refining india 2023
customer’s process specialists, who iter- ated the Compabloc and S&T performances at different temperature approaches. The optimum point, in this case, was to design the Compablocs for a 12°C pinch tempera- ture and a 22°C HAT, limited by the perfor- mance of the existing S&T on the cold end. This performance met the project’s goals, and the solution was implemented in 2016. The refinery started up the Compablocs in early 2017. The thermal and hydraulic per- formance was exactly as expected. However, after several months of operation, increases in pressure drop were detected on the hot end of the feed side in the Compabloc, located at the dry point of the exchanger. The root cause of fouling was determined to be an excess of corrosion inhibitor being dosed in the naphtha upstream, causing the filming agent to be deposited at the dry point of the feed. The Compabloc was cleaned of the fouling material, and a process adjust- ment was made, after which performance returned to the typical unit cycle length.
Overhead condenser
Fuel gas and H O to gas sweetening
Feed/ bottoms exchanger
Stripper
Water to sour water stripper
Make - up H
Recycle compressor
Reboiler
Combined feed exchanger
Charge heater
Naphtha feed
Desulphurised naphtha cooler
Desulphurisation reactor
Desulphurised naphtha
Contact: salwati.ahmad@alfalaval.com
Figure 3 Compabloc in naphtha hydrotreating unit
Cost-driven natural gas vs hydrogen power for generators
Rene Gonzalez Editor, PTQ
as a system. Although limited delivery technology for hydrogen infrastructure is available commercially, a viable infra- structure requires efficient hydrogen deliv- ery from where it is produced to the power generator. Plans are still in their infancy for the delivery systems. These systems include pipelines, liquefaction plants, trucks, stor- age facilities, compressors, and dispens- ers involved in delivering hydrogen fuel. Limited blending of hydrogen in NG pipe- lines and related infrastructure continues, but problems with leakage and embrittle- ment are of concern to pipeline operators. DOE’s Hydrogen and Fuel Cell Technologies Office is focused on develop- ing technologies that can produce hydro- gen at $2/kg by 2026 and $1/kg by 2031 via net-zero-carbon pathways in support of the Hydrogen Energy Earthshot goal of reducing the cost of clean hydrogen by 80% to $1 per 1 kilogram in 1 decade (‘1 1 1’). Meanwhile, continued development of shale-based resources, such as the Eagle Ford in Texas and the nascent but giant Vaca Muerta in Argentina, will stabilise NG prices for decades. Falling renewable power costs and improving electrolyser technologies could perhaps make green hydrogen cost-effec- tive in the future. There has been a recent surge in new proposals for burning hydro- gen, favoured by ESG investors and hydrogen ‘virtue signallers’. Global hydro- gen demand grew about 3% in 2022 but remains concentrated in traditional uses, with slow penetration in new uses.
produce carbon dioxide (CO₂) emissions when burned, making it a viable alternative to NG in efforts to reduce carbon footprints • Long-term sustainability : Hydrogen can be produced using various methods, including electrolysis of water (using renew- able energy) and biomass gasification • High energy density : Hydrogen has a higher energy content per unit of weight compared to NG, leading to more efficient energy storage and transportation • Distributed production : Hydrogen can be produced locally, enabling distributed energy systems that are not dependent on large NG pipelines, further enhancing energy resilience. Challenges It is important to note that hydrogen also comes with challenges: • Production cost : Electrolysis-based hydrogen production is more expensive compared to NG, with various predictions as to when technical advancements will improve cost-effectiveness • Infrastructure : Significant infrastruc- ture changes come with hydrogen fuel, including production, storage, and distribu- tion facilities, a potential barrier to its wide- spread adoption • Storage and transportation : The low density of hydrogen as a gas requires specialised storage and transportation infrastructure • Safety concerns : Hydrogen is highly flammable, difficult to refuel, requiring stringent safety measures, especially in confined spaces or densely populated areas. While the value for many power gener-
ators is determined by the lower cost of NG, the primary driver for others is the role hydrogen can play in transitioning to cleaner energy systems. Choosing pure or partial hydrogen concentrations over NG for pow- ering generators depends on specific cir- cumstances, availability of resources, and technological advancements in the field. Some industrial infrastructure, such as power plants, is under construction that will start with a low hydrogen-to-NG ratio and eventually transition entirely to hydrogen, making the plant carbon emission-free, but there are significant challenges, including: • Compressors used for NG may require modifications to handle hydrogen, espe- cially at higher hydrogen concentration • With hydrogen having different cryogenic properties compared to LNG, tank materi- als must be compatible to prevent leaks or structural issues • Hydrogen has a higher propensity for embrittlement and leaks compared to NG, so safety measures and risk assessments must be thoroughly evaluated when trans- porting and handling hydrogen through established LNG infrastructure • To avoid contamination and potential safety issues, ensuring the purity of the hydrogen being transported is crucial, which may also include the need to take additional NG purification steps to meet the required hydrogen purity levels. In a recent publication by Keith Williams at Seeking Alpha, the point is made that in the hydrogen economy, the picture is con- fusing, and the timeline is too long. Further research is needed to analyse the trade- offs between hydrogen production and delivery options when considered together
Regulatory policies promoting green hydro- gen are accelerating, but natural gas (NG) is far more competitive on a per-cost basis. Generators can be powered with a blend of NG gas and as much as a 20% hydrogen mix until hydrogen costs can be reduced, but challenges are many for making it a dis- patchable resource. Green hydrogen pro- jects are still at the proof-of-concept stage. Even so, generators are already availa- ble that can run from 0–100% hydrogen blends, with relatively efficient field retro- fitting from NG to hydrogen. Competitive hydrogen-based power gen- eration depends on its production cost using electrolysers, infrastructure setup, and operation and maintenance expenses. Green hydrogen costs are expected to decline to about $15/MMBtu ($2/kg) by 2030 and $7.4/MMBtu ($1/kg) in 2050. However, this must be considered against the much lower IMF 2024 projected Henry Hub cost for NG at $2.65/MMBtu. The World Bank expects that the NG price at Henry Hub will stabilise at $4 per MMBtu by 2030. Even with favourable long-term NG cost projections, government policies sup- porting the adoption of hydrogen tech- nologies weigh heavily on making 100% green hydrogen a mandated alternative to NG beyond 2030 due to various fac- tors, depending on the specific context and requirements, including: • Renewable energy integration : By utilising hydrogen as a fuel, the genera- tor’s operation can be aligned with clean energy goals and reduce greenhouse gas emissions • Decarbonisation : Hydrogen does not
Contact: editor@petroleumtechnology.com
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