Subsurface gas hydrates in the northern Gulf of Mexico

Marine and Petroleum Geology 34 (2012) 4e30

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Subsurface gas hydrates in the northern Gulf of Mexico Ray Boswell a, *, Timothy S. Collett b, Matthew Frye c, William Shedd d, Daniel R. McConnell e, Dianna Shelander f a

U.S. Department of Energy, National Energy Technology Laboratory, Morgantown, WV, United States U.S. Geological Survey, Denver, CO, United States c U.S. Bureau of Ocean Energy Management, Herndon, VA, United States d U.S. Bureau of Ocean Energy Management, New Orleans, LA, United States e AOA Geophysics, Houston, TX, United States f Schlumberger, Houston, TX, United States b

a r t i c l e i n f o

a b s t r a c t

Article history: Received 23 June 2011 Received in revised form 7 October 2011 Accepted 9 October 2011 Available online 19 October 2011

The northern Gulf of Mexico (GoM) has long been a focus area for the study of gas hydrates. Throughout the 1980s and 1990s, work focused on massive gas hydrates deposits that were found to form at and near the seafloor in association with hydrocarbon seeps. However, as global scientific and industrial interest in assessment of the drilling hazards and resource implications of gas hydrate accelerated, focus shifted to understanding the nature and abundance of “buried” gas hydrates. Through 2005, despite the drilling of more than 1200 oil and gas industry wells through the gas hydrate stability zone, published evidence of significant sub-seafloor gas hydrate in the GoM was lacking. A 2005 drilling program by the GoM Gas Hydrate Joint Industry Project (the JIP) provided an initial confirmation of the occurrence of gas hydrates below the GoM seafloor. In 2006, release of data from a 2003 industry well in Alaminos Canyon 818 provided initial documentation of gas hydrate occurrence at high concentrations in sand reservoirs in the GoM. From 2006 to 2008, the JIP facilitated the integration of geophysical and geological data to identify sites prospective for gas hydrate-bearing sands, culminating in the recommendation of numerous drilling targets within four sites spanning a range of typical deepwater settings. Concurrent with, but independent of, the JIP prospecting effort, the Bureau of Ocean Energy Management (BOEM) conducted a preliminary assessment of the GoM gas hydrate petroleum system, resulting in an estimate of 607 trillion cubic meters (21,444 trillion cubic feet) gas-in-place of which roughly one-third occurs at expected high concentrations in sand reservoirs. In 2009, the JIP drilled seven wells at three sites, discovering gas hydrate at high saturation in sand reservoirs in four wells and suspected gas hydrate at low to moderate saturations in two other wells. These results provide an initial confirmation of the complex nature and occurrence of gas hydrate-bearing sands in the GoM, the efficacy of the integrated geological/geophysical prospecting approach used to identify the JIP drilling sites, and the relevance of the 2008 BOEM assessment. Published by Elsevier Ltd.

Keywords: Gas Hydrate Northern Gulf of Mexico

1. Introduction Gas hydrates are naturally-occurring clathrate compounds comprised of an open lattice of water molecules enclosing single molecules of various gases, most commonly methane (CH4), without chemical bonding (Sloan and Koh, 2008). Globally, gas hydrates hold vast volumes of methane, with significant relevance to a range of science issues (Kvenvolden, 1988), including global carbon cycling (Dickens, 2003), global climate change (Archer, 2007), natural geohazards (Maslin et al., 2010), and future energy

* Corresponding author. Tel.: þ1 304 285 4541; fax: þ1 304 285 4216. E-mail address: [email protected] (R. Boswell). 0264-8172/$ e see front matter Published by Elsevier Ltd. doi:10.1016/j.marpetgeo.2011.10.003

supply (Collett, 2002). Fundamental science related to the development and nature of gas hydrate systems has been the focus of a number of recent marine drilling/coring programs conducted under the auspices of the Integrated Ocean Drilling Program (IODP and its predecessors). In addition, industrial concerns such as geohazard and energy resource evaluation have been the primary motivation for numerous arctic and deepwater programs in recent years. For a detailed review of these programs, the reader is referred to Collett et al. (2009). Together, these field programs have confirmed that gas hydrate exists in great abundance in nature, but in a range of occurrence types that (1) reflect fundamental differences in the local geologic systems, and (2) have differing degrees of relevance to the various environmental, resource, and hazards issues related to gas hydrate (Boswell and Collett, 2011).

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The primary gas hydrate occurrence types and typical saturations (Sh: % of sediment pore space occupied by gas hydrate) are: (1) solid masses (“mounds”) that occur primarily at, or very near, the seafloor in association with vents; (2) pore-filling gas hydrate, typically at low Sh (w10% or less) in fine-grained sediments and commonly at much higher Sh (50%e90%) in coarser-grained sediments (coarse silts and sands); and (3) grain-displacing gas hydrates (nodules, veins and fracture fills: Holland et al., 2008; Schultheiss et al., 2009), with average Sh ranging from <5% to 40% or more (Lee and Collett, 2009). Among these primary types, field data, experimental studies and numerical simulation conducted to date indicate that seafloor mounds are not relevant to energy resource issues as they are generally very small in size, and not conducive to extraction using existing drilling technologies. While these occurrences can pose safety issues for field development (Gharib et al., 2008), they are generally not a significant drilling hazard as they are relatively easy to detect and avoid (McConnell et al., 2012). Similarly, numerical modeling studies (Moridis and Sloan, 2007) indicate that gas hydrates in fine-grained sediments are not attractive resource targets and represent manageable deepwater drilling hazards (Birchwood et al., 2008) although long-term well-bore instability related to thermal effects of producing deeper conventional oil and gas through overlying hydrate-bearing sediments remain poorly constrained (Hadley et al., 2008). As a result, gas hydrate within sand reservoirs, where Sh can be very high, is attracting increasing interest, both as a potential producible resource (ex.

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Moridis et al., 2009) and as a possible drilling hazard (McConnell et al., 2012). This report reviews the evolving perception on the potential occurrence of subsurface (nominally defined as w50 þ meters below the seafloor (mbsf)) gas hydrates in the GoM and summarizes the objectives, methodology, and results of two recent evaluation programs: 2008 Bureau of Ocean Energy Management (BOEM) resource assessment (Frye, 2008), and the 2009 JIP Leg II logging-while-drilling (LWD) program. Additional detailed reports on subsurface gas hydrates in the GoM derived from these two programs can be found in the companion papers to this Special Thematic Set. 2. Gas hydrates in the Gulf of Mexico Gas hydrates have been reported throughout the Outer Continental Shelf (OCS) of the United States (US); however, work to assess marine gas hydrates in the US recently has been most strongly focused on the northern slope of the GoM continental margin (Fig. 1). The GoM basin opened in the Late Triassic-Early Jurassic and during its early development was dominated by deposition of thick sequences of Louann Salt (Salvador, 1991). Throughout the Tertiary, the basin was progressively filled by large volumes of continental detritus, much of it fine-grained and derived from the North American continent to the north and west, producing a thick and wide continental shelf. This sediment loading resulted in the mobilization of the deep salt, ultimately producing

Fig. 1. Selected gas-hydrate-related sites in the deepwater Gulf of Mexico. Circles denote Gulf of Mexico JIP Leg I (2005) drilling/coring sites. Stars mark Leg II (2009) LWD sites. Additional sites evaluated but not drilled by the JIP are marked by triangles. Squares mark sites discussed in the text.

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an array of salt-cored diapiric structures and accommodating faults, fringed by deep salt-withdrawal mini-basins (Bryant et al., 1990; see Fig. 2). As discussed below, the geological complexity of the GoM has profound effects on the occurrence and distribution of gas hydrates. 2.1. Early phases of investigation Following initial physical sampling (via piston coring) conducted at the Bush Hill site (Green Canyon (GC) 185: Brooks et al., 1984), gas hydrate studies in the GoM focused primarily on mapping the physical distribution, and analyzing the gas geochemistry, of surficial “mounds.” The association of gas hydrate with surficial anomalies such as vents and carbonate hard grounds, and the association of those features with shallow fault systems at the margins of salt structures, was quickly established (Brooks et al., 1986; Roberts, 1995), as was the common co-occurrence of unique chemosynthetic communities (MacDonald et al., 1994). Both shallow biogenic and thermogenic gas was recovered from hydrates throughout the upper and middle slope (Milkov and Sassen, 2000): at the Bush Hill site, gases within gas hydrates were found to be virtually identical to those sampled from underlying conventional gas accumulations in the Jolliet Field (Sassen et al., 1999). Perhaps the initial report of gas hydrates being encountered below the GoM seafloor, with no obvious connection to seafloor anomalies, was the visual observation of mm- to cm-scale “crystals” of gas hydrate in sediment recovered from 20 to 40 mbsf at Deep Sea Drilling Project Leg 96 Site 618 in the Orca basin (Pflaum et al., 1986) in 1983. The nature and form of the gas hydrate observed in situ is not clear, although the sediments were described as primarily mud-rich with potential preferred occurrence of the gas hydrate within minor interbedded biogenic (primarily shell fragments) sands. The gas was interpreted to be biogenic in origin. No published reports of subsurface gas hydrate in the northern GoM occurred over the next two decades, despite the drilling of more than 1200 industry wells in water depths of 500 m or more (Table 1). Please see Hutchinson et al. (2011) for a full review of the early phases of gas hydrate research in the GoM. 2.2. The Gulf of Mexico gas hydrate petroleum system Given typical seafloor temperatures, and subsurface temperature, pressure, and geochemical gradients, the base of structure I gas hydrate stability intersects the GoM seafloor at roughly 600 m

