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Subsurface hydrocarbon observations at any scale serve as critical clues to understand and reconstruct migration pathways and charge histories through geological time to assess the risk of petroleum exploration targets. Hydrocarbon migration commonly occurred millions of years ago, and the pathways can rarely be observed in wells or in outcrops. Therefore, hydrocarbon migration modeling tools are important to test and quantify the processes and elements, which impact hydrocarbon migration. This paper presents a new method of analyzing migration in superimposed basins, which have experienced multiple stages of basin subsidence and inversion, during which multiple episodes of hydrocarbon generation, migration, and accumulation occurred. The new modeling method first identifies the character of the migration and accumulation units by synthesizing geological factors, such as heterogeneity of carrier beds and reservoirs. Second, hydrocarbon migration is analyzed as a geologic process, for which the invasion-percolation (IP) migration method seems to be most suitable. The IP migration method demonstrates a good relationship between migration driving and resisting forces along pathways and thus can be used to reasonably model hydrocarbon migration processes at any scale of units in a basin. The new migration method provides insights into quantitative methods that can be applied to petroleum system analysis. The new method has been applied to several Chinese basins and has proven to be useful for defining exploration targets and resource assessments in mature, frontier, and, especially, tectonically complex basins. A case study of the Upper Triassic Chang 7 and Chang 8 units in the southern Ordos Basin, central China, is presented to demonstrate a multistage hydrocarbon accumulation unit. Modeling results show that the same pairs of reservoir-seal sets contained different accumulation units in the geological past with different styles of hydrocarbon migration and different accumulation patterns. It can be concluded that the style and character of early hydrocarbon migration have significantly affected the more recent hydrocarbon migration and the present-day distribution of hydrocarbons.

The Lower Jurassic Ahe Formation is an important exploration target for deep clastic reservoirs in the eastern Kuqa Depression. The Ahe Formation sandstones show heterogeneous porosity and permeability petrophysical properties. These properties have been poorly understood, limiting forecast of petroleum accumulations and making it difficult to develop the reservoirs. Based on cores, thin sections, SEM, and fluid inclusions, this study examined sandstone composition and texture and diagenetic heterogeneity at the core scale. The aim was to understand the influence of variations in detrital composition and texture on diagenetic and reservoir quality evolution. The Ahe Formation sandstones are dominantly fine- to coarse-grained litharenites, with minor feldspathic litharenites. In fining-up sand beds, detrital grain size determines the degree of mechanical compaction and, consequently, the abundance of porosity through ductile grains and muddy matrix. Local complete calcite cementation is a noticeable exception to this general trend. Three sandstone petrofacies have been defined based on texture and framework composition, detrital matrix, diagenesis, and pore types: (1) ductile-lean sandstone, (2) ductile-rich sandstone, and (3) tightly calcite-cemented sandstone. Different petrofacies experienced contrasting diagenetic and porosity evolution pathways. Ductile-lean sandstones underwent lower degree of compaction relative to ductile-rich sandstones during the eodiagenesis stage, and extensive grain dissolution occurred. The petrofacies remained relatively porous and permeable before early oil arrival. With continued burial, the porosity and permeability in the sandstones were further reduced by cementation. The petrofacies still had moderate porosity and permeability and were substantially charged when late petroleum migrated into the reservoirs. Thus, ductile-lean sandstones constitute effective reservoir rocks in deep reservoirs. By translating petrofacies to signatures of well logs, the effective properties of the reservoir rocks can be forecasted at the well scale.

A comprehensive study on rift stratigraphy requires a solid understanding of sequence architecture along the steep margins of rift basins. This study analyzes an Eocene lacustrine sequence along the steep margin of the Dongying depression in eastern China through integrated core, well-log, and three-dimensional seismic analyses. The lacustrine sequence is bounded by unconformities and their correlative conformities at the base and top and consists of three systems tracts, namely an early expansion systems tract (EEST), late expansion–early contraction systems tract (LEECST), and late contraction systems tract (LCST), which record a lake expansion–contraction cycle. These systems tracts differ in thickness and development of depositional systems. The EEST is the thickest and contains well-developed marginal and basinal fan systems with an overall retrogradational stacking pattern. The well-developed fan systems are the most striking features within the sequence. The LEECST is the most widespread and contains dominantly profundal–sublittoral deposits. The LCST is the thinnest, with poorly developed fan systems, and is characterized by significant erosion by fluvial incision. The variable thickness and development of depositional systems in the three systems tracts are the responses to the interplay of sediment supply and accommodation space. Accommodation space establishes the framework for sedimentary infill, and sediment supply determines spatial distribution and temporal evolution of depositional systems within each systems tract. This study provides a lake expansion–contraction scheme to divide a lacustrine stratigraphic sequence into systems tracts and highlights the feasibility of applying this approach in studying sequence stratigraphy along the steep margin of a lacustrine rift basin. The results also provide understandings for the development, distribution, and evolution of depositional systems and their controlling factors along the steep margin of other rift basins in the world.

