THE SIGNIFICANCE OF HYDROCARBON SHOWS AND OIL RECOVERIES IN THE LONGREACH AREA, CENTRAL QUEENSLAND

1989 ◽  
Vol 29 (1) ◽  
pp. 157
Author(s):  
C.C. Hodge ◽  
N.J. Russell ◽  
M. Smyth
Keyword(s):  
Joint Venture ◽  
Oil And Gas ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Variable Nature ◽  
Water Well ◽  
Reflectance Measurements ◽  
Cooper Basin ◽  
Commercial Oil

In 1925, over 40 gallons of oil were recovered from the Longreach town- water well. More recently, Corona 1, drilled by the ATP 271P Joint Venture in 1984, recovered 9 m (0.5 bbls) of oil in the drill pipe.These oil recoveries, along with several water- bore oil and gas occurrences, are all located in the Longreach area, Central Queensland, over 100 km north- northeast of the Cooper Basin zero edge. The oil recoveries and shows are therefore considered to be the product of source rocks other than those of the Cooper Basin.The Birkhead Formation, the unit considered most likely to source the Longreach and Corona oils, has been studied with a view to understanding the nature of hydrocarbon generation in the vicinity of the Maneroo Platform. The variables measured include (1) thickness of the shale units, (2) volume and type of dispersed organic matter (DOM) and (3) maturity (vitrinite reflectance). Measurements were taken from 10 exploration wells through the whole formation to provide uniform comparative assessment.The Birkhead Formation in the Maneroo Platform area is shown to have an anomalously low sandstone- to- shale ratio, vitrinite reflectance values (Rm(o)) consistently greater than 0.7 per cent and a favourable petroleum generative geochemistry.These results emphasise the highly variable nature of the Eromanga Basin sequence, and therefore its diverse generative potential, and highlight the encouraging prospectivity of the Maneroo Platform area despite the present lack of commercial oil discoveries.

scholarly journals Hydrocarbon generation from Carboniferous-Permian coaly source rocks in the Huanghua depression under different geological processes

2020 ◽  
Vol 17 (6) ◽  
pp. 1540-1555
Author(s):  
Jin-Jun Xu ◽  
Qiang Jin
Keyword(s):  
Oil And Gas ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Bohai Bay ◽  
Hydrocarbon Generation ◽  
Oil And Gas Exploration ◽  
Geological Processes ◽  
Light Oil ◽  
Huanghua Depression ◽  
Higher Temperature

AbstractNatural gas and condensate derived from Carboniferous-Permian (C-P) coaly source rocks discovered in the Dagang Oilfield in the Bohai Bay Basin (east China) have important implications for the potential exploration of C-P coaly source rocks. This study analyzed the secondary, tertiary, and dynamic characteristics of hydrocarbon generation in order to predict the hydrocarbon potentials of different exploration areas in the Dagang Oilfield. The results indicated that C-P oil and gas were generated from coaly source rocks by secondary or tertiary hydrocarbon generation and characterized by notably different hydrocarbon products and generation dynamics. Secondary hydrocarbon generation was completed when the maturity reached vitrinite reflectance (Ro) of 0.7%–0.9% before uplift prior to the Eocene. Tertiary hydrocarbon generation from the source rocks was limited in deep buried sags in the Oligocene, where the products consisted of light oil and gas. The activation energies for secondary and tertiary hydrocarbon generation were 260–280 kJ/mol and 300–330 kJ/mol, respectively, indicating that each instance of hydrocarbon generation required higher temperature or deeper burial than the previous instance. Locations with secondary or tertiary hydrocarbon generation from C-P coaly source rocks were interpreted as potential oil and gas exploration regions.

