Fracture-controlled gas hydrate systems in the northern Gulf of Mexico

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Abstract

High-angle, open mode fractures control the presence of natural gas hydrate in water-saturated clays at the Keathley Canyon 151 site in the northern Gulf of Mexico, which was investigated for gas hydrates as part of the Chevron Joint Industry Project drilling in 2005. We analyze logging-while-drilling resistivity images and infer that gas hydrate accumulated in situ in two modes: filling fractures and saturating permeable beds. High-angle hydrate-filled fractures are the most common mode for gas hydrate occurrence at this site, with most of these fractures dipping at angles of more than 40° and occurring between 220 and 300 m below seafloor. These fractures all strike approximately N–S, which agrees with the 165°SE–345°NW maximum horizontal stress direction determined from borehole breakouts and which aligns with local bathymetric contours. In one interval of hydrate-filled fractures, porosity increases with increasing hydrate saturation. We suggest that high pore pressure may have dilated sediments during fracture formation, causing this increase in porosity. Furthermore, the formation of gas hydrate may have heaved fractures apart, also increasing the formation porosity in this interval.

Introduction

Specific low temperature and elevated pressure conditions dictate the stability of natural gas hydrate. Gas hydrate forms from a combination of water and natural gas, and can be found in the marine sediment along many continental margins (Kvenvolden and Barnard, 1982). On seismic sections the base of the gas hydrate stability zone (GHSZ) may be indicated by a strong negative polarity reflector known as a bottom-simulating reflector or BSR (Markl et al., 1970). The distribution of gas hydrate within the GHSZ is highly variable and depends on sediment type, gas flow, and tectonic regime.

Recently, several studies have suggested that natural gas may migrate through the GHSZ along faults, fractures, and/or other high permeability conduits (Hornbach et al., 2004, Nimblett and Ruppel, 2003, Tréhu et al., 2004). Several authors have proposed that hydrate-filled fractures may either be the primary locus of hydrate accumulation in marine sediment or hydrate-filled relics of the conduits that fed natural gas into what are now laterally extensive hydrate-bearing beds (Kleinberg, 2008, Milkov and Sassen, 2001, Nimblett and Ruppel, 2003, Sassen et al., 2001, Sassen et al., 1999). Weinberger and Brown (2006) found complicated fracture networks to be the primary method of fluid flow for natural gas and an important mode of gas hydrate accumulation at Hydrate Ridge, offshore Oregon. These hydro-fracture networks were found to be oriented parallel to the maximum horizontal stress direction (SHmax) determined from borehole breakouts in logging-while-drilling (LWD) images (Goldberg and Janik, 2006).

In this paper, we infer the distribution and location of gas hydrate using LWD resistivity images from Hole KC151-2 drilled in the Keathley Canyon area of the northern Gulf of Mexico and analyze the associated stress field. The results are used to describe in greater detail the open mode fracture system that was found to control gas hydrate occurrences in this area (Claypool, 2006).

Section snippets

Geologic setting

In 2005, the Chevron Joint Industry Project (JIP), cosponsored by the U.S. Department of Energy (DOE), drilled two holes at Site KC151 in Keathley Canyon in the northern Gulf of Mexico (Fig. 1). Hole KC151-2 (26.8229°N, 92.9864°W) was drilled and logged using LWD tools. Hole KC151-3, located ∼10 m from KC151-2, was cored and wireline logged. For the purposes of this paper, Hole KC151-2 will be referred to as Hole 2 and Hole KC151-3 will be referred to as Hole 3.

The Gulf of Mexico is a passive

Hole 2

Hole 2 was drilled to 459 mbsf using LWD tools that collect conventional well log data as well as borehole image data. Fig. 3 displays the caliper, gamma ray, ring resistivity, and density logs acquired in Hole 2. The caliper measures the diameter of the borehole. From 0 to 115 mbsf, the hole is enlarged by ∼2.5 to 7.5 cm from the standard 21.5-cm diameter, resulting in lower data quality in this interval. The most extreme enlargements occurred from 100 to 115 mbsf, which correlates to a sandy clay

Resistivity images from Hole 2

The geoVISION™ tool (GVR6) is an LWD tool that records continuous 360° oriented measurements of the downhole resistivity while drilling. These measurements produce images of the near-wellbore environment. Shallow, medium and deep button electrodes lie longitudinally along the surface of the tool and measure nominally 2.5, 7.65 and 12.7 cm deep into the formation, respectively. All buttons have a vertical resolution between 5 and 7.5 cm. The GVR6 performs best in 21.5-cm diameter hole. The

Fractures

All fractures in Hole 2 dip easterly or westerly, and thus all strike in the N–S direction. Fracture aperture is not accurately represented on resistivity images; fractures in this hole are likely on the order of a millimeter or smaller in aperture. A dip plot (Fig. 5) displays the dip and strike of each fracture identified on the borehole images from 180 to 310 mbsf.

We infer that hydrate-filled fractures dominate the fracture system. A few hydrate-filled fractures occur within the sandy clay

Local stress regime

The local topography near Site KC151 is shown in Fig. 9. At Site KC151, SHmax is oriented parallel to the axis of the ridge. The borehole breakouts, which reflect SHmin, are oriented normal to the ridge. This local stress regime occurs because the ridge is a structurally strong feature and well supported in the SHmax direction, but unsupported in the SHmin direction, leading to spalling and mass wasting of sediments downslope. Yassir and Zerwer (1997) used borehole breakouts to study the stress

Conclusions

Evaluation of hydrate distribution from the borehole resistivity images in Keathley Canyon KC151-2 indicates that the fracture system controls hydrate distribution. We infer that: (1) hydrate forms primarily within the fractures and not in beds; (2) natural gas may prefer to move along the relatively more permeable fracture system rather than through the surrounding sediment; (3) the fracture system is a result of the local stress regime; and (4) gas dilation and hydrate-forced heave may cause

Acknowledgements

We thank C. Broglia and T. Williams for their help with GeoFrame™ (Mark of Schlumberger) processing of the well log data, and A. Malinverno for collaborating on hydrate saturation estimates using numerical methods. We also thank the creators of the mapping and analysis programs, Geomapapp and Stereonet for Macintosh, both used in this research, available at www.geomapapp.org and http://www.geo.cornell.edu/geology/faculty/RWA/.

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