Cambrian Ordovician Source Rocks Research Articles

Geochemical characteristics of Cambrian bitumen and Cambrian-Ordovician source rocks in the Keping area, NW Tarim Basin

The Cambrian Yuertus Formation and Ordovician Saergan and Yingan formation source rocks, which TOC contents of 0.38%–4.30%, are well developed in the Keping area of the Tarim Basin. Reservoir bitumen had been found in the Cambrian Wusongger Formation and Shayilike Formation. In this study, the geochemical characteristics of the bitumen and source rocks were analyzed through biomarkers for oil-source correlation. The results show that the characteristics of the bitumen and Yuertus Formation source rocks are similar. Comparatively, the Yuertus Formation source rocks and bitumen have lower Pr/Ph values and higher C28/C29 regular steranes values. The maturity characteristics and depositional environment of the Cambrian source rocks in the Keping area and the platform basin areas are similar. Plots of Ph/n-C18versus Pr/n-C17, Ts/(Ts+Tm) versus 4-/1-MDBT (methyl dibenzothiophene), and DBT/P (dibenzothiophene/phenanthrene) versus Pr/Ph distinguish the bitumen and source rocks well. As an original plot, we found that the Fla/Py (fluoranthene/pyrene) versus MP/P (methyl-phenanthrene/phenanthrene) intersection plot can be used to identify the possible sources of polycyclic aromatic hydrocarbons (PAHs) to a certain extent and can distinguish between the Cambrian and Ordovician source rocks in this study. Comprehensive analysis revealed that the bitumen samples most likely originated from the Yuertus Formation source rocks. It was also found that the biomarker characteristics such as the shape type of the C27-C28-C29 regular steranes, triarylosteranes, and triarylosteroids are not applicable to distinguishing the Cambrian and Ordovician source rocks in the Keping area. These research findings provide references for studying the Lower Paleozoic oil-source correlation in the platform in the Tarim Basin.

Sedimentary Environments of Cambrian–Ordovician Source Rocks and Ultra‐deep Petroleum Accumulation in the Tarim Basin

AbstractThe Tarim Basin is the only petroliferous basin enriched with marine oil and gas in China. It is presently also the deepest basin for petroleum exploration and development in the world. There are two main sets of marine Source Rocks (SRs) in the Tarim Basin, namely the high over‐mature Cambrian–Lower Ordovician (∊ –O1) and the moderately mature Middle–Upper Ordovician (O2–3). The characteristic biomarkers of SRs and oils indicate that the main origin of the marine petroleum is a mixed source of ∊ –O1 and O2–3 SRs. With increasing burial, the hydrocarbon contribution of the ∊ –O1 SRs gradually increases. Accompanied by the superposition of multi‐stage hydrocarbon‐generation of the SRs and various secondary alteration processes, the emergence and abnormal enrichment of terpenoids, thiophene and trimethylaryl isoprenoid in deep reservoirs indicate a complex genesis of various deep oils and gases. Through the analysis of the biofacies and sedimentary environments of the ∊ –O1 and O2–3 SRs, it is shown that the lower Paleozoic high‐quality SRs in the Tarim Basin were mainly deposited in a passive continental margin and the gentle slope of the platform, deep‐water shelf and slope facies, which has exhibited a good response to the local tectonic‐sedimentary environment. The slope of the paleo‐uplift is the mutual area for the development of carbonate reservoirs and the deposition of marine SRs, which would be favorable for the accumulation of petroleum. Due to the characteristics of low ground temperature, the latest rapid and deep burial does not cause massive oil‐cracking in the paleo‐uplift and slope area. Therefore, it is speculated that the marine reservoirs in the slope of the Tabei Uplift are likely to be a favorable area for deep petroleum exploration, while the oil‐cracking gas would be a potential reserve around the west margin of the Manjiaer Depression. Hydrocarbons were generated from various unit SRs, mainly migrating along the lateral unconformities or reservoirs and the vertical faults. They eventually brought up three major types of exploration fields: middle and lower Cambrian salt‐related assemblages, dolomite inner reservoirs and Middle and Lower Ordovician oil‐bearing karst, which would become the most favorable target of marine ultra‐deep exploration in the Tarim Basin.

