Vertical Hydrocarbon Migration Research Articles

Controls by organic geochemistry trackers of secondary hydrocarbon accumulation during Neotectonic central uplift of the Tarim basin

Abstract Because of the Himalayan Neotectonic uplift, the Tarim Tectonic Block, a cratonic terrane which contain cover rocks of the Lower Paleozoic marine succession (a marginal basin containing huge petroleum paleo-reservoirs) experienced strong extrusion tendency. This extrusion was one of the most important factors to control the migration or accumulation of petroleum, and impact the pattern of paleo-reservoirs. In the Tarim basin, the Neotectonic activity tilted the Carboniferous and younger formation and activated old fractures. The inherited active faults of Tazhong area are mainly distributed in two big groups, respectively around the central uplift and the Tazhong-I faults. Tazhong-4 structure is combined with the two major fault zones, and is strongly affected by Neotectonics. According to the distribution characteristics of triaromatic dinosterane, 4-methyl-cholestanes and other special biomarkers in the oil samples of Tazhong-4 area, it was showed that oils in the different reservoirs were from the same source. And the vertical Pressure–Volume–Temperature (PVT) characteristics of the petroleum reservoirs changed from unsaturated oils into the unsaturated condensates. It was shown that the Tazhong-4 reservoirs had experienced a complicated accumulation process of multi-period charge, mixture and adjustment, which related closely with the multi-stage compressive Neotectonics affecting the Cenozoic sequences of the Tarim Basin and its lower paleozoic source rocks and paleo-reservoirs. The transport parameters of nitrogen compounds indicated the vertical migration of petroleum in the Tazhong-4 reservoirs. The paleozoic and current oil–water contacts (POWC & OWC) could be clearly separated by the analysis of the grains with oil inclusion (GOI). Based on the gas chromatography of oil–sand between POWC and OWC, biodegradation was not obvious. That reflects the formation of OWC and migration of POWC occurred much later. Recent activity of fault led to vertical migration of hydrocarbons and the OWC of paleo-reservoir ascended. In the central uplift of basin platform area, the multi-stratum hydrocarbons migrated and accumulated along the active faults, opening during Neotectonic activity.

The Accumulation Rules of Budate Burial Hill Hydrocarbon Reservoir of Suderte Oilfield in Hailar Basin

Metamorphic rock burial hill reservoir of Beier rift in Hailaer Basin, with large scale reservoir and high output has complex fault system. The fault through going direction roughly is NEE direction, and has wide fault section and lateral quickly changed fault displacement. Metamorphic rock reservoir can be divided into the vertical weathered fracture zone, crack and dissolved pores and caves development belt and tight zone. Accumulation is controlled by hydrocarbon ability of source rock, contacting relationship of source rock and reservoir, oil storage ability of reservoir, and vertical and lateral hydrocarbon migration ability of fault and unconformity surface. And formed top surface weathering crust accumulation pattern which the hydrocarbon migrated laterally along the unconformity surface, and interior reservoir pattern of crack broken zone accumulation which hydrocarbon migrated vertically along fault.

Development characteristics and hydrocarbon accumulation significance of fractures in Lower Silurian Kalpintag Formation, northern slope of central Tarim Basin

Abstract Based on the data of core, microscope thin section, scanning electron microscope, cathode luminescence, and conventional and dipole acoustic logging, the development characteristics and hydrocarbon accumulation significance of fractures in the Lower Silurian Kalpintag Formation on the northern slope of the central Tarim Basin were studied. A large number of mainly high-angle or vertical fractures developed in the study area. They feature low density, long length, medium width and low filling extent. More fractures were found in the relatively weak bands of rock, such as the margins and interlayers of boulder clays. Conventional logging curves showed two peaks and one order of magnitude difference. The anisotropy of fast shear wave in dipole acoustic logging showed that fracture development was influenced by NE trending strike-slip faults and the NE-SW trending maximum horizontal principal stress. The fractures in the Kalpintag Formation played important roles in the formation of tight sand-stone reservoirs. They improved the porosity and permeability of tight sandstones, and the large-scale, high-angle or vertical fractures served as pathways for vertical migration of hydrocarbons. For the small-scale adjustment of hydrocarbon migration, the small-scale, low-angle or horizontal fractures were important.

