Carbon capture and storage

Filling the Technical Gaps on the Road to Megascale Carbon Storage

Broad consensus is forming on the need for a massive expansion in global carbon capture and storage (CCS) capacity. But what are the uncertainties, bottlenecks, and opportunities in the subsurface that await CCS planners?

CO2 Refrigeration System
High-pressure CO2 refrigeration unit.
Credit: Getty Images.

It may help bring balance to the world’s anxieties over climate change and its future energy needs. However, at this stage in the game, a rapid buildout of carbon capture and storage (CSS) capacity is far from certain.

Oft cited is the need for bigger financial incentives to jump-start more commercial CCS projects, either in the form of bigger tax credits and stiffer carbon pricing. Less spoken to is the fact that there are also geotechnical gaps that need to be filled in order to understand all the risks and uncertainties.

“We need to be putting [CO2] in the right geology, and secure sites for CCS are not everywhere,” said Steve Melzer, a CO2 injection specialist and founder of Midland-based Melzer Consulting. In using the word "secure," the veteran geological engineer of more than 30 years was underlining the ultimate requirement that CCS facility planners do everything possible to avoid CO2 leakage.

He was one of several experts that addressed the subsurface aspects involved in scaling up CCS at last month’s Unconventional Resources Technology Conference (URTeC). They acknowledged that while CCS has a 50-year track record, it pales in comparison to what is being proposed as necessary to stop the clock on climate change.

Important to note is that the high cost of commercial CCS hubs will demand economies of scale, likely in the form of unprecedented levels of localized injection activity. “So, we need more than small-volume injection case histories to really be comfortable in making those investment decisions,” emphasized Melzer.

A project that may establish such a benchmark is ExxonMobil's proposed US Gulf Coast CCS hub which the oil and gas major said could consume 100 megatons annually of CO2 by 2040—more than double the world's current injection volume. However, ExxonMobil says it cannot move forward on the $100-billion project without financial support from the government.

The Global CCS Challenge in Oil and Gas Terms

In its “Net Zero by 2050” report, the International Energy Agency (IEA) said CCS capacity must reach 1.6 gigatons of CO2 annually by 2030. That figure must then rise to 7.6 gigatons per year by 2050.

  • Using the oil and gas industry’s more familiar surface volume figures, these milestones roughly equate 80 Bcf/D and 380 Bcf/D of CO2, respectively.
  • Today, the world injects only around 40 megatons of CO2 annually, or 2 Bcf/D, for permanent sequestration at 23 CCS projects—19 of which are in the US. As of last year, 65 additional commercial CCS projects were in the development pipeline.
  • Despite the recent momentum, global CCS capacity must increase by at least two orders of magnitude over the next 30 years to realize IEA’s net-zero scenario. According to one study, such vast volumes could mean the world needs 10,000 to 14,000 CO2 injection wells that it does not have today.

Key Subsurface Concerns, Bottlenecks, and Opportunities

In order to meet the immense scope outlined by the IEA, experts at URTeC spoke to several of the subsurface issues CCS developers will have to work through first.

Caprock Integrity. A competent geologic seal(s) is a paramount requirement for the permanent storage of CO2 and to avoid leakage to the surface or into freshwater aquifers. There are several aspects to maintaining caprock integrity, but it all begins with proper site selection.

  • Less tectonically active formations are going to be a good place to start looking for an injection site. Specific examples of these stable formations in the US include the Denver-Julesburg Basin (foreland basin); the Permian Basin (Cratonic basin); and the US Gulf Coast (divergent/passive margin basin).
  • “The beauty of the Cratonic basins is that they’re usually capped by evaporites,” said Melzer who works on CO2 projects in the Permian. He added that the evaporites, particularly the salts, make the caprock ductile at relatively low pressures and depths (e.g., 1,500 psi, 2,500 ft). Under such conditions, he added, that “you’ve got a very effective seal for anything injected below it.”
  • Adequate lateral continuity of the injection reservoir is another key ingredient. Melzer said without this feature "we're going to increase the pressure and cause issues with our seals."

Wellbore Integrity. Aside from the formation, another top concern is the injection wellbore itself and how it is drilled/constructed.

