Stages Of Thermal Evolution Research Articles

Mechanisms of Reservoir Space Preservation in Ultra-Deep Shales: Insights from the Ordovician–Silurian Wufeng–Longmaxi Formation, Eastern Sichuan Basin

This study aims to explore the reservoir characteristics and formation mechanisms of ultra-deep shale gas in the Ordovician–Silurian Wufeng–Longmaxi Formation in the Sichuan Basin in order to provide theoretical support and practical guidance for the exploration and development of ultra-deep shale gas. With recent breakthroughs in ultra-deep shale gas exploration, understanding its organic matter development, mineral composition, and reservoir space characteristics has become particularly important. The background of this research lies in the significant potential of ultra-deep shale gas, which remains inadequately understood, necessitating an in-depth analysis of its pore structure and reservoir quality. Through a systematic study of the ultra-deep shale in well FS1 of Sichuan Basin, that the following was found: (i) The ultra-deep shale in the Wufeng–Longmaxi Formation is mainly composed of quartz and clay minerals, exhibiting high total organic carbon (TOC) and high porosity characteristics, indicating it is in an overmature thermal evolution stage. (ii) Organic pores and microcracks in the ultra-deep shale are more developed compared to middle-shallow and deep shale, forming a complex pore structure that is conducive to gas storage. (iii) In the diagenesis process, the dissolution and recrystallization of the biogenic skeleton promote the cementation between autogenetic quartz particles, forming a rigid skeleton that effectively inhibits the impact of mechanical compaction. (iv) The overpressure environment created by the hydrocarbon generation process, along with gas production from hydrocarbon cracking, can effectively offset the mechanical compaction of overburden pressure on micropores, and this overpressure environment also promotes the further development of microfractures, which is beneficial for the development and preservation of ultra-deep shale pores. In summary, this study not only reveals the reservoir characteristics and formation mechanisms of ultra-deep shale but also provides essential references for the exploration and development of ultra-deep shale gas in the Sichuan Basin and similar regions, emphasizing the ongoing significance of research in this field.

Types of lithofacies in the Lower Cambrian marine shale of the Northern Guizhou Region and their suitability for shale gas exploration

The lithofacies and thermal maturity of the over-mature Lower Cambrian marine shale in the Northern Guizhou Region, and their impacts on reservoir properties in this shale were analyzed by combining geochemistry, mineralogy, and gas adsorption methods. Ten lithofacies were identified, and the dominant lithofacies in the studied shale are lean-total organic carbon (TOC) argillaceous-rich siliceous shale (LTAS), medium-TOC siliceous shale (MTSS), and rich-TOC siliceous shale (RTSS). Since the gas generation potential of organic matter was weak, meso- and macro-pores were compressed or filled during the thermal evolution stage with a vitrinite reflectance (RO) range of 3.0%–4.0%. The controlling factors for methane adsorption capacity in the shale samples are significantly influenced by TOC content rather than thermal maturity. Among the RTSS, MTSS, and LTAS samples, RTSS exhibits the highest favorability for preserving hydrocarbon gas, followed by MTSS. The shale types in this study play a significant role in determining the properties of shale reservoirs, serving as an effective parameter for evaluating shale gas development potential. The RTSS and MTSS with a RO range of 2.0%–3.0% stand out as the most favorable target shale types for shale gas exploration and development.

High-velocity oblique impact experiments on ice and snow spheres: Implications for the collisional evolution of icy planetesimals at different thermal evolution stages

In order to determine the effect of impact angle on the impact strength of icy planetesimals, we conducted a range of oblique impact experiments for spherical ice and snow targets simulating icy planetesimals at different thermal evolution stages. The ice targets had no porosity and the snow targets had a porosity of 0.5. A polycarbonate or glass sphere impacted the ice targets at 744–1747 m s−1 and the snow targets at 938–5085 m s−1 over a range of impact angles from grazing to head-on collisions. All experiments were conducted using a two-stage light gas gun and a target chamber set in a cold room of −15 °C at Kobe University, Japan. The impact strength, which is a specific energy, Q, when the largest fragment mass is a half of the original target mass, for the ice and snow targets in a head-on collision was determined to be 12 and 520 J kg−1, respectively, whereas it was found that the impact strength depended on the impact velocity. Thus, the normalized largest fragment mass, ml/Mt, could well scale with the velocity dependent Q, that is, Qviγ (where ml and Mt are the masses of largest fragment and target, respectively, and vi is the impact velocity). At high Q, ml/Mt increased drastically with the decrease of impact angle when the impact angle was smaller than a critical angle, θc, and θc~30° for the ice targets and θc~45° for the snow targets. At small Q, ml/Mt continued to increase as the impact angle became smaller for both types of targets. The ml/Mt for oblique impacts had a good correlation with the effective specific energy, Qeff=Qsin2θ, where θ is the impact angle, and the effective impact strength was determined to be 16 J kg−1 and 499 J kg−1 for the ice and snow targets, irrespective of the impact angle. Furthermore, the scaling parameter, Πs_eff, which was proposed by Housen and Holsapple (1990) but includes Qeff instead of Q, multiplied by 1−ϕλ, where ϕ is the porosity, showed even better correlation with ml/Mt, and all ml/Mt data of ice and snow targets could be merged, irrespective of impact velocity and ϕ. Based on our experimental results and a theory on the oblique impact of solar system bodies proposed by Shoemaker (1962), we could estimate the degree of disruption (ml/Mt) at any impact energy and any impact angle for icy planetesimals. Our findings demonstrate that the degree of disruption for icy planetesimals that have experienced sufficient thermal evolution was larger than that for those that did not experience significant thermal evolution.

