Bicyclic alkanes in source rocks of the Triassic Yanchang Formation in the Ordos Basin and their inconsistency in oil-source correlation

The Triassic Yanchang Formation is the main source rocks for Mesozoic oil in Ordos Basin. The formation includes 10 oil-bearing beds (Ch 1–Ch 10), that each can be further divided into two to three intervals. Abundant C₁₂–C₁₄ and C₁₅–C₁₆ bicyclic alkanes have been detected in the formation in the Xifeng oilfield, Ordos Basin. The C₁₂–C₁₄ group is dominated by C₁₂ and C₁₃, and the C₁₅–C₁₆ group contains abundant C₁₅. The groups show three distribution patterns: A) the C₁₂–C₁₄ group is the major component in the non-source rocks of the Ch 7-1 and Ch 8-1 intervals; B) both groups are abundant and are common in source rocks of the Ch 7-3 interval; and C) the C₁₅–C₁₆ group is the major component in source rocks of the Ch 7-3 interval and also in sediments that contain type Ⅰ or partial sapropel type Ⅱ₁ organic matter (OM) in the Ch 7-2 and Ch 8-1 intervals. Although thermal maturities of the source rocks in the Ch 7 section are similar, they show significant differences with respect to the drimane isomerisation index, which indicates that the drimane rearrangement is controlled by thermal evolution of the sediments, but may also be closely related to the depositional environment. This study determined that reducing environments are more conducive to preservation of drimane than oxic environments. The drimane isomerisation index and the value of the hopane parameter Tm/Ts are positively correlated. The parameter Tm/Ts varies over a wide range within the sequence, and the large variations may be a result of terrigenous OM input by turbidity currents and/or gravity flows, mixed with the autochthonous sediments. Abundant homodrimane in both source rocks may reflect reducing environments in deep lakes and major input of higher plant OM. Organic-rich shale and oil shale in the Ch 7-3 interval of the Yanchang Formation are the primary sources of oil in reservoirs in the Xifeng area. The crude oil is rich in bicyclic alkanes that are dominated by C₁₅–C₁₆ as source rocks with pattern C for bicyclic alkanes, which indicates an origin mainly from the Ch 7-3 interval. The main peaks in all of the crude oils are associated with 8β(H)-drimane and lower abundance of rearranged drimane. However, most of the source rocks have a main peak associated with 8β(H)-homodrimane or rearranged drimane. Weak microbial action, selective degradation and water washing may be the cause of the significant difference in bicyclic sesquiterpane composition between the crude oil and the source rocks. The result suggests that oil-source correlations based on the bicyclic sesquiterpanes are questionable.     

Does compaction-induced subsidence control accommodation space at the top of prograding carbonate platforms? Constraints from the numerical modelling of the Triassic Esino Limestone (Southern Alps,Italy)

The demise of the high-relief, steep-slope, prograding Ladinian-Early Carnian carbonate platforms of the Esino Limestone (Central Southern Alps of Italy) is marked by subaerial exposure of the platform top associated with different erosional (mainly karst-related), depositional and diagenetic processes (Calcare Rosso). The exposure-related deposits consist of three major facies associations: 1) residual soils with thin lenses of conglomerates with black pebbles, and, locally, weathered vulcanites; 2) chaotic breccia lenses irregularly distributed in the uppermost part of the Esino Limestone carbonate platform, interpreted as collapse breccias in karstic setting: 3) inter-supratidal carbonate cycles with dissolution and development of paleosols and tepee structures.Facies distribution follows the sub-environments of the underlying Esino Limestone. Facies 1 and 2 typically characterize the core of the platform, covering the underlying inner platform facies. Facies 3 instead develops toward the edge of the platform, above reef-upper slope facies of the prograding facies of the Esino Limestone. The thickness of facies 3 decreases toward the core of the platform. Facies distribution reflects differences in the accommodation space and sedimentary processes from the rim (highest accommodation, favouring the deposition of peritidal-supratidal carbonates) to the core (reduced accommodation, causing pedogenesis and karstification) of the carbonate system.The observed thickness changes may be controlled by different factors: 1) syndepositional tectonics, 2) subsidence induced by magmatic activity or 3) differential subsidence controlled by the stratigraphic architecture of the Esino Limestone platform and adjoining basins. As evidence of tectonics was not observed and the presence of volcanic bodies is only documented tens of km away from the study area, the scenario involving the creation of accommodation space by compaction of the basinal sediments (resedimented, fine-grained calciturbidites) during the progradation of the carbonate platform is here investigated. Numerical modelling was performed to verify the compatibility of compaction-induced subsidence with the observed depositional architecture. The models were built to simulate the architectural evolution of the platform by progressively adding layers from deepest to shallowest, while compacting the underlying sediments, in order to evaluate compaction-induced subsidence (and accommodation space for the Calcare Rosso) after the deposition of the youngest platform strata. Modelling results allow us to conclude that the wedge geometry of the Calcare Rosso, deposited on top of the extinct Esino carbonate platform, can be explained by subsidence controlled by compaction of the basinal sediments present below the early-cemented, fast prograding platform slope deposits.     

