Next Article in Journal
Investigation and Kinetic Analysis of Rare Earth Elements Leaching: Case Study of the Weathering Crust of the Kundybay Deposit (Northern Kazakhstan)
Previous Article in Journal
Advancements in Anode Slime Treatment: Effects of pH, Temperature, and Concentration of ClO−/OH− on Selenium Dissolution from Decopperized Anode Slimes
 
 
Search for Articles:
Title / Keyword
Author / Affiliation / Email
Journal
Article Type
 
 
Advanced Search
 
Section
Special Issue
Volume
Issue
Number
Page
 
Journals
Minerals
Volume 15
Issue 5
10.3390/min15050443
minerals-logo
Submit to this Journal Review for this Journal Propose a Special Issue
► Article Menu

Article Menu

share Share announcement Help format_quote Cite question_answer Discuss in SciProfiles
first_page
settings
Order Article Reprints
Font Type:
Arial Georgia Verdana
Font Size:
Aa Aa Aa
Line Spacing:
Column Width:
Background:
Article

Bitumen Characteristics, Genesis, and Hydrocarbon Significance in Paleozoic Reservoirs: A Case Study in the Kongxi Slope Zone, Dagang Oilfield, Huanghua Depression

by
Da Lou
1,2,*,
Yingchang Cao
1 and
Xueyu Han
1
1
School of Geoscience, China University of Petroleum (East China), Qingdao 266580, China
2
Research Institute of Exploration and Development, PetroChina Dagang Oilfield Company, Tianjin 300450, China
*
Author to whom correspondence should be addressed.
Minerals 2025, 15(5), 443; https://doi.org/10.3390/min15050443
Submission received: 11 November 2024 / Revised: 9 April 2025 / Accepted: 11 April 2025 / Published: 25 April 2025
(This article belongs to the Special Issue Organic Petrology and Geochemistry: Exploring the Organic-Rich Facies)
Browse Figures
Versions Notes

Abstract

The Paleozoic strata in the Kongxi slope zone of the Dagang oilfield, Huanghua depression, exhibit significant hydrocarbon exploration potential. Although bitumen is widely present in the Paleozoic reservoirs, its formation process and genetic mechanism remain poorly understood. This study systematically investigates the occurrence, maturity, origin, and evolutionary processes of Paleozoic reservoir bitumen in the Kongxi zone through core observations, microscopic analyses, geochemical testing, and thermal simulation experiments. The results reveal that reservoir bitumen in the Kongxi slope zone is characteristically black with medium to medium-high maturity. In core samples, bitumen occurs as bands, veins, lines, and dispersions within partially filled fractures and breccia pores. Petrographic analysis shows bitumen partially occupying intergranular pores and intergranular pores of Lower Paleozoic carbonate rocks and Upper Paleozoic sandstones, either as complete or partial pore fills. Additional bitumen occurrences include strip-like deposits along microfractures and as bitumen inclusions. Dark brown bitumen fractions were also identified in crude oil separates. The formation and evolution of Paleozoic reservoir bitumen in the Kongxi slope zone occurred in two main stages. The first-stage bitumen originated from Ordovician marine hydrocarbon source rocks, subsequently undergoing oxidative water washing and biodegradation during tectonic uplift stage. This bitumen retains compositional affinity with crude oils from Lower Paleozoic carbonate rocks. Second-stage bitumen formed through the thermal evolution of Carboniferous crude oil during deeper burial, showing compositional similarities with Carboniferous source rocks and their oil. This two-stage bitumen evolution indicates charging events in the Paleozoic reservoirs. While early uplift and exposure destroyed some paleo-reservoirs, unexposed areas within the Dagang oilfield may still contain preserved primary accumulations. Furthermore, second-stage hydrocarbon, dominated condensates derived from Carboniferous coal-bearing sequences since the Eocene, experienced limited thermal evolution to form some bitumen. These condensate accumulations remain the primary exploration target in the Paleozoic Formations.

1. Introduction

The Huanghua depression, located in the hinterland of the Bohai Bay Basin in eastern China, is a Cenozoic fault basin developed on the basis of a Paleozoic–Mesozoic residual basin [1]. Basement fracture-fold deformation and multi-rotation evolution in the region during the Mesozoic and Cenozoic periods established crucial conditions for buried hill formation. Recent exploration has revealed ten large and medium-sized oil and gas reservoirs in the Paleozoic formations of the Huanghua depression, notably in the Wumaying, Chenghai, and Kongxi areas. However, the complex geological conditions and multi-stage tectonic evolution have obscured the mechanisms of the formation, evolution, and preservation of hydrocarbons reservoirs, hampering the effective selection of exploration targets within the Paleozoic formations.
Reservoir bitumen is an important indicator of hydrocarbon formation and the modification process [2,3,4], offering insights into ancient hydrocarbon reservoirs [5,6,7,8]. In subsurface hydrocarbon reservoirs, the genesis of reservoir bitumen involves complex processes [9,10,11], including the mixing of crude oils with different properties, gas invasion, biodegradation, and thermal alteration [12,13,14]. While challenging to study, reservoir bitumen remains a focal point in petroleum geochemistry research [15]. The diverse bitumen types present in Paleozoic cores from the Huanghua depression preserve valuable geological information for hydrocarbon reservoir evolution [16,17,18,19,20]. Understanding the genetic mechanisms of these reservoir bitumen deposits is, therefore, crucial for the exploration of Paleozoic reservoirs in the Huanghua depression.
The Kongxi slope zone, a structural unit within the Huanghua depression, has yielded industrial oil flows from Ordovician and Carboniferous source rocks in wells Konggu 3, Konggu 4, and Konggu 7. Significant reservoir bitumen occurrences have also been identified in the Paleozoic rocks. This study investigates the bitumen characteristics in the Paleozoic reservoirs through comprehensive testing. By analyzing geochemical indicators of bitumen sources and thermal experiment results, we reveal the processes of bitumen formation and evolution, establish a development model, and clarify the geological significance of reservoir bitumen. These findings provide scientific support for hydrocarbon exploration in the Paleozoic formations of the Huanghua depression.

2. Geological Background

The Kongxi slope zone (KXZ), located in the central part of the Huanghua depression between the Qikou sag and the Cangdong sag, encompasses an exploration area of about 600 km2. The KXZ forms a northeast-trending wedge-like fault block bounded by two retrograde faults [21] (Figure 1). The stratigraphic sequence includes Lower Paleozoic (Cambrian and Ordovician), Upper Paleozoic (Carboniferous and Permian), Mesozoic (Triassic, Jurassic, and Cretaceous), Cenozoic (Paleogene and Neogene), and Quaternary formations. Prior to the Middle Triassic period, the KSZ and broader Huanghua depression experienced uniform uplift and burial processes without significant rupture, folding, or magmatic activities. Since the Late Triassic period, with the combined influence of left-lateral translation along the Tantanlu fault and the Qinling orogenic belt, the Kongxi reverse fault was formed and underwent a progression from its development to the gradual decay of its retrograde effects. Since the Late Jurassic period, large-scale uplift and extensional have actions occurred, leading to the develop of normal faults, including the Cangdong fault. The Cenozoic tectonic evolution occurred in two distinct stages: an early Tertiary rifting stage characterized by horizontal extension, volcanic activity, and rapid basin subsidence and deposition; and a Late Tertiary and Quaternary depression stage marked by uniform and slow subsidence [22,23].
The lower Paleozoic Ordovician formation in the Kongxi slope zone is dominated by carbonate rocks containing marine source rocks. These source rocks exhibit an average total organic carbon (TOC) content of 0.16%, predominantly type I and II-1 organic matter, with vitrinite reflectance (Ro%) values ranging from 1.2% to 1.8%. The upper Paleozoic Cretaceous formation contains coal-bearing source rocks [22,23], with TOC values of 35%–70% in coal beds and 3%-5% in dark mudstone. These rocks contain primarily type III organic matter, with subordinate type II-2, and Ro values ranging from 0.6% to 1.3%. The Paleozoic succession includes well-developed reservoir rocks: carbonate reservoirs in the Lower Paleozoic and sandstone reservoirs in the Upper Paleozoic. Together with regional seal units, these form effective source–reservoir–seal systems (Figure 2).

