U.S. Environmental Protection Agency Industrial Environmental Research     EPA~600/7-77-081
Office of Researcn and Development Laboratory
               Research Triangle Park, North Carolina 27711 AllQUSt 1977
       PROCESS TECHNOLOGY
       BACKGROUND
       FOR ENVIRONMENTAL
       ASSESSMENT/SYSTEMS ANALYSIS
       UTILIZING RESIDUAL FUEL OIL
       Interagency
       Energy-Environment
       Research and Development
       Program Report

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                       RESEARCH REPORTING SERIES
Research reports of the Office of Research and  Development, U.S.
Environmental Protection Agency,  have been grouped  into seven series.
These seven broad categories were established to  facilitate further
development and application of environmental technology.  Elimination
of  traditional grouping was consciously planned to  foster technology
transfer and a maximum interface  in related fields.  The seven series
are:

     1.  Environmental Health Effects Research
     2.  Environmental Protection Technology
     3.  Ecological Research
     4.  Environmental Monitoring
     5.  Socioeconomic Environmental Studies
     6.  Scientific and Technical Assessment Reports (STAR)
     7.  Interagency Energy-Environment Research  and Development

This report has been assigned to  the INTERAGENCY  ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series.   Reports  in this series result from
the effort funded under the 17-agehcy Federal Energy/Environment
Research and Development Program.  These studies  relate to EPA's
mission to protect the public health and welfare  from adverse effects
of pollutants associated with energy systems.   The  goal of the Program
is to assure the rapid development of domestic  energy supplies in an
environmentally—compatible manner by providing the necessary
environmental data and control technology. Investigations include
analyses of the transport of energy-related pollutants and their health
and ecological effects; assessments of,  and development of, control
technologies for energy systems;  and integrated assessments of a wide
range of energy-related environmental issues.

                            REVIEW NOTICE

This report has been reviewed by the participating Federal
Agencies, and approved for publication.  Approval does not
signify that the contents necessarily reflect the views and
policies of the Government, nor  does mention  of trade names
or commercial products constitute endorsement or recommen-
dation for use.
This document is available to the public through the  National Technical
Information Service, Springfield, Virginia  22161.

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                                     EPA-600/7-77-081
                                         August 1977
PROCESS TECHNOLOGY BACKGROUND
           FOR ENVIRONMENTAL
   ASSESSMENT/SYSTEMS ANALYSIS
      UTILIZING RESIDUAL FUEL OIL
                         by

                    M.F. Tyndall, R.C. Foster,
                    E.K. Jones, and F.D. Kodras

                      Catalytic, Inc.
                   Highway 51 and Johnston Road
                   Charlotte, North Carolina 28210
                    Contract No. 68-02-2155
                   Program Element No. EHE623A
                  EPA Project Officer: Samuel L Rakes

                Industrial Environmental Research Laboratory
                 Office of Energy, Minerals, and Industry
                  Research Triangle Park, N. C. 27711
                       Prepared for

                U.S. ENVIRONMENTAL PROTECTION AGENCY
                  Office of Research and Development
                    Washington, O.C. 20460

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                                  CONTENTS






Figures	iii




Tables	±v




Abbreviations and Symbols	   v




     1.  Executive Summary	    1




     2.  Introduction	   4




     3.  Annual Summary of Environmental Assessment by Task	   6




     4.  Residual Oil Gasification Process	11




     5.  Direct Hydrodesulfurization	30




     6.  Flue Gas Desulfurization	40




     7.  Conclusions	64




Glossary	68
                                    ii

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                                  FIGURES






Number                                                                  Pag




  1      Environmental assessment diagram 	   9



  2      Shell Gasification Process 	  15




  3      Shell Closed Carbon Recovery System	  16




  4      Selexol H~S removal process	17




  5      Straight through GLAUS process 	  18




  6      Shell Glaus Off-Gas Treating (SCOT) process	19




  7      Typical residual oil gasification unit (POX)  	  21




  8      Typical gasification cleanup unit for (POX)... 	  22




  9      Direct hydrodesulfurization unit operations	33




 10      HDS entering and exiting streams	- . . . .  34




 11      Material balance for Shell HDS unit	35




 12      Double alkali process - ammonia absorbent	45




 13      Dowa Al_(SO,)  • Al-O  absorbent - double alkali process ...  46




 14      Limestone slurry scrubbing throwaway process  	  47




 15      Test run on FGD unit using MgO	50




 16      Double alkali process - sodium acetate-absorbent 	  58




 17      Sulfur dioxide reduction trends in Japan 	  59
                                    iii

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                                   TABLES


Number                                                                    Page

   1      Description of Flow from Figures 7 & 8	   23

   2      Summary of Potential Pollutants	   24

   3      Typical Feed and Products	   25

   4      Weight Balance for Process (Air Oxidant) 	   26

   5      Energy Balance for Process (Air Oxidant) 	   27

   6      Potential Pollutant Streams	   28

   7      Total Costs of Producing 2.35 x 109 BTU/HR (LEV) of
             Product Gas	   29

   8      Commercial Direct HDS Facilities	   31

   9      Tail-Gas Treatment on Commercial Units 	   38

  10      Major Wet-Type Flue Gas Desulfurization Processes	   43

  11      Development of Commercial FGD Processes	   44

  12      Wastewater from FGD Plants	   52

  13      Comparison of Design and Operating Parameters Versus
             Performance	54-55

  14      Environmental Pollutant Control Capabilities of Residual
             Oil-Fired Boiler Flue Gas Cleaning Processes. . . 	   57

  15      Ambient Air Quality Standards	   60

  16      NO  Emission Standard (ppm)	   61
            jC
  17      Plant Cost in Battery Limits	   62

  18      FGD Cost by Wet-Lime Gypsum Process in Japan (1975$)	   63

  19      U. S. Battery Limits Capital Investment and Annual Costs ...   64


                                      iv

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                      LIST OF ABBREVIATIONS AND SYMBOLS
CW          — cooling water
HDS         — hydrodesulfurization
POX         — partial oxidation
CAFB        — chemically active fluid bed
FGD         — flue gas desulfurization
ROSE        — residual oil solvent extraction
Btu         — British thermal units
            — standard cubic feet
SCFM        — standard cubic feet per minute (60 F, 1 atm.)
SCFMD       — standard cubic feet per minute - dry basis
HHV         — higher heating value
LHV         — lower heating value
LSFO        — low sulfur fuel oil
DOP         — Universal Oil Products
ppm         — parts per million
ppm(v)      — parts per million by volume
GR          — grains
NSPS        — new source performance standard
Eff.        — efficiency
T/hr.       — metric tons per hour
L/G         — liquid/ gas ratio
Nm^/hr.     — normal cubic meters /hour
KW          — kilowatts
MW          — megawatts
SV          — space velocity
SS          — suspended solids
bbl.        — barrels (42 U.S. gallons)

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                                 SECTION 1
                             EXECUTIVE SUMMARY

OBJECTIVE
     The objective of the work reported here is to execute an environmental
assessment from a systems analysis of the present commercially operating pro-
cesses capable of using residual fuel oil to generate electricity.  Tiie pro-
cesses under study include:
     1.  Pretreatment - Hydrodesulfurization (HDS) processing
         removes sulfur and other pollutants from fuel oil
         prior to combustion.
     2.  Conversion - Partial oxidation (POX) and chemically
         active fluidized bed (CAFB) processing convert resi-
         dual fuel to an environmentally acceptable gas, which
         can be used directly or in a combined cycle system.
     3.  Post-treatment - Flue gas desulfurization (FGD) tech-
         niques remove pollutants by cleaning the tail-gas
         from conventional boiler combustion.
RESULTS OVERVIEW
    The status of the environmental assessment project is presented in this
report, where all existing data has been compiled on residual fuel oil pro-
cesses.  An intensive study of three major control processes was required for
the assessment of present commercial technology.
     The information obtained on the processes was reviewed for a detailed.
engineering and cost analysis.  At the present time, several economic studies
are being conducted for commercial partial oxidation schemes.  Five FGD sys-
tems and four HDS processes have been reviewed.  A study of the combined cy-
cle units has been started and is oeing continued.  The commercial status of

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the processes under study shows that there are numerous units now in operation
having significant capacities and operating experience.
     The emissions of representative commercial HDS, FGD, and POX units were
identified and characterized.  Each process was analyzed in terms of basic
unit operations.  An overall material balance was then made for typical feed
to determine the quantity of each emission based on the feed and pollutant ele-
ment under consideration.  From the material balance, each pollutant could be
followed through the process to its final form and point of environmental impact.
     Residual fuel oil contains hydrocarbons and certain contaminants such as
sulfur, ash, and metals.  These contaminants can be potential pollution prob-
lems as they are transferred in different forms to the media from each of the
processes.
     Sulfur data is well defined on all H-S and S0_ removal processes.  How-
ever, very little data is available on other potential pollutants including
vanadium, nickel, NO , ash,  particulates, carcinogens, etc.  All important
                    X
emission levels from the process units have been calculated; however, it will
be necessary to analyze samples from various cleanup processes in order to
determine present and future emission levels.  No problems are anticipated
with excess pollution from sulfur in the effluent gas from these processes.
     Investment costs and operating requirements have been used to estimate
the control costs and efficiencies.  Data collected on the trip to Japan were
helpful in making these estimates and in obtaining missing information on com-
mercial HDS, POX, and FGD processes.  Secrecy agreements have been entered
into with several major companies to assist in developing this information.
Some missing information still exists in the area of treatment and final dis-
posal of some effluent streams, which contain important pollutants such as
metals, carbon, ash, etc.  Further plant visits will be required to obtain
samples of these streams.  Samples from plants will be analyzed to determine
the potential pollution products.   The necessity of a sampling program for
each process is  unquestionable.  An order of magnitude estimate by engineering
calculation would perhaps suffice in some cases; however, emission data is
required through sampling to complete the environmental assessment.

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CONCLUSIONS
     It is concluded that each process under study is established as an eco-
nomically acceptable unit by operating experience on a. commercial scale.  The
flexibility of each process has been demonstrated by a proven acceptance of
variable feedstocks within certain design limits.
     Contaminates such as sulfur, nickel, and vanadium are successfully remov-
ed from the fuel and in some cases may be used for the production of saleable
byproducts.  Additional process equipment is required in most cases to upgrade
byproducts to a final form.  At least eighty to ninety percent removal effi-
ciencies have been demonstrated for most contaminants.  Sulfur removal effi-
ciencies of 95 to 99% are common in FGD processes.
     The capital and operating cost estimates indicate that the price for
these processes is high for the U.S.A. presently.  The process cost is very
sensitive to feed composition.  It should become more economical in the future
to charge heavier lower-priced feeds into the POX process, middle-range feeds
into the HDS process, and low sulfur fuel oils for the FGD units.

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                                   SECTION 2
                                 INTRODUCTION

     In May, 1976, Catalytic, Inc. began environmental and economic assessments
of methods utilizing or those capable of utilizing residual oil to produce
electricity.  The methods were classified by state of development into one of
three phases of work.
     Phase I:    Processes, such as hydrodesulfurization (HDS),
                 flue gas desulfurization (FGD)  and partial
                 oxidation (POX), which are operating or in
                 commercial design.
     Phase II:   Processes, such as Chemically Active Fluidized
                 Bed (CAFB),  which are in the demonstration
                 plant design but have a good chance of becoming
                 commercially feasible during the three years of
                 the contract.
     Phase III:  Processes, such as residual oil solvent extrac-
                 tion (ROSE), which are in the pilot plant phase
                 of development.
     The effort during this first year (May, 1976 - May, 1977)  has been the
assessment of the Phase I processes.  This report presents the information ob-
tained, status, conclusions and recommendations  for the three Phase I process-
es:  HDS, FGD and POX.  We have, however, begun preparation of the work plan
for the Phase II assessment of CAFB.
     Descriptions of the partial oxidation, hydrodesulfurization, and flue gas
desulfurization processes appear in Sections 4,  5 and 6, respectively.  Since
HDS and FGD are commercial and operating, the emphasis in each of these sec-
tions is on the presentation and discussion of information obtained on the
units we have visited.