Tectono-thermal evolution of Cambrian–Ordovician source rocks and implications for hydrocarbon generation in the eastern Tarim Basin, NW China

The tectono-thermal evolution is an important control on petroliferous basin development; however, this evolution is difficult to reconstruct in sedimentary basins subjected to multiple tectono-thermal events. The Tarim Basin is the largest petroliferous basin in northwestern China and hosts a complex oil–gas system comprising several sets of source, reservoir, and cap rocks that have experienced multiple tectonic, thermal, and sedimentary events. Large oil and gas reserves have been discovered in the central and northern Tarim Basin during the last 30 years, but none in the eastern part of the basin. This is generally attributed to the high thermal maturity reached by source rocks during the Late Ordovician, and subsequent hydrocarbon loss. Therefore, reconstructing the Cambrian–Ordovician tectono-thermal evolution is critical in facilitating successful oil and gas exploration in this region. We compiled equivalent vitrinite reflectance data (n = 178) of source rocks from seven wells in the Tarim Basin, which for Cambrian–Ordovician source rocks are >1.3%, beyond the hydrocarbon generation threshold and in the main gas and dry gas generation stages. The Cambrian–Ordovician source rocks experienced rapid burial and heating during the Caledonian period, entered the hydrocarbon generation stage during the Middle–Late Ordovician, and reached peak hydrocarbon generation at the end-Caledonian period. They might have experienced secondary hydrocarbon generation after the Jurassic. Homogenization temperatures of fluid inclusions (n = 616) from wells GC4, LX1, MD1, and YD2 as well as the modeled thermal evolution reveal a main hydrocarbon generation event during the Caledonian period and a secondary event in the Yanshanian and Himalayan period in other wells (LX1, MD1, and YD2). Hercynian and Indosinian uplift and exhumation in the eastern Tarim Basin controlled the main structures, and faulting created favorable conditions for secondary hydrocarbon generation and migration at this time. Since the Yanshanian and Himalayan, the Tarim Basin has experienced further sedimentation and heating, and the tectono-thermal evolution might have been related to the formation of the Tibetan Plateau. In summary, our reconstruction of the tectono-thermal evolution of Cambrian–Ordovician strata and the hydrocarbon generation history of the Tarim Basin suggests that the eastern Tarim Basin may also have hydrocarbon generation potential and can guide future oil and gas exploration.

Geochemical characteristics, genetic types and sources of natural gas in the Yingjisu Depression, Tarim Basin, China

The Yingjisu Depression in the Tarim Basin produces gas with high wetness, nitrogen content, and ethane carbon isotope is abnormally depleted. The hydrocarbon generation capability of the Jurassic coal strata in this area has been controversial. Anomalies in the geochemical characteristics and the actual geological conditions have resulted in challenges in identifying the source and genetic type of natural gas in the Yingjisu Depression. In the present study, the composition and carbon isotope of natural gas are investigated. In addition, the controversial Jurassic coal strata are comprehensively evaluated, and the biomarkers are analyzed. The actual geological conditions of the Yingjisu Depression are studied combined with geochemical analysis. The components and carbon isotope suggest that the natural gas in the Yingjisu Depression is oil-associated gas generated from marine source rocks in the late mature stage. The formation temperature of the natural gas was higher than 185 °C, which represents secondary cracking oil at high thermal maturity. The Jurassic coal strata has low Tmax (lower than 435 °C) and %Ro = 0.3–0.7. These strata cannot be the source rocks of natural gas in the Yingjisu Depression with high content of N2, typical of marine sediment. However, the biomarkers confirmed that the oil and gas in the Yingjisu Depression were derived from the Cambrian–Ordovician source rocks rather than the Jurassic. Therefore, the natural gas in the Yingjisu Depression is the secondary cracking of oil from the Cambrian–Ordovician paleo-reservoir. According to the actual geological conditions, the cracked gas migrated upward along deep faults to accumulate in the Silurian and Jurassic reservoirs, eventually forming the Yingjisu Depression gas field.

