Stream
Recovery Compressor Module cost
BEP
H 2 value over five
Total Capex
Total
Five-year
(kg/hr H2)
power required
+ancillary + compression
(months)
Opex over five years
ROI
years
Catalytic reformer 95% purity Catalytic reformer 99% purity Catalytic reformer 99.9% purity Isomerisation unit 95% purity Isomerisation unit 99% purity Isomerisation unit 99.9% purity
991.9 994.1 941.3
1,243.9
$0.21 $1.39 $3.06 $0.21 $1.13 $1.33
3.86
$74.3M $74.5M $70.5M $22.4M $22.3M $21.3M
$4.7M
$4.1M $2.2M $2.7M $0.9M $0.7M $1.2M
742%
647
44.12 99.76
$55.2M $117.0M
30%
817.2 279.3 216.9 365.8
-41% 759%
299.38
4.52
$1.7M
297.3 284.4
35.41 41.78
$13.2M $14.5M
60% 35%
Table 4 Isomerisation unit and catalytic reformer economic analysis with recompression to feed pressures
a $4.7M Capex investment and $4.1M in compression costs over the membrane life. Figure 2 shows a visual comparison of each case vs the cost of new H 2 from a grey SMR H₂ plant and a blue SMR H₂ plant, including the Opex cost for compression back to feed pressures. Conclusions ROG streams will be a crucial source of H2 in refineries as product regulations and crude processing requirements drive increased H 2 demands. The need will further increase as energy companies look to limit heavy sources of carbon within their operations to meet net zero goals by 2050. As refiners shift from SMR-produced grey H2 to green or blue, costs will increase, lowering the economic barrier to down- stream H 2 recovery and purification. In this analysis, we reviewed sample ROG streams pro- duced from several hydrotreaters, a hydrocracker, an isom- erisation unit, and a catalytic reformer for their potential separation and purification via Divi-H, a next-generation H 2 separation membrane produced by Divigas. The gasoil and diesel/kerosene hydrotreaters, as well as the hydrocracker, are great membrane separation utilisation options. Separation and purification costs range from only $0.023-$0.55 without recompression, depending on the purities required, and there are multiple lower-pressure units capable of receiving these streams at the produced pressures. Even where recompression is required, H2 is producible at 99.9% purities with payoff periods of less than two years, even in an environment where grey H 2 is available. These eco - nomics will only improve with blue and green H 2 production. The naphtha hydrotreater and isomerisation units operate at reduced pressures and, therefore, have less driving force for membrane separation. However, the case for recapture via membrane separation is still compelling, depending on the processes in place at the refinery. Without recompres- sion, separation and purification costs range from $0.048 to $1.23 per kg, depending on the purities required. With compression back to feed pressures, this cost moves to $0.17-$1.33 per kg and is still lower than the average cost to produce an additional kg of fresh H2 from a grey process. Even at the lower operating pressures, these processes have membrane separation value in a grey H 2 refinery, which will only improve with movements to blue and green H 2 . Finally, we looked at the catalytic reformer and the FCC as sources of H 2-rich ROG. The catalytic reformer is an H2 producer whose H₂ is frequently used to supplement the
SMR unit for the refinery. The FCC produces extremely low-pressure, low-purity H2. Both units are unlikely to be good candidates for H₂ recovery via membrane separation, and in the case of the catalytic reformer, they will continue to leverage existing PSA technology for any H 2 recovery. Based on this assessment, the following areas are excel- lent locations for membrane separation and purification to recover H 2 : • High-pressure systems where a reduced-pressure H2 per - meate stream can be fed to lower operating pressure units. • ROG streams where traditional PSA or cryogenic sepa- ration is not feasible or requires excessive pre-processing and filtration. • Recovery areas where H 2 purity is flexible. This could be units where the H 2 will be recycled directly back into the same unit after compression to increase H₂ partial pres- sures while removing contaminates. • Areas where ROGs containing greater than 50% H₂ are being fed to fuel gas systems and are not currently recycled. References 1 Bergerson J A, Petroleum Refinery Life Cycle Inventory Model (PRELIM), PRELIM: The Petroleum Refinery Life Cycle Inventory Model, Calgary , Alberta, Canada: University of Calgary, 2022. 2 Faraji S, Sotudeh-Gharebagh R, Mostoufi N, Hydrogen recovery from refinery off-gases, Journal of Applied Sciences, 2005, pp.459-464. 3 Harrison S, Marquez M, The key to the lock, Hydrocarbon Engineering , 2022. 4 Kunz R G, Combustion of Refinery Fuel Gas, John Wiley & Sons, Inc., 2009. 5 LaFleur A, Use and optimization of hydrogen at oil refineries, DOE H2@Scale Workshop, University of Houston, 2017. 6 Meyers R A, Handbook of Petroleum Refining Processes, McGraw- Hill, 2003. 7 Mivechian A, Pakizeh M, Hydrogen recovery from Tehran refinery off-gas using pressure swing adsorption, Korean J. Chem. Eng , 2013, pp.937-946. 8 Patel N, Baade B, Fong L W, Khurana V, Creating value through refin- ery hydrogen management, ARTC , Singapore , 2006. 9 Speight J G, Handbook of Petroleum Refining, Boca Raton, FL, CRC Press, 2017. 10 Tagliabue M, Refinery off-gas in hydrogen production, Digital Refining, 2022. Zach Foss is Director of Business Development for Divigas, responsible for sales, marketing, strategic initiatives, and project management. He has 10 years of experience manufacturing and selling downstream pet - rochemical and speciality products. He holds a BS in chemical engineer - ing from the University of Texas. Email: Zach.foss@divigas.com
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