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     As part of the contract, a work plan describing six major task areas was
prepared.  A discussion of the work performed and status for each of these
tasks appears in Section 3.  Also included in Section 3 is a summary of how
the process technology background reported here fits into the environmental
assessment procedures.
     Based on the information we have obtained and an evaluation of progress
made, conclusions may be drawn as to the environmental acceptability of
each process based on reported actual performance testing, calculations, and
sound engineering judgement.  These results were compared with all existing
New Source Performance Standards (NSPS) as applied to utility boilers burning
liquid fossil fuels.
     The recommended steps necessary to complete the assessment are included
in the environmental assessment methodology.

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                                 SECTION 3
            ANNUAL SUMMARY OF ENVIRONMENTAL ASSESSMENT BY TASK

Task 2.0:  Review and Analysis of Environmental, Engineering and Cost Data
     During the past year, information has been obtained on the processes for
environmentally acceptable residual fuel oil utilization.  The information
was reviewed for environmental data and for engineering and cost analysis.
An intensive study of the three major processes -•FGD, HDS, POX - was begun,
and data obtained on these processes in operating Japanese plants were ana-
lyzed.  At the present time, several economic studies are being conducted for
commercial partial oxidation schemes; five FGD systems and four HDS processes
are being reviewed.  A study of the combined cycle units has been started and
is being continued.
Task 3.0:  Identification of Important Pollutants and Projection of Attain-
           able Emission Levels
     The objective of the Phase I program is to identify and characterize the
emissions of representative commercial HDS, FGD, and partial oxidation units.
The goal of this preliminary environmental assessment is to determine the
environmental adequacy of these processes.  The first step in the assessment
procedure was to analyze the residual fuel oil utilization processes in terms
of basic unit operation.  This analysis was begun for POX, FGD, and HDS.   The
next step included the identification and characterization of effluent
streams for each of the various HDS, POX, and FGD processes.  Areas of poten-
tial concern have also been identified.  To determine the pollutant loadings
in the effluent streams, a typical overall material balance has been made for
each process.  After additional studies are completed, an estimate of the
control efficiency will be considered as a function of costs and process
operating conditions.  Data collected on the trip to Japan have been analyzed
and tabulated on a material balance sheet.  A tabulation of investment costs

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and operating requirements has been prepared and will be used to estimate con-
trol costs and efficiencies.
Task 4.0:  Identification of Missing Information and Design of Program to
           Develop Such Information
     During the past year, our efforts have been concentrated on obtaining
missing information on commercial HDS, POX, and FGD processes.  In order to
obtain this information, secrecy agreements have been entered into with sev-
eral major companies, and visits have been made to various FGD, HDS,  and POX
operating units.  A trip to Japan was also made for the purpose of obtaining
process, cost, and environmental data on commercial HDS, POX, and FGD pro-
cesses.  The results of the survey taken in Japan indicate several areas in
which additional data on commercial scale FGD systems is needed before a re-
liable, complete environmental analysis can be given.  A test program to ob-
tain the missing information must be designed and planned in detail with the
guidance and approval of the Task Officer.
Task 5.0:  Design and Execution of Source, Fugitive and Ambient Measurement
           Program
     Based on the analysis of the results of our trip to Japan, a sampling
program will be designed, using the best available information, to obtain
emission data required to complete the environmental assessment.  A comprehen-
sive breadth and depth in scope of work and definition of total effort requires
the guidance and approval of the Task Officer.  The necessity of the sampling
program is unquestionable; however, a + 25% order of magnitude of error in
estimating by engineering calculations may suffice for filling in data gaps.
Task 6.0:  General Program Support
     An information storage and retrieval system was developed and put into
full operation in August, 1976.  In the past year, Catalytic, Inc. has pro-
vided technical assistance to Beard Engineering, Inc.  A visit was made to
Baton Rouge, La. to discuss monitoring and sampling requirements for a POX
combined plant being designed for the Louisiana Municipal Power Commission,
and a trip report was prepared detailing the results of the visit.  A report
was also prepared presenting the results of the Japanese trip, the sources of
information and a brief description of the information obtained.

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Status of Environmental Assessment Program on Residual Oil Utilization
     A depiction of the methodology of functions and relationships in the en-
vironmental assessment process was given in. reference EPA documents "IERL-RTP
Environmental Assessment Guideline Document, First Edition" dated March, 1976,
and the draft by R. P. Hangebrauck dated May 11, 1977, for Energy Assessment
and Control Division Programs (Figure 1).   The environmental assessment (EA)
strategy is divided into several steps.' The status of these steps for the
residual oil utilization study follows:
Current Environmental and Process Technology Background--
     Identification of current residual oil processes and their environmental
backgrounds has included a study of process flowsheets, status and schedules;
identification of possible emission sources within the process; projection of
possible emissions by means of theoretical calculations and engineering con-
sideration; listing of potential pollutants; collection of health/ecological
effects, transformation/transport, and related information for potential pol-
lutants.  This information has been gathered, analyzed, and tabulated for the
energy consumption, economical merit, and environmental acceptability.  Most
of the emission loadings to all media have'been defined for comparison with
CAFB and with any other new residual oil processes entering the commercial or
demonstration stages; however, information concerning health, ecological ef-
fects and transformation/transport at ambient conditions has been delayed by
other contractors.
Environmental Objectives Development—
     Development of environmental objectives based ultimately on health and
ecological effects of possible pollutants  and expressing the goals in terms
of acceptable emissions has severe built-in delays.  Pollutants are priori-
tized based upon partially available effects.  The goals depend upon health
and ecological effects rather than the process.  The cause of delays in this
step is ascribable to the incompleted draft Multi-media Environmental Goals
(MEG) charts that list approximately 200 substances.  The MEG charts targeted
for June, 1977, have been delayed considerably.

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                                                                   CONTROL TECHNOLOGY
                                                                   DEVELOPMENT

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Environmental Data Acquisition—•
     Comprehensive analyses of emissions from existing commercial facilities
require further sampling and analysis.  A staged analytical approach will
determine, in the most cost effective manner, which of the potential pollu-
tants are being emitted and at what levels.  All Level I sampling criteria
was not completed during this first year of effort, but some preliminary
guidelines will be followed for gathering data from some of the residual pro-
cesses.  The bioassay criteria and protocol need to be established this coming
year.
Control Technology Assessment—
     Assessment of available control technology, including identification of
specific control technologies, evaluation of the cost of alternative degrees
of control, and a preliminary assessment of the environmental impact of the
control process have been completed.  Best available technology was evaluated
for Flue Gas Desulfurization (FGD), hydrodesulfurization (HDS) and partial
oxidation (POX) combine cycle systems.  The nitrogen oxide scrubbing or the
flue gas denitrification is still in the developmental stages.  This technol-
ogy may be commercially applied in a few years for an economic and environ-
mental assessment.  It is possible, when sampling in Japan, that a residual
oil-fired utility boiler may be available for our performance tests and anal-
ysis next year.  The final disposal of HDS catalysts may be investigated
at this same time.
Environmental A3 ternatives Analysis—
     Analysis of environmental alternatives have been initiated for FGD, HDS
and POX to identify the optimum combination of control devices for all pollu-
tants and process streams considering the trade-offs between cost and degree
of control.  Using the Source Analysis Model (SAM)/IA - for Rapid Screening,
the FGD, HDS and POX control options were applied to a residual oil-fired
utility power plant (75 to 500MW).  The SAM/IA technique is aimed at determin-
ing which option FGD, HDS or POX is most environmentally effective and at
defining the problem pollutants in terms of relative degree of hazard.  Best
commercially available control technology will be defined using NSPS existing
standards for liquid fossil fuel power plants.
                                     10

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                                 SECTION 4
                  RESIDUAL OIL GASIFICATION PROCESS (POX)

DESCRIPTION 01 PROCESS
     Over 100 commercial Partial Oxidation Reactors are  now  in successful opera-
tion around the world.  Over half of these are charging Residual Fuel Oil
with many others on Crude Oil.  Others operate on light oil, naphtha and nat-
ural gas.

     At the present time, there is only one commercial unit in the Continen-
tal United States.  This unit charges Residual Fuel Oil and produces hydro-
gen.  Another unit is operating on mixed feeds in Puerto Rico, and a Lurgi
unit is operating on naphtha in Hawaii.   Three additional units  are planned for
completion in the near future.
     Essentially, any residual fuel oil or lighter hydrocarbon can be charg-
ed.  The residual fuel oil is partially oxidized to form a gaseous mixture
of carbon monoxide (CO) and hydrogen (HO with a small amount of methane
(CH,).  Either oxygen (0_) or air (0- + NO can be used for the partial oxi-
dation.  Some carbon dioxide (CO-) and carbon soot (C) are formed as by-pro-
ducts.  When air is used, the nitrogen remains in the gas product.  When oxy-
gen is used, the peak temperatures are usually controlled by a dilutant such
as steam or carbon dioxide.  Carbon soot is produced as a result of incom-
plete combustion.
     Residual fuel oil contains hydrocarbons and certain contaminants such
as sulfur^(S), nitrogen (N), ash, and various metals, which are mainly so-
dium (Na),  vanadium (V) and nickel (Ni).  The sodium is usually reduced to a
sufficiently low level by crude oil desalting before the residue is fed to
the reactor.  Excessive sodium could damage the reactor lining.  Some of the
ash components, including vanadium and nickel compounds, along with some
                                     11

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hydrogen cyanide (HCN), ammonia (NH,) and any formic acid (HCO^H) formed, are
removed from the product gas in a water scrubber, since they are either solu-
ble or suspended in water.  The carbon soot remains in suspension in the water
and can be removed by naphtha extraction or other recovery methods.  The soot
may then be recycled to the reactor for further reaction.  Some ash is removed
from the reactor as friable slag during shutdown for inspection.  The sulfur
products are only slightly soluble in water- and therefore remain in the product
gas stream as hydrogen sulfide (H~S), with some carbonyl sulfide (COS) and a
trace of carbon disulfide (CS2).
     Several commercial processes are available for removal of up to 99+ per-
cent of the H»S from the product gas.  Some processes selectively remove the
H-S, leaving much of the CO- in the gas.  The CO- is desirable when using the
gas as fuel to a gas turbine.  By removal of much of the CO ,  using other
absorbents, the product gas will have a higher Btu content.
     The desulfurized product gas with essentially all the CO™ removed will
have a Btu value of 320 to 325 Btu/SCF,HHV when 0. is used for the oxidation.
By comparison,  the product from air oxidation will have a Btu value of 120 to
125 Btu/SCF,HHV because of the nitrogen remaining in the gas.   Because 02 is
more costly than air, the product gas from 0« partial oxidation is more costly
per MM Btu produced.
DESCRIPTION OF EQUIPMENT
Salt Removal.  If residual fuel oil has been transported by ship, rail or
truck, a chance of  contamination by salt water always exists.  The salt  con-
tent should be reduced to 10 pounds or less per 1,000 barrels  of oil in order
to prevent damage to the reactor lining.  Water washing, followed by electro-
static precipitators or centrifuges to remove the salt water,  are usually ade-
quate.  Where high salt contents must be removed, several units in series may
be required.
Feed Preheaters.   All feed to the reactor should be preheated for maximum
efficiency.  This requires preheaters for the residual fuel oil and oxygen or
air.
Reactor.  In the reactor there are two zones - the combustion zone and re-
action zone.  The fuel oil and air or oxygen are intimately mixed in the

                                     12

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combustion zone where part of the oil is burned and part is cracked by the re-
sulting high temperatures.  In the reaction zone, the combustion products react
with the cracked products to form the desired product gas.  The combustion must
be carefully controlled by limiting the oxygen, as excess combustion will in-
crease the carbon dioxide produced, and insufficient combustion will produce
excess carbon in the product gas.  Carbon is a by-product of the reaction and
may be recovered and recycled to the reactor as a suspension in the residual
fuel oil feedstock.  The design and installation of the reactor refractory
liner, and the design of the burners, is critical for proper operation of the
process.
Waste Heat Exchanger.  Much of the efficiency of the gasification process de-
pends upon recovering the maximum heat possible.  The waste heat exchanger at
the outlet of the reactor is used to recover much of this heat in the form of
steam.  Treated feedwater is charged to the exchanger and, because of the high
temperatures at the reactor outlet, high pressure-saturated steam is generated.
     In addition to the design of the waste heat exchanger for high tempera-
ture and pressure, special design must be used to allow the carbon by-product
to pass through the exchanger without fouling.  Such fouling would reduce the
amount of steam produced, thus lowering the efficiency of the process.  Treat-
ed feedwater preheating in an economizer exchanger is usually used to further
cool the reactor product gas in order to recover more heat.  Additional heat
recovery may be obtained from the product gas after slurry separation and be-
fore gas scrubbing.  (Figure 2)
Product Gas Wash.  The product gas from the economizer is contacted by water
in a spray vessel followed by a carbon slurry separator; most of the soot is
removed here.  The remaining soot is removed from the product gas in a scrub-
ber.  The water wash is designed to remove essentially all of the product gas
contaminants that are soluble in water plus the carbon soot and certain ash
compounds which remain suspended in the water.  These contaminants are mainly
carbon, ash, including vanadium and nickel compounds, hydrogen cyanide,
ammonia and traces of formic acid.  All of these contaminants are potential
pollutants and should be handled accordingly.  By treating the spent wash
water, the hydrogen cyanide, formic acid and ammonia can be disposed of safely,
leaving only the metals and ash.

