Net zero electricity and hydrogen production with post-combustion CO₂ capture and storage

Abstract

Carbon Capture and Storage (CCS) systems are seen as a key technology for enabling the global imperative of arresting anthropogenic climate change. For this goal to be achieved, the global annual net change in atmospheric CO₂ must be reduced to zero, or below, within the next few decades. For CCS to be compatible with this target, residual, or uncaptured, CO₂ emissions from the process they decarbonise, and any downstream or upstream greenhouse gas (GHG) emissions must also be reduced to zero, or the equivalent amount of CO₂ recaptured within an appropriate timeframe.

Historically, CO₂ capture fractions from CCS systems of 90% have been targeted, citing exponentially increasing costs and energy demands as the barrier to achieving higher removal rates. This remaining 10%, or indeed 5%, as 95% CO₂ capture fractions have gained traction in recent years, is clearly incompatible with the goal of zero net change in atmospheric CO₂ (or net zero), let alone any aspirations for net CO₂ removal as is required by a growing number of climate models.

This thesis uses state of the art knowledge to investigate the thermodynamic, process and economic requirements to efficiently achieve ultra-high CO₂ capture fractions in post combustion capture (PCC) plants using a monoethanolamine (MEA) solvent. This revels the potential for PCC plants to operate at a CO₂ capture fraction resulting in no net addition of CO₂ to the atmosphere, termed 100% fossil CO₂ capture. This is completed by taking two standard and one novel, which was optimised as part of this work, energy conversion processes that will utilise CCS; combined cycle gas turbines (CCGT), for flexible and dispatchable power production, steam methane reforming (SMR), producing hydrogen as an option for fuel switching applications and the newly termed combined fuel and power (CFP) which combines the CCGT and SMR processes. Detailed process and economic models were developed that indicate that, if designed appropriately, the CCGT, SMR and CFP processes can achieve 100% fossil CO₂ capture with minimal process modification, commercially available technology and an approximately linear increase in production costs relative to CO₂ capture fraction.

For a CCGT, an additional 0.5%-point decrease in thermal efficiency (Lower Heating Value (LHV)) results from transitioning from 95% gross to 100% fossil CO₂ capture with an associated 4% increase in capital expenditure (CAPEX), while for the SMR a 1.9%-point decrease in thermal efficiency (Higher Heating Value (HHV)) and 5% increase in CAPEX is reported. For the CFP a 0.5% decrease and 3% increase for thermal efficiency (2nd Law) and CAPEX is predicted, however a 4.4% increase in 2nd law thermal efficiency and a 17.3% decrease in CAPEX relative to operating the CCGT and SMR processes separately is seen. For the CCGT and SMR processes, the cost of recapturing upstream and downstream emissions using direct air capture (DAC) is also investigated. This results in a 9% (SMR) and 29% (CCGT) increase in production cost, for a median cost of DAC of 300 £/tCO₂ and global average natural gas supply chain emission rate of 1.5%, however high degrees of sensitivity are observed for both these variables.

The process conditions considered necessary to efficiently achieve 100% fossil CO₂ capture, namely increased solvent regeneration pressures (210 – 275KPa vs 170 – 190KPa), and therefore temperature (125 - 135oC vs 115 – 125oC), and increased exposure times to flue gases are thought to increase the degradation rate of CO₂ capture solvents. This is investigated through process modelling and the application of a newly developed monoethanolamine (MEA) degradation framework. This predicts that degradation rates increase by 24−138% when achieving 100% fossil CO₂ capture relative to a 95% gross CO₂ capture fraction, with absorber intercooling and minimising desorber sump residence times emerging as key plant parameters to minimise degradation. An economic assessment concludes that this increase would result in an increased operational expenditure (OPEX) of between 0.02−0.38 £/tCO₂.

Dynamic operations of CCS plants, particularly start up and shutdown (SUSD) events, pose a key operational challenge, particularly aiming to achieve ultra-high rates of CO₂ capture (+99%), as a constant flow of appropriately lean solvent is critical. Due to thermal inertia in the desorber, and indeed the availability of thermal energy during plant start up, it may not always be possible to produce lean solvent at the rate or quality required to enable high CO₂ capture fractions under dynamic operation. Through pilot scale test campaigns, start-up CO₂ capture fractions of greater than +97% are demonstrated though simulated start-up sequences when using an enhanced solvent storage scheme. While the procurement of operational data from a commercial CCGT demonstrates the availability of previously waste steam from the CCGT SUSD sequences that can be utilised to accelerated PCC start up times, reducing the required rich solvent capacity and additional solvent inventory from 350% of the base solvent inventory to just 50%, increasing the economic viability of CO₂ capture during SUSD.

The analysis presented in this thesis provides critical and novel evidence that will advise designers on the process and economic considerations required to efficiently develop projects that achieve net zero compatible CO₂ capture fractions in PCC plants.