Formation and characteristics of large-medium buried-hill hydrocarbon reservoirs in Bohai Sea

There had been a long history of the buried-hill hydrocarbon reservoirs exploration operation in Bohai Sea.Between 1970s and 1990s,based on the onshore exploration experiences in eastern China,many boreholes were drilled in order to detect large-scale carbonate buried-hill hydrocarbon reservoirs in Bohai Sea,but no prominent discoveries was achieved.In-depth re-evaluation and examination were conducted upon these exploration failures,a new understanding that Bohai Sea had unique geological characteristics of buried hills was concluded.Bedrocks on the uplifts of Bohai oil province were mainly granites and migmatitic granites of Archean,Proterozoic and Mesozoic,as well as minor Lower Paleozoic carbonates.Proterozoic algae dolomite was most favorable for buried-hill hydrocarbon reservoirs however which were not developed in Bohai Sea.A large number of faults in Bohai oil province were developed and faults activities were intense in the late period.Thus,conventionally,reservoirs and preservation conditions of the buried hills were believed to be poor in Bohai Sea,and were not favourable for formation of large-scale buried-hill hydrocarbon reservoirs.Through the long-term practices and deep analyses,the coupling between granites,migmatitic granites and intense bedrock faults was favorable for buried-hill reservoirs with high test production and relatively low core recovery rate.Geophysical data could be used for accurate predictions of bedrock lithology and faults.The monadnock buried hills on the low uplifts adjacent to hydrocarbon-rich sags were covered by shallow to semi-deep lacustrine shale,which was favorable for buried-hill hydrocarbon reservoirs.Under the guidance of a series of innovative understandings,the re-exploration of buried hills in Bohai Sea achieved two largest granite buried-hill oil and gas fields with 100 million tons of reserves.The understanding and practice processes might also inspire exploration of other areas.

Geologic Characteristics of Volcanic Hydrocarbon Reservoirs and Exploration Directions in China

Volcanic rocks are distributed widely in China, which are important exploration targets. By analyzing many discovered volcanic hydrocarbon reservoirs all over the world, the authors summarized the geologic characteristics of the formation of volcanic hydrocarbon reservoirs in China, and gave further exploration directions and advices. （1） There are mainly Carboniferous-Permian, Jurassic-Cretaceous, Paleogene-Neogene volcanic rocks in oil- and gas-bearing basins in China, which are mainly distributed in the Junggar Basin, Songliao Basin, Bohai Bay Basin, etc. There are mainly intermediate rocks and acidic rocks in east China, and intermediate rocks and basic rocks in west China. They primarily develop in intracontinentai rift settings and island arc environments. （2） Porefissure reservoirs are distributed widely in basins, which are volcanic rocks mainly in explosive and effusive facies. （3） Volcanic hydrocarbon reservoirs are chiefly near-source lithostratigraphic hydrocarbon reservoirs, and the oil and gas accumulation is predominantly controlled by lithotypes, faults and structural positions. （4） Deep-seated oil and gas reservoirs in the Songliao Basin and Carboniferous volcanic hydrocarbon reservoirs in the Junggar Basin are potential giant volcanic gas provinces, the volcanic hydrocarbon reservoirs in the Bohai Bay Basin and Santanghu Basin are favorable for oil and gas reserves increase, and volcanic rocks in the Turpan Basin, Sichuan Basin, Tarim Basin have exploration potentiality. （5） The technology series of oil and gas exploration in volcanic rocks have been preliminarily formed.

A unified model for the formation and distribution of both conventional and unconventional hydrocarbon reservoirs