The origin, migration and accumulation of the Ordovician gas in the Tazhong III region, Tarim Basin, NW China

Abstract The Ordovician large-scale gas reservoir in the Tazhong III region (burial depth > 6000 m) is a typical deep strata gas reservoir in the Tarim Basin of NW China. The origin, migration and accumulation of the Ordovician natural gas in the Tazhong III region were investigated by integrating geological, geophysical, and geochemical parameters. The parameters that were successfully analyzed included the gas compositions and carbon isotope ratios, production data, burial and geothermal histories, oil compositions and properties, together with the diamantane index. The results indicated that the Ordovician natural gas in the Tazhong III region originated from Cambrian-Ordovician paleo-oil cracking, accompanied by a large amount of H2S generated from thermochemical sulfate reduction (TSR). When the oil cracking gas migrated vertically into the Ordovician reservoir through the Tazhong I fault and strike-slip faults, it was preferentially charged in the pinnate fault zones of strike-slip faults with high porosity and permeability, leading to the enrichment of natural gas and an abnormal distribution of the compositions and properties of hydrocarbon. Then, oil cracking gas intruded into and altered the previous oil reservoir from northeast to southwest through the strike-slip faults, unconformities and pore-fracture reservoir belt, leading to the differential accumulation of hydrocarbon in districts of the Tazhong III region. The Ordovician natural gas migration-accumulation model in the Tazhong III region indicates a great exploration potential in the deep or super-deep strata of the Tarim Basin. Further exploration activities in the Ordovician reservoir of the Tarim Basin should be conducted in the regions where Cambrian-Ordovician source rocks are well developed, and the stress fracture zones-related deep fault should be emphasized.

Carbon isotopic compositions and origin of Paleozoic crude oil in the platform region of Tarim Basin, NW China

Based on the carbon isotopic compositions of Cambrian-Ordovician source rocks Kerogen Samples and Paleozoic crude oil in the platform region of Tarim Basin, the origin and source of Paleozoic crude oil were investigated. There are at least two sets of source rocks with different carbon isotope compositions in the Cambrian, the Lower Cambrian source rock with lighter carbon isotope composition and Middle-Upper Cambrian source rock with heavier carbon isotope composition, while the Ordovician source rock is somewhere in between. The δ13C values of Paleozoic crude oil samples are wide in distribution range, from −35.2‰ to −28.1‰. The crude oil with lighter carbon isotopic compositions (δ13C<−34.0‰) was mainly derived from Lower Cambrian source rock, and the crude oil with heavier carbon isotopic composition (δ13C>−29.0‰) was mainly derived from the Middle-Upper Cambrian source rocks, and the crude oil with δ13C value in between may be derived from Cambrian source rocks. It is concluded through analysis that the Cambrian source rock could become the major source rock in the Tarim Basin and the platform region has huge potential oil and gas resources in the deep formations.

Correlation of crude oils and oil components from reservoirs and source rocks using carbon isotopic compositions of individual n-alkanes in the Tazhong and Tabei Uplift of the Tarim Basin, China

Carbon isotopic compositions were determined by GC–IRMS for individual n-alkanes in crude oils and the free, adsorbed and inclusion oils recovered by sequential extraction from reservoir rocks in the Tazhong Uplift and Tahe oilfield in the Tabei Uplift of Tarim Basin as well as extracts of the Cambrian–Ordovician source rocks in the basin. The variations of the δ13C values of individual n-alkanes among the 15 oils from the Tazhong Uplift and among the 15 oils from the Triassic and Carboniferous sandstone reservoirs and the 21 oils from the Ordovician carbonate reservoirs in the Tahe oilfield demonstrate that these marine oils are derived from two end member source rocks. The major proportion of these marine oils is derived from the type A source rocks with low δ13C values while a minor proportion is derived from the type B source rocks with high δ13C values. Type A source rocks are within either the Cambrian–Lower Ordovician or the Middle–Upper Ordovician strata (not drilled so far) while type B source rocks are within the Cambrian–Lower Ordovician strata, as found in boreholes TD2 and Fang 1. In addition, the three oils from the Cretaceous sandstone reservoirs in the Tahe oilfield with exceptionally high Pr/Ph ratio and δ13C values of individual n-alkanes are derived, or mainly derived, from the Triassic–Jurassic terrigenous source rocks located in Quka Depression.The difference of the δ13C values of individual n-alkanes among the free, adsorbed and inclusion oils in the reservoir rocks and corresponding crude oils reflects source variation during the reservoir filling process. In general, the initial oil charge is derived from the type B source rocks with high δ13C values while the later oil charge is derived from the type A source rocks with low δ13C values.The δ13C values of individual n-alkanes do not simply correlate with the biomarker parameters for the marine oils in the Tazhong Uplift and Tahe oilfield, suggesting that molecular parameters alone are not adequate for reliable oil-source correlation for high maturity oils with complex mixing.

