CCS: Costing the Earth?

Without an effective UK carbon tax, decision-makers cannot make the business case for carbon capture and storage

TO deliver net zero in the UK, carbon capture and storage (CCS) at scale is seen as a key enabler by most commentators and regulators. Whilst it seems inevitable that CCS will be adopted, I have some fundamental issues with the technology.

Here we'll look at a description of the unit operations and equipment associated with CCS, and then crunch some numbers for an example of CO₂ capture from a combined cycle gas turbine power generating plant.

The main capture operations comprise: 

Flue gas blowing where the gas pressure is increased sufficient to overcome the pressure drop in the downstream CO₂ removal plant. CO₂ removal and solvent regeneration using an aqueous amine solution.  A counter flow absorber is used in which a lean amine solution reacts with the CO₂. The CO_2^-rich amine is taken from the absorber to a stripper where the reaction is reversed – CO₂ is released from the rich amine by the application of heat. The lean amine stripped of CO₂ is continuously returned to the absorber.

Figure 1 shows a simplified PFD of the blower and amine plant.

From the amine plant, the CO₂ is compressed in multiple stages to typically 110 bar where it is supercritical. Part way along the compression train the CO₂ is dehydrated to prevent corrosion and hydrate formation (ice-like solid clathrate of CO₂ and water) within the pipeline system from the capture plant to the sequestration location.

Dehydration is facilitated by molecular sieves; here, water in the CO₂ stream is adsorbed onto a solid alumina-silicate. This is a timer-controlled, batch process where one bed is adsorbing whilst another bed, one that has previously adsorbed water, is being regenerated by the application of heat. The bed is typically heated to 275^oC to drive off the adsorbed water. Once the heating cycle is complete the bed is cooled and returned to service.

Figures 2 and 3 show typical compression and dehydration PFDs. Note the last stage of CO₂ pressure boosting is a pump, since CO₂ at high pressure is behaving more like an incompressible liquid.

On review of the CCS configuration it is clear that there are some large energy consumers – flue gas blower, amine regenerator, CO₂ compressors and the molecular sieve regeneration heaters. These introduce a parasitic load onto the CCGT and consequently lower the overall power plant generating efficiency.

Scoping calculations can quickly identify the extent of the efficiency reduction from deploying CCS.

Let’s take the basis as methane as the fossil fuel feedstock used to generate 1 MW of electricity from a CCGT generating plant with a 55% thermal efficiency.

The lower heating value for methane is 50,000 kJ/kg hence the quantity of feed methane required can be calculated as 0.036 kg/s.

The combustion process will produce 1 mole of CO₂ per mole of methane combusted, hence CO₂ production rate will be 0.1 kg/s. Assuming the flue gas has a molecular mass of 28 and is 8 mol% CO₂, the mass of flue gas can be calculated as 0.8 kg/s.

The flue gas blower will discharge at approximately 1.5 bar. A polytropic compressor calculation yields a power requirement of 22 kW for the blower.

The amine reboiler heat requirement is typically 3.5 MJ per kg CO₂ absorbed. Hence, for a CO₂ flow of 0.1 kg/s the thermal duty is 350 kW. The heat for the reboiler is supplied by LP steam at around 3.5 bar. That is steam that cannot be used to produce electricity. The 350 kW (thermal) steam requirement translates to approximately 27 kW of lost electrical generation.

Compressing CO₂ from 1 bar to 110 bar will require five stages. Using a pressure-enthalpy chart the compression power is calculated as 54 kW. This is shown in Figure 4.  

The molecular sieve dehydration regeneration load is estimated at 3 kW. 

Assuming the balance of the plant electrical load is 5% of the total load, the additional parasitic load for CCS is as shown in Table 1.

Hence the parasitic load introduced by CCS is an additional 11%. The consequence being the overall thermal efficiency of power generation drops from 55 to 50%. This scoping calculation identifying an 11% efficiency reduction is consistent with the work of others.

For a coal-fired station the efficiency reduction will double. This is a consequence of the calorific value of bituminous coal (30,000 kJ/kg). Compared to methane with a calorific value of 50,000 kJ/kg, the amount of CO₂ produced from coal to obtain the same amount of energy equivalent will be in proportion to the calorific value, ie 1.67.

In addition to reducing generating efficiency, it is clear that deploying CCS will require a large capital outlay and, because of the additional equipment, the operating cost of power generation will also increase.  Furthermore, CCS introduces new safety dimensions associated with pressurised CO₂ and amine handling.

Now throw in the fact that to maintain the same generation power output, more methane will have to be consumed – 11% more. That means the gas producers will have to process 11% more gas resulting in more gas producer GHG emissions per unit of electricity generated.

Against this background, I keep asking myself what power generation utility company is going to invest in UK CCS when its deployment has no commercial incentive? CCS makes CCGT generation less efficient; it is significantly more expensive and is less safe.

This is a point brought out by Lord Oxburgh, who stated in his 2016, CCS report to Government: “There is no serious commercial incentive and it will stay that way unless the state demonstrates there is a business there.”

"It simply remains cheaper to release emissions than to capture them..."

The same point was also identified in a recent DNV-GL position paper, Heading for Hydrogen. It is the findings of a survey of more than 1,000 senior oil and gas professionals covering safety, infrastructure, CCS and policy. 

It makes for interesting reading. To my mind there was one paragraph that really stood out, in the CCS narrative: “Today, however, it simply remains cheaper to release emissions than to capture them. So in competitive markets the strongest business cases do not include CCS. This seems to be true of the oil and gas industry: nearly three-quarters of respondents to our survey (73%) say that oil and gas companies will decarbonise only if it makes financial sense for them.” 

How to make the case

Once again, it is a stark reminder that, for many decision-makers, there is no business case for CCS.

For the state to provide a business case for CCS the answer seems obvious; an effective carbon tax. There are moves in Government to change Carbon Emission Taxes – as indicated in the policy paper published on 11 March. It remains to be seen whether this will set a floor price for carbon that will materially change the prevailing business view and make CCS make business sense.

If there were an effective UK carbon tax, the recent decision by DRAX to build a new gas-powered station without CCS may have panned out differently.