Implications For Hydrocarbon Exploration Research Articles

Evolution of deepwater sedimentary environments and its implication for hydrocarbon exploration in Qiongdongnan Basin, northwestern South China Sea

Over the past several years, a number of hydrocarbon reservoirs have been discovered in the deepwater area of Qiongdongnan Basin, northwestern South China Sea. These oil/gas fields demonstrate that the evolution of the deepwater sedimentary environment are controlling the formation and distribution of large-scale clastic reservoirs. Integration between seismic and borehole data were necessary to best clarify the distribution and quality of these deepwater reservoirs. Geochemical and paleobiological evidence from discrete samples was also applied to document specific information regarding the sedimentary environment. Results show that the Qiongdongnan Basin has existed as a thriving marine environment since Oligocene, when several rifting depressions developed throughout the entire Qiongdongnan Basin. Triggered by the faults activities, several distinct provenances supplied the coarse sediments, transporting and depositing them in deep parts of the rifting depressions. A fan delta system then formed nearby the source in the deeper area of these rifting depressions. The sedimentary environment of Qiongdongnan gradiationally became deepwater since early Miocene. Consequently, abundances of sediments were transported from Hainan Island and Southern Uplift, and then sunk into the basin center. The submarine fans revealed by many boreholes in this area verified them as good reservoir. Because the area reached its lowest sea level at late Miocene and the Southern Uplift subsidenced under sea level, not providing any sediment, so that the carbonate mesa and biorhythms characteristic of this area also developed during this period. In the west part of Qiongdongnan Basin, sediments transported from Vietnam increased in response to the Tibetan Uplift. Consequently, a central canyon developed along the center of Qiongdongnan Basin, which has been confirmed by several boreholes as a favorable hydrocarbon reservoir. The clarification of the deepwater sedimentary environment’s evolution is potentially highly beneficial to future hydrocarbon exploration in the deepwater area of Qiongdongnan Basin.

Origin of diamondoid and sulphur compounds in the Tazhong Ordovician condensate, Tarim Basin, China: Implications for hydrocarbon exploration in deep-buried strata

In this paper, we analyse the Ordovician condensate in the Tazhong area of the Tarim Basin, NW China, using a new high-resolution comprehensive two-dimensional gas chromatography with time-of-flight mass spectrometry (GC × GC-TOFMS). Results show that 4778 compounds at a signal-to-noise ratio of more than 100 were detected, reflecting the advantage of this method in the analysis of condensate. Abundant adamantane series compounds and some diamantane series compounds, as well as a series of sulphur-containing compounds (including the benzothiophene series, and the dibenzothiophene series) were detected for the first time in the study area. Combined with the results of a study on oil and gas sources and migration/accumulation, we address the origin of these compounds. It is implied that the diamondoids were not formed in-situ due to oil cracking (in reservoir approximately 5500 m deep at temperature around 139 °C), whereas the cracking of oil to gas may have occurred in the deeper-buried Cambrian dolomite reservoir at a reservoir temperature of 180–220 °C (8500–11,000 m depth). The oil-cracked gas (secondary cracking product) might have migrated to and accumulated in the shallower-buried Ordovician reservoir, accompanied by abundant diamondoids. The formation of sulphur-containing compounds may be related to thermochemical sulphate reduction (TSR), which, similar to the oil cracking, took place in the deeper-buried Cambrian reservoir. Under high-temperature TSR, SO42− in the formation water is reduced to H2S and organic sulphur compounds, leading to the enrichment of sulphur in crude oils (e.g., benzothiophene, and dibenzothiophene series). As such, it is implied that the Tazhong area could potentially be explored for deep-buried oil-cracked gas.

