Multi-stage Hydrocarbon Research Articles

Source identification and accumulation restoration of complex oil reservoirs in Mahu Sag, Junggar Basin

Oil sources and accumulations in complex oil reservoirs of superimposed basins are difficult to identify and recover because of multiple kitchens and multistage charging processes. Constraining the oil sources and characterizing their accumulation patterns is a critical challenge. In this study, 46 crude oils from the Upper Wuerhe Formation, a widely distributed oil reservoir in the Mahu Sag of the Junggar Basin, NW China, are geochemically characterized to assess their sources and spatial distribution. These oils are divided into four groups: group I oils (characterized by high β-carotane and gammacerane concentrations, low C21/C23 and (C19 + C20)/C23 tricyclic terpane ratios, and low Pr/Ph ratios); group II oils (characterized by low β-carotane and gammacerane concentrations, high C21/C23 and (C19 + C20)/C23 tricyclic terpane ratios, and moderate Pr/Ph ratios); group III oils (very high Pr/Ph ratio (>3), the lowest β-carotane and gammacerane concentrations, and low tricyclic terpane concentration, but relatively high C19 and C20 tricyclic terpane abundance); and group IV oils (refered to here as geochemically hybrid, and inferred to be sourced from mixed P1f and C/P1j source rocks). The integration of oil-source correlation and geological framework indicates that oils generated from multiple kitchens are more likely to be near-sourced accumulations, providing a plausible example for oil accumulation in a complex oil reservoir of superimposed basin with several sets of kitchens and multistage oil charging history. The results show that multisource and multistage hydrocarbon accumulation is a common characteristic of prolific superimposed basins. The oil accumulation pattern must be established by carefully characterizing sources and charging processes to reduce the risk of exploration activities.

Revealing continuous hydrocarbon generation and shale oil accumulation of saline lacustrine source rocks by sequential extraction

Saline lacustrine fine-grained rocks are important hydrocarbon source rocks and host large shale oil accumulations worldwide. However, the specific process and mechanism of hydrocarbon generation and accumulation in such rocks are not clear. Sequential extraction is a method to chemically separate different hydrocarbon fractions in sedimentary rocks, commonly as free, adsorbed and retained hydrocarbons, and thus can theoretically record the entire process of hydrocarbon generation and accumulation. To test this hypothesis, here sequential extraction was carried out on source rock samples with varying maturities from the alkaline lacustrine strata of the Lower Permian Fengcheng Formation, Mahu Sag, Junggar Basin, northwest China. The 17β-ethylandrostane/C29-sterane ααα20R and tricyclic terpane/pentacyclic triterpane ratios vary with maturity. In contrast, some biomarker parameters are not significantly affected by thermal maturity, including pristane/phytane, β-carotane index (β-carotane/main peak n-alkane), sterane/hopane, 7-+8-methyl index (7-+8-monomethyl heptadecane/main peak n-alkane), and C28/C29 regular sterane values, and can thus be used for oil–source rock correlations. The low-maturity source rocks have undergone one stage of hydrocarbon generation and associated shale oil accumulation, whereas source rocks with relatively high maturity have experienced multi-stage hydrocarbon generation and associated shale oil accumulation. In the early stages, cyanobacteria were the main bioprecursor to hydrocarbons and, with increasing maturity, Dunaliella gradually became the more important bioprecursor. Hydrocarbon generation by these alkaline lacustrine source rocks involved multiple sources and stages, which accounts for the abundant shale oil resources in the Mahu Sag with one-billion-ton reserves. This might be general for saline lacustrine source rocks worldwide, which can generate both conventional and unconventional hydrocarbons in large scales. Compared with conventional thermal modeling to constrain the generation history of hydrocarbon source rocks, a unique advantage of sequential extraction is its ability to characterize the entire history of hydrocarbon generation under geological conditions.

Multistage Hydrocarbon Generation of Saline Lacustrine Source Rocks in Hydrous Pyrolysis: Insights from Clay Mineral-Organic Matter Interactions.

