National Renewable Energy Laboratory 

Innovation for Our Energy Future 

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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 – Black Liquor Gasification 

Nexant Inc. 

San Francisco, California 

Subcontract Report 

NREL/SR-510-39944 

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 – Black Liquor Gasification 

Nexant Inc. 

San Francisco, California 

NREL Technical Monitor: Kelly Ibsen 

Prepared under Subcontract No. ACO-5-44027 

Subcontract Report 

NREL/SR-510-39944 

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 Sulfur Removal for Low-Temperature Design Case ........................................... 1-2 

1.2.2 Sulfur Removal for High-Temperature Design Case........................................... 1-3 

1.3 Discussion.................................................................................................................... 1-4 

1.3.1 Technologies Not Chosen.................................................................................... 1-4 

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

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

2.2 Key Design Assumptions............................................................................................. 2-3 

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

2.4 Changing Flows, Conditions, and Compositions......................................................... 2-6 

2.4.1 Flowrate Impacts.................................................................................................. 2-6 

2.4.2 Composition Impacts........................................................................................... 2-9 

2.5 Follow-Up and Areas for Further Study .................................................................... 2-10 

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

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

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

3.3 Differences with Wood Gasification Cases................................................................. 3-4 

3.3.1 Size....................................................................................................................... 3-4 

3.3.2 Complexity........................................................................................................... 3-5 

Section 4 Sulfur Recycle Options.......................................................................................... 4-1 

4.1 Introduction.................................................................................................................. 4-1 

4.2 Pulping Methods.......................................................................................................... 4-1 

Appendix A High-Temperature Gasifier to Power Design Case PFDs......................... A-1 

Appendix B Low-Temperature Gasifier to Power Design Case PFDs.......................... B-1 

Appendix C High-Temperature Gasifier to Chemicals Design Case PFDs.................. C-1 

Appendix D Low-Temperature Gasifier to Chemicals Design Case PFDs................... D-1 

Appendix E Equipment Lists............................................................................................ E-1 

Task 2: Gas Cleanup Design and Cost Estimates i 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 
Contents 

Tables 

Table Page 

ES-1 Syngas Clean-Up Case Summary ..................................................................................ES-1 

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

1-2 Sulfur Specifications for Gas Cleanup............................................................................. 1-2 

2-1 Black Liquor Syngas Sulfur Removal Costs (Installed).................................................. 2-2 

2-2 Catalyst and Chemicals Requirements............................................................................. 2-4 

2-3 High Temperature Syngas to Power Case Utility Requirements..................................... 2-5 

2-4 Low Temperature Syngas to Power Case Utility Requirements ..................................... 2-5 

2-5 High Temperature Syngas to Chemicals Case Utility Requirements .............................. 2-5 

2-6 Low Temperature Syngas to Chemicals Case Utility Requirements............................... 2-6 

2-7 Examples of Typical Exponents for Equipment Cost Versus Capacity .......................... 2-8 

3-1 Black Liquor Plant Labor Costs....................................................................................... 3-3 

3-2 Complexity Differences between Black Liquor and Wood Gasification Cases.............. 3-5 

4-1 Sulfur Recycle Options for Various Pulping Methods .................................................... 4-2 

Task 2: Gas Cleanup Design and Cost Estimates ii 

Black Liquor Sulfur Removal Design and Cost Estimates 

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 removal of acid gases from black liquor derived syngas for use in both power 

and liquid fuels synthesis. Two different 3,200 metric tonne per day gasification schemes, both 

low-temperature/low-pressure (1100°F, 40 psi) and high-temperature/high-pressure (1800°F, 500 

psi) were used for syngas production. Initial syngas conditions from each of the gasifiers was 

provided to the team by NREL and Princeton University. Nexant was the prime contractor and 

principal investigator during this task; technical assistance was provided by both GTI and Emery 

Energy. 

The initial task was to evaluate the different technologies suitable for acid gas removal from the 

different syngas streams, with the end-use (power or chemicals) defining the amount of treatment 

required. After these preliminary investigations, process models were developed for each of the 

cases that incorporated equipment deemed suitable for sulfur and carbon dioxide removal. Final 

designs were developed that include unit sizes, energy use, capital and operating costs, and labor 

requirements. An analysis of the impact that syngas flowrate and composition changes have on 

the designs was then performed as a sensitivity to the base cases. Finally, Nexant evaluated the 

possible ways to reintroduce recovered sulfur back into the front-end of the pulping process. 

The technologies chosen differed considerably based on the end-use of the syngas. For power 

applications, the target was to removal sulfur to roughly 100 ppm, while minimizing the amount 

of carbon dioxide removed. It was determined that COS removal beds, followed by single 

absorber amine systems, are suitable to meet this specification. A standard Claus and Tail Gas 

Treating unit is included for recovery of elemental sulfur. For the chemicals synthesis cases, a 

multi-column physical solvent system (Genosorb, similar in style to Selexol) was selected for 

deep sulfur removal and to provide suitable H2S concentration in the acid gas for feed to a 

standard Claus unit. Zinc oxide beds are incorporated downstream of the Genosorb units as a 

polishing/guard step. While amine units with zinc oxide beds were originally evaluated for the 

chemical synthesis designs, their inability to selectively concentrate the H2S in the acid gas 

stream made them unsuitable. The results of the analysis for both cases can be seen in Table ES1 below, with information on the capital cost and utility requirements: 

Table ES-1 Syngas Clean-Up Case Summary 

Low-Temp 

to Power 

High-Temp 

to Power 

Low-Temp 

to Chemicals 

High-Temp 

to Chemicals 

Black Liquor Feedrate (MTPD) 3,200 3,200 3,200 3,200 

Syngas Rate (Mlb/hr) 196.9 203.1 196.9 203.1 

Total Installed Cost ($MM) 36.7 27.8 50.2 55.2 

Power Required (MW) 1.6 1.0 5.7 5.7 

Net Steam Required (Mlb/hr) 47 32 75 42 

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

Black Liquor Sulfur Removal Design and Cost Estimates 

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

Table ES-1 shows how the chemical synthesis cases require significantly more capital and power 

during operation. The chemicals synthesis cases are more expensive than the power cases due to 

the need to remove CO2 with physical solvents, the inclusion of ZnO beds, and the use of a shift 

reactor in the high temperature case. The need for the shift reactor creates additional carbon 

dioxide, placing a greater load on the Genosorb system. The pressure in both chemicals cases is 

lower than what is typically observed in physical solvent systems, leading to higher solvent 

circulation requirements and cost. The use of ZnO and shift reactors requires additional heat 

exchangers to be added to the design, further increasing the cost. Finally, the Genosorb system 

requires solvent refrigeration which increases the system power load. 

The syngas from the low temperature gasifier has roughly double the mass of H2S as the high 

temperature case, increasing the cost of the acid gas removal and Claus sections of the low 

temperature plants relative to the high temperature cases. This is the main reason for the cost 

difference in the power only cases. 

Based on the pulping process used, these designs could be incorporated into a pulp and paper 

facility for recovery of some of the process sulfur. This is especially true of polysulfide 

processes, where recovered elemental sulfur can be reacted with sodium sulfide to create 

polysulfide chemicals suitable for pulping uses. The use of other pulping processes may limit 

the ability to use recovered sulfur until new technologies are developed. 

Future studies should focus on the following areas to further define suitable technologies and 

confirm costs: 

 Integration of the sulfur removal section with the other parts of the gasification plant 

to obtain a better understanding of overall plant costs. 

 Alternate methods for CO2 removal in the chemicals cases. A cost comparison of 

different physical solvents and other technologies for acid gas removal would provide 

additional data to confirm the appropriate physical solvent to use in the syngas to 

chemicals design. Raising the system pressure would decrease the cost of the 

physical solvent system. 

Task 2: Gas Cleanup Design and Cost Estimates ES-2 

Black Liquor Sulfur Removal Design and Cost Estimates 

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

This study provides designs and costs for sulfur removal from black liquor derived syngas for 

both liquid fuels synthesis and power generation. Two different syngas compositions, derived 

from both low (1100°F) and high (1800°F) temperature gasification conditions, were evaluated 

for a 3200 metric tonne per day plant. The different gasification conditions and end-uses created 

four distinct cases with different conditioning requirements. The goal was to provide NREL 

with design packages that included process flow diagrams, equipment requirements, mass and 

energy balances, capital and operating costs, and labor requirements for inclusion into a larger 

black liquor conversion study. The study also addressed how the designs would be impacted by 

changing flowrates and syngas compositions. 

The work was divided into two main task areas. The first Subtasks (2.4.1 and 2.4.2) discussed 

the technologies suitable for sulfur removal for each case, along with major areas of uncertainty 

that would be studied in greater detail during the design. This rationale for technology selection 

has been updated and is shown in Section 1. Subtasks 2.4.3 through 2.4.7 consisted of 

equipment sizing, development of costs, and scaling analysis. This was an iterative process, for 

some of the technologies initially selected for use were later rejected after performing process 

modeling and receiving information from vendors. The final design and cost information, 

reflecting technologies appropriate for each case, is shown in Sections 2 and 3. While the issue 

of how recovered sulfur can be recycled for use in the pulping process was not quantitatively 

addressed, process options are discussed in Section 4. 

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

gathering the initial technology data, previous team studies (especially the wood gasification 

cases addressed in Subtask 2.2 of this overall study), data on black liquor gasification from Dr. 

Eric Larson at Princeton University, vendor information, and NREL input were all used to 

establish the items for consideration. Vendors were especially helpful in providing data for 

packaged units and unique technologies, such as Ortloff Engineers (Claus sulfur recovery), 

Uhde/GTI (physical solvent systems), Sud-Chemie (COS beds), and Johnson Matthey (ZnO 

beds). 

HYSYS was used for modeling the overall process. Design and performance for many of the 

units is based off of previous studies and vendor supplied information. 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 the packaged units and unique technologies mentioned above. 

Industry derived cost curves were used for the acid gas removal systems and as a check on other 

process items. Operating costs were developed from vendor supplied information and the system 

energy balance. Finally, labor requirements are derived from a scale-up of a detailed study put 

together by Emery Energy specific to biomass gasification. Comparisons are made to the labor 

estimate produced for the wood gasification case in Subtask 2.2. 

Task 2: Gas Cleanup Design and Cost Estimates 1 

Black Liquor Sulfur Removal Design and Cost Estimates 

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

1.1 INTRODUCTION 

The initial goal for the Nexant team was to evaluate the different sulfur cleanup processes 

suitable for syngas produced from a 3200 metric tonne per day black liquor gasification process. 

Two design cases have been explored: meeting the sulfur specifications for power generation 

(~100 ppm) and chemicals production (~0.1 ppm). The rationale for the technology selection is 

discussed in this section. 

The syngas compositions and sulfur cleanup requirements are listed in Tables 1-1 and 1-2 below. 

Table 1-1 lists the syngas compositions for the high-temperature gasification case after syngas 

cooling and heat recovery. For the low-temperature gasification case, the syngas composition 

listed is after syngas cooling and compression. 

