Report to the

Global CCS Institute

Final Front‐End Engineering and

Design Study Report

January 2012

 
DISCLAIMER

This Report and the contents hereof (collectively, this 

“Report”) are being provided pursuant to and in 

accordance with that certain Funding Agreement by 

and between the Global Carbon Capture and Storage 

Institute Ltd. and Tenaska, Inc. (the “Funding 

Agreement”). Except as otherwise explicitly stated in 

the Funding Agreement, the provisions of the 

Funding Agreement are for the sole protection and 

legal benefit of the parties thereto, and their permitted 

successors and assigns, and no other person or entity 

shall be a direct or indirect beneficiary of, or have 

any direct or indirect cause of action or claim against, 

any party arising from the Funding Agreement or the 

publication, disclosure or distribution of this Report. 

This Report does not constitute the provision of 

engineering or design services or advice and should 

not be utilized or relied on by any person or entity as 

engineering or design services or advice. For the 

avoidance of doubt, neither Tenaska, Inc., Tenaska 

Trailblazer Partners LLC, nor their affiliates shall be 

liable to any third party for any harm or loss 

associated with utilization of or reliance on this 

Report. 
Abstract 

The Trailblazer Energy Center (Trailblazer or Project) is a supercritical pulverized coal 

electric generating station under development by Tenaska. Trailblazer is expected to be 

the first new-build pulverized coal plant in the USA to incorporate a commercial-scale 

post-combustion carbon dioxide capture plant into the initial design. The Project will be 

designed to capture 85 to 90 percent of the carbon dioxide that otherwise would be 

emitted into the atmosphere. The Project will generate nominally 760 MW gross at 

summer ambient temperature with the CO2 capture plant operating. The site is in Nolan 

County, Texas, United States of America (USA), approximately nine miles east of 

Sweetwater, Texas. 

Tenaska selected Fluor Econamine FG PlusSM technology and contracted with Fluor to 

complete a Front-End Engineering and Design (FEED) study for the carbon dioxide 

capture portion of the Project. This report provides a complete summary of the FEED 

study effort including: pertinent Project background information, the scope of facilities 

covered, the scope of the FEED study services, identification and treatment of health, 

safety, and environmental risk issues, highlights and challenges, next steps, lessons 

learned, and conclusions. 

This is the eleventh in a series of knowledge sharing reports on Carbon Capture and 

Storage (CCS), developed by Tenaska for the Global CCS Institute. 
Final Front-End Engineering and Design Study Report 

January 2012 

Table of Contents 

1.0 INTRODUCTION AND BACKGROUND .................................................................. 1

1.1 Project Overview ........................................................................................................ 1

1.2 Developer Background .............................................................................................. 2

1.3 Partner Information .................................................................................................... 3

1.4 Project Development History and Status ................................................................. 4

1.5 Technology and Engineering Providers .................................................................. 7

1.5.1 Owner’s Engineer ................................................................................................................ 7

1.5.2 EPC Contractor ................................................................................................................... 7

1.5.3 CO2 Capture Technology Provider Selection ...................................................................... 8

1.5.4 CO2 Capture Technology Overview .................................................................................... 9

1.6 FEED Study Requirement and Objective ............................................................... 11

2.0 PURPOSE AND GOALS ................................................................................... 12

2.1 Trailblazer Project Purpose and Goals .................................................................. 12

2.1.1 Carbon Regulation Early Mover .............................................................................. 12

2.1.2 Strategic Access to Existing CO2 Markets ............................................................. 12

2.1.3 National Energy Security ......................................................................................... 12

2.2 Trailblazer CC Plant FEED Study Purpose and Goals .......................................... 13

2.3 Final FEED Study Report Purpose and Goals ....................................................... 13

3.0 EXECUTIVE SUMMARY ................................................................................... 14

3.1 Background and Overview ...................................................................................... 14

3.2 Results and Conclusions ......................................................................................... 15

3.3 Summary of FEED Study Lessons Learned .......................................................... 15

4.0 CC PLANT PROJECT FACILITIES SCOPE ......................................................... 18

4.1 Background Information .......................................................................................... 18

4.2 Division of Responsibility, Interface and Battery Limits ...................................... 18

4.3 Scope of Facilities Included .................................................................................... 19

4.4 Exclusions ................................................................................................................. 21

5.0 FEED STUDY SCOPE OF SERVICES ............................................................... 22

5.1 Progression/Schedule .............................................................................................. 23

5.2 Process Engineering ................................................................................................ 23
5.2.1 Design Basis ..................................................................................................................... 23

5.2.2 Process Simulation and Heat and Material Balances ........................................................ 29

5.2.3 Process Equipment Data Sheets ...................................................................................... 29

5.2.4 P&IDs and Summaries ...................................................................................................... 30

5.2.5 Design Reviews ................................................................................................................ 30

5.3 Equipment Definition ............................................................................................... 31

5.4 Equipment Pricing .................................................................................................... 33

5.5 Plant Design & Model ............................................................................................... 34

5.6 Bulk Material Quantification and Pricing ............................................................... 35

5.6.1 Types ................................................................................................................................ 35

5.6.2 Quantification Methods ...................................................................................................... 36

5.6.3 Pricing Methods ................................................................................................................ 36

5.7 EPC Execution Planning .......................................................................................... 37

5.7.1 Execution Method and Schedule ....................................................................................... 38

5.7.2 Engineering and Support Services .................................................................................... 39

5.7.3 Procurement ...................................................................................................................... 39

5.7.4 Construction ...................................................................................................................... 39

5.7.5 Commissioning .................................................................................................................. 40

5.8 Capital Cost Estimation ........................................................................................... 41

5.8.1 Direct Field Costs .............................................................................................................. 42

5.8.2 Indirect Field Costs............................................................................................................ 42

5.8.3 Home Office Costs ............................................................................................................ 42

5.8.4 Miscellaneous Costs ......................................................................................................... 43

5.8.5 Project Company (Owners’) Costs .................................................................................... 43

5.8.6 Escalation and Contingency .............................................................................................. 44

5.8.7 Project Code of Accounts .................................................................................................. 44

5.8.8 Open Book Estimate Approach ......................................................................................... 45

5.8.9 Capital Cost ....................................................................................................................... 46

5.9 Operating Cost Estimation ...................................................................................... 46

5.10 Performance Summary ............................................................................................ 48

5.11 FEED Study Completion .......................................................................................... 49

5.12 Potential Future Value Engineering and Optimization Studies ........................... 50

6.0 HEALTH, SAFETY AND ENVIRONMENTAL ITEMS ............................................... 51

6.1 Process Hazard Analysis ......................................................................................... 51

6.1.1 HAZID ............................................................................................................................... 51

6.1.2 HAZOP .............................................................................................................................. 53
6.2 Air Emissions ............................................................................................................ 54

6.3 Wastes ....................................................................................................................... 55

6.4 Fire Protection .......................................................................................................... 56

6.5 Dispersion Modeling ................................................................................................ 56

7.0 HIGHLIGHTS AND CHALLENGES ...................................................................... 58

7.1 Highlights .................................................................................................................. 58

7.2 Challenges ................................................................................................................ 62

8.0 NEXT STEPS ................................................................................................. 64

8.1 Tenaska Responsibilities ......................................................................................... 64

8.2 Fluor Responsibilities .............................................................................................. 64

9.0 LESSONS LEARNED ...................................................................................... 66

10.0 RELEVANCE TO CARBON CAPTURE AND STORAGE .......................................... 68

11.0 CONCLUSIONS .............................................................................................. 69

12.0 ACRONYMS AND CITATIONS ........................................................................... 71
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1.0 Introduction and Background 

1.1 Project Overview 

The Trailblazer Energy Center (Trailblazer or Project) is a supercritical pulverized coal 

electric generating station (PC Plant) combined with a commercial-scale, postcombustion carbon dioxide (CO2) capture plant (CC Plant) under development by 

Tenaska. The Project will generate nominally 760 MW gross at summer ambient 

temperature with the CC Plant operating. The site is in Nolan County, Texas, United 

States of America (USA), approximately nine miles east of Sweetwater, Texas. 

Trailblazer is expected to be the first new-build coal-fueled power plant in the USA to 

incorporate a post-combustion CC Plant into the initial design. The station is being 

designed to capture 85 to 90 percent of the CO2 that otherwise would be emitted into the 

atmosphere which is nominally 17,100 to 18,100 short tons per day (16,420 metric tons 

per day). CO2 from the Project will be sold into the Permian Basin CO2 market, where it 

will be used for enhanced oil recovery (EOR) and, ultimately, permanently stored 

underground. 

Figure 1 – Trailblazer Plant Conceptual Illustration 

Sub-bituminous coal will be delivered to the Project from the Powder River Basin (PRB) 

in Wyoming via the Union Pacific (UP) and/or Burlington Northern Santa Fe (BNSF) 

railroads. The Project site is bordered on the north by the UP and on the south by the 

BNSF. The Project will interconnect to the Electric Reliability Council of Texas 

(ERCOT) 345 kV electrical system, most likely at a substation about six miles from the 

Project site. 

The Project is being developed by Tenaska, and is owned by Tenaska Trailblazer 

Partners, LLC. Tenaska Trailblazer Partners, LLC is owned 65 percent by affiliates of 

Tenaska and 35 percent by Arch Coal, Inc. 

See http://www.tenaskatrailblazer.com for more information about the Project. 
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1.2 Developer Background 

Since its founding in 1987, Tenaska has successfully developed and constructed 15 

power generation facilities, totaling more than 9,000 MW. Today, Tenaska operates 

eight power generation facilities totaling 6,700 MW that it owns in partnership with other 

companies. Tenaska also provides energy risk management services and is involved in 

asset acquisition and management, power marketing, fuel supply, natural gas exploration, 

production and transportation systems, biofuels marketing and electric transmission 

development. 

Tenaska Capital Management, an affiliate, provides management services for standalone 

private equity funds, with almost $4.5 billion USA dollars (USD) in assets, including 

nine power plants and multiple natural gas midstream assets, including gas storage, 

gathering and processing facilities. In 2010, Tenaska and its affiliates managed 

approximately 34,000 MW of assets on behalf of a variety of customers and private 

equity investors. 

An affiliate, Tenaska Marketing Ventures (TMV), is regarded as one of the top 10 natural 

gas marketers in North America, and provides natural gas commodity, volume 

management, hedging and asset management products and services. In 2010, TMV was 

ranked No. 1 in the USA in natural gas pipeline capacity trading according to Bostonbased CapacityCenter.com, which monitors and collects capacity and operational 

information on all interstate pipelines. 

Another affiliate, Tenaska Power Services Co. (TPS), specializes in electric power 

marketing and asset management for utilities and non-utility generators and is one of the 

largest marketers of electric power in the USA. TPS has developed a significant presence 

in the wind industry and continues to be the leading third-party provider of scheduling, 

marketing, and asset management services for wind generation in ERCOT and the 

Southwest Power Pool. 

In 2010, Tenaska had gross operating revenues of USD$10 billion and assets of 

approximately USD$3.2 billion. In 2011, Forbes magazine ranked Tenaska as 25th 

among the largest privately-held USA companies, based on 2010 revenues. 

 
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Figure 2 – Tenaska Projects and Office Locations 

See http://www.tenaska.com for more information about Tenaska. 

1.3 Partner Information 

In March 2010, Arch Coal acquired a 35 percent share of Tenaska Trailblazer Partners, 

LLC (the Project Company) from affiliates of Tenaska. St. Louis-based Arch Coal is the 

second largest U.S. coal producer, with revenues of USD$3.2 billion in 2010. Through 

its national network of mines, Arch Coal supplies cleaner-burning, low-sulfur coal to 

U.S. power producers to fuel roughly 8 percent of the nation’s electricity. The company 

also ships coal to domestic and international steel manufacturers as well as international 

power producers. 

In total, Arch Coal contributes about 16 percent of the domestic coal supply from 23 

mining complexes in Wyoming, Utah, Colorado, Illinois, West Virginia, Kentucky, 

Virginia, and Maryland. 

Arch Coal controls a domestic reserve base totaling 5.5 billion tons (4.26 billion metric 

tons). 

In addition to becoming a valued partner, Arch Coal also will provide low-sulfur PRB 

coal to the Project under a 20-year coal supply agreement. 

See http://www.archcoal.com for more information about Arch Coal. 
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1.4 Project Development History and Status 

In early 2007 Tenaska developed the opinion that it was increasingly likely that the USA 

would take steps to regulate CO2 emissions. In response, the company formed a multidiscipline task force to investigate the development opportunities that would be created in 

a carbon-constrained environment. The task force believed there could be economic 

incentives for “first movers” that might not be available on an ongoing basis to those who 

were slower to react to this change. 

The company drew task force members from the Development, Environmental, and 

Engineering groups within Tenaska. After a six-month review, the task force 

recommended development of a PC plant with post-combustion CO2 capture in west 

Texas. The company’s Executive Board approved the recommendation in the fourth 

quarter of 2007. 

Following internal approval, Tenaska has advanced Project development according to the 

milestone schedule shown in Figure 3 below. Additionally, the report to the Global CCS 

Institute titled Development of the Tenaska Trailblazer Energy Center, dated August 

2010, provides a history of the Project, the rationale behind the site selection and 

technology selection, and identifies key challenges the Project faces. 

Figure 3 – Historical Trailblazer Project Development 

Date Activity / Milestone 

2007  Conceptual phase conducted 

 Tenaska Board approves development of the Project 

February 2008 

 Site procured 

 Air permit application filed with the Texas Commission on Environmental 

Quality (TCEQ) 

 Electric interconnection request filed with ERCOT 

 Project announced 

July 2008 Local office in Sweetwater, Texas opened 

September 2008 ERCOT issues its initial study of the Project’s interconnection request 

December 2008 Engaged Burns & McDonnell to serve as the Owner’s Engineer 

January 2009 Nolan County tax abatement granted 

February 2009 TCEQ issues draft air permit for public comment 

March 2009 Hospital district tax abatement granted 

May 2009 

 Texas Legislature passes clean energy legislation that provides grants and tax 

incentives for carbon-fueled electric generating projects that capture at least 70 

percent of the CO2 they otherwise would emit and meet stringent air emission 

standards for nitrogen oxides, sulfur dioxide, particulate matter and mercury 

 Texas Legislature passes legislation that establishes a framework for regulation 

of CO2 sequestration and storage 
-5-

Date Activity / Milestone 

June 2009 Fluor Enterprises selected as Engineering, Construction and Procurement (EPC) 

contractor 

July 2009 Tenaska requested direct referral of its air permit application to the Texas State 

Office of Administrative Hearings for a contested case hearing 

March 2010  Arch Coal, Inc. purchases 35 percent share of the Project company 

 Project signs a 20-year coal supply agreement with Arch Coal 

April 2010  Tenaska commits to use of dry cooling technology 

 Tenaska signs settlement agreement with the Environmental Defense Fund 

June 2010 Trailblazer signs a funding agreement with the Global Carbon Capture and Storage 

Institute (Global CCS Institute) to receive a USD$7 million grant 

July 2010 Fluor Econamine FG Plus CO2 capture technology is selected 

August 2010 Fluor begins the CC Plant FEED study 

December 2010 Trailblazer receives its final air permits from the TCEQ 

May 2011 Tenaska open book review of CC Plant cost estimate 

June 2011 CC Plant FEED study completed 

July 2011 Tenaska signs an agreement with the City of Stamford for a portion of its water 

supply needs 

One of the well-known challenges with CCS is the cost – primarily in terms of the capital 

cost and energy consumption. Under current market conditions, power plants with CCS 

cannot compete with those without CCS. The strategic location of the Project provides 

the ability to sell CO2 into the mature Permian Basin EOR market. This defrays some of 

the costs of CCS. However, the current CO2 market prices are insufficient to cover the 

entire costs of CO2 capture. In addition, the CO2 prices vary as a function of oil prices, 

which introduces uncertainty in this revenue stream over the life of the Project. 

Thus, the Project requires some recognition of the value associated with capturing CO2 in 

order to be economic. With the status of the USA political climate (which is notably 

different than in 2007 when Tenaska launched the Project) the timing for such 

recognition and, thus, further Project development, is uncertain. As such, on the 

engineering side, the Project is currently in the documentation stage and will undergo 

only very slow development until the key Project signals change. Overall project 

development will continue to advance in the areas that are required to maintain an “early 

mover” position. Some of these areas include water supply, maintaining the air permit, 

lobbying, legislative support, and local community interaction on the Project. 

Section 8.0 discusses next steps for the Project in general and the CC Plant engineering in 

particular. 

Figure 4 below depicts the current development status of the Trailblazer project using the 

project development framework tailored for CCS projects in the ‘Define’ phase by the 

Global CCS Institute. 
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Figure 4 – Trailblazer Project Development Status 

Activity Trailblazer Status during ‘Define’ Phase 

Project Context and 

Opportunity Definition and 

Recommendation 

Completed in 2007 with Tenaska Board approval to proceed. 

Site Selection Completed in February 2008 with purchase of the Project site 

Stakeholder and External 

Relations 

Public engagement activities ongoing 

Environment Environmental studies completed; air permits received in 2010 

Permit matrix developed 

Health and Safety Completed Hazard Identification (HAZID) and Hazard and Operability 

(HAZOP) studies. A safety program will be implemented for construction, 

commissioning, and operations consistent with the programs used at other 

Tenaska facilities. 

Fuel Supply 20-year fuel agreement with Arch Coal executed in March 2010 

Power Plant – Capture 

Facility 

 Preliminary PC Plant engineering completed 

 CC Plant FEED study completed 

 Potential value engineering opportunities identified 

 Basic design interfaces defined 

CO2 Product  Conservative preliminary CO2 specification established for the FEED 

study based on industry data. 

 CO2 transportation pipeline route will be determined once an agreement 

is in place with the CO2 purchaser 

Infrastructure  Only minor railroad right-of-way (ROW) required as both BNSF and UP 

railroads both border the Project site. Railroad interconnections will be 

determined once rail transportation contracts are in place 

 Electric transmission interconnection request submitted; Facility study 

confirmed the ability to interconnect. Recently the studies have been 

reopened to accommodate a later commercial operations date. 

Project Delivery  Fluor Enterprises was selected as the EPC contractor and the CO2

capture technology provider 

 Relationship established under a memorandum of understanding 

including an EPC term sheet 

 EPC contract not yet completed 

Capital / Operating Costs FEED study resulted in a firm, “overnight” EPC price for the CC Plant. PC 

Plant pricing is indicative and will be finalized prior to EPC contract 

signing. 

Operations Tenaska will work with its operations subsidiary to define a plan 

Revenue and Trading Power and CO2 off-take parties have not been selected and agreements will 

need to be negotiated 

Ownership and Legal Project ownership and governance structure is in place. Tenaska entities 

own 65% of the Project company and Arch Coal purchased a 35% share of 

the Project company in March 2010. 

IP Management Fluor IP protection covered under a license agreement. EPC and 

technology provider are the same company. 

Financial Analysis  Market studies for power and CO2 completed 

 Detailed proforma constructed 

Risk Owner Risk analysis will take place prior to financial close. EPC Contract 

structure for both the PC and CC Plants envisioned to be fixed price, datecertain type with certain risks allocated to the contractor and technology 
-7-

Activity Trailblazer Status during ‘Define’ Phase 

provider. 

Funding  Project owners have provided development funding 

 Funding agreement with Global CCS Institute in place 

Future Work Plan  Public engagement efforts continue 

 Engineering work suspended pending USA federal government action 

on carbon capture incentives and market conditions 

 Maintain environmental permits 

Status of Studies Various technical studies completed as outlined in reports provided to the 

Global CCS Institute 

1.5 Technology and Engineering Providers 

1.5.1 Owner’s Engineer 

In December 2008, prior to solicitation and selection of the Project EPC contractor and 

CO2 capture technology provider, Tenaska engaged Burns & McDonnell to be the 

Owner’s Engineer. Burns & McDonnell is a full-service engineering, architecture, 

construction, environmental and consulting solutions firm. Its staff of more than 3,000 

represents virtually all design disciplines. Burns & McDonnell plans, designs, permits, 

constructs and manages facilities all over the world. In 2010, the Engineering NewsRecord ranked Burns & McDonnell number 22 in design firms and number 8 in power 

plant design firms. See http://www.burnsmcd.com for more information. 

1.5.2 EPC Contractor 

In order to develop the Project with guarantees for plant performance and to obtain a high 

percentage of the capital cost for the Project on a firm price basis (developed during an 

open book estimate phase), Tenaska conducted a competitive proposal process to select 

an EPC contractor for the Project. 

Immediately following engagement of Burns & McDonnell, Tenaska and Burns & 

McDonnell developed and issued a Request for Proposal (RFP) to initiate this process. 

The RFP went to experienced and reputable engineering firms, CO2 technology 

providers, and EPC contractors. 

In the RFP, Tenaska asked for proposals to include (1) a PC Plant based on a recent 

similar- size reference project executed by the contractor and, separately, (2) a CC Plant 

based on a the contractor’s preferred technology or technologies. By doing so, Tenaska 

and Burns & McDonnell were able to evaluate the prospective contractors’ experience 

with and ability to execute both parts of the Project scope. The RFP also revealed certain 

alignments and conflicts among the pool of prospective EPC contractors and leading CO2

capture technology providers. 

Tenaska received and evaluated multiple proposals. The evaluation criteria included 

indicative pricing, experience, performance, schedule, commercial terms, and ability to 

perform. 

In June 2009, after extensive analysis and proposal conditioning, Tenaska selected Fluor 

Enterprises, an affiliate of Fluor Corporation (collectively, Fluor) to be the EPC 
-8-

contractor for the Project. Fluor and Tenaska signed a Memorandum of Understanding 

(MOU) whereby the parties agreed to work together to define the scope of the Project and 

to develop and negotiate an EPC contract for the PC plant and, potentially, the CC plant. 

Although Fluor included its own Econamine FG+SM (EFG+) technology in the EPC bid, 

they remained open to engineering and constructing a third party technology or allowing 

the potential for a third party CO2 capture supplier/constructor to work at the Trailblazer 

site in parallel with Fluor. Tenaska required this flexibility as a provision of the MOU. 

1.5.3 CO2 Capture Technology Provider Selection 

After establishing the initial MOU with Fluor, Tenaska began a process to identify the 

preferred CC Plant technology provider and EPC contractor. Burns & McDonnell 

assumed the lead role to avoid any perception of conflict of interest with Fluor related to 

its in-house CO2 capture technology. 

The selected vendor would proceed into an approximately nine month (planned duration) 

FEED process to engineer the initial design, quantify capital cost for the CC plant 

(including all interface costs with the PC plant), and to establish performance guarantees. 

The selected vendor would need the financial strength to assume commercial risks 

associated with new technology should the Project proceed to construction and ultimately 

operation. 

The process included two phases – pre-qualification and competitive bidding. 

For the pre-qualification phase, conducted from June 2009 through September 2009, 

Tenaska contacted seven CO2 capture technology vendors to determine their level of 

technology development in the industry and their interest in entering into a competitive 

bidding process for award of the CC Plant FEED study. Six of the seven vendors 

responded with general information about their process technology, history of 

development, business profile and financial information. At the end of the prequalification phase, Tenaska and Burns & McDonnell analyzed the submissions and 

identified a shortlist of four vendors using Kepner-Tregoe Decision Analysis. 

For the subsequent competitive bidding phase, Tenaska, Fluor, and Burns & McDonnell 

developed a formal bid package containing commercial terms and conditions and 

technical specifications. Burns & McDonnell issued the package in October 2009 to the 

four shortlisted vendors. The package solicited indicative bids for either an engineerprocure (EP) approach or an EPC approach – whichever method the supplier preferred. 

One bidder submitted a bid under an EP approach and an EPC approach and three bidders 

submitted under an EPC approach only. Those technology providers that did not have inhouse EPC capability formed teams with contractors in order to meet the RFP 

requirements. 

Tenaska received all bids by January 2010. After bid evaluation, Tenaska selected Fluor 

to license, engineer, procure, and construct its EFG+ technology. In June 2010, the 

parties amended and restated the original MOU with the appropriate provisions to reflect 

that Fluor would conduct a FEED study for the CC plant. In the amended agreement, 

Fluor and Tenaska agreed to establish the Project capital cost through an open book 
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process. This was an important condition of the agreement because Tenaska selected 

Fluor, in part, based on an indicative capital cost bid. Thus, Tenaska required a higher 

level of transparency into the final capital cost estimate to rationalize any differences in 

the final cost against the bid cost. Section 5.8.8 discusses the Open Book Estimate 

Approach. 

Further information on the process undertaken by Tenaska to identify and select the 

preferred vendor to perform the CC Plant FEED study for the Project can be found in a 

separate report provided to the Global CCS Institute in January 2011 and titled CO2

Technology Evaluation, Methodology and Criteria. 

