Hydrocarbon Migration Pathways Research Articles

Application of NSO compounds in the research of hydrocarbon migration direction in the Wangjiagang area of the Dongying sagin the Bohai Bay Basin

The determination of hydrocarbon migration direction is an important part in the study of petroleum accumulation in petroliferous basins, and plays an important role in guiding oil and gas exploration activity. Despite their relatively low content in petroleum, the polar nitrogen-, sulphur-and oxygen- containing compounds (collectively referred to as NSO compounds) have great potential in characterizing the hydrocarbon migration process. A series of crude oils along hydrocarbon migration pathway were selected and analysed using GC×GC/TOFMS and GC-MS in the Wangjiagang area of the Dongying sag. Total concentration of NSO compounds and other related parameters are determined to verify the role of different parameters in indicating hydrocarbon migration. Our research result shows that the total amount of NSO compounds, 1-/3-MC ratio, 1,8-/2,7-DMC ratio, 4-/1-MDBF ratio and 2,4-/1,4-DMDBT ratio changes grandully with the increase of migration distances. Thus, these parameters can be applied as effective migration direction indicators in study area. Some other parameters may not be suitable for the identification of hydrocarbon migration direction in the study area.

Characterization and genetic significance of mold pores in tight sandstone: A case from the lower part of the Yanchang Formation in the Wuqi–Ansai area

The lower part of the Yanchang Formation in the Wuqi–Ansai area consists of three layers which are generally characterized by low (5–10%) to extra-low (<5%) porosity and extra-low (10–100 md) to ultra-low (<10md) permeability. Based on microscopic observation of casting thin sections, mercury injection tests, micro-CT scanning, inclusion temperature measurement, and fluorescence tests, it was determined that the pore types of the reservoirs mainly included secondary pores between pores, intraparticle pores in feldspar, intercrystallite pores in clay, mold pores, and laumonite dissolution pores. With decreasing porosity and permeability of the reservoirs, the proportions of intraparticle pores in feldspar and mold pores increased; however, the proportion of interparticle pores decreased. The pores of the reservoirs, which were dominated by mold pores, mostly showed coarse skewness and good sorting with few pore throats and low coordination numbers. These pores were spatially isolated and rarely connected by throats. Quartz microcrystals were observed to be closely attached to the pore walls and growing along them. Diagenetic analysis indicated that the mold pores formed after the sandstones were intensely compacted and before the reservoirs were densified. As the hydrocarbon source rock matured and discharged acidic fluids, the grains and matrix in the sandstone reservoirs gradually dissolved to form pores, and some of the feldspar particles were even completely eroded into mold pores. In the following densification process of cements filling pores, the mold pores located on hydrocarbon migration pathways were filled by small amounts of oil and gas; thus, they could be retained after densification. Pores of this type were morphologically isolated because of the cementation of most throats. After the intense and selective corrosion of the reservoirs, some macropores were filled by small amounts of oil and gas during the later densification of reservoirs. This led to the survival of mold pores and has made the mold pores a symbol of the process in which the reservoirs were densified after hydrocarbon accumulation.

Deep Learning for Characterizing Paleokarst Collapse Features in 3‐D Seismic Images

AbstractPaleokarst systems are found extensively in carbonate‐prone basins worldwide. They can form large reservoirs and provide efficient pathways for hydrocarbon migration, but they can also create serious engineering geohazards. The full delineation of potentially buried paleokarst systems plays an important role for reservoir characterization, oil and gas production, and other engineering tasks. We propose a supervised convolutional neural network (CNN) to automatically and accurately characterize paleokarst and associated collapse features from 3‐D seismic images. To avoid time‐consuming manual labeling for training the CNN, we propose an efficient workflow to automatically generate numerous 3‐D training image pairs including synthetic seismic images and the corresponding label images of the collapsed paleokarst features simulated in the seismic images. With this workflow, we are able to simulate realistic and diverse geologic structures and collapsed paleokarst features in the training images from which the CNN can effectively learn to recognize the collapsed paleokarst features in real field seismic images. Two field examples from the Fort Worth Basin demonstrate that our CNN‐based method is superior to conventional automatic methods in delineating paleokarst collapse features from seismic images. From the CNN‐based paleokarst characterization, we can further automatically extract 3‐D collapsed paleokarst systems and quantitatively measure their geometric parameters. Our CNN‐based method is highly efficient and takes only seconds to classify collapsed paleokarst features a 3‐D seismic image with 320 × 1, 024 × 1, 024 samples (approximately 268 km2) by using one graphics processing unit.