The discovery and large-scale exploration of unconventional oil/gas resources since 1980s have been considered as the most important advancement in the history of petroleum geology;that has not only changed the balance of supply and demand in the global energy market,but also improved our understanding of the formation mechanisms and distribution characteristics of oil/gas reservoirs.However,what is the difference of conventional and unconventional resources and why they always related to each other in petroliferous basins is not clear.As the differences and correlations between unconventional and conventional resources are complex challenging issues and very critical for resources assessment and hydrocarbon exploration,this paper focused on studying the relationship of formations and distributions among different oil/gas reservoirs.Drilling results of 12,237 exploratory wells in 6 representative petroliferous basins of China and distribution characteristics for 52,926 oil/gas accumulations over the world were applied to clarify the formation conditions and genetic relations of different oil/gas reservoirs in a petroliferous basin,and then to establish a unified model to address the differences and correlations of conventional and unconventional reservoirs.In this model,conventional reservoirs formed in free hydrocarbon dynamic field with high porosity and permeability located above the boundary of hydrocarbon buoyancy-driven accumulation depth limit.Unconventional tight reservoirs formed in confined hydrocarbon dynamic field with low porosity and permeability located between hydrocarbon buoyancy-driven accumulation depth limit and hydrocarbon accumulation depth limit.Shale oil/gas reservoirs formed in the bound hydrocarbon dynamic field with low porosity and ultra-low permeability within the source rock layers.More than 75%of proved reserves around the world are discovered in the free hydrocarbon dynamic field,which is estimated to contain only 10%of originally generated hydrocarbons.Most of undiscovered resources distributed in the confined hydrocarbon dynamic field and the bound hydrocarbon dynamic field,which contains 90%of original generated hydrocarbons,implying a reasonable and promising area for future hydrocarbon explorations.The buried depths of hydrocarbon dynamic fields become shallow with the increase of heat flow,and the remaining oil/gas resources mainly exist in the deep area of“cold basin”with low geothermal gradient.Lithology changing in the hydrocarbon dynamic field causes local anomalies in the oil/gas dynamic mechanism,leading to the local formation of unconventional hydrocarbon reservoirs in the free hydrocarbon dynamic field or the occurrence of oil/gas enrichment sweet points with high porosity and permeability in the confined hydrocarbon dynamic field.The tectonic movements destroy the medium conditions and oil/gas components,which leads to the transformation of conventional oil/gas reservoirs formed in free hydrocarbon dynamic field to unconventional ones or unconventional ones formed in confined and bound hydrocarbon dynamic fields to conventional ones.

K-Ar Dating of Authigenic Illites and Its Applications to the Study of Hydrocarbon Charging Histories of Typical Sandstone Reservoirs in Tarim Basin, China

The Tarim Basin in China comprises eight sets of sandstone reservoirs, five of which are investigated in detail in this study. The main purpose of this study is to investigate the hydrocarbon charging histories of reservoirs by applying K-Ar dating of authigenic illites. The ages of authigenic illites from the Lower Silurian bituminous sandstones in the Central Uplift area range from 383.5 to 235.2 Ma, suggesting that the Silurian oil accumulations were formed from the late Caledonian till the late Hercynian. The ages of authigenic illites from the Upper Devonian Donghe Sandstone reservoirs range from 263.8 to 231.3 Ma, indicating that hydrocarbon accumulations within the Donghe sandstone were formed mainly in the late Hercynian. The authigenic illites ages from the Lower Jurassic Yangxia Group sandstones in the Yinan-2 gas reservoir (Yinan-2, Kuqa Depression) range from 28.1 to 23.9 Ma, suggesting that the initial hydrocarbon charging occurred in the Miocene. The ages of the authigenic illites from the Lower Cretaceous sandstones in the Akemomu gas field (Ake-1, Kashi Sag, Southwest Depression) range from 22.6 to 18.8 Ma, indicating a probable early oil accumulation or early migration of hydrocarbon within this area. The illites from the Paleogene sandstones in the Dina-2 gas reservoir (Dina-201, Kuqa Depression) have a detrital origin; they cannot be used to study the hydrocarbon charging histories. The ages of authigenic illites in the underlying Cretaceous sandstones in the same well (Dina-201) range from 25.5 to 15.5 Ma, indicating that hydrocarbon charging in this reservoir probably occurred within the Miocene. This study highlights the potential of applying K-Ar dating of authigenic illites to investigate the timing of hydrocarbon charging histories of the Tarim Basin reservoir sandstones.

