INDUSTRIAL FUEL CHOICE
ANALYSIS MODEL
Model Documentation
JUNE 1980
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INDUSTRIAL FUEL CHOICE
ANALYSIS MODEL
PRIMARY MODEL DOCUMENTATION
Prepared for:
U.S. Environmental Protection Agency
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
Prepared by:
Energy and Environmental Analysis, Inc.
1111 North 19th Street
Arlington, Virginia 22209.
June 1980
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This report was prepared by Energy and Environmental Analysis,
Inc. under contract No. 68-02-3330 for the U.S. Environmental
Protection Agency and does not necessarily state or reflect the
views, opinions, or policies of the EPA or the Federal Government.
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TABLE OF CONTENTS
Page
1. IFCAM OVERVIEW 1-1
1.1 Purpose of Model 1-1
1.2 Key Model Inputs. . 1-2
1.3 Model Logic 1-4
1.4 Model Capabilities 1-13
1.5 Report Organization 1-15
2. INDUSTRIAL ENERGY CONSUMPTION 2-1
2.1 Introduction 2-1
2.2 Energy Consumption Baseline 2-1
2.3 Overview of Industrial Energy Use 2-5
2.4 Projections of Industrial Fossil Fuel Consumption 2-10
3. CHARACTERISTICS OF INDUSTRIAL FOSSIL FUEL USE 3-1
3.1 Introduction 3-1
3.2 Characterization of Fossil Fuel Use by New and
Existing Facilities 3-2
3.3 Characterization of Fossil Fuels by Functional Use 3-11
3.4 Classification of Fuel Use by Size and Capacity Utilization 3-17
3.5 Allocating Fuel Demands Between Gas and Oil in Existing
Combustors 3-24
4. TECHNICAL AND OTHER CONSTRAINTS TO FUEL SUBSTITUTION 4-1
4.1 Introduction . . . 4-1
4.2 Boilers 4-3
4.3 Process Heaters 4-4
4.4 Summary of Technical Feasibility Evaluations 4-12
4.5 Other Constraints 4-17
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TABLE OF CONTENTS
(Continued)
5. ASSIGNMENT OF ENVIRONMENTAL REGULATIONS AND POLLUTION
CONTROL STRATEGIES 5-1
5.1 Introduction 5-1
5.2 Assignment of Boilers to AQCR's 5-1
5.3 Assignment of Environmental Regulations to Individual
Combustors 5-3
5.4 Assignment of Pollution Control Strategies 5-9
5.5 Other Environmental Requirements 5-23
6. ECONOMICS OF THE FUEL CHOICE DECISION 6-1
6.1 Introduction 6-1
6.2 Cost Components 6-1
6.3 Investment Decision Approach 6-17
6.4 Summary 6-35
7. MODEL OUTPUTS 7-1
7.1 Introduction 7-1
7.2 Energy Impacts 7-1
7.3 Environmental Impacts 7-2
7.4 Cost Impacts 7-2
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TABLE OF CONTENTS
(Continued)
Page
Appendix A - Energy Consumption Data Base A-l
Appendix B - Major Fuel Burning Installation Survey B-l
Appendix C - Midterm Energy Forecasting System C-l
Appendix 0 - Projection Method D-l
Appendix E - Size and Capacity Utilization of New Industrial Boilers E-l
Appendix F - Industrial Boiler and Pollution Control Cost Data. . . . F-l
Appendix G - Process Heat Characteristics and Cost Data G-l
Appendix H - Energy Scenario Specifications H-l
Appendix I - Sulfur Premiums 1-1
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TABLES
Number Title Page
1-1
2-1
2-2
2-3
2-4
2-5
2-6
2-7
3-1
3-2
3-3
3-4
3-5
4-1
4-2
4-3
5-1
5-2
5-3
5-4
5-5
5-6
Summary of Report Organization
1974 Net Energy Consumption in the U.S
Characterization of Industrial Energy Consumption in 1974.
Adjustments to ECDB Industrial Energy Use
Industrial Fossil Fuel Consumption in 1974 by Major
Industry
Industrial Fossil Fuel Consumption in "Other" Industries
in 1974
Fossil Fuel Consumption in Industrial Boilers by Industry
in 1974.
Energy Consumption Trends in the Industrial Sector ....
Normal Retirement Rates for Process Heat Uses
Illustration of Bias Introduced by Energy Conservation
Policies
Distribution of Fossil Fuels Between Boiler and Process
Heat Uses in 1974
IFCAM Boiler Size/Type Assumptions
Sample Size/Capacity Utilization Distribution of New
Boilers for Two Industries
Technical Feasibility of Coal Use by Industry in Process
Heat Applications
Technical Substitution Potential: Coal for Gaseous and
Oil Fuels in Process Heat Equipment
Market Penetration Lead Times for a New Coal-Fired
Nonboiler Use: Optimistic Schedule
Current Boiler NSPS Regulations
Uncontrolled Air Emission Rates for Industrial Boilers . .
Boiler Compliance Strategies
Coal Characteristics
Particulate Matter Control Efficiencies
NO Control Technologies
1-18
2-3
2-4
2-6
2-7
2-8
2-9
2-11
3-8
3-10
3-14
3-19
3-25
4-15
4-16
4-17
5-6
5-10
5-11
5-13
5-18
5-19
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TABLES
(Continued)
Number Title Page
5-7 Potential NO Control From Combustion Modifications .... 5-21
6-1 IFCAM Boiler Size/Type Assumptions 6-3
6-2 Sample Boiler and Pollution Control Costs 6-7
6-3 Sample Coal Types 6-9
6-4 Sample Environmental Regulations 6-10
6-5 Coal Characteristics 6-13
6-6 1985 Industrial Coal Transportation Costs 6-18
6-7 Financial Parameter Assumptions for Sample Cost Comparison. 6-30
6-8 Sample After-Tax NPV Calculation for Capital Expenses . . . 6-31
6-9 Sample After-Tax NPV Calculation for Annual Non-Fuel O&M
Expenses 6-33
6-10 Sample Calculation of Annualized Costs 6-36
6-11 Comparison of Annual ized Costs 6-37
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TABLES
(Continued)
Number Title Page
A-l Level of Detail Available in ECDB A-3
A-2 Comparison of 1974 BOM and ECDB Cross-Sectional Data. . . . A-4
D-l Projected Industrial Energy Conservation Factors D-4
D-2 Sample Calculation of Projected Energy Demand by Industry . D-5
D-3 Comparison of the Preliminary Projection amd a MEFS
Projection of Total Regional Fossil Fuel Demand D-6
E-l Comparison of NEDS and PEDCo Data E-3
E-2 Representative New Boiler Size/Capacity Utilization Rate
Categories E-4
E-3 New Industrial Boiler Size/Capacity Utilization
Distribution E-6
F-l Fuel Type Characteristics .' F-2
F-2 Representative Boilers Selected for Evaluation F-3
F-3 Industrial Boiler Types F-5
F-4 Basic Equipment and Installation Items Included in a New
Boiler Facility F-7
F-5 Boiler Non-Fuel Annual O&M Cost Components F-8
F-6 New Industrial Oil/Gas Boiler Capital Costs F-9
F-7 Industrial Oil/Gas Boiler Annual O&M Costs F-10
F-8 Sample New Industrial Coal Boiler Capital Costs F-12
F-9 Sample Industrial Coal Boiler Annual O&M Costs F-13
F-10 Sample Coal Types F-14
F-ll Boiler Retrofit Capital Costs by Component F-18
F-12 Boiler Retrofit Capital Costs F-19
F-13 Available Pollution Control Technologies F-20
F-14 Physical Coal Cleaning Specifications F-22
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TABLES
(Continued)
Number Title Page
F-15 Physical Coal Cleaning Capital Cost Components F-24
F-16 Physical Coal Cleaning Annual O&M Cost Components F-25
F-17 Physical Coal Cleaning Parameters F-27
F-18 FGD Capital Cost Components F-29
F-19 FGD Annual O&M Cost Components F-30
F-20 Sample FGD Capital and O&M Costs by Boiler Size F-31
F-21 Sample FGD Capital and O&M Costs by Percent Sulfur
Reduction for Two Boiler Sizes F-33
F-22 Particulate Matter Control Efficiencies F-34
F-23 Particulate Matter Control Equipment Annual O&M Cost
Components F-36
F-24 Sample PM Control Capital and O&M Costs by Boiler Size. . . F-37
F-25 NO Control Technologies -. F-39
/\
F-26 Potential NO Control from Combustion Modifications .... F-40
/\
F-27 Utility and Commodity Cost Assumptions F-42
G-l Data Estimates of Non-boiler Characteristics G-2
G-2 New Non-boiler Cost Comparison for a 333 MMBtu/hr. Rotary
Cement Kiln G-ll
G-3 Detailed Cost Breakdown for Retrofitting a 333 MMBtu/hr.
Rotary Cement Kiln . G-15
G-4 New Non-boiler Cost Estimates G-19
G-5 Non-Boiler Retrofit Capital Cost Estimates G-20
1-1 Tabulation of 1990 Coal Prices for the Northern Appalachian
Supply Regions 1-6
1-2 1990 Crude Mix as Represented by Catalytic Residua 1-8
1-3 Costs of Direct HDS for 0.3 and 0.8% Sulfur Fuel Oil. ... 1-9
1-4 Residual Fuel Oil Desulfurization Costs 1-13
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FIGURES
Number Title Page
1-1 IFCAM Model Structure 1-5
5-1 Coal Supply Regions 5-15
6-1 Coal Supply Regions 6-14
6-2 Major Steps in Fuel Choice-Decision 6-20
6-3 Major Steps in Selecting Least Cost Coal Type 6-21
C-l Simplified Overview of the Midterm Energy Forecasting
System C-3
C-2 MEFS Demand Module C-5
D-l Federal Regions D-7
H-l Federal Regions H-2
1-1 Residual Fuel Oil Desulfurization Cost for a 2.93% S
Residua 1-11
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1. IFCAM OVERVIEW
1.1 PURPOSE OF MODEL
The Industrial Fuel Choice Analysis Model (IFCAM) is an energy
demand model developed to evaluate fuel choice decisions in the indus-
trial sector over a five to 15 year forecasting horizon. IFCAM, a
highly disaggregated process engineering model,* is a comprehensive
analytical tool that can help decision makers in both the public and
private sectors assess a range of energy, environmental, and cost impacts
resulting from policy alternatives. Specifically, IFCAM can help eval-
uate fuel choice alternatives in the industrial sector.
The basic assumption in the model's analytical approach is that
fuel choice decisions are made by selecting the fuel alternative with
the lowest expected life cycle costs. The "population" of industrial
combustors is identified and the total costs of each alternative fuel
type are compared on an after-tax discounted cash flow basis for each
combustor. The costs include capital and annual operating, maintenance,
A process engineering model represents each new and existing technical
alternative with direct engineering information and can analyze specific
policies with respect to their effect on each technical alternative.
IFCAM is not an econometric model(mathematical equations solved simul-
taneous ly~wTth coefficients estimated statistically from historical
data), an optimization model (derivation of "best" solutions by means
of algebraic procedures such as linear programming), or a simulation
or systems dynamic model (mathematical equations solved recursively
with coefficients estimated from a modeler's experience and intuition).
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and fuel expenses. Technical and environmental constraints to fuel
substitution alternatives also are considered.
The model structure has been designed to analyze the impacts on
industrial fuel choices of four sets of factors: fuel prices, govern-
ment energy and environmental policy proposals, the costs associated
with firing alternative fuels, and other key model parameters. Earlier
versions of IFCAM have been used extensively by the Department of
Energy (DOE) to analyze key provisions of the Powerplant and Industrial
2 3
Fuel Use Act (PIFUA), project industrial energy demand, and evaluate
4
the effects of oil and gas user taxes and incremental pricing of natural
gas on the industrial sector.
Most recently, the model capabilities have been expanded to evaluate
detailed environmental regulations and numerous pollution control strategies.
IFCAM currently is being used by the U.S. Environmental Protection
Agency (EPA) to estimate the aggregate energy, cost, and environmental
impacts of regulatory alternatives in the analysis of New Source Perfor-
mance Standards (NSPS) for industrial fossil fuel-fired boilers. The
NSPS regulates air emissions of particulate matter (PM), sulfur dioxide
(SO,), and nitrogen oxides (NO ).
£ /\
The remainder of this section discusses the model's key inputs, the
model logic, and the model capabilities.
1.2 KEY MODEL INPUTS
The major exogenous inputs to IFCAM are the energy scenario, envi-
ronmental regulations, and cost data. Energy policies can affect indus-
trial fuel choice decisions by altering financial parameters (e.g., coal
1-2
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investment proposals) or'by restricting fuel choice alternatives (e.g.,
requiring coal consumption in large new industrial boilers). Environmental
regulatory policies affect fuel choice decisions by altering the relative
costs of burning alternative fuels. Regulations pertaining to particulate
matter, SCL, and NO from fuel-burning sources include State and local SIP
L* A
regulations and Federal NSPS.
The energy scenario* includes projections of:
Delivered fuel prices by region
Industrial production growth rates by region and major industry -
group
Total industrial fossil fuel demand by region
Financial parameters (e.g., discount rate)
Energy policies (e.g., PIFUA and the Energy Tax Act - ETA).
The delivered fuel price forecast includes assumptions about world oil
prices, natural gas deregulation and incremental pricing, and fuel
taxes. Industrial production growth rate projections incorporate assump-
tions about future economic activity.
IFCAM originally was developed partly to provide the DOE's Midterm
Energy Forecasting System (MEFS) with an alternative source of forecasts
of industrial fossil fuel mix. IFCAM was structured to use MEFS estimates
of overall industrial fuel demands and to focus on the mix of fossil
fuel consumption in the industrial sector. Thus, IFCAM can provide
See Appendix H for an outline of energy scenario specifications.
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detailed results for the time periods covered by MEFS (1985, 1990, and
1995) for the 10 Federal regions.
1.3 MODEL LOGIC
This subsection outlines the general structure of IFCAM and briefly
describes each model step. Figure 1-1 outlines the model structure,
identifying the following key inputs and major analytical steps:
Inputs 1, 2, and 3 --Energy Demand and Industrial Production
Model Step #1 - Characterize Fuel Consumption
Model Step #2 - Create and Site Individual Combustors
Model Step #3 - Determine Environmental Requirements
Model Step #4 - Identify Technical Fuel Substitution Potential
Input 4 - Fuel Prices, Energy Policy, and Financial Parameters
Model Step #5 - Analyze Economics of Fuel Choice.
i
Detailed discussions of key assumptions and data sources are presented
in Sections 2 through 6 of this report. Section 7 outlines model output
features.
1.3.1 Overview of Model Structure
1.3.1.1 Inputs of Fossil Energy Demand and Industrial Production*
IFCAM focuses on the choice between coal, oil, and gas with the
level of fossil fuel demand specified as an exogenous input. To date,
total fossil fuel demand for all industry has been generated by MEFS for
each of the 10 Federal regions.
See Appendix H for an outline of energy scenario specifications.
1-4
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FIGURE 1-1
IFCAM MODEL STRUCTURE
INPUT 1
INDUSTRIAL \
FOSSIL FUEL I
USE IN 1111\1
Refional Fuel Piicei
INPUT 4 Eoeify Policy
Financial Paia«etefs
INPUT 2
INDUSTRIAL \
PRODUCTION I
GROWTH RATES /
i
tn
CREATE I SITE
INDIVIDUAL COMBUSTORS
Ideality by:
location
capacity limitation
useful Illc .
cuifcal luel
lype(s) lol eilslini unill
ENVIRONMENTAL
REQUIREMENTS
Assifn Re|ulalloos
Specify Council Stialeilet
ECONOMICS OF FUEL
CHOICE
* Assi|D Costi to
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The MEFS model is a general equilibrium energy model that relies on
the Data Resources, Inc. (DRI) macroeconomic model to provide the economic
trends which drive the growth in energy demand. MEFS estimates total
regional industrial fossil fuel demand by fuel type.* National industrial
production growth rates for eight industrial sectors are provided by the
DRI model runs. These industrial production growth rates are regionalized
by DOE and are used in IFCAM to capture shifts in energy demand among
the major energy consuming industries.
1.3.1.2 Characterization of Industrial Energy Use
In this first model step, total regional fossil fuel demand estimates
are disaggregated to characterize industrial energy use by factors such
as industry group, functional use, existing fuel type, combustor size,
and location. These factors are significant because they:
Alter the costs of using alternative fuels (e.g., fuel costs
vary according to industrial location)
Determine the economics of fuel choice (considering such
factors as the combustor's capacity utilization rate)
Distinguish elements of energy use specifically targeted by
energy policy measures (e.g., new boilers above a cutoff
size).
Energy use is disaggregated into eight industrial subsectors. These
subsectors are unique in terms of growth rates, regional dispersion, and
technical capability to use alternative fuels.
IFCAM disaggregates fuel use by functional use, i.e., by boiler and
process heaters. Over 40 process applications, such as tubestill heaters
MEFS only distinguishes between petroleum refining and all other
industrial energy uses.
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used-in atmospheric distillation in petroleum refineries, cement kilns,
metal reheating furnaces, and glass melters, are characterized. Categor-
ization by functional use is important because the technical capability
to use residual oil or coal in many processes varies due to problems of
product contamination, corrosion, temperature control, and current
equipment design. The costs of burning alternative fuels also vary
significantly among process applications.
In addition to classifying combustors by functional use, combustors
are classified according to whether they are new or existing facilities.
Existing units are further classified by the type of fuel they were
designed to fire and whether they can be retrofitted to fire alternate
fuels.
Combustors are also categorized by factors, such as size and location,
which affect the costs of burning alternative fuels. Seven size classes
are distinguished for boilers and one to three size classes for each
process heat application. Combustors are categorized by location since
fuel users in New England pay relatively higher prices for coal than
fuel users in the Midwest.
Operating practices also distinguish combustors. For boilers, five
capacity utilization classes, with representative values ranging from 25
to 75 percent, are used to distinguish a wide range of operating practices
varying by industry and combustor size.
1.3.1.3 Creation of Individual Combustors
Fuel use is classified into individual combustor units (Step 2 in
Figure 1-1) according to location (region), size, capacity utilization,
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and industry. Air Quality Control Region (AQCR) is the only level of
additional detail (244 AQCR's) developed in this step. Environmental
regulations for all existing combustors and many new fuel-burning facili-
ties vary among States and among counties within States. Since environ-
mental control costs are a major factor affecting the economics of fuel
choice, IFCAM is designed to reflect this variation in environmental
costs.
Large existing boilers are sited in their actual locations while
new boilers and small existing boilers are located according to histor-
ical (within Federal region) patterns by AQCR. Although current loca-
tional patterns are estimated crudely, AQCR siting provides a framework
for more sophisticated facility siting algorithms at a future date.
1.3.1.4 Assignment of Environmental Regulations and Pollution Control
Strategies
Environmental regulations play an important role in determining the
level of fuel substitution. Environmental regulations may increase
capital, operating, and fuel costs by increasing the environmental
control required or quality of fuel burned. The specific regulations
vary geographically (AQCR), by combustor size and type, and by type of
fuel.
Environmental regulations on a State and Federal level have been
examined for three pollutants: S09, particulate matter, and NO . Regu-
£ /\
lations are developed for three categories of combustors in JFCAM:
boilers subject to NSPS, boilers not subject to NSPS, and process heaters.
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State and local regulations in many areas are being revised, especially
where air quality standards are not being attained. Although IFCAM
model runs have used only current regulations, revised regulations can
be inserted easily.
The NSPS regulations for new boilers are being revised to conform
with the 1977 Clean Air Act (CAA) amendments. Several regulatory alter-
natives have been evaluated to determine the impacts on projections of
fossil fuel mix. Several formats of NSPS specifications for SCL control
for coal-fired boilers can be analyzed using IFCAM. For example, the
regulation can vary by boiler size and be specified as:
t A ceiling emission rate (Ibs. of pollutant/MMBtu of fuel
burned)
A recommended percentage removal (e.g., 90 percent removal of
original uncontrolled sulfur content)
A recommended percentage removal and a "floor" emissions rate
(e.g., 90 percent removal but no lower than 0.8 Ibs. SOp/MMBtu)
A minimum percentage removal to be used if the recommended
percentage removal results in controlled emissions less than
the floor emissions rate.
IFCAM includes three types of flue gas desulfurization (FGD) systems
(two have combined SO^/particulate matter control) and four types of
post-combustion particulate matter control. The scrubber costs are
unique for each coal type and SOp emissions limit, and allow for both
partial scrubbing and full scrubbing.
1.3.1.5 Technical Potential to Use Substitute Fuels
The next model step is to identify the industrial fuel uses (primarily
process heat applications) that clearly would not select coal or residual
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oil due to technical constraints, timing considerations, or general
economic factors. When residual oil and/or coal are technically infeas-
ible, the economic alternatives are limited to distillate oil or natural
gas. An evaluation of technical potential considers the following
factors:
Technical capability to use coal or residual oil
Lead times to develop new coal-firing technologies and order
new equipment for process heat applications not currently
burning coal
While coal firing is a proven technology in new boiler applications,
coal currently is used in only a few process heat applications. Conse-
quently, IFCAM incorporates a judgment of the technical feasibility of
coal use for major process heat applications, ranked according to the
risk of equipment failure. When new equipment designs must be developed,
lead times for the design and operation of demonstration facilities are
included. These technology development lead times, which range from
three to six years, will limit severely the applicability of coal firing
in process heat applications in 1985-90. A similar distinction is made
for residual fuel oil when technical problems preclude its use.
For boilers and several process heaters, fuel switching is restricted
to conversions between oil and gas. Since attempts to retrofit coal
would involve major redesign of the furnace and possibly an efficiency
loss and significant derating, the cost of retrofitting a non-coal
capable boiler to burn coal is considered to be prohibitive.
In considering the impact of proposed energy policy decisions,
IFCAM also incorporates lead times for the construction of new facilities.
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For example, the construction lead time for a new boiler typically
ranges from two to three years.
Supply-related constraints that could limit coal use include the
availability of coal supplies, production capacity limits on new boilers,
and environmental control equipment. These constraints are not incorporated
specifically into the model logic and have been analyzed separately,
given the demands implied by a specific model run.
1.3.1.6 Fuel Prices, Energy Policy and Financial Parameter Inputs
IFCAM can analyze fuel price variations and two types of energy
policy measures: tax policies that affect the economics of fuel choice
and regulatory programs. Fuel price variations are used in IFCAM to
model fuel taxes, natural gas deregulation, or variations in price
trajectories. Fuel types include natural gas, distillate fuel oil,
residual fuel oil (four sulfur classes), and coal. The price of each
fuel type can differ by region and increase in real terms over time.
Delivered coal prices are estimated by adding F.O.B. mine costs,
coal cleaning costs, and transportation expenses from supply to demand
region centroids. Of the 39 coal types in IFCAM, there are nine raw
coals that are not cleaned and 14 raw coals that are processed to produce
16 cleaned coal types.* Coal cleaning reduces sulfur and ash content
and increases Btu content, thus reducing pollution control costs and
annual tonnage requirements. Coal transportation costs are estimated
using single-car rail rates.
Two raw coals are cleaned to two different levels.
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The investment incentives considered focus primarily on differen-
tial depreciation methods for coal-, oil-, or gas-fired unit capital
investments and on increased investment tax credits (ITC's) for invest-
ments in alternative fuels. The impacts of differential depreciation
methods and investment incentives are handled within the scope of the
main model logic (Step 5 in Figure 1-1).
The coal conversion regulatory program established under PIFUA
targets boilers with a rated capacity greater than 100 MMBtu/hr. An
economic test compares the total cost [capital, annual operating and
maintenance (O&M), and fuel] of burning coal to the total 'cost of burning
imported oil to simulate legislative provisions related to economic
exemptions. IFCAM projects the level of increased coal use under the
program, in the absence of any implementation problems.
1.3.1.7 Economics of Fuel Choice
The following presents the method for simulating the fuel choice
investment decision for the industrial sector. For each combustor, the
capital, operating, and fuel costs for each alternative fuel type are
compared. This comparison employs a standard net present value (NPV)
calculation as the investment criterion. An economic fuel choice is
calculated for each combustor. In cases when technical or environmental
problems preclude a certain fuel choice, the next best economic alter-
native is chosen.
The major components considered in the NPV calculation are shown
below:
Capital cost
Construction period
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Revenue life
Depreciation life and method
ITC
Discount rate
Fuel price
Annual fuel consumption
O&M costs
Corporate tax.
The components of NPV can be divided into three major subsets:
policy inputs, standard model assumptions, and key model variables.
Policy inputs are depreciation life and method, ITC, and fuel prices.
Standard model assumptions are construction period and corporate tax
rate. These elements do not vary by combustor characteristics and
represent standard investment assumptions. Key model variables (capital
costs, revenue life, discount rate, annual fuel consumption by capacity
utilization and size, and O&M costs) all vary with factors considered in
the model and are discussed below.
Capital cost components were developed for each fuel type as a
function of combustor type, size, and environmental control requirements,
according to new or existing status and prior fuel design. Capital cost
components are calculated for each combustor. For example, when considering
coal use, if an existing oil boiler previously had burned coal, then
only the retrofit costs of converting back to coal would be considered
in the NPV. A new unit, on the other hand, would examine the total cost
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(capital, O&M, and fuel) of coal, oil, and gas when evaluating an invest-
ment decision. O&M costs do not vary by the new/existing status of a
combustor but do change by combustor type, fuel type, size, capacity
utilization, and pollution control strategy.
The discount rate used for the NPV represents the hurdle rate or
required rate of return on an investment. The actual value of the
discount rate that should be used is uncertain; however, the discount
rate is designed conceptually to take into account the cost of capital
and an investment priority scheme.
New fuel-using combustors are necessary to provide steam or process
heat to meet increased industrial production goals or to replace wornout
facilities. Conversions of existing facilities to an alternative fuel
choice would be undertaken solely to reduce energy costs, not to satisfy
production goals. These "discretionary" investments in existing fuel-using
facilities are required in IFCAM to pass a more severe hurdle rate test
than are new combustors in order to simulate capital rationing schemes
currently applied in the industrial sector.
In the actual analysis, the NPV of capital and annual O&M costs for
all the possible environmental control scenarios and fuel types is
calculated for each combustor. These NPVs are matched to the appropriate
NPV of the price stream for each fuel type that could be burned in the
combustor, and a least cost fuel type is determined. IFCAM, in effect,
chooses the least cost fuel and associated environmental control strategy
within the limits of the technical feasibility and environmental constraints.
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1.4 MODEL CAPABILITIES
1.4.1 General Attributes
IFCAM has two major attributes. The first is its high level of
disaggregation. IFCAM simulates fuel choice decisions at the combustor
level and can account for a considerable amount of variability in factors
(technical, regulatory, and economic) that influence fuel decisions.
Second, IFCAM is sensitive to policy variables that can alter fuel
choice decisions to meet a national objective (e.g., clean air or reduced
oil imports).
IFCAM provides a logical framework for comprehensive analysis of
alternative scenarios. It clarifies decision alternatives by providing
information on the relative impacts of different courses of action.
IFCAM's general approach has been reviewed with industrial managers.
Some of the model details have been simplified to achieve a reasonable
balance between reality and manageability, but generally the model has
been expanded to include a wide range of critical factors and parameter
values.
1.4.2 Specific Attributes
Sensitivity analyses can be performed with respect to the key model
inputs (e.g., fuel prices) or to the standard model assumptions (e.g.,
new boiler size distribution, retirement rates). For example, IFCAM can
evaluate the impacts of investment incentives (e.g., ITC's) or regulatory
policies to promote coal use. Key provisions of the ETA and PIFUA are
incorporated in IFCAM. A wide range of alternatives are also available
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for each combustor in terms of the number of options of fuel types and
pollution control strategies.
IFCAM projects the fuel mix in new units and-estimates fuel switching
in existing units. The potential for oil and coal substitution in
energy-intensive processes is evaluated to identify technical constraints
to future fuel choice decisions.
IFCAM generates aggregate results for 1985, 1990, and 1995. The
energy mix estimates are available by fuel type, size, new or existing
status, functional use (boilers versus process heaters), nine industry
groups, and region. The total capital, operating, and fuel expenses are
also available. Air emissions of particulate matter, S0?, and NO are
L- /S
estimated. Solid and liquid waste disposal requirements and energy
penalties associated with the operation of pollution control equipment
are also estimated. Therefore, IFCAM produces complete energy, cost,
and environmental impacts of alternative scenarios.
1.4.3 Limitations
The major assumption in the analytical approach is that fuel choice
decisions are made by selecting the fuel with the lowest expected life
cycle costs. However, perceptions about fuel supply reliability and
availability (e.g., potential coal miners' strikes, natural gas curtail-
ments, oil embargoes), other fuel types used at the plant, staff experience
with fuel types not currently used, capital availability, and the reliabilty
of pollution control equipment also can influence fuel choice decisions.
These factors generally are not quantifiable on a uniform basis for all
1-16
-------
plants. As a result, any model is limited in its ability to generalize
V
about future courses of action.
IFCAM, an energy demand model, does not normally iterate with a
supply model to reach an equilibrium solution with respect to balancing
supply and demand or marginal fuel prices. In addition, IFCAM estimates
the fuel mix with the total level of demand specified as an exogenous
input. The model excludes electricity, raw materials, feedstocks, wood,
byproduct fuels, and liquefied petroleum gas.
IFCAM does not consider alternatives such as process changes,
shifts from direct to indirect firing, increased electrification, or
coal conversion technologies such as liquefaction. Atmospheric fluidized
bed combustion (AFBC) and low Btu gas are coal conversion technologies
that will be added. However, the mid-term time frame of IFCAM precludes
significant market penetration of advanced technologies still in the
development stage.
1.5 REPORT ORGANIZATION
The remaining sections of this report present a more detailed
discussion of the major model steps. Sections 2 through 6 review details
of the model logic and data sources. Section 7 summarizes key features
of model output capabilities.
Table 1-1 compares the report sections to the model inputs and
steps. Section 2 summarizes Input 1: Industrial Fossil Fuel Use in
1974 and reviews the approach for projecting fossil fuel use by major
industry group using Input 2: Industrial Production Growth Rates and
1-17
-------
TABLE 1-1. SUMMARY OF REPORT ORGANIZATION
Report Section
Model Inputs and Steps
2: Industrial Energy
Consumption
3: Characteristics of
Industrial Fossil Fuel Use
4: Technical and Other Con-
straints to Fuel Substitution
5: Assignment of Environmental
Regulations and Pollution
Control Strategies
6: Economics of the Fuel Choice
Decision
Inputs 1 & 3: Fossil Fuel
Demand in 1974 and 1985
(1990, 1995)
Input 2: Industrial Production
Growth Rates
Step #1: Characterize Fuel
Consumption - by industry
Step #1: Characterize Fuel
Consumption - detailed classi-
fications
Step #2: Create Individual Com-
bustors
Step #4: Technical Fuel Substi-
tution Potential
Step #2: Site Individual Combustors
Step #3: Environmental Requirements
Input 4: Regional Fuel Prices,
Energy Policy, Financial Parameters
Step #5: Economics of Fuel Choice
1-18
-------
Input 3: Industrial Fossil Fuel Demand in 1985. Section 3 describes
the approach for completing Step 1: Characterize Fuel Consumption and
initiating Step 2: Create Individual Combustors. Section 4 discusses
Step 4: Technical Fuel Substitution Potential. Step 2: Site Individual
Combustors and Step 3: Environmental Requirements are detailed in
Section 5. Section 6 presents examples of the fuel choice decision
using sample financial parameters from Input 4 to illustrate Step 5:
Economics of the Fuel Choice. Aggregate model outputs are not presented
in this report.
1-19
-------
REFERENCES
Industrial Fuel Choice Analysis Model. Volume I - Primary Model
Documentation and Volume II - Appendices to Model Documentation.
Energy and Environmental Analysis, Inc. Arlington, Va. Draft
report prepared for the Office of Policy and Evaluation, U.S.
Department of Energy. January 1979. 309 p.
Coal Utilization Model of the Industrial Sector. Volume I - Primary
Model Documentation and Volume II - Appendices to Model Documentation.
Energy and Environmental Analysis, Inc. Arlington, Va. Draft
report prepared for the Office of Policy and Evaluation, U.S.
Department of Energy. October 1978.
Mead, D.E., F.H. Murphy, and W.D. Montgomery. Analysis of Proposed
U.S. Department of Energy Regulations Implementing the Powerplant
and Industrial Fuel Use Act. Energy Information Administration,
U.S. Department of Energy. Publication No. DOE/EIA-0102/21.
November 1978. 198 p.
Technical and Economic Feasibility of Alternative Fuel Use in
Process Heaters and Small Boilers. Energy and Environmental Analysis,
Inc. Arlington, Va. Prepared for the Energy Information Adminis-
tration, U.S. Department of Energy. Publication No. DOE/EIA-10547-01.
February 1980. 298 p.
Analysis of Key Economic Test Parameters in the Powerplant and
Industrial Fuel Use Act. Energy and Environmental Analysis, Inc.
Arlington, Va. Draft report prepared for the Office of Policy and
Evaluation, U.S. Department of Energy. January 1979. 47 p.
Annual Report to Congress 1978. Energy Information Administration,
U.S. Department of Energy. Publication No. DOE/EIA-0173/3. p.
391.
An Analysis of the Potential for Coal Use in the Industrial Sector.
Energy and Environmental Analysis, Inc. Arlington, Va. Prepared
for the President's Commission on.Coal. March 1980. 66 p.
Kincel, K.K., F.H. Murphy, H. Walton. An Evaluation of Energy
Related Tax and Tax Credit Programs. Energy Information Adminis-
tration, U.S. Department of Energy. Publication No. DOE/EIA-0102/8.
July 1978. 131 p.
1-20
-------
REFERENCES (cont'd)
5. Technical Staff Analysis in Response to Notice of Proposed Rulemaking
on Phase II of Incremental Pricing. Office of Policy and Evaluation,
U.S. Department of Energy. Prepared for the Federal Energy Regulatory
Commission. February 1980.
The Premium on Natural Gas as a Boiler Fuel in the Industrial
Sector. Energy and Environmental Analysis, Inc. Arlington, Va.
Prepared for the Office of Policy and Evaluation, U.S. Department
of Energy. May 1979.
6. EEA has developed ISTUM to estimate new technology penetration in
the industrial sector. See Industrial Sector Technology Use Model
(ISTUM): Industrial Energy Use in the United States, 1974-2000.
Energy and Environmental Analysis, Inc. Arlington, Va. Prepared
for the U.S. Department of Energy. Publication No. DOE/FE/2344-1,
-2, -3, -4. October 1979. 1200 p.
1-21
-------
2. INDUSTRIAL ENERGY CONSUMPTION
2.1 INTRODUCTION
This section describes the first step used in characterizing industrial
fuel use -- transforming MEFS inputs of potential coal, oil, and gas
demand into fossil fuel demands by major industrial sectors. Introductory
parts of this section include definitions of the fuel uses covered in
IFCAM and an overview of industrial fuel use by industry and major
functional uses.
2.2 ENERGY CONSUMPTION BASELINE
The primary data sources used for energy consumption information
in IFCAM are the Energy Consumption Data Base (ECDB)2 and the MEFS
model.* The ECDB contains historical fuel consumption data disaggregated
by industry, region, and fuel type. MEFS projects total industrial
energy consumption levels by region in 1985, 1990, and 1995.** Since
the fossil energy demand estimates used as inputs into IFCAM are derived
from MEFS, the first step in developing an industrial energy data base
involves reconciling the definitional differences in the ECDB and MEFS
historical data bases.
* See Appendix C for a description of MEFS.
** MEFS also projects the fuel mix but IFCAM was developed in part to
provide MEFS with an alternative source of forecasts of industrial
fossil fuel mix.
2-1
-------
In 1974, net energy consumption (consumption less production) for
all economic sectors was about 70 quadrillion Btu (74 x 10 kJ). The
industrial sector (excluding fuel use for transportation) accounted for
36 percent of total fuel consumption in the United States (see Table 2-1).
Fossil fuels are used in the industrial sector as a means to generate
process .heat, as a boiler fuel, and as a feedstock. Examples of process
heat equipment include furnaces, ovens, dryers, kilns, and tubestill
heaters. Boilers are used to generate steam and hot water for space
heating, process steam, and electricity generation. Miscellaneous
functional uses (primarily of electricity) include electrolytic processes,
machine drive, cooling, and lighting.
Table 2-2 presents estimates of industrial energy consumption in
1974 by functional use and fuel type. Boiler fuel is the largest single
functional energy use category. Natural gas contributed one-half of the
boiler and process heat energy demand in the industrial sector in 1974.
In IFCAM, the industrial sector is defined to include all manufac-
turing, mining, construction, and agriculture sectors of the economy.
Since the fossil energy demand estimates used as inputs into IFCAM
usually have been derived from MEFS, several conventions have been
followed. All gasoline and diesel fuel have been classified as transpor-
tation sector consumption. Likewise, the consumption of oil products
for the production of asphalt used in the construction industry has been
reclassified as commercial sector use.
2-2
-------
TABLE 2-1. 1974 NET ENERGY CONSUMPTION IN THE U.S.3
(1015 W (1015 Btu))
Sector
Residential
Commercial
Industrial
Manufacturing
Mining
Construction
Agriculture
Transportation
Private (Residential)
Industrial /Commercial
Electric Utilities9
TOTAL
Coal
(X)
0.1 (0.1)
3.9 (3.7)
3.8 (3.6)
(X)
0
(X)
0
0
0
9.1 (8.6)
13.1 (12.4)
Oil
4.
1.
8.
4.
0.
1.
1.
17.
10.
6.
3.
33.
0
2
0
6
3
9
2
0
9
1
5
8
(3.8)
(1.1)
(7.6)
(4.4)c
(0.3)
(1.8)
(1.1)
(16.1)f
(10.3)
(5.8)
(3.3)
(32.0)
Natural Gas
5.6
2.4
9.1
7.5
1.5
0
0.2
0.7
0
0.7
3.7
21.5
(5.3)
(2.3)
(8.6)
(7.1)
d.4)e
(0.2)
(0.7)
(0.7)
(3.5)
(20.4)
Electricity
2.2
1.9
2.5
2.2
0.1
(X)
0.1
(X)
0
0
-6.8
-0.2
(2.0)
(1.8)
(2.4)
(2.1)
(0.1)
(0.1)
(-6.4)
(-0.2)
NSK/NECb
(X)
0.1 (0.1)
3.1 (2.9)
3.0 (2.8)d
(X)
0
0
0
0
0
2.3 (2.2)
5.5 (5.2)
Total
11.7
5.7
26.7
21.2
2.0
2.0
1.5
17.7
10.9
6.9
11.8
73.6
(11.1)
(5.4)
(25.3)
(20.1)
(1.9)
(1.9)
(1.4)
(16.8)
(10.3)
(6.5)
(11.2)
(69.8)
(X) - Less than 52.8 trillion kj (50 trillion Btu).
a Energy Consumption Oata Base. EEA, Inc. Consumption less production. The energy used to produce electricity, steam, coke oven gas
and blast furnace gas is counted only once.
Not specified by kind/not elsewhere classified. NSK can contain coal, oil, gas, electricity, or other fuels. An example of NEC would
be black liquor used in the pulp and paper industry.
c Excludes 243 trillion kj (231 trillion Btu) of asphalt.
d Includes 912 trillion kj (865 trillion Btu) of wood residuals and 1,099 trillion kJ (1,042 trillion Btu) of refinery (still) gas.
The balance may be natural gas used in small industries.
May be understated by nearly a half quad.
Excludes approximately 0.95 x 10 kj (0.9 quads) of military consumption.
9 Approximately 160 trillion kj (152 trillion Btu) is unaccounted for.
2-3
-------
TABLE 2-2, CHARACTERIZATION OF INDUSTRIAL ENERGY
CONSUMPTION IN 1974a
(1015 kJ (1015 Btu))
Functional Use
Fuel Type
Coal
Oil
Distillate fuel oil
Residual fuel oil
Other0
Natural Gas
Electricity
Otherd
TOTAL
a Energy Consumption
Miscellaneous and
C T ..,.1 ..-I-- i nr _-.-.,
Raw
Boilers Materials
1.2 (1.1) 2.4 (2.3)
1.3 (1.2) 3.0 (2.8)
0.2 (0.2)
1.1 (1.0)
- . 3.0 (2.8)
3.6 (3.4) 0.5 (0.5)
-
1.2 (1.1)
7.2 (6.8) 5.9 (5.6)
Data Base. EEA, Inc.
unclassified uses.
t m
Process
Heat
0,3 (0.3)
1.7 (1.6)
0.2 (0.2)
0.6 (0.6)
0.8 (0.8)
3.0 (2.8)
0.1 (0.1)
0.8 (0.8)
5.9 (5.6)
1 *> *. «. ~J _J A*
Otherb
-
2.2 (2.1)
0.7 (0.7)
-
1.5 (1.4)
2.0 (1.9)
2.4 (2.3)
1.1 (1.0)
-7.7 (7.3)
Total
3.9 (3.7)
8.0 (7.6)
1.2 (1.1)
1.6 (1.5)
5.3 (5.0)
9.1 (8.6)
2.5 (2.4)
3.1 (2.9)
26.7 (25.3)
products.
Includes 0.95»«x 10 kJ (0.9 quads) of wood residuals and 1.05 x 10 kJ
(1.0 quads) of refinery (still) gas. The balance may be natural gas used
in small industries in small boilers.
2-4
-------
Electricity use is excluded since IFCAM focuses only on fossil
energy demand. Raw materials, feedstocks, byproduct fuels,* and lique-
fied petroleum gas (LPG) are excluded because the energy and environmental
policy issues to be analyzed using the model do not focus on these fuel
uses. As a result of these classifications, IFCAM accounts for about
one-half** of total industrial energy consumption (see Table 2-3).
2.3 OVERVIEW OF INDUSTRIAL ENERGY USE
There are nine major industry'groups in IFCAM. Table 2-4 presents
the distribution of 1974 industrial fossil fuel consumption by major
industry group and fuel type. This table reflects the concentration of
fuel use in several key industrial sectors. Five industry groups (Paper,
Chemicals, Petroleum Refining, Steel, and Stone, Clay and Glass) accounted
for over 50 percent of non-feedstock coal, fuel oil, and gas consumption
in the industrial sector in 1974. Table 2-5 summarizes the distribution
of industries included in the "other" industry group in Table 2-4.
Boilers account for nearly one-half of the historical fuel coverage
in IFCAM. The distribution of coal, fuel oil, and gas consumption by
major industry group is shown in Table 2-6. The Chemicals and Paper
* Refinery (still) gas, coke oven gas, blast furnace gas, tar, and pitch
are excluded. Black liquor, wood and bark are not covered in MEFS
concepts, although these energy sources can substitute for fossil
fuels.
** 12.2 out of 25.3 quads in 1974.
Table 2-3 shows the relative differences between an old MEFS baseline
and the current IFCAM baseline.
2-5
-------
cr>
TABLE 2-3. ADJUSTMENTS TO ECDB INDUSTRIAL ENERGY USE
(1015 kJ (1015 Btu))
Original ECDjjf (1974)
Less:
Raw material and feedstock
LPG
Byproduct fuels
Electricity
Other definitional
Adjusted ECDB (1974)
MEFS (1975)
a Metallurgical coal.
Primarily asphalt consumption
sector.
Coal Oil
3.9 (3.7) 8.0 (7.6)
2.5 (2.4)a 2.0 (1.9)
0.2 (0.2)
1.1 (1.0)C
1.8 (1.7)e
1.4 (1.3) 3.1 (2.9)
1.5 (1.4) 3.5 (3.3)
in the construction industry
i
Gas Other
9.1 (8.6) 5.6 (5.3)
0.5 (0.5) 0.9 (0.9)b
0.9 (0.9)d
2.5 (2.4)
1.1 (1.0)f
8.5 (8.1)
8.8 (8.3)
and classified by BOM/MEFS in
Total
26.7 (25.3)
6.1 (5.8)
0.2 (0.2)
2.0 (1.9)
2.5 (2.4)
2.8 (2.7)
13.0 (12.3)
13.7 (13.0)
the commercial
Primarily wood residuals.
e BOM/MEFS defines all gasoline and diesel fuel consumption in the transportation sector. Also includes a
small amount of miscellaneous petroleum products.
Fuels in ECDB that are not classified by fuel type due to Census reporting errors or incomplete data. As
much as 0.5 quads of natural gas may be misclassified here.