Table 1-1 Syngas Compositions and Operating Parameters1

High-Temperature 

Gasifier Syngas 

Low-Temperature Gasifier 

Syngas 

Gasifier Temperature 1,832°F (1000°C) 1,112°F (600°C) 

Gasifier Pressure 508 psia (35 bar) 39 psia (2.7 bar) 

Syngas Flowrate (lb/hr) 203,133 196,870 

Syngas temperature to the sulfur removal unit, °F 252 200 

Syngas pressure to the sulfur removal unit, psia 487 332 

Compositions Mol% Mol% 

 H2 36.30 55.68 

 CO 34.44 21.35 

 CO2 18.15 13.80 

 CH4 1.88 3.13 

 H2O 6.32 3.85 

 COS 0.07 0.01 

 H2S 1.63 2.17 

 NH3 0.005 - 

 Ar 0.87 - 

 N2 0.32 - 

H2:CO molar ratio 1.05 2.61 

 

1 Information from Dr. Eric Larson, Princeton University 

Task 2: Gas Cleanup Design and Cost Estimates 1-1 

Black Liquor Sulfur Removal Design and Cost Estimates 

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

Table 1-2 Sulfur Specifications for Gas Cleanup 

Process Contaminants Level Source/Comment 

Power Generation Sulfur 100 ppmv Typically between 100 and 200 ppm for 

coal gasification facilities 

Methanol Synthesis Sulfur (not COS) <0.5 ppmv 

(<0.1 ppmv preferred) 

Kung, 1992 

1.2 PROCESS DESCRIPTION AND RATIONALE 

1.2.1 Sulfur Removal for Low-Temperature Design Case 

Sulfur Removal for Power Generation 

The syngas exiting the low-temperature gasifier contains sulfur compounds that must be 

removed prior to power generation or chemicals production. For the power generation cases, the 

selected sulfur removal process is a COS hydrolysis reactor followed by an amine unit. The 

syngas, at 200°F and 337 psia, enters the COS hydrolysis reactor where COS is converted to 

H2S. The syngas exiting the COS hydrolysis unit is cooled to the operating temperature of the 

amine unit, approximately at 110°F. The amine unit is designed to selectively remove H2S to a 

concentration of 100 ppmv; after an analysis of possible amine solvents, it was determined that 

MDEA is appropriate for this application. Selective removal of H2S without CO2 removal is 

desirable in power applications since CO2 in the syngas increases the volumetric flow to the 

turbine and boosts power output. 

In addition to MDEA, DGA was also evaluated as a possible solvent for the amine unit. Since 

DGA has the ability to remove COS along with H2S, its use would allow the elimination of the 

upstream COS hydrolysis unit, reducing overall capital costs. While simulations run with DGA 

and vendor input from Huntsman showed that DGA could successfully remove ~90% of the 

COS, it removes too much CO2 to be appropriate for a power application. 

The acid gas from the amine system is sent to the sulfur recovery unit (SRU). The SRU is a 

Claus plant with a sulfur recovery capacity of approximately 100 TPD. Although this sulfur 

recovery rate is low for a typical Claus plant, recovery of pure sulfur is desired for recycle back 

into the pulping process. 

Sulfur Removal for Chemicals Production 

For the chemicals production case, the sulfur removal requirement is assumed to be what is 

required for methanol synthesis. The sulfur removal unit consists of a multi-absorber physical 

solvent system (Clarient/Uhde’s Genosorb system, similar to that of Selexol), followed by ZnO 

reactor beds as a polishing step. The Genosorb unit is designed to remove the bulk of the H2S to 

about 1 ppmv and ~70% of the CO2. CO2 removal is necessary for methanol synthesis due to the 

required stoichiometric ratio of H2, CO, and CO2 : 

(H2 – CO2) / (CO + CO2) = 2 

Task 2: Gas Cleanup Design and Cost Estimates 1-2 

Black Liquor Sulfur Removal Design and Cost Estimates 

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

Initial investigations into sulfur removal for chemical production focused on chemical solvents, 

namely DEA. Although DEA can remove sufficient amounts of both H2S and CO2, the H2S 

content in the resulting acid gas stream is too low for feed to a Claus SRU (a minimum 

concentration of 40% H2S in the acid gas effluent is desired for normal Claus operation). 

Multiple simulations were attempted, including different amine circulation rates and two 

absorbers, in an attempt to increase the H2S content. None of these efforts were successful, 

forcing the team to explore other options for sulfur removal. 

The Genosorb process is frequently marketed in Europe as an alternative to the Selexol process. 

Both Genosorb and Selexol physical solvent processes are based on the use of polyethylene 

glycol ether solvent mixtures. The Selexol process solvent is a mixture of dimethyl ethers of 

polyethylene glycol, and has the formulation CH3O(CH2CH2O)nCH3 where n is between 3 and 9. 

There are other process suppliers using solvents similar to the Selexol process, such as Clariant 

GmbH of Germany, which offers a family of dialkyl ethers of polyethylene glycol. The Clariant 

solvents, under the Genosorb name, include dimethyl and dibutyl ethers of polyethylene glycols. 

Treatment in the Genosorb unit removes the H2S and COS content to roughly 1 ppm. Following 

the Genosorb unit, the sweet syngas enters the ZnO reactor where residual COS and H2S are 

removed at 750°F. The ZnO reactor is used as a polishing step to reduce the sulfur concentration 

to < 0.1 ppmv. 

1.2.2 Sulfur Removal for High-Temperature Design Case 

Sulfur Removal for Power Generation 

For the power generation case, the sulfur removal process for the syngas from the hightemperature gasifier is similar to that of the syngas from the low-temperature gasifier. The sulfur 

removal unit consists of a COS hydrolysis reactor followed by an MDEA amine unit. The 

syngas enters the COS hydrolysis reactor at 252°F and 487 psia. Similar to the low-temperature 

design case, DGA was also evaluated as a possible solvent. As with the low-temperature case, 

DGA removes too much CO2 than what is appropriate for use in power generation. 

Sulfur Removal for Chemicals Production 

For the chemicals production case, the sulfur removal process is also similar to that of the lowtemperature gasifier case, with the exception of the shift reaction step prior to the Genosorb unit. 

The syngas exiting the high-temperature gasifier has a H2/CO ratio of 1.05; thus, a portion of the 

syngas is sent to the shift reactor to adjust the H2/CO ratio. The shifted syngas is mixed with the 

unshifted portion, then is cooled before entering the Genosorb unit. The configuration of the 

Genosorb unit is similar to that of the low-temperature syngas case. A greater amount of CO2

removal is required in this case due to the CO2 produced in the shift reactor. The sweet syngas 

exiting the amine unit then enters the ZnO reactor where the residual COS and H2S compounds 

are removed to meet the sulfur requirement of < 0.1 ppmv. As in the low temperature case, a 

chemical solvent system (amine) could not be configured to remove the necessary acid gases and 

have an H2S concentration high enough for feed to a Claus SRU. 

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

Black Liquor Sulfur Removal Design and Cost Estimates 

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

1.3 DISCUSSION 

1.3.1 Technologies Not Chosen 

Physical solvent systems such as Selexol and Rectisol were considered but not originally 

selected for this process. Only when it was determined that an amine system could not 

effectively concentrate the H2S at a high enough level for feed to a Claus SRU was a physical 

solvent system selected. Generally, physical solvents are considered when there is high system 

pressure (> 700 psi), or high acid gas partial pressure (> 50 psi). The syngas in this study has 

adequate acid gas partial pressure to consider physical solvent systems; however, a chemical 

solvent system (amine) was originally chosen instead on the basis of comparable sulfur removal 

capability and cost. The relatively low syngas pressure available in each case decreases the 

physical solvent removal efficiency and increases solvent circulation requirements. This leads to 

higher overall capital and operating costs. 

A Rectisol system can remove virtually all the acid gas components such as H2S, CO2, COS, 

HCN, and mercaptans to the level required for chemicals production without the need for 

separate COS hydrolysis and ZnO reactor units. However, the capital investment for a Rectisol 

system can be significant because of the complexity, power requirements, and use of stainless 

steel in parts of the design. Since the syngas in this study contains only COS and H2S, the 

configurations established in both the power and chemicals designs should be sufficient to meet 

the sulfur removal requirements. 

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

Black Liquor Sulfur Removal Design and Cost Estimates 

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

2.1 INTRODUCTION AND METHODOLOGY 

After deciding on the appropriate technology for sulfur removal and recovery, the next step was 

to size process equipment for sulfur removal from black liquor derived syngas, and obtain cost 

estimates for individual pieces of equipment. 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 original process selection 

deliverable (Subtasks 2.4.1 and 2.4.2). Further refinement was made after vendor 

input and analysis of the process model results. 

 Vendor quotes were obtained for unique and specialized equipment such as ZnO 

catalyst/reactors, Claus sulfur recovery, and all catalysts. Performance information 

for the physical solvent system, Genosorb, was obtained from Uhde. Cost for the 

system was estimated from Uhde supplied information, previous physical solvent 

studies, and industry developed cost estimates for amines versus physical solvents for 

IGCC applications. 

 The performance and energy requirements for the amine units were estimated using 

commercially available software that is specific for amine unit modeling (ProTreat 

and HYSYS). In addition, input was provided by vendors for estimating COS 

removal from the amine systems and for assistance in simulation development. Once 

performance specifics were obtained, an industry developed cost curve was used for 

estimating installed cost. 

A complete set of PFDs can be seen in Appendix A through D. The design and cost estimates 

for the high-pressure and low-pressure cases are presented in the Equipment List, which can be 

seen in Appendix E. The Equipment List groups process equipment by the following categories: 

reactors, cyclones, vessels, heat exchangers, compressors, pumps, turbines, and packaged units 

(the amine and sulfur recovery 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 

Task 2: Gas Cleanup Design and Cost Estimates 2-1 

Black Liquor Sulfur Removal Design and Cost Estimates 

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

An installation factor of 2.57 was applied to the equipment cost to arrive at the total installed 

cost. The installation factor was derived based upon previous experience and Bechtel estimates. 

The total installed cost for each of the cases can be seen in Table 2-1. 

Table 2-1 Black Liquor Syngas Sulfur Removal Costs (Installed) 

Case Capital Cost ($MM) 

High–Temperature Gasifier to Power 27.8 

Low-Temperature Gasifier to Power 36.7 

High-Temperature Gasifier to Chemicals 55.2 

Low-Temperature Gasifier to Chemicals 50.2 

As can be seen in the equipment list (Appendix E), a major source of plant cost is due to the 

Claus sulfur recovery and Tail Gas Treating units. The cost of these units represents 60 to 70% 

of the overall plant costs in both power cases. The designs represent a standard Claus and Tail 

Gas Recovery system; however, the sulfur recovery configuration that is used in a black liquor 

gasification plant may vary based on the pulping process and technology choice for sulfur 

recovery. A more detailed explanation of the sulfur recycle options is presented in Section 4. 

The chemicals synthesis cases are more expensive than the power cases due to the need to 

remove CO2, the inclusion of ZnO beds, and the use of a shift reactor in the high temperature 

case. The use of ZnO and shift reactors also requires additional heat exchangers to be added to 

the design, further increasing the cost. In addition, the chemicals cases required the use of more 

expensive physical solvents for sulfur and CO2 removal. Although COS beds were no longer 

necessary due to the ability of the Genosorb system to adequately remove COS, this reduction in 

cost did not offset the overall expense of the Genosorb unit. Lower solvent temperatures, 

inclusion of an additional stripping column, higher solvent flow rates, and relatively low system 

pressure for a physical solvent system all increases the cost of the physical solvent acid gas 

removal unit when compared to the amine system used in the power cases. 

