Fluid flow in the Keathley Canyon 151 Mini-Basin, northern Gulf of Mexico

Marine and Petroleum Geology 25 (2008) 919–923

Contents lists available at ScienceDirect

Marine and Petroleum Geology journal homepage: www.elsevier.com/locate/marpetgeo

Fluid flow in the Keathley Canyon 151 Mini-Basin, northern Gulf of Mexico Brandon Dugan Department of Earth Science, Rice University, 6100 Main Street, MS-126, Houston, TX 77005, USA

a r t i c l e i n f o

a b s t r a c t

Article history: Received 18 April 2007 Received in revised form 25 July 2007 Accepted 22 December 2007

Laboratory experiments and drilling observations are used to estimate vertically upward fluid flow rates of approximately 4 mm/yr in Keathley Canyon, northern Gulf of Mexico. Based on uncertainty in pressure and permeability models, flow rates exceed 1.3 mm/yr but are less than 28 mm/yr. Consolidation experiments document that permeability decreases from 1015 m2 at the seafloor to 1018 m2 at 300 m below seafloor. I use these experimental data with logging-while-drilling data to constrain a permeability function for the basin. Sediment discharge from an open borehole filled with weighted mud is used to estimate a minimum overpressure gradient of 4.3 kPa m1 in the Keathley Canyon mini-basin. The overpressure gradient and permeability model are input into Darcy’s law to estimate an average flow rate for the basin. These flow rates are consistent with estimates of compaction-driven flow from existing regional-scale models of flow in the northern Gulf of Mexico. Hydrate stability calculations for the basin predict a 25 m deepening of the base of hydrate stability due to overpressure. Ó 2008 Elsevier Ltd. All rights reserved.

Keywords: Permeability Fluid Flow Overpressure Gulf of Mexico Keathley Canyon Ocean drilling

1. Introduction Fluid fluxes provide important controls on heat and chemical transport and sediment deformation in continental margins. Fluid migration influences mineral dissolution and precipitation, basin subsidence, seafloor seepage, and the distribution of hydrocarbons in sedimentary basins (e.g., Bethke et al., 1988; Parnell, 2002; Toth, 1996). Migration of free gas, gas composition, dissolved solutes, and heat transport is often evaluated in gas hydrate settings because they affect gas hydrate stability (Ruppel et al., 2005; Sloan, 1998; Wood et al., 2002). Wood et al. (2002) describe localized shoaling of the base of hydrate stability along the Cascadia margin. They infer that the shoaling results from free gas migration into the regional hydrate stability zone and use models to constrain the vertically upward heat flux required to create the shoaling (Wood et al., 2002). In the Gulf of Mexico, variations in porewater salinity and heat flow near seafloor mounds are used to understand how focused fluid flow, chemical transport, and mud expulsion influence the local stability of gas hydrate (Ruppel et al., 2005). These two studies, as well as numerical modeling studies (Wilson and Ruppel, 2007), suggest net upward migration of fluids, however, direct measurements are not available. At the seafloor, Tryon and Brown (2004) use aqueous flux meters to make direct measurements of vertical fluid flow from 0.01 to 15 mm/day in the region near the Bush Hill hydrate mound in the northern Gulf of Mexico.

E-mail address: [email protected] 0264-8172/$ – see front matter Ó 2008 Elsevier Ltd. All rights reserved. doi:10.1016/j.marpetgeo.2007.12.005

With respect to hydrate deposits, these studies show that flow magnitude and fluid composition are critical to understanding hydrate stability, and that fluxes can change on temporal and spatial scales. Often, however, the regional distribution of hydrate is modeled from the average pressure, temperature, composition of fluids and gas, and supply of gas (Bhatnagar et al., 2007; Sloan, 1998; Xu and Ruppel, 1999). Building on the importance of fluid flow in basin systems, I present estimates of vertical flow in sediments of Keathley Canyon (KC), northern Gulf of Mexico. These estimates represent average flow rates through hundreds of meters of fine-grained sediment. Consolidation experiments are used to develop a void ratio-permeability model for sediments in the mini-basin. Logging-whiledrilling data document the downhole lithology and void ratio for input into the permeability model. In situ overpressure is estimated from drilling observations made by a remote-operated vehicle (ROV) and from density data from an open, flowing borehole. Pressure data coupled with permeability data are used to model average fluid flow rates.