water depth (Collett, 1995). Variations in gas chemistry, reflecting the presence of thermogenic ethane and heavier molecular weight hydrocarbon gases, and the resultant formation of structure II gas hydrates may extend this limit as shallow as 300 m (Milkov and Sassen, 2000). While temperature, pressure, and chemistry vary in any geologic system, the sedimentologic, stratigraphic, and hydrologic disruptions related to pervasive salt tectonism render the northern GoM highly heterogeneous (Frye, 2008). This complexity is reflected in a map of the thickness of the gas hydrate stability zone (GHSZ) for the GC protraction area (Fig. 3). 2.2.1. Gas charge The GoM hosts a prolific deepwater petroleum system. From 1992 to 2006, GoM wells in >200 m of water have yielded w2.9 billion barrels of oil and 12.7 trillion cubic feet of gas. Numerous deepwater hydrocarbon seeps and gas-hydrate “mounds” (Milkov and Sassen, 2001; Shedd et al., 2012) provide further evidence of active hydrocarbon sourcing to the GHSZ. In addition to the substantial generation of thermogenic hydrocarbons, the basin is also favorable for the occurrence of biogenic methane due to high total organic carbon input and high sedimentation rate (Frye, 2008; Hutchinson et al., 2011). Large lateral variations in near-surface methane flux, as indicated by variable surficial features (Roberts, 2001) and highly variable depth of penetration of sulfate into the seafloor (see Paull et al., 2005), suggest that gas migration is regionally heterogeneous and focused into discrete high-flux pathways. 2.2.2. Reservoir A key element in the evaluation of the gas hydrate component of the GoM petroleum system (particularly with respect to energy resource potential) is the presence of sand-rich reservoirs. The potential for sand-rich turbiditic fans in the abyssal plain of the GoM is high. Furthermore, the structural complexity of the GoM shelf and slope provide additional sand exploration targets in relatively shallower water of the slope. Unlike other, less complex passive margin settings where sand by-pass of the slope is common, deposition of thick sand bodies can occur where gravitydriven depositional events enter salt-withdrawal mini-basins (Fig. 4: see Prather et al., 1998 and Prather, 2003 for more discussion). An opportunity to assess the nature and occurrence of these “ponded” depositional systems was afforded by IODP Expedition 308 (Flemings et al., 2006), which drilled seismically-inferred turbidite sequences in the Brazos-Trinity Basin IV (Badalini et al., 2000; Beaubeouf et al., 2003). Expedition 308 documented

Fig. 2. Geology of the northern Gulf of Mexico shelf and slope showing the occurrence of salt (black) and generalized stratigraphy. Approximate location of the base of gas hydrate stability is shown with dashed red line. General line of this section is shown in Fig. 1. Image modified from Prather (2000) after Diegel et al., 1995. Used with permission. (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)

R. Boswell et al. / Marine and Petroleum Geology 34 (2012) 4e30 Table 1 Statistics related to deepwater oil and gas drilling in the deepwater Gulf of Mexico. The left-hand columns show the distribution of 1753 wells drilled in water depths exceeding 457 m (1500 ft) in 2-year increments through November 2010. The righthand columns show the distribution of these wells by water depth. Data derived from BOEM on-line well databases. Deepwater wells by year drilled

Deepwater wells by water depth

Year interval

No. of wells

cum. wells

Depth interval (ft)

No. of wells

cum. wells

1976 or prior 1977e1978 1979e1980 1981e1982 1983e1984 1985e1986 1987e1988 1989e1990 1991e1992 1993e1994 1995e1996 1997e1998 1999e2000 2001e2002 2003e2004 2005e2006 2007e2008 2009e2010 Year unknown

3 2 5 9 27 45 65 76 42 54 116 205 177 269 194 149 162 147a 6

3 5 10 19 46 91 156 232 274 328 444 649 826 1095 1289 1438 1600 1747 1753

1500e1999 2000e2499 2500e2999 3000e3499 3500e3999 4000e4499 4500e4999 5000e5499 5500e5999 6000e6499 6500e6999 7000e7499 7500e7999 8000e8499 8500e8999 9000e9499 9500e9999 10000e10499 10500-deeper

268 159 239 190 177 189 88 83 61 72 90 32 48 22 17 9 7 2 0

268 427 666 856 1033 1222 1310 1393 1454 1526 1616 1648 1696 1718 1735 1744 1751 1753 1753

a

Through mid-November, 2010.

a sands-rich shallow section, including very-fine to medium grained sands within the upper 100 m below seafloor (mbsf: w330 ft below seafloor (fbsf)). The extent of these sand bodies had been masked in seismic data due to the low acoustic impedance between the water-wet sands and the enclosing muds (Flemings et al., 2006). Subsequently, the regional occurrence of shallow sand

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units (in this case, defined as within 610 m (2000 ft) of the seafloor) was indicated by analysis of more than 800 logging-while-drilling (LWD) datasets from throughout the northern GoM (Frye, 2008). This mapping, which integrated seismic-facies analyses, indicated that sand lithology may comprise greater than 20% of the total shallow section within many mini-basin interiors and is also likely within the Mississippi Canyon and upper fan on the deep basin plain (Fig. 5). 2.2.3. Gas hydrate occurrence Despite abundant evidence of hydrocarbon supply to the GHSZ, and despite the prior USGS determination that geologic and geochemical conditions were sufficient to host large volumes of gas hydrate within the GoM (Collett, 1995), pessimism regarding the basin’s potential to host significant occurrences of subsurface gas hydrates was common. For example, the localization of gas sourcing to the GHSZ associated with high-flux conduits was viewed as potentially leaving large regions of the GoM shallow sedimentary section, particularly in the center of relatively undeformed mini-basins, deprived of the methane needed to form substantial subsurface gas hydrate (Milkov and Sassen, 2000; Paull et al., 2005). Conversely, the unique thermal and pore-water salinity conditions associated with areas of high fluid flux were also shown to be inconsistent with significant gas hydrate occurrence (Ruppel et al., 2005). Furthermore, a lack of observation of traditional geophysical indicators for gas hydrate such as extensive bottom-simulating reflectors (BSR) or broad “blanking zones” (Kvenvolden and Lorenson, 2001; Cooper and Hart, 2003) suggested that gas hydrates may not be present in substantial quantities in the GoM. Driven by the need to understand gas hydrate drilling hazards (reviewed in McConnell et al., 2012), detailed investigations utilizing industry data began to provide a different viewpoint.

Fig. 3. Thickness of sediments within the gas hydrate stability zone within the Green Canyon protraction area (location indicated in Fig. 1) showing complex local variation driven by occurrence of shallow salt bodies and the effect of those bodies on geothermal and geochemical conditions that impact the depth of the base of gas hydrate stability (modified from Frye, 2008).

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Fig. 4. In the northern Gulf of Mexico, high sedimentation rates and salt tectonics result in modification of the basin topography from the idealized profile for a passive continental margin. The resultant mini-basins produce depositional gradient changes that enhance the potential for coarse-grained sediment deposition within the slope (from Prather, 2000).

McConnell and Kendall (2002), presented detailed geophysical evidence of gas hydrate occurrence within multiple units with the Terrebonne mini-basin in the northeastern portion of the Walker Ridge protraction area (see Fig. 6). This and subsequent work indicated that the variable stratigraphy and complex structures present in the GoM can produce previously unappreciated geophysical manifestations of gas hydrate, most notably the anomalous alignment of “bright spots” within individual units at the base of gas hydrate stability (BGHS: see Johnson and Smith, 2006) and the reversal of the phase of those events as they traverse the BGHS (McConnell and Zhang, 2005). In addition, close review of seismic data revealed that traditional BSRs do occur in the GoM, including in the GC (Smith et al., 2005; Kou et al., 2007),

Walker Ridge (WR; Kou et al., 2007), East Breaks (EB; Dai et al., 2004) and Keathley Canyon (KC; Hutchinson et al., 2008a) protraction areas. Most recently, the Bureau of Ocean Energy Management (BOEM) documented the occurrence of 145 geophysical features inferred to mark the BGHS throughout the northern GoM (Shedd et al., 2012), with more than half being of the “discontinuous” type as described by McConnell and Kendall (2002). 2.3. Industry encounters with gas hydrate in the GoM Although industry has been drilling in the deepwater GoM since the late 1970s, we are not aware of any published reports of

Fig. 5. Estimated occurrence of sand-rich lithologies within 610 m (2000 ft) of the seafloor in the northern Gulf of Mexico (from Frye, 2008).

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Fig. 6. The seismic manifestation of the base of gas hydrate stability in the Walker Ridge protraction area as described by McConnell and Kendall (2002). The data shows widelyseparated anomalous events aligned at the BGHS and not the classical, continuous bottom-simulating reflectors that have been documented in many other regions and assumed to be diagnostic of “buried” gas hydrate (image used by permission of OTC).

gas hydrates inferred from deepwater industry well data prior to 2005. This can be partly attributed to effective avoidance of areas determined to be gas-hydrate-prone, as well as the inadequacy of the data typically acquired in the shallow portions of deepwater wells for the purpose of gas hydrate identification (Smith et al., 2005). However, it is likely that gas hydrates were encountered. Perhaps the earliest example is the 1995 EB992 #001 (“Rockefeller”) well that penetrated a shallow geophysical anomaly within the GHSZ (Frye et al., 2010). The well confirmed the anomaly to be derived from a thick, slightly resistive, sand body; however, it is unclear if hydrates exist or were interpreted to exist at this site, and no additional log data suitable for the evaluation of gas hydrate occurrence was collected (note: correlative sand bodies in Alaminos Canyon (AC) 21 (roughly 8 miles west) were drilled by the JIP in 2009 as summarized in a later section of this report). By 2005, more than 1200 wells had been drilled in the northern GoM in water depths exceeding 1500 ft (457 m: Table 1) with no known reports of gas hydrate-bearing sediments and with no drilling incidents that could be attributed to in situ gas hydrates (Smith et al., 2005). Perhaps the initial industry report on subsurface gas hydrate as a potential drilling hazard in the GoM was provided by Williamson et al. (2005) who referenced log, seismic, and drilling observations to infer a 30 m (100 ft) zone of gas hydrate disseminated in clay-rich sediments in GC 653 (see Fig. 1). This report indicated that such occurrences should not be a significant drilling hazard, but that higher concentration accumulations that could occur in sand units deserved further investigation. It is very likely that other wells drilled in this time frame encountered thin hydrate-bearing sands (ex. the WR313 #001 well, see Frye et al., 2012) that were not recognized or deemed insignificant. In 2003, Chevron drilled the AC818 #001(“Tiger” or “Tiger Shark”) well in 2744 m (9004 ft) of water to test deep (Lower Tertiary Wilcox) conventional oil and gas prospects on a large anticlinal structure within the Perdido Fold Belt. The well was designed to enable the collection a comprehensive dataset to determine the nature of