Mesozoic and Cenozoic Tectono-Thermal Reconstruction of the Southern Ordos Basin: Revealed by Apatite Fission Track and (U-Th)/He Dating

The Ordos Basin is rich in oil and gas resources in the Paleozoic strata. The southern part of the basin boasts a thick Paleozoic sedimentary sequence, enriched organic matter, favorable sedimentary facies, and hydrocarbon source rocks with an over-mature thermal evolution stage. However, the lack of in-depth study of the tectono-thermal evolution in the southern basin limits regional oil and gas exploration. In this study, drill core and outcrop samples were collected from the Shanbei Slope and the Weibei Uplift, respectively. These samples were subjected to apatite fission track (AFT) and (U-Th)/He dating (AHe). The results were used to reconstruct the thermal history of the southern basin, calculate exhumation rates, and analyze the tectonic evolution of the basin. The seven annealed AFT data values from the Shanbei Slope range from 21.4 to 52.8 Ma, with mean track lengths of 13.24 μm, and the twelve unannealed AFT data values from the Weibei Uplift range from 111.9 to 204.6 Ma. The seven AHe data values from the Shanbei Slope range from 17.0 to 31.8 Ma, and the eight AHe data values from the Weibei Uplift range from 31.7 to 47.5 Ma. The thermal history is characterized by a prolonged phase of burial and heating from the Triassic to the Late Early Cretaceous, followed by a phase of uplift and cooling that continued into the Cenozoic. This cooling phase exhibits three distinct stages with varying rates of uplift and cooling. According to the dating results, the cooling timing of the southern basin was earlier than that of the central part, and the southern basin experienced higher uplift rates during the Paleogene than in other periods of the Cenozoic. This may be attributed to the far-field effects of the collision between the Indian Plate and the Eurasian Plate during the Paleogene.

The implication of kinetics characteristics of modern organisms for the hydrocarbon generation evolution of organic matter components in the lacustrine source rocks: A case study of the Dongying Formation from the Bozhong Sag, Bohai Bay Basin

The hydrocarbon generation evolution characteristics of lacustrine source rocks are crucial for understanding hydrocarbon resources. In this research, we focus on the mudstone found in the third member of the Paleogene Dongying Formation (E3d3) within the Bozhong Sag of the Bohai Bay Basin as a case study. An analysis of the discrepancy in geochemical characteristics and kinetic parameters was carried out by utilizing the modern organisms (pine pollen and benthic algae) analogies to the organic matter (OM) components (Pinaceae sporopollen and benthic algae amorphous). Furthermore, the bulk hydrocarbon evolution of the Dongying Formation mudstones was further discussed in combination with a water-added sealing thermal simulation experiment and basin simulation. Our findings indicate that the pine pollen and benthic algae have higher OM abundance compared to the E3d3 mudstones, and their OM types are both Ⅱ1-Ⅱ2, which possess excellent potential for oil generation. In contrast, the E3d3 mudstones are predominantly in the low mature to mature thermal evolution stage. When we compare hydrocarbon generation rates and transformation ratios using Rock-Eval pyrolysis, it becomes evident that modern organisms are more prone to generate large amounts of hydrocarbons even at a low mature stage. The kinetic parameters of pine pollen are notably higher compared to those of benthic algae and the E3d3 mudstone samples. In parallel first-order reactions, the activation energy obtained by the single-frequency factor model (SFFP model) displays a narrow distribution range, while the activation energy distribution range of the multi-frequency factor model (MFFP model) is broader. The MFFP model focuses more on the variations of hydrocarbon kinetic parameters throughout the entire process, which is more in conformity with the actual geological process. The enclosed thermal simulation experiment and basin simulation analysis unveil the presence of two distinct phases of hydrocarbon generation within the Dongying Formation. Furthermore, it becomes evident that abundant benthic algae and Pinaceae sporopollen components play vital roles in both of these phases. In conclusion, the method of applying modern organisms to analogize the hydrocarbon generation evolution characteristics of the parent components of lacustrine source rocks seems feasible. Meanwhile, the Dongying Formation in the Bozhong Sag also possesses broad exploration prospects for hydrocarbon resources.

