Search

In marine continental margins, high saturations of natural gas hydrate are observed within the gas hydrate stability zone, but the gas migration pathways to the hydrate reservoir are not often clear. We focus on a site in Green Canyon Block 955 (GC 955) in the Gulf of Mexico, where gas hydrate occurs in a 35 m-thick reservoir with saturations of 79-93% in numerous centimeter- to decimeter-thick sandy silt layers and little to no gas hydrate in the interbedded cm to decimeter-thick clayey silt layers. Different datasets (well logging, coring, and seismic data) suggest different types of potential methane migration mechanisms. For example, relatively high particulate organic carbon content in the reservoir and the microbial methane source indicated by gas chromatography and methane isotopes suggest gas might be made locally and migration could occur through dissolved methane sources or water advection. In contrast, the visible deeply rooted faults intersecting the gas hydrate reservoir and the gas pockets adjacent to the faults on seismic data suggest that free gas may migrate directly into the reservoir. We tested three different mechanisms to form gas hydrate at GC 955: short-range methane diffusion, short-range methane diffusion coupled with upward water advection, and free gas flow. The 1-D and 2-D numerical models show that both the short-range migration and the upward water advection are not enough to form high saturations gas hydrate at GC 955, and that free gas flow is required to form the high saturations of gas hydrate observed at GC 955.

This study developed a one-dimensional numerical model of sedimentation and compaction based on the equivalent isochrone framework to investigate the impact of creep on geopressure during burial. In this framework, the void ratio is a function of effective stress and strain rate; the change in void ratio is the same with each order of magnitude decrease in strain rate at a constant effective stress. We simulated lower void ratio and higher overpressure when creep was included compared to cases where no creep was present and void ratio is only a function of effective stress. Creep causes apparent overconsolidation. The apparent overconsolidation ratio is used to quantify the magnitude of creep; this is the vertical distance from the normal compression curve in a void ratio v. effective stress plot. The magnitude of creep depends on the loading rate, and increases with depth at sites with low sedimentation rates. These findings bridge the gap between laboratory and field observations on rock compression behaviours. For example, it provides one explanation why laboratory-derived compression curves have a higher void ratio at a given effective stress. In addition, it suggests under what conditions the rock will behave elastically. Thematic collection: This article is part of the Geopressure collection available at: https://www.lyellcollection.org/cc/geopressure

The University of Texas Hydrate Pressure Coring Expedition (UT-GOM2-1) recovered cores at near in situ formation pressures from a gas hydrate reservoir composed of sandy silt and clayey silt beds in Green Canyon Block 955 in the deep-water Gulf of Mexico. The expedition results are synthesized and linked to other detailed analyses presented in this volume. Millimeter- to meter-scale beds of sandy silt and clayey silt are interbedded on the levee of a turbidite channel. The hydrate saturation (the volume fraction of the pore space occupied by hydrate) in the sandy silts ranges from 79% to 93%, and there is little to no hydrate in the clayey silt. Gas from the hydrates is composed of nearly pure methane (99.99%) with less than 400 ppm of ethane or heavier hydrocarbons. The δ13C values from the methane are depleted (−60‰ to −65‰ Vienna Peedee belemnite), and it is interpreted that the gases were largely generated by primary microbial methanogenesis but that low concentrations of propane or heavier hydrocarbons record at least trace thermogenic components. The in situ pore-water salinity is very close to that of seawater. This suggests that the excess salinity generated during hydrate formation diffused away because the hydrate formed slowly or because it formed long ago. Because the sandy silt deposits have high hydrate concentration and high intrinsic permeability, they may represent a class of reservoir that can be economically developed. Results from this expedition will inform a new generation of reservoir simulation models that will illuminate how these reservoirs might be best produced.

