EPA 600/7-86-032
                                  NTIS PB87-110516
  CONTROL OF  SULFUR EMISSIONS FROM OIL SHALE

    RETORTING USING SPENT SHALE ABSORPTION
                      by
        K.  D.  VanZanten and F. C. Haas
                J3A Associates
           Golden,  Colorado 80401
           Contract No.  68-03-1969
               Project Officer

               Edward R.  Bates
Air and Energy Engineering  Research Laboratory
     U.S. Environmental Protection Agency
     Research Triangle Park,  N.C.  27711
                Prepared For:

    U. S. Environmental  Protection Agency
      Office of Research and Development
           Washington,  D.  C.   20460

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                                     NOTICE
     The information in this document has been funded wholly or in  part
by the United States Environmental  Protection Agency under Contract
68-03-1969 to J&A Associates, Inc.   It has been subject  to the  Agency's
peer and administrative review, and it has been approved for publication
as an EPA document.  Mention of trade names or commercial  products  does
not constitute endorsement or recommendation for use.
                                   ii

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                                    ABSTRACT

Control of sulfur emissions constitutes a major portion  of the
environmental control cost for oil  shale facilities.   These substantial
sulfur control costs have encouraged developers to seek  less costly but
equally or more effective methods for limiting sulfur emissions.
Recently a strong industry trend has been to look toward the potential
for combusting carbonaceous retorted shale to recover its energy  value  (a
plus in terms of economics and resource conservation), while exploring
the possibility of absorbing the sulfur gases produced during retorting
onto the calcined carbonate material present after combustion of  retorted
western oil shale.

This study investigated the environmental advantages/disadvantages  of
absorbing S02 onto combusted retorted oil shale.  The objective of  this
program was to obtain more information in support of  PSD permitting
decisions on sulfur control and to investigate whether emission of  other
pollutants such as nitrogen oxide (NOX) and trace elements might  be
significantly increased by the combustion process. The  program was done
in two phases.  Phase I developed an engineering assessment and costs for
application of this sulfur absorption process to selected leading
retorting processes.  In Phase II,  experimental work  in  an integrated oil
shale pilot plant defined operability and proof of principle and  defined
trace element emissions.

Based on the pilot plant data obtained in this study, fluid bed operating
conditions are recommended to optimize S02 and NOX control.  In general,
conditions that favor low S02 emissions also favor low CO and trace
hydrocarbon emissions but do not favor low NOX emissions.  The general
ranges of operating conditions which produced reasonable results  both
from an operating and emissions viewpoints are given  in  the report.
Results of the trace element tests indicated some relative trends with
regard to emissions but because of the short duration of the sampling,  no
hard conclusions can be reached which would allow extrapolation of
results to long term steady-state operations.

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                       TABLE OF CONTENTS
     Notice	  ii
     Foreword	iii
     Abstract	iv
     Figures	.vii
     Tables	  viii
     Tables in Appendix A	  	  x
     Abbreviations  and Symbosl	,xi
     English/Metric Conversions	xii

I.   INTRODUCTION

     A.  Background	1
     B.  Conventional  Sulfur Control  Technologies.  ...  2
     C.  The Absorption on Spent Shale Concept	.3
     D.  ASSP Process  Description	.  .4
     E.  Phase I -  Engineering  Evaluation/Conceptual
          Process Design	.4
     F.  Phase II - Pilot Plant Program	6

II.  SUMMARY AND CONCLUSIONS

     A.  Phase I Conceptual  Design and Economics	8
     B.  Phase II Pilot Plant Testing	9

III. CONCEPTUAL DESIGN AND ECONOMICS

     A.  Design Basis	13
     B.  Costs	.17

IV.  PILOT PLANT TESTING

     A.  Description of the Pilot Plant	.  .24
     B.  Plant Instrumentation	.26
     C.  Experimental  Procedure	26
     D.  Discussion of Results	31
     E.  Process Variable Correlations	34
     F.  Trace Element Sampling and Analyses	48

V.   RECOMMENDATIONS ON DESIGN  AND OPERATION OF A FLUID
     BED COMBUSTOR  WHICH OPTIMIZES S02 and NOX  CONTROL.  . 57

VI.  QUALITY ASSURANCE/QUALITY  CONTROL

     A.  QA Objectives and Performance	59
     B.  Sampling Methodology and Results.	  .61
     C.  Analytical Methodology and Results	..64
     D.  Trace Element Methodology and Results	.69
                              v.

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                     TABLE OF CONTENTS (Continued)

                                                         Page

VII.  REFERENCES	.71

APPENDIX A - Data from Fluidized Bed Tests. . ...... 73

APPENDIX B - Leaching and Hydraulic Properties
             of Three Baghouse Ash Samples	.103

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                             LIST OF  FIGURES

 Number                                                   Page

 1.   ASSP  Process Flow Diagram	  5

 2.   Effect of Flue Gas Oxygen  on S0£ and
      NOx  Emissions	-.11

 3.   Effect of Flue Gas Oxygen  on CO and Trace
      Hydrocarbon Emissions  	 .11

 4.   Process Flow Diagram for ASSP Evaluation -
      Direct Heated (Modified In-Situ with Unishale C). . 14

 5.   Process Flow Diagram for ASSP Evaluation -
      Indirect Heated (Unishale B) . . . .	15

 6.   Process Flow Diagram for ASSP Evaluation -
      Integral Part of Process  (Lurgi)	16

 7.   Pilot Plant Process Flow Diagram ..... 	 25

 8.   Effect of Flue Gas Oxygen on SOg Emissions 	 36

 9.   Effect of Flue Gas Oxygen on NOX Emissions ..... 37

 10.  Effect of Flue Gas Oxygen on CO Emissions	.38

 11.  Effect of Flue Gas Oxygen on Trace
      Hydrocarbon Emissions  	 .40

 12.  Effect of Flue Gas Oxygen on Baghouse
      Ash Organic Carbon	 .41

 13.  Effect of Solids  Residence Time on
      S02 Emissions	.42

 14.  Effect of Solids  Residence Time on NOX
      Emissions	.43

 15,  Effect of Solids  Residence Time on CO Emissions . . .44

 16.  Effect of Fluid Bed Temperature on S02 Emissions  . .  45

 17.  Effect of Fluid Bed Organic Carbon on Organic
      Carbon Combustion Efficiency	, .46

 18.  Effect of Baghouse Ash Organic  Carbon on
      Organic Carbon Combustion Efficiency 	47

 19.  Sampling Train  for Recycle Retort  Gas  and Flue Gas. .49

20.  Comparison of Flue Gas Oxygen Analyses.  . .  . . . . .68
                         vn

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                          LIST OF TABLES

Number                                                   Page

1.   Cost Comparison for ASSP	9

2.   Equipment Changes for ASSP	.17

3.   Conceptual Design Bases 	 ..18

4.   Major Parameters Used in ASSP Conceptual Designs .  . 19

5.   Incremental Capital Cost for ASSP
      Conceptual Designs 	.20

6.   Incremental Operating Costs for ASSP
      Conceptual Designs 	 	21

7.   Incremental Capital and Operating Costs for
      ASSP Conceptual Designs 	  .22

8.   Properties of Raw Shale Used in Combustor Tests . . .27

9.   Range of Operating Conditions and Process Vriables  . 31

10.  Range of Flue Gas Composition and
      Organic Carbon Combustion Efficiency 	31

11.  Range of Solids Composition	32

12.  Mass Flow Rate Measurements	', .33

13.  Process Variable Correlations 	35

14.  Trace Element Analyses from Pilot Plant
      Tests 7, 12 and 19C . . .	 51

15.  Summary of Elemental  Balances Around Combustor ... 52

16.  Percentage of Trace Elements Present in
      Raw Shale Found in Retort Gas  and Flue Gas ....  .53

17.  Percent Distribution of Total  Element Concentration
      in Gas Stream Found in Various Scrubbers .....  .56

18.  Comparison of Fluid Bed Combustor
      Operating Conditions  	  .57

19.  Comparison of Test 19C Operating Conditions
      with Conceptual  Design .	58

19a. Summary of Precision Accuracy and
      Completeness  Objectives	  ...  * 60
                              vm

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                       LIST OF TABLES (Continued)

Number                                                   Page
20.  Sample of Analyses and Frequency of Analysis  .... 61
21.  Summary of Duplicate Mineral  Carbon Analyses  .  .  .  . 64
22.  Summary of Duplicate Total  Carbon,  Hydrogen
      and Nitrogen Analyses 	 64
23.  Summary of Duplicate Sulfur Analyses 	.65
24.  Summary of Spike Recoveries	65
25.  Summary of Spike Recoveries	69
26.  Summary of Duplicate Analyses 	70
                            ix

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                          LIST OF TABLES  IN APPENDIX A

Number                                                        Pa'ge
A-l  Summary of Fluid Bed Combustor Tests  	 74
A-2  Fluid Bed Combustor Operating Conditions	77
A-3  Properties of Retorted Solids Feed to Combustor ....  80
A-4  Properties of Combusted Shale (Heat Carrier)
      from Combustor	81
A-5  Properties of Combusted Fines (Baghouse Ash)
      from Combustor	82
A-6  Elemental Analysius of Selected Solids by
      X-ray Fluorescence	83
A-7  Analysis of Natural Gas and Retort Gas
      Used in Combustor Tests. ..... 	 84
A-8  Combustor Flue Gas Composition and Flow Rates	87
A-9  Overall Mass Flow Balances. ...... 	 90
A-10 Total Carbon Balances	92
A-ll Mineral Carbon Balances	93
A-12 Organic Carbon Balances	 .94
A-13 Sulfur Balances	95
A-14 Nitrogen Accountability in Solids and
      Flue Gas NOX	96
A-15 Mercury Balances Around Combustor 	 97
A-16 Cadmium Balances Around Combustor.	.98
A-17 Arsenic Balances Around Combustor 	 99
A-18 Lead Balances Around Combustor	100
A-19 Beryllium Balances Around Combustor 	101
A-20 Fluoride Balances Around Combustor 	 102

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                       LIST OF ABBREVIATIONS AND SYMBOLS
ABBREVIATIONS

AA
ASSP
DEA
F6D
ft/ sec
g/hr
9/1
GPT
HSP
kg/hr
Ib/hr
LTPSD
MDEA
mg/hr
MIS
ml
ppm
ppmv
SCFM
TPSD
v%
vol%
wt%
Atomic Absorption
Absorption on Spent Shale Process
Diethanolamine
Flue gas desulfurization
Feet per second
Grams per hour
Grams per liter
Gallons per ton
Hydrocarbon Solids Processing
Kilograms per hour
Pounds per hour
Long tons per stream day
Cubic meters per hour
Methyldi ethanolami ne
Milligrams per hour
Modified in-situ
Milliliter
Parts per million
Parts per million by volume
Standard cubic feet per minute
Tons per stream day
Micrograms per cubic meter
Volume percent
Volume percent
Weight percent
SYMBOLS

As
Be
Ca
Ca/S
CaCO-3
CaMg(C03)2
Cd
CO
C02
COS
CS2
F
FeS
FeS2
H2S~
Hg
UNO 3
Arsenic
Be ry 11 i urn
Calcium
Calcium to sulfur mole
ratio

Calcium carbonate
Calcium magnesium
carbonate (dolomite)

Cadmi urn
Carbon monoxide
Carbon dioxide
Carbonyl  sulfide
Carbon disulfide
Flourine
Iron (ferrous) sulfide
Iron (ferric) sulfide
Hydrogen sulfide
Mercury
Nitric acid
Mg
MgCOs

N2
NaOH

NH3
NOX

02
Pb
S02
Magnesium
Magnesium
carbonate
Nitrogen
Sodi urn
hydroxide
Ammonia
Nitrogen
 oxides
Oxygen
Lead
Sulfur dioxide

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ENGLISH/METRIC CONVERSIONS
TO CONVERT
ENGLISH UNIT
Barrels
Cubic Feet
Day
Degrees Celcius
Degrees Fahrenheit
Feet
Gallons
Hours
Inches
Minutes
Pounds
Tons
INTO
SI METRIC UNIT
Cubic Meters
Cubic Meters
Seconds
Degrees Kelvin
Degrees Kelvin
Meters
Cubic Meters
Seconds
Meters
Seconds
«
Ki 1 og rams
Kilograms
MULTIPLY
BY
0.159
0.02832
86,400
°C + 273
(°F-32)xl. 8+273
0.3048 •
0.003785
3600
0.0254
60
0.4536
907.18

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                                I.   INTRODUCTION

A,.   Background

Control of sulfur emissions is a key environmental concern in the retorting of
oil shale.  Oil shale may contain 2% or more sulfur, while a typical shale in
the Green River Formation of Colorado contains about 0.7% sulfur.  Although
this sulfur concentration is not large compared to some high sulfur coals (4
to 8% sulfur), large-scale production of  shale oil will require processing
millions of tons of oil  shale; thus, sulfur emissions would be very great if
controls were not applied.  About 16 to 30% of the sulfur in oil shale is
liberated to the vapors  (oil  and gas)  produced during retorting, and the
remainder stays with the spent shale.  Retort gasses generally contain
hydrogen sulfide (H2S) as the major sulfur compound and lesser amounts of
other organic sulfur compounds such as sulfur dioxide (S02), carbonyl sulfide
(COS), carbon disulfide  (C$2), and mercaptans (CHsSH and
To date, the federal government has not promulgated New Source Performance
Standards for the oil  shale industry.   However, the U.S. Environmental
Protection Agency does regulate S02 (and some other emissions) through
Prevention of Significant Deterioration (PSD) peimitting requirements of the
Clean Air Act.  This legislation requires use of Best Available Control
Technology - cost considered (BACT) to  minimize the addition of specified
pollutants in order to preserve air quality.  PSD permits are issued on a
facility by facility basis after careful  analysis of each application.  The
federal PSD requirement that generally  is most difficult for developers to
meet is the 24 hour Class I air quality standard limiting SOj? to 5  g/rn3.  In
addition to federal requirements, states also control the emission of S02 from
oil shale facilities.   For example, the State of Colorado limits S02 emissions
to less than 0.3 pound of S02 per barrel  of shale oil produced.

Control of sulfur emissions has been estimated to constitute a major portion
of the environmental control cost for oil  shale facilities.  For example, the
Denver Research Institute estimated costs (in 1980 dollars) in the range of $1
to $3 per barrel of shale oil produced  H ,2) t  These substantial sulfur
control costs have encouraged developers  to seek less costly but equally or
more effective methods for limiting sulfur emissions.  Recently, a strong
industry trend has been to look toward  the potential for combusting carbon on
carbonaceous retorted shale to recover  its energy value (a plus in terms of
economics and resource conservation), while exploring the possibility of
absorbing the sulfur gases produced during retorting onto the calcined
carbonate material present after combustion of retorted western oil shale.

This study investigated the environmental  advantages/disadvantages of
absorbing S02 onto combusted retorted oil  shale.  The objective of this
program was to obtain more information  in support of PSD permitting decisions
on sulfur control and to investigate whether emission of other pollutants such
as nitrogen oxide (NOX) and trace elements might be significantly increased by
the combustion process.  The program was  done in two phases.  Phase I
developed an engineering assessment and costs for application of this sulfur
absorption process to selected leading  retorting processes.  In Phase II,
experimental work in an integrated oil  shale pilot plant defined operability
and proof of principle and defined trace  element emissions.

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B .   Conventional . Sulfur Control Technologies

Two approaches have generally been used to control sulfur emissions from
retort gases — removal of the sulfur compounds from the gas before it is
combusted (gas sweetening) or combustion of the gas followed by removal  of the
    from the flue gases (flue gas desulfurization).
Gas sweetening processes such as amine absorption and Stretford generally  are
very effective in removing H£S.  However, organic sulfur compounds,
principally COS, are not significantly removed or are only partly removed  by
these conventional processes.  While f^S levels are reduced to about 10 ppmv
in the sweet gas, overall sulfur removal efficiencies are lower (95-98%)
because the organic sulfur compounds are not completely removed.

Flue gas desulfurization (FGD) processes, which use an aqueous slurry of lime
to absorb S02 from the flue gas, generally are not as highly effective in
removing SOg.  Typical S0£ removal efficiencies range from 90 to 95%.  In
addition, FGD processes must handle larger volumes of gas than gas sweetening
processes.

To meet Colorado's air quality regulations of 0.3 Ib. S02/bbl of shale oil
produced, about 95-96% of the total sulfur in the gas would have to  be
removed.  This makes use of FGD processes marginal and tends to focus more
interest on gas sweetening processes.  However, gas sweetening plants are
generally expensive to build and operate, and the sulfur product recovered may
not be saleable because of product impurities or the remoteness of the oil
shale plants from traditional sulfur markets.

The practicality of conventional control technologies applied to oil  shale
plants depends to a great extent on the type of retorting process employed;
i.e., direct heated vs. indirect heated.  Direct heated retorts are  those in
which direct combustion with air occurs inside the retort to supply  the heat
of retorting.  Examples of such processes are Modified In-Situ (MIS), Paraho
Direct Heated, and Union A.  Indirect heated retorts provide heat using heated
gases or solids and no combustion occurs in the retort vessel.   Examples are
Union B and C, Tosco II, Lurgi, and Chevron STB.

In direct heated retorts, sulfur is liberated mostly as H?S,  but the  off-gases
are relatively dilute in hydrocarbons because large quantities of N£, Og, C0£,
and HgO are liberated from combustion.  HgS removal  from such gas streams is
quite expensive using conventional gas sweetening technologies and in some
cases is economically prohibitive.  Non-selective processes (i.e., processes
which co-sorb both HgS and C02> are unattractive because of the very  great
cost associated with removing the large quantities of C02-   Selective
processes (selective for H?S), such as Stretford, are more  economically
attractive, but there remain numerous technical  concerns about Stretford-type
processes with regard to solvent degradation, quality of product sulfur, spent
solvent disposal, etc.

From a sulfur emissions viewpoint, indirect heated retorts  are  less
problematic with respect to gas treatment,  but there are a  number of  problem
areas.   Indirect heated retorts produce gases with relatively little  COo
(although higher than natural  or refinery gases), and don't have 02 or N2 as
diluents.  Proposed treating plants for indirect heated retorts use

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conventional processes such as amine sweetening or other processes typically
applied to handling natural or refinery gases.   Typfca77y,  regenerated H^S
streams end up in a Glaus sulfur plant with tail  gas  treatment.  Design of a
C'laus plant as applied to oil shale gas treating is complicated  by quantities
of both NH3 and C02, which are higher than in  natural  or refinery gases.
Also, virtually none of the conventional gas sweetening  processes do much to
remove sulfur species other than H2S; e.g., COS,  CS£,  and mercaptans.  For the
most part, these remain in the gas which,  when burned, end  up  as S02 in the
stack.  All of these conventional treating plants are  more  expensive to build
and operate than comparable systems in refineries and  gas plants because of
the higher levels of C02, and to a lesser extent, because of higher levels of
NH3 and unsaturated hydrocarbons.

C,,   The Absorption on Spent Shale Concept

Retorted shale contains from 4 to 10 wt% organic  carbon,  and research efforts
have been directed to recovering this energy by combusting  the shale, usually
in a fluid bed or other fluidized transport device.   Initially there was some
concern that excessive sulfur emissions might  result because the retorted
shale contains approximately 0.7 wt% sulfur in  the form  of  organic sulfur,
pyrite (Fe$2)s and/or pyrrhotite (FeS).  However, it was soon  discovered that
sulfur emissions were very low when combusting  carbonate-containing retorted
shale.  Approximately half the mineral  content  of Green  River  oil shale
consists of dolomite [CaMg(C03)2] and calcite  (CaCOs).   These two minerals are
the essential components of calcareous rocks used in controlling S02 in coal
combustion.  These carbonates in oil  shale are  fine-grained, with grain sizes
ranging from 1 to 10 microns which is desirable since  fine-grained calcareous
rocks are generally better S02 sorbents than the  coarse  grained  rocks.

A number of laboratory and small pilot scale experiments  have been conducted
to test the ability of carbonate-containing shales to  control sulfur
emissions.  For example, McCarthy^3)  conducted experiments  in a  four inch
diameter fluidized bed burning raw shale fines  and sulfur containing gases.
He found that at 810-820°CS a 0.2 v% H2$ gas could be  burned, emitting less
than 1 ppmv sulfur as S02.

This ability of combusted carbonate-containing  spent shale  to absorb S02 gives
rise to a novel  concept for controlling sulfur  emissions  in oil  shale plants.,
This concept will be referred to as ASSP which  stands  for Absorption on Spent
Shale Process.

The ASSP concept has several potential  advantages over conventional sulfur
removal technologies:                                                       ;

     o    The sorbent is cheap and inherently  abundant in oil shale plants.

     o    The process requires combustion  of the  spent shale which is already
          incorporated into several of the retorting technologies or which
          would be a useful  add-on to recover  residual carbon values.

     o    Since non-H2S compounds are converted to S02 by combustion, ASSP
          could represent a more efficient removal  relative to gas sweetening
          processes which only remove H2S.

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D-   ASSP Process Description
The ASSP concept uses a fluidized transport system to combust  either  raw or
retorted shale, thereby providing the vehicle for converting sulfur compounds
to S02 and absorbing the SCfc in the shale matrix.  The concept envisions
either a conventional dense-phase fluidized bed or a dilute-phase contactor
(lift pipe).  Key elements of the process are shown in Figure  1.
Solids feed is either crushed raw shale or retorted shale with a top  size of
1/4-inch or a mixture of raw and retorted shale.   Air is introduced at  the
bottom of the contactor along with process and/or waste gases  to be treated.
The contactor is provided with coils for removing heat. Heat  removed is used
either for heating process gas streams or for raising steam.   Cyclones,  flue
gas coolers, scrubbers, and/or baghouses are provided for recovering  heat and
removing dust from the combuster flue gas.
NOX emissions are controlled by staged combustion; i.e., an oxygen-lean first
stage followed by an oxygen-rich second stage.
Spent gas is discharged and cooled for heat recovery and moisturized  prior to
di sposal.
E.   Phase I - Engineering Evaluation/Conceptual  Process Designs
The engineering assessment of the ASSP concept completed during Phase I
evaluated three types of retorting processes:
     o    Direct heated
     o    Indirect heated
     o    Indirect heated with combustion integrated into the  process
Specific retorting technologies and sites were  selected as representative of
these three retort types, as follows:
Retort Type              Process                  Site
Direct heated            MIS with Unishale C      Cathedral Bluffs (Tract C-b)
Indirect heated          Unishale B               Union Oil (Parachute  Creek)
Integral combustor       Lurgi                    Rio Blanco (Tract C-a)
Integral combustor       Unishale C*              Union Oil
* The Unishale C Process is Unishale B with the addition of a  fluid bed
combustor.

