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Hydrocarbon source rock obviously controls the formation and distribution of hydrocarbon reservoirs. Based on the geological concept of “source control theory”, the concept of a hydrocarbon distribution threshold was put forward. This means the maximum range for hydrocarbon controlled by the source rock conditions to migrate in the hydrocarbon basins. Three quantitative analysis models are proposed on this basis, namely the hydrocarbon accumulation probability, maximum hydrocarbon scale threshold and reserve distribution probability, which respectively refer to the probability of forming a hydrocarbon reservoir, the possible maximum scale of the hydrocarbon reservoir and the percentage of reserve distribution in a certain area within the hydrocarbon distribution threshold. Statistical analysis on 539 hydrocarbon reservoirs discovered in 28 hydrocarbon source kitchens from seven sedimentary basins and sags of eastern China shows the maximum reservoir scale possibly formed in the hydrocarbon basin, hydrocarbon accumulation probability and oil and gas reserve distribution probability are all controlled by the characteristics of the hydrocarbon source rock. Generally, as the distances from the hydrocarbon source rock center and hydrocarbon discharge boundary get longer and the hydrocarbon discharge intensity of hydrocarbon source rock center gets smaller, there will be lower probability of hydrocarbon accumulation. Corresponding quantitative models are established based on single factor statistics and multivariate analysis. Practical application in the Jiyang Depression shows that the prediction from the quantitative analysis model for the hydrocarbon distribution threshold agree well with the actual exploration results, indicating that the quantitative analysis model is likely to be a feasible tool.

Hydrocarbon distribution rules in the deep and shallow parts of sedimentary basins are considerably different, particularly in the following four aspects. First, the critical porosity for hydrocarbon migration is much lower in the deep parts of basins: at a depth of 7000 m, hydrocarbons can accumulate only in rocks with porosity less than 5%. However, in the shallow parts of basins (i.e., depths of around 1000 m), hydrocarbon can accumulate in rocks only when porosity is over 20%. Second, hydrocarbon reservoirs tend to exhibit negative pressures after hydrocarbon accumulation at depth, with a pressure coefficient less than 0.7. However, hydrocarbon reservoirs at shallow depths tend to exhibit high pressure after hydrocarbon accumulation. Third, deep reservoirs tend to exhibit characteristics of oil (–gas)–water inversion, indicating that the oil (gas) accumulated under the water. However, the oil (gas) tends to accumulate over water in shallow reservoirs. Fourth, continuous unconventional tight hydrocarbon reservoirs are distributed widely in deep reservoirs, where the buoyancy force is not the primary dynamic force and the caprock is not involved during the process of hydrocarbon accumulation. Conversely, the majority of hydrocarbons in shallow regions accumulate in traps with complex structures. The results of this study indicate that two dynamic boundary conditions are primarily responsible for the above phenomena: a lower limit to the buoyancy force and the lower limit of hydrocarbon accumulation overall, corresponding to about 10%–12% porosity and irreducible water saturation of 100%, respectively. These two dynamic boundary conditions were used to divide sedimentary basins into three different dynamic fields of hydrocarbon accumulation: the free fluid dynamic field, limit fluid dynamic field, and restrain fluid dynamic field. The free fluid dynamic field is located between the surface and the lower limit of the buoyancy force, such that hydrocarbons in this field migrate and accumulate under the influence of, for example, the buoyancy force, pressure, hydrodynamic force, and capillary force. The hydrocarbon reservoirs formed are characterized as “four high,” indicating that they accumulate in high structures, are sealed in high locations, migrate into areas of high porosity, and are stored in reservoirs at high pressure. The basic features of distribution and accumulation in this case include hydrocarbon migration as a result of the buoyancy force and formation of a reservoir by a caprock. The limit fluid dynamic field is located between the lower limit of the buoyancy force and the lower limit of hydrocarbon accumulation overall; the hydrocarbon migrates and accumulates as a result of, for example, the molecular expansion force and the capillary force. The hydrocarbon reservoirs formed are characterized as “four low,” indicating that hydrocarbons accumulate in low structures, migrate into areas of low porosity, and accumulate in reservoirs with low pressure, and that oil(–gas)–water inversion occurs at low locations. Continuous hydrocarbon accumulation over a large area is a basic feature of this field. The restrain fluid dynamic field is located under the bottom of hydrocarbon accumulation, such that the entire pore space is filled with water. Hydrocarbons migrate as a result of the molecular diffusion force only. This field lacks many of the basic conditions required for formation of hydrocarbon reservoirs: there is no effective porosity, movable fluid, or hydrocarbon accumulation, and potential for hydrocarbon exploration is low. Many conventional hydrocarbon resources have been discovered and exploited in the free fluid dynamic field of shallow reservoirs, where exploration potential was previously considered to be low. Continuous unconventional tight hydrocarbon resources have been discovered in the limit fluid dynamic field of deep reservoirs; the exploration potential of this setting is thought to be tremendous, indicating that future exploration should be focused primarily in this direction.

