Petroleum Migration Research Articles

Quantifying Biodegradation of Mesozoic Oil in the Eastern Chepaizi Uplift Using the Refined Manco Scale and Its Impact on Petroleum Migration

Quantifying Biodegradation of Mesozoic Oil in the Eastern Chepaizi Uplift Using the Refined Manco Scale and Its Impact on Petroleum Migration

Assessment of the Migration of Polar Compounds from Petroleum-Contaminated Soil Using a Column Leaching Experiment.

When petroleum leaks into soil, the polar compounds exhibit strong biological toxicity, causing serious damage to soil animals, plants, and microorganisms and potentially threatening human health. However, the systematic comprehension of the migration of polar compounds in petroleum-contaminated soil remains limited. Herein, we employed elemental analysis, stable carbon isotope analysis, and high-resolution mass spectrometry techniques to study the migration of polar compounds in petroleum-contaminated soil using a column leaching experiment. The results indicate that petroleum migration ability in soil is limited, and the compounds are primarily concentrated in the soil above 40 cm. The C/N, C/H, and δ13C ratios of organic matter in soils are highly affected by petroleum contamination. Meanwhile, the different compound classes show varying migration abilities, with N1 and N1O1 compounds exhibiting stronger adsorption capacity on soil, while oxygen-containing compounds are more likely to migrate with water to deeper soil. Additionally, molecular polarity, unsaturation degree, and size are key factors affecting the migration of polar compounds in petroleum within the soil. This simulation experiment offers valuable insights into comprehending migration of polar compounds in petroleum-contaminated soil and their potential impacts for soil ecological environment.

Petroleum migration and accumulation in a shale oil system of the Upper Cretaceous Qingshankou Formation in the Songliao Basin, northeastern China

Petroleum migration and accumulation in a shale oil system of the Upper Cretaceous Qingshankou Formation in the Songliao Basin, northeastern China

Distribution of magmatic intrusions and key petroleum system elements in the Pliocene–Holocene Pangani Rift Basin, Northeastern Tanzania

The sedimentary fills in the Pangani rift basin (PRB) of northeastern Tanzania have not yet been studied in detail and their petroleum potential is poorly understood. This study aims at assessing distribution of magmatic intrusions and key petroleum system elements in the PRB based on 2D seismic, remote sensing, and aeromagnetic data interpretations. Results show that evolution of the basin fill was influenced by sediment supply, magmatism, and tectonics. The PRB contains Pliocene–Holocene clastic, magmatic, and volcaniclastic deposits. The clastic sediment was sourced from the north-northeast and east-southeast of the PRB. The magmatic and volcaniclastic rocks were formed during Pleistocene–Holocene and are increasing in frequency toward the north and northeast of the basin. Tectonics and faulting created depocenters and magma conduits; magmatic intrusions and fault systems form potential petroleum traps. Seismic interpretation has shown that PRB contains potential reservoir and seal rocks for possible petroleum accumulations. Fault systems dissecting the PRB provided petroleum migration pathways from deep buried source rocks to potential reservoirs. For the first time, this study has shown that the PRB contains key petroleum system elements for petroleum accumulations to occur. Our results will be of interest to researchers working in different East African Rift basins.

Source rocks of the Birrindudu Basin: perspectives from a new sampling program

The Paleo- to Mesoproterozoic Birrindudu Basin is an underexplored frontier basin straddling the Northern Territory and Western Australia, and is a region of focus for the second phase of Geoscience Australia’s Exploring for the Future (EFTF) program (2020–2024). Hydrocarbon exploration in the Birrindudu Basin has been limited and a thorough assessment of the basin’s petroleum potential is lacking due to the absence of data in the region. To bridge this data gap, a comprehensive analytical program including organic petrology, programmed pyrolysis and oil fluid inclusion analysis was undertaken on cores from six drill holes to improve the understanding of the basin’s source rock potential and assess petroleum migration. Organic petrological analyses reveal that the primary maceral identified in the cores is alginite mainly originating from filamentous cyanobacteria, while bitumen is the most common unstructured secondary organic matter. New reflectance data based on alginite and bitumen reflectance indicate the sampled sections have reached a thermal maturity suitable for hydrocarbon generation. Oil inclusion analyses provide evidence for oil generation and migration, and hence elements of a petroleum system are present in the basin.

