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                                - 162 -
 low boiling materials into the system will appear as  an emission  from the
 vacuum pump, so the pollution control system (e.g. .incinerator),  must be
 designed to accommodate surges such as those caused by upsets.  Emulsions can also
 occur in the overhead recovery system of vacuum units and  may require provision
 for storage and reworking.

           Filtration is the other method used to remove solids  from the heavy
 liquid,  if a vacuum filter is used, the above comments are  applicable.  An
 alternative is pressure filtration in which case leaks and spills can be a
 problem.  Filtration is a difficult operation,  complicated by the fact that
 removing filter cake is necessary.   Filtration involves solid,  liquid, and
 gas streams all of which can contribute to emissions, including transient
 ones.  With rotary filters a cake is scraped off,  which may  be  pasty, hard
 to handle, and contribute to plugging difficulties.   If plugging  occurs,
 operation may be interrupted to open up equipment  and wash it out.   Special
 cleanup and collection facilities should be available for  this.  Often a
 precoat is used and can introduce additional emission problems  in its storage
 and handling, application, and removal to disposal.

     8.4.7  Shift and Cooling

           The shift reactor may be a fixed bed of  iron based or cobalt-
 molybdenum catalyst.  During operation it might become partially  plugged''
 by dust, in which case efforts may be made to clear it by  steaming or
 backblowing.  Emissions would not be expected since the flowing streams
 will be contained and handled in the gas cleanup system.   If the  shift
 reactor must be opened for servicing,  then transient  emissions  of  the
 catalyst or deposits might occur.  Emissions of dust,  sulfur compounds,
 or iron carbonyl from iron type catalysts should be considered  and pro-
 tection provided as needed.  Trace elements such as arsenic,  lead, etc.
 may very likely build up on the shift  catalyst  and in this general area
 of the plant,  requiring special protective measures.   However,  sufficient
 data on the subject are not yet available to allow defining  the situation
 and methods for environmental control.  Charging,  replacing, and  discharging
 catalyst especially call for dust control.   Spent  catalyst should be returned
 for reworking 6c .'disposed of in a way to avoid  transient pollution from
 dust or leaching.

           Gas  cooling and scrubbing  is  the  next operation, typically using
 a  waste  heat boiler followed by heat exchangers and a scrubber.   The boiler
 and exchangers may develop leaks due to  erosion or corrosion, causing emis-
 sions  directly or  indirectly.   Protective measures include careful design,
 monitoring and inspection,  preventive  maintenance, plus  employee  training
 and education.

           Scrubbing to remove dust  is  a  critical operation to avoid  problems
 downstream.  An upset may result if  water circulation is lost for any reason
 such as  pump or motor failure.   Attendant overheating or over-pressuring
may lead  to  additional upsets.   Deposits can occur, requiring extensive
 flushing  of  dirty water to sewers or storage.  Transient emissions of gases,
 liquids,  and solids can be controlled  by prior consideration and  planning,
 including  appropriate sparing of critical pumps and other  items.   Provision
 could be made  for example to automatically  divert  any severely  contaminated
water  (as  could  result  from a tube failure)  directly  to waste water  treating.

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                               - 163 -
     8.4.8  Acid Gas Removal

          One of the transient emissions on a  coal  conversion plant that  is
of greatest environmental concern  is from the  acid  gas  removal  in case of
upset.  If it gives inadequate cleanup for any reason,  gas product can
not be used and will have to be diverted to a  flare since sizeable storage
or a complete backup system is hardly practical.  The flare  should be designed
for efficient combustion, smokeless operation,  and  noise control.  Sulfur
emission could be very high from the flare until  the difficulties are cor-
rected or operation is cut back to avoid diverting  to the flare.  Typical
flow rate (Figure 8.1) to acid gas removal is  32 MM scfh containing
380 tons/day sulfur, that potentially would be flared if all of the gas
had to be diverted to a flare.  One proposed design has 2 trains of acid
gas removal each sized for 75% of  the total flow, which would require
diverting 25% of the total flow in case one train shutdown, assuming that
the other train could be quickly brought up to its  full capacity.  Depending
on the type of upset, partial sulfur removal might  be maintained thereby
decreasing emissions, but clearly, very thorough and careful planning and
operation are required to minimize this large  potential source of transient
emissions.

          A second major concern is possible contamination of the CC>2 vent
gas rejected to the atmosphere.  It is a very  large stream, and many acid
gas removal systems have difficulty in achieving a  satisfactorily low sulfur
level in the rejected CC>2.  Therefore, upsets  are liable to cause a temporary
increase in sulfur level that could be very objectionable.  It is not certain
that the waste C02 stream will always be incinerated before release,  since it
is so large a stream that incineration would consume considerable additional
fuel; however, incineration is one available control method to oxidize sulfur
compounds, combustibles, and other contaminants.

          Entrainment of scrubbing liquid into the  C02  vent stream is another
possible source of contamination,  especially if there are upsets and surges
in flow or pressure.  Incineration, if used, may take care of this -- or
consideration can be given to use of entrainment separation devices for
protection.

          The circulating chemical or solution used for absorption is often
filtered to remove solids that tend to accumulate and could cause fouling
or other problems.  The filters are cleaned periodically and the waste
material must be disposed of (78).  In addition, cyclic interruptions
associated with filter cleaning may cause upsets or result in emissions or
leaks of gas or liquid.  Operating procedures  should be defined to minimize
all transient emissions.  The waste solids may represent residual coal
ash carried along with the acid gases, or there can be  rust  particles or
degradation products.  Washing or  incineration may  be needed before disposal,
depending upon its exact nature.

          All processes for acid gas removal have chemical losses or
chemical purge streams to dispose of as a result of leaks, vapor pressure,
side reactions, degradation caused by contaminants,  etc.  Makeup chemicals
are required, possibly amounting to 1.6 tons/day in the case of Rectisol
methanol scrubbing (79) or 150 gallons/day for a Benfield hot potassium
carbonate system (80).  Other chemicals are often added as activators or
to combat corrosion, fouling, or foaming (81).

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                                   - 164  -
           It should be clearly recognized that all chemicals used by the  plant
 must be accounted for, generally showing up as effluents,  in which case
 effective and adequate environmental controls or disposal  should  be provided
 as necessary.  Upset could result in unexpected contamination or  degradation
 of the scrubbing medium,  such that it may have to be purged and replaced.
 Storage should be available for purge materials so that  they can  be retained
 for reclaimation or ultimate disposal.  Of course, storage is also needed  for
 the normal chemical solution inventory to use when the system is  shut down or
 emptied for any reason.

           An area of great uncertainty is the fate of trace elements (As,  Cd,
 Se, Cl, F, etc.) in the gas cleanup facilities.  Some may  pass through the gas
 scrubber into acid.gas removal where they may deposit, react with the solution,
 or otherwise accumulate and have to be removed as transient effluents. More
 information is needed to define the problem.

           Following acid gas removal, final traces of sulfur are  removed  by a
 guard bed of zinc oxide in order to protect the methanation catalyst. It  is
 estimated that the zinc oxide will be replaced every 3 to  6 months.  Fixed
 bed reactors are used, requiring depressuring and purging  with nitrogen or
 inert gas for catalyst replacement or maintenance.  These  vent streams should
 be collected and returned to the system or sent to blowdown facilities for
 disposal.  The spent zinc oxide cannot be regenerated easily but  can be returned
 to a manufacturer for reworking.  The total sulfur removed by the guard is only
 a small fraction of a percent of the total sulfur contained in the coal feed
 since most ot it has been removed previously.   Adequate  dust  control  should
 be provided during dumping and recharging of zinc oxide  and  other materials
 used in the guard system.   Experience shows that  loading and  unloading of
 catalyst or solids handling can cause a dust nuisance, which  may require
 shields,  hoods,  and a collection system with cleanup.  There  also may be
 unappreciated health effects.

      8.4.9  Methanation,  Compression
            and  Drying	

          At  this point in the process  the streams are very  clean with
 regard to sulfur and dust  but  the high  operating  pressure  can lead  to
 leaks.  Prior to methanation the gases  contain  considerable CO which  is
 toxic,  so monitoring the process area and other precautions may be  needed
 for  protection.   There is  also a possibility of forming  highly toxic
 nickel carbonyl  as mentioned earlier,  if upset  conditions  lead to  a
 catalyst  temperature,  below 400°F for  example.  Startup  of  the methanation
 reactor generally involves  pretreatment  operation which  can  cause  tran-
 sient  releases as discussed in Section 8.2  on startup, while  Section  8.3
 covers considerations  related  to shutdown of  the  facilities.

          The large  heat release  of the methanation reaction  is used  to
make steam by recirculating  gas  through waste heat boilers.   Pressure on
 the gas side is usually higher  than the pressure  of steam  generated;
consequently any  leakage in  the  exchanger will  add gas to  the steam
system rather than vice versa.   This  gas  leakage  must  then be removed
from the steam, and  shows up as  purge gas on steam condensers.  For

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                              - 165 -


 example when the steam is used to drive a condensing turbine,  there
 is  also a vacuum pump  to remove non-condensible gases from the steam
 condenser.   The latter gases are pumped for release to the atmosphere,
 some times without cleanup or incineration.  Clearly, such purges of
 "non-condensible" gases can constitute undesirable emissions and should
 be  reviewed  to  see whether incineration or some other cleanup  is needed.
 Certainly in the case  of tube failure a considerable amount of carbon
 monoxide  and other combustible gases could get into the steam system
 from which  they would  be rejected to the atmosphere.

          Methanation  forms water which is recovered and used  for makeup.
 As  shown  in  Figures 8.1 and 8.2 for SNG manufacture, this can  amount to
 about 3000  tons/day.   It is clean condensate, although dissolved gases
 will be released when  it is depressured so these gases should  be collected
 and may be  sent to the fuel system.  The gas still contains moisture which
 must be removed to meet pipeline specifications.  Glycol drying is commonly
 used, although  other liquid or solid dessicants may be used instead.
 The dessicant is regenerated by stripping or heating, releasing water vapor
 which may be vented to the atmosphere.  If upsets occur, there is a
 possibility  that glycol (or other dessicant)  might also be  released  to
 the atmosphere,  so environmental protection should be considered.

          A  booster compressor is sometimes needed to raise the product
 gas to  pipeline pressure.   Leaks and  failures on this equipment could
 cause inadvertent releases of combustible gas,  or of steam  in  the  event
 that steam turbine drives are used.   Final cooling of the gas  by cooling
 water or  air cooling may be used, in  which case leaks could introduce
 combustible  gas into the cooling water system and cooling tower,  or
 directly  to  the atmosphere.

          Starting up  and pretreating of  the methanation catalyst  have
 already been discussed.   Upsets  during operation of  the unit may require
 repeating the pretreat operation,  or  even replacing  the catalyst, with
 associated environmental concerns as  described.

      8.4.10  Sulfur Plant

          The sulfur recovery plant is vital,  in that without  it, opera-
 tion of the  coal conversion plant must be interrupted.   As  shown in Figure
 8.1 and 8.2  about 2500-5000 tpd  of sulfur containing gases  are  fed to the
 Glaus plant,  including  perhaps 400 tpd of sulfur of  which roughly  99% is
 probably  recovered.  For reliability,  the sulfur plant  consist  of multiple
 units with excess combined capacity.   Thus,  some designs include 3 units
 each having  50%  of  base  capacity,  or  two  units  of 75% capacity each.  Since
 it  is not possible to  startup a  sulfur plant  instantaneously they must
 all be on stream all of  the time,  but running at part load.  Then  sudden
 changes in feed  gas rate can  be  accomodated  quickly.

          Changes  in composition  of the feed  gas can also cause upsets
 on  the sulfur plant.  It depends  upon combustion of  the  proper  fraction
 of feed gas  to give the  stoichiometric amount of S02  to  just react com-
pletely with H2S  in the  part  that  bypasses combustion.   Hence  any  change

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                               - 166 -
 that affects combustion air requirement can cause an upset.  Change in
 content of  the feed gas could be one factor, while a sudden change in the
 content of  hydrocarbons is another.  Loss of flame, or an unstable flame,
 would disrupt the sulfur recovery operation.

          Upsets, for example excessive hydrocarbons, can throw the
 product sulfur off specification, such that it cannot be sold.  If this
 happens the sulfur must be stored until it can be disposed of.  Possibly
 it could be worked off by feeding through the sulfur plant feed gas
 incinerator after steady operation has been resumed.

          The sulfur pit is a potential source of obnoxious odors, and
 even fires.  H^S is rather soluble in molten sulfur and could be released.
 Standard procedures and operating techniques are available from suppliers
 and should  be reviewed to be sure that environmental controls are sat-
 isfactory.

          The sulfur plant will usually include tail gas cleanup, using
 one of the  various processes offered.  Gas volume is the same as in the
 Glaus plant, or larger, while the sulfur entering tail gas cleanup will
 be perhaps  5% of that to the Glaus plant.  Upsets on the sulfur plant
 can also upset the tail gas cleanup of course, and in addition it is
 subject to  its own upsets.  Scrubbing is usually used, introducing the
 possibility of deactivating or contaminating the solution such that it
 must be removed and replaced.  All chemical purges gould be sent to
 storage from which they can be cleaned up for reuse or otherwise disposed
 of in an acceptable manner.

          Solids may have to be disposed of periodically.  Catalyst used
 in the Glaus reaction has an estimated life of 3-5 years (82) after which
 it is discarded.  There may also be other solids resulting from cleanout,
 general maintenance, or salt deposits etc., that must be disposed of
 without excessive pollution.

     8.4.11 Oxygen Plant

          As in the case of primary emissions the oxygen plant is relatively
 clean; no major transient emissions are likely.  The major potentially
 adverse impact of the oxygen plant would be in the event of an unexpected
 shutdown that would upset the gasification part of the plant.  Fortunately
 the service factor on oxygen production is high and the likelihood of
 upsets is small, although this might be offset if only one train is used
 for oxygen  production.  Liquid oxygen storage equivalent to say 8 hours
 requirement is often provided to assure smooth operations.

          Oxygen consumption for gasification is typically about 5000-
 6000 tons/day, giving a waste nitrogen stream of 15,000 to 20,000
 tons/day that will be returned to the atmosphere.  Transient emissions
such as defrosting of exchangers, etc., should not present environmental
problems.

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                               - 167 -
     8.4.12  Solids  Disposal

           For  the large gasification plants being considered,  ash from
 the gasifier to  be  disposed of may be 1000 tons/day on bituminous coal,
 or  perhaps 3000  tons/day when feeding lignite.  In addition,  ash from
 coal used in the utility boiler and for plant fuel can add about 200-
 500 tons/day.  Handling losses amounting to a fraction of 1%  could be
 excessive.   Spills, dusting, accumulation in tanks and ponds,  etc. could
 total  1000 tons/year,  so a program of cleanup and disposal should be part
 of  the planning.  Ash  quenching can generate odors that may have to be
 contained,  for example, calcium sulfide in the ash tends to react with
 moisture and C02 in the atmosphere to release H2S.  Also, if  not contained,
 quenching could  release clouds of steam, particularly if upsets result in
 insufficient quench water, amounting to an estimated 15 MM scfd of steam.

           Leaching  of  ash, refuse from coal cleaning, sludge  and other
 solid  wastes could  cause transient releases, for example in case of a
 storm  or due to  a spring thaw.  Overflow or draining of retention ponds
 could  give large temporary effluents.  Other upsets might discharge sour
 water  (amounting to 16,000 tons/day for example) if waste water treating
 is  disrupted.  Even though the water may have been processed  in the sour
 water  stripper it will have a strong odor and could contain large amounts
 of  soluble salts, such as ammonium chloride.

           Filter cake  may be an oily waste from liquefaction  processes.
 Usually it can be disposed of by gasification or incineration,  but in
 case of upsets it may  present a disposal problem.  The slurry to be
 filtered is made up of very heavy oil or tar, so if it cools  off or
 is  spilled a difficult cleanup situation is faced.  Again, satisfactory
 plans  must be  developed ahead of time.  Oily waste from tank  cleanings
 etc. presents  somewhat similar problems, and fluid bed incineration would
 appear to be one good  approach.

     8.4.13  Water Treating

           In general,  the water systems on a plant will include process
 and sour water cleanup, a cooling water circuit, makeup water treating,
 collection of  storm runoff, and a recirculating water system  for coal
 cleaning where this step is included.  Facilities can include ponds,
.an  oil  separator, cooling  tower,  exchangers,  pumps,  etc.  all of which
 are  subject  to upsets  in more  ways  than can be predicted,  resulting  in the
 release of transients.   Chemicals are used in most of the water  systems,
 such as chlorine, chromates, sulfuric acid,  and caustic;  consequently,
 they may appear as  transient effluents,  especially during operating  upsets.

          It is sometimes  proposed  to add  treated sanitary waste  to  the
 cooling tower as makeup, although fouling  problems may be thereby aggravated.
 In a typical design  this could contribute  10-15% of total makeup  water
 to the plant; however,  the drift  loss and  spray from the  cooling  tower
 should be considered in  that contamination could result,  at least at times.

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                              - 168 -
 One pertinent study showed significant  entrainment  of water  containing
 microorganisms when air was passed  through  a  simulated  cooling  tower  (83),
 suggesting that extensive pretreatment  of sanitary  waste may be needed
 if such use is contemplated.   In some cases effluent from  a  municipal
 sewage treating plant has been used for industrial  plant makeup water,
 so progress has been made in solving the attendant  problems  (84).
 However, the environmental factors  may  not  have been adequately addressed.


           The various water systems in  the  plant  are closely interrelated,
 and an upset in one can affect the  others to  cause  transient effluents.
 Thus,  sour water is usually cleaned up  to reuse as  cooling tower makeup,
 so failure of the stripper could allow  excessive  amounts of  l^S, NH3,
 etc.  to be introduced to the  cooling tower, causing serious  emissions.
 Instrumentation to monitor the quality  of makeup  water  going to the cooling
 water  system may give the desired protection, with  provision for diverting
 unsatisfactory water to  covered  storage.  The water systems are discussed
 below  with respect  to  transient  emissions, covering the areas:   waste
 water  treatment,  cooling water system, and makeup water treating.

           Waste Water Treatment

           The usual steps in  industrial waste water treatment are:

           -  solids separation
           -  extraction of phenols
           -  sour water stripping
           -  oil removal
           -  biological oxidation
           -  filtration
           -  activated carbon if needed

 All of these could contribute occasional or inadvertent emissions.
 Residual ash and solids scrubbed from the gas are separated  in  a clarifier
 or filter for disposal.   Mai-operation  may  increase the amount  of  solids
 (e.g., plugging of dipleg on  cyclone separator downstream  of gasifier)
 and result in overloading or  plugging of the  solids separation  facilities
 in waste water treatment.   These solids may have  to be  flushed  to  storage,
 possibly to a pond if there is no problem due to  odors  or  vapors.  However,
 there  is also a question on trace elements  since  many are  appreciably
 volatile in gasification.   Some, such as fumes of arsenic  or lead  may
 appear in the scrubbing water,  or be associated with the ash fines and
 be susceptible to leaching when the ash is  diposed  of.  The  large  amounts
 of trace elements that might  be carried out of the  gasifier  with the  raw
 gas are defined in the individual process reports.  Spills of wet  ash could
 lead to a dust nuisance when  they dry out,  and, therefore  should be cleaned
 up promptly.

           Extraction of  phenols  is  the  next step  in waste  water treatment
except  for  those  processes that  do  not  make substantial amounts of phenols.
Solubility  of  cresols  and  phenols in water  may be 2-8 wt.  %, and both
low temperature  gasification  and liquefaction form  considerable amounts
of them.  For  example  a  design using Lurgi  gasifiers shows 120  tons/day

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                             - 169 -
 of  crude  phenols  produced.   If an upset in the extraction plant results
 in  an  abnormally  high phenol content in the water going to biological
 oxidation,  there  could be a similar surge in phenol content of the water
 effluent  which might then contaminate sources of drinking water.   A level
 of  only  .001 mg/1 causes  objectionable taste,  while even .0001 mg/1 leads
 to  off-flavor  in  fish (85).  Chemicals used for extraction of  phenol may
 also contribute to transient emissions.

          Sour  water stripping to remove NH3 and H~S from the  waste water
 is  a vital  part of water  treatment,  and any departure from its normal
 performance could disrupt or overload subsequent water treating operations.
 Stripping is subject to the usual types of equipment failures,  or  to
 interruption of electrical power  or steam, but is also liable  to plugging
 of  critical exchangers due to salts such as ammonium carbonate, etc.
 Furthermore, changes in the feed  stream could decrease cleanup efficiency
 temporarily.   In  some large plant design studies it has  been considered
 desirable to include 100% spare facilities for sour  water  stripping.
 that  is,  two  independent  trains each of which can handle the full  design
 flow rate (86).

          If sour water stripping were ineffective for some reason, such
 as  steam  failure, then the effluent could approach feed  water  composition.
 As  reported for the  Synthane process (4),  sour water from the  gasification
 typically may  contain 5,000-11,000 mg/1 of phenol.   Because of  the  high
 level  of  contaminants it  appears  prudent to provide some closed storage
 for sour  water  to handle  any surges in feed,  or to  temporarily  retain off-
 specification water  leaving the stripper so that it  can  be reprocessed
 and not allowed to become a transient effluent.   Flow rate of  sour  water
 may be 16,000  tons/day (see Figure 8.1) which is very large, but storage
 equivalent  to  several hours to 1  day should be feasible,  and useful during
 startup or  shutdown  of the plant.

          It will be seen that there is a definite  possibility of  con-
 taminated water being released to holding ponds in  the water treatment
 system, giving  rise  to strong odors or evaporation  of oil and  other
 compounds.  Therefore,  the  operations should be followed closely to
 protect against serious emissions from ponds or other areas, using
 continuous  monitoring instruments where appropriate.  Ammonia  is often
 recovered as a  byproduct  and could contribute to emissions, but these
 can be controlled using facilities and operating procedures that are well
 established.

          After sour water  stripping  the waste water is  processed  to
separate oil,  using  for example an API separator followed  by froth  flota-
tion.   At times, oil vapors  and other  contaminants  can be  released,  e.g.,
on hot windy days or  if the  water entering becomes  too warm.   A common
practice now is to cover  or  enclose  these  facilities to  control emissions.

          Since biological  oxidation  is generally depended upon to  clean
up many minor contaminants  in waste water,  any upset could result  in
transient releases.  Changes in entering composition,  concentration,
temperature, etc., are known to be detrimental (37)  so some surge
capacity is  often provided  on  the feed to  help maintain  uniform conditions,

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                               -  170 -
A proper balance of nutrients is needed for reasonably completed con-
sumption of all components, and in some cases specific nutrients such as
phosphate have to be added to balance high nitrogen entering.  Careful
monitoring and control may be needed (88).

          The bioculture can be inhibited or killed by poisons such as
chlorine and chromates which are frequently added to the cooling water
circuit to control biofouling and corrosion, again introducing potential
for upsets.  The bioculture is associated with "activated sludge" retained
in the biox system, and if it dies due to lack of food or from poisons
the system can easily become anaerobic and generate very obnoxious sulfur
and other type odors.  Education and training of personnel plus close
attention to operations is perhaps the best practical answer.  A holding
pond  following biox is also desirable, and protects against suspended
solids in the effluent in the event that the activated sludge becomes
difficult to separate for recycle.  Disposal of sludge requires attention
as discussed in Section 8.4.12.

          Sometimes a separate filtration step is included to remove
particulates or any residue of sludge which would contribute BOD.  Sand
filters may be used, with periodic back flushing to return the solids
to waste water treating, to incineration or to other disposal so as to
control emissions.  Activated carbon may be used for final polishing,
in which case it is regenerated intermittently by stripping with hot
combustion gases.  This regeneration gas effluent should then be
incinerated, of course, to destroy desorbed materials and any carbon
dust.

          Other possible transient sources of waste water to consider
will  include storm runoff.  Initially, say during the first hour of a
storm, most of the oil and dirt may be washed from the area giving
contaminated water.  Subsequent runoff should be relatively clean and
useful as makeup without extensive treatment.

          Pretreating of the coal to destroy caking properties is used in
some  operations, and can result in considerable sour water to be treated
as mentioned in Section 8.4.3.  Also coal cleaning to decrease ash and
pyrites may be included at the coal conversion location, in which case
there is an additional large water stream to be treated.  Most of the
water is cleaned up for reuse in washing, screening, or other operations,
but after settling and clarifying the water, it still contains very fine
particulates which are removed in a settling pond.  Leaching is also of
concern in coal cleaning operations and on ash from conversion or furnaces.
These few examples will illustrate the broad approach that is needed in
considering environmental controls on waste water cleanup.

          Certain other items in water treating should be commented  on
particularly those operations where chemicals are consumed.  An  example
of typxcal consumption of chemicals for a projected easlf1r«Mrtn „!„  I
is given in Table 8.5.  In treating makeupVter'1^1^ abused
to precipitate hardneness, while sulfuric acid, caustic, and salt may be

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                                - 171 -
                               Table 8.5

                    Typical Catalyst and Chemicals
                 Consumption in a Liquefaction Process
                          (Based on Ref. 42)
                    Item
        Amount
Diatomaceous Earth Filter Precoat
Mono e thanolamine
Cellulose, Asbestors, and Diatomaceous Earth
Corrosion Inhibitor, A
Antifoam
Hydrogenation Catalyst
Sodium Hydroxide
Active Carbon
CO Shift Catalyst
Benfield Solution - K^CC^
                    DEA
                    V205
Methanator Catalyst
Zinc Oxide Pellets
BSRP CoMo Catalyst
Sulfur Recovery Catalyst
Stretford Solution Chemical Makeup
Corrosion Inhibitor, B
Polymer Dispersant
Sulfuric Acid
Chlorine
Phosphate Polymer Antifoam
Hydrazine (oxygen scavenger)
Lime
Aluminum Sulfate
Caustic soda
20 tons/day
3750 to 12,600
22 to 110 Ih/day
3-1/4 to 6-1/2 gal/day
7-1/2 to 16 gal/day
255,700 Ib (3-yr life)
340 Ib/day
50 to 100 Ib/day
2399 ft3 (1-yr life)
986 Ib/month
99 Ib/month
17 Ib/month
140 ft3 (3-yr life)
71 ft3 (3-yr life)
750 ft3 (3-yr life)
5200 (3-yr life)
$386/day
319 Ib/day
319 Ib/day
3209 Ib/day
1766 Ib/day
383 Ib/day
2.7 Ib/day
2072 Ib/day
1295 Ib/day
2135 Ib/day

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                             - 172 -
 consumed in regenerating ion exchange  resins used  to  demineralize boiler
 feed water.   The  operations  are  often  cyclic,  generating  intermittent
 effluents;  moreover,  the storage and handling  of the  chemicals  and
 effluents could cause transient  emissions  unless care and planning
 are adequate.   Chemical cleaning of exchangers and equipment  is another
 source of wastes  (89).   As in the case of  barge washing (90), washing out
 storage tanks adds more water to be cleaned up.

      8.4.14  Steam and  Power Supply

           A coal  conversion  plant requires steam and  electric power which
 are usually supplied  from a  utilities  section  of the  plant although there
 may be an emergency power tie-in with  an outside supply.  Fuel  used for
 making steam may  be clean low Btu gas  made from coal,  or  the  coal may be
 burned directly and stack gas cleanup  used to  control pollution.  In the
 first case many of the  concerns  on transient emissions are transferred to
 the gasification  operation which manufactures  the  low Btu gas.   The second
 case combines the concerns of a  coal fired boiler  plus stack  gas cleanup.

           Combustion  of coal necessarily produces  ash refuse  which calls
 for protection against  transient emissions.  Great care is needed in
 handling, storage and disposal to control  dust, odors, or contribution
 of suspended solids in water streams.  Leaching of trace  elements from
 the ash is also of concern,  and  while  some work has been  done in this
 area (91),  a great deal more is  needed as  has  been pointed out  earlier
 in this report.

           Ash causes  fouling of  heat transfer  surfaces in coal  fired
 boilers,  and cleaning is accomplished  by "soot blowing" using a high
 velocity steam jet to blow deposits off the tubes.  Soot  blowing is
 done on stream, without interrupting the operation, consequently the
 disloged dust is  dispersed in the flowing  gas  and  carried down  stream
 where it appears  as a surge  in dust content (92).   The gas is usually
 passed through an electrostatic  precipitator,  which gives reasonably
 good cleanup of dust.   Incidentally, the dust  from soot blowing would
 be expected  to have an  unusually high  content  of relatively volatile
 and toxic  trace elements.  Where stack gas scrubbing  is used  for cleanup,
 backup dust  control is  thereby provided.

           In an electrostatic precipitator the dust deposits  on collection
 plates which are  cleaned periodically  by rapping (e.g., 2-10  minute cycles).
 While most  of  the dislodged  dust falls into a  hopper  and  is recovered,
 there is  some increase  in dust loss due to rapping.  Consideration has
 been given to  the interaction between  soot blowing cycles, rapping cycles,
 etc.  on dust loss (92).   (This reference also  presents operating experience
 on  a  large power plant.)  In the past, occasions have arisen  where parti-
 culates formed loose  deposits in a stack,  accumulated sulfuric  acid and
 other  contaminants, and  then sometimes became  dislodged,  to blow out
 through the  stack and fall in nearby areas as  smut.   The  situation can
and should be prevented.  The explanation  of deposition is related to
condensation on the walls due to cooling.  Dew point  of flue  gases is
raised very considerably  over the water dew point  by  the  presence of

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                                 - 173 -
only minor amounts  of  SO^ which forms  sulfuric acid.   This  phenomenon
is well known in  connection with corrosion of heat exchangers  used for
low temperature heat recovery  on furnaces and boilers.  Acid dew points
of 320°F are common for  flue gases from high sulfur fuels,  whereas the
dew point predicted from water vapor content alone may be only 120-130°F.
In the stack, wall  temperatures  are  cooler  than the flue  gases due  to
heat loss so significant condensation  can result,  for  example  in  the
range of 200-300°F.  Furthermore,  the  concentration of sulfuric acid in
the condensed liquid is surprisingly high.  At a dew point of 200°F the
equilibrium concentration of sulfuric  acid  is 65%, while  at 300°F it is
83% for typical flue gases.  A solution to  the problem is simply  to pre-
vent possible condensation  by  maintaining all  surface  temperature above
the acid dew point, using adequate insulation  or other means.

          Tube failure in the  furnace  can upset combustion  and give severe
smoke and dust in the  furnace  effluent.   One possible  approach is
to be prepared to isolate and  shut off the section of  tubes  involved as
fast as possible.

          Stack gas cleanup is perhaps the most critical  part  of  the
utilities system  with  regard to  potential transient emission of pollutants,
especially of dust, smoke,  and sulfur.   If it  fails to operate properly
for any reason, emissions become excessive and  the boiler may  have  to
be shut down unless a  clean fuel can be substituted immediately.  Perhaps
a standby system  to fire oil fuel could be used, and it would  also be
useful for startups.  Otherwise,  parallel trains might be considered with
stack gas cleanup facilities,  which may be convenient  when  the design
provides, for example 3 boilers,  each  with  a stack gas cleanup system and
each supplying 50%  of design requirement and all three intended to be
operating at all  times.

          Stack gas cleanup often involves the use of  chemicals,  and
usually with a sizeable  consumption  of them.   Moreover it necessarily
generates byproduct sulfur  or  sulfur compounds such as H^S  or  gypsum.
Again, there are  concerns about inadvertent handling losses on chemicals,
as well as possible intermittent purges of solution needed  to  maintain
scrubbing capacity.  Plans  are needed  for containing and  disposing  of
such materials.   Incineration  of  these materials may be an  acceptable
means of disposal.

          One comment on boilers  that  may affect transients is that some
state codes require that boilers  be  shut down for  inspection at stated
intervals.  Thus, the quantity of  transients is increased.

          Electric power for the  plant  will usually be supplied from a
generator driven by a condensing  steam turbine.  Heat  from  the condenser
is dissipated to  cooling water or  by air cooling.  As  mentioned earlier,
vacuum on the condenser (of 2-4  in. mercury absolute)  is  maintained by a
pump that removes non-condensible  gases  and rejects them  to the atmosphere.
Thus,  any gases that get into  the  steam system can become emissions at
this point and may require  controls.

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                                 - 174 -
          It should be emphasized that extremely high reliability is
needed on the power supply, since without it the plant will have to
shutdown and may have serious transient emissions.  One example is loss of
power on an electrostatic precipitator.  Extra efforts should be made to
protect against interruption of electric supply to essential facilities,
by using tie-ins to other sources, emergency generators, spares driven
by steam turbines, etc.

8.5  Maintenance

          Maintenance on the plant covers repairs, cleaning, additions,
and general servicing of facilities.  There are several categories of
work including unscheduled or emergency repairs due to failure of pumps,
heat transfer surfaces, etc.  A second category is routine maintenance
during  turnarounds to inspect and recondition equipment as needed.  A
third type of maintenance is "preventive," such as scheduled servicing
of seals, pumps, exchangers, etc. to replace worn parts and prevent upsets
or leaks before they occur.  This is somewhat like the normal oil-change
or tune-up on an automobile.  In a fourth group is "predictive" maintenance
which is now becoming possible as a result of progress and sophistication
in instrumentation and computer applications (93).  It will be seen that
the degree of concern on transient emissions is very directly related to
the overall philosophy and planning on maintenance.  Environmental aspects
improve as the maintenance program proceeds in the direction of the third
and fourth categories discussed above.

          Before general maintenance is started on equipment, the plant will
have been depressured and purged.  Liquid and solids inventories will have
been removed to the extent possible and sent to storage.  Opening the equip-
ment at this point should not cause serious emissions, although spills can
be expected and will need to be cleaned up.  Some parts of the system will
then be flushed with oil or water to remove tar, sour water, dust, etc.
The liquid used for washing should be contained and cleaned up, while the
contaminants in it should be separated for disposal.

           Cleaning  is  a  necessary part  of  the procedure  to  remove  solids
deposits  in vessels, piping, heat exchanger and  the  like.   One method
of cleaning uses a blast of air,  containing sand  or  shot.   Other methods
use a high pressure water  jet,  or strong chemicals.  Regardless  of  the
method, precautions are needed  to avoid  transient releases  of  the  deposits
being removed, or the materials used in the cleaning operation.   In some
cases,  the presence of toxic trace  elements may  require  special  considera-
tion.  Many such elements  are partially volatile at  gasification conditions
(e.g., arsenic, lead,  cadmium etc.) and  are expected to  deposit  on sur-
faces downstream as the  gas is  cooled.  Protection of  personnel  is needed
in addition to plans for safe disposal of such trace elements.  Additionally,
consideration should be given to all chemicals and materials used  in
maintenance, as well as chemicals or residues that are used in the  plant
or that might remain in the unit at shutdown.  The latter may include
carcinogenic tar, chemical solutions in the acid  gas removal system and on
stack gas or Glaus plant tail gas cleanup, or sour water.   Plans  should
provide for collecting, storing, and disposing of  all  such  miscellaneous
wastes.

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                                   - 175 -
          During  the shutdown,  various catalysts used in the process  may
 be regenerated, screened  to remove fines,  or replaced.   Dusting and
 emissions need  to be controlled.   Also, catalyst (e.g.,  methanation)  or
 some  deposits may be pyrophoric,  requiring suitable precautions.  Noise
 during  a turnaround may be sufficient to be objectionable or even harmful,
 depending upon  the situation.   Truck traffic and the high level of activity
 can also cause  problems but can be allieviated by prior  consideration.

