Petroleum Geology Research Articles

Three-dimensional reconstruction of granular porous media based on deep generative models.

Reconstruction of microstructure in granular porous media, which can be viewed as granular assemblies, is crucial for studying their characteristics and physical properties in various fields concerned with the behavior of such media, including petroleum geology and computational materials science. In spite of the fact that many existing studies have investigated grain reconstruction, most of them treat grains as simplified individuals for discrete reconstruction, which cannot replicate the complex geometrical shapes and natural interactions between grains. In this work, a hybrid generative model based on a deep-learning algorithm is proposed for high-quality three-dimensional (3D) microstructure reconstruction of granular porous media from a single two-dimensional (2D) slice image. The method extracts 2D prior information from the given image and generates the grain set as a whole. Both a self-attention module and effective pattern loss are introduced in a bid to enhance the reconstruction ability of the model. Samples with grains of varied geometrical shapes are utilized for the validation of our method, and experimental results demonstrate that our proposed approach can accurately reproduce the complex morphology and spatial distribution of grains without any artificiality. Furthermore, once the model training is complete, rapid end-to-end generation of diverse 3D realizations from a single 2D image can be achieved.

Petroleum geology of conventional and unconventional resources: Introduction

Understanding reservoir, source, seal, migration pathways and trap characterization is the first step towards better energy resource exploitation. Several studies have been conducted in recent decades on the reservoir characteristics of conventional resources. Unconventional resources, on the other hand, have received more attention as alternative future energy solutions to depleted conventional resources. Drilling, exploration, development, and production of conventional and unconventional resources pose technical challenges to the energy industry. This special issue attempts to address the most pressing technical challenges in developing conventional reservoirs (such as sandstone and carbonate reservoirs) as well as unconventional energy sources (e.g., shale gas, shale oil, tight gas sand, coal bed methane, geothermal and gas hydrates). The special issue is composed of 21 papers that are classified into six different groups related to the physical and mechanical properties of reservoirs, petroleum geochemistry, petroleum geology, geological modelling, unconventional resource evaluation and conventional reservoir evaluation.

Characteristics of bound biomarkers released from pyrobitumens generated from the cracking of different types of crude oils

Pyrobitumen has attracted significant attention from petroleum geologists and geochemists due to its close relationship with crude oil and natural gas. Generally, the analysis of free biomarkers in pyrobitumen is of limited use, because these biomarkers can be easily modified by biodegradation and thermal alteration. The utilization of bound biomarkers in pyrobitumen appears to be a viable solution to address these issues. However, the compositions and concentrations of bound biomarker moieties in pyrobitumen can also be influenced by external factors such as thermal stress during its formation and the original abundance of asphaltenes in oil. The goal of this study is to examine the evolutionary history of free and bound biomarkers during the formation process of pyrobitumen from different types of crude oil. This is beneficial for the interpretation of covalently bound biomarkers released from natural pyrobitumens in applications such as oil/gas–solid bitumen-source correlation and oil/gas migration studies. Anhydrous and hydrous pyrolysis experiments were conducted on three types of crude oil (condensate, black oil, and heavy oil) to simulate the formation process of pyrobitumen. The comparison of free biomarkers in the liquid residuals of the oil pyrolysis and the bound biomarkers released by the hydropyrolysis of the corresponding pyrobitumen products indicated that the differences between free and bound biomarkers vary with the types of original oils. At elevated thermal maturity (Easy %Ro ≥ ca. 1.0%), the higher the absolute abundance of the asphaltene fraction within a particular oil, the greater the similarity between the distribution of bound biomarkers (especially for steroids) released from pyrobitumen and the corresponding original oil. Thus, the use of pyrobitumen-bound biomarkers formed by heavy oil (asphaltene-rich) can obtain relatively accurate biogenic information on paleo-reservoirs. However, caution should be exercised when employing pyrobitumen-bound biomarkers in paleo-reservoirs formed by light oil (asphaltene-depleted).