Hydrocarbon Accumulation Coefficient (HAC) is an important parameter in the genetic method of hydrocarbon resource assessment. This parameter is usually derived from a simple geological analogy or from expert judgment based on experience, which can lead to large uncertainties in hydrocarbon resource assessment results. In this article, we introduce a new method for determining the HAC, based on Single Factor Correlation Analysis and Multivariate Regression Analysis, using data collected from basins with a high degree of exploration maturity and large amounts of proven reserves. Firstly, the principal factors that control the hydrocarbon accumulation coefficient, such as the time ratio of peak expulsion and caprock formation, the ratio of maximum fault throw and caprock thickness, and the rate of fault displacement, are determined by Single Factor Correlation Analyses. A quantitative model can then be established between HAC and the principal controlling factors using the Multivariate Regression Analysis. The proposed method was applied to the Huanghekou Sag in Bohai Bay Basin, eastern China. The results show that the HAC is 29% in the Huanghekou Sag, with a total resource of 1435 × 106 m3 oil equivalent, which is consistent with geological observations of this basin and suggests that the proposed method improves the applicability of the generic method in resource assessment.

The field size distribution method, such as the Pareto model, is commonly used in hydrocarbon resource assessment in China. It has the advantage of predicting not only the total resources but also the individual field sizes. However, the method has a large uncertainty range in the model parameter estimates. A multi-parameter-constrained Pareto model is proposed to improve parameter estimations. The constraints introduced include: a) total resource estimate from other methods (e.g. genetic method); b) the largest size of undiscovered fields from an empirical relationship between play resources and the largest field sizes in well explored basins; and c) the number of undiscovered fields constrained by the number of untested traps (including subtle traps). By introducing the three constraints, the method provides realistic results with less uncertainty and is consistent with petroleum system models derived from hydrocarbon exploration. The application of this proposed method to Bozhong Sag in the Bohai Bay Basin suggests a total resource of 4130×106 m3 in 48 fields, of which 1165×106 m3 are in 27 discovered fields and 2965×106 m3 are in the remaining 21 undiscovered fields. The largest discovered field is 369×106 m3 and the largest remaining field expected is 853×106 m3. The results of the application appear to be consistent with the current exploration status and geological understanding of the study area.

The Bozhong Sag is the biggest hydrocarbon rich sag in the Bohai Sea area. However, hydrocarbon resource potential and its distribution are not clear, which restricts petroleum exploration. According to the material balance principle and the hydrocarbon accumulation threshold theory, the resource potential and distribution characteristics of hydrocarbons were evaluated quantitatively with hydrocarbon accumulation systems as evaluation units. The upper and lower plays in the Bozhong Sag and surrounding areas each can be divided into six hydrocarbon accumulation systems. The total afforded accumulation hydrocarbon quantity in the Bozhong Sag and surrounding areas is 60.265×108 t of oil (43.185×108 t in the upper play, 17.080×108 t in the lower play) and 27.03×1011 m3 of gas (17.76×1011 m3 in the upper play and 9.27×1011 m3 in the lower play). The Shijiutuo (I) and Bodong (II) accumulation systems are the further exploration areas with the greatest afforded accumulation hydrocarbon quantity. Key words: Bozhong Sag, hydrocarbon accumulation system, hydrocarbon accumulation threshold, hydrocarbon accumulation quantity, resource evaluation

Research on effective source rocks directly affects the accuracy of identifying hydrocarbon resources, and indirectly affects the exploration decisions in petroliferous basins. Although the previous evaluation methods of effective source rocks vary relatively widely, a complete quantitative evaluation approach has not yet been developed. For that reason, we redefined the concept of effective source rocks based on the existing research results. Surrounding this definition, and guided by the hydrocarbon expulsion theory, the quantitative model called “two stages and three steps” method is established to predict effective source rocks. Its application in the Bozhong Depression indicates that among the four sets source rocks in the Bozhong Depression, the Member 3 of the Shahejie Formation (Es3) has the largest effective source rock thickness, and the Member 1-Member 2 of the Shahejie Formation (Es1+2) is the second largest. The effective part of dark mudstone is only 30%–80% of the total volume and with the increase of buried depth and improvement of quality, the effective part increases. Comprehensive analysis indicates that the “two stages and three steps” method is a practical technique for effective source rock prediction.