The conclusions of this engineering assessment  are given in Section II  and
discussed in more detail in Section III.

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Rotort«d Shale
 R«w Slialo Finos
                                                t      t
                                              Better    t?£P
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F.   Phase II - Pilot Plant Program                                         ;

Phase II of the EPA contract involved pilot scale experimental testing of the
ASSP concept.  The test facility  used in Phase II was a pilot plant used by
Tosco Corporation to develop their  Hydrocarbon Solids Processing (HSP)
process(4).  The pilot plant has  a  nominal  capacity of six tons per day of oil
shale and contains a fluidized bed  combustor which is eighteen inches in
diameter.  A process description  of the pilot plant is given in Section IV.

Key questions addressed in the Phase II test program included:

     o    How effective is ASSP in  controlling sulfur emissions?

     o    Will ASSP produce large quantities of NOX?

     o    What are the most favorable operating conditions to achieve maximum
          sulfur control while holding NOX  emissions to a minimum?

     o    Will retorted or raw oil  shale combustion produce significant
          emissions of trace elements such  as mercury or cadmium?

The Phase I engineering assessment  evaluated application of the ASSP concept
to several types of retorts which would either incorporate a lift pipe or a
fluidized bed combustor as an integral part of the process.  The Phase II
pilot plant program studied the burning of  retort gas in a fluidized bed
combustor which was integrated into the retorting process, i.e., the combustor
provides retort heat by burning residual carbon on spent shale and the spent :
shale is returned as hot solids to  the retort.

The pilot plant was operated for  ten days between October 14 and 25, 1985.
The pilot plant was operated three  shifts per day, five days a week, Monday
through Friday.  Each shift consisted of three operators and one shift
engineer.  Operator duties included operating the plant, recording all data
and taking samples.  See Section  VI Part A  for a description of the sampling
procedures used for these tests.

A total of 44 "tests" were conducted during which plant operating data was
recorded.  Solid and gas samples  were taken on 27 of these tests.

Twenty tests were selected for further evaluation by submitting the solids
samples for chemical analysis. Eight of these tests were analyzed fairly
completely and the other 12 were  subjected  to less extensive analysis.  The
solids and gases exiting the combustor from three tests were analyzed for six
trace metals.  Large (5-gallon) samples of  combustor fines were also collected
during three other tests for leaching studies at Colorado State University
(See Appendix B).  Conclusions from the pilot plant program are given in
Section II and a discussion of the  pilot plant results is given in Section IV.

Total carbon, mineral carbon, organic carbon, and sulfur balances were
completed on the twenty tests selected for  more complete evaluation.  Mass
rate balances were calculated on  all 44 tests, i.e., pounds per hour of all
solid and gas streams entering and  leaving  the fluid bed combustor.  Trace
element balances for six trace metals were  also calculated for three of the
tests.
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Correlations of selected process  variables and their effect on S0£ and NOX
emissions and other key dependent variables were prepared and are discussed in
Section IV.  Recomnendations  on design and operation of a fluid bed combustor
for S02 and NO^ control are given in  Section V.  A discussion of quality
assurance/quality control  procedures  as applied to sampling and analysis is
given in Section VI.   Tables containing detailed information on test operating
conditions, sample analyses,  mass flow balances and trace element balances are
given in Appendix A.
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                          II.  SUMMARY AND CONCLUSIONS

The results of the Phase I study indicate that the  ASSP concept is technically
and economically viable compared to conventional  sulfur removal technologies
for most oil shale retorting processes.   The  results  of the Phase II pilot
program indicate that the ASSP concept is quite effective  in controlling
sulfur emissions and with carefully controlled operating conditions, NOX
emissions can also be reduced by more than 85 percent.  The pilot plant
program also determined that some trace  elements  are  volatilized by fluid bed
temperatures in the range of 1240 to 1550°F.

A.   Phase I Conceptual Design and Economics

For evaluation purposes, specific projects were chosen as  representative of
the three retort types:

     o    Direct heated - MIS with Unishale C - Cathedral  Bluffs

     o    Indirect heated - Unishale B - Union Oil

     o    Integral Combustor - Lurgi - Rio Blanco
                             - Unishale  C - Union Oil

This study assumed that MDEA amine absorption B used  to remove acid gases from
indirect heated retort gases and that regenerated acid gases are burned in the
ASSP combustor.  MIS gases were assumed  to be processed on the ASSP combustor
without pretreatment.

For comparison purposes, conventional sulfur  removal  processes were evaluated:

     o    Direct heated -          Case  A:  Unisulf + Flue Gas Desulfun'zation
                                   on MIS gases
                                   Case  B:  Unisulf -f Stretford on MIS gases

     o    Indirect heated -        Unisulf

     o    Integral Combustor -     DEA + Stratford  on Lurgi
                                   Unisulf on Unishale C

Major equipment costs were taken frm EPA Pollution  Control Technical Manuals
(PCTM),  ASSP equipment were sized and costs  factored from in-house data and
PCTMs.   Costs were factored to first quarter  1985.

Results of the cost study showed changes in incremental capital and operating
costs for ASSP relative to conventional  processing  in Table 1 below:
-------
                       TABLE 1.   COST COM>ARISON FOR ASSP
Retort Type
Retorting Process
ASSP Incremental
Direct Heated
Case A, Case B
MI S/Uni shale C
-71.2 63.2
Indirect
Heated
Uni shale B
+90.2
Integral
Combust or
Lurgi Uni shale
-13.0 -32.1
C
 Capital Cost

$106 Relative to
 Conventional Base

ASSP Incremental Annual   +10.83
 Operating Cost, $106
 Relative to
 Conventional
                    +12.07    -19.21
                                                           -2.29   -1..56
These cost comparisons show that the best potential  for  application of ASSP
are those processes which already have a spent shale combustor integrated into
the retorting process (e.g., Lurgi,  Unishale C,  Chevron  STB, and Tosco HSP).
Capital and operating cost savings for Unishale C  and Lurgi cases are
primarily a result of deleting the Unisulf and Stretford plants.

Economics for indirect and direct heated retorts are good to marginal.
Factors which will affect the economics are:

     o    How effective by combustor heat can be utilized (simple steam
          raising is the least desirable)

     o    The value of steam

     o    The use of fast or circulating fluid beds  to reduce investment in
          combustor equipment

B.   Phase II Pilot Plant Testing

Pilot plant tests were performed in  a bubbling fluid bed combustor of the type
which is integrated into the retort  process.   A  total of 44 individual tests
were performed.  Variables evaluated were combustor  temperature, solids
residence time, gas residence time,  oxygen concentration,  inlet gas sulfur
concentration, staged combustion, and raw shale injection.  Over the entire
range of conditions tested, emissions of -primary pollutants were:
Component

S02
NOX
CO
Trace Hydrocarbons
                                              1-38 ppmv
                                            80-670 ppmv
                                              0.05-1.80 vol%
                                            51-8465 ppmv
-------
Key findings of the tests were:

     o    S02 emissions were easily controlled to  low levels at virtually all
          conditions tested probably as  a  result of the high Ca/S ratios used.

     o    NOX emissions were primarily sensitive to oxygen concentration
          (Figure 2).  Reasonably good NOX control could be obtained with flue
          gas oxygen concentrations below  about 3  vol%.  The lowest NOX
          concentrations were seen at 02 levels approaching zero but at the
          expense of higher CO and trace hydrocarbon emissions.

     o    CO and trace hydrocarbon emissions were  primarily sensitive to flue
          gas oxygen concentration (Figure 3).  Good control of both could be
          obtained at 02 levels  above about 2  vo1%.

Emissions of NOX and S02 move in a direction opposite to CO and trace
hydrocarbon emissions.  Thus finding a set of  operating conditions which
minimize all four represents a compromise.  One test was run which produced
nearly optimum results.  Conditions for  this test  were:

               Bed Temperature              1227°F
               Solids Residence  Time        9.4 min.
               Gas Residence Time           0.9 sec.
               Gas Supply Velocity          44 ft/sec       !
               Flue Gas 02                  2.6 vol%
               Ca/S Mole Ratio              10.3
               Raw Shale/Spent Shale Ratio  1:36

At these conditions the following results  were  obtained:

               S02                          11 ppmv
               NOX                          160 ppmv
               CO                           0.27  von
               Trace Hydrocarbon            388 ppmv
               Combustion Efficiency        89%

During selected tests, both combustor flue gas and retort gas were sampled and
analyzed for selected trace elements—mercury,  cadmium, arsenic, lead,
beryllium and fluoride.  During  these tests, solids streams were also analyzed
for trace elements in an attempt to determine  where trace elements go.  One
run was performed where a spike  solution of mercury and cadmium was added to
the combustor.

Results of the trace element tests indicated some  relative trends with regard,
to emissions but because of the  short duration  of  the sampling, no hard
conclusions can be reached which would allow extrapolation of results to long
term steady-state operations.  Some of the key observations were:

     o    Lead, beryllium and fluoride were found  to have low volatility.
          That is, of the amounts present  in raw shale, only very small
          percentages were volatized to  the gas streams.

     o    Arsenic was found in significant concentrations in the retort, gas
          (100-400 ppmv) although the amount of arsenic represented less than
          15% of that in the raw shale.


                                  10
-------
Q.
Q.

pi
O
in
UJ
40




35 -




30 -




25 -




20 -




15 -




10 -




 5 -
   024

                         FLUE GAS O2. VOLJ5


  Figure 2.   Effect of flue gas oxygen on 502
                                                                       7OO
                                                                     - 600
                                                                     - 500
- 400
                                                                     - 30O
                                                                     - 200
                                                                     -  10O
       Q.
       Q.
                                                                             z
                                                                             to
                                                                             UJ
                                                        NO  emissions.
     1.8
o
u
                               FLUE GAS O2, VOL%



     Figure 3.  Effect of flue  gas  oxygen on CO and trace hydrocarbon emissions.
                                     11
-------
     o    So little mercury was present in  the  raw shale  that mercury
          emissions could not be characterized  with  high  accuracy.  Mercury
          emissions were very low except during the  spike indicating that
          mercury, if present in higher concentrations  in the raw shale, could
          possibly pose emissions problems.

     o    Cadmium demonstrated moderate volatility at higher retort and
          combustor temperatures but emissions  represented less than 10% of
          cadmium present in raw shale.

There is some evidence that mercury and cadmium introduced to the combustor
during the spike test condensed within the  retort equipment and revolatized
over time.  However, because of the limited number of samples taken, it would
not be prudent to draw any hard conclusions.  Longer term steady-state
operations would have to be studied to determine the fate of mercury arid
cadmium with more certainty.
                                  12
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                     III.  CONCEPTUAL DESIGN AND ECONOMICS
A.   Design Basis
For study purposes, specific retorting technologies and sites were selected as
representative of the direct heated, indirect heated and integrated coisibustor
types:
     Retort Type
Process
     Direct heated       MIS with Unishale C
     Indirect heated     Unishale B
     Integral combustor  Lurgi
     Integral combustor  Unishale C*
Site

Cathedral Bluffs (Tract C-b)
Union Oil (Parachute Creek)
Rio Blanco (Tract C-a)
Union Oil (Parachute Creek)
*    The Unishale C process is Unishale B with the addition of a fluid bed
     combustor.

Simplified block flow diagrams for each study case are given in Figures 4, 5
arid 6.

The study assumed that an amine process is used to remove acid gases (H2$ and
C(>2) from indirect heated retort gases.  The regenerator acid gases are then
processed in either a fluidized bed combustor (Unishale C process) or a lift
pipe combustor (Lurgi process) where spent shale and/or raw shale fines are
burned to supply some of the retorting heat requirements.  Modified in-situ
retort gases are processed directly in a fluidized bed combustor without any
pretreatment.

For each type of retort studied, a conceptual process design was developed to
evaluate the potential effectiveness and cost of applying the ASSP process on
a commercial scale.  Conventional sulfur removal processes, which are either
being planned or are currently in use, were also evaluated.  The capital and
operating costs of the ASSP process were then compared to these conventional
sulfur removal processes.
Conventional processes evaluated were:

     Retort Type         Retort Process

     Direct heated       MIS + Unishale C
     Indirect heated     Unishale B
     Integral combustor  Lurgi
     Integral combustor  Unishale C
                    Conventional Treating Process

                    Case A:  Unisulf + Flue Gas
                             Desulfurization on MIS
                             gases
                    Case B:  Unisulf + Stretford on
                             MIS gases
                    Unisulf*
                    Diethanolamine (DEA) + Stretford
                    Unisulf
     Unisulf is a Union Oil Company proprietary sulfur removal process
                                   13
-------
 Raw Shala Fines and Dust
Retort

 Vapor
                MIS

              Absorber

               Cooler
                                                                              8weel Qai
                                                                              to Process
                                R«tori Oaa
                                Spent Shala
                                   Retort Gas
                                          Air
                                                                             Acid Oaaas
                                                                        (H23 p4ua CO% ol
                                                                         Retort Oaa CO-
 Shata Ash
^>
 to Disposal
                        FIGURE 4
         PROCESS FLOW DIAGRAM FOR ASSP EVALUATION
     DIRECT  HEATED (MODIFIED IN-SITU WITH UNISHALE C)
                            14
-------
                                                                     Acid <]•••«
                                                               
-------
Run-o-I-MIno
                                                                                              Shale Ash to Disposal
                                                                                   Supplemental Fuel (Retort Gas)
                             to Pipeline
(H23  pJus 60% of

 Retort Qa* CO2)
                                                FIGURE 6
                              PROCESS FLOW DIAGRAM FOR ASSP  EVALUATION
                                  INTEGRAL PART OF PROCESS  (LURGl)
                                                         16
-------
A separate study was  done to select the best amlne process  for concentrating
gases from Unishale B and Lurgi.   Although the conventional  sulfur control
processes proposed  for Unishale B and Lurgi retorting  are the Unisulf and
DEA/Stretford  respectively, the methyldiethanolamine (MDEA)  process was
selected for ASSP because:

     o    It is partially selective for H2S over C02.   About 50% of the C02
          will pass through, thus reducing solvent circulation requirements
          which in  turn reduce both capital and operating costs.

     o    MDEA is not significantly degraded by COS.

     o    Hydrocarbon solubility is low.

     o    The  process is non-proprietary.

     o    MDEA solvent is relatively inexpensive.

     o    No exotic metallurgy is required.

B.   Costs

Equipment costs for Lurgi, Unishale B and C,, and MIS  commercial plants were
taken from the EPA  Pollution Control Technical Manuals (PCTMs) which describe
the Union*5),  Cathedral BluffsH) (Tract C-b), and Rio Blanco*6) (Tract C-a)
projects in detail.  All major ASSP equipment items were sized and costs were
factored from  in-house data bases as well as information contained in the
PCTMs.  All cost  data were factored to  first quarter 1985 using the CE Plant
Cost Index.  Equipment additions and deletions are  summarized in Table 2.
Design bases for  each retort type are summarized in Table 3.  A summary of
major equipment and process design parameters are given in  Table 4.


                           TABLE 2.  EQUIPMENT CHANGES FOR ASSP


                	Direct Heated         Indirect           Integral
                Case A: FGO   case B: stretfoFd  Heated            Combustor	

    Retort Process MIS/Untshale C  MIS/Un1shale C    Unishale B         Lurgi   Unishale C

    Systems Added for ASSP                                        „...«..
                	MDEA	    MDEA             MDEA   MDEA
                _	—Hu1d1zed Beds	    F1u1d1zed Beds

    Systems Deleted for ASSP                                            „  .  , „
                Unisulf       Unisulf          Unisulf           DEA    Unisulf
                MIS  F6D System  MIS Stretford      Recycle Gas Heater  Stretford
                MIS  Steam Boiler MIS Steam Boiler   Spent Shale Cooler


 Incremental  capital  costs  for  each ASSP case are summarized  in  Table 5    A
 summary  of incremental annual  operating costs  is given in Table 6.   Table 7
 summarizes the incremental  capital and  operating costs for ASSP  relative  to
 the conventional  sulfur  removal  schemes.

                                         17
-------
TABLE 3. CONCEPTUAL DESIGN BASES
Direct Heated
Retorting Process MIS Uni shale C
Site —Tract C-b--
Plant Capacity, TPSD 36,200 13,600
Shale Grade, 6PT 27 35
'! No. of Retorts 19 1
Conventional Sulfur
Control: Case A: FGD Unisulf
Case B: Stretford Unisulf
ASSP Parameters:
Combustor Type -^--Fluid Bed —
Number of Combustors 5
Tempera ture,°F 1350
Spent Shale Combusted,
103 ib/hr 871
Raw Shale Combusted,
103 Ib/hr 67
Retort Gases to
Combustor, 103 Ib/hr 1805
Acid Gases to
Combustor, TO3 Ib/hr 12
Total Sulfur Fed to
Combustor, Ib/hr 5373
Ca/S Molar Ratio 23
Flue Gas $03, ppmv 10*
Indirect Heated
Uni shale B
Union
27,200
34
2
Unisulf
Fluid Bed
2
1350
1760
133
0
11
2204
133
10*
Integral Combustor
Lurgi Uni shale C
Tract C-a Union
119,000 27,200 ;
23 34
13 2
DEA+ Unisulf
Stretford
Lift Pipe Fluid Bed
13 ; 2
1200-1300 1350
8533 1760
0 133
107 0
29 11
1160 2204
1088 133
30 10*
*  Determined in Phase II  Pilot Plant Program
                                          18
-------
TABLE 4, MAJOR PARAMETERS
Direct Heated
Retorting Process MIS Uni shale C
C-? *a _____Tv>ar*+ P_K______

Number of Retorts 19 1
Raw Shale Grade, 6PT 26.7 35
Raw Shale Processed,
TPSD 36,200 13,600
Raw Shale Processed
per Retort, TPSD 1,900 13,600
Net Oil Produced, BPSD 13,800 10,000
Net Retort Gas Produced,
Ib/hr 1,804,990 41,280
Sulfur Control Parameters (Base Case)
Type of Sulfur Control Case A: Case A:
FGD UNISULF
Case B: Case B:
Stretford UNISULF
Sulfur Produced, LTPSD Case A: Case A:
None 19.5
Case B: Case B:
33.8 19.5
Spent Shale Combustion Parameters (Conceptual
Type of Shale Combustor NA Fluid Bed
Number of Combustors NA 5
Temperature, °F NA 1350
Gas Residence Time, sec 1.0 1.0
Spent Shale Combusted,
Ib/hr NA 870,607
Raw Shale Combusted,
Ib/hr NA 66,666
Retort Gases to
Combustors, Ib/hr 1,804,990 0
Acid Gases to
Combustors, Ib/hr 0 11,905
Sulfur to Combustors,
Ib/hr , ^ 1,825 3,548
Ca/S Mole Ratio(a) 22.8 22.8
S02 i n Combustor Fl ue
Gas, ppmv 10 10
USED IN ASSP CONCEPTUAL
Indirect Heated
Uni shale B
llninn
Uf 1 1 UII
2
34

27,200

13,600
20,000

82,030

UNISULF



24.4



Designs)
Fluid Bed
2
1350
1.0

1,759,250 8

133,333

0

11,304

2,204
133

10
DESIGNS
Integral Combustor
Lurgi Uni shale C
T*»p/*"h P— a 1 In inn
1 1 dv. u \* a un i uii
13 2
23 34

119,000 27,200

9,150 13,600
63,140 20,000

149,045 82,030

DEA+ UNISULF
Stretford


7.56 24.4




Lift Pipe Fluid Bed
13 2
1200-1300 1350
1-3 1.0

,533,105 1,759,250

0 133,333

107,028 0

28,675 11,304

1,160 2,204
1,088 133

30 10
(a)  Based on available calcium (CaCOs or CaO) in shales and total sulfur in retort gases
     and/or acid gases entering the spent shale combustor.
FGD = Flue Gas Desulfurization
NA = Not Applicable
                                              19
-------
TABLE 5.
: Retorting Process
Site
Number of Retorts
i Type of Spent Shale
Combustors
Number of Combustors
Added Capital Cost,$lo6
i
MDEA Acid Gas Removal
: Lift Pipe Combustors
: Fluidized Bed
Combustors
INCREMENTAL CAPITAL COST FOR ASSP CONCEPTUAL DESIGNS
Direct
Heated
MIS Uni shale C
19 1
NA Fluidized
Bed
NA 5
Case A: Case B:
MIS with MIS with
FGD Stretford
$ 5.8
NA
$ 130.0
TOTAL $ 135.8
Deleted Capital Costs $10^
DEA Acid Gas Removal
Stretford Sulfur
Recovery
; UNISULF Sulfur Recovery
Spent Shale Shaft
Cooler
Recycle Gas Heater
Flue Gas Desulfur-
ization
MIS Gas Steam Boiler
TOTAL
! Net Capital Cost
; (Credit), $10^
NA
NA
$( 33.0)
NA
NA
$( 56.0)
$(118.0)
$(207.0)
$( 71.2)
$ 5.8
NA
$ 130.0
$ 135.8
NA
$( 48.0)
$( 33.0)
NA
NA
NA
$(118.0)
$(199.0)
$( 63.2)
Indirect Heated
Unishale B
Union
2
Fluidized
Bed
2
$ 5.6
NA
$ 146.0
$ 151.6
NA
NA
$( 37.7)
$( 14.4)
$( 9.3)
NA
NA
$( 61.4)
$ 90.2
Integral
Lurgi
Tract C-a
13
Lift Pipe
13
$ 9.9
No Charge
NA
T~~9".9
$04.3)
$( 8.6)
NA
NA
NA
NA
NA
$(22.9)
$03.0)
Combustor
Unishale C
Union
2
Fluidized
Bed
2
$ 5.6
NA
Mo Charge
$ 5.6
NA ; •
MA
$(37.7)
NA
MA ;
MA
NA
$(37.7)
$(32.1)
FGD = Flue Gas-Desulfurization
NA = Not Applicable
                                            20
-------
            TABLE 6.  INCREMENTAL OPERATING COSTS FOR ASSP CONCEPTUAL DESIGNS

