Designing a seabed geochemical study

MICHAEL A. ABRAMS, Apache Corporation

A survey should include the ability to identify the target features in real time and collect the sediment cores on target below the zone of maximum disturbance. Analysis should include a full range of hydrocarbons as well as select non-hydrocarbon gases.

Seabed coring operations for the University of Utah Surface Geochemistry Calibration field study conducted in August 2006 over Anadarko’s Marco Polo field in the Gulf of Mexico, Green Canyon block 608.

Surface geochemistry is a relatively routine exploration method used to investigate issues of hydrocarbon generation and charge.^1–6 The presence of near-surface migrated petroleum provides strong evidence that an active petroleum system is present as well as critical information on petroleum source, maturity and migration pathways.^6–8 This article summarizes results from the multiphase Surface Geochemistry Calibration (SGC) study conducted by the Energy and Geoscience Institute (EGI) at the University of Utah.⁹

Multiple methods are applied to collect, prepare, extract and analyze near-surface migrated hydrocarbons contained within marine sediments.^{2,6,7,10–12} Few of these methods have been rigorously examined in both lab and field studies. The discussion below is based on a series of lab and field studies conducted to groundtruth the current methods as well as develop new protocols.^9,12–14

PRE-SURVEY PLANNING

Pre-survey planning is critical to identify potential petroleum seep targets, develop a cost-effective real-time seismic program, choose a coring device best suited for local sedimentary conditions with a safe corer recovery system, and organize sediment sample preparation protocols.

Core site selection. Core samples should target migration pathways that contain seismic and/or other evidence of petroleum leakage.^15–16 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 hardgrounds (carbonate), hydrocarbon-related diagenetic zones (HRDZ),¹⁷ wipeout zones (also known as gas chimneys) or acoustic blanking (reflection discontinuity and amplitude loss creating distortion zones), bottom-simulating reflector (BSR, gas hydrate related), water column gas anomalies, near-surface bright spots and seismic event pull-downs (signal slowdown due to gas).

Core targets should include a variety of features across the area of exploration interest. In addition, regional reference cores to define the non-seepage sediment geochemical signal will be important, especially in areas where source rock reworking and/or transported signatures could be present.^8,18–20 Replicate cores should be collected on targeted features that have the greatest potential to contain near-surface migrated hydrocarbons.

Real-time seismic. Real-time imaging provides greater detail to confirm that the targeted feature is present and its extent, and to better understand its relationship to active hydrocarbon seepage. In addition, the real-time data provides a definitive target location. An effective real-time seismic program requires minimal set-up time. Hull-mounted systems are ideal since they do not require time to launch and retrieve. A focused beam and sufficient power are required to obtain good penetration and target resolution in deepwater environments.

Sampling equipment. The seabed sampling device chosen should obtain the maximum amount of recovery relative to penetration for the study area’s sediment regime, water depth and vessel capabilities. The device most often used to collect seabed samples is a gravity corer, which consists of a hollow tube (barrel) attached to a weight (core body). There are two main types of gravity corers: open barrel and piston.²¹ Both systems rely on their weight to push a barrel into the seabed.

The open-barrel gravity corer employs a valve system to remove the incoming water, and works best in shelfal to upper-slope silts and very fine grained sands.²² The piston corer is similar to an open-barrel corer, except that it uses a trigger weight to initiate free fall and a stationary internal piston to create a suction effect that assists in maximizing core recovery and minimizing sediment disturbance.²³ The piston corer has proven to be a very effective tool to obtain more than 4 m of sediment core in deepwater, fine-grained sedimentary environments.²² 

The corer launching and recovery system is also a very important component of a safe and efficient seabed sampling operation that minimizes core sample disturbance. It should be designed to allow for corer free fall with efficient braking, vessel movement during corer operations, fast retrieval to surface in deepwater operations (100–300 m/min.), and safe corer deck recovery in poor sea conditions. Locating the corer during deepwater coring operations (greater than 1,000 m) is also critical. The most common acoustic positioning system used in seabed geochemical operations is the ultra-short baseline (USBL) system, which can provide 5–10 m of accuracy, depending on the water depth, USBL system and operator.

