H. NJUGUNA and J. LEWIS, Worley Comprimo, Brentford, England, UK; and F. E. JENSEN, Topsoe, Lyngby, Denmark
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.
The 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 compared.
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 recovery processa.
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 project include:
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 production/consumption (TABLE 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 include:
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.
Overall, 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 plant case.
Evaluating 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
NOTES
a TopClaus®
HESBON 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.