Fourth EAGE CO2 Geological Storage Workshop

In this presentation the technical assessments, challenges, work processes and risks in the qualification of the Johansen site will be described. The site has been qualified in accordance EU storage directive and capacity and safe storage has been documented. Failure to ensure and communicate safe storage will be a serious threat to implementation of CCS. Work processes and criteria for screening, storage site qualification and development planning was established. After a screening process with several storage alternatives, the Johansen Formation was selected and a qualification program performed. The effort was to evaluate the storage to a maximum with the available data and to reduce uncertainties. 3D seismic was acquired and integrated to a cube covering the storage complex area. A conceptual geological model was established and a large numerical model constructed. Potential communication channel was investigated and communicating pore volume estimated. Leakage scenarios were studied and leakage risk estimated. Cap rock integrity and and fault seal studies performed. An entire risk register was established with impact, mitigating action etc, which indicated acceptable risk for storing the Mongstad volumes. A key learning is that the work processes from the petroleum industry cannot just be copied; however, considerable adjustments are required.

The CO2 storage atlas of the Barents Sea has been prepared by the Norwegian Petroleum Directorate at the request of the Ministry of Petroleum and Energy (Halland et al. 2013). 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. We have built on the knowledge we have from the petroleum industry and from the two CO2 storage projects, Sleipner and Snøhvit, on the Norwegian Continental Shelf. Detailed work has been carried out on all relevant geological formations and hydrocarbon fields. The work is based on several studies as well as data from more than 40 years of petroleum activity on the Norwegian Continental Shelf. Evaluated storage possibilities are saline aquifers, defined structures, abandoned oil and gas fields, and use of CO2 in producing fields to enhance recovery. The storage mechanisms considered are both structural and stratigraphic trapping. A number of geological formations have been individually evaluated, and grouped into saline aquifers. The aquifers were evaluated with regard to reservoir quality and presence of relevant sealing formations. Those aquifers that may have a relevant storage potential in terms of depth, capacity and injectivity have been considered. Structural maps and thickness maps of the geological formations are presented in the atlas, and were used to calculate pore volumes. A simulation model of the Bjarmeland structure within Stø Formation equivalent (Middle Jurassic) is situated on the southern end of the Bjarmeland Platform towards the Nyslepp Fault Complex (Fig.1). The model was built for the purpose of assessing its CO2 storage potential. The Stø Formation is thickest in southwestern wells, thinning generally eastwards (Fig.2). The sands in the Stø Fm were deposited in prograding coastal regimes, and a variety of linear clastic coastal lithofacies are represented. Marked shale/siltstone intervals represent regional transgressive pulses in the late Toarcian and late Aalenian.

The CO2CRC (Cooperative Research Centre for Greenhouse Gas Technologies) started a pilot project for carbon dioxide storage, the CO2CRC Otway Project, in Nirranda South, Victoria, Australia in 2005. Several analyses have been conducted to demonstrate that carbon capture and storage (CCS) is technically and environmentally safe. In particular, our workflow uses a one-way coupled geomechanical model to assess fault stability and potential fault reactivation in order to prevent leakage of CO2 along faults. State of stress on the faults is checked against Mohr-Coulomb failure criterion in both cases. Fault stability analysis has been performed taking into account assumptions derived from regional studies. Critical pore pressures needed for fault reactivation have been calculated for injection scenarios using both analytical and numerical approaches.

nder arbitrary uniformly-wet conditions with the use of an novel semi-analytical model. The interfacial tension between brine and CO2 is obtained as a function of the phases density difference, and the contact angle is evaluated based on the Frumkin–Derjaguin equation with the application of the DLVO theory to compute disjoining pressures isotherm curves under various storage formation conditions. Based on the developed model, the CO2 entry pressure can be computed in realistic cap-rock pore spaces extracted from 2D rock images from core samples located at various storage depths and under the appropriate pressure, temperature and brine ionic strength conditions. The dependency of brine/CO2 interfacial tension, contact angle and capillary entry pressure on CO2 storage depth and brine ionic strength is also investigated. The proposed workflow for entry pressure estimation and the relationship between capillary entry pressure and depth could enhance our understanding and improve the safety of CO2 storage. The simulated depth-dependent capillary entry pressure curves could also be incorporated into a reservoir simulation model to predict CO2 migration in the storage unit.

