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Quartz cementation is a critical factor in the reservoir quality of ultra-deeply buried sandstones because of the high temperature and high-pressure at great depths. Therefore, determining the main influences retarding the growth of the quartz overgrowths is important for predicting the sweet spots of tight gas sandstones. The vast Keshen-2 gas field in Kuqa Depression is typical of such ultra-deep gas fields, despite the porosity and permeability of the target sandstones in the Lower Cretaceous Bashijiqike Formation being less than 10% and 0.5 md, respectively. The main gas reservoirs had been buried previously to a depth of 7000 m, with the maximum fluid temperature approaching 160 °C, in which authigenic quartz cements are extremely common. The heterogeneity of the physical properties and quartz cementation was investigated using core analysis, log interpretation, thin sections and scanning electron microscopy (SEM). The findings indicated that the Bashijiqike Formation could be stratified into upper porous and lower tight zones. The porosity of the sandstones in the upper zone is generally higher than 5% and abundant polycrystalline quartz grains are present. However, the reservoirs in the lower zone with low overall porosity values below 5%, contain high contents of monocrystalline quartz grains. The polycrystalline quartz grains show brown cathodoluminescence that indicates mainly a metamorphic source from the southern Tianshan provenance which is located to the north of Keshen-2. The monocrystalline quartz grains display primarily blue to violet luminescence colours, suggesting an origin from volcanic or plutonic mother rocks of the Wensu and Kuluketage provenance areas, situated to the southwest and southeast, respectively. The monocrystalline quartz grains are surrounded commonly by quartz overgrowths, whereas the polycrystalline quartz grains are cemented slightly. The presence of polycrystalline quartz grains hampers potential quartz overgrowths—the critical reason preserving the intergranular pores in the ultra-deeply buried sandstones of this gas field. Accordingly, we propose that the metamorphic quartz grain content is the main factor inhibiting quartz cementation, which preserves reservoir quality. This knowledge is conducive to determining the growing mechanism of high-quality reservoirs and predicting the sweet spots of gas production in the ultra-deeply buried sandstones.

Abundant oil resources associated with overpressure have been confirmed to be present in the Paleogene Shahejie Formation in the Chezhen Depression. Pore pressure strongly influences the migration and trapping of hydrocarbons and impacts the safety of drilling operations. The origin of the overpressure and the relationship between overpressure and hydrocarbon migration are not clearly understood in the Chezhen Depression, which has brought difficulties in prospect evaluation and during drilling. According to the measured pressures, mud weights, logging responses, and basin modeling results, the possible overpressure mechanisms in the Shahejie Formation in the Chezhen Depression are revealed, and the distribution of overpressure and its implications for oil migration dynamics are discussed. The overpressure in the Shahejie Formation is mainly concentrated in Es3 and Es4, and the distribution of overpressure in reservoirs is complex. The disequilibrium compaction of rapidly buried Paleocene mudstones is a common overpressure mechanism in the Chezhen Depression, and the overpressure points in acoustic transit time-vertical effective stress, density-vertical effective stress and acoustic transit time-density cross plots follow the loading curves. Hydrocarbon generation has played an important role in overpressure generation at depth in the center of the Chezhen Depression. The acoustic transit time of high-overpressured intervals shows more anomalies than the density measurements, and the overpressure points fall on the unloading curves in rock property-vertical effective stress cross plots. However, overpressure due to hydrocarbon generation rarely occurs in isolation and always appears simultaneously with disequilibrium compaction. The transfer of overpressure often complicates the pressure distribution in sandstones, leading overpressure and normal pressure to occur at similar depths. The overpressure in the Chezhen Depression promoted oil migration and improved the efficiency of oil accumulation. In particular, overpressure was the main force driving the migration of the oil generated in the Es3u downward to the Es4 reservoirs. Knowledge of the mechanisms and distributions of overpressure has great significance for further exploration in the Chezhen Depression and other extensional basins.

