Basin Rocks Research Articles

Revisiting Controls on Shale Oil Accumulation in Saline Lacustrine Basins: The Permian Lucaogou Formation Mixed Rocks, Junggar Basin

Fine-grained mixed rocks in saline lacustrine basins are important targets for shale oil exploration. However, the controls on shale oil accumulation are complex due to the multi-source mixed deposition. This is a challenging issue in the study of shale oil. Here, we present a case study in the Middle Permian Lucaogou Formation in the Jimusar Sag, Junggar Basin, northwestern China. Results show that the Lucaogou Formation consists mainly of carbonate rocks, dolomitic or calcareous mudstones, tuffaceous or silty mudstones, and siltstones. The dolomitic/calcareous mudstones (TOCaverage=6.44 wt.%) and tuffaceous/silty mudstones (TOCaverage=4.83 wt.%) have the best hydrocarbon generation potential and contain type I–II1 kerogens that are in the peak oil generation stage. However, the shale oil potential is highest for the carbonate rocks and siltstones with average oil saturation index (OSI) values of 315.03 mg HC/g TOC and 343.27 mg HC/g TOC, respectively. This indicates that hydrocarbon generation potential is not the main factor controlling shale oil potential. Micro-nanoscale pores are the main control. Abundant dissolution pores provide excellent reservoir space for near-source migration and accumulation of shale oil. Different mixing processes between lithofacies control the accumulation of shale oil, and shale oil productivity is the best when multi-facies deposition in transitional zones formed the mixed rocks (facies mixing). In addition, local accumulations of calcareous organisms and adjacent carbonate components on terrigenous sediments (in situ mixing) are also conducive to shale oil enrichment. This is an unusual and special feature of saline lacustrine shale oils, which is different from freshwater lacustrine and marine shale oils. Comprehensive assessment of source rock and reservoir is needed to robustly establish a widely applicable method to determine the shale oil potential in such basins.

Distribution and fractionation of rare earth elements in suspended particulate matter in a coastal river, Southeast China.

BackgroundIn the river system, the geochemistry of rare earth elements (REEs, a series of elements from La to Lu) in suspended particulate matter (SPM) is generally controlled by rock weathering processes and hydrochemical characteristics, as well as being affected by anthropogenic activities. However, the variations of geochemical characteristics and behaviors of REEs in SPM with a salinity gradient from the inland river to the estuary have been short of a systematic understanding.MethodsThe REE concentrations, Post Archean Australia Shale (PAAS)-normalized REE, La/Yb, La/Sm, and Sm/Yb ratios of SPM were investigated in the Jiulongjiang River, which is a coastal river mainly flowing through granite rocks in Southeast China. The correlation relationships between physicochemical parameters (including water pH, total dissolved solids (TDS), HCO3– concentrations, and the concentrations of major elements of SPM) and PAAS-normalized REE ratios of SPM were analyzed to determine the factors that affect the REE concentration and fractionation of SPM in the different regions of Jiulongjiang River, including the main stream and tributary of Beixi River, Xixi River, Nanxi River, and estuary. Additionally, the Ce, Eu, and Gd anomalies of SPM were estimated.ResultsThe average ∑REE concentration of SPM (352 mg/kg) in the granite rock basin was twice higher than the mean value (175 mg/kg) of the world’s rivers. The PAAS-normalized REE ratios of SPM in the main rivers including Beixi River (main stream), Xixi River, and Nanxi River were near due to the same lithologic distribution. In the tributary of Beixi River, the input of low-weathered carbonate minerals which contain very few REE caused the lower REE concentrations of SPM. The PAAS-normalized REE ratios of SPM in the estuary were significantly lower than those in the main rivers, which was mainly attributed to the significant REE removal with the increment of salinity. The enrichment of LREE relative to HREE in SPM increased with decreasing water pH in the main rivers. In the estuary, the preferential removal of dissolved LREE occurred compared to HREE with the increment of salinity. The negative Ce and Eu anomalies of SPM occurred in both the main rivers and estuary region and rare Gd pollution was present in the basin. Additionally, human activities caused the increment of REE concentrations and more negative Ce anomaly at some specific sites, such as dam effect and agricultural pollution.ConclusionsThe REE concentrations and fractionations of SPM in river water mainly depend on lithologic distribution and riverine pH, while they are affected by salinity in the estuary.

