National Renewable Energy Laboratory 

Innovation for Our Energy Future 

A national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

NREL is operated by Midwest Research Institute ● Battelle Contract No. DE-AC36-99-GO10337 

Equipment Design and Cost 

Estimation for Small Modular 

Biomass Systems, Synthesis 

Gas Cleanup, and Oxygen 

Separation Equipment 

Task 2: Gas Cleanup Design and Cost 

Estimates – Wood Feedstock 

Nexant Inc. 

San Francisco, California 

Subcontract Report 

NREL/SR-510-39945 

May 2006 
Equipment Design and Cost 

Estimation for Small Modular 

Biomass Systems, Synthesis 

Gas Cleanup, and Oxygen 

Separation Equipment 

Task 2: Gas Cleanup Design and Cost 

Estimates – Wood Feedstock 

Nexant Inc. 

San Francisco, California 

NREL Technical Monitor: Kelly Ibsen 

Prepared under Subcontract No. ACO-5-44027 

Subcontract Report 

NREL/SR-510-39945 

May 2006 

National Renewable Energy Laboratory 

1617 Cole Boulevard, Golden, Colorado 80401-3393 

303-275-3000 • www.nrel.gov 

Operated for the U.S. Department of Energy 

Office of Energy Efficiency and Renewable Energy 

by Midwest Research Institute • Battelle 

Contract No. DE-AC36-99-GO10337
This publication was reproduced from the best available copy 

Submitted by the subcontractor and received no editorial review at NREL

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Contents 

Sections Page 

Executive Summary................................................................................................................ ES-1 

Introduction and Methodology.................................................................................................... 1 

Section 1 Process Selection Rationale................................................................................... 1-1 

1.1 Introduction.................................................................................................................. 1-1 

1.2 Process Description and Rationale............................................................................... 1-2 

1.2.1 Low-Pressure Syngas Process Description.......................................................... 1-3 

1.2.2 High-Pressure Syngas Process Description ......................................................... 1-5 

1.3 Discussion.................................................................................................................... 1-6 

1.3.1 Technologies Not Chosen.................................................................................... 1-6 

Section 2 Equipment Design and Cost Estimates................................................................ 2-1 

2.1 Introduction and Methodology .................................................................................... 2-1 

2.2 Key Design Assumptions............................................................................................. 2-2 

2.2.1 Sulfur and CO2 Removal ..................................................................................... 2-2 

2.2.2 Tar Reforming...................................................................................................... 2-2 

2.2.3 Cyclones............................................................................................................... 2-3 

2.2.4 Heat Integration ................................................................................................... 2-3 

2.2.5 Methanol Compressor.......................................................................................... 2-3 

2.3 Operating Costs and Utility Requirements.................................................................. 2-3 

2.4 Differences with NREL Biomass to Hydrogen Design ............................................... 2-6 

2.4.1 Added Equipment to Chemicals Design.............................................................. 2-6 

2.4.2 Increase in Steel Price.......................................................................................... 2-7 

2.4.3 Engineering Assumptions.................................................................................... 2-7 

2.5 Changing Flows, Conditions, and Compositions......................................................... 2-9 

2.5.1 Flowrate Impacts.................................................................................................. 2-9 

2.5.2 Composition Impacts......................................................................................... 2-12 

2.6 Follow-Up and Areas for Further Study .................................................................... 2-12 

Section 3 Labor Requirements.............................................................................................. 3-1 

3.1 Summary...................................................................................................................... 3-1 

3.2 Labor Requirements..................................................................................................... 3-1 

3.3 Differences with Emery Energy 70 MWe Case........................................................... 3-4 

3.4 Differences with NREL Biomass to Hydrogen Case................................................... 3-4 
Contents 

Sections Page 

Appendix A High-Pressure Syngas Design Case PFDs................................................... A-1 

Appendix B Low-Pressure Syngas Design Case PFDs.................................................... B-1 

Appendix C Equipment Lists and Data Sheets................................................................ C-1 

Appendix D Gas Cleanup Technologies Evaluated......................................................... D-1 

D.1 Introduction................................................................................................................. D-1 

D.2 Particulate Removal Technologies ............................................................................. D-1 

D.3 Tar Removal Technologies......................................................................................... D-5 

D.4 Acid Gas Removal Technologies................................................................................ D-7 

D.5 Ammonia, Alkali, and Other Contaminants ............................................................. D-13 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock ii 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Contents 

Tables and Figures 

Table A Syngas Clean-Up Case Summary .............................................................................. ES-2 

Table 1-1 Syngas Compositions and Operating Parameters....................................................... 1-1 

Table 1-2 Gas Cleanup Requirements ........................................................................................ 1-2 

Figure 1-1 General Syngas Clean-Up Process Flow................................................................... 1-2 

Table 1-3 Tar Reformer Performance......................................................................................... 1-3 

Table 2-1 Catalyst and Chemical Requirements......................................................................... 2-4 

Table 2-2 High-Pressure Case Utility Requirements.................................................................. 2-5 

Table 2-3 Low-Pressure Case Utility Requirements .................................................................. 2-5 

Table 2-4 Examples of Typical Exponents for Equipment Cost Versus Capacity..................2-11 

Table 3-1 Labor Costs................................................................................................................. 3-3 

Figure D-1 Principle of Barrier Filters....................................................................................... D-2 

Table D-1 Comparison of Syngas Reforming Process Technology .......................................... D-7 

Figure D-2 Typical Amine System Flow Diagram.................................................................... D-8 

Figure D-3 Typical Physical Solvent System Flow Diagram.................................................. D-10 

Figure D-4 Typical LO-CATTM System Flow Diagram.......................................................... D-11 

Figure D-5 Traditional ZnO Purification System.................................................................... D-12 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock iii 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Executive Summary 

As part of Task 2, Gas Cleanup and Cost Estimates, the team investigated the appropriate 

process scheme for treatment of wood derived syngas for use in the synthesis of liquid fuels. 

Two different 2,000 metric tonne per day gasification schemes, a low-pressure, indirect system 

using the BCL gasifier, and a high-pressure, direct system using GTI gasification technology, 

were evaluated. Initial syngas conditions from each of the gasifiers was provided to the team by 

NREL. Nexant was the prime contractor and principal investigator during this task; technical 

assistance was provided by both GTI and Emery Energy. 

The first task explored the different process options available for the removal of the main process 

impurities, including particulates, sulfur, carbon dioxide, tar, ammonia, and metals. From this 

list, selection of commercial technologies appropriate for syngas clean-up was made based on the 

criteria of cost and the ability to meet the final specifications. Preliminary flow schemes were 

established and presented to NREL; after discussion and modification, final designs, including 

unit sizes, energy use, capital and operating costs, and labor requirements, were developed. 

Finally, Nexant performed an analysis to determine how changes in syngas flowrates and 

compositions would impact the designs, for future reference as the plant size changes. 

The technologies chosen for both cases did not differ considerably. Each case possesses the 

following pieces of equipment: 

 Cyclones for particulate removal 

 Tar cracking for the removal of heavy and light hydrocarbons. Steam is injected in 

varying amounts into the tar cracker to set the appropriate hydrogen to carbon 

monoxide ratio. 

 Syngas cooling, necessary for downstream sulfur treatment, and a water 

quench/venturi scrubber for ammonia and trace contaminant removal 

 Amine treatment for sulfur and carbon dioxide removal 

 Zinc oxide beds for additional sulfur removal down to the low levels required for 

fuels synthesis 

 Liquid phase oxidation of acid gas for sulfur recovery 

The low-pressure gasifier case required the use of a process gas compressor to raise the gas 

pressure to the level appropriate for downstream treatment and product synthesis. Information 

was also provided for the level of clean syngas compression necessary to prepare both cases for 

methanol synthesis. 

The results of the analysis for both cases can be seen in Table A below, with information on the 

capital and operating costs: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock ES-1 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Executive Summary 

TABLE A SYNGAS CLEAN-UP CASE SUMMARY 

Low-Pressure 

BCL Gasifier 

High-Pressure 

GTI Gasifier 

Wood Feedrate (MTPD) 2,000 2,000 

Syngas Rate (lb/hr) 316,369 418,416 

Total Installed Cost ($MM) 109.4 76.5 

Power Required (MW) 18.5 (5.2) 

Net Steam Required (lb/hr) 44,000 114,000 

Water Required (GPM) 37,806 25,454 

Natural Gas (MMSCFD) 7 8 

Catalysts and Chemicals ($/day) 1,931 1,457 

The bulk of the cost difference between the two cases is due to the process gas compressor 

required in the low-pressure case. The two cases use similar equipment for all other steps of the 

process; although the cases had different gas flowrates and compositions, the equipment impact 

is small relative to that of the process gas compressor. While these results imply that direct 

gasification is preferred, this study did not take into account other differences in the two process 

schemes, such as the potential need for an oxygen plant in the high-pressure to chemicals case. 

The team also compared the clean-up system design and costs versus the design developed by 

NREL for a recent biomass to hydrogen study. The cost for the clean-up section of the biomass 

to chemicals designs is more expensive due to three main reasons: more equipment necessary in 

the chemical production designs, the increase in steel prices from 2002 to 2005, and different 

engineering assumptions made in the chemicals production case. The main engineering 

difference is the cost assumed for the process gas compressor in the low pressure case; a larger 

compressor and selection of a different design type increases the installed cost by $25MM versus 

the NREL design. In addition, gas clean-up cost assumptions made by NREL from previous 

studies likely underestimated the cost of the tar cracker and heat exchange equipment. 

This study updates previous NREL investigations by providing the most up-to-date information 

for appropriate technologies and their respective costs. Future studies should focus on the 

following areas to further define suitable technologies and confirm costs: 

 Alternatives for Tar Removal: Further study and analysis should be performed to 

validate the methods used by the team. In addition, alternative tar removal 

technology should be considered, including cracking within the gasifier. 

 Process Integration, Gasification Systems and Biorefinery: Integration of the cleanup section with the other parts of the gasification plant will provide a better picture of 

the overall plant costs. 

 Alternate CO2/Sulfur Removal Steps: A cost comparison of amine versus physical 

solvents would provide additional data to confirm the appropriate use of amine in this 

design Advanced technologies for acid gas removal, such as warm gas clean-up, 

should also be considered. 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock ES-2 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Executive Summary 

 Other Impurities in the Syngas: If it is deemed that the level of items such as metals 

and halides entering the scrubber will not adversely impact the FT or methanol 

catalysts, this step could be removed. 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock ES-3 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Introduction and Methodology 

This study provides designs and costs for cleaning wood derived syngas in preparation for feed 

to liquid fuel synthesis units. Two different starting conditions, one with syngas derived from a 

low-pressure, indirect gasifier, and one from a high-pressure, direct gasifier, were evaluated. 

The goal was to provide NREL with a complete design package, including process flow 

diagrams, equipment specification sheets, mass and energy balances, capital and operating costs, 

and labor requirements, that can be used to evaluate the feasibility of biomass to chemicals 

technologies. The study also addressed how the designs would be impacted by changing 

flowrates and syngas compositions, so that the designs could be adapted to other process 

conditions. 

The work was divided into three main task areas. The first Subtask (2.1) presented a list of 

possible gas clean-up technologies, with recommendations provided for the most suitable ones 

for additional analysis. The results of this study can be seen in Appendix D. Next, preliminary 

process flow diagrams were developed, along with an initial material balance (Subtasks 2.2.1 and 

2.2.2). This was reviewed with NREL, and modifications made before the final design work 

began. The final phase consisted of performing equipment sizing, development of costs, and 

scaling analysis (Subtasks 2.2.3 through 2.2.7). 

A variety of resources were used throughout the project to produce the final designs. In 

gathering the initial technology data, previous team studies, literature reviews, vendor 

information, and NREL input were all used to establish the items for consideration. Vendors and 

R&D facilities were especially helpful in providing data for novel technologies, such as tar 

cracking and liquid phase sulfur oxidation. Team members involved in biomass gasification, 

GTI and Emery Energy, provided valuable insight on reliability and feasibility issues. 

HYSYS was used for modeling the overall process, with vendor input for specialty equipment. 

Design and performance of the amine system, LO-CATTM unit, tar cracker, and process gas 

compressor were provided by vendors and estimated through other modeling work. All other 

process equipment was sized by the HYSYS program. Since the basis for the tar cracker, the 

NREL TCPDU, is not commercial, data from NREL was used, along with assumptions for bed 

fluidization needs and heat transfer requirements to produce a size estimate. Greater detail for 

the assumptions made can be found in Section 2. 

Costing was performed in a similar fashion as design, with commercially available software, 

ICARUS, used for much of the equipment sized using HYSYS. All cost estimates use a second 

quarter 2005 basis. Quotes were obtained from vendors for unique and capitally intensive items, 

such as the process gas compressor, cyclones, ZnO beds, and LO-CATTM unit. Industry derived 

cost curves were used for the amine system and as a check on other process items. Operating 

costs were developed from vendor supplied information and the energy balance. Finally, labor 

requirements are derived from a scale-up of a detailed study by Emery Energy specific to 

biomass gasification. For all results, comparisons were made throughout the study to results 

from previously developed NREL reports. 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 1 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Section 1 Process Selection Rationale 

1.1 INTRODUCTION 

The initial task for the Nexant team was to identify and evaluate all commercially available 

technology for clean-up of wood derived syngas. The technology list, with information on 

operating size ranges and conditions, materials of construction, and cleanup parameters, can be 

seen in Appendix D. After a review of technology options with NREL, flow schemes were 

developed for both the high and low pressure cases. The result of this analysis and justification 

for the technologies chosen is detailed in this section. 

The compositions of the syngas from the gasifiers and the cleanup requirements are listed in 

Tables 1-1 and 1-2 below1

. Each case being evaluated assumed a wood feedrate of 2,000 metric 

tonnes per day (MTPD). 

TABLE 1-1 SYNGAS COMPOSITIONS AND OPERATING PARAMETERS 

Syngas from 

BCL Gasifier 

Syngas from 

GTI Gasifier 

Temperature, °F 1,598°F (870°C) 1,598°F (870°C) 

Pressure 33 psia (1.6 bar) 460 psia (32 bar) 

Steam/bone dry feed 0.4 lb/lb 0.76 kg/kg 

Compositions Mol% (wet) Mol% (wet) 

 H2 12.91 13.10 

 CO2 6.93 19.40 

 CO 22.84 8.10 

 H2O 45.87 50.70 

 CH4 8.32 7.80 

 C2H2 0.22 --- 

 C2H4 2.35 0.10 

 C2H6 0.16 0.20 

 C6H6 0.07 0.30 

 Tar (C10H8) 0.13 0.10 

 NH3 0.18 0.10 

 H2S 0.04 0.04 

Gas Yield 0.04 lbmol of dry gas/lb bone dry feed 0.05 lbmol of dry gas/lb bone dry feed 

Char Yield 0.22 lb/lb bone dry feed 0.0514 lb/lb bone dry feed 

H2:CO molar ratio 0.57 1.62 

 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 1-1 

1 Information provided by Pamela Spath, NREL. 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Section 1 Process Selection Rationale 

The gas pressure assumed from the BCL gasifier, 33 psia, is higher than initially evaluated 

during this project. Preliminary investigations were performed using a syngas pressure of 23 

psia. Raising the pressure by 10 psia allows for a simpler and more reliable design, by allowing 

a water wash upstream of the compression stage. 

TABLE 1-2 GAS CLEANUP REQUIREMENTS 

Process Contaminants Level Source/Comment 

Sulfur 0.2 ppm 

1 ppmv 

60 ppb 

Dry, 1981 

Boerrigter, et al, 2002 

Turk, et al, 2001 

Fischer-Tropsch Synthesis Halides 10 ppb Boerrigter, et al, 2002 

Nitrogen 10 ppmv NH3 

0.2 ppmv NOx 

10 ppb HCN 

Turk, et al, 2001 

Sulfur (not COS) <0.5 ppmv 

(<0.1 ppmv preferred) 

Kung, 1992 

Halides 0.001 ppmv Twigg and Spencer 2001 Methanol Synthesis 

Fe and Ni 0.005 ppmv Kung, 1992 

The main impurities in the syngas exiting the gasifier that must be removed are char, tars, 

hydrocarbons, sulfur, and CO2. In addition, trace contaminants such as ammonia, metals, 

halides, and alkali species were of sufficient concern that equipment was added to remove them 

as well. Finally, the syngas must also be adjusted to obtain the appropriate H2/CO ratio. 

1.2 PROCESS DESCRIPTION AND RATIONALE 

A schematic for the process design developed for both cases can be seen in Figure 1-1. Both the 

low and high pressure cases used very similar processes for syngas clean-up: particulate removal 

with cyclones, tar reforming, cooling and water scrubbing, acid gas removal with amine, and 

sulfur polishing. The main difference between the cases is the inclusion of a compression step in 

the low-pressure case. A detailed description of each design is addressed in this section. 

FIGURE 1-1 GENERAL SYNGAS CLEAN-UP PROCESS FLOW 

Cyclones Raw 

Syngas

Scrubber Tar 

Reformer

Syngas

Cooling

Water

LO-CAT

Sulfur

Amine

CO2

ZnO Bed

For low pressure 

cases only Water

Steam for Power

Syngas 

Compression

Particulate 

Removal

Gas 

Conditioning

Char to 

Combustor

To Treatment

Impurity 

Removal

Compressor

Acid Gas 

Removal

Clean 

Syngas

Guard Bed 

Preheater

Sulfur 

Guard Bed

Steam

Acid 

Gas

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 1-2 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Section 1 Process Selection Rationale 

1.2.1 Low-Pressure Syngas Process Description 

Particulate Removal 

The syngas exiting the gasifier contains impurities that must be removed in order to meet the 

specifications required for methanol or FT synthesis. Cyclones are used as the initial step in the 

gas cleanup process to remove the bulk of the char entrained in the syngas stream. This 

technology is standard in industry due to its low cost and high level of performance for removing 

particulates. Syngas from the low-pressure gasifier is sent through four parallel cyclones 

operating at 1598°F and 33 psia. 

Tar Reforming 

Syngas is fed to a tar reformer to remove tars, light hydrocarbons, and ammonia before any 

additional gas treating or cooling. Reforming must occur prior to cooling the syngas to prevent 

tar condensation and deposition on downstream equipment. The tar reformer was modeled using 

NREL’s “goal design” reactor conversion for the Thermochemical Pilot Development Unit 

(TCPDU). Table 1-3 shows the assumed reactor conversion rate as provided by NREL. In the 

tar reformer, tars (mono and polyaromatic compounds) and light hydrocarbons such as methane, 

ethylene, and ethane are converted to H2 and CO. Ammonia is converted to N2 and H2. Since 

the reactor effluent contains about 1.3 mol% CH4, and 0.2 mol% of other hydrocarbons, 

additional downstream steam reforming was deemed not necessary. This conclusion was 

confirmed by NREL2. 

TABLE 1-3 TAR REFORMER PERFORMANCE 

Compound % Conversion 

Methane (CH4) 80 

Ethane (C2H6) 99 

Ethylene (C2H4) 90 

Tars (C10+) 99.9 

Benzene (C6H6) 99 

Ammonia (NH3) 90 

Syngas exiting the tar reformer enters another cyclone to separate both entrained reforming 

catalyst and any residual char. The solids are then sent to a catalyst regenerator. The catalyst is 

sent to a regenerator vessel, where char and residual carbon is combusted. The hot, regenerated 

catalyst is then recycled back to the reactor vessel, acting as the heat source for the reforming 

reactions. 

Syngas Cooling 

The remaining gas treatment steps require the syngas to be at a much lower temperature. 

Therefore, the gas is cooled in three stages from 1598°F to 225°F prior to scrubbing. The heat 

 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 1-3 

2 Nexant team discussion with Pamela Spath, April 2005. 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Section 1 Process Selection Rationale 

recovered from the process is used for steam generation throughout the system. The process 

design has been optimized as much as possible to use this steam, reducing the plant utility load. 

Integration was limited to the needs of the clean-up section; broader heat integration with the 

overall thermochemical platform or biomass refinery may lead to additional efficiency gains. 

Scrubbing and Quench 

The syngas is sent to the Syngas Venturi Scrubber, C-200, to remove any remaining ammonia, 

particulates, metals, halides, or alkali remaining in the system. The water circulation rate to the 

scrubber is adjusted such that the exiting syngas is quenched to the appropriate temperature for 

feed to the first stage of the compressor. 

Compression 

Any residual condensate in the syngas exiting the scrubber is removed in the Syngas Compressor 

KO Drum, V-300. The cooled syngas stream is compressed to 445 psia using a 4-stage 

centrifugal compressor with interstage cooling. The compressor is modeled assuming a 

horizontally split centrifugal design, with a polytropic efficiency of 78% and 110°F intercoolers. 

After discussion with compressor vendors3

 and internal analysis by Nexant, it was determined 

that this type of compressor is appropriate for this gas flowrate, pressure ratio, and reliability 

requirements. While an integrally geared compressor was considered due to its lower cost, this 

type of compressor was not recommended due to the high flowrate and reliability required. The 

discharge pressure is designed such that the compressed gas is at the operating pressure range for 

FT synthesis. 

Sulfur Removal 

Originally, the scheme developed was use of LO-CATTM and ZnO polishing for H2S removal, 

followed by amine for CO2 removal. After discussions with NREL, this was modified so that 

amine was used for both H2S and CO2 removal. The ZnO beds remained in the design as a 

guard/polishing step after the amine unit, while the LO-CATTM unit is now used to remove H2S 

from the acid gas stream. The benefit of this design is reduced load on both the LO-CATTM and 

ZnO units; the flow going to the LO-CATTM unit in this case is now only the acid gas stream 

instead of the entire syngas stream, and the inlet H2S concentration at the ZnO bed is expected to 

be lower. This should increase the lifespan of the ZnO catalyst. 

The syngas exiting the gasifier contains ~400 ppmv of H2S. An amine unit with a high 

circulation rate can reduce the syngas sulfur concentration to below 10 ppmv, with a target of 2-3 

ppmv. Due to the high amount of CO2 removal required, it is this component that drives the 

circulation rate and unit size, not H2S. The ZnO beds are used as a polishing step to reduce the 

sulfur concentration to the < 0.1 ppmv level required for methanol and FT synthesis. The gas 

exiting the amine absorber is heated to the operating temperature of the ZnO beds, 750°F. 

For the low-pressure case, DEA was selected, while MDEA is used for the high-pressure case. 

This selection is based on design simulation runs by matching the desired CO2 and H2S removal 

 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 1-4 

3 Consultation made with both Elliott Compressor and GE. 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Section 1 Process Selection Rationale 

requirements to the selectivity of the amine solvents. Attempts were also made to choose 

solvents that minimized net energy requirements. 

Water-Gas Shift and CO2 Removal 

FT synthesis requires a H2/CO ratio of 2:1, and methanol synthesis requires the following 

stoichiometric ratio of H2, CO, and CO2: 

 (H2 – CO2) / (CO + CO2) = 2 

The syngas stream exiting the ZnO beds has a H2/CO ratio of 1.7 and a stoichiometric ratio of 

0.89, which are inadequate for FT or methanol synthesis. A combination of water injection into 

the tar cracker, followed by CO2 removal in the amine unit, has been selected to adjust these 

ratios. In methanol synthesis, H2 will react preferentially with CO2 over CO to form methanol. 

This results in a significantly lowered methanol yield, greatly impacting the process efficiency. 

In FT synthesis, CO2 acts as a diluent; however, for a design in which the off-gas from the FT 

reactor is recycled back to the reactor to improve conversion, removal of CO2 is necessary to 

prevent CO2 buildup in the reactor. 

The initial designs for the low pressure system incorporated a shift reactor instead of water 

injection to assist in obtaining the necessary composition ratios. Further analysis and review 

with NREL led to the determination that a shift reactor was unnecessary, and that steam injection 

into the tar cracker is sufficient to perform the required shift. Elimination of this unit operation 

helps to reduce the overall system cost. 

CO2 removal can be achieved through different processes such as chemical (amine) or physical 

(Selexol or Rectisol) absorption, as outlined in Appendix D. The syngas stream entering the CO2

removal unit is at about 420 psia and 110°F. Since physical absorption process is best suited for 

high pressure (>700 psia) and low temperature systems, an amine system was selected to remove 

CO2 from the syngas. In addition to the syngas already possessing the appropriate operating 

conditions for chemical absorption, an amine system is also likely to be less expensive than the 

Selexol or Rectisol system. A side-by-side cost analysis from vendors would be necessary to 

confirm the optimal design. Approximately 98% of the CO2 in the syngas stream must be 

removed in order to meet the stoichiometric ratio requirement for methanol synthesis. 

The treated syngas exits the amine absorber at approximately 110°F and 440 psia. The treated 

syngas is sent to either the methanol or FT reactor. For methanol synthesis, the treated gas is 

compressed and heated to the operating conditions of the methanol reactor, about 1160 psia and 

460°F. For FT synthesis, the treated gas is heated to 350°F. 

1.2.2 High-Pressure Syngas Process Description 

The cleanup process scheme for the syngas from the high-pressure gasifier is similar to that of 

the syngas from the low-pressure gasifier with the exception of the syngas compression step, 

differences in the heat balances, and process unit size variations due to different syngas 

compositions and conditions. Information about these differences is presented below. 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 1-5 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Section 1 Process Selection Rationale 

Similar to the low-pressure case, high-pressure syngas is sent through a series of cyclones to 

remove the bulk of the char entrained in the syngas stream. The syngas is then sent to the tar 

reformer for removal of tars, methane, other light hydrocarbons, and ammonia. Steam is added 

to the syngas entering the tar reformer so that the shift reaction that occurs in the reformer can 

yield the required H2/CO ratio for methanol or FT synthesis. Due to a more appropriate 

synthesis ratio in the raw syngas stream, less steam is required relative to the low-pressure case. 

The reformer effluent is then sent to the water scrubbing unit for removal of residual char, alkali, 

metals, halides, and ammonia. 

Following the water scrubbing unit, the syngas is sent to an amine unit where MDEA is used for 

the removal of both H2S and CO2. As in the low-pressure case, a LO-CATTM unit is used for 

sulfur recovery, while ZnO beds are used for reducing the syngas sulfur content to below < 0.1 

ppmv H2S. Rationale for process selection of the sulfur and CO2 removal units is similar to that 

of the low-pressure syngas case, although MDEA was used instead of DEA in the amine system. 

The treated syngas is sent to either the methanol or FT reactor. For methanol synthesis, the 

treated gas requires compression and pre-heating to 1160 psia and 460°F prior to entering the 

methanol reactor. For FT synthesis, the treated gas requires pre-heating to 350°F. 

1.3 DISCUSSION 

1.3.1 Technologies Not Chosen 

As presented in Appendix D, a list of technologies was provided for performing the various gas 

cleanup tasks required. From this list, specific technologies have been selected for each of the 

designs presented here. Below is a list of the technologies that were not chosen, and the 

rationale behind those decisions. 

Particulate Removal 

Ceramic and Metal Candle Filters: Candle filters could be used in place of cyclones for char 

and catalyst separation from the syngas stream. Little commercial experience exists in operating 

these types of filters at the temperatures (1500°F+) that the cyclones operate under. At this 

temperature, only ceramic filters could be considered. A recent study performed by Nexant for 

the DOE’s National Energy Technology Laboratory4

 examined replacing a third stage cyclone 

with a ceramic candle filter. The cost of this high temperature filter, even assuming an “nth plant 

design”, did not justify the change. Because of the limited commercial experience and high cost, 

these options were eliminated. 

Baghouse Filters: As with candle filters, baghouse filters are not appropriate for high 

temperature applications. Therefore, they cannot replace the cyclones as an effective solids 

removal option. 

Electrostatic Precipitators: Since dry ESPs can only operate up to ~750°F and wet ESPs up to 

~200°F, this option cannot replace cyclones for solids removal. In addition, the high cost and 

waste streams produced make them unattractive relative to other filtration options. 

 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 1-6 

4 “Gasification Alternatives for Industrial Applications: Subtask 3.3—Alternate Design for the Eastern Coal Case, DOE Contract DE-AC26-

99FT40342, April 2005. 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Section 1 Process Selection Rationale 

Tar and Hydrocarbon Removal 

Wet Scrubbing: Due to the relatively low content of tar in the syngas stream and the non-power 

application being considered, wet scrubbing could be considered a viable option for tar removal. 

However, inclusion of a wet scrubber may make a steam reformer necessary to remove 

hydrocarbons from the system. In addition, wet scrubbing for tar removal creates considerable 

waste removal and treatment issues and lowers process efficiencies. A detailed analysis 

comparing the current configuration with a wet scrubber/steam reformer would be of interest to 

confirm these assumptions. 

Hydrocarbon Reforming (SMR/POx/ATR): Due to the low content of hydrocarbons exiting the 

tar cracker, it was determined that this step was unnecessary. Both FT and methanol synthesis 

reactors should be able to handle the quantity of hydrocarbons without severely impacting 

performance. 

Other Technologies: During the course of the design work for the current configuration, other 

alternatives, such as injection of cracking catalyst directly into the gasifier and changes in 

gasifier operation, were identified. Limited empirical data for these technology options make 

them impractical for design use at this time. 

Sulfur Removal 

LO-CAT TM

: The initial designs for sulfur removal from the syngas stream used the LO-CATTM

technology due to the low net syngas sulfur content. Redesigns of the combined sulfur and CO2

removal system demonstrated that using LO-CATTM for sulfur recovery and amine for sulfur and 

CO2 removal was more economic. 

Physical Solvents: As can be seen in Appendix D, physical solvents (Rectisol/Selexol 

processes, for example) typically operate at low temperatures and high pressures. Changes in the 

stream pressure leaving the scrubber/quench may be required prior to entering a physical solvent 

unit for optimum performance, whereas the current process conditions are more appropriate for 

feed to an amine system. In addition, previous Nexant studies have determined little to no cost 

benefit in implementing a physical solvent system over other treatment methods for systems of 

this nature. A more in-depth analysis would be required to confirm the cost difference between 

physical absorbents and an amine/ZnO treatment system. 

COS Hydrolysis: Due to the limited COS expected to be produced from a biomass gasification 

system, this removal step was omitted. 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 1-7 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Section 2 Equipment Design and Cost Estimates 

2.1 INTRODUCTION AND METHODOLOGY 

Design and cost estimates were obtained using three major sources: 

 HYSYS and ICARUS were used to obtain design and cost estimates for generic 

equipment such as vessels, pumps, compressors, and heat exchangers. The design 

basis was agreed upon after the submission of the design information outlined in 

Section 1. 

 Vendor quotes were obtained for unique and specialized equipment such as cyclones, 

ZnO catalyst/reactors, LO-CATTM sulfur absorption, and compressors. Some items, 

such as compressors and blowers, were estimated both by HYSYS/ICARUS and 

through vendor quotes in order to validate the results. 

 The amine unit performance and energy requirements were estimated using 

commercially available software that is specific for amine unit modeling. Once 

performance requirements were obtained, an industry developed cost curve was used 

for estimating installed cost. 

An updated set of PFDs can be seen in Appendices A and B. The design and cost estimates for 

the high-pressure and low-pressure cases are presented in the Equipment List and Data Sheets, 

which can be seen in Appendix C. The Equipment List groups process equipment by the 

following categories: reactors, cyclones, vessels, heat exchangers, compressors, pumps, turbines, 

and packaged units (the amine and LO-CATTM units). Shown in the Equipment List are the 

following items: 

 Unit size and weight 

 Design duty (exchangers) 

 Design temperature and pressure 

 Power usage 

 Materials of construction 

 Price (uninstalled) on both a Q2 2004 and Q2 2005 basis 

 Source for cost estimate 

 Comments and notes 

An installation factor of 2.57 was applied to all base equipment costs, with the exception of the 

process gas compressor, to arrive at the total installed cost. The installation factor was derived 

based upon previous experience and vendor estimates. An installation factor of 2.47 was used 

for the compressor based on previous detailed compressor cost analysis. The total installed cost 

for the low-pressure case is $109MM, while the installed cost for the high-pressure case is 

$76MM. The difference is largely due to the process gas compressor used in the low-pressure 

case. 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 2-1 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Section 2 Equipment Design and Cost Estimates 

2.2 KEY DESIGN ASSUMPTIONS 

A complete description of the process and rationale for choosing the technologies in this 

deliverable can be seen in Section 1. Each case assumed a feedrate of 2,000 MTPD. Issues 

encountered when performing the unit designs are outlined below. 

2.2.1 Sulfur and CO2 Removal 

As mentioned in Section 1, DEA was selected for the low-pressure case, while MDEA is used 

for the high-pressure case. This selection is based on design simulation runs by matching the 

desired CO2 and H2S removal requirements to the selectivity of the amine solvents. The level of 

CO2 removal is the major driving force in determining the amine system size and cost; without 

the need for CO2 removal, the unit cost decreases significantly. 

2.2.2 Tar Reforming 

Design and cost estimation of the tar reformer/regenerator presented a challenge to the team. 

Because no commercial data exists on design or cost for the performance outlined by the “goal” 

TCPDU case, a number of assumptions have been made: 

 Reaction temperatures equal to the inlet gas temperature (1598 and 1576°F). These 

temperatures are derived from conversations with NREL. Recent experimental 

studies at Iowa State University on catalytic tar destruction have demonstrated 

successful operation at ~1350 to 1550°F 5. Sensitivity cases were run at 1472 and 

1200°F; the results show that heat duty is strongly impacted by the reaction 

temperature. Since the catalyst is the heat carrier in the reaction, the reaction 

temperature will greatly impact natural gas use and catalyst circulation rates. 

Minimizing these factors will trade-off with catalyst activity as the reaction 

temperature is lowered. This may be an area for future optimization and testing at the 

TCPDU. 

 Low pressure operation for the regenerator to cut down on combustion air blower 

costs. This design is assuming the use of a pressurized rotary lock to increase recycle 

catalyst pressure. There is the risk that a rotary lock may be inadequate for this 

service due to the high catalyst circulation rates leading to premature erosion. If this 

is the case, either a lockhopper system or pressurized regenerator vessel would need 

to be included, significantly adding to the cost. 

 Catalyst recycle rate based entirely off of thermodynamic requirements. Because of 

the endothermic reforming reactions, the regenerated catalyst must carry the heat 

necessary to maintain reactor temperature. 

 Catalyst heat capacity of 0.25 Btu/lb/°F 

 Plug flow within the reactor, with a Gas Hour Space Velocity (GHSV) of 2000/hr, to 

establish the basis for the bed volume and catalyst inventory. The calculated cracker 

 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 2-2 

5 Zhang, R., Brown, R., Suby, A., Cummer, K., “Catalytic Destruction of Tar in Biomass Derived Producer Gas”, Energy Conversion and 

Management, Vol. 45, pp. 995-1014, 2004. 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Section 2 Equipment Design and Cost Estimates 

bed length was multiplied by a factor of four to account for deviations from ideal plug 

flow. 

 Bed diameter calculated by first estimating the minimum and maximum bed 

fluidization velocities, then an average of these estimates taken. Fluidization 

velocities calculated from catalyst and syngas properties. 

Both ASPEN and HYSYS were used to model these systems, with all necessary thermodynamic 

and kinetic assumptions included. The results from both simulations came out very close to one 

another with a very high heat duty (~150 to 170 MMBTU/hr) and catalyst circulation rate 

(~24,000 to 29,000 MTPD) in each case. While the cost of the actual vessels are not very high 

($1.3MM to $1.5MM), the catalyst load is substantial, and costs could be high based on what 

assumptions are made for catalyst losses and system maintenance requirements. Since the 

catalyst is regenerated in the process, minimizing losses is key to reducing operating costs. 

2.2.3 Cyclones 

A number of assumptions were made for the particle size distribution, efficiency, and outlet 

particle loading. Since no explicit direction was given by NREL, assumptions using 

experimental data from small-scale gasifiers was assumed and given to vendors for sizing (99%+ 

particulate removal and an average particle size of 50 μm). 

