UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

REGION IX 

75 Hawthorne Street 

San Francisco, CA 94105

MEMO 

SUBJECT: GHG BACT Analysis Addressing Pre-Combustion Carbon Capture and 

Storage/Sequestration (CCS) for the SPI-Anderson Permit Project 

TO: SPI-Anderson PSD Permit Administrative Record 

FROM: Shaheerah Kelly, Environmental Engineer 

 U.S. EPA, Region 9, Air Division, Permits Office 

DATE: April 25, 2014 

The attachment to this memo is an addendum to the Supplemental Statement of Basis and 

Ambient Air Quality Impact Report for Greenhouse Gas (GHG) Emissions dated November 

2013 (GHG AAQIR). This addendum supplements EPA’s Best Available Control Technology 

(BACT) analysis for GHG in Section 5 of the GHG AAQIR. 

Attachment 
GHG BACT Analysis Addressing Pre-Combustion CCS for the SPI-Anderson Permit Project 

April 2014 

Page 2

GHG BACT Analysis Addressing Pre-Combustion Carbon Capture 

and Storage/Sequestration (CCS) for the SPI-Anderson Project

In the Supplemental Statement of Basis and Ambient Air Quality Impact Report for Greenhouse 

Gas Emissions dated November 2013 (GHG AAQIR), EPA’s evaluation stated that there are 

three approaches to CO2 capture that are generally applicable to power generation: (1) precombustion systems designed to separate CO2 and hydrogen (H2) from produced syngas, (2) 

post-combustion systems designed to separate CO2 from flue gas, and (3) oxy-combustion that 

uses high-purity oxygen (O2) instead of air, which produces flue gas composed largely of CO2. 

We stated that the use of a pre-combustion system would require a gasification unit to produce 

syngas from the biomass fuel, which would amount to redefining the source. However, we are 

revising this determination based on additional information we received from the applicant and 

our independent research. 

Step 1 – Identify Available Control Technologies 

EPA is including pre-combustion CCS as a control alternative for the proposed biomass boiler. 

Step 2 – Eliminate Technically Infeasible Control Technologies 

A pre-combustion CCS system is a complex system comprised of a group of technologies that 

remove CO2 (i.e., pre-combustion CO2 capture) before the combustion of the hydrogen-rich fuel 

produced in this system, and transport and storage (or sequestration) of the CO2 gas. Such a 

system would be used instead of the proposed stoker boiler for producing electricity for the grid 

and steam for SPI’s lumber operation. 

Pre-Combustion CO2 Capture 

The pre-combustion CO2 capture would involve the following processes: gasification plant 

(which includes preparation of the biomass feedstock); raw gas cooling (via water quench or heat 

recovery systems); water-gas shift reactor; gas cleanup; air separation unit (ASU); and CO2

removal. 

Gasification plant: Gasification involves heating solid biomass in an oxygen-starved 

environment to produce a low or medium calorific gas. The gasification plant generally would 

consist of a gasifier and a natural-gas- or oil-fired heater for heating the gasifier to a certain 

temperature, as well as equipment for preparing, processing, and conveying the biomass 

feedstock. Preparation of the biomass feedstock is not expected to be a significant change for the 

SPI facility. The biomass feedstock, with the addition of steam and oxygen, is charged to the 

gasifier. An ASU is used to generate the enriched oxygen supply necessary for the gasification 

process. During gasification, the biomass is converted to gaseous products and char and/or ash 

at high temperatures. Depending on a number of variables such as feedstock characteristics, 

temperature and gasifying agent (e.g., use of air, oxygen, and/or steam), the composition of the 
GHG BACT Analysis Addressing Pre-Combustion CCS for the SPI-Anderson Permit Project 

April 2014 

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gaseous products can consist of carbon monoxide (CO), carbon dioxide (CO2), hydrogen (H2), 

methane (CH4), nitrogen (N2), as well as non-gaseous byproducts such as char and tars. At 

gasification temperatures above 1275°K (1835°F) the resulting gas stream consists primarily of 

CO and H2 called synthesis gas or syngas. At relatively lower gasification temperatures, other 

components such as methane and higher hydrocarbons (tars) are also present in the resulting gas 

stream, and this is often referred to as producer gas. (Carbo, Michiel, Global Technology 

Roadmap for CCS in Industry, Biomass-based industrial CO2 sources: biofuels production with 

CCS at 13-14). For purposes of this analysis, we refer to the gas exiting the gasifer as “raw gas.” 

