Seismic based characterization of total organic content from the marine Sembar shale,Lower Indus Basin,Pakistan

The exploration and production of unconventional resources has increased significantly over the past few years around the globe to fulfill growing energy demands. Hydrocarbon potential of these unconventional petroleum systems depends on the presence of significant organic matter; their thermal maturity and the quality of present hydrocarbons i.e. gas or oil shale. In this work, we present a workflow for estimating Total Organic Content (TOC) from seismic reflection data. To achieve the objective of this study, we have chosen a classic potential candidate for exploration of unconventional reserves, the shale of the Sembar Formation, Lower Indus Basin, Pakistan. Our method includes the estimation of TOC from the well data using the Passey’s ΔlogR and Schwarzkofp’s methods. From seismic data, maps of Relative Acoustic Impedance (RAI) are extracted at maximum and minimum TOC zones within the Sembar Formation. A geostatistical trend with good correlation coefficient (R²) for cross-plots between TOC and RAI at well locations is used for estimation of seismic based TOC at the reservoir scale. Our results suggest a good calibration of TOC values from seismic at well locations. The estimated TOC values range from 1 to 4% showing that the shale of the Sembar Formation lies in the range of good to excellent unconventional oil/gas play within the context of TOC. This methodology of source rock evaluation provides a spatial distribution of TOC at the reservoir scale as compared to the conventional distribution generated from samples collected over sparse wells. The approach presented in this work has wider applications for source rock evaluation in other similar petroliferous basins worldwide.     

Source rock characteristics and hydrocarbon generation modelling of Upper Cretaceous Mukalla Formation in the Jiza-Qamar Basin,Eastern Yemen

The Upper Cretaceous Mukalla coals and other organic-rich sediments which are widely exposed in the Jiza-Qamar Basin and believed to be a major source rocks, were analysed using organic geochemistry and petrology. The total organic carbon (TOC) contents of the Mukalla source rocks range from 0.72 to 79.90% with an average TOC value of 21.50%. The coals and coaly shale sediments are relatively higher in organic richness, consistent with source rocks generative potential. The samples analysed have vitrinite reflectance in the range of 0.84–1.10 %Ro and pyrolysis T_max in the range of 432–454 °C indicate that the Mukalla source rocks contain mature to late mature organic matter. Good oil-generating potential is anticipated from the coals and coaly shale sediments with high hydrogen indices (250–449 mg HC/g TOC). This is supported by their significant amounts of oil-liptinite macerals are present in these coals and coaly shale sediments and Py-GC (S₂) pyrograms with n-alkane/alkene doublets extending beyond nC₃₀. The shales are dominated by Type III kerogen (HI < 200 mg HC/g TOC), and are thus considered to be gas-prone.One-dimensional basin modelling was performed to analysis the hydrocarbon generation and expulsion history of the Mukalla source rocks in the Jiza-Qamar Basin based on the reconstruction of the burial/thermal maturity histories in order to improve our understanding of the of hydrocarbon generation potential of the Mukalla source rocks. Calibration of the model with measured vitrinite reflectance (Ro) and borehole temperature data indicates that the present-day heat flow in the Jiza-Qamar Basin varies from 45.0 mW/m² to 70.0 mW/m² and the paleo-heat flow increased from 80 Ma to 25 Ma, reached a peak heat-flow values of approximately 70.0 mW/m² at 25 Ma and then decreased exponentially from 25 Ma to present-day. The peak paleo-heat flow is explained by the Gulf of Aden and Red Sea Tertiary rifting during Oligocene-Middle Miocene, which has a considerable influence on the thermal maturity of the Mukalla source rocks. The source rocks of the Mukalla Formation are presently in a stage of oil and condensate generation with maturity from 0.50% to 1.10% Ro. Oil generation (0.5% Ro) in the Mukalla source rocks began from about 61 Ma to 54 Ma and the peak hydrocarbon generation (1.0% Ro) occurred approximately from 25 Ma to 20 Ma. The modelled hydrocarbon expulsion evolution suggested that the timing of hydrocarbon expulsion from the Mukalla source rocks began from 15 Ma to present-day.     