Marine hydrocarbon source rocks of the Upper Permian Longtan Formation and their contribution to gas accumulation in the northeastern Sichuan Basin,southwest China

Identification of the main hydrocarbon source rocks of the large Puguang gas field (northeastern Sichuan Basin, southwest China) has been the subject of much discussion in recent years. A key aspect has been the lack of a comprehensive understanding of the development of hydrocarbon source rocks of the Upper Permian Longtan Formation, which had been thought to contain mainly coal seams and thick carbonate layers. In this paper, based on geological data from more than ten wells and outcrops and their related mineralogy and geochemistry, we investigated the depositional environment and main factors controlling organic matter enrichment in the Longtan Formation. We propose a model which combines information on the geological environment and biological changes over time. In the model, organic matter from prolific phytoplankton blooms was deposited in quiescent platform interior sags with rising sea-levels. During the Longtan period, the area from Bazhong to Dazhou was a platform interior sag with relatively deep water and a closed environment, which was controlled by multiple factors including syngenetic fault settling, isolation of submarine uplifts and rising sea-levels leading to water column stratification. Although the bottom water was anoxic, the phytoplankton were able to bloom in the well-lit upper euphotic zone thus giving rise to a set of sapropelic black shales and marlstones containing mostly algal organic matter with minor terrestrial contributions. As a consequence, these rocks have a high hydrocarbon generation potentials and can be classified as high-quality source rocks. The area from Bazhong to Dazhou is a center of hydrocarbon generation, being the main source of reservoired paleo-oils and presently discovered as pyrobitumen in the Puguang gas field. The identification of these source rocks is very important to guide future petroleum exploration in the northeastern Sichuan Basin.     

Jurassic source rocks in the Vienna Basin (Austria): Assessment of conventional and unconventional petroleum potential

The Upper Jurassic marlstones (Mikulov Fm.) and marly limestones (Falkenstein Fm.) are the main source rocks for conventional hydrocarbons in the Vienna Basin in Austria. In addition, the Mikulov Formation has been considered a potential shale gas play. In this paper, organic geochemical, petrographical and mineralogical data from both formations in borehole Staatz 1 are used to determine the source potential and its vertical variability. Additional samples from other boreholes are used to evaluate lateral trends. Deltaic sediments (Lower Quarzarenite Member) and prodelta shales (Lower Shale Member) of the Middle Jurassic Gresten Formation have been discussed as secondary sources for hydrocarbons in the Vienna Basin area and are therefore included in the present study.The Falkenstein and Mikulov formations in Staatz 1 contain up to 2.5 wt%TOC. The organic matter is dominated by algal material. Nevertheless, HI values are relative low (<400 mgHC/gTOC), a result of organic matter degradation in a dysoxic environment. Both formations hold a fair to good petroleum potential. Because of its great thickness (∼1500 m), the source potential index of the Upper Jurrasic interval is high (7.5 tHC/m²). Within the oil window, the Falkenstein and Mikulov formations will produce paraffinic-naphtenic-aromatic low wax oil with low sulfur content. Whereas vertical variations are minor, limited data from the deep overmature samples suggest that original TOC contents may have increased basinwards. Based on TOC contents (typically <2.0 wt%) and the very deep position of the maturity cut-off values for shale oil/gas production (∼4000 and 5000 m, respectively), the potential for economic recovery of unconventional petroleum is limited. The Lower Quarzarenite Member of the Middle Jurassic Gresten Formation hosts a moderate oil potential, while the Lower Shale Member is are poor source rock.     