3. Methods

3.1. Thin Section and Fluorescence Analysis

First, thin sections with a thickness of 60 μm were prepared. After preparation, the thin sections with bitumen and liquid hydrocarbon were identified using an Axioskop 40 microscope (Carl Zeiss, Oberkochen, Germany) with a UV light. The characteristics and distribution of pyrobitumen and oil in the rocks were analyzed.

3.2. Reflectance Measurements

Bitumen polished blocks were prepared according to standard procedures [24,25]. Reflectance measurements (random, oil immersion) of selected bitumen samples were conducted using a Leica DM-4P microscope (Thorlabs, New Jersey, NJ, USA) equipped with a 50X oil immersion objective and Diskus-Fossil vitrinite reflectance system (Hilgers Technisches Buero, Königswinter, Germany) [26]. Before taking the measurements, the microscope was calibrated against an yttrium–aluminum garnet standard (0.889%) and a cubic zirconia standard (3.125%).

3.3. Thermovaporization Gas Chromatography

Thermovaporization gas chromatography (Tvap-GC) was carried out on bulk samples using the Quantum MSSV-2 Thermal Analysis System (GEOS4, Michendorf, Germany). A sample of approximately 20 mg was placed in a 30 mm long capillary glass tube, which was then sealed using a hydrogen flame to seal the ends of the glass tube with an internal diameter of 3 mm. To purge outside contaminants, the tube was inserted into a pyrolytic oven and heated in helium for 5 min at 300 °C. Finally, the products were released from the tube by hammering it after heating it in the pyrolytic oven at 300 °C for 10 min and then transferred into Agilent GC-6890A (Process Sensing Technologies, Hauppauge, NY, USA) gas chromatography system. The method has previously been described by Han et al. (2015) [27].

3.4. Fourier Transform Ion Cyclotron Resonance Mass Spectrometry (FT-ICR MS)

Mass analyses of the samples were performed in negative-ion ESI mode using a SolariX XR FT-ICR MS (Bruker Daltonik GmbH, Bremen, Germany) equipped with a 9.4 T refrigerated actively shielded superconducting magnet (Bruker Biospin, Wissembourg, France). Each sample was analyzed three times. The mass range was set to 150−800 Da. The ion accumulation time was 0.6 s. A total of 40 continuous 4 M data FT-ICR transients were added to enhance the signal-to-noise ratio and the dynamic range, as described by Jiang et al. (2019) [20].

3.5. Micro-Raman Spectroscopy

To obtain Raman signals corresponding with the D peak (A1g symmetric vibration caused by the disorder in the sp2 C network) and G peak (C = C tensile vibration in the aromatic ring plane with E2g symmetry), which may represent bitumen maturity, the bitumen in thin sections and separated from crude oils was analyzed using a Renishaw inVia Raman microscope. The Renishaw inVia Raman microscope was used to acquire the spectra using 514 nm laser excitation, a 20 Olympus objective with 0.25 numerical aperture, and a 600-groove/mm grating with a spectral resolution of about 2 cm−1; a~18 mW laser light was focused on the sample during the measurement. The accumulation time was 30 s for each step, and 3 accumulations were conducted for every spectrum. The Raman signals from 300 cm−1 to 4000 cm−1 were collected and analyzed. For spectral calibration, the instrument was calibrated daily using a silicon wafer (520.7 cm−1 peak) to ensure a wavenumber accuracy error of <0.5 cm−1. Regarding fluorescence suppression, background fluorescence interference was reduced through confocal mode (50 μm pinhole) and low laser power (18 mW). As for data processing, the raw spectra underwent baseline correction (polynomial fitting) and Savitzky–Golay smoothing (5 cm−1 window width, 2nd-order polynomial). These additions ensure full reproducibility and align with standardized Raman spectroscopy protocols.

3.6. Thermal Experiments

Thermal pyrolysis experiments in transparent silica tubes and high-temperature-high-pressure (HTHP) reactors were conducted. Distilled water, C16H34, crude oil, and crushed grains of carbonate rocks from the study area were used. C16H34 was selected, as it represents a significant component of crude oil, and using a simple individual alkane can help in our understanding of hydrocarbon evolution processes. The thermal experiments were conducted at 420 °C for five days. After the thermal experiments, the oil and minerals were analyzed to analyze the evolution of petroleum into bitumen.

3.7. SEM and EDS Analysis

Minerals were dried and fixed on aluminum stubs with conducting tape and coated with gold. The texture and secondary mineralization after reaction were examined using a Coxem-30plus SEM (Media System Lab, Rovereto, Italy). An EDS system (XFlasher Detector 430-M (Bruker Daltonik GmbH, Bremen, Germany), which allows for analysis at a spot of about 1 μm in diameter, was used to test the elemental composition of the minerals, with an error of 0.1%.

4. Results

4.1. Occurrent States of Reservoir Bitumen

The reservoir bitumen comprised black solid bitumen, graphitic plating, and particles derived from crude oil through diagenetic maturation and metamorphism, typically occurring in crystalline cavities or intergranular pores. Analysis of core samples and oil samples obtained from the Paleozoic (Ordovician and Carboniferous–Permian) formations in the Kongxi slope zone revealed widespread reservoir bitumen occurrence in the Paleozoic carbonate reservoirs, with partial development also in the Carboniferous–Permian sandstone reservoirs. Overall, reservoir bitumen is mainly concentrated in wells Konggu 3, Konggu 4, Konggu 7, and Konggu 8, located near hydrocarbon accumulations, or appears in the lower part of the Kongxi slope zone. In addition, reservoir bitumen is also present in the cores and thin sections of water well Konggu 6, located in the upper part of the slope zone.
Core observations show widespread residual black bitumen in partially filled fractures and breccia pores, occurring as bands, veins, linear features, and dispersed deposits (Figure 3a–d). The Ordovician carbonate cores from wells Konggu 3, Konggu 4, and Konggu 7 contain greyish-black, non-fluorescent solid bitumen in partially filled fractures, while bitumen development is also evident in Carboniferous sandstone cores from wells Konggu 4 and Konggu 8. Petrographic examination revealed black bitumen under plane-polarized light, distributed as complete to partial fills in carbonatite breccia interstitial pores, intergranular pores, and clastic intergranular pores, with band-like and dipping occurrences in microfractures (Figure 3e–h). Some of the bitumen filling pores or fractures appears black under plane-polarized light and non-fluorescent under ultraviolet light, predominantly as charred bitumen, and is sometimes accompanied by blue-white or dark yellow fluorescent crude oil distribution around the bitumen. For example, the bitumen in micro-fractures of well Konggu 3 is often associated with blue-white fluorescent light oil and minor dark yellow crude oil, while well Konggu 6 shows the opposite pattern. In addition, fluid inclusion analysis revealed blue-white and dark yellow hydrocarbon inclusions alongside black bitumen inclusions with inconspicuous fluorescence, sometimes showing concurrent bitumen and light oil generation through weak bluish-white fluorescence (Figure 3i,j). Additional dark brown bitumen fractions were observed microscopically in the crude oil separated from wells Konggu 4 and Niugu 1 × 1 (Figure 3k,l).