Evaluation of Eocene source rock for potential shale oil and gas generation in north Cambay Basin,India

Source rock potential of 108 representative samples from 3 m intervals over a 324 m thick shale section of middle Eocene age from the north Cambay Basin, India have been studied. Variation in total organic carbon (TOC) and its relationship with loss on ignition (LOI) have been used for initial screening. Screened samples were subjected to Rock-Eval pyrolysis and organic petrography. A TOC log indicated wide variation with streaks of elevated TOC. A 30 m thick organic-rich interval starting at 1954 m depth, displayed properties consistent with a possible shale oil or gas reservoir. TOC (wt%) values of the selected samples were found to vary from 0.68% to 3.62%, with an average value of 2.2. The modified van Krevelen diagram as well as HI vs. T_max plot indicate prevalence of Type II to Type III kerogen. T_max measurements ranged from 425 °C to 439 °C, indicating immature to early mature stage, which was confirmed by the mean vitrinite reflectance values (%R_o of 0.63, 0.65 and 0.67 at 1988 m, 1954 m, and 1963 m, respectively). Quantification of hydrocarbon generation, migration and retention characteristics of the 30 m source rock interval suggests 85% expulsion of hydrocarbon. Oil in place (OIP) resource of the 30 m source rock was estimated to be 3.23 MMbbls per 640 acres. The Oil saturation index (OSI) crossover log showed, from a geochemical perspective, moderate risk for producing the estimated reserve along with well location for tapping the identified resource.     

Depositional environment and geochemical characteristics of the Lower Carboniferous source rocks in the Marsel area,Chu-Sarysu Basin,Southern Kazakhstan

There are two sets of carbonate source rocks in the Lower Carboniferous layers in Marsel: the Visean (C₁v) and Serpukhovian (C₁sr). 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 C₁v and C₁sr 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 C₁v and C₁sr were 0.79% and 0.5%, respectively, which were higher than the threshold of effective carbonate source rocks. Dominated by type-III kerogen, the C₁v and C₁sr 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 C₁v and C₁sr, 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 C₁v and C₁sr 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.     

Logging identification and characteristic analysis of marine–continental transitional organic-rich shale in the Carboniferous-Permian strata,Bohai Bay Basin

Currently, global shale gas exploration and exploitation are focused on marine shale. Recently, major shale gas-oil breakthroughs have been made within continental and marine–continental transitional shale in China. This study will show how transitional shale is of great importance. Based on geological field surveys, core observations, thin section analysis, organic geochemistry and X-ray diffraction, we systematically studied the basic geological characteristics (including lithology, mineral composition, and organic geochemistry) of this transitional shale. By comparative analysis of well logging data from 260 wells in the Taiyuan–Shanxi shale, we will show that these methods are effective for identifying organic-rich shale from conventional well logs and determining its thickness distribution in the Carboniferous–Permian strata of the Taiyuan–Shanxi transitional coal-bearing formation.The results indicate that the Taiyuan–Shanxi shale has a high TOC (most 2%–4%) and that the lithology is primarily carbonaceous shale with type Ⅱ₂-Ⅲ kerogens. The high thermal maturation (Ro ≥ 1.1%) favors the generation of gas. The mineral components primarily include clay minerals, quartz, and plagioclase with a moderate brittle mineral content (47 wt.%) and high clay mineral content (51 wt.%) dominated by kaolinite (43%) and mixed-layer illite-smectite (31%). The transitional organic-rich shale on conventional log curves is generally characterized by higher gamma ray (GR), neutron porosity (CNL), acoustic travel time (AC), resistivity (R_t), potassium (K), and uranium (U) readings and a lower density (DEN), photoelectric absorption index (PE) and thorium-uranium ratio (TH/U). After analyzing the log response characteristics of the organic-rich shale, the most sensitive logging curves (such as CNL, AC, DEN, PE and U) were optimized to conduct logging overlays and to construct cross-plots to qualitatively identify organic-rich shale. The identified organic-rich shale amalgamates in the middle-upper member of the Taiyuan Formation and the lower member of the Shanxi Formation consistent with the results of the TOC analysis and practical gas logging. Based on the qualitative evaluation methods of the modified △LogR and a multivariate linear regression model, we calculated the TOC of shale wells in the Taiyuan–Shanxi formation. From this we calculated the characteristic values of organic-rich shale thickness. The results indicate that organic-rich shale in the Taiyuan formation is thicker than that in the Shanxi formation. Additionally, the thickness of organic-rich shale within lagoons and deep reed swamp facies are much thicker (25–35 m and 40–80 m) than other structural profile types, whereas their lateral distribution is less than that of marine shale. The relatively small continuous thickness of the single shale layer and high clay content may have negative effects for developing the shale gas potential.     

