The front matter contains the title page, copyright page, dedication, table of contents, and about the editors.

Abstract This collection of new research describes aspects, observations, and implications of natural hydrocarbon manifestations colloquially referred to as seeps. There is tremendous variation in seeps — their fluids, gases, setting, and associations — and they are not easy to characterize. Yet they are true oracles of nature and speak directly to the prospector. With the increased resolution power of many geophysical methods, we are seeing direct evidence of seeps on a wide variety of data, including conventional seismic data. This volume is designed and organized to help answer key questions workers may develop from working field data: (1) What do seeps look like in various perspectives, data types, and environments? (2) What kind of methodologies may be used to detect and measure seeps? (3) What does the seep tell me about the prospect or area hydrocarbon system and associated risks? Accordingly, the chapters of this book are divided into three sections that discuss the descriptions and observations of seeps, the science of seepage and methodology, and the implications of seeps.

Abstract Three-dimensional coupled deformation and fluid-flow numerical modeling, charge-history analysis, and seismic imaging of inferred leakage-related geobodies are integrated to investigate the response of a complex set of Jurassic trap-bounding normal faults to extensional reactivation and to assess hydrocarbon upfault seepage on the Laminaria High (Timor Sea, Australian North West Shelf). Fluid inclusion data are consistent with the presence of paleo-oil columns below the current accumulations in the Laminaria and Corallina fields. Evidence for other partially breached (current and paleo-oil column) as well as breached (dry with paleo-oil column) closures across the region implies that active and widespread seepage took place after the time of initial oil charge. The distribution of current and paleo-oil zones, and the location of inferred hydrocarbon leakage indicators defined on 3D seismic data, correlates with the prediction of fault-seal effectiveness based on modeled strain distribution. Within the geologic framework of the Laminaria High area, this distribution suggests that when sufficient reactivation shear strain is accumulated by reservoir faults, ductile deformation might give way to brittle failure in the top seal, allowing active flow pathways to develop and upfault seepage to take place from the reservoir to thief zones or the seafloor. The observations emphasize that strain and upfault fluid-flow partitioning is constrained by prereactivation fault size, lateral fault-tip distributions, and the presence of fault jogs inherited from successive episodes of growth processes. These elements can explain the complex distribution of paleo- and preserved oil columns in the study area and further support Cenozoic tectonic activity as being the first-order control on trap breaching and hydrocarbon seepage in this region.

Abstract Analyses of large tracts of seismic data reveal thousands of sites on the northern Gulf of Mexico (GOM) continental slope where vertical migration of subsurface fluids and gases reaches the modern seabed. A common characteristic of these sites is the occurrence of locally precipitated 13 C-depleted authigenic carbonates. Recent studies of the poorly understood middle and lower slope indicate that the geochemical conditions required for carbonate precipitation exist across the full depth range of the slope. However, a wide range of mineralogical, petrographical, and isotopic variations occurs. Analysis of 450 samples from about 100 sites spread over the entire slope indicates that seep carbonates are composed mostly of high-magnesium calcite (HMC) and aragonite. Minor amounts of dolomite occur in samples from most sites. Samples from a few sites contain more than 50 wt.% of dolomite. These mineralogical compositions are typical of authigenic carbonates from the entire slope. The HMC and dolomite are mineralogies associated mostly with the matrix that formed in the shallow subsurface, whereas aragonite is found mostly as void-filling cement precipitated close to the seabed. Stable isotopic compositions of carbon and oxygen vary within sites (-32.2‰–14.0‰ for δ 13 C and 2.6‰–6.8‰ for δ 18 O), but much greater variation (-64.4‰– 14.0‰ for δ 13 C and 1.5‰–6.8‰ for δ 18 O) occurs between sites. Between-site variation in δ 13 C values is attributed primarily to different parent hydrocarbon sources. Within-site variation in δ 13 C values has many potential origins, including the rate at which hydrocarbons are delivered to the zone of precipitation, differences in biologically forced processes, spatial changes in hydrocarbon source, and differential sequestration of hydrocarbons by gas-hydrate formation. In addition, chemosynthetic communities, such as bathymodiolid mussels and vestimentiferan tubeworms, may have distinct geochemical impacts on associated seep carbonates. Initial studies indicate that carbonates formed in mussel beds and tubeworm communities have different δ 13 C values even at the same seep site. Carbon isotopic vital effects of seep mussels and tubeworms, fluid physical pumping by mussels, and release of sulfate by tubeworm roots may be responsible for the relatively more negative δ 13 C values of tubeworm-associated carbonates. Careful petrographic and geochemical analyses of samples from the entire slope provide a general understanding of slopewide variability in seep carbonate properties. In addition to carbonates, barite is common at many seeps on the northern GOM slope. Barite is found disseminated in surface sediments; it also occurs as small mounds, chimneys, cones, and crusts. Mineralogically, samples of barite may contain carbonate minerals, HMC, and dolomite, but aragonite is absent in all samples analyzed so far.

