CO2 capture systems, and combined them into a product that has the

capability to meet the production capacity and the emissions to atmosphere at reduced capital and

operating costs. The Low Cost Design (LCDesign™)20,21,22 includes several features that contribute to

lowering the costs such as modular design approach, optimized process flow, formulated solvents,

and optimized operating parameters.



Table 4‐4 HTC Purenergy PCC Operating Experience



Demonstration Plants ND ND ND 3





Location: Ferrybridge Power Station, UK




Current operating status: Shutdown

20 ElMoudir, W., Aboudheir, A., Fairchild, J.: HTC Solvent Reclaimer System at Searles Valley Minerals Facility in Trona, California. GHGT‐12 21 ElMoudir, W., Aboudheir, A.: Design Parameters Affecting the Commercial Post Combustion CO2 Capture Plants. GHGT‐11 22 ElMoudir, W., Aboudheir, A.: Performance of Formulated Solvent in Handling of Enriched CO2 Flue Gas Stream. GHGT‐10




Location: ASCO Test Center, Switzerland

Flue gas source: Natural Gas Boiler





Location: Norway






Figure 4‐4 shows the recommended overall HTC LCDesignTM PFD for large‐scale CO2 capture plants.

Figure 4‐4 Simplified Process Schematic of the HTC LCDesignTM



The flue gas rate is handled in the PCC unit consisting of three major sections: DCC, absorption

column, and stripper column. DCC is mainly required to condition and cool the flue gas temperature

before entering to the absorber section. The DCC will produce excess water from water

condensation during the cooling process, which can be used for water make‐up after filtration

process to remove any fly ash or solid fine particles, as in the case for a coal‐fired flue gas. In the

current HTC LCDesignTM process configuration, the excess water from the DCC is sent to the top of

the washing section as a water make‐up and to wash/cool the off‐gas in order to reduce the solvent

loss considerably (> 98%) and to maintain the plant in water balance. The reflux water is directed to

the bottom of the absorber. This imparts some benefits on the overall energy utilization and the

capital/operation cost reduction.

Not shown in Figure 4‐4 is HTC’s delta Reclaimer (ΔReclaimer™) system, which is a patented

technology based on a simple vacuum unit operation. HTC claims that the ΔReclaimer™ has the

capability to reclaim single and mixed amines or glycol solvents more efficiently at minimum capital

and operating costs. It is designed to remove all high‐boiling degradation products, ionic species,

impurities and fine suspended solids from the chemical solvents. It is also designed to operate

continuously by feeding the contaminated solvent to the delta Reclaimer as a slipstream or from a

storage tank.

Figure 4‐5 depicts the ΔReclaimer™ process unit operation. It consists of an inline mixer unit for

mixing the feed solvent with chemical solutions, solvent evaporator unit with sidearm heater to

maintain the solvent at specified temperature, condenser unit with liquid/gas separator to recover

the solvent, vacuum pump unit to maintain the required operating pressure, and solvent

condensate pump.

Sodium hydroxide, 50% NaOH, and sodium carbonate, 28% Na2CO3, have been used as the bases to

successfully liberate the amines from the accumulated HSS in the feed solvent. The amount of

chemical injection in the inline mixer depends on the HSS concentration and the feed rate. The main

utilities used to operate the reclaimer are a small slipstream of saturated steam at 2.8 barg (40 psig),

cooling water at average temperature of 25 °C (77 °F), process water, and instrument air.

In the evaporator of the ΔReclaimer™, the concentration of the salts and the high‐boiling organic

compounds (degradation products) increases as reclaimed solvent is evaporated, condensed and

then returned to the CO2 plant for reuse. When the wastes reach a high concentration, darkening

the accumulated fluid, part of the accumulated waste is withdrawn from the bottom of the

evaporator, while the reclaimer remains in continuous operation. Any non‐condensable gases,

which are in very small amounts, are removed by the vacuum pump.



Figure 4‐5 Simplified Process Schematic of the HTC delta Reclaimer System

4.5 MHI KM‐CDR PROCESS

4.5.1 Introduction

MHI is known to offer large‐scale, high‐performance and reliable CO2 recovery plants for application

in a wide variety of industries. MHI has developed an advanced, commercially available CO2 recovery

process: the Kansai Mitsubishi Carbon Dioxide recovery (KM CDR) Process23,24,25,26, which delivers

economic performance for plants of wide ranging capacities.

The MHI CO2 recovery process utilizes "KS‐1™", an advanced hindered amine solvent, in conjunction

with a line of special proprietary equipment. The technology was developed through cooperation

between MHI and Kansai Electric Power Company, Inc. (KANSAI). It is based on an advanced and

23 Tsujiuchi, T., Yonekawa, T., Miyamoto, O., et al.: Project Update of the Development of the KM CDR Process. 3rd Post Combustion Capture Conference (PCCC3) 24 Iijima, M., Nagayasu, T., et al.: MHI’s Energy Efficient Flue Gas CO2 Capture Technology and Large Scale CCS Demonstration Test at Coal‐Fire Power Plants in USA. Mitsubishi Heavy Industries Technical Review Vol. 48 No. 1 (March 2011) 25 Hirata, T., Yonekawa, T., Tsujiuchi, T., et al.: Current Status of MHI CO2 Capture Plant technology, 500 TPD CCS Demonstration of Test Results and Reliable Technologies Applied to Coal Fired Flue Gas. GHGT‐12 26 Endo, T., Kajiya, Y., Nagayasu, H., Iijima, M., et al: Current Status of MHI CO2 Capture Plant technology, Large Scale Demonstration project and Road Map to Commercialization for Coal Fired Flue Gas Application. GHGT‐10



proven technology for recovering CO2 from various flue gas sources. MHI claims that users who

adopt the KM CDR process will see tangible benefits such as lower energy consumption, lower

solvent degradation and low corrosion rates.



Table 4‐5 MHI KM‐CDR Process Operating Experience


Commercial Plants ND ND ND 11






Location: NRG WA Parish Power Plant, Thompsons, Texas, USA




Current operating status: Startup due in 4th quarter 2016


Location: Mobile, Alabama, USA






Location: Osaka, Japan

Flue gas source: Simulated NGCC





Location: Not Disclosed








Location: Houston, Texas, USA



CO2 recovered, Nm3/hr Not Disclosed

Current status: Completed; plant is under construction and due to startup in

4th quarter 2016


Figure 4‐6 shows a simplified PFD of the MHI KM‐CDR Process®.

Figure 4‐6 Simplified Process Schematic of the MHI KM‐CDR Process®

In the MHI KM‐CDR Process®, the CO2‐containing flue gas is introduced into the flue gas quencher,

where it is first cooled then pressurized by the blower installed downstream of the quencher. The

flue gas is then delivered into the CO2 absorber that is filled with packing. The flue gas enters the

bottom section of the absorber and reacts with the alkaline absorption solvent, KS‐1TM, on the

surface of the packing. The KS‐1TM absorbs the CO2 while the remaining flue gas is vented at the top

of the absorber and into the atmosphere. The KS‐1TM solvent, now rich in CO2, is pumped and

transferred to the regenerator where the CO2 is separated from the KS‐1TM solvent via steam

stripping, resulting in regeneration of the KS‐1TM for re‐use in the absorber again.



The cost of the steam used to regenerate the absorption solvent comprises the greatest portion of

operating costs of CO2 recovery plants. MHI and KANSAI constructed a pilot test plant with a

capacity of 2 metric tons of CO2 per day at the Nanko Power Plant of Kansai Electric Power Co., Inc.

near Osaka, with testing commencing in 1991. These activities conducted at this pilot plant led to

the development and commercialization of the KS‐1™ absorption solvent. Moreover, MHI has been

working to develop new absorption solvents and optimize the process operation in order to fulfil its

goal of further reducing PCC energy consumption.

With regards to emissions and the generation of waste streams, MHI, through numerous amine

emission test campaigns in its small pilot plant and laboratory scale test, discovered that solvent

emissions increased significantly with SO3 concentration in the flue gas at the CO2 absorber inlet, a

problem that is more relevant to coal‐fired flue gas.

MHI has since developed an amine emission reduction system for the KM‐CDR® process and the

system was evaluated at its demonstration plant at Plant Barry in Mobile, Alabama. At the

demonstration plant, a sulfur burner was installed to supply SO3 to the flue gas. In the case of using

the conventional washing and demister system in the CO2 absorber, the test data showed that

amine emissions clearly increased with SO3 concentration at the quencher inlet. However, when

MHI’s amine emission reduction technology was tested, amine emissions were significantly reduced

to less than 1/10 compared with the conventional system. MHI also measured total Volatile Organic

Compound (VOC) emissions and verified that the emissions level of the commercial scale CO2

capture plant using KM‐CDR® Process were acceptable.

4.6 SHELL CANSOLV CO2 CAPTURE TECHNOLOGY

4.6.1 Introduction

The Shell Cansolv PCC process utilizes Cansolv DC‐20127,28,29,30 as the absorbent. It is a regenerable

solvent, which Shell claims to have higher loading capacity and requires lower steam consumption

compared to conventional absorbents in PCC applications.

The Shell Cansolv technology is ideal for use in coal‐fired and natural gas power plants, where

enormous amounts of CO2 are generated. It is also suitable for capturing CO2 from boiler flue gas in

smaller scale applications in the mining and chemical industries. The pure CO2 product output by the

Shell Cansolv technology enables EOR or CCUS downstream of the plant.

27 Stephenne, K.: Start‐Up of World’s First Commercial Post‐Combustion Coal Fired CCS Project: Contribution of Shell Cansolv to SaskPower Boundary Dam ICCS Project. GHGT‐12 28 Singh, A, Stephenne, K.: Shell Cansolv CO2 capture technology: Achievement from First Commercial Plant. GHGT‐12 29 Campbell, M.: Technology Innovation & Advancements for Shell Cansolv CO2 capture solvents. GHGT‐12 30 Shaw, D.: Cansolv CO2 Capture: The Value of Integration. GHGT‐9





Table 4‐6 Shell Cansolv CO2 Capture Technology Operating Experience



Demonstration Plants ND ND ND ND





Location: Estevan, Saskatchewan, Canada






Location: Aberdeen, Scotland




Current status: Pre‐Final Investment Decision


Figure 4‐7 shows a preliminary simplified PFD of the Shell Cansolv capture plant. The Cansolv CO2

capture plant is comprised of the following major components: (1) Pre‐scrubber: to sub‐cool flue gas

and decrease the SO2 level to below 5 ppmv; (2) CO2 Absorber: to absorb the CO2 in Cansolv DC‐201

solvent; (3) CO2 Stripper: to regenerate the solvent and release CO2, producing a high‐purity CO2

product stream; and (4) Amine purification unit: to remove HSS and degradation products from the

Cansolv solvent and minimize solvent makeup.



Figure 4‐7 Simplified Process Schematic of the Shell Cansolv PCC Plant

Prior to entering the CO2 absorber, the flue gas is passed through the pre‐scrubber to be cooled in a

cooling column and decrease the flue gas SO2 content. This is achieved by a cooled water circulation

loop entering at the top of the cooling column and caustic injection equipped with packing and

counter currently cooling the flue gas.

The flue gas is then ducted to the CO2 absorber, where CO2 is absorbed from the flue gas by

countercurrent contact with the Cansolv DC‐201 solvent in a vertical multi‐level packed‐bed tower.

The gas entering the absorption section of the column will have sufficient pressure to overcome the

pressure drop in the packing. The treated flue gas leaving the top of the CO2 absorption section will

pass through an advanced wash section to maintain water balance and control emissions to the

atmosphere before being released through the stack.

Lean absorbent pumps deliver CO2‐lean absorbent from tankage through the lean absorbent cooler

to the top of the CO2 absorber. The lean absorbent is cooled to enhance the CO2 removal

performance of the absorbent.

The rich absorbent is collected in the bottom sump of the CO2 absorber and is pumped by the rich

absorbent pumps and heated in the CO2 lean/rich heat exchangers to recover heat from the hot lean

absorbent from the stripper bottoms. Rich absorbent is piped to the top of the stripping section of

the CO2 stripper for absorbent regeneration and CO2 recovery. The rich absorbent enters the column

under the CO2 reflux rectification packing section and flows onto a gallery tray that allows for vapor



disengagement from the rich absorbent before it flows down to two stripping packing sections.

