C. VENTHAM and J. Lewis, Worley Comprimo, Brentford, England, UK; and F. E. JENSEN, Topsoe, Lyngby, Denmark
It is widely accepted that state-of-the-art sulfur recovery technologies utilize the modified Claus process as well as some extension technology on the tail gas. To achieve the highest sulfur recovery, the extension technology converts all tail gas sulfur species to hydrogen sulfide (H2S) by hydrogenation and hydrolysis, which is subsequently captured in an amine absorber and recycled to the Claus thermal reactor. The industry has developed amine solvents of increased H2S selectivity, with the most selective often regarded as the best available technology.
One of the more interesting challenges to the tail gas treatment technology described above is the direct conversion to sulfuric acid—after all, that is the destination of much of the recovered sulfur. However, the logistics of that approach are complex, primarily with respect to local sulfuric acid demand. Technically, conversion to sulfuric acid can provide better economics and decreased environmental impact, if there are no transportation restrictions.
Worley Comprimo and Topsoe have developed a sulfur recovery processa based on proven technology, whereby sulfuric acid produced in a wet gas sulfuric acid (WSA) tail gas treating unit (TGTU) is recycled back to the Claus thermal reactor.
With fewer equipment items and demonstrable high reliability, coupled with an energy balance benefit evidenced by operating plants and studies, the new flow scheme challenges for the position of best available technology.
A series of three articles presented here and in two other issues of Hydrocarbon Processing cover all aspects of the technology. Part 1 (December 2022) covered the technological aspects and development, while Parts 2 and 3 cover environmental and economic aspects, respectively. Case studies covering a range of Claus plant acid gas feed streams are used for economic comparisons.
Part 1 presented the chemistry and technical aspects of the technology, which was compared against conventional BSR amine-based tail gas treating. It highlighted that the sulfur recovery processa is suitable for greenfield and brownfield applications with no waste streams produced or chemicals required.
This Part 2 will explore the environmental benefits of the lower utility consumption of the sulfur recovery processa at a time when many companies, countries and governments are acting to reduce their carbon footprint.
The carbon footprint and environmental benefit of the sulfur recovery processa are examined in two case studies, covering a wide range of acid gas. The CO2 emissions at the stack and equivalent CO2 emissions from utility producers and consumers are compared to those of an SRU and BSR amine-based TGTU flow scheme, with both technologies recovering 99.9% sulfur.
In both cases, it was found that the CO2 emissions are significantly lower with the new sulfur recovery processa, thanks to the lower natural gas requirement and electricity consumption, while producing significantly more steam that can be utilized outside the SRU facilities. Flow schemes of the two technologies being compared are shown in FIG. 5.
The first case study examines a greenfield oil refinery SRU, processing 90 mol% H2S amine acid gas and sour water stripper (SWS) offgas, producing 270 tpd of sulfur. The second case study is a greenfield gas plant in a hot climate processing 46 mol% H2S amine acid gas and producing 1,330 tpd of sulfur.
To compare the carbon footprint of the two technologies, this article will focus on the direct CO2 emissions in the flue gas and the equivalent CO2 emissions resulting from the utility consumers and producers.
TABLE 1 presents the utilities consumed and produced in the refinery case, with the incinerator utility consumption/production included with the TGTU.
As it can be seen from TABLE 1, the SRU utility consumption and production is slightly lower for the sulfur recovery processa, although both SRUs process the same quantity of amine acid gas and SWS offgas, and consist of the same design, producing the same quantity of sulfur. Because of the oxygen carrier function of the sulfuric acid recycled to the reaction furnace in the sulfur recovery processa, air demand in the reaction furnace is reduced. Similarly, no CO2 is recycled, as is the case with the TGTU recycle to the reaction furnace for the BSR amine-based TGTU. The smaller volumetric flow in the new sulfur recovery processa makes the SRU smaller, resulting in lower electricity consumption, steam production and consumption.
The major difference in the utility figures between the two technologies comes from the two TGTUs, where utility consumption is much higher in the BSR amine-based TGTU scheme.
The electrical consumption is lower in the WSA process, as there are no air coolers and considerably fewer pumps. The natural gas consumption is also lower in the WSA combustor than in the TGTU incinerator.
It is well known that TGTU regenerator reboilers consume a significant quantity of LP steam; in this case study, the LP steam produced in the SRU is insufficient to fulfill the demand in the regenerator reboiler. Conversely, the WSA produces a significant quantity of HP steam with no LP steam consumed.
This is further confirmed by the utility values from the gas plant utility summary shown in TABLE 2.
The energy consumption in the TGTU is even higher for this case, as fuel gas is required in a reducing gas generator situated upstream of the hydrogenation reactor.
In this case, coolant is required for both tail gas treating technologies when air cooling is insufficient, which impacts the electricity consumption of both technologies. In the SRU + BSR amine-based TGTU, coolant is required to cool down the amine in the hotter months of the year, while coolant is required in the WSA year-round. This would also be applicable to a refinery case in a warm climate.
Due to the leaner amine acid gas, natural gas co-firing is also required in the SRU reaction furnace to achieve a high enough temperature to destroy benzene, toluene, ethylbenzene and xylene (BTEX) present in the acid gas. This demand is higher in the SRU and TGTU flow scheme, as the TGTU recycle further dilutes the acid gas. A combustion air pre-heater is also implemented to help increase the reaction furnace temperature. In the SRU and TGTU flow scheme, a fired heater is deployed to heat up the combustion air rather than a steam heater, as a steam heater would not provide sufficient heat to reach the required temperature in the reaction furnace. This consequently further increases natural gas demand. In the sulfur recovery processa scheme, a combustion air preheater can be deployed utilizing some of the HP steam produced in the waste heat boiler, thus optimizing heat integration within the sulfur recovery facilities.