The organic matter (OM) in shale is closely associated with clay minerals, and its maturation is usually accompanied by the diagenesis of these minerals, especially smectite illitization. However, the effect of mineral transformation and its accompanying change of mineral-OM interactions in shale on hydrocarbon generation is still unclear. To investigate this question, smectite-rich immature shale was selected to carry out hydrous pyrolysis. Organic geochemistry and mineralogy of pyrolysates at different temperatures show that the maturation of OM is accompanied by the transformation of bulk and clay minerals. Based on the change in hydrocarbon yield, Rock-Eval parameters, and mineral composition, hydrocarbon generation in this study is divided into three stages: 25-300, 300-400, and 400-500 °C, which are the result of the synergistic evolution of clay minerals and OM. Multistage hydrocarbon generation can be attributed to the mineral transformation-induced desorption of mineral-bound soluble OM (SOM), decarboxylation and hydrocracking of kerogen promoted by solid acids, and cross-linking and cracking reactions of free SOM and residual kerogen under high temperatures. Although different from the classical hydrocarbon generation model of kerogen, this multistage hydrocarbon generation is consistent with the characteristics of the saline lacustrine source rocks in nature. The mineral transformation-induced desorption of SOM is a new pathway for petroleum formation, which can well explain the formation of low-mature oils in nature. In addition, the release of mineral-bound and kerogen-bound biomarkers results in two reversals of isomerization ratios. Considering mineral transformation and mineral-OM interactions can help us better understand and refine the hydrocarbon generation theory of OM.

Influence of heterogeneity on fluid property variations in carbonate reservoirs with multistage hydrocarbon accumulation: A case study of the Khasib formation, Cretaceous, AB oilfield, southern Iraq

Abstract The fluid distribution is considerably influenced by the reservoir homogeneity. This study analyzes carbonate reservoir heterogeneity and hydrocarbon accumulation processes in the Khasib reservoirs in AB oilfield in the Middle East to discuss factors controlling the distribution of fluid and the effects of this distribution on the productivity of single wells. The Khasib reservoirs in the AB oilfield show uniform vertical distributions, with a large difference in the longitudinal pore throats, and the upper part of the reservoir is better than the lower one. Because the hydrocarbon accumulation is multiphasic, the heterogeneity of crude oil is based on whether traps are formed in the early or late stage of source rock formation during accumulation. Moreover, the longitudinal physical differences in crude oil properties are mainly attributed to the longitudinal differences in the pore throats. The difference in the pore throat and physical properties of crude oil affords differences in the productivity of horizontal wells in different subzones.

Features of the Early Hydrocarbon Accumulation and Its Effects on the Late Accumulation in Sandstone Reservoir: A Case Study of the Eocene Dongying Depression, Bohai Bay Basin

Multi-stage hydrocarbon generation and accumulation are very common in petroliferous basins. Also, determination of hydrocarbon accumulation stages and each related diagenetic feature is important for understanding the distribution of current oil and gas resources in one individual basin. However, in the case of conventional sandstone reservoirs, few studies have focused on these resulting reservoir features (e.g., physical property and wettability) that are caused by the first accumulation of hydrocarbons and their geological implications. In this study, taking the reservoir from the Eocene Dongying Depression as an example, we investigated the features of the early hydrocarbon accumulation and its effects on the late accumulation, by analyzing the early accumulation-related paragenesis, fluid inclusions, clay minerals content, reservoir physical property, and wettability in sandstones. Our results show that the early stage accumulation of the overpressured hydrocarbon fluid could support and offset some loads of overburden, weaken the normal compaction, and preserve some original pores. Also, the early hydrocarbon accumulation resulted in an alternated, diagenetic fluid environment from the initial acidic to subsequent alkalic conditions, with the overall dissolution intensity stronger than the cementation, and formed a large number of secondary pores. As a result, the early accumulation was beneficial to reservoir space development and provided more space for the late hydrocarbons. In addition, the early hydrocarbon accumulation could cause the alteration of rock wettability and gradually formed a lipophilic migration pathway from the source rock to the reservoir. Also, the late stage of hydrocarbons would preferentially choose this dominant pathway for their migration (i.e., inheritance of migration pathway).