Mineralogical analysis and the evaluation of the petrophysical parameter Vshale for reservoir description

Water saturation in otherwise hydrocarbon-saturated sandstones is closely related to the sandstone's clay mineralogy. Laboratory analysis of the clay mineralogy of three sandstones, containing kaolinite, chlorite and illite, is used to provide the basis for deciding which logs are most suitable for evaluating clay mineral content and distribution (V_shale). The gamma log, which is held traditionally to be a reliable ‘shale’ log, proves to be a poor indicator of shaliness (i.e. clay mineral content) in all three examples. Microresistivity (MSFL) logs, and in some instances neutron porosity logs, give the most realistic correlations with the actual clay mineralogy. Standard values for clay mineral properties which are often used in the petrophysical characterization of sandstones are thought to be unreliable especially when not used in conjunction with textural data from petrographic studies.     

Calibration of the mudrock compaction curve by eliminating the effect of organic matter in organic-rich shales: Application to the southern Ordos Basin,China

The mudrock log-derived compaction curve is a significant tool for investigating the primary migration of hydrocarbon, predicting fluid overpressure, estimating formation erosion thicknesses and restoring the buried history and paleo-structure of a basin. However, the presence of kerogen in organic-rich shales can create typically high logging values of the acoustic transit time. Thus, the abnormally high values of the acoustic transit time for organic-rich rocks may not truly reflect the porosity variations of subsurface rocks, leading to great uncertainties in the understanding of the mudstone compaction and a certain amount of error in the abnormal fluid pressure estimation when using the mudrock log-derived compaction curve. Therefore, it is necessary to recalibrate the mudstone compaction curve by eliminating the increment of the acoustic transit time caused by the kerogen content of organic-rich mudstones. Taking the southwest Ordos Basin as an example, this paper presents a new equivalent volume model based on the composition of organic-rich shale in which the kerogen content is also considered. Based on the quantitative relationship between the rock composition and the acoustic transit time, a quantitative formula for calculating the acoustic transit time increment caused by the kerogen is derived. This formula shows that the increment depends not only on the organic content but also on the occurrence state, pore size, pore fluid composition and other factors. X-ray diffraction (XRD) data were used to determine the main mineral composition of the mudstone and to calculate the acoustic transit time of the rock skeleton. Then, the mudstone compaction curve in the Zhenjing area was calibrated by combining the measured porosity and total organic carbon (TOC) of the mudstone based on the correction formula. The compaction characteristics varied significantly between before and after the calibration. The slope of the normal compaction trend (NCT) line decreased by 30–55%, and the acoustic transit time deviation from the NCT in the undercompaction interval decreased significantly. The overpressure at the maximum burial depth estimated by the equivalent depth method is in better agreement with the results obtained by numerical simulation after the calibration, and the porosity determined from the well log after the calibration is also closer to the true measured value. The method proposed in this paper is of great significance for improving the reliability and accuracy of compaction research on organic-rich mudstones, especially for the accurate estimation of abnormal pressure in the source rock layer. Additionally, it can be used as an effective reference for mudstone compaction studies in similar geological settings areas or basins.     

Models for dynamic evaluation of mudstone/shale cap rocks and their applications in the Lower Paleozoic sequences,Sichuan Basin,SW China

The estimation of the sealing capability of cap rocks dynamically is one of the fundamental geological problems that must be resolved in petroleum exploration. In this paper, a porosity–capillary pressure (ϕ–P_c) method was used to estimate the sealing capacity during cap rock burial and a permeability–capillary pressure (K–P_c) plus over-consolidation ratio (OCR) method to estimate the sealing capacity during uplift. Based on 120 capillary pressure–porosity measurements, a ϕ–P_c mathematical model has been established for the burial phase. By analyzing the permeability data measured from 12 mudstone/shale samples from different stratigraphic intervals under step loading conditions, a permeability–confining pressure (K–P) mathematical model has been constructed. Moreover, capillary pressure–permeability data measured from 141 mudstone or shale cap rocks have been used to establish a K–P_c mathematical model for seal capacity evaluation during uplift. Additionally, the OCR of mudstone or shale was calculated from the results of reconstructed burial and uplift histories. These mathematical models were used in case studies in the Sichuan Basin, South China. The results indicate that capillary pressure (P_c) is inadequate in evaluating sealing capacity of cap rocks but the combination of parameters P_c and OCR works well. The agreement between calculated and measured values shows the effectiveness and reliability of the models for dynamic estimation of the sealing capacity of mudstone/shale cap rocks established in this study.     

