CO2 capture options for steam methane reforming based hydrogen manufacturing units

A growing number of national governments and energy companies, including Shell, have announced net-zero-emission ambitions. To help fulfil their responsibilities under the 2015 Paris Agreement on climate change, governments around the world are increasingly creating incentives for reducing CO2 emissions and producing low-carbon products through tax credits (the USA having led with 45Q) or emission credit trading schemes such as the low-carbon fuel standards in California and British Columbia.

Laurent Thomas & Gary Bowerbank

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Article Summary

A growing number of national governments and energy companies, including Shell, have announced net-zero-emission ambitions. To help fulfil their responsibilities under the 2015 Paris Agreement on climate change, governments around the world are increasingly creating incentives for reducing CO2 emissions and producing low-carbon products through tax credits (the USA having led with 45Q) or emission credit trading schemes such as the low-carbon fuel standards in California and British Columbia. They are also directly penalising CO2 emissions. For example, by 2030, Norway plans to increase its carbon tax from $94 to $2351 per tonne of CO2 and Canada is increasing its carbon tax from $39 to $133 per ton of CO2.² Consequently, refiners and chemical plants have a mandate to reduce their CO2 emissions substantially.

The UN’s Intergovernmental Panel on Climate Change special report on the impact of a 1.5°C rise on global warming concludes that “early scale-up of industry carbon capture and storage is essential to achieve the stringent temperature target”. The International Energy Agency agrees, stating that carbon capture, utilisation and storage (CCUS) is a key technology for reducing CO2 emissions in carbon intensive industrial processes and offers one of the lowest-cost ways of doing so. 

By 2050, 2.8 billion t/y of CO2 needs to be captured and permanently stored to meet the International Energy Agency’s sustainable development scenario, which meets the UN’s Sustainable Development Goals for energy access, emissions and air quality, and has a 66% probability of limiting global temperature rise to 1.8°C.³ Currently, CCUS projects capture about 40 million t/y of CO2, so many more projects are needed in the coming decades.⁴

CCUS offers a cost-effective way to enable carbon-intense industries to continue to operate through the energy transition. And, it has been proven through the successful decarbonisation of coal-fired power, oil sands and cement businesses that needed to reduce their emissions to secure their social licences to operate.

For refineries and chemical plants, any serious ambition to reduce carbon intensity is likely to include CCUS to decarbonise processes that inherently generate CO2 emissions, although energy-efficiency initiatives, fuel switching and process optimisation will be part of the solution.

Leveraging experience
Carbon capture technology is not new; it is established and proven. In the 1930s, carbon capture technologies began commercial operation in the processing of natural gas. In the 1970s, commercial scale CO2 injection into reservoirs started. To date, more than 260 million tonnes of anthropogenic CO2 has been captured and stored, mostly through enhanced oil recovery (EOR) projects; the current CCUS capacity is about 40 million t/y.⁴

Other energy-intensive sectors, for example, coal-fired power generation, oil sands extraction and cement manufacture, have already been charged with dramatically reducing the carbon intensity of their operations. Refiners can leverage the operational experience, technologies and expertise from these sectors to do the same.

For example, the coal-fired power generation sector, after a first generation of carbon capture projects with a capture cost of about $100/t of CO2, is now targeting costs of half this, about $50/t of CO2, for its future projects.³

Why target hydrogen manufacturing units? 
Upgrading the bottom of the barrel to clean fuels requires hydrogen. Refineries and chemical plants often have a hydrogen manufacturing unit (HMU) based on SMR technology. But an HMU creates a substantial amount of CO2 emissions — from both chemical reactions and burning fuel to power the process. Many refinery units produce CO2 (see Figure 1), but the HMU is a good target for carbon capture because it generates a large, relatively pure stream of CO2. It also provides an opportunity to consider the relative merits of CO2 capture from high-pressure, pre-combustion and low-pressure, post-combustions streams using two mature Shell technologies (Figure 2).

High and low pressure options 
This article showcases two leading technologies with established records for cost-effective carbon capture in a wide range of industries:
-  Shell’s CANSOLV* CO2 Capture System for capturing CO2 from low-pressure streams, including flue gas; and
-  Shell’s ADIP* ULTRA solvent technology for capturing CO2 from high-pressure process streams.
The selection of a retrofitting option for a refinery (pre- or post-combustion) depends on, among other factors, the value assigned to the captured CO2 (from avoided tax, tradable credits or income from its use in EOR or other industrial applications).

Low-pressure streams
Shell’s CANSOLV CO2 Capture System can capture up to 99% of the CO2 from post-combustion, low-pressure off-gases. As a tail-end, low-pressure CO2 capture technology, it is well suited for retrofitting. It uses a regenerable solvent based on a proprietary amine to capture the CO2, which is released as a pure stream that can be sold, sequestered or used in EOR.