 8.6   Chemicals  and Catalyst Replacement

          As previously mentioned, various chemicals and catalysts are
 used  by the plant for  acid gas  removal or  other scrubbing systems and in
 water treating, etc.   In  addition, catalysts are used for shifting, as
 sulfur  guards,  in methanation,  the sulfur  plant, etc. All of these chemicals
 and catalysts require  environmentally sound storage and  handling as well
 as provision for  satisfactory disposal of  spent materials.  An illustration
 of chemicals consumed  in  coal conversion is shown in Table 8,5 for the  SRC
 process.

          Water gas shift catalyst may be  regenerated and screened at
 intervals to remove deposits and  fines which cause high  pressure drop in
 fixed beds.  It is estimated that the operation may take up to 5 days.
 The pyrophoric  potential  of this  catalyst  should be taken into account.
 Acid  gas removal  has a chemicals  makeup that is sometimes taken care  of
 by removing part  of the inventory and replacing it with  fresh solution.
 Disposal of the purge  will have to be tailored to the specific chemical
 composition.  In  some  cases it  can be completely destroyed by incineration,
 while in other  cases the  presence of heavy metals (vanadium)  or toxic
 elements  (arsenic) will complicate the situation.

          Replacement  of  zinc oxide guard  ahead of the methanator will  be
 needed  perhaps  2-3 times  a year,  at which  time the spent catalyst might be
 returned to a manufacturer for  reprocessing.   Methanation catalyst may  have
 a life  of a year  or more  but may  lose activity and have  to be replaced
 sooner.  Again, the catalyst may  be pyrophoric and in addition toxic  car-
 bonyls  may be present.  Standards for personnel protection may require
 respirators and other  suitable  precautions.

          In those plants that  include hydrotreating of  liquid products
 or byproducts,  the catalyst may be either  nickel based or cobalt-molybdenum.
 Precautions for working with these and other catalyst are available from
 various manufacturers  (66).

          Hydrogen manufacture  is needed in the liquefaction processes,
 and uses process  steps  very similar to gasification to make SNG,  although
 the shifting and  acid gas removal are intensified.   Transient considerations
 are similar to  those described  for gasification.   In addition,  soot may be
 formed if partial oxidation of  solids  or heavy oil  is used.   While this  is
normally recycled to gasification and  converted,  it  does  represent an
additional material that  could  lead  to  transient  emissions.

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                               - 176 -
           Water treating uses many chemicals that require precautions as
 covered briefly at the beginning of this section.  One other aspect should
 be mentioned, that is, the possible effect of corrosion of heat exchangers
 in cooling water services.  Surface area may easily exceed 100,000 sq.  ft.
 and at a modest corrosion rate of 1 mil/year, and with copper tubes this
 could introduce 5600 Ib/year of copper into the cooling water circuit.

 8.7  Storage of Products and Byproducts

           Storage and handling of liquids and solids are well known sources
 of transient emissions, for example in oil refining and chemicals manufacture
 these can be the largest single source of emissions (69) •  Suitable pre-
 cautions have been developed to control tank breathing and filling losses,
 as well as in product handling and shipping, and these are especially
 pertinent on coal liquefaction plants.  Similarly, precautions are avail-
 able for ammonia,  sulfur,  phenols and  specific  chemicals and  should be
 followed when applicable.   Storage of  molten sulfur,  for example,  intro-
 duces the possibility of H^S release or fires.

 8.8   Design Considerations

          Most  transient emissions  can be attributed  to  upsets, startup,
 shutdown, or  other interruptions;  therefore design features that improve
 reliability and  service factor will  generally be environmentally desirable.
 A basic  consideration  is the number  of  equipment trains  to use.  Gasifiers
 that  are currently in  commercial  use have a limited capacity, less  than
 1000  tons/day of coal,  so 30 units may be needed for  a large plant.  Service
 factors  may be  85-90%,  and provision is needed  to allow  shuting down any
 one  unit for  maintenance without  disrupting  the rest  of  the plant.
 Frequently  the  gasifiers will be  grouped  to  feed two  separate and
 independent trains of  gas  cleanup facilities.   Similarly,  parallel  trains
 are  used in other areas of  the  plant as illustrated  in Table 8.6.   For
 some  gasification and  liquefaction processes  under development  the  use of
 only  two reactors is projected  for a large plant  (94).

          The order of starting up and shutting down  individual sections of
 the process can affect emissions,  as discussed.   In general, stopping the
 flow  of  coal  and oxygen to  the gasifier will  be a  first  step at shutdown,
 while environmental controls such as acid gas removal and the sulfur plant
 will  be  the last to be shutdown,  along with  the utilities system.   Automatic
 shutdown of individual systems or pieces of  equipment will be provided by
 "fail-safe" instrumentation.  Again, preplanning  can  minimize adverse
 environmental effects  by assuring that proper facilities are available when
needed.

          Slowdown and vent  streams  can often be sent to a common
 collection system where any  condensible liquids will  be recovered.   The
remaining gas will be  incinerated,  or  where  appropriate, it  can be burned
 in a  furnace  to  recover heating value.   Streams released from pressure
relief valves can often be handled in  the  same  or  a  similar  system, as
well as vents from lock hoppers,  vacuum systems,  etc.

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                                - 177 -
                               Table 8.6
            Example of Number of Trains and Spares Proposed
            	for Large Scale Gasification Plant	
                  930 MM scfd of 215 Btu/scf gas from
                    10,000 tpd Illinois coal
                             (From Ref. 95)
                                                       Operating/Spare
Air Compression                                              4/1
Air Separation                                               4/0
Oxygen Compression                                           4/0
Gasification                                                 4/1
Particulate Removal and Gas Cooling
  Bulk Particulate Removal                                   4/1
  High Temperature Cooling                                   4/1
  Low Temperature Cooling                                    4/1
Acid Gas Removal                                             4/0
Expansion                                                    4/0
Power Generation                                             1/0
Sulfur Recovery                                              2/1
Tail Gas Treating                                            2/1
Water Treating                                               1/0
Cooling Water System                                         1/0
Process Condensate Treating                                  1/0

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                                - 178 -
          Consideration should be given to having a supply of low sulfur
 fuel  oil available for use as backup, in case of failures on cleanup sys-
 tems  used on  furnaces that normally burn dirty fuel.

          Mechanical seals on pumps, although more costly than simple
 packing, will minimize leaks.  Blowback of gas, oil, etc. through the
 seal  may also be used to prevent leakage, or a collection jacket could
 be  used.

          Areas of the plant where spills of oil, coal, ash, etc., are
 most  likely should be identified and probably should be confined by
 curbing or  wells so that any spills are contained and can be cleaned up.
 Vacuum cleanup truck and flushing facilities should be available where
 needed.  A  separate oily water system, such as those used in oil refineries
 usually should be provided.  Protection against vapor emissions at sewer
 connections and junction boxes is sometimes needed.  A separate storm sewer
 system and  retention pond can be used to recover clean water from rain run-
 off.   However, experience shows that the initial part of such run-off may
 be  oily and contaminated so it should be diverted to the oily water sewer.

          Protection against emissions from all storage and handling areas
 should be reviewed to be sure that it is adequate.  Storage for "off-
 specification" production should be available so that it can be recovered
 and used rather than sent to waste disposal.

          In  designing a plant it should be recognized that all chemicals
 and material  entering the plant must also leave in some form since they
 do  not simply disappear.  This includes dissolved solids in makeup water
 for example.  It also applies to trace elements entering with the feed
 coal,  some  of which may accumulate as deposits on equipment and have to
 be  removed  by cleaning.  Toxic elements such as arsenic, lead, etc., will
 require precautions and special consideration.  If there is major uncer-
 tainty as to  where the toxic elements will appear, and in what form, then
 it  necessarily follows that there must be a corresponding uncertainty as
 to  whether  environmental controls are adequate.

          Elements such as chlorine in the coal can form HC1 during gasi-
 fication or liquefaction which will appear in the downstream recovery
 system.  It is not clear in what form it will ultimately leave the system,
 or  whether  pH control will be needed.  One concern is that chlorides can
 cause  stress  corrosion cracking of alloy steels used for fabrication,
 resulting in  tube failure or leaks that would be environmentally undesirable.

          One of the most effective means for controlling transient emis-
sions  is  to guard against failures and to be ready for fast response if
 they do occur.  This calls for a thorough and effective program of monitoring
 inspection, and maintenance.  Likewise, an intensive and recurring program
 to  educate and train personnel can reduce losses, conserve resources, and
protect the environment.

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                                 -  179  -
                          9.  BIBLIOGRAPHY
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 (2)  Hall, H. J., Varga, G. M., Jr. and Magee, E. M., "Symposium
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                                 - 180 -
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                                 -  181  -
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                                  - 182 -
(45)  Schultz, Hyman, et al, "The Fate of Some Trace Elements During
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(51)  Forney, A. J., et al, "Trace Element and Major Component Balances
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      Center, Report No. PERC/TPR-75/1, August 1975.

(52)  Forney, A. J., et al, "Analyses of Tars, Chars, Gases, and Water
      Found in Effluents from the Synthane Process," Bureau of Mines
      Applications of Improved Technology to Provide Clean Energy Programs,
      Tech. Prog. Report 76, January 1974.

(53)  Kalfadelis, C. D., et al, "Evaluation of Pollution Control in Fossil
      Fuel Conversion Processes; Analytical Test Plan," EPA-650/2-74-009-1,
      October 1975.

(54)  "Char Oil Energy Development," Office of Coal Research, R&D Report
      No. 73 - Interim Report No. 2, GPO Cat. No. I63.10:73/Int. 2,
      July 1974.

(55)  Forney, A. J., et al, "Symposium Proceedings:  Environmental Aspects
      of Fuel Conversion Technology," St. Louis, Missouri, May 1974,
      EPA-650/2-74-118, p. 107, October 1974.

(56)  Communication from the Scottish Gas Board, Westfield Works,
      Cardenden, Fife, Scotland, November 1974.

C57)  Communication from the South African Coal, Oil, and Gas Corporation,
      Ltd. (SASOL), Sasolburg, S,outh Africa, November 1974.
                                ,":.;\.
(58)  Communication from Azot Sanayii, Kutahya, Turkey, November 1974.

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                                  - 183 -
(59)  Shultz, F. G. and Lewis, P. S., "Hot Sulfur Removal from Producer
      Gas," Paper presented at the 3rd International Conference on
      Fluidized Bed Combustion, Hueston Woods State Park, Ohio, October
      29-November 1, 1972.

(60)  Squires, A. M., "Cyclic Use of Calcined Dolomite to Desulfurized
      Fuels Undergoing Gasification," Paper No. 14 in "Fuel Gasifications,"
      Advances in Chemistry Series 69, ACS, Washington, B.C., 1967.

(61)  Moore, R. H., et al, "A Process for Cleaning and Removal of Sulfur
      Compounds from Low Btu Gases," R&D Report No. 100, Interim Report
      No. 1, by Pacific Northwest Laboratories, Division Battelle
      Memorial Institute, for Office of Coal Research, August 1974.

(62)  Colorado State University, "Water Pollution Potential of Spent Oil
      Shale Residues," for EPA, NTIS PB-206 808, December 1974.

(63)  Ricketts, T. S., "Operation of the Westfield Lurgi Plant", Journal
      of Inst. of Gas Eng., Oct. 1967, p. 563.

(64)  Goeke, E. K., "Chemical Age (India)," 25_ No. 5 pp. 301-305

(65)  Chemetron Corp., "Technical Data Sheets on Girdler Catalyst,"
      G521072 and G61RS1072.

(66)  Catalyst Regeneration Services Inc., "Hydrocarbon Processing,"
      Sept. 1975 p. 319.

(67)  Jones, H. R., "Pollution Control in the Petroleum Industry,
      ndc Manual 1973.

(68)  Vanderlinde, L. G., "Smokeless Flares," Hydrocarbon Processing
      Oct. 1974, pp. 99-104.

(69)  Congram, G. E., "Proper Maintenance Extends Pump Seal Life,"
      Oil Gas Journal, Nov. 10, 1975, pp. 186-188.

(70)  Colgate, J. L., Akers, D. J., and From, R. W., "Gob Pile Stabilization,"
      Reclamation, and Utilization," OCR R&D Report No. 75, 1973.

(71)  Lillis, E. J. and Young, D., "EPA Looks at Fugitive Emissions,"
      JAPCA 25_No. 10, pp. 1015-1018.

(72)  Story, M. J., "Proceedings of International Clean Air Conference,"
      Rotrua, New Zealand, Feb. 17-21, 1975.

(73)  Maze, R. W., "Air Cooler or Water Tower - Which for Heat Disposal?"
      Chemical Engineering, Jan. 6, 1975, pp. 106-114

(74)  Booz Allen and Hamilton Company study for EPA, "Pollution Control
      in Fossil Fuel Conversion Processes," No. 9075-015, March 1974.

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                                 - 184 -
(75)  Schora, F. C., "Analysis of the Hygas Coal Gasification Plant Design,"
      AIChE 65th Annual Meeting, New York City, Nov. 27-30, 1972.

(76)  Kavlic, V. J., Lee, B. S., "Coal Pretreatment in Fluidized Bed,"
      American Chemical Society, Division of Fuel Chemistry, Sept. 1966.

(77)  Patton, P. W. and Joyce, C. F., "How to Find the Lowest Cost Vacuum
      System," Chemical Engineering, Feb. 2, 1976.

(78)  "Clean Boiler Fuels from Coal," R&D Report 82 Interim Report No. 1
      Volume II (Figure 9), Prepared for OCR by Ralph M. Parsons Co.

(79)  "Gas Processing Handbook," Hydrocarbon Processing, April 1975,
      pp. 79-135.

(80)  McRea, D. H., "Benfield Activated Hot Potassium Carbonate Process,"
      EPA Symposium:  Environmental Aspects of Fuel Conversion Technology
      Hollywood, Florida, Dec. 15-18, 1975.

(81)  Heisler, L., and Weiss, H., "Experience with an Austrian Gas Plant,"
      Hydrocarbon Processing, May 1975, pp. 157-161.

(82)  Pearson, M. J., "Developments in Glaus Plant Catalysts," Hydrocarbon
      Processing, Feb. 1973, pp. 81-85.

(83)  Thibodeaux, L. J., and Carter, N. J., "Coliform Emissions from
      Air/Water Contractors," Recent Advances in Air Pollution Control,
      AIChE, 1974.

(84)  Donohue, J. M., and Nathan, C. C., "Unusual Problems in Cooling Water
      Treatment," Chem. Eng. Progress, ^JL No. 7 pp. 88-96.

(85)  "Cleaning Our Environment," ACS 1969, p. 148.

(86)  Detman, R., "Procedures for Pricing Synthetic Pipeline Gas from Coal,"
      Seventh Pipeline Gas Symposium, Chicago, 111., Oct. 27-29, 1975.

(87)  Workshop on Water Needs at University of Illinois, Oct. 20-22, 1974,
      Res. Rept. 93 dated Nov. 1974, p. 180 and reference 3.
  *

(88)  Kostenbader, P. D., and Flecksteiner, J. W., "Biological Oxidation
      of Coke Plant Weak Ammonia Liquor," Journal WPCF 4]^ No. 2 pp. 200-207.

(89)  Congram, G. E., "Trim Fuel Costs in Steam Generation," Oil Gas
      Journal, May 5, 1975, pp. 235-237.

(90)  Ball,  J., Adams, D. G., and Stryker, C. A., "Management of Tank
      Washings in Marine and Coastal Commerce," Texas A&M University,
      Report TAMU-SG-74-221, Feb. 1975.

(91)  Beckner, J. L., "Trace Element Composition and Disposal of Gasifier
      Ash,"  Seventh Synthetic Pipeline Gas Symposium  (AGA), Chicago,  111.
      Oct. 27-29, 1975.

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                                 - 185 -
(92)  Mills,  R.  A.,  and Tassicker,  0.  J.,  "Analysis of Pilot Plant
     Electrostatic  Precipitator Testing," International Clean Air
     Conference,  Rotorua,  New Zealand,  Feb.  17-21, 1975.

(93)  James,  R., and Block, H. P.,  "Predictive Maintenance System
     Improved at Exxon Chemical Plant," Oil  Gas Journal, Feb. 2,  1976,
     pp.  59-64.

(94)  Bolln,  J.  J.,  "Commercial Concept  Designs," Fifth Synthetic Pipeline
     Symposium, Chicago,  111., Oct.  29-31, 1973.

(95)  Fluor Engineers and  Constructors Inc.,  "Economics of Air vs. 02
     Pressure Gasification of Coal,"  EPRI239-1, Jan.  1975, (PB 242, 595).

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              - 186 -
            APPENDIX A
Process Descriptions - Gasification

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                                   -  187  -



                                APPENDIX A

                   PROCESS DESCRIPTIONS  - GASIFICATION
          In this appendix a general description is presented of the
gasification processes studied.  The reader is referred to the individual
process reports for details.

A.I  Koppers-Totzek Process

     A.1.1  General

          The gasifier operates at about 2700°F and atmospheric pressure
with oxygen, a small amount of steam, and a dilute suspension of powdered
coal to produce synthesis gas.  The product gas is high in CO and hydro-
gen, with negligible methane.  The process is described generally in the
Koppers brochures.  Additional information has been obtained from the
literature and by discussions with the Koppers Company.  A discussion of
the processing steps follows.

     A.1.2  Main Gasification Stream

          Figure A.1.1 is a block flow diagram of the process and auxiliary
facilities.  This design, based on the design supplied by the Koppers
Company, feeds 6,750 T/D of bituminous coal containing 16.5% moisture,
17.3% ash, and 0.63% sulfur with a HHV of 8830 Btu/lb.  The product gas,
after acid gas removal, is 290 MM cfd with a HHV of 303 Btu/cf and 300 ppm
sulfur.  This sulfur content meets requirements but could be reduced by
the use of more equipment.  Most commercial applications are for making
ammonia or methanol, but the gas can also be used as a clean fuel for
firing ceramics, glass manufacture, etc., or for steam generation and
combined cycle power plants or for upgrading to high Btu SNG; in other
words the gas can be used whenever synthesis gas, fuel gas or reducing
gas can be used.  The process can also be used to gasify coal fines, char,
hydrocarbons, or tar.

          A.1.2.1   Coal Preparation

          The  first unit to be considered is the coal  storage pile and hand-
ling facilities.  This particular design does not require beneficiation of
coals of  30% ash content or lower.  For  30 days storage, the coal piles are
about 200 feet wide,  20  feet high, and 1,000 feet long.  There are two  of
these, with loading,  unloading, and conveying equipment.  These will generally
be tamped down, but there  can  still be dusting and wind loss.  Covered
conveyors should be used,  and  other precautions included in  the design  to
minimize dusting from stacking etc.  Thorough planning is necessary  to
avoid possible  combustion  in coal storage piles etc.,  and to provide for
extinguishing  any fires  that may start.

          Coal  drying uses a rotary drum drier fired with part of  the
product gas, giving a sulfur level in the off gas well below that  allowa-
ble for liquid  or solid  fuel firing.  Use of  feed  coal as  fuel would be more

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 GASIFICATION PROCESS
                                                                                                                        GAS TO DRYER

COAL IN 	


COAL
STORAGE


r
f ' 1
COAL
PREP.


GAS IF IER



1
DUST
REMOVAL
J
-^
	 ^

p/WpDCC





ACID
pAC
REMOVAL

I,
PRODUCT
GAS
.VXILIARV FA


°2
PLANT


SULFUR
PLANT


UTILITIES


WATER
TRHAT.

WASTE
WATER
TREAT .

COOLING
TOWER
                                                                                                                                    oo
                                                                                                                                    oo
                                                         Figure A.1.1



                                             Koppers-Totzek Gasification Process

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                                - 189 -
efficient than the use of product gas but would give 1.4 Ib S02/MM Btu
compared to the allowable 1.2 Ib S02/MM Btu.  However, the major part
of the fuel could be coal, supplemented by some product gas to meet
sulfur emission limits.  A large volume of excess air is used to bring
the drying gas temperature down to less than 1000°F in order to avoid
overheating the coal.  Also, flue gas is recycled on the drier to hold a
maximum of about 10% oxygen in the gas.  The coal is not oxidized in the
drying step and no tar, sulfur, or volatiles should be evolved, since the
coal temperature is not over 200°F.  It may be that a fluid bed drier
would be more effective than the preceeding because it would allow a
higher gas inlet temperature without overheating the coal.  This would
reduce the volume of dusty effluent gas since less excess air is needed,
and the fuel efficiency would increase correspondingly.  As an alterna-
tive, it might be possible to dry the coal using heat in the flue gas
from the utility boiler.

           The drier vent gas must be cleaned up and for this purpose
 an electrostatic precipitator was added to the base design.  Bag
 filters  might be used instead, but they must be kept hot enough to avoid
 water  condensation.  A water scrubber could be used, and may be
 preferred  if  odors in this vent gas are objectionable.  The degree of
 odor  control  needed will depend on the type of coal and the plant
 location.   It may be more of a problem for example on lignite, and this
 information should be obtained from plane or experimental operations.
 Even  so,  the  gas will have a high moisture content and may form a
 water  fog  under certain atmospheric conditions.  In locations where this
 is not acceptable, one solution is to make sure that the vent gas  is
 above  the  critical temperature for fog formation.

          Grinding and pneumatic transport with nitrogen are designed
for completely closed gas recycle.  The gas balance lines from this system
 (e.g. coal feed hoppers)  should be vented into the dust removal system.
Great care should be taken to avoid spills, overflow, leaks on seals, and
the like.  As a further precaution to control pollution, this entire
system could be housed in a building, with positive ventilation control
tied into bag filters.

           Noise  control may also be needed.  While the building may shield
 the process area  from undue noise of the grinding and handling operations,
additional precautions may be needed from the standpoint of personnel
 inside the building.

          A.1.2.2  Gasifier

          The gasifier uses an entrained flow of coal, oxygen and steam.
Coal is fed by screw feeders and is intimately mixed with steam and
oxygen.   The high temperature of operation causes slagging of the ash.
Part of the slag exits at the bottom of the reactor and part passes
overhead with the gas.  The very hot gases are quenched above the
reactor by a water spray before entering a waste heat boiler.  Low
pressure steam is produced in the gasifier jacket and high pressure steam
is produced in the waste heat boiler.  The gas then passes to the gas
cleaning  section.

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                                  -  190 -
           A.1.2.3   Gas  Cleaning

           The raw  product gas is cooled  in a  waste  heat  boiler and  then
 scrubbed with water.  Water from the scrubber,  containing  approximately
 half of the slag as well as dissolved H2S  etc.,  goes  to  a  clarifier to remove
 solids and then to a cooling tower in which the  air will strip out  dissolved
 gases.  If all the dissolved H2S is stripped  into the air,  it  will  give
 a concentration of 1-2 vppm.  While this  is below the Maximum  Allowable
 Concentration, it  is far above the  odor threshold and would be unacceptable.
 It is common to find an appreciable Biox action in  the cooling water cir-
 cuit, and Koppers  Company experience shows  that there is no odor problem,
 but this area needs better definition, particularly on higher sulfur coals.
 The problem can be avoided by using indirect cooling by cooling water or
 air-fins.  The calculated amount of H2S is  less than 100 Ibs/hr and it
 should be relatively easy to  inactivate it  by adding lime slurry, or by
 passing the circulating water through a bed of lump limestone.   There
 might be sufficient alkalinity from the fraction of the slag that is
 carried over to do the task.

           A.1.2.4   Acid Gas Removal

           After compression,  the gas  is scrubbed with amine to remove H~S.
 It is understood that Koppers Company is planning to use MDEA (methyl
 diethanolamine) for selective removal  of l^S; thus,  a concentration of
 227o H2S passes to  the Glaus plant.

          The final product gas after scrubbing contains  200 vppm of H2S,
 as well as an estimated 100 vppm of COS.   This gas  is considered a  relatively
 clean low Btu fuel.  The sulfur level is  too high,  however, for methanation
 etc., to make a high Btu fuel.  However,  if methanation is desired other
 systems can be used to reduce sulfur to acceptable  limits.

      A.1.3  Auxiliary Facilities

           In addition to the  basic  process, a number of auxiliary facili-
 ties are required  which will  now be discussed with regard to effluents
 to the air.

           A.1.3.1   Oxygen Plant

           The oxygen plant provides 4,000  tons  per  day of  oxygen.  It
 should pose  no pollution problems  since the only major effluent is  a
 nitrogen stream, but there is a  large consumption of  utilities which
 affects  overall thermal efficiency  of the  process.

           A.1.3.2   Sulfur Plant

           The IkS  stream from acid  gas removal goes to a Glaus plant.
 Sulfur recovery of about 97% can be achieved with  three  stages in
 "straight-through" flow.  The tail  gas still contains about 1 ton per
 day  of sulfur and  must  be cleaned up, although this gas  volume of 7 MM cfd
 is small  relative  to the other effluents.   A .number of processes are
 available now for  tail  gas clean up and  several of  these will be in  com-
mercial  use  soon (e.g.  Shell's SCOT process,  Wellman-Lord process,

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                                 - 191  -
  Beavon Process,  etc.)-   In some,  the tail gas is  first  reduced to  convert
  all sulfur compounds  to H2S which can then be removed;  in  others,  the
  tail gas  is incinerated and the S02 is then scrubbed  out.   Limestone
  scrubbing of the incinerated tail gas may be used, with disposal of
  spent limestone  along with the coal ash being returned  to  the mine.  The
  amount of spent  limestone is relatively small.

           No specific  preference is indicated for  Glaus  tail gas clean-up
  since by  the time that  coal gasification finds much commercial application
  in this country, there  will be considerable commercial  experience  to
  draw  on.  It is reasonably certain that there will be  at  least one
  demonstrated, satisfactory process available.

           A.1.3.3  Utilities

           In the  utilities  area', the main  cooling tower has by far  the
  largest volume of discharge, 48,000 MM cfd of air. It  is therefore critical
  froir.  the  standpoint of  pollution.  In  this particular case it is  not ex-
  pected  to  contain significant amounts  of undesirable contaminants.  The
  cooling water circuit is  clean and does not  contain ash or objectionable
  materials  such as H2S.  Normally a certain amount  of leakage can  be
  expected  on exchangers  using cooling water.  Since the process  operates
  at  low  pressure,  this should not be a major  item.   Also, most of  this
  cooling water is  from steam condensers of drivers  on compressors,  rather
  than  on oil,  sour water,  etc.  Cooling towers will always have  the  problem
  of mist as well  as fog  fcreation, as discussed under the area of  gas
  scrubbing.

           The utility power plant is a major item  from the  standpoint of
  pollution  as well as thermal efficiency of the over all  process, and is
  sized to make the plant self-sufficient in steam and power.   It is  desir-
  able to burn coal as fuel, which means that sulfur and ash  removal  are  re-
  quired on  the flue gas.  This particular coal contains  0.63  wt. 7<, sulfur
  corresponding to 1.4 Ib S02/MM btu, whereas the allowable is 1.2. Therefore,
 some sulfur control  is required.   There are many ways  to  do  this.   As
 one  example, a water scrubber can  be  used  to  remove ash and  if some
 limestone  is added it  should be feasible  to  remove,for example,  20%
 of  the S02>  and thereby  conform to regulations.  The amount  of limestone
 to  dispose of  is  moderate,  amounting  to about  40 tons  per day for complete
 S02  removal,  compared  to the ash production  of 235 tons  per  day from
 the  utility boiler.

           An alternative is to  burn part  of  the product gas along with coal
 to meet the allowable quantity of S02 in the flue gas discharged to the
atmosphere.  It would be possible to burn only product  gas in this  utility
boiler to supply all the fuel required.  This may not be a practical case
but does set a limit.  It would result  in minimum pollution from the utility
boiler, with regard to sulfur and particulates, in  cases where this is
justified or necessary.  The volume of flue gas from the power plant is
320 MM cfd, or about the same as the volume of clean product fuel  gas.

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                                    - 192 -
          In view of the intensive effort underway on flue  gas  clean-up,
 it  is expected that there will be techniques in wide spread use by  the
 time that coal gasification finds extensive application.  When  flue gas
 desulfurization is used on a boiler with coal firing, it  may be desirable
 to  add  the Glaus tail gas to the boiler so that it is incinerated and
 passes  through the sulfur cleanup.  This would avoid the  need for
 separate facilities for tail gas cleanup, but it does assume that the
 Glaus plant would be near the boiler house.   Location of  the boiler might
 also be dictated by the practicality of using the flue gas  for  coal
 drying.

 A.2 Synthane Process

     A.2.1  General

          The Synthane Process  being  developed by the  Bureau of Mines
 is an intrinsically high efficiency fluidized bed coal gasification
 system  operating at commercial  pipeline  pressure  and designed  to produce
 high-Btu content product gas.   Gasification is accomplished in the
 presence of steam/oxygen, whereby heat required for the  gasification
 reactions is supplied by the  reaction of oxygen with a portion of  the
 coal.   High pressure favors methane yield,  minimizes gasifier  volume,
reduces oxygen requirement and  reduces product  gas  compression.  A good
 fluidized bed operation insures the homogeneous reaction system required
to avoid damage by locally high oxygen concentrations-

          It was found possible to pretreat any caking coal by  the  proper
 combination of oxygen content of the fluidizing gas, temperature, and
 residence time, using a single vessel  system wherein the  operations of
 coal pretreatment, carbonization,  and  gasification are combined.

          An engineering evaluation of the Synthane Process, which by
 this time incorporated Bureau of  Mines methanation developments,
was prepared by The M.W. Kellogg  Company in 1970.  Notwithstanding
 the substantial extension of  high-pressure technology required to com-
mercialize the process, there was found sufficient incentive in the
economies projected in terms  of overall simplicity, high gasifier methane
yield,  and small reaction volumes to  proceed with design of a prototype
 large pilot plant.  The prototype pilot plant was designed  by The Lummus
 Company, and is now being operated.
          A block flow diagram of the process and auxiliary facilities
is shown in Figure A.2.1.  This design feeds 14,250 tpd of a Pittsburgh
seam coal containing 2.57» moisture, 7.4% ash, and 1.6% sulfur to the
gasifiers.  250MM scfd of product gas is produced, with a HHV of 927
Btu/scf.

     A.2.2  Main Gasification Stream

          A.2.2.1  Coal Preparation and Storage

          On-site coal storage will be required for all gasification
plants to provide back-up for continuous gasification operations.  For

-------
                                    PUR.IF.
                                                           MEVH.
                                                                   GI&


                                                                  COMP.
                                                                                  J0.4MM
CHAR
I3	
                     PIANT
                                                                                       i

                                                                                       !-•
                                                                                       V€>


                                                                                       I
                          Figure A.2.1




  SYNTHANE Coal Gasification - 250 million SCFD High -  BTU Gas

-------
                                - 194 -
 thirty days storage,  there might be four piles, each about  200 feet
 wide, 20 feet high, and  1000 feet long.  Careful management and planning
 will minimize dusting and wind loss and the hazard of combustion in
 storage facilities.

           The feed coal  employed in this design has low inherent moisture
 content, such  that a special coal drying  step is not provided.   It may
 be possible  to operate  the system without such a facility with  coal from
 particular seams, but this indicates  enclosed on-site storage.   Coal of
 the  type and size range (-3/4 inch) indicated to be held in stockpiles
 in this design might be expected to acquire and retain 6-8 weight per
 cent surface moisture on exposure to  rain.

           A.2.2.2  Coal  Grinding

           Approximately  53 MM cfd of atmospheric air is aspirated into
 the ball-mill grinding operation, which reduces coal size to 70 percent
 through 200 mesh.  The air stream is heated in a circulation system and
 passed through the mills, where it serves both to control moisture in
 the pulverizing process  and as transport medium for the pulverized material.

            The  coal/air  mixture  passes through cyclones, where separation
 occurs, and  the  air  stream  is discharged to the atmosphere through bag
 filters.   Such arrangement  is commercially proven, with acceptable
 particulate  emission, though  load on  the filters may amount to  some
 60 tpd  in  this case. Only trace quantities of hydrocarbons have
 been detected  in such commercial streams, and odor is not considered
 a problem.   Collected fines from the  filters are recycled to mill product.

           A.2.2.3 Gasification

                A.2.2.3.1 Coal Feed System

           Coal is charged to the gasifiers  in the  Bureau of Mines  design
 through pressurized  lock hoppers.  A number of alternatives regarding
 the mechanical arrangement, the pressurizing medium,  and  the consequent
 net energy requirement  and pollution potential of  lock hopper operation
 appear feasible.

          In  this design, each gasifier is provided with one lock
hopper, which discharges alternately  into two feed hoppers from which
coal  is passed  to the gasifier using  a steam/oxygen mix as transport
medium.  Oxygen reacts with  coal in the transfer line, liberating heat
which prevents  steam  condensation,that might otherwise interfere with
coal transport.   Hence,  in this  case,  some pretreatment of coal occurs
in the transfer  line.

          The gasifier charging  sequence involves filling  the vented
lock hopper from  pulverized  coal storage bins, pressurizing the filled
lock hopper,  and  discharging its load into a feed hopper.   In this
configuration,  it is  presumed  that a  feed hopper is maintained slightly
above gasifier  operating pressure while on line  to  the  gasifier, and

-------
                               - 195 -
that pressure is allowed to drop  to  the  gasifier pressure level as the
hopper empties.  At this point, the  feed hopper is ready to accept another
charge from the filled, pressurized  lock hopper.

          The pressurized lock hopper must be vented  to essentially
atmospheric pressure when empty of coal  in order to be refilled.  In a
multiple gasifier system, operation  may  be sequenced  such that initial
venting may be to a lock hopper awaiting press'urization, or to a suc-
cession, of these, such that some  of  the  energy represented by the com-
pressed gas may be recovered directly, while simultaneously reducing
the quantity of residual gas to be vented ultimately.  Alternatively, two
or more lock hoppers might be provided each gasifier  specifically to
permit such sequencing, since there  may  be practical  operating limita-
tions to the degree to which gasifier operation may be scheduled.

          The choice of pressurizing medium may directly affect the main
gasification processing sequence, as well as the design and operation of
the lock hopper system.  The use  of  steam alone as this medium is con-
sidered mechanically unacceptable due to interference expected with coal
transport from condensation, which may not be controllable.

          Since some fraction of  the pressurizing medium will travel
with the coal into the gasifier,  the use of a nitrogen-containing inert
gas for such medium is considered unacceptable from a process viewpoint,
since it dilutes the product gas, reducing its heating value, and
occupies volume in the reaction sequence otherwise.

          It is believed that C02, which is separated from the main
process gas stream following shift conversion, is the preferred pres-
surization medium.  Such C02 must be superheated to prevent lique-
faction at 1000 psia, and the rate of heat loss from the pressurized
feed system must be controlled to prevent condensation.  Depending
on the mode of operation of the feed system,  the volume of raw
gas issuing from the gasifier may be increased some 3-5 percent
as a consequence of admission of pressurization gas with coal.  This
increased volume must be handled through the acid gas removal step,  but
it is presumed otherwise not to affect process operation.

          In the method of operation of  the coal feed system described
above for this design, there should  be no opportunity for gasifier
gas to back through  the lock hopper. Hence, trace quantities only of
coal-originated materials, other  than coal dust, should appear in vent
gas.  However, the use of a heated hopper system,  as  will be  required
if C02 is the  pressurization medium, may subject coal in contact with
heated surfaces to sufficiently high temperature to cause stripping of
volatiles or of sulfurous gas.  Formation of carbon-  or carbonyl sulfides
is also possible.

         We have assumed an alternative  to continuous atmospheric vent-
ing which involves containment of lock hopper vent gas, as  in gas holders
from which it  could be recompressed, limiting the  requirement for fresh
make-up gas to the losses (largely back  into the system) from the coal
feed system.   In this arrangement,  it will probably be necessary to
treat or filter gas  entering the  holder  to remove  dust.

