OTC-24219

Best practices for the collection, analysis, and interpretation of seabed geochemical samples to evaluate subsurface hydrocarbon generation and entrapment Michael A. Abrams, Apache Corporation

Copyright 2013, Offshore Technology Conference This paper was prepared for presentation at the Offshore Technology Conference held in Houston, Texas, USA, 6–9 May 2013. This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessar ily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright.

Abstract The detection and measurement of migrated hydrocarbons in near-surface marine sediments is a relatively routine exploration method to investigate issues of hydrocarbon charge. The presence of near-surface migrated thermogenic hydrocarbons provides strong evidence that an active petroleum system is present, as well as critical information on source, maturity and migration pathways. There are multiple methods currently applied by industry to collect, prepare, extract, and analyze migrated hydrocarbons within near-surface marine sediments. To improve the detection of seabed thermogenic hydrocarbon seepage, core samples should be collected along likely major migration pathways (cross stratal leakage features) identified by conventional deep seismic and high-resolution seafloor imaging technology. Real time imaging provides greater detail to confirm targeted features for more precise core targeting. Not all targeted cores will hit the designated feature and thus collecting replicates along major migration features is critical. Collecting sediment samples below the Zone of Maximum Disturbance (ZMD) to avoid possible transition zone alteration effects and recent organic matter (ROM) masking problems is critical. Choosing a coring device best suited for local seabed conditions will maximize both penetration and sediment recovery. Multiple sections per core should be collected at variable depths providing a geochemistry profile. Geochemical analysis should include a full range of hydrocarbon types; hydrocarbon gases (C1 to C5), gasoline plus range hydrocarbons (C5 to C12), and high molecular weight hydrocarbons (C12+). Two types of geochemistry samples should be collected; one to capture the volatile light hydrocarbons (C1 to C12) and non-hydrocarbon gases; and a second for the higher molecular weight hydrocarbons (C12+). The light hydrocarbons require special handling and containers to limit volatile loss and prevent post sampling microbial alteration. Bulk sediment measurements such as quantity of organic matter and sand percent can provide additional important non geochemical information. Identification of background versus anomalous populations is critical when evaluating sub-surface migrated seabed hydrocarbons. Sediment hydrocarbons are normally highly altered and may not resemble conventional reservoir oil. Novel petroleum related hydrocarbon compounds need to be examined to fully evaluate organic maturity and source facies. Mapping thermogenic hydrocarbon seeps (oil and gas) relative to key cross-stratal migration pathways via fluid flow modeling and seismic attribute analysis provides an effective petroleum systems tool to better understand the near-surface petroleum relative to subsurface hydrocarbon generation and entrapment. Bear in mind not all surface geochemical surveys will result in the detection of statistically valid thermogenic hydrocarbon seepage.

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Introduction The detection and measurement of migrated hydrocarbons in near-surface marine sediments is a relatively routine exploration method to investigate issues of hydrocarbon charge (Jones and Drozd, 1983; Horvitz, 1985; Brooks and Carey, 1986; Klusman, 1993; Schumacher and Abrams, 1996; and Schumacher and LeShack, 2002; Abrams, 2005; Abrams and Dahdah, 2011). The presence of near-surface migrated hydrocarbons can provide strong evidence an active petroleum system is present as well as critical information on source, maturity and migration pathways (Abrams et al., 2001; and Abrams 2005). The rate and volume of hydrocarbon seepage to near-surface sediments controls the surface geological, geophysical, biological, and geochemical expression (Roberts et al., 1990) which can range from macroseepage to microseepage. Macroseepage contains large volumes of hydrocarbon leakage and is expressed as high pore space gas saturation and/or oil staining; and associated with near-surface features such as fault scarps, pockmarks, hard grounds, mud-volcanoes, and/or chemosynthetic communities (Abrams, 2005). Microseepage contains lower volumes of hydrocarbon leakage and the physical and geochemical expression will become more difficult to identify with episodic and/or low level seepage (Abrams, 2005). There are multiple methods currently applied by industry contractors to collect, prepare, extract, and analyze near-surface migrated hydrocarbons within marine sediments (Bernard, 1978; Horvitz, 1985; Bjoroy and Ferriday, 2002; Abrams, et al. 2001; Abrams, 2005, Abrams and Dahdah, 2010). The purpose of this paper is to provide guidance for best practices based on studies undertaken during a multiyear laboratory and field Surface Geochemistry Calibration study (Abrams, 2002) at the University of Utah’s Energy and Geoscience Institute.

Sample Collection Seabed sampling has evolved with more effective coring, geophysical, and navigation tools; as well as better understanding of migration and near-surface processes. The early days of grid surveys with shallow cores (less than 1 meter) and no real-time seismic have been replaced with pre-survey high resolution seismic and remote sensing data to identify major migration pathways and possible seep features, deep coring technologies to collect sediment samples below the Zone of Maximum Disturbance (Abrams, 1992), and tracking devices to assist in the placement of corer on the designated target. Pre-Cruise Core Site Selection Seabed geochemical cores can be collected using a grid spacing pattern over the area of interest, or target features of interest (Abrams, 1992 and 1996). Grid surveys are undertaken in areas where the processes controlling the migration of petroleum to the surface are assumed to be dominantly vertical, thus, causing a surface pattern reflective of a subsurface petroleum accumulation. The resulting near-surface geochemical measurements are contoured to look for surface patterns related to a subsurface petroleum accumulation. The apical (directly above) or halo (around the edges) surface geochemical anomaly is then used as evidence a petroleum charged trap is present (Horvitz, 1985). In selected cases, geochemical measurements and/or ratios can be used to assist in the evaluation of oil versus gas (Jones and Drozd, 1983). Grid surveys should only be used when sufficient surface geochemical calibration measurements are available to confirm near-vertical leakage is present within the area of interest. The more common approach in offshore seabed geochemical surveys is to target migration pathways which contain seismic or other evidence of hydrocarbon leakage. This approach has been called site specific (Abrams, 1992 and 1996). Petroleum from subsurface accumulations, or a mature source rock, will leak to the near-surface via buoyancy driven forces along major cross stratal breakage (faults and fluid expulsion features) or along major fluid flow pathways (hydrodynamic). The leaking fluids and gases can exhibit seismic expressions (acoustic anomalies) and/or seabed morphological features depending on the hydrocarbon phase, leakage rates, and volume as well as sediment type. These features include pockmarks (seabed depression), seabed hard grounds (carbonate), HRDZ subsurface hard grounds (hydrocarbon-related diagenetic zone, O’Brien, 1995), wipe out zones (gas chimneys), acoustic blanking (reflection discontinuity and amplitude loss creating distortion zones), BSR (bottom simulating reflector, gas hydrate related), water column gas anomalies, near-surface bright spots, and seismic event push down (slow down signal due to gas) (Figure 1a and b). A surface and/or near-surface features map should be generated to evaluate distribution of these anomalous features relative to regional geology and basin features. The subsurface to surface fluid migration