Retorting Process
O4+y\
bi te
Number of Retorts
Type of Spent Shale
Combustor

Number of Combustors
Added Operating Cost,
$1 o°/Yr*

MDEA Acid Gas Removal
Lift Pipe Combustors
Fluidlzed Bed
Combustors
TOTAL
Deleted Operating Cost,
DEA Acid Gas Removal
Stretford Sulfur
Recovery
UNISULF Sulfur Recovery
Spent Shale Shaft
Cooler and Recycle
Gas Heater
Flue Gas Desulfur-
izatlon
MIS Gas Steam Boiler
TOTAL
Net Annual Operating
Cost (Credit), $106/Yr
Direct
MIS


19

MA

NA
Case A:
MIS with
FGD
$ 1.26
NA

$(16.66)
$(15.40)
$lQ6/Yr*
NA

NA
$(2.48)


NA

($ 7.21)
$ 35.92
$ 26.23
$ 10.83
Heated
Uni shale C
r_h— — - -

1

Fluidized
Bed
5
Case B:
MIS with
Stretford
$ 1.26
NA

$(16.66)
$(15.40)

NA

$( 5.97)
$( 2.48)


NA

NA
$ 35.92
$ 27.47
$ 12.07
Indirect Heated
Uni shale B
1 1n*? nn
Uf I I Uil
2

Fluidized
Bed
2



$ 1.24
NA

$( 4.54)
$( 3.30)

NA

NA
$( 2.80)


$(13.11)

NA
NA
$(15.91)
$(19.21)
Integral Combustor
Lurgi Llnishalje C
TVart P— a Union
ii uw v w a uit i vii
13 2

Lift Pipe Fluidized
Bed
13 2



$ 2.51 $ 1.24
No Charge NA

NA No Charge
$(2.51) $ 1.24

$(3.90) NA :

$(0.90) NA
NA $(2.80)


NA NA

NA NA
NA NA
$(4.80) $(2.80)
$(2.29) $(1.56)
FGD = Flue Gas Desulfurization
NA = Not Applicable
*    150 psig steam $4.00/1O3 lb
     400 psig steam $4.50/103 lb
     600 psig steam $5.00/1O3 Ib
     Fuel gas $3.00/106 Btu
     Electricity $0.05/kWh
                                           21
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                    TABLE 7.   INCREMENTAL  CAPITAL  AND  OPERATING  COSTS  FOR
                                   ASSP  CONCEPTUAL DESIGNS
Retorting Process

Site

Number of Retorts

Type of Spent Shale
 Combustor

Number of Combustors

Conceptual Design
Summary

Systems Added for ASSP:
Systems Deleted for
 ASSP:
   Direct Heated

MIS       Unishale C

	Tract C-b	—

19        1

NA        Fluidized


NA        5

Case A:   Case B:
MIS w/FGD MIS w/Stret-
(e)       ford (f)
MDEA(g)   MDEA
-Fluidized Beds-(a)
                                                  Indirect Heated

                                                  Uni shale B

                                                  Union

                                                  2

                                                  Fluidized Bed
-------
Results of this study show that the best potential for application of ASSP are
tt«>se processes which already have a spent shale combustor Integrated into the
retorting process (e.g., Lurgi, Unishale C, Chevron STB, and Tosco HSP).
Capital and operating cost savings for Unishale C and Lurgi cases are
primarily a result of deleting the Unisulf and Stretford plants.

For indirect heated processes (e.g., Paraho Indirect, Tosco II, and Unishale
B),, payout on the additional investment for ASSP equipment would be good to
marginal depending primarily on how effectively the add-on spent shale
combustor can be integrated into the process.  That is, economically, it is
better that heat from the combustor products be recovered and used directly in
the retort rather than used for steam raising.  For this study, it was assumed
that combustor flue gases are used to heat recycle gas for the Union B retort
(this has been proposed by Union as the preferred Unishale C scheme).  The
economics of this case are also quite sensitive to values used for steam and
fuel.  The values used here are considered quite conservative.  Use of higher
values will, of course, tilt the economics more favorably toward ASSP.

In the direct heated cases, results show substantial savings in capital costs
for ASSP relative to both Stretford and flue gas desulfurization approaches.
However, the capital savings are at the expense of increased operating costs
primarily as a result of deleting the MIS steam boiler which produces much
larger quantities of useable steam than can be produced by ASSP.  Again, the
economics here are quite sensitive to steam values, although,:in this case,
higher steam values would tilt the economics away from ASSP.  Also, investment
in fluid bed equipment is very large (on the order of $130 million) because of
the very large volumes of dilute MIS retort gases which must be handled,.
However, if fast or circulating fluid beds can be utilized, the number of
additional combustors required could be reduced from four to as few as one or
two.  This would reduce capital investment significantly and tilt the
economics more in favor of ASSP.                              :

There may also be an environmental advantage to using ASSP for the direct
heated Case B.  The ASSP process should remove the non-H2S sulfur species from
the MIS retort offgas, while the alternative Stretford process would not
effectively remove the non-H2S sulfur species.
                                    23
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                            IV.   PILOT  PLANT TESTING

A.   Description of the Pilot Plant

The test facility used in Phase II  was  a  pilot  plant built by Tosco
Corporation to develop their Hydrocarbon  Solids Processing (HSP) process.
The pilot plant has a nominal  capacity  of six tons per day of oil shale and
contains a fluidized bed combustor  which  is  eighteen inches in diameter.  A
process flow diagram of the plant is  shown in Figure 7.  A description of the
process is given below.

Raw oil shale, crushed to minus 1/4-inch  and smaller, is pneumatically lifted
to the shale feed weigh hopper system from which shale is metered into the
retort at a constant rate.  The raw shale from  the weigh hopper can be
preheated up to 300 to 500°F in the steam jacketed retort feed screw.  The
retort is an inclined rotating cylinder in which oil shale and hot heat
carrier solids (from the fluid bed  combustor) are mixed.  The mixture of heat
earner and oil shale is conveyed concurrently  through the retort to the
retort accumulator.  The feed rates of  raw oil  shale and heat carrier are
adjusted to maintain the desired temperature in the retort, approximately
900°F.

The mixture of spent shale and heat carrier  from the retort, called retorted
solids, is pneumatically conveyed from  the accumulator discharge screw into
the fluid bed combustor using superheated steam.  The fuel residue on the
spent shale (primarily organic carbon and hydrogen) is combusted to provide
part or all of the heat required to pyrolyze the oil shale.  Combusted solids,
which consititute the heat carrier, are drawn off from the fluid bed combustor
and are recycled to the retort.

The combustor is an atmospheric, dense  phase, bubbling, fluidized bed.  The
spent shale fuel is supplemented as needed by injection of natural gas or
retort gas into the bed.  Solid fuels such as raw oil shale and coal can also
be used.  The bed is fluidized by hot flue gases from an external burner.
Flow rates of air, natural gas, retort  gas and  superheated steam are measured
with orifice meters and controlled  with pneumatic flow control valves.  Flow
rates are adjusted to maintain bed  fluidization, bed temperature and oxygen
concentration in the combustor flue gas.   The dense phase bed level is
indicated by a differential pressure  measurement between the bottom of the bed
and the top of the freeboard section.  The dense phase bed density is measured
by differential pressure measurement between the bottom of the bed and a point
two feet above that point.

Flue gas and entrained shale ash from the combustor are cooled in a heat
exchanger and the ash is separated  from the  flue gas in a baghouse.  From this
baghouse weigh bin the ash flows to a moisturizer where it is mixed with water
prior to disposal.  The clean flue  gas  flow  is  measured with an orifice meter
prior to being vented to the atmosphere.

Pyrolysis vapors from the retort are cooled  and the oil and water condensed in
a quench tower and overhead condenser.  Condensed heavy oil from the quench
tower, as well as light oil and water condensed in the overhead condenser, are
collected in separate drums.  The non-condensed retort vapors are either


                                 24
-------
                                                    eg
                                                    (S
                                                    a

                                                    |
                                                rv  u.
                                                UJ  CO
                                                =3  UJ
                                                to  o
                                                E  i
                                                    O-
                                                    a.

                                                    o
                                                    a.
25
-------
metered and sent to a flare or are diverted to the  fluid bed corabustor through
a blower used to overcome the pressure in  the  bed.   For the majority of the
pilot plant tests, retort gas was burned in the fluid bed to supply the l^S
and non-HgS sulfur compounds.  In addition, H2S and COS from pressurized
cylinders was used to  spike" the retort gas to allow significantly higher
sulfur concentrations in the injected retort gas than would have been possible
with only retort gas.

B.   Plant Instrumentation

In addition to instruments provided for process control,  instrumentation was
provided to determine mass flow balances around the fluid bed combustor and to
monitor key component concentrations in the flue gas stream.

     o    Weights of raw shale feed and baghouse ash were continuously
          monitored by electronic weigh scale  systems located on the
          respective hoppers.

     o    Mass flow rates of retorted solids and heat carrier were measured
          via calibrated screw conveyors,

     o    Combustor air, combustor burner  natural gas,  retort gas, transfer
          line superheated steam, transfer line air (overfire air used for
          secondary combustion) and combustor  flue  gas were all measured with
          orifice meters.

     o    Numerous air and nitrogen purges, used to keep  pressure taps free of
          dust were individually measured  by rotameters.
     o    Cylinder fyS and COS injected into the  retort gas were measured with
          rotameters.

     o    Sulfur content of the retort gas  was  continuously measured with an
          on-line sulfur analyzer.

     o    Concentrations of oxygen,  carbon  monoxide, nitrogen oxides arid
          sulfur dioxide in the flue gas were continuously monitored via
          on-line analyzers.

C.   Experimental Procedure

Parachute Creek oil shale obtained from the Colony mine was used for the pilot
plant program.  This shale was crushed to minus 1/4-inch particle size and had
a nominal richness of 34-37 gallons per ton.  Table 8 gives the analysis of
two raw shale samples taken near the beginning  and end of the pilot plant
program.  The shale used is similar to the  shale  being processed by the Union
Oil commercial plant.   This shale has significant amounts of calcium and
magnesium carbonates,  which when decomposed to  the oxides, are available for
sulfur absorption.
                                  26
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TABLE 8.  PROPERTIES OF RAW SHALE USED IN COMBUSTOR TESTS
Test Number
Shale Size Range
Fischer Assay, 6PT
Oil, wt %
Gas, wt %
Water, wt %
Residue, wt %
Moisture, wt%
Elemental Analysis, wt %
Mineral Carbon
Organic Carbon
Hydrogen
Ni trogen
Sulfur
Ash Analysis, wt %
Do! omi te
MgCOa
CaCOa
Total
Calcite
CaCOS
Total CaCOs
Ca, wt %
Mg, wt %
Screen Size, Standard Mesh, wt %
+ 4
-4+8
-8+12
-12 + 20
-20 + 40
-40 + 80
-80
7
1/4" x 0
36.9
13.9
2.5
1.2
82.4
0.73
4.45
17.65
2.35
0.64
0.86
11.4
11.1
2275"

12.5
23.6
9.42
2.69
13.32
49.66
12.04
12.02
5.73
3.63
3.60
19
1/4" x 0
34.2
12.9
2.5
1.2
83.4
1.49
4.35
16.33
2.24
0.64
0.75
8.9
11.9
2U78"

13.8
25.7
10.28
2.88
4.88
38.82
14.42
17.06
9.43
6.76
8.63
                            27
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Sorae of the key process variables evaluated in the pilot plant program were:

     o    Bed temperature
     o    Solids residence time (bed depth and solids circulation rate)
     o    Gas residence time (superficial  velocity)                         :
     o    Ca/S mole ratio
     o    Flue gas oxygen concentration
     o    Raw shale/spent shale ratio
     o    Single stage and two stage combustion               •

During single stage combustion tests, all  combustion air flows through the
fluid bed and superheated steam is used to pneumatically convey retorted
solids to the combustor via the transfer line.  In this mode,  the bed is
normally oxygen-rich.

During two stage combustion tests, combustion air to the combustor is used  as
follows.  First, combustion air to the bed is reduced until  the flue  gas
oxygen concentration becomes zero.  At this condition of running oxygen
deficient in the bed, NOX drops to minimum values and CO and trace
hydrocarbons increase significantly.  Then, overfire air is  added to  the
retorted solids transfer line while simultaneously reducing  superheated steam
flow until the desired flue gas Q£ level is achieved.  Since the transfer line
does not enter the fluid bed, overfire air and superheated steam do not pass
through the bed.  Thus overfire air can only combust CO and  trace hydrocarbons
in the freeboard portion of the combustor.  If done correctly, NOX emissions
theoretically should not increase as the overfire air is added to the
combustor.

Bed temperature and solids residence time  are the key variables that  affect
carbonate decomposition, a factor which is essential  in obtaining efficient
sulfur absorption.  Because the combustor  is integrated with the retort, none
of the combustor operating conditions can  be considered to be  truly
independent variables.  That is, all operating conditions depend to some
extent on other conditions:

     o    Combustor temperature depends upon:
               Natural gas fl ow rate
               Natural gas composition
               Retort gas flow rate
               Retort gas composition
               Combustion air flow rate
               Retorted solids flow rate
               Retorted solids organic carbon content (which in turn  depends
               on shale feed rate and retort temperature)
               Temperatures of all streams entering the combustor.

     o    Retort temperature depends upon  heat carrier rate, shale feed rate,
          and their respective temperatures.

     o    Solids residence time depends upon:
               Retorted solids flow rate
               Combustor bed depth
                                  28
-------
     o    Gas  residence  time depends upon:
               Gas superficial  velocity  in the bed
               Combustor bed depth

     o    Superficial  gas velocity  depends upon:
               Combustion air  flow  rate
               Natural gas flow rate                          ,'
               Retort  gas fl ow rate

     o    Ca/S mole ratio depends upon:
               Retort  gas flow rate
               Retort  gas sulfur concentration
               Retorted solids flow rate and  calcium concentration

     o    Flue gas oxygen concentration  depends  upon:
               Combustion air  flow  rate
               Natural gas flow rate and composition
               Retort  gas flow rate and  composition
               Retorted solids flow rate and  organic carbon concentration
               Combustion efficiency
               Carbonate decomposition

Since superheated steam was used to pneumatically convey  retorted solids to
the combustor, the steam flow  rate  will  affect the wet  flue gas composition,
but will not affect the dry flue gas composition.  Also,  since the steam
discharges solids near the top of the  bed and not into  the bed, the steeim does
not pass through the bed and  so does not affect  gas superficial velocity or
cause dilution of the  gases in the  bed.

Due to the interdependence of  one variable on another,  a  parametic study where
one condition at a time is varied while  holding  all other conditions constant
was not possible.

Because a large number of tests were planned to  evaluate  the effect of process
variables on S02 and NOv emissions, complete  material balances were not
possible in the two week operating  period.   Instead, mass flow balances were
done on 44 "tests".  A test consisted  of the  following:   After the pilot plant
was started up and was run at steady state conditions for 1-2 hours, a test
was officially started.  Operating  data  on all streams  in and out of the
combustor were taken.   Such data included temperatures, pressures, orifice and
rotameter readings for the retorted solids and heat carrier screw RPM's,, and
mass flow rates calculated from the change  in the raw shale and baghouse ash
weigh hopper readings.  In addition, oxygen,  carbon monoxide, S0£ and NOX
readings on the four flue gas on-stream analyzers were  recorded along with the
sulfur concentration from the  retort  gas on-line analyzer.  While these data
were being taken, samples of raw shale,  retorted solids,  heat carrier,
baghouse ash, retort gas and  combustor flue  gas  were also taken.  A
description of the sampling procedures used for  these tests is given in
Section VI, as well as the analytical  methods used on the samples.
                                   29
-------
Recording the test operating data and obtaining the six samples would normally
•take about. 15 to 20 minutes.  When all  data and samples for a  test were
acquired, operating conditions were changed and the pilot plant and  combustor
allowed to line out at a new set of conditions.  When the combustor  was lined
out on these new conditions for 1-2 hours, a new test would start with the  .
taking of data and samples.

While operating data was logged for each of the 44 tests, solid and  gas
samples were taken on only 27 of these tests as shown in Table A-l.   Twenty
tests were selected for more complete evaluation by submitting the solids
samples for chemical analysis.  Eight of these twenty tests were analyzed
fairly completely and the other 12 were subjected to a more routine  analysis.
The solids and gases from three tests were analyzed for six trace elements
(arsenic, cadmium, mercury, beryllium,  lead and fluoride).  Large (5-gallort)
samples of baghouse ash were also collected during three other tests for
leaching studies at Colorado State University.
                                   30
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D.   Discussion of Results

Key operating conditions for the 44 tests  performed are  given  in Table A-2.
The range of operating conditions and process  variables  for these tests are
summarized below:

         TABLE 9.  RANGE OF OPERATING CONDITIONS  AND PROCESS VARIABLES
     Bed Temperature, °F                               1127-1558
     Freeboard Temperature, °F                         1273-1593
     Bed Pressure, Inches of Water                       66- 102
     Retorted Solids to Combustor, Ib/hr               2487-3615
     Raw Shale to Combustor, Ib/hr                        0- 133
     Retort Gas to Combustor, SCFM                        0-6.66
     HoS in Retort Gas, mole %                         0.43-9.28
     Bed Depth, ft                                     3.27-4.28
     Solids Residence Time, rain.                       8.07-18.72
     Gas Superficial Velocity, ft/sec                  3.78-7.20
     Gas Residence Time, sec                           0.46-1.13
     Flue Gas Oxygen, mole %                              0-6.25
     Carbonate Decomposition, %                        45.5-83.3
     Ca/S Mole Ratio                                   6.20-10.25
Over this range of conditions, flue gas composition and organic carbon
combustion efficiency ranged as follows:

          TABLE 10.  RANGE OF FLUE GAS COMPOSITION AND ORGANIC CARBON
                             COMBUSTION EFFICIENCY
     Flue Gas Composition                              Range
          S02, ppmv                                     1-38  ;
          NOX, ppmv                                    80-670
          CO, mole %                                   0.05-1.80
          Trace Hydrocarbons, ppmv                     51-8465
          Organic Carbon Combustion Efficiency %       57.5-100.0


Solid samples from 20 tests were analyzed for total  carbon, mineral
(carbonate) carbon, hydrogen, nitrogen and sulfur.   Organic carbon was
calculated by subtracting mineral carbon from total  carbon.   On eight of  these
20 tests, dolomite [CaMg(C03)23, calcite (CaC03) and calcium  and magnesium
contents were determined, as well .as particle size analysis.   Analyses  of
retorted solids, heat carrier and baghouse ash are  given in Tables A-3, A-4
and A-5.

Analysis of selected solids from Tests 7, 12 and 19  by X-ray  fluorescence is
shown in Table A-6.  The weight percent of fourteen  elements  is defined by
this analysis.
                                   31
-------
The range pf composition for thesfe solids is summarized below:

                     TABLE IT, RANGE OF SOLIDS COMPOSITION



                         Retorted Solids     Heat Carrier    Baghouse Ash
Mineral Carbon, wt%
Organic Carbon, wt%
Hydrogen, wt%
Nitrogen, wt%
Sulfur, wt%
Dolomite
MgC03, wtX
CaCOa, wt %
Calcite (CaCOa), wt%
Total CaCOa, wt%
f*a w4**y
wO 9 W 1*/<3
Mg, wt%
0.58
0.37
0.01
0.04
0.38

0.0 -
0.0 -
4.8 -
4.8 -
4.87
1.37
- 1.63
- 0.97
- 0.13
- 0.15
- 0.86

0.0
3.7
9.8
13.1
- 7.00
- 1.86
0.32 -
0.00 -
0.00 -
0.00 -
0.41 -

0.0 -
0.0 -
2.8 -
2.8 - 1
4.60 -
1.28 -
1.45
0.30
0.06
0.12
0.84

0.0
1.6
9.4
1.0
7.23
1.97 ,.
0.76 -
0.00 -
0.00 -
0.09 -
0.99 -

0.0
0.0
6.3
6.3
13.00
3.70
4.72
1.53
0.24
0.33
1.81 - .

- 5,.8
- 15..2
- 19..5
- 32,,4
- 16,,50
- 4.,48
In general, the particle size range of the retorted solids and  heat carrier
did not exhibit significant differences,  probably because the heat carrier
comprised about 85% of the retorted solids mass.   The  baghouse  ash, however,
was primarily -80 mesh material, with a mean diameter  of 7.9 to 10.4 microns.
A particle size analysis of the -80 mesh  fraction of the baghouse ash is also
given in Table A-5.

Natural gas and retort gas were used to supply part of the combustor heat.
Analyses of these gases is given in Table A-7.  Only one natural gas analysis
was taken since in the past the composition of this gas has been fairly stable.