                                     13

-------
Carbon Separation.  The carbon soot may be separated from the water by sever-
al methods.  One method involves using naphtha extraction of soot from water
suspension followed by transfer to fuel oil.  The naphtha is recovered by
distillation from the naphtha/soot/fuel oil mixture.  This produces a soot/
feedstock slurry which can be recycled to the reactor for converting into
additional product gas.  Besides the soot being a potential pollutant, it also
contains some ash, vanadium and nickel.  (Figure 3)
Sulfur Removal.  The product gas from the water scrubber still contains most
of the sulfur compounds and carbon dioxide.  Thus, it is necessary to pass
the gas through a contactor containing an absorbent for removal of hydrogen
sulfide.  In addition to the hydrogen sulfide, which is the major sulfur com-
ponent in the gas, there is also some carbonyl sulfide and traces of carbon
disulfide.  An absorbent should be chosen that will also remove as much as
possible of these sulfur compounds.   All of these sulfur compounds will nor-
mally form sulfur dioxide if the product gas is burned, and they should be
considered as pollutants.
     The carbon dioxide in the product gas is a dilutant.  When the product
gas is to be used as a fuel for gas  turbines, the carbon dioxide has some
beneficial effects and is normally left in the gas.  Under these conditions,
a selective H_S absorbent is usually chosen that will absorb the CO- to a
lesser extent.   When a higher Btu content of the gas is desired, an absorbent
is chosen that removes both the sulfur compounds and the carbon dioxide.
(Figure 4)
Sulfur Recovery.  Disposal of the hydrogen sulfide removed in desulfurization
usually calls for the addition of a Glaus unit.  Hydrogen sulfide is charged
to the Glaus unit to produce sulfur.  The effluent gas from this unit usually
contains some residual sulfur dioxide and should be considered as a potential
pollutant.  However, further processing is available which will reduce the
sulfur emission to very low levels such as a SCOT or IFF unit.  (Figures 5 & 6)
                                     14

-------
OXYGEN
OR AIR
O	
BOILER FEEDWATER
O
               REACTOR
                           WASTE-HEAT
                           EXCHANGER
        OIL FEED
HP STEAM
                                                                   SCRUBBER
                                                                                 PRODUCT GAS
                                                                    /
                                                                o  •
                                                  CARBON SLURRY g |
                                                     SEPARATOR   w
                                                                                   C.W.
    RECYCLE
    WATER
                                                                                WATER TO
                                 CARBON RECOVERY
                                   AND RECYCLE
                      Figure  2.  Shell Gasification Process
                                                                                TREATMENT

-------
               CARBON
       AGGLOMERATION/SETTLER
 CARBON
  WATER
 SLURRY
FUEL OIL
  STEAM
                       CARBON
                       AGGLOMERATES
             J    L
                                        CARBON AGGLOMERATES
                                          FUEL OIL COLUMN
        c
    LIGHT
DISTILLATE
(NAPHTHA)
                 Figure 3.  Shell Closed Carbon Recovery  System.
                    C.W.
->. WATER
                                                                                              WATER TO
                                                                                              TREATMENT
                                                                                              RESIDUAL
                                                                                              FUEL AND
                                                                                              CARBON TO
                                                                                              REACTOR

-------
PURIFIED GAS
                 Figure A.  Selexol II-S removal process.

-------
oo
        LIQUID
       SULFUR
                                                           AIR
  ACID GAS
FROM SELEXOL
                                                               CATALYTIC REACTORS
                                                                                       RECYCLE GAS
                                                                                       FROM SCOT UNIT
                                                                                     WASTE HEAT BOILER
                                                                    L.P. STEAM

                                                           CONDENSERS
                          Figure 5.  Straight through CLAUS process.
       TAIL GAS TO
       SCOT UNIT

-------
               RECYCLED ACID GAS TO CLAUS UNIT
     TAIL GAS
    FROM CLAUS

       FUEL.
       AIR
vo
     REDUCTION
      REACTOR
                           QUENCH
                              LP.
                              STEAM
                                                    GAS
k





1



J



»,

A

ABSOR

RICH      LEAN
AMINE    AMINE


STRIPP

V


ER
•* 	 ,
J
d
                                L.P.
                                STEAM
                                        WATER
                          Figure  6.   Shell  Glaus Off-Gas Treating  (SCOT) process.

-------
     Figure 7 shows a typical residual oil gasification unit with steam gener-
ation.  Streams are numbered, and a description of each stream follows.  Steam
heat can be used on the feed instead of fired heaters.
     Figure 8 shows typical cleanup units with carbon separation and recycle,
hydrogen sulfide removal in a Selexol unit, production of sulfur in a Glaus
unit, and cleanup of the Glaus effluent gas in a SCOT unit.
     Table 1 gives a description of each stream in the POX process plus the
associated additional equipment for cleaning up the gas stream.
     Table 2 is a summary of all of the significant potential pollutants from
the process.  They are listed beneath the streams in which it is possible
for them to exist.  Each stream should be analyzed on a commercial unit in
order to determine the existence and emission level of each potential pollu-
tant.
     Table 3 shows typical feedstocks and products to a residual fuel oil gas-
ifier, commonly called a partial oxidation unit (POX).  These feeds and pro-
ducts are the basis for the numbers shown in the following tables.
     Table 4 is a weight balance around a unit to produce a gas  at the heat
                9                                                9
rate of 2.5 x 10  Btu/hr. higher heating value (HHV) or 2.35 x 10  Btu/hr.
lower heating value (LEV).
     Table 5 indicates the efficiency of the above unit.  The first efficiency
is through the oxidizer and heat recovery system which shows a 93 to 96% heat
recovery range when compared to the heat content of the feed charged.  The
second efficiency shows 79.2% after all sulfur removal and cleanup equipment
is considered.
     Table 6 considers all of the potential pollutants which  can be produced  in
the process and follows them through each piece of equipment, showing the
possible level in-each stream under normal operating conditions.
     Table 7 is an estimate of the capital costs and operating costs of the
above unit.  It indicates that when charging a residual fuel oil to this size
unit costing $10/bbl., a clean 118 Btu/(LHV)  gas at 275 psig can be produced
for approximately $3/MM Btu.
                                      20

-------
           SALT
         SETTLER
               AIR
            PREHEATER
        HPSTEAM
       GENERATOR
RESIDUUM
STORAGE
RESIDUUM
 HEATER
REACTOR
FEEDWATER
PREHEATER
           CARBON/
           SLURRY
          SEPARATOR
               7.  Typical residual, oil guaIflea Lion unit  (POX).

-------
 WATER
SCRUBBER
WATER
FLASH
   H2S
ABSORBER
CLAUS
UNIT
          NAPHTHA
         EXTRACTION
       RESIDUUM
        STRIPPER
            H2S
         STRIPPER
            SCOT
           CLEANUP
          Figure 8.  Typical gasification cleanup unit for (POX)

-------
             TABLE 1.  DESCRIPTION OF FLUW FROM FIGURES 6 AND 7
Stream
  No.                                   Stream Description

   1                     Residual Fuel Oil to Heated Storage
   2                     Residual Fuel Oil to Feed Preheater
   3                     Residual Fuel Oil to Carbon Recovery
   4                     Residual Fuel Oil Plus Carbon From Recovery
   5                     Residual Fuel Oil Plus Carbon From Feed Preheater
   6                     Process Oxidation Air to Feed Preheater
   7                     Cooled Process Gas to Water Wash
   7A                    Gas to Water Scrubber
   8                     Water Scrubbed Process Gas to Acid Gas Scrubber
   9                     Clean Process Gas Product
  10                     Hydrogen Sulfide Plus Carbon Dioxide to Glaus Unit
  11                     Combustion Air to Glaus Unit
  12                     Total to Claus Unit
  13                     Sulfur Product
  14                     Claus Effluent Gas to SCOT Unit
  15                     Combustion Air to SCOT Unit
  16                     Fuel Gas to SCOT Unit
  17                     SCOT Unit Stack Gas
  18                     Residual Oil Preheater Stack Gas
  19                     Stack Gas From Process Oxidation Air Preheater
  20                     Treated Feedwater to Preheater
  21                     High Pressure Steam
  22                     Preheated Feedwater
  23                     Carbon and Water From Carbon/Slurry Separator
  24                     Naphtha Makeup to Naphtha Extraction
  25                     Naphtha and Carbon From Naphtha Extraction
  26                     Water Makeup to Water Scrubber
  27                     Waste Water
  28                     Recycle Water to Water Scrubber
  29                     Water Plus Entrained Naphtha to Water Flash
  30                     Stripped Naphtha From Water Flash
  31                     Naphtha Reflux
  32                     Naphtha Stripped From Residuum/Carbon Mixture Water
                           to Carbon Slurry Separator
                                     23

-------
                TABLE 2.   SUMMARY OF POTENTIAL POLLUTANTS
Carbon  By-product
   Vanadium
   Nickel
   Other Ash Components
Effluent Wash Water
   Soluble and Suspended Ash Components
   Carbon (Minor)
   Vanadium
   Nickel
   Hydrogen Cyanide (minor)
   Formic Acid (trace)
   Ammonia (minor)
Product Gas
   Carbon (trace)
   Carbon Monoxide
   Hydrogen Sulfide (minor)
   Hydrogen Cyanide (trace)
Burned Product Gas
   Sulfur Dioxide
   Carbon Monoxide
   Particulate Matter (minor)
                                     24

-------
                    TABLE 3 .  TYPICAL FEED AND PRODUCTS
            Feedstocks
                     Final Gas Product
Oil Feedstock
            Final Product Gas
   Kuwait 1050 F+ Residue

     Gravity, °API
       S.G. 60/60°F
       Lb/Bbl

     Composition, % wt.
       Carbon
       Hydrogen
       Sulfur
       Nitrogen
       Oxygen
       Ash
     Viscosity, SSF
       210°F
       275°F
     Metals, ppm wt.
       Nickel
       Vanadium

Naphtha For Soot Recovery

     Gravity, °API
       S.G. 60/60°F
       Lb/Bbl

     Composition, % wt.
       Carbon
       Hydrogen
    5.6
    1.032
  361.5
   83.72
     .68
     .55
     .50
     .50
     .05
                              100.00
1,300
  140
   30
  130
   60
    0.739
  258.3
   85.19
   14.81
Estimated Composition,
% Volume
  Hydrogen                    14.3
  Carbon Monoxide             23.7
  Carbon Dioxide               0.02
  Water                        0.28
  Methane                      0.26
  Nitrogen                    60.65
  Argon                        0.76
  Hydrogen Sulfide   j
  Carbonyl Sulf ide   j"     —3QOm>a
        Total                100.00

  Average Molecular Weight    24.33
Higher Heating Value,
  BTU/SCF
Lower Heating Value,
  BTU/SCF
125.5

118.0
                              100.00
                                     25

-------
Stream
  No.

