Mature Source Rocks Research Articles

Detection and potential geochemical significance of methyltrimethyltridecylchromans in mature crude oils

Methyltrimethyltridecylchromans (MTTCs) are biomarkers that are commonly used to identify immature-low mature source rocks or crude oil. MTTCs are abundant in the mature crude oils found in the Machang area of the southern Dongpu Depression in the Bohai Bay Basin. To explore the mechanism behind the enrichment of MTTCs in mature crude oils, a detailed study was conducted to investigate their distribution characteristics in crude oil samples. The study integrated tectonic evolution history, distribution characteristics, and thermal history of source rocks, molecular fingerprints characteristics of crude oils, and catalytic characteristics and combination features of clay minerals in the wall rock of crude oils. Based on this analysis, two enrichment models were proposed: (1) The first model suggests that crude oils were mixed with a small amount of immature-low mature soluble bitumen containing MTTCs; (2) The second model proposes that the evolutionary mechanism of clay minerals in the reservoir could reduce the decomposition rate and degree of MTTCs, resulting in their relative enrichment. Therefore, this study provides insights into the enrichment mechanism of MTTCs in mature crude oils and highlights the importance of considering various factors, such as tectonic evolution history, source rock characteristics, and catalytic properties of clay minerals, to understand the distribution and enrichment of biomarkers in crude oils.

Study on the Tight Gas Accumulation Process and Model in the Transition Zone at the Margin of the Basin: A Case Study on the Permian Lower Shihezi Formation, Duguijiahan Block, Ordos Basin, Northern China

Recent discoveries of oil and gas have principally been located in the central part of the Ordos Basin, which is a petroliferous basin with the largest discovered reserves and annual production of tight sandstone gas in China. For tight sandstone gas reservoirs in the transition zone of the basin margin, the process of natural gas accumulation has remained relatively vaguely understood, because of the transitional accumulation of geological conditions such as structure, sedimentation, and preservation. In this study, thin-section identification and scanning electron microscopic observations of the reservoir core, measurement of the physical properties of the reservoir, microscopic petrography research and measurement of the homogenization temperature of fluid inclusions, digital simulations, and laser Raman spectroscopy analysis were combined to analyze the process of natural gas accumulation of the Permian Lower Shihezi Formation in Duguijiahan block, Hangjinqi area, northern Ordos Basin. The results showed that the Lower Shihezi Formation reservoir in the Duguijiahan block began gas charging in the southern part as early as the Early Cretaceous (130–128 Ma), and then gradually charged in the northern part. Three stages were identified in the digital simulations of gas charging, i.e., the breakthrough, rapid, and fully saturated stages. The initial porosity of the Lower Shihezi Formation reservoir ranged between 28% and 40%. Later, because of strong compaction and interstitial filling during burial, the sandstone porosity decreased rapidly, and densification (porosity < 10%) occurred in the mid–late Jurassic. This late tectonic uplift caused a continuous reduction in ground temperature, and diagenesis had a weak effect on pore transformation. The present porosity of the Lower Shihezi Formation reservoir basically inherited its characteristics in the late Early Cretaceous. The current average porosity of the reservoir is 8.58%, and the average permeability is 0.88 mD, and it can thus be characterized as a tight reservoir. The gas accumulation process of the Lower Shihezi Formation has three stages: (1) the depositional stage (C–P), corresponding to the depositional stage of the source-reservoir-cap combination in gas reservoir; (2) the natural gas accumulation stage (T–K1), corresponding to the period of rapid source rock maturation and natural gas charging step-by-step; and (3) the gas reservoir adjustment stage (K2–present), corresponding to the period of uplift and natural gas charging in the early stage that gradually migrated and accumulated northward along the fracture zone. Finally, the gas accumulation model in the transition zone at the margin of basin was established.

Restoring source rock initial quality and quantity with kinetic-based inversion - Applied to the Wolfcamp play in the Permian Delaware Basin

