The transnational cooperation behind CCS projects: an interview with Shelagh Baines

Companies in the oil and gas exploration sector are exploring innovative ways to reduce their carbon footprint, and Halliburton is no exception. Halliburton is one of the largest transnational corporations that provides products and services to the global energy industry. On its way to achieve 40% reduction of Scope 1 and 2 emissions by 2035 from the 2018 baseline, the company is exploring CCS as one of its net-zero strategies.

Through a written interview, Halliburton's Technical Director of Carbon Management Shelagh Baines shared what collaborative CCS projects look like, and the success factors and future considerations of the CCS technology. 

Could you briefly introduce your role and area of expertise within the field of geology and CCS?

I hold a degree and a Ph.D. in Earth Sciences. My research focuses on low-temperature geology and geochemistry of unusual minerals found in oil reservoirs in the U.K. North Sea hydrocarbon province. As a geologist in 1998, I attended a joint industry project (JIP) meeting to understand the impact and long-term behavior of CO2 injected by the Sleipner CCS project, the first commercial CCS effort, funded by several energy companies and the European Union. The project aimed to understand the long-term behavior of injected CO2. CO2 is chemically reactive, which made the work fascinating for a geochemist. But I also felt that the project's goal was important, and that the oil and gas industry had the knowledge and experience to succeed.

How are collaborations made with domestic or international companies on a CCS project?

Cross-project collaboration comes from either ownership of individual elements of the full project chain. For example, a domestic company may own and operate an emitting facility but lack downstream capabilities and collaborate with an entity that can manage and operate the transport and/or storage elements of the full-chain project.

What geological factors are considered when choosing a site to start a CCS project, and how do some of them serve as challenges? 

For a CO2 storage project to be a success, several elements must combine for both technical and business factors that evaluate potential storage sites by posing a series of questions.

Ms. Baines shared that Halliburton first considers storage resource size, investigating whether the site has sufficient capacity to hold the required volume of CO2.

Halliburton also considers injectivity, examining if the site can accept the required volume of CO2 at a rate that does not damage any subsurface elements. If pressure from CO2 injection builds around the injection well or elsewhere on the site, it can damage subsurface elements, reactivate faults or fractures, or even cause rock to fracture. It may be possible to reduce this risk by the injection of CO2 at a slower rate or through more wells, but these workarounds may affect project economics.

Containment is another important aspect considered by Halliburton, as it explores if CO2 will remain within the targeted pore space in the storage reservoir. An evaluation must assess the risk of CO2 migration and subsequent leakage from permitted pore space, either via geological pathways or through engineered paths such as old legacy wells, or even new-build injection or monitoring wells. The risk of this kind of CO2 movement can be minimized through careful assessment of the subsurface geology, creation of a CO2 storage injection plan that avoids contact between the CO2 and any older wells, intervention and repair of old wells, and careful plan and design of new wells.

In addition to these three elements, projects also require legal access to the necessary pore space within the project timeframe and verify that the storage site is suitable for monitoring the injected CO2.

In your experience, how does geological storage in depleted oil and gas reservoirs differ from storage in saline aquifers?

While the overall aim of CO2 storage in depleted fields and saline aquifers is the same: long-term secure geological storage, both site types have different characteristics and development challenges. Data availability or knowledge status is a big one. Although we may have little static data/characterization for a saline aquifer compared to a depleted field, the big difference is in how we understand how a buoyant fluid, such as CO2, will behave under injection at that storage site.

In terms of containment, hydrocarbons “prove a positive,” meaning that, if oil or gas is present in a reservoir, the geological system is proven capable of holding some volume of buoyant fluid. This is not so for saline aquifers, where we must “prove a negative” that the geological system will not allow the escape of buoyant fluids with little data. This is georisk: the risk of leakage due to geological factors.

Engineered risk is a key risk factor in depleted fields. Legacy wells, or existing wells—for example, historical exploration, appraisal, or oil and gas production wells—represent one of the biggest risks of loss of containment. And while we can mitigate the risk of leakage associated with existing wells, this can affect project CAPEX (upfront cost) and may be difficult to implement. In offshore projects, locating a legacy well if it is plugged and abandoned can be the biggest challenge. Projects may be abandoned if the cost of making legacy wells safe before CO2 injection is too high. Saline aquifers may carry a lower risk of engineered loss of containment, but if they are sitting above a producing formation, many wells may pass through the saline aquifer, are often the fast-drilled, minimum-cost section of a well, and can be prone to increased leakage risk.

In phase management, CO2 is different, both chemically and thermodynamically, to hydrocarbons. In normal pressured saline aquifers, the main requirement is to ensure CO2 remains in a dense (supercritical) phase to maximize the mass of CO2 that can be stored. This occurs at depths of at least 800-1000 m below the surface of the earth. In depleted fields, there can be a significant difference between the pressure of CO2 arriving at the wellhead and the pressure in the reservoir under CO2 injection. This can lead to the CO2 changes “phase,” for example, from dense liquid state to gas phase in an instant, which is a violent transformation and can cause problems with changes in density of the CO2 and a rapid drop in temperature. Our challenge is to design a well and an injection plan to handle and control the CO2 phase over the project lifecycle as injection starts and the reservoir starts to re-pressure.

How do you envision geological carbon storage as a promising tool to achieve net-zero?

CCS is just one technology, but may be critical for the reduction of emissions as it has the potential to capture and store large volumes of CO2, and keep them out of the atmosphere for an extended period of time to allow the Earth's carbon cycle to reach something close to equilibrium. We must harness the most appropriate technologies for the geographic location (not everywhere has suitable geological storage sites), the volume of emissions, and the local economy.

From a long-term sustainability perspective, what do you think needs more research to ensure the stability of CCS storage sites over decades or even centuries?

I think the CCS industry has progressed over the past 20 to 30 years. The cost of CCS remains an obstacle, but from a technical perspective, one concern is how to assess the risk of leakage from legacy wells. Old wells were drilled several decades ago with a wide range of materials and methods. These wells were not drilled with long-term CO2 storage in mind. Production wells may have been in service for several years and have been exposed to different fluids and stresses. Our job is to perform a risk assessment on all these factors and identify the risk of loss of containment, evaluate the effect of any movement of CO2 around the well, and plan and perform corrective action to prevent the risk of CO2 migration along the well that is cause for concern for other resources (e.g., potable water) or surface release.