./450/3-86/011
ERA
I States
nmental Protection
V
Office of Air Quality
Planning and Standards
Research Triangle Park NC 27711
EPA-450/3-86-011
October 1986
Air
Review of
New Source
Performance
Standards for
Petroleum Refinery
Fuel Gas
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EPA-450/3-86-011
I
Review of New Source Performance
Standards for Petroleum Refinery Fuel Gas
V
^
I
I
f^ Emission Standards and Engineering Division
X
f\
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, NC 27711
October 1986
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This report has been reviewed by the Emission Standards and Engineering Division of the Office of Air Quality Planning
and Standards, EPA, and approved for publication. Mention of trade names or commercial products is not intended to
constitute endorsemnent or recommendation for use. Copies of this report are available through the Library Services
Office (MD-35), U.S. Environmental Protection Agency, Research Triangle Park, N.C. 27711, or from National Technical
Information Services, 5285 Port Royal Road, Springfield, Virginia 22161.
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TABLE OF CONTENTS
Page
1. SUMMARY 1-1
1.1 CONTROL TECHNOLOGY 1-1
1.2 ECONOMIC CONSIDERATIONS AFFECTING THE NSPS 1-1
2. CURRENT STANDARD 2-1
2.1 NEW SOURCE PERFORMANCE STANDARDS 2-1
2.2 LEGISLATIVE HISTORY 2-12
2.3 STATE REGULATIONS 2-15
2.4 OTHER FEDERAL REGULATIONS 2-16
2.5 REFERENCES 2-18
3. INDUSTRY DESCRIPTION
3.1 BACKGROUND INFORMATION 3-1
3.2 INDUSTRY CHARACTERIZATION 3-4
3.3 EMISSIONS FROM COMBUSTION OF REFINERY FUEL GAS 3-8
3.4 SELECTION OF REFINERY COMBUSTION DEVICES FOR NSPS CONTROL 3-10
3.5 REFERENCES 3-10
4. STATUS OF CONTROL TECHNOLOGY 4-1
4.1 ALKANOLAMINE PROCESS SYSTEM 4-1
4.2 THE LO-CAT® HYDROGEN SULFIDE OXIDATION PROCESS 4-8
4.3 FACILITIES SUBJECT TO THE NSPS 4-12
4.4 COMPLIANCE TEST RESULTS 4-13
4.5 EMISSION MONITORING 4-15
4.6 REFERENCES 4-16
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Page
5. MODEL PLANTS 5-1
5.1 MODEL PLANTS AND CONTROL SYSTEMS 5-1
5.2 EMISSION REDUCTIONS 5-2
6. COST ANALYSIS 6-1
6.1 INTRODUCTION 6-1
6.2 AMINE TREATMENT WITH CLAUS SULFUR RECOVERY 6-2
6.3 LO-CAT® PROCESS 6-6
6.4 COST-EFFECTIVENESS 6-16
6.5 COST COMPARISON 6-23
6.6 REFERENCES 6-24
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1. SUMMARY
1.1 CONTROL TECHNOLOGY
Currently, petroleum refineries are using two types of control
technologies, the alkanolamine or the LO-CAT® system, to comply with the
hydrogen sulfide (H2S) concentration limit (230 mg/dscm) of this new
source performance standard (NSPS). Data for fifteen compliance tests
were obtained from nine different refineries. All of the test data are
from refineries that use an alkanolamine system. The compliance test
results range from 2.97 mg/dscm to 119.43 mg/dscm.
No compliance test data were obtained from a LO-CAT® system; however,
one refinery with such a system has installed a continuous H2$ monitor.
According to information submitted by the refinery, the f^S concentration
ranges from 20 ppmv to 50 ppmv and averages 30 ppmv {NSPS is 162 ppmv).
The review did not find any demonstrated technologies for controlling
emissions that achieve more control than the alkanolamine or the LO-CAT®
systems.
1.2 ECONOMIC CONSIDERATIONS AFFECTING THE NSPS
Another primary issue involving review of the NSPS is the cost of
controls. The cost effectiveness of controlling the H2$ concentration in
refinery fuel gas was estimated for four model plant sizes at three H2S
concentrations for both types of control systems. For most of the new NSPS
units, the costs of control per unit of sulfur dioxide (S02) removed will
be less than those discussed in this section. The cost effectiveness
ranges from $201 per ton of S02 to a credit of $23.9 per ton of S02 for
the alkanolamine system with a Claus sulfur recovery unit. The cost
effectiveness for the LO-CAT® system ranges from $89 per ton to $399 per
ton of S02 removed.
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2. CURRENT STANDARDS
This chapter presents and discusses the current regulations for air
pollutant emissions from refinery fuel gas combustion devices. Federal
regulations for new sources, other Federal regulations, and State regulations
(for exisiting and new sources) are all addressed in order to give an overall
picture of the regulatory structure for this emission source category. The
focus, however, is on the new source performance standards (NSPS) for sulfur
dioxide emissions from refinery fuel gas combustion devices.
A summary of the NSPS is first presented, followed by detailed discussions
of the specific requirements, definitions, and specifications of the NSPS.
This is followed by a brief description of other Federal and State regulations
that may also affect existing and new sources in this category.
2.1 NEW SOURCE PERFORMANCE STANDARDS
2.1.1 Background
New source performance standards regulate emissions of air pollutants
from new, modified, and reconstructed facilities in various industrial categories.
The regulations establish emission limits and require emission performance
testing, continuous monitoring, and periodic reporting. The authority for
the NSPS regulations is granted to the U.S. Environmental Protection Agency
(EPA) under Section 111 of the Clean Air Act.1
The regulation for fuel gas combustion devices in petroleum refineries
is listed in Subpart J of 40 CFR 60, (Code of Federal Regulations; Title 40 -
Protection of Environment; Part 60 - Standards of Performance for New
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2-2
Stationary Sources; Subpart J - Standards of Performance for Petroleum Refineries)
Subpart J addresses specific requirements for this source category, but
Subpart J also incorporates the general requirements for any NSPS. These
general requirements are listed in Subpart A (General Provisions) of 40 CFR 60.
Other sources of air pollution emissions from petroleum refineries are
also regulated under the new source performance standard regulatory program.
Subpart J also regulates sulfur dioxide emissions from Claus sulfur recovery
plants, and sulfur dioxide, carbon monoxide, and particulate emissions from
fluid catalytic cracking unit catalyst regenerators. Subpart H regulates
sulfuric acid mist and sulfur dioxide emissions from sulfuric acid plants.
Volatile organic compound (VOC) emissions from storage vessels for petroleum
liquids are regulated under Subparts K and Ka. Subpart GGG regulates VOC
emissions due to leaks from process equipment.
2.1.2 Summary of the NSPS for Refinery Fuel Gas Combustion Devices
New source performance standards were promulgated by the EPA on March 8,
1974, limiting emissions of sulfur dioxide ($02) from new, modified and
reconstructed fuel gas combustion devices at petroleum refineries. No signif-
icant changes have occurred since then. These standards apply to an affected
facility which commences construction or modification after June 11, 1973.
The affected facility for this standard is any fuel gas combustion
device in a petroleum refinery. These devices are defined as any equipment
used to burn fuel gas, such as process heaters, boilers, and flares, but some
combustion sources in a refinery are specifically exempted in the definition.
The regulated air pollutant is S02- Sulfur dioxide emissions from fuel
gas combustion devices can be controlled by reducing the hydrogen sulfide
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content of the fuel gas prior to combustion or by flue gas desulfurization
(FGD) after combustion. The standard was written with the intent to limit
the H2$ content of fuel gas, although the owner/operator has the option of
using FGD. The standard prohibits the burning of fuel gas containing more
than 230 mg HgS/dscm (0.10 gr/dscf) in any fuel gas combustion device; however,
the standard does not apply to unusual situations, such as emergency gas
releases or process upsets. Compliance is demonstrated by an initial
performance test using EPA Method 11. Subsequent continuous monitoring of
H2$ in the incoming fuel gas is required; however, since monitor performance
specifications have not been established yet, this monitoring requirement is
not in effect.
An alternative compliance option is included. Instead of controlling the
H2S in the incoming fuel gas, the S02 emissions may be controlled directly by
treating the effluent gases resulting from the combustion of fuel gas.
However, it must be shown that treating the effluent combustion gases will
control S02 emissions as effectively as controlling the h^S in the incoming
fuel gas. Compliance for this option is demonstrated by an initial performance
test using EPA Method 6, and continuous monitoring of S02 in the effluent gas
is required.
The regulation also specifies a series of reporting and recordkeeping
requirements. A refinery that has combustion devices subject to the NSPS
is required to keep records, submit reports to EPA, and notify EPA of particular
plans and occurrences as described in section 2.1.8.
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2.1.3 Applicability of Standards2
2.1.3.1 Affected facilities.
The NSPS is applicable to any new, modified, or reconstructed combustion
device which commenced construction after June 11, 1973, and which burns fuel
gas in a petroleum refinery.
Petroleum is defined as,
"the crude oil removed from the earth and the oils derived from
tar sands, shale, and coal."
A petroleum refinery is defined as,
"any facility engaged in producing gasoline, kerosene, distillate
fuel oils, residual fuel oils, lubricants, or other products
through distillation of petroleum or through redistillation,
cracking or reforming of unfinished petroleum derivatives."
The EPA's definition of a petroleum refinery is thus interpreted broadly to
encompass shale oil refineries, solvent refined coal plants, one-step topping
plants, and small re-refining operations.
Fuel gas is defined as,
"any gas which is generated at a petroleum refinery and which is
combusted. Fuel gas also includes natural gas when the natural
gas is combined and combusted in any proportion with a gas
generated at a refinery. Fuel gas does not include gases
generated by catalytic cracking unit catalyst regenerators and
fluid coking burners."
The specific exemption is included for gases generated by these particular
processes because it is impractical to control the S02 emissions that would
result from burning the H2$ in these gases. These off-gases contain relatively
low levels of H2$ and contain very high levels of carbon dioxide, making it
difficult to reduce the H2S concentration further in conventional amine
treating units. However, if these exempted, off-gases are combined with fuel
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gas from another part of a refinery, then the combined gas stream would be
subject to the NSPS limit if it is combusted in a new combustion device.
Natural gas refers to pipeline standard natural gas (meeting specifications
of < 0.25 grains H2S / 100 scf). Thus, if natural gas is purchased and burned
exclusively in a combustion device, then H2$ content of the gas will necessarily
be below the NSPS limit. If natural gas is mixed with refinery generated
fuel gas, then the combined stream is considered "fuel gas" and its H2S
>
concentration must be under the NSPS limit prior to combustion in a new source.
A fuel gas combustion device is defined as,
"any equipment, such as process heaters, boilers and flares used
to combust fuel gas, except facilities in which gases are
combusted to produce sulfur or sulfuric acid."
There are two reasons for including the specific exemption for combustion
devices used to produce sulfur or sulfuric acid. First, the combustion in
this case is a step in the chemical conversion process, and the resulting
post-combustion stream is considered a process stream that undergoes further
processing, not an effluent stream. Second, there are separate NSPS's limiting
air emissions from these processes. (Sulfuric acid plants are regulated
under Subpart G; Claus sulfur recovery plants under a different part of
Subpart J.)
2.1.3.2 Applicability date.
The NSPS applies only if the construction or modification commenced
after June 11, 1973, (the date of the original proposal of the regulation).
The term "commenced" is defined in the General Provisions to 40 CFR 60,
(Section 60.2),
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"Commenced means that an owner or operator has undertaken a
continuous program of construction or modification or that an
owner or operator has entered into a binding agreement or
contractual obligation to undertake and complete, within a
reasonable time, a continuous program of construction or
modification."
Thus, a fuel gas combustion device that existed prior to the proposal on
June 11, 1973, and has not been significantly changed or altered since then
would not be regulated under the NSPS.
2.1.3.3 Modification.
While NSPS are intended primarily for newly constructed facilities,
existing sources can become subject to an NSPS through either "modification"
or "reconstruction." These terms are defined in detail in the General Provi-
sions for Part 60, (40 CFR 60.14 and 40 CFR 60.15).
An existing fuel gas combustion device becomes subject to the NSPS under
the modification provision if there is any physical or operational change
that causes an increase in the emission rate. A number of clarifications,
exemptions, and exceptions to the modification provision are listed. The
following actions by themselves are not considered to be modifications:
0 routine maintenance, repair, and replacement
0 production increases achieved without any capital expenditure
0 production increases resulting from an increase in the hours
of operation
0 use of an alternative fuel if the existing facility was
originally designed to accommodate such an alternative use
0 addition or replacement of equipment for emission control (as
long as the replacement does not increase emissions)
0 relocation or change of ownership of an existing facility.
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Also, the addition or modification of one facility at a source will not cause
other unaltered facilities at that source to become subject to the NSPS.
Specifically, for petroleum refineries, if one fuel gas combustion device is
added or modified, then only that particular device must meet the NSPS; the
other existing combustion devices throughout the refinery are not affected.
2.1.3.4 Reconstruction
An existing facility becomes subject to the NSPS upon reconstruction
regardless of any change in the rate of emissions. Reconstruction is defined
as the replacement of components of an existing facility to the extent that
the cumulative fixed capital cost of the new components exceeds 50 percent
of the cost that would be required to construct a comparable entirely new
facility.
2.1.4 Controlled Pollutant
The NSPS limits emissions to the atmosphere of SOg from the exhaust of
refinery combustion devices which burn fuel gas. Although the regulated air
pollutant is S02, the S02 emissions to the atmosphere are not regulated directly,
Instead SOg emissions are controlled indirectly by regulating the amount of
H2$ in the incoming fuel gas.
2.1.5 Exceptions to the Emission Standard
The standard prohibits the burning of fuel gas containing more than 230
mg HgS/dscm (0.10 grain/dscf) in any new, modified, or reconstructed combustion
device. The H2S content of the incoming fuel gas can be reduced in three
ways - by using sweeter crude with a lower sulfur content, by pretreatment of
the fuel gas before combustion in an acid gas treating unit, and by blending
natural gas with the fuel gas. Although this mixing dilutes the H2S concentra-
tion without reducing overall S02 emissions, the blending of natural gas with
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fuel gas Is not considered a circumvention of the standard, because this is
often normal and necessary refinery operating practice. Natural gas is used
as auxiliary fuel since many refineries require more gas than they generate.
Also, natural gas is used to ensure a constant flow of fuel to processes,
while the amount of refinery generated fuel gas may vary with operating
conditions or upsets in other process units.