Benzocarbazole and methylxanthone molecular migration tracers unravel migration routes and filling history of Veslefrikk, Oseberg-East and Brage reservoirs in the Norwegian North Sea

Identification of petroleum migration routes and reservoir filling processes is feasible by applying carbazoles or xanthones as molecular migration tracers. To verify their utility, a well-constrained migration route was chosen for this study: the petroleum migration along the Veslefrikk and Oseberg East fields until reaching the Statfjord Formation compartment within the Brage field in the Norwegian North Sea. This migration route comprises an ideal test case because the oil is sourced from the same kitchen area, yielding very similar oil families in all three fields, and because the maturity remains within the main oil window, below 0.9 Ro % vitrinite reflectance equivalence.Different methodologies applied by two laboratories, from sample preparation to analytical methods, yielded identical results of migration direction and route using the benzocarbazole ratio ([a]/([a]+[c]), thus underlining practicability and robustness of this molecular migration parameter. The benzocarbazole ratio (BCR) in this study was neither affected by source rock facies, and/or biodegradation. A thermal maturity effect on BCR is considered here to be of only subordinate impact whereas it substantially affects benzocarbazole concentrations. The BCR declined from values of 0.68 at onset of migration to 0.42 at end of migration, whereby the absolute concentrations of benzocarbazoles in parallel declined by a factor of 10, from 5000 to 500 ng/g oil. The distribution and concentration of methylxanthones evolved comparable to that of benzocarbazoles. The methylxanthones ratios (MXR) from onset of migration until reaching the Brage field declined from a value of 0.85 to 0.42. The benzocarbazoles and methylxanthones, like other geo/biomarkers, preferentially reflect the first charge of the most polar and least mature oil delivered upon petroleum migration and could help to understand the reservoir filling history.Migrating oils derived from the Sogn Graben kitchen entered the Veslefrikk oil field first and continued until the structure was filled to spill point. Thereafter, migration continued to the Oseberg East oil field and after reaching spill point there it continued to the Brage field and its Statfjord formation compartment. The complex migration route represents a classical fill to spill scenario and benzocarbazole fractionation upon migration delineates the initial filling trends. The maturity values of crude oils are in the mid-oil window and show trends of covariance with the molecular migration indicators, thus proving to be supporting tracers in a classical fill to spill scenario, where maturity values are lowest when migration distances are greatest. This is due to the first expelled oil being of lowest thermal maturity entering the nearest reservoir first and then being displaced into farther reservoirs along the migration route upon arrival of later oil (more mature) charges.

Determining complex petroleum migration pathways along faults and sandbodies: a new method and application

Introduction: The reservoir-forming rule in the paleo-slope zone outside petroliferous basins’ source kitchens of the eastern basin in China is unclear, manifested in the distribution of oil and gas in complex multi-layers. This study focuses on petroleum migration along faults and sandbodies to clarify this question and improve the exploration efficiency of petroleum in areas with similar geological conditions.Method: We summarized two models of petroleum migration based on two factors: the connected sandbodies and the vertical unsealing faults. Model I is conducive to the migration of hydrocarbons within a single layer, while Model II is conducive to the vertical migration of hydrocarbons across layers. Combining the means for evaluating fault sealing and sandbody connectivity, integrating these models could form a set of characterization methods for the distribution of the complex fluid migration pathways.Results: This method is applied to characterize the complex multilayer migration pathways distribution in the first and second members of the Shahejie Formation in the central-southern area of the Wen’an Slope in the Baxian Sag, Jizhong Depression, Bohai Bay Basin, China. The results show that, in the first and second members of the Shahejie Formation in the central-southern area of the Wen’an Slope, the area for Model II is mainly distributed in the central-eastern regions. The second member has a Model I area distributed in its western region, and the first member has a Model I area distributed in its centraleastern parts. The latter distribution area is larger than the former. According to hydrocarbon migration analysis, the first member is more conducive to large regional migration and accumulation of hydrocarbons than the second member.Discussion: The predicted result of petroleum migration is consistent with the hydrocarbon distribution found in the central-southern areas of the Wen’an Slope, which is that oil and gas distribution in the first member is significantly greater than that in the second member. Thus, our method is feasible for characterizing the regional distribution of complex multi-layer migration pathways in simple tectonic setting and oil source conditions. However, further research is still needed to increase the effectiveness of present petroleum migration analysis.