HANDLING AND PROCESSING

Once the corer has been retrieved, a series of important procedures must be followed to process the sediment samples quickly, efficiently and consistently. The core liner with the sediment should be removed immediately, taken to the wet laboratory, and cut into core sections by the deck staff, avoiding contamination from lubricants or vessel exhaust fumes. Three sections per core should be collected at designated depths with replicates. There are two types of geochemistry samples collected, each requiring special protocols and sampling containers. The volatile hydrocarbons (C₁ to C₁₂) and non-hydrocarbon gases require special handling, since these sediment gases and volatile liquids can be lost relatively easily during the sediment handling and preservation process. The most common container used for the collection of volatile gases is a 500-ml compression-lid non-coated metal can. The higher-molecular-weight hydrocarbons (C12 and up) are more stable at surface conditions and, thus, do not require special handling.

A volatile hydrocarbon sample will include a consistent volume of unprocessed sediment in a proper storage container with water and inert gas (helium) or air headspace in a mix of equal parts sediment sample, water and gas headspace.¹² Additional processing is required to prevent post-sampling microbial activity. The method most commonly used involves the addition of antibacterial agents such as sodium azide followed by deep freezing. Research indicates that super-saturating the water with salt and thoroughly mixing sediment with the salt-saturated water is also effective to minimize bacterial activity.¹⁴ 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 the dissolved phase (water-sediment mix), assisting in the headspace extraction process.¹² 

The preservation of non-volatile, high-molecular-weight hydrocarbon samples involves placing about 500 ml of unprocessed sediment in an aluminum foil square using clean spatulas to prevent contaminations from hand cleaning materials or moisturizers. The sediment sample is tightly wrapped in the foil square, flattening the sediment sample and making sure there are no air pockets. The sample is then placed in a labeled standard plastic sealing bag and deep frozen until analysis.

SAMPLE ANALYSIS

The screening analytical program is conducted on all sediment samples to identify those samples with anomalous-gas, gasoline-range and/or high-molecular-weight hydrocarbons, as well as non-hydrocarbon gases (CO₂, N₂ and O₂).

The most common method to examine seabed migrated gases includes conventional can headspace analysis. This procedure examines the sediment gases contained within the pore space, either dissolved in the pore waters (solute) or as free gas (vapor).¹⁰ The amount of gas depends on pore water salinity, in-situ temperature and pressure, and gas type (relative amounts of non-hydrocarbon components and methane vs. wet gases: ethane, propane, butane and pentane). This non-mechanical procedure uses high-speed shaking to release vapor-phase interstitial sediment gases into the can headspace. The SGC laboratory and field calibration studies demonstrated that conventional interstitial headspace gas extraction, when conducted properly, will provide sediment gas compositions and compound-specific isotopes similar to the charge and reservoir gases.¹² 

The bound gases are believed to be attached to organic and/or mineral surfaces, entrapped in structured water, or entrapped in authigenic carbonate inclusions. They, therefore, require a more rigorous procedure to remove.^2,11 The SGC research project demonstrated that the adsorbed and ball-mill-bound gas methods can introduce a systematic fractionation resulting in gas and isotopic compositions different from the charge and reservoir gases.^8,12 Previous studies have shown that, in some cases, the bound sediment gases can provide reliable information on the subsurface petroleum-related gases. It is the author’s opinion that carbonate inclusions were formed as part of the shallow sediment alteration process, which entrapped near-surface migrated gases in these unique cases.^16,24–25

The gasoline-range hydrocarbons are molecules with five to 12 carbon atoms, and are derived from thermogenic processes associated with a mature source rock. These moderate-boiling-point hydrocarbons are volatile and migrate along key oil migration pathways. They, therefore, require a more advanced method to extract and analyze. Two methods are currently available to evaluate these hydrocarbons: the Gore Module, developed by W. L. Gore and Associates, and headspace solid-phase microextraction (HSPME).¹⁴ The Gore Module method examines C₂ to C₂₀ using a module constructed of ePTFE (polytetrafluoroethylene), sorbent-filled collectors and thermal desorption coupled with mass spectrometry. HSPME uses a fused silica SPME assembly followed by thermal desorption gas chromatography analysis. Both methods provide important information on a group of hydrocarbons rarely examined in most seabed geochemical surveys.