1.5.4 CO2 Capture Technology Overview 

Tenaska selected Fluor as the preferred supplier to perform the CC Plant FEED and 

proceed with the Project to completion. Fluor’s EFG+ CO2 capture technology is 

conceptually shown in Figure 5 below. Fluor formulated its amine-based solvent to 

recover CO2 from low-pressure, oxygen-containing streams. The EFG+ process is 

similar in overall concept to amine-based gas treating processes which have been 

practiced for many years in the natural gas, petrochemical, and refining industries. 

Figure 5 – EFG+ Simplified Process Flow Diagram (Generic*) 

*Note that this is generic drawing for EFG+; for Trailblazer, all cooling water 

exchangers are replaced with air coolers 

 

(DCC) 

BLOWER 

(STRIPPER) 
-10-

Below is a typical process description. Refer to Figure 5 above. 

The flue gas enters the bottom of the Direct Contact Cooler (DCC) where the gas is 

cooled by a circulating water stream. The circulating water stream contacts the flue gas 

over packing and removes the majority of any particulates present. Lowering the gas 

temperature is beneficial because: 

 Much of the water vapor contained in the flue gas is condensed and separated from 

the feed gas before entering the solvent system. The need to boil off excess water 

from the solvent loop is significantly reduced; 

 The reduction in water vapor flow reduces the overall mass flow to the blower; and 

 The lower temperature of the flue gas results in higher density and therefore lower 

volumetric flow rate to the blower. 

The circulating water enters the top of the DCC and is heated by the cooling and 

condensing of water vapor in the flue gas. Excess water, produced in the DCC from the 

condensing of water vapor in the flue gas, is routed to the battery limits after filtration. 

For applications where the flue gas contains higher levels of SO2, the top section of the 

DCC contains a circulating scrubbing solution that is dosed with sodium hydroxide. The 

purpose of the solution is to further reduce the SO2 content of the flue gas – to extremely 

low (single digit ppm) levels – since SO2 will create degradation of the solvent in the 

absorber. 

The cooled overhead gas from the DCC flows to the absorber via the blower. The flue 

gas enters the bottom of the absorber and flows upwards counter current to the circulating 

solvent. The solvent reacts chemically to remove the CO2 in the feed gas. Residue gas, 

consisting mainly of nitrogen and oxygen, is washed with a circulating wash water stream 

before leaving the top of the absorber. 

The CO2 rich solvent from the bottom of the absorber flows to the solvent regeneration 

section. The rich solvent is heated against hot lean solvent from the stripper in the 

solvent cross heat exchanger. The hot rich solvent then enters the stripper and flows 

down counter-current to stripping stream, which removes CO2 from the rich solvent. 

Heat for stripping is supplied by low pressure steam via the reboiler. Lean solvent from 

the stripper is cooled in the solvent cross heat exchanger and lean solvent cooler prior to 

be routed back to the absorber. A portion of the cooled lean solvent is diverted through a 

solvent filtration system to remove solution contaminants. 

The overhead vapor from the stripper is cooled and most of the water is condensed out of 

the low pressure CO2 product. The majority of the condensed water returns to the top of 

the stripper as reflux, while the balance returns to the absorber. The remaining low 

pressure CO2 product is routed to the compression section where the product CO2 is 

compressed and treated to meet the final product specifications. 

Some contaminants, such as heat stable salts (sulfates, nitrates, and oxalates of 

monoethanol amine (MEA)) and thermal/oxidation degradation products, cannot be 

removed in the solvent filtration package and must be removed through a reclaiming 
-11-

operation. In order to minimize solvent degradation, Fluor has recently developed a lowpressure, low residence time reclaiming system. 

Refer to Attachment 1, Page 3 for a full process description of the Fluor EFG+ 

technology. 

1.6 FEED Study Requirement and Objective 

Post-combustion CO2 capture has not yet been deployed at the scale needed to process 

the entire flue gas stream produced by a world-scale coal-fueled power plant. Doing so 

creates business and technical challenges. 

One of these challenges with such a first-of-a-kind deployment is that technology 

providers, original equipment manufacturers (OEMs), and EPC contractors do not yet 

possess the information or experience to firm-bid the elements of the plant at the scale 

required. Therefore, project developers have to fund a costly FEED study to define the 

costs and performance with enough certainty to establish commercial guarantees and to 

attract equity and debt financing. 

In defining how to achieve this objective, it is useful to reference industry standards. For 

example, the FEED study would generally meet the requirements of a Front End Loading 

3 study, as set out by Independent Project Analysis, Inc. Also the cost estimate would 

need to qualify as a Class 2 or Class 3 estimate according to the Association for the 

Advancement of Cost Engineering (AACE). Sometimes, this type of estimate is referred 

to as an “appropriations” or “authorization” grade estimate. AACE documented the 

requirements of its classification levels in International Recommended Practice No. 18R97 titled “Cost Estimate Classification System – As Applied in the Engineering, 

Procurement, and Construction for the Process Industries.” The document is available at 

www.aacei.org and is included as Attachment 6. 

Tenaska and Fluor developed a FEED study scope to meet these standards. The scope 

required Fluor to complete a nominally nine-month (planned duration) effort. The effort 

consisted of a progression of engineering activities to produce formal technical 

“deliverable” documents. These deliverables ultimately enabled Fluor to use highly 

accurate deterministic cost estimation techniques sufficient to support a firm-price 

commercial offering with a relatively low contingency allowance. Through conditions to 

its agreement with Fluor, Tenaska gained insight to the final CC Plant capital cost 

through an open book estimating process. 

Section 5.0 provides a detailed description of the FEED study scope of services. 
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2.0 Purpose and Goals 

This section describes the purpose and goals of: 

 the Trailblazer Project, 

 the Trailblazer CC Plant FEED Study, and 

 this report 

2.1 Trailblazer Project Purpose and Goals 

2.1.1 Carbon Regulation Early Mover 

In early 2007 Tenaska developed the opinion that it was increasingly likely that the USA 

would take steps to regulate CO2 emissions. In response, the company formed a multidiscipline task force to investigate the development opportunities that would be created in 

a carbon-constrained environment. The company drew task force members from the 

Development, Environmental, and Engineering groups within Tenaska. 

The task force believed there could be economic incentives for “first movers” that might 

not be available on an ongoing basis or to those who were slower to react to this change. 

After a six-month review, the task force recommended development of a pulverized coal 

plant with CO2 capture in West Texas. The company’s Executive Board approved the 

recommendation in the fourth quarter of 2007. 

2.1.2 Strategic Access to Existing CO2 Markets 

The task force also recommended the Project be strategically located in West Texas to 

provide access to the Permian Basin oilfields. The Permian Basin is the location of the 

world’s largest and most robust CO2 market which provides supply for Enhanced Oil 

Recovery (EOR). Oil producers have used EOR in the Permian Basin since the early 

1970s. As such, in Texas, rules and regulations are already in place with regard to CO2

handling and disposal. The addition of CO2 capture equipment will increase the cost of 

the Project and, in Trailblazer’s case, consume a significant amount of the electricity that 

otherwise would be available for sale. As a result, Tenaska viewed a robust CO2 market 

as being essential to the Project’s success. 

2.1.3 National Energy Security 

Tenaska conceived the Project during a period of energy turmoil in the USA. Events 

contributing this turmoil included: Venezuela’s reduced oil production in 2003, China’s 

increasing demand for oil throughout the mid 2000s, and the huge price spikes caused by 

Hurricanes Katrina and Rita in 2005. 

Trailblazer is envisioned to enhance the USA’s national energy security interests in three 

ways: 

 Providing a path forward for the use of coal – the nation’s most abundant and 

affordable fossil fuel – as an electric generating fuel in a carbon-constrained world; 

 Boosting domestic oil production using anthropogenic CO2; and 
-13-

 Providing affordable, reliable base load electric energy to help meet the nation’s 

growing electricity demand.

The USA government recognized all of these goals as being important to the continued 

energy security of the USA. 

2.2 Trailblazer CC Plant FEED Study Purpose and Goals 

The technical and commercial objectives of the FEED study were: 

Completion of pre-financing portion of the engineering which included process, 

mechanical, civil, structural, and electrical engineering for the CC Plant scope and which 

results in: 

 Confirmation of the expected performance backed by commercial guarantees; 

 Technical and execution planning in sufficient detail to support a highly-accurate 

EPC cost estimate and a firm price commercial offer for Project execution; 

 Affirmation that the EPC price is consistent with the indicative bid used in the 

evaluation and selection of Fluor with confirmation through an open-book review 

process; 

 A design meeting the Owner’s and industry standards for integrity, operability, 

availability, safety, and environmental profile; 

 An annual O&M cost estimate for the CC Plant; 

 Confirmation that scale up to a large commercial size is achievable; 

 Confirmation that major equipment can be procured for the configuration and sizes 

planned; and 

 Confirmation of constructability.

2.3 Final FEED Study Report Purpose and Goals 

The overall goal of this report is to provide information and insights that can be used by 

others embarking on a post-combustion CO2 capture project FEED study. 

The key purposes of this report are to: 

 Describe the scope of the CC Plant and the FEED study performed; 

 Provide FEED study results including cost and performance; 

 Describe challenges and highlights of the FEED study; 

 Confirm that construction and operation of a large scale CC plant integrated with a 

PC plant is feasible; 

 Confirm that the health, safety and environmental impacts associated with a CO2

capture plant are acceptable; 

 Provide the “next steps” required to advance the development of the Project; and 

 Provide lessons learned from the FEED study 
-14-

3.0 Executive Summary 

3.1 Background and Overview 

Trailblazer is a supercritical PC electric generating station under development in Nolan 

County, Texas, USA, approximately nine miles east of Sweetwater, Texas. Trailblazer is 

expected to be the first new-build coal plant in the USA to incorporate a commercialscale post-combustion CC Plant into the initial design. The Project will be designed to 

capture 85 to 90 percent of the CO2 that otherwise would be emitted into the atmosphere. 

The plant will generate nominally 760 MW gross (at the summer ambient temperature 

with the CC Plant operating). 

The aims of the Project are to capitalize on potential early-mover credits associated with 

potential carbon legislation, provide for beneficial reuse of the capture CO2 through EOR 

in the Permian Basin, and contribute to USA energy security through the use of coal and 

production of domestic oil. 

In advancing Project development, Tenaska conducted separate competitive and 

sequential processes to select the Project EPC contractor and the CC technology provider. 

Through these processes, Tenaska selected Fluor Enterprises for both roles including 

supply of the EFG+ CO2 capture technology. 

Tenaska contracted with Fluor to complete a FEED study for the CC Plant. A FEED 

study is necessary because suppliers in this developing industry do not yet have 

experience at commercial scale for a large CC plant. The main purpose of the FEED is to 

complete enough technical definition (requiring nominally 15 – 20 percent of the overall 

engineering and planning effort) of the Project to support firm price offering and 

commercial performance guarantees. 

Key activities in the FEED study included: clear definition of the CC Plant scope of 

facilities, division of responsibility, and interface with the PC Plant; process engineering 

(to establish the design basis, simulate the process, produce heat and material balances, 

etc); equipment definition and competitively-bid pricing; plant layout development and 

3D modeling; design reviews and the HAZOP study; bulk materials quantification and 

pricing; EPC execution planning and schedule development; and cost estimation. In 

defining the CC Plant scope, certain items have been excluded and assumed to be part of 

the PC Plant scope – for which the engineering and cost estimation has not been 

completed. 

This report provides a complete summary of the FEED study effort including: pertinent 

Project background information, the scope of facilities covered, the scope of the FEED 

study services, identification and treatment of health, safety, and environmental risk 

issues, highlights and challenges, next steps, lessons learned, and conclusions. 
-15-

3.2 Results and Conclusions 

Tenaska and Fluor achieved the goals of the CC Plant FEED study, resulting in: 

 A design which meets Tenaska and industry standards and notably so in the areas of 

safety (through incorporation of the findings from the hazard and operability study 

and air dispersion modeling) and environmental profile (through specification of the 

CO2 capture rate at and permitted air emissions in the design basis); 

 Confirmation that the technology can be scaled up to a constructable design at 

commercial size through (1) process and discipline engineering design and 

computational fluid dynamics (CFD) analysis, (2) 3D model development, and (3) 

receipt of firm price quotes for large equipment; 

 Production of engineering design and planning deliverables which supported 

deterministic cost estimation; 

 Confirmation of the cost estimate basis through an open-book process (described 

later); 

 A firm second-quarter overnight EPC price offer of USD$667,100,000 for the CC 

Plant that is consistent with the original indicative bid for the CC Plant. This supports 

the overall project (PC and CC Plants) cost basis consisting of (1) an EPC cost (with 

contingency and escalation) of USD$2,800,000,000 to USD$3,300,000,000 plus (2) 

Owner’s costs, interconnects, financing fees, and interest during construction at an 

additional USD$1,000,000,000 to USD$1,250,000,000; 

 An O&M cost estimate totaling nominally USD$10,400,000 per year (excluding 

power and steam consumption which represent net power generation losses for the 

overall project which includes both the PC and CC Plants); and 

 Establishment of performance guarantees which, after the addition of an appropriate 

margin, were consistent with the expected performance in Fluor’s indicative bid. 

3.3 Summary of FEED Study Lessons Learned 

Following is a list of the lessons learned in preparing for, conducting, and managing the 

CC Plant FEED study: 

 Interface Definition and Optimization. Defining and optimizing the interface between 

the PC and CC Plants was important during the CC Plant FEED study (e.g. heat 

integration). These two pieces of the overall Project scope are different technically 

and generally belong to two different industries (power and chemical process). As a 

result, it is natural that experience in the respective scope areas comes from different 

organizations and these organizations can have different codes, design criteria, and 

standard practices. It is necessary to have both organizations (whether they are the 

same company or different companies) directly involved. Furthermore, it is ideal if 

both pieces of the scope are developed simultaneously to realize synergies between 

the two scopes. 
-16-

 Single Point of Contact. Tenaska realized strong coordination from the direct 

involvement of both the PC and CC teams and reaffirmed the value of having both 

scopes awarded to one organization. By doing so, Fluor was able to apply common 

methods in areas such as project management, document control, and technical design 

procedures. This also reduced concerns with proper handling of confidential 

information and allowed greater transparency in seeking optimized heat integration. 

 Value Engineering. Tenaska experienced success with a continuous focus on value 

engineering through the FEED study as the capital cost estimate came in very near the 

indicative bid. Through this approach, the team reduced the capital cost by 

approximately USD$23,400,000. Some of the design ideas contributing to this 

reduction include the application of: 

o A single CO2 compressor soft starter for both machines; 

o Plate and Frame-type heat exchangers for stripper reboilers; 

o Optimized the absorber and DCC construction materials; 

o Eliminated large-bore alloy block and bypass valves; and 

o An “in-line” (instead of “right angle”) plot plan arrangement. 

 Vendor Support. Tenaska and Fluor experienced some minor difficulty in attracting 

vendor interest and, therefore, obtaining multiple compliant and competitive bids for 

all equipment. 

 Firm Project Economics. It is not yet known how CO2 regulations and prices will 

affect power prices locally and nationally. CO2 price support from regulations or 

legislation is necessary because CO2 prices available from EOR off-takers (a 

commonly used rule of thumb algorithm is CO2 price per million cubic feet = 2% of 

the posted project equivalent oil price per barrel) are insufficient to support CO2

capture – especially with the inherent volatility in the crude oil commodity market. 

Thus, during the FEED it was difficult to evaluate design alternatives. 

 Operations Support. Although Tenaska had substantial support in terms of project 

management and discipline engineering both internally and via Burns & McDonnell, 

the FEED team recommends a greater level of involvement from experienced 

operations personnel to ensure alignment with the operational capabilities determined 

in the design phase. 

 Capital Cost Estimate Accuracy. Tenaska selected Fluor as the CC Plant technology 

provider on the basis of multiple criteria, with one being the nonbinding indicative 

capital cost of the plant based on Econamine FG+ technology – perhaps an AACE 

Class 4 or 5 estimate with nominally +/- 30% accuracy. As such, a key objective of 

the FEED study was to complete engineering design definition to increase the 

accuracy of the estimate sufficiently to allow Fluor to offer a firm price for the CC 

Plant scope of the Project with a contingency allowance that was determined prior to 

the study. 

 
-17-

 Addressing Key Scale-Up Issues. With the large equipment required for the CC Plant 

and the scale-up it represents from previous experience, a few key areas required 

special engineering study. These included the mechanical design of the large flue gas 

ducts, CFD modeling of the flue gas flow in these ducts, CFD modeling of the gas 

and liquid distribution in the DCC and absorber, and detailed evaluation of the CO2

compressor vendor bids and experience. 
-18-

4.0 CC Plant Project Facilities Scope 

4.1 Background Information 

Tenaska selected Fluor to initiate front-end engineering and procurement services for the 

PC Plant portion of the Project under an open book estimate phase in June 2009. 

Tenaska placed this work on hold in May 2010 at approximately 30 percent engineering 

completion. During that period, Tenaska also selected the Fluor EFG+ as the CO2

capture technology under a competitive bidding process. In making this selection, 

Tenaska valued the potential execution synergies between the PC and CC project 

components (among other evaluation criteria). 

Further information on the process undertaken by Tenaska to identify and select the 

preferred vendor to perform the carbon capture FEED for the Project can be found in a 

separate report provided to the Global CCS Institute in January 2011 and titled CO2

Technology Evaluation, Methodology and Criteria. 

4.2 Division of Responsibility, Interface and Battery Limits 

Fluor executed the CC Plant FEED study beginning in August 2010 and finishing in June 

2011. The effort was approximately 10 months in duration (including a nominal onemonth schedule extension caused by Tenaska). 

Fluor performed this work under a multi-office execution plan to ensure alignment 

between the PC Plant and CC Plant offices. Although the FEED study is a standalone 

estimate for the CC Plant, it considered synergies due to a combined execution between 

the PC and the CC Plants. As such, during the CC Plant FEED study, it was necessary to 

develop a detailed Division of Responsibility (DOR) matrix – Refer to Attachment 2. 

Compared to the DOR matrix, the CC Plant scope can be more simply described in terms 

of the geographic “battery limits” (boundary). This boundary is depicted by a red line 

shown on the simplified plot plan in Attachment 1 Page 9. The battery limits are also 

shown on the block flow diagram (Attachment 1, Page 10) and the process flow diagrams 

(Attachment 1, beginning Page 11). 

In general, Project scope inside this boundary is “inside battery limits” (ISBL) and, 

therefore, included. Project scope outside this boundary is “outside battery limits” 

(OSBL) and, therefore, excluded. With Respect to the CC Plant, OSBL scope items are 

either the responsibility of the Fluor PC Plant team or of Tenaska per the DOR matrix. 

There are two notable exceptions to this simple geographical description of the scope 

division. The scope excludes the following ISBL items: 

 Site preparation, fencing, grading and drainage, paving and surfacing 

 Digital Control System (DCS) equipment; control and instrument cables 

 
-19-

Also, note the scope split for flue gas ductwork. The CC Plant only includes the 

ductwork between the DCCs and the absorber. Ductwork from the flue gas 

desulfurization (FGD) to the DCC and from the absorber to the stack is part of the PC 

Plant scope. 

These various exclusions are not included in the CC Plant cost and have not been 

estimated. 

In addition to the DOR and geographical depiction of the battery limits, as part of the 

FEED study, Fluor developed a table to define all the interfaces between the PC and CC 

Plants. Figure 6, below, is a copy of the interface table. 

Figure 6 – PC / CC Battery Limit Interface Table 

Interface Area From To Comment 

Absorber/Stack CLM-1002 Stack Absorber Vent Duct 

DCC/PC Power Plant CLM-1001 Flue Gas Feed 

CC/PC Pipeway FLT-1001A/B Battery Limit Excess DCC Water 

CC/PC Pipeway P-1007A/B Battery Limit Scrubbing Solution Blowdown 

CC/PC Pipeway HX-1003 Battery Limit PC Condensate Return 

CC/PC Pipeway Battery Limit HX-1003 PC Condensate Supply 

CC/PC Pipeway P-1008A/B Battery Limit Condensate Return 

CC/PC Pipeway V-1004 Battery Limit Condensate to PC Plant 

CC/PC Pipeway CMP-1002 Battery Limit Compressed CO2 Product 

CC/PC Pipeway Battery Limit DSH-1001 Low Pressure Steam Supply 

CC/PC Pipeway Battery Limit Utility Pipeway Demineralized Water 

CC/PC Pipeway Power Plant Utility Pipeway Instrument Take-Off 

CC/PC Pipeway Power Plant Utility Pipeway Plant Air 

CC/PC Pipeway Power Plant Utility Pipeway Service Water 

Common Area Power Plant Utility Pipeway Potable Water 

Following are more detailed descriptions of the scope inclusions (Section 4.3) and 

exclusions (Section 4.4) that may assist in understanding the DOR matrix. 

4.3 Scope of Facilities Included 

Following is a descriptive summary-level list of the scope included in the CC Plant 

portion of the Project. This list is consistent with the more detailed DOR matrix in 

Attachment 2. 

 CO2 Capture Process Equipment. 

o All equipment wetted by the flue gas polishing and CO2 capture process 

fluids. (The large equipment includes the DCC’s, CO2 absorbers, CO2

strippers, reboilers, CO2 stripper condenser, and solvent reclaimer.); 

o Equipment required for process heating and cooling (air coolers etc.); 

o Wetted instruments; 

o Control valves; 
-20-

o Access platforms, ladders, stairs and lifting equipment; and 

o First fill of solvents and reagents. 

 Flue Gas Handling Fans. Include flue gas booster fans for overcoming the 

differential pressure associated with the CO2 capture process equipment. The scope 

excludes the PC Plant induced draft fan. 

 CO2 Compression Equipment. This includes the large compressor machines, inter 

and after coolers, driers, and catalytic oxidation equipment. 

 Field Fabricated and Shop Fabricated Tanks.

 Miscellaneous Equipment. This includes equipment not related to the CO2 capture or 

compression processes such as sump pumps, safety showers, building fire protection, 

vapor and gas detection equipment, and the continuous emissions monitoring system. 

 Flue Gas Ductwork. The scope of supply for ductwork begins with the inlet flange of 

the DCC and ends with the discharge flange of the treated flue gas from the absorber. 

(The CC Plant scope does not include the ductwork from the FGD to the DCC or the 

ductwork from the absorber overhead back to the stack.) The scope also includes 

support steel, thermal insulation, dampers, and expansion joints. 

 Piping. All piping between CO2 capture process and CO2 compression equipment 

within battery limits. This also includes piping not related to the carbon capture or 

compression processes such as utilities supply (i.e. potable water, building fire 

protection, air conditioning, etc.). 

 Auxiliary Power Distribution. 345kV/13.6kV 

 Motors for CO2 Capture Process and Compression Equipment. 

 Electric Power Cable(s). 

o Electric power cable(s) from motor control centers for the carbon capture and 

CO2 compression facility 

o Power distribution for the CC Plant beginning with the secondary connections 

to the auxiliary transformers. 

 Buildings for CO2 capture and compression facilities 

 Foundations for CO2 capture and compression facilities 

 Structural Steel for support of all structures, vessels, flues and ducts, pipe systems, 

and all provisions for access and egress including stair towers. Include all hoists, 

cranes, monorails for facility. 

 First Fills of Chemicals and Lubricants. 

 Start-Up and Commissioning Spares. 
-21-

4.4 Exclusions 

Following is a descriptive list of the scope excluded from the CC Plant portion of the 

Project. Excluded items may either be the responsibility of the PC Plant scope or of 

Tenaska. This list is consistent with the more detailed DOR matrix in Attachment 2. 

 Site Preparation, fencing, grading, drainage, paving, and surfacing both ISBL and 

OSBL of the CC Plant. By combining all site preparation for both the PC and CC 

Plants, there is expected to be cost and execution synergy in the civil scope contract; 

 PC Plant including coal delivery and handling, PC boiler, steam turbine generator and 

steam cycle equipment, switchyard, induced draft fan, selective catalytic reduction 

(SCR) of NOx, baghouse, activated carbon injection (ACI), FGD, and the stack; 

 Flue Gas Ductwork System upstream of the DCC inlet flange and downstream of the 

absorber outlet flange. Also not included is the bypass of carbon capture process 

equipment between by-pass dampers and the stack. Ductwork downstream of carbon 

capture process equipment (from outlet flange of last process column to stack) is not 

included; 

 DCS Equipment; control and instrumentation cables; 

 OSBL Utility Piping Systems including instrument air, plant air, nitrogen, potable 

water, fire water, cooling water, steam, condensate, process sewer, sanitary sewer and 

storm water sewer; 

 Emergency Power Generation; 

 Onsite CO2 Pipeline from CC Plant battery limits to the Trailblazer property 

fenceline; 

 Product CO2 Pipeline from fenceline to point of interconnection; 

 Plant Roads; 

 Supply of Liquids required by the CO2 Capture and Compression Facility 

(demineralized water, cooling water supply and return, steam, and condensate); 

 345 kV Power Distribution line and connection to auxiliary transformers located at 

the CC Plant; 

 Operational Spares; and 

 Noise Attenuation has been applied on a minimal basis pending project wide 

evaluation to be performed for the overall project by Fluor Power. Equipment has 

been specified to meet the 85dba threshold at a distance of three feet (1 meter). 
-22-

5.0 FEED Study Scope of Services 

This section describes the FEED study scope for the CC Plant portion of the Project, 

which will utilize Fluor EFG+ technology. 