Influence of thermal maturity on carbazole distributions in coal source rocks during compaction pyrolysis experiments

Carbazole compounds are widely used in determining the direction of petroleum migration, but the effect of thermal maturity on carbazoles is still ambiguity. In this paper, using compaction pyrolysis simulation experiments, artificial mature samples with vitrinite reflectance (Ro) range from 0.38 to 3.0% were acquired. And the content and composition change characteristics of carbazole compounds were analyzed in coal source rocks. The experimental results showed that thermal maturity controls the generation of a large amount of carbazole compounds in coal rocks. Compared with the low mature stage, the content of carbazole compounds was about 10–100 times higher in the mature stage. With the increasing maturity, in the coal sample, the content of carbazole compounds showed a trend of first increasing and then decreasing. In derivatives of carbazole, the corresponding maturity for the maximum generation of ethylcarbazole (EC), dimethylcarbazole (DMCA), methylcarbazole (MCA), carbazole (CA) and benzocarbazole (BCA) performed the increasing sequence. With the increasing maturity, the relative abundance of 2-MCA, 1,7-DMCA and benzo[a]carbazole increased with the increasing maturity, while 4-MCA, 1,4-DMCA and benzo[c]carbazole gradually decreased. Benzocarbazole ratio [a]/[a] +[ c] varies only in a narrow range 0.36–0.61 in the entire maturity range, suggesting limited maturity dependence. The experimental conclusion provides more theoretical basis for future geochemical analysis using carbazole compounds.

Solid bitumen as an indicator of petroleum migration, thermal maturity, and contact metamorphism: A case study in the Barrandian Basin (Silurian - Devonian), Czech Republic

Silurian and Devonian marine shales and limestones of the Barrandian Basin host abundant black solid, non-fluorescing bitumens that fill tectonic fractures and veins, and occlude fossil moulds and diagenetic concretions. Solid bitumen, interpreted as thermally degraded petroleum, entered the rocks during several successive episodes of fracture-bound petroleum migration that occurred during deeper burial of the strata. Regional distribution of bitumen reflectance values that range between ∼0.9–2.3% Rr, correlate with variations of its FT-IR and Raman spectroscopic characteristics and aromatic hydrocarbon composition, and collectively evidence the maturity trend increasing across the basin from the southwest to the northeast. The reflectance of chitinozoans and graptolites (∼0.8–1.9% Rr) in the country rocks and homogenization temperatures of hydrocarbon fluid inclusions document palaeotemperatures ranging between ∼90–150 °C, characteristic of the oil window zone grading into the gas/condensate zone. Although in a basin-wide perspective the averaged values of solid bitumen and zooclast optical reflectance converge and indicate the same northeastern-increasing regional diagenetic trend, solid bitumen reflectance values vary considerably at individual localities and even within some bitumen samples. The wide scatter of optical reflectance values and the heterogeneity of optical properties, which were attributed to the presence of multiple source rocks in the basin, the variable lithology of bitumen host rocks, or other variables, hamper the use of solid bitumen as a simple alternative to zooclast/vitrinite reflectance palaeothermometers in a given basin. On the other hand, the highly anisotropic domain and the mesophase “coking” textures of the solid bitumen that were recognized in the NE part of the basin provide unique evidence on an anomalous, hitherto unrecognized, geologically short-lasting thermal event that affected the Palaeozoic rocks. A line of indirect evidence suggests that the coking of the bitumen was caused by a cryptic intrusion, possibly a concealed branch of the Central Bohemian Pluton, which intruded into the strata during the Variscan orogeny. More rarely occurring semi-solid, vividly yellow fluorescing waxy bitumen, that postdates solid bitumen in some fractures and voids, does not reveal a regional thermal maturation trend. It precipitated from relict waxy oils that migrated through the strata during a post-Neogene uplift of the Barrandian region.