Detection of gas chimney and its linkage with deep-seated reservoir in poseidon, NW shelf, Australia from 3D seismic data using multi-attribute analysis and artificial neural network approach

Accurate delineation of hydrocarbon seepage has significant implications in accentuating hydrocarbon migration pathways and assessing seal integrity thereby alleviating drilling hazards. Knowledge of migration pathways and understanding about the source/reservoir plays a vital role in successful evaluation of hydrocarbon seepage. Many researchers have reported events of gas leakage in Poseidon area; however, it has never been investigated in detail to confirm the origin of the gas leakage and their migration pathways. In this study, an attempt has been made to decipher the relationship between shallow gas migration expressions such as pockmarks, mud-volcanos, direct hydrocarbon indicators (DHIs), push-downs, amplitude blanking, with the reservoir present in the study area. Adopted approach includes development of a chimney probability cube (CPC), in which extracted seismic attributes are optimally combined using a non-linear multi-layer perceptron (MLP) network. During the training and testing phase of the 3-layer MLP network, 0.3–0.25 normalized RMS error and <5% of misclassification is achieved. The processed cube is further validated using spectral decomposition approach, and a cross-plot of Lambda-Rho (petrophysical parameters) versus obtained chimney probability values. The CPC facilitates an enhanced 3D visualization of gas flow channels and deciphers its association with an existing deep-seated reservoir in Plover Formation. The results of this study will provide significant input for hydrocarbon prospect evaluation as well as for making informed drilling decisions in the study area.

1D and 2D basin modeling, in evaluating the hydrocarbon generation-migration-accumulation potential, at coastal Fars Area, Southern Iran

One of the giant hydrocarbon generation zones in Iran has been developed in the south of the Zagros Mountain Range (i.e., South Zagros), located between the South Zagros and the Persian Gulf in a foreland basin known for high levels of exploration uncertainties (due to the presence of complex structures, multiple source layers, and migration pathways). In this basin, the Permotriassic formations provide for the main reservoir strata, while the hydrocarbon content is deemed to be derived from the “hot shales” of the Silurian-Ordovician Sarchahan Formation, serving as source rock. As the focus of the present research, the Coastal Fars region is developed along the shores of southern Iran and hosts a number of gas reservoirs that have been increasingly discovered since 1970. Developed in the Permotriassic siliciclastics and carbonates of the Faraghan, Dalan, and Kangan Formations, gas reservoirs have made the Coastal Fars a hot zone for exploration and production activities. In this research, one 2D and five 1D models of the basin (at five exploration wells) were constructed to evaluate the maturity of the main Silurian-Ordovician source rock and further investigate the hydrocarbon charge, timing, migration pathways, and accumulation sites. The models were then utilized to investigate the relationship between the presence of multiple shale layers and hydrocarbon content of the reservoir at one of the studied wells using Rock-Eval analysis. This study showed that an uplift that happened after the hydrocarbon generation has led to a dry hole in the study area. The results indicated that the Sarchahan Formation is probably the main source rock across the region, according to previous researches in this area its organic contents were dated back to the late Ordovician rather than the Silurian. The shale intercalations across the reservoirs (Kangan and Upper Dalan), especially in the Khayam Field, were found to produce more than 90% of their hydrocarbon generation potential. No non-indigenous hydrocarbon was identified across the study area, implying that the entire hydrocarbon content was generated by the identified source rocks. Laboratory analysis indicated the presence of type II and type III kerogen at a local heat flow rate of about 65 mW/m2 since the Cretaceous. In total, the Sarchahan Formation was found to reach a maximum burial depth of 6 km, making it matured to overmatured all over the study area.

