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The third member of the Upper Triassic Xujiahe Formation (T 3 x3) is a typical source-reservoir-cap unit for natural gas exploration in the Sichuan Basin. However, most previous studies mainly focused on the T 3 x3 as a source rock, ignoring its role as a reservoir. As a result, the evaluation of hydrocarbon resource potential was not accurate. This study established a hydrocarbon generation and expulsion model through analyzing the geological and geochemical characteristics of the T 3 x3 source rocks, and calculated the resource potential of conventional gas, tight gas and shale gas systematically with combining the lower boundary of buoyancy-dominated accumulation (LBBA). The results indicated that the thickness of the source rocks dominated by mudstone was distributed widely, with an average value of more than 45 m. The sedimentary environment was salty lacustrine deposits. They have a high content of total organic carbon (TOC) with an average value of 4.80 wt%, the kerogen is mainly type III with minor type II, and the thermal evolution has entered the high to over mature stage. The hydrocarbon generation threshold was determined to be 0.5%Ro, while the hydrocarbon expulsion threshold and the LBBA were determined to be 0.83%Ro and 1.12%Ro, respectively. The efficiency of hydrocarbon expulsion was relatively high, with an average of about 56%. Also, the maximum hydrocarbon generation and expulsion intensity reached to 110 × 108 m3/km2 and 53 × 108 m3/km2. The amounts of hydrocarbon generation, expulsion and residual associated with the T 3 x3 source rocks were 125.68 × 1012m3, 70.38 × 1012m3, and 55.30 × 1012m3, respectively. Under the criterion condition of the LBBA, the conventional gas resource was 7.21 × 1010m3, the tight gas resource was 294.34 × 1010m3, and the shale gas resource was 2488.50 × 1010m3. It indicated good prospects for exploration. • The geological and geochemical characteristics of source rocks were described. • The hydrocarbon generation and expulsion characteristics were studied by hydrocarbon generation potential method. • The resource potential of conventional and unconventional gas was calculated systemically. [ABSTRACT FROM AUTHOR]

Superimposed basins are commonly characterized by a complex distribution of oil and gas accumulations. Because they have generally experienced multistage hydrocarbon accumulation and tectonic movement, it is challenging to predict favorable exploration zones in these basins. The exploration of the deep strata of the Sichuan Basin (i.e., a typical superimposed basin), West China, has been unsatisfactory for petroleum prospectors. Therefore, we chose the Cambrian Longwangmiao Formation in the Sichuan Basin as an example to demonstrate the method, i.e., combination of petroleum system elements to quantitatively predict the petroleum favorable exploration zones. Based on the detailed analysis of the hydrocarbon accumulation process, the source rock (S), migration (M), reservoir depositional facies (D), and regional cap rock (C) are the most important elements controlling the formation and distribution of oil and gas accumulations in the studied basin. By studying the functional relationships among these four elements and the distribution of the petroleum accumulations, we determined the accumulation probability related to each element and quantitatively predicted the probability of a favorable hydrocarbon accumulation zone. We built a quantitative model of the reservoir preservation probability based on the statistical relationship between the intensity of the tectonic movement and subsequent destruction of existing oil and gas accumulations. Favorable exploration zones can be determined by overlaying favorable accumulation zones with disturbances associated with the tectonic evolution. The results suggest that the most favorable exploration zones of the Longwangmiao Formation in the Sichuan Basin are distributed in the regions west of Weiyuan and east of Gaoshiti–Moxi, Pengxi–Yilong, and Dazhou–Kaijiang. The production data for existing fields in the Sichuan Basin show that 87% of the successful wells are in the predicted favorable exploration zones and that the success rate with respect to the prediction of failure wells is 67%. This approach highlights the most prospective exploration areas in superimposed basins, which, in general, is challenging and complex for traditional basin modeling tools. • Favorable hydrocarbon accumulation zones are quantitatively predicted. • Impact of tectonic movement on the petroleum accumulations is studied. • Petroleum favorable exploration zones in complex superimposed basin are predicted. • The coincidence rate of the application of the model is 87%. [ABSTRACT FROM AUTHOR]

The Lower Permian Taiyuan Formation is a lithic-abundant, tight gas sandstone reservoir in the Kangning field, northeastern Ordos Basin. To clarify the gas accumulation process in tight gas sands, the relationship between the densification of Taiyuan Formation sandstones and gas charging is analyzed. Core porosities of the Taiyuan Formation are mostly below 10%, and air permeabilities are below 1 mD. The sandstone reservoirs are characterized by strong heterogeneity. Dissolution pores and large amounts of micropores in clay minerals dominate the storage space. This porosity is the result of the impact of diagenesis. Porosity evolution modeling confirmed well the prediction of the period of sandstone densification (225-215 Ma) based on the basin analysis as well as diagenetic calibration. Strong compaction dominated the physical property (porosity and permeability) reduction with cementation as a subordinate factor. The integration of burial history and fluid inclusion data suggested that large quantities of gas migrated into the Taiyuan sandstone reservoirs from 176 Ma to 80 Ma when the reservoirs were already tight (porosity <10%). Gas expansion forces provided by source rocks were the main driving force for gas charging instead of buoyancy. Since the late Cretaceous, uplift activity had little influence on Taiyuan tight gas-sands due to self-generation and self-storage. Overlapping sandstone bodies interbedded with high-thickness and good-quality source rocks jointly determined development of tight gas sands. These study results may explain the gas accumulation process and provide insights into gas exploration and development when this method is applied elsewhere. • A new method to indicate the type of gas accumulation. • Three stages of gas accumulation process for Taiyuan Formation in Kangning area. [ABSTRACT FROM AUTHOR]

Abstract The Ordos Basin is a significant gas-producing region in China. Previous studies have shown that a large amount of the gas discovered in the upper Paleozoic strata originated from Carboniferous–lower Permian coal and its interbedded coal measure mudstone. To compare the hydrocarbon generation characteristics and process, two coal and coal measure mudstone samples from the Shanxi Formation in the Shenfu area were used in confined gold tube pyrolysis experiments. The analytical results revealed that both samples had poor oil generation potential, with maximum C 6+ yields of 171.65–175.67 mg/g TOC for the coal and 50.12–51.86 mg/g TOC for the coal measure mudstone at the heating rate of 2 °C/h and 20 °C/h. However, their gas generation potentials are good, and the coal exhibited higher values than the mudstone, with final laboratory C 1 –C 5 yields of 154.71–173.32 mg/g TOC for the coal and 82.52–98.96 mg/g TOC for the coal measure mudstone. Based on a comprehensive analysis of the indicators lnC 2 /C 3 , lnC 1 /C 2 and δ 13C 1 – δ 13C 2 , the hydrocarbon generation process can be divided into three stages. The results of extrapolation to geological conditions revealed that the main gas generation stages of both source rocks in the Shanxi Formation began in the Early Cretaceous. Because of the regional tectonic uplift and the decrease in the geothermal gradient in the Late Cretaceous, the C 1 –C 5 volume yields of the coal and the coal measure mudstone reached plateaus of 78.4 ml/g TOC and 32.7 ml/g TOC, respectively, in the Late Cretaceous, and the current transformation ratios of C 1 –C 5 for the coal and the coal measure mudstone are only 32.1% and 22.8%, respectively. Highlights • Geochemical characteristics of the lower Permian Shanxi Formation coal and coal measure mudstone were analysed. • Confined pyrolysis experiments were performed on the two selected sample types. • Hydrocarbon generation process were determined based on the indicators of yields and carbon isotopes. • Kinetic parameters were used to simulate the hydrocarbon generation history of the coal and coal measure mudstone. [ABSTRACT FROM AUTHOR]

