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Accurate reservoir evaluation requires reliable three-dimensional (3-D) geological models. This study conducted 3-D geological modeling for numerical flow simulation of the B1 sand gas hydrate reservoir at the Kuparuk State 7-11-12 pad, Prudhoe Bay Unit, Alaska North Slope. The model integrates well logs, core, and seismic data to address spatial heterogeneity in geological structures and reservoir properties. Two modeling types were performed: structural framework modeling and petrophysical property modeling. For structural framework modeling, seismic data and well log markers were used to reproduce subsurface structures characterized by a normal fault system. A volume-based modeling algorithm and stair-step gridding were applied. The resulting 3-D model comprised 2,640,000 grid cells across 264 layers, including seven fault grids. For petrophysical property modeling, total porosity was initially modeled using sequential Gaussian simulation with collocated cokriging. To reproduce the upward coarsening of the B1 sand, upscaled log-derived total porosity and a 3-D trend depicting total porosity variation were used as primary and secondary data, respectively. Gas hydrate saturation distribution was modeled similarly, with secondary data from estimated porosity distribution and seismic-derived acoustic impedance map enhancing accuracy. Results indicate higher gas hydrate saturation in the upper part of the B1 sand and areas with higher acoustic impedance. Intrinsic permeability was modeled from the total porosity and clay-bound water volume, and effective permeability was derived from the gas hydrate saturation and intrinsic permeability distributions based on the “Tokyo model”. Effective permeability distributions were influenced by the total porosity, gas hydrate saturation, and intrinsic permeability. Within the same layer, higher gas hydrate saturation leads to decreased effective permeability. In total, 100 sets of multiple scenarios were prepared, providing input data for dynamic flow simulations to evaluate the effects of lateral heterogeneity in reservoir properties and the hydraulic characteristics of faults on production behavior for preassessment before the long-term production test.

Comprehensive data sets were obtained during the gas production tests from a gas-hydrate reservoir in Eastern Nankai Trough (2013 and 2017), including the gas and water production rates, downhole pressure, temperature-monitoring data, log- and core-derived reservoir property information, and seismic volume. Numerical simulations using a compositional and thermal-coupling numerical model (MH21-HYDRES) had been conducted earlier and after each production test for production behavior prediction purposes and history-matching to reevaluate the reservoir property information. The actual production behavior demonstrated some deviations from the prediction by the numerical model. For example, the model predicted a gradual increase in the gas production rates under the constant pressure drawdown but real gas rates were almost constant or slightly decreasing, some inconsistencies in the temperature data and derived vertical and temporal production profiles were observed, and differences in the production behavior exist among the wells that were drilled within a 60 m radius area. To reduce the gap between the model and actual results, understand the nature of the gas-hydrate reservoir, and understand the physical processes during the gas-hydrate dissociation, comparison of the modeling results and obtained data was repeated, along with reexamination of the geological and geophysical data. The study results revealed two features, namely, vertical and horizontal heterogeneities of the formation and complexly disturbed situation in the near-wellbore region due to the unconsolidated nature of the sediments, which were determined as the main causes for the discrepancy in the model and actual production behavior.

The Iġnik Sikumi Gas Hydrate Exchange Field Experiment was conducted by ConocoPhillips in partnership with the U.S. Department of Energy, the Japan Oil, Gas and Metals National Corporation, and the U.S. Geological Survey within the Prudhoe Bay Unit on the Alaska North Slope during 2011 and 2012. The primary goals of the program were to (1) determine the feasibility of gas injection into hydrate-bearing sand reservoirs and (2) observe reservoir response upon subsequent flowback in order to assess the potential for CO2exchange for CH4in naturally occurring gas hydrate reservoirs. Initial modeling determined that no feasible means of injection of pure CO2was likely, given the presence of free water in the reservoir. Laboratory and numerical modeling studies indicated that the injection of a mixture of CO2and N2offered the best potential for gas injection and exchange. The test featured the following primary operational phases: (1) injection of a gaseous phase mixture of CO2, N2, and chemical tracers; (2) flowback conducted at downhole pressures above the stability threshold for native CH4hydrate; and (3) an extended (30-days) flowback at pressures near, and then below, the stability threshold of native CH4hydrate. The test findings indicate that the formation of a range of mixed-gas hydrates resulted in a net exchange of CO2for CH4in the reservoir, although the complexity of the subsurface environment renders the nature, extent, and efficiency of the exchange reaction uncertain. The next steps in the evaluation of exchange technology should feature multiple well applications; however, such field test programs will require extensive preparatory experimental and numerical modeling studies and will likely be a secondary priority to further field testing of production through depressurization. Additional insights gained from the field program include the following: (1) gas hydrate destabilization is self-limiting, dispelling any notion of the potential for uncontrolled destabilization; (2) gas hydrate test wells must be carefully designed to enable rapid remediation of wellbore blockages that will occur during any cessation in operations; (3) sand production during hydrate production likely can be managed through standard engineering controls; and (4) reservoir heat exchange during depressurization was more favorable than expectedmitigating concerns for near-wellbore freezing and enabling consideration of more aggressive pressure reduction.