Steam generated in the stripper reboilers, flowing counter‐currently to the rich absorbent, is used to

strip the rich absorbent of CO2.

Steam in the stripper, carrying the stripped CO2, flows up the stripper column into the rectification

packing section at the top, where a portion of the vapor is condensed by recycled reflux to enrich

the overhead CO2 gas stream. The CO2 stripper overhead gas is partially condensed in the CO2

stripper overhead condensers. The two‐phase mixture then flows to the CO2 reflux accumulator

where the CO2 is separated from water. The reflux water is collected and returned to the CO2

stripper, while the CO2 product gas is sent to the CO2 compression unit.

The Cansolv absorbent can accumulate HSS, as well as various degradation products over time,

which must be removed from the absorbent to maintain the guaranteed system performance. The

Shell Cansolv process uses an ion exchange package, thermal reclaimer unit, and CO2 absorbent

filters to remove the contaminants.

A small fraction of the lean solvent flow is circulated through the ion exchange package to remove

ionic degradation products. For the non‐ionic species, the thermal reclaimer unit is used to separate

them from the active absorbent. It distills the absorbent under vacuum conditions to separate the

principle constituents of the absorbent; water and absorbent, leaving the degradation products and

other contaminants in the bottom. Finally, cartridge type filter units are used depending on the

amount of particulate and trace metal contaminants present in the absorbent.



5. INTEGRATION METHODOLOGY FOR FULL‐SCALE PCC WITH POZA RICA NGCC

5.1 INTRODUCTION

An objective of the Task 1 study is to select the top three candidates from the six near‐term

commercial‐ready PCC technologies identified in the Pre‐Screening exercise (described in Section 2)

for pilot plant testing within the next 3‐to‐5 years, followed by full‐scale PCC demonstration

implementation in the Poza Rica NGCC power plant 5‐to‐10 years after pilot testing. Both the pilot

and the full‐scale PCC retrofits will be fully integrated into the existing Poza Rica NGCC operation.

The technology selection criterion is to be based on minimum impact on the overall power plant

economics, including both performance and cost impacts, from retrofitting a full‐scale PCC into the

NGCC. The full‐scale PCC is to recover 85% of the CO2 from 100% of the flue gas leaving the NGCC

HRSG. The PCC retrofit scope includes all new systems and modifications of existing NGCC systems

necessary to deliver the captured CO2 to the power plant B/L at 152.7 bara (2,215 psia) for pipeline

transport to an EOR end‐user. The transport pipeline and the EOR designs will be done by other

parties and are outside the scope of this study.

Figure 5‐1 is a simplified block flow diagram showing the major new systems, as well as

modifications to the existing Poza Rica plant, resulting from the PCC retrofit. The major changes

include the following:

1. New flue gas booster compression system

2. New post‐combustion CO2 capture system

3. New CO2 compression and dehydration system

4. Modifications to the existing plant:

a. HRSG stack modifications for flue gas extraction

b. Modifications for steam extraction and power recovery

c. New PCC cooling tower

d. New PCC cooling water pump and circulation system

e. New PCC de‐ionized water system

f. Modified raw water supply & treatment systems

g. Additional interconnecting ducting and piping

Ideally, process H&M balances, equipment designs, performance estimations, operating and capital

costs development for process selection purpose should be done by a single party to ensure

consistency in design and cost estimation philosophy and methodology. This philosophy is carried

out to the maximum extent possible for the Task 1 study. With the exception of the PCC system

(Item 2 in the list above), the design and cost estimates for all other systems listed were carried out

by Nexant on a consistent basis. The PCC systems are proprietary, and their corresponding designs

and cost estimations are carried out by the individual PCC licensors.



Figure 5‐1 Post‐PCC Retrofit Poza Rica NGCC Simplified BFD

Existing NGCC, No Change Design & Cost by Nexant Design & Cost by PCC Licensor Design & Cost by Others

3 IdenticalSteam Turbines

Single GT/HRSG

HP SH Steam

CO2-Rich Flue Gas

Post-PCC Retrofit Poza Rica NGCC

GT/HRSG:1. 163 MW Siemen/Westinghouse GT2. 1,595 MMBtu(LHV)/Hr NG Firing3. 900 MMBtu/Hr HRSG Abs Duty4. 580,000 #/Hr HP Stm

Three Identical Siemen Stm Turb:1. 192,000 #/Hr HP SH Stm Each2. 1,100 psig/975 F HP SH Stm3. 27 MW Gross Pre-PCC Each

PCC Plant CO2 Recovery

PCC Plant CO2

Compression

LP CO2

S/CCO2

CO2-Lean Flue Gas Vent from Absorber top


Other NGCC Plant Modifications:1. CW/CT Systems2. Raw & Filtered Water Systems3. RO/De-Ionized Water System 4. Electrical Distribution Systems5. Inter-Connecting Pipings

Super-CriticalCO2 to EOR Via

Pipeline


LP Sat SteamCondensat

De-Superheater



5.2 EVALUATION METHODOLOGY

The evaluation methodology used to determine the overall NGCC economic impact from the

addition of the full‐size PCC consisted of the following:

1. Developed a ThermoFlex model of the existing Poza Rica NGCC to serve as the basis for all PCC integration cases to be evaluated against. The predicted overall NGCC performance is benchmarked against the performance provided by Poza Rica to ensure accuracy of the model.

2. Developed overall balances on power generation/consumption, cooling water loads, and de‐ionized water/filtered water/raw river water demands to define existing NGCC plant support facility capacities. These served as the bases to determine post‐PCC retrofit modifications, and new system additions requirements.

3. Developed a common PCC plant design basis to be used by all licensors to design their respective PCC packages. The design basis identified the following metrics, which are identical for all licensors:

flue gas feed flow, composition, pressure and temperature conditions,

degree of CO2 recovery,

treated flue gas vent emission specifications,

interface utility and offsite commodity supply and return conditions, and

timeframe and location of the provided PCC capital cost.

4. Developed a preliminary generic 30% MEA‐based PCC design to serve as a benchmark for comparison to ensure PCC licensor replies are reasonable. The preliminary generic 30% MEA‐based PCC design includes heat and material balances (HMB), equipment sizing, major equipment (ME) factored cost estimates, and estimated PCC chemical consumptions and costs.

In view of a) the short amount of time available for the PCC licensors to respond to the questionnaire, b) the fact that their responses were provided voluntarily without compensation, and c) the proprietary nature of the PCC licensor data, Nexant anticipated that some of the licensors may not be able to provide all of the interface information necessary for NGCC integration evaluation. The generic MEA design thus provides a means to estimate the missing licensor data needed for NGCC integration.

5. Developed designs and ME factored cost estimates for the new flue gas booster compressor, and the CO2 compression and dehydration systems to fully define the overall NGCC interface requirements of the 30% MEA‐based PCC process systems.

6. Revised the existing Poza Rica NGCC ThermoFlex model to integrate the generic 30% MEA PCC process interface steam/condensate demands to determine post PCC‐retrofit overall steam cycle operation and power generation.



7. Developed overall balances for the post‐PCC retrofitted Poza Rica power generation/ consumption, cooling water loads, and de‐ionized water/filtered water/raw river water demands to define plant modifications, and new system additions needed to support full‐size generic 30% MEA PCC technology.

8. Developed designs and cost estimations of plant modifications and additions needed to support post PCC‐Retrofit Poza Rica operations.

9. Prepared preliminary plot layouts to determine PCC plant locations and to estimate inter‐connecting pipe runs and costs.

10. Estimated incremental overall operating costs between pre‐ and post‐PCC retrofitted NGCC operations.

11. Determined the impact on overall cost of electricity (COE) after integrating the full‐size 30% MEA PCC operations into the Poza Rica NGCC power plant based on the defined capital and operating costs.

12. Repeated above Steps 5 through 11 for each PCC technology based on capital cost and interface requirements provided by the respective PCC technology licensor or supplier.

13. Determined the relative economics of the PCC technologies based on least impact to the overall Poza Rica COE.

5.3 EXISTING (PRE‐PCC RETROFIT) POZA RICA NGCC MODEL PERFORMANCE

5.3.1 Steam Cycle Performance

Keeping the same firing rate of 1,680 GJ/hr [LHV31] (1,595 MMBtu/hr [LHV]) of natural gas, the

ThermoFlex‐modeled, single Siemens/Westinghouse W501F GT generates approximately 166 MWe

of power. Exhaust from the GT goes through a single HRSG and produces roughly 261,300 kg/hr

(576,000 lb/hr) of 79 bara/525 °C (1,152 psia/977 °F) HP steam, 19,400 kg/hr (42,800 lb/hr) of 14

bara/298 °C (198 psia/569 °F) IP steam, plus 14,900 kg/hr (32,800 lb/hr) of 5 bara/179 °C (72 psia/

354 °F) LP steam. Steam from the single HRSG goes to three identical STGs to generate 82.5 MWe of

power, or 27.5 MWe from each STG. Exhaust from each STG goes through an individual surface

condenser. Each condenser is cooled with cooling water (CW) from one dedicated cooling tower.

Figure 5‐2 summarizes the pre‐PCC retrofit Poza Rica NGCC design operation as predicted by the

ThermoFlex model.

31 LHV = Lower Heating Value



Figure 5‐2 Existing Poza Rica NGCC Operation

POWER GENERATION:kW

Generation:

CW Return from Gas Turb Generation 166,570

STG Train 3 STG 2 & STG 3 Stm Turb Generation 82,500 Total Generation 249,070

RFI RFI CalcNatural Filtered GT CW Supply to

Gas Amb Air Exhaust STG 2 & STG 3Mol Wt Vol % Vol % Vol %

N2 28.01 1.01 75.99 73.26 from STG 3

O2 32.00 0.00 20.39 12.32 STG Train 2 One of Three Identical STG Units CO2 44.01 0.81 0.03 3.81 from STG 2 Argon 39.95 0.00 0.92 0.89 645,273 PPH H2S 34.08 0.0330 0.00 0.00 1.29 psia 1.29 psia

CH4 16.04 89.97 0.00 0.00 110 oF 110 deg F C2H6 30.07 6.65 0.00 0.00 32,588 PPH C3H8 44.10 1.04 0.00 0.00 90 deg F iC4 58.12 0.22 0.00 0.00 nC4 58.12 0.20 0.00 0.00 C5's 72.15 0.08 0.00 0.00 C6's 86.18 0.00 0.00 0.00 SO2 64.06 0.00 0.00 0.0011 192,055 PPH

Steam 18.02 0.00 2.67 9.72 1,117 psia 210.4 MMBtu/Hr

Total Vol % 100.00 100.00 100.00 975 deg F 200 PPH

Total MPH 4,355 121,261 125,840 84 psia

Total LB/Hr 77,694 3,477,073 3,554,768 316 deg F LHV, MMBtu/Hr 1,595 0 0 ppmW Sulfur 592 0 13

28.1 MW GrossNGCC Design Basis: 0.6 MW Gen Loss

1. Gas Turbine (GT) Exhaust Gas Temperature (EGT) of 1141 F, flue gas flow of 3,554,734 lb/hr, 27.5 MW Netand gross output of 162.8 MW are from HRSG Case 1 Specifications.

2. GT Air Compressor (AC) pressure ratio of 15.78 and discharge temperature of 788 F are from Siemen GT Startup Load Curve. These are used to back-calc the AC polytropic efficency.