2.2.4 Heat Integration 

The process heating and cooling needs were evaluated and heat integration performed to 

maximize heat recovery. The process design includes a steam cycle that recovers the majority of 

the process heat by generating steam. For hot process streams that could not be integrated in the 

steam cycle, cooling water was used to provide cooling duty. A steam turbine is included in the 

design to generate power from the excess process steam. 

2.2.5 Methanol Compressor 

It was assumed that a clean syngas pressure of 1160 psia was required for methanol synthesis. 

Therefore, a compression system with interstage cooling has been included in the design. 

2.3 OPERATING COSTS AND UTILITY REQUIREMENTS 

Catalyst and chemical needs, along with utility requirements, can be seen in Tables 2-1 through 

2-3. The units with the highest operating cost are the amine system and the tar cracker. Steam 

cost contributes the largest cost component for the amine unit. A portion of the steam required 

for the amine unit is extracted from the steam turbine, and the remainder is assumed to be 

imported. About 44,000 lb/hr of steam is imported for the low-pressure case, and 113,500 lb/hr 

for the high-pressure case. Imports may be unnecessary if excess steam from elsewhere in the 

gasification unit is available. 

The other major source of operating cost is the catalyst requirement for the tar cracker. The tar 

cracker specifics were determined by estimating the minimum fluidization velocity, required 

space velocity, and the required heat duty demanded of the regenerated catalyst. The total 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 2-3 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Section 2 Equipment Design and Cost Estimates 

amount of catalyst is equal to the settled bed volume of the two fluidized beds, plus an additional 

10% for transfer line inventory. Due to the very high heat load and quantity of gas to be 

handled, the initial catalyst loading is substantial: ~300 tonnes in the HP case, and ~830 tonnes 

in the LP case. 

The remaining catalyst and chemicals cost are in-line with the assumptions made by NREL; in 

fact, some of the costs used by NREL in the biomass to hydrogen report are used here either for 

consistency, or because little other information exists. For example, it is unknown what the cost 

will be of tar cracker catalyst that can perform as expected in the NREL “goal” design. 

Nexant has not made assumptions for the total yearly operating cost at this time; this cost could 

vary considerably based on the assumptions made for plant performance and the assumptions for 

catalyst, chemicals, and power costs. An estimate for operating cost should be performed for an 

entire integrated gasification unit or biorefinery, instead of the clean-up unit as a stand-alone 

facility. Suggestions for proper estimation and reducing operating costs include: 

 An availability of 85 to 90% would be appropriate for this design 

 Both low and high pressure designs would likely require steam imports. This could 

come from purchases or excess steam production elsewhere in the gasification plant 

 A 0.01% per day catalyst loss in the tar cracker, as assumed by NREL in the “goal” 

hydrogen design, is appropriate for initial cyclone operation, but will likely degrade 

over time. Typical catalyst assumptions and make-up rates for similar technologies 

range from 0.01% to 0.1%. 

If a loss rate of 0.01% is assumed, and costs for the ZnO beds are amortized over the 

year, the daily catalyst and chemical cost is $1931/day for the low-pressure case, and 

$1457/day for the high pressure case. This takes into account tar cracker losses, ZnO 

bed replacement, and LO-CATTM requirements. This is shown in Table 2-1 below. 

TABLE 2-1 CATALYST AND CHEMICAL REQUIREMENTS 

Variable Amount Required Cost Notes 

Tar 

Reformer 

Catalyst 

Low- Pressure Case: 1,820,000 lbs 

High-Pressure Case: 662,000 lbs 

Price: $4.67/lb (NREL 

H2 Report) 

No commercial catalyst is currently 

available for this operation. Assuming a 

GHSV of 2000/hr, and a catalyst volume 

equal to the settled bed volume of the two 

fluidized beds plus 10% for transfer lines. 

ZnO 

Catalyst 

Low-Pressure Case: 777 cubic feet 

High-Pressure Case: 707 cubic feet 

Price: $355/cubic foot 

(Johnson Matthey). 

Initial fill then replaced every year. 

Catalyst inventory based on H2S removal 

capacity from 2 ppmv to 0.1 ppmv. 

Sulfur 

Recovery 

Chemicals 

Low-Pressure Case: 1.7 

Tonnes/Day of Sulfur Removal 

High-Pressure Case: 2.4 

Tonnes/Day of Sulfur Removal 

Price: $191/tonne 

sulfur removed (GTP 

Quote) 

 

Assumes price for all LO-CATTM chemicals 

required. Does not include utility 

requirements. 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 2-4 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Section 2 Equipment Design and Cost Estimates 

Steam, water, natural gas, and combustion air requirements are similar between both the high 

and low pressure cases. The main difference is in the power and cooling requirements. This is 

mostly due to the syngas compressor; the large energy and interstage cooling duty required adds 

considerably more to the utility requirements. Some of the cooling duty is recaptured in the 

steam system. 

High-pressure case utility requirements can be seen in Table 2-2 below. 

TABLE 2-2 HIGH-PRESSURE CASE UTILITY REQUIREMENTS 

Low-pressure case utility requirements can be seen in Table 2-3. 

TABLE 2-3 LOW-PRESSURE CASE UTILITY REQUIREMENTS 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 2-5 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Section 2 Equipment Design and Cost Estimates 

2.4 DIFFERENCES WITH NREL BIOMASS TO HYDROGEN DESIGN 

In general, the cost of the clean-up section of the biomass to chemicals designs is more 

expensive than for the NREL Biomass to Hydrogen design6. There are three main reasons for 

this: more equipment necessary in the chemicals designs, the increase in steel prices from 2002 

to 2005, and different engineering assumptions made in the chemicals case. Information on each 

reason will be elaborated upon below. 

2.4.1 Added Equipment to Chemicals Design 

The two major unit operations that are new to this design versus the hydrogen cases are the 

amine unit and the syngas compressor for methanol synthesis. In the hydrogen cases, a LOCATTM unit and ZnO bed was used for H2S removal, while the PSA removed carbon dioxide. 

The chemicals cases also use the LO-CATTM and ZnO units, but instead of a PSA, an amine unit 

is used for the bulk H2S and CO2 removal. The cost for the amine units is driven largely by the 

need for CO2 removal; due to the low H2S content in the syngas, the cost of the amine unit would 

be roughly half as much if CO2 removal was not required. The LO-CATTM unit is used in this 

case for clean-up of the acid gas stream from the amine unit instead of bulk H2S removal. 

Because of the CO2 content and different operating requirements versus the hydrogen case, the 

quote provided by GTP is roughly double the price used in the hydrogen case. 

 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 2-6 

6 Spath, P.; Aden, A.; Eggeman, T.; Ringer, M.; Wallace, B.; Jechura, J. (2005). Biomass to Hydrogen Production Detailed Design and 

Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. 161 pp.; NREL Report No. TP-510-37408. 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Section 2 Equipment Design and Cost Estimates 

In order to compress the clean syngas up to methanol synthesis pressure, a ~8,000 HP 

compressor is required. This unit was not necessary in the hydrogen case, adding to the overall 

cost. Taking into account a $12MM credit by not using the PSA, the LP cost increases by 

~$8.5MM, while the HP cost increases by ~$18.5MM due specifically to the extra equipment 

needed. 

2.4.2 Increase in Steel Price 

NREL used 2002 as the cost basis for the biomass to hydrogen designs, while Nexant is using Q2 

2005. The increase in steel price between 2002 and 2005 has been significant, impacting the 

prices quoted in the Nexant design. The Q2 2005 basis for hot-rolled steel is ~$400 to $450/ton, 

up from ~$250 to $300/ton in 20027

. Steel prices have been very volatile in the last 3 years due 

to strong worldwide demand, a sharp rise in energy prices, consolidation in the US steel market, 

and a weak US dollar. 

Because of this basis difference, the 2002 NREL basis would need to be escalated not only for 

inflation but also for steel price in order to put it on the same basis as this study. It is difficult to 

place a blanket escalation factor on the design due to the impacts that steel price has on different 

pieces of equipment; for example, this may make up much of the difference in price in 

equipment like vessels and exchangers, but have less of an impact on compressor prices. Each 

unit should be evaluated independently to determine the impact that steel price has on overall 

unit cost. 

2.4.3 Engineering Assumptions 

A side-by-side comparison of all the major process units was performed for the HP and LP cases 

versus the NREL hydrogen design. A few differences were noticed that are outlined below. A 

direct comparison cannot be performed on units that were lumped into the “Gas Cleanup” section 

of the NREL design and not explicitly sized. While the major differences are outlined here, only 

a brief attempt at determining the cost difference has been made. 

Reactors and Columns 

ZnO Beds: While the size of the ZnO beds in this design is smaller than the hydrogen case, the 

installed cost is roughly double. This is likely due to the difference in steel price. 

Tar Reformer/Regenerator: In the hydrogen design, this is included in the “Cleanup” costs, so 

no explicit design information is available. The NREL assumption for “Cleanup” took the 

average of a number of different studies; however, only one of these studies, Weyerhaeuser 

(2000), had a tar cracker. The “Cleanup” section for the Weyerhaeuser study was ~$9MM 

greater than the other designs, implying that the majority of the cost may be due to the tar 

cracker cost. The NREL “Cleanup” assumption may be low since the hydrogen design has a tar 

cracker, yet only one of the studies used to obtain the “Cleanup” cost also has a tar cracker. 

 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 2-7 

7 For more information, see the Bureau of Labor Statistics “Producer Price Series”, along with Lazaroff, Leon, “Steel Regains Some Luster”, 

Detroit Free Press, 25 July 2005 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Section 2 Equipment Design and Cost Estimates 

Cyclones 

Since these were part of the “Cleanup” average, no explicit design numbers were provided as 

part of the hydrogen study. Design quotes from vendors are used for this part of the plant in the 

chemicals design. 

Vessels 

The Nexant estimate is higher than the hydrogen design due to 1) the venturi and quench being 

included as part of the “Cleanup” estimate, 2) larger vessel sizes for the steam system than what 

was assumed in the hydrogen design, and 3) steel prices. Depending on the price assumed for 

the venturi /quench in the hydrogen design, the Nexant estimate appears to be ~$3MM greater 

than the hydrogen case. 

Heat Exchangers 

A number of differences exist between the hydrogen and chemicals designs, making the installed 

cost for exchangers in the chemical production case ~$4MM to $6MM higher than in the 

hydrogen case: 

 There is a large cost discrepancy between the exchangers downstream of the tar 

reformer. The Nexant designs are larger and considerably more expensive; Nexant 

assumed refractory lining, while it is unclear if this assumption is made in the 

hydrogen design. 

 The Nexant design has a number of exchangers not included in the hydrogen design: 

amine precoolers (HP case), methanol compressor coolers (both cases), and ZnO 

coolers (both cases). 

 A few of the exchangers in the hydrogen design are included in the “Cleanup” 

section, so it is difficult to make a direction comparison. 

Compressors and Blowers 

As mentioned earlier, the syngas compressor for methanol synthesis adds ~$7MM to the 

installed cost relative to the hydrogen case. This compressor was not necessary in the NREL 

hydrogen design. 

There is a major difference between the NREL and Nexant assumptions for the syngas 

compressor in the LP case. While NREL shows an installed cost of ~$12MM for a 30,000 HP 

compressor, Nexant estimates that a ~38,000 HP compressor is required at an installed cost of 

~$37MM ($15MM for the equipment alone). The equipment cost comes directly from Elliott 

Compressor; checks on the validity of the estimate using cost curves, ICARUS, and other 

vendors show that this is within the +/- 30% estimate desired by the study. The NREL study 

assumed that an integrally geared compressor type would be appropriate, while this report uses a 

horizontally split centrifugal compressor recommended by vendors. Analysis using cost 

estimating software shows that this assumption is the main reason for the cost difference. 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 2-8 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Section 2 Equipment Design and Cost Estimates 

Pumps 

Both Nexant and NREL designs are in agreement in regards to the pumps. 

Steam Turbine 

The Nexant estimate is slightly higher than the NREL estimate, ~$12MM installed versus 

$10MM. This difference is likely due to steel prices. 

The other difference that should be pointed out between the hydrogen and chemicals cases is the 

assumption made for the installation factor. NREL used a 2.47 installation factor, which is 

derived from literature sources. Nexant used 2.57 in both the HP and LP cases, except on the 

process gas compressor, where 2.47 is used. These numbers are derived independently from 

previous experience and vendor engineering estimates. While the factors are very similar to one 

another, this difference can make a 4% difference ($2MM) on an equipment cost of $20MM. 

2.5 CHANGING FLOWS, CONDITIONS, AND COMPOSITIONS 

Per the scope of work outlined by NREL as part of this project, Nexant has been asked to 

provide input on how the design estimates will be adjusted if the syngas flowrates or 

compositions vary. Information for both the high and low-pressure cases, along with the scaling 

factors appropriate for each major piece of process equipment, are outlined below. 

2.5.1 Flowrate Impacts 

In general the limits on process equipment sizes are usually the result of manufacturing 

restraints, transportation limits, and maintenance restrictions. For this evaluation, it was assumed 

that the throughput would be increased by 50% and the equipment size or capacity would 

increase accordingly. The affects of this change are discussed below with respect to both the 

low- and high-pressure cases. 

Low-Pressure Syngas Design Cases 

For the Low-Pressure Syngas Design Cases some of the equipment has already reached size 

limitations that required multiple trains or parallel equipment. Thus, increasing the capacity by 

50% will require more parallel equipment and a more complex and expensive piping manifold. 

Examples include: 

 Gasifier Cyclones (4 required for the base capacity) 

 Tar Reformer SG Cooler/Steam Generator (2 required) 

 Tar Reformer SG Cooler/BFW Preheater (2 required) 

 Compressor Interstage Cooling - 1st stage (2 required) 

 Syngas Venturi Scrubber/Quench Tower (2 required) 

Thus, for a 50% increase in capacity, the design would require 6 gasifier cyclones, 3 of each 

major heat exchanger, and 3 venturi scrubbers. 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 2-9 

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United States Department of Energy/National Renewable Energy Laboratory 
Section 2 Equipment Design and Cost Estimates 

Other items, such as the 1st Stage KO Drum, may require either a parallel unit or field 

construction due to equipment size and weight limitations during transportation. While the limits 

for ground transportation vary from state to state, typically, codes limit standard transport sizes 

to ~14 feet in width and height, 53 feet long and 80,000 pounds. Locating this facility in Iowa 

will mean that most equipment will be transported to the site either by rail or truck. Access to 

the Mississippi or Missouri Rivers may allow larger vessels to be used. For the 1st Stage KO 

Drum, the inside diameter would increase to about 16 feet (from a 13 foot diameter) at a capacity 

50% greater than the base case. However, when considering transportation by road, auxiliary 

equipment such as nozzles and flanges must be taken into consideration. This item would be 

well beyond most road transportation limits in the U.S. To manage this limitation, options are 

either transportation by rail or barge, parallel pieces of equipment, or field fabrication. 

Other equipment may exceed the maximum recommended size for a single train, and would 

require a second, parallel unit. This includes items such as the Syngas Compressor and the shell 

and tube heat exchanger for the Flue Gas Cooler/Steam Superheater service. In the latter case, 

the size of the heat exchanger is actually a maintenance issue. The diameter of the tube bundle 

of these units is larger than a normal bundle puller could handle (maximum limit is about 6-7 

feet diameter). It then becomes an economic question of bringing in special maintenance 

equipment during turnarounds or using smaller, parallel process equipment. 

High-Pressure Syngas Design Cases 

For the High-Pressure Syngas Design Cases, most of the equipment is smaller than the 

corresponding equipment for the Low-Pressure Syngas Design Cases as a result of the high 

pressure operation. Only a few items, when scaled by +50%, would require a parallel unit. Two 

major exchangers, the Tar Reformer SG Cooler/Steam Generator and Flue Gas Cooler/Steam 

Superheater, were discussed above. Another area is equipment within the LO-CATTM unit. 

These include the Inlet Gas KO Drum and the LO-CATTM Oxidizer Vessel. The former would 

require a vessel with an inside diameter of over 17 feet and the latter would required an inside 

diameter of about 16 feet. As noted previously, the outside diameter (including nozzles and 

flanges) would be well beyond most road transportation limits in the U.S. Vendors for process 

items of this nature can provide input for the appropriate process configuration for this service. 

Appropriate vessel sizing for the amine system is also of concern in this design. The amine 

system contains two relatively large columns – the scrubber and the regenerator. Considering a 

50% increase in capacity, the column diameters will increase by about 20 to 25%. In particular, 

the regeneration column may exceed the transportation size limitations and thus, require parallel 

trains or field fabrication. 

General Information 

A plant that is 50% larger will require more plot area not only due to the larger equipment and 

storage, but due to offsite considerations. For example, the flare will have to be designed for a 

load that is 50% larger. This will require either a taller flare or moving the flare further away 

from the main process units. A higher flare may meet with height restrictions. Thus, the area 

that is restricted around the flare may increase. 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 2-10 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Section 2 Equipment Design and Cost Estimates 

Estimating the Capital Investment Cost 

In most cases the capital cost for a capacity increase or decrease of 50% can be estimated using 

exponential methods. That is, the new capital cost can be estimated by using capacity ratio 

exponents based on published correlations and the following formula: 

C2 = C1 (q2/q1)

n 

where C stands for cost, q for flowrate, and where the value of the exponent n depends on the 

type of equipment. In reviewing the literature for the various exponents, some discrepancies in 

published factors are apparent due to variation in definition, scope and size. Technology has also 

advanced over time, making it less expensive to produce larger machinery now than in years 

past. In addition, new regulations dictate expenditures for environmental control and safety not 

included in earlier equipment. In the table that follows, the most recent literature information is 

listed. Traditionally, when a specific value is not known, an exponent value of 0.6 is often used 

for equipment and a value of 0.7 for chemical process plants (usually expressed in terms of 

annual production capacity). Table 2-4 gives typical values of n for most of the equipment 

included in these designs.8,9,10,11,12

TABLE 2-4 EXAMPLES OF TYPICAL EXPONENTS FOR 

EQUIPMENT COST VERSUS CAPACITY 

Equipment Size Range Units Exponent** 

Reactor – fixed beds N/A 0.65-0.70 

Column (including internals) 300-30,000 Feed rate, million lb/yr 0.62 

Cyclone 20-8,000 Cubic feet/m 0.64 

Vessel – vertical 100-20,000 US gallons 0.30 

Vessel – horizontal 100-80,000 US gallons 0.62 

Heat exchanger (S&T) 20-20,000 Square feet 0.59 

Venturi scrubber N/A 0.60 

Compressor – centrifugal* 200-30,000 hp 0.62 

Blower* 0.5 - 150 Thousand standard cubic feet 

per minute 

0.60 

Pump* 0.5-40 

40-400 

hp 0.30 

0.67 

Turbine 

Pressure discharge 

Vacuum discharge 

20-5,000 

200-8,000 

hp 0.81 

Motor 10-25 hp 0.56 

 

8 Perry, Robert H., and Green Don W., Perry’s Chemical Engineers’ Handbook, 7th edition, page 9-69. 9 Walas, Stanley M., “Chemical Process Equipment – Selection and Design,” Butterworths, page 665 

10 Blank, L. T. and A. J. Tarquin, “Engineering Economy,” McGraw-Hill 

11 Peters, Max S. and Timmerhaus, Klaus D., “Plant Design and Economics for Chemical Engineers,” McGraw-Hill, page 170 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 2-11 

12 Remer, Donald S. and Chai, Lawrence H., “Design Cost Factors for Scaling-up Engineering Equipment,” Chemical Engineering Progress, 

August 1990, pp 77-82 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Section 2 Equipment Design and Cost Estimates 

Equipment Size Range Units Exponent** 

25-200 0.77 

Package unit N/A 0.75 

Other N/A 0.6 – 0.7 

* excluding driver 

** this estimating method gives only the purchase price of the equipment; additional installation cost for labor, foundations and construction 

expenses will make the final cost higher. 

2.5.2 Composition Impacts 

The major units that will be impacted by a large change in syngas composition are the tar 

reformer and the venturi scrubber. Due to the relatively low concentration of sulfur in the syngas 

stream, +/-50% fluctuations in the H2S content should not impact how the sulfur removal system 

is designed. Significant changes in the inlet H2/CO ratio may also require modifications of the 

design in order to establish the appropriate downstream composition. 

The obvious change that will influence the design of the tar reformer is the amount of 

hydrocarbons in the syngas from the gasifier. Currently, the design is assuming that a separate 

reformer is not necessary, with the tar reformer converting most hydrocarbons exiting the 

gasifier. If either the hydrocarbon yield increases or the tar reformer conversion is lower than 

planned, a separate reformer for light hydrocarbons should be considered. The amount and type 

of hydrocarbons will affect the operating conditions which will in turn affect the water gas shift 

reaction. A change in the H2/CO ratio may require divorcing the shift reaction from the tar 

reformer (i.e., a separate shift reactor instead of just adding steam to the tar reformer). 

A 50% increase in particulates may require different/larger cyclones or a redesign of the venturi 

scrubber in order to handle the larger load. This is largely controlled by the gasifier operation; 

reliable performance data should be established prior to deciding upon a particulate removal 

scheme. Higher particulate loading than planned can significantly hurt overall plant 

performance. 

A 50% increase in H2S will not affect the sulfur recovery processes. LO-CATTM can handle 

between 150 lbs to 20 tonnes of sulfur per day, and concentrations between 100 ppm and about 

10% H2S. Even at 50 percent more H2S, the concentration still remains within the operating 

limits for LO-CATTM. In addition, the solvent circulation rate in the amine unit can be increased 

to remove additional H2S if the sulfur concentration is higher than expected. 

2.6 FOLLOW-UP AND AREAS FOR FURTHER STUDY 

The analysis performed sets the base case for the clean-up section of two different biomass-tochemicals designs. After in-depth analysis of these cases, the team has identified a number of 

areas for further study: 

 Alternatives for Tar Removal: A number of assumptions have been made for sizing 

and costing of this unit. Greater study and analysis, both in the laboratory and 

through simulations, should be performed to determine if the methods used are valid. 

In addition, alternative tar removal technology should be considered, including: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 2-12 

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Section 2 Equipment Design and Cost Estimates 

− Introduction of tar cracking catalyst into the gasifier. Typically, this has not been 

done due to concerns with deactivation and erosion. 

− Gasifier operation to reduce hydrocarbon yields. 

− Using a water wash for tars, followed by a standard reformer for hydrocarbons. 

While this increases the cost of quenching and wastewater handling, the cost 

tradeoff may be economic. 

 Process Integration, Gasification Systems and Biorefinery: Integration of the cleanup section with the other parts of the gasification plant will provide a better picture of 

the overall plant costs. In addition, use of this thermochemical platform has been 

considered for future application into an integrated “biorefinery”. This base case 

could be used for a determination of the process requirements and offerings that a 

thermochemical platform could provide. 

 Alternate CO2/Sulfur Removal Steps: Based on the design information provided and 

past studies that have been examined, the steps incorporated for CO2 and sulfur 

removal has been determined to be appropriate at this stage. A cost comparison of 

amine versus physical solvents and new technologies for acid gas removal would 

provide additional data to confirm the appropriate use of amine in this design. 

 New technology is currently being explored to remove sulfur without having to cool 

to 110°F or below. Since none of this technology is currently commercial, it has not 

been evaluated for use in this design. If available however, warm sulfur clean-up 

may increase efficiency in this design, by reducing the amount of reheat necessary 

prior to entering the shift reactor. 

 Other Impurities in the Syngas: For the low pressure case, a scrubber has been 

included to remove residual ammonia, and any metals, halides, or alkali remaining in 

the system. If it is deemed that the level of these impurities entering the scrubber will 

not adversely impact the FT or methanol catalysts, this step could be removed. 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 2-13 

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Section 3 Labor Requirements 

3.1 SUMMARY 

The labor projections for the 2000 MTPD biomass gasification plant are based on a combination 

of 1) models developed from Emery Energy’s 70MWe Gasification Plant design completed 

under prior DOE contracts, 2) additional “adders” for the scale and complexity (chemical plant 

nature / hydrogen production) of the 2000 MTPD plant being considered, and 3) previous 

experience of Nexant and other team members. The high pressure, oxygen-blown, 2000 MTPD 

plant requires labor skills with slightly greater operating experience than power-only facilities, 

and thus commands a premium for these skills. 

The labor rates derived from Emery’s 70 MWe Biomass IGCC (1200 MTPD plant) case were 

~$1,650,000 per year (not including subcontracted services) versus the $2,274,720 projected for 

the labor costs for the 2000 MTPD biomass to chemicals design. This difference of roughly 

$625,000 represents the higher level of experience needed for the larger plant, greater materials 

handling rates, and increased labor for plant maintenance. A discussion of the reasons for this 

difference, along with differences between the recent NREL Biomass to Hydrogen report, is 

contained below. Some of the main differences with the NREL Hydrogen report include 

different job descriptions, the use of a back-up shift crew, utilization of contract labor, and lower 

assumptions for overhead costs. 

3.2 LABOR REQUIREMENTS 

The following labor categories and positions will be required for the 2000 MTPD biomass plant. 

 General Plant Manager: Responsible for all personnel and plant decisions, 

including new employee hiring, operator training, fuel contracts, maintenance 

contracts, general equipment purchases, external communications, and operating 

schedules. Engineering degree required, with 10+ years of chemical plant operating 

experience. Salary of $100,000/yr. 

 Administrative Assistant/Company Controller: Support the general plant manager, 

manages personnel records, completes company payroll, manages time accounting 

records, manages company benefits, employee investment accounts, and insurance 

enrollments. Accountant degree required with 5+ years of experience. Salary of 

$45,000/yr. 

 Secretary/Receptionist: Supports the General Plant Manager and Company 

Controller. Receives visitors, answers phone, and attends to office administrative 

duties. Salary/Wages of $25,000/yr. 

 Laboratory Manager: Oversees all laboratory equipment and laboratory technicians. 

Responsible for product quality; testing performed both on finished product and 

intermediate streams (via on-line equipment and sample draws). Works straight days, 

with some overtime possible. Salary/Wages of $50,000/yr. 

 Laboratory Technician: Responsible for sample gathering, analytical equipment 

maintenance, and laboratory testing. Works straight days, with some overtime 

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Section 3 Labor Requirements 

possible. Shift operating crew can assist with some sample gathering as necessary; 

contract equipment technicians can assist with analytical equipment repair as 

necessary. Salary/Wages of $35,000/yr. 

 Shift Operating Crew: The plant will be operated by a four-member crew shift each 

week, with responsibilities defined below: 

 Shift Superintendent. The shift superintendent is the chief operator who mans the 

control station and simultaneously directs the activities of the shift crew. The shift 

superintendent is a degreed engineer who understands the plant, understands the 

technical and physical operations, and makes key operating decisions. The shift 

superintendent ensures compliance with plant quality, safety, industrial hygiene, and 

environmental requirements. 5-10 years of chemical plant operating experience is 

preferred for this position. Salary of $75,000/yr. 

 Support Operator. The support operator aids the shift superintendent with plant 

operation. The support operator is also tasked with bulk material handling such as 

feedstock receipts/inspection/weigh-in and ash weigh-out/disposal shipments. The 

support operator attends to feed and ash sampling/characterization, waste water 

disposal sampling, and provides general plant support in relief of the shift 

superintendent. The support operator is also tasked with monitoring plant emissions 

rates, including daily/weekly calibration of effluent gas monitors. The support 

operator verifies that plant operating records and daily logs are correct. This position 

coordinates fuel characterizations and waste water analyses. A novice degreed 

engineer or experienced technician is sufficient for this position. Salary of $45,000/yr 

 Millwright. The shift millwright conducts hourly and daily equipment inspections, 

safety rounds, completes scheduled equipment process maintenance, supports 

equipment maintenance and equipment replacements, contracts and supervises crafts 

such as pipe fitters, electricians, welders, and special instrument technicians when 

such functions exceed the millwright’s capabilities. The millwright preferably has an 

associate degree in mechanical, industrial, or design engineering technology with 5-

10 years experience. Salary of $60,000. 

 Millwright Assistant/Yard Labor. Supports millwright and accompanies millwright 

and contracted crafts, particularly during dangerous work activities, such as confined 

space entries and working from heights. The millwright assistant supports tool setup, 

job errands, and plant cleanup. Salary of $35,000. 

Shifts run for 12 hours with two crews per day. Crews report to work 30 minutes prior to the 

shift turnover to perform receive shift operating instructions and to pass information on critical 

operations and maintenance. Each crew member is allotted 30 minutes for a meal break. Thus, 

each shift extends 12.5 hours, with 0.5 hours meal break, or 12 hours of labor. Crews operate on 

a 4 days on / 4 days off rotation. This requires 84 hours on average per crew member for any 

two-week pay period. 

Five complete shift teams are engaged. The fifth crew provides coverage for individual 

vacations, sick leave, and holidays. The fifth crew also fills in for continuing training and for 

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Section 3 Labor Requirements 

new hire training. The fifth crew also supports ongoing maintenance and periodic 

outage/turnaround planning. In addition, the fifth crew supports updates to control system 

programming, data collection, and instruments. The millwright assistant on the fifth crew 

supports plant cleanup and janitorial activities. The fifth crew works 40-hour straight days when 

not substituting for members of the four-crew rotation. 

Table 3-1 summarizes the plant operating labor by category, salary, and total cost. 

TABLE 3-1 LABOR COSTS 

Position Number 

Base Salary or 

Hourly Rate 

Annual 

Overtime 

and Holiday 

Hours Overtime Rate 

Total Annual 

Cost 

General Plant Manager 1 $100,000 N/A N/A $100,000 

Company Controller 1 $45,000 N/A N/A $45,000 

Secretary/ Receptionist 1 $25,000 None N/A $25,000 

Laboratory Manager 1 $50,000 240 $30 $57,200 

Laboratory Technician 2 $35,000 240 $22.50 $80,800 

Shift Superintendent 5 $75,000 680 $45 $405,600 

Support Operator 5 $45,000 680 $25 $242,000 

Millwright 5 $60,000 680 $32.50 $322,100 

Millwright Assistant 5 $15.00/hr 560 $22.50 $144,000 

Total Base Salaries and 

Wages 

$1,421,700 

General Overhead and 

Benefits 

(60% of total salaries) 

$853,020 

Total Base Wages and 

Benefits 

$2,274,720 

Subcontracted Crafts 

Welder $80/hr 1200 $96,000 

Electrician $75/hr 640 $48,000 

Pipe Fitter $65/hr 600 $39,000 

Insulator/Painter $60/hr 400 $24,000 

Carpenter $55/hr 400 $22,000 

Instrument Technician $90/hr 400 $36,000 

Total Subcontracted 

Labor 

$265,000 

Total Labor and Benefits 

(Operating Labor Cost) 

$2,539,720 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 3-3 

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Section 3 Labor Requirements 

3.3 DIFFERENCES WITH EMERY ENERGY 70 MWE CASE 

Both the complexity and size of this facility increases the labor costs over what Emery Energy 

has assumed for their 70 MWe biomass gasification facility. The size of the unit (1200 MTPD 

vs. 2000 MTPD) slightly increases the number of shift workers and contract hours required, but 

does not increase the plant management or engineering requirements. This represents an 

economy-of-scale advantage enjoyed by larger gasification facilities; while the total labor 

requirement is greater than the 1200 MTPD facility, the marginal amount of labor required 

decreases as plant size increases. 

This design contains additional equipment than what is assumed in Emery Energy’s 70 MWe 

facility design. While this design does not contain a gas turbine, steam turbine, or HRSG, 

additional equipment includes enhanced sulfur removal (an amine system and ZnO beds), 

chemicals synthesis equipment, and tar cracking. It is this increase in complexity, rather than the 

increase in size, that adds the majority of the increase in labor costs. 

3.4 DIFFERENCES WITH NREL BIOMASS TO HYDROGEN CASE 

In the 2005 study, NREL made assumptions for the labor requirements necessary for a 2000 TPD 

wood gasification to hydrogen plant. The size being considered in this design is exactly the 

same, and the complexity is roughly the same as the NREL case. The only main difference is the 

inclusion of chemicals synthesis equipment, which takes the place of the PSA and related 

equipment required for hydrogen production. 

The labor requirements developed for the chemicals synthesis cases are lower by almost 

$1.5MM due to the assumptions made by the Nexant team. The main differences are highlighted 

below: 

 Salary Assumptions: In general, slightly higher salaries are assumed in the 

chemicals synthesis design for employees such as the plant manager, engineers, and 

operators. Higher salaries may be necessary to attract workers to facilities employing 

complicated and novel technologies. 

 Administrative Assistants: Instead of the three assistants assumed by NREL, this 

design assumes only two: the company controller/administrative assistant and the 

main receptionist. The main difference is that the truck handling work performed by 

the assistant in the NREL design will now be split amongst the millwrights and 

assistants. 

 Work Assignments for Shift Workers: As mentioned in the job descriptions, it is 

assumed that support operators will assist with yard issues, feedstock delivery, and 

field work, while the superintendent will largely be responsible for control issues. 

This reduces the need for yard employees and operators whose sole job is to man 

control boards. The five crews effectively allow for additional personnel capable of 

supporting offloading and weighing of the biomass feedstock. 

 Subcontract Labor: In order to reduce the need for full-time staff for part-time work, 

a number of specific skills, such as welders, electricians, and carpenters, will be 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 3-4 

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Section 3 Labor Requirements 

contracted out. This reduces the overall labor costs and overhead. No subcontract 

labor was assumed in the NREL hydrogen case. 

 Overhead: The labor estimate made in this case has roughly half as much full-time 

staff by utilizing more contract labor and changing the job description of day and shift 

employees. This is one reason that the estimate for overhead expenses (60%) is less 

than the biomass to hydrogen case (95%). In addition, the assumption has been made 

that a small firm will own and operate this facility. In general, overhead has been 

found to be less in smaller firms than in large multinationals; this assumption could 

be revised based on the ownership basis. This assumption for the overhead rate has 

been confirmed by Emery Energy, and is consistent with other small gasification 

companies that have limited facilities and indirect labor costs. 

 Overtime Assumptions: The NREL hydrogen case assumed straight salaries for all 

employees, with no overtime. The chemicals case assumes ~2500 hours of overtime 

per year, roughly split over the 4 main shift worker categories. Allowing overtime 

reduces the number of full-time employees required, and decreases overall labor costs 

versus the NREL hydrogen case. 