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                                  - 196 -
               A.2.2.3.2  Char Letdown

          Ash must be removed from the  Synthane  gasifier,  as in most
gasification processes,  in  a  more  or  less  continuous  fashion,  to main-
tain carbon concentrations  in the  gasification zone sufficiently high
for desired reactions to proceed.   Experimental  work  indicates incentive
for limiting the degree of  carbon  gasification,  and a proposed feature
of the  Synthane  process involves setting the  carbon content  of the ash
(char)  removed from the gasifier such  that combustion of the char will
balance the total steam and energy requirements  for the process.

          The high operating  pressure of the  Synthane gasifier imposes
special problems on the system used to  extract char.   At the point of
discharge from the gasifier bed, char is indicated to be at  temperatures
in excess of 1700°F.

          The char in this design represents a significant sensible heat
discharge from the gasifier.  From  thermal and process  points  of view,
perhaps the ideal system would transfer hot char directly to the boiler
in which it is to be combusted along with any associated gas,  preserving
most of this heat and  avoiding use  of cooling media, water or  steam,
that would require additional  energy to subsequently separate  or treat.
The mechanical design  of a throttling arrangement  that  would permit such
operation, however, will require substantial development.

          Consideration  of a variety of alternatives  led the designers
of the  large pilot plant to  a  system wherein char  is  cooled  in situ
prior to the point at  which  it must be passed through valves.   Hot
char is caused to flow  into a separate  fluidized bed  cooler  by regulating
the pressure differential between  the gasifier bed and the cooler.  Steam
is used to fluidize the bed,  and water  is  injected  into  the  system for
cooling. High-pressure steam is generated in the»cooler,  and this
steam may be used in  the process  (specifically  in the carbon monoxide
shift converter) after  it has been filtered to remove char fines.  The
designers point  out that this steam might  be directed to  the gasifier
in its  contaminated state if  the gasifier  distributor were designed  to
introduce contaminated  steam  and oxygen separately.

          Cooled char may be  fluidized out of the cooler bed into lock
hoppers, avoiding throttling  valves, or may be passed from the bottom of the
cooler  bed through  valves into  lock hoppers-  Agglomerates which may come from
the gasifier could present  problems with either  method of cooler operation.

          The preferred alternative is  a  "dry" system, in which  a filled
char lock hopper is isolated  with  valves which are arranged to be blown
clean before closing.   Steam  is vented to  atmosphere  via  filters arranged
within  the lock  hopper, ahead of the  pressure-reducing valves.  Char  flows
out of  the bottom of  the lock hopper  into  a conveying line  in which  stoam  is
used as transport medium.  The empty lock hopper is  repressurized with
steam before being put  on line to again receive char.

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                                   -  197 -
          A second alternative directs a char/steam mix  from  the cooler
through a slide valve into a char slurry quench tank, where water sprays
cool the char and a slurry is formed.  The quench tank is vented to the
char cooler.  Char slurry is depressured through orifice valve arrangements,
the char slurry is filtered to recover water,  and water  is recycled to the
slurry quench tank through coolers.   The char  filter cake is  estimated to
contain 40-50 percent water in this  case.

          Gas from the gasifier will be carried into the char cooler
along with char.  It is presumed that most of  this gas will issue from
the char cooler along with the generated steam and be directed back into
the main gasification stream, either directly  into the gasifiers or at
the shift converters.  It is not possible to estimate the degree of gas
contamination that may persist through the char depressurizing system
into the steam which is indicated to be vented ultimately from a "dry
char" process.  Some 3000 pounds per hour of steam is estimated to be
so vented if this scheme be applied  to the Bureau of Mines design.
Depending on its composition, some of this vent steam may be  employed in
the scrubber water treating system,  or may serve to transport char to the
utility boiler, in an integrated commercial plant.   Although  there
would probably be least atmospheric  pollution  associated with a "wet char"
or slurry letdown system, the water  pollution  generated  and the energy
associated with water treatment and  wet char combustion  would indicate
that the slurry technique would be used only if an operable dry char
arrangement cannot be developed.

          To summarize, the design basis does  not specify the method by
which char will be removed from the  gasifiers, except to provide lock
hoppers to receive char.  The lock hopper volume provided is  not consistent
with estimates of char density, so that lock hopper cycle rate may be
higher than indicated.

          With the preferred dry char  process,  we have assumed  that  about
100,000  pounds per hour of high pressure  steam will be generated  by  direct
water  injection in the char cooler,  and that this steam, along  with  as-
sociated gasifier gas, will be reintroduced  into the process  at  the  shift
converters.  Some 3000 to 6000 pounds  per hour of steam is  estimated to be
vented from the lock hoppers, depending on cycle rate.  "Dry"  char is as-
sumed to be conveyed to the utility boiler using a steam transport  system.
Net atmospheric pollution associated with char let-down is  therefore as-
sumed minor.

          A.2.2.4  Dust Removal

          Raw gas  issuing from the  gasifiers must be treated  to remove
particulates and condensable matter that may interfere with subsequent
gas processing.  The precise nature of materials  which must be  separated
from raw gas at this point is not known, except that coal or  char fines
and coal-tars or oils  are assumed to be present.

          In the design basis,  gas from the gasifiers passes  first
through cyclones,  where heavier particles (char1) are removed, and then the

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                                 -  198 -
gas is subjected to cold-water  scrubbing.  Scrubber liquor effluent  is
depressured into decanters, where tar separation occurs,  and water is
recirculated to the scrubbers through water-cooled heat exchangers by
high-pressure pumps.   This design does not further detail the  operation,
or provide for further handling of separated products or of scrubber
liquid.

          We believe it may be  possible to adapt a "tar-scrubber" of the
type developed for petroleum fluid coking reactors to the Synthane coal
gasifier to avoid the mechanical problems associated with tar  and solids
deposition in the gas outlets.  Moreover, it should be possible  to
extract high-level energy from  the process.

          In the fluid coker,  the  scrubber vessel is integral with the coker
reactor.   The cyclone is  internal  to  the reactor, with its  outlet  gas
discharge  into the scrubber.   Heavy tar condensed from the  gas stream
in the scrubber is pumped  through  external exchangers, where high-pressure
steam  is  generated.   The  cooled  tar stream separates, with  the portion
not used  for scrubbing being  returned to the  coker feed line.   It  is of
coarse necessary to control  temperature of the tar pool in  the bottom
of the scrubber vessel and tar velocities in  the external circuit  to pre-
vent coking and solids deposition.

          In the Synthane design, gasifier outlet temperature is estimated
to be  800-1400°F.   A stean dew-point  of about 440°F is  estimated for the
raw gas conditions.   It is further  estimated  that up to 70  percent of the
heavy  tar  in the gas stream may be  condensed  by operation of the tar
scrubber at  about  560°F,  or  sufficiently high in temperature to
permit generation  of 1000 psia steam  in the external circuit.   It  is
estimated  that about 365,000  pounds per hour  of 1000 psia steam could be
generated  in this  manner, assuming  gasifier output to be at  1000°F.


         Removal of  the bulk of the heavy tar in the gas stream at this
point  should greatly reduce the emulsification problem as water is con-
densed from the gas  downstream.  Similarly, the tar scrubber would
serve  to remove a  major fraction of the char, ash, and coal fines contained
in this gas,  so that loads on  the  downstream  tar-oil separation ar>d water
treatment  systems  should be  reduced significantly.

         From a thermal point  of view,  it would be desirable to return
the separated tar  stream to  the gasifier, as  is done in the petroleum
coker.  But  if this  is found  to adversely affect gasification, such
separated tar could instead be  directed  to  the char utility boiler or
may be further processed for  sale.

          In this design, we have assumed  that scrubbing will be used
following the tar scrubber, but that gas which separates  from the scrubber
effluents on depressuring will  be recompressed back  into  the main gas
stream at a point following shift conversion.  Additional  tar and hydro-
carbons which condense along with water  from the  gas  stream as the  stream
temperature is lowered may be directed to  finishing  facilities to be
processed for sale, or could be burned in  the  utility boiler.  Either or

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                                 - 199 -
both water and light  hydrocarbon might be recirculated to scrub the gas
stream, and steam could be  generated in the process of cooling the
circulated fluids.  Alternatively at some point, gas would be sufficiently
clean to permit direct operation in a conventional waste heat boiler.  On
the assumption that gas temperature is reduced to about 300°F to effect
clean-up, some 300,000 to 400,000 pounds per hour of low-pressure steam
may be generated in the scrubbers.

          A.2.2.5  Shift Conversion

          Scrubbed raw gas from the dust removal  process  is separated
into two equal  streams,  one of which by-passes  the  shift  converters,
since only half of the total stream must be  shifted to  adjust the total
H2:CO ratio to  3:1 for purposes of methanation.   In this  design, a
significant quantity  of high-pressure steam  must  be introduced to the
catalytic shift converters to achieve desired  equilibrium, however.

          A.2.2.6  Waste Heat Recovery

          The raw gas streams which are split  ahead of  shift conversion
are recombined  following the converters, and are  cooled from an average
temperature of  about  500°F to 300° F ahead  of the  gas purification system.
Low-pressure  steam is generated, and there are no effluents to atmosphere.

          A.2.2.7  Light Hydrocarbon Removal

         For  our design, we have assumed that  the gas stream may be cooled
in water exchangers  to about 90°F after it has  been used  to reboil the
Benfield regenerator  and passed through light  oil scrubbers to remove B-T-X
components.  The scrubbing fluid would be  available from  the upstream
hydrocarbon separators.  Gas which separates on depressurizing this scrubber
effluent could  be recycled to the vapor space  of  the upstream separators
for recompression into the main gas stream.  Downstream distillation facili-
ties would be required to  separate naphtha if  it  were to  be sold.  It is
estimated that  20,000-25,000 GPD of B-T-X  coald be  so separated, requiring
an estimated  equivalent  of 25,000 pounds per hour of low-pressure steam.

         Part of the  heat  removed in the cooling  process  could be returned
to the gas stream after scrubbing by exchange  with the heated water leav-
ing the coolers, so  that the net thermal loss might be  held to the equiva-
lent of about 60,000  pounds per hour of low-pressure steam.  About 18,000
pounds per hour of water would be condensed  from  the gas  stream on cooling,
and this (equivalent)  water would have to  be reintroduced on reheating the
gas to avoid depletion of  the Benfield solution.  This  might best be
accomplished by direct  introduction of high-pressure steam, rather than by
reintrodaction  of the  contaminated separated water, which would be directed
to the waste water treatment facility.

          A.2.2.8  Gas Purification

          The gas purification or acid gas  removal process which  is  used
is the "Benfield" hot potassium carbonate system developed by  the Bureau

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                                   -  200 -
of Mines.  This method  of  removing C(>2 and H2S from the produced  gas  is
indicated to have substantial  thermal advantage over amine  systems at the
high process pressure employed.

           In  the Benfield system,  gas  absorption takes place in a con-
centrated  aqueous solution of potassium carbonate which is maintained
at above the  atmospheric  boiling point of the solution (225°-240°F) in
the high-pressure absorber.   The high  solution temperature permits high
concentrations cf carbonate  (alkalinity)  to exist without incurring
precipitation of bicarbonate according to:

                     K2C°3 + C°2  + H2°   	*  2KHCO

Partial  regeneration of the rich carbonate solution is effected by
flashing as the solution  is depressured into the regenerators.   In this
design,  sensible heat  of  the  main gas  stream is used to reboil the
regenerators,  so that  the gas is cooled to about 260° F in the process.
The gas  is further cooled in  cold-water exchangers to about 225° F before
entering the absorbers.

           It  is necessary in  this design to admit additional low-pressure
steam into the regenerators to complete the regeneration process  and to
balance  heat  and water requirements.   Regenerated solution is pumped back
through  the absorbers. The main process gas stream exits the absorbers
at 230°F,  and is cooled by cold-water  exchange to about 100°F before
undergoing residual sulfur cleanup.   Stripped acid-gas flows to the sul-
fur recovery  plant.

          A.2.2.9  Residual Sulfur Cleanup

           Methanation  catalysts  are adversely sensitive to very small
quantities of sulfur in feed  gas.   The Benfield system is reported  to
be capable of operation such  that sulfur present in process gas as  hydrogen
sulfide  and carbonyl sulfide  may be virtually completely removed.   Less
is known about the other  forms of organic sulfur which may be present in
process  gas,  especially thiophenes.

          This design incorporates a sequence of  iron oxide and char
towers for residual sulfur cleanup ahead of  the methanation reactors.
It is estimated that total sulfur in gas may be reduced to less than
0.1 grain/100  ft3 in this  arrangement.   Some provision will have to be
made to permit change-out  of the  beds in this section.  Hence, the high-
pressure gas in the beds will  have  to be vented,  and the beds will have
to be inerted  before being opened.  It  is  assumed  that the vented high-
pressure gas will be directed  to  the utility boiler.  Steam, which may
be used for inerting, may  be directed back to the Benfield regenerator.

           Steaming, or other  iiierting, will also be required to purge
the bed  of oxygen when a  new bed is to be put on  line.   It  is  assumed
then  that  the only discharge  to atmosphere from this  section will be
such  inerting medium,  and, further, that  the quantity  of this  gas will
be very  small.

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                                  -  201  -
          A.2.2.10  Methanation

          The Bureau of Mines has developed  two methanation processes
for application in the Synthane system,  and  both will be tested in the
prototype pilot plant being constructed  at Bruceton.

          This design incorporates the Tube  Wall Reactor or TWR process,
in which the methanation reactor is constructed in  the form of a heat
exchanger.  Reaction occurs on a Raney nickel  catalyst coating applied
to the exterior of the exchanger tubes,  and  Dowtherm is vaporized through
the tubes to remove reaction heat.  High-pressure steam is generated in a
separate boiler in the process of condensing and cooling the Dowtherm heat
exchange fluid, which is then recycled to the  methanator.

          A.2.2.11  Final Methanation

          The design basis does not include  specific equipment for
limiting CO content of product gas issuing from methanation.  Depending
on the ultimate use of product, CO content may be required to be held
to less than 0.1 volume percent.  The experimental  data reported to date
would indicate that a final treat will be required  to limit CO content in
methanator effluent to specification.  In a  commercial plant, some
arrangement, possibly involving standby  methanators, would probably be
required in any event to handle sudden loss  of activity or other mal-
function in the process train at this point.   In our design, we have
assumed that specification CO levels will be achieved in the methanation
plant proper.

          A.2.2.12  Final Compression

          Pressure drop through the Synthane train  is indicated to amount
to about 65 psi.   Gas leaving the methanation  plant is cooled to 100°F to
remove water, and is then compressed to  1000 psig,  the design product
delivery pressure.

     A.2.3  Auxiliary Facilities

          We have elected in this study to treat  the main gasification
stream separately from all other facilities, which are thereby defined
as auxiliary facilities.  The functions of these  auxiliary facilities
are nonetheless  required by the process, and, for economic   and/or
ecologic  reasons, would be constructed along with the gasification
system in an integrated plant.

          A.2.3.1  Oxygen Plant

          The oxygen plant provides  a  total  of 3650  tons per day of
oxygen.   The only effluents to  the air  from  this  facility should be the
components  of  air, principally  nitrogen.   About  330 MM scfd  of nitrogen
will be  separated.  Some of this  nitrogen  may be  used  to advantage in
the plant to inert vessels or conveyances, to serve  as transport medium
for combustible powders or dusts,  as an inert stripping  agent in
regeneration or distillation, or  to  dilute other  effluent gas streams.

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                                 - 202 -
 It will  be possible to generate about 900  KW of electricity by recovering
 the compression energy of the nitrogen through turbo-expanders.

           About 425 MM scfd of air  is taken into the oxygen  facility.
 Placement of the oxygen facility will depend in part on the  desire  to
 maintain the quality of the air drawn into the system and, especially,
 to minimize interference from plant effluents,

          A.2.3.2  Sulfur Plant

          The Stretford process has been assumed for sulfur removal.  In
 the Stretford process, sour gas is washed  with an aqueous solution
 containing sodium carbonate, sodium vanadate, anthraquinone disulfonic
 acid,  and a  trace of chelated iron.   The solution reaches an equilibrium
 with respect to C02, such that only small  amounts of CC>2 are removed
 from the gas undergoing treatment.

           In this system, H2S dissolves  in the alkaline solution, and
 may be removed to any desired level.  The hydrosulfide formed reacts
 with the 5-valent state vanadium, and is oxidized to elemental sulfur
 The wash liquor is regenerated by air blowing,  wherein reduced
 vanadium is restored to the 5-valent state via an oxygen transfer
 involving the ADA.   The sulfur is removed by froth flotation and
 filtration or centrifugation.

          A.2.3.3  Utilities

               A.2.3.3.1  Power and Steam  Generation

          The choice  of  fuel for  the generation  of  the auxiliary electric
power  and steam required by coal  gasification plants markedly affects
the  overall  process  thermal efficiency.   It is  generally least efficient
to burn  the  clean product  gas for this purpose.   On the other hand,
investment in power-plant  facilities,  including  those required to handle
the  fuel and to treat  the flue gas,  is generally least when product gas
is so  used.

          Synthane gasification is one of the  class of coal gasification
processes which generate a carbon-containing char.   Research to date
would  indicate that  it is not desirable  to gasify more than about 90%
of the carbon in feed  coal,  and that it may be  preferable to limit
gasification to about  60-70 per cent of  carbon for  most feeds.  A
particular feature of  the  Synthane  process design,  therefore, is that
the  carbon content of  char  leaving the gasifier  may be adjusted such
that the  subsequent combustion of the  char will  balance the power and
steam requirements for the  system.

          It may be assumed that combustion of Synthane chars will be
possible  in conventional fireboxes if product gas is used as supplemental
fuel.  This alternative might be preferred then on the basis of carrying
the  least developmental debits, and because it should be possible to
adjust S02 concentration in flue gas from  most chars such that subsequent

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                                 - 203 -
flue gas  treatment  may be  avoided.   It has  the disadvantage of adversely
affecting overall thermal  efficiency.

          For this  design, we have  assumed  that equipment will be de-
veloped to combust  char alone with  essentially complete carbon utilization.
This may  be possible,  for  example,  in a  fluidized bed boiler and,
especially, in a fluidized bed system which incorporates combustion in
the presence of limestone  to remove sulfur.  Otherwise, such char com-
bustion will in general require that flue gases be treated to remove
sulfur.  And, as indicated above, the development of a large-scale char
burning system, as  with the development  of  any new commercial boiler
concept,  may involve appreciable effort, a  long lead time, and considerable
investment.

               A.2.3.3.2  Cooling Water

          A total of 260,000 gpm of cooling water is indicated to be
required  in this design.  If cooling towers were used for this total
plant, a  minimum of 6600 gpm of water would be evaporated.  Drift loss
would be  in excess  of 500  gpm, and  draw-off might be about 800 gpm.  Air
requirement would amount to some 48,000  MM  scfd.  Reheat of plumes would
be required to avoid fogs  in some cases.

               A.2.3.3.3  Waste Water Treatment

          Facilities  required to treat  water, including  raw water,  boiler
feed water, and aqueous effluents,  will include separate  collection facilities

             Effluent  or  chemical  sewer
             Oily water sewer
             Oily  storm sewer
             Clean storm  sewer
             Cooling  tower  blowdown
             Boiler blowdown
             Sanitary  waste

           Retention ponds for run-offs  and for  flow equalization within
the system will be required.  Run-off  from the  paved process area could
easily exceed  15,000  gpm  during rainstorms-  Run-off from the unpaved
process  and  storage areas could exceed  60,000 gpm in a maximum one-hour
period.
           Pretreatment  facilities will include sour water stripping
for chemical effluents and Imhoff tanks or septic tanks and drainage
fields for sanitary waste.

           Gravity  settling facilities  for oily wastes will include API
separators,  skim ponds, or parallel plate separators-

           Secondary treatment for oily and chemical wastes will  include
dissolved  air  flotation units, granular-media filtration, or  chemical
flocculation units-

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                                 - 204  -
          Oxygen demand reduction may be accomplished in activated sludge
units, trickling filters, natural or aerated lagoons, or by activated
carbon treatment.

          Boiler feedwater treatment will in general involve use of ion-
exchange resins.  Reverse osmosis, electrodialysis, and ozonation may
find special application.

A.3   Lurgi Process

      A.3.1  General

          The Lurgi process  has  operations similar to other types of
coal  gasification processes,  except  for  the gasification step itself.  The
gasification step in each case  is peculiar  to  the  process-   In general,
coal  gasification involves  getting coal from the mine,  storing it,
reducing its size to that necessary for gasification,  and,  possibly,
pretreating the coal.  The  gasifier raw gas  is generally  processed
through  a shift reactor which converts  carbon  monoxide and  steam
to carbon dioxide and hydrogen.  The hydrogen  is necessary  for
a later  step in methanation.  This shift reaction  is only applied
to the raw gas if one desires to up-grade it to a  synthetic natural
gas  (SNG)  stream.  For a low heating value  gas, a  water gas shift
section  is not required.  In this Lurgi study, the assumption is that
the  gas  will be up-graded to SNG.  Following the shift there is a
clean-up step to  remove from the effluent  gas all the H~S  and most of
the  C02•  The acid gases are then taken for sulphur production through
a Glaus  plant or other sulfur recovery  process.  The last traces of
sulfur are then removed from the gas purification  product stream in
order not to poison the methanation catalyst.

           The next step is  methanation, where  three moles of hydrogen react
with  each mole of carbon monoxide to produce a mole of methane and a mole
of steam.   Considerable quantities of C02 also react to produce methane.
These are  highly exothermic reactions which produce a  fair  amount of the
steam required in the plant.  Following methanation there is a drying
step  and the gas is compressed  to pipeline  pressure.

          The plant is designed  to produce 250 MM scfd of SNG with a
heating value of 972 Btu/scf. A flow diagram for the plant is shown  in
Figure A.3.1.

     A.3.2  Main Gasification Stream

          A.3.2.1  Coal Storage  and  Pretreatment

          The  coal  storage  part of  the  plant does  not  involve  coal  cleaning,
gangue removal  or  primary screening. All of these  operations  are assumed  to
have taken place at  the  mine.   The  coal from the mine  is  transported  to
the gasification plant by a  continuous belt conveyor.  The higher heating
value (HHV) used in the design is 8872 Btu/lb of coal.

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Coal
   Air
                             Oxygen
                             Plant
                             c
                             oj
                             M
                             X
                             o
               Coal
           Preparation'
           Feed
           Coal
       Oxygen
       Blown
       Gasifiers
                                                            SNG
    Air
 Gasifiers
and Purifi-
  cation
   Ash
Disposal
S3
o
Ul
                      Raw Water
                      Treatment
                         and
                       Storage
                                                        Figure A.3.1

                                                        LURGI Process

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                                -  206 -
           The  sub-bituminous coal delivered to the gasification plant is
 crushed  to 1-3/4" x 0.   Six storage areas are used for stock piling.  Each
 area  is  1,750   ft.  long  x  124  ft^ wide and  contains roughly  120,000  tons
 of  coal.   Coal from the  various storage  piles is blended prior to feeding
 it  to  the  gasifier in order to achieve proper heating value  control (Btu
 control).   An  emergency  stock  pile and re-claiming facility  are  available
 to  provide an  additional 650,000 tons of coal.  This  will provide a 25 day
 supply of  coal in cases  of emergency.

           A secondary screening  facility  is present at the gasification
 plant.  The 1-3/4"  x 0 coal  is  screened  to  produce two gasifier feed
 sizes  (1-3/4"  x 5/8" and 3/8" x  3/16").   Two  sizes of coal are used  as
 an  economic measure  to minimize  size  reduction and screening operations.
 All undersized material  is  conveyed at a  rate  of  about 260 tons per  hour
 to  a briquetting  plant.  Briquettes are  fabricated and sized to 1-3/4" x
 5/8".  The briquettes are mixed  with  the  feed  going to the gasifier.  The
 briquetting plant contains  mixers,  coaters  and compactors in order  to mix
 the coal fines with a tar binder.

           Wet  scrubber dust collectors are installed in the screening
 and briquetting plant to eliminate dust and  fuel  emissions.   Sprays are
 used at transfer points for dust suppression.

           A.3.2.2  Gasification

           In the Lurgi Process, gasification takes place  in a counter-
 current moving bed of coal at 420 psig.   A cyclic  mode of operating using
 a pressurized  hopper is used to feed coal.   The pressurizing  medium is
 a slip stream  of raw gas which is later recompressed and  put  back  into
 the raw gas stream going to purification.   The gasifier has a water jacket
 to  protect the vessel and provide steam for gasification.  Approximately
 107» of the gasification steam requirement is provided  in  this manner.

           In general there are three process zones in  the gasifier.  The
 first zone devolatilizes the coal.  As the coal drops  down it is met with
 hot synthesis  gas coming up from the bottom causing devolatilizati on ,
 thus  removing  hydrocarbons and methane  from the coal.  As the coal
 drops  lower to the second zone, gasification  occurs by  the  reaction
 of  carbon  with steam.  Finally as the coal approaches the grate, carbon
 is  burned  to produce the heat  required  for the gasification process.

           The  top and middle zone temperatures are generally  between
 1100 and 1400°F, where the devolatilization and gasification  take  place.
 The gas leaves the bed between 700 and 1100°F  depending on  the  rank  of
 the coal.  The effluent stream for the Navajo  sub-bituminous  coal  will
be approximately 850°F.   The temperature  of the ash is kept below  the
 ash fusion temperature by introducing sufficient  steam to avoid ash
 fusion.

           The  gas  stream leaving the  Lurgi gasifier contains coal dust,
oil, naphtha,  phenol, ammonia,  tar oil,  ash,  char and other constituents.
This mixture goes  through  a scrubbing and cooling tower to  remove the tar.

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                                   - 207 -
The raw gas stream then goes through a waste heat  boiler where the raw
gas temperature is cooled to about 370°F.   The boiler  produces 112 psia
steam for the Rectisol, Phenosolvan, and Stretford plants.  The raw gas
stream after cooling is split into roughly two equal parts.  Half of it
goes through shift conversion to produce additional hydrogen which will
be needed for methanation.  The other half goes directly to the gas
purification system.  Any liquid that is condensed in  the waste heat
boiler and gas cooling section is sent to the gas  liquor separation unit.

           The  coal lock hopper gas is compressed and mixed with the
stream  that  goes  directly to purification.  This  lock hopper gas stream
is mixed  with  other vent streams which contain sufficient quantities
of carbon monoxide and methane to warrant  its re-introduction into
the  raw gas  stream.

          A.3.2 3  Tar Separation

           The  water that was used to initially quench the gas as it comes
out  of  the gasifier becomes a gas liquor.  The gas liquor cools the crude
gas mixture  to a  temperature at which it is saturated with water.  This
gas  liquor is  then flashed, and the tar is removed out of the bottom.
The  top phase  is  then sent to water purification.  The gas liquor flash
tanks will also receive the aqueous effluent from the cooling area prior
to the  shift reactor.  In the gas liquor purification system,dissolved
phenol  and ammonia are removed for subsequent by-product recovery value.

          A.3.2.4  Shift Conversion

           Slightly less  than half of  the  total crude  gas  is  sent  to  the
shift conversion  section.   The  crude  gas  will be  cooled  in a waste heat
boiler  generating steam at  about 76 psia.   This  is the gas that  goes  to
the shift  reactor section.   The shift reactors are designed  to produce
hydrogen by the "water-gas shift" reaction.   The shift  gas feed is
quenched and  washed in a countercurrent water tower.  The washed gas is
heated and passed through a pre-reactor to remove  carbon containing
residues.   The heated gas will be shifted  in a series of reactors
resulting in  77.2% conversion of carbon monoxide.   The  equilibrium
temperature at which the 77.2% of the  CO would be  converted in this
system is 800°F.  Shift reactors generally operate between 700 and 1000°F.
The shift section is designed to produce a ratio of over three moles of
hydrogen to each mole of carbon monoxide in the total gas stream for
methanation.   In this design the ratio of  H~:CO going to methanation is
3.7.

          The hot gas  liquor and tar  which are condensed  during  cooling in
the wast heat boiler  are  sent to the  tar  separation units.   The  product
stream from shift conversion is then  mixed with the by-pass  gas  stream
from the gasification  unit  and  is cooled  and sent to  gas  purification.
Since the shift reaction  is  fairly exothermic, a  fair quantity  of heat is
recovered prior to  the  low  temperature  gas purification  step.   Heat is
also recovered  from the crude gas stream that does not go through the shift
reactors.

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                                    - 208  -
          A.3.2.5  Gas Purification

          The effluent stream from the shift reactor section is  combined
with the other half of the raw gas and the recompressed lock hopper gas,
and is then sent to the purification system.  The mixed gas  stream is
cooled to low temperature in order to go into the Rectisol system.
The Rectisol process is a low temperature methanol wash process  which
removes acid gases such as H2S, COS and C02 down to a level  of about 0.1
vppm.  The gas purification system is also used for drying and reducing the
C02 level prior to final pipeline compression.   The efficiency of methanol
absorption increases considerably with decreasing temperature.   The lowest
temperature used  in  the  process  is on the order of -75°F.   The  first
vessel in the Rectisol unit  is a prewash tower which strips out naptha
and cools the raw gas.   The  absorber then removes I^S and COS down to
about 0.1 vppm.   Roughly 88% of  the C02 is also absorbed at this time.
The effluent  raw  gas  from the methanol refrigerated absorption column is
used to cool  the  incoming acid gas stream.  This sulfur free gas stream
is then sent  to the  methanation  area.

          All the  acid gas streams are combined into a single stream
anil delivered to  the  sulfur  recovery plant.  The sulfur plant stream
also includes the  carbon dioxide that is removed after methanation.
The ncid gases  from  the  cold  methanol are recovered in a multi-stage
operation-  The acid  gas containing stream is  regenerated by step-
wise c-xpnnsion.  The  last step is a vacuum distillation. The stream
to the sulfur plant  contains,  in addition to the acid gases, a
fciir amount of  product  hydrocarbons and carhon monoxide which  will
ultimately be burned in the incinerator.  A mechanical compression
refrigeration cycle is used which provides refrigeration at  two  tempera-
tures:  high level refrigeration at 32°F and -50°F which is  used for  the
acid gas treatment.  The 32°F methanol stream is used mostly for removing
water vapor.

          A.3.2.6  Methanation

          The feed gas leaving the acid gas purification system  is  pre-
heated with product gas leaving the methanation reaction section.
Methanation catalysts are known to be extremely sensitive to poisoning
by sulfur.  The fresh feed is therefore treated with zinc oxide  beds
prior to exposure to the catalyst.  A fraction of the methanated product
is recycled and mixed with the feed to dilute the concentration  of
reactants in the feed.  The heat of reaction that is generated by the
synthesis of methane is removed by converting boiler feed water  to  process
steam.   This steam is used for gasification and in other parts of the plant.

          A.3.2.7  Compression and Dehydration

          The product gas from the methanation  reaction section leaves
at approximately  225 psia and 800°F- The  r.tream is cooled  and  is  sent
to a final  product condensate separator.   The  water is recovered  and is
sent to the raw water treatment plant.   The gas is cooled  Lo 90°F and
is then recompressed from 225 to  500  psin.  This stream is then sent

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                                 - 209 -
back to acid gas removal systems for C(>2 and water removal.  The effluent
from the gas purification system is then sent to the  second  stage of the
compressor where the pressure is boosted to 915  psia  to meet pipeline
requirements.  Air cooling is used to cool the compressor  effluent gas
prior to delivery to the pipeline.

     A.3.3  Auxiliary Facilities

          In addition  to the basic process facilities described above
a nu-nber of auxiliary  fa-ci 1 Lties are required to make the plant run
efficiently and  to  remove pollutants.  These will be described in this
section.

          A.3.3.1  Oxygen Plant

          Three oxygen plants are required in this process to produce
6,000 tons per day of 98% pure oxygen.  Approximately 444,000 scfm of
air are compressed to 90 psia with three parallel  centrifugal compressors.
In so doing, the moisture content of the air is  condensed  and is available
for process use.

          A.3.3.2  Sulfur Plant

          The IkS effluent stream from the acid  gas purification system
and the E^S from the acid gas treatment plant (hot potassium carbonate)
from fuel gas production are sent to a Stretford sulfur recovery plant.
The Stretford process was chosen for sulfur recovery  in this plant
because the total percentage of sulfur in the input stream is only 170.
It is not practical to use a Glaus Plant for less  than 10% H2S; capital
and operating costs increase drastically as throughput volume increases.
Roughly, 94% of the sulfur that comes into this  unit  is removed and high
quality elemental sulfur is  produced.  The effluent stream contains 741
ppm of sulfur as I^S and COS.  This stream is combined with  fuel gas and
is incinerated in the superheater fire box.

          The  acid  gas entering the Stretford unit is treated with a
water  solution containing sodium carbonate, sodium vanadate,  anthra-
quinone disulfonic  acid (ADA), citric acid, and traces of chelated
iron at 80°F and a  pH  of 8*5.  The H2S is oxidized by the vanadate to
form elemental  sulfur.  The  vanadium, which is  reduced by  the sulfur
reaction, is then reoxidized by the ADA to the  pentavalant state.  This
reaction occurs  in  the absorber using air as the oxidizing medium.  The
liquid containing elemental  sulfur passes to an oxidizer where ADA is
reoxidized  by  air.   The elemental sulfur/air froth overflows to a
holding tank.   The  reoxidized solution is recycled back to the absorber.
The sulfur  is  recovered from the sulfur froth by  filtration,  centrifugation
or floatation.   A typical Stretford solution purge contains sodium
salts of anthraquinone disulfonate, metavanadate, citrate,  thiosulfate
and thiocyanate  for which acceptable disposal must be arranged.

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                                  - 210 -
          A.3.3.3   Incineration

           The effluent stream from the Stretford sulfur plant  is  sent
 to incineration.  The incinerator superheater  fire box consumes  about
 13.7% of the product gas from the air gasification section.  This cor-
 responds to 44.9 MM scfd.  This stream which consists essentially of
 96% carbon dioxide will have a total flow of 367 MM  scfd on  a  dry
 basis, and a higher heating value of 29 Btu/scf..  Approximately  321  M
 Ib/hr of air will be required to  completely burn the Stretford effluent
 stream.  The combined effluents from incineration and superheating come
 out of a common stack.  The flue gas composition will be 62.5% CP2,
 7.47. H20,295 ppm 502, 76.5 ppm COS, 57.5 ppm NOX, 0.3%, 0?, and 29.87.
 N2•  The total amount of heat input into the incinerator/superheater
 is approximately 872 million Btu/hr.

          A.3.3.4   Power and Steam Production

          The power requirements for the gasification  complex are  met
 with a  boiler-gas turbine combined cycle fired with a  low Btu gas  produced
 in a Lurgi gasifier using air.  The Navajo coal is gasified  at about
 285 psig.  The method of operating the 10 gasifiers (9 on stream and 1
 on stand-by) is similar to that previously described for  the oxygen
 gasifiers.  The raw gas produced goes through a tar separation unit and
 then through an acid gas treatment section.   The raw gas  is  desulfurized
 using a hot potassium carbonate system.   The H2S and C02  from the  hot
 potassium carbonate system is sent to the Stretford unit  and combined
 with the Rectisol effluent in order to produce elemental  sulfur.

          The same  type of coal preparation mentioned  previously is used
 for this gasification.  The lock hopper vent gas is compressed and com-
 bined with the raw  gas prior to acid gas treatment.   In this system, hot
 compressed air and  steam are mixed and introduced through the bottom
 grate.   The ash is  removed and combined with the ash from the oxygen
 gasifier in the ash quench pond.  The ash slurry is transported back to
 the mine for ultimate disposal.  Approximately 327 MM scfd of dry  fuel
 gas  is  thus produced with a higher heating value of 230 Btu/scf.