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.

Micro-nano scale pores can accurately and fastly be measured by the nuclear magnetic resonance (NMR) technique, which provides a new method to quantitatively characterize pore structures in tight sandstone. Based on the method of calibration of mercury pressure data for NMR T2 spectrum, for the measurement inaccuracy due to the mercury saturation less than 100% in tight sandstone, the mercury pressure curve and T2 spectrum is used to cumulate from the maximum pore on the right boundary to the small pores in the left, the range of pore-throat radius measured by the mercury injection in the leftward cumulative curve is selected as a comparable interval of NMR pore-throat radius, and the longitudinal interpolation method and the least square method are utilized to construct the distribution curve of pore-throat radius transformed by T2 spectrum. The modified method is used to obtain NMR T2 spectrum, conversion coefficient of pore-throat radius and pore-throat radius distribution of the Carboniferous-Permian tight sandstone gas reservoirs in the eastern Linqing depression, and characteristics of reservoir pore structures are quantitatively investigated; in addition, in combination with analysis of thin section and scanning electron microscopy, the reservoir effectiveness and cause of the pore structure variability in the tight sandstone are also well studied. The results show that the NMR pore-throat radius curve obtained by the modified method has a high consistency with the mercury injection curve, and the NMR test accuracy of tight sandstone is significantly improved. In the study area, the pore-throat radius of the Carboniferous-Permian tight sandstone mainly ranges from 0.002 to 2 μm, the pore is generally submicro-nano scale, but the pore-throat radius distribution of different types of sandstone varies significantly. The lithic quartz sandstone is rich in siliceous matter and poor in plastic detritus and matrix, generally dominated by submicro-scale pore-throats including micro-scale pore-throats; lithic feldspar sandstone and quartz-rich feldspar lithic sandstone are rich in quartz and poor in plastic detritus and matrix, dominated by submicro-nano scale pore-throats (nano-scale pore-throats predominantly); the lithic fragment-rich feldspar lithic sandstone and lithic sandstone are poor in quartz and rich in plastic detritus and matrix, mainly dominated by nano-scale pore-throats smaller than 0.05 μm. Micropetrographic components are key factors to control pore structure difference and reservoir effectiveness, and the reservoir quality may be macroscopically controlled by sedimentary microfacies; the lithic quartz sandstones of coarse- and fine-grained point bar/riverbed microfacies are the most favorable reservoirs; the lithic feldspar sandstone of fine-grained point bar microfacies, the quartz-rich feldspar lithic sandstone of fine-grained distributary channel and barrier bar microfacies are relatively favorable reservoirs, while both lithic fragment-rich feldspar lithic sandstone and lithic sandstone of tidal-flat facies are ineffective reservoirs with very poor porosity and permeability. Keywords: NMR T2 spectrum, Mercury injection, Conversion coefficient, Pore-throat, Rock fabric, Microfacies, Tight sandstone, Linqing depression

Grain crushing is common, and porosity loss due to mechanical compaction dominates in cool, young, rapidly subsiding and deep basins where cementation do not have enough time to significantly reduce porosity. However, the application of existing porosity predicted model during compaction in deep buried sandstone may be doubt when the grain crushing is intense. Based on compaction experiments, the grain crushing, grain size distribution and packing texture were analyzed, and a quantitative evaluation method for predicting compaction porosity loss (COPL) were proposed, which consider grain breakage and packing texture evolution stages. The results of compaction experiments confirmed that grain crushing, grain size, grain packing texture and effective stress in sandstone all influence porosity reduction during compaction in cool, young, rapidly subsiding basins. The sandstones experienced grain sliding, grain crushing, and grain rearrangement after crushing during compaction. The grain packing texture transforms from one-component packing to binary packing texture due to intense grain crushing in well-sorted coarse sandstone. Parameter ‘S’, which is named as grain-crushing factor is significantly linear with effective stress. Analysis of our results leads to a dynamic equilibrium that describes the grain crushing in sandstone during compaction. The relationship between σ*(MZ)2 and COPL reflects the dynamic equilibrium during the compaction of sandstone with grain crushing. When mean grain size of sandstone under different stress can be obtained from experiment, the function between parameter σ*(Mz)2 and COPL are well applied in porosity prediction. The partial derivative (∂COPL/∂σ*) calculated by existing logarithmic porosity predicted model agree with the measured data better than that of values calculated by existing exponential porosity predicted model in sandstone with intense grain crushing. For underground sandstone which mean grain size under different stress cannot be obtained, the logarithmic porosity predicted model can be applied in sandstone which grain crushing is intense, the constant parameter in logarithmic porosity predicted model can be predicted by mean grain size. The exponential porosity predicted model were well applied in sandstone without grain crushing. The selection of porosity predicted model of sandstone during compaction should be based on the intense of grain crushing and the stage of compaction.