To calculate the volume of hydrocarbon generated from a mature source rock, it is necessary to restore the total organic carbon (TOC) and hydrogen index (HI) to their initial conditions before the hydrocarbon generation. Various methods have been proposed to restore source rock properties. Most of these methods require measured HI data and assumptions on initial HI (HIi) to calculate the transformation ratio (TR) and then restore the initial TOC (TOCi) from measured TOC data. Estimating HIi can be challenging for samples with high maturity, for cases in which immature samples and maceral data are lacking, or for heterogeneous source rocks. This study presents a workflow using a kinetic-based inversion procedure to restore the source-rock's HIi and TOCi from measured HI and TOC data. Unlike the other methods, the kinetic-based inversion method uses simulated TR derived from the basin model and independent of assumed HIi to restore the HIi and TOCi from measured HI and TOC data. Thus, a pre-defined basin model with calibrated thermal model and assigned kinetic (organofacies) for the source rock intervals is required before the kinetic-based inversion procedure is performed. The workflow is applied to the Wolfcamp Play in the Permian Delaware Basin using a proprietary dataset covering the whole basin spatially. Based on geochemical interpretation, the organofacies within the Wolfcamp interval vary from predominantly marine clastic (OF “B”) to mixed marine-terrigenous (OF “D/E”) facies. The kinetic-based inversion result shows a considerable range of restored HIi and TOCi, values indicating source rock heterogeneity of the Wolfcamp Play. Generally, Wolfcamp A and B intervals are excellent source rocks with P50 HIi of ca. 594 and 508 mgHC/gTOC and P50 TOCi of 2.84 and 2.60 wt%, respectively. Wolfcamp C and D intervals are also good-very good source rocks with relatively lower potential than Wolfcamp A and B. Despite the limitation and uncertainty as to the consequence of using TR derived from the basin model, the kinetic-based inversion procedure has the advantages of requiring no assumption for HIi and restoring the source rock according to the thermal maturity, source rock organofacies, kinetic model, and measured data, among many others. Interpreted overall kerogen type of the Wolfcamp source rock using restored HIi and TOCi supports the interpretation of predominantly marine to mixed marine-terrigenous typed organofacies source rock using other data. Preliminary calculation of the restored HIi and TOCi and the calculated volumes of hydrocarbon yield also support the massive hydrocarbon volume predicted and produced for the Wolfcamp Play in the Delaware Basin.

The evolution characteristics of diamondoids in coal measures and their potential application in maturity evaluation

In this study, gold tube thermal simulation experiments were carried out on the soluble components (extracts) and insoluble components (extracted coal-measure mudstones) of coal-measure mudstones, and diamondoid compounds in the pyrolysis products were quantitatively analyzed. The results showed that diamondoid compounds in the extracts and the extracted coal-measure mudstones had undergone the process of formation and decomposition during thermal evolution. Based on the quantitative composition of the extracts and the extracted coal-measure mudstones, the calculated evolution characteristics of the diamondoid compounds in the coal-measure mudstones were mainly consistent with the results of thermal simulation experiments, indicating that the formation of diamondoid compounds was primarily controlled by the original material source. Some diamondoid maturity parameters (MAI, EAI, TMAI-1) in coal-measure mudstones were consistent with the parameters of the evolution characteristics in marine shale. Therefore, the relationship between these parameters and vitrinite reflectance can be established, to calculate the maturity of marine source rocks. In addition, the evolution characteristics and some diamondoid maturity parameters in the extracts and the extracted coal- measure mudstones showed a good linear relationship, but the specific characteristics were different, which may enable the identification of kerogen cracking and secondary cracking of crude oil.

Thermal maturity calibration of extremely high-mature pre-Devonian strata: A case study from the Lower Cambrian Qiongzhusi Formation in the Sichuan Basin, South China

Thermal maturity assessment of pre-Devonian strata is challenging due to the absence of humic vitrinite, and conventional organic geochemical methods (i.e., Rock-Eval Tmax, atomic H/C, biomarker parameters) are usually ineffective for the highly-over mature source rocks. The Lower Cambrian Qiongzhusi Formation shale in the Sichuan Basin, as the main high-quality source rock, is an important exploration target for shale gas. In this study, optical reflectance and Raman spectroscopy measurements were performed on eight Qiongzhusi Formation core samples from well JY1 in conjunction with basin modelling to calibrate to equivalent vitrinite reflectance and constrain thermal maturity. The results reveal solid bitumens/pyrobitumens as the predominant organic constituents in the Qiongzhusi Formation. As burial depth increases from 3,300m to 3,600m, the solid bitumen reflectance acquired from optical measurement and Raman calculation increase from 2.53% to 3.86%, and from 2.88% to 3.49%, respectively, along with increasing optical anisotropy. The Raman-calculated solid bitumen reflectance data are consistent with the optical reflectance data at depths <3,500m, while the former become lower than the latter at depths >3,500m and are consistent with reflectance values constrained by basin modelling. We propose that the surface quality and granularity of solid bitumen, hydrothermal fluid alteration, and varied thermal conductivity of mineral matrix result in the higher optical reflectance of solid bitumen occurrence in the Qiongzhusi carbonates. The multidisciplinary calibration approach integrating optical reflectance measurement, Raman spectroscopy and basin thermal modelling is considered effective and more accurate for thermal maturity assessment.