4-D evolution of anticlines and implications for hydrocarbon exploration within the Zagros Fold-Thrust Belt, Kurdistan Region, Iraq

ABSTRACT The Zagros Fold-Thrust Belt, extending from southern Iran, through northern Iraq and into Turkey, is characterized by elongate NW-trending anticlines that house large hydrocarbon accumulations. In recent years, the Kurdistan region of northern Iraq has become an area of interest for both structural studies and petroleum exploration-related investigation. Key questions to be answered concern the nature of the anticlines and whether the geometry of any associated thrusts can be predicted from surface geomorphology, as well the 4-D evolution of the area and along-strike continuity of the anticlines. To address these questions, this study combines field data, remote-sensing data concerning the structure and geomorphology of the anticlines, and structural modeling in order to produce robust interpretations of the geometries of the reverse fault structures that core the majority of these anticlines. Results indicate that this methodology can be used to constrain potential thrust configurations at depth and the probable style of fold amplification and lateral propagation. In addition, this study shows that the growth of the anticlines can be considered in 4-D, with consideration given to the interaction of the Zagros-age deformation with the pre-existing basement fabric. We demonstrate that combining both structural and geomorphological methodologies can lead to a better understanding of the geometry and evolution of the trap-forming structures in the Kurdistan region of Iraq and thus is expected to be of interest to the petroleum industry.

Neoproterozoic Re–Os systematics of organic-rich rocks in the São Francisco Basin, Brazil and implications for hydrocarbon exploration

The São Francisco Basin contains a remarkable archive of Neoproterozoic strata and its hydrocarbon-bearing strata are receiving increasing attention as global oil and gas exploration targets progressively deeper and older rocks. New Re–Os geochronology for the Paracatu Slate Formation of the Canastra Group, Brazil, yields a depositional age of 1002±45Ma. This age represents the first successful application of the Re–Os system to rocks of this group and indicates excellent agreement with a previously published U–Pb detrital zircon age (Rodrigues et al., 2010). Together with TOC values of ca. 2wt.% (despite greenschist metamorphism), it might be argued that the São Francisco Basin has had the potential for hydrocarbon generation since the Tonian (1000–850Ma). In addition, we also report an imprecise Re–Os age (1304±210Ma) for the Serra do Garrote Formation, a further potential source rock of the Vazante Group. We suggest, based on petrological evidence, that the Re–Os systematics were disturbed by post-depositional fluid flow that was most likely associated with Vazante ore deposit mineralization. An attempt to determine a Re–Os date for the Sete Lagoas Formation, a putative post-Sturtian cap carbonate, is precluded owing to low Re abundances (≤100ppt). Major environmental changes in the aftermath of the Jequitaí glaciation, particularly the development of palaeotopography such as subglacial tunnel valleys, may account for the apparent random distribution of TOC enrichment in these Cryogenian/Ediacaran post-glacial deposits. This scenario might thus have major implications for the hydrocarbon prospectivity of this post-glacial succession.

Carbonate karst reservoirs of the Tarim Basin, northwest China: Types, features, origins, and implications for hydrocarbon exploration

Karst reservoirs are important exploration targets in marine carbonates of hydrocarbon-bearing basins around the world. In the Tarim Basin of northwest China, four types of carbonate karst reservoirs were delineated using data from more than 200 wells, including cores, thin sections, wireline logs, drilling logs, and production data; these were supplemented with seismic and other data. The four types of karst reservoirs described were all formed by meteoric water circulation but not limited in the vadose or phreatic zones, including buried tower karst, interlayer karst, overlying-aquiclude confining karst, and fault-related karst. Buried tower karst occurred in the carbonate successions underneath a regional unconformity (buried tower area), resembling the active karsting in the Guilin Region of South China. Interlayer karst developed during a relatively shorter exposure period compared with buried tower karst but is also situated on a paleouplift. Overlying-aquiclude confining karst is essentially a by-product and on the fringes of buried tower karst, and though it appears to be distributed evenly below a disconformity, it is not related to the disconformity in origin. Fault-related karst occurred in the carbonate succession of a high steep anticline with faults cutting through aquicludes and into the carbonates; dissolution is concentrated along faults and the crest of the anticline. We studied three previously undocumented types of karst and proved that karst reservoirs in the Tarim Basin occur not only in the carbonate succession under a regional unconformity, but also where no significant unconformity is recognized. Similar examples have been found in other basins of China and are expected to occur in other basins worldwide, particularly in areas of complex geologic history.