中国南海北部珠江口-琼东南盆地钻井岩屑地球化学特征及深水区天然气聚集特征

The Qiongdongnan Basin and Zhujiang River(Pearl River) Mouth Basin, important petroliferous basins in the northern South China Sea, contain abundant oil and gas resource. In this study, on basis of discussing impact of oil-base mud on TOC content and Rock-Eval parameters of cutting shale samples, the authors did comprehensive analysis of source rock quality, thermal evolution and control effect of source rock in gas accumulation of the Qiongdongnan and the Zhujiang River Mouth Basins. The contrast analysis of TOC contents and Rock-Eval parameters before and after extraction for cutting shale samples indicates that except for a weaker impact on Rock-Eval parameter S_2, oil-base mud has certain impact on Rock-Eval S_1, Tmax and TOC contents. When concerning oil-base mud influence on source rock geochemistry parameters, the shales in the Yacheng/Enping,Lingshui/Zhuhai and Sanya/Zhuhai Formations have mainly Type Ⅱ and Ⅲ organic matter with better gas potential and oil potential. The thermal evolution analysis suggests that the depth interval of the oil window is between 3 000 m and 5 000 m. Source rocks in the deepwater area have generated abundant gas mainly due to the late stage of the oil window and the high-supper mature stage. Gas reservoir formation condition analysis made clear that the source rock is the primary factor and fault is a necessary condition for gas accumulation. Spatial coupling of source, fault and reservoir is essential for gas accumulation and the inside of hydrocarbon-generating sag is future potential gas exploration area.     

Seismic inversion as a predictive tool for porosity and facies delineation in Paleocene fluvial/lacustrine reservoirs,Melut Basin,Sudan

The Melut Basin is a rift basin in the interior Sudan linked to the Mesozoic-Cenozoic Central and Western African Rift System. The Paleocene Yabus Formation is the main reservoir deposited in heterogeneous fluvial/lacustrine environment. Delineation of channel sandstone from shale is a challenge in reservoir exploration and development. We demonstrate a detailed 3D quantitative seismic interpretation approach that integrates petrophysical properties derived from well logs analysis. A porosity transform of acoustic impedance inversion provided a link between elastic and rock properties. Thus, we used seismic porosity to discriminate between different facies with appropriate validation by well logs. At the basin scale, the results revealed lateral and vertical facies heterogeneity in the Melut Basin. Good reservoir quality is observed in the Paleocene Yabus Formation. The sand facies indicated high porosity (20%) corresponding to low acoustic impedance (20000–24000 g ft/(cm3.s)). However, lower quality reservoir is observed in the Cretaceous Melut Formation. The porosity of sand/shale facies is low (5%), corresponding to high acoustic impedance (29000–34000 g ft/(cm3.s)). This suggests that the Yabus Sandstone is potentially forming a better reservoir quality than Melut Formation. At the reservoir scale, we evaluated the facies quality of Yabus Formation subsequences using petrophysical analysis. The subsequences YB1 to YB3, YB4 to YB7 and YB8 to YB10 showed relatively similar linear regressions, respectively. The subsequence of YB4 to YB7 is considered the best reservoir with higher porosity (25%). However, subsequence YB1 to YB3 showed lower reservoir quality with higher shale volume (30%). This attributed to floodplain shale deposits in this subsequence. Similarly, the high porosity (20%) recognized in deeper subsequences YB6 to YB9 is due to clean sand facies. We learnt a lesson that appropriate seismic preconditioning, exhaustive petrophysical analysis and well log validation are important keys for improved reservoir quality prediction results in fluvial/lacustrine basins.     

