Hydrocarbon Migration Research Articles

Про значення природних карбонатів у процесах синтезу і генези вуглеводнів у літосфері Землі

The fundamental importance of studies of the processes of synthesis and genesis of hydrocarbons in the Earth's lithosphere has been confirmed and the prospects of the chosen direction for advanced research have been demonstrated, as well as for the thorough development of genetic principles of physical and chemical conditions of the formation of hydrocarbons deposits in various geological minds, focusing on the role of natural carbonate formation in this process. It is shown in this connection that one of the most striking natural phenomena of the Earth’s lithosphere is the obvious manifestations of veinlet-impregnated carbonate mineralization. This has been discussed in detail in the case of some areas of the Ukrainian Carpathians and Pre-Сarpathians, where the original carbonate veinlets of hydrothermal origin with traces of hydrocarbons migration are often happened, but industrial research works is rarely carried out because of their low (as expected) prospects for gas and oil deposits. We pay attention to the areas of development of the calcite veinlets with rare, perfectly faceted crystals of quartz – “Marmarosh diamonds” among the Cretaceous and Paleogene deposits of the South-Western slope of the Carpathians. As a result, supporting materials on the importance of natural carbonates in the processes of synthesis and genesis of hydrocarbons in the Earth’s lithosphere are given. It consists in the revealed previously unknown property of natural carbonates, mainly calcium carbonate, under the action of abiogenic high-thermobaric deep fluid to decompose and be an additional source of carbon with different isotopic compositions in the processes of synthesis and genesis of hydrocarbons: gas, oil, bitumen as well as a carrier of these compounds in time of their migration and conservation in new creations in the deposits of oil and gas-bearing areas and metallogenic provinces: deposits-fields, veins, fluid inclusions, veinlet-impregnated mineralization.

Hydrocarbon accumulation conditions and exploration targets of the Sinian Dengying Formation in the Southeastern Sichuan Basin

No breakthrough has been made in petroleum exploration of the Sinian Dengying Formation in the southeastern Sichuan Basin as the major factors controlling the hydrocarbon accumulation of the Dengying Formation have not been well established, including the development period and distribution of the platform margin, the effectiveness of the source-reservoir combination and the reliability of the Cambrian pre-salt structural trap. Based on the interpretation of seismic data and hydrocarbon-source correlation, the distribution of the platform margin of the Sinian Dengying Formation in the southeastern Sichuan Basin was mapped. Moreover, the gas source rocks of the Dengying Formation were clarified according to geochemical characteristics of fluid inclusions, and the pre-salt structures were further confirmed by seismic forward modeling and experiments of prestack depth migration. Results showed that the sedimentary facies of the 4th member of Dengying Formation in the southeastern Sichuan Basin was platform margin of gentle slope type. The platform margin reservoir of the Dengying Formation and the Lower Cambrian source rocks constitute a favorable source - reservoir combination. The carbon isotope characteristics of gas in fluid inclusions indicate that some of the oil/gas in the Dengying Formation were contributed by the Doushantuo Formation source rocks. As the difference in seismic velocities between carbonate rocks and gypsum/salt beds may cause a reduction in the amplitude of pre-salt structures, the low-amplitude structures identified on current seismic profiles are underestimated instead of overestimated. Accordingly, the Sinian structural traps are confirmed to develop in the deep pre-salt sequences in the low-steep anticline belt, southeastern Sichuan Basin. On the basis of the above new understanding, we propose two types of hydrocarbon migration modes for the Sinian Dengying Formation in southeastern Sichuan Basin, including lateral migration of hydrocarbons generated from the Cambrian Qiongzusi Formation and vertical migration of hydrocarbons derived from the Sinian Doushantuo Formation. Lithologic traps at the platform margin and pre-salt structural traps within the platform are favorable targets for natural gas exploration.