Early Palaeozoic evolution of Libya: perspectives from Jabal Eghei with implications for hydrocarbon exploration in Al Kufrah Basin

AbstractThis paper presents new stratigraphic and sedimentological data of the Ordovician, Silurian, and Mesozoic succession exposed on the western flank of Al Kufrah Basin. Field data (logged sections, photographs, palaeocurrent analyses) are presented from the Jabal Eghei region. This region lies ca. 200 km E of the closest stratigraphic tie point at Mourizidie on the eastern flank of the Murzuq Basin. The succession starts with the Hawaz Formation (Middle Ordovician) comprising >100 m of cross‐bedded and bioturbated sandstones that are interpreted as deposits of tidal currents in an open shelf setting. The contact between the Hawaz and Mamuniyat formations is an erosional unconformity, incised during advance of Late Ordovician ice sheets towards the NE. The Mamuniyat Formation comprises >150 m of massive and graded sandstones tentatively assigned to the Hirnantian, and contains an intraformational, soft‐sediment striated surface that is interpreted to record re‐advance of ice sheets over Jabal Eghei. The outcrop section suggests the sandstone would form an excellent reservoir in the subsurface. The Mamuniyat Formation is overlain by the Tanezzuft Formation (uppermost Ordovician–lowermost Silurian). This includes sandy limestone/calcareous sandstone, a Planolites horizon, and then 50 m of interbedded shale, silt and fine‐grained, graded and hummocky cross‐stratified sandstone recording deposition from both shallow marine turbidity currents and storm flows. A striated pavement in the lower part of this sequence is overlain by calcareous lonestone‐bearing intervals (interpreted as ice‐rafted debris). These features testify to late phases of glacial advance probably post‐dating the regional Hirnantian glacial maximum. The basal Silurian ‘hot shale’ facies is not developed in this area, probably because late glacial advance suppressed the preservation of organic matter. The upper part of the Tanezzuft Formation is truncated by an unconformity above which palaeosol‐bearing fluvial deposits (undifferentiated Mesozoic) occur.

Cenozoic salt tectonics in the Officer Basin, Western Australia: implications for hydrocarbon exploration

The Neoproterozoic western Officer Basin has a total sedimentary fill of up to 8 km and a depositional history with similarities to other central Australian basins, particularly the Amadeus Basin. The size and remoteness of the basin has traditionally been an impediment to exploration, and only sparse seismic and well data are available. In such areas, potential field data can be a powerful exploration tool to assess petroleum prospectively. Salt distribution and mobilisation in the Officer Basin is poorly understood and has been significantly under-estimated due to a lack of quality seismic data. Examination of the existing aeromagnetic, gravity and seismic data, along with satellite and Shuttle Radar Topography Mission (SRTM) data, indicate that surface and shallow salt is abundant in the northern and central parts of the basin. Remobilisation of salt is greatest in the eastern part of the study area, decreasing towards the west, although the extent of salt occurrence to the west is unclear. Salt diapirs occur along structural trends; east to west in the northeastern (Gibson) part of the basin, and northwest to southeast in the central (Yowalga) area. Neotectonic features such as surface lineaments and recent earthquake data suggest that minor tectonic reactivation is occurring in the present day, and is consistent with a present-day stress orientation of approximately 095°. Miocene to recent stress orientations suggest that structures in the Gibson area may have been reactivated as right lateral faults, whereas those in the Yowalga area are reactivated as left lateral faults. Potential trap styles in the western Officer Basin include structural plays related to salt movement, such as drape folds, diaper overhangs, and thrusts. Late-stage movement of salt must, therefore, be considered when assessing the timing of migration pathways and possible seal breach. An improved understanding of the extent of salt in the Officer Basin, and the degree of reactivation during the Cenozoic, is vital for successful exploration in the region. Acquisition of high-resolution magnetic and gravity data would be a cost-effective exploration tool for better definition of salt and associated hydrocarbon traps.