          The flue  gas  is  used  in  a combined  cycle operation.  Approximately
 1/4  of  the total gas  is  sent  to  gas  turbines  to operate  the oxygen plant
 compressors.  The rest  of  the  fuel gas  stream is heated  in a fuel gas fired
 heater  prior to going  through  a  fuel  gas  expander. The  effluent  stream
 from  the expander is used  to  fire  the  fuel  gas  heater,  steam superheater,
 incinerator, and the power boiler.   The  fuel  gas distribution  is  given
 in Table 5.

          A.3.3.5  Raw Water Treatment

          Raw water is supplied to a 21-day hold up storage reservoir
 from a major source such as a lake or river.   The capacity of the  reservoir
 is 185 million gallons, and it occupies a site of 28 acres by 30 feet
deep.  The reservoir serves various functions  which include a place to
settle silt and provide water for fire control.   The reservoir  is   lined

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                                  - 211  -
 to avoid  seepage.  The rate of evaporation from the reservoir is  145 gpm
 Raw water strainers are placed on the inlet to the pumps going to the
 raw water treatment section.

           Approximately 4900 gpm of raw water are pumped out of
 the reservoir to the  treatment section.  An additional  600 gpm are
 recycled  from the methanation reaction and condensate  from the
 oxygen plant.  After  the  water is strained to remove silt,  it is
 pumped to a lime treater where it is treated and clarified.  The water
 in the clarifier is treated with alum and polymers.  The effluents from
 the clarifier are drained to a clear-well where they are  temporarily
 stored.   The  water from  the  clear-well  is  pumped  thr-v :gh  anthracite
 pressure  filters.  Approximately 4500 gpm are sent to  demineralization.
 Of this amount 3900 gpm go in to become feed water for steam production.
 The demineralization section blowdown consisting of 551 gpm is sent
 to the ash quench area.  Roughly 1/3 of the latter amount of water
 is taken  back to the mine as part of the a.sh slurry for ultimate dis-
 posal. The process condensate aerator is used to remove hydrocarbons
 as well as carbon dioxide which might be dissolved in the water.   The
 effluent  from the eoudensate aerating vessel is mixed  with the  deminera liiscr
 effluent.  The total demineralizer effluent flow rate  is therefore
 approximately 4500 gpm.  The pressure filter requires  roughly 300 gpm
 of back wash  which is sent back into the reservoir. The reservoir
 capacity  is sized so that all the silt can be collected  over the life
 of the project which  is  roughly 25 years.

            Approximately 2 tons per hour of water treating chemicals
 will have to  be disposed of  from the raw water treatment section.  Most
 of these  chemicals are sent to the evaporation pond and stored there
 for the life  of the project.  Roughly 1000 Ib per hour of water  treating
 chemical  wastes are chemicals associated with che demineralization section.
 The demineralization waste stream contains caustic,sulfuric acid and
 resins.  The  internal water cooling system also requires chemical treatment.

          The plant is designed to use 130,000 gpm of cooling water.
This system removes 1170 MM Btu/hr.  Water is designed  to leave the
cooling water system at 75°F and is returned at 93°F«  The cooling
water make-up requirement is approximately 2.27» of the  circulation or
2810 gpm.   Most of this make-up is supplied from the effluent water
treatment  area.  The cooling water is supplied by three 5-cell cross-
flow cooling towers.  The cooling water is treated with chemicals in
order to control corrosion, scale formation, plant growth and pH.
The cooling towers are designed for a wet bulb temperature of 67°F,
allowing an 8°F approach  to the designed condition.  The  cooling tower
blowdown,  consisting of only 210 gpm, is sent to  the evaporation pcnd.
Drift loss from the cooling towers is 260 gpm.  The chemicals  that are
added to the cooling tower include an antifoam package, a biological
control package,  a scale  and corrosion control package, and  sulfuric
acid for pH control-

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                                  - 212  -
               A.3.3.6  Gas Liquor Treatment and
                        Effluent Water Treatment

           The aqueous streams  condensed from the coal gasification and
    processing areas by scrubbing and  cooling the crude gas stream are
called the gas liquor.  Gas liquor is  collected in one central area coming
from gasification, shift, gas purification, and fuel gas synthesis.  Before
all of these aqueous streams are collected,a 11 of the tar, the tar oil
naphtha, and naphtha will have  been collected and stored for by-product
value.  Gas liquor streams will  contain all of the ammonia and phenols
that are produced in gasification.  In addition to these by-products,
the gas liquor will also contain carbon dioxide, hydrogen sulfide, trace
quantities of hydrogen cvanide,  and other  trace components:

           The incoming gas liquor stream  is filtered to remove  suspended
matter such as coal  dust and ash.  Disposition of the  filtered  solid
material  may  be  a  problem  as it x^ill  be contaminated with traces of
materials  from the  gas  liquor.   The  liquid  is then mixed with an organic
solvent (isopropyl ether) in an extractor in order to dissolve the phenol. The
Phenosolvan process is an integral part of  the gas liquor treatment
section.  The phenol solvent mixture  is collected and fed to solvent
distillation columns where  crude phenol is  recovered as the bottom product,
and  the solvent as the overhead product.  The solvent is then recycled to
extractors after removing some  of the  contained water.  The raffinate is
stripped with fuel gas to remove traces of  solvent which are picked up in
the  extraction step.  The fuel  gas is  scrubbed with crude phenol product
to recover the solvent.   Finally, the  phenol solvent mixture is distilled
in the solvent recovery stripper to produce the crude phenol product,  and
the  solvent is recycled to  the  extraction step.  The solvent free
raffinate is heated and steam stripped to remove carbon dioxide, hydrogen
sulfide, and ammonia.

           The effluent stream from  the  steam stripper is  air cooled
and  sent  to  the  deacidifier reboiler. The carbon dioxide  and hydrogen
sulfide  coming off the  reboiler are  recompressed and treated in the
Rectisol  process.   The  ammonia is collected as a 24.1  wt %  aqueous
solution.  Some  of the  vent gas associated with collecting the ammonia
in solution  is sent  to  incineration.   The  bottoms from the steam heated
ammonia  stripper go to  the effluent  water  treatment section after air
cooling.

          The effluent water treatment system, biological treatment
(biox), is used to reduce the phenol and ammonia concentrations in
the effluent from the gas  liquor so that the water can be reused as
cooling tower make-up.   The biox system is  also used to treat sanitary
sewage discharge and discharge  from  the API separator.   Approximately
2900 gpm of effluent come  from the gas liquor  treatment  area,and 110 gpm
come from all the other feed streams. These  two streams are treated
in series.  The first section  treats  the gas  liquor effluent in an
aeration basin followed by a settling basin.  The second section treats
the effluent from  tfaa   first section,as well  as  the 110  gpm from all other
streams in the same way. Thus,  the second  treatment area acts as a

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                                  -  213  -
polishing section for the effluent water treatment plant.  The purified
liquid from the polishing settling basin is filtered  and  sent to the
cooling tower sump.

               A.3.3.7  Ash Disposal

           Dry ash produced from both the oxygen blown gasifier and the
air blown gasifier is  quenched with demineralizer blowdown water.  The
water is used to reduce the ash temperature and to avoid dust  problems
in transporting  the ash.   Quenched wet ash is sent from the ash hopper through
a drag conveyor  to the belt conveyor for ultimate disposal to the mine.
Additional ash slurry  that is carried with the steam produced  in the quench
goes to a bin lock condenser as well as to a cyclone separator,  followed by
a droplet separator, and  finally through an ash slurry thickener.  The
de-watered ash is  then  conveyed back to the mine  on  the  belt conveyor
together with the  ash  from the ash hopper.   A  total  of 466,700  Ib/hr
of wet ash is transferred.   Of that amount  roughly 73,000  Ib/hr
is water, 20,000  Ib/hr  is  the equivalent  of dry ash  free coal, and
374,000 Ib/hr is  ash.   The sulfur content of this material  is
approximately 0.05%.   In addition to the  ash,  some spent chemicals and
sludge from the water  effluent treatment  plant  are also  sent to the mine
for burial.  The  total  quantity of additional material will not add  more
than 0.5 wt  % to the mass going  back  to the mine.

A.4  COp Acceptor Process

     A.4.1  General

          This process makes synthetic natural  gas (SNG)  from lignite
by gasifying it with steam at 1500°F and 150 psig. Heat  is supplied
indirectly by circulating dolomite which also takes up C02 and sulfur.
After clean-up to remove dust and sulfur,  the gas  is  methanated, giving
a heating value of 952 Btu/cf HHV.  Since the gas  fed to  methanation
has a high hydrogen content, it requires no shifting  or C02 removal
ahead of the methanator.  It is compressed and  dried  to meet pipeline
requirements.  Figure A.4.1 shows the general flow diagram of the C02
acceptor process.

     A.4.2  Main Gasification Stream

          The plant is sized to make 250 x 109 Btu/day of synthetic
natural gas having a higher heating value  of 952 Btu  per  cubic foot
(262.6 MM scfd).   Total consumption of lignite  is  28,517  tpd of 33.67%
moisture content.  The preheated lignite fed to  the gasifier contains
.90% sulfur,  11.45% ash, and has a higher  heating  value of 11,120 Btu per
pound.

          A.4.2.1  Coal Preparation

          Large  storage piles are needed in view of the high lignite
consumption rate.  Tamping down of the storage pile as it is being formed
is one  customary  precaution to prevent dusting and fires, but facilities
and plans are also needed  for extinguishing  fires  if  they occur.

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   Raw
 Lignite
   Feed
COAL
PREP.
                        Preheated
                        Lignite
                                  GASIFIIR
GASIFICATION PROCESS
                          Steam
                           Acceptor
                                               Raw
                                               Gas
                                              HEAT
                                            RECOVERY
                                                                   Cooled
                                                                    Gas
                                                                              SCRUBBER
                                                                                         Scrubbed
                                                                                          Gas
                      ACID GAS
                       REMOVAL
                                                                                                               Low S
                                                                                                               Low Btu
                                                                                                                Gas
                                                                                                                         MEIHANATOR
                                                                                                                                    High Btu
                                                                                                                                      Gas
                      COMPRESS
                        AND
                        DRY
                                                                                                                                                          Pipeline
                                                                                                                                                          Gas Product
                                          •Char
                            *• Acceptor
                                 REGENERATOR
                                               Flue
                                               Gas
                                             HEAT
                                            RECOVERY,
                                          |CO BURN-UP,
                                             DUST
                                            REMOVAL
                                                                     Flue
                                                                     Gas
 GAS
TURBINE
                                                                                                     AUXILIARY FACILITIES
SULFUR
PLANT
COOLING
 TOWER
                                                              Ash
                                                                                                                                                                        Si
                                                                     .ASH
                                                                    DESULF.
                                                                                                   WASTE
                                                                                                   WATER
                                                                                                  TREATMENT
                                                        MAKE-UP
                                                         WATER
                                                       TREATMENT
                                                                    Figure  A.4.1

                                                              C02 Acceptor  Process

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                                 - 215 -
          In the coal drying system,  hot combustion gas  is contacted with
the lignite feed.  General requirements are that the hot gas must be
introduced at less than 1000°F so that local over-heating does not occur
and release a large amount of volatile material  from the lignite.  Also,
oxygen content of the gas is held down to about  11% or  less by recycling
flue gas in order to meet safety requirements.

          Sulfur emission from the coal preparation section is decreased
primarily by using some desulfurized  low Btu gas from the gasification
section as fuel to the furnaces.  This gas is not methanated but rather
is drawn off after acid gas removal.

           To bring total sulfur emission down to the target 1.2 Ibs  S02
per MM Btu requires replacing 25% of the lignite fuel  with gas, corresponding
to 1.0 MM scfh or about 2.6% of the  total gas made by  gasification.  For
simplicity,  flue gas from the regenerator has not been added  to the  coal
preparation system.  Instead, flue gas from the dryer  is recycled  through
the furnaces to lower flame temperature and thereby reduce NOx  formation.
          Cyclones are used to separate ash from the hot  gas after
the furnace.  The hot gas of course picks up lignite fines  in passing
through the drying and grinding operation, therefore,  bag filters are
provided on the vent gas streams in order to recover all  dust.

          Separate bag  filters are provided on  the preheater.  This
operation consumes only 12% of the total  fuel for coal preparation,
and only gas fuel is  fired to it.  Consequently, all of  the fines
recovered from the gas  leaving the preheater are pure lignite and can
be used as  fuel for the furnaces if desired.

          To minimize loss of fines in the dryer, it can be operated on
a relatively coarse crushed lignite of say 1/2" size.  Then the fine
grinding can be carried out after the  dryer and before the preheater.
With this arrangement the very fine lignite is exposed to  a smaller
volume of gas so that the problem of dust recovery  is minimized.

               A. 4. 2. 2  Gasifier

          A stream of reject  acceptor  leaves  the gasifier at 1500°F,
cooled by a fluid bed cooler  that allows generating  steam for use in the
gasifier.   Final cooling uses a small  amount  of  water that  is evaporated
to dryness so that the material is  not  wetted.

          A. 4. 2. 3  Gas Cleaning

            Raw gas leaves  the  gasifier through  cyclones  which  remove
most of the solids.   It is cooled  in a waste heat boiler to make  steam,
and then scrubbed with  water to  remove essentially  all of  the  dust
using Venturi type scrubbers operating at the dew point  and evaporating
a small amount of water.  The gas  is further cooled to L50°F  in air-
fins so as  recover condensate and  conserve  cooling  water.

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                                 -  216 -
          A.4.2.4  Acid Gas Removal

          The raw gas contains 330  ppm of  sulfur, mainly as t^S.  Sulfur
removal is required before methanating, but it is undesirable to remove
much COn because it is needed to consume the available hydrogen during
methanation.  Various processes have been  reported that remove concentra-
ted streams of I^S while allowing most  of  the C(>2 to pass through the
absorber system.  A major problem in most  gasification systems is obtaining
a C02 stream free from sulfur that  can be  vented.   In the present case the
sulfur only has to be removed to a  level  sufficiently low to prevent over-
loading the zinc oxide guard boxes-

          Consideration should be given to using an  absorption/oxidation
process, such as Stretford, Takahax, IFF etc., on the  raw gas directly.
This would remove H2S only and convert it  to  sulfur  product  without
removing C02.

          As an alternative, it may be possible  to take  low  sulfur
ash from the ash desulfurizing system  and  add it to  the  scrubber
water so as to pick up sulfur.  Sulfur-containing ash  could  then be
returned to the ash desulfurizing system  for  regeneration.

          A.4.2.5  Methanation and  Compression

           Final clean-up of the gas  is accomplished in  a bed of zinc
oxide before methanation, to remove traces of sulfur and dust which
could foul the catalyst.  There may be traces of tar fog, naphthalene,
etc. present  in the gas,  in which case it would  be  desirable to include a
guard bed of activated carbon.  Methanation itself  generates no effluents
to the air-  After methanation the gas is compressed to 1000 psig and
dried, for example with glycol, before being sent  to the pipeline.

          A.4.2.6  Regenerator

           The  circulating dolomite is calcined at  1850°F to remove C02-
Make up dolomite is also added and calcined.   Heat  is supplied by burning
the required  amount  of  char with air  in a fluid bed regenerator operating
at 150 psig.  A small  content  of carbon monoxide is maintained  in the
outlet gas  in order  to avoid  forming  oxidation  compounds  of  calcium
which were found  to  cause  deposits.  The  flue gas is  removed through
cyclone separators to  take  out most of the dust, consisting  of  ash
residue from all  of  the  lignite  fed to the gasifier.  This  ash is removed
from the system by way of  a fluid bed  cooler, and sent  to the  ash desulfuriz-
ing unit.

           Gas from  the  cyclones passes to heat exchangers where steam  is
super-heated to 1200°F.  Additional steam is then generated in a waste
heat boiler.  At an appropriate point  in  this system  additional air
can be added to burn up  residual carbon monoxide (e.g.  before  the waste
heat boiler). This is necessary  to avoid  releasing  carbon monoxide  to
the atmosphere, and at the same  time  it provides a  convenient  way to
recover high level heat  by burning the carbon monoxide.   It  is known
that this reaction is reasonably fast at  temperatures above 1300°F.

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                                  -  217  -
The reaction raises the gas temperature by about  300°F, which  still  leaves
it lower than the regenerator  temperature of  1850°F,  consequently, deposits
should not be a problem.

           Flue gas then goes  to an  expansion turbine  to  recover  power.
For a turbine inlet temperature of 1000°F or  higher,  enough power can
be generated to drive both  the air compressor and the  product  gas
compressor.  In fact, there may be excess power available.  Noise
control for this area needs careful  attention in  a  final  plant design.

           The flue gas contains 470 ppm of total sulfur,  and can be
 discharged to the atmosphere, assuming that  the dust content,  nitrogen
 oxides, and odor are acceptable.  Further information is  needed on these
 critical items.  The NOX content may be low,  in view of the relatively
 low combustion temperature in the regenerator, but specific data should
 be obtained on this in the pilot operations-  For treating the ash to
 remove sulfur, a stream of C02 is needed, which might be  provided by
 scrubbing part of the flue gas.

          A.4.2.7  Ash Desulfurizer

            Ash produced from the coal is processed to give 98% sulfur
 removal by reacting  it in  a water slurry with C02 at  190°F.   Off-gas
 containing a calculated 27% H2S, 7% C02 and  66%  H20 is sent to a sulfur
 recovery plant such  as a Glaus, Stretford, or other type unit.   All
 of the gas streams in this system are contained  and should not cause
 environmental problems.  The  carbonated ash  is withdrawn as a 50% slurry
 in water and is not  expected  to create odors, although this should be
 checked out.  C02 required for this operation is  1530 moles/hr,  including
 25% excess over theoretical and can be provided  from  the regenerator
 flue gas.

     A.4.3  Auxiliary Facilities

          In addition to  the basic process, auxiliary  facilities are
required which will now be  discussed.

          A.4.3.1  Sulfur Plant

          H2S streams from acid gas removal and from the ash desulfurizer
go to a  sulfur recovery plant.  If a Glaus plant is used,  sulfur recovery
of about 97% can be achieved with three stages in "straight-through"
flow.   The tail gas still  contains about 3 tons per day of sulfur and
might be cleaned up,  although this gas volume  of 20 MM cfd is small  relative
to the  other effluents.  In fact, in this process as opposed to others, the
sulfur in the Glaus tail  gas represents such a small percentage of emitted
sulfur that  investments or  costs  for  sulfur removal could best  be
spent  cleaning  the  regenerator flue gas or dryer vent gas.  Thus,  the
Claus  tail gas  could  be incinerated and vented to the dryer stack and
a  small  additional  quantity of clean product gas added as  fuel to decrease
total  sulfur emissions to  acceptable levels.    No specific  preference
is  indicated  for sulfur recovery.

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                                 - 218 -
          A.4.3.2  Utilities

          Net utility requirements are low because  considerable power
is recovered by passing the regeneration flue  gas through  an expander
turbine.  Also a large amount of heat is recovered  in waste heat boilers
to generate steam, and on the methanator where the  heat  released by
reaction amounts to about 19% of the heating value  in the  entering
gas.  Most of this can be converted to steam by recirculating gas
from the reactpr through waste heat boilers.  Under development are
alternative techniques using a fluid bed or liquid  slurry  reactor  that
should be more efficient.

           A utilities balance for the process indicates that the
process is self-sufficient in steam and power, so that no utility
boiler is required for normal operation.  It is likely that a more
definitive and optimized utility balance will show  that  it is possible
to make more steam and power than  consumed by the gasification plant,
so that these could be used for shops, mining operations,  offices  and
general off-sites.  For example, 1.65  million pounds per  hour of  steam
at 150 psig is used in the gasifier.  This could be generated at
a higher pressure such as  600 psig and run through  bleeder turbines
down to 150 psig, while generating by-product power at the rate of
about 40,000 kW.

           In the utilities area,  the main cooling tower has by far
the largest volume of discharge.  It  is, therefore, critical from
the standpoint of pollution.  In this particular case it is not expected
to contain significant amounts of undesirable contaminants.  The cooling
water circuit is  clean and should not contain ash or objectionable
materials such as phenols, oil, or H2S.  Normally a certain amount of
leakage can be expected on exchangers using cooling water.  Since  the
process operates mainly at 150 psig pressure,  this  should not be a
major item.  Also, most of the cooling water is from steam condensers
on drivers rather than on  oil, sour water, etc.

           Total  cooling water requirement is modest considering the
plant size.  Effluents to  the air  from this cooling tower amount to
457,000 Ibs/hr  of water evaporated,  plus 43,000 Ibs/hr of estimated drift
loss or mist.  Flow of air through the tower is 15,000 MM cfd.

          The drift loss or mist will contain dissolved solids which
can result in deposits on  the ground  and on nearby equipment, and  in
some cases drift  loss has  caused icing problems on equipment and public
roads in the winter.  With any cooling tower,  the problem of fog formation
must be assessed, since under certain conditions the moisture condenses
and the resulting plume can be a problem if it affects public highways.
Reheat of the stack gas is one way to reduce fog formation, but is in-
efficient.  In planning the layout of the plant facilities, these  aspects
should be given careful consideration, and every effort made to avoid
potential problems by proper placement of the equipment.

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                                - 219 -
          There will also be evaporation and the possibility of odor from
 ponds and water treating facilities.  While most of the ammonia will
 be  recovered as a by-product, the waste water still will contain traces  of
 ammonia and probably also some phenols, hydrocarbons, etc.  particularly
 during start-up or during upsets.  These must be controlled and a biolo-
 gical oxidation (biox) pond for waste water treating is needed.  Depending
 upon pilot plant results with regard to tar and hydrocarbons produced, it
 may be necessary to provide an oil separator ahead of the biox unit,
 and possibly a froth flotation separator.

 A. 5 BIGAS Process

     A.5.1  General

          The plant is sized to make 250 million scfd of pipeline gas by
 gasifying coal with steam and oxygen.  The design includes shift conversion
 and methanation to give a gas with a heating value of 943 Btu per cubic  foot,
 available at 1,075 psia.  Western Kentucky coal is used, and after cleaning
 and washing, the amount if 14,535 tons per day (at a nominal 8.4% moisture)
 which provides all of the fuel for coal drying and utilities production  in
 addition to the gasification requirements.

          A flow plan of the process is shown in Figure A.5.1.   It is
 convenient to subdivide the process into the following operations,  each
 of  which will be described in the following subsections:   (1)  Coal
 Preparation, (2) Gasification, (e) Quench and Dust Removal,  (4) Shift
 Conversion, (5) Acid Gas Removal, (6) Methanation, and (7) Auxiliary
 Facilities.

     A.5.2  Main Gasification Stream

          A.5.2.1  Coal Preparation and Drying

           This process section includes crushing, cleaning and drying as
 well as  a  storage pile with 30 days capacity.  Run of mine coal  feed
 amounts  to 23,243 tons per day.  This is crushed and coarse refuse is re-
 jected amounting to 4,804 tons par day.  The coal can then be sent to
 storage, or to the washing operation which rejects an additional  3,904
 tons per day.   Drained coal from washing, containing 8.4% moisture, is
 used partly as fuel to the utilities plant supplying steam for the pro-
 cess, while the remainder goes to the grinding and drying facilities.
 Here it is  ground to 70% smaller than 200 mesh, dried to 1.3% moisture,
 and sent to storage silos.  Some of the dried coal is used as fuel in
 the dryer,  amounting to 11,137 pounds per hour or about 134 tons  per
 day.

          Since the  gasifier operates at 80 atmospheres, it is necessary to
pressurize the coal  feed.   The  original design used piston feeders to push
the  coal into a high pressure  feed hopper  and is the system  used  in the
present environmental evaluation.   Subsequent work has indicated  that other
methods such as lock hoppers  or slurry feeding  may be preferable; however.
the  change would rnaka only minor modifications in effluents to the
environment, although thermal  efficiency would be lower than  for  the case
using piston feeders.

-------
RUN OF
MINE COAL

CRUSH
SCREEN
AND
WASH
CLEANED
COAL

GRIND
AND
DRY
GROUND
COAL

GASIFIER

RAW GAS __

QUENCH
&
SAND
FILTERS
CLEANED_GAS

CLEANED
GAS 	

SHIFT
&
COOL
SHIFTED GAS ^__
*-'
ACID GAS
REMOVAL
SCRUBBED GAS
.*•-*
METH.
DRYER


                                                 PIPELINE GAS
                                                                                           N3
                                                                                           O
WASTE
WATER
TREAT.
MAKEUP
 WATER
 TREAT.
COOLING
   TOWER
UTILITY
  BOILER
      Figure A.5.1

      BIGAS  Process

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                                       -  221 -
          A.5.2.2  Gasification

           The coal is gasified using steam and oxygen in a two zone reactor
 at 80 atmospheres.  Operation of the reactor is based on entrained flow
 rather than using a fluidized bed or fixed bed reactor.  Coal is fed
 to the top  1700°F zone where it mixes with steam and hot synthesis gas
 entering from the lower zone.  Conditions in this upper zone favor high
 formation of  methane,  with negligible amounts of tar or oil.  Although
 the volatile  content of the coal feed is completely consumed,  there is
 considerable  unreacted char remaining which is carried out with the gas
 and recovered by cyclones following the reactor.

          The char is  recycled by means of lock hoppers to the lower
 gasification  zone where it is reacted with steam and oxygen at 3000°F
 A special char feeding system is provided, since it is indicated that
 a reliable  and very uniform feed rate must be maintained,  so as to avoid
 conditions  that could  give excessive flame temperatures.   Synthesis gas
 is formed and passes to the upper reactor as  described earlier.   Slag  is
 withdrawn from the bottom,  quenched with water,  and removed by way of
 lock hoppers.   Stoce it has little or no combustible content,  it  can be
 discarded (fro* an energy viewpoint).

          A.5.2.3  Quench and Dust Removal

           Hot raw gas from the gasifier passes to cyclone  separators which
 remove most of the char and solid particles in the gas. Quench water  is
 added to the  cyclone in order to moderate the temperature,  and additional
 quench water  is added in a quench vessel after the cyclone separator.

           The quenched gas still contains some dust that was not removed
 by the cyclones, but must be removed so as not to plug the fixed bed of
 shift conversion catalyst.  Rather than scrub the dust out with water,
 which would require considerable cooling,  the dust is filtered out
 at high temperature using sand beds.  These operate in parallel  in a
 cyclic manner.  Pressure drop will build-up during the onstream cycle,
 and the bed is cleaned when necessary by back flushing with clean gas
 so as to lift and agitate the sand particles.  Entrained dust  from back
 flushing is then returned to the gasifier where it leaves  with the slag.

          A.5.2.4  Shift Conversion

          After dust removal,  the gas next goes to a shift converter where
 carbon monoxide reacts with steam to form hydrogen and carbon  dioxide,  incre^
 the  ratio of  H2 to CO  to three to one as required in the final methanation.
A  sulfur resistant shift catalyst must be  used,  resulting  in relatively
 low  activity  compared  to those used on sulfur free gases.   A large excess
of steam is maintained to give 50 mol.  °L steam in order to  facilitate  the
desired  reaction and to prevent  catalyst degradation or carbonaceous
deposits.   Steam conversion in this shift  reactor is  about  27%.

          After  shift  conversion,  the gas  is  cooled to remove  most of  the
remaining moisture.  This,  of  course,  produces  sour water  containing H2S

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                                - 222 -
and ammonia and possibly traces of cyanides,  phenols, etc.  It is con-
veniently disposed of by using it as part  of  the quench water, and thereby
provides steam required for shift conversion.   One  advantage of this
specific design is that a very large quantity of sour water can be dis-
posed of by injecting it into the hot gas  for quenching.  A further
advantage is that no facilities are then needed for generating steam used
in shift conversion, and neither are exchangers needed for cooling the hot
raw gas from the gasifier.

          A. 5. 2. 5  Acid Gas Removal

          Removal of all  sulfur compounds is needed to meet pipeline  gas
specifications  and  to protect the methanation catalyst.  The bulk of  the
sulfur, as well as  CO  ,  Is  removed using  the proprietary Benfield process
based on hot carbonate  scrubbing.  Two  separate absorber towers  are used
in series.  The first of  these produces a gas relatively high  in sulfur
content, about  8% H S,  to facilitate sulfur  recovery in  the Claus plant.
T-he second absorber is  for final cleanup  of  sulfur from  the gas  and for
CO- removal.

          Most of the C02 is removed in  this  second absorber and vented
 to  the air; however, this C0£ vent stream contains excessive amounts of
 EyS, namely 3400 ppm, and further processing  is  needed  to clean it up.
 Therefore, adsorption using molecular sieves  has been provided to recover
 the H2S content and send it to the Claus sulfur  plant.  Gas leaving the
 hot carbonate scrubbing system used in the present design contains
 moisture, most of which is removed by cooling the gas ahead of methanation.
 This is a clean condensate which can be used  for boiler feed water make-up.
           Gasification can produce  many compounds  in addition to
 such  as  cyanides  and  thiocyanates as  well  as  large amounts of ammonia.
 There are  also various sulfur compounds, particularly carbonyl sulfide
 and some carbon disulfide.  It is essential to completely remove all of
 these before methanation .in order to  protect  catalyst activity.
 Most  of  the  ammonia and compounds that are highly  soluble in water will
 be removed in the condensation after  shift conversion.  Hot carbonate
 systems  for  acid  gas  removal have the important advantage that they do
 remove carbonyl sulfide.  Amine systems, in general, do not remove carbonyl
 sulfide, and noreover react irreversibly with cyanides thus requiring purge
 of the chemical solution.

          A. 5. 2. 6  Methanation and Drying

           Clean synthesis  gas is methanated in this section to increase
 the heating value, of  the gas up to  pipeline quality.  The reaction of
 CO with  3  volumes of  H£ to make methane and water  can be carried out in
 a fixed  bed  of nickel catalyst. A  guard bed of zinc oxide ahead of the
 reactor  removes traces of  sulfur compounds in order to protect the
methanation  catalyst.   Mathanation  is a highly exothermic reaction,
 releasing  about 20% of the heating  value in the reacting gases.  Reactor
 temperatures  of 500°F at the inlet  and 850°F at the outlet are maintained
by recirculating  some of the gas leaving the reactor through exchangers

-------
                                    - 223 -
 to  generate  high pressure steam.   Methanation is  carried out  to  a high
 conversion so that the residual CO content is no  more  than the 0.1 Vol. 7,
 specified for pipeline quality gas.  Residual hydrogen content is 5.1 Vol. 7..
 Since methanation generates a considerable amount of water, this is
 recovered as clean condensate upon cooling.   More complete'drying of the
 gas is  then  carried out using a glycol system to  meet  the requirement
 of  7 Ib  water maximum per MM scf in. gas.

          A.5.3  Auxiliary Facilities

           In addition  to the  gasification  system,  auxiliary facilities are
 needed  to make the plant complete and self-sufficient.  A Glaus plant is
 included  to  make by-product sulfur from the H2S that is recovered in acid
 gas removal.  The basic Glaus plant will not  give adequate  sulfur recovery
 or  clean-up, since the feed gas will contain  no more than  157. H2S, therefore
 tail gas  clean-up was  added.

           A  conventional air  separation plant is  included  in the base design
 to  provide oxygen needed for  gasification.  It does  not generate contaminated
 waste  streams, but it  is a large  consumer  of  utilities  and  therefore has
 an  important effect on thermal efficiency.

           As would be  expected, the process uses  large  amounts of steam
 and electricity.  All  utilities needed to  make the plant  self-sufficient
 are provided in the design, including high pressure  and low pressure steam,
 electric  power generation, water  make-up treating, circulating cooling
 water,  and waste water treating.   Fuel requirement  for these has been
 been included on the basis that coal would be used for  fuel.  Since the
 coal has  a high sulfur content, pollution control  will be needed on
 these fuel consumers.   The simplest approach  is to add flue gas clean-up
 so  that coal can still be used as fuel,  and a number of processes are
 available.   An alternative would be to use  low sulfur, low Btu gas made
 in  the  process  for fuel in utilities generation and in coal drying.

           The particular study includes utilities requirements for offices,
 shops,  laboratories, and cafeteria (e.g. 50,000 Ib/hr of  steam for heating
 buildings).   These are not always included  in similar studies of other
 processes; therefore,  caution is  required  in  making  comparisons with other
 studies.

 A. 6  HYGAS Process

     A.6.1  General

           The process makes  250  MM scfd of pipeline  gas (SNG)  froa
 Illinois  No. 6 coal by gasifying it with  medium  Btu gas (mainly CO plus
 H2  and  steam) in a series  of  countercurrent  fluidized zones.  Residual
 char is then gasified with oxygen and steam  in a bottom zone to provide
 gas  for gasification in the upper zones.   Carbon content of the rejected
 char may  be  10-30 t/t.  %.

           Raw gas is cleaned-up,  shifted,  and aethanated.  Operating
pressute  is  sufficiently high so  that compression of  the product gas is

-------
                                - 224 -
 avoided.   The  method of pressurizing coal feed involves slurrying  it
 with light oil by-product, pumping to high pressure,  and evaporating  the
 slurry to dryness by direct contact with hot raw gas  in a fluidized bed.

           A block flow diagram of the processing steps is shown in
 Figure A.6.1.  The process can conveniently be sub-divided into a  sequence
 of operations, each of which will be described in the following sub-
 sections:   (1) Coal Preparation, (2) Gasification, (3) Quench and  Dust
 Removal,  (4) Shift Conversion and Cooling, (5) Acid Gas Removal,  (6)
 Methanation and  (7) Auxiliary Facilities.

      A.6.2  Main Gasification Stream

           A.6.2.1  Coal Preparation

           These facilities  include storage and handling,  crushing,, and
 drying.   It is  assumed  that cleaned coal is delivered^  the separation
 of refuse and washing having been done at the mine  or  elsewhere with
 suitable  disposal of waste,  and environmental controls*   Coal feed,
 amounting to  17.517 tons/day (6.48% moisture), is received and 30 days
 storage is provided.  Since the storage pile is very  large,  roughly 15
 acres at  25  ft high, protection will be needed to control dust nuisance
 due to wind, while rain run off should be collected and cleaned up to
 supply makeup  water for the plant.

           Crusning is the next step in coal preparation,  to reduce the
 coal feed to minus 8 mesh.   Crushed coal is then dried  to negligible
 moisture  content in a fluid bed drier fired with part  of  the low Btu. gas
 produced by the U-Gas system.   The latter also supplies clean gas fuel
 for generating  utilities, and consumes 22.5% of-the total coal used by
 the plant.

           Dried  coal going to gasification is pressurized by mixing with
 oil to form a  slurry which is pumped to about 1200 psia.   Theoretical
 power for pumping is about 4500 horsepower.  Oil is vaporized and  re-
 covered when the slurry is subsequently dried.  Sufficient oil is thereby
 recycled  to  give a slurry containing 35% coal/65% oil, and cooling is
 provided  so  that temperature of the recycle oil is 400°F.

           It should be emphasized again that this specific study case
 does  not  include pretreating to destroy caking properties of the coal
 feed.

          A.6.2.2  Gasification

          The HYGAS reactor has four zones, through which the coal passes.
These include an initial drying zone, followed by gasification zones  at
 increasing temperature and severity.  Slurry feed is  dried in the first
 zone  at 600°F using heat in the raw gas.  Vaporized oil is condensed and
most of it is recycled to slurry preparation, but part of it is withdrawn
as net product.

-------
Cleaned Coal

Coal
Preparation
t '

Coal _
I
\
Slurry
Preparation
X. t_
Coal
Slurn^


Gasificatic

t t
Raw
^ Has .^


Oil
Quench
Cooled
Gas ^

Shift

Shifted
Gas

Scrub

Clean
Gas ^

Acid
Treat
Sulfur
Free
Gas

Me thane

J. t f . J t 1
Pipeline
,
-------
                              - 226  -
          Dry coal then flows  to the next bed at 1250° where partial
 gasification occurs, then to a bed at 1750°.  Finally the char passes
 to the bottom zone where steam and oxygen are added for  final gasifica-
 tion.  Residual char rejected  from this lower zone may contain 10-30%
 carbon, corresponding to 2-7%  of the original carbon contained in the
 coal feed.  The char is slurried in water, depressured,  and discharged
 through lock hoppers.