 Back-Up Shift Crew: Unlike the NREL hydrogen design, the back-up fifth shift team 

would be available to cover a number of different duties during the day shift, 

decreasing the need for specialty workers in each area. 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 3-5 

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Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock A-1 

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Appendix A High-Pressure Syngas Design Case PFDs 
Appendix A High-Pressur

Hydrogen lb/hr 4,935 4,935 4,935 - - 14,182 14,182 - - 0 0 

CO2 lb/hr 159,234 159,234 159,234 - - 161,857 161,857 188 131 39,529 39,529 

CO lb/hr 42,314 42,314 42,314 - - 90,773 90,773 - - 0 0 

H2O lb/hr 170,183 170,183 170,183 - 26,000 162,870 162,870 - 5,175 36,433 36,433 

Methane (CH4) lb/hr 23,334 23,334 23,334 - - 4,667 4,667 12,995 - 0 0 

Acetylene (C2H2) lb/hr - - - - - 0 0 - - 0 0 

Ethylene (C2H4) lb/hr 523 523 523 - - 52 52 - - 0 0 

Ethane (C2H6) lb/hr 1,122 1,122 1,122 - - 11 11 800 - 0 0 

Propane lb/hr - - - - - 0 0 183 - 0 0 

Isobutane lb/hr - - - - - 0 0 50 - 0 0 

n-Butane lb/hr - - - - - 0 0 50 - 0 0 

Pentane lb/hr - - - - - 0 0 122 - 0 0 

Benzene (C6H6) lb/hr 4,370 4,370 4,370 - - 44 44 - - 0 0 

Tar (C10H8) lb/hr 2,390 2,390 2,390 - - 2 2 - - 0 0 

Ammonia (NH3) lb/hr 318 318 318 - - 32 32 - - 0 0 

H2S lb/hr 254 254 254 - - 254 254 - - 0 0 

Char lb/hr 9,440 188 4 9,436 - 4 4 - - - - 

Oxygen lb/hr - - - - - 0 0 - 60,170 3,898 3,898 

Argon lb/hr - - - - - 0 0 - 3,349 3,349 3,349 

Nitrogen lb/hr - - - - - 235 235 263 196,376 196,638 196,638

Sulfur (solid) lb/hr - - - - - - - - - - - 

Unit 100 101 103 104 105 106 108 110 111 112 113 

Mass Flow lb/hr 418,416 409,164 408,980 26,000 9,436 434,982 434,982 14,650 265,200 279,847 279,847

Temperature F 1,576 1,576 1,576 1,576 757 1,576 370 60 90 1,798 839 

Pressure psia 460.0 460.0 459.9 459.9 460.0 456.9 446.9 14.7 14.7 14.7 14.5 

Vapour Fraction 0.96 1.00 1.00 0.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00MW 21.5 21.9 21.9 12.0 18.0 18.7 18.7 17.1 28.6 27.6 27.6 

Heat Flow MMBtu/hr -1,423.6 -1,437.5 -1,437.7 14.1 -141.8 -1,419.7 -1,674.3 -28.3 -29.5 -218.0 -301.7

Components

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Appendix A High-Pressur

Unit 108 201 202 203 205 

Mass Flow lb/hr 434,982 413,207 504 21,271 413,207

Temperature F 370 364 356 364 110

Pressure psia 446.9 444.5 444.5 456.0 429.5

Vapour Fraction 1.00 0.00 1.00 0.00 0.65MW 18.7 18.0 18.7 18.0 18.7 

Heat Flow MMBtu/hr -1,674.3 -3.2 -1,554.2 -138.2 -1,739.6

Components

Hydrogen lb/hr 14,182 0 14,179 1 14,179

CO2 lb/hr 161,857 161,688 1 36 161,688

CO lb/hr 90,773 0 90,758 3 90,758

H2O lb/hr 162,870 141,289 499 21,230 141,289

Methane (CH4) lb/hr 4,667 0 4,667 0 4,667Acetylene (C2H2) lb/hr 0 0 0 0 0Ethylene (C2H4) lb/hr 52 0 52 0 52Ethane (C2H6) lb/hr 11 0 11 0 11Propane lb/hr 0 0 0 0 0Isobutane lb/hr 0 0 0 0 0n-Butane lb/hr 0 0 0 0 0

Pentane lb/hr 0 0 0 0 0Benzene (C6H6) lb/hr 44 0 44 0 44

Tar (C10H8) lb/hr 2 0 2 0 2Ammonia (NH3) lb/hr 32 0 29 1 29

H2S lb/hr 254 0 253 0 253

Char lb/hr 4 4 0 - 0

Oxygen lb/hr 0 0 0 0 0

Argon lb/hr 0 0 0 0 0

Nitrogen lb/hr 235 0 235 0 235

Sulfur (solid) lb/hr - - - - -

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Appendix A High-Pressur

Unit 205 300 301 302 303 305 306 307 308 309 310 311 312 313 314 315 

Mass Flow lb/hr 413,207 272,078 141,129 118,505 118,505 161,485 2,384,401 2,537,954 2,536,269 1,685 2,536,269 2,587,826 213,042 240,048 2,374,785 78,564

Temperature F 110 110 110 110 110 130 110 152 152 152 200 245 258 203 130 258 

Pressure psia 429.5 429.5 429.5 422.0 422.0 19.6 432.0 445.0 30.0 30.0 25.0 25.0 30.0 21.4 16.4 30.0 

Vapour Fraction 0.65 1.00 0.00 1.00 1.00 1.00 0.00 0.00 1.00 0.00 0.05 0.00 1.00 1.00 0.00 0.00MW 18.7 19.0 18.1 11.0 11.0 40.4 31.3 31.9 28.9 31.9 31.9 29.7 18.3 28.7 18.0 31.4 

Heat Flow MMBtu/hr -1,739.6 -953.9ComponentsHydrogen lb/hr 14,179 14,178 14,149 0 14,149 1 - 30 29 1 1 - - 1 0 - 

CO2 lb/hr 161,688 160,911 778 8,184 151,360 8,184 154,523 1,796 153,156 1,367 153,156 6,432 4,637 151,419 59 1,796 

CO lb/hr 90,758 90,755 90,592 3 90,592 5 - 166 161 5 5 - - 5 0 - 

H2O lb/hr 141,289 970 140,319 581 581 9,868 1,189,367 1,189,733 1,189,619 114 1,189,619 1,387,605 207,854 88,372 1,179,751 78,504

Methane (CH4) lb/hr 4,667 4,666 0 4,655 4,655 0 - 11 11 0 0 - - 0 0 - 

Acetylene (C2H2) lb/hr - 0 - - - - - - - - - - - - - - 

Ethylene (C2H4) lb/hr 52 52 0 52 52 0 - 0 0 0 0 - - 0 0 - 

Ethane (C2H6) lb/hr 11 11 0 11 11 0 - 0 0 0 0 - - 0 0 - 

Propane lb/hr - 0 - - - - - - - - - - - - - - 

Isobutane lb/hr - 0 - - - - - - - - - - - - - - 

n-Butane lb/hr - 0 - - - - - - - - - - - - - - 

Pentane lb/hr - 0 - - - - - - - - - - - - - - 

Benzene (C6H6) lb/hr 44 44 0 40 40 2 - 3 1 2 2 - - 2 0 - 

Tar (C10H8) lb/hr 2 2 0 2 2 - - - - - - - - - - - 

Ammonia (NH3) lb/hr 29 4 25 4 4 - - - - - - - - - - - 

H2S lb/hr 253 249 4 1 1 248 3 252 251 1 251 3 1 248 0 3 

Char lb/hr - 0 - - - - - - - - - - - - - - 

Oxygen lb/hr - 0 - - - - - - - - - - - - - - 

Argon lb/hr - 0 - - - - - - - - - - - - - - 

Nitrogen lb/hr 235 235 0 235 235 0 - 0 0 0 0 - - 0 0 - 

Sulfur (solid) lb/hr - - - - - - - - - - - - - - - - 

MDEA lb/hr - - - - - 1,193,235 - 1,193,235 1,193,235 0 1,193,235 1,193,786 551 0 1,193,235 0

316 317 520 521 524 525

2,374,785 2,374,785 113,499 130,439 243,938 243,924

176 177 338 472 410 310

30.0 432.0 100.0 100.0 100.0 90.0

0.00 0.00 1.00 1.00 1.00 0.0031.4 31.4 18.0 18.0 18.0 18.0

-640.4 -727.6 -1,368.1 -1,601.6

- - - - - -

1,796 1,796 - - - -

- - - - - -

1,179,751 1,179,751 113,499 130,439 243,938 243,924

- - - - - -

- - - - - -

- - - - - -

- - - - - -

- - - - - -

- - - - - -

- - - - - -

- - - - - -

- - - - - -

- - - - - -

- - - - - -

3 3 - - - -

- - - - - -

- - - - - -

- - - - - -

- - - - - -

- - - - - -

1,193,235 1,193,235 - - - -

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Appendix A High-Pressur

Unit 305 331 332 333 334 335

Mass Flow lb/hr 160,969 156,507 4,923 375 9,400 381Temperature F 130 132 132 122 70 70 Pressure psia 19.7 18.7 14.7 18.0 14.8 64.7

Vapour Fraction 1.00 1.00 0.00 1.00 1.00 0.00MW 40.4 42.0 25.5 28.8 33.2 18.0

Heat Flow MMBtu/hrComponentsHydrogen lb/hr 1 1 - - - - 

CO2 lb/hr 150,873 146,625 3 - 4,301 - CO lb/hr 5 5 - - - - 

H2O lb/hr 9,841 9,811 137 - 387 381

Methane (CH4) lb/hr - - - - - - 

Acetylene (C2H2) lb/hr - - - - - - 

Ethylene (C2H4) lb/hr - - - - - - Ethane (C2H6) lb/hr - - - - - - 

Propane lb/hr - - - - - - 

Isobutane lb/hr - - - - - - 

n-Butane lb/hr - - - - - - 

Pentane lb/hr - - - - - - 

Benzene (C6H6) lb/hr - - - - - - 

Tar (C10H8) lb/hr - - - - - - 

Ammonia (NH3) lb/hr - - - - - - 

H2S lb/hr 248 2 - - - - 

Char lb/hrOxygen lb/hr - - 1,136 - 988 - 

Argon lb/hrNitrogen lb/hr - 63 3,787 - 3,724 - 

Sulfur (solid) lb/hr - - 223 - - - 

KHCO3 lb/hr - - 5 - - - K2S2O3 lb/hr - - 7 - - - 

FE lb/hr - - 0 - - - 

KOH lb/hr - - - - - - 

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Appendix A High-Pressur

Unit 113 115 303 320 321 323 

Mass Flow lb/hr 279,847 279,847 118,506 118,506 118,505 118,505

Temperature F 839 221 110 750 750 110 Pressure psia 14.5 422.0 14.7 417.0 412.0 402.0

Vapour Fraction 1.00 1.00 1.00 1.00 1.00 1.00MW 27.6 27.6 11.0 11.0 11.0 11.0 

Heat Flow MMBtu/hr -301.7 -350.8 -195.7 -146.0 -146.0 -195.7

Components

Hydrogen lb/hr 0 14,149 0 14,149 14,149 14,149 

CO2 lb/hr 39,529 39,529 8,184 8,184 8,184 8,184

CO lb/hr 0 90,592 0 90,592 90,592 90,592 

H2O lb/hr 36,433 36,433 581 581 581 581 

Methane (CH4) lb/hr 0 4,655 0 4,655 4,655 4,655

Acetylene (C2H2) lb/hr 0 - 0 - - - 

Ethylene (C2H4) lb/hr 0 52 0 52 52 52 

Ethane (C2H6) lb/hr 0 11 0 11 11 11 

Propane lb/hr 0 - 0 - - - 

Isobutane lb/hr 0 - 0 - - - 

n-Butane lb/hr 0 - 0 - - - 

Pentane lb/hr 0 - 0 - - - 

Benzene (C6H6) lb/hr 0 40 0 40 40 40 

Tar (C10H8) lb/hr 0 0 2 2 2 2 

Ammonia (NH3) lb/hr 0 0 4 4 4 4 

H2S lb/hr 0 0 1 1 0 0 

Char lb/hr - - - - - - 

Oxygen lb/hr 3,898 3,898 - - - - 

Argon lb/hr 3,349 3,349 - - - - 

Nitrogen lb/hr 196,638 196,638 235 235 235 235 

Sulfur (solid) lb/hr - - - - - - 

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Appendix A High-Pressur

Unit 323 400 401 403 406 407 518 526 

Mass Flow lb/hr 118,505 118,505 - 118,505 118,505 118,505 17,614 17,614 

Temperature F 110 110 110 200 240 460 472 324 

Pressure psia 402.0 402.0 402.0 1,165.0 995.0 1,160.0 100.0 95.0 

Vapour Fraction 1.00 1.00 0.00 1.00 1.00 1.00 1.00 0.00MW 11.0 11.0 18.0 11.0 11.0 11.0 18.0 18.0 

Heat Flow MMBtu/hr -195.7 -195.7 0.0 -189.0 -185.9 -168.8 -98.3 -115.4

Components

Hydrogen lb/hr 14,149 14,149 - 14,149 14,149 14,149 - - 

CO2 lb/hr 8,184 8,184 - 8,184 8,184 8,184 - - CO lb/hr 90,592 90,592 - 90,592 90,592 90,592 - - H2O lb/hr 581 581 - 581 581 17,614 581 17,614 

Methane (CH4) lb/hr 4,655 4,655 - 4,655 4,655 4,655 - - 

Acetylene (C2H2) lb/hr - - - - - - - - 

Ethylene (C2H4) lb/hr 52 52 - 52 52 52 - - 

Ethane (C2H6) lb/hr 11 11 - 11 11 11 - - 

Propane lb/hr - - - - - - - - 

Isobutane lb/hr - - - - - - - - 

n-Butane lb/hr - - - - - - - - 

Pentane lb/hr - - - - - - - - 

Benzene (C6H6) lb/hr 40 40 - 40 40 40 - - 

Tar (C10H8) lb/hr 2 2 - 2 2 - 2 - Ammonia (NH3) lb/hr 4 4 - 4 4 - 4 - H2S lb/hr 0 0 - 0 0 - 0 - Char lb/hr - - - - - - - - 

Oxygen lb/hr - - - - - - - - 

Argon lb/hr - - - - - - - - 

Nitrogen lb/hr 235 235 - 235 235 235 - - 

Sulfur (solid) lb/hr - - - - - - - - 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix A High-Pressur

Unit 500 502 504 505 506 507 508 509 525 526 530

Mass Flow lb/hr 74,631 319,878 319,878 319,878 319,878 320,040 2,180 320,040 243,924 17,614 2,154

Temperature F 60 212 212 212 239 239 240 242 310 324 298

Pressure psia 14.7 14.7 14.7 30.0 25.0 20.0 1,295.0 25.0 90.0 95.0 65.0

Vapour Fraction 0.00 0.00 0.00 0.00 0.00 1.00 0.00 0.00 0.00 0.00 1.00MW 18.0 18.0 18.0 18.0 18.0 18.0 18.0 18.0 18.0 18.0 18.0

Heat Flow MMBtu/hr -509.6 -2,134.0 -2,134.0 -2,134.0 -2,124.7 -12.4 -2,125.6 -2,123.9 -1,601.6 -115.4 -12.2

Components

Hydrogen lb/hr - 0 0 0 0 0 0 - 0 - -CO2 lb/hr - 0 0 0 0 0 0 - 0 - -

CO lb/hr - 0 0 0 0 0 0 - 0 - -

H2O lb/hr 74,631 319,878 319,878 319,878 319,878 320,040 2,180 320,040 243,924 17,614 2,154

Methane (CH4) lb/hr - 0 0 0 0 0 0 - 0 - -

Acetylene (C2H2) lb/hr - 0 0 0 0 0 0 - 0 - -

Ethylene (C2H4) lb/hr - 0 0 0 0 0 0 - 0 - -

Ethane (C2H6) lb/hr - 0 0 0 0 0 0 - 0 - -Propane lb/hr - - - - - - - - - - -

Isobutane lb/hr - - - - - - - - - - -

n-Butane lb/hr - - - - - - - - - - -

Pentane lb/hr - - - - - - - - - - -

Benzene (C6H6) lb/hr - 0 0 0 0 0 0 - 0 - -Tar (C10H8) lb/hr - - - - - - - - - - -

Ammonia (NH3) lb/hr - - - - - - - - - - -

H2S lb/hr - 0 0 0 0 0 0 - 0 - -

Char lb/hr - - - - - - - - - - -

Oxygen lb/hr - - - - - - - - - - -

Argon lb/hr - - - - - - - - - - -

Nitrogen lb/hr - 0 0 0 0 0 0 - 0 - -

Sulfur (solid) lb/hr - - - - - - - - - - -

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix A High-Pressur

Unit 510 512 513 530 531 532

Mass Flow lb/hr 320,040 313,639 6,401 2,154 4,247 4,247

Temperature F 555 575 555 298 298 110

Pressure psia 1,280.0 1,270.0 1,280.0 65.0 65.0 60.0

Vapour Fraction 0.00 1.00 0.00 1.00 0.00 0.00MW 18.0 18.0 18.0 18.0 18.0 18.0

Heat Flow MMBtu/hr -2,006.4 -1,762.6 -40.1 -12.2 -27.9 -28.8

Components

Hydrogen lb/hr - - - - - - 

CO2 lb/hr - - - - - - 

CO lb/hr - - - - - - 

H2O lb/hr 320,040 313,639 6,401 2,154 4,247 4,247

Methane (CH4) lb/hr - - - - - - 

Acetylene (C2H2) lb/hr - - - - - - 

Ethylene (C2H4) lb/hr - - - - - - 

Ethane (C2H6) lb/hr - - - - - - 

Propane lb/hr - - - - - - 

Isobutane lb/hr - - - - - - 

n-Butane lb/hr - - - - - - 

Pentane lb/hr - - - - - - 

Benzene (C6H6) lb/hr - - - - - - 

Tar (C10H8) lb/hr - - - - - - 

Ammonia (NH3) lb/hr - - - - - - 

H2S lb/hr - - - - - - 

Char lb/hr - - - - - - 

Oxygen lb/hr - - - - - - 

Argon lb/hr - - - - - - 

Nitrogen lb/hr - - - - - - 

Sulfur (solid) lb/hr - - - - - - 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix A 

 Final 

High-Pressur

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 

Report 

United States Department of Energy/National Renewable Energy Laboratory 

Unit 514 518 519 521 522

Mass Flow lb/hr 313,639 17,614 26,000 130,439 139,586Temperature F 1,000 472 758 472 758

Pressure psia 1,260.0 100.0 460.0 100.0 460.0

Vapour Fraction 1.00 1.00 1.00 1.00 1.00MW 18.0 18.0 18.0 18.0 18.0

Heat Flow MMBtu/hr -1,678.9 -98.3 -141.8 -727.6 -761.4

Components

Hydrogen lb/hr - - - - - CO2 lb/hr - - - - - CO lb/hr - - - - - 

H2O lb/hr 313,639 17,614 130,439 26,000 139,586

Methane (CH4) lb/hr - - - - - Acetylene (C2H2) lb/hr - - - - - Ethylene (C2H4) lb/hr - - - - - Ethane (C2H6) lb/hr - - - - - Propane lb/hr - - - - - Isobutane lb/hr - - - - - n-Butane lb/hr - - - - - Pentane lb/hr - - - - - Benzene (C6H6) lb/hr - - - - - Tar (C10H8) lb/hr - - - - - Ammonia (NH3) lb/hr - - - - - H2S lb/hr - - - - - Char lb/hr - - - - - Oxygen lb/hr - - - - - Argon lb/hr - - - - - Nitrogen lb/hr - - - - - Sulfur (solid) lb/hr - - - - - 
 Final 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock B-1 

Report 

United States Department of Energy/National Renewable Energy Laboratory 

Appendix B Low-Pressure Syngas Design Case PFDs 
Appendix B Low-Pressur

S-100 A/B/C/D

Gasifier Cyclones

(NOTE 2)

100

106

H-100

Tar Reformer Cooler/ 

Steam Generator

(NOTE 1)

R-100

Tar Reformer

N

L

No. DATE 

SCALE: 

SYNGASFROM GASIFIER

BOILER FEED WATER FR. PUMP

TO CHAR COMBUSTOR

S-100 A/B/C/D

Gasifier Cyclones

7' ID x 35' T/T

R-100

Tar Reformer

29' ID x 89' T/T

H-100

Tar Reformer Cooler/ 

Steam Generator

Duty: 167 MMBTU/hr

H-101

Tar Reformer Cooler/ 

BFW Preheater

Duty: 50.6 MMBTU/hr

A-600

P-602

S-102

Tar Reformer

Cyclone

S-103

Catalyst 

Regenerator

Cyclone

MAKE-UP CATALYST 120

R-101

Catalyst 

Regenerator

NATURAL GAS

CATALYST PURGE TOOFF-SITE

COMBUSTION AIR

110

K-100

Combustion Air Blower

111

112

R-101

Catalyst Regenerator

23' ID x 72' T/T

S-102

Tar Reformer

Cyclone

5' ID x 25' T/T

S-103

Catalyst Regenerator

Cyclone

4' ID x 17' T/T

H-103

Flue Gas Cooler/

Steam Superheater

H-102

Tar Reformer Cooler/ 

Deaerator Preheater

Duty: 11.3 MMBTU/hr

F

St

Du

H-101

Tar Reformer Cooler/

BFW Preheater

105

103

104

LP STEAM

DEAERATOR FEED WATER

P-601

H-102

Tar Reformer Cooler/

Deaerator Preheater

A-600

NOTES:1. SEE SECTION A-601 FOR DETAIL OF STEAM GENERATOR UNIT2. FOUR UNITS OPERATE IN PARALLEL

Unit 100 103 104 105 106 109 110 111 112 113 

Mass Flow lb/hr 316,369 275,978 40,391 328,979 53,000 328,979 13,190 235,200 248,388 248,388

Temperature F 1,598 1,598 1,598 376 1,598 225 60 90 1,798 935 

Pressure psia 33.0 32.9 32.9 50.0 29.9 18.2 14.7 14.7 14.7 14.5 

Vapour Fraction 0.80 1.00 0.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00MW 18.7 20.3 12.0 18.0 16.7 16.7 17.1 28.6 27.6 27.6 

Heat Flow MMBtu/hr -722.8 -784.2 61.4 -297.9 -936.3 -1,165.3 -25.5 -26.1 -197.5 -264.8

Components

Hydrogen lb/hr 3,538 3,538 - - 15,262 15,262 - - 0 0

CO2 lb/hr 41,379 41,379 - - 103,295 103,295 169 116 35,588 35,588

CO lb/hr 86,796 86,796 - - 97,976 97,976 - - 0 0

H2O lb/hr 112,176 112,176 - 53,000 107,295 107,295 - 4,589 32,732 32,732

Methane (CH4) lb/hr 18,106 18,106 - - 3,621 11,700 3,621 - 0 0

Acetylene (C2H2) lb/hr 777 777 - - 78 - 78 - 0 0

Ethylene (C2H4) lb/hr 8,944 8,944 - - 894 894 - - 0 0

Ethane (C2H6) lb/hr 653 653 - - 7 720 7 - 0 0

Propane lb/hr - - - - 0 165 0 - 0 0

Isobutane lb/hr - - - - 0 45 0 - 0 0

n-Butane lb/hr - - - - 0 45 0 - 0 0

Pentane lb/hr - - - - 0 110 0 - 0 0

Benzene (C6H6) lb/hr 742 742 - - 7 - 7 - 0 0

Tar (C10H8) lb/hr 2,260 2,260 - - 2 - 2 - 0 0

Ammonia (NH3) lb/hr 416 416 - - 42 - 42 - 0 0

H2S lb/hr 175 175 - - 175 175 - - 0 0

Char lb/hr 40,407 40,391 16 - 16 - 16 - - -

Oxygen lb/hr - - - - 0 - 0 53,363 2,699 2,699

Argon lb/hr - - - - 0 - 0 2,970 2,970 2,970

Nitrogen lb/hr - - - - 308 308 237 174,161 174,398 174,398

Sulfur (solid) lb/hr - - - - - - - - - -

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix B Low-Pressur

H-102

FROM TAR REFORMER COOLER

109

201

T-200

Sludge Settling Tank

T-201

Quench Water

Recirculation Tank

202

C-200

Syngas Venturi Scrubber/

Quench Tower

14’ ID x 29’ T/T (Quench Tower)

T-200 

Sludge Settling Tank

1’ ID x 3’ T/T

H-200 

Quench Water 

Recirculation Cooler

Duty: 21.8 MMBtu/hr

A-2

N

L

No. DATE 

SCALE: 

R

P-201

Quench Water

Recirculation Pump

T-201 

Quench Water 

Recirculation Tank

9’ ID x 27’ T/T

P-201 

Quench Water 

Recirculation Pump

844 GPM

7 BHP

A-100

C-200

Syngas Venturi Scrubber/

Quench Tower

(NOTE 1)

Unit 109 201 202 203 

Mass Flow lb/hr 328,979 317,371 516 11,092 

Temperature F 225 163 157 163 

Pressure psia 18.2 15.9 15.9 26.0 

Vapour Fraction 1.00 0.00 1.00 0.00MW 16.7 17.7 16.7 18.0 

Heat Flow MMBtu/hr -1,165.3 -3.4 -1,109.3 -74.6

Components

Hydrogen lb/hr 15,262 15,262 0 0 CO2 lb/hr 103,295 103,268 0 1 CO lb/hr 97,976 97,976 0 0 H2O lb/hr 107,295 95,740 500 11,091 

Methane (CH4) lb/hr 3,621 3,621 0 0 

Acetylene (C2H2) lb/hr 78 78 0 0 Ethylene (C2H4) lb/hr 894 894 0 0 

Ethane (C2H6) lb/hr 7 0 7 0 

Propane lb/hr 0 0 0 0 

Isobutane lb/hr 0 0 0 0 

n-Butane lb/hr 0 0 0 0 

Pentane lb/hr 0 0 0 0 

Benzene (C6H6) lb/hr 7 0 7 0 

Tar (C10H8) lb/hr 2 0 2 0 

Ammonia (NH3) lb/hr 42 33 0 0 H2S lb/hr 175 175 0 0 

Char lb/hr 16 16 0 - Oxygen lb/hr 0 0 0 0 

Argon lb/hr 0 0 0 0 

Nitrogen lb/hr 308 308 0 0 

Sulfur (solid) lb/hr - - - - 

NOTES:1. TWO UNITS OPERATE IN PARALLEL

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix B Low-Pressur

Unit 301 302 304 306 308 310 312 314 316 317

Mass Flow lb/hr 94,902 317,371 317,371 232,617 232,617 225,773 225,773 223,220 223,220 222,469Temperature F 110 157 110 110 110 110 110 110 110 110Pressure psia 15.9 15.9 30.0 30.0 79.0 79.0 215.0 215.0 445.0 445.0

Vapour Fraction 0.00 1.00 0.75 1.00 0.97 1.00 0.99 1.00 1.00 1.00

MW 18.0 16.7 16.7 16.3 16.3 16.2 16.2 16.2 16.2 16.2 

Heat Flow MMBtu/hr -643.0 -1,109.3 -1,204.1 -629.8 -637.0 -590.7 -593.6 -576.3 -577.5 -572.4

Components

Hydrogen lb/hr 0 15,262 15,262 15,262 15,262 15,262 15,262 15,262 15,262 15,262

CO2 lb/hr 36 103,268 103,268 103,245 103,245 103,240 103,240 103,235 103,235 103,232

CO lb/hr 0 97,976 97,976 97,976 97,976 97,976 97,976 97,976 97,976 97,976

H2O lb/hr 94,854 95,740 95,740 11,017 11,017 4,180 4,180 1,633 1,633 886 

Methane (CH4) lb/hr 0 3,621 3,621 3,621 3,621 3,621 3,621 3,621 3,621 3,621

Acetylene (C2H2) lb/hr 0 78 78 78 78 78 78 78 78 78

Ethylene (C2H4) lb/hr 0 894 894 894 894 894 894 894 894 894 

Ethane (C2H6) lb/hr 0 7 7 7 7 7 7 7 7 7 

Propane lb/hr - 0 0 - - - - - - - 

Isobutane lb/hr - 0 0 - - - - - - - 

n-Butane lb/hr - 0 0 - - - - - - - 

Pentane lb/hr - 0 0 - - - - - - - 

Benzene (C6H6) lb/hr 0 7 7 7 7 7 7 7 7 7 

Tar (C10H8) lb/hr 0 2 2 2 2 2 2 2 2 2 

Ammonia (NH3) lb/hr 12 33 33 26 26 24 24 23 23 22

H2S lb/hr 0 175 175 175 175 175 175 175 175 175 

Char lb/hr - - - - - - - - - - 

Oxygen lb/hr - 0 0 - - - - - - - 

Argon lb/hr - 0 0 - - - - - - - 

Nitrogen lb/hr 0 308 308 308 308 308 308 308 308 308 

Sulfur (solid) lb/hr - - - - - - - - - - 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix B Low-Pressur

V-403

Reflux Accumula

H-401

Rich Solvent/ 

Lean Solvent

Exchanger

P-400

Lean Solvent

 Pump

P-401

Reflux Pump

401

407

411

412

402

V-401

Rich Solvent

Flash Drum

COMPRESSED SYNGAS 

Sw

K

C-400

Amine Absorber

V-401

Rich Solvent

Flash Drum

P-400

Lean Solvent Pump

2486 GPM

802 BHP

C-401

Stripper

P-401

Reflux Pump

54 GPM

H-402

Lean Solvent Cooler

Duty: 114.0 MMBTU/hr

H-403

Stripper Reboiler

Duty: 147.8 MMBTU/hr

H-401

Rich Solvent/Lean 

Solvent Exchanger

Duty: 54.9 MMBTU/hr

N

LO

No. DATE 

SCALE: 

H-405

Acid Gas Condenser

Duty: 29.0 MMBTU/hr

A-300

K-200

CW

H-402

Lean Solvent

Cooler

V-402

Sweet Gas 

KO Drum

C-400

Amine

Absorber

C-401 

Stripper

413

404

400

408

H-403

Stripper Reboier

409

410

625

406

H-405

Acid Gas

Condenser

317

To Flare

414

415

Unit 317 400 401 402 403 405 406 407 408 409 410 411 412 413 414 415

Mass Flow lb/hr 1,244,605 222,470 1,339,954 127,107 127,107 94,477 1,333,166 6,788 1,333,166 1,379,976 140,473 120,942 1,239,503 26,465 1,239,503 1,239,503

Temperature F 110 110 160 115 115 130 157 157 200 241 253 193 130 253 209 209

Pressure psia 445.0 445.0 445.0 440.4 440.4 19.6 50.0 50.0 45.0 25.0 30.0 21.6 19.6 30.0 30.0 445.0

Vapour Fraction 1.00 0.00 0.00 1.00 1.00 1.00 1.00 0.00 0.00 0.00 1.00 1.00 0.00 0.00 0.00 0.00MW 16.2 24.2 24.9 11.0 11.0 40.5 37.3 24.9 24.9 23.5 18.6 31.8 18.0 24.2 24.2 24.2

Heat Flow MMBtu/hr -572.4 -206.2 -206.2ComponentsHydrogen lb/hr 15,262 - 22 15,240 15,240 - 22 0 0 - - - - - - - 

Carbon Dioxide lb/hr 103,233 11,519 106,499 8,260 8,260 88,628 100,143 6,356 100,143 18,366 6,847 88,663 35 11,519 11,519 11,519

Carbon Monoxide lb/hr 97,976 - 122 97,854 97,854 - 121 1 1 - - - - - - - 

Water lb/hr 859,599 886 859,638 825 825 5,681 268 859,370 859,370 987,990 133,553 32,111 26,430 854,437 854,437 854,437

Methane lb/hr 3,621 - 6 3,615 3,615 - 6 0 0 - - - - - - - 

Acetylene lb/hr 78 - - 78 78 - - - - - - - - - - - 

Ethylene lb/hr 894 - 4 890 890 - 4 0 0 - - - - - - - 

Ethane lb/hr - 7 0 7 7 - 0 0 0 - - - - - - - 

Propane lb/hr - - - - - - - - - - - - - - - - 

Isobutane lb/hr - - - - - - - - - - - - - - - - 

n-Butane lb/hr - - - - - - - - - - - - - - - - 

Pentane lb/hr - - - - - - - - - - - - - - - - 

Benzene lb/hr - 7 0 7 7 - 0 0 0 - - - - - - - Tar lb/hr - 2 - 2 2 - - - - - - - - - - - 

Ammonia lb/hr 22 - - 22 22 - - - - - - - - - - - 

Hydrogen Sulfide lb/hr 175 0 175 0 0 168 11 164 164 0 0 168 0 0 0 0

Char lb/hr - - - - - - - - - - - - - - - - 

Oxygen lb/hr - - - - - - - - - - - - - - - - 

Argon lb/hrNitrogen lb/hr 308 - 0 308 308 - 0 0 0 - - - - - - - 

Sulfur (solid) lb/hr - - - - - - - - - - - - - - - - 

DEA lb/hr 373,487 - 373,487 0 0 - 0 373,487 373,487 373,620 73 0 0 373,547 373,547 373,547

624

620 621 624 625

 106,459 44,137 150,596 150,596

292 376 352 267 

50.0 50.0 50.0 40.0 

1.00 1.00 1.00 0.0018.0 18.0 18.0 18.0 

-249.8 -598.3 -848.1 -995.8

- 0 0 0 - 0 0 0 - 0 0 0 

44,137 106,459 150,596 150,596

- 0 0 0 - 0 0 0 - 0 0 0 - 0 0 0 - - - - - - - - - - - - - - - - - 0 0 0 - - - - - - - - - 0 0 0 - - - -

- - - - - - - - - 0 0 0 - - - - - - - - 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix B Low-Pressur

Unit 405 431 432 433 434 435 

Mass Flow lb/hr 94,477 92,150 3,479 262 6,574 270 

Temperature F 130 132 132 70 132 70

Pressure psia 19.7 18.7 14.7 17.9 14.8 64.7

Vapour Fraction 1.00 1.00 0.00 1.00 1.00 0.00MW 40.5 40.4 92.9 28.8 33.1 18.0

Heat Flow MMBtu/hrComponentsHydrogen lb/hr - - - - - - 

CO2 lb/hr 88,628 86,444 2,969 - - 

CO lb/hr - - - - - - 

H2O lb/hr 5,681 5,661 97 - 274 270 

Methane (CH4) lb/hr - - - - - - 

Acetylene (C2H2) lb/hr - - - - - - 

Ethylene (C2H4) lb/hr - - - - - - 

Ethane (C2H6) lb/hr - - - - - - 

Propane lb/hr - - - - - - 

Isobutane lb/hr - - - - - - 

n-Butane lb/hr - - - - - - 

Pentane lb/hr - - - - - - 

Benzene (C6H6) lb/hr - - - - - - 

Tar (C10H8) lb/hr - - - - - - 

Ammonia (NH3) lb/hr - - - - - - 

H2S lb/hr 168 2 - - - - 

Char lb/hrOxygen lb/hr - - - 803 699 - 

Argon lb/hrNitrogen lb/hr - 43 2,676 - 2,633 - 

Sulfur (solid) lb/hr - - 157 - - - 

KHCO3 lb/hr - - 4 - - - 

K2S2O3 lb/hr - - 5 - - - 

FE lb/hr - - 0 - - - KOH lb/hr - - - - - - 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix B Low-Pressur

Hydrogen lb/hr 0 0 15,240 15,240 15,240 15,240 

CO2 lb/hr 35,588 35,588 8,260 8,260 8,260 8,260 CO lb/hr 0 0 97,853 97,853 97,853 97,853 

H2O lb/hr 32,732 32,732 817 817 817 817 

Methane (CH4) lb/hr 0 0 3,615 3,615 3,615 3,615 

Acetylene (C2H2) lb/hr 0 0 78 78 78 78 

Ethylene (C2H4) lb/hr 0 0 890 890 890 890 

Ethane (C2H6) lb/hr 0 0 7 7 7 7 

Propane lb/hr 0 0 - - - - 

Isobutane lb/hr 0 0 - - - - 

n-Butane lb/hr 0 0 - - - - Pentane lb/hr 0 0 - - - - Benzene (C6H6) lb/hr 0 0 7 7 7 7 

Tar (C10H8) lb/hr 0 0 2 2 2 2 

Ammonia (NH3) lb/hr 0 0 22 22 22 22 

H2S lb/hr 0 0 1 1 0 0 

Char lb/hr - - - - - - 

Oxygen lb/hr 2,699 2,699 - - - - 

Argon lb/hr 2,970 2,970 - - - - 

Nitrogen lb/hr 174,398 174,398 308 308 308 308 Sulfur (solid) lb/hr - - - - - - 

Unit 113 115 403 420 421 423

Mass Flow lb/hr 248,388 248,388 127,099 127,099 127,098 127,098

Temperature F 935 196 115 750 750 110 

Pressure psia 14.5 14.7 440.4 435.4 425.0 415.0 Vapour Fraction 1.00 1.00 1.00 1.00 1.00 1.00MW 27.6 27.6 11.0 11.0 11.0 11.0 