Structural characteristics of continental carbonate-rich shale and shale oil movability: A case study of the Paleogene Shahejie Formation shale in Jiyang Depression, Bohai Bay Basin, China

Based on rock mineral and geochemical analysis, microscopic observation, physical property measurement, and thin laminae separation test, etc., the characteristics of typical laminae of the Paleogene Shahejie Formation carbonate-rich shale in the Jiyang Depression were analyzed, and the organic matter abundance, reservoir properties, and oil-bearing properties of different laminae were compared. Typical shale storage-seepage structures were classified, and the mobility of oil in different types of shale storage-seepage structure was compared. The results show that the repeated superposition of mud laminae and calcite laminae are the main layer structure of carbonate-rich shales. The calcite laminae are divided into micritic calcite laminae, sparry calcite laminae and fibrous calcite vein. The mud-rich laminae are the main contributor to the organic matter abundance and porosity of shale, with the best hydrocarbon generation potential, reservoir capacity, and oil-bearing property. The micritic calcite laminae also have relatively good hydrocarbon generation potential, reservoir capacity and oil-bearing property. The sparry calcite laminae and fibrous calcite vein have good permeability and conductivity. Four types of shale storage-seepage structure are developed in the carbonate-rich shale, and the mobility of oil in each type of storage-seepage structure is in descending order: sparry calcite laminae enriched shale storage-seepage structure, mixed calcite laminae enriched shale storage-seepage structure, fibrous calcite vein enriched shale storage-seepage structure, and micritic calcite laminae enriched shale storage-seepage structure. The exploration targets of carbonate-rich shale in the Jiyang Depression Shahejie Formation are different in terms of storage-seepage structure at different thermal evolution stages.

Evolution of organic pores in Permian low maturity shales from the Dalong Formation in the Sichuan Basin: Insights from a thermal simulation experiment

Shale oil and gas exploration is greatly impacted by the development and evolution of organic pore structures. In order to study the evolution of shale pore structures over maturities, we conducted thermal simulation experiments on low-mature organic-rich shale (Ro = 0.73%, TOC = 9.57%) obtained from the Dalong Formation. Various maturity stages were covered in these experiments, from low to over-maturity. By analyzing mineral composition, organic geochemistry, and characteristics of pore structures at various temperatures used for thermal simulation, we examined how organic matter pores generate and evolve during the formation of shale hydrocarbons. As a result, an integrated model of the evolution of pore structures in organic-rich shale was developed. Our study revealed the following insights: With increasing thermal simulation temperature, shale pore development exhibited three distinct stages: initial development, rapid development, and slow development. These stages correspond respectively to the three stages of organic matter thermal evolution. The distribution of pores in the shale transitioned from a unimodal structure dominated by larger pores to a bimodal structure with both micropores and macropores. Decomposition of organic matter and pressure compaction play a controlling role on organic porosity. Pore structure parameters and fractal dimensions of the pores were primarily influenced by organic matter decomposition, residual liquid hydrocarbons, and diagenetic processes. Additionally, kerogen type, morphology of organic matter debris, symbiosis of minerals-organic matter also impacted pore development.

Genesis and distribution of oils in Mahu Sag, Junggar Basin, NW China

Based on the geological and geochemical analysis of potential source rocks in different formations and the classification of crude oil types, combined with the hydrocarbon generation thermal simulation experiments, the source, genesis, and distribution of different types of oils in the Mahu large oil province of the Junggar Basin are investigated. Four sets of potential source rocks are developed in the Mahu Sag. Specifically, the source rocks of the Permian Fengcheng Formation have the highest hydrocarbon generation potential and contain mainly Types II and I organic matters, with a high oil generation capacity. In contrast, the source rocks in other formations exhibit lower hydrocarbon generation potential and contain mainly Type III organic matter, with dominant gas generation. Oils in the Mahu Sag can be classified as three types: A, B and C, which display ascending, mountainous and descending C20-C21-C23 tricyclic terpenes abundance patterns in sequence, and gradually increasing relative content of tricyclic terpenes and sterane isomerization parameters, indicating an increasing oil maturity. Different types of oils are distributed spatially in an obviously orderly manner: Type A oil is close to the edge of the sag, Type C oil is concentrated in the center of the sag, and Type B oil lies in the slope area between Type A and Type C. The results of oil-source correlation and thermal simulation experiments show that the three types of oils come from the source rocks of the Fengcheng Formation at different thermal evolution stages. This new understanding of the differential genesis of oils in the Mahu Sag reasonably explains the source, distribution, and genetic mechanism of the three types of oils. The study results are of important guidance for the comprehensive and three-dimensional oil exploration, the identification of oil distribution in the total petroleum system, and the prediction of favorable exploration areas in the Mahu Sag.