Ordovician Basement Hydrocarbon Reservoirs in the Tarim Basin, China

Ordovician marine carbonate basement traps are widely developed in the paleo-highs and paleo-slopes in the Tarim Basin. Reservoirs are mainly altered pore-cavity-fissure reservoirs. Oil sources are marine carbonate rocks of the Lower Paleozoic. Thus, the paleo-highs and paleo-slopes have good reservoiring conditions and they are the main areas to explore giant and large-scale oil reservoirs. The main factors for their reservoiring are: (1) Effective combination of fenestral pore-cavity-fracture reservoirs, resulting from multi-stage, multi-cyclic karstification (paleo-hypergene and deep buried) and fracturing, with effective overlying seals, especially mudstone and gypsum mudstone in the Carboniferous Bachu Formation, is essential to hydrocarbon reservoiring and high and stable production; (2) Long-term inherited large rises and multi-stage fracture systems confine the development range of karst reservoirs and control hydrocarbon migration, accumulation and reservoiring; (3) Long-term multi-source hydrocarbon supply, early reservoiring alteration and late charging adjustment are important reservoiring mechanisms and determine the resource structure and oil and gas properties. Favorable areas for exploration of Ordovician carbonate basement hydrocarbon reservoirs in the Tarim Basin are the Akekule rise, Katahe uplift, Hetianhe paleo-high and Yakela faulted rise.

Alteration and Reformation of Hydrocarbon Reservoirs and Prediction of Remaining Potential Resources in Superimposed Basins

Complex hydrocarbon reservoirs developed widely in the superimposed basins of China formed from multiple structural alterations, reformation and destruction of hydrocarbon reservoirs formed at early stages. They are characterized currently by trap adjustment, component variation, phase conversion, and scale reformation. This is significant for guiding current hydrocarbon exploration by revealing evolution mechanisms after hydrocarbon reservoir formation and for predicting remaining potential resources. Based on the analysis of a number of complex hydrocarbon reservoirs, there are four geologic features controlling the degree of destruction of hydrocarbon reservoirs formed at early stages： tectonic event intensity, frequency, time and caprock sealing for oil and gas during tectonic evolution. Research shows that the larger the tectonic event intensity, the more frequent the tectonic event, the later the last tectonic event, the weaker the caprock sealing for oil and gas, and the greater the volume of destroyed hydrocarbons in the early stages. Based on research on the main controlling factors of hydrocarbon reservoir destruction mechanisms, a geological model of tectonic superimposition and a mathematical model evaluating potential remaining complex hydrocarbon reservoirs have been established. The predication method and technical procedures were applied in the Tazhong area of Tarim Basin, where four stages of hydrocarbon accumulation and three stages of hydrocarbon alteration occurred. Geohistorical hydrocarbon accumulation reached 3.184 billion tons, of which 1.271 billion tons were destroyed. The total volume of remaining resources available for exploration is -1.9 billion tons.

Controlling effects of the Ordovician carbonate pore structure on hydrocarbon reservoirs in the Tarim Basin, China

The Ordovician carbonate reservoirs in the Tarim Basin with secondary dissolution pores and vugs have complicated pore structures. The weathering crust reservoirs mainly consist of large cavities or vugs connected by fractures, but most of the reef-shoal reservoirs have complex and small throats among matrix pores. The pore structure can be divided into four types： big pore and big throat, big pore but small throat, small pore and small throat, and fracture type. Most of the average throat radius falls between 0.03 and 0.07μm, close to that of unconventional reservoirs except in local areas with developed fractures. Fluid driving force analysis shows that the differentiation of fluid is mainly controlled by the throat radius in two kinds of mechanism separated by the critical throat radius about 0.1 μm. There is obvious fluid differentiation and oil/gas/water contact in fracture-cavity reservoirs with big throats. However, most of reservoirs under the critical throat radius have high capillary pressure, which resulted in incomplete differentiation of gas/oil/water, and complicated fluid distribution and fluid properties in the unconventional reservoirs.