          The countercurrent  contacting between gas and char provided by
this niultibed arrangement results irx a considerable saving in oxygen.  Of
the total methane in the product, 58% is fenced in tha gasifier by the
favorable effects of high pressure, temperature gradient, and the  contri-
bution from volatile natter in the coal feed.

          A.6.2.3  Quench and  Dust Removal

          Raw gas leaving the  drying bed of the gasifier at 600°F, is
 cooled to 400°F by contact with a recirculating oil stream, whereby
most of  the oil is  condensed out and returned to slurry preparation,.
Temperature is  maintained high enough to avoid condensing water which
could  cause emulsion, problems;  moreover, the steam is  needed for the
subsequent  shift reaction.   Heat removed in this cooling operating can
be used  to  generate low pressure steam by recirculating the 400°F oil
 through waste heat  boilers.

          When  the  oil  is condensed upon cooling, most of  the dust in,
the raw gas leaving the drying bed will  also be  removed.   Since the
condensed oil is recycled"and used for slurryiag coal  feed, the fines
will also be recycled and buildup in concentration, unless some provi-
sion is made  to purge them from the system.

          A.6.2.4  Shift Conversion and Cooling

          The next  step in gas  handling is shift conversion,  to react
part of tha CO  with steam and thereby increase the H2/CO ratio to 3/1
as needed for methanation.  A sulfur resistant shift  catalyst such as
cobalt-molybdenum is used, and  one-third of the raw gas bypasses the
catalytic reactor.   The catalyst is  also exposed to oil vapors contained
in the gas, and operates at about 700°F.

          After  shift conversion, the gas is cooled to condense most of
the moisture. This  sour water is cleaned up for reuse by extraction and
stripping,  which operations will be described later.

          A.6.2.5  Acid  Gas Treatment

          At this point, the gas still  contains various  contaminants
that must be retsavedj  such as:  H2S, COS,  C02,  and condensable hydro-
carbons.  The required  cleanup is accomplished  by  scrubbing with
refrigerated-niathar.ol, using the Rectisol  process.  Gases containing
the  sulfur  compounds removed in the Rectisol unit  are sent  to a Claus
plant  for sulfur recovery.  Tha Claus plant also provides incineration
of COS and  combustibles on this stream.
-------
                                 - 227  -
          Most of the C02  is  renoved as a separate stream In the Rectisol
regeneration, and indicated  to  be discharged tc the atmosphere.   However%
this vent stream is  shown  as  containing over 2.0 vol.  % of combustibles»
most of X7hich is ethane; consequently, it will require further cleanup
or incineration.  While sulfur  content is indicated to be low, nil IbS
and 30 ppm. COS, other detailed  evaluations of similar  Rectisol applica-
tions show that additional controls will be needed.

          It is not clear that any one  simple process for acid gas treatneat
available today can simultaneously meat the targets of a highly concentrated
stream to the sulfur plant, together with a C02 waste stream that is clean
enough to discharge directly to the atmosphere, without further treatnent
such as sulfur cleanup or incineration.  Therefore it appears that addi-
tional facilities will be needed, such  as adsorption by molecular sieves
or activated carbon.

          A guard bed, for  example of zinc oxide,  is used to remove re-
maining traces of  sulfur in the clean gas,  so  as  to protect the methana-
tion catalyst, which  is  extremely sensitive to  sulfur poisoning.  Reheat-
ing is needed since  the guard bed operates at about 600°F, and can be
provided by  heat  exchange with gas leaving the methanator.  Such preheat
is  also  needed to  initiate the Eethanation reaction when this is carried
out in a fixed bed of  catalyst.

          A.6.2.6  Methanation and Drying

          Fixed bed  catalytic reactors with  conventional nickel base
catalyst are used to react CO and H£ to form, methane and water.   Operat-
ing temperature is 550-900°F.  Outlet gas at 900°F is  recycled to the
inlet through waste  heat boilers which generate steam,  thereby recover-
ing the  large exothermic heat of reaction.  Keat release amounts to
954 KM Btu/hr, which can generate about 1 million Ib/hr of high pressure
steam.

          Water formed  by  the methanation. reaction is  condensed and re-
covered when the product gas  is cooled, providing 200s000 Ib/hr of clean
condensate suitable  for boiler feed water sakaup.   Final drying of the
gas  is effected by scrubbing with glycol, to meet pipeline specifications
of  7 lb/MM scf.  The product  specification of 0.10 vol. % CO maximum is
met  by providing effective  control of methanation and  excess hydrogen,
leaving 6.5 vol.  % hydrogen in the product gas.   High  heating value is
then 960 Btu/cf.
-------
                                _ 228 -
     A.6.3  Auxiliary Facilities

          To make the plant complete and self-sufficient, various
utilities and auxiliary facilities are needed  in addition to the main
gasification process.  A Glaus plant is used for sulfur recovery on a
concentrated stream from acid gas removal, with tail gas cleanup by
incineration followed by scrubbing with sulfite to remove S(>2» using
the Wellman-Lord process.  The Rectisol design basis provided shows
29.8 vol. % H2S in the feed to the Glaus plant, while at the same
time the CC>2 vent gas contains no H2S and 300  ppm of carbonyl sulfide.
This would represent a very desirable high concentration of feed to the
sulfur plant together with complete removal of E^jS from the C02 vent
gas, although the latter contains an excessive amount of COS plus 2
vol. % combustibles, so it would require further treatment.  However,
other data on similar designs do not support the excellent separation
assumed in the HTGAS design; consequently further investigation and
evaluation are called for.

           Oxygen for gasification is supplied by a conventional air sep-
aration plant.  While it  does  not generate contaminated waste streams,  it
is a large consumer of  utilities, with a correspondingly large impact on
thermal efficiency for  the overall process.

          Large amounts of steam and power are needed in the process.
These are supplied by a utilities system fired with clean gas fuel manu-
factured by the U-Gas process being developed  by The Institute of Gas
Technology.

          In the U-Gas process,  coal feed goes first to a pretreating
reactor to destroy caking properties.   Here it is contacted with
air  at  750-800°F in a fluid bed to give partial  oxidation, accompanied
by a decrease in volatiles.  A very large aaount of heat is released,
which is used to generate  steaa.   Hot char then  goas to a second  reactor
where it is  gasified with  steam arid air at 1800°F and 300 psia in a
fluid bed.   Off gas from pretreating,  with a high heating valua of only
39 Btu/CF, contains tar and sulfur,  so it is mixed with hot gases  from
the  gasifier in order to destroy the tar.

          Sulfur removal is provided at high temperature by contacting
the gas with a "molten metal," which is regenerated in a separate zone
by reacting with air to form a  concentrated S02 stream that is sent to
the sulfur plant.

          After further clean  up by cooling  to  condense water and"by
scrubbing, the gas is used as  clean fuel for coal drying, furnaces, and
gas turbines.
-------
                                 - 229 -
          A combined cycle system is used to maximize efficiency By first
burning the high  pressure fuel gas from the U-Gas  unit for use in a gas
 turbine,  and  then discharging the hot  exhaust to a boiler furnace which
 supplies  process steam.  Combined cycle systems are a very effective way
 to  supply by-product povrer for  the oxygen plant compressors and for
 generating electricity.

          Water treatment is an important part of  the process.  A
 Phenosolvan unit is used in water treatment.  Treated water from the
 Phenosolvan unit then passes to a sour water stripper which removes
 ammonia as a by-product, and I^S  which is sent to  the sulfur plant.

           Other  auxiliary  facilities include treatment of makeup water,
 boiler feed water preparation,  storage of by-product oil, phenol, ammonia,
 and sulfur, as well as ash disposal, and  a cooling water circuit x/ith
 cooling tower.  The waste water is treated  in a biox unit before sending
 it  to  cooling  tower makeup.

 A.7 U-Gas Process

     A.7.1  General

           In the  U-Gas process, pretreated  coal is gasified with steam and
 air in a  fluidized solids system, at  1900°F and 350  psig to make 840 MM
 scfd of low Btu clean gas fuel (158 Btu/scf) suitable for use in a
 combined  cycle power plant.  Coal feed amounts to  7346  tons/day
 containing 6% moisture.
     A.7.2  Main Gasification Stream

          As shown in Figure  A.7.1,  dry coal crushed to 1/4 inch  and smal-
ler is fed to the pretreater  by means of lock hoppers.  Gases  from the pre-
treater flow into the gasifier  at a  point above the fluid bed,  for the
purpose of reacting and  destroying all tar and oil vapors that  are evolved
in pretreating.   A residence  time of 10-15 seconds is provided  on the
vapors.

           In the  fluid bed  gasifier operating  at about 2 ft/sec,  char is
 reacted to give a carbon level of  about 20%  in the ash.   Agglomeration of
 ash particles is accomplished in a "spouting"  zone or venturi  throat  at
 the bottom of the gasifier  maintained at sintering temperature by adding
 air and  steam.   Ash agglomerates of perhaps  1/8  inch  diameter  pass  down
 through  this throat, to be  quenched and removed  from  the system.   Dust
 recovered by cyclones from  the raw gas product is  also passed  through the
 agglomerating zone.
-------
Pretreate
( ^of
Dry Crushed 1
Coal Coal p«-| ""Gas
TI *— frpnf
r Cyclone
fgas f ~ •* 1550'F

»^ Generation
Prep. > crea:j v/ -» and
i |f Superheat
>»• solids * 	 *— 1
I'LZ3
^!
| Steam St*am
*••""• IT" Qw:"er
to Coal Air ^ J
Dryer '
1 ' Water
Settler!
1

Char
Water
Treating
r
Figure A. 7.1

Hot Gas

Air
Cooler
Cooled Gas^






Cooling
Tower

Waste
Water
Treating
Gas to

s
s°2[_
Sulfur

teat
Glaus
Plant
Tail. Gas
Cleanup
Low Btu Clean
Product Gas
' t
\
O
L 1
U-Gas Process
-------
                                  - 231 -
          Raw  gas  Is  cooled in a waste heat boiler to make high pressure
steam,  follov7ing by additional heat recovery to preheat boiler feed water.
Air cooling  is then used to bring the gas down to scrubbing temperature.
The water scrubber removes  dust and ammonia primarily, together with
unreacted steam.   Gas liquor from the scrubber is processed in a sour water
stripper to recover ammonia  and  remove H2S.  The treated water is
recycled to  the cooling  tower or used to  slurry the ash  being  returned
to the mine  for disposal.

          In this  particular design,  water is indicated  to be  recycled to
extinction within  the process,  in which case there would be no net water
discharge that might  cause  environmental  concern.  However,  there will be
soluble salts  (e.g.,  sodium chloride  and  sulfate) introduced with the makeup
water, plus  volatile  elements from gasification (chlorine,  fluorine,  boron,
etc.) that will accumulate  and must be purged from the system.   It is
obvious that some  water  must be discharged.

          Sulfur is removed from the  cooled  gas using the Selexol process
based on a glycol  type solvent, which can remove I^S and COS from the gas.
About 60% of the C02  is  left in the gas,  but the solvent does  dehydrate the
gas.
          Clean, low Btu  gas from the  Selexol unit is available to use
as fuel, or in a combined cycle  system.  The H£S stream from solvent
regeneration is indicated to contain 16.6% H2S, and is sent to a Glaus
unit for sulfur recovery. Tail  gas cleanup by the Wellman-Lord process
is included to give 250 ppm  S02  in the final gas released  to the atmos-
phere.

          High heating value of the total gas produced is 5533 MM Btu/hr,
but part of  the gas is needed to'"supply requirements of  the process.  Net
gas available  from the process is 5060 MM Btu/hr, equivalent to a potential
power generation of 593,000 KW at a nominal 40% efficiency. Of the total
gas produced,  6.7% is consumed in the process to supply  fuel to the coal
dryer and  tail gas incinerator on the sulfur plant, plus a combined cycle
system  supplying plant electricty and power for air compression.  In addition,
steam is generated from  waste heat in the process, but all of  this is used
within  the plant,  partly to drive the air compressor.

     A.7.3   Auxiliary Facilities

          Auxiliary facilities  are required  in addition  to the basic process,
su.ch as coal handling and storage.  Coal  preparation will include drying and
crushing,  as well  as  coal cleaning unless this is provided elsewhere.  Ash
handling and disposal  are also  needed,  with  means to drain the ash slurry,
recover the water  for reuse,  and transport the drained ash to  the mine or to
a landfill area.  The  Claus  plant for sulfur recovery includes tail gas
cleanup by scrubbing with sodium sulfite  using the Wellman-Lord process,  but
sulfur storage  and  shipping  facilities  are also needed.
-------
                                 - 232  -
          Waste water treatment employs the Chevron process to recover
by-product ammonia,  and makes  it feasible to reuse the water.   While
not included in the  original design, a biological oxidation system (biox)
is needed to give adequate  cleanup of the water for return to  the  cooling
water circuit.   In addition, to prevent buildup of sodium salts etc. ,
some water will have to be  discharged from the plant.

          The  plant may be self sufficient  in steam.and power during
normal operation, but  in order to  start  it  up a furnace or other method
for heating is  required, together with startup steam and power.  Fuel for
startup probably  should be oil rather than  gas or coalj so as Co avoid the
storage problem with gas,  or  the environmental problems with coal due to
sulfur and ash.

          Makeup  water must be brought in and treated" to make it suitable
for use in the  cooling water  circuit, while further treatment and cteinineral-
ization are required to supply boiler feedwater makeup.  Cooling towers are
used, and.are  a major  area of environmental concern.

          Other facilities required are  maintenance s'hops, fire protection,
warehouses, control laboratory, offices, cafeteria,  roads, trucks, etc.,
all of which must be taken into account  in.  assessing total environmental
impact.

A.8  Winkler Process

     A.8.1  General

          Lignite type  coal is gasified at about 1700°F and 2  atmospheres
in a turbulent  bed of particles using oxygen and steam, to make medium
Btu gas for fuel or  synthesis.  Some of the residual char is withdrawn
from the bottom of the  gasification reactor,  but most of it is blown
overhead as a result of the high gas velocity of 5-10ft/sec.  Most of the
entrained char  is  collected in cyclones for disposal, and the  gas  is then
cooled and cleaned up to remove residual dust and sulfur.

          An overall flowplan  of the process is shown in Figure A.8.1
The process can be subdivided  into a sequence of steps, each of which
will be described in the following sub-sections:  (1) Goal Preparation,
(2) Gasification,  (3) Cooling  and Scrubbing,  (4) Sulfur Removal, and
(5) Auxiliary facilities.

     A.8.2  Main Gasification  Stream

          A.8.2.1  Coal Preparation

          This section of  the plant includes  storage and handling,  drying,
and crushing.   It is assumed  that coal cleaning is  not required, or that
it is carried  out elsewhere.   Storage requirements will depend upon the
specific  situation  but may provide for example 30 days reserve.

          Drying  may not always be needed, since  it  is only necessary  to
avoid surface  moisture which  would cause problems  in handling and crushing.
-------
                                       Cyclone
                                                                                           To Plant FMl

Coal Feed



WINKLER
GASIFIER
Raw
G»«



HEAT
RECOVERY
Cooled
Gas
	 *"
  T
Steaa
   Oxygen
           Char
Char
SCRUBBER

Scrubbed
CBS

ELECTRO-
STATIC
FRKCIP.
Dust-free
Cat

AuurUK
REMOVAL

.



OXYGEN
PLANT





SULFUR
PUNT
_,___•




UTILITIES
FOR
START
UP




COOLING
TOWER




HASTE
HATER
TREAT




MMXDP
HATER
TREAT
hO
CO
CO
1
      Air
                          FIGURE A.8.1
                         WINKLER PROCESS
-------
                                  - 234 -
 Rotating tray dryers are used, and for this study a moisture removal of 5%
 on feed has been taken.  Cool gas is recycled to control gas inlet  temper-
 ature so as not to drive off volatiles.  Stack temperature  is  350-400°F,
 resulting in good fuel efficiency.  Coal can be used as fuel if  flue gas
 desulfurization is providedj but instead of this we have used  part  of the
 clean product gas as fuel to the dryer, with bag fibers on the  vent gas
 to control dust emissions.  Coal is crushed to 0-Srtun, all of which  is sent
 to the gaisifer feed hopper.

          A.8.2.2  Gasification

          Coal  from the feed hopper is  fed to the gasifier by means of
 screw feeders which give the necessary  pressure seal.  Steam and  oxygen
 are added near  the bottom of the reactor, maintaining the particles in
 a turbulent bed where reaction takes place without reaching temperatures
 that would  fuse the ash.  Typically, the bed may be at about 1700°F so
 that tar and heavy hydrocarbons are destroyed by gasification reactions.

           Considerable fines are  entrained from the bed,  consequently
 supplemental oxygen and steara are added just above the  bed  to  help consume
 them.  Heat exchange surface in the dilute phase above  the  bed removes heat
 for  temperature control and generates  useful steam.  Additional cooling of
 the  raw  gas to about 1300°F is accomplished by injecting  condensate just
 before the gas leaves  the reactor, in  order to prevent  fused deposits in
 the  downstream waste heat boiler.

          With  high reactivity coal,  conversion of carbon in  the coal
 feed may be 90%.  The remainder is in  the char by-product, and represents
 a significant loss of heating value unless  it is used.  Part  of  the rejected
 char is removed from the bottom of the gasifier, but most of  it  (ca. 70%)
 is recovered by a cyclone separator from the exit gases.

          Steam fed to the gasifier amounts to about 0.5 pound per pound
 of coal  feed, while steam conversion including moisture in the coal feed
 is 27%.   Oxygen consumed is 0.57 pounds  per pound of coal feed.

          A.8.2.3  Gas Cooling and  Dust  Removal

           Hot  raw gas leaving the reactor  at about 1300°F passes through
 an exchanger  to superheat steara,  followed  by a waste  heat boiler and a°cyclone
 to remove entrained  char.   The gas then goes to a  scrubbing tower where it
 is cooled by direct  contact with recirculated water.

          Most  of  the  particulates are removed by  scrubbing .and are separated
 from the  water  in a  settler.   They are included with  the char for disposal.
 Clarified water is cooled by indirect  exchange with cooling water before
 it  is recirculated to the  scrubber.  Net production of this water or gas
 liquor constitutes sour water  containing HaS, ammonia,  cyanides, etc-,
 present in the  raw gas.  The sour  water is processed  in waste water treating
 so that it can be reused.

          Since the scrubbed gas will  still contain a  snail amount of dust,
it is passed through an electrostatic  precipitator  for  final cleanup.  It
-------
                                   - 235 -
can then be compressed, further processed, or used as desired.   Traces
of contaminants may remain in the gas after scrubbing, such as  ammonia,
sulfur, oil, etc., especially during upsets or start up.   Depending on
the intended use, further cleanup may be necessary.

          A.8.2.4  Sulfur Removal

          The next  processing step on the gas  is  sulfur removal by
scrubbing with  a  suitable solution, such as amine, hot carbonate, or a  glycol
type solvent.   These can be regenerated by stripping to give  a concentrated
H2S stream  that is  sent to sulfur recovery.  For  this study scrubbing  with
hot carbonate is  assumed, since it will remove perhaps  half of the carbonyl
sulfide present in  the gas, and ssome 10% of the total sulfur  will be in
this form which is  not removed by amines.

     A.8.3  Auxiliary Facilities

          In order  to make a realistic and thorough  evaluation of environ-
mental impacts, a complete and self-sufficient plant must be  considered,
including items such as oxygen plant, sulfur recovery,  water  treating,  and
utilities generation.   Oxygen is supplied from a conventional air lique-
faction plant.  The amount is large, equal to 11,536 tons/day.   For sulfur
recovery, a Glaus plant is included with tail gas  cleanup using one of
the many processes offered for this service.   Gas  sent to the Glaus plant
from acid gas treatment contains about 15 vol.  °L sulfur compounds (mainly
H2S) and 85 vol.% C02 on a dry basis.  A small amount of  clean  product
gas is used as fuel to incinerate tail gas on the  sulfur  plant.

          A major item is waste water treating on  the gas liquor condensed
in the scrubber.  Flow rate is 11,140 tons/day,  and cleanup  is  required
to remove particulates, contaminants such as  compounds containing sulfur,
nitrogen, or oxygen, as well as arsenic,  cadmium,  lead, chlorine, fluorine,
and other trace elements that are known to be volatile at conditions in
the gasifier.   This water stream must be thoroughly cleaned  up  in any
case, and then represents a very desirable makeup water for  the plant.
Facilities include sour water stripping,  biological oxidation (biox),
and sand filtration prior to using it as cooling tower makeup.   Production
of phenols is expected to be relatively low at the  conditions used in the
gasifier (1700°F) so that solvent extraction to remove large  amounts of
phenols is not included at this time.

          Other auxiliary facilities include  treatment of makeup water
for the cooling water system and for boiler feed water, plus  plant
utilities such as steam and electric power.   It appears from the balances
that the plant should be self-sufficient in steam  and power  during normal
operation,  although provision must also be made for startup.  As far as
energy balances  and thermal efficiency are concerned, no  coal or clean
product gas need be consumed to generate plant utilities.
-------
               - 236 -
            APPENDIX B
Process Descriptions - Liquefaction
-------
                                 - 237 -



                                APPENDIX B

                   PROCESS DESCRIPTIONS - LIQUEFACTION


           In this appendix,  a general description is presented of the
 liquefaction processes studied.  The reader is referred to the individual
 process reports for details.

 B.I  COED Process

      B.I.I  General

           The COED process  being developed  by the FMC Corporation is a
 continuous,  staged fluidized-bed coal pyrolysis operating  at  low  pressure,
 and is designed to recover  liquid, gaseous, and solid fuel components
 from the pyrolysis train.   Heat for the pyrolysis is generated by the
 reaction of  oxygen with a portion of the char in the last  pyrolysis stage,
 and is carried counter-currently through the train by the  circulation of
 hot gases and char.   Heat  is also introduced by the air combustion of the
 gas used to  dry feed coal and to heat fluidizing gas for the  first stage.
 The number of stages in the pyrolysis and the operating temperatures in
 each may be  varied to accommodate feed coals with widely ranging  caking
 or agglomerating tendencies.

           Oil that is condensed from the released volatiles is filtered
 on a rotary  precoat pressure filter and catalytically hydrotreated
 at high pressure to produce a synthetic crude oil.  Medium-Btu gas
 produced after the removal  of acid gases is suitable as clean fuel,
 or may be converted to hydrogen or to  high-Btu gas in auxiliary
 facilities.   Residual char (50-60% of  feed  coal) that is produced
 has heating  value and sulfur content about  the same as  feed coal,
 so that its  ultimate utilization may largely determine  process viability.

           Fibure B.I.I shows a condensation of the main process train and
 Figure B.I.2 shows each unit in the complex.

      B.I.2  Main Gasification Stream

           B.I.2.1  Coal Storage and Preparation

                B.I.2.1.1 Coal Storage

           On-site coal storage will be required to provide back-up for
 continuous conversion  operations.   For thirty days storage, there might
 be  eight  piles,  each about 200 feet wide, 20  feet  high,  and 1000  feet
 long.   Containment of  air-borne dusts  is  generally the  only air pollution
 control required  for transport and storage  operations,  although odor may
 be  a  problem in  some instances.   Covered  or enclosed  conveyances  with dust
 removal equipment may  be necessary,  but precautions  must be taken against
 fire  or explosion.  Circulating gas streams which  may be used  to  inert  or
blanket a  particular operation or  which may issue  from  drying  operations
will generally require treatment to limit particulate content  before
-------
COAL
                                                                                                                  Is}
                                                                                                                  CO
                                                                                                                  oo
                                                Figure B.I.I


                                           COED Coal Conversion

                                             (All rates in tph)
-------
CCIkL
                                               PUNT
                                                                                                 /
CO
NO
                                            Figure B.I.2
                          COED Design Revised to Incorporate Environmental
                            Controls and To Include Auxiliary Facilities
-------
                                    - 240 -
discharge  to  the atmosphere.  Careful management and planning will
minimize dusting and wind loss and the hazard of combustion in storage
facilities.

           The as-received feed coal employed in  this design is  indicated
to have 10-14 weight percent moisture content.   The FMC process  basis
feeds coal of about 5.9 weight percent moisture  to the coal dryer ahead of
the first  pyrolyzer.  Hence the free or surface  moisture  is assumed  to
be removed in the  upstream coal preparation plant, although,  obviously,
the coal dryer proper may be arranged to  remove  a larger  fraction of
the original moisture.

           Illinois No. 6 coal is currently being supplied with about 17
percent moisture, but this moisture content is a function of the
operation  of  laundering equipment.  In a commercial conversion plant
situated at the mine, closer control of the delivered moisture would be
possible,  but with corresponding increase in energy consumption.

           The reactivity of coals may be markedly affected by exposure to
air, and water serves to seal available pore volume, retarding
oxidation.  Hence  the desired moisture content may be related to the
average time-in-storage in a particular facility.

               B.I.2.1.2  Coal Grinding

           Free moisture will be removed from feed coal by milling in a
stream of  hot combustion gases, as is practiced  in the FMC pilot plant.
Coal sized 16 Tyler mesh or smaller, but with minimum fines, is required
for the pilot plant, although other studies have indicated that particles
up to 1/8  inch or  6-mesh may be suitable.  In either case, the mechanical
size reduction of  an Illinois coal is expected to generate a considerable
quantity of -200 mesh fines, especially if appreciable drying accompanies
the milling operation.  The quantity of such fines has been estimated to
be 5 to 8  percent  of the feed, depending on the  type of equipment that
may be used and on the acceptable size range, screening or separation
efficiencies, and  the recycle rates employed around the mill.   Some small
fraction of these  fines will pass through the system with the sized coal.
Additional fines will be produced in the coal dryer proper, and the
ultimate consideration is that the total fines fed to the dryer or to the
first pyrolyzer shall not overload the cyclone systems provided to effect
their separation from the respective effluent streams.  There may also
be a relationship between the coal size fed to the system and the observable
filter rates on raw pyrolysis oil.  Fines generated in coal preparation,
amounting  to 5 percent of feed coal, will not be charged  to pyrolysis, but
will issue as a fuel product.  Coal fines would  probably be charged  to the
char gasification  system, if this facility is included.

          Clean product gas is fired in the mill heater (the basis
indicates  that natural gas is used).  About 110  tph of water must be
removed if coal is received with 14 percent moisture.  This may  require
the firing of 15-20 tph of product gas with 180-200 tph of combustion air
in the milling circuit.  Assuming a dry particulate separation  system
is adequate, bag filters might be used to recover fines from  the  vented
gas following primary classification in cyclones.
-------
                                 - 241 -
          Depending on water-use constraints, it may be desirable to
condense water from the vent gas for reuse.  This stream could be combined
with, or treated similarly to, gas issuing from the coal drying and
first-stage pyrolysis section, wherein the gas is scrubbed in venturi
scrubber-coolers.  The additional cooling requirement would be about
equal to that provided in the design basis for treating vent gas from
that section.  It is presumed, however, that the additional coal fines
separated from scrubber effluent by filtration in this way could not
be recycled to the pyrolyzer, and would issue from the system as sludge.
This sludge, containing 50 percent water, would preferentially be
charged along with char to gasification, if char gasification is included,
or might be combusted with char in a char boiler.  However, the dry
separation system employing bag filters would be preferred in the latter
case.
           Vent gas which issues from the bag filters from the milling
circuit may contain a significant carbon monoxide concentration,  depending
on the combustion parameters employed in the mill.  It may be necessary
to direct the stream to a boiler stack or incinerator to complete
the combustion.  Another possibility is to employ a noble-metal catalytic
afterburner, which would minimize the additional fuel  requirement,
to neutralize the stream.

          B.I.2.2  Coal Drying and First Stage Pyrolysis

          Clean natural gas is burned sub-stoichiometrically both to
dry feed coal  and to heat fluidizing gas for the first stage of pyrolysis.
Both  gas and air feeds to the heaters must be raised in pressure  to
match the operating pressures of the coal dryer and first stage,
nominally 7-8  psig.

           Coal is fed from storage  hoppers by  mechanical feeders  into
a mixing tee from which  it  is blown  into  the dryer with heated transport
(recirculated) gas.

           A cascade of  two internal gas  cyclones  is  provided  both  the coal
dryer  and the  first pyrolysis reactor.  Gas which  issues  from  the  first
pyrolyzer is circulated through  the  fluidizing-gas heater for  the  coal
dryer.  Gas which issues from the  coal  dryer passes through  an external
cyclone and is then scrubbed in  venturi scrubber-coolers, which  serve
to complete the removal of  coal  and  char  fines,  as well  as  traces  of
coal  liquids from the gas stream.  Fines  which  are recovered in  the
external cyclone are passed through  a mechanical  feeder  to  a mixing
tee where they are injected into the first-stage  pyrolyzer  by  recirculated
gas.  Water equivalent to that  introduced with  coal and  formed in  the
combustion processes is  condensed  from  the  gas  in the scrubbing  process.

           Scrubber effluent passes  into  a  gas-liquid separator,  and
the liquor stream is decanted and  filtered  to  remove  solids.     The
solids removed by filtration amount  to about one percent of the coal
feed, and the wet filter cake ±s recycled back to coal feed.  The decanted
liquor, except for a purge  stream which, along with the filtrate from the
-------
                                 -  242  -
 fines  filter, balances the removal of water from the section, is pumped
 back to  the venturi scrubbers through water-cooled heat exchangers.

           The  gas  stream which  issues  from the  separator,  except  for  a
 purge  stream  which  removes the nitrogen introduced  in the  combustion
 processes, is compressed  and  recirculated  to the gas  heaters.   This
 purge  gas  stream is essentially  the  only gaseous release  from this  section.
 Like the gas  stream envisioned for the  coal preparation section (see
 above),  it is indicated  to contain about 3.7 percent  carbon monoxide,
 and will probably require further treatment before  it may  be released
 to the atmosphere.  It may be possible to inject it into a boiler stack(s)
 along  with air  or oxygen  to reduce CO emission.  Alternatively the
 stream(s) may have to be  incinerated in specific equipment for this
 purpose  with  additional fuel.  The gas stream in this  case represents a
 loss of  combustible equivalent to about 230 MM Btu/hr.  It is indicated to
 be sulfur-free.

          B.I.2.3  Stages 2. 3. 4 Pyrolysis

           Coal which has undergone  first-stage  pyrolysis  (at  temperatures
 of about 550-600°F) is passed  out of the stage  into a mixing tee,  from
 which  it is transported  into  the  second stage  by heated recycle gas.
 Pyrolysis  stages 2,3, and 4 are  cascaded such  that pyrolyzed solids
 pass through  the stages  in sequence  in  transport gas  streams.   Super-
 heated steam  and oxygen  are injected into  the  last stage,  where heat is
 released by partial combustion.   Substantial recycle,  of hot (^^1550°F)
 char from  this  last stage is  used to supply heat to stages  .2 and 3,
 in which it otherwise serves  as  an inert diluent.  Similarly,  hot  gas
 which  issues  from the last stage  is  passed  counter-currently through the
 cascade, serving also as  the  primary fluidizing  medium in  these reactors.
 Stages 2 and  3  operate at about  850° and 1050°F  respectively.

           The  pyrolyzer  vessels  are each  about  60-70 feet in diameter.
 A total  of eight pyrolyzers in two trains   is  required to  process  the
 indicated  feed  coal.  All fluidized  vessels are  equipped with internal
 dual-cascade  cyclone systems.

           Gas  which issues from the second pyrolyzer passes through an
 external cyclone before being  directed  to  the  product recovery system.
 Fines  which are separated are  directed, along  with  product char from
 the last stage, to  a fluidized bed cooler,  which is used  to generate
 265,000  Ib/hr.  of 600 psia steam. First-stage  recycle gas is used to
 fluidize the  char cooler, and  the gas which issues from the cooler is
 directed back to the venturi  scrubbers  in  the  first  section after it
 has passed through  an external cyclone. Fines from this  cyclone are
 added  to the  char make from the  last stage.  Product  char is available
 at this  point at 800°F-

          Char  will be further cooled by cold-water exchange.   In the
pilot  plant,   a  two-pass screw conveyor,  in which cooling water  is supplied
 to a hollow screw, as well as to  the jackets of both  flights, is used  to
cool char to  about 100°F.  About  180,000 Ib/hr of 150  psia  steam may be
generated in  the commercial operation if suitable equipment  can be designed.
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                              -  243  -
          It has been assumed that clean product gas will be used to
superheat the steam and oxygen feeds to the last pyrolysis stage.   About
10.5 tons of gas is required, along with about 105 tons of air per hour.
The combustion products should be dischargeable without further treatment.

          B.I.2.4  Product Recovery System

          Gas from the pyrolysis section is cooled and washed in two
cascade venturi scrubber stages to condense oil and solid components
from the gas stream.  The gas which issues from the second scrubber gas-
liquid separator is passed through an electrostatic precipitator to remove
microscopic droplets and is then cooled to 110°F by cold-water exchange to
condense water.  About a quarter  of  the gas  stream is  compressed
and reheated  for use as transport  gas  in  the  pyrolysis  train.   The
remainder issues from the  system  as  raw product  gas, which  is  to  be
directed to an  acid-gas removal system.

          The oil and water condensed from the gas stream in the scrubber-
coolers  is decanted and separates  into three  phases:  a  light  oil  phase,
a middle (aqueous phase),  and  a heavy  oil phase.   The  oil phases  are
collected separately for  dehydration in steam-jacketed  vessels.   The
combined dehydrated oil is pumped  to the  COED oil  filtration  system.

          A recycle liquor pump takes suction from the middle phase in
the decanter.   Recycle  liquor  is  cooled  in cold-water exchangers  before
being  injected  into  the venturi  scrubbers.  Water condensed from the
incoming gas  leaves  the section  as a purge ahead of the recycle liquor
coolers, and  is indicated  to be  recirculated to the last pyrolysis
stage.

          The only major effluents to the atmosphere from this section are
the combustion  gases  from the  recycle  transport-gas heater.   Since clean
product  gas  is  fired  in this heater, the  combustion gases are
dischargeable directly-

          Vents from the oil decanters and dehydrators are directed to
an incinerator.   Under normal operation, and with adequate condensing
capacity in the vapor take-offs from the dehydrators, vent flow should
be minimal.

          B.I.2.5  COED Oil Filtration

          FMC has designed a filtration plant to handle the COED raw oil
output based on filtration rates demonstrated in its pilot plant.   The
system employs  ten 700 ft.2-rotary pressure precoat filters to remove
char fines from the raw oil  ahead  of hydrotreating.   Each  filter is operated
on a 7-hour precoat cycle,  followed  by a  41-hour filtration cycle.

          Both  the precoat and the raw oil to filtration are  heated, using
steam, to about 340°F.  Inert  gas  (nitrogen)  is  compressed,  heated, and
recirculated  for pressurizing  the  filters.  The  gas purge  from the system,
equivalent to the nitrogen make-up,  is directed  to an incinerator.  It  is
indicated to  contain only  trace quantities of combustibles  and sulfur.
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                                - 244 -
           Hot filter cake (38% oil,  52%  char,  10% filter  aid  at  350°F)  is
 discharged at the rate of about 15  tph,  and  is added  to the plant's  char
 output in the process basis.   FMC has  recently suggested  that filter cake
 will instead be recycled to coal feed.   Filtered  oil  is directed to  the
 hydrotreating facility.