The high-temperature to chemicals case is more expensive than the low-temperature case due to 

the greater acid gas removal requirement. The shift reactor in the high-temperature case 

significantly increases the CO2 content, which, in general, increases the cost of the acid gas 

removal system. However, the lower pressure of the low-temperature system raises the removal 

cost on a dollar/ton basis due to higher solvent circulation requirements. Future studies should 

look at increasing system pressure to lower the physical solvent system cost. 

The syngas from the low temperature gasifier has roughly double the mass of H2S as the high 

temperature cases. This increase in sulfur content not only increases the cost of the acid gas 

removal unit, but also significantly increases the cost of the Claus and Tail Gas Treating sections 

of the plant. The higher sulfur content increases the overall cost in the low-temperature cases by 

~$8MM due to the increased cost of the Claus and Tail Gas Treating units. 

Task 2: Gas Cleanup Design and Cost Estimates 2-2 

Black Liquor Sulfur Removal Design and Cost Estimates 

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. Additional design specific assumptions are outlined below. 

Amine System: For the power cases, an amine needed to be used that was selective for H2S 

removal and that minimized CO2 removal. MDEA is appropriate and relatively cost effective in 

this service. The simulations performed with MDEA show that a single absorber system can 

work effectively, provided the amine circulation rate and column size are large enough. 

Genosorb: A multi-column process was determined to be appropriate for both removing the 

necessary acid gas and concentrating the H2S adequately for feed to the Claus unit. The system 

consists of separate H2S and CO2 absorbers in order to remove the appropriate amount of acid 

gases specified in the design basis. This design is also necessary for flashing off CO2 captured in 

the H2S absorber. Multiple stages of solvent flash may be required for solvent regeneration. In 

addition, a CO2 enrichment column may be necessary in certain instances, such as the low 

temperature case, to pre-load the solvent to prevent too much CO2 removal from the syngas 

stream. A general multi-column process flow is shown in the PFD section of this report. 

Heat Integration: Detailed heat integration was not practical for this design, since sulfur treating 

is only a small portion of a large black liquor gasification facility. However, areas have been 

identified in the PFDs where heat can be recovered via steam generation.

COS Removal Beds: In both power cases, COS hydrolysis beds were required to remove 

sufficient COS from the inlet syngas stream. Two different types of COS removal catalysts are 

used. Based on vendor recommendations, a platinum based catalyst has been selected for the 

high temperature gasification cases, while a chromium catalyst is used in the low temperature 

cases. Platinum catalysts are best suited for high pressure and streams that contain contaminants 

such as ammonia. 

Sulfur Recovery: Per the scope agreed upon with NREL, a cost has been estimated for sulfur 

recovery and tail gas treating, with a generic PFD included with each design. The cost estimate 

is derived from previous vendor quotes for a Claus and Tail Gas Treating unit, scaled to meet the 

sulfur design requirements. The cost estimate has been confirmed with other literature sources. 

The actual configuration for sulfur recovery and reuse in the pulping process may vary. 

2.3 OPERATING COSTS AND UTILITY REQUIREMENTS 

Operating costs and utility requirements can be seen in Tables 2-2 through 2-6. The main 

sources of costs are catalysts for the ZnO, shift, and COS beds, and steam/power for the acid gas 

removal and sulfur recovery units. With the exception of the platinum catalyst required in the 

high temperature power case, catalyst costs are relatively low. Power and steam needs for the 

acid gas removal and recovery units make up the majority of the operating costs. The physical 

solvent system requires significantly more power to operate than the amine unit due to the chiller 

required to maintain low solvent temperatures. This power requirement greatly raises the 

operating cost of the chemicals cases when compared to the power-only designs. 

Task 2: Gas Cleanup Design and Cost Estimates 2-3 

Black Liquor Sulfur Removal Design and Cost Estimates 

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

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

considerably based on the assumptions made for plant performance and for steam, chemicals, 

and power costs. For example, the overall gasification plant may have excess power and steam 

that can be used by the sulfur treating units at low cost. Until this section of the plant is

incorporated into a complete black liquor gasification unit, it is not possible to estimate the 

overall operating costs. 

Table 2-2 Catalyst and Chemicals Requirements 

Variable Amount Required Cost Notes 

COS 

Removal 

Catalyst 

Low-Temperature to Power Case: 

2470 cubic feet 

High-Temperature to Power Case: 

2400 cubic feet 

Price: 

LT to Power: $575/cubic 

foot (Cr based) 

HT to Power: $1587/cubic 

foot (Pt based) 

Information provided by SudChemie. Initial fill, then replaced 

every 5 years. HT case process 

conditions require the more robust 

catalyst. 

ZnO 

Catalyst 

Low-Temperature to Chemicals Case: 

823 cubic feet 

High-Temperature to Chemicals Case: 

818 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. 

Sour Shift 

Catalyst 

High-Temperature to Chemicals Case: 

150 cubic feet 

Price: $575/cubic foot 

(Sud-Chemie) 

Initial fill then replaced every one 

to two years. 

Acid Gas 

Removal 

Chemicals 

Low-Temperature to Power Case: 

337,200 lb/hr lean MDEA 

High-Temperature to Power Case: 

297,500 lb/hr lean MDEA 

Low-Temperature to Chemicals Case: 

1,160,000 lb/hr lean Genosorb 

High-Temperature to Chemicals Case: 

668,000 lb/hr lean Genosorb 

Price: 

MDEA = ~$0.50/lb 

Genosorb = ~$1.30/lb 

 

Make-up requirements may vary. 

Chemical cost may vary. 

Task 2: Gas Cleanup Design and Cost Estimates 2-4 

Black Liquor Sulfur Removal Design and Cost Estimates 

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

Table 2-3 High Temperature Syngas To Power Case Utility Requirements 

Norm. Max 

(3). KW 385 psig 35 psig 5 psig Cond. Proc. C.W. circ. (2). Water MMBtu/hr (LHV)

H-100 Syngas Cooler/Steam Generator (7.0)

H-101 Amine Precooler 2,009 20.1

H-103 Lean Solvent Cooler 1,674 16.8

H-104 Amine Stripper Reboiler 39.9

H-105 Acid Gas Condenser 1,672 16.7

P-101 Lean Solvent Pump 230 172

A-120 Claus Plant 1,111 829 3.5 (5.4) (21) 29.7

TOTAL 1,341 1,000 4 35 (7) (21) 5,356 54 30

NOTES: 1. All Figures shown above represent normal utility usage requirements except:

 () indicates normal utility generated

 * indicates intermittent usage or make, not included in totals

2. CWS temperature is 80 F and CWR temperature is 100 F. Makeup water to cooling tower is not shown

3. Utility consumption for max. load conditions is not shown.

Fuel Gas

Item Name

Cooling 

MMBTU/HR Water, GPM

Item No

Steam 

M Pounds per Hour

Elect. 

Power Load BHP

Table 2-4 Low Temperature Syngas To Power Case Utility Requirements 

Norm. Max 

(3). KW 385 psig 35 psig 5 psig Cond. Proc. C.W. circ. (2). Water MMBtu/hr (LHV)

H-100 Syngas Cooler/Steam Generator (8.6)

H-101 Amine Precooler 2,080 20.8

H-103 Lean Solvent Cooler 2,269 22.7

H-104 Amine Stripper Reboiler 58.9 (59)

H-105 Acid Gas Condenser 2,967 29.7

P-101 Lean Solvent Pump 200 149

A-120 Claus Plant 1,908 1423 6.0 (9.2) (36) 50.9

TOTAL 2,108 1,572 6 50 (9) (95) 7,316 73 51

NOTES: 1. All Figures shown above represent normal utility usage requirements except:

 () indicates normal utility generated

 * indicates intermittent usage or make, not included in totals

2. CWS temperature is 80 F and CWR temperature is 100 F. Makeup water to cooling tower is not shown

3. Utility consumption for max. load conditions is not shown.

Steam 

M Pounds per Hour Water, GPM Cooling MMBTU/HR Fuel Gas

Item No Item Name

Load BHP Elect. 

Power

Table 2-5 High Temperature Syngas To Chemicals Case Utility Requirements 

Norm. Max 

(3). KW 485 psig

385 

psig

35 to 

80 

psig

5 

psig Cond. Proc. C.W. circ. (2). Water MMBtu/hr (LHV) MMSCFD

H-110 LT Shift Cooler/ LP Steam Generator (78.0)

H-111 Syngas Cooler/ LP Steam Generator 15 11 (31.1)

H-112 Solvent Precooler 3,095 31.0

Genosorb Unit 6,568 4,900 29.0 1,809 18.1

H-118 ZnO Beds Preheater 29.9

R-110 LT Shift Reactor 93.7

A-120 Claus Plant 1,117 833 3.5 (5.4) (21) 29.8

TOTAL 7,700 5,744 94 4 (25) (31) (21) 4,904 49

NOTES: 1. All Figures shown above represent normal utility usage requirements except:

 () indicates normal utility generated

 * indicates intermittent usage or make, not included in totals

2. CWS temperature is 80 F and CWR temperature is 100 F. Makeup water to cooling tower is not shown

3. Utility consumption for max. load conditions is not shown.

Combustion 

Air

Steam 

M Pounds per Hour Water, GPM Cooling MMBTU/HR Fuel Gas

Item No Item Name

Load BHP Elect. 

Power

Task 2: Gas Cleanup Design and Cost Estimates 2-5 

Black Liquor Sulfur Removal Design and Cost Estimates 

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

Table 2-6 Low Temperature Syngas To Chemicals Case Utility Requirements 

Norm. Max 

(3). KW 385 

psig

35 or 

80 

psig

5 

psig Cond. Proc. C.W. circ. 

(2). Water MMBtu/hr 

(LHV)

H-100 Syngas Cooler/Steam Generator (8.6)

H-111 Solvent Precooler 1,558 15.6

H-117 ZnO Beds Preheater 45.0

Genosorb Unit 5764 4300 42.6 2,683 26.9

A-120 Claus Plant 1,915 1429 6.1 (9.2) (36) 51.1

TOTAL 7,679 5,729 6 78 (9) (36) 4,242 42

NOTES: 1. All Figures shown above represent normal utility usage requirements except:

 () indicates normal utility generated

 * indicates intermittent usage or make, not included in totals

2. CWS temperature is 80 F and CWR temperature is 100 F. Makeup water to cooling tower is not shown

3. Utility consumption for max. load conditions is not shown.

Steam 

M Pounds per Hour Water, GPM Cooling 

MMBTU/HR Fuel Gas

Item No Item Name

Load BHP Elect. 

Power

A few differences exist in the utility requirements between the high and low temperature cases, 

as well as the power and chemicals cases. In general, the H2S yield out of the low-temperature 

gasifier is higher, leading to an increased load on the acid gas removal and sulfur recovery units. 

A greater net amount of power and steam is therefore necessary in the low temperature cases. 