Resin composition: An indicator of oil maturity as revealed by fourier transform ion cyclotron resonance mass spectrometry

A pyrolysis experiment was carried out on a Dongying Depression kerogen sample to separate the resin from the oil. Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) with a positive-ion detector was used to detect the relative proportional changes in the compounds of the resin. During the whole pyrolysis experiment, the relative ratio of resin exceed 10% of the soluble component at each temperature point. Five compounds were detected from the resin: N1, N1O1, N1O2, O1, and O2. To research the changes in the proportions of the compounds during pyrolysis clearly, these five compounds were divided into three classes: N1, N1Ox, and Ox. The N1 class has the largest proportion in resin at the beginning of the pyrolysis, while Ox class has the least proportion. And the relationship between the number and the molecular mass of three classes compound was researched. With increasing maturity, the proportion of N1 and the N1Ox class decreased rapidly, while the Ox class increased slowly. Through researching these resin compounds, it was found that an inversion in the proportions of above three compounds appeared at the end of the oil window. At the same time, we found that the DBE and carbon number of resin compounds have changed obviously during the pyrolysis: the DBE increased, while the carbon number decreased significantly. And the details of the change of each compound have been research. This research extends our knowledge of judging the maturity of crude oil during the pyrolysis through the characteristics of compounds in resin and provides the new index based on resin for the evaluation of thermal evolution stage and hydrocarbon generation capacity of source rocks.

Seismic interpretation and geological evaluation of hydrocarbon source rocks in volcanic-rich continental lacustrine rift basins: A case study of the Lower Cretaceous Yingcheng Formation from the Changling Fault Depression in the Songliao Basin, NE China

The Lower Cretaceous Yingcheng Formation in the Changling Fault Depression in the Songliao Basin is composed of volcanic-rich continental lacustrine rift basin sediments. Its complex stratigraphic structure and the difficulty in predicting the hydrocarbon source rock distribution restrict the exploration and evaluation of deep hydrocarbons in this region. This paper uses seismic stratigraphy to divide the strata and interpret dark mudstone layers based on logging and seismic. These data are combined with geochemical test data from hydrocarbon source rocks to assess its quality and predict its distribution. This study indicates that the three types of unconformities identified divide the Yingcheng Formation into four sedimentary sequences. In the Yingcheng Formation depositional period, the number of grabens or half-grabens associated with the Changling Fault Depression decreased, the size of the rift basins increased, and the depositional center migrated to the north and west. During the depositional period of the First and Second Members, volcanic rocks were widely developed, and mud sediments were deposited between several small grabens or half-grabens. During the depositional period of the Third and fourth Members, the study area became a unified lacustrine rift basin with clearly defined geological signatures developed in each sedimentary sequence, which can be divided into three systems tracts. Mudstones in the Lake Transgressive Systems Tract are laterally continuous and widely distributed. The organic matter in these mudstones, with fair to good abundance levels, is predominantly type II2 and type III kerogen and all have reached mature to highly mature stage of thermal evolution, which are favorable hydrocarbon source rock layers. In plan view, the favorable hydrocarbon source rock zones are mostly formed in the Changling Sag, Dongling Structural Zone and Longfengshan Sag. This study offers guidance and direction for deep hydrocarbon exploration in the Changling Fault Depression, and also provides a reference for methods and ideas to predict hydrocarbon source rock distribution in other lacustrine rift basins.

Characteristics of Liquid-Hydrocarbon Yield and Biomarkers in Various Thermal-Evolution Stages: A Simulation Experiment with the Middle Jurassic Source Rocks in the Northern Margin of the Qaidam Basin

Although there are many studies on the Jurassic source rocks in the northern margin of the Qaidam Basin, the characteristics of biomarkers and products with the same source rock in different evolutionary stages are still not well understood. Such an understanding is essential for accurately estimating oil and gas resources. In order to explore the hydrocarbon-generation potential of high-quality source rocks of the Middle Jurassic and the evolution of liquid hydrocarbons and biomarkers, we carried out simulation research (under hydrous conditions) at various temperatures (250, 300, 350, 400 and 450 °C) with the mudstone of the Yu 33 well in the Yuka Sag. The results revealed that the “oil window” of the Middle Jurassic source rocks in the Yuka area was 300 °C (simulation temperature, Ro = 0.84%), but this was not the peak of hydrocarbon expulsion, which was gradually reached and stabilized above 350 °C. Overall, the concentration of alkanes and aromatics increased with temperature; although the concentration of alkanes was complex in the low evolutionary stages, temperature (simulated maturity) was still the main factor controlling the change in alkanes and aromatics. Among the maturity parameters of biomarkers, the ratio of ∑tricyclic terpanes/∑hopanes was the most effective parameter for indicating the maturity evolution of the Yuka area, but others were complicated by the increasing temperature. Therefore, when evaluating maturity, the applicability of other parameters needed to be fully considered. The results obtained offer new insights in the research on liquid-hydrocarbon and biomarker evolution of the Middle Jurassic source rocks in the Yuka Sag of the Qaidam Basin.