Hydrocarbon Generation Indication from Source Rock to Reservoir Rock: Case Studies of Anambra and Abakaliki Basins South-Eastern Nigeria

2016 ◽  
Author(s):  
Samuel Salufu ◽  
Rita Onolemhemhen ◽  
Sunday Isehunwa
Keyword(s):  
Case Studies ◽  
Source Rock ◽  
Oil And Gas ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Reservoir Rock ◽  
Hydrocarbon Generation ◽  
Geochemical Analysis ◽  
Anambra Basin ◽  
Oil Generation

ABSTRACT This paper sought to use information from outcrop sections to characterize the source and reservoir rocks in a basin in order to give indication(s) for hydrocarbon generation potential in a basin in minimizing uncertainty and risk that are allied with exploration and field development of oil and gas, using subsurface data from well logs, well sections, seismic and core. The methods of study includes detailed geological, stratigraphical, geochemical, structural,, petro-graphical, and sedimentological studies of rock units from outcrop sections within two basins; Anambra Basin and Abakaliki Basin were used as case studies. Thirty eight samples of shale were collected from these Basins; geochemical analysis (rockeval) was performed on the samples to determine the total organic content (TOC) and to assess the oil generating window. The results were analyzed using Rock wares, Origin, and Surfer software in order to properly characterize the potential source rock(s) and reservoir rock(s) in the basins, and factor(s) that can favour hydrocarbon traps. The results of the geological, stratigraphical, sedimentological, geochemical, and structural, were used to developed a new model for hydrocarbon generation in the Basins. The result of the geochemical analysis of shale samples from the Anambra Basin shows that the TOC values are ≥ 1wt%, Tmax ≥ 431°C, Vitrinite reflectance values are ≥ 0.6%, and S1+S2 values are > 2.5mg/g for Mamu Formation while shale samples from other formations within Anambra Basin fall out of these ranges. The shale unit in the Mamu Formation is the major source rock for oil generation in the Anambra Basin while others have potential for gas generation with very little oil generation. The shale samples from Abakaliki Basin shows that S1+S2 values range from< 1 – 20mg/g, TOC values range from 0.31-4.55wt%, vitrinite reflectance ranges from 0.41-1.24% and Tmax ranges from423°C – 466°C. This result also shows that there is no source rock for oil generation in Abakaliki Basin; it is either gas or graphite. This observation indicates that all the source rocks within Abakaliki Basin have exceeded petroleum generating stage due to high geothermal heat resulting from deep depth or the shale units have not attained catagenesis stage as a result of S1+S2 values lesser than 2.5mg/g despite TOC values of ≥ 0.5wt% and vitrinite reflectance values of ≥ 0.6%. The novelty of this study is that the study has been able to show that here there is much more oil than the previous authors claimed, and the distribution of this oil and gas in the basins is controlled by two major factors; the pattern of distribution of the materials of the source rock prior to subsidence and during the subsidence period in the basin, and the pattern and the rate of tectonic activities, and heat flow in the basin. If these factors are known, it would help to reduce the uncertainties associated with exploration for oil and gas in the two basins.

scholarly journals Paleotemperature modeling of hydrocarbon generation centers and their role in the formation of «Paleozoic» oil deposits (Ostaninskoe field, Tomsk region)

Georesursy ◽  
2021 ◽  
Vol 23 (1) ◽  
pp. 2-16
Author(s):  
Valery I. Isaev ◽  
Margarita F. Galieva ◽  
Anna O. Aleeva ◽  
Galina A. Lobova ◽  
Vitaly I. Starostenko ◽  
...  
Keyword(s):  
Heat Flow ◽  
Oil And Gas ◽  
Vitrinite Reflectance ◽  
Hydrocarbon Generation ◽  
Weathering Crust ◽  
Tomsk Region ◽  
History Of ◽  
Oil Deposits ◽  
Reflectance Measurements