The need to remove CO2 in the chemicals cases changes the type of solvent used, leading to a 

significantly greater power load. Solvent chilling requirements increase both the power and 

cooling water supply required in the chemicals cases. 

2.4 CHANGING FLOWS, CONDITIONS, AND COMPOSITIONS 

As was presented in the wood gasification cases2

, an analysis was performed to estimate the 

impact that changes in flowrate and composition would have on the black liquor sulfur removal 

designs. Information for all four design cases are outlined below; the scaling factors appropriate 

for each piece of equipment are listed in Table 2-7. 

2.4.1 Flowrate Impacts 

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

guidelines, transportation limits, and maintenance restrictions. An analysis of how the designs 

would change if the throughput was increased by 50% was performed. The effects of this 

change are discussed below with respect to all four black liquor gasification cases. A discussion 

of changes due to lower flows (i.e., a minus 50% change in flow) is not included. Designs of 

this nature would only make the plant equipment smaller and piping simpler (fewer parallel 

units). 

 

2 Nexant, “Task 2 Final Report, Gas Cleanup Design and Cost Estimates: Wood Feedstock”, as part of Subcontract ACO-5-44027, 

December 2005 

Task 2: Gas Cleanup Design and Cost Estimates 2-6 

Black Liquor Sulfur Removal Design and Cost Estimates 

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

High-Temperature Gasification Cases 

Power Production 

For the high-temperature gasifier for power production design case, the COS hydrolysis reactor 

will have to have an additional parallel train or field fabrication performed due to equipment size 

and weight limitations during transportation. For this reactor, the drum inside diameter would 

increase from 14 feet to about 17 feet for a flowrate 50% greater than the base case. The outside 

diameter (including nozzles and flanges) would be well beyond most road transportation limits in 

the U.S. However, transportation by rail or barge may still be feasible depending on the exact 

plant location. 

Another piece of equipment that may require a parallel train is the syngas cooler/LP steam 

generator (H-100). In this case, the size limitation of the heat exchanger is 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 for the tube bundle). It then becomes an economic 

question of bringing in special maintenance equipment during turnarounds, or using smaller, 

parallel, process equipment. 

It is expected that the amine absorber and stripper required for this design will have already 

exceeded the maximum transport size, and thus require parallel units or field fabrication. 

Increasing the capacity by 50% may require additional parallel equipment and a more complex 

pumping manifold. 

Chemicals Production 

The syngas cooler has the same issue as the cooler in the power case, with a base case tube 

bundle that would be over 7 feet. Also, the Genosorb unit, as with the power case, may already 

require a parallel unit or field fabrication in the base design. Expanding the capacity by 50% will 

require more parallel equipment and a more complex pumping manifold. 

The chemicals case requires additional pieces of equipment that were also evaluated. The LT 

shift reactor is small enough in the base case that multiple trains would not be required in a 

scaled-up design. The LT shift cooler/LP steam generator would face the same tube bundle 

restriction that the syngas cooler does, since the base case exchanger has a diameter over 7 feet. 

Low-Temperature Gasification Cases 

Power Production 

For the low-temperature gasifier for power production design case, the issues raised in the hightemperature gasifier for power production discussion above concerning the COS hydrolysis 

reactor and amine unit are applicable for this design as well. Units in parallel of field fabrication 

for these sections will be required. 

Task 2: Gas Cleanup Design and Cost Estimates 2-7 

Black Liquor Sulfur Removal Design and Cost Estimates 

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

Chemicals Production 

For the chemicals production case, a larger ZnO bed preheater would exceed the general 

maintenance limits for pulling the tube bundle, and may require a parallel unit. An analysis will 

need to be made to determine if a parallel bed is worth the additional investment. And as with 

the high-temperature to chemicals case, it is likely that the Genosorb unit would require a 

parallel unit or field fabrication. 

General Information 

Other considerations must be made to take into account the impact that an increase in flowrate 

will have on the overall plant. A plant that is 50% larger will require more plot area due not only 

to the larger equipment and storage requirements, but due to offsite considerations. The utility 

requirements will need to be scaled accordingly. In addition, 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 operational units. 

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 2-7 gives typical values of n for most of the equipment 

included in these designs. 

Task 2: Gas Cleanup Design and Cost Estimates 2-8 

Black Liquor Sulfur Removal Design and Cost Estimates 

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

Table 2-7 Examples of Typical Exponents for Equipment Cost Versus Capacity3,4,5,6,7

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 

Equipment Size Range Units Exponent** 

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 

25-200 

hp 0.56 

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. 

2.4.2 Composition Impacts 

The designs presented here are most sensitive to changes in CO and COS. It does not appear that 

changes significant enough in CO2, H2S, or methane concentrations could occur that would 

change the designs significantly. The expected rates of fluctuation in these components could be 

handled by the current designs. 

Increasing the CO concentration will have a significant influence on the COS hydrolysis reactor 

for the low-temperature to power case. At a higher CO concentration, a different catalyst 

(platinum on alumina) would be recommended by the vendor to provide a greater efficiency and 

appropriate performance. The platinum based catalyst will be more expensive, but a smaller 

reactor will be necessary due to the higher space velocity necessary. Changes in the H2/CO ratio 

 

3 Perry, Robert H., and Green Don W., Perry’s Chemical Engineers’ Handbook, 7th edition, page 9-69. 4 Walas, Stanley M., “Chemical Process Equipment – Selection and Design,” Butterworths, page 665 

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

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

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

August 1990, pp 77-82 

Task 2: Gas Cleanup Design and Cost Estimates 2-9 

Black Liquor Sulfur Removal Design and Cost Estimates 

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

could also impact the chemicals cases, and may require different conditions to assure the 

appropriate ratio for synthesis is maintained. 

An increase in the COS concentration could be significant since the COS reactors are already at 

the limit for most forms of transport (14 feet). An elevated amount of COS entering the reactor 

would require either more frequent catalyst changeouts, a change in the way the reactor is 

fabricated, or a parallel train. 

2.5 FOLLOW-UP AND AREAS FOR FURTHER STUDY 

The analysis performed in this section of the project sets the base case for the sulfur removal 

section of four different black liquor gasification designs. After in-depth analysis of these cases, 

the team has identified a number of areas for further study: 

 The original vendor quotes obtained for COS removal used a platinum catalyst for 

both power designs. Only through in-depth discussion with the vendor was it 

determined that a chromium catalyst could be substituted for some process 

conditions. A greater investigation of the assumed process conditions and discussions 

with other vendors will help to confirm if the more expensive platinum catalyst is 

necessary. 

 Integration of the sulfur removal section with the other parts of the gasification plant 

to get a better picture of overall plant costs. 

− An analysis should also be performed for how the result of this analysis fits with 

previous black liquor gasification studies, such as the Larson papers8

. Previous 

studies have spent little time on this topic; integrating the detailed results from 

this study will provide more insight and better accuracy for the actual facility 

costs. 

 Alternate methods for CO2 removal in the chemicals cases. A cost comparison of 

different physical solvents and other technologies for acid gas removal would provide 

additional data to confirm the appropriate physical solvent to use in the syngas to 

chemicals design. Use of amine has already been ruled out due to the inability to 

concentrate H2S in the feed stream to the Claus unit. 

 Appropriate assumptions for operating costs, including availability, catalyst life in 

each major reactor, and a determination of if steam and power could be exported from 

elsewhere in the gasification plant. 

 An investigation into the ability to raise the syngas pressure in the chemicals cases to 

lower the cost of the acid gas removal system. While raising system pressure will 

either require different gasification design specifications or downstream compression, 

these changes may be justified based on the decrease in unit costs of the physical 

solvent acid gas removal system. 

 

8 Larson E.D., S. Consonni, and R.E. Katofsky (2003). “A Cost-Benefit Assessment of Biomass Gasification Power Generation in the Pulp 

and Paper Industry,” Princeton University, October 3, Page 96. 

Task 2: Gas Cleanup Design and Cost Estimates 2-10 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 
Section 3 Labor Requirements 

3.1 SUMMARY 

The work completed in the previously referenced wood gasification designs acts as a base case to 

estimate the labor requirements for the four black liquor derived syngas cases. Because this 

design task focused on only a small portion of the overall black liquor conversion facility, a 

number of assumptions had to be made for the rest of the plant. Differences with the wood 

gasification cases were identified and will be highlighted below. 

The two major items investigated relative to the wood gasification cases were the plant size and 

the level of complexity. For labor estimating purposes, the black liquor plant size is considered 

roughly similar to the wood gasification cases. While a greater amount of mass is being fed to 

the gasifier (3200 MTPD of black liquor, versus 2000 MTPD of wood), the amount of syngas 

entering the sulfur removal block is actually lower (~200 Mlb/hr versus 227 to 272 Mlb/hr). 

Based on these numbers, the plant size for labor purposes is considered the same. 

All the black liquor designs are also estimated to have roughly the same complexity as the wood 

gasification cases. While the black liquor gasification plants have additional sulfur treatment 

requirements (COS beds, Claus units, and two absorber acid gas treatment units for the 

chemicals cases), some units that exist in the wood gasification cases, such as feedstock handling 

and the LO-CAT unit, are no longer required. In addition, the cases producing power would 

require a gas turbine and HRSG, but would no longer need units specific to chemicals synthesis, 

such as additional syngas compressors, reactors, and certain heat exchange equipment. For these 

reasons, the complexity between the power and chemicals cases is also considered similar. 

In summary, the labor estimate for the chemicals cases is estimated to be the same as for the 

wood gasification cases, $2,539,720/year. For the power cases, it is not expected that a 

dedicated on-site laboratory would be required. Eliminating the laboratory manager and 

technician needs will cut the labor requirements by $220,800/year, to $2,318,920/year total labor 

costs. 

3.2 LABOR REQUIREMENTS 

The following labor categories and positions will be required for the 3200 MTPD black liquor 

gasification plant. It is assumed that this facility is connected to, but independent from, the pulp 

and paper plant. Having a dedicated feed source to the gasification plant will eliminate the need 

for feedstock handling and storage facilities. If the plant is independent, a different management 

team and overhead rate is necessary than what may be used in the pulping plant. If both the 

pulping and gasification facility was owned and operated by the same entity, it is possible that 

management, overhead, and technical labor costs could be reduced. Since black liquor 

gasification is not a widely accepted commercial technology that will likely be owned and 

operated by a group distinct from the existing pulp and paper facility, this synergy is not 

assumed at this time. Plant optimization studies should keep this potential cost reduction in 

mind. 

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

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 
Section 3 Labor Requirements 

The information below was largely presented in the wood gasification final report. Slight 

modifications have been made for the black liquor cases. 

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. Necessary in chemicals case ONLY. 

Laboratory Technician: Responsible for sample gathering, analytical equipment maintenance, 

and laboratory testing. Works straight days, with some overtime 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. Necessary in 

chemicals case ONLY.