           B.I.2.6  Hydrotreating

           Hydrotreating is employed  to upgrade the heavy  pyrolysis oil
 through the addition of hydrogen, which  serves to convert sulfur to
 hydrogen sulfide, nitrogen to ammonia, and oxygen to  water, as well  as  to
 increase the oil's hydrogen content  through  saturation  reactions.  In the
 FMC base design,  hydrotreating is performed  at a  total  pressure  of 1710-
 1720 psia.   Filtered oil from the filtration plant is pumped, along  with
 hydrogen from a reforming plant and  some recycled oil,  through a gas-fired
 preheater into initial catalytic guard reactors.   The guard reactors are
 intended to prevent plugging of the  main hydrotreating  reactors  by pro-
 viding for deposition of coke formed in  the  system on low surface-to-volume
 packing.

           The hydrotreating reactors are three-section, down-flow devices.
 The gas-oil mixture from the guard bed is introduced  at the reactor  head
 along with additional recycle hydrogen.   Recycled oil and hydrogen at
 low temperature (100-200°F) are introduced between the  catalyst  sections in
 the reactor to absorb some of the exothermic heat of  reaction.

           The hydrotreated effluent is cooled and flows  into a high-
 pressure flash drum, where oil-water-gas separation  is effected.  About
 60 percent of the gas which separates  is recycled by compression to  the
 hydrotreaters.   The remainder is directed to the  hydrogen plant.  A
 little less than half of the oil which separates  is recycled  to  the
 hydrotreaters.   The remainder,  taken as  product,  is depressured  into a
 receiving tank.  From the tank it is pumped  into a stripping tower, where
 clean product gas is used to strip  hydrogen  sulfide and  ammonia.

           Clean product gas is used also to  strip ammonia and H2S from
 the water which separates from hydrotreater  effluent.  Stripped water  is
 recycled  to the last pyrolysis  stage.  The gas effluents  from the stripper
 are directed to gas clean-up.

          The  only major effluents  to  atmosphere  from this section are
 the  combustion  gases from the hydrotreater preheater.  About  4.5 tph of
 product gas is  consumed,  along with  about 84 tph  of combustion air.   The
 products  of combustion should be dischargeable directly without further
 treatment.

          The process  basis includes a large cooling  requirement for
 hydrotreating effluent,  even though  preheating is supplied to hydro-
 treating  feed.  The  developers  have  indicated  that heat integration  should
be possible  in a  commercial installation to  some  degree.   The concern
involves possible degradation of  raw oil feed  in  a heating system which
is not precisely  controlled.  It  has been assumed that  380,000 Ib/hr of
600 psia steam will  be generated  in  this cooler.
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                                - 245 -
          The process  design basis does not provide for catalyst replacement
 in this  section.  Nor  are facilities included for presulfiding catalyst,
 if this  be required, or for regenerating catalyst.  .A major unresolved
 process  question  relates to the catalyst life that may be expected in
 commercial operation.   Pilot plant results show that activity drops after
 300-500  Ib oil/lb catalyst, but pilot-plant conditions are considered
 more rigorous than  should be the steady-state condition of the commercial
 unit.

          Since high-temperatures are required generally for the regeneration
 of the cobalt molybdenum or nickel/tungsten sulfide catalysts used;
 regeneration, if  it is  practiced, will occur off-site.  Moreover, it is
 assumed  that the  hydrotreaters will be designed to run continuously
 between  maintenance shut-downs.   It is not clear, however, whether two
 vessels  provided  are required to  treat the total stream, or whether one
 represents stand-by capacity.  Presumably some standby capacity will be
 required to permit catalyst changeout in the event of sudden activity
 loss or  development of  high pressure drop.

     B.I.3  Hydrogen Plant

          The COED process  gas product is indicated to be the source of
 hydrogen for the  hydrotreating of raw COED oil.  Steam reforming, cryogenic
 separation, and partial  oxidation have been investigated as means for
 recovering the required  hydrogen  from process gas, but the type of
 hydrogen plant that may  ultimately be used will be a function of the
 location of the plant  (or of the  coal type being processed) and of the
 product  sales slate, as  well as of the size of the installation.  For
 the present design, it  has  been assumed that the steam reforming case,
 as outlined by FMC,will  be  used.

          COED process gas  at 15 psia is compressed to 410 psia and
 passed through a  Sulfinol system  to remove C02 and H^S.  Regenerated acid
 gases are directed to  the sulfur  recovery plant.   The  cleaned  process gas
 containing about  1 ppm H2S  is divided into  a  fuel  gas  stream and  a  process
 feed gas stream.  The  process feed gas  is passed over  a  zinc oxide  sulfur
 guard bed to remove sulfur  traces, and  is then heated  by combustion of
 the fuel gas and  hydrogenated with recycle  product hydrogen to remove
 unsaturates.  Steam is  injected  and reforming- and  shifting occur  catalyti-
 cally according to:

            CH4 + H20  	^ CO +  2E2  (reforming)
            CO +  H20   	> C02 + H2  (CO shift)

C02 formed in the reactions is removed  in a second scrubber-absorber
and the  process gas is  finally methanated catalytically  to convert  residual
CO to methane according to  3H2 +  CO 	> CH4 + H20.   Resulting product
gas is available  at 200  psig.

         The  bleed  gas from the hydrotreating plant, containing  about
2 percent H2S and about  0.1 percent ammonia, is returned to the hydrogen
plant for reprocessing.   It may be preferable to first scrub this stream
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                                - 246 -
with water  separately to remove the ammonia trace.  About 3.5 tph of
I^S must also be removed from this stream, and the I^S residual, after
water  scrubbing, would be removed in an acid gas scrubber and directed
to the sulfur recovery plant.

          About 9.4 tph of hydrogen is consumed in hydrotreating 185 tph
of raw oil  (about 3000 ft-Vbbl).  it is of course not required that
initial acid gas removal be included in the hydrogen plant if acid gas
removal is  otherwise provided for the total product gas stream.   Moreover,
gas from the cleaning operation would be available at pressure so that
compression is required only from that pressure level.  About a  third of
the hydrogen requirement can be generated from excess CO and hydrocarbons
present in  the hydrotreating bleed stream.  About 25 tph of clean product
gas would be required additionally to be fed to the unit, and about 43 tph
of water would be consumed in the reformer.

          If a hydrogen plant design as described  is  employed,  it should
be possible to recover energy from the expansion of the  hydrotreating
bleed  gas through use of turboexpanders or equivalent facilities to
offset the  energy required for  recompression to the level required in
the hydrogen plant.

          The major gaseous effluents from the hydrogen  plant will be the
products of combustion from the fired heaters and  the C02 stream removed
from the processed gas after reforming.   Since clean  product gas is
consumed in the heaters, the products of  combustion should  be dischargeable
directly.   Some 23 tph of gas is fired.   About 60 tph of C02 will be
removed from the process gas, and this too may be discharged.

     B.I.4  Auxiliary Facilities

          B.I.4.1  Oxygen Plant

          The oxygen plant provides a total of 3760 tons per day of
oxygen from 440 MM scfd of air  to the last pyrolysis stage.  About 340 MM
scfd of nitrogen will be separated.   Some of this nitrogen may be used
to advantage in the plant to inert vessels or conveyances, to serve as
transport medium for combustible powders or dusts, as an inert stripping
agent  in regeneration or distillation, or to dilute other effluent gas
streams.  Nitrogen is also used to pressurize the rotary pressure raw-oil
filters.

          B.I.4.2  Acid Gas Removal

          The "Benfield" hot potassium carbonate system is assumed  in
the present study.  In the Benfield system, gas absorption takes place in
a concentrated aqueous solution of potassium carbonate which  is maintained
at above the atmospheric boiling point of the solution (225-240°F)  in a
pressurized absorber.   The high solution temperature permits  high  concen-
trations of carbonate to exist without incurring precipitation of bi-
carbonate.
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                                - 247 -
           Partial  regeneration  of  the rich carbonate solution is  effected
 by flashing as  the solution  is  depressured into the regenerators.   Low-
 pressure  steam  is  admitted to the  regenerator and/or to the reboiler to
 supply the heat requirement.  Regenerated solution is recirculated  to the
 absorbers by solution pumps.  Stripped  acid gas flows to the sulfur
 recovery  plant  after condensation  of excess x^ater.  Dapressurization
 of the rich solution from Che absorber  through hydraulic turbines may
 recover some of the power required to  circulate  solution.

           Raw product  gas  from  the product recovery section must be
 compressed for  effective  scrubbing.  The actual pressure level  that  will
 be employed will be  a  trade-off between compression costs and the
 utilities consumptions required otherwise.  Based on the concentration of
 acid  gases present in  raw gas,  a total  scrubbing pressure between 100 and
 200 psis  is indicated, whether  an  amine or hot carbonate system is employed.
 It is estimated that  the compressor driver will  require the equivalent
 of 500,000 Ib/hr.  of high-pressure steam  to handle the primary raw  gas
 stream.  Some 1,400,000 gph  of  solution must be circulated, requiring the
 equivalent of 5700 KW.  Some 450 MM Btu/hr is required for regeneration,
 supplied  as steam, and about this  same  cooling duty will be required.
 Additionally, some 100,000 Ib/hr of high-pressure  steam,1200 KW and 95 MM Btu/hr
 as low-pressure steam and as codling water will be required to treat the
 stripping gas stream.

           Clean gas may be directed to the various  fired heaters  throughout
 the plant, and  to  the  utility boiler (see below).  Product gas loss  into
 the regenerator off-gas stream  can be held to less than 0.1 percent  in
 proprietary configurations of the  process.  Moreover, it is possible to
 selectively remove H2S, if this is required to produce a suitable feed
 for a Claus sulfur plant.

           B.I.4.3  Sulfur Plant

           The type of sulfur plant that  will  be used has not been specified
 by FMC-  The combined  acid-gas streams resulting from treatment of raw
 product gas (pyrolysis gas) and hydrotreating bleed gas would appear to
 yield an  H2§ concentration  of  about 7  percent,  based on gas analyses
 presented in the FMC  design.   Additional concentraced H2S streams may
 result from treatment of  sour  water and  stripping gas.  FMC has indicated
 that  high-sulfur  Illinois coals will  yield  H2S  levels in the range of
 10-20 percent.

           For this study, it has  been  assumed that  acid gas will  be
 sufficiently high in l^S content  to permit use  of a Claus recovery system.
 Depending on the"acid gas removal process employed,  I^S may be  preferen-
 tially absorbed to increase its concentration in off-gas fed to the sulfur
 plant.  Claus units are operated  commercially with  entering H2S concen-
 trations  as low as 6 percent.   But these systems  generally employ oxygen,
 so that some of the cost advantage relative to  a  process like Stretford,
which does effectively treat low  concentrations,  may dissipate.
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                              - 248 -
          Tail gas from the Glaus  unit must be desulfurized, however.
Several processes have been developed for  this purpose.  FMC indicates
that the Beavon or Shell Glaus  Off-Gas Treating  (SCOT) process may be
employed.  It may also be feasible to employ  one of the flue-gas
desulfurization variants using  limestone to scrub tail gas, or processes
such as the Wellman-Lord S02 Recovery Process or the  IFF Secondary
Recovery Process may be applied.

          Most proprietary  tail-gas treatment processes operate to convert
S02 to H2S, which may then be selectively removed.   The Beavon system
catalytically hydrogenates  the S02 over cobalt-tnolybdate.   The catalyst
is also effective for reacting CO, which may be present,  with water to
form hydrogen, and for  the  reaction of COS and CS2 with water to form
ItaS.

          The hydrogenated  stream is cooled to condense water, and the H2S
stream is fed into a Stretford unit to recover sulfur in elemental form.
Treated  tail gas may contain less than 200 ppm sulfur, with almost all
of this being carbonyl  sulfide.  Condensate may be stripped of f^S and
directed to boiler feed water treatment.

          About 500 tpd of  elemental sulfur will be separated at the
sulfur plant, depending on  the sulfur content of the feed coal and on
the processing employed.  Total sulfur emission to the atmosphere may
be held  to less  than 200  lbs/hr., and the treated tail gas may be
directed to a boiler stack  for disposal.  The small air stream used to
regenerate the Stretford  solution in the  tail gas treatment plant may
also be  so directed.

          B.I.4.4  Utilities

               B.I.4.4.1  Power and  Steam  Generation

           The  choice  of fuel for  the generation of  the auxiliary electric
power  and  steam required by coal  gasification plants markedly affects
the overall  process  thermal efficiency.   It  is  generally  least efficient
to burn  the  clean product gas  for this  purpose.  On  the other hand,
investment  in  power-plant facilities,  including those required to handle
the fuel and  to  treat  the flue gas, is  generally  least when product
gas is so  used.

          COED  conversion generates a carbon-containing char equivalent
to some  50-60 weight  percent of  the coal  fed to pyrolysis.   Since this
is considered  a  fuel  product,  it  would  appear  that  it should be so
used in  the  plant proper.  However, it  suffers  as  an acceptable fuel in
this case  to about  the  same extent as  does  the  feed  coal, in that its
sulfur content is observed  to be about the same as that of feed coal.

          It has been assumed in this study that dirty fuels would not
be combusted in  the plant,  so that  clean  product gas would be used also
for the generation of steam and power requirements.  However, the
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                                 - 249 -


total utility balances require  some  additional  fuel  source.  Of  the
513 tph of contaminated product gas  issuing  from  the product recovery
system, there is net 171 tph of dry  gas  available  from  the acid-gas
removal system.  Some 25 tph is required  as  feed  to  the hydrogen
plant, so that the net available  gas for fuel is  146 tph.  The gas is
estimated to have a higher heating value  of  505 Btu per scf, so  that
the total available fuel gas equivalent  is about 4180 MM Btu per hour.

          Net steam requirements  for the  facility  total 783 000 Ib/hr
equivalent to a 1130 MM Btu/hr  fuel  requirement.  Net electrical      '
power requirements total 93,200 KW,  equivalent to 902 MM Btu/hr of
additional fuel.  The plant otherwise fires fuel equivalent to  2842 MM Btu/hr
in process heaters. Hence the  total  requirement,4874 MM Btu per hour,
cannot be supplied by the product gas stream alone.  The shortfall,
equivalent to  694 MM Btu/hr,  would  presumably  come  from char.

          We have considered that the 2032 MM Btu/hr fuel  equivalent
required at the power plant could be supplied by  the combinative firing
of product char and product gas in suitably designed boilers.   The fuel
requirement is such that if all of the char required to supply  the fuel
shortfall, about 30 tph, is fired in the power plant along  with about
47 tph of product gas, the sulfur emission would be such that  flue-gas
treatment would still be required.  About 2.1 tph of S(>2 would  be
emitted, equivalent to about 2.0  Ib/MM Btu, or above the level  permitted
by current standards for solid  fuels.

          Flue-gas treatment might be avoided if  char were combusted
with product gas throughout the plant.   This would require additional
investment in char handling and grinding equipment, as well as particulate
control on all fired heaters and  ash handling and  disposal facilities,
and may be less attractive than installation of flue-gas treating
facilities on the main boiler.   A variety of flue  gas treatment  processes
for particulate and SOX control are  under development,  and  significant
progress in this area may be expected by the time a commercial  plant  is
constructed.

          The coal fines estimated to be produced in the coal grinding
operation could supply the fuel shortfall.  This alternative may be
attractive in a commercial facility because there would be  no  additional
grinding debit and because the  fines production might be entirely con-
sumed.  However, such coal fines may  command a higher premium  as  a salable
fuel than char, and it may be preferred to charge the coal  fines  to char
gasification, depending on the  system used for that purpose.

          It has been assumed for the purpose of thermal efficiency
calculations that char will be  combusted in the plant to make-up the fuel
shortfall, and the process for  flue-gas  treatment has not been debited.
It is recognized that char treatment (gasification) is practically required
in a commercial design.
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                                 - 250 -
               B.I.4.4.2  Cooling Water

          A total of 200,000 gpm of cooling water is indicated to be
required for operating the FMC design.  Because most ot this requirement
is used for thermal exchange against relatively low-pressure streams,
the circuit should be relatively free from process contamination leakage -

          A design wet bulb temperature of 77°"F and an approach to the
wet bulb temperature of 8°F was assumed, with a circulating water
temperature rise of 30°F.   9,000 gpm  is required as cooling tower make-
up, equivalent to 4.5 percent of circulation.  Some 3,000,000 pounds
per hour of water  is  evaporated at the cooling tower, 600 gpm is lost
as drift, and 2400 gpm is withdrawn as blowdown, and is directed to the
water treatment facility.   The cooling  requirement  to condense water
from the coal grinding effluent gas  stream  has not  been included.  If
water availability is constrained, this may be attractive.

          It is probable  that  environmental  considerations and the
costs of water reclamation will  operate to restrict industrial water
consumption in most domestic  locations.  Hence a commercial design might
maximize use of air-cooled heat  exchangers,  reserving the use of cold
water only for "trim-cooling" or low-level heat transfer applications.
The overall economic balance will consider added investments in heat-
exchange and electrical hardware associated with air-fin usage,  as
well as investment in incremental electrical generation capacity.   Running
costs for the generation of power and for equipment operation would be
balanced against the net reduction in water treatment and pumping costs,
as well as the net reduction in water loss.

          On the basis that half of the requirement may be displaced
with forced draft air-cooled heat exchangers, the incremental electrical
power requirement is estimated to amount to 26,000 KW.  Added cooling
water requirement associated with the incremental power generation would
bring the net total cooling water requirement to an estimated 100,000 gpm,
so that water loss by evaporation might be reduced to about 3025 gpm at the
cooling towers.  Drift loss would amount to 300  gpm on this basis.  Blow-
down, or draw-off from the system, might be held to 1200 gpm.  There would
be a reduction in the power requirement for pumping cooling water.  On
the other hand, direct discharge of heat to the air environment in certain
locations may be less desirable  than  the humid ification associated with
cooling towers.
          The physical environmental situation at a particular site,
including water availability, climatic conditions, and available area,
will set limits on the designer's options  for heat rejection.  Other
means, such as cooling ponds, ma*y be practicable.  In very special situations,
it may prove economic to recover some of the low-level heat, as by circulation
in central heating systems to nearby communities or in trade-off situations
with irrigation water supplies, where hot  water may be used to extend  growing
seasons.  In all situations, the sociological impact of  the use of  the
environment will be an over-riding factor.
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                               - 251 -
               B.I.4.4.3  Water Treatment

          Analyses of the aqueous condensates produced in the pyrolysis
and hydrotreating plants have not been specified.  FMC has indicated
that these streams would be preferentially recycled to the last, or hottest
pyrolyzer, or to char gasification if it be included, after minimal pro-
cessing to strip ammonia and hydrogen sulfide.

          Recycle to a high-temperature char gasification system should
present no difficulty.  However, the long-term recycle to pyrolysis
requires additional  study,  since  temperatures  are  rather low and  there
is no basis on which to estimate  the degree of "by-pass" through  the
fluidized bed system.  Demonstration of  such  long-term  recycle, however,
would considerably reduce  investment in  treatment  facilities.   The
question may be largely academic, however, because it would  appear
that a large-scale installation,  unless  it were  arranged to  combust
char onsite or in an adjacent  facility,  would  include some form of
high-temperature char gasification.  We have assumed that pyrolysis liquor
may be recycled in the present design.

          Facilities required  to  treat water,  including raw  water,
boiler feed water, and aqueous  effluents, will include  separate collection
facilities:

             Effluent  or  chemical  sewer
             Oily water sewer
             Oily storm sewer
             Clean storm  sewer
             Cooling tower blowdown
             Boiler  blowdown
             Sanitary  waste

          Retention  ponds  for  run-offs  and  for flow equalization  within
the system will be required.   Run-off  from the paved process area could
easily exceed 15,000 gpm  during rainstorms.   Run-off from the unpaved
process and storage  areas  could exceed  80,000 gpm in a  maximum one-
hour period.

          Pretreatment facilities  will  include sour water stripping
for chemical effluents and Imhoff tanks  or  septic tanks and  drainage
fields for sanitary waste.  Gravity settling facilities for oily wastes
will include API separators, skim ponds, or parallel plate separators.
Secondary treatment for oily and chemical wastes will include dissolved
air flotation units, granular-media filtration, or chemical flocculation
units.  Oxygen demand reduction may be accomplished in activated sludge
units, trickling filters, natural or aerated lagoons, or by activated
carbon treatment.

          Boiler feedwater  treatment will in general involve use of ion-
exchange resins.   Reverse osmosis, electrodialysis, and ozonation may
find special application.
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                             -  252 -
          The COED plant may be able to take advantage of the properties
of  char and of attractive incremental costs for oxygen to assist its
waste water treatment.  Hence, the char produced by the process may have
some of the attributes of activated carbon, which has been shown to be
effective in the removal of a wide variety of the water contaminants
expected.

          Similarly,  oxidation of contaminants  in water  using oxygen,
and especially ozone,  is normally reserved  for  polishing drinking water
supplies because of high costs.   Direct  oxidation,  however,  is very
effective in reducing phenol,  cyanide  and  thiocyanate levels in waste
water,  and has particular advantage in that solids  concentrations
are not thereby  increased.

B.2 SRC Process
     B.2.1  General

          The SRC design is based on converting  10,000  tons/day  of  Illinois
type bituminous coal to net liquid products  amounting to 25,000  barrels/day
of heavy clean liquid fuel, of which 2/3  has  a  sulfur  content of 0.5%
while the remaining 1/3 contains about 0.270  sulfur.  The plant facilities
can be conveniently grouped into several areas including coal preparation
and handling, coal liquefaction and filtration,  gas cleaning and acid gas
removal, product handling and treating, char gasification,  hydrogen
production, and finally auxiliary facilities such as utilities,  oxygen
manufacture, water treating, and  a  sulfur plant.  A black flow diagram of
the process is shown  in Figure B.2.1.

     B.2.2  Main Liquefaction Stream

          B.2.2.1  Coal Storage and Preparation

          Run of mine  coal  is delivered in  rail  cars,  unloaded, and
mechanically stacked  in a  storage pile with 3 days capacity.  Coal con-
taining moisture is reclaimed from  storage  and conveyed to  a breaker.
Refuse larger than 3  inches in size from the  breaker is returned to  the
mine for disposal.  Coal smaller  than 3 inches goes to a second storage
pile with 8000 tons capacity, which feeds the washing  and cleaning opera-
tion.  Here it is processed through a series  of  jigs,  screens,  centrifuges
and cyclones, followed by  a roll  crusher to reduce it  in size to 1-1/4
inch or smaller.  Refuse from this  cleaning operation  goes  to a settling
pond to clean-up the water  for reuse.

          The next process  step is  to dry the washed coal,  using a flow
dryer to reduce the moisture content to 2.77o.  Part of the  dried coal
supplies the fuel required  for drying.  However,  the sulfur content  of
this coal is very high and  flue gas clean-up  would be  required  to  remove
sulfur as well as particulates.   An alternative  is to  burn  part of the
product gas as fuel in the dryer  and use bag  filters or a water scrubber
to control particulates.  Fuel consumption  can be reduced by using a
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        Figure B.2.1




SRC Coal Liquefaction Process
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                               -  254 -
 minimum amount  of  excess  air  and  allowing  a higher  moisture  content  in
 the flue gas.   At  the  same  time,  the  volume of  vent gas  to clean-up  is
 similarly reduced.   The dried coal is then pulverized to 1/8" and smaller
 and fed to the  liquefaction section at  a rate of 416 tph.

           B.2.2.2   Slurry Formation and Liquefaction

           The coal  is  mixed with  20,000 tpd of  recycle oil at 550°F,
 to form a slurry at 368°F.  Upon  mixing, moisture in the coal evaporates,
 is recovered in a  condenser,  and  is returned to the slurry,  so that  this
 water does not  become  an  effluent from  the plant.   The resulting  slurry
 is recycled through a  system  supplying  the high pressure feed pumps
 which deliver slurry to the reactor section at  1,000 psig pressure.  The
 slurry of coal  and  recycled oil is mixed with makeup synthesis gas and
 recycle gas containing steam  formed by  injecting and vaporizing sour water
 recovered from  the  products leaving the reactor.  This mixture of gas  and
 slurry goes through a  pre-heat furnace, where it is heated to 900°F, and
 then to a reactor which operates  at about  840°F and 1,000 psig, with about
 one hour holding time.  Total gas flow  to  the reactor corresponds to about
 45,000 cu.  ft.  per  ton of coal processed.  In this  particular design,
 synthesis-gas is used  in  the  reactor  rather than pure hydrogen.  Carbon
 monoxide in this gas is shifted to hydrogen in  the  reactor and, the water
 needed for this is  added  in the feed.   Conversion of coal is about 91%
 on a moisture and ash-free  basis.

           The stream leaving  the liquefaction reactor passes  to a  separator
 at 840°F from which  gas is  removed overhead and  recycled  to  the reactor
 after passing through  acid  gas removal.   Liquid  from the  bottom of the
 separator is cooled  and recycled in p*rt to the  slurry mixing t»nk where
 it is used  to suspend  the coal feed so that it  can be pumped  to high
 pressure.   This recycle portion does not have to be  filtered.  The
 remaining liquid from  the separator after the reactor goes to a rotary
 pre-coat filter where  ash and  solid particles are  removed.  Liquid pro-
 duct from the filter contains  about 0.5% sulfur and  constitutes the main
 clean liquid product from the process.  About one third  of it is  further
 processed by catalytic hydrotreating  with  pure  hydrogen  to reduce its
 sulfur content  to 0.2%.

           B.2.2.3   Hydrotreating

           The primary  product stream  of filtered  reactor liquid is
 fractionated to give naphtha  and  a light distillate, both of which are
 further'hydrotreated.   Heat for distillation is provided by a furnace
which  generates a  significant amount  of flue gas.   Since product gas  is
used  as  fuel, it should be  practical  to meet  the  emissions requirement
for  laree  stationary boilers  with regard  to  sulfur, particulates, NOX,
 and  CO.

          The product  hydrotreating section  also  uses furnaces for pre-
heating  before  the  reactor  and on stripping  the product.  The comment
made on  the distillation  furnace  applies here  also.  Hydrogen compression
is included in  this  section,  and  since  it  involves  high pressure, the
possibility of  leaks requires special consideration as discussed previously.
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                                 -  255  -
          When  the high  pressure liquid products are depressured  a
considerable amount  of dissolved gas is released, which should be recovered
or used for fuel.  Similarly,  when the sour water is depressured, gas will
be released which would  cause  a serious odor problem if vented to the air.
Facilities are,  therefore,  needed to recover this gas and send it to
the sulfur plant.

     B.2.3  Acid Gas Removal

          Separate acid  gas removal  units  are provided  on:   the  gas  recycled
to the reactor,  product  fuel gas,  after the gasifier, and in hydrogen manu-
facture.  Amine  scrubbing is used  to remove sulfur from the recycle gas to
aid desulfurization,  and on the  product gas so as to provide clean fuel for
use in the plant.  Scrubbing removes H2S which goes to a sulfur plant.  It
is expected that there will be  other forms of sulfur present such as carbonyl
sulfide  which will  not  be  removed effectively by amine scrubbing.  This is
particularly true for the gasification system supplying raw gas for hydrogen
manufacture since the high  CO content of the gas results in a high formation
of COS, as much  as 10% of the  total  sulfur content  in some  similar  systems.
This will be removed by  caustic scrubbing  but creates a  very large  amount
of spent caustic that needs disposal.   Some work has  been reported  on
hydrolyzing COS  etc.  to  I^S over catalyst,  prior to  amine scrubbing,  which
would improve the situation.   Scrubbing  the  raw  gas with hot carbonate
may be preferrable,  as it should remove  COS without  consuming  caustic.
Perhaps a better alternative is to use the low Btu gas  from gasification
as plant fuel where  the  clean-up requirements are less  stringent, and then
make hydrogen from product  gas  using well  demonstrated  technology.

     B.2.4  Hydrogen Manufacture

          In the section making pure hydrogen for hydrotreating,  all  CO
in the feed gas  is shifted  with steam  and  the C02 scrubbed  out using  the
proprietary Benfield hot carbonate process.   This makes  a concentrated
C02 stream which is  vented  to  the  atmosphere  (809 tpd C02>,  and assurance
is needed that  it is low enough in sulfur, mist,  and  chemicals, etc., to be
acceptable, and  that it  is  vented  in a way to avoid hazards.  One concern
is that various  sulfur and  other compounds  from  gasification may be removed
along with C02  and contaminate  the C02 vent  stream.   Additional  facilities
may be required  to clean up this stream, and  we  have  added  a scrubbing
system for this  purpose  to  recover sulfur compounds.  These  compounds are
then combined with the feed to  the Glaus plant for processing.

     B.2.5  Gasification and Slag  Disposal

         In this section, synthesis  gas  is made  by reacting a slurry of
the filter cake  with steam  and  oxygen  in a slagging gasifier.  The filter
cake contains residual ash  from the  coal  amounting to 713 tons per day,
together with 818 tpd of unreacted char,  and is  mixed with  1530  tpcl of
oil  to form a pumpnble slurry.   Oxygen consumption is 1964 tpd whllo the
total  steam rate to gasification is  1837 tpd  and the  steam  conversion
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                                - 256 -
 657o.   The gasifier  operates at 1700°F in the top zone, 3000°F in the
 bottom zone,  and  200  psig.  It is a modification of a system under
 development known as  BI-GAS.  Molten slag is removed at the bottom and
 quenched to form  steam which  is returned to the gasifier, while excess
 water forms a slurry  with  the fragmented slag so that it can be with-
 drawn.

           Of  the  oil-filter cake  slurry charged to gasification,  30% of
 it goes to a  top  zone where the  temperature is  1700°F.   Consequently,
 small amounts of  tar  or  oil and  soot may be present,  in which case additional
 recovery facilities may  be required due to  problems with exchanger fouling,
 emulsion, etc.  The design does provide a cyclone  to  recover dry char from
 the raw gas and recycle  it to the 3000°F zone,  since  the cake is  not
 completely gasified in one pass.   A venturi scrubber  is included  for final
 dust  removal.

           The main  effluents  to the air from this  section  are  from  two
 furnaces preheating the  feed  streams to gasification.   These  furnaces
 fire  clean gas  so that there  should be  no problem  in meeting  target
 emissions, as discussed  in the section  on Product  Handling and  Hydrotreating.
 One furnace preheats  clean steam  to 1050°F  for  feeding  to  the  top of
 the gasifier  along  with  30% of the slurry feed.   The other furnace heats
 recycle char  suspended in  gas and steam, for feeding to the 2000°F zone
 along with the  other  70% of the slurry  feed.

           Sour  water  from  scrubbing the raw gas contains sulfur compounds,
 ammonia,  phenols, etc.   This  stream is  treated before discharge to extract
 phenols,  and  goes to  a sour water  stripper  which removes light  gases
 that  are  sent to  the  sulfur plant.  It  then flows  through  oil  separators
 and to  a  biox pond.

           The  slag quenching operation is described in general terms,
 and  the  SOOO^F gasifier zone is segregated from the. water  slurry,
 quenching zone.  No  specific facilities are shown  for particle size
 control,  such  as grinding, and the system depends on the  shattering
 effect of quenching  to  form  a pumpable slurry.

          The design  provides a slag storage pile in the coal storage
area, prior to  back-hauling it to the mine.   Since the slag is removed
as a  slurry,   it will  have  to  be drained and stacked.  Some of the  slag
may be very fine, consequently there could be dust  problems when  it dries
out.  The extent of odors  and sulfur emissions in this operation needs
to be determined.   Also,  vater from draining must be recovered and  reused,
since it will contain considerable suspended solids.  It can be
recirculated   through  the storm pond,  provided this does not cause
secondary pollution problems  due to odors or leachable materials.

      B.2.6 Auxiliary Facilities

           In  addition to the  main process,  various  auxiliary  facilities
are needed,such as  the oxygen plant, sulfur plant,  utilities,  water
treating, and product storage, which must be considered  from  the
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                                - 257 -
 standpoint  of  effluents  to  the  air.  The  oxygen plant is a large consumer
 of power and therefore has  an important effect on  thermal efficiency and
 energy  consumption.   One approach  uses electric drives on the main air
 compressor, but  where clean fuel is  available a  flue  gas  turbine
 may  be  more attractive.   Or a high pressure bleeder steam turbine
 can  be  used, for example generating steam at 600  psig or  higher and
 depressuring it  through  the turbine  to  say 125 psig to supply  steam
 for  reboilers  on acid gas removal, preheating, etc.  When a  specific
 plant design is  made, it will be important to optimize the utilities
 system.

          The  sulfur plant uses a  Glaus  unit, with tail  gas  clean-up.
 Concentration  of H2S in  the feed is  only 7.7 mole percent, resulting
 in a low  sulfur  recovery on the Glaus  unit.  Therefore an efficient
 tail gas  clean-up system is needed and  there are  a number of available
 processes to choose  from.  The  design  is  based on using  the  proprietary
 Beavon  process to reduce residual  sulfur compounds to H2S, which
 is then removed  in a Stretford  type  scrubbing operation.   Other systems
 could be used  for tail gas  clean-up  such  as  the IFF, Takahax, Wellman-Lord
 or Scot processes.   Vent gas from  the tail  gas clean-up operation can be
 vented  to the  atmosphere without incineration in some cases.

          The  Stretford  type process uses a  scrubbing liquid containing
 catalyst to oxidize  H2S  to  free sulfur.   The  scrubbing liquid is then
 reoxidized by  blowing with  air,  and  precautions must be taken to avoid
 release of  odors  or  entrained liquid etc.  to  the atmosphere.   This air
 effluent should  pass through an incinerator  or furnace unless it is clear
 that H2$ and other emissions will  be acceptable.
          Product sulfur may be handled and stored as a liquid  in
 completely enclosed equipment to avoid emissions.  If it is handled
 and  stored as a solid, control of dusting will be required.

         The  largest volume  of discharge  to  the atmosphere  from  the
utility area  is  on  the  cooling tower.  Air flow through  it  is about
31,000 MM  cfd,  and  it  is  therefore  critical  from  the  standpoint
of pollutants.   It  might  be  expected  that  the  recirculated  cooling
water would be  perfectly  clean and  free of contaminants, however,
experience shows  that  there  will  be appreciable leakage  in  exchangers
and occasionally  tube  failures, especially with high  pressure operations
In the present  design  cooling water is exchanged  with oil,  sour  water,
raw gas, amines,  etc.;  therefore,  contaminants may get into the
circulating cooling water and then  be  transferred to  the air in  the
cooling tower,  which necessarily  provides  effective  contacting and
stripping.

          Cooling towers also have a potential problem due  to drift
 loss,  that is mist  or  spray which is  carried out  with the  effluent
 air.   Since  this contains dissolved solids it can result in deposits
when  the  mist settles  and evaporates.  In addition there is a
potential  plume or  fog problem,  if the atmospheric conditions  are
 such  that  moisture  in  the air leaving the cooling tower condenses
upon  mixing with cooler ambient  air.   This occurs whenever the mix
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                               - 258 -
temperature is below that corresponding to saturation.   Although
reheating the effluent air will prevent the plume,  it  is not normally
warranted and consumes energy unless it can be accomplished  using
waste heat.

         The utilities section includes a boiler to provide  steam
and electric power. It has a large gas effluent, so that
emissions of dust, sulfur, NOX and CO must be controlled.  The
large fuel consumption of the boiler has a correspondingly large
effect on thermal efficiency of the overall plant.