The standard does not apply to unusual situations, such as emergency gas
releases due to process upsets. Process upset gas is defined as,
"any gas generated by a petroleum refinery process unit
as a result of start-up, shut-down, upset, or malfunction."3
Start-up, shut-down, upset, and malfunction considerations are defined in the
General Provisions for 40 CFR Part 60. The combustion of process upset gas
in a flare, or the combustion in a flare of process gas or fuel gas which is
released to the flare as a result of relief valve leakage is specifically
exempted from this regulation. However, flares which burn a continuous
process gas stream are subject to the NSPS regulations.
2.1.6 Testing Requirements
The owner or operator of a fuel gas burning device subject to NSPS
is required to conduct performance tests within a specified period after
start-up, and thereafter from time to time as may be specified by the EPA.
These performance tests are required in order to demonstrate that the standards
are being met by the new device. General testing and reporting requirements
are listed in the General Provisions, (Section 60.7), while testing details
specific to this source category are found in Subpart J, (Section 60.106).
The initial test of performance of a facility must be conducted within
60 days after the facility first achieves its maximum intended rate of operation.
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However, If the Intended rate of operation is not achieved within 120 days of
initial start-up, the initial test must nevertheless be conducted within 180
days of start-up. Thirty days must be allowed for prior notice to the EPA,
to allow the Agency to designate an observer to witness the test.
To demonstrate compliance with the standard limiting the amount of ^S
in the fuel gas prior to combustion, EPA Reference Method 11 is used to
determine the concentration of H2S. A performance test consists of 3 runs,
,/
with each run consisting of 2 samples. Samples are taken at approximately
one-hour intervals with a minimum sampling time of 10 minutes per sample.
The arithmetic mean of the three runs constitutes the value used to determine
whether the facility is in compliance. (Necessary modifications in the
details of the test methods may be made, if approved in advance by the EPA.)
A written report of the test is to be furnished to the EPA.
2.1.7 Monitoring Requirements
The regulation requires a continuous H2$ monitor on the fuel gas line at
the inlet to each combustion device that is subject to the NSPS. When a
refinery has several fuel gas combustion devices having a common source of
fuel gas, monitoring may be done at one location instead of each combustion
device having a separate monitor. This situation is common in many refineries
where a centralized acid gas treatment plant treats H2S rich gases from
several refinery process units and then routes the treated exit gases to
combustion devices throughout the refinery. Excess emissions are defined as
any 3 hour period when the integrated (or arithmetic) average concentration
of H2S in the fuel gas exceeds the standard of 230 mg H2S/dscm.
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The monitoring system must continuously monitor and record the H2S
concentration. Under the General Provisions (Section 60.13), "continuous" is
defined to mean that the monitoring system must complete at least one cycle
of operation (sampling, analysis, and data recording) for each successive
15-minute period. The owner or operator must install, calibrate, maintain,
and operate the continuous monitor according to the requirements which are
detailed in the subpart and the general provisions. Also, the continuous
monitoring system must satisfy the performance specifications in Appendix B
of 40 CFR 60.
The EPA has not yet developed instrument performance specifications for
H2S continuous monitoring systems. Therefore, refinery combustion devices
subject to the NSPS are effectively exempt from the H2S monitoring requirements
until EPA establishes performance specifications for an H2S monitor.
2.1.8 Recordkeeping and Reporting Requirements
A refinery that has combustion devices subject to the NSPS, is required
to keep records, submit certain reports to EPA, and notify EPA of certain
plans and occurrences.
One-time "notification" reports concerning the start of construction or
reconstruction, anticipated and actual startup dates, and physical or operational
changes to existing facilities are required so that the EPA will be able to
identify affected sources. In addition, other records and reports are necessary
to enable the EPA to identify sources that may not be in compliance with the
standard. These include initial performance test results, quarterly reports
of excess emissions, and retaining records of plant upsets and excess emissions
for 2 years. Details of these requirements are listed in the General Provisions
(40 CFR 60.7).
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2.1.9 Option for an SO? Emission Limit
Sulfur dioxide emissions from fuel gas combustion devices can be controlled
by reducing the H2S in the incoming fuel gas or by reducing the 862 in the
exhaust gases. The standard was written with the intent to limit the ^S
content of fuel gas, and all of the refinery sources subject to the NSPS to
date are currently reducing S02 emissions by pretreatment of the fuel gases
to remove the ^S.
However, the regulation includes a second, alternative provision which
allows the burning of fuel gas with a higher H2S content provided the effluent
gases are treated to reduce the S02 emissions. This flue gas desulfurization
would probably be accomplished with an add-on air pollution control device.
In case this emission control option is selected, the regulation sets forth a
parallel set of emission standards and testing, monitoring, reporting, and
recordkeeping requirements. Because no refinery has yet elected the FGD
options, the alternative provisions in the regulation will not be discussed
in detail in this report.
The NSPS does not set a specific S02 emission limit if this alternative
approach is followed. Instead, the source must calculate and determine an
equivalent S02 emission level that would control S02 emissions as effectively
as complying with the standard for H2$ concentration in the fuel gas. Because
the inlet fuel gas streams, operating conditions, and parameters may vary for
each combustion device, an equivalent S02 emission limit would probably need
to be calculated for each affected facility on a case-by-case basis. The
information must be submitted to the EPA for approval.
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Compliance for this option is demonstrated by a performance test using
EPA Methods 1, 2, and 6 for determining the sampling site, volumetric flowrate,
and S02 concentration. Continuous monitoring of the $02 concentration in the
effluent is also required in the regulation. Since EPA has listed performance
specifications for continuous SOg instruments (in Performance Specification 2
of Appendix B to 40 CFR 60), these monitoring requirements are in effect and
must be carried out. Excess emissions are defined as a 3-hour period when
the average S02 concentration exceeds a predetermined level that was previously
calculated and approved for that particular combustion source. The testing,
monitoring, recordkeeping, and reporting requirements are similar to those
discussed for the H2$ concentration standard, and details are listed in
Subpart J and the General Provisions.
2.2 LEGISLATIVE HISTORY
Standards of performance for air emissions from petroleum refineries
were first proposed on June 11, 1973 (38 FR 15406) and promulgated on
March 8, 1974 (39 FR 9308). Since then, there have been 3 proposed and
8 final rulemakings which affected the standard for sulfur dioxide emissions
from fuel gas combustion sources in refineries. These rulemakings consisted
of minor clerical corrections, changes to the monitoring requirements, and
changes to the definition of fuel gas. A listing and brief summary of these
is given in Table 2.1.
2.2.1 Changes to Definitions
The definitions of "fuel gas" and "fuel gas combustion device" were
changed to clarify the original intent of the regulation and to match the
conventional nomenclature used in the industry. These formal changes to
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TABLE 2.1
LIST OF RULEMAKINGS AFFECTING NSPS FOR
REFINERY FUEL GAS COMBUSTION DEVICES
DATE
06-11-73
03-08-74
09-11-74
10-06-75
07-25-77
08-17-77
03-03-78
10-04-76
03-15-78
FEDERAL REGISTER
CITATION
38 FR 15406
39 FR 9308
39 FR 32852
40 FR 46250
42 FR 37936
42 FR 41424
43 FR 8800
41 FR 43866
43 FR 10866
TYPE OF
ACTION
Proposal
Final
Proposal
Final
SUMMARY OF ACTION
Final
Final
Final
Proposal
Fi nal
0 Original regulation limiting S02
emissions and including testing,
monitoring, and reporting requirements.
0 Added universal monitoring and reporting
requirements to General Provisions,
(40 CFR 60.7 & 60.13).
0 Eliminated monitoring requirements
for H2$ in fuel gas; revised
monitoring requirements for S02 in
exhaust gas.
0 Clarification, adding applicability
date to the definition of the
affected facility.
0 Clerical change to revise statuatory
authority citations for clarity.
0 Clerical change to amend statuatory
authority citations per Clean Air
Act Amendments of 1977.
0 Re-added monitoring requirements for
H2S in fuel gas.
03-12-79
03-03-80
12-01-80
44 FR 13480
45 FR 13991
45 FR 79452
Final ° Change definition of "fuel gas" and
"fuel gas combustion device" to
clarify when an incinerator-waste
heat boiler is affected by the NSPS.
Proposal ° Change definition of "fuel gas" to
Final clarify which gaseous fuels are
covered by NSPS, particularly when
"natural gas" is a "fuel gas".
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the regulation were Initiated in part as a response to several questions
which had arisen concerning applicability determinations. Since the changes
were merely clarifying the original intent of the regulation, these changes
did not have a significant impact on emissions.
2.2.2 Monitoring
The original standard included requirements for the monitoring of the
H2$ at the inlet or S02 at the outlet of a fuel gas combustion device. At
the time, however, no guidance or instructions were provided on how to conduct
the monitoring, and so sources were temporarily exempted from monitoring.
(Incidentially, this approach was taken for all of the early NSPS regulations
covering several industries because no monitoring guidelines had been set by
EPA at the time for any pollutant.)
Major changes and additions to monitoring requirements were issued a
short time later (proposed 9/11/74 and promulgated 10/6/75). These changes
added overall monitoring and reporting requirements to the General Provisions
for all NSPS's and set forth detailed performance specifications for SOg
monitoring instruments. Concurrently, there were coordinating revisions
to the S02 monitoring requirements in Subpart J for the exhaust gases from
refinery combustion devices. At the same time, all monitoring requirements
for H2S levels in the inlet gases were eliminated because specifications for
those instruments had not yet been set. Then, this approach was reversed in
a later rulemaking (proposed on 10/4/76 and promulgated on 3/15/78), when
monitoring requirements for H2S in the fuel gas were reinstated; however,
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since detailed performance specifications for H2S monitors have not been
promulgated, the H2S monitoring requirements still do not have to be carried
out. The overall result of these actions and current status of requirements
for H2$ monitoring is that universal, general monitoring requirements and
guidelines are in place but specific, detailed requirements for H2S monitors
have not yet been determined. Thus, no H2S monitoring is required at this
time.
2.3 STATE REGULATIONS
2.3.1 State Regulations for Existing Sources
A review of State regulations has shown a wide variation in the types of
regulations, degree of stringency, and methods of enforcing the limitations.
Many States have several forms of regulations, each applying to a different
fuel or type of source, and do not necessarily conform to or parallel the
NSPS format. For example, with regard to source category, the NSPS specifies
fuel gas combustion devices in petroleum refineries, whereas a State regulation
may specify a different source category: petroleum refinery combustion
sources; a combustion source in any industrial facility; combustion sources
that burn gaseous fuels.
State regulations may limit emissions of S02 by limiting the H2S in the
fuel gas (as does the NSPS), the total S02 emissions from the combustion
device, or the total S02 emissions from the petroleum refinery. In general,
S02 emissions are limited by a regulation restricting the quantity of S02
emitted per unit quantity of heat input or by limiting the sulfur content of
the fuels. In some States, the regulation specifies the maximum allowable
ground level S02 concentration resulting from the emissions.
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Sulfur dioxide regulations fall Into one of the following regulatory
formats:
1. ppm S02, by volume, in the effluent
2. Pounds of S02 per million Btu's of heat Input
3. Requirements on the sulfur content of the fuel, such as ppm HSS In
the fuel gas or weight percent sulfur In fuel oil
4. Ambient air quality levels similar or the same as the National
Ambient Air Quality Standard (NAAQS) for S02
2.3.2 State Regulations for New Sources
For new sources, most States have been delegated enforcement authority
for the NSPS for the petroleum refining industry, and most have adopted the
NSPS as written. No State has adopted an emission limit more stringent than
the NSPS limit of 0.10 gr H2S/dscf; although some States or local air pollu-
tion control agencies have adopted more stringent monitoring requirements.
The Puget Sound agency (in Washington State) and three counties in southern
California have required continuous emission monitoring with a continuous
automated instrument even though this requirement is officially not in effect
under the NSPS until Instrument performance specifications are promulgated.
2.4 OTHER FEDERAL REGULATIONS
There has been additional regulatory activity since the promulgation of
the current NSPS which affects the emissions from refinery fuel gas combustion
sources. In addition to State regulations (for existing and new sources) and
the NSPS, some petroleum refineries may be required to achieve more stringent
emission levels from fuel gas combustion devices under regulations for the
Prevention of Significant Deterioration (PSD)4 or under State Implementation
Plans (SIP) which are subject to nonattainment review by EPA.5
2.4.1 PSD Regulations
If a new facility is built in an area which is attaining the NAAQS for
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S02, then it falls under the PSD regulations and must use the best available
control technology (BACT). In general, BACT determination is applied on a
case-by-case basis and must be at least as stringent as the NSPS level. For
this source category, the BACT emission level has been defined as equal to
the NSPS level.6 Some State and local enforcing agencies have also used the
PSD regulations as a means of requiring some form of emission monitoring and
corresponding emission monitoring reports.
2.4.2 Nonattainment Area Regulations
If a new source is located in a nonattainment area for NAAQS for S02,
then emission control technology capable of the lowest achievable emission
reduction (LAER) is required. In general, LAER is at least as stringent
as the NSPS, but for this source category, LAER has also been defined as
equal to the NSPS.7
2.4.3 Other NSPS Regulations
The NSPS under review in this study limits-the S0£ emissions from all
new, modified, or reconstructed fuel gas combustion devices, which include
process heaters, boilers, and flares used to combust fuel gas. The air pollution
emissions from these combustion sources may also be regulated by other
NSPS's (either current or under development). The additional requirements
and restrictions imposed by these other NSPS's do not affect or conflict
with the emission reductions required by the fuel gas NSPS, but they may
affect the planning and design of new combustion sources by refinery owners.
A new or modified boiler which has a heat input greater than 250 million
BTU per hour may also be subject to the provisions of Subpart D or Subpart Da
of 40 CFR 60; the applicable subpart is based on the date of construction
of the source and whether the source is classified as an industrial boiler
-------
2-18
or a utility boiler. These subparts limit opacity, participate emissions,
and NOX emissions, as well as S02 emissions. Similarly, a medium-sized, new
or modified boiler (100 to 250 million BTU per hour) may be subject to the
provisions of Subpart Db, which is currently under development.
2.5 References
1. Clean Air Act As Amended, August 1977. 42 U.S.C. Title I--Air
Pollution Prevention and Control. Part A--Air Quality and Emission
Limitations; Section 111—Standards of Performance for New Stationary
Sources. Washington, D.C.