Depositional evolution of a progradational to aggradational,mixed-influenced deltaic succession: Jurassic Tofte and Ile formations,southern Halten Terrace,offshore Norway

Predicting the hydrodynamics, morphology and evolution of ancient deltaic successions requires the evaluation of the three-dimensional depositional process regime based on sedimentary facies analysis. This has been applied to a core-based subsurface facies analysis of a mixed-energy, clastic coastal-deltaic succession in the Lower-to-Middle Jurassic of the Halten Terrace, offshore mid-Norway. Three genetically related successions with a total thickness of 100–300 m and a total duration of 12.5 Myr comprising eight facies associations record two initial progradational phases and a final aggradational phase. The progradational phases (I and II) consist of coarsening upward successions that pass from prodelta and offshore mudstones (FA1), through delta front and mouth bar sandstones (FA2) and into erosionally based fluvial- (FA3) and marine-influenced (FA4) channel fills. The two progradational phases are interpreted as fluvial- and wave-dominated, tide-influenced deltas. The aggradational phase (III) consists of distributary channel fills (FA3 and FA4), tide-dominated channels (FA5), intertidal to subtidal heterolithic fine-grained sandstones (FA6) and coals (FA7). The aggradational phase displays more complex facies relationships and a wider range of environments, including (1) mixed tide- and fluvial-dominated, wave-influenced deltas, (2) non-deltaic shorelines (tidal channels, tidal flats and vegetated swamps), and (3) lower shoreface deposits (FA8). The progradational to aggradational evolution of this coastal succession is represented by an overall upward decrease in grain size, decrease in fluvial influence and increase in tidal influence. This evolution is attributed to an allogenic increase in the rate of accommodation space generation relative to sediment supply due to tectonic activity of the rift basin. In addition, during progradation, there was also an autogenic increase in sediment storage on the coastal plain, resulting in a gradual autoretreat of the depositional system. This is manifested in the subsequent aggradation of the system, when coarse-grained sandstones were trapped in proximal locations, while only finer grained sediment reached the coastline, where it was readily reworked by tidal and wave processes.     

Influence of natural fractures on gas accumulation in the Upper Triassic tight gas sandstones in the northwestern Sichuan Basin,China

The Upper Triassic Xujiahe Formation in the northwestern Sichuan Basin, China, is a typical tight gas sandstone reservoir that contains natural fractures and has an average porosity of 1.10% and air permeability less than 0.1 md because of compaction and cementation. According to outcrops, cores and image logs, three types of natural fractures, namely, tectonic, diagenetic and overpressure-related fractures, have developed in the tight gas sandstones. The tectonic fractures include small faults, intraformational shear fractures and horizontal shear fractures, whereas the diagenetic fractures mainly include bed-parallel fractures. According to thin sections, the microfractures also include tectonic, diagenetic and overpressure-related microfractures. The diagenetic microfractures consist of transgranular, intragranular and grain-boundary fractures. Among these fractures, intraformational shear fractures, horizontal shear fractures and small faults are predominant and significant for fluid movement. Based on the Monte Carlo method, these intraformational shear fractures and horizontal shear fractures improve the reservoir porosity and permeability, thus serving as an important storage space and primary fluid-flow channels in the tight sandstones. The small faults may provide seepage channels in adjacent layers by cutting through layers. In addition, these intragranular and grain-boundary fractures increase the connectivity of the tight gas sandstones by linking tiny pores. The tectonic microfractures improve the seepage capability of the tight gas sandstones to some extent. Low-dip angle fractures are more abundant in the T₃X³ member than in the T₃X² and T₃X⁴ members. The fracture intensities of the sandstones in the T₃X³ member are greater than those in the T₃X² and T₃X⁴ members. The fracture intensities do not always decrease with increasing bed thickness for the tight sandstones. When the bed thickness of the tight sandstones is less than 1.0 m, the fracture intensities increase with increasing bed thickness in the T₃X³ member. Fluid inclusion evidence and burial history analysis indicate that the tectonic fractures developed over three periods. The first period was at the end of the Triassic to the Early Jurassic. The tectonic fractures developed during oil generation but before the matrix's porosity and permeability reduced, which suggests that these tectonic fractures could provide seepage channels for oil migration and accumulation. The second period was at the end of the Cretaceous after the matrix's porosity and permeability reduced but during peak gas generation, which indicates that gas mainly migrated and accumulated in the tectonic fractures. The third period was at the end of the Eogene to the Early Neogene. The tectonic fractures could provide seepage channels for secondary gas migration and accumulation from the Upper Triassic Xujiahe Formation into the overlying Jurassic Formation.     