          Thermal efficiency of any coal conversion process  must take
into account the fuel consumed in utilities generation,  since this can
amount to 15-25% of the main process.  In general it is  desirable  to
burn low grade fuel such as char or coal rather than high value product
gas or liquid.  In the case of the SRC process its  purpose is to produce
clean boiler fuel so that it is reasonable to use this product to  supply
utilities fuel, as required.  It is important to achieve high efficiency
in generating utilities and the combined cycle is,  therefore, receiving
a lot of attention.  In the combined cycle, a gas or liquid  fuel is burned
at perhaps 10 atmospheres pressure, giving hot gases which are passed
through a turbine to generate electric power and then to a boiler  generating
high pressure steam.  Solid fuel, such as coal, can also be  used by
gasifying the coal and cleaning up the raw gas to provide low Btu  gas
fuel for the turbine.  Such alternatives need to be evaluated carefully
in each specific application in order to define the best combination.


          i?our water from liquefaction contains compounds with strong
odors, such as phenols, H2S, and ammonia.  In the waste  water treating
section, phenols, etc. are extracted from the sour water by contacting
it with a light oil, which is then recycled through catalytic hydro-
genation to destroy compounds containing oxygen or nitrogen.  The  raf-
finate is then stripped to remove. I^S, ammonia, and traces of oil  and
solvent which are disposed of to the sulfur plant.   Ammonia  might  be
recovered as a by-product.   However, most of the nitrogen  in the coal
remains in the oil product and,  therefore,  the production  of ammonia is
small.

          Depending upon the efficiency  of  the  extraction and  stripping
operations, the level of contaminants  in the waste water may be reduced
to a  level low enough to be acceptable without  over-loading  the biox unit.
An oil separator is provided ahead  of  the biox.  Except for  this  and the
biox unir, these facilities are  all  enclosed  in order to  avoid any direct
effluents to the atmosphere.  Sour water from the  gasification and product
hydrotreating areas is also stripped to  remove  HoS and  ammonia prior to
discharging to the biox unit.

          In view of the very strong odor  created  by phenols and  by
components in the sour water, careful  consideration should  be  given
to this in planning and designing  all  plant facilities.   All oil-water
separators should be covered to  contain  odors,  and it is  possible that
the biox unit will also need to  be  covered.   Further  experimental data
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                             - 259 -
should be obtained to define the requirements  for  this.  The SRC oil
product contains various oxygenated compounds,  including phenols and
cresols, as well as relatively large amounts of nitrogen compounds such as
pyfidine types.  These have very strong odors  and  can create problems in
handling and storage.

          If the product is solidified by cooling  in a  prilling  tower
with direct contact with air, obnoxious fumes  can  be formed  (similar
to those generated in asphalt oxidation). These cannot  be  discharged
to the atmosphere and might be incinerated, or gas recirculation could
be used with indirect cooling.  An alternative is  to solidify  the product
on a metal belt which is cooled by exchange with water.  Instead of making
a solid product, it could be kept hot above the melting point  and handled
as a liquid, in which case it will be important to exclude air from the
storage and handling facilities.  Tests on similar type materials have
shown that oxidation reactions induce polymerization, resulting in a large
increase in viscosity, and potential gum and asphaltic deposits.   Storage
tanks are needed with inert gas purge which is  vented to the incinerator
to control emissions and odors.

          This design has a rather large waste  water discharge amounting
to 30% of the make-up.  This includes boiler feed-water blow down,  cooling
tower blow down, sour water to biox, and the water from sanitary sewers.
The total waste water discharge is 1,064 gpm compared to the make-up of
3,626 gpm.  It appears that much of the water blow down could be treated
and reused without reaching excessive levels of dissolved  solids in the
cooling tower circuit.  Thus, the boiler blow  down of 120  gpm can be used
as make up  to  the cooling tower.  Evaporation  from the  cooling tower
is about  1800  gpm and it would be expected that the water  blow down rate
could be  appreciably less than the 600 gpm provided, without having too
much build-up  in dissolved solids.  The best disposition of  the
water effluent from the plant will depend upon its location  and  the
specific  situation.  It might be used to slurry the ash and  solid refuse
from coal cleaning for return  to the mine, or  it may be acceptable to
discharge it to a river.  Composition of the major components  in this
discharge water are needed in a specific case  in order  to  determine
whether the method of disposal will be satisfactory.

B.3  H-Coal Process

     B.3.1  General

           In  the H-Coal process, coal is reacted catalytlcally with hydrogen
 in a slurry system to  make synthetic  crude.  The process can also be  used
 to make low sulfur fuel oil by operating at lower severity.  For syncrude
 operation, reaction conditions are  about 850°F  and high pressure, such  as
 2000 psig.  Syncrude production is  91,240 barrells/day for the plant
 feeding 25,000 tons/day of dry coal to the  H-Coal reactor.  An overall
 flowplan  for  the  process  is  shown in  Figure B.3.1.

           An  ebullating bed reactor is used wherein the slurry of  coal
 and catalyst  in oil is agitated by bubbling hydrogen gas through it.  Size
 of the catalyst is large relative to  the coal,  so thati although  the catalyst
-------
                                   Dryer
                                    Vent
                                    Gas
                                                                                                                                                       To.Plant Fuel:
                                                  Coal to
                                                                                                              ___ Recycle Hydrogen
Vacuum Bottoms;

Oil
Carbon
Ash
Coal Feed
Illinois No. 6
10% Moisture
C
ms :

•> Gaslfi
f— +
\ A
earn
Oxygen N1(
1
Oxyger
Plant
1
^^ Coal
tion
oal _.



.. - Dust
^ Separatic
1
Ash
rogen Sulfur
\ t
i Sulfur
Plant

Utility Boiler
1 . Coal
^ feeding
dry coal
1
Recycle Oil
Sulfur

Slurry


Lique-
faction
1 t
Hydrogen



Gas
Cleanup
1 t 1
HoS Stream Steam Sour Water
Flue
Gas Ash Moist Air slowdown Water j^
t t f t t t

Utility Cooling
Boiler Tower

Waste
Water
Treating

Gas and Vapors




1 Slurry
Recycle
Oil *«•
Vent Gas:
	 «^_

•»-
C02
Hater
Sludge
t t
Makeup
Water
Treating
Ligh
~>

Separate
t Oil ,
1 '
A
Gas 1
r- <^ 1 .^
Net Clean
Fuel Gas
^Sour Water \
H2S Stream
Liquid |
tion 1
HeavyT Oil

""•• synthetic crude
Vacuum *~
Hstlllatiot
Bottoms Slurry
to Gasifler
Oil
Storage

                                       1            t      t
                      Air
                                       Stream
Coal  Limestone    Air    Makeup    Waste Water
                          Water
                                                                                                          Water
                                                                               Figure  B.3.1

                                                                Block Flow Plan of H-Coal Plant for Coal Liquefaction
                                                                                                                                                                             O
                                                                                                                                                                             I
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                             - 261 -
is fluidized, it is retained in the  reactor and is not  carried out with
the liquid  oil sidestream leaving the  reactor.  In addition, a gas stream
is withdrawn  separately from the reactor top.

          The following  subsections  describe the various  operations in the
overall plant.  These can be conviently  grouped into several  areas  covering
coal preparation and handling,  coal  liquefaction, gas  separation and. cleatxup,
liquid product recovery,  hydrogen  manufacture,  and auxiliary  facilities such
as utilities, water treating,  oxygen plant, and sulfur plant.  This grouping
will be followed through the report.

     B.3.2  Main Liquefaction Stream

         B.3.2.1  Coal Preparation  and Feeding

         This study assumes that cleaned  coal is delivered  to the plant,
consequently  the facilities and environmental concerns  associated with coal
cleaning will be at a different location,  and therefore are  not covered.
Coal cleaning generates considerable amounts of solid refuse to dispose of
and wash water to be cleaned up for  reuse.  A very large  coal storage pile
is included,  having 30 days supply for example.

           Coal  feed having a nominal 10% moisture is sent first to a dryer
where essentially  all moisture is  removed, and the coal is then crushed
through 40 mesh.   Crushed coal is  mixed  with recycle oil  to form a slurry
that can be  pumped into  the high pressure hydrogeaation system.  In addition,
part of the  dried  coal goes to the gasifier so that  hydrogen  production can
be increased to balance  consumption, and dried coal  also  supplies the fuel
used on the  utility boiler.

         B.3.2.2  Liquefaction Section

           The coal slurry, together  with makeup and  recycle hydrogen,  goes
to a preheat furnace and then to the H-Coal reactor  where 'hydrogenation takes
place in the presence of an ebullating bed of coarse catalyst particles.
About 96%  of the carbon  in the coal  is converted to  liquid or gas products,
while the  remaining carbon is retained in the ash which is withdrawn! as a
sidestreao from the reactor in the form  of a slurry  with  product oil.  Part
of this slurry  is  recirculated to  the bottom of the  reactor to maintain
desired flow conditions.

           Gases are withdrawn as a separate stream from  the top of the
reactor -  part  of  the  gas being recycled to the reactor  inlet after cleanup
to remove  sulfur compounds.  The remaining gas is withdrawn as a product
from the process,  and  part of it is  used to supply clean fuel to the coal
dryer, reactor preheat furnace, and  tail gas incinerator on the Glaus plant.
In the gas cleanup operation,  water  and  oil are condensed from, the gases
leaving the  reactor.  The resulting  sour water is sent to waste water
treating while the oil is combined with  the main liquid product.

          The naia oil product is  withdrawn from the reactor via a liquid
phase settling zone within the reactor so that the  large catalyst particles
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                               - 262 -
 are  separated from the oil product and retained in the reactor.  The with-
 drawn liquid contains ash and unreacted coal particles which are segregated
 by vacuum distillation into the heaviest bottom fraction of the oil.  This
 vacuum bottoms is used to make hydrogen for the process by gasification with
 oxygen and steam.

          Heat is recovered from the hot effluents leaving the reactor, and
 used to preheat feed streams or to make steam.  Hydrogenation is an exothermic
 reaction, giving an estimated heat release for this study case of 700 MM
 Btu/hr, corresponding to 7700 Btu/lb hydrogen consumed, which heat; is also
 recovered and used.

          B.3.2.3  Gas Separation and  Cleanup

          A gas and vapor stream is withdrawn froa the top of the liquefaction
 reactor,  above the liquid level.  It is substantially free of entraised
 liquid, and therefore contains little or no solids.  Upon cooling, oil and
 water condense out and are separated.  The sour water is sent to waste water
 treating, while part of the oil is recycled to fora a slurry with the coal
 feed and  the remainder of the oil is included in the final syncrude product.

          The gas after condensation is cleaned up to remove sulfur compounds
 which are. sent to sulfur recovery.  Part of the clean gas is recycled to the
 H-Oil unit to supply hydrogen, and the rest is available as byproduct fuel  .  .
 gas  or for plant fuel.  The process used for removing sulfur from the gas,
 is assumed to be scrubbing with an aqueous solution of amine, although hot
 carbonate could be used instead.

          B.3.2.4  Liquid Product Recovery

          A liquid  stream is drawn off separately from the reactor, consisting
 of a slurry of ash  and unreacted coal in heavy oil.  This slurry is distilled
 under vacuum  to produce a clean light distillate  oil, part of which is     ".
 recycled  for  slurrying the coal feed while the remainder is withdrawn as
 syncrude  product along with some of  the light oil condensed from the gases
 leaving the reactor.

          Heavy bottoms from the vacuum tower, containing ash and unreacted
 coal, is  used to make hydrogen  in a  partial oxidation gasifier.

      B.3.3  Hydrogen Manufacture

          A partial oxidation system is used for manufacturing hydrogen,
 consuming as raw material the slurry of vacuum bottoms which may otherwise
 present a disposal problem.  The developer has indicated that a Texaco type
 partial oxidation process is used, since this type of gasifier is exoected
 to be able to handle such a feedstock whereas some alternative processes
may  not be able to.
                                                                         *

          The amount of vacuum bottoms is not sufficient to make all of the
hydrogen needed, so some coal feed is also sent to the gasifier, adding to
the coal consumption -for the plant.  Oxygen for gasification is supplied by
an onsite oxygen plant, while the required steam is provided from waste
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                                 - 263 -
heat boilers.  The gasification reactor  operates at slagging conditions,
over 2000°F, and  500  psig pressure.

          Raw gas is  quenched and then scrubbed with water  to remove
particulatea including ash and soot.   Water condensed at  this point contains
a wida spectrum of contaminants including  ammonia, HCN and  other nitrogen
compounds, various sulfur compounds,  phenols,  etc., this  sour water is seat
to waste water cleanup.

          Sulfur  compounds are removed from the gas in the  next processing
step by scrubbing with amine.  Some C02  is also removed but this is
incidental.  Amine solution from the  absorber  is regenerated in a stripping
tower with raboiler.   The-sulfur containing gas stream from amine regeneration
is sent to a Glaus plant for sulfur recovery.  Tail gas cleanup is includad,
as is common practice, so that the sulfur  plant will meet emission require-
ments .

          The clean desulfurized gas  is  reheated and mixed  with supplemental
steam for processing  in the shift- conversion reactor.  After shifting, the
gas is cooled, and scrubbed to remove C(>2  using one of the  available  con-
ventional systems such as hot carbonate.  The  C02 stream  is vented to the
atmosphere as  a waste  product.

          Finally, the product hydrogen is compressed  and fed  to the
hydroliquefaction  reactor which operates at  about 2000 psig.

     B.3.4 Auxiliary  Facilities

          The discussion so far has described  the basic processing units
used in a plant for hydroliquefaction of coal.  In addition, auxiliary
facilities are needed such as an oxygen  plant, sulfur plant, and utilities
systems to supply steam,  electric power, and water.  Waste  water treating
is also required. In addition to contributing effluents  and emissions, these
auxiliary facilities  may also consume additional fuel in  the form of  coal
or clean products from the process.

          Oxygen is made by liquefaction of  air,  giving a waste stream
of nitrogen that is clean and can be vented  directly to the  atmosphere.
A sulfur plant is  needed to recover by-product sulfur  from the various
sulfur compounds  removed  in the gas cleanup operations on the H-Oil unit
and in hydrogen manufacture.  A Claus type sulfur plant is  used, with tail
gas cleanup in order  to meet  environmental requirements.  Total, sulfur
production amounts to 1295 tons/day.

          In order to make the  plant  self-sufficient, utility steam and
electric power are generated for use  in  the process so that purchase  of
utilities  is avoided.

          Utility steam is generated  at  1000 psig pressure and used  to
drive the turbogenerator and compressors.   In  some cases, bleeder  turbines
are used in order to  balance out the  generation and consumption of steam at
-------
                                - 264 -
 600  psig and 70 psig.   Coal  is  used as fuel in the utility boiler, on the
 basis  that stack gas cleanup will be provided to control  emissions of
 sulfur and particulates.   The amount of coal used in the  boiler is 3020
 tons/day on a dry basis,  giving 299 tons of ash to dispose of.

          Water is used for  cooling, primarily to condense steam from tur-
 bines  or on overhead condensers.  Cooling water is recirculated at 200,000
 gpm  through a cooling tower  where about three-quarters of the heat is
 dissipated by evaporation, and  the remainder is taken up  as  sensible heat
 of the air passing through.

          Waste water from the  hydroliquefaction section  contains a wide
 range  of pollutants including H^S and other sulfur compounds, nitrogen
 compounds such as ammonia, HCN,  pyridines, etc., phenols  and other
 oxygenated compounds,  plus suspended solids, oil, and tar.   It would not
 be acceptable to discharge such water directly from the plant; therefore
 it is  cleaned up and reused.  Cleanup of waste water involves the following
 operations:

          •  Settling and filtration to remove solids.

          *  Extraction of phenols using a suitable solvent.

          •  Soiir water stripping to remove H2S, NH3, and other
             low boiling materials.

          •  Biological oxidation (biox) to consume residual small
             amounts of various contaminants, which are converted to
             cellular sludge.             .    -

          •  Activated carbon adsorption, if needed, for final polishing.

          •  Possibly special treatment for trace elements.

 Asssonia will be. recovered as a by-product, amount-ing.to  205 tons/day while
 other  contaminants removed from the waste water, '.such  as  E^S  and phenols
 can  be sent  to the sulfur plant for incineration, or returned to the process
 where  they can be converted and destroyed.

          Treated waste water is used as cooling  tower makeup,  supplemented
 by boiler blowdown and fresh water.  Slowdown from the cooling tower con-
 stitutes the net water discharge from the plant amounting to 5100 tons/day
 (850 gpm).   This blowdown,  together with drift loss from the cooling tower,
 serves to purge dissolved solids from the system  so as to prevent excessive
 buildup in the cooling water circuit.

          Fresh water makeup is supplied to the cooling  tower, as well as
 to boiler feed water preparation.  Combined,  these  amount to 37,680 tons/day
or 6300 gpm, which is the overall water consumption of the plant.  Treating
of makeup water includes lime softening and clarification, plus demineraliza-
tion on the portion going to boiler feed water.
-------
              - 265 -
              APPENDIX C






Process Descriptions - Coal Treating
-------
                                - 266 -



                               APPENDIX C

                 PROCESS DESCRIPTIONS  - COAL TREATING


           In this  appendix  on  Coal  Treating, only  the Meyers  Process has
 been investigated  in depth.  A summary description is included here.
 For a more detailed  description,  see the process report.

 C. 1  Meyers Process

      C.I.I  General

           In the Meyers process,  the pyrites in the coal  are  removed by
 reaction with ferric sulfate in  a solution containing ferric  and  ferrous
 sulfates and sulfuric acid.  The  ferric ion is  continuously regenerated
 by reaction of oxygen arid ferrous ion.   The elemental sulfur  product is
 extracted with an  organic solvent.   The iron product from the pyrites  is
 removed as solid ferric and ferrous sulfates.

           A block  flow diagram of the  basic Meyers process is shown in
 Figure C.I.

      C.I.2  Main Process Streams

           C.I.2.1  Coal Storage and Preparation

           ROM coal,  8 in. X 0, is received at the  plant and stored.  Three
 days storage (7920 tons, wet)  has been suggested.   This quantity  of coal
 would probably be  stored in silos with nitrogen blanketing.   It would
 probably be advisable to store more coal (e.g., 30 days supply) in a
 "permanent" pile for emergency use.  This  pile  could be covered with
 asphalt and used only in case  of  mine  outage.

           The  ROM  coal is conveyed  to  pulverizers  where the coal  is reduced
 to  80% less  than 200 mesh.  The coal from  the pulverizers  is  then fed  to
 the Reaction Section.

           It is  not  necessary  to  dry the coal as it is subsequently
 slurried  in  a water  solution.  It is assumed that  covered  conveyers will
be  used throughout to minimize dust problems.   The coal dimunition
equipment  can be enclosed, with air vented to bag  filters.  This  will
reduce  outside noise as well as provide for dust containment.

           C.I.2.2  Reactor  Section

           Pulverized coal is mixed  with recycled leach solution in a flow
through mixing tank.   The mixing  vessel is maintained at  about 210°F.  The
slurry  is  continually pumped from the  mixing vessel to one of 10  reactor
vessels.
-------
Feed Coal
                Coal Storage and
              Preparation Section
Reaction
 Section
Sulfur Removal
   Section
                                                      Iron Sulfate
                                                      Recovery Section
 Product
 Drying
 Section
                                                                                                                                                  Product
                                                                                                                                                   Coal
                                       Sulfur
                                      Recovery
                                       Section
                                                                                                                                                                  I
                                                                                                                                                                  10
                     Oxygen
                      Plant
  Makeup
  Water
Treatment
   Cooling
    Tower
Steam and
  Power
Generation
                                                                         Figure  C.I

                                                           Flow Diagram  of  Meyers Process
-------
                                   - 268 -
           In the  reactor  vessels,  the  slurry  is  contacted with  oxygen at
about  300°F.   The pyritic sulfur  is  95%  converted  to  elemental  sulfur and
sulfate  in the reactor  vessels.   The reactions taking place  in  the  reactors
are shown below:

           Leaching Reactions
           (1)   FeS2  + Fe2(S04)3  •> 3FeS04 + 2S

           (2)   FeS2  + 7Fe2(S04)3 + 8H20  •*•   15FeS04

 Since  the net  S04:S  production from FeS2 is  approximately  1.5:1,  the over-
 all  leaching reaction is:

           (3)   FeS2  + 4.6Fe2(S04)3 +  4.8H20  -> 10.2FeS04 +  4.8H2S04 + 0.8S

           Regeneration Reaction

           (4)   9.6FeS04  + 4.8H2S04 +  2.402   + 4.8Fe2(S04)3 + 4.8H20

           Net  Overall Reaction

           (5)   FeS2  + 2.402     0.2Fe2(S04>3 + 0.6FeS04 +  0.8S

           The  excess ferric  and ferrous sulfates must be removed  from  the
 system.   The slurry  is cooled by heat  exchange with  fresh  feed and then
 by cooling water  and is  pumped to  the  Sulfur Removal Section.

           C.I. 2. 3  Sulfur Removal  Section

           In the  Sulfur  Removal Section, approximately 60% of the leach
 solution  is removed  in hydroclones and recycled to the Reaction Section.
 The  remaining  leach  solution is removed by filtration and  is passed to
 the  Iron  Sulfate  Recovery Section.

           The wet  filter cake is washed with water and then mixed with
 recycle solvent (e.g., light naphtha)  at 160°F and most of the elemental
 sulfur is  dissolved.   The  resulting slurry is filtered to  remove  the
 cleaned coal which passes  to the Product Drying Section.   The sulfur-rich
 solvent is separated from water by decantation and passes  to the  Sulfur
 Recovery  Section.

           C.I. 2. 4  Product Drying  Section

          The treated coal,  containing about 25% moisture  and 5%  solvent
 (dry basis), is conducted  to the drying section.  The coal is partially
dried under vacuum;  the  sensible heat  of the coal is sufficient to remove
all the solvent and  about  20% of the water.   The vapors are returned  to
the Sulfur Removal Section where they  are condensed  in a water cooled
vessel.  The water and solvent are separated by decantation and reused in
the process.  The coal product, containing 20% moisture  (dry basis)  then
leaves the process .
-------
                                 - 269 -
          C.I.2.5  Sulfur Recovery Section

          The sulfur-laden solvent and miscellaneous solvent and water
streams are passed to the Sulfur Recovery Section.  The solvent is removed
from the sulfur by distillation and the sulfur leaves the process.  Water
and rich solvent are separated by decantation.  The water is recycled
to the Reaction Section and the solvent is returned to the Sulfur Removal
Section.  Makeup water and solvent are added to the system through the
Sulfur Recovery Section.

          C.I.2.6  Iron Sulfate Recovery Section

          The water filtrate from filtration in the Sulfur Removal Section
passes to the Iron Sulfate Recovery Section.  Since the process produces
iron from the pyrites, it is necessary to remove iron from the system.  The
filtrate is heated to about 265°F, and some of the water is flashed
overhead.  Part of the steam thus formed is returned to the Reaction
Section and part passes to the Sulfur Recovery Section.  The remaining
slurry of iron sulfates is filtered at 215°F to produce an iron sulfate
filter cake for disposal.  The filtrate is returned to the Reaction
Section.

     C.I.3  Auxiliary Facilities

          The auxiliary facilities in the complex include an oxygen plant,
raw water treatment, cooling towers and steam and power generating
facilities.  These auxiliary units must be considered to evaluate effluent
problems and overall thermal efficiency.

          The oxygen plant is a major consumer of power and there is a
large gaseous effluent.  It has been assumed in the present design that
an extraction turbine, using 600 psig steam, is used to drive the air
compressor in the oxygen plant.  The extraction steam, at 115 psig, is
utilized in the rest of the plant.

          A raw water treatment system is provided to furnish makeup
water to the steam boiler and cooling tower.  Cooling tower blowdown is
sent to an evaporation pond.  Product coal is burned in the steam plant.
The use of product in the boiler furnace affects the thermal efficiency
of the overall plant.  Control of particulate matter can be effected by
the use of commercial electrostatic precipitators, cyclones and/or
scrubbers.
-------
            - 270 -
             APPENDIX D




Trace Elements in Petroleum and Shale
-------
                               - 271 -



                               APPENDIX D

                  TRACE  ELEMENTS IN PETROLEUM AND SHALE


D.I  Domestic  Crude Oils

           Approximately two-thirds of domestic crude oil production is
obtained  from  a relatively small number of large oil fields, sometimes
termed  "giant" fields.*  Generally, U.S. giant fields are defined as
those possessing reserves in excess of 100,000,000 bbl.  (Some of the
older fields which have been in continual production may now possess
reserves  less  than this level.  Additionally, certain large new fields
may  presently  be shut in  or in a state of development thereby accounting
for  their relatively low  production.)  These large oil fields are res-
ponsible  for a majority of U.S. oil production and they are also
representative of the nation's total oil production.  This occurs
because many smaller oil  fields in close proximity to the giant fields
possess very similar characteristics including similar trace element
concentrations.  In practice,  the production of these smaller fields is
generally combined with that from the large fields in the pipe line net-
works that grid oil producing  regions.  Thus, the oil arriving at
refineries is  a mixture,  dominated by production of the giant fields.
Consequently,  for practical purposes, the characteristics of the larger
fields  characterize the great  bulk of all domestic petroleum production.

     D.I.I Sulfur and  Nitrogen Data

           Because of the  prominence of the giant fields, their crudes
have been subject to much of the trace element data that are available.
Sulfur  and nitrogen data  for crude oils from these fields are the most
complete  and consequently will be considered separately.  Of a total of
259  giant U.S.  oil fields,  sulfur data were obtained for 251 fields
(96.9%) and nitrogen data were acquired for 229 fields (88.4%).  On a
production basis,  sulfur  data  covered 94.6% of giant field's production,
and  the nitrogen data 88.5%.   Most of the sulfur and nitrogen data were
obtained  from  Bureau of Mines  sources through either publications or open
files of  crude oil analyses.

           In assembling this compilation, data from published, widely
available sources were  utilized in preference to data from less avail-
able sources.   Consequently, published Bureau of Mines data took pre-
cedence over Bureau of  Mines open file analysis data.  An average was
obtained  when  duplicate BuMines data were available for a given field.
Data officially published by the Bureau were used in preference to those
appearing elseswhere, even if  the authors of these other works were
Bureau  personnel.   The  giant field sulfur and nitrogen data follow in
Table D.I.
   "Giant field" is a relative term.  Of the current producers, the two
   largest are the Wilmington (California) and East Texas fields.  Each
   produces approximately 70-75 thousands barrels per day.  This may be
   contrasted with the Ghawar field in Saudi Arabia, the world's largest,
   which has a production level more than ten fold greater than Wilmington.
   Reserves of the Ghawar field are estimated to approach 70 billion
   barrels.
-------
                               - 272 -
          The data presented in Table D.I were evaluated on both a pro-
duction and a geometric average basis.  These evaluations are discussed
below by element.

          Sulfur - The sulfur data were plotted as a histogram.  The
resulting frequency distribution is shown as Figure D.I.  In this figure,
each sulfur percentage increment covers a range centering on the value
shown.  For example, the sulfur value of 0.3 covers a range of 0.25
to  0.3499% sulfur.  The sulfur data are log normally distributed about
the 0.2% level, although the distribution possesses a long tail.  A
distribution of this type is the classic one found for the distribution
of  many trace elements in the earth's crust.

          The geometric mean of the sulfur data as calculated from
Table D.I was 0.42%.  A production average calculated from this same
data was 0.77% S, indicating that certain large production fields
possessed a greater than average sulfur content.  Crudes possessing
a sulfur level of <0.1 were treated as if this level were 0.1 for cal-
culation purposes.

          The sulfur data ranged from less than 0.1% for a number of
fields in southern Texas near the Gulf Coast (Texas Railroad Commission
Corpus Christi District 4) to 5.07% and 4.99% for the Cat Canyon West
and Santa Maria Valley fields of the coastal area of California.

          Nitrogen - A histogram of the nitrogen data is shown in Figure
D.2.  As with the sulfur graph, each nitrogen percentage increment is
centered on the value shown so that the value of 0.25 covers a range of
0.24 to 0.2599% N.  Once again the data appear to be log normally dis-
tributed with a long tail.  The modal value occurs at 0.03% N.

          The geometric mean of the nitrogen data of Table D.I was
0.028%.  This is in contrast to a production average of 0.159%.  As
with sulfur content, substantial production from high nitrogen content
fields has made the production average greater than the geometric mean.

          The lowest nitrogen level, 0.002%, was observed for crude
from the recently discovered Jay field in Florida.  The highest, 0.913%,
was found for crude from the San Ardo field in the coastal region of
California.  It is well known that many California crudes possess very
high nitrogen as well as sulfur levels.  Consequently, it was not unexpected
that all crudes possessing nitrogen levels above 0.5% were from California.

     D.I.2  Other Trace Element Data

          With the exception of sulfur and nitrogen, the Bureau of Mines
has not performed trace element analysis as part of their routine analyses
of crude oils.  This factor, coupled with the lack of widespread pub-
lished data in this area from other sources, means that a large gap
exists in reliable information on trace elements.  Consequently, no
complete trace element distribution is possible even for the giant fields.
-------
                          -  273 -
                         Table D.I

                Sulfur and Nitrogen Content
               of The Giant U.S. Oil Fields
  ^State/Region and Field
ALABAMA
  Citronelle
Sulfur,   Nitrogen,
Weight     Weight
Percent    Percent
 0.38
ALASKA
  Granite Point
  McArthur River
  Middle Ground Shoal
  Prudhoe Bay  (North Slope)
  Swanson River

APPALACHIAN
  Allegany
  Bradford

ARKANSAS
  Magnolia
  Schuler and  East
  Smackover

CALIFORNIA
  SAN JOAQUIN VALLEY
  Belridge South
  Buena Vista
  Coalinga
  Coalinga Nose
  Coles Levee  North
  Cuyama  South-
  Cymric
  Edison
  Elk Hills
  Fruitvale
  Greeley
  Kern Front
  Kern River
  Kettleman  North Dome
  Lost Hills
  McKittrick - Main Area
  Midway  Sunset
  Mount Poso
  Rio Bravo
  COASTAL  AREA
   Carpenteria Offshore
  Cat Canyon West
  Dos Cuadras
   Elwood
 *  Oil and Gas Journal, January
 0.02
 0.16
 0.05
 1.07
 0.16
 0.12
 0.11
 0.90
 1.55
 2.10
0.02
0.039
0.160
0.119
0.23
0.203
0.028
0.010
0.02
0.112
0.08
    1971
 Production
(Thousands
of Barrels)*


    6,390
    5,552
   40,683
   11,277
    1,076
   11,709
      388
    2,470
      850
      800
    2,800
0.23
0.59
0.43
0.25
0.39
0.42
1.16
0-20
0.68
0.93
0.31
0.85
1.19
0.40
0.33
0.96
0.94
0.68
0.35
__
5.07

	
0.773
—
0.303
0.194
0.309
0.337
0.63
0.446
0.472
0.527
0.266
0.676
0.604
0.212
0.094
0.67
0.42
0.475
0-158
__
0.54
—
__
9,211
5,429
7,866
4,752
1,006
2,034
3,345
1,417
951
1,109
761
3,440
25,542
840
2,328
5,348
33,583
1,378
425
5,295
2,705
27,739
108
  31,  1972 pp. 95-100.
-------
                           - 274  -
                     Table D.I  (Cont'd)
   State/Region and Field

   Orcutt
   Rincon
   San  Ardo
   Sanca Ynez***
   Santa Maria Valley
   South Mountain
   Ventura
 LOS ANGELES BASIN
   Beverly Hills
   Brea Olinda
   Coyote East
   Coyote West
   Dominguez
   Huntington Beach
   Inglewood
   Long Beach
   Montebello
   Richfield
   Santa Fe Springs
   Seal Beach
   Torrance
   Wilmington
 COLORADO
   Rangely

 FLORIDA
   Jay
 ILLINOIS
   Clay City
   Dale
   Loudon
   New  Harmony
   Salem
 KANSAS
   Bemis-Shutts
   Chase-Silica
   Eldorado
   Hall-Gurney
   Kraft-Prusa
   Trapp

LOUISIANA
 NORTH
  Black Lake
  Caddo-Pine  Island
  Delhi
  Haynesville (Ark.-La.)
  Homer
  Lake  St. John
  Rodessa  (La.-Tex.)