Raw gas cooling: The raw gas exiting the gasifier is sent to a water quench or similar process to 

cool the gas down. The gas needs to be sufficiently cooled so that it can be sent directly to the 

gas clean-up. If the gasifier has a high gas outlet temperature, the heat from the raw gas may be 

used to generate steam for the steam turbine. If a combined cycle gas turbine operation is used, a 

steam turbine is supplied with steam from the gas turbine heat recovery steam generator 

(HRSG). 

Gas cleanup system: Typically, syngas must be thoroughly cleaned prior to further use, 

especially if it will be used in a combustion turbine. The gas cleanup process consists of initially 

removing particulates, soot and heavy metals. Subsequently, other compounds are removed such 

as tars, acid gases, and sulfur-containing compounds. The degree of cleanup will depend of the 

combustion unit employed. For instance, more cleaning may be needed if the gas is burned in a 

gas turbine rather than a gas boiler. 

Water-gas shift reactor: The gas exiting the gas cleanup system is sent to a water-gas shift 

reactor. This process converts CO to CO2, and is generally necessary for CO2 removal. The 

water-gas shift involves the catalytic reaction of CO and steam. Since the gas initially contains 

primarily CO and H2, this shift reaction diminishes the concentration of CO and enriches the 

concentration of H2 in the pre-combustion raw gas stream via the following reaction. 

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∆

 . ଶܪ	൅ ଶܱܥ	 →

CO2 Removal: CO2-laden clean gas exiting the water-shift reactor is then sent to an absorber 

where CO2 is removed from the gas stream. This CO2 gas is compressed, and transported via 

pipelines for storage and sequestration. 

Combustion of Hydrogen-rich Gas 

The resulting clean gas is primarily H2 gas, or hydrogen-rich gas, can be burned in a gas boiler to 

produce steam, or in a combined cycle turbine generator system to produce both steam and 

electricity. The clean gas is mixed with nitrogen (for flow control, flame stabilization and NOx 

reduction) and/or diluted with water before it is supplied to the gas turbine combustion chamber 

or boiler. Depending on the availability of hydrogen-rich gas, the combustion unit can (1) 

combust hydrogen-rich gas alone, (2) co-fire hydrogen-rich gas and natural gas, or (3) natural 
GHG BACT Analysis Addressing Pre-Combustion CCS for the SPI-Anderson Permit Project 

April 2014 

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gas alone (e.g., during periods of startup, shutdown, or upset periods, or when the supply of 

hydrogen-rich gas is intermittent or not available). 

Carbon Capture and Storage of CO2

Captured and compressed CO2 must be transported via CO2 pipelines to a storage facility or end 

use, such as enhanced oil recovery (EOR). California Department of Conservation Division of 

Oil, Gas & Geothermal Resources (DOGGR) oversees the drilling, operation, maintenance, and 

plugging and abandonment of oil, natural gas, and geothermal wells in the state. There are 6 oil 

and gas districts in California (see Figure 1). Shasta County is located in District 6, which is 

comprised of the northern California counties. 

Figure 1: Oil and Gas District Boundaries in California 

Source: California Oil & Gas Fields, Volume 1 - Central California, 

California Department of Conservation Division of Oil, Gas, and Geothermal Resources 

DOGGR provides publications and other information on individual oil fields and the EOR work 

done in each. There are several oil and gas fields located in northern California. Most of these 

fields contain gas wells, and do not produce oil. There are no oil and gas fields in Shasta County 
GHG BACT Analysis Addressing Pre-Combustion CCS for the SPI-Anderson Permit Project 

April 2014 

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(see Figure 2). Furthermore, there are currently no EOR activities in the oil fields within 

District 6.1

 There are EOR activities in Districts 1 through 5 in central and southern California. 