-------
TABLE 2-4. INDUSTRIAL FOSSIL FUEL CONSUMPTION IN 1974 BY MAJOR INDUSTRY1
(1012 kJ (1012 Btu))
ro
i
Industry
Food
Textiles
Paper
Chemicals
Petroleum
Refining
Stone, Clay
and Glass
Steel
Aluminum
Other0
TOTAL
Coal
$ 79.4 (75.3)
23.2 (22.0)
220.3 (208.8)
339.9 (322.2)
5.6 (5.3)
246.9 (234.0)
179.7 (170.3)
32.7 (31.0)
261.0 (247.4)
1,388.7 (1,316.3)
a
Energy Consumption Data Base.
Natural Gas
501.8 (475.6)
107.7 (102.1)
437.1 (414.3)
1,706.1 (1,617.2)
1,172.5 (1,111.4)
734.6 (696.3)
719.4 (681.9)
433.8 (411.2)
2,798.4 (2,652.5)
8,611.4 (8,162.5) 1,
EEA, Inc. Excludes
Distillate
Fuel Oil
70.5 (66.8)
27.4 (26.0)
26.6 (25.2)
126.7 (120.1)
53.1 (50.3)
80.2 (76.0)
15.6 (14.8)
17.9 (17.0)
801.8 (760.0)
219.8 (1,156.
raw material
Residual
Fuel Oil
69.1 (65.5)
38.7 (36.7)
515.5 (488.6)
174.2 (165.1)
297.0 (281.5)
52.2 (49.5)
263.3 (249.6)
17.9 (17.0)
201.3 (190.8)
2) 1,629.2 (1,544.3)
and feedstock uses.
Total
720.8 (683.2)
197.1 (186.8)
1,199.4 (1,136.9)
2,347-0 (2,224.6)
1,528.2 (1,448.5)
1,113.9 (1,055.8)
1,178.0 (1,116.6)
502.4 (476.2)
4,062.5 (3,850.7)
12,849.2 (12,179.3)
Washington, D.C. 1975. Table 18.
Draft Target Report on the Development of and Establishment of Energy Efficiency Improvement Targets for
Primary Metals Industries, SIC 33. Volume II. Appendices. Battelle Columbus Laboratories. Columbus,
Ohio. 1977. Prepared for the Federal Energy Administration.
Includes miscellaneous manufacturing, agriculture, and mining industries.
-------
TAOLE 2-5. INDUSTRIAL FOSSIL FUEL CONSUMPTION IN "OTHER" INDUSTRIES IN 1974*
(1012 kJ (1012 Btu))
PO
CO
Industry
Tobacco
Apparel
Lumber
Furniture
Rubber
Leather
Primary metals
Machinery
Electrical
machinery
Transportation
equipment
Measuring
equipment
Miscellaneous
manufacturing
SUBTOTAL
Unaccounted for
TOTAL MISCELLANEOUS
MANUFACTURING
Agriculture
Mining
TOTAL
Coal
5.8 (5.5)
1.1 (1.0)
3.0 (2.8)
3.0 (2.8)
31.2 (29.6)
1.4 (1.3)
78.9 (74.8)
21.2 (20.1)
13.9 (13.2)
50.2 (47.6)
-
O.B (0.8)
210.5 (199.5)
11.2 (10.6) -
221.7 (210.1)
0.7 (0.7)
38.5 (36.5)
261.0 (247.4)
Natural
Gas
4.7 (4.5)
16.2 (15.4)
76.9 (72.9)
26.7 (25.3)
91.4 (86. 6)
5.5 (5.2)
234.1 (221.9)
173.3 (164.3)
102.2 (96.9)
152.0 (144.1)
16.7 (15.8)
19.8 (18.8)
919.6 (871.7)
252.7 (239.5)
1172.3 (llll. 2)
177.3 (168.1)
1448.7 (1373.2)
2798.4 (2652.5)
Distillate
Fuel Oil
1.2 (1.1)
4.5 (4.3)
36.0 (34.1)
5.4 (5.1)
19.3 (18.3)
3.2 (3.0)
9.8 (9.3)
17.9 (17.0)
11.7 (II. 1)
17.6 (16.7)
3.5 (3.3)
4.6 (4.4)
134.7 (127.7)
29.2 (27.7)
163.9 (155.4)
514.3 (487.5)
123.5 (117.1)
801.8 (760.0)
Residual
Fuel Oil
4.3 (4.1)
1.5 (1.4)
8.8 (8.3)
2.6 (2.5)
27.1 (25.7)
3.5 (3.3)
15.3 (14.5)
17.4 (16.5)
10.9 (10.3)
25.1 (23.8)
9.9 (9.4)
4.3 (4.1)
130.7 (123.9)
19.3 (18.3)
150.0 (142.2)
-
51.3 (48.6)
201.3 (190.8)
Total
16.0 (15.2)
23.2 (22.1)
124.6 (118.1)
37.7 (35.7)
169.0 (160.2)
13.5 (12.8)
338.1 (320.5)
229.9 (217.9)
138.7 (131.5)
245.0 (232.2)
30.0 (28.5)
29.6 (28.1)
1395.6 (1322.8)
312.4 (296.1)
1707.9 (1618.9)
692.4 (656.3)
1662.2 (1575.5)
4062.5 (3850.7)
Energy Consumption Data Base. EEA, Inc.
Excludes steel and aluminum Industries.
-------
TABLE 2-6. FOSSIL FUEL CONSUMPTION IN INDUSTRIAL BOILERS BY INDUSTRY IN 1974C
(1012 kJ (1012 Btu))
ro
i
10
Industry
Food
Texti les
Paper
Chemicals
Petroleum Refining
Stone, Clay and
Glass
Steel
Aluminum
Other
TOTAL
Coal
79.4
23.2
220.3
339.9
5.6
1.5
165.6
32.7
261.0
1129.3
(75.3)
(22.0)
(208.8)
(322.2)
(5.3)
(1.4)
(157.0)
(31.0)
(247.4)
(1070.4)
Natural
Gas
357.8
74.2
302.9
1042.1
288.3
4.4
179.4
232.5
1084.3
3565.9
(339.
(70.
(287.
(987.
(273.
(4.
(170.
(220.
(1027.
(3380.
1)
3)
1)
8)
3)
2)
0)
4)
8)b
0)
Distillate
Fuel Oil
47.3
25.1
16.2
57.1
13.4
0.5
-
-
93.4
253.0
(44.8)
(23.8)
(15.4)
(54.1)
(12.7)
(0.5)
(88.5)c
(239.8)
Residual
Fuel Oil
48.0
35.4
434.4
88.7
78.9
0.3
41.1
10.1
365.5
1102.6
(45.5)
(33.6)
(411.8)
(84.1)
(74.8)
(0.3)
(39.0)
(9.6)
(346.4)
(1045.1)
Total
532.5
157.9
973.9
1527.9
386.2
6.8
386.1
275.4
1804.2
6050.7
(504.7)
(149.7)
(923.1)
(1448.2)
(366.1)
(6.4)
(366.0)
(261.0)
(1710.1)
(5735.3)
a Excludes about 0.8 x 10 kJ (0.8 quads) of wood residuals in the paper industry and about 0.3 x 10 kJ
(0.3 quads) of refinery gas in the petroleum refining industry.
May be understated by as much as 1.1 x 10 kJ (1.0 quad) in small boilers.
c 15
May be understated by as much as 0.4 x 10 kJ (0.4 quads) in small boilers.
-------
industries consumed 40 percent of industrial boiler fossil fuel con-
sumption in 1974.
Recent trends in industrial energy consumption are presented in
Table 2-7. Since 1974, natural gas consumption has declined and oil
consumption has increased. However, total fuel consumption has not
increased in the last two years.
2.4 PROJECTIONS OF INDUSTRIAL FOSSIL FUEL CONSUMPTION
2.4.1 Introduction
Sections 2.2 and 2.3 have summarized the base year data (Input 1,
Figure 1-1). This section discusses the approach for disaggregating
MEFS input totals (Input 3, Figure 1-1) by major industry group. Further
disaggregation by combustor type, size, and capacity utilization is
described in Section 3.
MEFS projects regional industrial demand for fossil fuels only for
/
two sectors, Petroleum Refining and all other industrial uses. IFCAM
disaggregates the second group into eight major industry groups:
Food
Textiles
Paper
Chemicals
Stone, Clay, and Glass (SCG)
Steel
Aluminum
Other (includes miscellaneous manufacturing, mining, and
agriculture)
2-10
-------
TABLE 2-7. ENERGY CONSUMPTION TRENDS IN THE INDUSTRIAL SECTOR0
(1015 kJ (1015 Btu))
Year
1979
1978
1977
1976
1975
1974
1974 (ECDB)
Coal
3.8 (3.6)
3.7 (3.5)
3.7 (3.5)
4.0 (3.8)
4.0 (3.8)
4.3 (4.1)
3.9 (3.7)
Natural
Gas
8.2 (7.8)
8.9 (8.4)
9.1 (8.6)
9.2 (8.7)
8.9 (8.4)
10.4 (9.9)
10.1 (9.6)C
Oil
7.8 (7.4)
7.6 (7.2)
7.5 (7.1)
6.6 (6.3)
5.8 (5.5)
6.1 (5.8)
6.5 (6.2)d
Electricity
3.1 (2.9)
3.0 (2.8)
2.8 (2.7)
2.7 (2.6)
2.4 (2.3)
2.5 (2.4)
2.5 (2.4)
Total b
23.9 (22.7)
23.1 (21.9)
23.1 (21.9)
22.6 (21.4)
21.1 (20.0)
23.4 (22.2)
23.2 (22.0)
Monthly Energy Review. Energy Information Administration, U.S. Department of Energy. Washington, D.C.
Publication No. DOE/EIA 0035/03(80). March 1980. p. 23.
Excludes wood residuals and refinery (still) gas.
Includes 1.0 quads classified as "Other" fuel in Table 2-2.
Excludes 1.4 quads of gasoline and diesel fuel classified as oil in Table 2-3 and as the transportation
sector in the DOE estimates.
-------
The first seven major industry groups account for two-thirds of total
industrial fossil fuel consumption (excluding raw material and feedstock
uses) in the MEFS all other category.
Analyzing industrial fossil fuel demand by these major industry
subgroups adds an important element of realism to IFCAM. First, pro-
duction growth rates differ significantly among industrial sectors.
Since the economics of coal use are much more favorable for new com-
bustors, those sectors with relatively high growth rates will tend to
rely more on coal. Second, the ratio of energy use in boilers compared
to process heat uses varies significantly among industries (from 74 per-
cent boiler use in food processing to 25 percent boiler use in Petroleum
Refining). Since technical problems impeding coal and residual oil use
are more severe in process heat energy uses than in boilers, industries
in which boiler energy use is predominant will tend to utilize rela-
tively more coal and oil. Third, even within the category of boiler
fuel uses, boiler sizes and operating rates differ substantially between
industries. For example, in food processing the boilers tend to be
small and operate at relatively low capacity utilization rates, while
the Paper industry is characterized by large boilers operating at high
capacity utilization rates. Other factors being equal, the tendency to
select coal will be greater in paper manufacturing than in food pro-
cessing since coal boiler economics are most attractive in large units
with high operating rates. Fourth, the potential to use coal or oil
also is substantially different among process heat uses between indus-
2-12
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trial sectors. SCG processes have significant coal potential while
process heat operations in the chemical industry are not favorable for
coal or oil use. By projecting fossil fuel demand for the nine indus-
trial classifications, these factors can be weighted appropriately to
reflect more accurately the overall industrial potential of coal or oil
over gas.
2.4.2 Fossil Fuel Projections by Industry
Energy demand projections depend on rates of production growth, the
introduction of new technologies (such as continuous casting in steel
which reduces energy consumption per ton of steel processed), shifts in
the product mix within any,specific industry (as toward more highly
processed, more energy-intensive frozen foods), fuel costs, opportunities
to install energy recovery equipment, and capital available for energy
saving measures. Business cycle fluctuations also affect energy consump-
tion per unit of product.
In the MEFS model, energy demand is driven by industrial output
growth rates and fuel prices which are input into econometric equations
based on historical relationships. The IFCAM model was specified to be
consistent with the regional energy control totals generated by MEFS.
In order to classify regional fossil fuel use by the nine industrial
sectors used in IFCAM, the following steps were taken.*
Regional industrial production growth rates for the nine sectors
were taken from the same macroeconomic model output used in the MEFS
run.
* Further details of all of the steps in this procedure are described
in Appendix D.
2-13
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> The output growth rates were adjusted for an expected reduction in
energy use per unit of output by industry (conservation effect).
» Baseline (1974) data is multiplied by the adjusted industry/region
growth rates to derive preliminary total fossil fuel consumption by
region and industry.
i The industry estimates in each region are then normalized to be
consistent with the MEFS regional totals.
This approach is identical for 1985, 1990, and 1995. As a result,
the projected industry mix can potentially be significantly different
from the historical mix. It is also possible for total expected fossil
fuel consumption in some industry and region to decrease if the conser-
vation factor (reduction in energy use per unit of production) is larger
than the industrial production growth rate or if the preliminary esti-
mates are substantially higher than the MEFS regional total and the
industry estimates must be reduced (normalized).
2-14
-------
REFERENCES
1. For a comparison of data sources, see Data Sources and Methods for
Industrial Energy Analysis. Energy and Environmental Analysis,
Inc. Arlington, Va. Publication No. DOE/ET/2344-1. August 1979.
140 p. Prepared for the U.S. Department of Energy.
2. Energy Consumption Data Base. Energy and Environmental Analysis,
Inc. Arlington, Va. June 1977. Prepared for the Federal Energy
Administration. See Appendix A for a comparison of ECDB and Bureau
of Mines data.
2-15
-------
3.x CHARACTERISTICS OF INDUSTRIAL FOSSIL FUEL USE
3.1 INTRODUCTION
To determine the portion of total projected industrial fuel demand
that may utilize alternative fuels, expected fossil fuel uses need to be
identified according to characteristics that affect the costs and technical
aspects of fuel substitution. One characteristic that affects the
technical capability to use coal or oil is the type of combustor used.
Technical issues related to fuel use differ, for example, among boilers,
cement kilns, and tubestill heaters. Characteristics that affect the
costs of using alternative fuels include combustor type, size, whether
the combustor is a new or existing unit, and capacity utilization.
Characteristics related to pollution control requirements that also
affect the costs of using alternative fuels include combustor type,
size, new/existing status, and location. Finally, many of the policy
proposals evaluated by IFCAM target particular subcategories of indus-
trial oil and gas demand. A disaggregated classification of fuel uses
allows explicit consideration of taxes, investment incentives, regulations,
and exemptions, all which vary in their impact on categories of industrial
fuel use.
This section discusses those characteristics used to classify
industrial fossil fuel uses, and explains the methodology and data bases
used in the disaggregation. The major classification steps performed
sequentially for each industry in each region include:
3-1
-------
Classifying fuel use in new combustors, in existing combustors
originally designed to fire coal, or in existing units designed
to fire only oil or natural gas
Allocating fuel demands by functional use (i.e., type of combustor)
Classifying fuel use by combustor size and capacity utilization
Allocating current natural gas and oil supplies among existing
industrial uses.
3.2 CATEGORIZATION OF FOSSIL FUEL USE BY NEW AND EXISTING FACILITIES
3.2.1 Importance of New/Existing Distinction
This distinction is critical to any analysis of fuel choice decisions
since the technical capability, the nature of the investment decision,
and the costs of using alternate fuels differ for existing units and new
facilities. Technical issues associated with coal use are typically far
more severe for an existing combustor not originally designed to fire
coal than for a new facility. For example, it is cheaper to replace an
existing boiler designed only to fire gas with a new coal-fired boiler
than to modify the gas-fired boiler to fire coal. It is possible to
retrofit (or modify) some process heaters to fire coal, but technical
problems generally are so severe that accelerated retirement of an
existing scarce fuel-fired combustor and replacement with a new coal-
fired combustor will be more economical than retrofit.
Due to varying technical problems associated with converting existing
combustors to fire coal, the investment decisions and associated costs
of fuel substitution differ among combustors. The following four classes
of combustors each involve different technical problems, costs, and
investment decisions:
3-2
-------
Existing coal-capable units: These combustors currently are
firing oil or gas but originally were designed to use coal.
Minor capital investment is needed to refurbish coal-related
equipment already available in order to return to coal use.
Pollution control equipment may be needed as well, depending
on environmental regulations.
t Existing units designed to fire only oil and/or gas that can be
retrofitted: For these combustors, it is cheaper to retrofit
an existing unit to fire coal rather than to entirely replace
the combustor with a new coal-fired unit. The elements of the
investment decision for conversion to oil or gas are similar
to those for the existing coal-capable combustor.
t Existing units designed to fire only oil and/or gas that cannot
be retrofitted economically: For this class of combustors, it
is more economic to replace an existing unit with a new coal-
fired unit than to retrofit the facility.
New facilities: For new combustors, the costs of new units
for each fuel type are compared, including total capital
investments and operating and fuel costs.
Many government policies and regulations recognize the differences
in investment approach and costs between new and existing units. Since
existing units are viewed as much more costly to convert to coal than
new units, some energy policy proposals designed to encourage the use of
coal over oil and gas target only new units. For example, PIFUA exempts
existing units with no coal firing capability from provisions mandating
conversion of industrial boiler energy use from oil and gas to coal.
The designation of fuel demands as either new or existing allows for
more careful study of proposed policies as well as proper accounting for
different investment decisions.
3.2.2 Approach to Allocation of Fuel Use Among New/Existing Facilities
Since projected fossil energy demand in any future year is an
exogenous input to the IFCAM model, the split between energy use in new
3-3
-------
facilities (i.e., for a 1985 projection, facilities coming on line
between 1975 and 1985) and existing facilities (i.e., units that existed
in 1975 and that still will consume energy in 1985) will be determined
by the exogenous growth rate in total fossil fuel demand plus the retire-
ment rate of existing facilities.
3.2.3 Determination of Normal Retirement Rates
Retirement of energy use in existing combustors can occur through
reduced capacity utilization or actions that reduce fuel use to essentially
zero, such as actual scrappage or a shift to standby status. Recent
analysis of trends in capacity utilization (see Appendix E) indicate
that there is no systematic correlation between capacity utilization and
combustor age. Consequently, this analysis defines retirement as scrapping
or placing the unit on a standby availability status.
The decision to retire a combustor is determined by many parameters.
Over time, equipment will deteriorate and require replacement. Maintenance
costs tend to increase and, depending on the type of combustor, fuel use
efficiency (e.g., for a boiler, Btu of fuel input per pound of steam
generated) may decline. Essentially random factors, such as the phaseout
of an uneconomic plant or part of an old plant's production, also can
cause a combustor to retire. In addition, the technical fuel use
efficiency and cost of new combustors will affect retirement rates.
Fuel costs, conservation potential, the availability of capital, and
other investment demands all influence retirement rates. Logically, the
decision to replace combustors depends on the economics of plant- and
corporate-specific situations.
3-4
-------
There are few useful studies of the empirical determinants of
retirement rates. The ideal set of data required to estimate retirement
rates, such as the number of combustors installed in historical time
periods, is not generally available. Thus, the retirement rates used in
IFCAM are estimated based on relevant studies.
A simple approach to estimating retirement rates for boilers would
assume a 30-year normal life in light of an historical trend in manufac-
turing energy growth of three percent per annum (1954-1971). If a
constant three percent per annum growth rate is assumed, then the rate
of retirement per year would be equivalent to two percent of each year's
energy consumption levels. In fact, however, the growth rate in energy
combustion capacity is cyclical rather than constant, and useful life is
not a constant 30 years for boilers but varies depending on the factors
discussed earlier. For example, there was a surge in new investments
during World War II as the economy geared to the war effort. Many of
these units are now 30-35 years old; the retirement rate of the existing
stock of combustors, therefore, should be higher than two percent per
year.
In a previous study, EEA used the concept of vintaging plus decay
2
factors to estimate retirement or capital turnover rates. This approach
indicated retirement rates (percent of annual energy use retired) for
boilers ranging from two to three percent.
Using the simple approach described above, which yielded two percent
per annum retirement rates, and adjusting this rate upward to allow for
3-5
-------
the cyclically high rate of manufacturing investments during the 1940's,
IFCAM uses a retirement rate of 2.5 percent per year for boilers.* This
retirement rate appears to be in the range of estimates obtained in the
EEA study using the vintaging approach.
This analysis assumes that a constant percentage of the current
capital stock is retired every period. As a result, total retirement is
a function not only of the retirement rate selected, but also of the
rate of growth of the capital stock. This approach may overstate retire-
ments during periods of high growth and understate retirements during
periods of low growth.
The calculation procedure of the total retirement of existing
boilers between 1974 and 1985 is as follows. First, total boiler fossil
fuel demand in 1985 is estimated.** Second, total boiler fossil fuel
demand in every year between 1974 and 1985 is estimated by using the
compound average annual growth rate. Third, the retirement rate (2.5
percent) is applied to the total estimated boiler fossil fuel consumption
in 1975, 1976, .... 1985 in order to determine the total amount of
boiler fossil fuel demand to be retired in the 1974-1985 period.
Coal consumption in industrial boilers existing in 1974 is retired
at one percent annually. This approach insures that existing coal
boilers will be retired at a lower rate than existing oil/gas boilers.
* The 2.5 percent retirement rate for boilers is equivalent to a 40-year
useful life for stable capital stock.
** See Section 3.3.2.
3-6
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In addition, old oil/gas boilers* in the MFBI are also retired. The
remaining amount of oil and gas consumption in industrial boilers to be
retired is the difference between the total amount of fossil fuel consump-
tion to be retired and the total amount of oil and gas (in old boilers)
and coal retired. This remaining amount of oil and gas consumption to
be retired is allocated proportionately across the remaining oil and gas
consumption in industrial boilers in 1974.
Even when determining such "ballpark" replacement rates, it is
important to distinguish among major industrial processes. Process
combustor service lives vary substantially among industries and, to a
lesser extent, within industries. For example, in the glass industry,
regenerative furnaces have average useful lives of five to seven years;
unit melters last only three to five years. In the steel industry,
units used in some processes (e.g., blast furnace hydrocarbon injection
and traveling grate pelletizers) last up to 50 years. The range of
nonboiler service lives is so large among industries that retirement
rates in this analysis are industry-specific. Table 3-1 displays the
retirement rate used for each industry group.
3.2.4 Caveats and Issues
The retirement rates used in IFCAM are based on reasonable judgments
in the context of limited available data and related studies. There is
no question that the normal retirement rate is a critical element in
Boilers installed before 1945.
3-7
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TABLE 3-1. NORMAL RETIREMENT RATES FOR PROCESS HEAT USES3
(percent of annual energy use retired)
Industry Retirement rate
Food
Textiles
Paper
Chemicals
Petroleum Refining
Stone, Clay and Glass
Steel
Aluminum
Otherb
4.7
4.2
3.4
2.0
1.9
4.0
1.7
3.9
3.6
Retirement rates were derived by taking the normal
service life of the major process heat uses in each
industry sector and using the reciprocal of that
useful life as the annual replacement rate.
Includes miscellaneous manufacturing, agriculture,
and mining. See Table 2-5.
3-8
-------
fuel choice decisions since the technical issues and associated economics
tend to strongly discourage coal use in existing combustors not originally
designed to fire coal. There is a bias against retrofitting from one
fuel to another since no capital investment is necessary to continue to
fire the existing fuel. The retirement rates used in IFCAM are reasonable,
but further work in this area using a solid empirical base is necessary.
One factor worth emphasizing is that EEA's approach to estimating
retirement rates does not consider the effect of rising fuel costs or
energy policy on the overall efficiency of energy use in existing combustors,
For example, taxes on fuel use affecting existing combustors will conserve
energy because higher fuel costs will promote efforts to increase the
efficiency of existing units; this energy conservation, however, will
not be captured by retirement rates based on historical trends. The
failure of IFCAM to consider the impact of energy policy or fuel prices
on overall energy efficiency in existing units will tend to bias fuel
mix results away from coal. This bias occurs because the projected year
fossil energy demand (exogenous to IFCAM) does include the effect of
higher fuel prices, for example, on overall fuel use efficiency. Since
IFCAM ignores this conservation effect in determining normal retirement
rates, conservation benefits come entirely out of fuel use in new combustors.
This bias can be seen in Table 3-2 by comparing two scenarios of
fossil fuel demand input to IFCAM. In the base case scenario, adjustment
for normal retirements results in fuel use of 70 units in existing
combustors and 80 units in new combustors, a total demand of 150 units.
3-9
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TABLE 3-2. ILLUSTRATION OF BIAS INTRODUCED BY
ENERGY CONSERVATION POLICIES
Scenario 1:
base case
Scenario 2:
higher fuel prices
or conservation
policy measures
Fuel use in existing
combustors in 1975
Less normal retirements
Fuel use in existing com-
bustors in projection year
Total projected fossil fuel
use in projection year
Fuel use in projection year in:
- existing ccmbustors
- new combustors
- all combustors
100
30
70
150
70
80
150
100
30
70
140
70
70
140
3-10
-------
In scenario 2, higher fuel prices or conservation policy estimates
reduce aggregate fossil fuel demand from 150 to 140 units. Since normal
retirements are not adjusted to capture this conservation effect, all
the conservation implicitly takes place in new combustors. Since coal
use is relatively more economic in new units, this approach tends to
understate the estimate of coal use generated by IFCAM in scenarios with
higher fuel prices or conservation policy measures.
3.3 CATEGORIZATION OF FOSSIL FUELS BY FUNCTIONAL USE
3.3.1 Approach
Classifying fossil fuels by functional use is critical because the
technical and economic issues of fuel substitution vary according to
specific process applications. To categorize fossil fuels by functional
use, projected energy consumption for each region and industry first is
split into two functional use classes: boilers and process heaters.
Boilers use fossil fuels to produce process steam and internally generated
electricity.* Boilers consume more oil and gas than any other single
industrial consumption process. Process heat applications include
furnaces, ovens, kilns, and heaters and exclude all boiler and feedstock
uses.
Although types of boilers (combustor size and capacity utilization)
vary among industrial sectors, issues related to costs or the technical
capability to utilize alternative fuels are generic for each boiler of
* Cogeneration is not a model feature. As a result, IFCAM may under-
state projections of fossil fuel demand in industrial boilers.
3-11
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the same size operating at the same capacity utilization rate. Process
heaters, however, must be evaluated according to specific applications
since costs and technical problems differ, for example, among tubestill
heaters used in crude distillation in petroleum refining, tubestill
heaters used in catalytic cracking in petroleum refining, and reheat
furnaces used in the manufacture of steel and nonferrous metals. Conse-
quently, fossil fuel demand must be classified by functional use in two
steps. First, fuel use is split between boilers and process heaters.
Second, within each industry, fossil fuel use is classified into major
process heat uses.
3.3.2 Allocation of Projected Fossil Fuel Use Among Boiler and Nonboiler
Categories by Industry
For each region and industry, projected total fossil fuel consumption
is split between two classes: boilers and process heaters. The breakdown
is based on 1974 data from the ECDB. Currently, coal is used primarily
in boilers; cement kilns are the exception. For most of the industries
shown, the difference in boiler/nonboiler splits between oil and gas use
is slight. When differences exist, there are no obvious technical or
economic reasons for a particular industry to prefer oil to gas, or vice
versa. The discrepancies between the functional use splits for each
fuel are smaller than the level of probable error associated with ECDB
functional use data. Consequently, the split between the two major
functional uses is based on the sum of historical coal, oil, and gas
consumption in each industry. The focus on total fossil fuels, rather
than on coal, oil, and gas separately, seems warranted since the ratio
3-12
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of coal to oil to gas in the future is expected to differ substantially
from historical patterns. Consequently, the classification by functional
use and new/existing combustors is made first only for total fossil
scarce fuels, leaving the specific allocation of fossil fuel demands by
fuel type to a later step in the classification process.
National functional use shares for fossil fuels by industry are
shown in Table 3-3. Based on fuel use, major industry groups generally
can be disaggregated into predominantly boiler or nonboiler industries.
The industries predominantly using boilers are Food, Textiles, and
Paper, while nonboiler industries are Petroleum Refining, SCG, and
Steel. Aluminum, Chemicals, and "Other" industries use approximately an
equal mix of boiler and process heat fuel.
The boiler industries can be classified further as industries using
small boilers (e.g., Food and Textiles) or industries using large boilers
(e.g., Paper and Chemical Manufacturing). In the Food industry, process
steam is used primarily for washing and sterilizing containers, cooking,
evaporating, space heating, and electricity generation. The Textile
industry relies heavily on purchased electricity to drive the machinery
in the plants; fuel oil and natural gas are used predominantly in this
industry in boilers. In this industry, process steam also is used for
fabric preparation, dyeing, and finishing operations as well as space
heating. Very little electricity is generated in textile mills.
The large-boiler industries, Paper and Chemical Manufacturing, use
a significant portion of total steam demand to generate electricity. In
3-13
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TABLE 3-3. DISTRIBUTION OF FOSSIL FUELS BETWEEN BOILER AND
PROCESS HEAT USES IN 1974a
Industry
Food
Texti 1 es
Paper
Chemicals
Petroleum Refining
Stone, Clay and Glass
Steel
Aluminum
Other0
Boiler
74
80
81
65
25
_b
33
55
44
Process heat
26
20
19
35
75
99
67
45
56
aCompare Tables 2-4 and 2-6.
Less than 1 percent.
clncludes miscellaneous manufacturing, agriculture, and mining.
See Table 2-5.
3-14
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Chemical Manufacturing, process steam demand is used to strip away
unreacted feed, as dilution steam, and to drive steam compressors. The
process fuel uses are primarily in cracking furnaces. Process steam in
the Paper industry is used to generate electricity and in the pulping
and bleaching processes. Some systems also use steam in debarking.
Process uses of scarce fuels in the Petroleum Refining industry are
in tubestill heaters or furnaces. In Steel manufacture, blast furnaces,
soaking pits, reheat furnaces, and heat treating applications are the
primary process uses. SCG fuel use is dominated by cement production
which uses process heat in cement kilns. Glass production comprises the
other significant portion of SCG, with glass furnaces as the primary
energy user.
Aluminum is a large electricity producer and the bulk of the boiler
use in that industry is consumed to self-generate electricity. The rest
of the fuel, roughly half, is consumed in direct heat applications.
3.3.3 Allocation of Nonboiler Fuel Use Among Processes
Fossil fuel use in process heat applications for each region and
industry includes fuel consumed in many distinct processes. The share
of fossil fuels consumed by each type of process within an industry
3
group was derived from a recent study of industrial energy use. These
shares essentially reflect current energy use by process. No systematic
effort was made to project carefully changes in the relative shares of
fossil fuels among process applications within all industries. The
historical shares generally were assumed to hold for both new and existing
facilities in all regions for each industry.
3-15
-------
These shares of fuel consumption use were adjusted roughly to
account for major trends that shift the process mix for three industries:
Petroleum Refining, Steel, and Aluminum.. In Petroleum Refining and
Steel, two processes currently using oil and gas (thermal cracking and
open hearth smelting) are not expected to be installed in any new facility.
This trend was accounted for by setting scarce fuel uses in these two
processes equal to zero for new facilities only and normalizing the re-
maining process use shares to equal 100 percent. Adjustments also were
made to account for differences in the shares of fuel use by process and
region for steel and aluminum, industries in which certain processes are
located in only a few regions. For example, 75 percent of the primary
steel industry is located in the Great Lakes region close to major
deposits of iron ore and supplies of coking coal. In these regions,
scarce fuels are used in integrated steel mills. Outside these regions,
the process mix was adjusted to reflect the absence of consumption in
beneficiation, blast furnaces, and steel-making furnaces.
3.3.4 'Problems and Biases
The major weakness of this method of allocating scarce fuel consump-
tion by functional use among combustor types is that it relies on historical
patterns except when differences in process mix by region or for new/
existing facilities are critical. While a careful study of the future
shifts in the relative importance of various industrial processes would
improve the accuracy of forecasts, the current approach employed should
reflect accurately key shifts in relative energy use among industries
and the volume of energy used in new versus existing facilities.
3-16
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3.4 CLASSIFICATION OF FUEL USE BY SIZE AND CAPACITY UTILIZATION
3.4.1 Introduction
The size and capacity utilization of a combustor greatly affect
fuel choice decisions. Combustor size is important for several reasons.
First, combustor costs are characterized by economies of scale and these
directly affect the economics of -fuel choice decisions. Second, pollution
control strategies, often involving substantial capital and operating
costs, vary by size. Third, environmental regulations, both State and
Federal, often specify levels of air pollution control by combustor
size. Fourth, recent Federal energy tax policies, investment incentives,
and regulatory proposals have targeted industrial combustors of specific
size ranges. To capture these implications of combustor size on fuel
choice decisions, IFCAM'disaggregates fuel demand into several size
categories.
The capacity utilization of a combustor is also a critical parameter
in the economics of fuel choice decisions. A capacity utilization rate
represents the total Btu actually burned in a combustor during a year
divided by the maximum Btu that could be burned, assuming a fixed design
firing rate of the combustor and 8,760 hours of operation per year. A
high capacity utilization rate gives certain capital intensive technologies
(with large economies of scale) a competitive edge.
3.4.2 Combustor Size
Fuel use is allocated into seven size classes for boilers and a
variety of sizes appropriate to specific process heat uses. Distribution
3-17
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of fuel use by size is treated differently for boilers and process
heaters, and for new versus existing combustors.
3.4.2.1 Boilers
There are seven standard sizes for new boilers in IFCAM. Table 3-4
summarizes key assumptions in each boiler size class. Costs and emission
rates vary significantly by boiler type and firing method.
The following lists major data sources on boiler size:
Sales data for new orders collected by the American Boiler
Manufacturers Association (ABMA)
DOE's Major Fuel Burning Installation (MFBI) survey*
EPA's National Emissions Data System (NEDS)
A recent report on the current boiler inventory prepared by
PEDCo Environmental, Inc.
ABMA has collected sales data for the last 15 years. MFBI data is
limited to large boilers existing in 1974 with firing rates of over 99
MMBtu/hr. The NEDS data base includes information from about 34,000
facilities. The PEDCo report used these data sources and other reports
to estimate the 1977 industrial/commercial boiler capacity.
The distribution of boiler sizes varies significantly by industry.
Size distributions for new industrial boilers have been developed for
each major industry group. NEDS data by major industry group was normal-
ized to be consistent with the aggregate PEDCo report size distribution.**
ABMA data were not used because these data contain relatively few records
for several industries.
* See Appendix B.
** See Appendix E for a complete discussion.
3-18
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TABLE 3-4. IFCAM BOILER SIZE/TYPE ASSUMPTIONS
Boiler Size Category
MW (MMBtu/hr)
Type
Representative
Range Size Coal
2.93-8.79
(10-30)
8.79-14.65
(30-50)
14.65-21.98
(50-75)
21.98-29.3
(75-100)
29.3-51.28
(100-175)
51.28-73.25
(175-250)
>73.25
(>250)
5.86
(20)
11.72
(40)
18.17
(62)
25.49
(87)
40.14
(137)
62.12
(212)
95.23
(325)
package,
watertube,
underfeed
stoker
package,
watertube,
underfeed
stoker
field-erected,
watertube,
chain grate
stoker
field-erected,
watertube,
spreader stoker
field-erected
watertube,
spreader stoker
field-erected,
watertube,
pulverized
coal
field-erected,
watertube,
pulverized <^oal
Residual Oil/
Natural Gas
package,
firetube
package,
watertube
package,
watertube,
package,
watertube
package,
watertube
two package
watertube
two package,
watertube
Distillate Oil/
Natural Gas
package
firetube
package,
watertube
package,
watertube
package,
watertube
package,
watertube
two package,
watertube
two package,
watertube
Chain grate stoker emission rates with spreader stoker capital and O&M
cost estimates.
3-19
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This methodology assumes that, over the long-term, future new
boiler sales will reflect the current size distribution. Changes in
energy and environmental regulatory policies, process changes and economics,
however, may change substantially the future boiler size distribution.
Aggregate data on large existing units have been collected from the
MFBI file. Coal, oil, and gas consumption in boilers greater than 99
MMBtu/hr (29 MW) and existing in 1974 have been identified by location
(AQCR), firing capability by fuel type, industry, and size class [100-250
MMBtu/hr (29-73 MW) and greater than 250 MMBtu/hr (73 MW)]. Fossil fuel
consumption in smaller existing units is not covered by the MFBI file,
and NEDS data does not include 1974 data for all combustors. Therefore,
fuel consumption in smaller units was estimated by fuel type, region,
and industry as a residual ~ aggregate ECDB fuel consumption in boilers
less aggregate MFBI fuel consumption in boilers.
3.4.2.2 Process Heaters
There are no comparable data sources available to determine the
distribution of fuel use by size in process heat applications. A systematic
collection of such data was beyond the scope of this effort; conse-
quently, a distribution of fuel use by combustor size was developed
based on judgments by EEA staff familiar with these industries and on
comments provided by industry representatives. The MFBI survey contains
size data for large process heaters, but because process definitions
were so difficult to relate to the MFBI questionnaire responses and
since a much larger share of process heat fuel use is in units below
3-20
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100 HMBtu/hr (29 MW), the MFBI data were not used. The size distribution
for process heaters was assumed to be the same for new and existing
combustors. Size classes for each process are presented in Appendix G.
3.4.3 Capacity Utilization
The capacity utilization rate of combustors is a major factor
affecting the economics of investment decisions. IFCAM in its present '
form can accept any distribution of capacity utilization as a function
of industry, combustor type, size, and new/existing status. There are
some consistency issues regarding the use of historical data on capacity
utilization as a surrogate for the distribution of boilers installed in
the future. However, there is neither sufficient, conclusive knowledge
of the factors that influence capacity utilization rates nor information
on the trends to develop a definitive structure of this distribution.
The current distribution of capacity utilization rates in the model
reflects historical data. Like the size distribution, this also does
not vary with time.
The next two subsections discuss EEA's approach in developing the
capacity utilization distribution for combustors, the factors that
affect capacity utilization rates, and some biases of the methodology.
3.4.3.1 Approach
Three distributions were developed for the three combustor classes:
existing boilers, new boilers, and process heaters. MFBI data were used
to create the existing large boiler distribution. NEDS data were used
3-21
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to structure new boiler distribution,* and in-house engineering analysis
was used to form the distribution of process heaters.
For large existing boilers with a firing rate of 100 MMBtu/hr or
more, five capacity utilization classes were created for each boiler
size category. Units with rates between zero and 30 percent were assigned
a capacity utilization rate of 25 percent. Units with rates between 30
and 50 percent were rated at 45 percent, units between 50 and 60 percent
at 55 percent, units between 60 and 70 percent at 65 percent, and units
above 70 percent were given a capacity utilization rate of 75 percent.
These data were derived from the MFBI file. For existing boilers smaller
than 100 MMBtu/hr, a unimodal capacity utilization distribution was
assumed. This distribution can be disaggregated further if programs
that specifically target the existing boiler market are proposed; in the
meantime the unimodal distribution is a satisfactory approximation.
For new boilers, the NEDS data base was used to develop the capacity
utilization distribution. Five capacity utilization rate classes were
also used. Refer to Appendix E for a more detailed description of the
capacity utilization distribution for new boilers.
Very little data exist on capacity utilization rates of process
heat uses; consequently, a single capacity utilization rate is assumed
for each specific process. These rates are subjective estimates based
primarily on in-house industry knowledge. In general, capacity utiliza-
tion rates tend to be systematically higher for process heater than for
See Appendix E for a complete discussion.
3-22
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boilers. Appendix G provides details of capacity utilization rates by
process.
3.4.3.2 Summary and Caveats
There are a number of factors that might affect the capacity utili-
zation rates of combustors. A partial list of these factors is given
below:
Economics of operation
Industry group
Functional use
New/existing distinction
Size
Age
Fuel type/price
Plant capacity in relation to annual steam demand.
Statistical analyses of the MFBI file indicate that capacity utilization
is affected by variables considered in IFCAM (industry and size) as well
as other variables not included in the model. However, plant-specific
situations may contribute more to variability than do generic factors.
Unique steam load characteristics (peak demand, seasonal fluctuations),
boiler mix, and excess capacity, for example, are important parameters
affecting capacity utilization. Different boiler types have unique
turndown and start-up capabilities and can influence plant engineers'
judgments.
Ideally, the size/capacity utilization distribution would be contin-
uous. Use of a discrete distribution with several size/capacity utilization
3-23
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rate categories captures the relevant trends and does not introduce a
significant bias in the results. There are, on the other hand, certain
rigidities in this distribution that may generate some bias. The distri-
bution is based on historical data and does not change over time.
Subsequently, it may not capture any trends toward certain sizes or
capacity utilization rates. The distribution is also not a direct
function of fuel type and thus cannot capture any correlation that may
exist. The data is collected on a national level and is applied uniformly
to all regions. In the absence of definitive studies on these issues,
using a historical national distribution for this modeling exercise is
an appropriate alternative.
An example of the variation of the size/capacity utilization distri-
bution of new boilers for two industries is illustrated in Table 3-5.
Most energy use in the food processing industry is in small capacity
utilization categories (25 and 45 percent); most of the fuel use in the
energy-intensive Petroleum Refining industry is in the higher capacity
utilization categories (65 and 75 percent). For further details on the
size/capacity utilization distribution, see Appendix E.
3.5 ALLOCATING FUEL DEMANDS BETWEEN GAS AND OIL IN EXISTING COMBUSTORS
3.5.1 Introduction.
The previous steps have classified fuel use for each region and
industry by functional use, new versus existing combustors, size, and
capacity utilization. Total fuel use in existing combustors must be
allocated by fuel type. New units' fuel use is determined by the invest-
ment decision in the model; existing coal use is assumed to remain coal
3-24
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TABLE 3-5. SAMPLE SIZE/CAPACITY UTILIZATION DISTRIBUTION OF NEW BOILERS FOR TWO INDUSTRIES .
CO
I
ro
en
Food Processing
Capacity
Size Class Utilization
MW (MMBtu/hr) Rate (%)
2.9-14.7 (10-50) 25
45
75
14.7-29.3 (50-100) 25
45
29.3-73.3 (100-250) 25
75
>73.3 (>250) 25
r r
OU
% of Total
Industry Boiler
Fuel Use
*
15.3
6.4
13.1
11.7
4.7
17.8
10.1
6.0
14.9
Petroleum Refining
Capacity
Size Class Utilization
MW (MMBtu/hr) Rate (%)
2.9-14.7 (10-50) 25
65
75
14.7-29.3 (50-100) 45
75
29.3-73.3 (100-250) 25
75
>73.3 (>250) 25
75
% of Total
Industrial Boiler
Fuel Use
6.6
7.3
17.4
3.8
14.8
4.3
15.3
8.6
21.9
Several size clases have been aggregated in this table to emphasize the differences in the two industries.
-------
in the future. Existing non-coal fuel use initially must be allocated
among gas, residual oil, and distillate oil. This allocation is necessary
in order to determine the current fuel type in retrofit decisions for
substituting one fuel with another. For example, if a combustor current-
ly is firing oil, equipment required for oil fuel handling and storage
already will exist. For a unit currently firing only gas, the above
equipment must be installed prior to conversion to oil firing capability.
When possible, this allocation is determined by actual fuel use in the
combustor; when such data are not available, other methods of allocation
are used. To define these different methods, three types of combustors
are examined: large existing boilers,, small existing boilers, and
existing process heat uses.
3.5.2 Fuel Type for Large Existing Boilers
Oil and gas use in boilers with a firing rate greater than 100
MMBtu/hr are derived directly from MFBI data, which detail the fuel use
capability of each boiler. Units burning oil or gas in 1974 are assumed
to continue to do so until a decision to retrofit to an alternative fuel
is made in the model.
3.5.3 Fuel Type for Small Existing Boilers
Explicit, disaggregated data on fuel use in boilers with a firing
rate less than 100 MMBtu/hr generally are not available.* To determine
distributions of fuel use by fuel type, region, and industry, 1974 ECDB
* DOE will distribute a new survey form to collect 1979 data for boilers
and process heaters larger than 50 MMBtu/hr later this year.
3-26
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data were used. Oil and gas totals from the ECDB were reduced by fuel
use accounted for by combustors covered by the MFBI file; ECDB fuel use
already had been separated by functional use. The resulting distribution
of natural gas, distillate oil, and residual oil fuel use is applied to
existing boiler fuel use totals not yet allocated.