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pathways can be mapped in 3D or time slice using tools such as the Chimney Cube (Ligtenberg, 2003). Swath bathymetry is also a valuable technique for identifying surface petroleum migration features particularly in areas of active surface seepage (Dolan et al., 2004). The next key question is how many cores are required to fully evaluate a study area? Multiple factors should be considered to address this question, including area size, number of potential leakage features, and most importantly, project budget. In most seabed geochemical surveys, budget is the single most constraining factor in defining the number of cores to be collected. A good general rule of thumb is at least 100 cores should be collected in frontier exploration areas with 200 to 300 the more likely target. Keep in mind most frontier exploration areas yield hit rates less than 5% depending of seepage type (active versus passive) (Abrams, 2005; Abrams and Dahdah, 2011). The hit rate is defined as the number of cores with strong evidence of thermogenic hydrocarbons based on multiple geochemical parameters versus total number of cores. If you collect 100 cores, chances are less than 5 will yield confirmed thermogenic seepage and less if you are in an area of passive seepage. Core targets should include a variety of features across the area of exploration interest. Do not concentrate on one type of feature and/or area. Target near-surface features associated with major migration pathways and prioritize potential migration pathways with seismic evidence of near-surface hydrocarbon leakage or calibrated back-scatter signal from a multi-beam bathymetry survey (Dolan et al., 2004). In addition, collect regional reference cores to define the non-seepage sediment signal especially in areas where source rock reworking and/or transported signatures could be present (Abrams and Piggott, 1996; Abrams and Dahdah, 2011; Dembicki, 2010). Collect replicate cores on targeted features which have the greatest potential to contain near-surface migrated hydrocarbons. At least 2 cores should be obtained per target and possibly more if the feature is a high priority target. Real Time Seismic Obtaining real time images of the targeted feature will greatly enhance your seabed geochemical program. An effective real time seismic program requires minimum set up time and sufficient power to obtain good penetration and target resolution. The real time image provides greater detail to confirm the feature is present, extent of feature, and better understand its relationship to active hydrocarbon seepage. In addition, it provides a definitive target location. Hull mounted systems are ideal since they do not require time to launch and retrieve. A focused beam with sufficient power is required to obtain good imaging in deep water environments. Choose seismic equipment that will obtain sufficient resolution to characterize the target, minimal effort to launch and retrieve, and lastly, provide onboard research staff the ability to image targets and adjust coring location as needed (Dembicki and Samuels, 2007 and 2008). Seabed Sampling It is very important to choose a sediment sampling device which will obtain the maximum amount of recovery relative to penetration for the study area’s sediment regime, water depth, and vessel capabilities. There are many corers available to collect near-surface marine sediments and each sediment sampling device has its own water depth and lithology limitations. The device most often used is a gravity corer. Gravity corers consist of a hollow tube (barrel) attached to a weight (core body) (Figure 2a). There are two types of gravity corers, open barrel and piston (Hopkins, 1964). Both systems rely on their weight to push a barrel into the seabed, hence why they are called gravity corers. The open barrel core system consists of a flow thru barrel attached to a corer body with a series of exhaust ports and floating ball or flapper valve which provides an exit for incoming water (Figure 2a). The corer free-falls by releasing the winch brake at a designated distance above the seabed surface. The open barrel gravity corer works best in shelfal to upper slope silts and very fine grained sands (Abrams, 1982). The piston corer is very much like an open barrel corer except it utilizes a trigger weight to initiate the free fall and a stationary internal piston to create a suction that assists in maximizing core recovery and minimize sediment disturbance (Kullenberg, 1947). The piston corer was designed for deep-water fine-grained sediments and has proven to be an effective tool to obtain greater than 4 meters of sediment core in deep water fine grained sedimentary environments (Abrams, 1982). Gravity core recoveries are generally limited by equipment design and sediment conditions (Abrams, 1982). Most standard gravity corers rarely recover more than 3 to 6 meters of sediments in upper to lower slope environments with the exception of the Maxi Piston Corers which can obtain cored intervals in excess of 30 meters. Sediment recovery

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for most gravity corers range from 50 to 80% and will depend heavily on the venting system design, nature of the surface sediment, and internal diameter (Abrams, 1982). Open barrel corer sediment penetration and recovery can be increased by: streamlining core body maximizing velocity and stability during free fall, decrease internal and external wall friction with non-hydrocarbon lubricants (silica based), increase inner barrel flow thru (water exit as fast as core material enters), and increase sediment retention with better valve seal (Abrams, 1982). There are mechanical coring devices which use rotary drilling or vibration to assist sediment barrel penetration without using gravitational forces. One device which has been used in seabed geochemistry is the vibracore. The vibracore consists of a pipe attached to an air pressure or electric vibrating head. The vibrator head will vibrate with high frequency low amplitude motion to facilitate sediment penetration. The older air driven devices are water depth limited generally less than 50 meters. The newer electric vibracore devices can work in water depths up to 1,500 meters. Although initially designed to collect samples in shelfal coarser grained lithologies, the vibracorers have also been used to assist in the collection of compacted and slightly cemented sediments where conventional gravity driven devices may not penetrate. The corer launching and recovery system is also a very important component of seabed sampling to undertake a safe and efficient operation as well as minimize core sample disturbance. The corer launching/recovery system should be designed to allow for corer free fall with efficient braking system, vessel movement during corer operations, fast retrieval to surface in deep water operations (100 to 300 meters/minute), and safe corer recovery in poor sea conditions. One such system designed for an open barrel gravity corer is shown in Figure 2b. This system was designed with an electro-hydraulic core recovery system to minimize deck handling and core disturbance, accumulator to allow for ship movement in high sea conditions, and self contained A-frame system for easy mobilization (Abrams Gravity Coring System – GC2, see Fugro Alluvial Offshore website for details). Locating the corer during deep water coring operations (greater than 1,000 meters) is also critical. There are several acoustic systems currently available to assist in tracking the corer while being deployed in deep water settings. The most common acoustic positioning system used in seabed geochemical operations is the Ultra Short Baseline (USBL) system. The USBL acoustic positioning system can provide 5 to 10 meter accuracy depending on water depth, USBL system, and operator. Keep in mind locating the corer relative to a target can be accomplished using a USBL system but placing the corer on the specific feature is another matter. Data from Abrams and Dahdah (2011) suggest that many cores did not hit the targeted feature based on geochemical results. Trying to move a weighted corer in water depths greater than 1,000 meters from a surface vessel is extremely difficult. The corer will not move in direct response to the vessel movement due to the large distance between the vessel and corer. To date, there is no cost effective system to manipulate the corer directly on the targeted feature. The next advancement in marine sediment sampling will be the ability to place a sediment corer with great precision on the targeted feature.

Onboard Sample Collection Sediment Sampling Protocols Once the corer with recovered sediment has been retrieved, a series of important procedures must be followed to process sediment samples quickly, efficiently, and consistently. The core barrel inner liner with sediment should be removed immediately, taken to a wet laboratory, and cut into sections by deck staff avoiding contamination from lubricants or vessel exhaust fumes. Three sections per core should be collected at designated depths as shown in Figure 3. Replicate (back-up) samples should be collected and stored until primary samples have arrived to the final destination for analysis. Back-up samples will be critical if the primary sediment samples are lost or damaged in transit. In addition, back-up samples can be used to quality control results from primary sample analysis. Sample Type and Containers Two types of geochemistry samples should be collected each requiring special protocols and sample containers. The volatile hydrocarbons (C1 to C12) and non-hydrocarbon gases require special handling since the sediment gases and volatile liquids can be lost relatively easily during sediment handling and preservation process. The higher molecular weight hydrocarbons (HMW) (C12+) are more stable at surface conditions and thus do not require the special handling to minimize volatile loss.