Figure 2: Oil and Gas Wells/Fields in Northern California 

Source: DOGGR Well Finder at http://maps.conservation.ca.gov/doggr/index.html

Technical Feasibility 

Because the source category for identifying potentially available control technologies in Step 1 is 

broad, certain technologies may be determined infeasible under Step 2 when the particular 

physical, engineering and chemical processes of the proposed source are considered in more 

detail. The analysis in Step 2 may review whether a technology has been “demonstrated”, which 

is generally established if the technology has been installed and operated successfully elsewhere. 

If the technology has not been demonstrated, it may still be technically feasible if the technology 

is both “available” and “applicable.” (See NSR Workshop Manual, Draft, October 1990 at B.17.) 

Commercial CCS, including pre-combustion CCS, has been planned for a number of coal-fired 

power generation and industrial applications. The industrial applications are projects in the gas 

 

1 See California Oil & Gas Fields, Volume III – Northern California

= oil/gas well 

NEVADA 

Anderson

CALIFORNIA
GHG BACT Analysis Addressing Pre-Combustion CCS for the SPI-Anderson Permit Project 

April 2014 

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processing and chemical production industries, where the separation of CO2 is part of the process 

design. Pre-combustion CCS is currently “demonstrated in practice” at facilities such as Dakota 

Gasification and Coffeyville Fertilizer. In addition, several pre-combustion CCS projects are 

currently being proposed in the United States, and a number of these projects in the United States 

are demonstration projects being funding by U.S. Department of Energy.2 The equipment used 

to accomplish pre-combustion CCS at these facilities is currently available and applicable to the 

biomass feedstock at the SPI-Anderson facility. 

EPA has not considered the BACT requirement as a means to redefine the design of the facility 

when considering available control alternatives. In considering this, EPA looks at whether the 

control option substantially alters the purpose or basic design of the proposed facility that it 

should be considered a redefinition of the source. SPI’s primary business is operation of a 

lumber production facility. An integral part of the facility is providing steam to eight steamheated, double-track, kilns used for drying lumber. SPI may accomplish continuous steam 

production to the kilns by storing hydrogen-rich gas produced in the gasification operation and 

burning the stored gas at a later time or by burning natural gas when hydrogen-rich gas is not 

available. Thus, EPA is revising its previous determination regarding pre-combustion CCS, and 

we have determined that this technology is technically feasible for the boiler project at the SPIAnderson facility. 

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Pre-combustion CCS has been primarily proposed for projects that use coal or petcoke as a fossil 

fuel. DOE evaluated three proposed fossil fuel feedstock IGCC power plant configurations with 

carbon capture, and determined that the GE Energy facility could achieve 90.2 percent reduction 

of CO2 in syngas, the Conoco Phillips facility could achieve 88.4 percent reduction of CO2 in 

syngas, and the Shell facility could achieve 90.8 percent reduction of CO2 in syngas.3 The 

Hydrogen Energy California (HECA) project, a fossil fuel feedstock IGCC power plant proposed 

near Bakersfield, California, is also projected to achieve 90 percent reduction of CO2 in syngas.4 

Based on this information, an approximate 90 percent reduction of CO2 in the gas stream can be 

expected for a prep-combustion CO2 capture system, and is considered to be a “full capture” 

CCS system. A “partial capture” CCS system achieves some level less than 90 percent of 

capture. Regardless of whether “full capture” or “partial capture” of CO2 from the gas stream is 

employed, CO2 compression, transportation (i.e., through pipelines) and storage (i.e., geologic 

sequestration or use in EOR) will be needed. 

 

2

 See http://sequestration.mit.edu/tools/projects/index_capture.html and 

http://www.netl.doe.gov/research/coal/major-demonstrations/clean-coal-power-initiative. 3

 See Cost and Performance Baseline for Fossil Energy Plants, Vol. 1, DOE/NETL-2007/1281, May 2007. 4 See Notice of Final Determination of Compliance (FDOC) for Hydrogen Energy California Facility: 5-7616, 

Project: 1121903, Issued July 8, 2013. 
GHG BACT Analysis Addressing Pre-Combustion CCS for the SPI-Anderson Permit Project 

April 2014 

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Our GHG AAQIR included a table of recent GHG BACT determinations made at similar 

facilities according to the RACT/BACT/LAER Clearinghouse (RBLC), as well as other permit 

determinations not included in the RBLC. (See Table 5-8 of the GHG AAQIR.) There are no 

similar biomass facilities that currently use pre-combustion CCS for reducing CO2 emissions. 