Based on comprehensive analysis of reservoir-forming conditions, the diversity of reservoir and the difference of multistage hydrocarbon charge are the key factors for the carbonate hydrocarbon accumulation of the Ordovician in the Tarim Basin. Undergone four major deposition-tectonic cycles, the Ordovician carbonate formed a stable structural framework with huge uplifts, in which are developed reservoirs of the reef-bank type and unconformity type, and resulted in multistage hydrocarbon charge and accumulation during the Caledonian, Late Hercynian and Late Himalayan. With low matrix porosity and permeability of the Ordovician carbonate, the secondary solution pores and caverns serve as the main reservoir space. The polyphase tectonic movements formed unconformity reservoirs widely distributed around the paleo-uplifts; and the reef-bank reservoir is controlled by two kinds of sedimentary facies belts, namely the steep slope and gentle slope. The unconventional carbonate pool is characterized by extensive distribution, no obvious edge water or bottom water, complicated oil/gas/water relations and severe heterogeneity controlled by reservoirs. The low porosity and low permeability reservoir together with multi-period hydrocarbon accumulation resulted in the difference and complex of the distribution and production of oil/gas/water. The distribution of hydrocarbon is controlled by the temporal-spatial relation between revolution of source rocks and paleo-uplifts. The heterogenetic carbonate reservoir and late-stage gas charge are the main factors making the oil/ gas phase complicated. The slope areas of the paleo-uplifts formed in the Paleozoic are the main carbonate exploration directions based on comprehensive evaluation. The Ordovician of the northern slope of the Tazhong uplift, Lunnan and its periphery areas are practical exploration fields. The Yengimahalla-Hanikatam and Markit slopes are the important replacement targets for carbonate exploration. Gucheng, Tadong, the deep layers of Cambrian dolomite in the Lunnan and Tazhong-Bachu areas are favorable directions for research and risk exploration.

Superimposed basins in West China have experienced multi-stage tectonic events and multicycle hydrocarbon reservoir formation, and complex hydrocarbon reservoirs have been discovered widely in basins of this kind. Most of the complex hydrocarbon reservoirs are characterized by relocation, scale re-construction, component variation and phase state transformation, and their distributions are very difficult to predict. Research shows that regional caprock (C), high-quality sedimentary facies (Deposits, D), paleohighs (Mountain, M) and source rock (S) are four geologic elements contributing to complex hydrocarbon reservoir formation and distribution of western superimposed basins. Longitudinal sequential combinations of the four elements control the strata of hydrocarbon reservoir formation, and planar superimpositions and combinations control the range of hydrocarbon reservoir and their simultaneous joint effects in geohistory determine the time of hydrocarbon reservoir formation. Multiple-element matching reservoir formation presents a basic mode of reservoir formation in superimposed basins, and we recommend it is expressed as T-CDMS. Based on the multiple-element matching reservoir formation mode, a comprehensive reservoir formation index (Tcdms) is developed in this paper to characterize reservoir formation conditions, and a method is presented to predict reservoir formation range and probability of occurrence in superimposed basins. Through application of new theory, methods and technology, the favorable reservoir formation range and probability of occurrence in the Ordovician target zone in Tarim Basin in four different reservoir formation periods are predicted. Results show that central Tarim, Yinmaili and Lunnan are the three most favorable regions where Ordovician oil and gas fields may have formed. The coincidence of prediction results with currently discovered hydrocarbon reservoirs reaches 97%. This reflects the effectiveness and reliability of the new theory, methods and technology.

The oil, gas and water volumes revealed by the productivity of exploratory wells do not reflect the actual underground situations. Under the geologic conditions, a certain amount of dissolved natural gas is stored in oil or water. Based on the production test data of exploratory wells in the Tazhong uplift of the Tarim basin, this paper discusses in detail the differences in occurrence and distribution featrues between the surface and underground natural gases; presents a restoration of the surface gas occurrence to actual underground geologic conditions according to the dissolubility of natural gas under different temperature, pressure and medium conditions; and classifies the natural gas into three states, i.e. the oversaturated, saturated and undersaturated, according to its relative content underground. Through a comparative analysis of the differences in surface and underground occurrences of natural gas, it discusses the hydrocarbon reservoir formation mechanism and distribution rules, thereby providing guidances as new methods and technologies for the prediction of potential natural gas reservoir distribution in the study area.

