No abstract

CO2 sequestration and storage into methane (CH4) hydrate sediments is investigated in this study to evaluate CH4 replacement by CO2 in hydrates through both macroscale and microscale experiments at varying thermodynamic conditions. The kinetics of CO2-CH4 replacement in hydrates was experimentally evaluated using the production/CO2 sequestration setup within the methane hydrate stability zone (HSZ) and within (HSZ-I)/outside the CO2 HSZ (HSZ-II). These results were further extended at the microscale using a visual glass micromodel to validate the CH4-replacement/CO2 storage kinetics in presence of a commercial Kinetic Hydrate Inhibitor (KHI) to explore the feasibility of KHI for mitigation of CO2 hydrate blockage during CO2 injection. Up to 71% CH4 gas recovery was obtained in the macroscale excess gas experiments within the HSZ-II, whereas the higher water saturation condition diminished this CH4 recovery by 9.3%. Deep inside the HSZ-I, a significant CH4 production of 51.7% was obtained (at frozen conditions) with 1% of an inhibitor application in water.For the first time ever, our novel microscale micromodel evaluations clearly revealed the release of CH4 gas through the convection, slow CO2 diffusive mass transfer and the CO2-CH4 replacement, within the HSZ-I. Moreover, this process potentially benefits from the long-term permanent CO2 sequestration and storage in the form of clathrate hydrates while offsetting the cost of its injection through the clean energy methane recovery.

No abstract

The oil recovery process is controlled by the rates of gas injection and oil production, relative permeabilities, reservoir heterogeneities and the balance among viscous, capillary and gravity forces. Crestal gas injection in horizontal, vertical or reef type oil reservoirs recovers significant volumes of the residual oil due to the gas-oil gravity drainage mechanism, indicating the significance of gravity forces. This study investigates the effects of the parameters that control the process (e.g., rate of the gas injection and oil production) and reservoir heterogeneities on the overall performance of immiscible gravity drainage enhanced oil recovery (EOR). Reservoir simulation studies are conducted to map effective combinations of these parameters with respect to the oil recovery performance. Introduction Gravity forces play an important role at nearly every stage of the producing life of the reservoir, whether it is primary depletion, secondary water or gas injection schemes or tertiary enhanced or improved oil recovery methods(1). They can be advantageously used to maximize oil recovery from the oil bearing zone under investigation through gravity drainage mechanism. Several cases reported in the literature suggest that it could deliver as high as 87 to 95% incremental oil recoveries in contrast to other gas injection EOR methods. Gas-Oil Gravity Drainage Process Gravity drainage is a process in which gravity acts as a main driving force and where gas replaces voidage volume(2). It is commonly implemented in either of the dipping or pinnacle reef type reservoirs. CO2-assisted gravity drainage EOR process is a top-down process in which gas is injected in the gas cap through vertical wells at a rate lower than the critical rate (Figure 1). Critical rate is the rate at which injection gas fingers through oil zone (viscous instabilities) leading to its premature breakthrough at the production wells. Injected gas segregates and creates a gas-oil interface. Controlled oil production is started through horizontal wells placed at the bottom of the oil zone such that the voidage created by oil withdrawal (in addition to minor dissolved volumes) is replaced by the equivalent CO2 injection volume. When this happens, pressure differential across the gas cap and oil zone [that is gas-oil contact (GOC)] stay at or close to zero implying that the pressure in the gas zone behind the CO2 floodfront would be constant(3). This helps to maintain the reservoir pressure nearly constant.

No abstract

Gas injection is one of the key enhanced oil recovery (EOR) methods. Significant volumes of the residual oil, remaining after earlier EOR methods, has been reported to be recovered through the gravity drainage mechanism, following the crestal gas injection in the horizontal, dipping or reef type oil reservoirs. The rate of oil recovery is controlled by the viscous/capillary/gravity forces, the rate of gas injection and oil production, the difference of oil and gas density, the oil relative permeability, the oil viscosity and number of other operational parameters. Risk analysis of these parameters helps to identify their relative dominance during gas-oil gravity drainage process. The interactions between various process controlling parameters is studied through development of scaling groups that govern the displacement process. Functional relationships between those scaling groups and their effect on the overall performance of immiscible gas-driven gravity drainage EOR are investigated in this study. This enables an estimation of fractional oil recovery for the combinations of scaling groups. The results of numerical sensitivity analysis through the reservoir simulations are presented to map the effective combinations of the dimensionless scaling groups for gas-oil gravity drainage EOR method.

No abstract

In carbon capture, utilization and storage (CCUS), a thorough understanding of thermophysical behaviour of the candidate fluid is an essential requirement for accurate design and optimised operation of the processes. In this communication, vapour liquid equilibrium data (VLE) of the binary mixtures of CO+CO2 are presented. A static-analytic method was used to obtain VLE data at six isotherms (253.15, 261.45, 273.00, 283.05, 293.05, 298.15) K and pressures up to 12 MPa. The standard uncertainties of the measured temperature and pressure were estimated to be 0.1 K, 0.005 MPa, respectively. Also, the standard uncertainty of the measured molar composition of each phase is found to be less than 1.1%. The measured experimental results are then compared with some predictive thermodynamic equations of state (EoS) (i.e. the Peng Robinson (PR-78) with classical or Wong-Sandler mixing rules, the GERG, and EoS-CG without an with a specific departure function) and available data in the literature. A sound agreement is observed between the results of this work and some of the VLE data published in the open literature. Furthermore, for all isotherms, the best agreement is observed between experimental results and predicted VLE data from the PR-EoS with the Wong-Sandler mixing rules and the EoS-CG with a specific departure function. However, a significant deviation is found between measured results and VLE data calculated using the GERG-EoS.