Heat Flow MMBtu/hr -264.8 -317.2 -206.1 -153.2 -153.2 -206.5

Components

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix B Low-Pressur

Unit 423 500 501 503 506 507 618 626 

Mass Flow lb/hr 127,098 127,035 63 127,035 127,035 127,035 18,832 18,832 

Temperature F 110 110 110 200 239 460 487 324 

Pressure psia 415.0 415.0 415.0 995.0 1,160.0 1,155.0 100.0 95.0 

Vapour Fraction 1.00 1.00 0.00 1.00 1.00 1.00 1.00 0.00MW 11.0 11.0 18.0 11.0 11.0 11.0 18.0 18.0 

Heat Flow MMBtu/hr -206.5 -206.1 -0.4 -198.9 -195.7 -177.3 -104.9 -123.4

Components

Hydrogen lb/hr 15,240 15,240 0 15,240 15,240 15,240 0 0 

CO2 lb/hr 8,260 8,260 0 8,260 8,260 8,260 0 0 

CO lb/hr 97,853 97,853 0 97,853 97,853 97,853 0 0 

H2O lb/hr 817 754 63 754 754 754 18,832 18,832 Methane (CH4) lb/hr 3,615 3,615 0 3,615 3,615 3,615 0 0 

Acetylene (C2H2) lb/hr 78 78 0 78 78 78 0 0 

Ethylene (C2H4) lb/hr 890 890 0 890 890 890 0 0 

Ethane (C2H6) lb/hr 7 7 0 7 7 7 0 0 

Propane lb/hr - - - - - - - - 

Isobutane lb/hr - - - - - - - - 

n-Butane lb/hr - - - - - - - - 

Pentane lb/hr - - - - - - - - 

Benzene (C6H6) lb/hr 7 7 0 7 7 7 0 0 

Tar (C10H8) lb/hr 2 2 0 2 2 2 - - 

Ammonia (NH3) lb/hr 22 22 0 22 22 22 - - H2S lb/hr 0 0 0 0 0 0 0 0 

Char lb/hr - - - - - - - - 

Oxygen lb/hr - - - - - - - - 

Argon lb/hr - - - - - - - - 

Nitrogen lb/hr 308 308 0 308 308 308 0 0 

Sulfur (solid) lb/hr - - - - - - - - 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix B Low-Pressur

P-601

Deaerator 

Feed Pump

P-602

Boiler Feed Water Pump

V-601

CondensateSurge Drum

V-602

Deaerator

V-600

Condensate

Collection Tank

M-600

Hot Process 

Water Softener System

A-600: S

N

LO

No. DATE 

SCALE: 

MAKE-UP WATER

600

602

604

608

M-600

Hot Process Water 

Softener System

V-600

Condensate Collection Tank

5’ ID x 12’ T/T

V-601

Condensate Surge Drum

5’-6” ID x 16’-6” T/T

V-602

Deaerator

2’ ID x 7' T/T (Top)

5’ - 6" ID x 16' - 6" T/T (Bottom)

P-601

Deaerator Feed Pump

537 GPM

7 BHP

P-602

Boiler Feed Pump

548 GPM

570 BHP

609

MEOH PREHEATER CONDENSATE

A-100

H-102

AMMONIAHYDRAZINE

626

A-500A-601

BLOWDOWN FR. FLASH DRUM

V-604

630

605

PREHEATED DEAERATOR FEED WATER

606

607

H-501

P-600

Condensate Make-up 

Water Pump

173 GPM

1 BHP

P-600

Condensate Make-up 

Water Pump

A-400

STRIPPER REBOILER CONDENSATE

H-403 625

Unit 600 602 604 605 606 607 608 609 625 626 630

Mass Flow lb/hr 87,404 256,818 256,818 256,818 256,818 256,896 1,579 256,896 150,588 18,826 1,648

Temperature F 195 60 195 195 237 237 238 240 257 315 298

Pressure psia 14.7 14.7 14.7 30.0 25.0 20.0 1,295.0 24.0 40.0 95.0 65.0

Vapour Fraction 0.00 0.00 0.00 0.00 0.00 1.00 0.00 0.00 0.00 0.00 1.00MW 18.0 18.0 18.0 18.0 18.0 18.0 18.0 18.0 18.0 18.0 18.0

Heat Flow MMBtu/hr -596.9 -1,717.8 -1,717.8 -1,717.8 -1,706.4 -9.0 -1,706.8 -1,705.5 -997.4 -123.5 -9.3

Components

Hydrogen lb/hr - 0 0 0 0 0 0 0 - 0 0 CO2 lb/hr - 0 0 0 0 0 0 0 - 0 0 CO lb/hr - 0 0 0 0 0 0 0 - 0 0 H2O lb/hr 87,404 256,818 256,818 256,818 256,818 256,896 1,579 256,896 150,588 18,826 1,648Methane (CH4) lb/hr - 0 0 0 0 0 0 0 - 0 0 Acetylene (C2H2) lb/hr - 0 0 0 0 0 0 0 - 0 0 Ethylene (C2H4) lb/hr - 0 0 0 0 0 0 - 0 0 0 

Ethane (C2H6) lb/hr - 0 0 0 0 0 0 0 - 0 0 Propane lb/hr - - - - - - - - - - -

Isobutane lb/hr - - - - - - - - - - -

n-Butane lb/hr - - - - - - - - - - -

Pentane lb/hr - - - - - - - - - - -

Benzene (C6H6) lb/hr - 0 0 0 0 0 0 0 - 0 0 Tar (C10H8) lb/hr - 0 0 0 0 - - - - 0 - 

Ammonia (NH3) lb/hr - - - - - - - - - - -

H2S lb/hr - 0 0 0 0 0 0 0 - 0 0 Char lb/hr - - - - - - - - - - -

Oxygen lb/hr - - - - - - - - - - -

Argon lb/hr - - - - - - - - - - -

Nitrogen lb/hr - 0 0 0 0 0 0 0 - 0 0 Sulfur (solid) lb/hr - - - - - - - - - - -

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix B Low-Pressur

Hydrogen lb/hr 0 0 0 0 0 0 

CO2 lb/hr 0 0 0 0 0 0 

CO lb/hr 0 0 0 0 0 0 

H2O lb/hr 256,896 251,758 5,138 1,648 3,490 3,490

Methane (CH4) lb/hr 0 0 0 0 0 0 

Acetylene (C2H2) lb/hr 0 0 0 0 0 0 

Ethylene (C2H4) lb/hr 0 0 0 0 0 0 

Ethane (C2H6) lb/hr 0 0 0 0 0 0 

Propane lb/hr - - - - - - 

Isobutane lb/hr - - - - - - 

n-Butane lb/hr - - - - - - Pentane lb/hr - - - - - - Benzene (C6H6) lb/hr 0 0 0 0 0 0 

Tar (C10H8) lb/hr - - - - - - 

Ammonia (NH3) lb/hr - - - - - - 

H2S lb/hr 0 0 0 0 0 0 

Char lb/hr - - - - - - 

Oxygen lb/hr - - - - - - 

Argon lb/hr - - - - - - 

Nitrogen lb/hr 0 0 0 0 0 0 

Sulfur (solid) lb/hr - - - - - - 

Unit 610 612 613 631 632 630

Mass Flow lb/hr 256,896 251,758 5,138 1,648 3,490 3,490

Temperature F 547 575 547 298 298 115

Pressure psia 1,285.0 1,275.0 1,285.0 65.0 65.0 60.0

Vapour Fraction 0.00 1.00 0.00 1.00 0.00 0.00MW 18.0 18.0 18.0 18.0 18.0 18.0Heat Flow MMBtu/hr -1,614.3 -1,415.0 -32.3 -9.3 -23.0 -23.6

Components

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix B 

 Final 

Low-Pressur

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 

Report 

United States Department of Energy/National Renewable Energy Laboratory 

A-602: 

N

LO

No. DATE 

SCALE: 

M-601

Extraction Steam

Turbine/Generator

618

M-601

Extraction Steam Turbine/Generator

19410 kW

A-100

H-103

SUPERHEATED STEAM

614

LP STEAM

621619622

MP STEAM

Unit 614 618 619 621 622 

Mass Flow lb/hr 251,758 18,832 106,459 53,000 73,467

Temperature F 1,000 487 376 376 376 

Pressure psia 1,265.0 100.0 50.0 50.0 50.0 

Vapour Fraction 1.00 1.00 1.00 1.00 1.00MW 18.0 18.0 18.0 18.0 18.0 

Heat Flow MMBtu/hr -1,347.7 -104.9 -297.9 -598.3 -412.9

Components

Hydrogen lb/hr 0 0 0 0 0 

CO2 lb/hr 0 0 0 0 0 

CO lb/hr 0 0 0 0 0 

H2O lb/hr 251,758 18,832 106,459 53,000 73,467

Methane (CH4) lb/hr 0 0 0 0 0 

Acetylene (C2H2) lb/hr 0 0 0 0 0 

Ethylene (C2H4) lb/hr 0 0 0 0 0 

Ethane (C2H6) lb/hr 0 0 0 0 0 

Propane lb/hr - - - - - 

Isobutane lb/hr - - - - - 

n-Butane lb/hr - - - - - 

Pentane lb/hr - - - - - 

Benzene (C6H6) lb/hr 0 0 0 0 0 Tar (C10H8) lb/hr - - - - - 

Ammonia (NH3) lb/hr - - - - - 

H2S lb/hr 0 0 0 0 0 

Char lb/hr - - - - - 

Oxygen lb/hr - - - - - 

Argon lb/hr - - - - - 

Nitrogen lb/hr 0 0 0 0 0 

Sulfur (solid) lb/hr - - - - - 
 Final 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-1 

Report 

United States Department of Energy/National Renewable Energy Laboratory 

Appendix C Equipment Lists and Data Sheets 

The following two appendices show the equipment lists for the high-pressure and low-pressure 

syngas design cases, along with detailed data sheets for some of the major pieces of equipment. 

No specific detail was developed for the tar cracking equipment due to the preliminary nature of 

its design. In addition, no additional information beyond what is presented in the equipment list 

was produced for vessels and pumps. Detailed equipment sheets are only shown for exchangers, 

cyclones, and compressors, where additional design data was developed. 
Appendix C 

HIGH PRESSURE SYNGAS DESIGN CASE 

Design Operating 

Quantity Price, total Price Escalated, Total Installed 

Item No Description Type Per Train Size Weight Head Design Duty P T P T Power Useage Materials (unistalled) total (uninstalled) 

Q2 2004 Cost Index Q2 2005 Cost Index 

Cost Quote S

lbs PSI PSIG oF PSIG oF (No.) HP (US $) (US $) (US $) 

Reactors R-100 Tar Reformer Fluidized Bed 20' ID x 20' T/T 490 1675 445 1576 Refractory lined CS $950,942 GT

R-101 Catalyst Regenerator 22' ID x 70' T/T 20 1950 5 1850 

Refractory lined 

CS $329,616 GT

R-320 R-321 

Total 

ZnO Beds ZnO Beds 

Vertical Vertical 

1 1 

4' - 3" ID x 8' T/T 4' - 3" ID x 8' T/T 

43,856 43,856 

2 ppmv H2S inlet 

2 ppmv H2S inlet 

445 445 

850 850 

402 402 

750 750 

CS CS 

$219,280 $219,280 

$1,719,118 

Johnson Johnson 

Cyclones 

3304 lb/hr dust CS w/ 4" refractory 

S-100 Gasifier Cyclone Cyclone 1 5' ID x 25' T/T loading 

1128 lb/hr dust 

490 650 445 1576 lining 

CS w/ 4" refractory 

$355,000 Fisher Ko

S-102 Tar Reformer Cyclone Cyclone 1 5' - 6" ID x 27' - 6" T/T loading 

1128 lb/hr dust 

490 650 442 1576 lining 

CS w/ 4" refractory 

$410,000 Fisher Ko

S-103 Total 

Catalyst Regenerator Cyclone Cyclone 1 5' ID x 25' T/T loading 490 650 442 1576 lining $265,000 

$1,030,000 

Fisher Ko

Columns, Vessels & Tanks 

3' - 2" ID x 7' - 9" T-T (Venturi); 

5' - 3" ID x 8' - 11" T-T (Quench 

C-200 Syngas Venturi Scrubber & Quench Tower Vertical 1 Tower) 485 420 432 370 CS $316,000 EPA Cos

V-400 Treated Gas KO Drum Vertical 1 5' ID x 15' T-T 31700 422 160 382 110 CS $31,700 $37,580 ICAR

V-400A V-500 

Interstage KO Drum Condensate Collection Drum 

Vertical 

Vertical 

1 

1 

5' ID x 15' T-T 

5' ID x 13' T-T 

29300 

4170 

1030 

15 

250 

265 

980 

0 

200 

212 

CS 

CS 

$57,800 

$14,745 

$68,522 

$17,480 

ICAR

ICAR

V-501 Condensate Surge Drum Horizontal 1 6' ID x 17' T-T 6300 15 145 0 94 CS $22,195 $26,312 ICAR

V-502 Deaerator Horizontal 1 6' ID x 17' T-T; 2' ID x 7' T-T 7900 25 290 10 240 CS $31,350 $37,165 ICAR

V-503 Steam Drum Horizontal 1 9' ID x 27' T-T 139300 1335 625 1265 575 SA 302B $764,205 $1,018,227 ICARV-504 Blowdown Flash Drum Vertical 1 2' ID x 6' T-T 1300 65 350 50 298 CS $8,200 $9,721 ICAR

T-200 Sludge Settling Tank Horizontal 1 1' ID x 3' T/T 300 475 415 430 364 CS $4,800 $5,690 ICAR

T-201 Total 

Quench Water Recirculation Tank Horizontal 1 4' - 6" ID x 14' T/T 3600 475 360 430 311 CS $14,460 $17,142 

$1,553,840 

ICAR

Heat Exchangers 

5' - 7" ID x 12' T-T T 1335 625 1270 575 CS 

H-100 Tar Reformer SG Cooler/Steam Generator Shell & Tube 2 Surface area: 5206 SQFT 

7' - 6" ID x 20' T-T 

203.7 MMBTU/hr S 

T 

485 

1335 

1675 

600 

442 

1270 

1576 

551 

CS - refractory 

CS 

$1,465,600 $1,664,628 ICAR

H-101 Tar Reformer SG Cooler/BFW Preheater Shell & Tube 1 Surface area: 23969 SQFT 50.84 MMBTU/hr S 485 675 437 624 CS $513,500 $583,233 ICAR

8' - 4" ID x 14' T-T T 1335 1100 1255 1000 316S 

H-102 Flue Gas Cooler/Steam Superheater Shell & Tube 1 Surface area: 8915 SQFT 83.65 MMBTU/hr S 15 1900 0 1798 CS - refractory $1,598,750 $1,815,860 ICAR

3' - 6" ID x 10' T-T T 485 415 441 364 CS 

H-200 Quench Water Recirculation Shell & Tube 1 Surface area: 2867 SQFT 22.34 MMBTU/hr S 20 150 5 100 CS $80,000 $90,864 ICAR

4' - 8" ID x 14' T-T T 1335 400 1280 349 CS 

H-201 Amine Precooler/BFW Preheat Shell & Tube 1 Surface area: 7511 SQFT 

3' - 4" ID x 6' T-T 

36.99 MMBTU/hr S 

T 

470 

30 

410 300 

427 

15 

356 

239 

CS 

CS 

$260,300 $295,649 ICAR

H-202 Amine Precooler/Deaerator FW Preheat Shell & Tube 1 Surface area: 585 SQFT 

8' ID x 8' T-T 

9.24 MMBTU/hr S 

T 

465 

65 

400 150 

422 

50 

338 

100 

CS 

CS 

$16,260 $18,468 ICAR

H-203 Amine Precooler Shell & Tube 1 Surface area: 11541 SQFT 

8' ID x 8' T-T 

139.3 MMBTU/hr S 

T 

460 

450 

350 

800 

432 

407 

305 750 

CS 

CS 

$309,600 $351,644 ICAR

H-320 ZnO Preheater Shell & Tube 1 Surface area: 19400 SQFT 49.69 MMBTU/hr S 15 910 0 839 CS $288,000 $327,110 ICAR

5' ID x 16' T-T T 1335 615 1270 565 CS 

H-321 ZnO SG Cooler/BFW Preheater Shell & Tube 1 Surface area: 5440 SQFT 29.85 MMBTU/hr S 440 800 397 750 CS $192,600 $218,755 ICAR

3' ID x 8' T-T T 65 150 50 100 CS 

H-322 Post ZnO Syngas Cooler Shell & Tube 1 Surface area: 1620 SQFT 

1' - 11" ID x 6' T-T 

19.91 MMBTU/hr S 

T 

435 

1035 

420 390 

393 985 

370 

338 

CS 

CS 

$56,100 $63,718 ICAR

H-400A MeOH Compressor Interstage Cooler Shell & Tube 1 Surface area: 476 SQFT 

6' ID x 18' T-T 

10.47 MMBTU/hr S 

T 

65 

1210 

150 

515 

100 

1150 

50 

460 

CS 

CS 

$32,200 $36,573 ICAR

H-401 MeOH Syngas Preheat Shell & Tube 1 Surface area: 16212 SQFT 

1' - 3" ID x 4' T-T 

17.14 MMBTU/hr S 

T 

100 

65 

525 150 

85 

50 

472 

100 

CS 

CS 

$355,140 $403,368 ICAR

Total 

H-501 Blowdown Cooler Shell & Tube 1 Surface area: 130 SQFT 0.84 MMBTU/hr S 65 350 50 298 CS $19,100 

$5,891,565 

$21,694 ICAR

Compressors & Blowers 

Chicago Blo

K-100 Combustion Air Blower Blower 2 61910 ACFM 5 0 90 1800 CS $274,305 ICAR

K-320 Flue Gas Blower Blower 2 85400 ACFM 0.4 0 214 207 CS $233,875 Scaled fr. Ch

K-400 MeOH Compressor - 2 Stages Centrifugal 1 2746 ACFM 74,500 758 387 110 8388 CS $2,133,200 $2,522,936 ICAR

Total $3,031,115 Pumps P-201 Quench Water Recirculation Centrifugal 2 282 GPM 420 14 475 360 430 311 3 CS $10,600 $11,021 ICAR

P-500 Condensate Make-up Water Pump Centrifugal 2 147 GPM 440 5 20 110 0 60 1.3 CS $5,400 $5,614 ICAR

P-501 Deaerator Feed Pump Centrifugal 2 674 GPM 680 15 30 150 0 98 8 CS $17,200 $17,883 ICARP-502 

Total 

Boiler Feed Water Pump Centrifugal 2 684 GPM 9,000 1,270 1345 290 11 240 710 CS $325,000 $337,903 

$372,421 

ICAR

Steam Turbine M-501 Steam Turbine Steam Turbine 1 172,900 -1,160 1245 1000 (14710 kW) CS $4,534,500 $5,362,953 ICAR

Total $5,362,953 Package Units 

A-300 Amine Unit $22,413,600 GRI Cos

A-301 LO-CAT Unit $3,998,550 $5,348,550 Gas Technol

TOTAL EQUIPMENT COST, (excld. Package units) $18,961,012 $48,729,802 TOTAL INSTALLED COST $76,491,952 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 

Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

LOW PRESSURE SYNGAS DESIGN CASE 

Design Operating 

Item No Description Type Quantity Size, each Weight Head Design Duty, total P T P T Power Useage Materials 

Price, total 

(unistalled) 

Price Escalated, 

total (uninstalled) 

Total Installed 

Cost Quote Source 

Q2 2004 Cost Index Q2 2005 Cost Index 

lbs PSI PSIG oF PSIG oF (No.) HP (US $) (US $) (US $) 

Reactors R-100 Tar Reformer Fluidized Bed 1 29' ID x 89' T/T 30 1700 15 1598 Refractory lined CS $921,786 GTI 

R-101 Catalyst Regenerator 1 23' ID x 72' T/T 30 1700 15 1598 Refractory lined CS $545,886 GTI 

R-420 ZnO Beds Vertical 1 4' - 6" ID x 8' T/T 44,522 2 ppmv H2S inlet 455 850 415 750 CS $222,610 Johnson Matthey 777 

R-421 ZnO Beds Vertical 1 4' - 6" ID x 8' T/T 44,522 2 ppmv H2S inlet 455 850 415 750 CS $222,610 Johnson Matthey Total $1,912,892 

Cyclones S-100 14,142 lb/hr dust 650 (see CS w/ 4" RefA/B/C/D Gasifier Cyclone Cyclone 4 7' ID x 35' T/T loading 33 comments) 18 1598 refractory lining $1,225,000 Fisher Kosterman tem

1,000 lb/hr dust 650 (see CS w/ 4" Ref

S-102 Tar Reformer Cyclone Cyclone 1 5' ID x 25' T/T loading 33 comments) 15 1598 refractory lining $370,000 Fisher Kosterman tem

1,000 lb/hr dust 650 (see CS w/ 4" Ref

S-103 Catalyst Regenerator Cyclone Cyclone 1 4' ID x 17' T/T loading 33 comments) 15 1598 refractory lining $250,000 Fisher Kosterman tem

Total $1,845,000 Columns, Vessels & Tanks C-200 Syngas Venturi Scrubber & Quench Tower Vertical 2 14' ID x 29' T/T 19 275 4 225 CS $340,000 Croll Reynolds 

V-300 Syngas KO Drum Vertical 2 14' ID x 28' T/T 31,500 16 210 1 157 CS $306,800 $363,711 ICARUS 

V-300A 1st Stage KO Drum Vertical 1 13' ID x 26' T/T 25,500 30 160 15 110 CS $73,400 $87,016 ICARUS V-300B 2nd Stage KO Drum Vertical 1 10' ID x 20' T/T 24,700 79 160 64 110 CS $54,300 $64,373 ICARUS 

V-300C 3rd Stage KO Drum Vertical 1 7' ID x 21' T/T 21,900 220 160 200 110 CS $41,800 $49,554 ICARUS V-300D Post KO Drum Vertical 1 6' ID x 18' T/T 23,600 475 160 430 110 CS $45,400 $53,822 ICARUS 

V-500 Treated Gas KO Drum Vertical 1 5' ID x 15' T/T 14,900 440 160 400 110 CS $31,800 $37,699 ICARUS V-500A Interstage KO Drum Vertical 1 5' ID x 15' T/T 29,300 1,030 250 980 200 CS $57,800 $68,522 ICARUS V-600 Condensate Collection Tank Vertical 1 5' ID x 12' T/T 3,990 15 245 0 195 CS $14,100 $16,716 ICARUS 

V-601 Condensate Surge Drum Horizontal 1 5' - 6" ID x 16' - 6" T/T 5,483 15 245 0 195 CS $19,320 $22,904 ICARUS 

V-602 Deaerator Vertical 1 6' ID x 18' T/T; 2' ID x 6' T/T 7,800 25 290 10 237 CS $35,700 $42,322 ICARUS 

V-603 Steam Drum Horizontal 1 9' ID x 27' T/T 139,300 1335 625 1270 575 SA 302B $764,205 $1,018,227 ICARUS 

V-604 Blowdown Flash Drum Vertical 1 2' ID x 6' T/T 1,200 65 350 50 298 CS $7,500 $8,891 ICARUS T-200 Sludge Settling Tank Horizontal 1 1' ID x 3' T/T 300 16 180 1 128 CS $4,000 $4,742 ICARUS 

T-201 Quench Water Recirculation Tank Horizontal 1 9' ID x 27' T/T 15,300 16 180 1 128 CS $60,700 $71,960 ICARUS 

Total $2,250,458 Heat Exchangers 

H-100 Tar Reformer SG Cooler/Steam Generator Shell & Tube 2 

6' ID x 14' T/T 

Surface area: 5354 SQFT 167 MMBTU/hr 

T 1335 625 1270 575 CS 

S 30 1700 15 1598 CS - refractory $989,400 $1,129,202 ICARUS Ref

H-101 Tar Reformer SG Cooler/BFW Preheater Shell & Tube 2 

4' - 9" ID x 14' T/T 

Surface area: 6667 SQFT 50.61 MMBTU/hr 

T 1335 600 1,280 542 CS 

S 20 675 12 624 CS $682,550 $775,240 ICARUS 

H-102 Tar Reformer Cooler/Deaerator FW Preheat Shell & Tube 1 

6' - 3" ID x 14' T/T 

Surface area: 5621 SQFT 11.34 MMBTU/hr 

T 30 280 15 227 CS 

S 20 350 9 300 CS $104,600 $118,805 ICARUS 

H-103 Flue Gas Cooler/Steam Superheater Shell & Tube 1 

7' - 6" ID x 14' T/T 

Surface area: 5770 SQFT 67.26 MMBTU/hr 

T 1335 1100 985 1275 316S 

S 15 1900 0 1798 CS - refractory $1,016,858 $1,154,947 ICARUS Ref

H-200 Quench Water Recirculation Cooler Shell & Tube 1 

5' - 11" ID x 10' T/T 

Surface area: 9232 SQFT 22.2 MMBTU/hr 

T 30 150 5 100 CS 

S 30 215 11 161 CS $203,800 $231,476 ICARUS 

H-300A Compressor Interstage Cooling Shell & Tube 2 

6' - 10" ID x 12' T/T 

Surface area: 14235 SQFT 122 MMBTU/hr 

T 35 400 20 344 CS 

S 65 150 50 100 CS $802,600 $911,593 ICARUS 

H-300B Compressor Interstage Cooling Shell & Tube 1 

3' - 11" ID x 10' T/T 

Surface area: 3435 SQFT 32.79 MMBTU/hr 

T 65 150 50 100 CS 

S 85 400 69 350 CS $72,300 $82,118 ICARUS 

H-300C Compressor Interstage Cooling Shell & Tube 1 

4' - 3" ID x 10' T/T 

Surface area: 4368 SQFT 27.69 MMBTU/hr 

T 230 400 205 349 CS 

S 65 150 50 100 CS $95,000 $107,901 ICARUS 

H-300D Compressor Interstage Cooling Shell & Tube 1 

3' - 6" ID x 10' T/T 

Surface area: 2934 SQFT 18.21 MMBTU/hr 

T 485 330 435 277 CS 

S 65 150 50 100 CS $74,900 $85,071 ICARUS 

H-420 ZnO Preheater Shell & Tube 1 

7' - 6" ID x 8' T/T 

Surface area: 14480 SQFT 52.90 MMBTU/hr 

T 465 800 420 750 CS 

S 15 990 0 945 CS $289,300 $328,587 ICARUS 

H-421 ZnO Syngas Cooler/BFW Preheat Shell & Tube 1 

5' - 4" ID x 12' T/T 

Surface area: 6915 SQFT 40.57 MMBTU/hr 

T 1335 600 1,280 542 CS 

S 455 800 410 750 CS $244,300 $277,476 ICARUS 

H-422 ZnO Syngas Cooler Shell & Tube 1 

2' - 6" ID x 8' T/T 

Surface area: 1190 SQFT 11.86 MMBTU/hr 

T 65 150 50 100 CS 

S 450 315 405 265 CS $41,210 $46,806 ICARUS 

H-500A MeOH Compressor Interstage Cooling Shell & Tube 1 

2' - 6" ID x 8' T/T 

Surface area: 511 SQFT 11.06 MMBTU/hr 

T 1,035 385 985 333 CS 

S 65 150 50 100 CS $33,800 $38,390 ICARUS 

H-501 MeOH Syngas Preheat Shell & Tube 1 

6' ID x 14' T/T 

Surface area: 12712 SQFT 18.45 MMBTU/hr 

T 1,261 515 1,145 460 CS 

S 100 540 85 487 CS $278,500 $316,320 ICARUS 

H-601 Blowdown Cooler Shell & Tube 1 

1' ID x 4' T/T 

Surface area: 89 SQFT 0.609 MMBTU/hr 

T 65 150 50 100 CS 

S 65 350 50 298 CS $18,400 $20,899 ICARUS 

Total $5,624,833 Compressors 

Chicago Blower Corp./ Use

K-100 Combustion Air Blower Blower 2 54910 ACFM 3 0 90 1600 CS $256,425 ICARUS 100

K-420 Flue Gas Blower Blower 2 73100 ACFM 0.4 0 176 177 CS $202,375 Scaled fr. Chicago Blower 2 - K-300 Syngas Compressor- 4 stages Centrifugal 1 131800 ACFM 333,100 434 1 157 38,786 CS $15,000,000 $37,050,000 Elliott 2.4K-500 MeOH Compressor- 2 stages Centrifugal 1 2854 ACFM 31,100 745 399 115 8,717 CS $2,369,000 Ariel Corp. 

Total $17,827,800 Pumps P-201 Quench Recirculation Pump Centrifugal 2 2423 GPM 800 10.12 26 211 1.18 160.9 20 CS $91,000 $94,613 ICARUS 2 - 

P-600 Condensate Make-up Water Pump Centrifugal 2 172 GPM 440 5 20 110 0 60 1 CS $6,320 $6,571 ICARUS 2 - 

P-601 Deaerator Feed Pump Centrifugal 2 537 GPM 810 15.3 30 160 15 108.8 7 CS $17,400 $18,091 ICARUS 2 - P-602 Boiler Feedwater Pump Centrifugal 2 548 GPM 8,900 1275 1350 278 20 227.9 570 CS $316,800 $329,377 ICARUS 2 - 

Total $448,651 Steam Turbine 

M-601 Steam Turbine- 2 extraction stages Steam Turbine 1 221,200 -1200 1,250 1,000 (19410 kW) CS $5,459,900 $6,457,424 ICARUS 

Total $6,457,424 Package Units A-400 Amine Unit $12,452,000 GRI Cost Curve 

A-401 LO-CAT Unit $3,733,550 $5,003,550 Gas Technology Products 

TOTAL EQUIPMENT COST, (excld. Package units) $36,367,057 $91,963,336 

Instequ

TOTAL INSTALLED COST $109,418,886 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock 

Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

DATA SHEETS, HIGH PRESSURE DESIGN 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. HP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit Tar Reformer SG Cooler/HP Steam Generator Item No H-100

Size 67x 144 Type BEM - HORZ Connected in 2 Parallel 1 Series

Surf/Unit (Eff) 10411 ft2 Shells/Unit 2 Surface/Shell (Effective) 5206 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Syngas fr Tar Reformer Preheated BFW

Total Fluid Entering lb/hr 435,000 313,900

 Vapor 435,000 0

 Liquid 0 313,900

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 313,900

Liquid Density (In/Out) lb/ft3 0.000/0.000 46.162/45.419

Liquid Viscosity cP 0.000 0.091

Liquid Specific Heat Btu/lb-F 0.000 1.644

Liquid Thermal Conductivity Btu/hr-ft-F 0.000 0.320

Vapor Mol. Weight (In/Out) 18.66/18.66 0.0/18.02

Vapor Viscosity cP 0.0285 0.0200

Vapor Specific Heat Btu/lb-F 0.492 0.774

Vapor Thermal Conductivity Btu/hr-ft-F 0.067 0.025

Temperature (In/Out) °F 1,576.0/624.0 556.0/575.0

Operating Pressure psi(Abs) 457.000 1,285.000

Velocity ft/sec 43.504 8.337

Pressure Drop (Allow/Calc) psi 5.000/3.245 5.000/1.133

Fouling resistance hr-ft2-F/Btu 0.001000 0.005000

Heat Exchanged 203,700,000 Btu/hr mtd (corr) 307.674 °F

Transfer Rate, Service 63.6 Clean 128.2 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 500/ 1,360/

Design Temp. °F 1675 600

No. Passes per Shell 1 6

Corrosion Allow. in 0.0625 0.0625

Connections In 1-19.0 6.0 

Size & Out 1-17.0 12.0 

Rating Intermediate 0 0 

Tube No 1912 OD 1.000 in Thk 0.065 Length 12.00 ft Pitch 1.25000 / 30.0°

Tube Type PLAIN Material 

Shell I.D 67.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 19.1 (Area) Spacing-cc 29.1

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 2,412 Bundle Entrance 1,266 Bundle Exit 2,915

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-4 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. HP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit Tar Reformer SG Cooler/BFW Preheater Item No H-101

Size 90x 240 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 23969 ft2 Shells/Unit 1 Surface/Shell (Effective) 23969 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Syngas fr Tar Reformer BFW

Total Fluid Entering lb/hr 435,000 208,600

 Vapor 435,000 0

 Liquid 0 208,600

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 0

Liquid Density (In/Out) lb/ft3 0.000/0.000 55.214/46.316

Liquid Viscosity cP 0.000 0.116

Liquid Specific Heat Btu/lb-F 0.000 1.368

Liquid Thermal Conductivity Btu/hr-ft-F 0.000 0.358

Vapor Mol. Weight (In/Out) 18.66/18.66 0.0/0.0

Vapor Viscosity cP 0.0199 0.0000

Vapor Specific Heat Btu/lb-F 0.461 0.000

Vapor Thermal Conductivity Btu/hr-ft-F 0.044 0.000

Temperature (In/Out) °F 624.0/370.0 349.0/551.0

Operating Pressure psi(Abs) 452.000 1,285.000

Velocity ft/sec 33.096 -

Pressure Drop (Allow/Calc) psi 10.000/8.600 5.000/0.359

Fouling resistance hr-ft2-F/Btu 0.001000 0.005000

Heat Exchanged 50,840,000 Btu/hr mtd (corr) 41.736 °F

Transfer Rate, Service 50.8 Clean 86.9 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 500/ 1,350/

Design Temp. °F 675 600

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-19.0 6.0 

Size & Out 1-19.0 6.0 

Rating Intermediate 0 0 

Tube No 6830 OD 0.750 in Thk 0.065 Length 20.00 ft Pitch 1.00000 / 30.0°

Tube Type PLAIN Material 

Shell I.D 90.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 13.8 (Area) Spacing-cc 24.1

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 5,194 Bundle Entrance 1,440 Bundle Exit 4,997

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-5 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. HP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit Flue Gas Cooler/Steam Superheater Item No H-102

Size 100x 168 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 8915 ft2 Shells/Unit 1 Surface/Shell (Effective) 8915 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Flue Gas fr. Tar Regen Superheated Steam

Total Fluid Entering lb/hr 280,200 313,900

 Vapor 280,200 313,900

 Liquid 0 0

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 0

Liquid Density (In/Out) lb/ft3 0.000/0.000 0.000/0.000

Liquid Viscosity cP 0.000 0.000

Liquid Specific Heat Btu/lb-F 0.000 0.000

Liquid Thermal Conductivity Btu/hr-ft-F 0.000 0.000

Vapor Mol. Weight (In/Out) 27.56/27.56 18.02/18.02

Vapor Viscosity cP 0.0399 0.0254

Vapor Specific Heat Btu/lb-F 0.314 0.676

Vapor Thermal Conductivity Btu/hr-ft-F 0.039 0.036

Temperature (In/Out) °F 1,798.0/839.0 575.0/1,000.0

Operating Pressure psi(Abs) 14.700 1,270.000

Velocity ft/sec 211.463 4.576

Pressure Drop (Allow/Calc) psi 2.000/1.798 5.000/0.484

Fouling resistance hr-ft2-F/Btu 0.001000 0.005000

Heat Exchanged 83,650,000 Btu/hr mtd (corr) 482.751 °F

Transfer Rate, Service 19.4 Clean 22.7 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 30/ 1,350/

Design Temp. °F 1900 1100

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-61.0 15.0 

Size & Out 1-55.0 15.0 

Rating Intermediate 0 0 

Tube No 3900 OD 0.750 in Thk 0.065 Length 14.00 ft Pitch 1.25000 / 45.0°

Tube Type PLAIN Material 

Shell I.D 100.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 40.7 (Area) Spacing-cc 69.9

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 880 Bundle Entrance 3,144 Bundle Exit 1,037

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-6 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. HP Syngas Csae

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit Quench Water Recirculation Item No H-200

Size 42x 120 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 2867 ft2 Shells/Unit 1 Surface/Shell (Effective) 2867 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Cooling Water Quench Water

Total Fluid Entering lb/hr 1,117,000 105,700

 Vapor 0 0

 Liquid 1,117,000 105,700

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 0

Liquid Density (In/Out) lb/ft3 61.436/61.060 57.041/61.765

Liquid Viscosity cP 0.510 0.301

Liquid Specific Heat Btu/lb-F 1.005 1.017

Liquid Thermal Conductivity Btu/hr-ft-F 1.122 0.381

Vapor Mol. Weight (In/Out) 0.0/0.0 0.0/0.0

Vapor Viscosity cP 0.0000 0.0000

Vapor Specific Heat Btu/lb-F 0.000 0.000

Vapor Thermal Conductivity Btu/hr-ft-F 0.000 0.000

Temperature (In/Out) °F 80.0/100.0 311.0/110.0

Operating Pressure psi(Abs) 20.000 456.000

Velocity ft/sec 3.475 -

Pressure Drop (Allow/Calc) psi 5.000/3.632 5.000/0.424

Fouling resistance hr-ft2-F/Btu 0.002000 0.001000

Heat Exchanged 22,340,000 Btu/hr mtd (corr) 92.789 °F

Transfer Rate, Service 84.0 Clean 115.0 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 35/ 500/

Design Temp. °F 150 415

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-12.0 4.0 

Size & Out 1-12.0 4.0 

Rating Intermediate 0 0 

Tube No 1558 OD 0.750 in Thk 0.065 Length 10.00 ft Pitch 0.93750 / 30.0°

Tube Type PLAIN Material 

Shell I.D 42.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 22.8 (Area) Spacing-cc 24.0

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 2,540 Bundle Entrance 1,308 Bundle Exit 3,750

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-7 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. HP Syngas Case

Address Proposal No.

