-------
TABLE 5 1-12 (cont )
Control
Technology
Thermal BeHOx
Electron Beam
Scr ut>b i ng
Absorption
deduction
Absorption
Oxidation
Oxidation
Absorption
Reduction
Operating Principle
HH3 injected In a 1,300-
1,800"F flam* zone where
NO + W\3 * N2 + H20
Removal of S02 and NOx by
reaction with MH3 in the
presence of electrons
Products are (NH^SO, *
NH4NOa
NOx 1s converted to HH3 by
tht reducing effect of S02 to
sake (MH«)XS04 with a liquid
Fe EOTA catalyst In a 20-tray
coluwi.
NOx and $02 art absorbed in
a KOH/KHn04 solution and »r«
oxidized to KHDa and K2504,
Either 0a or C102 are used to
oxidize NO to N02.
Performance
Up to 70% HQx removal
Up to 85% NOx, 90% iOs
removal
70-85% H0X, 90S SO,
resieval .
No data available
Up to 85* NOx, 95% SOZ
removal if S0;./H0x
ratio is 2.5.
Development
Status
Demonstrated
commercial ly
Pilot plant stage
only
Hot demonstrated
commercially.
Not demonstrated
commercially
Not demonstrated
commercially.
Advantages
By-product recovery not
required tow capital cost.
Simultaneous removal of SO*
and NOx
Ho oxidizing agent required.
Sinultaneous removal of S02
and NOx.
Simultaneous renaval of SOS
and NOx
01 satlsantages
Requires large amounts «f
N% Narrow operating
range .
Power consunption is 3%
of plant output for beam
accelerator High
capital cost Require*
nigh efficiency ESP
R«
-------
Stack gas removal. Flue gas treatment for NOx removal is a relatively
new, developing technology. Two broad categories may be defined: wet
processes in which NOx is absorbed into an aqueous solution, and dry proc-
esses in which NOx is reduced by ammonia.
The wet NOx removal processes also serve as a mechanism to reduce sulfur
dioxide emissions and, as such, can provide effective environmental control
wnere both pollutants are present. However, due to the low solubility of NOx
in aqueous solutions and the low removal efficiencies obtainable, absorption
techniques usually prove to be very expensive.
Dry NOx removal systems, in general, display higher nitrogen oxide
reduction capabilities and are economically more viable than wet systems.
These processes are usually ammonia based and may be selective or non-
selective and catalytic or noncatalytic. Depending on the individual process
applied, ammonia is injected into the flue gas at some point after complete
combustion and prior to a minimum gas temperature of 350°F. In the resulting
reaction, NOx combine with ammonia to form molecular nitrogen and water.
NitrogenOxides Control Technologies Analyzed—
The primary source of NOx emissions from the Lurgi-Open Pit plant is the
Lurgi flue gas discharge system. According to Rio Blanco, the NOx emissions
in the Lurgi flue gas originate only from the fuel-based nitrogen in the
organic residue on the-, processed shal.e. The temperature in the lift pipes
(1,240°F) is claimed to be low enough so that thermal fixation of the atmos-
pheric nitrogen does riot occur during- processed shale incineration (Rio
Bianco Oil Shale Co., February 1981). • Since there is JIG fuel combustion in
the plant, additional NOx emissions are not formed.
Ammonia in the Lurgi retort gas is removed during product liquor conden-
sation. Since this is an integral processing step in the Lurgi technology,
it is not considered a pollution control measure.
Once removed in the Lurgi gas liquor, the actual recovery of NH3 is
achieved with an ammonia recovery process. Since the process is considered
to be a water treatment technology, it is discussed in Section 5.2.
The modified DDP for Tract C-a (Rio Blanco Oil Shale Co., February 1981)
reports that the concentration of NOx in the flue gas is 300 ppmv, which is
equivalent to 3,600 Ib/hr of N02, or 2,430 Ib/hr NOx assuming 90% NO and 10%
N02, by weight. In a separate organic nitrogen material balance presented in
the same document, however, 0.3 Ib of organic nitrogen/ton of raw shale is
reported to be converted to NOx. This latter value is equivalent to about
4,900 Ib/hr N02, or 400 ppmv in the flue gas.
If the formation of NOx in the flue gas is due only to the oxidation
of fuel-based nitrogen, as is claimed by Rio Blanco (.Rio Blanco Oil Shale
Co., February 1981), combustion modifications cannot be employed to control
the NOx. Also, techniques do not exist for removing organic nitrogen from
the processed shale. However, if thermal fixation of atmospheric nitrogen
does occur in the lift pipes, combustion modifications can be applied in
163
-------
order to reduce the NOx formation. The stack gas NQx removal techniques may
be applicable regardless Of the origin of NOx; but most ofsthe« have not been
successful in commercial-scale, continuous operations. Only refrigerated
tanks for the storage of ammonia were examined as an indirect NOx control
measure. The fixed capital cost for the storage tanks is estimated to be
$466,000 and the total annual operating cost is $15,000. This results in a
total annual control cost of $88,000* or 0.4 cents/bbl of oil (see Section 6
for details on computation of the total annual control cost). The cost for
the ammonia storage tank£ also constitutes the total cost of NQx control for
the plant.
Total Nitrogen Oxides Emissions—
There are only two plant emissions that contain N0x--the flue gas and
diesel exhaust. The quantities of NOx in the two streams are listed in
Table 5.1-13.
TABLE 5.1-13. TOTAL NOx EMISSIONS FROM THE PLANT
Stream
Number
24
31
TOTAL
Emission Source
Diesel Equipment
Flue Gas Discharge
System
NOx Emissions3
(Ib/hr)
469.9
2,432.4b
2,902.3
a Expressed as 90% NO and 10% N02, by weight.
Value is based on 300 ppmv NOx in the flue gas, according to the informa-
tion from Rio Blanco Oil Shale Co., February 1981.
Source: SWEC estimates, except as noted.
5.1.4 Hydrocarbon Control
Hydrocarbon compounds are emitted to the atmosphere as a result of
incomplete fuel combustion or as a fugitive emission from small leaks in
processing or storage equipment.
The hydrocarbon emissions from noncombustion sources are usually refer-
red to as volatile organic compounds (VOC) or reactive hydrocarbons (RHC) in
government regulations restricting their emission. Federal and State regu-
lations limit these hydrocarbon emissions because of their role in the
formation of photochemical smog and ozone production.
164
-------
Inventory of Control Technologies—
As illustrated in Figure 5.1-8 and discussed in Table 5.1-14, hydro-
carbon emissions can be controlled by the following categories of control
technologies:
* Additional sealing of process equipment
* Vapor recovery
« Complete fuel combustion
« Catalytic converters
* Thermal oxidizers.
Additional sealing of process equipment. Hydrocarbon emission control
by additional sealing of process and storage equipment is best accomplished
by engineering these features into the plant. This includes double seals on
tanks, pumps, and other rotating machinery, closed-loop sampling, caps on
open-ended valves, and periodic monitoring of equipment to find hydrocarbon
leaks quickly. This will result in a minimum additional plant capital cost
and will more than pay for itself due to the value of the hydrocarbons which
are prevented from being emitted.
Vapor recovery. When hydrocarbon vapor emissions cannot be controlled
by additional sealing of equipment, a vapor recovery system can be installed
to collect and condense the vapors by refrigeration and return them to the
process.
CgjHplete fuel combustion. The most cost-effective way to control hydro-
carbon emissions from fuel combustion processes is to operate the process
with enough excess air to ensure complete oxidation of all hydrocarbons to
C02 and 1^0, i.e., complete fuel combustion.
Catalytic converters. When complete fuel combustion does not occur, the
hot exhaust gas from the process can be sent through a catalytic converter.
In the catalytic converter, the gas is passed over a catalyst where the
unburned hydrocarbons are reacted with the excess air in the exhaust gas and
are converted to C02 and H20.
Thermal oxl dl zers . Hydrocarbon vapor streams or any other waste gas
stream containing unburned hydrocarbons can be burned in a thermal oxidizer
with excess air and additional fuel, if needed; this completely oxidizes all
hydrocarbons to C02 and H20.
Hydroca rbon Control Techno 1 ogj e $
The hydrocarbon emissions in the iurgi-Open Pit plant emanate from the
leakage in the valves, pumps, etc., as the fugitive emissions from oil
product storage, and due to the incomplete combustion of the fuels.
Hydrocarbon emissions from diesel -burning equipment are controlled by
installation of, catalytic conversion systems. The least costly fugitive
165
-------
HYDROCARBON
CONTROL
TECHNOLOGIES
ADDITIONAL SEALIN6
ON PROCESS
EQUIPMENT
VAPOR
RECOVERY
COMPLETE FUEL
COMBUSTION
CATALYTIC
CONVERTERS
THERMAL
OXIDIZERS
SOURCE' SWEC
FIGURE 5J-8 HYDROCARBON CONTROL TECHNOLOGIES
166
-------
TABLE 5,1-14. KEY FEATURES OF HYDROCARBON CONTROL TECHNOLOGIES
Control
Technology
Additional
Sealing on
Process
Equipment
Operating Principle
Double seals an pumps and
rotating machinery and caps
on open-ended valves reduce
hydrocarbon losses from the
equipment
Performance
About 60%-65% reduction
of fugitive hydrocarbon
emissions Is possible
with this level of
control
Development
Status
Commercially proven.
Advantages
Requires a small capital and
operating cost and will
probably more than pay for
this cost due to the value of
the hydrocarbons which are
prevented from being emitted.
Disadvantages
Should be implemented
during naw plant
construction Requires
more capital Investment
to retrofit the controls
of an existing plant.
tn
Vapor Recovery
Complete Fuel
Combustion
Catalytic
Converters
Thermal
Qxidizers
Hydrocarbon vapors emitted
from process equipment are
collected and condensed by
refrigeration and then
returned to the process
Combustion process 1s operated
with excess air to ensure
complete oxidation of all
hydrocarbons to C02 and H20.
Hot exhaust gas Is passed over
a catalyst where the unhurried
hydrocarbons are reacted with
the excess air 1n the exhaust
gas and are converted to C02
and H20.
Waste gas streams containing
unburned hydrocarbons ire
burned with excess air and
additional fuel 1f needed to
completely oxidize all
hydrocarbons to C02 and H20.
About 80-90% of the Conacre tally proven.
hydrocarbon vapors can
usually be condensed
and returned to the
system.
Can convert close to Commercially proven.
100% of all hydrocarbons
in the fuel to C02 and
HZ0.
Can convert up to BOSS
of the hydrocarbons In
diesel exhaust gas
streams to C02 and H20,
for other fuel burning
processes, up to 99%
conversion 1s possible
Can convert close to Com
1QOX of all hydrocarbons
in the gas stream to C02
and H20
Commercially proven.
erclally proven
A reliable system which is
best applied to potential
point source emission streams.
Eliminates the need for
downstream equipment to
complete the conversion of CO
to COZ.
Does not require any fuel and
has no moving parts so that
routine maintenance Is minimal.
Will ensure complete oxidation
of hydrocarbons and any other
unwanted components in the gas
stream.
Can be a high energy
requirenent to operate
the refrigeration system.
An adequate air.fuel
ratio must be maintained
The catalyst, which is
expensive, must be
replaced periodically.
Can have a high energy
requirement when supple-
mental fuel is used.
Source: SWEC based on information from Research and Education Association, 1980
-------
hydrocarbon emissions control for storage tanks is proper sealing. Alterna-
tively, vapor recovery can be used, but the expense is extremely high for
these systems. As a standard industry practice, double-sealed, floating roof
storage tanks are provided for volatile product storage. Internal plant
leaks are controlled by use of adequate seals and strict maintenance proce-
dures. Approximately 232 Ib/hr of hydrocarbons (expressed as methane) are
estimated by Rio Blanco for the 4,400 TPSO Lurgi module (Rio Blanco Oil Shale
Co., February 1981).. Except for using proper combustion practices, no other
technologies are provided to reduce the hydrocarbon release in the flue gas.
Table 5.1-15 lists the hydrocarbon control practices and equipment con-
sidered, and Table 5.1-16 presents the costs for hydrocarbon control for the
entire plant.
TABLE 5.1-15. HYDROCARBON CONTROL PRACTICES AND EQUIPMENT
Capital Cost Items Operating Cost Items
Floating Roof Storage Tanks (2) Maintenance
200' diameter x 48', 268,000 bbl (each)
Welded API 550 code
Double seals
Carbon steel
Complete Combustion of Fuels
Dual Mechanical Seals on Pumps and Valves
Catalytic Converters on all Diesel Equipment
Monitoring Equipment
Source: SWEC.
Total Hydrocarbon Emissions—-
Table 5.1-17 summarizes the hydrocarbon emission sources and control
equipment used for the emissions.
5.1.5 Carbon MonoxideControl
Carbon monoxide (CO) is usually formed by incomplete combustion of
fossil fuels. Normally, an excess of oxygen Is supplied to a combustion
process to ensure that all of the carbon in the fuel is converted to carbon
dioxide (CG2). When a shortage of oxygen occurs in the combustion process,
some of the carbon is only partially oxidized to CO. Federal and State
standards and regulations limit CO emissions because of their deleterious
effect on the human respiratory system.
168
-------
TABLE 5.1-16. COST OF HYDROCARBON POLLUTION CONTROL
CB -
<£> -
Stream
Number
24
, 112
44, 47
Control
Description
Catalytic
Converters
Maintenance
Floating Roof
Storage Tanks
Control Location
Diesel Equipment
Valves, Pumps, etc.
Product Storage
TOTAL
Fixed
Number Capital Cost
of Units ($000' s)
170
61
2 300
531
Total
Annual Operating
Cost ($000 's)
65
(59)b
(Ml)
(135)
Total
Annual Control
Cost ($000' s)a
106
(44)
(89)
(27)
See Section 6 for details on computation of the total annual control cost.
Values in parentheses ( ) indicate profit after subtracting the total annual capital and operating
charges from the annual by-product credit of $125,000 from maintenance and $155,000 from the storage
tanks, both at $32/bbl of oil.
Source: DRI estimates based on information provided by SWEC.
-------
TABLE 5.1-17. TOTAL HYDROCARBON EMISSIONS FROM THE PLANT
Stream
Number
24
31
Emission Source Control Description
Diesel Equipment Catalytic Converters
Flue Gas Discharge
Hydrocarbon
Emissions (Ib/hr)
12.7
6,261.7*
System
112
44,
47
TOTAL
Valves,
Product
Pumps, etc.
Storage
Maintenance
Floating
Tanks
Roof Storage
35.
65.
6,376.
5
5
4
* According to the information from Rio Blanco Oil Shale Co., February 1981,
about 232 Ib/hr of hydrocarbons (expressed as CH4) are estimated from the
4,400 TPSD Lurgi module (the processed shale rate is 3,518 TPSD). The
reported value is extrapolated for the commercial operation (94,956 TPSD
of processed shale).
Source; SWEC estimates, except as noted.
The easiest and most cost-effective way to control CO emissions is to
use excess oxygen in the combustion processes to ensure complete combustion.
When incomplete combustion does occur, catalytic converters or thermal or
chemical oxidizers may be used to oxidize the remaining CO to C02.
Inventory of Control Technologies—
Figure 5.1-9 shows a list of the applicable carbon monoxide control
technologies, and Table 5.1-18 describes in detail the features of these
control methods.
Complete fuel combustion controls CO emissions by not allowing them to
be formed. This is done by operating with enough excess air to ensure com-
plete oxidation of all carbon to C02 instead of only partial oxidation to CO.
When CO is formed in a combustion process, a catalytic converter or thermal
or chemical oxidizer can be used.
Carbon MonoxideControl Technologles Analyzed—
By far, the largest amount of CO is emitted from the Lurgi flue gas dis-
charge system. The sources of this CO may be the incomplete combustion of
the residual organic matter on the processed shale, decomposition of the
carbonate minerals, and a steam/coke reaction in the processed shale
quencher/moisturizer. To maximize the combustion of the organic residue, an
170
-------
CONTROL
TECHNOLOGIES
COMPLETE FUEL
COMBUSTION
CATALYTIC
CONVERTERS
THERMAL
QXIQIZERS
CHEMICAL
OXIDIZERS
SOURCE: SWEC
FIGURE 5.1-9 CARSON MONOXIDE CONTROL TECHNOLOGIES
171
-------
TA8LE 5.1-18 KEY FEATURES OF CARBON MONOXIDE CONTROL TECHNOLOGIES
"si
PO
Control
Technology
Complete Fuel
Combustion
Operating Principle
Costbustlon process is operated
with excess air to ensure
complete oxidation of all
carbon to C02, instead of
only partial oxidation to CO
Performance
Can convert close to
100X of all carbon in
the fuel to CO^.
Development
Status
Commercially proven.
Advantages
Eliminates the need for
downstream equipment to
complete the conversion of CO
to C0t
Disadvantages
An adequate a1r:fuel
ratio must be maintained
Catalytic Hot exhaust gas is passed over
Converters a catalyst where the CO in the
gas is reacted with the excess
air !n the exhaust gas and is
converted to C02.
Thermal Waste gas streams containing
Oxidizers CO are burned with excess air
and additional fuel If needed
to completely oxidize alt CO
to CO*
Chemical Gas streams containing CO are
Oxidizers scrubbed with a solution
containing a chemical oxi-
dizing agent which oxidizes
the CO to C02.
Can convert up to 90S!
of all CO in diesel
exhaust gas to COg; for
other fuel burning
processes, up to 99%
conversion Is possible.
Can convert up to 100%
of all CO in the gas
stream to C0j.
Can convert up to 99%
of all CO In the gas
stream to CO;.
Commercially proven
Commercially proven
Commercially proven.
Does not require any fuel and
has no moving parts so that
routine maintenance Is minimal.
Will ensure complete oxidation
of CO to C02 and complete
oxidation of any other unwanted
components In the gas stream.
Oxidizes the CO to C02 without
using fuel to heat up the
entire gas stream.
The catalyst, which 1s
expensive, must be
replaced periodically
Can have a high energy
requirement when Supple-
mental fwel 1s used. *
Requl res the use of
expensive chemicals
Source SWEC based on Information from Research and Education Association, 1980.
-------
excess of air is used. Decomposition of carbonates is unavoidable because
the processed shale recycle stream has to attain a high temperature to
provide the heat of retorting. The steam/coke reactions may also be unavoid-
ab'a.
The CO content of the flue gas is reported to be less than 90 ppmv.
"^"his may be reduced further by the post-combustion of the flue gas; however,
due to the large volume and low heating value of the flue gas, it would be
Inpractica'.
Diesel-powered equipment is another source of the CO emissions. The
diesel engines are equipped with catalytic converters to control the CO.
Since the converters also control hydrocarbons, they have been included under
hydrocarbon emission control.
Total Carbon Monoxide Emissions--
Table 5.1-19 summarizes the carbon monoxide emission sources and control
equipment used for the emissions.
TABLE 5.1-19. TOTAL CO EMISSIONS FROM THE PLANT
Stream
Number
24
31
TOTAL
Emission Source
Diesel Equipment
Lurgi Flue Gas Discharge
System
CO Emissions
Control Description (Ib/hr)
Catalytic Converters 34.8
657.4*
692.2
* According to the information from Rio Blanco Oil Shale Co., February 1981,
the flue gas contains about 90 ppmv CO.
Source: SWEC estimates, except as noted.
8.1.6 Control of Other Criteria Pollutants
In addition to the primary air pollutants discussed so far, there may be
oths" criteria pollutants, such as lead, mercury, beryllium and fluorides,
emitted from the Lurgi-Qpen Pit facility. Some of these pollutants are
nonvolatile; therefore, they may be released only as fugitive dust constitu-
ents. Any control of the dust will also serve to control the nonvolatile
pollutants. Volatile pollutants may potentially be released with the Lurgi
flue gas and/or the tail gas from the Stratford process. Some pollutants
do not occur naturally and some are unlikely to form during oil shale
processing.
" 173
-------
5.1.7 Control of Moncn'teria Air Pollutants
Meaningful test data are not available to determine whether emissions of
noncriteria air pollutants are a concern. Consequently, no information on
control technologies for such pollutants was generated for this manual. Men-
tion of species such as PQMs (U.S. EPA, 1980) and trace elements such as
arsenic (Fox, Mason and Duvall, 1979; Girvin, Madeishi and Fox, June 1980)
are noted.
5.2 WATER MANAGEMENT AND POLLUTION CONTROL
As in other industries and oil shale operations, the Lurgi-Open Pit
plant—from mining activities to final product and waste disposition-~wi11
produce water effluents which will require proper disposal. These effluents
may contain the following pollutants:
* Suspended Matter, Oil and Grease
* Dissolved Gases and Volatiles
* Dissolved Inorganics
« Dissolved Organics.
This section describes the current, commercially available alternate
systems for controlling the above pollutants. The following subsections pro-
vide inventories of control technologies for each of the pollutant classes, a
discussion of advantages and disadvantages, and important points to consider
in selecting a particular technology. The performance, design, and cost date
for the leading technologies are also presented.
5.2.1 Suspended Matter, Oil and Grease
Undissolved matter found in wastewater effluents includes solid parti-
cles as well as oils and greases. The solids are usually the raw and proc-
essed shale particles that are washed into the retort water and those that
are entrained in the retort vapors and subsequently removed in the gas con-
densates. The retort water and gas condensate also contain trapped oil and
oil-in-water emulsions. Service and storm runoffs contain suspended matter,
as well as oils and greases. Also, the source water contains suspended soil
particles and debris.
In general, the control of suspended matter at oil shale plants will be
accomplished using conventional technology. For example, clarification in
gravity settlers (with addition of flocculants) and multimedia filtration
will, in most cases, provide adequate control. Associated energy consumption
and costs are generally low.
The control of undissolved oils- and greases in oil shale wastewaters has
not been studied in detail. API-type gravity settlers have the potential to
provide adequate control for most of the waste streams generated. It is
possible, however, that some wastewaters will contain oil-in-water emulsions;
if so, additional control steps may be required. Heating the water or adding
174
-------
chemicals may be sufficient to break the emulsion; otherwise, filter coa-
lescence (or possibly ultrafiltration) may be required.
The degree to which emulsified oil needs removal is dependent on down-
stream processing and reuse. In cooling towers, the oil may foul heat
exchange surfaces and thus require prior removal. Similarly, fouling, and
possibly foaming, may occur when stripping the retort water or gas conden-
sats. The extent to which such problems will arise is not known.
The energy consumption and cost of oil separation by gravity means are
generally low. Thermal or chemical treatment, if required, would cause some
increase in costs. Filter coalescence and, in particular, ultrafiltration
generally are more costly and would be considered only if other procedures
prove inadequate.
Inventory of Control Technologies—
Figure 5.2-1 shows different types of technologies that apply to control
of suspended matter and oils and greases. Key features of these technologies
are provided in Table 5.2-1.
API-type separators. For gravity separation of oil in large holding
tanks, seoarators should be designed within the following limits: (a) hori-
zontal velocity of less than 3 fpm, (b) depth between 3-8 ft, and (c) depth-
to-width ratio of approximately 0,4. Oil is skimmed from the surface and
collected for reuse or disposal. Gravity separation is not effective for
emulsified oils that might be present in some retort waters (American
Petroleum Institute, 1969).
Sedimentation. This is a gravity process in which the solid phase
settles and is withdrawn as a slurry. Clarification may be carried out in
large holding ponds, plate (lamella) settlers or hydrocyclones. Chemicals
(flocculants and coagulants) may be added to precipitate salts (softening) or
to aid settling of suspended solids (Humenick, 1977).
Flotation. This is a gravity process in which the solid phase rises to
the surface and is skimmed off as a slurry. Air bubbles may be introduced
into the flotation vessels to assist separation (Humenick, 1977).
Csntrifugation. This is a modified gravity method to afford separation
or settling of fine, suspended matter and oils. The wastewater is subjected
to a radial force greater than the gravity field by rapidly rotating it.
Suspended matter denser than water moves radially away from the center of
rotation, while the lighter matter moves toward the center. Concentrated
matter can be removed periodically or in a continuous manner. For continuous
operations, the sludge should be fluid to facilitate its removal. The
technology may not be applicable to highly viscous fluids.
Coagulation - fjocculation. Fine. particles suspended in a fluid are
subjected to size enlargement by addition of chemicals (coagulants and floc-
culants), then allowed to settle by gravity or under applied force. Gentle
agitation alone sometimes may afford the flocculation of the particles. The
. ' ' 175
-------
SUSPENDED
MATTER, OIL 8
GREASE CONTROL
TECHNOLOGIES
GRAVITY
SEPARATION
CENTRIFUGATtQN
PHYSICAL/
CHEMICAL
FILTRATION
API-TYPE
"SEPARATORS
•SEDIMENTATION
• FLOTATION
COAGULATION-
FLQCCULATION
•CHEMICAL SEPARATION
.THICKENING
• SOLIDS FILTRATION
• FILTER COALESCENCE
• ULTRAFILTRATtON
SOURCE' WPA
FIGURE 5,2-1 SUSPENDED MATTER, OIL AND GREASE CONTROL TECHNOLOGIES
176
-------
TABLt 5.2-1 KEV FEATURES OF CONTROI TECHNOLOGTCS FOR SUSPENDED MATTER, OHS AMD GREASES
Control
Technology
Operating Principle
Components
Removed
Removal
Efficiency
Feed
Requirements/
Restrictions
By-products
and Wastes
Comments,
Gravity Separation
(API-type
Separators,
Sedimentation,
Flotation)
Csntrifugaiion
Provision of adequate residence Suspended 90+% removal of
time in a stagnant vessel to solids, TSS typical for
allow suspended matter to tars, oils, sedimentation,
separate Into lighter and Immiscible 50% for
heavier than water components. liquids. flotation.
Extra surfaces may be included
to save space (lamella settler),
or rising air bubbles nay be
used to assist separation
(dissolved air flotation).
A greater than gravity force As above As above
field is applied by rapid
rotation to accelerate the
separation
Minimum feed
stream
turbulence.
Oils, sludges,
sol ids
Not useful for emulsions
or very fine particles
As above.
More expensive than
gravity separation.
Used for predrying
sludges from gravity
separation devices or
for separation of fine
particles.
Physical/Chemical
(Coagulation*
Flocculatlon,
Chemical
Separation,
Thickening)
Filtration
(Solids Filtra-
tion, Filter
Coalescence,
UltrafHtration)
Use of agents to promote the
coalescence of fine suspended
solids, tars and oils.
Generally used in conjunction
with a gravity separation
process.
Involves passing wastewater
through a suitable filter
medium. Filter material 1s
discarded cr cleaned by
backf lushing
Promotes
removal of
finely
dispersed
particles
Depends on
medium Both
coarse and
fine
structure
materials
are used
industrially.
90+% removal of
„ fine solids is
achievable with
proper design.
90-99% is
typical.
.'. •
A wide range
of commercial
flocculants
are available.
Filter media
(sand, clay,
fabric or
polymeric
membrane)
Same as
gravity
separation.
Filter backwash,
spent filter
media.
,.
Widely used in makeup
water treatment systems
to remove fine solids.
Filter coalescence or
ultrafiltration are use-
ful for oil emulsions.
Source: WPA.
-------
technology may also be applicable to liquid dispersions-and liquid particu-
lates.- -• •-.'"•. " . " " '* """' ' '"
Chemical separation. Addition of chemicals to break emulsion way be
used in conjunction with filtration and*is normally followed by gravity sepa-
ration. The type and dosage of chemicals required is determined by trial
(American Petroleum Institute, 1969). Chemicals may also be added to precip-
itate sa1ts.or_ to increase crystal size.
Thickening. Slurries previously obtained from gravity, centrifugation,
and filtration methods can be further concentrated, or thickened, by addition
of chemical agents or binders. The thickened slurry may then be subjected
to the same methods for final disposition (Adams and Eckenfelder, 1974;
Humenick, 1977).
Solids filtration. The water stream is passed through a filter medium
which holds back the solid phase. Filters may be of the fabric type, as in
plate and frame, rotating drum (vacuum) and cartridge units, or granular, as
in sand filters. Filtration is generally more expensive than sedimentation
but can remove smaller particles (Humenick, 1977).
Filter coalescence. Gravity separation of oil from water is standard
industrial and refinery practice; however, the API-type separators are inade-
quate for very small oil particles. One very important method for removal
of small oil droplets is coalescence (Water Purification Associates.
December 1975).
When a dispersion of micron-sized droplets of one liquid (oil) in
another (water) flows through an appropriate porous solid, coalescence of the
dispersed phase is induced and separation of the liquids results. The dis-
persed phase can be allowed to accumulate without leaving the porous medium,
with periodic regeneration to remove accumulated oil.
Filter media are usually either the packed fibrous type (e.g., fiber
glass, steel wool) or unconsolidated granular materials (e.g., sand, gravel,
crushed coal). Because of their large specific surface and high voids,-
fibrous media are usually more efficient in removing droplets for a given bed
depth than are granular media. However, fibrous media are more susceptible
to blockage by suspended solids and are more difficult to regenerate, in
addition to being more costly than most granular media.
Advantages of filter-coalescers include high separation efficiency for
dilute suspensions of very small droplets, potentially small space require-
ments, the possibility of continuous operation, and the potential for the
recovery of the dispersed phase. Disadvantages of this process are that
suspended solids can accumulate to require frequent medium regeneration or
replacement, and pumping costs can be substantial. As far as is known, the
system has not been evaluated on retort waters, and extensive pilot plant
testing would be required to determine its feasibility on these waters.
UltraflItration. Passage through a submicron-sized membrane filter
separates emulsified oil as well as suspended matter and large organic
178
-------
molecules (MWt S 1,000). The oil droplets are collected in the concentrate
and removed by gravity separation. This process is significantly more costly
than normal filtration (Water Purification Associates, December 1975).
Con tro 1 Tec hno 1 ggi es
The streams that require removal of suspended matter, oils and greases
are: .- *•
• Mine Water (stream 4)
• Gas Liquor (stream 41)
• Runoff and Leachates (streams 92, 93)
• Slowdowns and Concentrates (streams 88, 104).
Mine water is obtained from dewatering of the deep aquifers under
Tract C-a. While the water does not contain any oils and greases, it does
contain suspended matter. Sedimentation by gravity settling and clarifica-
tion with addition of alum are the approaches proposed to reduce the sus-
pended matter in the mine water. Table 5.2-2 presents the design features
and cost data for clarification, and Figure 5.2-2 shows a cost curve for the
clarifier. This activity could be considered as part of the process rather
than pollution control.
In the Lurgi retorting process, gas liquor is condensed along with light
oils in the third condensation tower. It may also contain some particulate
matter that was not removed in the cyclones and two previous towers, but this
is not envisioned as a problem; however, the gas liquor will need separation
from the light oils. An API-type oil/water separator with channel covers was
examined for this purpose. As stated earlier, the separators are not fully
established as useful devices for shale oils, but difficulty in achieving
separation from light oils is not anticipated. Table 5.2-3 and Figure 5.2-3
present the cost and design information and the cost curve, respectively,, for
the API separator.
Service and fire water runoff, storm runoff, and leachate from shale
piles may contain oily materials. Again, an API-type oil/water separator was
examined as the control. This will also allow separation of suspended matter
along with the water. The cost and design data for this separator are given
in Table 5.2-4, while a cost curve is already included in Figure 5,2-3.
The blowdowns, sludges, and concentrates from various processing units
will also contain suspended matter. These streams are collected in an
equalization pond for possible use in processed shale moisturizing. Since
gravity settlement affords separation of the suspended matter, the equaliza-
tion pond also might be viewed as a pollution control. Its design and cost
are presented in Table S.2-5, and a cost curve is given in Figure 5,2-4.
Other Technologies Analyzed—
In the event that the excess mine water is reinjected into the aquifer
(instead of discharging it on the surface}, even more water will need to be
-------
TABLE 5.2-2. DESI6N ANQ COST OF MINE WATER CLARIFICATION8
Item
Mine Water Flow Rate
Flow Rate/Clarifier
Number of Clarifiers
Diameter
Area of Clarifier
Alum Rate (30 ppm)
Fixed Capital Cost
Direct Annual Operating Cost
Maintenance @ 4%
Alum § 12t/lb
TOTAL
Total Annual Control Cost
Unit
gpm
gpm
ft
103 ft2
ton/yr
$103
$103
$103
Quantity
16,500
970
17
40
22,3
980
2,560
84
235
319
961
This technology could be considered as part of the process rather than
pollution control.
Retention time and rise rate are 120 qiin. and 1 gpm/ft2, respectively.
c Maintenance is based on the fixed capital cost less contingency.
See Section 6 for details on computation of the total annual control cost.
Source: WPA estimates.
180
-------
oo
100
SOURCE: WPA
1000
1500 2000 2500
FLOW RATE, gpm/CLARiriER
3000
10
3500 4000
FIGURE 5,2-2 COST OF MINE WATER CLARIFICATION
-------
TABLE 5.2-3. DESISN AMD COST OF API OIL/WATER SEPARATOR
FOR GAS LIQUOR
Item
Gas Liquor Flow Rate
No. of Channels (1 standby)
Channel Cross Sectional Area
Channel Depth
Channel Length
Fixed Capital Cost
Direct Annual Operating Cost3
Maintenance.© 3%b
Total Annual Control Cost
Unit
gpm
—
ft2
ft
ft
$103
$103
$103
Quantity
586
2
21
6.5
50
161
4
35
The fixed capital cost and direct annual operating cost for the standby
channel are included.
