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Abstract

Summary

Carbon capture and storage with utilization in enhanced oil recovery (EOR), or CCUS, is perceived as the most cost-effective method of disposing captured carbon dioxide (CO2) emissions. CO2 injection for EOR has been performed for many decades with a focus on hydrocarbon recovery. However with CCUS, two new factors will bring additional challenges to a well-established industry. First, CO2 storage will be increasingly emphasized in order to meet greenhouse gas emissions targets, requiring operators to quantify the fate of CO2 in the reservoir. Second, CO2-EOR will be introduced into the offshore environment, where economic constraints may restrict the number and placement of wells thus impacting flow regimes in the reservoir. In both cases, the interaction between CO2 and hydrocarbons at the fine scale plays an important role, and therefore detailed understanding is required for effectively managing CO2 migration and storage efficiency in CO2-EOR reservoirs, or any storage reservoirs with existing hydrocarbons.

Fine-scale interactions between CO2 and hydrocarbons occur in zones where fluids mix in a fully miscible setting. The mixing process occurs at the sub-centimeter-scale and involves complex convective-diffusive processes. Most oils exhibit non-monotonic change in density when mixed with CO2, which leads to density instabilities in the mixing zone. These density differences can play a significant role in parts of the reservoir that are gravity dominated, either by design or constraint. One key factor is that density instabilities may occur that drive convective mixing and impact the flow behavior of mixed fluids in these regimes.

In this paper, we investigate gravity-driven mixing for different CO2-hydrocarbon mixtures using a highly accurate computational model. The simulation results are used to characterize the fine-scale behavior of convective mixing. We consider reservoir conditions similar to the current Snøhvit CCS project in offshore Norway (approximately 20 MPa and 80 C). In that storage project, CO2 is injected into the water leg of a gas-producing field, just below a 10-m oil layer. If CO2 migrates into the gas plume through the oil, there is a risk of contamination at the producing wells. Due to the resolution required to correctly capture convective cells, it is not possible to simulate the entire reservoir. Therefore, we consider a simplified scenario where CO2 mixes with oil from above or below given a completely static initial condition. The results from this study can help provide insight into the potential impact of non-monotonic mixture density for CO2 migration in hydrocarbon reservoirs.

© EAGE Publications BV
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/content/papers/10.3997/2214-4609.201802239
2018-09-03
2024-04-25

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http://instance.metastore.ingenta.com/content/papers/10.3997/2214-4609.201802239
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CO2 Convection In Oil Driven By Non-Monotonic Mixture Density
Conference Proceedings 2018, 1 (2018); https://doi.org/10.3997/2214-4609.201802239
/content/papers/10.3997/2214-4609.201802239
/content/papers/10.3997/2214-4609.201802239
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