Study and exploration of the pre-Jurassic oil and gas complex in Western Siberia is one of the aspects of hydrocarbon raw-material base development. The main scope of this study is to locate the source of Paleozoic hydrocarbons. The problem of modeling and assessing the role of Paleozoic-Mesozoic hydrocarbon generation centers in the formation of «Paleozoic» oil deposits in the section of the Ostaninskoe oil and gas condensate field (Tomsk region) is solved. In the formation of the oil and gas content of the pre-Jurassic basement two reservoirs are involved: the weathering crust and the roof of the bed-rock Paleozoic. The first was formed during the period of 213–208 Ma, and the second is genetically determined by epigenetic processes in the weathering crust. Potential hydrocarbon sources for the weathering crust and bed-rock Paleozoic reservoirs are Domanic type rocks in the crystalline basement: Larinskaya S1lr, Mirnaya D1mr, Chuzikskaya D2cz, Chaginskaya D3cg Formations, as well as Tyumenskaya J1-2tm and Bazhenovskaya J3bg Formations in sedimentary cover. To perform joint paleotemperature modeling of sedimentary basins of the «modern» Jurassic-Cretaceous and Paleozoic «paleobasins», the Ostaninskaya 438P well was selected, which is due to the presence of measured temperatures both in the Jurassic sections and in the pre-Jurassic formations, as well as fluid inflows from the pre-Jurassic horizons into the well. At the first step, the solution of the inverse problem of geothermics was obtained using reservoir temperatures and vitrinite reflectance measurements from the Mesozoic deposits: density of deep heat flow from the base of sedimentary section was determined, which is characterized by a quasi-constant value from the Jurassic to the present. The second step was to solve the inverse problem using vitrinite reflectance measurements from Paleozoic sediments. As a result, the heat flow value was obtained for the key moments of geodynamic history of the stratigraphic section, starting from the Silurian. By solving direct problems of geothermics with the given values of heat flow, the structural-tectonic and thermal history of four Paleozoic potential oil source formations (as well as Jurassic – Bazhenov and Tyumen Formations) has been retraced. The controversial aspects of the heat transfer model in the section of the Ostaninskoe field are considered. It has been established that the Tyumen and Bazhenov oil sources (most likely Bazhenov) are syngenetic (in terms of generation, accumulation and preservation time) for the weathering crust and the Paleozoic reservoirs. The role of the Chaginskaya Formation as gas source is insignificant.

scholarly journals Effects of igneous intrusions on source rock in the early diagenetic stage: A case study on Beipiao Formation in Jinyang Basin, Northeast China

2020 ◽  
Vol 12 (1) ◽  
pp. 990-1002
Author(s):  
Shouliang Sun ◽  
Tao Zhang ◽  
Yongfei Li ◽  
Shuwang Chen ◽  
Qiushi Sun
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
Thermal Evolution ◽  
Vitrinite Reflectance ◽  
Scientific Basis ◽  
Source Rocks ◽  
Temperature History ◽  
Hydrocarbon Generation ◽  
Intrusive Body ◽  
Geochemical Parameters

AbstractMesozoic intrusive bodies play an important role in the temperature history and hydrocarbon maturation of the Jinyang Basin in northeastern China. The Beipiao Formation, which is the main source rock in Jinyang Basin, was intruded by numerous igneous bodies and dykes in many areas. The effects of igneous intrusive bodies on thermal evolution and hydrocarbon generation and migration in the Beipiao Formation were investigated. A series of samples from the outcrop near the intrusive body were analyzed for vitrinite reflectance (R0%) and other organic geochemical parameters to evaluate the lateral extension of the thermal aureole. The R0 values of the samples increase from a background value of ∼0.9% at a distance above 200 m from the intrusive body to more than 2.0% at the vicinity of the contact zone. The width of the altered zone is equal to the thickness of the intrusive body outcropped in the field. Organic geochemical proxies also indicate the intrusive body plays a positive and beneficial role in the formation of regional oil and gas resources. Due to the influence of the anomalous heat from the intrusive body, the hydrocarbon conversion rate of the source rocks of the Beipiao Formation was significantly improved. The accumulation properties and the storage capacity of the shales also greatly improved due to the intrusive body as indicated by the free hydrocarbon migration in the shales. This new understanding not only provides a reliable scientific basis for the accurate assessment of oil and gas genesis and resources in the Jinyang Basin but also provides guidance and reference for oil and gas exploration in the similar type of basin.

scholarly journals Geochemical Evaluation of the Cretaceous Mudrocks and Sandstones (Wackes) in the Southern Bredasdorp Basin, Offshore South Africa: Implications for Hydrocarbon Potential

Minerals ◽  
2020 ◽  
Vol 10 (7) ◽  
pp. 595
Author(s):  
Temitope Love Baiyegunhi ◽  
Kuiwu Liu ◽  
Oswald Gwavava ◽  
Nicola Wagner ◽  
Christopher Baiyegunhi
Keyword(s):  
South Africa ◽  
Oil And Gas ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Geochemical Data ◽  
Minor Amount ◽  
Hydrocarbon Potential ◽  
Hydrocarbon Generation ◽  
Thermal Maturity ◽  
The Mean