Maintenance is based on the fixed capital cost less contingency.
See Section 6 for details on computation of the total annual control cost.
Source: WPA estimates based on information from American Petroleum
Institute, 1969.
182
-------
M '.
CO
CO
tO
o
en
o
o
a.
o
a
ui
x
500
SOURCE: WPA
1000 1500 2000 2500
FLOW RATE, gpm/SEPARATOR
3000
12.0
10.0
to
o
— 8.0
in
O
O
-------
TABLE 5.2^4. DESIGN AND COST OF OIL/WATER SEPARATOR
FOR RUNOFFS AND LEACHATE
Item
Runoff Flow Rate
No. of Channels (1 standby)
Channel Cross Sectional Area
Channel Depth
Channel Length
Fixed Capital Costa
Direct Annual Operating Cost9
Maintenance @ 3%
Total Annual Control Costc
Unit
gpm
—
ft2
ft
ft
$io3
$103
$103
Quantity
169
2
8
3
50
41
1
11
The fixed capital cost and direct annual operating cost for the standby
channel are included.
Maintenance is based on the fixed capital cost less contingency.
See Section 6 for details on computation of the total annual control cost.
Source: WPA estimates based on information from American Petroleum
Institute, 1969.
184
-------
TABLE 5.2-5. DESIGN AND COST OF EQUALIZATION POND
Item Unit Quantity
Total Water Flow Rate gpm (acre-ft/yr) 2,525 (4,065)
Pond Area acre 3,27
Pond fleetii ft 10
Fixed Capital Cost $103 181
Direct Annual Operating Cost $103
Maintenance t 2%a 3
Total Annual Control Costb $103 46
a Maintenance is based on the fixed capital cost less contingency.
D See Section 6 for details on computation of the total annual control cost.
Source: WPA estimates.
dewatered because some of the reinjected water will flow back to the dewater-
ing we!Is.
The water to be reinjected would need to be clarified. This should be
performed in closed clarifiers to avoid exposure of the excess water to tne
environment. A closed clarifier was examined for the reinjection water, and
its design and cost information is presented in Table 5.2-6. A cost curve
based on the design of the clarifier is shown in Figure 5.2-5.
5.2.2 Dissolved Gases and Volatiles
Dissolved gases include ammonia, carbon dioxide, and hydrogen sulfide,
while volatile materials are low molecular weight organics. Methods for
removing these substances from water are summarized in Figure 5.2-6. Steam
stripping is the most likely process to be used and has been successfully
despor»strayed on a laboratory scale for some oil shale wastewaters (Hicks and
Liang, January 1981).
Inventory of Control Techno!ogles—
Tabie 5.2-7 presents m inventory of applicable control technologies,
along with their key features, for the dissolved volatiles. Basically, most
technologies involve stripping of the d-isso-1 v«d gases by either elevating the
temperature, applying vacuum, -or displacement with carrifer gases. More
specific removal can be accomplished by using an adsorbent selective for the
gas in question.
185
-------
00
en
200
150
O
O
-------
TABLE 5.2-6. DESIGN AND COST OF EXCESS MINE WATER CLARIFICATION*
Item
Excess Mine Water Flow Rate
FT Of* Rate/Clarifier
Number of Clan'fiers
Diameter
Area of Clarifier
Alum Rate (30 ppm)
Fixed Capital Cost
Direct Annual Operating Cost
Maintenance 0 4%b
Alum @ 12$ /I b
TOTAL
Unit
gptn
gpm
—
ft
103 ft2
ton/yr
$103
$103
Quantity
15,330
510
30
30
20.7
900
3,545
115
216
331
This technology could be considered as part of the process rather than
pollution control,
Maintenance is based on the fixed capital cost less contingency.
Source: WPA estimates.
Steam stripping. Steam stripping of sour waters (e.g., waters con-
taining dissolved ammonia and hydrogen sulfide) and coke-oven liquors
(e.g., waters containing dissolved ammonia and carbon dioxide) is standard
practice in the petroleum and steel industries. Stripping has also been used
as part of the "Phenosolvan" process on coal gasification process condensates
(American Petroleum Institute, March 1978; Beychok, 1967).
The dissolved gases are stripped from the solution by bubbling steam
through it, generally in packed or tray columns. The steam may be directly
sparged (live) or used indirectly in a reboiler, as in distillation columns.
The stripped gases, along with other volatile materials, are removed in a
relatively concentrated gas stream which may be treated for adsorption/
recovery of a specific substance or incinerated. Carbon dioxide is readily
stripped at efficiencies of +99%; ammonia strips less easily, and pH eleva-
tion may be required in some cases for 99% removal. Hydrogen sulfide does
not strip as easily as carbon dioxide but can generally be removed down to
the 10-20 ppm range. Casts are for eqyipaent and steam and are proportional
to the volume of water to be treated.
Steam requirements range from approximately 10 to 15 IDS steam per
100 Ibs water treated. For a given separation, .a greater column height Is
-------
'1SOO 9Nll¥H3dO IVflNNV 103810
o
CM
o
o
CJ
O
in
o
o
o
SO
'8
00
O
o
8
8
to
or
E
Q.
01
cc
o
LL.
UJ
i
o
X
Ul
t/)
O
o
ui
K
O
*«H
u.
'ISOD
Q3XN
o
Of
o
188
-------
DISSOLVED GASES
8 VQLATILES
CONTROL
TECHNOLOGIES
STEAM
STRIPPING
VACUUM
DISTILLATION
INERT GAS
STRIPPING
ADSORPTION
SOURCE' WPA
Fi&URE 5-2-6* ,OtSS0LV|l*0tSE3 AND VQUTltES-tQNfROL TECHNOLOGIES
189
-------
TfliLE 5.2-7. KEY FEA1URF.S OF CONTROL TFCHHOLOGIES TOR DISSOLVED GASES AND VOLATILES
Control
Technology
Steam Stripping
Operating Principle
Increasing temperature and
providing a po$itive flow
of steam through the waste-
water Removes volatile
orgamcs and inorganics
with overhead steam.
Components
Removed
NHa, acid
gases
(C02, H2S,
HCN), light
hydrocarbons
Removal
Efficiency
90+% of "free"
anuDonia and acid
gases typical.
Hydrocarbon
rewoval varies
with volatility
of stripped
components
Feed
Requirements/
Restrictions
Acid/caustic
for pH adjust-
ment optional.
By-products
and Wastes
Stripped gases,
uncondensod
steam
Comments
Acid/caustic addition
can be used to improve
the efficiency and
selectivity of the
stripping process
U3
O
Vacuum Low pressure, low temperature As above As above
Distillation stripping process.
Inert Gas Same as stream stripping, but As above As above
Stripping using air, nitrogen, or other
available inert gas in place
of steam.
As above.
As above.
Stripped gases.
Stripped and
inert gases
High energy require-
ments. Not cost
competitive in a plant
where stripping steam is
readily available.
Normally used at ambient
temperature, most
suitable for low concen-
tration wastes.
Adsorption
Adsorption of NH3 onto
clinoptilolite and volatile
orgamcs onto polymeric
res i ns
NH3,
volatile
orgamcs
High removal
efficiencies
possible.
Not suitable
for high con-
centrations
Regenerant and
adsorbent wastes.
Generally used as
polishing step.
a
Source: WPA
-------
required for a lower steam rate. The selection of steam rate and column
height is based on energy and equipment costs.
The stripped gases may be incinerated or treated further to recover
ammonia and sulfur. Ammonia may be recovered as anhydrous ammonia, aqua
(20-30%) ammonia or ammonium sulfate. In cases where the sulfate is derived
from flue gas desulfurization, the sulfate route may be viable depending, in
part, on the marketability of ammonium sulfate and on the costs of alterna-
tive flue gas desulfurization processes. Because oil shale plants generally
will have ammonia available as a by-product, S02 scrubbing with NH3 may be
attractive when the technology is sufficiently developed and tested. Re-
covery of anhydrous ammonia involves considerable capital and energy (steam)
requirements, but these are partially offset with by-product ammonia sales.
The stability of the ammonia market must be considered when selecting a
recovery process.
Vacuum disti1lation. Distillation at reduced pressure has many indus-
trial applications, but these primarily involve distillation or fractionation
of compounds with high boiling points or low thermal stability. The method
may be applicable to stripping of gases and volatile compounds, but the
energy requirements are high relative to those for steam or inert gas strip-
ping.
Insrt^ gas sjtrlgptM- This method is applicable to dilute, or low
strength, wastewaters for which steam stripping may not be practical. The
operating principle is similar to that for steam stripping, except air,
nitrogen, carbon dioxide, or other inert gases may be used. Its application
to high strength liquids is generally not practical because,large column
heights and gas compression costs are required.
Adsorption. Dissolved gases and volatile components may be adsorbed on
specific surface-active materials by passing wastewaters through a bed of the
adsorbent. The gases may then be desorbed thermally, and the regenerated
adsorbent is recycled. This method is generally used in trace removal
applications.
Control Technologies Analyzed—
The streams that may require removal of dissolved gases and volatiles
• Gas Liquor (stream 41)
* Compression Condensate (stream 49).
The compression condensate is also a retort gas condensate obtained
during compression and cooling of the retort gas; therefore, it is combined
with the gas liquor for treatment. The condensates are previously freed from
oil and emulsion in the oil/water separator, but some polar organics, such as
phenols and fatty acids, remain dissolved. A portion of the dissolved
organics can be steam stripped along with other dissolved gases. The gas
liquor also contains a significant amount of ammonia, both free as well as
191
-------
fixed, with sulfur dioxide and carbon dioxide. Since the intended use of the
gas liquor is in processed shale moisturizing, most of the fixed ammonia must
also be removed from the gas liquor prior to its use; otherwise, it may be
released into the environment upon contact with the alkaline processed shale.
Steam stripping alone would remove free ammonia and other volatile components
from the liquor, but pH adjustment may be necessary to release fixed ammonia.
A further control of the released ammonia is also desirable and this may be
accomplished with an ammonia recovery plant.
Ammonia recovery was examined as a control for the gas liquor. The de-
sign specifications for the ammonia recovery plant are given in Table 5.2-8s
the cost is presented in Table 5.2-9, and a cost curve is presented in
Figure 5.2-7. The description and material balance for the process are
presented in Sections 3,3.8 and 4.2.7, respectively.
5-2.3 Dissolved Inorganics
Dissolved inorganics are usually not a problem unless the compounds are
judged to be hazardous (e.g., trace metals) or when fouling of equipment
(e.g., boilers) occurs because of the high salt content of the waters being
used. Natural waters and waters that come into contact with the solids may
need to be treated if they are intended for critical uses in the plant.
Processed shale moisturizing, on the other hand, may not require control of
dissolved inorganics. In fact, waters with high salt content can be used for
this purpose, thereby avoiding the need for other controls. Since gas con-
densates do not contain significant amounts of dissolved inorganics, a treat-
ment may not be necessary.
Inventory of Control Technologies—
Methods for removal of dissolved inorganics are shown in Figure 5.2-8,
while some of the key features of the technologies are presented in
Table 5.2-10. The operating principles for some of the methods shown in the
figure are detailed below.
Precipitation. Chemicals may be added to precipitate salts, e.g., lime
addition for carbonate (hardness) removal. Processed shale is also believed
to behave like a softener for inorganic carbon reduction (Humenick, 1977).
The process is simple, but it will usually require the use of other methods
(e.g., gravity separation, centrifugation, filtration) to remove the precipi-
tate.
Ionexchange. Cations and anions in solution are replaced with hydrogen
and hydroxyl ions on exchange resins capable of producing a water virtually
free of common salts. The resins are regenerated with relatively strong acid
and alkali solutions, and the regenerant wastes must be controlled. Costs go
up with increasing concentration of salts in the water. Ion exchange is
normally used only where a very clean water is required from a relatively
clean or mildly brackish supply. The organics present are not removed and
may foul the exchange resins (Calmon and Gold, 1979),
192
-------
TABLE 5.2-8. DESIGN OF AMMONIA RECOVERY SYSTEM*
Design Parameter
Gas Condensate Feed Rate to
Stripper Column
Ammonia Rate
Steam Rate
Ceo] ing Water Circulated
Electricity
Chemicals
H3P04
NaOH
Steao Stripping Column
Diameter
Height
Material
Reboilers on Steam Stripping Column
Number
Surface area (each)
Material
Keat Exchanger on Steam Stripping Column
Nunbsr
Surface area (each)
Material
Absorption Column
Diameter
Height
Material
Recoil er on Absorber
Surface area
Material
Heat Exchanger on Absorber
Surface area
Material
Stripper Tower
Diameter
Height
Material
Unit
gpm
"Ib/hr
10s Ib/hr
gpm
kW
Ib/hr
Ib/hr
ft
ft
»—
—
ft2
~—
—
ft2
""""
ft
ft
~~
ft2
--
ft2
--
ft
ft
--
Quantity
594
1,883
53
1,080
47
13
293
6.3
95
CS/SS
1
2,300
CS/SS
3
5,000
CS/SS
5
50
SS
701
CS/SS
948
CS/SS
3.3
60
SS
(Continued)
1S3
-------
TABLE $.2-8 (cent.)
Design Parameter
Heat Exchanger on Stripper
Surface area
Material
Fractionator
Diameter
Height
Material
Fractionator Feed Tank
Diameter
Height
Capacity
Material
Reboiler on Fractionator
Surface area
Material
Heat Exchanger on Fractionator
Surface area
Material
Flasn Drum
Diameter
Height
Capacity
Material
Lean Solution Cooler
Surface area
Material
Solution Heat Exchanger
Surface area
Material
'Unit
ft2
-"-
ft
ft
_ —
ft
ft
gal
_-.
ft2
--
ft2
—
ft
ft
gal
-"""
ft2
- —
ft2
-•*
Quantity
1,137
SS
1.5
64
SS
7
4.3
1,278
SS
209
CS/SS
645
CS/SS
4
1.4
142
SS
1,554
CS/SS
303
SS
* This table is based on the Phosam-W process, which is only one example of
many available processes for the recovery of ammonia,
Source: WPA estimates based on information provided by U.S.S. Engineers and
Consultants, Inc., April 1978.
194
-------
TABLE 5.2-9. COST OF AMMONIA RECOVERY
Item Unit Quantity
Fixed Capital Cost $103
Towers 1,660
Heat exchangers 1,920
Drums, etc. 47
TOTAL 3,627
Direct Annual Operating Cost
Maintenance @ 4%a 118
Labor, 24 hr/day @ $30/hr 237
Steam @ $3/MMBtu 1,565
Cooling water @ 3t/m3 circulated 60
Electricity § St/kW-hr 11
Chemicals
NaOH 404
H3P04 __2f
TOTAL 2,419
Credit for Ammonia Sales @ $110/ton $103/yr 816
Total Annual Control Costb $103 2,395
a Maintenance is based on the fixed capital cost less contingency.
See Section 6 for details on computation of the total annual control cost.
Source: WPA estimates based on information provided by U.S.S. Engineers and
Consultants, Inc., April 1978.
195
-------
6000
-------
DISSOLVED INORGANICS
CONTROL TECHNOLOGIES
SOURCE= WPA
CHEMICAL
PRECIPITATION
ION EXCHANGE
MEMBRANE
PROCESSES
EVAPORATION
FREEZING
SPECIFIC
ADSORPTION
REVERSE
' OSMOSIS (RO)
L-ELECTRODIALYSISCED!
-THERMAL
.VAPOR
COMPRESSION
FIGURE-5.2-8 DISSOLVED tNORGANICS,CONTROL TECHNOLOGIES
197
-------
TABIE 5.2-10. KEY FEATURES OF CONTROL TECHNOLOGIES FOR DISSOLVED INORGANICS
ifl
00
Control
technology
Chemical
Precipitation
Ion Exchange
Operating Principle
Use of agents to promote
the precipitation of
inorganic solids from
wastewaters
Substitution of H+ and
OH" ions for objectionable
ionic species Exchange
Components
Removed
Ca, Hg, heavy
metals,
alkalinity
Heavy metals,
F' , Cft ,
scaling species
Removal
Efficiency
Variable,
depending on
constituents.
90+X for most
ions. Regenera-
tion frequency
Feed
Eequi rements/
Restrictions
Lime, polymer,
and soda ash
may be required,
Regenerants ,
replacement
resins.
By-products
and Wastes
Sludg« contam-
inated with
heavy metals.
Spent
regenerants
and resins.
Comments
Generally followed by
filtration and/or
activated carbon
adsorption
Most effective as a
polishing process.
Clearly applicable to
resins regenerated with
add base or salt solutions.
is a key
parameter
boiler feedwater treat-
ment Reeds; of limited
use in treating process
wastewaters containing
high concentrations of
organics or dissolved
solids
Membrane Processes
(RO, ED)
Evaporation
(Thermal , Vapor
Compression)
Freezing
Specific
Adsorption
Separation of dissolved
matter by a seralpermeable
membrane under a pressure
(RO) or electric (ED)
gradient
Application of heat (solar,
steam, etc.) to evaporate
wastewater or concentrate
streams.
Cooling with formation of
ice which fs separated
from remaining brine.
Adsorption of specific ions
onto resins or other adsorbent.
Ionized salts
All nonvolatile
species will
remain in brine
Dissolved salts,
including
organits.
Boron, fluoride,
trace metals
90-99% removal
of dissolved
salts
99+% rejection
of nonvolatile
dissolved solids.
90+% possible
90+X in properly
designed systems
Filtration, pH
adjustment,
foulant
control .
Fouling/scaling
of heat
exchange sur-
faces must be
prevented
As above
Concentrate ,
spent membranes.
Recovered
co ndens ate , non-
condensible
gases, waste
brine
Concentrate
stream
As above.
RO and ED have been used
commercially for desalt-.
nation Concentrate
stream way be 10-30J6 of
Input stream.
Solar evaporation itey be
unacceptable due to air
pollution Vapor
compression evaporation
has been successfully
tested on retort waters.
Not yet demonstrated
comraerda'Hy. ,*
Useful as a polishing
process
Source: WPA
-------
Reverse osmosis (RO). Sometimes called "hyper filtration," RO Is a proc-
ess for recovering relatively pure water from solutions. Water is passed
through a hyperfilter, or semipermeable membrane, which rejects dissolved
materials. As in normal filtration, the driving force is hydrostatic
pressure, but in this case, the pressure has to be greater than the osmotic
pressure of the solution. Osmotic pressures are related to the total molar
concentration of the solution and its temperature (Hicks and Liang,
January 1981).
The water is passed under pressure (greater than 200 psi) through a mem-
brane which is impermeable to most inorganic salts and many organics. These
"rejected1* substances remain in a concentrate stream which may be 10-20% of
the feedwater volume. The treated water or permeate will generally contain
less than 10%, and often less than 1%, of the rejected substances. Costs
scale primarily with the volume of water to be treated but are also dependent
on concentration. At very high solute concentrations (e.g., seawater), costs
increase rapidly due to the high applied pressures that are required. The
flux of water through the membrane, i.e., the permeate recovery rate, in-
creases linearly with the pressure by which the applied pressure exceeds the
osmotic pressure. Fluxes of 10 gal/ft2/day have been measured for retort
water at an applied pressure of 600 psi. Typical applied pressures for
brackish waters range from 200 to 600 psi and greater.
Membranes consist essentially of a thin skin (0.1 to 0.25 urn) of active
chemical (cellulose acetate^ polyamide) on a- porous substructure, which may
then be housed in a spiral-wound module for commercial application. Other
geometries are also available. Rejection of >strong,,electrolytes is normally
in excess of 90% and can exceed 99 percent. Nearly complete rejection is
obtained from most species with molecular weights- greater than about 150.
However, low molecular weight nonelectrolytes (e.g., small organic molecules
like urea, and weak acids such as boric acid) are poorly rejected. Rejec-
tions of these substances can sometimes be improved by adjusting the solution
pH to a value where the compound dissociates (e.g., boron is rejected above
pH = 10).
Some advantages of RO treatment are the low labor and space requirements
and the high rejection rates obtained for a wide range of dissolved contami-
nants, Of particular relevance to oil shale retort water is that both organ-
ic and inorganic compounds can be simultaneously removed under favorable pH
conditions and that such a system can accommodate changing water flow rates.
A serious disadvantage of the process is that the membranes are susceptible
to Dlockage by deposition of solids. This so-called fouling results from
solids present in the feed solution or from precipitation of solids as the
concentration in the brine exceeds the solubility limit; it may even result
biological activity on the membrane surface.
Fouling rates may be reduced by proper pretreatment and by reducing the
concentration increase in the brine. Reverse osmosis does not destroy the
pollutants, it merely concentrates them into a smaller liquid stream. Re-
ducing the concentration increase implies reducing the product recovery and
increasing the amount of brine for disposal. Fouling can be further
-------
controlled by periodic washing, although there is generally a certain amount
of irreversible fouling that determines membrane life and operating costs.
Costs scale proportionately with the volume of product water recovered,
but they are also dependent on the degree of recovery and membrane fouling
characteristics. As the concentration of pollutants in wastewater increases,
so does the osmotic pressure; hence, higher applied pressures are required to
maintain the desired permeate flux. Energy costs, however, are normally
small relative to membrane costs.
Electrodialysis (ED). Electrodialysis is the use of an electromotive
force to transport ionized materials in a solution through a diaphragm, or
membrane. The process can be made selective by using ion-specific membranes
which allow passage of only certain ions. A common application of electro-
dialysis is in the desalting of brackish waters containing 1,000-5,000 ppm of
salts. A removal efficiency of 90-99% is usually achievable.
Thermal evaporation. This approach includes processes in which heat is
applied to vaporize water, leaving a concentrated solution or slurry for
disposal. The high energy required for evaporation is recovered in most
processes by condensing the water vapor and, as a result, producing a stream
of relatively pure water. Volatile contaminants, if present, may require
removal in an upstream stripping process in cases where a clean product water
is necessary. Multiple effect boiling (MEB) and multistage flash (MSF) are
two procedures commonly used for evaporation (Water Purification Associates,
December 1975).
Disadvantages of thermal processes are that volatile substances are not
controlled, and (energy) costs are generally higher than for processes not
involving a phase change. Problems related to scaling of heat transfer
surfaces and corrosion are also encountered. These problems may be accentu-
ated with waters containing high organic loadings, such as oil shale waste-
water. Thermal processes may find application if there is a need for dirty
steam, as occurs in many in situ processes.
Vapor,.compression evaporation. This-is a method for evaporating water
by the use of mechanical energy. Thermal energy required for evaporation is
obtained by mechanical compression of the vapor instead of by heating. The
wastewater is boiled in an evaporator to produce a vapor which is compressed
in order to raise its temperature, and then it is passed through the tubes in
the evaporator where the necessary heat exchange between the vapor and waste-
water takes place. The vapor cools and condenses upon heat exchange and a
relatively pure water is produced.
The advantage of vapor compression is that the heat required for vapor
formation is recirculated so that the amount that must be dissipated is much
less than the latent heat of vaporization. This approach results in rela-
tively low energy requirements and essentially negligible cooling water
requirements. The penalties are the high capital costs associated with the
compressor, which must handle the large volumes of vapor, and increased
maintenance costs. Other disadvantages of vapor compression evaporation are
similar to those of the thermal processes.
200
-------
The energy required for the single effect vapor compression units is
about 70-90 kW-hr per thousand gallons of product water. Some single effect
vapor compression units (RCC evaporator) can recover up to 98% of the waste-
water containing up to 11,000 mg/1 total dissolved solids.
Freezing. The water is reduced in temperature to produce a solid (ice)
phase and a concentrated brine. The ice is washed free of salts and then
melted to produce a virtually pure water. Both inorganics and organics are
removed in the brine stream. Since the costs scale with the volume of water
to be treated, freezing would normally be applied to relatively concentrated
low volume wastes. While this process is theoretically more efficient than
evaooration, it has yet to be applied commercially. It is included irs this
inventory as it may be useful for controlling retort waters, provided opera-
t'ing proolems can be resolved in the future (Barduhn, September 1967; Water
Purification Associates, December 1975).
Sgecif1c adsorption. The processes in this category are similar to the
ion exchange processes, except that the affinity between the sorbent materi-
als and the solutes being removed is of a physical nature. The sorbents may
be natural or synthetic and usually have pores, or lattice vacancies, of
uniform size and dimensions which are specific for the solutes. The proces-
ses are not applicable to high strength wastewaters and are generally used
fo" t^aca removal applications.
Control Technologies Analyzed—
Tie following streams may require control of dissolved inorganics:
® Boiler feedwater (stream 94)
« Cooling Tower Makeup Water (stream 97).
Based on the quality of the water, demineralization using reverse
osmosis was examined as the most economical treatment of the mine water. A
relatively large boiler blowdown is required, however, to maintain acceptable
concentration levels in the boilers in order to prevent scaling. The boiler
blowdown is used for processed shale moistening. The blowdown does represent
an energy loss from the boiler system, and some heat recovery from this
stream might prove cost effective. The material rejected by reverse osmosis
is also used for processed shale moistening after equalization with other
wastewaters. Table 5.2-11 gives the basis for design and costs of boiler
feedwater treatment, and Figure 5.2-9 shows a specific cost curve for boile**
feeawater treatment by reverse osmosis. This treatment could be considered
as part of the process rather than pollution control.
Clarified mine water is usexl as cooling tower makeup. As a treatment,
some sulfuric acid is added to convert calcium carbonate to the more soluble
calcium sulfats. The cooling tower is operated at 1.5- cycles of concentra-
tion, which means that the concentration of dissolved species in the blowdown
is 1.5 times that in the makeup* Since this concentration is not excessive,
there should not be any problem in using the cooling tower blowdown for
processed shale moisturizing. Table 5.2-12 contains design and cost informa-
tion for the cooling tower makeup treatment, and Figure 5.2-10 presents a
201
-------
TABLE 5.2-11. DESIGN AND COST OF BOILER FEEDWATER TREATMENT3
Item Unit Quantity
Boiler Slowdown gpm 21
Steam Losses gpm 11
Softener Regeneration Waste gpm 11
TOTAL MAKEUP (clarified mine water) gpm 43
Fixed Capital Cost $103
Elements @ $1,160 each 20
Pressure vessel t $1,920 each 6
Degasifier _5
Subtotal 31
Total equipment cost
(250% of subtotal) 78
Civil work & installation
(25% of total equipment cost) 19
Contingency 25
TOTAL 122
Direct Annual Operating Cost $103
Maintenance § 3%b 4
Labor, 4 hr/day @ $30/hr 40
Electricity @ 3$/kW-hr 11
Membrane replacement (1.5-yr life)
and chemicals 14
TOTAL 69
Total Annual Control Costc $103 94
a This technology could be considered as part of the process rather than
pollution control.
Maintenance is based on the fixed capital cost less contingency.
c See Section 6 for details on computation of the total annual control cost.
Source: WPA estimates based on information from Peters and Timmerhaus,
1980.
202
-------
180
TOO
30 40
FLOW RATE, gpm
50
60
90
- 70
o
•V9-
J~"
(f>
O
eo „
o:
LU
a.
o
O
Ul
a:
60 =
50
70
SOURCE: WPA
FIGURE b.2-9 COST OF BOILER FEEDWATER TREATMENT WITH REVERSE OSMOSIS
-------
cost curve for the treatment. The cooling tower makeup treatment could be
considered as part of the process rather than pollution control.
TABLE 5.2-12. DESIGN AND COST OF COOLING WATER TREATMENT3
Item Unit Quantity
Evaporation and Drift Losses gpm
Slowdown gpm
TOTAL MAKEUP (clarified mine water) gpm
Cycles of Concentration — 1.5
Sulfuric Acid Addition ,mg/l (ppm) 150
ton/yr 785
Direct Annual Operating Cost $103
Sulfuric acid @ $65/ton 51
Total Annual Control Cost 52
This technology could be considered as part of the process rather than
pollution control.
See Section 6 for details on computation of the total annual control cost.
Source: WPA estimates based on information from Peters and Timmerhaus,
1980.
Other Control TechnologiesAnalyzed—
Several additional dissolved inorganics control technologies were
analyzed. These include reverse osmosis, boron adsorption, and phenol ad-
sorption to remove dissolved salts, boron and phenol, respectively, from the
excess mine water prior to its discharge. Cooling towers and solar evapora-
tion ponds were examined for treating the process waters. Although these
technologies have not been proposed for the Lurgi-Open Pit plant, they were
analyzed as viable alternatives in the event that the wastewater disposal and
reuse strategies for the plant are varied.
As stated earlier, the approach adopted for excess mine water disposal
is to discharge it on the surface. If the quality of the excess mine water
after clarification does not satisfy the criteria for surface discharge, the
gross inorganic content can be reduced first by reverse osmosis (RO),
followed by the removal of boron and phenol from the RO permeate using
specific ion exchange resins.
204
-------
O
tfi
1000 2000 3000
4000 5000 6000
FLOW RATE, gpm
7000 8000 9000 10,000
SOURCE: WPA
FIGURE 5.2-10 COST OF COOLING WATER TREATMENT
-------
Reverse osmosis is a useful technology in that it affords simultaneous
removal of the dissolved inorganics .and-organics. With-this technology, the
wastewater is forced through a semipermeable membrane which allows the water
to pass through but rejects the dissolved matter, especially that which is
highly ionized. At optimum pH, up to 95% of the inorganics and organics can
be rejected. The permeate is usually a fairly clean water that is suitable
for high quality water needs. The RO technology has been tested on the aqui-
fer waters from Tract C-b and a rejection of over 98% of the total dissolved
solids has been obtained (Water Purification Associates, unpublished). The
resin adsorption technologies are widely used in wastewater treatment, al-
though experience with the aquifer waters from Tract C-a has not been docu-
mented. Two flow schemes (Examples I and II) depicting the above treatment
and water reuse technologies are presented in Figure 5.2-11, while the flow
diagrams for the RO process and the boron and phenol adsorption processes are
presented in Figures 5.2-12 and 5.2-13, respectively. Table 5.2-13 gives the
mine water composition before and after these treatments. Design and cost
information for the RO process is presented in Table 5.2-14 and for the boron
and phenol adsorption systems in Tables 5.2-15 and 5.2-16, respectively. The
cost curves for the three technologies are illustrated in Figures 5.2-14,
5.2-15 and 5.2-16.
In the event that the process generated waters are not used for proc-
essed shale moisturizing, then a water reuse plan would have to be de-
veloped One approach among many possibilities would be to treat the gas
liquor (after ammonia removal) by adsorption on activated carbon to reduce
the organic content. The treated water could then be used as cooling tower
,makeup water, thereby controlling the dissolved inorganics. Since the cool-
ing tower can b'e run at fairly high cycles of concentration, roost of the
water is lost as evaporation and drift, and a small amount of blowdown is
produced. The blowdown could then be placed in a solar evaporation pond to
evaporate the remainder of the water, and the precipitated material could be
properly discarded. Figure 5.2-17 shows this train for the gas liquor treat-
ment. Table 5.2-17 presents the material balance around the cooling tower,
while Tables 5.2-18 and 5.2-19 give the design and cost details for the
cooling tower makeup treatment and solar evaporation pond, respectively. The
cost curve presented previously in Figure 5.2-10 is applicable to the cooling
tower makeup treatment indicated here. This treatment could be considered
part of the process rather than pollution control. A cost curve for the
solar pond is presented in Figure 5.2-18.
5.2.4 EH s so 1 .ygd_0r_ganjcs
Removal of volatile organics by stripping may be sufficient for reuse of
process waters in processed shale moisturizing; however, nonvolatile organic
components are not removable by stripping. Therefore, for higher quality
uses, further treatment may be necessary. Some of the available approaches
are discussed below,
Inventory of Control Technologies—
The technologies available for dissolved organics control are shown in
Figure 5.2-19 and are described in Table 5.2-20.
206
-------
ISS'
o
EXAMPLE I
txctss
MINE WATER
11,242
REVERSE
OSMOSIS
PERMEATE
8,330
CONCENTRATE
2,912
BORON
ADSORPTION
PROCESSED SHALE
MOISTURIZING
s*~
8,330 r
PHENOL
ADSORPTION
SURFACE
DISCHARGED
8,330
EXCESS
MINE WATER
10,190
REVERSE
OSMOSIS
PERM EAT
8,149
CONCENTRATE
2,04!
ALL FLOWS IN 6PM
SOURCE^ WPA
EXAMPLE IT
AERATION
POND
PROCESSED SHALE
MOISTURIZING
SURFACE
DISCHARGE
8,149
FIGURE 5 2-11 FLOW SCHEME FOR RO, BORON ADSORPTION AND PHENOL ADSORPTION TREATMENTS
-------
CONCENTRATE
TO PROCESSED
SHALE
MQ'STUWWS
LOW PRESSURE SYSTEM
PERMEATE
TO 80RON
ABSORPTION
STREAM
IDENTITY
FUQWRATE:
I03!b/hr
gpm
TEMPERATURE,0?
PRESSURE, psig
EXCESS MINE
WATER
11242
AMB
AMB
RO PERMEATE
8330
MO
AMB
R 0 CONCENTRATE
2912
no
AMB
COOLING WATER
N.D.
80
AMB
SOURCE^ WPft
FIGURE 5.2-12 REVERSE OSMOSIS PROCESS FLOW SCHEME
208
-------
RQ PERMEATE >
RQ PERMEATE
RESIN
MAKEUP
REGENERATION \
9 JgJRT>
______
CHEMICAL N
1CH OH)
RESIN\
MAKEUP
AMBERLIFE
IRA-743
IN
SERVICE
AMBERLlTE
XAD-4
IN
SERVICE
BORON
-HAOSORPTION
DISCHARGE
n_zni
PHENOL
ADSORPTION
DISCHARGE
REGENERATION
> —
1
in i
!