Pore development and the location of retained hydrocarbons are key topics to understand the shale oil system. In an attempt to investigate pore network characteristics and oil retention in lacustrine shales, 24 samples from the Es 3 shales in the Dongpu Depression, Bohai Bay Basin were subjected to mineralogical, petrological, geochemistry and pore structure investigations using X-ray diffraction (XRD), thin section, field emission-scanning electronic microscope (FE-SEM), N 2 adsorption-desorption. After removing retained oil by solvent extraction, 12 selected samples were again analyzed by Rock-Eval pyrolysis and N 2 adsorption-desorption experiment. According to the mineral compositions and petrological characteristics, six types of lithofacies are identified in the Es 3 shales in the Dongpu Depression: laminated calcareous shales, lenticular calcareous shales, laminated argillaceous shales, massive argillaceous shales, laminated siliceous shales, and massive siliceous shales. Geochemical characteristics of these shales are quite different, as calcareous/laminated shales have higher TOC contents than massive argillaceous and siliceous shales. Interparticle pores, intraparticle pores, organic matter pores and fracture pores are observed in the studied samples, while bitumens were found retaining in well-connected pore network. The N 2 adsorption-desorption experiments on samples before and after solvent extraction reveal the different pore structure characteristics in six lithofacies and the occurrence of oil in lacustrine shales. In general, pore volumes within pore diameter range of 1.7–10nm and 10–200nm of samples show increase after solvent extraction, indicating that large and small pores in shales both play important roles in oil retention. Oil retained in shales can be divided as free and heavy fractions, as from the pyrolysis results. In lacustrine shales, larger pores are main storage space for hydrocarbon. Larger pores in different lithologies have similar capacity for free oil retention, while those in calcareous and argillaceous shales are more efficient for heavy oil retention. For both free and heavy oil, small pores in argillaceous shales are efficient for their storage. [ABSTRACT FROM AUTHOR]

Evaluation of carbonate heterogeneity, closely related to pore geometry and connectivity, is important in oil and gas field production and reservoir prediction. To profoundly understand the heterogeneity of Lower Carboniferous carbonate reservoirs in the Marsel area, including Visean (C 1 v) and Serpukhovian (C 1 sr), the pore structure and fractal characteristics are investigated using routine petrophysical measurements, X-ray diffraction (XRD), cast thin section analysis, scanning electron microscopy (SEM), and mercury injection capillary pressure (MICP) tests. The origin of potentially prolific reservoir, the relationships between fractal dimension and reservoir physical properties, mineral composition and pore structure are also discussed. XRD results reveal that the mineral compositions are highly heterogeneous in C 1 v and C 1 sr. Routine petrophysical experiments indicate that C 1 v and C 1 sr are generally tight. However, some high porosity-permeability zones exist in C 1 sr, which is described as a potentially prolific reservoir. The cast thin section and SEM analyses identify three main pore types in the potentially prolific reservoir: interparticle dissolution pores, intercrystalline dissolution pores, and moldic pores. The MICP data reflect that the pore-throat radii in the prolific reservoir range from 0.29 to 4.6 μm, whereas those in tight section are typically <0.14 μm. The fractal dimensions are computed based on MICP data, and the fractal characteristics of the potentially prolific reservoir in C 1 sr are divided into two segments. In the tight section, relatively larger fractal dimensions are observed, indicating highly heterogeneous pore structure. The potentially prolific reservoir in C 1 sr is formed mainly because of penecontemporaneous dolomitization and leaching due to meteoric freshwater ingress. Different mineral compositions have differing effects on the fractal characteristics of the pore structure. Relatively good correlations of fractal dimension with porosity, permeability, sorting coefficient, and skewness indicate that fractal dimensions are helpful in reservoir quality evaluation and quantitative characterization of pore networks. [ABSTRACT FROM AUTHOR]

Hydrocarbon evaporative loss evaluation is important for shale oil resource assessment. We propose a mass balance model to evaluate the hydrocarbon evaporative loss (S 1-loss ) in this study. The proposed method is applied to a large Rock-Eval pyrolysis dataset on source rock samples from the Lucaogou Formation in the Jimusaer Depression of the Junggar Basin, NW China, as a case study to evaluate the S 1-loss . The results indicate that the S 1-loss can range from 0.12 to 7.25 mg/g Rock, corresponding to 11%–89% loss of the generated hydrocarbons (S 1-loss /(S 1 +S 1-loss )) due to evaporation before lab analysis. It appears that when Ro ≤ 1.3%, S 1-loss and S 1-loss /TOC decreases gradually with increasing Ro, likely corresponding to increasing oil density as results of heterogeneous source rock compositions and increased accommodation space via the creation of organic pores of large specific surface for heavy and large hydrocarbon molecules in oil window. When Ro > 1.3%, S 1-loss /TOC begins to increase with increasing Ro as more oil crack to gaseous and light hydrocarbons that are more susceptible to evaporative loss. In the case of similar Ro, the relative S 1-loss /TOC varies little among the samples but the absolute S 1-loss amount increases with increasing TOC. Restricted by regional geological conditions in this study, we focused on the S 1-loss for lacustrine type I kerogen only, and quantification of evaporative loss for other kerogen types remains a subject for further study. [ABSTRACT FROM AUTHOR]