Vertical anomaly clusters: Evidence for vertical gas migration across multilayered sealing sequences

We present the results of a seismic interpretational study of amplitude anomalies in the East Falkland basin using an extensive grid of approximately 8000 line kilometers (4971 line miles) of high-resolution two-dimensional seismic reflection data. We mapped 474 discrete amplitude anomalies developed within a dominantly hemipelagic and highly reflective megasequence of the Cretaceous to early Cenozoic that is distributed in a northeast–southwest swath across the basin. The amplitude anomalies range from a kilometer to over 25 km (15.5 mi) in lateral extent, have sharp lateral amplitude cutoffs, sometimes at faulted margins, and are invariably associated with reflections with negative acoustic impedance contrasts. They exhibit class III amplitude versus offset (AVO) responses, frequency shadows, and push-down effects, from which the amplitude anomalies are interpreted as related to free gas. All the amplitude anomalies are characterized by vertical clustering, and based on this strong spatial association we refer to these mappable groups of amplitude anomalies as vertical anomaly clusters (VACs). We suggest that VACs form by strongly focused vertical hydrocarbon migration in a heterogeneous stacked sequence of poor-quality reservoirs interbedded with layers with lower permeability, and where the necessary bottom-to-top cross-stratal flow exploits a well-developed fault and fracture network. Similar vertical associations of gas-related amplitude anomalies could be expected in many other basins, so VACs may be a useful direct hydrocarbon indicator with specific genetic significance for hydrocarbon migration mechanisms.

Analysis of main controlling factors for hydrocarbon accumulation in central rift zones of the Hailar-Tamtsag Basin using a fault-caprock dual control mode

The Hailar-Tamtsag Basin is a typical rift basin where two sets of regional caprocks are developed, i.e., mudstone caprocks (containing a small amount of tuff) developed in strong rifting stage and fault-depression stage, respectively. The caprocks have a cumulative thickness of 50–120 m in general, and a single-layer thickness of 20–50 m, interbedded with sandstone about 1–2 m thick. The large set of mudstone is distributed continuously, as pure mudstone caprock. Forty-three mudstone and tuff samples were taken to perform displacement pressure test with our independently developed displacement pressure tester. Test result shows that the displacement pressure is 0.04–10.00 MPa, which is equivalent to 0.09–20.01 MPa after being corrected to the actual burial depth. As the burial depth increases, the displacement pressure rises gradually, and is 1–10 times greater than that of oil-bearing sandstone or conglomerate reservoir at the same burial depth. The difference between displacement pressure of mudstone caprock and sandstone or conglomerate reservoir increases greatly if the burial depth exceeds 1000 m. Because of the displacement pressure difference between caprock and reservoir, the maximum height of hydrocarbon column sealed by the caprock ranges from 300 m to 2000 m, much higher than the height of the trap closure at the same burial depth. No hydrocarbons will leak through such caprocks. Analysis of the reservoir GOI, homogeneous temperature, and crude maturity of both deep and shallow reservoirs in Well Wu-20 in the Wuerxun Depression shows that Damoguaihe II Member reservoir is a secondary reservoir developed during adjustment of early reservoir. It is mainly distributed in inverted structures. Faulting is one of the main factors breaking the integrity of caprocks. Three kinds of faults are often related to the migration of hydrocarbons across regional caprocks: the first type refers to the positive inverted faults breaking the early sealing conditions and making the hydrocarbons accumulated in the early period re-migration; the second type refers to the faults with shear mudstone smear structures which lose their continuity and open vertically when the fault throws exceed 5 times of the mudstone thickness; the third type refers to the normal faults developed in the structural inversion stage, which have a typical cataclastic structure and are easy to cause vertical migration of hydrocarbons. Hydrocarbon enriched horizons of the rift basins are co-controlled by “fault-caprock”. Specifically, 95% of the geological reserve is controlled by regional caprocks, and only 5% is controlled by open faults, secondary oil/gas reservoirs are developed over regional caprocks.

Distribution of aromatic hydrocarbons in the context of sediments of oil and gas bearing complexes (on the example of Krasnoleninsky arch deposits)

On the base of unique geochemical studies of the core samples from two exploration wells interstratal movement of heavy oil hydrocarbons has been revealed in the section of Rogozhnik-ov and North-Rogozhnikov deposits of the Krasnoleninsk dome (West Siberia). Geochemical model of vertical migration of heavy oil hydrocarbons has been plotted where those compounds have been distinguished which are capable of interstratal movement, the form of migration has been proposed and the distance of movement of substances in the section has been estimated. The distance of vertical interstratal migration of aromatic hydrocarbons makes it possible to recommend their anomalous concentrations as direct prospecting criteria. Migration of oil hydrocarbons from the sedimentary cover to basement deposits has been revealed.