a strong shallow seismic anomaly inferred to mark the impingement of the Oligocene Frio sand on the BGHS at w450 mbsf (1500 fbsf) (Smith et al., 2006). The well data confirmed the occurrence of Frio sand, with the upper 20 m (60 ft.) of the unit being marked by high resistivity and high acoustic velocity consistent with Sh ranging from 70 to 80% (Boswell et al., 2009). 2.4. The Gulf of Mexico joint industry project Leg I (2005) As deepwater drilling escalated in the late 1990’s (Table 1), the practice of avoiding suspected gas hydrates, regardless of their nature or potential concentration, became more problematic and costly. In order to better inform decisions about well placement and drilling practices, the GoM gas hydrates JIP was formed, and soon partnered with the U.S. Department of Energy (DOE) to enable research to assess the nature and implications of gas hydrate in the GoM. The initial stage of the JIP effort focused on experimental and modeling studies to determine gas hydrate’s impact on sediment physical properties across a range of sediment grain sizes (see Santamarina and Ruppel, 2008) and to develop predictive well-bore stability models (Birchwood et al., 2007). Primary focus was on those gas hydrate occurrences that were deemed to be the most common in the GoM and the most difficult to assess pre-drill: low concentrations of gas hydrate disseminated within clay-dominated sediments. This phase culminated in 2005 with JIP “Leg I” drilling and coring at sites in Atwater Valley (AT) 13/14 and KC151 (Fig. 1: see Ruppel et al., 2008). The drilling in KC151, which focused on deeper targets, confirmed pre-drill interpretations of gas hydrate occurrence from seismic data (Dai et al., 2008b). Log data indicated that gas hydrate in KC151 occurred primarily within high-angle fractures in clay-rich sediments and also as disseminated pore-fill within a small number of thin, relatively coarser-grained, beds (Cook et al., 2008). The drilling results enabled the JIP to determine that low-Sh deposits in fine-grained sediments pose only modest drilling hazards that are readily managed via existing well-bore pressure and fluid temperature management practices (Birchwood et al., 2008).

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A summary of the results of the JIP program through 2005 can be found in various reports included in Ruppel et al. (2008). 2.5. Regional GoM gas hydrate resource assessments 2.5.1. Pre-2008 assessments The total volume of methane housed in gas hydrate in the GoM has been assessed on multiple occasions (Fig. 7). Krason et al. (1985) estimated 67 trillion cubic meters (tcm: 2366 trillion cubic feet (tcf)) gas-in-place using a regional assumption of 5% average Sh applied to the full inferred thickness of the GHSZ. Collett (1995) initiated the petroleum system approach to gas hydrate assessment by considering the regional variation in parameters that control gas hydrate occurrence; including gas sourcing, subsurface temperature and pressure, and reservoir quality. With respect to the northern GoM, this assessment produced a mean estimate of 1080 tcm (38,251 tcf) gas-in-place. This value was reduced shortly thereafter to 680 tcm (24,000 tcf) to incorporate reduced expectations for Sh based on findings from ODP Leg 164 to the Blake Ridge (per Hutchinson et al., 2011). In contrast, Milkov and Sassen (2001), working from the assumption that gas hydrate in the GoM occurs predominantly in relatively shallow and massive forms in association with faults and vents, assessed in-place gas resources at 12 tcm (423 tcf) but limited the geographic extent to that of known surficial gas hydrate deposits. Klauda and Sandler (2003) conducted numerical simulations of gas generation and conversion to gas hydrate, resulting in an estimate of 120 tcm (4238 tcf) of methane in hydrate form in the GoM. Following on their 2001 report, Milkov and Sassen (2003) attempted the first assessment of potentially-recoverable gas hydrate resources in the GoM. This study reflects the combined context of the authors’ prior work on surficial, vent-related gas hydrate occurrences in the GoM and evaluation of subsurface gas hydrate in sand-poor locales such as the Blake Ridge and Hydrate Ridge (see Milkov, 2004). As a result, they conclude that any porefilling gas hydrate would likely occur only at low saturations disseminated over large areas (termed “stratigraphic” accumulations) and were not viable economic targets. In contrast, “structural”

Fig. 7. Published estimates of gas hydrate in-place resource volumes in the Gulf of Mexico. A) Krason et al. (1985); B) Collett (1995: red: initial estimate, yellow: revised estimate); C) Milkov and Sassen (2001); D) Klauda and Sandler (2003); E) Frye (2008) (where circle indicates total in-place gas and star indicates the volume assessed to occur specifically in sand reservoirs). (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)

accumulations, characterized by concentrations of massive, graindisplacing forms such as mounds and dense networks of fractureor vein-fills associated with faults, were assumed to be the only available occurrences with sufficient resource density for economic extraction. Subsequently, recognition of the occurrence of high-Sh gas-hydrate-bearing sands in the marine environment (ex. Tsuji et al., 2009) and the lack of feasible demonstrated production options for the “structural”-type accumulation, the focus on gas hydrate resource assessment in the GoM, and globally, has shifted to the pore-filling, sand-hosted accumulations (Collett et al., 2009). 2.5.2. 2008 BOEM assessment In an attempt to better constrain the occurrence of gas hydrate in the GoM, the BOEM released, in 2008, the results of a comprehensive, probabilistic gas-in-place resource assessment (Frye, 2008). This work incorporates the latest concepts on the nature of GoM gas hydrate systems into a robust, stochastic modeling approach. To support future BOEM assessments of potentiallyrecoverable resource volumes, the study differentiated in-place volumes into two categories; (1) total in-place resources (without regard to host lithology), and (2) that potentially producible subset occurring as pore fill within sand reservoirs. The BOEM study assessed 450,000 km2 of the northern GoM (see Fig. 5). A mass balance analysis was applied to each of 202,079 model cells (each 2.32 km2), incorporating statistically-based assessments of total organic carbon, sedimentation rates, biogenic methane generation as a function of temperature, migration potential (including both vertical and lateral components), and gas hydrate formation. Other spatially-resolved inputs such as water depth, thickness of relevant sedimentary section, sand-shale ratio, and changes in porosity and permeability with depth, were derived from a variety of datasets, including w200,000 km2 of industry 3-D seismic data, 250,000 km of industry 2-D seismic data, and well logs from more than 800 deepwater wells. The BOEM assessment focused primarily on biogenic methane generation as the source for formation of GoM gas hydrate. However, isotopic data from seafloor seeps indicate that roughly half of vent gas in the GoM is thermogenic in origin, suggesting strong potential for thermogenic sourcing to the GHSZ. While the other half of that gas is apparently biogenic in origin, it remains a complex issue to determine if that gas is primary biogenic gas or thermogenic gas that was subsequently altered and bio-degraded during migration (i.e. Masterson et al., 2001). Nonetheless, efforts to develop a spatially-resolved mass-balance model of thermogenic gases proved to be complex, and therefore thermogenic gas contribution was generally not considered. However, additional gas charge in excess of that assessed from biogenic sources was provided for those 4700 specific grid cells where seafloor features (particularly seismic reflectivity anomalies) suggested high rates of gas flux. The 2008 BOEM assessment model includes three process modules (charge, container, and concentration) and an integration module (Frye, 2008). In the charge module, gas is generated by converting total organic carbon into methane through biogenic processes. The rate at which methanogenic organisms convert organic carbon to methane is modeled by scaling the maximum initial production value by permeability and allowing the entire process to be driven by temperature. Methane gas is modeled as migrating both vertically and laterally through hydrodynamic catchment areas, providing a charge to each cell. In the container module, gross thickness of the GSHZ is calculated by solving an implicit function that is based on the phase stability equation of Milkov and Sassen (2001) modified to account for the effect of salt bodies on geothermal gradients (per O’Brien and Lerch, 1988)

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and pore-water chemistry, as well as for local variations of gas chemistry. The concentration module calculates potential gas hydrate content of each cell (as a percent of the bulk rock volume) by separately calculating Sh and available pore space for both sand and mud lithologic end-members. Interpreted sandmud percentages from integrated well-log and seismic analyses are then used to produce per cell in-place gas hydrate volumes. Cells within the area of surficial seismic anomalies (high flux sites) are assumed to have sufficient charge volume to fill the available effective void space to its calculated capacity, despite the model’s calculated charge volume. The model was executed over 1000 trials to yield a distribution of in-place volumes, with total resource volumes expressed as a cumulative probability distribution. The map of gas hydrate distribution generated by the BOEM assessment clearly reflects the complex geology of the northern GoM (Fig. 8). Within the minibasin province, large areas of little to no gas hydrate correspond to shallow salt features that displace or occupy much of the GHSZ. In contrast, thick sedimentary sections within the deep mini-basins and much of the abyssal plain provide an abundant supply of biogenic gas and often contain rich per cell in-place volumes. The complex geology of the minibasin province also provides increased opportunities for lateral migration and concentration of charge, resulting in a heterogeneous distribution of gas hydrate resources, as opposed to the more homogeneous distribution inferred for less complex areas, in which vertical migration is assumed to dominate. Lastly, the sand-rich cone of the upper Mississippi Fan is highly prospective for gas-hydrate-bearing sands, due to enhanced methanogenesis, gas generation, and presence of sandrich sediments. The 2008 BOEM assessment reported a mean estimate of 607 tcm (21,444 tcf) gas-in-place within gas hydrate in the northern GoM, with approximately 190 tcm (6710 tcf) in sand reservoirs (Frye, 2008). The determination that nearly one-third of the total resource may reside in sand reservoirs is a significant, but not unprecedented finding: a robust and probabilistic assessment of a 10,000 km2 area of the eastern Nankai Trough (Fujii et al., 2008) reported one-half of the total gas-in-place in gas hydrate as occurring at high saturations in sand-rich units.