Overpressure origins and evolution in deep-buried strata: A case study of the Jurassic Formation, central Junggar Basin, western China

Overpressure is significant to the exploration and exploitation of petroleum due to its influence on hydrocarbon accumulation and drilling strategies. The deep-burial hydrocarbon reservoirs of Jurassic strata in the central Junggar Basin are characterized by intensive overpressure, whose origins are complex and still unclear. In this study, Bowers’ method and sonic velocity-density crossplot method based on well logging data were used as a combination for overpressure judgements in geophysics. Furthermore, the corresponding geological processes were analysed in quality and quantity to provide a rational comprehension of the overpressure origins and the model of overpressure evolution and hydrocarbon accumulation processes. The results showed that hydrocarbon generation in the Jurassic source rocks led to overpressure in the mudstones, while hydrocarbon generation in Permian source rocks led to overpressure in the sandstone reservoirs in Jurassic strata by vertical pressure transfer. The burial and thermal history indicated that the aquathermal effect of pore fluids by temperature increase in deep strata is also an important origin of overpressure, while disequilibrium compaction may not be the dominant cause for the overpressure in deep-buried strata. Furthermore, the continuous tectonic compression in both the north–south and west-east trends from the Jurassic period to the present may also have enhanced the overpressure in deep strata. Meanwhile, the developed faults formed by intensive tectonic compression led to pressure transfer from source rocks to the Jurassic reservoirs. Overpressured geofluids with hydrocarbons migrated to sandstone reservoirs and aggravated the overpressure in the Jurassic strata. To conclude, the intensive overpressure in the central Junggar Basin is attributed to the combination of multiple mechanisms, including hydrocarbon generation, the aquathermal effect, tectonic compression and pressure transfer. Furthermore, the developed overpressure indicated hydrocarbon migration and accumulation processes and the potential of oil and gas reservoirs in deeply buried strata. We hope this study will provide a systematic research concept for overpressure origin analysis and provide guidance for petroleum exploration and exploitation in deep-buried strata.

Mercury isotope variation during organic matter maturation to petroleum

Although both sedimentary rocks and petroleum generally contain detectable levels of Hg, the characteristics of Hg isotope fractionation and its transformation from biomass to sedimentary rocks to petroleum have not been sufficiently investigated to date. Here, we report Hg contents and isotope compositions in source rocks and crude oils from the Paleogene of the Bohai Bay Basin and in source rocks from the Permian and Jurassic of the Sichuan Basin in China. Our analysis made use of an improved crude oil Hg pre-concentration system involving pyrolytic cracking and KMnO4/H2SO4 Hg trapping to analyze Hg fractionation during organic matter maturation to petroleum. Positive mass-independent fractionation (MIF) signatures of Hg isotopes were detected in the source rocks, with Δ199Hg ranging between −0.04‰ and + 0.48‰ (mean + 0.12 ± 0.12‰), which is significantly different from the negative Δ199Hg of terrestrial non-source rocks. Positive Hg-MIF signatures were detected in the crude oil, with Δ199Hg ranging between +0.04‰ and + 0.21‰ (mean + 0.13 ± 0.06‰). We propose a model of Hg isotopic fractionation related to organic matter history. From organic matter to source rock, Hg system variations are attributed to endogenic (i.e., photoreduction) and exogenic processes (i.e., terrestrial, magmatic and hydrothermal Hg inputs). From source rock to petroleum, Hg is mobilized during hydrocarbon migration, a process that occurs with MDF but without significant MIF.

Qualitative mineralogical analysis of Barracuda exploration well in the offshore Mannar Basin (the Indian Ocean) using FTIR and XRD techniques

The Mannar Basin plays a vital role in petroleum exploration in Sri Lanka, and its Barracuda exploration well was drilled up to 4206 m in depth. The objective of the current study is to identify mineralogy using Fourier-transform infrared (FTIR) and X-ray diffraction (XRD) analyses. The FTIR and XRD analyses confirm the presence of quartz, feldspar, clay minerals (e.g., kaolinite, montmorillonite), calcite, and hematite in all marlstone and mudstone samples. These sedimentary rocks can be identified as potential petroleum source rocks in the Mannar Basin. Quartz, carbonate, and hematite cementations are directly reduced porosity and permeability, and thus primary migration of hydrocarbons from potential source rocks. Clay minerals act as a seal for hydrocarbon migrations in the Mannar Basin. A variety of dominant clay mineral assemblages allows the reconstruction of several paleoclimatic chronozones in warm/wet and arid climates. In contrast, feldspar dissolution promotes the primary migration of hydrocarbon from potential petroleum source rocks. Consequently, this study concluded that common minerals such as quartz, carbonate, and hematite are associated with the trapping and binding processes of hydrocarbons.