  • Hamed Soroush pointed out that “breakouts and drilling-induced tensile fractures during drilling are a risk to wellbore integrity and can be sources of CO2 leakage.” In addition to best drilling practices, he said another key to preventing fugitive CO2 will be a quality cement job behind the casing.
  • Soroush is the CEO of Petrolearn, an Atlanta, Georgia-based geoscience training and consulting firm. He’s been studying drilling aspects of CCS and said just like in oil and gas developments, drilling problems and delays also drive up overall costs. "However, since CCS projects are typically not economically profitable, this imposed cost is much more pronounced," he said.
  • With robust geomechanical modeling, CSS planners can mitigate downhole issues by analyzing different wellbore trajectories and mud weights. However, Soroush warned, "As much as a good geomechanical model is valuable in reducing risk and project costs, a bad geomechanical model can be can be so misleading and have completely opposite results."

Induced Seismicity. Though typically small in nature, induced seismicity poses a danger to life and property and may also impact caprock or wellbore integrity.

  • To avoid triggering these events, CCS projects will rely on extensive site characterization to determine safe injection thresholds and avoid sensitive areas where changes in the stress field may lead to the reactivation of faults or large fractures.
  • Oil and gas industry experience may prove extremely helpful since it has conducted extensive research on induced seismicity related to saltwater disposal wells in North America.
  • Soroush stressed again that this issue demands geomechanical modeling, specifically the variety that try to account for fluid dynamics and temperature shifts in the reservoir. Geomechanics is the only science that can identify microseismicity risk and prevent it by the optimization of the injection strategy," he insisted.

Interaction Issues. Driven by economics, many CO2 transportation networks will terminate at concentrated CCS sites using an array of injector wells. This will add a significant degree of complexity as demand for CCS capacity rises in the coming years.

  • While injected CO2 remains close the wellbore, “the pressure effects are almost instantaneous and expand at quite a distance,” said Hannes Leetaru, head of petroleum geology at the Illinois State Geological Survey.
  • Hence, CO2 plumes from neighboring injector wells will interact, creating risk and uncertainty that must be well planned for. This affects the future use of an area, which begs the needs for regional-scale management.
  • Pressure fronts may “sterilize adjacent storage capacity,” noted Michael Stephenson, the director of science and technology at the British Geological Survey. In such scenarios, he said “perhaps ‘not-the-best’ geological site is actually the best one to begin with because it avoids those interactions.”

Data Access. Repositories of publicly available geologic data will help CCS researchers and planners mitigate induced seismicity and estimate injection capacities.

  • However, Stephenson said more privately held and other disparate datasets held by research bodies need to be brought together in order to paint a better picture of the world’s CCS opportunities.
  • “This is recognized as a global problem across geology,” he said, adding that there is a lot of data out there, but so much of it resides in small, private databases which makes it difficult to access. Initiatives like the Deep-Time Digital Earth Program (DDE) represent one of the proposed solutions.
  • Led by the International Union of Geological Sciences, the DDE is developing an open platform that links together geoscience data from existing databases and integrates data science tools to aid research and new discoveries.  

Formation Evaluation. Today, only four of the world’s large-scale CCS facilities are injecting into deep saline formations. Going forward, though, saline formations are considered to be a prime target for CCS explorers, thanks in large part to their global abundance and large storage capacities.

  • However, high-salinity formations lower CO2 solubility, or the ability of the gas to dissolve into the brine. Thus “a deep understanding of aquifer salinity is needed,” said Rahul Grover, a reservoir performance product manager with Schlumberger.
  • This may drive demand for less-saline formations which can be identified by existing well logging technologies such as downward spectroscopy. Grover said the specialized tool measures formation chlorine, which when coupled with other conventional logs, “gives us a robust, continuous water-salinity estimation.” During the injection phase, other spectroscopy-logging techniques can be used to measure CO2 saturation.
  • Permanent fiber-optic cables represent another technology asset that can help monitor pressure fronts, saturation plumes, zonal stress, and acquire 4D seismic surveys. Grover also noted that fiber optics are well-proven tools for leak detection and for identifying seismicity.