Gas hydrate bearing sediments (HBS) are natural soils formed in permafrost and submarine settings where the temperature and pressure conditions are such that gas hydrates are stable. If these conditions shift from the hydrate stability zone, hydrates dissociate and move from the solid to the gas phase. Hydrate dissociation is accompanied by significant changes in sediment structure and strongly affects its mechanical behavior (e.g. sediment stiffenss, strength and dilatancy). The mechanical behavior of HBS is very complex and its modeling poses great challenges. This paper presents a new geomechanical model for hydrate bearing sediments. The model incorporates the concept of partition stress, plus a number of inelastic mechanisms proposed to capture the complex behavior of this type of soil. This constitutive model is especially well suited to simulate the behavior of HBS upon dissociation. The model was applied and validated against experimental data from triaxial and oedometric tests conducted on manufactured and natural specimens involving different hydrate saturation, hydrate morphology, and confinement conditions. Particular attention was paid to model the HBS behavior during hydrate dissociation under loading. The model performance was highly satisfactory in all the cases studied. It managed to properly capture the main features of HBS mechanical behavior and it also assisted to interpret the behavior of this type of sediment under different loading and hydrate conditions.
DOE NETL), the Japan Oil, Gas, and Metals National Corporation (JOGMEC), and the U.S. Geological Survey (USGS) successfully drilled and logged the Hydrate-01 Stratigraphic Test Well (STW) in the greater Prudhoe Bay oil field on the Alaska North Slope. The logging-while-drilling (LWD) data confirmed the presence of gas hydrate-bearing reservoirs within sand reservoirs in Units D and B that are suitable targets for future testing. The deeper "B1-sand" is considered to be the most favorable for reservoir response testing due the following factors: confirmed high gas hydrate saturation in sediments of high intrinsic permeability; isolated from direct communication with saline aquifers; and located in the proximity of the base of gas hydrate stability, thus allowing efficient gas hydrate decomposition by the depressurization method. The interpreted log data and side-wall core sample measurements were used to create reservoir models for the Prudhoe Bay Unit (PBU) Kuparuk 7-11-12 site. The vertical heterogeneity in porosity, gas hydrate saturation, irreducible water saturation, and permeability distributions for reservoir and nonreservoir units was implemented using fine mesh discretization. To induce gas hydrate destabilization, the depressurization of the B1 sand was carried out using scenarios with constant bottom hole pressure (BHP) and staged multistep decrease of BHP values. Three simulators, MH21-HYDRES, TOUGH+Hydrate, and CMG STARS were engaged to conduct various sensitivity cases to determine the impact of the lateral extension of the reservoir models, uncertainty in in situ reservoir permeability, and water influxes from seal on productivity. Water and gas production rates and volumes predicted using three simulators reveal overall agreement. At the most probable case, gas and water production rates of up to 2.6 MMSCF/day and 8000 fluid bbl/day, respectively, should be accounted for well test designs, surface facility requirements, and field test activities. The full consideration of the multiple cases and scenarios indicates significant uncertainty in simulation results due to uncertainties in key reservoir properties. This underscores the need for acquisition of extended duration production field test data as a means to clarify true reservoir potential.
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