Source and thermal maturity assessment of the Paleozoic-Mesozoic organic matter in the Risha gas field, Jordan

Detailed geochemical analyses of the Lower Silurian-Cretaceous shales in the Risha Field were carried out to determine their source input (marine or terrigenous), paleoenvironment, maturity, and hydrocarbon generation potential for their contributions to the gas field. The Lower Silurian shales are believed to be effective source rocks for oil within the Paleozoic petroleum system in the Risha field. Furthermore, the Upper Cretaceous shales have high hydrocarbon potentials and are considered as a promising source for oil and gas. The Upper Ordovician, Lower Silurian and Upper Cretaceous shales in the study area were deposited in a marine anoxic environment, resulting in the accumulation of highly liptinitic organic matters derived from algae and bacteria (Type II kerogen). The maturity of the Lower Silurian source rocks increases from the oil window to the gas window. Ordovician shales have reached the over maturity stage. Current hydrogen index (HI) values for the Silurian organic matter are relatively low after significant hydrocarbon production and expulsion. Two oil types are found from the standard petroleum geochemical analyses of the studied shales: naphthenic oil from immature Cretaceous black shales and high maturity paraffinic oils from Lower Silurian and Ordovician layers. The thermal history model of the Lower Paleozoic source rocks reveals that the Lower Silurian shales reached the dry gas generation stage 280–250 million years ago during Early Triassic, suggesting the large volume of gas accumulated in the Risha field mainly from the Silurian source rocks.

Fluid inclusion evidence for overpressure-induced shale oil accumulation

Abstract Shale oil is becoming increasingly important in the global energy market, but its accumulation mechanism is not fully understood. We present novel and direct fluid inclusion data from the Lower Permian Fengcheng Formation, Mahu Sag, Junggar Basin, northwest China. Shortite veins in this source rock contain abundant two-phase gas-liquid hydrocarbon inclusions and coeval aqueous inclusions. The inclusions have highly variable degrees of bubble filling (5–80 vol% vapor) and homogenization temperature differences between oil and aqueous inclusions (~50 °C), which demonstrate that fluid (oil-gas-water) immiscibility occurred at high pressures. The hydrocarbon inclusions record different levels of fluid over-pressure (32.9–43.0 MPa), with a paleopressure coefficient of 1.3–1.7. Episodic fluid over-pressure release resulted in shale oil accumulation, with faults/fractures acting as important migration pathways. Oil from deeper and more mature source rocks within the Fengcheng Formation was expelled upward to the shale oil reservoir. These processes are common and important in shale oil systems. These results show that the accumulation of unconventional hydrocarbons occurs pervasively within the reservoirs, and fluid displacement is critical in exploration and exploitation.

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.

Genetic Relationship between Mississippi Valley-Type Pb–Zn Mineralization and Hydrocarbon Accumulation in the Wusihe Deposits, Southwestern Margin of the Sichuan Basin, China

The coexistence of numerous Mississippi Valley-type (MVT) Pb–Zn deposits and oil/gas reservoirs in the world suggests a close genetic relationship between mineralization and hydrocarbon accumulation. The Wusihe MVT Pb–Zn deposits are located along the southwestern margin of the Sichuan Basin. Based on the spatiotemporal relation between Pb–Zn deposits and paleo-oil/gas reservoirs, ore material sources, and processes of mineralization and hydrocarbon accumulation, a new genetic relationship between mineralization and hydrocarbon accumulation is suggested for these deposits. The Wusihe Pb–Zn deposits are hosted in the Ediacaran Dengying Formation dolostone, accompanied by a large amount of thermally cracked bitumen in the ore bodies. The Pb–Zn deposits and paleo-oil/gas reservoirs are distributed along the paleokarst interface; they overlap spatially, and the ore body occupies the upper part of the paleo-oil/gas reservoirs. Both the Pb–Zn ore and sphalerite are rich in thermally cracked bitumen, in which µm sized galena and sphalerite may be observed, and the contents of lead and zinc in the bitumen are higher than those required for Pb–Zn mineralization. The paleo-oil/gas reservoirs experienced paleo-oil reservoir formation, paleo-gas reservoir generation, and paleo-gas reservoir destruction. The generation time of the paleo-gas reservoirs is similar to the metallogenic time. The source rocks from the Cambrian Qiongzhusi Formation not only provided oil sources for paleo-oil reservoirs but also provided ore-forming metal elements for mineralization. Liquid oil with abundant ore-forming metals accumulated to form paleo-oil reservoirs with mature organic matter in source rocks. As paleo-oil reservoirs were buried, the oil underwent in situ thermal cracking to form overpressure paleo-gas reservoirs and a large amount of bitumen. Along with the thermal cracking of the oil, the metal elements decoupled from organic matter and H2S formed by thermochemical sulfate reduction (TSR) and minor decomposition of the organic matter dissolved in oilfield brine to form the ore fluid. The large-scale Pb–Zn mineralization is mainly related to the destruction of the overpressured paleo-gas reservoir; the sudden pressure relief caused the ore fluid around the gas–water interface to migrate upward into the paleo-gas reservoirs and induced extensive metal sulfide precipitation in the ore fluid, resulting in special spatiotemporal associated or paragenetic relations of galena, sphalerite, and bitumen.