Phase zonation of distribution of hydrocarbons in the southern part of the Timan-Pechora oil and gas province according to the principle of differential entrapment

The article reviewed the phase zonation of the distribution of hydrocarbons in natural reservoirs in the southern part of the Timan-Pechora plate (Verkhnepechorskaya and Izhma-Pechora depressions) and the Timan ridge (Ukhta-Izhemsky wall) from the standpoint of the Maximov-Savchenko-Gassou principle of differential hydrocarbon entrapment. Undoubtedly, the formation of oil and gas deposits is a very complex process and at the same time the principle of differential entrapment is a special case in nature. However, the distribution of hydrocarbons accumulations of various phase states formed according to the principle of differential entrapment is quite often observed in the trap chain, so that the spacing of oil and gas accumulations fits well into this concept and works for the above-mentioned structures. Keywords: migration and accumulation of hydrocarbons; principle of differential entrapment of hydrocarbons; phase zonation; oil density.

ANALYSIS OF DEPOSITIONAL ENVIRONMENTS OF UK FIELD RESERVOIR SANDS IN NIGER DELTA BASIN, NIGERIA

The environments of deposition play a vital role during hydrocarbon formation, migration, trapping and storage. Since the reservoir rocks are a function of their depositional environments, the successful tapping of hydrocarbon from its host rock when wells are drilled depends largely on the petrophysical characteristics of the reservoir rocks which in turn originated from and are influenced by their depositional environment. The reservoir facies in Niger Delta shows a broad range of characteristic sedimentological complexities that gave rise to subsurface geological, drilling and production problems occurring in UK Field. The problems include inaccurate determination of environments of deposition, imperfect stratigraphic correlations and reservoir top uncertainty across the UK Field which are targeted by this research in other to help resolve these challenges facing oil and gas industries in the Niger Delta basin of Nigeria. The research findings will assist in the evaluation of depositional environments and well-to-well lithologic correlation within the UK Field and Niger Delta Basin at large. It will also help to unravel major causes of reservoir top uncertainty in UK Field. Also, it will help in future planning and drilling of new wells within UK Field. The determination of the depositional environments of UK Field reservoir sands were carried out to determine the depositional environment of reservoir sand bodies based on data from seven (7) wells. The determination of depositional environments of sand facies penetrated by wells UK1, UK2, UK3, UK4, UK5, UK6 and UK8 was achieved through a side-by-side comparison of their log suites to standard log motifs. Results of facies analysis showed that the reservoir sands belong to mostly (i) fluvial channel, (ii) barrier bar, (iii) lower-middle shoreface, (iv) distributary mouth bar, (v) distributary channel, (vi) point bar and (vii) tidal channel environments that belonged to parts of a deltaic system. Lithologic correlation result reveals the existence of good correlation among all wells in UK Field due to good geological similarities except well UK8 that failed to correlate perfectly with others thereby establishing the existence of reservoir top uncertainty within UK Field. Therefore, reservoir top uncertainty within UK Field is geologically controlled.

Exceptional preservation of organic matter and iron-organic colloidal mineralization in hydrothermal black smoker-type sulfide mineralization from the Paleoarchean seafloor

Fossil organic matter (OM) in Paleoarchean rocks is an invaluable tracer of ancient life, yet it is often contentious due to low preservation potentials of its original organic molecular characteristics under generally high metamorphic grades. This study reports on exceptionally preserved OM within black smoker-type sulfide mineralizations from the 3.24 billion-years-old Sulphur Springs volcanic-hosted massive sulfide deposit, East Pilbara Terrane, northwestern Australia. Fine scale mineralogical and organic molecular variations – documented by SEM and TEM techniques, Raman and FTIR Spectroscopy, as well as ToF-SIMS analysis – trace the formation of millimetre-scale pyritic hydrothermal orifices. Overmature OM (≳200–250 °C) enriched in aromatic hydrocarbons occurs within earliest formed colloform-banded pyrite that could have precipitated at high temperature upon mixing of hot hydrothermal fluids with cold seawater. In contrast, mature OM (within the catagenesis window; ∼100–150 °C) with lower proportions of aromatic hydrocarbons occasionally occurs alongside pyrite within barite near the inner paleofluid conduits of the hydrothermal orifices. A deposition of this OM generation from cooler fluids enriched in sulfate during waning hydrothermal activity is corroborated by its association with original mineralogy, particularly the occurrence of isolated nanoinclusions of OM within hydrothermal barite away from grain boundaries or fissures and cracks, which renders impossible an origin from post-depositional hydrocarbon migration. When compared to the overmature OM within colloform-banded pyrite, the better-preserved inner OM not only contains less abundant, smaller, and less ordered aromatic hydrocarbons, but also higher amounts of aliphatic molecules with longer chain lengths and higher proportions of carbonyl and amide functional groups. Although the latter characteristics are consistent with contributions by microbial biomass, abiotic origins are equally plausible because hydrothermal processes can produce OM with similar organic molecular attributes. Irrespective of these uncertainties on the ultimate sourcing of OM, common intergrowths of the cooler OM with nanoscopic iron oxides – hematite and lesser magnetite – hint at its hydrothermal deposition from colloidal particles that have been stabilized by iron-organic complexation. Further research is required to ascertain the significance of this process for the hydrothermal cycling and release of organic carbons and bound iron into the Paleoarchean oceans. Collectively, our results show that ancient marine hydrothermal systems can preserve OM with differing degrees of thermal degradation, which allows for insights into its sourcing, cycling, and deposition.