The Tarim Basin in China is a complicated superimposed basin with four periods of hydrocarbon accumulations and three periods of modifications due to tectonic movements, forming complicated hydrocarbon reservoirs, many of which have gone through reservoir migration, reservoir scale reformation, reservoir damage and phase alterations a result of the tectonic events. Due to the complexity, the hydrocarbon exploration in this region has low success drilling rate. It is of great importance to study the destruction to the early hydrocarbon accumulations by the tectonic movements and quantitatively evaluate the remaining resource for understanding the current hydrocarbon distribution and guiding the exploration. This study analyzed six periods of large tectonic events in the Tarim Basin, and found the destroyed hydrocarbon volume was mainly controlled by four geological factors, including the ratio of the destroyed to the original hydrocarbon amount, tectonic event number and sequence, and the cap seal capacity. Larger ratio of destroyed hydrocarbon, less tectonic event number, later sequence and stronger cap seal capacity lead to more hydrocarbons preserved through the tectonic events. Based on the geological analysis, we established quantitative relationships among the destroyed hydrocarbon volume by the tectonic events (Q l ), the volume of primary hydrocarbon accumulation (Q 0 ), the ratio of destroyed hydrocarbon (K l ), the tectonic event number (n) and sequence (i), and cap seal capacity (fc). Using these relationships and the calibrated geological parameters, we delineated the hydrocarbon accumulation and destruction history and quantified the hydrocarbon loss due to the tectonic events for both the Tazhong area and the whole Tarim Basin. In the Tazhong area, four major accumulation events occurred at 510 Ma, 298 Ma, 227 Ma and 38 Ma with each accumulation underwent 68%, 59%, 28% and 0% of hydrocarbon loss due to later tectonic events. In total, over 60% of the original hydrocarbon reserves have been destroyed in the Tarim Basin, with an estimate of ca. 1.9 billion tons remaining hydrocarbons in the Tazhong area. At present, more than 95% oil and gas reservoirs and over 93% high quality exploration wells are located in the areas with high remaining resource potential predicted in this study, whereas 70% non-commercial production wells are located outside. Overall, this work shows that a careful evaluation of the damage to reservoirs from tectonic events can considerably enhance the success rate of hydrocarbon exploration. [ABSTRACT FROM AUTHOR]

There are two sets of carbonate source rocks in the Lower Carboniferous layers in Marsel: the Visean (C 1 v) and Serpukhovian (C 1 sr). However, their geochemical and geological characteristics have not been studied systematically. To assess the source rocks and reveal the hydrocarbon generation potential, the depositional paleoenvironment and distribution of C 1 v and C 1 sr source rocks were studied using total organic carbon (TOC) content, Rock-Eval pyrolysis and vitrinite reflectance (Ro) data, stable carbon isotope data, gas chromatography (GC) and gas chromatography-mass spectrometry (GC-MS) analysis data. The data were then compared with well logging data to understand the distribution of high-quality source rocks. The data were also incorporated into basin models to reveal the burial and thermal histories and timing of hydrocarbon generation. The results illustrated that the average residual TOC contents of C 1 v and C 1 sr were 0.79% and 0.5%, respectively, which were higher than the threshold of effective carbonate source rocks. Dominated by type-III kerogen, the C 1 v and C 1 sr source rocks tended to be gas-bearing. The two source rocks were generally mature to highly mature; the average Ro was 1.51% and 1.23% in C 1 v and C 1 sr, respectively. The source rocks were deposited in strongly reducing to weakly oxidizing marine–terrigenous environments, with most organic material originating from higher terrigenous plants and a few aquatic organisms. During the Permian, the deep burial depth and high heat flow caused a quick and high maturation of the source rocks, which were subsequently uplifted and eroded, stopping the generation and expulsion of hydrocarbons in the C 1 v and C 1 sr source rocks. The initial TOC fitted by the △logR method was recovered, and it suggests that high-quality source rocks (TOC ≥ 1%) are mainly distributed in the northern and central local structural belt. [ABSTRACT FROM AUTHOR]

The Pearl River Mouth Basin in the South China Sea has accumulated >2 km of Eocene sediments in its deep basin, and has become the exploration focus due to the recent discoveries of the HZ25-7 oil field in the Eocene Wenchang (E 2 w) Formation. In this study, the geochemical characteristics of potential source rocks and petroleum in the HZ25-7 oil field are investigated and the possible origins and accumulation models developed. The analytical results reveal two sets of potential source rocks, E 2 w and Enping (E 2 e) formations developed in the study area. The semi-deep-to-deep lacustrine E 2 w source rocks are characterized by relatively low C 29 steranes, low C 19 /C 23 tricyclic terpane (<0.6), low C 24 tetracyclic terpane/C 30 hopane (<0.1), low trans-trans-trans -bicadinane (T)/C 30 hopane (most <2.0), and high C 30 4-methyl sterane/ΣC 29 sterane (>0.2) ratios. In contrast, the shallow lacustrine and deltaic swamp-plain E 2 e source rocks are characterized by relatively high C 29 steranes, high C 19 /C 23 tricyclic terpane (>0.6), high C 24 tetracyclic terpane/C 30 hopane (>0.1), variable yet overall high T/C 30 hopane, and low C 30 4-methyl sterane/ΣC 29 sterane (<0.2) ratios. The relatively low C 19 /C 23 tricyclic terpane ratios (mean value: 0.39), low C 24 tetracyclic terpane/C 30 hopane ratios (mean value: 0.07), high C 30 4-methyl sterane/ΣC 29 sterane ratios (mean value: 1.14), and relatively high C 27 regular sterane content of petroleum in the HZ25-7 oil field indicate that the petroleum most likely originated from the E 2 w Formation mudstone in the Huizhou Depression. One stage of continuous charging is identified in the HZ25-7 oil field; oil injection is from 16 Ma to present and peak filling occurs after 12 Ma. Thin sandstone beds with relatively good connectivity and physical properties (porosity and permeability) in the E 2 w Formation are favorable conduits for the lateral migration of petroleum. This petroleum accumulation pattern implies that the E 2 w Formation on the western and southern margins of the Huizhou Depression are favorable for petroleum accumulation because they are located in a migration pathway. Thus exploration should focus in these areas in the future. [ABSTRACT FROM AUTHOR]

Shales from the Lower Silurian Longmaxi Formation in the Sichuan Basin are among the most important shale gas reservoirs in China, and have been investigated because of their great shale gas potential. To understand the pore structure and fractal characteristics of the shales, a series of experiments was conducted on core samples from the Lower Silurian Longmaxi Formation in the Sichuan Basin of China, including X-ray diffraction (XRD), total organic carbon (TOC) content and vitrinite reflectance (Ro) analysis, field emission-environmental scanning electron microscope (FE-ESEM) observation, and low-pressure N 2 adsorption-desorption experiments. Frenkel-Halsey-Hill (FHH) method was applied to calculate fractal dimensions. In addition, the pore genesis, the relationships between composition and thermal maturity, the pore structure parameters, and the fractal dimensions are discussed. FE-ESEM observation results show that the Longmaxi Formation shales are dominated by organic-matter (OM) pores along with interparticle (interP) pores, intraparticle (intraP) pores and fracture pores. This study identified the fractal dimensions at relative pressures of 0–0.45 and 0.45–1 as D 1 and D 2 respectively. D 1 ranged from 2.60 to 2.71 and D 2 ranged from 2.71 to 2.82. D 1 was typically smaller than D 2 , indicating that the smaller pores in shales were more homogeneous than the larger ones. The formation of these OM pores is owing to kerogen deformation during the thermal maturation, which results in a large number of nanopores. The pore structure of the Longmaxi Formation shales is primarily controlled by TOC content and thermal maturity. TOC content is a controlling factor on the fractal dimensions as it exhibited positive correlations with D 1 and D 2 . Fractal dimensions are useful for the characterization of the pore structures complexity of the Longmaxi Formation shales because D 1 and D 2 correlate well with pore structure parameters as they both increase with the increase of surface area and the decrease of average pore diameter. [ABSTRACT FROM AUTHOR]