Plant Location Date Rev. 

Service of Unit Amine Precooler/BFW Preheat Item No H-201

Size 56x 168 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 7511 ft2 Shells/Unit 1 Surface/Shell (Effective) 7511 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name BFW Syngas to Amine Absorber

Total Fluid Entering lb/hr 320,300 414,200

 Vapor 0 414,200

 Liquid 320,300 0

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 40,260

Liquid Density (In/Out) lb/ft3 58.527/55.201 0.000/56.407

Liquid Viscosity cP 0.188 0.150

Liquid Specific Heat Btu/lb-F 1.086 1.037

Liquid Thermal Conductivity Btu/hr-ft-F 0.393 0.404

Vapor Mol. Weight (In/Out) 0.0/0.0 18.69/18.69

Vapor Viscosity cP 0.0000 0.0176

Vapor Specific Heat Btu/lb-F 0.000 0.467

Vapor Thermal Conductivity Btu/hr-ft-F 0.000 0.040

Temperature (In/Out) °F 242.0/349.0 356.0/338.0

Operating Pressure psi(Abs) 1,295.000 442.000

Velocity ft/sec 0.893 18.179

Pressure Drop (Allow/Calc) psi 5.000/0.697 5.000/0.635

Fouling resistance hr-ft2-F/Btu 0.002000 0.001000

Heat Exchanged 36,985,000 Btu/hr mtd (corr) 34.052 °F

Transfer Rate, Service 144.6 Clean 300.2 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 1,425/ 1,360/

Design Temp. °F 410 400

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-8.0 23.0 

Size & Out 1-8.0 23.0 

Rating Intermediate 0 0 

Tube No 3030 OD 0.750 in Thk 0.065 Length 14.00 ft Pitch 0.93750 / 30.0°

Tube Type PLAIN Material 

Shell I.D 56.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 10.0 (Area) Spacing-cc 11.1

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 1,110 Bundle Entrance 167 Bundle Exit 1,585

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-8 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. HP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit Amine Precooler/Deaerator FW Preheat Item No H-202

Size 40x 72 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 585 ft2 Shells/Unit 1 Surface/Shell (Effective) 585 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Syngas to Amine Absorber Deaerator Feed Water

Total Fluid Entering lb/hr 414,200 320,000

 Vapor 373,940 0

 Liquid 40,260 320,000

 Steam

 Noncondensable

Fluid Vaporized or Condensed 9,444 0

Liquid Density (In/Out) lb/ft3 55.290/55.492 59.180/58.595

Liquid Viscosity cP 0.092 0.262

Liquid Specific Heat Btu/lb-F 1.111 1.020

Liquid Thermal Conductivity Btu/hr-ft-F 0.395 0.385

Vapor Mol. Weight (In/Out) 18.96/18.9436 0.0/0.0

Vapor Viscosity cP 0.0179 0.0000

Vapor Specific Heat Btu/lb-F 0.445 0.000

Vapor Thermal Conductivity Btu/hr-ft-F 0.041 0.000

Temperature (In/Out) °F 338.0/332.0 212.0/239.4

Operating Pressure psi(Abs) 437.000 30.000

Velocity ft/sec 25.051 -

Pressure Drop (Allow/Calc) psi 5.000/1.075 5.000/0.287

Fouling resistance hr-ft2-F/Btu 0.001000 0.002000

Heat Exchanged 9,238,000 Btu/hr mtd (corr) 108.950 °F

Transfer Rate, Service 145.0 Clean 322.3 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 480/ 45/

Design Temp. °F 400 300

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-23.0 8.0 

Size & Out 1-19.0 8.0 

Rating Intermediate 0 0 

Tube No 550 OD 0.750 in Thk 0.065 Length 6.00 ft Pitch 1.25000 / 45.0°

Tube Type PLAIN Material 

Shell I.D 40.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 49.0 (Area) Spacing-cc 38.9

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 1,486 Bundle Entrance 2,490 Bundle Exit 2,529

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-9 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. HP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit Amine Precooler Item No H-203

Size 96x 96 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 11541 ft2 Shells/Unit 1 Surface/Shell (Effective) 11541 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Syngas to Amine Absorber Cooling Water

Total Fluid Entering lb/hr 414,200 6,965,000

 Vapor 364,537 0

 Liquid 49,663 6,965,000

 Steam

 Noncondensable

Fluid Vaporized or Condensed 97,296 0

Liquid Density (In/Out) lb/ft3 55.608/62.120 62.000/61.573

Liquid Viscosity cP 0.211 0.627

Liquid Specific Heat Btu/lb-F 1.063 1.001

Liquid Thermal Conductivity Btu/hr-ft-F 0.384 0.365

Vapor Mol. Weight (In/Out) 18.8591/18.96 0.0/0.0

Vapor Viscosity cP 0.0168 0.0000

Vapor Specific Heat Btu/lb-F 0.424 0.000

Vapor Thermal Conductivity Btu/hr-ft-F 0.041 0.000

Temperature (In/Out) °F 332.0/110.0 80.0/100.0

Operating Pressure psi(Abs) 432.000 65.000

Velocity ft/sec 13.546 -

Pressure Drop (Allow/Calc) psi 5.000/1.874 5.000/0.592

Fouling resistance hr-ft2-F/Btu 0.001000 0.002000

Heat Exchanged 139,300,000 Btu/hr mtd (corr) 98.751 °F

Transfer Rate, Service 122.2 Clean 210.0 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 475/ 80/

Design Temp. °F 350 150

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-23.0 31.0 

Size & Out 1-17.0 31.0 

Rating Intermediate 0 0 

Tube No 8842 OD 0.750 in Thk 0.065 Length 8.00 ft Pitch 0.93750 / 30.0°

Tube Type PLAIN Material 

Shell I.D 96.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 18.6 (Area) Spacing-cc 39.8

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 1,463 Bundle Entrance 1,418 Bundle Exit 3,610

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-10 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. HP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit ZnO Preheater Item No H-320

Size 96x 96 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 19400 ft2 Shells/Unit 1 Surface/Shell (Effective) 19400 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Flue Gas fr. Tar Regen Sweet Syngas

Total Fluid Entering lb/hr 280,200 118,500

 Vapor 280,200 118,500

 Liquid 0 0

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 0

Liquid Density (In/Out) lb/ft3 0.000/0.000 0.000/0.000

Liquid Viscosity cP 0.000 0.000

Liquid Specific Heat Btu/lb-F 0.000 0.000

Liquid Thermal Conductivity Btu/hr-ft-F 0.000 0.000

Vapor Mol. Weight (In/Out) 27.56/27.56 10.99/10.99

Vapor Viscosity cP 0.0157 0.0182

Vapor Specific Heat Btu/lb-F 0.312 0.659

Vapor Thermal Conductivity Btu/hr-ft-F 0.012 0.076

Temperature (In/Out) °F 839.0/214.0 100.0/750.0

Operating Pressure psi(Abs) 14.500 422.000

Velocity ft/sec 64.628 2.701

Pressure Drop (Allow/Calc) psi 2.000/1.675 5.000/0.488

Fouling resistance hr-ft2-F/Btu 0.002000 0.002000

Heat Exchanged 49,960,000 Btu/hr mtd (corr) 96.31 °F

Transfer Rate, Service 26.55 Clean Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 30/ 465/

Design Temp. °F 910 800

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-53.0 12.0 

Size & Out 1-47.0 15.0 

Rating Intermediate 0 0 

Tube No 14190 OD 0.750 in Thk 0.065 Length 8.00 ft Pitch 1.25000 / 45.0°

Tube Type PLAIN Material 

Shell I.D 163.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 36.0 (Area) Spacing-cc 65.0

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 900 Bundle Entrance 673 Bundle Exit 651

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-11 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. HP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit ZnO SG Cooler/BFW Preheater Item No H-321

Size 60x 192 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 5440 ft2 Shells/Unit 1 Surface/Shell (Effective) 5440 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Syngas fr ZnO Beds BFW

Total Fluid Entering lb/hr 118,500 111,600

 Vapor 118,500 0

 Liquid 0 111,600

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 0

Liquid Density (In/Out) lb/ft3 0.000/0.000 54.688/45.460

Liquid Viscosity cP 0.000 0.115

Liquid Specific Heat Btu/lb-F 0.000 1.429

Liquid Thermal Conductivity Btu/hr-ft-F 0.000 0.352

Vapor Mol. Weight (In/Out) 10.99/10.99 0.0/0.0

Vapor Viscosity cP 0.0203 0.0000

Vapor Specific Heat Btu/lb-F 0.663 0.000

Vapor Thermal Conductivity Btu/hr-ft-F 0.086 0.000

Temperature (In/Out) °F 750.0/370.0 349.0/565.0

Operating Pressure psi(Abs) 412.000 1,285.000

Velocity ft/sec 30.448 -

Pressure Drop (Allow/Calc) psi 5.000/3.935 5.000/0.407

Fouling resistance hr-ft2-F/Btu 0.001000 0.002000

Heat Exchanged 29,850,000 Btu/hr mtd (corr) 75.373 °F

Transfer Rate, Service 72.8 Clean 99.1 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 455/ 1,350/

Design Temp. °F 800 615

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-15.0 4.0 

Size & Out 1-13.0 6.0 

Rating Intermediate 0 0 

Tube No 1902 OD 0.750 in Thk 0.065 Length 16.00 ft Pitch 1.25000 / 30.0°

Tube Type PLAIN Material 

Shell I.D 60.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 14.0 (Area) Spacing-cc 14.5

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 2,063 Bundle Entrance 272 Bundle Exit 2,203

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-12 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. HP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit Post ZnO Syngas Cooler Item No H-322

Size 36x 96 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 1620 ft2 Shells/Unit 1 Surface/Shell (Effective) 1620 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Syngas fr. ZnO Beds Cooling Water

Total Fluid Entering lb/hr 118,500 995,500

 Vapor 118,500 0

 Liquid 0 995,500

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 0

Liquid Density (In/Out) lb/ft3 0.000/0.000 62.000/62.000

Liquid Viscosity cP 0.000 0.762

Liquid Specific Heat Btu/lb-F 0.000 1.000

Liquid Thermal Conductivity Btu/hr-ft-F 0.000 0.363

Vapor Mol. Weight (In/Out) 10.99/10.99 0.0/0.0

Vapor Viscosity cP 0.0148 0.0000

Vapor Specific Heat Btu/lb-F 0.647 0.000

Vapor Thermal Conductivity Btu/hr-ft-F 0.065 0.000

Temperature (In/Out) °F 370.0/110.0 80.0/100.0

Operating Pressure psi(Abs) 407.000 65.000

Velocity ft/sec 47.403 -

Pressure Drop (Allow/Calc) psi 5.000/3.747 5.000/0.585

Fouling resistance hr-ft2-F/Btu 0.001000 0.002000

Heat Exchanged 19,910,000 Btu/hr mtd (corr) 109.229 °F

Transfer Rate, Service 112.6 Clean 183.2 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 450/ 80/

Design Temp. °F 420 150

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-13.0 12.0 

Size & Out 1-12.0 12.0 

Rating Intermediate 0 0 

Tube No 1102 OD 0.750 in Thk 0.065 Length 8.00 ft Pitch 0.93750 / 30.0°

Tube Type PLAIN Material 

Shell I.D 36.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 24.3 (Area) Spacing-cc 24.0

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 2,539 Bundle Entrance 1,981 Bundle Exit 3,675

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-13 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. HP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit MeOH Compressor Interstage Cooler Item No H-400A

Size 23x 72 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 476 ft2 Shells/Unit 1 Surface/Shell (Effective) 476 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Cooling water Syngas

Total Fluid Entering lb/hr 537,000 118,500

 Vapor 0 118,500

 Liquid 537,000 0

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 0

Liquid Density (In/Out) lb/ft3 62.000/62.000 0.000/0.000

Liquid Viscosity cP 0.762 0.000

Liquid Specific Heat Btu/lb-F 1.000 0.000

Liquid Thermal Conductivity Btu/hr-ft-F 0.363 0.000

Vapor Mol. Weight (In/Out) 0.0/0.0 10.99/10.99

Vapor Viscosity cP 0.0000 0.0155

Vapor Specific Heat Btu/lb-F 0.000 0.655

Vapor Thermal Conductivity Btu/hr-ft-F 0.000 0.068

Temperature (In/Out) °F 80.0/100.0 338.0/200.0

Operating Pressure psi(Abs) 65.000 1,000.000

Velocity ft/sec 4.236 25.340

Pressure Drop (Allow/Calc) psi 5.000/2.578 5.000/0.675

Fouling resistance hr-ft2-F/Btu 0.002000 0.001000

Heat Exchanged 10,470,000 Btu/hr mtd (corr) 172.318 °F

Transfer Rate, Service 127.7 Clean 216.4 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 80/ 1,050/

Design Temp. °F 150 390

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-10.0 12.0 

Size & Out 1-10.0 10.0 

Rating Intermediate 0 0 

Tube No 442 OD 0.750 in Thk 0.065 Length 6.00 ft Pitch 0.93750 / 30.0°

Tube Type PLAIN Material 

Shell I.D 23.25 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 23.5 (Area) Spacing-cc 16.3

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 1,206 Bundle Entrance 1,316 Bundle Exit 1,940

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-14 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. HP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit MeOH Syngas Preheat Item No H-401

Size 72x 216 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 16212 ft2 Shells/Unit 1 Surface/Shell (Effective) 16212 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Steam Syngas to MeOH Rxn

Total Fluid Entering lb/hr 17,610 118,500

 Vapor 17,610 118,500

 Liquid 0 0

 Steam

 Noncondensable

Fluid Vaporized or Condensed 17,610 0

Liquid Density (In/Out) lb/ft3 0.000/54.780 0.000/0.000

Liquid Viscosity cP 0.128 0.000

Liquid Specific Heat Btu/lb-F 1.157 0.000

Liquid Thermal Conductivity Btu/hr-ft-F 0.393 0.000

Vapor Mol. Weight (In/Out) 18.02/18.02 10.99/10.99

Vapor Viscosity cP 0.0161 0.0170

Vapor Specific Heat Btu/lb-F 0.483 0.660

Vapor Thermal Conductivity Btu/hr-ft-F 0.020 0.074

Temperature (In/Out) °F 471.7/324.0 240.0/460.0

Operating Pressure psi(Abs) 100.000 1,165.000

Velocity ft/sec 4.482 2.118

Pressure Drop (Allow/Calc) psi 5.000/0.586 5.000/0.430

Fouling resistance hr-ft2-F/Btu 0.005000 0.001000

Heat Exchanged 17,140,000 Btu/hr mtd (corr) 45.146 °F

Transfer Rate, Service 23.4 Clean 27.4 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 130/ 1,225/

Design Temp. °F 545 515

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-8.0 10.0 

Size & Out 1-2.0 12.0 

Rating Intermediate 0 0 

Tube No 5044 OD 0.750 in Thk 0.065 Length 18.00 ft Pitch 0.93750 / 30.0°

Tube Type PLAIN Material 

Shell I.D 72.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection NO

Baffles Cross Type VERT- SEG %Cut 10.2 (Area) Spacing-cc 14.3

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 1,057 Bundle Entrance 1,398 Bundle Exit 1,158

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-15 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. HP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit Blowdown Cooler Item No H-501

Size 15x 48 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 130 ft2 Shells/Unit 1 Surface/Shell (Effective) 130 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Blowdown Cooling water

Total Fluid Entering lb/hr 3,987 41,985

 Vapor 0 0

 Liquid 3,987 41,985

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 0

Liquid Density (In/Out) lb/ft3 56.607/62.000 62.000/62.000

Liquid Viscosity cP 0.311 0.762

Liquid Specific Heat Btu/lb-F 1.059 1.000

Liquid Thermal Conductivity Btu/hr-ft-F 0.382 0.363

Vapor Mol. Weight (In/Out) 0.0/0.0 0.0/0.0

Vapor Viscosity cP 0.0000 0.0000

Vapor Specific Heat Btu/lb-F 0.000 0.000

Vapor Thermal Conductivity Btu/hr-ft-F 0.000 0.000

Temperature (In/Out) °F 298.0/110.0 80.0/100.0

Operating Pressure psi(Abs) 65.000 65.000

Velocity ft/sec 0.143 0.528

Pressure Drop (Allow/Calc) psi 5.000/0.154 5.000/0.206

Fouling resistance hr-ft2-F/Btu 0.001000 0.002000

Heat Exchanged 839,700 Btu/hr mtd (corr) 89.027 °F

Transfer Rate, Service 72.7 Clean 97.5 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 80/ 80/

Design Temp. °F 350 150

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-1.0 3.0 

Size & Out 1-1.0 3.0 

Rating Intermediate 0 0 

Tube No 170 OD 0.750 in Thk 0.065 Length 4.00 ft Pitch 0.93750 / 30.0°

Tube Type PLAIN Material 

Shell I.D 15.25 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 8.6 (Area) Spacing-cc 3.0

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 728 Bundle Entrance 9 Bundle Exit 423

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-16 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

COMPRESSOR NUMBER

GAS HANDLED

NORMAL FLOW SCFM

NORMAL FLOW LB/HR

DESIGN FLOW SCFM

MOL WT.

Value

 @ F / PSIA

SUCTION CONDITIONS

SUCTION PRESSURE PSIA

COMPR. FACTOR @ SUCTION

FLOW AT SUCTION ACFM

ORIGIN PSIA

TEMPERATURE F

LINE LOSS PSI (2)

OTHER LOSSES PSI (1, 2)

CONTINGENCY PSI

DISCHARGE CONDITIONS

DISCH. PRESSURE PSIA

DISCH. TEMPERATURE F (2)

COMPR. FACTOR @ DISCH.

DELIVERY PSIA

LINE LOSS PSI (2)

EXCHANGER LOSS PSI (2)

HEATER LOSS PSI (2)

CONTROL VALVE LOSS PSI (2)

OTHER LOSSES PSI (2)

CONTINGENCY PSI (2)

TOTAL LOSSES PSI (2)

COMPRESSION RATIO

EFFICIENCY (2)

BHP (2)

COMPRESSOR TYPE

DRIVER TYPE

GAS COMPOSITION: Vol. %

H2O

O2

Ar

N2

DATE PROC PROJ. CLIENT

JOB NO

REV

NO

SERVICE

Cp/Cv

3.1

0.9

75.7

20.3

1800

1.36

0.75

20

90 / 14.7

28.63

1.4

265,200

Air

58,597

K-100

Combustion Air

NREL Contract ACO-5-44027

NREL BIOMASS GASIFICATION: High Pressure Syngas Case (GTI Gasifier)

REVISIONS

DRAWING NO

(1) INCLUDES ALLOWANCE FOR SUCTION OR DISCHARGE SNUBBER

(2) VALUE TABULATED IS ESTIMATED AND MUST BE VERIFIED BY FINAL MECHANICAL DESIGN

14.7

0.999

157

61,910

90

0.999

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-17 

Appendix C 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 

COMPRESSOR NUMBER

GAS HANDLED

NORMAL FLOW SCFM

NORMAL FLOW LB/HR

DESIGN FLOW SCFM

MOL WT.

Value

 @ F / PSIA

SUCTION CONDITIONS

SUCTION PRESSURE PSIA

COMPR. FACTOR @ SUCTION

FLOW AT SUCTION ACFM

ORIGIN PSIA

TEMPERATURE F

LINE LOSS PSI (2)

OTHER LOSSES PSI (1, 2)

CONTINGENCY PSI

DISCHARGE CONDITIONS

DISCH. PRESSURE PSIA

DISCH. TEMPERATURE F (2)

COMPR. FACTOR @ DISCH.

DELIVERY PSIA

LINE LOSS PSI (2)

EXCHANGER LOSS PSI (2)

HEATER LOSS PSI (2)

CONTROL VALVE LOSS PSI (2)

OTHER LOSSES PSI (2)

CONTINGENCY PSI (2)

TOTAL LOSSES PSI (2)

COMPRESSION RATIO

EFFICIENCY (2)

BHP (2)

COMPRESSOR TYPE

DRIVER TYPE

GAS COMPOSITION: Vol. %

H2O

O2

Ar

N2

DATE PROC PROJ. CLIENT

JOB NO

REV

NO

SERVICE

Cp/Cv

3.1

0.9

75.7

20.3

1800

1.36

0.75

20

90 / 14.7

28.63

1.4

265,200

Air

58,597

K-100

Combustion Air

NREL Contract ACO-5-44027

NREL BIOMASS GASIFICATION: High Pressure Syngas Case (GTI Gasifier)

REVISIONS

DRAWING NO

(1) INCLUDES ALLOWANCE FOR SUCTION OR DISCHARGE SNUBBER

(2) VALUE TABULATED IS ESTIMATED AND MUST BE VERIFIED BY FINAL MECHANICAL DESIGN

14.7

0.999

157

61,910

90

0.999

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

COMPRESSOR NUMBER

GAS HANDLED

NORMAL FLOW SCFM

NORMAL FLOW LB/HR

DESIGN FLOW SCFM

MOL WT.

Value

 @ F / PSIA

SUCTION CONDITIONS

SUCTION PRESSURE PSIA

COMPR. FACTOR @ SUCTION

FLOW AT SUCTION ACFM

ORIGIN PSIA

TEMPERATURE F

LINE LOSS PSI (2)

OTHER LOSSES PSI (1, 2)

CONTINGENCY PSI

DISCHARGE CONDITIONS

DISCH. PRESSURE PSIA

DISCH. TEMPERATURE F (2)

COMPR. FACTOR @ DISCH.

DELIVERY PSIA

LINE LOSS PSI (2)

EXCHANGER LOSS PSI (2)

HEATER LOSS PSI (2)

CONTROL VALVE LOSS PSI (2)

OTHER LOSSES PSI (2)

CONTINGENCY PSI (2)

TOTAL LOSSES PSI (2)

COMPRESSION RATIO

EFFICIENCY (2)

BHP (2)

COMPRESSOR TYPE

DRIVER TYPE

GAS COMPOSITION: Vol. %

CO2

H2O

O2

Ar

N2

DATE PROC PROJ. CLIENT

JOB NO

REV

0.9985

221

85,400

214

0.9985

14.3

(1) INCLUDES ALLOWANCE FOR SUCTION OR DISCHARGE SNUBBER

(2) VALUE TABULATED IS ESTIMATED AND MUST BE VERIFIED BY FINAL MECHANICAL DESIGN

NREL Contract ACO-5-44027

NREL BIOMASS GASIFICATION: High Pressure Syngas Case (GTI Gasifier)

REVISIONS

DRAWING NO

K-320

Flue Gas Blower

Flue Gas

64,194

279,800

27.58

1.365

202.5 / 14.3

14.7

1.03

0.75

207

10.93

1.03

0.73

SERVICE

Cp/Cv

72.98

14.33

NO

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-18 

Appendix C 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 

COMPRESSOR NUMBER

GAS HANDLED

NORMAL FLOW SCFM

NORMAL FLOW LB/HR

DESIGN FLOW SCFM

MOL WT.

Value

 @ F / PSIA

SUCTION CONDITIONS

SUCTION PRESSURE PSIA

COMPR. FACTOR @ SUCTION

FLOW AT SUCTION ACFM

ORIGIN PSIA

TEMPERATURE F

LINE LOSS PSI (2)

OTHER LOSSES PSI (1, 2)

CONTINGENCY PSI

DISCHARGE CONDITIONS

DISCH. PRESSURE PSIA

DISCH. TEMPERATURE F (2)

COMPR. FACTOR @ DISCH.

DELIVERY PSIA

LINE LOSS PSI (2)

EXCHANGER LOSS PSI (2)

HEATER LOSS PSI (2)

CONTROL VALVE LOSS PSI (2)

OTHER LOSSES PSI (2)

CONTINGENCY PSI (2)

TOTAL LOSSES PSI (2)

COMPRESSION RATIO

EFFICIENCY (2)

BHP (2)

COMPRESSOR TYPE

DRIVER TYPE

GAS COMPOSITION: Vol. %

CO2

H2O

O2

Ar

N2

DATE PROC PROJ. CLIENT

JOB NO

REV

0.9985

221

85,400

214

0.9985

14.3

(1) INCLUDES ALLOWANCE FOR SUCTION OR DISCHARGE SNUBBER

(2) VALUE TABULATED IS ESTIMATED AND MUST BE VERIFIED BY FINAL MECHANICAL DESIGN

NREL Contract ACO-5-44027

NREL BIOMASS GASIFICATION: High Pressure Syngas Case (GTI Gasifier)

REVISIONS

DRAWING NO

K-320

Flue Gas Blower

Flue Gas

64,194

279,800

27.58

1.365

202.5 / 14.3

14.7

1.03

0.75

207

10.93

1.03

0.73

SERVICE

Cp/Cv

72.98

14.33

NO

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

COMPRESSOR NUMBER

GAS HANDLED

NORMAL FLOW SCFM

NORMAL FLOW LB/HR

DESIGN FLOW SCFM

MOL WT.

Value

 @ F / PSIA

SUCTION CONDITIONS

SUCTION PRESSURE PSIA

COMPR. FACTOR @ SUCTION

FLOW AT SUCTION ACFM

ORIGIN PSIA

TEMPERATURE F

LINE LOSS PSI (2)

OTHER LOSSES PSI (1, 2)

CONTINGENCY PSI

DISCHARGE CONDITIONS

DISCH. PRESSURE PSIA

DISCH. TEMPERATURE F (2)

COMPR. FACTOR @ DISCH.

DELIVERY PSIA

LINE LOSS PSI (2)

EXCHANGER LOSS PSI (2)

HEATER LOSS PSI (2)

CONTROL VALVE LOSS PSI (2)

OTHER LOSSES PSI (2)

CONTINGENCY PSI (2)

TOTAL LOSSES PSI (2)

COMPRESSION RATIO

EFFICIENCY (2)

BHP (2)

COMPRESSOR TYPE

DRIVER TYPE

GAS COMPOSITION: Vol. %

H2

CO2

CO

H20

CH4

C2H2

C2H4

C2H6

Benzene (C6H6)

Tar (C10H8)

NH3

N2

DATE PROC PROJ. CLIENT

JOB NO

REV

0.000001 0.000001

0.00005 0.00005

0.00002 0.00002

240.4

1.022 1.026

(1) INCLUDES ALLOWANCE FOR SUCTION OR DISCHARGE SNUBBER

(2) VALUE TABULATED IS ESTIMATED AND MUST BE VERIFIED BY FINAL MECHANICAL DESIGN

NREL Contract ACO-5-44027

NREL BIOMASS GASIFICATION: High Pressure Syngas Case (GTI Gasifier)

REVISIONS

DRAWING NO

K-400A K-400B

MeOH Comp-1 MeOH Comp-2

Treated Syngas Treated Syngas

68,247 68,247

118,500 118,500

10.99 10.99

1.418 1.423

110 / 402 200 / 995

110 200

402 995

1.006 1.021

1,567 1,306

1,000 1,165

334.8

2.49 1.17

0.75 0.75

7,102 1,286

65.10 65.1

1.50 1.5

30.08 30.08

0.27 0.27

2.70 2.7

0.02 0.02

SERVICE

Cp/Cv

0.00003 0.00003

0.08 0.08

NO

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-19 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

COMPRESSOR NUMBER

GAS HANDLED

NORMAL FLOW SCFM

NORMAL FLOW LB/HR

DESIGN FLOW SCFM

MOL WT.

Value

 @ F / PSIA

SUCTION CONDITIONS

SUCTION PRESSURE PSIA

COMPR. FACTOR @ SUCTION

FLOW AT SUCTION ACFM

ORIGIN PSIA

TEMPERATURE F

LINE LOSS PSI (2)

OTHER LOSSES PSI (1, 2)

CONTINGENCY PSI

DISCHARGE CONDITIONS

DISCH. PRESSURE PSIA

DISCH. TEMPERATURE F (2)

COMPR. FACTOR @ DISCH.

DELIVERY PSIA

LINE LOSS PSI (2)

EXCHANGER LOSS PSI (2)

HEATER LOSS PSI (2)

CONTROL VALVE LOSS PSI (2)

OTHER LOSSES PSI (2)

CONTINGENCY PSI (2)

TOTAL LOSSES PSI (2)

COMPRESSION RATIO

EFFICIENCY (2)

kW Generated (2)

Turbine TYPE

DRIVER TYPE

GAS COMPOSITION: Vol. %

H2

CO2

CO

H20

CH4

C2H2

C2H4

C2H6

Benzene (C6H6)

Tar (C10H8)

NH3

N2

DATE PROC PROJ. CLIENT

JOB NO

REV

0.9521 0.974

(1) INCLUDES ALLOWANCE FOR SUCTION OR DISCHARGE SNUBBER

(2) VALUE TABULATED IS ESTIMATED AND MUST BE VERIFIED BY FINAL MECHANICAL DESIGN

NREL Contract ACO-5-44027

NREL BIOMASS GASIFICATION: High Pressure Syngas Case (GTI Gasifier)

REVISIONS

DRAWING NO

M-501A M-501B

Steam Turbine - 

Extraction Stage 1

Steam Turbine - 

Extraction Stage 2

Steam Steam 

110,138 51,979

313,600 148,100

18.02 18.02

1.384 1.353

1000 / 1260 758 / 460

1000 758

1260 460

0.9334 0.9521

3,369 3,709

460 100

758 472

- -

0.75 0.75

9,341 5,371

Steam Steam

SERVICE

Cp/Cv

100% 100%

NO

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-20 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Site Location Date Rev.

Flow Viscosity Density

Molecular 

Weight 

(Ave.)

Particle 

Size (mm) 

(Stokes' 

MMD)

Volumetric 

Flowrate Temperature 

lb/h lb/ft-sec lb/ft3 lb/mole acfm °F

418,416.00 2.54E-05 0.47800 21.5 14,589.00 1,576

9,440.00 62.40 60

460.00

455.57

120.00

460.00

50

98

Emery Design Calculations Summary for S-100 (for Reference Only)

Mechanical Sizing Inside 

Diam (in)

Uninsulated 

Outside Diam 

(in)

ID (in) OD (in) Thickness (in) Designation Overall Height 

(ft)

In 32 42 Upper Shell 58 60 1 ASME VIII 25

Out 24 34 Inner Tube 24 26 1

Bottom Cone 1 ASME VIII

Refractory 50 4

Design 

Temperature 

(°F)

Solids 

Removal 

Flowrate 

(CFM)

Differential 

Design 

Pressure 

(psig)

Type

Rotary Air Lock 1598 Inner Wall Outer Shell Inner Wall Outer Shell Inner Wall Outer Shell

Level Indicator 1598 CercastTM MS CercastTM MS CercastTM MS

Inner Tube

MS

Fisher-Klosterman, Inc (Refer to Vendor Communications and Data Sheets)

Ryan Bruner, Sales Manager

P.O. Box 11190

Lousville, KY

Ph: 502-572-4000 ext 213

Email: rab@fkinc.com

Recommendation: Replace S-100 and S-101 with one (1) cyclone only:

One (1) cyclone (XQ120-30M) with the following features:

Design, fabricated, tested, and stamped as an ASME vessel Interior surfaces to be lined with 4" of Vesuvius Cercast 3300 castable refractory

1-1/4" plate carbon steel construction All welding per FKI Class 3 preocedures with 100% penetration

Dust receiver section with flanged discharge Exterior to be sandblasted and painted with high temperature aluminum paint

Inlet transition to 24"∅ gas inlet flange Design pressure (psig) 460

30"∅ verticle gas outlet flange Design Temperature (F) 650

Approximate Overall Dimensions:

Gas Conditions at Inlet: Particulate Conditions at Inlet:

Volume per cylone (acfm) 14,589 Specific Gravity 1.000

Density (lbm/ft3) 0.478 Dust Loading (Grains/acf) 31.3

Viscosity (lbm/ft-sec) 2.54E-05

Inlet Velocity (ft/sec) 68.39 Fraction Efficiencies: Stokes Equiv. % Efficiency

No load pres. drop (in.W.C.) 106.35 Dia.(microns) Weight %

Full load pres. Drop (in. W.C.) 85.46 2.5 6.11

3 15.75

3.5 21.47

4 27.4

4.5 33.3

5 39.04

6 44.49

6.5 49.6

7.5 58.71

8.5 66.32

9.5 72.57

12 83.53

16 89.99

23 95.08

33 97.84

Upper Section Lower Conical section

Cyclone Body Materials of Construction

Connections Size 

& Rating

Gas

Particulate

Design/Test Pressure Psig

Cyclone Specification Sheet

Remarks: Inlet and outlet manifolding is not included in Fisher-Klosterman quote for these four cylones. Estimated cost of splitter and collection is $25,000. 

Refer to supplier data sheet for Vesuvius CERCASTTM 3300 Castable refractory. 

SERVICE OF HIGH PRESSURE UNIT S-100

Nozzles

Gas Discharge Pressure (psig)

Pressure Drop, Max Allow. (" .WC.)

Gas Inlet Pressure (psia)

Component Data

Inlet Conditions

Vendor/Supplier Specifications and Price Quote

Price (2005 U.S.$) $ 355,000.00

Design Particulate Cutpoint

Design Separation Efficiency at Cutpoint (%)

5 ft∅ x 25 ft tall

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-21 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Site Location Date Rev.

Flow Viscosity Density

Molecular 

Weight 

(Ave.)