I
_ TREATED
*" WATER
STREAM
IDENTITY
flowRATE*
RO
PERMEATE
qpm 8330
RESIN
MAKEUP
ND.
REGENERATION I REGENERATION
CHEMICAL CHEMICA
0.03
RESIN
MAKEUP
N.D.
BORON
ADSORPTION
DISCHARGE
NO.
PHENOL
ADSORPTO*
DISCHARGE
N.D.
SOgpd
TEMPERATURE, °F 110 AMB
PRESSURE, psigl AMB
TREATED
WATER
8330
-AMB
-AMB
FIGURE 5.2-13 BORON AND PHENOL ADSORPTION PROCESS FLOW SCHEME
-------
TABLE 5.2-13. EXCESS MINI HATER COHPOS1TION AFTER RO, BORON ADSORPTION
MIS PHENOL ADSORPTION TREATMENTS
Parameter
AlKalinity, as CaCOa
Aluminum
Ammonia, total
Arsenic
Boron
Calcium
Chloride
Chromium
COD
Cyamde
Fluoride
Lead
Mercury
pH (units)
Phenols
Silica
Sodium
TCS
Sulfete
Sulfioe
Flow Rate (gpn>)
Example I
Example II
Raw
Mine Water8
560
0.2
0.89
0.01
0.62
20
18
<0.01
15
0 01
8 5
0.2
0,003
7 0
0 0025
20
320
1,000
205
0.6
(11,242)
(10,190)
RO
Permeate
28
0.01
0.22
0.0005
0.31
0.2
0.9
<0.0005
1.5
0 001
0.85
0.04
0.0008
~7
0. 0013
4
16
50
4.1
0.03
(8,330)^
(8,14Sr
After
RO
Concentrate
2,688
1.0
3.6
0.05
1.9
99.2
86.4
0.05
69
0 05
39 1
0.8
0 01
~7
0.01
84
1,536
4,800
1,004
2.9
(2,912)
(2,041)
Treatment, wg/1
Boron Adsorption
28
0.01
0.22
0.0005
~o
0.2
0 9
<0.0005
1.5
0,001
0 85
0.04
0 0008
~7
0 0013
4
16
50
4 1
0 03
(8,330)
-~
h
Phenol Adsorption
28
0 01
0 22
0 0005
~0
0 2
0 9
<0.0005
1.5
0 001
0 85
0.04
0 0008
~7
~o
4
16
50
4 1
0.03
(8,330)
—
Based on data in Table 4.2-22, assuming mine water is 43% from upper and 57% from lower aquifer.
The removal efficiencies for very small concentrations of boron and phenol have not yet been established.
c In Exaiwle II, more of the mine water is ysed in processed shale moisturizing; therefore, a lower amount
is available for treatment and disposal.
Assuming permeate recovery factor is 80%.
Source WPA estimates based on data from Gulf Oil Corp. and Standard Of! Co, (Indiana), Hay 1977,
210
-------
TABLE 5.2-14. DESIGN AND COST OF REVERSE OSMOSIS TREATMENT
OF EXCESS MINE WATER
Item
Nine Water Flow
Number of Elements
Number of Pressure Vessels
Surface Area
Membrane Flux
Electricity
Fixed Capital Cost
Elements @ $1,160 each
Pressure vessels i $1,920 each
Subtotal
Total equipment cost
(250% of subtotal)
Civil work and installation
(25% of total equipment)
Contingency
TOTAL
Direct Annual Operating Cost
Maintenance & 4%
Labor, 48 hr/day § $30/hr
Electricity @ 3$/kW-hr
Membrane replacement (1.5-yr life)
Scale inhibiting chemical
TOTAL
Unit Example I
gpm 11,242
5,000
800
ft2 /element 165
gal/day/ft2 15-20
kW 3,520
$103
5,800
1,536
7,336
18,340
4,585
5.275
28,200
$103
917
473
832
3,457
70
5,749
Example IIa
10,190
4,530
730
165
15-20
3,190
5,255
1,402
6,657
16,643 ,_
4,161
4,796
25,600
832
473
754
3,133
65
5,257
In Example II, more of the mine water is used for processed shale moist-
urizing; therefore, a lower amount is available for treatment and
disposal.
Maintenance is based on the fixed capital cost less contingency.
Source: WPA estimates based orr information from Hicks and Liang,
January 1981.
211
-------
30,000
25,000
20,000
8 15,000
I
a.
a
10,000
5000
2000
4000 6000 8000
FLOW RATE, gpm
6000
5000
4000 O
t/j
8
3000 1
to
a.
O
2000
LU
fK
1000
10,000 12,000
SOURCE: WPA
FIGURE 5.2-14 COST OF ORGANICS REMOVAL WITH REVERSE OSMOSIS
-------
9.5
9.0
CO
O
o
o.
z
<£
1
0.8
9500
SOURCE: WPA
FIGURE 5.2-15 COST OF BORON REMOVAL WITH ION EXCHANGE SYSTEM
-------
70
S 6,5
V)
o
£
% 6,0
o
UJ
X
5,5
5,0
5000
I
6000 7000
8000 9000
FLOW RATE, gpm
1.4
1.2
1,0
o
v»
o
to
cc
UJ
Q_
O
=3
z
*t
0.8 S
0.6
10,000 11,000
SOURCE; WPA
FIGURE 5.2-16 COST OF PHENOL REMOVAL WITH ION EXCHANGE SYSTEM
-------
LOSSES
i
132
MINE WATER j 528
MAKEUP
t
GAS LIQUOR
594
AMMONIA
RECOVERY
STRIPPED
562 *"
CARBON
ADSORPTION
0/*it IQ&JCTft
"wl«* 3*lt,y
562 "*
COOLING
WATER
TREATMENT
TREATED
WATER ^
562
COOLING
TOWER
EVAPORATION^
681 *"
DRIFT mr
Q ^
COOLING
TOWER
SLOWDOWN
ALL FLOWS IN GPM
SOURCE: WPA
200
EVAPORATION
200
FIGURE 5.2-17 FLOW SCHEME FOR COOLING TOWER MAKEUP AND SOLAR EVAPORATION TREATMENTS
-------
TABLE 5.2-17. MATERIAL BALANCE AROUND COOLIHfi TOWER
CD
Before Treatment
Components
NH3
TOS
Qrganics
H20
TOTAL
Wastewater From
Carton Adsorption
Ib/hr {gpm)
6
429
85
281.049 (562)
281,569
Mine Water
Makeup
Ib/hr (gpm)
__
265
—
264.000 (528)
264,265
Mass %
0.001
0.127
0.016
99.856
100.000
Total Evaporation
Ib/hr (gpm) Ib/hr
6 6
694
85
545,049 (1,090) 440,500
545,834 440,506
After Treatment
Drift Slowdown
Ib/hr (gpm) Mass %
__
0.688
0,084
4,500 (9) _3i._227
4,500 100.00
to Solar Pond
Ib/hr (gpm)
'—
694 ;
65
1D0.049 (200)
100,828
Source: WPA estimates.
-------
TABU 5.2-18. DESIGN AND COST OF COOLING TOWER MAKEUP TREATMENT*
Item
Evaooratlon and Drift Losses
Slowdown
TOTAL MAKEUP
Cycles of Concentration
Sulfurlc Acid Addition
Direct Annual Operating Cost
Sulfuric acid @ $65/ton
Unit
gpm
gpm
gpm
—
mg/1 (ppm)
ton/yr
$103
Quantity
890
200
1,090
5.5
550
1,185
77
* This technology could be considered as part of the process rather than
pollution control.
Source: WPA estimates based on information from Peters and Timmerhaus,
1980.
TABLE 5.2-19. DESIGN AND COST OF SOLAR EVAPORATION POND
Item
Flow Rats to Pond
Evaporation Rate
Pond Area
Pond Depth
Liner (chlorosulfonated polyethylene)
Fixed Capital Cost
Direct Annual Operating Cost
Maintenance @ 2%*
Unit
gpm
acre^ft/yr
in/yr
acres
ft
103 ft2
$103
$103
Quantity
200
290
15
257
3
11,200
14,200
231
* Maintenance is based on the fixed capital cost less contingency.
Source: WPA estimates.
- 219
-------
to
o
CO
o
o
a.
-------
DISSOLVED QRGAN1CS
CONTROL TECHNOLOGIES
SOURCE' WPA
BIOLOGICAL
WET AIR
OXIDATION
CHEMICAL
OXIDATION
THERMAL
OXIDATION
MEMBRANE
PROCESSES
ADSORPTION
FREEZING
SOLVENT
EXTRACTION
EVAPORATION
DISPOSAL AHD
CONTAINMENT
r REVERSE OSMOS!S(ROS
•ULTRAFILTRATIQN(UF)
•CARBON
-RESIN
-PROCESSED SHALE
STRIPPING
COOLING TOWER
SOLAR
FIGURE 5.2-19 DISSOLVED ORGAIttCS CONTROL TECHNOLOGIES
221
-------
TABLE 5.2-20. KEY FEATURES OF CONTROL TECHNOLOGIES FOR DISSOLVED OR6AKICS
ro
w
IsS
Control
lechnology
Biological
Wet Air Oxidation
Chemical Oxidation
Thermal Oxidation
Membrane Processes
{UF, RQ)
Adsorption
(Carbon, Resin,
Processed Shale)
Operating Principle
Oxidation to C02 and H20
(aerobic) or reduction to CH4
(anaerobic) in the presence of
suspended bacteria
Direct reaction of 02 with
wastewater in a closed,
pressurized vessel at
elevated temperatures.
Reaction of organics in
wastewater with 03,
peroxides or chlorine-based
oxidants
Organics are combusted and the
water stream is simultaneously
evaporated.
Separation of water and
dissolved matter by semi-
permeable membrane under
influence of pressure field.
Adsorption of organics in
water by activated carbon
or polymeric resin Powdered
activated carbon has been
used in conjunction with
biological processes
Components
Removed
TOC, BOD, COD.
TOC, BOD, COO,
as wel 1 as some
oxidizable
inor games
TOC, BOD, COD,
oxidizable
inorganics
All oxidtzable
organics
Large molecules
(UO, inter-
mediate size
and ioriizable
molecules (RO).
Many organics
Remova1
Efficiency
50% rfflioval of
TOC typical for
retort waters
Efficiency
enhanced by
addition of PAC
90+X removal of
BOD, COD, TOC
is possible in
a system with a
residence time
of one hour or
greater.
90+% achievable
depending upon
conditions of
operation
Essential 1y
100% in
properly
designed system.
50-98% of
separable
components
50% removal of
TOt typical for
raw and
pretreated oil
shale
was tews ters
Feed
Requirements/
Restrictions
Relatively
constant feed
temperature
and pollutant
loadings are
required to
ralmmize
"shocks" to the
system Air or
oxygen must be
added to aerobi c
systems.
Supplemental
nutrients may
be required
Air or oxygen,
heat If
autothermic
reaction
conditions are
not present
Oxidant
Feed should be
concentrated
to reduce fuel
required for
water
evaporation
Filtration,
pH adjustment,
removal of
foul ants.
Adsorbent.
By-products
and Wastes
Biosludge, COZ
In aerobic,
CH, in anaerobic
process
Vent gases con-
taining CO,
C02, light
hydrocarbons,
NH3, sulfur
species.
Vent gases ,
wastewater and
reaction
products.
Flue gases
Concentrate
stream, spent
membranes
Spent adsorbent
Comments
Long residence times
(days) require large
reactor vessels, ftir
emissions during
aeration may require
that the vessels be
enclosed
Promising, but not
proven in this applica-
tion Fairly rigorous
construction materials
are required
Chlorine-based
oxldants may cause
problems with treated
wastewater
If NH3 or sulfur-
species are present,
NOx and S02 emissions
may require control.
Effective but
expensive control
Long-term membrane
fouling not yet studied.
Probably more effective
as a polishing rather
than a bulk organics
removal process
(Continued)
-------
TABLE 5.2-20 (cant }
Control
Technology
Freezing
Solvent Extractian
Evaporation
(Stripping, Cooling
Tower, Solar)
Disposal and
Containment
*^™« >
Operating Principle
Cooling to form pure ice
crystals which are separated
from the concentrated brine
Wastewater is intimately
mixed with a water- immiscible
organic solvent. Dissolved
organics partition occurs
between water and organic
solvent phase.
Evaporate volatile components
by applying heat via steam,
solar energy, or exchange with
the cooling water return from
the plant. Simultaneously
concentrate the nonvolatile
compounds.
Fixing of the contaminants on
a substrate or disposal or
contalnnent with Isolation
from surroundings
Components Removal
Removed Efficiency
TOC, TBS 90+% possible
Components Found to be
soluble in ineffective for
organic solvent oil shale
used wastewaters.
TOC, TDS, _ Variable,
depending on
the volatility
of the
compounds
TOC, TDS Variable,
• depending upon
the method used
and surrounding
factors.
•
Feod
Requirements/ By-products
Restrictions and Wastes
Concentrate
stream, ice
Solvent, Recovered
solvent regen- organics
eration system
Removal of Overhead vapors
volatile and concentrate
components stream
preferred.
Remova 1 of
volatile
components
preferred.
Coiranents
Volatile components
are removed along with
the nonvolatile? Not
yet demonstrated
commercially
Will not be used unless
suitable solvent is
found
Direct steam stripping
may remove azeotropic
components Slow air
and biological oxidation
are possible with the
cooling tower and solar
evaporation
The wastewater may
be contained, or
remjected, underground.
Contaminants nay be
chemically and physi~
cally fixed on the
processed shale
Source: WPA,
-------
Biologicaltreatment. Biological processes may be aerobic, where organ-
ics are oxidized to -carbon dioxide 'and. water, or anaerobic, where the
organics are reduced to methane. BotJr approaches produce sludge as a waste.
Aerobic processes are faster and less susceptible to toxicity problems than
anaerobic processes, but oxygenation equipment is required. Bench-scale
tests on retort waters have shown that minor changes in retort water composi-
tion can result in a significant reduction in the performance of a weTl-
acclimated system. In the presence of biorefractory (nonbiodegradable)
organics, powdered-activated carbon may be added to the bioreactors to
achieve acceptable reduction in organic content. Necessary pretreatment
includes -stripping, pH adjustment, and nutrient addition; control of specific
toxic materials may be required as well (Adams and Eckenfelder, 1974; Hicks,
et al., June 1979; Hicks and Wei, December 1980).
Met air oxidation (WAO). This is a procedure for the destruction of
organic matter dissolved or suspended in water or wastewater by oxidiz-
ing with air at high temperatures. The temperatures used are above the
normal boiling point of water, and the reaction is carried out under pres-
sure to prevent boiling. The pressure is usually 600 psig or above. The
degree of oxidation achieved depends on the temperature and the material
oxidized.
The advantage of WAO is that the organics do not have to be biodegrad-
able to be oxidized. In fact, WAO often produces biodegradable substances
from refractory material. For economic reasons, it is recommended that
WAO systems be designed to remove no more than 80% of the organics. The
optimum effluent is one that has a COD/BOD ratio of unity, i.e., the chemi-
cally oxidizable material is also biologically oxidizable. Biological
oxidation can be used as a post treatment (Water Purification Associates,
December 1975; Wilhelmi and Knopp, August 1979).
The WAO procedure is normally used for high strength wastes because
costs scale with the volume of water to be treated. The energy needs for
WAO often can be supplied by heat released in the process itself if the
wastewater has a high concentration of reactive material. It is an expensive
process and would be considered only for high strength wastes not amenable to
other treatments, such as solvent extraction.
Chero1ca|oxidation. In this process, oxidation of the organics is
caused by adding oxidizing agents to the wastewaters. The oxidants are
usually comprised of ozone, peroxides, chlorine, chlorates, etc. These
chemicals are nonselective; that is, they oxidize total organic carbon as
well as some inorganics. The oxidation may be carried out at ambient
temperature, which is an advantage. Formation of obnoxious wastes is likely
with chlorinated oxidants. Explosion is also a possibility under uncon-
trolled conditions.
Thermal oxidation. The wastewater is evaporated and the dissolved
organics are simultaneously combusted by directly firing burners that are
submerged under the wastewater. Organic nitrogen and sulfur compounds
will convert to NOx and S02, which is a disadvantage. Additional waste
gases may form if the fuel combustion is incomplete. Heat transfer within
224
-------
the wastewater is efficient; however, due to the presence of a large amount
of noncondensable combustion gases, waste heat recovery from the overhead
vapors may not be practical. Energy requirements can be reduced by using a
praeoncerrtrated wastewater,
Reverse osmosis. In addition to removing inorganics, this process
removes orgam'cs to a certain extent, particularly if the organics are
ionized. Tests on in situ retort waters have shown that, at a high oH, about
95% of the organics are removed. Modern polyamide thin film membranes are
available for high pH operation, but additional data on membrane fouling
characteristics with retort waters are required. The concentrate stream
produced requires treatment, possibly by WAO (Water Purification Associates.
December 1975; Hicks and Liang, January 1981).
Ultraflltratign. In addition to separation of oils and suspended
particles, ultrafiltration will also separate large organic molecules
(HWt £ 1,000). It is unlikely that ultrafiltration will be incorporated into
a treatment train for the removal of large organic molecules, as these are
not a significant fraction of total organics in retort waters. However,
ultrafiltration may be used for emulsified oil separation and, in that case,
would serve as a useful pretreatment to RO (Water Purification Associates,
December 1975).
Carbon adsqrptToru This technology is used to remove organic materials
from sewage and industrial water, as well as taste and odor from drinking
water. It is usually used in conjunction with biological treatment as a
pretreatraept or polishing treatment (Cheremisinoff and Ellerbusch, 1978;
Water Purification Associates, December 1975). Laboratory results from
combined carbon adsorption and biological treatment of modified in situ oil
shale retort water indicate that up to 85% removal of dissolved organics can
ba achieved compared to approximately 50% removal with biological treatment
alone (Jones, Sakaji and Daughton, August 1982).
Activated carbon is produced by charring wood or coal at high tempera-
tures. Charring temperature is the main factor determining the adsorption
characteristics of granular or powdered-activated carbon.
Carbon must be regenerated when it is exhausted. The regeneration is
accomplished by passing the carbon through a furnace at high temperature,
usually around 800-1,000°C, with restricted oxidation to remove the adsorbed
layer on the carbon. The quality of carbon after regeneration is slightly
lower than the virgin carbon, and small quantities of virgin carbon must be
added to retain the required activity.
Activated carbon has ion exchange groups and can be used to remove metal
ions from water. It has been found that, under proper conditions of pH ana
oxidation, some metal ions are adsorbed very strongly.
Regeneration costs are a significant pmrt of overall treatment costs,
making the process uneconomical for high strength wastes, for which frequent
regeneration is required. Regeneration also is not attractive for small
units. Energy costs for running an activated carbon wastewater treatment
-------
plant are small, not considering regeneration, and are proportional to the
pressure drop across the activated- carbon contactor. Fouling in carbon
adsorption units is reduced if the influent stream is adequately pretreated.
Resin adsorption. Resin adsorption is a physical process for removal
of organic materials. Normally, it is considered as a polishing step, after
bulk organic removal in upstream wastewater treatment steps, but may be used
on waters having higher loadings than would be used for carbon. Also, it is
useful for removal of specific toxic materials and phenol.
The polymer (resin) surface can be made hydrophobic or hydrophilic.
Activated groups can be introduced to increase selectivity. Regeneration can
be accomplished by washing with methanol, weak acid or weak base. Steam can
be used to vaporize adsorbed materials.
Adsorption on processed shale. This method has been proposed for
organics control in retort waters at oil shale plants. In studies at
Lawrence Berkeley Laboratory, processed shale from the Lurgi, Parana,
TOSCO II, and three simulated in situ processes were contacted with four
separate simulated in situ retort waters in batch and continuous (column)
systems (Fox, Jackson and Sakaji, 1980). These studies indicated that the
processed shale reduces the inorganic carbon by 50-98%, the organic carbon by
7-73%, and elevates the pH from initial levels of 8-9 to a final level of
10-11. An advantage of the process is that the increase in pH would facili-
tate downstream ammonia stripping and would reduce the loading on downstream
organic removal steps.
freeaing. As previously discussed, freezing also removes dissolved
organics. One advantage of freezing over evaporation processes is that
volatile organics are removed as well. This process has yet to be applied
commercially (Barduhn, September 1967; Water Purification Associates,
December 1975).
Solvent extraction. When wastewater is contacted with a sparingly
soluble immiscible organic solvent, the dissolved organic contaminants
partition themselves between the aqueous and organic phases according to
their relative solubility in each. The organic phase is separated and the
dissolved contaminants removed in a distillation step. Alternatively,
the solvent and dissolved organics may be incinerated. Solvent extraction
is most economical for high strength wastes because costs scale with the
volume of water to be treated and are relatively independent of the amount
of substances removed. Unfortunately, effective solvents for the wide range
of organics present in retort water have not been found, and it appears
unlikely that solvent extraction will be useful in retort water treatment
(Hicks, et al., June 1979).
Stripping. Volatile organics are removed along with ammonia and the
acid gases in a stripping column or other thermal evaporative process. The
amount of organics removed depends essentially on their volatility relative
to water. Organics in retort water are relatively nonvolatile and indications
are that less than 20% will be removed in a column stripping 99% of the
ammonia. Organics in gas1 condensates, such as the TOSCO II foul water, are
226
-------
significantly more volatile, and bench-scale tests have shown that up to 85%
of the organics are removed along with the ammonia. The volatile organics
may then be incinerated, along with the other stripped gases, or may be ad-
sorbed from the gas stream prior to ammonia recovery (Hicks and Liang,
January 1981).
Cooling tower. The cooling tower may be regarded as a water treatment
systara. As such, its main function is to concentrate the dissolved salts,
w-Tich may then be removed at lower cost in a sidestream or blowdown treat-
ment stage. When using process wastewaters as cooling tower makeup, upstream
removal of ammonia and organics need not be as efficient (and therefore as
axpensive) as when the wastewater is discharged. It has been demonstrated
that refinery phenolic wastewaters can be used in a cooling tower and that
faic-oxidation of phenol will occur with very high efficiencies (Hart,
June 11, 1973). Ttie conditions necessary for successful bio-oxidation are
low sulfide (below 2 ppm) and small variations in pH (between 7.8 to 8.3).
Chlorination is used to prevent biological growth. Corrosion of steel has
been low. Ammonia will not concentrate in a cooling tower, but it will
vaporize with the water.
Solar evaporation. Solar radiation incident upon the surface cf an
open evaporation pond is used as the energy source. Large, lined, shallow
ponds are feasible for this application. The rate of evaporation depends
on humidity, wind velocity and solar energy absorbed. Dyes may be added
to the wastewater to increase the energy absorption, with a consequent in-
crease in the rate of evaporation. Land is a major cost, and problems
re1atsd tc final disposition' of the concentrated wastes may arise. Bio-
logical and slow air oxidation of the organics may occur. Volatile and
odoriferous components must be removed from the wastewater prior _ to its
evascra'cion.
Pisfiosal and centalnment. Wastewater can be "controlled" with a minimum
of treatment by some disposal or containment options. These options include
processed shale wetting as part of the disposal procedure. The water and
contaminants are either "cemented" or adsorbed into the processed shale.
Provision of an impermeable lining under the shale pile can prevent water
from percolating through to the ground if the shale does not cement. Water
used for processed shale wetting should not contain any volatiles. Since
water used for revegetation and leaching of processed shale piles will con-
tribute to runoff, it may have to be of considerably higher quality than that
used for moistening.
Wastewater may be injected underground (deep well injection), as in
disposal of some oil well brine wastes (Mercer, Campbell and Wakayima,
May 1979). However, costs for underground injection may be significant
because deep wells are required to prevent contamination of upper level
aquifers. Legal and environmental probTems associated with underground
injection have not been clarified. Reinjection of mine drainage waters may
be a possibility for disposal of this stream when excesses exist. Geologic
ar-d hydrologic effects may require evaluation.
227
-------
Corttro 1 Techno 1 ogl es Analyzed--
The primary stream .which may require control of dissolved organics is:
* Excess Mine Water (stream 75).
Aeration of the excess mine water by bubbling air through it was ex-
amined as a dissolved organics control technology. Aeration serves many pur-
poses; for example, it provides oxygen for biological activity in the water,
carries out oxidation of chemically oxidizable organics, oxidizes some
inorganics and removes odorous compounds. Two examples, reflecting slight
changes in the water distribution in the plant, were analyzed to obtain the
cost and design information for the treatment, as presented in Table 5.2-21.
A cost curve for the aeration pond is shown in Figure 5.2-20.
TABLE 5.2-21. DESIGN AND COST OF AERATION POND
Item
Excess Nine Water Rate
Retention Time
Pond Depth
Surface Area
Capacity of Aerator
Fixed Capital Cost
Land preparation
Aerators
TOTAL
Direct Annual Operating Cost
Maintenance @ 4%
Labor, 10 hr/day @ $30/hr
Electricity @ 3$/kW-hr
TOTAL
Total Annual Control Cost
Unit
9P«n
day
ft
10s ft2
ftVmin. of air
$103
$103
$103
Example I
8,330
1
10
160
7,950
224
206
430
14
99
_4_Q
153
262
Example IIa
8,149
1
1C
157
7,340
•*•)- «n>
It'U
410
14
99
JIZ
150
—
In Example II, more of the mine water is i^sed for processed shale imrstur-
izing; therefore, a lower amount is available for treatment and disposal
Maintenance is based on the fixed capital cost less contingency.
c See Section 6 for details on computation of the total annual control cost.
No cost is given for Example II as it is not part of the case study.
Source: WPA estimates.
228
-------
000
1*1
2 600
4*
in
O
O
400
a.
O
Id
X
200
T~T
T~—n~"
2000 4000
6000 BOOO
FLOW RATE, gpm
180
160
CO
O
ID
tE
1JJ
Q-
o
140
3
Z
Z
10,000 12,000
120 £
O
100
SOURCE: WPA
FIGURE 5.2-20 COST OF AERATION POND
-------
Other Control Technologies Analyzed"
Reinjection of the excess mine water back Into the aquifers was analyzed
as a viable alternative to surface discharge. This approach has been men-
tioned for Tract C-a in the event that excess mine water remained after the
process needs (Gulf Oil Corp. and Standard Of! Co. [Indiana], March 1976). A
combined dewatering rate of 16,500 gptn was calculated from the published data
for the two aquifers under the tract, and approximately 8,300 gpm of the mine
water were estimated to remain after fulfilling the process requirements.
This value was used in determining the essential criteria for reinjection.
The reinjection option has an interesting feature built in: that is,
reinjection of the excess mine water back into the aquifers will increase the
flow at the dewatering wells. Even more water will now be available for
reinjection which, in turn, will again increase the dewatering rate. The
extent of the flow increase is dependent upon the reinjection distance from
the pit—the farther the reinjection point, the smaller the influence on
dewatering. The increases in dewatering rates at equilibrium, as a function
of the distance from the pit center, have been determined by an iterative
process for the two aquifers and are presented in Figures 5.2-21 and 5.2-22.
Figure 5.2-23 represents reinjection pressure as a function of distance. A
distance of 50,000 feet from the pit center was finally selected for the
reinjection into the upper aquifer after taking into consideration the
pressures, flow increases, etc., involved. At equilibrium, approximately
15.000 gpm of the excess mine water will need to be reinjected, causing a
flow-back of 7,000 gpm at the dewatering wells, for a total dewatering rate
of 23,500 gpm. The design and- cost details for the reinjection system are
given in Table 5.2-22, and a cost curve is shown in Figure 5.2-24.
If the use of wastewaters with high organics loading is not acceptable
for processed shale moisturizing or reuse in the plant, additional organics
removal efficiency can be achieved by several technologies, such as reverse
osmosis and carbon adsorption. These technologies have not been proposed for
the Lurgi-Open Pit plant, but they have been analyzed based on their poten-
tial for application in oil shale wastewater treatment.
Reverse osmosis affords simultaneous removal of the dissolved inorganics
and organics. This technology has already been discussed under Dissolved
Inorganics control. Under optimum conditions, high removal of dissolved
compounds is obtainable with RO, but the permeate from RO may still contain
some low molecular weight organic compounds. This stream can be subjected to
organics polishing by adsorption on activated carbon. With this technology,
the wastewater is allowed to pass through a bed of activated carbon on which
the dissolved organics are adsorbed and a cleaner water emerges. The spent
carbon is regenerated periodically by steam or hot gas stripping, and the
desorbed material is incinerated before it is vented to the atmosphere. If
the bulk organics and inorganics have been removed previously (e.g., by RO
treatment), the carbon adsorption treated water can be used for high quality
water needs (e.g., as a makeup to the cooling tower). Figure 5.2-25 shows
the process flow diagram for carbon adsorption (a flow scheme for the
technology, when applied to the gas liquor, was already presented in
Figure 5.2-17). Table 5.2-23 indicates the composition of the treated water,
230
-------
JS3 •
UJ
1
—* 3
ft
LU
CC
I
J_
"0 I
SOURCE' SWEC
_i
i
3456
DISTANCE FROM PIT CENTER TO REINJECTIOM WELL
FIGURE 5.2-21 UPPER AQUIFER DEWATERING RATE INCREASE WITH REINJECTION DISTANCE
-------
6r
n_
19
LU
X
la
C3
LU
a:
UJ
5
LU
(/I
LOWER AQUIFER
°0
j
0
SOURCE' SWEC
12 3456
DISTANCE FROM PIT CENTER TO REiNJECTION WELL
(FT x 10,000)
RSURE 5.2-22 LOWER AQUIFER DEWflTERINC RATE INCREASE WITH REINJECTION DISTANCE
-------
o
8
s
OK
a.
1 2
*»
3g
a>
§ I
O UPPER AQUIFER
O LOWER AQUIFER
_L
J_
j_
•'O !
SOURCE .SWEC
2 3 4 S 6 7
DISTANCE FROM PIT CENTER TO RDMJECTIOM WELLlFT » 10,000)
FIGURE 5.2-23 REfNJECTION PRESSURE AS A FUNCTION OF DISTANCE
-------
TABLE 5.2-22. DESIGN AND COST OF REINJECTION SYSTEM
Item
Excess Mir>e Water Flow Rate
Pipeline Pumps
Flow rate (each)
Capacity (each)
Discharge pressure
Motor (diesel driven)
Carbon Steel Pipe
Length
Diameter
Design pressure
Insulated Carbon Steel Pipe
Length
Diameter
Design pressure
Reinjection Pumps
Flow rate (each)
Capacity (each)
Discharge pressure
Motor (diesel driven)
Reinjection Wells
Carbon steel casing diameter
Depth
Das i go pressure
Valves
Diameter
Valves
Diameter
Diesel Storage Tank
Capacity
Fixed Capital Cost
Pipeline pumps
Pipe (30")
Pipe (10")
Reinjection pumps
Reinjection wells
Valves (30")
Valves (10")
Diesel tank
TOTAL
Direct Annual Operating Cost
Maintenance
Utilities
TOTAL
Unit
gpn
—
gpra
gpni
psig
HP
ft
in
psig
ft
in
psig
—
gpm
gpffl
psig
HP
—
in
ft
psig
—
in
--
in
gal
$103
$103
Quantity
15,330
3
5,100
7,500
150
1,000
50,000
30
200
5,000
10
1,500
30
510
750
1,200
750
10
10
450
1,500
5
30
60
10
50,000
160
15,620
655
5,853
685
79
308
49
23,409
123
2.898
3,021
Source: SWEC estimates.
234
-------
5.0
2000
3000
4000 5000 6000
FLOW RATE, gpm/PUMP
7000
SOURCE; OKI based on information provided by SWEC
FIGURE 5.2-24 COST OF EXCESS NINE WATER REINJECTION
0.6
8000
-------
w
01
STB1PPED\
r
,|
A
£—
i
SPENT
CARBON
STORAGE
AFTER
k BURNER
FEED
TANK
\ /
»*
SCRUBBER
^,,
'
—»J FLUE GAS \
STREAM
IDENTITY
FLOW I03ACFM
HATE I03ll>/ltf
jpm
TEMP,°F
ngree .
, flSly
FUEL
GAS
N.D
AMB
H n
STRIPPED
GAS
LIQUOR
261 6
562
1 10
• HO
~*
MAKEUP
CARBON
004
AMB
AIR
NO.
AMB
SCRUBBER
DISCHARGE
ND
NO
SPENT
CARBON
004
NO.
CA TREATED
PTIR
281 6
562
AMB
SCRUBBEB
FLUE 5AS
H.p
HE-
PROCESS
WAKfUR
WAtfS
'< P
AMP
«- 2UH
SOURCE WPfl
FIGURE 52-25 CARBON ADSORPTION PROCESS FLOW SCHEME
-------
Table 5.2-24 gives the design specifications and cost information for the
carbon adsorption technology, and Figure 5.2-26 presents a cost curve for the
techno:ogy.
TABLE 5.2-23. MATERIAL BALANCE AROUND CARBON ADSORPTION UNIT
Component
NH3
(NH4)2S03
Organics (TOC)
H20
Before
Mass %
0.0021
0.15
0.06
99.79
Treatment
Ib/hr (gpra)
S
429
170
281,049 (562)
After
Mass %
0. 0021
0.15
0.03
99.82
Treatment
Ib/hr (gpm)
6
429
85
281,049 (562)
TOTAL 100.00 281,654 100.00 281,569
Source: WPA estimates.