Pre-Drilling Prediction Techniques on the High-Temperature High-Pressure Hydrocarbon Reservoirs Offshore Hainan Island,China

Decreasing the risks and geohazards associated with drilling engineering in high-temperature high-pressure(HTHP) geologic settings begins with the implementation of pre-drilling prediction techniques(PPTs). To improve the accuracy of geopressure prediction in HTHP hydrocarbon reservoirs offshore Hainan Island, we made a comprehensive summary of current PPTs to identify existing problems and challenges by analyzing the global distribution of HTHP hydrocarbon reservoirs, the research status of PPTs, and the geologic setting and its HTHP formation mechanism. Our research results indicate that the HTHP formation mechanism in the study area is caused by multiple factors, including rapid loading, diapir intrusions, hydrocarbon generation, and the thermal expansion of pore fluids. Due to this multi-factor interaction, a cloud of HTHP hydrocarbon reservoirs has developed in the Ying-Qiong Basin, but only traditional PPTs have been implemented, based on the assumption of conditions that do not conform to the actual geologic environment, e.g., Bellotti's law and Eaton's law. In this paper, we focus on these issues, identify some challenges and solutions, and call for further PPT research to address the drawbacks of previous works and meet the challenges associated with the deepwater technology gap. In this way, we hope to contribute to the improved accuracy of geopressure prediction prior to drilling and provide support for future HTHP drilling offshore Hainan Island.

A method for evaluating paleo hydrocarbon pools and predicting secondary reservoirs:a case study of the Sangonghe Formation in the Mosuowan area,Junggar Basin

Taking the Jurassic Sangonghe Formation in the Mosuowan-Mobei area of the Junggar Basin as an example, this paper provides a method that evaluates paleo hydrocarbon pools and predicts secondary reservoirs. Through Quantitative Grain Fluorescence （QGF） experiments, well-tie seismic correlation, and paleo structure analysis, the scale and distribution of paleo hydrocarbon pools in the study area are outlined. Combining current structural features and fault characteristics, the re-migration pathways of paleo oil and gas are depicted. Based on barrier conditions on the oil re-migration pathways and current reservoir distribution, we recognize three types of secondary reservoirs. By analyzing structural evolution and sand body-fault distribution, the major control factors of secondary reservoirs are specified and, consequently, favorable zones for secondary reservoirs are predicted. The results are mainly as follows. （1） In the primary accumulation period in the Cretaceous, paleo hydrocarbon pools were formed in the Sangonghe Formation of the Mosuowan uplift and their size and distribution were extensive and the exploration potential for secondary reservoirs should not be ignored. Besides, paleo reservoirs were also formed in the Mobei uplift, but just small scale. （2） In the adjustment period in the Neogene, traps were reshaped or destroyed and so were the paleo reservoirs, resulting in oil release. The released oil migrated linearly northward along the structural highs of the Mobei uplift and the Qianshao low-relief uplift and then formed secondary reservoirs when it met new traps. In this process, a structural ridge cooperated with sand bodies and faults, applying unobstructed pathways for oil and gas re-migration. （3） The secondary hydrocarbon pools are classified into three types： low-relief anticlinal type, lithologic pinch-out type and fault block type. The distribution of the first type is controlled by a residual low uplift in the north flank of the paleo-anticline. The second type is distributed in the lithologic pinch-out zones on the periphery of the inherited paleo uplift. The third type is controlled by fault zones of which the strikes are perpendicular to the hydrocarbon re-migration pathways. （4） Four favorable zones for secondary reservoirs are predicted： the low-relief structural zone of the north flank of the Mosuowan paleo-anticline, the fault barrier zone on the western flank of the Mobei uplift, the Qianshao low-relief uplift and the north area of the Mobei uplift that parallels the fault zone. The study above effectively supports the exploration of the Qianshao low-relief uplift, with commercial oil discovered in the Qianshaol well. Besides, the research process in this paper can also be applied to other basins to explore for secondary reservoirs.

Experimental Investigation on Condensate Revaporization During Gas Injection Development in Fractured Gas Condensate Reservoirs