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3. The JIP Leg II LWD program (2009) 3.1. Background In 2006, the GoM JIP extended its focus to include assessment of both the geohazard and energy resource implications of gas hydrates within coarse-grained sediments in the GoM. Given that only one prior well (AC818 #001) had conclusively encountered gas-hydrate-bearing sands in the basin, substantial geologic risk was inherent in any effort designed to locate and drill gas hydrate-bearing sands. Therefore, the JIP elected to proceed with a staged process (Jones et al., 2008) consisting of (1); geologicalgeophysical prospecting that integrated direct evaluation of prospective geophysical events (Shelander et al., 2010, 2012) with geologic-geophysical interpretation of gas sources, migration, and occurrence of sand reservoirs (see Hutchinson et al., 2008b); (3) an exploratory drilling program (JIP Leg II) that deferred coring to enable the maximum number of sites to be tested via loggingwhile-drilling (LWD) operations; and (3) a third and final field program (JIP Leg III, still in planning at the time of this report) to acquire and analyze pressure core samples from gas-hydratebearing reservoirs and associated seals (Balczewski et al., 2011). 3.2. Prospecting for gas-hydrate-bearing sands The application of a full petroleum systems approach to the evaluation of gas hydrate research drilling sites is a fundamental contribution of the JIP-supported program (Collett et al., 2009). This approach, which is very similar to the concept that has traditionally guided conventional hydrocarbon exploration, is based on mitigating the uncertainty in subsurface geologic exploration through the independent evaluation of the various elements required to produce the desired deposits. The key elements are discussed in the following sections. 3.2.1. “Direct” evidence for gas hydrate Gas hydrate accumulations, particularly those of significant thickness and Sh to be the most compelling production targets, impart substantial physical property changes on the sediment. In the context of exploration, the most useful feature is an increase in

Fig. 8. Mapped distribution of in-place methane in gas hydrate-bearing sands in the Gulf of Mexico as reported from the 2008 BOEM regional gas hydrate resource assessment. The map shows increased potential occurrence within mini-basins on the slope, as well as within the sand-rich cone of the upper Mississippi Fan (from Frye, 2008).

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acoustic velocity. Therefore, high-amplitude events (at appropriately shallow depths) of the same polarity as the seafloor reflector (“peak” reflectors) occurring within the inferred GHSZ, are highly prospective indicators for gas-hydrate-bearing sands (Saeki et al., 2010; Boswell and Saeki, 2010). However, strong peak amplitudes alone are not conclusive, as they can be produced in other ways; including porosity reduction through diagenetic effects, unusual sediment density or compaction, or the simple lithologic contrast between water-saturated sands and muds, particularly in very shallow sub-seafloor settings where the muds are highly porous and unconsolidated. To further mitigate these uncertainties, additional geologic and geophysical evidence that correlates the geophysical event with the co-occurrence of sand-prone sediments and substantial supplies of gas, is required (Collett et al., 2009). 3.2.2. Reservoir Reference to log data from nearby wells and seismic facies analysis can indicate sedimentary packages that may be preferentially sand prone and sequence-stratigraphic concepts can similarly enable inferences on overall depositional architecture (ex. Vail, 1987). Delineation of the mapped geometry of prospective geophysical anomalies can be indicative of sand lithology where those geometries suggest sand-prone features; including morphologies such as lobate fans or elongated or meandering channels with bounding levees. Similarly, the conformity of mapped anomalies to structures, such as their truncation at faults or alignment with post-depositional structure, can provide further support to the interpretation that the geophysical anomalies being imaged are reflecting changes in pore fill and not sedimentologic/ diagenetic aspects of the unit. 3.2.3. Charge and migration The GoM is a known petroliferous basin, so the overall potential for gas charge to any sand reservoir in the shallow section is good. However, focused migration pathways along faults and other structures provide clear means for gas supplies to by-pass potential reservoirs. Recent or ongoing gas charge is also favorable, as dissolution effects may degrade occurrences over time even if pressure-temperature conditions remain favorable. Within the context of the JIP effort, confirmation of the supply of gas to the inferred sand units was evaluated based on geophysical indications of gas below the BGHS; including seismic bright spots (gas accumulations within sand units); broad areas of reduced reflectivity and seismic event attenuation (diffuse gas accumulations within muds); identification of migration pathways that link gas sources to the prospective reservoirs; and seafloor indications of gas venting such as hard-grounds, mud volcanoes, and pockmarks that suggest active flux along the observed migration pathways. This approach highlights the contribution of deeper (most likely thermogenic) gas sources. The potential at various sites for sourcing via short migration from local organic-rich sediments (re Malinverno, 2010) was not directly evaluated. 3.3. JIP Leg II site selection A key objective of the JIP Leg II program was to test the hypotheses that gas hydrate occurs in sand reservoirs within the deepwater GoM and that specific accumulations can be delineated prior to drilling through an integrated geophysical-geological approach. In 2006, scientists from the BOEM, the USGS, the DOE, Schlumberger, AOA Geophysics, and other organizations reviewed sites in which gas-hydrate-bearing sands may have been directly indicated in well log data. A number of potential drilling targets within the AC818 site were selected; however, no other potential

sites could be confidently identified. Therefore, the effort was extended to consider locations in which gas-hydrate-bearing sands were indicated in geophysical data, but for which direct well confirmation was lacking. Scientists from AOA Geophysics brought forward two sites: the first, WR313, was the site earlier described by McConnell and Kendall (2002) (see Fig. 6); the second, GC955, was prospective due to a pattern of anomalous high-amplitude seismic features concentrated at the inferred BGHS within a fourway closed structure (Fig. 9) in an area of inferred high fluid flux (McConnell, 2000; Heggland, 2004). By mid-2008, hazard assessments and well-bore stability modeling had been conducted for more than two dozen potential targets at the AC818, WR313, and GC955 sites (NETL, 2011). These analyses indicated the potential for complex drilling operations at the AC818 site, and that site was abandoned as a candidate for JIP Leg II operations. Due to delays in rig availability, the planned summer 2008 field operations at the remaining two sites were deferred to early 2009. This delay was used to assess additional sites in AC21 and GC781. However, shortly before the expedition, it was determined that ongoing industry drilling operations in the GC781 area precluded obtaining the permissions required for JIP drilling. Ultimately, JIP Leg II was launched in late April 2009 with a total of 20 drill locations permitted within the WR313, GC955, and AC21/EB992 sites (see Collett et al., 2010). 3.4. 2009 JIP Leg II LWD program 3.4.1. Objectives The primary goal of the JIP Leg II field program was the collection of a comprehensive suite of logging-while-drilling (LWD) data through gas-hydrate-bearing sand reservoirs. These data were collected to (1) confirm of the occurrence of gas hydrate at high concentration in reservoir quality sands in the GoM; (2) test the prospecting approach employed by the JIP to delineate and characterize gas-hydrate-bearing sands prior to drilling; (3) determine the detailed nature and architecture of gas hydrate reservoirs and associated seals in order to understand gas hydrate occurrence and to support increasingly-sophisticated numerical modeling; (4) provide insight into the planning and selection of sites and for JIP Leg III coring programs; and (5) provide insight into the ongoing BOEM assessment. 3.4.2. Operations JIP Leg II conducted operations at seven drill locations within three drill sites (see Fig. 1 and Table 2). To enable full evaluation of the target intervals, well total depth was planned as w150 m (w500 ft) below the deepest target of interest. For each site, the initial drill location was set prior to the onset of the expedition in accordance with shallow hazard assessments (see McConnell et al., 2012); with the selection of additional drill locations from those previously permitted determined in real time based on results of preceding wells. Pre-drill protocols called for each well to be drilled primarily with sea-water and abandoned with heavy mud. The data acquisition program featured a state-of-the-art LWD and measurement-while-drilling (MWD) tool string (see Collett et al., 2012; Mrozewski et al., 2010). A summary of Leg II operations follows; for a detailed timeline of shipboard activities, please see Collett et al. (2010). JIP Leg II began on April 16, 2009 with mobilization at sea of the Helix Q4000 semi-submersible mobile offshore drilling unit during transit to the WR313 site. Well WR313-G was spud on April 18 and drilled to planned total depth. Potential tool wear related to difficult drilling conditions necessitated bringing the LWD string to the surface, and during this time, the Q4000 transited 16.7 km (9 nmi) to GC955, where three holes were drilled (GC955-I, GC955-H, and

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Fig. 9. Geology of the Green Canyon 955 site highlighting features of the confluence of evidence of gas sourcing (high-amplitude events indicating gas accumulations), gas migration pathways (abundant faults), and favorable reservoir facies (likely associated with levees of the imaged channel system) within a folded structure (the GC955 dome). Seismic dataÓ 2011 WesternGeco. Used by permission.

caliper data indicate that the most stable portions of the wells drilled during JIP Leg II were those in which substantial volumes of gas hydrate were present, providing significant additional mechanical strength to the otherwise highly-unconsolidated sediments (Collett et al., 2012). In addition to borehole cavings experienced during WR313-G, additional drilling problems were encountered in two wells. Upon completion of drilling and withdrawal of drill pipr from the GC955I well, the well was observed by remote operated vehicle (ROV) to be flowing water at the seafloor. The LWD string was retrieved to the surface, and the drill pipe re-entered the hole to place a cement plug. The most notable drilling event of JIP Leg II, however, was a complex event at the GC955-Q well. The well was drilled immediately following the GC955-H well, in which thick gas-hydratebearing sand and shale sections were drilled without incident and without any indication of free gas. Although the Q-location had been assessed with an elevated risk of free gas in pre-expedition hazard reviews (McConnell et al., 2010); the science team determined that the drill risk was sufficiently mitigated by the revised drilling protocol that included the use of heavy drill fluids through the target reservoir section. Drilling proceeded as expected, with gas-hydrate-bearing sands being encountered through the target interval. However, with the drill bit at 2443 mbrf (8014 fbrf),

GC955-Q) from April 22 to 28. The Q4000 then traveled back to WR313, drilling the WR313-H well from April 29 to May 1. The program concluded with a 324 km (175 nmi) transit to AC21 and the drilling of the AC21-A and AC21-B wells from May 3 to 4. Additional drilling of sites permitted in EB992 was not conducted due to ongoing drilling operations in that area and the determination that additional drilling would not substantially add to the insight obtained from the AC21-A and -B wells. 3.4.3. Drilling issues JIP Leg II continually balanced efforts to maximize LWD data quality while maintaining hole stability. To provide the highest quality data, the JIP had planned to eliminate the use of shallow casing strings and heavy drilling fluids and operate in a full open hole using sea-water with gel sweeps as needed. However, borehole wall collapse and inefficient cuttings removal during the drilling of the initial well (WR313-G) necessitated periodic backreaming and other drilling measures that degraded the LWD data (Collett et al., 2012; Birchwood and Noeth, 2012; Cook et al., 2012). As a result, standard drilling plans were modified to include the introduction of heavy drill fluids at roughly 450 m (1500 ft) drilling depth. Careful control of drilling fluid temperatures mitigated risks related to gas hydrate dissociation during drilling. In fact, the

Table 2 Statistics for the seven wells drilled in Gulf of Mexico Joint Industry Project Leg II. WELL

API No.