Laminar Structure and Reservoir Quality of Shales with High Clay Mineral Content in the Qingshankou Formation, Songliao Basin

This paper investigates high-maturity organic matter-rich shales with high clay mineral contents in the Qingshankou Formation, in the Gulong Depression of the Songliao Basin, at a sub-millimeter scale, using a new laminar division method based on XRF data. The influence of laminar structure on reservoir quality is examined using a combination of geochemistry, mineralogy, and pore structures. Explanatory models are established. Three types of laminar units are distinguished in the study area based on differences in pore structure. These are clay mineral laminae (UA), clay mineral-Ostracod laminae (UB), and clay mineral-felsic laminae (UC). UA has illite intergranular pores, micro-fractures, and organic pores, with diameters of 0.5~2 μm. UB primarily contains Ostracod shell margin fractures, pyrite intergranular pores, and chlorite intragranular pores. UC contains albite and illite intergranular pores. Nitrogen adsorption tests show that UA has the highest clay content and the best specific pore volume and specific surface area, indicating that clay minerals are the main contributors to the pores in this type of unit. 2D–3D models of different laminae reveal that carbonate cement is widely developed in UB and UC, but dissolution pores are less developed, with the result that the porosity of UA is two to three times greater than that of UB or UC. It appears that intergranular pores and fractures, formed during the transformation of clay minerals during the advanced thermal evolution stage, are the main contributors to storage space and flow channels. Thermal evolution, clay mineral transformation, and carbonate cementation are the key factors causing differences between laminar units. In addition, clay mineral laminae (UA) are the most important laminar units for shale oil enrichment in the study area. This finding is of great significance for accurately predicting the distribution of shale “sweet spots” and guiding shale oil and gas exploration.

Impact of thermal maturity on the diagenesis and porosity of lacustrine oil-prone shales: Insights from natural shale samples with thermal maturation in the oil generation window

Shale diagenesis controls the generation, migration and accumulation of hydrocarbons through time and has become a frontier area of study in the fields of sedimentology and petroleum geology. There have been only a few studies on the generation of organic pores in lacustrine shale oil reservoirs during the oil generation thermal evolution stage. In this study, lacustrine organic-rich shale samples at various stages of maturity, from the first member of the Songliao Basin Qingshankou Formation were investigated, and a thermal transformation law of macerals was established, based on organic petrology. The diagenetic alteration styles and sequences were investigated using a high-resolution field emission scanning electron microscope, and cathode luminescence. Furthermore, automated pore extraction technology enabled the examination of the characteristics and genetic process of organic and inorganic pores under the influence of thermal maturation. The results indicate that a small quantity of pre-oil bitumen is generated during the early oil mature stage (Ro: 0.7% - 0.9%), and that the generation of a large quantity of post-oil bitumen that occurs following the peak oil generation stage (i.e., late oil mature stage, Ro: 1.1% - 1.4%), is controlled by the unimodal distribution of the activation energy of Type I kerogen. Compaction intensity certainly influences pore volume reduction. Siliceous cementation primarily occurs during peak oil generation maturity and the subsequent thermal evolution stage. The pores formed in the oil generation window primarily arise from mineral dissolution and organic matter polycondensation. Following peak oil generation, the pores undergo iron dolomitization, smectite illitization, and bitumen cracking. The degree of development of inorganic pores, the most common pore type in shale oil reservoirs, appears to have a significant impact on the total porosity of a reservoir shale. During thermal evolution, the inorganic pore volumes show a decreasing trend. There is a secondary pore development stage, reached when Ro exceeds 1.2%, closely related to the transformation of clay minerals. According to the hydrocarbon generation kinetics and compaction model, organic pore volumes increase gradually at 0.7%Ro, reach their peak at 1.1%Ro, and then steadily decrease due to compaction. The organic pores are relatively well developed when Ro is >0.85% (at the start of the oil window). The shale oil reservoir's most favorable thermal evolution stage is late oil maturity stage that follows the oil generation peak.