The FEED study is a critical phase in the development of large projects – particularly 

those that are unique in terms of scale, technology, or configuration, where reference 

plant cost and performance information is unavailable. As described in Sections 1.6 and 

2.2, the main objective of the FEED study phase is to establish and define the technical 

scope of work and project execution in sufficient detail to determine the project cost and 

commercial terms that form the basis of a firm EPC price and proposal for the Project. 

Doing so requires completion of approximately 15 – 20 percent of the total CC Plant 

engineering and planning effort, which reduces the Project risk before moving into 

detailed engineering and construction. 

The FEED project team was a multi-discipline task force, comprised of members 

experienced in EFG+ technology and power plant design. The team included all the 

elements of a full project execution team with specialists in the engineering fields and 

functions identified in the positions below: 

 Project Management; 

 Process Engineering; 

 Mechanical Engineering; 

 Civil and Structural Engineering; 

 Piping Engineering; 

 Electrical Engineering; 

 Instrument and Controls Systems Engineering; 

 Health, Safety, and Environmental; 

 Scheduling and Planning; 

 Procurement; 

 Contracts; 

 Construction; 

 Commissioning & Start-up; and 

 Cost Estimating . 

Each of these departments worked together as an integrated team. The team performed 

the work in the project development sequence discussed in Section 5.1. Accordingly, the 

team composition changed as the CC Plant design evolved. Fluor ensured a seamless 

interface between project team members through routine communication and multiple 

design reviews that emphasized teamwork between specialists. Interface with the PC 

design team was also critical, and successfully performed with specific focus on how the 

PC Plant operates with respect to the CC Plant and the battery limit interfaces. 

The services contract executed between Tenaska and Fluor for the FEED development 

included progress payment terms based on a milestone deliverables plan that reflected the 

design development process for a typical FEED phase of large projects. 
-23-

5.1 Progression/Schedule 

Originally, the planned FEED study schedule duration was nine months. During the 

FEED study, the team encountered a few issues that would either require a schedule 

extension (due to the sequential nature of the activities) or increased cost to maintain 

schedule. Tenaska elected to extend the schedule. As a result the actual FEED study 

duration was approximately 10 months. 

The FEED study followed a typical development sequence. The sequence includes the 

eight phases listed below, with key deliverables associated with each phase listed in 

parentheses. 

 Phase 1: Process Engineering (Design Basis, Process Flow Diagrams (PFDs), Heat 

and Material Balances (HMBs); 

 Phase 2: Equipment Definition (equipment data sheets, specifications); 

 Phase 3: Equipment Pricing (bid lists, bid packages, bid tabs); 

 Phase 4: Plant Layout & Model (Plot Plan); 

 Phase 5: Material Quantification (MTOs, Physical Drawings); 

 Phase 6: EPC Execution Planning (EPC Schedule, Contract Plan); 

 Phase 7: Cost Estimating (Capital, Operating Costs); and 

 Phase 8: Commercial Proposal (Cost, Schedule, Performance Guarantees). 

Attachment 3 contains a simplified schedule of the FEED study activities showing the 

completion dates for key deliverables coming out of the phases listed above. The 

following sections discuss each of these FEED study phases in more detail. 

5.2 Process Engineering 

5.2.1 Design Basis 

Process engineering starts with the preparation and establishment of the formal Project 

design basis. However, prior to doing so, Tenaska provided its high-level input, which 

included: 

 Selection of PRB coal supplied by Arch Coal; 

 Selection of assumed PC boiler technology; 

 Determination of coal heat input and resulting flue gas flow rate and composition; 

 Selection of Fluor EFG+ technology; 

 Project life of 30 years; 

 Design for air cooling to minimize water consumption rate (Refer to separate Global 

CCS Institute study report titled “Cooling Alternatives Evaluation for a New 

Pulverized Coal Power Plant with Carbon Capture”);

 Ensure design meets permitted air emission limits – see Section 6.2; 

 CO2 product to meet or exceed current Permian Basin quality specifications (see 

Figure 9); 

 The CO2 removal system shall have a CO2 recovery of 90 percent or greater; 

 Design the CC Plant for 25 percent turndown in total flue gas mass flow rate. The 

turndown for each train operated individually or jointly is 50 percent. For joint 

operation, turndown may vary between trains; 
-24-

 PC Plant capacity factor is 90 percent; 

 Desired on stream factor is 346.75 days per year; and 

 All rotating equipment drivers shall be electric. 

In addition, prior to the FEED study, Tenaska and Burns & McDonnell established 

economic evaluation factors for the Project. The purpose of these factors is to allow the 

combined FEED study team to evaluate various potential design options and determine 

the best economic decision for the Project. Figure 7 below is a table of these five factors. 

Figure 7 –Project Economic Evaluation Factors 

Parameter Value

Value of Electric Power USD$3,550 per kW 

Value of Steam USD$284 per lb/hr (per 0.454 kg/hr) 

Value of Flue Gas Pressure Drop USD$1,325,800 per inch of water (per 0.249 kPa)

Value of Solvent USD$75,820 per lb/hr (per 0.454 kg/hr) 

Value of CO2 Captured USD$4,476,842 per 0.1percent below 90 percent 

The value of electric power is based on the sum of (1) the estimated specific capital cost 

for the PC Plant, and (2) the 30-year net present value of coal conversion efficiency using 

an assumed fuel cost at the commercial operations date (COD) and a discount rate of 10 

percent. This value was, then, converted to USD$/kW using assumed PC plant heat rate 

and net output. 

The value of steam is based on value of electric power (USD$3,550/kW) multiplied by 

the low pressure steam turbine power generation efficiency of 80 kW per 1,000 lb/hr (per 

454 kg/hr). Note: Through the FEED study it was determined that the rate of power 

generation losses associated with low pressure steam extraction were lower than this 

value. 

The value of flue gas pressure drop is based on the value of electric power 

(USD$3,550/kW) multiplied by the calculated kW power demand per inch of water 

pressure drop for a fan handling 2,800,000 actual cubic feet per minute (79,287 actual 

cubic meters per minute) with an assumed efficiency of 88 percent. It should be noted 

that the pressure drop evaluation factor and electric power evaluation factor were applied 

separately to the applicable design attributes of the project so as to ensure that that the 

analysis did not “double count” for the incremental electric necessary to overcome higher 

pressure drop. 

The value of solvent is based on the 30-year net present value of one lb/hr of solvent 

consumption using an assumed 2009 MEA price of USD$1,550/ton (escalated by 3 

percent per year) and a discount rate of 10 percent. 

The CO2 value is the 30-year net present value, using a 10 percent discount rate, of 0.1 

percent CO2 emitted based on a CO2 value of USD$60/ton, and 3 percent escalation rate 
-25-

(with 0.1 percent CO2 converted to tons of CO2 using the design coal input rate and 

carbon content). 

Tenaska anticipated encountering a number of design decisions requiring economic 

analysis using these factors. However, most of the design decisions were straightforward 

and clear such that detailed analysis was not warranted. Some of these items include: 

reducing/limiting the number of control valve bypasses, isolation valves, instrumentation, 

and ductwork runs, evaluation of the absorber material of construction, and evaluation of 

the reboiler heat exchanger type. 

 

In addition, since this Project is in the development stage, the actual economic factors are 

not known. (Power and CO2 off-take agreements, which will establish the pricing basis, 

have not been negotiated.) As such, this uncertainty gave a lack of confidence in utilizing 

these factors when a particular design issue was applicable (e.g. further optimizing the air 

cooler design temperature). 

Fluor used input from Tenaska to develop the detailed CC Plant project design basis. The 

final process design basis establishes the parameters necessary to complete process 

simulation modeling. Fluor uses process simulations to establish the heat and material 

balance and to define the technical parameters of the plant equipment and systems. The 

following sections describe the items included in the resulting design. 

CC Plant feedstock (flue gas) quantity, composition, and conditions 

The flue gas feedstock flow rate and composition are key elements in the design. During 

the development of the PC Plant component, Tenaska provided the Fluor PC team with 

various design coal compositions. The PC team used the design coal data to simulate the 

performance of the boiler and determine the combustion flue gas composition and flow 

rates. Tenaska also provided the assumed PC boiler technology for the Project. 

Therefore, when the CC Plant FEED study began, Fluor generated the flue gas 

combustion compositions to include the assumed boiler design. Also included in the 

combustion simulations was a conservative amount of air to account for air leakage into 

the boiler. 

For the various coals, the calculations produced different flue gas compositions and flow 

rates. The Fluor FEED team selected the flue gas with the harshest conditions (highest 

flow rate, lowest CO2 concentration, and highest oxygen concentration) to be the basis of 

the design and basis of performance guarantees for the CC Plant. The final design flue 

gas consisted of the properties and composition shown in Figure 8: 
-26-

Figure 8 – Flue Gas Properties and Composition 

Parameter Value

Composition 

N2 66.060 vol% 

O2 4.676 vol% 

CO2 11.640 vol% 

H2O 16.830 vol% 

Ar 0.795 vol% 

SO2 10 ppmv 

NOX 26.3 ppmv 

Flow Rate 327,196 lbmol/hr (148,414 kgmol/hr) 

Temperature 131.3°F (55.2°C) 

Pressure 13.67 psia (94.25 kPa) 

Product specifications (quality and conditions)

Tenaska defined the CO2 product recovery rate and quality specification as shown in 

Figure 9. Across all parameters, the specification meets or exceeds the typical Permian 

Basin CO2 specification. Unfortunately, because the CO2 off-take agreements have not 

been established, the final specification is not known. Nor is it known whether the Project 

will need to meet the specification continuously or if there may be some flexibility 

regarding certain parameters. 

Figure 9 – CO2 Product Specifications 

Parameter Value

End Use Enhanced Oil Recovery 

Recovery Rate 18,103 STPD (16,163 Metric ton/d) 

90% at ambient design temperature 

Temperature < 100 

Pressure 2,500 psig (~17,338 kPa absolute) 

Purity >98 vol% 

Maximum O2 concentration < 10 ppmw 

Maximum N2 + Ar concentration < 4 mol% 

Maximum H2O concentration <30 lb/million ft3 (481 kg/m3) 

Maximum H2S concentration < 20 ppmw 

Maximum concentration of: SO2, CH4, NH3, and solvent Not detectable 

Among these parameters, the most challenging are the O2 concentration, which requires 

reaction with hydrogen across an oxidation catalyst, and the water concentration, which is 

met through drying on molecular sieve beds. 

Regarding purity, the typical Permian Basin specification is 95 vol%. Tenaska raised the 

project specification to 98 vol% because it is easily achieved with Fluor EFG+ 

technology. However, in doing so, Tenaska did not lower the levels of contaminants 

present (such as inerts). 
-27-

Utility/support systems and heat integration

The development of the process design basis required significant interface between the 

CC and the PC Plant teams. Figure 6 in Section 4.4 provides a table of these interfaces. 

Among them are utility and support systems provided by the PC Plant. The PC and CC 

project FEED teams jointly developed the battery limit conditions for these systems. Key 

items affecting the process design include: 

 The PC Plant will provide saturated 50 psig (approximately 446 kPa absolute) low 

pressure steam to the CC Plant which returns to the PC Plant as condensate.

 PC Plant condensate at 114oF (45.6oC) is heated against hot overhead vapor from the 

CO2 stripper

The latter item represents heat integration between the PC and CC Plants and is a method 

to optimize the thermal efficiency of the overall Project. Prior to the CC Plant FEED 

study, Fluor, Tenaska, and Burns & McDonnell also considered heat integration with the 

CO2 compressor intercoolers. However, Tenaska elected not to pursue this integration 

due to: (1) potential contamination of the condensate with CO2 (from potential leaks) that 

could result in accelerated corrosion of boiler tubes, (2) the fact that the integrated design 

would be dependent on the CO2 compressor, which has not been selected, and (3) the 

intercoolers are another source of low-grade heat and there is a limited ability to utilize it 

in the PC Plant steam cycle – there is only minimal temperature difference between the 

intercooler temperatures and prospective PC water streams that appears to outweigh the 

potential cost of integration.

Site-specific design criteria 

There are a number of site-related items in the design basis. They include ambient 

temperature ranges, elevation, atmospheric pressure, rainfall, etc. Figure 10 contains 

these values for the Project. 

Figure 10 – Site-Specific Design Basis Parameters 

Parameter Value

Maximum Dry Bulb Temperature Recorded 110.0oF (43.3°C ) 

Minimum Dry Bulb Temperature -9.0°F ( -22.8oC) 

Dry Bulb Design Temperature for CC Plant 82.0oF (27.8°C ) 

Design Relative Humidity 56 % 

Site Elevation 2000 ft (610 m) 

Atmospheric Pressure 13.66 psia (90.1 MPa) 

Annual Mean Rainfall 25.0 inches (63.5cm) 

Daily Maximum Rainfall 9.0 inches (22.9cm) 

Mean Wind Velocity 11.7 miles per hour (18.8 km/hr) 

Design Wind Velocity 90.0 miles per hour (144.8 km/hr) 

Prevailing Wind Direction (See Figure 11) 

Seismic Zone Site Class C 
-28-

Figure 11 – Wind Rose 

Annual Average Wind Data for Abilene, TX 1961-1992 

The most important of these site-related parameters is the design temperature. 

Determination of the design temperature is interrelated with the availability of water and 

the cooling method selected for the Project. 

The Project is located in a semi-arid area, with annual rainfall averaging about 22 inches 

(56 centimeters). As such, prior to the CC Plant FEED study, Tenaska and Fluor 

explored several cooling options for both the PC and CC Plants. Fluor completed the 

study in February 2010, which included: 

1. air cooling, 

2. full wet cooling, and 

3. partial wet cooling (hybrid cooling). 

Subsequent to this analysis Tenaska decided that Trailblazer will employ air (dry) cooling 

in order to reduce the Project’s water usage due to both the economic results of the 

analysis and the limited water resources in the area. 

With regard to the air cooling, Tenaska established separate and distinct ambient design 

temperatures for the PC and CC Plants, respectively. Tenaska set the PC Plant design 

temperature at 99.6°F (37.6°C) which is near the maximum ambient temperature (99th

percentile) for the site. However, Tenaska set the CC Plant design temperature at 82°F 
-29-

(27.8°C), where only approximately 15 percent of the annual hours are higher than this 

temperature. When the ambient temperature exceeds the design temperature, Tenaska 

and Fluor expect the CO2 capture rate of the CC Plant to decrease slightly from the 90 

percent capture design point (falling to approximately 88 percent at 99.6°F). 

Tenaska preferred the slight capture rate degradation at high ambient temperatures over 

the alternative of a 99.6°F (37.6°C) design temperature which would have vastly 

increased the number of air coolers (to maintain the process operating conditions) and the 

associated capital cost. Tenaska deemed the small CO2 capture degradation to be 

acceptable because it meets the stated goal to achieve between 85 and 90 percent CO2

capture. 

If regulations require continuous 90 percent capture in the future, Tenaska could add 

more air coolers. PC Plant thermal efficiency is much more sensitive to high ambient 

temperatures and, thus, Tenaska retained a high ambient design temperature for the PC 

Plant. For additional information, refer to separate Global CCS Institute report titled 

“Cooling Alternatives Evaluation for a New Pulverized Coal Power Plant with Carbon 

Capture.” 

Operational objectives (such as plant turndown and reliability)

Among the main areas where Tenaska provided input to the design basis were the 

operational and reliability criteria. Tenaska and Fluor agreed that the turndown of the CC 

plant would be 50 percent for each train operated individually or jointly. For joint 

operation, the turndown percent could vary between trains. With the 2x50% train 

arrangement, this turndown requirement is inherently met by the Fluor process 

configuration (as limited by the absorber turndown limit) and has no other impact on the 

design of the facility. This equates to operating anywhere in the range of 25 percent to 

100 percent total flue gas flow. Tenaska also requested the CC Plant be designed for a 

PC Plant capacity factor of 90 percent and an on stream factor of 346.75 days per year. 

5.2.2 Process Simulation and Heat and Material Balances 

Based on the design basis criteria, Fluor prepared process simulations. Process 

simulation, when validated with measured data and when programmed properly, is an 

efficient way to rigorously perform process engineering calculations and to produce the 

heat and material balance (HMB) – See Attachment 1, Page 12. Fluor uses a proprietary 

rate-based simulation model calibrated against historical operating plant data and from 

recent pilot plant test results. 

The HMB formed the basis for developing the preliminary process equipment list, the 

PFDs (See Attachment 1, Page 11), and process data sheets. PFDs depict the major 

equipment and major process systems for the plant. 

5.2.3 Process Equipment Data Sheets 

The PFDs form the basis for developing both material selection diagrams (MSDs) as well 

as the start of the piping and instrumentation diagrams (P&IDs). The MSDs are a 

collaborative effort between process engineers, who define the conditions and 
-30-

compositions of the various process and utility streams, and metallurgical engineers, who 

determine optimum materials of construction for the various plant equipment and 

systems. The MSDs form the basis for mechanical equipment, piping, and 

instrumentation material specifications. 

Process engineers then develop process equipment data sheets from HMB and MSD 

results. The process equipment data sheets include primary results from the HMB, 

including pressure, temperature, and equipment size criteria. Later, mechanical engineers 

will add further details to the data sheets. 

5.2.4 P&IDs and Summaries 

The P&IDs are the next step in the process engineering phase. P&IDs are a collaborative 

effort between all the engineering disciplines. P&IDs include all the major equipment 

and systems depicted in the PFD, as well as all the utility and process support systems 

required to complete the design. P&IDs represent a primary engineering deliverable, and 

establish the technical definition for virtually all the engineering disciplines. The P&IDs 

evolve during the project as new details emerge, including vendor-specific equipment 

parameters. Following completion of reviews and the HAZOP study, and prior to bulk 

material quantity estimation, the P&IDs are frozen and issued for design. 

The final activity in the process engineering phase is the preparation of flow stream 

summaries, including utility system and environmental summaries, and pipeline flow 

summaries. Other engineering disciplines use this data for further development in the 

areas of system sizing, instrumentation and control systems design, environmental 

permits and hydraulic sizing of piping systems. 

5.2.5 Design Reviews 

Fluor and Tenaska conducted four major design reviews during the FEED study. Below 

is a description of each in chronological order: 

1. PFD Review. Fluor engineers described the PFDs including the major streams and 

the functionality of each piece of equipment in the EFG+ design. The PFDs also 

show the control philosophy for the plant operation. The diagrams were reviewed 

and discussed with the Tenaska project team throughout the course of half a day. 

Fluor addressed the list of questions and recommendations that came up during the 

meeting in the final revision of the PFDs. 

2. HAZID. A HAZID is the high-level safety assessment done very early in design 

development. Fluor and Tenaska engineers carried out a HAZID study led by a 

moderator experienced in the HAZID technique. Dividing the EFG+ into sections 

based on the preliminary plot plan, the HAZID team considered each area of the plant 

against a checklist of general hazards. As a result, the team identified potential 

hazards. For each identified hazard, the team considered the risk presented by the 

hazard and all possible means of either eliminating the hazard or mitigating the risk. 

The moderator assigned actions to either discipline groups or individuals to ensure the 

mitigating control. The HAZID review lasted for one day. See Section 6.1.1 for 

additional information. 
-31-

3. P&ID Review. Fluor engineers reviewed the P&IDs with Tenaska’s project team. In 

the review, Fluor described each process and utility line. These descriptions included 

defining the valve types, equipment connections, line sizes, piping connectivity, and 

various operating scenarios. The review lasted four days. The Fluor team 

documented Tenaska’s recommendations and addressed them in the final revision of 

the P&IDs.

4. HAZOP. A HAZOP is a structured and systematic technique for process hazard 

analysis and risk management. The USA government has mandated Process Hazard 

Analysis (PHA) for certain types of facilities through the Occupational Health and 

Safety Administration (OSHA) Code of Federal Regulations (CFR) number 

1910.119. This regulation is also called Process Safety Management. Although the 

regulation may not strictly apply to the Project or to CO2 capture facilities in general, 

the method has become widely accepted in the process industry as a productive way 

to identify and manage process safety. As such, with these positive benefits and 

without an official determination as to its applicability, Tenaska elected to conduct a 

HAZOP for the Project. 

The scope of a HAZOP includes the identification of (1) potential hazards in a system 

and (2) operability problems likely to lead to nonconforming products. The HAZOP 

method assumes that deviations from the intended design or operating conditions 

cause the occurrence of risk events. The HAZOP moderator facilitates identification 

of such deviations by using sets of “guide words” as a systematic list of deviation 

perspectives. For the Project, the HAZOP team of Fluor, Tenaska, and Burns & 

McDonnell engineers used P&IDs as a starting point. Fluor pre-divided each system 

into nodes. The team individually discussed the nodes following the guide words. 

The three-day review resulted in a list of recommended modifications to the P&IDs 

or items that required further study. See Section 6.1.2 for additional information.

5.3 Equipment Definition 

The process engineering deliverables described above provide the fundamental data 

necessary to start discipline-specific engineering in the mechanical, structural, piping, 

control systems, and electrical areas. Fluor categorizes this work into two primary areas: 

(1) engineering of equipment and systems and (2) physical layout of interconnecting 

systems (plot plan). This section describes the former category. 

As described in Section 5.2.3, process engineers prepare and provide the equipment 

process data sheets to the other engineering disciplines for further development and 

definition. Mechanical engineers use the process data sheets to further develop the 

equipment designs. After doing so, the engineers add mechanical details to the data 

sheets. 

After sizing the equipment and creating the associated data sheets for each, mechanical 

engineers provided a sized equipment list to the other engineering disciplines. The other 

discipline engineers used this equipment list to complete their designs. For example, 

piping engineers used the equipment list to create the plot plan and electrical engineers 

used it to design the electrical systems. 
-32-

Complete technical definition of each piece of major mechanical equipment includes the 

data sheets discussed above, narrative procurement specifications, and engineering notes. 

Fluor prepared the narrative specifications using internal standard documents, modified 

to reflect project-specific criteria. Similarly, in developing the engineering notes, Fluor 

identified any unique requirements. When combined, these documents formed the basis 

for the equipment technical definition necessary to support equipment pricing through 

competitive bidding by qualified vendors. 

Mechanical equipment includes: 

 Pressure Vessels. Mechanical engineers develop outline drawings based on process 

criteria. After doing so, they add code requirements, metallurgy, wall thickness 

calculations, nozzle/shell attachment criteria, ladder and platform layouts, and 

internal support requirements to the vessel data sheet. 

 Rotating Equipment (including pumps, blowers and compressors). Mechanical 

engineers develop the general rotating equipment design configuration based on 

process flow criteria. The effort includes selection of equipment type. There are 

many types of compressors, blowers, and pumps, but at a high level the options 

would include: 

o Compressors: centrifugal versus reciprocating; 

o Pumps: in-line or centrifugal or positive displacement; and 

o Blowers: axial fan configurations. 

Fluor developed preliminary horsepower ratings as part of selecting the rotating 

equipment type for each application. In addition to selection of the equipment type 

for each service, mechanical engineers specified the associated auxiliary systems, 

such as lube oil criteria, minimum flow bypass systems, and seal specifications. After 

adding this information, the completed mechanical data sheet provides sufficient 

detail to support competitive bidding. 

 Heat Exchangers. There are three roles for heat exchangers: those which cool the 

process against a utility (like cooling water or air), those which heat the process 

against a utility (like steam), and those which interchange thermal energy between 

process streams for efficiency. Regarding the first role, the majority of heat 

exchangers in cooling service for the Project are air-cooled type design (also called 

fin-fans) due both to the limited water availability in semi-arid west Texas and to the 

cooling study determination of dry cooling. For the other heat exchanger roles, the 

Project will utilize “plate and frame” type as well as limited “shell and tube” 

exchanger designs. Mechanical engineers selected among these types based on the 

experience and application. The engineers then performed heat transfer calculations 

to establish heat transfer surface area requirements. The engineers used this 

information to establish the general footprint and physical outline of the exchangers. 