2. Keathley Canyon basin Keathley Canyon Lease Block 151 is located on the continental slope of the northern Gulf of Mexico (Fig. 1). This is a region characterized by deposition within ponded mini-basins. High gamma ray values measured with logging-while-drilling (LWD) tools suggest that the mini-basin is dominated by silt- and clay-sized sediments with the exception of one sand-prone interval from 95 to 110 mbsf (meters below seafloor) identified at borehole KC 151 #2

920

B. Dugan / Marine and Petroleum Geology 25 (2008) 919–923

31˚N

30˚

29˚

Louisiana

Texas

0

km

FL

500m m 0 100 0m 200

KC

300

0m

26˚ 95˚W

AL

100

28˚

27˚

MS

93˚

89˚

91˚

87˚

Fig. 1. Basemap locating the Keathley Canyon (KC) study region in the northern Gulf of Mexico. Contours are water depth [m].

(Claypool, 2006). Shore-based grain size analyses confirm that finegrained sediments dominate the sedimentary column (Winters et al., 2008). Typical of mini-basin systems, sediments within the mini-basin thin toward the basin flanks and thicken toward the basin center. Hutchinson et al. (2008) describe the stratigraphic and geologic evolution of the basin with the use of high resolution multi-channel seismic data. Interpretations of the seismic data suggest that the processes controlling deposition have changed as the basin evolved, however, log and core data suggest grain size has remained fine-grained regardless of depositional conditions or process.

4. Geomechanical experiments Constant-rate-of-strain consolidation (CRSC) experiments (ASTM International, 2006) were completed on core specimens from KC 151 #3 at room temperature (20  C). These experiments documented the bulk physical properties of water-saturated sediments during elastic and elasto-plastic deformation. Each vertically-oriented specimen was removed from the core liner and trimmed directly into a fixed-ring consolidation cell. This process minimized sample disturbance from desiccation and preparation. The specimen, confined in the cell, was placed in the consolidation chamber with filter paper and porous stones on the top and bottom. The consolidation chamber was filled with distilled water and a back pressure of 0.59 MPa was applied to ensure saturation. Backpressure saturation continued for at least 8 h while maintaining the height of the specimen. At the onset of consolidation, the base pressure was isolated from the controlled pore pressure. Strain rate during consolidation ranged from 0.5% to0.7%/h. During consolidation, base pressure was passively recorded while pore pressure was maintained at 0.59 MPa. The total stress required to maintain the prescribed strain rate was recorded. Standard reduction of the consolidation data provided stress– strain curves for each specimen. I processed the stress–strain data to define, the elasto-plastic behavior the sediment (compression index, Cc) and the elastic behavior of the sediment (swell index, Cs) (Lambe and Whitman, 1969). Cc was determined during primary consolidation at stresses exceeding in situ vertical effective stress for each specimen. Cs was evaluated from data collected during unloading cycles. Compression indices ranged from 0.15 to 0.61 with an average of 0.26 (Table 1). Swell indices averaged 15% of the compression indices (Table 1).

3. Drilling and sampling

5. Permeability model

Two adjacent boreholes (KC 151 #2 and KC 151 #3) were drilled in the mini-basin in 1320 m water depth. KC 151 #2 was dedicated to LWD activities and was drilled to 494 mbsf. KC 151 #3 was used for coring and reached a total depth of 474 mbsf. Claypool (2006) described the drilling, logging, and coring operations and objectives for these sites. Spot coring at KC 151 #3 provided samples for ship-based and shore-based geochemical (e.g., Kastner et al., 2008) and geomechanical analyses (e.g., Yun et al., 2006a,b). Porewater for geochemical analyses was extracted from cores immediately after recovery. The remaining sections of standard, non-pressure cores were logged on a multi-sensor core logger to measure bulk physical properties (Claypool, 2006). I selected core samples for this study based on the multi-sensor core logger data. Sampling was limited to core intervals that were devoid of expansion cracks and gas voids. Whole-round samples selected for shore-based geomechanical tests were sealed with end-caps to preserve natural saturation. Samples were stored in refrigerated storage at 4  C until geomechanical tests were performed.

