Implications For Hydrocarbon Exploration Research Articles

Late Triassic to present-day tectono-thermal history of the coastal part of the Asturian basin: Implications for hydrocarbon exploration and for the North-Iberian margin evolution

The Asturian Basin, situated on the North Iberian margin, is a Permian-Mesozoic extensional basin developed over a Variscan Palaeozoic basement, subsequently inverted during the Cenozoic Alpine orogeny. The compilation of cartographic, structural, biostratigraphic and vitrinite reflectance data collected in a Late Triassic-Jurassic succession, excellently exposed along the Cantabrian Sea coast, has allowed us to gain insight into the Mesozoic and Cenozoic tectono-thermal history of this basin. The oldest recorded event occurred in Middle-Late Jurassic times and consisted of uplift, development of a large syncline, and normal faulting accompanied by circulation of hydrothermal fluids along the faults. The basin emersion caused an angular unconformity, together with a change in the sedimentary environment that passed from marine to continental. A second event, whose age was probably Late Jurassic-Early Cretaceous, was responsible for extensional reactivation of previous normal faults accompanied by a weaker fault-related hydrothermal episode. In Cenozoic (Eocene-Miocene) times, as a consequence of the Alpine orogeny some of the previous faults were reactivated as reverse and/or strike-slip faults, and folds developed. Here we analyse which structures were active during each event, their relationship with the hydrothermal fluids, the control they exerted on the hydrocarbon generation, and how the large-scale models proposed for this portion of the North Iberian margin fit the onshore field observations, in particular regarding the structural position of the Asturian Basin within the Iberian Plate Mesozoic rifts and the role of the Ventaniella Fault.

Integrated 3D Reservoir Modeling and Tectonic Evaluation of the Upper Cretaceous Bahariya Formation in the Burg El Arab Area, Egypt: Implications for Hydrocarbon Exploration and Production Strategies

Integrated 3D Reservoir Modeling and Tectonic Evaluation of the Upper Cretaceous Bahariya Formation in the Burg El Arab Area, Egypt: Implications for Hydrocarbon Exploration and Production Strategies

Structural segmentation in the Qiongdongnan Basin, South China Sea: Insights from analogue models and implications for hydrocarbon exploration

Structural segmentation in the Qiongdongnan Basin, South China Sea: Insights from analogue models and implications for hydrocarbon exploration

Pore Structure Characteristics and Reservoir Classification of Tight Sandstones within the Upper Permian Longtan Formation in the Laoshan Uplift, South Yellow Sea Basin: Implications for Hydrocarbon Exploration

The Upper Permian Longtan Formation in the Laoshan Uplift of the South Yellow Sea Basin hosts thick and distinctive tight sandstones. However, a comprehensive understanding of its pore structure and reservoir classification remains lacking. This study investigates the fully cored well, CSDP-2, utilizing thin section analysis, scanning electron microscopy, energy spectrum analysis, X-ray diffraction, high-pressure mercury intrusion, and nuclear magnetic resonance to characterize its petrophysical properties, pore space, and movable fluid characteristics. Additionally, fractal principles are further employed to examine reservoir heterogeneity and conduct a quantitative assessment, considering the complexity of tight sandstone pore structures. The findings reveal that the sandstones predominantly comprise feldspathic litharenites, with an average porosity of 1.567% and permeability of 0.099 mD, primarily containing intragranular pores. Two distinct sets of pores with significantly different sizes (r < 2 μm; r > 6 μm) were identified, displaying relatively high fractal dimensions and discrete distribution. Movable fluids primarily occupy pores with radii > 0.019 μm, reflecting pronounced overall heterogeneity. The reservoir was classified into three categories utilizing permeability, median radius, and movable fluid saturation as key evaluation parameters, with Class I representing a relatively high-quality reservoir. These findings advance our understanding of the pore development mechanism of tight sandstone reservoirs and provide geological evidence for further hydrocarbon exploration in this study area.