Numerical Simulation Analysis of Wellbore Integrity and Casing Damage in High-Temperature Injection and Production of Shale Oil

Shale oil represents a relatively new form of unconventional oil and gas resource, and the extensive exploration and development of shale oil resources carry significant implications for China’s oil and gas supply and demand dynamics. At present, within the realm of low-maturity shale oil extraction technologies, the reservoir must be subjected to elevated temperatures ranging between 400 to 60 °C. Prolonged exposure of wellbores to such high temperatures can result in a substantial decrease in cement strength, the formation of microcracks due to cement cracking, and damage stemming from thermal stresses on the casing. Casing damage stands out as a prominent factor contributing to wellbore integrity failures and well shutdowns within the context of shale oil development. Given the limited natural energy reservoirs of shale oil formations, it becomes necessary to supplement the reservoir’s energy during the development process. Furthermore, shale oil exhibits high viscosity and poor flowability, and conventional water injection methods yield limited efficacy. This situation can induce significant shifts in the stress field and rock mechanical parameters, potentially activating specific formations and complicating the load dynamics on the casing. Consequently, the risk of failure increases. In light of these considerations, this study uses numerical simulations to study the integrity of high-temperature injection and production wellbores in shale oil and aims to encompass a comprehensive evaluation and analysis of the principal factors that influence casing damage, the fluctuations in thermal stress, and the yield strength of various steel grades of casings exposed to alternating stress conditions. Subsequently, this paper developed a model for simulating the temperature and pressure within shale oil and steam injection wellbores to support engineering design analysis. The research results indicate that the application of pre-stress results in a significant increase in stress at the casing pipe head while causing a noticeable decrease in stress within the pipe wall. When N80 casing is used, the entire casing experiences thermal stresses surpassing the casing’s yield limit. Stress concentration may arise at both ends of the external seal, potentially leading to casing contraction, shear failure, and, under non-uniform stress conditions, casing bending deformation. The temperature of steam injection significantly influences the temperature field of the casing wall, with stress values experiencing a marked reduction when the steam injection temperature decreases from 350 °C to 200 °C, underscoring the substantial impact of temperature on casing thermal stress. As the steam injection process advances along with injection-production cycles, shear stresses at the interface can exceed the bond strength, resulting in relative slippage between the cement and the casing. The bonding force between the wellbore and the cement primarily depends on the interface’s friction, particularly in the context of friction during wellhead lifting. This study endeavors to determine rational injection and production parameters under varying conditions, optimize completion methods, reduce casing damage, and extend the casing’s operational life; it aims to offer critical technical support for the safe and efficient development of shale oil resources.

Impact of Thermal Maturation of the Upper Cretaceous Bituminous Limestone of Attarat Um Ghudran Central Jordan on Calcareous Nannofossil Preservation.

Oil shale deposits of the Late Cretaceous from three boreholes in central Jordan were examined to assess the impact of thermal maturation on the content of nannofossils. Thermal activity has been shown to have a strong effect on organic matter content and composition but its effect on calcareous nannofossil assemblages remains inconclusive. This study aims to determine the impact of thermal maturation on nannofossil assemblages and to compare this to an estimated maturity level based on bulk geochemical analysis. Micropaleontological and geochemical analyses were conducted on 31 samples from three oil shale wells drilled in Attarat Um Ghudran central Jordan. Several types of nannofossil preservation have been recorded, including dissolution, overgrowth, and breakage. In the Jordan oil shale sections, nannofossils exhibit a variety of preservation types, with intense dissolution in the middle part of the study sections. The vast majority of the samples had high TOC enrichment, with 29 samples exceeding values of >10%. Kerogen recovery and quality from the oil shale are very good, with a predominance of fluorescent amorphous organic matter (AOM) and minor algal components. The low fluorescence preservation index (FPI), which is 1 in most of the samples, indicates that alteration occurred due to intense thermal activities in the study interval. The palynomorph and AOM fluorescence, ranging from a spore coloration index (SCI) of 3 to 5, suggest that the studied samples were approaching the oil window. A correlation between the nannofossil preservation and geochemical parameters shows a predominance of poorly preserved nannofossils along with high total organic carbon contents and an elevated hydrogen index (HI). We show that low FPI values and a higher level of maturity are associated with poor nannofossil preservation, suggesting that nannofossils, in conjunction with petrographic analysis of kerogen, could be used as a rapid screening technique for estimating levels of oil-shale maturity. The nature of the tectonism in the study area, including faulting and a metamorphosed zone, enhanced the maturity, which might explain why the nannofossils were so significantly affected.