Petroleum Retention, Intraformational Migration and Segmented Accumulation within the Organic‐rich Shale in the Cretaceous Qingshankou Formation of the Gulong Sag, Songliao Basin, Northeast China

AbstractIn this study, organic geochemical and petrological analyses were conducted on 111 shale samples from a well to understand the retention, intraformational migration and segmented accumulation (shale oil enrichment in different intervals is unconnected) features of shale oil within the organic‐rich shale in the Qingshankou Formation of the Gulong Sag. Our study shows that retained petroleum characteristics in the investigated succession are mainly influenced by three factors: organic richness, intraformational migration and segmented accumulation. Organic matter richness primarily controls the amount of retained petroleum, especially the ‘live’ component indicated by the S2 value rather than the total organic carbon (TOC) figure alone. The negative expulsion efficiencies determined by mass‐balance calculations of hydrocarbons reveal that petroleum from adjacent organic‐rich intervals migrates into the interval of about 2386–2408 m, which is characterized by high free hydrocarbon (S1), OSI and saturated hydrocarbons content, along with a greater difference in δ13C values between polar compounds (including resins and asphaltenes) and saturated hydrocarbons. The depth‐dependent heterogeneity of carbon isotope ratios (δ13C) of mud methane gas, δ13C of extracts gross composition (SARA), δ13C of kerogen and SARA content of extracts suggest that the studied succession can be subdivided into four intervals. The shale oil sealing enrichment character in each interval is further corroborated by the distinct δ13C values of mud methane gas in different intervals. Due to the migration of petroleum into the 2386–2408 m interval, the S1, OSI and saturated hydrocarbons content of the interval show higher relative values. The maturity of organic matter in the 2471–2500 m interval is at the highest with the smaller size molecular components of the retained petroleum. Thus, favorable ‘sweet spots’ may be found in the 2386–2408 m interval and the 2471–2500 m interval, according to the experiment results in this study.

Basin development and petroleum prospectivity of the hybrid turbidite-contourite system in the east Pande area, offshore Tanzania

2D seismic reflection and wellbore data were used to investigate the structure and stratigraphy of the East Pande block, offshore Tanzania, allowing an assessment to be made of basin development and the occurrence of petroleum system elements. Interpretation of the 2D seismic data showed that patterns of sedimentation were controlled by the Cretaceous- Quaternary oceanic circulation (including bottom currents) together with sea level changes and the basin-ward input of detrital material from the Tanzania mainland, resulting in the development of at least five reservoir-seal combinations. The identified reservoir rocks include hybrid turbidite-contourite deposits together with channel sands and their associated levee successions which have moderate porosity and a low shale volume. Regionally, the hybrid turbidite-contourite deposits have not been studied in detail; their presence in the East Pande area may be of interest to both local and regional researchers. Potential structural traps in the study area include faults and local folds; another trapping mechanism is provided by stratigraphic pinch-outs which are characterized in seismic data by flat spots indicative of hydrocarbon accumulations. Deep-rooted faults and erosive channel bases are interpreted to have allowed petroleum migration from underlying source rocks to shallower reservoir intervals. The mapped faults in the study area have N–S to NNW-SSE trends which conform to the Permo-Triassic fault systems of the coastal Tanzania basin. This suggests that the locations and orientations of younger faults was controlled by the pre-existing structural grain linked to Karoo (Permo-Triassic) faulting. The results of this study suggest that the East Pande area offshore Tanzania may have significant petroleum prospectivity.

Maceral evolution of lacustrine shale and its effects on the development of organic pores during low mature to high mature stage: A case study from the Qingshankou Formation in northern Songliao Basin, northeast China