4.2. Maturity of Reservoir Bitumen

Marine facies typically lack vitrinite bodies for thermal maturity assessment, necessitating the used of bitumen reflectance (Rb) measurements, which can be converted to equivalent vitrinite reflectance (Ro) using the relationship Ro = 0.618Rb + 0.4 [28]. Analysis of 63 samples from the Ordovician and Carboniferous–Permian intervals of wells Konggu 7 and Konggu 8 in the Kongxi slope area yielded average Rb values of 1.22% and 0.60%, respectively, which convert into equivalent Ro values of 1.15% and 0.77% (Table 1). These data indicate medium to high thermal maturity for the Carboniferous–Ordovician bitumen in the Kongxi slope area.
Laser Raman analysis was conducted on bitumen extracted from Carboniferous–Permian crude oil of well Konggu 4 and Ordovician crude oil of Niugu 1 × 1, yielding characteristic Raman spectra (Figure 4). The spectra show two distinct peaks: a D peak at approximately 1355 cm−1 and a G peak at approximately 1590 cm−1. Both peaks are well developed and sharp, with the G peak showing greater sharpness than the D peak, indicating dominance of a high-carbon component. The moderate prominence of the D peak suggests a medium to high carbonization level of the reservoir bitumen [8]. Based on the ratio of the D-peak Raman intensity (ID) to the G-peak Raman intensity (IG), the ID/IG ratios of 0.60 and 0.61 for wells Konggu 4 and Niugu 1 × 1 correspond to calculated Ro values of 1.0% and 0.96%, respectively. The similar maturity values between the bitumen in the crude oil is and the reservoir bitumen indicate that hydrocarbons generated from both Ordovician and Carboniferous source rocks in the Kongxi slope zone reached medium to high thermal maturity.

4.3. Geochemical Parameters of Reservoir Bitumen

4.3.1. Characteristics of Hydrocarbons

The thermal desorption chromatography and mass spectrometry analyses of solid bitumen from Paleozoic carbonate and sandstone reservoirs in the Kongxi slope zone revealed distinct characteristics (Figure 5). Bitumen from Paleozoic Ordovician fractures in well Konggu 7 exhibited evidence of crude oil biodegradation while maintaining a relatively intact n-alkane sequence in thermal desorption products (Figure 5a). The products have low contents of benzene and toluene, phytocarbon and even-carbon-numbered predominance, and identical carbon isotopes of saturated hydrocarbons and aromatic hydrocarbons (δ13CVPDB) of −31.3‰. Terpene and sterane mass spectrometry of Ordovician bitumen from fractures in well Konggu 7 revealed significant tricyclic terpene detection, medium-high Ts, medium-high gamma waxes, high pregnane-rendered sterane, and C27 predominance (Figure 5b,c). In contrast, the bitumen in the Upper Paleozoic Carboniferous sandstone in well Konggu 8 was significantly different from that in the Lower Paleozoic carbonate reservoir of well Konggu 7, with carbon isotope values of −28.7‰ and −25.5‰ for saturated hydrocarbons and aromatics, respectively, and with low tricyclic terpene alkane content, a low Ts/Tm ratio, trace gamma-waxanes, and C29 dominance (Figure 5d,e).

4.3.2. Characteristics of Non-Hydrocarbons

The Fourier transform ion cyclotron resonance mass spectrometer (Solarix XR 9.0T) analysis of condensates from wells Qigu 8 and Yinggu 2 and bitumen from well Konggu 3 revealed distinctive compositional characteristics. The Ordovician reservoir bitumen from well Konggu 3 showed elevated nitrogen and sulfur compound contents (Figure 6a,b,e) and exhibited dominant fatty acid carbon peaks at C22 and C24 (Figure 6f), indicating relatively low carbon numbers. In contrast, coal-derived crude oils from wells Qigu 8 and Yinggu 2 displayed markedly higher contents of oxygenated compounds (Figure 6c–e) and showed dominant fatty acid carbon peaks at C34 and C36 (Figure 6f), reflecting a relatively high carbon number.

5. Discussion

5.1. Sources of Paleozoic Reservoir Bitumen

5.1.1. Geochemical Indicators of Crude Oil

Three distinct crude oil types, sourced from Ordovician marine and Carboniferous-Permian coal measures, are present in the Kongxi slope zone. Crude oil in well Konggu 4 shows a relative density of 0.79, a viscosity of 1.15 mPa-s at 50 °C, and contains 7.20% bitumen, 6.6% wax, and 0.03 sulfur. The medium crude oil from well Niugu 1 × 1 exhibits a relatively density of 0.89, a viscosity of 5.26 mPa-s at 50 °C, and contains 27.66% mastic bitumen, 3.53% wax, and 0.17% sulfur content. Crude oil in well Konggu 7 has a relative density of 0.94, a viscosity of 46.74 mPa-s at 50 °C, and contains 33.58% bitumen, 1.99% wax, and 0.26% sulfur.
Whole-oil gas chromatographic analysis of the three crude oils (Figure 7) revealed distinctive compositional characteristics. Crude oil from well Konggu 4 shows an n-alkane distribution from nC11 to nC35 in a single-peak pattern, with the main peak at nC16, indicating higher organisms of the oil-generating parent materials (Figure 7a). Crude oil in well Niugu 1 × 1 exhibits an n-alkane distribution ranging from nC11 to nC29, with the main peak at nC14 (Figure 7d). Crude oil in well Konggu 7 shows an n-alkane distribution ranging from nC12 to nC30, with main peaks at nC17 to nC18 and a prominent hump, suggesting significant biodegradation (Figure 7g). The pristane/phytane (Pr/Ph) ratios, which indicate the depositional environment and organic matter source [9], were 2.04 and 2.93 for wells Konggu 4 and Niugu 1 × 1, respectively, suggesting terrestrial organic matter formed in oxidizing environments. Meanwhile, well Konggu 7′s low ratio of 1.6 indicates transitional marine–terrestrial deposition with oxic–anoxic conditions. Terpene and sterane mass spectrometry analyses showed that the condensate from well Konggu 4 has low tricyclic terpene content, a low Ts/Tm ratio, trace gamma wax alkanes, and C29 dominance (Figure 7b,c). Crude oil from well Niugu 1 × 1 exhibits minor tricyclic terpene alkanes, a low Ts/Tm ratio, low gamma wax alkanes, and C27 dominance (Figure 7e,f). Heavy oil from well Konggu 7 exhibits elevated tricyclic terpene alkanes, a high Ts/Tm ratio, medium-high gamma wax alkanes, high pregnane-rearranged sterols, and C27 dominance (Figure 7h,i). Overall, the condensate from well Konggu 4 shows affinity with Upper Paleozoic coal matter, similar to the characteristics of the condensate from Yinggu 2. Heavy oil from well Konggu 7 exhibits affinity with Ordovician carbonate rocks. The intermediate geochemical indicators of the medium oil from well Niugu 1 × 1 suggest a mixed source.

