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Sulfur Recovery Units (SRU) 
March 1995

                    Technical Disclaimer

References to abatement technologies are not intended to
represent minimum or maximum levels of Best Available Control
Technology (BACT).  Determinations of BACT are made on a case
by case basis.  BACT determinations are always subject to
adjustment in consideration of specific process requirements,
air quality concerns and recent developments in abatement
technology.  Additionally, specific health effect concerns may
indicate stricter abatement than required by the BACT
determination.

The represented calculation methods are intended as an aid in
the completion of acceptable permit applications; alternative
calculation methods may be equally acceptable if they are
based upon, and adequately demonstrate, sound engineering
assumptions or data.

These guidelines are applicable as of the date of this
document, but are subject to revision during the permit
application preparation and review period.  It is the
responsibility of the applicants to remain abreast of any
guideline or regulation developments which may affect their
industries.

BACT Guidelines

Sulfur recovery units (SRU) maybe required at onshore natural
gas plants and are, in general, expected at petroleum
refineries.  The typical SRU proposed is a three-stage
Claus with a tail gas treating unit (TGTU) if greater than
ninety-six percent recovery is required.  Other types of
sulfur recovery technology installed in Texas are Cold Bed
Adsorption (CBA), MCRC, SulFerox, Clinsulf, Selectox and
LoCat.  Although much of the following discussion pertains to
Claus units, the same issues:  control effectiveness,
reliability, on-stream time and enforceability must be
addressed regardless of the type of SRU proposed.  

Sulfur

Emissions

Sulfur emissions are emitted from process fugitive components
as hydrogen sulfide (H2S), sour water tanks, SRU as sulfur
dioxide (SO2) and H2S, sulfur pits and loading operations. 
The thermal oxidizer or tail gas incinerator (TGI) is expected
to oxidize H2S to SO2 with an efficiency of 99.9 percent. 
Acid gas flares are assumed to ninety-eight percent efficient
in converting H2S to SO2.  Any acid gas flaring must be
handled by a flare that can meet the design and operation
requirements of Title 40 Code of Federal Regulations Part
60.18 (40 CFR 60.18) for maximum tip velocities and minimum
British Thermal Unit (BTU) values.  The sulfur pit and sulfur
loading operations are expected to be controlled either
through a recovery system routing vapors back to the process
or by routing the vapors to an incinerator or other control
device.  Much has been written by the TNRCC on sulfur recovery
as a control technology.  For further details regarding SRU in
Texas, see the following documents:

"BACT Criteria for SRU in Texas" presented to the Lawrence
  Reid Gas Conditioning in Norman, Oklahoma, March 1993.
"Refinery SRU Permit Considerations in Texas", December 10,
  1993.
"Refinery Acid Gas Systems Air Permit Considerations",
  December 10, 1993.  

The remainder of the sulfur emissions discussion specifies the
concerns which should be addressed when implementing a SRU. 
Guidelines have been provided at the end of this document,
Table 1, relating the expected efficiency and the potential
sulfur to be recovered.  The TNRCC does not endorse the use of
a particular sulfur recovery technology.  However, the
proposed technology should meet the target performance level
consistently and have high reliability.  Exemptions provided
in New Source Performance Standards do not supersede the
requirements of a permit to meet a specified recovery rate. 
An air quality permit will be issued based on an expected
recovery efficiency which is not variable with lower inlet
concentrations.  The proposed technology must be able to
consistently achieve the represented efficiency over the
expected range of operating conditions.  Additionally, the
control system should have minimal downtime and be equipped
with alternative means to handle the acid gas other than long
term flaring.  Lastly, the control system should provide
measures to ensure enforceability.  

Starting with control effectiveness, Table 1, Sulfur Recovery
Efficiency Guidelines, lists the expected efficiencies based
on the size of the facility being permitted.  At petroleum
refineries, SRU greater than ten long tons per day (LTPD) will
probably need sort of TGTU technology to achieve the
guideline.  

In order to maintain ongoing reliability, measures should be
incorporated into the facility design to insure proper
operation.  A high efficiency is meaningless if the SRU is not
on-line.  To this end, the design must incorporate two ideas,
proper upstream handling of acid gas and design of the SRU.  

