Description: Highlights • PetroMod is the 1st basin modelling software including methane hydrate simulation. • The Gas hydrate module includes physical, thermodynamic, and kinetic properties. • PetroMod simulates the evolution over time of the GHSZ. • PetroMod includes a kinetic for the organic matter degradation at low temperature. Abstract Within the German gas hydrate initiative SUGAR, a new 2-D/3-D module simulating the biogenic generation of methane from organic matter and the formation of gas hydrates has been developed and included in the petroleum systems modelling software package PetroMod®. Typically, PetroMod® simulates the thermogenic generation of multiple hydrocarbon components (oil and gas), their migration through geological strata, finally predicting oil and gas accumulations in suitable reservoir formations. We have extended PetroMod® to simulate gas hydrate accumulations in marine and permafrost environments by the implementation of algorithms describing (1) the physical, thermodynamic, and kinetic properties of gas hydrates; and (2) a kinetic continuum model for the microbially mediated, low temperature degradation of particulate organic carbon in sediments. Additionally, the temporal and spatial resolutions of PetroMod® were increased in order to simulate processes on time scales of hundreds of years and within decimetres of spatial extension. In order to validate the abilities of the new hydrate module, we present here results of a theoretical layer-cake model. The simulation runs predict the spatial distribution and evolution in time of the gas hydrate stability field, the generation and migration of thermogenic and biogenic methane gas, and its accumulation as gas hydrates.

Description: We have performed 2D and 3D gas hydrate (GH) petroleum systems modeling for the Pleistocene turbiditic sedimentary sequences distributed in the Daini-Atsumi area in the eastern Nankai Trough to understand the accumulation mechanisms and their spatial distribution related to geologic and geochemical processes. High-resolution seismic facies analysis and interpretations were used to define facies distributions in the models. We have created a new biogenic methane generation model based on the biomarker analysis using core samples and incorporated it into our model. Our 2D models were built and simulated to confirm the parameters to be used for 3D modeling. Global sea level changes and paleogeometry estimated from 3D structural restoration results were taken into account to determine the paleowater depth of the deposited sedimentary sequences. Pressure and temperature distributions were modeled because they are the basic factors that control the GH stability zone. Our 2D modeling results suggested that the setting of biogenic methane generation depth is one of the most important controlling factors for GH accumulation in the Nankai Trough, which may be related to the timing of methane upward migration (expulsion) and methane solution process in pore water. Our 3D modeling results suggested that the distribution of sandy sediments and the formation dip direction are important controlling factors in the accumulation of GHs. We also found that the simulated amount of GH accumulation from the petroleum systems modeling compares well with independent estimations using 3D seismic and well data. This suggests that the model constructed in this study is valid for this GH system evaluation and that this type of evaluation can be useful as a supplemental approach to resource assessment.

Description: The Alaska North Slope comprises an area of about 400,000 km2 including prominent gas and oil fields. Gas hydrates occur widely at the Alaska North Slope. A recent assessment by the USGS estimates 0.7-4.47 x 1012 m3 of technically recoverable gas hydrates based on well data and drilled hydrate accumulations. In spring 2012 a production field trial, testing CO2/N2 injection and depressurization, was conducted by USDOE/JOGMEC/ConocoPhillips at the Ignik Sikumi site. The 3D geological model of the Alaska North Slope developed by the USGS and Schlumberger is used to test the new gas hydrate module in the petroleum systems modeling software PetroMod®. Model results of the present extent of the gas hydrate stability zone (GHSZ) are in good agreement with results from well data. The model simulations reveal that the evolution of the GHSZ over time is primarily controlled by the climatic conditions regulating the extent of the permafrost during the last 1 Myr. Preliminary model runs predict the highest gas hydrate saturations near the major faults and at the bottom of the GHSZ, where thermogenic methane gas accumulates after migration through the most permeable stratigraphic layers (e.g. Sag River Sandstone Fm, Ivishak Fm). Gas hydrate saturations predicted for the Mount Elbert Stratigraphic Test Well and the Ignik Sikumi sites are basically controlled by the alternation of layers with different permeability and the fault properties (time of opening, permeability, etc). Further results including a total gas hydrate assessment for the Alaska North Slope will be presented during the conference.