Abstract The ebullition of methane through the seafloor (macroseepage) is a relatively rare occurrence. Such seepage has been proven to affect the seabed’s sediments, its topography, its life, and the seawater in various ways and at various scales. From the results of detailed surveys conducted on three distinct and continuous macroseeps in the North Sea (Tommeliten, Scanner, and Gullfaks) over several decades, using a range of tools and scientific disciplines and comparing the various results from these macroseeps with those of shallow methane macroseeps elsewhere, it is concluded that macroseepage of methane at less than 160-m water depth most probably affects not only the local topography, geochemistry, biogeology, and water column but also the region, including the downstream water column, the seafloor surface, and the seawater surface. In addition, some macroseeps provide methane to the lower atmosphere. It is also suspected that some macroseeps give birth to adjacent microseepage and therefore represent important geobiological systems that can only be understood properly by long-term studies performed at many scales and by cross-disciplinary scientific methods. Marine methane macroseeps are characterized by (1) visual ebullition through seafloor holes; (2) hydroacoustic flares (columnar midwater reflections); (3) ethane concentration anomalies in the water column and adjacent sediment porewater; (4) development of visual, biological, and chemical aureoles surrounding the seep location; (5) anomalies (strong gradients) in chemical, temperature, and biological composition of the water column, especially downcurrent (e.g., pH, eH, carbon dioxide [CO 2 ], oxygen [O 2 ], methane [CH 4 ], sulfate, sulfide); (6) topographical effects (mounds, depressions, pockmarks); (7) carbonate cementation of subsurface sediments surrounding the conduit and adjacent sediments; (8) bacterial mats on the sediment surface adjacent to a seep; (9) upwelling of seawater; (10) downwelling (circulation) of seawater into conduit throats; (11) sea-surface effects, e.g., nutrients coming to the surface because of upwelling; (12) sea-surface slicks and seabirds feeding, downcurrent of the seep; (13) attraction of fish and other macrofauna to the seep; and (14) anomalies in methane concentration in the lower atmosphere above the seep. These effects are listed in order of occurrence, with the most common first (1 and 2) and the less common at the bottom (13 and 14).

Abstract Seep features in the area of the Marco Polo field in the Gulf of Mexico were identified using remote sensing, conventional seismic data, and high-resolution geophysical data collected from an autonomous underwater vehicle (AUV). Using these data, the potential seep features were mapped based on their geomorphology and acoustic characteristics. Results show that a mud volcano and a mud mound field had the highest probability of macroseepage, confirmed by subsequent sampling and analysis of seafloor sediments. The 3D seismic data in the area around the Marco Polo field were also processed to highlight gas chimneys. Chimneys were highlighted using a neural network approach with directional seismic attributes. The chimney processing results showed evidence of chimneys that should provide vertical hydrocarbon migration pathways through the salt canopy. These chimneys directly underlie the Marco Polo field and provide a mechanism for charging the field. The processing also showed fault-related chimneys on the flank of the Marco Polo field. These chimneys correlate to mud mounds and a mud volcano, detected by the AUV data. The surface features associated with the chimneys contain hydrocarbon seepage, based on surface sampling. Good conformance between chimney and seafloor indications of seepage reinforces the relationship between the seeped hydrocarbons and the subsurface reservoir. These combined data have the potential for assessing seepage flux rates as well as quantifying the risk for hydrocarbon charge and seal. The work demonstrates that chimney processing and interpretation used in conjunction with seep detection has the capability to improve risk assessment in mature and frontier basins.

