CO2/Brine/Rock Interactions Under CO2 Sequestration Conditions

CO₂/brine/rock interactions under CO₂ sequestration conditions

Y. Soong^*, B. H. Howard, S. W. Hedges, D. McIntyre, R. Warzinski, G. Irdi, I. Haljasmaa¹_, and D. Crandall¹

U.S. DOE, National Energy Technology Laboratory,

P.O. Box 10940, Pittsburgh, PA 15236

¹ URS Co.

It has indicated by Intergovernmental Panel on Climate Change Study that injection of CO₂ into confined geological formations, given their potentially massive carbon storage capacity and widespread geographic distribution, represents one of the most promising options for mitigating anthropogenically-induced global climate change.  The Mount Simon sandstone in the Midwest region of the U.S is recognized as a promising candidate host reservoir for carbon sequestration. The Mount Simon is a deep saline aquifer and is a primary reservoir target for large scale carbon dioxide injection tests due to its proximity to CO₂ sources, favorable depth, thickness, permeability, porosity, and the presence of the overlying Eau Claire Formation as a seal.  The Midwest Geological Sequestration Consortium (MGSC) has selected the Mount Simon as the reservoir at its major demonstration project. While the Mount Simon Sandstone has ideal reservoir characteristics in some areas, there are significant variations in porosity, permeability, and mineralogy.

 

Numerous studies have been conducted to investigate changes in host rock properties when exposed to CO₂.  Luquot and Gouze conducted CO₂-enriched fluid flow through a carbonate core sample under in situ sequestration conditions (T = 100 °C and P = 12 MPa).  Under these conditions, a decrease in permeability and porosity is seen that is linked to precipitation of Mg-rich calcite.    Gouze and Luquot also conducted an X-ray microtomography characterization study of porosity, permeability and reactive surface changes during the dissolution of pure calcite in a brine-CO₂ mixture.  It  showed that the increase in permeability is due to the decrease of the tortuosity for homogeneous dissolution, whereas it is due to the combination of tortuosity decrease and hydraulic radius increase for heterogeneous dissolution.  Jove Colon et al., studied the permeability, porosity and reactive surface area evolution during dissolution of nonfractured, clay-free Fontainebleau sandstone cores using a flow-through percolation reactor. The experiments were performed at 80°C with 0.1 M NaOH solution.  The permeability was found to vary depending on where the dissolution occurred: in the pore void or the pore throat.  Liu et al., conducted a simulation study of CO₂ sequestration in the Mount Simon sandstone via TOUGHREACT. They indicated that a strongly acidified zone (pH 3-5) forms in the areas affected by the injected CO₂ and consequently causes extensive secondary mineral precipitation (calcite, magnesite, ankerite, alunite and anhydrite) and dissolution of feldspars.  Thus, the injection of CO₂ into a deep saline aquifer affects porosity since it can cause both mineral dissolution and precipitation in the formation.  To predict if there will be any changes to the reservoir during sequestration, it is critical to understand the behavior of the authigenic minerals that line pore spaces when they are in contact with the CO₂ saturated brine.

  

An experimental study was conducted to assess the impacts of injected CO₂. Core samples from the Mount Simon formation were placed in CO₂ saturated brines at sequestration temperature of 85 °C and pressure of 23.8 MPa in the presence of synthetic Illinois Basin brine for a period of six months in a set of 1.3 liter high-pressure vessels (17-4PH-1150 stainless steel, 10.2 cm I.D. x 16.5 cm depth, manufactured by Thar Technologies, Inc.).  One sandstone sample with a porosity of 7.9% was obtained at depth of 1,769.7 m from a well located in Vermillion County, IN.  The other sample with a porosity of 1.4% was collected at depth of 2634.2 m from a well located in Knox County, IN.  The major mineral composition for the first sample is 78% quartz, 15% Feldspar and with less than 2% microcline and trace minerals.  The primary mineral composition of the second sample obtained from Knox County is 70% quartz, 22% Feldspar, and around 4% illite/muscovite.  Micro CT, CT, XRD, SEM, petrography, porosity, and permeability analyses were conducted prior to the six month exposure.  Upon completion of the experiment, the analyses were repeated.

The permeability of the Vermillion sandstone after the six month exposure to CO₂ and brine was 0.85 mD compared to 1.6 mD for the fresh sample. On the other hand, the permeability of Knox sandstone was 69 nD compared to 50 nD for the fresh sample. The results suggest that the exposure altered the pore characteristics and thus the permeability of the sample. Micro CT analysis as well as SEM backscattered images were used to probe the Vermillion and Knox Co. sandstone before and after the six month exposure to the CO₂/brine environment.  It can be seen that mineral dissolution and mineral precipitation occurred after the samples were exposed to CO₂/brine for six months.  Mineral precipitation occurred in the Vermillion sample pores and cracks blocking flow and resulting within the observed 50% decrease in permeability.  For the case of Knox sandstone, the mineral dissolution occurred in pore though the precipitation was observed in the exterior of the sample.  This might result in increasing in permeability.  In addition, from the analyses of the reacted brines within the reactor, it indicated the possibly of Feldspar dissolution.

When CO₂ is injected into a saline formation, acidic conditions form in the brine in the nearby portion of the reservoir thus reducing the pH of the brine in the vicinity of the injection system.  Minor minerals in the sandstone, such as K-feldspar, calcite, kaolinite, microcline etc., that are stable in the native environment but not stable at lower pH can dissolve. Eventually, the increase of cation concentration produced by mineral dissolution can supersaturate the fluids with respect to other minerals.  If this occurs, precipitation of new minerals can result in a change of porosity and permeability which could affect both CO₂ storage capacity and fluid movement. The issue is further complicated by the evolution of pore geometry due to these geochemical reactions that may affect the overall hydrologic properties of the host rock and therefore the performance of the unit as an effective reservoir. 

The decreasing permeability found in Vermillion sandstone was probably due to Feldspar dissolution, migration and precipitation altering the sandstone pore/crack structure.  For the case of sandstone from Knox county, the permeability increased by 38%.  It might be due to the Feldspar dissolution in the pore and mineral precipitation at exterior surface of the sandstone.  Investigations are continuing to more clearly elucidate the mechanisms and geochemistry of this system, especially at the pore structure scale.