5.2.5 Water Requirements
Steam Production—
Approximately 1 million Ib/hr of 550 psig steam are produced by waste
neat recovery in the Lurgi retorting system. The steam is of high quality
because only clarified mine water is used. A small portion of the high
pressure steam is reduced to 60 psig by driving the retort gas compressor
turbines. The low pressure steam thus generated is circulated to various
areas of the plant to meet other requirements. This low pressure steam
condenses upon use and is returned to the boilers without treatment. Since a
large portion of the high pressure steam is not used, it is available for
power generation.
Table 5.2-25 presents the steam balance for the plant; as indicated,
approximately 866,000 Ib/hr, or over 80%, of the total steam is available as
a net product. This amount is equivalent to 120 MW of electricity. The
power requirement for the lift pipe air compressor is estimated to be about
150 HW; thus, the excess steam can satisfy about 80% of this requirement.
A 0.5% loss factor and IX blowdown is assumed for the total steam
produced. This loss is made up with additional clarified water. Both the
feedwater and the makeup water undergo boiler feedwater treatment by zeolite
softening ami demineralization. Estimated water quality parameters for the
boilar feedwater are indicated in Table 5.2-26.
•237
-------
TABLE 5,2-24. DESIGN AND COST OF ACTIVATED CARBON ADSORPTION
FOR PROCESS .WATERS
•
Item
Stripped Gas Liquor Flow Rate
Organic Loading
Grgarn'cs Removed
Carbon Capacity
No. of Beds (1 standby)
Bed Diameter
Bed Depth
Carbon Volume/Bed
Carbon Regeneration
Regeneration Period
Carbon Loss in Regeneration (5%)
Furnace Area
Fuel
Steam
Fixed Capital Cost
Direct Annual Operating Cost
Maintenance @ 4%*
Labor, 12 hr/day @ $30/hr
Regeneration and carbon replacement
TOTAL
Unit
gprti
mg COD/1
Ib COD/hr
1b COD/1 b C
—
ft
ft
ft3
Ib/day
days
Ib/day
ft2
Btu/lb C
Btu/lb C
$1Q3
$103
Quantity
562
1,600
800
0.6
2
12
6.5
3,350
18,000
1
900
180
3,000
1,450
2,500
81
118
882
1,081
* Maintenance is based on the fixed capital cost less contingency.
Source: WPA estimates based on information from Cheremisinoff and
Ellerbusch, 1978.
238
-------
3.0
2.5
8
g»
o
o
i.5
'200
300
A.
400 500 600
FLOW RATE, gpm
1.50
tag
1.00
DC.
UJ
Q.
O
13
Z
z
-------
TABLE 5.2-25. STEAM PRODUCTION, USES AND BOILER FEEDWATER MEEDS
Parameter
Steam Production
Waste Heat Boiler
Steam Uses
Ammonia Recovery
Stretford Gas Treatment
Naphtha Recovery
DEA Treatment
Net for Power Generation
TOTAL
Net Steam Circulated
Feedwater Makeup Requirements
Losses (0.5% of circulated)
B 1 owdown
Softener Regeneration Waste
TOTAL FEEDWATER MAKEUP
Unit '" '' Quantity
. 10s Ib/hr
1,060
103 Ib/hr
53
1
10
130
866
1,060
gpm 2,120
gpm
11
21
11
43
Source: WPA estimates.
TABLE 5.2-26. WATER QUALITY PARAMETERS FOR BOILER FEEDWATER
Parameter
TDS, mg/1
Total Alkalinity, rag/1 CaC03
Total Hardness, mg/1 CaC03
Iron, mg/1 Fe
Copper, mg/1 Cu
Silica, mg/1 Si02
Specific Conductance, pmhos/cm
Low Pressure
0-300 psi
2,300*
470*
0.3
0.1
0.05
100*
4,700*
High Pressure
600-750 psi
1,300*
270*
0.2
0.025
0.02
20*
2,700*
* For a boiler concentration factor of 1.5.
Source: WPA estimates based on data from Krisher, August 28, 1978.
240
-------
Cooling Water—
Typical cooling water requirements for the Lurgi-Qpen Pit plant a^e
summarized in Table 5.2-27. Treated mine water could be used as the makeup
to the cooling tower. The water quality parameters for the cooling water are
indicated in Table 5.2-28. The cycles of concentration are kept low; the
relatively large amount of blowdown is used, after equalization with other
streams, far processed ' shale quenching and moistening. Sulfuric acid is
added to the makeup water to control carbonate scaling.
TABLE 5.2-27. PLANT COOLING WATER REQUIREMENTS
Water Use Unit Quantity
Evaporation gpm
Second and Third Condensation Towers 325
Naphtha Recovery 5
Gas Compression 8
Amine Absorber 66
St^etford Gas Treatment 2
Ammonia Recovery 27
Steam Condensing, Plant Drives 450
TOTAL EVAPORATION ' 883
Cooling Tower Drift gpm
(1% of evaporation)
Slowdown gpm
TOTAL COOLING TOWER MAKEUP
Cycles of Concentration
Source: WPA estimates.
Processed Shale Hoi stem ng—
The hot processed shale leaving the Lurgi retorting area must be cooled
and moistened with water in the processed shale moisturizing mixer before
being sent to the disposal area. The hot shale is first quenched, resulting
in evaporation of approximately 1,984 gprn of water. The steam generated from
the quenching operation is combined with the Lurgi flue gas before entering
the electrostatic precipitator. The quenched shale is then moisturized to a
final moisture content of approximately 19% to facilitate compaction and
stabilization. The optimum moisture content and the extent to which the
wastewaters should be treated have not yet been determined. The falowdowns
from the cooling tower, boilers, and clarifiers could be used for quenching
and isoistening. These water streams should not contain volatile material
241 " -
-------
TABLE 5.2-28. WATER QUALITY PARAMETERS FOR COOLING TOWER RECIRCULATIQN"
Parameter
Langelier Saturation Index
Ryznar Stability Index
PH
Calcium, Big/1 as CaC03
Total Iron, mg/1
Manganese, mg/1
Copper , mg/1
Aluminum, mg/1
Sulfide, mg/1
Silica, mg/1
(Cs)-(S04), product
TDS, mg/1
Conductivity, micromhos/cm3
Suspended Solids, mg/1
TOC mg/1
HH3 mg/1
CN" mg/1
Limits
Minimum Maximum
+0.5 +1.5
+6.5 +7.5
e.o s.o
20-50 300
400
0.5
0.5
0.08
1
5
150
100
500,000
2,500
4,000
100-150
600
100
5
Remarks
N&nchromate treatment
Nonchromate treatment
Nonchromate treatment
Chromate treatment
For pH < 7.5
For pH > 7.5
Both calcium and
sulfate expressed
as njg/1 CaC03
a
concentration.
The limits for the Langelier Saturation Index (an indication of CaC03
saturation) presume the presence of precipitation inhibitors in nonchromate
treatment programs. In the absence of such additives, the limits would be
reduced to 0 and 0.5.
Source: WPA estimates based on data from Hart, June 11, 1973.
242
-------
which would be released upon contact with the hot shale. Table 5.2-29
indicates the water flow rates (gpm) for quenching and moisturizing.
TABLE 5.2-29. WATER REQUIREMENTS FOR PROCESSED SHALE
DISPOSAL AND OUST CONTROL
Water Required Shale Rate Water Rate
Water Use Mass % of Shale 103 Ib/hr gpm
P"g_cessgd_Sha1e Disposal
Quenching 12.5 7,913* 1,984
Moistening 23.0 7,913 3,640
Processed Shale Dust Control 2.9 7,913 459
Revegetation 4.1 7,913
Raw Shale Dust Control
At Mine
Crushing
At Plant
3.2
1.4
1.0
9,916
' 9; 915
9,916
634
285
190
* Dry processed shale rate.
Source: WPA estimates.
Processed Shale 01 sposal—
At the disposal area, water is needed for dust suppression and for
revsgetation. Table 5.2-29 also includes the water requirements for these
needs. The water required for dust control is 2.9 mass percent of the dry
processed shale rate, and the requirement for revegetation is 4.1 mass
percent. Any water used in revegetation at the disposal area should be of a
quality acceptable for agricultural use.
Oust_Co'ntro1--
The water requirements for mining, crushing, and fugitive dust control
are also summarized in Table 5.2-29, These requirements are given as flow
rates (gpm), as well as mass percents of the raw shale rate. The mass
percents are 3.2%, 1.4%, and 1.0% for mining, crushing, and fugitive dust
control, respectively.
243
-------
Water used in confined mining operations should be low in volatile or
toxic materials because mining personnel• will be directly exposed to it.
Also, the water should contain low amounts of suspended and dissolved, sol ids,
to reduce clogging and scaling in spray nozzles. The water used in Brining,
crushing, and fugitive dust control operations cannot be recovered.
Miscellaneous Requirements—
These include potable and sanitary needs, as well as service and fire:
water requirements. Table 5.2-30 summarizes these water requirements in
terms of makeup, discharge and overall water consumption. Any treatment
necessary for these waters is standard practice and not a pollution control
activity and, therefore, is not discussed in depth.
TABLE 5.2-30, POTABLE AND SERVICE WATER REQUIREMENTS
Usage Consumption Employees Makeup Discharge
Water Use gal/Man-Shi ft % No. gpm gpm
Sam' tary/Potabl s
At Plant 33 28 950 16 10
At Mine 33 28 580 10 8
Service/Fire Water
At Plant
At Mine
66
50
33
100
950
580
29
14
19
Source: WPA estimates.
5.3 SOLID WASTE MANAGEMENT
The Lurgi-Open Pit processing facility will be a source of large quan-
tities of plant wastes which will require disposal. Table 5.3-1 indicates
the makeup of the waste material that will be discarded from the plant over a
period of 20 years (project life). Sections 3 and 4 give information about
the origin and composition of these streams.
The waste material disposal approach and the practices used in the
disposal can have a long-lasting impact on the atmosphere and hydrology of
the area as well as on the local aesthetics and habitat. The primary areas
of environmental concern in this regard are;
244
-------
TABLE 5.3-1. MAJOR WASTES PRODUCED OVER A PERIOD OF 20 YEARS
Stream
Number Stream Description
2
3
28
29
59
70
88
90
91
92
93
95
96
102
103
104
105
109
111
Subore
Overburden
Slowdown from Waste Heat Boiler
Processed Shale
Spent Amine
Stripped Gas Liquor
Humidified Air Cooler Slowdown
Water for Dust Palliatives
Processed Shale Revegetation Water
Raw Shale Leachate
Storm Runoff
Service and Fire Water
Mine Water Clarifier Sludge
Treated Sanitary Water
Sanitary Water Treatment Sludge
Boiler Feedwater Treatment
Concentrate
Cooling Tower Slowdown
Clarified Mine Water to Processed
Shale Moistening
Aerated Pond Sludge
TOTAL
Material Quantity
Quantity, as a Percent of
106 tons Total Waste Quantity
78.21
408. 00
0.83
623.86
N.D.*
22.05
26.06
61,81
25.58
N.D.
5,91
0.75
6150
0.71
N.D.
0.43
.
44.27
86.41
N.D.
1,391.38
5.62
29,32
0.06
44.84
N.D.
1.58
1.87
4,44
1.84
N.D.
0,42
0.05
0,47
0.05
N.D.
0.03
3.18
6,21
N.D.
99.98
* N.D. = Not determined.
Source: ORI estimates based on information from Gulf Oil Corp. and Standard
Oil Co. (Indiana), March 1976, and Rio Blanco Oil Shale Co.,
February 1981.
245
-------
» Surface Hydrology
* Subsurface Hydrology ~ "
» Surface Stabilization
• Hazardous Wastes.
This section briefly describes the disposal approaches that may be
applicable to the wastes produced from an abovegrourvd retorting facility
(e.g., Lurgi-Open Pit) involving surface mining of the oil shale. In addi-
tion, a discussion of control technologies available to mitigate the poten-
tial impacts in the areas mentioned above is presented. The applicability
of these technologies should be determined on a site-specific, case-by-case
basis. Specific information for the facilities involving underground mining
and aboveground retorting can be found in the TOSCO II PCTM, while specific
information for the combined Modified In Situ-aboveground retorting opera-
tions can be found in the MIS-Lurgi PCTM.
5.3.1 D1sposal Approaches
The following discussion applies to the basic methods for handling solid
wastes produced by the Lurgi-Open Pit processes. Generally, the mining
method, geography and hydrology of the area, and the waste characteristics
influence the applicability of a disposal approach. The key features of each
approach are summarized in Table 5.3-2. A discussion of the control tech-
nologies applicable to these disposal alternatives is presented later in
this section. •
landfills—
A landfill basically entails placing the waste material as a compacted
fill in a suitable location. The wastes from the processing facility are
transported to the disposal site by conveyors or trucks and then hauled to
the active portion of the landfill. Usually, the solids are laid down in
lifts of 9-18 inches and compacted to a suitable in-place density. The
compacted fill may be built with a proper slope to a vertical height of
40-50 feet and then flattened, or benched, to provide a passageway for the
disposal equipment and to facilitate runoff collection. The overall landfill
can be constructed gradually in this fashion, using a multiple-bench arrange-
ment.
Depending upon the geography of the disposal site, the landfill may be
built on a level or nearly level surface, in the head of a valley, or across
a valley. The applicable control technologies will vary somewhat with site
topography but still will be designed to protect the surface and subsurface
waters. Applicable control technologies include runon and runoff catchment
ponds, embankments and diversion systems, liners and covers, and revegeta-
tion. Provision for structural stability of the fill is also a major con-
sideration.
A surface landfill of some type will need to be included in most
oil shale developments. This results from the shale undergoing a volume
246
-------
TABLE 5.3-2. KEY FEATURES OF SOLID WASTE DISPOSAL APPROACHES
__«,_«,.«„ _ . ,. . 1 !___ .11 . 1 1 . r ..... 1 11 II Illl I. _ ,
Disposal
Approach
Principle
Advantages
Disadvantages
Landfills
Open Pit
Backfill
Hazardous Waste
Lagoon
Place wastes as fin in
a convenient surface
location and isolate
from the surrounding ,
environment.
Place wastes as fill in
the inactive parts of
the pit.
Place hazardous wastes
in a lined pond and
isolate them.
Relatively simple placement
and isolation of wastes.
Does not .interfere with
production.
Decreases size of necessary
surface landfill. Restores
original contours.
The oil shale developer
can maintain absolute
control over the waste
disposition.
Dust and erosion control and
reclamation/revegetation are
relatively labor-intensive
operations. Occupies a
significant amount of land
surface.
Difficult to isolate the
wastes from the surrounding
environment. Placement is
relatively difficult, complex,
and interferes with produc-
tion.
Design, construction, and
reclamation may be complex.
Requires a relatively level
site.
Source: SWEC.
-------
expansion upon mining, crushing, and processing, which precludes all of the
shale being'returned to .the mine, • •-• '•- .--•-..
Open Pit Backfill—
In many respects, the procedures and technologies used in open pit
backfilling would be similar to those used in surface landfills. That
is, the wastes would be transported to the pit, compacted, and built up
to the desired elevation. Stable slopes must be maintained during the
simultaneous production and disposal activities and during reclamation,
unless the final contour is level with the ground surface.
Runon and runoff collection systems may be necessary to keep the fill
and production areas as dry as possible. Permanent groundwater and leachate
collection systems may be impractical because the collected water would need
to be pumped to the surface and treated for discharge long after the project
is shut down. Use of bottom and side liners may be a consideration to reduce
the interaction between any leachate produced and groundwater. Placing the
wastes in layers to restore the geologic and hydrologic system may also be a
consideration.
The pit may be filled below, level with, or above the surrounding ground
surface depending upon the quantity of the waste material, site-specific
conditions, development plans for the future and permit requirements. A
major advantage of backfilling the open pit is that the original contour of
the land surface can be more closely restored. Space requirements for the
production and disposal activities may be a limiting factor for backfilling
small pits.
Hazardous Waste Lagoon—
A hazardous waste lagoon would be a permitted facility either on the
project site or off site. It would likely consist of a lined pond designed
to be suitable for the containment of hazardous wastes. The major consider-
ations in the design of such a pond would include a runon diversion system,
an embankment, one or two impervious bottom liners with a drained sand
layer below or between them, a slurry wall beneath the embankment, a surface
seal layer, and provisions for reclamation and revegetation (U.S. EPA,
September 1980).
Once the lagoon is filled to its capacity, wick drains could be in-
stalled to facilitate evaporation, allowing quicker consolidation of the
sludge. Gravel could also be added to aid consolidation. An impermeable
surface seal may then be added on top and joined with the bottom liner to
isolate the wastes from the surrounding environment. The final aspects would
include placing subsoil and topsoil over the seal, followed by revegetation
of the surface.
5.3.2 Surface Hydrology Control Technologies
Solid waste management practices in the area of surface hydrology en-
tail the handling of surface waters on and around the disposal facility.
248
-------
Specifically, surface streams and precipitation are prevented from running
onto the waste pile and contaminated waters (runoff, leachate) are kept from
mixing with the natural waters.
The technologies discussed below are those that are applicable to a
surface landfill, and they are summarized in Figure 5.3-1. The key features
of the technologies are highlighted in Table 5.3-3 and a more detailed
description with cost data is presented in the text.
Runon Dj vers 1 on System—
A runcn diversion system will generally be needed with any surface
landfill to prevent surface water from flowing onto the waste material and
becoming contaminated or causing erosion. The system may include ditches,
lined channels, conduits, and embankments arranged to direct the flow of
surface water around or away from the waste material, and energy dfssipators
to moderate the impact of the flow.
The complexity and extent of the system will vary widely based on the
amount of water to be diverted and the arrangement of the site. For a fill
on a relatively level site, runon diversion may require only a system of
channels and small embankments to deflect surface flow away from the land-
fill. In the case of a head-of- valley fill or a cross-valley fill, runon
diversion might include an embankment dam to retain peak flows from the
design storm until they can be passed through a conduit beneath or around
the fill. Alternatively., the system may consist of a conduit or channel
large enough to pass the design flow without an embankment (without reten-
tion).
design of a runon diversion system will be influenced by: tne size
of the drainage area and topography which affect the runon rates, retentions,
and embankment material quantities; the size, length, and complexity of
controlled release structures and channeling systems; and the need for and
extent of energy dissipators and/or drop structures. For example, the runon
from a site with a large drainage area in a gently sloping topography could
be diverted quite efficiently by an unlined canal or channel; another site
with small runoff rates, but highly erodible steep topography, may necessi-
tate cost-intensive lined channels, flumes or conduits, as well as drop
structures or energy dissipators.
Ryngff_Col1_ecti on System— -
A runoff collection system usually consists of a system of channels,
ditches, and conduits arranged to prevent the surface water that has con-
tacted the waste material from leaving the site. Another purpose of this
system is to drain the surface water from the wastes to limit the erosion and
infiltration potential. Collected water may also be used to meet process
needs,
The basic elements of this system are backs! oped benches on the face
of the landfill and a means of collecting the water from the fill surface.
Generally, half-round pipes, impervious membranes, or highly compacted soil
'""249
-------
RUNON
DIVERSION
SYSTEM
— WITH RETENTION
!- NO RETENTION
junrHvt
HYDROLOGY
CONTROL
rcruunr nflicc
RUNOFF
COLLECTION
SYSTEM
RUNOFF/LEACHATE
COLLECTION PONDS
SOURCE-' SWEC
FIGURE 5 3- I SURFACE HYDROLOGY CONTROL TECHNOLOGIES
250
-------
TABLL 5.3-3. KEY FEATURES OF SURFACE HYDROLOGY CONTROL TECHNOLOGIES
Control
Technology
Principle
Runon Diversion
System
With Retention
No Retention
Runoff Collection
System
Runoff/Leacnate
Collection Ponds
Uses channels and embank-
ments to prevent surface
water from contacting
the waste material.
Embankment dam holds
peak flows for controlled
release, evaporation, or
percolation into the
ground.
Channel or conduit is
sized to convey peak flow
with no retention of
water.
Drained benches collect
and remove precipitation
falling on the disposal
site.
Lined ponds are used to
retain leachate and
runoff.
Purpose
Reduces erosion and
increases site stability.
Reduces the amount of water
contacting the waste
material, thereby reducing
the potential for surface
water pollution.
Reduces erosion of fill and
infiltration into fill.
Collects water for reuse or
discharge.
Prevents release of contami-
nated waters.
Comments
Reduces the amount of water
contaminated, thereby reducing
treatment costs.
Requirements for the channel
or conduit are greatly
reduced. Provides flexibility
in the use of the collected
water.
Eliminates the need for runon
retention structures and
associated maintenance. More
expensive than using an
embankment for retention and
controlled discharge of the
peak flow.
Decreases erosion and
infiltration. Requires main-
tenance.
Collects water for reuse,
treatment and discharge.
Source: SWEC.
-------
or wastes are used to line ditches which collect the runoff from the bench
and the segment of the landfill slope 'afeoye it, as shown in Figures 5.3-2
and 5.3-3. The ditches empty into central conduits leading to a "containment/
evaporation pond at the toe of the landfill." On larger piles or in areas
with extensive rainfalls, small embankments on the crest of the landfill or
on the benches might be used to retain the runoff and thus limit the peak
flows into tne rest of the drainage system.
A problem with limiting the peak flows using embankments on the waste
pile is that the water ponded on the landfill will have a greater tendency
to infiltrate the waste material. This increased infiltration could have a
detrimental effect on the stability of the slope and will somewhat increase
the amount of water which must be handled by the leachate collection system
(discussed under subsurface hydrology).
The costs for a variety of runoff collection system designs for surface
landfills were estimated and these are plotted in Figure 5.3-4. Example 1
used shaped benches with unlined ditches for lateral conveyance and concrete
weir collectors and corrugated metal pipe with energy dissipators for
vertical conveyance. It also incorporated some temporary retention of runoff
on the waste pile surface, which reduced the necessary capacity and cost of
the vertical conveyance portion of the system. Example 2 used split cor-
rugated metal pipe to line the collection ditches to facilitate lateral
conveyance, and concrete weir collectors and corrugated metal pipe with
energy dissipators for vertical conveyance. Example 3 used the lined ditches
for lateral conveyance, with a concrete flume and a stilling basin for
vertical conveyance.
The cost data, as can be seen in the plot, are highly dependent on the
particular design, and no single cost curve relationship can be drawn through
the data points. Example 1, which assumes a more modest design^ defines the
lower boundary of the cost envelope, and Example 3 defines the high end of
the cost envelope.
The design of the runoff collection system for open pit backfills
would differ from that for surface landfills because the runoff has to be
pumped to the surface for its disposition. Hence, a system for an open pit
project might consist of a series of collection sumps located at the junction
of the pit wall and landfill, from which the collected water is pumped to
the surface and probably used for processed shale moistening. Both the
sumps and pumps require only operating expenditures, as any associated
capital expenditure is considered to be a part of the mining plan. The total
annual operating costs for the sumps and pumps for an open pit mine, as
described in Sections 2, 3 and 4, were estimated to be $63,000 and $16,000,
respectively, while the total annual control costs were estimated to be
$64,000 (0.3 cents/bbl of oil) and $16,000 (0.1 cents/bbl of oil). The
details of cost computation are presented in Section 6.
Runoff/Leaehate Collection Ponds—
At the outlet of the collection system for surface runoff, a structure
is needed to contain the collected water for reuse, treatment and discharge,
252
-------
HIGHLY COMPACTED SOIL HALF-ROUND PIPE
PAVED INVERT SECTION
COLLECTOR DRAIN DETAIL
SOURCE- SWEC bosedon Colony Development Operation, March 1980
FIGURE 5.3-2 TYPICAL RUNOFF COLLECTION SYSTEMS
-------
UNDERGROU
NO COLLiCTOft DRAIN PIPE
SECTION
PLAN
SOURCE: SWEC based on Colony Development
Operation, March 1980
SECTION
FIGURE 53-3 RUNOFF COLLECTION AND CHANNELING
-------
-------
or for evaporation. The structure would consist of an embankment across a
former stream channel to form a pond,- and 'the pond may fee-lined or unlined
depending upon the nature of the impounded material. If a liner is needed,
it would be protected from wave action, as necessary, using rip-rap, a sand
layer, soil cement or similar materials. Since the pond would be located at
the base of the landfill, it might also be used to collect the leachate from
the fill.
Cost data for four examples of runoff/1eachate collection ponds for
surface landfills are presented in Figures 5.3-5 and 5.3-6. Figure 5.3-5
presents the total cost of the embankment and liner as a function of the
construction material quantities used in each case, while figure 5.3-6
isolates the cost of the liner as a function of the liner material quanti-
ty only. Examples 1, 2 and 3 utilized compacted processed shale as the
liner, while Example 4 used Mancos Shale as the liner. The relatively hign
cost of using an off-tract material (Example 4) is evident in the figures.
The cost increase is incurred due to the source development, processing
and hauling of Mancos Shale. Slight cost differences may be observed
between similar systems, and these can be attributed to site-specific
features, such as the arrangement and configuration of the embankments and
ponds,
A runoff collection and containment system for a pit backfilling
approach differs from that for the surface landfills. Instead of an embank-
ment and pond downgradient from the landfill, a series of collection sumps
and pumps would be used, as discussed under Runoff Collection System.
5.3.3 Subsurface Hydrology Control Technologies
The technologies and practices in the area of subsurface hydrology
involve the handling of groundwater seepage under a landfill to prevent
infiltration of the pile and the control of water from the pile to prevent
contamination of the groundwater. The technologies, as summarized in
Figure 5.3-7, are applicable to a surface landfill, and their key features
are presented in Table 5.3-4. Detailed descriptions of the technologies,
along with cost information, are presented below.
For open pit backfilling, subsurface hydrology control may consist of
aquifer dewatering. Since this operation would be an integral part of the
mining plan, additional costs for backfilling would not be incurred.
Liners and Covers—
A liner is essentially a material with low water permeability that is
installed at the bottom of a landfill or pond. Its purpose is to prevent the
contaminated waters from the wastes from mixing with the groundwater. It
also prevents groundwater from infiltrating the bottom of the landfill.
A cover is also made up of a low-permeability material and it is used as
a surface sealer for the landfill. It prevents the runoff from infiltrating
the pile, thereby reducing the quantity of the leachate and minimizing
stability problems.
256
-------
O
4A>
ff)
O
O
J-
0.
<
O
Q
lu
X
J_
O
_L
O.i 0,2 0.3 0.4
CONSTRUCTION MATERIAL VOLUME , 106 yd3
0.5
NOTES:
All Examples include cost of embankments and pond liners.
Examples 1, 2 & 3 Include pond liners constructed of processed shale.
Example 4 includes a liner constructed of Mancos Shale (off-tract
material); cost is increased due to processing and transport.
See Section 6.2.3 for details on the solid waste management cost
methodology.
SOURCE: SWEC
FIGURE 5.3-5 RUNOFF/LEACHATE POND COSTS
" 257
-------
1000
800
600
V)
O
O
£L
4
O
400 -
200 -
O,
0 (00 200
LINER MATERIAL QUANTITY, I03 yd3
NOTES:
Examples 1, 2 & 3 include liners constructed of processed shale.
Example 4 includes a liner constructed of Mancos Shale (off-tract
material); cost is increased due to processing and transport.
See Section 6.2.3 for details on the solid waste management cost
methodology.
SOURCE: SWEC
FIGURE 5.3-6 RUNQFF/IEACHATE POND LINER COSTS
258
-------
LINERS
AND
COVERS
SUBSURFACE
HYDROLOGY
CONTROL
TECHNOLOGIES
LEACHATE
COLLECTION
SYSTEM
I— SYNTHETIC
OFF-SITE
NATURAL MATERIAL
COMPACTED
PROCESSED
SHALE
GRQUNDWATER
COLLECTION
SYSTEM
SOURCE^
FIGURE 5.3-7 SUBSURTACE HYDWL06Y CONTROL TECHNOLOGIES
259
-------
TABLE 5.3-4. KEY FEATURES OF SUBSURFACE HYDROLOGY CONTROL TECHNOLOGIES
Control
Technology
Principle
Purpose
Comments
Liners and Covers
Low permeability layer
severely restricts
seepage.
ISi
en
o
Synthetic
Off-site Natural
Material
Compacted
Processed Shale
Leachate
Collection System
Groundwater
Collection System
Collects leachate at the
base of the landfill and
drains Into the pond.
Collects groundwater
seepage beneath the
landfill and drain.
Reduce formation of leachate.
Prevent contamination of
the groundwater by leachate
from the fill. Prevent
grtfundwater invasion of the
fill, which might produce
instability and additional
leachate.
Reduces groundwater con-
tamination by effectively
removing the leachate.
Prevents loss of fill
stability due to saturation.
Prevents loss of fill
stability due to buildup
of groundwater pressure
beneath the liner.
Provide the lowest permea-
bility but have the highest
cost. Long-term durability
is questionable.
High cost. Advantage is
long-term durability. '
Lowest cost. Small particles
may infiltrate adjacent
drains. Advantage is long-
term durability.
Collected water may be used
for process needs.
Collected water may be used
for process needs.
Source: SWLC.
-------
There are several materials which can be considered for the liners and
covers. Probably the least expensive material would be compacted processed
shale. It has the advantage of being readily available at the site. A
similar Dining could be made of processed shale or clay from off site if the
quality of the processed shale from the site is unsuitable; however, these
options would be relatively expensive due to the extra handling and hauling
costs. There is also a variety of synthetic liners which could be con-
sidered. High-density polyethylene, for example, would range upward from a
price simi'ar to that for the off-site materials, depending upon the thick-
ness used. This would make it very expensive for use in a processed shale
landfill and it may have questionable long-term durability. Another option
that could be considered, particularly for a hazardous waste lagoon, is
simply a combination of a synthetic liner with one of the other liners
mentioned above.
Linings made of natural materials will dry and crack if they are left
exposed to the weathering elements for long periods. Therefore, if a pond is
not expected to remain at a relatively consistent level, a synthetic liner
mignt be considered. Hazardous waste lagoons sometimes have double liners;
howevers the catchment and evaporation ponds presumably will need only one
liner or no liner since they will not contain hazardous materials. If a
combination of two liners is used, the synthetic liner may be placed above
the latural material liner to prevent its drying and cracking. In cases
where a. synthetic liner is used, it should be covered by a layer of sand or
g»*ave" to protect it from traffic and wave .action. Also, because of the
weight of the fill and because the fill may be placed above an underground
mine, the liner must accommodate a certain amount of subsidence and stretch-
ing and still function properly.
Tiie cost of liners and covers depends on the quantity and type of
material used. Figure 5.3-8 presents the costs for three separate liner and
cover systems for surface landfills. Examples 1 and 2 assumed the use of
highly compacted processed shale for construction of the liners, while
Example 3 assumed the use of Mancos Shale. The compacted processed shale
represents the lowest material cost option, while Mancos Shale is a more
expensive natural material since it has associated source development,
processing and hauling costs. The cost curve in the figure may be used to
obtain an "order-of-magnitude" estimate of liner cost utilizing highly
compacted processed shale as the construction material. The estimated cost
fa** other liner materials would fall above this curve to a degree which is
dependent on the source development, processing, and hauling costs associated
with delivering these materials to the disposal site.
LeachateCol 1ection System—
The purpose of a leachate collection system is to collect water which
infiltrates a landfill and drain it efficiently in order to prevent the
saturation of the landfill and contamination of groundwater beneath the waste
p":is, as well as to facilitate handling of the leachate.
Leachate collection systems typically consist of blankets, or zones, of
highly pervious sand and gravel. In some cases this is augmented with
261
-------
25J~
g 15
O
ca
z
o I0
a
NOTES:
4 8 12
MATERIAL QUANTITY, 10s yd3
16
Examples 1 & 2 utilize 3 feet of highly compacted processed shale for liner
paterial.
Example 3 utilizes 3 feet of compacted Mancos Shale (off-tract material)
for liner material; cost of processing and hauling this material makes
this option more expensive than the others.
The costs indicated are cumulative for the project life.
See Section 6.2.3 for details on the solid waste management cost
methodology.
SOURCE: SWEC
FI6UIE 5,3-8 LINER COSTS
262
-------
embedded perforated pipe to increase the capacity, and it may also include
collector ditches where the system emerges onto a broad level area. The sand
or gravel layer would be located just above the bottom liner and it may be
wrapped in filter fabric or surrounded by carefully graded sand filters to
prevent infiltration by the processed shale particles. In either case, the
collection system should be designed so that movement and settlement do not
-esuit in discontinuity of the gravel layer or impede drainage to the
collection or evaporation ponds.
Tne costs for four distinct leachate collection systems for surface
landfills were estimated and these are presented in Figure 5.3-9. In
Examples 1 and 2, due to the valley shape of the disposal site, only the
drain material was necessary for the collection system. The leachate in
~hese two cases was drained in the runoff/leachate collection pond located
downstream from the landfill. In Example 3, a toe ditch was necessary to
collect the leachate due to the presence of the broad valley area at the toe
of the landfill. The ditch was then drained into the common runoff/leachate
collection pond. Example 4 also required a toe ditch which was drained into
a leachate collection pond, while the runoff was impounded separately in
evaporation ponds on the waste pile surface. Examples 3 and 4 required the
same drainage material quantity. The cost difference between the two
examples is due to the inclusion of a separate collection pond in Example 4.