Diagenesis, paleoenvironments, and petroleum geology of sediments lining the West and Central African Rift System, Koum Basin, North Cameroon

Diagenesis, paleoenvironments, and petroleum geology of sediments lining the West and Central African Rift System, Koum Basin, North Cameroon

Petroleum geology of marl in Triassic Leikoupo Formation and discovery significance of Well Chongtan1 in central Sichuan Basin, SW China

In 2022, the risk exploration well Chongtan1 (CT1) in the Sichuan Basin revealed commercial oil and gas flow during test in a new zone – the marl of the second submember of the third member of Leikoupo Formation (Lei-32) of Middle Triassic, recording a significant discovery. However, the hydrocarbon accumulation in marl remains unclear, which restricts the selection and deployment of exploration area. Focusing on Well CT1, the hydrocarbon accumulation characteristics of Lei-32 marl are analyzed to clarify the potential zones for exploration. The following findings are obtained. First, according to the geochemical analysis of petroleum and source rocks, oil and gas in the Lei-32 marl of Well CT1 are originated from the same marl. The marl acts as both source rock and reservoir rock. Second, the Lei-32 marl in central Sichuan Basin is of lagoonal facies, with a thickness of 40–130 m, an area of about 40 000 km2, a hydrocarbon generation intensity of (4–12)×108 m3/km2, and an estimated quantity of generated hydrocarbons of 25×1012 m3. Third, the lagoonal marl reservoirs are widely distributed in central Sichuan Basin. Typically, in Xichong–Yilong, Ziyang–Jianyang and Moxi South, the reservoirs are 20–60 m thick and cover an area of 7500 km2. Fourth, hydrocarbons in the lagoonal marl are generated and stored in the Lei-32 marl, which means that marl serves as both source rock and reservoir rock. They represent a new type of unconventional resource, which is worthy of exploring. Fifth, based on the interpretation of 2D and 3D seismic data from central Sichuan Basin, Xichong and Suining are defined as favorable prospects with estimated resources of (2000–3000)×108 m3.

Single-Factor Comprehensive Reservoir Quality Classification Evaluation-Taking the Hala'alat Mountains at the Northwestern Margin of the Junggar Basin as an Example.

In the process of petroleum geology exploration and development, reservoir quality evaluation is an essential component. However, conventional reservoir quality evaluation methods are no longer able to provide accurate and comprehensive assessments for all types of reservoirs. Therefore, the comprehensive evaluation of reservoir quality using multiple single factors is of significant importance in improving the level of reservoir quality assessment and enhancing the effectiveness of oil and gas exploration techniques. Conventional reservoir quality evaluation methods can assess only the quality of individual reservoir properties, resulting in limited classification outcomes. Taking the Cretaceous formations in the southern margin of the Hala'alat Mountain in the Junggar Basin as the research object, preliminary classification criteria were established based on the principles of formation coefficient, storage coefficient, and flow unit index. Combining experimental data such as core observation, thin-section identification, pore permeability analysis, and scanning electron microscopy, a comprehensive set of reservoir quality classification and evaluation criteria were developed. Furthermore, the corresponding reservoir classification evaluation maps were generated to illustrate the spatial distribution of reservoir quality. The study reveals that the area can be classified into four types of reservoirs, namely, Class I, Class II, Class III, and Class IV, corresponding to the best reservoir, relatively good reservoir, relatively poor reservoir, and poor reservoir, respectively. Among them, the second (K1q2) and third (K1q3) members of the Cretaceous Qingshuihe Formation, as well as the first (K1h1) and third (K1h3) members of the Cretaceous Hutubi Formation, exhibit the best reservoir quality as Class II. On the other hand, the second member of the Cretaceous Hutubi Formation (K1h2) exhibits the best reservoir quality as Class III, with relatively poorer reservoir quality overall. The research findings of this study can provide an important theoretical basis for oil and gas exploration and development in the region.