Geological roles of the siltstones in tight oil play

Understanding the hydrocarbon accumulation pattern in unconventional tight reservoirs is crucial for hydrocarbon evaluation and oil/gas extraction from such reservoirs. Previous studies on tight oil accumulation are mostly concerned with self-generation or from source to reservoir rock over short distances. However, the Lucaogou tight oil in Jimusar Sag of Junggar Basin shows transitional feature in between. The Lucaogou Formation comprises fine-grain sedimentary rocks characterized by thin laminations and frequently alternating beds. The Lucaogou tight silt/fine sandstones are poorly sorted. Dissolved pores are the primary pore spaces, with average porosity of 9.20%. Although the TOC of most silt/fine sandstones after Soxhlet extraction is lower than that before extraction, they show that the Lucaogou siltstones in the area of study have fair to good hydrocarbon generation potential (average TOC of 1.19%, average S₂ of 4.33 mg/g), while fine sandstones are relatively weak in terms of hydrocarbon generation (average TOC of 0.4%, average S₂ of 0.78 mg/g). The hydrocarbon generation amount of siltstones, which was calculated according to basin modeling transformation ratio combined with original TOC based on source rock parameters, occupies 16%–72% of oil retention amount. Although siltstones cannot produce the entire oil reserve, they certainly provide part of them. Grain size is negatively correlated with organic matter content in the Lucaogou silt/fine sandstones. Fine grain sediments are characterized by lower deposition rate, stronger adsorption capacity and oxidation resistance, which are favorable for formation of high quality source rocks. Low energy depositional environment is the primary reason for the formation of siltstones containing organic matter. Positive correlation between organic matter content and clay content in Lucaogou siltstones supports this view point. Lucaogou siltstones appear to be effective reservoir rocks due to there relatively high porosity, and also act as source rocks due to the fair to good hydrocarbon generation capability.     

Pore characterization of organic-rich Lower Cambrian shales in Qiannan Depression of Guizhou Province,Southwestern China

Nine organic-rich shale samples of Lower Cambrian black shales were collected from a recently drilled well in the Qiannan Depression, Guizhou Province where they are widely distributed with shallower burial depth than in Sichuan Basin, and their geochemistry and pore characterization were investigated. The results show that the Lower Cambrian shales in Qiannan Depression are organic rich with TOC content ranging from 2.81% to 12.9%, thermally overmature with equivalent vitrinite reflectance values in the range of 2.92–3.25%, and clay contents are high and range from 32.4% to 53.2%. The samples have a total helium porosity ranging from 2.46% to 4.13% and total surface area in the range of 9.08–37.19 m²/g. The estimated porosity in organic matters (defined as the ratio of organic pores to the volume of total organic matters) based on the plot of TOC vs helium porosity is about 10% for the Lower Cambrian shales in Qiannan Depression and is far lower than that of the Lower Silurian shales (36%) in and around Sichan Basin. This indicates that either the organic pores in the Lower Cambrian shale samples have been more severely compacted than or they did not develop organic pores as abundantly as the Lower Silurian shales. Our studies also reveal that the micropore volumes determined by Dubinin–Radushkevich (DR) equation is usually overestimated and this overestimation is closely related to the non-micropore surface area of shales (i.e. the surface area of meso- and macro-pores). However, the modified BET equation can remove this overestimation and be conveniently used to evaluate the micropore volumes/surface area and the non-micropore surface areas of micropore-rich shales.     

基于颜色显示快速估算页岩有机碳含量的新方法

有机碳含量(TOC)是页岩气储层评价的关键参数之一,它既是页岩生气的物质基础,也是页岩吸附气的重要载体。以鄂尔多斯盆地山西组页岩系统为例,根据不同的颜色显示划分出4种岩性:黑色煤、灰黑色页岩、灰色页岩、灰白色粉砂岩,赋予这4种岩性不同的颜色显示值,计算页岩系统的总颜色评价值(TCA),拟合页岩系统中TCA和实测TOC之间的关系,依据TCA估算页岩系统的TOC。研究发现,当页岩系统中4种岩性的颜色显示值为等比数列(1、2、4、8)时,TCA和实测TOC相关系数(R2)高,且以指数拟合和三次方拟合的相关系数(R2)最高;页岩系统中TCA的对数和实测TOC的对数呈现良好的正相关性,根据页岩中TCA估算的TOC和实测TOC十分接近。因此,在室外工作中可以利用该方法快速估算页岩系统的TOC,从而为页岩气目标层段的优选提供参考依据。     