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The most common container used for the collection of volatile hydrocarbons and non-hydrocarbon gases is a 500 ml compression lid non-coated metal can. The two major problems with compression lid non-coated metal cans are rusting and leakage. The non-coated cans will rust relatively quickly and thus cannot store marine sediment samples much beyond a few months. Compression lids are prone to leakage problems if not properly handled and shipped (Abrams and Dahdah, 2010). A screw on cap with a sealing non-reactive gasket system such as the plastic ISOJARS and disrupter canisters (Abrams and Dahdah, 2010) provide the most efficient and fool-proof sealing and storage system. The ideal collection container for HMW hydrocarbon sediment samples would be a clean glass jar. Unfortunately glass jars break easily in transit and thus are not optimal in remote area surveys. Plastic bags are more practical for wet marine sediment samples, however, contaminants from the plastic bags such as phthalates can be a problem (Grosjean and Logan, 2007). These contaminants do not impact the overall interpretation but may appear as major peaks during screening gas chromatography analysis. One way to get around the plastic bag contamination issue is to wrap the sediment sample in aluminum foil prior to placing in plastic bag. This will keep sediment separate from the plastic bag reducing contamination issues. Not all aluminum foil is sufficiently clean to use for sediment sampling. Some commercial aluminum foil may contain coating to prevent sticking which will affect the solvent extraction results. Another option is plasticizer-free plastic bags. Sample Preparation and Preservation Volatile hydrocarbons (C1 to C12) and non-hydrocarbon gases: The preparation procedures used by many of the surface geochemistry contractors include placing a set volume of sediment in a sample container with processed seawater and inert gas (Helium) or air headspace (Abrams and Dahdah, 2010). The amount of sediment to be collected, as well as volume of water and headspace to be added, is important in optimizing the extraction of small concentrations of migrated light hydrocarbons mixed with marine sediments. The most used procedure includes a 1/3, 1/3, and 1/3 mix of sediment sample, water, and gas headspace. According to Bernard (1978), there are two competing issues; forming a mixture thin enough to speed the equilibrium partitioning versus minimizing the fraction of gas left dissolved in the water upon equilibrium. The 1/3, 1/3, 1/3 split allows at least 85% of most soluble gases to partition into the gas phase at equilibrium (methane is 93 to 95%) with the aid of agitation and heating (Bernard, 1978). Note that the addition of water also appears to assist in leakage issues with compression lid non-coated metal cans (Abrams and Dahdah, 2010). Additional special processing is required to prevent post-sampling microbial activity. The method currently used to prevent in-situ microbial activity includes the addition of anti-bacterial agents such as sodium azide followed by deep freezing. The amount of bacteriacide required to prevent microbial activity has not been rigorously examined. To the best of the author’s knowledge, no comprehensive studies have been conducted to evaluate the effectiveness of these anti-bacterial agents, how much is required, or if the anti-bacterial agents impact the geochemistry results. Abrams et al. (2009) indicated super-saturating the sample water with salt and thoroughly mixing sediment with the salt saturated water is an effective method to minimize bacterial activity. In addition, the higher salinities decrease the water solubility such that more of the volatile hydrocarbons will partition to the vapor phase (container headspace) relative to dissolved phase (water sediment mix) assisting in the headspace extraction process. However, the sample container must be resistant to salt solution corrosion. This is an additional plus for plastic containers such as the ISOJARS and disrupter canisters. The amount of salt required to reach saturation can easily be calculated using solubility parameters for salt and water at surface pressure and temperature conditions. To assist in the prevention of microbial activity, the prepared sample should be kept frozen until analysis. Most contractors use a conventional deep freezer (-5 to -10°C) to accomplish this but Bjoroy and Ferriday (2002) suggest a deeper freeze is required to fully prevent microbial activity (-80°C). High Molecular Weight Hydrocarbons (C12+): Approximately 500 ml of sediment is placed in an aluminum foil square using clean spatulas to prevent any contaminations from hand cleaning materials or moisturizers. The sediment sample is tightly wrapped in the aluminum foil square flattening the sediment sample into a pancake making sure there are no air pockets. The aluminum foil sediment sample is placed in a labeled standard plastic sealing bag and deep frozen until analysis.

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SAMPLE ANALYSIS Screening Analysis Program The screening analytical program is conducted on all sediment samples with the purpose of identifying samples with anomalous gas, gasoline plus range, and/or high molecular weight hydrocarbons as well as non-hydrocarbon gases (CO2, N2, and O2) (Figure 4). Hydrocarbon gases (C1 to C5) and non hydrocarbon gases: Sediment gases can reside in the interstitial spaces, bound to mineral or organic surfaces, and/or entrapped in carbonate inclusions (Abrams, 2005; and Abrams and Dahdah, 2010). The terminology used for each sediment gas extraction method generally refers to the physical removal process and not the gas phase. The exact nature (physical binding state) of the gases removed by each procedure is still poorly understood. Interstitial sediment gases are contained within sediment pore space either dissolved in the pore waters (solute) or as free gas (vapor) (Bernard, 1978). The two most common methods used to extract interstitial gases from near-surface sediments include non-mechanical (headspace) and mechanical break up (blender and disrupter). The non-mechanical headspace method utilizes a high speed shaking process to release interstitial sediment gases into container headspace (Bernard, 1978). The mechanical break-up method utilizes blades to assist in the release of interstitial sediment gases (Abrams and Dahdah, 2010). A new sediment gas extraction procedure was developed as part of the Surface Geochemistry Calibration study to break apart sediment without introducing fractionation problems noted with conventional blender methods (Badeira de Mello, et al., 2005; Abrams and Dahdah, 2010). The disrupter was designed to provide mechanical break up capabilities and capture interstitial sediment gases with minimal fractionation and/or alteration (Abrams and Dahdah, 2010). Sediment pass quickly through a fixed blade breaking apart sediment sample and releasing interstitial gases into disrupter container headspace without transferring sample from the shipboard storage container to a blender. The sample transfer has been shown to result in differential volatile fractionation (Abrams et al., 2009). A more rigorous analytical procedure is required to remove bound gases from unconsolidated marine sediments. The

traditional adsorbed gas extraction process requires removal of coarse-grained fraction (greater than 63 m) by wet-

sieving. The less than 63 m fraction is heated in phosphoric acid within a partial vacuum to remove bound hydrocarbon gas (Horvitz, 1985). The Horvitz adsorbed gas method described above has been modified by Whiticar (2002). Whiticar’s microdesoprtion method uses the whole unwashed sample and removes interstitial sediment gas prior to bound gas extraction using a closed vessel system (Whiticar, 2002). Another adsorbed gas extraction method called ball mill utilizes a metal ball within a stainless steel container to pulverize the sediment and release bound sediment gases into container’s headspace (Bjoroy and Ferriday, 2002). The released gases are collected from the ball mill container’s headspace through a septum. Laboratory (Abrams and Dahdah, 2010) and field (Abrams and Dahdah, 2011) calibration studies demonstrate selected interstitial gas extraction methods will provide sediment gas compositions and compound specific isotopes similar to laboratory charged or migrated reservoir gases. However, the gas-charged experiments indicate the adsorbed and ball mill gas extraction laboratory procedures alter the original charge gas composition resulting in gases with elevated gas wetness (ethane plus hydrocarbons) (Abrams and Dahdah, 2010). Similar observations were made in field experiments comparing near-surface adsorbed sediment signature relative to reservoir gases (Abrams and Dahdah, 2011). It is the author’s recommendation to use an interstitial gas extraction method such as the disrupter (Abrams and Dahdah, 2010) or can headspace (Bernard, 1978) with a tight sealing storage container and water preparation procedure to best remove and analyze migrated sediment gases (Abrams and Dahdah, 2010). Gasoline plus range hydrocarbons (C5 to C12): The gasoline plus range petroleum hydrocarbons (middle boiling point hydrocarbons) comprise of molecules with five to twelve carbons (C5 to C12) arranged in linear, branched and cyclic aliphatic structures along with monoaromatic hydrocarbons such as benzene, toluene and o-, m-, and p-xylenes. To date, few surface geochemical surveys have attempted to evaluate the gasoline plus range hydrocarbons in near-surface marine sediments. Sampling the C5 to C12 hydrocarbons in near-surface sediments requires a method which can capture and analyze the middle boiling point range hydrocarbons with minimum fractionation. Standard solvent extraction methods will not work since the solvents currently used are within the similar boiling point range as the hydrocarbons of interest.

