Second EAGE Sustainable Earth Sciences (SES) Conference and Exhibition

In this paper, we demonstrate the importance of predicting the effects of fracture networks on flow, using a case study from the In Salah CO2 storage site in Algeria. We show how fracture permeability is closely controlled by the stress regime determining the conductive fracture network, and that the anisotropy of the conductive network is reflected in surfaces deformation imaged by InSAR. Our results demonstrate that fracture network prediction combined with present day stress analysis can be used to successfully predict CO2 movement in the sub-surface.

Inducing hydraulic fractures is vital in developing enhanced geothermal systems. To the same extent, simulation of such fluid-driven fractures is a complicated process to model even for simple geometries. This difficulty is subjected to the moving boundary conditions due to propagation of crack, non-linear governing equations of fluid flow within the fractures and the high gradient of mechanical deformation near the fracture tip. This paper presents an XFEM framework developed for numerical modeling of hydraulically induced fractures in a porous media interacting with the flow of fluid. This model takes the fully coupled hydro-mechanical processes into account and also, uses the concept of cohesive crack which is more suitable to describe the nonlinear behavior of the quasi-brittle material in the fracture process zone.

Many uncertainties exist in geochemical modeling. Mineral reactive surface area is one of the uncertain parameters. QEMSCAN analyses are performed on sandstone samples from a Dutch CO2 natural analogue to determine reactive surface areas. Geochemical modeling is performed using QEMSCAN surface areas and surface areas which are conventionally used in modeling. The model predicts that the QEMSCAN reactive surface areas result in higher reaction rates and faster equilibration of the sandstones with CO2. The fact that reactions are predicted to occur in a sandstone which has been in contact with CO2 for geological times suggests that the reservoir mineralogy is not yet in equilibrium with CO2. This would indicate that, even if mineral reactive surface areas are determined in detail, geochemical models strongly overestimate reaction kinetics. Other uncertain parameters which can affect kinetics, like mineral nucleation and ion diffusion, should be evaluated in order to be able to better predict long-term CO2-mineral reactions and storage integrity.

The goal of this work is to simulate CO2 storage in a deep saline aquifer case that is currently considered for field injection. Results of RTM are obtained using both TOUGHREACT and the in-house Shell reservoir simulator MoReS, which was recently coupled with the geochemical software PHREEQC. The obtained results are very similar when the same geochemical database and input parameters are used. Small changes in porosity, up to a maximum of 0.003, are computed as a result of dissolution and precipitation reactions. Benchmarking of simulation software is important for quality control and confidence in obtained results.

Renewables suffer from fluctuating energy generation, which means that they generate energy overspills during beneficial weather conditions which, due to lack of large scale storage options, cannot be used at a later point but is wasted. A viable option would be to convert the energy into hydrogen and to store it in existing porous subsurface formations. To assess the influence of hydrogen rock interaction during underground storage of natural gas hydrogen mixtures in porous subsurface formations, a geochemical gibbs free energy simulation was done. The simulation was conducted for the mineral assembly of two existing porous subsurface formations. The model showed that hydrogen increases the pH, and therefore changes the mineral composition of the reservoir rock by dissolving dolomite and precipitating calcite and talc. Additional investigations included crystalline mine rals which were not affected and clay minerals which could not be assessed as reliable data for these minerals is not yet available. Finally the stability of sulphides was assessed to rule out the possible generation of H2S. It was found that under subsurface conditions, sulphides will stay stable

This paper presents the outline of the CO2-DISSOLVED project whose objective is to assess the technical-economic feasibility of a novel CCS concept integrating geothermal energy recovery, aqueous dissolution of CO2 and injection via a doublet system, and an innovative post-combustion CO2 capture technology. Compared to the use of a supercritical phase, this approach offers substantial benefits in terms of storage safety, due to lower brine displacement risks, lower CO2 escape risks, and the potential for more rapid mineralization. However, the solubility of CO2 in brine will be a limiting factor to the amount of CO2 that can be injected. Consequently, and as another contributing novel factor, this proposal targets low to medium range CO2 emitters (ca. 10-100 kt/yr), that could be compatible with a single doublet installation. Since it is intended to be a local solution, the costs related to CO2 transport would then be dramatically reduced, provided that the local underground geology is favorable. Finally, this project adds the potential for energy and/or revenue generation through geothermal heat recovery. This constitutes an interesting way of valorization of the injection operations, demonstrating that an actual synergy between CO2 storage and geothermal activities may exist.