Influence of igneous sills on Paleocene turbidite deposition in the Faroe–Shetland Basin: a case study in Flett and Muckle sub-basin and its implication for hydrocarbon exploration

Abstract A new interpretation on three-dimensional seismic data from the Flett and Muckle sub-basins of the Faroe–Shetland Basin has shown dyke and sill emplacement influencing the Paleocene turbidite deposition. Sill and dyke emplacement in the study area created significant inflation anticlines during Paleocene time and affected palaeotopography at the seafloor. The uplift of older Early Paleocene (Sullom) and Middle Paleocene (early Vaila) turbidite deposits results in their erosion and redeposition in adjacent lows or transports them further into the basin by erosive channels. By using public domain well and biostratigraphic data from wells 208/19-1, 206/2a-1 and 206/1-2, seismic data and the use of seismic sequence stratigraphy to map the onlapping seismic reflectors on the flanks of the inflated anticlines, the relative timing of sill emplacement in the study area is shown to be Early–Middle Paleocene. The ability to identify these systems and understand the interaction between palaeotopography and Paleocene turbidite deposition in the basin is key to unlocking the hydrocarbon potential in the UK flank of the Faroe–Shetland Basin.

Evolutionary characteristics of the sags to the east of Tan–Lu Fault Zone, Bohai Bay Basin (China): Implications for hydrocarbon exploration and regional tectonic evolution

Some Cenozoic half-grabens (sags) have been found to the east of the Tan–Lu Fault Zone in the Bohai Bay Basin, east China. The evolutionary history of these sags is consistent with the entire Bohai Bay Basin; besides, some remarkable characteristics which had not been mentioned in previous studies of the Bohai Bay Basin are presented, and they are the keys to understand the regional tectonic evolution. Among them, two characteristics are emphasized: (1) the structural and evolutionary features of the sags were markedly changed at about 38Ma; (2) the Paleogene basin underwent several times of uplifts and denudations during Paleogene. The first characteristic shows that the normal faulting was the dominant structural deformation before 38Ma, and after then, the strike-slip movement might initiate to influence the basin. The second characteristic indicates remarkable reducing of the present-day residual basin relative to the original basin and, implies the episodic uplifting of the Jiaoliao massif. Besides, our estimation on the hydrocarbon exploration potential of these sags shows that part of them can sustain the formation of medium-large oilfield independently, while, part can contribute to the formation of large oilfield.

Diagenetic Implications of Stylolitization In Pelagic Carbonates, Canterbury Basin, Offshore New Zealand