   1

  24

   6
   9

  13



  17
             TABLE  4.   WEIGHT BALANCE FOR PROCESS (AIR OXIDANT)
                                  Input
                                 M Ib./hr.

                                   205.9

                                     1.8

                                 1,226.5

                                 1,434.2
Residuum

Naphtha

Air to Gasifier



Clean Product Gas

Sulfur
Losses - CO- and HO
                                                      Output
                                                     M Ib./hr.
1,278.0

   11.0

1,289.0

  145.2
                                    26

-------
             TABLE  5.   ENERGY BALANCE FOR PROCESS  (AIR OXIDANT)


Basis:  2,350 x 10  Btu/hr.  Net Heating Value Final Product Gas
Stream                                       Million          Million
  No.                                        Btu/hr.    %     Btu/hr.

    1      Net Heating Value of Residuum
             Feed                            3,407.2

   24      Net Heating Value of Naphtha
             Feed                               35.5
                                             3,442.7   100%

    9      Net Heating Value of Clean
             Product Gas                                       2,350      68.3

21-22      Enthalpy of Surplus Steam
             Generated                                           953      27.7

           Efficiency Before Sulfur Removal                    3,303      96.0*

           Heat Required for Sulfur Removal                      618      18.0

   13      Heating Value of Sulfur Produced                   	42       1.2

           Heating Value of Net Surplus Steam
             and Gas After Sulfur Removal                      2,727      79.2
 * maximum value indicated, however, may be as  low
   as 93%
                                     27

-------
                   TABLE  6.   POTENTIAL POLLUTANT STREAMS


     The list of streams below does not include the steam  boiler  and  cooling

tower blow downs, as these are common to many other units.  Also,  it  does  not

include the water effluent from the salt settler on the residual  oil  feed.
Stream
  No.
  17
  18
  19
  27
     Description

Product Gas
  l,278,000#/hr.
  830,000 SCFM
SCOT Stack Gas
Residuum Heater Stack
  45,100#/hr.
  11,600 SCFM

Air Preheater Stack
  360,000#/hr.
  92,500 SCFM

Wash Water Effluent
  42,300#/hr.
Potential
Pollutant

    HS
    COS
    CO
    HCN
Particulate

    SO
    NO
Particulate

    SO
    NO^
Particulate

    SO
    NO
Particulate

    Ash
    Va
    Ni
    HCN
   Phenol
  13
Sulfur
  ll,000#/hr.
 ///hr.

    300
     83
302,900
  Trace
  Trace

     40

     45

     43
    160
     14

    350
  1,270
    115

    100
     26
      6
  Trace
  Trace

  Trace
                                   28

-------
  TABLE 7.   TOTAL COSTS OF PRODUCING 2.35  x 10  BTU/HR  (LEV) OF PRODUCT GAS
    Capital Costs

Gasification Unit
Desulfurization
Sour Water Stripping
Sulfur Recovery
Waste Water Treatment
Booster Compressor
Cooling Tower
Other Expenses
                 Millions of
                   1977 $
Operating Costs

     Variable

Residual Fuel
Naphtha
Steam
  1350 psia
  1275 psia,
65 psia
Cooling Water
Electricity
Boiler Feed Water
925°F
          Unit
Cost,
C/MM Btu
bbl
bbl

Ib
Ib
Ib
MGal
KWH
gal
1000
1200

0.453
0.570
0.402
2.0
0.9
.08
235.0
2.4

(151.8)
127.7
1.0
3.8
1.8
1.1


237.4






                                                             221.0
Fixed

Operating Labor
Direct Overhead
Operating Materials
   Total Operating Expense
Maintenance Labor
Maintenance Material
Direct Overhead
   Total Maintenance Expense
Indirect Overhead
Taxes, Ins., Royalty, etc.
Total Operating Cost
Capital Charge for 9/
Fuel Gas Mfg. Cost
         E.P.
                                           $/MM Btu

                                          3.0
                                          1.2
                                          0.4	
                                                  4.6
                                          3.5
                                          3.5
                                          2.0	
                                                  9.0
                                          4.4
                                          3.8
                                     29

-------
                                  SECTION 5
                         DIRECT HYDRODESULFURIZATION

     The rapid growth of energy consumption in heavily industrialized coun-
tries, such as Japan and the United States, has created a large demand for
heavy fuel oils.  The increase in consumption created a rise in ambient sul-
fur dioxide concentrations.  To reduce the environmental impact of the com-
bustion of these fuels, sulfur-in-fuel regulations were adopted.  In Japan,
for instance, utilities are required to burn from as low as 0.1% sulfur by
weight to no greater than about 1.0% sulfur.
     One method of producing these low sulfur fuel oils (LSFO) is direct hy-
drodesulfurization of reduced atmospheric crudes.
     Since 1968, reduced crude direct hydrodesulfurization technology has been
applied to produce LSFO from Middle East atmospheric residues.  There are at
this time 11 commercial direct HDS units operating with a combined production
capacity of 459,000 barrels per day of low sulfur fuel oil (LSFO).  Ten of the
11 units are in Japan.  Information about the location, licensee, licensor and
capacity of each of the plants appears in Table 8.
PROCESS DESCRIPTION
     The direct hydrodesulfurization process consists of 7 interconnected
unit operations:
     1.  Storage and Pretreatment
     2.  Reaction Section
     3.  Separation Section
     4.  Recycle Gas Purification
     5.  Sulfur Recovery
                                     30

-------
TABLE  8.  COMMERCIAL DIRECT HYDRODESULFURIZATION FACILITIES
Licensee
AMINOL
Asia Oil
Idemitsu Kosan


Kashima Oil
Maruzen Oil
Mitsubishi Oil
Nippon Mining Co.
Okinawa S. S.
Seibu Oil
Plant
Location
Kuwait
Yokohama , Jap an
Aichi, Japan
Chiba, Japan
Hyogo , Japan
Kashima, Japan
Chiba, Japan
Mizushima, Japan
Mizushima, Japan
Okinawa, Japan
Onoda, Japan
Licensor
UOP
UOP
Gulf
UOP
Gulf
UOP
Union Oil
Gulf
Gulf
Gulf
Shell
Plant
Capacity (BPD
35,000
30,000
50,000
40,000
40,000
45,000
60,000
45,000
31,000
38,000
45,000
                            31

-------
     6.  Tail Gas Treatment
     7.  Fractionation Section
     As shown in Figure 9, atmospheric reduced crude from the storage and pre-
treatment section passes into the reactor after being combined with makeup
hydrogen and recycle gas.  In the reactor, the sulfur in the reduced crude
combines with the hydrogen to form hydrogen sulfide (H_S).  The reactor efflu-
ent enters a series of flash vessels which separate the stream into liquid,
recycle-gas and sour fuel gas fractions.  The liquid streams pass to a distil-
lation column for fractionation into low sulfur fuel oil (LSFO), middle dis-
tillate, naphtha, and sour fuel gas.  The recycle gas goes to an amine scrub-
ber where the tUS is removed.  It is necessary to remove the H»S, since its
presence in the hydrogen-rich recycle gas would reduce the desulfurization
rate.  This purified recycle gas is either used as quench gas to moderate the
reactor's temperature or mixed with the feed and make-up hydrogen.  The rich
amine passes to an amine regenerator for separation of the recycle amine and
hydrogen sulfide.
     The ELS rich off-gas stream from the amine regenerator passes to a Glaus
unit for recovery of the sulfur.  The Glaus feed stream may contain 95-99%
ILS, of which about 97% is converted into molten sulfur.  The unconverted
H S exits the unit in the form of sulfur dioxide (SCL).   Since the SCL concen-
trations in the Glaus tail-gas are generally significantly higher than nation-
al or local standards,  additional control, in the form of a tail-gas treater
(TGT),  is required.
                                     32

-------
NAPHTHA
FRACTIONATION
   SECTION
 LOW SULFUR
 FUEL OIL •*-
                                   LIQUID
SEPARATION
 SECTION
                                           RECYCLE
 REDUCED
 CRUDE
   STORAGE
      &
PRETREATMENT
                                             GAS
                                                 GAS
RECYCLE GAS
PURIFICATION
 REACTION
  SECTION
                                                                  oc
                                                                  <
                                                                  o
                                                                  I
                                                                  o
                                                                  LU
                                                                  O
                                                                   AIR
                                                                  CO
                                                                  C3
                                                                  Q
  SULFUR
 RECOVERY
                              HYDROGEN
                               MAKE-UP
-SULFUR
                                                                             TAIL GAS
                                                                             CLEAN-UP
                                                                              BY-
                                                                              PRODUCT
                                                                                              TO
                                                                                            STACK
                    figure 9.  Direct hydrodoaulfurizntIon unit operations.

-------
 MATERIAL BALANCE AROUND HDS  UNIT
      Typically,  the HDS system has  two  input  streams  and eight  output
 streams.
                            FLUE GAS FROM
MAKE-UP
HYDROGEN
REDUCED
CRUDE
t
HDS
SYSTEM







	 >.

                                                    WASTE GAS FROM TAIL-GAS
                                                    TREATER
                                                    BY-PRODUCT
                                                    OFF-GAS
                                                        PRODUCTS
                                                    NAPHTHA
                                                  *. Ml DOLE DISTILLATE
                                                    LOW SULFUR FUEL OIL

                                                  *. WASTE WATER
                Figure  10.  HDS entering and exiting streams.

     A representative material balance appears in Figure 11.   The data is for
the Shell HDS unit at the Seibu Oil Refinery in Yamaguchi, Japan.  Similar
diagrams are being prepared for the Gulf and Universal Oil Products (UOP)
licensed units visited.
HDS EMISSIONS
     In the previous section, there are three streams leaving the HDS system
which interface directly with the environment:
     1.  Flue gas from furnaces
     2.  Waste gas from tail-gas treater
     3.  Waste water
                                     34

-------
LO
                                               FUEL CONTAINS
                                                 LESS THAN
                                                0.7% SULFUR
59 M TON/D
HYDROGEN
45.000 BPD
KUWAIT
	 >
REDUCED
CRUDE
i
\

•




>>.