2. U.S. Environmental Protection Agency. Code of Federal Regulations.
Title 40, Part 60. Sections 60.101. Office of the Federal Register.
Washington, D.C. July 1, 1985.
3. Same as reference #2.
4. Reference 1. Part C--Prevention of Significant Deterioration of Air
Qua!i ty.
5. Reference 1. Part D—Plan Requirements for Nonattainment Areas.
6. U.S. Environmental Protection Agency. BACT/LAER Clearinghouse -
A Compilation of Control Technology Determinations. U.S. EPA,
Research Triangle Park, N.C. EPA 450/3-85-016 (a-d). June 1985.
7. Same as reference #6.
-------
3. INDUSTRY DESCRIPTION
This chapter describes a typical petroleum refinery, its various
production processes and the range of products produced by a refinery.
Also, the current number of operating refineries and their geographical
location are discussed as well as the industry growth rate. Finally,
emissions from combustion of refinery fuel gas and the rational for
choosing refinery fuel gas for new source performance standard control
are discussed.
3.1 BACKGROUND INFORMATION
A petroleum refinery transforms crude oil into a variety of useful
products. The petroleum refining industry produces more than 2500 products
that can be categorized into the following classes: fuel gas, gasoline,
kerosene, fuel oil, lubricating oil, grease, wax, asphalt, coke, chemicals,
and solvents. There is no "typical" refinery, since the number of products
and the product mix varies widely within a refinery as well as between
refineries. The manufacturing processes also vary depending on refinery
age, type of technology, capacity, location, and type of crude processed.
Petroleum refinery operations involve physical separation of components
of the crude oil (e.g., crude distillation) and chemical conversion
processes which transform some of the less useful components of the oil
into more useful products (e.g., cracking of high molecular weight oils
into lower molecular weight products such as gasoline).
The processing sequence of a refinery is illustrated in Figure 3-1.
The crude oil is heated and charged to an atmospheric distillation
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3-2
ATMOSPHESIC CHUDE OIL SEPAHAIIOH UNIT
-o
72
O
00
oo
o m
GO
3» I
-------
3-3
tower where it is separated into several light, intermediate, and heavy
fractions. The bottoms from the tower are sent to a vacuum distillation
unit for further separation. The bottoms from the vacuum still are
thermally cracked in a coker to produce a wet gas, coker gasoline,
and coke. A portion of the bottoms from the vacuum still may be processed
into asphalt. Gas oils from the atmospheric and vacuum distillation
units are used as feedstocks for the catalytic cracking and hydrocracking
units. These units convert the gas oils to gasoline and distillate fuel.
The gasoline from these units is fed to a catalytic reformer to improve
the octane number and then blended with other refinery streams to make
gasolines for marketing.
The wet gas streams from the distillation, coker, and cracking units
are combined and fractionated into fuel gas, liquified petroleum gas, and
unsaturated and saturated branched chain and straight chain, light
hydrocarbons containing from three to five carbon atoms. The fuel gas is
used as fuel in the refinery furnaces. The straight chain saturated
hydrocarbons are blended into gasoline. The unsaturated hydrocarbons and
the branched chain hydrocarbons, primarily isobutane, are processed in an
alkylation unit. In the alkylation unit the unsaturated hydrocarbons
react with isobutane to form isoparaffins which are blended into gasoline
to increase the octane.
The middle distillates from the crude unit, the coker unit, and the
cracking unit are blended into diesel and jet fuels and furnace oil.
Heavy vacuum gas oils and reduced crude oil from some crudes can be
processed into lubricating oils, waxes, and grease.
-------
3-4
3.2 INDUSTRY CHARACTERIZATION
As of January 1, 1985, there were 191 operable refineries in the
United States with total crude oil distillation capacity of 15.1 million
barrels per calendar-day^/ and 15.9 million barrels per stream day,]V
Table 3.1 lists the number of operating refineries along with the total
crude capacity located in each State. These refineries are distributed
among 35 states, with 79 refineries (41 percent) being concentrated in
the three major refining States of Texas, California, and Louisiana.
These three States account for an even higher percentage (57 percent) of
the total U.S. crude oil refining capacity. Texas alone accounts for
approximately 27 percent of the total crude oil refining capacity, while
Louisiana and California account for about 15 percent each.
In addition, there are four operating refineries in Puerto Rico, Virgin
Islands, Guam, and the Hawaiian Foreign Trade Zone with a combined crude
capacity of 771,000 barrels per calendar day.2 Because these are territories
and not formally part of the United States, these refineries are usually
not included in industry studies and figures for the U.S.; however, these
refineries are regulated under federal EPA new source performance standards.
£/ Barrels per calendar day (b/cd): the average volume a refinery unit
processes each day including downtime used for turnarounds. This is actual
total volume for the year divided by 365.
]V Barrels per stream day (b/sd): the amount a unit can process
running at full capacity under optimal crude and product slate conditions
for short periods.
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3-5
TABLE 3.1
OPERATING REFINERIES IN THE U.S. (AS OF JANUARY 1, 1985)3
State
Al abama
Alaska
Ari zona
Arkansas
California
Colorado
Delaware
Georgia
Hawaii
Illinois
Indiana
Kansas
Kentucky
Louisiana
Mary! and
Michigan
Minnesota
Mississippi
Montana
Nevada
New Jersey
New Mexico
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Tennessee
Texas
Utah
Virginia
Washington
West Virginia
Wisconsin
Wyoming
No.
Plants
1
4
1
4
30
3
1
2
2
8
5
7
2
16
1
4
2
5
6
1
5
3
2
5
5
1
8
1
33
6
1
7
2
1
6
b/cd
80,000
138,930
5,000
69,170
2,265,098
94,700
140,000
28,800
1'09,500
946,000
431,300
338,000
218,900
2,188,793
14,200
119,400
204,143
362,400
147,500
4,500
503,000
63,050
62,800
515,700
374,000
15,000
658,700
57,000
4,145,900
154,950
51,000
410,550
16,500
39,000
162,778
Crude Capacity
b/sd
81,300
142,910
5,263
70,950
2,381,417
98,500
150,000
32,000
118,426
1,003,550
445,500
352,383
226,000
2,280,958
14,947
•126,094
211,220
383,104
154,147
4,700
533,210
66,000
65,400
540,000
390,394
15,789
691,300
60,000
4,385,273
161,868
53,000
427,543
17,000
40,000
168,052
Total
191
15,136,262
15,898,198
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3-6
Since January 1, 1981, a net total of 101 refineries have been shut
down with a total capacity of 2.5 million barrels per calendar day.
(Table 3-2 and Table 3-3). During 1984, a total of 26 refineries were
shut down and 2 refineries were started up resulting in a net decrease of
24 plants with an associated loss in crude distillation capacity of
0.5 million barrels per calendar day. The majority of these closings
occurred at refineries with crude distillation capacity of 30,000 barrels
per calendar day or less. These closings accounted for a net reduction
of 19 facilities. Refineries with crude distillation capacity greater
than 30,000 barrels per calendar day showed a net reduction of 5
facilities during 1984.
Refinery utilization (actual production vs. production capacity)
peaked at 78.2 percent in August 1984; the average rate for the year rose
to 76.2 percent, from the previous year's average of 71.7 percent.4
Total downstream charge capacity on January 1, 1985, stood at 28.3
million barrels per stream day, a net decrease of 0.4 million barrels per
stream day. Downstream charging capacity includes the following processes:
vacuum distillation, thermal operation, catalytic cracking (fresh and
recycled), catalytic reforming, catalytic hydrocracking, and catalytic
hydrotreating. New construction at existing refineries and the start-up
of previously closed refineries was more than offset by the nearly 0.7
million barrels per stream day capacity closed during 1984. The most
significant declines were in vacuum distillation and catalytic reforming,
dropping 2 percent and 4 percent, respectively. However, during the
year, downstream charge capacity increased 3 percent for catalytic cracking
(recycled) and nearly 11 percent for catalytic hydrocracking.5
-------
3-7
TABLE 3-2
Number of Operable Refineries in the U.S.6>7«8»9>10
Year
1981
1982
1983
1984
1985
Total
303
273
225
220
191
TABLE 3-3
Crude Oil Disti11ationll,12,13,14,15,16
(Thousands of Barrels per Calendar Day)
U.S. Capacity
Puerto Rico
Virgin Islands and Guam
Hawaiian Foreign Trade Zone
1981
18,465
228
714
68
1982
17,669
255
744
68
1983
16,157
244
559
60
1984
15,862
121
558
60
1985
15,13'
121
588
62
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3-8
Refiners project that total downstream charge capacity may drop to
28.1 million barrels per stream day by 1986. However, the downstream
processing mix is not projected to change appreciably from January 1,
1985, levels. All major downstream refinery processes, except catalytic
hydrotreating, are expected to fall below current year levels.^
Refinery receipts of crude oil averaged 12.2 million barrels per day
during 1984, up 0.5 million barrels per day from 1983. This increase
represented a reversal of the downward trend that started in 1979.
Receipts of domestic crude oil averaged 8.8 million barrels per day and
foreign averaged 3.3 million barrels per day. Most of the increase
in refinery receipts of crude oil was from domestic sources, rising from
8.6 million barrels per day during 1983 to 8.8 million barrels per day
during 1984. Foreign crude receipts also rose during 1984, reaching 3.3
million barrels per day from 3.2 million barrels per day during 1983.18
3.3 EMISSIONS FROM COMBUSTION OF REFINERY FUEL GAS
An integrated refinery uses energy equivalent to about 10 percent
of the total energy content in the crude oil it processes.^ The fuel
requirements of any one refinery depends on the nature of the feed, the
final product yield and the level of the individual product quality. All
of the refinery's energy needs could be derived from its own crude oil
feed, usually refinery fuel gas and residual oil, but most refineries are
designed to use available supplemental fuels such as natural gas.
Figure 3-1 illustrates a modern refinery, the various processes and
their respective products. As indicated in Figure 3-1, several refinery
processes produce refinery fuel gas as a by-product. After removing the
-------
3-9
H2S, the refinery fuel gas is burned in various combustion devices (boilers
and heaters) located throughout the refinery. Based on five plant surveys
and trip reports, there do not appear to be any particular processes or
combustion devices in which refineries utilize refinery fuel gas as a fuel.
The number of combustion devices and the various processes in which refinery
fuel gas is burned varies greatly from one refinery to another.
Since all crude oil contains some amount of sulfur, the refinery
fuel gas produced by the various processes will also contain sulfur. The
sulfur content of crude oil ranges from less than 0.1 percent to greater
»
than 5 percent sulfur by weight. Sulfur in the refinery fuel gas will be
in the form of hydrogen sulfide (H2S), carbonyl sulfide, mecaptan sulfur plus
GI and C2 sulfides. As the sulfur concentration of the crude oil increases,
so does the concentration of H.2$ and other sulfur compounds in the refinery
fuel gas. Combustion of refinery fuel gas containing H2$ produces sulfur
dioxide (S0£). Thus, when untreated refinery fuel gas derived from crude
oil with a high sulfur content is burned in the various process combustion
sources, substantial quantities of S02 will be emitted to the atmosphere.
As discussed in Chapter 2, the new source performance standard
prohibits the burning of refinery fuel gas containing more than 230 mg
H2S/dscm (0.10 gr/dscf) in any combustion device that burns refinery fuel
gas. The combustion of process upset gas in a flare, and process gas or
refinery fuel gas released to a flare from relief valve leakage is exempt
from this standard.
The alternative to the 230 mg H2S/dscm refinery fuel gas standard is
that an owner or operator may elect to treat the gases resulting from the
-------
3-10
combustion of refinery fuel gas so as to limit the release of S02 to the
atmosphere. The EPA Administrator must be satisfied that treatment of
the combustion gases controls S02 emissions as effectively as compliance
with the H2S standard.
The standard is equivalent to a S02 content of approximately
20 gr/100 scf of refinery fuel gas burned. Burning such fuel will result
in a concentration of 15 to 20 parts per million S02 in the combustion
products.20
3.4 SELECTION OF REFINERY COMBUSTION DEVICES FOR NSPS CONTROL
Combustion devices that burn refinery fuel gas were originally selected
for NSPS development because of their potential to emit sulfur dioxide (S02)
in significant quantities. At the time of the NSPS development, (in the
early 1970's) the nationwide emissions of S02 were estimated to be 28 million
tons per year. It was estimated that in 1970 approximately 0.8 million tons
of sulfur dioxide were emitted from petroleum refineries.^1 The background
study for the original NSPS predicted an overall emissions reduction for
controlled sources of 95 percent.
3.5 REFERENCES
1. Laster L.L., 1973. Atmospheric Emissions from the Petroleum Industry.
National Environmental Research Center, Research Triangle Park, N.C. 27711.
NTIS, Springfield, Virginia. PB-224-040.
2. National Petroleum Refiners Association. U.S. Refining Capacity.
Washington, D.C. July 1, 1985.
3. Cantrell, A. Annual Refining Survey. Oil and Gas Journal. Page 122.
March 18, 1985.
4. Same as reference #2. Page iii.
5. Same as reference #2. Page iii.
6. Cantrell, A. Annual Refining Survey. Oil and Gas Journal. Page 112.
March 30, 1981.
-------
3-11
7. Cantrell, A. Annual Refining Survey. Oil and Gas Journal. Page 130.
March 22, 1982.
8. Cantrell, A. Annual Refining Survey. Oil and Gas Journal. Page 130.
March 21, 1983.
9. Cantrell, A. Annual Refining Survey. Oil and Gas Journal. Page 112.
March 26, 1984.
10. Same as reference #3. Page 123.
11. Same as reference #6.
12. Same as reference #7.
13. Same as reference #8.
14. Same as reference #9.
15. Same as reference #3. Page 123.
16. Same as reference #2.
17. Same as reference #2. Page V.
18. Same as reference #2. Page V.
19. 1985 HPI Market Data. Hydrocarbon Processing, page 26.
20. Background Information for Proposed New Source Performance Standards:
Asphalt Concrete Plants, Petroleum Refineries, Storage Vessels,
Secondary Lead Smelters and Refineries, Brass or Bronze Ingot
Production Plants, Iron and Steel Plants, and Sewage Treatment
Plants. U.S. Environmental Protection Agency. Research Triangle
Park, N.C. Publication Number APTD-1352a. June 1973. Page 27.
21. National Air Pollutant Emission Estimates, 1940-1983. U.S. EPA,
RTP, N.C. EPA 450/4-84-028. December 1984.