The Tazhong paleouplift is divided into the upper and the lower structural layers, bounded by the unconformity surface at the top of the Ordovician carbonate rock. The reservoirs in the two layers from different parts vary in number, type and reserves, but the mechanism was rarely researched before. Therefore, an explanation of the mechanism will promote petroleum exploration in Tazhong paleouplift. After studying the evolution and reservoir distribution of the Tazhong paleouplift, it is concluded that the evolution in late Caledonian, late Hercynian and Himalayan periods resulted in the upper and the lower structural layers. It is also defined that in the upper structural layer, structural and stratigraphic overlap reservoirs are developed at the top and the upper part of the paleouplift, which are dominated by oil reservoirs, while for the lower structural layer, lithological reservoirs are developed in the lower part of the paleouplift, which are dominated by gas reservoirs, and more reserves are discovered in the lower structural layer than the upper. Through a comparative analysis of accumulation conditions of the upper and the lower structural layers, the mechanism of enrichment differences is clearly explained. The reservoir and seal conditions of the lower structural layer are better than those of the upper layer, which is the reason why more reservoirs have been found in the former. The differences in the carrier system types, trap types and charging periods between the upper and the lower structural layers lead to differences in the reservoir types and distribution. An accumulation model is established for the Tazhong paleouplift. For the upper structural layer, the structural reservoirs and the stratigraphic overlap reservoirs are formed at the upper part of the paleouplift, while for the lower structural layer, the weathering crust reservoirs are formed at the top, the reef-flat reservoirs are formed on the lateral margin, the karst and inside reservoirs are formed in the lower part of the paleouplift.

Many of the sedimentary basins in western China were formed through the superposition and compounding of at least two previously developed sedimentary basins and in general they can be termed as complex superimposed basins. The distinct differences between these basins and monotype basins are their discontinuous stratigraphic sedimentation, stratigraphic structure and stratigraphic stress-strain action over geological history. Based on the correlation of chronological age on structural sections, superimposed basins can be divided into five types in this study: (1) continuous sedimentation type superimposed basins, (2) middle and late stratigraphic superimposed basins, (3) early and late stratigraphic superimposed basins, (4) early and middle stratigraphic superimposed basins, and (5) long-term exposed superimposed basins. Multiple source-reservoir-caprock assemblages have developed in such basins. In addition, multi-stage hydrocarbon generation and expulsion, multiple sources, polycyclic hydrocarbon accumulation and multiple-type hydrocarbon reservoirs adjustment, reformation and destruction have occurred in these basins. The complex reservoirs that have been discovered widely in the superimposed basins to date have remarkably different geologic features from primary reservoirs, and the root causes of this are folding, denudation and the fracture effect caused by multiphase tectonic events in the superimposed basins as well as associated seepage, diffusion, spilling, oxidation, degradation and cracking. Based on their genesis characteristics, complex reservoirs are divided into five categories: (1) primary reservoirs, (2) trap adjustment type reservoirs, (3) component variant reservoirs, (4) phase conversion type reservoirs and (5) scale-reformed reservoirs.

The Silurian stratum in the Tazhong uplift is an important horizon for exploration because it preserves some features of the hydrocarbons produced from multi-stage tectonic evolution. For this reason, the study of the origin of the Silurian oils and their formation characteristics constitutes a major part in revealing the mechanisms for the composite hydrocarbon accumulation zone in the Tazhong area. Geochemical investigations indicate that the physical properties of the Silurian oils in Tazhong vary with belts and blocks, i.e., heavy oils are distributed in the TZ47–15 well-block in the North Slope while normal and light oils in the No. I fault belt and the TZ16 well-block, which means that the oil properties are controlled by structural patterns. Most biomarkers in the Silurian oils are similar to that of the Mid-Upper Ordovician source rocks, suggesting a good genetic relationship. However, the compound specific isotope of n-alkanes in the oils and the chemical components of the hydrocarbons in fluid inclusions indicate that these oils are mixed oils derived from both the Mid-Upper Ordovician and the Cambrian–Lower Ordovician source rocks. Most Silurian oils have a record of secondary alterations like earlier biodegradation, including the occurrence of “UCM” humps in the total ion current (TIC) chromatogram of saturated and aromatic hydrocarbons and 25-norhopane in saturated hydrocarbons of the crude oils, and regular changes in the abundances of light and heavy components from the structural low to the structural high. The fact that the Silurian oils are enriched in chain alkanes, e.g., n-alkanes and 25-norhopane, suggests that they were mixed oils of the earlier degraded oils with the later normal oils. It is suggested that the Silurian oils experienced at least three episodes of petroleum charging according to the composition and distribution as well as the maturity of reservoir crude oils and the oils in fluid inclusions. The migration and accumulation models of these oils in the TZ47–15 well-blocks, the No. I fault belt and the TZ16 well-block are different from but related to each other. The investigation of the origin of the mixed oils and the hydrocarbon migration and accumulation mechanisms in different charging periods is of great significance to petroleum exploration in this area.