Latitude (N)

Longitude (W)

Water Depth (ft)

Well Depth (fbrf)

Well Depth (fbsf)

AC21-A AC21-B GC955-H GC955-I GC955-Q WR313-G WR313-H

608054007000 608054007100 608114053700 608114054400 608114054300 608124003900 608124004000

26 26 27 27 27 26 26

94 94 90 90 90 91 91

4889 4883 6670 6770 6516 6562 6450

6700 6050 8654 9027 8078 10200 9770

1760 1116 1933 2205 1511 3586 3269

55 56 00 00 00 39 39

23.8503 39.1900 02.0707 59.5305 07.3484 47.4841 44.8482

54 53 25 25 26 41 40

00.0702 35.6216 35.1142 16.8928 11.7156 01.9404 33.7467

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drilling was halted when the ROV observed an abrupt and shortlived expulsion of material from the well. No gas was observed in the hole by the MWD fluid density measurements, indicating that the release likely included solid phase gas hydrate and drill cuttings that had been allowed to accumulate in the well-bore during a prolonged drilling hiatus while making a pipe connection (Collett et al., 2010). In response to this event, the hole was displaced with 13.0 ppg mud, and the well observed for 1 h with no further releases observed at the well-head. However, as the LWD string was being pulled from the hole, a small but steady leakage of gas bubbles was observed. Once the LWD tool string was recovered, the drill pipe re-entered the hole and pumped 16.0 ppg mud followed by cement. Subsequent log and seismic data analyses suggest that a free gas zone likely is present at the site below the well-log inferred gas hydrate (Shelander et al., 2012; Zhang et al., 2012). It remains unclear whether the well penetrated into a gas-bearing zone or if communication with a slightly deeper gas accumulation was created by the well control procedures (Collett et al., 2010). 3.5. JIP Leg II drilling results: WR313 3.5.1. WR313 objectives The WR313 drill site lies in w1980 m (w6500 ft) of water within the Terrebonne minibasin (see Frye et al., 2012). The minibasin is elongated from north to south, bounded by saltcored ridges, with a central ridge dividing the basin in to separate eastern and western sub-basins (Fig. 10). During periods of relative uplift of these bounding ridges, gravity-driven sediment flows entering from the north would have been focused within the axial portions of the sub-basins and experienced reduced-toreversed gradients, with resulting diminishment of channelized facies and the deposition of “ponded” turbiditic sands (see Boswell et al., 2012). The ongoing uplift of the mini-basin margins continued to deform the sedimentary section through recent time, with much of the strata presently dipping 10 or more on the basin flanks. An existing industry well (the WR313 #001), located in a structurally high position on the eastern margin of the western sub-basin exhibits numerous thin zones of elevated resistivity, although the log quality is poor, and no sands of seismically-resolvable thickness are apparent (see Frye et al., 2012). The primary attribute of the WR313 site that was prospective for gas hydrate was a series of anomalous seismic responses that align with the inferred BGHS (Fig. 6: McConnell and Kendall, 2000). This configuration was interpreted to indicate the buoyant separation of free gas and water within porous and permeable units with up-dip accumulations of gas hydrate forming an up-dip barrier for further gas migration (Fig. 11). In map view, the seismic-inferred unit geometry suggests channelized facies (McConnell and Zhang, 2005; Shedd et al., 2010a; Boswell et al., 2012). Pre-drill seismic inversions for two units (“blue” and “orange”, discussed below), indicated potential for high Sh (Shelander et al., 2010, 2012). The primary hypothesis tested at WR313 was the interpretation that phase reversals at intermittent stratigraphic levels that are aligned consistent with the inferred BGHS are reliable indicators of the occurrence of gas-hydrate-bearing sands within a variable sand-shale sequence. In addition, the site offered the opportunity to drill a given reservoir at different positions with respect to the BGHS, providing insight on the lateral extent and geologic controls on the occurrence of gas hydrate. Therefore, a second hypothesis to be tested attributed the observed the up-dip termination of the anomalous amplitude (and inferred Sh) within individual units to loss of reservoir quality, as opposed to an alternative interpretation of gradual reduction in Sh away from the BGHS (and the source of

Fig. 10. Seafloor topography at the WR313 site, showing the drill locations within the western lobe of the Terrebonne minibasin.

gas) within a reservoir of generally consistent quality. This hypothesis was favored as a second, up-dip, reversal of amplitude polarity was not observed at any horizon. 3.5.2. WR313 results Two of six wells permitted for the WR313 site were drilled in Leg II. WR313-G tested a large geophysical amplitude anomaly in the “blue” unit (see Shelander et al., 2012) in a location just to the east (up-dip) of the level of the phase reversal. The well encountered a variable succession of muds and sands as expected (see Collett et al., 2012), with background resistivity within the primarilymuddy shallow section of w1 U-m. However, resistivity from 4 to 10 U-m was recorded through a 120 m (400 ft) thick interval (Fig. 12) that is interpreted to represent networks of thin, steeply inclined, grain-displacing, gas-hydrate-filled fractures (Fig. 13: see Cook et al., 2012). Below this zone, numerous thin gas-hydratebearing sands and silts were observed within a predominantly fine-grained section (Fig. 14). The “blue” target was observed to contained a net of w9 m (w30 ft) of high Sh sand within a 21 m (70 ft) gross interval of interbedded sand and muc (Fig. 15). Additional details regarding the nature of the “blue” unit are provided in Frye et al. (2012) and Boswell et al., (2012). The WR313-H well was drilled approximately 1 km up-dip to the east of the G well. The shallow, fracture-filling gas hydrate occurrence was again observed (Fig. 12), and as with the G well, the underlying sediments contained interbedded muds and thin gas-hydrate-bearing sands (Fig. 14). The well penetrated the “blue” unit at approximately the up-dip termination of the gas hydrate accumulation as based on seismic inversion. The sand was observed

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Fig. 11. Seismic data from the base of gas hydrate stability at the Walker Ridge 313 site, showing the variable geophysical response of numerous sand layers that traverse the base of gas hydrate stability, including aligned high-amplitude reflectors and phase reversals interpreted to represent gas hydrate, free gas, and water within sand reservoirs within a variable sand-mud sequence. (modified from Shelander et al., 2010). Seismic dataÓ 2011 WesternGeco. Used by permission.

to have graded into a sand-poor interval with reduced thickness and porosity as compared to the down-dip G well, but still fully saturated with gas hydrate (Fig. 16). A second, deeper unit (“orange”) was drilled in a location of strong “peak” seismic response very near the BGHS and observed to occur as two lobes of very clean sand, each with sharp basal and upper contacts (Fig. 17). Resistivity in the upper lobe is very high, with Sh estimates locally exceeding 90%, whereas the lower lobe was less resistive, with Sh estimates ranging from 50% to 60% (Collett et al., 2012). A third, still

deeper unit (“green”) was penetrated in a position below the BGHS and just slightly below the inferred free-gas/water contact (Fig. 12) and found to include multiple, clean, water-wet sands within a 35 m (115 ft) thick interval. The results of WR313 LWD operations confirm the geological/ geophysical model that links phase reversals of strong amplitude and appropriate polarity to substantial accumulations of gas hydrate in deeply buried sand reservoirs. Thick gas hydrate-bearing sands were found as expected in association with the peak seismic

Fig. 12. Overlay of select LWD data from JIP Leg II WR313-G and WR313-H wells on regional seismic data showing the major occurrences of gas hydrate, including a shallow, stratabound zone interpreted to host gas-hydrate filled fractures in fine-grained sediments and deeper occurrences as pore-fill in sand. Seismic dataÓ 2011 WesternGeco. Used by permission.

