**1. Introduction**

Saline aquifers hold the largest potential for geological CO2 storage considering total volume, economic and environmental factors [1]. CO2 storage is considered one important measure for the imminent reduction of greenhouse gas emissions and climate change mitigation [2]. Most suitable reservoir candidates, pilot projects, and commercial operations utilize siliciclastic deeply buried sandstones [3,4]. In evaluating the suitability of saline aquifers for CO2 storage, geological characterization is of crucial importance in estimating the reservoir property distribution and reactivity under prevailing reservoir conditions. Sedimentary facies and burial diagenesis control the petrophysical properties and mineralogical composition of the reservoir host rock, and to some extent the chemistry of pore water. These factors must be specified when evaluating the relative effect of various trapping mechanisms for CO2 (i.e., structural, residual, solubility, ionic, and mineral trapping [5]). The physical and chemical immobilization of CO2 are important controls in risk assessments.

Predictions of the CO2 trapping potential of a storage reservoir over hundreds to thousands of years requires a sound understanding of the geochemical reactions that will come about when CO2 is injected and the thermodynamic system is perturbed [6]. Such predictions ideally require detailed knowledge about the mineralogy, formation water chemistry, mineral surface reactivities, and reaction rates. These data are then used as input in the geochemical batch or reactive transport numerical simulations (e.g., [7–12]). This is, however, not trivial for several reasons. First, there is no simple way to accurately estimate reactive surface areas of the various reactive mineral phases without careful sediment analyses and theoretical models to relate reactive and total surface areas [13–16]. This may lead to corresponding orders-of-magnitude uncertainties in the rates of CO2 mineral trapping [17]. Second, the most commonly used rate models, i.e., based on transition state theory (TST), have been suggested to largely overestimate the growth rates of secondary carbonates at low temperatures and in the shorter time scales (<100–1000 years) [10,17,18]. Third, data on the mineralogy may in many cases be available only as crude XRD data, without details on the individual mineral morphologies, grain size, sediment maturity, etc.

The relative importance of the various trapping mechanisms for injected CO2 in aquifers has been discussed ever since Gunther and co-workers published their geochemical simulations on solubility, ionic, and mineral trapping in the early nineties [19,20]. This relates especially to how fast these reactions are, and if they will impose porosity/permeability changes. This has implications if true complex multiphase reactive flow simulations are needed, or if flow and reactions can be partly separated. Most commonly, reservoir simulations of CO2 storage only include the dissolved CO2 in contact with separate phase CO2, and disregard the mineral-formation water reactions due to slow reaction rates. Furthermore, the heterogeneity of reservoirs with respect to mineralogy and grain size has seldom been taken into account (e.g., [7,16,21–23]). However, some mineral phases and occurrences do seem to react and contribute to mineralization in shorter time scales (100's of years) (e.g., [10,24]) and are thus valid for consideration in sensitivity studies of storage reservoir performance.

We show how to more accurately estimate input parameter values for reactive mineral surface areas, as used in the geochemical modelling of long-term mineralization potential for CO2. Reservoir models can be improved by upscaling from pore- and grain-scale to sedimentary facies distributions with the associated reactive mineral characteristics [25]. A general workflow is outlined, which can be applied to improve facies and mineral specific estimates of reactive surface areas and mineralization potential for CO2 in sandstone aquifers.

## *Case Study: The Johansen Formation, North Sea (NORWAY)*

Simulation examples with input from the Johansen Formation are provided. The Johansen Formation is part of the Northern Lights full scale storage prospect offshore Norway (Figure 1), which is highly relevant at this time due to imminent drilling and plans for CO2 injection [26]. The first formal license for injecting and storing CO2 as part of full-value chain carbon capture and storage (CCS) was approved by Norwegian authorities as of 2019 (Exploitation Licence EL001, by the Norwegian Petroleum Directorate) [26].

The Johansen Formation (Dunlin Group) is a sandstone of early Jurassic age [27]. This prospective reservoir is located offshore of the city of Bergen on the western Norwegian coast (Figure 1). It displays thicknesses in the order of 100–180 m and is located at burial depths of 2–3 km. The saline aquifer is in parts underlying the operating Troll Gas Field in the North, and as a premise for storing CO2, there is to be no risk of interference with on-going production [4]. Thus, the potential injection area considered in evaluations of storage potential for CO2 is located approximately 20 km south of Troll, at top formation depths in the order of 3 km. The Cook Formation is likely to be in contact with the Johansen Formation and provide as a secondary reservoir unit. The main sealing unit is the Drake Formation mudstone [4,28,29].

**Figure 1.** The Johansen Formation is a prospective CO2 storage reservoir offshore of Norway, located at burial depths of ca. 2100–3200 m. The operating hydrocarbon field "Troll" (yellow) is located north of the licensed CO2 injection area "EL001". The cored well 31/2-3 is marked in red, and additional wells with wire line data from the Johansen Formation are marked as black dots. There are no well data available from EL001 as of yet, while an appraisal well is planned [26]. Source data are available at factmaps.npd.no, with suggested injection area and depth maps as shown in [29].

The Johansen Formation is interpreted as a progradational to retrogradational sequence of shallow marine sandy deposits sourced from the east [28,29]. The depositional environment in the licenced injection area (Figure 1) has been interpreted to comprise lower to upper shoreface deposits based on seismic data and extrapolation (across distance and depth) of well data from the Troll area [28]. However, an accurate facies description of sandstone in the injection area is not feasible until an appraisal and/or injection well is drilled and sample material becomes available. The shallow marine facies and mineral assemblages of the Johansen Formation appear analogous to several other CO2 reservoir candidates on the Norwegian Shelf, e.g., the Sognefjord, Fensfjord, Krossfjord, Cook, and Gassum formations [29–35].