Identification of a large Upper Cretaceous polygonal fault network in the Hammerfest basin: Implications on the reactivation of regional faulting and gas leakage dynamics, SW Barents Sea

We use a high resolution 3D seismic dataset covering 970km2, over the Snøhvit and Albatross gas fields of the Hammerfest Basin in the Barents Sea, in order to investigate the basin fault architecture and identify potential fluid pathways of deeper thermogenic gas and fluids. A polygonal fault (PF) interval not previously published is described in the three non-connected blocks within Campanian sequences, which could imply a permeable complex network of pathways that facilitate the vertical migration of hydrocarbons along the fault planes. The dominant orientation of the PFs is similar to the main regional tectonic fault trend (EW), suggesting a tectonic influence upon the development of polygonal faults, although some individual PFs locally seem to develop orthogonally to regional 1st order tectonic faults. A lithologic control on the occurrence of PF patterns is evident as none are observed within calcareous low clay sediments. The PF networks present three main orientations: dominant ENE/WSW, secondary NNE/SSW and a minor NE/SW. Paleocene–Early Eocene Faults (PEEFs) prevail above the PF networks, with coinciding ENE/WSW fault strikes, interpreted as preferential reactivation of the PF systems. Numerous amplitude anomalies, linked to the escape of thermogenic fluids from the Jurassic reservoir were identified. We present a conceptual model where the 1st order reactivated faults and PEEFs acted as pathways for fluids from the deeper hydrocarbon reservoirs. The PEEFs are partially sealing with a lateral migration component. Interplay between the PFs, PEEFs and the 1st order reactivated faults focuses the fluids vertically along the polygonal fault traces creating a wider diffuse zone which form large gas cloud anomalies in the seismic data.

Distribution and sources of petroleum-hydrocarbon in soil profiles of the Hunpu wastewater-irrigated area, China's northeast

Petroleum-contamination soil is ubiquitous. The various sources of this contamination necessitate the effective evaluation of the contamination level, contaminant transport analysis and identification of the pollution sources. In the present study, soil profiles were collected from both upland and paddy fields along the strike of the irrigation canals in the Hunpu wastewater irrigation region in northeast China. The concentrations of aliphatic hydrocarbons in the soil were analyzed. The sites near the oil wells, wastewater irrigation canal and Shenyang City were found to have high concentrations of [∑n-alkanes (sum of n-alkanes): (0.8 to 32.2) μgg−1 dry wt.; TAH (total aliphatic hydrocarbons): (5.0 to 161.2) μgg−1 dry wt.]. The geochemical analysis results showed various degrees of petroleum pollution. The ∑n-alkanes varied (0.5 to 7.5) μgg−1 while TAH varied (1.6 to 47.2) μgg−1 at other sites where biogenic hydrocarbons were dominant. The results from the principal components and redundancy analyses showed that the samples containing hydrocarbons from wastewater irrigation, oil wells, and atmospheric deposition were partitioned into different groups. These results further represented that the soil properties had some effects on hydrocarbon distribution especially the sand content which had significantly negative correlation with oil-related hydrocarbons. The current study showed that the early input and vertical migration of hydrocarbons resulted in a high deep-soil hydrocarbon concentration.

Oil hydrocarbon migration in soils of the northeast of Sakhalin Island

The results of vertical and lateral intrasoil migration of oil hydrocarbons (OHCs) in podzolic, techno-podzolic, brown forest, alluvial meadow-bog, and peat gley soils of Sakhalin Island are presented in this article. An estimation of the spatial distribution of oil hydrocarbons on the surface of oil spills, industrial sites, and natural discharges of oil is made. The factors influencing the structure of contamination halos and migration intensity of oil hydrocarbons in soils are considered.