New insights into Upper Cretaceous hydrocarbon traps of platform-basin flanks in the Sahel Eastern Tunisian petroleum province: Inferred optimal hydrocarbon reserves accumulations

The eastern Tunisian margin is considered an Upper Cretaceous and Eocene petroleum province. It has been affected by Mesozoic rifting and Cenozoic compression. Several oil and gas shows and accumulations have been discovered in Upper Cretaceous carbonates within structural anticlinal closures. These anticlinal highs represent inherited rift platform horsts with hiatuses, unconformities and sediment erosion. Seismic sequence stratigraphy and seismic tectonic analyses of Mesozoic and Cenozoic horizons, delineate the control of deep-rooted transtensional and transpressional Flower structure fault corridors, intruded by Upper Triassic salt. Petroleum system modelling and time events chart reconstruction of real and pseudo-wells, indicate that Cretaceous source rocks maturation and hydrocarbon generation began during Late Cretaceous with expulsion occurring from Eocene to Pliocene times. Hence, Upper Cretaceous petroleum system dynamics is intimately linked to basin geodynamics; where hydrocarbon migration pathways could follow the migration, rotation and tilting of platform and basin blocks. The volume of Lower Fahden and Bahloul source rocks expelled hydrocarbons from the basin kitchens, is much greater than that found in the drilled anticlinal axis. These hydrocarbons could have been trapped along the platform-basin border flanks and may not have reached the highest position on the anticlinal crest closure. Such pathways explain the unaccounted-for hydrocarbon volumes. These volumes could be trapped along the faults seal branches, unconformities, pinchouts as well as in the evidenced progradational and reefal system tracts sequences in the flank borders of the platforms. These traps could represent new exploration targets as potential structural and stratigraphic plays.

Integrated fluid inclusion studies and source rock parameters in constraining hydrocarbon potential in offshore Lamu Basin, Kenya

Fluid inclusion signal strength and visual inclusion abundance are generally lower along migration pathways than in charged reservoirs from the same area. A zone that displays strong fluid inclusion stratigraphy (FIS) hydrocarbon indications and high visualized petroleum inclusion abundance, indicates paleo-charge or in some cases a migration pathway, e.g, where inclusion abundance is enhanced by extensive microfracturing. In this study, fluid inclusion data are interpreted in seven offshore wells of the Lamu Basin to enhance the understanding of hydrocarbon generation, migration and migration pathways. The study also examines the interrelationship among rock texture, rock composition and trapped fluid distribution in the study area. The studies were based on FIS analyzed data courtesy of Fluid Inclusion Technologies (FIT) Inc. in USA laboratories. FIT conducted analysis on 391 samples from the Paleocene to Upper Jurassic (Kiboko-1 well), 249 from the Paleoecene to Campanian (Kubwa-1 well), 106 from the Maastrichtian to Turonian (Mbawa-1 well), 59 from the Eocene to Campanian (Pomboo-1 well), 26 form the Lower Eocene to Maastrichtian (Simba-1 well), 16 from the Eocene to Maastrichtian (Kipini-1 well) and 11 from the Maastrichtian to Campanian (Kofia-1 well). It also made analysis on sidewall core sample plates, with 44 from the Maastrichtian to Campanian (Kubwa-1 well), 108 from the Campanian to Upper Jurassic (Kiboko-1 well) and 8 from the Campanian (Pomboo-1 well) for petrographic evaluation. For photomicroscopy, thin sections were examined under a petrographic microscope using Ultra Violet (UV) fluorescence and microthermometry, in order to verify the presence of petroleum bearing inclusions in the rock samples and to explore textural relationships that may yield additional information on the timing of hydrocarbon migration or generation. Gas shows in Mbawa-1 well is a result of generated hydrocarbons from the carbonate interbeds in the Upper Cretaceous. Gas shows are pockets trapped in the thin carbonate rich beds. There is low abundance of upper-low, moderate and upper-moderate gravity liquid petroleum inclusions in Kubwa-1 well (central deep offshore). The low abundance suggests migration events rather than paleo-accumulations, possibly involving several discrete charges. Despite sufficient vitrinite reflectance and total organic carbon (TOC) content, the temperatures are still insufficient for hydrocarbon generation in the southern deep offshore in the region where Kiboko-1 well is located. There is no sufficient evidence for access to mature source rocks in the deep offshore basin.