Multi-stage hydrocarbon migration and accumulation of Permian petroleum system in the Zaysan Basin, NE Kazakhstan

The Zaysan Basin in northeastern Kazakhstan is a petroliferous basin that closely correlates with the Central Asian Orogenic Belt (CAOB). The basin is characterized by multi-stage hydrocarbon migration and accumulation, while the details are poorly understood. Hydrocarbon accumulation processes were investigated within the constraints of the regional tectonic evolution and the timing of trap formation. Along with assessment of geochemical characteristics, hydrocarbon generation and accumulation models were established. Light blue-green fluorescence colours of intergranular oil were identified for the deep Permian and Jurassic reservoirs, but they were absent within the shallow Paleogene Severozagsan reservoirs. Geochemical results indicate that source rocks for the oils were deposited in anoxic brackish-saline environments, and mainly contain type I and type II kerogen. Oil and extracted bitumen from the Permian and Jurassic reservoirs originate from the same Permian source rocks and show low maturity. The biodegradation of oils within the Permian and Jurassic reservoirs, however, indicates different alteration processes. Paleogene gas is the biodegradation product of the oils. In the study area, two stages of oil charge and one stage of gas charge were identified. The first oil charge began about 207 Ma (Late Triassic) when the source rock entered the oil window. The oil migrated into the Permian reservoirs and subsequently underwent biodegradation. The second oil charge took place about 70–100 Ma and was controlled by Late Cretaceous cooling and exhumation events. Oil in the Jurassic reservoir originated by oil remigration from the Permian reservoir. The gas charge occurred during the Late Cenozoic. The gas was mainly the biodegradation of oils and accumulated in Paleogene reservoirs.

Multi-Stage Hydrocarbon Generation Model of Saline Lacustrine Source Rocks: Insights from Hydrous Pyrolysis Based on Clay Mineral-Organic Matter Interactions

Multi-Stage Hydrocarbon Generation Model of Saline Lacustrine Source Rocks: Insights from Hydrous Pyrolysis Based on Clay Mineral-Organic Matter Interactions

Controlling factors of hydrocarbon accumulation and differential distribution in the western Qaidam Basin, Tibet Plateau

Hydrocarbon distribution in the western Qaidam Basin is complex and characterised by large reserves, dispersed distribution, local enrichment, and multi-layer accumulation. Near the Altyn Tagh Ranges, the traps are mainly oil-filled, whereas far away and near the basin centre, they are gas-filled. With hydrocarbon distribution in the western Qaidam Basin poorly understood, the tectonic evolution, source-rock thermal evolution and space–time configurations were studied using burial history, strata thickness, source-rock generation and expulsion processes, and trap formation. Mode 1 system was characterised by continuous hydrocarbon accumulation, rapid source-rock burial and trap formation early in the basin history resulting in early generation and trapping of low maturity oil and later generation of high maturity oil. Mode 2 was characterised by mid-section hydrocarbon accumulation, steady source-rock burial velocity and trap formation with the traps filled by mature oil and small amounts of gas. Mode 3 was characterised by tail hydrocarbon accumulation, rapid source-rock burial and trap formation late in basin development resulting in traps filled with high-maturity gas. In the Mesozoic–Cenozoic petroleum system, such as the Dina2 condensate gas field, hydrocarbon accumulation was earlier than in the Yingxi Shizigou oilfield belonging to the Cenozoic petroleum system, which was mainly controlled by tectonic evolution and source-rock thermal evolution. The well-matching relationships between hydrocarbon generation–expulsion time and trap formation may create a giant oilfield, an earlier formed trap, later matured source rock and good preservation leading to continuous accumulation of hydrocarbon favourable for exploration. Key points In the western Qaidam Basin, hydrocarbon differential distribution was mainly controlled by source-rock burial history, stratigraphic thickness and trap formation processes. Multi-stage hydrocarbon accumulation characteristics are classified into three modes according to the thermal evolution stage of the source rock. A comparison of hydrocarbon accumulation processes between the Yingxi oilfield in the western Qaidam Basin and Dina 2 gas fields in the Kuqa foreland basin allowed hydrocarbon accumulation modes to be determined.

