H. NJUGUNA and J.
LEWIS, Worley Comprimo, Brentford, England, UK; and F. E. JENSEN, Topsoe,
Worley Comprimo and Topsoe have developed a new sulfur
recovery processa that combines
conventional Claus technology from Comprimo with the proven wet gas sulfuric acid
(WSA) process from Topsoe. In this combined process, sulfuric acid is produced
and recycled back to the Claus furnace to produce sulfur. The combination of
these two well-proven technologies results in a simple, reliable and
energy-efficient sulfur recovery processa.
new sulfur recovery processa offers a complete solution to
treat a variety of amine acid gas and sour water stripper (SWS) offgas and can reach sulfur recovery efficiencies of 99.9% or more without a Beavon
sulfur removal (BSR) amine-based tail gas treatment unit (TGTU), which is the
conventional setup and is known to be expensive to install and operate at
larger sulfur capacities.
In the previous two
articles (Part 1 in December 2022 and Part 2 in January 2023) in this three-part series, the new sulfur recovery processa
was introduced as a solution for Claus tail gas treating and meeting ever
challenging emissions requirements. The chemistry and other technical aspects
of the technology were compared against a Claus unit with conventional BSR
amine-based tail gas treating. The environmental benefits were evaluated by
comparing the carbon footprint of an SRU and BSR amine-based TGTU against the
new sulfur recovery processa configuration. Two cases studies (a
refinery case study and a gas plant case study) were evaluated, covering a wide
range of acid gas.
Having proved the chemistry and environmental merits (Parts 1 and 2,
respectively), this paper will evaluate the economics of the technology. For
operating expenditures (OPEX), the utility consumption and production and the
effect on the overall cost are evaluated, as are capital expenditures (CAPEX)
differences. Finally, the net present value of the two configurations will be
In both cases, it was found that the new sulfur recovery processa
represents more value due to savings in the utility consumption and the
production of HP/MP steam. Savings can also be found in CAPEX. A high-level indication
of the potential CAPEX savings of the new sulfur recovery processa
can be discerned by comparing the equipment count summarized in TABLE 6. Note: The
equipment count of the Claus section is the same for both options and is not
included in TABLE 6.
Only the equipment associated with the WSA is shown in the table under the new sulfur
Apart from a reduction in equipment count of nine items, perhaps the most
pertinent comparison is the removal of the three columns (quench column, amine
absorber and amine regenerator). This has some benefits in reducing the plot
area requirement in addition to CAPEX savings.
Refinery case. To quantify the CAPEX and OPEX savings, both configurations were
considered in a case study for a typical refinery application: a 270-tpd SRU
with typical refinery feed streams of amine acid gas and SWS offgas (TABLE 7). A sulfur
recovery of 99.9% was required. An acidified MDEA was used for the conventional
design so the benefits of that over-generic MDEA were already accounted for. A Class
4 factored estimate was prepared on a U.S. Gulf Coast basis. Details of the
The cost estimate considered facilities only within the SRU (ISBL). Common
factors were excluded (e.g., site preparation). The sulfur product value was
also excluded as it was common for both configurations.
The results were striking and are detailed in TABLES 8 and 9, first covering utility
8) and then monetized to give CAPEX and OPEX over 10 yr (TABLE 9).
The new sulfur recovery processa consumes more BFW and
cooling water, but this is more than offset by the reduction in use of electric
power and natural gas (i.e, $3 MM/yr vs. $3.6 MM/yr for total consumption). On
the production side, the new sulfur recovery processa produces much
more steam, giving an overall production figure of $4.9 MM/yr vs. $3.3 MM/yr.
The overall operating income for the new sulfur recovery processa is
just under $2 MM/yr, whereas the conventional design suffers an operating
income loss of $270,000/yr.
The operating income potential is heavily dependent on the value of HP
steam. The new sulfur recovery processa offers a distinct advantage
in the value of HP steam due to its impact on the overall operating income (FIG. 8). The
operating income breaks even at a steam cost of $7.6/t with the new sulfur
recovery processa vs. $15.3/t with an SRU with BSR amine-based TGTU.
Considering CAPEX, the new sulfur recovery processa
configuration is $61.8 MM vs. $69.4 MM—with a savings of 12% (and up to 30% using
generic MDEA in the Claus + BSR amine configuration) and the savings in OPEX, this
provides a total savings of $31 MM over 10 yr.
Gas plant case. To provide a different economic perspective of the new sulfur recovery
processa, a 1,330-tpd gas plant case in the Middle East with a lean acid
gas feed (45% H2S) was evaluated (TABLE 10). The sulfur recovery required is
99.9% This type of acid gas would typically require fuel gas co-firing with a
conventional setup to ensure BTEX destruction temperatures are achieved. A
hindered amine TGTU is required to meet the required sulfur efficiency. Like
the refinery case, the estimate is a Class 4 factored estimate on a U.S. Gulf Coast
basis. Details of the project
The cost estimate considered facilities only within the SRU (ISBL). Common
factors were excluded, as was sulfur product value, as it is common for both
configurations. The utility costs for the gas plant case are based on typical
costs in the Middle East region.