	 _>.
	 — ^.
  WASTE GAS STREAM
  CONTAINING LESS THAN
  300 ppm SC>2

  230 MT/DAY SULFUR
                                                                               >. CrC4 OFFGAS-33M TONS/DAY
>. 390 BPD NAPHTHA |NEG.
               SULFUR)

  9,250 BPD MIDDLE DISTILLATE
  (0.01% SULFUR BY WEIGHT)

  33,600 BPD TYPE "C" FUEL
  (0.8% SULFUR BY WEIGHT)
                                                                                 WASTE WATER - 450 M TONS/DAY
                           Figure ll.  Material balance for Shell HDS unit.
                                  45,000 barrel-per-day design basis

-------
 Sour Off-Gas
     The C--C, off-gas stream is not emitted directly to the atmosphere.  In-
 stead, the stream is combined with other refinery "sour" fuel gas streams and
 sent to an amine scrubber for removal of the H«S.  The scrubbed gas then goes
 to a fuel gas pool for use throughout the refinery.  Because of the higher
make-up hydrogen requirements in the Gulf Type IV process (produces 0.1-0.3%
 sulfur fuel oil), the sour fuel gas from the HDS unit passes to a hydrogen
 recovery unit.
     The selection of furnace fuels, tail-gas treatment and waste water sepa-
ration and treatment are dependent upon:
     1.  National and local air and water pollution emission
         standards.
     2.  Specific design and operating requirements of refinery
     3.  Feed and product requirements
     4.  Economics
Waste Water
     Water is introduced into the HDS unit for two purposes:
     1.  As wash water to the reactor effluent coolers to
         remove ammonium hydrosulfide (NH.HS)
     2.  As a condensed stripping stream
     About 90% of the total sour water is from the wash with the remaining
10% being condensed steam.   The combined stream is fed into a sour water
stripper for separation of  the liquid and gaseous streams.   The combined feed
typically has between 1.0-2.5 weight % H^S and 0.5-1.0 weight % ammonia (NH-).
The waste water from the stripper contains approximately Sppra by weight H^S
and 50ppm by weight NH». The stripped hydrogen sulfide and ammonia are piped
to the sulfur recovery unit where they are combined with H-S rich amine re-
genator off-gas.   At the Idemitsu Kosan refinery in Hyogo Prefecture,  the
sour water passes to a Chevron waste water treatment (WWT)  unit.  This unit
converts the sour water into three streams:
                                     36

-------
     1.  High-purity H2S which is fed into the SRU
     2.  Pure saleable ammonia
     3.  Recycle water which is fed to crude oil desalter
Flue Gas from Furnaces
     Various arrangements of heaters are used to preheat the reduced crude
feed, make-up hydrogen, recycle gas and fractionator feed.  During the Japan-
ese trip, we found heaters  fired by low sulfur fuel oil, fuel gas and a com-
bination of these fuels.  A limiting factor in the selection of heater fuel is
the allowable emission standards.  As an example, the SCL emissions standards
in Yamaguchi Prefecture require the sulfur content of the furnace fuel be less
than 0.5% by weight.  In operation, the furnaces are fired by a combination of
70% oil and 30% refinery fuel gas.  Since the gas contains virtually no sul-
fur, 0.7% sulfur oil can be used and the emission standards will still be met.
Tail Gas Treatment
     A variety of tail gas  treatment methods have been used to reduce the sul-
fur dioxide emission from the Glaus units to environmentally acceptable lev-
els.  The process selection is based on consideration of items such as the de-
sired degree of control, capital and operating costs, by-product credits and
maintenance costs.  Table 9 lists the tail-gas treatment techniques for the
seven refineries visited.   Only one unit, the thoroughbred 101 scrubber at the
Nippon's Mizushima refinery, produces a saleable by-product.  The SCOT units,
although most expensive from an operating standpoint, result in the lowest
S02 concentration (20-100ppm by volume).
PROCESS ECONOMICS
     Present estimates for  the desulfurization of reduced crude range from $2.00
to $4.00 per barrel.   The cost  depends  on  items  such  as  hydrogen cost,
size of plant, raw material costs, desired depth of desulfurization and the
          t
cost of money.
     Data obtained on Japanese units is being analyzed, with the ultimate ob-
jective of determining the  range of desulfurization for the actual operating
units.  Total capital costs were obtained for all seven plants; however, prob-
lems have been encountered  in establishing an equal basis.  In some cases, the

                                      37

-------
              TABLE  9.  TAIL-GAS TREATMENT ON COMMERCIAL UNITS
     Refiner

Asia Oil

Idemitsu Kosan
Kashima Oil
Mitsubishi Oil
Nippon Mining Co.
Seibu Oil
Plant Location

   Yokohama

   Aichi


   Hyogo



   Kashima


   Mizushima



   Mizushima


   Onoda
      Tail-Gas Treatment
Shell Claus off-gas treater
   (SCOT)

Institut Francais de Petrols
   (IFF) tail-gas treater
   followed by incineration

Shell Claus off-gas treater
   (SCOT)

Institut Francais de Petrole
   (IFF) tail-gas treater
   followed by caustic scrubber

Chiyoda thoroughbred 101 flue
   gas scrubber

Shell Claus off-gas treater
   (SCOT)
                                    38

-------
cost included the sulfur recovery and tail-gas treater,  while in other cases,
the cost was not included.  This is further complicated by the capital costs
being for the year the unit was constructed.  The year constructed varies from
1970 for the Kashima Oil unit to 1976 for the Seibu Oil facility.
     Operating costs in the form of utilities, chemicals, catalyst and man-
power present less of a problem.  The data we acquired during the trip are in
the form of quantities consumed, not cost.  Appropriate cost factors will be
applied to convert quantities into dollar-per-barrel costs.
                                      39

-------
                                   SECTION 6
                        FLUE GAS DESULFURIZATION (FGD)

     This study presents the results of a preliminary environmental assessment
of the Flue Gas Desulfurization (FGD) process attached to a residual oil-fired
boiler.  All waste streams contributing to air, water and solid waste pollu-
tants were evaluated in terms of emission rates.  The FGD control technology
assessment involved SO- removal efficiencies of burning high sulfur (2,5%)
residual oil and evaluation of process control capabilities.  The FGD process
performance was also evaluated on the effective removal of particulates that
carry the bulk of the trace elements and toxic substances.  The reliability of
the FGD process was considered under varying boiler loads, firing rates of
residual oil and fuel contaminant content.  The effects of transient conditions
of start-up, shutdown and upset operating conditions on emission control were
considered.
     Some grab samples were taken for Prelevel I orientation and for the compil-
ation of a partial emissions inventory of the residual oil-fired boiler in
electric utility power plant.  In addition to the environmental and control
technology assessment, an economic evaluation of the FGD process relative to
alternative residual oil utilization techniques is  presented.  Finally, recom-
mendations are made for further environmental assessment procedures and for the
control technology research and development to be carried out.
DESCRIPTION OF PROCESS
     Although the most advanced flue gas desulfurization (FGD) processes are
generally of the "throwaway" type which produce an  unusable mixture of sulfur
compounds, development work is also in progress on  a number of "regenerable"
processes which can ultimately produce either elemental sulfur or sulfuric
acid as a by-product.  Elemental sulfur is normally preferred because it is a
non-corrosive solid which is easily handled, stored, and shipped.

                                      40

-------
     Evaluations of all waste streams from the FGD systems and a tabulation of
process emissions are included.  These data were derived from engineering esti-
mates, Dr. Ando, Pedco Surveys, and from various plant field sampling and
laboratory analysis programs.  Emission rates determined for the various util-
ity power plants were then used to predict pollutant loadings for the FGD sys-
tems.  These results are compared with legal requirements, quantifiable health,
and ecological effects.
TYPES OF PROCESSES
     This section describes the categories of the various Japanese plants list-
ed in Table 10.  The development of commercial FGD processes is listed in
Table 11 by year demonstrated and by classification of operation.
Non-Slurry Processes
Sodium Solution Scrubbing - S02 Regeneration and Reduction to Sulfur—
     Stack gas is washed with water in a venturi scrubber for removal of parti-
culates and then washed in a spray scrubber with a recirculating solution of
sodium salts in water for SO- removal.  Makeup sodium carbonate is added to cov-
er handling and oxidation losses of sodium sulfite to sulfate.  Sodium sulfate
crystals are purged from the system, dried, and sold.  Water is evaporated from
the scrubbing solution using a single-effect evaporator to crystallize and
thermally decompose sodium bisulfite, driving off concentrated SO .  The result-
ing sodium sulfite is recycled to the scrubber and the SO^ is reacted with
methane for reduction to elemental sulfur.  The regeneration and reduction areas
are designed as a cyclic absorption-desorption process for removing sulfur
dioxide from waste gases and producing a concentrated sulfur dioxide gas for
feed to a contact sulfuric acid plant or to a Glaus sulfur plant.
Ammonia Process-
     Flue gas is passed through a scrubbing tower and SO^ is absorbed by an
aqueous stream of ammonium hydroxide, bisulfite, and sulfite.  Makeup ammonia
is injected into the flue gas ahead of the scrubber.  The scrubber effluent is
filtered to remove sludge and then aerated to oxidize the ammonium sulfite to
ammonium sulfate.  The ammonium sulfate is crystallized in an evaporator and
then centrifuged and dried (Figure 12).

                                       41

-------
Aluminum Sulfate Process—
     Flue gas, after the acid mist has been removed, is sent to an absorption
tower where SO  is absorbed by a basic aluminum sulfate solution.  The enrich-
              2
ed solution goes to a regenerator and SCL is stripped off by steam heating.
The  SO- stream is dried and returned to the sulfuric acid plant.  A side
stream of enriched solution is reacted with calcium carbonate to prevent
buildup of SO- in the absorbent.  The calcium sulfate is removed by filtra-
tion (Figure 13).
Slurry Processes
Limestone Slurry Scrubbing—
     Stack gas is washed with a recirculating slurry (pH of 5.8-6.4) of lime-
stone and reacted calcium salts in water,  using a two-stage (venturi and mo-
bile bed) scrubber system for particulate and S0_ removal (Figure 14).  Lime-
stone feed is ground wet prior to addition to the scrubber effluent hold
tank.  Calcium sulfite and sulfate salts are withdrawn to a disposal area for
discard.  Reheat of stack gas to 175°F is provided.
Lime Slurry Scrubbing—
     Stack gas is washed with a recirculating slurry (pH of 6.0-8.0) of cal-
cined limestone (lime)  and reacted calcium salts in water using two stages of
venturi scrubbing.   Lime is purchased from a nearby calcination operation,
slaked, and added to both circulation streams.  Calcium sulfite and sulfate
are withdrawn to a disposal area for discard.  Reheat of stack gas to 175°F
is provided.
Magnesia Slurry Scrubbing - Regeneration to EUSO.—
     Stack gas is washed using two separate stages of venturi scrubbing—the
first utilizing water for removal of particulates, and the second utilizing
a recirculating slurry (pH of 7.5-8.5)  of magnesia (MgO) and reacted magne-
sium - sulfur salts in water for removal of SO..  Makeup magnesia is slaked and
and added to cover only handling losses, since the sulfates formed are reduced
during regeneration.  Slurry from the S02 scrubber is dewatered, dried, cal-
 cined,  and recycled during which concentrated S07 is evolved to a contact
sulfuric acid plant producing 98% acid.
                                    42

-------
        TABLE 10.  MAJOR WET-TYPE FLUE GAS DESULFURIZATION PROCESSES
     Categories
Absorbent
I.   Non-Slurry        Dil. Sulfuric Acid
     (Double Alkali)
                       Sodium Sulfite
                       Ammonium Hydroxide
                        By-Product

                      Gypsum

                      Gypsum
     Process
    Licensors

Chiyoda

Showa-Denko

Kur eha-Kawas aki

Showa-Denko
                       Aluminum Sulfate

                       Sodium Sulfite
                 Gypsum

                 SO™ or Sulfur
                                        Dowa Mining

                                        Wellman-Lord
II.  Slurry
Lime or Limestone     Gypsum
                       Magnesium Oxide
                      Calcium Sulfite
                      (Throw-away)

                      EnSO, or S00
                                   Mitsubishi H.I.,
                                   Hitachi, etc.

                                   Chemico
                                   Chemico
                                    43

-------
             TABLE 11.   DEVELOPMENT OF COMMERCIAL  FGD PROCESSES
         Scrubbing Process

1.  Limestone/Sludge
      (CaO,  CaCO_)  Absorbent
2.  Lime/Sludge
      (Ca(OH)2) Absorbent

3.  Magox-Sulfur
      (MgO) Absorbent
    Catalyst Oxidation Acid
       (dilute H2SO, with sodium
       salt absorbents)

    Sodium/Sulfur
      (Na2S03,  NaOH,  Na2C03)
      Absorbent
6.  Double Alkali/Sludge
      Na SO., + CaCO_ or Ca(OH)
                  CaCO
                                    Year
                                Demonstrated

                                   1968-71
                                   1971-72


                                   1972-73
                                  1972-73
                                  1973-74
                                  1973-74
         ,),SO
         (SO )
     Al  (SO )  +
     Sodium Acetate
7.   Ammonia/ Sulfur or Ferti-
      lizer (ammonium salts)
     absorbent
                                  1974-75
                                                        Classification/
                                                     Operating Principles

                                               Throwaway processes/wet absorp-
                                               tion in scrubber by slurry;  in-
                                               soluble sulfites and sulfates
                                               disposed of as waste

                                               Same as above
Regenerative process/wet absorp-
tion in scrubber by magnesium
oxide slurry magnesium oxide
regeneration by calcining, SO-
by-product sulfur

Regenerative process/catalytic
oxidation by V~0,- catalyst into
sulfuric acid

Regenerative process/sodium base
scrubbing with sulfite to pro-
duce bisulfite regeneration in
evaporator-crystallizer; bleed
stream purge of sulfate solution

Throwaway process/wet absorption
in scrubber; reaction products
precipitation and removed from
recycle stream
                                               Regenerative process/ammonia
                                               base scrubbing with wet Glaus
                                               recovery of sulfur or fertili-
                                               zer application
                                    44

-------
                                 TO STACK
.p-
Ln

















FLUE
GAS




















COOLER

CONCEN-
TPATHR




















<-





*»




^


















rf.,,_
L























Hllw







1






SCRUBBER

































<-

j




^-












>






t




^
^ —


s
t

,
-i_
-/

^















	 IMM3 MAK






t





f\ VlrMTCD
UAlUl^cn










t-ur














AIR
I
^\
<—<











k j
























L



































»,



•w






1
T

REACTORS





TANK




HYDRO-
CLONE




THICKENER




LIME









_/-^ 	 f ^
I
^f-1 1


CcrslTRirUCjt
-^* ~
GYPSUM


,:w



                                                       NH4OH
                         Figure 12.  Double  alkali  process  -  ammonia  absorbent.