In total, 2.37 million tons of marine crude oil originating from mixed source rocks has been discovered in the Tarim basin. Geological and geochemical analyses have confirmed that these mixed hydrocarbons are mainly from two sets of source rocks, including the Cambrian – Lower Ordovician and Middle-Upper Ordovician hydrocarbon source rocks. In this study, we determined the set of source rocks primarily responsible for the mixed hydrocarbons and the next location to be explored. Differences in n-alkane carbon isotopes in end-member oils from Cambrian–Lower Ordovician and Middle-Upper Ordovician source rocks were examined. A material balance model and simulation methods were used to evaluate the relative amounts contributed by each source. The results from known reserves in the Tazhong area show that the mixing ratio or contribution is up to 65% from Cambrian–Lower Ordovician source rocks and is generally higher than that from Middle-Upper Ordovician source rocks. The discovery of deep hydrocarbons has caused the total oil contribution from the Cambrian–Lower Ordovician to increase. The mixing ratio of Cambrian–Lower Ordovician oil varies depending on the well, formation, and block. It increases from west to east horizontally and from top to bottom vertically. Hydrocarbons from Cambrian–Lower Ordovician source rocks migrate upward along faults, and the mixing ratio decreases as the distance from the oil source fault increases. Favorable areas for Cambrian–Lower Ordovician hydrocarbon exploration are deep layers and areas near the fault zone that are connected to deep layers. The material balance model for carbon isotopes and evaluation methods for relative contributions considered differences in relative concentration and carbon isotope structure of n-alkanes. Herein, new methods for the identification and evaluation of hydrocarbons in the petroleum system of this superimposed basin are presented. [ABSTRACT FROM AUTHOR]

In recent years, new oil reservoirs have been discovered in the Eocene tight sandstone of the Huilu area, northern part of the Pearl River Mouth basin, South China Sea, indicating good prospects for tight oil exploration in the area. Exploration has shown that the Huilu area contains two main sets of source rocks: the Eocene Wenchang (E 2 w) and Enping (E 2 e) formations. To satisfy the requirements for further exploration in the Huilu area, particularly for tight oil in Eocene sand reservoirs, it is necessary to re-examine and analyze the hydrocarbon generation and expulsion characteristics. Based on mass balance, this study investigated the hydrocarbon generation and expulsion characteristics as well as the tight oil resource potential using geological and geochemical data and a modified conceptual model for generation and expulsion. The results show that the threshold and peak expulsion of the E 2 w source rocks are at 0.6% vitrinite reflectance and 0.9% vitrinite reflectance, respectively. There were five hydrocarbon expulsion centers, located in the western, eastern, and northern Huizhou Sag and the southern and northern Lufeng Sag. The hydrocarbon yields attributed to E 2 w source rocks are 2.4 × 10 11 tons and 1.6 × 10 11 tons, respectively, with an expulsion efficiency of 65%. The E 2 e source rock threshold and peak expulsion are at 0.65% vitrinite reflectance and 0.93% vitrinite reflectance, respectively, with hydrocarbon expulsion centers located in the centers of the Huizhou and Lufeng sags. The yields attributed to E 2 e source rocks are 1.1 × 10 11 tons and 0.2 × 10 11 tons, respectively, with an expulsion efficiency of 20%. Using an accumulation coefficient of 7%–13%, the Eocene tight reservoirs could contain approximately 1.3 × 10 10 tons to 2.3 × 10 10 tons, with an average of 1.8 × 10 10 tons, of in-place tight oil resources (highest recoverable coefficient can reach 17–18%), indicating that there is significant tight oil potential in the Eocene strata of the Huilu area. [ABSTRACT FROM AUTHOR]

Although a large amount of petroleum has been discovered in the Tarim Basin, the origin of the oils is still disputed. Yingmaili Oilfield was selected as a case study to further examine hydrocarbon generation and accumulation in the basin. Detailed geochemical studies were conducted to unravel the formation mechanisms. The oils in the field correlate well with Middle–Upper Ordovician (O 2+3 ) rocks (or similar rocks). Oil–oil and oil–source rock correlation by maturity parameters of saturate and aromatic hydrocarbons suggest that the Yingmaili and adjacent oils are primarily comparable to source rocks deeper than 6000 m. The results also showed that carbonates might be important potential source rocks as indicated by a relatively high abundance of aromatic sulfur compounds and relatively high C 29 /C 30 -hopane and C 35 /C 34 -hopane ratios of the oils, which are typical features of carbonate source rocks. We suggest the oil from wells YG2 and YG2-1C are more suitable to be end members from the O 2+3 source rocks (or similar rocks) than the oil from well YM2 as previously suggested. We also suggest that the previous model of hydrocarbon migration along the Ordovician unconformity should be revised. [ABSTRACT FROM AUTHOR]

The Middle Eocene Wenchang (WC) formation in the Huizhou depression of the Pearl River Mouth basin is an important geological element for petroleum exploration in the South China Sea. In this study, the geological and geochemical characteristics of the WC source rocks, including the distribution, sedimentary environment, organic matter type, hydrocarbon generation potential and thermal maturity were investigated. Hydrocarbon generation history and hydrocarbon expulsion intensity and quantities were evaluated through one dimensional basin modelling and an improved hydrocarbon generation potential methodology. The WC source rocks are widely distributed and have an elevated thickness (mostly thicker than 200 m, with a maximum thickness greater than 1000 m); they were deposited in a lacustrine weak oxidation–weak reduction sedimentary environment with low salinity. The source rocks have low to high organic matter abundance (TOC mainly ranges from 0.27 to 3.59 wt% with an average of 1.39 wt%) dominated by II 1 –type and II 2 –type kerogen, resulting in significant hydrocarbon generating potential under moderate–high thermal evolution (R o mainly ranges from 0.65% to 1.2% on the margins of sags and greater than 1.2% in the centre of sags). The source rocks became mature (R o = 0.5%) in the early Miocene and began to generate hydrocarbons. They reached the hydrocarbon expulsion threshold at 0.8% R o and the hydrocarbon expulsion rate became greatest at 1.1% R o . The expulsion intensities in the H26 sag, H21 sag, X24 sag and X23 sag are relatively large, with their greatest expulsion intensities being 104 × 10 6 , 71 × 10 6 , 62 × 10 6 and 53 × 10 6 t/km 2 , respectively. The comprehensive hydrocarbon expulsion efficiency was approximately 75%. About 690.1 × 10 8 t of hydrocarbons were expulsed from the WC source rocks in the Huizhou depression. [ABSTRACT FROM AUTHOR]

