Search

The origin of Precambrian dolomites has attracted research interest as a result of their association with petroleum resources. The long diagenetic history of these dolomites and multiple periods of hydrothermal activity mean that dating and identifying different periods of dolomite formation is challenging. This study focuses on dolomites in the Precambrian Dengying Formation of the Sichuan Basin, central China, and presents new petrographic, in situ laser ablation inductively coupled plasma mass spectrometry U–Pb and trace element, and Sr–C–O isotopic data to characterize three types of dolomite and constrain their age and origin. In situ U–Pb dating of type I dolomite yielded a lower intercept age of 637 ± 35 Ma. The rare earth element (REE) patterns, 87Sr/86Sr ratios (0.70827–0.70903), and δ13C VPDB (0.8‰–1.0‰) and δ18O VPDB (−1.5‰ to −1.0‰) values of type I dolomite indicate their derivation from seawater or a precursory source with seawater characteristics. Type II dolomite yielded an age of 636 ± 15 Ma and has lower ΣREE and slightly higher δ13C VPDB (1.2‰–1.5‰) and δ18O VPDB (−0.9‰ to −0.3‰) values than type I, as well as similar 87Sr/86Sr ratios and parallel REE patterns that are indicative of formation by reflux seepage dolomitization. The type III dolomite is characterized by large crystals, unique REE patterns, high 87Sr/86Sr values (0.70942–0.70975), and negative δ18O VPDB values (−6.4‰ to −3.1‰) that indicate a hydrothermal origin. The relationships between hydrothermal dolomite and bitumen indicate that the paleo-oil charging within the Dengying Formation reservoir occurred after the hydrothermal activity at 516 ± 49 Ma. The early hydrothermal activity provided space for the subsequent fluid movement, and oil and gas charging. Our integrated approach, incorporating petrographic, geochemical, isotopic, and geochronological data, constrains the ages of different dolomite phases and an oil-charging event within the Dengying Formation reservoir and provides new insights into the evolution of petroleum systems in general. • We identified three types of dolomites of Dengying Formation matching with the age of diagenesis and fluid activity. • The LA–ICP–MS in situ U–Pb dating of Dengying Formation dolomite yields a lower intercept age of 637 ± 35 Ma. • The dating results suggest an extensional event existed at 516 ± 49 Ma, and accounted for the deposition of hydrocarbon source rocks. • This study outlines potential approaches for furthering our understanding of dolomites and ancient petroleum systems. [ABSTRACT FROM AUTHOR]

Free oils and inclusion oils were extracted from the third member of the Eocene Shahejie Formation (Es3) reservoir sandstones of the wells Chun 51 and Liang 28 in the Dongying Depression, China, and then analyzed by gas chromatography–mass spectrometry (GC–MS). Results show that biomarker distribution characteristics of the free oils and their associated inclusion oils are similar in each Es3 reservoir sandstones of the two wells, but the distributions of Pr/Ph ratio, gammacerane, hopane series and C 27 –C 29 steranes in well Chun 51 oils are strikingly different from those of well Liang 28 oils. However, the C 29 sterane ββ/(ββ + αα), Ts/(Ts + Tm) and C 31 hopane 22S/(22S + 22R) ratios of inclusion oils are higher than those of related free oils in all the samples, this may indicate that maturity indicators decreased after reaching the maximum and relatively high mature oils were trapped in petroleum inclusions. Comparison with biomarkers of source-rock extracts shows that oils in the Es3 reservoir of well Chun 51 were generated from the upper Es4 source rocks, whereas oils in the Es3 reservoir of well Liang 28 were derived from the lower Es3 source rocks. Moreover, the microthermometric data and burial history indicate one oil-charging episode in the Es3 reservoirs of the two wells, during the late Neogene. It's concluded that different charging histories of these two reservoirs were attributed mainly to the sealing effect of the fault. • Biomarker compositions of fluid inclusions and free oils were discussed. • Oil-sources of the two studied Es3 reservoirs were single but different. • Oil-charging times of the two Es3 reservoirs were defined. • Different oil-charging histories of the two Es3 reservoirs were analyzed. [ABSTRACT FROM AUTHOR]