Organic matter (OM) hosted pores are crucial for the storage and migration of petroleum in shale reservoirs. Thermal maturity and macerals type are important factors controlling the development of pores therein. In this study, six lacustrine shale samples with different thermal maturities from the first member of the Qingshankou Formation in the Songliao Basin, of which vitrinite reflectance (Ro) ranging from 0.58% to 1.43%, were selected for a comparative analysis. Scanning electron microscopy (SEM) and reflected light microscopy were combined to investigate the development of organic pores in different macerals during thermal maturation. The results show that alginite and liptodetrinite are the dominant primary macerals, followed by bituminite. Only a few primary organic pores developed in the alginite at the lowest maturity (Ro = 0.58%). As a result of petroleum generation, oil-prone macerals began to transform to initial-oil solid bitumen at the early oil window (Ro = 0.73%) and shrinkage cracks were observed. Initial-oil solid bitumen cracked to oil, gas and post-oil bitumen by primary cracking (Ro = 0.98%). Moreover, solid bitumen (SB) was found to be the dominant OM when Ro > 0.98%, which indicates that SB is the product of oil-prone macerals transformation. Many secondary bubble pores were observed on SB, which formed by gas release, while devolatilization cracks developed on migrated SB. Additionally, at the late oil window (Ro = 1.16%), migrated SB filled the interparticle pore spaces. With further increase in temperature, the liquid oil underwent secondary cracking into pyrobitumen and gas, and spongy pores developed on the pyrobitumen at higher levels of maturity (Ro = 1.43%), which formed when pyrobitumen cracked into gas. Vitrinite and inertinite are stable without any visible pores over the range of maturities, verifying their low petroleum generation potential. In addition, it was concluded that clay minerals could have a catalytic effect on the petroleum generation, which may explain why organic-clay mixtures had more abundant pores than single OM particles. However, after Ro > 0.98%, authigenic minerals occupied the organic pore spaces on the organic-clay mixtures, resulting in fewer pores compared to those observed in samples at the early to peak oil window.

Petroleum system modeling in complex tectonic setting; a study case of the Huallaga-Marañon retroforeland basin system, Peru

The present study explores the oil and gas potential of the Huallaga–Marañon Andean retroforeland basins in Perú, considering a regional transect which extends from the Eastern Cordillera in the west trough the Huallaga fold-and-thrust belt at the Andean deformation front to the Marañon Basin in the east. The sequential restoration of main tectonic events was derived from previous stratigraphic and structural interpretations revisited with reprocessed seismic lines, and new geochemical, petrographical, geochronological and thermochronological data. The resulting framework was tested in a 2-D Basin and Petroleum System Modeling (BPSM) to check the relationship between burial history, thermal maturity evolution and timing of hydrocarbon generation, expulsion and trapping at regional scale. BPSM suggests that during the Late Cretaceous (ca. 80 Ma) the petroleum generated in the Upper Triassic–Lower Jurassic source rock known as the Aramachay Formation migrated through the Middle–Upper Jurassic Sarayaquillo Formation basal sandstones up to 250 km and accumulated in the southeast of the Marañon Basin. From the Late Miocene, the reactivation of vertical faults favored the migration and accumulation of petroleum in Cretaceous siliciclastic reservoirs which is consistent with the hydrocarbon fields existence in this sector of the basin.In addition, results of modeling show that in the southwest of the Marañon Basin the development of structures during Late Miocene times postdated the generation and expulsion of hydrocarbons calculated for the Aramachay Formation which introduces a risk of synchronization between oil migration and charge. However, part of the generated hydrocarbons during the Late Cretaceous and Cenozoic are partially preserved in Jurassic reservoirs due to the high seal capacity of mudstones of the Sarayaquillo Formation. Such hydrocarbon fluids are redistributed and migrated into structural traps during Miocene times. In addition, the Miocene gas generation and expulsion also will reduce the risk of synchronization with the development of structures. In the Eastern Cordillera, organic-rich levels of the Aramachay Formation are in the late immature to early oil window show the occurrence of organic pores adding hydrocarbon storage capacity, suggesting this unit to be considered as a potential unconventional target in future exploration activities.