Due to potential fluctuations in inlet gas flows and H2S
concentration, maintaining acid gas quality to the SRU can be
a problem at onshore natural gas plants, but tends not to be
a problem at petroleum refineries.  Feed to a conventional
straight through type Claus plant should maintain a
concentration of at least fifty percent H2S.  If
concentrations of forty percent H2S or less are anticipated,
additional measures such as split flow design, acid gas
enrichment and feed/air preheat should be considered to
maintain stable combustion in the Clause furnace.  A
conventional Claus unit is not recommended for concentrations
of thirty percent H2S or less and other sulfur technologies
should be explored.  These values were obtained from available
literature and do not necessarily reflect the position of the
agency.  

A straight configuration is usually recommended for a Claus
unit where the H2S feed concentration exceeds forty percent. 
With lower concentration feeds, stable combustion is difficult
because a smaller portion of the entire feed stream will be
oxidized in the furnace.  The split-flow design allows part of
the flow to be routed directly to the waste heat boiler. 
Utilizing split-flow allows an increase in the flame
temperature in the front burner zone to properly destroy
ammonia (NH3) and hydrocarbons (HC) and oxidize H2S.  Problems
with this design include the potential for some HC, NH3 and
other contaminants to be fed directly from the amine acid gas
to the first catalytic reactor.  This may be eliminated as a
concern through the use of burners utilizing high intensity,
swirling action to aid the destruction of these contaminants. 

Contaminants in the acid gases being fed to the SRU can
drastically affect not only performance but also reliability. 
The two main contaminants are NH3, which is not usually a
problem at onshore natural gas plants and HC.  NH3, if not
handled properly, will cause NH3 salt deposits not only in
the SRU but in any associated TGTU.  Slugs of HC can upset the
chemical balance in the thermal reactor causing decreased
sulfur conversion.  HC can also foul catalyst in the converter
beds.  

In order to minimize NH3 in the amine acid gas, adequate water
wash should be provided at the upstream hydrotreating and
hydrocracking units.  The maximum amount of NH3 should be
removed prior to treatment in the amine units.  Otherwise, NH3
will carry through with the amine acid gases to the Claus
thermal reactor.  Since NH3 is not expected in the amine acid
gas stream, the NH3 will not be properly destroyed in the
Claus furnace, thereby contributing to the formation of NH3
salts in the catalyst beds.  If thorough water wash is not
feasible at upstream units, then the water draw-off from the
amine regenerator overhead drum should be increased to assure
minimum carryover of NH3 to the Claus reactors to avoid this
problem.  

To prevent HC slugs from carrying over into the SRU, adequate
retention time in the sour water system and the amine system
should be provided upstream of the SRU.  Typically, acceptable
retention times for sour water have been three to five days to
allow for adequate HC separation.  A retention time of thirty
minutes is an acceptable value for the amine surge tanks. 
Further, operation of the rich amine flash tanks at the lowest
possible pressure should maximize the removal of light HC. 
This requires a low-pressure gas line returning flashed vapors
back to the upstream processes or to a flare.  

SRU Design

Now that upstream considerations have been considered, the SRU
design should be evaluated for reliability.  Reliability plays
a major part in the review of a proposed technology. 
Consideration must be given to acid gas handling during SRU
downtime.  An adequate system will have an on-stream time of
ninety-eight to ninety-nine percent.  The TNRCC expects the
applicant to limit acid gas flaring as much as possible.  To
that end, the preference is for no acid gas flaring during
scheduled maintenance.  For larger facilities, parallel trains
will prevent acid gas flaring by allowing one train to process
the acid gas if the other goes down.  To put this in
perspective, for onshore natural gas plants, parallel and
redundant units are especially preferred if the amount of
sulfur recovered is greater than eighty LTPD.  For petroleum
refineries, this level is ten LTPD.  The ability to
interchange should be built in the design such that each train
has the ability to process seventy-five percent of design
maximum load for the total sulfur complex.  Therefore, if one
SRU or TGTU goes down, the other can operate at 100 percent of
its design maximum and production will only have to be cut
back twenty-five percent of the combined total sulfur
throughput for both trains or fifty percent of the throughput
for each individual train.  If the applicant can not propose
redundant and parallel systems, a curtailment system should be
proposed to allow for no continuous flaring in the event of an
upset at the SRU.  For partially redundant systems, acid gas
curtailment will still be necessary as the applicant is still
restricted to operating within the permitted maximum allowable
emission limits.  The applicant should consider excess
capacity in the sour water and hydrotreating feed holdup to
allow the petroleum refinery to eliminate or reduce processing
during SRU downtime, thereby reducing the acid gas load to the
SRU.  