Distribution patterns and controlling factors of beach bars in Qinghai Lake, NW China

The significance of beach-bar reservoirs, which are intricately linked to unconventional hydrocarbon reservoirs, has gained increased attention. This study elucidates the complex mechanisms governing the formation, spatial distribution, and morphological characteristics of beach bars in Qinghai Lake, NW China, highlighting the interplay of lake-level fluctuations, wind wave dynamics, sediment provenance, and terrain gradient. Our findings reveal that large-scale lake-level fluctuations primarily dictate the initial formation settings of beach bars, while small-scale fluctuations refine their internal stratification and sedimentary features. Wind wave dynamics play a critical role in defining suitable depth zones for beach bar development, influencing their morphology and resulting in distinct sedimentary characteristics across different lake zones. Furthermore, the study categorizes beach bars into three main systems based on sediment provenance—bedrock, alluvial fan (fan delta), and braided river systems—each exhibiting unique compositional and structural attributes. Terrain gradient around the lake significantly affects beach bar formation, with areas having a gradient less than 0.7° being particularly favorable. This research advances our understanding of lacustrine beach bar dynamics, offering insights into their potential as indicators of past environmental conditions and their implications for hydrocarbon exploration. The comprehensive analysis of controlling factors provides a foundation for predicting beach bar distribution and contributes to the broader field of sedimentary geology by integrating multi-disciplinary approaches to study lacustrine sedimentary processes.

Fault locking and alternate fault activity revealed by simple tools and approaches — Examples from the Western Canadian Sedimentary Basin with implications for hydrocarbon exploration and production

The geology toolkit that is used to reveal faults and fractures is much wider than before. This is due to 3D and 4D views in exploratory statistics programs and to the availability of user-friendly GIS software. These tools allow us to visualize a multitude of parameters that will be briefly explored here. A review of many geologic and nongeologic parameters led to evidence of fault locking and alternate fault activity. It also resulted in new structural models for the Western Canadian Sedimentary Basin (WCSB). The presented data sets include earthquakes, drilling, production, well data, aeromagnetic data, and more. Various integrated approaches reveal well-defined fault patterns that are typical of a strike-slip regime and the existence of previously unrecognized detachments that are important for hydrocarbon exploration. Some of the new geometries and associated mechanisms are illustrated here with outcrop analogues and present-day cross sections, maps, and 3D views. Only the most recent of the two identified strike-slip regimes is covered in this paper. Some emphasis is given to the recognition of detachments at various scales. Among these is the importance of megadetachments displacing the sedimentary cover by up to 16 km with respect to the aeromag. Hence, there is a need for reconstruction before making conclusions. The WCSB has a lot more to offer to explorers who understand faults, fractures, and migration paths. Integrating many types of information in map or 3D views offers new tools to identify and characterize faults.

Sedimentary characteristics, lithofacies, and paleogeography of the Middle–Lower Cambrian in the Tarim Basin, NW China

The Cambrian pre-salt dolomite sequence in the Tarim Basin is a target zone of great strategic significance for hydrocarbon exploration in the basin. Using the results of the interpretation of 3D seismic data from Lunnan and 2D seismic data covering the whole basin, and based on a synthesis of outcrop data, drilling data, well logs, core data, and thin-section data, and the findings from previous studies, this paper studies the characteristics of the facies of the Middle–Lower Cambrian in the platform area in the Tarim Basin, the formation and evolution of platform margins, and the sedimentary characteristics, lithofacies, and paleogeographic characteristics of the Middle–Lower Cambrian series. Based on the types of lithofacies and the seismic facies analysis, the sedimentary facies of the Middle–Lower Cambrian strata can be classified into the five types. From bottom to top, the Middle–Lower Cambrian have experienced several development stages, including the deposition of continental shelf sediments of the Yuertusi Formation, gently sloping non-rimmed platform margin sediments of the Xiaoerbulake Formation, weakly rimmed platform margin sediments of the Wusongger and Shayilike formations, and strongly rimmed platform margin sediments of the Awatage Formation. In each stage, the platform margin shifted further east relative to its location in the previous stage. Based on these results and previous studies, the lithofacies and paleogeography maps of the Middle–Lower Cambrian in the Tarim Basin are modified, and the implications for hydrocarbon exploration in this area are discussed.