Polycyclic aromatic sulfur heterocycles used as molecular markers in crude oils and source rocks

Polycyclic aromatic sulfur heterocycles (PASHs), such as benzothiophenes (BTs), dibenzothiophenes (DBTs), and benzonaphthothiophenes (BNTs), are found in crude oil and source rocks and have been extensively studied in the last decades. PASHs play a significant role in organic geochemistry as molecular markers (S-markers) because they are common in a variety of both oils and source rocks and mainly due to their thermal stability. Furthermore, relative to other hydrocarbon groups such as alkanes and many aromatic compounds, S-markers are highly stable and degradation-resistant. Thus, S-markers have been studied to obtain important information about thermal evolution, depositional environment, maturity as well as about petroleum migration and biodegradation. DBT-related markers, such as 4-MDBT/1-MDBT, 4,6-DMDBT/1,4-DMDBT, and benzonaphtho[2,1-d]thiophene/benzonaphtho[1,2-d]thiophene ([2,1]BNT/[1,2]BNT) are good maturity indicators, particularly for high to over-mature oil. The application of these S-markers overcomes the limitation of hopane and sterane maturity indicators which are restricted to a relatively low maturation range. S-markers are also related to the type of source rock where oils derived from siliceous rocks are rich in BT, DBT, DMDBT, and TMDBT and their relative concentrations are lower than those in carbonate-sourced oils. Individual DBTs are used to indicate susceptibility to biodegradation in the following order: DBT > 4-MDBT > 2-+3-MDBT > 1-MDBT. In this study, PASHs used as S-markers individually or through diagnostic ratios in crude oils and source rocks were reviewed. Different analytical techniques (including classical and innovative approaches) used to quantify and characterize S-markers, are discussed. According to our knowledge, this article is the first overview of PASHs employed as geochemical markers and provides an overview of the different alternatives for sample preparation, instrumental analysis, identification, and quantification of these compounds.

A comparison of hydrothermal events and petroleum migration between Ediacaran and lower Cambrian carbonates, Central Sichuan Basin

Hydrothermal minerals and associated organic matter have been frequently found in the Ediacaran and lower Cambrian carbonate reservoirs, separated by internal shale source rocks, in the Central Sichuan Basin. This work provides a thorough comparison of petrography, geochemical signatures, fluid inclusions and ages between the hydrothermal minerals in the Ediacaran Dengying Formation (Fm) and the lower Cambrian Longwangmiao Formation. This comparison leads to a better understanding of the behaviour and migration history of hydrothermal fluids and petroleum. During the Ediacaran–Cambrian transition, the flux of silicon-rich hydrothermal fluid triggered by seafloor-related volcanic events, resulted in the exclusive occurrence of silicification in the Dengying Fm. During P3–T3, two different hydrothermal systems were found in the Dengying and Longwangmiao formations. The hydrothermal fluids in the Dengying reservoirs were dominated by a mixture of basement-derived Mississippi Valley Type [MVT] ore fluids and shale-derived oil-bearing brines, while those in the Longwangmiao Fm were mainly the oil-bearing brines. The upwards migration of the MVT ore fluids, characterized by very hot, saline, radioactive and Eu-rich conditions, was promoted by the activity of the Emeishan mantle plume 259.4–248 Ma and then blocked by the lower Cambrian shales and trapped only within the underlying Dengying reservoirs. The expulsion of the warm, less saline and moderately radioactive brines and oil was induced by thermal maturation of the organic-rich shales, which might have occurred over a longer duration (261–218.7 Ma). During 170.7–125.8 Ma (J2–K2), the combined effects of the overmature source rocks and Yanshanian tectonic compression facilitated the migration of much hotter shale-derived brines, as well as gas hydrocarbons, across the Ediacaran to lower Cambrian carbonate reservoirs. This comparative study provides some insights into the behaviour of hydrothermal fluids and petroleum in carbonates with internal organic-rich shales.

Research on type I kerogen molecular simulation and docking between kerogen and saturated hydrocarbon molecule during oil generation

The interaction between kerogen and hydrocarbons is of great importance in the study of petroleum migration and reservoirs. In this study, type I kerogen was collected from Xinjiang Province, China and laboratory thermal maturation was used to investigate changes in the chemical structure of kerogen during hydrocarbon generation. A series of 2D and 3D kerogen molecular models were established with an increase in maturity, and the Gibbs free energy was calculated for the interacting kerogen and the selected free hydrocarbons. Based on the changes in kerogen structure, we found that during condensation reactions, protonated and branched aromatic carbon is continuously transformed into bridgehead aromatic carbon. fH a’, fB a’, fS a’ and fO a’ were proposed to evaluate this phenomenon. In addition, molecular docking was successfully applied to petroleum geochemistry. The results of the molecular docking indicated that both molecular size and relative proportion of methyl groups could affect the binding energy between geological organic matters. Therefore, kerogen might adsorb higher masses of n-C15 to n-C20 and isomers with more methyl groups. This study introduces the method of molecular docking into the research of oil and gas geological and it provides a new way for the selective adsorption phenomenon of solid–liquid organic matter interaction. And this research has important implications for method on oil migration and geochemical molecular simulation techniques.

