Lower Cambrian Source Rocks Research Articles

Characteristics of Dengying Fm sedimentary sequence in the central–western Sichuan Basin and their controlling effect on gas accumulation

A large gas reservoir in the Sinian Dengying Fm was recently discovered in Anyue area, central Sichuan Basin. In order to promote the oil and gas exploration in this area, it is of great significance to sustainably deepen the analysis on its high-quality reservoir distribution and source-reservoir assemblage. In this paper, a series of studies were performed on the sequence frameworks and sedimentary filling evolution characteristics of the Dengying Fm in central–western Sichuan Basin, and their controlling effects on the reservoir development and distribution and source-reservoir assemblage during its sedimentation. It is shown that the Deyang–Anyue paleo-rift is, on the whole, distributed in a NW direction, and is morphologically wide and steep in the north, but narrow and gentle in the south. There are two rift boundaries of the second and fourth members of Dengying Fm (Deng 2 Member and Deng 4 Member, respectively). The rift of Deng 2 Member is distributed in the shape of “U” in Deyang–Neijiang area. Dengying Fm is divided into four third-order sequences (SQ1–SQ4). In SQ3 of Gaoshiti–Moxi area, central Sichuan Basin, a complete sedimentation reflection structure of transgressive overlap and regressive progradation can be identified with early–middle Deng 4 Member platform margin. The paleo-rift was in embryo before the sedimentation of Sinian, so the sedimentary filling and lithofacies distribution of the Sinian were influenced by the inherited activities of pre-Sinian rifts. The favorable distribution zones of high-quality reservoirs are located at the rift margins of Deng 2 and Deng 4 Members that were formed respectively during the SQ2 and SQ4 and the platform margin of early Deng 4 Member that was formed during the SQ3. A laterally connected source-reservoir assemblage occurs at the margins of Deng 2 and Deng 4 Members around the Lower Cambrian source rocks of the paleo-rift. The northwestward extending margin zone along the eastern flank of the paleo-rift shows a good potential for hydrocarbon accumulation.

Source characterization of highly mature pyrobitumens using trace and rare earth element geochemistry: Sinian–Paleozoic paleo-oil reservoirs in South China

Understanding the relationships between migrated hydrocarbons and source rocks under highly mature conditions (i.e., pyrobitumen–source correlation) is a critical and challenging issue in the field of petroleum geology and geochemistry. Based on a case study of three Sinian–Paleozoic paleo-oil reservoirs from Yunan and Guizhou provinces, South China, we attempt to provide further understanding of this issue using trace and rare earth element (REE) geochemistry, which can characterize the depositional setting, organic input and rock provenance of source rocks. Results show that the bitumens from the three paleo-oil reservoirs can be distinguished from each other using ‘Post-Archean Australian Shale (PAAS)’-normalized trace element distribution patterns, REE distribution patterns, hierarchal cluster analysis of element concentrations and redox- and provenance-sensitive elemental ratios (e.g., V/Ni, Ni/Co, Ni/Mo, Zr/Cr, La/Sc and La/Co). Pyrobitumen in the Devonian Xiaocaoba paleo-oil reservoir is derived primarily from Devonian source rocks, representing a self-sourced petroleum system and one stage hydrocarbon charging. Similarly, pyrobitumen in the Sinian Jinsha–Yankong paleo-reservoir also received a single fluid charge, but the source is different and likely generated by contributions from both lower Cambrian and Sinian sources. In contrast, the bitumen in Ordovician Kaili–Luomian paleo-reservoirs are indicated to have contributions from two different hydrocarbon sources and thus experienced two stages of hydrocarbon charging: an early charge from lower Cambrian source rocks and a later charge from Permian source rocks. The new trace and rare earth element method used in this study appears to be effective at providing a better understanding of the hydrocarbon–source correlation under highly mature conditions. The results improve our understanding of the complex hydrocarbon accumulation–alteration evolution in the marine strata of South China, which is a potential target for petroleum exploration.