3. HRSG steam & condensate flows are estimated from HRSG Case 1 heat and material balance (H&MB).

4. Steam drum blowdowns are assumed to be 5% of steam generation. Deaerator vent is assumed to be 200 lb/hr. 5. Natural gas and ambient air composition are taken from Request For Information (RFI) table filled by CFE. Exhaust composition are calculated. 32,786 PPH 32,786 PPH

72 psia 84 psia 84 psia 354 deg F 316 deg F 316 deg F

42,802 PPH 198 psia 569 deg F

677,860 PPH 110 deg F

1,302 psia649,916 PPH 84 psia 316 deg F

28,808 PPH

1,556 2003 GT Des Spec Sht 2,140 PPH1,595 MMBtu(LHV)/Hr 218 psia 84 psia

77,694 lbs/hr HRSG-1 316 deg F

474.7 psia 576,165 PPH 579,961

77 oF 1,152 psia 1172 604,974 PPH 977 deg F 976 3,554,768 Lbs/Hr

14.7 psia

195.1 deg F

1023 lb/sec Est @ 59 F Amb T from Flue Gas flow3,477,073 lb/hr @ Actual Amb T

14.7 psia Amb Pressure 14.5 psia Inlet Pressure 9,570 2003 GT Des Spec

89.6 oF Amb Temp 89.6 oF 9,570 Btu/kW-Hr GT Ht Rate57.0 % RH 44,942 PPH HRSG

Flue Gas

232 psia 229 psia 0 lbs/hr Mol Wt MPH Mol% Wet Mol% Dry

787 deg F 2229 deg F N2 28.01 92,188 73.26% 81.15%

166.6 MW O2 32.00 15,504 12.32% 13.65%

162.8 HRSG-1 CO2 44.01 4,793 3.81% 4.22% Argon 39.95 1,121 0.89% 0.99%

Steam 18.016 12,232 9.72%

------------------- -------- -------- --------

Total MPH 125,838 100.00% 100.00% Total LB/Hr 3,554,768

HRSG-13,554,734 3,554,388 lbs/hr

15.14 15.39 psia1,141 1,138 oF

0 2/19/2016 RCRev. Date BY

908 MMBtu/Hr (Flue Gas Cooling) Total5 MMBtu/Hr (Loss) Total Job Rev.

904 MMBtu/Hr (Absorbed) Total No. No.

1 Total Number of HRSGs66' H x 21' W x 49' L Dimensions per HRSG A02484 0

World Bank Mexican NGCC PCC Study

Existing (Pre-PCC Retrofit) POZA RICA NGCC Operation

DRAWING No.

Figure 5-2

Natural Gas Combine Cycle (NGCC) Process Flow DiagramPoza Rica HRSG Design Case (HRSG Case 1) : 32 C Amb T & 57% RH

1xW501F with 3,554,670 Lb/Hr 1141 F Flue Gas at 90 F Amb T & 57% RH

Issued for Task 1 ReportRevision

Nexant, Inc.San Francisco, California

C102MP Steam Drum

Stm Turbine Generator

GT Generator

Air Comp K101Gas Turbine

K102Steam Turbine

E101Heat Recovery Steam Generator (HRSG)

Ambient Air

CW Return

CW Supply

Deaerator Vent

Flue Gas

V-101Stack

C105BD Flash

Drum

GT Nat Gas

GT Combustor

C103LP Stm Drum

/ Dearator

BD To WWT

HP BD

MP BD

E102Surface

Condenser

De-ionized WaterTank

HP SH1HP EVAP

HP SH3 HP SH2

C101HP Steam Drum

MP SH1 MP EVAPMP ECON

LP EVAP MU WATER PREHTR

39

G102 A/BSurf Cond Pump

G102 A/B MP BFW Pumps

51

G103 A/BDIW Pump

22

34

37

15

704

701

19

7

1

G104 A/BCW Pump

LP SH

HP ECON 1

G101 A/B HP BFW Pumps

HP ECON 2 HP ECON 3

DesuperHt BFW

4 5

6

17

38

12

13

20

23

25

32

24

29 30

26

33

45

52

AC Inlet Filter

9

82

5

HP Econ 2 & 3 Bypass 11

34701 704



5.3.2 Overall NGCC Balance and Performance

The overall power balance, CW and CT loads for the existing Poza Rica NGCC are summarized in

Table 5‐1.

Table 5‐1 Existing Poza Rica NGCC Overall Balance and Performance

Overall Poza Rica Power Balance:

Pre‐PCC

Retrofit

Output at Generator Outlet, kW:

Existing Siemens/Westinghouse GT 166,570

Existing Siemens Steam Turbine (Total for 3 operating) 82,500

New BP Power Recovery Turbine 0

Total Gross Generation 249,070

Parasitic Loads, kW:

Existing HP & IP BFW Pumps 1,047

Existing Condensate & Hot Cond Recycle Pumps 101

Existing Raw Water & Filtered Water Pumps 159

Existing Cooling Water Pumps 3,626

Existing Cooling Tower Fans 1,350

Transformer Loss Allowance 730

Misc Existing NGCC Loss Allowance 200

New Flue Gas Booster Blower 0

New PCC CO2 Capture & Compression Loads 0

New PCC Cooling Water Pumps 0

New PCC Cooling Tower Fans 0

Misc New PCC Loss Allowance 0

Total NGCC/PCC Electrical Loads 7,213

Net Poza Rica Power Export, kW 241,857

Poza Rica CW/CT Duty Breakdown: (Generic 30% MEA)

Pre‐PCC

Retrofit

Existing NGCC CW/CT Duty, GJ/hr (MMBtu/hr) 666 (631)

New PCC CW/CT Duty, GJ/hr (MMBtu/hr) 0

Total Poza Rica CW/CT Duty, GJ/hr (MMBtu/hr) 666 (631)

Overall water balances for the existing Poza Rica NGCC are summarized in Figure 5‐3. The total

estimated raw river water withdraw is about 345 m3/hr or 1,500 gallons per minute (gpm). About

90% of the water is used for makeup to the existing CT. Of the total CT makeup, 80% is lost through

evaporative cooling, and 20% is lost to blowdown, which represents a 5‐cycle of concentration for

the CT.



Figure 5‐3 Existing Poza Rica NGCC Overall Water Balance

1,080 GPM

1,516 GPM 1,485 GPM 1,350 GPM 270 GPM

30 GPMCondenser Duty = 631 MMBtu/Hr

85 GPM Avg 20 GPM

50 GPM 0 1/21/2016 Initial Estimate for Task 2 RCRev. Date Revision BY

Job Rev.No. No.

A02484 0

DRAWING No.

PFD-Water Bal-101

POZA RICA 240 MW NGCCPCC RETROFIT STUDY

OVERALL WATER BALANCE DIAGRAM

Pre-PCC Operation at 100% GT Output

Existing Cooling Tower

(5 Cycles of Conc.)

Pre PCC Retrofit NGCC Simplified Overall Water Balance Diagram

Existing NGCC ACF/RO/ED System 1x200 GPM ACF/RO

+2x88 GPM ED

1. Existing river water pumps and supply pipeline max capacity is is 1550 gpm.

CT BlowdownRiver Water

CT Evaporation Loss for dissipating Surface Cond

Loads

CT Blowdowns to

WWT & Disposal

Feed Water Treatment:

Clarifier & Filter

Misc NGCC Makeup

Allowance

Exist ACF/RO/ED Purge

Feed Water Treat Purge

5.4 PCC DESIGN BASIS AND QUESTIONNAIRE TO SELECTED LICENSORS

These were discussed previously in Sections 2 and 3. The Design Basis and the request for

information Questionnaire are provided for reference in Appendices D and C respectively.

5.5 FULL‐SIZE 30% GENERIC MEA‐BASED PCC AND CO2 COMPRESSION DESIGN

The simplified PFDs for the full‐size generic 30% MEA PCC and CO2 compression design, together

with the major stream HMBs are presented in Appendix F.

The 30% MEA PCC Plant includes the following major equipment:

• Feed Blower

• Feed Scrubber (direct contact cooler)

• Absorber

• Regenerator/Reboiler/Condenser System

• Rich/Lean Exchanger

• Lean MEA Cooler

• Rich and Lean MEA Pumps

• MEA Filtration and Reclaiming Packages

• MEA Storage Tank

The CO2 Compression Plant includes the following major equipment:



• CO2 Compression with Inter‐stage and After‐Coolers and KO Drums

• Supercritical CO2 Pump, Surge Drum, & After‐Cooler

• CO2 Dehydration Package

Major equipment lists for the MEA PCC Plant and CO2 Compression Plant are also presented in

Appendix F.

5.6 POST‐PCC RETROFIT POZA RICA NGCC MODEL PERFORMANCE

5.6.1 Steam Cycle Performance

Figure 5‐4 summarizes the post‐PCC retrofit Poza Rica NGCC steam cycle operation and

performance, based on using full‐size generic 30% MEA PCC technology, as predicted by the

ThermoFlex model.

The single Siemens/Westinghouse W501F GT is operating at the same throughput as the pre‐PCC

retrofit case, firing 1,680 GJ (LHV)/hr (1,595 MMBtu [LHV]/hr) of natural gas. Based on the model, it

generates approximately 166 MW of power. Exhaust from the GT goes through the single HRSG and

produces roughly 261,000 kg/hr (577,000 lb/hr) of 78 barg/525 °C (1150 psig/975 °F) HP steam,

18,000 kg/hr (40,000 lb/hr) of 12 barg/300 °C (170 psig/570 °F) IP steam, plus 13,000 kg/hr (28,000

lb/hr) of 2 barg/170 °C (30 psig/340 °F) LP steam.

For post‐PCC retrofit operation, roughly 50% of the HP steam from the HRSG is routed to the PCC

plant for amine regeneration uses. As a result, the three existing STGs now only receive roughly half

of the pre‐PCC retrofit HP steam flow. Based on sliding pressure STG operation, HP steam pressure

after each STG’s inlet control stop valve (CSV) drops from the pre‐PCC retrofit value of 76 barg

(1,100 psig) down to roughly 50 barg (730 psig). Power production from each STG drops from 27

MW down to about 13 MW. Each of the three existing surface condenser duties and its associated

CW load also drops to roughly 50% of the pre‐PCC retrofit value.

Since HRSG HP steam generation is the same as pre‐PCC retrofit operation, the pressure exiting the

HRSG HP superheater is essentially the same as pre‐PCC retrofit. The existing STG CSV serves as

backpressure controller between the HRSG outlet and the STG inlet, which should provide

protection against potential excessive differential pressure damage within the HRSG HP steam

generation circuit during post‐PCC retrofit operations. The HRSG IP and LP steam pressure floats on

the STG pressure and will drop slightly from the pre‐PCC retrofit level due to lower STG pressure.

Because the generic 30% MEA PCC regeneration only requires saturated steam at 3 barg (45 psig),

the extraction steam is routed through a new Back Pressure Turbine (BPT) generator to recover

some power from HP steam depressurization. Roughly 50% of the power loss from the three existing

STG is recovered by the BPT. Exhaust from the BPT is de‐superheated with condensate to near

saturation temperature before the steam is sent to PCC regeneration.



Figure 5‐4 Post‐PCC Retrofit Poza Rica NGCC Operation

POWER GENERATION:kW

Generation:

CW Return from Gas Turb Generation 166,550

STG Train 3 STG 2 & STG 3 Stm Turb Generation 39,625 BP Turb Generation 21,617

RFI RFI Calc Total Generation 227,792Natural Filtered GT CW Supply to

Gas Amb Air Exhaust STG 2 & STG 3Mol Wt Vol % Vol % Vol %

N2 28.01 1.01 75.99 73.26 from STG 3

O2 32.00 0.00 20.39 12.32 STG Train 2 One of Three Identical STG Units CO2 44.01 0.81 0.03 3.81 from STG 2 Argon 39.95 0.00 0.92 0.89 342,997 PPH H2S 34.08 0.0330 0.00 0.00 0.83 psia .83 psia

CH4 16.04 89.97 0.00 0.00 96 oF 96 deg F C2H6 30.07 6.65 0.00 0.00 110,143 PPH C3H8 44.10 1.04 0.00 0.00 90 deg F iC4 58.12 0.22 0.00 0.00 nC4 58.12 0.20 0.00 0.00 C5's 72.15 0.08 0.00 0.00 C6's 86.18 0.00 0.00 0.00 SO2 64.06 0.00 0.00 0.0011 92,671 PPH

Steam 18.02 0.00 2.67 9.72 742 psia 114.8 MMBtu/Hr

Total Vol % 100.00 100.00 100.00 955 deg F 200 PPH

Total MPH 4,355 121,261 125,840 60 psia

Total LB/Hr 77,694 3,477,073 3,554,768 292 deg F LHV, MMBtu/Hr 1,595 0 0 ppmW Sulfur 592 0 13

65,380 PPH

13.5 MW Gross 96 deg F

NGCC Design Basis: 0.3 MW Gen Loss1. Gas Turbine (GT) Exhaust Gas Temperature (EGT) of 1141 F, flue gas flow of 3,554,734 lb/hr, 13.2 MW Net

and gross output of 162.8 MW are from HRSG Case 1 Specifications.

