Bulletin Article


We present a method of using fault displacement-distance profiles to distinguish fault-bend, shear fault-bend, and fault-propagation folds, and use these insights to guide balanced and retrodeformable interpretations of these structures. We first describe the displacement profiles associated with different end-member fault-related folding models, then provide examples of structures that are consistent with these model-based predictions. Natural examples are imaged in high-resolution two- and three dimensional seismic reflection data sets from the Niger Delta, Sichuan Basin, Sierras Pampeanas, and Cascadia to record variations in displacement with distance updip along faults (termed displacement-distance profiles). Fault-bend folds exhibit constant displacement along fault segments and changes in displacement associated with bends in faults, shear fault-bend folds demonstrate an increase in displacement through the shearing interval, and fault-propagation folds exhibit decreasing displacement toward the fault tip. More complex structures are then investigated using this method, demonstrating that displacement-distance profiles can be used to provide insight into structures that involve multiple fault-related folding processes or have changed kinematic behavior over time. These interpretations are supported by comparison with the kinematics inferred from the geometry of growth strata overlying these structures. Collectively, these analyses illustrate that the displacement-distance approach can provide valuable insights into the styles of fault-related folding.


The Tarim Basin is one of the most important hydrocabon-bearing evaporite basins in China. Four salt-bearing sequences, the Middle and Lower Cambrian, the Mississippian, the Paleogene, and the Neogene, have various thickness and areal distribution. They are important detachment layers and intensely affect the structural deformation in the basin. The Kuqa depression is a subordinate structural unit with abundant salt structures in the Tarim Basin. Salt overthrusts, salt pillows, salt anticlines, salt diapirs, and salt-withdrawal basins are predominant in the depression. Contraction that resulted from orogeny played a key function on the formation of salt structures. Growth strata reveal that intense salt structural deformation in the Kuqa depression occurred during the Himalayan movement from Oligocene to Holocene, with early structural deformation in the north and late deformation in the south. Growth sequences also record at least two phases of salt tectonism. In the Yingmaili, Tahe, and Tazhong areas, low-amplitude salt pillows are the most common salt structures, and these structures are commonly accompanied by thrust faults. The faulting and uplifting of basement blocks controlled the location of salt structures. The differences in the geometries of salt structures in different regions show that the thickness of the salt sequences has an important influence on the development of salt-cored detachment folds and related thrust faults in the Tarim Basin.

Salt sequences and salt structures in the Tarim Basin are closely linked to hydrocarbon accumulations. Oil and gas fields have been discovered in the subsalt, intrasalt, and suprasalt strata. Salt deformation has created numerous potential traps, and salt sequences have provided a good seal for the preservation of hydrocarbon accumulations. Large- and small-scale faults related with salt structures have also given favorable migration pathways for oil and gas. When interpreting seismic profiles, special attention needs to be paid to the clastic and carbonate interbeds within the salt sequences because they may lead to incorrect structural interpretation. In the Tarim Basin, the subsalt anticlinal traps are good targets for hydrocarbon exploration.


Using diverse geologic and geophysical data from recent exploration and development, and experimental results of analysis of gas content, gas capacity, and gas composition, this article discusses how geologic, structural, and hydrological factors determine the heterogeneous distribution of gas in the Weibei coalbed methane (CBM) field.

The coal rank of the Pennsylvanian no. 5 coal seam is mainly low-volatile bituminous and semianthracite. The total gas content is 2.69 to 16.15 m3/t (95.00–570.33 scf/t), and gas saturation is 26.0% to 93.2%. Burial coalification followed by tectonically driven hydrothermal activity controls not only thermal maturity, but also the quality and quantity of thermogenic gas generated from the coal.

Gas composition indicates that the CBM is dry and of dominantly thermogenic origin. The thermogenic gases have been altered by fractionation that may be related to subsurface water movement in the southern part of the study area.

Three gas accumulation models are identified: (1) gas diffusion and long-distance migration of thermogenic gases to no-flow boundaries for sorption and minor conventional trapping, (2) hydrodynamic trapping of gas in structural lows, and (3) gas loss by hydrodynamic flushing. The first two models are applicable for the formation of two CBM enrichment areas in blocks B3 and B4, whereas the last model explains extremely low gas content and gas saturation in block B5. The variable gas content, saturation, and accumulation characteristics are mainly controlled by these gas accumulation models.

This article reviews the mechanisms of shale gas storage and discusses the major risks or uncertainties for shale gas exploration in China. At a given temperature and pressure, the gas sorption capacities of organic-rich shales are primarily controlled by the organic matter richness but may be significantly influenced by the type and maturity of the organic matter, mineral composition (especially clay content), moisture content, pore volume and structure, resulting in different ratios of gas sorption capacity (GSC) to total organic carbon content for different shales. In laboratory experiments, the GSC of organic-rich shales increases with increasing pressure and decreases with increasing temperature. Under geologic conditions (assuming hydrostatic pressure gradient and constant thermal gradient), the GSC increases initially with depth due to the predominating effect of pressure, passes through a maximum, and then decreases because of the influence of increasing temperature at greater depth. This pattern of variation is quite similar to that observed for coals and is of great significance for understanding the changes in GSC of organic-rich shales over geologic time as a function of burial history. At an elevated temperature and pressure and with the presence of moisture, the gas sorption capacities of organic-rich shales are quite low. As a result, adsorption alone cannot protect sufficient gas for high-maturity organic-rich shales to be commercial gas reservoirs. Two models are proposed to predict the variation of GSC and total gas content over geologic time as a function of burial history. High contents of free gas in organic-rich shales can be preserved in relatively closed systems. Loss of free gas during postgeneration uplift and erosion may result in undersaturation (the total gas contents lower than the sorption capacity) and is the major risk for gas exploration in marine organic-rich shales in China.

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