Geochemical characteristics of crude oils and hydrocarbon accumulation in the Palogue Oilfield, Melut Basin, South Sudan

The Palogue Oilfield is the largest oilfield in the Melut Basin, an important petroliferous rift basin in Africa. Geochemical analyses, including gas chromatography and gas-mass chromatography were adopted to analyze the biomarker composition and geochemical characteristics of oils from the Palogue Oilfield and the neighboring Moleeta and Jamous lows. Oil-oil correlations were performed for the Palogue Oilfield and the Moleeta/Jamous lows, and the hydrocarbon accumulations of the Palogue Oilfield were studied based on the oil maturities, thermal evolution modelling of the Moleeta/Jamous lows and the petroleum system analysis of the Melut Basin. Geochemical analysis indicates that the oils of the Moleeta/Jamous lows are derived from terrestrial higher plants, with the low ratios (<1) of light n-alkanes to heavy n-alkanes (∑nC21-/∑nC22+) and the predominance of C29 regular sterane, but there still are some geochemical differences in distribution shape of n-alkanes, paleoenvironments and maturities in these two lows. The oils of the Palogue Oilfield have mixed-source features and their geochemical characteristics are more like those of the Jamous low, and a few oils are like the oils in the Moleeta low. The Jamous low has a larger area and higher thermal maturity than the Moleeta low, and the abundant oils generated by the Al Renk source rocks (upper part of early Cretaceous) in the Jamous low are the primary contributors to the formation of the giant Palogue Oilfield. The vitrinite reflectance equivalent (Rc) converted by the methyl phenanthrene ratio indicates that the oil maturities of the Palogue Oilfield range from 0.65% to 1.07%. Thermal evolution modelling of the Moleeta/Jamous lows indicates that the Jamous low generated and expelled hydrocarbons earlier than the Moleeta low. The maturity of Al Renk source rocks reached 0.65% at 70Ma (Late Cretaceous) and 1.07% at 38Ma (Eocene) in the Jamous low, and reached 0.65% at 59Ma (Paleocene) and 1.07% at present in the Moleeta low. Thus, the high-maturity oils (Ro> 1.07%) generated by the source rocks in the Jamous low since 38 Ma have not been discovered in the primary production layers of the Paleogene Samma and Yabus Formations in the higher part of the Palogue structure, a drape-anticline developing on a paleo-high between the Jamous and Moleeta lows. The maturity parameter of Ts/(Ts + Tm) shows that the oil maturities from late Cretaceous Formation in the well PS-7 and PS-8 are close to the oils in the Jamous Low and are significantly higher than the oils from the Paleogene Formation in the higher part of the Palogue structure. So, the Cretaceous Formation under the Paleogene pay zones and the Paleogene Formation in the lower part of the Palogue structure likely accumulated high-maturity oils from the Jamous low, which will enhance the exploration potential of the Palogue Oilfield. The petroleum system study indicates that the end of Oligocene (late Paleogene) is the critical moment for the Paleogene hydrocarbon accumulations in the Melut Basin. Whereas, the high-maturity oil accumulations (Ro> 1.07%) in Cretaceous formations in the Palogue Oilfield occurred after 38Ma (late Eocene), when the Al Renk source rocks in the Jamous low started to enter the high thermal evolution stage with the Ro> 1.07%.

Geological characteristics and shale oil potential of alkaline lacustrine source rock in Fengcheng Formation of the Mahu Sag, Junggar Basin, Western China

Shale oil is the main field of unconventional hydrocarbon exploration and exploitation. Additionally, deep (>4500 m) petroleum exploration in sedimentary basins is a worldwide frontier topic. The Fengcheng Formation in the Junggar Basin is deeply buried and formed in the special sedimentary environment of alkaline lakes. Studying this set of source rocks will provide insights into the deep unconventional hydrocarbon exploration in other basins with similar geologic settings worldwide. Therefore, this research takes Fengcheng shale as the object to systematically analyze the geochemical characteristics, reservoir quality, and shale oil resources’ potential based on total organic carbon (TOC), Rock-Eval pyrolysis, vitrinite reflectance (Ro), X-ray diffraction (XRD), field emission-scanning electron microscopy (FE-SEM), and other experimental methods.The Fengcheng shale has moderate organic matter abundance (0.5%–2.0%) and high hydrocarbon generation potential (averaging 3.95 mg/g). The shale is mainly comprised of type II kerogen, which can easily generate oil. Meanwhile, the source rock has reached the mature to high-mature thermal evolution stage. The mineral composition reveals the shale of Fengcheng Formation mainly contains higher values of carbonate minerals and lower quantities of clay minerals. Shale has poor physical properties, with porosity ranging from 1.0 to 12.0% (3.37% on average) and permeability generally lower than 0.1mD. However, the Fengcheng shale has a significantly higher brittleness than the North American marine shales and has good conditions for hydraulic fracturing. The pores developed in the shale are mainly intergranular, micro-fractures, and intragranular pores, while organic pores are rare. Generally, the hydrocarbon of the shale mainly exists in inorganic pores. Fractures are well developed in shale, and many micro-fractures and macro-fractures can be seen in the core. These fractures are important for hydrocarbons migration and accumulation. The shale oil saturation index OSI and S1 show that despite the migration of some hydrocarbons from the source rocks of the Fengcheng Formation, a large amount of crude oil is still retained, and a considerable part of the shale oil is movable oil. It indicates that Fengcheng shale is rich in shale oil resources and is a favorable target for shale oil exploration and exploitation.