Geochemical distortion on shale oil maturity caused by oil migration: Insights from the non-hydrocarbons revealed by FT-ICR MS

Oil migration may influence the reliability of molecular maturity parameters. Sample extracts from a shaly sequence subjected to intrasource migration, were characterized using FT-ICR MS and GC–MS techniques. The hydrocarbon maturity parameters including sterane isomer ratios and methylphenanthrene indices (MPI) are relatively higher in siltstones than in shales. In contrast, the non-hydrocarbons indicate a lower maturity in siltstones as revealed by the smaller size of molecular cores, the larger length of alkyl side chains, and the more enrichment of Ox species. It is concluded that this discrepancy is attributable to petroleum migration. The thermal-stable isomers of hydrocarbons, used as numerators in the ratios, have stronger mobility consequently leading to a faster migration into siltstones. In contrast, the molecules of non-hydrocarbons with low aromatization and molecular size, and higher alkylation degrees, easily migrate into the siltstones due to relatively lower polarity, precipitability, and absorptivity. Additionally, the hydrophilic matrix surface and high porosity of the strata also facilitate the accumulation of non-hydrocarbons in the siltstones during the early diagenesis. Such findings contribute to a better understanding of oil molecular migration behavior, and suggest a caution for using geochemical indices as maturity parameters when involving petroleum migration.

Geochemical Characteristics of the Chang 7 Source Rocks of the Triassic Yanchang Formation in Ordos Basin, China: Implications for Organic Matter Accumulation and Shale Oil Potential

The Chang 7 member of the Upper Triassic Yanchang Formation in the Ordos Basin is considered to hold the main source rocks for conventional and unconventional oil and gas. The lamination or lithology alteration in vertical and lateral directions, even over a short distance, is a common feature in lacustrine source rocks. The differences in the geochemical characteristics of black shales, dark mudstones and interbedded sandstones have been scarcely reported, and their influences on the petroleum generation potential and shale oil potential are not clear. To this end, 22 core samples were collected from the Lower and Middle Chang 7 (C7-3 and C7-2) members of the Triassic from well CYX in the Qingcheng area. By conducting a series of geochemical analyses including TOC, Rock-Eval pyrolysis yields, bitumen extraction and quantification, and the separation and quantification of saturates, aromatics, resins and asphaltenes, along with biomarker analyses, several results were found. Firstly, the C7-3 and C7-2 source rocks are thermally mature and have entered into the stage of hydrocarbon generation. The C7-3 and C7-2 source rocks have a good to very good hydrocarbon generation potential especially the C7-3 black shales. Secondly, terrigenous source input is more abundant in C7-2, whereas the source input of phytoplankton, algae or microbial lipids is more abundant in C7-3. Moreover, a high TOC content basically corresponds to low wax indexes, terrigenous/aquatic ratios (TARs), and Pr/nC17 and Ph/nC18 ratios and high C27/C29 regular sterane ratios, which suggests that the source input of phytoplankton, algae or microbial lipids is favorable for OM accumulation. Third, analyses of the molecular composition of saturated fractions in shales and interbedded sandstones and the production index demonstrate the migration of petroleum from organic-rich source rocks to their organic-lean counterparts. The C7-2 dark mudstones could be considered as a potential “sweet spot” since their oil saturation index (OSI) was the highest among all the studied samples and they are more enriched in light aliphatic fractions.