-------
       TO STACK
FLUE
GAS
          i
       SCRUBBER
       \
CaCO3
                                                                                                   GYPSUM
                               AI2
-------
FLUE
GAS
                    VENTURI
                   SCRUBBER
                   AUXILIARY
                   SCRUBBER
                  (FOR LOW pH)
                                                                                 TO STACK
                      VENTURI
                     SCRUBBER
OXIDIZER
                                                              THICKENER
                                                     AIR
                                                                                        CaC03
                                     P
                                         CENTRIFUGE
GYPSUM
                           Figure 14 .  Limestone slurry scrubbing throwaway process.

-------
 POLLUTANTS
 Important Pollutants in Stack Gas to FGD Units
 1.  Particulates
 2.  Sulfur oxides  (SO )
                     x
 3.  Nitrogen oxides (NO )
                       X
 4.  Hydrocarbons (HC)
 5.  Carbon monoxide (CO)
 6.  Trace elements (70 elements)
 7.  Benzene soluble organics (BSO)*
 8.  Particulate polycyclic organic matter
    (PPOM) Benzo(a)pyrenes (BaP)
 9.  Polyhalogenated hydrocarbons (PHH)

Emission Sources in Terms of Unit Operations
     Particulate emission rates vary with the type of fuel, as well as with
boiler design and operating factors.  Opacity and particulate matter are in-
 creased as the fuel ash content increases.  Correct air-to-fuel ratios help
minimize particulate emissions.  Either an excess or lack of air restricts
 organic matter from being oxidized in the boiler.  Oil-fired units require
proper oil preheat temperatures to minimize emissions.
     Essentially all sulfur in the fuel is oxidized to SO- , and one to five
percent of the S0? is  oxidized to SO, during combustion.  About 95 percent of
the. sulfur is emitted to the FGD, the remainder reacting with the ash.
     The impact of the combustion of fuel oil on the concentrations of trace
elements in aerosols has been shown to be dependent on the concentration of
ash in the oil being burned^ln the boiler and also the firing rate.
     Particulate emissions resulting from the combustion of fuel oil are dom-
inated by sub-micron particles which contain most of the mass of many ele-
ments.  The residence time of these particles in the atmosphere will be longer

                                     48

-------
than some other fuels.
Atmospheric Emissions—
     From the FGD processes, these emissions are either participate emissions
or by-products of the scrubber chemical reactions.  Particulate emissions re-
sult from the residual fuel oil ash content.
     The Federal emission standards (NSPS) are:
       Particulate                      0.1 Lbs/106Btu or 0.12 GR/SCFD
       S02                              0.8 Lbs/106Btu or SSOppra
       N0x                              0.3 Lbs/106Btu or 227ppm
     The Massachusetts State regulations are:
                                             % Removal Efficiency
       S02 » 63.3ppm(v)                              93.6%
           = 271.9 Lbs/hr
           = 0.201 Lbs/106Btu
       Particulate = 0.044 GR/SCFD                   63.4%
                   = 150 Lbs/hr
                   = 0.295 Lbs/106Btu
     These standards were applied to a magnesium oxide FGD test run.  The oil
analysis used in the magnesium oxide FGD process (Figure 15)  was composed of:
(1) sulfur, 1.89 to 2.15%; (2) ash, 0.07 to 0.10%; and (3) carbon varied from
84.39 to 84.79%.  The 150MW power plant emitted 2721 to 4227 Ibs.  per hour
S0_ as input to the FGD scrubber whose outlet was 200 to 294 Ibs.  per hour or
a SO- removal efficiency varying from 89.2 to 92.7%.  The nitrogen oxides were
not analyzed.
     The particulate input to the FGD scrubber ranged from 151 to  399 Ibs. per
hour of by-products of combustion and oxidation for a removal efficiency of 45
to 70%.  Removal efficiency of particulates of less than 1 micron  varied from
53 to 65%.  This shows a  typical inefficiency of most venturi-type scrubbers.
The health effects on living tissue of these submicron particles is well docu-
mented.  The spectrographic analysis indicated the following concentrations

                                     49

-------
RESIDUA!
OIL-FIREC
UTILITY
BOILER
151 MW
8,968 Btu
KW
; \



1354 x 106 Btu
PER HR INPUT
999,000 PPH STIM
@ 1857 PSIG
991°F

53% EXCESS AIR
RESIDUA!
Wt.%
1.89
0.07
84.54
11.24
0.10
2.16
9268.3 GPM
TRACE
ELEMENT

TO FGD









S02 = 983.9 ppm (V)
= 4227.8 Ibs/hr
430,232 SCFMD =
3.122 lbs/106 Btu
Particulate =
= 0.108 GR/SCFD
- 399 LBS/HR
= 0.295 LBS/106 Btu
ASH CONTENT TO FGD
COMBUSTIBLES,
CARBON 54 61%
VANADIUM 9 13%
MAGNESIUM 5 7%
IRON 0.48 0.49%
SULFUR 13 22%
uOILF.O. NO. 6 898,907 SCFM FROM FGD •*






FROM



898,907 SCFM




FGD

58 74%
9 16%
0.7 t.28%
0.15 0.20%
15 23%


Btu/lb
SULFUR
ASH
CARBON
HYDROGEN
NITROGEN
OXYGEN
19,083 Btu/lb
CONCEN- EMISSION
TRATION FACTOR


















FGD UNIT
USING MgO
WITH

REGENERATION
















> .
> f
RECYCLE SLURRY RECYCLE
MgO FEED
WATER = 90 0.43 1.55%V
SOLIDS =10 0.68 0.374%Ni
100 WT%



\ '
	 (ppm) (a/106 Btu) TYPlCAl COMPOSITION OF MAIOR Fnn CTRFAMQ
BkNTIMONY
ARSENIC
3ARIUM
MANGANESE
MICKEL
riN
MNADIUM
0.024 0.0059
WT. % of TOTAL STREAM
°'08 °-002 MoO MciSC
011 0 003 -•*- •
0~04 0001 RECYCLE SLURRY* 10% SOLIDS 0.3 6.:
16' 039 CENTRIFUGE CAKE 2.2 37.f
On 002 CALCINER FEED
9' o'22 CALCINER PRODUCT


•3 Mt)S04 WATER & INERTS
5 14.4 79.0
J 6.5 53.5
7.1 60.3 10.9 21.7
87.1 0 7.7 5.1
Figure 1.5.   Test run on FGD unit using M
-------
of toxic elements in the FGD source emissions:  vanadium varied from 980 to
1320ppm; sodium, SlOOppm; zinc, 680ppm; aluminum, 200ppm; and Co-12ppm, MNSppm,
Cu-17ppm, S-5ppm, and several others were below Ippm in the residual oil as fired.
Solid Wastes Emissions—
     In the regenerated MgO process, the vanadium input in scrubber varied from
0.43 to 1.55% and the nickel varied from 0.08 to 0.374% over a 9 month period.
     The greatest fugitive dust losses for this project occurred at the regen-
eration plant where 0.5 tons per day were scalped off the calciner product as
large lumps before the pulverization process.  Future system design will pro-
vide for the reclaiming of these losses.  In addition, 1.5 tons per day were
lost from the neutralizer overflow.  In subsequent designs, this large loss can
be recovered for recycle by separation of solids in the neutralizer overflow.
The material balance calculation showed a loss over the entire power plant op-
eration of 0.37 tons per operation day.  This loss represents about 3.5% of the
total MgO make-up rate.
                                                   MgO (Dry Basis)
          Loss to Stack                  '         0.13 tons per day
          Scrubber Overflow                       0.14 tons per day
          Miscellaneous                           0.10 tons per day
          Total                                   0.37 tons per day
Waste Water and Solid Wastes—
     These have been discussed in other sections of this report in detail with
reference to Table 12.
Commercial Unit Emissions
Limestone Slurry Process—
     A considerable quantity of CaS03/CaS04 solid waste is generated, approach-
ing as much as 4 times the weight of the sulfur removed.  Wastes discharged to
settling ponds are reported to have poor settling properties.  This may lead to
difficulty when reclaiming the land for future use.  Potential runoff from the
ponding site could lead to additional water pollution problems as shown in
Table 12 indicating high make-up water and high waste-water ratios.  Another
                                     51

-------
      TABLE 12 .  WASTEWATER FROM FGD PLANTS

Rank
1.
2.
3.
4.
5.
6.
7.







Process
Babcock-Hitachi
Wellman-MKK
Mitsubishi (MHI)
Showa Denko
Chubu-MKK
Chiyoda
Chemico Mitsui*

Load
pH
S04(As MgS04)
Ni
R2°3*
Inlet
SO
MW (ppm)
500 1,500
220 1,800
750 1,480
150 1,400
85 1,300
350 1,540
150 2,830
*STACK DRAININGS
6/13/73
145 MW
4.1
13.3%
0.01%
0.12%

Makeup

Water Water Ratio Waste-Water
(T/hr.) % Ratio %
5.0
3.0
14.0
3.5
3.5
24.0
40.6
ANALYSIS
7/17/73
145 MW
4.3
7.0%
0.004%
0.18%
26
—
37
45
62
64
39
7/18/73
145 MW
3.3
5.3%
0.003%
0.22%
10
14
19
23
41
68
23






R2°3 = Fe2°3
                        52

-------
disadvantage of the Limestone Slurry process is low operating reliability fron
slurry plugging of scrubber internals.  Also, reheat and high pressure drop cause
an increase in already high energy consumption as indicated in Table 13.  One ad-
vantage of the process, besides being the oldest and most economical process,
is the elimination of electrostatic precipitators by a high particulate removal
efficiency of 83% as shown in Table 14.
Magnesia Slurry Process—
     This process has the following advantages:  (1) capability of achieving a-
bove 90% S02 removal efficiency; (2) minimal waste water or solid disposal prob-
lems; (3) excellent flexibility for by-product switching from sulfuric acid to
elemental sulfur; and (4) simultaneous SO  and NO  removal efficiency (Table 14).
                                         fc       X
Double Alkali Process—
     A simpler and more reliable process than the lime/limestone, it has the
same pollution problems common to throwaway processes in having high waste wat-
er and waste solids to dispose as depicted in Table 12 (Chiyoda process).  It
is more reliable than the lime process because a clear solution is used in the
scrubber with less possibility of buildup of scale.
Weak Acid Process—
     The advantages of this process are:  (1) simplicity and reliability of the
various unit operations involving clear absorbent solution; (2) capability of
achieving high S02 removal efficiency  (95% or better, Table 13, item 7) ; (3)
ability to produce non-polluting elemental sulfur or high strength sulfuric
acid; (4) high reliability when provided with high surge capacity before and af-
ter the absorber during highly variable boiler load changes.  The disadvantages
are:   high power requirements and thiosulfate bleed-off stream pollution unless
oxidation is complete.
The Acetic Acid Double Alkali Process—
     This process has a high degree of S02 absorption efficiency of less than
Ippm S0_ in the exit gas when the inlet gas enters at 1500-1700ppm.  This un-
usually high S07 removal efficiency is obtained by the use of perforated trays
with high L/G values and the high S02 affinity of sodium acetate recirculating
on each tray.  A typical block diagram is shown in Figure 16.