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Conventional headspace gas analysis is the most common sediment extraction method used to evaluate gasoline plus range hydrocarbons in unconsolidated shallow marine sediments. This method has been proven to work with fresh macroseepage samples but is not an effective extraction method for low level seepage samples (Abrams et al., 2009). A second method used by industry is the Gore Sorber® module. The Gore Sorber® method evaluates hydrocarbons in the C2 to C20+ carbon range using a module constructed of GORE-TEX ePTFE (polytetrafluoroethylene) and sorbent filled collectors. Modules are analyzed via thermal desorption coupled with mass spectroscopy. The passive sampling method was modified for marine geochemical surveys. The Gore Sorber® module is placed in a special glass container with a designated volume of sediment taken from the core sample instead of placing the sorbers in the soil for several weeks. The Gore Sorber® method and their current offshore sampling protocols will provide quantitative information on sediment gasoline range hydrocarbons based on field studies conducted as part of the SGC research project (Abrams, et al., 2009). A new protocol developed as part of the SGC research program uses Headspace Solid Phase Microextraction (HSPME). HSPME will also provide sediment gasoline plus range hydrocarbons analysis (Abrams, et al., 2009). The sample is collected after the disrupter headspace volatiles have been collected using a fused silica HSPME assembly. The recommended HSPME assembly is made up of 100 PDMS (polydimethylsiloxane) fiber with 100 micron thickness coating. The HSPME assembly is inserted into the disrupter headspace for a 20 minute extraction, then manually injected onto split/splitless Gas Chromatography (GC) inlet for desorption (Abrams, et al., 2009). The HSPME method relies on “equilibrium” between sample, headspace, and fiber providing a representation of the gasoline plus range hydrocarbons contained within the sediment sample. Laboratory and field studies indicate HSPME will provide a relatively inexpensive semi quantitative analysis of the sediment gasoline plus range hydrocarbons (Abrams et al., 2009) but the Gore Sorber® thermal extraction method combined with a mass spectrometry provides more compositional detail which may prove to be very helpful in evaluating seep hydrocarbon source and maturity. Higher molecular weight hydrocarbons (C12+): The most common screening procedures used by industry to evaluate presence of migrated high molecular weight hydrocarbons thermogenic hydrocarbons (C12 plus) include solvent extraction followed by extract gas chromatography and excitation-fluorescence mapping (Total Scanning Fluorescence, TSF). A dried sediment sample is ground to a uniform size; an aliquot by weight is extracted with an organic solvent (Soxhlet or accelerated solvent extractor), and lastly concentrated then examined by extract gas chromatography and Total Scanning Fluorescence analysis. Comparison of different extraction solvents indicates that both n-hexane (low polarity) and dichloromethane (DCM) (more polar) are suitable for marine sediment petroleum hydrocarbons screening (Logan et al., 2009). However, DCM may be more effective for the extraction of UCM (unresolved complex mixture) material (Logan et al., 2009). UCM quantification is important in the screening process to determine the presence or absence of migrated thermogenic hydrocarbons (Abrams and Dahdah, 2011). Also note whole extract gas chromatography analysis using short column and fast temperature ramp helps accentuate the UCM thereby enhancing the ability to identify migrated thermogenic hydrocarbons (Logan et al., 2009). The TSF fluorescence spectrometry method detects and measures organic compounds containing one or more aromatic functional groups (Brooks et al., 1983). Sediments are irradiated with light scanning from about 250 to 500nm at 10nm intervals in a spectrometer. The fluorescence emissions spectrum is recorded for each excitation wavelength scanning from about 250 nm to 500 nm building a 3-D spectrum. The SGC laboratory and field studies, as well as studies undertaken by Geoscience Australia, demonstrate TSF is not a quantitative method and in many cases will provide misleading results (Edwards and Crawford, 1999; Logan et al., 2009; Abrams and Dahdah, 2011). The SGC studies do not support using TSF as a reliable seabed geochemistry screening tool. Similar high molecular weight hydrocarbon screening information is already captured with the extraction GC analysis. Advanced Analysis Program The advanced analysis program is designed to determine origin of the anomalous hydrocarbons using more advanced analytical methods such as isotope ratio gas chromatography-mass spectrometry (IR GC-MS) and gas chromatography-mass spectrometry (GC-MS).

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Hydrocarbon gases (C1 to C5): Gas composition by itself will not provide sufficient information to fully evaluate anomalous sediment gas origin. Compound specific isotopic analysis from IR GC-MS analysis is critical to determine gas maturity and source facies as well as potential mixing with in-situ derived gases and secondary alterations (Abrams, 1989; Abrams 2005, and Abrams and Dahdah, 2011). Several other factors may affect sediment gas concentration and composition. Published studies by Horvitz (1972) and Abrams (1996 and 2005) demonstrate surface geochemical signatures will vary with sediment size, type, and organic content. The quantity of organic matter, usually expressed as percent total organic carbon (% TOC), is measured with a Leco Carbon Analyzer. The TOC measurement is also very helpful to evaluate presence of reworked source rock within recent soil-sediment. The sediment sample lithology can be easily evaluated quantitatively by simply calculating