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Fig. 13. LWD data from the WR313-H well showing responses typical of the shallow gas hydrate occurrence at the WR313 site. The borehole resistivity image at right shows sigmoidal features (one highlighted by dashed curve) that are inferred to be gas hydrate-filled fractures (see Cook et al., 2012; Lee and Collett, 2012). Location of this interval is noted on Fig. 12.

anomalies at both the “blue” and “orange” units. The occurrence of the gas hydrate up-dip of inferred free gas accumulations strongly suggests that the gas entrained in the hydrate was derived by largely lateral migration along the unit from relatively distant sources (Frye et al., 2012). The comparison of the LWD data for the “blue” unit between the G and H locations also supports the interpretation that the control on the extent of gas hydrate occurrence at this site, as well as the observed up-dip reduction in seismic amplitude, relates primarily to changes in gas hydrate volume driven by reservoir quality, as opposed to changes in Sh. Please see Frye et al. (2012) and Boswell et al. (2012) for further discussion of the WR313 findings. One unexpected result of the WR313 drilling was the observation of gas hydrate-charge within numerous thin sand units throughout the GHSZ in both wells. These sands occur as much as w300 m (w1000 ft) above the BGHS, and significantly displaced from clear sources of free gas. As a result, they may represent local, biogenic sourcing per the mechanism described by Malinverno (2009). However, one of these units, (indicated as “unit A” on Fig. 12), can be

traced over large distances, exhibiting strong amplitude responses and clear phase reversals locally where the unit crosses the inferred BGHS (Fig. 14), suggesting the potential for extensive gas hydrate occurrence and significant lateral gas migration within individual units (Shedd et al., 2010a; Frye et al., 2012). A second unanticipated finding of the drilling at WR313 was the occurrence of grain-displacing gas hydrate within the shallow, mud-rich section. One interpretation of this occurrence is that it represents a shallow zone in which methane gas is exsolving from vertically-diffusing fluids due to reduced methane solubility with decreasing depth (per Xu and Ruppel, 1999). However, the shallow fracture occurrence was observed in both the G and H wells (and upon further inspection, the WR313 #001 well) with the upper and lower contacts corresponding to common stratigraphic units (see Fig. 12). The occurrence as a “strata-bound” accumulation, particularly when those strata are steeply inclined and therefore extend across a range of depths, pressures, and temperatures, strongly suggests that the dominant control on the occurrence is lithologic in nature. This interpretation is supported by the

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Fig. 14. Data related to various thin sands drilled at the WR313 site. A) LWD data from the WR313-H well highlighting a resistive, high-velocity shallow sand unit. An RMS amplitude extraction encompassing this unit (panel C) shows a distribution pattern consistent with sand-rich units flanking a central, sand-poor channel. Red line on C is location of seismic data shown in panel B, which illustrates a phase reversal associated with this unit at the base of gas hydrate stability (dashed black line), indicating likely gas hydrate fill (fromShedd et al., 2010b; Frye et al., 2012). D) LWD data from the WR313-G well highlighting three addition thin sands that contain gas hydrate at high saturations (see Frye et al., 2012 for further discussion). The locations of the log sections shown in panels A and D are noted on Fig. 12. Seismic data shown in panels B and C areÓ 2011 by WesternGeco. Used by permission. (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)

observation that this unit is of notably higher bulk density (Fig. 18) than the surrounding sediments, suggesting a potentially more compacted and competent unit that may have been prone to respond to deformation in a relatively brittle fashion. In concert with reduced methane solubility with depth, such fracture porosity could represent favorable thermodynamic traps for the formation of gas hydrate from vertically-diffusing dissolved fluids. The WR313 drilling results enabled Frye et al. (2012) to provide an initial estimation of gas hydrate in-place resources within the Terrebonne basin at 1.25 tcfg, with 1.02 tcf occurring within finegrained sediments and 0.23 tcf occurring in sands. Numerical

modeling studies based on the WR313 accumulations indicate potentially high rates of gas production, due in large part to the benefits of the unit’s relatively deep burial and interbedded nature, which provides additional sources for heat flux into to counter endothermic cooling during dissociation (Myshakin et al., 2012). 3.6. JIP Leg II results: GC955 3.6.1. GC955 objectives The GC955 site is located in over 1980 m (6500 ft) of water on the GoM abyssal plain, approximately 8 km (5 mi) seaward of the Green

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Fig. 15. LWD data from the WR313-G well showing the interpreted occurrence of gas hydrate saturated sands (green color) within the “blue” unit. The locations of these units are noted on Fig. 12. (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)

Canyon embayment into the Sigsbee Escarpment (Fig. 19). The Green Canyon has served as a persistent focal point for sediment delivery into the deep GoM throughout the Tertiary (McConnell et al., 2010). A prominent Pleistocene channel/levee system traverses the center of the block from NW to SE (“Channel 12” of Weimer, 1990) at a depth of roughly 300 mbsf (w1000 fbsf: Fig. 20). The occurrence of shallow sands associated with this channel is confirmed by a series of industry wells that have logged more than 90 m (w300 ft) of clean, blocky sands in the central and eastern portions of the block (see Boswell et al., 2012). However, the most prospective areas for gas hydrate occur in a faulted, four-way structural closure (the “GC955 dome”) in the southwestern corner of the block (McConnell et al., 2010). The GC955 dome hosts a complex array of strong but patchy seismic amplitudes that are limited to depths roughly equal to or greater than the inferred BGHS (Fig. 9: McConnell et al., 2010). The dome is cut by a complex network of normal faults and contains numerous indications of active fluid flux (McConnell, 2000; Heggland, 2004; McConnell et al., 2010). Whereas the WR313 site presented extensive amplitude anomalies with map-view morphology consistent with sand-rich geobodies, the amplitude anomalies within the GC955 dome are of limited extent, exhibit no clear relationship to geology (Fig. 21), and include juxtaposed leading peaks and troughs, suggesting

complex, patchy occurrences of gas hydrate and free gas (see Zhang et al., 2012; Shelander et al., 2012). The GC955-H well is located on the flank of the dome, and targeted a leading peak event about 2 km2 (500 ac) in size at a projected depth of w410 mbsf (1350 fbsf). The GC955-Q location occurs near the structural crest of the dome and features a set of strong amplitude events with the uppermost being a strong peak, but with several strong trough events immediately subjacent. As a result, the Q-location was assessed with a high likelihood of free gas in pre-drill assessments (McConnell et al., 2010). The primary uncertainty with the H and Q locations was the occurrence of reservoir sands given the large lateral offset from the imaged channel and prior industry wells (Fig. 20). Therefore, additional prospects were identified proximal to the inferred primary channel location. These prospects were typically less compelling than those on the GC955 dome, as the associated geophysical anomalies were either small, muted, or exhibited configurations suggesting control by lithological (as opposed to pore-fill) changes. However, one off-structure prospect (denoted as “I”), located very near the GC955 #001 well location, was of interest as it featured a muted leading peak anomaly at the same stratigraphic level as a potential gas hydrate occurrence that had been noted in the GC955 #001 well (Fig. 20).

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Fig. 16. LWD data from the WR313-H well showing the interpreted occurrence of gas hydrate saturated sands (green color) within the “blue” unit. The location of these units is noted on Fig. 12. (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)

The primary geologic model for the GC955 dome drill sites invoked a thick sand body spanning the BGHS in the area of focused gas charge. The hypothesis was that gas accumulated in the sand from below, forming a zone of gas hydrate of varying thickness

(likely influenced by proximity to faults and reservoir quality) at the BGHZ. Once formed, this gas hydrate restricted the further vertical migration of gas into shallower portions of the sand-body. A further hypothesis that the GC955 drilling was designed to test

Fig. 17. LWD data from the WR313-H well showing the interpreted occurrence of gas hydrate saturated sands (green color) within the “orange” interval. The location of these units is noted on Fig. 12. (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)

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Fig. 18. Selected LWD data from the shallow, fracture-filling gas hydrate occurrence in WR313. Note that the gas hydrate (as noted on Fig. 12) appears to be coincident with a specific stratigraphic unit of elevated bulk density.

was the potential for additional accumulations of gas hydrate in sands within the seismically-muted section above the inferred BGHS. One possibility was that gas hydrate could be concentrated within sands but restricted to the margins of steeply inclined faults or fractures, producing inclined, planar, accumulations that are not imaged on seismic data. An alternative hypothesis was that Sh at the top of the sand package was broadly gradational (consistent with the fining-upwards character common in many sand units), potentially serving to mute the seismic response of the top of gas hydrate.

Fig. 19. Seafloor topography at the Green Canyon 955 site, showing the drill locations at the toe of the Sigsbee Escarpment adjacent to the Green Canyon re-entrant.

3.6.2. GC955 results Three wells were drilled in GC955 (Fig. 22). The LWD data collected in the GC955-I well indicated that the upper 378 m (1240 ft) of sediment is predominantly mud as expected. From that depth, a sand-rich section is observed, including a 46 m (152 ft) thick upper unit showing sharp base and gradational top, and a 40 m (131 ft) thick lower sand showing gradational base and sharp top (Collett et al., 2012). Resistivity in both the upper and lower sands was low (w0.7 U-m) and uniform, indicating no occurrence of gas hydrate. The two sand-rich intervals are separated by a 30 m (99 ft) thick mud-rich interval that contained a total of 6.5 m (21 ft) of sand in three thin units. Within these sands, there is less than 1 m (w2 ft) in which high porosity is associated with elevated resistivity (3e5 U-m) and high acoustic velocities, representing the only inferred gas hydrate-charged units observed at the GC955-I well. The most likely explanation is limited gas charge and lack of trapping geometry in the thicker units due to location off the structural closure. Local self-sourcing of the thinner and isolated (not regionally extensive) units is possible. Upon abandonment, the GC955-I well flowed water (presumably from the sand zones: Collett et al., 2010), suggesting significant regional extent and hydraulic connectivity of the sands.

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Fig. 20. Amplitude extraction along the “C” horizon (noted in Fig. 9) within Green Canyon 955. A major channel system traverses the block. Industry drilling (the GC955 #001 and #002 wells) confirmed thick sands in proximal locations. Circular area in lower left denotes the position of the GC955 dome, where the targets for the GC955-H and GC955-Q wells were located at slightly deeper stratigraphic levels. Seismic dataÓ 2011 WesternGeco. Used by permission.