Tectonic Evaluation, Seismic Interpretation, and Its Implication for Hydrocarbon Exploration in Gorontalo Basin

Tectonic Evaluation, Seismic Interpretation, and Its Implication for Hydrocarbon Exploration in Gorontalo Basin

Seismic attributes and quantitative reverse reservoir simulations of shallow-marine eocene sedimentary fairways, extensional rifting Indus onshore petroleum system, southern Pakistan: Implications for hydrocarbon exploration

Quantitative reservoir characterization plays a vital role in exploring carbonate depositional systems. The subsurface vertical and lateral changes in the tectonics and sea level adversely impact the signatures of band-limited seismic data. The seismic amplitudes are very sensitive to these vertical and lateral tilts of the stratigraphy and sedimentology of the subsurface stratigraphic layers. The dynamical tectonic-based fluctuating sea creates vital seismic expressions of high amplitude. These seismic expressions can inversely infer the dense-fractured depositional parasequences, thickness, porosity, and lithological change for the accommodation space and the sedimentary influxes for the development of petroleum fairways. Hence, it becomes very challenging to predict whether the producing zone for hydrocarbons sourced from the wet-gas-bearing zones is a potential zone for hydrocarbon exploration or a light oil-bearing zone (WGZ or LOZ). Therefore, the development of reverse quantitative simulations of parasequences within the extensional regimes is always a very complex research problem during stratigraphic-based fuel exploration of thin-bedded carbonate systems. This research utilizes the spectral-based amplitudes along with the instantaneous waveform-based temperature-porosity stratigraphic simulations (WTPS) on middle-Eocene carbonates (MCARB), Pakistan. 18-Hz amplitudes detect the gas-bearing stratigraphic prospect of 230 km2 on the northern flanks. The 18-Hz-based WTPS has predicted the parasequences within the complete petroleum systems. 24 m thick progradational and laterally continuous and fractured reservoirs are deposited within the wet-gas-bearing zones (WGZ) throughout a rapidly falling sea and succeeding growth at 175 °F and 28% porosity pseudo-wells. Deposition of 15–20 m thick deep-marine transgressive shale has been completed throughout a rising sea level at a temperature of 125 °F and 12% poor porosity. There is a lateral change in the dense-fractured then low-velocity from 2.1 to 1.8 g/cc and 2670 to 1690 ms/s predicted by WTPS from the NE to SW zones of MCARB, which impacts the presence of 1.5 km of the regionally developed pure stratigraphic trap. The WGZ has a vertically resolved thickness of 24 m, which is appreciably above the resolvable magnitude threshold of 23 m. Hence, it implies that the extensive fall of sea level followed by the regional development of the accommodation space for the accumulation of WGZ carbonate stratigraphic units is at its accurate location within the sub-surface reservoir system. This workflow has robust consequences towards exploring petroleum systems, Onshore Pakistan. Hence, this workflow may serve as an exemplary move towards regional analogues aimed at world carbonate in extensional regimes.