the sand percent (fraction greater than 63 m by either weight or volume). Higher molecular weight hydrocarbons (C12+): When anomalous high molecular weight hydrocarbons are found with screening procedures, further molecular characterization is very important to understand origin of the anomalous hydrocarbons. GC-MS, also known as biomarker analysis, provides detailed molecular information on chemical biological markers. Biological markers are chemical compounds which can be linked to a known biological precursor and provide key information on source facies and organic maturity (Peters and Moldowan, 1993). Key biomarker compounds can be measured in oils and seep extracts, therefore, providing a method to correlate surface seep to subsurface oils and/or source rocks. A Gulf of Mexico Marco Polo field survey undertaken as part of the SGC study demonstrates the importance of biomarker data to assist in detecting and interpreting low concentration petroleum seepage (microseepage) (Dembicki, 2010). Extract biomarker data on macro and micro seepage sediment samples provides a means to characterize the ROM contribution to the biomarker signal and in turn allows for the identification of migrated thermogenic hydrocarbons when the concentration of seeped oil is low relative to ROM (microseepage). Dembicki (2010) also noted the hopanes and steranes will be more suspectable to near-surface microbial alteration in the higher concentration samples (macroseepage), whereas the tricyclic/tetracyclic terpanes, diasteranes, monoaromatic steroids, and triaromatic steroids are more resistent. The Marco Polo biomarker studies by Dembicki (2010) on replicate samples demonstrate care must be taken to recognize recent organic matter contributions and that failure to understand these processes can lead to incorrect interpretations. Additional Sample Types and Analysis Ocean Surface Slick Evaluation: Several methods are currently available to collect and evaluate ocean surface slicks. The old school method uses Nybolt adsorbent material placed in the slick using a pole then stored frozen until analysis. The SGC field and laboratory studies tested several other methods (Abrams and Logan, 2010). The study determined two sampling methods are required to properly collect volatile light hydrocarbons (wet gas and gasoline plus range) and high molecular weight (C12 plus) hydrocarbons (Abrams and Logan, 2010); Gore Sorber® slick sampler and General Oceanics Model 5080. The Gore Sorber® slick sampler is a modified version of the soil sampling module and uses Gore’s proprietary thermal extraction mass spectrometry analysis. This Gore Sorber method best captures the fresh seepage which contains the light hydrocarbon fraction. The General Oceanics Model 5080 Oil Sampling Net Kit with a DCM solvent extraction works best for the higher molecular weight hydrocarbon (C12 plus) fraction including petroleum derived biomarkers. Sediment Microbial Analysis: In selected geological settings, the measurement of near-surface sediment microbial populations may be an effective tool in seep zones with very low seepage rates and in-situ alteration problems. Near-surface microbial populations have been used to evaluate potential hydrocarbon seepage (Schumacher, 1996) such as GeoMicrobial’s Microbial Oil Survey Technique (MOST) and MicroPro GmbH Microbial Prospection for Oil and Gas (MPOG). Both methods assume there is a direct relationship between the hydrocarbon concentrations in near-surface sediments and selected microbial populations. These two methods culture surface sediment samples (top 20 cm) in the laboratory using a petroleum proxy to evaluate microbial populations which are believed to be related to petroleum leakage. These methods will only culture 1 to 3% of in situ microbial population and thus may not be the most effective method to examine near-surface microbial populations related to subsurface hydrocarbons (Ashby et al., 2007). A new method called SARD, Serial Analysis of Ribosomal DNA, was tested in the SGC study. SARD is a DNA based, culture independent, method to evaluate seabed seepage microbial communities. DNA sequencing of the 16S rRNA gene is used as a proxy for corresponding genome (Ashby et al., 2007). The method uses PCR-amplification of 16S rRNA gene from genomic DNA followed by cloning and sequencing. The SGC study indicates SARD can provide a

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more robust method to evaluate low level near-surface seepage within selected surface sediment conditions (Ashby et al., 2007).

Interpretation and Integration Examination of seabed geochemical survey interpretations relative to post-drill results indicates many of the “failures” were due to poor interpretations and lack of integration (Abrams, 2005). Proper interpretation of near-surface geochemical data requires recognition of background and anomalous populations, indigenous biological material (recent organic matter) contribution, transported hydrocarbon seepage, reworked source rock, in-situ or post-sampling microbial alteration, field or laboratory contamination, and sampling fractionation-partitioning effects (Abrams, et al., 2001; Abrams, 2005; Abrams, et al. 2009; Abrams and Dahdah, 2010; and Abrams and Dahdah, 2011). Proper integration requires the consideration of interpreted surface geochemical data in context with other data types, typically seismic but can also include geological observations. Hydrocarbon and non hydrocarbon gases: The identification of background versus anomalous signatures for near-surface hydrocarbon and non-hydrocarbon sediment gases is extremely important. The most common mistake made by interpreters is to identify a variable background signal as migrated thermogenic hydrocarbons (Abrams, 2005). Another common error is assuming the “anomalous” samples represent migrated thermogenic hydrocarbons. The anomalous samples could also reflect other factors such as in-situ microbial activity, variation in sediment type, differences in sampling depths, variation in sampling period, and/or secondary alterations (Abrams, 2005). The first step in evaluating seabed sediment gases is to identify the background population relative to anomalous population using a graphical method such as a simple histogram or cumulative frequency plot. The anomalous population should have total gas concentrations significantly greater than the in-situ background population (orders of magnitude). Consideration should be made that the background signal is likely represented by a log-normal distribution. The second step is a Wet Gas Fraction (∑C2 – C5/∑C1 – C5) versus Total Hydrocarbon Gas (∑C1– C5) cross plot (Figure 5a). Areas with thermogenic hydrocarbon seepage will display four distinctive group of samples; background with low wet gas fraction, background with elevated wet gas fraction (fractionated), anomalous with low wet gas fraction, and anomalous with elevated wet gas fraction (Figure 5b). The anomalous samples with elevated wet gas fraction are more likely to be related to migrated thermogenic sediment gases. Compound specific isotopic analysis will be required to confirm. The anomalous with low wet gas fraction samples may also be thermogenic but could also be localized microbial generated gas. Not all seabed geochemical surveys will recover migrated thermogenic hydrocarbons and thus contain all four groups. Additional plots such as Total Hydrocarbon Gas versus depth below surface, Wet Gas Fraction versus depth below surface, percent sand versus Total Hydrocarbon Gas, and Total Organic Carbon versus Total Hydrocarbon Gas are helpful to confirm the anomalous population is real and not related to sampling depth or sediment type. The compound specific carbon isotopic ratio data provides additional information critical in determining origin of anomalous gas, thermogenic or microbial. Thermogenic methane is enriched in

13C relative to microbial derived

methane with most values ranging from 13

C1 -50 to -35 per mil. Microbial gases vary from 13

C1 -120 to -60 per mil (Whiticar, 1999). Examining the isotopic separation between methane and ethane as well as ethane and propane will

assist in evaluating gas maturity and mixing (James, 1983 and Schoell, 1983). Hydrogen isotopes (1H,

2HD) can

provide additional information to unravel complex generation and alteration history. The DCH4 for methane derived

from bacterial carbonate reduction ranges from -250 to -150 per mil whereas the DCH4 values for methane derived from bacterial methyl type fermentation range from -375 to -275 per mil. Thermogenic methane deuterium values range from -300 to -100 per mil (Schoell, 1983). Conventional gas wetness (wet gas fraction) and methane carbon isotopic cutoffs values used for reservoir hydrocarbon gases do not always work for near-surface sediment gases and thus much caution should be used when plotting seabed gas data on charts designed for reservoir gases. The field sampling, collection process, and in some cases analytical procedures, may result in compositional fractionation (loss of methane relative to the wet gases) (Abrams, 2005; Abrams et al., 2009; and Abrams and Dahdah, 2010 and 2011). Specific cutoff values for background versus anomalous gas concentrations and thermogenic versus microbial, will vary for different seepage types, sediment conditions, and analytical methods. Also note that secondary alteration by microbes in the shallow sediments