Abstract The migration architecture of the Gippsland Basin, Australia, is dominated by two highly connected, filled-to-spill fill and spill (fill-spill) chains — the northern chain (gas dominated) and the southern chain (oil dominated) — that extend east–west across the basin and link at its far western nearshore part, forming a convergent chain that then extends onshore. The reservoir units across the basin are sealed by smectite-rich marine claystones that have very high seal potential within the central basin but become less effective toward the basin flanks and onshore. Decreasing top-seal potential along the convergent fill-spill chain onshore has localized the formation of a 25-km-long zone of leakage and seepage; here, leaking hydrocarbons are expressed as gas chimneys, as natural seeps, and as a prominent zone of shallow uranium enrichment. Active seepage, documented by a combination of chimney mapping and water-column geochemical sniffer data, also occurs in several areas offshore — mostly along the basin margins at the conjunction of well-developed migration fairways and zones of failing top and fault seal. Fluid inclusion and migration-modeling data reveal that the first major hydrocarbon charge in the basin, including that into the giant gas fields that dominate the northern fill-spill chain, was oil; this charge appears to have filled the traps to spill point, probably in the Late Miocene. Gas subsequently entered many of these traps in the Pliocene and displaced the oil, pushing it farther along the fill-spill chains. A lack of gas charge into the eastern portion of the southern fill-spill chain preserved the early oil charge along that trend. The integration of basin-scale fluid-flow modeling with assessments of seal integrity, charge history, and leakage-seepage processes provides a powerful, generic, predictive approach for assessing not only the petroleum systems and hydrocarbon prospectivity of a basin but also its ultimate CO 2 geostorage potential.

Abstract Detailed microbial surveys were acquired over the Agua Del Cajon and El Salitral fields in the Neuquén Basin of Argentina to detect bypassed oil reservoirs. Depleted reservoirs quickly lose their associated microbial anomalies. Thus, these surveys can often detect nondepleted reservoirs. Although microbial surveys are an effective measure of hydrocarbon microseepage, they have several limitations. First, hydrocarbon microseepage is predominantly vertical, but it can be influenced by faulting and offset from the source of the anomaly. Second, we cannot determine the depth of the suspected reservoir. To provide a link from reservoir to surface, we need to delineate the hydrocarbon migration pathways. On seismic data, vertical hydrocarbon migration paths are characterized by vertically aligned zones of chaotic reflectivity, called gas chimneys. These chimneys are detected by training a neural network using multiple seismic attributes and examples of gas chimneys picked by the interpreter. The resulting chimney volume is visualized in 3D seismic volume to determine where the hydrocarbons originated and where they migrated. Results of the study show a good correlation between strong surface microbial anomalies and shallow chimneys. Many of the chimneys have a deep origin in the gas-prone Jurassic Molles interval. There is also a good correlation between deeper Jurassic gas pay and these chimneys. The Late Jurassic Vaca Muerta, a thermally mature oil-prone source shale, provides an effective top seal for these deep pays. Chimneys, associated with the major east–west-trending thrust fault and northwest-trending shear faults, penetrate the Vaca Muerta interval. Cretaceous Quintuco carbonates and Centenario clastic oil reservoirs are closely associated with these chimneys. The deep chimneys are the means to expel oil from the Vaca Muerta shales into the shallow reservoirs. The combination of microbial surveys and chimney detection is being used to successfully discover bypassed pay in this area.

Abstract Microbial communities inhabiting prolific hydrocarbon seeps in the Gulf of Mexico have been characterized by culture-independent DNA profiling of 16S ribosomal RNA (rRNA) genes. High-throughput 454 pyrosequencing was combined with serial analysis of ribosomal DNA (SARD) to vastly increase the number and, hence, sensitivity and accuracy of microbial 16S rRNA gene detection. This approach enabled the detection of more than 5 million ribosomal sequence tags and revealed that approximately one-third of the sequence tags showed a similar distribution among the sediment piston-core samples compared to the major hydrocarbon constituents present in the seeps. Numerous correlated distributions or associations were found between particular microbial DNA sequences and specific hydrocarbons, suggesting a biochemical role in the transformation of these compounds. Quantitative polymerase chain reaction (qPCR) primers were designed to target these 16S rRNA gene sequences and were found to accurately detect and serve as sensitive bioindicators for these hydrocarbons in blind tests. The results underscore the need for a thorough characterization of geochemistry and microbiology to fully understand the dynamics of these biogeochemical associations.