In refiners’ technical and economic evaluations for capturing CO2 from flue gas, the CANSOLV CO2 Capture System may emerge as the preferred option because of key features such as:
-  CO2 purity. The pure CO2 product enables EOR, CCS or utilisation of the captured CO2.
-  Adaptability. The system is highly adaptable to a wide variety of industrial applications with CO2 concentrations from less than 3% to 25% and higher. The design and the simple principle of operation ensure high turndown, transient operation flexibility and long run lengths between turnarounds.
-  Low waste. The process uses a regenerable solvent with improved resistance to oxidative and thermal degradation and, thus, produces little in the way of direct waste by-products.
-  Retrofit suitability. As a tail-end system, it is ideal for retrofit scenarios.
-  Low operating costs. The system offers cutting-edge performance. Its low parasitic energy consumption, fast kinetics and low volatility help to reduce the costs of operation and amine consumption.
-  Track record. The largest application in operation is designed to capture 1 million t/y of CO2 and has been operating for four years (see the SaskPower case study)

Process description
The key steps of the CANSOLV CO2 Capture System (see Figure 3) are as follows:
1. The feed gas is quenched and saturated in a circulated water pre-scrubber.
2. The gas contacts the lean amine solution in a countercurrent packed absorption column.
3. CO2 is absorbed and the treated gas exits to atmosphere.
4. Midway along the column, partially loaded amine is removed from the tower, cooled and reintroduced over a layer of mass-transfer packing.
5. CO2-rich amine from the absorption column is pumped through a lean—rich amine heat exchanger and then to the regeneration column (stripper).
6. Rising, low-pressure, saturated steam in the column regenerates the lean amine solution. CO2 is recovered as a pure, water-saturated product.
7. Lean amine is pumped from the stripper reboiler to the absorption column for reuse in capturing CO2.
8. The CO2 is directed to by-product management systems.

Case study: SaskPower
To extend the operating life of the 150-MW Unit 3 at its Boundary Dam power station in Saskatchewan, Canada, SaskPower needed to reduce its CO2 and sulphur dioxide (SO2) emissions. This six-unit, lignite-fired plant is SaskPower’s largest coal-fired power station and a significant source of electricity for the region.

After carefully evaluating a range of technical options, SaskPower chose to add a CANSOLV SO2—CO2 Integrated Capture System for combined carbon capture and flue gas desulphurisation. This involved adding a 55-m-tall CO2 absorber, a 40-m-tall CO2 stripper, a 31-m-tall SO2 absorber and a 17-m-tall SO2 stripper.

The unit is designed to capture 1 million t/y of CO2, which is compressed, transported through pipelines and used for EOR in nearby oil fields. The CO2 is thus permanently stored in deep geological formations where it cannot contribute to climate change.

The SO2 from the flue gas is converted to up to 60 t/d of sulphuric acid — a marketable by-product. Among its many other potential applications, the acid can be a feedstock for the local fertiliser industry.

The SO2—CO2 capture plant and its underlying chemistry enable SaskPower to continue to operate under strict Canadian CO2 emissions regulations.

High-pressure streams
In addition to the possibility of capturing CO2 from low-pressure flue gas, Shell ADIP solvent technology offers the alternative of capturing CO2 from the high-pressure process gases. The technology is deployed at more than 500 Shell and non‑Shell sites worldwide and has a proven record in the natural gas sector for deep removal of CO2. It is increasingly finding applications in refining.

The latest generation of this technology is ADIP ULTRA, which uses an optimised solvent formulation and an improved design based on years of operational lessons learned. Used with the latest-generation column internals (Shell Turbo Trays), this technology can easily achieve bulk removal or meet deep specifications for the treated gas while optimising both the capacity of the solvent and the regeneration duty (see Figure 4).

Compared with using conventional accelerated methyl diethanolamine, ADIP ULTRA technology can help to:
-  Reduce capital costs by up to 30%, thereby increasing project net present value;
-  Lower regeneration energy requirements by up to 30%;
-  Capture up to 25% more CO2, thereby enabling monetisation of difficult gas without capital investment; and
-  Provide operating stability, which enables operators to push the limits
ADIP technology’s applications include the removal of hydrogen sulphide and CO2 from refinery and natural gas streams, and the bulk removal of CO2 from gas streams.

Case study: Quest

The Scotford upgrader at the Athabasca oil sands project in Alberta, Canada, produces synthetic crude oil by processing mined bitumen with hydrogen at a high temperature and pressure to break up the large hydrocarbon molecules of the bitumen. The hydrogen is generated by three on-site HMUs that create significant CO2 emissions.

Shell added CO2 capture infrastructure adjacent to the HMUs. This uses amine absorbers based on ADIP ULTRA technology to capture about 80% of the CO2 from the HMUs’ process gas streams. The captured CO2 is then dehydrated and compressed before being transported by pipeline about 75 km and injected into a layer of rock more than 2 km underground.

Value delivered
During its first five years of operation, the Quest project has successfully captured and sequestered more than 5 million tonnes of CO2 from the Scotford upgrader. The facility has proven to be capable of capturing in excess of its nameplate capacity of 1 million t/y of CO2. Reducing CO2 emissions by 1 million t/y is equivalent to taking 175,000 North American cars off the road.

Quest is the world’s first commercial-scale CCS project for an oil sands operation.