The effect of chlorite rims on reservoir quality in Chang 7 sandstone reservoirs in the Ordos Basin, China

Chlorite rims have been of interest to petroleum geologists over the past several decades, as a significant number of abnormal high-porosity sandstone reservoirs at great depths have been related to chlorite rims. To clarify the contribution of chlorite rims to porosity preservation in sandstones, the relationship between chlorite rims and porosity evolution in Chang 7 sandstones of the Upper Triassic Yanchang Formation in the Ordos Basin in north-central China was investigated using thin sections, scanning electron microscopy, energy dispersive X-ray spectroscopy, and X-ray diffraction analyses. Based on the detrital composition and diagenetic evolution pathway analyses, it was concluded that chlorite rims inhibited the formation of quartz cementation. However, in addition to quartz cementation, compaction and other cements (commonly carbonates and clays) also control the porosity evolution of sandstones. In sandstones in which porosity reduction is largely controlled by compaction or other cements, chlorite rims may have a limited effect on porosity preservation. Thus, chlorite rims can play an important role in porosity preservation only in sandstones in which quartz cementation is the main process of porosity destruction. The results of this study indicate that the development of high-porosity sandstones is often controlled by many factors, and the effects of chlorite rims on porosity preservation are not always significant.

Improvement of in situ LA-ICP-MS U-Pb dating method for carbonate minerals and its application in petroleum geology

Improvement of in situ LA-ICP-MS U-Pb dating method for carbonate minerals and its application in petroleum geology

The environmental transformation mechanism of the coal- and oil shale-bearing interval in the Eocene Dalianhe Formation, Yilan Basin, Northeast China

Assemblages of multiple organic matter (OM)-related sedimentary energy systems are common in the Eocene nonmarine basins of Northeast China. During the Middle Eocene Climatic Optimum, oil shale developed in large quantities in the Yilan Basin. Numerous scientific papers have concentrated on the sedimentary cycle and industrial quality of the coal- and oil shale-bearing intervals, whereas few studies have studied the genetic environmental transformation mechanism of the coal and oil shale deposits. The Dalianhe Formation cover thick oil shale member and coal unit, which is a natural archive for studying the environmental evolution of lake swamp systems. In the present paper, the thermal maturity of organic matter (OM), oil shale industrial quality, coal rank, source of OM and paleoenvironmental conditions associated with OM accumulation in the Yilan Basin are investigated through bulk geochemical analyses, organic maceral analyses and biomarker composition analyses. The coal in the Yilan Basin is classified as subbituminous coal with high total organic carbon (TOC) values, high oil yields, low ash yields, and type II OM. The quality of the low-maturity oil shale in the Coal-Bearing Member is better than that in the Oil Shale Member. The oil shale in the Yilan Basin has type I-II OM and relatively high oil yields, which corresponds to the considerable content of liptinite with a predominantly alginite composition. Based on the higher Pr/Ph values, coal was deposited under oxic–dysoxic conditions, and the OM in the coal mainly originated from terrestrial plants, whereas the oil shale accumulated in a dysoxic environment with lower Pr/Ph values, and featured mixed OM sources, including terrestrial plants and low aquatic organisms. Affected by lake level fluctuations and wide peat swamping, the thickest and highest-quality coal and oil shale developed in swamps under a dysoxic–oxic water column in freshwater environments. Subsequently, the lake basin expanded rapidly, and the sedimentary environment changed to a dysoxic–oxic semideep–deep lake, in which extremely thick mudstone and a large amount of inferior oil shale with low oil yields accumulated under the influence of gravity flows. The basin continued to rapidly subside, the water column became anoxic–dysoxic, and the deposition of mudstone, siltstone and fine sandstone predominated.