Tectonic fracture and its significance in hydrocarbon migration and accumulation: a case study on middle and lower Ordovician in Tabei Uplift of Tarim Basin, NW China

Middle and lower Ordovician carbonate rock in the Tabei Uplift of the Tarim Basin forms important fractured reservoir beds. Core and log data indicate that tectonic fractures, as the main fractures in the Tabei Uplift, could be mainly classified into two types: oblique fractures and approximately vertical fractures. The fractures are mainly NNW‐trending and NNE‐trending, coincident with the large faults nearby. Fracture abundance was also controlled by lithology, and faults nearby played a significant role. Cores, thin sections and tests show that these carbonate rocks have as much as 2.5% fracture porosity and as much as 150 md fracture permeability. Based on the intersection of fractures in cores, together with fluid inclusion temperature data, and the timing of faulting from seismic profiles, tectonic fractures were considered to be mainly formed in three periods: the late Silurian when the first‐stage oblique fractures were formed, the late Permian when approximately vertical fractures were formed, and the late Tertiary when the second‐stage oblique fractures were formed. Lower Cambrian source rocks started to enter the stage of generous hydrocarbon generation and expulsion in the Silurian. Ordovician source rocks started to enter the stage of generous hydrocarbon generation and expulsion in the Permian and enter the over‐mature stage in the late Tertiary when light oil was generated. Timing of tectonic fractures formation and burial history analysis suggest that fractures formation might coincide with oil accumulation when fractures provided the pathway and storage space for the low permeability and low porosity reservoir beds caused by previous compaction and cementation. Considering the presence of a large amount of fracture‐developed dolomite in the deeper Ordovician Penglaiba Formation, the undrilled Penglaiba Formation should be paid more attention. Copyright © 2015 John Wiley & Sons, Ltd.

The study on the source of the oil seeps and bitumens in the Tianjingshan structure of the northern Longmen Mountain structure of Sichuan Basin, China

The Tianjingshan structure of the northern Longmen Mountain is located in the north of the Sichuan province, China. Two primary source rocks are present in this region, the overmature Infracambrian-Lower Cambrian source rocks and the mature Upper-Permian source rocks. Oil seeps and solid bitumens occur extensively in the Mesozoic and Paleozoic marine strata, indicating good exploration prospects in this area. However, oil-to-source correlation in the Tianjingshan structure is difficult due to both high maturity of the Lower Cambrian source rocks and severe biodegradation of oil seeps and bitumens.In this work, one oil seep from the Permian Qixia Formation and two severely degraded bitumens from the Cambrian strata in the Tianjingshan structure were correlated with their potential source rocks. Hydropyrolysis was used to release biomarkers bound to kerogen of the overmature Lower Cambrian source rock. The released biomarkers were used for the oil-to-source correlation together with those indexes resistant to thermal degradation and biodegradation. Based on the geochemical data and the petroleum geological settings of the area, it can be inferred that the Cambrian, Ordovician and Silurian bitumens with light bulk isotopic values (commonly δ13C < −34.0‰) were sourced from the Infracambrian -Lower Cambrian source rocks, while the oil in the Permian reservoir was initially charged by the oil from the Infracambrian-Lower Cambrian source rocks and then later charged by the oil from the Upper-Permian source rocks. The Infracambrian-Lower Cambrian source rocks are the major oil source in the Tianjingshan structure. The Upper-Permian source rocks only partly contributed to the reservoirs in the neighbouring strata.