Seismic Imaging of Collapsed-Anticline Diapirs in Central Tunisia

Central Tunisia is characterized by major fault systems, being ornamented by salt diapirs of the Late Triassic evaporite-rich interval. Salt movement began in the Late Triassic and continues to the present-day. Lasting halokinesis create pillows, diapirs, salt wall and salt-cored folds, sometimes, with collapse graben above. Salt diapir structures have been mapped and many regions collapsed diapirs are, perhaps, associated to salt removal. These structures were eroded resulting exposure and sub-aerial erosion by the Late Cretaceous to Paleogene uplift and post-Middle Miocene. The initial studies and findings related to salt structures in Tunisia suggesting a clear correlation between diapiric uplift and local tectonic structures. In particular, the N‒S and NW‒SE shortening trends during the Neogene and Quaternary folding strongly controlled the development of rows of diapirs and salt walls. The salt activities are controlled by tectonics as well as differential loading in the Triassic sediments over long distances, displaying that the mobilization of Triassic sediments covered the whole region and not just the zones near the single diapiric structures. Here we will focus also in the salt related plays and the associated petroleum systems with particular emphasis on trap types, reservoir and hydrocarbon migration pathways. Obviously, all these elements are linked together to certain degree and controlled by the salt tectonics.

Hydrocarbon migration pathway and methane budget for a Gulf of Mexico natural seep site: Green Canyon 600

Hydrocarbon seeps occur worldwide along continental margins and act as conduits for fluid discharge from the lithosphere to the overlying hydrosphere/atmosphere. The dynamics and rates of hydrocarbon release at cold seeps remain poorly constrained. Seepage enables a variety of processes that alter the seafloor morphology and affect the geochemistry of substrata, supporting diverse and important chemosynthetic communities. Here we merge complementary geochemical (oil fingerprinting), geophysical (deep seismic, subbottom, backscatter, multibeam) and video/imaging (Video Time Lapse Camera, DSV ALVIN video, ROV video, AUV photo surveys) data sets to constrain the pathways and magnitudes of methane fluxes from the source reservoir to the seafloor at a well-studied, prolific seep site, Green Canyon (GC) 600 in the Northern Gulf of Mexico. Oil samples from the reservoir, an active vent, and the sea-surface showed compositional similarities consistent with the plumbing system structure identified in seismic data. Spatial distribution of seep indicators such as bacterial mats, microbial communities, methane derived carbonates, and hydrate outcrops, were then used to quantify the total magnitude of methane potentially sequestered in the study domain. Using a systems approach, we combined published values for methane fluxes with data we collected across various scales and resolutions to compile a methane budget for GC600. The system considered for the methane budget is defined as the movement of methane from the salt ridge to the seafloor-water interface for each seep domain, Birthday Candles and Mega Plume. Total estimated input of methane was 2.8×108–2.2×109 mol/yr in the Birthday Candles domain, and 2.7×108–2.3×109 in the Mega Plume domain. The combined total output of the system ranged from 3.2×105–8.2×105 and 3.2×106–5.2×106 mol/yr respectively for Birthday Candles and Mega Plume domains, leaving a potential surplus (input minus output) of 2.6×108–2.3×109 mol/yr. Processes that could balance this budget include accumulation of gas hydrate and sediment free-gas, and the underestimated potential of biological sinks such as methane oxidation.