Geochemistry of dolerite intrusions of the southeastern Main Karoo Basin, South Africa: Magma evolution, evidence for thermogenic gas sequestration, and potential implications for the early Toarcian Oceanic Anoxic Event

The igneous intrusions of the Karoo Large Igneous Province (LIP) provide critical information on the magma plumbing system, which served as source rock maturation agent for organic-rich sedimentary rocks of the Main Karoo Basin as well as pathway and barrier to subsurface fluid flow. Here, we present results from the research borehole KWV-01 drilled in the Eastern Cape Province of South Africa. The intersected succession, spanning the Dwyka to the lower Beaufort Group, provides representative samples of the Karoo LIP magma plumbing system.Using whole-rock and Sr-Nd isotope analyses, our data suggest that primary melts were derived from a sub-lithospheric mantle source and acquired a subduction signature through interaction with a metasomatised lithospheric mantle. Three magma types identified within this study show a geochemical overlap with previously reported data from the Golden Valley Sill Complex, ca. 220 km to the NW of the analysed borehole. The results of MELTS and EC-RAFC modelling on the three magma types reveal that their compositional differences are related to variable degrees of fractional crystallisation and contamination by lower crustal rocks and/or the sedimentary host rocks of the Main Karoo Basin.Our results indicate that at least one of the sills acted as fractured reservoir, thereby providing evidence that igneous intrusions are important for CO2 sequestration. We quantified the implications of this process for the Karoo LIP-related Toarcian Oceanic Anoxic Event using the thermogenic gas budget produced by state-of-the-art computer simulations and tested various end-member scenarios for partial thermogenic gas sequestration. In agreement with recent studies, we show that all the flat parts of the Karoo sills acted as sequestration reservoirs. Our results have general implications for LIP volcanism in organic-rich basins, suggesting that a good first-order approximation of thermogenic gas emission is half the amount mobilised in the contact aureoles of LIP plumbing systems.

Organic matter composition and thermal maturity evaluation of Mesoproterozoic source rocks in the Beetaloo Sub-Basin, Australia

The Beetaloo Sub-basin in northern Australia comprises extensively developed marine, organic-rich shales within the Mesoproterozoic Velkerri and Kyalla formations. Oil and gas derived from the thermal maturation of primitive organic matter in these shales represent some of the oldest and best-preserved hydrocarbon accumulations identified worldwide. The organic matter is derived largely from prokaryotes with petrographic evidence indicating these primarily occur as filamentous strands or lamellae typical of cyanobacteria (blue-green algae) and commonly referred to as ‘alginite’. The shales also contain bitumen generated through thermal maturation of the primary organic matter, as well as pyrobitumen remaining as a residue after secondary cracking of heavy hydrocarbons to gas. At present, no well-defined method exists to accurately assess thermal maturity nor define their hydrocarbon generation windows in source rocks of this age. Our organic petrographic and geochemical analyses indicate alginite reflectance (Ra) increases with thermal maturity showing consistent relationships with depth, atomic H/C of kerogen and aromatic molecular ratios of extractable organic matter in the shales. Among the aromatic parameters tested, vitrinite reflectance calculated from methylphenanthrene index (MPI-1 Rc) shows the strongest correlation with Ra (Rc = 0.5834Ra + 0.3842) confirming it is an effective parameter to calibrate thermal maturity models, particularly for wells where only organic petrology data are available. Molecular and isotopic composition of in situ hydrocarbons from two deep wells suggest the primary hydrocarbon generation window for Mesoproterozoic source rocks lies between Ra ∼ 0.2 % (Rc ∼ 0.5 %) and ∼ 1.5 % (Rc ∼ 1.25 %) with the dry gas threshold at Ra > 2.5 % (Rc > 1.8 %). These findings represent a refinement of the existing source rock maturity evaluation methods for the Beetaloo Sub-basin and serve as a guide for assessing other Precambrian petroleum systems worldwide.