Controls on Timing of Hydrothermal Fluid Flow in South-Central Kansas, North-Central Oklahoma, and the Tri-State Mineral District

Paleozoic sedimentary rocks in the southern midcontinent of the United States have been affected by multiple events of deformation and fluid flow, resulting in petroleum migration, thermal alteration, Mississippi Valley-type mineralization, and a complex diagenetic history. This record is a hidden history of how cratonal settings respond to tectonic and non-tectonic drivers. The aim of this contribution is to better understand the controls on fluid migration in Paleozoic strata to evaluate whether hydrothermal activity is forced by tectonic or non-tectonic processes. This paper summarizes and vets the distribution of published dates related to thermal events in the southern midcontinent. In addition, we present new U-Pb dates obtained by laser ablation–inductively coupled plasma–mass spectrometry (LA-ICP-MS) on calcite cements that were formed from hydrothermal fluids. These are from three samples from the Berexco Wellington KGS 1-32 core in Sumner County, Kansas; an ore sample from the Tri-State Mineral District, Neck City, Missouri; and a core sample from the Blackbird 4-33 well in Osage County, Oklahoma. Previous studies of these calcite samples provided evidence for hydrothermal fluid flow, with one of the Wellington samples possibly recording vertical hydrothermal fluid flow out of the basement. The sample from the Tri-State Mineral District (Missouri) yields a mid-Cretaceous age of 115.6±3.1 Ma. This age falls into the timing of the Sevier Orogeny along the west coast and the development of its foreland basin in the midcontinent. Calcites from the Mississippian interval in the Wellington KGS 1-32 core yield dates of 305±10.5 Ma and 305.1±9.1 Ma. Calcite in Mississippian strata from the Blackbird 4-33 core yields a date of 308.6±2.5 Ma. These dates from Mississippian calcite cements indicate hydrothermal fluid flow in the Late Pennsylvanian that coincides with the timing of the Marathon-Ouachita Orogeny or the Ancestral Rocky Mountains Orogeny. A calcite sample from the Ordovician Arbuckle Group from the Berexco Wellington KGS 1-32 core yielded an age of 5.6±1.6 Ma, coinciding with a time after high elevation uplift of the Rocky Mountains was already far advanced. We propose that this hydrothermal fluid flow may have been associated with increased meteoric recharge and increased regional fluid pressure in a basement aquifer that activated local seismic events far into the continental interior. The distribution of ages of hydrothermal fluid flow confirms a syntectonic driver during the Ouachita Orogeny and Ancestral Rocky Mountains Orogeny deformation. Continuation of hydrothermal fluid flow well into the Permian and tailing off early in the Triassic indicates a post-tectonic driver, where uplifted areas continued to provide the recharge from gravity-driven fluid flow, until the mountains were mostly beveled by the early part of the Triassic. A dearth of Triassic and Jurassic hydrothermal events suggests Gulf of Mexico rifting and extension were less important. Rejuvenation of hydrothermal fluid flow in the Cretaceous and continuing into the Paleogene indicates that elevation and regional flexure from both the Sevier and Laramide events continued to drive hydrothermal fluid flow far from the main sites of mountainous uplift and deformation. Finally, hydrothermal fluid flow associated with more recent uplift of the Rocky Mountains may have been activated by recharge events that pressurized a regional basement aquifer and triggered seismic activity.

The Fault Effects on the Oil Migration in the Ultra-Deep Fuman Oilfield of the Tarim Basin, NW China

A giant, ultra-deep (>7000 m) strike-slip fault-related oilfield has been found in the central depression of the Tarim Basin. However, little research has addressed this discovery to understand the fault effects on the oil migration, which constrains the oil exploitation deployment and well optimization. Based on fault modeling and fluid analysis, we present the effects of fault segment on the oil segmentation and migration in the ultra-deep Fuman Oilfield. The results show a distinct fault segmentation and also subsequent variable fault architecture and non-connected fracture network other than a through-going fault zone. There are fault segment-related isolated fractured reservoirs and fluid variation along the fault strike, which indicates that a large oilfield comprises a series of unconnected small oil reservoirs along the fault segments. The fluid segmentation and molecular indicator of dibenzothiophenes reveal that there is a variable petroleum lateral migration along the strike-slip fault segment. The fault segmentation is a major contribution in the varied oil accumulation along the strike-slip fault zone in Fuman Oilfield. This case study suggests that fault segmentation has variable effects on petroleum migration and accumulation along the strike-slip zone.