Data point 5 on the figure represents the cost of drainage material only for
Examples 3 and 4. The cost of the toe ditch may be obtained by subtracting
data po^'nt 5 from 4.
The costs for similar systems should be proportional to the volume of
drainage material used, but slight deviations may be encountered due to the
site-specific conditions.
For open pit mining and backfilling operations, some leachate is likely
to be collected in the pit along with the runoff and it may be used for
processed shale moisturizing. Controlling the leachate after the backfilling
operations have been completed would not be practical. Therefore, emphasis
snou1d be placed on minimizing the production of leachate. Some considera-
tions in this regard would be to reduce the overall permeability of the
backfilled mass and to minimize penetration of surface water by utilizing a
cover.
Grgundwater Col1ection System—
The purpose of a groundwater collection system is to relieve pressure
from the seeps and springs beneath a landfill. This situation is most likely
In the cases of cross-valley or head-of-valley landfills. The system will be
essentially identical to the leachate collection system except it would be
below the bottom liner rather than above it.
Groundwater collection systems typically consist of blankets or zones
of pervious sand and gravel drained beyond the perimeter of the landfill.
This fpay be augmented with embedded perforated pipe to increase capacity and
with collector ditches. The sand or gravel layer would be lined as necessary
with filter fabric or surrounded by properly graded sand filters to prevent
263
-------
100
CO
o
o
h- 50
tC.
U!
CL
O
h-
o
Ui
NOTES:
04
03
O,
5,000 10,000
VOLUME OF DRAIN MATERIAL, yd3
Examples 1 & 2 require only drain material due to the valley shape;
leachate containment is performed by the contaminated runoff catchment pond
of which the leachate is a negligible component.
Example 3 includes cost of toe ditch for collection due to broad valley at
waste pile toe; containment is also by the contaminated runoff catchment
pond.
Example 4 includes toe ditch collection and separate containment pond
because, in this case, contaminated runoff is contained in evaporation
ponds on the waste pile surface.
Example 5 includes only the drain material cost of Examples 3 & 4.
The costs indicated are cumulative for the project life.
See Section 6.2.3 for details on the solid waste management cost
methodology.
SOURCE: SWEC
FIGURE 5.3-9 LEACHATE COLLECTION COSTS
264
-------
infiltration of smaller particles from adjacent materials. The system must
also be designed to maintain its continuity despite possible subsidence or
setfement of the landfill.
The costs of two groundwater collection systems for surface landfills
were estimated and these are plotted in Figure 5.3-10. Both systems used
gravel blankets under the pile to collect the groundwater seepage. In
Example 2 the gravel blankets were used only above the seeps and springs,
while in Example 1 an extensive network of the blankets was considered,
resulting in a higher cost. The cost of the collection system should be
proportional to the quantity of the drainage material used.
The use of a groundwater collection system under an open pit backfill
does not appear practical, especially in areas like Tract C-a where a large
amount of groundwater exists. A control over the groundwater flow in the pit
during active operations is achieved by dewatering the aquifers, which is
performed to keep the pit as dry as possible to facilitate mining; hence, it
is net considered a solid waste management technology. At the completion of
the project, the dewatering wells are shut down and original groundwater
levels are reestablished.
Some conceptual controls, such as hydrologic barriers and bypass, may be
applied to reduce the groundwater interaction with the backfilled material.
These are discussed in the MIS-Lurgi PCTM.
5.3,4 Suriface_Stab11 Ization Technologies
The activities and technologies in the area of surface stabilization
involve the treatment of the disturbed land surface and the problems as-
sociated with the disposal and reclamation of the waste material. These
technologies are outlined in Figure 5.3-11 and their key features are
presented in Table 5,3-5.
Dust Control—•
The purpose of dust suppression is to limit pollution from airborne
dust, particularly during the placement of the waste material in a fill.
Dust suppression can be accomplished by spraying the haul roads and fill
surface with water or a combination of water and a chemical binder. Haul
roads could, alternatively, be paved.
Use of water alone for dust suppression would necessitate repeated
aoplications, often more than one per day, to be effective. Water with a
chemical binder should necessitate only a few applications to a given
surface to stabilize it for a year or more unless it receives heavy traffic.
Finally, vegetation would provide perhaps the most permanent means of dust
control, but this would not be practical except on surfaces which would not
be disturbed for a number of years.
The dust suppression technology assumed in developing the cost data for
two examples consisted of routine spraying of the processed shale pile with
water and additives to minimize -the,.,dust generated tiue to the wind and the
265
-------
w
O
•«#. 4
o
o
e
u
0.
o
o
u
£ 2
Q
ff,
/
/
/
I
I
0.1 0.2 0,3 0.4 0.5 0.6 0.7 0.6
VOLUME OF DRAIN MATERIAL, I06 yd3
0.9
NOTES:
Examples 1 & 2 consist of gravel blankets for collection of groundwater
from springs and seeps; extent of blankets dictated by the existence and
extent of such conditions.
The costs indicated are cumulative for the project life.
See Section 6.2.3 for details on the solid waste management cost
methodology.
SOURCE: SWEC
FIGUEE 5.3-10 GROUNDWATER COLLECTION COSTS
266
-------
DUST
CONTROL
WATER AND
BINDERS
PAVE HAUL
'
<— REVEGETATtQN
aunrm^c
STABILIZATION
CONTROL
TECHNOLOGIES
EROSION
CONTROL
i— MULCH
<— REVEGETATIOM
STABLE
DESIGN
SOURCE' SWEC
FIGURE 5,3-II SURFACE STABMJZATIQN TECHNOLOGIES
267
-------
TABLE 5.3-5, KEY FEATURES Of SURFACE STABILIZATION TECHNOLOGIES
Control
Technology
Principle
Purpose
Comments
Dust Control
Water and
Binders
Pave Haul Roads
Revegetation
Erosion Control
Mulch
Revegetation
Stable Slope
Design
Prevents or limits dust
pollution from wind blowing
across exposed surfaces or
from vehicular traffic.
Fluid sprayed on the
surface binds the fine
particles together.
A hard surface on the
haul road prevents
generation of dust by
vehicular traffic.
Vegetation prevents dust
caused by wind.
Simplifies reclamation,
prevents blockage of the
drains, and prevents contam-
ination of surface waters by
eroded material.
Various materials are
placed on the slope to
limit erosion.
Plant growth is started
on the slope to limit
erosion.
Design slope to minimize
stability problems and
maintenance.
Makes erosion control,
revegetation, and drainage
easier. Restricts waste
material to a definite,
predefined area.
Well developed technology
that is commonly used in
mining operations.
Should improve traffic
conditions on the road.
Not useful in areas with any
equipment traffic or where
the surface is being disturbed
by other activities.
Quick and easy to accomplish
but is only a temporary
measure.
Permanent control but slow to
achieve.
Source: SWEC
-------
waste hauling and placement activities. Depending on the processed shale
characteristics, this operation could either be continuous or intermittent.
The cost curve in Figure 5.3-12 is based on the assumption that both the
manpower and equipment operation requirements are continuous. Theoretically,
these requirements could differ depending on the rate of waste production and
the surface area of the particular waste pile; however, both cases estimated
were assumed to be equivalent in this respect.
Erosion Control—
The purpose of erosion control is to keep the waste material in place so
that the surface drains remain free flowing, the slopes remain stable, eroded
material does not pollute surface streams, and reclamation and revegetation
efforts are not hampered. Some means of limiting erosion include contouring
the surface with short and gentle slopes, providing for drainage of the
slopes at frequent intervals, using mulch or filter fabric to dampen the
impact of water flow, and revegetating the completed faces. Of these
measures, grading and drainage are essential, take effect immediately, and
last as long as they are maintained. Mulch or filter fabric also provide a
quick control, but they are of a temporary nature. Revegetation provides a
permanent control, but it is generally slower to take effect.
A major consideration in planning erosion control measures is tne
severity of rainfall in the area. A large proportion of the water from a
high-intensity rainfall would run off the surface, thus increasing the
erosion.
Reclamation and revegetation consist of placing a subsoil and topsoil
strata of sufficient -thickness to support vegetation, and then seeding the
disoosal area with native or introduced species. The^greatest contributor to
the nagnitude of cost for this control technology is the thickness of the
soil strata and the costs associated with the delivered soil material, i.e..
tne source development, processing and hauling costs. Soil and subsoil
stripped from the disposal site may not be available in sufficient quantity
to meet the reclamation needs. The cost curves presented in Figure 5.3-13
illustrate fi^e examples. Examples 1 and 5 included 2 feet of subsoil
(sane-gravel material) and 30 inches of topsoil, both of which were brought
in from off-site sources and thus had additional costs involved. Examples 2
and 3 alsb used the same thicknesses, but the soils were available on the
site. Example 4 used no subsoil and only 6 inches of topsoil which was
available on the site; therefore, additional material costs were not in-
volved. All examples included the cost of revegetation. It is evident from
the figure that the cost of erosion control can vary significantly depending
or» the factors considered; however, in any category, the costs are propor-
tions! to the area reclaimed and revegetated.
Stable Slope ...Design—
The purpose of designing the slopes to be stable under prevailing
conditions is to minimize the maintenance of the landfill and to avoid
hampering of the reclamation and revegetation efforts. The techniques used
in designing stable slopes are a well developed part of soils engineering.
" " ' - ,269 ....•-••••••--
-------
50
40
«e
O
0}
8 30
—
<
E
u
&
O 20
O
LlJ
cc
10
I
I
10 20
PROJECT LIFE, YEARS
30
NOTES:
Example 1 assumes a 30-year project life, while Example 2 assumes a
20-year life.
The Lurgi-Open Pit Case Study has a project life of 20 years.
The costs indicated are cumulative for the project life.
See Section 5.2.3 for details on the solid waste management cost
methodology.
SOURCE: SWEC
FIGURE 5.3-12 DUST CONTROL COSTS
270
-------
(0
O
60
50
h-
OT
8 40
O
2
< 30
K
uJ
Q.
° 2°
O
Ul
cc
5 10
X
X
£L
i
O
I
500 1^300 1,500
RECLAIMED AREA, ACRES
i
2,000
NOTES:
Examples 1 & 5 include 2 feet of subsoil and 30 inches of topsoil, both
obtained off site.
Examples 2 & 3 include 2 feet of subsoil and 30 inches of topsoil obtained
on site.
Example 4 includes no subsoil and only 6 inches of topsoil obtained on
site.
The costs indicated are cumulative for the project life.
See Section 6.2.3 for details on the solid waste management cost
isethodology.
SOURCE: SWEC
FIGURE 5.3-13 RECLAMATION AND REVEGETATION COSTS
271
-------
To arrive at the most advantageous slope,design, other factors besides basic
stability, such as erosion, ease of placement, reclamation "and revegetation^
must be considered. However, the physical characteristics of the waste
material will dictate a limiting slope angle. The costs of achieving a
stable slope design are incidental to the placement and revegetation of the
fill material; hence, additional costs are not involved.
5.3.5 Hazardous Waste Control Technologies
The control of hazardous waste involves its permanent impoundment in a
permitted disposal facility. This facility may be built on the project site
or the wastes may be sent to an existent, off-site permitted facility. These
options are outlined in Figure 5.3-14 and their key features are presented in
Table 5.3-6.
On-site Disposal—
Hazardous waste lagoons are a well developed and accepted approach to
solid waste management. They are actually an integration of several control
technologies discussed in Sections 5.3.2, 5.3.3 and 5.3.4. Some of the in-
cluded technologies would be an embankment surrounding the lagoon, a runon
diversion system, one or two bottom liners, a surface cover, reclamation and
revegetation, and monitoring.
There are certain advantages to building a hazardous waste facility on
site. This option automatically assumes segregation of the hazardous and
nonhazardous wastes and, hence, their separate disposal. An advantage of
this approach is that much of the material necessary for the lagoon would be
available on site or it already would have been brought in for the non-
hazardous waste landfill. Furthermore, transport of the wastes beyond the
property boundaries will not be required. A significant advantage may be
that the producer of the hazardous wastes (the oil shale developer) will have
complete control over the disposal of the wastes.
There are also certain disadvantages to on-site disposal of the
hazardous wastes. To be efficient in evaporating the liquids and consoli-
dating the sludge, the lagoon should be located preferably on a level site,
which may not be readily available. Rugged, uneven terrain would increase
the cost of site preparation, runon control and reclamation. There is also
a possibility that the lagoon may interfere with other ongoing activities
and the resource recovery.
Off-site Disposal-°
0 f f - s ite exlstent f ac11ity. This would be an already existing facility
where the wastes can_ be disposed of on an "as needed" basis. A payment is
required for every shipment, but the cost may be lower than that of building
and maintaining a new facility. Also, a significant amount of time and
effort involved" in the licensing, design, and construction of a new facility
can be saved. The capacity and distance of the existent facility must also
be considered in selecting the disposal approach.
272
-------
HAZARDOUS
WASTE
CONTROL
TECHNOLOGIES
ON-SITE
DISPOSAL
OFF-SITE
DISPOSAL
SOURCE^ SWEC
FIGURE 5.3-14 HAZARDOUS WASTE CONTROL TECHNOLOGIES
273
-------
TABLE 5.3-6. KEY FEATURES OF HAZARDOUS WASTE CONTROL TECHNOLOGIES
Control
Technology Principle Purpose Comments
On-site Disposal Dispose of hazardous Dispose of hazardous wastes The oil shale developer has
wastes in a lagoon produced by processing of complete control of hazardous
established on site. oil shales. wastes produced by the
facility.
Off-site Disposal Establish lagoon off Dispose of hazardous wastes Provides a broader selection
site or pay for disposal produced by processing of of sites, although the waste!
in existing permitted oil shales. must be transported. Poten-
facility. tially less involvement with
the wastes.
Source: SWEC,
-------
SECTION 6
POLLUTION CONTROL COSTS
This section provides an analysis of estimated pollution control costs
for the Lurgi-Open Pit case study analyzed in this manual (see Sections 2
and 3 for a description of the case study). Section 6.1 presents fixed
capital and direct annual operating costs for each control and explains how
they were developed. These costs are referred to as the "engineering costs."
Section 6.2 explains the cost analysis methodology used to develop the
total annual and per-barrel pollution control costs. These costs combine
capital and annual operating costs, allow for taxes, and incorporate a return
on investment. This is an approach similar to that which a private developer
mignt use to determine costs or assess the economic feasibility of a project.
Section 6.2 also aetails the economic assumptions that are incorporated into
the calculation of total annual control costs.
Section 6.3 presents estimated total annual control costs and per-barrel
costs for each control using a set of standard economic assumptions. These
costs are assembled into total per-barrel costs for air and water pollution
control for the case study examined in this manual. This section also
examines the sensitivity of the per-barrel control costs to a series of
changes in the engineering costs and economic assumptions.
Section 6.4 provides more detailed information supporting Sections 6.1,
6.2 and 6.3. Section 6.4.1 provides the algorithms that were used to
determine total annual control costs and per-barrel control costs, and
Sections 6.4.2 and 6.4.3 provide examples, respectively, of fixed charge rate
calculations and cost levelizing calculations.
Section 6 uses a large number of cost and economic terms. The inter-
re"! aticnships among the more important of these terms is illustrated in
Figure 6.0-1. Each term is explained when it is first used in the text, but
the reader may find it helpful to use this figure to provide an overview
while reading the various sections. In addition, Table 6.2-4, presented
later in this section, indicates the estimated relative magnitude of the
components of per-barrel control cost for a typical major pollution control,
6.1 ENGINEERING COST DATA
6.1.1 Bases of Engineering Cost Data
Throughout this manual a distinction is made between capital costs and
annual operating costs. There are two types of capital cost, fixed capital
- 275
-------
ENGINEERING COSTS
rsj
~j
cr>
DIRECT ANNUAL
OPERATING COSTS
(DOC)
« Maintenance
• Operating Supplies
• Operating Labor
• Utilities
- Cooling Water
- Staam
- Electricity
(Tables 6 1-1,6 1-2)
SOLID WASTE
MANAGEMENT COSTS
(Year-by-Year Cash Flows)
(Table 6 1-3)
FIXED CAPITAL
COSTS (FCC)
(Tables 6 hi, 6 1-2)
<^
COST ANALYSIS METHODOLOGY
INDIRECT ANNUAL OPERATING COSTS
(IOC)
» Annual Property TDK and Insurance
Allowance (TIA = f [FCC J)
» Annuol Extra Start-up Costs
( ESC = f [FCC, DOC])
» Annual By-product Credit (BP,
Tobies 6 3-3,6 3-4)
• Annuol Severance Tax Credit
(STC = f [FCC,TIA,eSC,BP]>
DOC
DOC
BARRELS PER
STREAM DAY
(BPSD)
IOC ^
TOTAL
,, ANNUAL
OPERATING
COST
,. (TOC=DOC + 1OC)
,-"-"" •—— — '
— ~-^ FCC
BPSD ^
PER- BARREL
CONTROL COST
(CPB * TC -f
BPSD X 328.5*)
TOC
FIXED CAPITAL CHARGE RATE
(RF- ft Economic Assumptions])
FCC
WORKING
CAPITAL ""
(WC - f C DOC, BP1 ) W°RKING CAPITAL CHAR6E RATE
{RW- ! [Economic Assumptions])
RF— »>
RW ^
TC
TOTAL
ANNUAL
CONTROL
COST
(TC*CC+TOC)
j
CC
TOTAL
ANNUAL
CAPITAL
CHARGE
(CC
*
RF X FCC
+ RW X WC) ,
* 328,5 is the number of operating days in a normal year
SOURCE DRI
FIGURE 60-
Note- f means "a function of"
INTERRELATIONSHIPS AMONG VARIOUS COST AND ECONOMIC TERMS
-------
and working capital, and two types of annual operating cost, direct and
indirect.
Fixed capital is investment in construction and equipment, whereas
working capital is money that is required to operate the plant, e.g., that
which is tied up in inventories.
Direct annual operating costs include maintenance, operating supplies,
operating labor and utilities costs. Indirect annual operating costs com-
prise additional annual costs, i.e., property tax and insurance, an allowance
for extra start-up costs, a credit for severance tax not paid and by-product
credits.
Section 6.1 only considers fixed capital costs and direct annual
operating costs. Working capital and indirect annual operating costs are
considered in Section 6.2.
Assumptions Used to Develop Costs—
All costs are expressed in mid-1980 constant dollars. The following
data apply to air and water pollution control costs. Solid waste management
costs were developed on the basis that these activities are contracted out,
sines they are all construct!on-type activities (see discussion later in this
subsection),
Fixedcap1tal costs. Fixed capital costs are of 'the "preliminary
estimate" category. Physical plant costs for a1r~ emission controls were
developed by Stone and Webster Engineering Corporation (SWEC) and for water
pollution controls by Water Purification Associates (WPA), Actual vendor
cuotes were used for major items of equipment; costs for other equipment were
obtained from data files maintained by SWEC and WPA. Total pbysica' plant
costs were developed from the equipment costs by adding appropriate allow-
ances for the following:
® Site preparation, excavation and foundations
* Concrete and rebar
® Support structures
* Piping, ductwork, joints, valves, dampers, etc.
• Duct and pipe insulation
» Pumps and blowers
» Electrical
* Instrumentation and controls
• Monitoring equipment
» Erection and commissioning
» Painting
* Buildings.
277
-------
To arrive at the total fixed capital•cost, the following factors were
added to the physical plant cost: - . ' '
Engineering and
construction overhead; 25% of physical plant cost.
Contractor's fee: 3% of bare module cost {physical plant
cost plys engineering and construction
overhead).
Contingency: 20% of bare module cost.
For an explanation of this method of developing estimates of fixed
capital costs, see Uhl (June 1979). A 20% contingency factor was chosen
because there are only pilot plant data for the Lurgi retorting process.
It is considered that the accuracy of these cost estimates is within
±30 percent. Although the accuracy of a preliminary fixed capital cost
estimate is normally regarded as ±20 percent, uncertainties about stream
magnitudes and composition decrease the accuracy of these estimates to
±30 percent.
Directannual operating costs. There are two components which make up
the total annual operating cost. The direct annual operating cost can be
regarded as the basic (or engineering) cost, while calculation of the in-
direct annual operating cost makes some adjustments to this cost. By-product
credits are included in the indirect annual operating cost. Data on the
bases of direct annual operating costs are given below, while the bases of
indirect annual operating costs are outlined in Section 6.2.
Direct annual operating costs are made up of the following components:
• Maintenance
• Operating supplies
* Operating labor
• Utilities
—Cooling water
—Steam
--Electricity.
Maintenance costs include maintenance labor and replacement parts,
consumables used for maintenance, etc.
Operating supplies are consumable items (such as chemicals) used in
the regular operation of the control (as opposed to use for maintenance).
278
-------
Operating (and maintenance) labor is costed at $30/hr. This is a
"loaded" rate, meaning that it incorporates some overhead-type costs tc avoid
developing them separately. The rate is made up as follows:
A. Wages for direct labor $11.00/hr
8. Fringe benefits (45% of A) 4.95
C. Field supervision (15% of A + B) 2.40
D. Overhead (50% of A + B + C) 9.20
E. General & administrative charge
(9% of A + B + C + D) 2.45
Total $30.00/hr
In mid-1980, examination of union agreements showed that oil refinery
direct operating labor was receiving approximately $10/hr in Colorado.
However, it is anticipated that when oil shale development occurs, this will
bid up local labor rates, so $ll/hr, which was used for the oil shale PCTMs,
is a reasonable value. The multiplier factors, used to arrive at the
"loaded'1 labor rate of $3Q/hr, were suggested by SWEC based on project
experience in the western U.S.A.
Cooling water is costed at 11.3 cents per 103 gal circulated (3f/m2).
This is only a charge for the use of the cooling tower. The cost of treating
the makeup water is included under water pollution control.
Drocess steam is charged at $3.00 per million Btu.
Electricity is charged at 3 cents per kW-hr.*
There is no contingency factor in the direct annual operating costs for
air and water pollution controls.
So"Hd Waste Management Costs--
Son' d waste management costs in the form of year-by-year cash flows were
developed by SWEC using company cost data files. They include the same
engineering and construction overhead, contractor's fee, and contingency
factor (20%) as the fixed capital costs discussed earlier. The use of a 20%
contingency factor is appropriate since all solid waste management costs are
of a construction nature, subject to uncertainties similar to those inherent
in fixed capital costs.
* To be consistent among the three oil shale PCTMs, electricity is charged at
3 cents per kW-hr, whether purchased or generated on site. This figure
represents a compromise between the value of electricity sold by plants
that will have surplus on-site generated power and the higher cost of power
purchased from a utility. . ,. >-t ^_,
" " 279
-------
6.1.2 PetalIsof Engineerlng Costs
Tables 6.1-1 and 6.1-2 present details of-the fixed capital and direct
annual operating costs for each air and water pollution control. The oper-
ating costs relate to a year of normal operation, i.e., full production. For
the start-up period^ direct annual operating costs are modified to an appro-
priate level by the cost analysis methodology.
Table 6.1-3 details the solid waste management costs on a year-by-year
basis. These costs are allocated to fixed capital or direct annual operating
categories in Section 6,2 (Table 6.2-3). Insufficient information was
available to develop a complete plan for solid waste management operations.
Consequently, the solid waste management costs presented here are for certain
items only and do not represent the total pollution control cost for solid
waste.
6.2 COST ANALYSIS METHODOLOGY
In the cost analysis, engineering cost data are transformed into two
primary measures—the total annual pollution control cost and the control
cost per barrel of shale oil. These costs incorporate both capital and
annual operating costs and consider project timing, taxes, and the necessary
return on investment.
6.2.1 Overview of Cost AnalysisMethodology
In private industry, one of the most widely accepted methods of evalu-
ating the economics of a project is the discounted cash flow (OCF) approach.
Using this approach, a project must be able to demonstrate that it can
produce some established minimum rate of return on investment—known as a
"hurdle" rate—to be acceptable.
One method for applying the DCF approach to a complete oil shale project
is to determine the selling price which would provide the revenue required to
produce a minimum acceptable rate of return (DCF ROR). With this method, a
selling price for oil can be established by distributing the required revenue
uniformly over every barrel of oil produced.
The same technique can be utilized to determine the total annual and
per-barrel costs of pollution control. In practice, pollution control is
not a separable aspect of an oil shale project. Consequently, a private
developer will require the same DCF ROR on< pollution controls as for the
entire project.
If the revenue necessary to provide the required DCF ROR for each
control (expressed in constant dollars) is distributed uniformly over each
barrel of shale oil produced, then this also implies a constant total revenue
requirement in each year of normal (full) production. However, in the
start-up years, less oil is produced, with the result that the annual revenue
requirement is prorated. Additional costs incurred in the start-up period
were spread over all production in order to produce a uniform per-barrel
control cost.
280
-------
TABLE 5.1-1. DETAILFO ENGINEERING cosrs FOR MR POLLUTION CONTROLS
00
Control
(No of Units)
Participate Controls
Fabric Filters (2)
Fabric Filter (1)
Fabric Filter (1)
Fabric Filters (3)
Fabric Filters (2)
Fabric filters (8)
Fabric Filters (8)
Fabric Filters (9)
Fabric Filters (9)
Fabric Filter (1)
Fabric Filters (2)
Fabric Filters (3)
Fabric Filters (2)
Fabric Filters (2)
Fabric Filters (2)
Fabric Filters (4)
Fabric Filters (2)
Fabric Filters (2)
Water and Foam
Sprays
' Fabric Filters (4)
Fabric Filters (13)
Flue Gas Treatment
Fixed
Capital Cost
Control Location ($000' s)
Primary Crusher (ore)
Primary Crusher (subore)
Primary Crusher (overburden)
Raw Shale Conveyor Transfer
Points
Conveyor to Stockpile
Secondary Crushers
Secondary Screens
Tertiary Crushers
Tertiary Screens
Fine Ore Storage
Processed Shale Conveyor
Transfer Points
Processed Shale Load-out
Hoppers
Conveyor to Secondary
Crushers
Conveyor to Secondary Screens
Conveyor to Tertiary Crushers
Conveyor to Tertiary Screens
Conveyor to Fine Ore Storage
Conveyor to Retort Fead
Hoppers
Open Stockpiles, etc
Retort Feed Hoppers
Conveyor to Retorts
987
105
552
1,051
628
4,828
4,828
5,432
5,432
249
559
569
348
348
348
696
348
348
909
1,837
2,059
Components of Direct Annual
Operating
Maintenance Supplies
19
2
11
21
12
94
94
106
106
6
11
11
~J _„
"? „_
7
14
7
7
117 1,065
36
40
Operating Cost flOOO's/yr)
Operating
Labor Electricity
44
4
23
44
73
203
203
228
2ZS
10
23
23
15
15
15
30
15
15
274
77
87
Total Direct
Annual Operating
Cost ($000's/yr)
63
6
34
65
85
297
297
334
334
15
34
34
22
22
22
44
22
22
1,456
113
127
Electrostatic
Predpltators (13)
Flue Gas Discharge System
50,734
330
1,814
2,144
(Continued)
-------
TABLE 6 1-1 (cent.)
• • - - --" •• — • • • ' • '
Control
(No. of Units)
Miscellaneous Controls
Stretford (1)
Ammonia Storage
Tank (1)
Floating Roof 011
Storage Tanks (2)
Proper Maintenance
Catalytic Converters
Control Location
DEft Unit
Ammonia Recovery
Product Storage
Valves, Pumps, etc
Diesel Equipment
Fixed Components of
Capital Cost
($000' s) Maintenance
6,860 134
466
300
61 55
170 60
Direct Annual Operating Cost <$000's/yr) Totai Direct
Operating Operating Annual Operating
Supplies Labor Electricity Cost <$000's/yr)
164 350 121* 769
6 — 61
so
* This Includes $24,000 for steam.
Source- DRI estimates based on Information provided by SWEC.
ro
CO
ISJ
-------
TABLE 6.1-2. DETAILED ENGINEERING COSTS FOR WATER POLLUTION CONTROLS
.
Control
Ammonia Recovery
Unit
API Oil/Water
Separator
Fixed
Capital Cost
($000' s)
3,627
161
Mine Water Clarifier* 2,560
Cooling Water
rs> Treatment*
00
U)
Boilef Feedwater
Treatment*
Equalization Pond
Runoff Oil /Water
Separator
Aeration Pond
TOTAL
—
122
181
41
430
7,122
Components of Direct Annual Operating Cost ($000's/yr)
Maintenance
118
4
84
—
4
3
1
14
228
Operating
Supplies
428
--
235
51
14
„
--
--
728
Operating Cooling
Labor Water Steam Electricity
237 60 1,565 11
--
—
—
40 — — 11
„_
--
99 — — 40
376 60 1,565 62
Total Direct
Annual Operating
Cost ($000's/yr)
2,419
4
319
51
69
3
1
153
3,019
* These technologies could be considered as part of the process rather than pollution control.
Source: DRI estimates based on information provided by WPA.
-------
TABLE 6.1-3
ENGINEERING COSTS AND TIMING OF SOLID WASTE MANAGEMENT ACTIVITIES
(Thousands of Dollars)
Activity
SURFACE HYDROLOGY
Runoff Collection Sumps
Runoff Collection Pumps
Deep Monitoring Wells
Shallow Monitor ing Wells
Piezometers
SURFACE STABILIZATION
Dust Suppression
Revegetation
Topsoil
Seed
Project Year ->
123456789 10
58 58 58 58 58 58 5B 58 58 58
15 15 15 15 15 15 15 15 15 15
858
26
432
6,204 9,196 11,079 11,079 11,079 11,079 11,079 11,079 11,079 11,079
1X3
00
•I*
Activity
SURFACE HYDROLOGY
Runoff Collection Sumps
Runoff Collection Pumps
Project Year -»
11 12 13 14 " 15 16 17 18 19 20 21
58 58 58 58 58 68 58 58 58 58
15 15 15 15 15 15 15 15 15 15
Deep Monitoring Wells
Shallow Monitoring Wells
Piezometers
SURFACE STABILIZATION
Dust Suppression
Revegetation
Topsoi1
Seed
11,079
11,079
11,079 11,079 11,079
11,079 11,079 11,079
11,079
183
46
11
11,079
185
46
12
Note Year 1 is the first year of production. This is subsequent to the 30-year open pit development period
Source. DRI estimates based on information provided by SWEC
185
46
11
-------
The total annual required revenue is utilized to satisfy two major
components: the total annual operating cost, and a component that provides
the necessary return on investment, called the total annual capital charge.
Note that with the DCF approach, profit is based solely on investment;
operating costs are passed straight through as one component of the total
"evenue requirement, without addition of any profit element. This is normal
practice for industrial project assessments.
To relate an annual capital charge to the corresponding investment, a
"capital charge rate" was used. In practice, there are two types of capital
investment: fixed capital (i.e., physical equipment) and working capital
(which is nondepreciable investment). The "fixed charge rate" is defined as
the proportion of investment in fixed capital that must be recovered in a
year of normal production in order to provide the required DCF ROR. The
"working capital charge rate" performs a similar function for the working
capital. The total annual capital charge for a pollution control is the sum
of the annual fixed capital charge and the annual working capital charge.
Fixed charge rates have several economic assumptions embedded in them.
Some o* these assumptions are common to all pollution controls, i.e., the
project life and operating (stream) factors, the income tax rate, and the
*"equirad DCF ROR.
Other assumptions vary according to the pollution control or group of
controls. These are: the timing of the investment in fixed capital, the
depreciation peridd, and the investment tax" 'credit details. Consequently,
different fixed charge rates are used for different groups of pollution
controls.* (These rates, as well as-the underlying standard economic assump-
tions, are listed later in Table 6.2-2.)
The working capital charge rate depends only on the project life and
operating factors, the timing of the investment in working capital and the
required DCF ROR. Since none of these assumptions varies among controls, the
same working capital charge rate is used for each control.
As already indicated, the total annual cost for a control is the sum of
the total annual capital charge and the total annual operating cost. The
total annual operating cost comprises two components. The "direct annual
operating cost" consists of maintenance, operating supplies, operating labor
and utilities. The "indirect annual operating cost" comprises an annual
allowance for property taxes and insurance, any annual by-product credits,
and an allowance for extra start-up costs, i.e., those that are in excess of
the direct annual operating cost prorated in accordance with production. It
also includes a credit reflecting a reduction in the Colorado severance tax
The use of several different fixed charge rates in the same oil shale
PCTH may appear complex. However, since the manuals examine several
alternatives for pollution control, an accurate evaluation of capital
charges is needed, A less accurate approach, such as assuming a single
capital expenditure profile for all controls, could conceivably affect
the per-barrel cost ranking of pollution control alternatives.
-------
that must be paid, because the cost of-each pollution control reduces the
severance tax liability.* Extra start-up costs and the severance tax credit
are "levelized" to distribute them uniformly over each barrel of shale oil
produced since they' do not vary in proportion to production. (Levelizing
takes a cost that does not vary in proportion to production and finds an
economically equivalent cost that has the same time-profile MS production
[see Sections 6.2.3 and 6.4.3].) To summarize:
Total Annual Control Cost = Annual Fixed Capital Charge + Annual
Working Capital Charge + Direct Annual Operating Cost + Indirect
Annual Operating Cost.