Retort gas contained from 23 to 58 percent nitrogen due to the  use of nitrogen
purges around the retort.  On two tests (9 and 15), retort gas  became diluted
with air when the blower used to feed retort gas to the combustor developed a
negative suction pressure and air was drawn into the retort gas system.,
During these tests, oxygen and nitrogen comprised 78 to 86 percent of the gas.
To increase the sulfur concentration in the retort gas,  H£S  and COS  from
pressurized cylinders were injected into the retort gas  upstream  of  the
sampling point.  This increased the I^S concentration from an  initial
concentration of about 0.4 - 0.5 mole percent to 2 - 4 percent and in Test 8,
9,,3 percent.  The retort gas was spiked with F^S and COS in  33 of the 44 tests.
A continuous sulfur analyzer was also used on the retort gas.   However  this
analyzer did not perform consistently, and although  it was  calibrated once or
more each day, it tended to drift out of calibration quickly.   Therefore, data
from this analyzer is considered unreliable and is not used in  any  of the
correlations.  Data obtained from gas bomb samples was used instead.

Flue gas from the confcustor was analyzed continuously for oxygen, carbon
monoxide, sulfur dioxide and nitrogen oxides.  These analyses are given in
Table A-8 along with gas chroma tographic (GC) analyses.
                                  32
-------
Flue gas samples were also analyzed for trace hydrocarbons using a
icmization detector.

To calculate the flue gas mass flow rate, the molecular weight of the  wet flue
gas was needed.  Since the dry flue gas mole weight was available from GC
analysis, the moisture content of the flue gas was estimated using nitrogen  as
a tie element.

For those tests where flue gas GC analyses were not available, dry flue gas
nitrogen content and molecular weight values were estimated from tests with
similar operating conditions.
Mass flow rate balances for all 44 tests are given in Table A-9.
was calculated or estimated as follows:

                     TABLE 12.  MASS FLOW RATE MEASUREMENTS
                     Each  stream
                Stream
          Raw Shale to Retort
          Heat Carrier
          Retorted Solids

          Baghouse Ash
          Combustion Air
          Natural Gas
          Retort Gas
          Overfire Air
          Superheated Steam
          Raw Shale to Combustor
          Air/No Purges
          HgS/COS injected into Retort Gas
          Wet Flue Gas
How Measured or Estimated
     Weigh Hopper
     Calibrated Screw
     Heat Carrier Rate + (0.82  x
     Raw Shale Rate)
     Weigh Hopper
     Ori fi ce
     Orifice
     Orifice
     Orifice
     Orifice
     Calibrated Screw
     Rotameters
     Rotameters
     Estimated from Orifice  and
     Dry Flue Gas Analysis
Initially, it was planned to measure retorted solids flow by  a calibrated
screw, but due to the variable flow characteristics of this stream  it was
almost impossible to get a reliable flow rate determination.   Therefore, it
was decided to take the heat carrier rate,  which was fairly constant during  a
given test and add to that the estimated spent shale production rate  (0.82 x
raw shale rate) to get the retorted solids  flow rate.

In general, mass flow balances for all 44 tests were fairly good, as seen in
Table A-9.  The balance closure averaged 98.63 percent.   For  the 20 tests
subjected to solids analysis the balance closure averaged 98.35 percent.

Total carbon, mineral carbon, organic carbon and sulfur balances were
calculated for 20 tests using the mass flow rates from Table  A-9, the
elemental analyses for raw shale, retorted  solids, heat carrier and baghouse
ash and the natural gas, retort gas and flue gas compositions.   The total
carbon, mineral carbon and organic carbon balances are given  in Tables A-10,
A-ll and A-12, respectively.  Mineral carbon balances were forced to 100
                                  33
-------
percent closure by adjusting the mineral carbon in the flue gas.  Total carbon
balances had an average balance closure of 108.95 percent, and organic carbon
balances had an average closure of 115.41 percent.

Sulfur balances for the 20 selected tests are given in Table A-13.
Essentially no sulfur was found in the flue gas.  Sulfur in the baghouse ash
was fairly constant while sulfur in the heat carrier varied in a manner
similar to the retorted solids.  Sulfur balance closure averaged 105.17
percent.

Nitrogen accountability in the solid streams and as flue gas NOX is shown in
Table A-14.  Only nitrogen in the solids and in NOX was considered, since
consideration of elemental nitrogen in the gas streams would have overshadowed
the nitrogen in the solid streams and flue gas NOX by several orders of
macinitude.  These tests showed that nitrogen in the feed converted to NOX
varied'from 0.6 to 19.2 percent, with an average conversion of 6.0 percent.

E.   Process Variable Correlations

The extent to which process  variables correlated with S02, NOX, CO and  trace
hydrocarbon emissions as well as to organic carbon combustion efficiency is
summarized in Table 13.   Decreasing oxygen concentration  in the flue gas
tended to increase S02 emissions.  Figure 8 shows the effect  of analyzer 0£ on
flue gas SO?.  Tests where  both  raw and  spent  shale were  fed  to the combustor
showed the highest SOe levels.   No difference  was seen  between single  stage
and two  stage  combustion, however.

Decreasing oxygen concentration tends  to decrease NOX emissions,  as shown  in
Figure  9.  Staged combustion did not  show a  reduction in  NOX  emissions  over
single stage  combustion as  had been expected.

This unexpected  result may  be due to  the burning  of fines in  the  oxygen-rich
freeboard  generating  significant quantities  of NOX.   Some points  to consider
 are:

      o    The nitrogen rich fines (baghouse  ash)  contain  an average of 27
           percent of  the nitrogen in  the solids fed to  the combustor  even
           though the  fines only account for  15 percent  of the retorted solids
           fed.

      o    Higher temperatures in the  freeboard due to the burning of  fines (up
           to 300°F higher)  would mean greater reactivity  of the fines.

      o    The smaller particle size of the fines could result in increased
           combustion rates.

      o    Gas residence times in the freeboard can be two to three times the
           gas residence time in the bed.

      o    The freeboard generally contains some excess oxygen, and as seen in
           Figure 9, NOX tends to increase as oxygen concentration increases.

 Decreasing oxygen concentration increased CO emissions as shown in Figure 10.
 As oxygen concentration nears zero percent, CO levels increase dramatically.
                                    34
-------
GC 02
Analyzer 02
GC 02
Analyzer 02
GC 02
Analyzer 02
GC 02
GC 02
Solids
Solids
Solids
       Residence Time
       Residence Time
       Residence Time
Bed Organic Carbon
Ash Organic Carbon
Flue Gas CO
Flue Gas S02
                   TABLE 13.   PROCESS VARIABLE CORRELATIONS
                    Variables Which Produced A Correlation
versus       Flue Gas S02
versus       Flue Gas S02
versus       Flue Gas NOX
versus       Flue Gas NOX
versus       Flue Gas CO
versus       Flue Gas CO
versus       Flue Gas Trace Hydrocarbons
versus       Baghouse Ash Organic Carbon
versus       Flue Gas S02
versus       Fl ue Gas NOX
versus       Flue Gas CO
versus       Organic Carbon Combustion Efficiency
versus       Organic Carbon Combustion Efficiency
versus       Flue Gas NOX
versus       Flue Gas NOy
                Variables Which Did Not Produce A Correlation
GC 02                    versus
Bed Organic Carbon       versus
Ash Organic Carbon       versus
Solids Residence Time    versus
Gas Residence Time       versus
Geis Residence Time       versus
Gas Residence Time       versus
Gas Residence Time       versus
Fluid Bed Temperature    versus
Fluid Bed Temperature    versus
Fluid Bed Temperature    versus
Fluid Bed Temperature    versus
Ca/S Mole Ratio          versus
C/N Mole Ratio           versus
                                     Organic Carbon Combustion Efficiency
                                     Flue Gas NOX
                                     Flue Gas NOX
                                     Organic Carbon Combustion Efficiency
                                     Fl ue Gas S02
                                     Flue Gas NOX
                                     Flue Gas CO
                                     Organic Carbon Combustion Efficiency
                                     Flue Gas S02
                                     Flue Gas NOX
                                     Flue Gas CO
                                     Organic Carbon Combustion Efficiency
                                     Flue Gas S02
                                     Flue Gas NOX
                                 35
-------
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          38
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The effect of oxygen concentration on trace hydrocarbons  is  shown in Figure
IT.  Trace hydrocarbons also increase dramatically as oxygen concentration
approaches zero.

As oxygen concentration decreases below two percent,  S02,  CO,  and trace
hydrocarbon emissions increase significantly.   Thus,  two  percent 03  is felt to
be a minimum for controlling these emissions from a spent  shale  combustor.

Decreasing oxygen concentration also tends to increase the organic carbon
content of the baghouse ash, as shown in Figure 12.  However,  oxygen
concentration did not correlate with organic carbon combustion efficiency.

As the solids residence time in the combustor decreases,  $62 emissions
increase (Figure 13), NOX emissions tend to decrease  (Figure 14)  and CO
emissions tend to increase (Figure 15).  Although there is considerable
scatter in the NOX and CO data, general trends are apparent.  Solids residence
time did not correlate with organic carbon combustion efficiency.

Neither gas residence time nor bed temperature correlated  with $62,  NOX, CO or
organic carbon combustion efficiency.  The scatter in the  plot of fluid bed
temperature vs. S02 emissions is shown in Figure 16.

Dependent variables which were found to correlate are bed organic carbon vs.
organic carbon combustion efficiency (Figure 17) and baghouse ash organic
carbon vs. organic carbon combustion efficiency (Figure 18).  However, these
correlations would be expected since organic carbon contents of  both solids
streams used to calculate organic carbon combustion efficiency.   The ash
organic carbon vs. combustion efficiency (Figure 18)  shows two separate
correlations, one for single stage combustion and one for two stage
combustion.  Other dependent variables that could be cross-correlated were CO
vs. NOX and S02 vs. NOX.

At: the high Ca/S ratios studied in this program, no effect was seen  on S02
emissions over the range of 6.2 to 10.2 Ca/S mole ratio.   It is  speculated
that at low ratios an increase in S02 emissions might be  observed.

Increasing the organic carbon/nitrogen ratio in the fluid bed would  be
expected to decrease NOX emissions.  No such correlation  was found,  however.
                                  39
-------
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                                       47
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F.   Trace Element Sampling and Analyses

     This section describes and discusses the sampling and analyses
of selected process streams for the following trace elements:
arsenic, cadmium, mercury, beryllium, lead and fluorine as
fluoride.  The streams sampled and analyzed were raw shale,  retorted
solids, heat carrier, baghouse ash, retort gas and combustor flue
gas.  Oil and retort water were not analyzed.  The primary goal was
to determine the trace element concentration in the retort gas and
flue gas.

     Previous investigators (7-18) have measured trace element
concentrations in various process streams from laboratory and
simulated in-situ retorts.  Mercury concentrations of from less than
0.2 to 8,200 ug/m3 have been reported in retort gases.   Cadmium
concentrations of from 1 ug/m3 (ref.14) to over 1000 ug/m3 (ref. 15)
have been reported in retort gases.  Arsenic concentrations  from 5
(ref. 16) to 300 ug/m3 (ref. 18) have been reported in gas streams
from oil shale retorts.  No data have been reported on  beryllium in
oil shale processing gas streams.

Sampling Procedures

     The sampling train for both the retort gas and flue gas
consisted first of a cold-finger trap (ice bath)  followed by an
in-line filter holder containing a 0.4 micron filter followed by an
irnpinger containing 150 ml of 5% HMOs.   Mext in 1ine was a second
impinger containing 150 ml of 5% NaOH solution, followed by  two
activated charcoal  traps in series.  A recent publication's)
reported that activated charcoal is an efficient collector for
mercury if the flow rate is kept at one liter per minute or  tess.  A
schematic of the train is shown in Figure 19.  Quality Control/
Quality Assurance are discussed in Section VI.

     Retort gas and combustor flue gas were sampled during three
pilot plant tests;  Tests 7, 12 and 19C.  Retorting and  combustion
temperatures were varied for these three tests; average temperatures
are given below:
                              Average              Average
Test Number             Retorting Temp,  "F     Combustion Temp, °F

    7                         1015                  1550    '
   12                          930                  1430
   19C                         860                  1240

    Gas sampling times were approximately one  hour with a total of
about 30-40 liters of gas collected.  Temperature of both gas
streams at the point of sampling  was  ambient,  due to cooling of the
gases from heat losses.  Some of  the  more volatile metals probably
condensed out in various parts of the pilot plant due to this
cooling.

                                  48
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     During  Test  12, an aqueous solution containing 3 g/L Hg and 3
 g/L  Cd (prepared from the nitrate salts) was pumped into the bottom
 of the combustor to determine their fate in the combustor.   The
 amount of mercury and cadmium fed in the spike represents about 4700
 times  and 170 times, respectively, the amounts of mercury and
 cadmium entering the system in the raw shale during the 2 hour spike
 period.

     Corresponding composite samples of raw shale, retort discharge,
 heat carrier and baghouse ash were taken during the tests.   !

 Analytical  Methodology

     The aqueous  portion of the cold traps,  which were very  small
 (the maximum collected during any test was  only 1.1 gram) and  the
 HMOs and NaOH solutions were digested with  HNOs according to EPA
 procedures.  Mercury was determined by cold vapor atomic absorption,
 arsenic by  hydride generation AA, cadmium,  lead and beryllium  by
 furnace AA  and fluoride by specific ion electrode.

     The filter samples, which contained very little particulate
 matter (the largest amount in any run was 0.1  gram) were cut in
 half.   One  half  was digested with HMOs and  arsenic, cadmium, lead,
 beryllium and fluoride determined as described above.   The  other
 half of the filter was digested for mercury analysis according to
 the  EPA procedure which uses sulfuric acid, nitric acid, potassium
 permanganate and  potassium persulfate as the digestion media.
 Mercury was then determined by cold vapor AA.

     The  activated charcoal samples were digested in HN03 and
 arsenic,  cadmium, lead, beryllium and fluoride determined as
 described above.   A separate aliquot of the charcoal was digested
 with sulfuric acid, nitric acid,  potassium  permanganate and
 potassium persulfate;  this digest was used  for the mercury  analysis.

    The  raw shale, retorted solids,  heat carrier and baghouse  ash
 were digested in HNp3  and arsenic, cadmium, lead and beryllium
 determined as described above.  For the mercury analysis the samples
 were treated the same as the activated charcoal samples.  A lithium
metaborate  fusion followed by specific  ion  electrode determination
 was  done  for the fluoride analysis.

 Discussion of Results

         A summary of  the analytical  results for all the elements
 analyzed are given in  Table 14.   Due  to the low levels  of mercury
 found  in  the raw shale (0.025 and 0.015 ppm) and an increase in mass
 of the retorted solids  and heat carrier of  between 5 and 6.5 times
 that of the raw shale,  the mercury level  in these streams was
generally below the detection  limit,  except for Test 12 in which
mercury and cadmium salts were injected into the combustor.  It is
quite possible  that mercury volatilized during retorting or
 combustion condensed on the cooler parts of the plant equipment.
Previous work has reported difficulties in  collecting and analyzing
mercury in retort gases^).


                                  50
-------
      TABLE 14.   TRACE ELEMENT ANALYSES FROM PILOT PLANT TESTS 7, .12 AMD 19C
Test 7 (High Temp.)
Raw Shale, ppmw
Retorted Solids, ppmw
Heat Garner, ppmw
Baghouse Ash, ppmw
Retort Gas, ug/m3
Flue Gas, ug/m3
Test 12 (Med. Temp, Metals
Retorted Solids, ppmw
Heat Carrier, ppmw
Baghouse Ash, ppmw
Retort Gas, ug/m3
Flue Gas, ug/m3
Test 19C (Low Temp. )
Raw Shale, ppm
Retorted Solids, ppm
Heat Carner, ppm
Baghouse Ash, ppm
Retort Gas, ug/m3
Flue Gas, ug/m3
ppmw - parts per million
(a) - Values appear higf
„ "9
0.025
0.005
0.005
0.009
4
4
Spike)
0.011
0.067
2.1
106
24,720

0.015
0.005
0.005
0.019
4
22
by weight
i but are
Cd
TJ75"9
0.87
0.86
0.70
184
26

23
24
51
264
25

0.69
1.4
1.6
9.1
2
15
*
reporte
As
"5F
36
47
90
11 5,355(a)
8

37
31
92
88,103(a)
9

54
42
35
72
49
9
d as measure
Pb
"76
24
22
20
2,546(a)
113

24
22
24
146
6

30
27
26
25 ,
9
9
d. A DOS:
Be
TJ755
0.48
0.68
1.02
2
9

0.64
0.52
1.08
2
2

0.68
0.64
0.56
1.24
2
2
;ible
F
W
240
230
700
35
35

330
290
890
35
35

730
410
350
780
35
35

         explanation for those  high values is that As and Pb from prior runs had
         condensed within the system and was flushed out by this high
         temperature run.

    A summary of material  balances for the elements is given in Table
15.  Complete balances  are given  in later sections.  Mat en* a T
balances could only be  calculated around the fluid bed combustor
because the shale oil and  pyrolysis water were not analyzed. h
                                 51
-------
       TABLE 15.  SUMMARY OF ELEMENTAL BALANCES AROUND COMBUSTOR
% Recovery

Test 7
Test 12
Test 19C
Hi
(a)
43(b)
(c)
Cjd
95
65(b)
(c)
•As
139
98
87
Pb_
88
91
91
jte
148
89
94
F_
119
105
90
(.a)  Mercury values were so low that no balance could be determined.
(b)  Includes metal spike.
(c)  Not meaningful, due to unknown amount of metals still  present
     from the Hg and Cd spike during Test 12, about forty-eight hours
     before Test 19C.
     Table 16 gives the percentage of trace elements present in the
raw shale feed which was found in the retort gas and flue gas.   In
Test 12 the amount of mercury and cadmium added to the combustor is
included as part of the total.  Note that although the trace elements
were fed to the combustor, significant amounts of mercury (41.3
percent) were found in the retort gas.  Mercury and possibly some
cadmium were probably deposited on the heat carrier in the combustor
and recycled back to the retort where they were re-volatilized.
                                  52
-------
      TABLE 16.  PERCENTAGE OF TRACE  ELENENTS PRESENT  IN  RAW ;SHALE
                    FOUND IN RETORT GAS AND FLUE GAS
                                % Found In          % Found  In
Test 7                          Retort Gas           Flue Gas
Hg                              ND                 ND
Ccl                               27
As;                              13.8               0.03
Pb                               0.65              0.8
Be                              ND                 2.7
F                               ND                 ND

Test 12

Hg(a)                           0.01               41.3
Cd(a)                           0.02               0.005
As                              11.2               0.03
Pb                              0.03               0.04
Be                              ND                 ND
F                               ND                 ND

Test 19C

Hg(b)                           --                 --
Ccl(b)
As                              0.004              0.03
Pb                              0.001               0.7
Be                              ND                 ND
F                               ND                 ND
ND = Not detected - below limit of detection  which was  4  ug/nr*.
(a)  Includes metal spikes.
(b)  Not applicable due to unknown amount of  Hg and  Cd  still  present
     from the spiking of these metals in Test 12 spike.
                                  53
-------
    Detailed elemental balances around the combustor for the  three
tests are given in Tables A-15 to A-20.  A mercury balance for Test
7 could not be obtained due to very low concentrations  of mercury in
the raw shale feed and limitations on the detection limits of the
retorted solids which was the feed to the combustor.  The only
mercury detected was in the baghouse ash which contained 251 of  the
mercury present in the raw shale.  It is reasonable to  assume, based
on previous investigator's work, that at least 75% or more of the
mercury volatilized and deposited on cool  surfaces in various parts
of the pilot plant.  However, it should be remembered that due to
the large increase in mass of the retorted solids  compared to the
raw shale feed, any mercury present in the retorted solids could
have been below the detection limits.  In Test 12, (metals spike to
the combustor) only 43% of the mercury was recovered from the spike
addition.  Of the 43% recovered, 96% of it was in  the combustor  flue
gas.  The high recovery in Test 19C probably reflects the residual
amount of mercury still present in the pilot plant from the spike in
Test 12.

    A good cadmium balance (95%) was obtained in Test 7.   In  the
metals spike, Test 12, only 65% of the cadmium was recovered, the
balance probably being deposited on cool surfaces  in  the  pilot
plant.  The high recovery in Test 19C again reflects  the  residual
metals present from Test 12.

    The high arsenic recovery of 139% in Test 7 is probably due  to
re-volatilization of some arsenic deposited from previous  tests.
The retorting temperature in this test was 1015°F  which  is
considerably higher than normal  and the combustor  temperature was
1550°F which was the highest in the test program.

    The lead material  balances for the three  tests are  fairly
consistent at 90% recovery.                                   '

    The reasons for the high beryllium recovery of 148%  in Test 7
and fluoride recovery of 119% in Test 7 are unknown at  this time,
but may be similar to that for arsenic.
                                  54
-------
     Listed  in Table  17  are  the percentages of the total amount of
 the elements that were  found  in the various scrubber devices.  No
 elements were found  in  the  filter samples or the second activated
 charcoal  samples.

     Where detected,  about 75  to 90% of the mercury was found in the
 first  stage charcoal and about 10 to 25% in the nitric acid scrubber.

     Essentially all  of  the  cadmium in the flue gas was found in the
 first  stage charcoal except for Test 19C where all of the cadmium
 was found in the  caustic scrubber.  In the retort gas, 100% of the
 cadmium in Test 7 was found in the nitric acid scrubber.  In Test 12
 about  80% was in  the acid scrubber, about 10% in the caustic
 scrubber and 10% in  the charcoal.

     In the  flue gas  of Test 7 and 19C, all of the arsenic was found
 in  the charcoal.  In Test 12, about 80% of the arsenic in the flue
 gas was found in  the charcoal and the balance in the cold trap.  In
 the retort gas of Tests 7 and 12, all  of the arsenic was found in
 the cold trap.  In Test 19C, about 70% of the arsenic in the retort
 gas was found in the charcoal  and the balance in the caustic
 scrubber.

     In the flue gas of Tests 7 and 19C, all  of the lead was found in
 the caustic scrubber.  In the flue gas of Test 12, all  of the lead
 was found in the cold trap.