-------
-------
4. STATUS OF CONTROL TECHNOLOGY
This chapter discusses the control techniques being used to meet the
new source performance standards (NSPS). In order to comply with the
hydrogen sulfide (H2$) emission requirements (230 mg/dscm, 0.10 gr/dscf)
of this NSPS, the owner/operator of the affected facility has the option
of either reducing the H2S concentration prior to burning the refinery
fuel gas in the affected facility or treating the sulfur dioxide (S02)
emissions from the affected facility. At this time, all known affected
facilities control S0£ emissions by reducing the H2$ concentration in the
fuel gas prior to being burned.
A review of the literature, the Environmental Protection Agency
(EPA) compliance data system, discussions with refinery personnel, trade
organizations, local, State, and EPA regional agencies reveals that two
processes are being used to comply with the NSPS. These two systems are
the alkanolamine process system and the LO-CAT® system. These processes
are discussed below.
4.1. ALKANOLAMINE PROCESS SYSTEM
The first commercially available alkanolamine was triethanolamine (TEA)
which was used in early natural gas treating plants. As other members of
the alkanolamine family were introduced into the market, they were evaluated
as possible acid gas absorbents.l Alkanol amines are categorized as being
primary, secondary, or tertiary, depending upon the degree of substitution
of the central nitrogen atom by organic groups. Structural formulas for
the various alkanolamines are presented in Figure 4-1. Two commercially
utilized primary amines are monoethanol amine (MEA) and diglycol amine (DGA),
-------
4-2
each shows single substitution of organic groups at the central nitrogen
atom. Two commercially available secondary amines are diethanolamine (DEA)
and diisopropanolamine (DIPA). The two secondary amines show double
substitution of organic groups at the central nitrogen atom. A triple
substitution of organic groups at the central nitrogen atom is possible,
hence the tertiary amines: triethanolamine (TEA) and methyldiethanolamine
(MDEA).
Alkanolamines are weak organic bases with each one of the amines
illustrated in Figure 4-1 having at least one hydroxyl group (OH) and one
amino group. In general, it can be considered that the hydroxyl group
serves to reduce the vapor pressure and increase the water solubility,
while the amino group provides the necessary alkalinity in water solutions
to cause the absorption of acidic gases.2 As crude oil is processed the
following acid gases are formed and can be found in untreated refinery
fuel gas: hydrogen sulfide (H2S), carbon dioxide (003), and carbonyl
sulfide (COS). These compounds are considered to be acid gases because
when dissolved in an aqueous medium, they dissociate to form weak acids.
The acid gas and amine base will combine chemically to form an acid-base
complex called a salt, thus removing the acid gas from the process stream.3
The principal reactions of the alkanolamines with H2$ are listed in
Table 4-1. The reactions shown in Table 4-1 proceed to the right at low
temperatures and to the left at higher temperatures. This is the reason
that H2S can be absorbed by alkanolamine solutions at ambient temperatures.
At elevated temperatures (as exist in the stripper column), the reactions
are reversed with the sulfide and carbamate salts being decomposed and the
acid gases released in the stripper column.*
-------
4-3
FIGURE 4-1
MOLECULAR STRUCTURES OF COMMON GAS TREATING AMINES5
Primary Amines: single substitution of organic group at the nitrogen atom
Monoethanolamine (MEA) Diglycolamine (DGA)
MW =61 MW = 105
H
;N-CH2-CH2-OH N-CH2-CH2-0-CH2-CH2-OH
Secondary Amines: double substitution of organic group at the nitrogen atom
Diethanolamine (DEA) Diisopropanolamine (DIPA)
MW = 105 MW = 133
HO-CH2-CH2-N-CH2-CH2-OH HO-CH-CH2-N-CH2-CH-OH
I III
H CH3 H CH3
Tertiary Amines: triple substitution of organic group at the nitrogen atom
Triethanolomine (TEA) Methyldiethanolamine (MDEA)
MW = 149 MW = 119
HO-CH2-CH2-N-CH2-CH2-OH HO-CH2-CH2-N-CH2-CH2-OH
CH2-CH2-OH CH3
-------
4-4
TABLE 4-1
PRINCIPAL REACTIONS OF ALKANOLAMINES WITH HYDROGEN SULFIDE6
Primary Amines
+ H2s <::::::::::> (RNH3)2s
(RNH3)2s + H2s <:::::::::
Secondary Amines
2R2NH + H2s <:::::::::> (R2NH2)2s
(R2NH2)2s + H2s <:::::::::> 2R2NH
Tertiary Amines
2R3N + H2s <:::::::::> (R3NH)2s
(R3NH)2s + H2s <:::::::::> 2R3NHHs
R = C2H4OH
-------
4-5
Various literature sources Indicate that as alkanolamines were
developed and field tested, the primary and secondary amines displaced
TEA. Triethanolamine was displaced largely because of its low ^B capacity
(resulting from higher equivalent weight), its low reactivity (as a
tertiary amine), and its relatively poor stability.7 Information obtained
via plant visits and contacts with petroleum refineries indicate that
primary and secondary amines are indeed the principle types of amines
used in alkanolamine process systems. However, one refinery responded
that it used MDEA, a tertiary amine. Also, two of the five refineries
that were visited are considering switching from DEA to MDEA because
of its selectivity for removing only HgS and the associated reduction in
energy needed to regenerate the MDEA.8,9
The general process flow for an alkanolamine processing plant is
shown in Figure 4-2. The process flow scheme varies little, regardless
of the aqueous amine solution used to remove H2S. The primary pieces of
equipment of concern are the absorber column and stripper column, together
with the associated piping, heat exchange, and separation equipment.
The sour refinery fuel gas containing H2$ will nearly always enter
the alkanolamine process plant through a separator (not shown) to remove
any free petroleum liquids and/or entrained solids. The sour gas then
enters the bottom of the absorber column and flows upward through the
absorber in intimate counter-current contact with the aqueous amine
solution. The H2S is removed and sweetened gas leaves the top of the
absorber and flows to another separator (not shown) to remove any amine
solution and/or entrained solids that are carried over with the exiting
refinery gas.
-------
4-6
FIGURE 4-2
ALKANOLAMINE TREATING UNIT
10
^•TREATED PROCESS GAS
,REGENERATED
AMINE-, FOUL AMINE
SOUR PROCESS GAS
JU^ACIO - WATER
* ^ /
ABSORBER
STRIPPER
HYDROGEN
SULFIDE,
TO SULFUR
RECOVERY
WATER
AMINE
-------
4-7
Lean amine solution from the bottom of the stripper column is pumped
through an amine-amine heat exchanger and then through a water or air-
cooled exchanger before being introduced to the top tray of the absorber
column. The amine moves downward through the absorber counter-current to
the sour gas, and absorbs HgS from the gas stream. Rich amine solution
flows from the bottom of the absorber through the amine-amine heat
exchanger and then to the top of the stripper column.
The amine-amine heat exchanger serves as a heat conservation device
and lowers total heat requirements for the process. The rich solution
flows downward through the stripper in counter-current contact with vapor
generated .in the reboiler. The reboiler vapor (primarily steam) strips
the acid gases from the rich solution. The acid gases and steam leave
the top of the stripper and pass through a condenser, where the major
portion of the steam is condensed and cooled. The acid gases are separated
in a separator and sent to the sulfur recovery unit. The condensed steam
is returned to the top of the stripper column as reflux or a slip stream
is bled off to control the ammonia concentration in the top of the stripper
column to help maintain the amine system water balance.
Rich amine solution leaves the bottom of the absorber at an elevated
temperature due to the heat of reaction released when acid gases react
with the amine. The amine cooler serves to lower the lean amine temperature
to the 100°F range. Higher temperature on the lean amine solution will
result in excessive amine losses through vaporization and also lower acid
gas carrying capacity in the solution because of temperature effects.
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4-8
4.2 THE LO-CAT® HYDROGEN SULFIDE OXIDATION PROCESS
The LO-CAT® process, a process based on a liquid-phase-oxidation
technique originated by Humphreys and Glasgow (London), was developed to
provide an isothermal process for carrying out the modified Claus reaction.H
H2S + 1/2 02 > H20 + S°
The LO-CAT® process has two basic designs: aerobic, which absorbs H2S
from air laden streams, and anaerobic, used when the gas stream has
little or no oxygen present. The anaerobic application is used in treating
refinery fuel gas. Figure 4-3 is a flow diagram of an anaerobic LO-CAT®
*
H2S oxidation process used to treat refinery fuel gas.
The LO-CAT® process removes sulfur by using a proprietary catalyst
that consists of an aqueous solution of chelated iron, buffered with soda
ash (Na2C03), potassium hydroxide (KOH) or any other common alkali to a
pH of about 8. The LO-CAT® catalyst solution is circulated in a closed loop
between the absorbers and the oxidizer vessel. Sour gas passes through
an inlet gas scrubber to remove entrained liquids and enters the absorber
at line pressure through a specially designed venturi prescrubber. The
gas passes upward through a low liquid-filled vessel, an absorber, in
which the sour gas contacts the LO-CAT® catalyst solution flowing downward.
In the absorbers the H2S gas is absorbed very rapidly into the catalyst
solution where it is immediately oxidized to precipitate elemental sulfur.
The following chemical reactions take place in the absorber vessel:12
(1) H2S Absorption
H2S + H20 > H2S (aqueous) + H20
(2) First lonization
H2S (aqueous) > H+ + HS"
-------
4-9
FIGURE 4-3
FLOW DIAGRAM OF A LO-CAT SYSTEM
13
SOUR GAS
SCRUBBER
VEiNTURI LIQUID FILLED
PRE-CCINTACTOR ABSORBER
OXIDIZER AIR
COMPRESSOR
SEPARATOR
SULFUR
LOADOUT
STATION
MOLTEN
SULFUR
STORAGE
•ntr •« our
SOLUTION
CNtCUiniON
CMCUICAL UBITION tOUmKMT MOT »MOWW.
-------
4-10
(3) Second lonization
HS" > H+ + S=
(4) Oxidation of Sulfide
2Fe+++ + S= - > 2Fe++ + S°
f,
Sweet gas with less than 100 ppm H2S leaves the absorber vessel and
passes through a sweet gas scrubber (not shown in Figure 4-3) to guard
against mist carryover before entering the fuel system.
Active LO-CAT® catalyst solution enters the absorber column at the top
and flows downward through the vessel counter-current to the gas flow. The
spent solution leaves at the bottom of the vessel. Partially reduced
solution is regenerated in the oxidizer vessel by direct contact with
compressed air.
Regeneration of the LO-CAT® solution in the oxidizer vessel involves the
following reactions:I4
(5) Oxygen Absorption
02 + H20 -> 2(0) (aqueous) + H20
(6) Regeneration of Iron
2Fe++ + 0 (aqueous) + H20 — -> 2 Fe+++ + 2 (OH)~
Overall, the reaction is
(7) H2S + 0.5 02 > H20 + S°
The air used to generate the catalyst solution is supplied by an air
blower to an air sparger grid near the bottom of the oxidizer. The spent
air, with a small fraction of the oxygen removed, leaves the top of the
oxidizer vessel and discharges to the atmosphere.
-------
4-11
The circulating catalyst solution, which contains elemental sulfur
in a slurried form, flows from the absorber back to the oxidizer through
a solution cooler which removes heat generated by the exothermic reactions
in the absorber. Sulfur formed in the absorber vessel circulates with
the solution and the particles grow to the 10-20 micrometer range. The
larger particles settle out of the bulk solution, flow in the bottom of
the oxidizer vessel, and are flushed out the oxidizer vessel as a slurry
of 10 to 20 percent by weight of sulfur. The sulfur slurry is pumped at
approximately 100 psig through a special non-plugging heat exchanger or
melter, where it is heated to 270°F by 50 psig steam. The aqueous catalyst
solution/molten sulfur mixture formed in the melter is fed through steam
jacketed piping to a steam jacketed separator vessel. Molten sulfur is
withdrawn from the separator vessel to a molten sulfur storage tank or a
sulfur pit where it is stored for ultimate shipment by truck or rail car.
The clarified catalyst solution leaves the sulfur settler through a
back pressure control valve set at about 75 psig. The bulk of the solution is
returned to the settler vessel and then to the absorber/oxidizer circuit.
In the oxidation of H2S to sulfur, some side reaction takes place which
may be represented by the equation:15
(8) 2HS~ + 1.5 02 > H2S203
This reaction reduces the pH of the scrubbing solution, and NagCOs,
KOH, or other alkaline salt must be added to maintain the pH of the solution
in the 8-8.5 pH range. This leads to a gradual buildup of sodium thiosulfate
(Na2S203) or similar water-soluble sulfur-containing salts in the solution.
These have no deleterious effect at concentrations below 30 percent by
weight. When the thiosulfate concentration exceeds 30 percent by weight
-------
4-12
some of the spent catalyst solution is withdrawn to a holding tank for
disposal. The thiosulfate has a commercial value; thus, this solution
can be sold and the thiosulfate reclaimed. Another means of disposal is
to treat this solution in the refinery's biological wastewater treatment
system.
4.3 FACILITIES SUBJECT TO THE NSPS
In Chapter 2 the term "affected facility" was discussed and defined.
As noted, the affected facility is defined as the combustion device that
is capable of burning refinery fuel gas and not the H2S control system.
Information obtained from plant trips and surveys indicates that refinery
fuel gas is burned in combustion devices that are used in a wide variety
of production processes within a refinery. There does not appear to be a
tendency for refineries to use refinery fuel gas as an energy source in
any particular production process. Thus the utilization of refinery fuel
gas will vary from one refinery to another.
According to information supplied by the EPA's Stationary Source
Compliance Division (SSCO), fifty-four (54) petroleum refineries have become
subject to the H£S portion of this NSPS since 1975. Unfortunately, an
accurate number of affected facilities within each refinery could not be
determined. The information supplied by SSCD is considered to underestimate
the number of refineries and affected facilities subject to this NSPS.
This low estimate is attributed to the fact that some State agencies that
have authority to enforce the Clean Air Act do not report all the refineries
and affected facilities to SSCD.
Trade journals were also reviewed for information. These sources
report new refinery construction projects plus modification and reconstruction
-------
4-13
projects that are occurring at petroleum refineries. Unfortunately, the
manner in which the modification and reconstruction projects are reported
does not indicate whether these projects will be subject to the ^S portion of
this NSPS nor how many combustion sources are involved. A review of various
trade journals from 1980 to 1985 indicates there have been construction
projects at 42 petroleum refineries that involve either an amine treater
unit, a LO-CAT® unit, or unspecified refinery fuel gas recovery.
