Carbon capture and storage (CCS) isn’t new to conversations around cleaning up oil and gas emissions. In its early days, CCS felt ambitious and outlandishly expensive, but as it reaches broader commercialisation and becomes an increasingly mainstream decarbonisation solution, the questions around it are shifting away from viability and towards measurability.
The Society for Underwater Technology (SUT) reported that knowing carbon dioxide (CO₂) remains stored is “possibly the biggest technical challenge associated with offshore CCUS [carbon capture, utilisation and storage]”. The risk of leaks from stores post-injection is a significant concern, with legacy wells presenting the most significant leakage risk.
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Leaks unpick environmental wins and pose health risks to humans and surrounding biota. Demonstrating continued storage is a heavy burden of proof, and it is operators that are ultimately responsible for assessing leakage risks and providing reliable monitoring for the indefinite future.
While this might sound like the industry is marking its own homework, global governments are gradually becoming more involved and monitoring technologies are constantly improving.
Different sites have different challenges, however, and tracing plume migration across some rock formations is easier than others. Saline aquifers have the complication of being at hydrostatic pressure at the point of CO₂ injection, while hydrocarbon reservoirs have more complex stress path histories.
Both will play a part in the oil and gas decarbonisation picture, but it is monitoring technologies that will define the reliability of emerging CCS projects.
Monitoring CCS in depleted hydrocarbon reservoirs
Depleted hydrocarbon reservoirs are permeable and porous rocks left behind after oil or gas is extracted. Compressed CO₂ can be pumped into these reservoirs through wellbores, where it is trapped in pore spaces or by cap rocks, or dissolved in brine.
Having held hydrocarbons for millions of years, the conditions are ideal for CO₂ storage, offering a large potential storage capacity per cubic metre. Their lengthy lifespans as hydrocarbon sources also mean operators begin with an advantage: extensive seismic data from the exploration and appraisal period.
However, there are also risks including geological leak paths, insufficient plugging depth for repressurisation and possible corrosion if improper materials are used. Leak paths can be caused by naturally occurring fault zones or cap rock failure, when the capillary pressure of the reservoir exceeds the displacement pressure of the top seal, or in abandoned wells if cement degrades or the well is improperly sealed.
According to a report by the Net Zero Technology Centre, “wells represent both the primary pathway for CO₂ injection and the most likely avenue for potential leakage, making well integrity and performance monitoring essential components of any CCS project”.
Despite the risks, the industry is confident it can measure continued storage in these reservoirs. Chairing the CCS panel at DECARBON 2026, Petrofac’s subsea and pipelines manager Philip Cooper told Offshore Technology: “The monitoring and verification of wells is a huge focus in both reservoir engineering and well engineering. Different projects have different approaches. Many of them have additional wells, purely for monitoring.”
These monitoring wells provide continuous, long-term data on subsurface pressure and temperature. What they don’t offer, however, is leak location: a challenge solved by strategic sensor placement.
SUT chair Mike Fearn explains: “It depends where you have got your measurement outputs and how far apart these are. If you have got them every kilometre, you should be able to indicate where the leak is potentially coming from. Then, it is a case of shutting down the carbon capture in the short-term to fix that leak and try and seal it – even a small leak is quite serious.”
The measurement outputs in question can include high-resolution sensors for bottom hole pressure and temperatures, as well as acoustic fibre-optic sensing systems and chemical tracer technologies.
However, to track plume movement accurately across the entire carbon storage site, a more wholistic measurement, monitoring and verification (MMV) approach is usually employed. Data acquired from sensors is paired with reservoir modelling and 4D seismic monitoring to produce a more complete pictures of the movement of CO₂.
The industry has long ascertained the value of 4D seismic monitoring for depleted reservoirs. Cooper comments that “they do a seismic scan in the reservoir and come back later to see how the plume has moved”, noting that Norway successfully obtained “quite a bit of data” on the underground movement of CO₂ from the Snorre project.
However, recent scholarship has questioned the value of continued seismic monitoring. In a 2025 paper, reservoir geophysicists highlighted that “limitations arise from the patchy and heterogeneous seismic response, where large portions of the reservoir may fall below detectability thresholds, while only isolated zones exhibit measurable changes after several years”.
Monitoring CCS in saline aquifers
Saline aquifers are deep underground geological formations of porous rock containing salty brine. Compressed CO₂ is injected into the aquifer through specialised wells, where it spreads within the porous rock and becomes gradually trapped by physical dissolution and mineralisation processes.