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 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 

Task 2: Gas Cleanup Design and Cost Estimates 3-2 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 
Section 3 Labor Requirements 

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, holidays, training, ongoing maintenance and periodic outage/turnaround 

planning. In addition, the fifth crew supports updates to control system programming, data 

collection, and instruments. 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 Black Liquor Plant 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** 

(**Chemicals Only) 

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

Laboratory 

Technician** 

(**Chemicals Only)

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

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

Task 2: Gas Cleanup Design and Cost Estimates 3-3 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 
Section 3 Labor Requirements 

Position Number 

Base Salary 

or Hourly 

Rate 

Annual 

Overtime 

and Holiday 

Hours 

Overtime 

Rate 

Total Annual 

Cost 

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—Chemicals) $2,539,720 

Total Labor and Benefits (Operating Labor Cost—Power) $2,318,920 

3.3 DIFFERENCES WITH WOOD GASIFICATION CASES 

Two major items were considered when estimating the labor differences between the wood and 

black liquor gasification cases: size and complexity impacts. Note that a number of assumptions 

have been made in both sets of cases since only a portion of the plant was designed by the 

Nexant team. The labor estimates provided here are for the entire gasification facility, assuming 

a stand-alone plant with a dedicated feed source. After these designs are integrated into a 

complete facility, these assumptions should be checked for their validity. 

3.3.1 Size 

The wood gasification final report demonstrated that a larger gasification facility will only 

require an incrementally larger labor force as the size increases. The size related differences 

between Emery Energy’s 70 MWe facility (which the labor estimate was originally based on) 

and the wood gasification cases were relatively minor. In the black liquor gasification cases, the 

total feed to the gasifier is larger relative to the wood gasification cases. However, gasifying a 

liquid feedstock is very different than a solid one. The total amount of syngas exiting the gasifier 

in the black liquor cases varies considerably depending on the type of gasification scheme used. 

The difference is largely due to the amount of entrained water assumed in the high-temperature 

case. 

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

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 
Section 3 Labor Requirements 

In order to perform a more direct comparison, Nexant looked closely at the water-free syngas 

flowrate entering the sulfur removal units. The black liquor syngas flowrate, ~200 Mlb/hr, is 10 

to 35% lower than in the wood gasification cases. Since the main reason for the high syngas 

flowrate exiting the gasifier in the high-temperature case is only due to the amount of entrained 

water, this should not add considerably to the plant labor requirements. While it is possible that 

this lower water-free flow rate may lead to slightly lower labor requirements, it is likely that the 

amount of labor will be similar. Therefore, it was assumed that the size of the facility being 

considered in the black liquor gasification case is the same as the wood gasification case for 

labor requirements. 

3.3.2 Complexity 

The unit operation requirements in the black liquor and wood gasification cases were compared 

against each other to determine the complexity impacts. The major differences in the black 

liquor relative to the wood gasification designs can be seen in Table 3-2. 

Table 3-2 Complexity Differences Between Black Liquor and Wood Gasification Cases 

All BL Cases BL Power Cases BL Chemicals Cases 

Units Added Claus S Recovery and Tail Gas 

Treatment 

Gas Turbine 

HRSG 

COS Removal Beds 

Shift Reactor (HT Case Only) 

Genosorb Unit 

Units Removed LO-CAT 

Major Feed Handling Equipment 

Chemicals Synthesis Equipment 

Methanol Compressor 

Amine Unit 

The shift and COS removal beds do not add a significant amount of complexity to the black 

liquor designs, but the Claus, Tail Gas Treating, and Genosorb units do. This is balanced by 

removing the LO-CAT sulfur recovery unit, much of the feedstock handling equipment, and the 

amine system in the chemicals cases. Because of the assumption that a dedicated black liquor 

stream will be available for the gasifier, much of the weighing, crushing, and drying equipment 

necessary for the wood gasification cases has been removed. The net impact is that in general, 

the black liquor cases do not add to the design complexity. 

The introduction of a gas turbine and HRSG adds significantly to the complexity of a power 

production case. However, once all the equipment necessary for chemicals synthesis, such as a 

dedicated syngas compressor, multiple reactors, preheat exchangers, recycle streams, and 

sampling stations, are removed, the net impact is estimated to be minor. In fact, the laboratory 

supervisor and technicians deemed necessary in the chemicals cases can be eliminated from the 

power only case. Any sampling of the feedstock is assumed to be done at the pulping facility. 

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

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 
Section 4 Sulfur Recycle Options 

As part of the project scope, Nexant was asked to consider the possible ways to reintroduce 

recovered sulfur back to the front-end of the pulping process. Being able to turn sulfur recovered 

from the syngas back into the chemicals used in the pulping process will increase process 

efficiency, eliminate waste disposal, and improve the environmental footprint. While Nexant did 

not evaluate the process economic or overall plant impacts, a number of potential recovery 

options, tied to different pulping processes, are outlined here for future study. 

4.1 INTRODUCTION 

The pulp and paper industry currently uses Tomlinson boilers to produce energy from the black 

liquor produced in the Kraft pulping process. A number of researchers and professionals 

advocate replacing Tomlinson boilers in the pulp and paper industry with gasifiers in order to 

more efficiently create energy from the black liquor produced in the Kraft pulping process. 

While initial studies have shown that black liquor gasification has potential, there are some 

concerns with the technology. One concern involves the loss of sulfur that is present as Na2S in 

both the white liquor and the black liquor as H2S in the gasifier. A low temperature gasifier and 

a high temperature gasifier have been shown to lose 44% and 16% of the Na2S present in the 

black liquor to the syngas, respectively9

. This H2S can be captured and converted to elemental 

sulfur, but the method in which this sulfur should be recycled is not established. The following 

summarizes possible methods for capturing and recycling the sulfur. 

4.2 PULPING METHODS 

The following information comes from “A Cost-Benefit Assessment of BLGCC Technology” 

from Eric Larson et al10. Of the four alternative ways of pulping, each requires a different way 

to recycle sulfur: 

 Polysulfide Pulping: Polysulfide can be produced by capturing H2S from the 

scrubber, converting it to elemental sulfur in a Claus plant, and then remixing the 

sulfur with white liquor. Subsequent use of polysulfide in the digester results in pulp 

yield increases on the order of 1–2%11. 

 Split Sulfide Pulping: Green liquor from the gas scrubber will have a high sulfide 

content and a low alkali content. Impregnation of wood chips with this stream will 

satisfy one of the well-known pulping rules-of-thumb, which recommends a high 

concentration of free hydrosulfide ions in the initial phase of the cook. The resulting 

pulp should have less residual lignin that is difficult to dissolve, and the strength will 

be enhanced by about 5%.12

 

9 Eric Larson. “A Cost Benefit Assessment of Biomass Gasification Power Generation in the Pulp and Paper Industry.” October 8, 2003. S6 10 Eric Larson et al. “A Cost-Benefit Assessment of BLGCC Technology.” TAPPI Journal. Vol. 83 No. 6. 

11 Jarneel, H., TAPPI 1994 Pulping Conference Proceedings, TAPPI PRESS,Atlanta, 1994, p. 781.; Prasad, D. Y., Jameel, H., and Gratzl, J., 

“Extended delignification of hardwood with anthraquinone and polysulfide,” TAPPI 1995 Pulping Conference Proceedings,TAPPI PRESS, 

Atlanta, 1995. 

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

12 Teder, A. and Tormund, D., Tappi J. 72(5): 205(1990).

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 
Section 4 Sulfur Recycle Options 

 Alkaline Sulfite and Anthraquinone (ASAQ) Pulping: ASAQ pulping has been 

reported to give substantially higher yields than Kraft processes13. Pulping processes 

based on alkaline sulfite and anthraquinone also have much lower potential for 

producing odor than Kraft processes have. The problem with implementation of 

ASAQ pulping has been the inability to regenerate sodium sulfite with the Tomlinson 

recovery cycle. Recovery of H2S from the gasifier makes it possible to regenerate 

part of the sulfite.

 Hydrogen Sulfide Impregnation: Researchers at STFI have shown that impregnation 

of Scandinavian softwood chips with green liquor in the presence of 0.3-MPa 

hydrogen sulfide results in a 5% yield increase14. 

Sulfur recycle options for different pulping methods, along with the benefits and drawbacks, are 

shown in Table 4-1. 

Table 4-1 Sulfur Recycle Options for Various Pulping Methods 

Method Benefits Drawbacks 

Polysulfide Pulping Sulfur Recycle Options 

Option #1: Capture H2S 

with conventional sulfur 

removal technology (amine, 

Selexol, or Rectisol) and 

convert to elemental S with 

a Claus Unit. Dissolve 

elemental sulfur in Na2S at 

moderate temperature 

(<100oF). This creates 

polysulfide (Na2-S3-S) that 

can be used to digest 

feedstock for polysulfide 

pulping15. 

 Polysulfide pulping has a higher 

digester yield than conventional 

pulping for a fixed pulp production. 

 Pulp yield increases are on the 

order of 1-2%16.

 Conventional sulfur removal 

technologies are well established. 

 CO2 co-absorption can be avoided 

when H2S is converted to 

elemental sulfur. Avoiding this 

decreases the causticizing load 

compared to Options #2 and #317. 

 Increased causticizing load due to 

increased amount of Na2CO3 leaving the 

gasifier in the condensed phase. 

 Decreases the alkali content of whiteliquor. 

Option #2: Capture H2S 

with green liquor as 

scrubbing medium. Then, 

convert the green liquor to 

white liquor with a 

causticizing cycle18. 

 No need for sulfur removal 

technology or Claus. 

 Polysulfide pulping has a higher 

digester yield than conventional 

pulping for a fixed pulp production. 

 Not as established a process as Selexol, 

Rectisol, or amine. Experimental testing 

needs to be performed to determine if 

this process is appropriate. 

 Increased causticizing load due to CO2 in 

the syngas being co-absorbed in the 

green liquor. The co-absorbed CO2 will 

form additional Na2CO3 in the liquor that 

must be eventually converted back to 

 

13 Ingruber, O.V., Kocurek, M.J., and Wong, A., Pulp and Paper Manufacture, Vol. 4: Sulfite Science and Technology, Joint Textbook

Committee of the Paper Industry, TAPPI and CPPA,Atlanta, Montreal, 1985, p. 46. 14 Olm, L., Tormund, D., and Gidnert, E. B., TAPPI 1998 Breaking the Pulp Yield Barrier Symposium Proceedings, TAPPI PRESS, Atlanta, 

1998, p. 69. 15 ibid. S5 

16 Eric Larson et al. “A Cost-Benefit Assessment of BLGCC Technology.” TAPPI Journal. Vol. 83 No. 6. 

17 Causticizing load: required lime kiln capacity and lime kiln fuel consumption per unit of black liquor solids.

18 Larson (2003) S5-6 

Task 2: Gas Cleanup Design and Cost Estimates 4-2 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 
Section 4 Sulfur Recycle Options 

Method Benefits Drawbacks 

NaOH. 

 Decreases the alkali content of the whiteliquor. 

Option #3: Capture H2S 

with white liquor and 

convert completely to white 

liquor with causticizing 

cycle19. 

 No need for sulfur removal 

technology or Claus. 

 Polysulfide pulping has a higher 

digester yield than conventional 

pulping for a fixed pulp production. 

 As with Option #2, not as established a 

process as Selexol, Rectisol, or amine. 

Experimental testing needs to be 

performed to determine if this process is 

appropriate. 

 Increased causticizing load due to CO2 in 

the syngas being co-absorbed in the 

white liquor. The co-absorbed CO2 will 

form additional Na2CO3 in the liquor that 

must be eventually converted back to 

NaOH. 