The Qibei sag (QS), at the western region of the Bohai Bay Basin (BBB), eastern China, has made significant progress in the deep gas exploration recently, indicating that the deep gas reservoirs have good exploration prospects. The deep gas reservoirs within the second member of the Shahejie Formation of the Paleogene (E 2 s 2 ) are buried at approximately 5000 m. The sources and hydrocarbon accumulation mechanisms were investigated by analyzing the regional structure, integrating geologic and geochemical parameters of source rocks and natural gas. Analyzing results show that, in the QS and adjacent areas (QSAA), three sets of source rocks (E 2 s 1 , E 2 s 2 , E 2 s 3 ) were developed, which differ in organic chemical characters, but have abundant organic matters in fair-good standard. Affected by burial history, E 2 s 3 source rocks have entered into the high mature-over mature stage and E 2 s 1 source rocks are mainly in mature stage. The methane content of natural gas (78%∼91%), the methane carbon isotope value (−41.3‰∼−34.6‰) and the positive carbon isotope sequence (δ 13 C 1 <δ 13 C 2 <δ 13 C 3 <δ 13 C 4 ) indicate that the deep gas is organic origin and mainly from thermogenic gas. The relationship between light hydrocarbon character parameters and thermal evolution degree indicates that the deep gas in the QS is mainly from E 2 s 2 and E 2 s 3 source rocks of the sag. Since the different hydrocarbon generation history, there exist two hydrocarbon accumulation periods in QS, and the early period is characterized by oil accumulation, which occurs at the shallows, such as the Binshen6 block; the late period is characterized by gas accumulation, which happens in the depth mostly, such as the Binshen22 block. The different hydrocarbon generation history results in the relative enrichment of gas in the depth and the phenomenon of oil–gas inversion. [ABSTRACT FROM AUTHOR]

Abstract: Subtle traps have become an important petroleum play type for exploration in the Dongying Depression, Bohai Bay Basin, eastern China. The majority of the oil pools are in the middle interval of the Es 3 member of the Eocene–Oligocene Shahejie Formation, with the subtle traps being primarily in the lenticular, basin floor turbidite sands enclosed within basin floor mudstones. Detailed geochemical investigation of 68 oil and rock samples from the depression reveals that in contrast to previous models, the oils from the subtle traps correlate poorly with the surrounding source rocks. While the high pristane/phytane (Pr/Ph > 1) and low gammacerane/C30-hopane ratios in these source rocks represent a freshwater lacustrine setting, the oils feature low Pr/Ph ratios (<1) and relatively high gammacerane contents similar to the upper source rocks deposited in a brackish lacustrine setting. The compound-specific isotope ratios of n-alkanes in the oils have intermediate values between those observed in extracts from the lower Es 3 and upper Es 4 source rocks. Consequently, the oils in the subtle traps were most likely derived from mixed and sources, with the contribution from the source rocks being predominant. The oils generated from the source rocks must have migrated through a thick interval of the source rocks to reach the subtle traps in the , through which there are no apparent structural nor stratigraphic pathways. The traditional migration and accumulation model, i.e. indigenous crude oil with short migration distance to lenticular oil pools, should be revised to account for the charging of oils from source rocks. [ABSTRACT FROM AUTHOR]

Abstract: A great difference exists between the hydrocarbon charging characteristics of different Tertiary lacustrine turbidites in the Jiyang Super-depression of the Bohai Bay Basin, east China. Based on wireline log data, core observation and thin-section analyses, this study presents detailed reservoir property data and their controlling effects from several case studies and discusses the geological factors that govern the hydrocarbon accumulation in turbidite reservoirs. The lacustrine fluxoturbidite bodies investigated are typically distributed in an area of 0.5–10km2, with a thickness of 5–20m. The sandstones of the Tertiary turbidites in the Jiyang Super-depression have been strongly altered diagenetically by mechanical compaction, cementation and mineral dissolution. The effect of compaction caused the porosity to decrease drastically with the burial depths, especially during the early diagenesis when the porosity was reduced by over 15%. The effect of cementation and mineral dissolution during the late-stage diagenesis is dominated by carbonate cementation in sandstones. High carbonate cement content is usually associated with low porosity and permeability. Carbonate dissolution (secondary porosity zone) and primary calcite dissolution is believed to be related to thermal maturation of organic matter and clay mineral reactions in the surrounding shales and mudstone. Two stages of carbonate cementation were identified: the precipitation from pore-water during sedimentation and secondary precipitation in sandstones from the organic acid-dissolved carbonate minerals from source rocks. Petrophysical properties have controlled hydrocarbon accumulation in turbidite sandstones: high porosity and permeability sandstones have high oil saturation and are excellent producing reservoirs. It is also noticed that interstitial matter content affects the oil-bearing property to some degree. There are three essential elements for high oil-bearing turbidite reservoirs: excellent pore types, low carbonate cement (<5%) and good petrophysical properties with average porosity >15% and average permeability >10mD. [Copyright &y& Elsevier]

The decline of proven conventional petroleum resources in the shallow portions of the Nanpu sag has shifted attention to the exploration of deep unconventional oil and gas resources there, especially the shale oil resources in the middle Eocene shales of the Shahejie Formation (MES shales). In this study, to assess the oil potential of the MES shales, we carried out a systematical geochemical and basin modeling characterization. The results show that the MES shales have low maturity and are at the early stage of hydrocarbon generation, with a mean vitrinite reflectance of 0.64% and low ratio of C 27 18α(H)-22, 29, 30-trisnorneohopane to C 27 17α(H)-22, 29, 30-trisnorhopane (0.44–1.18). The MES shales contain abundant organic matter (OM), with an average total organic carbon content of 2.21 wt %. Biomarker analyses show that the OM in the MES shales derived mainly from floating macrophyte and aquatic algae, microalgae and bacteria. The sapropelinite group in the MES shales is predominant in the organic macerals, and the kerogen is sapropelic and dominated by types I and II 1. Biomarker analyses also reveal that the MES shales were deposited in the stratified water column as suggested by the presence of gammacerane, under relatively warm and wet climatic conditions. The anoxic conditions built up in the water column facilitated the OM preservation, although slight microbial degradation resulted in relatively high carbon preference index values. Modeling results based on geochemical data and basin analyses show that considerable quantities of hydrocarbons remain in the low-maturity MES shales. The preliminary estimate of the quantity of shale oil resources in the Gaoliu area of Nanpu sag is approximately 1.78 × 108 t. Nanpu sag have good shale oil potential, and shale oil exploration may be more feasible for MES shales, especially in the context of in-situ heating technology. • Middle Eocene Shale in Nanpu Sag of the Bohai Bay Basin are typical early mature. • MES shale deposited under a warm and wet climate with slight microbial degradation. • Middle Eocene lacustrine shale in Nanpu Sag contains good shale oil potential. [ABSTRACT FROM AUTHOR]