Geochemical characteristics and genesis of natural gas in the Upper Triassic Xujiahe Formation in the Sichuan Basin

Abstract In recent years, the geochemical characteristics, genesis and sources of natural gas in the Upper Triassic Xujiahe Formation in the Sichuan Basin have received extensive attention, but their genesis and sources are still controversial. In this study, taking the natural gas from the Xujiahe Formation in the Sichuan Basin as an example, the source and genesis of the natural gas have been systematically analyzed. The results show that the natural gas of the Xujiahe Formation in the Sichuan Basin is dominated by methane, followed by a small amount of CO2 and N2; only the southern Sichuan area contains a small amount of H2S, which comes from the supply of the underlying carbonate source rocks. Except for the western Sichuan Basin, the drying coefficient of the natural gas is generally less than 0.95 (wet gas). Furthermore, the composition of the natural gas is mainly controlled by the maturity of source rocks. The carbon isotope of ethane in natural gas ranges from −33.9 to −21.5‰, and the hydrogen isotope of methane ranges from −188‰ to −151‰. The carbon and hydrogen isotope values are higher in the western Sichuan Basin than in the central, northeastern and southern Sichuan Basin. The identification of the origin of natural gas and the comparison of gas sources show that the natural gas in the Xujiahe Formation is mainly coal-derived gas from its own coal-measure source rocks; the natural gas in the northern part of the southern Sichuan Basin is oil-derived gas originating from the Changxing Formation and the Silurian marine source rocks; however, the natural gas in the northeastern Sichuan Basin is a mixture of coal-derived and oil-derived gases. In addition, the carbon and hydrogen isotopes in some natural gas samples from the Xujiahe Formation have inversions of δ13C1 &gt; δ13C2, δ13C2 &gt; δ13C3, δ13C3 &gt; δ13C4, and δD2 &gt; δD3, and the magnitude of the inversions is small. It is considered to be caused by the mixing of gases from the same source, as well as the mixing of coal-derived and oil-derived gases.

Evaluation of Hydrocarbon Generation Potential of Laiyang Formation Source Rocks in Ri-Qing-Wei Basin, Eastern Shandong

The Ri-Qing-Wei Basin is a newly discovered Late Mesozoic rift basin on the eastern Shandong coast in recent years. Thick, continuous deposited source rocks are found in the Lingshan Island scientific drilling project. Therefore, it is necessary to evaluate the distribution and hydrocarbon generation potential of source rocks in this area. Organic geochemical experiments were carried out on samples from the core of LK-1 and outcrops in the Lingshan Island, the Laoshan area, and the Jimo Zhougezhuang area to evaluate the maturity, abundance, and type of organic matter in source rocks. The results show that the cumulative thickness of the source rocks in the study area is more than 500 m, and the TOC content is generally greater than 1.0%. The organic matter type is good (mainly type II1 and type II2 kerogen) and the Ro value is more than 2.0. The thermal evolution degree of the organic matter is high with natural gas predominantly generated. We carried out Rock-Eval, PY-GC and gold tube experiments on low-maturity samples of Laikong 2 and established a chemical kinetic model to quantitatively evaluate the study area in combination with sedimentary burial history and thermal history data. The results show that the total resources of the five sags in the study area are about 476 billion cubic meters, and the average resource intensity is about 82.2 million cubic meters/km2. Among them, the resource intensities of the Lingshan Island Sag and Laoshan Sag are 112.6 million cubic meters/km2 and 98.8 million cubic meters/km2, respectively. Studied sites are “small and fertile” and may be used as favorable exploration prospect areas.

Accumulation mechanism and model of coal measure derived oil and gas in the deep reservoir of Huanghua Depression, Bohai Bay Basin, China