Hydrocarbon generation potential and model of the deep lacustrine source rocks in the Dongying Depression, Bohai Bay Basin

The deep mudstone in the Palaeogene of the Dongying Depression has been relatively deeply buried and is a useful example of a deep source rock. We use TOC, rock pyrolysis, gas chromatography-mass spectrometry (GC-MS) and vitrinite reflectance (VRo) to evaluate organic matter types, the sedimentary environment, thermal maturity, and hydrocarbon generation potential. Thermal pyrolysis experiments and PVT phase simulation were also used to study the evolution of hydrocarbon generation in these deep source rocks. Two sets of dark mudstone are formed in a reductive salt lake environment, and the organic matter types are mainly I and II. TOC data and pyrolysis experiments show considerable hydrocarbon generation potential. The mudstone samples present low pristane/phytane, high gammacerane/C30hopane, and gammacerane/C31hopane (22R) values, reflecting a strong reduction environment with development of gypsum and salt rocks for the source rocks. A significant effect of maturity on the carbon isotope was indicated, and the carbon isotope values of aromatics are unusually heavier than those of saturated hydrocarbons and resins. The maturity parameters VRo and pyrolysis peak temperature (Tmax) are somewhat reduced owing to the influence of multiple units of gypsum-salt rocks. The VRo values of the two sets of mudstone are in the range 0.74%–1.0% and 0.75%–1.95%, respectively, indicating that these mudstones are mainly moderately mature and high to over mature. The results of thermal simulation experiments of a hypersaline mudstone show that the increase in organic matter maturity is uneven at different stages of thermal evolution, and the increasing rate is relatively fast in the oil generation window. The wide maturity range of the source rocks contributes to the formation of various types of reservoirs, including normal oil, volatile light oil, condensate gas and single dry gas in the deep part of depression; all reservoir types are distributed regularly with burial depth. A detailed hydrocarbon generation model for salt lake facies is proposed to show the evolutionary stages of biogas, bitumen, low mature oil, normal oil, wet gas, volatile oil, condensate gas, and dry gas with increasing thermal maturity. Reservoirs of volatile oil, condensate gas, and dry gas develop at depths of >4000 m. At depths of >4500 m, condensate gas and single dry gas reservoirs mainly exist; these are the main targets for deep petroleum exploration in the area.

Geochemical Characteristics and Genesis of Cambrian Shale Gas in the Southern Margin of Hannan Ancient Uplift

The geological characteristics of shale and the gas composition and carbon isotopic variation from the shale are very important indicators for the shale gas study. This article analyzed the geological characteristics of Cambrian Niutitang shale and focused on the gas composition and carbon isotopic characteristics of the shale gas from the Cambrian Niutitang Formation. We can see that the total organic carbon content ranges from 0.41 to 4.29%, with an average of 1.65%, which is mainly type I and Ⅱ1. The thermal maturity of sample ranges from 1.98 to 2.53%, with an average of 2.30%, which is in the postmature stage of thermal evolution. The Cambrian Niutitang Formation shale gas in the southern margin of the Hannan ancient uplift is the high-quality hydrocarbon gas methane that takes an absolute majority with a content ranging from 89.60 to 99.19% with an average of 96.46%. The wetness of the gas from the study area ranges from 0.06 to 0.42%, with only 0.25% on an average, which is defined as typical dry gas. The distribution of carbon isotope values has partial “reverse” characteristics that are δ13C1 &amp;gt; δ13C2 and δ13C2 &amp;lt; δ13C3. The natural gas of Niutitang Formation in the study area belongs to thermogenic gas. At the same time, it is found that some data points are beyond the range of thermogenic gas, which is mainly due to the low-humidity and heavy carbon isotope value of methane caused by the high maturity of source rock. In the study area, the Niutitang Formation natural gas carbon isotope values are located in Zone III with the characteristics of mixed reversal gas in the δ13C1-δ13C2 part.