For air and water pollution controls, direct annual operating costs are
specified for a normal year of production and are implicitly prorated during
the start-up years. In practice, operating costs during the start-up period
will be higher, but this is allowed for via the extra start-up costs
discussed in Section 6.2.2. The solid waste management costs are developed
in the form of a year-by-year cash flow (see Table 6.1-3) which must be
converted into equivalent fixed capital and direct annual operating costs
for a full production year (see Section 6.2.3 and Table 6.2-3).
The per-barrel control cost is obtained by dividing the total annual
control cost by the production in a normal (full production) year. (Per-
barrel operating costs and capital charges can be calculated in the same
way.) The detailed algorithms for these calculations and for determining
fixed and working capital charge factors are given in Section 6.4.1.
6.2,2 Economic Assumptions Used in Total CostCalculations
To transform engineering cost data provided in Section 6.1.2 into total
annual capital charges, total annual operating costs, and total annual or
per-barrel control costs, a number of economic assumptions were made. Most
of these assumptions are listed in Table 6.2-1, and Table 6.2-2 summarizes
those assumptions that vary from control to control. The values given in
these two tables are the standard values, known as the "standard economic
assumptions," which have been used for the cost analyses presented in the
oil shale PCTMs. Some of these are varied in the sensitivity analyses which
are used to show how control costs change in response to alternative economic
assumptions and to changes in the engineering costs.
The distinction between the two components of operating cost is made for
convenience in performing the calculations and is not fundamental. The
direct annual operating cost is comprised of basic cost elements, whereas
the indirect annual operating cost comprises a series of adjustments that
are influenced by other factors, such as tax assumptions. Direct annual
operating costs for each control are given in Tables 6.1-1, 6.1-2 and
6.2-3. Indirect annual operating costs for all controls are calculated
using a standard algorithm (see Section 6.2.2), except for any by-product
credits which are given in Tables 6.3,3 and 6.3.4.
286
-------
TABLE 6 2-1. SUMMARY OF STANDARD COST AND ECONOMIC ASSUMPTIONS
Assumptions
COST iSSUMFTIQNS
* Sase Year Mid-1580 dollars
» Direct Labor Rate- $11.00/br*
* ''Loaned" Labor Rate*: $3Q.OO/tir
« F-"xed Capital Costs 25% engineering and construction overhead and 3% contractor's fee Included*
» Contingency Allowances: 20%, all fixed capital costs*
0%, fnost operating costs*
20%, solid wasta direct operating costs
ECONOMIC ASSUMPTIONS
• Project Life: 20 years*
o No»-ma1 Output. 63,140 Barrels per Stream Day (8PSD)
« Operating (stream) Factors: Year 1 - 50%
Year 2 - 75%
Years 3-20 - 90%*
of a normal year's direct
operating cost
• Working Capital: 30 days' total operating cost (excluding by-product credit), plus 60 days'
by-product credit
• Annual Allowance for Property Taxes and Insurance: 3% of fixed capital
« Colorado Severance Tax: Credit allowed
• Timing of Investment: Initial fixed capital expenditures can occur in Years -3 through +1,
expenditures and tax considerations for each control are phased in accordance with the construction
and initial operation of each control (see Table 6.2-2 for schedules)
• Corporate Financing: Tax credits and allowances can be passed through to a parent company that can
benefit from them •urate.diataly, without watting for the project to become profitable*
• Fadaral Depletion Allowance: Does not affect pollution control costs
* These ipethods and factors are in accordance with the recommendations, dated April 22, 1980, of EPA's
ad hoc synfuels cost coiwltte*.
Source: OKI
287
-------
TABLE 6.2-2. ECONOMIC ASSUMPTIONS THAT VARY FROM CONTROL TO CONTROL
Retort Timing
Controls associated with retorting:
certain fabric f filers, electrostatic
precipitators, Stretford, ammonia
recovery unit, API oil/water
separator, boiler feedwater and
cooling water treatment
H1ne Timing
Controls governed by mine and project
start up most fabric filters, water
and foam sprays, ammonia and oil
storage, Maintenance of valves, pumps,
etc-
Early Water Management
Controls associated with mine and
site water treatment- mine water
" clarifier, equalization pond, runoff
oil /water separator, aeration pond
Ca ta ly 1 1 c Converters'"
(on dlesel equipment)
Solid Waste Management (Year 1)
Deep monitoring wells
Solid Waste Management (Year 10)
Shallow monitoring wells and
piezometers
Capital Expenditure
Profile
Year -2: 10%
Year -1: 30%
Year 0: 60%
Year -1- 30%
Year 0 70%
Year -3: 100%
Year 0 100%
Year +7- 100%
Year +14 100%
Year +1. 100%
Year +10: 100%
Investment Tax Credit Depreciation Fixed Charge Rate8
RatP % Profile Life (years) Starts Percent
20 Same as. 16 Year -fl 16 17
capital
20 Sane as, 16 Year +1 15.61
capital"
20 Year -2: 100% 16 Year -2 21 64
13 l/3d Year +1: 100% 5 Year +1: 100% 23,36
Year +8: 100% 5 Year +8: 100%
Year +15- 100% 5 Year +15: 100%
20 Year +2: 100% 10 Year +2 12 49
20 Year +11: 100% 10 Year +11 4. 51
For standard economic assumptions (see Table 6 2-1).
Qualifies for investment tax credit progress payments,
c Capital Is replaced twice during project life.
Investment tax credit is reduced because equipment life is less than 7 years
Source DRI
-------
Where appropriate, the standard economic assumptions are discussed
below. Others are discussed in connection with the sensitivity analyses in
Section 6.3.2.
lining of Control Capital Expenditures —
6.2-2 includes the fixed capital expenditure profiles for each
category of control. Although a number of developers and other organizations
have published construction schedules for oil shale plants, no schedule is
available that is appropriate to a Lurgi-Open Pit plant of this size.
Instead, the schedule was based on data for a 51,500 BPSD TOSCO II plant for
which comparatively good data are available (Nutter and Waitman, 1978;
telephone interview with C. S. Waitman, Tosco Corp. , February 1979; Colony
Development Operation, 1977). Engineering judgment was then used to deter-
mine when the pollution controls would be procured and installed, incorpo-
rating the impact of payments made during off-site fabrication. In general,
sxpendi tyres on pollution controls tend to be incurred later than those for
nost retort construction activities, since the controls are usually among the
last items to be installed.
Part of the water pollution control system constitutes an exception to
the above discussion. Basic site water management facilities must be instal-
led and operational before most other activities can commence. Consequently,
these iteras were assumed to be installed in Year -3 (i.e., 4 years before
production commences) and placed into service in Year -2 for depreciation
purposes. The mine water treatment system was given the same timing, but
this is somewhat arbitrary since the mine is assumed to be fully developed at
the commencement of this case study analysis. Also, because no mine develop-
ment is included in this case study analysis, it was assumed that the mobile
diesel equipment was purchased in Year 0 and placed into service in the first
year of crocfuction, Year 1.
Assumptions for Taxation*--
Oeggecj j t i o n . All oil shale PCTMs used a 16-year depreciation period
for most assets. This corresponds to the mid-point of the IRS1 Asset
Depreciation Range (ADR) guidelines for oil refineries. In practice^ many
companies would use the lower end of the ADR range, which is 13 years;
however, H nas been found that this would make very little difference in
the results of the analysis.
A]1 analyses were conducted prior to enactment of the Economic Recovery Tax
Act o^ 1981 (PL 97-34). As far as an oil shale project is concerned, the
main impact of this act is to permit very rapid depreciation under the
Accelerated Cost Recovery System (ACRS). Using ACRS, most property would
be depreciated over 5 years and mobile equipment would be depreciated over
3 years. A rough estimate of the effect of the provisions of the Economic
Recovery Tax Act of 1981 on the pollution control costs is given in
Section 6.3.1.
289
-------
Some equipment clearly qualifies for a shorter life. Capital items
associated with processed shale disposal, i.e., the monitoring wells and
piezometers, were regarded as mining equipment, for which a 10-year depre-
ciation period was used. A 5-year depreciation period was used for the
mobile diesel equipment, and it was assumed that this equipment was replaced
twice during the project life.
The depreciation method used for all taxation calculations was the
Sum-of-the-Year's Digits method.
Investment Tax Credit (ITC). A basic 20% ITC was used for all items in
accordance with the Energy Tax Act of 1978 (PL 95-618). The mobile equipment
has a depreciation period of only 5 years, so the credit is reduced by
one-third, to 13 1/3 percent.
Where payments for a control extend over more than one year, the tax
credit can be taken as the capital is expended, in accordance with the IRS1
progress payments rule. Otherwise, it is taken when the asset is placed into
service.
Incometax rate. A combined State and Federal tax rate of 48% was used.
In practice, CoTorado has a 5% tax rate, so the effective percentage rate
should be: 5 •*• ([1 - 0.05] x 46) = 48.7%. The error introduced by using 48%
is negligible.
Depletion allowance. The Federal depletion allowance has not been
incorporated into the calculation of taxes. The justification for this is as
follows. The percentage depletion allowance is 15% on the "gross income"
from an oil shale property. In this case, since the sales or transfer price
of shale oil (and, hence, gross income) is independent of pollution control
costs, the depletion allowance will not affect those costs. However, there
is a limitation that the percentage depletion allowance cannot exceed 50% of
the taxpayer's taxable income from the property, computed without allowance
for depletion. Since pollution control costs reduce the taxable income, they
could affect the depletion allowance if it was limited under the above rule,
and this would then be a cost attributable to pollution control. While this
might well be the case in a start-up year, it appears that this limit is
unlikely to apply during a normal year's operation. This is because the
complete project's total annual operating costs are a comparatively low
proportion of its total annual costs, including capital-related costs (based
on data for an open pit mine with unspecified type of surface retort
producing 100,000 barrels per day [Peat, Marwick, Mitchell & Co.,
September 1980]).
Hence, the impact of the Federal percentage depletion allowance on
pollution control costs has been disregarded. This may introduce minor
errors during start-up years, but complete project cost data are not publicly
available to permit the effect to be calculated. Cost depletion, which might
at times be taken instead of percentage depletion, is clearly irrelevant to
pollution control costs.
290
-------
PCF MM. Twelve percent (per year) was used as a standard assuasption
(see Section 6,3.2).
Project life. The expected project life (measured fro® the comaencewent
of production) will be determined by exhaustion of the oil shale reserves or
by technological obsolescence. Planned project lives used for evaluations of
oil shale developments range from 18 to 30 years. Twenty years is a coason
period to use for economic evaluations and was used in this
Increasing the life has a very small effect on the results at nornal DCF
(i.e., 12% or more).
Sjtart-ypprpfjle. The start-up profile and normal year operating factor
are on projections for a TOSCO II plant (Nutter and Waitnan, 1978).
Lyrgi representatives consider that a Lurgi plant should achieve a better
start-up profile than a TOSCO II plant, but they feel that a 90% operating
factor «ay be slightly optimistic for a normal year (interview with H. Weiss
awl J. Arnhold of Lurgi Kohle und MineralBtechnik GmbH, in Denver, Colorado,
January 1981). The operating (stream) factors used (i.e., Year 1: §d»,
Year 2: 75%, Years 3-20: 90%) are considered to be the most appropriate
assumptions that can be made at this time.
Caaponents of Annual Indirect OperatingCosts—
Tiie annual indirect operating cost is composed as follows:
Annual property tax and insurance allowance
*• Extra start-up costs (levelized)
- Severance tax credit (levelized)
- Annual by-product credit (if any).
grgg_erty__tax _and Insurance allowance. The annual indirect operating
cost includes 3% of the fixed capital cost as an allowance for property tax
and insurance. This value was selected by DRI after review of a wide variety
of sources.
Extra start-up cost. The total extra start-up cost (which is treated as
an operating cost, as opposed to being capitalized) is derived froa the fixed
capital and direct annual operating costs. The capital-related cosponent is
3% of the fixed capital cost as an allowance for "fix it" costs. The oper-
ating cost-related component which is 20% of a normal year's direct
operating cost, allows for hiring and training employees before production
and for higher unit costs during the start-up period. This value
for the extra start-up cost for surface retorting plants with a 2-year start-
up period was selected by DRI after a review of several sources, including
estimates for TOSCO II (Nutter and Waitman, 1978) and Paraho (Pforzheiner and
Kur»chaT, March 24, 1977) plants. The extra start-up cost was assumed to be
incurred during the first year of production but is levelized to spread it
uniformly over every barrel of oil produced (see Sections 6.4.1 and 6.4.3).
291
-------
..- • Under Colorado HB 1076, enacted in 1977,
severance tax is levied on the production of a commercial oil shale facility
at the rate of 4% of the "gross proceeds" for surface retorted oil. "Gross
proceeds" is defined as the value of the oil shale at the point of severance
arid is calculated by subtracting costs (e.g., retorting and mining) from the
gross sales income. Since pollution controls add to costs, they reduce the
gross proceeds by a corresponding amount. Hence, a credit for severance tax
not psid should be deducted from the pollution control costs.
tffiile operating costs are clearly allowable in calculating gross
proceeds, return on capita] does not appear to be (the statute refers to
allowing "...costs, including direct and indirect expenditures for:
(a) equipment and machinery....''). Hence, when this credit Is calculated,
the capital charge must be replaced by some form of amortization. For this
analysis, tne severance tax credit calculations are based on direct and
indirect annual operating costs, plus 5% of the fixed capital cost to provide
capital amortization over the 20-year project life.
In applying this credit, allowance was also made for exemptions to the
tax for the first 10,000 barrels per day of production and for plants that
have not achieved 50% of their design capacity, together with reduced rates
of tax in the early years. The credit is levelized in order to achieve a
uniform per-barrel cost. The methodology utilized (LFAC2 in Section 6.4.1}
is not precise, but since the severence tax correction, is typically less than
2% of the total annual or per-barrel control cost (see Section 6.2.4),
further refinement is not justified.*
8ya*groductL.credits. The by-product credit (if any) for each control is
shown in Tables 6.3-3 and 6.3-4. (The^e are no salable by-products ^roro
solid waste management.) By-product values of $110 per ton for ammonia. $30
per long ton for sulfur, and $32 per barrel for oils were used.
At present, there is no significant market for sulfur in the Rocky
Mountain Region; in the past, shipping costs to move recovered sulfur to a
chemical complex could have been greater than its delivered value. However.
the price of high Quality sulfur has gone up substantially in recent years.
reaching values as high as $129 per long ton (U.S. DO!, August 1981). High
demand for sulfur is projected through the year 2000 (Rangnow and Fasullo,
September 28S 1981). Hence, a nominal $30 per long ton has been included for
recovered sulfur. However, if in the future a sulfuric acid plant and
fertilizer complex are developed in the area, the values of by-product sulfur
and ammonia would be raised.
* Sines this analysis was conducted, the Colorado Legislature has amended the
severance tax legislation pertaining to oil shale. While the basic rate
for aooveground retorting is unchanged, the various exeffptions discussed
above are reduced. This will result in plants paying slightly more sever-
ance tax, which marginally increases the severance tax credit, thereby
marginally (much less than 1%) reducing the pollution control cost.
292
-------
The by-product value of $32 per barrel for light oils recovered by
pollution control activities is higher than the selling price assumed for
snale oil, which is $30 per barrel. Light oils are more valuable than heavy
oils, and it is the lighter fractions that would be prevented from evapora-
tion by the pollution controls. Consequently, a higher value is justified
for recovered shale oil as opposed to whole shale oil,
Working Capital-"
The working capital associated with a control was taken as one month's
total operating cost plus three months' by-product credit. This is equiv-
alent tc be one month's total operating cost disregarding the by-product
credit, plus two months' by-product credit. Two months' by-product credit
represents one month's inventory and one month's receivables. These values
were selected by DRI after review of a variety of data sources.
Working capital is advanced in accordance with the direct annual oper-
ating cost plus the extra start-up cost, as follows:
Operating Output as Operating Cost Working
(Qn-Stream) % of Full Relative to Full Capital
Factor Production Production Increment
Year I 50% 56% 76% 76%
Year 2 75% 83% 83% 7%
Year 3 90% 100% ' 100% 17%
100%
Seventy-six percent of the working capital is advanced in Year 1 because
this includes the 20% extra start-up cost (56% + 20% = 76%). In Year 2, the
operating cost increases from 76% to 83% of normal, hence 7% more worldng
capital is required. A similar argument applies to Year 3, leading to a 17%
working capital increment. All working capital is recovered in Year 20.
The working capital charge rate (RW) is calculated in a similar way to a
fixed charge rate (see Sections 6.4.1 and 6.4.2). For 12% DCF ROR and normal
project-timing assumptions, RW = 20.83%.
6.2.3 Solid Waste Management Costs
Throughout this manual a distinction is made between fixed capital costs
and annual operating costs. The importance of this distinction is related to
the treatment for determining income tax liability. Operating costs can be
claimed as an expense in the year in which they are incurred, whereas a fixed
capital cost must be depreciated over the period for which the asset is
expected to be used. The effect of classifying a cost as an operating cost
ratner than a capital cost is to reduce the tax liability in any given year.
For air and water pollution controls, the distinction between fixed
capital and annual operating costs is unequivocal. For solid waste manage-
ment costs which are developed in the form of year-by-year cash flows
293
-------
(Table 6.1-3), the distinction is less--dear. The cost.of deep monitoring
wells, which occurs-only in Year 1 (the first year of production in this case
study analysis)» was treated as a,fixed capital cost, while costs that occur
throughout the project life were considered as operating costs. Costs that
occur at the end of the project (e.g., revegetation) were also treated as
operating costs, since there is no remaining project life over which to
depreciate them. In the Lurgi-Qpen Pit case study, there are two costs, the
shallow monitoring wells and piezometers, that occur only in'Year 10, i.e.,
halfway through-the project's life. Although by no means a clear-cut
decision, these costs were designated fixed capital costs since there is
still sufficient time over which to depreciate the assets before the project
ends.
Since the solid waste management operating costs are not proportional to
production, they were "levelized" to transform them into equivalent direct
annual operating costs that are proportional to production, so that they can
be treated in the same way as other direct annual operating costs. Level-
izing involves determining the annual cost that is proportional to production
and which has the same present value (for a given DCF ROR) as the irregular
operating cost stream. Further explanation and an example are provided in
Section 6.4.3. Costs designated as fixed capital were not levelized.
Table 6.2-3 presents the solid waste management fixed capital costs
and direct annual operating costs (levelized at 12% DCF ROR) derived from
Table 6.1-3.
6.2.4 Control Cost Exaftple
Table 6.2-4 provides an example of the composition of the various
elements of per-barrel control cost for a single major pollution control, the
electrostatic precipitators. Per-barrel costs follow identical proportions
to annual costs.
It can be seen that the fixed capital charge amounts to 68.4% of the
total cost, whereas the working capital charge is only 0.5% of the total
cost. It is interesting to note that the fixed capital charge is almost
entirely return on equity, as the investment tax credit (20% of fixed capital
cost) almost offsets the income tax liability over the project life when both
are discounted at 12%, which is the specified DCF ROR. This illustrates the
effect of the time-value of money, as the tax credit is given before produc-
tion commences, whereas the regular tax liability is weighted toward the
later years of the project.
The direct operating cost for the electrostatic precipitators is 17.8%
of the total cost. Electricity (15.0%) is the largest component, followed by
maintenance. This particular pollution control has no operating labor or
supplies.
The indirect operating cost amounts to 13.3% of the total cost for this
control, of which 12.6% results from the cost of property tax and insurance.
The extra start-up costs and the severance tax credit are 2.1% and 1.4%,
respectively, of the total.
294
-------
TABLE 6.2-3. FIXED CAPITAL AND DIRECT ANNUAL OPERATING COSTS
FOR SOLID WASTE MANAGEMENT
Fixed Direct Annual„
Capital Cost Operating Cost0
Activity ($000's) ($000's/yr)
SURFACE HYDROLOGY
Runoff Collection Sumps 63
Runoff Collection Pumps 16
Deep Monitoring Wells 858
Shallow Monitoring Wells 26C
Piezometers 432°
SURFACE STABILIZATION .
Dust Suppression 11,079
Revegetation 8
Topsail 2
Seed 1
3 The direct annual operating costs are 1 eve!ized with respect to production
at 12% DCF ROR.
b
Spent in first year of production, Year 1.
c Spent in tenth year of production, Year 10.
Source; DRI.
295
-------
TABLE 6.2-4. PEt-BARREL COST BREAKDOWN FOR ELECTROSTATIC PRECIPITATORS
(Standard Economic Assumptions)
Cost Category
Cents/Barrel
Percentage of Total
Fixed Capital Charge
Equity Return (12% ROR)
Income Taxes Paid
Investment Tax Credit
Working Capital Charge
Direct Operating Costs
Maintenance
Operating Supplies
Operating Labor
Cooling Water
Steam
Electricity
Indirect Operating Costs
Taxes and Insurance
Extra Start-up Costs
Severance Tax Credit
By-product Credit
TOTAL COST
37.4
9.6
(7.4)
1.6
8.7
7.3
1.2
(0.8)
39.6
0.3
10.3
7.7
57.9
2.8
15.0
12.6
2.1
(1-4)
68.4
0.5
17.8
13.3
100.0
Source: DRI.
These cost proportions for the electrostatic precipitators are typi-
cal of those for air pollution controls. However, for some controls, the
indirect operating cost or even the per-barrel control cost can become
negative where there is a significant by-product credit.
Water pollution control costs tend to be less capital-intensive, i.e.,
the ratio of the total annual capital charge to the total annual operating
296
-------
cost is lower. This is because some controls have high operating supplies
and utility costs.
Solid waste management costs are different in that they are basically
either a fixed capital cost or a direct annual operating cost, but not both
for & given control. This reduces working capital and indirect annual
operating costs, respectively, to essentially zero.
6.3 COST ANALYSIS RESULTS
The methodology used to develop the data presented in this section is
identical to a complete discounted cash flow evaluation; that is, it solves
for the annual or per-barrel revenue required to provide the specified return
on tne investment (DCF ROR) associated with a control. This revenue require-
ment is known as the total annual or per-barrel control cost. The cost
metnodology is outlined in Section 6.2, and further details are provided in
Section 6.4.1.
Two control items—proper maintenance of valves and pumps and the
floating roof oil storage tanks—have relatively large by-product credits
which lead to negative total annual costs (i.e., total annual cost credits).
Although these items might consequently not be considered pollution controls,
their costs have been included in the total cost of air pollution control.
The net credit associated with these items represents a very small proportion
(lass than 0.6%) of the total air pollution control cost using standard
economic assumptions,'and :even less using the sensitivity analyses.
5.3.1 Results for Standard Economic Assumptions*
The term "standard economic assumptions" is used to describe the normal
economic assumptions presented in* Tables 6.2-1 and 6.2-2. The majority of
these assumptions are in reasonable accord with normal engineering and
economic evaluation practices. The most critical economic assumption is that
* As "already mentioned, this analysis was developed prior to enactment of the
Economic Recovery Tax Act of 1981. The rapid depreciation (ACRS) permitted
fay this act would significantly reduce the values of the fixed charge
factors, especially for normal ("pass through") financing as opposed to
stand-alone financing.
For standard economic assumptions, very rough estimates of the changes in
total annual control costs are as follows:
Air controls: 1085 decrease on aggregate.
Water controls: 5% decrease on aggregate.
Solid waste mgt.: 0-15% decrease, depending orr item.
As an alternative assumption, If the energy portion (10%) of the investment
tax credit were allowed to expire at the end of 1982, the combined effect
of this and ACRS would be to cause small increases in total annual control
costs.
-297
-------
of 12% required DCF ROR. This figure was adopted for the oil shale PCTMs and
would be appropriate for a mature industry, but it is probably low for a
pioneer plant at,this time (see Sections 6.2.1 and 6.3,2 for a discussion of
factors influencing the selection of a DCF ROR).
Table 6.3-1 provides a detailed summary of pollution control costs, by
control group, developed using the standard economic assumptions for the case
study considered in this manual. Table 6.3-2 details the specific controls
included in each control grouping. Note that total costs for solid waste
management are not provided. A complete solid waste management plan for the
Lurgi-Open Fit plant has not been proposed. As a result, cost estimates are
available for particular items only, and no estimate of total solid waste
management cost can be made at this time.
Table 6.3-1 shows that the total fixed capital cost for all air pol-
lution control equipment is approximately $91 million, while the total
per-barrel control cost is $1.14. The total fixed capital cost for water
pollution control is approximately $7 million, and the total per-barrel
control cost is 19 cents.
Table 6.3-1 also compares the per-barrel cost of pollution control to an
assumed $30 per-barrel value for shale oil.* For air pollution control,
the proportion is 3.8 percent. The total water pollution control cost
represents approximately 0.6% of the $30 per-barrel value of shale oil.
The works-gate value of $30 per barrel (mid-1980 dollars) for Lurgi
retorted shale oil was based on two sources: a developer's estimate of $29
for a light shale oil (Cathedral Bluffs Shale Oil Co., November 14, 1980),
and a study by Peat, Marwick, Mitchell & Co. (September 1980) which derived
current values for shale oil. This study concluded that the per-barrel value
of shale oil (at the project site) was approximately $31.50 to $32.50" for
surface retorted oil. In no case was upgrading involved.
It is generally anticipated that the real price of oil will increase in
the future. Hence, the value of $30 may be considered to be a conservative
estimate because it does not include any element of future escalation rela-
tive to the general level of prices. For example, if oil prices were to
escalate at only 2% per annum relative to general cost levels (which can be
expected to include pollution control costs), the real value of shale oil
would reach almost $45 per barrel (in mid-1980 dollars) by the year 2000,
i.e., at the end of the 20-year project life.
Cost..Details--
Full cost details for each air and water pollution control (using
standard economic assumptions) are presented in Tables 6.3-3 and 6.3-4. As
already noted, two items—proper maintenance of valves and pumps and the
floating roof oil storage tanks—were found to have negative total annual
* Other prices for the value of shale oil are used in the other oil shale
PCTMs, reflecting quality differences.
298
-------
TABLE 6.3-1. POLLUTION CONTROL COSTS, BY CONTROL GROUP, FOR THE
STANDARD ECONOMIC ASSUMPTIONS
co
' " ^ ' ~
Control Group
Air Pollution Control
Particulate Control
Flue Gas Treatment
Miscellaneous Air
TOTAL AIR
Water Pollution Control
Retort Water
Miscellaneous Water
TOTAL WATER
Fixed ,
Capital Cost
($000' s)
32,451
50,734
7.857
91,042
3,788
3^334
7,122
Total Annual
Capital
Charge0
($000's/yr)
5,168
8,269
1,310
14,747
685
727
1,412
Total Annual
Operating
Cost
($000's/yr)
4,471
3,747
795
9,013
1,745
701
2,446
Total Annual
Control Cost
($000's/yr)
9,639
12,016
2,105
23,760
2,430
1,428
3,858
Per- barrel
Control Cost
(cents/bbl)
47
58
10
115
12
_7
19
Per-barrel
Control Cost as
a Proportion .
of Oil Value0
1.5
1.9
0.3
3.8
0.4
0,2
0.6
Refer to Table 6.3-2 for a listing of the items that are included in each control group.
Does not include working capital
c Includes charge for working capital.
Assuming shale oil is valued at ISO/barrel
Source: DRI.
-------
TABLE 6.3-2. CONTROL GROUPINGS
Group Designation
Specific Controls
Air Pollution Control
Participate Control:
Flue Gas Treatment:
Miscellaneous Air:
Fabric filters, water and foam sprays.
Electrostatic precipitators.
Stretford, ammonia storage, floating roof
oil storage tanks, proper maintenance of
valves and pumps, catalytic converters.
Water Pollution Control
Retort Water:
Miscellaneous Water:
Ammonia recovery unit, API oil/water
separator.
Mine water clarifier,* boiler feedwater
treatment,* cooling water treatment,*
equalization pond, runoff oil/water
separator, aeration pond.
* These technologies could be considered as part of the process rather than
pollution control.
\
Source: DRI.
costs. In these cases, the annual by-product credits were large enough to
more than offset the total annual capital charges and total annual operating
costs. These items were, nevertheless, incorporated into the air pollution
control cost total.
Table 6.3-5 presents the costs of nine solid waste management items. Of
the nine, dust suppression is by far the most costly item—$11.3 million
total annual control cost, or 54 cents per barrel. This item is entirely an
operating expenditure (zero fixed capital cost). The only solid waste man-
agement items with fixed capital costs are the deep monitoring wells, the
shallow monitoring wel1ss and the piezometers, which total $1.3 million.
It should be remembered that these costs do not represent the full cost
associated with a complete solid waste management operation. Even so, the
per-barrel control cost associated with these nine solid waste management
items is significantly greater than the total per-barrel control cost for
water pollution control.
300
-------
TABLE 6 3-3 DFTAILS OF AIR POLLUTION CONTROL COSTS, STANDARD ECONOMIC ASSUMPTIONS
U>
3
Control Identification
(No of Units)
Fabric Filters (2)
Fabric Filter (1)
Fabric Filter (i)
Fabric Filters (3)
f-abric Filte s (2)
Fabric Filte s (8)
Fabric Filte s (8)
Fabric Filte s (9)
Fabric Filte s (9)
Fabric Filter (1)
Fabric Filters (2)
Fabric Filters (3)
Fabric Filters (2)
Fabric Filters (2)
Fabric Filters (2)
Fabric Filters (4)
Fabric Filters (2)
Fabric Filters (2)
Water and Foam Sprays
Fabric Filters (4)
Fabric Filters (13)
Fixed
Charge
Factor
(*)
15.61
15 61
15 61
15 61
15 61
15 61
15.61
15 61
15.61
15 61
15.61
15.61
IS 61
16 61
15 61
15.61
15.61
15 61
15.61
16 17
16 17
Subtotal Participate Controls
Stretford {!)
Ammonia Storage (1)
Floating Roof Storage
Tanks (2)
Maintenance of Valves, etc.
Catalytic Converters
16 17
15.61
15.61
15 61
23 36
Subtotal Misc. Air Controls
Electrostatic
Precipitators (13)
TOTAL AIR POLLUTION CONTROLS
8 Includes fixed and working
Includes annual by-product
c For sulfur at $30/Iong ton
16 17
Fixed
Capital
Cost
($000 '&)
987
105
552
1,051
628
4,828
4,828
5,432
5,432
249
559
559
348
348
348
696
348
348
909
1,837
2,059
32,451
6,860
466
300
61
170
7,857
5JL_?J4
9JL042
capital charges RW =
credit
Working
Capital
($000' s)
8
1
4
a
9
38
38
42
42
2
4
4
3
3
3
6
3
3
124
14
IS
375
94
1
27
26
5
153
312
840
20,83%
Total Annual
Capital
Charge*
($000's>/yr)
156
1?
87
166
100
762
762
857
857
39
aa
88
55
55
55
110
55
55
168
300
336
5,168
1,129
73
52
15
41
1,310
jy>§9
iiiMZ
Direct
Annual
Op Cost
(1000's/yr)
63
6
34
65
85
297
297
334
334
Ib
34
34
22
22
22
44
22
22
1,456
113
127
3,448
769
—
—
61
60
890
2,144
6^482
Annual Indirect
By-product Annual ^
Crpdit Op Cost
($QOQ's/yr) ($000's/yr)
31
-._ -5
17
33
20
152
152
172
172
8
18
18
11
11
__ "1 1
22
11
11
27
58
65
1,023
72C 146
15
155^ (141)
126° (120)
5
353 (95)
— Ii32
353 2,531
Total
Annual
Op Cast
<$OOfl's/yiO
94
9
51
98
105
449
449
506
506
23
52
52
33
33
33
66
33
33
1,483
171
192
4,471
915
15
(141)
(59)
65
795
3^747
iiQ13
Total Annual
Control tost
(lOQO's/yr)
250
26
138
264
205
1,211
1,211
1,363
1,363
62
140
140
88
88
88
176
88
88
1,651
471
528
9,639
2,044
«8
(89)
(44)
106
2,105
ULfili
23,760
Per-barrel
Control Cost
(cents)
1 2
0 1
0 7
1 3
1.0
5 8
5 8
6 6
6 6
0.3
0 7
0.7
0.4
0 4
0 4
0 8
0,4
0 4
8.0
2.3
2 6
46 5
9 9
0.4
(0:4)
(0.2)
- 0 5
10 2
-ill
114 6
d For light shale oil at $32/bbl.
Source DRI estimates based
on data provided by SWEC
-------
TABLE 6 3-4 DETAILS OF WATER POLLUTION CONTROL COSTS, STANDARD ECONOMIC ASSUMPTIONS
o
_ ~ .
Control Identification
Ammonia Recovery Unit
API Oil/Water Separator
Subtotal Retort Water
Mine Water Clarifier" .
Cooling Water Treatment d
Boi ler Feedwater Treatment
Equalization Pond
Runoff Oil/Water Separator
Aeration Pond
Subtotal Misc Water
TOTAL WATER POLLUTION CONTROLS
Fixed
Charge
Factor
(%)
16.17
16.17
21 64
16.17
16.17
21 64
21.64
21.64
Fixed
Capital
Cost
($000 's)
3,627
161
3,788
2,560
—
122
181
41
430
3,334
7,122
Working
Capital
($000 's)
349
1
350
33
4
6
1
<1
14
58
408
__
Total Annual
Capital
Charge
($000's/yr)
659
26
685
561
1
21
39
9
96
727
1,412
Direct
Annual
Op, Cost
($000's/yr)
2,419
4
2,423
319
51
69
3
1
153
596
3,019
Annual
By-product
Credit
(lOOO's/yr)
816C
—
816
..