It is common for many tight gas sandstone reservoirs to have experienced an early oil charge before gas invading. To determine the effects of early oil emplacement on reservoir quality and gas migration has important role in predicting “sweet spots” of gas production in tight sand reservoirs. We investigated the palaeo and current fluids contacts accurately due to parameters from quantitative grain fluorescence in the Lower Jurassic Ahe Formation of Dibei gas field. The porosity and permeability values in palaeo-oil leg are totally higher than in palaeo-water leg, especially there being a wide gap of permeability with an order of magnitude. The variation of reservoir quality derives from the early oil emplacement, which restrained clay conversions from kaolinite or illite-smectite mixed-layer into fibrous illite that dramatically increasing flow-path tortuosity in sandstones, according to core analysis and X-ray diffraction. The early oil preserved penetrating quality of palaeo-oil leg, but the sandstones that never experienced early oil emplacement contains much more fibrous illite. It made most of early oil pathways subsequently act as the migration pathways for late gas and less than 50% of the migration pathways for gas were caused by microfractures due to quantitative grain fluorescence. Only the sandstones with medium early oil saturation did become sweet spots for gas in the tight sand reservoirs. Too much and too little oil once saturated in pores maybe adverse to the late gas migration and accumulation.

The Nanyang Sag in the Nanxiang Basin, eastern China, has a large petroleum resource, although the genetic potential of source rocks and oil-rock correlation in the Paleogene Hetaoyuan Formation is unclear. Organic geochemistry and molecular geochemistry analyses of mudstone and oil samples were performed to evaluate source rock potential, classify oil groups, and establish accurate oil-source rock correlation. The results suggest that the second member (Eh(2)) and the third member (Eh(3)) of the Hetaoyuan Formation are good source rocks, contain abundant organic matter and oil-prone kerogen, and are thermally mature. Oil samples from Eh(2) and Eh(3) were separated into 3 groups derived from different source rocks. Group I oils are mainly distributed in the Eh(2) and Eh(3) members around the Dongzhuang (Dongz) structure belt and are characterized by a low saturated hydrocarbon content (SAT, 39.07-49.54%), high total resin (RE) and asphaltene (ASP) content (17.22-22.80%), low gammacerane index (gammacerane/C(30)17(H)-hopane 0.88), and low Pr/Ph (

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.

Shale oil and gas have been discovered in the lacustrine Zhangjiatan Shale in the southern Ordos Basin, China. To study the distribution of extractable organic matter (EOM) in the Zhangjiatan Shale ([Formula: see text] ranges from 1.25% to 1.28%), geochemical characterization of core samples of different lithologies, scanning electron microscope observations, low-pressure [Formula: see text] and [Formula: see text] adsorption, and helium pycnometry were conducted. The content and saturation of the EOM in the pores were quantitatively characterized. The results show that the distribution of the EOM in the shale interval is heterogeneous. In general, the shale layers have a higher EOM content and saturation than siltstone layers. The total organic content and the original storage capacity control the EOM content in the shale layers. For the siltstone layers, the EOM content is mainly determined by the original storage capacity. On average, 75% of the EOM occurs in the mesopores, followed by 14% in the macropores, and 11% in the micropores. The EOM saturation in the pores decreases with the increase in pore diameter. The distribution of EOM in the shale pores is closely related to the pore type. Micropores and mesopores developed in the kerogens and pyrobitumens and the clay-mineral pores coated with organic matter are most favorable for EOM retention and charging.