Basic characteristics of Ordovician carbonate reservoir beds in the Lungudong region of northeastern part of the Tarim Basin are described in detail and the reservoir-forming conditions of oil and gas are preliminarily discussed in this paper by collecting and sorting out a large amount of data. The carbonate reservoir beds are mainly developed in open-platform and platform marginal facies; the reservoir beds have large changes in and low average values of physical property; the main type is fractured reservoir beds with the fracture-porous type second. The reservoir bed development is chiefly controlled by the distribution of sedimentary facies, tectonic activity and karstification. Whereas the accumulation and distribution of hydrocarbons in the region are controlled by an advantageous structural location, a good reservoir-caprock combination and a favorable transporting system, with the distribution characterized by zones horizontally and belts vertically, the oil and gas are mainly concentrated in areas with structural uplift, densely developed fractures, and surface karst, a vertical vadose zone, and a horizontal undercurrent belt of palaeokarst.

The oil source of the Tarim Basin has been controversial over a long time. This study characterizes the crude oil and investigates the oil sources in the Lunnan region, Tarim Basin by adopting compound specific isotopes of n-alkanes and biomarkers approaches. Although the crude oil has a good correlation with the Middle-Upper Ordovician (O2+3) source rocks and a poor correlation with the Cambrian-Lower Ordovician (∈-O1) based on biomarkers, the s13C data of n-alkanes of the Lunnan oils show an intermediate value between ∈-O1 and O2+3 genetic affinity oils, which suggests that the Lunnan oils are actually of an extensively mixed source. A quantification of oil mixing was performed and the results show that the contribution of the Cambrian-Lower Ordovician source rocks ranges from 11% to 70% (averaging 36%), slightly less than that of the Tazhong uplift. It is suggested that the inconsistency between the biomarkers and δ13C in determining the oil sources in the Lunnan Region results from multiple petroleum charge episodes with different chemical components in one or more episode(s) and different sources. The widespread marine mixed-source oil in the basin indicates that significant petroleum potential in deep horizons is possible. To unravel hydrocarbons accumulation mechanisms for the Lunnan oils is crucial to further petroleum exploration and exploitation in the region.

Complex superimposed basins exhibit multi-stage tectonic events and multi-stage reservoir formation; hydrocarbon reservoirs formed in the early stage have generally late-stage genesis characteristics after undergoing adjustment, reconstruction and destruction of later-stage multiple tectonic events. In this paper, this phenomenon is called the late-stage reservoir formation effect. The late-stage reservoir formation effect is a basic feature of oil and gas-forming reservoirs in complex superimposed basins, revealing not only multi-stage character, relevance and complexity of oil and gas-forming reservoirs in superimposed basins but also the importance of late-stage reservoir formation. Late-stage reservoir formation is not a basic feature of oil and gas forming reservoir in superimposed basins. Multi-stage reservoir formation only characterizes one aspect of oil and gas-forming reservoir in superimposed basins and does not represent fully the complexity of oil and gas-forming reservoir in superimposed basins. We suggest using “late-stage reservoir formation effect” to replace the “late-stage reservoir formation” concept to guide the exploration of complex reservoirs in superimposed basins. Under current geologic conditions, the late-stage reservoir formation effect is represented mainly by four basic forms: phase transformation, scale reconstruction, component variation and trap adjustment. The late-stage reservoir formation effect is produced by two kinds of geologic processes: first, the oil and gas retention function of various geologic thresholds (hydrocarbon expulsion threshold, hydrocarbon migration threshold, and hydrocarbon accumulating threshold) causes the actual time of oil and gas reservoir formation to be later than the time of generation of large amounts of hydrocarbon in a conventional sense, producing the late-stage reservoir formation effect; second, multiple types of tectonic events (continuously strong reconstruction, early-stage strong reconstruction, middle-stage strong reconstruction, late-stage strong reconstruction and long-term stable sedimentation) after oil and gas reservoir formation lead to adjustment, reconstruction and destruction of reservoirs formed earlier, and form new secondary hydrocarbon reservoirs due to the late-stage reservoir formation effect.

Recent detailed organic geochemical and geological investigation indicate that oils of the Bamianhe oilfield, Bohai Bay Basin, East China are the mixture of less mature oils and normal oils derived from the Es4 mudstones and shales with a wide range of thermal maturity from immature to middle-maturity, and most of the oils were proved to be sourced from the depocenter of the Niuzhuang Sag immediately adjacent to the Bamianhe oilfield. Two approaches to quantify the amount of immature oils mixed through quantitative biomarkers were established. One is a relatively simple way only through organic geochemical analysis while the other is to be combined with basin modeling. Selecting biomarkers as proxies is the crucial point in both of them. The results show that the less mature oils mixed in the Bamianhe oilfield is less than 10% and 18% respectively based on the two approaches, which coincide with the results of oil-source rock correlation.