CRSC experiments also provided data to evaluate flow properties for Keathley Canyon sediments. Hydraulic conductivity (K [m/s]) was calculated based on the strain rate and base excess pressure (ASTM International, 2006):

K ¼

e_ HHo gw : 2Du

(1)

In Eq. (1), e_ is the strain rate [1/s], Ho is the initial specimen height [m], H is the instantaneous specimen height [m], Du is the base excess pressure [Pa], and gw is the unit weight of water [Pa/m]. Hydraulic conductivity-void ratio (K–e) data during primary consolidation were isolated to define a K function for each specimen (Fig. 2). The K function for each specimen was used to estimate hydraulic conductivity at in situ void ratio (Table 1). This approach assumed a log-linear relationship between hydraulic conductivity and void ratio (Lambe and Whitman, 1969) and that the initial specimen void ratio from the CRSC experiment equaled the in situ void ratio. The void ratio assumption was based on moisture-anddensity-based bulk density measurements being nearly identical to

Table 1 In situ void ratio (ei), compression index (Cc), swelling index (Cs), hydraulic conductivity (K), and permeability (k) of specimens from Keathley Canyon Boring KC151#3 KC151#3 KC151#3 KC151#3 KC151#3 KC151#3 KC151#3 KC151#3

Core-section 1H-5 2H-8 3H-5 4H-3 10C-3 14C-1 19H-5 20H-5

mbsf 5.05 17.27 22.61 31.19 226.53 243.13 280.01 298.31

ei 2.73 1.49 1.49 1.30 0.81 0.84 1.04 1.05

Cc 0.61 0.26 0.23 0.20 0.18 0.15 0.26 0.24

Cs 0.065 0.038 0.041 0.035 0.025 0.024 0.042 0.060

k (m2)

K (m/s) 8

1.06  10 8.99  1010 9.14  109 1.42  109 3.19  1010 4.79  1010 7.98  1011 4.35  1010

1.05  1015 8.95  1017 9.10  1016 1.41  1016 3.18  1017 4.76  1017 7.94  1018 4.33  1017

B. Dugan / Marine and Petroleum Geology 25 (2008) 919–923

-14

1.4

log(permeability [m2])

1.35

Void Ratio

921

1.3

1.25

-15

-16

-17 1.2 -9.45

-9.4

-9.35

-9.3

0.5

-9.25

1.0

1.5

2.0

2.5

3.0

Void Ratio

log(hydraulic conductivity [m/s]) Fig. 2. Hydraulic conductivity-void ratio (K–e) data during primary consolidation for a specimen from KC 151 #3. Specimen was from 17.27 mbsf and had an initial void ratio of 1.49. A regression of the e–log(k) data yields an estimate of in situ permeability of 8.95  1017 m2 at e ¼ 1.49 (Table 1).

Fig. 3. Permeability-void ratio data for KC 151 #3. Solid circles are the estimated in situ permeability based on the in situ void ratio of the specimen (Table 1). Solid black line is the best-fit, linear regression of the log(k)-void ratio data. Grey-shaded area is the 68% confidence interval (one standard deviation).

bulk density measured by logging-while-drilling tools (Winters et al., 2008). Initial specimen void ratio was determined from mass and density measurements (e.g., Blum, 1997). In situ hydraulic conductivity was transformed to in situ permeability (k [m2]) using:

300 mbsf, void ratio decreases slowly and estimated permeability approaches 1017 m2. I calculated the equivalent vertical permeability (keq) of the sedimentary section at KC 151 #3 from the downhole permeability profile (Fig. 4). For flow perpendicular to bedding, such as vertical flow at Keathley Canyon, keq is controlled by low permeability sediments and is defined by the harmonic mean of the permeabilitydepth profile (Freeze and Cherry, 1979):

Km ; rw g

(2)

where rw is the density of seawater [kg/m3], g is the acceleration due to gravity [m/s2], and m denotes the dynamic viscosity [Pa s]. Average seawater density (1024 kg/m3) and constant dynamic viscosity (0.001 Pa s) are assumed. I used the in situ void ratio and permeability data to define a permeability function for the fine-grained sediments in the Keathley Canyon mini-basin. A linear regression of the log(k) and void ratio (e) data (Table 1) yielded the permeability-void ratio model for Keathley Canyon sediments:

logðkÞ ¼ 0:90e  17:23:

Pn b keq ¼ Pn 1 i : ðb =ki Þ i 1

0

(3)

Specimens with similar void ratio were documented to have variable permeability (Table 1; Fig. 3). To characterize uncertainty of the permeability function, the model was bounded by the 68% confidence interval (one standard deviation) (Fig. 3). I constructed a downhole permeability model (Fig. 4) by applying Eq. (3) to logging-while-drilling void ratio data (Claypool, 2006). LWD bulk density was related to void ratio [e ¼ (rb  rs)/ (rw  rb)] assuming constant seawater density (1024 kg/m3) and sediment density (rs ¼ 2700 kg/m3). Sediment density was based on laboratory measurements of sediment from KC 151 #3 (Winters et al., 2008). I limited permeability prediction to the fine-grained sediments in the basin because those were the sediments used in CRSC experiments and fine-grained sediments composed a majority of the basin fill. Fine-grained sediments were identified by high gamma ray values and intact borehole conditions measured with LWD tools. Core inspection and grain size analyses (Winters et al., 2008) confirmed these grain size interpretations. Permeability based on the best-fit model (Eq. (3)) to the void ratio data decreases rapidly in the shallow section and then gradually (Fig. 4). Permeability is nearly 1014 m2 at the seafloor and decreases to less than 1016 m2 by 50 mbsf. This directly reflects the large decrease in void ratio from 0 to 50 mbsf (Fig. 4). From 50 to

(4)

In Eq. (4), bi is the thickness of layer i, ki is that layer’s permeability, and n is the number of layers. With the void ratio-estimated permeability, Eq. (4) yields keq of 3.1 1017 m2 for these

100

Depth (mbsf)

k ¼

200

300

400 1.0

2.5 0

Bulk Density [g/cm3]

2

Void Ratio

4 -17

-14

log(perm. [m2])

Fig. 4. Downhole bulk density, void ratio, and permeability at KC 151 #2. Bulk density data are from logging-while-drilling. Void ratio is calculated from the bulk density data. Permeability is estimated using the best-fit to experimental data (Eq. (3)) (Fig. 3).

922

B. Dugan / Marine and Petroleum Geology 25 (2008) 919–923

sediments. The 68% confidence interval for the permeability model provides a range of keq from 9.8  1018 to 9.8  1017 m2. 6. Pressure model ROV observations of logging-while-drilling operations at KC 151 #2 documented sediment and fluid outflow from the borehole after reaching the bottom of the hole (Claypool, 2006). This flow created a sediment plume around the borehole (Fig. 5). The plume formed while pulling the drill string from the borehole and continued after a weighted mud (1460 kg m3) was emplaced in the borehole (Claypool, 2006). Continued discharge after displacing the borehole with weighted mud suggested that the flow was driven by formation pressures, perhaps by a sand layer at the base of the borehole (Claypool, 2006), and was not an artifact of drilling. If the flow were drilling-induced, filling the borehole with weighted mud would have stopped the flow. Twenty hours after filling KC 151 #2 with weighted mud, ROV monitoring confirmed the flow had stopped. It was inferred that flow stopped due to collapse of the borehole. I used the interpretation that the flow was driven by formation pressure and the measured density of the weighted mud to estimate the minimum pressure gradient in Keathley Canyon. Vertically upward seepage and discharge occurred when a critical pressure gradient (icrit) was achieved or exceeded (Craig, 1992; Davies et al., 2007):

icrit ¼

g0 : gw

(5)

Here, g0 ¼ (rb  rw)g is the effective unit weight of the sediment– water mixture being displaced. The bulk density of the weighted drilling mud at KC 151 #2 was 1460 kg/m3. This bulk density equated to a minimum critical gradient equal to 0.43 based on Eq. (5). Measured bulk density of the basin sediments was used to determine the upper bound for the critical pressure gradient. The average bulk density of the sediments from LWD data at KC 151 #2 was rb ¼ 1950 kg/m3 (Fig. 4). This bulk density provided an upper bound on the critical gradient equal to 0.90. A gradient in excess of 0.90 would have resulted in liquefaction of the sedimentary column. 7. Flow characterization Vertical fluid flow (q) through the sediments near KC 151 #3 can be estimated from Darcy’s law:

Fig. 5. Photograph of slurry discharge from KC 151 #2 after drilling. Image was taken by the ROV that was used to monitor drilling operations after displacement of the borehole with weighted mud.

q ¼

keq rw g dh : m dl

(6)

In Eq. (6), dh/dl is the hydraulic gradient in the formation, which is assumed to be equal to icrit. I base this assumption on the interpretation that the borehole flow was driven by the in situ hydraulic gradient. If drilling activities (e.g., formation charging or borehole swabbing) had caused the flow, it would have been of shorter duration and would have been stopped by displacing the borehole with weighted mud. The flow, however, continued after filling the borehole with weighted mud and removing the drill string. For the equivalent permeability and critical gradient estimates in Keathley Canyon, vertical flow rate is predicted to be at least 1.3 mm/yr and not to exceed 28 mm/yr. For the best fit of the permeability model (Figs. 3 and 4) and the minimum critical gradient based on weighted mud, the flow rate estimate is 4 mm/yr. Low permeability layers will dominate the equivalent permeability; therefore I infer the lower flow rates are probably most representative of average vertical flow in the mini-basin. 8. Discussion Compression indices for the Keathley Canyon sediments during primary consolidation have an average of 0.26. The swell indices have an average value of 0.041 (15% of the compression indices). Swell indices are always much smaller than compression indices for primary consolidation (Lambe and Whitman, 1969), and the experimental results reported here are similar to other normally consolidated Gulf of Mexico mud (Lee et al., 2008). Field-based estimates of compression indices in Keathley Canyon range from 0.74 to 1.1 (Winters et al., 2008; Yun et al., 2006a). The laboratoryconstrained indices are controlled by primary consolidation over short time periods (days to weeks), whereas the field-constrained parameters are influenced by primary consolidation and secondary processes such as creep over geologic time scales. These secondary processes yield higher compression indices from field data due to increased deformation without appreciable stress changes. The predicted vertical flow rates, 1.3–28 mm/yr, expand and strengthen previous interpretations of flow in the northern Gulf of Mexico. Regional numerical flow models for the northern Gulf of Mexico predict maximum vertical advection rates of tens of cm/yr in Plio-Pleistocene sediments (e.g., Harrison and Summa, 1991). Compaction is driving these flow rates, which are greatest near depocenters and decrease with increasing distance from depocenters (Bethke et al., 1988; Harrison and Summa, 1991). Keathley Canyon is not a major depocenter for Pleistocene sediments, so it is expected that the compaction-driven flow rates would be lower than the maximum velocities near major depocenters. Together the flow estimates for Keathley Canyon and basin-scale models suggest that 1–4 mm/yr may be the best estimates of flow rates in the Keathley Canyon mini-basin. Shallow overpressure and flow systems exist throughout the Gulf of Mexico. In the Ursa basin of the northern Gulf of Mexico, active fluid flow in the shallow subsurface drives shallow water flows (Ostermeier et al., 2000). IODP Expedition 308 provides pressure measurements in mudstone overlying the major shallow water flow sands in the Ursa basin (Flemings et al., 2006). The measurements document a minimum overpressure gradient (dP*/ dz) of 5.2 kPa/m (Flemings et al., 2006). My analyses of weighted mud and borehole flows in Keathley Canyon yields a minimum overpressure gradient of 4.3 kPa/m (dP*/dz ¼ icritrwg). A lower overpressure gradient in Keathley Canyon, relative to the Ursa basin, is consistent with the interpretations of Ostermeier et al. (2000) that shallow water flow risk is lower in Keathley Canyon than in the Ursa basin. One reason for lower overpressure gradients