Gas hydrate saturation in the Krishna–Godavari basin from P-wave velocity and electrical resistivity logs

During the Indian National Gas Hydrate Program (NGHP) Expedition 01, a series of well logs were acquired at several sites across the Krishna–Godavari (KG) Basin. Electrical resistivity logs were used for gas hydrate saturation estimates using Archie’s method. The measured in situ pore-water salinity, seafloor temperature and geothermal gradients were used to determine the baseline pore-water resistivity. In the absence of core data, Arp’s law was used to estimate in situ pore-water resistivity. Uncertainties in the Archie’s approach are related to the calibration of Archie coefficient (a), cementation factor (m) and saturation exponent (n) values. We also have estimated gas hydrate saturation from sonic P-wave velocity logs considering the gas hydrate in-frame effective medium rock-physics model. Uncertainties in the effective medium modeling stem from the choice of mineral assemblage used in the model. In both methods we assume that gas hydrate forms in sediment pore space. Combined observations from these analyses show that gas hydrate saturations are relatively low (<5% of the pore space) at the sites of the KG Basin. However, several intervals of increased saturations were observed e.g. at Site NGHP-01-03 (S_h = 15–20%, in two zones between 168 and 198 mbsf), Site NGHP-01-05 (S_h = 35–38% in two discrete zone between 70 and 90 mbsf), and Site NGHP-01-07 shows the gas hydrate saturation more than 25% in two zones between 75 and 155 mbsf. A total of 10 drill sites and associated log data, regional occurrences of bottom-simulating reflectors from 2D and 3D seismic data, and thermal modeling of the gas hydrate stability zone, were used to estimate the total amount of gas hydrate within the KG Basin. Average gas hydrate saturations for the entire gas hydrate stability zone (seafloor to base of gas hydrate stability), sediment porosities, and statistically derived extreme values for these parameters were defined from the logs. The total area considered based on the BSR seismic data covers ∼720 km². Using the statistical ranges in all parameters involved in the calculation, the total amount of gas from gas hydrate in the KG Basin study area varies from a minimum of ∼5.7 trillion-cubic feet (TCF) to ∼32.1 TCF.     

Pore structure and fractal characteristics of organic-rich shales: A case study of the lower Silurian Longmaxi shales in the Sichuan Basin,SW China

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 N₂ 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 D₁ and D₂ respectively. D₁ ranged from 2.60 to 2.71 and D₂ ranged from 2.71 to 2.82. D₁ was typically smaller than D₂, 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 D₁ and D₂. Fractal dimensions are useful for the characterization of the pore structures complexity of the Longmaxi Formation shales because D₁ and D₂ correlate well with pore structure parameters as they both increase with the increase of surface area and the decrease of average pore diameter.     

Enrichment and distribution of shale oil in the Cretaceous Qingshankou Formation,Songliao Basin,Northeast China

The Songliao Basin is a large-scale petroliferous basin in China. With a gradual decline in conventional oil production, the exploration and development of replacement resources in the basin is becoming increasingly important. Previous studies have shown that the Cretaceous Qingshankou Formation (K₂qn) has favorable geological conditions for the formation of shale oil. Thus, shale oil in the Qingshankou Formation represents a promising and practical replacement resource for conventional oil. In this study, geological field surveys, core observation, sample tests, and the analysis of well logs were applied to study the geochemical and reservoir characteristics of shales, identify shale oil beds, build shale oil enrichment models, and classify favorable exploration areas of shale oil from the Cretaceous Qingshankou Formation. The organic matter content is high in shales from the first member of the Cretaceous Qingshankou Formation (K₂qn¹), with average total organic carbon (TOC) content exceeding 2%. The organic matter is mainly derived from lower aquatic organisms in a reducing brackish to fresh water environment, resulting in mostly type I kerogen. The vitrinite reflectance (Ro) and the temperature at which the maximum is release of hydrocarbons from cracking of kerogen occurred during pyrolysis (T_max) respectively range from 0.5% to 1.1% and from 430 °C to 450 °C, indicating that the K₂qn¹ shales are in the low-mature to mature stage (Ro ranges from 0.5% to 1.2%) and currently generating a large amount of oil. The favorable depth for oil generation and expulsion is 1800–2200 m and 1900–2500 m, respectively as determined by basin modeling. The reserving space of the K₂qn¹ shale oil includes micropores and mircofractures. The micropore reservoirs are developed in shales interbedded with siltstones exhibiting high gamma ray (GR), high resistivity (Rt), low density (DEN), and slightly abnormal spontaneous potential (SP) in the well-logging curves. The microfracture reservoirs are mainly thick shales with high Rt, high AC (acoustic transit time), high GR, low DEN, and abnormal SP. Based on the shale distribution, geochemical characteristics, reservoir types, fracture development, and the process of shale oil generation and enrichment, the southern Taikang and northern Da'an are classified as two favorable shale oil exploration areas in the Songliao Basin.     

