Vincent Nana Boah Amponsah

Disposing of carbon dioxide (CO₂) in the seafloor environment in its hydrate form provides an efficient means of CO₂ storage in virtually unlimited quantity. The process requires that the in situ condition be above the hydrate-forming pressure and below the hydrate-forming temperature and that the bulk CO₂ hydrates have densities greater than seawater density for gravitational stability. The objectives of this study are (1) to find an efficient method for generating stable CO₂ hydrates, (2) to identify the required equipment for efficient production of CO₂ hydrates, and (3) to identify the required water depth in various seawater environments for CO₂ injection. The first objective was achieved using a windowed reactor to observe the floating and settling behavior of generated CO₂ hydrates. CO₂ injection into the chilly water phase and water injection into the cold CO₂ phase were both investigated at various pressures and temperatures. CO₂ injection into the chilly water phase was found to generate bulk CO₂ hydrates of density less than that of water due to the excess CO₂ trapped in the bulk hydrates. Water injection into the cold CO₂ phase was found to generate bulk CO₂ hydrates of density greater than that of water due to the excess water trapped in the bulk hydrates. The second objective was achieved by designing a complete set of equipment to be installed on a ship with an open-bottom reactor assembly attached to the ship. The third objective was achieved by cross-plotting the hydrate-forming pressure curve versus the seawater hydrostatic pressure curve for seven seas and the Arctic Ocean. Results show that the minimum required seawater depth varies from 120 m in the Arctic Ocean to 650 m in the Mediterranean Sea environment.

Disposing carbon dioxide (CO2) in seafloor environment in its hydrate form provides an efficient means of CO2 storage in virtually unlimited quantity. The process requires that the in-situ condition be above the hydrate forming pressure and below the hydrate forming temperature and the bulk CO2-hydrates have densities greater than seawater density for gravitational stability. The objectives of this study are (1) to find an efficient method for generating stable CO2-hydrates, (2) to identify the required equipment for efficient production of CO2-hydrates, and (3) to identify the required water depth in various seawater environments for CO2 injection. The first objective was achieved using a windowed reactor to observe the rising-settling behavior of generated CO2-hydrates. CO2-injection into chilly water phase and water-injection into cold CO2 phase were both investigated in various pressures and temperatures. CO2-injection into chilly water phase was found to generate bulk CO2-hydrates of density less than water density due to the excess CO2 trapped in the bulk hydrates. Water-injection into cold CO2 phase was found to generate bulk CO2-hydrates of density greater than water density due to the excess water trapped in the bulk hydrates. The second objective was achieved by designing a complete set of equipment to be installed on a ship with an open-bottom reactor assembly attached to the ship. The third objective was achieved by cross-plotting hydrate-forming pressure curve versus seawater hydrostatic pressure curve for seven seas and the Arctic Ocean. Result shows that the minimum required seawater depth varies from 120 m in the Arctic Ocean to 650 m in the Mediterranean Sea environment.

An improved depleting sand fracture model was derived in this work using Finite Element Methods, taking into consideration the effect of pore pressure and production on in situ stresses. Sets of governing equations from the commercial finite element simulator COMSOL Multiphysics were used to obtain a model that compares well with the existing fracture model, mainly based on the Mohr–Coulomb failure criterion. The model uniquely couples reservoir depletion-induced stress evolution with fracture initiation and propagation within a unified finite element framework. A constant overburden load was used since its value majorly depends on depth, and the formation is assumed to be fixed at the bottom. The reservoir is assumed to be depleting at a constant rate with no water injection to assist pressure, with an average porosity of 25% and an average permeability of 251 mD at the beginning of production. The reservoir compacted during production, and in turn, porosity and permeability were reduced over the years of observation. Fracturing was observed to be much easier for the depleted reservoir, since horizontal stresses, which might have created friction, are reduced during reservoir production, signifying that for depleted reservoirs, a small fracture pressure is required. Created fractures are observed to propagate in the direction of the maximum horizontal stress and perpendicular to the direction of the minimum horizontal stress.

Injecting carbon dioxide (CO₂) into underground geo-structures, such as depleted oil and gas reservoirs, reduces man-made CO₂ emissions into the atmosphere or removes what is already there. Studies have identified the risks of CO₂ leaks from these underground geo-structures through wellbores back into the atmosphere due to the high mobility of CO₂ in gaseous and supercritical states. This work aims at proposing a novel method of CO₂ storage using the Joule–Thomson cooling effect to effectively produce CO₂ hydrates on seafloors, with an objective to avoid the leakage risks of storage in depleted oil and gas reservoirs. Through the combination of thermodynamic data, analysis of hydrate stability, and engineering design with established working parameters, this study proposes an innovative concept and an enabling process for CO₂ placement onto seafloors for safe storage. The results of case analysis of typical seawater conditions reveal that the appropriate seafloor depth ranges for different applications (>1900 m for liquid CO₂ and 700–1900 m for CO₂ hydrate). An engineering design procedure for real applications is outlined.

Scale deposition during waterflooding, driven by the incompatibility between injected seawater and formation of water, poses significant challenges to reservoir performance. This study examines the mechanisms of inorganic scale formation and assesses its impact on productivity index, permeability, and pressure dynamics using the ECLIPSE simulator. A five-layered reservoir model with one injector and one producer (spaced 700 feet apart) was simulated under varying seawater injection rates of 1000, 3000, and 5000 stock tank barrels per day (stb/day). The results revealed rapid water breakthrough and escalating water cuts (34–38%) across scenarios, with scale deposition concentrated in layers 3 and 4, reducing permeability by up to 47% and productivity index by 50%. Layer 3 exhibited a threefold higher scaling due to the intense mixing of seawater and the formation of water. The study highlights the necessity of sulfate removal, alternative water sources, well repositioning, and preemptive scale inhibition to minimize reservoir damage caused by scale-induced permeability impairment.

Amathematical model was derived in this study to reveal the mechanism of CO2 imbibition in shale formations considering the combined effects of capillary force and viscous force in concave curved triangle pore channels surrounded by different solid materials with different wettability. The model reveals that CO2 imbibition depth is proportional to the square root of CO2 soaking time, square root of the pore size determined by grain size, square root of interfacial tension and cosine of contact angle, and inversely proportional to the square root of CO2 viscosity. Up to three solid wall materials with different contact angles can be considered in the model. Using the average contact angle for the three materials over-estimates the imbibition distance. CO2 imbibition is faster in concave curved triangle pores than in equivalent circular-shaped pores. The dimensionless geometry correction factor is less than unity (α = 0.81). The newly developed imbibition model can be used for predicting the maximum time of imbibition between parallel fractures in multi-fractured shale formations. Document Type: Original article Cited as: Zhang, J., Guo, B., Amponsah, V. N. B. A more rigorous mathematical model for capillary imbibition of CO2 in shale gas formations. Capillarity, 2025, 14(3): 63-71. https://doi.org/10.46690/capi.2025.03.01