B. Dugan / Marine and Petroleum Geology 25 (2008) 919–923

in the Keathley Canyon region could be its increased distance from major Pleistocene depocenters in comparison to the Ursa basin (McFarlan and LeRoy, 1988). The Keathley Canyon flow analysis represents a simplified, onedimensional approximation of the hydrogeologic system. The analysis assumes steady-state conditions that may not be valid near seeps or vents (Tryon and Brown, 2004). Steady-state conditions, however, should be valid in much of the Keathley Canyon minibasin where stratigraphy is continuous and not cross-cut by large faults (Hutchinson et al., 2008). The average flow rate through sediments in the Keathley Canyon mini-basin provides excellent controls for modeling studies and inputs to gas hydrate formation and stability models (Bhatnagar et al., 2007). Heterogeneous, high permeability layers, such as the sand at 95–110 mbsf in KC 151 #2 (Claypool, 2006), could act as a conduits into which fluids are focused. Faults along the basin flanks could also act as permeable conduits and that enhance heat flow on the eastern edge of the basin as observed by Hutchinson et al. (2008). Such heterogeneous features require high resolution data and models beyond the scope of this model for average flow. The average flow models, however, provide a minimum flow rate for conditions in permeable heterogeneities. Basin-wide overpressure will also affect the gas hydrate stability field. The temperature gradient near the boreholes is w29  C/km based on downhole temperature measurements (Claypool, 2006). Three-phase equilibrium calculations (e.g., Sloan, 1998) using the estimated overpressure and the temperature data suggest that the base of gas hydrate stability in the basin should be 25 m deeper than if the basin were at hydrostatic pressure. Elevated salinity (up to 50 parts per thousand) in the basin (Claypool, 2006) will cause the three-phase equilibrium to shoal and this counter-acts deepening due to overpressure. To accurately model the base of gas hydrate stability field, overpressure, salinity, and gas composition must be included in the hydrate stability model. 9. Conclusions Fluids in the Keathley Canyon mini-basin are driven vertically upward toward the seafloor. Fluid velocities at steady-state are estimated to be approximately 4 mm/yr in this fine-grained basin. Uncertainty in pressure and permeability estimates are used to document flow that must exceed 1.3 mm/yr but cannot exceed 28 mm/yr. The vertically upward flow is driven by a minimum overpressure gradient estimated to be 4.3 kPa/m, based on density of weighted mud and observed outflow from KC 151 #2. These flow rates and moderate overpressures are consistent with compaction-driven flow in Gulf of Mexico basins with moderate sedimentation rates. For the observed temperature gradients in Keathley Canyon, the pressures predicted in the basin suggest the base of hydrate stability would be 25 m deeper than if the basin had hydrostatic pressure. Variable porewater chemistry and gas composition also affect the base of hydrate stability in Keathley Canyon. Acknowledgements The Joint Industry Project for Methane Hydrate, managed by Chevron with funds from the Department of Energy’s National Energy Technology Laboratory (DE-FC26-01NT41330) and Rice University supported this research. Constructive and insightful