The GC995-H well was drilled about 1 mile southwest of the I-location on the eastern flank of the GC955 dome. While drilling the shallow, mud-rich, section, three zones of elevated (commonly 4 to 10 U-m) but erratic resistivity were observed. Borehole resistivity images indicate numerous planar, resistive features indicating gas-hydrate occurrence in nearly vertical fractures (Lee and Collett, 2012; Cook et al., 2012). This interval shows no indication of gas hydrate in the seismic data, although it is coincident with the intersection of the well-bore with several seismically-imaged normal faults (Boswell et al., 2012). The target sand unit was encountered at 2430 m (7974 ft) drilling depth and observed to be 99 m (325 ft) in gross thickness. Within this unit, three discrete gas-hydrate-bearing zones of 27 m (88 ft), 4 m (13 ft), and 1 m (3 ft) gross thickness were logged with the remainder of the unit being fully water-saturated. High-resolution resistivity images showed that the occurrence of gas hydrate is concentrated in units commonly 1 m or less in thickness, interbedded with units of lesser Sh that are typically 0.2e0.3 m thick (Fig. 23: see Cook et al., (2012); Boswell et al., (2012)). Resistivity within these two water-bearing zones is slightly lower (0.6e0.8 U-m) than that seen in the upper and basal waterbearing portions of the overall sand body (uniformly 0.8e0.9 Um) suggesting slightly higher salinity; however, due to increased

borehole washout in the water-saturated sands, the LWD data in the non-hydrate-bearing sands is highly suspect. The uncertainty in log quality may also extend to the gamma-ray data, which suggests strong reductions in clay content coincident with the water-bearing, washed-out, zones. It is not clear whether 1) these gamma-ray indications are substantially correct, and the washed-out/gas hydrate-free sands marginal to the gas hydratebearing units are truly of higher reservoir quality; or 2) the gamma-ray data is impacted by the enlarged hole. No evidence of free gas was observed at any point during the drilling of the GC955-H well. The GC955-Q location was drilled near the crest of the GC955 dome in an up-thrown fault block to the west of the GC955-H well (Boswell et al., 2012). As with the GC955-H and GC955-I wells, the GC955-Q well drilled a thick sequence of mud-dominated sediments in the shallow section; however, despite being w1.5 km from the GC955-H location where a thick section of fracture-filling gas hydrate was logged, no evidence of gas hydrate was observed in this interval. At a drilling depth of 2417 m (7931 ft), the GC955Q well encountered the top of the sand-rich target interval as expected (Fig. 24). Below an upper water-saturated zone and thin low-porosity zone, the sand appears to be thinly bedded, porous, and gas-hydrate saturated in a manner similar to that observed at

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Fig. 21. Pre-drill interpretation of gas hydrate saturation within the Green Canyon 955 site showing the inferred patchy occurrence of gas hydrate.

the H location. At drilling depth of 1511 m (8027 ft), operations were halted (see drilling issues discussion above) and therefore no LWD data was recorded in the bottom 10 m (35 ft) of the hole. However, the available data indicate high Sh to a drilling depth of

at least 2444 m (8017 ft: Collett et al., 2012). As discussed above, seismic data analyses conducted post-drill suggest that the well may have penetrated (or approached closely) free gas-bearing sands (Shelander et al., 2012; Zhang et al., 2012).

Fig. 22. LWD data for the three JIP Leg II wells posted upon an arbitrary display of seismic data at the GC955 site. Green coloration shows the inferred gas hydrate occurrences at the base of gas hydrate stability (dashed line). Seismic dataÓ 2011 WesternGeco. Used by permission. (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)

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Fig. 23. LWD data from the GC955-H well showing the interpreted occurrence of gas hydrate within thinly-laminated sands (green color) and associated bounding water-bearing sand units (blue color). (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)

The results of the drilling in GC955 are generally consistent with the exploration model, with strong leading peak amplitudes delineating thick gas hydrate occurrences within sands (Fig. 22). The lateral discontinuity in the seismic events is attributable largely to complex fault compartmentalization (Boswell et al., 2012); however, the detailed controls on gas hydrate occurrence within the sand body remain unclear. In the case of the GC955-H well, the poor quality of the LWD data in water-wet sands renders it uncertain if the lack of gas hydrate in those units is due to inadequate reservoir quality, inability to charge due to permeability reductions related to the GH formation in the surrounding units, some self-reorganization of gas hydrate post formation, or to the inability to charge certain portions of the sand due to too high reservoir quality (lack of sufficient trap or increased fluid flow capacity that inhibited sufficient methane concentration to enable gas hydrate formation). This latter interpretation appears to be supported by the gamma-ray log, which shows the bounding gas-hydrate-free sands to have lower shale content, although the impact of the excessive hole washout on the LWD gamma-ray tools is not clear. It is also possible that these units are lithologically similar to the gas-hydrate-bearing sands, with unrecognized faulting or stratigraphic compartmentalization playing a role in controlling gas hydrate occurrence. Another potential explanation that may be relevant to the relationships at the base of the accumulation is that the BGHS at this location may not be manifest as a single sharp boundary, but as zone where

conditions fluctuate spatially in and out of stability conditions reflecting subtle and local variations in geochemical and petrophysical properties in a manner similar to that described by Wright et al. (2005). The pre-drill hypothesis that gas hydrate could extend higher into the GHSZ than indicated in the seismic data was not confirmed, as a sharp top to the gas hydrate occurrence was observed at the H well, despite the overall lithologic gradation of the formation. Where a more gradational top was observed at the GC955-Q well, a strong seismic event nonetheless occurs. The exploration concept of potential elevated gas hydrate occurrence in sand in vertical zones related to major faults was not clearly tested in the GC955 program as the sand units did not extend high enough in the section to occur where the wells crossed clearly-imaged faults. However, gas hydrate did occur in muds in these faulted intervals in the GC955-H well (Lee and Collett, 2012) and due to the total lack of any indication of the fracture-filling gas hydrate in the nearby and unfaulted Q well, this occurrence is clearly limited in lateral extent and likely represents a largely vertical feature directly tied to the fault geometry. 3.7. JIP Leg 2 results: AC21 3.7.1. AC21 objectives The proposed JIP Leg II drilling sites in EB992 and AC21/65 lie within the Diana minibasin in the northwestern GoM. The

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Fig. 24. LWD data from the GC955-Q well showing the logged portion of the gas hydrate-bearing sand interval (green color). Drilling complications precluded data collection through the full potential reservoir section. (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)

minibasin produces significant oil and gas from deeper Lower Pleistocene and Upper Pliocene reservoirs from the Diana, Hoover, and Rockefeller fields (Sullivan et al., 2004). The JIP Leg II targets test an areally-extensive peak-over-trough amplitude anomaly associated with a shallow sand body as confirmed by the 1995 EB992 #001 “Rockefeller” well. Regional mapping of the seismic attributes revealed a unit of complex depositional architecture, including a complex array of laterally-coalescing elongate geobodies (Frye et al., 2010). Analysis of the 1995 LWD resistivity data indicated potential Sh ranging from 20 to 40% (Frye et al., 2010) an estimate consistent with that derived from analysis of the seismic data (Lee et al., 2012; Shelander et al., 2012). Unlike the primary JIP Leg II targets at the WR313 and GC955 sites, the AC21 targets occur well above the BGHS (w240 m (w800 ft) above) and relatively close to the seafloor (w180 mbsf (600 fbsf)). Locations in both AC21/65 and EB992 were permitted, and while lying more than 8 km (5 mi) apart, provided opportunities to test different settings within a common geologic prospect (see Frye et al., 2010). Although the EB992 #001 well had mitigated much of the geologic risk associated with the AC21 targets, the confirmation of charge was complex. Although evidence for charge is present regionally (ex. Fig. 25), the paucity of major migration pathways, the uniformity and lack of lateral variation of the amplitude response within the target reservoir, even where located close to prospective migration pathways, was a concern. The EB992 #001 log data indicated resistivity is low, but much greater than that seen in wet sands in nearby wells and slightly greater than that in the bounding shales (Frye et al., 2010). The only significant lateral variation in the amplitude response at the top of the unit throughout the AC21-EB992 region appears at the margins of the sand body and is likely a reflection of tuning effects (Frye et al., 2010) suggesting that Sh is generally similar over the extent of the sand body. The sediments are also very young, being no more

than 200,000 years in age (Frye et al., 2010), resulting in concerns as to whether sufficient time was available to fully charge the unit. Notably, the modest pre-drill Sh estimate of w30% Sh represents an intermediate level not commonly seen in reservoirquality sands. The primary hypothesis to be tested at the AC21/EB992 site was that gas hydrate could occur at low to moderate Sh in young, regionally extensive, reservoir-quality sands well above the BGHS. Furthermore, the possibility that the 1995-vintage EB992 #001 LWD data were unreliable due to poor logging conditions or perhaps complex reservoir architecture (such as very-thinly interbedded sands and shales) indicated a potential that a high-quality LWD dataset might reveal substantially different, and potentially higher, Sh. 3.7.2. AC21 results JIP Leg II drilled two wells into the prospective shallow sand facies in AC 21 (Fig. 26). The AC21-A location tested an anomalous geophysical response in which the regional single peak-trough pair is replaced by four higher-amplitude seismic events. The well encountered two sands (4 and 17 m (13 and 56 ft) thick) separated by a 5 m (15 ft) mud unit (Fig. 27). Resistivity in these sands was consistent at w2 U-m; slightly above the 1.5 U-m recorded in the surrounding muds and very similar to that observed in the EB992 #001 well. The AC21-A well also recorded slightly elevated resistivity (1e2 U-m) within a 79 m (258 ft) thick shale-rich section at a depth of 1888 mbsf (6193 fbsf) that extended to the approximate position of the inferred BGHS (Fig. 28). This likely represents the occurrence of disseminated gas hydrate at low Sh. The AC21-B well targeted an amplitude response more typical of the regional accumulation. The well encountered a single sand body 38 m (125 ft) thick at a depth of 1662 mbsf (5452 fbsf: Fig. 27). The resistivity of the sand (1.8e2.5 U-m) was similar, but slightly

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25

Fig. 25. Seismic data from Alaminos Canyon 21, showing evidence of gas charge and the relative nature of the shallow sands targeted by JIP Leg II. Seismic dataÓ 2011 WesternGeco. Used by permission.

more variable, than observed at the A well, perhaps reflecting greater lithologic variation within the unit. Despite concerted efforts to mitigate sand wash-out while drilling through the reservoir section (Collett et al., 2010), significant hole erosion could not be avoided in either well, and the LWD data quality for the sands is therefore poor. The AC21 drilling confirmed the target horizon is a thick, widespread, sand unit (see Boswell et al. (2012) for discussion of the depositional origin of the unit) with resistivity slightly elevated

with respect to the bounding shale units. Unfortunately, the poor quality of the log data greatly complicates the ability to constrain the occurrence or saturation of gas hydrate, although the extensive hole washout and low resistivity suggest that Sh in the sand is not high. Lee et al., (2012), present models that correct for borehole washout and integrate the available LWD and seismic data to determine that gas hydrate most likely exists in the range of 8e28% Sh. If gas hydrate is present in the unit, the limitation on its concentration is most likely insufficient charge (see Frye et al.,

Fig. 26. LWD data from the two wells drilled at the Alaminos Canyon 21 site posted over seismic data. Seismic dataÓ 2011 WesternGeco. Used by permission.