The southern Bredasdorp Basin, off the south coast of South Africa, is only partly understood in terms of its hydrocarbon potential when compared to the central and northern parts of the basin. Hydrocarbon potential assessments in this part of the basin have been limited, perhaps because the few drilled exploration wells were unproductive for hydrocarbons, yielding trivial oil and gas. The partial integration of data in the southern Bredasdorp Basin provides another reason for the unsuccessful oil and gas exploration. In this study, selected Cretaceous mudrocks and sandstones (wacke) from exploration wells E-AH1, E-AJ1, E-BA1, E-BB1 and E-D3 drilled in the southern part of the Bredasdorp Basin were examined to assess their total organic carbon (TOC), thermal maturity, organic matter type and hydrocarbon generation potential. The organic geochemical results show that these rocks have TOC contents ranging from 0.14 to 7.03 wt.%. The hydrogen index (HI), oxygen index (OI), and hydrocarbon index (S2/S3) values vary between 24–263 mg HC/g TOC, 4–78 mg CO2/g TOC, and 0.01–18 mgHC/mgCO2 TOC, respectively, indicating predominantly Type III and IV kerogen with a minor amount of mixed Type II/III kerogen. The mean vitrinite reflectance values vary from 0.60–1.20%, indicating that the samples are in the oil-generation window. The Tmax and PI values are consistent with the mean vitrinite reflectance values, indicating that the Bredasdorp source rocks have entered the oil window and are considered as effective source rocks in the Bredasdorp Basin. The hydrocarbon genetic potential (SP), normalized oil content (NOC) and production index (PI) values all indicate poor to fair hydrocarbon generative potential. Based on the geochemical data, it can be inferred that most of the mudrocks and sandstones (wackes) in the southern part of the Bredasdorp Basin have attained sufficient burial depth and thermal maturity for oil and gas generation potential.

Evidence from the Changing Carbon Isotopic of Kerogen, Oil, and Gas during Hydrous Pyrolysis from Pinghu Formation, the Xihu Sag, East China Sea Basin

Energies ◽  
2021 ◽  
Vol 14 (24) ◽  
pp. 8317
Author(s):  
Qiang Cao ◽  
Jiaren Ye ◽  
Yongchao Lu ◽  
Yang Tian ◽  
Jinshui Liu ◽  
...  
Keyword(s):  
Carbon Isotopes ◽  
Oil And Gas ◽  
Thermal Evolution ◽  
Vitrinite Reflectance ◽  
Heating Time ◽  
Source Rocks ◽  
Evolution Process ◽  
Carbon Isotopic ◽  
Hydrous Pyrolysis ◽  
Increasing Temperature

Semi-open hydrous pyrolysis experiments on coal-measure source rocks in the Xihu Sag were conducted to investigate the carbon isotope evolution of kerogen, bitumen, generated expelled oil, and gases with increasing thermal maturity. Seven corresponding experiments were conducted at 335 °C, 360 °C, 400 °C, 455 °C, 480 °C, 525 °C, and 575 °C, while other experimental factors, such as the heating time and rate, lithostatic and hydrodynamic pressures, and columnar original samples were kept the same. The results show that the simulated temperatures were positive for the measured vitrinite reflectance (Ro), with a correlation coefficient (R2) of 0.9861. With increasing temperatures, lower maturity, maturity, higher maturity, and post-maturity stages occurred at simulated temperatures (Ts) of 335–360 °C, 360–400 °C, 400–480 °C, and 480–575 °C, respectively. The increasing gas hydrocarbons with increasing temperature reflected the higher gas potential. Moreover, the carbon isotopes of kerogen, bitumen, expelled oil, and gases were associated with increased temperatures; among gases, methane was the most sensitive to maturity. Ignoring the intermediate reaction process, the thermal evolution process can be summarized as kerogen0(original) + bitumen0(original)→kerogenr (residual kerogen) + expelled oil (generated) + bitumenn+r (generated + residual) + C2+(generated + residual) + CH4(generated). Among these, bitumen, expelled oil, and C2-5 acted as reactants and products, whereas kerogen and methane were the reactants and products, respectively. Furthermore, the order of the carbon isotopes during the thermal evolution process was identified as: δ13C1 < 13C2-5 < δ13Cexpelled oil < δ13Cbitumen < δ13Ckerogen. Thus, the reaction and production mechanisms of carbon isotopes can be obtained based on their changing degree and yields in kerogen, bitumen, expelled oil, and gases. Furthermore, combining the analysis of the geochemical characteristics of the Pinghu Formation coal–oil-type gas in actual strata with these pyrolysis experiments, it was identified that this area also had substantial development potential. Therefore, this study provides theoretical support and guidance for the formation mechanism and exploration of oil and gas based on changing carbon isotopes.