     In Test 7, about 60% of the lead in the  retort gas was found  in
 the acid scrubber and the balance in the caustic scrubber.   In Test
 12,  the opposite was true,  about 65% of the  lead in the retort gas
was in the caustic scrubber and the balance  was  found in the acid
 scrubber with a small amount in the cold trap.   In Test 19C, all  of
 the lead in the retort gas  was found in the  cold trap.

    Only one sample contained beryllium,  that being the flue gas  of
Test 7.  All of the beryllium  was found on the charcoal.      ;

    No fluoride was detected in any of the samples.

    No attempt was made  to  determine  the  species  of the elements
present in the gas streams,  but it is  reasonable to assume  that,
under the wide  variation in  operating  conditions  of the three  tests,
different'species will  form  and will be collected in different
scrubbing media.

    Any future  sampling  of  this type should  use  at least all  of the
scrubbers that were  used in  this  study.
                                  55
-------
TABLE 17.  PERCENT DISTRIBUTION OF TOTAL ELEMENT CONCENTRATION  IN
              GAS STREAM FOUND IN VARIOUS SCRUBBERS

Flue Gas
Hg
Cd
As
Pb
Be
F
Retort Gas
Cd
As
Pb
Be
F

Fl ue Gas
Hq
Cd
As
Pb
Be
F
Retort Gas
Hcj
Cd
As
Pb
Be
F

Flue Gas
Hg
Cd
As;
Pb
Be
F
Retort Gas
Cd
As;
Pb
Be
F

Col d Trap
w «•
3.5
—
0.4
--
—

—
99.95
0.2
--
__


0.03
--
17.4
100.0
__ . .
--

6.8
0.2
99.88
1.4
-—
—


—
—
—
—
--
—

— —
__
100.0
. --
.._
Test 7
HNOa Scrubber NaOH Scrubber
•-. .mi
—
-_ —
99.6
-- __
—

100.0 —
0.02
61.0 38.8
— _._
__ __
Test 12

22.76 1.09
_ _ _ _
__ __
—
__ __
-_ --

17.7
81.7 9.1
0.08
32.9 65.8
__ __ •
—
Test 19C

11.8
100.0
__ __
100.0
__ __
— - --

11 ii
31.7
__ __
__ __
__ __

First Stage
Charcoal
..
96.5
100. 0
__
100.0
— ;


0.04
__ .
__
__


76.11
100.0
82.6
__
__
-._

75.5
9.1
0.04
M M
__
-- '

:
88.2
--
100.0
__ :
__
__ ;

••••
68.3
__
__
— - :
 Not Detected.
                               56
-------
           V.  RECOMMENDATIONS  ON  DESIGN AND OPERATION OF A FLUID BED
                 COMBUSTOR WHICH OPTIMIZES S0£ AND NOX CONTROL

Based on the pilot plant data obtained in this study, fluid bed operating
conditions are recommended to optimize S0£ and NOX control.  In general,
conditions that favor low S0£ emissions also favor low CO and trace
hydrocarbon emissions but do not favor low NOX emissions.  The general ranges
of operating conditions which produced reasonable results both from an
operating and emissions viewpoint  are  given below.  Conditions used in the
Phase I conceptual design work are shown for comparison  in Table 18.

       TABLE 18.  COMPARISON OF FLUID  BED COMBUSTOR OPERATING CONDITIONS
Operating Conditions
Fluid Bed Temperature, F
Solids Residence Time, min
Gas Residence Time, sec.
Gas Superficial Velocity, ft/sec
Flue Gas Oxygen, mole %
Carbonate Decomposition, %
Ca/S Mole Ratio
Raw Shale/Spent Shale Ratio
Recommended Conceptual Design
llbU to IbbO
11 to 14
0.5 to 1.0
7+
2+
45+
6+
3/97
13bU
14
1.0
5.0
3.0
60
23
7/93
This comparison indicates that the conditions chosen  for the conceptual design
are reasonable and in most cases conservative.

Gas residence time did not affect S02,  NOX,  CO or trace hydrocarbon emissions
over the range evaluated in this program.  With this  in mind, gas velocities
could likely be increased to 10 feet per second or more, which begins to
approach the operating range of fast or circulating fluid beds.  However,
further testing would be needed to determine the upper limits of gas velocity
in the bed.


Nitrogen oxide emissions are minimized at the lowest  possible oxygen
concentration and solids residence time.   Oxygen concentrations approaching
zero are needed to reduce NOX levels to less than 100 ppmv.

Mixing raw shale into the spent shale appears to lower NOX levels to a range
of 160-210 ppmv, while S02 concentrations range from  about 10 to 40 ppmv.
Test 19C, where only raw and spent shale were combusted (no retort gas was
burned), resulted in the following emissions:
Test 19C Emissions
CO
S02
NOX
Trace Hydrocarbons
U.27 mol
11 ppmv
160 ppmv
388 ppmv
This test closely approximates the conceptual  design as  seen  in Table  19 and
is an optimum with regard to all emissions.
                                  57
-------
 TABLE 19.  COI^ARISON OF TEST 19C OPERATING  CONDITIONS  WITH CONCEPTUAL DESIGN
          Operating Conditions           Test 19C      Conceptual Design

     Fluid Bed Temperature, °F            1227              1350
     Solids Residence Time, mln              9.39              14
     Gas Residence Time, sec                 0.87               l.o
     Gas Superficial Velocity, ft/sec         4.41               5.0
     Flue Gas Oxygen, mole %                 2.6                3.0
     Carbonate Decomposition,  %            55.3               60
     Ca/S Mole Ratio                       10.25              23
     Raw Shale/Spent Shale Ratio        2.7/97.3                7/93
     Organic Carbon Combustion
      Efficiency, %                        88.9*              94


     *  Since fluid bed temperature  did  not affect NOX emissions, the optimum
     emission and combustion efficiency would  likely be obtained at a higher
     bed tempeTaTure that 1227°F.

Si'nee tests with high sulfur input in both retort gas (Test 8) and natural gas
(Test 13) produced only 2 ppmv of  S0£ in  the  flue gas, it is felt that
combustion of retort gas and raw shale together would not result in higher S02
emissions than shown in Test 19C.  That is, it does not appear that sulfur
content of the inlet gas has much  effect  on S0£ emissions.
                                 58
-------
                   VI.  QUALITY ASSURANCE/QUALITY CONTROL
A.  QA Objectives and Performance

    1. Objectives

         Table  19A  summarizes  QA  objectives  with  regard  to precision,
accuracy  and  completeness  for the key emissions analyses as discussed in
the QA/QC plan.

         Arsenic   determination   using  hydride  generation  and  mercury
determination  using  cold  vapor  are  difficult  for solid samples at low
levels  and  the  wide  accuracy range reflects the difficulties with these
matrices.    Beryllium  and lead determination methodology will be selected
dependent on the levels found early in the testing regimen.

         Trace    metal    scan    using    X-Ray   Fluorescence   provides
semi-quantititve  data.    Precision of the counting is excellent, however,
interferences  limit  the  accuracy of the individual samples.  Comparative
values   obtained  with  similar  solid  products  can  be  very  reliable.
Standardization  methods  for  individual  components  can  be applied for
selected metals.  Audit .values are expected to be within limits listed.

         Hydrogen  sulfide  and  organic  sulfur  species analyses are raost
affected  by  sampling  procedures  and equipment.  Failure to purge sample
containers  properly, shale dust in sample streams, leaking containers, and
gas  instability  are  potential  problems  which  must be recognized.  The
analyses  for organic sulfur compounds are difficult for streams containing
large hydrogen sulfide concentrations since this peak can mask the others.

         On-stream  analyses  of gaseous emissions (oxygen, sulfur dioxide,
nitrogen  oxides  and  carbon  monoxides)  are  most  affected by potential
problems   with   the   sample   line,   e.g.?  plugging  with solids  and
condensates.    Filters,  condensers  and  traps  have  been   installed  to
minimize such problems.

    2.  Performance

         QA  performance with regard to sampling and analytical methodology
are  discussed Un the following sections B through D for. each  sample and/or
analysis employed.

         QA  performance in the key emissions data areas was generally very
good  and  met  the  defined objectives.  Results on mercury emissions were
out;side  the  range  of  objectives  probably due to the very  low levels of
mercury encountered (in many cases mercury was below detection limits).

                                   59
-------
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-------
B,   Sampling Methodology and Results

Six solid/gas streams were routinely sampled as  follows.  Each stream is
identified diagramatically in Figure 7.

          Stream                        Description
            1                           Raw Shale  Feed
            2                           Retorted Solids
            3                           Heat Carrier
            4                           Baghouse Ash
            5                           Retort Gas to Combustor
            6                           Flue Gas

A list of sample analyses and frequency  of  analysis for each stream is given
in Table 20.                                               ;

1.   Sampl i ng Me th o do! ogy

     a.   Raw Shale Feed Samples (Stream 1)

Raw shale samples were taken at the inlet to the steam heated screw conveyor
feeding the retort.  These relatively cool  samples (50°F to 160°F) were taken
as follows:
                                                           i
     1.   Open sample point valve and drain a quantity of solids to assure a
          clean flow path.  Discard these solids.
     2.   Keeping valve open, drain solids  into  a  one quart sample can.
     3.   Close sample point valve.   Seal sample can with lid and label can.

              TABLE 20.  SAMPLE ANALYSES AND FREQUENCY OF ANALYSIS
Raw
Analysis Shale
Fischer Assay S
Mo i sture S
Total Carbon S
Mineral Carbon S
Hydrogen S
Nitrogen S
Sulfur S
Mineral Breakdown S
Particle Size S
GC Scan
Trace Hydrocarbon
Continuous Sulfur Analyzer
02, NOX, CO, S02
Continuous Analyzers
Arnmoni a
Ca, Mg S
Retorted
Solids


R
R
R
R
R
NR
NR






NR
Heat
Carrier


R
R
R
R
R
NR
NR






NR
Baghouse Retort
Ash Gas


R
R
R
R
R
NR
NR
R

R



NR
Flue
Gas









R
R


R
NR

S = Spot analysis done for two tests
NR = Non-routine analysis  done for  3 to 8 tests
R = Routine analysis done  for  20  tests

                                 61
-------
      b-    Retorted  Solids and Heat Carrier Samples (Streams 2 and 3)

 These relatively hot solids (about 900°F for the retorted solids and 1100 to
 11350 F for the heat carrier) required special sampling procedures.   Each
 solids sample point was provided with a ball or plug valve which when opened
 allows solids to drain by gravity into the solids sampler.  The solids sampler
 consisted  of a one  foot length of two inch diameter pipe closed at  the bottom
 and  fitted with a ball valve at the top end.  Purge connections were provided
 on the sampler pipe at both top and bottom.  To take a solids sample these
 steps were followed:

      1.    Purge sampler with nitrogen.
      2.    Open sample point valve and drain a quantity of solids to assure a
           clear flow path.  Discard these solids.
      3.    Connect sampler, open sampler valve and sample point valve and allow
           solids to drain into sampler.
      4.    Close sampler and sample point valves and disconnect sampler,,
      5.    Quench sampler in water.
      6.    Open sampler valve and dump contents of sampler into sample can,
           seal can with lid and label  can.

      c.    Baghouse Ash Samples (Stream 4)

These samples were taken at the flue gas inlet to the baghouse.   A  three inch
sample line with a ball valve was teed into the flue gas  line.   Warm flue gas
 (about 300°F to 400°F) containing combusted fines was sampled as follows:

      1.   The sample valve was opened and dusty gas  vented for about 1C)
           seconds to clean the line.
      2.   The valve was closed and the open end of a 6-inch diameter baghouse
          bag was tied to the end of the sample line.
      3.   The valve was opened and dusty flue gas  was vented through the bag
           for about 5-10 minutes,  or until  about one  quart of solids was
          collected.
      4.   The valve was closed and the solids collected in the bag  were  put
          into a quart sample can.   The  can was sealed with a lid and labeled.

      d.   Retort Gas and Flue Gas Samples (Streams 5  and  6)

These gas  samples were taken in glass  flow-through bombs  having  glass
stopcocks on either end.   Sample's  were taken  through  sampling valves  on
1/4-inch tubing.   Samples were taken as  follows:

     1.   The sample valve was  opened  and gas was  allowed  to  flow for a  few
          seconds to assure adequate gas flow and  pressure.
     2.   The valve was closed  and the sample bomb was  attached  to  the sample
          tubing  with  tight fitting  clear plastic  tubing.
     3.   The stopcocks were  both  opened and  then  the  sample  valve  and flow
          was verified by allowing the gas  to  bubble  through  a clear  plastic
          water bottle.   If no  flow was  observed,  the  stopcocks were  cleaned
          with  a  small  wire.
     4.   After good gas flow was  established,  the gas  was  allowed  to flow
       .   through  the  bomb for  a minimum of five minutes and  a maximum of ten
          minutes.

                                  62                         ,               •:
-------
     5.   To maximize gas pressure in the bomb and prevent air  contamination,
          the downstream stopcock was closed first,  followed  by the  upstream
          stopcock and finally the sample valve.
     6.   The sample bomb was removed from the plastic  tubing and labeled.


     2.   Sampling Results

No problems were encountered sampling the raw shale,  retorted solids, heat
carrier and baghouse ash samples.

The status of the retort gas sampling for the 44  tests  can be summarized as
follows:

                              Retort Gas Sampling

                                             Number  of  Tests
               Sulfur Analysis Only                T
               Complete GC Analysis               22
               No Sample Taken                    12
               Bad Samples                          2
               No Retort Gas to Combust or           7
                    TOTAL
Of 25 retort gas samples taken,  only two were improperly  taken so that no
analysis was possible.

Retort gas samples were taken near the point where  the  retort gas entered the
combustor.  On five tests,  the pulsating pressure in  the  fluid bed caused
large pressure spikes which forced solids from the  bed  into  the retort gas
line.  When retort gas samples were taken some shale  dust entered the glass
sample bombs and absorbed all of the H£S and part or  all  of  the C02-  On one
test, so much dust entered  the bomb that no  analysis  was  possible.

The status of flue gas sampling  during the 44 tests is  as follows:

                                Flue Gas Samples

                                             Number of  Tests
               Complete GC  Analysis                ?5
               No Sampl e Taken                     11
               Bad Samples  (air  in sample)          5
                    TOTAL                        ~PT
                                  63
-------
C,   Analytical Methodology and Results

     1.   Laboratory Analyses

Mineral Carbon (Coulometrlc Analysis)

Essentially all of the solid samples analyzed for mineral carbon were done in
duplicate.  A blank and reference sodium carbonate sample were analyzed before
and after every seven to ten samples.   Representative  duplicate values are
given in Table 21.

            TABLE 21.  SUMMARY OF DUPLICATE MINERAL CARBON ANALYSES
Sample No.
541/3
54174
54175
54176
54183
54184
54185
Sample Description
Baghouse Ash
Raw Shale
Heat Carrier
Retorted Solids
Retorted Solids
Heat Carrier
Baghouse Ash
Dupl icates, wt% ;
2.24, 2.ZU
4.42, 4.48
0.34, 0.32
0.50, 0.66
0.85, 0.79
0.34, 0.32
0.98, 0.96
Total Carbon, Hydrogen and Nitrogen (Elemental Analyzer)

All of the solid samples analyzed for total carbon, hydrogen and nitrogen were
done in duplicate.   A blank is  run  once per batch of samples and a reference
shale sample is run before and  after each four samples.  Representative
results are given in Table 22.

  TABLE 22.  SUMMARY OF DUPLICATE TOTAL CARBON, HYDROGEN AND NITROGEN ANALYSES
Sampl e No.
  54173
  54174
  54175
  54176
  54183
  54184
  54185
Sample Description
Baghouse Ash
Raw Shale
Heat Carrier
Retorted Solids
Retorted Solids
Heat Carrier
Baghouse Ash
                                              Duplicates, wt%
Total
2.33,
22.20
0.52,
1.27,
1.39,
0.26,
0.85,
L
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0.63
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0.05
0.06
0.01
0.10
                                 64
-------
Sulfur (X-ray Fluorescence)

All of the solid samples analyzed for total sulfur were done in duplicate.
Calibration standards for the x-ray analyses were prepared from synthetically
produced shale media and varying amounts of CaSCty.  Representative results  are
given in Table 23.

                TABLE 23.  SUMMARY OF DUPLICATE SULFUR ANALYSES
Sample No.
541 30
54136
54157
54128
54185
54135
Sampl e Descri ption
Heat Carrier
Heat Carrier
Retorted Solids
Baghouse Ash
Baghouse Ash
Retorted Solids
Duplicates, wt%
0.44, 0.44
0.55, 0.55
0.78, 0.79
0.99, 0.99
1.71, 1.72
0.66, 0.66
With each batch of samples, usually between 5 and 10,  a  spike was made to  the
sample and percent recovery determined.   Representative  results  are  given  in
Table 24.

                     TABLE 24.  SUMMARY  OF SPIKE RECOVERIES
Sample No.
54130
54157
54128
54185
54135
Sample Description
Heat earner
Retorted Solids
Baghouse Ash
Baghouse Ash
Retorted Solids
Duplicates, wt%
104.2, 99.2
108.4, 108.0
95.4, 94.6
94.1, 94.5
105.0, 106.7
Mole Percent Concentrations of Gases by Gas Chromatography

Linear calibration factors and ranges of concentrations are  determined  for
specific gas components found in retort gas and flue gas.  Calibration  factors
were determined by injecting known concentrations of the following  components:

          Hydrogen                      isoButane
          Oxygen                        normal  Butane
          Nitrogen                      isoButylene + Butene-1
          Carbon Monoxide               trans-Butene-2
          Carbon Dioxide                cis-Butene-2
          Hydrogen Sulfide              iso-Pentanes
          Methane                       normal  Pentane
          Ethane                        Pentenes
          Ethene                        normal  Hexane
          Propane                       normal  Heptane
          Propene

The method of analysis was gas chromatography using thermal  conductivity as
the detection system.  The quantitation method  was external  standard
calibration using certified calibration gases.   Daily calibration checks are
made by analyzing standard gases as samples.

                                  65
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Total Trace Hydrocarbons by Gas Chromatography

Total trace hydrocarbons in the flue gas were determined by gas  chromatography
with flame ionization as the detection method.  A calibration curve giving
response factors and showing linearity was established at the beginning  of  the
test period by analyzing known concentrations of hydrocarbon mixtures in the
part per million range.  Hydrocarbon mixtures were certified and traceable  to
EPA standards.  A daily calibration check point was determined by analyzing an
EPA calibration standard mixture and chromatographic conditions  adjusted to
keep the check point on the initial calibration curve.      ',

Sample and calibration gases were injected using gas tight syringes and
quantitated using the external standard calibration method.   Standard
hydrocarbon mixtures were analyzed and calculated as total  butane.   All
samples were reported on a normal butane equivalent.

Determination of Carbonyl Sul fide, Hydrogen Sulfide, Carbon Pisulfide, Sulfur
Dioxide, Methyl Mercaptan and Ethyl Mercaptan by Gas Chromatography Using
Flame Photometric Detection

Trace sulfur component analysis in the part per million range was determined
using gas chromatography and flame photometric detection.   Calibration curves
and response factors were established for each component at the  beginning of
the testing period.  Calibration gases in the part per mill ion range were
prepared using permeation tubes and diffusion wafers certified and  traceable
to NBS materials.  A daily calibration check of EPA certified sulfur dioxide
gas at 50 ppm was used to insure detector response stability throughout  the
testing period.

Calibration gases and samples were injected using gas tight syringes.  Sulfur
species were detected using a flame photometric detector with a  sulfur
specific optical filter of 394 nanometers.

Particle Size                                               ',  '              •

Particle size analysis by screening using 4, 8, 12, 20, 40 and 80 mesh screens
were done on selected solids "samples.   One  quart samples were run through a
splitter until about 500g were obtained.  The 500g was screened  and the
retains on each screen were weighed and particle size distribution
calculated.  The -80 mesh material was further analyzed on an automatic
particle size analyzer in triplicate.   Results for a sample  of baghouse  ash
are given below:

     -80 Mesh in Microns, wt%                Sample No.  54173

     -176 + 125                              0, 0, 0
     -125 +88                              0, 0, 0       -
      -88 +  62                              0, 0, 0        -
      -62 +44                              0, 0, 0
      -44 +  31                              0, 0, 0
      -31 +  22                              10.7, 9.9, 9.4
      -22 +  16                              10.3, 8.1, 8.6
      -16 +  11                              13.9, 13.2, 12.2
      -11 + 7.8                              21.4, 22.0, 22.1
     -7.8 + 5.5                              16.3, 16.9, 17.6
     -5.5 + 3.9                              11.9, 13.1, 13.1
     -3.9 + 2.8                              7.4,  8.1, 8.2
     -2.8 + 1.9                              7.7,  8.4, 8.6

                                  66
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     2.   Continuous Analyzers

A continuous total sulfur analyzer was used on the retort gas.  This  analyzer
did not perform consistently, and although it was  calibrated once  or  more each
day, it tended to drift out of calibration quickly.   Data from  this analyzer
was considered unreliable and was not used in any  of  the  correlations.

Continuous oxygen, carbon monoxide, sulfur dioxide and  nitrogen oxides
analyzers were used on the flue gas.   These analyzers performed well  and had
essentially no downtime.   These analyzers were calibrated every day or every
other day using zero and  span gases traceable to NBS  standards.  The  flue gas
was conditioned by a filter, chiller and silica gel dryer before injection
into the analyzers.  A comparison of analyzer oxygen  concentration with gas
cnromatography oxygen content is shown in Figure 20.
                                 67
-------
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                                        68
-------
D.   Trace Element Methodology and Results

Sampling and analyses for the trace elements mercury, cadmium, arsenic, lead
beryllium and fluoride are given in a previous section.

For the atomic absorption analyses of mercury  (cold vapor), arsenic (hydride
generation), cadmium, lead and beryllium (furnace), reagent blanks and
calibration standards were run before and after every fifth sample.  Various
types of samples were spiked with  known  amounts of analyte and the percentage
recovery determined.   Results are  given  in Table 25.