Seismic attributes and quantitative inverse dynamical simulations for characterization of late Cretaceous classical fluvial meander channelized stratigraphic traps system, onshore Indus, Pakistan: Implications for hydrocarbon exploration

Meandering channel systems and point bars (PBRL) of the fluvial depositional system (FDPS) globally form primary stratigraphic traps (PST). These ultra-thin-bedded and sub-seismic features are developed during rising sea-levels (transgressive) and standstill (aggradational parasequences) inside the transgressive system tract (TST). The aggradational parasequences of TST have coarse-grained sandstone-filled PSTs, which have specific thickness, density, velocity, angle of the sedimentary reserves, and depositional and erosional characteristics for the development of seismic reflection configurations. All these implications are the key controlling factors for developing the aggrading parasequence sets of TST throughout a sea-level standstill, which is not feasible to predict using the full spectrum-based time and depth mapping tools. The full spectrum-based amplitude volumes lack the tuning frequency content for achieving the above-addressed implications. They require sophisticated tuned-frequency amplitudes, which are responsible to resolve these PSTs when they are filled with porous (Ps) and gas-saturated (Sgas) sedimentary facies, and hence, they show unique seismic-based expressions (velocity and density). Therefore, all these implications are achieved in this study by operating the spectral attributes and the instantaneous spectral decomposition-based velocity and density reservoir simulations (SVDRS) on a hydrocarbons-producing arena, onshore Indus, Pakistan. The tuning thickness for this FDPS was 8.75 m. The 42-Hz spectral attribute shows ∼13 m parallel and wavy seismic reflection configurations, but failed in predicting the horizontally deposited PST, simulated density and velocity, shelf or basin plain, and lateral distribution of Sgas and Ps point bars along the subsidence zones. SVDRS have predicted the ∼86–95% Sgas; ∼31–35% Ps; 14–16 m thick (on inverted density simulation); 2453–2500 m/s velocity; inside the 2.2–2.3 g/c.c densely-fractured and inclined (<3°) aggradational parasequences with parallel reflection configurations for high sinuosity index (S.I) > 2.2 PBRLs, which implicates the presence of a meandering channelized reservoir stream. These stratigraphic configurations implicate the low-risk and highly rewarding hydrocarbon prospecting zones due to no spilling out of the hydrocarbon from the PST during the sea-level standstills. These hydrocarbon-bearing PBRLs have a lateral extent of >2 km, which is an appreciable signature of velocity and densities to develop these traps as the future stratigraphic prospect. These PBRLs with >90% Sgas and >32% Ps of PST are completely embedded within the topmost and horizontal regions with transgressive shales facies (seal) of TST and low-Ps shaly-sandstones, which implicates the landward shifting of shoreline during the sea-level rising events. The uncertainty analysis for simulated velocity and density validates a strong R2>0.85% and 0.90% along the high sinuosity index (S.I.)>2.2 implicates the presence of meandering channel streams., which have implicated the presence of non-Ps and water-statured (Sw) retrogradational parasequences. This workflow has developed this FDPS into a pure stratigraphic trap, and hence, the presented scheme of exploration may serve to explore the remaining reserves from the exploration zones for global FDPS.

Palaeogeographical development of two merging delta systems (Eocene Shahejie Formation) in the Bohai Bay Basin, E China and implications for hydrocarbon exploration

Two deltas developed simultaneously during the Eocene on the eastern side of a large lake that existed in the Dongying Sub-basin, which forms part of the Bohai Bay Basin in eastern China. The rivers that built the deltas had different catchment areas, which resulted in sediments with different permeability and porosity, due to differences in sorting and mud content. Both deltas prograded, and mass flows that originated frequently on their fronts formed lobes that expanded laterally. This eventually led to merging of both deltas, a feature that has rarely been described from ancient deposits thus far. Core analysis and seismic reflection data show that the merging of the two deltas took place in nine phases, determined by phases of slower progradation or even temporary retrogradation in between. The alternation of sediments from both deltas and their eventual mixing makes the architecture of the merged deltas much more complex than that of ‘classical’ single deltas. This affects the predictability of the spatial distribution of possible reservoir characteristics significantly, but detailed core analysis shows that the best hydrocarbon reservoirs consist of sand bodies formed in distributary channels on the delta plains, and of sandy turbidites formed in the deep-lacustrine environment in front of the merged deltas.

