A binational effort, between the United States and Canada, characterized the lowermost saline system in the Williston and Alberta Basins of the northern Great Plains–Prairie region of North America in the United States and Canada. This 3-year project was conducted with the goal of determining the potential for geologic storage of carbon dioxide (CO2) in rock formations of the 517,000 sq mi Cambro-Ordovician Saline System (COSS). This project was led on the U.S. side by the Energy & Environmental Research Center (EERC) through the Plains CO2 Reduction (PCOR) Partnership and on the Canadian side by Alberta Innovates Technology Futures (AITF). The project characterized the COSS using well log and core data from three states and three provinces and determined its storage potential by creating a heterogeneous 3-D model and determined the effects of CO2 storage in this system using dynamic simulation. The area underlain by the COSS includes several large CO2 sources that each emits more than 1 Mt CO2/year. Assuming that each of these sources will target the COSS for the storage of their CO2, the primary questions addressed by this study are 1) what is the CO2 storage resource of the COSS, 2) how many years of current CO2 emissions will it be capable of storing, and 3) what will be required and what will be the effect of injecting 104 Mt/yr of CO2 into the COSS? A 3-D geocellular model was created and used to determine the static CO2 storage resource and the dynamic storage capacity. The complexity of the reservoir was characterized from numerous sources of data, including the online databases of North Dakota, South Dakota, and Montana and a wealth of data provided by project partners in Canada. Multimineral petrophysical analysis was conducted to determine the system’s gross lithology and key petrophysical characteristics. Information derived from these analyses was used to create a facies model that captures the heterogeneity of the COSS at this broad scale. The completed geocellular model contains information on temperature, pressure, porosity, permeability, and salinity. These variables were distilled to produce components needed to compute the CO2 storage resource of the COSS following the Esaline formula detailed by the U.S. Department of Energy (DOE) Office of Fossil Energy Atlas III and IV (2010, 2012). The resulting effective static CO2 storage resource is 218, 412, and 706 Gt at the P10, P50, and P90 percentiles, respectively. This resource potential represents more than 2100 years of storage for the current 104 Mt/yr point source emissions. To further evaluate this extensive system and thus its viability as a potential sink, the geocellular model was used as the framework for an assessment of the system’s dynamic CO2 storage capacity. In the area above the COSS, there are 25 large stationary sources that were viii grouped into 16 geographic areas that have a combined annual emission of 104 Mt. With this in mind, the first injection scenario considered seven cases where the target was to inject this total mass of CO2 for 36 or 50 years in the 16 injection areas using a total of 210 wells. Results from these cases show a total mass of CO2 injected ranging from 82 to 1412 Mt across the injection period of 36 and 50 years. These values represent between 2.2% and 27.2% of the available CO2 emitted from the 16 source locations. In the second scenario, eight new cases where the original 16 injection locations were disaggregated and moved (pipelined) to areas defined by the model as having good reservoir volume connection (geobodies) based on permeabilities greater than 50 mD. Injection amounts in the second scenario range from 1949 to 3112 Mt of CO2. These values represent 37.5% to 59.8% of the CO2 emitted from the source locations. Based on the results of both scenarios, the selection of areas with better permeability and connected volume had a large impact on increasing the total amount of CO2 stored and the per well injection rates. However, even in the better area, the COSS was not able to support 211 injection wells with an average injection rate of 0.5 Mt/yr. In the second scenario, the average annual per well injection rate was between 185,000 and 275,000 tons/yr. At these injection rates, a total of 378 to 563 wells would have been required to meet the injection target. Pressure differences monitored in the second scenario show small changes in the 50-year injection time period. These minimal pressure differences indicate small risks of leakage from the reservoir and integrity of the sealing cap rock due to CO2 injection in the COSS. The results of the static CO2 storage resource estimate indicate that the COSS has thousands of years of storage potential at the current point source CO2 emission levels. However, the actual task of injecting the annual emissions is more difficult. Results from simulation indicate that injecting all the point source CO2 in an area directly beneath the sources using 210 wells did not result in meeting the storage target. With that in mind, the COSS model and simulations were run on limited data, and just because these simulation cases indicated that the injection volumes, as a whole, could not be reached does not mean that the geology around a particular CO2 source is poor. These results indicate that there is sufficient storage potential in the COSS to store all of the current point source CO2 emissions for at least the next 50 years; however, more wells will likely be needed and spread out over more of the COSS to achieve this goal.
- PDFWDP-Task 16 D92 Revised-Dec14.pdf