Differentiation of the Bazhenov Formation Bitumoids in the North-Surgut Region during Generation and Migration

Abstract —The Bazhenov Formation of the Western Siberian oil-and-gas province is currently one of the key objects of potential growth in oil reserves and production. Here we present results of a geochemical study of the Bazhenov Formation according to the methodology developed at Trofimuk Institute of Petroleum Geology and Geophysics, Novosibirsk (IPGG SB RAS) for rocks highly enriched in organic matter. The features of the group and hydrocarbon compositions of the bitumoids that are filling open and closed pores of the Bazhenov Formation rocks from the North-Surgut region were considered. It has been established that most of the naphthides are in a free (phase-segregated) or sorbed state in a closed pore space. The open pores contain the most mobile components of bitumoids, redistributed from closed pores during the primary migration and remained after the secondary migration of naphtides from the Bazhenov Formation to the Berriasian–lower Aptian reservoirs (A and B strata groups). The methodology used in this work allows determining intervals with increased open porosity and oil saturation in the section of the Bazhenov Formation (silicites and carbonates) by the volume of pore space occupied by open-pore bitumoids.

A novel method for petroleum and natural gas resource potential evaluation and prediction by support vector machines (SVM)

Petroleum and natural gas resources (PNGR) are some of the major forms of fossil energy that are important for the development of industry and energy security. Along with the growing demand of petroleum consumption and the requirement for enhancing drilling success rate, reducing the exploration risk and saving exploration cost, prediction method for PNGR potential with high accuracy and wide practicability is needed. However, the existing PNGR evaluation and prediction methods based on traditional statistical principles are far from meeting the requirements of the present petroleum exploration and exploitation. Therefore, this study introduces a novel method for PNGR potential prediction by applying support vector machines (SVM) in the context of the rapid development of artificial intelligence and machine learning. This novel machine learning methodology first proposed a combination of support vector classification (SVC) for hydrocarbon accumulation probability prediction and then support vector regression (SVR) for reserve abundance prediction. The combining use of classification and regression model can fully utilize the professional knowledge of petroleum geology and the powerful data processing capabilities of machine learning algorithms and hence significantly improve the performance of the method. Furthermore, the dataset is set based on petroleum geology knowledge with the feature variables of source rock, sandstone reservoirs, sealing capacity and hydrocarbon migration, whose distribution are predictable and thus ensures the predictive effect in practical petroleum exploration. The results show that the testing accuracy of the hydrocarbon accumulation probability evaluation model by SVC ranges from 80% to 100% with an average of 88.92%. The performance of the SVR model for evaluating reserve abundance also performs well with the highest correlation coefficient of 0.767. In addition, several validation ways are applied for testing the reliability and stability of the model. For a hold-out test for a new zone, the model provides precise prediction of hydrocarbon accumulation probability and reserve abundance with an accuracy of 72.5% and a correlation coefficient of 0.744. The evaluation metric of the F1-score shows an average of 0.91 for the SVC models, the 4-fold cross-validation shows an average correlation coefficient of 0.663 for SVR model, which indicates the good performance of the SVC and SVR model. To conclude, this study not only provides an intelligent ML method system for PNGR potential precisely evaluation and prediction with the combination of SVC and SVR which is firstly used by application of ML in petroleum industry field, but is also significant for the application of ML in petroleum and natural gas exploration and exploitation.