Linking the sedimentary cyclicity with mechanical and physical properties of limestone and marl rocks, Dam Formation, Eastern Saudi Arabia: Implications for hydrocarbon exploration and reservoir development

Linking the sedimentary cyclicity with mechanical and physical properties of limestone and marl rocks, Dam Formation, Eastern Saudi Arabia: Implications for hydrocarbon exploration and reservoir development

Dolomitization in the Upper Paleozoic succession of the north-Ostaninsk field, Nyurolsk Basin, Western Siberia: Implications for hydrocarbon exploration

Paleozoic rocks in Western Siberia may contain significant hydrocarbon resources. However, effective methods for their exploration are poorly constrained. This study provides new insights into the causes of reservoir formation using the upper part of the Paleozoic succession of the North-Ostaninsk field in the Nyurolsk Basin as a case study. The carbonate rocks have been affected by dolomitization. Four dolomite generations have been identified: Floating in the matrix (D1), fracture-filling (D2.1), stylolite-associated (D2.2), partly replacive (D3) and, pervasive (D4). The last one replaces biogenic limestone in the upper part of the Paleozoic succession and coincides with the presence of a reservoir in the field. A systematic analysis petrographic, fluid inclusion, and carbon and oxygen isotope investigations suggest that the origin of dolomite is from the downward infiltration of meteoric water with higher Mg2+ and Fe2+ derived from the alteration of tuffaceous materials. The results, along with values of the magnetic field anomaly, reveal the relationship between dolomitization and the distribution of the oil and gas reserves in this Paleozoic succession within the basement of the West Siberian Basin. This new insight may be used to predict similar accumulations in poorly explored territories.

Geological Distribution of the Miocene Carbonate Platform in the Xisha Sea Area of the South China Sea, and Its Implications for Hydrocarbon Exploration

The newly collected seismic data and the existing drilling data provide a good opportunity to better understand the carbonate platform distribution characteristics and the hydrocarbon resource potential in the Xisha sea area of the South China Sea. Based on the seismic data and the reflection characteristics of the carbonate platform’s edge, three boundary indicators were established: abrupt lithological interfaces, fault interfaces, and tidal channels. Combined with the regional geological settings, its spatial and temporal distribution was clearly identified for the first time. The development of the Miocene carbonate platform in the Xisha sea area is divided into six phases, which are further assigned to three evolutionary stages: the bloom stage, the recession stage, and the submerged stage. The sedimentary facies belt of the carbonate platform in each stage is well developed, and the reefs are mainly distributed on the west and southwest edges of the platform. The analysis of the data indicates that the area of the reef and carbonate platform reached 80,000 km2 during the mature period, followed by a retreat period where the scale decreased with the platform’s decline. The Miocene carbonate rocks in the Xisha sea area are widely distributed. They have experienced multiple periods of exposure and infiltration, which further improved the quality of their physical properties for hydrocarbon reservoirs. According to the regional hydrocarbon geological conditions in this area—including the source rock, migration system and the capping layer—the hydrocarbon accumulation potential is preliminarily discussed in this paper. A reservoir model of the reef and carbonate platform is established, which is proposed as typical characteristics of “lower generation, upper accumulation”. It is pointed out that the carbonate platform in the Xisha sea area adjacent to the Huaguang Sag in the Qiongdongnan Basin and the northern Zhongjiannan Basin is a potential area for oil and gas exploration.