Use of the subsurface has become steadily more intensive and globalized. This is due to wider application of conventional uses and to the emergence of relatively new, unconventional uses. This raises the question of whether we are managing the subsurface space in a sustainable way that also enables us to understand and mitigate the risks that may emerge. Depending on the purpose of subsurface space use, typical risk challenges may include e.g. impacts to groundwater, oil and gas resources. Expanding uses of the subsurface motivates additional effort to mitigate well-known and relatively new risks. Estimating risk levels in complex systems can be a daunting task if the strategy is to construct simulation models of all known physical processes combined with uncertainties in the system, which for subsurface projects, often dominate the system description. An alternative approach described here isolates the main risk drivers in a high-level probabilistic format known as a Bayesian (Belief) Network (BN). The BN approach accommodates more general relationships between uncertain variables than event or fault trees and allows expression of probabilities to consistently influence the top-level risk indicators. A BN risk model will typically be more compact and legible than its fault/event tree equivalent.

The CO2 storage atlas of the Norwegian part of the North Sea and Norwegian Sea has been prepared by the Norwegian Petroleum Directorate at the request of the Ministry of Petroleum and Energy. The main objectives have been to identify the safe and effective areas for long-term storage of CO2 and to avoid possible negative interference with ongoing and future petroleum activity. 27 geological formations have been individually assessed, and grouped into saline aquifers. The assessed aquifers have been ranked according to guidelines which have been developed for this study. The evaluation of geological volumes suitable for injecting and storing CO2 can be viewed as a step-wise approximation as shown in the maturation pyramid. A modeling study will be presented to understand the timing and extent of long distance CO2 migration

Successful CO2 storage in deep saline aquifers relies on economic efficiency, sufficient capacity and long-term security of the storage formation. Unfortunately, these three criteria of CO2 storage are generally in conflict, and often difficult to guarantee when there is a lack of geological characteristics of the storage site. We overcome these challenges by developing: 1) multiwell CO2 injection strategies using a multi-criterion optimization to handle conflicting objectives; 2) CO2 injection management that is robust against model uncertainty. PUNQ-S3 model was modified as a leaky storage to study injection strategies associated with the risks of CO2 leakage under geological uncertainty. Based on our numerical results, the NSGA-II with the ASGI technique can effectively obtain a set of efficient-frontier injection strategies. For the uncertainty assessment, the impact of the model uncertainty to the outcomes is significant. Therefore, our findings suggest using the mixture distribution of the objective-function values, as opposed to the traditional Gaussian distribution to cover model uncertainty

A rock physics diagnostics study is performed for the Tubåen formation in the Snøhvit field with the aim of characterizing the transport properties for the different sand intervals. This is combined with co2 injection laboratory experiments for selected plugs from the sand intervals to understand the impact the CO2 injection have on the microstructure of the rock framework and its physical properties. The rock physics diagnostic indicates that parts of the Tubåen formation are dominated by stiff load bearing contact cement, other parts by pore-filling grains that can be related to poor sorting, and that don’t contribute to the stiffness of the rock. Some of these fine particles may become dislodged due to CO2 injection, which permanently changes the load bearing framework of the formation. The laboratory experiments and SEM images indicate that the CO2 injection cause a re-arrangement of the rock framework and of the movable fines that change the rock framework. The importance of fines migration is likely to depend on the initial microstructure of the rock. The results of the ongoing laboratory experiments will help to better understand the effect on the different sand intervals of the Tubåen formation.