                     TABLE 25.   SUMMARY  OF SPIKE RECOVERIES
     Sample No.
     626-53-3
     626-53-4
     626-53-5
     54173
     Sample Mo.
     662-47-3
     54174
    Sample No.
    54174
    54554
    Sample No.
    626-54-4
    54553
    SamplI e No.
    54553
    626-47-3
    Sampl e No.
    54174
            Mercury

 Sample Description
 Charcoal         """"
 Acid Scrubber
 Caustic Scrubber
 Charcoal
 Baghouse Ash

            Cadmi urn

 Sample Description
 caustic Scrubber
 Acid Scrubber
 Raw  Shale

           Arsenic

 Sample Description
 Raw  Shale
 Retorted Solids

             Lead

 Sampl e  De sc ri p t i o n
Acid  Scrubber
 Acid  Scrubber
 Raw Shale

          Beryllium

Sample Description
Raw Shale
Acid Scrubber

           Fluori de

Sample Description
Raw Shale
  Recovery of Spike
        9"5
        95
       117
       103
        92
% Recovery of Spike
        77
        82
% Recovery of Spike
       TTO
        98
  Recovery  of Spike
        53"""
        76
        79
  Recovery  of  Spike
     :  55
      112
  Recovery  of Spike
        75"
                                  69
-------
Duplicate analyses were also run on various samples.   Results  are  given  in
Table 26*.

                    TABLE 26.  SUMMARY OF DUPLICATE ANALYSES
     Sample No.
     b2b-bO-4
     662-54-6
     54556
     Sample No.
     626-49-4
     626-53-3
     626-54-4
     626-49-5
     626-53-5
     Sample No.
     b2b-49~3
     626-49-4
     626-53-3
     626-53-4
     626-49-5
     626-53-5
     Sam pi e No.
     br2~6~-49-3
     626-49-4
     626-53-3
     626-49-5
     Sample No.
     bZb-49-3
     626-49-4
     626-53-3
     626-53-4
     626-49-5
     626-53-5
     Sample No.
                             Mercury

                  Sample Description
                  Caustic Scrubber Di ge s t
                  Charcoal
                  Baghouse Ash

                             Cadmium

                  Sample Description
                  Acid Scrubber Digest
                  Caustic Scrubber Digest
                  Acid Scrubber Digest
                  Caustic Scrubber Digest
                  Charcoal
                  Charcoal

                             Arsenic

                  Sample Description
                  Acid Scrubber Digest
                  Caustic Scrubber Digest
                  Acid Scrubber Digest
                  Caustic Scrubber Digest
                  Charcoal Digest
                  Charcoal Digest

                              Lead

                  Sample Description
                  Acid Scrubber Digest
                  Caustic Scrubber Digest
                  Acid Scrubber Digest
                  Charcoal Digest

                           Beryl 1 i urn
                         Duplicates
                         /b, bu ng/25ml
                         173, 152 ng/g
                         20, 18 ng/g
 Duplicates
  rU.uui, u.uOl ug/ml
 0.001, 0.001 ug/ml
 0.001, O.OOT ug/ml
        0.001 ug/ml
        0.007 ug/ml
                         0.001
                         0.010
                         0.004, O.OQ2 ug/ml
                         Duplicates ,
                                ng/bml
                                ng/5ml
                                ng/5ml
                         5.8, 5.0 ng/5ml
                         0, 7 ng/5ml
                         42, 32 ng/5ml
                         Duplicates
                         U.UU2, U.OOl  ug/ml
                         0.001, 0.001  ug/ml
                        ^-0.001, 0.001  ug/ml
                        •^0.001,^0.001  ug/ml
                 Sample Description
                 Acid Scrubber Digest
                 Caustic Scrubber Digest ^0.001, -c.0.001
                 Acid Scrubber Digest
                 Caustic Scrubber Digest -CO.001
                 Charcoal Digest
                 Charcoal Digest
                         Duplicates
                                  17.001
                                  0.001
                         .0.001,<0.001
                                    001
                                    001
      .,<0,
<0.001,<0.
<0.001,<0.001
             ug/ml
             ug/ml
             ug/ml
             ug/ml
             ug/ml
             ug/ml
    545
ft
5?
           Fluoride

Sample Description
Retorted Solids
 Duplicates
p
y,
      3bb ug/g
                                  70
-------
                           VII.   REFERENCES

1,.   Denver Research Institute,  "Pollution Control Technical Manual:
     Modified In-situ Oil  Shale  Retorting Combined with Lurgi
     Surface Retorting,"  U.S.  Environmental Protection Agency,
     EPA-600/8-83-004 (NTIS PB83-200-121), 1983.  Cited on pp. 1, 17.

2,.   Denver Research Institute,  "Pollution  Control Technical
     Manual: Tosco II Oil  Shale  Retorting with Underground Mining,"
     U.S. Environmental Protection Agency, EPA-600/8-83-003 (NTIS
     PB83-200-212), 1983.  Cited  on page  1.

3,.   McCarthy, H.E., "Fluidized  Bed  Combustion of Oil Shale",
     Sixteenth Oil Shale  Symposium Proceedings, Colorado School of
     Mines, April 13-15,  1983, Golden, Colorado, pp. 469-476.  Cited
     on page 3.

4,,   Hall, R. N., "Hydrocarbon Solids Process - HSP Technology",
     AIChE Spring National  Meeting,  Anaheim, California, June 8,
     1982.  Cited on page 6.

5,,   Denver Research Institute,  Private  correspondence with Kishor
     Gala.  Cited on page  17.

6.,   Denver Research Institute,  Pollution Control Technical Manual:
     Lurgi Oil Shale Retorting With  Open Pit Mining," U.S.
     Environmental Protection  Agency, EPA-600/8-83-005 (NTIS
     PB83-200-204), 1983.   Cited on  page 17.

7.,   Fox, J. P., "Distribution of Mercury during Simulated Iri-situ
     Oil Shale Retorting",  Environmental Science and Technology, 19,
     pp 316-322, April, 1985.  Cited on  page 48.

8.,   Hodgson, A. T., et.  a!.,  "Mercury  Mass Distribution During
     Laboratory and Simulated  In-situ Oil Shale Retorting", Lawrence
     Berkeley Laboratory,  Berkeley,  CA, February, 1982, Report
     LBL-12908.  Cited on  pp. 48,  50.

9.,   Hodgson, A. T., Pollar, M.  J.,  Brown, N. J., "Mercury Emissions
     from a Modified In-situ Oil  Shale Retort", Atmos. Environ. 18,
     pp. 247-253, 1984.  Cited on page 48.

1C).  Olsen, K. B., "Characterization of  Mercury, Arsenic and
     Selenium in the Product Streams of  the Pacific Northwest
     Laboratory 6-Kg, Retort", Rich!and, Washington, Prepared for
     the U.S. DOE, Contract DE-AC06-76RL01830, July, 1985.  Cited on
     page 48.

                                   71                        I
-------
                     VII.   REFERENCES  (continued)

11.  Fruchter, J. S., et.  a!.,  "Elemental Partitioning in
     Aboveground Oil Shale Retort Pilot Plant", Environmental
     Science and Technology,  November, 1980.  Cited on page 48.

12.  Fox, J. P., et. al.,  "The  Partitioning of As, Cd, Cu, Hg, Pb
     and Zn During Simulated  In-situ Oil Shale Retorting", 10th
     Annual Oil Shale Symposium,  Golden, Colorado, 1977.  Cited on
     page 48.

13.  Fox, J. P., et. al.,  "Partitioning of Major, Minor and Trace
     Elements During Simulated  In-situ Oil Shale Retorting in a
     Controlled State Retort",  12th Annual Oil Shale Symposium,
     Golden, Colorado, 1979.  Cited on page 48.

14.  Rinaldi, G. M., Delaney, J.  L. and Hedley, W. H., Environmental
     "Characterization of  Geokinetics1 In-Situ Oil Shale Retorting
     Technology", Two Volumes,  U.S. EPA Report EPA 600/7-81-021 a
     (1981) Main Report and EPA 600/7-81-021b (1981) Appendices,
     NTIS PB 81 163727 and PB 81  163735 respectively.  Cited on page
     48.

15.  Hodgson, A. T., unpublished  data on Cd in gases from a
     Fischer-Assay-type oil shale retort, Lawrence Berkeley
     Laboratory, Berkeley, CA (1985).  Cited on page 48.

16.  Ondov, J.  M. and others, "Measurements of Potential Atmospheric
     Pollutants in Off-Gases  from the Lawrence Livermore National
     National Laboratory's 6-Tonne Retort, Experiment L-3", Lawrence
     Livermore National Laboratory Report UCRL-53265 (1982).  Cited
     on page 48.

17.  Fruchter,  J. S., Wilkerson,  C. L., Evans, J. C., Sanders R. W.,
     and Abel,  K. W.,  "Source Characterization Studies at the Paraho
     Semiworks Oil Shale Retort",  Battelle Pacific Northwest
     Laboratory Report PNL-2945 (1981).  Cited on page 48.

18.  UNOCAL, "Environmental Monitoring Plan Outline, Parachute Creek
     Shale Oil  Program Phase  I Advanced Technology Program", Report
     Submitted to Synthetic Fuels Corporation (1985).  Cited on page
     48.

19.  Dummarey,  R., Dams, R.,  Hoste, J., "Comparison of the
     Collection and Desorption Efficiency of Activated Charcoal,
     Silver and Gold for the  Determination of Vapor-Phase
     Atmospheric Mercury", Anal.  Chem., 1985,  pp. 2638-2643.  Cited
     on page 48.                                             :

                                  72
-------
APPENDIX A
    73
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89
-------
                     TABLE A-9. OVERALL MASS FLOW BALANCES
RUN NO.
INPUTS, LB/HR
RETORTED SOLIDS
STEAM
AIR
NAT'L GAS
RETORT GAS
OVERFIRE AIR
PURGES
RAW SHALE
TOTAL INPUTS
OUTPUTS, LB/HR
HEAT CARRIER
BAGHOUSE ASH
FLUE GAS
TOTAL OUTPUTS
BALANCE CLOSURE, X
1
2487.00
156.80
683.40
15.90
16.40
0.00
10.30
0.00
3369.80
2091.00
368.00
873.10
3332.10
98.88
1A
2662.00
178.50
679.90
15.70
21.10
0.00
10.50
0.00
3567.70
2247.00
420.00
914.20
3581.20
100.38
2
2601.00
179.80
730.30
11.90
19.90
0.00
11.30
0.00
3554. 20
2195.00
377.00
895.20
3467.20
97.55
3
3404.00
138.90
802.00
10.30
14.40
0.00
11.10
0.00
4380.70
2927.00
479.00
913.80
4319.80
98.61
4
3352.00
153.00
702.90
8.30
17.50
0.00
11.80
0.00
4245.50
2927.00
408.00
843.20
4178.20
98.41
5
3395.00
122.50
784.60
11.60
14.90
0.00
11.10
0.00
4339.70
2927.00
464.00
981.90
4372.90
100.77
6
3343.00
127.80
695.60
12.00
14.30
0.00
11.80
0.00
4204.50
2927.00
330.00
827.10
4084.10
97.14
6A
3345.00
135.50
788.30
11.40
14.00
0.00
11.80
0.00
4306.00
2927.00
391.00
938.40
4256.40
98.85
6B
3343.00
128.50
700.70
13.80
14.10
0.00
11.80
0.00
4211.90
2927.00
441.00
853.60
4221.60
100.23
, 6C
3158.00
147.30
676.70
18.00
14.00
0.00
11.80
0.00
4025.80
2718.00
464.00
830.90
4012.90
99.68
60
3062.00
172.40
564.70
15.60
13.70
0.00
11.80
0.00
3840.20
2718.00
385.00
765.00
3868.00
100.72
RUN NO.
                  6E
                        6R
                                    7A
                                         7AA
                                                7B
                                                      7C
                                                            70
                                                                              10P
INPUTS, LB/HR
RETORTED SOLIDS
STEAM
AIR
NAT'L GAS
RETORT GAS
OVERFIRE AIR
PURGES
RAW .SHALE
TOTAL INPUTS
OUTPUTS, LB/HR
HEAT CARRIER
BAGHOUSE ASH
FLUE GAS
TOTAL OUTPUTS
BALANCE CLOSURE, S

3014.00
148.10
600.90
14.80
13.70
0.00
11.80
0.00
3803.30

2718.00
222.00
843.90
3783.90
99.49

3014.00
148.10
600.90
14.80
12.50
0.00
11.80
0.00
3802.10

2718.00
222.00
782.70
3722.70
97.91

2598.00
137.00
803.30
16.20
26.10
0.00
12.60
0.00
3593.20

2195.00
340.00
988.40
3523.40
98.06

2620.00
139.30
803.30
16.20
24.40
0.00
12.60
0.00
3615.80

2195.00
360.00
1008.60
3563.60
98.56

2620.00
136.30
803.30
16.00
27.60
0.00
12.60
0.00
3615.80

2195.00
360.00
1033.90
3588.90
99.26

2620.00
139.40
679.20
13.70
29.40
0.00
12.60
0.00
3494.30

2195.00
303.00
850.60
3348.60
95.83

2535.00
152.90
795.70
16.20
23.80
0.00
12.60
0.00
3536.20

2195.00
278.00
997.30
3470.30
98.14

2587.00
133.20
879.70
16.00
20.90
0.00
12.60
0.00
3649.40

2247.00
260.00
1077.00
3584.00
98.21

2603.00
135.30
768.80
16.00
20.60
0.00
12.60
0.00
3556.30

2195.00
335.00
980.80
3510.80
98.72

2907.00
154.20
767.20
16.40
18.40
0.00
11.80
0.00
3875.00

2613.00
302.00
997.00
3912.00
100.95

3040.00
143.00
656.60
18.00
17.50
0.00
11.80
0.00
3886.90

2613.00
391.00
844.90
3848.90
99.02
                                 (continued)
                                           90
-------
                                       TABLE A-9 (continued)
RUN NO.
INPUTS, LB/Hli
RETORTED SOLIDS
STEAM
AIR
NAT 'I GAS
RETORT GAS
OVERFIRE AIR
PURGES
RAW SHALE
TOTAL INPUTS
OUTPUTS. LB/HR
HEAT CARRIER
BAGHOUSE ASH
FLUE GAS
TOTAL OUTPUTS
BALANCE CLOSURE,*
10
3013.00
117.40
655.50
18.00
17.40
152.90
11.80
0.00
3986.00
2613.00
368.00
942.90
3923.90
98.44
11
2921.00
74.30
695.60
13.40
24.90
217.30
11.80
0.00
3958.30
2509.00
347.00
1078.70
3934.70
99.40
11A
2510.00
169.40
565.10
15.60
18.80
0.00
11.80
0.00
3290.70
2038.00
387.00
870.90
3295.90
100.16
11B
2510.00
161.30
565.10
15.50
18.90
195.40
11.80
0.00
3478.00
2038.00
444.00
917.60
3399.60
97.75
11C
2530.00
92.80
583.30
16.40
17.20
360.00
11.80
0.00
3611.50
2091.00
423.00
1043.10
3557.10
98.49
11D
2511.00
92.10
609.40
16.70
14.50
362.30
11.80
0.00
3617.80
2091.00
399.00
1072.00
3562.00
98.46
12
2867.00
17.00
692.50
17.10
26.10
298.20
11.80
0.00
3929.70
2509.00
381.30
1039.40
3929.70
100.00
12A
2703.00
17.00
704.90
17.20
28.00
300.40
11.80
0.00
3782.30
2300.00
430.70
1051.60
3782.30
100.00
13
2728.00
0.00
711.00
16,40
16.00
318.00
11.80
0.00
3801.20
2300.00
360.00
1042.60
3702.60
97.41
14
3581.00
154.50
563.60
14.10
23.30
0.00
11.70
0.00
4348.20
3188.00
357.00
780.70
4325.70
99.48
15
3311.00
97.40
483.50
6.90
28.60
114.80
11.80
0.00
4054.00
2822.00
335.00
704.50
3861.50
95.25
RUN NO.                16     17A     17B     17C     17D      18     19A      198     19C     20P      20
INPUTS, LB/HR
RETORTED SOLIDS
STEAM
AIR
NAT'L GAS
RETORT GAS
OVERFIRE AIR
PURGES
RAW SHALE
TOTAL INPUTS
OUTPUTS, LB/HR
HEAT CARRIER
BAGHOUSE ASH
FLUE GAS ,
TOTAL OUTPUTS
BALANCE CLOSURE,*

3615.00
134.50
540.10
18.00
20.10
0.00
11.80
0.00
4339.50

3198.00
450.70
690.80
4339.50
100.00

3482.00
162.70
616.60
14.50
0.00
0.00
11.80
133.10
4420.70

3031.00
436.00
820.40
4287.40
96.98

3504.00
162.70
711.00
14.80
0.00
0.00
11.80
133.10
4537.40

3031.00
434.00
945.90
4410.90
97.21

3535.00
157.50
764.90
13.70
0.00
0.00
11.80
133.10
4616.00

3031.00
491.00
996.00
4518.00
97.88

3490.00
168.70
704.90
13.70
0.00
137.30
11.80
133.10
4659.50

3031.00
475.00
1109.60
4615.60
99.06

3525.00
151.70
751.30
13.70
21.90
0.00
12.60
0.00
4476.20

3031.00
461.00
979.60
4471.60
99.90

3454.00
156.50
631.10
11.60
0.00
228.90
11.80
94.70
4588.60

3031.00
389.00
1035.50
4455.50
97.10

3454.00
152.70
583.40
16.70
0.00
228.90
11.30
94.70
4541.70

3031.00
348.00
958.50
4337.50
95.50

3454.00
115.10
583.40
16.70
0.00
228.90
. 11.80
94.70
4504.60

3031.00
389.00
957.50
4377.50
97.18

3400.00
135.40
575.10
16.80
20.00
0.00
11.80
0.00
4159.10

3031.00
399.00
735.10
4165.10
100.14

3400.00
115.50
501.30
17.40
20.00
285.30
11.80
0.00
4351.30

3031.00
318.00
930.40
4279.40
98.35
                                                   91
-------
                      TABLE A-10. TOTAL CARBON BALANCES
RUN NO.
INPUTS, LB/HR TOT C
RETORTED SOLIDS
STEAK
AIR
NAT'L GAS
OVERFIRE AIR
RETORT GAS
PURGES
RAW SHALE
TOTAL INPUTS
OUTPUTS, LB/HR TOT C
HEAT CARRIER
BAGHOUSE ASH
FLUE GAS
TOTAL OUTPUTS
BALANCE CLOSURE,*
2

33.81
0.00
0.00
7.39
0.00
8.37
0.00
0.00
49,57

18.00
10.33
41.54
69.87
140.94
4

53.63
0.00
0.00
5.15
0.00
7.67
0.00
0.00
66.46

24.00
15.10
40.30
79.40
119.48
6

61.85
0.00
0.00
7.45
0.00
4.80
0.00
0.00
74.09

35.12
12.71
36.31
84.14
113.56
7

30.40
0.00
P. 00
10.06
0.00
12.13
0.00
0.00
52.58

12.07
7.62
47.25
66.93
127.30
8

35.40
0.00
0.00
9.93
0.00
8.07
0.00
0.00
53.40

7.24
3.25
49.73
60.22
112.76
10

44.59
0.00
0.00
11.17
0.00
6.78
0.00
0.00
62.55

9.41
10.60
46.58
66.58
106.45
11

40.31
0.00
0.00
8.32
0.00
11.15
0.00
0.00
59.78

8.78
2.67
63.43
74.88
125.27
11A

51.71
0.00
0.00
9.68
0.00
7.29
0.00
0.00
68.68

11.62
14.55
43.02
69.19
100.74
11B

51.20
0.00
0.00
9.68
0.00
8.04
0.00
0.00
68.93

14.47
14.83
48.72
78.02
113.20
11C

50.09
0.00
0.00
10.18
0.00
7.32
0.00
0.00
67.59

12.96
12.35
51.11
76.43
113.07
RUN N0-             HD      12     13     14     17A    17B    17C     18    19C     20
INPUTS, LB/HR TOT C
RETORTED SOLIDS
STEAM
AIR
NAT'L GAS
OVERFIRE AIR
RETORT GAS
' PURGES
RAW SHALE
TOTAL INPUTS
OUTPUTS, LB/HR TOT C
HEAT CARRIER
BAGHOUSE ASH
FLUE GAS
TOTAL OUTPUTS
BALANCE CLOSURE, X .