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Fig. 27. LWD data over the main sand reservoir targets for the AC21-A and AC21-B wells.

2010) due potentially both to the young age of the sediment and the lack of major gas migration pathways into the unit. In this unit, it may be the case that a substantial contribution to any gas charge is local and biogenic (per Malinverno, 2009). Alternatively, the charge

may be via migration through an invasive network of nearly vertical fractures, providing an unfocused, ubiquitous charge of upwardly migrating gas (Miller et al., 2012). The possibility that gas hydrate is not present, and that the observed resistivity and seismic responses

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27

Fig. 28. LWD data for the AC21-A well showing the deeper occurrence of inferred gas hydrate in fine-grained sediments at the base of gas hydrate stability.

Fig. 29. Comparison of general nature of gas hydrate occurrence and the geophysical expression of the BGHS in two end-member generalized marine settings of A) an area of generally homogeneous geology and non-focused fluid flux (conducive to the formation of regional BSRs); and B) an area of highly heterogeneous geology (such as the northern Gulf of Mexico) that results in highly-focused fluid flux pathways and preferred expression of the BGHS as discontinuous, locally-pluming features.

are due to other factors, such as unexpected mineralogy, overconsolidation, or other factors, cannot be fully discounted. 4. Summary Gas hydrates are a well-documented component of the shallow sediments in the deepwater GoM. Following the initial discovery of

outcropping gas hydrates at the Bush Hill site in the early 1980s, it was widely believed that the vast majority of gas hydrate in the GoM, and particularly any gas hydrates at elevated concentrations, would occur on or very near the seafloor in association with faultrelated vent sites. This perception was widely supported by indications that methane flux was highly localized within the basin, with broad areas of the seafloor showing limited evidence of

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significant gas supply to the shallowest sediments. High heat flow and high salinities related to salt-enabled focused flow paths also served to further limit the potential for subsurface gas hydrates. A lack of industry reports of encounters with gas hydrate within the shallow sections of more than 1200 deepwater industry wells further supported this general conclusion. While industry was apparently very successful in its effort to avoid gas hydrate (Smith et al., 2005), detailed examinations for shallow hazards appraisal (see McConnell et al., 2012), began to uncover compelling evidence for deeply buried gas hydrate in the GoM. In 2003, the first industry well designed to gather quality log data within the GHSZ documented 18 m (60 ft) of gas hydrate at high Sh in sands in AC818 (Boswell et al., 2009). Industry’s desire to more fully understand the occurrence and implications of subsurface gas hydrates in the deepwater GoM was further advanced with the formation of an international JIP, managed by Chevron in partnership with the DOE. The 2005 JIP Leg I field program focused on drilling hazard issues, and resulted in the validation of its wellbore stability model and the determination that safe protocols existed for drilling the fine-grained near-seafloor sediments that typify the GoM, given their likely occurrence at low saturations (Birchwood et al., 2007). Leg I also provided critical advances in field sampling technologies, provided the first test of pre-drill estimates of subsurface gas hydrate in an exploration context, and uncovered the first deeply-buried occurrence of strata-bound, fracture-filling gas hydrate in clay-dominated sediments. Upon the successful conclusion of the Leg I drilling program, the JIP refocused its effort in 2006 on assessing the occurrence and implications of gas hydrate at high saturation, which necessitated a search for gas-hydrate-bearing sands. This effort coincided with an independent program within the BOEM to conduct a comprehensive assessment of natural gas resource volumes associated with gas hydrate in the northern GoM. In 2008, an initial estimate of 607 tcm (21,444 tcf) of gas-in-place with 190 tcm (6710 Tcf) occurring within sand reservoirs (Frye, 2008), was released. By early 2009, scientists collaborating with the JIP had moved beyond the traditional reliance on BSRs and surficial indicators of methane flux by prospecting specifically for gas hydrate-bearing sands using traditional geological/geophysical hydrocarbon exploration approaches as tailored for gas hydrates. JIP Leg II tested this approach in the spring of 2009 by drilling seven wells at three sites. Of these wells, six encountered gas hydrate in sand reservoirs consistent with pre-drill estimates (see Shelander et al., 2012). JIP Leg II drilling at the WR313 site confirmed the geologic model linking aligned anomalous seismic amplitudes and associated phase reversals with gas hydrate occurrence in sands in an interbedded sand-shale sequence. Shedd et al., (2012), report that similar “discontinuous BSRs” occur at as many as 85 additional locations in the GoM with more than half of those with good evidence of associated phase reversals. The WR313 drilling also confirmed that gas hydrate occurrences in sand reservoirs is not restricted to locations in close proximity to the present BGHS, but may occur over large distances and persist well above the BGHS provided the occurrence of sufficient reservoir quality. Lastly, the WR313 program revealed a widespread, 125 m (400 þ ft) thick, shallow, and clay-dominant unit that may hold large quantities of methane as low saturation, fracture-filling gas hydrate (Frye et al., 2012; Lee et al., 2012; Cook et al., 2012). Regional seismic data indicate that this occurrence is regionally extensive and associated with a specific stratigraphic interval (“strata-bound”), with the fracturing perhaps being related to the physical properties of the sediment and not to a localized area of enhanced vertical fluid flow as seen in other fracture-filling gas hydrate occurrences. The JIP drilling program at GC955 re-enforced the model of direct geophysical indication of gas hydrate-bearing sands through

observation of strong “leading peak” amplitudes. The GC955-I well, which did not encounter substantial gas hydrate, had combined high potential for sand with modest geophysical indicators in an area of uncertain charge and off-structure (non-trapping) position, further underscoring the need to fully consider all elements of the petroleum system elements. Two wells drilled in structurallyfavorable positions with abundant evidence of gas sourcing encountered thick gas hydrates occurrences in sand-rich, faultcompartmentalized, reservoirs (Boswell et al., 2012). However, the specific controls on the limits of the gas hydrate occurrence are poorly understood. The close association of gas-hydrate-bearing and water-bearing sands observed in the GC955-H well is difficult to fully explain with the available data, although many possibilities exist. Core samples collected and analyzed under retained in situ conditions will be needed. The findings of the AC21 program are somewhat inconclusive due to poor log quality. The available log and seismic data indicate that gas hydrate may be present at low to moderate saturations throughout a regionally extensive sand unit well above the BGHS (Lee et al., 2012; Shelander et al., 2012). As with GC955, core samples collected and analyzed under retained in situ conditions will be needed to further constrain these estimates. Overall, recent work in the Gulf of Mexico, highlighted by the 2008 BOEM assessment and the 2009 JIP Leg II drilling program, indicate the potential for substantial occurrence of gas hydrate in the subsurface of the GoM with implications for both resource recovery (see Frye et al., 2012; Myshakin et al., 2012) and geohazards (see McConnell et al., 2012). These findings have enabled an increased appreciation for the geologic complexity of the GoM and the impact of that complexity on the nature of gas hydrate occurrence in the basin (Fig. 29). Whereas in other less complex settings, a more regionally-homogeneous stratigraphy and supply of gas can produce strong and continuous “bottom-simulating reflectors” and “blanking zones”, the focused fluid migration, structural heterogeneity, and widespread occurrence of reservoir facies in the GoM may result a more varied geological-geophysical manifestation of gas hydrate occurrence (see Shedd et al., 2012). The success of the JIP drilling program, which discovered gas hydrate at high Sh in 4 of 7 wells drilled (and at expected Sh in 6 of 7 wells), validates the efficacy of the prospecting/evaluation approach used in to support the JIP and BOEM programs. Particularly, delineation of gas hydrate at high Sh in sand reservoirs can often be reliably predicted where it occurs at seismically-resolvable thickness, and where geologic interpretation supports the supply of gas to sand-prone facies. The results may also provide new insights to support the further improvement of the regional gas hydrate resource assessment in the GoM. Notably, findings from the WR313 and GC955 sites suggest that a significant component of the gas charge to the GHSZ may have migrated substantial distances from deeper, potentially thermogenic, sources that have not been rigorously evaluated in prior resource assessment efforts. Acknowledgments The authors wish to thank those that contributed to the BOEM 2008 gas hydrate assessment, as well as all those that have supported the Gulf of Mexico Gas Hydrate Joint Industry Program from its inception in 2000. Special thanks to those that contributed to the selection and evaluation of JIP Leg II drill sites; scientists at AOA Geophysics that conducted the JIP Leg II pre-site hazards survey, our colleagues in Schlumberger, Chevron, and Columbia University who supported Leg II pre-drill operational planning; the science team from Columbia University and BOEM that sailed on Leg II and who enabled the collection of and analysis of Leg II LWD data; the captain and crew of the Helix Q4000; the Chevron drill site

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supervisors and safety engineers; Baker-Hughes mud engineers and many others. Lastly, we wish to acknowledge the support of the members of the Executive Board of the Gulf of Mexico Gas Hydrates Joint Industry Project. References Archer, D., 2007. Methane hydrate stability and anthropogenic climate change. Biogeosciences 4, 521e544. Badalini, G., Kneller, B., Winkler, C., 2000. Architecture and Processes in the Late Pleistocene Brazos-Trinity Turbidite System, Gulf of Mexico Continental Slope Proc. GCSSEPM 20th Ann. Res. Conf., 16e34. Balczewski, J., Boswell, R., Collett, T., Baker, R., 2011. International collaboration on deepwater natural gas hydrate continues e Gulf of Mexico gas hydrate JIP: past, present, and future. Proc. 7th Int. Conf. Gas Hydrates, 6. Edinburgh, Scotland. Beaubeouf, R., Abreu, V., Van Wagoner, J., 2003. 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