Following these activities, the engineers added the results (e.g. heat transfer duties 

and dimensional characteristics) to the mechanical data sheets.
-33-

 Packaged Equipment. Packaged equipment includes chemical injection packages and 

product gas dehydration systems. This equipment category includes items comprised 

of multiple smaller equipment components that are shop fabricated and skid mounted. 

Like the other equipment areas, mechanical engineering expands upon the process 

data to establish overall performance criteria and specific design requirements for 

each of the smaller equipment components.

 Electrical Equipment and Instruments. Electrical equipment includes transformers, 

switchgear, etc. 

5.4 Equipment Pricing 

Major equipment and systems pricing was a key element in the development of the 

Project cost estimate. Major equipment represented a substantial portion of the overall 

Project cost. Fluor established pricing through a competitive bidding process during the 

course of the FEED study. This effort included development of a qualified vendor bid 

list, development of commercial purchase order terms, the assembly and issue of bid 

packages to approved bidders, and receipt, evaluation and selection of the recommended 

vendors. The following discussion includes more details about the steps in this pricing 

process. 

The pricing effort starts with the identification of high-value equipment and systems that 

comprise the majority of capital cost for the Project. The threshold value for this list was 

set at those items expected to be greater than USD$250,000, but was reduced for highvalue equipment where good in-house pricing history was available, or supplemented for 

lower-value equipment that was unique to Fluor experience. This list included the major 

mechanical equipment items, major electrical equipment, and instrumentation. 

Fluor developed a vendor bid list for the identified equipment based on qualified vendors 

from previous EFG+ project experience and compared/supplemented it with the bid list 

prepared previously by the PC Plant team. This resulted in a bid list that would allow 

realization of potential volume discount purchases for combined like equipment 

procurement between the PC and CC Plant components. Tenaska reviewed and provided 

input to the final bid list. 

Fluor developed purchase order commercial terms based on standard practices 

supplemented with applicable terms from the Tenaska-Fluor EPC contract term sheet 

(part of the MOU). Fluor combined the resulting commercial term document with the 

technical attachments to produce complete Request for Quotation (RFQ) bid packages for 

each identified purchase order. 

Fluor issued the RFQ packages to each identified bidder from the approved bid list and 

set bid submission deadlines ranging from 4 to 6 weeks, depending on complexity of the 

equipment and systems. During this period, the FEED team supported the bidding 

process by providing clarifications to vendor questions. In select cases, Fluor invited 

vendors to bid conditioning meetings to discuss both technical and commercial terms and 

ensure common understanding of project objectives. 

 
-34-

Once received, Fluor evaluated the bids on both a commercial and technical basis. The 

evaluations resulted in the preparation of formal bid tabulations. These tabulations were 

a contract deliverable for Tenaska and identified the bid pricing as well as conformance 

to, or departure from, the various commercial and technical elements of the bid package. 

This tabulation provided the basis for the selection of the recommended vendor and 

associated cost. Fluor and Tenaska reviewed the bid tabulations to ensure agreement on 

the recommended vendors. 

Fluor summarized the resulting list of recommended bidders and associated cost into 

priced equipment lists for inclusion into the Project cost estimate. 

After agreement on the preferred vendor with Tenaska, the FEED engineering team 

incorporated vendor-specific equipment information into the design. 

5.5 Plant Design & Model 

Fluor started the plot plan using the PFDs and preliminary equipment sizes. As 

equipment sizing and requirements became available, Fluor modified and refined the plot 

plan. The plot plan, along with the P&IDs, represents a key element in project definition 

and is the composite effort of all the engineering disciplines. Fluor and Tenaska 

completed extensive reviews of the plot plan to ensure achievement of the Project 

constructability, operability, and maintainability objectives. 

The approved plot plan sets the basis for the development of a three-dimensional (3D) 

model of the Project. This model is a common approach for large-scale, multi-discipline 

projects, and provides a common design platform for all engineering disciplines to ensure 

integrity of final interfaces and minimization of interferences and errors. 

The previous generation engineering world used manual drawings to provide directions 

to construction and as a medium for developing material quantities. In that design 

environment, the various engineering disciplines involved in a project (structural, 

architectural, mechanical, piping, electrical, and instrumentation) all developed their 

respective designs independently. Other engineering disciplines then checked these 

independent designs for conflicts and continuity in design. This manual method 

introduced human error, and resulted in errors in both construction drawings and material 

quantities. The industry averaged three to five percent rework due to construction 

drawing errors. 

The introduction of the computer age brought in the next phase of engineering design – 

two-dimensional Computer Aided Design (CAD) software. Similar to the manual 

drawing approach, each engineering discipline prepared drawings in a CAD format, and 

checked each other’s design for conflict and continuity of design. The mathematical 

processing capabilities of CAD software significantly reduced dimensional errors. 

However, design interferences and associated rework remained a significant issue for 

construction. 

The next development was use of 3D modeling that allowed all engineering disciplines to 

work on a common design platform. This approach not only resulted in reduced 

dimensional error with the automated mathematical dimensional checks, but also 
-35-

automatically identified clashes or interferences between engineering designs. The 3D 

approach significantly reduced construction interference problems. 

At that point, the 3D model was a drafting tool that provided the benefits cited above. 

The next development was the ability to link databases to the model, allowing 

“intelligence” to be included in the design. Material specifications, structural steel 

catalogue data, electrical system connectivity, and overall plant process flow criteria 

database information have all been linked to the model electronically to provide access to 

technical data and specifications within the model. 

Another area in which computer advances have brought benefit is transparency – the 

ability to present the design in a 3D environment to facilitate design reviews. Reviewers 

can readily visualize the finished product and are much better positioned to provide input 

into design reviews. The 3D design medium clearly conveys construction sequencing, 

operator accessibility, and safety features. 

In addition, the bulk material take-off (MTO) effort is transparent and automated. It is 

tough to question the accuracy of piping quantities, for example, when they are readily 

accessible in the model. With ready downloads by various criteria, the 3D model 

eliminates the need for “over-buy” of excess material for contingency. All together, the 

development of the 3D model is a large stride toward improving the quality and accuracy 

of engineering. 

Although project engineering and construction are the primary areas benefitting from the 

3D model, there also are benefits for the owner once the project is completed and the 

facility is in operation. The 3D model provides an excellent training tool for operators 

and maintenance personnel, allowing them to become familiar with the plant 

configuration. The owner can maintain the model in as-built conditions to provide ready 

documentation of the plant configuration and subsequent design changes. 

Fluor used a state-of-the-art 3D software system for the Project. The model included 

foundations, structural steel, mechanical equipment, buildings, pipe, and cable corridors. 

Due to the scope of the FEED study phase, Fluor did not perform detailed 3D modeling 

of instrumentation and electrical systems. However, Fluor would complete this modeling 

during the detailed engineering phase of the Project. 

Attachment 5 contains a screenshot from the 3D model constructed for the Project. 

5.6 Bulk Material Quantification and Pricing 

In addition to the engineered equipment and systems costs discussed above, 

quantification and pricing for bulk materials also are major considerations in defining the 

project scope and cost. 

5.6.1 Types 

Bulk materials typically include: 

 non-engineered items, such as concrete (including rebar, embeds); 

 structural steel (pipe racks, supports, and platforms); 
-36-

 piping systems (pipe, elbows, tees, valves); 

 electrical (cable trays, cable, conduit, junction boxes); and 

 control systems items. 

Bulk materials also include pre-fabricated buildings, such as the electrical equipment 

power distribution centers or the analyzer shelters, and equipment shelters for the product 

compressor buildings. 

5.6.2 Quantification Methods 

Fluor quantified the majority of bulk materials for foundations, structural steel and piping 

systems through the 3D model. In addition to physical layouts, the model database also 

includes component specifications. Accordingly, downloads from the finished model 

provided bulk materials by category and specification. 

Fluor based the electrical and control systems bulk material quantities on plan drawings, 

supplemented with cable tray/cable layouts, development of cable schedules and standard 

details for multiple, common applications (again, not through the 3D model). Fluor then 

summarized these bulk materials according to material categories and specifications. 

5.6.3 Pricing Methods 

Bulk materials are readily available “off-the-shelf” commodities. As commodities, they 

are subject to pricing volatility associated with the raw materials of construction. 

However, the amount of pricing volatility varies among the different bulk materials. An 

example is copper, which greatly influences electrical cable and wire costs. Another area 

of potential price volatility is for materials that are more labor intensive to fabricate and 

subject to labor escalation costs. These include bulk materials that are shop fabricated 

prior to delivery to jobsite, including structural steel and pipe, as well as the prefabricated buildings discussed above. 

The construction industry commonly uses bulk materials and, thus, these materials are 

readily available with standard pricing. For the CC Plant, Fluor derived the majority of 

material pricing from recent project history for like commodities and volume purchases. 

Fluor supplemented with informal budgetary pricing from preferred suppliers for 

commodities where recent project history was lacking or where labor was a significant 

cost component of the delivered product. Fluor used informal budgetary vendor quotes to 

validate in-house pricing on items such as pre-fabricated buildings and shop fabricated 

steel and piping. 

One area of exception to this bulk material pricing approach was the large diameter alloy 

valves. Although a bulk item in the general sense, these valves are not routine items and, 

therefore, Fluor considers them specialty bulk items. Fluor based the pricing for these 

large diameter alloy valves on a formal, competitive bidding process among approved 

suppliers. 

 
-37-

In summary, Fluor priced bulk material using three methods, as follows: 

 For items that have relatively low price volatility, Fluor applied in-house/recent 

project purchase order values for similar commodities and volume purchases. 

Items in this category include concrete, rebar, embeds, small bore valves, 

flanges, fittings, bolts, gaskets, conduit, cable tray and, miscellaneous supports; 

 Budgetary, informal pricing from preferred suppliers for shop-fabricated steel, 

shop fabricated pipe, pre-engineered buildings and cable; and 

 Formal competitive bidding for large diameter alloy valves. 

Figure 12 below summarizes the bulk pricing approach:

Figure 12 – Bulk Material Pricing Methodology 

Account Bulk Item Description 

Pricing Methodology 

In-house/ 

recent project 

history 

Informal quote 

from preferred 

supplier 

Formal 

Competitive 

quote 

Concrete Concrete, rebar, embeds X 

Anchor bolts X 

Steel Shop fabricated steel X 

Misc Steel X 

Buildings Pre-Engineered X 

Piping 

Small bore valves, flanges, 

bolts, gaskets 

X 

Shop fabricated piping X 

Large bore alloy valves X 

Electrical 

Cable and wire X 

Cable tray, junction boxes, 

switches, panels 

X 

Instrumentation Tubing, valves, instrument 

stands 

X 

Fluor included the final bulk material quantities and associated pricing data in the project 

capital cost estimate. 

5.7 EPC Execution Planning 

Project execution planning must consider a wide variety of issues to develop the most 

efficient and cost-effective approach. Some of the major considerations that must be 

addressed in the formulation of Engineering, Procurement Construction, and 

Commissioning (EPCC) execution planning include: 

 Contract terms; 

 Labor availability; 

 Site logistics; 
-38-

 Technical complexity; 

 Major equipment and material sources; and 

 Extent of field fabrication. 

Much of the execution planning is dependent on the FEED study design. For example, 

the FEED study defines the amount of specialty field-fabricated equipment, the extent 

and metallurgy of piping systems, and the plot layout, all of which are considerations that 

influence the optimum project execution approach. Accordingly, the execution planning 

effort cannot begin in earnest until much of the early project FEED engineering has been 

accomplished. 

5.7.1 Execution Method and Schedule 

Fluor will execute the Project as a single project, with both PC and CC components under 

a common timeline. This approach will allow the Project to realize efficiencies and 

volume discount cost savings for combined contracts. It also will allow for the effective 

optimization of craft labor pool resources. 

Fluor documented the details of its approach in the EPCC schedule. As an integrated 

schedule, it identifies execution interfaces and interdependencies between the PC and CC 

Plants. Examples of these interfaces include completion of the overall site civil activities 

(assigned to the PC Plant execution scope) to support CC above-ground construction 

mobilization and on-line dates of major interconnecting common systems required for 

CC start-up. 

The overall Project (including both PC and CC plants) schedule is 57 months. This 

duration starts at full notice-to-proceed (NTP) and ends at substantial completion (which 

includes CC Plant commissioning and successful performance testing). The schedule 

begins with detailed engineering and procurement efforts with a focus on long lead time 

delivery items. This 23-month phase of the effort includes two key review points set up 

to occur at 30% and 60% of engineering completion. Construction follows the 

engineering effort with a slight overlap. Including commissioning (and performance 

testing), this phase is 36 months in duration. 

Attachment 4 is a simplified version of the EPCC Schedule. 

Construction scheduling considers many factors, including equipment deliveries, extent 

of field fabrication activities, subcontracting plans, craft labor availability, and PC plant 

interfaces. Schedule development also considers work sequences, concentration of craft 

personnel, inspection, and testing procedures. 

In addition to identifying these critical schedule interfaces, the schedule also defines the 

engineering durations. Timing of equipment vendor data availability and completion of 

the primary design reviews drive these durations. 

Critical path runs through equipment procurement (including receipt of supplier data), 

design reviews, piling/foundations, stack erection (PC scope), field fabricated equipment 

(DCCs, Absorbers, strippers, and lean flash drums), CO2 compressor and buildings, 
-39-

instrumentation, and commissioning. To maintain the critical path, Fluor will put initial 

emphasis in the detailed engineering phase on validating the design and supplier of long 

lead equipment (field fabricated items and CO2 compressors) so that vendor data can be 

received as soon as possible. 

The following subsections describe each of the EPCC components of the Project 

execution. 

5.7.2 Engineering and Support Services 

Engineering execution variables include determining design mediums/deliverables (such 

as 3D model discussed above), schedule, specialty third party subcontracting, multioffice execution, procurement plans, and construction support. The FEED team 

establishes each of these items as the basis for developing detailed home office costs. 

Fluor developed organization charts to establish project organization structure and 

identify key positions including staff levels and associated wage rates. The organization 

includes both engineering and project support services (project management and controls, 

administration, quality, procurement, contracts and construction and commissioning 

planning). The amount of time allocated to the Project for each organizational position is 

a function of the activities and sequence of the EPCC schedule. As needed, Fluor 

identified and solicited proposals for third-party specialty engineering subcontracts. The 

home office plan also includes computer systems and in-house system costs. 

Using this information, Fluor prepared the internal home office cost estimates. 

5.7.3 Procurement 

Procurement and contract execution is another support service like those described above. 

Execution planning for procurement requires establishing how the project material and 

equipment will be provided and what portion of the work will be subcontracted. The plan 

leverages the FEED study procurement work and vendor bid list. Fluor supplemented the 

FEED study information with the identification of bulk material orders and associated 

vendor bid list and bid packages. Similarly, Fluor will develop a subcontract plan based 

on the construction execution approach. 

5.7.4 Construction 

The FEED study team interfaced with construction planning to identify material types, 

equipment, and design features required for the Project. Fluor held design and 

constructability reviews. The purpose of these reviews is to align the Project team on the 

best method to design the facility with consideration for the construction methods. This 

interface resulted in a constructable design, but also provided the necessary background 

to develop the construction execution plan. In considering constructability, no 

modularization (other than standard pre-dress vessels or skid mounted equipment 

assemblies) was considered. For the scale of this plant, primarily stick-built field 

erection is the only realistic option. 

Construction planning includes determination of the split between work performed by 

directly hired labor (“direct hire”) and the work performed by a subcontractor. This split 
-40-

is dependent on labor availability, regional labor posture (i.e. union or open shop / nonunion), and the type of work. Determination of this split influences the construction 

management organization, temporary facilities, work sequences, etc. To determine this 

split, Fluor performed a labor survey to determine regional craft availability and wage 

rates during the FEED study. Based on this survey, Fluor identified the work that will be 

performed on a direct hire versus a subcontract basis. 

The determination of construction work allocation then formed the basis for development 

of the overall project EPCC schedule. In addition, Fluor considered the following items 

in developing the construction schedule: 

 Procurement Plan – The procurement plan affects the EPCC schedule in several ways 

as it (1) determines the timing of when vendor data will be available to support the 

engineering effort, (2) documents the quoted material and equipment deliveries, (3) 

defines inspection hold points, and (4) includes shipping and logistics. The plan also 

needed to be consistent with construction “need date” based on the construction 

execution sequence that meets the overall schedule duration target; 

 Availability of detailed engineering drawings (both internal and vendor) – Fluor 

defined the engineering work sequences and durations based on the receipt of vendor 

data (from the procurement plan), and completion of the 30 percent, 60 percent, and 

90 percent completion-level 3D model reviews;

 Site mobilization timing (considered with respect to the engineering and procurement 

plans);

 Interface with the PC Plant – most importantly, completion of site preparation/civil 

works and utility tie-in dates;

 Craft levels;

 Work sequences; and 

 Subcontract award dates and quoted work durations.

Using this input information, Fluor developed the schedule using software programmed 

to reflect sequence and interface logic between activities. 

5.7.5 Commissioning 

This final execution planning activities are commissioning, start-up, and performance 

testing. These activities are included because the Tenaska – Fluor MOU defines contract 

completion as “substantial completion” which includes successful performance testing. 

Fluor divides commissioning into two types – cold commissioning and hot 

commissioning. Completion of cold commissioning is the basis for achieving mechanical 

completion. Hot commissioning energizes utility systems in preparation for feedstock 

introduction. 

Mechanical completion occurs when the facility has been substantially installed, but not 

yet put into operation. At mechanical completion, all the mechanical integrity, 

continuity, and safety checks have been completed to the extent possible without 
-41-

energization or operation of any plant component or system. Reaching mechanical 

completion requires cold commissioning activities, including system cleaning and motor 

rotation checks. The commissioning team is responsible for cold commissioning and, in 

the period prior to reaching mechanical completion, the commissioning team works under 

the direction of the construction team. The commissioning team is typically mobilized 6-

9 months prior to construction reaching mechanical completion. 

Once the team achieves mechanical completion, the facility care, custody, and control 

transfer from the construction team to the commissioning team. The commissioning 

team then begins hot commissioning. During hot commissioning, the commissioning 

team brings all utilities on-line, starting with electrical power. Steam, condensate, water, 

air systems, etc. all are brought on-line, followed by chemical or packaged systems, such 

as dehydration or chemical injection systems. Once all utilities and subsystems are online, the plant is ready to introduce feedstock and begin start-up of the facility. 

Fluor will then perform start-up and operate the plant for “calibration” – a period during 

which each of the systems and major equipment components are fine tuned for site 

conditions. This operation mode continues until the facility achieves steady-state 

operation, at which time it is ready for performance testing. Fluor will perform formal 

testing to ensure the facility meets the throughput and performance guarantees. 

During the commissioning period, Fluor will also provide operations and maintenance 

training. 

After successful performance testing and completion of the training activities, Fluor will 

turn over care, custody and control to Tenaska and the Project is essentially completed. 

Fluor incorporated each of these steps into the EPCC schedule. The final phase of the 

EPCC schedule development was to verify that the facility on-line dates were achievable. 

5.8 Capital Cost Estimation 

Fluor prepared the Project capital cost estimate based on the FEED study deliverables 

and project execution plans discussed in the previous sections. Project capital costs have 

several elements in the formulation, broken down into general categories as follows: 

 Direct Field Costs; 

 Indirect Field Costs; 

 Home Office Costs; 

 Miscellaneous Costs; 

 Project Company (i.e. Owner) Costs; and 

 Contingency and Escalation 

This section describes each of these categories. In addition, this section also describes 

the way in which Fluor breaks down the capital cost estimate. Fluor calls this break 

down the “Code of Accounts.” Lastly, this section discusses the “Open Book” estimate 

approach and the final CC Plant capital cost established by Fluor during the FEED study. 
-42-

5.8.1 Direct Field Costs 

Direct field costs include the material and equipment costs, construction labor and 

subcontracts – i.e. all the cost to provide the permanent facility. 

Sections 5.4 and 5.6 describe the method for establishing equipment pricing and material 

quantities/pricing. 

The Project includes major subcontracts for the field-erected vessels (DCCs and 

absorbers). Similar to major equipment, these major subcontracts also were 

competitively bid during the FEED study. 

Fluor developed the craft labor hours based on material quantities and equipment 

quantities. To do this, Fluor applied historical installation productivity rates to these 

quantities to develop base labor hours. Fluor then adjusted these historical rates with 

site-specific factors to correct for conditions (e.g. weather, operating plant environment, 

etc.) that may influence worker productivity. 

Fluor compiled the resulting costs from material, equipment, subcontracts, and labor, all 

of which combine to determine the Project direct field cost. 

5.8.2 Indirect Field Costs 

Indirect field costs are those costs that support the construction field effort, but are not 

part of the permanent plant facilities. Indirect costs are broken down into further 

categories, such as temporary facilities, construction service contracts, construction 

management, construction equipment, and insurance, permits, and performance bonds (as 

applicable). Most of the indirect field costs are time-driven. Accordingly, Fluor used the 

execution plan and the EPCC schedule to develop these costs. 

Temporary facilities include onsite construction offices, temporary utilities, material 

warehouse, lunchrooms, restrooms, and first aid facilities. 

Construction service contracts include medical personnel, janitorial services, inspection, 

and testing subcontracts and welder training. 

Construction management provides overall site management, including administration, 

subcontract management, project controls (cost and schedule reporting), turnover 

management, safety, and onsite engineering support. 

Construction equipment costs include costs for small tools, site vehicles, welding 

machines, heavy lift equipment, and cranes. 

Finally, construction insurance, performance bonds (if required), and construction permit 

costs are included. 

Collectively the costs for these items result in the indirect field cost for the project. 

5.8.3 Home Office Costs 

The bulk of the home office costs are associated with the engineering design – i.e. the 
-43-

labor costs for the design team of engineers and designers. The balance of the home 

office cost is for support functions including project management, procurement, contract 

management, project controls (planning and scheduling), information technology support, 

project accounting, quality assurance/control, and other miscellaneous support. 

5.8.4 Miscellaneous Costs 

Miscellaneous costs include a variety of remaining items, including freight and logistics, 

commissioning and start-up costs, and import duties/fees. Many times miscellaneous 

costs include sales taxes, although these taxes are the Project Company’s responsibility in 

the case of Trailblazer. Because the Project materials and equipment have worldwide 

supply sources, both international and domestic freight costs required detailed 

quantification. Fluor compared ocean freight quotes (and compared them against 

historical costs) for overseas equipment and materials suppliers. Fluor also identified and 

quantified import duties and taxes. Similarly with inland freight, Fluor evaluated and 

optimized various alternate logistics plans (rail, truck, air) to establish the delivery costs. 

In addition to manpower costs for these teams, other costs include specialty cleaning 

processes, temporary test facilities (platforms, ports, etc.), sampling and lab testing costs, 

and first fill of catalysts and chemicals. After start-up, costs for plant operation to stable 

condition for performance testing also are included. 

5.8.5 Project Company (Owners’) Costs 

Project Company costs are items to the Project Company’s account and are separate from 

the EPC capital cost. Figure 13 is a list of these potential items. 

Figure 13 – Project Company Cost Line Items 

Accounting 

Business Interruption Insurance 

Business management systems 

Capital Spares 

Client staff and expenses 

Coal Pile / Fuel Inventory 

Construction Backup Power 

Consultants 

Contaminated & hazardous material disposal 

Demolition / Site Clearing 

Electric Interconnection 

Environmental and Operating Permits 

Gas Interconnection 

Geotechnical Report 

Interest During Construction 

Interest Rate Hedging Instruments 

Lab Equipment 

Land cost 

Legal 

Lender Commitment Fees 

Lender Reimbursement of Expenses 

Letters of Credit Fees and Charges 

Market Consultant 

Mortgage Recording Fee 

Office Equipment and Supplies 

Chemicals and catalysts (ex. first fills) 

Owner’s auditing/inspection/witness testing 

Owner’s Engineer 

Permanent office and laboratory equipment 

Permanent office furniture 

Permanent warehouse and equipment 

Pipelines 

Plant operations/maintenance vehicles 

Plant security 

Project Management 

Property Insurance 

Property Taxes 

Rail Interconnection 

Roadway Improvements 

Site Access 

Site Labor 

Sponsor Development Costs 

Title Insurance 

Topographical Mapping 
-44-

Lubricants (initial inventory and operating) 

Machine shop equipment 

Maintenance equipment and tools 

Up Front Finance Fees 

Warehouse spares (2yr spares) 

Water Interconnection (Plant and potable) 

Working Capital 

Tenaska has estimated Owners’ costs in the context of the combined overall project 

(PC+CC Plants). As compared to the combined total EPC cost, Tenaska estimates that 

Owners’ costs will comprise approximately an incremental 45% cost (or around 31% of 

the all-in capital cost). This increment is primarily comprised of water interconnection, 

land, Owners’ contingency, development cost reimbursement, project management, precommercial operation date operating costs, initial fuel (coal) inventory, builder’s/marine 

cargo/liability insurances, financing/commitment/letter of credit fees, property tax during 

construction, interest during construction, and working capital. 