The potential for bias in this method depends on two factors: the
accuracy of the ECBD data and the completeness of the MFBI file coverage
of large boilers (see Appendices A and B for further details). Large
boilers not captured in the MFBI file will be placed in a smaller size
category (fuel use for a 100 MMBtu/hr boiler not covered by MFBI data
might be assumed to be divided between two 50 MMBtu/hr units).
3.5.4 Fuel Type for Existing Process Heat Applications
Explicit data are not available on fuel use in process heat appli-
cations. In addition, unlike boilers that can be designed to fire gas,
oil, or coal, some processes must, for technical reasons, burn gas,
while others are restricted to gas and distillate oil. The former
processes must be given priority in the allocation of scarce gas supplies.
To account for these priority uses of gas in existing process
heaters, an allocation scheme was developed. For each process heat
application, an in-house estimate was made determining the percent of
fuel used in that process that had to be gas. For some processes, such
as blast furnaces, no gas use is required; other processes, such as
pyrolytic furnaces in the chemical industry, are believed to use only
gas in existing units.
3-27
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Total gas use, by region and industry, was derived from the ECDB.
For each region, the gas total is allocated among processes, giving
priority to those that can only use gas. If any gas remains after this
allocation, it is distributed among the lower priority users in proportion
to total fuel use by process. The remaining fuel use of these other
processes is allocated to residual and distillate fuel oil. Allocation
of residual oil is limited only to those processes in which residual oil
use is technically feasible.
3-28
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REFERENCES
1. Energy Conservation in the Manufacturing Sector, 1954-1990. Energy
and Environmental Analysis, Inc. Arlington, Va. Prepared for the
Council on Environmental Quality. Published by the Federal Energy
Administration Project Independence Blueprint Interagency Task
Force on Energy Conservation. November 1974.
2. Industrial Sector Technology Use Model (ISTUM): Industrial Energy
Use in the United States, 1974-2000. Energy and Environmental
Analysis, Inc. Arlington, Va. Prepared for U.S. Department of
Energy. Publication No. DOE/FE/2344-1. October 1979. pp. IV-101
to IV-114 and VI-26 to VI-33.
3. The Technical Feasibility of Coal Use in Industrial Process Heat
Applications. Energy and Environmental Analysis, Inc. Arlington,
Va. Draft report prepared for the Office of Policy and Evaluation,
U.S. Department of Energy. May 1978. 353 p.
4. Devitt, T., P. Spaite, and L Gibbs. Population and Characteristics
of Industrial/Commercial Boilers in the U.S. PEDCo Environmental,
Inc. Cincinnati, Ohio. Prepared for the Industrial Environmental
Research Laboratory, U.S. Environmental Protection Agency. Publica-
tion No. EPA-600/7-79-178a. August 1979. 462p.
5. Industrial Fuel Choice Analysis Model. Volume II. Appendices to
Model Documentation. Energy and Environmental Analysis, Inc.
Arlington, Va. Appendix F. Draft report prepared for the Office
of Policy and Evaluation, U.S. Department of Energy. January 1979.
3-29
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4. TECHNICAL AND OTHER CONSTRAINTS TO FUEL SUBSTITUTION
4.1 INTRODUCTION
Sections 2 and 3 describe how industrial demand for coal, oil, and
gas is classified by industry, new/existing combustor, functional use
(combustor type), size, and capacity utilization. In this section,
industrial fuel demand is screened to identify fuel choice options that
clearly are not feasible due to technical constraints, timing consider-
ations, or broad economic factors. For any investment decision, only
those fuels not limited by constraints will be allowed to compete in the
economic test.
This screening process considers four factors that would limit the
potential to substitute certain fuels for others during 1985-1995. The
first factor is the technical capability to use coal or oil. If the use
of either of these fuels would contaminate products (such as indirect
heat applications in food processing) or lead to equipment failure or
safety hazards, then certain energy uses are precluded from selecting
these fuels.
A second consideration related to the technical capability to
utilize oil or coal is the lead time required for introducing new tech-
nologies not considered proven by industry. This is an important factor
since coal is proven in boilers and in only a few process heat applica-
tions such as cement and lime kilns. Lead times for developing and
4-1
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testing new equipment configurations designed for coal firing may preclude
from coal use new combustors scheduled to come on line prior to the
commercial availability of coal-using equipment.
The third factor also relates to timing and applies only in 1985.
Some fuel choice decisions already have been made; these decisions
involve both new combustors already installed by 1978 plus commitments
made for orders of new combustors coming on line in the next few years.
In evaluating fuel choice for new energy uses coming on line between
1975 and 1985, these decisions, based on past or current economics of
fuel choice, must be considered.
The fourth factor used to screen the potential for fuel substitution
is the general economic considerations that effectively prohibit coal or
oil use in certain applications. It is possible to prejudge that oil or
coal use will not be economically feasible in some applications; these
processes are discussed below.
In addition to the above constraints, other potential constraints
on coal and oil substitution not explicitly incorporated into the model
logic are discussed below. Whether these factors, which are supply-
related (e.g., equipment availability), will constrain coal or oil use
depends on the magnitude of coal and oil demands generated by the model.
Since the effect of these screening factors differs substantially for
boilers and process heaters, these two combustor types are discussed
separately.
4-2
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4.2 BOILERS
4.2.1 Technical Feasibility
A boiler is a container in which water is evaporated continuously
into steam by the application of heat. Hot combustion products heat
water in tubes (watertube) or pass through tubes to heat water in a
vessel (firetube). Boilers are distinguished by size (capacity, or
pounds of steam produced per hour; or firing rate, MMBtu consumed per
hour), operating pressure and temperature, fuel type, firing method, and
whether they are shop-assembled at the factory (package) or field-erected
onsite. Boilers generate steam for process uses or space heating and
electricity generation. Coal, gas, and oil use in boilers is a proven
technology. Steam quality generally is unaffected by fuel type, although
there are small differences in boiler efficiencies related to fuel type
and firing method.
Boilers over 30 MMBtu/hr are primarily watertube boilers consisting
of a drum with a multiplicity of tubes in which a water-steam mixture
circulates. The watertube design is ideal for burning coal as well as
conventional oil and gas.
Smaller boilers (under 30 MMBtu/hr) are primarily firetube boilers.
Firetube boilers have a drum containg water and pass hot combustion
products through tubes within the boiler shell. In the United States,
package firetubes are primarily oil- or gas-fired.
Existing boilers can be retrofitted to burn oil or gas; they can be
converted to coal either by reconverting units originally designed to
4-3
-------
fire coal or by accelerating replacement of existing units that never
fired coal; conversion to any other fuel involves retrofitting the
boiler. Retrofitting, for coal use, oil/natural gas boilers that never
were designed to burn coal is impractical for two reasons. First,
boiler capacity must be downrated substantially (20 to 60 percent less
than original design capacity) and second, necessary modifications to
existing equipment may be physically impossible.
The primary constraint to boiler modification is combustion volume.
Significantly more combustion volume is required for burning coal than
for burning oil or gas to insure that the flue gas temperature at the
entrance to the boiler covective section is below coal's ash-softening
point. Coal firing also requires additional burnout time to permit more
heat absorption in the radiant (waterwall) section. If it is physically
impossible or economically impractical to enlarge the furnace area,
boiler capacity must be downrated substantially.
Other boiler constraints to coal conversion are convective section
and air preheater redesign and the addition of sootblowers and fans.
Due to these technical problems, converting units not originally designed
to burn coal to coal firing is assumed infeasible unless the boiler is
replaced.
4.3 PROCESS HEATERS
4.3.1 Issues
Direct coal use is a proven technology for only a small portion of
current consumption of gaseous and oil fuels in process heat equipment
4-4
-------
o
(including retrofitting existing equipment and in new equipment).
Proven coal technologies exist primarily in cement and lime processing.
Use of residual oil is less of a problem than coal use in most processes;
3
the few exceptions include uses in food, textile, and glass processes.
When coal substitution is technically feasible, coal use may be
hindered by a lack of successfully demonstrated and commercially available
equipment and more cost-effective equipment used by other fuels. Capital
investment decisions and safety and business risks also determine if a
process application will be shifted from gaseous fuels to coal or oil.
Business risks include the possibilities of equipment failure and loss
of productive capacity or diminished product quality.
Technical capability was evaluated only for direct coal firing in
process heaters. Other alternatives that could increase reliance on
coal include shifts from fossil fuels to electricity, process changes
such as shifting from direct to indirect firing, or technologies that
convert coal into oil. The option to electrify rather than use fossil
fuels is addressed explicitly in the MEFS model used to generate fossil
fuel demand inputs into IFCAM. To the extent that process changes or
coal-to-oil conversion technologies have similar applicability, lead
time, and costs as the direct-fired options in IFCAM, the estimates of
coal use in process heaters generated by IFCAM would be as accurate as
current data allow. EEA has run one of its other models that includes
the coal conversion technologies to obtain rough estimates of additional
A
coal use from technology options not evaluated in IFCAM.
4-5
-------
4.3.2 Technical Feasibility
Specific factors limiting the technical feasibility of coal or
residual oil use in process heat applications include:
Burner size
Heat distribution requirements
Fuel contaminants.
In evaluating the technical potential of fuel substitution for each
industrial process, new and retrofit units are disaggregated. This
distinction was adopted because several existing process uses gradually
are being phased out of production and replaced by newer, more efficient
processes and because some coal and oil use applications feasible in new
uses cannot be retrofit into existing facilities. These constraints
vary by different equipment configurations and by product process. As a
result, each major energy-using process must be analyzed separately to
determine the technical feasibility and risks associated with direct
coal or oil use. The following subsections describe process heat equip-
ment characteristics and the major technical coal or oil substitution
problems.
4.3.2.1 Process Heat Equipment Characteristics
Process heat equipment includes a furnace and auxiliary equipment
that deliver heat energy to a product to raise its temperature for
further processing or to cause a product transformation, including
chemical reactions, physical changes in the crystalline structure, and
phase changes (e.g., melting, evaporation). In direct-fired applications,
4-6
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combustion products can contact the material being processed. In indirect
firing, a solid barrier separates the flame from the material.
Equipment sizes vary and are measured in terms of heat released,
fuel consumed, or quantity of product processed. Processing can be
continuous or batch jobs. Process heaters also are distinguished by the
various ways products are transported through them. Fluid products
generally are conveyed through tubes (as in a tubestill heater in Petroleum
Refining and Chemical Industries) in a continuous process. Solid products
may be moved mechanically or the furnace may move around the product.
Operating temperatures and heat distribution patterns also characterize
process heat equipment. In the following subsections, specific technical
problems of coal firing are discussed. Although many of these problems
also occur when firing with residual oil, they are minor; coal firing
greatly increases the severity of these technical constraints.
4.3.2.2 Coal Flame Characteristics and Burner Design
The coal flame is long, highly radiant, and slow burning. Since
coal particles continue to burn in suspension, combustion may not be
complete by the time the flame has traveled the length of the furnace.
Flame impingement on furnace walls prior to complete combustion can
cause slags to develop as the coal particles fuse and accumulate. Flame
length and impingement can be controlled to a degree by burner design
and positioning. Burners designed to project the coal in a swirling or
cyclonic motion force the coal to spray in a wide pattern, thereby
reducing the projection of the flame. However, reproduction of a short,
sharp, gas-like flame is extremely difficult..
4-7
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Burner size is an important parameter because some processes require
a well-defined flame pattern and cannot tolerate local over-heating;
these requirements may restrict the combustion of solid fuels to larger
burners in some processes. In other applications, combustion need only
be completed by the time flue gases leave the firebox or before they
reach the stack. Coal creates problems because its combustion time is
longer then that for oil or gaseous fuels and its flame maintenance is
more complex. If short, turbulent flames are not required (e.g., in
cement and lime production), then burner size limitations do not constrain
coal use.
The excess air requirement for coal combustion is higher than that
for gas. Consequently, furnace volume and draft must be greater to
assure complete combustion. Furnace volume increases also can result
from the need to accommodate the length of the coal flame. In some
applications, additional combustion air has to be supplied.
4.3.2.3 Heat Distribution
Heat distribution often is very important. Some processes require
a uniform temperature while others maintain uneven but controlled,
temperature variations. In multiple burner applications, accurate fuel
delivery is essential to maintain proper heat configurations. The heat
released from an individual coal burner cannot be held constant because
coal is a heterogeneous mixture, and the coal delivery system cannot
adequately control the amount of fuel delivered due to variable coal
particle sizes. Even if a relatively constant fuel feed rate could be
4-8
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attained, heat input would not be constant because coal Btu content
varies, resulting in swings of chemical heat input into the burner.
Conventional technology for firing coal, therefore, has a limited
ability to respond quickly and accurately to furnace temperature fluc-
tuations with an immediate fuel input response. Delivery of coal to the
burner is more difficult than delivery of liquid or gaseous fuels.
Special handling systems are required to grind and meter the coal properly
prior to firing; such systems are not necessary for natural gas or oil.
Although coal delivery systems have been developed recently to meter
pulverized coal to as many as 150 burners with adequate accuracy and
control, these systems are costly.
4.3.2.4 Fuel Contaminants
Fuel contaminants can impair product quality, accelerate furnace
wear, or plug furnace passages. The product can be deteriorated by
contaminants resting on or chemically combining with it. Furnace wear
is caused by corrosion, erosion, and fluxing.* These adverse effects
tend to increase costs, require earlier equipment replacement, and can
affect equipment safety or reliability.
Contaminants that most frequently affect solid fuel firing in
furnaces are sulfur, vanadium, and ash. The sulfur content of coal
varies between 0.6 and five percent and the ash content ranges from four
*Fluxing is the combining of a new component with a solid to lower the
melting point (e.g., salt and ice). Constituents of coal ash have this
effect on some refractories.
4-9
-------
to 20 percent of the fuel by volume. Vanadium and sulfur oxidize during
combustion to form vanadium oxide, which spalls (deteriorates) refractories,
corrodes metal surfaces (especially at furnace temperatures above 1000°F),
and reduces furnace life. S02 corrodes metal at higher temperatures and
also presents an emissions problem.
Coal combustion produces an ash consisting primarily of silica,
alumina, iron oxide, and calcium oxide. This ash can contaminate products
through either simple contact with the product or a chemical reaction.
Product deterioration ranges from cosmetic affects such as color or
outside surface changes to more severe problems including the diminishing
of a product's structural strength and the addition of undesirable
properties to the product. In certain metal processing activities,
surface scaling due to ash can be stripped away, but costs will be
increased. Ash constituents occasionally are a necessary or neutral
element to the product, as in cement manufacturing. In other cases,
such as glass annealing, ash contamination probably cannot be tolerated.
Ash also tends to attack furnace metals and refractory linings
through corrosion and slagging. The refractory and ash combine at the
refractory's surface to form a liquid or semi sol id eutectic mixture that
runs off the refractory wall. If this process is allowed to continue,
the refractory wall tends to deteriorate. This problem is surmountable
(at higher costs) in high-grade refractories that bring the fluxing
action within tolerable limits.
4-10
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If furnace temperatures exceed the ash fusion point of coal, ash is
deposited on the furnace walls and refractories, and furnace efficiency
is reduced. The liquid form of ash cannot be removed without shutting
down the furnace. Ash also tends to impair furnace and heat recovery
equipment through plugging. In solid form, ash plugging can be overcome
by equipment design and mechanical sootblowing techniques. Plugging
problems are more severe at furnace temperatures at which ash fusion can
plug flue gas outlets or heat recovery equipment passages.
In conjunction with sulfur, ash corrodes metal tubes or other
surfaces in the furnace. The corrosion problems become more severe at
higher furnace temperatures (1000-1400°F) which speed up corrosive
chemical reactions, although there is a dropoff after 1450°F. To some
extent, corrosion can be minimized (again, at higher costs) by using
special corrosion-resistant alloys. However, many of these alloys do
not have sufficient structural strength to be employed at higher furnace
temperatures when the corrosive effects of sulfate are most severe.
Higher chrome alloys (>30 percent chromium) sacrifice structural strength
for corrosion resistance up to about 1000 F. Chromium nickel stainless
steels have greater structural strength than high chrome alloys but also
resist corrosion only up to approximately 1000°F. Nickle-based super
alloys can be used at high temperatures without sacrificing tensile
strength but are susceptible to chloride attack.
4-11
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4.4 SUMMARY OF TECHNICAL FEASIBILITY EVALUATIONS
When considering the technical feasibility of coal and oil use,
each process application is classified into one of the following four
categories, based on the severity of technical risks.*
Proven: In these applications, coal or oil has been used in commercial
scale processes within the United States. The technology has been
sufficiently proven to support commercial ventures.
Low Risk: For these process applications, it should be possible to
construct and operate successfully a coal- or oil-fired unit without
significant risk of failure. In every case, however, a new design must
be prepared. For example, the majority of heaters in the Petroleum.
Refining industry currently are designed with underfiring. Coal-fired
heaters would have to be designed with burners firing vertically down-
ward or from the side of the furnace to prevent ash from falling onto
the burners. The new design would have to handle differences in flame
characteristics, volume of the firebox, and other special problems
associated with coal burning discussed earlier. Low risk essentially
represents surmountable technical obstacles, but the unit must be built
and demonstrated before it can be considered commercially available.
*These categories refer only to conventional process heater designs and do
not apply to gasification technologies. The evaluation also does not
consider the potential to shift from direct-fired process equipment (where
coal combustion products impact directly on the product being processed) to
indirect firing (where combustion products do not come in direct contact
with the products being processed). If such shifts are feasible, the
potential for coal use is greater than indicated in this report.
4-12
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High Risk: In these process applications, the obstacles to coal or
oil use are more severe. Use of coal may impose special design prob-
lems, higher risk of materials failure, equipment downtime, or greater
safety hazards. For these processes, it may be possible to apply coal
effectively, but the risks of failure are much greater than for the
low-risk category.
Probably Infeasible: For these processes, the problems of coal or
oil use appear to be so severe that unless new breakthroughs in design
or material quality occur, coal cannot be burned.
In the operation of the model, the risk evaluation does not change
for 1985, 1990, and 1995. Thus, a high-risk fuel use in a process in
1985 might become low risk by 1990 and proven in 1995 but will be considered
in the model as a high risk alternative in and after 1985. Likewise, when
the use of a certain fuel in a process was considered infeasible in
1985, it also was considered infeasible in 1990 and 1995. This assumption
introduces some bias against coal or oil use to the extent that techno-
logical breakthroughs are made.
IFCAM can be operated given any assumption regarding technological
risk. Generally, the model has been operated including proven, low-,
and high-risk technology options. However, it could be operated allowing
only proven or proven plus low-risk technological options, thus limiting
the potential market penetration of residual oil and coal.
The results of the technical analyses suggest that most potential
coal use in process applications is in the Petroleum Refining, SCG,
4-13
-------
Steel, and Aluminum industries (see Table 4-1). Table 4-2 emphasizes
that the technical potential for coal use is higher for new units than
it is for retrofitting existing units burning oil or gas. Residual oil
use, however, has much wider potential; retrofits or new units are
considered feasible in most of the processes specifically studied. See
Appendix G for process-by-process detail on the feasibility of coal or
oil use.
4.4.1 Lead Time
For all processes technically capable of using coal, there are lead
time factors affecting the date of commercial availability. For a
proven technology, coal use is limited only by commitments already made
in an analogous manner to the new boilers discussed earlier. However,
when coal firing technology is not proven, other factors affecting
commercial availability and market penetration of the new technology
must be taken into account. Table 4-3 provides an example of additional
lead time factors necessary when coal use in a technology is unproven
(for example, coal use in new tubestill heaters for atmospheric crude
oil distillation).
The first key assumption in this scenario is that either the private
or public sector initiates development of the coal firing technology in
January 1979. In this optimistic scenario, it takes two years to design
and construct one or more commercial facilities. One year is allowed
for thorough testing and operational experience. Assuming successful
operating experience, a minimum of two or more years is necessary for
4-14
-------
TABLE 4-1. TECHNICAL FEASIBILITY OF COAL USE BY INDUSTRY
IN PROCESS HEAT APPLICATIONS3
Combustor application
New - Retrofit -
% of all fossil % of all oil and gas
Industry fuel use in new units use in existing units
Food
Textiles
Paper
Chemicals
Petroleum Refining
SCG
Steel
Aluminum
Otherb
TOTAL
0
0
0
2
79
87
44
70
0
51
0
0
0
1
0
83
44
70
0
22
The Technical Feasibility of Coal Use in Industrial Process Heat
Applications. Energy and Environmental Analysis, Inc. Arlington,
Va. May 1978. 353 p. Draft report prepared for the Office of
Policy and Evaluation, U.S. Department of Energy. Includes proven,
low risk, and high risk assessments.
This study did not evaluate the technical feasibility of coal substi-
tution in these industries.
4-15
-------
TABLE 4-2. TECHNICAL SUBTITUTION POTENTIAL:
COAL FOR GASEOUS AND OIL FUELS IN PROCESS HEAT EQUIPMENT3
(% of evaluated industry consumption of gaseous and oil fuels)
Risk category
Proven
Low risk
High risk
Infeasible
Not accounted for
TOTAL
New units
14.8
22.6
13.6
45.5
3.5
100.0
Retrofit
existing
7.4
13.3
1.6
72.1
5.6
100.0
of
units
The Technical Feasibility of Coal Use in Industrial Process Heat
Applications. Energy and Environmental Analysis, Inc. Arlington,
Va. May 1978. pp. 1-3, 1-4. Draft report prepared for the Office
of Policy and Evaluation, U.S. Department of Energy. Gaseous fuels
for the purposes of this table include methane, propane, butane,
liquefied petroleum gas, and refinery off-gas. Oil fuels include No.
1 fuel oil, No. 2 fuel oil, kerosene, diesel oil, No. 5 fuel oil, No.
6 fuel oil, tar, and pitch.
-------
TABLE 4-3. MARKET PENETRATION LEAD TIMES FOR A
NEW COAL-FIRED NONBOILER USE: OPTIMISTIC SCHEDULE
Example: Atmospheric Crude Oil Distillation Tubestill Heater
Start date January 1, 1979
Demonstration time:
Construction period 2 years
Proving experience 1 year
Total 3 years
t Construction of new commer- 2 years
cial coal facility
Initial year of market 1984
penetration
Percent of market penetration 20 percent
in 1984
-------
construction lead time to install the first commercial scale facilities.
Adding the demonstration and construction lead times, units coming on
line in 1984 would be the first ones that might fire coal.*
Not all new units, however, would select coal even if it were the
economic choice. Past experience suggests that new technologies are
installed at a relatively slow pace as companies test the units in their
own facilities and gain operation experience before accepting a new
technology. The estimated rate of market penetration was derived from
past experience based on the penetration rate for new hydrocracking
equipment from 1968-1977. Extrapolating from that experience, 20
percent of the new units coming on line in the 1984-85 time period would
select coal firing if it were economic. If energy demands to fire new
tubestill heaters were distributed evenly over 1975-85, then a maximum
of three percent of the energy use in new tubestill heaters could select
coal if the economics were favorable.** A less optimistic time
schedule would reduce market penetration by 1985 to zero.
An identical approach was followed for all processes technically
capable of burning coal. See Appendix G for a list of the lead time
factors for all technically feasible coal firing processes.
* Other timing scenarios which have less optimistic assumptions
related to the development period can also be run.
** 1984-1985 covers 15 percent if the interval of new energy demands are
the same each year. Applying the 20 percent penetration rate to 15
percent of the energy implies a maximum coal market penetration of
three percent.
4-18
-------
4.5 OTHER CONSTRAINTS
The use of certain fuels is limited by two types of potential con-
straints not explicitly incorporated into the model framework. The
first constraint is site-specific factors that would preclude use of a
certain fuel, especially coal, in otherwise economical situations. The
second set of constraints, relating to supply questions, is not tested
explicitly in the model but must be considered.
Site-specific constraints include factors such as limited land or
space requirements, particularly in the case of existing plants. The
failure to incorporate any specific downward adjustment for space con-
straints tends to bias the results in favor of additional coal use.
Data on such constraints are not readily available. The effects of such
factors can be simulated arbitrarily by assuming that a certain percen-
tage of coal or oil use in existing facilities is precluded by siting
considerations.
It is important to remember that IFCAM is strictly an energy demand
model and that any supply-related constraints are considered external to
the model. The model results must be viewed in interaction with an
energy supply model to provide equilibrium fuel use results. In reality,
gas, oil, and coal supply availability may constrain the level of demand
for certain fuels in some.regions, as will constraints in the form of
backlogs in orders for pollution control equipment and boiler and process
heat application equipment. The effect of the supply factors, particularly
those that could limit coal use, are typically analyzed outside the model
framework.
-------
REFERENCES
1. Bell, A. W. and B. P. Breen. Converting Gas Boilers to Oil and
Coal. Chemical Engineering. 83(9):93-101. April 26, 1976;
Burke, J. M. and M. 0. Matson. Industrial Boilers Fuel Switching
Methods, Costs, and Environmental Impacts. Radian Corp. Austin,
Texas. Prepared for the Office of Air Quality Planning and Standards,
U.S. Environmental Protection Agency. Publication No. EPA-450/3-78-123
(PB-293014) December 1978. 172 p.
Bogot, A. and R. C. Sherrill. Principal Aspects of Converting
Steam Generators Back to Coal Firing. Combustion Engineering, Inc.
Publication No. TIS-4588 Presented at the NCA/BCR Coal Conference
and Expo II. Louisville. October 21-23, 1975. 9 p.
Cross, F. L. Pragmatic Approach to Industrial Boiler Conversion to
Coal. Presented at the Fifth Energy Technology Conference.
Washington, D.C. February 27-March 1, 1978. 6 p.
Feeley, F. G. Energy Conversion Problems from the Industrial Users
Viewpoint. 01 in Corp. Presented at the Fourth Energy Technology
Conference. Washington, D.C. March 14-16, 1977. 8 p.
Llinares, V. Using Coal for Steam and Power Generation in Industrial
Boilers. Combustion Engineering, Inc. Publication No. TIS-5405
Presented at the Manufacturing Chemists Association Energy Seminar.
Washington, D.C. September 28-29, 1977. 12 p.
Marshall, R. W. Boiler Conversion - An Effective Pollution Control.
Iron and Steel Engineer. 50:59-64. January 1973.
Schweiger, R. G. Should you Convert to Coal? Power. 120:38-41.
July 1976.
Siebold, P. F. and R. D. Bessette. Latest Equipment and Design for
New Coal-Fired Plants and the Conversion of Existing Plants to Coal
Firing. Riley Stoker Corp. Presented at the Industrial Fuel Con-
ference. Purdue U., Lafayette. October 6-7, 1976. Also presented
at the Kentucky Industrial Coal Conference. April 26-27, 1978. 32 p.
2. The Technical Feasibility of Coal Use in Industrial Process Heat
Applications. Energy and Environmental Analysis, Inc. Arlington,
Va. Draft report prepared for the Office of Policy and Evaluation,
U.S. Department of Energy. May 1978. 353 p.
-------
3. The Substitution Potential of Alternative Fuels for Natural Gas in
Selected Industries. Energy and Environmental Analysis, Inc.
Arlington, Va. Prepared for the Office of Energy Programs, U.S.
Department of Commerce. June 1978. 209 p.
4. Industrial Sector Technology Use Model (ISTUM): Industrial Energy
Use in the United States, 1974-2000. Energy and Environmental
Analysis, Inc. Arlington, Va. Prepared for the U.S. Department of
Energy. Publication No. DOE/FE/2344-1,-2,-3, 4. October 1979.
1200 p.
5. Summarized from reports referenced above in Footnotes 2 and 3.
4-21
-------
5. ASSIGNMENT OF ENVIRONMENTAL REGULATIONS AND POLLUTION
CONTROL STRATEGIES
5.1 INTRODUCTION
Environmental regulations play an important role in determining
industrial fuel choice. For example, air emission regulations alter
relative capital and fuel costs and may preclude the use of certain
fuels in combustors. Specific environmental regulations can vary
according to geographic location, combustor size and type, and fuel
type. Both Federal and State environmental regulations influence fuel
choice.
The impact of environmental regulations is modeled in IFCAM in a
three-step process. First, each boiler is assigned to an AQCR based on
historical location patterns of industrial energy consumption. Second,
the specific emission limit applicable to each combustor is identified.
Next, the pollutant control equipment and the fuel quality required to
meet emission limits are specified. For process heat equipment, only
the last step is necessary. These three steps are discussed in the
following sections.
5.2 ASSIGNMENT OF BOILERS TO AQCR'S
The environmental regulations that apply to any type of combustor
can vary significantly from one AQCR to the next. While NSPS provisions
apply equally in all parts of all regions, SIP provisions often vary
among AQCR's and, in some cases, among areas within AQCR's.
5-1
-------
Within each region, new boilers and small existing boilers are
located randomly by AQCR according to historical patterns. Within each
region and fuel type, a cumulative distribution function was developed
for the level of fuel use in each AQCR. The fuel-specific distribution
of fuel use among AQCR's is based on a 1975 working paper that used EPA
emission inventory data (including fuel use). If AQCR #1 consumed
three times as much fuel as AQCR #2 consumed, then each new boiler (in
each industry, size/capacity utilization class) is three times more
likely to site in AQCR #1 than in AQCR #2.
No attempt was made to model changes in industrial location pat-
terns. Such trends are extremely difficult to identify and project and
certainly were beyond the scope of this effort. Consequently, State and
local environmental regulations implicitly are assumed not to influence
industrial location patterns. Using historical location patterns to
predict future location patterns concentrates new energy consumption in
areas where energy consumption has been located in the past. If future
industrial energy location patterns tend to shift away from existing
concentrations of energy use, then the costs of using coal may tend to
be lower than that forecasted by IFCAM.
In a previous study, EEA identified the AQCR location of large
2
existing boilers in the MFBI file. By reviewing the city, county,
state, and zip code information on the survey forms, EEA coded the AQCR
on existing boiler records. Consequently, no additional effort was
required to locate large existing boilers.
5-2
-------
5.3 ASSIGNMENT OF ENVIRONMENTAL REGULATIONS TO INDIVIDUAL COMBUSTORS
5.3.1 Scope
The fuel used to fire a combustor is influenced by environmental
regulations governing air pollution emissions, among other factors. A
variety of environmental regulations may apply to any combustor depending
upon combustor type, size, location, and the fuel fired by the unit.
The environmental regulations to which a combustor is subject help
determine a combustor1s pollution control equipment as well as its fuel
choice.
The regulations used in IFCAM are Federal and State air pollution
control standards resulting from the 1970 and 1977 CAA Amendments. This
act gave the EPA the authority to establish National Ambient Air Quality
Standards (NAAQS) that would protect the health and welfare of the
population. The EPA promulgated NAAQS for six "criteria pollutants":
S09, particulate matter (PM), NO , hydrocarbons (HC), carbon monoxide
£ /\
(CO), and photochemical oxidants.
Industrial sources are subject to two classes of environmental
regulations adopted by States to insure compliance with ambient stan-
dards:
State Implementation Plan (SIP's)
Nonattainment(NA)/Prevention of Significant Deterioration
(PSD).
SIP's are developed by each state to implement and maintain NAAQS within
its geographical area. NA and PSD rules, designed to upgrade or main-
tain the air quality of specific areas in accordance with NAAQS, are
5-3
-------
incorporated in SIP's on a case-by-case basis. NA/PSD rules and their
relationship to SIP's are discussed in Section 5.5, Other Environmental
Requirements.
The CAA also gave EPA the authority to promulgate NSPS, national
standards governing the air emissions from specific categories of newly
constructed sources. NSPS are technology-defined Federal standards;
combustors subject to NSPS must use the best available emission control
technologies (BACT). Current NSPS provisions apply to boilers commenc-
ing on-line status after 1971 that have firing rates above 250 MMBtu/hr
heat input. For any unit of this type, the current NSPS is the binding
regulation unless the applicable SIP for any given unit is more stringent
-- hence binding -- than the NSPS. The current NSPS for industrial
fossil fuel-fired boilers is under scrutiny to determine the need for,
and extent of, revisions to the regulation.
The State and Federal regulations governing the emissions of three
pollutants subject to NAAQS -- S09, PM, and NO -- are considered in
w A
IFCAM. Regulations pertaining to the other NAAQS pollutants -- CO, HC,
and photochemical oxidants -- are not modeled in IFCAM since industrial
processes emit these pollutants in negligible quantities or in quantities
that do not differ significantly among fuel types.
State and Federal regulations can vary by combustor fuel use.
Regulations applicable to combustors that fire one of the following
fuels are considered in IFCAM: coal, residual fuel oil, distillate fuel
oil, and natural gas. Regulations limiting S0?, PM, and NO are assumed
£ /\
5-4
-------
to apply to coal- and residual oil-fired combustors. In IFCAM, distil-
late oil- and natural gas-fired combustors are subject only to NO
regulations since units firing these fuels are assumed to emit insignif-
icant levels of S02 and PM.
The following examines the effect of these regulations on three
general classes of combustors: (1) boilers subject to NSPS, (2) boilers
subject to SIP's, and (3) nonboiler processes.
5.3.2 New Boilers Subject to NSPS
All boilers installed after the base year (1974) with firing rates
greater than 250 MMBtu/hr heat input are subject to NSPS provisions.
Coal-, oil-, and natural gas-fired units are subject to the NSPS emis-
sion limitations presented in Table 5-1. IFCAM applies these limita-
tions to units operating before 1982 that are not subject to more stringent
SIP's.
For new units that come on-line after 1982, IFCAM can evaluate
several regulatory alternatives. For example, IFCAM can evaluate the
effect of expanding the size applicability of the regulation to include
new units smaller than 250 MMBtu/hr heat input. Alternatively, IFCAM
can evaluate the effects of a pollutant percentage reduction requirement
or a change in stringency from the current NSPS. For example, the
regulation for controlling S02 emissions from coal-fired boilers can
vary by boiler size and can be specified as the following:
A ceiling emission rate (Ibs. of pollutant/MMBtu of fuel
burned)
A recommended percentage removal (e.g., 90 percent removal of
sulfur content)
5-5
-------
TABLE 5-1. CURRENT BOILER NSPS REGULATIONS
Fuel
Type
Boiler Size
MW (MMBtu/hr)
Pollutant
SO,
PM
NO.
Coal
Oil
Gas
>73.25 (>250) 1.2 Ibs/MMBtu .10 Ibs/MMBtu .7 Ibs/MMBtu
(515.9 ng/J) (43 ng/J) (300.9 ng/J)
>73.25 (>250) .8 Ibs/MMBtu
(343.9 ng/J)
>73.25 (>250)
,10 Ibs/MMBtu
(43 ng/J)
.3 Ibs/MMBtu
(129 ng/J)
.2 Ibs/MMBtu
(86 ng/J)
Heat input
5-6
-------
A recommended percentage removal and a "floor" emission rate
(e.g., 90 percent removal but no lower than 0.5 Ibs/MMBtu)
A minimum percentage removal to be applied if the recommended
percentage removal results in controlled emission rates less
than the "floor."
5.3.3 Boilers Subject to SIP's
All existing boilers and new boilers with firing rates lower than
250 MMBtu/hr heat input are subject to SIP's.* Larger new boilers
subject to SIP's more stringent than the current NSPS also must abide
with SIP regulations. SIP's limits on SCL, PM, and NO emissions vary
£ /\
substantially within and among states, both in the severity of the
standards and in the way they are expressed. Some states specify stan-
dards only in terms of ambient conditions. Most states, however, specify
standards in a variety of forms including pounds of pollutant per energy
release of the fuel (Ib/MMBtu), pounds of pollutant emitted per 1000
pounds of steam, or pollutant content of the fuel, by weight, in percentage
terms. In many states, SIP requirements also vary by fuel type and
boiler size.
A set of regulations reflecting the diversity of SIP requirements
has been compiled for use in IFCAM. These SIP's are identified by AQCR
and combustor fuel type and are specified as pounds of pollutant emitted
per million Btu of fuel burned. Since a number of AQCR's contain por-
tions of two, three, or four states, average SIP's are calculated for
Small new boilers may be subject to an alternative NSPS which is
more stringent than the applicable SIP standard.
5-7
-------
interstate AQCR's. Each state's SIP regulation is weighted by the fuel
consumption within the state's geographical portion of the AQCR, and
these weighted SIP's are averaged to estimate one interstate regulation.
SIP values also are approximated for states in which SIP regula-
tions vary by city or county, averaging period, form of specification,
or boiler size class applicability. SIP's in IFCAM are classified among
three boiler size categories: 10-100 MMBtu/hr, 100-250 MMBtu/hr, and
greater than 250 MMBtu/hr. For each size class, the regulation in the
SIP file is expressed as: a x + c, where x is the boiler firing rate
(MMBtu/hr heat input). This form permits estimating the applicable
regulation for a specific size instead of using an average value. The
IFCAM SIP file includes SIP revisions as of July 1979.
5.3.4 Environmental Standards for Process Heaters
Emission limits for fuel burning in process heaters are not defined
as clearly as for boilers. This is largely a consequence of the histori-
cal reliance of process heaters on gas and fuel oil. Many process
sources that are controlled, such as sulfuric acid plants, are not
related to fuel combustion. The few processes that use coal, such as
cement kilns, generally are not major emitters due to the nature of the
production process. For example, coal ash becomes an element of the
product in cement manufacturing. More generally, current SIP's applicable
to process sources may become completely outmoded or irrelevant given
fuel use trends away from natural gas. In cases in which gas currently
is being used, SIP's may not be applicable to oil or coal.
5-8
-------
As a result of these problems, a hypothetical set of-regulations is
applied to certain process sources, depending on the general context of
the environmental regulatory scenario. These scenarios are specified
directly in terms of pollution control strategies and are discussed in
the following section.
5.4 ASSIGNMENT OF POLLUTION CONTROL STRATEGIES
5.4.1 Boilers
To comply with air emission regulations, boiler owners assess con-
trol strategies based upon available fuels and pollution control equip-
ment. The control strategy employed by boiler owners depends upon the
amount of emission reduction required to meet applicable regulations.
Boiler owners can choose to burn a fuel grade whose uncontrolled emis-
sion rates are within the limits established by the standards or a
particular fuel grade in combination with pollution control equipment as
their control strategy. Table 5-2 presents the uncontrolled boiler air
emission rates for the four major fuel types available in IFCAM: natural
gas, distillate oil, residual oil, and coal.
Many emission control standards necessitate the use of pollution
control equipment to reduce boiler emissions. Several pollution control
technologies are available in IFCAM (see Table 5-3). These technologies
vary by pollutant, combustor application, and technical capability.
Control strategies for coal-fired boilers include the use of: one
of 23 raw or 16 physically cleaned coals, three types of FGD equipment,
four types of particulate collection equipment, and several types of NO
combustion modification.
5-9
-------
TABLE 5-2. UNCONTROLLED AIR EMISSION RATES FOR INDUSTRIAL BOILERS3
(ng/J (lb/MMBtu))
Fuel Type
Natural Gas
Distillate Oil
Residual Oil
o All
o 3 S
o 1.6 S
o 0.8 S
a 0.3 S
Coal
o underfeed stoker
o chaingrate stoker
o spreader stoker
o pulverized coal
Boiler Size
(MW (MMBtu/hr))
<8.79(<30)
>8.79(>30)
<8.79(<30)
>8.79(>30)
£8.79(<30)
>8.79(>30)
all
all
all
all
' <17.58
(<60)
17.58 - 21.98
(60 - 75}
21.98 - 58.6
(75 - 200}
>58.6
(>200)
so2
.2579(0.0006)
.2579(0.0006)
85.98(0.2)
85.98(0.2)
343.94(0.8)
134.99(0.314)
19 x 106* S/K8
(19,001 * S/B)
19 x 106 « S/Ka
(19,001 * S/B)
19 x 106 * S/Ka
(19,001 « S/8)
19 x 106 * S/Ka
(19,001 * S/B)
Pollutant
PM
4.29(0.01)
4.29(0.01)
6.19(0.0144)
6.19(0.0144)
25 x 106* A/K
(2500 * A/B)
25 x 106 * A/K
(2,500 « A/B)
65 x 106 " A/K
(6500 » A/B)
80 x 106 * A/K
(8000 « A/B)
N0,
39.98(0.093)
119.95(0.279)
70.08(0.163)
89.85(0.209)
150.04
(0.349)
139.72
(0.325)
264.83
(0.616)
285.04
(0.663)
s
A
K
3
= % Sulfur
= % Ash
= kJ/kg
= Btu/lb
<8.79
>8.79
MW.
MW,
(<30
(>30
MMBtu/hr):
MMBtu/hr):
firetube
watertube
Approximate
5-10
-------
TABLE 5-3. BOILER COMPLIANCE STRATEGIES
Pollutant
S02 Particulate Matter N0x
Pre-Combustion Physical Coal Cleaning
Post-Combustion Flue Gas Desulfurization Mechanical Collector . Combustion Modifications
o Double Alkali Wet Scrubber^
o Lime Spray Drying Electrostatic Precipitator
o Sodium Spray Drying Fabric Filter
Coal only
Combined SO?/PM control system; includes a fabric filter
-------
Combustion of a raw coal represents a control strategy when the raw
coal-fired combustor's uncontrolled pollutant emissions are lower than
the level allowed by emission regulations. Fuels associated with allowable
emission rates without the application of pollution control equipment
are referred to as compliance fuels; of the 39 coals available in IFCAM,
many could be used as compliance fuels to meet local S02 emission regula-
tions. The raw coal grades available in IFCAM are presented in Table
5-4 by supply region (see Figure 5-1).
This wide array of coal grades has been included in IFCAM for two
reasons. First, the range of coal grades in IFCAM reflects the wide
range of grades available. Second, since SIP regulations for SOp con-
trol vary significantly in stringency from one area to the next, the
availability of numerous potential compliance coals in IFCAM should lead
to a reasonable portrayal of compliance costs.
Coal-fired boilers can burn one of 16 cleaned coal grades available
in IFCAM as their control strategy. These cleaned coal grades are the
products of physical coal cleaning (PCC), which reduces potential S02
and PM emissions by removing ash and pyritic sulfur minerals from raw
coals. The cleaned coal has a higher heating value by weight than the
raw feed coal.
Versar, Inc.* estimated the capital and O&M costs associated with
several coal preparation plants. These costs have been converted to an
annualized capital and O&M cost; these annualized costs have been added
to the F.O.B. mine prices of the feed coal. Finally, the cleaned coal
See Appendix F for references.
5-12
-------
TABLE 5-4. COAL CHARACTERISTICS
en
i
OJ
Supply
Reg 1 on
Northern
Appa-
lachia
Central
Appa-
lachia
Southern
Appal achia
ng SOp Ibs. SOp
per J per MMBiu
2579.53
1466.03*
988.03
1620.81
984.52*
1182.29
739.47*
735.17
580.39*
2166.81
1526.22*
1741.18
1263.92*
1190.88
760.77*
743.77
558.40*
537.40
494.41*
528.80
455.72
975.92
6.0
3.41*
2.3*
3.77
2.29*
2.75
1.72*
1.71
1.35*
5.04
3.55*
4.05
2.94*
2.77
1.77*
1.73
1.30*
1.25
1.15*
1.23
1.06*
2.27
% Sulfur %
Dry
3.45
2.21
1.57
2.5
1.6
1.86
1.22
0.92
0.82
2.95
2.31
2.7
2.0
1.56
1.24
1.18
0.94
0.87
0.83
0.85
0.75
1.6
Wet
3.28
2.01
1.38
2.47
1.56
1.79
1.10
0.91
0.76
2.88
2.22
2.64
1.96
1.52
1.16
1.15
0.85
0.83
0.76
0.82
0.67
1.51
Dry
23.9
14.4
9.7
11.7
10.3
12.8
8.7
28.7
19.9
23.1
15.5
13.5
12.6
25.9
9.7
10.4
4.7
11.2
8.1
10.9
9.5
7.6
Ash
Wet
22.7
13.1
8.5
11.5
10.0
12.4
7.9
28.4
18.5
22.6
14.9
13.2
12.4
25.2
9.1
10.2
4.3
10.7
7.5
10.6
8.6
7.2
HHV Dry
kJ/kg
26,772
30,171
31,876
30,866
32,471
31,420
32,887
25,005
28,079
27,186
30,243
30,982
31,587
26,226
32,471
31,685
33,697
32,310
33,453
32,203
32,783
32,797
Btu/lb
11,510
12,971
13,704
13,270
13,960
13,508
14,139
10,750
12,072
11,688
13,002
13,320
13,580
11,275
13,960
13,622
14,487
13,891
14,382
13,845
14,094
14,100
HHV, Wet %
kJ/kg
25,432
27,400
27,954
30,464
31,594
30,319
29 ,829
24,753
26,142
26,589
29,063
30,301
31,043
25,516
30,554
31,052
31,136
30,954
30,978
21,238
30,994
30,994
Btu/lb
10,934
11,778
12,018
13,097
13,583
13,035
12,824
10,642
11,239
11,431
12,495
13,027
13,346
10,970
13,136
13,350
13,386
13,308
13,318
13,430
12.699
13,325
Moisture
5.0
9.2
12.3
1.3
2.7
3.5
9.3
1.0
6.9
2.2
3.9
2.2
1.7
2.7
5.9
2.0
7.6
4.2
7.4
3.0
9.9
5.5
*Cleaned Coal.