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can result in carbon isotopic ratios heavier than the original values (Abrams, 1989). James and Burns (1984) recognized microbial alteration of reservoir gases resulting in significant changes in the wet gas isotopic ratios for individual wet gas components. Note that propane will be preferentially attacked resulting in isotopic values heavier than the original value (Abrams and Dahdah, 2011) Gasoline plus range hydrocarbons: Evaluation of gasoline plus range hydrocarbons (C5 to C12) in near-surface sediments is complicated due to a limited worldwide database to understand a “typical” background and seep gasoline plus range signature. Examination of HSPME extract gas chromatograms from several seabed geochemical surveys demonstrates samples with migrated gasoline range hydrocarbons display a very different compound distribution than normally found in conventional reservoir oils (Abrams, et al., 2009). The HSPME extract gas chromatograms have very low normal alkanes, aromatics, cycloalkanes, and cycloalkanes with one methyl group but elevated isoalkanes and cycloalkanes with more than one methyl group. This compound distribution is commonly found in biodegraded and water washed reservoir oils indicating the gasoline plus range hydrocarbons are subject to severe alteration effects in marine sediments. Gasoline plus range hydrocarbon compound specific evaluation with near-surface seabed samples is very difficult due to severe alteration; thus, the most useful HSPME screening parameter is Sum of Carbon Number (SCN) (Abrams, et al., 2009). This generates a bulk number which in conjunction with the GC chromatogram, will assist in determining presence of migrated gasoline plus range hydrocarbons. If more detailed compositional information is required, then the Gore Sorber/thermal desorption mass spectrometry will provide greater compound identification. However, the migrated gasoline plus range hydrocarbons will most likely be greatly affected by microbial alteration. Further study needs to be conducted to examine key thermogenic gasoline range compounds which are more resistant to microbial alteration. High molecular weight hydrocarbons gases: The interpretation of seep-related high molecular weight hydrocarbons in shallow sediments can be problematic. Moderate seeps with lower levels of migrated thermogenic hydrocarbons are usually accompanied by an overprint of recent organic matter which can obscure the thermogenic signal (Logan et al., 2009). Macroseeps are commonly characterized by severe biodegradation which results in sediment extract gas chromatograms being dominated by a large unresolved complex mixture (UCM) (Abrams, 2005). The first step in evaluating sediment extract GC data is a visual examination of the chromatogram for presence of normal alkanes, distribution of normal alkanes, isoprenoids (norpristane, pristine and phytane), ROM signature, elevated UCM, and shape of UCM. Next, examine Carbon Preference Index (odd/even ratio of n-paraffins) which should decrease from values approximately 4 (ROM dominated) with increasing petroleum influence to values approximately 1 (petroleum hydrocarbon dominated). Whole extract gas chromatograms will display predictable changes depending on relative amount of recent organic matter and/or biological remains unrelated to seepage hydrocarbons migrating from depth. The type of in-situ extractable organic material present in the sediment sample will be dependent on the origin (provenance) and local biological setting. When a seep has undergone little biodegradation, the seep HMW hydrocarbons can be detected using the sum of n-alkanes within the C10 to C22 n-alkane range (Abrams, 2005 and Logan et al., 2009). When an oil seep has undergone extensive biodegradation, as is the case with most seeps, the most effective way for migrated HMW hydrocarbons screening is to examine concentration and shape of the UCM (Logan et al., 2009). Plot Total Hydrocarbon Gas versus Total Extract GC UCM; and Total HSPME SCN versus total extract GC UCM. The relationship of light hydrocarbons relative to the high molecular weight hydrocarbons can be very helpful in evaluating potential reworking (see discussion below), transported, contamination, and seepage activity (Abrams, 2005). Not all near-surface high molecular weight thermogenic signatures will be related to petroleum leakage. Recently deposited thermally mature source rock derived from near-by uplifted and eroded sediment provenances can be confused with localized migrated hydrocarbon seepage (Piggott and Abrams, 1996). Key geochemical characteristics which indicate reworked mature source rock is present include: strong thermogenic high molecular weight (C12 plus) signal with little or no ROM character, extract gas chromatograms with a full complement of normal paraffin (no evidence of microbial alteration), low levels of total extractable hydrocarbon (less than 100 ug/gm extract), little or no associated sediment interstitial gas, elevated total organic carbon (TOC), thermogenic seep signatures present in more than 30% of cores, and cores with a thermogenic signature both within and away from targeted seep zones (background samples). If this geochemical signature is present, the following additional information will provide

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confirmation reworked source rock may be present: biostratigraphic evaluation of core samples to look for paleontological evidence of reworked detrital kerogen, programmed pyrolysis (elevated S1 indicating free hydrocarbons present), pyrolysis-GC (thermal extraction with GC analysis), geologic maps with mature source outcrops present in study area, and comparison of molecular characteristics of “seep” to local provenance source rock outcrop. Near-surface thermogenic high molecular weight hydrocarbons derived from subsurface leakage can be carried along with displaced sediments and transported to locations downdip. The displaced thermogenic hydrocarbons will contain relatively low concentrations of thermogenic hydrocarbons relative to localized hydrocarbon seepage (Cole et al., 2001). Comparison of background and cores collected on targeted features will assist in identifying a transported signature. Laboratory contamination was first recognized by Barwise et al. (1996) but has been noted in other surface geochemical surveys (Abrams, 2005). Laboratory contamination will be associated with the following observations: similar thermogenic signature present in over 30% of the cores and limited boiling range indicating a refined product (most laboratory lubricants less than C25 boiling point fraction). To confirm potential contamination, send selected backup samples to another laboratory for a similar solvent extraction GC analysis and see if the anomalous geochemical signature persists. Migration pathway analysis is critical in understanding the near-surface seepage in terms of petroleum system dynamics. Fluid flow modeling, seismic attribute evaluation (mapping vertical noise trails), and surface morphology analysis are independent non-geochemical ways to interpret near-surface geochemical anomalies and how they may relate to subsurface hydrocarbon generation and entrapment. Mapping thermogenic hydrocarbon seeps (oil and gas) relative to potential cross-stratal migration pathways is also a useful method to establish effective migration pathways to charge potential traps. Multidimensional fluid flow both along strata and cross stratal can be simulated using one of the many modeling programs. These modeling programs depend on capillary entry pressure, pore fluid dynamics (pore pressure and type), and regional hydrodynamics which are largely unknown in most frontier exploration areas. Nevertheless, the programs provide generalized understandings of major fluid flow directions and help to evaluate the significance of near-surface thermogenic hydrocarbons relative to subsurface petroleum generation and entrapment.

Summary and Conclusions Seabed geochemical surveys will provide important exploration information with hard data on source, maturity, and migration pathways. It is critical to properly collect and analyze near-surface sediment samples as well as correctly evaluate and integrate the surface geochemistry results to avoid misinterpretation.

Pre-survey core selection: Sample sites should target major migration pathways which contain evidence of hydrocarbon leakage based on pre-survey geophysical and remote sensing observations. A sufficient number of cores are needed to assure detection of thermogenic hydrocarbon leakage (at least 100), if present in the study area.

Seabed collection equipment: Choose coring device best suited for local seabed conditions maximizing penetration-recovery in order to obtain sediment samples below the Zone of Maximum Disturbance. The corer and corer handling system must be efficient and simple for quick and safe core recovery.

Real time seismic: Real time imaging provides greater detail to confirm feature and provide a specific real time target to core.

Sample collection and preservation: Three sections per core should be collected at variable depths. Two types of geochemistry samples should be collected: volatile light hydrocarbons (C1 to C10+) and non-hydrocarbon gases; and low volatile higher molecular weight hydrocarbons (C12+). The volatile light hydrocarbons require special handling to limit volatile loss. The addition of super-saturated water and freezing will prevent post sampling microbial alteration. The higher molecular weight hydrocarbon samples should be preserved in tightly wrapped uncoated aluminum foil placed in plastic bags and frozen.