Role of the Chalk in development of deep overpressure in the Central North Sea

Abstract A high magnitude of overpressure is a characteristic of the deep, sub-Chalk reservoirs of the Central North Sea. The Upper Cretaceous chalk there comprises both reservoir and non-reservoir intervals, the former volumetrically minor but most commonly identified near the top of the Tor Formation. The majority of non-reservoir chalk has been extensively cemented with average fractional gross porosity of 0.08, and permeability in the nano- to microDarcy range (10 −18 –10 −21 m 2 ), and sealing properties comparable to shale. Hence deeply buried chalk is comparable to shale in preventing dewatering and allowing overpressure to develop. Direct pressure measurements in the Chalk are restricted to the reservoir intervals, plus in rare fractured chalk, but reveal that Chalk pressures lie on a pressure gradient which links to the Lower Cenozoic reservoir above the Chalk and the Jurassic/Triassic reservoir pressures below. Hence a pore pressure profile of constantly increasing overpressure with increasing depth is indicated. Mud weight profiles through the Chalk, by contrast, show many borehole pressures lower than those indicated by these direct measurements, implying wells are routinely drilled underbalanced. The Chalk is therefore considered the main pressure transition zone to high pressures in sub-Chalk reservoirs. In addition to its role as a regional seal for overpressure, the Base Chalk can be shown to be highly significant to trap integrity. Analysis of dry holes and hydrocarbon discoveries relative to their aquifer seal capacity (the difference between water pressure and minimum stress) shows that the best empirical relationship exists at Base Chalk, rather than Base Seal/Top Reservoir, where the relationship is traditionally examined. Using a database of 65 wells from the HP/HT area of the Central North Sea, and extending the known aquifer gradients from the Fulmar reservoirs via Base Cretaceous to Base Chalk, leads to a risking threshold at 5.2 MPa (750 psi) aquifer seal capacity. Discoveries constitute 88% of the wells above the threshold and 36% below, with 100% dry holes where the aquifer seal capacity is zero (i.e. predicted breached trap). This relationship at Base Chalk can be used to identify leak points which control vertical hydrocarbon migration as well as assessing the risk associated with drilling high-pressure prospects in the Central North Sea.

Petroleum systems of the Bass Basin: a 3D modelling perspective

Petroleum generation, expulsion, migration and accumulation have been modelled in 3D at basin-scale for the Bass Basin, Tasmania. The petroleum systems model shows several source rocks of different ages have generated and expelled sufficient hydrocarbons to fill structures in the basin; however, the lithologies and fault properties in the model result in generally limited migration after hydrocarbon expulsion started. Impermeable faults, together with several fine-gained sealing facies in the Lower and Middle Eastern View Group (EVG) have resulted in minor vertical hydrocarbon migration in the lower parts of the EVG. An exception occurs in the northeastern part of the basin, where strike-slip movement of suitably oriented faults during Miocene reactivation resulted in breaches in deeper accumulations and migration to upper reservoir sands and, in several cases, leakage through the regional seal. The Middle Eastern View Group source rocks have produced most of the gas in the basin. Oil appears to be largely limited to the Yolla Trough, related to the relatively high thermal maturation of Narimba Sequence source rocks. In general, most of the hydrocarbon expelled from the Otway Megasequence occurred prior to the regional seal being deposited; however, modelling predicts it can contribute to the hydrocarbon inventory of the Cape Wickham Sub-basin. In particular, the modelling predicted an Otway sourced accumulation at the site of the recently drilled Rockhopper–1. In the Durroon Sub-basin in the Bark Trough, the Otway Megasequence is predicted to be the main source of accumulations. The modelling has provided detailed insights into migration in the existing plays and has allowed assessment of the reasons for previous exploration failures (e.g., a migration shadow at Toolka–1) and to suggest new locations with viable migration histories. Reservoir sands of the Upper EVG are only prospective in the Yolla and Cormorant troughs where charged by Early Eocene sources; however, Miocene reactivation is a major exploration risk in this area.