Petroleum migration and accumulation: Modeling and applications

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.

New insights into marine hydrocarbon geological conditions in the South Yellow Sea Basin: evidence from borehole CSDP-2

The South Yellow Sea Basin (SYSB) has multiple sets of proven source rocks and good hydrocarbon prospects, but no industrial oil and gas has been explored at present. To solve this puzzle for petroleum geologists, we systematically investigated the marine hydrocarbon geological conditions based on cores and testing data from borehole CSDP-2, the first exploration well with continuous coring in SYSB. The qualities of source rocks are evaluated in detail according to organic matter abundance, type, and maturity. The reservoir characterization mainly includes porosity, permeability, and reservoir space. Displacement pressure test and stratum thickness are the main foundations for defining the caprocks. Then, the oil-source rock correlation in the Permian and stratum model are analyzed to determine the favorable source-reservoir-caprock assemblages. The results show that three sets of effective source rocks (the Lower Triassic, Upper Permian, and Lower Permian), two sets of tight sandstone reservoirs (the Upper Permian and Lower Silurian-Upper Devonian), and two sets of caprocks (the Lower Triassic and Carboniferous) combine to constitute the hydrocarbon reservoir-forming assemblages of “lower-generation and upper-accumulation” and “self-generation and self-accumulation”, thus laying a solid foundation for promising petroleum prospects. The three sets of marine source rocks are characterized by successive generation and expulsion stages, which guarantees multistage hydrocarbon accumulation. Another three sets of continental source rocks distributed across the Middle Jurassic, Upper Cretaceous, and Paleogene depression areas, especially in the Northern Depression, may supplement some hydrocarbons for the Central Uplift through faults and the Indosinian unconformity. The favorable Permian exploration strata have been identified in the Central Uplift of SYSB. First, the Lower Permian and Upper Permian source rocks with high organic matter abundance and high thermal maturity supply sufficient hydrocarbons. Secondly, the interbedding relationship between the source rocks and sandstones in the Upper Permian strata ensures that hydrocarbons have been migrated into the nearby Upper Permian sandstones, reflecting near-source hydrocarbon accumulation. Finally, the good sealing property of the Lower Triassic Qinglong Formation caprocks plays an indispensable role in hydrocarbon preservation of the Permian reservoirs. This conclusion is supported by direct oil shows, gas logging anomalous layers, and hydrocarbon-bearing fluid inclusions.

Reservoir characteristics and multi-stage hydrocarbon accumulation of the Upper Triassic Yanchang Formation in the southwestern Ordos Basin, NW China

The Chang-8 and Chang-6 members of the Upper Triassic Yanchang Formation (lower part) are regarded as the main oil producing members of the Ordos Basin. Recently, new hydrocarbon discoveries have been made in the upper part of the Yanchang Formation (e.g., Chang-3) in the southwestern Ordos Basin, implying that this interval also has a good potential for hydrocarbon exploration. However, studies on the origin of the high-quality reservoir, hydrocarbon migration, and accumulation patterns remain insufficient. In this study, integrated petrological, mineralogical, and fluid inclusion tests are employed to evaluate reservoir characteristics, and reconstruct the history of hydrocarbon migration and accumulation during oil and gas reservoir formation. The results reveal that the Yanchang Formation is characterized by low porosity (8 − 14%), medium permeability (0.5 − 5 mD), and strong heterogeneity; the reservoir properties are controlled by secondary porosity. Two types of dissolution are recognized in the present study. Secondary pore formation in the lower part of the formation is related to organic acid activity, while dissolution in the upper part is mainly influenced by atmospheric fresh water associated with the unconformity surface. The Yanchang Formation underwent hydrocarbon charging in three phases: the early Early Cretaceous, late Early Cretaceous, and middle Late Cretaceous. A model for hydrocarbon migration and accumulation in the Yanchang reservoirs was established based on the basin evolution. We suggest that hydrocarbon accumulation occurred at the early stage, and that hydrocarbons migrated into the upper part of the Yanchang Formation by way of tectonic fractures and overpressure caused by continuous and episodic hydrocarbon expulsion during secondary migration, forming potential oil reservoirs during the later stage.