Relict hydrocarbon seeps in the Oligocene–Miocene Subis carbonate platform, Malaysia: Implications on hydrocarbon generation and migration pathways and potential sealing by shale gouging

Occurrences of the highly productive, yet complex oil and gas‐ bearing Oligocene–Miocene buried carbonate platforms of the South China Sea and adjoining onshore equivalents necessitates understanding the form, timing and pathways of hydrocarbon migration plays. Here, we report the occurrence of structural‐stratigraphic controls on relict seepage and evaluate the hydrocarbon generation and migration pathway in the exposed Subis carbonate platform. Our results show that the seepages occur essentially along a post‐depositional fault plane located along the flank of a Miocene reef. The samples (n: 3) contain 0.14–1.42% of total organic carbon (TOC). The Hydrogen Index (HI) varies between 72 and 147 Mg HC/g TOC and the Oxygen Index (OI) from 32 to 234 mg CO2/g TOC. Similarly, the Production Index (PI) varies between 0.11 and 0.26. The source rock potentials are poor (n = 2) and good (n = 1). The studied samples show the Tmax uniformly as 433°C and PI values &gt;0.1 and are therefore thermally immature. The occurrence of seepages sampled along the eastern flank of Subis buildup falls in the autochthonous field, indicating that the hydrocarbon was produced within the indigenous formation (Subis Limestone). This indicates absence of migration from deeper and older layers. However, occurrence of this seepage along a fault plane probably reactivated immediately after lithification of the Oligocene–Miocene carbonate bioherm and affected the matrix of the rocks, suggest that the hydrocarbon generated might have moved upward along this fault plane, assimilated into the host rock, especially in the finer matrix portions of the carbonates. The presence of CO2 at temperatures between 300–550°C is also suggestive of an organic matter origin or solution seams of the Subis Limestone and this inference obviates migration from deep‐seated faults and any connectivity and/or openness of the petroleum system between the subsurface and the atmosphere.

Syn-depositional fault control on hydrocarbon migration and accumulation pattern: a case study from Tangbei Area, Bohai Bay Basin, NE China

Tangbei Area, a complex syn-depositional fault development area, is located in petroliferous Bohai Bay Basin with abundant petroleum resources in the Paleogene. The way to figure out possible migration pathways and potential accumulation accommodation controlled by syn-depositional faults has become a key issue for predicting favorable reservoirs. Based on seismic volume and wireline logs, we carried out fine seismic interpretation, document the faults and their combinations in plane view and section view, and reveal its influence on hydrocarbon migration and accumulation. The results indicate that fine seismic interpretation in the study area provides the distribution and characteristics of syn-depositional faults generated by regional tectonic activities. In addition, syn-depositional faults play an important influence on basin structure and the pathways and traps for hydrocarbon migration and accumulation. Three types of syn-depositional faults are divided based on their locations. It is found that syn-depositional faults in steep slope zone are much favorable for hydrocarbon migration and accumulation. Syn-depositional faults in different depositional periods throughout basin evolution act as pathways for hydrocarbon migration, as well as act as seals, which depend on surrounding lithology associations and sealing or leaking properties through time.

Direct and indirect surface geochemical methods in petroleum exploration: a case study from eastern part of the Polish Outer Carpathians

The objective of this paper is to evaluate the relationship between the distributions of direct and indirect, surface geochemical indices in the selected part of the Outer Carpathians. The research included analysis of molecular composition of soil gas samples and calcite contents as well as the measurements of magnetic susceptibility and pH of soil samples. The survey contained 96 soil gas samples collected from 1.2 m depth and 96 soil samples taken from interval 0.7–0.8 m depth. The maximum concentrations of methane, total alkanes C2–C5 and total alkenes C2–C4 were: 2100, 10.43 and 0.772 ppm. The magnetic susceptibility values changed from 3.6 to 21.5 x 10–8 m3/kg. The calcium carbonate contents varied from 0.02 to 29.92 wt% and the pH values measured in soil solutions obtained changed from 4.5 to 8.3. Although the results demonstrate no correlation between the direct soil gas anomalies and the indirect geochemical indicators, the integrated profiles in Fig. 7 suggest possible haloes in the calcite/magnetic data that could be related to hydrocarbons migrating from depth. There are, however, various independent mechanisms that might control the appearance of these mineral anomalies. Secondary changes of mineral composition of soils disclosed by the indirect methods, even if controlled by hydrocarbon migration throughout geological time, might cause some closure of migration pathways, influencing the location of active hydrocarbon migration pathways. Comprehensive interpretation of the results obtained by direct and indirect methods in this paper provides another positive example helping to better understand the complicated mechanism of hydrocarbon migration and the potential usefulness of indirect methods suitable for hydrocarbon exploration.