—
—
—
—
—
-
816
Indirect
Annual .
Op Cost
($000's/yr)
(683)
5
(678)
81
(<1)
4
6
1
13
105
(513)
Total
Annual
Op Cost
($000's/yr)
1,736
9
1,745
400
51
73
9
2
166
701
2,446
Total Annual
Control Cost
($000's/yr)
2,395
as
2,430
961
52
94
48
11
262
1,428
M5S
Per -barrel
Control Cost
(cents)
11 6
0.2
11,8
4.6
0.3
0.5
0 2
0.1
1 3
7,0
18-8 •
Includes fixed and working capital charges. RW = 20.83%.
Includes annual by-product credit.
For ammonia at $110/ton.
These technologies could be considered as part of the process rather than pollution control.
Source- DRI estimates based on data provided by WPA.
-------
TABLE 6.3-5. DETAILS OF SOLID WASTE MANAGEMENT COSTS, STAKOARD ECONOMIC ASSUMPTIONS
Fixed Fixed
Charge Capital
Factor Cost
Control Identification (%) ($000' s)
SURFACE HYDROLOGY
Runoff Collection Sumps
Runoff Collection Pumps
Deep Monitoring Wells 12.49 858
Shallow Monitoring Wells 4,51 26
UJ Piezometers 4. SI 432
o
SURFACE STABILIZATION
Dust Suppression
Revegetation
Topsoll
Seed
Total Annual Direct
Working Capital Annual
Capital Charge* Op Cost
($000's) ($000's/yr) ($000's/yr)
5 1 63
1 <1 16
2 108
<1 1
1 20
923 192 11,079
1 <1 8
<1 — 2
.»..- w— t
Indirect Total
Annual Annual Total Annual Per-barrel
Op Cost Op Cost Control Cost Control Cost
($OQO's/yr) ($QOO's/yr) (lOOO's/yr) (cents)
(<1) 63 64 0.3
— ' 16 16 01
27 27 135 0 7
112 <0.1
14 14 34 02
(14) 11,065 11,257 54 3
— 88 <0.1
2 2 <0 1
1 1
* Includes fixed and working capital charges RW = 20 83%
Note There are no by-product credits.
Source: ORI estimates based on data provided by SWEC
-------
6.3.2 Sens1ti vi ty Analyses
This section explores the sensitivity of the results to changes in the
engineering costs and economic assumptions. In general, only a single change
from the standard economic assumptions was made in each case, enabling the
impact of this change to be isolated. Table 6.3-6 summarizes the changes
made for each case, while Table 6.3-7 displays the fixed and working capital
charge rates used to calculate per-barrel control costs. Per-barrel pol-
lution control costs, expressed as a percentage of a $30 per-barrel shale oil
value, are given in Table 6.3-8. Table 6.3-9 provides additional detail for
the absolute per-barrel control costs and includes percentage changes from
the standard economic assumptions. Comparative results for the various
sensitivity analyses are presented graphically in Figure 6.3-1. No sensitiv-
ity analysis has been performed on the solid waste management costs, as only
partial cost estimates were available. Each sensitivity analysis is dis-
cussed below.
Twenty Percent Increase in Fixed Capital Costs—
Cost escalation is always a problem with pioneer plants because of tne
numerous uncertainties (Merrow, September 1978; Merrow, Chapel and Worthing,
July 1979). A 20% increase is not at all unreasonable despite the inclusion
of a 20% contingency in fixed capital cost estimates.
Table 6.3-9 shows that a 20% increase in fixed capital costs has a
moderate effect on pollution control costs. As would be expected, the more
capital-intensive air pollution controls show the greatest increase. The
total air pollution control cost increases by 15% (16 cents per barrel),
while the total water pollution control cost increases by 8% (only 1 cent per
barrel).
TwentyPercent Increase in Operating Costs—
Operating costs are often better defined than capital costs, which is
why an operating cost contingency is not normally included in the direct
annual operating costs. However, there are many reasons why operating costs
could be higher than anticipated. For example, regional shortages of skilled
labor could result in higher wages and reduced productivity. Also, labor
costs may escalate faster than other costs. Maintenance costs could be
higher than expected, and both utility requirements and utility unit costs
could deviate from expectations.
For air pollution controls, the overall effect of an increase in direct
annual operating cost is much less than that of the same percentage increase
in fixed capital cost. For a 20% increase, the total air pollution control
cost increases by only 6 cents per barrel (a 6% increase). The more oper-
ating cost-intensive total water pollution control cost increases by 3 cents
per barrel (a 16% increase). This is a reversal of the results obtained for
a 20% increase in fixed capital costs, and confirms that the air pollution
controls are much more capital-intensive than the water pollution controls.
304
-------
TABLE 6 3-6 ASSUMPTIONS FOR SENSITIVITY ANALYSES*
g
tn
Sensitivity Analysis
+20% Fixed Capital Costs
+20* Direct Operating Costs
+66 T% Utilities Costs
60% of Planned Output
Delayed Start-up
15* DCF ROR
Stand-alone Financing
Stand-alone Financing
»t 15% DCF ROR
+20JS Fixed Capital Costs,
DCF ROR
m
12%
12X
12%
12%
15*
m
15%
15*
Fixed Capital
Costs
Increased 209!
SEA
SEA
SEA
SEA
SEA
SEA
SEA
Increased 20%
Direct Operating
Costs
SEA
Increased 20%
UtiUty portion
increased 66 7%
Decreased 10%
SEA
SEA
SEA
SEA
SEA
Byproduct
Credits
SEA
SEA
SEA
Decreased 20%
SEA
SEA
SEA 7
SEA J
SEA
Comments
A 2-year delay was incorporated into the RC
and RW calculations by halting production in
Years 2 and 3 and resuming in Year 4 Project
life was Increased to 22 years
For RC and 8VJ calculations, investment tax
credit and depreciation earned in or before
Year 3 were accumulated and taken as a lump
sun 1n Year 3. The schedules after Year 3
remained unchanged
A 2-year delay was incorporated into the RC
Delayed Start-up and
15% DCF ROR
+20X Fixed Capital Costs,
Delayed Start-up, 15%
DCF ROR and Stand-alone
Financing "
15%
Increased 20%
SEA
SEA
and RW calculations by halting production in
Years 2 and 3 and resuming in Year 4 Project
life was increased to 22 years
A 2-year delay was incorporated into the RC
and RW calculations as above, and the
investment tax credit arid depreciation were
accumulated to Year 5
* SEA indicates that the costs are the same as those used for analysis based on standaid economic assumptions
Source- DRI.
-------
TABLE 6 3-7 CHARGE RATES F0« SENSITIVITY ANALYSES
w
o
Sensitivity Analyses
Standard +20% Fixed +20* Direct +66 7% 80% of
Economic Capital Operating Utilities Planned Delayed 15% Stand-alone
Assumptions Costs Costs Costs Output Start-tip OCF ROR Financing
Hxed Charge Rate
Retort Timing 16 17 16.17 16.17 16 17 16 17 19 52 20 92 18.52
Mine Timing 15 61 15 61 15 61 15 61 15,61 19 23 20 06 17,81
Early Water
Management 21 i4 21 64 21.64 21 64 21 64 26 66 30 01 26 82
Catalytic
Converters 23 36 23 36 23 36 23 36 23 36 26 46 27.03 25 14
Working Capital
Charge Bate 20.83 20 83 20 83 20 83 20 83 20 96 25 58 20 83
Contained
Stand-alone Assumptions »*ith
Financing at Combined Stand-alone
15S DCF ROR Assumptions3 Financing
24.31 26 94 33 92
23.23 25 82 32 S3
37.62 38,63 51 89
29 53 31 91 38.91
25 58 25 80 2S.80
Combined assumptions ara 20% increase In fixed capital costs, 15% DCF ROR and delayed start-up
Refer to Table 6,2-2 for pollution controls included in each category
Source DRI
-------
TABLE 6.3-8. SENSITIVITY ANALYSES EXPRESSED AS
A PERCENTAGE OF SHALE OIL VALUE
Per-barrel Control Cost as a
Percent of ISO/Barrel Shale Oil Value
Sensitivity Analysis
Standard Economic Assumptions
20% Increase in Fixed Capital Costs
20% Increase in Direct Operating Costs
66.7% Increase in Utilities Costs
80% of Planned Output
Delayed Start-up
15% DCF ROR
Stand-alone Financing
Stand-alone Financing at 15% DCF ROR
Coirbined Assumptions*
Air
3.8
4.4
4.0
4.2
4.7
4.4
4.5
4.2
5.0
6.3
Water
0.6
0.7
0.7
0.8
0.7
0.7
0.7
0.7
0.8
0.9
Combined Assumptions with Stand-alone
Financing* 7.5 1.0
* Combined assumptions are 20% increase in fixed capital costs, 15% DCF ROR
and decayed start-up.
Soiree: DRI.
66.7%Increase inUtilities Costs—
Operation of various controls requires inputs of electricity and steam.
Under standard economic assumptions, electricity is valued at 3 cents per
kW-hr, and it is assumed that steam is generated at a cost of $3/MMBtu. The
electricity charge of 3 cents per kW-hr may very likely underestimate the
true cost of power purchased from the grid (should this prove necessary) as
it is a compromise value between plants that can sell power and those that
must purchase power (see Section 6.1.1). Since the Lurgi-Open Pit plant is
likely to require electricity from outside sources, a 5 cents per kW-hr rate
(a 66.7% increase) was considered. At the same time, the cost of steam was
also increased by 66.7%, as the standard rate for this input of $3/MMBtu may
also prove to be conservative. Three dollars per million Btu is a typical
1S80 value used for heat inputs in engineering studies, but no detailed cost
evaluation was conducted for this manual. Hence, the steam cost pust be
considered uncertain.
307
-------
TABLE 6.3*9. SENSITIVITY ANALYSES BY MEDIUM
Air Pollution
Control
Sensitivity Analysis
Standard Economic Assumptions
20% Increase in Fixed Capital
Costs
20% Increase in Direct Operating
Costs
66.7% Increase in Utilities
Costs
80% of Planned Output
Delayed Start-up
15% DCF ROR
Stand-alone Financing
Stand-alone Financing at
15% DCF ROR
Combined Assumptions*
Combined Assumptions with
Stand-alone Financing*
cents/bfal
115
131
121
126
140
131
136
125
150
188
224
% change
—
+14.8
+5.6
+10.2
+22.0
+14.3
+18.5
+8.8
+31.2
+64.2
+95.9
Water Pollution
Control
cents/bbl
10
20
22
24
22
20
21
20
23
26
30
% change
--
+8.1
+16.0
+28.6
+20.2
+8.1
+12.9
+6.7
+22.7
+39.4
+61.1
* Combined assumptions are 20% increase in fixed capital costs, 15% DCF ROR
and delayed start-up.
Note; Percentage changes may not agree with figures calculated from cents
per barrel due to rounding.
Source: DRI.
The results indicate that utility costs constitute a moderately impor-
tant component of pollution control costs. The total water pollution control
cost increases by 28% (5 cents per barrel). This increase can be attributed
to the large quantities of steam required by the ammonia recovery unit. The
effect on air pollution control costs is less significant (although the
absolute increase in costs is greater). The 66.7% increase in utilities
costs causes the total air pollution control cost to rise by 10% (11 cents
308
-------
o
ID
2 50
2.00
I SO
!00
SO
8
2*
o
us
I 21
0.50
1.26
055
140'
051
131 , _ 1.36 _L
\77~77Tt "25
043
044
0.43
I 50
044
188
0.4T
2.24
0.4T
.50 r
n IQ A 9ft (K22
g-yy-7-* I/1 y y > / A KS/.S^
1 0»2 1 | 012 1 1 015
SWOARD 20%1NOJEASE 20%INCREASE
ECONOMC INFIXED INDIRECT
ASSUMPTIONS CAPITAL OPERATING
COSTS COSTS
024
s..s's_jf i
017 1
66.7%
INCREASE IN
UTILITIES
COSTS
Q22~-
014
PLANNED
OUTPUT
" 020 0,21 020 °-2J
1.012 1 1 012 I 1 012 1 1 012
DELAYED 15% STANO- STAND-
START- OCF ROR ALONE ALONE
UP FINANCING FINANCING
AT 15%
OCF ROR
026
j 012
030
////
012
COMBINED , COMBINED
ASSUMPTIONS ASSUMPTION
WITH
STAND-ALON
FINANCING
L/J TOTAL CAPITAL CHARGE
| [ TOTAL OPERATING COST
* COMBINED ASSUMPTIONS ARE 20% INCREASE IN FIXED CAPITAL COSTS, 15% OCF fiOR AND DELAYED START-UP
SOURCE: Dftl
FIGURE 6 3-1 SENSITIVITY ANALYSES TOTAL PCR-BARREL AIR ANDWATFR POLLUTION CONTROL COSTS
-------
per barrel). This increase is due -largely to the significant amounts of
electricity requ-ired"to operate the electrostatic precipitators and fabric
filters. ' •-'* ' - - ' ' '
E1ghty Percgnt of PIanned Output—
A frequent problem with pioneer process plants is that they fail to
achieve their planned output. Occasionally they produce more. When a plant
fails to reach its planned output, the annual fixed capital charges must be
spread over reduced output, and the direct annual operating costs decrease by
a lesser proportion than the output because some components (such as main-
tenance) are virtually unchanged.
For the case of a plant that achieves only 80% of planned output, it was
assumed that direct annual operating costs fall to 90% of the full production
costs. Production in the start-up years and by-product credits were prorated
to 80% of the standard values.
Overall, the results are relatively severe, with the more capital-
intensive air pollution controls showing the greatest increase. Total air
pollution control cost increases 22% (25 cents per barrel), while the total
water pollution control cost increases 20% (3 cents per barrel).
De 1 ayed _Sta_rt-_up—
Because of the time-value of money implicit in the discounting proce-
dure, anything that delays or curtails production raises annual capital
charges and, hence, the per-barrel control cost; conversly, anything that
accelerates or extends production reduces the costs.
For this analysis, production is halted for two years (Years 2 and 3)
and then follows the normal build-up profile displaced by two years. (The
project life is extended by 2 years to 22 years.) This profile corresponds
to the scenario that the plant initially starts production according to
schedule; then, at the end of Year I, the plant is closed down because
serious operational problems have developed and must be solved, which takes
two years.
The effects of this case are only moderately severe. Total air pollu-
tion control cost increases 14% (16 cents per barrel). The less capital-
intensive total water pollution control cost increases by 8% (1 cent per
barrel).
Fifteen Percent DCF ROR--
The minimum acceptable DCF ROR used in a project feasibility study is
normally not divulged by developers and, in any event, is influenced by
alternative investment opportunities and other factors. However, there is
broad confirmation that a rate between 12% and 15% per annum (in constant
dollars) is appropriate for evaluating oil shale investments (Denver Research
Institute, et al., July 1979; also see Merrow, September 1978). This ROR,
which is called a "hurdle rate," is higher than the return that a company
310
-------
actually earns on its capital for a number of reasons. First, it is an
unfortunate fact of life that many projects earn less than the projected
"ate because things do not work out as expected. This is only partly
offset by the few that do better than anticipated. Second, project evalua-
tions do not usually include such costs as R and D, exploration, and reserve
acquisition; also, they may not include recovery of some general corporate
expenses.
The single most important factor that influences the required DCF ROR is
the perceived riskiness of the project. A high risk project is expected to
pass a higher ROR hurdle than a low risk project. Some of the types of risks
that might be subjectively taken into account in selecting a minimum accept-
able 30R for a mining project in the U.S. include:
» Unproven technology (and, hence, uncertain equipment costs);
« Geologic uncertainty;
« Very large investments in relationship to total corporate assets;
« Rapid inflation in some cost components;
« Long construction and start-up periods;
« Narket uncertainty;
• Regulatory uncertainty (leading to delays or added costs); and
* Difficult working 'condition's"or adverse,socioeconomic impacts
leading to manpower problems. .'
For any first generation commercial synfuef plant,.: all 'the -above factor's
are present, with the possible exception of geologic uncertainty. At this
time, most of these factors are strongly present in oiil shale projects. The
standard economic assumption is 12% DCF ROR, which is probably the lowest
acceptable ROR for a' private enterprise shale'oil plant with proven technol-
ogy. For a pioneer plant, industry is likely to require at least 15% ROR,
unless it wishes to "buy into" a new industry. Of course, if another party
(e.g., the Federal government) were prepared to share the risk in some way,
the required ROR would be reduced. Even though spine of the risks listed
above do not apply to'pollution controls, Industry does: not perceive environ-
menta" costs to be separable from the total project.' Hence, all components
o* a project, including pollution controls,,must earn the specified DCF RQR.
i
Increasing the required DCF ROR from 12 to 15% has a substantial effect
on pollution control costs. Once again, air pollution controls show the
greatest increase. The total air pollution control cost increases by 19%
(21 cents per barrel), while th« total water pollution control cost increases
by 13% (or 2 cents per barrel).
Stand-alone Financing—
The term "stand-alone financing" is used to describe a project in
which investment tax credits and allowances for depreciation cannot be
passed through to a parent company (or companies) which can benefit from
311
-------
them immediately. {These benefits are treated as negative Income tax in
conducting the alternative "pass-through" form of prdject evaluation which is
used under standard economic assumptions,) Instead,'it is necessaryfor the
project to become profitable before the tax benefits can be obtained. It is
difficult to determine when this might occur because it requires a detailed
knowledge of the overall project economics; in any event, the timing of the
benefits will be affected by the selling price of the shale oil. However, it
is known that some of the developers are assuming stand-alone financing for
their evaluations since it more closely reflects their tax positions than
does pass-through financing.
To 'determine the approximate effect of substituting stand-alone
financing for pass-through financing, it was assumed that no investment tax
credit or depreciation could be claimed until the third year of production,
i.e., the first year of full output. This assumption was based on examina-
tion of the cash flow analysis for an open pit mine with surface retorting
presented in a recent oil shale tax study (Peat, Warwick, Mitchell & Co.,
September 1980). It must be emphasized that this assumption is very sim-
plistic (and probably conservative), since the relevant details in the tax
study were significantly different from those assumed in this manual. As
expectedj the effect was larger for the more capital-intensive air pollution
controls, although the overall effect for both control groups is fairly mild.
Total air pollution control cost increases 10 cents per barrel (9%), while
the total water pollution control cost increases 1 cent per barrel (7%). A
more refined calculation might yield substantially greater Increases.
especially if a low, value was used for the price of shale oil, thereby
reducing profitability,
The effect of stand-alone financing was also evaluated at 15% DCF RQR,
using the same -assumptions as above. This probably comes closer to a devel-
oper's evaluation. The resulting increases in costs are quite substantial,
with the total air pollution control cost increasing 35 cents per barrel
(31%) and the total water pollution control cost increasing 4 cents per
barrel (23%).
Combined Cases—
Two combined cases were evaluated using the components already dis-
cussed. However, it is not sufficient to construct these analyses by simply
combining the results from the earlier findings, so new analyses were devel-
oped. The two cases are as follows:
Combined assumptions
* 20% increase in fixed capital costs
* Delayed start-up
» 15% DCF ROR
» Everything else as standard economic assumptions.
312
-------
Combined assumptions with stand-alone financing
* 20% increase in fixed capital costs
® Delayed start-up
« 15% DCF ROR
* Stand-alone financing
• Everything else as standard economic assumptions.
These combined cases are intended to be quite plausible adverse scenar-
ios (i.e., 20% increase in fixed capital costs and delayed start-up) looked
at *rom industry's viewpoint (i.e, 15% DCF ROR, with or without stand-alone
finarcing, depending on the company),
The results indicate that these cases would impose significant burdens
on industry. The more capital-intensive air pollution controls increase in
cost by 64% (73 cents per barrel) for regular ("pass-through") financing and
by 96% ($1.09 per barrel)' for stand-alone financing. Total water pollution
control cost rises approximately 39% (7 cents per barrel) for the regular
case and 61% (11 cents per barrel) for the stand-alone case. The absolute
level of pollution control costs reaches $1.88 per barrel for all air cen-
tre's and 26 cents per barrel for water pollution controls for the regular
(pass-through) case. For combined assumptions with stand-alone financing,
absolute pollution control costs are $2.24 per barrel for total air and
30 cents per barrel 'for total water. -These results represent an almost
doubling of tha absdlute- cost of air pollution controls.
Returning to Table 6.3-8, it can be seen that the total cost of air
pollution control is roughly 4% of the assumed $30 per-barrel value for shale
oil under the standard economic assumptions. The total water pollution
contra", cost is roughly 0.6% of the value of the oil.
With respect to air pollution controls, only the two sets of combined
assumptions produce major increases in cost. In these two cases, the total
control cost reaches 6.3 and 7.5% of the assumed $30 value for shale oil.
Water pollution control costs have proven to be less sensitive to
changes in the engineering costs and economic assumptions. Only the last two
sensitivity analyses (the two sets of combined assumptions) produce notice-
able increases in total water pollution control costs. From a base of 0.6%
of the shale oil value under the standard economic assumptions, water pol-
lution control cost rises no higher than to 1.0% of the oil value (for
combined assumptions with stand-alone financing). When compared with air
pollution control costs, water control costs are more sensitive to changes in
direct operating costs and utilities, as opposed to changes that affect fixed
capital charges. Increases in direct operating costs and utilities costs,
however, do not produce significantly larger increases in total water pollu-
tion control costs than those sensitivity analyses which affect fixed capital
chs^ges.
313
-------
Figure 6,3-1 sftl'its the pollution control costs Into'a per-barrel total
.capital charge and a per-barrel total -operating cost. This figure effec-
tively illustrates the response of capital-intensive controls (air) vs.
operating cast-i-ntensive controls (water) to the different sensitivity
analyses.
6.4 DETAILS OF COST ANALYSIS METHODOLOGY
6.4.1 CostAlgorithms
This section provides the algorithms used to calculate total annual and
per-barrel control costs and capital charge factors.
Calculation of Total Annual and Per-barrel Control Costs—
The totalannual Control cost (TC) of each item considered for pollution
control is the sura of the total annual operating cost (TOC) and the total
annual capital charge (CC). That is:
TC = TOC + CC
and TOC = DOC + IOC
where: DOC = Direct annual operating cost
IOC = Indirect annual operating cost
and CC = (FCC x RF) + (WC x RW)
where: FCC - Fixed capital cost
WC = Working capital
RF = Fixed charge factor
RW = Working capital charge factor
The cost per barrel (CPB) is the total annual cost divided by the normal
annual production, i.e.:
CPp = TC -r (BPSD x 328.5)
where: BPSD = Barrels per stream day
The factor, 328.5, is the number of normal operating days per year.
The derivation of each cost component is explained below.
Direct annual operating cost. DOC is a data input derived from the
engineering cost analysis. It is the annual cost for a normal year and is
taken from one of the data Tables 6.1-1, 6.1-2 or 6.2-3.
Indirect annual operating cost. The indirect annual operating cost
(IOC) is calculated as follows:
314
-------
IOC = TIA + ESC - STC - BP
where: TIA = Annual property tax and insurance allowance
ESC = Annual extra start-up costs (levelized—see below)
STC = Annual severance tax credit (levelized--see below)
BP = Annual by-product credit
BP is an input generated from stream data and shown In one of the tables in
Sectien 6.3, and:
TIA = 0.03 x FCC
ESC = (0.03 x FCC + 0.20 x DOC) x LFAC1
STC = 0.04 x [(DOC + ESC + TIA - BP) + 0.05 x FCC] x LFAC2
LFAC1 and LFAC2 are levelizing factors that spread ESC and STC uniformly
over all units of production* LFAC2 also makes adjustments for the severance
tax exemptions allowed for low production. These factors are as follows:
(1 -f r)-1
LFAC1 = • •
0-56 , 0.83 . ^20 1
"** > ^ , v o "*"
1 + r (l^F nf3 (1 + r)n
(1 + r)"1
0.56 0.83 (1 + r)~2 - (1 + r)"20
1 + r (1 + r)2 r
LFAC2 = BPSD - 10,000
BPSD
1 v 0-83 _ . 1 v 1 . 3 „ 1 . (1 f r)-4 - (1 +
4 x (1 + r)2 2 x (1 + r)3 4 x (1 + r)4 r
0.56 0.83 (1 -t- r)"2 - (1 -t- r)'20
1 + r (1 + r)^ r
where: r = Discount rate = DCF ROR
BPSD = Barrels per stream day (i.e., normal daily output)
A numerical example of a levelizing calculation is giv«n in Section 6.4.3.
Capital costs. Fixed capital cost (FCC) is an input taken from one of
the data tables. Working capital (WC) is calculated as follows;
... .WC * 1/12 x TOC + 1/4 x BP
315
-------
Capital.ChargeFactors*- ' , , * '
The'fixed charge factor equation is:
0C S
N
2 [(1 + r) x (K - T x 0
n=J n n
N
(1 - T) I [(1 * r)"n 0 ]
n=l
-cn)]
where: K = Capital expenditure in year n (I K = 1.000)
C - Investment credit in year n
0 = Depreciation in year n
0 = Operating income in year n (0 = 1.000 in a normal
n year) n
r = Discount Rate = DCF ROR
T ~ Tax rate
N = Last year of project
J = First year of project (i.e., -3)
Note that the first year of production is Year 1.
The same equation is used to determine the working capital charge factor
(RW), except that the D and C terms are omitted,
6.4.2 ExampleCalculation of a Fixed Charge Factor
Table 6.4-1 provides an example of the calculation of a fixed charge
factor. The data used are for retort timing, using standard economic
assumptions (see Table 6.2-2).
The following is an explanation of the calculations in the table.
Expenditures are shown negative, while income (and taxes avoided) is shown
positive. Column [2] is a schedule of capital expenditures to be made over
a three-year period., totaling an arbitrary $1,000. (Unit value is used
instead of $1,000 in the equation above.) Columns [3], [4], and [5] deal
with allowances associated with this capital expenditure. Column [3] is a
schedule of depreciation, commencing in Year 1 when the asset is placed into
service. Column [4] gives the value of the depreciation allowed to the
company. This value is the income tax not incurred as a consequence of the
depreciation deduction, and it is 48% of Column [3]. Column [5] is the 20%
investment tax credit available in each year a capital expenditure is made.
(This is a direct credit against tax and does not have to be multiplied by
the tax rate,)
Column [6] represents the income stream resulting from the $1,000
investment (Column [2]). Income in a normal, full production year is
316
-------
TAB1C 6,4-3 EXAMPLE OF FIXED CHARGE FACTOR CAICUIATTOH
(Standard Fcftnomlc Assumptions, Retort Timing)
Year
[11
-2
-1
0
1
2
3
4
5
e
7
8
9
10
11
12
13
14
15
1$
17
18
19
20
Gross
Capital
[2]
(ioo. oo)
(300.00)
(600.00)
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0,00
0 00
0.00
0 00
0.00
0,00
o.oo
0 00
0.00
d oo
(1,000 00)
Depreciation
Amount
[3]
0.00
0.00
0.00
117.65
110. 29
102 94
95.59
88.24
80.88
73.53
66.18
58.82
51 47
44.12
36.76
29,41
22.06
14.71
7.35
0 00
0 00
6 00
8 00
l.QOO 00
Allowances
Depreciation Investment
Value @ 48% fax Tax Credit
[4] [b]
0 00
0.00
0.00
56.47
52.94
49.41
45.88
42.36
38.82
35.29
31 77
28 23
24.71
21 18
17,64
14.12
10 59
7,06
3 53
0.00
0.00
0 00
0.00
480.00
20.00
60.00
120.00
0.00
0.00
0.00
0 00
0.00
0.00
0.00
0.00
0.00
0.00
0,00
0.00
0 00
' 0.00
0.00
0 00
0 00
0 00
0 00
0 00
200 00
Operdtj
Gross
[6]
0 OOx
O.OOx
0 OOx
O.S6x
0 83x
l.OOx
l.OOx
1 OOx
l.OOx
l.OOx
l.OOx
1 OOx
l.OOx
l.OOx
1 OOx
l.OOx
l.OOx
l.OOx
1 OOx
l.OOx
1 OOx
1 OOx
1 OOx
jig_ Income
Net After
48% Tax
[7]
0 OOx
O.OOx
O.OOx
0 291x
0 432x
0 520x
0.520X
0 520x
0 520x
0. 520x
0 520x
0 520x
0 520*
Q.5ZOX
0 520x
0 520x
0 520x
0 520x
0 520x
0 S20X
0.520X
0 520x
0 520x
Net Present Values
Discount Factors After-tax
at 12% Income*
[8] [9]
1 2544
] 1200
1 0000
0.8929
0 7972
0,7118
0 b355
0 5674
0 5066
0 4523
0 4039
0 3606
0 3220
0.2875
0 2567
0 2292
0 2046
0 1827
0 1631
0 1456
0. 1300
0 1161
0 1037
0. OOOOx
0. OOOOx
0 OOOOx
0.2600X
0 3441x
0.3701X
0.3305X
0 29Slx
0.2634X
0 2352X
0 2100x
0 1875x
0.1674X
0 1495X
0.1335x
0. 1192X
0 1064x
0.0950X
0.0848X
0 0757x
0 0676x
0 0604X
0 0539x
3 6093X
Depreciation
Allowance
[10]
o.oo
0.00
0.00
50.42
42 20
35.17
29.16
24 03
19.67
15.97
12.83
10.18
7.95
6.09
4 53
3.24
2 17
1.29
0.58
0.00
0 00
0.00
0.00
265.48
Investment
Tax Credit
[11]
26 09
67 20
120. 00
0.00
0 00
0 00
0 00
0 00
0 00
0 00
0.00
0.00
0 00
0.00
0.00
0.00
0 00
0.00
0 00
0.00
0 00
0 00
0 00
212.29
Capital
C123
(125 44)
{336 00)
(600 00)
0 00
0 00
0 00
0 00
0 00
0 00
0 00
0 00
0 00
0 00
0.00
0 00
0 00
0,00
0 00
0 00
0 00
0 00
0 00
0 00
(1,061 44)
'
* After-tax Income is before depreciation allowance and investment tax credit
Sourc.e DR1
-------
designated by 1ll,Q0x, " • Since income 4s proportional -to production,- and
production in the startup years is Jess- than full production, the first two
years of income are appropriately reduced', f;e., 0.56x in Year 1 (0.56 is the
50% operating factor in Year 1 divided by the 90% factor for a normal year)
and 0.83x in Year 2, Column £7] shows the residual income to the company
after income tax is paid on the income in Column [6].
The 12% discount factors in Column [8] are used to generate the present
values in Columns [9], [10],. [11] and [12]. After summing the columns of
present values of after- tax income, depreciation allowance, investment tax
credit, and capital expenditure, an equation is constructed to determine the
gross income, x, which must be generated by the $1,000 of invested capital to
achieve a 12% DCF RQR; thus:
3.6093x = 1,061.44 - 265.48 - 212.29
[9] = [12] - [10] - [11]
therefore: x = = 161.71
(x represents the gross income in a full production year that is
necessary to provide the specified DCF ROR, 12%, on $1,000 of fixed
capital.)
hence: RF = ' = 16.17%
6-4,3 Cost Level i zing Calculations
While most direct operating costs vary in proportion to plant output,
the operating Costs for solid waste management do not. A prime example of
this is the cost of surface reclamation, which only occurs at the end of the
project. To spread these costs in a pattern consistent with -production,
these operating costs are transformed into an annual figure which can then be
applied to each barrel of shale oil produced. This is done by calculating a
"levelized cost" for a normal year's production. This technique is also used
to spread the extra start-up cost and severance tax credit uniformly over
shale oil production.
A "levelizing factor" is used to make this transformation. The fol-
lowing equation shows how a levelizing factor is used to arrive at a level-
ized cost (i.e. 5 a stream of payments having the same profile as production),
given the present value of a nonuniform stream of payments:
i -]•,!/.+_ I(Present Values of a Cost Stream)
Level! zed Cost -- Levelizing Factor - ~
By dividing the levelized cost by a normal year's output, a cost per unit of
production is derived.
318
-------
The equation for calculating the 1 eve!izing factor (LF) is;
LF = PVFA(r,N) -
where: LF ~ Levelizing factor
PVFA, N^ = Present value factor of a uniform series of
^r> ' payments for N years
PVF, ^ = Present value factor of a single payment in
tr'nj year n
r = Discount Rate = OCF ROR
N = Number of production years
S = Number of years in the start-up period
n - Any specific year in the start-up period
L - The proportion of normal output during any given
n start-up year; the series of L values constitutes
the "start-up profile"
The second term on the right-hand side of the above equation is an
adjustment to the uniform series represented by the first term. The comple-
ment of the L figure (i.e., that portion of each start-up year which is
less than full production) is discounted, summed, and then' subtracted from
the uniform series. Since the start-up years have high present values, the
effect of subtracting this term has a substantial impact on the levelizing
factor. Because the levelizing factor is the denominator in the equation
which determines the levelized cost (and, hence, the unit cost), this adjust-
ment term raises tne per-barrel cost.
Cost_ Levelizing Example—
To illustrate the concept of cost levelization, calculation of the 12%
OCF ROR levelizing factor used in this manual is presented below:
Proportion of
Year Normal Output (L ) PVF i 12% (1~Ln) * PVF
1 0.56' 0.8929 0.3929
2 0.83 0.7972 0.1355
3 1.00 ^
> 5.7793 0.0000
I
20 1,00 ' .