Statistical evaluation and calibration of model predictions of the oil and gas field distributions in superimposed basins: A case study of the Cambrian Longwangmiao Formation in the Sichuan Basin, China

Abstract Superimposed basins are commonly characterized by a complex distribution of oil and gas accumulations. Because they have generally experienced multistage hydrocarbon accumulation and tectonic movement, it is challenging to predict favorable exploration zones in these basins. The exploration of the deep strata of the Sichuan Basin (i.e., a typical superimposed basin), West China, has been unsatisfactory for petroleum prospectors. Therefore, we chose the Cambrian Longwangmiao Formation in the Sichuan Basin as an example to demonstrate the method, i.e., combination of petroleum system elements to quantitatively predict the petroleum favorable exploration zones. Based on the detailed analysis of the hydrocarbon accumulation process, the source rock (S), migration (M), reservoir depositional facies (D), and regional cap rock (C) are the most important elements controlling the formation and distribution of oil and gas accumulations in the studied basin. By studying the functional relationships among these four elements and the distribution of the petroleum accumulations, we determined the accumulation probability related to each element and quantitatively predicted the probability of a favorable hydrocarbon accumulation zone. We built a quantitative model of the reservoir preservation probability based on the statistical relationship between the intensity of the tectonic movement and subsequent destruction of existing oil and gas accumulations. Favorable exploration zones can be determined by overlaying favorable accumulation zones with disturbances associated with the tectonic evolution. The results suggest that the most favorable exploration zones of the Longwangmiao Formation in the Sichuan Basin are distributed in the regions west of Weiyuan and east of Gaoshiti–Moxi, Pengxi–Yilong, and Dazhou–Kaijiang. The production data for existing fields in the Sichuan Basin show that 87% of the successful wells are in the predicted favorable exploration zones and that the success rate with respect to the prediction of failure wells is 67%. This approach highlights the most prospective exploration areas in superimposed basins, which, in general, is challenging and complex for traditional basin modeling tools.

Characteristics and migration mechanisms of natural gas in tight sandstone reservoirs in the Longfengshan sag, Songliao Basin, China

To better understand gas migration and accumulation in tight sandstone reservoirs, we conducted an integrated petrographic and geochemical analysis of hydrocarbon and aqueous fluid inclusions. This analysis was combined with the burial and multistage hydrocarbon charging histories of the reservoir. The variability in the types of hydrocarbon inclusions in the tight sandstone reservoirs can be mapped to identify phase fractionation during burial and migration. The oil-bearing inclusions resulted from the heterogeneous capture of oil generated during the first hydrocarbon charging period, when the sandstones had not yet reached tight reservoir conditions. The gas-bearing inclusions in the tight sandstone reservoirs formed during the phase fractionation of dissolved and free gas due to unstable pressure conditions. The gas-bearing inclusions are characterized by a varying vapor volume fraction (φvap). A higher proportion of gas-bearing inclusions with φvap < 25% was observed near the source rock with TOC content >1.2%. In contrast, in structural highs, a higher proportion of gas-water inclusions with φvap > 25% was observed, demonstrating that phase fractionation occurred during migration. The GOI data suggest that the dissolved gas migration mainly occurred in the reservoir near the source rock with TOC content >1.2%. The subsequent free gas separation in relation to upward migration and strata uplift caused free gas to migrate farther into the tight sandstone reservoir. Additionally, the gases displayed benzene/n-hexane ratio, methane and ethane δ13C values increasing initially, then decreasing along the migration pathway, recording the phase state evolution of the natural gas during the burial history of the reservoirs.