-------
TABLE 5-4. COAL CHARACTERISTICS
(Continued)
LTI
I
Supply ng SOp
Region #per J
Midwest
Central
west
Western
No. Great
Plains
Rockies
South-
west
3826.31
2295.78*
2042.13
1276.87*
1182.29*
1625.11
997.42
5606.18
3435.08*
2575.23
1074.81
717.97
374.03
795.36
546.00
503.01*
694.18
Ibs. S0?
per MMBtu
8.9
5.34*
4.75
2.97*
2.75*
3.78
2.32
13.04
7.99*
5.99
2.5
1.67
0.87
1.85
1.27
1.17*
1.51
% Sulfur
Dry
4.35
3.30
2.88
1.99
1.85
2.5
1.5
5.22
4.05
4.17
1.4
1.0
0.5
1.2
0.8
0.75
0.9
Wet
4.0
3.06
2.70
1.84
1.72
2.18
1.38
4.74
3.67
3.95
1.3
0.81
0.39
1.16
0.76
0.70
0.80
' ' "
% Ash
Dry
29.9
11.4
16.4
7.5
7.1
8.7
10.5
27.2
8.0
5.2
10.4
9.8
4.6
6.5
11.6
10.0
11.3
"1
Wet
27.5
10.6
15.4
6.9
6.6
7.6
9.7
24.7
7.3
4.9
9.4
7.9
3.5
6.3
11.0
9.5
10.1
"1 Mi M 1 ' I
HHV
kJ/kg
22,753
28,773
28,191
31,185
31,317
30,773
30,075
18,634
23,546
32,480
26,191
27,912
26,889
31,122
29,354
29,657
27,889
IK: l.-,c I
Dry
Btu/lb
9,782
12,370
12,120
13,407
13,464
13,230
12,930
8,011
10,123
13,964
11,260
12,000
11,560
13,380
12,620
12,750
11,990
1 1
HHVj Wet %
kJ/kg
20,932
26,672
26,500
28,752
29,187
26,896
27,670
16,901
21,357
32,369
23,572
22,553
20,704
30,033
27,917
28,056
24,821
Btu/lb
8,999
11,467
11,393
12,361
12,548
11,563
11,896
7,266
9,182
13,916
10,134
9,696
8,901
12,912
12,002
12,062
10,671
Moisture
8.0
7.3
6.0
6.8
12.6
8.0
9.3
9.3
5.5
14.2
19.2
23.0
3.5
4.9
5.4
11.0
*Cleaned Coal.
-------
FIGURE 5-1 COAL SUPPLY REGIONS
A.
ifill II11 mil I nous Con I
^J .Suh-IVituifll nous Coal
i l»n I te
w.
./ Aiil Inac I te
!. Northern A|i|tninciiia
2. Central Appalachla
3. Southern Appalachla
I. Midwest
5. Central West
6. CM If
7. lUistorn Northern Groat Plains
11. Western Northern Great Plains
0. Hock Ios
10. Southwest
11. Northwest
12. Alaska (not shown)
Source:
It. fi. Ceo I oj; I nil .Siirvoy niilletln I'll 2
(*O(ll I1<)SI)IIITC!-J llf lIlO till I I 1>.I Sl.ito.t I.
I III-?,I
-------
costs are adjusted to account for Btu losses incurred in transforming
the raw coal into cleaned coal. Appendix F summarizes these cost assump-
tions.
One type of available control equipment to control S0? emissions is
flue gas desulfurization (FGD), or scrubbers. Appendix F presents
sample costs for selected processes. The types of FGD equipment cur-
rently available in IFCAM are dual alkali, lime spray drying, and sodium
spray drying. The spray drying systems include a fabric filter to
control simultaneously PM and S02 emissions. The scrubber costs are
expressed as a continuous function relating a boiler's input (fuel)
sulfur and ash content to the percent sulfur removal required in order
to meet emission regulations. The scrubber costs calculated for each
boiler are unique for each coal (or residual oil) type and regulation.
There are 117 distinct SQy control strategies (three FGD types times 39
coal grades) for coal-fired boilers and 12 SCL control strategies (three
FGD types times four residual oil grades) for residual oil-fired units.*
These FGD technologies are assumed to be capable of removing up to
90 percent of potential S0« emissions. Dual alkali costs are applicable
if it is necessary to remove between 75 and 90 percent of potential S02
emissions. If less than 75 percent S0~ emission reduction is necessary
to meet the regulation, the flue gas flow rate for the dual alkali
system is reduced to simulate a bypass system. The flue gas'passing
If scrubbing is required. Scrubbing usually is not required for all
coal or residual fuel oil types to comply with SIP regulations.
5-16
-------
through the dual alkali scrubber is subject to 90 percent SO,, removal.
The dual alkali scrubber removal capability is modeled in this fashion
to simulate the practice of "partially scrubbing" S02 emissions to
reduce compliance costs.
Four particulate collection devices are available in IFCAM for
application to coal-fired boilers: electrostatic precipitator (ESP),
fabric filter (FF), wet scrubber (WS), and mechanical collector (MC).
Residual oil-fired boilers use ESP's exclusively. The costs of these
devices depend on the flue gas flow rate, the uncontrolled emission
rate, and the percent reduction in particulates required to meet PM
emission limitations. Sample costs are presented in Appendix F.
The particulate control devices available in IFCAM vary by boiler
type applicability and technical capability. Table 5-5 presents the
control efficiences assumed for each device.
NO control strategies available in IFCAM are represented by several
/\
types of NO combustion modifications:
/\
Low excess air
Staged combustion air
Low NO burners
Flue gas recirculation
Reduced air preheat
Ammonia injection.
Table 5-6 presents NO control technologies. Key cost variables for NO
/\ />
controls are boiler size and NO reduction requirements. The cost
/\
5-17
-------
TABLE 5-5. PARTICULATE MATTER CONTROL EFFICIENCIES'
Technology
Control Limit (Percentage)
Fabric filter
99.9
Electrostatic precipitator
99.9 (coal)
90.0 (residual oil)
Wet scrubber
98.9
Mechanical collector
80. Ol
85. Oc
90. 0*
Gardner, R.I. et a!., p. A-1.
Restricted to particulate emission regulations less than 0.1 Ib/MMBtu
(50 ng/J). Ibid., pp. 59-61.
Pulverized coal, >200 MMBtu/hr. (>58.6 MW).
Spreader stoker, 75-200 MMBtu/hr (22 - 58.6 MW).
Other stokers, <75 MMBtu/hr (<22 MW).
5-18
-------
TABLE 5-6. NO CONTROL TECHNOLOGIES0
01
I
Boi
Boiler and Fuel Type MW
Pulverized coal 59 (200)
Spreader stoker
Chain grate stoker
Underfeed stoker
Residual oil
Firetube
Watertube
Distillate oil
Firetube
Watertube
Natural Gas
Firetube
Watertube
LEGEND: - = No controls required
ND = No Data
LNB = Low NO burners
RAP = Reduced air preheat
ler Size(s)
(MMBtu/hr)
and 117 (400)
25 (85)
44 (150)
22 (75)
9 (30)
4.4 (15)
8.8 (30)
44 (150)
4.4 (15)
29 (100)
44 (150)
29 (100)
44 (150)
Moderate
-
SCA
-
-
-
LEA
LEA
-
LEA
LEA
-
RAP
RAP
LEA =
SCA =
NH, =
FGR =
Level of Control
Intermediate
LEA
ND
LEA
-
-
LEA
SCA
SCA
LEA
RAP
RAP
-
RAP + SCA
RAP + SCA
Low excess air
Staged combustion air
Ammonia injection
Flue gas recirculation
Stringent
SCA
NH3
SCA
LEA
LEA
SCA
LNB
LNB
FGR
SCA
SCA
-
RAP + LNB
RAP + LNB
Acurex Corporation
With air preheat
-------
variables take into account improvements in combustion efficiency due to
NO control application. Costs for NO controls also are described in
/\ f\
Appendix F.
Similar to FGD and particulate control technologies, NO combustion
y\
modifications are subject to removal efficiency limitations and variations
in applicability. Table 5-7 presents the removal efficiencies of the
modifications applied to specific boiler/fuel type categories.
5.4.2 Process Heaters
Emission limits for coal-fired process heaters are difficult to
assess since coal is used in only a few process applications and few
regulations regarding coal use currently exist. Emissions for the most
important coal-using process, cement kilns, do not pose significant
problems since they are absorbed into the product rather than passed
into a flue gas stream. Given that uncontrolled emission rates under
coal firing are not known at this time, the emission controls required
for direct burning of coal as a solid fuel in process heaters necessarily
are conjectural. Basically, an ESP was required for all coal-fired
process heat applications but not for oil-fired process heaters. FGD
was required for new coal-fired process heaters in petroleum refining
and other selected applications (e.g., reverberatory furnaces) either
when high emissions seemed likely or when stringent sulfur controls
already were required on process equipment. Process-specific environ-
mental control strategies are detailed in Appendix G.
5-20
-------
TABLE 5-7. POTENTIAL NO CONTROL FROM COMBUSTION MODIFICATIONS3
/\
Boiler and Fuel Type Lb/MMBtu (ng/J)b
Natural gas and distillate oil
Firetube 0.06 (26)
Natural gas
Watertube0 0.156 (67)
Distillate oil
Watertubec 0.109 (47)
Residual oil
Firetube 0.067 (29)
Watertube 0.172 (74)
Pulverized coal 0.163 (70)
Spreader stoker 0.316 (136)
Other stokers 0.037 (16)
a Gardner, R.I., et al., pp. 73-79.
Maximum amount of NO emissions removed from flue gas
c With air preheat
5-21
-------
5.4.3 Emission Calculations
Air Emissions: IFCAM projects air emissions for three pollutants -
S02, PM, NO . The level of air emissions is a function of fuel type,
boiler type, and the emission regulation. Uncontrolled emission rates
for all the IFCAM boilers and fuel types are presented in Table 5-2. If
the applicable regulation requires emission reductions for SO^, then the
level of emissions is the following:
Controlled emissions = .9 x (S x (1 - Sc)) + .1 x S
Where S = uncontrolled S02 emissions (ng/J)
Sc = reduction required to meet standard (fraction)
4
This calculation assumes a 90 percent reliability factor for scrubbers.
If the applicable regulation requires emission reductions for
either particulates or NO , the level of emissions is the following:
/\
Controlled PM emissions = (1 - PC) x P
Controlled NO emissions = (1 - Nc) x N
Where P = uncontrol PM emissions (ng/J)
PC = reduction required to meet standard (fraction)
N = Uncontrolled NO emissions (ng/J)
Nc = reduction required to meet standard (fraction)
These calculations assume a 100 percent reliability factor for PM and
NO controls.
J\
Solid Waste: Solid waste factors for boilers and each of the
control technologies that produce solid waste are inputs to IFCAM. For
example, FGD solid waste emissions are determined through a factor
relating input sulfur content of the fuel, input ash content of the
fuel, heating value of the fuel, and amount of S0? and PM emission
5-22
-------
reductions to kilograms of solid waste produced. The level of solid
waste generated is a function of the demand for the control technologies
that produce solid wastes and the types of fuel used.
Water Pollution: Liquid wastes are calculated in a similar fashion
to solid wastes. A liquid waste factor for each of the control technologies
that produce liquid waste is an input to IFCAM. The amount of liquid
waste generated by boilers is a function of the demand for the control
technologies producing liquid wastes.
Emission levels are calculated for each combustor based on their
particular compliance strategy (i.e., fuel type, boiler type, pollution
control). Following individual calculation, emissions are aggregated to
produce regional and national emission levels by fuel type and control
technology.
5.5 OTHER ENVIRONMENTAL REQUIREMENTS
In addition to the NSPS and SIP's discussed in Section 5.3, two
other currently evolving environmental restrictions can influence fuel
choice decisions. The first are restrictions applicable in air quality
problem areas (NA regulations), and the second are regulations applicable
in clean air areas (PSD regulations).
5.5.1 Nonattainment Areas
NA areas are zones in which NAAQS for specified pollutants are
being exceeded. EPA has called for SIP revisions in these areas to
insure that reasonable progress toward air quality goals by legislatively
mandated schedules (1982 or 1987) is achieved.
5-23
-------
NA-related SIP revisions dan vary in type, depending upon the
strategy selected by state and local governments. If air quality pro-
blems result from a few large emission sources, states may require
emission reductions from those sources. Alternatively, states may
require all coal-fired sources within the NA zone to install control
equipment. Another approach could be to require control equipment for
all new sources and purchases of emission reductions (called emission
offsets) from existing facilities equal to or greater than emissions
generated by the new facility.
A limited number of states have revised their SIP's to model NA
requirements. SIP revisions finalized before July 1979 that apply to
the majority of sources within an area are taken into account in the
IFCAM SIP file. This approach to modeling NA-related SIP revisions may
understate the stringency of local regulations.
5.5.2 Clean Air Areas
Outside of nonattainment areas, states are required to insure that
air quality as a consequence of economic growth does not deteriorate
beyond specified increments in air quality levels. New sources with
emissions above a certain level are required to comply with BACT limits
applied on a case-by-case basis considering both cost and energy impli-
cations.
Since PSD rules are applied on a case-by-case or site-specific
basis, PSD regulations have not been modeled in IFCAM. This approach
also may understate the stringency of local regulations, although to a
lesser degree than the more stringent NA rules.
5-24
-------
REFERENCES
1. Fossil Fuel Demand for Stationary - Source Combustion and Other
Selected Data for Each State and Air Quality Control Region. The
Mitre Corp. April 1975. Fuel mix by AQCR is based upon 1971 data
from a Battelle Columbus study performed for EPA.
2. Final Revised Environmental Impact Statement, Coal Conversion
Program, Energy Supply and Environmental Coordination Act (as
amended), Section 2, FES-77-3, May 1977.
3. Gardner, R.I., R. Chang, L.D. Broz. Cost, Energy, and Environmental
Algorithms for NO , SO , and PM Controls for Industrial Boilers.
Acurex Corporation. Morrisville, N.C. Prepared for the Industrial
Environmental Research Laboratory, U.S. Environmental Protection
Agency. December 1979. p. A-2.
4. Letter and attachments from Hargrove, O.W., Radian Corporation
to Mobley, J.D., EPA. February 26, 1980. Industrial boiler
control technology reliability.
5. Gardner, R.I., et al., Op. Cit.
6. Ibid.
5-25
-------
6. ECONOMICS OF THE FUEL CHOICE DECISION
6.1 INTRODUCTION
The basic approach for estimating the future industrial fuel mix is
to "create" individual combustors, make fuel choice decisions for each
combustor, and aggregate the results. Sections 2 and 3 discuss the
creation of the industrial combustor population. The technical and
environmental constraints limiting the available, alternatives are discussed
in Sections 4 and 5. This section details the economics of the fuel
choice decision.
This section is organized into two parts. First, the capital and
annual non-fuel O&M and fuel costs are discussed. Data sources and
major assumptions are outlined. Second, the investment decision frame-
work is summarized and sample cost calculations and comparisons are
presented.
6.2 COST COMPONENTS
6.2.1 Capital Costs
This section examines the components of capital cost estimates, the
methodology used to derive cost estimates, and the nature of data sources
used. Capital costs are discussed separately for new and existing
boilers; capital cost estimates for process heaters are discussed in
Appendix G. More detail concerning exact components of boiler capital
cost, cost algorithms, and data sources is presented in Appendix F.
6-1
-------
All costs are expressed as 1978 dollars. Capital costs are assumed
not to increase in real terms over time, and installation expenses are
assumed not to vary by region.
6.2.1.1 New Boiler Costs
Boiler cost calculations are based on costs for a single boiler
installation. This assumption tends to overstate costs for cases in
which several boilers are sited at one plant, since plant economies of
scale for fuel handling and environmental control equipment are not
taken into account. Boilers can be purchased in several different types
and sizes, and boiler design and costs are influenced primarily by the
following parameters:
Fuel type
Steam quality
Firing method
Capacity.
There are seven standard boiler sizes in IFCAM. Table 6-1 summarizes
key assumptions in each boiler size class. Costs and emissions rates
vary significantly by boiler type and firing method. All new firetube
boilers are assumed to be single-fuel fired. All new watertube oil and
gas boilers are assumed to be dual-fuel fired.
Large oil and gas boilers are assumed to be multiple (two) package
units as opposed to a single field-erected unit. Since multiple package
units are significantly less expensive than single field-erected units,
this assumption biases economics of the fuel choice decision in favor of
oil and gas use in large new boilers.
6-2
-------
TABLE 6-1. IFCAM BOILER SIZE/TYPE ASSUMPTIONS
Boiler Size Category
MW (MMBtu/hr)
Range
2.93-8.79
(10-30)
8.79-14.65
(30-50)
14.65-21.98
(50-75)
21.98-29.3
(75-100)
29.3-51.28
(100-175)
51.28-73.25
(175-250)
>73.25
(>250)
Representative
Size
5.86
(20)
11.72
(40)
18.17
(62)
»
25.49
(87)
40.14
(137)
62.12
(212)
95.23
(325)
Coal
package,
watertube,
underfeed
stoker
package,
watertube,
underfeed
stoker
field-erected,
watertube,
chain grate
stoker
field-erected,
watertube,
spreader stoker
field-erected
watertube,
spreader stoker
field-erected,
watertube,
pulverized
coal
field -erected,
watertube,
pulverized coal
Type
Residual Oil/
Natural Gas
package,
firetube
package,
watertube
package,
watertube,
package,
watertube
package,
watertube
two package
watertube
two package,
watertube
Distillate Oil/
Natural Gas
package
firetube
package,
watertube
package,
watertube
package,
watertube
package,
watertube
two package,
watertube
two package,
watertube
Chain grate stoker emission rates with spreader stoker capital and O&M
cost estimates.
6-3
-------
Boiler costs were developed and translated into cost algorithms by
PEDCo Environmental, Inc. The major components of boiler capital costs
are listed below:
Equipment
- boiler
- auxiliary equipment such as instrumentation, pumps, fuel
handling, ash disposal, and water treatment
Direct installation cost
Indirect installation cost
- engineering
- construction fees
- start-up
Other
- contingencies
- working capital.
6.2.1.2 Existing Boiler Capital Costs
Costs for converting existing boilers from one fuel to another are
calculated for two classes of existing boilers: those originally designed
to fire coal that currently are using oil or gas, and those originally
designed to fire only oil or gas. Conversion to any fuel but coal will
involve the same costs for both classes.
The cost of converting coal-capable boilers (those originally
designed to fire coal) is related to the operational status of equipment
needed to burn coal. When the boiler currently is using some coal,
conversion can simply comprise eliminating further oil or gas use. At
the other extreme, conversion of a coal-capable boiler that never actually
6-4
-------
fired coal would require installing pollution control and all coal-related
auxiliary equipment.
Retrofit costs for conversions from gas, residual oil, or distillate
oil to gas, residual oil, or distillate oil were evaluated for nine
unique retrofit combinations.
6.2.1.3 Environmental Control Equipment
The available pollution' control technologies are presented in
Section 5. These technologies include:
Flue gas desulfurization systems
Particulate control equipment
Combustion modifications to control NO emissions.
4\
Detailed cost equations have been developed, and cost summaries are
included in Appendix F. These cost equations estimate capital expenses
for specific applications: fuel type, boiler size, and required percentage
reduction.
6.2.2 Operating Costs - Non-Fuel
O&M costs (exclusive of fuel) include costs related to the combustor,
environmental controls, and fuel handling. Annual O&M cost estimates
include labor, materials, utilities, overhead, general and administrative
costs, taxes, insurance, and interest on working capital. Annual O&M
costs are expressed as 1978 dollars and are assumed not to increase in
real terms over time or vary by region. Boiler-related and pollution
control O&M costs are summarized in Appendix F. Process heat O&M costs
are presented in Appendix G.
-------
6.2.3 Sample Boiler and Pollution Control Costs
Sample boiler and pollution control capital and annual O&M expenses
are presented in Appendix F. Table 6-2 compares cost estimates for six
fuel types. Distillate fuel oil is not shown because its costs are
similar to natural gas cost estimates. Only one of four residual oil
types is summarized,* and only four of the 39 coal types in IFCAM are
represented. Characteristics of the four coal types listed in Table 6-2
are summarized in Table 6-3.
The environmental regulation assumptions used to develop the pollu-
tion control costs are shown in Table 6-4. These regulations require
FGD systems on high sulfur oil and coal types, particulate control equip-
ment on all residual oil and coal types, and NO control on all fuel
types for a small watertube industrial boiler.
The pollution control costs listed in Table 6-2 represent potential
compliance strategies with the regulations summarized in Table 6-4.
There are other compliance strategies for S0? and PM control for coal-
fired boilers:
The eastern and midwestern high sulfur coal types can select a
double alkali system with one of the four types of particulate
control equipment or a sodium spray drying FGD system.
The eastern low sulfur coal type can also select from one of
the other particulate control types.
The selection of the least cost control strategy for each coal type
depends on the comparison of the total capital and annual non-fuel O&M
*Boiler and NO control costs do not vary by type of residual fuel
oil. However, S09 and PM control costs do vary by type of residual fuel
oil. *
b-6
-------
TABLE 6-2. SAMPLE BOILER AND POLLUTION CONTROL COSTS0
(000 $1978)
Cost
Component
Capital:
Boiler- related
Pollution Control
C/"\O
i>02
PM
M/"\ V*
NOx
TOTAL
Annual non-fuel O&M:^
Boiler- related
Pollution Control
f* f\ 1
S02
PM
fci/\ . .
NOx
TOTAL
Natural
Gas
1,438
0
0
26
1,464
381
0
0
52
433
Residual.
Fuel Oil0
1,461
0
145f
19
1,625
382
0
-.gf
-18h
380
Eastern High
Sulfur Coal
5,013
1,179C
0
103
6,295
806
458C
0
10
1,274
Eastern Low
Sulfur Coal
4,690
341d
488e
103
5,621
786
224d
55e
10
1,075
Midwestern High
Sulfur Coal
4,917
1 111°
0
103
6,131
794
372C
0
10
1,176
Western Low
Sulfur Coal
5,374
0
499e
103
5,976
809
0
48e
10
867
-------
TABLE 6-2. SAMPLE BOILER AND POLLUTION CONTROL COSTS
(000 $1978)
(continued)
a 25.5 MW (87 MMBtu/hr) heat input
0.8 percent sulfur
Lime spray drying system (includes a fabric filter) and simultaneously controls S02 an emissions
Double alkali system
00 6 r , -- n .
Fabric filter
f ESP
^ 55 percent capacity utilization rate
Negative, represents a net credit, fuel savings
-------
TABLE 6-3. SAMPLE COAL TYPES
MAJOR CHARACTERISTICS
Coal Type
Eastern
Eastern
High Sulfur
Low Sulfur
°' Midwestern High Sulfur
Western
Low Sulfur
Lbs.
Per
6.
1.
3.
0.
SO,
MMBtu
0
25
78
87
ng S02
per J
2,580
537
1,625
374
Percent
Sulfur0
3
0
2
0
.28
.83
.18
.39
Percent
Ash6
22.
10.
7.
3.
7
7
6
5
Heating
Btu/lb
10,934
13,308
11,563
8,901
Value0
kJ/kg
25,
30.
26,
20,
432
954
896
704
A complete list of all IFCAM coal types is presented in Table 6-5
Wet basis
-------
TABLE 6-4. SAMPLE ENVIRONMENTAL REGULATIONS3
(ng/J (Ibs./MMBtu))
Natural Residual
Pollutant Gas Fuel Oil
S02 - 387 ( 0.9)
PM - 13 (0.03)
N0₯ 64 (0.15) 129 ( 0.3)
^
Coal
516 ( 1.2)
21 (0.05)
129 ( 0.3)
Annual averaging period.
b-iO
-------
costs for each alternative control strategy for S02 and PM emissions
control:
Lime spraying drying
Sodium spray drying
Double alkali FGD system
- ESP
- fabric filter
- wet scrubber
- mechanical collector
One of the four types of particulate control equipment if
post-combustion control of SO^ emissions is not required.
The boiler-related and pollution control costs for coal units do vary
significantly by type of coal. FGD systems also substantially increase
the total capital and operating costs.
NO combustion modification techniques do alter boiler efficiencies
/\
because air and fuel flow controls may be changed. This is considered
in the fuel choice decisions by increasing or decreasing the NO control
annual non-fuel O&M costs. In some cases, increased efficiencies result
in fuel cost savings that are larger than the labor and material expenses
associated with the NO control technique, and the net annual non-fuel
/\
NO control O&M cost is negative (see Table 6-2 for residual fuel oil).
/\
6.2.4 Fuel Costs
Fuel costs significantly affect fuel choice decisions because they
contribute as much to the total annualized cost of a unit as annual
non-fuel O&M expenses and account for regional variations in fuel choice
decisions for similar units. Coal, for example, will be selected only
6-11
-------
if fuel cost savings will be sufficient to offset the higher capital and
operating costs associated with coal utilization.
Projected regional fuel prices are exogenous inputs to IFCAM. The
primary source is MEFS. This section will focus on the key issues
associated with fuel price projections.
6.2.4.1 Fuel Types
IFCAM uses the following fuel types:
0 Natural gas
Distillate fuel oil
Four residual fuel oil types
- 3.0% sulfur
- 1.6% sulfur
- 0.8% sulfur
- 0.3% sulfur
39 coal types (see Table 6-5 and Figure 6-1)
- 23 raw coals
- 16 physically cleaned coals.
6.2.4.2 Oil Price Projections
MEFS projects an average residual oil price for all grades and does
not distinguish between high and low sulfur fuel types.* A categorization
of fuel by sulfur content, however, is important because there is a
significant price premium associated with low sulfur fuel oil. The
price given for an average residual fuel oil is too expensive for the
boiler in which environmental regulations permit the burning of high
sulfur residual fuel oil without a scrubber to control SOp emissions.
The price also is not representative for boilers that must scrub high
DOE currently is adding residual oil sulfur classes to MEFS.
6-12
-------
TABLE 6-5. COAL CHARACTERISTICS
O'l
Supply
Region
ng S02
per J
Lbs. SO,
Per MMBtu
% Sulfur %
Dry
Wet
Dry
Ash
Wet
HHV Dry
kJ/kg
Btu/lb
HHV, Wet %
kJ/kg
Btu/lb
Moisture
*
Northern
Appa-
lachia
Central
Appa-
lachia
Southern
Appalachla
2579.53
1466.03*
988.03
1620.81
984.52*
1182.29
739.47*
735.17
580.39*
2166.81
1526.22*
1741.18
1263.92*
1190.88
760.77*
743.77
558.40*
537.40
494.41*
528.80
455.72
975.92
6.0
3.41*
2.3*
3.77
2.29*
2.75
1.72*
1.71
1.35*
5.04
3.55*
4.05
2.94*
2.77
1.77*
1.73
1.30*
1.25
1.15*
1.23
1.06*
2.27
3.45
2.21
1.57
2.5
1.6
1.86
1.22
0.92
0.82
2.95
2.31
2.7
2.0
1.56
1.24
1.18
0.94
0.87
0.83
0.85
0.75
1.6
3.28
2.01
1.38
2.47
1.56
1.79
1.10
0.91
0.76
2.88
2.22
2.64
1.96
1.52
1.16
1.15
0.85
0.83
0.76
0.82
0.67
1.51
23.9
14.4
9.7
11.7
10.3
12.8
8.7
28.7
19.9
23.1
15.5
13.5
12.6
25.9
9.7
10.4
4.7
11.2
8.1
10.9
9.5
7.6
!
22.7
13.1
8.5
11.5
10.0
12.4
7.9
28.4
18.5
22.6
14.9
13.2
12.4
25.2
9.1
10.2
4.3
10.7
7.5
10.6
8.6
7.2
26,772
30,171
31,876
30,866
32,471
31,420
32,887
25,005
28,079
27,186
30,243
30,982
31,587
26,226
32,471
31,685
33,697
32,310
33,453
32,203
32,783
32,797
11,510
12,971
13,704
13,270
13,960
13,508
14,139
10,750
12,072
11,688
13,002
13,320
13,580
11,275
13,960
13,622
14,487
13,891
14,382
13,845
14,094
14,100
25,432
27,400
27,954
30,464
31,594
30,319
29,829
24,753
26,142
26,589
29,063
30,301
31,043
25,516
30,554
31,052
31,136
30,954
30,978
21,238
30,994
30,994
10,934
11,778
12,018
13,097
13,583
13,035
12,824
10,642
11,239
11,431
12,495
13,027
13,346
10,970
13,136
13,350
13,386
13,308
13,318
13,430
12.699
13,325
5.0
9.2
12.3
1.3
2.7
3.5
9.3
1.0
6.9
2.2
3.9
2.2
1.7
2.7
5.9
2.0
7.6
4.2
7.4
3.0
9.9
5.5
*Cleaned Coal.
-------
TABLE 6-5. COAL CHARACTERISTICS
(Continued)
I
I"
4i>
Supply
Region
Midwest
Central
West
Western
No. Great
Plains
Rockies
South-
west
ng S09
per J^
3826.31
2295.78*
2042.13
1276.87*
1182.29*
1625.11
997.42
5606.18
3435.08*
2575.23
1074.81
717.97
374.03
795.36
546.00
503.01*
694.18
Lbs. SO,
Per MMBtu
8.9
5.34*
4.75
2.97*
2.75*
3.78
2.32
13.04
7.99*
5.99
2.5
1.67
0.87
1.85
1.27
1.17*
1.51
% Sulfur
Dry
4.35
3.30
2.88
1.99
1.85
2.5
1.5
5.22
4.05
4.17
1.4
1.0
0.5
1.2
0.8
0.75
0.9
Wet
4.0
3.06
2.70
1.84
1.72
2.18
1.38
4.74
3.67
3.95
1.3
0.81
0.39
1.16
0.76
0.70
0.80
% Ash
Dry
29.9
11.4
16.4
7.5
7.1
8.7
10.5
27.2
8.0
5.2
10.4
9.8
4.6
6.5
11.6
10.0
11.3
Wet
27.5
10.6
15.4
6.9
6.6
7.6
9.7
24.7
7.3
4.9
9.4
7.9
3.5
6.3
11.0
9.5
10.1
HHV Dry
kJ/kg
22,753
28,773
28,191
31,185
31,317
30,773
30,075
18,634
23,546
32,480
26,191
27,912
26,889
31,122
29,354
29,657
27,889
Btu/lb
9,782
12,370
12,120
13,407
13,464
13,230
12,930
8,011
10,123
13,964
11,260
12,000
11,560
13,380
12,620
12,750
11,990
HHV, Wet
kJ/kg
20,932
26,672
26,500
28,752
29,187
26,896
27,670
16,901
21,357
32,369
23,572
22,553
20,704
30,033
27,917
28,056
24,821
Btu/lb
8,999
11,467
11,393
12,361
12,548
11,563
11,896
7,266
9,182
13,916
10,134
9,696
8,901
12,912
12,002
12,062
10,671
%
Mo i s tu re
8.0
7.3
6.0
6.8
12.6
8.0
9.3
9.3
5.5
14.2
19.2
23.0
3.5
4.9
5.4
11.0
*Cleaned Coal.
-------
FIGURE 6-1 COAL SUPPLY REGIONS
v MKHiHI)
III I inn I nous Con I
^ .Suli-DltiiirtlnoiisCoa
/iiyy i.i i>ni te
I AIII hrnc I to
Northern A|i|talaclila
Central Apnnlnchln
Soiitliern Appoint-Ill H
Midwest
Central West
Cu If
Pastern Northern Great I'lnlns
Western Northern Great Mains
Hock Ios
Southwest
Northwest
Alaska (not shown)
Source:
II. .'!. Cooln|i|cnl Siirvoy Diillctln HI2
Con I Itcsmircus of Clio lliill«:tl States. .Ininuiry , I . I!I7
-------
sulfur residual fuel oil or burn low sulfur residual fuel oil to comply
with environmental standards.
MEFS residual oil price projections are representative for a 0.8 per-
cent sulfur oil type. Sulfur premiums have been developed to estimate
the relative prices for the other three residual oil types in IFCAM.
These assumptions are discussed in Appendix I.
6.2.4.3 Coal Price Projections
The methodology for determining coal prices was to estimate a base
price of coal in each supply region and the sulfur premiums. The sulfur
premium associated with each raw coal was added to this base price. The
prices of the cleaned coals were calculated by adjusting the price of
the feed coals by the cleaning costs. The raw and cleaned coal prices
were also marked-up by a factor to represent spot market rates.
Two major data sources were used to develop the FOB mine prices for
the 23 raw coals: the MEFS and the National Coal Model (NCM). To be
consistent with the other fuel prices used in IFCAM, the MEFS coal
prices were used to determine the base price for each supply region, and
later, to normalize the sulfur premiums. The NCM sulfur classes were
used to provide a finer degree of distinction for determining the price
premiums associated with lower sulfur coals. Eight sulfur classes were
available by using the NCM coal types as compared to three sulfur classes
(high, medium, and low) from the MEFS output. The NCM coal prices were
preferred, therefore, for estimating sulfur premiums. The coal prices
from both models were representative of contract prices for the utility
6-16
-------
sector. This necessitated a mark-up for spot market prices for the
industrial sector.*
Data on coal cleaning costs and characteristics were developed by
Versar, Inc. Processing costs, Btu losses, and solid waste disposal
costs were accounted for in this analysis.**
These F.O.B. mine coal prices can be translated into delivered
prices with the addition of transportation costs. Transportation costs
are based on single-car rail rates applicable to actual distances between
the coal supply centers and a centroid delivery point within each of the
10 demand regions (see Table 6-6). This method of calculating tranportation
costs will tend to overstate delivered coal prices where:
Plants are located near navigable waterways and barge deliveries
are less expensive
Coal volumes are sufficient to justify multiple-car or annual
volume discounts
Plants are located near demand region boundaries and are
closer to supply centers than the chosen demand region centroid.
Transportation charges will be understated for those plants located over
distances farther than the delivery point used for estimation.
6.3 INVESTMENT DECISION APPROACH
6.3.1 Decision Criteria
The fuel choice decision framework in IF:CAM is based on the premise
that industry will try to minimize the total costs of generating
* For a further discussion, see Appendix I.
** Cost estimates are presented in Appendix F.
6-17
-------
TABLE 6-6 1985 INDUSTRIAL COAL TRANSPORTATION COSTS'
(1978 $/megagram (1978 $/short ton))
Supply Region
Demand
Region
NE
NY/NY
MA
SA
HW
SW
C
NC
W
NW
Northern
Appalachia
21.
15.
11.
18.
13.
24.
18.
33.
68.
63.
08(19.16)
00(13.64)
15(10.14)
21(16.56)
11(11.92)
33(22.12)
83(17.12)
92(30.84)
20(62.00)
94(53.14)
Central
Appalachia
20.94(19.04)
14.87(13.52)
11.02(10.02)
10.78 (9.80)
11.90(10.82)
24.20(22.00)
13.29(12.08)
28.38(25.80)
63.62(57.84)
59.80(54.36)
Southern
Appalachia
32.16(29.24)
26.09(23.72)
22.24(20.22)
6.18(5.62)
15.62(14.20)
21.52(19.56)
17.01(15.46)
32.10(29.18)
65.38(59.44)
63.51(57.74)
Midwest
26.68(26.98)
t
23.61(21.46)
19.76(17.96)
16.39(14.90)
7.28 (6.62)
19.58(17.80)
8.67 (7.88)
23.76(21.60)
59.00(53.64)
55.18(50.16)
Central
West
37.
31.
27.
20.
9.
14.
2.
17.
52.
55.
64(34.22)
57(28.70)
72(25.20)
39(18.54)
66 (8.78)
72(13.38)
44 (2.22)
53(15.94)
78(47.98)
29(50.26)
Western North
Great Plains
59.44(54.04)
53.37(48.52)
49.52(45.02)
42.20(38.36)
30.45(27.68)
29.81(27.10)
25.08(22.80)
9.99 (9.08)
45.23(41.12)
34.23(31.12)
Rockies
59.44(54.04)
53.37(48.52)
49.52(45.02)
42.20(38.36)
31.46(28.60)
28.58(25.98)
23.85(21.68)
8.76 (7.96)
31.20(28.36)
37.45(34.08)
Southwest
67.
61.
58.
41.
40.
22.
32.
17.
41.
57.
65(61.50)
58(55.98)
28(52.48)
67(37.88)
02(36.38)
07(20.06)
41(29.46)
31(15.74)
62(37.84)
18(51.98)
DOE Midterm Energy Forecasting System. Estimates of single-car rail rates.
-------
steam or heat over the useful life of-the facility. Specifically,
decision-makers will tend to select that fuel with the lowest after-tax
net present value (NPV) of the cash outflows for operating, maintenance,
fuel and capital costs.
For a given set of fuel prices and government policies (energy,
environmental, and tax), IFCAM selects the least cost fuel type for each
boiler record by:
Choosing the least cost pollution control strategy for each
coal type
Adding the NPV of the discounted cash flows for capital, O&M,
and fuel expenses and selecting the least cost coal type
Repeating same procedure for residual fuel oil, distillate
fuel oil, and natural gas
0 Comparing total cost (capital, O&M, and fuel) of each alternative:
coal, residual oil, distillate oil, and natural gas
Selecting the least cost fuel type.
The above simplied assumption of IFCAM1s least cost decision process
can be modified to incorporate such government policies as PIFUA. As
currently interpreted, the act requires a new boiler greater than 100
MMBtu/hr to use coal unless that boiler can pass an economic test ratio
of 1.3.* More specifically, the total cost** of a coal-fired boiler must
be 30 percent greater than that of a high sulfur residual oil boiler
before it can qualify for an economic exemption from mandatory coal
use.
* Some new boilers with firing rates between 50 and 100 MMBtu/hr are
also subject to PIFUA regulations, but IFCAM does not apply coal
conversion policies to these units. Also existing coal-capable
boilers which are currently burning oil or gas are also subject to
these provisions.
** Annualized capital, O&M, and fuel.
-------
IFCAM has simulated this economic test in its least cost decision methodoV
ogy; however, IFCAM is not constrained to a simple ratio test. For
example, a tax on oil also could be used in IFCAM to discourage oil use
and encourage greater coal use.
Figure 6-2 summarizes the major steps in the fuel choice decision.
If the unit is not subject to the Fuel Use Act policies, the least cost
fuel type is calculated as described above. If the unit is subject to
Fuel Use Act regulations, the next step is to determine if it qualifies
for an economic exemption as described above. The Fuel Use Act policies
for qualifying for an economic exemption may be different than the
standard procedure for comparing total costs (e.g., discount rates or
fuel prices). Therefore, it may be necessary to calculate the least
coal type without using Fuel Use Act guidelines if the boiler does not
qualify for an economic exemption.
Figure 6-3 outlines the major steps in selecting the least cost
coal type. A similar sequence of steps is followed for selecting the
least cost oil type. Each boiler in the population has special charac-
teristics which are discussed in Section 4. The boiler costs and envi-
ronmental control requirements are functions of some of these parameters.
In addition, the boiler costs and percentage removal requirements are
unique for each coal type.
The applicable SIP and NSPS regulations are compared to determine
the most stringent regulation for SCL, PM and NO emissions. The least
£ /\
cost control strategy is calculated for each coal type. The total
b-20
-------
FIGURE 6-2 MAJOR STEPS IN FUEL CHOICE DECISION
NO
IS
BOILER
SUBJECT
YES
CALCULATE TOTAL ANNUALIZED
COSTS FOR COAL AND OIL AL-
TERNATIVES, AND SELECT LEAST
COST COAL AND OIL TYPES
V
CALCULATE LEAST
COST FUEL TYPE
YES
DOES BOILER
QUALIFY FOR
AN ECONOMIC
EXEMPTION?
NO
CALCULATE LEAST COST COAL
TYPE WITHOUT USING FUA
GUIDELINES
5-21
-------
FIGURE 6-3 MAJOR STEPS IN SELECTING LEAST COST COAL TYPE
Boiler
Population
EXAMPLE BOILER
Coal Boiler Capital
and Annual Non-Fuel
0 S M Costs
BOILER COSTS
FOR EACH COAL TYPE
39 COAL TYPES
Regulatory Requirements
(Coal)
Pollution Control
Costs
TEST CASE NSPS
DETERMINE MOST STRINGENT
SO,, PM, NO REGULATION
CALCULATE % REMOVAL REQUIREMENT
FOR EACH COAL TYPE AND POLLUTANT
T
CALCULATE CAPITAL AND ANNUAL
NON-FUEL 0 6 M COSTS FOR EACH
FGD SYSTEM, AND ESP, FF, WET
SCRUBBER AND MECH. COL.
ANNUALIZE CAPITAL
AND 0 S M COSTS
CALCULATE CAPITAL AND ANNUAL
NON-FUEL 0 5 M COSTS FOR NO
CONTROL
SELECT LEAST COST
COMBINED SO,/PM
CONTROL OPTION
ANNUALIZE CAPITAL
AND 0 5 M COSTS
Least Cost
Coal Type
CALCULATE TOTAL ANNUALIZED CAPITAL AND ANNUAL
NON-FUEL 0 S M COST (BOILER S POLLUTION CONTROL)
FOB MINE COAL PRICES, COAL CLEANING
COSTS, RAIL RATES
COMPARE TOTAL ANNUALIZED COSTS ANT) SELECT LEAST
COST COAL TYPE
6-22
-------
annual ized capital and non-fuel O&M costs for the boiler and all pollution
control equipment are added to the annual ized delivered coal price (the
sum of F.O.B. mine plus coal cleaning plus transportation costs) for
each of the 39 coal types and the least cost coal type is selected.
6.3.2 Overview of NPV Calculations
A conventional NPV approach is used to calculate the total after-tax
cost of steam or process heat. The components of this calculation,
using coal as an example fuel, include:
PO. - the cost of coal burned in the facility in year t
OC. - the operating costs of using coal in year t
OK - the total capital cost of the coal facility
OKt - the capital cost of the coal facility expensed in year t
0. - depreciation expense on capital in year t
e - the share. of capital cost which can be expensed (does
not form the base for capital depreciation)
T - the marginal tax rate
ITC - the allowable percentage investment tax credit
i - the discount rate
UL - the useful life of the investment
CP - the construction period for the facility
L - the life used for the NPV calculation (where L=UL+CP).
The following illustrates how these components are used to determine the
present value of energy costs for coal.
L (
^J.
NPV (coal) = (1+1t
t=l
6-23
-------
The decision to select residual oil, for example, will be made if:
NPV(coal) > max (NPV(gas), NPV(dist.), NPV(resid.)}*
6.3.3 Components of NPV Calculation
6.3.3.1 Fuel Prices, Operating Costs, and Capital Costs
For a discussion of the derivation of fuel and combustor type
specific costs, please refer to previous portions of this section.
6.3.3.2 Expensible Construction Costs
A portion (10 percent) of equipment and facility construction costs
are considered expensible in IFCAM. These expensible costs, allowable
deductions for income tax purposes, are excluded from the depreciable
capital cost. Expensible costs normally are higher than initial engineering
costs. They can vary for each case depending on the amount of work done
in-house and the portion of turnkey costs (i.e., total package delivered
to the fuel user). The estimate that 10 percent of construction costs
are expensible is assumed to be typical, based on discussions with
equipment vendors. It is also assumed to be expensed in the first year.
6.3.3.3 Construction Period
This period refers to the interval when capital expenditures are
being incurred for facility construction, and no fuel is being burned.
This period is assumed to be two years for all boilers and one-two years
for process heaters, depending upon the particular application. Although
package boilers can be installed more rapidly than field-erected boilers,
Since the NPV is always negative, the largest NPV is the least expensive
alternative.
