• The required CO2 injection rate for CCS to meet the net-zero ambition is significant. For example, if 15% of the total CO2 emissions savings is attributable to CCS, the amount of CO2 required to be sequestered is greater than the world’s total petroleum and liquid production line 46-56. • Deepwater (subsea) locations provide potential for high-rate, low-well-count development and sustained injectivity. Currently, all CCS operations exist in onshore and shallow-water offshore environments. No CCS project exists in a deepwater (or subsea) environment. (Note: the integrated deepwater system is subsea-dominated based on huge volume and fixed surrounding conditions.) • For improved system efficiency, optimal storage density, and operational stability, the desire is to inject CO2 at a supercritical state, maintain a dense phase in the entire system, and avoid flash vaporization at any point along the system. • We developed and validated an integrated (coupled) heat and fluid flow model for a subsea CO2 injection system that encompasses surface, subsea, and subsurface components. Our approach deploys a one-dimensional finite element model (FEM) to analyze non-isothermal CO2 flow to support surveillance plan and optimization for intermediate (non-boundary) nodes at the riser base and wellhead. • We concluded that for deepwater (subsea) systems, dense (supercritical and liquid) phase is maintained throughout the entire system for bounded conditions of: depleted-to-geopressured reservoir systems, high-to-low injectivity, varying subsea geometry (riser length, flowline length, pipe diameter, etc). We also evaluated start-up/ramp-up operations. • We identified the subsea wellhead as the most vulnerable point for flash vaporization at high injection rates due to frictional pressure drops and non-linear factors unique to higher-rate deepwater systems. Large-scale deployment of carbon capture and storage (CCS) will require substantially high rates of carbon dioxide (CO 2 ). This creates the need for development concepts that combine reliable injectivity with manageable well count. Deepwater subsea environments offer favorable pressure–temperature conditions for dense-phase CO 2 injection, but the integrated behavior of surface, subsea, and subsurface wellbore systems under such conditions is not yet well quantified and largely undocumented in existing literature. This study develops and applies a one-dimensional finite element model for non-isothermal CO 2 flow in an integrated deepwater injection system that includes surface facilities, riser, subsea flowline, and wellbore components. The model solves coupled conservation equations, uses CO 2 property data from National Institute of Standards and Technology, and employs unified correlations as a smoothing function within the phase transition region to ensure numerical stability. We apply the model to evaluate the impact of reservoir pressure, injectivity index, subsea geometry, and ramp-up strategy on system performance. Across depleted to geopressured reservoirs and a wide range of injectivities, deepwater conditions maintain CO 2 in a dense phase throughout the system under both low and high injection rates. The main operational risk is localized at the subsea wellhead, where frictional pressure losses in long flowlines can move the operating point toward the vapor region at high rates. Gradual ramp-up schedules and appropriately sized flowlines mitigate this risk and extend the dense-phase operating window. The results demonstrate that deepwater subsea CCS is technically feasible and can support high-rate, low-well-count developments, provided that frictional effects and ramp-up procedures are explicitly managed in design and operations.
Effiong et al. (Sun,) studied this question.