High-molecular-weight hydrocarbons (C₁₂ and up) are examined using solvent extraction followed by whole-extract gas chromatography (GC). Comparison of different extraction solvents indicates both n-hexane (low polarity) and dichloro-
methane (DCM, higher polarity) are suitable for marine sediment petroleum hydrocarbon screening.¹³

Published studies demonstrate that surface geochemical signatures can vary with sediment size, type and organic content.^2,4,6 The lithology type provides non-geochemical information that may be critical in interpreting the geochemical results.

When anomalous high-molecular-weight hydrocarbons are found using extract gas chromatography screening, further molecular characterization is needed to understand the anomalous hydrocarbons origin. Gas chromatography-mass spectrometry (GC-MS) provides detailed molecular information on biological markers, allowing correlation of surface seeps to subsurface oils and/or source rocks.

Sediment-extracted gas composition by itself will not provide sufficient information to determine anomalous gas origin. Compound-specific isotopic analysis using isotope-ratio (IR) GC-MS can determine gas maturity and source facies, as well as potential mixing with in-situ derived gases and secondary alterations.²⁴ 

DISCUSSION

The above information is based on the SGC laboratory and field studies, which provided a framework to develop technically sound and safe seabed geochemical surveys. Examination of a worldwide geochemistry database with post-well results demonstrated that most failures (dry holes in areas where surface geochemistry identified thermogenic seepage) were related to three key issues: improper sample collection, problematic analyical procedures and incorrect interpretation.

Collecting samples on target (within the petroleum seepage zone) and at least 3–4 m below the water-sediment interface is critical to ensure that the sample contains migrated hydrocarbons and to avoid near-surface alteration effects from the zone of maximum disturbance.^8,15

The SGC lab and field studies demonstrated how analytical procedures may impact the surface geochemical results. The adsorbed and ball-mill-sediment gas extraction methods provided gas compositions with elevated gas wetness and incorrect compound-specific gas isotopes relative to the charge and reservoir gases. It was concluded that this was most likely related to fractionation resulting from sample transfer and sediment washing.¹² Thus, much caution is required with bound-gas sediment-extraction data. Issues of field and lab contamination were also identified in the SGC research project. The analytical procedure and contract lab must be chosen with great caution to ensure that the results are real and not an artifact of the lab and procedure.

Lastly, misinterpretation is one of the most significant reasons for surface geochemistry failures. The SGC study indicated that the misidentification of variable background noise and reworked source rock or seepage as true signal was a relatively common error. In addition, few geochemical studies integrate the seabed geochemical results with basin geology. 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. 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.

The introduction of new analytical procedures such as HSPME and the Gore Module to evaluate seabed gasoline-range hydrocarbons will provide an additional hydrocarbon measurement not currently used in most seabed geochemical surveys. Most recently, a new microbiological survey method has been tested in the Gulf of Mexico to evaluate microbial communities related to seeping hydrocarbons.²⁶ These microbial communities inhabiting prolific hydrocarbon seeps can be characterized by culture-independent DNA profiling of 16S rRNA genes. Microbial profiling may prove to be an important tool in areas of low or inactive seepage.  

ACKNOWLEDGMENTS
This article was prepared from AAPG 947643 presented at the AAPG Annual Conference and Exhibition held in Houston, April 10–13, 2011. Thanks are due to the SGC research project’s industry supporters: Anadarko, Geoscience Australia, Statoil, Petrobras, Shell, ConocoPhillips, Eni, Wintershall, Nexen, BHP, Hunt, Total and Marathon. TDI-Brooks, Fugro, Gore Surveys, Taxon Biosciences, the University of California and the University of Victoria all provided support during the EGI research project. Also thanks are due to the research staff at the University of Utah—Nick Dahdah, Eva Francu and Janice Erickson—who provided assistance during the various phases of the SGC research project.

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