Controls on Reservoirs Quality of the Upper Jurassic Mengyin Formation Sandstones in Dongying Depression, Bohai Bay Basin, Eastern China

The Upper Jurassic Mengyin Formation sandstones are important targets for petroleum exploration in Dongying Depression of Bohai Bay Basin, Eastern China. Although the current burial depth of the Upper Jurassic Mengyin Formation sandstones is shallow (900–2500 m), the reservoir rocks are characterized by low porosity and low permeability due to the complex diagenetic modifications after deposition. Experimental tests and statistical methods, such as thin section, scanning electron microscopy (SEM), cathodoluminescence (CL), high pressure mercury injection (HPMI) and fluid inclusion analysis are conducted to delineate the mineralogical, petrographic and petro-physical characteristics. Results show that physical and chemical processes, including burial depth, burial and thermal history and pore fluid evolution, are both important for the diagenetic modifications that result in a variety changes in pore system and reservoir quality. According to numerical simulation of porosity evolution during lengthy burial and thermal history, porosity loss due to the early deep burial process under the high paleo-geothermal gradient can reach about 20%. Moreover, the burial history (effective stress and temperature) has a better guidance to reservoir quality prediction compared with current burial depth. The extensive compaction in sandstones also resulted in extremely low pore fluid flow during subsequent diagenetic processes, thus, the reaction products of dissolution cannot be removed, which would be precipitated as carbonate cements during stable reburial phase. Dissolution resulted from uncomformity-related meteoric flushing have been the most important porosity-enhancing factor in Mengyin Formation sandstones in spite of low thin section porosity averaged out to 3.22%. Secondary pores derived from dissolution of unstable silicates are more likely to develop in sandstones near the regional unconformity. The oil source fault activities may enhance the heterogeneity of reservoir rocks and control the reservoir quality by inducing micro-fractures and providing the main pathways for hydrocarbon migration.

Modeling of hydrocarbon migration and accumulation on the Chengzikou uplift, Bohai Bay Basin, China: Implications for petroleum exploration on slope belts in rift basins

The Chengzikou Uplift (CZKU) is a second-order structure surrounded by several hydrocarbon generative kitchens in the Bohai Bay Basin. However, six recently drilled wells on the CZKU failed to prove hydrocarbon occurrences, which causes confusion for the understanding of hydrocarbon migration and accumulation on the CZKU. Mainly based on the seismic database, this paper attempted to determine the hydrocarbon migration pathways and enrichment mechanisms on the CZKU. The results show that the lateral and vertical hydrocarbon migration seems to take place through a stepped pathway system consisting of permeable layers within unconformities, permeable carrier beds, and faults. Through a simple 3D modeling considering topography changes only, the hydrocarbons tend to migrate from the northern sags to the southern slope and uplift with parallel mainstreams and accumulate with convergent mainstreams. The potential hydrocarbon traps mainly include stratigraphic, structural, and structural-lithologic traps, most of which have been confirmed by previous explorations. Subsequently, two preliminary interpretations for the dry well on the CZKU are made: the first is hydrocarbons mainly accumulated in the Paleogene stratigraphic (onlapping) traps within the sag and slope area, conducting no further migration to the uplift; the other is hydrocarbons may migrate to the slope and uplift but were trapped in structural-lithologic traps associated with faults beyond the area of the dry wells. Moreover, favorable hydrocarbon accumulation targets are predicted to reduce exploration risk.