SOURCE ROCK EVALUATION AND BASIN MODELLING IN THE GORGAN PLAIN, SE SOUTH CASPIAN BASIN, NORTHERN IRAN

Hydrocarbon exploration in the Gorgan Plain to the SE of the South Caspian Basin (northern Iran) has taken place since the 1960s but no economic resources of petroleum have yet been discovered in this area and few studies of potential source rocks have been carried out. In this study, the generation potential and thermal maturity of potential Cenozoic source rocks are investigated on the basis of Rock‐Eval analyses of core and cuttings samples and organic petrographic observations. Hydrocarbon generation, migration and entrapment are evaluated from 2D basin modelling along two seismically‐derived profiles, oriented east‐west and north‐south across the Gorgan Plain area. The models used input data from ten wells.Rock‐Eval analysis of 65 samples from well C in the Gorgan Plain show that organic‐rich intervals with source rock potential are present in the Paleocene‐Eocene section (1.1% TOC) and in the Pliocene Cheleken Formation (1.5% TOC). These intervals in general contain organic matter of terrigenous origin (kerogen Type III) but have poor hydrocarbon generation potential (i.e. Rock‐Eval S1+S2). There is no evidence for an organic‐rich interval in the Oligocene – Miocene succession equivalent to the Maikop Group – Diatom Formation which is a major source rock in eastern Azerbaijan and the adjacent offshore.Results of 2D basin modelling indicate that potential source rocks in the Paleocene – Eocene and Pliocene (Cheleken Formation) intervals are thermally immature throughout most of the study area, but that their maturity increases westwards towards the centre of the South Caspian Basin due to the increasing thickness of the overburden. The source rocks may be sufficiently mature in kitchen areas (at depths of more than 4000 m) to have generated hydrocarbons which may have migrated laterally updip to the basin margins.

Using Clumped Isotopes to Reconstruct the Maximum Burial Temperature: A Case Study in the Sichuan Basin

For strata that have experienced continual burial in the early stage and uplift in the late stage, the present-day temperature is lower than the maximum burial temperature (MBT), which is a key parameter for studying the hydrocarbon generation history of source rocks in petroliferous basins. In this paper, a new method for reconstructing the MBT is proposed based on the solid-state reordering model of carbonate clumped isotopes (Δ47). The MBT reconstructed using the Δ47 was compared with the MBT constrained using the traditional Easy%Ro model. The clumped isotope temperature (TΔ47) of the Permian micritic limestone from the Xibeixiang outcrop (about 62°C) is much higher than its initial formation temperature (20–25°C), suggesting that the limestone experienced partial solid-state reordering during the late burial process. The MBT of the calcite obtained from the solid-state reordering model is 139–147°C, which is quite similar to the MBT determined using the Easy%Ro model (139.5–147.5°C). TΔ47 of the Permian and Triassic limestone and calcite cements in the Puguang gas field are 150–180°C, while TΔ47 of the micritic dolostone is about 70°C, suggesting that the Δ47 of the limestone and calcite cements experienced complete solid-state reordering and the dolostone only experienced partial solid-state reordering. The MBT of the dolomite determined using the solid-state reordering model is 200–220°C, which is also similar to the MBT determined using the Easy%Ro model (202–227°C). Therefore, the case studies from the Sichuan Basin suggest that Δ47 can be used to reconstruct the MBT of ancient carbonate strata lacking vitrinite and detrital zircon data. However, different types of carbonate samples should be used to reconstruct the MBT for strata that have experienced different temperature histories. Micritic limestone and very finely crystallized dolostone can be used to reconstruct the MBT of strata that have experienced MBTs of <150–200°C and >200–250°C, respectively.