As a kind of abnormal natural gas formed with special mechanism, the deep-basin gas, accumulated in the lower parts of a basin or syncline and trapped by a tight reservoir, has such characteristics as gas-water inversion, abnormal pressure, continuous distribution and tremendous reserves. Being a geological product of the evolution of petroliferous basins by the end of the middle-late stages, the formation of a deep-basin gas accumulation must meet four conditions, i.e., continuous and sufficient gas supply, tight reservoirs in continuous distribution, good sealing caps and stable structures. The areas, where the expansion force of natural gas is smaller than the sum of the capillary force and the hydrostatic pressure within tight reservoirs, are favorable for forming deep-basin gas pools. The range delineated by the above two forces corresponds to that of the deep-basin gas trap. Within the scope of the deep-basin gas trap, the balance relationship between the amounts of ingoing and overflowing gases determines the gas-bearing area of the deep-basin gas pool. The gas volume in regions with high porosity and high permeability is worth exploring under current technical conditions and it is equivalent to the practical resources (about 10%-20% of the deep-basin gas). Based on studies of deep-basin gas formation conditions, the theory of force balance and the equation of material balance, the favorable areas and gas-containing ranges, as well as possible gas-rich regions are preliminarily predicted in the deep-basin gas pools in the Upper Paleozoic He-8 segment of the Ordos basin.

Based on a detailed survey of the distribution and organic geochemical characteristics of potential source rocks in the South Slope of the Niuzhuang Sag, Bohai Bay Basin, eastern China, a new approach to assess the amount of hydrocarbons generated and expelled has been developed. The approach is applicable to evaluate hydrocarbons with different genetic mechanisms. The results show that the models for hydrocarbon generation and expulsion vary with potential source rocks, depending on thermal maturity, types of organic matter and paleoenvironment. Hydrocarbons are mostly generated and expelled from source rocks within the normal oil window. It was calculated that the special interval (algal-rich shales of the Es4 member formed in brackish environments) in the South Slope of the Niuzhuang Sag has a much higher potential of immature oil generation than the other intervals in the area. This suggests that hydrocarbons can definitely be generated in early diagenesis, especially under certain special geological settings. The proportion of hydrocarbons generated and expelled from the Es4 shales in the early diagenetic stage is up to 26.75% and 17.36%, respectively. It was also observed that laminated shales have a much higher expulsion efficiency than massive mudstones. In contrast, the special interval of the Es4 shales proposed from previous studies is probably not the whole rock for oil in the South Slope of the Niuzhuang Sag because of the small proportion of the gross volume and corresponding low percentage of hydrocarbons generated and expelled. A much lower expulsion efficiency of the source rock during the early stage relative to that within the normal oil window has been calculated. Our results indicate that the Es4 mudstones rather than the shales deposited in the Niuzhuang and Guangli Sag are the main source rocks for the oil discovered.

The hydrocarbon kitchen is appropriate for characterizing the center of providing hydrocarbon, and the research on its evolution has a great significance for petroleum exploration. The Bohai offshore area is located in the offshore Bohai Bay basin, North China. It is one of the most petroliferous basins in China. There developed four sets of potential source rocks in the Paleocene. The third member of the Shahejie Formation (E2s3) is the most important source rock. In this paper, the evolution histories of the maturation and hydrocarbon generation & expulsion of E2s3 source rocks are modeled based on the depositional and tectonic development history in combination with geochemical and thermal parameters. The hydrocarbon kitchen evolution of the E2s3 source rocks is analyzed using the amount of expelled hydrocarbon of the E2s3 source rocks in the main geological periods. The result shows that there developed two hydrocarbon kitchens at early stage, which then transformed to one main hydrocarbon kitchen and co-existing multi-hydrocarbon kitchens with the geological evolution, e.g. two hydrocarbon kitchens in the Bozhong and Qikou sags in the Paleocene and one main hydrocarbon kitchen in the Bozhong sag and multi-kitchens in the Qikou, Nanpu, Huanghekou, Liaozhong, Liaoxi and Qinnan sags from the Neogene to the present day. Most oil and gas fields are located in the uplifts and slopes around the main hydrocarbon kitchens, thus the study may provide new insights for understanding the petroleum exploration potential of the Bohai offshore area.