Differences between flow of injected CO 2 and hydrocarbon migration

Abstract Knowledge of fluid flow processes in the subsurface is important for CO 2 storage operations as well as for hydrocarbon exploration. Repeated seismic surveys for more than 10 years of CO 2 injection into the Utsira Formation, in the Sleipner area, offer a unique dataset. This dataset holds information on fluid migration processes that can be analysed for the benefit of hydrocarbon exploration and CO 2 storage considerations alike. Thorough analyses of these datasets reveal several features that give useful information of subsurface fluid flow processes. The CO 2 in the Utsira Formation has flowed laterally beneath thin, intra-formational shales. At the same time, CO 2 has flowed vertically through shaly horizons that would normally be considered as barriers to fluid flow. This flow has apparently taken place through vertically stacked flow conduits through the shales. These conduits may to some extent have existed prior to the start of CO 2 injection, but may also have been augmented by the CO 2 injection process. The calculated pushdown of seismic reflectors below the CO 2 plume is less than that observed, which may point to the presence of hitherto unrecognized flow paths for the CO 2 . Hydrocarbon migration pathways are in general not recognizable in seismic data. This implies that such avenues are significantly thinner than those of the CO 2 migration in the Utsira Formation. This result points to the presence of mixed-wet migration pathways, in which capillary flow resistance may not control the (sub-horizontal) flow path thickness. A circular depression at the top of the Utsira Formation that existed prior to the injection may be interpreted as a result of a deeper seated sand remobilization feature. Such features will also promote vertical hydrocarbon migration where they are present. A more widespread occurrence of such features may explain why hydrocarbons are generally found beneath thick shales, but are less likely to be found below thin intra-formational shales below the structural spillpoint of the top seal. These observations suggest that seal thickness is an important parameter, even if the capillary entry pressure of the sealing rock is sufficiently high to preserve significant hydrocarbon columns.

Petroleum geology of the Puguang sour gas field in the Sichuan Basin, SW China

The Puguang sour gas field in northeastern Sichuan Basin is the largest gas discovery in the Paleozoic marine strata in China, with at least 9 trillion cubic feet (tcf) of proven gas reserves. It is one of the many anticlinal structures formed during the Indo-Sinian orogeny, with gas being trapped in a composite structure–lithology pool. The presence of the Upper Permian coal measures, Lower Silurian and Lower Cambrian marine shales provided excellent hydrocarbon source rocks. The Lower Triassic and Upper Permian oolitic dolomites serve as high quality reservoir rocks, with 10–25% porosity and 1–1000 mD permeability, largely due to diagenetically produced secondary porosity. The Lower and Middle Triassic evaporate beds have acted as the direct top seal for the large Lower Triassic–Upper Permian gas accumulation. The thick Upper Triassic and Jurassic mudstone beds regionally cap the underlying marine carbonate strata. The deep-seated basement faults acted as vertical hydrocarbon migration conduits during faulting, and became effective flow barriers when the faulting ceased. The deep burial of a paleo-oil accumulation in reservoirs rich in sulfate resulted in extensive thermochemical sulfate reduction (TSR). This, together with the new gas injection and structural reconfiguration, transformed a paleo-oil pool to a large sour gas pool.

Nonconventional hydrocarbon targets in the crystalline basement, and the problem of the recent replenishment of hydrocarbon reserves

Analysis of the distribution of oil pools in sedimentary cover has shown that known platform hydrocarbon fields are closely associated with faults in the crystalline basement and the sedimentary cover itself. Oil pools in the lower productive beds of the sedimentary cover are linked to faulted zones in the crystalline basement. A genetic relationship between oil fields and tectonic dislocations indicates a dominant role for vertical migration in the accumulation of commercial hydrocarbons in the Paleozoic. The conducted geochemical, palynological, geophysical and geological studies have shown that oil and gas pools in the upper sedimentary cover have been formed due to the vertical migration of hydrocarbons, which is also confirmed by the vertical alignment of the oil pools.

Kinematic interpretation and structural evolution of North Oman, Block 6, since the Late Cretaceous and implications for timing of hydrocarbon migration into Cretaceous reservoirs

