• Evaluation of CO₂ sequestration through enhanced oil recovery in West Sak reservoir

      Nourpour Aghbash, Vahid (2013-05)
      CO₂ enhanced oil recovery (EOR) has been proposed as a method of sequestering CO₂. This study evaluates using CO₂ as an EOR agent in the West Sak reservoir. The injected CO₂ mixes with the oil and reduces the oil viscosity, enhancing its recovery. A considerable amount of CO₂ is left in the reservoir and 'sequestered'. Due to low reservoir temperature, this process can lead to formation of three hydrocarbon phases in the reservoir. An equation of state was tuned to simulate the West Sak oil and complex phase behavior of the CO₂-oil mixtures. A compositional simulator capable of handling three-phase flash calculation and four-phase flow was used to simulate CO₂ injection into a three-dimensional heterogeneous pattern model. The results showed that CO₂ EOR in the West Sak reservoir increases oil recovery by 4.5% of original oil in place and 48 million metric tons of CO₂ could be sequestered. Ignoring four-phase flow underestimated oil recovery and sequestered CO₂ volume. Enriching the CO₂ with natural gas liquid decreased sequestered CO₂ volume without a significant increase in oil recovery. Dissolution of CO₂ in the water phase and different water/CO₂ slug sizes and ratios did not change the sequestered CO₂ volume and oil recovery.
    • Molecular dynamics simulations to study the effect of fracturing on the efficiency of CH₄ - CO₂ replacement in hydrates

      Akheramka, Aditaya O.; Dandekar, Abhijit; Patil, Shirish; Ahmadi, Mohabbat; Ismail, Ahmed E. (2018-05)
      Feasible techniques for long-term methane production from naturally occurring gas hydrates are being explored in both marine and permafrost geological formations around the world. Most of the deposits are found in low-permeability reservoirs and the economic and efficient exploitation of these is an important issue. One of the techniques gaining momentum in recent years is the replacement of CH₄-hydrates with CO₂-hydrates. Studies have been performed, at both laboratory and field based experimental and simulation scale, to evaluate the feasibility of the in situ mass transfer by injecting CO₂ in gaseous, liquid, supercritical and emulsion form. Although thermodynamically feasible, these processes are limited by reaction kinetics and diffusive transport mechanisms. Increasing the permeability and the available surface area can lead to increased heat, mass and pressure transfer across the reservoir. Fracturing technology has been perfected over the years to provide a solution in such low-permeability reservoirs for surface-dependent processes. This work attempts to understand the effects of fracturing technology on the efficiency of this CH₄-CO₂ replacement process. Simulations are performed at the molecular scale to understand the effect of temperature, initial CO₂ concentration and initial surface area on the amount of CH₄ hydrates dissociated. A fully saturated methane hydrate lattice is subjected to a uniaxial tensile loading to validate the elastic mechanical properties and create a fracture opening for CO₂ injection. The Isothermal Young's modulus was found to be very close to literature values and equal to 8.25 GPa at 270 K. Liquid CO₂ molecules were then injected into an artificial fracture cavity, of known surface area, and the system was equilibrated to reach conditions suitable for CH₄ hydrate dissociation and CO₂ hydrate formation. The author finds that as the simulation progresses, CH₄ molecules are released into the cavity and the presence of CO₂ molecules aids in the rapid formation of CH₄ nanobubbles. These nanobubbles formed in the vicinity of the hydrate/liquid interface and not near the mouth of the cavity. The CO₂ molecules were observed to diffuse into the liquid region and were not a part of the nanobubble. Dissolved gas and water molecules are found to accumulate near the mouth of the cavity in all cases, potentially leading to secondary hydrate formation at longer time scales. Temperatures studied in this work did not have a significant effect on the replacement process. Simulations with varying initial CO₂ concentration, keeping the fracture surface area constant, show that the number of methane molecules released is directly proportional to the initial CO₂ concentration. It was also seen that the number of methane molecules released increases with the increase in the initial surface area available for mass transfer. On comparing the positive effect of the two parameters, the initial CO₂ concentration proved to have greater positive impact on the number of methane molecules released as compared to the surface area. These results provide some insight into the mechanism of combining the two recovery techniques. They lay the groundwork for further work exploring the use of fracturing as a primary kick-off technique prior to CO₂ injection for methane production from hydrates.
    • Scaling laws in cold heavy oil production with sand reservoirs

      Robertson, Keith W. III; Awoleke, Obadare; Peterson, Rorik; Ahmadi, Mohabbat; Liu, Jenny (2018-08)
      This thesis presents a rigorous step by step procedure for deriving the minimum set of scaling laws for Cold Heavy Oil Production with Sand (CHOPS) reservoirs based on a given set of physical equations using inspectional analysis. The resulting dimensionless equations are then simulated in COMSOL Mutiphysics to validate the dimensionless groups and determine which groups are more significant by performing a sensitivity analysis using a factorial design. The work starts simple by demonstrating how the above process is done for 1D single-phase flow and then slowly ramps up the complexity to account for foamy oil and then finally for wormholes by using a sand failure criterion. The end result is three dimensionless partial differential equations to be solved simultaneously using a finite element simulator. The significance of these groups is that they can be used to extrapolate between a small scale model and a large scale prototype.