Abstract Stylolites are irregular discontinuity surfaces that are thought to result from localized stress-induced dissolution during burial or tectonic compression. The genesis of stylolites and the controls on stylolitization are still debated, and the interplay between stylolitization, generation of carbonate-rich fluids, diagenetic fluid flow within fractures and matrix, cementation, and porosity modifications is complex. All of these processes have important diagenetic effects potentially altering the intrinsic properties of the host rock, with implications for hydrocarbon exploration and water resources in aquifers. We investigate the process of stylolitization by a macroscopic, petrographic, and geochemical study of pressure-solution features in Eocene to early Oligocene limestones in cores from the Integrated Ocean Drilling Program (IODP) Hole 317-U1352C (Canterbury Basin). The results indicate correlations among stylolite amplitude, stylolite density, and siliciclastic content of the host rock. These relationships are interpreted to suggest that siliciclastic content in carbonate rocks increases heterogeneity, which in turn impacts stylolite nucleation. Moreover, the geochemical data support that clay along the stylolite is not authigenic, but a relict from impurities in the limestone host rock. The statistical approach of stylolite spacing used in this study, which is different than previous studies, reinforces the model of random occurrence of stylolites in (carbonate) lithologic units. This study shows that local stresses in tectonically passive areas may allow the formation of rare oblique stylolites with peaks perpendicular to the stylolite plane. Estimation of the amount of limestone dissolved during stylolitization (minimum 7% to 12% of the depositional limestone) and the volume of sparite in the host rock (up to 1.6% of the compacted limestone) suggests that the pressure-solution fluids cemented the micropores, reducing porosity to about 10% (from a common porosity of about 40% in mechanically compacted chalk). This study thus highlights the importance of microporosity as a sink for burial cements, an observation difficult to make in thin-section. Analysis of stylolite infills at Site U1352 shows no evidence that the stylolites acted as conduits for diagenetic fluids, unless if the fluid was host-rock buffered and thus its chemistry indistinguishable from that of the host rock. The link between siliciclastic content in carbonate rocks and the spacing and amplitude of stylolites improves understanding of burial compaction processes. Predicting the morphology and spacing of stylolites in the subsurface can be used to identify baffles to cross-stylolite fluid flow or cementation (of microporosity) influencing heterogeneity of petrophysical properties in (subsurface reservoir) host rocks.

A well-preserved 250 million-year-old oil accumulation in the Tarim Basin, western China: Implications for hydrocarbon exploration in old and deep basins

A giant oilfield (YM-2) with an estimated reserve of close to one billion bbl was recently discovered in an Ordovician carbonate reservoir at a burial depth of 5800–6200 m in the northern Tarim Basin, western China. Biomarker and isotope geochemistry of the hydrocarbons indicate that the oil was derived from Ordovician marine source rocks at early to peak oil generation. Authigenic illite (K–Ar) dating, fluid inclusion analysis, fluid inclusion PVTx and thermal history modeling indicate that the accumulation is of primary in origin, and the original charge occurred in the Permian during the Late Hercynian Orogenic Stage, approximately 290–250 million years ago. The physiochemical compositions of the hydrocarbons and formation water remained largely unchanged since the initial accumulation. The excellent preservation of such an old accumulation at such a great depth is due to continuous burial of the YM-2 structure since the Triassic, a thick effective seal, and a relatively low geothermal gradient with a current reservoir temperature of 127–130 °C. This finding suggests that under suitable conditions old petroleum accumulations can be well-preserved, and some old and deep basins may be prospective frontiers for future exploration.

Origins of gypsum in deep carbonate reservoirs: Implications for hydrocarbon exploration and production

Gypsum can form penecontemporaneously in carbonate sediments, and it may be altered to anhydrite during burial. Some workers have suggested that gypsum dehydration is complete at burial depths of 3500 ft (1067 m); however, gypsum has been documented at depths as great as 13,100 ft (3993 m). Two examples of deeply buried gypsum illustrate contrasting origins. Gypsum in the Permian San Andres Formation in the Permian Basin of west Texas at a depth of 6000 ft (1829 m) occurs as anhydrite nodules with an outer rind of gypsum, suggesting that anhydrite was rehydrated to gypsum by interaction with interstitial brines. In contrast, gypsum in the carbonate beds of the Cretaceous Ferry Lake Anhydrite of the Mississippi Interior Salt Basin at 13,100 ft (3993 m) occurs as gypsum nodules with a rind of anhydrite, suggesting that the gypsum is primary and in the process of dehydration to anhydrite. These contrasting origins are likely a function of evaporite and carbonate stratigraphy. In the Permian Basin, a thick section of carbonate rocks is overlain by a relatively thin section of evaporites. In the Mississippi Interior Salt Basin, carbonates are interbedded with multiple evaporite beds, which inhibit circulation of interstitial brines. The burial temperature, pressure, and salinity of these formations suggest that gypsum could be preserved as primary or secondary gypsum. The presence of gypsum in reservoir rocks can affect porosity calculations, especially calculations using neutron porosity logs, which measure bound water of hydration in gypsum as porosity. Identification of gypsum at the depth of 13,100 ft (3993 m) indicates that log estimates of porosity in some deep carbonate reservoirs containing gypsum could have significant porosity and water saturation measurement errors.