Geochemistry,reservoir characterization and hydrocarbon generation potential of lacustrine shales: A case of YQ-1 well in the Yuqia Coalfield,northern Qaidam Basin,NW China

Ever since a breakthrough of marine shales in China, lacustrine shales have been attracting by the policy makers and scientists. Organic-rich shales of the Middle Jurassic strata are widely distributed in the Yuqia Coalfield of northern Qaidam Basin. In this paper, a total of 42 shale samples with a burial depth ranging from 475.5 m to 658.5 m were collected from the Shimengou Formation in the YQ-1 shale gas borehole of the study area, including 16 samples from the Lower Member and 26 samples from the Upper Member. Geochemistry, reservoir characteristics and hydrocarbon generation potential of the lacustrine shales in YQ-1 well were preliminarily investigated using the experiments of vitrinite reflectance measurement, maceral identification, mineralogical composition, carbon stable isotope, low-temperature nitrogen adsorption, methane isothermal adsorption and rock eval pyrolysis. The results show that the Shimengou shales have rich organic carbon (averaged 3.83%), which belong to a low thermal maturity stage with a mean vitrinite reflectance (R_o) of 0.49% and an average pyrolytic temperature of the generated maximum remaining hydrocarbon (T_max) of 432.8 °C. Relative to marine shales, the lacustrine shales show low brittleness index (averaged 34.9) but high clay contents (averaged 55.1%), high total porosities (averaged 13.71%) and great Langmuir volumes (averaged 4.73 cm⁻³ g). Unlike the marine and marine-transitional shales, the quartz contents and brittleness index (BI) values of the lacustrine shales first decrease then increase with the rising TOC contents. The kerogens from the Upper Member shales are dominant by the oil-prone types, whereas the kerogens from the Lower Member shales by the gas-prone types. The sedimentary environment of the shales influences the TOC contents, thus has a close connection with the hydrocarbon potential, mineralogical composition, kerogen types and pore structure. Additionally, in terms of the hydrocarbon generation potential, the Upper Member shales are regarded as very good and excellent rocks whereas the Lower Member shales mainly as poor and fair rocks. In overall, the shales in the top of the Upper Member can be explored for shale oil due to the higher free hydrocarbon amount (S₁), whereas the shales in the Lower Member and the Upper Member, with the depths greater than 1000 m, can be suggested to explore shale gas.     

Stable carbon isotope ratios of CH4-rich gas inclusions in shale-hosted fracture-fill mineralization: A tool for tracing hydrocarbon generation and migration in shale plays for oil and gas