Cenozoic Depositional Evolution and Stratal Patterns in the Western Pearl River Mouth Basin, South China Sea: Implications for Hydrocarbon Exploration

Investigating the deposition evolution and stratal stacking patterns in continental rift basins is critical not only to better understand the mechanism of basin fills but also to reveal the enrichment regularity of hydrocarbon reservoirs. The Pearl River Mouth Basin (PRMB) is a petroliferous continental rift basin located in the northern continental shelf of the South China Sea. In this study, the depositional evolution process and stacking pattern of the Zhu III Depression, western PRMB were studied through the integration of 3D seismic data, core data, and well logs. Five types of depositional systems formed from the Eocene to the Miocene, including the fan delta, meandering river delta, tidal flat, lacustrine system, and neritic shelf system. The representative depositional systems changed from the proximal fan delta and lacustrine system in the Eocene–early Oligocene, to the tidal flat and fan delta in the late Oligocene, and then the neritic shelf system in the Miocene. The statal stacking pattern varied in time and space with a total of six types of slope break belts developed. The diversity of sequence architecture results from the comprehensive effect of tectonic activities, sediment supply, sea/lake level changes, and geomorphic conditions. In addition, our results suggest that the types of traps are closely associated with stratal stacking patterns. Structural traps were developed in the regions of tectonic slope breaks, whereas lithological traps occurred within sedimentary slope breaks. This study highlights the diversity and complexity of sequence architecture in the continental rift basin, and the proposed hydrocarbon distribution patterns are applicable to reservoir prediction in the PRMB and the other continental rift basins.

3-D quantitative seismic imaging of tectonically-influenced Middle-Eocene carbonates stratigraphic traps of SE-Asian basins using spectral decomposition: Implications for hydrocarbon exploration

Carbonates form energetic stratigraphic petroleum systems. The tectonic uplifting and subsidence significantly affect the overall reservoir configurations. During these stratigraphic scenarios, the prediction of accurate thickness for subsidence and uplifting zones becomes challenging. The band-limited seismic data interpretation tools fail to detect the zones of thinning and thickening of sediments along with uplifting and subsidence. The band-limited seismic does not have the tuning frequency, that can be used to predict the accurate vertical thickness of the thin-bedded carbonates. The constant wavelet-based transformation tool (WT) and inverted reservoir simulations have robust implications for the quantification of any depositional system. Especially, when the reservoir is shallow marine, the application of WT has resolved a variety of stratigraphic traps in terms of their seismic and sedimentological aspects. The stratigraphic traps are comprised of thin beds, which are not resolvable on conventional seismic. These traps require a specific tuning frequency, which is the key ingredient for the prediction of oil and gas inside them and can only be obtained by the implementation of the WT tool. Therefore, the WT, static stratigraphic thickening wedge models (SSTWM), and WT–based instantaneous spectral thickness modeling (ISTM) tools are applied on a gas field in Indus Basin, Pakistan. The 43-Hz CWT images the densely fractured and faulted network within the shoal reservoir limestone lenticular lens (SRLL) with an aerial extent of 208 km2 in southwest-northeast orientations. The band-limited attributes revealed poor imaging of sub-surface carbonate systems. The 43-Hz wavelet-based SSTWM predicts a 15-m-thick coarse-grained SRLL along subsidence and a 12-m-thick fine-grained SRLL along uplifting zones. Post-stack processing at 43-Hz CWT tuning frequency predicts the 18 and 10 m thick sediments for SRLL along the subsidence and uplifting zone. The ISTM predicts a thickness of 31 m during subsidence within the SRLL and 14 m for uplifting zones. The 43-Hz tuning frequency-based processing at ISTM predicts enhanced thicknesses of 41 and 18 m for subsiding and uplifting sediments that are trapped inside the shoal limestone petroleum systems. The quantitative visualization of AI with the predicted thicknesses at ISTM has provided robust clues for imaging the internal stratigraphic architecture of the SRLL. The linear regression analysis remained a very successful tool for assessing the quantitative aspects of SRLL with a strong R2 > 0.95, which has implicated the real-time imagining of sea-level fall and rise. Only post-stack seismic data processing at 43-Hz found a very effective exploration tactic in predicting the enhanced thicknesses, and lateral continuity of the reservoir, and improved the S/N by removing the tuning effect of ambiguous lithology/fluids, which have accurately predicted the exact location along the subsidence zones. This workflow can act as an analogue stratigraphic exploration of remaining gas fields within Asian Basins and similar geological settings.