Seismic reflection, distribution, and potential trap of Permian volcanic rocks in the Tahe field

Permian Kaipaileicike (开派雷兹克) volcanic rocks approximately 0–200 m thick are drilled in the Tahe (塔河) field. The distribution of volcanic rocks and their potential to form hydrocarbon reservoirs are discussed based on the integrated interpretation of log and 3D seismic data. The volcanic rocks, mainly consisting of dacites and basalts, are sandwiched between the Lower Triassic and Lower Carboniferous and bounded by top and bottom unconformities. The dacites accumulated in a mound shape around volcanic craters, whereas the basalts are deposited in tabular or trough-fill geometries. Permian volcanic craters mainly located at the northwest corner of the Tahe field are identified from volcanic rock thickening, occurrence of volcanic breccias, structural arch of the top Permian, seismic attribute anomalies, and fault (piercing conduit) reflections. Along the northwest wing of a Carboniferous salt dome, a stratigraphic trap is formed by a northeast updip pinch-out of Permian volcanic rock. Oil indications within the trap are found in numerous wells. The reservoir volcanic rocks are mainly of the fracture-pore pattern and covered by the caprock of a Lower Triassic mudstone. The hydrocarbon reservoir, which can potentially be a medium-sized oil pool, is connected to Cambrian-Ordovician source rocks through normal faults along the salt dome boundary.

Evolution and Movement of Source Kitchens and Their Control of Oil and Gas in the Tarim Cratonic Basin, China

The cratonic region of the Tarim Basin contains two main Lower Paleozoic source rocks–the Middle-Upper Ordovician and Lower-Middle Cambrian. However, few research focus on the relation between the evolution of hydrocarbon kitchens and its role in controlling oil and gas. Based on previous research results, this paper applies geochemical parameters of rock pyrolysis, hydrocarbon expulsion threshold theory and hydrocarbon-generated potential methods to identify the effectiveness of source rocks from the Lower Paleozoic while quantitatively calculating the hydrocarbon expulsion intensities and amounts for the two sets of source rocks. The above result is used to analysis the distribution of the effective hydrocarbon kitchen in each primary history stage and the controls on oil and gas. This study shows multiple phases of oil and gas generation and expulsion from the Cambrian-Ordovician source rocks with four oil-generating peaks with large-scale oil migration and accumulation. According to the changes in hydrocarbon expulsion intensity within different stages, we can elucidate the evolution of the source kitchens, because the hydrocarbon kitchens from the two sets of source rocks migrated in time and space, and there are multiple hydrocarbon expulsion centers. Based on the concept of the oil/gas threshold distribution model, the relation between the quantitative characterization of the hydrocarbon kitchen controlling function, and quantitative prediction of reservoir formation probability is studied, and the result shows that oil and gas reservoirs are located in more than 50% probability of controlling area. However, different periods and different layers of stacked hydrocarbon kitchen is complex and causing the main mixing of oil and gas. All these hydrocarbon expulsion centers had control over the distribution of oil and gas in the basin. From a macro and quantitative point of view, this discovery will provide certain guide for oil and gas exploration.

The significance of 24-norcholestanes, triaromatic steroids and dinosteroids in oils and Cambrian–Ordovician source rocks from the cratonic region of the Tarim Basin, NW China