The gas field in the Bohai Bay Basin is a fractured metamorphic buried-hill reservoir with dual-media characteristics. The retrograde vaporization mechanism observed in this type of gas condensate reservoir differs significantly from that observed in sand gas condensate reservoirs. However, studies on improving the recovery of fractured gas condensate reservoirs are limited;thus, the impact of retrograde vaporization on condensate within fractured metamorphic buried-hill reservoirs remains unclear. To address this gap, a series of gas injection experiments are conducted in pressure-volume-temperature(PVT) cells and long-cores to investigate the retrograde vaporization effect of condensate using different gas injection media in fractured gas condensate reservoirs. We analyze the variation in condensate volume, gas-to-oil ratio, and condensate recovery during gas injection and examine the influence of various gas injection media(CO_(2), N_(2), and dry gas) under different reservoir properties and varying gas injection times. The results demonstrate that the exchange of components between injected gas and condensate significantly influences condensate retrograde vaporization in the formation. Compared with dry gas injection and N_(2) injection,CO_(2) injection exhibits a superior retrograde vaporization effect. At a CO_(2) injection volume of 1 PV, the percentage shrinkage volume of condensate is 13.82%. Additionally, at the maximum retrograde condensation pressure, CO_(2) injection can increase the recovery of condensate by 22.4%. However, the condensate recovery is notably lower in fractured gas condensate reservoirs than in homogeneous reservoirs, owing to the creation of dominant gas channeling by fractures, which leads to decreased condensate recovery. Regarding gas injection timing, the effect of gas injection at reservoir pressure on improving condensate recovery is superior to that of gas injection at the maximum retrograde condensation pressure. This research provides valuable guidance for designing gas injection development plans and dynamic tracking adjustments for fractured gas condensate reservoirs.

Hydrocarbon gas huff-n-puff optimization of multiple horizontal wells with complex fracture networks in the M unconventional reservoir

The oil production of the multi-fractured horizontal wells(MFHWs) declines quickly in unconventional oil reservoirs due to the fast depletion of natural energy. Gas injection has been acknowledged as an effective method to improve oil recovery factor from unconventional oil reservoirs. Hydrocarbon gas huff-n-puff becomes preferable when the CO_(2) source is limited. However, the impact of complex fracture networks and well interference on the EOR performance of multiple MFHWs is still unclear. The optimal gas huff-n-puff parameters are significant for enhancing oil recovery. This work aims to optimize the hydrocarbon gas injection and production parameters for multiple MFHWs with complex fracture networks in unconventional oil reservoirs. Firstly, the numerical model based on unstructured grids is developed to characterize the complex fracture networks and capture the dynamic fracture features.Secondly, the PVT phase behavior simulation was carried out to provide the fluid model for numerical simulation. Thirdly, the optimal parameters for hydrocarbon gas huff-n-puff were obtained. Finally, the dominant factors of hydrocarbon gas huff-n-puff under complex fracture networks are obtained by fuzzy mathematical method. Results reveal that the current pressure of hydrocarbon gas injection can achieve miscible displacement. The optimal injection and production parameters are obtained by single-factor analysis to analyze the effect of individual parameter. Gas injection time is the dominant factor of hydrocarbon gas huff-n-puff in unconventional oil reservoirs with complex fracture networks. This work can offer engineers guidance for hydrocarbon gas huff-n-puff of multiple MFHWs considering the complex fracture networks.

Characteristics of Paleozoic clastic reservoirs and the relationship with hydrocarbon accumulation in the Tazhong area of the Tarim Basin, west China

In order to predict favorable exploration areas of the Paleozoic, Carboniferous and Silurian clastic reservoirs in the Tazhong area of the Tarim Basin, west China, we studied the basic characteristics of Paleozoic clastic reservoirs in the Tazhong area based on a lot of data. Several issues about the hydrocarbon accumulation related to the reservoirs were also discussed. The results were concluded that： the high-value areas of the porosity and permeability of clastic reservoirs were located in the southeast of the Tazhong area; the content of cement （carbonate cement in particular） was the main factor controlling the porosity and permeability of clastic reservoirs; the hydrocarbon distributions of Carboniferous and Silurian clastic reservoirs were closely related to the porosity and permeability; the favorable hydrocarbon accumulation areas of the two sets of strata were located in the southeast of this area, especially in the updip pinch-out area.