5.8.6 Escalation and Contingency 

Project cost estimates normally include allocated costs for escalation and contingency. 

In most cases, Fluor would assess and apply cost escalation for (1) any delay between the 

timing of the project cost estimate until the NTP date and (2) the period between NTP 

and the actual purchase dates of equipment and materials. However, not knowing the 

Project NTP date, Tenaska requested that Fluor provide the EPC price in terms of an 

“overnight” price dated second quarter of 2011. Thus, the cost estimate does not include 

escalation, interest during construction, or any other Owners’ costs. 

Contingency is an amount of cost added to a cost estimate to account for potential risk 

items that could increase the cost of a project. Depending on the contract structure and 

method of financing, contingency may be carried by the contractor, the owner, or both. 

In addition, the entity or entities carrying the contingency may consider it to be “spent” 

(an unrecoverable portion of the project cost) or “reserved” (a pool of funds held back 

and used only if necessary. 

Fluor generally determines the contingency amount by identifying potential cost risk 

issues and apportioning added cost according to the probability that those risks will 

occur. 

In Trailblazer’s case, Fluor carries the contingency and assumes that it will be spent. 

Also, the Project MOU caps the contingency at the amount proposed by Fluor in its 

indicative bid. Fluor assessed the cost risk items using its typical process and deemed the 

MOU contingency amount to be acceptable. 

5.8.7 Project Code of Accounts 

The table below provides the code of accounts adopted for the Project. This code of 

accounts is typical to most large construction projects around the world. As indicated in 

a previous section of this report, a portion of the Tenaska CC Plant scope will be under 

the PC Plant portion of the project. Figure 14 identifies cost items outside the CC Plant 

cost that are included in the PC Plant portion of the Project. 

 
-45-

Figure 14 – Fluor Code of Accounts 

Account Description

Civil Site preparation, drainage & underground gravity systems, finish 

grading, roadways

Concrete Foundations, elevated structures, rebar, anchor bolts, embeds

Architectural Buildings, HVAC, plumbing

Mechanical Vessels, pumps, heat exchangers, compressors, packaged 

equipment

Piping Underground pressure systems, above ground systems, valves, 

pipe supports

Electrical Transformers, switchgear, cable, fixtures

Instrumentation Analyzers, field instruments, DCS, control valves, relief valves

Scaffolding/ Firewatch Safety Personnel

Temporary Facilities Trailers, temporary utilities, warehousing, laydown areas, fencing,

Construction Services Survey, inspection and testing, janitorial, security

Construction Management Site management, QA, Supervision, Logistics, Field Procurement, 

Contract Management, site engineering

Construction Equipment Heavy lift cranes, backhoes, forklifts, transport vehicles, welding 

machines, etc.

Home Office Engineering, Home Office Procurement

Freight Ocean and land freight to jobsite

Commissioning & Start-up Cold commissioning, hot commissioning, start-up, performance 

guarantees, operator training

Miscellaneous Costs Insurance, permits, escalation, contingency

5.8.8 Open Book Estimate Approach 

In the open book estimate process, Fluor made all costs in the EPC estimate available for 

review and comment by Tenaska. As part of the process, Fluor: 

 Evaluated and recommended all the major equipment and subcontract bids to 

Tenaska. However, Tenaska made the final selection of the appropriate bid 

ultimately used in the EPC estimate. 

 Used the FEED study design deliverables to quantify the bulk materials and, then, 

based the unit pricing (for example the cost per unit length of pipe) upon prices 

actually paid on other recent projects. 

 Determined installation labor rates by surveying labor costs in the Project location 

and adjusting for any anticipated other projects in the area. Fluor based the labor 

hours to install equipment upon historical data from actual hours used to install the 

same or similar equipment. Fluor, then, made adjustments are for differences, such as 

size and complexity.

Fluor, Tenaska, and Burns & McDonnell participated in a week-long open book meeting 

in which the parties reviewed the above methods and results and jointly agree on the 

capital cost of the Project. 
-46-

5.8.9 Capital Cost 

The CC Plant EPC price, for the scope described, including contingency and fees, on an 

overnight second quarter 2011 basis is nominally USD$667,100,000. Again, this price 

excludes escalation, interest during construction, and any Owner’s costs. 

This supports the overall project (PC and CC Plants) cost basis consisting of (1) an EPC 

cost (with contingency and escalation) of USD$2,800,000,000 to USD$3,300,000,000 

plus (2) Owner’s costs, interconnects, financing fees, and interest during construction at 

an additional USD$1,000,000,000 to USD$1,250,000,000; 

5.9 Operating Cost Estimation 

Operating cost items for the CC Plant include chemicals, utilities, operating labor, and 

maintenance. Following is a more detailed discussion of each. Figure 16 summarizes the 

costs of these items except utilities. 

 Chemicals. Chemicals required for the EFG+ process include: 

o Solvent – make-up for losses in the reclaimer effluent and volatilization 

o Caustic soda (sodium hydroxide or NaOH) – used in the top section of the 

DCC to provide the right chemical conditions to absorb SO2

o Activated carbon – used to filter a slipstream of solvent 

o Hydrogen – injected to react with oxygen in the CO2 product stream (forming 

water which is removed) in order to meet pipeline specifications 

o Catalytic oxidation (CATOX) catalyst – catalyst over which the hydrogen 

reaction occurs 

o Nitrogen – intermittent use to inert tanks and process equipment 

Fluor established the consumption rates through process simulation and development 

of the HMB. Fluor solicited and received current budgetary pricing for these 

chemicals supplied in Texas. The pricing would need to be refreshed at the time 

when the Project proceeds and may change throughout the operating life. The 

projected cost of these items totals to nominally USD$7,500,000 per year.

More detailed information on these consumption rates is available in Attachment 1, 

Page 7. 

 Operation Labor. Tenaska envisions combined management of both the PC and CC 

Plants. Fluor expects that the CC plant will require one control room operator and 

two field operators per shift. Assuming a four-shift schedule, a total of four control 

room operators and eight field operators will be required. In addition, the EFG+ plant 

will require a two laboratory technicians. Overall Plant Management is separately 

covered under the PC Plant staffing. 

The labor cost will depend on the locally competitive wages plus benefits. These 

values have not been determined for the Project. 

However, for example, for a fully-burdened average cost of USD$100,000 per 

employee per year, the total cost of operating labor for the CC plant would be USD$ 

1,400,000 (14 x USD$ 100,000) per year. 
-47-

 Maintenance. For convenience, Tenaska and Fluor have divided maintenance costs 

into two categories -- labor and materials. 

Fluor expects that a maintenance labor staff of five will be required, including a 

maintenance supervisor, an electrical and instrumentation supervisor, and three 

technicians (mechanical, electrical, and instrumentation). Using the same example 

cost basis as for operating labor, these employees would add cost of USD$500,000 

per year. 

Regarding maintenance materials, Fluor recommends establishment of a preventative 

and scheduled maintenance program for the CC Plant facilities. In the unlikely event 

that a maintenance activity requires a lift, the Project Company would rent cranes. To 

encompass the materials and rental costs, Fluor suggests an annual maintenance 

allowance of USD$400,000 to USD$500,000 per train per year. 

 Utilities. The PC Plant will supply utilities for the CC Plant, which include 50 psig 

(approximately 446 kPa absolute) low pressure (LP) steam (to drive the stripper 

reboiler and solvent reclaimer), power (various loads including flue gas blowers, 

solvent circulation pumps, lean vapor compressors, and CO2 product compressors), 

and demineralized water (make-up for the solvent wash section at the top of the 

absorber). 

Tenaska currently considers both the PC and CC Plants to be part of a single Project. 

As a result, the CC Plant power and steam demands are simply parasitic loads of the 

overall Project (like the other air quality control systems). Thus, the CC Plant does 

not have to buy these items. However, in the future, it would be possible to separate 

the ownership of the CC Plant from the PC Plant depending on business and 

regulatory drivers at the time. Figure 15 lists the utility consumption rates of the CC 

Plant. 

Figure 15 – CC Plant Utility Consumption Rates 

Utility Consumption Rate

50 psig (~446 kPa absolute) Steam 

2,011,800 lb/hr 

(912,537 kg/hr) 

1.33 lb steam / lb CO2

(1.33 kg steam / kg CO2) 

Power 119,770 kW 

Demineralized Water 47.5 gpm (1.7 m3/min) 

 
-48-

Figure 16 – CC Plant Operating Costs Summary 

Area Annual Cost (2011 Basis)

Chemicals USD$ 7,500,000 

Operating Labor USD$ 1,400,000 

Maintenance labor and Materials USD$ 1,500,000 

Total* USD$ 10,400,000 

*Excludes utilities and waste disposal costs 

5.10 Performance Summary 

Three parameters are important in describing the CC Plant performance. They include: 

 CO2 Capture Rate. In establishing the design basis, Tenaska set the design 

requirement for 90% capture rate of CO2 contained in the flue gas at the design 

ambient temperature of 82°F. However, as described previously, this capture rate can 

vary slightly with ambient temperature. The capture rate requirement expectation 

ultimately affects a large number of the process design parameters such as solvent 

flow rates, operating, temperatures, pressures, and equipment sizes. These effects, in 

turn, affect the other performance parameters. 

 Steam Consumption. The EFG+ technology is a thermal swing process. This means 

that the solvent heats up as CO2 dissolves in and reacts with the solvent (absorption) 

and that heating is required to release the CO2 from the solvent (regeneration). LP 

steam provides the heat for regeneration in the stripper reboilers. The amount of 

steam required for this heat input is dependent on a great number of parameters that 

are technology specific, including CO2 solvent loading, lean/rich cross-exchanger 

approach temperature, solvent species, solvent concentration, etc. Fluor has 

optimized among these parameters to provide the lowest steam consumption rate for 

the EFG+ solvent. The solvent reclaiming systems also use a small amount of steam. 

 Electrical Power Consumption. The process requires electrical power primarily to 

drive turbomachinery including the flue gas blower, solvent circulation pumps, and 

the CO2 product compressors. Fluor attempted to minimize the power demand 

through the specification and selection of the most efficient machines, by minimizing 

pressure drop through the DCC and absorber (which affect the blower power), and by 

maximizing the stripper overheard pressure. For example, CO2 compressors 

dominate the power demand, so Fluor and Tenaska specified and selected highly 

efficient integrally-geared machines. However, in purely accounting for the power 

consumption of the CC Plant, this analysis neglects the power generation savings due 

to the heat integration by preheating PC Plant steam cycle condensate against CC 

Plant stripper overhead. 

Together, the steam and electrical power consumption of the CC Plant represent a power 

loss range of nominally 28 to 30% of the PC Plant net output without the CC Plant 
-49-

operating (depending on the ambient condition). Note that the output of the of PC plant, 

being dry cooled, varies with ambient temperature. 

Figure 17 summarizes the expected performance of the CC Plant. The data in the figure 

do not account for the value of preheating PC plant boiler feed water against the stripper 

overhead.

Figure 17 – Expected Performance of the CC Plant

Performance Parameter Units Value 

CO2 Capture Rate 

Tons/d 

Lb/hr 

Metric ton/d 

% 

18,103 

1,508,583 

16,423 

90 

Steam Consumption lb/hr 

kg/hr 

2,011,800 

912,537 

Heat Input 

MMBtu/hr 

GJ/hr 

Btu/lb CO2 (captured) 

GJ/kg CO2 (captured) 

1,850 

1,952 

1,226 

2,853 

Power Demand* kW 

kWh/Ton CO2 (captured) 

119,770 

159 

* Includes CO2 product compression 

Attachment 1, pages 7 and 8 contain the performance values for the project.

5.11 FEED Study Completion 

Upon completion of the FEED deliverables and capital cost estimate, members of the 

Tenaska and Fluor project team met to conduct an open book estimate review. This 

review allowed the Tenaska team to review all aspects of the cost estimate. During the 

meetings, the group identified a list of recommendations, such as: 

 Confirmation of the construction labor wage rate build-up;

 Reduction in the quantity of platform and grating associated with the air coolers; and

 Revisit and confirm cost of catalytic oxidizer catalyst and equipment due to a 

difference between the open book cost estimate and the priced equipment list.

Afterwards, Fluor made the associated adjustments to the capital cost estimate. 

After finalizing the capital cost estimate, Fluor issued the FEED books to the Tenaska 

team. The books included all the project deliverables from each engineering discipline 

including the cost estimate. Then to complete the FEED project, the Fluor FEED study 

team presented the results of the FEED and EPC proposal to Tenaska. The presentation 

topics including highlights of the FEED study, a discussion of the EFG+ technology, and 

an overview of the EPC schedule and overall cost estimate. 
-50-

5.12 Potential Future Value Engineering and Optimization Studies 

Prior to and during the FEED study, Tenaska, Fluor, and Burns & McDonnell identified a 

number of design options with the potential to affect capital cost, operating cost, 

efficiency, and operability. However, the team did not carry out many of these studies 

due to time and cost considerations. 

In the future, it may make sense to complete some or all of these studies. These studies 

include: 

 Cooling Water Optimization Study. This study would evaluate the optimum 

distribution of the limited water supply available between the PC and CC plants. 

 Cooling Water Storage Tank Study. This study would evaluate whether it is 

economical to add a cooling water storage tank(s) for additional cooling water during 

peak cooling loads. 

 Flow Measurement and Ductwork Reduction Study. The current ducting 

configuration between the DCC outlet and the blower inlet includes a 6X diameter 

straight run – a design criterion established by flow measurement vendors. This 

results in an overhead vertical loop with the associated support system and stairwell 

access structure. This study would revisit the straight run criteria with the objective 

of reducing the overhead load and associated ducting and steel. The focus of the 

study is to identify alternate instrumentation or configurations that will achieve 

desired flow measurement accuracy and reduce the extent of ducting. 

 Air Cooler Heat Exchanger Optimization Study. Fluor used standard design practices 

to set the air cooler fin spacing. In this proposed study, Fluor would revisit these 

standard practices to evaluate the impact of relaxing the stringent design criteria to 

achieve cost savings. This study would include a technical evaluation and 

discussions with air cooler vendors. The study would quantify the potential capital 

cost changes against operating and maintenance impacts. 

 Metallurgical Optimization Study. This study would evaluate different materials of 

construction for potential cost saving versus the current design. 

 CO2 Product Optimization Study. Tenaska provided the CO2 product quality 

specification for the current EFG+ design basis. The quality is consistent with 

prevailing quality specifications for EOR in the Permian Basin. This study would 

revisit those assumptions with the objective of deleting or minimizing equipment 

including the CATOX and dehydration systems. 

 Vessel Pressure Drop Study. This study would evaluate the optimum design of vessel 

internal systems to identify potential enhanced process improvements and 

minimization of system pressure drop. 

 Ambient Air Design Temperature Study. This study would optimize the temperature 

design conditions for the most economical results (i.e. optimized CO2 capture rate 

versus capital and operating costs).
-51-

6.0 Health, Safety and Environmental Items 

6.1 Process Hazard Analysis 

As discussed previously, the USA government mandated PHA for certain types of 

facilities through OSHA CFR 1910.119. Although the regulation may not strictly apply 

to the Project or to CO2 capture facilities in general, PHA has become widely accepted in 

the process industry as a productive way to identify and manage process safety. As such, 

with these positive benefits and without an official determination as to its applicability, 

Tenaska elected to conduct PHA for the Project. 

There are several PHA methodologies. Some examples are “What-If,” Checklist, 

HAZOP, and Fault-Tree analysis. Selection among these methods depends on the degree 

of design information available and the complexity of the process. Tenaska and Fluor 

elected to utilize the HAZOP method which has the added benefit off identifying 

potential operability issues as well as process safety and environmental risks. Since the 

Project team cannot do the HAZOP until the P&IDs are available, Fluor and Tenaska also 

conducted a much higher-level HAZID earlier in the FEED study. The HAZID provided 

a way to identify and address potential safety issues at a very early stage in the design. 

6.1.1 HAZID 

Tenaska and Fluor conducted a HAZID for the CC Plant at Fluor’s Aliso Viejo office on 

November 3, 2010. The Fluor attendees included persons representing control systems, 

piping, mechanical equipment, project management, process engineering, and safety. 

Tenaska representatives included internal project management and operations, Burns & 

McDonnell project management, and a process engineering consultant. 

Fluor documented the review using Primatech’s PHAWorks, Version 5 software. In 

doing so, Fluor used a laptop PC with a projection device to allow all team members to 

review the recorded discussion. 

The HAZID method is a brainstorming process conducted in a team setting to identify 

process hazards in the early design stage. It focuses primarily on the non-process related 

hazards and hazards associated with unwanted process releases. The basis of the HAZID 

study is a set of hazard keywords used to examine each area/system on the PFDs. 

The HAZID addresses: 

a. Hazards inherent to plant operations, considering factors such as: 

 Each type of plant activity including receipt of feedstocks, interface with 

utilities, and disposition of products during normal operations as well as 

deviation from the normal; 

 The physical condition of the materials being handled, the materials’ physical 

and chemical properties, and the material inventories under both normal 

operations as well as their deviation from the normal; and 

 The possible physical, chemical, and toxic hazards. 
-52-

b. Hazards inherent to other site activities, considering all types of planned activity 

by the workforce associated with constructing, modifying, maintaining, and 

operating the site as well as their deviation from the normal. 

c. Hazards potentially impacting the site due to its location, the environment, and 

other external factors considering factors such as: 

 The nature and stability of the site terrain and ways in which it could interact 

adversely with the installation structures, plant, and other site activities; and 

 Possible effects of the environment, including extremes of climatic conditions 

on the site and the ways in which they could interact adversely with the 

structures, plant, and other site activities. 

Figure 18 depicts the HAZID methodology in flowchart form. 

Figure 18 – HAZID Methodology 

Where appropriate, the HAZID team made recommendations for risk reduction and/or 

further study. Fluor either implemented the recommendations or studied them further to 

determine whether any design changes were necessary. Some of the key items identified 

in the HAZID included: 

 Addressing issues related to CO2 venting such as: design of the vent heater system, 

plume modeling to address icing (from freezing of air humidity due to cooling from 

the Joule-Thomsen effect associated with depressurizing the CO2), and air dispersion 

modeling (see Section 6.5);
-53-

 Completion of a noise study, including start-up operations, to determine the need for 

any noise attenuation; and

 Addressing the potential for coal dust accumulation in various areas.

6.1.2 HAZOP 

Fluor and Tenaska conducted the HAZOP study for the CC Plant in the Fluor Aliso Viejo 

Offices on January 24th through 27th 2011. Like the HAZID, Fluor documented the 

review using Primatech’s PHAWorks, Version 5 software. In doing so, Fluor used a 

laptop PC with a projection device to allow all team members to review the recorded 

discussion. 

In leading the study, Fluor used a classical guideword technique to identify operator error 

or equipment failure scenarios that may cause a safety, environmental or business impact. 

The team evaluated the risk of each scenario. For scenarios demonstrating an 

unacceptable risk level, the team recommended the addition of administrative controls or 

modification of equipment/controls. 

Fluor divided the P&IDs into 34 nodes. The team reviewed them in sequential order 

according to the flow path. The team systematically reviewed the nodes looking for 

inadequacies in the design, potential equipment failures, potential deviations to the 

normal operating conditions, and human errors which could present safety hazards or 

operability concerns. The team’s discussion of the each node’s operation/function 

included: 

 Pressure (operating & maximum/minimum): The incoming pressure of the process 

fluid, pump/compressor pressure, the maximum node pressure that can be achieved, 

the corresponding ratings of the process vessels/lines, and the impact of a loss of 

upstream pressure; 

 Flow rate: Consider alternate destinations (if possible); 

 Temperature: Incoming process fluid, heat exchanger maximum/minimum, as well as 

flashing minimum temperature and corresponding equipment design ratings; and 

 Process material properties including single/multi-phase, flammable and/or toxic 

characteristics, corrosion potential, mixture concentration variations, viscosity or 

density changes, contamination potential, and corresponding equipment materials of 

construction. 

In doing so, the team identified 57 items for further review. 

For each of the identified items, the team determined the potential consequences without 

regard for the mitigation systems. Based on the extent of the business interruption, 

magnitude of the injury/fatality, or environmental impact of each hazard, the team 

assigned a consequence severity. 

Then, for each identified item, the team determined the likelihood of occurrence. During 

this step the team considered the number of initiating events, their frequency of 
-54-

occurrence, as well as the reliability of the mitigation system. In doing so, the team 

examined the full protective system, including relief/shutdown/control devices and DCS 

alarms (provided that the operator has sufficient time to respond to the upset condition). 

Using the consequence severity and likelihood values, the HAZOP team determined total 

risk as consequence x likelihood. For hazards with an unacceptable level of risk, the 

team identified and recommended methods to reduce the risk level. Figure 19 below 

describes the risk assessment methodology. 

Figure 19 -- Risk Assessment Methodology 

1. Select Deviation 

2. Determine Causes (Likelihood) 

 a. Equipment Failure 

 b. Operator Error 

3. Assess Consequences (Severity) 

 a. Nuisance 

 b. Process Upset 

 c. Product Quality 

 d. Equipment Damage 

 e. Lost Production 

 f. Environmental 

 g. Personnel Exposure 

 h. Toxic Release 

 i. Flammable Release 

 j. Explosion 

4. Assess Mitigation Capability (Reliability) 

 a. Mechanical Design 

 b. Mechanical Protection 

 i) Pressure Relief Valve, Vent 

 c. Control and Interlock 

 i) Active Control 

 ii) Passive Interlock 

 d. Operator Response 

 i) Reaction Time 

 ii) Diagnostic Information 

5. Judge Risk Qualitative 

 a. Likelihood 

 b. Severity 

After the HAZOP study, Fluor issued a report containing a table of all the items, the 

existing mitigations, and potential recommendations to reduce the risk. Fluor organized 

the table by nodes. Fluor studied and implemented the recommendations in the Project 

design (reflected on the P&IDs). 

6.2 Air Emissions 

For the FEED study design basis, Fluor and Tenaska established the requirement that the 

CC Plant amine air emissions be within the volatile organic compounds (VOCs) emission 
-55-

rates established under the TCEQ air permits (#s 8417, PSDTX1123, and HAP13) for the 

Project for all cases. Tenaska’s confidence in and satisfaction with this assumption was 

based on Fluor’s experience and performance guarantee. Figure 20 below is a table of 

the permitted emission rates. The air permit is publicly available. 

Figure 20 – Permitted Air Emissions 

Pollutant Performance Standard Compliance Averaging Period 

NOx 

0.070 lb/MMBtu (0.033 kg/GJ) 

0.060 lb/MMBtu (0.028 kg/GJ) 

0.050 lb/MMBtu (0.023 kg/GJ) 

24-hour average 

30-day rolling 

12-month rolling 

SO2 0.06 lb/MMBtu (0.028 kg/GJ) 30-day and 12-month rolling 

CO 0.10 lb/MMBtu (0.047 kg/GJ) 30-day and 12-month rolling 

Hg 1.7x10-6 lb/MMBtu (8.0x10-6 kg/GJ) 12-month rolling 

NH3 10 ppm 3-hour average 

Filterable PM/PM10 0.012 lb/MMBtu (0.006 kg/GJ) Annual 

PM/PM10 Total 0.025 lb/MMBtu (0.012 kg/GJ) Annual 

VOC 0.0036 lb/MMBtu (0.0017 kg/GJ) Annual 

H2SO4 0.0037 lb/MMBtu (0.0017 kg/GJ) Annual 

HCl 0.00063 lb/MMBtu (0.00030 kg/GJ) Annual 

HF 0.00050 lb/MMBtu (0.00023 kg/GJ) Annual 

Pb 0.00003 lb/MMBtu (0.00002 kg/GJ) Annual 

6.3 Wastes 

In the USA, the Resource Conservation and Recovery Act sets forth both solid and liquid 

wastes regulations. The Trailblazer CC Plant does not produce any solid wastes. 

However, four liquid products exit the system. Of these, one – the reclaimer effluent – is 

a waste. The other three are water streams utilized or treated in the PC Plant. 

As described in Section 1.5.4 and in the EFG+ Process Description (See Attachment 1, 

Pages 3-6), the EFG+ process is sensitive to incoming SO2 in the flue gas. As such, the 

design includes a scrubbing section in the top of the DCCs. However, any residual SO2

not removed in the DCCs will react with the EFG+ solvent and form heat stable salts 

(HSS). These salts accumulate in the circulating solvent which can lead to further 

solvent degradation and reduced process performance. To prevent these negative 

impacts, the EFG+ process includes a semi-continuous solvent reclaimer. In the 

reclaimer, a slipstream of hot lean solvent is treated with a sodium hydroxide solution. 