Cases of generalized low-frequency shadows of tight gas reservoirs

The phenomenon that frequency decreases and amplitude increases near the bottom of a gas layer on a seismic profile is called a low-frequency shadow, but this phenomenon may not occur in all gas reservoirs. When the tight gas reservoir is thick enough, spectral decomposition data after Fourier transformation will indicate characteristics similar to those of low-frequency shadows, which we call generalized low-frequency shadows. Compared to the dominant frequency of the nongas-bearing zone spectral, the dominant frequency of a gas zone moves toward the low end of the frequency range and the low-frequency amplitude increases accordingly. By analyzing known gas reservoirs such as the Sulige and Yanchang tight sandstones in the Ordos Basin and tight carbonate rocks in the Tarim Basin, we can see that, with the visual dominant seismic frequency close to 30 Hz, the peak frequency of the gas-bearing tight sandstones and tight dolomite reservoirs will move from approximately 30 to 10–15 Hz. There is a certain correlation among the drop of the dominant frequency of a tight gas reservoir, the attenuation energy difference, and the thickness and productivity of the gas layer. Several cases indicate that nearly all tight gas layers thicker than 15 m exhibit attenuation characteristics of generalized low-frequency shadows.

Storage space, pore–throat structure of igneous rocks and the significance to petroleum accumulation: An example from Junggar Basin, western China

Igneous rocks in deep basins are important unconventional petroleum reservoirs. Storage space and pore–throat structure of igneous rocks are crucial to be considered as effective reservoirs. There developed large-scale petroleum reservoirs in the Carboniferous igneous rocks of Hongshan-Zhongguai Bulge in the Junggar Basin, western China. The storage space and pore–throat structures of various types of igneous rocks and their significance to petroleum accumulation were studied based on the analysis of core samples. The methods include macroscopic core observation, microscopic observation under microscopes, scanning electron microscopy, micro-resistivity imaging logging and mercury injection experiments. Results show that the storage space is made up of primary gas pores, secondary dissolution pores and various types of fractures. The fillings of fractures are mainly calcite, followed by asphalt, chlorite and gypsum. The igneous rocks have different pore-throat structures, which govern the reservoir properties. Four types of igneous rock reservoirs were recognized, and the most favorable type is volcanic breccia and part of andesite. Dissolution plays an important role in remodeling the pore-throat structure and storage space. Tuff is the most susceptible to dissolution and present greatest alteration in storage space among the studied igneous rocks. An igneous rock weathering crust with high porosity formed near the unconformity capping the Carboniferous rocks, and oil is most abundant within 150 m across the unconformity surface. Faults and the weathering crust jointly control the formation of igneous rock reservoirs. The fault-controlled reservoirs commonly form in structural high position, and stratigraphic reservoirs generally developed in slope area.

3D hybrid imaging based on gravity migration and regularized focusing inversion to predict the Poyang Basin interface

Describing and understanding the basement relief of sedimentary basins is vital for oil and gas exploration. The traditional method to map an interface in each spatial direction is based on 3D modeling of gravity Bouguer anomalies with variable lateral and vertical density contrasts using a priori information derived from other types of geoscience data sets as constraints (e.g., well and/or seismic data). However, in the preexploration stage, vertical gravity [Formula: see text], which is sometimes the only available geophysical data, is typically used to recover smooth density contrast distributions under a generic set of constraints. Apparently, the use of the [Formula: see text] component is not sufficient to produce geologically reasonable interpretations with high resolution. To address this, we have developed a novel process of hybrid inversion, combining gravity migration and inversion using the same [Formula: see text] data set, to distinguish the complicated interface between basement and sedimentary basin rocks from a full-space inverted density distribution volume. First, a 3D-migrated model delineating the basic sedimentary basin structure is derived using a focusing gravity iterative migration method, where a priori information is not necessary. Subsequently, under the framework of the regularized focusing conjugate inversion algorithm, a high-resolution density contrast model is inverted for delineation of the basement boundary by integrating the 3D-migrated density model as a priori information. We examine the method using one synthetic example and a field data case, of which a transformed resolution density matrix is developed from logarithmic space to qualitatively evaluate the practical resolutions. The high resolution of the density distribution of the Cretaceous basement with a clear interface is achieved and verified by limited seismic data and strata markers in limited wells.