Geological and geophysical features of and controls on occurrence and accumulation of gas hydrates in the first offshore gas-hydrate production test region in the Shenhu area, Northern South China Sea

Abstract Integrated three-dimensional seismic, logging, sediment cores, and geochemical testing data were collected from Guangzhou Marine Geological Survey 3 and 4 hydrate drilling expeditions and used in this study for a comprehensive investigation of the geological and geophysical features and accumulation mechanism of hydrates in the first offshore gas-hydrate production test region (GHPTR) in the Shenhu area of the South China Sea. Seismic signatures indicative of disseminated hydrates and free gas include the bottom simulating reflector (BSR), gas chimney, and mud diapir associated with enhanced seismic reflections, acoustic blanking, masking, and chaotic appearance have been observed. The acoustic travel-time responses, density, and compensated neutron three porosity log analysis, high-precision grid tomography inversion analysis, and constrained sparse spike inversion confirm the presence of free gas below the gas-hydrate-bearing zone (GHBZ). Free-gas-bearing zones have significantly different p-wave impedances and low-velocity anomalies than the overlying GHBZ and surrounding strata. These anomalous zones are controlled by the structural attitude of the reservoir strata, which are characterized as inter-bedded stratigraphic units. Variations in the type and geological characteristics of the hydrocarbon migration pathways were observed between sites W18 and W19 on the western ridge and sites W11 and W17 on the eastern ridge in the GMGS study area. The efficiency of gas migration in the western ridge may be higher than that in the eastern ridge, resulting in variations in hydrate gas types, thickness of the GHBZ, and gas migration flux and accumulation. Except for site W11, hydrates were recovered below the structure I inferred BSR at sites W17, W18, and W19. The gas-hydrate stability zone calculations reveal that the structure I hydrate stability zone differs from the BSR depth and is generally shallower than the base of the logging anomaly, indicating the coexistence of structure I and II hydrates. The BSR is not indicative of the BGHSZ; it is rather regarded as a transitional indicator of structure I and II gas hydrates in the GHPTR. The appearance of free gas and hydrates below the structure I inferred BSR indicates that the Shenhu area is characterized by a complex hydrate formation and accumulation system resulting from the supply of biogenic and thermogenic gases. Despite fine-grained host sediments predominating the GHPTR, the coupling of favorable conditions including efficient hydrocarbon generation, sufficient gas supply, multiple pathways for gas migration, and relatively high reservoir porosity have led to the development of highly saturated gas-hydrate accumulations within relatively thick sedimentary sections, which demonstrates a significant resource potential.

Organic matter enrichment and hydrocarbon accumulation models of the marlstone in the Shulu Sag, Bohai Bay Basin, Northern China

Hybrid unconventional systems are composed of juxtaposed organic-rich and organic-lean intervals. Organic matter enrichment, hydrocarbon migration, and the spatial relationship of source rocks and reservoirs have important influences on differential hydrocarbon accumulation within the system. Most studies have ignored the complexity of hydrocarbon accumulation in unconventional oil reservoirs. A typical hybrid lithology system with a combination of marlstone and rudstone has been discovered in the lower part of the third member of the Shahejie Formation of the Shulu Sag, Bohai Bay Basin, Northern China. The basin showcases a strong heterogeneity in unconventional hydrocarbon production and is an appropriate case to study hydrocarbon accumulation within hybrid unconventional systems. However, relevant work in the study area was scarce. A study of the mechanisms of organic matter enrichment and hydrocarbon accumulation was required to understand the heterogeneity of the oil reservoirs. Nine units in ascending order, namely IL, IU, IIL, IIU, IIIL, IIIU, IV, VL, and VU, were proposed in this study. A detailed geochemical analysis was carried out to distinguish the organic matter sources and preservation conditions among the different units, and assess the migration patterns of the hydrocarbons. The results show that Unit IIL has the highest total organic carbon (TOC) content. Unit IIL has a higher quantity of aquatic sourced organic matter, with relatively high abundance of short chain n-alkanes, C27/C29 sterane, and 4-methyl steranes. Based on the low ratios of pristane to phytane, the varve-like lamination structure of the lithology and suitable salinity, we can speculate that good organic matter preservation conditions existed in Unit IIL. Maturity of the source rocks increases with depth. Biomarkers indicate that hydrocarbons within the marlstones were retained in situ, whereas hydrocarbons within the rudstones were derived from source rocks via short- or long-distance migrations. Fractures can act as effective pathways for hydrocarbon migration. Organic matter sources, preservation conditions, maturity, and hydrocarbon migration ways jointly controlled the formation of oil reservoirs in the Shulu Sag. The results of this study provide a better understanding of organic matter enrichment and hydrocarbon accumulation and guide further exploration in the basin.

