Over the last two decades, carbon capture, utilization and storage projects have evolved toward what is expected to become a profitable enterprise in a carbon-neutral future. Government policies, such as the Section 45Q federal tax credits and California’s Low Carbon Fuel Standard, provide incentives to offset costs. And, subsurface technical knowledge and related data sets from the petroleum industry play major roles in the quest for sustainable energy.
The March 3-5 CCUS Conference in Houston, sponsored by AAPG, the Society of Exploration Geophysicists and the Society of Petroleum Engineers, will include approximately 100 posters, presentations and panel discussions about this rapidly evolving field. Talks will highlight current CCUS work and challenges, including subsurface geologic storage; infrastructure and well design; enhanced oil recovery, injection and utilization; economic and regulatory frameworks; data analytics applications; and case studies.
Below are several topics that will be highlighted:
Blue Hydrogen and CCUS at Natural Gas Wellheads
Many are working on improving the efficiency of blue hydrogen production by reducing CO₂ emissions and transportation costs. Deena Elhossary, a graduate research assistant at the University of Texas at Austin, will discuss a new, integrated on-site sorption-enhanced steam-methane reforming process, which is proposed along with CO₂ injection into gas reservoirs for simultaneous low-carbon hydrogen production and CCUS.
A synthetic 3-D natural gas reservoir model, generated using CMG-GEM software, examined the effect of CO₂ injection on natural gas production. Sensitivity studies investigated the impact of reservoir characteristics and well operating conditions on methane recovery and CO₂ storage in the reservoir. Based on numerical simulation results, CO₂ injection significantly enhanced cumulative methane production compared to natural depletion. It also helped maintain reservoir pressure and displaced methane upward as a result of density difference.
Heterogeneity, longitudinal dispersion and injection rate appeared to have the most significant impact on natural gas recovery and CO₂ storage. This process produced carbon-free fuel hydrogen, the CO₂ was sequestrated in an underground reservoir with a well-known cap rock, and the natural gas recovery was enhanced. Transportation of CO₂ back to the reservoir was avoided. While past carbon sequestration studies have mainly focused on the storage of CO₂ in aquifers and depleted hydrocarbon reservoirs, this study focused on active natural gas reservoirs.
How International SMEs in CCUS Impact Legal Frameworks, Policy
During the 2023 Industrial Carbon Management Forum, the European Commission established a working group dedicated to CO₂ standards. This group will provide recommendations to the Commission on the need for minimum CO₂ stream quality standards. Lena Wammer Ostgaard, a legal adviser of international law at IOM Law in Oslo, Norway, will explain how the European Commission is regularly turning to the European Committee for Standardization, which develops standards for CO₂ capture, transportation, utilization, storage and carbon accounting, with requests for standards to use in legal frameworks.
As a result, the CEN may be asked to develop standards for the EC on CO₂ stream composition, for example, which might become key components in a potential new regulatory framework for CO₂ transportation in the European Union. This would set a regulated industry standard that project operators may need to follow.
This approach to standards could have far-reaching and significant implications for industry and projects in Europe. Standards provide tools to reduce costs, bridge gaps in frameworks and contracts, and will be crucial to ensure public support.
Subject matter experts from approximately 40 countries around the globe and 34 countries in Europe are influencing the contents of the European and national frameworks, thus increasing the industry’s influence on legal frameworks. This could have positive impacts on the CCUS industry, but at the same time result in a more multifaceted regulatory landscape for an emerging industry.
3-D Permian Basin Faulted Petrophysical Model
Accurate petrophysical models are critical for a variety of subsurface modeling tasks related to CCUS, including CO₂ storage capacity estimation, leakage risk assessment and injection strategy optimization. Robin Dommisse, a senior geological modeling adviser at the Bureau of Economic Geology at the University of Texas at Austin, will discuss the development of a 3-D Permian Basin model that uses a unique dataset consisting of calculated petrophysical well log curves, stratigraphic horizons and fault surfaces, interpreted using both 3-D seismic and well log interpretations.