Identifikasi Batuan Granit Daerah Prospek Panas Bumi Nyelanding menggunakan Metode Magnetik

This study aimed to identify granite rocks around the Nyelanding geothermal area, especially in the geothermal manifestations. This research used the magnetic method to analyze the subsurface structure of the geothermal area. Correction of magnetic data was performed in Microsoft excel 2010 software and two-dimensional modeling was performed using Oasis Montaj 8.4. The results showed that there are three layers of rock under Nyelanding hot springs, namely granite with a susceptibility of 0.009 - 0.05 SI to a depth of 500 meters and a layer of sandstone - clay, as well as layers of clay, gravel and silt with a susceptibility of 0.00001 - 0, 00005 SI. In conclusion, the local geology of the Nyelanding hot spring area is dominated by the presence of granite to a depth of 500 meters. The results of forward modeling on layers A-A' and C-C' show the subsurface structure of Nyelanding hot springs in the form of a granite rock basin which is estimated to be able to accumulate geothermal energy.
 Key words: Nonvolcanic Geothermal, Magnetic Method, Granite Susceptibility, Forward Modeling

Enrichment of tight oil and its controlling factors in central and western China

Taking the tight oil of the Zhongnan sag in the Ordos Basin, Jimusar sag in the Junggar Basin and Qingxi sag in the Jiuquan Basin as study objects, based on field survey, dissection of tight oil reservoirs, sample test, modeling experiment and comprehensive analysis, this study reveals that the tight oil accumulates at start-up pressure, advances under differential pressure, diffuses at alternating fast and low speeds, charges in stepped large area and migrates rapidly through fractures, and enriches in dominant fractures and pores. The root cause of ladder-like charge is the multiple scales of pores. The widespread source rock with high hydrocarbon generation intensity is the material basis for tight oil enrichment; the dominant source reservoir assemblage is the basic unit for tight oil enrichment; fractures and beddings are conducive to local rapid migration of tight oil; fractures and pores work together to control the enrichment of tight oil. Two typical accumulation models of tight oil are established, namely “source reservoir in coexistence, four optimal factors controlling enrichment around central area, and large-scale continuous distribution” for a large freshwater lake clastic rock basin and “source reservoir integration, four optimal factors controlling enrichment, central area distribution, small in size but high in enrichment degree “ for a small saline lake diamictite depression.

Source rocks in foreland basins: A preferential context for the development of natural hydraulic fractures

Bedding-parallel veins of fibrous calcite (also called “beef”) occur in many sedimentary basins, especially those containing low-permeability strata with organic source material for petroleum. The formation of such veins is commonly linked with fluid overpressure in these source rocks. In this review, we demonstrate that beef veins are most commonly present in foreland basins worldwide or in basins that recorded a compressive tectonic period. The formation of beef veins is related to two main phases: (1) the initiation of bedding-parallel fracture and (2) the infilling of the fracture. Previous structural studies have shown that formation of beef veins occurred during a period of compressive stress activity. This is especially the case for the Wessex Basin (United Kingdom) and the Neuquen Basin (Argentina). In this paper, we provide more observations for other basins: the Cordillera Oriental (Colombia), the Paris Basin (France), the northern Pyrenees (France), the Uinta Basin (United States), the Tian Shan Mountains (central Asia), and the Appalachian Mountains (United States). In the Paris Basin, beef vein formation is dated at 155 Ma (U/Pb calcite method) and is coeval with the compressional deformation in the eastern part of the basin. Because of the timing of generation for such veins and even if the theory and the experiments of fracturing demonstrate that bedding-parallel fractures can be generated only with a distributed fluid overpressure, the formation of beef veins seems to be a consequence of both fluid overpressures and a compressional tectonic stress.

Identifying oil sources in the wen'an slope of the baxian depression, the bohai bay basin, north China

With acquisition of geochemical data of oils and source rocks in mature basins, oil source re-identification is important for petroleum system analysis and subsequent exploration. In the Baxian Depression of the Bohai Bay Basin, the main source rocks are in the Sha-3 (Es3) and Sha-1 (Es1) Members of the Paleogene Shahejie Formation. These cannot be differentiated using the standard mass chromatograms and bivariate cross-plots of biomarker parameters obtained from the representative samples of the source rocks. In this paper, discriminant analysis (DA) was employed to highlight the difference between these two sets of the source rocks samples and to identify the sources of the oils in the multivariate space. Based on a comprehensive literature review, we selected twenty three candidate parameters that may reflect the oil sources, and excluded ones which are affected by the thermal maturity and biodegradation in the study area. Eight informative parameters were chosen with stepwise DA from these candidate parameters to establish a discriminant model for the oil-source correlation. The model achieved a high correct discrimination rate using leave-one-out cross-validation (90.7%) and original validation (94.4%). We found that these 8 parameters can describe the characteristics of the main sources and can effectively differentiate these sources. The high posterior probabilities in the oil-source correlation results indicate that the oils in the Wen'an Slope were mainly sourced from the source rock in Es3. These results, together with geological mapping of reservoir sand-bodies, suggest that more oil derived from the Es3 source rocks may exist below the thick shale and/or mudstone sequence in the Es1 than previously thought.