Sulfur,
Weight
Percent
2.48
0.40
2.25
4.99
2.79
0.94
2.45
0.75
0.95
0.82
0.40
1.57
2.50
1.29
0.68
1.86
0.33
0.55
1.84
1.44

Nitrogen,
Weight
Percent
0.525
0-48
0.913
0.56
—
0.413
0.612
0.525
0.336
0.347
0.360
0.648
0.640
0.55
0.316
0.575
0.271
0.394
0.555
0.65
1971
Production
(Thousands
of Barrels)*
2,173
4,580
9,939
1,966
1,962
10,188
8,400
4,228
864
2,436
1,717
16,249
3,992
3,183
740
1,910
953
1,468
1,338
72,859
 0.56

 0.32


 0.19
 0.15
 0.27
 0.23
 0.17

 0.57
 0.44
 0.18
 0.34
 Q.27
 0.41
0.37
0.82
0.66
0.83
0.17
0.46
 0.073

 0.002

 0.082
 0.080
 0.097
 0.158
 0.102

 0.162
 0.13
 O.Q85
 0.108
 0.171
 0.076
0.026
0.053
0.022
0.081

0.032
10,040

   370

 4,650
   690
 4,420
 2,740
 3,360

 2,590
 1,600
 1,500
 2,480
 3,200
 1,930
3,500
5,870
2,730
   330
1,170
   900
   *  Oil and Gas Journal,  January  31, 1972, pp. 95-100.
 ***  Undeveloped field,  Santa Barbara Channel.  Uncorroborated
      estimate of reserves  of 1  to 3 billion bbl.
-------
                         -  275 -
                  Table D.I  (Cont'd)
 State/Region and Field

OFFSHORE
 Bay Marchand Block 2
  (Incl. onshore)
 Eugene Island Block 126
 Grand Isle Block 16
 Grand Isle Block 43
 Grand Isle Block 47
 Main Pass Block 35
 Main Pass Block 41
 Main Pass Block 69
 Ship Shoal Block 208
 South Pass Block 24
  (Incl. onshore)
 South Pass Block 27
 Timbalier S. Block 135
 Timbalier Bay
  (Incl. onshore)
 West Delta Block 30
 West Delta Block 73
SOUTH, ONSHORE
 Avery Island
 Bay De Chene
 Bay St. Elaine
 Bayou Sale
 Black Bay West
 Caillou Island
  (Incl. offshore)
 Cote Blanche Bay West
 Cote Blanche Island
 Delta Farms
 Garden Island Bay
 Golden Meadow
 Grand Bay
 Hackberry East
 Hackberry West
 Iowa
 Jennings
 Lafitte
 Lake Barre
 Lake Pelto
 Lake Salvador
 Lake Washington
  (Incl. offshore)
 Leeville
 Paradis
 Quarantine Bay
 Romere Pass
 Venice
 Vinton
 Weeks Island
 West Bay
Sulfur,
Weight
Percent
Nitrogen,
 Weight
 Percent
    1971
 Production
(Thousands
of Barrels)*
0.46
0.15
0.18
—
0.23
0.19
0.16
0.25
0.38
0.26
0.18
0.66
0.33
0.33
—
0.12
0.27
0.39
0.16
0.19
0.23
0.16
0.10
0.26
0.22
0.18
0.31
0.30
0.29
0.20
0-26
0.30
0.14
0.21
0 .14
0.37
0.20
0.23
0.27
0.30
0.24
0.34
0.19
0.27
0.11
0.030
0.04
— —
0.04
0.071
0.025
0.098
0.02
0.068
0.049
0.088
0.081
0.09
—
—
0.060
0.04
—
0.04
0.04
0.033
0.01
0.055
0.06
—
—
0.054
—
0.039
—
—
0.02
0.035
0 .02
0 .146
0 .019
—
0 .061
—
—
0 .044
—
0 .071
30,806
5,621
21,681
22,776
4,271
3,504
18,469
12,775
10,038
20,330
21,425
13,578
30,988
26,390
15,987
3,400
6,643
7,775
5,293
9,892
31,828
15,658
8,797
1,278
16,096
2,738
6,680
2,226
3,760
876
292
10,877
7,592
4,891
4,380
10,913
4,343
1,898
7,117
3,759
5,475
2,299
10,183
9,563
     Oil and Gas Journal. January 31, 1972, pp. 95-100.
-------
                            -  276 -
                     Table D.I  (Cont'd)
  State/Region and Field

MISSISSIPPI
  Baxterville
  Heidelberg
  Tinsley

MONTANA
  Bell Creek
  Cut Bank

NEW MEXICO
  Caprock and East
  Denton
  Empire Abo
  Eunice
  Hobbs
  Maij amar
  Monument
  Vacuum

NORTH DAKOTA
  Beaver Lodge
  Tioga

OKLAHOMA
  Allen
  Avant
  Bowlegs
  Burbank
  Cement
  Gushing
  Earlsboro
  Edmond West
  Eola-Robberson
  Fitts
  Gler.a Pool
  Golden Trend
  Healdton
  Hewitt
  Little River
  Oklahoma City
  Seminole,  Greater
  Sho-Vel-Tum
  Sooner Trend
  St.  Louis
  Tonkawa
Sulfur,
Weight
Percent
 2.71
 3.75
 1.02
 0.24
 0.80
 0.17
 0.1?
 0.27
 1.
 1.
14
41
 0.55
 1.14
 0.95
 0.24
 0.31
 0.70
 0.18
 0.24
 0.24
 0.47
 0.22
 0.47
 0.21
 0.35
 0.27
 0.31
 0-15
 0.92
 0.65
 0.28
 0.16
 0.30
 1.18

 0.11
 0.16
         Nitrogen,
          Weight
          Percent
          0.111
          0.112
          0.08
          0.13
          0.055
0.034
0.014
0.014
0.071
0.08
0.062
0.071
0.075
         0.019
         0.016
          0.21

          0.140
          0.051
          0.152
          0.08

          0.045
          0.115

          0.096
          0.15
          0.15
          0.148
          0.065
          0.079
          0.016
          0.27

          0.04
          0.033
               1971
             Product
            (Thousands
            of Barrels)*
                9,300
                3,450
                2,450
                5,950
                5,180
   905
 2,350
 9,520
 1,330
 5,700
 6,040
 3,720
17,030
                3,140
                1,790
                2,920
                  365
                2,260
                5,240
                2,370
                4,300
                  765
                  730
                4,850
                1,420
                2,480
               12,330
                4,600
                5,660
                  440
                1,750
                1,640
               36,500
               15,240
                1,350
                  290
*  Oil and Gas Journal, January  31,  1972, pp.  95-100.
-------
                             - 277 -
                        Table D.I (Cont'd)
  State/Region and Field

TEXAS
 DISTRICT 1
  Big Wells
  Darst Creek
  Luling-Branyon
 DISTRICT 2
  Greta
  Refugio
  Tom O'Connor
  West Ranch
 DISTRICT 3
  Anahuac
  Barbers Hill
  Conroe
  Dickison-Gillock
  Goose Creek and East
  Hastings E&W
  High Island
  Hull-Merchant
  Humble
  Liberty South
  Magnet Withers
  Old Ocean
  Raccoon Bend
  Sour Lake
  Spindletop
  Thompson
  Webster
  West Columbia
 DISTRICT 4
  Agua Duke-Stratton
  Alazan North
  Borregas
  Government Wells N.
  Kelsey
  La Gloria and South
  Plymouth
  Seeligson
  Tij erina-Canales-Blucher
  White Point East
 DISTRICT 5
  Mexia
  Powell
  Van and Van Shallow
Sulfur,
Weight
Percent
Nitrogen,
 Weight
 Percent
0.78
0.86
0.17
0.11
0.17
0.14
0.23
0.27
0.15
0.82
0.13
0.20
0.26
0.35
0.46
0.14
0.19
0.14
0.19
0.14
0.15
0.25
0.21
0.21
<.l
0.04
<.l
0^22
0.13
<_1
o'.is
<.l
<.l
0-13
0.20
0.31
0.8
0.075
0.110
0.038
0.027
0.038
0.029
0.041
0.06
0.022
0.014
0.028
0.03
0.048
0.081
0.097
0.044
0.033
0.029
0.048
0.016
0.03
0.029
0.046
0.055
0-015
0.014
0.029
0.043
0.008
0.008
0.049
0.015
0.010
0.02
0.048
0.054
0.039
    1971
 Production
(Thousands
of Barrels)*
                            5,840
                            1,971
                            1,679

                            3,577
                              657
                            23,360
                            17,009

                            9,052
                              766
                            12,994
                            2,920
                            1,095
                            17,191
                            2,081
                            1,643
                            1,241
                              949
                            3,869
                            1,132
                            2,409
                            1,058
                              328
                            12,885
                            16,206
                            1,351

                            2,518
                            3,723
                            4,818
                              511
                            6,059
                              936
                              986
                            6,424
                            5,986
                            1,606

                              109
                              109
                            12,337
*  Oil and Gas Journal, January 31, 1972, pp. 95-100.
-------
                               -  278  -
                          Table D.I  (Cont'd)
   State/Region and Field
  DISTRICT 6
   East Texas
   Fairway
   Hawkins
   Neches
   New Hope
   Quitman
   Talco
  DISTRICT 7-C
   Big Lake
   Jameson
   McCamey
   Pegasus
  DISTRICT 8
   Andector
   Block 31
   Cowden North
   Cowden South,  Foster,
     Johnson
   Dollarhide
   Dora Roberts
   Dune
   Emma and Triple N
   Fuhrnan-Mascho
   Fullerton
   Goldsmith
   Headlee and North
   Hendrick
   Howard Glasscock
   latan East
   Jordan
   Kermit
   Keystone
   McElroy
   Means
   IJidland F'arnis
   Penwell
   Sand Hills
   Shafter Lake
   TXL
   Waddell
   Ward South
   Ward Estes North
   Yates
Sulfur,
Weight
Percent

 0.32
 0.24
 2.19
 0.13
 0.46
 0.92
 2.98
Nitrogen,
 Weight
 Percent

 0.066

 0.076
 0.083
 0.007
 0.036
0.26
<.l
2.26
0.73
0.22
0.11
1.89
1.77
0.39
<.l
3.11
<.l
2.06
0.37
1.12
<.l
1.73
1.92
1.47
1.48
0.94
0.57
2.37
1.75
0.13
1.75
2.06
0.25
0. 36
1.69
1.12
1.17
1.54
0-071
0.034
0.139
0.200
0.033
0.032
0.095
0.127
0.074
0.023
0.111
0.025
0.085
0.041
0.079
0.083
0.094
0.096
0.120
0.10
0.092
0.042
0.080
0.205
0.080
0 . 205
0.085
0.041
0 .067
0 .098
0 .08
0 .107
0 .150
    1971
 Production
(Thousands
of Barrels)*

   71,139
   14,271
   29,054
    3,942
      292
    3,103
    4,380

      474
    1,387
      985
    4,052

    5,694
    6,242
    9,782

   14,198
    7,592
    3,066
   11,425
    3,030
    1,935
    6,607
   20,951
    1,460
      766
    6,606
    3,687
    3,212
    2,007
    8,322
    9,015
    7,921
    6,059
    2,044
    6,606
    2,956
    4,854
    4,453
      803
   10,184
   13,359
*  Oil and Gas Journal, January  31,  1972,  pp.  95-100,
-------
                          -  279  -
                       Table D.I (Cont'd)
  State/Region and Field
 DISTRICT 8-A
  Cogdell Area
  Diamond M
  Kelly-Snyder
  Levelland
  Prentice
  Robertson
  Russell
  Salt Creek
  Seminole
  Slaughter
  Spraberry Trend
  Wasson
 DISTRICT 9
  KMA
  Walnut Bend
 DISTRICT 10
  Panhandle

UTAH
  Greater Aneth
  Greater Redwash

WYOMING
  Elk Basin (Mont.-Wyo.)
  Garland
  Grass Creek
  Hamilton Dome
  Hilight
  Lance Creek
  Lost Soldier
  Oregon Basin
  Salt Creek
Sulfur,
Weight
Percent
Nitrogen,
 Weight
 Percent
0.38
0.20
0.29
2.12
2.64
1.37
0.77
0.57
1.98
2.09
0.18
1.14
0.31
0.17
0 .063
0 .131
0 .066
0 .136
0 .117
0 .100
0 .078
0 .094
0 .106
—
0 .173
0 .065
0.068
0.05
  0.55
  0.20
  0.11
  1.78
  2.99
  2.63
  3.04

  0.10
  1.21
  3.44
  0.23
  0.067
  0.059
  0.255
  0.185
  0.290
  0.311
  0.343

  0.055
  0.076
  0.356
  0.109
   1971
 Production
(Thousands
of Barrels)*


   14,235
    7,373
   52,487
    9,746
    5,913
    2,774
    4,234
    9,271
    9,125
   35,515
   18,688
   51,210


    2,920
    3,942

   14,235
    7,660
    5,800
   14,380
    3,500
    3,760
    4,500
   11,300
      325
    4,820
   12,260
   11,750
    Oil and Gas Journal, January 31, 1972, pp. 95-100.
-------
    60  -
    50
to
    40
to

LL.
O

OL
LU
CQ
30
                                                                                                       N3
                                                                                                       oo
                                                                                                       O
    20
    10
                       Ill
                          .5
                            m
                                    1.0             1.5


                                      WEIGHT PERCENT SULFUR

                                        Figure D.I


                          Fequency Distribution of Sulfur Content
                           in Crude Oils  of  U.S.  Giant Oil Fields
2.0
2.5
T^
 >2.7
-------
    60
    50
    40
to
LJ
_1
D_

<
LU
CO
    30
    20
    10
         T   '  I   '
         01    .05
                                n
      n
          Finn
.15
1   I
  .25
1   I
  .35
                                  WEIGHT PERCENT NITROGEN
                                   Figure D.2
                   n
.45   >.50
                                                                00
                                                                I-1
                                                                I
                     Frequency Distribution of Nitrogen Content
                       in Crude Oils of U.S. Giant Oil Fields
-------
                                 - 282 -
           A number of more or less  classical  instrumental techniques
 has been used to obtain much of  the trace  element data that are avail-
 able.   These techniques include  flame  photometry, atomic absorption,
 emission spectroscopy, spectrochemical (colorimetric) analysis and
 x-ray fluorescence.  Although most  available  trace element data
 especially on vanadium and nickel have been obtained using these
 techniques, considerable data are now  being accumulated on many ele-
 ments using activation analysis, a  nuclear techniques  As some of these
 data are at variance with those  obtained using  the more classical
 methods, activation analysis data are  presented in a separate section.

           Some trace element data on petroleum  were published a number
 of years ago.  It is possible that  as  a greater understanding of pre-
 parative and analytical techniques  has developed, the ability to obtain
 reliable data has increased.  It is likely, therefore, that the more
 recent data are more accurate although this is  not necessairly so.

           Virtually all of the available trace  element data for U.S.
 oil fields were used to compile  Table  D.2.  Included are the state,
 field, analytical method used if available, year of publication and
 the source of the data.  Data are presented from all fields even those
 that are not significant producers.  Conflicting data are also present
 for certain fields.  Data from numerous published sources were utilized
 irrespective of analytical method or year  of  publication.  No data were
 averaged.   The search was limited to the following elements:  V, Ni, Fe,
 As,  Be,  Cd, Hg,  Se, Sb, Ba,  Cr,  Pb,  Mn, Mo, Te,  Sn.  However, for the
 most part, data were found only  for 10 of  these elements.  Data are
 presented  in the order V,  Ni,  Fe, Ba,  Cr,  Mn, Mo, Sn plus the available
 data for other elements.

           The trace element data presented in Table D.2 indicate that,
 in general, the lowest metal content domestic crudes are from the coastal
 and  offshore fields of Louisiana and Texas.   The highest metal content
 crudes are found in California.  This  parallels the observations made
 for  sulfur and nitrogen.   It is not surprising  that the levels of nit-
 rogen, vanadium and nickel should vary together because some nitrogen
 and  some of these (and other)  metals are frequently bound into a prophyrin
 ring.  This type of chelate coordination complex is known for its high
 stability.   All  of  the volatile metal  compounds present in crude oil
 are  metalloporphyrins.   The nature  of  the  nonvolatile metal compounds
 is not completely understood although  they too  may be complexes with
 more than  one porphyrin ring or  simple porphyrins with sizeable
 asphaltic  side chains.

          Data obtained from the Cymric field of California's San
 Joaquin Valley are  worthy of comment.   The high mercury levels reported
 for  this field are  in  no way representative of  domestic production in
 general or  of  California  production  in particular.  Cymric's high mer-
 cury content  can  be attributed to its  location  on the southeast pro-
longation of  the  main  mercury belt  east of the  San Andreas fault.  It
is,  therefore, not  surprising  that  the mercury  ore cinnabar found in
this region  is saturated with  hydrocarbons and  that crude oil hydro-
carbons appear to be saturated with  mercury.
-------
                                            -  283  -
                                            Table D.2
                  Trace  Element  Content  of  U.S.  Crude  Oils
        Stfte and Field
ALABAMA

  Toxey
  Toxey
 9
10
14
16
                                                                                    Analytical Method
Emission spectroscopy
Emission spectroscopy
                                                                                                           Year
                     1971
                     1971
ALASKA
  Kuparuk, Prudhoe Bay
  Kuparuk, Prudhoe Bay
  McArthur River, Cook Inlet
  Prudhoe Bay
  Put River, Prudhoe Bay
  Redoubt Shoal, Cook Inlet
  Trading Bay,  Cook Inlet
32
28
nd
31
16
nd
nd
13
12
nd
11
 6
 4
nd
Emission
Emission
Emission
Emission
Emission
Emission
Emission
spectroscopy
spectroscopy
spectroscopy
spectroscopy
spectroscopy
spectroscopy
spectroscopy
1971
1971
1971
1971
1971
1971
1971
 ARKANSAS
   Brister,  Columbia
   El Dorado,  East
   Schuler
   Smackover
   Stephens-Smart
   Tubal, Union
   West Atlanta
nd    nd                                     Emission spectroscopy
12    11                                     Emission spectroscopy
15.2  10.3   1.2  <1   <1   <1   nd  nd        Emission spectroscopy
nd     4                                     Emission spectroscopy
18.5  22.7   6.3  <1   <1   <1   nd  <1        Emission spectroscopy
nd    nd                                     Emission spectroscopy
<1    <1    <1    <1   <1   <1   nd  nd        Emission spectroscopy
                                                                     1971
                                                                     1971
                                                                     1961
                                                                     1971
                                                                     1961
                                                                     1971
                                                                     1961
 CALIFORNIA

   Ant Hill
   Arwin
   Bradley Sands
   Cat Canyon
   Cat Canyon
   Coalinger
   Coal- Oil Canyon
   Coles Levee
   Coles Levee
   Cuyama
   Cymric
   Cymric

   Cymric

   Cymric
   Cymric

   Cymric
   Edison
   Elk Hills
   Elwood South
   Gibson
   Gots Ridge
   Helm
   Helm
   Huntington  Beach
   Inglewood
   (Cattleman
   Kettleman Hills
   Las Flores
   Lompoc
   Lompoc
   Lost Hills
   Midway
   Nlcolai
   Nocth Belridge
   North Belridge
   North Belridge
   Nortn Belridge
   Orcutt
   Oxnard
   Purisma
   Raisin City
14.3 66.5 28.5 <1 <1 nd
9.0 28.0
134.5 —
128 75
209 102
5.1 21.9 5.1 <1 <1 <1
6.0 20.0
11.0 31.0
2.2 21.6 2.2 <1 <1 nd
10.0 32.0
30.0 43.0
0.8 2.3 2.0



0.6 1.1 2.0



1.0 2.0 2.0
6.0 11.0
8.3 38.5 38.5 <1 <1 <1
nd 11
37 125
188 80
14.0 27.0
2.5 10.5 2.5 <1 <1 nd
29 104
125.7 125.7 125.7 <1 1.3 nd
34.0 35.0 24.0
11.0 24.0
106.5 --
37.6
199 90
39.0 8.0
82.6 82.6 82.6 1.8 1.8 <1
246.5 —
— 107
— 80
— 83
23 83
162.5
403.5
218.5
8.0 21.0
nd nd




<1 nd


<1 nd



2.6'
2.4
1.9.

21.CT
14.0
2.9


<1 nd




nd <1

<1 nd





<1 nd









                                           D
                                        Emission spectroscopy          1961
                                        Emission spectroscopy          1956
                                        (1)                            W58
                                        Emission spectroscopy          1971
                                        Emission spectroscopy          1971
                                        Emission spectroscopy          1961
                                        Emission spectroscopy          1956
                                        Emission spectroscopy          1956
                                        Emission spectroscopy          1961
                                        Emission spectroscopy          1956
                                        Emission spectroscopy          1956
                                        Emission spectroscopy          1961

                                        Emission spectroscopy          1961

                                        Emission spectroscopy          1961
                                              Emission spectroscopy          1961

                                              Emission spectroscopy          1961
                                              Emission spectroscopy          1956
                                              Emission spectroscopy          1961
                                              Emission spectroscopy          1971
                                              X-ray fluorescence            1969
                                              Emission spectroscopy          1971
                                              Emission spectroscopy          1956
                                              Emission spectroscopy          1961
                                              Emission spectroscopy          1971
                                              Emission spectroscopy          1961
                                              Colorimetric                  1952
                                              (1)                           1958
                                              (1)                           1958
                                              (!)                           1958
                                              Emission spectroscopy         1971
                                              Emission spectroscopy         1956
                                              Emission spectroscopy         1961
                                               (!)                            1958
                                              X-ray  fluorescence (inter. std)1959
                                              Colorimetrii;                  1959
                                              Emission spectroscopy          1959
                                              X-ray  fluoresc. text,  std.)   1960
                                               (1)                            1958
                                               (1)                            1958
                                               (1)                            1958
                                               Emission spectroscopy          1956
(1)   Not  specified.

nd  Sought but not detected.
-------
                                  -  284 -
                             Table D.2 (Cont'd)
State and Field
Rio Bravo
Rio Bravo
Rio Bravo
Russell Ranch
San Joaquin
Santa Maria
Santa Maria
Santa Maria
Santa Maria
Santa Maria Valley
Santa Maria Valley
Santa Maria Valley
Santa Maria Valley
Signal Hill
Signal Hill
Tejon Hills
Ventura
Ventura
Ventura Avenue
Wheeler Ridge
Wilmington
Wilmington
Wilmington
Wilmington
Wilmington
Wilmington
Wilmington
COLORADO
Badger Creek
Badger Creek
Gramps
Gramp
Hiawatha
Moffat Dome
Rangely
Rangely
Rangely
Seep
White River Area
FLORIDA
Jay
ILLINOIS
Loudon
Loudon
KANSAS
Brews ter
Brewster
Brock
Coffeyville
Cunningham
Cunningham
lola
lola
"Kansas-1"
"Kansas-2"
McLouth
Otis Albert
Otis Albert
Pawnee Rock
Rhodes
Rhodes
Rhodes
Rhodes
Rhodes
Rhodes
Solomon
V

_
—
12.0
44.8
223
202
180
280
207
240
280
174
28
25
64
42
49
25.2
7
43
41
53
—
—
46
36.0

<1
<1
<1
<1
<1
<1
2.7
<1
<1
0.24
<1

nd

1.22
0.56

2.1
<1
1
3.8
44.2
24.0
15.6
4.5
—
—
<1
21.3
39.0
12.3
145
165
133
—
	
—
30
Ni Fe Ba Cr
2.2
2.6
2.5
26.0
—
97 17
—
106
130
97
—
—
174 1.7 <1 1.7
—
57
44
51
33 31
—
1.9
61
46 28
51
53
60
60
84 36 3.6 <1

<1 <1 <1 <1
"^l <1 <1 nd
5
>21
6.3 <1 <1 <1
6.0 <1 <1 <1
9.1 9.1 <1 <1
3.4 <1 <1 <1
—
	
—
36
38
32
7 <1 <1 <1
Mn Mo Sn As Analytical Method

X-ray fluorescence (int.
Emission spectroscopy
Emission spectroscopy
(1)
Colorimetric
(1)
Emission spectroscopy
Emission spectroscopy
Emission spectroscopy
X-ray fluorescence (int.
X-ray fluorescence (int.
<1 4.0 ad Emission spectroscopy
(1)
Emission spectroscopy
Emission spectroscopy
Emission spectroscopy
Colorimetric
(1)
Emission spectroscopy
Emission spectroscopy
Colorimetric
Emission spectroscopy
X-ray fluorescence (int.
X-ray fluorescence (int.
Emission spectroscopy
nd 1 nd Emission spectroscopy

<1 <1 <1 Emission spectroscopy
<1 <1 <1 Emission spectroscopy
<1 <1 <1 . Emission spectroscopy
<1 <1 <1 Emission spectroscopy -
<1 nd <1 Emission spectroscopy
<1 
-------
                                             -  285  -
                                     Table  D.2  (Cont'd)
      State and Field
                                                                                  Analytical Method
                                                                                                          IMZ.
LOUIS IAMA
  Bay Marchard
  Colqultt, Clairborne
  Colquitt, Clalrbome
  Colquitt, Calirborne
    (Smackover B)
  Delta (West) Offshore,
    Block 117
  Delta (West) Block 27
  Delta (West) Block 41
  Eugene Island, Offshore,
    Block 276
  Eugene Island, Offshore,
    Block 233
  Lake Washington
  Main Pass. Block 6
  Main Pass; Block 41
  Olla
  Ship Shoal, Offahore,
    Block 176
  Ship Shoal, Offshore,
    Block 176
  Ship Shoal, Block 208
  Shongaloo, N. Red Rock
  South Pass, Offshore,
    Block 62
  Tiabalier,  S., Offshore,
    Block  54
»d
nd
nd

»d

»d
nd
nd
                                      2
                                     nd
                                     nd
                                     nd
                               nd    nd
                               nd     4
                               nd     3
                               nd     1
                               <1     5.56 0.07
nd

nd
ad
nd

od

nd
                                     nd

                                     nd
                                       2
                                     nd

                                       4

                                     nd
Emission spectroscopy
Emission spectroscopy
Emission spectroscopy

Emission spectroscopy

Emission spectroscopy
Emission spectroscopy
Emission spectroscopy

Emission spectroscopy

Emission spectroscopy
Emission spectroscopy
Iniasion spectroscopy
Emission spectroacopy
Emission spactroscopy

Enlssion spectroscopy

Emission spectroscopy
Emission spectroscopy
Emission spectroacopy

Emission spectroscopy

Emission spectroseopy
1971
1971
1971
1971
1971
1971

1971

1971
1971
1971
1971
1952

1971

1971
1971
1971

1971

1971
MICHIGAN

  Trent
  —    0.23
                                             Emission spectroacopy
                                                                           1956
MISSISSIPPI
  Baxtervllle, lamar and
    Marlon
  Heidelberg
  Mississippi
  Tallhalla Creek, Smith
  Tallhalla Creek, Smith
  lallhalla Creek, Smith
     (Smackover)
  Tlngley. Yazoo

MONTANA
  Bell Creak
  Big Hall
  Soap Creek

HEU  MEXICO
  Rattlesnake
  Rattlesnake
  Table  Mesa

OKLAHOMA
  Allurve (Soyata)
  Allurve (Spwata)
  M-'llKVe (Sowata)
   Cary
   Chelsea (Sowata)
   Chelsea (Nomta)
   Chelsea (Mowata)
   Cheyarha
   Cheyarha
   Cheyarha
   Cheyarha
   Croewell
   Cruawell
   .Croiwall
   Croowell
   Cromrall
   Dill
   Dover,  Southeast
   Dust In
   E.  Lindsay
   E.  Seoinole
   E.  Teager
   Fish
   Clan Pool

   (1)  Hot
40
15.35

nd
nd
nd
7
nd
24
132
^.
<1
^i
15
6.02 1.78
.7
nd
nd
nd
5
2
13.2 <1 <1 <1
13.2 <1 <1 <1
<1 <1 <1 <1 <1
'I S6
std.) J*0
-------
                                   - 286 -
                            Table D.2  (Cont'd)
State and Field
Grief Creek
Hawkins
Hawkins
Horns Corner
Katie
Katie
Katie
Katie
Kendricfc
Konawa
Laffoon
Little River
Middle Gilliland
Naval Reserve
New England
N. Dill
N. E. Castle Ext.
N. E. Elmo re
N. E. Elmore
N. Okemah
N. W. Horns Corner
Olympia
Osage City
S. W. Maysville
S. W. Maysville
Tatums
Tatums
Tatums
Weleetka
W. Holdenvllle
W. Wewoka
Wewoka
Wewoka Lake
Wewoka Lake
Wewoka Lake
Wildhorse
Wynona
Wynona
TEXAS
Anahuac
Brantley-Jackson, Hopkins
Brantley-Jackson, Smackover
Conroe
East Texas
East Texas
East Texas
East Texas
Edgewood, Van Zandt
Finley
Jackson
Lake Trammel, Nolan
Mirando
Panhandle , Carson
Panhandle, Hutchinson
Panhandle, West Texas
Refugio
Refugio, Light
Salt Flat
Scurry County
Sweden
Talco
Talco
Wasson
West Texas

West Texas
West Texas
West Texas
West Texas
West Texas
West Texas
West Texas (Imogene)
Yates-Pecos
TracA F1 Bar
V 11 Fe Ba
0.10 0.42
2.10 8.50
0.72 3.50
0.70
0.17 0.52
0.48 1.60
0.29 1.00
0.24 1.00
<1 <1 <1 
-------
                                   - 287  -
                             Table  D.2  (Cont'd)
State and Field,
UTAH
Ducheene
Duchesne
Duchesne County
Red Wash
Red Wash
Roosevelt
Roosevelt
Virgin
Virgin
West Pleasant Valley
Wildcat
WYOMING
Beaver Creek
Big Horn Mix
Bison Basin
Circle Ridge
Corral Creek
Crooks Gap
Dallas
Dallas
Derby
Elk Bssln
Elk Basin
Garland
Grass Creek
Half Moon
Half Moon
Hamilton Dome
Hamilton Dome
Hamilton Dome
Little Mo
Lost Soldier
Lost Soldier
Lost Soldier
Mitchell Creek
North Oregon Basin
North Oregon Basin
North Oregon Basin
oil Mountain
Pilot Butte
Pilot Butte
Pine Ridge
Fresco tt No. 3
Recluse
Roelis
Salt Creek
Salt Creek
Salt Creek
Salt Creek
Skull Creek
South Casper Creek
South Fork
South Spring Creek
South Spring Creek
Steamboat Butte
Washakle
Wlnktanan Dome


<1
<1
<1
nd
nd
<1
<1
14.
8.
11.
0.

•d
15 ;
1.
48
59
2.
66
66
39
38
8.
36
106.
98.
50.
106.
55.
106.
83
<1
<1
<1.
72.
77.
72.
'60.
1'44.
45.
24.
•
nd
21.
nd
88
84.
j«

nd
nd
3.
5.
14.
8.
57
7.

nd
3.
2.
11.
11
2.
15.
66
39
9.
2
24
28.
27.
<1
26.
8.
24.
16
<1
<1
<1
72.
22.
14.
11.
33.
10.
5.
__ *
nd
7.
nd
15
8.
**
^A
3.
.-°-
3.
21.
102.
27.
6.
25.
li.




3


2
4
4
1


3.9
1.4
12.3
—
—
<1
<1
3.4
1.9
1MO.O
5


6
7
2

2
4


2

9
8
6
6
3
0
4
8
5
6
5
6

1


4
4

9
42
0
9
0
3
79
0
2



0.8
<1
<1
_
1.0
<1
1.5
<1
<1
<1
3.6
1.1
1.7
<1
<1
<1
2.7
<1
<1
<1
7.2
1.0
<1
<1
<1
j«
<1
-1
^1
""""*
—_
*"~
XI
*Vl
1701.
1961
1961
1961
im
1971
1961
1961
1961
1961
1961
1961
1941
19«1
1*61
1961
1971
1959
»n
1971
19*1
1961
1961
1961
1 8K&
JLT30
1961
1961
1961
1961
1961
193*
Wl

(1)  Not specified



 nd  Sought but not detected.
-------
                               - 288 -
D.2   Shale Oil

          The term oil shale covers a wide variety of fine-grained
sedimentary rocks that contain organic material.  Upon destructive
distillation much of  this organic material is released largely as an
oil which is termed shale oil.  The rock is only slightly soluble
in organic solvents and frequently does not appear or feel oily.  It
is tough, elastic, resistant to fracture and has essentially no per-
meability or porosity.

          The organic component of oil shale can be divided into two
parts, a part that is soluble in organic solvents and a part that is
not.  It is the  insoluble part, generally termed kerogen, which con-
stitutes the bulk of  the shale organic matter responsible for shale
oil.  The composition of kerogen varies considerably from shale
deposit to deposit but it is thought to consist of .largely cyclic
polymeric material probably held together by cross linkages involving
hetero atoms such as  nitrogen, sulfur and oxygen.

          There  is no truly typical shale oil but shale oils have some
properties in common.  In general, most shale oils are black, waxy
and possess high pour points.  Relative to conventional crude oils,
the nitrogen content  of crude shale oil is high although the sulfur
level is moderate.

          Oil shales  are widely distributed geographically.  However,
only  certain deposits are considered to be sufficiently rich in kerogen
to warrant commercial development.  In the U.S. oil shale deposits are
found in Tennessee and Nevada but the most important are in the Green
River Formation  of Colorado, Utah and Wyoming.  The Green River forma-
tion  has received attention as a possible source of fuels.  Within
this  formation,  shale deposits underlie an area of 17,000 square miles
in four basins:  the  Piceance Creek basin of Colorado, the Unita basin
of Utah and the  Washakie and Green River basins of Wyoming.

          The energy  potential of the Green River formation has been
estimated to be  more  than 1 trillion barrels of oil with 600 billion
coming from easily accessible, richer deposits which contain more than
25 gallons of oil per ton of shale.  Shale deposits vary in access-
ability from those at the surface to very deeply buried shales in the
Unita basin.  The outcrop called the Mahogany Ledge (because of its
color) is the location of an experimental mine and consequently has
been used to study mining and retorting methods.  Most U.S. elemental
shale oil analyses come from shale mined here.  The oil shales of the
Mahogany zone will probably be the first to be developed commercially.

          Table  D.3 presents sulfur and nitrogen data of crude shale
oil obtained from shale deposits throughout the world.  While many of
the samples were retorted using different techniques, it has been found
that generally the retorting method utilized has relatively little
effect on the characteristics of the oil produced unless extreme
-------


- 289 -
Table D.3




SULFUR AND NITROGEN CONTENT



Country
United States











Australia
Brazil
China
Estonia
France



Israel
Lebanon
New Zealand
Scotland
South Africa

Spain
Sweden
Thailand
OF CRUDE SHALE OILS


Formation/Location
Green River , Colorado
Green River
Green River
Green River
Green River
Green River
Green River
Green River
Green River*
Green River
Green River
De Kalb County, Tenn.
Glen Davis, N.S.W.
Paraiba Valley

Sulfur,
weight
per cent
0.74
0.69
0.77
0.51
0.67
0.72
0.71
0.64
1.10
0.66
0.59
3.38
0.56
0.41
Hwatien Mine, Manchuria 0.19
Kukersite
Autun
Severac
Severac
St. Hilaire
Urn Barek
—
0-repuki
—
Boksburg, Transvaal
Breyten, Transvaal
Puertollano
Kvarntorp
Maesod Area
1.10
0.51
3.00
3.40
0.61
6.2
1.5
0.64
0.35
0.64
0.61
0.40
1.65
0.41

Nitrogen,
weight
per cent
1.78
2.13
1.57
2.10
1.97
1.73
1.89
1.95
1.73
1.76
1.96
0.88
0.52
0.98
0.84
0.10
0.90
0.53
0.65
0.54
1.40
0.6
0.60
0.77
0.85
—
0.68
0.68
1.10
*  Core drilling sample,
-------
                               -  290  -
retorting conditions have been employed.  Of the deposits listed, only
the Green River can be considered to be a possible commercial source of
fuels for consumption in the U.S.  The others are included for the
purposes of comparison.

          Crude shale oil derived from the Green River formation possesses
an unusually high nitrogen level.  It has been found that generally the
nitrogen content is higher and the sulfur level lower in the higher
boiling shale oil fractions.  As of this writing, no metal content data
for shale oil appear to be available in the published literature.  An
unpublished analysis by the Bureau of Mines of shale oil obtained from
Green River shale indicates that this oil is high in iron and low in
vanadium and nickel.  The results obtained were:  vanadium, 0 ppm;
nickel, 4 ppm; and iron 67 ppm.  Most of the metals were associated with
the asphaltene fraction.

          The nitrogen compounds present in shale oil are particularly
troublesome in processing and must be removed before shale can be con-
verted into useful liquid or gaseous fuels.  Nitrogen removal can be
accomplished by severe hydrogen treatment which also reduces the sulfur
content to a low level.
-------
        - 291 -
       APPENDIX E




Table of Conversion Units
-------
                              - 292 -
                              APPENDIX E
                       TABLE OF CONVERSION UNITS
 To Convert From"

Btu

Btu/pound

Cubic feet/day

Feet

Gallons/minute

Inches

Pounds

Pounds/Btu

Pounds/hour

Pounds/square inch

Tons

Tons/day
            To
Calories, kg

Calories, kg/kilogram

Cubic meters/day

Meters

Cubic meters/minute

Centimeters

Kilograms

Kilograms/calorie, kg

Kilograms/hour

Kilograms/square centimeter

Metric tons

Metric tons/day
Multiply By

0.25198

0.55552

0.028317

0.30480

0.0037854

2.5400

0.45359

1.8001

0.45359

0.070307

0.90719

0.90719
          In line with usage current when this work was begun,  in  this
report M represents  thousand and MM represents million.
-------
                                      - 293 -

                          /»      TECHNICAL REPORT DATA
                          {Please read Instructions on the reverse before completing)
 REPORT NO.
EPA-600/2-76-101
                           2.
                                                       3. RECIPIENT'S ACCESSION*NO.
 TITLE AND SUBTITLE
Evaluation of Pollution Control in Fossil Fuel
Conversion Processes:  Final Report
                                                       5. REPORT DATE
                                                       April 1976
                                                       6. PERFORMING ORGANIZATION CODE
. AUTHOH(S)

E.M. Magee
                                                       8. PERFORMING ORGANIZATION REPORT NO.

                                                        Exxon/GRU.16DJ.76
&. PERFORMING ORdANIZATION NAME AND AOORESS
 Exxon Research and Engineering Company
 P.O. Box 8
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 EPA, Office of Research and Development
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                                                       Final; 6/72-1/76
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 Ext 2851.  This  is the final summary of EPA-R2-73-249 and the EPA-650/2-74-009
 series reports. already published.	
 B. AssTRACTTne revjew' gjves an overview of work, between June 1972 and January 1976,
 on various environmental aspects of fossil fuels.  Details of this work is presented
 in 14 reports published during this same period.  The details include potential pol-
 lutants in fossil fuels; quantities of solid, liquid, and gaseous effluents from coal
 treatment and conversion to gaseous and liquid fuels; and an analytical test plan for
 coal conversion systems. The overview report discusses commonality and differ-
 ences in the reviewed processes with emphasis on factors which might affect the
 environment when the processes are in commercial use.  Due to the lack of a
 sufficient database,  data and research and development needs are also addressed.
17.
                              KEY WORDS AND DOCUMENT ANALYSIS
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                                           Air Pollution Control
                                           Stationary Sources
                                           Fuel Conversion
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