 Decreases alkali content of white liquor. 

Split Sulfide Pulping Sulfur Recycle Options 

In this process, the sulfided 

white liquor streams are 

split during the pulping 

process. To recycle the 

sulfur, H2S can be captured 

by any method, then 

recycled to 2 different white 

liquor streams that differ by 

their sulfur content20,21. 

 Split sulfide pulping has a higher 

digester yield than conventional 

pulping for a fixed pulp production. 

It can increase digest yields by 

about 2%, compared to ~7% for 

polysufide pumping. 

 Could use conventional technology 

for H2S removal. 

 Unproven method. 

 Would require a fairly pure H2S stream. 

Other Sulfur Recycle Options 

Direct causticization with 

TiO2 in gasifier and removal 

of sulfur with a regenerative 

calcium based process22. 

 4.5% increase in overall energy 

efficiency compared to 

conventional recovery 

 Elimination of lime cycle (Annual 

savings of 100,000 barrels of oil for 

a 1,000 TPD mill) 

 Increased carbon conversion in 

gasifier 

 Conversion of sulfate to H2S 

 Increased tar conversion 

 Large amount of titanate solids handling 

 Disintegration of titanate particles during 

leaching 

 Agglomeration of bed particles 

 May not be appropriate for all gasifier 

configurations 

 

19 Ibid. S5-6 

20 Adriaan van Heiningen. “Causticizing Aspects and Sulfur Recovery in Black Liquor Gasification.” Colloqium on Black Liquor Combustion 

and Gasification.” Black Liquor Gasification Colloquium Presentations 2003. 21 Jean Ranard. Hasan Jameel. “Pulping Options with Black Liquor Gasification.” Black Liquor Gasification Colloquium Presentations 2003. 22 Ibid. 

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

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 
Task 2: Gas Cleanup Design and Cost Estimates A-1 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 

Appendix A High-Temperature Gasifier to Power Design Case PFDs 

The Claus Sulfur recovery unit shown here is for general information purpose only, and was not 

explicitly sized as part of the project scope. A cost estimate for this unit and a Tail Gas Treating 

process is provided in the equipment list. 
Appendix A High-Temperature Gasifie

Unit 100 101 102 103 200 201 

Mass Flow lb/hr 203,133 203,133 203,133 203,133 6,963 6,963 

Temperature F 325 326 240 110 220 230 

Pressure psia 487.3 482.3 477.3 472.3 25.0 20.0 

Vapour Fraction 1.00 1.00 1.00 0.94 0.00 1.00Molecular Weight 20.8 20.8 20.8 20.8 18.0 18.0 

Heat Flow MMBtu/hr -513.0 -513.0 -519.8 -539.9 -46.4 -39.6

Components

Hydrogen lb/hr 7,133 7,133 7,133 7,133 CO lb/hr 94,013 94,013 94,013 94,013

CO2 lb/hr 77,825 78,119 78,119 78,119

Methane (CH4) lb/hr 2,962 2,962 2,962 2,962 H2O lb/hr 11,094 10,973 10,973 10,973 6,963 6,963 

COS lb/hr 412 11 11 11 

H2S lb/hr 5,416 5,644 5,644 5,644 Ammonia (NH3) lb/hr 8 8 8 8 

Argon lb/hr 3,396 3,396 3,396 3,396 Nitrogen lb/hr 874 874 874 874 

Task 2: Gas Cleanup Design and Cost Estimates 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix A High-Temperature Gasifie

Unit 103 104 105 106 107 108 110 111 112 113 114 115 116 117 

Mass Flow lb/hr 203,133 192,683 161,146 10,450 161,146 337,030 27,998 368,552 5,760 362,792 362,792 369,416 34,622 43,435

Temperature F 110 110 110 124 124 130 110 171 156 156 200 245 258 206 

Pressure psia 472.3 472.3 472.3 468.4 468.4 17.1 472.3 472.3 30.0 30.0 25.0 25.0 30.0 22.1 

Vapour Fraction 0.94 1.00 0.00 1.00 1.00 1.00 0.00 0.00 1.00 0.00 0.06 0.00 1.00 1.00Molecular Weight 20.8 21.0 18.1 19.1 19.1 38.5 31.3 32.0 39.3 31.9 31.9 29.5 18.3 27.4 

Heat Flow MMBtu/hr -539.9 -70.6ComponentsHydrogen lb/hr 7,133 7,133 0 7,129 7,129 0 - 4 4 0 0 - - 0 

CO lb/hr 94,013 94,012 0 93,976 93,976 0 - 39 39 0 0 - - 0 

CO2 lb/hr 78,119 78,073 47 52,003 52,003 21,145 237 26,311 4,929 21,382 21,382 945 708 21,154 

Methane (CH4) lb/hr 2,962 2,962 0 2,960 2,960 0 - 2 2 0 0 - - 0 

H2O lb/hr 10,973 586 10,388 762 762 1,720 168,176 167,974 314 167,660 167,660 199,757 33,817 17,140

COS lb/hr 11 11 0 11 11 0 - 0 0 0 0 - - 0 

H2S lb/hr 5,644 5,633 11 32 32 5,133 14 5,617 470 5,146 5,146 20 6 5,140 

Ammonia (NH3) lb/hr 8 4 3 4 4 - - - - - - - - - 

Argon lb/hr 3,396 3,396 0 3,394 3,394 0 - 2 2 0 0 - - 0 

Nitrogen lb/hr 874 874 0 874 874 0 - 0 0 0 0 - - 0 MDEA lb/hr - - - 0 0 - 168,604 168,604 0 168,604 168,604 168,694 90 0 

118 119 120 121 122 123 

 334,794 15,437 334,794 334,794 39,850 39,850 

130 258 168 169 298 298 

17.1 30.0 472.3 30.0 65.0 60.0 

0.00 0.00 0.00 0.00 1.00 0.0018.0 31.5 31.5 31.5 18.0

 - 0 - -  - 0 - -  237 9 237 237  - 0 - -  165,940 15,421 165,940 165,940 39,850 39,850 

 - 0 - -  14 7 14 14

- - - - 

 - 0 - -  - 0 - -  168,604 0 168,604 168,604

Task 2: Gas Cleanup Design and Cost Estimates 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix A High-Temperature Gasifie

Task 2: Gas Cleanup Design and Cost Estimates 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 

NR

No. DATE 

SCALE: 

Reaction

Furnace

R-121A

Catalytic Converter

R-121B

Catalytic Converter

BFW STM

Spent

Catalyst

Sulfur

CW CW

Tail

Gas

ACID GAS FR. AMINE UNIT

AIR

R-120

Reaction Furnace

R-120

Reaction Furnace

H-120A

Sulfur Condenser

H-121A

Reheater

R-121A

Catalytic Converter

H-120B

Sulfur Condenser

H-121B

Reheater

R-121B

Catalytic Converter

H-120A

Sulfur Condenser

H-121A

Reheater

H-120B

Sulfur Condenser

H-121B

Reheater H-120C Sulfur Condenser

STM
Task 2: Gas Cleanup Design and Cost Estimates B-1 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 

Appendix B Low-Temperature Gasifier to Power Design Case PFDs 

The Claus Sulfur recovery unit shown here is for general information purpose only, and was not 

explicitly sized as part of the project scope. A cost estimate for this unit and a Tail Gas Treating 

process is provided in the equipment list. 
Appendix B Low-Temperature Gasifier 

Hydrogen lb/hr 14,617 14,617 14,617 14,617 - - 

CO lb/hr 77,854 77,853 77,853 77,853 - - CO2 lb/hr 79,095 79,161 79,161 79,161 - - 

Methane (CH4) lb/hr 6,547 6,547 6,547 6,547 - - 

H2O lb/hr 9,027 9,003 9,003 9,003 8,636 8,636

COS lb/hr 105 15 15 15 - - 

H2S lb/hr 9,626 9,672 9,672 9,672 - - 

Ammonia (NH3) lb/hr - - - - - - 

Argon lb/hr - - - - - - 

Nitrogen lb/hr - - - - - - 

Unit 100 101 102 103 200 201

Mass Flow lb/hr 196,870 196,870 196,868 196,868 8,636 8,636

Temperature F 325 325 240 110 220 230Pressure psia 336.5 331.5 326.5 321.5 25.0 20.0 

Vapour Fraction 1.00 1.00 1.00 0.97 0.00 1.00Molecular Weight 15.1 15.1 15.1 15.1 18.0 18.0 

Heat Flow MMBtu/hr -480.5 -480.5 -488.9 -509.7 -57.5 -49.1

Components

Task 2: Gas Cleanup Design and Cost Estimates 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix B Low-Temperature Gasifier 

V-104

Reflux Accumula

H-102

Rich Solvent/

Lean Solvent

Exchanger

P-101

Lean Solvent Pump

P-102

Reflux Pump

111

113

117

118

106

V-103

Rich Solvent

Flash Drum

SYNGAS FR. AMINE PRECOOLER 

V-102

Sweet Gas

KO Drum

C-101

Amine Absorber

V-

Rich S

Flash 

P-101

Lean Solvent Pump

860 GPM

200 BHP

C-102

Stripper

P-102

Reflux Pump

55 GPM

H-103

Lean Solvent Cooler

Duty: 22.7 MMBTU/hr

H-104

Stripper Reboiler

Duty: 54.9 MMBTU/hr

V-101

Amine KO Drum

H-102

Rich Solvent/Lean 

Solvent Exchanger

Duty: 30.2 MMBTU/hr

H-105

Acid Gas Condenser

Duty: 29.7 MMBTU/hr

A-100

H-101

CW

H-103

Lean Solvent Cooler

V-102

Sweet Gas

KO Drum

C-101

Amine 

Absorber

C-102

Stripper

119

109

110

114

H-104

Stripper Reboiler

115

116 

112

H-105

Acid Gas Condenser

103

V-101

Amine KO Drum

104105

120

To Flare

121

NR

No. DATE 

SCALE: 

Unit 103 104 105 106 107 108 110 111 112 113 114 115 116 117 

Mass Flow lb/hr 196,868 188,887 154,832 7,981 154,832 433,309 33,820 467,276 465,452 1,824 465,452 492,512 60,881 61,275

Temperature F 110 110 110 118 118 130 110 160 157 157 200 253 248 220 

Pressure psia 321.5 321.5 321.5 323.3 323.3 326.5 25.0 326.5 30.0 30.0 30.0 28.0 25.0 25.0 

Vapour Fraction 0.97 1.00 0.00 1.00 1.00 1.00 0.00 0.00 1.00 0.00 0.05 0.00 1.00 1.00Molecular Weight 15.1 15.0 18.0 13.2 13.2 38.6 31.2 31.7 37.1 31.7 31.7 28.7 18.1 25.6 

Heat Flow MMBtu/hr -509.7 -54.0ComponentsHydrogen lb/hr 14,617 14,617 14,612 0 14,612 0 - 5 5 0 0 - - 0 

CO lb/hr 77,853 77,853 77,834 0 77,834 0 - 22 22 0 0 - - 0 

CO2 lb/hr 79,161 79,143 54,648 19 54,648 23,045 24,699 196 23,242 1,457 23,242 674 23,067 477