Identification of effective source rocks in different sedimentary environments and evaluation of hydrocarbon resources potential: A case study of paleogene source rocks in the Dongpu Depression, Bohai Bay Basin

Source rocks in lacustrine rifting basins have great heterogeneity, which leads to imprecise assessments of hydrocarbon resources. Previous studies evaluated the source rocks of different sedimentary environments in lacustrine basins or depressions using the same lower limit of effective source rocks (i.e., the minimum total organic carbon (TOC) at which the source rocks are capable of expelling hydrocarbons). In this study, the source rock samples were selected from five formations in the Dongpu Depression for organic geochemical experiments and quantitative simulations of hydrocarbon expulsion. According to salinity differences, every formation was divided into a saline area, transition area and freshwater area. The results show that the maximum thickness of source rocks developed in the saline and transition areas is 700 m. Additionally, source rocks with a higher TOC and oil-prone organic matter types (II1 and II2) also develop in the saline and transition areas, and most have entered the mature stage. The TOC values corresponding to the lower limit of effective source rocks in the saline, transition, and freshwater areas are 0.3%, 0.4% and 0.5%, respectively. Furthermore, the hydrocarbon expulsion ratio (amount of hydrocarbon discharged per unit of TOC from the source rocks) for the freshwater area is 253.1 mg/g, while the ratios in the saline and transition areas are relatively higher at 439.4 mg/g and 369.3 mg/g, respectively. The hydrocarbon expulsion rate (change in the expulsion ratio per unit thermal evolution degree) and hydrocarbon expulsion efficiency (ratio of cumulative hydrocarbon expulsion amount to generation amount) in the saline, transition and freshwater areas present maxima when the Ro (vitrinite reflectance) values are 0.95%, 0.85% and 0.82%, respectively. The hydrocarbon expulsion quantities in the saline, transition and freshwater areas account for 24%, 49% and 27% of the total, respectively. Therefore, the main hydrocarbon expulsion area is the transition area of the Dongpu Depression associated with the thickest source rocks. Es3M and Es3L source rocks in the transition area with high organic matter abundant and type II kerogen are more promising than the other formations. This study is the first to report on effective source rocks in different sedimentary environments in lacustrine basins and can provide guidance for future exploration in the Dongpu Depression and a reference for future research on source rocks in other lacustrine basins.

The Development Characteristics and Distribution Predictions of the Paleogene Coal‐measure Source Rock in the Qiongdongnan Basin, Northern South China Sea

AbstractThere are known to be enormous Cenozoic coal‐type oil and gas resources located in the basins of the South China Sea, among which the Paleogene coal‐measure source rock are one of the main source rock. In order to more effectively analyze the distribution laws of coal‐measure source rock in marginal sea basins and guide coal‐type oil and gas explorations, the Oligocene coal‐measure source rock in the Qiongdongnan Basin were selected as examples in order to systematically analyze the types, development characteristics, control factors, and distribution prediction methods of coal‐measure source rock in marginal sea basins. The Qiongdongnan Basin is located in the northern region of the South China Sea. Previous explorations of the area have determined that the Oligocene coal‐measure source rock in the Qiongdongnan Basin have typical “binary structures”, which include coal seams and terrigenous marine mudstone. Among those, the terrigenous marine mudstone has been found to greatly expand the scope of the coal‐measure source rock. In addition, the coal seams which have been exposed by drilling have been observed to have the characteristics of thin single layer thickness, many layers, and poor stability. Meanwhile, the terrigenous marine mudstone has the characteristics of large thickness and wide distribution. The development of coal‐measure source rock is known to be controlled by many factors, such as paleoclimate and paleobotany condition, paleo‐structure and topography, paleo‐geography, rise and fall of base level, and so on. In accordance with the comprehensive analyses of various control factors of coal‐measure source rock, and the changes in water body energy in sedimentary environments, a genetic model of the “energy belt” for the development and distribution of coal‐measure source rock was proposed. Also, the development and distribution characteristics of coal‐measure source rock in different types of energy belts were clarified. Then, based on the development and distribution characteristics of coal‐measure source rock and their controlling factors, prediction methods of the distribution ranges of coal‐measure source rock were proposed from both qualitative and (semi‐) quantitative aspects. That is to say, a method for (semi‐) quantitative predictions of the distribution ranges of coal‐bearing intervals based on model wave impedance inversion and neural network wave impedance inversion, along with a method for (semi‐) quantitative predictions of the distribution ranges of terrigenous marine mudstone based on topographical slopes, were introduced in this study.