Prediction Method and Application of Hydrocarbon Fluid Migration through Faulted Cap Rocks

Hydrocarbon fluid migration through faulted cap rocks was determined by comparing the maximum connected thickness of cap rocks required for hydrocarbon fluid migration and the actual values, since cap rocks are important in the study of hydrocarbon fluid distribution in petroliferous basins based on its migration mechanism(s). The maximum connected thickness required was identified by comparing the cap rocks, fault displacement, and oil/gas distribution. The hydrocarbon fluid at the Putaohua reservoir migrated to the overlying Saertu and Heidimiao reservoirs in the Bayan Chagan Area, northern Songliao Basin. This was predicted to demonstrate the validity of the method. The results show that the adjusted Putaohua oil reservoir was distributed near the Talahai fault and Bayanchagan fault, rather than the Gulong sag in the southwest of the study area, where oil migrated vertically through the Sapu cap rocks to the overlying Saertu reservoir. Thick mudstone cap rocks in the second member of the Nenjiang Formation made it difficult for hydrocarbon fluid to migrate to the Heidimiao reservoir. This agrees well with hydrocarbon fluid distribution at the Putaohua, Saertu, and Heidimiao reservoirs in the Bayan Chagan Area, indicating that this method is feasible for predicting hydrocarbon fluid migration through faulted cap rocks.

Yam Seep at Four-Way Closure Ridge: a prominent active gas seep system at the accretionary wedge SW offshore Taiwan

Hydroacoustic surveys at the accretionary wedge southwest of Taiwan reveal a confined active hydrocarbon seepage area of ~ 49,000 m2 in ~ 1350 m water depth on the northern crest of the Four-Way Closure Ridge, which we call Yam Seep. In this study, multibeam and side-scan sonar data acquired during surveys with an autonomous underwater vehicle during an expedition with R/V Ocean Researcher I in 2017 showed that the area is characterized by rough topography and high seafloor backscatter. Seafloor observations with a video sled and sediment sampling with gravity corers and the MeBo seafloor drill rig during an expedition with R/V SONNE in 2018 revealed that the area is almost entirely covered by intensely fractured methane-derived carbonates, which indicate that seepage has been ongoing for thousands of years. Hydroacoustic anomalies (‘flares’) in the water column indicated the presence of several gas bubble emission sites mostly at the center and eastern flank of the area in 2019. Drilling through massive carbonates in the northwestern part of Yam Seep induced free gas escape from a depth of ~ 5.1 m. This suggests the presence of gas hydrates in the subsurface as the seep area is located well within the gas hydrate stability zone. The inter-disciplinary investigations of the Yam Seep demonstrate that upward migration of light hydrocarbons and seafloor discharge has a considerable influence on the seabed properties.

Using Spontaneous Imbibition to Evaluate the Hydrocarbon Migration and Accumulation Potential of Shale Reservoirs: A Case Study of the Permian Fengcheng Formation in the Mahu Sag, Junggar Basin

Using Spontaneous Imbibition to Evaluate the Hydrocarbon Migration and Accumulation Potential of Shale Reservoirs: A Case Study of the Permian Fengcheng Formation in the Mahu Sag, Junggar Basin

Identifying the hydrocarbon potential from seismic, geochemical, and wireline data of the Sallum intra-basin, North Western Desert of Egypt