Early dolomitization and subsequent recrystallization of Middle Ordovician carbonates in the western flank of the Ordos Basin, Northern China: Implications for hydrocarbon exploration

The pervasive dolostone from the Middle Ordovician Zhuozishan Formation in the Ordos Basin (Northern China) are considered as potential hydrocarbon reservoirs. Three types of matrix dolomites (Md) are recognized: 1) very fine to fine crystalline, nonplanar-a to planar-e dolomite (Md1); 2) fine to medium crystalline, nonplanar-a to planar-e dolomite (Md2); and 3) medium crystalline, planar-s to nonplanar-a dolomite (Md3). The initial dolomitization of Md1 and Md2 dolomites is inferred to have taken place in the presence of seepage reflux of slightly evaporated seawater in the near-surface to shallow burial settings, and insignificant recrystallization occurred in the process of being buried again, according to petrography, trace elements, and oxygen-carbon-strontium isotopic geochemistry. Coarser crystals with cloudy cores and clear rims consist of the Md3 dolomites, and the texture shows irregular contacts between planar-s and nonplanar-a crystal. Geochemical analysis reveals that the Md3 dolomites have a negative shift in δ18O values with increasing Mn contents, and a negative δ18O trend with depth in the same well, while the δ13C does not tend to correlate with the oxygen isotopes. Additionally, the 87Sr/86Sr ratios of Md3 dolomites are relatively higher due to contribution of radiogenic 87Sr. Petrological attribute and geochemical evidence suggest that the massive Md3 dolomites can be due to significant recrystallization of earlier formed dolomites during burial period. The unevenly distributed pores in Md3 dolomites suggest the heterogeneous structure of the precursor dolomites, which may be the Md2 dolomites. The residual particles of Md2 dolomites indicate the precursor limestones were deposited in a relatively high-energy part of the shoal. Hence, the wide distributed Md3 dolomites show salient facies-controlled characteristics, which suggests strategies for hydrocarbon exploration of potential heterogeneous dolomite reservoir.

Stratigraphic palynology and micropaleontological study of the Cretaceous-Paleogene succession of the Nani-1 well of the Anambra and Niger Delta basins: Implications for hydrocarbon exploration

Integrated palynological and micropaleontological analyses were carried out on the Nani-1 well drilled into the Anambra and Niger Delta basins of Nigeria. The study is aimed at reconstructing biozones and paleoenvironments of deposition, as well as deducing the sequence stratigraphic framework of the Cretaceous-Paleogene successions of an area containing key elements for hydrocarbon exploration. Encountered lithofacies succession of sandstone, siltstone, dark-grey to black shale, and coal beds comprises six lithostratigraphic units, namely the Nkporo Group (Campanian-Maastrichtian), Mamu Formation (Middle Maastrichtian), Ajali Formation (Middle-Late Maastrichtian), Nsukka Formation (Late Maastrichtian), Imo Formation (Danian-Thanetian) and Ameki Group (Eocene). Fourteen dinoflagellate zones (A-N) and seven pollen and spore subzones (A1-G1) are recognized based on the first occurrence of two or more species. Two major stratigraphic events are documented: (1) dinoflagellate cyst (dinocyst) zone G at 880 m depth marked by first appearance of Danea aff. californica and Danea cf. mutabilis in association with Cordosphaeridium fibrospinosum, and the last occurrence of Danea aff. californica and Phelodinium magnificum place the Cretaceous-Paleogene (K/Pg) boundary in the lowermost part of the Imo Formation; and (2) a hiatus characterized by a starved section observed at 380 m directly overlain by the Early Eocene assemblages of the Ameki Group indicates a sequence boundary at Imo/Ameki Boundary. Thus, a chronostratigraphic chart is developed for parts of the Anambra Basin and the Niger Delta. Six depositional environments which include marginal to shallow marine, marshy lagoon to estuarine, shallow neritic and tidally influenced fluvial channel are identified, and palynostratigraphic evidences indicate that fresh water palynomorphs are present in the Lower Maastrichtian strata. Four sequence boundaries and four maximum flooding surfaces are also identified within the Maastrichtian–Early Eocene sediments. The paleoenvironmental reconstruction shows that possible hydrocarbon reservoirs in the basin are the marine sandstone facies of the Nkporo Group and Mamu Formation. Their shale members constitute potential source rocks, while the overlying shale units of the Nsukka and Imo formations may provide regional seals for hydrocarbon habitation.