Dolomitization of the lower Ordovician Catoche formation: Implications for hydrocarbon exploration in western Newfoundland

The lower Ordovician St. George Group in Western Newfoundland consists of a sequence of subtidal and peritidal carbonates, which are extensively dolomitized. The current study investigates the diagenetic evolution of the Catoche Formation from the Port aux Choix and Port au Port peninsulas in order to study the controls on reservoir quality in western Newfoundland. The Catoche Formation dolomites are classified into three main generations. Early and pervasive replacement dolomite (D1) indicates that dolomitization began during early stages of diagenesis. Stable isotope and trace element data indicate significant variations between D1 dolomite on the Port aux Choix and Port au Port peninsulas. The depleted δ 18O signature of D1 dolomite fluids (−8.7 ± 1.3‰ VPBD) on the Port aux Choix Peninsula is consistent with partial dolomitization associated with mixing of seawater and meteoric waters on the flanks of structural highs. In contrast δ 18O values (−6.1 ± 0.7‰ VPBD) and trace element data from the Port au Port Peninsula indicate that pervasive D1 was associated with mixing of possibly post evaporitic brines with meteoric waters. Later-stage replacement dolomites (D2) are associated with enhancement in porosity through the development of intercrystalline pores, while latest stage saddle dolomite (D3), significantly occluded the pores in some horizons. D2 dolomite formed due to the influx of warm (>100 °C), saline (>15 eq. wt% NaCl) fluids. Intercrystalline porosity in D2 formed due to the dolomitization of precursor calcite, due to the lower molar volume of dolomite compared to calcite. Therefore porosity development is lower on the Port au Port Peninsula, with no significant volume change during the recrystallization of the pervasive early (D1) dolomicrite. Similarly, extensive porous horizons on the Port aux Choix Peninsula are related to the limited extent of D1 dolomitization. This suggests that the quality of a potential dolomite reservoir is strongly controlled by tectonic and diagenetic history of host carbonates.

The dinoflagellate cyst Subtilisphaera from the Eocene of the Qaidam Basin, northwest China, and its implications for hydrocarbon exploration

Although an abundance of 4-methyl-sterane and dinosterane thought to derive from dinoflagellates, has been detected in the Palaeogene source rocks and crude oils in the Qaidam Basin, China, no unequivocal dinoflagellate cysts have been found previously in Cretaceous–Palaeogene terrestrial deposits in this basin, including the Xiaganchaigou Formation. This study reports on a new discovery using detailed analysis of a dinoflagellate cyst assemblage, composed solely of Subtilisphaera, from the Xiaganchaigou Formation on the north margin of the Qaidam Basin. The biomarkers 4-methylsterane and dinosterane in the corresponding fossil-bearing beds have also been detected, further validating the dependability of dinoflagellate cysts. These fossils provide direct evidence of the dinoflagellate contribution to Palaeogene crude oil in the Qaidam Basin and fill a long-existing gap in oil-source correlation.