ABSTRACT The current study's objectives are to identify the primary source rock's hydrocarbon potential and, using various approaches, examine the Sallum Concession's petroleum system, which lies in the extreme northwestern part of the Western Desert of Egypt. We integrated seismic, geochemical, and well logging data. As a result, the structure analysis indicates that the area is elevated topographic land, representing a high intra-basin about the surrounding Faghour, Matrouh, and Shushan basins. Therefore, the site is a significant concession with various source rocks; Khatatba (Safa member) and Alam El-Buieb (AEB-3A member) are the oil-prone source rocks of the northern and southern parts of the area with high TOC (up to 11.3%) and mid-mature stage (0.7-1.0% Ro) at depth below 8000 ft. On the other hand, the Paleozoic Desouqy, Zeitoun, and Shiffah formations, located below 12000 ft, are gas-prone source rocks with high organic contents (TOC 1.41-4.64%) and fair potential for gas generation and are currently in the mid-mature stage (0.7-1.0% Ro). We concluded that the concession's low oil production might result from a delay in Kerogen maturity and hydrocarbon migration. Finally, the East of Sallum concession is the only potential area because the wells in the west do not show reservoirs characteristics.

Biomarkers and Carbon Isotope of Monomer Hydrocarbon in Application for Oil-Source Correlation and Migration in the Moxizhuang-Yongjin Block, Junggar Basin, NW China.

Different opinions on the oil-source correlation and migration of the Moxizhuang-Yongjin block in the Junggar Basin, NW China, have seriously affected oil and gas exploration in this area. This research is based on the results of biomarker analysis and carbon isotope of monomer hydrocarbon on crude oil and source rock samples from different blocks. Two oil families (A1, A2, and B) are classified by cluster analysis on nine typical biomarker ratios. Typically, sub-family A1 oils are distributed in the Zhuang 102 well block of the Moxizhuang block, and their gammacerane index is the highest. The abundance of C24 tetracyclic terpanes is the lowest, the C27 regular steranes are dominant, and the organic matter is mainly input by lower aquatic organisms. Sub-family A2 oils are distributed in the Zheng 1-1 well block of the Moxizhuang block. The gammacerane index of oils is lower than the former, and the abundance of C24 tetracyclic terpanes is higher. In the dual input of lower aquatic organisms and terrestrial higher plants, the input of terrestrial higher plants accounted for a larger proportion. Family B oils are distributed in the Yong 2 well block of the Yongjin block, and their gammacerane index is the lowest. They have a high abundance of C24 tetracyclic terpanes, and C29 regular steranes are dominant, reflecting the characteristics of terrigenous organic matter contribution. Based on the biomarker compound composition, at least two oil charges are indicated: Sub-family A1 oils are likely sourced from the Wuerhe formation, sub-family A2 oils may be a mixture of Wuerhe formation and Badaowan formation, and family B oils are likely sourced from the Badaowan formation. The oil families with typical genetic affinities may indicate two major petroleum systems or multiple oil systems existing in the study area. In addition, the characteristics of hydrocarbon accumulation and migration are also discussed, the oil and gas in the West Sag of Well Pen 1 and Changji Sag are filled from deep to shallow in the vertical direction and migrated from south to north in the horizontal direction, at the same time, with the help of sand bodies and faults, and they migrated to the north and northeast. This work provides a scientific basis for oil and gas exploration in the hinterland of the Junggar Basin.

Basin modeling constrains source rock position and dimension in the Burano-Bolognano petroleum system (Central Italy)

A two-dimensional basin and petroleum system modeling approach was applied to the Burano-Bolognano petroleum system (Central Italy) to constrain some factors (position, lateral extension and maturity of the source rock, the role of fractures and faults in hydrocarbon migration) which influenced its structural evolution and the related migration pathways. The petroleum system extends from the Majella Mountain to the northern Cigno, Vallecupa, Bonanno oil fields, intensively explored during the past century. Some features, such as the location and extension of the source rock and its maturity, and hydrocarbon pathways, are still undefined. Thus, we developed a 3D geological static model of the Cenozoic carbonate succession and then, we performed basin modeling along a 2D geological section, integrating the petrophysical properties of rocks measured in laboratory. Our results prove that the Burano source rock reached a low-middle maturity, and the best representation of the actual hydrocarbon occurrences is reached when the source rock is at north of the Majella Mountain with a minimum extension of 3 km. For the BBPS a strong lateral migration and a gradual oil biodegradation towards the Majella area must be considered. Moreover, modeling results highlight a minor control of the faults on the migration in this area. This basin modeling is relevance for investigations in similar settings since carbonate-ramp reservoir studies are usually very challenging to be correctly modeled due to their high heterogeneities.