Hydrocarbon preservation conditions in Mesozoic–Paleozoic marine strata in the South Yellow Sea Basin

In the South Yellow Sea Basin, Mesozoic–Paleozoic marine strata are generally well developed with large thickness, and they are characterized by multi-source and multi-stage hydrocarbon accumulation, providing a material basis for the formation of large-scale oil and gas fields. However, no substantial breakthrough has been made in this area. Based on previous research results, the complex tectonic pattern of this superimposed basin was formed by multi-stage tectonic movements and the favorable static conditions for hydrocarbon preservation were reworked or destroyed by later superimposition. Therefore, hydrocarbon preservation conditions are the key factors for restricting the breakthrough of marine oil and gas exploration in this area. In this paper, hydrocarbon preservation conditions of marine strata in the South Yellow Sea Basin were comprehensively analyzed from many aspects, such as tectonic movement, source conditions, caprock characteristics, magmatic activities, and hydrogeological and hydrogeochemical characteristics. It is indicated that the complex tectonic pattern of the South Yellow Sea Basin is resulted from tectonic events in multiple stages, and the development and evolution of regional source rocks are mainly controlled by two stages (i.e., the stable evolution stage of Mesozoic–Paleozoic marine basin and the Mesozoic–Cenozoic tectonic pattern transformation and basin formation stage), so the characteristics of differential oil and gas preservation are presented. Besides, better marine hydrocarbon preservation preconditions in this area are weaker tectonic reworking, development of high-quality thick source rocks, good vertical sealing capacity of caprocks, weaker magmatic activity and confined hydrogeological conditions. It is concluded that the Laoshan Uplift in the central part of the South Yellow Sea Basin is structurally stable with weaker faulting and magmatic activities, so it is better in oil and gas preservation conditions. Besides, several large-scale structural traps with good petroleum geological conditions and complete source–reservoir–caprock assemblages are developed in this area. Therefore, this area is the most promising region for Paleozoic marine oil and gas exploration in this basin.

A comparative study of salient petroleum features of the Proterozoic–Lower Paleozoic succession in major petroliferous basins in the world

The Proterozoic–Lower Paleozoic marine facies successions are developed in more than 20 basins with low exploration degree in the world. Some large-scale carbonate oil and gas fields have been found in the oldest succession in the Tarim Basin, Ordos Basin, Sichuan Basin, Permian Basin, Williston Basin, Michigan Basin, East Siberia Basin, and the Oman Basin. In order to reveal the hydrocarbon enrichment roles in the oldest succession, basin formation and evolution, hydrocarbon accumulation elements, and processes in the eight major basins are studied comparatively. The Williston Basin and Michigan Basin remained as stable cratonic basins after formation in the early Paleozoic, while the others developed into superimposed basins undergone multistage tectonic movements. The eight basins were mainly carbonate deposits in the Proterozoic–early Paleozoic having different sizes, frequent uplift, and subsidence leading to several regional unconformities. The main source rock is shale with total organic carbon content of generally greater than 1% and type I/II organic matters. Various types of reservoirs, such as karst reservoir, dolomite reservoir, reef-beach body reservoirs are developed. The reservoir spaces are mainly intergranular pore, intercrystalline pore, dissolved pore, and fracture. The reservoirs are highly heterogeneous with physical property changing greatly and consist mainly of gypsum-salt and shale cap rocks. The trap types can be divided into structural, stratigraphic, lithological, and complex types. The oil and gas reservoir types are classified according to trap types where the structural reservoirs are mostly developed. Many sets of source rocks are developed in these basins and experienced multistage hydrocarbon generation and expulsion processes. In different basins, the hydrocarbon accumulation processes are different and can be classified into two types, one is the process through multistage hydrocarbon accumulation with multistage adjustment and the other is the process through early hydrocarbon accumulation and late preservation.