923

comments by three anonymous reviewers helped strengthen this paper. References ASTM International, 2006. Standard test method for one-dimensional consolidation properties of saturated cohesive soils using controlled-strain loading, D4186-06. Bethke, C.M., Harrison, W.J., Upson, C., Altaner, S., 1988. Supercomputer analysis of sedimentary basins. Science 239, 261–267. Bhatnagar, G., Chapman, W.G., Dickens, G.R., Dugan, B., Hirasaki, G.J., 2007. Generalization of gas hydrate distribution and saturation in marine sediments by scaling of thermodynamic and transport processes. Am. J. Sci., doi:10.2475/06. 2007.01. Blum, P., 1997. Physical properties handbook: a guide to the shipboard measurements of physical properties of deep-sea cores, ODP Technical Note 26. . Claypool, G. (Ed.), 2006. Cruise Report: the Gulf of Mexico Gas Hydrate Joint Industry Project. Shipboard Scientific Party. http://www.netl.doe.gov/ technologies/oil-gas/publications/Hydrates/reports/GOMJIPCruise05.pdf. Craig, R.F., 1992. Soil Mechanics. Chapman & Hall, London, 427 pp. Davies, R.J., Swarbrick, R.E., Evans, R.J., Huuse, M., 2007. Birth of a mud volcano: East Java, 29 May 2006. GSA Today, doi:10.1130/GSAT01702A.1. Flemings, P.B., Behrmann, J.H., John, C.M., Expedition 308 Scientists, 2006. Proceedings of the IODP. Integrated Ocean Drilling Program Management International, Inc., College Station, TX, doi:10.2204/iodp.proc.308.2006. Freeze, R.A., Cherry, J.A., 1979. Groundwater. Prentice Hall, Englewood Cliffs, 604 pp. Harrison, W.J., Summa, L.L., 1991. Paleohydrology of the Gulf of Mexico Basin. Am. J. Sci. 291, 109–176. Hutchinson, D.R., Hart, P.E., Collett, T.S., Edwards, K.M., Twichell, D.C., Snyder, F., 2008. Geologic Framework of the 2005 Keathley Canyon gas hydrate research well, Northern Gulf of Mexico. Mar. Petr. Geol. 25, 906–918. Hutchinson, D.R., Hart, P.E., Ruppel, C.D., Snyder, F., Dugan, B., 2008. Seismic and thermal characterization of a bottom simulating reflection in the northern Gulf of Mexico. In: Johnson, A., Knapp, C., Boswell, R. (Eds.), Natural Gas Hydrates: Energy Resources, Potential and Associated Geologic Hazards. AAPG Special Publication. Kastner, M., Claypool, G., Roberston, G., 2008. Geochemical Constraints on the Origin of the Pore Fluids and Gas Hydrate Distribution at Atwater Valley and Keathley Canyon, Northern Gulf of Mexico. Mar. Petr. Geol. 25, 860–872. Lambe, T.W., Whitman, R.V., 1969. Soil Mechanics. John Wiley & Sons, New York, 553 pp. Lee, J.Y., Santamarina, J.C., Ruppel, C., 2008. Mechanical and electromagnetic properties of northern Gulf of Mexico Sediments with and without THF hydrates. Mar. Petr. Geol. 25, 884–895. McFarlan Jr., E., LeRoy, D.O., 1988. Subsurface geology of the late Tertiary and Quaternary deposits, coastal Louisiana and the adjacent continental shelf. Gulf Coast Assoc. Geol. Soc. Trans. 38, 421–433. Ostermeier, R.M., Pelletier, J.H., Winker, C.D., Nicholson, J.W., Rambow F.H., Cowan, K.M., 2000. Dealing with shallow-water flow in the deepwater Gulf of Mexico, offshore technology conference 2000, Houston, TX. Parnell, J., 2002. Fluid seeps at continental margins: towards an integrated plumbing system. Geofluids 2, 57–61. Ruppel, C., Dickens, G.R., Castellini, D.G., Gilhooly, W., Lizarralde, D., 2005. Heat and salt inhibition of gas hydrate formation in the northern Gulf of Mexico. Geophys. Res. Lett. 32, L04605. Sloan, E.D., 1998. Clathrate Hydrates of Natural Gas. Marcel Dekker, New York, 705 pp. Toth, J., 1996. Thoughts of a hydrogeologist on vertical migration and nearnearsurface geochemical exploration for petroleumpetroleum. In: Schumacher, D., Abrams, M. (Eds.), Hydrocarbon Migration and Its Near-Surface Expression. AAPG Memoir 66. AAPG, pp. 279–283. Tryon, M.D., Brown, K.M., 2004. Fluid and chemical cycling at Bush Hill: implications for gas- and hydrate-rich environments. Geochem. Geophys. Geosys., doi: 10.1029/2004GC000778. Wilson, A., Ruppel, C., 2007. Salt tectonics and shallow subseafloor fluid convection: models of coupled fluid-heat-salt transport. Geofluids 7 (4), 377–386. Winters, W.J., Dugan, B., Collett, T.S., 2008. Physical properties of sediments from Keathley Canyon and Atwater Valley, JIP Gulf of Mexico gas hydrate program drilling program. Mar. Petr. Geol. 25, 896–905. Wood, W.T., Gettrust, J.F., Chapman, N.R., Spence, G.D., Hyndman, R.D., 2002. Decreased stability of methane hydrates in marine sediments owing to phaseboundary roughness. Nature 420, 656–660. Xu, W., Ruppel, C., 1999. Predicting the occurrence, distribution, and evolution of methane gas hydrate in porous marine sediments. J. Geophys. Res. 104, 5081– 5095. Yun, T.S., Narsilio, G.A., Santamarina, J.C., 2006a. Physical characterization of core samples recovered from Gulf of Mexico. Mar. Petr. Geol. 23, 893–900. Yun, T.S., Narsilio, G.A., Santamarina, J.C., Ruppel, C., 2006b. Instrumented pressure testing chamber for characterizing sediment cores recovered at in situ hydrostatic pressure. Mar. Geol. 229, 285–293.