The Structural-Stratigraphic Framework And Petroleum Systems Of The Sandakan Basin, Offshore East Sabah, Malaysia

Decades of exploration activities in the Sandakan Basin offshore eastern Sabah, Malaysia, since the 1970s have yet to yield commercial hydrocarbon discoveries. Of the nineteen wells that have been drilled in the basin up to 2015, only five are classified as discoveries, all made between 1970 and 1995. There are essentially two main proven play types: (1) Early to Middle Miocene “Segama play”, in which the reservoir targets are the Tanjong Formation equivalents within the Segama Group, which were deposited as part of the synrift sequence. (2) Middle to Late Miocene “Sebahat play” in which the reservoirs belong to the Sebahat Formation, characterised by prograding deltaic shoreface and shelf sequences, advancing eastwards and southwards from an uplifting hinterland in central and northern Sabah. The best reservoir facies are shoreface sands, which have porosities greater than 20%, particularly at depths shallower than ~2000 m. Although the generative source rocks have not been penetrated, geochemical data indicate that they are present at depths greater than 3200 m. The source rocks are characterised by predominantly Type III and Types II/III organic matter, which are typical of deltaic settings. The data indicate that hydrocarbons were generated by source rocks with a maturity range of 0.7 – 0.8% vitrinite reflectance (Ro). The Sandakan Basin was affected by several compressional deformation events which are expressed as major erosional unconformities; most significantly, the Middle Miocene (“D2 event”, 13.0 Ma) and Late Miocene (“D3 event”, 8.6 Ma). The unconformities were the result of compression and faulting which, while being responsible for trap formation, may also pose significant risk to trap integrity and preservation. Modelling results indicate that hydrocarbon generation and migration took place during Late Miocene–Early Pliocene and continues today. The basin’s prospectivity, therefore, critically depends on the delicate interplay between the timing of trap formation and hydrocarbon migration. Understanding these processes requires detailed understanding of the structural evolution and petroleum systems of the basin.

Constraining hydrocarbon migration and accumulation by two-dimensional numerical simulation: Ordovician carbonate reservoirs of the Daniudi Area, Ordos Basin

The various types of reservoir space in carbonate reservoirs make the process of hydrocarbon migration and accumulation very complex. How to quantitatively characterize the characteristics of hydrocarbon migration and accumulation in carbonate reservoirs is one of the key problems for carbonate hydrocarbons exploration and exploitation. Taking the Ordovician in the Daniudi area of Ordos Basin as an example, three types of source rock-reservoir-cap assemblages, namely upper-generation assemblage, lateral variable assemblage, and self-generation-reservoir-cap assemblage, were determined by characterizing the forming elements of carbonate reservoirs. Petromod software is used to build a two-dimensional profile model, and vitrinite reflectance of source rock and porosity of the reservoir were used as correction parameters, and the hydrocarbon migration and accumulation process was simulated by the invasion percolation algorithm. It is confirmed that the Ordovician Majiagou formation in the study area has three periods of hydrocarbon charging and three periods of hydrocarbon adjustment. The hydrocarbon migration pathways in carbonate rocks include lateral contact in the pinch-out area, source rock-reservoir contact in the trough area, fault-connected, and source rock-reservoir superposition. The source rock-reservoir-cap assemblages of upper-generation assemblage and lateral variable assemblage correspond to the lateral contact in the pinch-out area, source rock-reservoir contact in the trough area, fault-connected, while self-generation-reservoir-cap assemblage corresponds to the fault-connected, and source rock-reservoir superposition. The high part of the structure and fault zone are the strongest structural deformation parts, whose fractures are relatively developed, controlling the location of hydrocarbon accumulation, meanwhile, the reservoir quality directly controls the degree of hydrocarbons saturation. The research results are beneficial to establish a more accurate quantitative evaluation method of hydrocarbon migration and accumulation in carbonate rocks and to understanding the controlling factors of hydrocarbon migration and accumulation in carbonate rocks.