Particle 

Size (mm) 

(Stokes' 

MMD)

Volumetric 

Flowrate Temperature 

lb/h lb/ft-sec lb/ft3 lb/mole acfm °F

434,982.00 0.38390 27.6 18,883.00 1,576

9,440.00 62.40 60

460.00

455.57

120.00

460.00

50

98

Emery Design Calculations Summary for S-102 (for Reference Only)

Mechanical Sizing Inside 

Diam (in)

Uninsulated 

Outside Diam 

(in)

ID (in) OD (in) Thickness (in) Designation Height (In) Height (ft)

In 32.0769 42.10 Upper Shell 1 ASME VIII 160 13.4

Out Inner Tube 32.10 4

Bottom Cone 1 ASME VIII

Refractory 4

Design 

Temperature 

(°F)

Solids 

Removal 

Flowrate 

(CFM)

Differential 

Design 

Pressure 

(psig)

Type

Rotary Air Lock 1598 20.4 15 Inner Wall Outer Shell Inner Wall Outer Shell Inner Wall Outer Shell

Level Indicator 1598 CercastTM MS CercastTM MS CercastTM MS

Inner Tube

MS

Fisher-Klosterman, Inc (Refer to Vendor Communications and Data Sheets)

Ryan Bruner, Sales Manager

P.O. Box 11190

Lousville, KY

Ph: 502-572-4000 ext 213

Email: rab@fkinc.com

Recommendation: 

One (1) cyclone (XQ120-30M) with the following features:

Design, fabricated, tested, and stamped as an ASME vessel Interior surfaces to be lined with 4" of Vesuvius Cercast 3300 castable refractory

1-1/4" plate carbon steel construction All welding per FKI Class 3 preocedures with 100% penetration

Dust receiver section with flanged discharge Exterior to be sandblasted and painted with high temperature aluminum paint

Inlet transition to 24"∅ gas inlet flange Design pressure (psig) 460

30"∅ verticle gas outlet flange Design Temperature (F) 650

Approximate Overall Dimensions: 5-1/2 ft∅ x 27 1/2 ft tall

Gas Conditions at Inlet: Particulate Conditions at Inlet:

Volume per cylone (acfm) 18,883 Specific Gravity 1.000

Density (lbm/ft3) 0.3839 Dust Loading (Grains/acf) 6.97

Viscosity (lbm/ft-sec) 2.78E-05

Inlet Velocity (ft/sec) 69.94 Fraction Efficiencies: Stokes Equiv. % Efficiency

No load pres. drop (in.W.C.) 83.63 Dia.(microns) Weight %

Full load pres. Drop (in. W.C.) 72.52 3 7.64

4 16.37

4.5 21.33

5 26.43

5.5 31.53

6 36.52

7 45.88

8 54.2

9 61.4

10 67.53

11 72.7

14 83.68

18 89.34

25 94.31

35 97.29

80 99.72

Upper Section Lower Conical section

Cyclone Body Materials of Construction

Connections Size 

& Rating

Gas

Particulate

Design/Test Pressure Psig

Cyclone Specification Sheet

Remarks: Inlet and outlet manifolding is not included in Fisher-Klosterman quote for these four cylones. Estimated cost of splitter and collection is $25,000. 

Refer to supplier data sheet for Vesuvius CERCASTTM 3300 Castable refractory. 

SERVICE OF HIGH PRESSURE UNIT S-102

Nozzles

Gas Discharge Pressure (psig)

Pressure Drop, Max Allow. (" .WC.)

Gas Inlet Pressure (psia)

Component Data

Inlet Conditions

Vendor/Supplier Specifications and Price Quote

Price (2005 U.S.$) $ 410,000.00

Design Particulate Cutpoint

Design Separation Efficiency at Cutpoint (%)

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-22 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Site Location Date Rev.

Flow Specific Heat Density

Molecular 

Weight 

(Ave.)

Particle 

Size (mm) 

(Stokes' 

MMD)

Volumetric 

Flowrate Temperature 

lb/h BTU/lb°F lb/ft3 lb/mole acfm °F

434,982.00 0.41421 20.14507 16,835.82 1576.0

9,440.00 33.00 60

460.00

455.57

120.00

460.00

50

98

Emery Design Calculations Summary for S-103 (for Reference Only)

Mechanical Sizing Inside 

Diam (in)

Uninsulated 

Outside Diam 

(in)

ID (in) OD (in) Thickness (in) Designation Height (In) Height (ft)

In 32.0769 42.10 Upper Shell 1 ASME VIII 160 13.4

Out Inner Tube 32.10 4

Bottom Cone 1 ASME VIII

Refractory 4

Design 

Temperature 

(°F)

Solids 

Removal 

Flowrate 

(CFM)

Differential 

Design 

Pressure 

(psig)

Type

Rotary Air Lock 1598 20.4 15 Inner Wall Outer Shell Inner Wall Outer Shell Inner Wall Outer Shell

Level Indicator 1598 CercastTM MS CercastTM MS CercastTM MS

Inner Tube

MS

Fisher-Klosterman, Inc (Refer to Vendor Communications and Data Sheets)

Ryan Bruner, Sales Manager

P.O. Box 11190

Lousville, KY

Ph: 502-572-4000 ext 213

Email: rab@fkinc.com

Recommendation:

One (1) cyclone (XQ120-30M) with the following features:

Design, fabricated, tested, and stamped as an ASME vessel Interior surfaces to be lined with 4" of Vesuvius Cercast 3300 castable refractory

1-1/4" plate carbon steel construction All welding per FKI Class 3 preocedures with 100% penetration

Dust receiver section with flanged discharge Exterior to be sandblasted and painted with high temperature aluminum paint

Inlet transition to 24"∅ gas inlet flange Design pressure (psig) 460

30"∅ verticle gas outlet flange Design Temperature (F) 650

Approximate Overall Dimensions: 4 ft∅ x 18 ft tall

Gas Conditions at Inlet: Particulate Conditions at Inlet:

Volume per cylone (acfm) 8,223 Specific Gravity 1.000

Density (lbm/ft3) 0.5679 Dust Loading (Grains/acf) 16

Viscosity (lbm/ft-sec) 2.87E-05

Inlet Velocity (ft/sec) 68.53 Fraction Efficiencies: Stokes Equiv. % Efficiency

No load pres. drop (in.W.C.) 103.76 Dia.(microns) Weight %

Full load pres. Drop (in. W.C.) 85.86 2.5 6.71

3.5 15.89

4 21.16

4.5 26.55

5 31.91

5.5 37.11

6 42.08

7 51.14

8 58.96

9 65.59

10 71.14

13 82.8

17 89.12

24 94.37

34 97.41

89 99.83

Upper Section Lower Conical section

Cyclone Body Materials of Construction

Connections Size 

& Rating

Gas

Particulate

Design/Test Pressure Psig

Cyclone Specification Sheet

Remarks: Inlet and outlet manifolding is not included in Fisher-Klosterman quote for these four cylones. Estimated cost of splitter and collection is $25,000. 

Refer to supplier data sheet for Vesuvius CERCASTTM 3300 Castable refractory. 

SERVICE OF HIGH PRESSURE UNIT S-103

Nozzles

Gas Discharge Pressure (psig)

Pressure Drop, Max Allow. (" .WC.)

Gas Inlet Pressure (psia)

Component Data

Inlet Conditions

Vendor/Supplier Specifications and Price Quote

Price (2005 U.S.$) $ 265,000.00

Design Particulate Cutpoint

Design Separation Efficiency at Cutpoint (%)

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-23 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

DATA SHEETS, LOW PRESSURE DESIGN 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. LP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit Tar Reformer SG Cooling/Steam Generator Item No H-100 Tar Ref Cooler

Size 72x 168 Type BEM - HORZ Connected in 2 Parallel 1 Series

Surf/Unit (Eff) 10708 ft2 Shells/Unit 2 Surface/Shell (Effective) 5354 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Syngas fr Tar Reformer Preheated BFW

Total Fluid Entering lb/hr 329,000 251,800

 Vapor 329,000 0

 Liquid 0 251,800

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 251,800

Liquid Density (In/Out) lb/ft3 0.000/0.000 46.533/45.419

Liquid Viscosity cP 0.000 0.092

Liquid Specific Heat Btu/lb-F 0.000 1.636

Liquid Thermal Conductivity Btu/hr-ft-F 0.000 0.321

Vapor Mol. Weight (In/Out) 16.74/16.74 0.0/18.02

Vapor Viscosity cP 0.0280 0.0200

Vapor Specific Heat Btu/lb-F 0.520 0.774

Vapor Thermal Conductivity Btu/hr-ft-F 0.078 0.025

Temperature (In/Out) °F 1,598.0/624.0 546.5/575.0

Operating Pressure psi(Abs) 29.900 1,285.000

Velocity ft/sec 280.241 7.682

Pressure Drop (Allow/Calc) psi 5.000/3.920 5.000/0.977

Fouling resistance hr-ft2-F/Btu 0.001000 0.005000

Heat Exchanged 167,000,000 Btu/hr mtd (corr) 318.656 °F

Transfer Rate, Service 48.9 Clean 80.8 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 45/ 1,350/

Design Temp. °F 1700 625

No. Passes per Shell 1 6

Corrosion Allow. in 0.0625 0.0625

Connections In 1-33.0 6.0 

Size & Out 1-29.0 10.0 

Rating Intermediate 0 0 

Tube No 1664 OD 1.000 in Thk 0.065 Length 14.00 ft Pitch 1.25000 / 30.0°

Tube Type PLAIN Material 

Shell I.D 72.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 34.7 (Area) Spacing-cc 73.7

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 2,611 Bundle Entrance 3,399 Bundle Exit 4,375

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-24 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. LP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit Tar Reformer SG Cooling/BFW Preheat Item No H-101 Tar Ref Cooler

Size 57x 168 Type BEM - HORZ Connected in 2 Parallel 1 Series

Surf/Unit (Eff) 13334 ft2 Shells/Unit 2 Surface/Shell (Effective) 6667 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Syngas fr Tar Reformer BFW

Total Fluid Entering lb/hr 329,000 142,594

 Vapor 329,000 0

 Liquid 0 142,594

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 0

Liquid Density (In/Out) lb/ft3 0.000/0.000 58.509/46.533

Liquid Viscosity cP 0.000 0.139

Liquid Specific Heat Btu/lb-F 0.000 1.340

Liquid Thermal Conductivity Btu/hr-ft-F 0.000 0.359

Vapor Mol. Weight (In/Out) 16.74/16.74 0.0/0.0

Vapor Viscosity cP 0.0189 0.0000

Vapor Specific Heat Btu/lb-F 0.475 0.000

Vapor Thermal Conductivity Btu/hr-ft-F 0.049 0.000

Temperature (In/Out) °F 624.0/300.0 240.0/546.5

Operating Pressure psi(Abs) 26.900 1,295.000

Velocity ft/sec 234.572 -

Pressure Drop (Allow/Calc) psi 5.000/4.568 5.000/0.513

Fouling resistance hr-ft2-F/Btu 0.001000 0.002000

Heat Exchanged 50,610,000 Btu/hr mtd (corr) 68.377 °F

Transfer Rate, Service 55.5 Clean 68.5 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 35/ 1,360/

Design Temp. °F 675 600

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-29.0 3.0 

Size & Out 1-29.0 4.0 

Rating Intermediate 0 0 

Tube No 2688 OD 0.750 in Thk 0.065 Length 14.00 ft Pitch 0.93750 / 30.0°

Tube Type PLAIN Material 

Shell I.D 57.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 37.1 (Area) Spacing-cc 75.5

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 2,563 Bundle Entrance 2,914 Bundle Exit 3,741

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-25 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. LP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit Tar Reformer SG Cooler/Deaerator FW Preheat Item No H-102 Tar Ref Cooler

Size 75x 168 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 5621 ft2 Shells/Unit 1 Surface/Shell (Effective) 5621 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Syngas fr H-101 Deaerator Feed Water

Total Fluid Entering lb/hr 329,000 257,000

 Vapor 329,000 0

 Liquid 0 257,000

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 0

Liquid Density (In/Out) lb/ft3 0.000/0.000 59.592/58.402

Liquid Viscosity cP 0.000 0.273

Liquid Specific Heat Btu/lb-F 0.000 1.054

Liquid Thermal Conductivity Btu/hr-ft-F 0.000 0.392

Vapor Mol. Weight (In/Out) 16.74/16.74 0.0/0.0

Vapor Viscosity cP 0.0156 0.0000

Vapor Specific Heat Btu/lb-F 0.461 0.000

Vapor Thermal Conductivity Btu/hr-ft-F 0.040 0.000

Temperature (In/Out) °F 300.0/225.0 195.0/237.0

Operating Pressure psi(Abs) 23.880 30.000

Velocity ft/sec 168.427 -

Pressure Drop (Allow/Calc) psi 5.000/2.790 5.000/0.489

Fouling resistance hr-ft2-F/Btu 0.001000 0.002000

Heat Exchanged 11,340,000 Btu/hr mtd (corr) 44.478 °F

Transfer Rate, Service 45.4 Clean 58.8 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 35/ 45/

Design Temp. °F 350 280

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-41.0 6.0 

Size & Out 1-42.0 6.0 

Rating Intermediate 0 0 

Tube No 2096 OD 0.750 in Thk 0.065 Length 14.00 ft Pitch 1.25000 / 30.0°

Tube Type PLAIN Material 

Shell I.D 75.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 41.0 (Area) Spacing-cc 81.9

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 2,021 Bundle Entrance 1,271 Bundle Exit 2,155

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-26 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. LP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit Flue Gas Cooler/Steam Superheater Item No H-103

Size 90x 168 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 5770 ft2 Shells/Unit 1 Surface/Shell (Effective) 5770 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Flue Gas fr. Tar Regen Superheated Steam

Total Fluid Entering lb/hr 248,400 251,800

 Vapor 248,400 251,800

 Liquid 0 0

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 0

Liquid Density (In/Out) lb/ft3 0.000/0.000 0.000/0.000

Liquid Viscosity cP 0.000 0.000

Liquid Specific Heat Btu/lb-F 0.000 0.000

Liquid Thermal Conductivity Btu/hr-ft-F 0.000 0.000

Vapor Mol. Weight (In/Out) 27.57/27.57 18.02/18.02

Vapor Viscosity cP 0.0405 0.0254

Vapor Specific Heat Btu/lb-F 0.313 0.678

Vapor Thermal Conductivity Btu/hr-ft-F 0.040 0.036

Temperature (In/Out) °F 1,798.0/935.0 575.0/1,000.0

Operating Pressure psi(Abs) 14.700 1,275.000

Velocity ft/sec 215.255 5.762

Pressure Drop (Allow/Calc) psi 2.000/1.727 5.000/0.629

Fouling resistance hr-ft2-F/Btu 0.001000 0.005000

Heat Exchanged 67,260,000 Btu/hr mtd (corr) 550.248 °F

Transfer Rate, Service 21.2 Clean 25.0 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 30/ 1,350/

Design Temp. °F 1900 1100

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-57.0 12.0 

Size & Out 1-53.0 15.0 

Rating Intermediate 0 0 

Tube No 2475 OD 0.750 in Thk 0.065 Length 14.00 ft Pitch 1.25000 / 45.0°

Tube Type PLAIN Material 

Shell I.D 90.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 38.4 (Area) Spacing-cc 71.2

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 906 Bundle Entrance 2,230 Bundle Exit 1,030

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-27 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. LP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit NREL Biomass Item No H-200 Quech Water Cooler

Size 71x 120 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 9232 ft2 Shells/Unit 1 Surface/Shell (Effective) 9232 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Quench Water Cooling Water

Total Fluid Entering lb/hr 1,189,000 1,107,500

 Vapor 0 0

 Liquid 1,189,000 1,107,500

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 0

Liquid Density (In/Out) lb/ft3 61.342/61.765 62.470/62.000

Liquid Viscosity cP 0.578 0.744

Liquid Specific Heat Btu/lb-F 1.003 0.998

Liquid Thermal Conductivity Btu/hr-ft-F 0.366 0.361

Vapor Mol. Weight (In/Out) 0.0/0.0 0.0/0.0

Vapor Viscosity cP 0.0000 0.0000

Vapor Specific Heat Btu/lb-F 0.000 0.000

Vapor Thermal Conductivity Btu/hr-ft-F 0.000 0.000

Temperature (In/Out) °F 128.0/110.0 80.0/100.0

Operating Pressure psi(Abs) 26.000 20.000

Velocity ft/sec 1.924 -

Pressure Drop (Allow/Calc) psi 5.000/1.722 5.000/0.549

Fouling resistance hr-ft2-F/Btu 0.001000 0.002000

Heat Exchanged 22,150,000 Btu/hr mtd (corr) 28.989 °F

Transfer Rate, Service 82.8 Clean 115.4 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 45/ 45/

Design Temp. °F 215 150

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-13.0 12.0 

Size & Out 1-13.0 12.0 

Rating Intermediate 0 0 

Tube No 4860 OD 0.750 in Thk 0.065 Length 10.00 ft Pitch 0.93750 / 30.0°

Tube Type PLAIN Material 

Shell I.D 71.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 9.2 (Area) Spacing-cc 14.1

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 2,093 Bundle Entrance 913 Bundle Exit 2,867

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-28 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. LP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit Compressor Interstage Cooling Item No H-300A

Size 82x 144 Type BEM - HORZ Connected in 2 Parallel 1 Series

Surf/Unit (Eff) 28471 ft2 Shells/Unit 2 Surface/Shell (Effective) 14235 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Cooling water 1st Stage Syngas

Total Fluid Entering lb/hr 6,100,000 317,400

 Vapor 0 317,400

 Liquid 6,100,000 0

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 85,698

Liquid Density (In/Out) lb/ft3 62.000/62.000 0.000/62.020

Liquid Viscosity cP 0.762 0.432

Liquid Specific Heat Btu/lb-F 1.000 1.035

Liquid Thermal Conductivity Btu/hr-ft-F 0.363 0.380

Vapor Mol. Weight (In/Out) 0.0/0.0 16.7/16.7

Vapor Viscosity cP 0.0000 0.0157

Vapor Specific Heat Btu/lb-F 0.000 0.460

Vapor Thermal Conductivity Btu/hr-ft-F 0.000 0.043

Temperature (In/Out) °F 80.0/100.0 344.0/110.0

Operating Pressure psi(Abs) 65.000 35.000

Velocity ft/sec 3.977 39.521

Pressure Drop (Allow/Calc) psi 5.000/4.889 5.000/0.642

Fouling resistance hr-ft2-F/Btu 0.002000 0.001000

Heat Exchanged 122,000,000 Btu/hr mtd (corr) 80.189 °F

Transfer Rate, Service 53.4 Clean 64.5 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 80/ 50/

Design Temp. °F 150 400

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-23.0 25.0 

Size & Out 1-23.0 23.0 

Rating Intermediate 0 0 

Tube No 6298 OD 0.750 in Thk 0.065 Length 12.00 ft Pitch 0.93750 / 30.0°

Tube Type PLAIN Material 

Shell I.D 82.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 12.4 (Area) Spacing-cc 24.0

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 1,391 Bundle Entrance 1,525 Bundle Exit 2,034

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-29 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. LP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit Compressor Interstage Cooling Item No H-300B

Size 47x 120 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 3435 ft2 Shells/Unit 1 Surface/Shell (Effective) 3435 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name 2nd Stage Syngas Cooling water

Total Fluid Entering lb/hr 232,600 1,639,500

 Vapor 232,600 0

 Liquid 0 1,639,500

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 0

Liquid Density (In/Out) lb/ft3 0.000/0.000 62.000/62.000

Liquid Viscosity cP 0.000 0.762

Liquid Specific Heat Btu/lb-F 0.000 1.000

Liquid Thermal Conductivity Btu/hr-ft-F 0.000 0.363

Vapor Mol. Weight (In/Out) 16.26/16.26 0.0/0.0

Vapor Viscosity cP 0.0162 0.0000

Vapor Specific Heat Btu/lb-F 0.470 0.000

Vapor Thermal Conductivity Btu/hr-ft-F 0.050 0.000

Temperature (In/Out) °F 350.0/110.0 80.0/100.0

Operating Pressure psi(Abs) 84.000 65.000

Velocity ft/sec 119.731 1.938

Pressure Drop (Allow/Calc) psi 5.000/3.994 5.000/0.664

Fouling resistance hr-ft2-F/Btu 0.001000 0.002000

Heat Exchanged 32,790,000 Btu/hr mtd (corr) 103.761 °F

Transfer Rate, Service 92.0 Clean 134.2 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 100/ 80/

Design Temp. °F 400 150

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-25.0 15.0 

Size & Out 1-23.0 15.0 

Rating Intermediate 0 0 

Tube No 1808 OD 0.750 in Thk 0.065 Length 10.00 ft Pitch 0.93750 / 30.0°

Tube Type PLAIN Material 

Shell I.D 47.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 37.2 (Area) Spacing-cc 58.0

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 2,286 Bundle Entrance 3,535 Bundle Exit 3,995

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-30 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. LP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit Compressor Interstage Cooling Item No H-300C

Size 51x 120 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 4368 ft2 Shells/Unit 1 Surface/Shell (Effective) 4368 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Cooling water 3rd Stage Syngas

Total Fluid Entering lb/hr 1,384,500 225,800

 Vapor 0 225,800

 Liquid 1,384,500 0

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 2,710

Liquid Density (In/Out) lb/ft3 62.000/62.000 0.000/62.250

Liquid Viscosity cP 0.762 0.558

Liquid Specific Heat Btu/lb-F 1.000 1.038

Liquid Thermal Conductivity Btu/hr-ft-F 0.363 0.368

Vapor Mol. Weight (In/Out) 0.0/0.0 16.21/16.21

Vapor Viscosity cP 0.0000 0.0164

Vapor Specific Heat Btu/lb-F 0.000 0.468

Vapor Thermal Conductivity Btu/hr-ft-F 0.000 0.051

Temperature (In/Out) °F 80.0/100.0 349.0/110.0

Operating Pressure psi(Abs) 65.000 220.000

Velocity ft/sec 3.395 26.531

Pressure Drop (Allow/Calc) psi 5.000/3.694 5.000/0.747

Fouling resistance hr-ft2-F/Btu 0.002000 0.001000

Heat Exchanged 27,690,000 Btu/hr mtd (corr) 92.157 °F

Transfer Rate, Service 68.8 Clean 88.3 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 80/ 245/

Design Temp. °F 150 400

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-15.0 19.0 

Size & Out 1-15.0 17.0 

Rating Intermediate 0 0 

Tube No 2350 OD 0.750 in Thk 0.065 Length 10.00 ft Pitch 0.93750 / 30.0°

Tube Type PLAIN Material 

Shell I.D 51.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 18.9 (Area) Spacing-cc 24.0

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 1,584 Bundle Entrance 1,413 Bundle Exit 2,336

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-31 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. LP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit Compressor Interstage Cooling Item No H-300D

Size 42x 120 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 2934 ft2 Shells/Unit 1 Surface/Shell (Effective) 2934 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Cooling water 4th Stage Syngas

Total Fluid Entering lb/hr 910,500 223,200

 Vapor 0 223,200

 Liquid 910,500 0

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 670

Liquid Density (In/Out) lb/ft3 62.000/62.000 0.000/62.210

Liquid Viscosity cP 0.762 0.580

Liquid Specific Heat Btu/lb-F 1.000 1.036

Liquid Thermal Conductivity Btu/hr-ft-F 0.363 0.367

Vapor Mol. Weight (In/Out) 0.0/0.0 16.2/16.2

Vapor Viscosity cP 0.0000 0.0160

Vapor Specific Heat Btu/lb-F 0.000 0.470

Vapor Thermal Conductivity Btu/hr-ft-F 0.000 0.049

Temperature (In/Out) °F 80.0/100.0 277.0/110.0

Operating Pressure psi(Abs) 65.000 450.000

Velocity ft/sec 3.281 17.909

Pressure Drop (Allow/Calc) psi 5.000/3.891 5.000/0.750

Fouling resistance hr-ft2-F/Btu 0.002000 0.001000

Heat Exchanged 18,210,000 Btu/hr mtd (corr) 79.340 °F

Transfer Rate, Service 78.2 Clean 104.5 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 80/ 500/

Design Temp. °F 150 330

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-12.0 15.0 

Size & Out 1-12.0 15.0 

Rating Intermediate 0 0 

Tube No 1594 OD 0.750 in Thk 0.065 Length 10.00 ft Pitch 0.93750 / 30.0°

Tube Type PLAIN Material 

Shell I.D 42.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 19.2 (Area) Spacing-cc 19.2

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 1,673 Bundle Entrance 1,289 Bundle Exit 2,454

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-32 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. LP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit ZnO Preheater Item No H-420 ZnO Preheater

Size 90x 96 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 14480 ft2 Shells/Unit 1 Surface/Shell (Effective) 14480 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Flue Gas fr. Tar Regen Sweet Syngas

Total Fluid Entering lb/hr 248,400 127,000

 Vapor 248,400 127,000

 Liquid 0 0

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 0

Liquid Density (In/Out) lb/ft3 0.000/0.000 0.000/0.000

Liquid Viscosity cP 0.000 0.000

Liquid Specific Heat Btu/lb-F 0.000 0.000

Liquid Thermal Conductivity Btu/hr-ft-F 0.000 0.000

Vapor Mol. Weight (In/Out) 27.57/27.57 10.99/10.99

Vapor Viscosity cP 0.0256 0.0182

Vapor Specific Heat Btu/lb-F 0.286 0.659

Vapor Thermal Conductivity Btu/hr-ft-F 0.024 0.076

Temperature (In/Out) °F 935.0/190.0 114.0/750.0

Operating Pressure psi(Abs) 14.500 440.000

Velocity ft/sec - -

Pressure Drop (Allow/Calc) psi 1.000/- 5.000/0.287

Fouling resistance hr-ft2-F/Btu 0.001000 0.001000

Heat Exchanged 52,900,000 Btu/hr mtd (corr) 122.52.15 °F

Transfer Rate, Service 29.82 Clean Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 30/ 480/

Design Temp. °F 990 800

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-35.0 10.0 

Size & Out 1-31.0 12.0 

Rating Intermediate 0 0 

Tube No 12160 OD 0.750 in Thk 0.065 Length 8.00 ft Pitch 0.9375 / 30.0°

Tube Type PLAIN Material 

Shell I.D 96.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 49.0 (Area) Spacing-cc 50

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle Bundle Entrance Bundle Exit

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-33 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. LP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit ZnO Syngas Cooler/BFW Preheat Item No H-421

Size 64x 144 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 6915 ft2 Shells/Unit 1 Surface/Shell (Effective) 6915 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Syngas fr ZnO Bed BFW

Total Fluid Entering lb/hr 127,000 114,306

 Vapor 127,000 0

 Liquid 0 114,306

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 0

Liquid Density (In/Out) lb/ft3 0.000/0.000 58.509/46.533

Liquid Viscosity cP 0.000 0.139

Liquid Specific Heat Btu/lb-F 0.000 1.340

Liquid Thermal Conductivity Btu/hr-ft-F 0.000 0.359

Vapor Mol. Weight (In/Out) 10.99/10.99 0.0/0.0

Vapor Viscosity cP 0.0196 0.0000

Vapor Specific Heat Btu/lb-F 0.660 0.000

Vapor Thermal Conductivity Btu/hr-ft-F 0.082 0.000

Temperature (In/Out) °F 750.0/265.0 240.0/546.5

Operating Pressure psi(Abs) 425.000 1,295.000

Velocity ft/sec 27.606 -

Pressure Drop (Allow/Calc) psi 5.000/2.034 5.000/0.399

Fouling resistance hr-ft2-F/Btu 0.001000 0.002000

Heat Exchanged 40,570,000 Btu/hr mtd (corr) 85.130 °F

Transfer Rate, Service 68.9 Clean 90.2 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 470/ 1,360/

Design Temp. °F 800 600

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-15.0 4.0 

Size & Out 1-13.0 6.0 

Rating Intermediate 0 0 

Tube No 3364 OD 0.750 in Thk 0.065 Length 12.00 ft Pitch 1.00000 / 30.0°

Tube Type PLAIN Material 

Shell I.D 64.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 18.6 (Area) Spacing-cc 24.0

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 2,297 Bundle Entrance 611 Bundle Exit 3,020

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-34 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. LP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit ZnO Syngas Cooler Item No H-422

Size 30x 96 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 1190 ft2 Shells/Unit 1 Surface/Shell (Effective) 1190 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Syngas fr H-421 Cooling Water

Total Fluid Entering lb/hr 127,000 593,000

 Vapor 127,000 0

 Liquid 0 593,000

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 0

Liquid Density (In/Out) lb/ft3 0.000/0.000 62.850/62.283

Liquid Viscosity cP 0.000 0.734

Liquid Specific Heat Btu/lb-F 0.000 1.027

Liquid Thermal Conductivity Btu/hr-ft-F 0.000 0.363

Vapor Mol. Weight (In/Out) 10.99/10.99 0.0/0.0

Vapor Viscosity cP 0.0140 0.0000

Vapor Specific Heat Btu/lb-F 0.645 0.000

Vapor Thermal Conductivity Btu/hr-ft-F 0.062 0.000

Temperature (In/Out) °F 265.0/120.0 80.0/100.0

Operating Pressure psi(Abs) 420.000 65.000

Velocity ft/sec 54.190 1.566

Pressure Drop (Allow/Calc) psi 5.000/4.440 5.000/0.420

Fouling resistance hr-ft2-F/Btu 0.001000 0.002000

Heat Exchanged 11,860,000 Btu/hr mtd (corr) 88.210 °F

Transfer Rate, Service 113.0 Clean 184.6 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 465/ 80/

Design Temp. °F 315 150

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-13.0 10.0 

Size & Out 1-12.0 10.0 

Rating Intermediate 0 0 

Tube No 802 OD 0.750 in Thk 0.065 Length 8.00 ft Pitch 0.93750 / 30.0°

Tube Type PLAIN Material 

Shell I.D 30.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection NO

Baffles Cross Type VERT- SEG %Cut 32.3 (Area) Spacing-cc 24.0

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 2,469 Bundle Entrance 3,979 Bundle Exit 4,341

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-35 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. LP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit MeOH Compressor Interstage Cooling Item No H-500A

Size 24x 72 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 511 ft2 Shells/Unit 1 Surface/Shell (Effective) 511 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Cooling water Syngas

Total Fluid Entering lb/hr 553,000 127,000

 Vapor 0 127,000

 Liquid 553,000 0

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 0

Liquid Density (In/Out) lb/ft3 62.000/62.000 0.000/0.000

Liquid Viscosity cP 0.762 0.000

Liquid Specific Heat Btu/lb-F 1.000 0.000

Liquid Thermal Conductivity Btu/hr-ft-F 0.363 0.000

Vapor Mol. Weight (In/Out) 0.0/0.0 10.99/10.99

Vapor Viscosity cP 0.0000 0.0155

Vapor Specific Heat Btu/lb-F 0.000 0.655

Vapor Thermal Conductivity Btu/hr-ft-F 0.000 0.068

Temperature (In/Out) °F 80.0/100.0 333.0/200.0

Operating Pressure psi(Abs) 65.000 1,000.000

Velocity ft/sec 4.182 25.131

Pressure Drop (Allow/Calc) psi 5.000/2.552 5.000/0.721

Fouling resistance hr-ft2-F/Btu 0.002000 0.001000

Heat Exchanged 11,060,000 Btu/hr mtd (corr) 170.297 °F

Transfer Rate, Service 127.1 Clean 215.4 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 80/ 1,050/

Design Temp. °F 150 385

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-10.0 12.0 

Size & Out 1-10.0 10.0 

Rating Intermediate 0 0 

Tube No 476 OD 0.750 in Thk 0.065 Length 6.00 ft Pitch 0.93750 / 30.0°

Tube Type PLAIN Material 

Shell I.D 24.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 23.4 (Area) Spacing-cc 16.3

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 1,279 Bundle Entrance 1,349 Bundle Exit 2,039

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-36 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. LP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit MeOH Syngas Preheat Item No H-501

Size 73x 168 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 12712 ft2 Shells/Unit 1 Surface/Shell (Effective) 12712 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Steam Syngas to MeOH Rxn

Total Fluid Entering lb/hr 18,830 127,000

 Vapor 18,830 127,000

 Liquid 0 0

 Steam

 Noncondensable

Fluid Vaporized or Condensed 18,830 0

Liquid Density (In/Out) lb/ft3 0.000/52.387 0.000/0.000

Liquid Viscosity cP 0.148 0.000

Liquid Specific Heat Btu/lb-F 1.120 0.000

Liquid Thermal Conductivity Btu/hr-ft-F 0.404 0.000

Vapor Mol. Weight (In/Out) 18.02/18.02 10.99/10.99

Vapor Viscosity cP 0.0161 0.0170

Vapor Specific Heat Btu/lb-F 0.492 0.659

Vapor Thermal Conductivity Btu/hr-ft-F 0.020 0.074

Temperature (In/Out) °F 487.0/324.0 239.0/460.0

Operating Pressure psi(Abs) 100.000 1,160.000

Velocity ft/sec 4.726 2.192

Pressure Drop (Allow/Calc) psi 5.000/0.548 5.000/0.492

Fouling resistance hr-ft2-F/Btu 0.005000 0.001000

Heat Exchanged 18,450,000 Btu/hr mtd (corr) 60.365 °F

Transfer Rate, Service 24.0 Clean 28.3 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 100/ 1,220/

Design Temp. °F 540 515

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-8.0 10.0 

Size & Out 1-2.0 12.0 

Rating Intermediate 0 0 

Tube No 5242 OD 0.750 in Thk 0.065 Length 14.00 ft Pitch 0.93750 / 30.0°

Tube Type PLAIN Material 

Shell I.D 73.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection NO

Baffles Cross Type VERT- SEG %Cut 10.4 (Area) Spacing-cc 14.5

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 1,228 Bundle Entrance 1,623 Bundle Exit 1,384

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-37 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Heat Exchanger Specification sheet

Job No. 

Customer NREL Ref No. LP Syngas Case

Address Proposal No.

Plant Location Date Rev. 0

Service of Unit Blowdown Cooler Item No H-601

Size 12x 48 Type BEM - HORZ Connected in 1 Parallel 1 Series

Surf/Unit (Eff) 89 ft2 Shells/Unit 1 Surface/Shell (Effective) 89 ft2

PERFORMANCE OF ONE UNIT

Fluid Allocation Shellside Tubeside

Fluid Name Blowdown Cooling water

Total Fluid Entering lb/hr 3,164 30,465

 Vapor 0 0

 Liquid 3,164 30,465

 Steam

 Noncondensable

Fluid Vaporized or Condensed 0 0

Liquid Density (In/Out) lb/ft3 56.607/62.000 62.000/62.000

Liquid Viscosity cP 0.311 0.762

Liquid Specific Heat Btu/lb-F 1.059 1.000

Liquid Thermal Conductivity Btu/hr-ft-F 0.382 0.363

Vapor Mol. Weight (In/Out) 0.0/0.0 0.0/0.0

Vapor Viscosity cP 0.0000 0.0000

Vapor Specific Heat Btu/lb-F 0.000 0.000

Vapor Thermal Conductivity Btu/hr-ft-F 0.000 0.000

Temperature (In/Out) °F 298.0/110.0 80.0/100.0

Operating Pressure psi(Abs) 65.000 65.000

Velocity ft/sec 0.170 0.561

Pressure Drop (Allow/Calc) psi 5.000/0.111 5.000/0.536

Fouling resistance hr-ft2-F/Btu 0.001000 0.002000

Heat Exchanged 609,300 Btu/hr mtd (corr) 89.027 °F

Transfer Rate, Service 76.9 Clean 104.4 Btu/hr-ft2-F

CONSTRUCTION OF ONE SHELL

 Shellside Tubeside Sketch

Design/Test Pres. psi 80/ 80/

Design Temp. °F 350 150

No. Passes per Shell 1 1

Corrosion Allow. in 0.0625 0.0625

Connections In 1-1.0 2.0 

Size & Out 1-1.0 2.0 

Rating Intermediate 0 0 

Tube No 116 OD 0.750 in Thk 0.065 Length 4.00 ft Pitch 0.93750 / 30.0°

Tube Type PLAIN Material 

Shell I.D 12.00 OD in Shell Cover INT

Channel or Bonnet Channel Cover 

Tubesheet-Stationary Tubesheet-Floating 

Floating Head Cover Impingement Protection YES

Baffles Cross Type VERT- SEG %Cut 10.1 (Area) Spacing-cc 2.3

Baffles-Long Seal Type 

Supports-Tube U-Bend Type 

Bypass Seal Arrangement Tube-Tubesheet Joint 

Expansion Joint Type 

Rho-V2 Inlet Nozzle 459 Bundle Entrance 10 Bundle Exit 268

Gasket-Shellside Tubeside Floating Head 

Code Requirement ASME Section 8, Divsion 1 TEMA Class R

Weight/Shell Filled with Water Bundle

Remarks: 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-38 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

COMPRESSOR NUMBER

GAS HANDLED

NORMAL FLOW SCFM

NORMAL FLOW LB/HR

DESIGN FLOW SCFM

MOL WT.