Multi-stage hydrocarbon accumulation and formation pressure evolution in Sinian Dengying Formation-Cambrian Longwangmiao Formation, Gaoshiti-Moxi structure, Sichuan Basin

Sichuan Basin is a typical superimposed basin, which experienced multi-phase tectonic movements, meanwhile Sinian–Cambrian underwent complex hydrocarbon accumulation processes, causing exploration difficulties in the past 60 years. Based on the microscopic evidence of fluid inclusions, combined with basin-modelling, this paper determines stages and time of hydrocarbon accumulation, reconstructs evolution of formation pressure and dynamic processes of hydrocarbon accumulation in Sinian Dengying Formation-Cambrian Longwangmiao Formation of Gaoshiti-Moxi structure. Three stages of inclusions are detected, including a stage of yellow-yellowgreen fluorescent oil inclusions, a stage of blue fluorescent oil-gas inclusions and a stage of non-fluorescent gas inclusions, reflecting the study area has experienced a series of complex hydrocarbon accumulation processes, such as formation of paleo-oil reservoirs, cracking of crude oil, formation of paleo-gas reservoirs and adjustment to present gas reservoirs, which occurred during 219–188, 192–146 and 168–0 Ma respectively. During the period of crude oil cracking, Dengying Formation-Longwangmiao Formation showed weak overpressure to overpressure characteristics, then after adjustment of paleo-gas reservoirs to present gas reservoirs, the pressure in Dengying Formation changed into overpressure but finally reduced to normal pressure system. However, due to excellent preservation conditions, the overpressure strength in Longwangmiao Formation only slightly decreased and was still kept to this day.

EXPLORATION OPPORTUNITIES OF THE TECTONICALLY INDUCED MISSISSIPPIAN HYDROTHERMAL DOLOMITE RESERVOIRS IN THE DNIEPER-DONETS BASIN

Exploration for oil and gas in the Lower Carboniferous (Mississippian) Carbonate Platform of Tournaisian - Early Visean age in the Dnieper-Donets basin (DDB) meets in many cases with particular problems caused by lack of detail knowledge about the spatial reservoir morphology and origin of the carbonate reservoirs. Application of the Trenton-Black River exploration play concept based on searching for structurally-controlled hydrothermal dolomite reservoirs (HTD) helps to solve the above task. Complex multistage hydrocarbon prospects in the Tournaisian - Lower Visean carbonate platform combining reservoirs of biohermal/reefal bodies, massive limestones with intense intraformational fracturing (“Mississippi lime” type), clastic and karstified rocks of the erosional residuum at intra-Visean unconformity («Mississippi chat» type), and structurally-controlled hydrothermal dolomites (“Trenton - Black River” type) are indentified in this study and create new promising exploration trend in the DDB. New strategy will shift exploration focus from limited portfolio of anticline and reefal traps to tectonically disturbed peripheral areas and monocline slopes of local depressions in the margin zones of the DDB paleorift thus extending its exploration life.

Effect and quantitative evaluation of CO2 derived from organic matter in coal on the formation of tight sandstone reservoirs

Tight reservoirs are widely distributed, especially in coal measure strata. Identification of the densification mechanism of the tight sandstone reservoirs is critical in effectively exploring and exploiting tight gas/oil resources. In this study, the gas formation from type III organic matter in coal was kinetically modeled for the whole diagenetic stage, from the shallow buried biogas generation stage to the deep buried thermal gas generation stage. The results demonstrated that during hydrocarbon formation, quantities of non-hydrocarbon gases, such as CO2, were generated. The proportion of CO2 is about 50%–70% of that of the C1–5, which far exceeds the CO2 content (0–5%) in the natural gas in the sedimentary basins. Geological case study analysis showed that a considerable part of the “lost” gaseous CO2 was converted into carbonate cement under favorable environments. Under the ideal conditions, the volume of the carbonate cement transformed from total CO2 generated by 1 m3 coal (Junggar Basin Jurassic, TOC 67%) can amount to 0.32 m3. Obviously, this process plays a very important role in the formation of tight sandstone reservoirs in the coal measures. Our results also show that the kinetic generation processes of C1–5 and CO2 are asynchronous. There are two main stages of CO2 generation, one at the weak diagenetic stage and the other at the over-mature stage, which are different from large-scale multi-stage hydrocarbon gas generation. Therefore, we can understand the mechanism of tight gas charging by determining the filling time for a tight gas reservoir and the key period of CO2 generation. Further analysis and correlation studies of a specific region are of great significance for determining the mechanism and modeling gas charging in tight reservoirs. It should be noted that the formation of tight sandstone reservoirs is the combined result of complex organic-inorganic and water-rock-hydrocarbon interactions. The details of spatial and temporal distributions of the carbonate cement derived from the organic CO2, which combines with metal ions (Ca/Mg/Fe) in the formation water, should be further investigated.