Formation mechanism and hydrocarbon exploration significance of the box fold in the Qiulitage structural belt, the Kuqa Depression, Tarim Basin, China

Clarifying the deformation characteristics and formation mechanisms of the box fold in the eastern Qiulitage structural belt can provide important references for the reconstruction of the evolution process and petroleum exploration in the Qiulitage structural belt. As a result of the deep geological structure displayed by seismic data and characteristics of faults and fractures within the box fold, the mechanical mechanism and structural evolution of the box fold in the eastern Qiulitage structural belt were investigated, along with the genesis and significance of hydrocarbon exploration of faults and fractures within the box fold. The results show that the surface box fold in the Qiulitage structural belt was formed via the conjugate kinking of the supra-salt structural layer, driven by the intensive southward compression during the Middle and Late Himalayan movements. The box fold has experienced three evolution stages, namely, the tectonically-inactive stage before the deposition of the Kuqa Formation, the fold rudiment stage during the early to middle deposition of the Kuqa Formation (Kuqa period), and the stage of fold finalization and uplift-denudation. The front flank of the box fold develops north-dipping thrust faults and network fracture systems formed during the early to middle Kuqa period and cemented by gypsum due to the precipitation of deep, high-salinity formation water. However, later faulting can cut and dislocate the cement. The upper fold core develops north-dipping tensile faults and near EW tensile fractures, while the lower fold core is associated with small back-thrust structures and near NS shear fractures. The neutral plane is expected to be in the middle-lower part of the fold. The back-flank of the box fold develops south-dipping back-thrust faults and near EW interlayer shear fractures caused via interlayer detachment. The core and back flank of the fold were less affected by the high-salinity formation water, leaving faults and fractures with no considerable cementation. The kink zone and its surroundings have high storage and flow capacities and thus the potential to and develop oil and gas reservoirs. Correctly interpreting kink zones in concealed areas can help expand the scale of original oil and gas reservoirs or discover new petroleum exploration domains. In the Qiulitage structural belt, the connection between deep and shallow fault systems leads to the migration of deep hydrocarbons to shallow layers and subsequent accumulation. The structural-lithologic oil and gas reservoir formed in the Paleogene thin sand layers of the upper part of the Lower Cretaceous and the structural oil and gas reservoir formed in supra-salt sandstone layers of the surface box fold are among The potential exploration domains in shallow layers.

Diagenesis- and thermal maturity-evolution of the Silurian unconventional hydrocarbon deposits (Tassili n’Ajjer plateau, Algeria): Clay mineralogy, graptolite reflectance, and K–Ar dating

The need for determining the thermal maturity of Lower Paleozoic rocks has increased with the intensified unconventional shale oil/gas resources exploration within North Africa, Arabian Peninsula, and the adjoining regions. Indeed, Lower Paleozoic strata represent an increasingly important resource that is related to the globally widespread occurrence of graptolite-bearing marine sediments in an expansive shelf area of the Gondwana. However, some crucial information for basin analysis remains poorly understood even across the largest hydrocarbon-producing province in Algeria.The present study provides a solid understanding of the diagenesis- and thermal maturity-evolution from the Tassili n’Ajjer plateau while involving multiple and independent approaches, such as clay mineralogy, petrography, graptolite reflectance, source rock maturity, as well as illite K−Ar geochronology. The combined use of X-ray analysis and field emission scanning electron microscope evidenced kaolinite, illite, and iron-rich chlorite as the main authigenic mineral phases. K−Ar data indicate that episodic in situ illite crystallization occurred at different times, the oldest illite at about 335 Ma and the youngest illite between 238 and 179 Ma, under diagenetic-to-hydrothermal conditions. Paleotemperature estimates (∼165–232 °C) derived from illite crystallinity (0.37–1.58 Δ°2θ), and graptolite reflectance (VReqv, 1.09–1.84%) values indicate deep diagenetic-low anchizone boundary conditions. This is broadly suggestive of late oil-to-dry gas zones of hydrocarbon generation and destruction, notably in the western sector of the study area.At least two heating events and diagenetic fluid flow processes are identified mainly in response to various tectonic events. They are largely due to fault reactivations, and migration of hot, potassium-rich, fluids throughout the Phanerozoic. Additionally, these events and processes had a later influence on the hydrocarbon maturation, migration, and/or entrapment, especially along the inherited N–S lineaments and Hoggar Massif mega-shear zones in the westernmost part of the Tassili n’Ajjer plateau.Lastly, it is important to highlight that the promising areas offering the highest potential for future unconventional hydrocarbon resource exploration could be most likely those bordering major lineaments, coupled with subsequent igneous activity, where unrestricted hydrothermal fluids are frequently reported, as well as the maturation, being much more advanced.