The deposition and preservation of high-quality rocks in a heterogeneous petroleum reservoir and associated mechanisms for hydrocarbon emplacement and migration are one of the most critical issues in deep exploration. Applying an integrated approach of petrography, SEM, stable carbon and oxygen isotopes, and fluid inclusion analyses, this study was designed to examine the relationship between diagenetic evolution and oil emplacement in the Lower Jurassic Sangonghe Formation in the Fukang Sag, central Junggar Basin (NW China). The sandstones consist mainly of feldspathic litharenite, and litharenite. Primary sandstone texture and compositions (grain size, ductile lithic sand grains) determine reservoir diagenetic heterogeneity. Grain size controls the overall abundances of cement and porosity, and reservoir properties through its effect on ductile lithic grains and hence on mechanical compaction. Ductile lithic-rich, very fine- to fine-grained sandstones had a limited diagenetic process in which compaction of easily deformed, clay-rich lithic grains predominated, resulting in a very rapid loss of porosity during burial. They achieved a high capillary entry pressure before the first oil arrival and were not charged later. In contrast, diagenetic events in the relatively coarser-grained sandstones with less abundant ductile lithic grains included dissolution and cementation as well as ductile compaction. Diagenesis progressed alternately with oil emplacement and in some cases, they occurred synchronously. Late diagenetic Fe-calcite, ankerite, and barite may be good mineralogical signatures of oil charge and migration. The nonreservoir, ductile lithic-rich, tightly compacted sandstones can constitute impermeable barrier interbeds embedded in permeable reservoir rocks, probably resulting in heterogeneous flow.

The second member of the Upper Triassic Xujiahe Formation is an important target for tight gas exploration in the western Sichuan Basin. The diagenetic history and reservoir evolution were investigated using integrated analyses of petrography, X-ray diffraction (XRD), scanning electron microscopy (SEM), cathodoluminescence (CL), fluid inclusion microthermometry and stable carbon and oxygen isotopes. The sandstones consist mainly of litharenites, sublitharenites and feldsparthic litharenites with fine-to medium-sand grain sizes, moderate to good sorting and subangular to subrounded roundness. The reservoir properties of the sandstones are generally poor with low porosity and matrix permeability, small pore-throat radii, and high displacement pressure. Eodiagenesis is composed mainly of mechanical compaction, precipitation of siderite, stage-I quartz overgrowths, chlorite, calcite and ferroan calcite. Mesodiagenesis consists mainly of mechanical and chemical compaction, calcite and ferroan calcite precipitation, stage-II and stage-III quartz cementation, feldspar dissolution and precipitation of illite, dolomite and ankerite. Three types of sandstone lithofacies are defined according to sandstone textures and composition, diagenetic minerals, grain sizes, sorting and pore types: lithofacies I, II and III. Compaction appears to reduce the reservoir quality more significantly compared to cementation. Authigenic chlorite coats were constructive in preserving primary porosity, while carbonate cementation decreased reservoir quality. Diagenetic evolution pathways and reservoir quality prediction models for the Upper Triassic Xujiahe Formation sandstones have been proposed to shed light on the different reservoir quality evolution patterns of various sandstone lithofacies. Lithofacies I ─ medium and coarse-grained sandstones characterized by extensive chlorite coating, feldspar dissolution and a low content of clay matrix and cement, appears to have the best reservoir properties and may serve as a high-quality reservoir facies in these tight sandstone reservoirs.

Tight sand gas plays an important role in the supply of natural gas production. It has significance for predicting sweet spots to recognize the characteristics and forming of heterogeneity in tight sandstone carrier beds. Heterogeneity responsible for spatial structure, such as the combination and distribution of relatively homogeneous rock layers, is basically established by deposition and eodiagenesis that collectively affect the mesogenesis. We have investigated the structural heterogeneity units by petrofacies in tight sandstone carrier beds of Dibei, eastern Kuqa Depression, according to core, logging, and micropetrology. There are four types of main petrofacies, that is, tight compacted, tight carbonate-cemented, gas-bearing, and water-bearing sandstones. The brine-rock-hydrocarbon diagenesis changes of different heterogeneity structural units have been determined according to the pore bitumen, hydrocarbon inclusions, and quantitative grain fluorescence. Ductile grains or eogenetic calcite cements destroy the reservoir quality of tight compacted or tight carbonate-cemented sandstones. Rigid grains can resist mechanical compaction and oil emplacement before gas charging can inhibit diagenesis to preserve reservoir property of other sandstones. We propose that there is an inheritance relationship between the late gas and early oil migration pathways, which implies that the sweet spots develop in the reservoirs that experienced early oil emplacement.

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.