Compared to reservoirs, aquifers have limited storage capacity per cubic metre of space; between two and 20% of pores are filled with CO₂ in saline aquifers, while depleted fields could have up to 80%. Explaining this in his 2024 paper, Richard Worden comments: “Saline aquifers, with their buoyant CO₂ plume, relative permeability controls, and the difference in viscosity of the CO₂ and the pre-existing brine, will have low-to-very-low proportions of the pores filled.”
Aquifers also have a muddier geological history and lack the pre-existing infrastructure that depleted fields feel the benefits of, making it logistically harder to prove that CO₂ is staying put.
Yet, the most significant difference between monitoring hydrocarbon reservoirs and saline aquifers is pressure. Already full of brine, saline aquifers have little room for added pressure, and monitoring must revolve more carefully around pressure changes, which can cause surface deformation (uplift) and subsidence (sinking).
However, while overpressurisation is a risk, it has a silver lining: it makes 4D seismic monitoring easier.
4D seismic monitoring has been heralded as providing “the greatest benefit of all monitoring techniques despite the great cost”. While it can be used in both depleted reservoirs and saline aquifers, it is considered the gold standard in saline aquifers because of the simpler pressure and fluid behaviour (pressure rises steadily and simply, making plume mapping easier) – paired with the benefit of the density contrast between CO₂ and brine in saline aquifers, making CO₂ easier to spot in seismic scans.
Equnior’s Sleipner and Snøhvit CCS sites in Norway are examples in which Worden says, “3D and 4D seismic imaging have proved to be spectacularly successful”. Meanwhile, research by Philip Ringrose on the Salah CCS site in Algeria found that the technique offered “significant benefits for overburden imaging and time-lapse responses with improved acquisition plan”.
The overall MMV picture will often also include electrical resistivity tomography, which is commonly used alongside seismic surveying. It tracks CO₂ movement by measuring time-lapse electrical resistivity changes as conductive brine is replaced by non-conductive CO₂. It is a cost-effective monitoring method but requires the CCS solution to be brine-based; hence, it performs better in saline aquifers than in hydrocarbon reservoirs due to the high sensitivity of resistivity measurements to pore-water salinity.
Fearn comments: “Different monitoring technologies have their strengths and weaknesses. You have to measure continuously, and take each site individually, to look at what is best. Sometimes a combination of sensors is best: you could have a flow meter, you could look at leak storage and you could measure temperature and pressure in the main storage hub with your flow line. That way, you are getting the best of everything.”
Indeed, Worden’s paper notes the contrast in the usefulness of monitoring wells: “The use of monitoring wells for measurement of pressure and temperature away from the injection well and fluid composition and isotopes from the plume may be possible in depleted gas fields with a large number of pre-existing wells. The use of monitoring boreholes from saline aquifers seems to be less likely, in most cases.”
CCS policy and regulation
Despite gradual progress, CCS is still in the early stages of widespread implementation. Currently, both depleted reservoirs and saline aquifers present limited commercial opportunity, which has deterred investment and innovation in the space. By extension, regulation has also lagged.
Yet, as the pressure to decarbonise grows, so will the reliance on CCS as a solution, and with it monitoring technologies will continue to emerge.
This offers rich potential for learning, as Shell has found with its Quest CCS project in Canada. Andreas Grobler, manager of strategic partnerships for the energy transition at Shell Germany, told Offshore Technology at DECARBON: “All of the data that we captured since the beginning [of Quest] – that is almost 10 years of data – is publicly available. The Canadian Government said it would support us, but it also wanted to benefit from the learnings, so we have shared this obligation, since the first injection, to monitor what CO₂ does. Now, over ten years, there has been no leakage at all, and the data is available.”
He continues: “It is the same thing at the Northern Lights project. The data is not yet available, but […] we jointly decided [with Equinor] that whatever we measure in accordance with monitoring obligations from the government, we are going to make publicly available for those projects that are publicly funded or government supported.”
For some governments, CCS is an opportunity to meet decarbonisation targets, particularly as 2030 deadlines loom large. This is the case in the UK, where regulatory responsibilities fall to the North Sea Transition Authority (NSTA), which explains to Offshore Technology: “At the permit award stage, NSTA has reviewed all the operator’s modelling and assumptions on the store and has to be confident that there is no significant risk of leakage. In addition, a monitoring plan is agreed to verify that is the case on an ongoing basis.
“The operators are responsible for monitoring, metering and sampling, and NSTA has the right to inspect monitoring reports and equipment,” the spokesperson adds.