Step 4 – Evaluate Most Effective Controls 

As previously mentioned above, the resulting clean gas is primarily H2 gas, or hydrogen-rich gas, 

which can be burned in a gas boiler to produce steam, or in a combined cycle turbine generator 

system to produce both steam and electricity. A combined cycle gas turbine (i.e., an integrated 

gasification combined cycle or IGCC facility) is more efficient since it can be used to generate 

electricity using a gas turbine and steam turbine which is supplied steam produced in a heat 

recovery steam generator (HRSG). 

However, the facility may have to burn natural gas, or burn both natural gas and hydrogen-rich 

fuel during periods when hydrogen-rich fuel is low or is not available (e.g., during maintenance, 

startup, shutdown, or upset of the gasification plant. This scenario would produce additional 

GHG emissions. 

The CO2 capture and compression system will decrease the facility’s thermal efficiency due to 

the additional parasitic energy load from the CO2 capture system. The parasitic load can occur in 

a number of places, including extraction of steam from the HRSG for operation of reboilers and 

providing electricity to drive the CO2 compressor. The drop in thermal efficiency with capture 

has multiple effects which include burning more biomass to produce the same amount of steam 

and electricity to meet the facility’s business needs. This has the effect of producing more GHG 

emissions. 

As previously mentioned above, regardless of whether “full capture” or “partial capture” of CO2

from the clean raw gas from the gasification process is employed, CO2 compression, 

transportation (i.e., through pipelines) and storage (i.e., geologic sequestration, or for use in 

EOR) will be needed. Captured and compressed CO2 must be transported to a storage facility 

(deep saline formation) or for end use (EOR). 

 

There are no nearby petroleum extraction operations or industrial processes that would be able to 

accept the volume of CO2 SPI is expected to emit. CO2 injection would have to occur at an EOR 

operation located in central or southern California. SPI considered the cost of EOR at an oil field 

in Brentwood, California, approximately 25 miles west of Stockton, California, and estimated 

that the cost of constructing a pipeline to transport CO2 from the Anderson facility to Brentwood, 

California would cost approximately $109,907,547.5

 Given that the cost of the project without 

gasification and CCS is $75,000,000, the pipeline cost represents a significant increase in the 

cost of the project, and the overall pre-combustion CCS costs would only increase if the cost 

 

5

 SPI Anderson email response to EPA dated September 14, 2013. 
GHG BACT Analysis Addressing Pre-Combustion CCS for the SPI-Anderson Permit Project 

April 2014 

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associated with CO2 capture equipment and the more likely transport of SPI’s CO2 to an EOR 

operation in central or southern California are considered. Accordingly, and for reason similar to 

those provided for post-combustion CCS discussed below, we are eliminating pre-combustion 

CCS using EOR as a GHG control option due to its disproportionate costs. 

Step 5 – Select BACT 

EPA has not changed its overall BACT determination for this facility based on the analysis 

below, since pre-combustion CCS is excluded as BACT in Step 4. Specifically, we continue to 

conclude that BACT for the proposed biomass-fired stoker boiler is (1) 0.36 pounds of CO2e per 

pound of steam (12-month rolling average basis), (2) combustion of biomass at all times except 

during periods of startup, shutdown and flame stabilization (in which natural gas fuel is allowed 

to be combusted), and (3) energy efficient design and use of good combustion and operational 

and maintenance practices as described in SPI’s permit application and subsequent submissions 

to the EPA, which include, but are not limited to, (i) construction and operation of an efficient, 

state-of-the-art, air-cooled, reciprocating stepgrate stoker boiler that ensures good combustion; 

(ii) operation of the boiler as a cogeneration unit; and (iii) operation and maintenance of the 

boiler in accordance with the manufacturer’s recommendations. The CO2e limit applies at all 

times, including during startups and shutdowns.