Value

 @ F / PSIA

SUCTION CONDITIONS

SUCTION PRESSURE PSIA

COMPR. FACTOR @ SUCTION

FLOW AT SUCTION ACFM

ORIGIN PSIA

TEMPERATURE F

LINE LOSS PSI (2)

OTHER LOSSES PSI (1, 2)

CONTINGENCY PSI

DISCHARGE CONDITIONS

DISCH. PRESSURE PSIA

DISCH. TEMPERATURE F (2)

COMPR. FACTOR @ DISCH.

DELIVERY PSIA

LINE LOSS PSI (2)

EXCHANGER LOSS PSI (2)

HEATER LOSS PSI (2)

CONTROL VALVE LOSS PSI (2)

OTHER LOSSES PSI (2)

CONTINGENCY PSI (2)

TOTAL LOSSES PSI (2)

COMPRESSION RATIO

EFFICIENCY (2)

BHP (2)

COMPRESSOR TYPE

DRIVER TYPE

GAS COMPOSITION: Vol. %

H2O

O2

Ar

N2

DATE PROC PROJ. CLIENT

JOB NO

REV

NO

SERVICE

Cp/Cv

3.1

0.9

75.7

20.3

1600

1.36

0.75

20

90 / 14.7

28.63

1.4

235,200

Air

51,965

K-100

Combustion Air

NREL Contract ACO-5-44027

NREL BIOMASS GASIFICATION: Low Pressure Syngas Case (BLC Gasifier)

REVISIONS

DRAWING NO

(1) INCLUDES ALLOWANCE FOR SUCTION OR DISCHARGE SNUBBER

(2) VALUE TABULATED IS ESTIMATED AND MUST BE VERIFIED BY FINAL MECHANICAL DESIGN

14.7

0.999

157

54,910

90

0.999

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-39 

Appendix C 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 

COMPRESSOR NUMBER

GAS HANDLED

NORMAL FLOW SCFM

NORMAL FLOW LB/HR

DESIGN FLOW SCFM

MOL WT.

Value

 @ F / PSIA

SUCTION CONDITIONS

SUCTION PRESSURE PSIA

COMPR. FACTOR @ SUCTION

FLOW AT SUCTION ACFM

ORIGIN PSIA

TEMPERATURE F

LINE LOSS PSI (2)

OTHER LOSSES PSI (1, 2)

CONTINGENCY PSI

DISCHARGE CONDITIONS

DISCH. PRESSURE PSIA

DISCH. TEMPERATURE F (2)

COMPR. FACTOR @ DISCH.

DELIVERY PSIA

LINE LOSS PSI (2)

EXCHANGER LOSS PSI (2)

HEATER LOSS PSI (2)

CONTROL VALVE LOSS PSI (2)

OTHER LOSSES PSI (2)

CONTINGENCY PSI (2)

TOTAL LOSSES PSI (2)

COMPRESSION RATIO

EFFICIENCY (2)

BHP (2)

COMPRESSOR TYPE

DRIVER TYPE

GAS COMPOSITION: Vol. %

H2O

O2

Ar

N2

DATE PROC PROJ. CLIENT

JOB NO

REV

NO

SERVICE

Cp/Cv

3.1

0.9

75.7

20.3

1600

1.36

0.75

20

90 / 14.7

28.63

1.4

235,200

Air

51,965

K-100

Combustion Air

NREL Contract ACO-5-44027

NREL BIOMASS GASIFICATION: Low Pressure Syngas Case (BLC Gasifier)

REVISIONS

DRAWING NO

(1) INCLUDES ALLOWANCE FOR SUCTION OR DISCHARGE SNUBBER

(2) VALUE TABULATED IS ESTIMATED AND MUST BE VERIFIED BY FINAL MECHANICAL DESIGN

14.7

0.999

157

54,910

90

0.999

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

COMPRESSOR NUMBER

GAS HANDLED

NORMAL FLOW SCFM

NORMAL FLOW LB/HR

DESIGN FLOW SCFM

MOL WT.

Value

 @ F / PSIA

SUCTION CONDITIONS

SUCTION PRESSURE PSIA

COMPR. FACTOR @ SUCTION

FLOW AT SUCTION ACFM

ORIGIN PSIA

TEMPERATURE F

LINE LOSS PSI (2)

OTHER LOSSES PSI (1, 2)

CONTINGENCY PSI

DISCHARGE CONDITIONS

DISCH. PRESSURE PSIA

DISCH. TEMPERATURE F (2)

COMPR. FACTOR @ DISCH.

DELIVERY PSIA

LINE LOSS PSI (2)

EXCHANGER LOSS PSI (2)

HEATER LOSS PSI (2)

CONTROL VALVE LOSS PSI (2)

OTHER LOSSES PSI (2)

CONTINGENCY PSI (2)

TOTAL LOSSES PSI (2)

COMPRESSION RATIO

EFFICIENCY (2)

BHP (2)

COMPRESSOR TYPE

DRIVER TYPE

GAS COMPOSITION: Vol. %

H2

CO2

CO

H2O

CH4

C2H2

C2H4

C2H6

Benzene (C6H6)

Tar (C10H8)

Ammonia (NH3)

H2S

N2

DATE PROC PROJ. CLIENT

JOB NO

REV

0.06 0.08 0.08 0.08

0.01 0.01 0.01 0.01

0.000006 0.000007

0.03 0.04 0.04 0.04

0 0.00001 0.000001 0.000001

(1) INCLUDES ALLOWANCE FOR SUCTION OR DISCHARGE SNUBBER

(2) VALUE TABULATED IS ESTIMATED AND MUST BE VERIFIED BY FINAL MECHANICAL DESIGN

NREL Contract ACO-5-44027

NREL BIOMASS GASIFICATION: Low Pressure Syngas Case (BCL Gasifier)

REVISIONS

K-300A - Stage 1 K-300B - Stage 2 K-300C - Stage 3

Syngas 

Compressor Stage 

1

Syngas Compressor 

Stage 2

Syngas 

Compressor Stage 

3

Syngas Syngas Syngas

120,208 90,448 88,044

317,371 232,617 225,773

16.7 16.26 16.21

1.36 1.374 1.379

157 / 15.88 110 / 30 110 / 79

157.1 110 110

15.88 30 79

0.9979 0.999 0.9985

131,756 48,531 17,936

1.001 1.003

35 84 220

344.2 349.6 349.1

0.9982

2.204 2.8 2.78

0.75 0.75 0.75

11,248 10,251 10,251

52.87 54.32

12.36 16.42 16.87

25.15

27.97 4.28 1.67

0.23

0.00002

1.19 1.58 1.62

0.02 0.02

0 0.000006

SERVICE

Cp/Cv

0 0.00001

0.02

0.02 0.22

18.42 24.48

39.79

NO

1.005

2.093

0.75

7,036

110 / 215

0.9972

6,513

450

277

DRAWING NO

54.88

K-300D - Stage 4

Syngas 

Compressor Stage 

4

Syngas

87,158

223,220

16.2

215

110

1.39

17.04

25.41

0.00002

0.66

1.64

0.02

0.23

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-40 

Appendix C 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 

COMPRESSOR NUMBER

GAS HANDLED

NORMAL FLOW SCFM

NORMAL FLOW LB/HR

DESIGN FLOW SCFM

MOL WT.

Value

 @ F / PSIA

SUCTION CONDITIONS

SUCTION PRESSURE PSIA

COMPR. FACTOR @ SUCTION

FLOW AT SUCTION ACFM

ORIGIN PSIA

TEMPERATURE F

LINE LOSS PSI (2)

OTHER LOSSES PSI (1, 2)

CONTINGENCY PSI

DISCHARGE CONDITIONS

DISCH. PRESSURE PSIA

DISCH. TEMPERATURE F (2)

COMPR. FACTOR @ DISCH.

DELIVERY PSIA

LINE LOSS PSI (2)

EXCHANGER LOSS PSI (2)

HEATER LOSS PSI (2)

CONTROL VALVE LOSS PSI (2)

OTHER LOSSES PSI (2)

CONTINGENCY PSI (2)

TOTAL LOSSES PSI (2)

COMPRESSION RATIO

EFFICIENCY (2)

BHP (2)

COMPRESSOR TYPE

DRIVER TYPE

GAS COMPOSITION: Vol. %

H2

CO2

CO

H2O

CH4

C2H2

C2H4

C2H6

Benzene (C6H6)

Tar (C10H8)

Ammonia (NH3)

H2S

N2

DATE PROC PROJ. CLIENT

JOB NO

REV

0.06 0.08 0.08 0.08

0.01 0.01 0.01 0.01

0.000006 0.000007

0.03 0.04 0.04 0.04

0 0.00001 0.000001 0.000001

(1) INCLUDES ALLOWANCE FOR SUCTION OR DISCHARGE SNUBBER

(2) VALUE TABULATED IS ESTIMATED AND MUST BE VERIFIED BY FINAL MECHANICAL DESIGN

NREL Contract ACO-5-44027

NREL BIOMASS GASIFICATION: Low Pressure Syngas Case (BCL Gasifier)

REVISIONS

K-300A - Stage 1 K-300B - Stage 2 K-300C - Stage 3

Syngas 

Compressor Stage 

1

Syngas Compressor 

Stage 2

Syngas 

Compressor Stage 

3

Syngas Syngas Syngas

120,208 90,448 88,044

317,371 232,617 225,773

16.7 16.26 16.21

1.36 1.374 1.379

157 / 15.88 110 / 30 110 / 79

157.1 110 110

15.88 30 79

0.9979 0.999 0.9985

131,756 48,531 17,936

1.001 1.003

35 84 220

344.2 349.6 349.1

0.9982

2.204 2.8 2.78

0.75 0.75 0.75

11,248 10,251 10,251

52.87 54.32

12.36 16.42 16.87

25.15

27.97 4.28 1.67

0.23

0.00002

1.19 1.58 1.62

0.02 0.02

0 0.000006

SERVICE

Cp/Cv

0 0.00001

0.02

0.02 0.22

18.42 24.48

39.79

NO

1.005

2.093

0.75

7,036

110 / 215

0.9972

6,513

450

277

DRAWING NO

54.88

K-300D - Stage 4

Syngas 

Compressor Stage 

4

Syngas

87,158

223,220

16.2

215

110

1.39

17.04

25.41

0.00002

0.66

1.64

0.02

0.23

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

COMPRESSOR NUMBER

GAS HANDLED

NORMAL FLOW SCFM

NORMAL FLOW LB/HR

DESIGN FLOW SCFM

MOL WT.

Value

 @ F / PSIA

SUCTION CONDITIONS

SUCTION PRESSURE PSIA

COMPR. FACTOR @ SUCTION

FLOW AT SUCTION ACFM

ORIGIN PSIA

TEMPERATURE F

LINE LOSS PSI (2)

OTHER LOSSES PSI (1, 2)

CONTINGENCY PSI

DISCHARGE CONDITIONS

DISCH. PRESSURE PSIA

DISCH. TEMPERATURE F (2)

COMPR. FACTOR @ DISCH.

DELIVERY PSIA

LINE LOSS PSI (2)

EXCHANGER LOSS PSI (2)

HEATER LOSS PSI (2)

CONTROL VALVE LOSS PSI (2)

OTHER LOSSES PSI (2)

CONTINGENCY PSI (2)

TOTAL LOSSES PSI (2)

COMPRESSION RATIO

EFFICIENCY (2)

BHP (2)

COMPRESSOR TYPE

DRIVER TYPE

GAS COMPOSITION: Vol. %

CO2

H2O

O2

Ar

N2

DATE PROC PROJ. CLIENT

JOB NO

REV

NO

SERVICE

Cp/Cv

75.67

0.03

20.29

0.91

3.1

177

1.028

0.75

14.7

176 / 14.3

27.57

1.367

248,400

Flue Gas

56,988

K-420

Flue Gas Blower

NREL Contract ACO-5-44027

NREL BIOMASS GASIFICATION: Low Pressure Syngas Case (BCL Gasifier)

REVISIONS

DRAWING NO

(1) INCLUDES ALLOWANCE FOR SUCTION OR DISCHARGE SNUBBER

(2) VALUE TABULATED IS ESTIMATED AND MUST BE VERIFIED BY FINAL MECHANICAL DESIGN

14.3

0.9982

182

71,490

175.8

0.9982

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-41 

Appendix C 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 

COMPRESSOR NUMBER

GAS HANDLED

NORMAL FLOW SCFM

NORMAL FLOW LB/HR

DESIGN FLOW SCFM

MOL WT.

Value

 @ F / PSIA

SUCTION CONDITIONS

SUCTION PRESSURE PSIA

COMPR. FACTOR @ SUCTION

FLOW AT SUCTION ACFM

ORIGIN PSIA

TEMPERATURE F

LINE LOSS PSI (2)

OTHER LOSSES PSI (1, 2)

CONTINGENCY PSI

DISCHARGE CONDITIONS

DISCH. PRESSURE PSIA

DISCH. TEMPERATURE F (2)

COMPR. FACTOR @ DISCH.

DELIVERY PSIA

LINE LOSS PSI (2)

EXCHANGER LOSS PSI (2)

HEATER LOSS PSI (2)

CONTROL VALVE LOSS PSI (2)

OTHER LOSSES PSI (2)

CONTINGENCY PSI (2)

TOTAL LOSSES PSI (2)

COMPRESSION RATIO

EFFICIENCY (2)

BHP (2)

COMPRESSOR TYPE

DRIVER TYPE

GAS COMPOSITION: Vol. %

CO2

H2O

O2

Ar

N2

DATE PROC PROJ. CLIENT

JOB NO

REV

NO

SERVICE

Cp/Cv

75.67

0.03

20.29

0.91

3.1

177

1.028

0.75

14.7

176 / 14.3

27.57

1.367

248,400

Flue Gas

56,988

K-420

Flue Gas Blower

NREL Contract ACO-5-44027

NREL BIOMASS GASIFICATION: Low Pressure Syngas Case (BCL Gasifier)

REVISIONS

DRAWING NO

(1) INCLUDES ALLOWANCE FOR SUCTION OR DISCHARGE SNUBBER

(2) VALUE TABULATED IS ESTIMATED AND MUST BE VERIFIED BY FINAL MECHANICAL DESIGN

14.3

0.9982

182

71,490

175.8

0.9982

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

COMPRESSOR NUMBER

GAS HANDLED

NORMAL FLOW SCFM

NORMAL FLOW LB/HR

DESIGN FLOW SCFM

MOL WT.

Value

 @ F / PSIA

SUCTION CONDITIONS

SUCTION PRESSURE PSIA

COMPR. FACTOR @ SUCTION

FLOW AT SUCTION ACFM

ORIGIN PSIA

TEMPERATURE F

LINE LOSS PSI (2)

OTHER LOSSES PSI (1, 2)

CONTINGENCY PSI

DISCHARGE CONDITIONS

DISCH. PRESSURE PSIA

DISCH. TEMPERATURE F (2)

COMPR. FACTOR @ DISCH.

DELIVERY PSIA

LINE LOSS PSI (2)

EXCHANGER LOSS PSI (2)

HEATER LOSS PSI (2)

CONTROL VALVE LOSS PSI (2)

OTHER LOSSES PSI (2)

CONTINGENCY PSI (2)

TOTAL LOSSES PSI (2)

COMPRESSION RATIO

EFFICIENCY (2)

BHP (2)

COMPRESSOR TYPE

DRIVER TYPE

GAS COMPOSITION: Vol. %

H2

CO2

CO

H20

CH4

C2H2

C2H4

C2H6

Benzene (C6H6)

Tar (C10H8)

NH3

N2

DATE PROC PROJ. CLIENT

JOB NO

REV

0.000001 0.000001

0.000008 0.000008

0.01 0.01

239.3

1.023 1.026

(1) INCLUDES ALLOWANCE FOR SUCTION OR DISCHARGE SNUBBER

(2) VALUE TABULATED IS ESTIMATED AND MUST BE VERIFIED BY FINAL MECHANICAL DESIGN

NREL Contract ACO-5-44027

NREL BIOMASS GASIFICATION: Low Pressure Syngas Case (BCL Gasifier)

REVISIONS

DRAWING NO

K-500A K-500B

MeOH Compressor 

Stage 1

MeOH Compressor 

Stage 2

Treated Syngas Treated Syngas

73,055 73,055

127,035 127,035

10.99 10.99

1.418 1.424

115 / 415 200 / 995

110 200

415 995

1.006 1.021

2,881 1,400

1,000 1,160

326

2.41 1.17

0.75 0.75

7,377 1,340

65.45 65.45

1.63 1.63

30.3 30.3

0.26 0.26

1.96 1.96

0.03

0.28 0.28

SERVICE

Cp/Cv

0.00002 0.00002

0.095 0.095

0.03

NO

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-42 

Appendix C 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 

COMPRESSOR NUMBER

GAS HANDLED

NORMAL FLOW SCFM

NORMAL FLOW LB/HR

DESIGN FLOW SCFM

MOL WT.

Value

 @ F / PSIA

SUCTION CONDITIONS

SUCTION PRESSURE PSIA

COMPR. FACTOR @ SUCTION

FLOW AT SUCTION ACFM

ORIGIN PSIA

TEMPERATURE F

LINE LOSS PSI (2)

OTHER LOSSES PSI (1, 2)

CONTINGENCY PSI

DISCHARGE CONDITIONS

DISCH. PRESSURE PSIA

DISCH. TEMPERATURE F (2)

COMPR. FACTOR @ DISCH.

DELIVERY PSIA

LINE LOSS PSI (2)

EXCHANGER LOSS PSI (2)

HEATER LOSS PSI (2)

CONTROL VALVE LOSS PSI (2)

OTHER LOSSES PSI (2)

CONTINGENCY PSI (2)

TOTAL LOSSES PSI (2)

COMPRESSION RATIO

EFFICIENCY (2)

BHP (2)

COMPRESSOR TYPE

DRIVER TYPE

GAS COMPOSITION: Vol. %

H2

CO2

CO

H20

CH4

C2H2

C2H4

C2H6

Benzene (C6H6)

Tar (C10H8)

NH3

N2

DATE PROC PROJ. CLIENT

JOB NO

REV

0.000001 0.000001

0.000008 0.000008

0.01 0.01

239.3

1.023 1.026

(1) INCLUDES ALLOWANCE FOR SUCTION OR DISCHARGE SNUBBER

(2) VALUE TABULATED IS ESTIMATED AND MUST BE VERIFIED BY FINAL MECHANICAL DESIGN

NREL Contract ACO-5-44027

NREL BIOMASS GASIFICATION: Low Pressure Syngas Case (BCL Gasifier)

REVISIONS

DRAWING NO

K-500A K-500B

MeOH Compressor 

Stage 1

MeOH Compressor 

Stage 2

Treated Syngas Treated Syngas

73,055 73,055

127,035 127,035

10.99 10.99

1.418 1.424

115 / 415 200 / 995

110 200

415 995

1.006 1.021

2,881 1,400

1,000 1,160

326

2.41 1.17

0.75 0.75

7,377 1,340

65.45 65.45

1.63 1.63

30.3 30.3

0.26 0.26

1.96 1.96

0.03

0.28 0.28

SERVICE

Cp/Cv

0.00002 0.00002

0.095 0.095

0.03

NO

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

COMPRESSOR NUMBER

GAS HANDLED

NORMAL FLOW SCFM

NORMAL FLOW LB/HR

DESIGN FLOW SCFM

MOL WT.

Value

 @ F / PSIA

SUCTION CONDITIONS

SUCTION PRESSURE PSIA

COMPR. FACTOR @ SUCTION

FLOW AT SUCTION ACFM

ORIGIN PSIA

TEMPERATURE F

LINE LOSS PSI (2)

OTHER LOSSES PSI (1, 2)

CONTINGENCY PSI

DISCHARGE CONDITIONS

DISCH. PRESSURE PSIA

DISCH. TEMPERATURE F (2)

COMPR. FACTOR @ DISCH.

DELIVERY PSIA

LINE LOSS PSI (2)

EXCHANGER LOSS PSI (2)

HEATER LOSS PSI (2)

CONTROL VALVE LOSS PSI (2)

OTHER LOSSES PSI (2)

CONTINGENCY PSI (2)

TOTAL LOSSES PSI (2)

COMPRESSION RATIO

EFFICIENCY (2)

kW Generated (2)

Turbine TYPE

DRIVER TYPE

GAS COMPOSITION: Vol. %

H2

CO2

CO

H20

CH4

C2H2

C2H4

C2H6

Benzene (C6H6)

Tar (C10H8)

NH3

N2

DATE PROC PROJ. CLIENT

JOB NO

REV

376

0.977 0.9833

(1) INCLUDES ALLOWANCE FOR SUCTION OR DISCHARGE SNUBBER

(2) VALUE TABULATED IS ESTIMATED AND MUST BE VERIFIED BY FINAL MECHANICAL DESIGN

NREL Contract ACO-5-44027

NREL BIOMASS GASIFICATION: Low Pressure Syngas Case (BCL Gasifier)

REVISIONS

DRAWING NO

M-601A M-601B

Steam Turbine - 

Extraction Stage 1

Steam Turbine - 

Extraction Stage 2

Steam Steam 

88,402 81,815

251,800 232,900

18.02 18.02

1.384 1.336

1000 / 1265 564.8 / 165

1000 487

1265 100

0.9332 0.977

2,691 21,390

100 50

487

- -

0.75 0.75

16,067 3,343

Steam Steam

SERVICE

Cp/Cv

100% 100%

NO

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-43 

Appendix C 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 

COMPRESSOR NUMBER

GAS HANDLED

NORMAL FLOW SCFM

NORMAL FLOW LB/HR

DESIGN FLOW SCFM

MOL WT.

Value

 @ F / PSIA

SUCTION CONDITIONS

SUCTION PRESSURE PSIA

COMPR. FACTOR @ SUCTION

FLOW AT SUCTION ACFM

ORIGIN PSIA

TEMPERATURE F

LINE LOSS PSI (2)

OTHER LOSSES PSI (1, 2)

CONTINGENCY PSI

DISCHARGE CONDITIONS

DISCH. PRESSURE PSIA

DISCH. TEMPERATURE F (2)

COMPR. FACTOR @ DISCH.

DELIVERY PSIA

LINE LOSS PSI (2)

EXCHANGER LOSS PSI (2)

HEATER LOSS PSI (2)

CONTROL VALVE LOSS PSI (2)

OTHER LOSSES PSI (2)

CONTINGENCY PSI (2)

TOTAL LOSSES PSI (2)

COMPRESSION RATIO

EFFICIENCY (2)

kW Generated (2)

Turbine TYPE

DRIVER TYPE

GAS COMPOSITION: Vol. %

H2

CO2

CO

H20

CH4

C2H2

C2H4

C2H6

Benzene (C6H6)

Tar (C10H8)

NH3

N2

DATE PROC PROJ. CLIENT

JOB NO

REV

376

0.977 0.9833

(1) INCLUDES ALLOWANCE FOR SUCTION OR DISCHARGE SNUBBER

(2) VALUE TABULATED IS ESTIMATED AND MUST BE VERIFIED BY FINAL MECHANICAL DESIGN

NREL Contract ACO-5-44027

NREL BIOMASS GASIFICATION: Low Pressure Syngas Case (BCL Gasifier)

REVISIONS

DRAWING NO

M-601A M-601B

Steam Turbine - 

Extraction Stage 1

Steam Turbine - 

Extraction Stage 2

Steam Steam 

88,402 81,815

251,800 232,900

18.02 18.02

1.384 1.336

1000 / 1265 564.8 / 165

1000 487

1265 100

0.9332 0.977

2,691 21,390

100 50

487

- -

0.75 0.75

16,067 3,343

Steam Steam

SERVICE

Cp/Cv

100% 100%

NO

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Site Location (Note: Four (4) parallel cyclones) Date Rev.

Flow Viscosity Density

Molecular 

Weight 

(Ave.)

Particle 

Size (mm) 

(Stokes' 

MMD)

Volumetric 

Flowrate Temperature 

lb/h lb/ft-sec lb/ft3 lb/mole acfm °F

316,369.00 2.35 x 10-5 0.03500 18.7 150,652.00 1,598

40,407.00 62.40 60

33.00

32.64

10.48

33.00

50

98

Emery Design Calculations Summary for S-100 (for Reference Only)

Mechanical Sizing Inside 

Diam (in)

Uninsulated 

Outside Diam 

(in)

ID (in) OD (in) Thickness (in) Designation Overall Height 

(ft)

In 48 58 Upper Shell 82 84 1 ASME VIII 35

Out 36 46 Inner Tube 36

Bottom TBD Cone 1 ASME VIII

Refractory 74 4

Design 

Temperature 

(°F)

Solids 

Removal 

Flowrate 

(CFM)

Differential 

Design 

Pressure 

(psig)

Type

Rotary Air Lock 1598 Inner Wall Outer Shell Inner Wall Outer Shell Inner Wall Outer Shell

Level Indicator 1598 CercastTM MS CercastTM MS CercastTM MS

Inner Tube

MS

Fisher-Klosterman, Inc (Refer to Vendor Communications and Data Sheets)

Ryan Bruner, Sales Manager

P.O. Box 11190

Lousville, Ky

Ph: 502-572-4000 ext 213

Email: rab@fkinc.com

Recommendation: Replace S-100 and S-101 with 4 cyclones operated in parallel using split air flow:

Four (4) XQ120-48M cyclone assemblies each with the following Features:

Design, fabricated, tested, and stamped as an ASME vessel Interior surfaces to be lined with 4" of Vesuvius Cercast 3300 castable refractory

3/8" plate carbon steel construction All welding per FKI Class 3 preocedures with 100% penetration

Dust receiver section with flanged discharge Exterior to be sandblasted and painted with high temperature aluminum paint

40"∅ gas inlet flange Design pressure (psig) 33

48"∅ verticle gas outlet flange Design Temperature (F) 650

Approximate Overall Dimensions: 7 ft∅ x 35 ft tall

Gas Conditions at Inlet: Particulate Conditions at Inlet:

Volume per cylone (acfm) 37,663 Specific Gravity 1.000

Density (lbm/ft3) 0.035 Dust Loading (Grains/acf) 31.3

Viscosity (lbm/ft-sec) 2.53E-05

Inlet Velocity (ft/sec) 78.46 Fraction Efficiencies: Stokes Equiv. % Efficiency

No load pres. drop (in.W.C.) 12.6 Dia.(microns) Weight %

Full load pres. Drop (in. W.C.) 10.02 3 7.37

3.5 16.3

4 21.44

4.5 26.75

5 32.07

5.5 37.27

6.5 42.27

7.5 51.48

8.5 59.48

9.5 66.29

10.5 71.99

13 82.36

17 89.12

24 94.36

34 97.39

89 99.83

Price (2005 U.S.$) 1,225,000.00 $ 

Design Particulate Cutpoint

Design Separation Efficiency at Cutpoint (%)

Cyclone Specification Sheet

Remarks: Inlet and outlet manifolding is not included in Fisher-Klosterman quote for these four cylones. Estimated cost of splitter and collection is $25,000. 

Refer to supplier data sheet for Vesuvius CERCASTTM 3300 Castable refractory. 

SERVICE OF LOW PRESSURE UNIT S-100 and S-101

Nozzles

Gas Discharge Pressure (psig)

Pressure Drop, Max Allow. (" .WC.)

Gas Inlet Pressure (psia)

Component Data

Inlet Conditions

Vendor/Supplier Specifications and Price Quote

Gas (Split into four parallel flows)

Particulate

Design/Test Pressure Psig

Upper Section Lower Conical section

Cyclone Body Materials of Construction

Connections Size 

& Rating

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-44 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Site Location Date Rev.

Flow Viscosity Density

Molecular 

Weight 

(Ave.)

Particle 

Size (mm) 

(Stokes' 

MMD)

Volumetric 

Flowrate Temperature 

lb/h BTU/lb°F lb/ft3 lb/mole acfm °F

328,979.00 2.78E-05 0.34470 16.7 150,612.01 1,598

40,407.00 62.40 60

33.00

32.64

10.00

33.00

50

98

Emery Design Calculations Summary for S-102 (for Reference Only)

Mechanical Sizing Inside Diam 

(in)

Uninsulated 

Outside Diam 

(in)

ID (in) OD (in) Thickness (in) Designation Overall Height 

(ft)

In 34 44 Upper Shell 58 60 1 ASME VIII 25

Out 26 36 Inner Tube 34

Bottom Cone 1 ASME VIII

Refractory 50 4

Design 

Temperature 

(°F)

Solids 

Removal 

Flowrate 

(CFM)

Differential 

Design 

Pressure 

(psig)

Type

Rotary Air Lock 1598 20.4 15 Inner Wall Outer Shell Inner Wall Outer Shell Inner Wall Outer Shell

Level Indicator 1598 CercastTM MS CercastTM MS CercastTM MS

Inner Tube

MS

Fisher-Klosterman, Inc (Refer to Vendor Communications and Data Sheets)

Ryan Bruner, Sales Manager

P.O. Box 11190

Lousville, Ky

Ph: 502-572-4000 ext 213

Email: rab@fkinc.com

Recommendation: Quote Pending

Four (4) XQ120-48M cyclone assemblies each with the following Features:

Design, fabricated, tested, and stamped as an ASME vessel Interior surfaces to be lined with 4" of Vesuvius Cercast 3300 castable refractory

3/8" plate carbon steel construction All welding per FKI Class 3 preocedures with 100% penetration

Dust receiver section with flanged discharge Exterior to be sandblasted and painted with high temperature aluminum paint

40"∅ gas inlet flange Design pressure (psig) 460

48"∅ verticle gas outlet flange Design Temperature (F) 650

Approximate Overall Dimensions:

Gas Conditions at Inlet: Particulate Conditions at Inlet:

Volume per cylone (acfm) 15,906 Specific Gravity 1.000

Density (lbm/ft3) 0.3447 Dust Loading (Grains/acf) 7.33

Viscosity (lbm/ft-sec) 2.78E-05

Inlet Velocity (ft/sec) 70.11 Fraction Efficiencies: Stokes Equiv. % Efficiency

No load pres. drop (in.W.C.) 73.64 Dia.(microns) Weight %

Full load pres. Drop (in. W.C.) 63.69 2.5 4.91

3.5 12.88

4.5 22.89

5 28.13

5.5 33.31

6 38.34

7 47.7

8 55.93

9 63

10 68.97

11 73.98

13 81.64

17 88.65

24 94.08

34 97.25

74 99.67

Upper Section Lower Conical section

Cyclone Body Materials of Construction

Connections Size 

& Rating

Gas

Particulate

Design/Test Pressure Psig

Cyclone Specification Sheet

Remarks: Inlet and outlet manifolding is not included in Fisher-Klosterman quote for these four cylones. Estimated cost of splitter and collection is $25,000. 

Refer to supplier data sheet for Vesuvius CERCASTTM 3300 Castable refractory. 

SERVICE OF LOW PRESSURE UNIT S-102

Nozzles

Gas Discharge Pressure (psig)

Pressure Drop, Max Allow. (" .WC.)

Gas Inlet Pressure (psia)

Component Data

Inlet Conditions

Vendor/Supplier Specifications and Price Quote

Price (2005 U.S.$) $ 370,000.00

Design Particulate Cutpoint

Design Separation Efficiency at Cutpoint (%)

5 ft∅ x 25 ft tall

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-45 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C 

Site Location Date Rev.

Flow Voscosity Density

Molecular 

Weight 

(Ave.)

Particle 

Size (mm) 

(Stokes' 

MMD)

Volumetric 

Flowrate Temperature 

lb/h lb/ft-sec lb/ft3 lb/mole acfm °F

248,368.00 2.87E-05 0.03501 27.6 7,289.00 1,798

40,407.00 1.00 60

33.00

32.64

10.00

33.00

50

98

Emery Design Calculations Summary for S-103 (for Reference Only)

Mechanical Sizing Inside 

Diam (in)

Uninsulated 

Outside Diam 

(in)

ID (in) OD (in) Thickness (in) Designation Overall Height 

(ft)

In 26 36 Upper Shell 46 48 1 ASME VIII 25

Out 18 28 Inner Tube 18 4

Bottom Cone 1 ASME VIII

Refractory 38 4

Design 

Temperature 

(°F)

Solids 

Removal 

Flowrate 

(CFM)

Differential 

Design 

Pressure 

(psig)

Type

Rotary Air Lock 938 20.4 15 Inner Wall Outer Shell Inner Wall Outer Shell Inner Wall Outer Shell

Level Indicator 938 CercastTM MS CercastTM MS CercastTM MS

Inner Tube

MS

Fisher-Klosterman, Inc (Refer to Vendor Communications and Data Sheets)

Ryan Bruner, Sales Manager

P.O. Box 11190

Lousville, Ky

Ph: 502-572-4000 ext 213

Email: rab@fkinc.com

Recommendation: Quote Pending

Four (4) XQ120-48M cyclone assemblies each with the following Features:

Design, fabricated, tested, and stamped as an ASME vessel Interior surfaces to be lined with 4" of Vesuvius Cercast 3300 castable refractory

3/8" plate carbon steel construction All welding per FKI Class 3 preocedures with 100% penetration

Dust receiver section with flanged discharge Exterior to be sandblasted and painted with high temperature aluminum paint

40"∅ gas inlet flange Design pressure (psig) 460

48"∅ verticle gas outlet flange Design Temperature (F) 650

Approximate Overall Dimensions:

Gas Conditions at Inlet: Particulate Conditions at Inlet:

Volume per cylone (acfm) 7,289 Specific Gravity 1.000

Density (lbm/ft3) 0.5679 Dust Loading (Grains/acf) 16

Viscosity (lbm/ft-sec) 2.87E-05

Inlet Velocity (ft/sec) 72.29 Fraction Efficiencies: Stokes Equiv. % Efficiency

No load pres. drop (in.W.C.) 120.63 Dia.(microns) Weight %

Full load pres. Drop (in. W.C.) 99.82 2.5 8.46

3 13.57

3.5 19.29

4 25.27

4.5 31.27

5 37.1

5.5 42.64

6 47.84

7 57.08

8 64.8

9 71.14

10 76.31

12 83.89

16 90.07

21 94.11

31 97.52

101 99.93

Vendor/Supplier Specifications and Price Quote

Price (2005 U.S.$) $ 250,000.00

Design Particulate Cutpoint

Design Separation Efficiency at Cutpoint (%)

4 ft∅ x 17 ft tall

Cyclone Specification Sheet

Remarks: Inlet and outlet manifolding is not included in Fisher-Klosterman quote for these four cylones. Estimated cost of splitter and collection is $25,000. 

Refer to supplier data sheet for Vesuvius CERCASTTM 3300 Castable refractory. 

SERVICE OF LOW PRESSURE UNIT S-103

Nozzles

Gas Discharge Pressure (psig)

Pressure Drop, Max Allow. (" .WC.)

Gas Inlet Pressure (psia)

Component Data

Inlet Conditions

Gas

Particulate

Design/Test Pressure Psig

Upper Section Lower Conical section

Cyclone Body Materials of Construction

Connections Size 

& Rating

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock C-46 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix D Gas Cleanup Technologies Evaluated 

D.1 INTRODUCTION 

The first task undertaken by the team was to examine commercial technologies that are suitable 

for synthesis gas cleanup for biomass gasification. Currently, there are various types of 

technologies available dependent upon the specific cleanup requirements. For example, the 

clean-up required for syngas that will ultimately be fed to a reciprocating engine is much less 

than for syngas used in chemical synthesis. This study examined all technologies that could be 

required for syngas that will be used for Fischer-Tropsch (FT) liquids and alcohol synthesis. 

The gas cleanup configuration for a system is generally determined by the composition of the 

syngas exiting the gasifier, the cleanup requirements for the intended use of the syngas, and 

economic considerations. Technologies such as cyclone separators, barrier filters, and 

electrostatic precipitators are routinely used for solid particulate removal. Catalytic tar crackers 

are employed to destroy tars and nitrogen contaminants. Wet scrubbers are used to remove a 

number of contaminants such particulates, alkali species, halides, soluble gases, and condensable 

liquids. Acid gas removal technologies encompass a large selection of processes including 

amine-based, physical solvent, liquid phase oxidation, and catalytic absorbent. Each section 

focuses on the operating size ranges and conditions, materials of construction, and cleanup 

parameters for each technology considered. 