Genesis and Characteristics of Miocene Deep‐water Clastic Rocks in Yinggehai and Qiongdongnan Basins, Northern South China Sea

AbstractVarious deep‐water deposits developed in the Yinggehai Basin and Qiongdongnan Basin (Ying‐Qiong Basin) in the northern South China Sea, making the two basins significantly hydrocarbon‐producing areas and ideal for studying the genetic mechanism and sedimentary characteristics of deep‐water clastic rocks. Using cores, image well logging, heavy mineral assemblages, and seismic data, we thoroughly studied the geometry, tectonic background, driving mechanism, and source‐to‐sink process of deep‐water deposits in the study area. The results showed that: (1) there were five genetic mechanisms of deep‐water clastic rock, i.e., slides, slumps, debris flows, turbidity currents, and bottom currents. (2) The sliding deposits were distributed from the delta front to the continental slope toe. The slumping deposits were mainly distributed at the continental slope toe or the basin's central area, far from the delta front. The turbidity deposits were widely developed in the deep‐water area, but with huge differences in thickness. The bottom currents mainly reworked previous deposits far from the slope. (3) Slip and extension along the preexisting fault zone were the main structural factors that drive the axial channel formation at the slope foot. (4) The sand‐rich gravity sediment flows in the Ying‐Qiong basin were primarily caused by the direct supply of terrigenous debris into the marine environment over the slope break.

New equation to decipher the relationship between carbon isotopic composition of methane and maturity of gas source rocks

The identification of the origin and source of natural gas is always a difficult and hot issue. Hereinto, the maturity identification is one of the most important scientific problems. Many empirical equations have been established to decipher the relationship between the maturity of gas source rocks and the carbon isotopic composition of natural gas. However, these equations proposed often fail to identify the maturity of the source rocks correctly, which in turn prevents the identification of genetic types and source rocks of the natural gas because the petroliferous sedimentary basins in China are complex and diverse, with multiple sets of source rocks and different thermal history. In this paper, the oil-associated gas from the Permian lacustrine source rocks and the coal-derived gas from the Jurassic source rocks in Junggar and Turpan-Hami basins have been investigated to decipher the relationship between the maturity (vitrinite reflectance) of gas source rocks and the carbon isotopic composition of methane. The equations established are δ13C1=25lgRo−42.5 for oil-associated gas, and δ13C1=25lgRo−37.5 for coal-derived gas. These new equations are suitable for the maturity identification of source rocks in most petroliferous basins, and favorable for the identification of the genetic type and source of natural gas, which is very important to improve the geological theory of natural gas.

Delineation of coaly source rock distribution and prediction of organic richness from integrated analysis of seismic and well data