Tilting and Flexural Stresses in Basins Due to Glaciations—An Example from the Barents Sea

Many of the Earth’s sedimentary basins are affected by glaciations. Repeated glaciations over millions of years may have had a significant effect on the physical conditions in sedimentary basins and on basin structuring. This paper presents some of the major effects that ice sheets might have on sedimentary basins, and includes examples of quantifications of their significance. Among the most important effects are movements of the solid Earth caused by glacial loading and unloading, and the related flexural stresses. The driving factor of these movements is isostasy. Most of the production licenses on the Norwegian Continental Shelf are located inside the margin of the former Last Glacial Maximum (LGM) ice sheet. Isostatic modeling shows that sedimentary basins near the former ice margin can be tilted as much as 3 m/km which might significantly alter pathways of hydrocarbon migration. In an example from the SW Barents Sea we show that flexural stresses related to the isostatic uplift after LGM deglaciation can produce stress changes large enough to result in increased fracture-related permeability in the sedimentary basin, and lead to potential spillage of hydrocarbons out of potential reservoirs. The results demonstrate that future basin modeling should consider including the loading effect of glaciations when dealing with petroleum potential in former glaciated areas.

Variation of subsidence in the Dezful Embayment, SW Iran: influence of reactivated basement structures

Subsidence analyses over the past 140 Ma in 15 wells in the Dezful Embayment, which is the main oil-producing area in the Zagros fold and thrust belt, SW Iran, have significantly improved our understanding of the post-Jurassic evolution of the basin. A number of regional-scale tectonic events since the Early Cretaceous were separated by tectonically quiescence periods, which controlled the basin architecture of Central Zagros basin evolution. Subsidence patterns in the Dezful Embayment during tectonically active periods are evidence for the influence of the Precambrian basement tectonics on sedimentation and deformation. This study shows that basement paleo-highs in the Central Zagros are regional-scale features, which may be related to regional upwarps, and are not restricted to the reactivation of deep-seated faults. However, when deep-seated faults developed over regional basement highs, their impact on sedimentation could intensify and be easily recognized in seismic by truncation/onlap features. The impacts of subsidence variations in the Dezful Embayment to the deposition and maturation of the Albian source rock, and on the development of migration path ways for hydrocarbons, are discussed.

Mapping hydrocarbon charge-points in the Wessex Basin using seismic, geochemistry and mineral magnetics

Abstract This study reports a multidisciplinary approach to determining hydrocarbon charge-points and migration in the Wessex Basin, southern England. Geochemical analysis of reservoir core material (Bridport Sandstone and Inferior Oolite) using gas chromatography-mass spectrometry (GC-MS), suggests that the oil in the Wessex Basin is from a single source, and that small variations in environmentally sensitive biomarkers are likely due to small differences in maturity or depositional conditions during the formation of the oil over millions of years. Using seismic data, basin modelling revealed two potential hydrocarbon migration pathways from the hanging wall of the Purbeck fault into the Sherwood Sandstone reservoir at Wytch Farm. One of these potential pathways is represented by cores termed Creech and the other Bushey Farm. To try to distinguish between the two potential pathways, cores were studied using mineral magnetic techniques. The magnetic signature was characterised using low-temperature (

Vertical dominant migration channel and hydrocarbon migration in complex fault zone, Bohai Bay sag, China

