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Numerical tools are essential for the prediction and evaluation of conventional hydrocarbon reservoir performance. Gas hydrates represent a vast natural resource with a significant energy potential. The numerical codes/tools describing processes involved during the dissociation (induced by several methods) for gas production from hydrates are powerful, but they need validation by comparison to empirical data to instill confidence in their predictions. In this study, we successfully reproduce experimental data of hydrate dissociation using the TOUGH+HYDRATE (T+H) code. Methane (CH4) hydrate growth and dissociation in partially water- and gas-saturated Bentheim sandstone were spatially resolved using Magnetic Resonance Imaging (MRI), which allows the in situ monitoring of saturation and phase transitions. All the CH4 that had been initially converted to gas hydrate was recovered during depressurization. The physical system was reproduced numerically, using both a simplified 2D model and a 3D grid involving ...

The effect of increased sulfate concentration in the imbibing water during oil recovery by spontaneous imbibitions in different outcrop chalks at various wettability conditions at 130 °C has been determined. Core plugs from three chalk outcrops, Rordal, Niobrara, and Stevns, were aged in crude oil and included in this study. Stevns chalk exhibited increased oil recovery during spontaneous imbibition with increased concentration of sulfate in the imbibing water phase. The effect was less than reported by others and was wettability dependent. Spontaneous imbibition tests showed that the added oil recovery was greatest at Amott water indices below 0.2, and tests at and above 0.25 showed only minor effects from sulfate. Niobrara and Rordal chalk did not show increased oil recovery with increased sulfate concentration in the brine. These core plugs reflected more water-wet imbibition characteristics at elevated temperature, and the effect of sulfate could not be isolated. Measurements of Amott water indices be...

We present experimental wettability alteration results in originally strongly water-wet, outcrop chalk core plugs using a static and two dynamic aging methods. Dynamic aging with continuous crude oil injection during the entire aging process exhibited greater reduction in water-wetness of the strongly water-wet chalk plugs than static aging without flushing. Two dynamic aging procedures were tested to find an optimal flooding rate for the most efficient reduction in water-wetness: (1) a constant crude oil flooding at 3 cm3/h using variable aging times (48, 96, and 192 h) and (2) a constant aging time (96 h) with variable flooding rates (1, 3, and 5 cm3/h). The aging temperature was kept constant in all tests (90 °C), and the impacts from varying aging times, pore volumes injected, and crude oil injection rate on the wettability alteration process were investigated. Aging was performed on consolidated, porous chalk samples with initial water present in the pore space. It was shown that static aging, i.e., ...

Two-dimensional imaging of water and oil saturations during waterfloods in fractured carbonate rock models was obtained using nuclear tracer imaging and magnetic resonance imaging. Large outcrop chalk and limestone blocks were aged in crude oil to obtain wetting conditions from strongly water-wet to weakly oil-wet. The change in the oil recovery mechanism as the wettability shifted was investigated with and without the presence of fractures. Visualization of local, in situ fluid saturations during waterfloods improved the interpretation of the displacement process and oil recovery mechanisms. Experimental results demonstrate how fractures determine the displacement pattern differently depending on the matrix wettability conditions during waterfloods. At strongly water-wet conditions, the fractures had a minor impact on the ultimate recovery but significantly changed the progression of the water front compared to the unfractured case. At less water-wet or oil-wet conditions, capillary imbibition of water f...

During spontaneous counter-current imbibition of brine into oil-filled porous rock, it is generally assumed that the flow rates of the brine and oil are equal and in opposite directions. However, significant scatter and inconsistent dimensionless times were observed in experiments using matched-viscosity fluids in two ends open (TEO) sandstone cores using an established correlation factor. In further TEO experiments, the oil production at each end face was measured separately and ranged from being equal and symmetrical to highly asymmetrical, with almost all of the mobile oil being produced from one end in nominally duplicate tests. The dimensionless time for scaled imbibition increased with increasing asymmetry in oil production. Thus, for imbibition into cores with the TEO boundary condition, although the overall flows of brine and oil have to be equal, the individual flows at each end face are not necessarily equal and opposite. The asymmetry in oil production during imbibition with the TEO boundary co...