Oolitic shoal complexes characterization of the Lower Triassic Feixianguan Formation in the Yuanba Gas Field,Northeast Sichuan Basin,China

The Yuanba Gas Field is the second largest natural gas reservoir in the Sichuan Basin, southwest China. The vast majority of the natural gas reserve is from the Permian Changhsingian reef complexes and Lower Triassic Feixianguan oolitic shoal complexes. To better understand this reservoir system, this study characterizes geological and geophysical properties, spatial and temporal distribution of the oolitic shoal complexes and factors that control the oolitic shoals character for the Lower Triassic Feixianguan Formation in the Yuanba Gas Field. Facies analysis, well-seismic tie, well logs, seismic character, impedance inversion, and root mean square (RMS) seismic attributes distinguish two oolitic shoal complex facies – FA-A and FA-B that occur in the study area. FA-A, located in the middle of oolitic shoal complex, is composed of well-sorted ooids with rounded shape. This facies is interpreted to have been deposited in shallow water with relatively high energy. In contrast, FA-B is located in flanks of the oolitic shoal complex, and consists of poorly sorted grains with various shape (rounded, subrounded and subangular). The oolitic shoal complexes were mainly deposited along the platform margin. From the early Fei 2 Member period to the late Fei 2 Member period, the oolitic shoals complexes on the platform margin gradually migrated from the southwest to the northeast with an extent ranging from less than 100 km²–150 km² in the Yuanba Gas Field. The migration of oolitic shoals coincided with the development of a series of progradational clinoforms, suggesting that progradational clinoforms caused by sea-level fall maybe are the main reason that lead to the migration of oolitic shoals. Finally, this study provide an integrated method for the researchers to characterize oolitic shoal complexes by using well cores, logs, seismic reflections, impedance inversion, and seismic attribute in other basins of the world.     

Reservoir origin and characterization of gas pools in intrusive rocks of the Yingcheng Formation,Songliao Basin,NE China

In 2013, the first discovery of gas pools in well LS 208 in intrusive rocks of the Songliao Basin (SB), NE China was made in the 2nd member of the Yingcheng Formation in the Yingtai rift depression, proving that intrusive rocks of the SB have the potential for gas exploration. However, the mechanisms behind the origin of reservoirs in intrusive rocks need to be identified for effective gas exploration. The gas pool in intrusive rocks can be characterized as a low-abundance, high-temperature, normal-pressure, methane-rich, and lithologic pool based on integrated coring, logging, seismic, and oil test methods. The intrusive rocks show primary and secondary porosities, such as shrinkage fractures (SF), spongy pores (SP), secondary sieve pores (SSP), and tectonic fractures (TF). The reservoir is of the fracture–pore type with low porosity and permeability. A capillary pressure curve for mercury intrusion indicates small pore-throat size, negative skewness, medium–high displacement pressure, and middle–low mercury saturation. The development of fractures was found to be related to the quenching effects of emplacement and tectonic inversion during the middle–late Campanian. SP and SSP formed during two phases. The first phase occurred during emplacement of the intrusive rock in the late Albian, when the intrusions underwent alteration by organic acids. The second phase occurred between the early Cenomanian and middle Campanian, when the intrusions underwent alteration by carbonic acid. The SF formed prior to oil charging, the SSP + SP formed during oil charging, and the TF formed during the middle–late Campanian and promoted the distribution of gas pools throughout the reservoir. The intrusive rocks in the SB and the adjacent basins were emplaced in the mudstone and coal units, and have great potential for gas exploration.     

Modeling uncertainty in the three-dimensional structural deformation and stratigraphic evolution from outcrop data: Implications for submarine channel knickpoint recognition

Digital outcrop models help to constrain the interactions of stratigraphic and structural heterogeneity on ancient depositional systems. This study uses a stochastic approach that incorporates stratigraphic and structural modeling to interrogate the three-dimensional morphology of deep-water channel strata outcropping on Sierra del Toro in the Magallanes Basin of Chile. This approach considers the relative contributions, and associated uncertainty, of erosional downcutting versus post-depositional structural folding and small-offset faulting on the present-day configuration of the submarine channel complexes. Paleodepositional channel-belt gradients were modeled using a combination of three-dimensional visualization, stochastic surface modeling, palinspastic restoration, and decompaction modeling that are bound with errors constrained by stratigraphic and structural uncertainty. Modeling results indicate that at least 100 m of downcutting occurs over 6 km, and the resultant thalweg gradient of 64–125 m/km (decompacted) suggests that the Cerro Toro axial channel belt is an out-of-grade depositional system. Furthermore, the presence of steeper segments (100–175 m/km decompacted) suggests the preservation of one or more knickpoints that are similar in magnitude to tectonically-induced knickpoints on the modern seafloor. The interpreted knickpoints are correlated with a decreasing channel width-depth ratio and an increase of channel depth. These results indicate that stochastic surface modeling using digital outcrop models can constrain stratigraphic interpretations and post-depositional structural heterogeneity.