There are three formation stages of Silurian hydrocarbon pools in the Tarim Basin. The widely distributed asphaltic sandstones in the Tazhong (central Tarim) and Tabei (northern Tarim) areas are the results of destruction of hydrocarbon pools formed in the first-stage, and the asphaltic sandstones around the Awati Sag were formed in the second-stage. The hydrocarbon migration characteristics reflected by the residual dry asphalts could represent the migration characteristics of hydrocarbons in the Silurian paleo-pools, while the present movable oil in the Silurian reservoirs is related to the later-stage (the third-stage) hydrocarbon accumulation.

This study presents an overview on the geological setting and geochemical characteristics of Pleistocene shallow gas accumulations in eastern Qaidam Basin, NW China. Five largest gas accumulations discovered in this region have a combined enclosure area of about 87 km2 and 7.9 trillion cubic feet (tcf) of proven plus controlled gas reserves. The dominance of methane (>99.9%) and the δ13C and δD values of methane (−68.51‰ to −65.00‰ and −227.55‰ to −221.94‰, respectively) suggest that these gases are biogenic, derived from the degradation of sedimentary organic matter by methanogens under relatively low temperatures ( 15%) and strong stratification. The deposition and extensive lateral occurrence of shore and shallow lake sands/silts in beach sand sheets and small bars provided excellent reservoirs for the biogenic gas generated from adjacent rocks. Effective but dynamic gas seals were provided by such factors as intermittent vertical variations in the sediment lithologies, hydraulic trapping due to mudstone water saturation, the hydrocarbon gradient created as a result of gas generation from potential caprocks, and the presence of a regional caprock consisting of 400–800-m-thick mudstones and evaporites. It appears that the most favorable traps for large gas accumulations occur on structural slopes near the major gas kitchen, and the prolific gas pools are often those large gentle anticlines with little faulting complication.

Deep Basin Gas is short for deep basin gas accumulation. It is an abnormal gas accumulation whose formation conditions, trapping mechanism and distribution are different from those of normal gas accumulations. Deep basin gas accumulation is characterized by gentle dip angles, subnormal pressure, gas-water inversion and co-occurrence of reservoir and source rock. The fundamental conditions favourable to the formation of deep basin gas accumulation include a plentiful gas source, tight reservoir and tight seal under the reservoir. Two balances are the prerequisite for formation and preservation of deep basin gas accumulation. One is the force balance that occurs between the upward forces, including gas volume expansion pressure and buoyancy, and the downward forces including hydrostatic pressure and capillary pressure. The other is material balance that occurs between the supply amount of gas and the escaping gas. If the amount of gas charging the reservoir is more than that of escaping gas, the distribution range of the accumulation will expand up to the boundary limited by the force balance; and vice versa, a lower supply will cause shrinkage of the range. The force balance determines the theoretical maximum range of deep basin gas accumulation. In this range, gas expelled from the source rock can be accumulated to form a deep basin gas pool. The greater the amount of gas that is expelled from the source rock, the larger will be the distribution range of deep basin gas accumulation. Beyond this range, gas that is expelled from the source rock has no choice but to migrate under the force of buoyancy to form a normal gas accumulation. The equation of force balance predicting the theoretical maximum range of deep basin gas is [Formula: see text] where, Sw ρw, g, ρg represent saturation of water in reservoir, density of water, acceleration of gravity and density of gas, respectively; T and R are, respectively, subsurface temperature of gas and gas constant; L represents the lateral distance from the depth of boundary force balance to the maximum depth of the depression centre. When the thickness of the reservoir( Hs), grain size of sandstone(D), porosity(Ø), and dip of strata(α) increase and maximum burial depth of reservoir( Zm) decreases, the likely distribution range of deep basin gas will shrink. In this paper, based on the mechanism of material balance, the equation calculating the distribution range of a deep basin gas pool in actual geological settings is [Formula: see text] It is shown that, in actual geological settings, the distribution range of deep basin gas accumulation will expand with better source conditions (or with an increase of thickness of source rock ( Hn), abundance of organic matter(C%), kerogen type(KTI) and thermal evolution degree ( Ro)) and with increase of burial rate (SR), burial depth( Zm) and salinity of formation water, but will shrink with increases of age of the reservoir(t), temperature( T), porosity(Ø), permeability (K) and dip of strata(). In the Xiaocaohu region and Well Taican 2 region of the Taibei sag in the Turpan-Hami Basin, stable structural settings, well-developed gas source, tight reservoir and feasible cover are favourable to form a deep basin gas reservoir. Drilling shows that there exist deep basin gas accumulations in Well Taican 2 region and Xiaocaohu sub-sag. For the gas layers drilled in the Jurassic Badaowan formation (J1b) and Xishanyao formation (J2x), there is subnormal pressure generally. The reservoirs outside the gas-bearing range in Hongtai and Gedatai gas field are tight and are interpreted as gas layers by logging and produce gas without water, and so belong to one part of a deep basin gas reservoir. Specially processed seismic data shows that there exists a large amount of natural gas in J1b and J2x of Well Taican 2 region. From the principles of force balance and material balance it is predicted in this paper that the distribution ranges of deep basin gas reservoir in J1b and J2x of Xiaocaohu sub-sag are 600km2 and 750km2, respectively, and the total reserves of natural gas should reach 11.3×1011m3. The Turpan-Hami Basin, located in northwest China, is of Mesozoic and Cenozoic age, and is a continental coal-bearing intermountain basin. Recently significant amounts of oil accumulations have been found in the Jurassic layer, and are thought be coal-derived oils, generated chiefly from coal-bearing layers of the Jurassic Badaowan formation (J1b) and Xishanyao formation (J2x) (Wu, 1996; 1997; Cheng, 1994; Huang, etc., 1995). Coal is a typical humic organic matter and, although it contains macerals of exinite etc. that generate oil, it mainly generates gas. The large oil accumulation that is found in the basin (in which the source rocks generate gas primarily) indicates that natural gas exploration has a wide realm and high prospectivity. We have studied the formation mechanisms of the natural gas reservoirs that have been found. The pressure and attitude features of the formation are different from those of a normal gas reservoir, and are the same as those of deep basin gas reservoirs reported by others (McMaster, 1983; Gant, 1983; Masters, 1993; Welte, et al, 1984; Gies, 1988; Masters, 1988; Yuan and Xu, etc, 1996; Rong, 1993; Li1 et al., 1997; Jin et al, 19982, Jin and Zhang 1999; Chen, 1998; Dai, 1983; Min et al., 1996; 1998). The conditions of accumulation are analyzed and evaluated with deep basin gas accumulation theory, based on which the potential distribution range of deep basin gas is predicted.