Abstract After seeped thermogenic hydrocarbons are discovered in seafloor sediments, biomarker analysis of the seeped oil is typically done to gain information about the contents of the subsurface accumulation. The analytical protocol usually consists of solvent extraction of the sediment with a nonpolar solvent such as hexane, followed by asphaltene precipitation and separation of saturate and aromatic hydrocarbon fractions prior to analysis of the hydrocarbons by gas chromatography–mass spectrometry (GC-MS). If the biomarker distributions obtained are unaltered, they can be used to correlate the seep oil to previously discovered oils in the basin or to deduce the characteristics of the source rock that generated the oil using conventional biomarker interpretation schemes. Unfortunately, these compound distributions are frequently compromised, which limits the information that can be discerned. When the concentration of seeped oil is low, the presence of background organic matter may mask the source-controlled geochemical information in the oil. Biomarker analysis of the background organic matter in the vicinity of the seepage is essential for distinguishing the thermogenic input from the background organic matter. Occasionally, reworked organic matter from eroded source rock, coal, or transported hydrocarbon seepage in the sediments may also contribute misleading information. As the concentration of seeped oil increases, biodegradation usually increases, often to the point where the biomarkers are altered. Hopanes and steranes are the biomarkers most susceptible to microbial alteration, although tricyclic terpanes, diasteranes, and aromatic steroids are more resistant and may provide useful information. In some sediments, biodegradation can be severe enough to alter the distributions of all compound types. Because the intensity of biodegradation can vary greatly within an individual seep feature or between a group of related features, biomarker analysis of multiple seeped oil samples provides the best opportunity to obtain useful data.

Abstract Gas-chimney analysis is a useful tool for evaluating shallow and deep hydrocarbon prospects by showing likely migration routes for deeply sourced thermogenic hydrocarbons as well as shallower biogenic hydrocarbons. Specialized seismic processing conditions the 3D data set so that only meaningful gas chimneys are analyzed. Once the data have been so conditioned, the interpreter can differentiate between faults that show evidence of leakage and those that do not show evidence of leakage and may be sealing faults. Many of the shallower chimneys can be tied directly to active surface seeps as well as shallow gas prospects and known hydrocarbon deposits. When this type of chimney analysis is coupled with techniques such as waveform segmentation, amplitude variation with offset, and absorption attribute analysis, the result is a very powerful 3D data volume that can be used to derisk shallow and deep gas prospects.

Abstract Hydrocarbon seeps occur naturally in many places, including onshore, offshore, and along the coast of Santa Barbara and Ventura counties in southern California. Existing seep-mapping projects include Santa Barbara County’s Natural Seep Inventory and the University of California Santa Barbara’s Bubbleology Coal Oil Point interactive explorer. Organic compounds typically associated with reservoir hydrocarbons are often recognized at or near the surface. Direct and indirect detection of these compounds and their associated (alteration) phenomena are a primary means of establishing the presence of an active or previously active petroleum system. Surface hydrocarbons can be detected by hyperspectral remote-sensing techniques. Hyperspectral data were collected over the Santa Barbara area onshore and offshore by gravity and magnetic surveys. The hyperspectral sensors collected data spanning the visible, near-infrared, shortwave-infrared, and thermal-infrared portions of the electromagnetic spectrum. Images were viewed using false-color infrared composite with different enhancement levels for preliminary hydrocarbon identification at various locations in the imagery. Spectral signatures from the airborne hyperspectral data, combined with field spectroradiometer measurements of known seeps, were used to create a spectral library. Numerical classification techniques identified known and previously unknown occurrences of hydrocarbons. Magnetic and gravity surveys were acquired simultaneously and were used to map major geologic trends and structures in relation to the presence of seeps. The occurrence and distribution of detected seeps provided direct evidence of the presence of an active petroleum system.

Abstract In the northern Gulf of Mexico (GOM), numerous seafloor hydrocarbon seeps are well documented through seismic, seafloor, and chemical studies. In some areas, the seafloor seeps expend sufficient hydrocarbons to pass through the water column and present as sea-surface oil slicks, which with careful review and certain conditions can be identified on satellite images. Some areas with recurring potential sea-surface oil slicks as identified by oil-criteria screened satellite images are located above or near proven subsurface hydrocarbon-producing areas. However, other areas with established production have no sea-surface hydrocarbon slicks, and several areas with potential sea-surface slicks currently have no subsurface production. A publicly available data set of reservoir information for the northern GOM was correlated to a data set of sea-surface slick sites as identified on satellite data. Thirteen variables were selected from the database to evaluate depth relationships, fluid properties, and reservoir properties in relation to slick presence. Because initial multivariate analysis indicated the slick-to-reservoir-variables relationships were nonlinear, a random forest (RF) classification-tree analysis was performed to identify which variables are more important for slick development. The RF analysis used a collection of binary decision trees to determine the relative importance of the reservoir variables in identifying sea-surface slicks. The RF model was able to correctly classify or predict the presence of a slick and identified water depth, gas-oil ratio, and reservoir chronozone as the three most important variables when predicting the formation of a sea-surface slick.