Points of discussion include the creation of a 3-D sealed faulted framework, including basement-rooted faults and shallower faults; the construction of a stratigraphic framework based on BEG and proprietary operator well top interpretations, with a particular focus on accurate shelf-to-basin correlations; the calculation of petrophysical log curves using 16,000 quad combo wells and relying on a multimineral inversion process resulting in the creation of quantitative rock type, porosity, and saturation; the distribution of petrophysical data along average five-foot-thick sublayers for each of the stratigraphic framework zones; the integration of historical production and injection data for the vertical and horizontal wells; and the validation of the 3-D petrophysical distributions using independent petrophysical well log curve results and quantitative core data measurements.
This 3-D faulted petrophysical geomodel used Schlumberger Petrel software consisting of more than 1.5 billion cells, with 16,000 calculated petrophysical well log curves, more than 50 stratigraphic zones from surface to basement, 2,000 faults, and historical production and injection data. The stratigraphic horizons were generated from 2.2 million tops in 26,000 wells. Thirty-eight 3-D seismic volumes and well logs used for the interpretation of the model were shared by operators and vendors and licensed from data providers.
The 3-D model can be used to help determine the capability of the Permian Basin to sequester CO₂. It is a first-of-its-kind Permian Basin-wide faulted petrophysical model and provides a rigorous basis for evaluating the petrophysical and fluid properties of all surface-to-basement zones within the framework of the stratigraphic and tectonic architecture of the Permian Basin.
Analog Selection, Project Comparison Using Offshore Carbon Storage Project Inventory and Data
Offshore geologic carbon storage efforts are accelerating as decarbonization strategies are being implemented worldwide. As new site characterizations take place, project information and data must be housed in central locations to improve the understanding of the success criteria for GCS. MacKenzie Mark-Moser, a research scientist at the National Energy Technology Lab, will discuss two products that have been developed to support deployment of offshore GCS. Both serve to illuminate trends in ongoing and upcoming offshore projects – such as transport, source, and geology – and can be leveraged by stakeholders to estimate storage resources, identify subsurface analogs, and address challenges to offshore GCS.
The International Offshore GCS Project Inventory is a product of extensive literature and data review in a spatial feature dataset that is accessible via an interactive dashboard. It contains more than 250 project and characterization site locations and carries as many as 50 attributes for each project. These include identification information, descriptive categorical information, source and transport information, capacity and injection rates, and geological information about reservoir and seal formations.
The Offshore GCS Data Collection leverages recent developments in spatial web applications and organizes U.S.-based datasets that automatically update and maintain consistent access. It aggregates and disseminates more than 300 publicly available data layers that can be leveraged to understand data availability and comparison. Nine themed web maps are aggregated into a single tool with a corresponding data catalog for access, visualization and exploration. Combined, these products provide information and tools for analog comparisons, project planning, and modeling.
Early Adoption of CCUS Projects Using Class II Well Projects
A case study of the early adoption of CCUS projects using Class II well projects, discussed by Robert Balch, director of the Petroleum Recovery Research Center at New Mexico Tech, will show the state of CCUS projects in the western and southwestern United States, differentiating between Class II projects in enhanced oil recovery and acid gas injection, and future in-progress projects involving Class VI wells.
The western United States has a long history of CO₂ storage in EOR projects and two decades of disposal of hydrogen sulfide with entrained CO₂ into acid-gas disposal wells. These wells are involved in oil production or the disposal of waste products from production and can use Class II wells and have eligibility for 45Q tax credits based on intended CO₂ use. An AGI well can claim the full disposal credit for the portion of the waste stream containing CO₂.
The Carbon Utilization and Storage Partnership of the Western United States, a regional U.S. Department of Energy Carbon Storage Initiative, has been involved with five midstream companies converting AGI operations to centralize additional sweet CO₂, permit additional Class II injection wells, and acquire approved monitoring, reporting and verification plans from the U.S. Environmental Protection Agency.
Storage projects in the Western United States have been ongoing for decades, and more than a gigaton of CO₂, primarily from natural sources, has gone into EOR projects. According to the EPA, 6.75 megatons of CO₂ were stored in the western United States, primarily in the Permian Basin and in EOR projects in 2022. As of August 2023, 77 percent of officially sequestered CO₂ in the country was injected into Permian Basin Class II wells.