4.4 COMPLIANCE TEST RESULTS
The Environmental Protection Agency regional offices, State agencies,
and petroleum refineries were contacted to obtain compliance test informa-
tion for new, modified, or reconstructed facilities.
All of the test data that were submitted were from refineries that use
an alkanolamine process system to remove the hydrogen sulfide (H2S) from
the refinery fuel gas. No compliance test data were obtained from a
refinery that uses the LO-CAT® system to treat sour refinery fuel gas.
4.4.1. Alkanolamine Process System Compliance Data16»17»18»19'20»21»22»23
Data for fifteen (15) compliance tests were obtained from nine (9)
different refineries. The results of these tests are listed in Table 4-2.
The new source performance standard (NSPS) for H£S is 230 mg/dscm
(O.lOgr/dscf). Compliance test results for the H2S concentration in
refinery fuel gas ranges from 2.97 mg/dscm to 119.43 mg/dscm. The data
indicate that refineries are able to meet the NSPS. Also, none of the
refineries that were contacted indicated that they were experiencing any
problems complying with the NSPS.
-------
4-14
TABLE 4-2
COMPLIANCE TEST RESULTS FOR ALKANOLAMINE PROCESS SYSTEMS
Ref i nery
A
B
C
D
E
F
G
H
I
Date of
Test
2/81
4/82
10/82
3/84
7/84
7/76
8/84
8/84
11/80
11/81
1/84
--
10/84
8/81
6/85
Type of
Alkanolamine Used
MEA/primary
ti H
n H
ii n
n n
DEA/secondary
MEA/primary
n H
DEA/secondary
DEA/secondary
n n
MEA/primary
MEA/primary
DEA/secondary
DGA/primary
Avg.H2S Concentration
(mg/dscm)
101
32
12
57
77
119.43
2.97
8.09
12.5
89.2
63.3
105.6
18.1
27.7
3.1
NSPS = 230 mg/dscm
-------
4-15
4.4.2 LO-CAT® Process System24
Currently, the LO-CAT® treatment system is used in only two (2)
refineries within the United States to remove H2S from refinery fuel gas.
Only one of these refineries was operating as of January 1985. Both of these
LO-CAT® systems are small units, less than 20 LT/D. Compliance tests have
not been performed for either of the two LO-CAT® systems. Thus, there are
no data for this type of system. However, one refinery has installed a
continuous H2$ monitor. According to information submitted by the refinery,
the \\2$ concentration of the refinery gas treated by the LO-CAT® system
ranges from 20 ppmv to 50 ppmv and averages 30 ppmv. The refinery reported
no excess emissions have occurred since the LO-CAT® system became operational.
4.5 Emission Monitoring
The NSPS requires an H2S continuous monitoring device to be installed
in order to determine compliance with the H2S standard of 230 mg/dscm.
However, the EPA has not yet developed performance specifications for H2S
continuous monitoring systems.
In April 1979, the EPA initiated work to establish specifications
and also to determine the durability, maintenance requirements, and data
validity of commercially available H2S continuous emission monitors.25
Five (5) H2$ monitors were selected for evaluation. Selection criteria
included operating principles, engineering judgment about suitability for
use at petroleum refineries, and total cost. The performance of the five
(5) H2$ monitors tested was disappointing. The absolute agreement between
reference Method 11 and all monitors was poor and variable in eight out
of ten relative accuracy tests. Thus, a conclusion of the test program
-------
4-16
was that the use of H2S monitors for compliance purposes could not be
recommended at that time nor could performance specifications for H2S
monitors be written. Even though performance specifications for continuous
H2$ monitoring devices have not been promulgated by the EPA, some refineries
have been required by State agencies to install an \\2$ continuous monitoring
device.
Refineries subject to the I^S portion of this NSPS that do not have a
continuous H2S monitor are using manually collected grab samples (Draeger
Tubes) to test the refinery fuel gas for H2S concentration. The frequency
with which these samples are collected varies from one refinery to another
and can range from 1 manual sample per shift to 3 manual samples per shift.
4.6 REFERENCES
1. Kohl, Arthur L. and Fred C. Riesenfeld. Gas Purification (Third
Edition). Houston, Gulf Publishing Company. 1979. Page 28.
2. Same as reference #1. Page 29.
3. Butwell, K. F., D. J. Kubek, and P. W. Sigmund. Alkanolamine Treating.
Hydrocarbon Processing. Page 108. March 1982.
4. Maddox, Dr. R. N. Gas and Liquid Sweetening. Norman, Oklahoma.
Campbell Publishing Series. 1974. Page 47.
5. Same as reference #3.
6. Same as reference #4. Pages 45-47.
7. Same as reference #1.
-------
4-17
8. Memo from El more, William Larry, EPA, to Kenneth R. Durkee, EPA.
January 27, 1986. Trip report for plant visit to Alliance Refinery,
B.P. Oil Incorporated, Belle Chasse, Louisiana.
9. Memo from Elmore, William Larry, EPA, to Kenneth R. Durkee, EPA.
January 22, 1986. Trip report for plant visit to Tenneco Oil Refinery,
Chalmette, Louisiana.
10. Background Information for Proposed New Source Performance Standards:
Asphalt Concrete Plants, Petroleum Refineries, Storage Vessels,
,Secondary Lead Smelters and Refineries, Brass or Bronze Ingot
Production Plants, Iron and Steel Plants, and Sewage Treatment
Plants. U.S. Environmental Protection Agency. Research Triangle
Park, N.C. Publication Number APTD-1352a. June 1973. Page 27.
11. Hardison, L. C. Treating Hydrogen Sulfide: An Alternative to Claus.
Chemical Engineering. January 21, 1985. Page 62.
12. Letter and attachments from L. C. Hardison, ARI Technologies, Inc. to
Elmore, Larry, EPA. October 18, 1985.
13. Same as reference #12.
14. Same as reference #12.
15. Same as reference #12.
16. Letter and attachments from Thompson, J. E., Citgo Petroleum Corporation
to Farmer, J. R., EPA. March 15, 1985. Response to Section 114
letter on petroleum refineries.
17. Letter and attachments from Ballard, B. F., Phillips Petroleum Company
to Farmer, J. R., EPA. March 21, 1985. Response to Section 114
letter on petroleum refineries.
18. Letter and attachments from Livermore, A. R., La Gloria Oil and Gas
Company, to Farmer, J. R., EPA. April 9, 1985. Response to
Section 114 letter on petroleum refineries.
19. Letter and attachments from Mull ins, J. A., Shell Oil Company, to
Farmer, J. R., EPA. April 9, 1985. Response to Section 114 letter
on petroleum refineries.
20. Letter and attachments from Cox, R. A., Texaco USA, to Farmer, J. R.,
EPA. March 29, 1985. Response to Section 114 letter on petroleum
refineries.
21. Letter and attachments from Owing, E. C., National Cooperative Refinery
Association, to Farmer, J. R., EPA. February 21, 1985. Response to
Section 114 letter on petroleum refineries.
-------
4-18
22. Memo and attachments from Mclaughlin, N. 0., EPA, to Durkee, K. R., EPA,
February 5, 1985. Trip report on plant visit to Murphy Oil Company,
Meraux, Louisiana.
23. Same as reference #9.
24. Letter and attachments from Hullinger, T. T., U.S. Oil and Refining
Company, to Farmer, J. R., EPA. May 15, 1985. Response to
Section 114 letter on petroleum refineries.
25. A Study To Evaluate Carbon Monoxide and Hydrogen Sulfide Continuous
Emission Monitors at an Oil Refinery. U.S. Environmental Protection
Agency. Research Triangle Park, N.C. EPA-600/4-82-054. August 1982.
-------
5. MODEL PLANTS AND CONTROL SYSTEMS
5.1 MODEL PLANTS AND CONTROL SYSTEMS
Model plants and model plant parameters are selected to represent
the range of facilities that have become subject to the NSPS since its
promulgation in 1974 or that are likely to be constructed, modified, or
reconstructed in the future. The control systems applied to the model
plants are selected to represent those control techniques that have been
commonly installed to meet the NSPS. The model plants are defined in
this chapter and a cost analysis of these model plants is presented in
Chapter 6.
As discussed in Chapter 4, two types of control systems are commonly
used by refineries to control H£S in refinery fuel gas. These two systems
are amine treater/Claus sulfur recovery units and LO-CAT® units.
The amine treater/Claus sulfur recovery unit combination is the most
widely used process. The LO-CAT® system is a relatively new process that
has been introduced since the last review of this standard and currently
only two LO-CAT® units (sulfur capacity 7 and 17.35 LT/D) have been
installed in the U.S. for HgS removal from refinery fuel gas.
5.1.1 Model Control Systems and H2S Concentrations
The selection and sizing of model ^S control systems is based on
the total sulfur loading in the untreated refinery fuel gas. Six sizes
of control units were evaluated for this review: 1, 2, 5.1, 10.2, 50.8,
and 101.6 Mg/D (1, 2, 5, 10, 50, and 100 LT/D). Three H2S concentrations
in the untreated refinery fuel gas (1, 5, and 10 percent H£S by volume)
were analyzed for each model plant.
-------
5-2
Tables 5-1 and 5-2 list the model plants. The amine treater/Claus
sulfur recovery unit was modeled for the following sizes: 5.1, 10.2,
50.8, and 101.6 Mg/D (5, 10, 50, and 100 LT/D). The LO-CAT® system was
modeled for 1, 2, 5.1, and 10.2 Mg/D (1, 2, 5, and 10 LT/D).
5.2 EMISSION REDUCTIONS
This section presents the sulfur dioxide (S02) emission reductions
that are achieved by each model control system. The emission reduction
for each model control system is determined by comparing the emissions
from a control system meeting the new source performance standard (NSPS)
versus the emissions from the baseline situation of no control.
5.2.1 Amine Treater/Cl aus Sulfur Recovery Unit
The S02 emission reductions for the model amine/Claus sulfur recovery
units are presented in Table 5-3. All incoming sulfur (in the form of
H2S) in the untreated fuel gas is either routed to fuel gas combustion
devices, converted in the Claus sulfur recovery unit to elemental sulfur,
or emitted from the Claus unit to the atmosphere. The model amine treaters
were designed to, achieve the NSPS limit of 230 mg of H2S/dscm in the fuel
gas stream to combustion sources, while the remainder of the H2S is sent
to the Claus unit. The model Claus units were designed to achieve a 96.6
percent sulfur recovery efficiency. For calculating emission reduction,
it was assumed that the amine treater/Claus system was operating at the
capacity of the Claus unit for 350 operating days per year.
-------
5-3
TABLE 5-1
MODEL PLANTS: AMINE TREATER AND CLAUS SRU
Model
Sulfur
(Mg/D)
5.08
10.16
50.8
101.6
Plant Size
Processed
(LT/D)
(5)
(10)
(50)
(100)
Fuel Gas
H2S Cone.
(% by Volume)
1
5
10
1
5
10
1
5
10
1
5
10
Amine
Efficiency
(%)
98.38
99.68
99.84
98.38
99.68
99.84
98.38
99.68
99.84
98.38
99.68
99.84
Glaus SRU
Efficiency
(%)
96.6
96.6
96.6
96.6
-------
5-4
TABLE 5-2
MODEL PLANTS: LO-CAT®
Model Plant Size RFG Unit
Sulfur Processed H2$ Cone. Efficiency
(Mg/D) (LT/D) (% by Volume)
1.016
(1)
1
5
10
98.38
99.68
99.84
2.032 (2) 1 98.38
5 99.68
10 99.84
5.08 (5) 1 98.38
5 99.68
10 99.84
10.16 (10) 1 98.38
5 99.68
10 99.84
-------
5-5
TABLE 5-3
S02 EMISSION REDUCTION USING A
AMINE TREATER/CLAUS SULFUR RECOVERY UNIT
Model Control Uncontrolled S02 S02 Emission
System Size3 Emissions b>c Reductions^
(Mg/D) (LT/D) (Mg/yr) (Mg/yr)
5.08
10.16
50.8
101.6
(5)
(10)
(50)
(100)
3556
7112
35560
71120
3435
6870
34350
68700
a Model control system size (i.e., amount of sulfur processed) is based on the
sulfur loading into the amine treater/Claus sulfur recovery unit.
b 1 year = 350 operating days
c 1 Mg of sulfur (S2) converts to 2 Mg of S02 emissions
d Efficiency of the sulfur recovery unit was assumed to be 96.6%
-------
5-6
5.2.2 LO-CAT® Unit
The S02 emission reductions for the model LO-CAT® units are presented
in Table 5.4. As indicated in Figure 4-3, the LO-CAT® process has no
emission stream to the atmosphere. All the incoming sulfur (in the form
of H2$) is either converted to elemental sulfur or routed to the fuel gas
combustion devices. The model LO-CAT® units were designed to achieve the
NSPS limit of 230 mg of H2S/dscm in the outlet fuel gas stream. For
calculating emission reductions, it was assumed that the LO-CAT® unit was
operating at capacity for 350 operating days per year.
-------
5-7
TABLE 5-4
S02 EMISSION REDUCTION USING A LO-CAT® UNIT
Model
System
(Mg/D)
1.016
2.032
5.08
10.16
Control
Size9
(LT/D)
(1)
(2)
(5)
(10)
H2S
Cone
(% by Vol.)
1
5
10
1
5
10
1
5
10
1
5
10
Uncontrolled S02
Emissions" »c
(Mg/yr)
712
712
712
1422
1422
1422
3556
3556
3556
7112
7112
7112
Control System
SO? Emissions
(Mg/yr)
11.5
2.3
1.1
2.3
4.6
2.3
57.6
11.4
5.7
115.2
22.8
11.. 4
S02 Emission
Reductions
(Mg/yr)
701
710
711
1399
1417
1420
3498
3545
3550
6997
7089
7101
a Model control system size (i.e. amount of sulfur processed) is based on the
sulfur loading into the LO-CAT® unit.
b 1 year = 350 operating days
c 1 Mg of sulfur (S2) converts to 2 Mg of S02 emissions
-------
6. COST ANALYSIS
6.1 INTRODUCTION
This section presents costs (in January 1985 dollars) of model plant
control systems necessary to meet the hydrogen sulfide (and consequently
the sulfur dioxide) provisions of the current NSPS for refinery fuel gas.