ABSTRACTOn the basis of structural style and differences in Late Cretaceous evolution, the carbonate platform in northern Oman and the allochthonous wedge comprising deepwater sediments and oceanic crust in the Oman Mountains form distinct structural domains. Imbrication associated with the emplacement of the Semail Ophiolite and predominantly SW-verging thrusting of the Arabian Platform margin culminated in the late early Campanian. The structural grain of NW-trending thrust faults and contractional folds contrasts markedly with the style and grain of the region immediately south of the Oman Mountains (our study area) and implies strong strain partitioning. Kinematic indicators from subsurface data, combined with the age of growth faulting, provide the basis for the interpretation that maximum horizontal stress was oriented NW-SE in this foreland region rather than NE-SW during the Campanian. The dominant tectonic control on the formation of faults is believed to have been an oblique “collision” of the Indian Continent with the Arabian Plate during the Santonian-Campanian. Deformation in this domain was dominated by distributed strike-slip and normal faulting. This period of faulting was significant for two reasons: (1) The faults both enhanced existing structures and formed new traps. They also allowed vertical migration of hydrocarbons from Palaeozoic reservoirs (e.g. Haushi clastic accumulations) into Shu’aiba and Natih carbonates above. Until that time, some 75 Ma ago, oil was retained in Late Palaeozoic and older traps. This period of deformation is a “Critical Event” within the context of Oman’s hydrocarbon distribution.(2) Faults with NNW and WNW orientations that developed at that time appear to be directly associated with important fracture systems that affect the productivity of several giant fields comprising Natih and Shu’aiba carbonate reservoirs (e.g. Lekhwair, Saih Rawl).Following this tectonic event, late Maastrichtian to Palaeocene uplift and erosion in excess of 1,000 m, is recorded by truncation of the Aruma Group and Natih Formation, as well as part of the Shu’aiba Formation below the base Cenozoic unconformity. Seismic velocity and porosity anomalies from Lekhwair field in the northwest to the Huqf-Haushi High in the southeast, provide additional support for the areal distribution of this event. Around the Lekhwair and Dhulaima fields, the circular to elliptical subcrop pattern below this unconformity does not support the notion of a peripheral bulge related to the emplacement of the allochthon.The stress field changed during the late Cenozoic with the opening of the Red Sea and Gulf of Aden, and the collision of the Arabian Plate with the Iranian Plate. NE-SW-oriented maximum horizontal stress during the late Cenozoic led to the formation of major folds resulting in, for example, the surface anticlines over the Natih and Fahud fields as well as causing inversion along the Maradi Fault Zone. This may also have led to the uplift of the Oman Mountains. The regional northerly subsidence caused by crustal loading of the Arabian Plate gently tilted traps during the Pliocene-Pleistocene from Lekhwair to Fahud.

タイ国第三系堆積盆地における湖成堆積層の発達と油ガス田の形成

Tertiary basins in Thailand are pull-apart basins which originated in coincidence with collision of Indian Plate and Eurasian Plate at the end of Cretaceous age. Lacustrine sediments of “Oligocene” age are commonly recognized in the lower part of the basins, which are known to act as source rock for crude oil both in onshore and offshore areas. Based on geochemical investigation of the basins, characteristic two patterns of petroleum system from the lacustrine source rock were recognized as (1) “syn-rift type” and (2) “post-rift type”. In the syn-rift type, source and reservoir rocks are interfingering, or reservoirs are located immediately above the source rocks, which lead to lateral migration or short vertical migration of hydrocarbons. In the post-rift type, source rocks are present at greater depth than reservoirs and, therefore, hydrocarbons should migrate vertically to shallower reservoirs and oil reservoirs and gas reservoirs coexist. Tertiary basins in Thailand originated with common lacustrine source rocks at the bottom. However, differences in the subsequent tectonic movement lead to the variations in depth and maturation level of the source rock and reservoir type. Consequently two different types of petroleum system were formed.

Petroleum system analysis: impact of shale diagenesis on reservoir fluid pressure, hydrocarbon migration, and biodegradation risks

Geological models for the effects of clay diagenesis on shale/mudstone properties are under evaluation for their use in predicting the distribution of hydrocarbon occurrences, and risk of biodegradation. Traditional clay petrology studies show that the onset of reactions, often described as smectite to illite diagenesis, begins at 60° to 80°C in sedimentary sequences. Petrophysical models based on the precipitation of diagenetic clay within shale pore systems indicate rapid and severe permeability reduction at the onset of this reaction. Evaluation of global petroleum systems in a variety of basin settings, including the North Sea and the Gulf of Mexico, indicate an exponential increase in probability of formation fluid overpressure and hydrocarbon occurrences at and above these temperatures, along with concurrent reduction in the risk of biodegradation of reservoired petroleum. The mechanism by which these risks are controlled in both cases can be related to clay diagenetic induced permeability reduction, which when combined with diagenetic porosity reduction models and geological factors restricting lateral drainage, increases the probability of vertical hydrocarbon migration via hydrofracturing of low-permeability shale units to create new petroleum systems/plays. The industry fails to appreciate the exponential increase in exploration risks as a function of reservoir temperature and often drills beyond the optimal entrapment zone of 60° to 120°C, with corresponding reductions in efficiency. Hydrocarbons which migrate to shallower depths and lower temperatures show an increased risk of biodegradation. The proposed migration mechanism is consistent with the distribution of global conventional oil resources at the basin scale. Geologically, however, spill-fill/lateral migration, mainly in foreland basin settings, has resulted in extensive heavy oil/tar sands deposits, which eluded entrapment at optimal conditions for recovery.