The quantitatively/semi-quantitatively formation conditions of vertical dominant hydrocarbon migration pathways were analyzed based on the big data analysis of petroleum geological parameters of complex fault Zone zone in the central-south Bohai Bay. According to this condition, the vertical dominant migration pathway and its charge points/segments are searched through structural modeling assistant analysis in the East Sag of Huanghekou. Under the constraints of charge points/segments, numerical simulation of hydrocarbon charge and migration is carried out to successfully predict hydrocarbon migration pathways and hydrocarbon enrichment blocks in shallow layers of complex fault zone. The main results are as follows: (1) The hydrocarbon charge in shallow layers of the active fault zone is differential, the charge points/sections of vertical dominant migration pathways are the starting points of shallow hydrocarbon migration and are very important for the hydrocarbon migration and accumulation in the shallow layers. (2) Among the shallow faults, those cutting the deep transfer bins or deep major migration pathways, with fault throw of more than 80 m in the accumulation period and the juxtaposition thickness between fault and caprock of the deep layers of less than 400 m are likely to be vertical dominant migration pathways in the sag area. (3) By controlling the vertical dominant migration pathways and charging points/segments in carrier layer, Neo-tectonic movement caused the differential hydrocarbon accumulation in the complex fault zone. The research results are of great significance for the fine exploration of the complex fault zone.

Paradox in bulk and molecular geochemical data and implications for hydrocarbon migration in the inter-salt lacustrine shale oil reservoir, Qianjiang Formation, Jianghan Basin, central China

This study analyzes the bulk and molecular geochemical data of 56 core samples of the Eocene Qianjiang Formation, a confined source rock unit embedded with salt intervals formed in a hypersaline lacustrine setting in central China. These source rocks within a single evaporative cycle collected from a recent shale oil exploration well are highly laminated, consisting of both intra- and inter-salt shales. Both organic pores and matrix pores serve as storage for hydrocarbon generated from kerogen within the source rock. Because the contrast in density between kerogen and oil, conversion of kerogen to oil inevitably leads to the increase in pore pressure and oil expulsion from kerogen within the same source rock unit. Impregnation of source rocks by expelled oils from nearby mature source rocks or from the organic-rich laminae within the same source rock units leads to anomalous Rock-Eval pyrolysis data, characterized by an abnormally high S1 peak, a high Production Index (PI), a suppressed Tmax and other anomalies. It is contradictory that both Rock-Eval pyrolysis data and sterane isomerization ratios of the studied inter-salt shale samples indicate strong impact of allochthonous hydrocarbons in the source rocks, whereas most aliphatic biomarker parameters obtained from the solvent extracts of these shales still provide useful information on the vertical variation in organic source input and depositional environment of the host rocks. This study provides insights into the bulk and molecular geochemical data interpretation, particularly in the inter-salt shale oil system evaluation in inferring the prevailing directions and pathways of diagenetic fluid movement and hydrocarbon migration.

Organic geochemistry of the Early Cretaceous shales, Saar Formation in the East Shabwah oil fields, onshore Masila Basin of eastern Yemen

The early Cretaceous Saar Formation includes potential petroleum-bearing source rocks in the onshore Masila Basin, eastern Yemen. The organic matter input, depositional environment conditions and petroleum generation potential from the Saar Formation shales were investigated using geochemical and organic petrological methods.The shales of the Saar Formation contain total organic carbon of 0.5–3.5 wt percent. The geochemical analysis of the organic matter indicated that these shales have fair to very good hydrocarbon source potential. The kerogen of the organic matter is dominated by Type II/III and Type III, referring to both oil- and gas-prone source rocks. The biomarker and bulk carbon isotope analyses of the organic matter suggested that the kerogens were constituted from a combination of marine and high land plant organic matter, and were preserved under suboxic depositional conditions.The geochemical and petrographic analyses of the shales (e.g., vitrinite reflectance (VRo), pyrolysis Tmax and biomarker maturity ratios) lead to the conclusion that the shales are generally immature to very early mature, particularly in shallower locations where the thermal alteration level of the organic matter is not strong enough to generate petroleum. Therefore, this work suggests that the mature source shale intervals of the Saar Formation existed in the deeper parts of the basin could reach a good maturity level that can produce potential hydrocarbons. Prediction of the potential migration pathways for hydrocarbons produced by deep shales could significantly aid in the future of petroleum exploration in the Masila Basin of Eastern Yemen.