Two control systems are analyzed: (1) for large sources of refinery fuel gas,
an amine treating section coupled with a Claus sulfur recovery plant; (2) for
smaller sources, a LO-CAT® process which absorbs the hydrogen sulfide and
oxidizes it to elemental sulfur with the aid of an iron-based catalyst.
(A more detailed discussion of the control systems appears in Chapter 4.)
Capital and annualized costs are estimated for the following model plant
sizes, all given on a nominal sulfur basis: LO-CAT® — 1.016 Mg per day
(1 long ton per day), 2.032 Mg/D (2 LT/D), 5.08 Mg/D (5 LT/D), and 10.16 Mg/D
(10 LT/D); amine-Claus -- 5.08 Mg/D (5 LT/D), 10.16 Mg/D (10 LT/D), 50.8
Mg/D (50 LT/D), 101.6 Mg/D (100 LT/D), 203.2 Mg/D (200 LT/D), 508 Mg/D (500
LT/D) and a plant expansion from 10.16 Mg/D to 10.668 Mg/D (10 to 10.5 LT/D)*.
(A more detailed discussion of model plants is presented in Chapter 5.)
Cost-effectiveness is calculated for all model plants and is discussed
for the two model plant sizes that are common to both control systems.
Except for the plant expansion, all estimated costs apply to new control
systems installed at new sources of refinery fuel gas. Note that the
cost of Claus tail gas treating is not considered in the analysis.
The costs presented for the amine-Claus process are based on raw cost,
data provided in References 1 and 2. Costs for the LO-CAT® process are
based on information from References 3, 4, and 5. Capital costs are on a
*Note: 1 Mg/D = 1.1025 short tons/D = 0.9844 LT/D
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6-2
turnkey basis and thus include the purchase cost of equipment and auxiliaries,
taxes, freight, and all necessary installation costs, as well as indirect
costs such as engineering and supervision, construction and field expense,
contractor fee, and contingency. Annualized costs include direct operating
costs such as operating labor, maintenance labor, utilities, and materials,
as well as ^indirect costs such as capital charges, overhead, property taxes,
insurance, and administration. Net annualized cost is also presented,
representing total annualized cost less the credit for recovered sulfur
where applicable. The costs thus obtained are "order-of-magnitude"--i.e.,
nominally j^ 50 percent in accuracy. Because most of the operating and
maintenance (O&M) costs have been calculated directly, their accuracy should
approach that of a study estimate (+_ 30 percent). Finally, because the
annualized costs are comprised of O&M costs and capital cost components,
their accuracy should fall between +_ 30 and +_ 50 percent.
6.2 AMINE TREATMENT WITH CLAUS SULFUR RECOVERY
6.2.1 Capital Costs
The capital costs for this combination process are estimated for
five model plants—four new and one expansion of an existing plant.
(Detailed model plant parameters are given in Chapter 5.) The capital
costs for the amine treatment section were calculated from cost factors
given in Reference 1 for gas sweetening operations. The process employs
diethanolamine (DEA) as the absorbent.
The capital costs for the Claus section were developed by updating the
costs in Reference 2 via the Chemical Engineering (CE) Plant Cost Index.
The capital cost for the 5.08 Mg/0 Claus plant was extrapolated logarithmically
from the 10.16 Mg/D model plant cost in Reference 1 (the smallest size)
using a 0.2 exponent, in accordance with cost vs. capacity formulas presented
-------
6-3
in Appendix A of Reference 1. The 0.2 exponent was found to hold in the low
size range, based on data gathered for Claus plants in Reference 1. Costs for
the 50 and 100 LT/D plants were updated from costs in Reference 1 for these sizes.
Capital costs for the two sections were added together for each model
plant and are presented in Table 6-1. The capital cost of the plant
expansion was calculated as the incremental cost of a 10.668 Mg/D plant
over a 10.16 Mg/D plant and does not include any retrofit costs. This
approach was taken as an expedient to arriving at an order-of-magnitude
cost for the expansion; it must be recognized that such an expansion would
be a site-specific case, the cost of which could vary significantly.
The capital costs for 200 and 500 LT/D model plants can be estimated
by multiplying the cost of the 100 LT/D plant by a factor of two or five,
respectively. This results from the fact that plants above 100 LT/D capacity
are normally constructed as trains, so that their costs vary linearly with
size.
6.2.2 Annualized Costs
The annualized costs associated with owning and operating the amine-
Claus plants are estimated for each model plant. The direct operating cost
includes operating and supervisory labor, maintenance, supplies, utilities,
chemicals, and catalysts. For the amine section, direct operating costs
were calculated by means of the cost factors given in Appendix A. For the
Claus section, the direct operating costs were developed by combining
consumption data with unit cost data, both from Reference 2. (The latter
are listed in Table 6-2.) The unit cost data were updated slightly by use
of Bureau of Labor Statistics factors in most cases, such as the Producer
Price Index.
-------
6-4
TABLE 6-1
CAPITAL COST SUMMARY
AMINE TREATMENT WITH CLAUS SULFUR RECOVERY
(January 1985 Dollars)
Cost in Thousands of Dollars
Plant, Capacity, Mg/D (LT/D) SuTfur
5.08 Mg/D (5 LT/D)
1% H2S
5% H2S
10% H2S
10.16 Mg/D (10 LT/D)
1% H2S
5% H2S
10% H2S
Ami nea
110
88.8
84.6
220
178
169
C1 ausb
2290
2290
2290
2630
2630
2630
Total c
2390
2370
2370
2840
2800
2790
50.8 Mg/D (50 LT/D)
1% H2S
5% H2S
10% H2S
101.6 Mg/D (100 LT/D)
1% H2S
5% H2S
10% H2S
Expansion of 0.508 Mg/D
(0.5 LT/D)d
1% H2S
5% H2S
10% H2S
a Cost developed from i
b Cost developed from i
1100
888
846
2200
1780
1690
10.7
9.2
8.5
nformation in Reference 1
nformation in Reference 2
4480
4480
4480
6470
6470
6470
25.8
25.8
25.8
.
5570
5360
5320
8670
8240
8160
36.5
35.0
34.3
c Totals may not add due to rounding.
d These costs represent
a 10.16 Mg/D plant.
the incremental costs of
a 10.688 Mg/D
plant over
-------
6-5
TABLE 6-2
ASSUMED UNIT COSTS FOR
OPERATING COST ESTIMATION
CLAUS SULFUR RECOVERY PLANTS^,c
Operating Cost Item
Operating 1 abor
Supervision labor
4300 Kp steam
1760 Kp steam
352 Kp steam
106 Kp steam
Steam condensate
Boiler feedwater
Electricity
Fuel gas
Sulfur
Unit Cost (Credit)
$15.00/h
$20.00/h
$17.50/Mgd
($16.25/Mg)
($14.00/Mg)
($11.00/Mg)
($ 3.00/Mg)
$ 3.60/Mg
$15.28/Gj
$ 4.00/Gj
($110/Mg)e
English Equivalent
$ 7.94/103lb
($ 7.37/103lb).
($ 6.35/103lb)
($ 4.99/103lb)
. ($ 1.36/103lb)
$ 1.63/103lb
$ 0.055/KWh
$ 4.22/MM BTU
($111.8/LT)
a For Claus plant operating cost estimation, unit costs were multiplied by
consumption factors given in Reference 2.
b Unit costs were not used for operating cost estimation for the amine
process or LO-CAT® process; operating costs for these processes were given
in References 1 and 3, respectively, as functions of gas flowrate or plant
capacity.
c The total costs for catalysts given in Reference 2 were multiplied by 1.1
to update them to January 1985 dollars.
d Cost or credit depending upon model plant.
e Based on the cost given for recovered (i.e., Claus plant) sulfur, Houston
terminal, in Chemical Marketing Reporter, January 21, 1985.
-------
6-6
Most indirect costs were factored from capital costs or direct operating
costs using appropriate factors from References 6 and 7. Capital recovery
was calculated from the capital cost with a 10 percent rate of return and a
15-year equipment life (Reference 2). There is no waste disposal cost,
because spent catalysts are regenerated. The annualized cost includes an
estimate of the credit for recovered sulfur at prices applicable in January
1985, a period of relative stability for recovered sulfur prices. Note
also that credit for different pressures of steam varies in that, in
general, the larger the Glaus plant, the greater the heat recovery practiced
and the higher the pressure of steam that is recovered.
The annualized costs for both sections were added together for each
model plant and are presented in Tables 6-3 through 6-9. Again, costs for
expanding the existing 10.16 Mg/D plant to 10.668 Mg/D were calculated as
incremental costs. All annualized costs are based on 350 operating days
per year. See Appendix B for an example of annualized cost estimation for
the individual processes that make up the control system (amine treating
and Claus sulfur recovery).
6.3 LO-CAT® PROCESS
6.3.1 Capital Costs
Capital costs for LO-CAT® model plants are also estimated. Although the
model plants envision incoming hydrogen sulfide concentrations of 1, 5, and 10
percent, according to Reference 5 the differences in capital cost among the three
would not be significant. Therefore, the costs are developed independent of
hydrogen sulfide concentration. The purchased equipment cost was taken directly
from Reference 3 and includes all primary and auxiliary equipment and
instrumentation. Taxes and freight costs were obtained from Reference 6.
-------
6-7
Table 6-3
ANNUALIZED COST SUMMARY*
AMINE TREATMENT WITH GLAUS SULFUR RECOVERY
5.08 Mg/D (5 LT/D) PTMT
(January 1985 Dollars)
Cost in Thousands of Dollars
H2S 5% H2S 10%H2S
Direct Operating Cost
Operating labor
Supervision
Maintenance, repairs
Supplies, laboratory
Utilities
4300 Kp steam
Boiler feedwater
Electricity
Fuel Gas
Chemicals, catalyst
Indirect Operating Cost
Overhead (50 percent of all labor costs)
Capital Recovery (10 percent rate of return,
15 years equipment life)
Taxes (one percent of capital cost)
Insurance (one percent of capital cost)
Administration (two percent of capital cost)
Total Annual i zed Cost Without Credit
Credits
4300 Kp steam
1760 Kp steam
352 Kp steam
106 Kp steam
Steam Condensate
Sulfur
Total Credits
Net Annual ized Cost
210
61
70
17
. 4
12
57
10
3
153
315
24
24
48
1,007
0
48
0
3
5
189
244
762
210
61
70
17
4
12
57
10
3
153
312
24
24
47
1,003
0
48
0
3
5
189
244
759
210
61
70
17
4
12
57
10
3
153
312
24
24
47
1,002
0
48
0
3
5
189
244
758
Totals may not add due to rounding
-------
6-8
Table 6-4
ANNUALIZED COST SUMMARYa
AMINE TREATMENT WITH GLAUS SULFUR RECOVERY
10.16 Mg/D (10 LT/D) PLANT
(January 1985 Dollars)
Cost in Thousands of Dollars
H2S
5%
10%H2S
Direct Operating Cost
Operating labor
Supervision
Maintenance, repairs
Supplies, laboratory
Utilities
4300 Kp steam
Boiler feedwater
Electricity
Fuel Gas
Chemicals, catalyst
Indirect Operating Cost
Overhead (50 percent of all labor costs)
Capital Recovery (10 percent rate of return,
15 years equipment life)
Taxes (one percent of capital cost)
Insurance (one percent of capital cost)
Administration (two percent of capital cost)
Total Annual i zed Cost Without Credit
Credits
4300 Kp steam
1760 Kp steam
352 Kp steam
1-06 Kp steam
Steam Condensate
Sulfur
Total Credits
Net Annual i zed Cost
210
61
82
17
7
24
114
19
7
155
- 374
28
28
57
1,184
0
95
0
6
9
378
489
695
210
61
82
17
7
24
114
19
7
155
369
28
28
56
1,177
0
95
0
6
9
378
489
688
210
61
82
17
7
24
114
19
7
155
367
28
28
56
1,175
0
95
0
6
9
378
489
686
Totals may not add due to rounding
-------
6-9
Table 6-5
ANNUALIZED COST SUMMARYa
AMINE TREATMENT WITH GLAUS SULFUR RECOVERY
50.8 Mg/D (50 LT/D) PLANT
(January 1985 Dollars)
Cost in Thousands of Dollars
H2S
5% H2S 10%H2S
Direct Operating Cost
Operating labor
Supervision
Maintenance, repairs
Supplies, laboratory
Utilities
4300 Kp steam
Boiler feedwater
Electricity
Fuel Gas
Chemicals, catalyst
Indirect Operating Cost
Overhead (50 percent of all labor costs)
Capital Recovery {10 percent rate of return,
15 years equipment life)
Taxes (one percent of capital cost)
Insurance (one percent of capital cost)
Administration (two percent of capital cost)
Total Annual i zed Cost Without Credit
Credits
4300 Kp steam
1760 Kp steam
352 Kp steam
106 Kp steam
Steam Condensate
Sulfur
Total Credits
Net Annual i zed Cost
210
61
151
17
58
170
512
97
35
169
733
56
56
111
2,436
0
464
18
26
50
1,889
2,448
(11)
210
61
151
17
58
170.
512
97
35
169
705
54
54
107
2,400
0
464
18
26
50
1,889
2,448
(47)
210
61
151
17
58
170
512
97
35
169
700
53
53
106
2,393
0
464
18
26
50
1,889
2,448
(55)
Totals may not add due to rounding
-------
6-10
Table 6-6
ANNUALIZED COST SUMMARYa»b
AMINE TREATMENT WITH CLAUS SULFUR RECOVERY
Mg/D I 100 LT/D) PLANT
(January 1985 Dollars)
Cost in Thousands of Dollars
H2S 5% H2S
10%H2S
Direct Operating Cost
Operating 1 abor
Supervision
Maintenance, repairs
Supplies, laboratory
Utilities
4300 Kp steam
Boiler feedwater
Electricity
Fuel Gas
ChemicaTs, catalyst
Indirect Operating Cost
. Overhead (50 percent of all labor costs)
Capital Recovery- (10 percent rate of return,
15 years equipment life)
Taxes (one percent of capital cost)
Insurance (one percent of capital cost)
Administration (two percent of capital cost)
Total Annual ized Cost Without Credit
Credits
4300 Kp steam
1760 Kp steam
352 Kp steam
106 Kp steam
Steam Condensate
Sulfur
Total Credits
Net Annual ized Cost
210
61
227
17
0
441
1,007
194
71
184
1,140
87
87
173
3,897
307
101
322
52
39
3,779
4,600
(702)
210
61
227
17
0
441
1,007
194
71
•
184.