Reconstructing the hydrocarbon generation and expulsion history of source rocks is an essential part of evaluating the hydrocarbon resource potential by genetic method. The hydrocarbon generation potential method is an efficient tool for quantifying the hydrocarbon generation and expulsion characteristics of source rock and evaluating the hydrocarbon resource potential based on Rock-Eval data. Although various revised versions of the method are publicly available, the following problems remain to be resolved: (a) the method is subjective; (b) implicit limitations are observed; and (c) rock mass loss is not considered, which may result in unacceptable errors. In this study, we propose a revised hydrocarbon generation potential method. Expressions for calculating the original rock mass (G o), original total organic carbon (TOC o), transformation ratio (T R), hydrocarbon expulsion ratio (E R) and hydrocarbon expulsion efficiency (f) were developed and incorporated into the hydrocarbon generation and expulsion history reconstruction and hydrocarbon resource potential evaluation, and these expressions combined conventional and unconventional resource evaluations systematically with objective and accurate results. The first member of the Qingshankou Formation (K 2 qn 1) in the Northern Songliao Basin, Northeast China, was used as an example to demonstrate the application of the proposed method. The results have been compared with the unrevised method using the same Rock-Eval data sets and verified with previous reports to demonstrate its reliability. The results also indicate that the hydrocarbon generation threshold (HGT) and hydrocarbon expulsion threshold (HET) of K 2 qn 1 are Ro = 0.4% and Ro = 0.6%, respectively. Three hydrocarbon generation and expulsion peak stages were identified: K 2 n (81–74 Ma), K 2 m (74–66 Ma), and N 2 t (66–0 Ma). The hydrocarbon generation and expulsion centers of K 2 qn 1 are mainly the Qijia-Gulong Sag and Sanzhao Sag. The resource potentials of conventional oil, unconventional tight oil, and shale oil associated with K 2 qn 1 source rocks in the Northern Songliao Basin are 8.15 × 108 t, 22.97 × 108 t, and 62.1 × 108 t, respectively. [ABSTRACT FROM AUTHOR]

The middle Eocene was a key period of global climate change from a warm "greenhouse" to a cooling "doubthouse". At the middle Eocene, an extensive arid climate in China was recorded in the mudstones and shales interbedded with salinastone which formed good hydrocarbon source rocks, especially in the Bohai Bay Basin. The sedimentary paleoenvironment and its variations affected the source rock quality and distribution. Based on successive and dense sampling of the middle Eocene Shahejie Formation shale (MES shale) in Nanpu Sag of Bohai Bay Basin, petro-mineralogical tests, geochemical methods and spectrum analysis were performed to analyse the palaeoenvironmental fluctuations and the responses to Milankovitch cycles. Element analysis on MES shale shows that the middle Eocene climate was arid and the sediments were deposited under dysoxic/suboxic conditions with relatively high salinity. Based on the Δlog R method, the organic matter (OM) abundance was evaluated and ranged from 0.18 to 3.55 wt % for MES shale. The mean primary productivity of 545 g C m−2 yr−1 shows a eutrophic environment in middle Eocene Nanpu paleolake. Wavelet analysis performed on gamma logging and palaeoenvironmental proxies revealed clear Milankovitch cycles for MES shale, and the cyclostratigraphic and palaeoenvironmental fluctuations were effected by astronomical oscillation periods of the short eccentricity cycle (100 k.y.), obliquity cycle (39 k.y.) and precession cycle (19 k.y.). The depositional rate of MES shale was corrected to 0.43 m/k.y. The sedimental process of MES shale was associated with palaeoenvironmental variation, which have been divided into four stages affecting OM accumulation. A hypothesis that the vast carbon of "greenhouse" gases in the Palaeocene and early Eocene was fixed in organic matters during middle Eocene and enriched in the hydrocarbon source rocks of the sedimentary basins formed at early Eocene was proposed to explain the "doubthouse" world in the Eocene. • Clear Milankovitch cycles exist in mid-Eocene lacustrine shale of Bohai Bay Basin. • Pale-climate integration effects on organic matter enrichment in lacustrine shale. • Carbon fixation in shales was critical to decline greenhouse gases at mid-Eocene. [ABSTRACT FROM AUTHOR]

Mineralogical, petrographical, geochemical analyses, and fluid inclusions petrography and microthermometry were combined to investigate the basic properties of the source rock (organic matter content, kerogen type, and thermal maturity) and sandstone reservoirs (composition, pore systems, porosity, and permeability), the hydrocarbon origin, and the formation mechanisms of the deep (>3.5 km) petroleum system in the Upper Paleogene Es1 (the uppermost member of the Shahejie Formation) in the No. 3 Structural Belt in the Nanpu Sag, Bohai Bay Basin. The results indicate that the Es1 source rock is primarily composed of dark gray mudstone and presents a set of high-quality source rocks (>500 m, average total organic carbon (TOC) 1.38%, in a mature stage (maximum pyrolysis yield of 430 °C–460 °C)). The Es1 sandstone is composed of lithic arkose formed in a braided river delta and has low porosity (average 13.4%) but moderate-high permeability (average 184.9 mD). The hydrocarbons originated from the Es1 source rocks in the Caofeidian subsag during two charging periods: 10 Ma and 3 Ma. The key factors controlling the formation of the deep petroleum system are as follows: (a) High-quality hydrocarbon supply, (b) Medium-high permeability reservoirs, (c) A favorable configuration of the source rock and reservoirs (self-generated and self-accumulated), and (d) Late hydrocarbon charging; the second factor is the most important. The medium-high permeability reservoirs are attributed to a high-energy depositional environment (distributary channels of braid delta front), a high content of rigid detrital grains (mainly quartz and metamorphic rock fragments) provided by the Archean granite provenance, and the secondary pores formed by feldspar dissolution. This study provides a new example for revealing the formation mechanisms of deep (>3.5 km) petroleum systems in the terrestrial rift basin across the Bohai Bay Basin. • Properties of sandstones and source rocks of a deep petroleum system are investigated. • The hydrocarbon origin of the deep petroleum system is revealed. • Controlling factors of high-quality sandstones are summarized. • Formation mechanisms of deep petroleum systems of the Bohai Bay Basin are detailed. [ABSTRACT FROM AUTHOR]