2. GT Air Compressor (AC) pressure ratio of 15.78 and discharge temperature of 788 F are from Siemen GT Startup Load Curve. These are used to back-calc the AC polytropic efficency.

3. HRSG steam & condensate flows are estimated from HRSG Case 1 heat and material balance (H&MB). 285,044 PPH

4. Steam drum blowdowns are assumed to be 5% of steam generation. Deaerator vent is assumed to be 200 lb/hr. 175 psia5. Natural gas and ambient air composition are taken from Request For Information (RFI) table filled by CFE. 28,053 PPH 28,053 PPH 256 deg F

Exhaust composition are calculated. 46 psia 60 psia 60 psia 342 deg F 292 deg F 292 deg F

297,418 PPH 40,375 PPH 1,131 psia 185 psia 976 deg F 569 deg F

453,140 PPH 96 deg F

1,295 psia646,598 PPH 60 psia

21.8 MW Gross 292 deg F

0.2 MW Gen Loss 21.6 MW Net

28,772 PPH

2,019 PPH1,595 MMBtu(LHV)/Hr 205 psia 60 psia

77,694 lbs/hr 292 deg F

474.7 psia 575,432 PPH

77 oF 1,145 psia 604,204 PPH 977 deg F

No Vent to Atm

1023 lb/sec Est @ 59 F Amb T from Flue Gas flow3,477,073 lb/hr @ Actual Amb T

14.7 psia Amb Pressure 14.5 psia Inlet Pressure

89.6 oF Amb Temp 89.6 oF 9,571 Btu/kW-Hr GT Ht Rate57.0 % RH 42,394 PPH HRSG

Flue Gas

232 psia 229 psia 0 lbs/hr Mol Wt MPH

787 deg F 2229 deg F N2 28.01 92,188

166.6 MW O2 32.00 15,504

CO2 44.01 4,793 3,554,768 Lbs/Hr Argon 39.95 1,121

14.7 psia Steam 18.016 12,232

195.1 deg F ------------------- --------

Total MPH 125,838 Total LB/Hr 3,554,768

3,554,383 lbs/hr15.39 psia1,138 oF

0 2/19/2016 RCRev. Date BY

908 MMBtu/Hr (Flue Gas Cooling) Total5 MMBtu/Hr (Loss) Total Job Rev.

904 MMBtu/Hr (Absorbed) Total No. No.

1 Total Number of HRSGs66' H x 21' W x 49' L Dimensions per HRSG A02484 0

Nexant, Inc.San Francisco, California

World Bank Mexican NGCC PCC Study

Post-PCC Retrofit POZA RICA NGCC Operation

Issued for Task 1 ReportRevision

DRAWING No.

Figure 5-3

Natural Gas Combine Cycle (NGCC) Process Flow DiagramPoza Rica HRSG Design Case (HRSG Case 1) : 32 C Amb T & 57% RH

1xW501F with 3,554,670 Lb/Hr 1141 F Flue Gas at 90 F Amb T & 57% RH 30 Wt% Generic MEA-Based PCC

C102MP Steam Drum

Stm Turbine Generator

GT Generator

Air Comp K101Gas Turbine

K102Steam Turbine

E101Heat Recovery Steam Generator (HRSG)

Ambient Air

CW Return

CW Supply

Deaerator Vent

Flue Gas

V-101Stack

C105BD Flash

Drum

GT Nat Gas

GT Combustor

C103LP Stm Drum

/ Dearator

BD To WWT

HP BD

MP BD

E102Surface

Condenser

De-ionized WaterTank

HP SH1HP EVAP

HP SH3 HP SH2

C101HP Steam Drum

MP SH1 MP EVAPMP ECON

LP EVAP MU WATER PREHTR

39

G102 A/BSurf Cond Pump

G102 A/B MP BFW Pumps

51

G103 A/BDIW Pump

22

34

37

15

704

701

19

7

1

G104 A/BCW Pump

LP SH

HP ECON 1

G101 A/B HP BFW Pumps

HP ECON 2 HP ECON 3

DesuperHt BFW

4 5

6

17

38

12

13

20

23

25

32

24

29 30

26

33

45

52

AC Inlet Filter

9

82

5

HP Econ 2 & 3 Bypass 11

34701 704

Process Condensate

De-SuperheaterLP Sat Steam to PCC

Regeneration


PCC Regeneration

PCC Regeneration

PCC Regeneration Return Condensate

PCC Makeup WaterPCC Wash Water Makeup

Flue Gas to PCC

BPT CSV

ExistSTG CSV




5.6.2 Overall NGCC Balance and Performance

The overall power balance, CW and CT loads for the post‐PCC retrofit Poza Rica NGCC are

summarized in Table 5‐2 for the generic 30% MEA PCC operation. Existing pre‐PCC retrofit

performances are shown for comparison purposes.

Table 5‐2 Post‐PCC Retrofit Poza Rica NGCC Overall Balance and Performance

Overall PR NGCC Power Balance: (Generic 30% MEA)

Pre‐PCC

Retrofit

Post‐PCC

Retrofit

Output at Generator Outlet, kW:

Existing Siemen/Westinghouse GT 166,570 166,550

Existing Siemen Steam Turbine (Total for 3 operating) 82,500 39,625

New BP Power Recovery Turbine 0 21,617

Total Gross Generation 249,070 227,792

Parasitic Loads, kW:

Existing HP & IP BFW Pumps 1,047 1,060

Existing Condensate & Hot Cond Recycle Pumps 101 53

Existing Raw Water & Filtered Water Pumps 159 206

Existing Cooling Water Pumps 3,626 3,626

Existing Cooling Tower Fans 1,350 1,350

Transformer Loss Allowance 730 667

Misc Existing NGCC Loss Allowance 200 200

New Flue Gas Booster Blower 0 8,768

New PCC CO2 Capture & Compression Loads 0 11,902

New PCC Cooling Water Pumps 0 3,292

New PCC Cooling Tower Fans 0 900

Misc New PCC Loss Allowance 0 0

Total NGCC/PCC Electrical Loads 7,213 32,025

Net Poza Rica Power Export, kW 241,857 195,768

Poza Rica CW/CT Duty Breakdown: (Generic 30% MEA) Pre‐PCC Post‐PCC

Existing NGCC CW/CT Duty, GJ/hr (MMBtu/hr) 666 (631) 363 (344)

New PCC CW/CT Duty, GJ/hr (MMBtu/hr) 0 466 (441)

Total Poza Rica CW/CT Duty, GJ/hr (MMBtu/hr) 666 (631) 829 (786)

The overall water balance for post‐PCC Poza Rica NGCC operation based on generic 30% MEA is

summarized in Figure 5‐5. The total estimated raw river water withdraw is about 430 m3/hr or 1,900

gpm. Approximately 80% of the water is used for makeup to the existing CT and the new PCC CT. Of

the total CT makeup, 80% is lost through evaporative cooling, and 20% is lost to blowdown which

represents a 5‐cycle of concentration for the CT.

Compared to the existing water usage shown in Figure 5‐3, the generic 30% MEA retrofit will

increase the overall Poza Rica raw water import by about 90 m3/hr or 400 gpm. Since the existing

river water withdraw is already near the maximum allowed, a new river water withdraw permit may

be required before PCC retrofit can proceed.



Figure 5‐5 Post‐PCC Retrofit Poza Rica NGCC Overall Water Balance

755 GPM

809 GPM 189 GPM

135 GPM

PCC Cooling Duty =

441 MMBtu/Hr

1,922 GPM589 GPM

336 GPM

1,883 GPM 1,545 GPM 737 GPM 147 GPM

38 GPMCondenser Duty = 344 MMBtu/Hr

20 GPM

48 GPM135 GPM

204 GPM 156 GPM 131 GPM

84 GPM Avg

0 1/21/2016 RC

Rev. Date BY

25 GPM

50 GPM

Job Rev.No. No.

A02484 0

DRAWING No.

PFD-Water Bal-102

Initial Estimate for Task 2

Revision

1/0/1900

30% MEA PCC RETROFIT STUDY

OVERALL WATER BALANCE DIAGRAM

Post-PCC Operation at 100% GT Output

PCC Cooling Towers (5 Cycles of

Conc)

New PCC ACF/RO/ED Systems

(77% Recovery)DM Water

PCC CT Blowdown

PCC MEA Absorber

Incremental BFW MU for PCC Stm

Injection

PCC CT Evaporation Loss for dissipating PCC Cooling Loads

New PCC ACF/RO/ED Purge

Makeup Wash Water

Post PCC Retrofit NGCC Simplified Overall Water

Balance Diagram

Existing CT Blowdown

CT Blowdowns to WWT & Disposal

PCC MEA-free Cond Purge

PCC MEA Feed

Scrubber

CT Evaporat'n Loss for dissipating Surface Condenser Cooling

L d

Existing Cooling Tower (5 Cycles of Conc.)

River Water

1. Existing river water pumps and supply pipeline max capacity is is 1550 gpm.

Feed Water Treatment: Clarifier & Filter

Existing NGCC AFC/RO/DM System1x200 GPM RO

+2x88 GPM ED

Misc NGCC Makeup

Allowance

Exist ACF/RO/ED Purge

Feed Water Treat Purge

5.7 NGCC PLANT MODIFICATIONS REQUIRED FOR PCC RETROFIT

The NGCC plant modifications major equipment list is presented in Appendix F. The major units and

summaries of their functions are presented below:

Louvers to the Existing HRSG Stack – Two sets of these flap‐type dampers are installed in the

existing stack. One set, installed near the top of the stack, is designed to be closed when the PCC is

in operation to prevent the untreated flue gas from exiting. The second set is installed at the base of

the HRSG in the ducting that leads to the absorber. This damper will be opened during PCC

operation to allow the flue gas flow to the absorber. A cost allowance for an additional (third) louver

is included for HRSG low‐pressure protection.

Flue Gas Ducting – New ductwork is required to route the flue gas leaving the HRSG to the PCC

facilities. The treated flue gas is vented to the atmosphere from the top of the absorber and is not

routed back to the existing stack, so no return ducting is necessary.

Letdown Steam Turbine – A portion of the superheated HP steam is extracted from the main steam

line to supply the PCC regeneration steam demand. Since the HP steam pressure is much higher

than what the PCC plant requires, a BPT generator is installed upstream of the PCC plant to recover



some power from the HP extraction steam before it is exhausted at the pressure required for the

PCC plant.

Desuperheater – The exhaust steam leaving the BPT is still superheated and too hot for PCC reboiler

operation. A water spray desuperheater is installed to cool the BPT steam exhaust to near saturation

before feeding to the PCC.

Piping Modifications – Piping is installed to route the superheated HP steam to the BPT and from

the BPT to the CO2 regenerator column’s reboiler. The reboiler condensate is also piped back to the

deaerator located in the steam plant.

PCC Cooling Tower – After Nexant’s visit to the Poza Rica NGCC plant, it was understood that CFE

would like to retain maximum operational flexibility after PCC retrofit by keeping all three steam

turbines and their respective CTs available. One new CT, consisting of six (6) cooling cells, is required

to handle the 30% MEA PCC plant’s additional cooling loads. Underground concrete CW piping

associated with the new CT is included to route the CW to and from the PCC CW consumers.

New Deionization Unit – Due to additional deionized (DI) water requirements for MEA absorber

water wash and larger BFW makeup water demand, a new reverse osmosis (RO)/DI unit is added to

the existing RO/DI system.

Miscellaneous Pumps – These are the pumps associated with the new CT, new RO/DI unit, DI water

flowing to the water wash section of the CO2 absorber, and the additional raw river water required

to be pumped from Canal de Llamada.

