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Jun-2022

Achieving 95% direct CO2 reduction for hydrogen plants

Decarbonisation solutions targeting existing refinery hydrogen plants enable refiners to achieve long-term CO2 capture while minimising site space requirements and capital.

Ken Chlapik, Dominic Winch and Diane Dierking
Johnson Matthey

Viewed : 3856


Article Summary

Based on decades of reforming experience, solutions using Advanced Reforming technologies can be integrated into existing hydrogen plants for 95% carbon dioxide (CO2) reduction.1 The syngas industry can reduce its CO2 emissions using innovative solutions for the energy-efficient production of hydrogen, ammonia, and methanol that are demonstrated at scale and available today.

Conventional, or grey, syngas production uses a steam methane reformer (SMR) to convert gasified coal, natural gas, and other hydrocarbon based feedstocks into a mixture of hydrogen and carbon monoxide. The hydrogen produced via this process is used for petroleum based clean fuel, ammonia fertiliser, and methanol production.

The syngas carbon monoxide (CO) can be used to produce chemicals, fuel, and energy, or additional hydrogen (H2) via the water gas shift (WGS) reaction. While syngas production through the decades has focused on reducing production cost, attention is now on reducing greenhouse gas (GHG) emissions to meet 2050 net-zero CO2 emissions targets.

Broadening the use of proven Advanced Reforming technologies, as well as CO2 capture, utilisation, or storage technologies (CCUS), can significantly reduce the carbon intensity of syngas production. These CCUS technologies use existing technology and materials, manufacturing, and supply chain infrastructure, enabling these solutions to be utilised at scale today.

Valued assets
Fifty years ago, most of the hydrogen available on a refinery site was a byproduct stream from the catalytic reformer. As clean fuel legislation progressed around the globe, SMR based hydrogen plants have been the means to produce the additional hydrogen needed to manufacture these clean fuels, providing ultra-low sulphur fuels that improve the environment in our cities and regions.

There are more than 700 refinery hydrogen plants around the world, and nearly 90% of these plants are SMR based. Over 40% are less than 20 years old, with many still being depreciated. These more modern plants have been designed to improve the efficiency and cost of the hydrogen produced, as well as manage the capital cost of the hydrogen plant.

For the last 30 years, most of these plants have been designed with pressure swing adsorption (PSA) based hydrogen purification systems that reduce the additional fossil fuel demand for the SMR through off-gas recycling. The plants’ recycled stream, or PSA purge gas, is the predominant portion of the fuel to the SMR.

While there might be long-term refinery site or regional plans to introduce low carbon hydrogen-fuelled energy through new blue or even green hydrogen assets to meet 2050 net-zero CO2 emissions targets, many existing hydrogen plants (see Figure 1) will be revamped to address the largest single source of CO2 emissions within the refinery.

CO2 in SMR based H2 production
Conventional SMR technology comprises a fired heater with catalyst filled tubes, in which reforming reactions take place. Usually, gasified coal, natural gas, or other hydrocarbon based fuels, such as refinery off-gas and PSA purge gas, are burned with air in the fired heater to generate thermal energy required for the reforming reactions.

CO2 generated in the fuel side of the SMR is emitted in the flue gas stream and referred to as post-combustion CO2. In general, the post-combustion flue gas is produced at low pressure and contains water, excess oxygen, and significant quantities of combustion related impurities from the fuel and air. Although technically complex, established solvent based technologies can be used to capture post-combustion CO2.

The other source of CO2 originates from process-side syngas production, where natural gas is converted into a mixture primarily of H2, CO2, and CO. This syngas is processed in a WGS reactor to convert the bulk of the CO process stream (containing greater than 70% H2) into a PSA process to reach high level (99+%) purity H2 for use in hydroprocessing and isomerisation units to produce cleaner fuels.

The CO2 generated is at high pressure, and the process stream composition is simpler with minimal impurities, making it easier to utilise. Consequently, capturing this process-side byproduct CO2 is less complex and costly, and established solvent and absorbent based technologies can provide cost-effective solutions.

Capturing post-combustion CO2
In a post-combustion scheme, CO2 is removed from the flue gas stream. Amine based post-combustion technology has previously been deployed at a commercial scale, but uptake has been low due to high capture costs.4,5

New technologies, including amine based as well as cryogenic and other novel forms of post-combustion, focus on minimising cost and improving reliability. Using carbon capture at this location can achieve CO2 reductions of greater than 90%. However, since the SMR furnace operates at a negative pressure, the flue gas pressure is quite low and will complicate the design of the solvent based system.

Lower pressure requires larger equipment, needing more space. Plot space is likely at a premium at existing facilities. Fired heaters operate with excess O2, which will pass into the flue gas stream, while the make-up fuel will likely contain sulphur and other impurities. The amine solutions used for carbon capture are prone to oxidative and sulphur degradation.

Fresh amine will have to be added more often on a post-combustion system, increasing operating costs. There is also a significant amount of wastewater created by removing some impurities and reducing flue gas temperature.

Capturing pre-combustion CO2
CO2 in the pre-combustion scheme is removed from the process stream after the WGS reactor and upstream of the PSA. The process stream will contain known components (H2O, CH4, CO, CO2, and N2), so impurities such as oxygen and sulphur are not present and will not contribute to the degradation of the amine solution.

Pressure control exists at the PSA inlet, meaning this stream will be available at high, defined pressure. These factors simplify the design and reduce the size of the removal system. In addition, the operating cost of the liquid amine based contact system will be lower for pre-combustion carbon capture.

While these systems benefit from smaller plot space (see Figure 2) and solvent stability, pre-combustion capture means only the process-side CO2 is removed. The total CO2 generated in a hydrogen plant can typically represent up to 60% of the total carbon emissions, but will vary depending on plant conditions.


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