Simulating Japan’s Second Offshore Natural Gas Hydrate Field Production Test: Insights on Near-Well Permeability Evolution

The 2017 field production test in the Eastern Nankai Trough (offshore Japan) achieved a gas production rate of 10,000 m3/day over a 20 day period, providing valuable fluid production data that warrant detailed investigation. In this study, we investigate by inverse numerical simulation (history-matching) the results of the 20 day field test at the AT1-P2 well in the Nankai Trough using TOUGH + Hydrate v1.5. The cumulative gas and water production estimated from the short-term simulation is 2.10 × 105 and 6.30 × 103 m3 with an average absolute relative deviation of 6.5% and 6.7%, respectively. Our findings suggest that the near-well permeability of natural gas hydrate (NGH) deposits exhibits a strong correlation with the depressurization scheme and has a significant impact on short-term fluid production. We further assessed the year-long fluid production performance for bottom hole pressure at 8.0 MPa for the AT1-P2 well. Simulation results show that the cumulative gas production rate increases by 63.8% to 1.72 × 104 m3/day for one-year production from its initial 20 day 1.05 × 104 m3/day, with the sand-silt alternation layers contributing to ∼81% of the cumulative gas produced. The evolution of phase saturations suggests the hydrate dissociation front expands to ∼100 m in the sand/silt alternation layer over a one-year period. We also conducted a sensitivity analysis of the effect of different depressurization schemes for short-term fluid production. The results indicate that decreasing the bottom-hole pressure has a strongly positive effect on fluid production, but the pressure drawdown rates show an insignificant impact. Insights gained from this study provide valuable guidance for understanding the role of near-well permeability and its temporal evolution on production as well as the optimization of the production strategy for future NGH field tests.