Carbon Sequestration Case Study: Large-Scale Exploration in a Basal Saline System in Canada and the United States

As one of the U.S. Department of Energy’s regional carbon sequestration partnerships, the Plains CO₂ Reduction (PCOR) Partnership is performing a case study on the feasibility of large-scale underground CO₂ storage in the basal saline system of central North America. The area of investigation encompasses approximately 1,500,000 km² of the Alberta and Williston Basins located in the provinces of Alberta, Saskatchewan, and Manitoba in Canada and the states of Montana, North Dakota, and South Dakota in the United States. The thickness of the system is up to 300 m, with a permeability range from 10 to 1250 mD and porosity ranging from 1% to 25%. The calculated static storage resource for CO₂ in this saline system is 480 billion metric tons. However, the realistic injectivity is highly dependent on the reservoir pressure buildup, which must be considered during the CO₂ injection and postinjection for storage resource estimation and risk assessment.

In the study area, there are 16 aggregated large-scale CO₂ sources. Eight scenarios were designed to address the dynamic CO₂ storage capacity and pressure transient. To increase the injectivity and maximize the storage resource use, various strategies were explored, including injector optimization, injection rate optimization, water extraction during CO₂ injection, modifications to the ratio of vertical permeability and horizontal permeability (Kv/Kh), boundary condition plays, and relative permeability changes. Dynamic simulation was set to initiate in 2014 and end in the year 2050. Another 50-year postinjection was followed to check the pressure transient for the whole domain.

The results indicate that the total injected CO₂ is 82.2 Mt for the base case, which includes a single injector at each of the 16 CO₂ source locations. To improve injectivity, the number of injection wells was increased to 210. The added wells increased the total injected CO₂ by 37% to 112.3 Mt. In another scenario, 20 water extractors were placed in conjunction with the injectors at the largest CO₂ emission source location, which resulted in the total CO₂ injected increasing to 183.1 Mt: 63% higher than the previous scenario. The scenarios exploring various Kv/Kh ratios showed the resulting effect on the dynamic storage capacity to be very small. However, the scenario involving changes to the relative permeability curves showed significant increase of the storage capacity over the base case. A time-stepped injection scenario involving bringing the 16 injection locations online over a series of years and at an increasing annual injection rate over the injection period showed better performance than the case where all of the sources begin injecting their full output simultaneously. This is because the higher rate in the beginning results in faster reservoir pressure buildup and ultimately constrains the injections. Overall, the pressure difference in the injection area between 2050 and 2014 was increased to ~800 psi, which is lower than the limitation of the reservoir pressure. After the 50-year postinjection period, the pressure difference decreased to ~400 psi.

The successful exploration of this case study for CO₂ storage in the basal saline system of central North America provides a basic guideline in performing evaluations of large-scale CO₂ storage demonstration projects. Specifically, this effort helps to answer questions regarding reservoir pressure buildup over the injection and postinjection periods and to track the CO₂ movement. This effort plays a crucial role in the entire process of CO₂ monitoring, verification, and accounting for such a large-scale case study of CO₂ storage estimation.