Abstract In this study, we investigate the petrophysical parameter values above which oil can accumulate, using a tight oil reservoir in the Jimusaer Depression, Junggar Basin, as an example. Statistical analysis of well-drilling data and effective porosity measurements is integrated with numerical simulations of force balance to illuminate the mechanisms that place a lower limit on the petrophysical parameters of tight hydrocarbon reservoirs. Further, we discuss the factors that influence these limits. The results show that when porosity is observed to be less than 5%, corresponding to a pore-throat radius of more than 0.2 μm, exploratory wells reach reservoirs comprising only water layers. The lower limit for oil accumulation is reached when irreducible water saturation reaches 100% and porosity is approximately 5%. This fits well with the values arrived at by modeling the force balance. In the reservoirs under consideration, oil charging is driven by excess pressure resulting from hydrocarbon generation and is resisted by capillary force. When the pore-throat radius is larger than 0.2 μm, the capillary force will be greater than the driving force, and tight reservoirs cannot be charged with oil. This corresponds to a porosity of approximately 5%, matching the results derived from observations. The values of these lower limits depend on many factors, such as source rock quality, depth, temperature, hydrocarbon-generation kinetics, and interfacial tension, and hence vary under different geological conditions. Thus, in lacustrine basins in China with type I kerogen-dominated source rocks, the lower limits are smaller than in those where other types dominate. Differences in the geothermal gradient mean that, at similar hydrocarbon-generation temperatures, the lower limits for reservoirs in Western China are smaller than for those in the east. There is also a smaller lower limitation porosity in tight gas reservoirs than in tight oil reservoirs due to the difference in interfacial tension. Highlights • Illuminate the mechanisms of the lower limits in tight hydrocarbon reservoirs. • Discuss the impact factors on lower limits of tight hydrocarbon reservoirs. • The lower limits of the P 2 l in Jimusaer are with throat radius of 0.2 μm and porosity of 5%. [ABSTRACT FROM AUTHOR]

Deep sour gases are found in the Ordovician carbonate reservoir of the Tazhong Uplift in the Tarim Basin, northwest China. All sour gases in this field are dominated by gas hydrocarbons (C 1 –C 4 ) with varying amounts of H 2 S. Most of the gases in the eastern Tazhong are characterized by high gas dryness coefficients (>0.95), 13 C-enriched methane (δ 13 C 1 ranging from −44.6‰ to −35.8‰), and small difference between values of the δ 13 C 2 and δ 13 C 1 (δ 13 C 2 - 1 ). In contrast, the gases in the western Tazhong are characterized by relatively low gas dryness coefficients (mostly < 0.90), 13 C-depleted methane (δ 13 C 1 ranging from −54.9‰ to −35.7‰), and high values of δ 13 C 2 - 1 , indicating relatively lower maturity. Gas compositions, carbon isotope ratios, and diamantane data together with thermal pyrolysis experiments using sealed gold tubes suggest that the Ordovician gases in the Tazhong Uplift belong to oil cracking gases mixed with high-maturity 13 C-enriched dry gases, which originated from the deeper paleo-reservoirs cracking. The H 2 S (0.0008%–23.1000%) is attributed to thermochemical sulfate reduction (TSR); in contrast to typical TSR-altered gases, the natural gases in the western Tazhong are characterized by low dryness coefficients, relatively 13 C-depleted methane, and high δ 13 C 2 - 1 , suggesting a low degree of TSR alteration. Observations suggest that the H 2 S contents are generally high in the western Tazhong, with positive correlation to Mg 2+ concentrations and total dissolved solids (TDS) in the Ordovician formation water, indicating that TSR has entered early period of SO 4 2− contact ion pairs (CIPs) oxidation. Compared with the eastern Tazhong, the Mg 2+ concentrations and TDS in the western Tazhong are higher and form more CIPs that accelerate TSR and produce H 2 S. In addition, based on the analysis of the Cambrian formation water and the Cambrian gypsiferous salt, TSR might have also exist in the deeper Cambrian reservoirs, and the TSR-altered gases with high content of H 2 S migrated along faults to Ordovician reservoirs. [ABSTRACT FROM AUTHOR]

Determination of total organic carbon (TOC) is essential in unconventional shale resource play evaluation. Indirect method, such as petrophysical approach, can provide a fast, convenient and cost efffective means for TOC estimation from well logs. Among the publically available approaches, the ΔlogR method is a popular one in conventional source rock evaluation and has been applied to unconventional resource play evaluation by many practitioners. Careful examination of the method finds that improvements can be made for a better TOC estimation with relaxed limitations. This study proposes the following revisions on the original ΔlogR method: 1) allowing estimation of petrophysical parameters from the targeted source rock rather an assumed linear approximation, 2) using additional logs to improve TOC prediction, and 3) replacing LOM (level of organic metamorphism unit) with a more commonly used thermal indicator Tmax for convenience. Depending on data or preference, the choice of using different porosity logs (density versus sonic) and parameter estimation methods (cross-plot method versus data-driven approaches) makes the revised method flexible for application. We present the revisions along with application examples from the Devonian Duvernay Shale in the Western Canada Sedimentary Basin to demonstrate the application of the improved ΔlogR method in shale gas evaluation. Comparison of the results from the revised method and the original one reveals that the revised models provide better and unbiased estimates of TOC with a higher correlation coefficient and bell-shaped residues centered at zero. [ABSTRACT FROM AUTHOR]

Abstract: The Tazhong area, at the center of the Tarim basin, western China, contains abundant hydrocarbon resources, principally in Ordovician carbonate reservoirs. The geological conditions for hydrocarbon accumulation in the area are quite complicated and are characterized by multiple stages of hydrocarbon generation, accumulation, adjustment and alteration. Despite decades of exploration and production in the region, the mechanisms of hydrocarbon accumulation and their controlling factors are still not well established. The geological setting and the distribution characteristics of the reservoir, have been used to investigate the mechanisms of accumulation, to quantitatively describe the main controlling factors, and to predict potential favorable hydrocarbon accumulation zones in Ordovician carbonate rocks of Tazhong. Our results show that the hydrocarbons in the Ordovician reservoirs came from mixed sources including middle-lower Cambrian and middle-upper Ordovician source rocks within the Majiaer Sag. Four stages of accumulation are recognized and hydrocarbons migrated into the Tazhong area along six intersections of NE and NW fault sets, principally from the northeast to the southwest but then, locally, from the northwest to the southeast. The Ordovician carbonate reservoirs are typically lithologically defined and the dynamic force of hydrocarbon accumulation is primarily reflects differential capillary forces. The accumulation and distribution of hydrocarbons was controlled by the petrophysical properties of the reservoir and by hydrocarbon supply/charge energy. The petrophysical properties of the reservoir controlled the hydrocarbon accumulation threshold with the maximum differential capillary pressure force, on average, approximately 13 MPa. The supply or charge energy of the hydrocarbons controls the accumulation distribution range. The daily production of individual wells decreases with increasing distance from the fault intersections and the maximum hydrocarbon migration distance is about 35 km. Reservoir properties and the hydrocarbon supply/charge Energy coupling Index (REI) appear to control hydrocarbon accumulation and distribution. Accumulation does not occur when the value of REI is ≤ 0.6, but is favored when values are higher. [Copyright &y& Elsevier]