Coaly facies (coals, shaly coals and coaly mudstones) are the primary source rock in several important petroleum basins in SE Asia and Australasia. Delineating these facies and quantifying their organic richness within kitchen areas are some of the key risks for petroleum exploration. To improve their delineation and characterisation using seismic data, a case study was undertaken of the coal-bearing Paleocene and Eocene intervals within the Maari 3D seismic volume area, offshore southern Taranaki Basin, New Zealand. Supporting data were acquired from well logs (including borehole image logs), existing geochemical analyses of well cuttings, and new laboratory measurements of in-situ geophysical and geochemical properties of coal samples from onshore coal mines and other outcrops. In the Paleocene–Eocene interval in the Maari 3D, coaly facies display characteristic low density (<2.5 g/cc) and velocity (<4000 m/s) and appear as bright, resistive layers in image logs. To delineate these facies in the Maari 3D volume, a post-stack seismic inversion was carried out and a P-impedance (product of density and P-wave velocity) model was prepared. Coaly facies exhibit moderate–high amplitude and moderately continuous (up to ~5 km) seismic reflectors, with low P-impedance (<9000 m/s × g/cc) character. Interval P-impedance and amplitude maps reveal temporal variation in the distribution and abundance of coaly facies within the Paleocene–Eocene coastal plain depositional environment. A logarithmic relationship between P-impedance and TOC was used to convert average P-impedance maps to proxy TOC maps for five Paleocene–Eocene time intervals. Coaly facies are most abundant in the low P-impedance areas in the southwestern and central parts of the study area where average TOC is estimated up to 30 wt.%. P-impedance-derived estimates of TOC may be less reliable in structurally high areas hosting hydrocarbon-bearing sandstones and siltstones as some of these facies show similar P-impedance character to coaly facies.

Geomechanical evaluation of a middle Cambrian unconventional oil and gas play in the southern Georgina Basin, northern Australia

Middle Cambrian sediments in the southern Georgina Basin contain multiple organic-rich source rocks and have been suggested to be prospective for both conventional and unconventional hydrocarbons. We present new geomechanical data collected from the middle Cambrian Arthur Creek Formation and Thorntonia Limestone in four wells (Baldwin 1, MacIntyre 1, Owen 2, Todd 1) in the southern Georgia Basin, and compare the data to mineralogical and geochemical datasets. Geomechanical test intervals were selected to allow geomechanical test results to be directly compared with the mineralogical and geochemical datasets (X-Ray Diffraction, HyLogger and organic geochemistry). Approximately 25 m of core was tested for unconfined compressive strength (UCS) using the scratch-testing technique, and results indicate values in the range of 60–150 MPa. Triaxial testing was also conducted to measure the poroelastic properties of core, and results indicated that Young’s modulus is generally in the range of 45–67 GPa. UCS and Young’s modulus are positively correlated and increase with depth through the prospective Arthur Creek Formation. The mechanical properties of the tested core are relatively indurated and stiff compared with young sedimentary rocks and broadly similar to proven shale gas plays in Australia and internationally. Mineralogically, the Georgina Basin rocks tested have lower clay contents than rocks from other Australian and international basins but no clear correlation was observed between geomechanical properties and mineralogy, suggesting that multiple factors contribute to the poroelastic and strength parameters. For example, parameters such as sonic velocity and porosity are weakly correlated to rock strength. Geomechanical data can be used alongside other datasets (e.g. sedimentological, geophysical and structural data) to better inform predictions of hydrocarbon prospectivity. KEY POINTS Middle Cambrian rocks from the Georgina Basin, Australia are prospective for conventional and unconventional hydrocarbons. Rock mechanical tests are conducted to determine how the organic-rich sediments might respond to stimulation. Mechanical analyses are evaluated alongside mineralogical, geochemical and well-log data to assess controls on rock strength properties. Geomechanical behaviour is complex and appears to be driven by multiple factors.

Using characteristics of pressure-temperature induced permeability variation of typical carbonate rock to determine its performance as reservoir or cap rock

The current research on carbonate rock often focuses on the storage space for oil and gas, and exploration of carbonate rock in petroliferous basins also mainly searches for high-quality reservoir rock for hydrocarbons. However, the importance of effective carbonate reservoir-cap rock configuration is increasingly highlighted, as hydrocarbon exploration advances towards deeper and older strata. Exploration practice shows that the favorable facies belt of carbonate rock, though deeply buried, still develops highly desirable reservoir rock with high porosity and permeability. Therefore, the presence of an effective carbonate cap rock collaborating with this reservoir rock becomes key to hydrocarbon exploration in deep carbonate rock. This research, for the first time, systematically and thoroughly carries out permeability measurement through the whole triaxial compression process of typical carbonate rock at varied temperatures, and captures the permeability evolution during deformation and failure, affected by temperatures and confining pressures. Test results show that typical dolomite and limestone present varied permeability variation characteristics in a triaxial loading state. Dolomite appears to be more of reservoir rock. It presents higher critical confining pressure for brittle–ductile transition, and is more prone to fracturing. Its permeability grows with temperature elevation. As for limestone, it has better performance as cap rock, which is embodied as the lower critical confining pressure for brittle–ductile transition, high sealing capacity, and permeability reduction with elevated temperatures. To sum up, vertical stacking of dolomite and limestone can form an effective reservoir-cap rock assemblage for hydrocarbon accumulation.

