A Technical Risk Review of Long-Term CO₂ Storage Under the Irish Sea

This article differs from my usual writing style.
It is a structured technical review of the proposed CO₂ storage beneath Liverpool Bay, part of the HyNet North West project.
This is not an argument against climate action.
It is an argument for transparency, proper modelling, and long-term accountability.

What Is Being Proposed?

The UK Government has licensed Eni UK to convert the depleted Hamilton, Hamilton North and Lennox gas fields beneath Liverpool Bay into a CO₂ storage complex.

Planned injection rates:

~4.5 million tonnes per year from 2028
Increasing toward ~10 million tonnes per year after 2030
Total lifetime storage potentially 130–200 million tonnes

CO₂ captured from heavy industry would be compressed into dense-phase (supercritical) form and injected 1–3 km below the seabed into porous sandstone formations that previously held natural gas.

The expectation is permanent containment.

Why Liverpool Bay Is Environmentally Sensitive

The proposed storage sits within a region that includes:

Liverpool Bay Special Protection Area (SPA)
Fylde Marine Conservation Zone (MCZ)
Dee & Mersey Estuary Ramsar and SSSI designations

The area supports:

Overwintering seabirds
Commercial fisheries (whelk, scallop, lobster, sole, plaice)
Complex marine ecosystems

Any long-term leakage would therefore have ecological and economic consequences.

The key question is not whether leakage is expected.
It is whether risks are transparently modelled and independently stress-tested.

What Happens Underground When CO₂ Is Injected?

1. Carbonic Acid Formation (Expected and Well-Studied)

When CO₂ dissolves in formation brine:

CO₂ + H₂O ⇌ H₂CO₃

Carbonic acid is a weak acid.
It lowers pH locally and initiates mineral reactions.

This can:

Dissolve carbonate minerals
Alter feldspar and clay minerals
Change porosity and permeability near injection zones

These reactions are expected and form part of standard CCS modelling.

Impurities in Industrial CO₂ Streams

Captured CO₂ is not perfectly pure.
Depending on capture source and process, trace impurities may include:

Hydrogen sulphide (H₂S)

Nitrogen oxides (NOₓ)

Oxygen (O₂)

Water

Trace metals

Most regulatory frameworks rely on project-specific impurity limits rather than a single statutory UK standard.

Impurity levels matter because certain species can generate stronger acids than carbonic acid.

Strong Acid Formation – Corrected and Realistic Assessment

If hydrogen sulphide (H₂S) and nitrogen oxides are oxidised underground, they can theoretically form:

Sulphuric acid:

H_{2} S + 2 O_{2} \to H_{2} S O_{4}

H2S+2O2→H2SO4

Nitric acid:

N O_{2} \to H N O_{3}

NO2→HNO3

However, oxidation underground depends on:

Oxygen availability

Reservoir redox conditions

Local fluid dynamics

It is not automatic.

What Is the Realistic Scale?

Assuming total injection of 200 million tonnes CO₂:

Maximum Theoretical Case (100% Oxidation – Upper Bound Only)

~26,700 tonnes sulphuric acid (at 60 ppm H₂S)

~2,860 tonnes nitric acid (at 10 ppm NO₂ equivalent)

These are mathematical ceilings, not expected outcomes.

More Realistic Scenario (5–10% Oxidation)

~1,300–2,700 tonnes sulphuric acid

~140–280 tonnes nitric acid

These values are scientifically defensible.

They are small relative to total reservoir mass, but they are not negligible in near-well environments.

Why Thousands of Tonnes Can Still Matter

Strong acids differ from carbonic acid:

They fully dissociate

They generate higher proton activity

They accelerate cement degradation

They increase corrosion rates

They enhance metal mobilisation under low pH

Acid generation would likely be concentrated near injection zones, where:

Pressure is highest

Fresh CO₂ first contacts brine

Rock and cement surfaces are most reactive

This makes impurity specification and oxidation modelling important design parameters.

Geomechanical Considerations

The Hamilton field is a depleted gas reservoir.

During gas production:

Pore pressure declined

Stress was redistributed

Rock compacted

Faults adjusted

CO₂ injection reverses that pressure regime.

As injection continues:

Reservoir pressure rises

Margin to fracture pressure narrows

Induced seismicity risk must be managed

Injection pressure must remain below fracture thresholds to avoid:

New fractures

Fault reactivation

Leakage pathway creation

This is a recognised issue in subsurface engineering literature.

Well Integrity: The Long-Term Variable

Depleted fields contain legacy wells.

Wellbores represent one of the most credible long-term leakage pathways.

Over decades:

Cement is exposed to acidic fluids

Steel casing experiences corrosion

Thermal cycling occurs

Even modest pH reduction increases cement degradation rates.

Long-duration modelling must explicitly address:

Cement chemistry evolution

Corrosion rates

Seal integrity beyond the injection period

What About Aquifers and Marine Impact?

Offshore aquifer contamination is unlikely unless structural leakage occurs.

However, if leakage were to occur:

CO₂-rich brine could lower local seawater pH

Dissolved metals could migrate with brine

Marine carbonate-forming organisms would be sensitive to acidification

These are low-probability but high-consequence scenarios.

They require transparent modelling.

Regulatory Oversight – Structural Questions

CCS regulation in the UK operates through:

Offshore Petroleum Regulator for Environment and Decommissioning (OPRED)

Environmental Permitting Regulations

Pipeline Safety Regulations

However:

There is no single binding UK statutory impurity specification

Impurity thresholds are often project-specific

Long-term (100-year+) modelling assumptions are not always publicly detailed

This creates uncertainty for independent review.

Long-Term Risk Framing (100-Year Horizon)

A credible risk assessment should examine:

Pressure evolution across injection lifetime

Fracture margin sensitivity

Impurity-driven geochemical evolution

Reactive transport modelling

Well integrity degradation over decades

Fault transmissibility under pressure cycling

Not because failure is expected —
but because permanent storage demands permanent accountability.

Evidence From Other CCS Projects

Historical CCS projects (Sleipner, Snøhvit, Weyburn, In Salah) demonstrate:

Containment is achievable

Monitoring is essential

Pressure management is critical

Geomechanical response can require operational adjustment

No single field globally has yet stored 200 million tonnes in one structure over full lifetime.

Scale matters.

What Should Happen Before Injection Begins

Before 2028 injection:

Full impurity disclosure

Published oxidation sensitivity modelling

Reactive transport modelling including impurity scenarios

100-year well integrity analysis

Publicly available fracture pressure margins

Independent peer review

These are reasonable requirements for permanent offshore storage.

Final Position

Carbon capture and storage is not inherently unsafe.
But large-scale offshore CO₂ injection into depleted gas fields introduces:

Pressure reversal

Reactive geochemistry

Long-duration material stress

Impurity sensitivity

Even under moderate oxidation assumptions, strong acid formation in the order of thousands of tonnes over project lifetime is plausible. While small relative to reservoir mass, these quantities are sufficient to justify explicit modelling and transparent disclosure.

If the modelling exists, it should be public.
If it does not, injection should not proceed until it does.

This is not anti-climate policy.
It is pro-transparency, pro-science, and pro-accountability.

Liverpool Bay Carbon Capture Project Analyse Report