5.1.2. Sources of Reservoir Bitumen

The higher content of tricyclic terpenes in Ordovician bitumen from well Konggu 7 (Figure 5b) suggests a marine bacteria or algae source rock origin with high degradation resistance. The predominance of C27 over C29 steranes (Figure 5c) further indicates lower aquatic organism source material [29]. The high Ts/Tm ratio, medium-high gamma-waxane indices, and elevated pregnane-rearranged steranes suggest a depositional environment with minimal terrestrial organic input and weak salinity reduction (Figure 5b,c). Higher nitrogen and sulfur compounds with a low-carbon-number fatty acid profile (Figure 6a,b) confirm marine hydrocarbon origins. In contrast, Carboniferous bitumen from well Konggu 8 shows carbon isotope values of −28.7‰ and −25.5‰ for saturated and aromatic hydrocarbons, respectively, indicating a coal-measure source. Low tricyclic terpene alkane content, low Ts/Tm ratios, and trace gamma wax alkanes (Figure 5d) suggest high terrestrial organic input under weakly oxidizing to reducing conditions [29]. C29 predominance over C27 indicates a higher plant source (Figure 5e), while elevated O1–2 content and high-carbon-number fatty acid confirm coal-derived origins (Figure 6d–f) [30]. These comprehensive analyses demonstrate that the Ordovician reservoir bitumen in the Kongxi slope zone has a certain affinity with Ordovician marine source rocks, while the Carboniferous bitumen exhibit affinity with coal-measure source rocks.

5.2. Reservoir Bitumen Thermal Simulation Experiments

The thermal evolution of reservoir crude oil involves the progressive transformation of high-molecular-weight liquid hydrocarbons into low-molecular-weight gaseous hydrocarbons, heavy oils, and carbonaceous bitumen. Two series of thermal simulation experiments were designed to investigate bitumen formation in carbonate reservoirs: one used ‘n-hexadecane–water–calcite’ and the other used ‘crude oil (Konggu 4 condensate, Niugu 1 × 1 medium crude oil)–carbonate rock’. The experiments revealed that initially colorless and non-fluorescent n-hexadecane developed varying fluorescence characteristic during thermal cracking progression (Figure 8). A comparison of aqueous and anhydrous conditions shows that pure n-hexadecane systems generated more polymeric liquid hydrocarbons during thermal simulation, with calcite presence increasing polymeric hydrocarbon generation and producing yellowish fluorescence. The n-hexadecane-distilled water system led to low-molecular-weight liquid hydrocarbon generation, which was further enhanced by calcite presence. Overall, calcite minerals in the anhydrous system promoted free radical cross-linking reactions, resulting in increased macromolecular hydrocarbon formation [31,32].
After a 5-day thermal simulation of ‘crude oil–carbonate rock’ at 420 °C, laser Raman testing of the post-experiment separated bitumen components revealed significantly increased maturity compared to the pre-experimental crude oil bitumen (Figure 9). SEM analysis showed extensive adsorption of residual heavy oil and solid bitumen on the surfaces of calcite mineral particles after oil-washing, with EDS analysis indicating dramatic changes in surface element composition, particularly with the carbon content increasing to 96.52%. Post-reaction analysis of crude oil from well Niugu 1 × 1 showed extensive bitumen coverage on the surface of calcite mineral particles, with EDS spectra indicating carbon content reaching 100% (Figure 10).

5.3. Evolutionary Patterns of Reservoir Bitumen

Through analysis of bitumen genesis and the Paleozoic burial, thermal, and hydrocarbon histories in the Kongxi slope zone, reservoir bitumen evolution can be divided into two main stages (Figure 11 and Figure 12). The first stage was oxidative washing and biodegradation-induced bitumen formation. During the Middle Triassic, vitrinite reflectivity in Lower Paleozoic marine and Upper Paleozoic coal source rocks in the Kongxi slope zone reached 0.5%–0.7%, initiating low-maturity hydrocarbon generation and accumulation in the Lower Paleozoic carbonatite reservoirs and the Upper Paleozoic sandstone reservoirs (Figure 12a). The Indosinian movement in the Late Triassic period caused stratigraphic retrograde uplift and suspended hydrocarbon production. Late Jurassic tectonic uplift exposed these paleo-oil reservoirs to surface conditions, and the early charged crude oil suffered washing, oxidation, and biodegradation, forming bitumen (Figure 12b) [33], as evidenced by the oil biodegradation signatures of the Ordovician fracture-filled bitumen from well Konggu 7 (Figure 7g). The second stage involved thermal alteration-induced bitumen formation. Cenozoic tectonic inversion in the Kongxi area led to rapid subsidence of the previous uplifted area, leading to thick sedimentation and triggering secondary hydrocarbon generation (Figure 12c). The current bottom temperatures of coal-measure source rocks in the western part of the Kongxi slope zone range from 130 to 190 °C, with Ro values of 1.0%-1.3%, indicating mature to highly mature conditions that generate condensates and gas, which fill the reservoirs. Deep burial temperatures, combined with carbonate mineral catalysis, promoted the thermal evolution of crude oil, generating both low-molecular-weight hydrocarbons and bitumen (Figure 12d). The relatively complete sequence of n-alkanes in the bitumen filling in the Ordovician fractures of well Konggu 7 suggest the formation of bitumen through complex geological effects following multiple charging events [15]. Overall, Paleozoic bitumen in the Kongxi slope zone is predominantly thermal metamorphic in origin, with medium to high maturity. The Ordovician bitumen is derived from the thermal alteration of marine crude oil, and the Carboniferous bitumen is derived from the Carboniferous–Permian coal system.

5.4. Geological Significances

Paleozoic reservoir bitumen in the Kongsi slope zone frequently occurs alongside yellow low-maturity medium-heavy crude oil and bluish-white light oil and oil inclusions, with geochemical characteristics showing strong affinity between the bitumen and crude oil. The fluid inclusion homogenization temperatures of brine inclusions in wells Konggu 1 (95 °C~100 °C, 110 °C~115 °C) (Figure 13a) and Konggu 6 (80 °C~85 °C, 110 °C) (Figure 13b) indicate two distinct oil charging processes in the Ordovician reservoirs. Marine source rocks likely experienced extensive hydrocarbon generation and migration during the mid-Triassic period, with Ordovician reservoir bitumen representing alteration products from later uplift exposure, severely compromising paleo-reservoirs in the exposed area. However, unexposed areas within the Dagang oilfield may still contain preserved paleo-reservoirs, representing important exploration targets. Particularly, this potential has been verified by a recent successful exploration in an Ordovician carbonate reservoir Qibei area close to the Kongxi slope zone [34]. Carboniferous–Permian hydrocarbon source rocks underwent two stages of hydrocarbon regeneration during the mid-Triassic and Cenozoic periods, with the Paleocene secondary phase predominantly generating light condensates and gas, representing the most important exploration targets in the Paleozoic formation [35].