Fluid evolution and related fluid–rock interactions of the Oligocene Zhuhai sandstones in the Baiyun Sag, northern margin of the South China Sea

Pore fluids control the diagenetic processes and storage spaces of deep clastic rock reservoirs and have become a major area of interest within the fields of sedimentology and petroleum geology. This paper aims to relate the diagenetic processes of the Oligocene Zhuhai sandstones in the Baiyun Sag to pore fluids varying with burial depth. The types and distribution patterns of authigenic minerals are investigated through analysis of petrographic, mineralogical, and geochemical features to illustrate the origin and flow patterns of pore fluids and their influences on reservoir diagenesis. Strong cementation of eogenetic carbonate cement near the sandstone–mudstone interface was a consequence of material migration from adjacent mudstones on a large scale. The pore fluids were mainly affected by microbial methanogenesis and carbonate mineral dissolution in adjacent mudstones during eogenesis. The pore fluids were diffusively transported in a relatively open geochemical system within a local range. Support for this model is provided by the heavier stable isotopic values present in eogenetic calcite and dolomite. Feldspar dissolution during early mesogenesis was spatially accompanied by the precipitation of authigenic quartz and ferroan carbonate cement. Pore fluids in this period were rich in organic acids and CO2, and their migration mechanism was diffusive transport. The obviously lighter carbon and oxygen isotopic compositions of the ferroan calcite support this inference. During late mesogenesis, the input of deep hydrothermal fluid might have been partly responsible for the precipitation of ankerite, barite and authigenic albite. Oil charging may have inhibited carbonate cementation and compaction, accordingly preserving porosity, and together with authigenic kaolinite, might have promoted the transition of the reservoir from water wet to oil wet to the benefit of oil entrapment. The findings reported here shed new light on the evaluation and prediction of sandstone reservoirs that have experienced multiple periods of fluid flow.

Seismic geomorphology analysis and petroleum geology significance of presalt Jurassic carbonate in the right bank of Amu Darya River

Paleogeomorphological pattern has a great influence on the formation of carbonate reef-shoal complexes and the evolution of carbonate reservoirs. Accurate paleogeomorphology restoration is one of the significant tasks while exploring oil and gas stored in carbonate rocks. However, the previous paleogeomorphology restoration methods mostly rely on high-density drilling data or high-quality seismic data. The applicability of these methods to areas with low-quality seismic data of presalt reservoirs and less drilling control is often low, and they cannot accurately restore paleogeomorphology. This will seriously affect the success rate of oil and gas exploration in presalt reservoirs. Hence, this study aims to address the problem associated with paleogeomorphology restoration under the conditions of highly flexible salt-gypsum rock and low-quality seismic data. By comparing the paleogeomorphology restoration principles of the impression and residual thickness methods and considering multiple factors such as sediment filling and tectonic evolution settings, an innovative model representing the relationship between geomorphology and seismic attributes was established and the paleogeomorphology in the period of deposition of the Middle Jurassic Callovian strata in the eastern part of the right bank of Amu Darya River was restored based on seismic geomorphology, 3D seismic data, drilling data, well log data, core data, and thin-section data. Based on the analysis of the reconstructed paleogeomorphology, it is observed that the high paleogeomorphology shoals in the western part of the study area obstruct the growth of the eastern shoals, affecting the development thickness. However, the quality of thin-layered shoal reservoirs in the eastern part is superior to those in the western part. The distribution of well-developed thick shoals and high-quality reservoirs in this area exhibits obvious spatial differentiation on the plane. Under the unique paleogeomorphology pattern of alternate uplifts and depressions in this area, the quality of reservoirs in the western part is poor, the development quality of reef-shoal reservoirs in the central and eastern region is superior, and the reservoirs in the paleogeomorphologic lowlands are poorly developed.

A Method for the Modified Estimation of Oil Shale Mineable Reserves for Shale Oil Projects: A Case Study

The amount if oil shale resources throughout the world has been roughly estimated in accordance with various resource estimation methods. However, in some instances, detailed and comprehensive supporting methodologies for the estimation of commercial shale oil reserves have not been presented. The goal of this study is to develop a comprehensive method for the modified estimation of oil shale mineable reserves for shale oil projects. The methodology characterises oil shale according to its calorific value, oil content, conditional organic mass, and ash content by utilising a Monte Carlo simulation. Based on the results of the case study, the developed method proposes considering the relationships of the in situ oil shale grade and tonnage material (oil shale + limestone) to the oil retorting feed material grade and tonnage by taking into account the retorting plant oil recovery. For this purpose, a Monte Carlo stochastic modelling algorithm was developed. Based on the data analysis, a modifying factor to convert mineral reserves to petroleum reserves was produced. The results of this study are useful for feasibility studies that estimate oil shale reserves in relation to justifying their utilisation fields. Some oil shale deposits have good potential for development but need to be re-estimated in accordance with the most sophisticated extraction and processing technologies.