Hydrocarbon accumulation in coal measure strata is consist of several types which includes intra-source accumulation and adjusted accumulation, particularly in basins that had experienced multi-stage tectonic activities. The mechanism governing this accumulation is extremely complex. Using the Paleozoic petroleum system in the Huanghua Depression as an example, the mechanism of hydrocarbon accumulation in deep reservoirs can be revealed by means of core observation, geochemistry testing of coal measure source rock, thin section observation, fluid inclusions testing, and profile analysis of typical reservoirs, combined with the burial and thermal history of strata. Based on the regional tectonic, the mechanism of hydrocarbon accumulation in coal measures is defined and the accumulation model was established. The results show that the Paleozoic petroleum system in the Huanghua Depression has three different types of source-reservoir-cap assemblages: under-source, intra-source, and above-source assemblage. Regional tectonic evolution controlled the hydrocarbon generation process of source rocks, showing the hydrocarbon generation characteristics of “oil in the early stage and gas in the late stage.” The Middle Cretaceous is the first of two periods of hydrocarbon accumulation, during which stage occurred in low-maturity oil and a small amount of natural gas were mainly stored in intergranular pores and dissolution pores. The tectonic uplift in the Late Cretaceous caused the destruction of the ancient reservoir. The second accumulation stage occurred in the Middle Paleogene to the present. A large amount of natural gas and high maturity oil were mostly stored in dissolution pores and structural fractures. The hydrocarbon accumulation in Huanghua Depression was simultaneously regulated by reservoir reformation, tectonic activities, and source rock maturation. Based on the foregoing understanding, the hydrocarbon accumulation model of “oil and gas transfer station” in coal measures is put forward, that is, oil and gas are first accumulated in intra-source or near-source reservoirs, and are then adjusted from this “oil and gas transfer station” to other areas as a result of tectonic activity.

Organic geochemistry and oil-source rock correlation of the Cretaceous succession in West Wadi El-Rayan (WWER) concession: Implications for a new Cretaceous petroleum system in the north Western Desert, Egypt

Mesozoic rift basins of the north Western Desert host the majority of proven oil reserves in Egypt. These basins are bounded by poorly-explored structural highs (Kattaniya high, Qattara ridge) with unknown petroleum system. The recently-discovered oil in West Wadi El-Rayan (WWER) concession in the southern part of the Kattaniya high highlighted a need for understanding the petroleum potential of these transit regions. The present study integrates geochemical and basin modelling results to define potential source rocks and decipher the mechanism of oil generation, expulsion and migration. In WWER concession, oil is produced from the Upper Cretaceous (Upper Bahariya) sandstones. Rock-Eval pyrolysis results demonstrate that the Lower Cretaceous Alam El Bueib (AEB) and Upper Cretaceous Lower Bahariya shales below the reservoir contain mature source rocks (S2 up to 28.76, Tmax > 430 °C). WWER oil displays a uniform composition with high pristane/phytane (Pr/Ph > 3), saturates/aromatics (>5.5) and canonical variable values (CV > 6) pointing to a generation from a terrestrial source rock. This is consistent with high contents of C30 hopane, C29 steranes and diasteranes as well as the very low values of dibenzothiophane (DBT)/Phenantherane (<0.1) confirming oil generation from a clay-rich source rock deposited in a fluvio-deltaic environment.Oil-source correlation highlights a robust similarity in compositional biomarkers between the WWER oil and AEB rock extracts. Additionally, the maturity-relevant biomarkers such as Ts/Tm trisnorhopanes and H32 S/(R + S) homohopanes favor an oil expulsion phase during the early stage of oil window in accordance with the basin modelling results and the maturity level of AEB organic-rich facies. These findings shed the light on a new petroleum system in the north Western Desert where the AEB fluvio-deltaic shales are capable of generating early mature oil which migrates through the Cretaceous deep-seated extensional faults into the Bahariya sandstone reservoir.

The genesis of gas condensates and light oilsin the lower paleozoic of Tarim Basin, NW China: The exploration implications for ultra-deep petroleum

Almost 8 × 108 tons marine condensate reserveshave been estimated to be present in the Paleozoic to Cenozoic reservoirs of the Tarim Basin. Thethermal maturity of condensate gases are estimated to be greater than 2.2%REo (vitrinite reflectance equivalent),which are higher than the calculated maturity of thecondensates <1.9%REo. Therefore, the formation of gas-condensates might include a mixture of later cracked gases with earlieroil accumulations. The mixture model indicates that the relative content of oil-cracking gases varies from 42% to 98% in condensate gases, and the mixing extent of kerogen and oil cracking gas with various maturities could also lead to the carbon isotope reversal of methane and ethane. The positive correlation between the gas-oil ratio (GOR) of gas condensates and the maturity of cracking gas shows that the cracking gas is much more enriched in the eastern Tabei uplift of the northern Tarim Basin thanthe Tazhong uplift ofcentral Tarim Basin. The relative abundance of the triaromatic dinosteranes in the condensates coincides with the feature of hydrocarbons derived from Cambrian source rocks Furthermore, based on the multi-stagethermal maturity of the Cambrian source rocks, the formation mechanism of secondary gas condensates has been demonstrated and reconstructed. Recent exploration discoveries in the ultra-deep Cambrian of the Tabei and Tazhong uplifts, involving ZS-1 and LT-1wells, confirmed the cracking gases were derived from the post-high mature Manjar Depression and that liquid hydrocarbons could be maintained in the ultra-deep of Tabei uplift. The findings are helpful toestimate the exploration potential of the deeper cracking gases in the high-temperature and high-pressurereservoirs of the Tarim Basin.