6. Conclusions

(1)
Bitumen in the Kongxi slope zone of the Dagang oilfield occurs as bands, veins, and dispersed deposits within fractures and pores. Petrographic analysis revealed black, non-fluorescent bitumen filling pores in carbonate and clastic rocks, often associated with fluorescent crude oil. Bitumen inclusions and dark brown bitumen components are also present in crude oil separates.
(2)
Reservoir bitumen formation in the Kongxi slope zone occurred in two stages: initial oxidative washing and biodegradation during Late Jurassic uplift, followed by thermal alteration during Cenozoic deep burial. The second stage was enhanced by carbonate mineral catalysis, generating both low-molecular-weight hydrocarbons and bitumen.
(3)
This evolution indicates multiple hydrocarbon charging events. While uplift destroyed some paleo-reservoirs, unexposed areas may contain preserved paleo-hydrocarbon accumulations. Post-Paleozoic light condensates from Carboniferous coal measures, showing limited thermal alteration, represent the primary exploration target.

Author Contributions

All authors have read and agreed to the published version of the manuscript.

Funding

This research received no external funding.

Data Availability Statement

Data openly available in a public repository.

Conflicts of Interest

Author Da Lou were employed by the Research Institute of Exploration and Development, Petro China Dagang Oilfield Company. The remaining authors declare that the research was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.