The grain packing texture of underground sandstone tends to be a major controlling factor in porosity loss during compaction when the effective stress and buried depth increase. However, existing models used to predict porosity loss during sandstone compaction mostly disregard the grain packing texture of sandstone. Based on the micromechanical parameters of discrete element method (DEM) numerical simulation reported in literature, we designed one-component, binary, and ternary packing textures with different grain size distributions and subsequently performed compaction under triaxial servo simulation. We monitored the porosity loss, grain displacement, and force acting on the grain contact point during compaction. Based on the packing texture in sandstone, we propose a new method that considers varying grain sizes, grain size contents, and packing texture types to determine porosity loss during compaction without grain crushing and plastic deformation. The applicability of the method under theoretical conditions was evaluated with 5, 31, and 53 types of one-component, binary, and ternary packing textures. The correlation coefficient between the predicted and simulated values of the void ratio change (△e) was 0.999 and 0.985 for the binary and ternary packing textures, respectively. The reliability of the proposed method was verified using nine groups of physical experimental data derived from literature. The results showed a correlation coefficient of 0.88 between the measured and predicted values of △e and porosity loss (△ϕ). Errors in physical experimental data were derived mainly from grain shape and the crushing of coarse grains. Although the predicted physical experimental data △e and △ϕ were inferior to DEM simulation data, our model was deemed reliable since it showed high correlation between predicted and measured values of △e and △ϕ. Furthermore, the proposed method characterized the influence of the micromechanical process of grain rotation and grain packing texture on reservoir quality during compaction, thereby establishing its importance in predicting reservoir quality of underground sandstone.

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.

International audience; In the NW Songliao Basin, NE China, petroleum is produced from fluvio-deltaic sandstones in the Upper Cretaceous Yaojia Formation. Source rocks are dark-colored lacustrine shales of the Qinshankou Formation. In this paper, two models were developed to characterize the petroleum migration pathways in the lower member (Member 1) of the Yaojia Formation. In the first model, which applies to the northern region of the study area, petroleum migrates only in the lowermost carrier bed in Member 1 immediately above the area of the source kitchen, and later in multiple carrier beds outside this area. In the second model, which represents migration patterns in the central and southern regions of the study area, petroleum migrates in multiple carrier beds both within and outside the area of the source kitchen. Pressures in the Yaojia Formation were inferred to be hydrostatic while petroleum expulsion and migration took place. Therefore seven "migration-accumulation" (i.e., local palaeo-drainage) systems were defined according to the fluid potential gradients. Migration loss was found to vary markedly between migration-accumulation systems in the study area, and was controlled by factors including the shape, width and area of the effective source rocks, the thickness and distribution of carrier beds inside the source area, the migration distance outside the source area, and the number of carrier beds involved in petroleum migration. Using these two models, petroleum loss during secondary migration was estimated. The loss during secondary migration was approximately 5.21 billion bbl of petroleum, which is approximately 6% of the petroleum expelled into the first Member of the Yaojia Formation. Nearly 80% of the total migration loss occurred in all the carrier beds above the source area.

Paleokarst systems are major carbonate reservoirs that can form significant and very large oilfields. The Ordovician carbonate reservoirs of the Tahe Oilfield represent a special type of hydrocarbon reservoir consisting primarily of paleokarst caves and fractures. Detailed characterization of paleokarst reservoirs in the Tahe area is challenging because of their heterogeneous distribution and, in particular, because these reservoirs are at depths exceeding 5500 m. This paper describes a detailed approach for integrating data from cores, imaging and conventional well logs, and high-quality seismic datasets to delineate the complex paleokarst systems in the Tahe Oilfield, particularly the paleocaves in the run-off zone. Based on the hydrologic genetic relationships between the karst and paleocaves observed in outcrops, we divided the paleocaves in the run-off zone into chambers, main channels, and branch channels. The chambers, which are generally taller than 15 m, are generally collapsed. The main channels, mostly 5–15 m tall, were the main passages for underground water flow and display good connectivity. The branch channels, typically less than 5 m tall, are relatively dispersed and still have a considerable volume. This method was applied to the area around Well T615, and two layers of paleocaves in the run-off zone were interpreted. Seismic mapping and three-dimensional modeling of the paleocaves were performed, and the lengths, widths, areas and volumes of these three types of paleocaves were statistically analyzed. Although most of the chambers have been penetrated by existing wells, the areas where the main channels and a dense network of branch channels developed are favorable targets for future drilling in the Tahe Oilfield. Our method of detecting and analyzing the paleokarst reservoir structure is applicable to similar paleokarst reservoirs.

Reservoir/carrier bed heterogeneity is a common geological phenomenon. This study applied a hydrocarbon migration model based on the invasion percolation theory to simulate the formation of hydrocarbon migration pathways in heterogeneous carrier beds. The results indicate that the pathways and hydrocarbon accumulations in reservoirs may differ from conventional models when continuous low-permeability layers occur as networks within reservoirs. Such low-permeability layers may have formed through depositional or diagenetic processes within reservoir rocks at variable scales. Oil-bearing reservoir in Donghe Sandstone in Hadexun Oilfield in northern Tarim Basin, China, was analyzed to demonstrate the forming mechanisms of substantial tilting of oil-water contact. Donghe Sandstone is a quartz sandstone deposited in an open marine shoreface-shelf environment during a major transgression in Early Carboniferous. . Major diagenetic products are abundant tabular concretions along bedding planes and cross laminae. The low-permeability concretions serve as fluid flow barriers which compartmentalize the Donghe Sandstone reservoir. As a result, the oil-water contacts and the saturation of oil in the reservoir appear irregular and tilted in Hadexun Oilfield and neighboring regions.

