Ultra-low emission flexible plants for blue hydrogen and power production, with electrically assisted reformers

This linkedin article resumes the content of the full paper available at this link, co-authored with Alessandro de Cataldo , Marco Astolfi , Paolo Chiesa and Stefano Campanari . The paper deals with the techno-economic analysis of "Powdrogen" plants for hydrogen and power production with CO2 capture and storage, designed to operate flexibly in response to variable electricity prices.

Following a brief description of the plant concept, this article will address the following questions:

• How to achieve very low emissions from blue hydrogen plants?
• What is the influence of methane leakage from the natural gas supply chain?
• How could these Powdrogen plants operate flexibly?
• How about the economics?

Plants configuration

The plants that we assessed in this study are resumed in the block diagram of the Figure below (detailed flowsheets can be found in the paper supplementary material), which includes:

• a steam reforming section, either based on fired tubular reforming (FTR) or autothermal reforming (ATR), followed by a water gas shift (WGS) section. In FTR-based plants, the reformer furnace is sustained by combustion of a portion of the H2-rich gas after CO2 separation (stream C in the figure);
• a CO2 separation section from syngas, based on an MDEA chemical absorption process;
• a hydrogen purification section based on a conventional PSA process;
• a heat recovery steam cycle, recovering heat from the hydrogen production plant;
• a combined cycle, that can burn the H2-rich gas after CO2 separation (stream A in the figure).

How to achieve very low emissions from the blue hydrogen plant?

There are three main strategies to reduce emissions from blue hydrogen plants (excluding the higher-cost post-combustion capture option):

1. To improve the WGS section by reducing the low-temperature WGS reactor exit temperature, e.g. by a cooled WGS reactor. This allows minimizing CO-slip, as it is mostly converted into CO2.
2. To design the CO2 separation section to achieve a very high CO2 separation efficiency of 99% or higher. This has been a state-of-the-art practice for decades in ammonia production plants.
3. To adopt a proper steam to carbon (S/C) ratio and increase the reforming temperature to ensure high CH4 conversion in the reformer. For ATR, it is normal to operate at reforming temperatures above 1000°C, and achieve very low methane slip. This is why all the announced low-emission blue hydrogen plants are based on ATR technology. For FTR, this is more challenging, as heat is transferred to the reacting gas through tubes that must resist very high temperatures. So, the options to increase the reforming temperature of FTR-based plants are: (i) to use advanced metal alloy tubes that allow to increase the reforming temperature from the baseline 890°C to, say, 950°C and (ii) to include an electrified reforming section after the FTR, where the temperature can be increased to above 1000°C with no need of heat transfer through tubular heat exchanger.

The figure below (from supplementary information) shows the sources of CO2 emissions from FTR and ATR operated at 30 bar, with WGS outlet temperature of 200°C and CO2 separation efficiency of 99%. Below 1000°C of reforming temperature, emissions are dominated by the unconverted CH4 (which is ultimately combusted).

Based on the considerations above, we assessed the following four plants:

1. a baseline “conventional” FTR plant, with a reforming temperature of 890°C, S/C=3.4, adiabatic WGS reactors and 95% CO2 separation efficiency;
2. an advanced “FTR-Plus” plant, with increased reforming temperature of 950°C, S/C=3.4, cooled LT-WGS reactor and 99% CO2 separation efficiency;
3. an advances electrified “e-FTR” plant, based on an FTR reactor with 950°C exit temperature and downstream electrified reformer with 1050°C exit temperature, S/C=3.4, cooled LT-WGS reactor and 99% CO2 separation efficiency;
4. an ATR plant, with a reforming temperature of 1050°C, S/C=1.5, adiabatic WGS and 99% CO2 separation efficiency.

The main assumptions and results are reported in the table below for the plant operating in hydrogen production mode and in power mode.

Overall carbon capture ratio ranges from 78% of the baseline FTR plant to 90% of the FTR-Plus and about 95% of the e-FTR and ATR plants. In hydrogen mode, the resulting direct emissions range from almost 2 kgCO2/kgH2 in the FTR plant to 0.9 kgCO2/kgH2 of the FTR-Plus and 0.40-0.55 of the e-FTR and the ATR plants. With the exception of the e-FTR plant, which is a mild electricity consumer (0.9 kWh/kgH2 consumption), the other plants export some electricity (0.6-0.9 kWh/kgH2).

In power mode, direct CO2 emissions range from 91 kg/MWh of the baseline FTR to 41 kg/MWh of the FTR-Plus and around 20 kg/MWh of the e-FTR and ATR plants.

What is the influence of methane leakage from the natural gas supply chain?

To make any natural gas-based plant sustainable, methane leakage from the supply chain need to be very low. Period.

With the Norwegian value chain (reported methane leakage of 0.2-0.4%), the climate impact of methane leakage is equivalent to roughly doubling the direct emissions of the low emission blue hydrogen and blue power plants discussed above.

An ultra-low emission and properly monitored natural gas supply chain (like the Norwegian one) is a precondition for any sustainable use of natural gas.

How could these plants operate flexibly?

The proposed blue hydrogen and power “Powdrogen” plants can operate flexibly exploiting 3 degrees of freedom, to take advantage of variable electricity prices (or, similarly, to balance variable renewables).

The first two degrees of freedom consist of: 1) changing the split ratio of the H2-rich gas between H2 production and electricity production and 2) reducing the load of the reforming plant.