Abstract Two oil families in Ordovician reservoirs from the cratonic region of the Tarim Basin are distinguished by the distribution of regular steranes, triaromatic steroids, norcholestanes and dinosteroids. Oils with relatively lower contents of C 28 regular steranes, C 26 20S, C 26 20R + C 27 20S and C 27 20R regular triaromatic steroids, dinosteranes, 24-norcholestanes and triaromatic dinosteroids originated from Middle–Upper Ordovician source rocks. In contrast, oils with abnormally high abundances of the above compounds are derived from Cambrian and Lower Ordovician source rocks. Only a few oils have previously been reported to be of Cambrian and Lower Ordovician origin, especially in the east region of the Tarim Basin. This study further reports the discovery of oil accumulations of Cambrian and Lower Ordovician origin in the Tabei and Tazhong Uplifts, which indicates a potential for further discoveries involving Cambrian and Lower Ordovician sourced oils in the Tarim Basin. Dinosteroids in petroleum and ancient sediments are generally thought to be biomarkers for dinoflagellates and 24-norcholestanes for dinoflagellates and diatoms. Therefore, the abnormally high abundance of these compounds in extracts from the organic-rich sediments in the Cambrian and Lower Ordovician and related oils in the cratonic region of the Tarim Basin suggests that phytoplankton algae related to dinoflagellates have appeared and might have flourished in the Tarim Basin during the Cambrian Period. Steroids with less common structural configurations are underutilized and can expand understanding of the early development history of organisms, as well as define petroleum systems.

Relations between spatial distribution and sequence types of the Cambrian-Ordovician marine source rocks in Tarim Basin

Marine source rocks are considered to be mainly composed of the Cambrian-Ordovician deposit in Tarim Basin. Based on the previous studies made by other researchers, the authors calculated the thickness and distribution scale of these Cambrian-Ordovician source rocks by integrating sequence stratigraphy with investigations on sedimentary environments, well-shooting demarcating and calibrating the thickness of unknown source rocks with the thickness of the known ones according to characteristics of the source rocks that have “double track” seismic lineup reflectance. The results showed that the distribution area of the Lower-Cambrian Yuertusi Fm. source rock in platform inner depressions, slopes and deep basins is much bigger than that of the Middle Cambrian evaporite-lagoon source rock. Moreover, the former is superior to the latter in terms of the source rock quality. Likewise, the Middle-Ordovician Heituao Fm. source rock in the slopes and deep basins has a much wider distribution and better quality than the Upper Ordovician, and its quality is also better than those of the Shaergan and Yinggan Fms. source rock within platforms as well as the lime-mud-mound source rock along the fringe of the Upper-Ordovician platform. Most good Lower-Cambrian source rocks of the Kalpin outcrop lie on the initial ingression surface or in the condensed member of the Type I sequence. In this section, the source rock in Type II is inferior to that in Type I, even being far from an effective one (TOC: <0.5%). Likewise, the good Middle-Ordovician Heituao source rock also lies on the initial ingression surface or in the condensed member of the Type I sequence, while the poor Yinggan source rock and the lime-mud-mound along the fringe of the platform develop all in the Type II sequence. Under the condition of the same sea-level rising altitude and time, the ingression displacement (S1) at the base border in Type I is larger than S2 in Type II. Thus, the distribution of the source rock developed above the base border in Type I is wider than that in Type II. The maximal ingression range dominates the ultimate distribution of source rocks. Because S1 is greater than S2, the relative rate of ingression on the base border of Type I is obviously bigger than that of Type II. The difference in ingression rate is one of the factors that lead to the superiority of the source rock at the base border in Type I to that Type II. Therefore, it is of great significance to study the spatial distribution, developing era and quality determination of source rocks by means of sequence stratigrahpy.

Geochemical characteristics of oil from well Shacan 2 in the Tarim Basin

A large amount of oil and gas was discovered from well Shacan 2 on 22 September, 1984. Since then, more oil discoveries have been made from exploration wells. Based on comprehensive studies of the geological and geochemical data, such as physical properties, biomarkers of saturated hydrocarbons and aromatic hydrocarbons, and isotopes of carbon, hydrogen and sulphur, it is found that the oil is characterized by marine algae and lower aquatic organisms. The oil is highly mature, biodegraded and has migrated far from the source. The isomerization of all the biomarkers in the oil is close to or equal to the thermal balance values. In addition, it has some characteristics of Lower Paleozoic oil in the aspects of n-alkane gas chromatography, monoaromatic steroid components and the composition of the isotopes of carbon and sulphur. From geochemical characteristics and an evaluation of the source rocks existing in the area, the oil is postulated to originate from marine Cambrian-Ordovician source rocks.