Research advances on the mechanisms of reservoir formation and hydrocarbon accumulation and the oil and gas development methods of deep and ultra-deep marine carbonates

Based on the new data of drilling, seismic, logging, test and experiments, the key scientific problems in reservoir formation, hydrocarbon accumulation and efficient oil and gas development methods of deep and ultra-deep marine carbonate strata in the central and western superimposed basin in China have been continuously studied.(1) The fault-controlled carbonate reservoir and the ancient dolomite reservoir are two important types of reservoirs in the deep and ultra-deep marine carbonates. According to the formation origin, the large-scale fault-controlled reservoir can be further divided into three types:fracture-cavity reservoir formed by tectonic rupture, fault and fluid-controlled reservoir, and shoal and mound reservoir modified by fault and fluid. The Sinian microbial dolomites are developed in the aragonite-dolomite sea. The predominant mound-shoal facies, early dolomitization and dissolution, acidic fluid environment, anhydrite capping and overpressure are the key factors for the formation and preservation of high-quality dolomite reservoirs.(2) The organic-rich shale of the marine carbonate strata in the superimposed basins of central and western China are mainly developed in the sedimentary environments of deep-water shelf of passive continental margin and carbonate ramp. The tectonic-thermal system is the important factor controlling the hydrocarbon phase in deep and ultra-deep reservoirs, and the reformed dynamic field controls oil and gas accumulation and distribution in deep and ultra-deep marine carbonates.(3) During the development of high-sulfur gas fields such as Puguang, sulfur precipitation blocks the wellbore. The application of sulfur solvent combined with coiled tubing has a significant effect on removing sulfur blockage. The integrated technology of dual-medium modeling and numerical simulation based on sedimentary simulation can accurately characterize the spatial distribution and changes of the water invasion front.Afterward, water control strategies for the entire life cycle of gas wells are proposed, including flow rate management, water drainage and plugging.(4) In the development of ultra-deep fault-controlled fractured-cavity reservoirs, well production declines rapidly due to the permeability reduction, which is a consequence of reservoir stress-sensitivity. The rapid phase change in condensate gas reservoir and pressure decline significantly affect the recovery of condensate oil. Innovative development methods such as gravity drive through water and natural gas injection, and natural gas drive through top injection and bottom production for ultra-deep fault-controlled condensate gas reservoirs are proposed. By adopting the hierarchical geological modeling and the fluid-solid-thermal coupled numerical simulation, the accuracy of producing performance prediction in oil and gas reservoirs has been effectively improved.

Turbidite Dynamics and Hydrocarbon Reservoir Formation in the Tano Basin: A Coastal West African Perspective

This study examines the turbidite dynamics and hydrocarbon reservoir formation in Ghana’s Tano Basin, which is located in coastal West Africa. Through an exploration of geological processes spanning millions of years, we uncover key factors shaping hydrocarbon accumulation, including source rock richness, temperature, pressure, and geological structures. The research offers valuable insights applicable to exploration, management, and sustainable resource exploitation in coastal West Africa. It facilitates the identification of exploration targets with higher hydrocarbon potential, enables the anticipation of reservoir potential within the Tano Basin, and assists in tailoring exploration and management strategies to specific geological conditions of the Tano Basin. Analysis of fluvial channels sheds light on their impact on landscape formation and hydrocarbon exploration. The investigation into turbidite systems unveils intricate interactions involving tectonics, sea-level fluctuations, and sedimentation patterns, influencing the development of reservoirs. An understanding of sediment transport and depositional settings is essential for efficient reservoir management. Geomorphological features, such as channels, submarine canyons, and distinct channel types, are essential in this situation. A detailed examination of turbidite channel structures, encompassing canyons, channel complexes, convex channels, and U-shaped channels, provides valuable insights and aids in identifying exploration targets like basal lag, channel levees, and lobes. These findings underscore the enduring significance of turbidite systems as conduits for sediment transport, contributing to enhanced reservoir management and efficient hydrocarbon production. The study also highlights how important it is to examine the configuration of sedimentary layers, stacking patterns, and angular laminated facies to identify turbidites, understand reservoir distribution, and improve well design. The dynamic nature of turbidite systems, influenced by basin characteristics such as shape and slope, is highlighted. The research provides valuable insights essential for successful hydrocarbon exploration, reservoir management, and sustainable resource exploitation in coastal West Africa.