1,084
82
82
165
3,825
307
101
322
52
39
3,779
4,600
(775)
210
61
227
17
0
441
1,007
194
71
184
1,073
82
82
163
3,810
307
101
322
52
39
3,779
4,600
(789)
a Totals may not add due to rounding.
b Note: For estimating the cost of plants with capacities in excess of 100 LT/D,
the costs in this table would be used as costs of individual trains. For
example, a 200 LT/D plant would consist of two 100 LT/D trains, and the costs
for the plant would be twice the costs in this table.
-------
6-11
Table 6-7
ANNUALIZED COST SUMMARY
AMINE TREATMENT WITH GLAUS
EXPANSION OF 10.16 Mg/D (10 LT/D) PLANT
(January 1985 Do!
1% H2S
Direct Operating Cost
Operating labor
Supervision
Maintenance, repairs
Supplies, laboratory
Utilities
Chemicals, catalyst
Indirect Operating Cost
Overhead (50 percent of all labor costs)
Capital Recovery (10 percent rate of return,
15 years equipment life).
Taxes (one percent of capital cost)
Insurance (one percent of capital cost)
Administration (two percent of capital cost)
Total Annual i zed Cost Without Credit
Credits
4300 Kp steam
1760 Kp steam
352 Kp steam
106 Kp steam
Steam Condensate
Sulfur
Total Credits
Net Annual i zed Cost
SULFUR RECOVERY
TO 10.668 Mg/D
lars)
10.66 Mg/D
210,000
60,900
83,000
16,800
172,300
7,268
155,300
379,600
28,870
28,870
57,740
1,200,600
-
0
100,100
0
6,601
9,767
396,800
513,268
687,330
(10.5 LT/D)
10.16 Mg/D
210,000
60,900
82,070
16,800
164,100
6,922
155,300
374,800
28,500
28,500
57,000
1,184,900
0
95,360
0
6,287
9,302
377,900
488,849
696,050
Incre-
mental
0
0
930
0
8,200
346
0
4,775
370 '
370
740
15,700
0
4,740
0
314
465
18,900
24,419
(8,720)
-------
6-12
Table 6-8
ANNUALIZED COST SUMMARY
AMINE TREATMENT WITH GLAUS "SDUFUR RECOVERY
EXPANSION OF 10.16 Mg/D (10 LT/D) PLANT TO 10.668 Mg/D (10.5 LT/D)
(January 1985 Dollars)
5% H2S
10.66 Mg/D 10.16 Mg/D Incre-
mental
Direct Operating Cost
Operating labor
Supervision
Mai ntenance , repai rs
Supplies, laboratory
Utilities
Chemicals, catalyst
Indirect Operating Cost
Overhead (50 percent of all labor costs)
Capital Recovery (10 percent rate of return,
15 years equipment life)
Taxes (one percent of capital cost)
Insurance (one percent of capital cost)
Administration (two percent of capital cost)
Total Annual i zed Cost Without Credit
Credits
4300 Kp steam
1760 Kp steam
352 Kp steam
106 Kp steam
Steam Condensate
Sulfur
Total Credits
Net Annuali zed Cost
210,000
60,900
83,000
16,800
172,300
7,268
155,300
373,850
28,430
28,430
56,860
1,193,140
0
100,100
0
6,601
9,767
396,800
513,268
679,870
210,000
60,900
82,070
16,800
164,100
6,922
155,300
369,250
28,080
28,080
56,160
. 1,177,660
0
95,360
0
6,287
9,302
377,900
488,849
688,810
0
0
930
0
8,200
346
0
4,600
350
350
700
15,480
0
4,740
0
314
465
18,900
24,419
(8,940)
-------
6-13
Table 6-9
ANNUALIZED COST SUMMARY
AMINE TREATMENT NITH CLAPS STUFUR RECOVERY
EXPANSION OF 10.16 Mg/D (10 LT/D) PLANT TO 10.668 Mg/D (10.5 LT/D)
(January 1985 Dollars)
10% H2S
10.66 Mg/D 10.16 Mg/D Incre-
mental
Direct Operating Cost
Operating labor
Supervision
Maintenance, repairs
Supplies, laboratory
Utilities
Chemicals, catalyst
Indirect Operating Cost
Overhead (50 percent of all labor costs)
Capital Recovery (10 percent rate of return,
15 years equipment life)
Taxes (one percent of capital cost)
Insurance (one percent of capital cost)
Administration (two percent of capital cost)
Total Annual i zed Cost Without Credit
Credits
4300 Kp steam
1760 Kp steam
352 Kp steam
106 Kp steam
Steam Condensate
Sulfur
Total Credits
Net Annual ized Cost
210,000
60,900
83,000
16,800
172,300
7,268
155,300
372,580
28,330
28,330
56,660
1,191,470
0
100,100
0
6,601
9,767
396,800
513,268
678,200
210,000
60,900
82,070
16,800
164,100
6,922
155,300
368,070
27,990
27,990
55,980
1,176,120
0
95,360
0
6,287
9,302
377,900
488,849
687,270
0
0
930
0
8,200
346
0
. 4,510
340
340
680
15,350
0
4,740
0
314
465
18,900
24,419
(9,070)
-------
6-14
Direct and indirect installation factors from Reference 7 were then applied
to each model plant purchased equipment cost to obtain total installed cost.
The capital costs for the four model plants are presented in Table 6-10.
6.3.2 Annualized Costs
The annualized costs for the LO-CAT® model plants have also been estimated.
Most of the direct operating costs were taken directly from Reference 3,
interpolating values from tabular data therein. Operating labor was calculated
based on one-third of a man per shift for all model plants (Reference 5), 350
days per year, and a labor rate of $15 per hour (see Table 6-2). Supervision
was figured at 15 percent of labor and maintenance labor was assumed to equal
operating labor (Reference 6). Catalyst costs, obtained from Reference 7,
were found to vary according to the method used to separate the recovered
sulfur from the catalyst solution.
Indirect costs were factored from capital costs or direct operating costs
using factors from References 6 and 8. As with the amine-Claus control system,
capital recovery is based on a 10 percent rate of return and a 15-year equip-
ment life. There are no waste disposal costs for spent catalyst, in accordance
with Reference 3. Product recovery credits for sulfur have also been calculated.
Note that because the LO-CAT® process directly produces the desulfurized refinery
fuel gas, these model plants are designed to meet (or better) the limit of 162
parts per million (ppm) H2$ in the gas. The design sulfur removal efficiencies
vary with H2S inlet concentration, with a consequent variation in sulfur
recovery. Note also that there is some question about the quality of sulfur
recovered from the LO-CAT® process. To be conservative, therefore, each
annualized cost table includes a cost for sulfur disposal, calculated at a
unit cost of $24.60 per long ton ($24.22 per Mg). The total annualized
-------
6-15
Table 6-10
CAPITAL COST SUMMARY
IP-CAT® PROCESS
(January 1985 Dollars)
Cost in Thousands of Dollars3
Plant Capacity. Mg/D (LT/D) Sulfur
Purchased equipmentb(A)
Taxes and freight(O.OSCXA)
Base Cost (B)
Direct/indirect installation
(0.50dXB)
Total Installed Cost
1.016(1)
520
£2
562
281
843
2.032(2) 5.08(5) 10.16(10)
810 1460 2380
65. 117. 190
875 1577 2570
438 789 1285
1313
2366
3855
3 Cost for each capacity applies for inlet hydrogen sulfide concentrations
of 1, 5, or 10 percent.
b Costs were developed from information in Reference 3 and include instru-
mentation.
c Reference 6 was the source of this factor.
d Overall installation factor suggested by Reference 7 for refinery installations,
-------
6-16
cost for the process is therefore bracketed between a low figure that
includes full credit and a high figure that includes the full cost of
disposal. In reality, the annualized cost would probably fall in between,
depending on the quality of the sulfur produced and the available markets
for sulfur of that quality.
The annualized costs for the model plants are presented in Tables 6-11
through 6-14.
>
6.4 COST-EFFECTIVENESS
The cost-effectiveness values are determined from the costs developed
in Sections 6.2 and 6.3 and the emission reductions presented in Chapter 5.
The cost-effectiveness values represent the estimated cost (in January 1985
dollars) that would be incurred by a refinery for each ton of S02 emissions
that is controlled.
Cost-effectiveness values for both control systems and all model plants
are shown in Tables 6-15 and 6-16, for the amine-Claus and LO-CAT® processes,
respectively. All cost-effectiveness values are based on a baseline of
zero control. For both processes, the C/E ratio increases as the model
plant size decreases.
The amine-Claus system's cost-effectiveness improves to a credit of
$10 to $12/Mg at the 101.6 Mg/D model plant size. The model plant size at
where the transition from cost to credit occurs is approximately 30 Mg/D.
(Note that because costs for the 203.2 and 508 Mg/D plants are multiples of
the cost for the 101.6 Mg/D plant, the cost-effectiveness for all plants
101.6 Mg/D and larger is exactly equal in this analysis.) Cost-effectiveness
is not a strong function of inlet H2S concentration in the range of concen-
trations examined in this analysis.
-------
6-17
Table 6-11
ANNUALI ZED COST SUMMARY a.
LO-CAT® PROCESS
1.016 Mg/D (1 LT/D) PLANT
(January 1985 Dollars)
Cost in
Thousands
of Dollars
Direct Operating Cost
Operating labor 42
Supervision 6
Maintenance labor 42
Utilities (electricity) 2
Catalysts and chemicals 64
Indirect Operating Cost
Overhead (50 percent of all labor costs) 45
Capital Recovery (10 percent rate of return, 15 years
equipment life) 111
Taxes (one percent of capital cost) . 8
Insurance (one percent of capital cost) 8
Administration (two percent of capital cost) 17
Total Annualized Cost Without Credit 346
Sulfur Credit0 38
Net Annualized Cost (With Credit) 308
Sulfur Disposal0 8
Total Annualized Cost with Disposal 355
aWith the exception of the sulfur credit and sulfur disposal cost, the costs
shown apply for inlet H2S concentration of 1,5, and 10 percent. See Note c.
^Totals may not add due to rounding.
cThe sulfur credit and disposal cost shown are for 1 percent I^S. For other
inlet H2S concentrations, the sulfur credit would be as follows: 5 percent
H2S — 39; 10 percent H2S -- 39.
H2S -- 9; 10 percent H2S -- 9.
The disposal cost would be: 5 percent
-------
6-18
Table 6-12
ANNUALIZED COST SUMMARY a,b
LO-CAT® /PROCESS
2.032 Mg/D (2 LT/D) PLANT
(January 1985 Dollars)
Cost in
Thousands
of Dollars
Direct Operating Cost
Operating labor 42
Supervision 6
Maintenance labor 42
Utilities (electricity) 3
Catalysts and chemicals 129
Indirect Operating Cost
Overhead (50 percent of all labor costs) 45
Capital Recovery (10 percent rate of return, 15 years
equipment life) 173
Taxes (one percent of capital cost) 13
Insurance (one percent of capital.cost) 13
Administration (two percent of capital cost) 26
Total Annualized Cost Without Credit 493
Sulfur Credit0 77
Net Annualized Cost (With Credit) 416
Sulfur Disposal0 17
Total Annualized Cost with Disposal 509
aWith the exception of the sulfur credit and sulfur disposal cost, the costs
shown apply for inlet H2S concentration of 1,5, and 10 percent. See Note c.
^Totals may not add due to rounding.
cThe sulfur credit and disposal cost shown are for 1 percent H2S. For other
inlet H2S concentrations, the sulfur credit would be as follows: 5 percent
H2S -- 78; 10 percent H2S -- 78.
H2S -- 17; 10 percent H2S -- 17.
The disposal cost would be: 5 percent
-------
6-19
Table 6-13
ANNUALI ZED COST SUMMARY a
LO-CAT® PROCESS
5.08 Mg/D (5 LT/D) PLANT
(January 1985 Dollars)
Cost in
Thousands
of Dollars
Direct Operating Cost
Operating labor
Supervision
Maintenance labor
Utilities (electricity)
Catalysts and chemicals
Indirect Operating Cost
Overhead (50 percent of all labor costs)
Capital Recovery (10 percent rate of return,
equipment life)
Taxes (one percent of capital cost)
Insurance (one percent of capital cost)
Administration (two percent of capital cost)
Total Annualized Cost Without Credit
Sulfur Credit0
Net Annualized Cost (With Credit)
Sulfur Disposalc
Total Annualized Cost with Disposal
15 years
42
6
42
5
142
45
311
24
24
47
688
192
496
42
731
aWith the exception of the sulfur credit and sulfur disposal cost, the costs
shown apply for inlet H2S concentration of 1,5, and 10 percent. See Note c.
^Totals may not add due to rounding.
cThe sulfur credit and disposal cost shown are for 1 percent f^S. For other
inlet H2S concentrations, the sulfur credit would be as follows: 5 percent
H2S -- 195; 10 percent t^S -- 195. The disposal cost would be: 5 percent
H2S — 43; 10 percent H2S -- 43.
-------
6-20
Table 6-14
ANNUALIZED COST SUMMARY a.b
LO-CAT® PROCESS
10.16 Mg/D (10 LT7DT PLANT
(January 1985 Dollars)
Cost in
Thousands
of Dollars
Direct Operating Cost
Operating labor 42
Supervision 6
Maintenance labor 42
Utilities (electricity) 7
Catalysts and chemicals " 284
Indirect Operating Cost
Overhead (50 percent of all labor costs) 45
Capital Recovery (10 percent rate of return, 15 years
equipment life) 507
Taxes (one percent of capital cost) 39
Insurance (one percent of capital cost) 39
Administration (two percent of capital cost) 77
Total Annualized Cost Without Credit 1088
Sulfur Credit0 . 385
Net Annualized Cost (With Credit) 703
Sulfur Disposal0 85
Total Annualized Cost with Disposal 1172
aWith the exception of the sulfur credit and sulfur disposal cost, the costs
shown apply for inlet H2S concentration of 1,5, and 10 percent. See Note c.
bTotals may not add due to rounding.
cThe sulfur credit and disposal cost shown are for 1 percent l^S. For other
inlet H2S concentrations, the sulfur credit would be as follows: 5 percent
H2S — 390; 10 percent F^S -- 391. The disposal cost would be: 5 percent
-- 86; 10 percent f^S -- 86.