Fluid inclusion gases in minerals from shale hosted fracture-fill mineralization have been analyzed for stable carbon isotopic ratios of CH₄ using a crushing device interfaced to an isotope ratio mass spectrometer (IRMS). The samples of Paleozoic strata under study originate from outcrops and wells in the Rhenish Massif and Campine Basin, Harz Mountains, and the upper slope of the Southern Permian Basin. Fracture-fill mineralization hosted by Mesozoic strata was sampled from drill cores in the Lower Saxony Basin. Some studied sites are candidates for shale gas exploration in Germany. Samples of Mesozoic strata are characterized by abundant calcite-filled horizontal fractures which preferentially occur in TOC-rich sections of the drilled sediments. Only rarely are vertical fractures filled with carbonates and/or quartz in drill cores from Mesozoic strata but in Paleozoic shale they occur frequently. The δ¹³C(CH₄) values of fluid inclusions in calcite from horizontal fractures hosted by Mesozoic strata suggest that gaseous hydrocarbons were generated during the oil/early gas window and that the formation of horizontal fractures seems to be related to hydraulic expulsion fracturing. The calculated maturity of the source rocks at the time of gas generation lies below the maturity derived from measured vitrinite reflectance. Thus, the formation of horizontal fractures and trapping of gas that was generated in the oil and/or early gas window obviously occurred prior to maximal burial. Rapidly increasing vitrinite reflectance data seen locally can be explained by hydrothermal alteration, as indicated by increasing δ¹³C (CH₄–CO₂) values in fluid inclusions. The formation of vertical fractures in studied Mesozoic sediments is related to stages of post-burial inversion; gas-rich inclusions in fracture filling minerals recorded the migration of gas that had probably been generated instantaneously, rather than cumulatively, from high to overmature source rocks. Since no evidence is given for the presence of early generated gas in studied Paleozoic shale, it appears likely that major gas loss from shales occurred due to deformation and uplift of these sediments in response to the Variscan Orogeny.     

Properties and shale oil potential of saline lacustrine shales in the Qianjiang Depression,Jianghan Basin,China

The geochemical and petrographic characteristics of saline lacustrine shales from the Qianjiang Formation, Jianghan Basin were investigated by organic geochemical analysis, X-ray diffraction (XRD), scanning electron microscopy (SEM) and low pressure nitrogen adsorption analysis. The results indicate that: the saline lacustrine shales of Eq3 member with high oil content are characterized by type I and type II oil-prone kerogen, variable TOC contents (1.0–10.0 wt%) and an early-maturity stage (R_o ranges between 0.41 and 0.76%). The mineral compositions of Eq3 saline shale show strong heterogeneity: brittle intervals with high contents of quartz and carbonate are frequently alternated with ductile intervals with high glauberite and clay contents. This combination might be beneficial for oil accumulation, but may cause significant challenges for the hydraulic stimulation strategy and long-term production of shale oil. The interparticle pores and intraparticle pores dominate the pore system of Eq3 shale, and organic matter hosted pores are absent. Widely distributed fractures, especially tectonic fractures, might play a key role in hydrocarbon migration and accumulation. The pore network is contributed to by both large size inorganic pores and abundant micro-factures, leading to a relatively high porosity (2.8–30.6%) and permeability (0.045–6.27 md) within the saline shale reservoir, which could enhance the flow ability and storage capacity of oil. The oil content (S₁ × 100/TOC, mg HC/g TOC and S₁, mg HC/g rock) and brittleness data demonstrate that the Eq3^3x section has both great potential for being a producible oil resource and hydraulic fracturing. Considering the hydrocarbon generation efficiency and properties of oil, the mature shale of Eq3 in the subsidence center of the Qianjiang Depression would be the most favorable zone for shale oil exploitation.     

Comprehensive polynomial simulation and prediction for Langmuir volume and Langmuir pressure of shale gas adsorption using multiple factors

In this study, 32 experimental measurements on the isothermal adsorption of methane for 18 shale samples from China's three largest continental oil basins—Songliao, Bohai Bay, and Ordos basins—were used to construct comprehensive polynomial simulation and prediction models for Langmuir volume and Langmuir pressure. The models were based on shale properties (total organic carbon (TOC) content, amount of residual hydrocarbon S₁, and mineral composition of rocks) and adsorption condition (temperature) using a weighted sum of multiple variables. The influences of various factors were quantitatively characterized, and the prediction accuracy was verified. Langmuir volume is mainly affected by temperature, shale TOC content, amount of residual hydrocarbon, and clay mineral content; Langmuir pressure is mainly affected by clay, carbonate, feldspar and illite content (because shale pore size can be affected by shale mineral composition). Based on the resource potential and the producibility of shale gas, the area suitable for shale gas exploration and development should have high abundance of organic matter (TOC and residual hydrocarbon S₁), low clay mineral content and feldspar content, high conversion rate of montmorillonite to illite (strong diagenesis), and high carbonate content. The comprehensive polynomial prediction model can effectively simulate and predict Langmuir volume and Langmuir pressure, thereby reducing the amount of work necessary for evaluation of shale gas resource potential and economic feasibility.