6-?4
-------
the bias introduced by the longer construction period of field-erected
boilers is offset roughly by the shorter useful life of package boilers.
6.3.3.4 Depreciation
Depreciation can be calculated using straight line, sum-of-years-
digits, or declining balance methods. The ETA permits investments in
coal facilities to be depreciated using accelerated methods while requiring
investments in new oil or gas boilers to be depreciated using a straight-
3
line method. As a result, all investments in process heat equipment
and coal boilers are depreciated using sum-of-years-digits depreciation.
The depreciable life is assumed to be 22 years for new coal boilers
and 28 years for new oil/gas boilers.* Depreciable lives for process
heat equipment are based on the "asset guideline period" which apply to
specific industrial applications.
6.3.3.5 Investment Tax Credit
The ITC rate is distinguished by fuel type in order to analyze
specific policy options related to different fuel types. The Energy Tax
Act provides several tax incentives for the use of coal and alternative
fuels. This legislation authorizes an additional 10 percent investment
tax credit (ITC) for coal and alternative fuel investments made between
October 1, 1978 and December 31, 1982 for the following:
Boilers and other combustors
Equipment to produce alternative fuels
* This assumes that coal boiler investments qualify to use the lower
limit of the asset depreciation range for industrial steam systems
and that oil/gas boiler investments must use the asset guideline
period .
-------
Pollution control equipment
Fuel handling and storage equipment.
However, since authorization expires in 1982, the additional ITC is not
normally modeled. Coal investments qualify for the normal 10 percent
ITC, and investments in new oil/gas boilers are denied the normal ITC.
6.3.3.6 Corporate Tax Rate
A tax rate of 50 percent is used to reflect the marginal corporate
Federal and State tax rate for investment decisions. This assumes that
corporations' earnings are sufficient to make this maximum tax rate
relevant for fuel choice decisions.
6.3.3.7 Discount Rate
A discount rate is the expression of the time value of capital used
in equivalence calculations comparing alternatives. This rate is essen-
tially a value judgement based on a compromise between present consumption
(i.e., distribution of profits to stockholders) and capital formation.
The discount rate represents the required rate of return; that rate at
which stockholders are indifferent between this and their next best
investment opportunity. Traditionally, the required rate of return
simply has meant the cost of capital. If an investment does not pay for
itself plus the charges incurred to finance the project, a firm is
better off not making the investment. In this analysis, the average cost
of capital and an investment priority scheme are accounted for explicitly.
The discount rate in IFCAM represents the average real after-tax
cost of capital, not nominal. Currently, IFCAM uses two discount rates
5-26
-------
for new units, eight percent for those units less than 100 MMBtu/hr and
7.7 percent for those units greater than 100 MMBtu/hr that are subject
to PIFUA.6
As discussed above, industrial investment decision-makers commonly
distinguish between discretionary investments, which are intended to
reduce costs, and required investments, which are intended to maintain
or expand market share or to fulfill legal obligations. According to
these definitions, investments to retrofit existing units to achieve
cost savings are classified as discretionary. Production could be
maintained with the existing oil- or gas-fired combustor since the only
purpose of converting to another fuel type would be to reduce costs. In
reality, the priority given to required over discretionary investment
would depend on capital availability and the payback on discretionary
investments, factors that vary from one company to another. The effect
of this investment priority has been simulated roughly in IFCAM by
raising the discount rate for retrofit (fuel switching) decisions by 50
percent, from eight to 12 percent on a real after-tax basis.
6.3.3.8 Useful Life of the Investment
i
The useful life of the investment for new boilers is assumed to be
28 years. For process heat applications, the useful life varies over a
wide range.*
Estimates of the physical life of new boilers range from 20 years
for package units to 45 years for large field-erected units. Due to
* See Appendix G.
6-27
-------
the discounted cash flow decision criteria, depreciation costs and
annual O&M and fuel expenses contribute relatively little to the total
NPV for periods longer than 20 years. Therefore, a single investment
period for all boiler fuel choice decisions is not expected to seriously
bias the analysis. Similarly, pollution control equipment often do not
have useful lives as long as 28 years. IFCAM currently does not increase
capital cost estimates to reflect the replacement of pollution control
equipment.
Retrofit decisions, however, are assumed to be made over a relatively
short investment period (five years). This is less than the remaining
useful lives of existing equipment. The purpose of this assumption is
to capture a short payback period usually required for retrofit invest-
ments and to simulate the retrofit in the correct year. For example, if
the remaining life was 15 or 20 years, there may be sufficient fuel cost
savings to encourage the conversion. However, it may be more economical
to convert the unit in five or 10 years, not today, because the fuel
price of the current fuel is not estimated to become more expensive than
the fuel price of the alternative fuel type for another five or 10
years.
6.3.4 Sample Calculation
In this subsection, a sample calculation is presented to illustrate
the model's approach in simulating investment decisions. Cost data
summarized in Section 6.2.3 and standard financial assumptions discussed
in Section 6.3.3 are employed. Investment alternatives for one new
boiler decision are compared.
6-28
-------
6.3.4.1 -Approach
The sample boiler is a 25.5 MW (87 MMBtu/hr) heat input unit with
an expected capacity utilization rate of 55 percent. The sample environ-
mental regulations and pollution control costs are summarized in Table 6-4.
The financial parameter assumptions for this sample calculation are
listed in Table 6-7. Table 6-8.illustrates the procedure for calculating
the after-tax NPV for a capital investment in a new coal facility. For
every dollar invested as a capital expense, the after-tax NPV is 0.5869
dollars.
The after-tax NPV for annual non-fuel O&M expenses is calculated
similarly. For years two through 30, the total annual non-fuel O&M
expense is the only cash flow each year. This cash flow is discounted,
and the cumulative cash flow is calculated. Annual non-fuel O&M expenses
are not considered during the first two years because that time represents
the construction period and the boiler is not assumed to be in operation
during this period. Since annual non-fuel O&M costs are not assumed to
increase over time, a factor representing the after-tax NPV for every
dollar spent as an annual non-fuel O&M expense can be calculated similarly
to that shown in Table 6-8 for capital expenses (see Table 6-9).
For illustrative purposes, the sample cost calculation will be
presented as an annualized cost over the 30-year investment period. The
after-tax NPV can be converted to an annualized cost by multiplying the
after-tax NPV by a capital recovery factor. In this case, with an eight
percent discount rate and a 30-year investment period, the capital
6-29
-------
TABLE 6-7. FINANCIAL PARAMETER ASSUMPTIONS FOR
SAMPLE COST COMPARISON
Financial Parameter
Coal
Oil/Gas
Depreciation method
Sum-of-Years-Digits Straight Line
Depreciation period (years)
ITC (percent)
Tax rate (percent)
Discount rate (percent)
Investment period (years)
22
10
50
8
30a
28
0
50
8
30a
Two year construction period and 28 years of operation.
-------
TABLE 6-8. SAMPLE AFTER-TAX NPV CALCULATION FOR CAPITAL EXPENSES'
CTi
I
OJ
Year
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
Depreciation
(0.0391)
(0.0374)
(0.0356)
(0.0338)
(0.0032)
(0.0302)
(0.0285)
(0.0267)
(0.0249)
(0.0231)
(0.0213)
(0.0196)
(0.0178)
(0.0160)
(0.0142)
Expensible Capital . Cash
Construction Investment ITC Flow
0.0500 0.4500 (0.0450) 0.4550
0.4500 (0.0450) 0.4050
(0.0391)
(0.0374)
(0.0356)
(0.0338)
(0.0320)
(0.0302)
(0.0285)
(0.0267)
(0.0249)
(0.0231)
(0.0213)
(0.0196)
(0.0178)
(0.0160)
(0.0142)
Discounted
Cash Flow
0.4550
0.3750
(0.0335)
(0.0297)
(0.0262)
(0.0230)
(0.0202)
(0.0176)
(0.0154)
(0.0134)
(0.0115)
(0.0099)
(0.0085)
(0.0072)
(0.0061)
(0.0050)
(0.0041)
Cumulative
NPV
0.4550
0.8300
0.7965
0.7668
0.7406
0.7176
0.6974
'0.6798
0.6644
0.6510
0.6395
0.6296
0.6211
0.6139
0.6078
0.6028
0.5987
-------
TABLE 6-8. SAMPLE AFTER-TAX NPV CALCULATION FOR CAPITAL EXPENSES'
(continued)
Year
18
19
20
21
22
23
24
. Expensible Capital .
Depreciation Construction Investment
(0.0125)
(0.0107)
(0.0089)
(0.0071)
(0.0053)
(0.0036)
(0.0018)
Cash
ITC Flow
(0.0125)
(0.0107)
(0.0089)
(0.0071)
(0.0053)
(0.0036)
(0.0018)
Discounted
Cash Flow
(0.0034)
(0.0027)
(0.0021)
(0.0015)
(0.0011)
(0.0007)
(0.0003)
Cumulative
NPV
0.5953
0.5926
0.5905
0.5890
0.5879
0.5872
0.5869
Capital investment is 1.0. This table assumes the financial parameters listed in the "Coal" column on Table 6-7.
(1-tax rate)*D. - D., or ~Dt/2. Only 90 percent of the total capital investment is assumed to be depreciable.
(1-tax rate) * 0.1* Capital investment, or 0.5 * 0.1 * 1.0.
(l-e)*OKt, where OKt = Capital investment /2 for t = 1, 2.
-(l-e)*OKt*0.1
Cash "
-------
TABLE 6-9. SAMPLE AFTER-TAX NPV CALCULATION FOR ANNUAL NON-FUEL O&M EXPENSES'
Year
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
Cash.
Flow0
-
-
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
Discounted
Cash Flow
-
-
0.429
0.397
0.368
0.341
0.315
0.292
0.270
0.250
0.232
0.215
0.199
0.184
0.170
Cumulative
NPV
0
0
0.429
0.826
1.194
1.535
1.850
2.142
2.412
2.662
2.894
3.109
3.308
3.492
3.662
Year
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Cash.
Flow0
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
Discounted
Cash Flowc
0.158
0.146
0.135
0.125
0.116
0.100
0.100
0.092
0.085
0.079
0.073
0.068
0.063
0.058
0.054
Cumulative
NPV
3.820
3.966
4.101
4.226
4.342
4.450
4.550
4.642
4.727
4.806
4.879
4.947
5.010
5.068
5.122
Annual O&M Cost (OCt) is 1.0. OC. = 0 when t = 1,2. This calculation assumes
a two year construction period ana 28 years of operation.
(1 - tax rate) * OC. = OC./2.
w U
Cash "
6-33
-------
recovery factor is 0.08883. Therefore, 0.08883 x 0.5869 equals 0.052.
For every dollar of capital invested, the after-tax annualized cost is
5.2 cents.
Using the financial assumptions in the "Oil/Gas" column of Table 6-7
and the same capital recovery factor, the after-tax annualization factor
for capital investments in new oil/gas boilers is 6.7 percent. The
shorter depreciation period, accelerated depreciation method, and higher
ITC for coal investments all contribute to a smaller annualization
factor for coal investments compared to oil/gas investments in this
sample comparison.
The annual non-fuel O&M after-tax annualization factor is not
different for coal and oil/gas expenses because the financial parameters
that determine this factor (discount rate, construction period, useful
life, and tax rate) are not dependent on the fuel type. For every
dollar spent as an annual non-fuel O&M expense, the after-tax annualized
cost is 45.5 cents.*
The sample comparison involves multiplying boiler and pollution
control costs by the appropriate after-tax annualization factor, adding
fuel prices,** and comparing the total annualized costs. This comparison
is performed in units of $/MMBtu, where the denominator represents the
annual fossil fuel consumption.
* 0.0883 (capital recovery factor) x 5.122 (see Table 6-9).
** After-tax annualized cost.
5-34
-------
6.3.4.2 Sample Calculation of Annualized Costs
Table 6-10 summarizes the procedure for calculating after-tax
annualized costs. This comparison is expressed in units of annualized
$/MMBtu in order to illustrate the relative contributions to total
annualized costs from capital, non-fuel O&M, and fuel components. This
procedure is similar for investments in oil or gas facilities except for
the substitution of a different annualization factor for the capital
investment (0.067). Total annualized costs can be derived by adding an
after-tax fuel price (as with annual non-fuel O&M expenses, about half
of the before tax price) to the annualized capital and O&M costs.
6.3.4.3 Comparison of Sample Annualized Capital and O&M Costs
The sample costs presented in Table 6-2 have been annualized and
are summarized in Table 6-11. For all fuel types, annual non-fuel O&M
costs contribute substantially more to total annualized costs than do
capital expenses. Capital and O&M costs also vary significantly by coal
type. Pollution control costs to control S02 emissions significantly
increase total annualized costs for coal-fired boilers required to
comply with environmental regulations.
6.4 SUMMARY
For each boiler in the population, IFCAM compares total capital and
annual non-fuel O&M costs in order to determine the least cost control
strategy for each fuel type. After-tax annualized fuel costs are added
to the after-tax boiler and pollution control capital and O&M costs for
each fuel type in order to estimate the least cost fuel type.
6-35
-------
TABLE 6-10. SAMPLE CALCULATION OF ANNUALIZED COSTS
($1978)
Cost
Component
Capital:
Boiler- related
Pollution Control
S0£
PM
NOX
TOTAL
Annual non-fuel O&M:
Boiler- related
Pollution control
so2
PM
N0x
TOTAL
$oooa
4,917
1,111
0
103
6,131
794
372
0
10
1,176
$/MMBtub
11.73
2.65
0
0.25
14.63
*
1.89
0.89
0
0.02
2.80
After-tax
Annual i zed
$/MMBtuc
0.61
0.14
0.00
0.01
0.76
0.86
0.40
0
0.01
1.27
a Midwestern high sulfur coal costs, Table 6-2
Costs in column 1 divided by annual fossil fuel consumption:
87 MMBtu/hr* 8760 hours/year * .55 capacity utilization rate.
0 Costs in column 2 multiplied by annualization factors: 0.052
for coal capital costs and 0.455 for annual non-fuel O&M expenses.
6-36
-------
TABLE 6-11. COMPARISON OF ANNUALIZED COSTS0
($1978/MMBtu)
FUEL TYPE
Cost
Component
Capital :
Boiler- related
Pollution Control
so2
PM
N0x
TOTAL
Annual non-fuel O&M:
Boiler- related
Pollution Control
so2
PM
N0x
TOTAL
Natural
Gas
0.23
0
0
Ob
0.23
0.41
0
0
0.06
0.47
Residual
Fuel Oil
0.23
0
0.02
Ob
0.26
0.41
0
0.02
(0.02)c
0.41
Eastern High
Sulfur Coal
0.62
0.15
0
0.01
0.78
0.87
0.50
0
0.01
1.38
Eastern Low
Sulfur Coal
0.58
0.04
0.06
0.01
0.69
0.85
0.24
0.07
0.01
1.16
Midwestern High
Sulfur Coal
0.61
0.14
0
0.01
0.76
0.86
0.40
0
0.01
1.27
Western Low
Sulfur Coal
0.67
0
0.06
0.01
0.74
0.88
0
0.05
0.01
0.94
See Table 6-2.
Less than $0.005/MMBtu.
Negative. Represents a net credit, fuel savings.
-------
REFERENCES
1. Cost Equations for Industrial Boilers. PEDCo Environmental, Inc.
Cincinnati, Ohio. Prepared for the Economic Analysis Branch, Office
of Air Quality Planning and Standards, U.S. Environmental Protection
Agency. January 1980. 21 p.
2. Federal Register. Vol. 44, No. 97. May 17, 1979. pp. 28950-29019.
3. Tax Information on Depreciation. Internal Revenue Service, U.S.
Department of the Treasury. Publication 534, 1979 Edition, p. 6.
4 Ibid.
5. Annual Report to Congress 1978. Energy Information Administration,
U.S. Department of Energy. Publication No. DOE/EIA - 0173/1,2,3,3-S1,
3-S2.
6. Federal Register. Vol. 44, No. 97. May 17, 1979. pp. 28950-29019.
A weighted average real cost of capital for 54 energy-intensive indus-
trial firms. Letter and attachment from Berkowitz, S. and L. Revzan,
Ernst & Ernst, to Stern, S., U.S. Department of Energy. May 7, 1979.
7. Devitt, T., P. Spaite, L. Gibbs. Population and Characteristics of
Industrial/Commercial Boilers in the U.S. PEDCo Environmental, Inc.
Cincinnati, Ohio. Publication No. EPA-600/7-79-178a. Prepared for
the Industrial Environmental Research Laboratory, U.S. Environmental
Protection Agency. August 1979. p. 133.
6-38
-------
7. MODEL OUTPUTS
7.1 INTRODUCTION
This section outlines key IFCAM outputs: the energy, environmental,
and cost impacts of alternative regulatory scenarios. Aggregate IFCAM
results are presented in other reports and thus are not presented in
this documentation.
7.2 ENERGY IMPACTS
IFCAM simulates fuel choice decisions at the combustor level and
aggregates the results. The projected fuel mix may be presented by:
Fuel type (including four residual oil sulfur classes and 39
coal types)
Federal region (10)
t New or existing units
Boiler or process heat combustors
Boiler size class (seven)
Major industry group (nine).
Comparisons may be made of the projected fuel mix from a base case and
from an alternative scenario in order to analyze potential energy impacts.
For a detailed discussion of these categories, see Section 3.
7.2.1 Energy Penalty
IFCAM also estimates the level of aggregate energy demand necessary
to operate pollution control equipment. These data are compared to
total industrial energy demand in order to evaluate the relative share
of fuel needed to operate pollution control equipment. Most of this
fuel demand is for electricity.
7-1
-------
7.3 ENVIRONMENTAL IMPACTS
7.3.1 Air Emissions
IFCAM projects the total amount of SO,,, participate matter, and NO
emissions from stationary fuel combustion in industrial sources. These
estimates assume that all combustors are in compliance with applicable
environmental regulations. Projected air emission estimates may be
presented in the same level of detail summarized above for the fuel mix.
Assumptions related to the calculation of controlled and uncontrolled
air emission rates are discussed in Section 5.
7.3.2 Water and Solid Waste Disposal Requirements
Liquid waste requirements are estimated in IFCAM for each pollution
control strategy. Wet scrubbers, available particulate control devices,
generate a liquid waste. Physical coal cleaning also produces a liquid
waste.
Likewise, solid waste disposal requirements for each technology are
estimated. Categories include:
Scrubber sludge (double alkali system) and solid waste (dry
scrubbing)
Bottom ash from coal firing
Fly ash collected by particulate control devices
Physical coal cleaning residue.
7.4 COST IMPACTS
Capital, annual O&M, and annualized fuel prices also are aggregated
for investments in new industrial boilers. Boiler-related expenses are
distinguished from pollution control investments. Therefore, the
7-2
-------
relative cost impacts of alternative scenarios can be estimated. Simi-
larly the cost impacts of alternative scenarios in process heat combustors
also can be estimated.
7-3
-------
APPENDIX A. ENERGY CONSUMPTION DATA BASE1
A.I BRIEF DESCRIPTION OF ECDB
This data base describes and documents energy consumption in the
United States during 1967, 1971, and 1974*. This information has
a wide variety of application in both energy and environmental areas.
The data base handles several million pieces of energy consumption (in
Btu or traditional units) and expenditure information on the agricultural,
mining, construction, manufacturing, transportation, commercial, household,
and electric utilities sectors on a state-by-state basis. The number of
data cells in each sector varies from 16,000 in the electric utilities
sector to 2,800,000 in the manufacturing sector. The elements are fully
cross-stratified so that, for example, the data base contains a record of
the amount'of coal used in the steel industry in Ohio during 1971 for coke
production. Although all combinations of data elements already are aggre-
gated to the Census region and national levels, any other combination of
State data such as EPA regions or PAD districts could be produced easily.
The data have been produced primarily by three different techniques:
(1) direct input from a primary source (Census, BOM, FPC, etc.) with case-
by-case refinements when superior data from isolated sources exist; (2)
disaggregating macro data by taking shares of control totals based on
output or other indicators; and (3) aggregating micro data, such as the
amounts of fuel required by various machines to complete various types of
construction projects.
Data for 1975 and 1976 will soon be available.
A-l
-------
A list outlining tyie 12 fuel types, 11 functional uses, and 26 in-
dustry subgroups is presented in Table A-l.
A.2 COMPARISON OF ECDB AND BUREAU OF MINES CONTROL TOTALS
ECDB was used in tandem with the MEFS industrial energy consumption
information. Since MEFS is based primarily on BOM data, it is useful to
compare BOM and ECDB even if only on a cross-sectional (all segments of the
economy) basis. By looking at the cross-sectional energy use, differences
in definition of the economic segments (e.g., commercial versus large
residential apartments or small utilities versus industry) will be elimi-
nated.
It appears that, in most cases, the sum of individual sectors' fuel
use in ECDB was close to control totals published by the BOM or other
primary data collectors. Some major discrepancies are apparent, however,
which cannot be attributed strictly to definitional differences. A pre-
liminary list of discrepancies is presented in Table A-2.
A summary of some of the factors contributing to the differences shown
in the above table are as follows:
Some of ECDB's fossil fuel is categorized as "other energy,
NSK/NEC," mainly due to establishments too small to report indi-
vidual fuels to the Census Bureau in the manufacturing sector.
a Petroleum usage in the ECDB omits about 0.2 quads (0.2 x 10 kJ)
of asphalt not used in the construction sector, but unable to be
classified according to industry in the manufacturing industry.
Natural gas use in the mining sector of the ECDB was derived from
Census Bureau data which were about 0.5 quads (0.5 x 10 kJ) less
than comparable BOM data for oil and gas extraction.
In addition, electricity production (6.4 quads, 6.7 x 10 kJ)) does
not equal electricity consumption (6.2 quads, 6.5 x 10 kJ)) when all
sector uses are added together. Since 6.2 quads (6.5 x 10 kJ) represents
A-2
-------
TABLE A-l. LEVEL OF DETAIL AVAILABLE IN ECDB
Fuel Type
Coal
Coke and breeze
Distillate oil (including diesel)
Residual oil
Asphalt
Miscellaneous petroleum products
Liquefied petroleum gases
Natural gas
Other gas, NSK/NEC
Hydro
Electricity
Other energy, NSK/NEC
Total - all energy
Functional Use
Space heating
Space cooling
Space conditioning, NSK/NEC
Lighting
Total direct heat
Direct heat - below 600°F
Direct heat - 600-1000°F
Direct heat - 1000-1500°F
Direct heat - above 1500°F
Direct heat, NSK
Raw material
Process steam
Electricity generation
Coke production
Machine drive
Electrolytic processes
Other uses, NSK/NEC
Total - all functional uses
Industry
Food and kindred products
Tobacco manufacturers
Textile mill products
Apparel
Lumber
Furniture
Paper (total)
Pulp., paper, paperboard, building
paper, and board mills
Other paper products NSK/NEC
Printing, publishing
Chemicals
Petroleum refining
Rubber and miscellaneous products
Leather
Stone, clay, glass, concrete
(total)
Cement
Other stone, clay, etc., NSK/NEC
Primary metals (total)
Blast furnace and steel mills
Aluminum
Other primary metals, NSK/NEC
Fabricated metal products
Machinery (except electrical)
Electrical and electronic
machinery
Transportation equipment
Measuring, etc., equipment
Miscellaneous manufacturing
industries
Other industries, NSK/NEC
Total - all industry
A-3
-------
TABLE A-2. COMPARISON OF 1974 BOM AND ECDB CROSS-SECTIONAL DATA
Fuel Type
Coal
Petroleum
Natural gas
Total Fossil Fuel
ECDB
[1015 kJ (1015 Btu)]
13.1 (12.4)
33.7 (32.0)
21.5 (20.4)
68.3 (64.8)
BOMa
[1015 kJ (1015 Btu)]
13.6 (12.9)
35.3 (33.5)
22.9 (21.7)
71.8 (68.1)
Difference
(%)
(4.0)
(4.7)
(6.4)
(5.1)
aMonthly Energy Review. .Energy Information Administration, U.S. Department
of Energy. Washington, D.C. Publication No. DOE/EIA 0035/03(80). March
1980. p. 6.
A-4
-------
only end use consumption and transmission losses may be eight to 10 percent
of net generation, the consumption estimate could be overstated or the
generation estimate understated by as much as 0.3 to 0.4 (0.3-0.4 x 10 kJ)
quads.
A-5
-------
REFERENCES
Energy Consumption Data Base. Energy and Environmental Analysis, Inc.
Arlington, Virginia. Prepared for the Federal Energy
Administration. June 1977.
A-6
-------
APPENDIX B. MAJOR FUEL BURNING INSTALLATION SURVEY
B.I DESCRIPTION
The Major Fuel Burning Installation (MFBI) report, a survey of indus-
trial plants, was performed in May 1975 by the Office of Fuel Utilization,
FEA (now DOE). The primary purpose of this survey was to identify large
combustors capable of firing coal that currently are relying heavily on
either oil or gas. Under ESECA, FEA had the authority to force these
plants to convert to coal. Total coverage is about 6,300 combustors at
3,400 plants.
The data from MFBI deal with specific plants (and government installa-
tions) and with specific combustors within those plants. The plants are
identified according to company name, street address, zip code, and state.
For the plant as a whole, the total number of boilers and the number of
"other combustors" are specified. The total designed firing rate for all
combustors is given. For individual combustors with a designed firing rate
greater than 99 MMBtu/hr (29 MW), the following information was collected:
Kind of combustor (boiler, burner, other)
Combustor capacity
Date installed
Primary and alternate energy sources (coal, residual, distillate,
gas, other)
Information "about current and historical coal burning capability
1974 and 1973 fuel use (Btu content and physical quantity con-
sumed of coal, residual oil, distillate oil, and gas)
« Percent of combustor output devoted to electric generation, space
heating, process steam, other
B-l
-------
Information about type of air pollution control equipment and re-
moval efficiencies.
B.2 COVERAGE
The MFBI survey does not provide complete coverage of the industrial
sector's energy usage. It focuses on large boilers, burners, or other
combustors, and detailed fuel usage information is not available for any
combustor that uses less than TOO MMBtu/hr. Even for a given plant with
several large combustors, the data in the MFBI survey do not give infor-
mation about all of that plant's energy demands since much of the fuel
conceivably could have been burned in smaller units or used for non-fuel
purposes (i.e., chemical feedstocks). Total 1974 energy use by the approx-
imately 6,300 large combustors covered in the survey was about 6.6 quadril-
lion Btu .(7 x 10 kJ), of which about 3.5 quads (3.7 x 10 kJ) were gas,
1.3 quads (1.4 x 1015 kJ) were oil, and about 1.8 quads (1.9 x 1015 kJ)
were coal.
MFBI coverage of total U.S. natural gas and fuel oil varies by fuel
type and combustor type (boiler or nonboiler). Total coverage of both
fuels, excluding feedstocks, is over 50 percent. MFBI coverage of boilers
is more extensive than the coverage of nonboiler combustors. Comparisons
with ECDB control totals indicate that MFBI data cover approximately 90
percent of the total U.S. oil burned in boilers and 70 percent of the
natural gas boiler total. This either reflects the greater use of natural
gas in boilers below the MFBI cutoff point or a lower reporting frequency
of natural gas users.
The MFBI data have not been published by DOE and are considered to be
confidential due to the information provided on individual companies.
Aggregated summaries by SIC code and state were prepared by EEA for use by
B-2
-------
FEA's 1975 Natural Gas Task Force and DOE's analysis of the proposed National
Energy Plan. The MFBI probably represents the only source of actual survey
data on the energy use characteristics of large combustors in specific
plants.
B.3 SAMPLE
The following seven pages represent the actual survey forms sent to
individual companies.
B-3
-------
FEDERAL ENERGY ADMINISTRATION
WASHINGTON. D.C, 20461
APPROVED BY GAD
B-ISI234 (S75022)
EXPIRES 6-30-75
THIS REPORT IS MANDATORY UNDER P.L. 93-275
MAJOR FUEL BURNING INSTALLATION COAL CONVERSION REPORT
FEA C-402-S-0
INSTRUCTIONS
L PURPOSE
Form FEA C-602-S0 is a repuesi for information from "major
fuel burning installations" to aid FEA in carrying out its respon-
sibilities under the Energy Supply und Environmental Coordination
Act of 19"- (P.L. 93-319). (A major fuel burning installation will
be referred to in Ihis form at "MFBI".) The survey is designed
to obiain data required by FEA 10 examine the feasibility and
effec: of issuing orders to specified major fuel burning installations
prohibiting them from burning oil or natural pas as their primary
. energy source.
n. WHO SHOULD SUBMIT
Form FEA C-6C2-S-0 must be-submined by every MFBt.
MFBI is defined OR page 3 of this form. Tne form may be filled
out by a responsible official at either the installation or. if appli-
cable, the parent organization.
in. TO WHOM
Two copies of the Form FEA C-602-S-0 must be filed with:
Federal Energy Administration
ATTN: OFU/CRB Room 6117
Washington. D.C. 20461
rv. WHEN
Form FEA C-602-S-0 must be submitted on or before Mav 21.
197.5.
V. GENERAL INSTRUCTIONS
This report is mandatory, and is being required pursuant to the
authorities granted 10 FEA by the Federal Enerfy Administration
Act of 1974 (P.L. 93-275).
A single Section I shall be filed for each facility, even if it is
comprised of more than one combusior of fuel. Sections II and
III shall be filed for each separate combusior with an individual
capacity of 100 million Btu's/hr or greater.
Fill in the combusior number and installation name at the top
of each applicable paae in order to facilitate handling should the
pages be inadvertently separated in mailing,
For all questions which can be answered by a "Yes" or "No",
"!" (for "Yes") or "0" (for "No") shall be entered in thr appropriate
block unless otherwise stated
A blank page has been provided at the end of this questionnaire
to permit comments to be continued where inadequate space is
provided on the form.
Vt. SPECIFIC INSTRUCTIONS
Section I
Item No.
1 Limii responses to the number of blocks provided, using
standard abbreviations where appropriate.
1 Air Quality Control Repion As designated by ihe Envi-
ronmental Protection Agency. Do noi fill in the line if
the AQCR is unknown.
4. 3 Includes all boilers and otner combustors regardless of
Design firing rate. If there are more lhan 99 in eimer of
fjcaiion Code (SIC) in the firsi column and the percent
of total shipmenu or services (by vaiue) in the-second.
Three entries are available for multi-commodity installa-
tions. If it is possible to enter more than three-SIC entries,
list the three with the highest percentage of total ship-
menu. If ihe SIC is unknown, describe the products OF
services on the line provided.
Section II
Item No.
1
Assign each combusior a twtwdieit identification number
if it does not already have one.
*a Fill in the blank with 1, 2. or 3.
I9b The term "rank" of coal refers to anthracite, bituminous.
tub-bituminous, or lignite.
I9g The term "other unique characteristics" refers toSc.mois-
ture, hardness, fusion, temperature, and all other applicable
coal parameters which must be maintained to insure proper
operation of the combusior.
21. 22 Fill in the estimated "average" Btu content.
Section III
hem Nri.
I Assign each stack a one-digit identification number.
3b The ~^ Availability" refers 10 the percentage of lime
the FCD equipment is available for operation (regardless
whsher or not it is actually operated).
4c. d & If it would be necessary to either install FOD or obtain
ie. d conforming coal, piease complete both item ic:. assuming
FCD is used, anj item (d). assuming conforming coal is
used.
VIL DEFINITIONS
1. "Major Fuel Burning Installation". An installation or unit
other ttun a powerpiant thai has or is a fossil-fuel fired boiler.
burner, or other combustor of fuel, or any combination thereof
at a single site, that has individually or in combination, a design
firing rate of 100 million BTU's per hour or greater, and includes
any person who owns, leases, operates, control; or supervises any
such installation or uniu Gas turbines and combined cycle or
internal combustion engines are excluded from this classification.
2. "Powerplant". A fossil-fuel fired steam tleeiric generating
unit that produces eieciric power for purposes of r minimum jmouni* rcauireC tor sian~uD.
-------
00 NOT FILL IN
CED
10
FEDERAL ENERGY ADMINISTRATE
MAJOR FUEL BURNING INSTALLATION COAL CONVERSION REPORT
FEA C-602-S-0
This report is mandatory under Public Law 93-275
SECTION I GENERAL PLANT INFORMATION
1. MFBI NAME AND LOCATION:
NAME
STREET
CTTY
STATE
I I I I I if IT I ! IT
26
27
I M II I I M M I I ri
43
ap
sa
AIR QUALITY CONTROL REGION (H known) .
PARENT COMPANY NAME AND GENERAL OFFICE LOCATION:
NAME
STREET __;
CITY
I I M M I M M M M
73
STATE.
ZIP
74
M
7S
DO NOT FILL IN
3. PERSON TO CONTACT IN FUTURE CORRESPONDENCE
NAME
TTTLE
3i
CITY/STATE
ZIP
TELEPHONE {witn Aru CoOt)
35
40
SO
4. TOTAL NUMBER OF BOILERS AT THIS INSTALLATION
-------
NAME .
5. 'TOTAL NUMBER OF OTHER COMBUSTORS AT THIS INSTALLATION
C. TOTAL DESIGNED FIRING RATE ft 10* Btu's/hr) (of * ana *S1
7. IDENTIFY PAIRINGS (ETC) OP COMBUSTORS (Examoie: Boiiert 04. OS, and OS Snare a Common Manilold ino are Vented tnrough i Common
Stuck)
Snndire
Industrial
Classification
(A Digit)
Percent ol
Toul Sniomentx
or Services
by Value
60
8. PRINCIPAL PRODUCTS PRODUCED AT. OR SERVICES PROVIDED
3Y THIS INSTALLATION (M SIC Codes are Unknown. Provide Wrmen
Description in S0iz* Provided).
67
eg
9. IDENTIFY THE MAJOR TECHNICAL. RSG'JLATORY. ECONOMIC. AND ENVIRONMENTAL IMPEDIMENTS. IF ANY. TO YOUR UTILIZING COAL TO
A GREATER EXTENT. AT THIS INSTALLATION)
00 NOT FILL IN
10. WHAT ACTIONS BY THE FEDERAL GOVERNMENT WOULD ENCOURAGE YOU TO UTILIZE COAL TO A GREATER EXTENT?
I'.. CERTiriCATJON:
CERTIFYING OFFICER I unity to me best ol my knowleooe mat tne information in this reoon is correct
NAME.
TITLE.
SIGNATURE.
DATE.
Till* 1£ USC 1001. makes II 4 crime lor any oerson knowingly and willingly to make to any agency or aaoanmem ol The United Staiea any
lalM. fictitious or fraudulent statements as to any matter witnm its jurisdiction.
1IMC O"ICI-Ot-<7T-Ut
-------
PEA C-SC2-S-0 FHOSHAL ENESGY ADMINISTRATION APPROVED BY GxO
»«*««. D.C. 2046! ££ » «««
j_^_This Report is Mandatory JJnder P.L S3-275 |
MAJOR FUEL BURNING INSTALLATION COAL CONVERSION REPORT
DO NOT PILL IN FILL IN THIS' PAGE FOR EACH COM BUSTOR OVER 99 MILLION STUs/HR
LJ I ! L_J MPSI NAMe,_. ,
SECTOR IT COMBUSTOR DATA
1. COM8USTOR NUMBER
2, WHAT KINO OF COMBUSTOR IS THIS?
1 - boilar . 2 - burner. 3 - ammr comoustor of lu«4
a. COMBUSTOF, CAPACITY ( * 10- BTU/HR)
t.- UANUStCTUBSO _ ._
m
D.
i i.i i
5. DATE INSTALLED (YEAR) 19 I I 1
6. *. It Comoustsr Mas ow> Moort'wd to B»Cao«et» of Burning Co«l. WM»t Y««r wm» it Modified?
a. Ho- wn il Modilwti? 18 .
7. 00 YOU INTEND TO INSTALL A TOP91NG TURBINE ON THIS COMeUSTOR?
a. It YB. Win You-N««0 re:
fl) R«Ql*c« Your Comevxtor..
(21 Modrty Yoor-Comouiior,
Cl MM* Kle Comeutior Modifienien.
b. II me Answer, to 7|«) «u -1" or ~Z~. Do You inwnd to Modi»yR«8t«e»'Your Comouaor to tn«t You Can Bum CMI?
8. PRIMARY EMeRGY SOURCE FOR EXISTING COM8USTOB
1 - co»l 2 midux 3 - dbrulun* < - gu 5 eowr Ixotcrty)
'en-
D
n
D
D
9. ALTERNATE ENERGY SOURCE FOR EXISTING COMBUSTOR
1 - ccaJ 2-reioual 3-dicii:»i» 4~gu S ~ oihvr ^spvary) . 6 <» no invrrai*.
IjV l*fr<*n*ff mttmrnat* rtmtrrtfaurm. H mtvf- .__,__
1S. IF CCAL S TH5 PRIMARY ENSRGT SOURCS. DO YOU INTEND TO CONTINUE PTS USE?
U. IF COAL IS NOT THE PRIMARY SNSfiGY SOURCS. DO YOU INTEND TO CONVERT TO COAL IN THE NEAR FUTURE?
12, WAS THIS COM3USTOR ORK3INALLT DESIGNED TO 9E CAPABLE OF BURNING COAL?
13. WAS COAL EVES BURNED IN (T?
14. CAN COAL NOW BE 9URNEO IN THIS COMBUSTOR?
IS. IS LAND AVAILABLE FOR COAL STORAGE?
n
n
n
n
a
n
n
16. IF THE ANSWER TO NO. 12 OR 13 IS "YES". IS ANY OR ALL OF THE COAL BURNING SUPPORT EQUIPMENT STILL IN PLACE? LJ
17. IF THE ANSV.'SR TO NO. 12 OR 13 IS -YSS". IS ANY OR ALL OF THIS EQUIPMENT STILL OPERATIONAL?
n
29
-------
COM8USTOR NUM9SR.
Mrol NAME
FILL IN THIS PAGE FOR EACH COMBUSTOR
OVER 99 MILLION STUs/HP.
19. IF COAL WAS SVSR L'ScD AS THE PRIMARY PUcL SC'JRCE PRIOR TO 1973 GIVE (lor me last year coal w«s »«):
a. Year _ 19
6. Honk 01 £"«'
c, PcrcBffl Asn ov Weiont (to me naaresijxrewtt).
A. P«rom Sultur by Wetfht (to ir>« \entn ol a ocreanl).
». BTU/lb^
f. Quantity.
g. Otn«r Uniou
. Tons/Y«»r
CD
DD
n. M«tnoO of D*«>»«ry: fTnm. Truck. Barjt. etc.)
i. IT Coal a not
U»«d. Do You AfitieiMu mat h Ceulfl b* Obtained it you Were to Convert?
D
j. If Not. Wny Net?
20. ESTIMATE YOUR ANNUAL NO»»-COAL FUEL SAVINGS 1? YOU WERE TO CONVERT TO COAL,
QUANTITY
RESIDUAL
DISTILLATE
GAS
I
39
101 bb!«/yr
10* MCF/yr
21. 1974 ANNUAL FUEL USE
% ASH
(by weiont)
COAL
RESIDUAL
OISTILLATE
GAS
SULFUR
BTU CONTENT (X103)
OUANTTTY
Ob)
I I I M IB")
(BaO
(MCF)
10" torn/yr
10* Dbls/yr
10' bbis/yr
10" MCF/yr
-------
M=3l NAME
PILL IN THIS PAGE FOR £ACH COM8USTOR
OVER 9S MILLION BTUs/Kn
22 1973 FUEL USE
COAL
RESIDUAL
DISTILLATE
GAS
m i i i i~n
79 80 1 5
% ASH
(By weicnt)
% SULFUR
(By weigm)
STU CONTENT (X10>)
QUANTITY
(8-0
L_LL
(MCF)
30
lOMofm/yr
10'BBim/yr
37
10» MCF/yr
23. IND!C.»T5 (10 tn« n«ir«st percent) THE PERCENT Of COMBUSTOR OUTPUT THAT IS DEVOTED TO:
ELECTRIC GENERATION
SPACE HEATING
PROCESS STEAM
OTHSS (Specify)
SECTION 111 AIR QUALITY
1. STACK NUMBER
n
2. STACK HEIGHT (Feel Above Ground)
n
3. CURRENTLY INSTALLED POLLUTION CONTROL EQUIPMENT AS PERTAINS TO THE COMSUSTOR (Answer Yes or No <
respectively).
a. Precionaior (Also referred to «s Oust Collector)
Type (Centrifugal. Electrostatic. Etc.) ________________________________.
Data Imaliee __________________________________________
Data I
itn < "i" or "0"
n
Desijn Ertieiency (%)
Aau»! SWciency (%) .
b. FLUE GAS OESULFURQATION fFGD; EQUIPMENT (Also referred to n Scrueper or Sullur Dioxide Aoiortier)
Tyoe (MAG Ox. LIMESTONE. Etc.)
Dale Installed ________________________________
n
ss
Date Last Operated
Design Efficiency f%)
Actual Efficiency (%) ,
-------
COMB-STOR'NO.
MF9I NAME
FILL IN THIS PAGE FOR EACH COMSL'STOR
OVER 99 MILLION BTUs/HR
<. TO BURN COAL ANO M£ST THE SIP EMISSION LIMITATIONS RELATING TO ATTAINMENT OF THE FEDERAL PRIMARY AMBIENT AIR
QUALITY STANDARDS. THIS INSTALLATION MUST:
(Answer witn Yes (1) or No <0) in me Oiocus prov.c-fl)
t. Upgrade Pfecioitators
II vex. give approximate cost S _____ time _____ (w«efcs)
B. Install Precipitaton
If yes. give approximate cost S ______ time ______ (weeks)
e. Insnll FGO
If yw. 9*v« aoproximate coat S _____ tim« _____ (waekx)
0. ODtain Cantormm; Coal
Tnn coal must M * Sultur By wei?!tt. _____ % Ash By w«igm.
Do you imieisaie mat you will be aoto to oeuin conforming coal?
0
D
D
D
D
S. TO BURN COAL AND MEET OTHER APPLICABLE SIP REQUIREMENTS, (THIS-INSTALLATION MUST: (Answer with a Yes (1) or
No (0) in trw oioexs orovioed)
l. Upgraot Pracipitalon
II y«s. give approxtmate cost S _____ time _
6. Irunll Prvcipitaiors
H yes. give appro*im*te cast S _____ time _
c. install FGO
14 ye*, give aperoiimate cost $ _____ rime _
a. OBtain Contorming Coal
This coal musi be _______% Sultur By wvignt
(weeks)
% Ash by weight-
Do you anticipate tnat you will be aBle to obtain conforming coal?
D
D
D
n
g
DO NOT FIU. IN
-------
APPENDIX C. MIDTERM ENERGY FORECASTING SYSTEM
The Midterm Energy Forecasting System* (MEFS) is a computer model of
the U.S. energy sector used to forecast issues related to energy demand and
energy supply for the years 1985, 1990, and 1995. The forecasts are broken
down by 10 Federal regions. The model simulates the interactions of energy
suppliers and consumers in the marketplace. The forecasting system explicity
represents the conversion of energy materials from one form to another for
final consumption. The forecasts generated are functions of varying economic
and policy assumptions structured into scenarios. The model determines a
point at which supply and demand balance for a collection of energy prices,
and it is assumed that prices will clear the market in all regions.
The MEFS is a collection of models which falls under the following
four categories:
Fuel-specific regional supply models
Sector-specific regional demand models
Regional conversion models, and
An integrating system - the Midterm Energy Market Model (MEMM).
The supply, demand, and conversion models are a combination of econometric,
structural, and structural/econometric methodologies. The MEMM is used to
integrate various sectors of the MEFS. This integration involves equilibra-
tion by partially competitive pricing, inclusion of transportation sectors
and consideration of the regulatory structures imposed on utilities, indus-
trial fuel users, and producers of oil and gas. Equilibration means that
* An extension of what was formerly referred to as the Project Independence
Evaluation System (PIES).
C-l
-------
the MEMM solves for an equilibrium point, that is, a price for each energy
material at which the amount supplied by producers exactly equals the
amount demanded by consumers. Price and quantity for each fuel are predicted
at all important points in the flow from extraction to final consumption.
Figure C-l gives a schematic of the overall structure of the MEFS.