The spatial distributions of faults and deep sea carbonate mounds in the Porcupine Basin, offshore Ireland

Localised populations of deep water carbonate mounds occur throughout the NE Atlantic margin of Ireland, the UK and Norway, but the mechanisms responsible for their nucleation and growth are not well known. Based in part on the interpretation of seismic data from the Porcupine Basin, offshore Ireland, it has been proposed previously that deeply rooted faults are present immediately beneath mounds and act as conduits for the vertical migration of mound-feeding hydrocarbons. Several discrete carbonate mound populations or provinces are present in the Porcupine Basin above a number of distinct fault systems at different levels in the stratigraphy. However, detailed mapping of the distributions of both mounds and faults for two of these provinces in the northern part of the basin, using 3D and 2D seismic data, demonstrates that there is a poor spatial relationship between the two. Furthermore, virtually all the reflector offsets directly beneath the mounds, which have previously been interpreted as faults can be attributed to seismic artefacts such as velocity pull-ups and diffraction cones. Therefore, our findings strongly suggest that seismically mappable faults do not play a pivotal role, as conductive fractures, in the evolution of the mounds. However, mounds located towards the NW margin of the Porcupine Basin are underlain by a shallow, intensely faulted slide package, which provides one potential association between faults and mounds.

Evidence for Active Growth Faulting in the Terrebonne Delta Plain, South Louisiana: Implications for Wetland Loss and the Vertical Migration of Petroleum

Two regional growth faults, the Golden Meadow Fault and the Lake Hatch Fault, were mapped in Terrebonne and Lafourche Parishes, Louisiana, utilizing over 3000 line kilometers of seismic data. The subcropping location of these faults identify major vegetation biozonations, new areas of wetland loss, and the position of transgressive lakes. The proposed mechanism governing these fault-related manifestations of subsidence involves the venting of fluid (and gas) from geopressured shales vertically up fault planes. Saline fluids and gases exiting a basin via growth faults provide accommodation space at depth, resulting in active, fault-induced subsidence in the down-thrown block. By contrast, areas along the fault trend where no fluids or gases were migrating would not result in an increase of accommodation space and would be considered inactive regarding faultinduced subsidence. The model that emerges is a growth fault trace that does not act in concert but more closely resembles a key-stepping system with sections alternating between active and inactive. These findings are relevant to the role of growth faults in subsidence-related coastal land loss and the vertical migration of hydrocarbons.

The nature and interpretation of geophysical and geochemical anomalies over oil and gas fields

Geochemical prospecting seeks surface or subsurface evidence of vertical migration of hydrocarbons. One application is to directly determine the presence of oil and gas in the reservoir. The basic principles of geochemical methods were recently reviewed by Colin Barker ( TLE , June and July 1999) and by Dietmar “Deet” Schumacher ( TLE , March 2000). However, Barker's articles did not discuss the location/interpretation of surface geochemical anomalies that, for the explorationist, is a most interesting and important subject, and Schumacher's article mainly discussed the case of “apical” anomalies over oil and gas fields, that is not always the occurrence. Surface geochemical exploration for hydrocarbons began in the 1930s. It has had great successes and publicized failures. In some cases geochemical anomalies were reported directly over oil and gas accumulations (apical), but in many cases the anomalies appeared annular and formed a ring (“halo”) above the margins of the field. This ambiguity has been restricting the use of this technique for many years. Examples of both cases are abundant in scientific journals. However, seismic and magnetic anomalies have also been observed over the edges of hydrocarbon accumulations. I suggest that combining the methods can improve exploration success. Absorption has been relatively ignored as an exploration tool in the United States. One characteristic of hydrocarbon accumulation is an increase in attenuation and changes in the frequency content of waves passing through the accumulation. Thus, absorption can be an independent source of information about the presence of hydrocarbons. Modern seismic data can detect the frequency absorption caused by hydrocarbon accumulation. As with geochemical anomalies, these absorption anomalies are in …