Studies on the sequence stratigraphic features of carbonate weathered residuum reveal that the key factor which makes the karstification possible is the permeability paths that occurred, controlled by the exposure events which resulted from drops in the sea level. The formation of carbonate weathered residuum was diagenetically associated with different interfaces of syndepositional sequences. Studies on the weathering degree (diagenetic maturation) of the parasequences in the sedimentary systems have come to the conclusion that the development maturation of the weathered residuum basically represents the increase or decrease of accommodation space. Ideally, a relevant model between sequence stratigraphy and weathered residuum is established. Introducing the theory of sequence stratigraphy into the study of the carbonate reservoirs within the weathered residuum led to the belief that sequence stratigraphic feature analysis of the carbonate weathered residuum is actually a relationship between the different interface natures and reservoir physical properties. By comparing relevant information all over the world, the authors hold that parasequences of neritic carbonates usually represent a small part of sedimentation, and the exposure period makes up about half the period of cycling. Weathered residuum reservoirs occurred dominantly within two temporal ranges: 30–120 Ma, corresponding to megasequences or mesosequences; and 0.01–0.5 Ma, corresponding to parasequences.

Massive dolostones are well developed and can be classified into fine saccharoidal dolostones and coarse saccharoidal dolostones in the Ordovician of the Ordos Basin, North China. An analysis of the inclusion reveals information for the study of the massive dolostones' genesis. The majority of thin sections show that the inclusions are poorly developed in the host crystals of the fine dolomites, but are well-developed in the pore-filling calcite crystals. The homogenization temperatures of the inclusions range from 49°C to 74°C, and the maximum depth of the inclusion formation calculated from such temperatures is about 172m. Thus the host crystals of the fine saccharoidal dolostones have been formed in shallow burial environments with a depth of about 172m. On the other hand, the inclusions are well -developed in the host crystals of the coarse saccharoidal dolostones. Analytical data of Raman spectra show that, among the inclusions, there is a great deal of methane and other organic material, suggesting that the inclusions must have been formed during the dry gas production stage of the organic material evolution in deep burial environments. The lowest homogenization temperature of the inclusion is 104°C (with pressure correction), and the least depth for the inclusion formation corresponding to such a temperature is about 2600m. Hence, it is believed that the coarse saccharoidal dolostones must have been formed in deep burial environments with hot liquid dolomitization. Therefore, the inclusion analyses bring out the conclusion that there are at least two types of dolomitization in the massive dolostones of the Ordovician of the Ordos basin, one of shallow burial with warm liquid, and the other deep with hot liquid.