5.8 PRELIMINARY POST‐30% MEA PCC RETROFIT PLOT LAYOUTS

5.8.1 Preliminary PCC Plot Layouts

The 30% MEA‐based PCC plant is divided into 5 sections: Flue Gas Blower, MEA tankage, CO2

absorption, CO2 regeneration, and CO2 compression. Figure 5‐6 shows a preliminary layout of the

flue gas blower, MEA tankage and CO2 absorption sections, while Figure 5‐7 shows the CO2

regeneration and CO2 compression/dehydration sections. The estimated dimensions for each of the

major process areas are:

Flue Gas Booster Blower: 30 ft x 30 ft (~ 9 m x 9 m)

CO2 Absorption: 190 ft x 100 ft (~ 58 m x 31 m)

CO2 Regeneration: 150 ft x 320 ft (~ 46 m x 98 m)

CO2 Compression: 150 ft x 130 ft ( ~ 46 m x 40 m)

MEA Tankage: 100 ft x 80 ft (~ 31 m x 24 m)

Based on these figures, the total estimated plot space required for the 30% MEA‐based PCC

including flue gas blower and CO2 compression/dehydration but excluding plant modifications is



about 9,000 m2 (96,000 ft2). Plant modification included a new cooling tower, which adds

approximately 1,594 m2 (17,000 ft2) into the overall plot space required.

5.8.2 PCC Equipment Placement/Integration Guidelines

The flue gas blower and PCC absorber tower locations are most critical due to the significant and

sizeable flue gas ducting interconnection and exhaust/stack features. These components need to be

located as close as possible to each other and to the existing stack to minimize the ductwork

requirements and the associated pressure drop.

The PCC regeneration facilities and CO2 compressors, while being significant components with

sizeable footprints, can have more flexibility for placement and distance since the interconnection

with the absorber towers are piping connections and not ductwork. The regeneration and

compressor facilities are located so as to make best use of available plot area while providing for

suitable construction, operations and maintenance access.

Per the description in Section 5.7, a new cooling tower is required for the PCC facilities. The cooling

tower requirements for the PCC facilities are not insignificant, as can be seen by the relative size of

the proposed PCC cooling tower shown on the site layout. The cooling tower is placed in available

space while respecting their need to be oriented with the prevailing wind directions for proper

performance.

Figure 5‐8 shows the preliminary, aerial view of the Poza Rica NGCC after 30% MEA PCC retrofit. The

white boxes represent the plot areas that are available for the retrofit PCC equipment and NGCC

plant modifications. This figure clearly shows that there is sufficient plot space required for a 30%

MEA‐based PCC retrofit. The major interconnecting pipe lengths were estimated based on this plot

plan.



Figure 5‐6 30% MEA PCC Plot Layout – Flue Gas Blower, MEA Tankage and CO2 Absorption Sections

G-106

K-101

MEA Absorber

C-10146' ID

G-101 A & B

PIP

EW

AY

MEA TANKAGE

CO2 ABSORPTION

G-100 A & B

FLUE GAS DUCT

G-103 A & B

To

Am

ine

Reg

ener

atio

n

FG Blower

E-105

E-100

Feed Scrubber

C-10044' ID

MEA Storage Tank

D-10158' ID



Figure 5‐7 30% MEA PCC Plot Layout – CO2 Regeneration and Compression/Dehydration Section

PIPEWAY

C-103

C-1

06

CO2 COMPRESSION

C-302

E-104A

E-104B

E-104C

E-104D

E-1

04

E

E-1

04

F

E-1

04

G

E-1

04

H

D-102&

G-107

E-102 A

E-102 B

E-102 C

E-102 D

G-102 A & B

G-104 A & B

E-101 B

E-101 C

E-101 D

E-101 E

E-101 A

K-301CO2 Compressor

K-301Motor

K-301Lube & Seal

Oil Skid

C-301

E-301 A / E-302 A

E-301 B / E-302 B

G-301 A & B

E-303 A / E-304 A

E-303 B / E-304 B

C-304

C-303

G-302 A & B

PIPEWAY

PIP

EW

AY

PIP

EW

AY

PIP

EW

AY

E-1

06

E-102 A

E-102 B

E-102 C

E-102 D

E-102 E

E-102 F

E-102 G

E-1

03

Dehydration Skid

MEA REGENERATION

BP

T

C-10211' ID (Top) x 16' ID (Btm)

Stripper



Figure 5‐8 Retrofitted Poza Rica NGCC with 30% MEA PCC Plot Plan

250 ft

240 ft

175 ft

150 ft

150 ft

150 ft

900 ft

600 ft

Flue Gas Blower MEA Storage TankCO2 Absorption Plant CO2 Regeneration Plant CO2 Compression Plant

75 ft

90 ft

CW Pumphouse

BPT

New Cooling Tower

Makeup Water Line(Above Ground)

New CT CW Line(Below Ground)

PCC Pipe Rack PCC Steam/Condensate Line

Available Plot Space



5.9 POZA RICA NGCC PCC RETROFIT ECONOMIC EVALUATION BASIS

5.9.1 Incremental Capital Cost

Each PCC licensor provided the design and the capital cost of the CO2 absorption/regeneration

plants associated with their respective proprietary PCC technology. Nexant developed the design

and capital cost of the CO2 absorption/regeneration plants for the generic 30% MEA‐based PCC

plant. In addition, Nexant also developed the designs and the capital costs for all of the other non‐

solvent related systems that are integral to NGCC PCC retrofitting, for the generic MEA technology,

and for all of the licensed PCC technologies. These non‐solvent related systems include: the flue gas

feed booster compression unit, CO2 compression/dehydration unit, and NGCC plant modifications.

In doing so, each PCC licensor’s responsibility/input is limited specifically to its technology,

minimizing any potential non‐PCC technology related interferences and inconsistencies associated

with technology comparison.

Capital costs for the Nexant‐designed systems were major‐equipment (ME) factored estimates for

U.S. Gulf Coast (USGC) locations with a target accuracy of ± 30 percent. For ME factored estimates,

equipment material and labor costs were developed from equipment sizes, quantities, and other

applicable design parameters. Bulk material and labor costs were factored from the ME costs. The

sum of the ME and bulk material costs, including shipping costs, forms the Total Direct Cost (TDC).

Construction indirect cost, factored from total direct labor cost, is added to the TDC to arrive at the

Total Field Cost (TFC). Vendor startup support cost (factored from ME cost), Home Office cost

(factored from TFC), and contingency (factored from TFC) are added to the TFC to come up with the

Total Plant Cost (TPC). The CAPEX reported in this study is at the TPC level. For the Nexant‐designed

systems, a contingency of 30% was added to cover uncertainties associated with scale‐up, missing

equipment and facilities associated with turndown, startup, normal/emergency shutdown, and

other transient operations not yet defined with a conceptual design.

Table 5‐3 summarizes the estimated capital cost for the generic MEA‐based PCC plants. The

estimated capital cost of the existing NGCC is included for comparison and to facilitate economic

evaluation via calculation of cost of electricity, described in greater detail in Section 6.3. Capital cost

of the existing NGCC is estimated assuming an installed cost of $1000/kW gross output.

Values listed in Table 5‐3 are January 2015 capital costs for USGC locations. Based on Nexant’s in‐

house historical data, the installed cost for Mexico location can vary anywhere from 80% to 120% of

the USGC cost. For this study, it is assumed that Mexico installed costs are the same as USGC

installed costs. For those non‐USGC capital costs provided by PCC licensors, they were adjusted to

USGC costs using Nexant’s in‐house historical location cost factors.



Table 5‐3 Generic 30% MEA‐based PCC Retrofit Capital Costs

Total Poza Rica NGCC Capital Costs, $MM Jan 2015: (Generic 30% MEA)

Pre‐PCC

Retrofit

Post‐PCC

Retrofit

Existing Poza Rica NGCC * 249 249

Flue Gas Booster Blower 0 14

PCC CO2 Capture & Compression/Dehydration 0 181

NGCC Plant Modifications 0 33

Total NGCC/PCC CapEx, $MM Jan 2015 at PR 249 477

Total Incremental CapEx, $MM Jan 2015 at PR Base 228

* Assumed existing Poza Rica NGCC CapEx at $1000 per gross kW

5.9.2 Incremental Operating Cost

Operating and maintenance (O&M) costs for retrofitting the Poza Rica NGCC with PCC is allocated as

either fixed and variable operating costs.

Fixed operating costs are essentially independent of actual capacity factor, number of hours of plant

operation, or amount of kilowatts produced. It consists mainly of costs for employee salaries, taxes

and insurances. For this study, the following are assumed for all cases:

1. 3 new 24/7 (operator) positions at 4.66 shifts/position for 14 total additional employees at

$40,000/year salary plus benefits

2. 3 new 8/5 (administrative) employees at $40,000/year salary plus benefits

3. Maintenance material and labor equal to 2.5% of CAPEX

4. Annual operating cost allowance for insurance at 1% of CAPEX

5. Annual operating cost allowance for property tax at 1% of CAPEX.

Variable operating costs are directly proportional to the power plant throughputs, and include

purchase costs for process consumables, catalysts and chemicals. Process consumables are feeds

directly used for power generation such as natural gas and raw water imports, plus disposal cost for

waste water discharges. Process consumables also include sale revenue (or disposal cost) associated

with the captured CO2 product. Catalysts and chemicals are primarily used for water treatments

(feed water, BFW, CW and waste water treatments), plus PCC amine, additive and filters

replacement and disposal costs. For this study, variable costs are estimated assuming:

Natural gas is priced at $2.37/GJ (LHV) or $2.50/MMBtu (LHV)

Raw river water is priced at $74/1000 m3 or $0.28/1000 gallons

Treated waste water is discharged back to the river at $7.4/1000 m3 or $0.028/1000 gallons

Annual on‐stream factor (AOF) of 8,000 hours per year (91.3%)

CO2 has zero worth (no renewable credits nor sale of CO2 for EOR purposes)

Amine makeup/disposal, as well as filter replacement/disposal costs for all cases are the

same as that for 30% generic MEA.



Due to the lack of PCC licensors’ responses relating to makeup costs for their proprietary solvents,

identical amine makeup costs are assumed for this study. While licensors are claiming significant

reduced solvent degradation losses compared to generic MEA, past Nexant studies on advanced

amines for PCC services had shown that the higher solvent prices tend to offset the savings on

reduced solvent losses, hence the overall amine makeup costs are about the same.

Table 5‐4 summarizes the estimated annual operating costs for the Poza Rica NGCC before and after

full‐size generic 30% MEA‐based PCC retrofit. It should be noted that the actual chemical

consumptions and costs information are not available from the Poza Rica plant. Values shown in

Table 5‐4 are typical treating requirements from past projects. Compared to the PCC contributions

of roughly $6.89 MM/year, these estimated water treating chemical costs highlight the relatively

minor contribution (roughly $0.58 MM/year or 10%) to the incremental catalysts & chemical costs

for PCC‐retrofit.

Table 5‐4 Generic 30% MEA‐based PCC Operating Costs

ANNUAL OPERATING COSTS, $MM/Year: (Generic 30% MEA)

Pre‐PCC

Retrofit

Post‐PCC

Retrofit

PROCESS CONSUMABLE COSTS (VARIABLE):

Natural Gas Feed 31.85 31.85

River Water Import 0.28 0.35

CO2 Product Export ‐ ‐

Process Waste Water Disposal 0.01 0.01

TOTAL PROCESS CONSUMABLES 32.13 32.21

CATALYSTS & CHEMICAL COSTS (VARIABLE): ***

Water Treating Chemicals 2.56 3.14

PCC Amine/Additives Makeup & Disposal * ‐ 6.47

PCC Carbon/Filters/Dessicant Replace & Disposal * ‐ 0.42

TOTAL CAT & CHEMICALS 2.56 10.03

FIXED COSTS:

Operating Labor ** 2.79 3.35

Maintenance Labor 3.74 7.16

Maintenance Material 2.49 4.77

Overhead Charges 2.40 2.52

Insurance & Property Tax 4.98 9.55

TOTAL FIXED COSTS 16.40 27.35

TOTAL OPERATING & MAINTENANCE COST 51.09 69.59

* Cost includes disposal allowance.