The sodium hydroxide reacts with the HSS to free up the solvent and form non-volatile 

sodium salts. Most of the solvent is recovered and returned to the EFG+ process. A 

small amount of solvent containing the sodium salts – the reclaimer effluent waste – exits 

the process and is stored in temporary containers. Tenaska will characterize the waste 

against RCRA test criteria and dispose of the waste offsite through a permitted third party 

waste disposal contractor. The character of the waste has a large effect on the cost of 

disposal. Since the characterization for Trailblazer has not been done, these costs have 
-56-

not been quantified. 

The other three liquid streams exiting the process include: 

 Excess quench water (i.e. net flue gas condensate) from the bottom section of the 

DCC;

 Scrubbing solution blowdown from the top SO2 – removal section of the DCC; and

 Compression condensate – water condensed out of the CO2 product in the CO2

compressor intercoolers. 

All three streams are routed back to the PC Plant for treatment (if any) and, ultimately, to 

off-set Plant water demand. 

6.4 Fire Protection 

In general, CO2 capture plants do not represent a major potential fire hazard due to the 

non-flammable characteristics of CO2. The biggest fire risks for these plants are the 

location of concentrated flammable fluids. These locations include major rotating 

equipment lube oil systems and electrical transformer liquids. For each of these 

locations, Fluor designated automated wet sprinkler deluge systems. 

In addition, the Project design includes a standard fire protection system comprised of 

firewater piping loop around the perimeter of the facility with fire hydrants and monitors 

spaced according to spray radius criteria. Tenaska will also locate hand-held fire 

extinguishers at utility stations throughout the plant. 

6.5 Dispersion Modeling 

During the course of both the HAZID and HAZOP reviews discussed in Section 6.1, 

Tenaska and Fluor determined that CO2 releases posed a concern in two areas; 

 release of the pressure containing system (piping, compressor, knock-out drums) 

within the confined product compressor building; and

 atmospheric release occurring due to upset conditions

In addition to potential CO2 releases, Tenaska and Fluor also identified the solvent 

storage facility as a potential hazard to workers due to potential spills occurring during 

solvent truck offloading operations. 

As a result, Tenaska and Fluor agreed that both the potential CO2-venting and the solvent 

spill scenarios should be subjected to further analysis with use of dispersion modeling 

computer simulations to determine potential resulting concentrations to plant operators 

and workers, as well as the nearby public. 

In completing the dispersion analysis, Fluor used the PHAST (Process Hazards Analysis 

Software Tool) dispersion modeling software to determine both on-site and off-site 

impacts. PHAST is a program that allows one to examine the progress of a potential 

incident from release onset, through the formation of a cloud and/or pool, to its 

dispersion. User-supplied parameters provide the necessary initial values and boundary 

conditions for modeling. The program applies appropriate entrainment and dispersion 
-57-

models as changing conditions warrant, accomplished through continuity algorithms 

PHAST employs to integrate these models to ensure a smooth transition between 

behavior patterns.

The dispersion analysis effort examined two CO2 release conditions and one solvent 

release. The Immediately Dangerous to Life and Health (IDLH) concentration values 

were used as a basis for determining on-site and off-site impacts. The IDLH value for 

CO2 is 40,000 ppm and for solvent is 30 ppm. 

The analysis results demonstrated that: 

 A CO2 release inside the compressor building would allow CO2 to exit through the 

five roof exhaust vents. The 40,000 ppm IDLH concentration level occurred at an 

elevation of approximately 15 feet above ground level and only for a downwind 

distance between 20 to 30 feet from the release point. Beyond this distance, the CO2

concentration dissipates rapidly. An impact from the vapor cloud on workers at 

ground level did not occur and any potential exposure to concentrations above the 

IDLH at any elevation is contained within the Project site 

 The CO2 vent on the piping downstream of the stripper overhead accumulator 

extended 10 feet above the roof of the compressor building or 70 feet above grade. 

The IDLH concentration from a release from this vent extended 35 feet downwind. 

It did not reach the ground or an operator accessible area; and 

 If a hot solvent spill occurred at the lean solvent pumps (P-1006 A/B), the liquid 

accumulated within the curbed area. The resulting evaporation of the solvent 

mixture created a 30 ppm IDLH dispersion contour that extended 60 feet downwind. 

This represents a small area where operators may be working. The solvent odor 

should quickly alert any exposed operators of the release giving them adequate time 

to relocate a short distance to safety. 
-58-

7.0 Highlights and Challenges 

In developing the Project, selecting the technology, and completing the FEED study, the 

FEED team encountered a number of issues. These issues have been categorized as 

“highlights” and “challenges,” and range from aspects of how the team managed the 

FEED study to the technical content. Project issues identified as “highlights” are unique 

aspects that enhanced the Project and differentiated it from other projects. These 

included areas of innovation and successes that improved the project objectives. Project 

issues identified as “challenges” were areas of the Project that are candidate for future 

improvement and may be addressed should the Project move forward.

7.1 Highlights 

 Competitive Process for CO2 Capture Technology. The CO2 capture industry is still 

in its infancy. As such, this creates a number of business and technical issues and 

risks to realize a Project at commercial power plant scale. A FEED study is required 

in order to establish cost and performance guarantees. However, because even a 

single FEED study is expensive, it is difficult to justify the cost of two competitive 

FEED studies. As a result, the Owner ends up being in a sole-supplier position with a 

single provider but without full guarantees. To minimize these risks, Tenaska 

evaluated technology providers and selected Fluor EFG+ through a competitive 

process. The process allowed Tenaska to evaluate indicative cost and performance 

projections, experience-level, ability to execute, and willingness to guarantee the 

process, and financial wherewithal on a common basis. 

 Sale of CO2 Product for EOR. As the name implies, CCS is comprised of two 

challenging aspects: capture and storage. Doing both adds substantial costs. Tenaska 

has strategically addressed the storage and the cost impact issues by locating the 

Project near the Permian Basin, which has a mature market for CO2 use in EOR. 

Through EOR, Tenaska has a commercially proven and clearly permittable method 

for permanent CO2 storage. Furthermore, because EOR results in additional oil 

production, the CO2 has value which comes back to the Project and offsets the cost of 

CCS to some extent. With this outlet for CO2, Fluor has designed the EFG+ process 

to produce CO2 product meeting the EOR market specifications. 

 Largest CO2 Capture Project. The Project would represent the world’s largest CO2

capture plant. The CC Plant would recover 18,103 short tons per day (16,423 metric 

tons per day) of CO2 using two trains applying Fluor’s EFG+ technology to recover 

90 percent of the CO2 in the coal-fueled flue gas. Most post-combustion CO2 capture 

plants that are have been built to date are in the range or 300 to 500 short tons per day 

(268 to 446 metric tons per day) CO2 production capacity. Additionally, other 

projects that are currently in development stages are in the range of 3,000 to 6,000 

short tons per day (2,679 to 4,464 metric tons per day). 

Therefore, Trailblazer would not only be the world’s largest CO2 capture plant, it 

would be significantly larger than other plants studied at this time. The dual train 

approach is another unique design feature of the Trailblazer facility. The risk 
-59-

associated with two operating trains is minimal since they do not share any major 

equipment. Chemical storage and injection systems are the only shared equipment 

between the trains. 

The largest post combustion carbon capture plant that Fluor has built was the 

Bellingham, Massachusetts plant which captures 350 short tons per day (313 metric 

tons per day). Note, however, that the Bellingham plant treated natural gas-fueled 

combustion turbine exhaust which is lower in CO2 concentration than pulverized coal 

flue gas and, thus, the equipment sizes are larger on a per ton basis. The Bellingham 

plant recovered 85% of the CO2 from the flue gas. Fluor designed Trailblazer to 

capture 90% of the incoming CO2. The increase in recovery is easily done by using 

more solvent without requiring a significant increase in steam or power usage. Fluor 

designed all current EFG+ plants to recover 90% of the incoming CO2. 

 Application of Air Cooling. Due to limited availability of water at the Project site, 

Tenaska determined air cooling to be the most economical (but highest capital cost) 

cooling method. For the CC Plant, Tenaska and Fluor agreed to adesign temperature 

of 82°F (27.8oC). The Project site ambient temperature exceeds this design 

temperature for approximately 15 percent of the annual hours. Tenaska and Fluor 

selected the 82°F (27.8oC) CC Plant design temperature in order to minimize the 

number of air cooler bays and, thus, the capital cost of the air coolers. At times where 

the air temperature exceeds 82°F (27.8oC), the CO2 capture recovery rate will degrade 

slightly (down to approximately 88% at 99.6°F (37.6oC) – the 99th percentile ambient 

condition). Fluor and Tenaska deemed this to be acceptable since the project goal 

was to recover between 85 and 90 percent of the incoming CO2 annually. 

 Large Equipment Sizes. Due to the large capacity of the plant, many of the 

equipment sizes are larger than have previously been built. The absorbers, DCCs, 

and CO2 product compressors would be the largest in the CO2 capture industry. Also, 

the Project will require a large number of air coolers. Throughout the course of the 

FEED, the Fluor and Tenaska project teams have worked with the vendors to ensure 

that they had the expertise and capabilities to build the equipment at such sizes. 

 Power Plant Heat Integration. Given the large size of the PC and CC Plants, any heat 

integration between the two would increase the efficiency of the overall system and 

could save on capital or operating costs. Fluor identified one such added heat 

integration point during the FEED. The PC Plant condensate is heated against 

overhead vapor from the EFG+ stripping columns. This increases the efficiency in 

the PC Plant since the condensate will enter the steam cycle at a higher temperature 

and require less heating from power plant sources. This additional heat picked up by 

the condensate results in a lower operating cost for the PC Plant while maintaining 

the same power output. In the CC Plant, the stripper overhead vapor requires cooling 

to knock out the water in the stream before it enters the overhead accumulator. By 

including the heat integration, a portion of the cooling is completed in PC condensate 

heater. Therefore, the air cooled stripper overhead condenser can be reduced in size 

which will result in a lower capital and operating cost for the condenser. The 
-60-

inclusion of the PC condensate heater will be an additional cost but the overall 

economics favor inclusion of this heat integration step. 

 Similarly, the team evaluated potential heat integration with the CO2 compressor 

intercoolers. However, as another source of low-grade heat, there is a limited ability 

to utilize it in the PC Plant steam cycle. This determination was affected by two 

aspects of the prospective system. First, the final CO2 compressor design had eight 

stages, which was an increase from the original basis. Thus, in order to achieve the 

specified discharge pressure, this large number of stages reduces the pressure ratio 

and temperature rise of the CO2 flowing through each stage. In addition, due to 

concerns over potential contamination from leaks of the CO2 into the power plant 

boiler feed water, a “liquid couple” exchanger design (where thermal energy in the 

CO2 would be transferred to an intermediate closed-loop system and, then, from this 

system to the boiler feed water) would be required. This design reduces the amount 

of heat that can be transferred because each of the two heat transfer has its own 

smaller temperature difference. Together, these aspects reduce the driving force such 

that little heat can be transferred for the required amount of equipment. 

 CFD Analysis for Large Equipment Vapor Distribution. Due to the large DCC and 

absorber sizes, it was imperative that the vapor distribution at the inlet nozzle and 

inside each column was adequate. To reduce the risk of maldistribution, the Project 

team decided to run a CFD simulation that would model the distribution (1) of the 

DCC inlet duct up to the inlet nozzle and (2) inside each column up to the bottom of 

the first bed of packing. 

The duct vendor designer conducted the CFD analysis of the inlet duct. The analysis 

conducted determined the flow pattern of the flue gas as it flowed through the ducting 

from the FGD to the DCC and as the vapor entered the DCC. It was necessary to 

ensure that the vapor velocity was relatively smooth at every section of the ducting 

and the inlet nozzle. Disruptions in flow patterns in the ducting would lead to 

inaccurate flow measurements of the flue gas entering the carbon capture plant. 

Additionally, any negative velocity sections at the DCC inlet nozzle would indicate 

that some of the vapor was circulating in the opposite direction. This phenomenon 

would hinder the performance of the column and, thus, the overall process. The 

results of the CFD analysis on the DCC ducting and inlet nozzle showed that by 

adding small straightening vanes at the elbows of the ducting, the flow patterns were 

sufficient for the flow measurements and for the operation of the DCC. 

The packing and internals vendor conducted the CFD analysis for the vapor 

distribution inside the DCC and absorber. For each vessel, the scope of the analysis 

included the vapor distribution from the inlet nozzle up to the bottom of the first 

packed bed. Adequate vapor distribution is important in each column in order for the 

packed bed sections to work as designed. From the results of the CFD analysis Fluor 

deemed the DCC and absorber designs to be adequate. 

 Materials Selection. Fluor studied different construction materials for various pieces 

of equipment and piping. For certain equipment, Fluor studied two types of 

metallurgical designs to identify the most cost effective option. To do so, Fluor 
-61-

solicited and received comparable pricing information from suppliers for each 

material under consideration. As such, Fluor was able to recommend and use the 

most cost effective materials of construction in the final cost estimate. 

 Use of “Turret” Ducting vs. Integral Shell Head in Large Process Vessels. The 

overhead duct of the absorber routes the flue gas to the power plant stack and then to 

the atmosphere. The ducting represents a significant cost in terms of material, 

instrumentation, and structural support. Fluor suggested implementing a turret design 

rather than a traditional shell head on the top of the absorber which would extend the 

height of the duct vertically before turning towards the stack. The turret design 

eliminates the top shell of the absorber and includes a top section which routes the 

flue gas 90 degrees without any vertical height required. The turret design would 

save on material costs of the ducting and, since the overall duct length was reduced, 

on the pressure drop of the flue gas. The lower pressure drop would reduce the load 

on the blower in the CC Plant. 

Before implementation, Fluor performed a CFD analysis on the turret design to 

ensure that the vapor flow characteristics were adequate and that the pressure drop of 

the design would decrease from the traditional shell design. Both aspects were 

proven through CFD analysis by the ducting vendor. Therefore, Fluor included the 

turret design in the final design. 

The DCC and absorber columns are large enough that they preclude shop fabrication 

and therefore require field fabrication, which significantly raises cost. The previous 

CO2 capture designs utilized a traditional vessel head integral with the vessel shell. 

The outlet of both of these columns is through the top nozzle located on the column 

head, and discharge through connected ducting. During the design of this system, an 

idea to replace the integral head with a ducting material type outlet was identified. A 

subsequent analysis concluded there would be significant cost savings using this 

feature. Thus, Fluor and Tenaska elected to include it in the design and associated 

cost estimate. 

Cost savings of nominally USD$340,000 is estimated for the four applicable vessels. 

 Continuous Value Engineering. Prior to the FEED study, Tenaska recognized the 

cost and performance impact of implementing CO2 capture. In addition, Tenaska 

selected Fluor based in part on an indicative EPC bid. As such, in executing the 

FEED study, Tenaska was keenly interested in minimizing the capital cost and 

ensuring the FEED cost estimate came in at or below Fluor’s indicative bid price. 

In pursuit of these objectives, Tenaska and Fluor managed the FEED study with a 

continuous value engineering approach. Examples of implementing this approach 

included: 

o Tenaska encouraged the Fluor project management and discipline engineers to 

raise ideas and options to reduce cost as they completed their assigned FEED 

study tasks; 
-62-

o In the design reviews and HAZOP, the FEED team brainstormed cost 

reduction ideas; and 

o Following completion of the FEED study, Tenaska and Fluor conducted a 

dedicated value engineering session to identify additional cost reduction ideas. 

Through this approach, the team reduced the capital cost by approximately 

USD$23,400,000. Some of the design ideas contributing to this reduction include the 

application of: 

o A single CO2 compressor soft starter for both machines; 

o Plate and Frame – type heat exchangers for stripper reboilers; 

o Optimized the absorber and DCC construction materials; 

o Eliminated large-bore alloy block and bypass valves; and 

o An “in-line” (instead of “right angle”) plot plan arrangement. 

Again, further optimizations, mostly related to the last value engineering session, may 

need to be considered later in the Project’s development. Section 5.12 provides a list of 

these items. 

7.2 Challenges 

 Change in Flue Gas Basis. As discussed in Section 5.2, the flue gas composition 

required updating before the CO2 capture FEED study could begin. The reason for 

this change was to synchronize the CC Plant design with the selected boiler 

technology and capacity (increased by nominally five percent as compared to the CC 

technology RFQ basis. This necessitated the running of combustion calculations to 

generate new flue gas stream information. 

In addition to the boiler design change, Fluor and Tenaska agreed to add a 

conservative amount of excess air to the combustion calculations to account for air 

leakage into the flue gas path. Re-doing these calculations caused a short delay in the 

start of the CO2 capture FEED study. The result of the calculations provided the CC 

Plant with a range of flue gas flow rates and compositions depending on the type of 

coal. The FEED team selected a hybrid flue gas composition which combined the 

most detrimental aspects from the range of coal flue gas compositions. 

 Status of PC Plant Design. Tenaska placed the PC Plant FEED study on hold at a 

stage of partial completion. During the CC FEED, this created challenges in defining 

interactions between the two plants. Before the next phase of study for the CO2

capture plant, the PC FEED study will need to be completed. 

 Organizational Continuity. Through the previous work to advance the PC Plant 

design and the more recent completion of the CC Plant FEED study, both Tenaska 

and Fluor experienced some organizational discontinuity due to: 

o Fluor reassigned some of the Project personnel when PC effort stopped; 
-63-

o Fluor introduced the EFG+ team to the Project when the CC Plant FEED 

effort began; 

o The EFG+ team evolved as nature of the FEED study activities progressed; 

o Tenaska moved personnel in and out of the Project over time as company 

priorities changed; and 

o Due to the reduced near-term likelihood of the Project, both Tenaska and 

Fluor reduced focus on effort toward the end of the FEED. 

 Economic Uncertainty. The economic assumptions established by Tenaska and 

Burns & McDonnell are not firm and are subject to change. The market value of CO2

used for EOR will vary based on oil pricing and future carbon legislation/regulations. 

The market value of power will also vary based on future environmental regulations, 

state regulations/mandates, economic recovery, and technology advancements. 

Project schedule uncertainty also affects all of the economic assumptions. The values 

of steam, electrical power, pressure drop, and CO2 that underpin the economic 

evaluation factors listed in Figure 7, all are affected by the aforementioned items. 

The value of solvent is based on current market pricing and it is expected to be 

reduced as demand for the product increases and the technology matures. The lack of 

firm project economic criteria limited design optimization efforts and impacted 

decisions made for the design basis. 

 Level of Vendor Support. Vendor support, responsiveness, and competition varied 

significantly. Some of the major equipment suppliers did not respond to RFQs. In 

addition, some of the vendors were not willing to provide firm price quotes as 

requested, but supplied budgetary quotes instead. (These issues were largely limited 

to the very large and unique cutting-edge equipment.) Comparisons and evaluations 

between budgetary and firm price quotes were difficult due to nonconformance to the 

RFQs. Some of the equipment was non-standard or first of a kind or larger than built 

to date. For this type of equipment, some vendors were limited in their ability to 

respond due to lack of previous experience and associated first-time design costs. 

Evaluation of some major equipment bids revealed large cost differentials that were 

not typical of a good competitive bidding. 

 Equipment Sizes. Certain pieces of equipment included in the CO2 capture FEED 

study were sized to be larger than previously built. For example, the CO2 product 

compressors were almost twice as large as the largest commercially operating CO2

compressor. Also, Tenaska and Fluor elected to perform CFD analysis on the large 

diameter columns to ensure proper vapor distribution. This CFD analysis was 

necessary because the size of the columns were larger than any operating in CO2

capture service. 
-64-

8.0 Next Steps 

One of the well-known challenges with CCS is the cost – primarily in terms of the capital 

cost and energy consumption. In the current market structure, power plants that employ 

CCS cannot compete with those that do not. The strategic location of the Project 

provides the ability to sell CO2 into the mature Permian Basin EOR market. This defrays 

some of the costs of CCS. However, the current CO2 market prices are insufficient to 

cover the entire costs of CO2 capture. In addition, the CO2 prices vary as a function of oil 

prices, which introduces uncertainty in this revenue stream over the life of the Project. 

Thus, the Project requires some recognition by the USA Federal government of the value 

associated with capturing CO2. With the status of the USA political climate (which is 

notably different than in 2007 when Tenaska launched the Project) the timing for such 

recognition is uncertain. As such, on the engineering side, the Project is currently in the 

documentation stage and will continue slow development until the key Project signals 

change. Overall Project development will continue to advance in the areas that are 

required to maintain an “early mover” position. Some of these areas include water 

supply, air permitting maintenance, lobbying, legislative support, and local community 

interaction. 

Despite this status, Tenaska and Fluor have developed plans for the next steps of the 

Project. Following is a list of these next steps divided into Tenaska responsibilities and 

Fluor responsibilities: 

8.1 Tenaska Responsibilities 

Upon completion of the FEED study, Tenaska will update Project economics using the 

FEED study cost and performance results. The economic modeling will formally 

confirm the current economic challenges facing the Project. As a result, Tenaska will 

focus on the following to maintain the first-move status, including: 

 Monitor federal carbon capture incentives/legislation/regulations; 

 Maintain / progress environmental permits – key permits would include storm 

and treated wastewater discharge (if required); 

 Continue sourcing water supply opportunities; and 

 Continue dialogue for off-take agreements. 

Upon a change in these key areas, Tenaska will revisit the Project economics. When the 

economics are favorable, Tenaska will engage Fluor to plan for completion of the 

activities listed in Section 8.2. 

8.2 Fluor Responsibilities 

The next steps to progress the CC Plant are as follows: 

 Apply Technological Improvements. Fluor’s EFG+ technology will be 

commissioning a demonstration plant in Wilhelmshaven, Germany during 2011on a 

coal-fueled flue gas. At this plant, Fluor will further validate the technology and 
-65-

verify new design features. Fluor will apply any improvements learned at the 

Wilhelmshaven plant to Trailblazer (at Tenaska’s option). 

 Refine and Implement Value Engineering Ideas. The Fluor and Tenaska project 

teams met at Fluor’s office in Aliso Viejo, California on June 7-9, 2011 to identify 

potential value engineering ideas. Ideas were brainstormed that could potentially 

lower the capital or operating costs of the plant. These ideas were ranked in order of 

cost savings and feasibility. The result of the meeting was a prioritized list of ideas 

for potential further study. 

 Refresh Cost Estimate. At a point in the future, the Trailblazer project will proceed 

into the EPC phase. Before the EPC phase starts, Fluor would refresh the FEED 

study to include any technology improvements to the EFG+ process since the process 

in continually adding improved design features. Additionally, Fluor will requote 

vendor bids to update the capital cost estimate. Lastly, Fluor will finalize the 

interfaces and integration between the PC and CC Plants before the EPC phase 

begins. 
-66-

9.0 Lessons Learned 

Following is a list of the lessons learned in preparing for, conducting, and managing the 

CC Plant FEED study: 

 Interface Definition and Optimization. Defining and optimizing the interface between 

the PC and CC Plants (e.g. heat integration) was important during the CC Plant FEED 

study. These two pieces of the overall Project scope are different technically and 

generally belong to two different industries (power and process). As a result, it is 

natural that experience in the respective scope areas comes from different 

organizations and these organizations can have different codes, design criteria, and 

standard practices. It is necessary to have both organizations (whether they are the 

same company or different companies) directly involved. Furthermore, it is ideal if 

the engineering of both pieces of the scope proceeds simultaneously to realize 

synergies between the two scopes. 

 Single Point of Contact. Tenaska realized strong coordination from the direct 

involvement of both the PC and CC teams and reaffirmed the value of having both 

scopes awarded to one organization. By doing so, Fluor was able to apply common 

methods in areas such as project management, document control, and design 

procedures. This also reduced concerns with proper handling of confidential 

information and allowed greater transparency in seeking optimized heat integration. 

 Value Engineering. Tenaska experienced success with a continuous focus on value 

engineering through the FEED study as the capital cost estimate came in very near the 

indicative bid. 

Through this approach, the team reduced the capital cost by approximately 

USD$23,400,000. Some of the design ideas contributing to this reduction include the 

application of: 

o A single CO2 compressor soft starter for both machines; 

o Plate and Frame – type heat exchangers for stripper reboilers; 

o Optimized the absorber and DCC construction materials; 

o Eliminated large-bore alloy block and bypass valves; and 

o An “in-line” (instead of “right angle”) plot plan arrangement. 

 Vendor Support. Tenaska and Fluor experienced some minor difficulty in attracting 

vendor interest and, therefore, obtaining multiple compliant and competitive bids for 

all equipment. 