59.26
0.00
0.00
10.37
0.00
5.63
0.00
0.00
75.25

14.22
11.37
52.53
78.12
103.81

61.93
0.00
0.00
10.61
0.00
11.03
0.00
0.00
83.57

18.32
5.49
60.70
84.51
101.12

47.47
0.00
0.00
10.18
0.00
6.76
0.00
0.00
64.41

11.96
3.74
53.38
69.09
107.26

85.94
0.00
0.00
8.75
0.00
6.95
0.00
0.00
101.65

49.10
22.31
37.86
109.27
107.50

74.17
0.00
0.00
9.00
0.00
0.00
0.00
27.53
110.69

32.13
26.60
46.76
105.49
95.30

65.88
0.00
0.00
9.19
0.00
0.00
0.00
27.53
102.59

33.95
17.79
54.67
106.41
103.73

61.51
0.00
0.00
8.50
0.00
0.00
0.00
27.53
97.54

18.79
15.66
60.16
94.61
97.00

51.47
0.00
0.00
8.50
0.00
8.53
0.00
0.00
68.50

13.03
15.95
32.91
61.90
90.36

77.37
O.OO1
0.00;
10.37
0.00
0.00
0.00
19.58
107.32

39.40'
11.24
55.82
106.47'
99.20;

80.92
0.00
0.00
10.80
0.00
7.79
0.00
0.00
99.51

47.28
9.16
44.10
100.54
101.04
                                         92
-------
                    TABLE A-11. MINERAL CARBON BALANCES
RUN KO.
INPUTS, LB/HR HIN. C
RETORTED SOLIDS
STEAM
AIR
NAT'L GAS
OVERFIRE AIR
RETORT GAS
PURGES
RAW SHALE
TOTAL INPUTS
OUTPUTS, LB/HR HIN. C
HEAT CARRIER
BAGHOUSE ASH
FLUE GAS
TOTAL OUTPUTS
BALANCE CLOSURE,*
2
20.29
0.00
0.00
0.00
0.00
1.19
0.00
0.00
21.48
18.00
9.76
0.00
27.76
129.28
4
37.21
0.00
0.00
0.00
0.00
1.11
0.00
0.00
38.32
24.00
15.10
0.00
39.10
102.03

49.
0.
0.
0.
0.
0.
0.
0.
50.
35.
12.
2.
50.
100.
6
48
00
00
00
00
75
00
00
22
12
71
40
23
01
7
15.07
0.00
0.00
0.00
0.00
1.14
0.00
0.00
16.20
7.24
7.55
1.41
16.20
99.99
8
21.34
0.00
0.00
0.00
0.00
0.82
0.00
0.00
22.17
7.24
3.25
11.69
22.18
100.06
10
27.12
. 0.00
0.00
0.00
0.00
0.80
0.00
0.00
' 27.92
9.41
10.01
8.50
27.92
100.00
11
24.24
0.00
0.00
0.00
0.00
1.08
0.00
0.00
25.33
8.78
2.67
13.88
25.33
100.02
11A
27.61
0.00
0.00
0.00
0.00
1.20
0.00
0.00
28.81
11.62
10.29
6.90
28.81
100.01
11B
28.87
0.00
0.00
0.00
0.00
1.25
0.00
0,00
soai
10L19
12.65
7.27
30.11
100.01
11C
29.35
0.00
0.00
0.00
0.00
1.14
0.00
0.00
30.48
6.69
10.36
13.42
•30.47
99.97
RUN NO.             11D     12     13     14    17A    17B     17C      18    19C     20
INPUTS, LB/HR HIN. C
RETORTED SOLIDS
STEAH
AIR
NAT'L GAS
OVERFIRE AIR
RETORT GAS
PURGES
RAW SHALE
TOTAL INPUTS
OUTPUTS, LB/HR HIN. C
HEAT CARRIER
BAGHOUSE ASH
FLUE GAS
TOTAL OUTPUTS
BALANCE CLOSURE,*

34
0
0
0
0
0
0
0
35

9
10
15
35
99

.90
.00
.00
.00
.00
.92
.00
.00
.83

.83
.33
.66
.82
.99

34.40
0.00
0.00
0.00
0.00
1.17
0.00
0.00
35.58

13.05
4.31
18.42
35.78
100.55

28.92
0.00
0.00
0.00
0.00
0.72
0.00
0.00
29.64

9.43
2.74
17.47
29.64
100.00

56.58
0.00
0.00
0.00
0.00
1.29
0.00
0.00
57.87

42.08
16.85
0.00
58.93
101.84

49.79
0.00
0.00
OiOO
0.00
0.00
0.00
5.79
55.58

29.10
20.27
6.21
55.58
100.00

39.60
0.00
0.00
0.00
0.00
0.00
0.00
5.79
45.39

32.13
14.71
0.00
46.84
103.21

41.36
0.00
0.00
0.00
0.00
0.00
0.00
5.79
47.15

18.79
13.70
14.66
47.15
100.00

32.43
0.00
0.00
0.00
0.00
1.59
0.00
0.00
34.02

13.03
14.29
6.69
34.01
100.00

53.88
01 00
0.00
0.00
0.00
0.00
0.00
4.12
58.00

35;77
10.54
11,69
58.00
100.00

55.42
0.00
0.00
0.00
0.00
1.45
0.00
0.00
56.87

43.95
8.87
4.05
56.87
100.01
                                       93
-------
                         TABLE A-12.  ORGANIC CARBON BALANCES
RUN NO.                 2       4      6       7       8      10      II     11A     118      11C

INPUTS,LB/HR ORG. C
  RETORTED SOLIDS
  STEAM
  AIR
  NAT'L GAS
  OVERFIRE AIR
  RETORT GAS
  PURGES
  RAW SHALE

TOTAL INPUTS          28.10   28.14   23.87    36.38   31.23   34.63    34.45   39.88   38.81    37.11
13.53
0.00
0.00
7.39
0.00
7.19
0.00
0.00
16.42
0.00
0.00
5.15
0.00
6.56
0.00
0.00
12.37
0.00
0.00
7.45
0.00
4.05
0.00
0.00
15.33
0.00
0.00
10.06
0.00
10.99
0.00
0.00
14.06
0.00
0.00
9.93
0.00
7.25
0.00
0.00
17.48
0.00
0.00
11.17
0.00
5.99
0.00
0.00
16.07
0.00
0.00
8.32
0.00
10.07
0.00
0.00
24.10
0.00
0.00
9.68
0.00
6.10
0.00
0.00
22.34
0.00
0.00
9.68
0.00
6*79
0.00
0.00
20.75
0.00
0.00
10.18
0.00
6.18
0.00
0.00
OUTPUTS, LB/HR ORG.
HEAT CARRIER
BAGHOUSE ASH
FLUE GAS
TOTAL OUTPUTS
BALANCE CLOSURE,*
C
0
0
41
42
149

.00
.57
.54
.10
.85

0.00
0.00
40.30
40.30 •
143.24

0.00
0.00
33.91
33.91
142.08

4.83
0.07
45.84
50.73
139.46

0.00
0.00
38.04
38.04
121.78

0.00
0.59
38.08
38.67
111.65

0.00
0.00
49.55
49.55
143.82

0.00
4.26
36.12
40.38
101.26

4.28
2.18
41.45
47.91
123.43

6.27
1.99
37.69
45.95
123.84
   NO.                11D      12       13      14     17A      178     17C      18      19C      20
INPUTS, LB/HR ORG. C
RETORTED SOLIDS
STEAM
AIR
NAT'L SAS
OVERFIRE AIR
RETORT GAS
PURGES
RAVI SHALE
TOTAL INPUTS
OUTPUTS, LB/HR ORG.
HEAT CARRIER
BAGHOUSE ASH
FLUE GAS
TOTAL OUTPUTS
BALAKCE CLOSURE,*

24.36
0.00
0.00
10.37
0.00
4.70
0,00
0.00
39.42
C
4.39
1.04
36.87
42.30
107.28

27.52
0.00
0.00
10.61
0.00
9.86
0.00
0.00
48.00

5,27
1.18
42.28
48.73
101.54

18.55
0.00
0.00
10.18
0.00
6.04
0.00
0.00
34.77

2.53
1.01
35.91
39.45
113.45

29.36
0.00
0.00
8.75
0.00
5.67
0.00
0.00
43.78

7.01
5.46
37.86
50.34
114.98

24.37
0.00
0.00
9.00
0.00
0.00
0.00
21.74
55.11

3.03
6.32
40.55
49.91
90.56

26.28
0.00
0.00
9.19
0.00
0.00
0.00
21.74
57.20

1.82
3.08
54.67
59.57
104.15

20.15
0.00
0.00
8.50
0.00
0.00
0.00
21.74
50.39

0.00
1.96
45.50
47.46
94.19

19.03
0.00
0.00
8.50
0.00
6.95
0.00
0.00
34.49

0.00
1.66
26.22
27.88
80.86

23.49
0.00
0.00
10.37
0.00
0.00
0.00
15.46
49.32

3.64
0.70
44.13
48.47
98.27

25.50
0.00
0.00
10.80
0.00
6.34
0.00
0.00
42.64

3.33
0.29
40.05
43.67
102.41
                                              94
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                                TABLE A-13.  SULFUR BALANCES
RUN NO.

INPUTS,LB/HR SULFUR
  RETORTED SOLIDS
  STEAM
  AIR
  NAT'L GAS
  OVERFIRE AIR
  RETORT GAS
  PURSES
  RAW  SHALE

TOTAL  INPUTS
                                                                10
                                                                        11
                                                                                11A
                                                                                        118
RUN NO.
                       11D
                                12
                                        13
                                                14
                                                        17A
                                                                17B
                                                                        17C
                                                                                 18
                                                                                        19C
                                                                                                11C
9.88
0.00
0.00
0.00
0.00
0.41
0.00
0.00
20.11
0.00
0.00
0.00
0.00
0.30
0.00
0.00
26.41
0.00
0.00
0.00
0.00
0.15
0.00
0.00
15.33
0.00
0.00
0.00
0.00
1.60
0.00
0.00
13.54
0.00
0.00
0.00
0.00
2.16
0.00
0.00
16.27
• 0.00
0.00
0.00
0.00
0.77
0.00
0.00
15.48
0.00
0.00
0.00
0.00
0.36
0.00
0.00
12,30
0.00
0.00
0.00
0.00
0.93
0.00
0.00
11.04
0.00
0.00
0.00
0.00
0.90
0.00
0.00
12.40
0.00
0.00
0.00
0.00
0.82
0.00
0.00
10.30    20.41    26.56   16.93   15.69    17.04    15.84    13.23    ll.;94    13,21
OUTPUTS, LB/HR SULFUR
HEAT CARRIER
BAGHOUSE ASH
FLUE GAS
TOTAL OUTPUTS
BALANCE CLOSURE,*
9.66
4.64
0.00
14.30
138.82
16.10
4.61
0.00
20.71
101.46
22.83
3.60
0.00
26.43
99.52
13.17
4.93
0.00
18.10
106.94
11.63
5.76
0.00
17.40
110.84
10.71
5.23
0.00
15.94
93.52
11.04
5.07
0.00
16.11
101.66
8.36
4.91
0.00
13.27
100.34

8.76
5.02
0.00
13.78
115.42

8.57
5.29
0.00
13.86
104.91
                                                                                                 20
INPUTS, LB/HR SULFUR
RETORTED SOLIDS
STEAM
AIR
NAT'L GAS
OVERFIRE AIR
RETORT GAS
PURGES
RAW SHALE
TOTAL INPUTS
OUTPUTS, LB/HR SULFUR
HEAT CARRIER
BAGHOUSE ASH
FLUE GAS
TOTAL OUTPUTS
BALANCE CLOSURE, %
12.05
0.00
0.00
0.00
0.00
0.71
0.00
0.00
12.77
8.99
4.91
0.00
13.90
108.86
15.48
0.00
0.00
0.00
0.00
1.16
0.00
0.00
16.64 .
11.04
5.45
0.00
16.49
99.12
13.91
0.00
0.00
0.00
0.00
2.40
0.00
0.00
16.31
10.35
6.52
0.00
16.87
103.39
30.80
0.00
0.00
0.00
0.00
1.07
0.00
0.00
31.87
26.78
3.86
0.00
30.63
96.13
25.42
0.00
0.00
0.00
0.00
0.00
0.00
1.00
26.42
22.73
4.32
0.00
27.05
102.39
23.13
0.00
0.00
0.00
0.00
0.00
0.00
1.00
24.12
20.00
4.90
0.00
24.91
103.25
17.32
0.00
0.00
0.00
0.00
0.00
0.00
1.00
18.32
13.94
5.65
0.00
19.59
106.93
17.63
0.00
0.00
0.00
0.00
0.64
0.00
0.00
18.27
14.25
5.16
0.00
19.41
106.24
17; 96
0.00
0.00
0.00
0.00
0.00
0.00
0.71
17.96
16.37
3i51
0.00
19188
110.70
19.72
0.00
0.00
0.00
0.00
0.59
0.00
0.00
20.31
15.46
3.43
0.00
18.89
93.03
                                                   95
-------
                CO

           0|   to

           CM   CM

                P-     CM
       •een or^k

       ojoj^cale
               ^-     CM
               f~     CM
                                      5    p-
               r-     CM
          p   a
               r—     CM
                                                            
-------
              TABLE A-15.   MERCURY BALANCES AROUND COMBUSTOR
Inputs Test 7
Retorted Sol ids, kg/hr 1178.1
Hg, mg/hr NO
Retort Gas, m3/hr 10.0
Hg, mg/hr ND
Metal Spike, mg/hr
Raw Shale, kg/hr
Hg, mg/hr
Total Hg In, mg/hr
Outputs
Heat Carner, kg/hr 995.6
Hg, mg/hr ND
Baghouse Ash, kg/hr 154.2
Hg, mg/hr 1.40
Flue Gas, n^/hr 410
Hg, mg/hr ND
Total Hg Out, mg/hr 1.40
Recovery, %
.*
Test 12
1300.4
14.30
9.8
1.04
23,166.0

23,181.34

1138.T
76.32
136.1
285.80
387
9566.40
9928.52
42.8
Test 19C
1566.7 '.
: ND


43.1
0.64
^0.64

1374.8
'< ND
157.8
3.00
398 8.76
11.76
1838
ND = Not detected.
                                       97
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TABLE A-16.  CADMIUM BALANCES AROUND COMBUSTOR
Inputs Test 7
Retorted Solids, kg/hr 1178.1
Cd, mg/hr 1.025
Retort Gas, m3/hr 10.0
Cd, mg/hr 0.002
Metal Spike, mg/hr
Raw Shale, kg/hr
Cd, mjj/hr
Total Cd In, mg/hr 1.027
Outputs
Heat Carn'er, kg/hr 995.6
Cda mg/hr 0.856
Baghouse Ash, kg/hr 154.2
Cds mg/hr 0.108
Flue Gas, m3/hr 410
Cd, mg/hr 0.011
Total Cd Out, mg/hr 0.975
Recovery, % 95
Test 12
1300.4
29.909
9.8
0.003
23.166

23,181.34

1138.1
76.32
136.1
285.80
387
9566.40
34.2652
64.6
Test 19C
1566.7
2.193


43.1
0.030
2.223

1374.8
2.200
157.8
1.436
398 0.006
3.642
164
                         98
-------
            TABLE A-17.   ARSENIC  BALANCES AROUND COMBUSTOR
Inputs                   Test 7         Test 12        Test 19C
Retorted Solids,kg/hr 1178.1         1300.4          1566.7
  As, g/hr                    42.41          48.11          65.80

Retort Gas, m3/hr       10.0            9.8
  As, g/hr                    1.15            0.86

Raw Shale, kg/hr                                      43.1
 As, g/hr                    	           	          2.33

Total As In, g/hr             43.56          48.97          68.13

Outputs

Heat Carrier, kg/hr   995.6          1138.1          1374.8
 As, g/hr                    46.79          35.28          48.12

Baghouse Ash, kg/hr   154.2           136.1           157.8
 As, g/hr                     13.88          12.52          11.36

Flue Gas, mVhr       410             387             398
 As, g/hr                     0.003           0.003         0.004

Total As Out, g/hr          60.673          47.803        59.484

Recovery, %                   139            97.6           87.3
                                      99
-------
             TABLE A-18.   LEAD  BALANCES AROUND COMBUSTOR
Inputs                    Test 7        Test 12         Test 19C

Retorted Sol ids,kg/hr 1178.1          1300.4          1566.7
  Pb, g/hr                    28.27          31.21          42.30

Retort Gas, m3/hr       10.0            9.8
  Pb, g/hr                     0.03           0.001

Raw Shale, kg/hr    .                                  43.1
 Pb, g/hr                    	           	          1.29

Total Pb In,  g/hr             28.30          31.211         43.60

Outputs

Heat Carrier, kg/hr   995.6           1138.1          1374.8
 Pb, g/hr                     21.90          25.03          35.74

Baghouse Ash, kg/hr   154.2            136.1           157.8
 Pb, g/hr                      3.08           3.27           3.95

Flue Gas, m3/hr       410             387             398
 Pb, g/hr                      0.05           0.002         0.05

Total Pb Out, g/hr            25.03          28.302         39.74

Recovery, %                   88.4           90.7           91.2
                                  100
-------
           TABLE A-19.   BERYLLIUM BALANCES  AROUND COMBUSTOR
Inputs                   Test  7         Test  12         Test 19C
Retorted Solids,kg/hr 1178.1          1300.4          1566.7
  Be, g/hr                    0.566          0.832          1.003
Retort Gas, m3/hr       10.0             9.8
  Be, g/hr                    ND              ND
Raw Shale, kg/hr                                      43.1
  Be, g/hr                    		        0.029
Total Be In, g/hr             0.566          0.832          1.032
Outputs
Heat Carrier, kg/hr   995.6          1138.1          1374.8
 Be, g/hr                     0.677          0.592          0.770
Baghouse Ash, kg/hr   154.2           136.1            157.8
 Be, g/hr                     0.157          0.147          0.196
Flue Gas, ra3/hr 410
Be, g/hr
Total Be Out, g/hr
Recovery, %
387
0.004
0.838
148
NO 	
0.739
88.7
398
ND 	
0.966
93.6
ND = Not detected.
                                       101
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           TABLE A-20.  FLUORIDE BALANCES AROUND COMBUSTOR
Inputs                   Test 7         Test 12         Test  19C
Retorted Solidsakg/hr 1178.1          1300.4          1566.7
  F, g/hr                     282.7          429.1          642.3
Retort Gas, m3/hr       10.0             9.8
  F, g/hr                     ND             ND
Raw Shale, kg/hr                            '          43.1
  F, g/hr                     	           	          31.5
Total F In, g/hr              282.7          429.1          673.8
Outputs
Heat Garner, kg/hr   995.6          1138.1          1374.8
 F, g/hr                      230.0          330.0          481.2
Baghouse Ash, kg/hr   154.2           136.1           157.8
 F, g/hr                      107.9          121.1          123.1
Flue Gas, uK/hr
F, g/hr
Total F Out, g/hr
Recovery, %
410 387
ND 	
337.9
119
ND 	
451.1
105
398 i
ND 	 i
604.3
89.7
ND = Not detected.
                                       102
-------
APPENDIX B
    103
-------
                                APPENDIX B
                   LEACHING AND HYDRAULIC PROPERTIES  OF
                        THREE BAGHOUSE ASH SAMPLES

                                    by

                          Dr. David B.  McWhorter
                        Colorado State University
 A.    INTRODUCTION

      Three  samples   of  baghouse  ash  were  provided to  Colorado  State
 University for the measurement of the  leaching  and hydraulic properties.
 The   samples  tested were designated by run number and sample number  and
 are,   respectively:    11-54591,   14-54592,  and  17B-54593.   The  operating
 conditions  of  the   retort,   fluid bed combuster,  and retort ^gas  under
 which  these  materials  were   produced  are presented elsewhere  in this
 report.                                                        !

      One   purpose of the tests made at Colorado State University was  to
 provide    information   on  the    potential  changes   in   the  leaching
 characteristics   of   retorted  oil shale that has undergone  the fluid bed
 combustion  and  other treatments  as described previously in this  report.
 This   is accomplished by comparing the  results  from  ESM tests (McWhorter
 and   Durnford, 1986)  on the ash samples with results from a similar test
 on  material   produced  by the   TOSCO-II  .retorting process.  While the
 results are not  rigorously comparable because the  final  products  did not
 derive from  identical  feed stock,  etc., the comparison remains useful as
 an indication  of any  significant  changes that may  occur.

      The  hydraulic  properties   of the  ash  samples  were measured to
 determine  if these materials exhibited any extraordinary .characteristics
 not   observed  previously  in  similar measurements on combusted  shales.
 Hydraulic  properties  of porous media are highly variable and sensitive
 to  many  parameters  unrelated   to the combustion and sulfur adsorption
 treatments  to  which these particular materials were subjected'.  It is,
 therefore,   not  possible  to attribute quantitative differences between
 the  properties  of  the ash samples and the corresponding properties  of
TOSCO-II  retorted  shales solely to the fluid bed combustion and sulfur
adsorption treatments received by the ash samples.

                                     104
-------
 B.   LEACHING EXPERIMENTS

      The  Equilibrated  Soluble Mass (ESM)(Nazareth,  1984;  McWhorter and
 Durnford,   1986)  test  was  used  in  this  project   as  a  method  for
 characterizing  the  leaching  properties  of  the baghouse ash samples.
 This  equilibrated  pore solution is subsequently displaced by injection
 of  distilled  water.    The  salient  feature  of  this test is that the
 chemical composition of the first effluent  from the column is that which
 evolved  during  the equilibration period under conditions  of liquid-to-
 solid  ratio  and aeration the are similar  to those expected under field
 conditions.

     ^In  the  ESM  column  leaching  test,   the sample is moistened with
 distilled water.   The moisturizing process is performed by weighing out
 a  dry sample to a given dry bulk density and sprinkling the sample with
 a  weighed  quantity of deionized water.  During the  sprinkling'process,
 the sample is continually mixed to distribute the water evenly,  and both
 the  water  added  and  the  total weight of the solid-liquid mixture is
 monitored.   After the moisturizing process is complete, the moisturized
 sample  equilibrates  for  72 hours  in  a  closed environment before the
 column is  packed and the leaching test run.

      The columns used in this study were  42-43 cm long with diameters of
 about  10  cm.    The  columns were packed  in lifts to  minimize separation
 and layering.   Although each of the ash samples was packed  as densely as
 possible,    achieving   densities   much  higher  than  1.0 g/cc  proved
 difficult.   The  #11   Baghouse Ash,  particularly,  was very difficult to
 pack because it had very little cohesiveness.

      The  leaching  test  is performed by injecting distilled water at a
 constant rate into the bottom of the column.   Bottom  injection minimizes
 air  entrapment and piping.   The bottom and top end-plates  of the  column
 have  2 mm conical disks machined onto  the  surfaces that promote uniform
 flow  over  the  cross  section  of  the  column and insure  mixing  of the
 effluent  as  it  enters  and  exits  the  column.   Perforated rigid disks
 support the  material  and  filter  disks  on the top  and bottom prevent
 movement  of  the  fines  through the end plates.   A rubber ring seals  the
 top  plate  to  the  column  body.Effluent  from the top of  the column is
 routed  through an electrical conductivity probe  and pH meter and  into a
 graduated  cylinder.  A record of the  cumulative volume of outflow,  time,
 pH,   EC,   and   inflow  pressure   is   maintained.    Effluent   samples  are
 collected  and  saved  at intervals  for  chemical  analyses.

