Fundamentals of CO2-Hydrocarbon Interactions for CO2 storage with EOR/EGR in offshore reservoirs: modeling, numerical methods and upscaling

Storage of carbon dioxide (CO2) in geological formations is a means to reduce atmospheric emissions of this greenhouse gas. CO2 storage combined with enhanced oil recovery (EOR) or enhanced gas recovery (EGR) is perceived as the most cost-effective method of disposing captured CO2 emissions. It has been performed for many decades in the US and Canada, but traditionally with a focus on hydrocarbon recovery. On the Norwegian Continental Shelf, CO2 storage will be emphasized in order to meet ambitious climate targets set in Norway and Europe. Project CHI has carried out basic research on CO2-hydrocarbon interactions for CO2 storage in oil and gas reservoirs that could fundamentally alter the ability to recover trapped hydrocarbons while simultaneously maximizing CO2 storage. The project has focused on two processes, convective mixing and wettability, which were chosen because recent experiments show compelling results that may have a significant, yet still largely unknown, impact on field-scale fluid flow (recovery) and trapping (storage). Convective mixing of CO2 in oil is caused by density variations in CO2-oil mixtures. It increases the mixing of injected CO2 with the oil, and this also modifies the mobility of the oil (recovery). Wettability is the preference of one fluid to be in contact with the rock surface over another. This impacts the capacity of the rock to trap CO2. However, wettability can change over time. The project has carried detailed modeling studies related to convective mixing. A new code has been developed to model convective mixing between CO2 and oil under various conditions. Results show intriguing results for CO2 mixing with oil from below. The density changes under mixing lead to very complex dynamics. Convective fingers move in two directions: up with lighter CO2 and down with a dense CO2-oil mixture. The mixing eventually stops before CO2 can reach the top of the oil zone, showing that it is possible to store CO2 safely away from the top of the reservoir. The prototype code has been created in MATLAB, which led to integration of the new model into now implemented into a fully compositional simulator within the OPM (Open Porous Media) open source software hub. The OPM model has been used to improve our understanding of the transition from viscous fingering to density-driven convection. This new knowledge can then be used to determine the correct way to model complex and flow-dependent mixing processes at the field scale. In addition to flow modeling, the project has completed a new thermodynamic model for CO2-hydrocarbon mixtures that compare well to the available data. This task has proved challenging given the highly unstable nature of the equations near critical points. A MATLAB code has been created that gives accurate values for density of CO2-hydrocarbon mixtures in single-phase and two-phase regions. In addition, the model is based on the cubic model, which has been adjusted to better match the available data. The model provides a description of the phase boundary between CO2 and many different hydrocarbons. This comprehensive model has been implemented together with the mixing code into OPM. The model is extremely useful not just for CO2 in the reservoir, but also for determining the properties of CO2-oil mixtures throughout the CO2-EOR value chain, i.e. wellbore flow, compression and handling. A PhD student has investigated the impact of wettability alteration when brine or oil wet rocks are exposed to CO2. The experimental evidence has been used to develop a porescale model for wettability alteration?contact angle changes over time with increased exposure to CO2. The porescale model can be used to carry out ?experiments? on the computer instead of expensive and time-consuming lab experiments. The experiments led to new models that describe how the petrophysical properties (capillarity and relative permeability) transition from one wettability state to another over time. The dynamic models contain an extra parameter that can be predicted by a simple and cheap contact-angle experiment performed in the lab. The new model has been examined by mathematicians to ensure that the additional dynamics do not cause instabilities in reservoir simulation. The new model has been implemented in OPM. After the project finishes, the model can be used to predict flow behavior in realistic storage settings where long-term wettability alteration is a factor. Two aspects can be examined: (1) increase the storage capacity in the reservoir on the short-term, and (2) the ability of the faults and seals to contain CO2 if a water-wet caprock seal changes to non-wetting.

The outcomes of the project are: - Training of a doctoral student, who gained important career-building skills coding in programming and communication. - Increased international collaboration in N America and Europe provided valuable guidance and enhanced the profile of Norwegian CO2 research with recognized experts. - Increased competence of researchers in wettability alteration and thermodynamics and connection with a wider interdisciplinary scientific community. - Transfer of knowledge to younger researchers crucial for maintaining excellence in CCS research. The project will have an impact for CCS stakeholders. For operators, storage technology TRL has increased from concept to prototyped software for CO2 reservoir simulation. Better understanding of CO2 behavior in saline aquifers, depleted oil and gas fields, and associated with CO2-EOR operations is important for building confidence in the safety and effectiveness of long-term CCS by industry, regulators and society.

Project CHI will carry out basic research on CO2-hydrocarbon interactions in CO2 storage with enhanced oil recovery (EOR) and enhanced gas recovery (EGR) reservoirs that could fundamentally alter the ability to recover trapped hydrocarbons while simultaneously maximizing CO2 storage. The project focuses on two processes, convection and wettability, which were chosen because recent numerical and laboratory experiments show compelling core-scale results that may have a significant, yet still largely unknown, impact on field-scale fluid flow (recovery) and trapping (storage). The ability to manage fluids in order to optimize both recovery and storage is dependent on advanced, next-generation models, which could significantly add value to CO2-EOR/EGR projects in light of stricter climate policies. Direct application of the standard reservoir models is not recommended because of known deficiencies with regard to fine-scale convection and dynamic wettability alteration. Thus, a necessary first step in the project is to thoroughly study the basic mathematical equations and detailed numerical models before any large-scale simulation experiments can be performed. The resulting advanced knowledge will be integrated into field-scale simulators and used to investigate expected impacts on CO2-EOR/EGR scenarios. A practical outcome of the project will be quantification of field-scale impacts and assessment of reservoir conditions under which oil and gas recovery can be improved while simultaneously increasing long-term storage potential.