Geometry of winglike clastic intrusions adjacent to a deep-water channel complex: Implications for hydrocarbon exploration and production

Because of their potentially large volumes and excellent reservoir properties, winglike clastic intrusion complexes may represent stand-alone exploration targets. However, determining the three-dimensional (3-D) geometry of such complexes is problematic because of limited exposure in the field and insufficient seismic resolution and well coverage in the subsurface. In this study, high-quality 3-D seismic reflection data from offshore Norway are used to determine the 3-D geometry of winglike intrusion complexes adjacent to a deep-water slope-channel complex. Intrusions form sheets or wings that are developed almost continuously along both margins of the 15-km (9-mi)-long channel complex. Intrusions dip up to 20 (more commonly 10), crosscut up to 90 m (30 ft) (undecompacted) of the overlying stratigraphy and extend up to 1095 m (3593 ft) away from the channel complex. Three styles of intrusion are observed: type 1: dikes lacking sills at their upper tips; type 2: dikes that pass upward into sills at their upper tips; and type 3: stepped sills that consist of linked sill and dike segments. These different styles of intrusions pass laterally into one another, leading to extreme complexity both between and along-strike individual intrusion complexes. Although the mechanisms driving initial overpressure development and injection itself are unclear, this study indicates that 3-D seismic data are a powerful tool in understanding the 3-D geometry of winglike clastic injection complexes and suggests that the true geometry of these features is more complex than previously documented. This study also has implications for potential reservoir geometries and hydrocarbon exploitation of winglike clastic intrusion complexes.

Quantification of Cretaceous-Cenozoic exhumation in the Otway Basin using sonic velocities and implications for hydrocarbon exploration

Quantification of Cretaceous-Cenozoic exhumation in the Otway Basin using sonic velocities and implications for hydrocarbon exploration

Miocene facies associations and sedimentary evolution of the Southern Transylvanian Basin (Romania): Implications for hydrocarbon exploration

The Transylvanian Basin is a mature hydrocarbon province of Romania characterized by two petroleum systems: Mesozoic (thermogenic) and Miocene (biogenic). An extensive outcrop-based sedimentological and micropaleontological study correlated to seismic and well data discusses the elements of the Miocene petroleum system. The facies associations are indicative of alluvial, fandelta, shallow- and deep-marine settings. These are grouped into four different depositional systems (evaporite, mud-carbonate, sand-mud and sand-gravel). Their evolution in time and space shows large differences between various parts of the basin that have important consequences for exploration. The Transylvanian gas is formed by more than 99% methane of bacterial origin. This is sourced by low quality (<1% TOC) deep-marine shales. The shales contain Type II and Type III kerogen. The organic material is thermally immature. The best source rocks were deposited during major transgressions in the central-eastern parts of the basin. In general, reservoir quality is the best (porosity < 20%, permeability < 1 D) in the basin center, where reservoirs are deep-marine turbidite sandstones. Lower quality reservoirs are conglomerate-rich slope channels and various shallow-marine sandstones located near the basin margins. The seals are formed by shales that hold gas columns of up to 60 m. The most common structural traps are in 4-way dip closures related to salt-cored folds. Their timing is coeval with the late (post-Pannonian) exhumation of the basin and strongly linked to coeval salt tectonics. This requires a late charge and migration. The largest traps typically have multistory (up to 20) pay zones with a total of 100 BCF to 1 TCF reserves. Exploration to date has focused on structural traps, but most of the obvious structures have been drilled. It is argued that significant exploration potential lies in stratigraphic plays, including confined submarine fans, slope channels, detached lowstand prograding wedges, incised valleys, diapir flanks, salt-tectonics related unconformities and various sub-volcanic plays. Risks of the petroleum system elements associated to these plays in different areas of the basin are discussed.