Palaeo-fluid evidence of the multi-stage hydrocarbon charges in Kela-2 gas field, Kuqa foreland basin, Tarim Basin

Abstract The multi-stage hydrocarbon charge process of Kela-2 gas field in the Kuqa foreland basin was studied from the perspective of palaeo-fluid evidence by the analyses of fluid inclusions, fluorescence spectroscopy, FE-SEM (field emission scanning electron microscopy) observation, core micro-CT scanning, and hydrocarbon geochemistry. The result shows that the Kela-2 gas field has experienced three periods of hydrocarbon charge process: (1) charged with oil at the early-middle period of the Miocence (N 1 ), (2) charged with high maturity oil & gas at the sedimentary period of the Pliocence Kuqa Formation (N 2 ) and then destroyed by intense tectonic compression, and (3) charged with high- and over-maturity coal-derived gas since the Quaternary. The widely distributed residual dry bitumen, the occurrence of gas-liquid two-phase hydrocarbon inclusions, the residual oils observed in the nanopores, the higher QGF and QGF-E index, and the higher S 1 , S 2 values of rock pyrolysis detected in both current gas zone and water zone, are the evidence of early oil charges. The residual dry bitumen, the occurrence of gas-oil-solid (bitumen) three-phase hydrocarbon inclusions, the loss of light n-alkanes and the relatively high content of aromatic hydrocarbons in the condense oil, and the abnormally high content of diamondoid hydrocarbons, are the strong evidence of gas flushing and deasphalting.

Petroleum System and Hydrocarbon Accumulation Characteristics in the Wenchang and Enping Formations in the Huizhou Sag, Pearl River Mouth Basin, China

Conventional oil and gas reservoirs are in the Oligocene and later formations in the Huizhou Sag, Pearl River Mouth Basin, South China, and oil &amp; gas were generated by the source rocks in the Eocene Wenchang and Eocene-Oligocene Enping Formations. However, exploration paradigm shift has been made in the Sag with the depletion of conventional reservoirs and recent oil and gas discoveries in the Wenchang and Enping Formations, and Wenchang and Enping become the new targets of exploration. With more detailed researches to evaluate the exploration potential in the two conventional source rock formations, basic factors of the petroleum system are analyzed based on seismic data, well drilling, and lab measurements. We used sequence stratigraphy and statistics to research thickness trend of source rock. Different from discontinuous distribution of lake basin during the Wenchang formation deposition suggested by predecessors, as the major source rock in the Wenchang Formation, SQ2 whose dominant facies are deep lakes and shallow lakes is present widely with thickness varies from 200 meters to 1000 meters, and the thickest source rocks locate in the Huixi, Luxi and Huidong half-grabens. Both the Wenchang and Enping formations contain multiple source rock-reservoirseal combinations. We conduct a detailed study on the petroleum system in the deeper reservoir-cap combinations in the Huizhou Sag. The study results in the hydrocarbon generation and migration timing. Reservoirs are classified based on the multi-stage structural movements and multi-stage hydrocarbon generations. We address the controlling effect of the structure evolution on hydrocarbon accumulation. Finally, we build a relationship between reservoir quality and structural units in the study area, and helps reduce the risks of the exploration and production in the Huizhou Sag.