MEFS includes a separate submodel to account for the supply curves of
each of the major energy inputs extracted from the earth. All supply
curves are entered as step functions in accord with the economics of exhaust-
ible resources whereby incremental amounts of fuel are extracted at increasing
costs. The development and production from a new oil or gas field is
modelled according to this incremental cost concept. Production from a new
field is assumed to decline over time using historical decline rates.
Offshore exploration is constrained by the amount of territory leased. Each
major supply sector is analyzed separately. There are separate sub-systems
to simulate Alaskan North Slope oil and gas production, the Naval Petroleum
Reserve, special oil and gas categories, such as shale oil and enhanced oil
recovery. Imported oil is considered available in unlimited quantities,
whereas imports of natural gas are modelled with quantity limitations. The
coal supply curves are of the same functional form as the oil and gas
supply curves. They are, however, estimated quite differently. Data on
the production potential and cost of mining various coal types are obtained
from an extensive data base describing known and potential coal reserves by
coal type, seam thickness, and depth. Capital availability, machinery and
manpower constraints are not modelled in the expansion of coal production.
C-2
-------
FIGURE C-l SIMPLIFIED OVERVIEW OF THE MIDTERM
ENERGY FORECASTING SYSTEM COMPONENTS1
SUPPLY
MARKET EQUILIBRIUM
DEMAND /MACRO
Integrating Linear
Programming Model
** ~ % ~
/Refineries & Snythetics \
/
i
Electric Power 'f
\ j
\ Transportation ''
Other
Conservation
Adjustments
f
Demand
for
Fuels
Macro
Economic
Model
(DRI)
Reproduced from, Validation and Assessment of Energy Models,
U.S. Dept. of Commerce, NBS, Special Publication 569, Feb. 1980,
p. 218.
C-3
-------
Some exogenous parameters are included to limit the growth in the produc-
tion of certain coal types.*
Several submodels are used in the MEFS to project the demand for
energy. Figure C-2 shows the breakdown of the four major demand sector
models in the MEFS. Most of these models are in a stage of transition,
always being adjusted and expanded. Some of them are on-line and some
off-line. Those models which operate off-line have reduced-form econometric
versions in the on-line system. Over time, all models are being brought
on-line, that is, being incorporated under one integrated computer system.
The reduced-form models are used to derive the consumption totals which are
then fed into the structural/econometric off-line models to break down into
fuel shares. The supply and demand models are dynamic. The forecasting
procedure takes a snapshot for the years 1985, 1990, and 1995. Then a
static equilibrium analysis is performed on the control totals. If the
equilibrium forecasts are not synchronous with the dynamic models, the
system is reiterated until an equilibrium is achieved. The MEMM plays the
integrating role in the sychronizing and equilibrating of the system.
* For a more detailed description of all the supply and demand assumptions
in the MEFS, refer to: Energy Information Administration, U.S. Department
of Energy. Annual Report to Congress 1978. Publication No. DOE/EIA-0173/3
and Applied Analysis Model Summaries (TR/OA/79-16) Publication No. DOE/EIA-0183/tf
Order No. 468. May 1979.
C-4
-------
FIGURE C-2 MEFS DEMAND MODULE*'0
.Hirst Model
ORNL
(Cons. Shifts)
Residential ; Commercial Industrial Transportation
(Hirst)
Jackson Model
ORNL
(Cons. Shifts)
(Fuel Shares)
s-
IFCAM Model
EEAb
(Fuel Shares)
(Fuels Policy)
/
Auto Model
Faucett
Light Duty Truck
i EEA
(Cons. Shifts)
f
i
\ s
-X /
' ^
-\ /-
, 4
1 1
!
Demands and Elasticities to Mid-term Energy Market Model
(MEMM)
Relationship of models used by DOE in 1979.
An earlier version of IFCAM developed for DOE. Does not
reflect the version of the model described in this report
Reproduced from the Proceedings of the Symposium to Review
Volume III of the 1978 Annual Report to Congress, Nov. 7-8,
1979, EIA, U.S. Dept. of Energy, p. 63.
C-5
-------
APPENDIX 0. PROJECTION METHOD
D.I INTRODUCTION
This appendix describes the methodology used to estimate industrial
fuel use by major industry and region. To be consistent with MEFS regional
total fossil fuel demand and to incorporate energy growth parameters at the
level of detail required in this analysis, final energy use projections
were derived in three steps:
Developing a detailed regional baseline of historical energy
use
Projecting growth and redistributing energy by region and
industry based on various inputs
Reconciling the detailed energy projection with MEFS regional
total fossil fuel demand. This procedure is necessary because
MEFS does not project fossil fuel demand by major industry
group (with the exception of the Petroleum Refining industry).
An energy data base was developed from existing data sources, primarily
ECDB, which include industry and regional detail. This baseline energy
demand was projected to 1985, 1990, and 1995, based on an industrial growth
projection consistent with MEFS input parameters and independent EEA estimates
of conservation factors. The resultant energy projection was not consistent
with the actual MEFS forecast of regional industrial energy use. To reconcile
these data differences, the industry ranking within each region was assumed
to be the same for both data sources and the estimated projected regional
totals by industry group were adjusted to equal total fossil fuel projections
from MEFS. The projection methodology for the 1985 fuel use total is
described in detail; the projections for 1990 and 1995 follow a similar
procedure.
0-1
-------
0.2 PROJECTION OF 1985 TOTAL ENERGY DEMAND
D.2,1 1974 Total Energy Demand
The first step in determining 1985 total energy demand was to determine
1974 energy demand by nine industry subgroups. The nine subgroups are
Food, Textiles, Paper, Chemicals, Petroleum Refining, SCG, Steel, Aluminum,
and Other industries. The "other" category includes manufacturing not
covered in the first eight subgroups plus mining, construction, and agricul-
ture. Gasoline and diesel use in the latter three industries in "other"
are classified in the transportation sector and, thus, are not considered
here.
The baseline energy demand was provided by the 1974 ECDB. After
removing feedstocks and classifying the industries into nine distinct
groups, the 1974 total energy was used as a proxy for energy demand by
industry and region. The raw 1974 data from the ECDB include fuel type,
state, and two-digit SIC detail. The fuels covered are steam coal, distil-
late fuel oil, residual fuel oil, and natural gas.
0.2.2 1974-1985 Conservation Adjusted Growth Factors
The second data step was to develop 1974-1985 conservation adjusted
growth factors. This step was divided into two parts, calculating output
growth factors and calculating energy conservation factors.
The macroeconomic forecasts used in MEFS were developed by Data
Resources, Inc. (DRI). To be consistent, DRI Trend Long projections of
industrial output demand by region, industry, and year have been used to
calculate the growth factors in IFCAM. The industrial production growth
rates are projections of value added data in constant dollars. National
DRI estimates have been disaggregated by region for each industry by DOE.
D-2
-------
A certain portion of industrial growth is expected to be offset by
energy conservation measures. The effect of these measures must be included
in industrial growth factors. Although conservation measures vary from
industry to industry, MEFS does not explicitly identify conservation measures
by industry. Consequently, MEFS was not used to estimate conservation
impacts in IFCAM.
The IFCAM conservation factors, i.e., the technical potential for
conservation in each industry subgroup, were derived from an EEA study
completed in 1974. These factors are presented in Table D-l and represent
projections for three periods, 1974-1985, 1974-1990, and 1974-1995. The
primary metal factor was used for both steel and aluminum, and the factor
for all industries was used for the "other industry" and textiles subgroups
in the model.
D.2.3 1985 Projected Energy
The 1985 projected energy is produced by multiplying the 1974 total
energy demand for each industry by its corresponding 1974-1985 industrial
production growth factor in each region and by the appropriate conservation
factor. Table 0-2 illustrates this for Region 3. The resulting 1985
energy demand projection contains total energy demand for each industry
within a region, but no fuel type detail within an industry. This prelimi-
nary projection of regional fuel demand for all regions is shown in Table
D-3.
D.3 RECONCILING INDEPENDENT PROJECTIONS WITH MEFS
Total fuel use is aggregated by region and reconciled with fuel control
totals provided by MEFS. The preliminary regional projected numbers are
normalized to those of MEFS under the assumption that fuel use by industry
D-3
-------
TABLE D-l. PROJECTED INDUSTRIAL ENERGY CONSERVATION FACTORS3
Industry
Food
Textiles'3
Paper
Chemicals
Petroleum Refining
SCG
Primary Metals
Other Industry
1985
0.949
0.844
0.871
0.842
0.924
0.827
0.825
0.844
1990, 1995
0.959
0.759
0.788
0.765
0.914
0.789
0.758
0.759
aEnergy Conservation in the Manufacturing Sector, 1954-1990. Energy
and Environmental Analysis, Inc. Arlington, Va. November 1974.
Prepared for the Council on Environmental Quality. Published by
the Federal Energy Administration Project Independence Blueprint
Interagency Task Force on Conservation. Energy consumption per
unit of output: 1975 =1.0.
All industry estimate.
D-4
-------
TABLE D-2. SAMPLE CALCULATION OF PROJECTED ENERGY DEMAND BY INDUSTRY
Industry
Food
Texti 1 es
Paper
Chemicals
SCG
Steel
Aluminum
Other
TOTAL
1974 Total Energy3
1012kJ (1012 Btu) x
54.6
21.6
90.6
237.6
129.1
443.0
6.5
252.8
1235.8
(51.8)
(20.5)
(85.9)
(225.2)
(122.4)
(419.9)
(6.2)
(239.6)
(1171.5)
Ind. Prod.
Growth Factor
1.52
1.32
1.30
1.41
1.36
0.96
0.96
1.32
-
Conservation
x Factor
0.949
0.844
0.871
0.842
0.827
0.825
0.825
0.844
-
Projected
1985 Total Energy
= 1012 kJ (1012 Btu)
78.8
24.1
102.7
282.1
145.3
350.9
5.2
281.6
1270.5
(74.7)
(22.8)
(97.3)
(267.4)
(137.7)
(332.6)
(4.9)
(266.9)
(1204.3)
Includes coal, distillate and residual fuel oil and natural gas in the
Middle Atlantic region. Excludes energy consumption in the Petroleum
Refining industry and feedstocks.
Ratio of projected 1985 value added statistic divided by the historical 1974 value added
statistic (both terms in constant dollars) for the Middle Atlantic Region.
Energy consumption per unit of production: 1975 = 1.0. Industry-specific factors.
Do not vary by region.
D-5
-------
TABLE D-3. COMPARISON OF THE PRELIMINARY PROJECTION AND A
MEFS PROJECTION OF REGIONAL TOTAL FOSSIL FUEL DEMAND IN 1985
Region
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
NE
NY/NJ
MA
SA
MW
SW
C
NC
W
NW
TOTAL
1985
Projected Fossil Fuel
1.012kJ (1012 Btu)
Preliminary
Projection
351.0
637.1
1270.6
2232.0
2417.0
4556.8
905.3
604.7
839.1
475.5
14289.0
(332
(603
(1204
(2115
(2291
(4319
(858.
(573.
(795.
(450.
(13544
.7)
.9)
-3)C
.6)
.0)
.2)
1)
2)
4)
7)
.1)
Demand Compound Annual
1974-85
MEFS
Projection
571.6
424.6
1195.7
1676.5
2279.4
4418.1
495.6
515.7
1210.7
415.5
13230.5
(541.
(402.
(1133.
(1589.
(2160.
(4187.
(469.
(488.
(1147.
(393.
(12515.
8)
5)
4)
1)
6)
8)
8)
8)
6)
9)
4)
Preliminary,
Projection
1.
0.
0.
2.
0.
0.
2.
3.
-0.
1.
0.
25
13
25
52
40
84
51
12
76
69
96
Growth Rate
(Percent)
MEFS
Projection
5.
-3.
-0.
-0.
-0.
0.
-2.
1.
2.
0.
0.
84
49
95
11
14
57
95
64
60
45
23
Excludes energy consumption in the Petroleum Refining industry and feedstocks.
''Growth rates are calculated assuming 1974 ECDB data as the base year data.
"Derivation presented in Table D-2.
D-6
-------
FIGURE D-l
FEDERAL REGIONS
Boston
New York City
Philadelphia
Washington D.C.
uxru I null
-------
within a region will not change on a relative basis. For example, the
preliminary projection indicates 2.3 quads of fuel use in the Midwest
region in 1985 while MEFS only predicts 2.16 quads of fuel use in that
region (see Table D-3). Therefore, each industry's fuel demand within the
Midwest region is reduced by 6 percent.*
This same procedure takes place for 1990 and 1995. Note that MEFS
also provides specific fuel use detail on the Petroleum Refinery sector;
thus, normalization of fuel use in this industry is not necessary.
D.4 RESULTS AND CONCLUSIONS
Several problems exist with the method used to project 1985 fossil
fuel demand. Differences in data bases, assumptions, and logic contribute
to the differences between preliminary industry projections and MEFS regional
totals. The program used to reconcile these results is fairly reasonable
only if the projected industry results are close to MEFS.
Table D-3 compares preliminary industry projections to a set of 1985
MEFS regional totals. The preliminary projection overstates regional fuel
consumption in most regions as compared to MEFS. Only in regions 1 and 9
are the MEFS fuel demand figures greater than those in the preliminary
projection. Region 7 shows a significant discrepency in the growth rates
for the two projections, the preliminary projection shows a
compound annual growth of 2.51 percent, whereas the MEFS projection shows
a decline of 2.95 percent.
(2.3 - 2.16)72.3 = 0.06.
0-8
-------
APPENDIX E. SIZE AND CAPACITY UTILIZATION OF
NEW INDUSTRIAL BOILERS
E.I INTRODUCTION
This appendix presents the methodology used in deriving IFCAM's size/
capacity utilization distribution for new boilers. This derivation was
based on two sources, EPA's National Emissions Data System (NEDS) and
PEDCo's study of the characteristics of industrial boilers in the U.S. The
second section of this appendix explains the procedure of obtaining the
distribution. The third section discusses some biases and other issues and
caveats pertaining to the data and the methodology.
E.2 DERIVATION OF THE BOILER SIZE/CAPACITY UTILIZATION DISTRIBUTION
E.2.1 Approach
The NEDS data base covers more than 94,000 emission sources at nearly
34,000 facilities. However, the NEDS data are not comprehensive because
this data base includes only those sources with a potential of emitting
more than 100 tons per year of any one of five major pollutants. The
information collected is related to air pollution emissions, stacks, and
control equipment. Data are also collected on the location, industry,
combustor type, fuel type, and operating rate.
Boiler records with operating rates greater than 100 percent of design
capacity at 8,760 hours per year were screened from the entire file. This
preliminary distribution was adjusted to correspond with the aggregate
industrial boiler size distribution presented in the PEDCo report.* The
*The PEDCo report includes estimates of the 1977 industrial/commercial
boiler inventory by type and size, but it does not contain estimates by
industry.
E-l
-------
adjusted distribution was used to estimate the mix of sizes and capacity
utilization rates for new boilers.
Table E-l compares the data from the two sources. As can be seen,
there is a significant difference between the two, especially in the 10-50
and 100-250 MMBtu/hr category. The reason for the difference is that the
NEDS data do not account for all firetube and small watertube boilers. This
is due to the criteria by which the NEDS data were collected (i.e. combustors
emitting pollutants below a certain minimum were not included in the survey).
Another reason for this difference is the editing performed on the NEDS
file (to delete inconsistent records which lacked key data elements or with
capacity utilizations greater than 100 percent) which essentially eliminated
a number of data sets and may .have created a bias in the relative distribution.
£.2.2 Application of the Methodology
The first step in the formulation of the size/capacity utilization
distribution was to create boiler size categories that were consistent with
both data sets. There were some complications in the way the two data sets
aggregated their boilers. The most prominent problem was in the 100-250
MMBtu/hr category. The aggregate number from PEDCo's report was restricted
to the 100-250 MMBtu/hr range. This rated capacity number was broken down
into the two required size categories using relative weights from the NEDS
data.* A similar procedure was followed in breaking down the 50-100 MMBtu/hr
size category.
The second step was to partition PEDCo's aggregate rated capacity
number for each boiler size "class into industrial totals. The weights
*The boiler size categories developed for IFCAM are shown in Table E-2.
E-2
-------
TABLE E-l. COMPARISON OF NEDS AND PEDCo DATA
(Percent of Total Industrial Capacity)
Boiler Size Class PEDCo3
MW(MMBtu/hr)
2.9-14.7 (10-50) 33
14.7-29.3 (50-100) 17 .
29.3-73.3 (100-250) 22
>73.3 ( >250) 28
NEDS
14
19
38
29
a Devitt, T. et.. at.., pp. 17, 19.
E-3
-------
TABLE E-2. REPRESENTATIVE NEW BOILER SIZE/CAPACITY UTILIZATION
RATE CATEGORIES
Boiler
Range
MW(MMBtu/hr)
2.9-8.8(10-30)
8.8-14.7(30-50)
14.7-22.0(50-75)
22.0-29.3(75-100)
29.3-51.3(100-175)
51.3-73.3(175-250)
>73.3 (>250)
Size
Representative
Unit
MW(MMBtu/hr)
5.9(20)
11.7(40)
18.2(62)
25.5(87)
40.1(137)
62.1(212)
95.2(325)
Capacity
Range
0-30
30-50
50-60
60-70
>70
Uti 1 ization(Percent)
Representative
Rate
25
45
55
65
75
E-4
-------
used for this industrial breakdown of the aggregate number were from the
rated capacity distribution in NEDS. Thus, for every industry and boiler
size class, there was a representative rated capacity figure in each cell.
The third step was to apportion the rated capacity figure for each
size class (for a given industry) into five capacity utilization rate
categories.* The weights used to proportion the rated capacity figure for
each size class into capacity utilizations categories were derived once
again from the NEDS data.
Using the representative sizes and capacity utilization rates an
actual fuel use distribution was derived. The actual fuel use was calcu-
lated as follows:
Actual fuel use = Rated capacity(MMBtu/hr) x capacity
utilization fraction x 8760(hrs/yr).
Next the fuel use figure in each cell was divided by the all industry total
r
to derive the percentage of total industrial fuel used in each cell. The
final step in this exercise was to reduce the potential fuel use cells to a
manageable amount given the limitations of computing time. There are
potentially (9 industries x 7 boiler sizes x 5 capacity utilization rates)
315 fuel use cells. A number of these cells had zero fuel use in them and
others had a negligible fraction of the total industrial boiler fuel use.
This distribtuion was adjusted accordingly and certain cells were aggregated
to develop a more pragmatic distribution. The final distribution of 111
cells is presented in Table E-3.**
*The capacity utilization rates developed for IFCAM are shown in Table E-2.
**The entry in each cell of Table E-3 is the fraction of that industry's
total new boiler fuel use.
E-5
-------
TABLE E-3. NEW INDUSTRIAL BOILER SIZE/CAPACITY UTILIZATION DISTRIBUTION
Major
Industry
Food
Boiler Size Capacity
MW (MMBtu/hr) Utilization
5.86(20)
5.86(20)
11.72(40
11.72(40)
11.72(40)
18.17(62)
18.17(62)
25.50 87)
.25
.75 '
.25
.45
.75
.25
.45
.25
40.15(137) .25
40.15(137) .75
62.13(212) .25
62.13(212) .75
95.25(325) .25
95.25(325) .65
Paper
5.86(20)
5.86(20)
11.72(40)
11.72(40)
11.72(40)
18.17(62)
18.17(62)
25.58(87)
25.58(87)
.25
.75
.25
.45
.75
.25.
.75
.25
.75
40.15(137) .25
40.15(137) .45
40.15(137) .75
62.13(212) .25
62.13(212) .75
95.25(325
95.25(325
95.25(325
.25
.45
.55
95.25(325) .75
Frequency
.080
.053
.073
.064
.078
.050
.0474
.067
.1321
.0585
.046
.042
.06
.149
.0223
.0265
.0192
.0286
.0416
.0348
.0265
.0239
.0296
.0260
.0249
.1045
.0208
.0784
.0613
.0411
.1301
.2599
E-6
-------
TABLE E-3. NEW INDUSTRIAL BOILER SIZE/CAPACITY UTILIZATION DISTRIBUTION
(continued)
Major
Industry
Chemicals
Textiles
Boiler Size
MW (MMBtu/hr)
5.86(20)
5.86(20)
5.86(20)
11.72(20)
11.72 40)
11.72(40)
11.72(40)
18.17(62)
18.17(62)
18.17(62)
25.50(87)
25.50(87)
40.15(137)
40.15(137)
40.15(137)
40.15(137)
62.13 212)
62.13(212)
62.13(212)
95.25(325)
95.25(325)
95.25(325)
95.25(325)
5.86(20)
5.86(20)
11.72(40)
11.72(40)
11.72(40)
25.50(62)
25.50(62)
40.15(87)
62.13(212)
Capacity
Utilization
.25
.45
.75
.25
.45
.65
.75
.25
.65
.75
.25
.65
.25
.45
.55
.75
.45
.65
.75
.25
.45
.65
.75
.25
.75
.25
.45
.75
.25
.75
.25
.45
Frequency
.023
.024
.0355
.036
.0254
.0182
.0605
.0283
.0206
.0322
.0154
.0470
.0331
.0221
.0307
.0998
.025
.0379
.0504
.0413
.0413
.084
.1683
.163
.081
.151
.067
.111
.063
.083
.081
.2
E-7
-------
TABLE E-3. NEW INDUSTRIAL BOILER SIZE/CAPACITY UTILIZATION DISTRIBUTION
(continued)
Major
Industry
Petroleum
Refining
Aluminum
Stone, Clay,
& Glass
Steel
Boiler Size
MW (MMBtu/hr)
5.86(20)
11.72(40)
11.72(40)
18.17(62)
18.17(62)
25.50(87)
40.15(137)
40.15(137)
62.13(212)
95.25(325)
95.25(325)
11.72(40)
11.72(40)
18.17(62)
40.15(137)
95.25(325)
95.25(325)
5.86(20)
5.86(20)
11.72(40)
40.15(137)
5.86(20)
11.72(40)
18.17(62)
25.50(87)
40.15(137)
40.15(137)
62.13(212)
95.25(325)
95.25(325)
Capaci ty
Utilization
.25
.65
.75
.45
.75
.75
.25
.75
.75
.25
.75
.25
.75
.45
.75
.25
.75
.25
.75
.75
.75
.75
.55
.55
.45
.45
.75
.75
.25 '
.75
Frequency
.0656
.0729
.1749
.0376
.0631
.0856
.0425
.0874
.0656
.0862
.2186
.204
.14
.097
.333
.113
.113
.1365
.146
.3249
.3926
.055
.1051
.1442
.0891
.1577
.071
.071
.1193
.1876
E-8
-------
TABLE E-3. NEW INDUSTRIAL BOILER SIZE/CAPACITY UTILIZATION DISTRIBUTION
(continued)
Major
Industry
Boiler Size
MW (MMBtu/hr)
Capaci ty
Utilization
Frequency
Other
5.86(20)
5.86(20)
5.96(20)
5.96(20)
11.72(40)
11.72(40)
11.72(40)
18.17(62)
18.17(62)
25.50(87)
40.15(137)
40.15(137)
40.15(137)
62.13(212)
62.13(212)
95.25(325)
95.25(325)
.25
.45
.55
.75
.25
.45
.75
.25
.65
.55
.25
.45
.75
.25
.75
.45
.75
.086
.0297
.0356
.0391
.1017
.0688
.0582
.05
.0664
.0669
.0524
.0508
.0336
.025
.0244
.1055
.1059
E-9
-------
E.4 SOME ISSUES AND CAVEATS
This section will address those issues in the methodology which may
introduce some bias and other areas not considered in the development of
this distribution. The boiler size/capacity utilization distribution is
based on historical data. If there are certain trends toward smaller
boiler sizes and/or higher capacity utilization- rates over time, this
distribution will not capture them and, hence, introduces some bias in the
fuel choice.
Before the present form of the distribution was developed, a study was
conducted analyzing the factors that influence capacity utilization rates.
Since this is an important issue with respect to fuel choice decisions, the
following factors that would potentially affect capacity utilization rates
were investigated:
Functional use (space heat, process steam, etc.)
Industry group
Age
Size of boiler
Fuel type/price
0 Plant boiler capacity in relation to annual steam demand.
Using MFBI data, a regression analysis incorporating these factors was
performed. The results of the study indicate that size and industry group
were significant in explaining the variance in the capacity utilization
rates. The other variables did not consistently have as strong an influence
2
on the capacity utilization rates. Given this study, the distribution was
constructed to account for the industrial variation and boiler size class
effects on capacity utilization rates by including nine industrial sectors
and seven boiler size classes.
E-10
-------
It is important to realize that the variables listed above probably
explain only a small share of the variance in boiler capacity utilization
rates. A large part of the variance is most likely a function of techno-
logy and site specific consideration both of which are difficult to quantify.
Historical data, on which the boiler size/capacity utilization distribution
is based, may implicitly account for most of these influences.
E-ll
-------
REFERENCES
1. Devitt, T., P. Spaite, L. Gibbs. Population and Characteristics of
Industrial/Commercial Boilers in the U.S. PEDCo Environmental, Inc.
Cincinnati, Ohio. Publication No. EPA-600/7-79-178a. Prepared for
the Industrial Environmental Research Laboratory, U.S. Environmental
Protection Agency. August 1979. 462 p.
2. Industrial Fuel Choice Analysis Model. Volume II. Appendices to
Model Documentation. Appendix F. Energy and Environmental Analysis,
Inc. Arlington, Va. Draft report prepared for the Office of
Policy and Evaluation, U.S. Department.of Energy. January 1979.
E-12
-------
APPENDIX F. INDUSTRIAL BOILER AND POLLUTION
CONTROL COST DATA
F.I INTRODUCTION
This appendix summarizes the capital and annual non-fuel operating and
maintenance (O&M) costs for industrial boilers and pollution control equip-
ment. The pollution control equipment includes flue gas desulfurization
(FGD) systems, particulate control devices, and combustion modifications
for NO control. Coal cleaning is also an alternative compliance strategy
A
and is discussed in this appendix.
j
Oil hydrodesulfurization is discussed in Appendix I. Low Btu gasifi-
cation, atmospheric fluidized bed combustion, and flue gas treatment tech-
niques for NO control are future model features and preliminary costs are
A
not presented in this report.
Retrofit as well as new unit capital cost estimates for industrial
boilers are presented in this appendix. IFCAM does permit fuel switching.
Data sources and key assumptions are discussed. Sample costs are also
presented in numerous tables.
F.2 INDUSTRIAL BOILER COSTS
F.2.1 New Boilers
F.2.1.1 Data Sources
PEDCo Environmental, Inc. has developed costs for new industrial
boilers for several fuel types and boiler sizes. The fuel types included
natural gas, distillate fuel oil, residual fuel oil and four coal types
(see Table F-l). Eleven standard boilers were selected as representatives
of the industrial boiler population (see Table F-2) and detailed cost
estimates were developed for each.
F-l
-------
TABLE F-l FUEL TYPE CHARACTERISTICS0
Fuel Type
Percent Sulfur Percent Ash Heating Value
Natural gas
Distillate fuel oil
Residual fuel oil
Trace
0.50
3.00
Trace 50,707 kJ/kg
21,800 Btu/lb
1,000 Btu/ft3
Trace 45,346 kJ/kg
19,500 Btu/lb
139,000 Btu/gallon
0.10 43,043 kJ/kg
18,500 Btu/lb
149,800 Btu/gallon
Eastern high
sulfur coal
Eastern medium
sulfur coal
Eastern low
sulfur coal
Western sub-
bituminous coal
3.54
2.28
0.90
0.60
10.. 58
13.20
6.86
5.40
27,447 kJ/kg
11,800 Btu/lb
30,703 kJ/kg
13,200 Btu/lb
32,099 kJ/kg
13,800 Btu/lb
22,330 kJ/kg
9,600 Btu/lb
Devitt, T. et.al., pp. 93, 94, 97, 104.
F-2
-------
TABLE F-2. REPRESENTATIVE BOILERS SELECTED FOR EVALUATION1
Boiler Type
Package, Scotch firetube
Package, Scotch firetube
Package, watertube, under-
feed stoker
Package, watertube
Field-erected, watertube,
chain-grate stoker
Package, watertube
Package, watertube
Package, watertube
Field-erected, watertube
spreader stoker
Field-erected, watertube
Field-erected, watertube
Fuel Type
Distillate Oil
Natural Gas
Coal
Residual Oil
Coal
Residual Oil
Distillate Oil
Natural Gas
Coal
Pulverized Coal
Pulverized Coal
Heat Input
MW (MMBtu/Hr)
4.4 (15)
4.4 (15)
8.8 (30)
8.8 (30)
22.0 (75)
44.0 (150)
44.0 (150)
44.0 (150)
44.0 (150)
58.6 (200)
117.2 (400)
Devitt, T. et. al., p. 89.
F-3
-------
Based on this background work and the PEDCo/DOE Boiler Cost System,
2
algorithms were developed by PEDCo for estimating industrial boiler costs.
These equations are a function of:
t Fuel type
0 The boiler firing rate (MMBtu/hr)
Capacity factor
Heating value and ash content (for coal)
There are also separate equations for:
Capital costs
- equipment
- installation
- indirect
Annual O&M costs
- utilities and chemicals
- direct labor
- supervision
- maintenance
- replacement parts
- overhead
F.2.1.2 Key Assumptions
Table F-3 presents the seven boiler sizes classes in IFCAM and the
representative boiler type for each size class. Note that multiple package
oil/gas watertube boilers are used instead of a single field-erected unit.
\
This results in a significant reduction in capital costs. Capital costs
are not assumed to vary by region or increase in real terms over time.
F-4
-------
TABLE F-3. INDUSTRIAL BOILER TYPES
Boiler Size
MMBtu/hr
Category
(MW)a
Representative
Range Size
10-30
(2.9 - 8.8)
30-50
(8.8 - 14.7)
50-75
(14.7 - 22.0)
75-100
(22.0 - 29.3)
100-175
(29.3 - 51.3)
175-250
(51.3 - 73.3)
>250
(>73.3)
20
(5.9)
40
(11.7)
62
(18.2)
87
(25.5)
137
(40.2)
212
(62.1)
325
(95.3)
Coal
package,
watertube,
underfeed
stoker
package,
watertube,
underfeed
stoker
field-erected,
watertube, .
chain grate
stoker
field-erected,
watertube,
spreader stoker
field-erected,
watertube,
spreader stoker
field-erected,
watertube,
pulverized coal
field-erected
watertube,
pulverized coal
Type
Residual Oil/
Natural Gas
package,
firetube
package,
watertube
package,
watertube
package,
watertube
package,
watertube
two package,
watertube
two package,
watertube
Distillate Oil/
Natural Gas
package,
f i retube
package,
watertube
package,
watertube
package,
watertube
package,
watertube
two package,
watertube
two package,
watertube
3 Heat input.
estimates.
F-5
-------
Annual non-fuel operating costs for package watertube oil/gas boilers
and all coal-fired boilers are based on a dual-unit facility. This assump-
tion lowers annual operating costs compared to a single boiler facility
because the utilities and labor requirements are shared. Annual non-fuel
O&M costs are not assumed to vary by region or increase in real terms over
time.
F.2.1.3 Cost Elements
The costs are based on a Greenfield boiler installation located in the
Midwest. The battery limits of the boiler facility extend from the fuel-
receiving equipment to the ash disposal operation, inclusively. Excluded
are steam and condensate piping beyond the boiler building and pollution
control equipment. The basic equipment items are listed in Table F-4.
Capital costs include both direct and indirect cost components.
Direct costs include equipment, auxiliaries, and installation estimates.
Indirect costs include estimates for engineering, construction and field
expense, construction fees, startup and performance. Although not included
specifically as part of the capital cost equations, estimates for contingen-
cies, land, and working capital have also been added. The O&M cost compon-
ents are presented in Table F-5.
F.2.1.4 Cost Data
Capital and annual O&M cost estimates for industrial oil/gas boilers
for each representative boiler size in IFCAM are presented in Tables F-6
and F-7. These costs do not vary substantially by fuel type. The capital
costs are identical for distillate fuel oil- and natural gas-fired boilers
except for working capital.* The cost estimates for natural gas assume
* Raw material stocks and O&M costs for a three-month period.
F-6
-------
TABLE F-4. BASIC EQUIPMENT AND INSTALLATION ITEMS INCLUDED
IN A NEW BOILER FACILITY3
Equipment:
Boiler (with fans and ducts)
Stack
Instrumentation
Pulverizers or stoker system
Feeders
Crushers
Deaerator
Heaters
Boiler feed pumps
Condensate systems
Water treating system
Chemical feed
Compressed air system
Coal handling system
Ash disposal system
Thawing equipment
Fuel oil system
Installation:
Foundations and supports
Duct .work (not included with boiler)
Piping
Insulation
Painting
Electrical
Building
Devitt, T. et al.s p. 130.
F-7
-------
TABLE F-5. BOILER NON-FUEL ANNUAL O&M COST COMPONENTS3
Direct Indirect
Direct Labor Overhead
Supervision - payroll
Maintenance labor . - plant
Maintenance materials General and administrative costs
Replacement parts Taxes
Electricity Insurance
Steam Interest on working capital
Cooling water
Process water
Bottom ash disposal
Chemicals
Devitt, T. et al., p. 122.
F-8
-------
TABLE F-6. NEW INDUSTRIAL OIL/GAS BOILER CAPITAL .COSTS3
(000 $1978)
Boi
MW
5.9
11.7
18.2
25.5
40.2
62.1
95.3
ler Sizeb
(MMBtu/hr)
(20)
(40)
(62)
(87)
(137)
(212)d
(325)d
Natural0
Gas
387
821
1,077
1,438
1,799
2,619
3,478
Distillate
Fuel Oil
405
825
1,083
1,455
1,811
2,598
3,462
Residual
Fuel Oil
415
838
1,097
1,461
1,825
2,619
3,478
a Total cost, including direct and indirect expenses (such as
contingency, land, and working capital). Does not include
pollution control costs.
Heat input.
Assumes dual-firing with distillate fuel oil except for single-
fuel package firetube boilers (5.9 MW., 20 MMBtu/hr).
Assumes two package watertube boilers., not a single field-erected
watertube boiler.
F-9
-------
TABLE F-7. INDUSTRIAL OIL/GAS BOILER ANNUAL O&M COSTS3
(000 $1978)
Boiler
MW
5.9
11.7
18.2
25.5
40.2
62.1
95.3
Sizeb
(MMBtu/hr)
(20)
(40)
(62)
(87)
(137)
(212)
(325)
Annual
0&MC
159 -
201 -
236 -
276 -
351 -
680 - 1,
890 - 1,
297
352
411
480
612
193
574
a Total costs including direct and indirect expenses.
Does not include pollution control or fuel costs.
Heat input.
c The low end of the range represents a 25 percent
capacity utilization rate and the high end repre-
sents a 75 percent capacity utilization rate.
F-10
-------
dual-fuel firing with distillate fuel oil, except for the package firetube
boiler (5.9 MW, 20 MMBtu/hr). Residual oil-fired boilers are slightly more
3
expensive primarily because of a more expensive fuel oil system. The
4
labor requirements are identical for oil- and gas-fired boilers. Most
other non-fuel O&M cost components do not vary by fuel type, except for
small differences in working capital and other indirect costs* which are a
function of the capital cost estimates.
Sample costs for industrial coal-fired boilers are presented in Tables
F-8 and F-9 for four coal types. Four coal types out of the 39 coal types
in IFCAM were selected to illustrate the sensitivity of the cost estimates
to the type of coal. Major characteristics of each sample coal type are
shown in Table F-10.
F.2.2 Retrofit of Existing Boilers
Data on the cost of installing new boilers were obtained primarily by
contacting boiler manufacturers. The costs of retrofitting an existing
boiler to an alternate fuel type were developed from three sources:
1) industrial users who had retrofitted their boilers: 2) equipment vendor
quotations for the cost of installing each piece of equipment necessary to
complete conversion; and 3) data contained in previous studies.
F.2.2.1 Key Assumptions
Retrofitting boilers implies shifting from an existing fuel to an
alternate fuel. Since we are considering four fuel types, each boiler has
three retrofit options; however, there are some restrictions on these
options. We assume that no coal boiler will retrofit away from coal because
of economic and legal considerations. We further assume that no residual
* General and administrative, taxes and insurance.
F-ll
-------
TABLE F-8. SAMPLE NEW INDUSTRIAL COAL BOILER CAPITAL COSTS3
(000 $1978)
Coal Type
Boiler Sizeb
MW (MMBtu/hr)
5.9
11.7
18.2
25.5
40.2
62.1
95.3
(20)
(40)
-(62)
(87)
(137)
(212)
(325)
Eastern
High Sulfur
1,536
2,397
3,716
5,013
7,360
12,482
16,018
Eastern
Low Sulfur
1,287
2,010
3,477
4,690
6,884
11,930
15,392
Midwestern Western
High Sulfur Low Sulfur
1,459
2,278
3,647
4,917
7,221
12,339
15,862
1,848
2,883
3,982
5,374
7,888
12,870
16,457
Total cost, including direct and indirect expenses (such as contingency,
land, and working capital). Does not include pollution control costs.
Characteristics of the sample coal types are summarized in Table F-10.
Heat input.
F-12
-------
TABLE F-9. SAMPLE INDUSTRIAL COAL BOILER ANNUAL O&M COSTSa
(000 $ 1978)
Boiler Size
MW (MMBtu/hr)
5.9
11.7
18.2
25.5
40.2
62.1
95.3
(20)
(40)
(62)
(87)
(37)
(212)
(325)
Eastern
High Sulfur
288-477
396-644
535-839
633-966
834-1,242
1,332-2,061
1,730-2,712
Coal
Eastern
Low Sulfur
261-438
356-586
524-823
617-943
810-1,206
1,305-2,020
1,687-2,648
Type
Midwestern
High Sulfur
275-453
377-607
530-831
625-955
822-1,215
1,319-2,034
1,708-2,648
Western
Low Sulfur
308-486
426-657
542-839
642-966
846-1,242
1,337-2,047
1,730-2,669
Total costs includes direct and indirect expenses. Does not
include pollution control or fuel costs. The low end of the range
represents a 25 percent capacity utilization and the high end
represents a 75 percent capacity utilization. Characteristics of
the sample coal types are summarized in Table F-10.
Heat input
F-13
-------
TABLE F-10. SAMPLE COAL TYPES
Major Characteristics
Coal Type
Eastern
High Sulfur
Eastern
Low Sulfur
Midwestern
High Sulfur
Western
Low Sulfur
a Other coal types
Lbs. S02
Per MMBtu
6.0
1.25
3.78
0.87
in IFCAM are
ng SOp
Per J
2,580
537
1,625
374
Percent
Sulfurb
3.28
0.83
2.18
0.39
presented in Table
Percent
Ashb
22.7
10.7
7.6
3.5
6-5.
Heating Value
Btu/lb (kJ/kg)
10,934 (25,432)
13,308 (30,954)
11,563 (26,896)
8,901 (20,704)
F-14
-------
oil boiler is likely to retrofit to distillate oil since the fuel price
differential between distillate and residual oil should equal or exceed
operating cost differentials.
When considering a retrofit to coal, two cases are possible depending
on whether or not the boiler originally was designed to burn coal. The
retrofit costs associated with each case can vary significantly. The two
cases are described below.
Coal-Capable Boilers. Coal-capable boilers are those originally
designed to burn coal. The cost of converting coal-capable
boilers back to coal depends on the operational status of equip-
ment needed to burn coal. On one extreme, when the boiler already
is using coal, conversion can be as simple as not burning any
more oil or gas, and conversion costs are negligible. On the
other hand, if auxiliary coal-burning equipment has not been
installed, conversion can entail purchase of new equipment.
Estimating the cost of such a conversion can be accomplished only
by determining the cost of components which may need to be pur-
chased or replaced and the cost of boiler modifications. Modi-
fication costs have been derived from costs reported by industrial
users, equipment vendors, and consulting engineering studies.
The cost of new equipment which may be necessary is estimated
from basic equipment costs provided by vendors.
Non-Coal Capable Boilers. Non-coal capable boilers are units
originally not designed to burn coal. Since attempts to retrofit
to coal would involve major redesign of the furnace and possibly
an efficiency loss, the cost of retrofitting a non-coal capable
boiler to burn coal is considered to be prohibitive.*
All existing boilers are assigned the same non-fuel annual O&M
costs that are described for new boilers. Annual non-fuel O&M
costs are not assumed to increase in real terms over time.
F.2.2.2 Cost Elements
For each retrofitting option, EEA examined the effect of retrofitting
on the important components of the boiler: burner/stoker, heat exchanger
tubes, refractories, sootblowers, economizers, air blowers, and the fuel
* See Section 4.
F-15
-------
control system (valves, metering devices, return flow equipment). The
extent of change required for each of the possible retrofit cases was
estimated. The installed cost of the new component considered necessary
was estimated from costs provided by vendors. Estimates of retrofit costs
were made using this information.
Every retrofit requires burners to be replaced or stokers to be
installed. Heat exchanging tubes-need to be replaced if the boiler is
retrofitted to burn residual oil or coal. These tubes prevent ash accumu-
lation on the ribbed tubes and increase the surface area exposed to combus-
tion products. The amount of refractory brick replaced depends on the type
of fuel the boiler is retrofitted for. The change is nominal when the
boiler is retrofitted to burn gas, distillate oil, or residual oil. However,
retrofitting to coal requires extensive refractory change to prevent eutectic
formations and significant deterioration of the refractory. A change to
residual oil and coal requires installation of high-quality refractory.
Accumulated ash can reduce significantly heat transfer through tubes;
ash deposition can be severe when burning residual oil and coal. Therefore,
sootblowers, devices that use steam/air to dislodge ash accumulation, are
installed when boilers are retrofitted to these two fuels. Typically,
residual oil and coal require greater percentages of excess air for complete
combustion. Therefore, additional air blower capacities also are installed
for these fuels.
When considering the above retrofits, no site-specific data on retrofit
requirements were examined. We could, therefore, be under- or overestimat-
ing retrofit costs. This variance may be especially pronounced when retro-
fitting to coal in a coal-capable boiler. We also assume that boiler
F-16
-------
efficiency remains unaffected by retrofitting,, For some boilers, this
probably will not be the case. When retrofitting to residual oil from gas,
there is a fundamental change in heat transfer mechanisms. The combustion
of residual oil produces luminous flames which increase the radiation heat
transfer in the radiation section of the boiler. The flue gases passing
through the convection section and the superheating section of the boiler
are, therefore, at a lower temperature. This lower flue gas temperature
may pose a problem in some boilers, where the steam is superheated to high
temperatures and pressures in the convection zone. A rearrangement, by
installing superheating tubes in the radiation section, may be necessary .
F.2.2.3 Sample Costs
Table F-ll details the eight retrofit options for boiler sizes 100-250
MMBtu/hr. The cost algorithms used for each component are shown in Appen-
dix G. For a particular retrofit, the blanks in the boiler-related direct
costs suggest that no change was considered necessary. Conversion from
residual oil to distillate oil is not considered likely. Therefore, retro-
fit costs for this option were not estimated. The total retrofit costs are
summarized in Table F-12.
F.3 POLLUTION CONTROL COSTS
Table F-13 presents the pollution control technologies currently
available in IFCAM. Future additions to this list include atmospheric
fluidized-bed combustion, low Btu gas and flue gas treatment techniques* to
control NO emissions. The costs for each control technology listed in
J\
Table F-13 are presented in this appendix in the following order:
0 Physical coal cleaning
* Selective catalytic reduction.
F-17
-------
TABLE F-11 BOILER RETROFIT CAPITAL COSTS BY COMPONENT3
($1978)
00
Cost Component G to D G to R G to C D to R D to C R to C D to G R to G
Burners/stokers 33,594 36,637 503,751 36,637 503,751 503,751 30,552 30,552
Heat exchanger tubes - 216,342 216,342 .216,342 216,342
Refractory material 959 1,571 81,301 1,571 81,301 81,301 959 959
Sootblowers - 58,482 58,482 58,482 58,482 -
Air blowers - 17,942 17,942 17,942 17,942 -
Total 34,553 330,974 877,818 330,974 877,818 585,052 31,511 31,511
a Boiler size 100-250 MMBtu/hr. These costs do not include indirect costs, fuel handling, ash handling,
and pollution control systems. G-Natural Gas. R- Residual Fuel Oil. D- Distillate Fuel Oil. C- Coal
Capable Boiler.