The operating maps resulting from these degrees of freedom are shown in the figure below, with the following extreme operating points:

• Hydrogen mode (H): reformer at full-load, gas turbine off, maximum hydrogen production.
• Electricity mode (E): reformer at full-load, zero hydrogen export, maximum electricity production.
• Polygeneration mode (Pol): reformer at full-load, gas turbine at minimum load, the unburned hydrogen is exported.
• Minimum reformer load: reformer at minimum load (assumed 50% for FTR and 70% for ATR) and production of electricity (ME), hydrogen (MH) or electricity + hydrogen with GT at minimum load (MPol).

The third degree of freedom consists in playing with the degree of electrification of the reformer, which may be adjusted based on electricity price/availability:

In e-FTR plants:

• during periods of high electricity prices, the electrified section may be switched off. This leads to lower reforming temperature and higher emissions;
• during periods of low electricity prices, the share of electricity input may be increased, for instance, by reducing the temperature at the exit of the fired reforming section while keeping the temperature at the outlet of the electrified section constant. This leads to higher hydrogen production, as a lower portion of the produced hydrogen is burned in the FTR furnace.

In ATR plants, if an electrified reforming section is integrated within or downstream the conventional oxygen-blown ATR section, during periods of low electricity prices it might be possible to implement the following strategies:

• hydrogen-boost 1 (HB1) strategy: increase the natural gas input (e.g. by 20%) keeping a fixed O2 flow rate and supply the heat needed to achieve the target exit temperature via electric heating;
• hydrogen-boost 2 (HB2) strategy: keep a fixed natural gas input, reduce the O2 flow rate (e.g. by 50%) and supply the heat needed to achieve the target exit temperature via electric heating.

Hydrogen boosting by electrification involves increasing the hydrogen output for a given natural gas input. From the ratio between the marginal increase in hydrogen production and the net marginal increase in electricity consumption, it is possible to calculate a power-to-hydrogen efficiency of up to around 72% in the e-FTR plant and 87–90 % in the ATR plant.

How about the economics?

We developed the economic analysis following two approaches:

The first is the classic “cost of hydrogen” (COH) and “cost of electricity” (COE) approach. For a very large-scale plant (hydrogen production capacity around 400’000 Nm3/h), designed to supply a large-scale H-class gas turbine, we obtained costs of hydrogen around 2.3 €/kg and costs of electricity of 100-110 €/MWh, assuming a natural gas price of 9 €/GJ (32 €/MWh). More than 60% of the costs of hydrogen and electricity are associated to the natural gas price.

The second approach aims at calculating the revenues from flexible Powdrogen plants exposed to exogenous hydrogen selling price and electricity price curves.

Results are shown in the figure below for e-FTR (left) and ATR (right) plants, with electricity price curves replicating the 2019 Danish market and possible illustrative 2035 and 2040 scenarios from the literature. H2 selling prices of 2 €/kg (solid vertical lines) and 2.5 €/kg (dashed vertical lines) are considered.

As an example, when examining the 2035 ATR case and considering 2 €/kg hydrogen price, a flexible Powdrogen plant would operate for almost 5800 hours (i.e. when electricity price is higher than about 90 €/MWh) in electricity mode (E), for a narrow period of 400 hours in hydrogen mode (H) and for about 2500 hours (i.e. when electricity price reduces below about 80 €/MWh) in hydrogen boost mode, with electric heating on. With a hydrogen selling price of 2.5 €/kg, the number of hours in electricity mode decreases to about 1300 hours. Below an electricity price of 114 €/MWh, it becomes economically preferable to switch the electric heating on and work in hydrogen boost mode.

The resulting calculated internal rate of return ranges between 4 and 12% with hydrogen selling price of 2 €/kg and between 14 and 17% with hydrogen selling price of 2.5 €/kg.

Conclusions

• Powdrogen plants based on fired tubular reformers (FTR) can achieve capture rates higher than 90 % through pre-combustion CO2 separation only, if a combination of technologies is adopted: a high reformer exit temperature (950 °C), an H2-fired furnace, a low exit temperature from the LT-WGS reactor and a high efficiency MDEA-based CO2 separation unit. Post-electrification of the reformer would allow reaching 95 % CO2 capture efficiency, with an e-FTR exit temperature of 1050 °C.
• Powdrogen plants based on ATR can approach a 95 % capture efficiency by combining a conventional reformer with a low exit temperature LT-WGS reactor and a high efficiency CO2 separation process.
• Hybridization of the reformer process by partial electrification offers the opportunity for operational flexibility in both FTR and ATR-based Powdrogen plants. In FTR-based plants, post-electrification may be adopted to reduce CO2 emissions and to increase H2 output, with a power-to-hydrogen conversion efficiency of up to around 72 %. Partial electrification of ATR allows for an increase in H2 output either by reducing O2 input or by increasing the natural gas input, with a power-to-hydrogen conversion efficiency of 87–90 %.
• The relative selling prices of hydrogen and electricity, and to a lesser extent, the cost of CO2 emission, determine the optimal operating mode of a flexible Powdrogen plant. The integration into the high renewable Danish electric grid of the year 2019 and of future 2035 and 2040 scenarios from the literature have been assessed. Powdrogen plants would operate in power mode, hydrogen mode and electrified hydrogen mode for variable periods, depending on the shape of the electricity price curve. In future 2035–2040 scenarios, featuring higher price variance (i.e. long periods with high price electricity over 100 €/MWh as well as long periods with low price below 30 €/MWh), Powdrogen plants would tend to operate predominantly in power mode (selling electricity at high prices) and in electrified hydrogen mode (increasing H2 output by consuming low-price electricity).
• With hydrogen selling prices of 2 €/kg and 2.5 €/kg, the economic analysis results in negative returns in the 2019 electricity price scenario and positive returns in the 2035-2040 scenarios, with internal rate of returns of 10–11 % and 14–17%.