References

  1. Yuan, G.; Cao, Y.; Sun, P.; Zhou, L.; Li, W.; Fu, L.; Li, H.; Lou, D.; Zhang, F. Genetic mechanisms of Permian Upper Shihezi sandstone reservoirs with multi-stage subsidence and uplift in the Huanghua Depression, Bohai Bay Basin, East China. Mar. Pet. 2021, 124, 104784. [Google Scholar] [CrossRef]
  2. Marzieh, H.K.; Omid, M.J.; Seyed, M.R.P.; Krzysztof, F.; Mohammad, R.S. Modification of thermal and rheological characteristics of bitumen by waste PET/GTR blends. Constr. Build. Mater. 2017, 134, 157–166. [Google Scholar]
  3. Huang, W.; Guo, Y.; Zheng, Y.; Ding, Q.; Sun, C.; Yu, J.; Zhu, M.; Yu, H. Chemical and rheological characteristics of rejuvenated bitumen with typical rejuvenators. Constr. Build. Mater. 2021, 273, 121525. [Google Scholar] [CrossRef]
  4. Abdul, M.M.; Muslich, H.S.; Madzlan, N.; Nur, I.M.Y.; Rizwan, A.M.; Abdulnaser, M.A.; Mujahid, A. Physicochemical, rheological and morphological properties of bitumen incorporating petroleum sludge. Constr. Build. Mater. 2021, 297, 123738. [Google Scholar]
  5. Jia, W.; Xiao, Z.; Yu, C.; Peng, P. Molecular and isotopic compositions of bitumens in Silurian tar sands from the Tarim Basin, NW China: Characterizing biodegradation and hydrocarbon charging in an old composite basin. Mar. Pet. Geol. 2010, 27, 13–25. [Google Scholar] [CrossRef]
  6. Åsa, L.L.; Viveca, W.; Björn, B. Adhesive surface characteristics of bitumen binders investigated by Atomic Force Microscopy. Fuel 2013, 113, 248–256. [Google Scholar]
  7. Paul, N.; Qi, L.; Murray, R.G. Role of water and fine solids in onset of coke formation during bitumen cracking. Fuel 2016, 166, 152–156. [Google Scholar]
  8. Jian, C.; Peng, P. A comparative study of free and bound bitumens from different maturesource rocks with Type III kerogens. Org. Geochem. 2017, 112, 1–15. [Google Scholar]
  9. Han, X.; Yu, J.; Huang, X.; Cao, Z.; Wang, R.; He, P. Preparation of reactive chain extension rejuvenators and its application in the aged SBS modified bitumen sustainable recycling. J. Clean. Prod. 2021, 314. [Google Scholar] [CrossRef]
  10. Huang, J.; He, W.; Lin, J.; Li, X.; Xu, Y.; Wang, Y.; Wang, H. Geochemical characteristics of bitumen from the Cambrian reservoir in the Ordos basin, Northern China: Insights into bitumen classification and origin. J. Asian Earth Sci. 2022, 230, 105168. [Google Scholar] [CrossRef]
  11. Kuo, J.; Tian, Y.; Jiang, J.; Yan, X.; Tian, J.; Wang, Z.; Zhang, J. The void characteristics of cement emulsified bitumen mixture under microwave heating by X-ray computed tomography. Constr. Build. Mater. 2024, 425, 136023. [Google Scholar] [CrossRef]
  12. Liu, C.; Gong, H.; Dun, C.; Wang, X.; Yang, Y.; Tong, C.; Zhang, Z. Anthraxolite Evolution and Vanadium Enrichment Mechanism in the Tanjianshan Group, Upper Ordovician in the Northern Qaidam Basin. Nat. Resour. Res. 2020, 29, 2127–2145. [Google Scholar] [CrossRef]
  13. Ma, A.L.; Zhang, S.C.; Zhang, D.J.; Lu, G.J. Ruthenium-ions-catalyzed oxidation of the asphaltenes of oils and oi-l source correlation in the Tarim Basin. Pet. Explor. Dev. 2004, 31, 54–58. [Google Scholar]
  14. Cheng, B.; Wang, T.-G.; Chen, Z.; Chang, X.; Yang, F. Biodegradation and possible source of Silurian and Carboniferous reservoir bitumens from the Halahatang sub-depression, Tarim Basin, NW China. Mar. Pet. Geol. 2016, 78, 236–246. [Google Scholar] [CrossRef]
  15. Gan, H.; Wang, H.; Shi, Y.; Ma, Q.; Liu, E.; Yan, D.; Pan, Z. Geochemical characteristics and genetic origin of crude oil in the Fushan sag, Beibuwan Basin, South China Sea. Mar. Pet. Geol. 2020, 112, 104114. [Google Scholar] [CrossRef]
  16. Fustic, M.; Bennett, B.; Adams, J.; Huang, H.; MacFarlane, B.; Leckie, D.A.; Larter, S. Bitumen and heavy oil geochemistry: A tool for distinguishing barriers from baffles in oil sands reservoirs. Bull. Can. Pet. Geol. 2011, 59, 295–316. [Google Scholar] [CrossRef]
  17. Jacob, H. Classification, structure, genesis and practical importance of natural solid oil bitumen (“migrabitumen”). Int. J. Coal Geol. 1989, 11, 65–79. [Google Scholar] [CrossRef]
  18. Lewan, M.D. Evaluation of petroleum generation by hydrous pyrolysis experimentation: Philosophical Transactions of the Royal Society of London. Ser. A Math. Phys. Sci. 1985, 315, 123–134. [Google Scholar]
  19. Stasiuk, L.D. The origin of pyrobitumens in upper Devonian Leduc formation gas reservoirs, Alberta, Canada: An optical and EDS study of oil to gas transformation. Mar. Pet. Geol. 1997, 14, 915–929. [Google Scholar] [CrossRef]
  20. Jiang, B.; Zhan, Z.-W.; Shi, Q.; Liao, Y.; Zou, Y.-R.; Tian, Y.; Peng, P. Chemometric Unmixing of Petroleum Mixtures by Negative Ion ESI FT-ICR MS Analysis. Anal. Chem. 2019, 91, 2209–2215. [Google Scholar] [CrossRef]
  21. Wang, T.G.; Wang, F.Y.; Lu, H.; Tang, Y.J. Oil source and formation period of Ordovician reservoirs in the Kongxi subduction zone of the Huanghua depression. Mar. Orig. Pet. Geol. 2000, 5, 47–54. [Google Scholar]
  22. Zhang, J.; Yang, P.X.; Pan, M.; Qi, J.F. Tectonic evolution of the Kongxi structural belt. J. Chengdu Univ. Technol. 2002, 29, 399–404. (In Chinese) [Google Scholar]
  23. Qi, J.F.; Zhang, Y.W.; Lu, K.Z.; Yang, Q. Genozoic tectonic evolution in Bohai Bay Basin Province. J. Univ. Pet. China 1995, 19, 1–6. (In Chinese) [Google Scholar]
  24. ASTM D2797/D2797M-11a; Standard Practice for Preparing Coal Samples for Microscopical Analysis by Reflected Light. ASTM International: West Conshohocken, PA, USA, 2015; 5p.
  25. ASTM D7708-23; Standard Test Method for Microscopical Determination of the Reflectance of Vitrinite Dispersed in Sedimentary Rocks. ASTM International: West Conshohocken, PA, USA, 2023.
  26. Wang, L.; Han, Y.; Lou, D.; He, Z.; Guo, X.; Steele-MacInnis, M. Hydrothermal petroleum related to intracontinental magmatism in the Bohai Bay Basin, eastern China. Mar. Pet. Geol. 2024, 167, 106982. [Google Scholar] [CrossRef]
  27. Han, Y.; Mahlstedt, N.; Horsfield, B. The Barnett Shale: Compositional fractionation associated with intraformational petroleum migration, retention, and expulsion. AAPG Bull. 2015, 99, 2173–2202. [Google Scholar] [CrossRef]
  28. Ma, Z.Y.; Zhang, L.; Zhu, X.C.; Zhu, X.X.; Huang, W. Characteristics and Genesis of Bitumen in Ordovician Reservoirsin Central Tarim Basin. Mar. Orig. Pet. Geol. 2014, 19, 19–24. (In Chinese) [Google Scholar]
  29. Yu, Y.; Sun, J.C.; Yu, Z.L.; Chen, D.R. Geochemical characteristics and oil source comparison of Paleozoic crude oil from the North Dagang Subduction Hill in the Huanghua depression. Inn. Mong. Petrochem. 2020, 46, 112–115. [Google Scholar]
  30. Ziegs, V.; Noah, M.; Poetz, S.; Horsfield, B.; Hartwig, A.; Rinna, J.; Skeie, J.E. Unravelling maturity- and migration-related carbazole and phenol distributions in Central Graben crude oils. Mar. Pet. Geol. 2018, 94, 114–130. [Google Scholar] [CrossRef]
  31. Yuan, G.-H.; Jin, Z.-H.; Cao, Y.-C.; Liu, K.-Y.; Gluyas, J.; Wang, Y.-Z.; Xi, K.-L. Evolution of nC16H34-water–mineral systems in thermal capsules and geological implications for deeply-buried hydrocarbon reservoirs. Geosci. Front. 2022, 13, 101322. [Google Scholar] [CrossRef]
  32. Yuan, G.; Cao, Y.; Jin, Z.; Schulz, H.-M.; Jin, Z.; Fang, R.; Zhao, X.; Liu, K.; Wang, J. Thermally driven organic-inorganic interactions in sedimentary basins: A review from source rocks to reservoirs. Earth-Sci. Rev. 2025, 262, 105043. [Google Scholar] [CrossRef]
  33. Hao, B.; Zhao, W.Z.; Hu, S.Y.; Shi, S.Y.; Gao, P.; Wang, T.S.; Huang, S.P.; Jiang, H. Bitumen formation of Cambrian Longwangmiao Formation in the central Sichuan and its implication for hydrocarbon accumulation. Pet. Res. 2018, 3, 44–56. [Google Scholar] [CrossRef]
  34. Yang, R.; Zhao, X.; Liu, H.; Li, H.; Zhao, C.; Pu, X. Hydrocarbon accumulation characteristics and favorable zones prediction in and under source of Paleozoic in Huanghua Depression, Bohai Bay Basin. Lithol. Reserv. 2023, 35, 110–125. [Google Scholar]
  35. Li, B.; Goldberg, K. Diagenesis and reservoir quality of Cambrian carbonates in the Tarim Basin, northwestern China. J. Asian Earth Sci. 2022, 223, 104972. [Google Scholar] [CrossRef]
Minerals 15 00443 g001
Figure 1. (a) Location and tectonic map of the Kongxi slope zone in the Dagang oilfield, Bohai Bay Basin, East China. (b) Seismic profile showing the distribution of strata in the Kongxi slope zone. The red star represents oil encountered in drilling, the yellow star represents natural gas encountered in drilling, and A–B represents the direction of the seismic profile.
Figure 1. (a) Location and tectonic map of the Kongxi slope zone in the Dagang oilfield, Bohai Bay Basin, East China. (b) Seismic profile showing the distribution of strata in the Kongxi slope zone. The red star represents oil encountered in drilling, the yellow star represents natural gas encountered in drilling, and A–B represents the direction of the seismic profile.
Minerals 15 00443 g001
Minerals 15 00443 g002
Figure 2. Typical wells with a source–reservoir–seal assemblage map of the Kongxi slope zone in the Dagang oilfield. The locations of the wells are presented in Figure 1.
Figure 2. Typical wells with a source–reservoir–seal assemblage map of the Kongxi slope zone in the Dagang oilfield. The locations of the wells are presented in Figure 1.
Minerals 15 00443 g002
Minerals 15 00443 g003
Figure 3. Characteristics of Paleozoic bitumen in core samples, thin sections, and crude oil separates in the Kongxi slope zone, Dagang oilfeild. (a) Well Konggu 3, 3402.91 m, striated bitumen; (b) well Konggu 4, 3810.74 m, dark brown bitumen in fractures; (c) well Konggu 7, 3793.38 m, dark brown bitumen infiltration; (d) well Konggu 8, 2818.10 m, sandstone bitumen (e) well Konggu 4, 3810.31 m bitumen in inter-conglomerate pore fractures (−); (f) well Konggu 8, 3010.73 m, bitumen in microfractures (−); (g) well Konggu 3, 3406.45 m, bitumen associated with bluish-white fluorescent light oil (UV); (h) well Konggu 6, 2721.18 m, bitumen associated with dark-yellow fluorescent crude oil (UV); (i) well Konggu 3, 3406.45 m, black bitumen inclusions with fluorescent inclusions (−); (j) well Konggu 3. 3406.45 m, black bitumen inclusions accompanied by fluorescent inclusions (UV); (k) bitumen in crude oil isolate from well Konggu 4; (l) bitumen in crude oil isolate from well Niugu 1 × 1.
Figure 3. Characteristics of Paleozoic bitumen in core samples, thin sections, and crude oil separates in the Kongxi slope zone, Dagang oilfeild. (a) Well Konggu 3, 3402.91 m, striated bitumen; (b) well Konggu 4, 3810.74 m, dark brown bitumen in fractures; (c) well Konggu 7, 3793.38 m, dark brown bitumen infiltration; (d) well Konggu 8, 2818.10 m, sandstone bitumen (e) well Konggu 4, 3810.31 m bitumen in inter-conglomerate pore fractures (−); (f) well Konggu 8, 3010.73 m, bitumen in microfractures (−); (g) well Konggu 3, 3406.45 m, bitumen associated with bluish-white fluorescent light oil (UV); (h) well Konggu 6, 2721.18 m, bitumen associated with dark-yellow fluorescent crude oil (UV); (i) well Konggu 3, 3406.45 m, black bitumen inclusions with fluorescent inclusions (−); (j) well Konggu 3. 3406.45 m, black bitumen inclusions accompanied by fluorescent inclusions (UV); (k) bitumen in crude oil isolate from well Konggu 4; (l) bitumen in crude oil isolate from well Niugu 1 × 1.
Minerals 15 00443 g003
Minerals 15 00443 g004
Figure 4. Laser Raman analysis of bitumen maturity in core samples and crude oil in the Kongxi slope zone. (a). Laser Raman spectrum of bitumen in crude oil from well Konggu 4 (test point is Figure 3k); (b) laser Raman spectrum of bitumen in crude oil from well Niugu 1 × 1 (test point is Figure 3l); (c) laser Raman spectrum of reservoir bitumen in well Konggu 8, 2818.1 m; (d) maturity analysis of bitumen in crude oil from wells Konggu 4 and Niugu 1 × 1.