-------
6-21
Table 6-15
COST EFFECTIVENESS
SULFUR DIOXIDE CONTROL
AHINE TREATMENT WITH GLAUS SULFUR RECOVERY^
(January 1985 Dollars)
Annualized
Plant Size Cost (Credit)
et Concentration Mg/day (LT/D) SlO^/yr Mg/yr
H2S
H2S
j
% H2S
5.08 (5)
10.16 (10)
50.8 (50)
101.6 (100)
0.51 (0.50)b
5.08 (5)
10.16 (10)
50.8 (50)
101.6 (100)
0.51 (0.50)b
5.08 (5.)
10.16 (10)
50.8 (50)
101.6 (100)
0.51 (0.50)b
762
695
(11)
(702)
(8.7)
759
688
(47)
(7.75)
(8.9)
758
686
(55)
(789)
(9.1)
3,435
6,870
34,350
68,700
344
3,435
6,870
34,350
68,700
344
3,435
6,870
34,350
68,700
344
S02 Removed
tons/yr $/Mg
3,787
7,573
37,867
75,734
379
3,787
7,573
37,867
75,734
379
3,787
7,573
37,867
75,734
379
222
101
(0.32)
(10.2)
(25.3)
221
100
(1.37)
(11.3)
(26.0)
221
100
(1.60)
(11.5)
(26.4)
C/E
$/ton
201
92
(0.29)
(9.3)
(23.0)
200
91
(1.24)
(10.2.)
(23.6)
200
91
(1.45)
(10.4)
(23.9)
The cost-effectiveness ratios for 200 LT/D and 500 LT/D plants would be the same as
shown for 100 LT/D, in that the annualized costs for these plants are multiples of the
100 LT/D costs in this analysis. However, if large plants were to be custom-designed,
their C/E ratios would be expected to be lower, reflecting economies of scale in the
capital costs.
Expansion case (10.16 to 10.668 Mg/D). All
between the base and expansion capacities.
values shown on these lines are incremental
-------
6-22
Table 6-16
COST EFFECTIVENESS
SULFUR DIOXIDE CONTROL
LO-CAT® PROCESS
(January 1985 Dollars)
Inlet Concentration
1% H2S
5% H2S
10% H2S
Plant Size
Mg/D (LT/D)
1.016 (1)
2.032 (2)
5.08 (5)
10.16 (10)
1.016 (1)
2.032 (2)
5.08 (5)
10.16 (10)
1.016 (1)
2.032 (2)
5.08 (5)
10.16 (10)
Sulfur
Status
recovered
disposed
recovered
disposed
recovered
disposed
recovered
disposed
recovered
disposed
recovered
disposed
recovered
disposed
recovered
disposed
recovered
disposed
recovered
disposed
recovered
disposed
recovered
disposed
*For the special case where neither a sulfur
Annual i zed
Cost (Credit)
$lo3/yr*
308
355
416
509
496
731
703
1,172
308
355
415
509
493
732
698
1,173
308
355
415
509
493
732
697
1,173
recovery credi
S02
Mg/yr
700
700
1,399
1,399
3,499
3,499
6,997
6,997
709
709
1,418
1,418
3,545
3,545
7,090
7,090
710
710
1,420
1,420
3,551
3,551
7,101
7,101
t nor a
Removed
tons/yr
771
771
1,543
1,543
3,856
3,856
7,713
7,713
781
781
1,563
1,563
3,907
3,907
7,815
7,815
783
783
1,565
1,565
3,914
3,914
7,827
7,827
disposal cost
$/Mg
440
507
297
364
142
209
100
168
434
501
293
359
139
206
98
165
434
500
292
358
139
206
98
165
were
C/E
$/t
39
46
27
33
12
18
9
15
39
45
26
32
12
18
8
15
39
45
26
32
12
18
8
15
taken
the annualized cost would be found in Table 6-11, -12, -13, or -14. The cost-effective-
ness would then be the quotient of this cost (the "Total Annualized Cost Without Credit")
and the "S02 Removed" value in column 5.
-------
6-23
The most interesting aspect of Tables 6-15 and 6-16 is the comparison of
cost-effectiveness between the two control systems at the common model plant
sizes--5.08 and 10.16 Mg/D. At the 10.16 Mg/D size, the cost-effectiveness
ratios of the amine-Claus and LO-CAT® systems (sulfur recovery case) are
essentially equal. But as the model plant size decreases to 5.08 Mg/D,
the amine-Claus system becomes less cost-effective than the LO-CAT® system
(sulfur recovery case). This indicates that for these lower sulfur loadings,
the LO-CAT® would be the preferred control system to use.
6.5 COST COMPARISON
To determine their representativeness, the capital costs plus the operating
and the maintenance (O&M) costs in Sections 6.2 and 6.3 were compared to cost
data obtained from refineries that responded to Section 114 letter requests.
Of the 13 plants covered in these 114 responses, seven contained enough cost/
process data to allow meaningful comparisons. Because some of the respondents
requested their cost data to be held confidential, no specific results
are shown herein. However, some general information about the cost comparisons
can be provided:
o After escalating all costs to January 1985 dollars, costs were
compared for seven amine treating units (ATU's), one LO-CAT®
system, and one combination ATU-CLAUS system. (Note: some
refineries provided data on more than one system.)
o All but one of the capital cost sets differed by less than +_ 50%,
the nominal accuracy of the total installed costs in the chapter.
o Larger discrepancies were seen in the O&M costs, due to differences
in unit prices, cost allocations, accounting methods, and other
factors. In all but one case, the O&M costs in the chapter were
higher than the respondents'.
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6-24
o Details of the cost comparison have been placed in the confidential
portion of the project docket.
6.6 REFERENCES FOR CHAPTER 6
1. Shumaker, Jeffrey L., Memorandum to Docket A-80-20A, dated September 11,
1984, concerning sweetening plant cost factors.
2. Review of New Source Performance Standards for Petroleum Refinery Glaus
Sulfur Recovery Plants, U.S. Environmental Protection Agency, EPA-450/
3-83-014, August 1983.
3. Hardison, L.C., "Minimizing Gas Treating Costs with LO-CAT® for
Removal", for presentation at the Panhandle Plains Regional Meeting of
the Gas Processors Association, Amarillo, TX, October 11, 1984.
4. Hardison, L.C., "Go from H2$ to S in One Unit", Hydrocarbon Processing,
April 1985, pp. 70-71.
5. Telecons—Thomas Beggs (JACA Corporation, Fort Washington, PA) with
Mr. L.C. Hardison (President, ARI Technologies, Inc., Palatine, IL):
April 1, 1985; May 21, 1985; and June 10, 1985.
6. Vatavuk, William M. and Neveril, Robert B., "Estimating' Ai r-Pollution Control
Costs—Part II: Estimating Capital and Operating Costs," Chemical Engineering,
November 3, 1980, pp. 157-162.
7. Letter from L. C. Hardison (ARI Technologies, Inc., Palatine, IL) to W.
L. Elmore (U.S. Environmental Protection Agency, Research Triangle Park, NC),
February 26, 1986.
8. Peters, M.S. and Timmerhaus, K.D., Plant Design and Economics for Chemical
Engineers, Third Edition. McGraw-Hill, New York, NY, 1980, pp. 203-209.
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APPENDIX A
Listed below are the cost factors that were obtained or derived from
Reference 1 and used in estimating capital and annual i zed costs for the
amine treating process.
Component Cost Factor
Capital cost (10% H2S) $0.51 per standard c,ubic feet
per day (SCFD) of acid gas*
Capital cost (1% H2S or 5% H2S)
Operating labor (including some
maintenance
0.9 (cap. cost at 10%)
+0.1 (cap. cost of 10%)j~ 10 ~l°'6
conc
$126,000 per year
Maintenance
$0.01 per year per SCFO acid gas
Utilities (heat and electricity)
$0.274 per year per SCFD acid gas
Chemicals
$0.0187 per year per SCFD acid gas
The acid gas flowrate is related to the sulfur loading, as follows:
Flowrate (SCFD) = 33,160 x S
where: S = sulfur fed to amine treater (LT/D)
Via this equation, the above factors may be rewritten in terms of the sulfur
loading.
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APPENDIX B
This section presents three examples of line item annualized costs for
the control systems analyzed. The model plant used for illustration is the
5.08 Mg/D (5 LT/D) plant with an inlet concentration of one percent
The examples are shown in Tables B-l, B-2, and B-3.
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B-2
Table B-l
LINE ITEM ANNUALIZED COST EXAMPLES
AMINE TREATMENT, 5 LT/D, 1% H?S
(January 1985 -Dollars)
Di rect
Operating labor&
Supervision
Maintenance
Utilities
Chemicals
Indi rect
Overhead
Capital recovery
Taxes
Insurance
Administration '
(direct from Reference 1) $126,000
15% of above: $126,000 x 0.15 18,900
$0.01 per SCFD: 165,800 x 0.01 1,658
$0.274 per SCFD: 165,800 x 0.274 45,429
$0.0187 per SCFD: 165,800 x 0.0187 3,100
50% of labor: (126,000 + 18,900) x 0.50 72,450
CRF (10 percent, 15 years) = 0.1315:
$109,925 x 0.1315 14,455
1 percent of capital cost:
$109,925 x 0.01 . 1,099
1 percent of capital cost:
$109,925 x 0.01 1,099
2 percent of capital cost:
$109,925 x 0.02 2,199
$286,389
a Direct factors from Reference 1. (See Appendix A).
b Includes an unspecified amount of maintenance labor.
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B-3
Table B-2
LINE ITEM ANNUALIZED COST EXAMPLES
CLAUS
Di rect
'Operating Labor
/
Supervision
Maintenance, repai
Supplies, lab
4300 Kp steam
Boiler feedwater
Electricity
Fuel gas
Catalyst
Indi rect
Overhead
Capital recovery
Taxes
Insurance
SULFUR RECOVERY PLANT 5 LT/D, 1% H?S
(January 1985 Dollars)
5600 hours x $15
year hour
2100 hours x $20
year hour
r13 3 percent of capital cost:
$2,285,000 X 0.03
20 percent of operating labor:
$84,000 X 0.20
200 Mq x $17.50
Year • Mg
3267 Mg_ X $3-60
Year Mg
764 Gj x $15.28
Year Gj
' 2423 Gj x $4
Year Gj
$655 * 5 LT/D * ,.,
10 LT/D
50 percent of labor:
0.50 X (84,000 + 42,000 + 0.5 X
CRF (10 percent, 15 years) =
0.1315: $2,285,000 X 0.1315
1 percent of capital cost:
$2,285,000 X 0.01
1 percent of capital cost:
$84,000
42,000
68,550
16,800
3,500
11,760
11,670.
9,690
361
80,138
68,550)
300,478
22,850
22,850
$2,285,000 X 0.01
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B-4
Table B-2 (cont'd)
Indirect (cont'd)
Administration 2 percent of capital cost: 45,700
$2,285,000 X 0.02
Total Annualized Cost w/o Credit 720,347
Credits
1760 Kp steam 2934 Mg x $16.25 47,680
year Mg
106 Kp steam 286 Hg x $11.00 3,144
year Mg
Steam condensate 1550 Mg x $3.00 4,651
year Mg
Sulfur •' 5.08 Mg x 0.966 recovery x 350 days y $110 188,930
day year Mg
Total Credits 244,405
NET ANNUALIZED COST . $475,942
a Consumption figures derived from cost data in Reference 2.
b Assumed to be equal parts labor and materials.
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B-5
Table B-3
LINE ITEM ANNUALIZED COST EXAMPLES
LO-CAT® PROCESS. 5 LT/D, 1% HgS
Direct
Operating Labor
Supervision
Maintenance labor
Utilities6
Catalysts and
Chemicals'3
Indirect
Overhead
Capital recovery
Taxes
Insurance
Administration
8 hours x 350 days x $15
day year hour
15% of above: $43,000 X 0.15
Same as operating
$2.70
5 LT
day
$81.20 x 5 LT
LT day
350 days
year
( 350 days
year
50 percent of labor:
(42,000 + 6,300 + 42,000) X 0.50
CRF (10 percent, 15 years) =
0.1315: $2,366,000 X 0.1315
1 percent of capital cost:
$2,366,000 X 0.01
1 percent of capital cost:
$2,366,000 x 0.01
2 percent of capital cost:
$2,366,000 X 0.02
Total Annual ized Cost w/o Credit
Sulfur Credit
5.08 Mg x 0-9838 recovery x 350 days
day year
$110
Mg
NET ANNUALIZED COST (WITH CREDIT)
Sulfur Disposal 5.08 Mg x 0.9838 recovery x 350 days x $24.22
day year Mg
TOTAL ANNUALIZED COST WITH DISPOSAL
$42,000
6,300
42,000
4,725
142,100
45,200
311,100
23,700
23,700
47,300
688,100
192,400
$495,700
42,400
$730,500
In most cases, unit consumption data were taken from References 3, 4,
and 5.
Unit costs for utilities and catalysts are not the same for all plant sizes,
as the quantities required of steam, electricity, catalyst, etc., vary
nonlinearly with capacity.
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
. REPORT NO.
EPA-450/3-86-011
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Review of New Source Performance Standards
for Petroleum Refinery Fuel Gas
5. REPORT DATE
October 1986
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
. PERFORMING ORGANIZATION NAME AND ADDRESS
Office of Air Quality Planning and Standards
Environmental Protection Agency
Research Triangle Park, NC 27711
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
12. SPONSORING AGENCY NAME AND ADDRESS
DAA for Air Quality Planning & Standards
Office of Air and Radiation
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
EPA 200/04
15. SUPPLEMENTARY NOTES
16. ABSTRACT
As required by Section lll(b) of the Clean Air Act, as amended, a four
year review of the new source performance standards for petroleum refineries
(40 CFR Subpart J) was conducted. This review was limited to the sulfur dioxide
standard as applied to refinery fuel gas. The report presents a summary of the
current standard, the status of current applicable control technology, and the
ability of plants to meet the standard. No revision to the standard is recommended;
however, EPA should investigate an alternative method of continuously measuring
the sulfur concentration of refinery fuel gas.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Petroleum Industry
Hydrogen Sulfide
Standards of Performance
Pollution Control
Air Pollution Control
13B
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
20. SECURITY CLASS (Thispage)
Unclassified
-Bl.
22. PRICE
EPA Form 2220-1 (R«v. 4-77) PREVIOUS EDITION is OBSOLETE
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