-------
TABLE F-12. BOILER RETROFIT CAPITAL COSTS'3
($1978)
Boiler Size Class
MMBtu/hr (MW)
>250 (>73)
100-250 (29-73)
<100 (<29)
Retrofit
From
Natural Gas
Dist. Oil
Res id. Oil
Natural Gas
Dist. Oil
Resid. Oil
Natural Gas
Dist. Oil
Resid. Oil
Natural Gas
57,335
57,335
31,511
3.1,511
16,247
16,247
Retrofi
Dist. Oil
62,626
34,,553
17,,825
t To
Resid. Oil
592,273
592,273
330,974
330,974
127,337
127,337
Coalb
1,432,113
1,432,113
909,056
877,818
877,818
585,052
363,806
363,806
247,812
These costs do not include indirect costs, fuel handling, ash handling, and
pollution control systems.
Coal-capable boilers
F-19
-------
TABLE F-13. AVAILABLE POLLUTION CONTROL TECHNOLOGIES
Category
Pollutant
S09 Participate Matter NO
C. j\
Pre-Combustion
Physical Coal Cleaning0
Post-Combustion
Flue Gas Desulfurization
o Double Alkali
o Lime Spray Drying
o Sodium Spray Drying
Mechanical Collector
Wet Scrubber
Electrostatic L
Precipitatoe
Fabric Filter
Combustion
Modifications
Also reduces ash content.
Applicable to residual oil and coal.
c Combined SOp/PM control strategy; includes a fabric filter.
Applicable only to coal.
-------
t Flue gas desulfurization
0 Participate control equipment
0 Combustion modification.
F.3.1 Physical Coal Cleaning
F.3.1.1 Data Sources
Versar, Inc. and Teknekron, Inc. recently prepared a report for EPA
which evaluated three SC^ control technologies: low sulfur western coal,
physical coal cleaning to remove ash and pyritic sulfur minerals, and
chemical coal cleaning to remove ash and pyritic and/or organic sulfur
content. Physical coal cleaning was assessed as a mature technology with
plants in operation for 15 or more years. Historically, coal has been
cleaned primarily to reduce ash. Physical coal cleaning reduces potential
pollutants (SCL and particulate matter emissions), increases the heating
value and reduces product variability.
Versar, Inc. also designed several coal preparation plants and esti-
8
mated the capital and O&M costs of each. These estimates were used to
develop benefication costs for physical coal cleaning.
F.3.1.2 Key Assumptions
Table F-14 compares properties for sixteen cleaned coals (product) and
the raw, unprocessed coals (feed). Plant input was designed to be 544
metric tons (600 short tons) per hour. Annual capacity throughput was
assumed to be 1.81 million metric tons (2.0 million short tons) based upon
a 13.3 hour operating day and 250 operating days per year. The plant is
located at the mine mouth, and coal storage loading conveyors and product
loading equipment are assumed to be part of the mine and have not been
duplicated.
F-21
-------
TABLE F-14. PHYSICAL COAL CLEANING SPECIFICATIONS*
Supply
Reg i on
Northern
Appalachia
Northern
Appalachia
Northern
Appalachia
Northern
Appalachia
Northern
Appalachia
Central
Appalachia
Central
Appalachia
Central
Appalachia
Central
Appalachia
Type
Feed
Product
Feed
Product
Feed
Product
Feed
Product
Feed
Product
Feed
Product
Feed
Product
Feed
Product
Feed
Product
Percent
AshD
23.9
14.4
23.9
9.7
11.7
10.3
12.8
8.7
28.7
19.9
23.1
15.5
13.5
12.6
25.9
9.7
10.4
4.7
Percent h
Total Sulfur0
3.45
2.21
3.45
1.57
2.5
1.6
1.86
1.22
0.92
0.82
2.95
2.31
2.7
2.0
1.56
1.24
1.18
0.94
Percent h
Pyritlc Sulfur
2.51
1.34
2.51
0.95
NA
NA
1.34
0.67
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Heating Value0
Btu/lb
(kJ/kg)
11,510 (26,772)
12,971 (30,171)
11,510 (26,772)
13,704 (31,876)
13,270 (30,866)
13,960 (32,471)
13,508 (31,420)
14,139 (32,887)
10,750 (25,005)
12,072 (28,079)
11,688 (27,186)
13,002 (30,243)
13,320 (30,982)
13,580 (31,587)
11,275 (26,226)
13,960 (32,471)
13,622 (31,685)
14,487 (33,697)
Percent
Moisture
5.0
9.2
5.0
12.3
1.3
2.7
3.5
9.3
1.0
6.9
2.2
3.9
2.2
1.7
2.7
5.9
2.0
7.6
Lbs. S02
per MMBtu
(ng S02 per J)
6.0 (2579.53)
3.41 (1466.03)
6.0 (2579.53)
2.3 (988.03)
3.77 (1620.81)
2.29 (984.52)
2.75 (1182.29)
1.72 (739.47)
1.71 (735.17)
1.35 (580.39)
5.04 (2166.81)
3.55 (1526.22)
4.05 (1741.18)
2.94 (1263.92)
2.77 (1190.88)
1.77 (760.77)
1.73 (743.77)
1.30 (558.40)
-------
TABLE F-14.
PHYSICAL COAL CLEANING SPECIFICATIONS'
(continued)
Supply
Region
Central
Appalachia
Central
Appalachia
Midwest
~n
w Midwest
Midwest
Central
West
Rockies
Type
Feed
Product
Feed
Product
Feed
Product
Feed
Product
Feed
Product
Feed
Product
Feed
Product
Percent
Ash°
11.2
8.1
10.9
9.5
29.9
11.4
16.4
7.5
16.4
7.1
27.2
8.0
11.6
10.0
Heating Valueb
Percent b Percent b Btu/lb
Total Sulfur Pyritic Sulfur (kJ/kg)
0.87
0.83
0.85
0.75
4.35
3.30
2.88
1.99
2.88
1.85
5.22
4.05
0.8
0.75
NA
NA
0.41
0.34
3.13
1.80
2.01
1.06
2.01
0.91
NA
NA
NA
NA
13,891 (32,310)
14,382 (33,453)
13,845 (32,203)
14,094 (32,783)
9,782 (22,753)
12,370 (28,773)
12,120 (28,191)
13,407 (31,185)
12,120 (28,191)
13,464 (31,317)
8,011 (18,634)
10,123 (23,546)
12,620 (29,354)
12,750 (29,657)
Lbs. S0?
Percent per MMBta
Moisture (ng S02 per J)
4.2
7.4
3.0
9.9
8.0
7.3
6.0
7.8
6.0
6.8
9.3
9.3
4.9
5.4
1.25 (537.40)
1.15 (494.41)
1.23 (528.80)
1.06 (455.72)
8.9 (3826.31)
5.34 (2295.78)
4.75 (2042.13)
2.97 (1276.87)
4.75 (2042.13)
2.75 (1182.29)
13.04 (5606.18)
7.99 (3435.08)
1.27 (546.00)
1.17 (503.01)
Versar, Inc.
Dry basis.
-------
F.3.1.3 Cost Elements
The direct and indirect cost elements for the capital and O&M estimates
are presented in Tables F-15 and F-16. The direct capital costs include
the cost of equipment and auxiliaries and the labor and materials required
to install the equipment. The O&M costs do not include product transport
to the end user or the feed price.
F.3.1.4 Cost Data
The capital cost estimates were multiplied by a capital recovery
factor* and added to the annual O&M costs for the plant. This annualized
cost was divided by the total annual product yield at each plant and is
presented in Table F-17. The cleaning credit in this table is measured as
the percentage reduction in terms of Ibs SO^/MMBtu. The energy penalty
represents the energy loss in refuse plus energy consumption in the plant
expressed as a percentage of the total product yield (measured in Btu's).
Btu recovery is equal to the ratio of the total Btu in the product divided
by the total Btu in the feed.
F.3.2 Flue Gas Desulfurization (FGD)
F.3.2.1 Data Sources
Radian Corporation conducted a study for EPA to evaluate the appli-
cability of various FGD technologies for controlling S02 emissions from
Q
industrial boilers . Development status, capital and operating costs,
energy requirements, environmental impacts and performance and operating
data were all considered. Five processes were selected as candidate systems
for application to industrial boilers:
* 20 years, 10 percent discount rate: 0.1175
F-24
-------
TABLE MS. PHYSICAL COAL CLEANING CAPITAL COST COMPONENTS6
Direct
Indirect
Raw coal storage and handling
Preparation plant equipment
Refuse equipment
Thickener
Coal sampling system
Engineering
Construction and field expense
Construction fees
Contingencies
Land
Working capital
Versar, Inc.
F-25
-------
TABLE F-16. PHYSICAL COAL CLEANING ANNUAL O&M COST COMPONENTS1
Direct
Indirect
Direct labor
Supervision
Maintenance labor
Maintenance materials and
replacement parts
Electricity
Water
*
Waste disposal
Chemicals
Overhead
- payroll
- plant
General and administrative
Taxes
Insurance
Versar, Inc.
F-26
-------
TABLE F-17. PHYSICAL COAL CLEANING PARAMETERS3
Lbs.
so2
Supply Per
Region MMBtu
NA 3.41
2.30
2.29C
1.72
1.35
CA 3.55
2.94C
1.77
1.30
1.15
1.06
MW 5.34
2.97
2.75
CW 7.99
R 1.17d
ng SO,
Per J
1,466.03
998.82
984. 52
739.47
580.39
1,526.22
1,263.97
760.96
558.89
494.41
455.72
2,295.78
1,276.87
1,182.29
3,435.08
503.01
Cost ($1978)b
Per Per Per
ton MMBtu GJ
2.05
3.28
3.02
1.81
2.64
1.56
3.02
3.02
2.75
3.00
1.48
3.01
2.34
2.75
3.59
1.48
.079
.12
.108
.064
.109
.06
.108
.108
.095
.104
.052
.122
.087
.102
.177
.058
.075
.114
.102
.061
.103
.057
.102
.102
.090
.099
.049
.116
.082
.097
.168
.055
Cleaning
Credit
(%)
43
62
36
37
23
30
36
36
25
8
14
40
37
42
39
8
Energy
Penalty
(%)
6.2
12.8
8.65
3.25
10.8
6.4
8.65
8.65
12.05
7.5
2.2
10.0
7.63
12.85
19.75
10.0
Btu
Recovery
(%)
94.2
88.7
92.1
96.9
90.3
93.8
92.1
92.1
89.3
93
98
91.6
92.9
88.6
83.1
91.6
a Versar, Inc. See Table F-14 for other characteristics.
Excludes price of feed, But Josses in refuse, and transportation costs.
Expressed as dollars per unit of product.
c Characteristics were assumed to be similar to CA 1.77 Ibs. SO^/MMBtu.
Characteristics were assumed to be similar to CA 1.06 Ibs. S02/MMBtu.
F-27
-------
Sodium throwaway scrubbing
0 Double alkali
0 Lime/limestone
Spray drying
Well man-Lord
The lime/limestone process is not included as a control strategy in
IFCAM because impacts are very similar to the double alkali process. The
Wellman-Lord system is also not an available option. Sodium throwaway
scrubbing is also not a current FGD process in IFCAM because the liquid
waste treatment system in the Radian report will not remove dissolved
chlorides or sulfates in the sodium throwaway system effluent. If zero
discharge of liquid wastes is assumed, then the cost of the liquid waste
treatment system to remove sulfates and chlorides would be prohibitive.
From this report, Acurex developed detailed equations for estimating
12
capital and annual O&M costs. These algorithms are applicable for con-
trolling S02 emissions from coal and residual oil combustion. Key variables
include flue gas flow rate, sulfur content in fuel, S02 percentage reduction
requirement and boiler size. The S02 control algorithms for a sodium
throwaway system have not been incorporated in IFCAM for the reasons cited
above.
F.3.2.2 Key Assumptions
Scrubbers are not expected to remove more than 90 percent of potential
13
SOp emissions in this analysis . The cost equations for the double alkali
system are representative for S02 removal efficiencies in the range of
75-90 percent. For partial scrubbing (less than 75 percent S02 removal),
the flue gas flow rate for the double alkali system is reduced to simulate
F-28
-------
a bypass system. The flue gas passing through the double alkali scrubber
is subject to 90 percent SCL removal.
F.3.2.3 Cost Elements
Capital costs include both direct and indirect expenses (see Table F-18),
Direct costs consist of the expenses for equipment and auxiliaries as well
as the cost of installation. Scrubber O&M cost components are listed in
Table F-19.
F.3.2.4 Cost Data
Table F-20 summarizes sample FGD costs for several boiler sizes. Cost
estimates are presented for the three FGD systems currently available in
IFCAM. The sodium spray drying and lime spray drying systems are more
expensive than the double alkali system because they include a fabric
filter for joint control of SCL and PM emissions. Particulate control
costs are added to the double alkali FGD system costs to compare with the
spray drying costs in order to determine the least cost control strategy.
Table F-21 shows the variation in capital and O&M costs by percent
sulfur reduction for two boiler sizes. The capital cost for the double
alkali system is quite sensitive to the percent reduction variable, whereas
the capital cost for the spray drying systems is not.
F.3.3 Particulate Control
F.3.3.1 Data Sources
GCA Corporation prepared a report for EPA which evaluated the technical
capabilities and costs of particulate control devices. Included in the
analysis were electrostatic precipitators, fabric filters, mechanical
collectors and wet scrubbers. This report concludes that these systems are
well-advanced, commercially available and generally reliable if properly
14
operated and maintained.
F-29
-------
TABLE F-18. FGD CAPITAL COST COMPONENTS0
Di rect
Indirect
Raw material handling
S02 scrubbing
Wastewater pumps
Regeneration
Solids separation
Solids col lection
Purge treatment
Sulfur production
Utilities and services
Fabric filter (spray drying only)
Engineering
Construction and field expenses
Construction fees
Start-up
Performance test
Contingency
Land
Working capital
Radian Corporation.
Including all material and labor installation costs.
F-30
-------
TABLE F-19. FGD ANNUAL O&M COST COMPONENTS3
Direct
Indirect
Operating labor
Supervision
Maintenance labor
Maintenance materials
Electricity
Steam
Process water
Methane
Wastewater treating
Solids disposal
Lime
Limestone
Sodium carbonate
Overhead
- payrol 1
- plant
General and administrative
Property taxes
Insurance
a Radian Corporation,
F-31
-------
I.
CO
ro
TABLE F-20. SAMPLE FGD CAPITAL AND O&M COSTS BY BOILER SIZE3
(000 $ 1978)
MW
11.7
23.4
35.2
46.9
58.6
70.3
82.1
93.8
Boiler
Size5
(MMBtu/hr)
(40)
(80)
(120)
(160)
(200)
(240)
(280)
(320)
Double Alkali
Capital
721
925
1058
1179
1349
1376
1457
1511
O&M
270
297
318
339
357
368
378
401
Sodium Spray Drying
Capital
734
1060
1336
1580
1821
1908
2105
2297
O&M
306
389
463
540
607
671
742
802
Lime Spray Drying
Capital
759
1079
1347
1588
1821
1896
2091
2282
O&M
301
378
445
509
569
624
688
740
Midwestern high sulfur coal (see Table F-8). The capacity utilization for all sizes
is 55 percent and the sulfur reduction is 90 percent.
Heat input
-------
TABLE F-21. SAMPLE FGD CAPITAL AND O&M COSTS BY PERCENT
SULFUR REDUCTION FOR TWO BOILER SIZES3
(000 $ 1978)
25.5 MW (87 MMBtu/hr)b
Percent Double Alkali Sodium Spray Drying Lime Spray Drying
Sulfur
Reduction Capital O&M Capital O&M Capital O&M
10 478 239 985 306 1010 306
30 650 260 1027 319 1052 323
50 767 277 1056 340 1081 340
70 859 289 1086 365 1107 365
90 939 300 1111 402 1132 390
-n
CO
W h
62.1 MW (212 MMBtu/hr)
Percent Double Alkali Sodium Spray Drying Lime Spray Drying
Sulfur
Reduction Capital0 O&M Capital O&M Capital O&M
10
30
50
70
90
633
878
1052
1185
1307
255
286
317
337
357
1532
1604
1655
1706
1757
388
419
470
531
623
1553-
1624
1675
1716
1757
388
429
470
521
582
a
Midwestern high sulfur coal (see Table F-8-). The capacity utilization is 55 percent
for both sizes.
Heat input
c Assumes a flue gas bypass system.
-------
Eight standard boilers were evaluated for four unique emission regula-
tions. The standard boilers include those listed in Table F-2 with the
following exceptions: residual oil, 8.8 MW (30 MMBtu/hr); natural gas and
distillate oil, 44 MW (150 MMBtu/hr). The emission regulations ranged from
0.6 Ib/MMBtu (258 ng/J) to 0.03 Ib/MMBtu (12.9 ng/J). In addition, three
distinct coal types were also considered. The fuel types correspond to
those presented in Table F-l excluding the eastern medium sulfur coal.
Acurex Corporation developed detailed cost equations from data pre-
sented in this report . The cost equations are a function of the flue gas
flow rate, the uncontrolled emission rate and the percentage reduction
requirement.
F.3.3.2 Key Assumptions
GCA Corporation concluded that the only practical control device for
particulate emissions control from residual oil-fired boilers is an electro-
static precipitator. There are also technical limits on the particulate
removal capabilities (see Table F-22).
F.3.3.3 Cost Elements
The control equipment costs include estimates for the equipment and
installation of the basic collector, connecting ductwork, storage hoppers
and ash handling system. The indirect capital cost categories are identical
to those shown in Table F-18. The particulate control equipment O&M cost
components are presented in Table F-23.
The Acurex report does not include a cost equation for an electro-
static precipitator (ESP) for an oil-fired industrial boiler. The cost
equations for a "hot" ESP (sulfur content less than 1 percent) were modified
to correct the ESP plate collector area (A" in the cost equations):
F-34
-------
TABLE F-22. PARTICULATE MATTER CONTROL EFFICIENCIES3
Technology Control Limit (Percentage)
Fabric filter 99.9
Electrostatic precipitator 99.9 (coal)
90.0 (residual oil)
Wet scrubber13 98.9
Mechanical collector 80.Oc
85. Od
90.08
a Gardner, R.I. et al., p. A-l.
Restricted to particulate emission regulations less than 0.1 Ib/MMBtu
(50 ng/J). Ibid., pp. 59-61.
c Pulverized coal, >200 MMBtu/hr. (>58.6MW).
d Spreader stoker, 75-200 MMBtu/hr (22 - 58.6 MW).
e Other stokers, <75 MMBtu/hr (<22 MW).
F-35
-------
TABLE F-23. PARTICULATE MATTER CONTROL EQUIPMENT
ANNUAL O&M COST COMPONENTS3
Direct
Indirect
Direct labor
Supervision
Maintenance labor,
materials and parts
Electricity
Steam
Cooling water
Process water
Waste disposal
Chemicals
Overhead
- payrol1
- plant
General and administrative
Property taxes
Insurance
GCA Corporation.
F-36
-------
011-fired ESP: A" = X* 46.7/2118 square feet
322
where X = specific collector area (10 ft /m /sec)
= 10T
T = (1.6659* log10(PC)) + 2.6935
PC = particulate matter percent reduction
F.3.3.4 Cost Data
Table F-24 shows sample PM control costs for several boiler sizes in
IFCAM. Costs are presented for three PM control systems. The mechanical
collector is not available as a control technology for this sample due to a
high ash reduction requirement. For the smaller sizes the ESP may lower
capital costs compared to a fabric filter and vice versa for the larger
sizes. The wet scrubber costs are significantly higher than those of an
ESP and a fabric filter.
F.3.4 Combustion Modifications
F.3.4.1 Data Sources
Acurex Corporation assessed the effectiveness, applicability, costs,
and limitations of combustion modification technologies for the control of
NO emissions from industrial boilers in a recent report for EPA . The
/\
process modifications analyzed include:
Low excess air
0 Staged combustion air
- burners out of service
- overfire or sidefire air
Low NO burners
A
Flue gas recirculation
F-37
-------
I
GJ
o»
TABLE F-24. SAMPLE PM CONTROL CAPITAL AND O&M COSTS BY BOILER SIZE3
(000 $1978)
Boiler Size
MW (MMBtu/hr)
8.8 (30)
17.6 (60)
29.3 (100)
44.0 (150)
58.6 (200)
70.3 (240)
82.1 (280)
93.8 (320)
Fabric
Capital
246
381
530
694
838
890
971
1064
Filter
O&M
25
35
58
79
106
116
121
139
ESP
Capital
124
240
477
715
954
1052
1228
1403
Wet Scrubber Mechanical Collector0
O&M Capital O&M Capital O&M
12 880 108
20 974 139
43 - -
65 - - -
96 - - -
104 -
121 -
139 -
Midwestern high sulfur coal (see Table F-8). The capacity utilization for all sizes is
55 percent. The ash reduction is 98 percent for sizes <75 MMBtu/hr and 99 percent for
sizes >75 MMBtu/hr.
Heat input
The mechanical collector is not available for >90 percent ash reduction.
The wet scrubber is not available for >98.9 percent ash reduction (see Table F-22).
-------
Reduced air preheat
Ammonia injection
The standard boilers are similar to those listed in Table F-2. Three
levels of control are analyzed. The control levels vary by boiler type and
fuel type, and range from 0.1 Ib/MMBtu (43 ng/J) for natural gas to 0.7
Ib/MMBtu (301 ng/J) for coal-fired boilers.
Acurex Corporation also prepared cost algorithms for each combination
18
of boiler type and fuel type. Key variables include boiler size and NO
A
reduction requirements. Algorithms were not developed individually for
each technology listed above. Algorithms were developed for the best
control system for each boiler/fuel type category across all control levels
(see Table F-25).
F.3.4.2 Key Assumptions
There are technical limits on the effectiveness of NO reductions which
X
vary by control techniques. Table F-26 summarizes the maximum NO reduction
A
assumptions for each boiler/fuel type.
F.3.4.3 Cost Elements
The capital cost estimates include basic equipment and auxiliaries and
installation. The indirect capital and O&M cost categories are the same as
those listed in Tables F-18 and F-19, respectively. O&M cost estimates
also consider variations in boiler efficiency because air and fuel flow
controls may be modified. As a result, O&M costs may be negative in some
cases where the fuel savings (expressed as a negative fuel cost, a credit)
are larger than the labor and material expenses.
F.4 GENERIC COST ASSUMPTIONS
Table F-27 presents representative utility and commodity cost assump-
tions in IFCAM. These estimates are used in the boiler and pollution
control cost algorithms to derive expected annual O&M costs.
F-39
-------
TABLE F-25.
N0v CONTROL TECHNOLOGIES'
y\
I
o
Boi
Boiler and Fuel Type MW
Pulverized coal 59 (200)
Spreader stoker
Chain grate stoker
Underfeed stoker
Residual oil
Firetube
Watertube
Distillate oil
Firetube
Watertubec
Natural gas
Firetube
Watertube
LEGEND: - = No controls required
ND = No Data
LNB = Low NO burners
RAP = Reduced air preheat
. Acurex Corporation
Heat input
With air preheat
ler Size(s).
(MMBtu/hr)D
and 117 (400)
25 (85)
44 (150)
22 (75)
9 (30)
4.4 (15)
8.8 (30)
44 (150)
4.4 (15)
29 (100)
44 (150)
29 (100)
44 (150)
Moderate
-
SCA
-
-
-
LEA
LEA
LEA
LEA
-
RAP
RAP
LEA =
SCA =
FG^ =
t
Level of Control
Intermediate
LEA
ND
LEA
-
-
LEA
SCA
SCA
LEA
RAP
RAP
-
RAP + SCA
RAP + SCA
Low excess air
Staged combustion air
Ammonia injection
Flue gas recirculation
Stringent
SCA
NH3
SCA
LEA
LEA
SCA
LNB
LNB
FGR
SCA
SCA
-
RAP + LNB
RAP + LNB
-------
TABLE F-26. POTENTIAL NOX CONTROL FROM COMBUSTION MODIFICATIONS3
Boiler and Fuel Type Lb/MMBtu (ng/J)b
Natural gas and distillate oil
Firetube 0.06 (26)
Natural gas
Watertubec 0.156 (67)
Distillate oil
Watertubec 0.109 (47)
Residual oil
Firetube 0.067 (29)
Watertube 0.172 (74)
Pulverized coal 0.163 (70)
Spreader stoker 0.316 (136)
Other stokers 0.037 (16)
a Gardner, R.I. et. al., pp. 73-79.
Maximum amount of NO emissions removed from flue gas
With air preheat
F-41
-------
TABLE F-27. UTILITY AND COMMODITY COST ASSUMPTIONS
Component
$1978
Electricity
Solid and sludge waste disposal
Liquid waste disposal
Process water
Steam
Sodium carbonate
Lime
Ammonia
b .
$0.0258/kWh
$0.0165/kg ($15/ton)
$0.47/m3
$0.04/m3 ($0.15/103 gal.)
$3.01/GJ ($3.50/103 Ib. steam)
$0.099/kg ($90/ton)
$0.0385/kg ($35/ton)
$0.143/kg ($130/ton)
a
b
Gardner, R.I. et. al., p. D-l.
Solid waste disposal cost is assumed to be equal to the sludge
waste disposal cost.
F-42
-------
REFERENCES
1. Devitt, T. , P. Spaite, and L. Gibbs. Population and Characteristics
of Industrial/Commercial Boilers in the U.S. PEDCo Environmental,
Inc. Cincinnati, Ohio. Publication No. EPA-600/7-79-178a. Prepared
for the Industrial Environmental Research Laboratory, U.S. Environmental
Protection Agency. August 1979. 462 p.
2. Cost Equations for Industrial Boilers. PEDCo Environmental, Inc.
Cincinnati, Ohio. Prepared for Economic Analysis Branch, Office of
Air Quality Planning and Standards, U.S. Environmental Protection
Agency. January 1980. 21 p.
3. Capital and Operating Costs for Industrial Boilers. PEDCo Environ-
mental, Inc. Cincinnati, Ohio. Prepared for the Economic Analysis
Branch, Office of Air Quality Planning and Standards, U.S. Environ-
mental Protection Agency. June 1979. 265 p.
4. Devitt, T. et al., p. 136 and Cost Equations for Industrial Boilers,
Op. Cit., p. 3-3.
5. Capital and Operating Costs for Industrial Boilers. Op. Cit.
6. For a list of technical references, see Footnote 1 at the end of
Section 4.
7. Technology Assessment Report for Industrial Boiler Applications: Coal
Cleaning and Low Sulfur Coal. Versar, Inc. Springfield, Virginia and
Teknekron, Inc. Berkeley, California. Publication No. EPA-600/7-79-178c.
Prepared for Industrial Environmental Research Laboratory, U.S. Environ-
mental Protection Agency. 1979.
8. Cost, Energy and Environmental Sensitivity Analysis of Coal Cleaning
Technologies for Industrial Boiler Applications. Versar, Inc.
Springfield, Virginia. Prepared for Industrial Environmental Research
Laboratory, U.S. Environmental Protection Agency. 1979.
9. Dickerman, J.C., and K.L. Johnson. Technology Assessment Report for
Industrial Boiler Applications: Flue Gas Desulfurization. Radian
Corporation. Durham, North Carolina. Publication No. EPA-600/7-79-178i.
Prepared for the Industrial Environmental Research Laboratory, U.S.
Environmental Protection Agency. November 1979. 664 p.
10. Letter from Mobley, J.D., EPA to Wehe, A.M., EPA. May 7, 1979. Energy/
Environmental Factors for ITAR Technologies.
11. Letter from Sedman, C., EPA, to Bain, J., EPA. October 4, 1979.
Deletion of Sodium Throw-away System from IFCAM.
F-43
-------
12. Gardner, R.I., R. Chang, and L.D. Broz. Cost, Energy, and Environ-
mental Algorithms for NO , SO , and PM Controls for Industrial Boilers.
Acurex Corporation. MorrS'svitle, North Carolina. Prepared for the
Industrial Environmental Research Laboratory, U.S. Environmental
Protection Agency. December 1979. 190 p.
13. Ibid., p. A-2.
14. Roeck, D.R. and R. Dennis. Technology Assessment Report for Industrial
Boiler Applications: Particulate Collection. GCA Corporation.
Bedford, Massachusetts. Publication No. EPA-600/7-79-178h. Prepared
for the Industrial Environmental Research Laboratory, U.S. Environmental
Protection Agency. December 1979. p. 18.
15. Gardner, R.I. et. al., Op. Cit.
16. Memo from Roeck, D. GCA/Technology Division to Turner, J., EPA. August
10, 1979. Particulate ITAR: Residual Oil ESP Sizing. Letter from
Held, K., Energy and Environmental Analysis, Inc. to Pratapas, J.,
EPA. September 7, 1979.
17. Technology Assessment Report for Industrial Boiler Applications: NO
Combustion Modification. Acurex Corporation. Mountain View, Cali- x
fornia. Publication No. EPA-600/7-79-178f. Prepared for the Industrial
Environmental Research Laboratory, U.S. Environmental Protection
Agency. 1979.
18. Gardner, R.I. et al., Op. Cit.
F-44
-------
APPENDIX G. PROCESS HEAT CHARACTERISTICS AND COST DATA
G.I INTRODUCTION
This appendix presents estimates of significant parameters and cost
data for process heaters.* Major energy-intensive process heaters have
been identified in a previous report prepared by EEA. The combustion
equipment has been described and total fuel consumption has been estimated.
This appendix summarizes the fuel substitution assessments in this report
and presents estimates of averages of other characteristics and costs.
G.2 MAJOR PARAMETERS
The effect of nonboiler characteristics such as firing rate, useful
life, technical conversion capability, pollution control devices, and lead
time factors on 1) the market penetration of a newly developed coal-burning
application; 2) the selection of environmental control strategies; and 3)
the estimation of process-specific capital and non-fuel O&M expenses by
fuel type has been discussed throughout the documentation report. This
appendix provides process-specific data for each of these significant
nonboiler characteristics.
Table G-l lists estimated data of nonboiler characteristics used in
IFCAM for the major energy-intensive process applications. Data estimates
also are listed for miscellaneous processes, characterized by the following
factors:
Relative contributions to total fuel consumption are known, but
are small.
No technical potential for coal use is expected.
Equipment types are too numerous and varied to gather relative
cost data by fuel type.
G-l
-------
TABLE 5-1. DATA ESTIMATES OF NONBOUER CHARACTERISTICS
Industry
Food
Textiles
Paper
Chemicals
Petroleum
Refining
SCO
Steel .
Aluninun
Other
Firing
Rate
Description (HMBtu/hr)
Miscellaneous
Miscellaneous
Miscellaneous
Primary reformer
Primary reformer
Miscellaneous
Tubestlll heater
Tubestill heater
Tubestlll heater d/
Tubestlll heater, HR7,
Tubestlll heater, HR°',
Tubestlll heater, HK/U
Tubestlll furnace
Miscellaneous
Unit imlter glass
Unit melter glass
Regenerative ml ter
Regenerative melter
Annealing lehr
Rotary kiln (cement)
Brick tunnel kiln
Brick tunnel kiln
Refractory br. tun. kiln
Refractory br. tun. kiln
Rotary kiln (line)
Miscellaneous
Vert, shaft ftirnaee
Tr«v. grate furnace
Sintering ftirnace
Coke oven battery
Blast fur. hydroc. inj.
Blast fur. stove
Pelletiz. grate kiln
Open hearth furnace
Soaking pits
Reheat furnace
Heat treat, furnace
Miscellaneous
Rotary kiln
Urne ealciner
Anode prebake oven
Anode prebake oven
Reverbera tory furnace
Reverberatory ftirnace
Heat treat, furnace
Heat treat, furnace
Miscellaneous
All other industry
10
10
10
340
60
60 '
99
215
364
99
2 15
364
97
10
50
125
50
200
5
333
11
42
11
42
96
30
15
200
1
740
400
5
250
135
40
200
10
10
50
96
10
20
10
40
5
20
10
10
C.U."
0.75
0.75
0.75
0.94
0.96
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.55
0.55
0.55
0.65
0.65
0.65
0.55
0.65
0.65
0.55
0.55
0.55
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.75
Use1
MIL
Ex.
10
10
10
15
10
10
IS
15
15
15
15
15
10
10
S
5
S
5
10
15
15
15
15
15
15
15
25
25
25
25
25
25
25
25
25
15
15
15
10
15
20
20
10
10
10
10
10
10
(_vr) Existlnq Units New Units
New 1985 1990 1995
20 0.0000 0.0000 0.0000
20 0.0000 0.0000 0.0000
20 0.0000 0.0000 0.0000
25 0.0000 0.0000 0.0000
20 0.0000 0.0000 0.0000
20 0.0000 0.0000 0.0000
25 0.0000 0.0000 0.0000
25 0.0000 0.0000 0.0000
25 0.0000 0.0000 Q.OOOO
25 0.0000 0.0000 0.0000
25 0.0000 0.0000 0.0000
25 0.0000 0.0000 0.0000
20 0.0000 0.0000 0.0000
20 0.0000 0.0000 0.0000
. 5 O.OOSO 0.1050 0.2000
5 0.0050 0.1050 0.2000
5 0.0050 0.1050 0.2000
S 0.0050 0.1050 0.2000
20 0.0000 0.0000 0.0000
25 0.7000 0.7000 1.0000
25 0.1900 0.3000 0.5000
25 0.1900 0.3000 0.5000
25 0.1500 0.3000 0.5000
25 0.1500 0.3000 0.5000
25 0.7000 0.9000 0.9000
25 0.0000 0.0000 0.0000
30 0.0900 0.2000 0.5000
30 0.5000 0.7500 1.0000
30 O.SOOO 0.7500 1.0000
50 0.0000 0.0000 0.0000
50 0.2500 0.5000 1.0000
50 0.0000 0.0000 0.0000
30 0.5000 1.0000 1.0000
50 0.9000 0.9000 1.0000
SO 0.0200 0.1500 0.5000
30 0.0750 0.1500 0.5000
30 0.0750 0.1500 0.5000
30 0.0000 0.0000 0.0000
20 0.0000 0.0000 0.0000
25 0.7000 0.7000 1.0000
35 0.0160 0.0800 0.2000
35 0.0160 0.0800 0.2000
15 0.0280 0.0800 0.2000
15 0.0280 0.0800 0.2000
20 0.0000 0.0000 0.0000
20 0.0000 0.0000 0.0000
20 0.0000 0.0000 0.0000
20 0.0000 0.0000 0.0000
1985 1990 1995
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.1070 0.3300 0.4500
0.1070 0.3300 0.4500
0.1070 0.3300 0.4500
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 Q.OOOO
0.0000 0.0000 0.0000
0.0050 0.1050 0.2000
0.0050 0.1050 0.2000
O.OOSO 0.1050 0.2000
0.0050 0.1050 0.2000
0.0000 0.0000 0.0000
0.6500 0.6500 1.0000
0.1900 0.3000 0.5000
0.1900 0.3000 0.5000
0.1500 0.3000 0.5000
0.1500 0.3000 0.5000
0.6500 1.0000 1.0000
0.0000 0.0000 0.0000
0.0900 0.2000 0.5000
0.5000 0.7500 1.0000
0.5000 0.7.500 1.0000
0.0000 0.0000 0.0000
0.2500 0.5000 1.0000
0.0100 0.1000 0.5000
O.SOOO 1 .0000 1 .0000
0.9000 0.9000 1.0000
0.2500 0.2500 0.5000
0.0750 0.2500 0.5000
0.0750 0.2500 0.5000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.6500 0.6500 1.0000
0.0500 0.2500 0.5000
0.0500 0.2500 0.5000
0.0875 0.2500 0.5000
0.0875 0.2500 0.5000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
Conversion
from Gas tab/
Res Id.
1
11
R
N
N
N
R
R
R
N
N
N
R
N
R
R
R
R
I
R
R
R
R
R
R
R
R
R
R
R
R
N
R
R
R
R
R
R
I
R
R
R
R
R
I
[
R
R
01st.
I
I
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
I
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
Coal
I
I
I
I
I
I
N
N
N
I
I
I
I
I
R
R
R
R
I
R
R
R
R
R
R
I
R
R
R
I
R
N
R
R
R
R
R
!
1
R
R
R
R
R
I
I
I
I
Pollution
Coal
-
FGO
FOO
FGO
FGO
FGO
FGO
FGO
-
Cyclone
Cyclone
Cyclone
Cyclone
Cyclone
Cyclone
Cyclone
FGO
FGO
Cyclone
FGD
Cyclone
ESP
ESP
ESP
Cyclone
ESP
ESP
ESP
ESP
ESP
_
-
-
Canti
Coej
Type
*
-
-
'
H, .
K
F
-
-
-
H
H
*
!
Hl_
H
H
ffi
H]
If
^1
HL-
1
>1
..]
H
H
1
1
I
I
L
li
n
n
Ll
-
b/.
'Capacity utilization
Three possibilities are considered In conversion:
d/
retrofit of unit possible
new unit required
use of Fuel (s technically infeaslble
high sulfur assumed required
low sulfur assumed required
no type required because use of fuel Is technically tnfeasible
High risk.
G-2
-------
Note that because these processes are considered as a group, estimates
are incorrect to the extent that they do not adequately represent individual
miscellaneous processes. It also is important to emphasize that all data
are estimates. This is because there is a lack of data describing the
nonboiler population; for example, data on size distributions, sales, load
factors, and current ages of existing units are unavailable. The estimates
used reflect average, not extreme, projections. Average sizes and load
factors were estimated in terms of fuel input (MMBtu/hr) and the ratio of
actual annual fuel consumption to the firing rate times 8760 hrs/yr.
Useful lives are process-specific and are important because they are used
in the economic analysis to estimate the total project life in the fuel
choice decision.
The technical evaluations of fuel substitution also are process-
specific. Oil is technically feasible for most processes; however, retro-
fitting to residual fuel oil is not technically feasible for several units
and replacement by new units is required. Coal use often is technically
infeasible, and gas is technically feasible for all processes. Issues
related to these technical evaluations are discussed in Section 4. More
details on process descriptions and specific technical risk assessments are
2
discussed in recent EEA reports.
The pollution control strategy for coal also is process-specific.
Location-specific environmental regulations for specific nonboiler processes
are unavailable, as are the locations of individual nonboilers. Therefore,
reasonable uniform control strategies were selected after considering
possible product contamination and process emissions not related to fuel
type but currently being controlled by pollution abatement equipment. For
G-3
-------
residual fuel oil, low sulfur oil without pollution control equipment was
selected as the optimal control strategy for all process heat applications.
To the extent that local regulations do not require the degree of pollution
control implied by these assumptions, the total cost of burning coal (and
perhaps residual fuel oil) may be overstated.
Pollution contro,! issues are discussed in greater detail in Section 5.
Lead time factors are discussed in detail below.
G.2.1 Lead Time Factors
Lead time factors refer to the time required for commercially unproven
technologies to impact the energy marketplace. Oil and gas uses are proven
\ i
technically and economically for most nonboiler processes and delays asso-
ciated with research, development, and commercialization are not anticipated.
This is not the case for coal, however, even with government incentives.
Although coal technology is not necessarily complex, it is new to the
industrial manager and engineer. The uncertainty associated with this
novelty must be dispelled before coal will gain a large percentage of the
nonboiler market. The uncertainty due to operational reliability also nust
be resolved. After the technology is demonstrated to be commercially
viable, it still is not used 100 percent. Some potential users are not
aware of the new technology; other potential users require a process to be
proven in their competitors' facilities and at one of their own installa-
tions before adopting the technology company-wide.
In a setting without government incentives, industry would try to
develop those coal use technologies that give the greatest reward for the
lowest effort and risk. After these technologies were developed, the more
difficult, less rewarding attempts at conversion would be considered. The
G-4
-------
more difficult conversions would draw on the experience of previous non-
boiler coal uses. Industry, if unregulated, would try one conversion at a
time rather than a wholesale conversion. '
Because coal use in nonboilers could damage major pieces of production
equipment, thus the entire manufacturing process, thorough development and
demonstration of the technology is needed before a firm will consider coal
substitution. The use of coal in nonboilers requires more than basic
research; it must be matched with the intricacies of each potential process
use. This match-up, called development design, must be formulated by
design engineers from furnace vendors, coal burner vendors, and users.
\
After the design is finalized, a prototype unit must be built based on the
design. The prototype unit would be operated in a commercial-like manner
to prove the design and confirm its reliability. The prototype operation,
called demonstration, would be followed by construction of the first commer-
cial facilities. Only after design, demonstration construction, demonstra-
tion, and commercial construction periods have elapsed would coal use start
to impact the fuel market.
Once the technology is proven, it is affected by market penetration
factors. These factors indicate that much less than 100 percent of the
potential users immediately will adopt the technology. In addition, the
innovativeness of different industries affects the absolute size of market
penetration factors. For each impacted industry, market penetrations were
projected in terms of percentage of new installations over a given time
frame adopting the direct coal use technology.
The composite of demonstration periods and penetration factors projects
the future maximum market share of coal in nonboilers, assuming a favorable
G-5
-------
economic climate. It was assumed that each industry will act in an expedi-
tous but businesslike manner to move toward coal use in nonboilers. Demon-
strations were assumed to start in all areas simultaneously rather than
starting with the relatively easy conversions first and the more difficult
and expensive conversions later. No resource constraints were considered.
It also was presumed that there would be a sufficient number of demonstra-
tions in each industry. No delays were assumed between the various steps
in the commercial testing of nonboiler coal technologies.
Penetration rates depend on other variables in addition to the industry
into which the technology is being introducted. Other market penetration
variables are profitability, demand growth, rate of old capital retirement,
and risk aversion.
An example of how lead time factors affect the potential for nonboiler
coal use will make this limiting mechanism clear. Consider, for example,
atmospheric distillation in petroleum refining. In the model, the start
date is assumed to be January 1, 1979. The prototype design and construc-
tion period was estimated to be two years in duration. Eight months were
allocated to the design and 16 months to the construction: January 1, 1979
+ two years = January 1, 1981.
Providng for a one-year demonstration of the coal burning: January 1,
1981 + one year - January 1, 1982.
After demonstration, there is a two-year commercial construction
phase: January 1, 1982 + two years = January 1, 1984.
A market penetration rate of 20 percent of total market in two years,
50 percent in five years, and 75 percent in 10 years has been estimated
based on industry history of introducing a new technology.
G-6
-------
Year end 1985: 9% x amount capacity installed in 1984
+20% x amount capacity installed in 1985
= total potential coal capacity for new units
installed by 1985
Year end 1990: 30% x amount capacity installed in 1986
+40% x amount capacity installed in 1987
+50% x amount capacity installed in 1988
+55% x amount capacity installed in 1989
+60% x amount capacity installed in 1990
= total potential coal capacity in new units installed
between 1985 and 1990
The start date greatly affects total capacity, especially in the
near-term time frame.
The data in Table G-l do show lead time factors increasing over time
(from 1985 to 1995) for each process technically capable of burning coal.
Zero lead time factors correspond to processes evaluated as technically
incapable of burning coal. Processes with relatively low lead time factors
in 1995 are nonhomogeneous categories with several unique equipment types
and configurations, not all of which are likely to be capable of burning
coal due to technical or business risk assessments.
G.3 COST DATA
G.3.1 Introduction
This section describes how nonboiler costs were calculated and presents
some of the costs used in the model. The costs were divided into four
categories for this appendix:
0 New unit capital costs
Retrofit capital costs
G-7
-------
0 Auxiliary equipment costs
O&M costs
Because costs were determined by analyzing a single nonboiler and all
necessary auxiliary equipment standing alone, total costs may be slightly
overstated. In most plants, combustors share auxiliary equipment, so that
the costs are split between several units.
G.3.2 New Nonboiler Capital Costs
G.3.2.1 Methodology and Sources for Calculating Costs
Because most industrial furnaces have been designed for specific
conditions, are replaced very slowly and have burned only one or two fuels,
there are no readily available equipment costs for most processes. For a
few processes which are becoming obsolete (for example, open hearth and
vertical shaft furnaces), no new capital costs were estimated. When possi-
ble, new capital costs were obtained from furnace equipment vendors and
users. For example, direct vendor quotations were used for 50 and 200
MMBtu/hr regenerative glass melters, rotary cement kilns, and several
direct-fired iron and steel industry furnaces. In the iron and steel
industry, some furnace users were visited and others were contacted by
phone to determine equipment costs. A petroleum industry consultant also
\
was referred to in establishing petroleum industry costs. In a few cases
when costs seemed unavailable, published data from cost estimating manuals
were used to determine base costs.
