Numerical Simulations of Depressurization-Induced Gas Hydrate Reservoir (B1 Sand) Response at the Prudhoe Bay Unit Kuparuk 7-11-12 Pad on the Alaska North Slope

In December 2018, a partnership between the U.S. Department of Energy National Energy Technology Laboratory (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.