Glacial erosion by the Trift glacier (Switzerland): Deciphering the development of riegels, rock basins and gorges

A long-lasting question in glacial geology is how and how fast glaciers were able to shape the distinctive landscapes of the Alps. This study contributes to the understanding on the formation of overdeepened basins, especially the processes and the amount of time involved. We examine the remarkably high (150 m) cross-valley bedrock riegel and the associated overdeepening located in front of the Trift glacier in the central Swiss Alps. A combined approach of field survey with measurements of two cosmogenic nuclides, 10Be and in-situ 14C, and a numerical model was used to determine the spatial glacial erosion patterns on the bedrock riegel. Ten samples were taken along two transects; one perpendicular to the glacier flow direction, from outside of the Little Ice Age (LIA) extent down to the centre of the riegel, and the other following the former ice-flow direction across the riegel. Analysis of measured nuclide concentrations shows that the sample outside of the LIA was constantly exposed since the retreat of the Egesen stadial Trift glacier (~11.5 ka). The samples inside the LIA extent indicate a distinct trend of increasing glacial erosion rates from 0 mm/a near the LIA ice margin to high erosion all across the top of the riegel. The resulting minimum glacial erosion rates from samples on the riegel are 0.5–1.1 mm/a (10Be) and 0.6–>1.8 mm/a (in-situ 14C) which correspond to minimum erosion depths of 1.6–>3 m (10Be) and 1–>5 m (14C). The extremely low nuclide concentrations measured at the riegel highlight the substantial erosion (predominantly abrasion) of the bedrock surface during late Holocene glacier coverage. Field observations suggest that the formation of the overdeepening and, as a consequence, the riegel is due to a combination of valley shape, bedrock structures, glacier confluence and hydrology. We further hypothesise that the gorge is a key factor responsible for this impressive overdeepening, by lowering the threshold for the subglacial meltwater, effectively decoupling the height of the riegel from the depth of the overdeepening.

Hydrochemistry Differences and Causes of Tectonic Lakes and Glacial Lakes in Tibetan Plateau

The Tibetan Plateau has the largest lake cluster in China and in the world. In order to clarify the differences of lake hydrochemistry of Tibetan Plateau, water samples were collected from 32 lakes, including 22 tectonic lakes and 11 glacial lakes, along the Tibetan Plateau road, from September to October 2016. We detected and analyzed the major ion concentrations and characteristics of samples, and discuss the hydrochemistry type, controlling factors, and major ion sources of lake water. The results showed that, firstly, tectonic lake samples on the Tibetan Plateau have much higher physicochemical parameters and ion contents than glacial lakes, and Total Dissolved Solids (TDS) contents fluctuate from high to low latitudes. The variations of ion concentrations in the northern part of the Qiagui Co were more fluctuating and have two obvious peaks, while the variations in the southern part were moderate. The TDS of glacial lakes were low and leveling off in the upper and middle reaches of the basin, while higher and more variable in the lower reaches. Secondly, the tectonic lakes were mainly chloride saline lakes, with Na+ as the major cation, and SO42−, Cl− as the major anions. Glacial lakes were mainly carbonate and sulfate type lakes, Ca2+ and Mg2+ were the major cations, HCO3− was the major anion, and SO42− was the second. Thirdly, the hydrochemistry processes of the tectonic lakes were mainly controlled by evaporation-crystallization, and the ions mainly came from the evaporites of basin. Glacial lake water samples were mainly influenced by the weathering of basin rocks, with ion sources strongly influenced by the weathering of basin carbonates than evaporites, with calcite and dolomite being important sources of Ca2+, Mg2+, and HCO3−.