Paleoweathering features in the Sergi Formation (Jurassic-Cretaceous), northeastern Brazil, and implications for hydrocarbon exploration

Resumo As paleoalteracoes da Formacao Sergi foram classificadas e estudadas com o objetivo de determinar sua genese e sua relacao com a evolucao estratigrafica. A Formacao Sergi faz parte da sequencia pre-rift da Bacia do Reconcavo (NE Brasil) e e composta por uma complexa justaposicao de arenitos eolicos e fluviais e pelitos lacustres. Essa formacao pode ser subdividida em tres sequencias deposicionais, limitadas por discordâncias regionais. As paleoalteracoes da Formacao Sergi foram classificadas em quatro tipos com diferentes interpretacoes geneticas: (1) marmoreado textural e caracterizado por uma alternância espacial de tons na rocha, resultante da mobilizacao dos oxidos de Fe em fases minerais onde ocorre a alternância entre estagios de oxidacao (coloracoes variando entre o amarelo, castanho e vermelho) e reducao (coloracoes variando entre cinza ou verde); (2) marmoreado nao-textural apresenta descoloracoes independentes das texturas originais da rocha; (3) concentracoes carbonaticas estao relacionadas, principalmente, a formacao de nodulos de carbonato, os quais apresentam estrutura interna macica que reflete o modo como foram formados pelo crescimento ou cristalizacao continuos; e (4) carbonatos bandados (silcificados), que estao associados ao inicio da formacao de superficies regulares, interpretados como resultado da precipitacao quimica de carbonatos em ambiente palustre. O padrao de cores do marmoreado, bem como as acumulacoes de carbonatos nao sao, na sua maioria, produtos de processos pedogenicos, mas refletem predominantemente a atividade de aguas subterrâneas e de variacoes do nivel freatico. Os intraclastos carbonaticos e os carbonatos bandados (silicificados) tem sua genese relacionada a processos pedogenicos em sentido estrito. Deste modo e natural que as aguas fluvial e meteorica sejam os fatores essenciais para que a evolucao das paleoalteracoes na Formacao Sergi acompanhe a tendencia deposicional, ja que ambos sao controlados pelos mesmos fatores –clima, relevo e taxa de sedimentacao.

Deepwater turbidites and their implications for hydrocarbon exploration in Qiongdongnan Basin, Northern South China Sea

Deepwater turbidites and their implications for hydrocarbon exploration in Qiongdongnan Basin, Northern South China Sea

Seismic characteristics of a reef carbonate reservoir and implications for hydrocarbon exploration in deepwater of the Qiongdongnan Basin, northern South China Sea

Our analysis of approximately 40,000 km of multichannel 2-D seismic data, reef oil-field seismic data, and data from several boreholes led to the identification of two areas of reef carbonate reservoirs in deepwater areas (water depth ≥ 500 m) of the Qiongdongnan Basin (QDNB), northern South China Sea. High-resolution sequence stratigraphic analysis revealed that the transgressive and highstand system tracts of the mid-Miocene Meishan Formation in the Beijiao and Ledong–Lingshui Depressions developed reef carbonates. The seismic features of the reef carbonates in these two areas include chaotic bedding, intermittent internal reflections, chaotic or blank reflections, mounded reflections, and apparent amplitude anomalies, similar to the seismic characteristics of the LH11-1 reef reservoir in the Dongsha Uplift and Island Reef of the Salawati Basin, Indonesia, which house large oil fields. The impedance values of reefs in the Beijiao and Ledong–Lingshui Depressions are 8000–9000 g/cc × m/s. Impedance sections reveal that the impedance of the LH11-1 reef reservoir in the northern South China Sea is 8000–10000 g/cc × m/s, whereas that of pure limestone in BD23-1-1 is >10000 g/cc × m/s. The mid-Miocene paleogeography of the Beijiao Depression was dominated by offshore and neritic environments, with only part of the southern Beijiao uplift emergent at that time. The input of terrigenous sediments was relatively minor in this area, meaning that terrigenous source areas were insignificant in terms of the Beijiao Depression; reef carbonates were probably widely distributed throughout the depression, as with the Ledong–Lingshui Depression. The combined geological and geophysical data indicate that shelf margin atolls were well developed in the Beijiao Depression, as in the Ledong–Lingshui Depression where small-scale patch or pinnacle reefs developed. These reef carbonates are promising reservoirs, representing important targets for deepwater hydrocarbon exploration.