Class II wells are most often administered by state regulators, and Class VI wells most often by the federal government. This is significant in that a Class II well can be permitted within a year, and Class VI wells take three or more years to be processed by the EPA. While the types of disposal for Class II wells are limited to the byproducts of oil and gas production, they represent a shorter path to early adoption of CCUS projects.
First Sequestration in a Carbonate Saline Aquifer: A Case Study
Carbonate saline aquifers in onshore Abu Dhabi have great potential for CO₂ sequestration. The geological setting is ideal, reservoir properties are excellent and the storage capacity is enormous. Jane Mason, a senior specialist of advanced geoscience solutions at the Abu Dhabi National Oil Company, will discuss the development of an injector dedicated to CO₂ sequestration that was drilled for the first time in the UAE in 2023. Its goal was to monitor and verify CO₂ injectivity, conformance and site containment. This is notoriously difficult in onshore Abu Dhabi because of the stiffness of carbonate rocks and the inherent non-repeatability of seismic surveying.
To improve seismic repeatability, the well was completed with fiber optic technology cemented in place behind casing. Fiber optic cable was also clamped to the outside of the injection tubing, allowing for direct comparison of measured results while complementing the data acquisition program. Seismic monitoring consists of zero-offset vertical seismic profiles every month, and 3-D VSPs every four months. The baseline for the 3-D VSP covers a 4-kilometer radius around the well to maximize subsurface coverage, but the radius of the repeat surveys will depend on the size of the expected CO₂ plume.
Preliminary time lapse data acquisition results show promising results. Twelve zero-offset VSPs and three 3-D VSP repeat surveys have been acquired and processed. Repeatability after corridor stack processing is excellent, and a clear time delay can be picked below the top of perforation as injected CO₂ volumes increase every month.
Processing of the 3-D VSPs was more complicated, however a similar time delay in the injection zone for the zero-offset VSPs was detected. These preliminary results are the first of their kind to be acquired for CO₂ injection in carbonates, and the exact extent of the CO₂ plume will require careful quantitative analysis. Minute changes in rock properties due to CO₂ injection in an onshore carbonate saline aquifer can be detected by seismic monitoring using a highly repeatable fiber optic-based system.
The fact that CO₂ plume monitoring is feasible and can effectively contribute to measuring, monitoring and verification specifications, unlocks the huge potential of carbonate saline aquifers in the United Arab Emirates and beyond.
CarbonSAFE
Large-scale deployment of carbon management technologies is crucial to achieving the ambitious climate goal of a net-zero emissions economy by 2050. The Department of Energy’s Office of Fossil Energy and Carbon Management, supported by the Bipartisan Infrastructure Law, is investing in the development of large-scale commercial carbon storage projects and associated transport infrastructure.
Traci Rodosta, senior program manager of carbon storage infrastructure at the FECM, will discuss the Carbon Storage Assurance Facility Enterprise (CarbonSAFE) program initiated in 2016 that supports the development of large-scale, commercial storage facilities. CarbonSAFE aims to catalyze the rapid deployment of storage onshore and offshore in a variety of geologic settings while facilitating technical knowledge-sharing and involving community benefits. Through exploration, appraisal and permitting storage facilities across the country, CarbonSAFE will provide regional solutions for decarbonization. Over a five-year period, from fiscal years 2022 through 2026, the BIL will expand and accelerate the CarbonSAFE initiative by investing more than $2 billion for carbon storage infrastructure throughout the country.
Nine new CarbonSAFE Phase II projects and 16 new Phase III projects have been selected in the first two rounds of BIL-supported CarbonSAFE funding opportunities. The initiative provides a regional solution for decarbonization through funding a portfolio of storage infrastructure that will provide the regional substructure for carbon management strategies. Regional solutions vary across the country, including storage types, and these new projects are evaluating storage potential in sandstones, carbonates and basalts.
As these projects move through the permitting and construction phases, they will create storage and transport anchor points for current and future capture facilities. These initial storage projects will catalyze the further build out of storage and transport infrastructure into the future.