 Firm Project Economics. It is not yet known how CO2 regulations and prices will 

affect power prices locally and nationally. CO2 price support from regulations or 

legislation is necessary because CO2 prices available from EOR off-takers (a 

commonly used rule of thumb algorithm is CO2 price per million cubic feet = 2% of 

the posted project equivalent oil price per barrel) are insufficient to support CO2
-67-

capture – especially with the inherent volatility in the crude oil commodity market. 

Thus, during the FEED it was difficult to evaluate design alternatives. 

 Operations Support. Although Tenaska had substantial support in terms of project 

management and discipline engineering both internally and via Burns & McDonnell, 

the FEED team recommends a greater level of involvement from experienced 

operations personnel to ensure alignment with the operational capabilities determined 

in the design phase. 

 Capital Cost Estimate Accuracy. Tenaska selected Fluor a the CC Plant technology 

provider on the basis of multiple criteria with one being the nonbinding indicative 

capital cost of the plant based on Econamine FG+ technology – perhaps an AACE 

Class 4 or 5 estimate with nominally +/- 30% accuracy. As such, a key objective of 

the FEED study was to complete engineering design definition to increase the 

accuracy of the estimate sufficiently to allow Fluor to offer firm price for the CC 

Plant scope of the Project with a contingency allowance that was determined prior to 

the study. 

 Addressing Key Scale-Up Issues. With the large equipment required for the CC Plant 

and the scale-up it represents from previous experience, a few key areas required 

special engineering study. These included the mechanical design of the large flue gas 

ducts, CFD modeling of the flue gas flow in these ducts, CFD modeling of the gas 

and liquid distribution in the DCC and absorber, and detailed evaluation of the CO2

compressor vendor bids and experience. 
-68-

10.0 Relevance to Carbon Capture and Storage 

A FEED study is required to complete enough technical definition to determine the cost 

and performance of a new CCS project with enough certainty to obtain financing. 

Completing the FEED study, along with receiving the appropriate permits and having the 

necessary economic drivers, will allow projects to move into execution and become a 

reality. 

However, a FEED study is a lengthy, costly, and detailed effort. This report documents 

the scope of such an effort, the results, and the lessons learned along the way. This 

content will help other developers to implement the best technical design, achieve cost 

and performance goals, and manage the effort as a whole. 
-69-

11.0 Conclusions 

Tenaska and Fluor completed a FEED study for the CC Plant portion of the Trailblazer 

Project. The study achieved its objectives (see Section 2.2) resulting in: 

 A design which meets Tenaska and industry standards, notably in the areas of safety 

(through incorporation of the findings from the HAZOP and air dispersion modeling) 

and environmental profile (through specification of the CO2 capture rate at and 

permitted air emissions in the design basis); 

 Confirmation that the technology can be scaled up to constructable design at 

commercial size though (1) process and discipline engineering design and CFD 

analysis, (2) 3D model development, and (3) receipt of firm price quotes for large 

equipment; 

 Production of engineering design and planning deliverables which supported 

deterministic cost estimation; 

 Confirmation of the cost estimate basis through an open-book process; 

 A firm second-quarter overnight EPC price offer of USD$667,100,000 for the CC 

Plant that was consistent with the original indicative bid for the CC Plant. This 

supports the overall project (PC and CC Plants) cost basis consisting of (1) an EPC 

cost (with contingency and escalation) of USD$2,800,000,000 to USD$3,300,000,000 

plus (2) Owner’s costs, interconnects, financing fees, and interest during construction 

at an additional USD$1,000,000,000 to USD$1,250,000,000; 

 An O&M cost estimate totaling nominally USD $10,400,000 per year (excluding 

power and steam consumption); and 

 Establishment of performance guarantees which, after the addition of an appropriate 

margin, were consistent with the expected performance in Fluor’s indicative bid. 

Tenaska and the Project avoided potential difficulties managing confidential information 

and benefitted from the single point of contact with Fluor and close coordination between 

the PC and CC engineering organizations. Additionally, the focus on continuous value 

engineering efforts (through every meeting/conference call, review of deliverables, 

design reviews, and a dedicated value engineering session) aided the team in achieving an 

EPC price which approached the indicative basis. 

Figure 21 shows how this report meets the goals listed in Section 2.3 

 
-70-

Figure 21 – Achievement of Report Goals 

Goals Satisfaction 

Describe the scope of the CC Plant and the FEED 

study performed 

Section 4.0 describes the scope of the CC Plant 

facilities while Section 5.0 describes the Scope of the 

FEED study services. 

Provide FEED study results including cost and 

performance 

 Capital Cost listed in Section 5.8.9 

 O&M Cost components listed in Section 5.9 

 Performance summarized Section 5.10 Figure 16 

and in Attachment 1, Pages 7&8 



Describe challenges and highlights of the FEED 

study 

Refer to Section 7.0 

Confirm that construction and operation of a large 

scale CO2 capture plant integrated with a coalfueled power plant is feasible 

 Constructability confirmed through internal Fluor 

meetings, plot plan development, and production 

of the 3D model. 

 Operation aspects addressed through completion 

of the HAZOP. 

 Overall feasibility back by Fluor firm price offer 

and performance guarantees. 

Confirm that the health, safety and environmental 

impacts associated with a carbon capture plant are 

acceptable 

Refer to Section 6.0 – accomplished by incorporating 

HAZOP findings into design and by air dispersion 

modeling of identified risk cases. 

Provide the “next steps” required to advance the 

development of the Project 

Refer to Section 8.0 

Provide lessons learned from the FEED study Refer to Section 9.0 
-71-

12.0 Acronyms and Citations 

Acronym Definition 

2D Two Dimensional 

3D Three Dimensional 

AACE Association for the Advancement of Cost Engineering 

ACFM Actual Cubic Feet per Minute 

ACI Activated Carbon Injection 

Ar Argon 

BNSF Burlington Northern Santa Fe Railroad 

Btu British Thermal Unit 

CAD Computer Automated Design 

CATOX Catalytic Oxidation 

CC Carbon (Dioxide) Capture 

CC Plant Commercial scale carbon capture plant portion of the Tenaska 

Trailblazer Energy Center 

CCS Carbon Capture and Sequestration (or Storage) 

CF Capacity Factor 

CFD Computational Fluid Dynamics 

CFR Code of Federal Regulations 

CH4 Methane 

CO2 Carbon Dioxide 

CO Carbon Monoxide 

COD Commercial Operations Date 

DCC Direct Contact Cooler 

DCS Distributed Control System 

DOR Division of Responsibility 

EDF Environmental Defense Fund 

EFG+ Econamine FG Plus 

EP Engineer & Procure 

EPC Engineer – Procure – Construct 

EPCC Engineering, Procurement, Construction, and Commissioning 

EOR Enhanced Oil Recovery 

ERCOT Electric Reliability Council of Texas 
-72-

Acronym Definition 

ESP Electrostatic Precipitator 

FEED Front-End Engineering Design 

FGD Flue Gas Desulfurization 

Fluor Fluor Enterprises and Fluor Corporation, collectively 

Global CCS Institute Global Carbon Capture and Storage Institute 

HAZID Hazard Identification Study 

HAZOP Hazard and Operability Study 

H2O Water 

H2S Hydrogen Sulfide 

H2SO4 Dihydrogen Sulfate (Sulfuric Acid) 

HCl Hydrogen Chloride 

HF Hydrogen Fluoride 

Hg Mercury 

HMB Heat and Material Balance 

HSS Heat Stable Salts 

HVAC Heating, Ventilation, and Air Conditioning 

IDLH Immediately Dangerous to Life and Health 

IP Intellectual Property 

ISBL Inside Battery Limits 

kV Kilo (thousand) Volt 

kW Kilo (thousand) Watt 

kPa Thousands of Pascals (unit of Pressure) 

lbmol Pound mole 

Lb Pound 

LLC Limited Liability Corporation 

LP Low Pressure (e.g. steam) 

MEA Monoethanol amine 

MW MegaWatt 

MCC Motor Control Center 

MMBtu Million British Thermal Units 

MOU Memorandum of Understanding 

MSD Material Selection Diagrams 

Mph Miles per Hour 
-73-

Acronym Definition 

NaOH Sodium Hydroxide or Caustic Soda 

N2 Nitrogen 

NH3 Ammonia 

NOx Nitrogen Oxides 

NPV Net Present Value 

NTP Notice to Proceed 

O2 Oxygen 

OEM Original Equipment Manufacturer 

OSBL Outside Battery Limits 

OSHA Occupational Safety and Health Administration 

Pb Lead 

PC Plant Supercritical pulverized coal electric generating station 

portion of the Tenaska Trailblazer Energy Center 

PFD Process Flow Diagram 

P&ID Process and Instrumentation Diagram 

PC Pulverized Coal 

PHAST Process Hazards Analysis Software Tool 

PHA Process Hazard Analysis 

PM Particulate Matter 

PRB Powder River Basin 

Project Tenaska Trailblazer Energy Center 

Project Company Tenaska Trailblazer Partners, LLC 

QA Quality Assurance 

RFP Request for Proposals 

RFQ Request for Quotation 

SI System International 

SCR Selective Catalytic Reduction 

SO2 Sulfur Dioxide 

STPD Short Ton per Day 

TCEQ Texas Commission on Environmental Quality 

TMV Tenaska Marketing Ventures 

TPS Tenaska Power Services 

Trailblazer Tenaska Trailblazer Energy Center 
-74-

Acronym Definition 

UP Union Pacific (Railroad) 

USA United States of America 

USD United States Dollars 

VOC Volatile Organic Chemical 
ATTACHMENT 1 

Non-Confidential FEED 

Study Deliverables 
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Funding Agreement Page 38 

Non-Confidential FEED Study Deliverables 
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TABLE OF CONTENTS

1.0 Process Description - Page 38 (b) (ii) (A) ........................................................... 3

1.1 Flue Gas Cooling and Trim SO2 Removal....................................................... 3

1.2 Flue Gas Blower and CO2 Absorption ............................................................ 4

1.3 Solvent Regeneration.................................................................................... 4

1.4 Steam and Condensate System....................................................................... 5

1.5 Solvent Reclaiming ...................................................................................... 5

1.6 Solvent Make-Up ......................................................................................... 6

1.7 CO2 Compression and Dehydration................................................................ 6

2.0 Process Performance – Page 38 (b) (ii) (B)......................................................... 7

3.0 CO2 Capture Efficiency and Capacity – Page 38 (b) (ii) (C) ............................... 8

4.0 Simplified Plot Plan – Page 38 (b) (ii) (D).......................................................... 9

5.0 Block Flow Diagram – Page 38 (b) (iii) (A)...................................................... 10

6.0 Process Flow Diagrams – Page 38 (b) (iv) (A + B)............................................ 11

7.0 Overall Heat and Material Balance – Page 38 (b) (v) (A) ................................. 12

8.0 Capital Cost Data – Page 38 (b) (vi) ................................................................ 13
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1.0 Process Description - Page 38 (b) (ii) (A) 

Equipment associated with Trains 1 and 2 have tag numbers 10XX and 20XX respectively. All 

common equipment items have tag numbers 00XX. In the following process description, only 

Train 1 equipment and common equipment are described. Train 2 is identical to Train 1. 

The plant is designed to be 100% air cooled. 

1.1 Flue Gas Cooling and Trim SO2 Removal 

Flue gas to the Econamine FG PlusSM (EFG+) facility comes from the Flue Gas Desulfurization 

(FGD) tower. The ducting from the FGD to the Power Plant stack will have two take off ducts. 

The two ducts will directly feed the two fifty percent EFG+ trains. 

Flue gas from the FGD unit is first routed to the 2-Stage Direct Contact Cooler (DCC) (CCCCLM-1001) for both cooling and trim SO2 removal in two separate packed sections. 

The flue gas enters the bottom of the DCC and is first cooled in the lower section by a circulating 

water stream. The circulating water contacts the flue gas over packing and most of the 

particulates present in the flue gas are removed by scrubbing. 

The circulating water enters the quench section of the DCC and is heated by the cooling and 

condensing of water vapor in the flue gas. Circulating water is drawn from the bottom of the 

DCC to the DCC Water Cooler (CCC-AHX-1001) by DCC Water Pump (CCC-P-1001A/B) and 

returned to the top of the column’s quench section. 100% air cooling is employed to cool the 

circulating water. 

A slip stream is diverted from the circulating water downstream of the DCC Water Pump 

through the DCC Water Filter (CCC-FLT-1001A/B), to continuously remove particulate matter. 

A portion of the filtered water is returned to the liquid surge volume in the bottom of the DCC. 

The excess water is sent to the battery limits. A small slip stream of the filtered excess water is 

intermittently diverted to dilute a 50 wt% sodium hydroxide (NaOH) solution to a 20 wt% NaOH 

solution, to be fed into the scrubbing solution for trim SO2 removal in the top section of the 

DCC. In the top section, the cooled flue gas from the DCC lower bed contacts a circulating 

scrubbing solution. The scrubbing solution is extracted from a chimney tray located above the 

quench section of the DCC and is sent back to the top of the column by DCC Scrubbing Solution 

Pump (CCC-P-1007A/B). A blow down slip is taken from the circulating scrubbing solution loop 

which is sent to the plant battery limits. The scrubbing solution enters the top of the DCC and 

absorbs the SO2 from the flue gas. The cooled, desulfurized flue gas passes through a mesh mist 

eliminator and exits the top of the column. 
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The 20 wt% NaOH solution supplied by the NaOH Injection Package (CCC-SKID-0001) is fed 

to the suction of the DCC Scrubbing Solution Pump in order to maintain the concentration in the 

scrubbing loop. 

Prior to the NaOH Injection Package, a 50 wt% NaOH solution from the 50 Wt% NaOH Storage 

Tank (CCC-TK-0002) is pumped by the 50 Wt% NaOH Pump (CCC-P-0004A/B) and diluted to 

a 20 wt% NaOH solution with the filtered excess quench water in the NaOH Dilution Mixer 

(CCC-MIX-0002). 

1.2 Flue Gas Blower and CO2 Absorption 

The Blower (CCC-BLO-1001), located downstream of the DCC, is used to overcome the 

pressure drop through the EFG+ plant. The flue gas enters the bottom of the Absorber (CCCCLM-1002) and flows upward through the packed column where it reacts with the lean solvent 

to remove 90% of the carbon dioxide (contained in the flue gas). A total draw of semi-rich 

solution is extracted from a chimney tray near the bottom of the second amine bed and sent by 

the Absorber Intercooler Pump (CCC-P-1003A/B) through the Absorber Intercooler (CCCAHX-1003). The semi-rich solution is cooled against air before being returned to the Absorber. 

Treated gas from the absorption section passes through a mesh mist eliminator and enters the 

wash section at the top of the Absorber where solvent in the vapor phase is captured by a 

circulating wash water loop. The wash water is removed from a chimney tray and sent by the 

circulating Absorber Wash Water Pump (CCC-P-1002A/B) through Absorber Wash Water 

Cooler (CCC-AHX-1002). The wash water is cooled against air and returned to the top of the 

Absorber. Demineralized (RO) water is also added to the top tray of the column to remove any 

entrained solvent in the exiting flue gas before the gas is routed through a mesh mist eliminator 

and through a duct to the power plant stack for venting to atmosphere. 

Excess solvent/water from the wash water section combines with lean solvent entering the top of 

the Absorber. 

1.3 Solvent Regeneration 

The carbon dioxide-rich solvent leaves the bottom of the Absorber and is pumped by a Rich 

Solvent Pump (CCC-P-1004A/B) to the solvent regeneration section. The rich solvent from the 

Absorber is routed to a Solvent Cross Exchanger (CCC-HX-1001) to heat the rich solution 

against the lean solution from the Lean Flash Drum (CCC-V-1002). The hot rich solvent then 

enters the Stripper (CCC-CLM-1003). 

The rich solvent flows down through two packed beds counter-current to stripping steam, which 

removes CO2 from the rich solvent. The solvent collects on the bottom chimney tray and is sent 
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to the Reboiler (CCC-HX-1002). Heat input to the Reboiler is provided by condensing low 

pressure (LP) steam. 

In the wash section of the Stripper above the feed nozzle, water from the Overhead Accumulator 

(CCC-V-1001) is used to wash any entrained solvent out of the vapor stream. The resulting 

vapor from the top of the Stripper contains CO2 saturated with water. The vapor is cooled and 

condensed against condensate from the PC plant in the PC Condensate Heater (CCC-HX-1003) 

and air by the Condenser (CCC-AHX-1012). The two phase mixture enters the Overhead 

Accumulator where the carbon dioxide and condensed water are separated. The condensed water 

is pumped out of the Overhead Accumulator by the Reflux Pump (CCC-P-1005A/B). A portion 

of the condensate is returned to the Stripper as reflux by the Reflux Pump. The remaining liquid 

from the Overhead Accumulator is sent to the Absorber. The carbon dioxide rich vapor is sent to 

the CO2 compressor (CCC-CMP-1002). 

The lean solvent leaving the Stripper is sent to a Lean Flash Drum (CCC-V-1002) where it is 

flashed at near atmospheric pressure. The resulting flashed vapor, consisting primarily of steam, 

is returned to the Stripper via the Lean Vapor Compressor (CCC-CMP-1001). 

The lean solvent from the Lean Flash Drum is pumped by the Lean Solvent Pump (CCC-P1006A/B) to the Solvent Cross Exchanger to provide heat to the rich solvent. After passing 

through the Solvent Cross Exchanger, the lean stream is further cooled against air in the Lean 

Solvent Cooler (CCC-AHX-1004) before being routed back to the Absorber. 

A portion of the cooled solvent is sent to the Lean Solvent Filtration Package. The package 

consists of a Carbon Bed Inlet Filter (CCC-FLT-1002), a Carbon Bed Filter (CCC-FLT-1003), 

and a Carbon Bed Outlet Filter (CCC-FLT-1004). The filtered solvent returns to the main lean 

solvent line where it is recycled back to the Absorber. 

1.4 Steam and Condensate System 

Low pressure superheated steam at the EFG+ Plant battery limits is provided by the power plant 

to meet all steam demands. The steam is desuperheated in the LP Steam Desuperheater (CCCDSH-1001) with low pressure condensate pumped by the Reboiler Condensate Pump (CCC-P1008A/B) from the Reboiler Condensate Drum (CCC-V-1003). Steam condensate is returned to 

the power plant battery limits. 

1.5 Solvent Reclaiming 

A slip stream of hot lean solvent from the Lean Solvent Pump discharge is taken out through a 

semi-continuous reclaiming operation. Also a 20 wt% NaOH solution stream is sent to the 

reclaimer system package. The recovered solvent is sent back to the Lean Flash Drum. The 
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reclaimer waste is routed to a waste container and is disposed of via an external disposal 

company. 

1.6 Solvent Make-Up 

The make-up solvent for both trains is stored in a common Solvent Storage Tank (CCC-TK0001). Solvent make-up (normally no flow) can be injected into the lean solvent lines when 

required. The solvent is sent from storage to either train’s lean solvent line by a common Solvent 

Make-up Pump (CCC-P-0001) via Solvent Make-Up Pump Suction Heater (CCC-HTR-0002). 

Any solvent spills will be collected in the Solvent Sumps (CCC-SUMP-1002) which are 

periodically emptied to the common Solvent Holding Tank (CCC-TK-0003) via Solvent Sump 

Pumps (CCC-P-1011). Solvent from the Solvent Holding Tank can be routed to the Absorbers by 

the Solvent Transfer Pump (CCC-P-0003) through the Solvent Sump Filter (CCC-FLT-0001). 

1.7 CO2 Compression and Dehydration 

Following recovery, the CO2 product must be compressed and purified to meet the pipeline 

specifications for oxygen and water. An eight stage, integrally-geared CO2 Compressor 

compresses the product carbon dioxide to 2500 psig. Upstream of the CATOX Unit (CCC-V1008), the gas is cooled with air coolers (CCC-AHX-1005/6/7/8) after each stage of 

compression. Any condensed water is separated from the gas in knockout drums (CCC-V1004/5/6/7). 

The CATOX Unit is used to reduce the O2 concentration by catalytic combustion of a hydrogen 

gas from the power plant with the partially compressed CO2 product after the fifth stage of 

compression. The CATOX Unit is a reactor containing a highly reactive catalyst that allows the 

safe and controlled combustion of hydrogen with oxygen, producing water which is knocked out 

after cooling. 

The gas leaving the CATOX Unit is cooled in the fifth stage intercooler (CCC-AHX-1009) with 

any condensed water separated from the gas in CO2 Compressor Knockout Drum #5 (CCC-V1009). The CO2 product is then sent to the CO2 Dehydration Package (CCC-DRY-1001) to 

reduce the water content in the stream to below the required dew point. Three more stages of 

compression are needed to achieve the required CO2 product pressure. The gas between the sixth 

and seventh stage of compression is cooled by CO2 Compressor Intercooler #6 (CCC-AHX1010). In the CO2 Compressor Aftercooler (CCC-AHX-1011) on the final stage of compression, 

the product carbon dioxide stream is cooled to 99°F and routed to the battery limit for pipeline 

transportation. 
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2.0 Process Performance – Page 38 (b) (ii) (B) 

EFG+ and Compression Plant Performance (Note 1) 

Steam Usage (lb/hr) (note 2) 2,011,800 

Power Consumption (kW) (note 3) 119,770 

Notes: 

1. Numbers given are for the sum of the two trains. 

2. Steam conditions at battery limits: 50 psig, saturated. 

3. The power consumption number excludes the following: 

o All heaters (not including the Reboiler Condensate Heater or the heater associated 

with the Dehydration package) 

o All fans (not including Air Cooled heat exchangers: CCC-AHX-1001/2001 through 

CCC-AHX-1012/2012) 

o All lighting 

o Air conditioning 

o Line tracing 

o Transformer power loss 

o Lube oil pumps and heaters 

o Panelboards 

o Station battery chargers 

o Welding receptacles 

o Bridge cranes 

o Air conditioning unit MV electrical room 

o RIE power supply (normal and alternate) 

o Non-continuous services 

a. Solvent make-up pump 

b. Solvent make-up pump suction heater 

c. Solvent Sump pump 

d. 50 wt% NaOH pumps 

e. Solvent Transfer pump 

f. CO2 Depressurization Heater
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3.0 CO2 Capture Efficiency and Capacity – Page 38 (b) (ii) (C)

EFG+ Plant Performance (Note 1) 

CO2 Capture Capacity (STPD) 18,103 

CO2 Capture Efficiency (%) 90 
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4.0 Simplified Plot Plan – Page 38 (b) (ii) (D)

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5.0 Block Flow Diagram – Page 38 (b) (iii) (A) 
Battery Limits

Flue Gas from FGD

Absorption Train # 1

Absorption Train # 2

Steam

from OSBl

Condensate

to OSBL

Stripper Tra

Abbreviations:RO Reverse OsmosisDCC Direct Contact CoolerOSBL Outside CC Plant Battery LimitsFGD Flue Gas Desulfurization

Solvent

Flue Gas

CO2 Product

Steam/Condensate

Water

Chemicals/Waste

C

Stripper

Reboiler

Rich Solvent

Blower Absorber

Blowdown 

Chemicals to OSBL

2-Stage 

DCC 

Flue Gas to Power 

Plant Stack

Excess Water 

to OSBL

Flash/Vapor 

Compressor

Stripper

Reboiler

Rich Solvent

Lean 

Solvent

Blower Absorber

Blowdown 

Chemicals to OSBL

2-Stage 

DCC 

Flue Gas to Power 

Plant Stack

Excess Water 

to OSBL 

Recovered 

Solvent

Stripper Tra

Lean 

Solvent

Flash/Vapor 

Compressor

Steam from 

OSBL

Condensate

to OSBL

10,057 

tons

CO2/day

10,057 

tons

CO2/day

1006 tons

CO2/day

1006 tons 

CO2/day

Demin (RO) 

Water from 

OSBL

Demin (RO) 

Water from 

OSBL C

to/fr

C

to/f

Recovered Solvent

C
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6.0 Process Flow Diagrams – Page 38 (b) (iv) (A + B) 






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7.0 Overall Heat and Material Balance – Page 38 (b) (v) (A) 
Tenaska 

Trailblazer Carbon Capture Plant FEED

Econamine FG PlusSM

CC-Plant Heat and Material Balance

All stream reports shown are for 1 of 2 trains, except for stream 001, which is common to both trains.Stream Numbers 101 106 110 Temperature, °F 131.3 129.4 104.8 Pressure, psia 13.67 73.66 68.76 