Methane (CH4) lb/hr 6,547 6,546 6,543 0 6,543 0 - 2 2 0 0 - - 0 H2O lb/hr 9,003 1,049 7,954 1,155 1,155 217,783 1,430 217,645 217,537 108 217,537 276,369 60,263 28,797

COS lb/hr 15 15 0 - - - - - - - - - - - 

H2S lb/hr 9,672 9,665 8 40 9,344 40 9,582 7 9,351 231 9,351 10 9,373 3

Ammonia (NH3) lb/hr - - - - - - - - - - - - - - 

Argon lb/hr - - - - - - - - - - - - - - 

Nitrogen lb/hr - - - - - - - - - - - - - - 

MDEA lb/hr - - - 0 0 - 215,322 215,322 215,322 0 215,322 215,459 137 38

118 119 120 121 122 123

 431,632 27,456 431,632 431,632 58,888 58,888

130 248 171 172 281 281

25.0 25.0 326.5 25.0 50.0 50.0

0.00 0.00 0.00 0.00 1.00 0.0018.1 31.3 31.3 31.3 18.0

 - 0 - -

 - 0 - - 196 22 196 196 - 0 - -

 216,106 27,368 216,106 216,106 58,888 58,888

- - - -

29 7 7 7

- - - -

- - - -

- - - -

 215,322 38 215,322 215,322

Task 2: Gas Cleanup Design and Cost Estimates 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix B Low-Temperature Gasifier 

Task 2: Gas Cleanup Design and Cost Estimates 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 
Task 2: Gas Cleanup Design and Cost Estimates C-1 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 

Appendix C High-Temperature Gasifier to Chemicals Design Case PFDs 

The Claus Sulfur recovery unit shown here is for general information purpose only, and was not 

explicitly sized as part of the project scope. A cost estimate for this unit and a Tail Gas Treating 

process is provided in the equipment list. 
Appendix C High-Temperature Gasifier to C

Hydrogen lb/hr 7,133 4,208 2,924 5,481 9,689 9,689 9,689 9,689 - - - - - 

CO lb/hr 94,013 55,467 38,545 58,494 3,026 58,494 58,494 58,494 - - - - - 

CO2 lb/hr 77,825 45,917 31,908 133,631 87,714 133,631 133,631 133,631 - - - - - 

Methane (CH4) lb/hr 2,962 1,748 1,215 1,215 2,962 2,962 2,962 2,962 - - - - - 

H2O lb/hr 11,094 6,545 98,227 75,383 81,928 81,928 81,928 81,928 93,679 78,007 78,007 31,122 31,122

COS lb/hr 412 243 169 169 412 412 412 412 - - - - - 

H2S lb/hr 5,416 3,196 2,221 2,221 5,416 5,416 5,416 5,416 - - - - - 

Ammonia (NH3) lb/hr 8 5 3 3 8 8 8 8 - - - - - 

Argon lb/hr 3,396 2,004 1,392 1,392 3,396 3,396 3,396 3,396 - - - - - 

Nitrogen lb/hr 874 516 358 358 874 874 874 874 - - - - - 

Unit 150 152 153 154 155 156 158 159 210 211 212 213 214 

Mass Flow lb/hr 203,133 119,848 176,963 176,963 296,811 296,811 296,811 296,811 93,679 78,007 78,007 31,122 31,122

Temperature F 252 252 460 718 551 300 240 120 608 272 282 220 230 Pressure psia 487.3 487.3 487.3 482.3 482.3 477.3 472.3 467.3 500.0 55.0 50.0 25.0 20.0 

Vapour Fraction 1.00 1.00 1.00 1.00 1.00 0.83 0.74 0.70 1.00 0.00 1.00 0.00 1.00Molecular Weight 20.8 20.8 19.2 19.2 19.9 19.9 19.9 19.9 18.0 18.0 18.0 18.0 18.0 

Heat Flow MMBtu/hr -518.7 -306.0 -731.3 -731.3 -1,037.3 -1,110.9 -1,141.4 -1,172.2 -518.7 -515.4 -441.8 -207.4 -176.9

Components

Task 2: Gas Cleanup Design and Cost Estimates 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C High-Temperature Gasifier to C

V-114

Reflux Accumulato

H-113

Lean/Rich Solvent

Exchanger

P-111

Lean Solvent Pump

167

169

173

174

162

V-112

Rich Flash Drum

SYNGAS FROM SOLVENT PRECOOLER 

C-111

H2S Absorber

V-112

Rich Solvent

Flash Drum

P-111

Lean Solvent 

Pump

C-113

Stripper P-114 Reflux Pump H-115 Lean Solvent Cooler H-117 Stripper Reboiler V-111 KO Drum H-113 Rich/Lean Solvent Exchanger 

H-116 Acid Gas Condenser

A-100

H-100

CW

C-111

H2S

Absorber

C-113

Stripper

175

176

183

170

H-117

Stripper Reboiler

171

172

168 159 (NOTE 1)

V-111

KO Drum

161160

177

C-112

CO2

Absorber

V-115

Sweet Syngas 

KO Drum

H-114

Loaded Solvent

 Cooler

H-115

Lean Solvent

Cooler

181163

V-113

Flash Drum

(note 2)

180

P-113

P-112 Semi-Lean Solvent Pump

Loaded Pump

166 184

178

H-116

Acid Gas Condenser

P-114

Reflux Pump

CW

C-112

CO2 Absorber

P-112

Loaded

Solvent 

Pump

P-113

Semi-Lean 

Solvent Pump

V-113

Flash Drum

H-114

Loaded Solvent

Cooler

NOTES:1. MATERIAL BALANCE PROVIDED BY UDHE BASED ON PROPRIETARY SIMULATION TOOLS. DESIGN PRESENTED IS A GENERIC TWO ABSORBER SYSTEM, AND MAY REQUIRE MODIFICATIONS BASED ON INLET COMPOSITION AND PRODUCT REQUIREMENTS2. MULTIPLE FLASH STAGES MAY BE NECESSARY. DEPENDING ON COMPOSITION, ADDITIONAL TREATMENT MAY BE REQUIRED

NR

No. DATE 

SCALE: 

CW

CO2 to Vent

(Note 2)

Unit 159 160 161 164 165 166 168 178 182

Mass Flow lb/hr 296,811 216,398 80,413 82,013 520,811 15,698 484,834 62,508 55,865

Temperature F 120 120 120 102 113 43 33 Pressure psia 462.3 462.3 462.3 454.0 23.2 72.5 16.0

Vapour Fraction 1.00 0.00 1.00 1.00 1.00 1.00 1.00

Molecular Weight 19.9 18.0 20.7 11.2 38.6 43.8 43.8

Components

Hydrogen lb/hr 9,689 - 9,689 9,610 - - 53 - 1 

CO lb/hr 58,494 - 58,494 56,462 0 - 934 - 41 

CO2 lb/hr 133,631 - 133,631 8,893 9,369 61,173 - 55,645 -

Methane (CH4) lb/hr 2,962 - 2,962 2,664 1 - 254 - 43 

H2O lb/hr 81,928 80,413 1,515 447 18 - 27 - 84 

COS lb/hr 412 - 412 303 1 - 57 - 51 

H2S lb/hr 5,416 - 5,416 5,416 0 - - - - 

Solvent lb/hr - - - - 520,811 - 484,834 - - 

Argon lb/hr 3,396 - 3,396 3,388 - - 7 - - 

Nitrogen lb/hr 874 - 874 874 - - - - - 

Task 2: Gas Cleanup Design and Cost Estimates 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C High-Temperature Gasifier to C

Unit 164 190 191 215 216 

Mass Flow lb/hr 82,013 82,013 82,012 29,748 29,748

Temperature F 102 750 750 775 281 

Pressure psia 454.0 454.0 450.0 50.0 50.0

Vapor Fraction 1.00 1.00 1.00 1.00 0.00Molecular Weight 11.2 11.2 11.2 18.0 18.0

Heat Flow MMBtu/hr -142.1 -107.3 -107.3 -161.4 -196.3

Components

Hydrogen lb/hr 9,610 9,610 9,610 - - 

CO lb/hr 56,462 56,462 56,462 - - 

CO2 lb/hr 8,893 8,893 8,893 - - Methane (CH4) lb/hr 2,664 2,664 2,664 - - 

H2O lb/hr 18 18 18 29,748 29,748

COS lb/hr 1 1 - - - 

H2S lb/hr - - - - - 

Ammonia (NH3) lb/hr - - - - - 

Argon lb/hr 3,388 3,388 3,388 - - 

Nitrogen lb/hr 874 874 874 - - 

Task 2: Gas Cleanup Design and Cost Estimates 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix C High-Temperature Gasifier to C

Task 2: Gas Cleanup Design and Cost Estimates 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 
Task 2: Gas Cleanup Design and Cost Estimates D-1 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 

Appendix D Low-Temperature Gasifier to Chemicals Design Case PFDs 

The Claus Sulfur recovery unit shown here is for general information purpose only, and was not 

explicitly sized as part of the project scope. A cost estimate for this unit and a Tail Gas Treating 

process is provided in the equipment list. 
Appendix D Low-Temperature Gasifier to Ch

V-114

Reflux Accumula

H-112

Lean/Rich Solvent

Exchanger

P-111

Lean Solvent Pump

161

163

167

168

156

V-112

Rich Flash Drum

SYNGAS FROM LP STEAM GENERATOR (H-110, NOT SHOWN) 

C-111

H2S Absorber

V-112

Rich Solvent

Flash Drum

P-111

Lean Solvent 

Pump

C-113

Stripper

P-114

Reflux Pump

H-114

Loaded Solvent

Cooler

H-116

Stripper Reboiler

V-111

 KO Drum

H-112

Rich/Lean Solvent 

Exchanger

H-115

Acid Gas 

Condenser

A-100

H-100

CW

C-111

H2S

Absorber

C-113

Stripper

169

170

178

164

H-116

Stripper Reboiler

165

166

150 162

V-111

 KO Drum

155154

171

C-112

CO2

Absorber

V-115

Sweet Syngas 

KO Drum

H-114

Loaded Solvent 

Cooler

H-113

Lean Solvent

Cooler

176157

V-113

Flash Drum

(note 2)

174

175

P-113

P-112 Semi-Lean Solvent Pump

Loaded Pump

160 179

172

H-115

Acid Gas Condenser

P-114

Reflux Pump

CW

C-112

CO2 Absorber

P-112

Loaded 

Pump

P-113

Semi-Lean 

Solvent Pump

V-113

Flash Drum

H-113

Lean Solvent

Cooler

CW

153

H-111

Solvent Precooler

H-111

Solvent Precooler

NR

No. DATE 

SCALE: 

NOTES:1. MATERIAL BALANCE PROVIDED BY UDHE BASED ON PROPRIETARY SIMULATION TOOLS. DESIGN PRESENTED IS A GENERIC TWO ABSORBER SYSTEM, AND MAY REQUIRE MODIFICATIONS BASED ON INLET COMPOSITION AND PRODUCT REQUIREMENTS2. MULTIPLE FLASH STAGES MAY BE NECESSARY. DEPENDING ON COMPOSITION, ADDITIONAL TREATMENT MAY BE REQUIRED