Microstructural Analysis of Organic-Rich Shales: Insights from an Electron Microscopic Study by Application of FIBSEM and TEM

Matrix-related pores play a significant role in controlling hydrocarbon production in organic-rich shales. Multiple matrix-related pore types of typical marine shales in the Sichuan Basin have been visually investigated and identified by transmission electron microscopy (TEM) on ultra-thin sections and by focused ion beam-scanning electron microscopy (FIBSEM) on polished sections. OM-hosted pores seem universal and range in sizes from below 1 nm to hundreds of nanometers and they are not homogeneously developed and distributed, which is mainly determined by thermal maturity and OM composition. Mineral-hosted pores are defined by mineral frameworks and occur in open spaces related to ductile or rigid grain fabric. The four porous mineral types that occur are clay intrapores, carbonate solvopores, pyrite interpores, and quartz interpores, and they range in size from less than 1 nm to more than several microns. Aggregate-hosted pores are predominantly associated with clay-organic aggregates, pyrite-organic aggregates, clay-pyrite aggregates, and clay-organic-pyrite aggregates. The most common aggregate-hosted pore networks are defined by clay-organic aggregates, and the pores are largely developed between the clay and organic layers and may be the important adsorption spaces for methane. Fracture-related pores include microchannels and microfractures of various sizes and shapes and they could play a key role in providing hydrocarbon migration pathways. FIBSEM and TEM show direct evidence that OM-hosted pores and fracture-related pores contribute more to the effective pore network and the excellent reservoir quality, whereas poor reservoir quality may come from aggregate-hosted pores.

Potential petroleum prospects in the middle Benue trough, central Nigeria: Inferences from integrated applications of geological, geophysical and geochemical studies

The Middle Benue Trough (MBT) is the least well-known of the three major sub-divisions of the Benue Trough (BT) and therefore poorly understood geologically. This paper presents preliminary results of an integrated geological, aeromagnetic, gravity and geochemical studies carried out as a first step approach to petroleum exploration in the central portion (MBT) of the Benue Trough, Nigeria, so as to be able to; 1. Appraise the regional geologic setting of the MBT with a view to understanding the stratigraphy and its oil generation characteristics; 2. Determine the basin configuration and sediment thicknesses and; 3. identify and delineate “leads” or prospect areas for further detailed exploration that could lead to significant commercial discoveries of hydrocarbon in the MBT. Results have revealed the existence of petroleum systems in the MBT with the interbedded shales of the Bima and Yolde formations at the upper portions and the shales of the Asu River Group, Awe, Ezeaku and Agwu formations corresponding to the potential source rocks. The main local potential reservoir rocks are the Bima Sandstones and sandstones of the Yolde Formation coupled with the interbedded arkosic sandstones of the Awe and Keana Formations, while potential regional seals are the shales of Pindiga Formation and the arkosic sandstones overlying the shales of the Asu River Group and the basal shales of the Ezeaku formation and the upper shales horizon of the Agwu formation. Geophysical studies (Aeromagnetic/gravity survey) revealed the variability of the surface to Basement depths within the Middle Benue Trough ranging from 3 – 6 km with the deepest portions of up to 8.2 km towards the Northeastern portion of the MBT. The thick sediment piles coupled with the favorable petroleum systems, provide the conditions necessary for hydrocarbon generation, migration and accumulation. The prominent lineament structure is the NE-SW directional Keana anticline which extends along a strike for more than 100 Km from the south of Makurdi to Zurak in the northern portion. Trans tensional and trans compressional fault systems in the basin have given rise to sub-surface and extensive lineament structures systems which could either constitute major structural traps or pathways for fluid (hydrocarbon) flow. The analysis of a wide range of geochemical data from the MBT revealed TOC values ranging from 0.43 to 3.90wt% for shales/coaly shales and 14.78–79.10wt% for shaly coal/coal facies embedded in the Agwu formation with Tmax values corresponding to immature to mature stages of thermal maturation. Their petroleum potential in terms of HI values ranges from 14 to 267mgHC/gTOC in shale/coaly shale facies and 36–157mgHC/gTOC in shaly coal/coal facies, corresponding to the predominance of type III (gas-prone) in addition to type II (oil and gas-prone) organic matter suggestive of having both oil and gas generating potential. The recent discovery of significant quantity of oil (+gas) in the well Kolmani River-1 in the Gongola Sub-basin, is in strong support of its occurrence in the MBT. The paper has recommended selected prospect areas favorable for further detail hydrocarbon exploration.