Assessment of hydrocarbon generation potential and thermal maturity of the deep offshore Lamu Basin, Kenya

In this study, the secondary well data for Cretaceous to Miocene cutting samples in four deep offshore exploration wells, i.e., Pomboo-1 in the north, Kubwa-1 in the central, Simba-1 and Kiboko-1 in the south of the deep offshore Lamu Basin were assessed for identifying source rock presence and examining thermal maturity of the source rocks. The 2D basin modelling was used to analyse the bulk gas transformation in the basin. Total organic carbon (TOC) content values for the wells range from 0.09 wt % to 2.23 wt % with an average of 0.78 wt %. The average organic richness is higher in the Upper Cretaceous (0.83 wt %) than in the Palaeogene (0.65 wt %), Lower Cretaceous (0.28 wt %) and Upper Jurassic (0.30 wt %). The S1 averages for the Upper Cretaceous are 3.76 mg HC/g rock in Pomboo-1 and 0.31mg HC/g rock in Kubwa-1. The S2 averages for the Upper Cretaceous are 5.00 mg HC/g rock in Pomboo-1 and 0.72 mg HC/g rock in Kubwa-1. Hydrogen index (HI) values vary between 4 and 512 mg HC/g TOC with an average of 157.09 mg HC/g TOC. Organic matters were identified as mixed types of II-III (oil and gas prone) and III-IV (gas prone) kerogen in the potential source rocks. The HI and S2 yield values are exceptionally high for the observed TOC values in Pomboo-1. The vitrinite reflectance and Tmax values of deep offshore Lamu Basin are in the ranges of 0.38%–0.72% and 360–441 °C, respectively. It suggests the existence of both immature and mature source rocks. Vitrinite reflectance maturity favours near coastal region in the Upper Cretaceous. These results explain why Pomboo-1, Kubwa-1, Simba-1 and Kiboko-1 wells were dry. The temperatures are still cool for hydrocarbon generation in deep offshore. The critical risk for deep offshore Lamu Basin is charge, primarily source presence, and a lack of definitive evidence of a deep-water marine source rock being present. The four wells penetrate good quality reservoir and seal rocks, but source rock presence and maturity remain the critical play risk in the deep offshore Lamu Basin.

Organic geochemistry of Cambro-Ordovician succession of Ny Friesland, Svalbard, High Arctic Norway: Petroleum generation potential and bulk geochemical properties

Lower Paleozoic source rock (SR) characteristics and paleo-depositional environments are not well understood in the Barents Sea region. Organic and inorganic geochemical analyses of 17 carbonaceous samples from the Lower Cambrian Tokammane Formation, the Lower to Middle Ordovician Kirtonryggen and Valhallfonna formations in Ny Friesland, north-east Spitsbergen, show that there is a striking difference in petroleum generation potential and bulk geochemical properties between the Cambrian and Ordovician samples, and also within the Ordovician samples. TOC contents of <0.20 wt% for the Lower Cambrian Tokammane Formation samples indicate poor source rock richness. TOC contents in the range between 0.3 and 2.1 wt% and HI values between 123 and 424 mg HC/g TOC for the Valhallfonna and Kirtonryggen formation samples suggest significant variation in remaining petroleum generation potential with oil-prone (Type II) to mixed oil- and gas-prone (Type II/III) kerogen. Source rock maturity parameters such as Tmax (range 435–449 °C) and production indices for most Ordovician samples suggest relatively uniform maturity levels, ranging from the early-, to the peak-, of the oil generation window (i.e. ca. 0.70–0.85% Ro). This maturity level could have significant implication on the original petroleum potential assuming early generation from carbonate source rocks. Bulk carbon isotope data show that the Lower Cambrian Tokammane Formation samples are heavier (δ13C range from −28.4 to −28.8‰) than the Lower to Middle Ordovician Valhallfonna Formation samples (δ13C range from −29.7 to −30.9‰). The differences in the source rock richness and kerogen type within the Ordovician samples are attributed to organic facies variation. Tentatively, three categories of source rock organic facies (B, BC and C) are supported based on assumed-initial hydrogen index values for the Ordovician samples. The reliability of the indicated organic facies could be supported by addition of biomarker data from bitumen extracts. To our knowledge, this is the first study revealing the existence of a potential Lower Paleozoic source rocks in this part of the High Arctic, and this facies may also exist on the continental shelf to the north and NE.