Analysis program for seabed gases: Sediment interstitial gases (C1 to C5) can be extracted using headspace or disrupter. Both methods provide a quantitative evaluation of migrated gases in unconsolidated marine sediments. The blender, ball mill and adsorbed sediment gas extraction method are not effective in characterizing seabed migrated gases. Samples with anomalous gases should undergo compound specific isotopic analysis to evaluate stable carbon isotopic ratio of each gas component.

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Analysis program for seabed gasoline plus range hydrocarbons: Headspace Solid Phase Microextraction provides a cost effective semi quantitative measurement of sediment gasoline plus range (C5 to C12+) hydrocarbons at a low cost. The Gore Sorber® method with sorbent filled collectors and thermal desorption coupled with mass spectroscopy provides a quantitative measurement but at a higher cost per sample.

Analysis program for sediment higher molecular weight hydrocarbons: Evaluate high molecular weight hydrocarbons (C12+) using solvent extraction (Dichloromethane) followed by whole extract gas chromatography. Total Scanning Fluorescence is not recommended.

Non geochemical analysis: Bulk sediment measurements such as quantity of organic matter (Total Organic

Matter) and sand percent (fraction greater than 63 m by either weight or volume) can be helpful to better understanding origin of anomalous hydrocarbons.

Interpretation of seabed gas data: Identify background versus anomalous populations with histogram or

cumulative frequency plot, then plot Wet Gas Fraction (C2 – C5/C1 – C5) versus Total Hydrocarbon

Interstitial Gas (C1– C5) to evaluate sample groupings: background with low wet gas fraction, background with elevated wet gas fraction (fractionated), anomalous with low wet gas fraction, and anomalous with elevated wet gas fraction. Lastly, use compound specific isotopic data and gas wetness fraction to characterize anomalous sediment gas origin.

Interpretation of seabed gasoline plus range data: The gasoline plus range hydrocarbons will be highly altered and not resemble conventional reservoir oil. Detecting and evaluating highly altered gasoline plus range hydrocarbons using HSPME is best accomplished with examination of Sum of Carbon Number.

Interpretation high molecular weight: The identification of migrated oil in marine sediments is carried out by visual examination of the extract GC chromatograms and UCM measurement. Samples with elevated UCM and non ROM GC chromatograms can be further examined using GC-MS (biomarker) analysis and evaluating the least degraded compounds.

Integration: Mapping thermogenic hydrocarbon seeps (oil and gas) relative to key cross-stratal migration pathways via fluid flow modeling and seismic attribute analysis provides an effective petroleum systems evaluation tool to better understand the seepage relative to subsurface hydrocarbon generation and entrapment. Surface hydrocarbon detection is rarely the “silver bullet” technology, but rather a complement to other data.

Acknowledgements Many thanks to the Surface Geochemistry Calibration (SGC) research project industry supporters; Drs. Harry Dembicki (Anadarko), Graham Logan (Geoscience Australia), Ger van Graas (StatoilHydro), Dennis Miller (Petrobras), Neil Frewin (Shell), Andy Bishop (Shell), Brad Huizinga (ConocoPhillips), Angelo Riva (ENI), and Peter Eisenach (Wintershall). Dr. Eva Francu and Nick Dahdah with the Energy & Geoscience Institute (EGI) at the University of Utah were extremely helpful during the various phases of the multi-year industry funded research project. The manuscript was greatly improved with critical reviews by Daniel Burggraf, Neil Frewin, and Dennis Yanchak.

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References Abrams, M. A., Modifications for increasing recovery and penetration in an open barrel gravity corer, OCEANS 82 Conference Record, IEE/MTS, Washington, DC, 82CH18 27.5, 661-666 (1982). Abrams, M. A., Interpretation of surface methane carbon isotopes extracted from surficial marine sediments for detection of subsurface hydrocarbons, Association Petroleum Geochemical Explorationist Bulletin, 5, 139-166 (1989). Abrams, M. A., Geophysical and geochemical evidence for subsurface hydrocarbon leakage in the Bering Sea Alaska, Marine and Petroleum Geology Bulletin, 9, 208-221 (1992). Abrams, M. A., Distribution of subsurface hydrocarbon seepage in near surface marine sediments, In: D. Schumacher and M. A. Abrams (Eds.), Hydrocarbon Migration and Its Near Surface Effects, American Association Petroleum Geology Memoir, 66, 1-14 (1996). Abrams, M. A., M. P. Segall, and S. G. Burtell, Best practices for detecting, identifying, and characterizing near-surface migration of hydrocarbons within marine sediments, Offshore Technology Conference, 13039 (2001). Abrams, M. A, Surface geochemical calibration research study: An example of research partnership between academia and industry: New insights into petroleum geoscience research through collaboration between industry and academia. Geological Society, May 8-9, 2002, London UK (2002). Abrams, M. A., Significance of hydrocarbon seepage relative to sub-surface petroleum generation and entrapment, Marine and Petroleum Geology Bulletin, 22-4, 457-478 (2005). Abrams, M. A., Dahdah, N. F., and Francu, F., Evaluating petroleum systems elements and processes in frontier exploration areas using seabed geochemistry, World Oil, 225-6, 53-60 (2004). Abrams, M., N. Dahdah, and E. Francu, Development of methods to collect and analyze gasoline plus range (C5 to C12) hydrocarbons from seabed sediments as indicators of subsurface hydrocarbon generation and entrapment: Applied Geochemistry, 24,1951-1970 (2009). Abrams, M. A, and Dahdah, N. F., Surface sediment gases as indicators of subsurface hydrocarbons - examining the record in laboratory and field studies, Marine and Petroleum Geology, 27, 273-284 (2010). Abrams, M. A. and Logan, G. A., Geochemical evaluation of ocean surface slick methods to ground truth satellite seepage anomalies for seepage detection, American Association Petroleum Geology Convention Abstracts, Annual AAPG Convention, April 11-14 2010, New Orleans, Louisiana (2010). Abrams, M. A. and Dahdah, N., Surface sediment hydrocarbons as indicators of subsurface hydrocarbons – field calibration of existing and new surface geochemistry methods in the Marco Polo Area Gulf of Mexico, American Association Petroleum Geology Bulletin, 95-11,1907-1935 (2011). Ashby, M. N., J. Rine, E. F. Mongodin, K. E. Nelson, and D. Dimster-Denk, Serial Analysis of rRNA Genes and the Unexpected Dominance of Rare Members of Microbial Communities, Applied Environmental Microbiology, 73-14, 4532–4542 (2007). Badeira de Mello, C. S., R. C. Goncalves, D. J. Miller, and J. B. L. Francolin, Blender: A surface geochemistry tool to sample interstitial hydrocarbons in soils and piston core sediments, International Meeting Organic Geochemistry meeting (2005). Barwise, T., J. Thrasher, and S. Hay, Contamination of Shallow Cores: A common problem, In: D. Schumacher and M. A. Abrams, eds., Hydrocarbon Migration and Its Near-Surface Expression, American Association Petroleum Geology Memoir 66, p. 359-362 (1996).