Formation and destruction processes of upper Sinian oil-gas pools in the Dingshan-Lintanchang structural belt, southeast Sichuan Basin, China

The lower Cambrian Niutitang Formation hydrocarbon source rocks at the Dingshan-Lintanchang structure in the southeast Sichuan Basin were of medium-good quality with two excellent hydrocarbon-generating centers developed in the periphery areas, with a possibility of forming a medium to large-sized oil-gas field. Good reservoir rocks were the upper Sinian (Dengying Formation) dolomites. The mudstone in the lower Cambrian Niutitang Formation with a good sealing capacity was the cap rock. The widely occurring bitumen in the Dengying Formation indicates that a paleo oil pool was once formed in the study area. The first stage of paleo oil pool formation was maturation of the lower Cambrian source rocks during the late Ordovician. Hydrocarbon generation from the lower Cambrian source rocks stopped due to the Devonian-Carboniferous uplifting. The lower Cambrian source rocks then restarted generation of large quantities of hydrocarbons after deposition of the middle Permian sediments. This was the second stage of the paleo oil pool formation. The oil in the paleo oil pool began to crack during the late Triassic and a paleo gas pool was formed. This paleo gas pool was destroyed during the Yanshan-Himalayan folding, uplifting and denudation. Bitumen can be widely seen in the Dengying Formation in wells and outcrops in the Sichuan Basin and its periphery areas. This provides strong evidence that the Dengying Formation in the Sichuan Basin and its periphery areas was once an ultra-large structural-lithologic oil-gas field, which was damaged during the Yanshan-Himalayan period.

Cracking conditions of crude oil under different geological environments

There are mainly 3 kinds of existing states of oil generating from source rocks, that is, dispersive liquid hydrocarbon inside of source rock, dispersive liquid hydrocarbon outside of source rock and concentrated liquid hydrocarbon outside of source rock. Because of the differences in thermal history and medium conditions around, and the interaction of organic and inorganic matter, the liquid hydrocarbon with 3 kinds of existing state has different cracking conditions. The gas generation dynamics experiments of crude oil matching different mediums indicate that the distribution of activation energy of methane changes a lot according to medium difference. The carbonate has a main influence on oil cracking conditions and can largely reduce its activation energy, which reflects the lower cracking temperature of crude oil. The mudstone takes a second place and the sandstone is the smallest. The catalytic cracking function to the oil of the carbonate, of the mudstone and of the sandstone changes weaken in turn. The corresponding Ro values of main gas generation period in different mediums are as follows: 1.5%–3.8% with pure crude oil, 1.2%–3.2% with dispersive crude oil in carbonate, 1.3%∼3.4% with dispersive crude oil in mudstone and 1.4%–3.6% with dispersive crude oil in sandstone. The influence of pressure to crude oil cracking is relatively complicated. In the low heating speed condition, pressure restrains the oil cracking and gas generation, but in the high heating speed condition, pressure has an indistinctive influence to the oil cracking and gas generation. Pressure also makes a different effort in different evolvement stage. Taking the middle and lower Cambrian source rocks in the Tarim Basin as an example, primary oil generating quantity is 2232.24×108t, residual oil and oil cracking gas quantity is 806.21×108t and 106.95×1012m3 respectively.

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.

Petroleum System in the Southeastern Siberia: From Proterozoic Sources to Cambrian Traps

Southeastern Siberia is the most explored part of the vast Lena-Tunguska petroleum province. It consists of three basic structures: PredPatom trough, Nepa-Botuobin anteclise, and Angara-Lene terrace. Main potential source rocks are largely upper Proterozoic within the PredPatom trough. Other Lower Cambrian source rocks are scattered to make up only 7-9% of the regional petroleum potential. Over 90% of oil and gas discovered to date is reservoired in the Riphean-Cambrian subsalt section on the Nepa-Botuobin and Angara-Lena regional highs. A thick Cambrian salt-bearing section provides a good seal. The main stage of hydrocarbon migration occurs in Vendian - Cambrian time out of the PredPatom trough. Traps are combining stratigraphic wedging out with structural features and reefs. Many of those were affected by late Paleozoic-early Mesozoic volcanic traps, sills, and/or overthrust tectonics. There are over 25 discoveries (mostly gas and condensate) in the region. About two of these are considered giant fields. Math modeling of hydrocarbon generation processes shows that significant petroleum potential is yet to be discovered, particularly in the PredPatom trough.