For industrial process furnaces that have never burned certain fuels
(usually coal or residual oil), cost estimates had to be made without re-
ferring to outside sources. These processes were assigned costs similar to
processes which have burned these fuels and which have similar major cost
components. For example, the costs for tubestill heaters that produce
G-8
-------
hydrogen in the petroleum industry were used to estimate the costs of
primary reformers used in the chemicals industry.
In many cases, estimates were made by taking the base cost of a natural
gas-fired furnace and adding the costs of all the specific changes required
to burn an alternate fuel. In an oversimplified case, the cost of a gas
-.burner would be subtracted from the total cost of a furnace or kiln and the
cost of a compatible coal burner would be added. The general example below
shows how an original gas furnace cost would be adjusted to arrive at the
coal cost.
Base cost = gas furnace cost - burner - refractories
Coal cost = base cost + burners + refractories + sootblowers +
combustion air blowers + pulverizers
G.3.2.2 Primary Cost Determinants
The most important determinant of process equipment costs is the
design of the furnace as required by its function and intended use. Steel
reheat furnaces, for example, can be side- or roof-fired, and soaking pits
are built in one of several designs. Independently of the fuel fired, the
design and firing rate are the two key parameters which affect costs. A
large portion of capital costs, however, are determined by the fuel fired
in the furnace. In general, fuel-related costs increase as the fuel fired
changes from natural gas to distillate oil to residual oil to coal.
Because gas burns very quickly and cleanly, capital costs are lowest
for gas-fired furnaces. Distillate oil, while containing small amounts of
sulfur preventing its use in a few processes, also burns cleanly, resulting
in capital costs very close to, but slightly higher than, those in gas-fired
furnaces. Because distillate oil is liquid, mechanical atomization is
required before burning, and it cannot be used for pilot lights or in
radiant tube furnaces.
G-9
-------
Although residual oil burns with higher luminosity than gas or distil-
late oil, burning residual oil may result in some product degradation, heat
distribution problems, furnace corrosion, and plugging of heat recovery de-
vices. If residual oil can be burned, thes'e factors influence furnace
design and increase the capital cost above the costs of gas- and distillate-
fired furnaces. The extra equipment required to burn residual oil includes
atomizers, combustion air blowers, and sootblowers. Capital costs of
residual-fired furances vary, but generally are 10-50 percent higher than
those of gas-fired furances.
Coal-fired furnaces must contend with similar, but more severe, prob-
lems than those encountered in residual oil-fired furances. In addition to
equipment necessary to control these problems, pulverizers or stokers are
needed. The design of coal furnaces and the extra fuel handling, ash
handling, and pollution control equipment required can cause coal-fired
furnaces to cost three times as much as gas-fired furnaces. Column 2 of
Table G-2 shows how installed capital costs vary by fuel type for a 333
MMBtu/hr capacity rotary cement kiln.
The problems associated with burning fuels other than gas prohibit
their use in several processes. Annealing lehrs in the glass industry can
burn only gas, for example, and coke ovens and rotary aluminum kilns cannot
burn coal. The infeasible fuels were not considered in the fuel choice
decision for these processes.
G.3.2.3 Miscellaneous Processes
An attempt has been made to model the portion of nonboiler energy use
not included in the major processes by using a "miscellaneous" process in
each industry. These extra processes generally have been assigned a smaller
firing rate than most of the major processes and a capacity utilization
G-10
-------
TABLE 6-2. NEW NONBOILER COST COMPARISON FOR A
333 MMBTU/HR ROTARY CEMENT KILN3
(TO3 1978 $)
Fuel Burned
Gas
Distillate
Residual
Coal
Capital
Cost
8,630
9,403
9,789
10,549
Incremental
O&M Costb
0
90
169
434
a Includes fuel handling and ash handling systems, but excludes pollution
control costs.
Capacity utilization of 90 percent.
G-ll
-------
typical of that industry. Because these are smaller processes, it was
assumed that burning coal would be infeasible. There is also an "all other
industry" process to simulate energy use in the other manufacturing indus-
tries and in non-manufacturing industries whose processes have not been
characterized yet.
G.3.3 Retrofit Capital Costs
G.3.3.1 Methodology and Sources for Cost Calculations
Like new capital costs, retrofit capital costs strongly depend on the
specific nonboiler conditions existing before retrofitting and on the fuel
to be fired. Estimating retrofit costs is difficult because, in many
cases, the process being considered never has been fired by other fuels,
especially coal. It is not known, for example, whether firing residual oil
in a regenerative glass melter will significantly reduce the length of its
campaign. Although there is one coal-fired steel reheat furnace in England,
it is unique, and there is no simple, reliable way to estimate the cost of
retrofitting other reheat furnaces.
The first step in estimating nonboiler retrofit costs was to determine
which fuels could not be burned in certain furnaces. A technical review of
each process determined that retrofitting to a specific fuel was infeasible
if burning that fuel would result in unacceptable heat distribution, furnace
deterioration, or product quality degradation. If a process was considered
infeasible with a certain fuel, that fuel is not considered in the fuel
choice decision for that process.
For most processes, retrofitting is more a question of cost than
technical feasibility. The cost of retrofitting nonboilers was estimated
by determining, on the average, what changes must be made, and what their
G-12
-------
costs would be. The cost of retrofitting any specific process was calcu-
lated by summing the costs of replacing and adding specific equipment.
Retrofits can be divided into relatively low and relatively high cost
cases. The relatively low cost retrofits require only routine changes of
standard equipment independent of combustor type. The capital cost esti-
mates include, where necessary, modifications of burners and combustion
controls, pulverizers, refractories, sootblowers, and combustion air blowers,
Retrofitting from gas to oil firing, for example, generally requires the
same number and kind of equipment changes for any process. In these low
cost cases, the annualized cost of retrofitting per MMBtu burned varies
only over a small range ($0.01-0.05) which generally is insignificant when
compared with purchased fuel and O&M costs per MMBtu burned.
When design complications or space limitations are important, retrofit
costs may be relatively high. For example, retrofitting roof-fired reheat
furnaces away from gas requires structural changes that make costs higher
than those for standard retrofits. The model makes no adjustment for these
high cost retrofit cases because results under current price projections
have indicated that all low cost retrofits will not be made. Therefore,
there is little incentive to undertake relatively high cost retrofits.
Although the percent of retrofit possibilities that have relatively
high costs is not known, industry contacts characterize the large majority
of retrofits as standard low cost cases. Efforts have begun to visit major
industries to determine how much energy is consumed in processes with high
retrofit costs and to determine what those costs are.
G-13
-------
G.3.3.2 Component Cost Calculations
Component costs were determined primarily by contacting equipment
vendors and nonboiler users who had retrofitted or were planning to retro-
fit their units. Refractories and sootblowers are costed per unit. Burner,
pulverizer, and combustion air blower costs are defined by exponential re-
lationships, based on data for a variety of sizes. All costs are for
installed equipment in 1978 dollars.
Burners: firing rate (FR) in MMBtu/hr
Natural gas burner cost = $803 x FR°'55 x 1.19
Distillate oil burner cost = $883 x FR°'55 X 1.19
Residual oil burner cost = $963 x FR°'55 x 1.19
Coal burner cost = $13,337 x FR°'55 x 1.19
Pulverizers: Assumes 24 MMBtu/ton coal; FR in MMBtu/hr
FR < 175: Cost = $2500 x FR x 1.19
175 < FR < 375: Cost = $1143 x FR x 1.19
375 < FR: Cost = $815 x FR x 1.19
4
Refractories: SF = number of square feet to be replaced
Gas, distillate oil, = SF x $20.2 x 1.19
residual oil cost
Coal cost - SF x $33 x 1.19
Sootblowers: SB = number of sootblowers required
15 ft blower cost = SB x $17,238 x 1.19
25 ft blower cost = SB x $24,573 x 1.19
Combustion air blowers:
Total cost = $26.2 x (cu ft/min)0'68 x 1.19
Table G-3 shows a detailed cost breakdown for retrofitting rotary
cement kilns, independent of the fuel fired before retrofitting. Because
G-14
-------
TABLE 6-3. DETAILED COST BREAKDOWN FOR RETROFITTING A
333 MMBTU/HR ROTARY CEMENT KILN
($ 1978)
Cost Component
Burners
Pulverizers
Refractories
Sootb lowers
Combustion air blowers
Fuel handling
Ash handling
Fuel pile
Engineering
Contingency
Retrofit
Natural Distillate
Gas Fuel Oil
23,313 25,636
42,163
506,119
2,331 6,758
5,129 14,915
to
Residual
Fuel Oil
27,959
23,157
75,376
449,884
12,650
27,828
Coal
387,213
469,654
23,157
561,398
46,578
453,008
182,120
400,663
Total 30,773 595;I591 616,854 2,523,791
G-15
-------
firing coal requires much more equipment than firing oil or gas, retrofit
costs to coal are largely independent of the fuel previously fired. For
retrofits from distillate oil to residual oil, the model may slightly
overstate costs because it assumes that the same additional equipment is
needed in a retrofit from natural gas as is needed in a retrofit from
distillate oil. This will be the case if the distillate oil is still
burned in other places, but, if not, a distillate oil-fired furnace probab-
ly already would have most of the required fuel handling equipment and its
burners may be able to fire residual oil.
The retrofit costs used in the model may overstate the total cost of
retrofitting because the model makes no allowance for existing processes
which are dual-fired. Where combustors are capable of firing two fuels,
there are no capital costs associated with changing to the secondary fuel.
Changing fuels may require an increase or decrease in the fuel input
to maintain the same heating conditions that existed before retrofitting.
Because each fuel burns with different flame characteristics, retrofitting
could result in derating a combustor (reducing the maximum firing rate) or
changing the firing rate to maintain the same amount of heat transfer.
Derating results from flame impingement or incomplete combustion and some-
times can be prevented by installing special burners. When a new fuel is
burned, the rate of radiative heat transfer will change due to the differ-
ence in flame luminosity. In some processes, the firing rate may have to
be slightly adjusted after retrofitting to maintain the same heat transfer
conditions. Discussions with industry contacts indicate that derating will
not occur in a significant number of retrofits, and firing rates will not
change substantially. The model, therefore, makes no adjustments to the
firing rate of a furnace retrofitted to burn a different fuel.
G-16
-------
G.3.3.3 Retrofit Cost Example
To demonstrate how retrofit capital costs have been calculated, the
following simple example shows how costs are estimated for a retrofit from
a gas-fired rotary cement kiln to coal-firing. The first step is to deter-
mine whether coal firing is feasible. Since many rotary cement kilns
currently are burning coal, coal firing certainly is feasible. In cement
kilns, it even is considered beneficial because coal flame characteristics
result in improved radiative heat transfer and coal ash enhances product
quality and suppresses alkali-aggregate reactions. The lime in a cement
kiln also removes SO- from emitted gas so that coal with less than 3.5
percent sulfur can be burned without scrubbers.
The second step establishes what components of a rotary cement kiln
must be changed to fire coal. Because kiln design is not a function of the
fuel burned, no design changes are required to retrofit to coal. However,
the gas burner must be replaced with a coal burner and coal pulverizers
also must be installed to prepare the coal for burning. Higher quality
refractories are not needed since a layer of clinker protects the refrac-
tories from increased wear. Sootblowers are unnecessary because ash does
not contaminate the product. Combustion air blowers are needed because
coal requires more excess air to burn thoroughly.
A coal handling and storage system will have to be installed, but,
because ash will be absorbed as a raw material, no ash handling system will
be needed. A coal stockpile of four weeks will be purchased to guard
against delays in coal delivery. The total retrofit capital cost equals
the sum of the costs of the above changes plus 10 percent of the sum for
engineering, plus 20 percent of the above costs (including engineering) for
contingencies.
G-17
-------
G.3.4 Auxiliary Equipment Costs
Cost estimates for coal handling, ash handling, and pollution control
equipment for process heaters have been derived from previous in-house
estimates made for boilers. These costs are largely independent of the
functional use, but are a function of the firing rate.
G.3.5 O&M Costs
Annual non-fuel operating and maintenance (O&M) cost estimates were
also derived from in-house estimates made for boilers. The model disre-
gards process-related O&M costs which are constant for all fuel types. The
nonboiler O&M cost estimates focus on the differences in fuel-related O&M
costs. This methodology assumes that for a given firing rate and capacity
utilization, the differences in O&M costs between alternative fuels are the
same for boilers and nonboilers.
G.3.6 Summary Cost Tables
Table G-4 shows total installed capital costs and O&M costs for all
nonboiler processes by fuel type. These capital cost figures include costs
for the nonboiler, fuel handling system, fuel stockpile, ash handling
system if coal-fired, engineering, offsite utilities, and contingencies.
The O&M costs include expenses related to fuel and ash handling in addition
to nonboiler expenses. Pollution control costs are excluded from both
capital and O&M figures.
Table G-5 summarizes total retrofit capital cost estimates for each
process. Conversions from residual fuel oil to distillate fuel oil were
not considered likely and, as a result, estimates for this type of retrofit
were not prepared.
G-18
-------
TABLE G-4. NEW IION80ILER COST ESTIMATES3
(000 $1978)
Industry
FooJ
r«ti les
:'3Der
i'lie.nicals
Petroleum
Refining
v; ^
1 's.!l
A iii'.iinum
ilner
Process
Miscellaneous
Miscellaneous
Miscellaneous
Primary Reformer (340)d
Primary Reformer (60)
Miscellaneous
Tubestill Heater
o (99)ad
o (215)°
o (3645"
o (99) Hhigh risk
o (215)^ high risk
o (364) bigh risk
Tu&estill Furnace
Miscellaneous
Unit melter glass (50)d
Unit melter glass (125)d
Regenerative melter (50)
Regenerative melter (200)
Annealing lehrs
Notary kiln (cement)
Face brick tunnel kiln (11)"
Face brick tunnel kiln (42)d
Refractory brick tunnel
kiln (ll)a
Refractory brick tunnel
kiln (42)a
Kotary kiln (lime)
Miscellaneous
Vertical iliaft furnace
Tripling grate furnace
Sintering furnace
Coke oven
Qlast furnace
hydrocarbon injection
Blast furnace stove
Pel lelizing grate kiln
Open hearth furnace
Soaking pit
< ,
Reheat furnace
Heat treating furnace
Miscellaneous
Rotary kiln (alumina)
Lime calciner
Anode preuake oven (10)
Anode prebake oven (20)d
Rever-beratory furnace (10)
Reverberatory furnace (40)
Heat treating furnace (5)d
Heat treating furnace (20)
Miscellaneous
Miscellaneous
Natural
Gas
Capital
300
300
300
2.970
632
593
1,478
2,504
3,616
1,552
2,566
3,708
1,441
157
1,367
2,520
1,799
5,761
71
8,630
396
1,391
396
1,391
2,733
274
e
319
802
8,312
16,048
281
64.796
e
4,815
9,628
1,524
95
1,935
2,733
5,760
7,919
489
1,722
155
431
309
300
Residual
Fuel Oil
Capital
b
b
414
4,520
828
775
1,869
3,194
4.163
1,908
3,445
4,823
1,830
219
1,617
3,032
2.186
7,078
b
9,789
544
1,808
589
1.808
3,112
327
e
606
765
9,934
16,747
296
65,440
e
4,922
10,057
1,589
120
b
3,112
5,810
7,999
544
1,823
b
b
380
414
OiMc
b
b
25
174
55
50
70
119
177
69
121
181
69
25
48
82
49
121
b
169
27
46
27
46
69
25
e
76
17
240
144
5
93
e
36
79
24
23
b
69
25
31
25
40
b
b
25
25
Distillate
Fuel Oil
Capital
b
b
321
4,305
776
727
1,755
2,988
4,436
1,793
3.387
4,527
1,720
181
1.484
2,804
1,912
6.207
b
9,403
424
1.495
425
1,495
2,949
296
e
590
1,286
9,571
16,717
289
65.153
e
4,883
9,912
1.540
109
1,894
2,949
5.787
8,015
514
1,814
168
481
336
321
o&nc
b
b
20
93
34
31
42
64
95
40
69
95
41
20
31
45
30
61
b
90
20
29
20
29 "
39
20
e
46
23
136
81
4
55
e
26
48
19
19
29
39
20
24
20
29
19
24
20
20
Coal
Capital
b
b
b
b
b
b
2.279
4,225
6.481
b
b
b
b
b
2,371
4.371
2,594
8,544
b
10.549
1.106
2,706
1,106
3.772
3,392
b
e
808
844
e
19,421
312
65,887
e
5,142
11.542
1,985
b
b
3,493
6,007
8,203
574
2,111
b
b
b
b
OSMC
b
b
b
b
b
b
203
333
471
b
b
b
b
b
144
246
142
332
b
434
69
142
69
151
196
b
e
256
20
e
445
14
299
e
113
276
61
b
b
198
61
84
58
102
b
b
b
b
j* Includes pollution control costs
Technically infeasible.
Fuel-related 04M costs above those required for natural gas.
J Firing rite (MM8tu/hr).
'' :ie» units dre not expected to be built.
G-19
-------
TABLE G-5. NONBOILER RETROFIT CAPITAL COST ESTIMATES'
(000 $1978)
Retrofit To:
Industry
Food
Textiles
Paper
Chemicals
Petroleum
Refining
Process
Mi seel laneous
Miscellaneous
Mi seel laneous
Primary. Reformer
(340)c
Primary Reformer
(60)*
Miscellaneous
Tubestjll Heater
(99)d
Tubestill Heater
(215)6
Tubestill Heater
(364)C
Tubestill Heater
(99)e
(high risk)
Tubestill Heater
(215)6
(high risk)
Tubestill Heater
(364)£
(high risk)
Retrofit
From
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id .
Dist.
Gas
Res id .
Di st.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Natural
Gas
.
, 24
24
_
24
24
_
24
24
_
352
152
.
100
63
_
90
56
120
61
220
94
380
163
120
61
220
94
380
163
Residual
Fuel Oil
b
-
b
b
M>
b
118
-
118
4,109
-
4,109
752
»
752
704
_
704
378
378
703
703
1,063
1,063
1,734
1,734
3,131
3,131
4,383
4,383
Distillate
Fuel Oil
b
b
-
b
b
-
46
-
-
763
-
-
188
-
-
173
_
-
245
-
472
-
793
-
245
-
472
-
793
-
Coal
b
b
b
b
b
b
b
b
b
b
b
b
b
b
b
b
b
b
2,072
2,072
2,072
3,841
3,841
3,841
5,889
5,889
5,889
b
b
b
b
b
b
b
b
b
G-20
-------
TABLE 6-5. NONBOILER RETROFIT CAPITAL COST ESTIMATES'1
(000 $1978)
Retrofit To:
Industry
Petroleum
Refining
SCG
SCG
Process
Tubestil 1 Furnace
Miscellaneous
Unit Melter Glass
(50)C
Unit Melter Glass
(125)d
Regenerative
Melter (50)c
Regenerative
Melter (200)c
Annealing Lehrs
Rotary Kiln
(cement)
Face Brick Tunnel
Kiln (11 )c
Face Brick Tunnel
Kiln (42)c
Refractory Brick
Tunnel Kiln
/ 1 1 \ ^
Refractory Brick
Tunnel Kiln
(42)
Retrofit
From
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id .
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Natural
Gas
118
60
_
31
17
_
44
44
71
71
.
14
14
-
44
20
.
65
65
-
31
31
25
25
62
62
-
38
38
-
94
94
Residual Distillate
Fuel Oil Fuel Oil Coal
374
-
374
163
_
163
209
-
209
344
344
148
-
148
427
-
407
b
-
b
618
-
618
108
108
217
217
124
-
124
255
-
255
240
-
-
42
_
-
143
-
-
301
-
Ill
-
-
394
-
-
b
-
-
597
-
-
51
-
149
-
65
-
-
184
-
-
1,847
1,755
1,847
b
b
b
1,693
1,656
1,693
2,752
2,735
2,752
1,160
1,152
1,160
2,401
2,379
2,379
b
b
b
2,859
2,825
2,859
876
846
876
1,922
1 ,887
1,922
876
846
876
2,449
2,415
2,449
G-21
-------
TABLE 6-5. NONBOILER RETROFIT CAPITAL COST ESTIMATES'
(000 $1978)
Retrofit To:
Industry
SCG
Steel
Process
Rotary Kiln
(lime)
Miscellaneous
Vertical Shaft
Furnace
Traveling Grate
Furnace
Sintering Furnace
Coke Oven
Blast Furnace
Hydrocarbon
Injection
Blast Furnace
Stove
Pel letizing
Grate Kiln
Open Hearth
Furnace
Soaking Pits
Reheat Furnace
Retrofit
From
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id .
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Natural
Gas
15
15
_
18
18
_
13
13
.
123
123
_
1
1
_
657
657
_
132
132
-
1
1
.
2
27
-
35
35
-
13
13
-
100
100
Residual
Fuel Oil
227
-
227
98
_
98
70
-
70
551
-
551
48
-
48
1,878
-
1,878
653
-
653
13
-
13
353
-
353
305
-
305
152
-
152
437
-
437
Distillate
Fuel Oil
189
-
-
42
_
.
39
.
-
375
-
-
5
-
-
1,733
-
-
645
-
-
- 10
.
-
309
-
-
220
-
-
75
-
-
344
-
-
Coal
1,565
1,552
1,565
b
b
b
695
691
695
734
734
734
386
356
386
b
b
b
4,313
4,313
4,313
283
283'
283
2,118
2,093
2,118
2,296
2,240
2,296
1,096
1,051
1,096
3,365
3,258
3,365
G-22
-------
TABLE 6-5. NONBOILER RETROFIT CAPITAL COST ESTIMATES*
(000 $1978)
Retrofit To:
Industry
Steel
Aluminum
Other
? Excludes
Technical
Process
Heat Treating
Miscellaneous
Rotary Kiln
(alumina)
Lime Calciner
Anode Prebake
Oven (10)c
Anode Prebake
Oven (20)c
Reverberatory
Furnace (10)
Reverberatory
Furnace (40)
Heat Treating
Furnace (5)
Heat Treating
Furnace (20)
Miscellaneous
Miscellaneous
pollution control
ly infeasible.
Firing rate (MMBtu/hr).
Retrofit
From
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Res id.
Dist.
Gas
Resid.
Dist.
Gas
Resid.
Dist.
Gas
Resid.
Dist.
Gas
Resid.
Dist.
Gas
Resid.
Dist.
Gas
Resid.
Dist.
Gas
Resid.
Dist.
Gas
Resid.
Dist.
costs.
G-23
Natural
Gas
8
8
_
10
10
_
1,759
11
_
15
15
8
8
_
12
12
_
6
6
_
13
13
-
13
13
_
30
30
-
19
19
_
24
24
Residual
Fuel Oil
82
-
82
57
-
57
b
-
b
227
-
227
87
87
115
-
115
83
-
83
155
-
155
84
-
79
118
- -
118
108
-
99
114
-
114
Distillate
Fuel Oil
27
-
-
30
_
-
106
-
-
189
-
-
33
-
56
-
-
30
-
-
92
-
-
35
-
-
84
-
-
51
_
-
58
-
Coal
665
635
665
b
b
b
b
b
b
1,565
1,552
1 ,565 .
664
608
664
895
812
895
507
477
507
1,119
1,085
1,119
637
608
637
1,151
1,135
1,151
b
b
b
b
. b
b
-------
REFERENCES
2.
3.
The Technical Feasibility of Coal Use in Industrial Process Heat
Applications. Energy and Environmental Analysis, Inc. Arlington, Va.
May 1978. 353 p. Draft report prepared for the Office of Policy and
Evaluation, U.S. Department of Energy.
Ibid.
Guthrie, K.M. Process Plant Estimating, Evaluation and Control.
Sol ana Beach, California, Craftsman Book Company of America, 1974.
604 p.
5.
6.
Costs of Process Equipment. Chemical Engineering.
Standard price escalation factors were used.
Guthrie, K.M., Op_. Cit.
March 16, 1964.
Industrial Fuel Choice Analysis Model. Volume II. Appendices to
Model Documentation. Energy and Environmental Analysis, Inc. Arling-
ton, Va. January 1979. Appendix H. Draft report prepared for the
Office of Policy and Evaluation, U.S. Department of Energy.
Ibid.
G-24
-------
APPENDIX H. ENERGY SCENARIO SPECIFICATIONS
H.I INTRODUCTION
This appendix outlines the requirements for specifying an energy
scenario. The energy scenario includes:
0 Aggregate regional industrial fossil fuel demand total projections
Regional industrial production growth rate forecasts by major
industry group
Regional fuel price forecasts by fuel type
Financial parameters and energy policies.
H.2 INDUSTRIAL FOSSIL FUEL DEMAND
IFCAM estimates regional fossil fuel mixes using exogenously specified
regional industrial fossil fuel demand projections.* The industrial sector
is defined to include manufacturing, construction, agriculture, and mining.
The fuel types to be included are natural gas, distillate fuel oil,
residual fuel oil, and coal. Projections of fossil fuel consumption for
feedstock or raw material uses should not be included. Liquefied petroleum
gas, gasoline, diesel fuel, refinery (still) gas and purchased electricity
also should not be included.**
The regions are the 10 Federal regions (see Figure H-l). The units
are trillions of Btu. The time periods are 1985, 1990, and 1995.
H.3 INDUSTRIAL PRODUCTION GROWTH RATES
IFCAM total regional fossil fuel demand using regional projections of
industrial production.*** If the total regional fossil fuel demand projections
* See Input 3 in Figure 1-1.
** See Section 2.2, Energy Consumption Baseline.
*** See Input 2 in Figure 1-1.
H-l
-------
FIGURE H-l
FEDERAL REGIONS
Boston
New York City
Philadelphia
Washington O.C.
-------
are available by major industry group, this step is not required. Industrial
production growth rates may be estimated from forecasts of value added data
or Federal Reserve Board industrial production indices. The base year is
1974 and forecasts are required by region and year (1985, 1990, 1995). The
nine major industry groups are Food, Textiles, Paper, Chemicals, Petroleum
Refining, Stone, Clay and Glass,* Steel, Aluminum, and all other.**
H.4 REGIONAL FUEL PRICES
IFCAM estimates future fuel choices by comparing total expected life
cycle costs for each fuel type (including fuel prices).*** Fuel prices are
assumed to increase in real terms over time, to vary between regions but not
to vary within a region. Fuel prices are required by fuel type (natural gas,
distillate fuel oil, residual fuel oil, and coal) and region. The units
are $/MMBtu, in constant 1978 dollars.
Fuel prices are necessary for each year between 1980 and 2025. Since
IFCAM estimtes total annuaized fuel prices over the expected life of the new
boiler (about 30 years), fuel choice decisions for new boilers installed in
1995 require estimates of fuel prices until the year 2025.
Sulfur premiums of different coal and residual fuel oil sulfur classes
have been estimated.**** Projections of coal and residual fuel oil prices
by sulfur category can be used to replace these estimates.
Retail or wholesale fuel oil price projections can be modeled. F.O.B.
mine coal price forecasts can be prepared for each coal type in IFCAM and
estimates of future increases in coal transportation costs can also be
incorporated in the fuel price forecast.
* Stone, Clay and Glass is a single industrial subsector.
** Includes miscellaneous manufacturing, agriculture, mining, and construction.
*** See Input 4 in Figure 1-1.
**** 5ee Appendix I.
H-3
-------
H.5 FINANCIAL PARAMETERS AND ENERGY POLICIES
Section 6, Economics of the Fuel Choice Decision,* presents a set of
assumptions about financial parameters and energy policies. These assump-
tions can be revised to simulate a different fuel choice decision framework.
For example, discount and tax rates can be modified or the procedure for
simulating the economic test to qualify for an exemption from Fuel Use Act
policies can be changed.
*See Section 6.3.
H-4
-------
APPENDIX I. SULFUR PREMIUMS
I.I INTRODUCTION
This appendix provides a detailed description of the methodology used
to project residual fuel oil and industrial coal prices for the fuel types
in the Industrial Fuel Choice Analysis Model (IFCAM). Generally, fuel
price projections are developed from outputs of DOE's Midterm Energy Fore-
casting System (MEFS). However, the fuel types in IFCAM do not directly
correspond with the types in MEFS or in the National Coal Model. The first
section of this appendix describes the approach for estimating F.O.B. mine
prices for IFCAM coal types which is consistent with price forecasts from
equilibrium supply/demand models. F.O.B. mine prices were developed for 23
raw coals and 16 clean coals.*
The second section concerns desulfurization costs for residual fuel
oil used to set prices for fuel oils of differing sulfur contents.
1.2 DERIVATION OF COAL PRICE PROJECTIONS
1.2.1 General Approach
Simply stated, the methodology was to estimate a base price for coal
in each supply region and to estimate the sulfur premiums. The sulfur
premium associated with each raw coal was added to this base price. The
prices of the cleaned coals were calculated by adjusting the price of their
parent coals by the cleaning costs. The raw and cleaned coal prices were
also marked-up by a factor to represent spot market rates.
* Major characteristics of the 39 coal types are presented in Table 6-5
of Volume I. Coal cleaning costs are discussed in Appendix F.
1-1
-------
Two major data sources were used to develop the FOB mine prices for
the 23 raw coals: the Midterm Energy Forecasting System (MEFS) and the
National Coal Model (NCM). To be consistent with the other fuel prices
used in IFCAM, the MEFS coal prices were used to determine the base price
for each supply region, and later to normalize the sulfur premiums. The NCM
sulfur classes were used to provide a finer degree of distinction for
determining the price premiums associated with lower sulfur coals. Eight
sulfur classes were available by using the NCM coal types as compared to
three sulfur classes (high, medium, and low) from the MEFS output. The NCM
coal prices were preferred, therefore, for estimating sulfur premiums. The
coal prices from both models were representative of contract prices for the
utility sector. This necessitated a mark-up for spot market prices for the
industrial sector.
Data on coal cleaning costs and characteristics were developed by
Versar, Inc.* Processing costs, Btu losses, and solid waste disposal costs
were accounted for in this analysis.
I.2.2. Major Assumptions
Coal prices from MEFS output for the Energy Information Administra-
tion's Annual Report to Congress 1978 and the latest National Coal Model
output for the recent utility NSPS analysis were examined. Subsequent MEFS
modifications may change these estimation procedures if new energy scenarios
are developed in the future.
*Cost, Energy and Environmental Sensitivity Analysis of Coal Cleaning
Technologies for Industrial Boiler Applications. Versar, Inc. Springfield,
Va. Prepared for the Industrial Environmental Research Laboratory, U.S.
Environmental Protection Agency. 1979.
1-2
-------
Most of the coal prices extracted from the MEFS and NCM outputs include
the costs of coarse benefication. MEFS and NCM assume that all bituminous
and mid-bituminous coals undergo coarse benefication. Since the coals used
in this analysis include both raw and cleaned coals, it was necessary to
remove the costs associated with coarse benefication from the MEFS and NCM
coal prices, and later, for the cleaned coals, to include the additional
costs of cleaning for sulfur, as well as ash, reduction.
The "raw" coal prices were developed from the coal prices containing
the costs of coarse benefication by multiplying these coal prices by 0.8,
and then by subtracting $.08 per million Btu (or $.09 per million Btu for
midbituminous coals). This adjustment accounted for Btu losses during the
cleaning process, and for the direct cost of coarse benefication.
1.2.3 Development of Coal Prices
For each supply region, predominant MEFS coal types were selected
based on total volume of demand. For example, the MEFS high and low sulfur
classes for the bituminous coal category were used as the bases for the
IFCAM raw coal prices from the Northern Appalachia supply region. The
bases served to bound the sulfur classes for which sulfur premiums were
developed. The high sulfur basis was used to calculate the base price to
which the NCM sulfur premiums would be added. Or conversely, if the medium
and low sulfur classes were selected, the low sulfur basis was used to
calculate the base price for which the incremental prices would be subtracted.
Additionally, the bases were used to normalize the NCM sulfur premiums.
The NCM sulfur classes and Btu category corresponding to the bases
were selected. From these "raw" coal prices and the bases, a normalization
factor was calculated. This factor was determined by dividing the difference
1-3
-------
in the MEFS prices for the bases by the difference in the.NCM prices for
the corresponding categories.
To determine the incremental coal prices associated with lower sulfur
coals, the NCM sulfur classes were identified which have average sulfur
levels within the range of the selected bases. These sulfur classes were
ordered by their average sulfur level, and merged with the sulfur contents
of the IFCAM raw coals. Interpolation between the NCM "raw" coal prices
was used to develop NCM prices corresponding to the sulfur content of the
IFCAM raw coals. Incremental coal prices were calculated as the difference
between the NCM "raw" coal price for the high sulfur basis and each of the
NCM "raw" coal prices determined by interpolation. The normalized NCM
sulfur premiums were the product of the incremental coal prices and the
normalization factor. The base price was increased incrementally by the
normalized sulfur premiums yielding the F.O.B. mine prices for each IFCAM
raw coal.
For each clean coal, the price of its parent coal was divided by the
Btu recovery factor and added to the coal cleaning cost. The recovery
4
factors and the costs of coal cleaning were developed by Versar.*
The F.O.B. mine prices for the IFCAM raw and cleaned coals were adjusted
to account for spot market purchases. The mark-up factors used to generate
the spot market prices are based on a DOE assumption that 16.5 percent is a
reasonable mark-up in the eastern supply regions and 19.5 percent is a
reasonable mark-up in the western supply regions.**
* See Table F-17. -,
** The mark-up factor for surface mines is 19.5 percent. Most western
production is from surface mines. The mark-up factor for underground mines
is 13.5 percent. It is assumed that a representative mark-up factor for
eastern supply regions is an average of the mark-ups for surface and under-
ground mines.
1-4
-------
Table 1-1 summarizes the steps used in the development of 1990 coal
prices for several raw coals in IFCAM.
1.3 RESIDUAL FUEL OIL DESULFURIZATION COSTS
Oesulfurization costs for residual fuel oil are used to set the prices
for fuel oils of different sulfur contents. Below is a summary of the
procedure to compute the desulfurization costs which are being used in the
IFCAM model.
1.3.1 Residual Fuel Oil Types
The IFCAM model analyzes four residual fuel oil types which vary by
sulfur content:
3.0% high sulfur content residual fuel oil
1.6% intermediate level sulfur content fuel oil
t 0.8% sulfur content fuel oil to meet the current new source SOp
standard for large oil-fired industrial boilers; and
0.3% low sulfur content residual fuel oil to reflect nearly the
maximum sulfur reduction feasible.
1.3.2 Approach and Major Assumptions
Residual fuel oil sulfur premiums are based on the cost of hydrosul-
furization (HDS) for a 1990 mix of crude residua. The HDS costs are developed
using data on crude residua analyzed by Catalytic, Inc. These residua are
used as representatives of the sulfur and metals contents of the types of
residual which could be produced from the MEFS 1990 projected mix of crudes.
The HDS costs for producing residual fuel oil from crude residua are developed
using Catalytic1s oil cleaning cost algorithms. The equations apply only
to direct HDS processing. For the residual fuel oils in IFCAM, however, it
is assumed that indirect HDS (i.e., blending) is used to produce fuel oils
having greater than 1.0%S. Direct HDS is only used to produce a fuel oil
with less than 1.0%S content.
1-5
-------
TABLE 1-1 TABULATION OP 1990 COAL PRICES FOR THE NORTHERN APPALACHIAN SUPPLY REGIONS
CT>
IFCAM
Raw Coal i
ng SO /J
(ISQ2/flMBtu)
2579
(6.0)
1621
(3.77)
1182
(2.75)
735
(1.71)
MEFS
Sulfur
Closes
High
. Lou
MEFS
Prices
(J/Ton)
(M.14)
' '.: '
(4B.il)
MEFS
Prices
J/GJ
(J/MMBtu)
1.J6
(1.43)
'f.
': 1.91
,..(3.02)
NEFS
'"Raw"
Prices
J/GJ
(J/MMBtu)
1.00
(1.06->)
1.46
(1.54)
NCM
Average
Sulfur
Levels
ng SO /J
(IS02/MflBtu)
2739
(6.37)
1S48
(3.6)
709
(1.65)
414
(1.01)
NCM
Sulfur
Classes
G
P
D
B
NCM
Prices
J/GJ
(J/MMBtu)
1.01
(1.07)
1.09
(1.15)
1.42
(1.50)
1.47
(1.55)
NCM
'"Raw"
Prices
J/CJ
(J/KMfltu)
0.74
(0.78)
0.75*
(0.79«)
O.BO
(O.B4-)
0.80
(0.84)
0.91*
(0.96«)
1.05
(I."')
K06 V
(1.12)
1.10
(1.16)
NCM
Incremental
Prices
J/GJ
($/MMBtu).
0.00
(0.00)
0.01
(0.01)
0.06
(0.06)
0.17
(0.18)
0.31
(O.SJ)
' ^ '
' .;ru(.,-..
'.-'.' ».V, r
' . .
Nomallled
Sulfur
Premluas
$/GJ
(J/MMBtu)
0.00
(0.00)
0.01
(0.01)
0.08
(0.08)
0.22
(0.23)
0.40
(0.42)
Contract
Price
»/GJ
U/MMBtu)
1.01
(1.07)
1.08
(1.14)
1.22
(1:29)
1.4 ..
(1.48)
IW.
;-.;c;i
:-.-.:;ili,i-t
.-: :- ';'!{.«
"' r.ii:fv
. ' : ..I.'1. '
Market
Price
I/GJ
U/MMfltu)
1.08
(1.25)
1.26
(1.33)
1.42
(1.50)
1.63 .
(1.72).
';il
J^
&$.
.-.i ..;::..
Base Price , . .'' j ' .'
Baled on Interpolation between NCM "raw" coal prices.
-------
An average crude residual, for which the HDS costs are estimated, is
based on the MEFS crude types for 1990. The %S of the crude residua of the
4
MEFS crude types are taken from Oil and Gas Journal data.
1.3.3 Derivation of the Residual Fuel Oil HDS Costs
1.3.3.1 Crude Mix
The 1990 crude mix is taken from MEFS Series C midrange projections.
The crude mix is split between domestic and imported crudes: domestic
crudes account for 59 percent, and imported crudes account for 41 percent
of the crude mix.
Each domestic and imported crude residua type is matched with one of
Catalytic1s residua by its sulfur and metals content. Although there are
six Catalytic ITAR residual, MEFS crude types are assigned to one of four
Catalytic residua. These residua, their sulfur and metals contents, and
the percent of the MEFS crudes represented by each are shown in Table 1-2.
1.3.3.2 Direct Desulfurization Costs
The cost of direct HDS is computed for Ceuta, Iranian, Kuwait, and
Cold Lake residua. For each residua, the HDS costs are estimated for 0.3%S
and 0.8%S residual fuel oils.
The HDS costs for each residua then are averaged for each of the fuel
oil types. The HDS cost averages are weighted according to the assigned
percentage of the 1990 MEFS crude mix. This procedure results in the
weighted average HDS costs shown in Table 1-3.
1.3.3.3 Indirect Desulfurization Costs
The desulfurization cost for the 1.6%S fuel oil in IFCAM is based on
the cost of 70% reduction through direct HDS and blending with 2.93%S
residua. The procedure used to develop the 70% HDS and blending cost is:
1-7
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TABLE 1-2. 1990 CRUDE MIX AS REPRESENTED BY CATALYTIC RESIDUA
Residua
Kuwait
Ceuta
Iranian
Cold Lake
%S
3.8
2.12
2.47
4.55
ppm Ni + V
60
292
183
236
% of Mix
44.5
44.0
10.44
1.02
% Domestic
30.8
19.6
8.68
_
% Imports
13.7
24.4
1.76
1.02
TOTAL 100.00 59.1 41.1
1-8
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TABLE 1-3. COSTS OF DIRECT HDS FOR 0.3 and 0.8% SULFUR FUEL OIL
Residual Fuel Oil
(annualized 1978 $/bbl)
Residua %S % of Mix 0.8%S 0.3%S
Ceuta 2.12 44.0 1.63 2.74
Iranian 2.47 10.5 1.72 2.67
Kuwait 3.80 44.5 2.21 2.74
Cold Lake 4.55 1.0 3.18 4.17
Weighted
Average 2.93 100.0 1.91 2.75
1-9
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Employ 70% HDS of 2.93%S residua to produce 0.88%S residual fuel
oil, and blend the residua and the 0.88%S fuel oil in proportions
that produce residual fuel oil in the range of 0.88%S and 1.6%S.
Determine the proportions of 0.88%S residual fuel oil that is
blended to produce 1.6%S residual fuel oil.
Base the cost of the blended residual fuel oil on the cost of
producing 0.88%S residual fuel oil, and the proportion of this
fuel oil used in manufacturing 1.6%S residual fuel oil
This computation gives an HDS cost of $1.67/bb1 to produce 0.88%S
residual fuel oil from 2.93%S residua. The proportion of 0.88%S residual
fuel oil required to produce 1.6%S fuel oil through blending corresponds
to the proportion of 0.88%S residual fuel oil used to produce the 1.6%S
fuel oil blend. Therefore, the cost of producing 1.6%S residual fuel
oil through blending is 65 percent of the cost of producing 0.88%S
residual fuel oil through HDS, or $1.09. Table 1-4 summarizes the costs
for the desulfurized residual fuel oils used in IFCAM.
The cost of producing 1.6%S residual fuel oil through indirect HDS
($1.09/bbl) is slightly less than the cost of direct HDS ($1.17/bbl).
1.3.4 General Cost Equation for Direct and Indirect Desulfurization
The direct HDS cost for <1.6%S fuel oil and the 70% indireact HDS
cost for >1.0%S are plotted in Figure 1-1. The corresponding equations
are:
HDS Cost: (Y) = 1.5609691 (X)°-501286
where X is the %S of the residual fuel oil
^ 70% HDS and blending cost: (Y) = 0.8005825 (X) + 2.3711487
where X is the %S of the residual fuel oil
The cost of 70% HDS and blending is cheaper than the cost of direct HDS
for 0.9%S to 1.6%S residual fuel oil.
1-10
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FIGURE 1-1
RESIDUAL FUEL OIL DESULFUR1ZATION
COST FOR A 2J3%S RESIDUA
(5/BBL) COST
3JO
100-
L5D-
2.00-
UO-
LOO-
.50-
'Oirect Desuifurization
Indirect Desulfurization-
I I I I I I I I I I I I
OJ U OJ 0.4 0.5 O.S 17 U OJ 1.0 U U
I
1.4
i
U
i
l.S
S IN FUEL OIL
1-11
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1.3.5 Residual Fuel Oil Sulfur Premiums In IFCAM
IFCAM uses the residual fuel oil desulfurization costs in Table 1-4
to define sulfur premiums. Since MEFS provides regional prices for only
one residual fuel oil type (0.8%S), sulfur premiums must be developed to
estimate regional prices for 0.3%S, 1.6%S, and 3%S residual fuel oils.
The sulfur premium is defined to be the difference in desulfuriza-
tion costs from 0.8%S. The sulfur premium for 0.3%S is $2.75/bbl less
$1.91/bbl, or $.84/bbl ($.13/MMBtu). Therefore, $.13/MMBtu is added to
the MEFS residual oil price.
The sulfur premium for 1.6%S is $1.09/bbl less $1.91/bbl, or
-$.82/bbl (-$.13/MMBtu). Therefore, $.13/MMBtu is subtracted from the
MEFS residual oil price. Similarly, the sulfur premium for 3%S is
-$1.91/bbl (-$.30/MMBtu) and $.30/MMBtu is subtracted from the MEFS
residual oil price.
1-12
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TABLE 1-4. RESIDUAL FUEL OIL DESULFURIZATION COSTS3
Residual Fuel Oil Desulfurization Costs
(1978 $/bb1)
1.6XS $1.09
0.8%S $1.91
0.35SS $2.75
Applicable for a 2.93 percent residua.
1-13
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REFERENCES
1. Memo from Chamberlain, I. U.S. Department of Energy to The Record.
July 2, 1979. Theory of Industrial Coal Price Mark-up and Theory of
Industrial and Utility Coal Mileage Cost.
2. Ibid.
3. Final Industrial Boiler Control Technology Algorithms. Acurex Coporation.
Morrisville, North Carolina. Prepared .for the Industrial Environmental
Research Laboratory, U.S. Environmental Protection Agency. July 1979.
65 p.
4. Aalund, Leo R. Guide to World Crudes. The Oil and Gas Journal. 74:
issues of March 29, April 12, May 10 and 24, June 7 and 21, and July 5,
1976; 76: issues of July 3, 17 and 31, 1978.
1-14
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