** Assumed 3 additional operating positions at 4.65 shifts per position.

*** Chemical usages are typical from past projects and do not necessary represent actual Poza Rica usages



5.9.3 Economic Evaluation Figure‐of‐Merit

The PCC process economic evaluation was conducted based on the overall performance (net power

export) of the Poza Rica NGCC with PCC retrofit, total capital expenditure (CAPEX) and operating

expenditure (OPEX). The overall economic performance of the Poza Rica NGCC with PCC was

evaluated using two figures‐of‐merit that took into account the abovementioned parameters. The

figures‐of‐merit are:

CAPEX + 7 Year OPEX Breakeven Electricity Price;

Cost of Electricity (COE)

CAPEX + 7 Year OPEX Breakeven Electricity Price (BEP)

This was the evaluation method recommended in the original study proposal. It is the required

electricity selling price required to recoup the capital expenditure plus 7 years’ worth of operating

expense. The formula for this breakeven price (BEP) is:

where AOF is the Annual On‐stream Factor. In order to calculate the BEP, it is necessary to include

the CAPEX and OPEX of the existing Poza Rica NGCC plant. These costs were shown under the “Pre‐

PCC” columns in Table 5‐3 and Table 5‐4. Using the same formula, Nexant estimated the CAPEX + 7

year OPEX BEP of the existing Poza Rica NGCC without PCC. The calculated pre‐PCC COE was then

used as the baseline cost in order to calculate the incremental BEP. The incremental BEP is the

difference between the post‐PCC BEP and the pre‐PCC BEP.

Table 5‐5 summarizes the estimated BEP for the generic MEA‐based PCC plants. The impact of CO2

product price on BEP is also shown. Revenue from the sale of CO2 decreases the electricity sale price

needed to breakeven on costs. The greater the CO2 product price, the lower the BEP. It is shown in

Table 5‐5 that a CO2 sale price of around $99 per metric ton (MT) or $90 per short ton (ST) is

required in order for the post‐PCC retrofit BEP to be the same as the pre‐PCC BEP.

Table 5‐5 Generic 30% MEA‐based PCC Retrofit CAPEX + 7 Year OPEX BEP



Cost of Electricity (COE)

The COE is the metric used by the U.S. DOE to evaluate power plants with CO2 capture. It is the

revenue received per net MWh that provides the stipulated internal rate of return on equity over

the entire economic analysis period. A simplified formula for the COE applies a capital charge factor

(CCF) to the CAPEX, which is based on a certain set of economic assumptions. These assumptions are

listed in Table 5‐7.

The formula for calculating the COE is:

where the CCF = 0.111 for NGCC plants with CO2 capture.

Again, Nexant estimated the pre‐PCC Poza Rica NGCC’s COE and used it as the baseline cost to

calculate the incremental COE. The incremental COE is the difference between the post‐PCC COE

and the pre‐PCC COE. Table 5‐6 summarizes the estimated COE for the generic MEA‐based PCC

plant:

Table 5‐6 Generic 30% MEA‐based PCC Retrofit COE

Cost Of Electricity (COE), $/MWh: (Generic 30% MEA)

Pre‐PCC

Retrofit

Post‐PCC

Retrofit

Capital Charge Factor (CCF) 0.111 0.111

Annual Onstream Factor (AOF) @ 8,000 hrs/yr 91.3% 91.3%

CapEx, $MM 249 477

Fixed OpEx, $MM/yr 16.4 27.4

AOF*Variable OpEx, $MM/yr 2.8 10.4

AOF*NG Cost, $MM/yr 31.8 31.8

AOF*Annual Net Power Export, MWh/yr 1,934,860 1,566,141

Calc COE, $/MWh 40.7 78.3

Incremental COE, $/MWh Base 37.6

* COE=(CCFxCapEx+Fix OpEx+AOF*Variable OpEx+AOF*NG Cost)/(AOF*Annual Net Power Export)



Table 5‐7 Economic Assumptions Used to Determine CCF

38% Effective Tax Rate

20 years, 150% declining balance

None

None

30 years

None

None

3.60%

Construction Period 3 years

10%, 60%, 30%

Zero for all parameters

100%

3.00%

Type of Security

Debt

Equity

TAXES

Income Tax Rate

FINANCING TERMS

Repayment Term of Debt

Grace Period on Debt Repayment

Capital Depreciation

Investment Tax Credit

Tax Holiday

Distribution of Total Overnight Capital over the Capital Expenditure

Period (before escalation)

Working Capital

% of Total Overnight Capital that is Depreciated

Debt Reserve Fund

TREATMENT OF CAPITAL COSTS

Capital Cost Escalation During Construction (nominal annual rate)

45

55

INFLATION

RSP, O&M, Fuel Escalation (nominal annual rate)

FINANCIAL STRUCTURE (HIGH RISK INVESTOR OWNED UTILITY)

Percent of Total

5.9.4 Poza Rica NGCC Economics for Full‐Size Licensor PCC Retrofit

The economic evaluation methodology described in this section was repeated for each of the

licensed PCC technology using data supplied by the respective PCC licensor. The results are

discussed in further detail in Section 6.



6. RESULTS OF FULL‐SCALE PCC INTEGRATION WITH POZA RICA NGCC

6.1 POZA RICA NGCC PRE‐ AND POST‐30% MEA PCC RETROFIT PERFORMANCE

As mentioned in the evaluation methodology presented in Section 5, Nexant modeled the existing

(i.e. pre‐PCC retrofit) Poza Rica NGCC performance based on its operation information/data

provided by CFE. Nexant then developed a conceptual design of a full‐scale PCC plant based on a

generic 30 wt% MEA process, and modeled the full‐scale effect of retrofitting it onto the Poza Rica

plant. The 30 wt% MEA PCC design was based on Nexant’s in‐house data, and retrofitting it onto the

Poza Rica plant serves the purpose of providing a preliminary independent assessment of the impact

of CO2 capture on the Poza Rica plant performance. It also helps to establish a reference design from

which to evaluate and compare the six selected PCC technologies.

The pre‐PCC retrofit Poza Rica NGCC CO2 emission rate is estimated to be 2,297 mTPD (2,532 STPD),

for a net power output of 242 MW. The required CO2 capture, as stated in the design basis, is 85%,

or 1,952 mTPD (2,152 STPD) of CO2.

Table 6‐1 summarizes and compares the Poza Rica plant performance before and after retrofitting

for CO2 capture, based on the generic 30 wt% MEA‐process design. As shown, significant plant

performance penalty is expected. The plant experiences a net power export reduction of about 46

MW, or 19%, from 242 MW to 196 MW. This corresponds to a net plant efficiency drop from 51.8%

to 42.0%, a loss of almost 10 percentage points. The majority of the power reduction is due to the

reduced output from the steam turbines and the auxiliary power requirements to run the PCC plant.



Table 6‐1 Poza Rica NGCC Pre‐PCC vs Post‐30% MEA PCC Retrofit Performance Summary

Pre‐PCC RetrofitPost‐PCC

Retrofit

NGCC CO2 Emissions, MTPD (STPD) 2297 (2532) 345 (380)

Recovered CO2 Product, MTPD (STPD) 0 (0) 1952 (2152)

% CO2 Capture 0 85%

Power Balance, MW

Generation

Gas Turbine Gross Output 166.6 166.6

Steam Turbine Gross Output 82.5 39.6

Back Pressure Turbine 0 21.6

Total Gross Output 249.1 227.8


Existing NGCC Plant Parasitic Loads 7.2 7.2

Flue Gas Blower 0 8.8

PCC + CO2 Compression + Plant Mods 0 16.1

Total New PCC Parasitic Load 7.2 32.0

Net Power Plant Export, MW 241.9 195.8

Delta Plant Export, MW ‐46.1

% Plant Export Reduction ‐19%

Net Plant Heat Rate, MJ/kWh (Btu/kWh) 6.94 (6584) 8.57 (8134)

Net Plant Efficiency, % LHV 51.8 42.0

Delta Plant Efficiency, percentage pt ‐9.9

Incremental Water Import, lpm (gpm) 0 (0) 1537 (406)

6.2 POZA LICENSOR RESPONSES CHECK AGAINST GENERIC 30% MEA

The different PCC technology licensors were responsible for providing the PCC B/L performance and

cost data in order for Nexant to perform the overall Poza Rica full‐scale retrofit evaluation. As a

check against posting or interpretation errors, selected licensor responses are compared against the

generic 30% MEA design. These are summarized in Table 6‐2. Due to the proprietary nature of the

data, the information is expressed as a percentage relative to the Nexant in‐house 30% MEA

Reference Design values, so that the actual data would remain confidential.

As shown in Table 6‐2, all advanced amine‐based PCC technology licensors’ design were based on

85% CO2 recovery except for Fluor which was based on 90% CO2 recovery. Due to time constraints,

Fluor was not able to provide the design for 85% CO2 recovery.



Relative heat of regeneration per unit CO2 captured from PCC licensors indicate about 20‐25% lower

than that for generic 30% MEA, which is consistent with typical claims by advanced amine providers.

Within the group, the differences cited are rather small.

Relative cooling loads (total for amine plus CO2 compression) are generally higher than that for

generic 30% MEA design. While one would expect lower cooling loads for the advanced PCC due to

lower regeneration heat input, the higher cooling loads could be a result of lower absorber feed

temperatures compared to the generic 30% MEA design.

Relative PCC auxiliary power consumption varies between 50% and 150% of the 30% MEA design.

These variations are inherent to the values provided by the licensors themselves. It is noted that

HTC did not provide the auxiliary power consumption of their PCC unit. In order to calculate the

HTC’s PCC performance, Nexant assumed that the auxiliary power consumption is 80% of the

generic MEA PCC power consumption, proportionate to the PCC regeneration heat.

Except for Alstom, all of the PCC licensor‐quoted CAPEXs are within about 10% of the estimate

CAPEX for the generic MEA design. This is remarkably consistent considering the potentially

different design philosophies, estimation details and methodology used among the PCC licensors.

The quoted CAPEXs were used directly in the economic evaluations. Relative ranking sensitivity to

PCC CAPEXs was carried out and results are discussed in Section 6.6.

Table 6‐2 Selected Summary of PCC Licensor Responses Relative to Nexant 30% MEA PCC Case

See Note 1Reference

30% MEA PCC

Design

Alstom

Advanced

Amine

BASF/Linde

PCC

Fluor

Econamine

Plus HTC Purenergy

MHI KS‐1

Process Shell CanSolv

CO2 Capture Rate 85% 86% 85% 90% 85% 85% 85%

PCC Regeneration Heat Relative to 100% 74% 74% 77% 80% 75% 73%

30% MEA

Cooling Load Relative to 30% MEA 100% 134% 107% 115% 88% 120% 115%

PCC Auxiliary Power Consumption 100% 155% 54% 109% N/A 59% 45%

Relative to 30% MEA (assume ~80%)

Reported CAPEX Reference USGC Western USGC USGC Canada USGC USGC

Location Europe

CAPEX (USGC) Relative to 100% 141% 107% 102% 112% 98% 112%

30% MEA Note 1: Values presented here are Nexant’s interpretation of the data provided by the PCC licensors and relative to

Nexant’s in‐house 30% MEA design.

6.3 POZA RICA NGCC POST‐PCC RETROFIT PERFORMANCE EVALUATION FOR ALL LICENSORS

For this study, Nexant was responsible for integrating the PCC plant into the existing Poza Rica NGCC

plant in order to evaluate the overall Poza Rica NGCC performance after PCC retrofit for each of the

CO2 capture technologies. Each respective PCC technology provider’s responsibility was limited to



providing their PCC B/L performance and cost estimation. Nexant provided the design of other units

integral to retrofitting the Poza Rica NGCC with PCC. These include: the flue gas feed blower, CO2

compression and dehydration unit, and NGCC plant modifications for PCC retrofit. By providing a

consistent design for each of these non‐proprietary units for all six retrofit cases, Nexant minimized

the relative overall design and cost estimation inconsistency and uncertainty.

Table 6‐3 summarizes and compares the Poza Rica NGCC performance before and after PCC for each

of the CO2 capture technologies. With regards to auxiliary power consumption, the PCC power

consumption provided by each PCC licensor is combined with Nexant’s CO2

compression/dehydration and plant modifications power consumption. This ensures that the

proprietary, PCC licensor‐provided auxiliary power consumption data remains confidential.