This work tackles the issue of water vaporization around the CO2 injectors. Indeed, CO2 is dehydrated before being reinjected into the gas field in order to limit corrosion risks in the facilities. This leads to water vaporization in the near well areas, and could also lead to CO2 injectivity impairment due to salt plugging. The key findings of this study are listed below. 1/ Modelling water-gas interactions for a gas development leads to reviewing the hydrocarbon volumes in place due to the presence of vaporized water in the gas phase. 2/ Flow models taking into account gas-water interactions can predict condensed water flow rates with time in order to contribute to the design of surface facilities. 3/ In the case of dry CO2 reinjection, significant fractions of the gas pool will be fully dehydrated. This result requires verifying potential implications in term of geomechanical or petrophysical behaviour of the rock, once dehydrated. 4/ A tentative modelling of water imbibition towards the dehydrated zone shows a limited flow of formation water, meaning that no salt blocking is expected to derive from this process.

Two-phase fault rock properties are generally neglected in CO2 sequestration modelling, and the one study that has addressed them concluded that two-phase fault-rock properties could be responsible for inhibiting pressure dissipation during sequestration in faulted saline aquifers. In this study we develop upon that work by modelling injection in idealised faulted saline aquifer with different geometrical characteristics as well as different two-phase fault rock and aquifer properties. We show that two-phase fault rock properties are not solely responsible for potential aquifer pressurization, and highlight the importance also of aquifer geometry and properties. Depending on aquifer thickness and fault throw as well as the fault-rock properties, CO2 may act as a relative permeability trap, restricting pressure equilibration via water flow through the fault.

Based on selection and also on availability of suitable core samples, reservoir rocks from 3 geological structures were selected for the experiments. The samples were exposed to spCO2 under 7,5 MPa and 35C for 3 month. Long term static experiment revelead that selected rock samples kept their properties regardless spCO2 exposure. Such an information would be important studying the suitability of reservoir structure for CO2 exposure as mineral changes are the most important parameter for potential injectability and storativity evaluation.

Two different experimental approaches for studying CO2–brine displacement and relation to a heterogeneous (layered) rock drilled perpendicular and parallel to bedding under isotropic is presented: One uses CT imaging to locally resolve the structural heterogeneity effect on pore fluid distribution and saturation and directly linking it to the geophysical measurements (resistivity and sonic velocity), the other using a ring electrode sample sleeve design to resolve local changes in resistivity in the flow direction during displacement. The studies demonstrates the importance and impact of sub core scale heterogeneity and flow/permeability anisotropy in dictating the electrical conductivity and sonic velocity response, locally and globally, during drainage and imbibition.

Pore to core scale approach is used to calculate the multiphase flow properties and the transport parameters of mass transfer with surface reaction of a real sandstone sample cored from gas field reservoir. The approach uses a simplified micro-structure of the porous medium. The pore-network (void space of the porous medium) is composed of pore-bodies joined by pore-throats with idealized geometry. Parameters defining the pore-bodies and the pore-throats distribution are determined by an optimization process aiming to match the experimental mercury intrusion capillary pressure (MICP) curve and petrophysical properties of the rock such as intrinsic permeability and formation factor. The flow is calculated by using Kirchhoff laws. Transport is determined in the asymptotic regime where the solute concentration undergoes an exponential evolution with time. The generated network is then used first to simulate the multiphase flow, the capillary pressure, relative permeability and resistivity index curves are derived. Then, reactive transport is addressed to infer pore evolutions and changes of petrophysical properties resulting from dissolution processes involved in CO2 storage. Finally, the role of the Peclet and Peclet-Damköhler dimensionless numbers on the reactive flow properties is highlighted.