Study on the logging response characteristics and the quantitative identification method of solid bitumen at different thermal evolution stages

Solid bitumen is the intermediate products during the oil and gas generation, and widely exists in petroliferous basins all over the world. Besides damaging the reservoir physical properties, solid bitumen affects the logging parameters and is hard to be identified by the conventional logging method. In this study, two different thermal evolution stages of solid bitumen, separately from the Devonian outcrop profile and the Well ST3 in the northwestern Sichuan Basin, are taken as an example. Through a series of analyses on the porosity, permeability, resistivity, S-wave time difference, P-wave time difference and nuclear magnetic resonance (NMR) before and after bitumen dissolution, the logging response characteristics of solid bitumen at different thermal evolution stages are clarified, and the logging quantitative identification method of solid bitumen is established. The results are as below: (1) The solubility of solid bitumen is linearly correlated with the increment of porosity, permeability, P-wave time difference and S-wave time difference, and exponentially correlated with the decrement of resistivity. (2) Under the equal solid bitumen content and with the increase of thermal evolution, the influence of solid bitumen on porosity and permeability gradually decreases, while the influence on acoustic time difference and resistivity gradually increases. (3) Two kinds of NMR logging interpretation models for bitumen reservoir are established based on the NMR response characteristics of solid bitumen at different thermal evolution stages. The solid bitumen from low thermal evolution stage has a strong response in NMR, while that from high thermal evolution stage is otherwise. The Peak 1 (0.1 ms – 10 ms) of the T2 spectrum can respond to most of the low thermal evolution stage solid bitumen, but just a few of the high thermal evolution stage solid bitumen. (4) The NMR logging quantitative calculation methods on different thermal evolution stage solid bitumen are established respectively to solve the difficult issues of quantitative identification of solid bitumen. All the researches above have important guiding significance for the logging quantitative calculation of solid bitumen and the selection of effective oil/gas test layers.

Source rock with high abundance of C28 regular sterane in typical brackish-saline lacustrine sediments: Biogenic source, depositional environment and hydrocarbon generation potential in Junggar Basin, China

In the brackish water sedimentary environment of the Junggar Basin in Xinjiang, the organic-rich shale and shale oil formation with relatively low maturity, is characterized by relatively high abundance of C28 regular steranes. However, the biogenic source of organic matter and favorable sedimentary environment for the type of source rock has been thoroughly classified. In this paper, organic geochemical and petrological, analyses of the Lucaogou Formation shale in the Jimusaer Sag, Junggar Basin in the north of Xinjiang Uygur Autonomy Region were carried out. The source rocks in the Lucaogou Formation are mainly composed of two types of maceral including lamalginite (cyanobacteria) and telalginite (green algae), with the former predominantly fueling the high C28 regular sterane content. Petrological, organic and inorganic geochemical analyses suggest that the lamalginite was developed in low-salinity water while the telalginite was developed in high-salinity water. Based on geochemical and organic petrological characteristics, both the lamalginite and telalginite have good hydrocarbon-generating potential, but in the lower thermal evolution stage of the Lucaogou Formation source rock, telalginite have higher hydrocarbon-generating rate.

Comparison of biomarkers in retained oil and expelled oil of lacustrine marlstone determined by hydrous pyrolysis: Application to hydrocarbon migration determination in the tight oil reservoir

Oil in an unconventional tight reservoir is considered to migrate from a very adjacent reservoir or be impregnated in situ within source rocks, but their large hydrocarbon molecular fractions during short‐distance migration in the tight system are poorly understood. In order to explore the evolution characteristics and differences of the geochemical properties, especially the biomarkers, between expelled oil (just detached from source rock and not undergoing long‐distance migration) and retained oil under different thermal evolution stages of lacustrine marlstone. Semi‐open hydrous pyrolysis was conducted on an immature lacustrine marlstone collected from the third member of the Eocene Shahejie Formation in Shulu Sag, Bohai Bay Basin and the hydrocarbon product expelled from and remained in the rock during pyrolysis were collected and analysed with gas chromatography–mass spectrum instrument. The results indicate that the saturates compositions show expelled oil having commonly lower thermal maturity than retained oil because expelled oil is a mixture of multiple‐term hydrocarbon expulsions, while retained oil is the remained final hydrocarbon product of pyrolysis in semi‐open experimental system. The hydrocarbon migration has a significant effect on the maturity‐related parameters distribution such as 20S/(20S + 20R) and αββ/(αββ + ααα) for C29 steranes. Hydrocarbon expulsion enables Ts/(Ts + Tm) ratio in expelled oil is much greater than that of retained oil at lower matural stage. The saturated hydrocarbon maturity biomarkers in retained oil and expelled oil vary in a subtly different pathways with increasing maturity, comparatively the aromatic hydrocarbon biomarkers, such as triaromatic steroids and methyl‐phenanthrene (MPI1 and MPI2), regularly changed during maturation, which is not obviously affected by migration effects and can be used not only for thermal maturity predications but also for oil–oil or oil–source correlation. C29 20S/(20S + 20R) and C29 αββ/(αββ + ααα) commonly are preferable maturity parameters for shale or mudstone, reflecting that mineral matrix and oil in source rock are not affected by migration and supposed to have an oil thermal maturity corresponding to depth. Combined with some tight reservoir cases in North America and China, the biomarker ratios variation along depth and its abnormal value can be used to predict sweet spots in tight reservoirs.