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Bernard, B. D., Light hydrocarbons in marine sediments, Ph.D. thesis, Texas A&M University, College Station, Texas, 144p (1978). Bjoroy, M and I. Ferriday, Surface geochemistry as an exploration tool: A comparison of results using different analytical techniques, American Association Petroleum Geology Hedberg Conference “Near-Surface Hydrocarbon Migration: Mechanisms and Seepage Rates”, September 16-19, 2001, Vancouver BC, Canada (2002). Brooks, J. M., M. C. Kennicutt II, B. D. Bernard, G. J. Genoux, and B. D Carey, Applications of total scanning fluorescence to exploration geochemistry, Offshore Technology Conference Proceedings, OTC-4624, 393-400 (1983). Brooks, J.M. and B. D. Carey, Offshore surface geochemical exploration, Oil and Gas Journal, 84, 66-72 (1986). Cole, G., A. Yu, F. Peel, R. Requejo, J. DeVay, J. Brooks, B. Bernard, J. Zumberge, and S. Brown, Constraining source and charge risk in deepwater areas, World Oil, October 2001, 222, 69-77 (2001). Dembicki, H. Jr. and B. M. Samuels, Identification, Characterization, and Ground-Truthing of deepwater Thermogenic Hydrocarbon Macro-Seepage Utilizing High – Resolution AUV Geophysical Data, Offshore Technology Conference April 30 to May 3, 2007, Houston Texas, OTC-18556 (2007). Dembicki, H. Jr., and B. M. Samuels, Improving the detection and Analysis of Seafloor Macro-Seeps: An example from the Marco Polo Field, Gulf of Mexico, International Petroleum Research Conference December 3-5, 2008 Kuala Lumpur, Malaysia, IPTC 12124 (2008). Dembicki, H, Recognizing and compensating for interference from recent organic matter and biodegradation during interpretation of biomarker data from seafloor hydrocarbon seeps: An example from the Marco Polo Area Seeps, Gulf of Mexico, Marine and Petroleum Geology, 27, 1936-1951 (2010). Dolan, P., D. Burggraf, K. Soofi, R. Fitzsimmons, E. Aydemir, O. Sennesseth, and L. Strickland, Challenges to exploration in frontier basins – The Barbados Accretionary Prism. AAPG International Conference: October 24-27, 2004 Cancun, Mexico (2004). Edwards, D., and N. Crawford, UVF Fluorimetry. AGSO (Australian Geological Survey Organization) Open File Research report (1999). Grosjean, E. and G. A. Logan, Incorporation of organic contaminants into geochemical samples and an assessment of potential sources: examples from Geoscience Australia marine survey S282, Organic Geochemistry, 39, 853-869 (2007). Hopkins, T. L., A survey of marine bottom samplers, In M. Seers (eds.), Progress in Oceanography, Pergamon-MacMillan, New York, 2, 213-256 (1964). Horvitz, L., On geochemical prospecting, Geophysics, 4, 210-228 (1939). Horvitz, L., Geochemical exploration for petroleum, Science, 229, p. 812-827 (1985). James, A. T., Correlation of natural gas by use of carbon isotopic distribution between hydrocarbon components, American Association Petroleum Geology Bulletin, 67, 1176-1191 (1983). Jones, V. T. and R. J. Drozd, Predictions of oil and gas potential by near surface geochemistry, American Association Petroleum Geology Bulletin, 67, 932-952 (1983). Klusman, R. W., Soil gas and related methods for natural resource exploration. John Wiley & Sons, New York, N. Y., 483p (1993).

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Lightenberg, J. H., Unravelling the petroleum system by enhancing fluid migration paths in seismic data using a neural network nased pattern recognition technique, Geofluids, 3, 255-261 (2003). Logan, G. A., M. A. Abrams, N. Dahdah, and E. Grosjean, Examining laboratory methods for evaluating migrated high molecular weight hydrocarbons in marine sediments as indicators of subsurface hydrocarbon generation and entrapment, Organic Geochemistry, 40, 365-375 (2009). Kullenberg, B., The piston core sampler. Svenska Hydrograf Bio. Komm. Skrifter Tredje Ser. Hydrograf, 1H2, 1-46 (1947). O’Brien, G. W., Hydrocarbon-related diagenetic zpones (HRDZs) in the Vulcan Sub-Basin, Timor Sea: recognition and exploration implications: APEA Journal, 220-251 (1995). Piggott, N and M. A. Abrams, Near-surface coring in the Beaufort and Chukchi seas, Alaska, In: D. Schumacher and M. Abrams, eds., Hydrocarbon migration and its near surface effects, American Association Petroleum Geology Memoir 66, p. 381-396 (1996). Roberts, H. H., P. Aharon, R. Carney, J. Larkin, and R. Sassen, Sea floor response to hydrocarbon seeps, Louisiana continental slope, Geo-marine Letters, 10, 232-243 (1990). Schoell, M, Genetic classification of natural gases, American Association Petroleum Geology Bulletin, 67, 2225-2238 (1983). Schumacher, D., and M. A. Abrams (Eds.), Hydrocarbon Migration and Its Near Surface Effects: American Association Petroleum Geology Memoir No. 66, 446p (1996). Schumacher, D, and L. A. LeSchack, Surface Exploration Case Histories: Applications of geochemistry, magnetics, and remote sensing, American Association Petroleum Geology Studies in Geology No. 48, 504p (2002). Whiticar, M. J., Carbon and hydrogen isotope systematics of bacterial formation and oxidation of methane, Chemical Geology, 161, 291-314 (1999).

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Figure 1 Seismic indications of seepage.

a. Seafloor shaded-relief image from Multi-beam Echosounder (MBE) showing various vent related seafloor features (image courtesy of Geosciences and Earth Marine Services).

b. Seismic profile showing near surface expulsion crater, vent chimney, shallow high amplitude events (image courtesy of Geosciences and Earth Marine Services).

Collapsed Hydrate/Mud Mound

Fluid/Gas Expulsion Crater

Mud Flow Channel

Pockmarks

Hydrate Mound

Venting Hydrate/Mud

Mound

Mud Flow Channel

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Figure 2 Open barrel corer and corer recovery system. a. Open barrel corer

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b. Corer recovery system.

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Figure 3 Core sub sampling protocols.

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Figure 4 Seabed sample analysis program.

Hydrocarbon Gas

C1 to C5

Gasoline Range

C5 to C12

High Molecular Weight HC

C12 plus

Screening AnalysisAll samples to identify anomalous samples

HeadspaceGC-FID

HSPMEGC-FID

Solvent extractionGC-FID

Advanced AnalysisSelected samples based on screening results

Compound Specific IsotopesGC-C-IRMS

Biomarker AnalysisSaturate & Aromatic GC-MS

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Figure 5a Wet Gas Fraction (C2 – C5/C1 – C5) versus Total Hydrocarbon Interstitial Gas (C1– C5) cross plot (modified from Abrams et al., 2001).

Figure 5b Wet Gas Fraction (C2 – C5/C1 – C5) versus Total Hydrocarbon Interstitial Gas (C1– C5) cross plot for the Marco Polo calibration survey (modified from Abrams and Dahdah, 2011); Can HS = canned headspace and Disrupter HS = disrupter headspace.

0.0

0.1

0.2

0.3

0.4

0.5

0.6

1 10 100 1000 10000 100000 1000000

We

t G

as

Fra

cti

on

(C

2-C

5/C

1-C

5)

Total Interstitial Hydrocarbon Gas (ppm)

Regional reference Can Headspace

Within Seep Zone Can Headspace

Near Seep Zone Can Headspace

Regional reference Disrupter Headspace

Within Seep Zone Disrupter Headspace

Near Seep Zone Disrupter Headspace

Anomalous

Background

Fractionated