      Table B-l   summarizes   the   significant parameters for the ESM test
 for  the   three  baghouse  samples  tested in this study.  Two values  for
 initial  moisture  contents  are  given in the table.  The reason if.or this
 is    that    the    samples  hydrated   during  the  equilibration  period,
particularly  #11  and #17.  The #11  Baghouse Ash sample was weighed and
moisturized   at   17 percent  distilled  water  by  weight.    After  the
moisturizing  procedure  was  completed and the sample container sealed,
the  temperature   of   the  sample  rose to 43°C after  ten minutes and to
maximum  of  48°C  in  twenty minutes.  The ambient temperature was 22°C.
During   column   packing  72 hours   later,   moisture   contents  of  the

                                     105
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               TABLE B-l.  ESM COLUMN LEACH TEST PARAMETERS
        Sample
Baghouse
 Ash #11
Baghouse
 Ash #14
Baghouse
 Ash #17
1.  Packed Volume (cm )
  3282
   3267
   3390
2.  Initial Moisture Content,
    % by weight added to
    dry sample*
    17.0
     17.0
     17.0
    Initial Moisture Content,
    % by weight determined
    by oven drying after
    equilibration period*
    10.6
     15.5
     13.3
    Dry Bulk Density

    (kg/m3)**
  1025
   1185
   1010
5.   Effective Particle
                 3
    Density (kg/m )
  3052
   2754
   2908
6.  Porosity
7   Flowrate (ml/hr)
     0.664


   120.0
      0.570
    144.8
      0.653
    161.8
    Total Time after
    outflow (hrs)
    22.7
     23.2
     24.1
 ^Difference between moisture added and moisture found by oven drying is
  due to hydration during 72 hour equilibration period.

**Dry Bulk Density is based on moisture content by oven drying given in
  3.
                                      106
-------
equilibrated  sample were determined'by standard oven drying methods and
found  to be 10.6, and 10.7, and 10.4 percent by weight, indicating that
significant hydration had occurred.  Similar data were collected for the
#17 sample tested.  A temperature change from 22°C to 42°G was noted for
the  #17  Baghouse Ash with a consequent drop in moisture content during
the  equilibrium  period from 17 percent to 13.3 percent by weight.  The
#14  Baghouse  Ash  had  a  measured  moisture content change from 17 to
15.5 percent (the average of three samples) but no change in temperature
was  noted.   Dry  bulk  densities shown in Table B-l are based on final
moisture contents.

G.   RESULTS OF LEACHING TESTS

     Tables  B-2,  B-3,  and  B-4  contain  the  data 'for  the chemical
composition  of the column effluent for the three samples.  Figures B-l,
B-2  and  B-3  show  the  variation  of the electrical conductivity as a
function of effluent volume.                                   '

     As  has  been  the  case  for  practically  all of the retorted and
combusted  shales subjected to the ESM test, the initial column effluent
is   quite  saline.   Furthermore,   the  overall  levels  of  individual
dissolved constituents are not remarkably different from those that have
been  observed  in  effluent  from  other  combusted shale materials.   A
second  index  to the leachability is the volume of effluent required to
achieve  a  50 percent relative electrical conductivity in the effluent.
Theoretical  considerations  (Nazareth,  1984)  show  that if all of the
leachable  solids are dissolved in the initial moisturizing waters, then
the  50 percent  relative  electrical  conductivity  should  occur at an
effluent  volume  equal  to  the  volume of moisture used in the initial
equilibration.     Occurrence   of  the  50 percent  relative  electrical
conductivity  at a volume greater than this value indicates the presence
of  significant  solubility  controls  and  the tendency for leaching to
occur  more  slowly.   All  of the baghouse ashes resulted in 50 percent
relative  concentrations  at effluent volumes near the volume of initial
moisturizing waters.                                           :

     The  plots  of  relative electrical conductivity (Figures B-l, B-2,
and  B-3)  show  a  tendency  toward  a  constant  relative  EC of about
20 percent  as  the  effluent  volume  becomes larger.   Again, this is a
characteristic observed in many other such tests.

     Table B-5   provides   data   for   a   direct  comparison  of  the
concentrations  of selected species in effluent from the ash samples and
from  TOSCO-II  retorted shale.  The first portion of the table compares
data  from  samples of the initial effluent; the second portion compares
data  from  samples  at  about the same effluent volumes collected after
leaching  was well advanced.  Perhaps the only remarkable differences in
the results are the much higher concentrations of potassium in the first
efflixents  from  the  combusted , shales  and  the  much  lower magnesium
concentration.   The concentration of other constituents, while certainly
not  the same,  are not so different that the ash samples would be put in
another  category  with respect to leaching.  Significantly, the sulfate
concentrations  derived  from  the ash samples are not greater than from

                                    107
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              TABLE B-2.  ESM TEST RESULTS FOR SAMPLE 11-54591
Parameter

pH
EC , ds/m
TDS,mg/l
Ca,mg/l
Mg,mg/l
Na,mg/l
K,mg/l
S04,mg/l
Cl,mg/l
N03,mg/l
NH4,mg/l
C03,mg/l
OH,mg/l
F,mg/l
Effluent Volume /Pore Volume

0.03
13.0
53.2
35720
647
<1
8850
4820
18380
83
11
92
1080
1810
5.4

0.09
12.8
42.6
26980
679
<1
6360
2990
13120
71
9
22
1040
1480
4.7

0.25
12.1
15.1
6850
1020
<1
817
272
2140
25
4
6
722
620
2.4

0.41
11.8
11.3
5050
1290
<1
162
96
1220
17
3
6
395
633
2.0

0.62
11.7
10.6
' 5140
1300
- <1
146
> 90
1130
17
3
6
925
: 300
1.7
Al,mg/l
Fe,mg/l
Mn,mg/l
Gu,mg/l
Zn,mg/l
Ni,mg/l
Mo,mg/l
Cd,mg/l
Cr,mg/l
Sr,mg/l
B,mg/l
Ba,mg/l
Pb,mg/l
Hg,mg/l
As,mg/1
Se,mg/l
0.10
0.02
0.01
0.18
0.15
<0.01
4.29
<0.01
2.99
38.1
0.55
0.21
<0.05
<0.001
0.006
0.210
0.22
0.02
0.02
0.02
0.02
<0.01
2.47
<0.01
1.66
38.3
1.60
0.20
<0.05
<0 . 001
<0 . 001
0.118
0.16
0.02
0.02
0.04
0.01
<0.01
0.62
<0.01
0.46
38.3
1.07
0.24
<0.05
<0.001
0.003
0.025
0.30
0.12
0.02
0.08
0.03
<0.01
0.27
<0.01
0.28
38.3
1.84
0.31
<0 . 05
<0..001
0.003
0.012
0.25
0.07
. 0.02
0.06
0.03
<0 . 01
, 0.29
<0 . 01
0.27
38.3
: 1.74
0.34
<0.05
<0.001
0.001
0.011
                                       108
-------
               TABLE B-3.   ESM TEST RESULTS  FOR SAMPLE  14-54591
Parameter
PH
EC , ds/m
TDS,mg/l
Ca,mg/l
Mg/mg/1
Na , mg/1
K,mg/l
S04,mg/l
Cl,mg/l
N03,mg/l
NH4,mg/l
C03,mg/l
OH, mg/1
F,mg/l
Effluent Volume/Pore Volume
0.04
12.5
25.7
20570
597
<1
5420
691
10640
414
11
113
1350
198
13.4
0.11
12.6
25.7
20330
571
<1
5320
635
10620
336
11 •
109
1510
83
13.8
0.28
12.5
18.9
13810
397
<1
3380 ,
469
6930
273
9
58
835
278
11.7
0.44
12.2
9.5
6680
689
<1
992
236
2740
142
6
39
519
121
8.8
0.60
12.1
6.4
4660
792
<1
298
132
1670
85
5
33
288
163
6.9
' 0.90
11.9
5.4
' 4310
774
<1
: 196
89
1560
96
: 4
33
! 220
141
6.2
Al,mg/l
Fe,mg/l
Mn,mg/l
Cu,mg/l
Zn,mg/l
Ni,mg/1
Mo,mg/1
Cd,mg/l
Cr,mg/l
Sr,mg/l
B,mg/l
Ba,mg/l
Pb,mg/l
Hg,mg/l
As,mg/1
Se,mg/l
0.56
0.02
0.01
0.21
0.03
<0.01
23.70
<0.01
0.13
19.3
1.16
0.13
<0.05
<0.001
0.039
0.242
0.59
0.03
0.02
0.14
0.04
<0.01
23.60
<0.01
0.13
19.6
1.44
0.13
<0.05
<0.001
<0.044
0.256
0.46
0.02
0.02
0.06
0.01
<0.01
14.90
<0.01
0.08
20.3
1.86
0.13
<0.05
<0.001
<.008
0.140
0.37
0.09
0.02
0.04
0,02
<0.01
6.10
<0.01
0.07
22.6
1.89
0.14
<0.05
<0.001
0.012
0.053
0.39
0.28
0.02
0.03
0.03
<0.01
3.60
<0.01
0.07
24.5
1.93
0.15
<0.05
<0.001
0.010
0.034
0.29
0.06
0.02
0.02
0.02
<0.01
3.30
<0.01
0.05
25.2
1.77
0.16
<0.05
<0.001
0.008
0.032
                                       109
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TABLE B-4.  ESM TEST RESULTS FOR SAMPLE 17-54591
Parameter
PH
EC , ds/m
TDS.mg/1
Ca,mg/l
Mg/mg/1
Na,mg/l
K.mg/1
S04,mg/l
Cl,mg/l
N03,mg/l
NH4,mg/l
C03,mg/l
OH,mg/l
F,mg/l
Effluent Volume /Pore Volume
0.03
13.3
53.3
17010
150
<1
5810
1870
2840
231
2
132
1440
3430
18.8
0.07
13.2
52.3
16120
167
<1
5470
1730
2460
171
1
93
1310
3570
15.4
0.19
13.0
34.1
9742
154
<1
3070
1040
1030
89
1
31
970
2150
7.7
0.33
12.6
14.1
4370
557
<1
689
284
203
20
<1
22
677
697
3.8
0.66
12.4
10.2
3540
723 !
<1 ;
186
113
59
.• 11
1 '
24
790 '
409
2.8
Al.mg/1
Fe,mg/l
Mn.mg/l
Cu , mg/1
Zn,mg/l
Ni,mg/l
Mo , mg/1
Cd.mg/1
Cr.mg/1
Sr,mg/l
B,mg/l
Ba , mg/1
Pb,mg/l
Hg,mg/l
As , mg/1
Se.mg/1
0.32
0.02
<0.01
0.29
0.33
<0.01
5.30
<0.01
0.05
12.0
1.02
0.25
<0.05
<0.001
0.022
0.043
0.26
0.01
0.01
0.12
0.13
<0.01
4.20
<0.01
0.05
14.9
0.56
0.33
<0.05
<0.001
0.014
0.032
0.17
0.01
0.01
0.02
0.02
<0.01
1.80
<0.01
0.05
26.0
1.70
0.52
<0.05
<0 . 001
0.001
0.016
0.24
0.01
0.01
0.01
0.01
<0.01
0.37
<0.01
0.05
37.3
1.49
1.31
<0 . 05
<0 . 001
<0.001
0.005
0.17
0.01
0.01
0.01
0.02
<0.01
0.14
<0.01
0.05
37.3
1.63
2.34
<0'.05
<0.001
0.001
0.015
                        110
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TABLE B-5.  COMPARISON OF EFFLUENTS FROM ASH SAMPLES AND
            TOSCO-II RETORTED SHALE
Initial Effluent
Parameter

EC , ds/m
pH
Na , mg/1
Ca,mg/l
Mg,mg/l
K,mg/l
S04>mg/l
Cl,mg/l
F,mg/l
MO, mg/1

Parameter

EC , ds/m
pH
Na,mg/l
Ca,mg/l
Mg,mg/l
K,mg/l
S04,mg;/l
Cl,mg/l
F,mg/l
MO, mg/1
11-54591

53.2
13.0
8850
647
<1
4820
18380
83
5.4
4.3

11-54591

10.6
11.7
146
1300
<1
90
1130
17
1,7
0.29
14-54592

25.7
12.5
5420
597
<1
691
10640
414
13.4
23.7
Final Effluent
14-54592

5.4
11.9
196
774
<1
89
1560
96
6.2
3.3
17-B-54593

53.2
13.3
5810
150
<1
1870
2840
231
18.8
5.3

17-B-54593

10.2
12.4
186
723
<1
113
59
11
2.8
0.14
TOSCO-II

36.5
!9.3
,9910
:368
695
'109
; 28510
:218
!24.9
26.3

TOSCO- II
r
ie.e

'1160
'•62
83
15.4
3132
8.9
122.0
5.4
                            111
-------
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                                 114
-------
 the   TOSCO-II  retorted  material.    Overall,   the  data  suggest  that:
 adsorption  of  chemicals  (primarily  sulfur)  from the flue gas did not
 substantially modify the levels or amounts of most constituents that are
 leached from the shale by this test.                           !

 D.    HYDRAULIC PROPERTIES

      Particle Density- The particle densities  of all three materials  were
 measured at 500 ml volumetric flasks.   Duplicate samples of the material
 were wetted under vacuum to insure removal of entrapped air.   Due to the.
 high  mass  of  soluble  salts  in the samples,  the calculations of the
 particle  density  were corrected for the  sample mass in solution.   This
 was  done  by measuring the total dissolved solids (T.D.S.)  in the flask
 solution,  calculating the total dissolved  mass  and then reducing initial
 sample  mass  by that amount.   Without that correction unreasonably  high
 values of particle density would have been obtained.

      Water  Characteristics -The  water characteristic of a material  is  a
 measure  of  the material's ability to hold capillary and adsorbed water
 at   pressures  less  than  atmospheric  and  water  contents   less  than
 saturation.   The amount of water held at a given capillary pressure  is  a.
 function of whether the material is drying or wetting.   Only  the wetting
 characteristics were measured.   The method used was consistent with  ASTM
 D2352  except water was circulated beneath the  plate to provide a source
 to  wet the samples.   Figure B-4 presents the  results of the analysis.

      Hydraulic Diffusivity-Using the  theory of  hydraulic diffusivity the
 unsaturated  hydraulic  conductivity  of a  porous  medium can be; measured
 The hydraulic diffusivity is defined  as:
where     D(0) = hydraulic diffusivity  (L2/T)                  '

          K(0) = hydraulic conductivity (L/T)

          6    = volumetric water content

          h   = capillary pressure  (L)

The  relation   dh/dd  is the slope of  the water holding capacity curve.
With  this relationship, Darcy's law for one -dimensional horizontal flow
can be stated as                                               1

          q = - D(0)30/dx                                           (2)

     Bruce  and  Klute  (1956)  showed that  D(0)  can be measured in an
unsteady  flow  cell.   A  horizontal  column  is wetted from a constant
pressure source for a relatively short period and then the water content
along the column is determined.   The diffusivity is calculated by:
                    \ fe
9    Sg     A dd                             (3)
x     i
                                    115
-------
      4

     »0r-
                                         no. //

                                       o no. 14
    10
 6
 o
o
,
w
2


"5.
o
    /O
               O./
0.2       0.3       0.4

    Wfafer  Confenf Q
                                                      0.5
0.6
                                                                          0.7
                     Figure B-4.  Water characteristics.


                                   116
-------
where      9. =  initial water  content

           A1- x/t1/2

This  method has  the advantage that data collected at different times is
normalized to yield a single  curve.

     For   materials  #11  and #14, columns at initial water contents of
about  10  percent by  weight were run.  Water contents at various times
were  measured by gamma attenuation.  The diffusivities for each density-
were   then   calculated   using   Eq.  (3).   Figure  B-5  presents  the
diffusivities  for  each  material.   The  values are reasonable for the
material and densities.

     Hydraulic  Gonductivity-The  unsaturated hydraulic conductivity can
be determined using the relation:.

           K(0) =  D(0) d0/dh                                   ,      (4)


     The   term   dd/dh  is  the   inverse  of  the  slope  of  the  water-
characteristic.    Using   this   relationship  and  the  measured  water-
characteristics   and  diffusivities, the unsaturated conductivities were
computed.   Figure  B-6 presents  the results.  The ranges are reasonable
for the materials and densities.                              ;

     Saturated    Hydraulic    Conductivity-The    saturated   hydraulic
conductivity  of  samples #11  and  #14 were determined with a falling head
permeameter.   Columns approximately 3.7 cm in diameter, 15 cm long with
a  flexible  membrane  between  the  sample  and  column wall were used.
During  testing,  the  region between  the membrane and column wall was
slightly   pressurized  to  ensure  no  seepage along the walls.  Maximum
hydraulic  gradients used were 6 for sample #14 and 16 for sample #11.
     Sample  #14  was  tested for  three days.  During that period, the
hydraulic  conductivity was constant at 1.7 x 10  cm/s.   Sample #11, due
to  its  cementing  characteristics, was tested twice.  The first column
was  packed immediately after moisturizing.   It had a conductivity which
declined  over  the  next  10 days from 4 x "cm/s to 2 x 10  cm/s.   The
second  column was packed after three days of curing.   It had a constant
conductivity of 2.6 x 10" cm/s.                                ;
                                    117
-------
     0.
   0.01
o
-------
     -4

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    /o'
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o
3
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1
     -7
   IO
   /o
                                   &.  no. //


                                  _o  no. 14
_L
          _L
                                             J_
               O./        0.2       0.3       0.4

                             Wafer  Confenf
                             0.5
0.6:
                                                a 7
                    Figure B-6.   Hydraulic conductivity.



                                     119
-------
                               REFERENCES

1.   Bruce,  R.R. and A. Klute.  1956.   The measurement of soil-moisture
     diffusivity.  Soil Sci. Soc. Am.  Proc., Vol.  20,  pp.  458-462.

2.   McWhorter,   D.B.   and  Durnford,   D.S.   Leaching  and  hydraulic
     properties  of retorted oil shale including effects from codisposal
     of  wastewater.    Final  Report on Cooperative Agreement CR-807668
     USEPA/AEERL-202, 180 p.

3.   Nazareth, V.A.  1984.  A Laboratory Column Leach Test for Oil  Shale
     Solid  Wastes.  Ph.D. Dissertation,  Colorado  State University,  Fort
     Collins, CO.
                                    120
-------
-------
                                 TECHNICAL REPORT DATA
                           (Please read Instructions on the reverse before completing)
 1. REPORT NO.
  EPA-600/7-86-032
             3. RECIPIENT'S ACCESSION-NO.
 4. TITLE AND SUBTITLE
 Control of Sulfur Emissions from Oil Shale Retorting
  Using Spent Shale Absorption
             5. REPORT DATE
               October 1986
             6. PERFORMING ORGANIZATION CODE
 7. AUTHOR(S)
 K.D. VanZanten and F. C.  Haas
             8. PERFORMING ORGANIZATION REPORT NO
 9. PERFORMING ORGANIZATION NAME AND ADDRESS
 J and A Associates
 18200 W.  Highway 72
 Golden, Colorado  80401
             10. PROGRAM ELEMENT NO.
             11. CONTRACT/GRANT NO.
             68-03-1969
 12. SPONSORING AGENCY NAME AND ADDRESS
 EPA,  Office of Research and Development
 Air and Energy Engineering Research Laboratory
 Research Triangle Park, NC 27711
             13. TYPE OF REPORT AND PERIOD COVERED
             Final; 10/85-2/86
             14. SPONSORING AGENCY CODE
              EPA/600/13
 15. SUPPLEMENTARY NOTESAEERL project officer is Edward R. Bates, Mail! Drop 62B, 919/
 541-2853.
 16. ABSTRACT
               report describes an investigation of the environmental advantages/dis-
 advantages of absorbing SO2 onto  combusted retorted oil shale.  The objective of this
 program was to obtain more information in support  of Prevention of Significant De-
 terioration (PSD) permitting decisions on sulfur control and to determine if the     i
 emission of other pollutants such as nitrogen oxides (NOx) and trace elements is sig<-
 nificantly increased by the combustion process.  The program consists of two phases:
 Phase I developed an  engineering assessment and costs for application of this sulfur
 absorption process to selected leading retorting processes, and Phase II was experi-
 mental work in an integrated oil shale pilot  plant to define  operability,  proof of prin-
 ciple, and trace element emissions. Based  on the pilot plant data obtained in this
 study, fluid bed operating conditions are recommended to  optimize ;SO2 and NOx con-
 trol. In general,  conditions that favor low SO2 emissions  also favor low CO and trace
 hydrocarbon emissions, but do not favor low NOx emissions.  The general ranges of
 operating conditions which produced reasonable results from both operating and
 emissions viewpoints are given  in the report. Results of the trace 'element tests in-
 dicated  some relative trends with  regard to emissions but, because of  the brevity of
 the sampling, no hard conclusions can be reached for extrapolation to the long term.
 7.
                              KEY WORDS AND DOCUMENT ANALYSIS
                 DESCRIPTORS
Pollution
Oil Shale
 Combustion
Sulfur
Emission
Absorption
 8. DISTRIBUTION STATEMENT
 Release to Public
                                           b.lDENTIFIERS/OPEN ENDED TERMS
                                            Pollution Control
                                            Stationary Sources
                                            Retorting
                                            Spent Shale
                                           19. SECURITY CLASS (ThisReport}
                                           Unclassified
20. SECURITY CLASS (Thispage)
Unclassified
EPA Form 2220-1 (9-73)
                                          121
                                                                    c.  COSATI Field/Group
                         13 B
                         08G
                         21B
                         07B
                         14G
                         21. NO. OF PAGES
                            131
                                                                    22. PRICE
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