We explore the petrophysical behavior of the two interbedded lithofacies (sandy silt and clayey silt) that constitute the Green Canyon Block 955 hydrate reservoir in the deep-water Gulf of Mexico by performing experiments on reconstituted samples of the reservoir material. Sandy silts reconstituted to the in situ porosity have a permeability of 11.8 md (1.18 × 10−14 m2), which is similar to the intrinsic permeabilities measured in intact cores from hydrate reservoirs of similar grain size offshore Japan (Nankai Trough) and offshore India. Reconstituted clayey silts have a much lower intrinsic permeability of 3.84 × 10−4 md (3.84 × 10−19 m2) at the in situ stress. The reconstituted sandy silt is less compressible than the clayey silt. Mercury injection capillary pressure measurements demonstrate that the largest pores with the clayey silt are still smaller than the pores remaining after 90% hydrate saturation in sandy silt. We interpret that the methane solubility in pores of clayey silt is always less than that necessary to form hydrate, which explains why no hydrate is present in the clayey silt. We upscale the reservoir properties to estimate the behavior of interbedded sandy silt and clayey silt. We find the upscaled intrinsic horizontal and vertical permeabilities for the entire reservoir interval are 8.6 md (8.6 × 10−15 m2) and 1.4 × 10−3 md (1.4 × 10−18 m2). We estimate that during reservoir production, a maximum vertical strain of approximately 12% will result. Ultimately, this study will inform reservoir simulation models with petrophysical properties at scales of both individual lithofacies and reservoir formation.

Author(s): Meyer, DW; Flemings, PB; DiCarlo, D; You, K; Phillips, SC; Kneafsey, TJ | Abstract: We form methane hydrate by injecting methane gas into a brine-saturated, coarse-grained sample under hydrate-stable thermodynamic conditions. Hydrate forms to a saturation of 11%, which is much lower than that predicted assuming three-phase (gas-hydrate-brine) thermodynamic equilibrium (67%). During hydrate formation, there are temporary flow blockages. We interpret that a hydrate skin forms a physical barrier at the gas-brine interface. The skin fails periodically when the pressure differential exceeds the skin strength. Once the skin is present, further hydrate formation is limited by the rate that methane can diffuse through the solid skin. This process produces distinct thermodynamic states on either side of the skin that allows gas to flow through the sample. This study illuminates how gas can be transported through the hydrate stability zone and thus provides a mechanism for the formation of concentrated hydrate deposits in sand reservoirs. It also illustrates that models that assume local equilibrium at the core-scale and larger may not capture the fundamental behaviors of these gas flow and hydrate formation processes.

We develop a one-dimensional analytical solution based on the method of characteristics to explore hydrate formation from gas injection into brine-saturated sediments within the hydrate stability zone. Our solution includes fully-coupled multiphase and multicomponent flow and the associated advective transport in a homogeneous system. Our solution shows that hydrate saturation is controlled by the initial thermodynamic state of the system, and changed by the gas fractional flow. Hydrate saturation in gas-rich systems can be estimated by 1−cl0clewhen Darcy flow dominates, where cl0 is the initial mass fraction of salt in brine, and cle is the mass fraction of salt in brine at three-phase (gas, liquid, and hydrate) equilibrium. Hydrate saturation is constant, gas saturation and gas flux decrease, and liquid saturation and liquid flux increase with the distance from the gas inlet to the hydrate solidification front. The total gas and liquid flux is constant from the gas inlet to the hydrate solidification front, and decreases abruptly at the hydrate solidification front due to gas inclusion into the hydrate phase. The advancing velocity of the hydrate solidification front decreases with hydrate saturation at a fixed gas inflow rate. This analytical solution illuminates how hydrate is formed by gas injection (methane, CO2, ethane, propane) at both the laboratory and field scales.

Methane hydrate formation and dissociation are buffered by salinity in a closed system. During hydrate formation, salt excluded from hydrate increases salinity, drives the system to three-phase (gas, water, and hydrate phases) equilibrium, and limits further hydrate formation and dissociation. We developed a zero-dimensional local thermodynamic equilibrium-based model to explain this concept. We demonstrated this concept by forming and melting methane hydrate from a partially brine-saturated sand sample in a controlled laboratory experiment by holding pressure constant (6.94 MPa) and changing temperature stepwise. The modeled methane gas consumptions and hydrate saturations agreed well with the experimental measurements after hydrate nucleation. Hydrate dissociation occurred synchronously with temperature increase. The exception to this behavior is that substantial subcooling (6.4°C in this study) was observed for hydrate nucleation. X-ray computed tomography scanning images showed that core-scale hydrate distribution was heterogeneous. This implied core-scale water and salt transport induced by hydrate formation. Bulk resistivity increased sharply with initial hydrate formation and then decreased as the hydrate ripened. This study reproduced the salinity-buffered hydrate behavior interpreted for natural gas-rich hydrate systems by allowing methane gas to freely enter/leave the sample in response to volume changes associated with hydrate formation and dissociation. It provides insights into observations made at the core scale and log scale of salinity elevation to three-phase equilibrium in natural hydrate systems.