scholarly journals Evaluation of hydrocarbons generated from the Permo-Carboniferous source rocks in Huanghua Depression of the Bohai Bay Basin, China

2018 ◽  
Vol 36 (5) ◽  
pp. 1229-1244
Author(s):  
Xiao-Rong Qu ◽  
Yan-Ming Zhu ◽  
Wu Li ◽  
Xin Tang ◽  
Han Zhang
Keyword(s):  
Oil And Gas ◽  
Source Rocks ◽  
Bohai Bay ◽  
Hydrocarbon Generation ◽  
Burial History ◽  
Bohai Bay Basin ◽  
Important Conclusion ◽  
The North ◽  
Huanghua Depression ◽  
History Of

The Huanghua Depression is located in the north-centre of Bohai Bay Basin, which is a rift basin developed in the Mesozoic over the basement of the Huabei Platform, China. Permo-Carboniferous source rocks were formed in the Huanghua Depression, which has experienced multiple complicated tectonic alterations with inhomogeneous uplift, deformation, buried depth and magma effect. As a result, the hydrocarbon generation evolution of Permo-Carboniferous source rocks was characterized by discontinuity and grading. On the basis of a detailed study on tectonic-burial history, the paper worked on the burial history, heating history and hydrocarbon generation history of Permo-Carboniferous source rocks in the Huanghua Depression combined with apatite fission track testing and fluid inclusion analyses using the EASY% Ro numerical simulation. The results revealed that their maturity evolved in stages with multiple hydrocarbon generations. In this paper, we clarified the tectonic episode, the strength of hydrocarbon generation and the time–spatial distribution of hydrocarbon regeneration. Finally, an important conclusion was made that the hydrocarbon regeneration of Permo-Carboniferous source rocks occurred in the Late Cenozoic and the subordinate depressions were brought forward as advantage zones for the depth exploration of Permo-Carboniferous oil and gas in the middle-northern part of the Huanghua Depression, Bohai Bay Basin, China.

scholarly journals New exploration strategy in igneous petroliferous basins – Enlightenment from simulation experiments

2018 ◽  
Vol 36 (4) ◽  
pp. 971-985
Author(s):  
Qingqiang Meng ◽  
Jiajun Jing ◽  
Jingzhou Li ◽  
Dongya Zhu ◽  
Ande Zou ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Liquid Hydrocarbon ◽  
Hydrogen Gas ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Simulation Experiments ◽  
Gaseous Hydrocarbon ◽  
Oil And Gas Fields ◽  
Gaseous Hydrocarbons ◽  
Hydrocarbon Productivity

There are two kinds of relationships between magmatism and the generation of hydrocarbons from source rocks in petroliferous basins, namely: (1) simultaneous magmatism and hydrocarbon generation, and (2) magmatism that occurs after hydrocarbon generation. Although the influence of magmatism on hydrocarbon source rocks has been extensively studied, there has not been a systematic comparison between these two relationships and their influences on hydrocarbon generation. Here, we present an overview of the influence of magmatism on hydrocarbon generation based on the results of simulation experiments. These experiments indicate that the two relationships outlined above have different influences on the generation of hydrocarbons. Magmatism that occurred after hydrocarbon generation contributed deeply sourced hydrogen gas that improved liquid hydrocarbon productivity between the mature and overmature stages of maturation, increasing liquid hydrocarbon productivity to as much as 451.59% in the case of simulation temperatures of up to 450°C during modelling where no hydrogen gas was added. This relationship also increased the gaseous hydrocarbon generation ratio at temperatures up to 450°C, owing to the cracking of initially generated liquid hydrocarbons and the cracking of kerogen. Our simulation experiments suggest that gaseous hydrocarbons dominate total hydrocarbon generation ratios for overmature source rocks, resulting in a change in petroleum accumulation processes. This in turn suggests that different exploration strategies are warranted for the different relationships outlined above. For example, simultaneous magmatism and hydrocarbon generation in an area means that exploration should focus on targets likely to host large oilfields, whereas in areas with magmatism that post-dates hydrocarbon generation the exploration should focus on both oil and gas fields. In addition, exploration strategies in igneous petroliferous basins should focus on identifying high-quality reservoirs as well as determining the relationship between magmatism and initial hydrocarbon generation.