D.2 PARTICULATE REMOVAL TECHNOLOGIES 

D.2.1 INTRODUCTION 

During the gasification process, the mineral matter contained in the biomass feedstock will form 

inorganic ash, and the unconverted biomass will form char. These particulates are entrained in 

the syngas stream as it exits the gasifier. The concentration of particulates produced is often 

influenced by the gasifier design. These particulates can present emissions problem and can 

cause abrasion to downstream equipment. Therefore, the particulates concentration must be 

reduced using various technologies discussed in the following paragraphs. 

Cyclone Separators 

Cyclones use centrifugal forces to separate the bulk of large size particulates from a gas stream. 

In gasification systems, cyclones are normally used as the first step in the gas cleanup process. 

They are relatively inexpensive to manufacture and easy to operate which translate to low capital 

and maintenance costs. In general, 90-98% of particulates 10 μm or larger in diameter can be 

removed, but the removal efficiency decreases significantly for smaller particulates13. The 

removal efficiency also decreases as the operating temperatures increases. Cyclones are capable 

of handling operating temperatures up to 2000°F and can be designed to operate at pressures 

normally encountered in gasifiers. Cyclones are usually made from carbon steel and are 

refractory lined to withstand high temperature environments. A flow range from 300 to 13,000 

CFM is typical for cyclones. This flow range is within the parameter of the syngas flow rate 

specified by NREL for this project. 

 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock D-1 

13 Donaldson Co., Inc. “Cyclone Dust Collectors,” July 2003, <http://www.donaldson.com/en/industrialair/literature/000984.pdf

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix D Gas Cleanup Technologies Evaluated 

D.2.2 BARRIER FILTERS 

Barrier filters remove particulates by capturing the particulates on the filter surfaces as the gas 

stream passes through the filter medium. The particulates accumulated on the filter surfaces 

form a cake, which can be dislodged by initiating a blowback flow. The blowback gas flows in 

the reverse direction of normal process flow and dislodges the filter cake, which is then removed 

from the system. The operating principle of barrier filters is illustrated in Figure D-1. Barrier 

filters include high-temperature filters, such as ceramic and metal candle filters, and lowtemperature filters, such as baghouse filters. 

FIGURE D-1 PRINCIPLE OF BARRIER FILTERS 

Filter Cake Medium

Feed Filtrate

Ceramic Candle Filters 

Ceramic filters are designed to remove particulate matter from gas streams at elevated 

temperatures. Ceramic filters can be designed for any flow requirement and can remove 90% of 

particulates larger than 0.3 μm

14. In theory, the ceramic filter elements, normally made of 

aluminosilicate or silicon carbide powder with a sodium aluminosilicate binder, have exceptional 

physical and thermal properties, and should be able to withstand high temperature operations of 

up to 1800°F. However, commercial operations using ceramic filters at this temperature range 

have not been successful due to the susceptibility of the filter elements to cracking. Advances in 

composite filter element materials that have resistance to crack propagation at high temperatures 

are being developed and tested15. At temperatures below 850°F, ceramic filters have 

demonstrated satisfactory operational reliability. 

In operations where tars are formed in the gasifier, ceramic filters should be operated at 

temperatures above the dew point of the tars (usually about 700-750°F) to avoid tar 

condensation. Condensed tar accumulates on filter surfaces and leads to plugging which will 

reduce the lifetime of the filter and impact process flowrates. 

Metal Candle Filters 

Metal filters are used in high temperature cleanup systems to remove particulate matter and can 

achieve filtration level as low as 1 μm. They can be designed to meet any flow requirement and 

can operate over a wide range of temperatures depending on the material of construction. Metal 

 

14 Pall Corp., “Syngas Filter Proposal,” 26 January 2005, office communication 

15 Jay E. Lane, Jean-Francois LeCostaouec, “Ceramic Composite Hot Gas Filter Development,” 

<http://www.netl.doe.gov/publications/proceedings/98/98ps/pspb-5.pdf

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock D-2 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix D Gas Cleanup Technologies Evaluated 

filters made from stainless steel can be used in cleanup systems for temperatures below 650°F 

while Inconel or alloy HR filters are suitable for operating temperatures up to 1100°F. At even 

higher temperatures, Fercalloy can withstand temperatures up to 1800°F16, although commercial 

operation at this temperature has not been demonstrated. Commercial operation of metal filters 

operating at a maximum temperature of 915°F has been successful at a few gasification facilities 

in Europe17. 

Some operational considerations for metal filters are the corrosion rate and tar deposition on 

filter elements. Under similar stream compositions and conditions, the corrosion rate of metal 

filter elements is ten times that of the surrounding piping; thus, a regular maintenance schedule is 

essential to ensure operational reliability. Additionally, in operations where filter elements are 

subjected to frequent cleaning cycles due to tar deposition, the lifetime of the filter will be 

reduced. Therefore, it is recommended that the filter be operated at a temperature above the dew 

point of the tars in the syngas stream to avoid tar condensation and deposition. 

Baghouse Filters 

Baghouse filters are made of a woven fabric or felted (non-woven) material to remove particulate 

matter from an air or gas stream and can remove particulates down to 2.5 μm18. For woven 

fabric filters, the removal efficiency increases as the thickness of filter cake increases; thus, the 

removal efficiency of these systems is constantly changing. Felted filter systems have a constant 

removal efficiency that does not depend on the thickness of the filter cake19. Baghouse filters are 

modular in design and thus can accommodate a wide flow range from 1,500 to 150,000 CFM. 

The air-to-cloth ratio, or ratio of the volumetric flow to cloth area, sets the size of a baghouse 

unit. The bag fabric can be made from various materials including polyester, acrylic, NOMEX, 

Teflon, Ryton, and fiberglass20. The operating temperature range of an application influences the 

selection of bag material. For example, materials such as polyester or acrylic are suitable for 

applications with operating temperatures below 300°F, while NOMEX, Teflon, Ryton, or 

fiberglass is recommended for temperatures up to 500°F. Due to the temperature limits of the 

filter fabric, baghouse filters are only used in the low-temperature cleanup systems. They are 

often used downstream of the cyclones so that the particulate loading on the filters can be 

reduced. 

Disadvantages of baghouse filters include the need for periodic bag replacement that can result in 

high maintenance costs and the potential for bag fire or explosion. A spark detection and 

extinguishment system, along with bag grounding strips, are recommended safety measures to 

mitigate the fire potential. Additionally, the performance of the filter fabrics degrades drastically 

with tar deposition on the fabric surface, so fabric surface treatments such as Teflon coating and 

pre-coating with limestone or other compatible filter aids is recommended. Such pre-coats can 

 

16 Mott Corp., “Fiber Metal. The High-Flow, Low-Pressure Drop Alternative,” June 2003, 

http://www.mottcorp.com/resource/pdf/PSFIBERfinal.pdf

17 Mike Wilson, Mott Corp., “Fercalloy Metal Filters,” 2 February 2005, Vendor input 

18 Donaldson Co., Inc. “Dalamatic Dust Collectors,” December 2002, http://www.donaldson.com/en/industrialair/literature/000983.pdf

19 EPA, “Air Pollution Technology Fact Sheet-Fabric Filter – Pulse-Jet Cleaned Type,” 

http://www.macrotek.net/pdf/FS_Pulse_Clean_Dust_Collector.pdf

20 Ducon, “Baghouse Filter,” 2003, http://www.ducon.com/bag-house-filter.php

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock D-3 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix D Gas Cleanup Technologies Evaluated 

also be used to adsorb mercury and other contaminants.. Industry experience suggests that either 

ceramic or metal filters should be used in place of baghouse filters in high temperature 

operations. 

D.2.3 ELECTROSTATIC PRECIPITATORS (ESPs) 

ESPs are commonly used in large power plants to control fly ash emissions. ESPs consist of 

discharge electrodes centered between positively grounded collection plates. As the gas stream 

laden with particulates passes through the ESP, the discharge electrodes provide a negative 

charge to the particulates. The positively grounded collection plates act as a magnet for the 

negatively charged particulates, which collect on the plates. The collected particulates are 

transported into the collection hopper by the rapper or vibrator system. 

ESPs are classified as either wet or dry processes. In wet ESPs, a water quench is applied either 

intermittently or continuously to the collection plates. The purpose of the water quench is to 

prevent possible fires that have occasionally resulted from the use of dry ESPs. The wastewater 

from wet ESPs must be treated prior to disposal. 

For dry ESPs, the removal efficiency decreases for particulates with a high electrical resistivity 

since these particulates can introduce positive ions into the gas space resulting in reduced 

attraction of the negatively charged particulates to the collection plates. Particulates with a high 

resistivity are commonly produced from combustion of low-sulfur coals. Flow ranges of 10,000 

– 300,000 CFM are typical for dry ESPs. Dry ESPs operate in the pressure range from vacuum 

conditions up to 150 psi and can operate at temperatures up to 750°F21. 

Wet ESPs can achieve 99.9% removal of sub-micron particulates down to 0.01 μm. Particulate 

resistivity does not affect removal efficiency of wet ESPs since the humid operating environment 

often reduces the resistivity of particulates. These systems are generally designed for gas flow 

range from 1,000 to 100,000 CFM. Gas streams with particulate sizes larger than 2 μm or with 

an exceptionally high particulate loading should be pretreated to reduce the load on the ESP. 

Wet ESPs operate in the pressure range from vacuum conditions up to 150 psi, with operating 

temperatures limited to 170-190°F22,23. 

The type of ESP selected for an application is largely influenced by the operating parameter and 

the type of particulates to be removed. However, the use of ESPs is limited in gasification 

systems due to the significant capital costs compared to other systems. Additionally, the removal 

efficiency of ESPs is sensitive to fluctuations in process conditions, such as changes in 

temperatures and pressures, gas compositions, and particulate loading. Therefore, ESPs are not 

suitable for biomass gasification applications that have highly variable syngas compositions from 

different feedstocks. 

 

21 Gerry Graham, “Controlling Stack Emissions in the Wood Products Industry,” http://www.ppcesp.com/ppcart.html 22 Ducon, “Wet & Dry Electrostatic Precipitators,” 2003, http://www.ducon.com/wet-dry-precipitators.php (24 January 2005) 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock D-4 

23 EPA, “Air Pollution Technology Fact Sheet-Wet Electrostatic Precipitator (ESP)-Wire-Pipe Type,” http://www.p2pays.org/ref/10/09890.pdf

(25 January 2005) 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix D Gas Cleanup Technologies Evaluated 

D.3 TAR REMOVAL TECHNOLOGIES 

D.3.1 INTRODUCTION 

Following NREL guidelines for the purpose of this project, tar is defined as C10+ hydrocarbons. 

Tar in syngas products can cause serious operational problems when the syngas stream cools 

below the dew point of the tars (usually about 700-750°F) and tar deposition occurs on 

downstream equipment and piping. Thus, tar removal is critical when there is tar present in the 

syngas. Tar can be removed either by physical or chemical processes. The most common 

physical process involves cooling the syngas stream to condense the tar into fine droplets and 

removing these droplets by wet scrubbing. Chemical process involves catalytic steam reforming 

of tars to lighter gases. 

D.3.2 WET SCRUBBERS 

Wet scrubbing is generally used to remove water-soluble contaminants from the syngas by 

absorption into a solvent. Tar components are water-soluble can be removed by this method. 

Additionally, wet scrubbing is also often used to remove a number of other contaminants such as 

particulates, alkali species, halides, soluble gases, and condensable liquids. In wet scrubbing, 

water is a common solvent choice. Wet scrubbers with the venturi design are frequently used in 

gas cleanup applications to achieve sub-micron particulate removal requirements. As the gas 

stream enters the venturi scrubber, the scrubbing liquid is sprayed into the gas stream. The two 

streams are thoroughly mixed by the turbulence in the venturi throat section where fine particles 

are impacted and agglomerate into liquid droplets. The liquid droplets are separated from the gas 

stream in a separator unit consisting of a cyclone separator or a mist eliminator. 

Venturi scrubbers can achieve 99.9% removal efficiency of sub-micron particulates. Flow range 

for a single-throat venturi is 500-100,000 SCFM. Flows above this range require either multiple 

venturi scrubbers in series or a multiple-throat venturi24. Venturi scrubbers with a quench 

section can accommodate high temperature gas streams up to 450°F, and they can operate over a 

wide range of pressures25. 

The standard material of construction for venturi scrubbers is carbon steel. For corrosive or high 

temperature applications, stainless steel or special alloys such as FRP (fiberglass reinforced 

plastic) and Inconel are used. 

The disadvantages of scrubbers include high pressure drop, the need to treat the wastewater 

effluent prior to disposal, and the loss of sensible heat of the syngas due to quenching. In power 

generation applications, the loss of sensible heat reduces the energy content of the gas and thus is 

undesirable; however, it is less of a concern in biomass refinery applications. Nevertheless, 

sensible heat loss will result in reduced overall system efficiency. 

 

24 EPA, “Air Pollution Technology Fact Sheet-Venturi Scrubber” <http://www.macrotek.net/pdf/FS_Venturi_Scrubber.pdf

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock D-5 

25 Envitech, Inc., “Venturi Scrubber,” <http://www.envitechinc.com/scrubber.zhtml

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix D Gas Cleanup Technologies Evaluated 

D.3.3 CATALYTIC TAR REFORMING 

Catalytic reforming of biomass tars is a developing technology for tar removal from syngas 

streams. The concept of this technology is to reform tar in a fluidized reactor bed, or tar cracker, 

into lighter gases using a proprietary catalyst. In addition to tar, light hydrocarbons (C1 to C5), 

benzene, and ammonia are also removed. A few large-scale biomass gasification facilities, such 

as Carbona in Denmark and the FERCO gasifier in Vermont, have demonstrated a novel catalyst 

in their tar crackers since commercial catalysts are too friable for this application26. The FERCO 

tar cracker removed 90% of the tar in the syngas stream using a novel catalyst known as DN3427. 

In both of these processes, a wet scrubber was used downstream of the tar cracker to remove 

residual tars and impurities. 

A tar cracker known as the Reverse Flow Tar Cracking (RFTC) reactor developed by BTG uses 

the steam reforming process with a commercial nickel catalyst28. The nickel catalyst is very 

sensitive to sulfur impurities; therefore, a syngas stream containing sulfur contaminants has to be 

desulfurized prior to entering the RFTC reactor. Due to the cooling requirement for the 

desulfurization process, the syngas is fed to the reactor at a temperature from 660 -1200°F and is 

heated to the reaction temperature of 1650 -1740°F in the reactor entrance section. The heated 

gas passes through a bed of nickel catalyst where tar, light hydrocarbons, and ammonia are 

removed by steam reforming. The main reactions of the RFTC reactor are: 

CnHm + nH2O Ù nCO + ( 1⁄2 m+n)H2 Hydrocarbon reforming 

2NH3 Ù N2 + 3H2 Reverse ammonia synthesis 

CO + H2O Ù CO2 + H2 Water-gas shift 

A small amount of the syngas is combusted to counterbalance the endothermic tar reforming 

reactions: 

H2 + 1⁄2 O2 Æ H2O 

CO + 1⁄2 O2 Æ CO2

CH4 + 2O2 Æ CO2 + 2H2O 

The typical conversion for the RFTC reactor is as follows: 

Components Conversion

 Benzene 82 

 Napthalene 99 

 Phenol 96 

 Total Aromatic 94 

 Total Phenols 98 

 Total Tar 96 

 Ammonia 99 

 

26 Don J. Stevens, “Hot Gas Conditioning: Recent Progress with Larger-Scale Biomass Gasification Systems,” prepared by Pacific Northwest 

National Laboratory for NREL, August, 2001 27 Mark A. Paisley, Mike J. Welch, “Biomass Gasification Combined Cycle Opportunities Using the Future Energy SilvaGas Gasifier Coupled 

to Alstrom’s Industrial Gas Turbines,” ASME Turbo Expo Land, Sea, and Air, Georgia World Congress Center, June 16-19, 2003 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock D-6 

28 BTG Biomass Technology Group, “Tar & Tar Removal,” 22 March 2004, http://www.btgworld.com/technologies/tar-removal.html 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix D Gas Cleanup Technologies Evaluated 

The partial oxidation reaction (POx) was also investigated as a possible process for tar and 

hydrocarbons removal. In this process, the syngas enters the POx reactor and mixes with oxygen 

that is at about 300°F. Partial oxidation and reforming reactions occur in a combustion zone 

where tar, methane, light hydrocarbons, and benzene are converted to CO and H2. The reformed 

gas exits the reactor at about 2500°F. 

The main disadvantage of POx is a reduction of the product gas heating value. In order to 

achieve destruction of the tars and oils, a high temperature reactor is required. While it is 

possible to crack the tars and oils at moderate temperatures, it is very difficult to selectively react 

methane. However at high temperatures oxidation of CO and H2 also occur. As a result, the gas 

composition will be shifted toward a lower H2:CO ratio. 

In order to improve the efficiency of POx, a catalyst can be used to lower the temperature, and 

hence also the amount of oxidizer required to destroy the tars and oils. A catalytic auto-reformer 

technology may provide a solution to biomass tar and oil elimination. Such an application would 

only apply to a particulate-free gas since any particulate in the gas could shortly blind the 

catalytic reactor. As shown in Table D-1 below, an auto-thermal reformer is essentially a hybrid 

between POx and steam reforming. 

TABLE D-1 COMPARISON OF SYNGAS REFORMING PROCESS TECHNOLOGY 

Gas Reforming Process 

Typical 

H2/CO ratio Comments 

Tar Cracking/Reforming wide range Developing technology. Operating information not widely 

available. 

Steam (Methane) Reforming 

SR or SMR 

3-4 Dominant technology for industrial H2 production 

Typically high efficiency 

Partial Oxidation (POx) 1.7-1.8 Used in refining to upgrade heavy liquid fuels 

Low efficiency 

May generate coke or soot 

Auto-thermal Reforming (ATR) 2.4-4 Hybrid of POx and SR 

D.4 ACID GAS REMOVAL TECHNOLOGIES 

D.4.1 INTRODUCTION 

Sulfur contaminants such as H2S, COS, CO2, mercaptans, and HCN poison catalysts used in 

liquid fuel synthesis. Therefore, the syntheses of methanol and FT liquids from syngas require 

that the sulfur be removed from the syngas to a residual level of 0.10 ppm or less. The syngas 

considered for this study contains approximately 400 ppmv of H2S; therefore, acid gas removal 

is critical in the gas cleanup process. Acid gas removal technologies can be categorized as 

amine-based, physical solvent, liquid phase oxidation, or catalytic absorbent processes. The type 

of technology selected is largely influenced by the system operating conditions, the sulfur level 

in the syngas stream, and the desired purity of the treated syngas. Brief descriptions to explain 

the overall process for each system are given in the following paragraphs. 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock D-7 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix D Gas Cleanup Technologies Evaluated 

D.4.2 AMINE-BASED SYSTEM 

Amine processes are proven technologies for the removal of H2S and CO2 from gas streams by 

absorption. Amine systems generally consist of an absorber, a stripper column, a flash separator, 

and heat exchangers. This is a low-temperature process in which the gas to be treated usually 

enters the absorber at approximately 110°F. In the absorber, acid gases are removed from the 

gas stream by chemical reactions with the amine solution. The sweet gas stream exits at the top 

of the absorber. Regeneration of the rich amine is accomplished through the flash separator to 

remove absorbed hydrocarbons followed by a stripper column to remove the H2S and CO2 from 

the amine solution. The lean amine solution is cooled and returned to the absorber. The stripped 

acid gas stream is cooled to recover water and then sent to a sulfur recovery unit. A typical 

amine system is shown in Figure D-2. 

FIGURE D-2 TYPICAL AMINE SYSTEM FLOW DIAGRAM 

Amine systems normally operate in the low to medium pressure range of 70-360 psi, although 

higher pressures can be accommodated with a specific amine solvent. However, in applications 

where the partial pressure of acid gases is high, the economy of an amine system declines in 

comparison to other systems. Amine systems can be designed to meet specific flow range and 

sulfur removal requirements. A sulfur removal level as low as 1 ppm can be achieved but at the 

expense of operating cost due to the large solvent circulation rate required29. 

There are a variety of amine solutions available. Each offers distinct advantages based on the 

specific treating condition. Commercially available amine solutions include30: 

 

29 Input from GTI, “Gas Cleanup Technologies Discussion,” 3 February 2005, office communication 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock D-8 

30 GPSA 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix D Gas Cleanup Technologies Evaluated 

MEA – Monoethanolamine removes both H2S and CO2 from gas streams and is generally used in 

low-pressure systems and in operations requiring stringent sulfur removal. 

DGA – Diglycolamine is used when there is a need for COS and mercaptan removal in addition 

to H2S. DGA can hydrolyze COS to H2S; thus, a COS hydrolysis unit is not needed in the 

cleanup system. 

DEA - Diethanolamine is used in medium- to high-pressure systems (above 500 psi) and is 

suitable for gas stream with a high ratio of H2S to CO2. 

MDEA - Methyldiethanolamine has a higher affinity for H2S than CO2. MDEA is used when 

there is a low ratio of H2S to CO2 in the gas stream so that the H2S can be concentrated in the 

acid gas effluent. If a Claus plant is used for sulfur recovery, a relatively high concentration of 

H2S (>15%) in the acid gas effluent is required for optimal Claus operation. 

After prolonged use, MEA, DGA, and MDEA solutions accumulate impurities that reduce the 

H2S removal efficiency of the solutions. A reclaim unit is needed to remove the impurities in 

order to improve system efficiency. 

One major operating concern for amine systems is corrosion. In water, H2S dissociates to form a 

weak acid while CO2 forms carbonic acid. These acids attack and corrode metal. Therefore, 

equipment in the amine systems may be clad with stainless steel to improve equipment life. 

D.4.3 PHYSICAL SOLVENT SYSTEM 

This acid gas removal technology uses an organic solvent to remove acid gases from gas streams 

by physical absorption without chemical reaction. The driving force of this process is the high 

solubility of acid gases in the organic solvent. In most cases, solubility increases as the 

temperature decreases and the pressure increases. Thus, physical absorption is a lowtemperature, high-pressure process, with high partial pressure of acid gases required for the 

economy and efficiency of this process. The temperature of the solvent should be as low as 

possible while the temperature of the gas to be treated usually enters the absorber at about 100°F. 

Physical solvent systems normally operate at pressures above 150 psi31. 

In general, physical solvent systems consist of an absorber, a stripper column, a series of flash 

separators, and heat exchangers. In the absorber, acid gases in the syngas stream are absorbed 

into the solvent solution. The sweet syngas stream exits the top of the absorber. Regeneration of 

the rich solvent stream is accomplished through a series of flash separators at reduced pressures 

to remove absorbed hydrocarbons followed by the stripper column to remove the acid gases from 

the solvent. The lean solvent solution is cooled and returned to the absorber. The stripped acid 

gas stream is cooled to recover water and then sent to a sulfur recovery unit. A typical physical 

solvent system is shown in Figure D-3. 

 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock D-9 

31 Gerhard Ranke, “Advantages of the Rectisol-Wash Process in Selective H2S Removal from Gas Mixtures,” 1973, office communication, 30 

January 2005 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix D Gas Cleanup Technologies Evaluated 

The two common physical systems are Rectisol and Selexol. The Rectisol process, which uses 

methanol at temperatures < 32°F, can achieve a sulfur removal level as low as 0.1 ppm. The 

Selexol process, which uses mixtures of dimethyl ethers of polyethylene glycol, can achieve a 

sulfur removal level of 1ppm32. 

Selection of material of construction depends on the solvent used. For example, stainless steel is 

required for much of the Rectisol process equipment, contributing to a significant capital cost. In 

the Selexol process, carbon steel is the standard material of construction, except for those areas 

with high severity where stainless steel will be used. 

FIGURE D-3 TYPICAL PHYSICAL SOLVENT SYSTEM FLOW DIAGRAM 

D.4.4 LIQUID PHASE OXIDATION PROCESS -- LO-CATTM

LO-CATTM is an oxidation process that uses iron catalyst held in a chelating agent to oxidize 

H2S to elemental sulfur. H2S is the only acid gas being removed in this process but a high CO2

concentration in the feedgas requires caustic for pH adjustment. A LO-CATTM process consists 

of 3 sections that include an absorber, an oxidizer for catalyst regeneration, and a sulfur handling 

unit. Figure D-4 illustrates a typical LO-CATTM unit. When the gas stream comes in contact 

with the LO-CATTM solution in the absorber, H2S in the gas stream is converted to elemental 

sulfur. The spent catalyst along with the elemental sulfur exit the absorber, then enter the 

oxidizer where the spent catalyst is regenerated by contact with oxygen in air, and the elemental 

sulfur is concentrated into a sulfur slurry. The sulfur slurry moves to the sulfur handling unit 

where it is washed to recover any entrained catalyst. The sulfur recovered from a LO-CATTM 

 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock D-10 

32 D.J. Kubek, E. Polla, F.P. Wilcher, “Purification and Recovery for Gasification,” Gasification Technologies Conference, October 1996, San 

Francisco, CA. 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix D Gas Cleanup Technologies Evaluated 

process contains a small amount of entrained residual catalyst and is considered low-value sulfur 

that is suitable for agricultural purposes but is undesirable as a chemical feedstock. 

The LO-CATTM process is suitable for small-scale applications that require less than 20 TPD of 

sulfur recovery capacity, making the LO-CATTM a candidate process for this study, which has 

less than 5 TPD of sulfur recovery. This process can achieve 99.9%+ of H2S removal 

efficiency33. This process can operate over a wide range of pressures from atmospheric up to 

600 psi, but most are low-pressure applications in amine acid gas service. The operating 

temperature is normally maintained at about 110°F since high temperatures degrade the LOCATTM solution that can affect removal efficiency. Advantages of this process include the 

ability to treat a wide range of gas compositions, a significant turndown flexibility, and less 

capital costs in comparison to the Claus process with the associated tail gas treating unit. 

FIGURE D-4 TYPICAL LO-CATTM SYSTEM FLOW DIAGRAM 

Since LO-CATTM only removes H2S, a COS hydrolysis unit upstream of the LO-CATTM is 

needed to hydrolyze any COS in the gas stream to H2S. Other acid gases, such as HCN and 

mercaptans, would have to be removed by wet scrubbing. 

The standard material used for LO-CATTM systems is stainless steel. Under certain conditions 

where there is build-up of chloride ions from the feed gas, FRP (fiberglass reinforced plastic) 

material is used to provide added stability for the stainless steel components34. 

D.4.5 CATALYTIC ABSORBENT—ZnO 

ZnO is often used as a polishing step for sulfur removal in gas streams where the sulfur level is 

below 20 ppmv. In a traditional purification system, illustrated in Figure D-5, ZnO is used in 

 

33 Douglas L. Heguy, Gary J. Nagl, “The State of Iron Redox Sulfur Plant Technology New Developments to an Established Technology,” 

<http://www.gtpmerichem.com/support/technical_papers/state_of_iron_redox.html> (25 January 2005) 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock D-11 

34 GTP-Merichem, “FAQ’s About Sulfur Removal and Recovery Using the LO-CAT System,” <http://www.gtpmerichem.com/support/faq.html> (25 January 2005) 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix D Gas Cleanup Technologies Evaluated 

conjunction with hydrogenation catalysts based on cobalt, molybdenum and nickel. This system 

involves the hydrogenation of sulfur compounds such as mercaptans to H2S, and halides such as 

chlorides to HCl. These compounds are then reacted with the ZnO absorbent where H2S is 

converted to zinc sulfide, and HCl forms a stable chloride. Additionally, ZnO also removes COS 

by hydrolysis to form H2S which is then adsorbed to form zinc sulfide. The general reactions are 

summarized below35: 

 Hydrogenation reactions: 

RSH + H2 Æ RH + H2S 

RCl + H2 Æ RH + HCl 

Reaction with ZnO: 

ZnO + H2S Ù ZnS + H2O 

ZnO + COS Ù ZnS + H2O 

FIGURE D-5 TRADITIONAL ZNO PURIFICATION SYSTEM 

A sulfur removal below 50 ppb is attainable with ZnO36. Since the sulfur specifications for 

alcohols and FT liquids are 0.10 ppm or less, ZnO will be used to achieve these requirements. 

However, a hydrogenation reactor will not likely be required since the syngas stream given by 

NREL does not contain halogens or any other sulfur compounds other than H2S. 

 

35 Johnson Matthey Group, “Purification Catalysts and Absorbents for Hydrogen Production,” available at http://www.jmcatalysts.com (25 

January 2005) 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock D-12 

36 Johnson Matthey Group, “Absorbent for Sulphur Polishing,” available at http://www.jmcatalysts.com (25 January 2005) 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix D Gas Cleanup Technologies Evaluated 

ZnO is active over a wide range of temperatures from ambient to 750°F; however, operating 

temperatures range between 660°F and 750°F are normally used to maximize absorption 

efficiency. Operating pressure limits are not a concern for the use of ZnO absorbent. The ZnO 

reactor is normally constructed from carbon steel clad with stainless steel to prevent corrosion 

caused by acid gases. 

One drawback of this process is the significant operating costs contributed by frequent 

replacement and disposal of ZnO absorbent since it cannot be regenerated. 

D.4.6 COS HYDROLYSIS 

COS can be removed simultaneously with H2S and other acid gases in some of the acid gas 

removal processes described above. In chemical absorption processes, the degree of COS 

removal is dependent upon the reactivity of the solvent solution with COS. For example, DGA 

can remove virtually all of the COS whereas MDEA has little reactivity with COS. In physical 

absorption processes, the solubility of COS in the physical solvent and the COS partial pressure 

determine the level of removal. A COS level of 0.1 ppm is attainable with the Rectisol process 

while the Selexol process can achieve 10 ppm COS37. In the ZnO process, approximately 80% 

of the COS can be removed by hydrolysis. 

When COS cannot be effectively removed by the conventional acid gas removal processes, a 

COS hydrolysis reactor is required and is placed upstream of the acid gas removal unit. COS 

removal is accomplished by hydrolysis of COS on a catalyst to form H2S which is sent to the 

downstream acid gas removal unit. Activated alumina catalysts are often used in these 

applications. COS removal to 0.1 ppm or below can be achieved38. COS hydrolysis reactors can 

operate over a wide range of pressures with temperatures in the range of 100°F – 450°F. The 

COS hydrolysis reactor is normally constructed from carbon steel clad with stainless steel to 

prevent corrosion caused by acid gases. 

D.4.7 SULFUR RECOVERY UNIT (SRU) 

In the sulfur recovery unit, the acid gas stream from the amine or physical solvent unit is 

recovered to elemental sulfur. In operations where the sulfur recovery is more than 20 TPD, a 

Claus SRU is generally an economical approach. However, since the amount of sulfur in the 

syngas for this study is small (< 5 TPD), a Claus operation would not be a cost-effective 

solution. For a low sulfur recovery capacity, a LO-CAT SRU would be a more suitable process. 

D.5 AMMONIA, ALKALI, AND OTHER CONTAMINANTS 

D.5.1 AMMONIA REMOVAL 

Two methods for removing ammonia include catalytic tar reforming and wet scrubbing. Tar 

cracker catalysts have been demonstrated to be effective at reducing ammonia in the syngas 

stream by conversion to N2 and H2. A tar cracker can be used to remove ammonia followed by 

 

37 Robert Chu, Senior Design Engineer, Nexant, “COS Removal,” office communication, 17 February 2005 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock D-13 

38 United Catalysts Inc., “UCI COS Hydrolysis Catalysts,” 22 June 1992, and office communication, 17 February 2005 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix D Gas Cleanup Technologies Evaluated 

gas cooling and a wet scrubber to remove residual ammonia. This cleanup configuration should 

achieve complete removal of ammonia. 

D.5.2 ALKALI REMOVAL 

Alkali removal is normally accomplished by cooling the syngas stream below 1100°F to allow 

condensation of alkali species followed by barrier filtration or wet scrubbing. Corrosion 

potential should be taken into consideration when using metal or ceramic candle filters due to 

possible reactions between the alkali and filter materials at high temperatures. Several 

demonstration facilities had used barrier filters to removal alkali along with other impurities. For 

example, ceramic filters were used at the Lahti facility in Finland and Varnamo in Sweden39,

40. 

The Varnamo facility experienced breakage of the ceramic filter elements and replaced them 

with sintered metal filters, which operated successfully. Baghouse filters were used in Lahti’s 

low-pressure gasification system and the FERCO facility in Vermont. 

Alkali can easily be removed by wet scrubbing, thus it is often the preferred method for alkali 

removal. Descriptions of operating and cleanup parameters for barrier filters and wet scrubbing 

are given earlier in this Appendix. 

D.5.3 REMOVAL OF OTHER CONTAMINANTS 

Contaminants such as halides or metals (i.e. nickel or iron) are not typical, but may exist in 

syngas produced from biomass gasification. If present, these impurities can be removed by wet 

scrubbing or purification by hydrogenation and ZnO absorption. 

 

39 OPET Finland, OPET Report 4 “Review of Finnish Biomass Gasification Technologies,” May 2002 

Task 2: Gas Cleanup Design and Cost Estimates, Wood Feedstock D-14 

40 Krister Stahl, et al. “Biomass IGCC at Varnamo, Sweden-Past and Future,” GCEP Energy Workshop, 27 April 2004, Stanford University, CA. 

 Final Report 

United States Department of Energy/National Renewable Energy Laboratory 
F1146-E(12/2004) 

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1. REPORT DATE (DD-MM-YYYY)

May 2006 

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Subcontract Report 

3. DATES COVERED (From - To)

 

5a. CONTRACT NUMBER

DE-AC36-99-GO10337 

5b. GRANT NUMBER

4. TITLE AND SUBTITLE

Equipment Design and Cost Estimation for Small Modular Biomass 

Systems, Synthesis Gas Cleanup, and Oxygen Separation 

Equipment; Task 2: Gas Cleanup Design and Cost Estimates – 

Wood Feedstock 

5c. PROGRAM ELEMENT NUMBER

5d. PROJECT NUMBER

NREL/SR-510-39945 

5e. TASK NUMBER

BB06.3710 

6. AUTHOR(S)

Nexant Inc. 

5f. WORK UNIT NUMBER

7. PERFORMING ORGANIZATION NAME(S) AND ADDRESS(ES)

Nexant Inc. 

101 Second St., 11th Floor 

San Francisco, CA 94105 

8. PERFORMING ORGANIZATION 

REPORT NUMBER

ACO-5-44027 

10. SPONSOR/MONITOR'S ACRONYM(S)

NREL 

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National Renewable Energy Laboratory 

1617 Cole Blvd. 

Golden, CO 80401-3393 11. SPONSORING/MONITORING 

AGENCY REPORT NUMBER

NREL/SR-510-39945 

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13. SUPPLEMENTARY NOTES

NREL Technical Monitor: Kelly Ibsen 

14. ABSTRACT (Maximum 200 Words)

As part of Task 2, Gas Cleanup and Cost Estimates, Nexant investigated the appropriate process scheme for 

treatment of wood-derived syngas for use in the synthesis of liquid fuels. Two different 2,000 metric tonne per day 

gasification schemes, a low-pressure, indirect system using the gasifier, and a high-pressure, direct system using 

gasification technology were evaluated. Initial syngas conditions from each of the gasifiers was provided to the team 

by the National Renewable Energy Laboraoty. Nexant was the prime contractor and principal investigator during this 

task; technical assistance was provided by both GTI and Emery Energy. 

15. SUBJECT TERMS

biomass; Nexant; small modular; synthesis gas; syngas; fluidized catalytic cracking; steam methane reforming; 

natural gas liquids expanders; scaling; wood; National Renewable Energy Laboratory; NREL 

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