Theory, Technology and Practice of Unconventional Petroleum Geology

Theory, Technology and Practice of Unconventional Petroleum Geology

Imbibition Mechanisms of Fracturing Fluid in Shale Oil Formation: A Review from the Multiscale Perspective

Imbibition Mechanisms of Fracturing Fluid in Shale Oil Formation: A Review from the Multiscale Perspective

Experimental study of hydraulic fracturing initiation and propagation from perforated wellbore in oil shale formation

Perforation hydraulic fracturing is essential in developing unconventional oil and gas resources. This study scales the critical parameters to simulate operations at the field scale, using a true triaxial hydraulic fracturing experimental system to mimic actual far-field stress conditions. The research simulates various scenarios of perforation and fracturing fluid parameters, which significantly influence fracture propagation behaviour and fracture network morphology. The results showed that the initiation pressure required for fracturing with perforation is 20.91% lower than that of open-hole fracturing. Multiple fractures, including bedding and branch fractures, exhibit cross-propagation behaviour, forming barrier-type morphology. Induced by perforation, hydraulic fracture initiation and propagation occur along the direction of maximum geo-stress, but unreasonable orientation and reduction in perforation length can also increase initiation pressure. The flow rate and viscosity of fracturing fluid are positively proportional to the initiation pressure. A high flow rate of 100 mL/min facilitates the generation of bedding fractures, enhances the bedding fractures connectivity and increases fracture network complexity. However, the increase in viscosity forces hydraulic fracture to penetrate the bedding plane directly and diminishes the complexity of the fracture network. Compared to the pressure build-up phase, fluctuations in the fracturing curve during the propagation phase are significantly related to the complexity of the fracture network. Small-scale structural surfaces developed within the strata can become part of the hydraulic fractures and increase the fracture network complexity. Additionally, the hydraulic fractures are captured and hindered by large-scale structural surfaces, forming a single fracture morphology. The findings significantly aid in predicting fracture propagation and fracture network morphology in oil shale exploitation.

Origin of gases and waters from a hypersaline, carbonate spring on Anticosti Island, Québec, Canada

Hypersaline spring water (TDS ∼ 85 g/L) and gas are escaping from the top of a calcite travertine mound on Anticosti Island. This mound is located in the Chaloupe River area above the Jupiter Fault which cuts through the Ordovician formations in the subsurface, including the oil and gas-rich Macasty Shale Formation. The Cl content is approximately 3 times that of seawater, but the geochemical profile indicates it to be a Paleozoic basin brine (geogenic He = 2E–7 cc/cc) evaporatively enriched beyond halite saturation (Br:Cl molar ratio = 0.0022 ± 0.00013) that has been diluted by some 73 ± 6% with meteoric waters. Measurable tritium (3.4 TU) indicates this to be a mixture of modern and Holocene recharge. The radioiodine (129I < 10 million atoms/L) is a three-component mixture of geogenic and post-nuclear contributions with low levels in pre-nuclear Holocene recharge. Degassing at the vent (1% to 2% CO2, PCO2 = 0.02 atm, >90% CH4) provokes calcite precipitation and travertine mound formation. Methane comprises a thermo-catalytic component and a biogenic component produced at depth in the organic-rich Macasty Formation by reduction of surface-derived dissolved inorganic carbon (DIC; a14C = 3.5 pMC), producing enriched δ13CDIC values recorded in the travertine. The occurrence of basin-derived brine and gas discharging in association with the surface expression of the Jupiter fault implies that this fault provides a pathway for deep circulation of meteoric waters, likely driven by the relief on the island.