scholarly journals Fluid geochemistry of the Jurassic Ahe Formation and implications for reservoir formation in the Dibei area, Tarim Basin, northwest China

2018 ◽  
Vol 36 (4) ◽  
pp. 801-819 ◽  
Author(s):  
Shuangfeng Zhao ◽  
Wen Chen ◽  
Zhenhong Wang ◽  
Ting Li ◽  
Hongxing Wei ◽  
...  
Keyword(s):  
Natural Gas ◽  
Tarim Basin ◽  
Oil And Gas ◽  
Northwest China ◽  
Source Rocks ◽  
Coal Measure ◽  
Hydrocarbon Generation ◽  
Gas Reservoirs ◽  
Isotopic Analyses ◽  
Jurassic Coal

The condensate gas reservoirs of the Jurassic Ahe Formation in the Dibei area of the Tarim Basin, northwest China are typical tight sandstone gas reservoirs and contain abundant resources. However, the hydrocarbon sources and reservoir accumulation mechanism remain debated. Here the distribution and geochemistry of fluids in the Ahe gas reservoirs are used to investigate the formation of the hydrocarbon reservoirs, including the history of hydrocarbon generation, trap development, and reservoir evolution. Carbon isotopic analyses show that the oil and natural gas of the Ahe Formation originated from different sources. The natural gas was derived from Jurassic coal measure source rocks, whereas the oil has mixed sources of Lower Triassic lacustrine source rocks and minor amounts of coal-derived oil from Jurassic coal measure source rocks. The geochemistry of light hydrocarbon components and n-alkanes shows that the early accumulated oil was later altered by infilling gas due to gas washing. Consequently, n-alkanes in the oil are scarce, whereas naphthenic and aromatic hydrocarbons with the same carbon numbers are relatively abundant. The fluids in the Ahe Formation gas reservoirs have an unusual distribution, where oil is distributed above gas and water is locally produced from the middle of some gas reservoirs. The geochemical characteristics of the fluids show that this anomalous distribution was closely related to the dynamic accumulation of oil and gas. The period of reservoir densification occurred between the two stages of oil and gas accumulation, which led to the early accumulated oil and part of the residual formation water being trapped in the tight reservoir. After later gas filling into the reservoir, the fluids could not undergo gravity differentiation, which accounts for the anomalous distribution of fluids in the Ahe Formation.

scholarly journals Thermal Maturation Regime Revisited in the Dongying Depression, Bohai Bay Basin, East China

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-17
Author(s):  
Haiping Huang ◽  
Hong Zhang ◽  
Zheng Li ◽  
Mei Liu
Keyword(s):  
Organic Geochemistry ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
East China ◽  
Burial Depth ◽  
Bohai Bay ◽  
Hydrocarbon Generation ◽  
Bohai Bay Basin ◽  
Dongying Depression ◽  
Hydrocarbon Maturation

To the accurate reconstruction of the hydrocarbon generation history in the Dongying Depression, Bohai Bay Basin, East China, core samples of the Eocene Shahejie Formation from 3 shale oil boreholes were analyzed using organic petrology and organic geochemistry methods. The shales are enriched in organic matter with good to excellent hydrocarbon generation potential. The maturity indicated by measured vitrinite reflectance (%Ro) falls in the range of 0.5–0.9% and increases with burial depth in each well. Changes in biomarker and aromatic hydrocarbon isomer distributions and biomarker concentrations are also unequivocally correlated with the thermal maturity of the source rocks. Maturity/depth relationships for hopanes, steranes, and aromatic hydrocarbons, constructed from core data indicate different well locations, have different thermal regimes. A systematic variability of maturity with geographical position along the depression has been illustrated, which is a dependence on the distance to the Tanlu Fault. Higher thermal gradient at the southern side of the Dongying Depression results in the same maturity level at shallower depth compared to the northern side. The significant regional thermal regime change from south to north in the Dongying Depression may exert an important impact on the timing of hydrocarbon maturation and expulsion at different locations. Different exploration strategies should be employed accordingly.

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