7.4694 0.5284
Hence: LF(r=12%> ^ yrs) = 7.4694 - 0.5284 = €.9410
(Note that all present values are expressed with respect to Year 0)
• 319
-------
This factor is. the same as the denominator "in the .levelizlng expressions
LFAC1 and HFAC2. '
As an illostration of a levelizing calculation, consider the
revegetation costs shown in Table 6.1-3. These costs are incurred , as
follows:-
Year 19: $185,000
Year 20: $185,000
Year 21: $185,000
The present value of these costs, expressed with respect to Year 0, is
calculated as follows:
Year Expenditure PVF § 12% Present Values
19 $185,000 0.1161
20 185,000 0.1037
21 185,000 0.0926
Thus, $57,794 is the present value of all the revegetation costs. To
turn this into a cost that is distributed uniformly with respect to output,
it must be divided by l^r=12%t N=20 years).
C7 704
Therefore, Level ized Cost = g 9410 = $8>326
Thus, $8,326 (rounded to $8,000 in Table 6.2-3) is the annual cost, in a
normal production year, that is equivalent to the irregular cost profile
given above. This direct annual operating cost can be used in conjunction
with the algorithms given in Section 6.4.1 for calculation of total annual
control cost and per-barrel control cost, whereas the irregular stream of
expenditures from which it was derived could not be used with the standard
methodology.
In summary, cost levelization redistributes a cost series that is not
proportional to production in such a way as to yield an equivalent series
that is proportional to production and has the same economic value.
320
-------
SECTION 7
DATA LIMITATION AND RESEARCH NEEDS
A number of limitations associated with stream characterization and
pollution control technology performance were identified in the data base
during the preparation of the Pollution Control Technical Manual for the
Lurgi oil shale retorting process combined with open pit mining. It is
important that users of this manual be aware of these limitations. It is
also important that these limitations be addressed prior to development of an
oil shale facility of the magnitude analyzed in this manual (e.g.,
.119,000 TPSD oil shale mined, 193,000 TPSD total solids mined, and
63,1*0 BPSD shale oil produced).
7,1 DATA LIMITATIONS
The description of the Lurgi retorting process and information regarding
applicable control technologies, performance, and costs used to prepare this
manual, were obtained from reports on the operation of pilot Lurgi retorts,
vendor descriptions, and engineering calculations used in conjunction with
experience transferred ,from analogue industries such as the petroleum,
utility, , and -mineral mining industries which utilize similar control
technologies. Until "hands on" experience is obtained from commercial-scale
oil shale operations, these sources constitute the best available data base.
However, the limitations of this data base should be clearly understood.
Pilot retorts were built and operated primarily to improve process design and
not for demonstrating operation of a commercial~sized retort with attendant
pollution control systems. Many pollution control systems have never been
pilot tasted with an oil shale retort. Even for those control systems that
were pilot tested, often the data collected have been very limited.
The primary experience with Lurgi retorting involves two pilot plants
(5 tons/day and 25 tons/day) and several laboratory-scale retorts operated in
West Germany during the past few years. Shales from Tract C-a, Tract C-b,
and the Colony mine in Colorado have been processed recently, and the
available data from these tests have been used in this manual. A full-sized
Lurgi retort is expected to process 8,800 TPSD of raw shale, and 13 of these
retorts will be needed to produce 63,140 BPSD of shale oil. This represents
an enormous scale-up of the pilot retorts; therefore, improvements in the
retort design and operating parameters may be inevitable, resulting in some
uncertainty about the stream compositions and performance of control
technologies.
Variations in the grade of the shale also introduce modifications to the
operating parameters and, hence, the data. This is evident from the
321
-------
retorting tests on the oil shale from Tracts C-a and C-b» from which
significantly different results were obtained. Thus, a> Tinea-r extrapolation
of the data from these operations may not be entirely applicable to the
processing of shales from other locations, and a direct transfer of the
information to other development sites must be made with caution.
It should also be noted that, to date; the Lurgi pilot plants have
consisted' of the retort and' flue gas discharge system only;" Other unit
processes
-------
regarding characterization of streams and control technology performance, as
revealed during preparation of the Lurgi-Open Pit PCTH, are identified in
Table 7.1-1. The status of the information is presented according to the
development stage of the source and technology. The specific information
sources are also identified. A reliability or confidence ranking is assigned
to i.he data for each stream and technology based on a subjective evaluation
of the direct applicability of the data to a commercial-scale Lurgi-Open Pit
facility. Some salient features and caveats in the information base are
noted, and specific research needs are identified to overcome some of the
data 'imitations.
323
-------
TABLE 7,1-1. BATA LIMITATIONS AND RESEARCH NEEDS
Streams, and Control
Technologies
(Hgure No.)
Pollutant
Controlled
Information
Status"
Information
>
Sources'5 Reliability1
Parti culate EIBIssions
TFFzT 3 3-10)
Baghouses
(3 3-2)
Participates
(point source)
fi,H
10,U
Water and Foam Participates
Sprays (fugitive)
(3 3-2, 3 3-10)
G,H
10,11
Retort Gas
(3 3-3,"3"3-4, 3 3-5)
Remarks
The partleulate emission estimates
have been calculated by using
-------
TABIE 7.1-1 (cent.)
Streams and Control
Technologies
(Figure No )
Stratford
(3.J-6)
Pollutant
Controlled
Information Information
Status"
Sources'* Reliability0
H,S
G.H.I
10,11
ro
Lurgl FlueGas
~=
Remarks
In this manual, the technology is
used to treat the acid gases obtained
during the retort gas purification
The operating experience with the
Lurgi retort gas is not documented
The technology has been tested
recently with the retort gas from a
pilot Modified In Situ retorting
experiment, but the data are not yet
available
The technology Is used commercially
in other industries at a scale
necessary to treat the Lurgi acid
gases
Non-BaS sulfur compounds (nay not be
recovered efficiently with the
technology
Excessive amounts of heavy organics
tend to deteriorate the reagents and
the quality of the sulfur product
Non-NHs nitrogen compounds may also
degrade the reagents
Research Needs
Excessive amounts of C02 in the feed
may have an adverse affect on the HZS
removal efficiency.
According to the vendor information,
an H2S renoval efficiency of 30 pprav
in the treated gas Is achievable with
a single absorber
The flue gas data have been obtained
from a pilot-scale experiment with the
Tract C-a oil shale
The operating data from actual source
testing need to be obtained
The pilot plant data need to be
obtained and the transferability of
the information to the Lurgi acid
gases needs to be verified. Scale-up
data may also need to be obtained
Tiw technology transferability needs
to b« verified.
The control efficiencies for COS,
CS2, nercaptans, etc , need to be
determined.
The impact on the efficiency of HaS
removal due to the presence of
condensable organics in the feed
needs to be quantified
The Impact of organic amines, HCH,
etc., on the Stretford cheuicals
needs to be quantified.
The impact on the efficiency of H2S
reatoval due to excessive amounts of
COZ needs to be quantified.
Scale-up data need to be obtained
(Continued)
-------
TABLE 7.1-1 (cent.)
Streams and Control
Technologies
(Figure No )
Pollutant
Controlled
Information Information
b
Status0
Sources
Reliability
CO
ISi
Electrostatic
PrecipHator
(3 3-3)
Particulates
G,H
10,11
Remarks
Research Meeds
The S02 content of the flue gas is
reported to be 30 pprav This amount
appears to be too low based oft the
material and elemental balances.
Adsorption of the SOg on the processed
shale to form calcium and magnesium
sulfates is given as the explanation
for the low SOZ emission.
Tfle NOx content of the flue gas is
reported to be 300 ppmv. Based on
the material and elemental balances,
this amount appears to be too low.
Only 10% of the fuel-based nitrogen in
the processed shale 1s reported to be
converted to NOx, while 90% Is
converted to elemental nitrogen.
Approximately 50% of the fuel-based
mtrogan is normally converted to NOx,
Data on trace elements and several
criteria pollutants are not
documented.
An electrostatic precipitator to
remove the particulates from the flue
gas has been suggested in the modified
DDP for Tract C-a
The operating experience with the
Lurgi pilot plant has been obtained.
The technology is used commercially
in the utility Industry at a scale
necessary to treat the Lurgi flue gas
The particulate removal efficiency
depends upon the resistivity of the
processed shale and the temperature
of the flue gas stream
Moisture in the flue gas generally
decreases the resistivity, thus
increases the control efficiency.
The efficiency of SQ2 adserption on
the processed shale needs to be
determined.
The actual NOx content of the flue
gas needs to be determined.
The conversion of th« fuel-based
nitrogen to NOx needs to be
quantified. Also, the extent of
thermal fixation of the atmospheric
nitrogen needs to be determined
The data on traci elements arid
criteria pollutants need to be
obtained from actual source testing.
Scale-up data need to be obtained.
The technology transfarability needs
to be verified^
the effect of variations -In the shale
grade on the resistivity of ttie
particulates needs to be quantified,
The relationship between the sioisture
content of the flue gas and control
efficiency needs to be studied.
(Continued)
-------
TABIE 7,1-1 {cent }
Streams and Control
Technologies
(Figure No )
,. Information Information
Controlled Status^ Sources
Reliability4
Fiberglass Fabric Participates G,H,I
Fugitive
Hydrocarbons
ro
-4
Floating Roof
Tanks
Maintenance
Catalytic
Converters
Hydrocarbons I
G,H
Hydrocarbons G,H
Hydrocarbons, G,H
CO
Gas liguor
Oil/Water
Separator
O.3-4)
Oils and
Greases
G,H,I
10,11
10
10
10,11
10,11
10,11
10,11
Remarks
Research Needs
(he fiberglass baghouses have a
much higher temperature 1it«1t than
conventional baghouses, but the
operating experience with the Luigi
flue gas is not documented
The technology 1s used in other
industries, ft participate control
efficiency comparable to that obtain-
able vith conventional baghouses
appears to be achievable
The fugitive hydrocarbons are
estimated from the properties of the
oil products.
Oouhle^sealed, floating roof storage
tanks have bten provided for volatile
product storage.
Floating roof storage tanks are used
commercially for oil storage
Routine maintenance of valves,
pumps, etc , is a commonly used
operational practice to control the
hydrocarbon leakage.
All diesel-powered machinery is
equipped with catalytic converters
to control hydrocarbon and CO
emissions The catalytic converters
are a commonly used technology.
ThB'compasition of the gas liquor has
been deterained from the pilot
experiment with the Tract C-a shale
"The operating experience with the gas
liquor is not documented
Ttip technology is used commercially
in other Industries.
The feasibility and efficiency of the
technology for the flue gas need to
be determined Also, the effect of
temperature needs to be studied.
The technology transferability needs
to be verified
Scale-up data need to be obtained
The feasibility and efficiency of
the technology for removal of oils
and greases from the gas liquor need
to be evaluated
The technology transferability needs
to be verified
(Continued)
-------
TABLE 7.1-1 (cont.)
Streams and Control
Technologies
(figure No.)
Ammonia Recovery
Unit
(3 3-9}
Pollutant
Controlled
Information Information
Status8 Sources'1 Reliability0
Remarks
Research Heeds
NH3
4,10
Carbon
Adsorption (CA)
(5 2-17, 5.2-25)
Dissolved
Organics
G.H.I
6,10,11
Co
W
Ot>
Cooling Tower dissolved
(3 3-11, 5 2-17) Solids
G.H.I
6,10,11
Oil emulsions may not be controlled
by the separator. Addition of
chemicals or heating the water nay be
necessary to break the emulsion.
The operating experience with the oil
shale process waters is not docu-
mented.
The technology Is used commercially
in other industries.
Dissolved organics in the gas conden-
sate may have a detrimental impact on
the efficiency of ammonia recovery
and the quality of the product.
The technology Is used eoramercially
in the treatment of industrial and
municipal wastewaters. The operating
experience with oil shale effluents
Is not documented. In this manual,
the technology is used for polishing
the stripped gas liquor before it can
be used in the cooling tower. A 50%
reduction in the organics appears to
tie achievable with this technology.
The cooling tower 1s a cownonly used
technology. It can be used to control
the dissolved solids in the process
waters if the volatile components have
been removed previously and the water
quality is suitable as the makeup to
the cooling tower In this manual,
first the volatile components in the
gas 1tquor are removed by steam strip-
ping in the ammonia recovery system,
then the organics are removed by
adsorption on carbon. The water thus
treated is evaporated in the cooling
tower and the dissolved solids are
concentrated in the cooling tower
blowdown,
The potential of forming oil emulsion
in the gas liquor needs to be ,
evaluated. , ,"
The feasibility and-efficiency- of the
technology for the Lurgi gs& liquor
need to be evaluated.
The technology transferebi IHy needs
to be evaluated
Dissolved organics in the gas
condensate and their Impact on the
efficiency of the technology need io
be estimated ~ "
The feasibility and efficiency of the
CA treatment for the lurgl gas liquor
need to be evaluated and/or the
technology transferability needs to
be verified. ;'.
The feasibility and efficiency of the
cooling tower for the stripped gas,
liquor need to be evaluated and/ot*.
the technology trafwferabllity"needs
to be verified.
(Continued)
-------
TABIE 7 1-1 (coot )
Streams and Control
Technologies
(Figure No )
Solar
Fvaporation
Pond
(5.2-17)
Pollutant
Controlled
Dissolved
Sol Ids
Information Information
b
Status
G.H.I
Sources
10
Reliability
Hi lie Water
"(3 3-2)
CO
l\>
CO
Reverse Osmosis
(RO)
(5 2-11, 5.2-12)
Dissolved
Organics and
Inorganics
G,H,I
7,10
ch Needs
The technology Is commonly used ft»r
concentrating the wastewaters. Solar
energy Incident on an open evaporation
pond is used to evaporate the water
The precipitated salts may be removed
periodically. In this manual, the
stripped gas liquor after the carbon
adsorption and cooling tower treat-
ments is concentrated further in the
solar evaporation pond. Sufficient
storage capacity and surface area are
provided to hold the water without
overflowing during the low-evaporation,
high-precipitation months
The composition of the water from the
upper and Tower aquifers has been
determined from the drilling and
pumping tests on Tract C-a. Based on
the storage coefficients and
transmissivity data, it was estimated
in this manual that 43% of the total
nine water was contributed by the
upper aquifer and 57% was contributed
by the lower aquifer. The average
mine water flow rate was estimated
to be 16,50(1 gpm, although the flows
frofc both aquifers are quite variable
The water quality also varies
considerably within an aquifer and
between the two aquifers
The operating experience with the mine
water is not documented, but the
technology is used commercially in
other applications In this manual,
the technology 1s applied to the
excess mine water for the removal
of bulk dissolved solids
Approximately 90-99* of the dissolved
Inorganics can be removed by the
technology The removal efficiency
for organics may be somewhat lower
The treated water is rleaned further
so that it can be discharged and the
rejected material 1s used for processed
shale moisturizing
Characterisation and disposal
approaches for the precipitated salts
need to be evaluated
Additional data on the aquifer water
quality and flow rates may need to be
obtained to assess potential reuse,
treatment, and disposal options for
the excess mine water
The feasibility and efficiency of the
technology for the mine water need to
be evaluated and/or the technology
transferabi1ity needs to be verified
(Continued)
-------
TABLE 7.1-1 (cont.)
Streams and Control
Technologies
(Figure No.)
Pollutant
Contro11ed
Information Information
Status"
Sources Reliability0
Remarks
Research Needs
Boron Adsorption
(5 2-11, 5 2-13)
Boron
10
Phenol Adsorption
(5 2-11, 5 2-13)
Phenol
10
Co
CO
o
Aeration Pond
(5.2-11)
Organics and
Alkalinity
10
Reinjection
System
8,10
This 1s an Ion-exchange technique
Involving a resin which 1s specific
for boron The operating experience
with mine water is not documented
In this manual, the technology is
applied to the RO treated water to
remove the boron in order to meet
discharge criteria.
This is also an ion-exchange
technique involving a resin which is
specific for phenol The operating
experience with the mine water is
not documented In this manual,
the technology is applied to the
excess mine water after it has been
treated by the RO and boron
adsorption technologies. The treated
water is then discharged on the
surface.
Kith this technique, the wastewater
is aerated by passing air or pure
oxygen through it. This process
affords decomposition of the
chemically oxidlzaole organic matter
as well as provides the oxygen for
the biological growth to carry out
biooxidation. Some oxidizable salts
of heavy metals can also be precipi-
tated out. In this manual, the
technology is applied to the RO
treated excess nine water The
aerated water is discharged on the
surface.
The technology is used for the deep
well injection of some oil brine
wastes, but the operating experience
with the excess mine water on
Tract C-a is not documented. In this
manual, the excess mine water is first
clarified in an enclosed clarifier,
then injected into the upper aquifer.
The feasibility and efficiency of th*
technology for the tilrte watef need to
be evaluated.
The feasibimy and efficiency- of the
technology for tine mine water need to
be evaluated.
The feasibility am* efficiency of th*
technology for the mine water need t*
be evaluated. ' ,!
The feasibility and efficiency of the
technology for the mine water _a't
Tract C-» need to J»e evaluated" and/or
the technology transf«rabUity needs
to be verified. * <
(Cootinued)
-------
fABLt 71-1 (cont )
Streams and Control
Technologies
(Figure No )
Pollutant
Controlled
Information Infotmatior*
b
Status1
Sources
Reliability
Solid Wastes
(17FM)
2,10
10
Open Pit
Backfilling
(3.3-W)
1,10
Remarks
The Lurgi processed shale composition
has been derived from the pilot plant
information on the Tract C-a shale and
the material and elemental balances.
Some physical properties of the turgi
processed shale from Tract C-a have
b«en measured in laboratory testing
The quality of the leachate fron the
Lurgi processed shale has been
determined in a laboratory experiment
Large quantities of the overburden and
subore are produced during mining.
The physical and chemical character-
istics of these solid wastes have not
been determined. The wastes are
disposed of along with the processed
shale.
Cooling tower blowdovm, boiler blow-
down, boiler feedwater treatment
regeneration waste, mine water
Clarifler sludge, storn runoff,
service and fire water, etc., are
coi-hii'.ei! to form the processed shale
moisturizing water
Backfilling of the open pit with the
solid wastes, after the pit has been
developed to a sufficient size, is
mentioned in the original DDP for
Tract C-a, but the design details
are not given.
Research Needs
Scale-up data need to be obtained
Scale-up data need to be obtained
Scale-up data need to be obtained.
The physical and chemical properties
of the overburden and subore need to
be determined. If these wastes are
to be mixed with the processed shale,
then the Impact on the properties of
the processed shale should be
evaluated
Th« extent to which the process
wastewaters need to be treated before
mixing with the processed shale needs
to be determined. Changes 1n the
physical and chemical properties of
the solid wastes due to the mixing of
various plant wastewaters also need
to be determined.
The issues associated with pit
configuration, fill slope, logistics
of simultaneous mining and back-
filling, etc., need to be addressed
by a detailed engineering analysis
specifically tailored for the
development site
Careful procedures for waste disposal
and project shutdown need to be
developed, keeping in perspective the
potential of resuming open pit raining
in the future
(Continued)
-------
TABLE 7 1-1 (cent.)
Streams and Control
Technologies
(Figure Ho )
Pollutant
Controlled
Information Information
Status"
Sources
Reliability"
U!
IVJ
Runoff Diversion
Sua>ps and Pumps
teachable
Compounds
10
Dust Control
Participates
10
Remarks
Placement of the wastes in the path
of the two intercepted aquifers roay
create the potential for groundwater
contamination after the mine
dewatering Is stopped
During the backfilling operation,
the runoff from the waste pile and
the pit walls is gathered in the
collection sumps located at the
junction of the fill and walls It
is then pumped to the surface for
eventual use in processed shale
nolsturizimj. After the project
shutdown, the runoff is allowed to
flow into the pit.
The control of fugitive dust
generated during waste transport
and placement is achieved by water
and foam sprays and by paving the
haul roads
Research Needs
The groundwater contamination
potential needs to be assessed.
The effectiveness of tiner materials
to isolate the waste from the ground-
water needs to be evaluated.
The advantages and disadvantages of
mixing the wastes versus keeping them
segregated need to be evaluated from
the operational as well as environs,
mental viewpoint.
Means of reestablishing the aquifers
need to be Investigated
Long-term Impacts of combining the
aquifers in th« pit need to be
evaluated on the basis" of water
quality, recharge rate, regional ,
usage, etc. *
Alternate systems for dust control,
such as application of chemical
binders and aspfralt-ic- emulsions,
need to be evaluated.
(Continued)
-------
TABLE 73-1 (cont,)
Streams and Control
Technologies
(Figurs No, )
Reclamation and
Revegetation
Pollutant Information
Controlled Status
teachable I
Gam pounds,
Particulates.etc
Information
Sources
10
Reliability
Remarks
Research Needs
Grubbing, stripping, and clearing of
the area is performed as part of the
raining activities. The completed
surface of the landfill is covered
with soil and vegetated The oper-
ating experience with revegetating
the Lurgi processed shale is not
documented
Reestablishment of the vegetation on
the landfill needs to be studied on
a long-terra basis
OJ
Wk
OJ
Information Status:
A Conceptual analysis.
B Laboratory, bench-scale studies—oil shale or similar Industry,
C Pilot plant studies—oil shale or similar industry
D Semi-warts studies—oil shale or similar industry
E Cortraerdial'scale studies—oil shale or similar Industry.
F Pilot-scale studies—related industries.
G Commercial-scale studies—related Industries.
H Vendor provided Information,
I Engineering calculations.
Information Sources (detailed source information can be found in Section 8, References)
1 Gulf Oil Corp and Standard 011 Co (Indiana), March 1976.
2 Rio Blanco Oil Shale Co., February 1961
3 Gulf Oil Corp. and Standard Oil Co. (Indiana), May 1977.
4 U.S.S. Engineers and Consultants, Inc , April 1978.
S Cheremisinoff and Ellerbusch, 1978.
6 Hart, June 11, 1973.
7 Hicks and Liang, January 1981.
8 Mercer, Campbell and Wakayima, May 1979.
9 Woodward Clyde Consultants, October 13, 1980
10 Engineering calculations (DRI, SWEC, WPA).
11 Vendor estimates,
c Reliability:
\ Information is Judged to be applicable, no problems envisioned
2 Information applicable, but some design or scale-up problems may be encountered
3 Information appHcabla, but significant design or scale-up problems nay be encountered
4 Information may be applicable, but both design as well as scale-up problems (nay be encountered.
5 Information may not be applicable without major design and ^cale-up modifications
Source OKI based on the references listed in footnote b.
-------
SECTION 8
REFERENCES
Adams, C.E. and W.W. Eckenfelder, eds. 1974. Process Design Techniques for
Industrial Waste Treatment. Associated Water and Air Resources
Engineers, Environmental Press, Nashville, Tennessee.
American Petroleum Institute. 1969. Manual on Disposal of Refinery Wastes,
Volume on Liquid Wastes. API, New York.
American Petroleum Institute. March 1978. A New Correlation of NHs, C02 and
H2S Volatility Data From Aqueous Sour Water Systems. Publication
No. 955. API, New York.
Barduhn, A.J. September 1967. The Freezing Processes for Desalting Saline
Waters. Progress in Refrigeration Science and Technology, Proceedings of
the International Congress of Refrigeration, 12ths Madrid. Vol. 1,
37-55.
BatteH e, Columbus Laboratories. October 1978. Control of NOx Emission by
Stack Gas Treatment. EPRI FP-925. Final report prepared for the
Electric Power Research Institute, Palo Alto, California.
Beychok, M.R. 1967. Aqueous Wastes from Petroleum and Petrochemical Plants.
John Wiley and Sons, Surrey, England.
Calmon, C. and H. Gold. 1979. Ion Exchange for Pollution Control. 2 vols.
CRC Press, Boca Raton, Florida.
Cathedral Bluffs Shale Oil Company. November 14, 1980. Proposal for Finan-
cial Assistance in the Form of a Loan Guarantee, Volume V. Submitted to
U.S. Department of Energy in response to Solicitation DE-PS60-81RA50480.
Che^emisinoff, P.N. and F. EHerbusch. 1978. Carbon Adsorption Handbook.
Ann Arbor Science, Ann Arbor, Michigan.
Colony Development Operation. 1977. Prevention of Significant Deteriora-
tion; Application to U.S. Environmental Protection Agency, Region VIII.
Colony Development Operation. March 1980. Application to Colorado Mined
Land Reclamation Board for Solid Waste Disposal Permit.
Denver Research Institute/Water Purification Associates/Stone and Webster
Engineering Corporation. July 1979. Predicted Costs of Environmental
335
-------
Controls for a Commercial Oil Shale Industry. U.S.. fJef*artment of-Energy
.Report_NQ. CQO-EO.07-2'. -''"'.' ' ' • "" ' ,
Dravo Corporation^ February. 1976. Handbook of Ga-sifiers and Gas Treatment
Systems. " FE-1-772-11. Final Report, Task Assignment No. 4, engineering
Support Services.. Submitted to the 0.S. Energy Research and Development
Administration.
Electric Power Research Institute. April 1980. Economic and Design Factors
for Flue Gas Desulfurization Technology. EPRI CS-1428.
Fox, J.P., D.E. Jackson and R.H. Sakaji. 1980. Potential Uses of Spent
Shale in the Treatment of Oil Shale Retort Waters. 13th Oil Shale
Symposium Proceedings, Colorado School of Mines, Golden, Colorado.
Fox, J.P., K.K. Mason and J.J. Duvall. 1979. Partitioning of Major, Minor
and Trace Elements During Simulated In Situ Oil Shale Retorting. 12th
Oil Shale Symposium Proceedings, Colorado School of Mines, Golden,
Colorado,
Girvin, D.C., T. Hadeishi and J.P. Fox. June 1980. Use of Zeeman Atomic
Absorption Spectroscopy for the Measurement of Mercury in Oil Shale
Gases. Oil Shale Symposium; Sampling, Analysis and Quality Assurance,
March 26-28, 1979, Denver, Colorado. EPA-60G/9-8Q-022. U.S. Environ-
mental Protection Agency.
Gulf Oil Corporation and Standard Oil Company (Indiana). March 1976. Rio
Blanco Oil Shale Project: Detailed Development Plan, Tract C-a.
4 vols. Submitted to U.S. Department of the Interior, Geological
Survey, Area Oil Shale Supervisor.
Gulf Oil Corporation and Standard Oil Company (Indiana), May 1977. Rio
Blanco Oil Shale Project: Revised Detailed Development Plan, Tract C-a.
4 vols. Submitted to U.S. Department of the Interior, Geological
Survey, Area Oil Shale Supervisor.
Hart, J.A. June 11, 1973. Waste Water Recycled for Use in Refinery Cooling
Towers. Oil and Gas Journal. 71(24):92-96.
Hicks, R.E., et al. June 1979. Wastewater Treatment in Coal Conversion.
EPA-600/7-79-133. U.S. Environmental Protection Agency.
Hicks, R.E. and L. Liang. January 1981. A Study of Reverse Osmosis for
Treating Oil Shale In Situ Wastewaters, Final Report. DOE/LC/10089-5.
U.S. Department of Energy.
Hicks, R.E. and I.E. Wei. December 1980. A Study of Aerobic Oxidation and
Allied Treatments for Upgrading In Situ Retort Waters, Final Report.
DOE/ 10097-1. U.S. Department of Energy.
Humenick, M.J. 1977. Water and Wastewater Treatment: Calculations for
Chemical and Physical Processes. Marcel Oekker, New York.
336
-------
Jones, B.M., R.H. Sakaji and C.G. Daughton. August 1982. Physicochemical
Treatment Methods for Oil Shale Wastewater: Evaluation as Aids to
Biooxidation. 15th Oil Shale Symposium Proceedings, Colorado School of
H-'nes, Golden, Colorado.
Kohl, A.L. and F.C. Riesenfeld. 1979. Gas Purification. 3rd ed. Gulf
Publishing Company, Houston, Texas.
Krisher, A.S. August 28, 1978. Raw Water Treatment in the CPI. Chemical
Engineering, 85(19):78-98.
Marnell, P. September 1976. Lurgi/Ruhrgas Shale Oil Process. Hydrocarbon
Processing. 55(9):269-271.
HcWhorter, D.B. 1980. Reconnaissance Study of Leachate Quality from Raw
Mined Oil Shale—Laboratory Columns. EPA-600/7-80-181. U.S. Environ-
mental Protection Agency.
Mercer, 8.W., A.C. Campbell and W. Wakayima. May 1979. Evaluation of Land
Disposal and Underground Injection of Shale Oil Wastewaters. U.S. De-
partment of Energy Report No. PNL-2596.
Marrow, E.W. September 1978. Constraints on the Commercialization of Oil
Shale. R-2293-DOE. U.S. Department of Energy.
Merrow, E.W. , S.W. Chapel and C. Worthing. July 1979. A Review of Cost
Estimation in New Technologies: Implications for Energy Process Plants.
R-2481-DOE. U.S. Department of Energy.
North-Monson Company. August 11, 1980. Communication with Stone and Webster
Engineering Corporation, Denver, Colorado, regarding baghouses.
Nutter, J. and C. Waittnan, 1978. Oil Shale Economics Update. Tosco Corpo-
ration, Los Angeles, California.
Occidental Oil Shale, Inc. and Tenneco Shale Oil Company. April 1981.
Prevention of Significant Deterioration; Application to U.S. Environ-
mental Protection Agency, Region VIII.
Peabody Process Systems, Inc. February 1981. Paid study on suitability of
the Holmes-Stratford Process for Oil Shale Projects. Prepared for
Denver Research Institute, Denver, Colorado.
Peat, Marwick, Mitchell & Co. September 1980. Final Report: Oil Shale Tax
Study. Prepared for the Committee on Oil Shale, Rocky Mountain Oil and
Gas Association. Washington, D.C,
Peters, M.S. and K.D. Timmerhaus. 1980, Plant Design and Economics for
Chemical Engineers. 3rd ed. McGraw-Hill.
337
-------
Pforzheimer^ H. and S.K. Kunchal. March"24, 1977. Conmercia] Evaluation, of
, an Oil Shale Industry Based on the Parana Process., Paper presented to
the American Chemical Society National Meeting* New Orleans, Louisiana.
Rangnow, O.G. and P.A. Fasullo. September 28, 19&1. Rapid Growth is Outlook
for Recovered Sulfur. Oil artd Gas Journal, 7S( 39):242-246.
Research and Education Association. 1980. Modern Pollution Control Tech-
nology., Vol. I: Air Pollution Control. New York.
Rio Blanco Oil Shale Company. February 1981. Modification to the Detailed
Development Plan, Tract C-a: Lurgi Demonstration Project. Submitted to
U.S. Department of the Interior, Geological Survey, Deputy Conservation
Manager - Oil Shale.
Rio Blanco Oil Shale Company. March 1981. Modular Development Phase Mon-
itoring Report Seven; December 1979 - November 1980, Year-End Report.
4 vols.
Schmalfeld, I. P. July 1975. The Use of the Lurgi-Ruhrgas Process for the
Distillation of Oil Shale. Quarterly of the Colorado School of Mines.
70-3:129-145.
Slawson, G.C., ed. April 1980. Monitoring Groundwater Quality: The Impact
of In-Situ Oil Shale Retorting. GE 78TMP-103. A report by GE-Tempo,
Santa Barbara, California, for U.S. Environmental Protection Agency
Contract No. 68-03-2449.
Stanfield, K.E., et al. 1951. Properties of Colorado Oil Shale. U.S. De-
partment of the Interior, Bureau of Mines Report No. 4825.
Stone and Webster Engineering Corporation. January 30, 1979. Reference Fos-
sil Power Plant, Book 2B-1.
TRW and DRI. 1975-1978. An Engineering Report on the Lurgi Retorting
Process for Oil Shale. U.S. Environmental Protection Agency Contract
No. EPA-68-Q2-1881.
Uhl, V.W. June 1979. A Standard Procedure for Cost Analysis of Pollution
Control Operations: Vol. II, Appendices. EPA-600/8-79-018b. U.S. En-
vironmental Protection Agency.
U.S. Department of the Interior, Bureau of Mines. August 1981. Minerals and
Materials: A Monthly Survey. Washington, D.C.
U.S. Department of the Interior, Minerals Management Service. July 29, 1982.
Notice of Suspension of Operations and Production and Minimum Royalty;
granted to Rio Blanco Oil Shale Company.
U.S. Environmental Protection Agency. September 1980. Lining of Waste
Impoundment and Disposal Facilities. Report No. SW-870.
338
-------
U.S. Environmental Protection Agency. 1980, Environmental Perspective on
the Emerging Oil Shale Industry. EPA-600/2-80-205a.
U.S.S, Engineers and Consultants, Inc. April 1978. Communication with Water
Purification Associates, Cambridge, Massachusetts, regarding information
en the Phosam-W process.
x
Water Purification Associates. December 1975. Innovative Technologies for
Water Pollution Abatement. NCWQ 75/13. National Committee on Water
Quality, Washington, D.C.
Wilheinri, A.R. and P.V. Knopp. August 1979. Wet A1r Oxidation: An Alterna-
tive to Incineration. Chemical Engineering Progress. 75(8):46-52.
Woodward-Clyde Consultants. October 13, 198Q. Preliminary Laboratory
Testing, Lurgi-Ruhrgas Retorted Shale. For Occidental Oil Shale, Inc.,
Grand Junction, Colorado.
York, E.O. June 13, 1980. Rio Blanco Oil Shale Company. Correspondence
with Denver Research Institute, Denver, Colorado, regarding information
on the Lurgi retorting process.
-------