From Table 6‐3, it can be seen that all six PCC technologies claim improvement in efficiency over the

30% MEA design, ranging from 8.4 to 9.3 percentage point loss, compared to 9.9 percentage point

loss in efficiency for the 30% MEA design. It should be noted that there is no peer reviewed data in

the public domain to compare the claims of the various technologies in comparison to the 30%

generic amine case. Pilot plant testing would be required to confirm any efficiency claims.



Table 6‐3 Poza Rica NGCC Pre‐PCC vs Post‐PCC Retrofit Performance Summary

See Note 1 Pre‐PCCGeneric 30%

MEA PCCAlstom BASF Fluor

HTC

PurenergyMHI Shell CanSolv

NGCC CO2 Emissions, MTPD (STPD) 2297 (2532) 345 (380) 328 (362) 344 (379) 229 (252) 346 (381) 346 (381) 342 (377)

Recovered CO2 Product, MTPD (STPD) 0 (0) 1952 (2152) 1969 (2170) 1953 (2153) 2068 (2280) 1951 (2151) 1951 (2151) 1955 (2155)

% CO2 Capture 0 85% 86% 85% 90% 85% 85% 85%

Power Balance, MW

Generation

Gas Turbine Gross Output 166.6 166.6 166.6 166.6 166.6 166.6 166.6 166.6

Steam Turbine Gross Output 82.5 39.6 49.6 49.4 46.0 46.7 49.2 49.4

Back Pressure Turbine 0 21.6 17 17 18 18 17 16.7

Total Gross Output 249.1 227.8 232.8 232.7 231.0 231.3 232.6 232.7


Existing NGCC Plant Parasitic Loads 7.2 7.2 7.2 7.2 7.2 7.2 7.2 7.2

Flue Gas Blower 0 8.8 8.8 8.8 8.8 8.8 8.8 8.8

PCC + CO2 Compression + Plant Mods 0 16.1 17.3 14.1 16.6 14.0 15.7 14.2

Total New PCC Parasitic Load 7.2 32.0 33.3 30.1 32.5 29.9 31.7 30.1

Net Power Plant Export, MW 241.9 195.8 199.5 202.6 198.4 201.4 200.9 202.5

Delta Plant Export, MW ‐46.1 ‐42.4 ‐39.3 ‐43.4 ‐40.5 ‐41.0 ‐39.3

% Plant Export Reduction ‐19% ‐18% ‐16% ‐18% ‐17% ‐17% ‐16%

Net Plant Heat Rate, MJ/kWh (Btu/kWh) 6.94 (6584) 8.57 (8134) 8.42 (7984) 8.28 (7860) 8.46 (8025) 8.33 (7907) 8.35 (7926) 8.29 (7862)

Net Plant Efficiency, % LHV 51.8 42.0 42.7 43.4 42.5 43.2 43.1 43.4

Delta Plant Efficiency, percentage pt ‐9.9 ‐9.1 ‐8.4 ‐9.3 ‐8.7 ‐8.8 ‐8.4

Incremental Water Import, lpm (gpm) 0 (0) 1537 (406) 3058 (808) 1718 (454) 1618 (427) 1328 (351) 2561 (676) 1580 (417) Note 1: Values presented here are Nexant’s interpretation of the data provided by the PCC licensors.



6.4 POZA RICA NGCC PCC RETROFIT ECONOMIC EVALUATION RESULTS

Table 6‐4 shows the economic evaluation results, including incremental CAPEX + 7 year breakeven

electricity price and incremental COE for each of the PCC technologies retrofitted into the Poza Rica

NGCC plant. With regard to PCC cost estimates, the PCC plant CAPEX that was provided by each PCC

licensor is combined with Nexant’s CO2 compression/dehydration plant CAPEX. This ensures that the

licensor‐provided PCC plant capital cost data remain confidential.

Based on the economic figures‐of‐merit, the various PCC licensors’ technologies are ranked for

comparative purposes. The lower the incremental CAPEX + 7 year breakeven electricity price/

incremental COE, the higher the ranking. As shown in Table 6‐5, for both methodologies, the PCC

licensors’ rankings are in the same order. Hence, we can use COE as the sole figure‐of‐merit in

ranking the various PCC technologies.

Figure 6‐1 shows a graphical representation of the COEs for the six PCC technology licensors. It

should be noted that with the exception of Alstom all other PCC technologies have very similar

COEs, being within a range of $1.3/MWh, or 4% of one another.



Table 6‐4 Incremental PCC Costs for Various Licensors

Generic 30%

MEA PCC

Design Alstom BASF / Linde Fluor

HTC

Purenergy MHI Shell CanSolv

CAPEX Estimate, $MM US USGC

PCC Plant + CO2 Compression

[Note 2] 181.4 234.7 187.7 181.9 194.5 178.8 194.9

Flue Gas Blower 14.2 14.2 14.2 14.2 14.2 14.2 14.2


TOTAL 228.4 281.4 232.3 228.0 237.8 223.9 239.5



Fixed Costs 11.0 13.3 11.1 10.9 11.4 10.8 11.6

TOTAL 18.5 21.0 18.7 18.5 18.7 18.3 19.1

43.2 47.9 40.7 42.0 41.7 40.4 41.5

N/A 6 2 5 4 1 3

37.6 41.4 35.3 36.5 36.2 35.1 36.0

N/A 6 2 5 4 1 3Ranking based on COE


Incremental Costs to Poza Rica

NGCC without CO2 Capture [Note

1]

CAPEX +7 Yr OPEX Breakeven

Electricity Price, $/MWh [Note 4]:

Ranking based on Breakeven Price

Estimated Cost of Electricity (COE),

$/MWh [Note 5]


Note 2 ‐ All figures except Nexant’s 'Generic 30% MEA Design' are based on vendor‐provided data, which are considered proprietary.


Note 4 ‐ Incremental to estimated existing Poza Rica NGCC CAPEX + 7 Year OPEX Breakeven Price of $44.79/MWh




Figure 6‐1 Incremental PCC COEs for Various Licensors

35.1 35.3 36.0 36.2

36.5

41.4

25

30

35

40

45

MHI BASF Shell CanSolv HTC Purenergy Fluor Alstom

Increm

ental COE, $/M

Wh

Incremental COE based on Licensors' Data



6.5 ECONOMIC EVALUATION RESULTS AFTER CO2 CAPTURE RATE ADJUSTMENTS

While Nexant’s questionnaire specified for PCC design to capture 85% of the Poza Rica plant’s CO2,

Fluor provided data based on a capture rate of 90%. The design for higher CO2 capture rate requires

a larger reboiling duty, which results in a larger steam extraction rate and consequently lower power

output from the steam turbine. The larger quantity of CO2 captured also increases the CO2

compression horsepower and costs. It is recognized that Fluor’s data would need to be adjusted to

ensure an apples‐to‐apples comparison with the other technologies.

Nexant made the estimated adjustments by: firstly, pro‐rated Fluor’s total CO2 regeneration duty

from 90% to 85%. The PCC auxiliary power consumption, CO2 compression power requirements and

cooling duty were also revised down accordingly. Finally, Fluor’s PCC plant CAPEX was reduced by

5% to account for the smaller absorber size.

Table 6‐5 shows the estimated PCC costs and ranking after adjusting for Fluor’s CO2 capture rate.

Rank values in green indicate that the technology has moved up in ranking while values in red mean

that the technology has slid down from the initial evaluation. Rankings in blue are unchanged from

the initial economic evaluation. Figure 6‐2 is the graphical representation of the COEs, adjusted for

Fluor’s 85% CO2 capture rate.

Based on the adjustments made to account for 85% CO2 capture rate for Fluor, its COE is now

$35.0/MWh, or about a $1.5/MWh decrease from the initial evaluation.



Table 6‐5 Incremental PCC Costs for Various Licensors after CO2 Capture Rate Adjustment for Fluor

Generic 30%

MEA PCC

Design Alstom BASF / Linde Fluor

HTC

Purenergy MHI Shell CanSolv

CAPEX Estimate, $MM US USGC

PCC Plant + CO2 Compression [Note

2] 181.4 234.7 187.7 174.0 194.5 178.8 194.9

Flue Gas Blower 14.2 14.2 14.2 14.2 14.2 14.2 14.2


TOTAL 228.4 281.4 232.3 219.7 237.8 223.9 239.5



Fixed Costs 11.0 13.3 11.1 10.9 11.4 10.8 11.6

TOTAL 18.5 21.0 18.7 18.4 18.7 18.3 19.1

37.6 41.4 35.3 35.0 36.2 35.1 36.0

N/A 6 3 1 5 2 4Ranking based on COE


Incremental Costs to Poza Rica NGCC

without CO2 Capture [Note 1]

Estimated Cost of Electricity (COE),

$/MWh [Note 4]


Note 2 ‐ All except Nexant 'Generic 30% MEA Design' are based on vendor‐provided data, which are considered proprietary.





Figure 6‐2 Incremental COEs for Various Licensors after CO2 Capture Rate Adjustment for Fluor

36.5

35.1 35.3 36.0 36.2

41.4

35.0

25

30

35

40

45


Increm

ental COE, $/M

Wh

Incremental COE based on Licensors' DataIncremental COE Adjusted for 85% CO2 Capture for Fluor



6.6 ECONOMIC EVALUATION RESULTS SENSITIVITY TO PCC CAPEX

As mentioned in Section 6.3, the PCC capital costs were provided by each of the PCC licensors as a

single value based on potentially different design philosophies, estimation details and methodology.

While the quoted CAPEXs are fairly consistent against the generic MEA CAPEX, each can easily vary

by ±10%.

To determine the sensitivity of the relative economic ranking to potential CAPEX variations, the

COEs were re‐evaluated for each PCC at 90% and 110% of the quoted PCC CAPEX. The Nexant‐

designed systems (flue gas blower, CO2 capture and compression, and NGCC plant modifications)

CAPEXs were not changed because they were designed and estimated on a consistent basis.

The bar‐chart in Figure 6‐3 shows the COEs for the six PCC technologies at the baseline and ±10%

PCC plant costs, for CO2 capture rates of 85%. The first bar (in blue) represents incremental COE

based on 100% of the licensor quoted CAPEX for the licensed amine plant. The second bar (in tan)

represents incremental COE based on 110% of the licensor quoted CAPEX. Lastly, the third bar (in

green) represents incremental COE based on 90% of the licensor quoted CAPEX.

The data show that at this level of accuracy, it cannot be determined if any one of the top 5 (all

except Alstom) technologies stands out among the rest. For example, Fluor may have the lowest

COE (blue bar) based on its quoted CAPEX (after adjustment to 85% CO2 capture), but just a 10%

increase in its PCC CAPEX would cause its COE (tan bar) to go up to $36.4/MWh, which would be

higher than the highest COE based on quoted CAPEX by HTC (blue bar, $36.2/MWh). Conversely, the

Fluor COE of $35.0/MWh (blue bar) at the licensor‐quoted CAPEX is higher than the highest COE

based on 90% of HTC’s quoted CAPEX (green bar, $34.6/MWh).

Within the licensors’ provided CAPEX accuracy, it would therefore be difficult to establish a relative

ranking of the top five PCC candidates with certainty.



Figure 6‐3 Incremental COEs for Various Licensors with ±10% PCC CAPEX

35.0 35.1 35.3 36.0 36.2

41.4

36.4 36.5 36.8 37.5 37.7

43.3

33.7 33.8 33.8 34.4 34.6

39.4

25

30

35

40

45


Increm

ental COE, $/M

Wh

Incremental COE Based on Licensors' Data (adjusted for 85% CO2 Capture for Fluor)

Incremental COE for +10% PCC CAPEX

Incremental COE for ‐10% PCC CAPEX



6.7 ECONOMIC EVALUATION RESULTS SENSITIVITY TO REBOILING DUTY

In the questionnaire to the PCC licensors, besides asking for the CO2 regeneration duties for treating

the full‐size Poza Rica NGCC flue gas, the licensors were also requested to provide a typical

regeneration duty per unit of CO2 captured for both NGCC and coal‐fired flue gases, from either

their pilot or demonstration plant units. With the exception of Shell, all the licensors provided

typical duties from processing coal‐fired flue gases. A few of these licensors provided data from

pilot testing on NGCC flue gases.