MW lbmol/hr mol% lbmol/hr mol% lbmol/hr mol%

H2O 18.02 27,533 16.8% 16,053 100.0% 52.0 96.1%

CO2 44.01 19,042 11.6% 1 88 ppmw 0 36 ppmw

N2 28.02 108,071 66.1% 0 9 ppmw 0 4 ppmw

Ar 39.95 1,300 0.8% 0 0 ppmw 0 0.0%

O2 32.00 7,649 4.7% 0 1 ppmw 0 0.0%

SO2 64.06 1.64 10 ppmv 0 14 ppmw 0 0.0%

NO2 46.01 0.47 3 ppmv 0 0.0% 0 0.0%

NO 30.01 3.83 23 ppmv 0 0.0% 0 0.0%

NaNO2 69.00 0 0.0% 0 0.0% 0.45 0.8%

NaHSO4 120.06 0 0.0% 0 0.0% 0 0.0%

NaOH 40.00 0 0.0% 0 0.0% 0 0.0%

NaHSO3 104.06 0 0.0% 0 0.0% 0 269 ppmw

Na2SO3 126.04 0 0.0% 0 0.0% 0.1 0.2%Na2SO4 142.04 0 0.0% 0 0.0% 1.5 2.6%

NaHCO3 84.00 0 0.0% 0 0.0% 0.1 0.2%

Na2CO3 105.98 0 0.0% 0 0.0% 0 328 ppmw

Total Molar Flow, lbmol/hr 163,598 16,054 54 Total Mass Flow, lb/hr 4,658,340 289,234 1,180 Molecular Weight 28.5 18.0 21.8 Density, lb/cuft 0.061 61.6 73.5 Liquid Flow, gpm 585.7 1.99 Vapor Flow, MMscfd (dry) 1,239Vapor Flow, MMscfd (wet) 1,490 Vapor Flow, cuft/hr (actual) 75,789,114 pH 3.7 7.6 

Note 1:

Stream Description Flue Gas to DCC 

Component Flows

Excess DCC Water 

(Note 1)

Scrubbing Solution 

Blowdown from DCC

Stream flow rate shown is during 20% NaOH storage tank filling in NaOH Injection Package. When 20% NaOH Storage tank is not filling, stream 106 flow rate increases b
Tenaska 

Trailblazer Carbon Capture Plant FEED

Econamine FG PlusSM

CC-Plant Heat and Material Balance

All stream reports shown are for 1 of 2 trains, except for stream 001, which is common to both trains.Stream Number 112 113 129 130 132 Temperature, °F 108.7 80.0 94.1 < 100.0 82.0 Pressure, psia 13.64 13.73 37.19 2,515.0 409.5 

MW lbmol/hr mol% lbmol/hr mol% lbmol/hr mol% lbmol/hr mol% lbmol/hr mol%

H2O 18.02 11,825 9.0% 1,316 100.0% 895 99.4% 0 < 3 ppmv 0 0.0%

CO2 44.01 1,904 1.5% 0 0.0% 5 0.6% 17,133 100.0% 0 0.0%

EFG+ Solvent 61.08 0 1 ppmv 0 0.0% 0 0.0% 0 0.0% 0 0.0%

N2 28.02 108,067 82.7% 0 0.0% 0 0.0% 4 217 ppmv 0 0.0%

Ar 39.95 1,300 1.0% 0 0.0% 0 0.0% 0 5 ppmv 0 0.0%

O2 32.00 7,649 5.9% 0 0.0% 0 0.0% 0 < 10 ppmw 0 0.0%

H2 2.02 0 0.0% 0 0.0% 0 0.0% 0 6 ppmv 1.0 100.0%

NO2 46.01 0 0.18 ppmv 0 0.0% 0 0.0% 0 0.0% 0 0.0%

NO 30.01 4 29 ppmv 0 0.0% 0 0.0% 0 0.0% 0 0.0%

HSS - 0 0.0% 0 0.0% 0 0.0% 0 0.0% 0 0.0%

Total Molar Flow, lbmol/hr 130,745 1,316 900 17,137 1.0 Total Mass Flow, lb/hr 3,620,980 23,700 16,190 754,130 2.0 Molecular Weight 27.7 18.0 18.0 44.0 2.0 Density, lb/cuft 0.062 62.2 39.3 27.1 0.144 Liquid Flow, gpm 47.5 51.4 3,474 Vapor Flow, MMscfd (dry) 1,083 0.01 Vapor Flow, MMscfd (wet) 1,191 0.01 Vapor Flow, cuft/hr (actual) 58,418,639 15.2 pH 7.0 3.7 

Stream Description Compression Condensate Make-up Wash Water to Absorber Treated Flue Gas to Power Plant Stack

Component Flows

Compressed CO2 

Product

Hydrogen 

to CATOX Unit
Tenaska 

Trailblazer Carbon Capture Plant FEED

Econamine FG PlusSM

CC-Plant Heat and Material Balance

All stream reports shown are for 1 of 2 trains, except for stream 001, which is common to both trains.Stream Numbers 136 001 Temperature, °F 283.7 82.0 Pressure, psia 13.66 17.66 

MW lbmol/hr mol% lbmol/hr mol%

H2O 18.02 - - 1,100 68.9%

CO2 44.01 - - 0.0 0.0%

EFG+ Solvent 61.08 - - 0.0 0.0%

HSS - - - 0.0 0.0%

Degradation Product - - - 0.0 0.0%

NaOH 40.00 - 495 31.1%

Total Molar Flow, lbmol/hr - 1,595

Total Mass Flow, lb/hr 280 35,840

Molecular Weight - 22.5

Density, lb/cuft 75.0 94.7

Liquid Flow, gpm 0.46 47.2

Vapor Flow, MMscfd (dry)Vapor Flow, MMscfd (wet)Vapor Flow, cuft/hr (actual)pH 8.4 14.0

Note 2: Stream flow rate shown is the maximum flow rate when 50% NaOH pump is filling the 20% NaOH storage tank in NaOH Injection Package. 50% NaOH Pump operatNote 3: Reclaimer effluent LHV is approximately 4,700 Btu/lb.

Reclaimer Effluent

(Note 3)

Component Flows

Stream Description 50 wt% NaOH (Note 2)
Tenaska Trailblazer Partners, LLC 

Trailblazer Energy Center Date 11 Aug 2011 

Carbon Capture Plant Page 13 of 13 

Contract: A4KC Revision 0

®

8.0 Capital Cost Data – Page 38 (b) (vi) 

Capital Cost Data 

Total Project Cost (USD) $667,099,000 
ATTACHMENT 2 

Project Division of 

Responsibility Matrix 
Carbon Capture Plant

Contract: A4KC

Reference 

No. Description Supply Erect / Install Startup & Commissioning Comments

SCOPE OF FACILITIES

OUTSIDE BATTERY LIMITS FACILITIES (OSBL)

OSBL1 Piping: Underground & above ground systems (see "Interconnecting Piping/Ducting Systems" for list of services) PC PC PC Includes utility systems and waste wa

OSBL2

Ductwork: Ducting & isolation damper upstream of the DCC (to DCC inlet expansion joint). Ducting & isloation damper downstream

of the Absorber outlet flange

PC PC PC

OSBL2A Ductwork Instrumentation; DCC inlet ducting instrumentation and Absorber outlet ducing instrumentation CC CC CC Instruments as identified on CC P&ID

OSBL3 Electrical: 345 Kv Power Feeder to CC ISBL Electrical equipment (to high side of auxiliary transformer) PC PC PC

OSBL4 Control Systems: Central Control Room, DCS, interconnecting cabling* from CC ISBL Marshalling Panels (located in PDCs) to PC PC PC * including fiber optic connection

OSBL5 Civil: Grading, drainage, paving PC PC PC

INSIDE BATTERY LIMITS FACILITIES (ISBL)

A1.0 DEMOLITION, SITEWORK, GRADING AND CIVIL

A1.1 Relocation of existing overhead lines, wellheads and other existing structures as required TENASKA TENASKA n/aA1.1 Site clearing PC PC n/aA1.2 Geotech Report PC n/a n/aA1.3 Topographical Mapping PC n/a n/aA1.4 Rough grade PC PC n/aA1.5 Final Grade PC PC n/aA1.6 Storm water collection and drain to offsite retention PC PC PC See also Interconnecting Piping SysteA1.7 Paving and gravel surfaces PC PC n/a includes spill containment areas for soA1.8 Fencing and gates PC PC n/a PC Plant is within facility perimeter fen

and CC plants

A2.0 STRUCTURAL n/a

A2.1 Foundation excavation and backfill CC CC n/aA2.2 Foundation Concrete/ Rebar/ Piles CC CC n/aA2.3 Embedments CC CC n/aA2.4 Support structures for CC process equipment and machinery CC CC n/aA2.5 Pipe racks ISBL CC CC n/aA2.6 Ducting supports CC CC n/aA2.7 Access platforms, stairs, ladders CC CC n/aA2.8 Compressor building overhead crane CC CC CC For compressor maintenance

A3.0 BUILDINGS

A3.1 Product Compressor buildings CC CC CC Pre-engineered building shelters (venA3.2 Power Distribution Centers (PDC) CC CC CC Pre-fabricated building to house electA3.3 Analyzer shelters CC CC CC Pre-fabricated shelters for housing anA3.4 Caustic Storage Building CC CC CC During EPCC phase, this facility will b

storage facility for overall project.

A3.5 Truck loading shelter CC CC CC

CARBON CAPTURE PLANT PROCESS EQUIPMENT SYSTEMS

Equipment inlcudes all auxililube oil, seal systems, etc. as 

B1.0 ABSORPTION EQUIPMENT SYSTEM CC CC CC

B1.1 Blower CC CC CC

B1.2 DCC Circulating Water Cooler CC CC CC

DIVISION OF RESPONSIBILITY MATRIX

For the purpose of summarizing what is included in the CC Plant EPCC price
Carbon Capture Plant

Contract: A4KC

Reference 

No. Description Supply Erect / Install Startup & Commissioning Comments

DIVISION OF RESPONSIBILITY MATRIX

For the purpose of summarizing what is included in the CC Plant EPCC price

B1.3 Circulating Wash Water Cooler CC CC CC

B1.4 Absorber Intercooler CC CC CC

B1.5 DCC Circulating Water Filter CC CC CC

B1.6 Wash Water Filter CC CC CC

B1.7 2-Stage Direct Contact Cooler (DCC) CC CC CCB1.8 Absorber CC CC CCB1.9 DCC Circulation Pump CC CC CC

B1.10 Circulating Wash Water Pump CC CC CC

B1.11 Absorber Intercooler Pump CC CC CC

B1.12 Rich Solvent Pump CC CC CC

B1.13 DCC Scrubbing Solution Pump CC CC CC

B2.0 STRIPPING EQUIPMENT SYSTEM CC CC CC

B2.1 Lean Vapor Compressor CC CC CC

B2.2 Solvent Cross Exchanger CC CC CC

B2.3 Lean Solvent Cooler CC CC CC

B2.4 Condenser CC CC CC

B2.5 Reboiler CC CC CC

B2.6 Carbon Bed Inlet Filter CC CC CC

B2.7 Carbon Bed CC CC CC

B2.8 Carbon Bed Outlet Filter CC CC CC

B2.9 Stripper CC CC CC

B2.10 Overhead Accumulator CC CC CC

B2.11 Lean Flash Drum CC CC CC

B2.12 Reboiler Condensate Drum CC CC CC

B2.13 Reflux Pump CC CC CC

B2.14 Lean Solvent Pump CC CC CC

B2.15 Reboiler Condensate Pump CC CC CC

B2.16 CO2 Silencer CC CC CC

B3.0 CO2 COMPRESSION EQUIPMENT SYSTEM CC CC CC See also Interconnecting Piping Sy

B3.1 Product CO2 Compressor CC CC CC

B3.2 CO2 Compression Intercoolers CC CC CC

B3.3 CO2 Compression Aftercooler CC CC CC

B3.4 CO2 Compressor Knock-out Drums CC CC CC

B3.5 CATOX Unit CC CC CC

B3.6 Dehydration Package CC CC CC

B3.7 CATOX Catalyst CC CC CC

B4.0 RECLAIMING EQUIPMENT SYSTEM CC CC CCB5.0 SOLVENT STORAGE AND MAKE-UP EQUIPMENT SYSTEM CC CC CC

B5.1 Solvent Sump Filter CC CC CC

B5.2 Solvent Make-up Pump CC CC CC

B5.3 Solvent Sump Pump CC CC CC

B5.4 Solvent Sump CC CC CC

B5.5 Solvent Storage Tank CC CC CC

B5.6 Solvent Make-up Pump Suction Heater CC CC CC

B6.0 CO2 DEPRESSURIZATION AND VENTING EQUIPMENT SYSTEM CC CC CC

B6.1 CO2 Depressurization Heater CC CC CC

B7.0 COOLING WATER SYSTEM CC CC CC

B7.1 Wet Surface Air Cooler CC CC CC Cooling for Product Compressor moto

plant water system 

INTERCONNECTING PIPING / DUCTING SYSTEMS - ABOVE GROUND

Systems include coatings, insupports, etc as required for 

C1.0 FLUE GAS DUCTINGC1.1 All ductwork between DCC, Blower and CC Absorber CC CC CC Including expansion joints
Carbon Capture Plant

Contract: A4KC

Reference 

No. Description Supply Erect / Install Startup & Commissioning Comments

DIVISION OF RESPONSIBILITY MATRIX

For the purpose of summarizing what is included in the CC Plant EPCC price

C2.0 EXCESS DCC WATER SYSTEMC2.1 Excess DCC water system CC CC CC

C3.0 HIGH PURITY WATER SYSTEM Demineralized water quality

C3.1 System ISBL CC CC CCC4.0 LOW PRESSURE STEAM SUPPLY

C4.1 Low pressure steam system CC CC CCC5.0 PC CONDENSATE HEATING SYSTEMC5.1 Supply system CC CC CC

C5.2 Return system CC CC CC

C6.0 CARBON CAPTURE CONDENSATE RETURN SYSTEM

C6.1 Condensate return system CC CC CC

C7.0 PLANT AIR

C7.1 Plant air distribution system CC CC CC Air compressors are located in OSBL 

C.72 Instrument Air system CC CC CC Air compressors are located in OSBL 

C8.0 SCRUBBING SOLUTION BLOWDOWN

C8.1 Scrubbing solution blowdown system CC CC CCC9.0 COOLING WATER MAKE-UPC9.1 Cooling water make-up system CC CC CC

C10.0 POTABLE WATER SYSTEM

C10.1 Potable water distribution system CC CC CC

C10.2 Safety Showers / Eyewash Stations CC CC CC

C11.0 SERVICE WATER SYSTEM

C11.1 Service water distribution system CC CC CCC11.2 Hose stations within CC BL CC CC CC

C12.0 HYDROGEN SYSTEMC12.1 Hydrogen lines ISBL CC CC CC

C13.0 COMPRESSED CO2 PRODUCT

C13.1 Piping from CO2 Compressor to isolation valve at battery limit CC CC CCC13.2 CO2 pipeline metering system TENASKA TENASKA TENASKA Location TBDC13.3 CO2 pipeline system TENASKA TENASKA TENASKA Location TBD

INTERCONNECTING PIPING / DUCTING SYSTEMS - UNDERGROUND

Systems include coatings, insupports, etc as required for 

D1.0 FIRE WATERD1.1 Fire Water U/G Piping PC PC PC Perimeter loop + branch lines to IBL d

D1.2 Hydrants/ Monitors / PIV PC PC PC Located on perimeter loop

D1.3 Deluge Systems (for lube oil skid, oil transformers, etc.) CC CC CC

D1.4 Hose Stations and Hose Boxes ISBL CC CC CC

D2.0 SOLVENT RECOVERY DRAIN SYSTEM System is for solvent only, no other ch

D2.1 Curbing and drain hub, normally closed valve CC CC CCD2.2 U/G piping CC CC CCD2.3 Sump, sump pumping and above ground storage CC CC CCD3.0 PROCESS WATER DRAIN SYSTEMD3.1 Curbing and drain hub, normally closed valve CC CC CCD3.2 U/G piping to offsite location PC PC PCD4.0 ACCIDENTALLY OILY CONTAMINATED WATER SYSTEMD4.1 Curbing and drain hub, normally closed valve CC CC CCD4.2 U/G piping to offsite location PC PC PCD5.0 WASTE WATER DRAIN SYSTEM

D5.1 Curbing and drain hub, normally closed valve CC CC CC

D5.2 U/G piping to offsite location PC PC PC

D6.0 STORM WATER SYSTEM See also Civil section

D6.1 Curbing and drain hub, normally closed valve CC CC CC 
Carbon Capture Plant

Contract: A4KC

Reference 

No. Description Supply Erect / Install Startup & Commissioning Comments

DIVISION OF RESPONSIBILITY MATRIX

For the purpose of summarizing what is included in the CC Plant EPCC price

D6.2 Catch Basins PC PC PC

D6.3 Underground Storm water drain system, including analyzer (if required) to offsite location PC PC PC

ELECTRICAL

E1.0 345kV power line to auxiliary transformers located at the CC plant PC PC PC

E2.0 Power Distribution Centers (PDC), including transformers, switchgear CC CC CC Pre-fabricated buildings to house elec

E3.0 Electrical power distribution system ISBL CC CC CC BL is the high voltage terminals of the 

E4.0 Lighting, trays, and raceways CC CC CCE5.0 Underground Grounding and Lightning Protection PC PC PC

E6.0 Cathodic Protection PC PC PC Pending geotechnical report 

E7.0 Heat Tracing CC CC CC This will be executed as part of an ove

estimate will include a ROM for the he

E8.0 DC/UPS equipment PC PC PC Battery, battery charger, Inverter, swit

E9.0 DC/UPS distribution CC CC CC In the CC scope, 120 V UPS distributi

and erected by the CC.

COMMUNICATIONS

F1.0 IT/Telecommunications Equipment TENASKA TENASKA TENASKA

F2.0 IT/Telecommunications Infrastructure (wiring/fiber/testing) TENASKA TENASKA TENASKA

F3.0 Site Security System PC PC PC

F4.0 Fiber Optic, and associated terminations PC PC PC FO terminations will be a subcontract

CONTROL SYSTEMS 

G1.0 Rotating equipment Programmable Logic Controllers CC CC CC Included with equipment orders

G2.0 Field Instruments and devices CC CC CC

G3.0 Cabling from field instruments to PDC marshalling cabinets CC CC CC Need to confirm with Ali (currently in E

G4.0 PDC marshalling panels and terminations PC PC PC

G5.0 Analyzer shelter sampling system CC CC CC

G6.0 Fire and Gas Detection System CC CC CC Field devices + interconnecting cablin

COMMISSIONING & STARTUP

H1.0 First fill of CC solvents and CC reagents. CC CC CC

H2.0 First fill other CC plant Chemicals CC CC CC

H3.0H4.0 Construction consumables for CC plant thru successful performance test/ acceptance CC CC CCH5.0 Start-up utilities (fuel, power, water, chemicals) TENASKA TENASKA TENASKA

H6.0 Startup Spare Parts (CC Scope) CC CC CC

OWNER COSTS

J1.0 Permanent office and laboratory equipment TENASKA TENASKA n/a Included in PC scope and plot area

J2.0 Permanent warehouse and warehouse equipment TENASKA TENASKA n/a Included in PC scope and plot area

J3.0 Maintenance equipment and tools TENASKA TENASKA n/a Included in PC scope and plot area

SCOPE OF SERVICES

(DELETED)
Carbon Capture Plant

Contract: A4KC

Reference 

No. Description Supply Erect / Install Startup & Commissioning Comments

DIVISION OF RESPONSIBILITY MATRIX

For the purpose of summarizing what is included in the CC Plant EPCC price

INDIRECT COSTS

K1.0 TEMPORARY FACILITIES

K1.1 Temporary Buildings PC n/a n/a Includes staff and subcontract mobile 

K1.2 Temporary Man-Camp n/a n/a n/a

K1.3 Site trailer office space for Tenaska personnel PC n/a n/a

K1.4 Material Laydown Facilities PC n/a n/a

K1.5 Temporary Power PC PC PC

K1.6 Temporary Water TENASKA TENASKA TENASKA 

K1.7 Roadways and parking PC n/a n/a

K1.8 Weather Protection PC n/a n/a

K1.9 Sanitary facilities PC PC PC

K1.10 Construction consumables PC PC PC

K2.0 CONSTRUCTION SERVICES

K2.1 Overall Site Security CC n/a n/a Portion associated with CC TBDK2.2 Site & office clean-up, rubbish disposal CC n/a n/a Portion associated with CC TBD

K2.3 Warehousing labor CC n/a n/a Portion associated with CC TBD

K2.4 Safety Training CC n/a n/a Portion associated with CC TBD

K2.5 Certifications, drug testing CC n/a n/a Portion associated with CC TBD

K2.6 Computers & servers CC n/a n/a Portion associated with CC TBD

K2.7 Office furniture CC n/a n/a Portion associated with CC TBD

K2.8 Site transportation Service (craft bussing) n/a n/a n/a

K2.9 Photocopiers PC n/a n/a

K3.0 CONSTRUCTION MANAGEMENT FIELD STAFF

K3.1 CM Staffing Costs & Perdiems CC n/a n/a

Portion associated with CC; of 56 totaassigned to CC construction. IncludesQuality Control, material managemen

K4.0 CRAFT BENEFITS & BURDENS

K4.1 Craft Benefits, burdens, incentive payments See Note See Note See Note Included in craft wage rate build-up

K5.0 CONSTRUCTION EQUIPMENT, SMALL TOOLS & HEAVY HAUL/LIFT

K5.1 Small tools CC CC CC Included in craft wage rate build-up

K5.2 Rental Equipment CC CC CC Portion associated with CC

E5.3 Heavy Haul/ Lift Euipment CC n/a n/a Portion associated with CC

K6.0 MISCELLANEOUS COSTS

K6.1 Import duties and surcharge TENASKA n/a n/a

K6.2 Sales Tax TENASKA TENASKA TENASKA

K6.3 Marine cargo insurance TENASKA n/a n/a

K6.4 Owner’s auditing/inspection/witness test TENASKA TENASKA TENASKA

K6.5 Permits- environmental, operating TENASKA TENASKA TENASKA

K6.6 Permits- building, construction CC n/a n/a

K6.7 Process Simulator n/a n/a n/a Requirement TBD

K6.8 All-Risk insurance TENASKA TENASKA TENASKA

K6.9 General liability, automobile, worker comp insurance CC CC CC

K6.10 Contaminated and hazardous material handling and/or disposal, including asbestos, lead, soils, and process fluids TENASKA TENASKA TENASKAK6.11 Operating Spare Parts TENASKA TENASKA TENASKA Based on list provided by Fluor

K7.0 COMMISSIONING & STARTUP Also see column "Startup & Comm

K7.1 Commissioning and Startup Management CC CC CC Interface with PC Commissioning and K7.2 Commissioning and Startup Craft CC CC CC

K7.3 Commissioning and Startup Operator Support TENASKA TENASKA TENASKA

K7.4 Operation thru successful Performance Test CC CC CC

K7.5 Vendor Field Representatives CC CC CC
ATTACHMENT 3 

FEED Study Schedule 
Tenaska Trailblazer 

CO2 Capture FEED Study

Milestone Summary Schedule

Month No. 1 2 3 4 5 6 7 8 

Calendar Month Aug Sep Oct Nov Dec Jan Feb Mar 

Summary MilestonesStart of FEEDKickoff MeetingOwner ExtensionIssue Design BasisIssue P&IDs - IFAIssue Plot Plan - IFAHAZOPIssue P&IDs - IFDMTOs to EstimatingEquip Pricing to Est'gIssue Final ReportPresentation
ATTACHMENT 4 

EPCC Schedule 
EPC Schedule

YEAR 1 - 2012 YEAR 2 - 2013 YEAR 3 - 2014 YEAR 4 - 2015 

Milestones

FNTP

Engineering

START PILING

MODEL REVIEW #1 MODEL REVIEW #2

CC ABOVEGROUNDMOBILIZATION

STACK SHELL ERECTIONCOMPLETE (PC)

PC MECH COMPLETION

PC UTILITIES ONLINE

Procurement

MAJOR EQPT POs EQPT VENDOR DATA

ELECT & INSTR VENDOR DATA

MAJOR EQPT DELIVERIES

Construction

Commissioning & Start-up

COMPANY CONFIDENTIAL
ATTACHMENT 5 

3D Model Shots 

ATTACHMENT 6 

AACE Cost Estimate 

Standards 
Copyrighted page(s) removed. Copyrighted 

material is not available in Regulations.gov since 

it may not be reproduced without consent of the 

copyright holder. 

Removed pages can be viewed at the USEPA 

Docket Center, Public Reading Room. 

Address: 1301 Constitution Ave, NW 

Room 3334 

Washington, DC 20004 

Telephone: 202-566-1744 

Email: docket-customerservice@epa.gov