Additional reliability issues are the proper design of the
thermal reactor, the ability to by-pass the TGTU and feed the
acid gas directly to the incinerator, the availability of
installed or warehoused sulfur pit pumps and operation of the
tail gas incinerator (TGI) at a minimum high temperature
cutoff of 1800F.  A high temperature cutoff should help
prevent early shutdown of the TGI which would result in H2S
emissions from a cold stack.  The thermal reactor design
should include considerations for spare equipment such as
blowers, pumps, etc., proper burn technology to accomplish
destruction of low concentrations of HC (less than three
volume percent) and NH3 (about 300 ppmv) and adequate
residence time.  Process control considerations include the
installation of a tail gas analyzer to insure that the H2S/SO2
ratio will be maintained at an optimum value of two to one. 
Typically, the analyzer sends a signal to adjust the air
supply according to demand.  Future permit reviews will
emphasize more process control to aid in tracking NH3 and HC
in amine and acid gas streams.  

The design of reheat between stages in the Claus unit has also
been examined for its effects on sulfur recovery and
reliability.  In hot gas by-pass, boiler outlet gases usually
contain large sources of uncondensed elemental sulfur which
may result in a reversal of the Claus reaction.  Since hot gas
by-pass reheat results in a lower overall net sulfur recovery,
this type of reheat is discouraged.  Direct heat mixing of the
reactor feed and combustion products may result in the
formation of sulfur trioxide if the air control is not
accurate.  Low air rates may result in the production of
carbon from HC in the feed.  These problems may lead to a
shorter catalyst life.  Indirect reheat methods result in the
best sulfur recovery rate and potentially longer catalyst
life.  The conclusion is a preference for an indirect heat
transfer provided by direct fired heaters.  

As mentioned earlier, with the split flow design, HC slugs are
a threat to the first catalyst bed, since a portion of the
flow is not routed through the combustion zone.  For a split
flow design, the applicant should adequately address this
problem.  

To ensure enforceability of permitted emission rates, the
permit will include performance testing, continuous
measurement of emissions and record keeping requirements. 
This will include continuous emissions monitoring systems
(CEMS) for SO2 and oxygen and in some instances carbon
monoxide (CO), stack testing to calibrate the CEMS and to
demonstrate initial performance for all pollutants,
calculations of sulfur recovery, record keeping of sulfur
production, gas processing rates, start-up, shutdown, upset
and major maintenance information.  

In summary, an acceptable BACT discussion of SRU will
demonstrate that sulfur recoveries will be consistent with the
guidelines, the overall design of the upstream units will
provide good separation, the SRU will be designed for stable
operation, redundancies that minimize downtime will be
installed and during SRU downtime acid gas will be handled
consistent with regulations.  

Other Pollutants

Because the thermal oxidizer or TGI is a combustion device,
the unit will also emit products of combustion such as CO and
nitrogen oxides (NOx).  For CO emissions, a maximum of 100
ppmv is expected.  For NOx, low NOx technology should be used
to achieve a maximum NOx emission rate of 0.06 pounds per
million BTU fired.  Sulfur Recovery Efficiency Guidelines
March 1995

                                     Table 1

                           Expected Control Efficiencies
                                   (in percent)

                       Modified Facilities    New Facilities

Onshore Natural Gas Plants

50<x LTPD                     99.8+                99.8+

20<x<50 LTPD              98.5 - 99.8 (1)          99.8+

10<x<20 LTPD              97.5 - 98.5 (1)      98.5 - 99.8 (1)

2<x<10 LTPD                   96.0             96.0 - 98.5 (1)

0.3<x<2 LTPD              Case-by-Case (3)         96.0+ (2)

0 to 0.3 LTPD                 Flare                Flare

Petroleum Refinery

10<x LTPD                     99+                  99.8

0<x<10 LTPD                   96               96.0 - 98.5 (1)

Note:  Actual values negotiated case-by-case based on factual
       situations.  Values are preliminary.  

(1)  Applicant shall investigate all control options that can
     achieve sulfur recoveries within this range.  

(2)  Applicant should investigate technical practicability and
     economic reasonableness for installing some type of
     sulfur control technology with ninety-six percent
     recovery as a target.

(3)  Applicant will be asked on a case-by-case basis to
     investigate the technical practicability and economic
     reasonableness of installing some type of sulfur control
     technology.