CO2 to Vent

(Note 2)

Hydrogen lb/hr 14,617 - 14,617 14,539 - - 74 - 5 

CO lb/hr 77,853 - 77,853 76,738 1 - 980 - 134

CO2 lb/hr 79,152 - 79,512 24,146 10,831 24,759 - 19,413 -

Methane (CH4) lb/hr 6,547 - 6,547 6,103 5 - 308 - 129

H2O lb/hr 9,003 7,634 1,369 623 33 - 9 - 28

COS lb/hr 105 - 105 104 0 - 1 - - 

H2S lb/hr 9,676 - 9,676 9,675 0 - - - - 

Solvent lb/hr - - - - 831,898 - 993,691 - - 

Argon lb/hr - - - - - - - - - 

Nitrogen lb/hr - - - - - - - - - 

Unit 153 154 155 158 159 160 162 172 177

Mass Flow lb/hr 196,953 189,319 7,634 121,560 831,898 21,240 26,133 993,691 19,709

Temperature F 120 120 120 98 113 43 33

Pressure psia 326.5 326.5 326.5 318.5 23.2 72.5 16.0

Vapour Fraction 1.00 0.00 1.00 1.00 1.00 1.00 1.00

Molecular Weight 15.1 18.0 15.0 11.1 37.4 40.0 43.0

Components

Task 2: Gas Cleanup Design and Cost Estimates 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix D Low-Temperature Gasifier to Ch

Hydrogen lb/hr 14,538 14,538 14,538 - - 

CO lb/hr 76,738 76,738 76,738 - - 

CO2 lb/hr 24,146 24,146 24,146 - - 

Methane (CH4) lb/hr 6,103 6,103 6,103 - - 

H2O lb/hr 33 33 44,977 33 44,977

COS lb/hr - - - - - 

H2S lb/hr - - - - - 

Ammonia (NH3) lb/hr - - - - - Argon lb/hr - - - - - Nitrogen lb/hr - - - - - 

Unit 158 190 191 212 213 

Mass Flow lb/hr 121,560 121,560 121,560 44,977 44,977

Temperature F 750 98 750 775 281 

Pressure psia 318.5 318.0 313.0 50.0 50.0

Vapour Fraction 1.00 1.00 1.00 1.00 0.00Molecular Weight 11.1 11.1 11.1 18.0 18.0

Components

Task 2: Gas Cleanup Design and Cost Estimates 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix D Low-Temperature Gasifier to Ch

Task 2: Gas Cleanup Design and Cost Estimates 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 
Task 2: Gas Cleanup Design and Cost Estimates E-1 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 

Appendix E Equipment Lists 

The equipment lists for all four black liquor gasification cases are shown below, with the two 

high temperature and two low temperature cases placed together on the same sheet. 
Appendix E 

High Temperature Syngas to Power and Chemicals Cases 

Item No Description Type 

Quantity 

Per Train Size Weight 

lbs 

Head 

PSI 

Design Duty T 

PSIG oF

P 

Design 

P T 

PSIG oF

Operating 

Power Useage 

 (No.) HP 

Materials 

Price, total 

(unistalled) 

Price Escalated, 

total (uninstalled) 

Total I

C

Q2 2004 Cost Index 

(US $) 

Q2 2005 Cost Index 

(US $) (U

Power Generation Case Reactors R-100 COS Hydrolysis 

Total 

Vertical 1 14' ID x 15' - 9" T/T 132,230 520 375 472 325 CS $315,598 $374,141 

$374,141 

Heat Exchangers 

Total 

H-101 Amine Pre-cooler H-100 Syngas Cooler/ LP Steam Generator 

Shell & Tube 

Shell & Tube 

1 

1 

6' ID x 12' T-T 

Surface area: 7907 SQFT 

4' - 1" ID x 8' T-T 

Surface area: 3120 SQFT 20.1 MMBTU/hr 

6.8 MMBTU/hr 

T 25 280 

S 515 375 

T 65 150 

S 510 290 

10 230 

467 326 

50 100 

462 240 

CS 

CS 

CS 

CS 

$287,585 

$87,300 $99,155 

$165,900 $188,429 

Packaged Units A-101 Amine Unit A-120 Claus Plant with Tail Gas Treating 

TOTAL EQUIPMENT COST, (excld. Package units) TOTAL INSTALLED COST 

$8,5

$17,6

$661,726 $1,7

$27,8

Chemicals Production Case Reactors R-110 LT Shift Reactor 

R-112 ZnO Sulfur Removal Beds 

R-113 ZnO Sulfur Removal Beds Total 

Vertical 

Vertical 

Vertical 

1 

1 

1 

4' - 11" ID x 8' T/T 

7' - 2" ID x 10' T/T 

7' - 2" ID x 10' T/T 

46,100 

66,800 

66,800 

770 

800 

800 

515 

480 480 

467 718 

437 750 

437 750 

CS CS 

CS 

$230,500 

$333,400 

$333,400 

$897,300 

Heat Exchangers 

Total 

H-110 LT Shift Cooler/ LP Steam Generator H-112 Solvent Pre-cooler H-111 Syngas Cooler/ LP Steam Generator H-118 ZnO Bed Preheater 

Shell & Tube Shell & Tube 

Shell & Tube Shell & Tube 

1 

1 

2 

1 

7' - 8" ID x 20' T-T 

Surface area: 29185 SQFT 

7' - 3" ID x 20' T-T 

Surface area: 20268 SQFT 

4' - 9" ID x 8' T-T 

Surface area: 4270 SQFT 

4' - 6" ID x 20' T-T 

Surface area: 10672 SQFT 

30.4 MMBTU/hr 

73.59 MMBTU/hr 

30.9 MMBTU/hr 

35.1 MMBTU/hr 

T 55 350 

S 515 600 

T 25 280 

S 510 350 

T 65 150 

S 500 290 

T 490 800 

S 50 825 

40 282 

467 551 

10 230 

462 300 

50 100 

452 240 

442 750 

35 775 

CS 

CS 

CS 

CS 

CS 

CS 

CS 

CS 

$1,975,383 

$899,900 $1,022,106 

$578,400 $656,947 

$113,100 $128,459 

$147,800 $167,871 

Packaged Units 

A-111 Genosorb Unit A-120 Claus Plant with Tail Gas Treating 

TOTAL EQUIPMENT COST, (excld. Package units) TOTAL INSTALLED COST 

$30,1$17,6

$2,872,683 $7,3

$55,1

Task 2: Gas Cleanup Design and Cost Estimates 

Black Liquor Sulfur Removal Design and Cost Estimates 

United States Department of Energy/National Renewable Energy Laboratory 
Appendix E 

Low Temperature Syngas to Chemicals Design Case 

Item No Description Type 

Quantity 

Per Train Size Weight 

lbs 

Head 

PSI 

Design Duty T 

PSIG oF

P 

Design 

P T 

PSIG oF

Operating 

Power Useage 

 (No.) HP 

Materials 

Price, total 

(unistalled) 

Price Escalated, 

total (uninstalled) 

Total I

C

Q2 2004 Cost Index 

(US $) 

Q2 2005 Cost Index 

(US $) (U

Power Generation Case Reactors R-100 COS Hydrolysis 

Total 

Vertical 1 13' ID x 18' - 6" T/T 130,200 355 375 322 325 CS $310,767 $368,414 

$368,414 

Heat Exchangers 

Total 

H-100 Syngas Cooler/ LP Steam Generator H-101 Amine Pre-cooler 

Shell & Tube 

Shell & Tube 

1 

1 

4' - 7" ID x 12' T-T 

Surface area: 4433 SQFT 

4' ID x 8' T-T 

Surface area: 2631 SQFT 20.8 MMBTU/hr 

8.4 MMBTU/hr 

T 25 280 

S 350 375 

T 65 150 

S 345 290 

10 230 

316 325 

50 100 

312 240 

CS 

CS 

CS 

CS 

$189,224 

$73,600 $83,595 

$93,000 $105,629 

Packaged Units A-101 Amine Unit 

A-120 Claus Plant with Tail Gas Treating TOTAL EQUIPMENT COST, (excld. Package units) TOTAL INSTALLED COST 

$10,2

$25,0

$557,639 $1,4

$36,6

Chemicals Production Case Reactors R-111 ZnO Sulfur Removal Beds 

R-112 ZnO Sulfur Removal Beds Total 

Vertical Vertical 

1 1 

7' - 3" ID x 10' T/T 7' - 3" ID x 10' T/T 

66,900 66,900 

800 800 

330 

330 

297 750 297 750 

CS CS 

$334,600 $334,600 

$669,200 

Heat Exchangers Total 

H-111 Solvent Pre-cooler H-117 ZnO Bed Preheater H-110 Syngas Cooler/ LP Steam Generator 

Shell & Tube 

Shell & Tube 

Shell & Tube 

1 1 

1 

4' - 7" ID x 12' T-T 

Surface area: 4433 SQFT 

4' - 6" ID x 8' T-T 

Surface area: 3285 SQFT 

6' - 2" ID x 18' T-T 

Surface area: 17750 SQFT 

15.6 MMBTU/hr 52.7 MMBTU/hr 

8.4 MMBTU/hr 

T 25 280 

S 350 375 

T 65 150 

S 355 250 

T 335 800 

S 50 825 

10 230 

316 325 

50 100 

322 200 

302 750 

35 775 

CS 

CS 

CS 

CS 

CS 

CS 

$383,560 

$91,900 $104,380 

$245,800 $279,180 

$93,000 $105,629 

Packaged Units A-111 Genosorb Unit 

A-120 Claus Plant with Tail Gas Treating TOTAL EQUIPMENT COST, (excld. Package units) TOTAL INSTALLED COST 

$22,4

$25,0

$1,052,760 $2,7

$50,1

Task 2: Gas Cleanup Design and Cost Estimates 

Black Liquor Sulfur Removal Design and Cost Estimates 

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 

2. REPORT TYPE

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 – 

Black Liquor Gasification 

5c. PROGRAM ELEMENT NUMBER

5d. PROJECT NUMBER

NREL/SR-510-39944 

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 

9. SPONSORING/MONITORING AGENCY NAME(S) AND ADDRESS(ES)

National Renewable Energy Laboratory 

1617 Cole Blvd. 

Golden, CO 80401-3393 11. SPONSORING/MONITORING 

AGENCY REPORT NUMBER

NREL/SR-510-39944 

12. DISTRIBUTION AVAILABILITY STATEMENT

National Technical Information Service 

U.S. Department of Commerce 

5285 Port Royal Road 

Springfield, VA 22161 

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 

removal of acid gases from black liquor-derived syngas for use in both power and liquid fuels synthesis. Two 3,200 

metric tonne per day gasification schemes, both low-temperature/low-pressure (1100°F, 40 psi) and hightemperature/high-pressure (1800°F, 500 psi) were used for syngas production. Initial syngas conditions from each of 

the gasifiers was provided to the team by the National Renewable Energy Laboratory and Princeton University. 

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; black liquor; National Renewable Energy Laboratory; NREL 

16. SECURITY CLASSIFICATION OF: 19a. NAME OF RESPONSIBLE PERSON 

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b. ABSTRACT 

Unclassified

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Unclassified

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