Based on Nexant’s experience from past studies, the low concentration of CO2 in an NGCC flue gas

(around 4%) can adversely affect the CO2 pickup of the amine solvent, resulting in increased CO2

regeneration duty, in the order of about 15‐20% more than the corresponding duty for CO2 capture

from coal‐fired flue gas, which typically contains about 12% CO2. Part of the higher duty can be

reduced through process design adjustments such as colder feed gas or absorber inter‐stage cooling,

but these adjustments tend to result in trade‐offs in the form of higher capital costs.

From the licensors’ responses, it was noted that some of the quoted CO2 regeneration duties for the

Poza Rica NGCC were unexpectedly low compared to their stated results from coal‐fired flue gas test

runs. On a normalized basis, BASF, Fluor and HTC each showed CO2 regeneration duties for the Poza

Rica NGCC that are only 5‐7% more than what their test data for coal‐fired flue gas showed. Since

the amine plant designs were proprietary, it was not possible to determine the extent of process

adjustments and cost trade‐offs that were included in these licensor quotes.

Nexant thus performed a sensitivity check to determine the impact on relative ranking in case the

regeneration duty is higher than stated. Nexant re‐evaluated the COE by adjusting BASF, Fluor, and

HTC’s NGCC CO2 regeneration duties to 115% of their stated coal‐fired flue gas test data duties.

Figure 6‐4 shows the COEs for the various PCC technologies at their reported reboiling duties and

after the aforementioned adjustments to BASF, Fluor and HTC’s duties. Differences in COE among

the top five candidates are still small and within the accuracy of the study.



Figure 6‐4 Incremental COEs for Various Licensors after CO2 Regeneration Duty Adjustments

35.0 35.1 35.3 36.0 36.2

41.4

35.7 35.9 36.7

25

30

35

40

45


Increm

ental COE, $/M

Wh

Incremental COE Based on Licensors' Data (adjusted for 85% CO2 Capture for Fluor)

Incremental COE Based on Adjusted CO2 Regeneration Duties



6.8 ECONOMIC EVALUATION RESULTS SENSITIVITY TO NATURAL GAS PRICES

Figure 6‐5 shows the sensitivity of the COEs for the six PCC technologies to natural gas price ranging

from $1/GJ ($1.06/MMBtu) to $10/GJ ($10.55/MMBtu). The baseline gas price used for all PCC

technologies in the evaluations is $2.37/GJ ($2.50/MMBtu).

Consistent with the results presented in Section 6.6, the COEs for the top five technologies are very

close to one another and it cannot be determined if any one of them stands out among the rest, be

it at high ($10/GJ) or low ($1/GJ) gas prices. However, it should be noted that the COE for Fluor’s

PCC technology increases at a greater rate than the other technologies due to its lower net plant

efficiency. At about $5/GJ ($5.28/MMBtu), the MHI and BASF PCC technologies, which have slightly

higher efficiencies than Fluor, now have an equal COE with Fluor. At the highest natural gas price

($10/GJ) evaluated in this sensitivity analysis, BASF’s technology has the lowest COE ($45.6/MWh) of

the six licensors.

6.9 ECONOMIC EVALUATION RESULTS SENSITIVITY TO ANNUAL ON‐STREAM FACTOR (AOF)

Figure 6‐6 shows the sensitivity of the COEs for the six PCC technologies to the power plant’s AOF

ranging from 75% to 100%. The baseline AOF used for all PCC technologies in the evaluations is

91.3%, or 8,000 hours per year.

Consistent with the results presented in Section 6.6 and 6.8, the COEs for the top five technologies

are bunched very closely together and no one technology stands out among the others, regardless

of a high or low AOF.



Figure 6‐5 COE Sensitivity to Natural Gas Prices for Various PCC Licensors

32

37

42

47

52

0.0 2.0 4.0 6.0 8.0 10.0 12.0

COE, $/M

Wh

Natural Gas Price, $/GJ

Alstom BASF Fluor (85% Capture) HTC Purenergy MHI Shell Cansolv

Baseline NG price at $2.37/GJ



Figure 6‐6 COE Sensitivity to Annual On‐Stream Factor for Various PCC Licensors

31

36

41

46

51

75.0 80.0 85.0 90.0 95.0 100.0

COE, $/M

Wh

Annual On‐Stream Factor, %

Alstom BASF Fluor (85% Capture) HTC Purenergy MHI Shell Cansolv

Baseline AOF of 91.3%(8,000 hours per year)



6.10 ESTIMATED PCC PLOT SPACE REQUIREMENTS

Figure 5‐8 in Section 5.8.2 shows the preliminary, aerial view of the Poza Rica NGCC after 30% MEA

PCC retrofit. The figure clearly shows that there is sufficient plot space required for a PCC retrofit. In

the questionnaire to the PCC licensors, Nexant requested the dimensions of the different PCC

sections. Based on the licensors’ responses, together with Nexant’s estimate for the area of the CO2

compression section, the total plot space requirements for each technology’s PCC plant, including

the flue gas blower and CO2 compression/dehydration units but excluding plant modifications, are

tabulated in Table 6‐6.

Table 6‐6 Estimated PCC Plot Space Requirements

PCC Technology

Total Plot Space Requirements, including

Flue Gas Blower & CO2

Compression/Dehydration excluding

Plant Mods, m2 (ft2)

30% MEA 9,000 (96,000)

Alstom 14,000 (150,000)

BASF 11,000 (120,000)

Fluor 6,300 (68,000)

HTC Purenergy 17,000 (180,000)

MHI 6,700 (72,000)

Shell Cansolv 6,900 (74,000)

The estimated total available plot space at the Poza Rica plant, not including space available for

plant modifications, is 24,500 m2 (264,000 ft2). This is much larger than the corresponding plot space

required by any one of the PCC technologies evaluated in this study.

The bulk of the plot space taken up by plant modifications, per the 30% MEA case, is the new

cooling tower and CW pump house, as depicted in Figure 5‐8. The estimated area occupied by these

units is about 1,950 m2 (21,000 ft2). Although several of the PCC licensors’ technologies require

larger CW flows than the 30% MEA‐based PCC, they are expected to require no more than two

additional cooling cells. Figure 5‐8 shows that there should be sufficient space around the new PCC

cooling tower to extend it by the two additional cooling cells required to accommodate the

increased CW demands.

Based on this analysis, the Poza Rica plant is expected to have sufficient area to support any one of

the six PCC technologies evaluated.



7. SUMMARY AND CONCLUSIONS

7.1 SUMMARY AND CONCLUSIONS

A preliminary carbon capture technology assessment and screening exercise was carried out with

the objective to identify the most appropriate, commercially‐available post‐combustion carbon

capture (PCC) technology for NGCC power plants in Mexico. This was to be followed by a more

detailed evaluation of the selected technology, which would serve as the basis for the development

of a conceptual design of a carbon capture pilot plant to be located at Poza Rica power station in

Veracruz. The World Bank’s and GoM’s desire is to design, build and operate the Poza Rica pilot

plant by 2019. Against that near‐term objective and the preliminary assessment performed, Nexant

recommends that the technology of interest should be focused on amine solvent‐based absorption

processes, of which (1) CO2 capture from an NGCC flue gas has already been in commercial practice,

albeit at a small scale, and (2) there are several well‐respected companies that are currently

developing second‐generation amine absorption CO2 capture processes, which promise better

energy efficiency and lower costs when compared with current state‐of‐the‐art 30% MEA

technology.

The current state‐of‐the‐art amine PCC technology for NGCC application is represented by that of

the Bellingham plant, located in Massachusetts, in the USA. The plant was engineered, constructed

and operated by Fluor Corporation. It was operated from 1991 to 2005, capturing CO2 not for

greenhouse gas mitigation purposes, but for industrial usage. During its operation, it captured about

350 STPD of CO2 from a slip stream of flue gas from a 320 MW NGCC power plant.

Six well‐known amine solvent‐based PCC technology licensors participated in the study and provided

data for Nexant to perform a more detailed technology evaluation, based on a full‐scale design

analysis of retrofitting the Poza Roca NGCC plant for CO2 capture. The six advanced amine capture

processes were compared against a generic state‐of‐the‐art amine design that was developed by

Nexant, based on 30 wt% MEA.

7.1.1 Design Analysis of Retrofitting Poza Rica Plant for Generic 30% MEA‐Based PCC

As would be expected, retrofitting Poza Rica for CO2 capture will significantly impact the plant’s

performance and economics. The retrofitted Poza Rica NGCC’s net power export is expected to be

reduced by 46 MW, or 19%, from 242 MW to 196 MW. The corresponding net plant efficiency would

decrease from 51.8% to 42.0%, a loss of almost 10 percentage points, as shown in Table 6‐1.

With respect to the economic impact, a COE increase in the order of $37.6/MWh is to be expected.

This represents a 92.4% increase in COE, meaning that the COE of the retrofitted Poza Rica plant

with PCC is almost double that of the existing operation without capture.

It should also be noted that retrofitting a power plant for post‐combustion CO2 capture is very much

site and configuration specific. This study is for Poza Rica with the configuration of a



Siemens/Westinghouse W501F gas turbine feeding into three small 27 MWe steam turbines.

Specific retrofit requirements may not be the same under different conditions.

7.1.2 Comparison of Six Advanced Amine‐based PCC Technologies

Nexant reviewed and analyzed the data provided by the various technology licensors. To the best of

its abilities and using sound engineering reasoning, Nexant adjusted and filled in missing data in the

evaluation process to ensure reasonable levels of consistency. Thus, the final assessment only

presents Nexant’s interpretation of the various technologies. Nexant makes no claims as to the

accuracy of the data provided (or lack thereof) as the basis for the study, nor the relative ranking as

a true representation of the technology status.

All six advanced amine‐based PCC technologies show a lower heat of regeneration compared to

generic 30% MEA, by about 20 to 25%. Within the group, however, the difference is small, only ±

3%. As a result, all six technologies show an improvement in overall efficiency over the generic 30%

MEA based retrofitted Poza Rica plant – a loss of plant efficiency ranging from 8.4 to 9.3 percentage

point instead, of 9.9, shown in Table 6‐2and Table 6‐3.

Per the agreed‐upon methodology, all six technologies were ranked based on COE as the economic

indicator, of which the licensor‐provided PCC plant CAPEX have a significant contribution. The

CAPEXs provided for the stand‐alone PCC plant from the various licensors, after making necessary

adjustments to bring the cost basis to a common USGC location, are within a reasonable range of

one other. The only exception is the PCC CAPEX from Alstom, which is about 41% higher than that

estimated for Nexant’s generic MEA design. The CAPEXs for the rest of the PCC technologies fall

within 98% to 112% of Nexant’s estimate. The Alstom provided cost was used, as is, in Nexant’s

economic evaluation.

Based on the calculated incremental increase in COE as the economic indicator, all of the advanced

PCC technologies under development show an improvement over the generic Nexant reference

MEA design. The only exception is Alstom because of its high CAPEX. The differences in COE among

the top five licensors, however, are within 4% of one another.

Within the level of data accuracy for the study, it would be reasonable to conclude that the top five

PCC technologies all have similar economic performances and it cannot be determined, with

certainty, that one is clearly superior to the rest. If three ‘top of its class’ candidates must be

chosen from the list, based on the COE results, then these would have to be Fluor, MHI, and BASF,

as shown in Figure 6‐3 in Section 6.5.

Final technology selection for future Poza Rica PCC implementation would, most likely, need to take

into other factors into consideration, such as process guarantee, technology licensing fee,

willingness to work with the GoM stakeholders to take on active role of participation into the

project, etc., as required.



7.2 PCC TECHNOLOGY LICENSORS’ REVIEW AND COMMENT

A copy of the drafted report, after the World Bank’s review and with its comments incorporated,

was provided to all six of the PCC technology licensors for their review and comment. This was done

on March 16, 2016 with a request to reply no later than April 1, 2016. Of the six licensors, only MHI

and Alstom replied. MHI’s comments, mainly on Section 4.5, have been incorporated. Alstom’s

comments are incorporated in Appendix G.

107

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