Stratigraphic-Tectonic Evolution and Characterization of the Carboniferous in the Karamay–Baikouquan Fault Zone in the Northwestern Margin of the Junggar Basin, Northwest China

The northwestern margin of the Junggar Basin has a complex tectonic history, which is challenging for hydrocarbon exploration. This study highlights the structural patterns, tectonic evolution, and controlling factors of the Karamay–Baikouquan Fault Zone (KBFZ) in the northwestern margin of the Junggar Basin based on well-log and 3D seismic data. The main findings of this study include the following: spatially, we have divided the structural patterns of KBFZ into three zones on the plane, namely, northern, central, and southern zones; temporarily, the tectonic evolution has been divided into five stages from Late Carboniferous to Cretaceous, namely, Early-Middle Carboniferous, Late Carboniferous-Early Permian, Middle-Late Permian, Triassic-Middle Jurassic, and Late Jurassic-Cretaceous. During the Hercynian and Indochina orogeny, the compressional stress from the movement of the Dalabute strike-slip fault and the Genghis–Junggar strike-slip fault produced various degrees of deformation in different locations in the KBFZ. The general structural style is a mixture of strike-slip and thrust-nappe. The main controlling factors include stress period, stress direction, and stratigraphic-lithologic associations. This study has implications for hydrocarbon exploration and development in the northwestern margin of the Junggar Basin.

Seismic sequence stratigraphy and depositional evolution of the Cretaceous-Paleogene sedimentary successions in the offshore Taranaki Basin, New Zealand: implications for hydrocarbon exploration

The seismic stratigraphy and sedimentary facies of the Cretaceous and Paleogene sedimentary successions in north-eastern offshore part of Taranaki Basin, New Zealand have been investigated in order to unravel their depositional evolution and identify the potential hydrocarbon plays. Interpretation of regional seismic lines covering the entire shelf-slope and deepwater regions as well as integrating seismic and sedimentary facies allows the identification of several seismic-stratigraphic sequences within the studied successions. Early Cretaceous syn-rift successions (C1 sequence) were deposited in the structural lows near the present-day slope as swamp and marsh facies changing basinwards into turbidites and marine shales. The post-rift Cretaceous sequences (C2, C3 sequences) started with the progradation of the Taranaki delta (C2A-C2D units) followed by sedimentation of the transgressive C3A-E facies accumulated in response to thermal subsidence and high-rates of clastic supply. Extensive shelf conditions prevailed during the deposition of C2 and C3 Cretaceous sequences continued during the Paleogene with deposition of uniform marine shales throughout the basin. Rates of sediment supply substantially decreased during Oligocene prompting the deposition of marine micrite-rich carbonate. Variation in fossil content confirms the occurrence of several cycles of sea level fluctuations and episodic variations in terrigenous input. Organic-rich facies could be associated with the prograding clinoforms of the C2B unit and probably contain, basinward, large amount of gas and oil prone kerogen. The transgressive facies of C2D unit may also contain organic-rich shales basinward and coal near the present day Taranaki shelf. Potential reservoirs are hosted on the C3 transgressive estuarine sandstones. Paleogene mudstones are excellent regional seals for the hydrocarbons generated and trapped in the underlying Late Cretaceous facies.