                                      53

-------
           TABLE 13.  COMPARISON OF DESIGN AND OPERATING PARAMETERS VERSUS PERFORMANCE
Identification

No.

1

2

3

4

Developer
MHI Mitsubishi-
Jecco
Mitsui

Babcock-Hitachi

Kureha-Kawasaki
Design Parameters
Capacity
1,000
NM /hr.
3
l,200d

840

1,450C

l,260d
Absorbent
Preci-
bitant
Stoichio-
metry

CaO l.C

CaC00
.95-2
CaCO
1.1-1.2
Na0SO_
Operating
Parameters
Slurry or
Solution
Type of
Absorber

GP3

Venturi

b
PP

GP3
J*. .
6.6

6

6.1

6.2
Conc.%

10

5

20

20
Energy Related
Parameters
L/G
Liters
Per NMn
J
10

10-15

10

10
Process Performance
Efficiencies
Pressure S00ppm
Drop *
MM H00
*»
200

200

850

150
f.
In

1,600

1,500

1,500

1,070
Out

30

150

60

5
Remov-
al
of SO,,
4.
98

90

96

99.5
5   Showa Denko


6   Nippon Kokan


7   Chiyoda



8   Kurabo
                         500    NaoS03     Cone
                         150
                              6.8    25      1-2     Scrubber  1,400   40     97
                                                     Only 250
       (NH.) SO.  Screen      6
       CaO^ L  *
30      2         250       700   30     96
                       1,050    dll.
                                H SO
                                CaC03
                  Tellerette  1     2-4     55-60
100    (NH,)_ SO, Tellerette  4
       CM
                                                              10
                          1,600   60     96
        6-10      100     1,500   80     85
(continued)

-------
                                       TABLE  13 (continued)
      Identification
Design Parameters
Operating
Parameters
       Energy Related
         Parameters
                    Process Performance
                       Efficiencies
No.   Developer

 9   Dowa


Capacity
1,000
NM^/hr.
Absorbent
Preci-
bitant
Stoichio-
metry



Type of
Absorber
                            150
Slurry or
Solution
h Cone . %
L/G
Liters
Per NM.
Pressure
Drop *
MM H00
               Tellerette
       10
                  100
                                                                                              SO ppm     Remov-
                                                                                                r          al
                                                                                               In  Out   of SO,,
                     600   20
                                                                          97
    10   Kureha
U1
    Ch,COONa,
    CaC03
                                                pp
 5.5
20
7-8*
                                                                                 280
1,400  1-5
99.6
     a - Grid packed
     b - Perforated plate
     c - Four scrubbers in parallel
     d - Two scrubbers in parallel
             e - For tail gas at 25°C. L/G 6-10 for flue gas
             f - Dissolved in CaCL? solution
             g - Including limestone scrubbing
             * - Including cooler, absorber and mist eliminator

-------
In Table 14, the acid mist (SOO ppm(v) values are consistently high and
above U.S.A. EPA standards.  Japan does not distinguish between SO., and S0?
emission separately, but they are both combined under the SO  regulations in
                                                            X
Japan.  There is no specific incentive to control SO- by the Japanese utility
industry.  However, there are processes for mist elimination by designers and
operators not listed in Table 14 that do accomplish good acid mist control
within the U.S.A. EPA standards of 20ppm, such as:  Mitsubishi Heavy Indus-
tries, Fugi Kosui,  IHI, Babcock-Hitachi and Mitsui Miike.  The amount of sul-
furic acid mist generated is directly dependent upon the amount of access air
used in the combustion of residual oil.  The submicron acid mist particles
escape readily past most absorption towers when a specific mist elimination
device is not designed into the FGD system.
                                     56

-------
      TABLE 14.   ENVIRONMENTAL POLLUTANT CONTROL CAPABILITIES  OF RESIDUAL
                 OIL-FIRED BOILER FLUE GAS  CLEANING PROCESSES
*
Size
Type of of FGD
Process Unit (MW)
1. (c) 2% H2SOA 180
2. (S-D) Sodium 90
Sulfite
3. (D) Aluminum 100
Sulfate
4. (K) Mg(OH), 85
+ CaCO
5. Limestone 500
U.S.A. EPA Standard —
for New Source Per-
formance Oil-fired
Boilers (73 to 1,000
MU)
* (0.80 Ibs. SOJ
1 x 10° Btu
1 (0.30 Ibs. NOJ
NM./H % of
(SCFM) NSPS
430,000 11%
260,000 9%
280,000 36%
230,000 24%
(860,000) 8%
100%
§ (0.06 grains)
SCF

Acid
Outlet S02 Mist
SO- Removal S0_
ppm Eff.(%) ppmfv)
10-60 96-98 50
50 95-98 85
10-20 95-99 92
130 90-96 80
44 96-97
550* — 20


Total
NO Emissions Particulates
x • 	
% of grains
NSPS ppm(v) NSPS NM3
58% 0.035
67% 0.040
--
88% 200 83% 0.050
83% 0.050
100% 2270 100% .141


1 x 10° Btu

-------
                      TO STACK
Ul
oo
         FLU EG AS
                          I
                       ACETIC
                        ACID
                      RECOVERY
                         S02
                      SCRUBBER
Ca C03
                                                                                      ACETIC ACID (MAKE-UPI

                                                                                      Na2 CO3 (MAKE-UP)
       GYPSUM
                       Figure 16 .   Double alkali process - sodium acetate-absorbent

-------
Projection of  Control Efficiency  for  Important Pollutants
     Most projections of  control  efficiency of important pollutants can be
based upon Japan's  experience with FGD systems applied to oil-fired utility
boilers.  The  Japanese  historical trends  in SO- reduction could become an ex-
ample for the  U.S.A.  for  the future.
     For a new plant with a capacity  of 500MW in the Tokyo and Osaka areas,
the  sulfur content  of oil charged to  a boiler must be below 0.3% even with
a  200m  stack.   As a result of  these regulations, the importation of low-
sulfur  fuels,  hydrodesulfurization of heavy oil, and flue gas desulfurization,
the  ambient  S0? concentration has decreased as shown below.
     Figure  17 shows  the  ambient SO,,  reduction in Japan over the last 12 years,
during which FGD and other processes have demonstrated emissions control.
    0.06
    0.04
 S02
 (ppm)
    0.02
                                    I
       1965      1967      1969      1971      1973      1975      1976
                                      YEAR
           Figure 17 .  Sulfur dioxide reduction trends in Japan.
1977
                                     59

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     The ambient standard for SO  concentration has been changed from O.OSppm
                                X
 (yearly average) to 0.04ppm  (daily average).  As a result of the new standard,
 the  hourly average should not exceed O.lppm and the daily average should not
 exceed 0.04ppm.  The standard is more stringent in Japan than in the U.S.A.
 and  West Germany.
                  TABLE 15.  AMBIENT AIR QUALITY STANDARDS
    (Daily or yearly average  converted into ppm by vol. at plant boundary)



Daily
SO
X
Yearly
N00
2
Daily Yearly

Japan 0 . 04
U.S.A.
West Germany
(0.016)
0.03
0.05
0.02 (0.008)
(0.13) 0.05
0.05

     The ambient air quality standard for N02 in Japan was set forth in 1973
at 0.02ppm in daily average, the most stringent figure in the world (Table 15).
The present yearly average of NO- concentration ranges from 0.02 to O.OSppm,
and the daily average often reaches 0.04-0.07ppm in many cities.
     The NO  emission standard for stationary sources was first set up in 1973
           A
and revised in 1975.  Table 16 shows the standard for boilers larger than
          3
100,000 Nm /hr.  Similar figures have been assigned to smaller boilers between
                     3
10,000 and 100,000 Nm /hr. since 1975.  The standard is also more stringent in
Japan than in the U.S.A. and other countries.
     The main reason the acid mist values are high and above U.S. EPA standards
is because Japan does not specify SO- emission loading standards; therefore, no
tight control is indicated by Japanese industries.  New standards for particu-
lates by Japan when enforced may solve this problem.  The non-restrictive par-
ticulates regulations or standards allow the Japanese industry an escape clause
on SO-.  The expensive acid mist, SO- mist eliminators, are costly to operate
because the high pressure drop requires extra fan horsepower and power costs.
Another solution is to have high exit stack entrance free board space prior to

                                     60

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                      TABLE 16.  N0__ EMISSION STANDARD (ppm)
Fuel              For new boilers                         For existing boilers

                  1973       1975                         1973            1975
Gas
Oil
Coal
130
180
480
100
150
480
170
230
750
130
230
750

     Combustion modification and improvement of burners  has been carried out
to meet the standard.  The ambient air quality standard, however, cannot be
attained even with more stringent emission standards.  More stringent regula-
tions to restrict total quantity of NO  emissions from stationary sources need
                                      X
to be applied.  The new regulations in Japan require the construction of many
flue gas denitrification plants which remove more than 80% of NO .
                                                                X
Estimated Capital and Operating Costs
     Among the various FGD processes, the sodium scrubbing process with by-
product of sodium sulfite is the simplest and most economical.  The second
lowest cost control technique on SO- is the throwaway wet-lime process,
but this requires a large disposal pond.  A plant based on the wet lime-gypsum
process costs about 25% more than the throwaway process but does not require a
waste pond.
     Examples of plant cost within battery limits are shown in Table 17.  The
cost went up sharply during the middle of 1975 because of inflation and  the
active demand for FGD plants.
     In Japan, a wet lime-gypsum process plant (200-300MW) now costs approxi-
mately $45-60/kW in battery limits, while a plant based on the indirect liae/
limestone process costs 5-30% more.  A plant using sulfuric acid by-product
processes costs 30-70% more than the wet lime-gypsum process.
                                     61

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            TABLE 17 .  PLANT COST IN BATTERY LIMITS ($1 = ¥300)
                (The  cost nearly tripled in late 1973 and has
                  decreased considerably since late 1975.)
                                                       Plant Cost
Process
Wellman-MKK
Sumitomo S.B.
Chemico-Mitsui
Hitachi-Tokyo
E.P.
Wellman-MKK
Shell
Chubu-MKK
Chemico-Mitsui
Mitsui-Chemico
Mitsubishi (MHI)
Kur eha-Kawas aki
Chiyoda
Babcock-Hitachi
Wellman-MKK
Absorbent
Na2S03
Carbon
Ca(OH)2
Carbon
Na2S03
CuO
CaC03
MgO
CaCO»
CaO
Na2S03
H2S04
CaC03
Na2S03
By-
product
H2S°4
H2S04
Sludge
Gypsum
H2S04
so2
Gypsum
so2
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
H2S04
Capacity
(MW)
70
55
128
150
220
40
89
180
250
188
450
350
500
160
1975
(M Dollars)
2.6
2.8
3.3
5.6
7.0
3.3
2.6
13
16
11.5
32
26
35
20
(1/kW)
37
51
26
39
32
83
29
72
64
61
71
74
70
125
Year Com-
pleted
1971
1971
1972
1972
1973
1973
1973
1974
1974
1974
1975
1975
1975
1975
     Examples of FGD costs to remove 90-95% of S0? by the wet lime-gypsum pro-
cess are shown in Table 18. The cost is about $14-17/kl oil or 3.0-3.6
mil/kWhr for different sized plants at 7 years depreciation and at 7,000 hours
yearly operation.
                                     62

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      TABLE 18.   FGD  COST BY WET LIME-GYPSUM PROCESS  IN JAPAN  (1975  $)
            (7 years depreciation,  7,000 hours  full  load operation.
             per  year.  Oil consumption:   150,000k./lOOMU/year,
               S:  2.8%, 90% removal.  Reheating  to 110°C.)
Investment  cost  ($1,000)

fixed  cost  ($1,000/year)