Figure 4. Laser Raman analysis of bitumen maturity in core samples and crude oil in the Kongxi slope zone. (a). Laser Raman spectrum of bitumen in crude oil from well Konggu 4 (test point is Figure 3k); (b) laser Raman spectrum of bitumen in crude oil from well Niugu 1 × 1 (test point is Figure 3l); (c) laser Raman spectrum of reservoir bitumen in well Konggu 8, 2818.1 m; (d) maturity analysis of bitumen in crude oil from wells Konggu 4 and Niugu 1 × 1.
Minerals 15 00443 g004
Minerals 15 00443 g005
Figure 5. Characteristics of bitumen hydrocarbons in Kongxi slope zone. (a) Well Konggu 7, 3793.38 m, thermal desorption chromatography of Ordovician bitumen; (b) well Konggu 7, 3793.38 m, terpene mass spectrometry of Ordovician bitumen; (c) well Konggu 7, 3793.38 m, terpene mass spectrometry of Ordovician bitumen; (d) well Konggu 8, 2818.1 m, terpene mass spectrometry of Carboniferous bitumen; (e) well Konggu 8, 2818.1 m, sterane mass spectrometry of Carboniferous bitumen.
Figure 5. Characteristics of bitumen hydrocarbons in Kongxi slope zone. (a) Well Konggu 7, 3793.38 m, thermal desorption chromatography of Ordovician bitumen; (b) well Konggu 7, 3793.38 m, terpene mass spectrometry of Ordovician bitumen; (c) well Konggu 7, 3793.38 m, terpene mass spectrometry of Ordovician bitumen; (d) well Konggu 8, 2818.1 m, terpene mass spectrometry of Carboniferous bitumen; (e) well Konggu 8, 2818.1 m, sterane mass spectrometry of Carboniferous bitumen.
Minerals 15 00443 g005
Minerals 15 00443 g006
Figure 6. Characteristics of non-hydrocarbon compounds in bitumen from different Paleozoic reservoirs in the Kongxi slope zone. (a) Well Konggu 3, 3403.41 m, crude oil negative ion electrospray high-resolution mass spectrometry; (b) well Konggu 3, 3403.41 m, pie chart of relative abundance of heteroatoms; (c) well Yinggu 2, 3793.38 m, crude oil negative-ion electrospray high-resolution mass spectrometry; (d) well Yinggu 2, 3793.38 m, pie chart of relative abundance of heteroatoms; (e) pie chart of relative abundance of nitrogen and sulfur compounds in bitumen of the manifolds of well Manqigu 8, well Yinggu 2, and the histograms of relative abundance of nitrogen and sulfur compounds in bitumen from well Konggu 3; (f) fatty acid distribution maps of wells Yinggu 2, Konggu 3, and Manqigu 8.
Figure 6. Characteristics of non-hydrocarbon compounds in bitumen from different Paleozoic reservoirs in the Kongxi slope zone. (a) Well Konggu 3, 3403.41 m, crude oil negative ion electrospray high-resolution mass spectrometry; (b) well Konggu 3, 3403.41 m, pie chart of relative abundance of heteroatoms; (c) well Yinggu 2, 3793.38 m, crude oil negative-ion electrospray high-resolution mass spectrometry; (d) well Yinggu 2, 3793.38 m, pie chart of relative abundance of heteroatoms; (e) pie chart of relative abundance of nitrogen and sulfur compounds in bitumen of the manifolds of well Manqigu 8, well Yinggu 2, and the histograms of relative abundance of nitrogen and sulfur compounds in bitumen from well Konggu 3; (f) fatty acid distribution maps of wells Yinggu 2, Konggu 3, and Manqigu 8.
Minerals 15 00443 g006
Minerals 15 00443 g007
Figure 7. Geochemical indicators of three types of crude oil in the Kongxi slope zone. (a) Gas chromatography of saturated hydrocarbons of Carboniferous–dialytic condensate from well Konggu 4; (b) terpane mass spectrometry of Carboniferous–dialytic condensate from well Konggu 4; (c) sterane mass spectrometry of Carboniferous–dialytic condensate from well Konggu 4; (d) gas chromatography of saturated hydrocarbons of Carboniferous-dialytic intermediate oils from well Niugu 1; (e) terpane mass spectrometry of intermediate oils from well Niugu 1 gas chromatography; (e) Carboniferous–Permian medium oil terpane mass spectra of well Niugu 1; (f) Carboniferous–Permian medium oil sterane mass spectra of well Niugu 1; (g) Ordovician thick oil saturated hydrocarbons gas chromatography of well Konggu 7; (h) Ordovician thick oil terpane mass spectra of well Konggu 7; (i) Ordovician thick oil sterane mass spectra of well Konggu 1.
Figure 7. Geochemical indicators of three types of crude oil in the Kongxi slope zone. (a) Gas chromatography of saturated hydrocarbons of Carboniferous–dialytic condensate from well Konggu 4; (b) terpane mass spectrometry of Carboniferous–dialytic condensate from well Konggu 4; (c) sterane mass spectrometry of Carboniferous–dialytic condensate from well Konggu 4; (d) gas chromatography of saturated hydrocarbons of Carboniferous-dialytic intermediate oils from well Niugu 1; (e) terpane mass spectrometry of intermediate oils from well Niugu 1 gas chromatography; (e) Carboniferous–Permian medium oil terpane mass spectra of well Niugu 1; (f) Carboniferous–Permian medium oil sterane mass spectra of well Niugu 1; (g) Ordovician thick oil saturated hydrocarbons gas chromatography of well Konggu 7; (h) Ordovician thick oil terpane mass spectra of well Konggu 7; (i) Ordovician thick oil sterane mass spectra of well Konggu 1.
Minerals 15 00443 g007
Minerals 15 00443 g008
Figure 8. Fluorescence colors of the liquid hydrocarbons generated in thermal experiments with different combinations of ‘nC16H34–water–calcite’ (3–6–10 days).
Figure 8. Fluorescence colors of the liquid hydrocarbons generated in thermal experiments with different combinations of ‘nC16H34–water–calcite’ (3–6–10 days).
Minerals 15 00443 g008
Minerals 15 00443 g009
Figure 9. Gas chromatograms of crude oils, microfeatures of bitumen in crude oils, and laser Raman plots before and after the experiments. (a) Gas chromatogram of crude oil before the thermal simulation experiment of well Konggu 4; (b) bitumen microcharacteristics in crude oil before the thermal simulation experiment of well Konggu 4; (c) bitumen laser Raman map in crude oil before the thermal simulation experiment of well Konggu 4 (the test point is in Figure 9b); (d) gas chromatogram of crude oil after the thermal simulation experiment of well Konggu 4; (e) bitumen microcharacteristics in crude oil after the thermal simulation experiment of well Konggu 4; (f) laser Raman map of bitumen in crude oil after thermal simulation experiment of well Konggu 4 (test point is shown in Figure 9e).
Figure 9. Gas chromatograms of crude oils, microfeatures of bitumen in crude oils, and laser Raman plots before and after the experiments. (a) Gas chromatogram of crude oil before the thermal simulation experiment of well Konggu 4; (b) bitumen microcharacteristics in crude oil before the thermal simulation experiment of well Konggu 4; (c) bitumen laser Raman map in crude oil before the thermal simulation experiment of well Konggu 4 (the test point is in Figure 9b); (d) gas chromatogram of crude oil after the thermal simulation experiment of well Konggu 4; (e) bitumen microcharacteristics in crude oil after the thermal simulation experiment of well Konggu 4; (f) laser Raman map of bitumen in crude oil after thermal simulation experiment of well Konggu 4 (test point is shown in Figure 9e).
Minerals 15 00443 g009
Minerals 15 00443 g010
Figure 10. SEM image of calcite minerals before and after the thermal experiments with different ‘crude oil–carbonate rock’ combinations. (a) SEM image of calcite minerals before the thermal simulation experiment; (b) EDS of calcite minerals before thermal simulation experiment; (c) SEM image of calcite minerals in the crude oil after the reaction with the crude oil from well Konggu 4; (d) EDS of calcite minerals in the crude oil after the reaction with the crude oil from well Konggu 4; (e) SEM image of calcite minerals after the reaction with the crude oil from well Niugu 1 × 1; (f) EDS of calcite minerals after the reaction with the crude oil from well Niugu 1 × 1.
Figure 10. SEM image of calcite minerals before and after the thermal experiments with different ‘crude oil–carbonate rock’ combinations. (a) SEM image of calcite minerals before the thermal simulation experiment; (b) EDS of calcite minerals before thermal simulation experiment; (c) SEM image of calcite minerals in the crude oil after the reaction with the crude oil from well Konggu 4; (d) EDS of calcite minerals in the crude oil after the reaction with the crude oil from well Konggu 4; (e) SEM image of calcite minerals after the reaction with the crude oil from well Niugu 1 × 1; (f) EDS of calcite minerals after the reaction with the crude oil from well Niugu 1 × 1.
Minerals 15 00443 g010
Minerals 15 00443 g011
Figure 11. A comprehensive evolution of geological events, including burial uplift, hydrocarbon generation, oil charging, and bitumen formation in the Paleozoic formations in the Kongxi slope zone.
Figure 11. A comprehensive evolution of geological events, including burial uplift, hydrocarbon generation, oil charging, and bitumen formation in the Paleozoic formations in the Kongxi slope zone.
Minerals 15 00443 g011
Minerals 15 00443 g012
Figure 12. Model diagrams showing reservoir hydrocarbon charging and bitumen evolution process in the Kongxi slope zone, Dagang oilfield. (a) Oil charging at the late stage of the middle Triassic period; (b) bitumen formation due to washing, oxidation, and biodegradation of early charged oil during the Middle Jurassic uplift stage; (c) generation and charging of second-stage oil during the late Oligocene period; (d) second-stage bitumen formed through the thermal evolution of Carboniferous crude oil during the deeper burial stage.
Figure 12. Model diagrams showing reservoir hydrocarbon charging and bitumen evolution process in the Kongxi slope zone, Dagang oilfield. (a) Oil charging at the late stage of the middle Triassic period; (b) bitumen formation due to washing, oxidation, and biodegradation of early charged oil during the Middle Jurassic uplift stage; (c) generation and charging of second-stage oil during the late Oligocene period; (d) second-stage bitumen formed through the thermal evolution of Carboniferous crude oil during the deeper burial stage.
Minerals 15 00443 g012
Minerals 15 00443 g013
Figure 13. (a) Well Konggu 1, 3272.1 m; (b) well Konggu 6, 2720.3 m. Histograms of homogeneous temperature distributions of aqueous fluid inclusions obtained in the lower Paleozoic carbonate rocks in the Kongxi slope zone. The temperature represents two stages of oil charging processes in these reservoirs.
Figure 13. (a) Well Konggu 1, 3272.1 m; (b) well Konggu 6, 2720.3 m. Histograms of homogeneous temperature distributions of aqueous fluid inclusions obtained in the lower Paleozoic carbonate rocks in the Kongxi slope zone. The temperature represents two stages of oil charging processes in these reservoirs.
Minerals 15 00443 g013
Table 1. Measured bitumen reflectance data of Paleozoic submerged reservoirs in the Kongxi slope zone.
Table 1. Measured bitumen reflectance data of Paleozoic submerged reservoirs in the Kongxi slope zone.
Well Konggu 7 (Ordovician)Well Konggu 8 (Carboniferous–Permian)
Depth (m)Bitumen Reflectance (Rb)Number of Testing PointsDepth (m)Bitumen Reflectance (Rb)Number of Testing Points
3212.201.022102740.100.53611
3254.321.137102746.200.54810
3287.261.25172783.300.5612
3445.301.36522797.410.5732
3674.521.479120,811.500.5866
3694.211.59452813.450.5985
3716.851.708102818.100.6116
3842.321.82222928.320.6234
3942.151.937102936.200.6363
3940.242.05112936.540.6481
Disclaimer/Publisher’s Note: The statements, opinions and data contained in all publications are solely those of the individual author(s) and contributor(s) and not of MDPI and/or the editor(s). MDPI and/or the editor(s) disclaim responsibility for any injury to people or property resulting from any ideas, methods, instructions or products referred to in the content.