These effective reservoir rocks that can have sufficient porosity and permeability and hydrocarbon accumulations determine economic reserves and high yield of tight oil and gas. Understanding the origin and distribution of these effective reservoir rocks is important for sorting out “sweet spots” in tight reservoirs. Multiple-scale analyses from the microscopic, via drill core to single wellbore have been conducted to examine reservoir heterogeneity of the Upper Paleozoic Shanxi Formation in the southeastern Ordos Basin. Five sandstone petrofacies have been defined in terms of texture and framework composition, detrital matrix, diagenesis and pore types: quartz arenite, tuffaceous quartz arenite, ductile lithic-lean sub-litharenite, ductile lithic-rich sandstone and tightly carbonate-cemented sandstone. The various petrofacies show fundamentally different pathways of diagenetic and reservoir-quality evolutions, due to the complexity of texture and detrital composition in the Shanxi Formation, directly related to the provenance and depositional environment. Quartz arenites and ductile grain-lean sub-litharenites both form effective reservoir rocks. By translating petrofacies to well-log signatures corrected from petrographic and core analysis data, a model based on factor analysis has been built to predict petrofacies at the well scale. For investigating the distribution of each petrofacies at the field scale, sequential indicator simulation method has been used to construct a 3-D petrofacies model with facies conditioning. The isopach maps of quartz arenites and ductile lithic-lean sub-litharenites have been made from the 3-D petrofacies model to quantify their areal distributions, and to define the “sweet spots” by combining isopach maps of these effective reservoir rocks and gas production data from well tests. The concept of reservoir petrofacies is an important tool for the characterization of tight sandstone reservoirs.

Studies on migration pathways remain qualitative, albeit extensive quantification of migration forcing. In this study, hydrocarbon carriers are defined as carrier units and their corresponding carrier beds for the Third Member of Eocene Shahejie Formation in the Dongying Depression, Bohai Bay Basin, eastern China, on the basis of their lithofacies and physical properties, spatial relationships, and data availability; secondary migration conduits are then quantified. A carrier unit is defined as a stratigraphic unit that contains microscopically porous and permeable carrier beds and is covered by regional seals. The carrier beds are macroscopically and physically connected to each other within a carrier unit and are hydrodynamically connected during secondary migration. A method of quantifying sandstone carrier units using common physical properties is developed. First, a carrier unit containing potential carrier beds is identified on the basis of lithofacies and their lateral changes. Second, physical connectivity of sandstone carrier beds is assessed on the basis of percolation theory. Third, the hydrodynamic connectivity of a sandstone carrier unit is analyzed using effective parameters that may reflect the hydraulic circulation in the carrier unit. Last, the conductivity of a sandstone carrier bed is quantitatively characterized using appropriate physical property parameters. The results for sandstone carrier units in the Third Member of the Shahejie Formation are used in numerical models addressing Pleistocene secondary migration. The model results explain the discovered accumulation and hydrocarbon shows well; and the model predictions on exploration targets have been confirmed by drilling.

Faults play an intricate role in hydrocarbon migration and accumulation since they can serve either as a conduit or a seal. Quantitative evaluation of fault opening/sealing properties requires the selection of valid and optimal parameters among numerous geological factors to characterize the hydraulic behaviors of faults. The present study focuses on the Chengbei Step-Fault Area in the Qikou Depression, Bohai Bay Basin, NE China, because hydrocarbon migration and accumulation in this area occurred in a relatively short period so that accumulated hydrocarbons can be used as an indicator to deduce hydraulic connectivity of a fault zone between two sites. Various geological parameters pertinent to a fault, such as burial depth, dip angle, throw, strike, percentage of sandstone of faulted intervals, fluid pressure in faulted mudstone, stress normal to the fault plane, and shale gouge ratio, are analyzed to assess their effectiveness in characterizing fault connectivity. An index, the fault-connectivity probability (Np), is proposed to evaluate the possibility that a fault has been once serving as a migration pathway. The statistical relationship between Np and any a geological parameter may be used to indicate the effectiveness of this parameter in characterizing the connectivity of a fault during hydrocarbon migration. The correlation coefficient of a relationship is a good indicator of the effectiveness; and the results are generally in agreement with qualitative assessments. Parameters representing a single geological factor are generally ineffective, whereas those representing implicitly or explicitly two or more factors, such as shale gouge ratio, stress normal to the fault plane, and fault opening index, are more effective.