Roman Berenblyum

Carbon dioxide capture and storage (CCS) is a necessary requirement for high-emitting CO₂ industries to significantly reduce volumes of greenhouse gases released into the atmosphere and mitigate climate change. Geological CO₂ storage into depleted oil and gas fields is the fastest and most accessible option for CCS deployment allowing for re-purposing existing infrastructures and utilizing significant knowledge about the subsurface acquired during field production operations. The location of such depleted fields in the neighborhoods of high-emitting CO₂ industries is an additional advantage of matured on-shore European fields. Considering these advantages, oil and gas operators are now evaluating different possibilities for CO₂ sequestration projects for the fields approaching end of production. This article describes an integrated approach to reservoir simulations focused on evaluating a CO₂ injection pilot at one of these matured fields operated by MND and located in the Czech Republic. The CO₂ injection site in focus is a naturally fractured carbonate reservoir. This oil-bearing formation has a gas cap and connection to a limited aquifer and was produced mainly by pressure depletion with limited pressure support from water injection. The article summarizes the results of the efforts made by the multi-disciplinary team. An integrated approach was developed starting from geological modeling of a naturally fractured reservoir, integrating the results of laboratory studies and their interpretations (geomechanics and geochemistry), dynamic field data analysis (pressure transient analysis, including time-lapse) and history matching reservoir model enabling simulation of the pilot CO₂ injection. The laboratory studies and field data analysis provided descriptions of stress-sensitive fracture properties and safe injection envelope preventing induced fracturing. The impact of potential salt precipitation in the near wellbore area was also included. These effects are considered in the context of a pilot CO₂ injection and addressed in the reservoir simulations of injection scenarios. Single-porosity and permeability reservoir simulations with a dominating fracture flow and black-oil formulation with CO₂ simulated as a solvent were performed in this study. The arguments for the choice of the simulation approach for the site in focus are shortly discussed. The reservoir simulations indicated a larger site injection capacity than that required for the pilot injection, and gravity-driven CO₂ migration pathway towards the gas cap in the reservoir. The application of the approach to the site in focus also revealed large uncertainties, related to fracture description and geomechanical evaluations, resulting in an uncertain safe injection envelope. These uncertainties should be addressed in further studies in preparation for the pilot. The article concludes with an overview of the outcomes of the integrated approach and its application to the field in focus, including a discussion of the issues and uncertainties revealed.

Carbon dioxide capture and storage (CCS) is a necessary requirement for high-emitting CO2 industries to significantly reduce volumes of greenhouse gases released to the atmosphere and mitigate the climate change. Geological CO2 storage into depleted oil and gas fields is the fastest and most accessible option for CCS deployment allowing for re-purposing of existing infrastructure and utilizing the significant knowledge about the subsurface acquired during the field production operations. Location of such depleted fields in neighbourhood of high-emitting CO2 industries is additional advantage available for matured on-shore Europe fields. Considering these advantages, the oil and gas operators are now evaluating different possibilities for CO2 sequestration projects for the fields approaching end of production. This article describes an integrated approach to reservoir simulations focused on evaluating CO2 injection pilot at one of such matured fields operated by MND and located in the Czech Republic. The potential CO2 injection site in focus is a naturally fractured carbonate reservoir. This oil-bearing formation has a gas cap at the top and a limited aquifer at the bottom of the reservoir and was produced mainly by pressure depletion with quite limited pressure support from water injection. The article summarizes results of efforts taken by the multi-disciplinary team to develop and apply an integrated approach to reservoir simulation started from geological modelling of the naturally fractured reservoir and integrating results of laboratory studies and their interpretation (geomechanical and geochemistry laboratory experiments) and dynamic field data analysis (pressure transient analysis including time-lapse) into the history matching of the reservoir model and simulations of pilot CO2 injection. Attention is given to evaluating and modelling stress-sensitive fracture properties and safe injection envelope preventing induced fracturing as well as impact of potential salt precipitation in the near wellbore area. These effects are considered in the context of pilot CO2 injection and addressed in reservoir simulations of the injection scenarios. Single porosity and permeability reservoir simulations with dominating fracture flow and black-oil formulation with CO2 simulated as a solvent were used in this study and arguments for such choice of the simulation approach for the site in focus are shortly discussed. The reservoir simulations have indicated larger site injection capacity than required for the pilot injection and allowed to evaluate CO2 migration pathway within the reservoir. The application of the approach to the site in focus has also revealed large uncertainties, related to fracture description and geomechanical evaluations, resulted in an uncertain safe injection envelope. These uncertainties should be addressed in further studies in preparation to the pilot. The article concludes with an overview of the outcomes of the integrated approach and its application to the field in focus including discussion of issues and uncertainties revealed.

Storing CO₂ in geological formations is an important component of reducing greenhouse gases emissions. The Carbon Capture and Storage (CCS) industry is now in its establishing phase, and if successful, massive storage volumes would be needed. It will hence be important to utilize each storage site to its maximum, without challenging the formation integrity. For different reasons, supply of CO₂ to the injection sites may be periodical or unstable, often considered as a risk element reducing the overall efficiency and economics of CCS projects. In this paper we present outcomes of investigations focusing on a variety of positive aspects of periodic CO₂ injection, including pressure management and storage capacity, also highlighting reservoir monitoring opportunities. A feasibility study of periodic injection into an infinite saline aquifer using a mechanistic reservoir model has indicated significant improvement in storage capacity compared to continuous injection. The reservoir pressure and CO₂ plume behavior were further studied revealing a ‘CO₂ expansion squeeze’ effect that governs the improved storage capacity observed in the feasibility study. Finally, the improved pressure measurement and storage capacity by periodic injection was confirmed by field-scale simulations based on a real geological set-up. The field-scale simulations have confirmed that ‘CO₂ expansion squeeze’ governs the positive effect, which is also influenced by well location in the geological structure and aquifer size, while CO₂ dissolution in water showed minor influence. Additional reservoir effects and risks not covered in this paper are then highlighted as a scope for further studies. The value of the periodic injection with intermittent CO₂ supply is finally discussed in the context of deployment and integration of this technology in the establishing CCS industry.