The geochemistry, origin and charge history of oils from the Yuqi area of Tarim Basin have been investigated, through GC, GC-MS and fluid inclusion microthermometry analysis. The Yuqi oils accumulated mainly in three intervals: (1) in the Lower-Middle Ordovician Yingshan Formation (O 1-2 y ) carbonate reservoirs; (2) in the overlying Upper Triassic Halahatang Formation (T 3 h ); and (3) in the Lower Cretaceous Yageliemu Formation (K 1 y ) sandstones. Oils from different reservoirs have distinct physical properties, varying from extra-heavy (O 1-2 y), heavy (T 3 h ), to light oils (T 3 h and K 1 y ). However, their geochemical compositions show a high degree of similarity, which indicates that they derive from the same source rock. Abundant tricyclic terpanes, gammacerane, dibenzothiophene and C 21 C 22 steranes, together with a low level of diasteranes, indicate an anoxic marine source rock for oils in the Yuqi area. Oil-oil correlation shows that Yuqi oils derive from the same source bed as Tahe oils. The co-occurrence of intact n -alkanes and 25-norhopanes in all the samples supports the proposition that there is a mixture of an early filled severely biodegraded oil and a late filled fresh oil. In this study, charge history is examined on the basis of integration of fluid inclusion homogenization temperature data with 1D burial-thermal history models. Two episodes of oil charging are identified in the O 1-2 y reservoir (well YQX1-1) at around 436-420 Ma (Middle-Late Silurian) and 10-3 Ma (Miocene to Pliocene), respectively. For the samples from the T 3 h and K 1 y intervals, only one episode of oil charge is indicated by the homogenization temperatures of coexisting aqueous inclusions with an inferred timing around 10-3 Ma. The T 3 h heavy oil reservoir is assumed to be a secondary hydrocarbon pool, which accumulated by re-migration and re-distribution of hydrocarbons from O 1-2 y hydrocarbon pools. The few early biodegraded oils in the K 1 y light oils were probably picked up along the migration pathway during the late fresh oil charging. [ABSTRACT FROM AUTHOR]

The Ordovician reservoir in the Halahatang Depression is one of the most commercially prolific oil reservoirs in the Tabei Uplift of the Tarim Basin, NW China. For this study, a total of 94 oil samples were collected from 88 exploration/production wells in this oilfield. All of the oils possess similar organic molecular compositions and belong to the same oil population. Oil-to-source correlation results indicate that oil accumulations discovered in Halahatang Oilfield were derived from the Upper Ordovician source rocks. The homogenization temperatures of fluid inclusion in the Ordovician reservoir in the Halahatang Oilfield range from 90 °C to 100 °C and from 140 °C to 160 °C. The bimodal distribution pattern shown in a histogram of the homogenization temperatures indicates that the Ordovician oil reservoir in the Halahatang Oilfield has been charged twice. Coupling this information with the reconstructed burial and geothermal histories by 1-D basin modeling, the homogenization temperatures can be related to the relative geological ages of 419 Ma to 410 Ma and 16 Ma to 8 Ma, namely, the Middle to Late Silurian and the Middle Miocene respectively, representing the two phases of oil charging and entrapment. The oil migration orientation and charging pathways can be traced using molecular indicators, such as Ts/(Ts + Tm) and TMNr parameters. The overall oil migration orientation in the oilfield is generally from south to north. Therefore, the source kitchen for the Halahatang Oilfield is predicted to be to the south side of the depression. The southern part of the Halahatang Depression, along the oil charging pathways, is identified as the most promising region for oil exploration. [ABSTRACT FROM AUTHOR]

Determining the place of paleo-oil cracking is crucial to understanding the formation mechanism of the gas reservoirs in the Precambrian–Cambrian strata. For the old strata the attainable information is limited because most paleo-oil have been cracked to gas at high thermal maturity, such as the Anyue giant gas field in the Moxi–Gaoshiti Bulge of Sichuan Basin, Southwestern China. In this study, the place of paleo-oil cracking was discussed based on solid bitumen found in the reservoirs. Numerous solid bitumen from the deep boreholes in the Precambrian Dengying (Z 2 dn 2 and Z 2 dn 4 ) and Lower Cambrian Longwangmiao (Є 1 l) formations of the Moxi–Gaoshiti Bulge were analyzed. Elemental and carbon isotope analyses and optical microscopic observations, such as Raman spectroscopy, scanning electron microscopy, and electronic probe, were performed on these solid bitumen samples. The obtained parameters, including the reflectance of the solid bitumen, parameters I(D)/I(G) and S(D)/S(G) from the Raman spectra, the compositions and carbon isotope of gas, burial history, and the predicted "equivalent vitrinite reflectance Ro" (EqVRo) for reservoirs, jointly support that solid bitumen are epigenetic bitumen in reservoirs other than primary bitumen in source rocks. This study provides a relatively solid evidence of in situ cracking of paleo-oil and the thermochemical sulfate reduction reaction between paleo-oil and dolomite reservoirs. Pyrite were found both in carbonate rocks and argillaceous rock, and the sulfur in pyrite is perceived as a pathway of H 2 S formation. The results provide a basis for understanding the formation mechanism of the deep huge gas field that was derived from paleo-oil cracking, and may contribute to future petroleum exploration in deep Precambrian–Lower Cambrian systems. • A vitrinite reflectance profile of the extensive shale form one well was provided. • The solid bitumen was confirmed to be from in situ oil cracking at high thermal maturity. • Evidences proved that the TSR reaction was involved in this crude oil cracking. • The reaction of pyrite with hydrocarbons was considered as a pathway of H 2 S formation. • Maturities" of solid bitumen and reservoirs were quantitative calculated and compared. [ABSTRACT FROM AUTHOR]