A comparison of the utility costs (TABLE 11) reveals savings that can be achieved
with the new sulfur recovery processa. The fuel gas consumption is
drastically reduced and significantly more HP steam is produced.
In the gas plant case, an operating income is not achievable in both
configurations. This is attributed to the consumption of fuel gas (FIG. 9). The new sulfur
recovery processa requires less fuel gas and electric power. Cooling
water is unavailable; therefore, refrigeration is necessary to achieve the
required cooling. The total consumption costs are still favorable to the new sulfur
recovery processa at $25.9 MM vs. $36.1 MM, with a savings of just
under 40%. The higher production of HP/MP steam by the new sulfur recovery
processa is $4.6 MM/yr, which is significant.
the annual operating costs of the new sulfur recovery processa are $14
MM vs. $29 MM, which is approximately half the cost.
The difference in fuel gas consumption is where the new sulfur recovery
processa provides the most value in the gas plant case. Fuel gas has
a large impact on operating costs. With a conventional configuration, fuel gas
consumption increases with leaner acid gas feed. There is a boundary at which
the costs of consuming fuel gas are considered too high and an alternative
solution could be considered, such as utilizing an acid gas enrichment unit.
This boundary is further extended if the new sulfur recovery processa
is implemented instead. The boundary line is dependent on the user and their valuation
of fuel gas.
The operating costs in the gas plant case (TABLE 12) are not supplemented by HP
steam to the same extent as the refinery case. However, the new sulfur recovery
processa offers a distinct advantage. The operating income breaks
even at a steam cost of $19.7/t with the new sulfur recovery processa
vs. $46.5/t with a conventional configuration. It should be noted that it is
unlikely that the user would have such high valuations of HP steam in a gas
the CAPEX, the new sulfur recovery processa configuration is $422.7 MM
vs. $427.6 MM, indicating a small savings of $5 MM. The requirement of fuel gas
co-firing in the new sulfur recovery processa case when compared to
SRU + BSR has the effect of increasing the size of the equipment and,
therefore, the CAPEX between the two cases is similar. The OPEX is where the
main difference is found: the new sulfur recovery processa gives a
savings of $14.9 MM—when
considering the costs over 10 yr, the savings is $155 MM.
After considering CAPEX and OPEX costs, the net present value (NPV) was
evaluated over 10 yr for both the refinery case and gas plant case. Assuming a
discount rate of 10% and excluding sulfur revenues, the results are presented
in TABLE 13.
Although the NPV is negative, the new sulfur recovery processa
still represents a more valuable proposition when compared to the Claus + Amine
option. The refinery case provides a $22-MM advantage to the new sulfur
recovery processa and the advantage is greater in the gas plant case
at $134 MM.
To evaluate the gas plant case study (1,330-tpd sulfur) and the refinery
case study (270 tpd) with a common metric, the NPV value per metric t of sulfur
produced can be calculated (TABLE 14).
Takeaways. The new sulfur recovery processa is the most cost-effective
per metric t of sulfur produced. The difference in NPV per metric t of sulfur
produced is $100,000 in both the refinery case and gas plant case in favor of the
new sulfur recovery processa when comparing the two configurations.
Economic features include:
This article (covering
commercial aspects) concludes a series of three articles detailing the new sulfur recovery processa. The December 2022 and January 2023 issues of Hydrocarbon
Processing included articles (Parts 1 and 2) covering technology and
environmental aspects. HP
NJUGUNA is a
Principal Process Engineer at Comprimo, part of the Worley group, and has
extensive experience working in the design of sulfur recovery plants
constituting the Claus process, SWS, amine regeneration and TGTUs throughout
his 15-yr career with the company. Njuguna has been heavily involved in the
early development of the TopClaus® technology. He graduated with an honors
degree in chemical engineering from the University of Nottingham in the UK and
earned an MS degree in forensic engineering and science from Cranfield
University in the UK. Njuguna is a Chartered Engineer and Member of the
Institute of Chemical Engineers (MIChemE).
JON LEWIS leads UK Operations for Comprimo, part of the Worley group, after
serving as Global Director for gas processing. Lewis’s responsibilities span consultancy,
project delivery, client support and business development. He has extensive
conceptual and detailed engineering experience and has held various roles
associated with gas processing terminals, offshore platforms and refineries in
his 29-yr career with the company, as well as managing the London Process
Department from 2004–2011.
He graduated with an MS degree in advanced chemical engineering from the
University of Manchester (UMIST) in the UK, is a Chartered Engineer and Fellow
of the Institute of Chemical Engineers (FIChemE), and has published articles
and presented at international conferences.
After graduation as a chemical engineer, FRANDS E. JENSEN has worked for Topsoe since 1979 in various marketing and sales
positions and has been dealing with most of the technologies offered by Topsoe.
Since 2003, Jensen has concentrated on the WSA, SNOX™ and TopClaus® technologies applied for sulfur removal
from offgases as Senior Sales Manager.