To evaluate petroleum resources, it is important to quantify the hydrocarbon generation and expulsion characteristics of source rock. The hydrocarbon generation potential method is an efficient model for calculating the characteristics of source rocks and evaluating the resource potential. The previous hydrocarbon generation potential model was mainly established by measured Rock-Eval pyrolysis data, and due to inappropriate preservation measures, an important component (volatile hydrocarbon content) of source rock may be significantly reduced. Prior methods may, therefore, not objectively reflect the properties of a source rock and cause unacceptable errors in the resource assessment. This study proposes an improved hydrocarbon generation potential method. The new method considers the initial hydrogen index (H I 0) and transformation ratio (Tr) during the evolution of source rocks, which can more realistically reflect the hydrocarbon generation and expulsion history of source rocks. Therefore, the hydrocarbon evaporative loss (Qloss) is calibrated and the hydrocarbon generation and expulsion features of source rocks are more accurately evaluated. The proposed method is used to examine the effectiveness of the third member of the Upper Paleogene Shahejie Formation (Es3) in Nanpu Sag. By utilizing the improved hydrocarbon generation potential model, the hydrocarbon expulsion threshold of the Es3 source rock is positioned at Ro = 0.875%. The maximum hydrocarbon generation and expulsion potential (Qg and Qe) are 593.78 and 323.78 mg HC/g TOC, respectively, and the maximum hydrocarbon expulsion efficiency is 54%. The maximum hydrocarbon generation and expulsion intensities are 500 × 104 t/km2 and 250 × 104 t/km2, respectively, which locate source rock at the Laoyemiao and Gaoshangpu Structural Belts. The amounts of generated and expelled hydrocarbon are 13.7 × 108 t and 6.9 × 108 t, respectively, and the resource potential of the tight oil of the Es3 in the Nanpu Sag is 0.69 × 104 t. Compared with the previous method, the improved hydrocarbon generation potential method limits the maximum Qg and calibrates the Qloss; therefore, the new method more objectively reflects the hydrocarbon generation and expulsion characteristics and resource prospect of the source rock. • A systematic evaluation was carried out of the Es3 source rocks in the Nanpu Sag. • An improved hydrocarbon generation potential method is proposed. • The new method is used to the Es3 in the Nanpu Sag to exam its effectiveness. • The improved and previous hydrocarbon generation are compared. [ABSTRACT FROM AUTHOR]

This study presents the reservoir characterization of the unconventional, organic-rich dolomitic tight-oil reservoir of the Lower Cretaceous Xiagou Formation in the Qingxi Sag, Jiuquan Basin. To better describe pore characteristics and understand contributors to pore development of the mixed siliciclastic-carbonate reservoirs, samples were examined by thin section, X-ray diffraction (XRD) analysis, total organic carbon (TOC) and Rock-Eval pyrolysis, porosity and permeability measurement, field emission scanning electron microscopy (FESEM), and nuclear magnetic resonance (NMR). Four types of laminations, including carbonate lamination, siliceous lamination, argillaceous lamination and organic matter lamination, are developed. The average TOC of 1.67% and calculated Ro of 0.72%–0.96% indicate that the Xiagou source rocks are qualifed oil-source. Various types of pores with different sizes and micro-fractures are observed in such tight, mixed siliciclastic–carbonate reservoirs. Compared to mudstone/shale and tight sandstone, the tight and mixed siliciclastic–carbonate reservoirs are characterized by: (1) widely developed and multiple types of lamina structure, (2) various pore types without secondary OM pores generated by organic matter conversion, (3) wide pore size distributions, and (4) abundant and multiple genetic types of micro-fractures. The difference in mineral composition is the primary cause of different pore structure characteristics. Dolomitic mudstone is dominated by interlayer pore of clay mineral, while argillaceous dolomite is characterized by interparticle fractures, interparticle pores, and micro-fractures (including shrinked micro-fracture). In dolomitic siltstone, the residual intergranular pore and intergranular dissolved pore are the most common pores. The nanopore occurs widely in all lithologies, but the proportion of micrometers-scale pores and macro-scale nanopore increases from dolomitic mudstone to argillaceous dolomite and dolomitic siltstone. The positive correlation between porosity/permeability and TOC indicate the existence of pores or micro-fractures within or along the edge of organic matters. The similar thermal maturity level (Ro 0.72%–0.96%) eliminates maturation as a variable in porosity development in the studying area. The lithofacies associations with high-quality source rocks and reservoirs (relatively high porosity and permeability or rich in brittle minerals) are the favorable targets. [ABSTRACT FROM AUTHOR]

Abstract: This paper reviews the historical development of both biogenic and non-biogenic petroleum formation. It also examines the recent claim that the so-called “abiotic” oil formation theory undermines the concept of “peak oil,” i.e. the notion that world oil production is destined to reach a maximum that will be followed by an irreversible decline. We show that peak oil is first and foremost a matter of production flows. Consequently, the mechanism of oil formation does not strongly affect depletion. We would need to revise the theory beyond peak oil only for the extreme — and unlikely — hypothesis of abiotic petroleum formation. [ABSTRACT FROM AUTHOR]

Based on the results of laboratory simulation experiments and field observations, the concept of ‘fault-fracture mesh petroleum play’ is proposed to explain the secondary petroleum accumulations in the Neogene reservoirs of the Jiyang Superdepression, Bohai Bay Basin, Eastern China. A well-defined fault-fracture mesh petroleum play usually contains three basic elements, an oil source network at the base, a transient storage for migrating hydrocarbons in the middle, and a petroleum accumulation network at the top. The oil source network provides fairways for hydrocarbons generated in a deep source to migrate vertically upward to shallow strata, often consisting of primary faults and fracture zones and/or regional unconformities in direct contact with mature petroleum source beds, and secondary faults intercepting lenticular fluvial sandstones. The transient storages for migrating hydrocarbons include the thick, porous, mat or sheet-like sandstones deposited under the fluvial, braided stream setting and occurring over relatively large geographic areas. These sandstones serve as temporary storage spaces, through which deep-sourced petroleum fluids migrate further, either laterally or vertically into shallower reservoirs. The upper petroleum accumulation network provides suitable habitats for oil and gas accumulation, comprising structural, lithologic, stratigraphic and combination traps. The Jiyang Superdepression of the Bohai Bay Basin hosts several excellent examples of the fault-fracture mesh petroleum play, where hydrocarbons in the Neogene reservoirs were derived either directly from Eocene-Oligocene source rocks, or from the redistribution of pre-existing oil accumulations in the deeper reservoirs. Reactivation of basement-involved faults and regional unconformities provided conduits for channeling the pre-Neogene hydrocarbons into the shallow strata. The magnitudes and frequencies of the faulting activities and their relative timings to those of peak oil generation and expulsion were critical factors for controlling the quantities of hydrocarbons transmitted to the Neogene strata. The thick sandstones and conglomerates in the lower Guantao Formation acted as excellent transient storages for the deep sourced oils, which were then trapped to form accumulations in the shallow structural, lithologic, stratigraphic and combination traps of the Guantao (Ng)–Minhuazhen (Nm) formations. With the recent discovery of several giant oilfields in the shallow Neogene reservoirs both onshore and offshore Bohai Bay Basin, the proposed ‘fault-fracture mesh petroleum play’ concept helps the exploration geologists to modify and clarify long held traditional concepts of petroleum play types in this basin, and expand upon the new exploration horizons of the shallow subtle petroleum traps. [Copyright &y& Elsevier]