   Depreciation

   Interest,  Insurance

   Total

Running cost  ($l,000/year)

   Lime

   Oil for  reheating  ($100/kl)

   Power  (
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   TABLE 19.  U. S. A. BATTERY LIMITS CAPITAL INVESTMENT AND ANNUAL COSTS


Power Size:  500MW

Residual Oil (No. 6) = 4.0% Sulfur

Mid 1977 Project Costs


                                     Total Capital          Annual Costs
                                    Investment $/KW     Mills/kWh (No Credits)

1.  Limes tone /Sludge                     100.02                 4.78
       (CaO, CaC03)

2.  Lime/Sludge                           94.64                 5.00
       (Ca(OH)2)

3.  Magox- Sulfur *                       105.87                 5.22
       (MgO)

4.  Catalyst Oxidation Acid              128.70                 4.36

5.  Sodium/Sulfur *                      124.29                 6.03
            0,  NaOH,  NaC0)
6.  Double Alkali/ Sludge                 118.94                 5.92
       (Na?SO-, + CaCO. or Ca(OH)9
       (NO SO. + CaCd
                   CaCOp

7.  Ammonia/ Sulfur *                     114.52                 4.67
* Elemental Sulfur is By-product


     A preliminary economic assessment is included  in Table  19.   It  compares
 the investment and operating costs of commercial FGD facilities with other
 FGD processes.
                                     64

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                                  SECTION 7
                                 CONCLUSIONS

FGD
     Based upon the review of the present Japanese FGD status for residual
oil-fired electric utility boilers, several economically feasible approaches
and environmentally acceptable FGD processes have demonstrated the effective
and efficient process control of sulfur dioxide emissions.  However, this is
not the case for sulfate particulates or other toxic elements and their com-
pounds both organic and inorganic in the particle size range below 3 micro-
meters.  There are many nitrogen oxide scrubbers that are still in the pilot
plant and demonstration stages of development in Japan.  It will be two or
three years before the final environmental assessment of commercially appli-
cable operations will be completed.
     The FGD processes have sulfur dioxide removal efficiencies of 90-98%,
overall particulate removal efficiencies of 40 to 80% and the nitrogen oxides
removal efficiencies of 50 to 90%.
     The flexibility in the design of many FGD processes has broad ranges of
capacities to accommodate 200ppm to 50,000ppm SO- inlet concentrations to the
scrubber without affecting the 90% SO- removal efficiency level.  Therefore,
it is readily apparent that the present U.S.A. Federal NSPS requiring only
75-80% S0_ removal efficiency may become  a more  restrictive  standard because of
current FGD process capability of removing 90 to 98% S02«
     The overall average particulate removal efficiencies of 84% fail to show
the 58% fractional efficiency for fine particulates below the 1 micron level.
In other words, the FGD processes fail to remove 42% of a hazardous human
health effect of respiratory damage from submicron trace metals and toxic
substances.
                                     65

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      The nitrogen oxide  removal  efficiency and FGD process flexibility data
will  not be available until later next year.
      The U.S.A. NSPS standard for particulate control limit of no more than
0.06  grains per dry standard cubic foot of utility boiler exhaust gas when
burning  liquid fuels can be more restrictive because the current FGD process
can remove participates as low as 0.04 grains per cubic foot of exhaust gas.
      Particulate  emissions resulting from the combustion of fuel oil are dom-
inated by sub-micron particles which contain most of the mass of many elements.
This  means that the residence time of these particles in the atmosphere will be
much  longer than  for an equivalent mass of particles emitted by other fossil
fueled power plants which typically emit substantially larger particles.
      To  determine  the impact of oil combustion on atmospheric trace-element
levels,  an accurate analyses of fuel oils will be required.  The variation in
fuel  oil composition will be defined by analyzing a wide range of samples.
Although most oil-fired power plants have little in the way of pollution con-
trol  devices, it would be useful to study their effect on the composition.
HDS
      Our  study has shown HDS to be a commercially-proven, reliable and flexi-
ble method of producing a low sulfur fuel oil from r&duced crude.  Environmen-
tally  potential pollutants such as nickel,  vanadium, and sulfur are removed
from  the  fuel and  converted into saleable by-products.  As an example, approx-
imately  230 tons of molten sulfur are produced in desulfurizing a 3.9% sulfur
(by weight) Kuwait reduced feed to a 0.8% sulfur product.  Eighty to ninety
percent  of the approximately 65  by wt. ppm metals  is  retained  on the  reactor
catalyst  for possible ultimate reclamation.
     The HDS units in Japan have been designed and operated to meet the Nation-
al and local prefecture air, water and noise emission standards.  Emphasis in
Japan has been on sulfur oxides (SO ),  oxides of nitrogen (NO ), particulates
                                   X                         Jt
and,  on a local basis,  ammonia (NH ), hydrogen sulfide (H-S), carbon monoxide
(CO),  and nickel and vanadium compounds.   Effluent standards  for water exist
for chemical oxygen demand (COD), suspended solids (SS), oil, pH, phenol, cya-
nide  (CN) and chromium (Cr).  Local plant boundary noise standards, usually
a maximum of 60dB, exist in many prefectures.
                                      66

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     Emission data obtained in Japan was generally limited to S0_,  H^S, NO
                                                                *~   £     X
and NH_ concentrations in the gaseous streams and H?S, NH-, COD and pH in the
liquid streams.  Information on the feed and products, such as API  gravity,
pour point and nitrogen and sulfur concentrations, was obtained. The compos-
ition of potentially hazardous compounds in the reduced crude will  be used in
an engineering analysis to determine the possible environmental impact.  Since
most of the units in Japan are processing Arabian light, the first  analysis
will be made on this feed.  If, upon completion of analysis, sampling is nec-
essary, a Level I program will be designed and executed while the selected
units are processing light Arabian reduced crude.  This will allow for a com-
parison of the calculated versus observed data.  A residfining unit is ready
to operate in this country at Exxon in Baytown, Texas.  Information obtained
from the unit will be reported as data becomes available.
POX
     With over 100 commercial units now in operation, the residual fuel oil
gasification process is established as a unit acceptable for the production
of low, medium, and high Btu gas at elevated pressures.  Alternately, the CO
and IL, can be used for the production of chemicals and petrochemicals by add-
ing additional equipment.
     When charging a residual fuel oil priced at $10/bbl and containing 5.5%
sulfur, the process can produce an environmentally acceptable gas of 125
Btu/SCF at elevated pressure for approximately $3/MM Btu.  Although this
price is high for the U.S. at the present time, it should become more eco-
nomical in the future.  The product cost is very sensitive to feed  cost, and
the price of the gas could be reduced by charging heavier, lower-priced
feeds.
                                     67

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                                  GLOSSARY
 araine regenerator:  A unit used to remove impurities, in the form of H-S, from
     the recycle amine stream.

 chemically active fluidized bed:  A fluidized limestone bed which produces a
     clean gaseous fuel from heavy high sulfur feedstocks.

 Claus unit:  A unit which produces sulfur from a mixture of l^S and SO-.

 crude oil desalting:  A process for washing inorganic salts from crude oil and
     separating the resulting salt water.

 economizer exchanger:  A heat exchanger in which low temperature heat is
     recovered.

 effluent gas:  A gas leaving any vessel or process.

 effluent streams:  The total material leaving any vessel or process.

 flash vessel:  A vessel used to separate liquid and gaseous portions of a feed
     stream by reduction of pressure.

 flue gas desulfurization:   A process in which sulfur-containing pollutants are
     removed from a flue gas stream by contact with absorbent liquids.

 fractionation:  The separation of a mixture into components by partial vapor-
     ization and subsequent condensation.

 friable slag:  Slag that does not cling to other materials but can be readily
     removed.

hydrodesulfurization:  The elimination of sulfur from residual fuel oil by the
     reaction of sulfur with hydrogen.

 IFF:  A unit which removes H~S from the gas leaving a Claus unit.  Inter
     Francis Petrole - French Petroleum Institute.

 partial oxidation:  Partial combustion of a solid, liquid, or gas.  The products
     of partial oxidation can be oxidized further to complete the combustion.

 particulate:   Any solid matter, as opposed to a liquid, which is dispersed in
     a gas.
                                     68

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                            GLOSSARY (continued)
quench gas:  A gas used to control (decrease) the temperature of segments of
     a reactor.

residfining unit:  A hydrodesulfurization unit licensed by Exxon.

residual fuel oil:  Thick viscous liquid remaining after separation of light
     fractions of crude oil.

residual oil gasification:  A process in which liquid residual oil is charged
     and a gas produced.

SCOT unit:  A unit which removes residual H2S from the gas leaving a Glaus
     unit.

Selexol unit:  A unit which selectively absorbs H-S without absorbing appre-
     ciable co2.

slurry separation:  Separation of a suspended solid from a liquid.

"sour" fuel gas:  A gas containing hydrogen sulfide (ELS) which is capable of
     producing energy when consumed.

tail-gas treater:  Control equipment which is added to the end of a process
     to reduce emissions to acceptable levels.

variable feedstocks:  More than one kind of feed to a unit or, alternately,
     different qualities of the same feed.

waste heat exchanger:  Recovery of heat that is normally lost by exchanging
     it with another stream of lower temperature.
                                     69

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                                TECHNICAL REPORT DATA
                          (Please read fiaovctions on the reverse before completing)
 1. REPORT NO.
  EPA-600/7-77-081
                           2.
                                                       3. RECIPIENTS ACCESSION-NO.
*• <'T<-E AND SUBTITLE process Technology Background for
Environmental Assessment/Systems Analysis Utilizing
Residual Fuel Oil
                                                      5. REPORT DATE
                                                        August 1977
                                                      6. PERFORMING ORGANIZATION CODE
          M. F.Tyndall, R.C.Foster, E.K.Jones,
 and F.D.Kodras
                                                      8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Catalytic, Inc.
Highway 51 and Johnston Road
Charlotte, North Carolina  28210
                                                      10. PROGRAM ELEMENT NO.
                                                      EHE623A
                                                      11. CONTRACT/GRANT NO.

                                                      68-02-2155
 12. SPONSORING AGENCY NAME AND ADDRESS
 EPA, Office of Research and Development
 Industrial Environmental Research Laboratory
 Research Triangle Park, NC 27711
                                                      13. TYPE OF REPORT AND PERIOD COVERED
                                                      Annual; 3/76-5/77    	
                                                      14. SPONSORING AGENCY CODE
                                                        EPA/600/13
15. SUPPLEMENTARY NOTES

Mail Drop 61, 919/541-2825"
                              project officer for this report is Samuel L. Rakes,
is. ABSTRACT
              repOrt gjves results of environmental and economic assessments of
processes using residual oil to generate electricity.  Emphasis was on three commer-
cially operating processes: flue gas desulfurization (FGD) of the tail gas from fuel oil
burning boilers; removal of the sulfur in residual fuel oil by hydrodesulfurization
(HDS); and conversion of residual fuel oil into low-Btu, sulfur-free gas by partial
oxidation (POX).  The effort started with a review and analysis of available literature.
Information obtained from the literature search identified many operating HDS,  FGD,
and POX units. However, available data was not adequate for a comprehensive
environmental and economic assessment.  To obtain more specific design and operating
data, actual plants were visited.  The additional data was sufficient to determine
points of discharge-and characterize the emissions from each process. Capital and
operating cost information was obtained for all units visited and will be used for
economic comparisons.
17.
                             KEY WORDS AND DOCUMENT ANALYSIS
                DESCRIPTORS
                                          b.lDENTIFIERS/OPEN ENDED TERMS
                                                                   c. COSATI Field/Group
Pollution
Industrial Processes
Assessments
Fuel Oil
Residual Oils
Electric Power
  Generation	
                         Flue Gases
                         Desulfurization
                         Hydrogenation
                         Oxidation
Pollution Control
Stationary Sources
Environmental Assess-
  ment
Tail Gases
Hydrodesulfurization
13B      21B
13H     07A,07D
14B      07 C
11H,21D  07B


10A
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                                                                        75
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                                       70

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