For other governments, CCS is an industry prerogative. For example, in the US, recent government support for CCS has been tied to its support for enhanced oil recovery. As a result, CCS tax credits have received bipartisan support through the One Big Beautiful Bill Act. The Department of Energy has also continued to run its Regional Carbon Sequestration Partnerships, which seek to support commercial-scale CCS projects while leveraging the technical learnings of its stakeholder base.
Globally, there is a trend of increased regulation around monitoring continued storage, but there is still significant disparity around government involvement. A 2024 report by the Global CCS Institute identified “significant progress in establishing enabling policies and regulations for CCS” in Australia and Indonesia but “nascent or absent” regulations in the broader Asia-Pacific region, specifically noting “critical gaps” in Malaysia, India and China.
Frequently asked questions
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What does “measurement, monitoring and verification (MMV)” mean in CCS, and why is it so important?
MMV is the evidence package that shows injected CO₂ is behaving as predicted, staying contained and not creating unacceptable risks. For operators, it is the practical way to meet a high burden of proof: you must demonstrate storage performance not just during injection, but for the long term. MMV typically combines direct measurements, such as subsurface pressure and temperature data from wells, with wider-area surveillance, such as time-lapse (4D) seismic and modelling that forecasts plume movement. The value is not only reassurance; it enables early warning and faster response if behaviour deviates. MMV also supports permitting and regulatory compliance, helps protect people and ecosystems from leakage impacts, and underpins investor confidence in CCS as a credible decarbonisation tool.
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Which monitoring technologies are most commonly used to detect CO₂ movement and potential leaks?
CCS monitoring usually relies on a layered set of tools because no single technology provides a complete picture. In wells, high-resolution pressure and temperature sensors give continuous insight into how the store is responding to injection, while acoustic fibre-optic sensing can detect subtle changes linked to flow or integrity issues. Chemical tracers can help confirm CO₂ presence and movement. For a site-wide view, 4D seismic is widely used to map plume migration over time by comparing repeated surveys. In saline aquifers, electrical resistivity tomography (ERT) can also be valuable because it detects changes as conductive brine is displaced by relatively non-conductive CO₂. The most robust approach typically fuses sensor data with reservoir models, improving confidence, narrowing uncertainties and helping pinpoint where to investigate if anomalies appear.
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Why do depleted hydrocarbon reservoirs and saline aquifers need different CCS monitoring strategies?
The geology and operating conditions differ in ways that change what you can measure and how clearly you can interpret it. Depleted reservoirs often start with a major advantage: decades of seismic and subsurface data gathered during exploration and production, plus existing wells that can sometimes be repurposed for monitoring. However, they may have complex stress histories and, critically, legacy wells that can become leakage pathways if cement degrades or sealing is inadequate. Saline aquifers, by contrast, usually have less historical data and infrastructure, making proof of storage harder to assemble. Pressure management is also more sensitive because aquifers are already brine-filled at hydrostatic pressure, so monitoring focuses heavily on pressure changes and possible surface deformation, alongside plume tracking.
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Is 4D seismic the gold standard for proving CO₂ storage?
4D seismic is often described as a gold standard because it can provide a field-wide picture of plume evolution, which is difficult to achieve with point measurements alone. It tends to perform particularly well in saline aquifers, where contrasts between brine and CO₂ and simpler pressure behaviour can make changes easier to image. That said, it is not a universal solution. Cost can be high, repeatability can be challenging, and in depleted reservoirs the seismic response may be patchy, with some areas falling below detection thresholds even after years. In practice, 4D seismic is most persuasive when integrated with other monitoring streams, such as downhole pressure and temperature, tracers and modelling, so that limitations in one dataset are compensated by strengths in another.
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Who is responsible for monitoring CCS, and what role do regulators play?
Operators carry the core responsibility for monitoring, assessing leakage risk and demonstrating ongoing containment, because they control injection, wells and data collection. This is why well integrity and performance monitoring are treated as central, especially given that wells can be both essential infrastructure and the most likely leakage pathway. Regulators increasingly shape what “good” looks like by requiring a monitoring plan, reviewing models and assumptions at the permitting stage, and retaining the right to inspect monitoring reports and equipment. In the UK, for example, the regulator must be satisfied there is no significant leakage risk and agrees an ongoing verification plan. Elsewhere, government involvement varies widely, from strong policy frameworks to gaps or nascent regulation, which can affect investor confidence and the consistency of long-term assurance.