Targeting the HMU
HMUs generate large, relatively pure CO2 streams and provide opportunities for CO2 capture from either the high-pressure, pre-combustion or the low-pressure, post-combustion streams. This gives refiners the flexibility to consider these two different routes to capturing significant quantities of CO2 at their facilities. It also provides the opportunity for a cost—benefit comparison of the two technologies described above to illustrates their relative benefits.

A typical 118,000-scm/h HMU with an SMR, high-temperature shift and pressure swing adsorption (PSA) line-up (see Figure 5) and natural gas fuel and feedstock can generate 830,000 t/y of CO2.

The CO2 generated by the SMR process reactions amounts to about 45% of the total CO2 emitted by the HMU. This CO2 can be captured from the high-pressure, pre-combustion stream after the shift reactor before PSA using ADIP ULTRA technology (Figure 5, Option 1).

Although this high-pressure capture recovers slightly less than half of the total CO2 emitted by the HMU, the higher pressure means smaller gas volumes and a higher absorption driving force, which usually results in a lower capture cost per tonne of CO2.

Alternatively, a CANSOLV CO2 Capture System can capture nearly all the CO2 (usually up to 95—98% under current economic incentives) from the low-pressure, post-combustion flue gas (Figure 5, Option 2). This option maximises the amount of CO2 captured, as the treated gas contains CO2 generated both by the process reactions and combustion in the furnace. However, the low-pressure stream means larger gas volumes and a lower CO2 partial pressure, and thus, a larger, more expensive unit requiring more space.

The choice between options 1 and 2 depends on the value of the captured CO2 (avoided tax, credits gained or income from commercial use for EOR, etc., minus the cost of capture (unit construction and operating costs)), among other factors such as available space, which drives the incentive to maximise the amount of CO2 captured: see Table 1, which shows an example for a 118,000-scm/h plant using hypothetical capture costs and CO2 value.

In this example, hypothetical yet credible values have been used to illustrate the relationship between amount captured and the unit capture cost operators often face. The unit cost of post-combustion capture is greater than for pre-combustion capture, and if a low or moderate value is assigned to the captured CO2, this usually results in a lower profitability.
However, if the value assigned to the captured CO2 is high, then the larger amount of CO2 captured significantly increases project revenues and offsets the higher capture cost to the point where the post-combustion capture option becomes more attractive.

Key takeaways
SMR-based HMUs offer the choice of capturing CO2 from the high-pressure, pre-combustion, pre-PSA process stream or from the low-pressure, post-combustion furnace off-gas. The decision to opt for pre- or post-combustion capture depends on the operator’s long-term view of the value/cost of CO2 over the life of the plant and whether its capture project is driven by minimising unit capture cost or maximising captured tonnage.

For low-pressure applications, Shell’s CANSOLV CO2 Capture System provides a robust, highly adaptable, reliable and proven technology for capturing up to 99% of the CO2 in exhaust gases, thereby producing a CO2 product suitable for sequestration, EOR or other industrial uses. It has been in use commercially for several years: reference sites are capturing up to 1 million t/y of CO2.

For high-pressure process streams, including those from HMUs and gasification units, Shell’s latest generation ADIP ULTRA technology offers robust CO2 capture with high levels of performance and reliability. ADIP technology is used at more than 500 sites to capture CO2 from high-pressure process streams. It is cost-effective and can help to reduce capital expenditure by up to 30% and lower regeneration energy requirements by up to 30% compared with conventional accelerated methyl diethanolamine technology.

What about new units?
This article discusses retrofitting CO2 capture technologies to high- and low-pressure streams from existing SMR-based HMUs.

However, blue hydrogen (hydrogen produced from natural gas with CCUS) is likely to be an important part of the future energy mix and will thus require additional greenfield units.

For such greenfield developments, the Shell Blue Hydrogen Process (SBHP), which is based on proven Shell gas partial oxidation and ADIP ULTRA technologies, offers a more cost-effective alternative than an SMR-based unit.

For greenfield applications, oxygen-based systems offer better value than SMR for producing blue hydrogen, particularly as they have better scalability (an independently backed conclusion).⁵ The SBHP offers key advantages over oxygen-based autothermal reforming, including a 10—25% lower levelised cost of hydrogen, a 20% lower capital expenditure, a 35% lower operating expenditure (excluding natural gas feedstock price), >99% CO2 capture and overall process simplicity.

1. www.upstreamonline.com/environment/norway-oil-sector-braced-for-huge-carbon-tax-hike-as-newclimate-plan-hatched/2-1-941509
2. https://www.energyhub.org/carbon-pricing/
3. International Energy Agency, https://www.iea.org/reports/world-energy-outlook-2019
4. Page, B., Turan, G., Zapantis, A., Beck L, Consoli, C., Havercroft, I., Liu, H., Loria, P.,Schneider, A.,Tamme, E., Townsend, A., Temple-Smith, L., Rassool, D. and Zhang, T., Global Status of CCS Report 2019, https://www.globalccsinstitute.com/resources/global-status-report/
5. Collidi, G., “Reference data and supporting literature reviews for SMR based hydrogen production with CCS,” IEAGHG Technical Review 2017-TR3 (2017), http://documentsieaghg.org/index.php/s/7Ii9WGEAufoMPvP/download

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