The increased steam production and lower natural gas and electricity consumption make the sulfur recovery processa a more energy efficient technology in both case studies, with yearly savings as shown in TABLE 3.
These savings will inexorably translate into a lower carbon footprint for the sulfur recovery processa. The savings in natural gas consumption are reflected in the lower CO2 emissions in the flue gas. In FIGS. 6 and 7, the total CO2 emissions in the flue gas are represented, which includes the CO2 emissions generated from natural gas consumption.
The acid gas processed in the refinery case study contains a small quantity of CO2 and so does not account for a substantial amount of the CO2 emissions at the stack, which come primarily from burning natural gas in either the SRU incinerator or WSA.
The gas plant case clearly illustrates the impact of the higher CO2 content in lean acid gas on the CO2 emissions at the stack. In this case, the CO2 in the feed gas represents the larger part of the emissions. However, direct CO2 emissions at the stack are lower with the sulfur recovery processa for both cases studied due to lower natural gas consumption. It should be noted that the CO2 emissions produced from the combustion of the natural gas in the fired heater in the BSR amine-based TGTU scheme are not accounted for here, as this results in indirect CO2 emissions.
Consumer and producer emissions. Beyond the direct CO2 emissions from the flue gas, the impact of indirect CO2 emissions from the utility consumers and producers should also be considered.
For this article, it is assumed that the electrical power required in the various blowers, pumps and air coolers is supplied by a national grid. For the refinery case study, the country’s equivalent CO2 emissions factor for electricity generation is 0.33 kg CO2e/kWh of electrical energy, while it is 0.43 kg CO2e/kWh of electrical energy for the country where the gas plant is located. The emissions factor will vary from country to country—depending on its energy strategies—so a country where electricity is produced in coal-fired power stations will have a high emissions factor. Conversely, a country producing electricity from renewable sources or nuclear power will have an emissions factor near zero.
SRUs are usually exporters of steam that can be used outside the SRU facility. Typically, steam is generated in a boiler using the heat produced from burning natural gas. If the steam exported from the SRU is consumed outside the facility, it represents a savings in equivalent CO2 emissions. The CO2 emissions factor for steam generation is calculated assuming a boiler efficiency of 85% and natural gas utilized as fuel, which results in a CO2 equivalent emissions factor of 0.20 kg CO2e/kWh of steam energy.
The carbon footprint impact from the supply of cooling water, BFW and the treatment of boiler blowdown were not calculated in the case studies but would contribute to indirect CO2 emissions. Equivalent CO2 emissions factors for water supply and water treatment are complex to calculate as they are directly impacted by the local availability of water, the size and type of utility system, and the water treatment being deployed. For this reason, equivalent CO2 emissions from water supply and treatment have not been assessed here. However, the following observations can be made for the comparison of the two technologies. The indirect CO2 emissions of the water consumption in the sulfur recovery processa would be higher than in the SRU and TGTU process, as the water demand (consisting of BFW and cooling water) is higher. However, the sulfur recovery processa does not produce wastewater streams or require chemicals, which tend to be energy demanding. Therefore, the carbon footprint of the higher water consumption in the sulfur recovery processa would be offset by the additional emissions resulting from the energy intensive treatment of wastewater and use of MDEA in the TGTU.
From the utility summaries presented in TABLES 1 and 2, the equivalent CO2 emissions are calculated for the sulfur recovery processa and SRU and TGTU flow schemes, while the direct CO2 emissions from burning natural gas in the TGTU incinerator or WSA combustor are accounted for in the flue gas emissions, as depicted in FIGS. 6 and 7.
Both the calculated direct and indirect CO2 emissions are lower for the new sulfur recovery processa, with significantly higher savings in CO2 emissions from steam production, which clearly shows the incentive of using the steam produced in the SRU outside its battery limit. This results in negative net CO2 emissions for the refinery case study.
In the gas plant case, both direct and indirect CO2 emissions are again lower for the sulfur recovery processa, resulting in almost half the net CO2 emissions thanks to lower natural gas consumption and high production of HP steam that can be used outside of the SRU facilities.
Over a 25-yr plant lifetime, in the refinery case, the sulfur recovery processa saves 784,250 t of CO2 e. An estimated 1,018,504 trees would be required to compensate for the higher emissions from the SRU and BSR amine-based TGTU. In the gas plant case, the sulfur recovery processa saves a staggering 8,015,881 t of CO2 e over 25 yr. An estimated 10,410,209 trees would be required to compensate for the emissions in this case.
The various configurations of the sulfur recovery processa mean the technology can compete with the long-established but energy-intensive BSR amine-based TGTU to achieve the tightest of SO2 emissions.
Takeaways. The environmental benefits of the sulfur recovery processa include:
Part 3 of this article will appear in the February 2023 issue. HP
NOTES
CAMILLE VENTHAM is a Senior Process Engineer at Comprimo, part of the Worley group. She has 16 yr of experience in the oil and gas industry in both design and technical studies and is responsible for managing all aspects of the process engineering and design of sulfur recovery units and TGTUs. Ventham holds an MS degree in chemical engineering from HEI (Hautes Etudes d’Ingenieur), Lille, and 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.