Abstract Many basins are dominated by vertical hydrocarbon migration. On seismic data, the vertical migration paths are generally recognized as vertically aligned zones of chaotic, often low-amplitude reflectivity. These are described variously as gas chimneys, blowout pipes, gas clouds, or hydrocarbon-related diagenetic zones. Analysis of the gas chimneys can be used for geohazard prediction, basin modeling, prospect risking, and many more applications. However, the weak expressions of gas chimneys in seismic data make them difficult to map. Thus, a method for detecting gas chimneys in poststack 3D seismic data has been developed to map their distribution and allow them to be visualized in three dimensions. This chimney probability volume is produced by a neural network from multiple seismic attributes extracted at examples of gas chimneys picked by the interpreter. Not all vertically aligned, low-amplitude, chaotic seismic reflectors represent hydrocarbon migration. Therefore, the subjective selection of training locations and the resulting neural-network predictions are validated by objective criteria before the results are used in geologic applications. Gas-chimney detection methods originally were used to highlight gas chimneys in shallow intervals to detect shallow gas reservoirs and geohazards. However, the methodology was soon used to highlight subtle, deep hydrocarbon migration pathways, hydrocarbon migration related to faulting, and expulsion from source rock. Other applications of gas-chimney analysis are overpressure prediction and prediction of the quality of gas-hydrate accumulations. Chimneys are classified based on their morphology and the relative position of the trap, faults, and chimneys. This classification provides criteria for risking top seal, vertical fault seal, and hydrocarbon charge on exploration prospects prior to drilling.

Abstract Oil seeps, shallow gas, and surface features such as seabed pockmarks and mud volcanoes are historically believed to be signs of deeper hydrocarbon accumulations. In the search for connections between shallow features and deeper hydrocarbon accumulations, gas chimneys and faults have been studied as possible routes for vertical migration of gas and fluids from source rocks and hydrocarbon-charged traps. Understanding these fluid migration pathways can help evaluate whether a trap is charged or has leaked. A method based on seismic attributes and use of neural networks has been developed to detect and display gas chimneys. This method makes it possible to detect and map gas chimneys in a consistent manner and to see the position of chimneys relative to faults and traps. The detection of gas chimneys in seismic data has therefore been used as a tool in an effort to distinguish between hydrocarbon-charged traps and dry traps with associated chimneys. Based on such case studies, a model of trap classification has been proposed and tested on more than 100 drilled traps in the Norwegian North Sea with good results.

Abstract Chimney analysis can help us assess reservoir risk in a gas field. Seismically derived gas-chimney volumes can be used to determine migration paths and relate them to surface seeps and mud volcanoes. From the chimney cubes, we observe the vertical hydrocarbon migration paths that can be interpreted from a source into reservoir traps and then to the near surface (shallow gas) and surface (seeps). Using data from the Ibhubesi field in Orange River Basin, South Africa, we examined many applications of chimney cubes, including unraveling the hydrocarbon history and migration paths; ranking prospects; detecting reservoir leakage, spill points, and sealing versus nonsealing faults; identifying potential overpressured zones and drilling (shallow gas) hazards; and revealing areas of seafloor instability. We exploited the principle of directional attributes to highlight areas in the seismic volume that are likely gas chimneys. Aside from conventional single-trace attributes such as amplitude, frequency, and energy, directional attributes such as dip-angle variance with different step-outs, similarity measures, and dip-azimuth-based contrast enhancement can be used in the neural network. Similar ideas are used to detect chimneys as well as other objects and interfaces such as faults, stratigraphic bodies, direct hydrocarbon indicators, and time-lapse objects. Chimney cubes are produced by running a selected and appropriately weighted set of attributes through a supervised multilayer perceptron (MLP) neural network. The weights are determined by training the network from available information and geologic interpretation.

This is the index to the book.

With the increased resolution power of many geophysical methods, we are seeing direct evidence of seeps on a wide variety of data, including conventional seismic. New methods and technology have also evolved to better measure and detect seeps and their artifacts and reservoir charge and to map migration and remigration routes. In addition, detection of seepage is important for minimizing the risks associated with shallow gas drilling hazards, ensuring platform stability, and preventing well blow-outs.