Share and Cite

MDPI and ACS Style

Lou, D.; Cao, Y.; Han, X. Bitumen Characteristics, Genesis, and Hydrocarbon Significance in Paleozoic Reservoirs: A Case Study in the Kongxi Slope Zone, Dagang Oilfield, Huanghua Depression. Minerals 2025, 15, 443. https://doi.org/10.3390/min15050443

AMA Style

Lou D, Cao Y, Han X. Bitumen Characteristics, Genesis, and Hydrocarbon Significance in Paleozoic Reservoirs: A Case Study in the Kongxi Slope Zone, Dagang Oilfield, Huanghua Depression. Minerals. 2025; 15(5):443. https://doi.org/10.3390/min15050443

Chicago/Turabian Style

Lou, Da, Yingchang Cao, and Xueyu Han. 2025. "Bitumen Characteristics, Genesis, and Hydrocarbon Significance in Paleozoic Reservoirs: A Case Study in the Kongxi Slope Zone, Dagang Oilfield, Huanghua Depression" Minerals 15, no. 5: 443. https://doi.org/10.3390/min15050443

APA Style

Lou, D., Cao, Y., & Han, X. (2025). Bitumen Characteristics, Genesis, and Hydrocarbon Significance in Paleozoic Reservoirs: A Case Study in the Kongxi Slope Zone, Dagang Oilfield, Huanghua Depression. Minerals, 15(5), 443. https://doi.org/10.3390/min15050443

Note that from the first issue of 2016, this journal uses article numbers instead of page numbers. See further details here.

Article Metrics

Back to TopTop