Origin, hydrocarbon accumulation and oil-gas enrichment of fault-karst carbonate reservoirs: A case study of Ordovician carbonate reservoirs in South Tahe area of Halahatang oilfield, Tarim Basin

Based on comprehensive analysis of tectonic and fault evolution, core, well logging, seismic, drilling, and production data, the reservoir space characteristic, distribution, origin of fault-karst carbonate reservoir in Yueman block of South Tahe area, Halahatang oilfield, Tarim Basin, were studied systematically. And the regular pattern of hydrocarbon accumulation and enrichment was analyzed systematically based on development practice of the reservoirs. The results show that fault-karst carbonate reservoirs are distributed in the form of "body by body" discontinuously, heterogeneously and irregularly, which are controlled by the development of faults. Three formation models of fault-karst carbonate reservoirs, namely, the models controlled by the main deep-large fault, the secondary fault and the secondary internal fault, are built. The hydrocarbon accumulation and enrichment of fault-karst carbonate reservoirs is controlled by the spatiotemporal matching relation between hydrocarbon generation period and fault activity, and the size and segmentation of fault. The study results can effectively guide the well deployment and help the efficient development of fault-karst carbonate reservoirs of South Tahe area, Halahatang oilfield.

Formation of the primary petroleum reservoir in Wumaying inner buried-hill of Huanghua Depression, Bohai Bay Basin, China

Well Yinggu 1 drilled on the tectonic belt of the Wumaying buried-hill in Huanghua Depression obtained non-H2S high-yield oil and gas flow from the Permian Lower Shihezi Formation sandstone. The oil and gas are derived from the Upper Paleozoic coal source rock, the petroleum reservoir is an inner buried-hill primary oil and gas accumulation, showing a good prospect of the Paleozoic inner buried-hill primary reservoir exploration. The formation and accumulation of the primary petroleum reservoir in the Wumaying inner buried-hill are discussed by studying the primary source conditions, the inner buried-hill reservoir-cap combinations and the hydrocarbon accumulation period. The primary petroleum reservoir has three preponderant characteristics of accumulation: secondary large-scale gas generation of coal source rock, multi reservoir-cap combinations and mainly late hydrocarbon charging, which formed the compound hydrocarbon accumulation of the above-source sandstone and under-source carbonate rock in the Paleozoic inner buried-hill. Along with the Mesozoic and Cenozoic tectonic activities, the formation of the primary reservoir in Wumaying inner buried-hill is characterized by "mixed oil and gas charge in local parts in early stage, adjustment accumulation due to structural high migration in middle stage, and large-scale natural gas charge and compound accumulation in late stage".

Heterogeneity and differential hydrocarbon accumulation model of deep reservoirs in foreland thrust belts: A case study of deep Cretaceous Qingshuihe Formation clastic reservoirs in southern Junggar Basin, NW China

Using the data of drilling, logging, core, experiments and production, the heterogeneity and differential hydrocarbon accumulation model of deep reservoirs in Cretaceous Qingshuihe Formation(K1q) in the western section of the foreland thrust belt in southern Junggar Basin are investigated. The target reservoirs are characterized by superimposition of conglomerates, sandy conglomerates and sandstones, with high content of plastic clasts. The reservoir space is mainly composed of intergranular pores. The reservoirs are overall tight, and the sandy conglomerate has the best physical properties. The coupling of short deep burial period with low paleotemperature gradient and formation overpressure led to the relatively weak diagenetic strength of the reservoirs. Specifically, the sandy conglomerates show relatively low carbonate cementation, low compaction rate and high dissolution porosity. The special stress-strain mechanism of the anticline makes the reservoirs at the top of the anticline turning point more reformed by fractures than those at the limbs, and the formation overpressure makes the fractures in open state. Moreover, the sandy conglomerates have the highest oil saturation. Typical anticline reservoirs are developed in deep part of the thrust belt, but characterized by "big trap with small reservoir". Significantly, the sandy conglomerates at the top of anticline turning point have better quality, lower in-situ stress and higher structural position than those at the limbs,with the internal hydrocarbons most enriched, making them high-yield oil/gas layers. The exponential decline of fractures makes hydrocarbon accumulation difficult in the reservoirs at the limbs. Nonetheless, plane hydrocarbon distribution is more extensive at the gentle limb than the steep limb.

Strike-Slip Faults and Their Control on Differential Hydrocarbon Enrichment in Carbonate Karst Reservoirs: A Case Study of Yingshan Formation on Northern Slope of Tazhong Uplift, Tarim Basin

Objective Oil and gas are abundant in the Ordovician Yingshan Formation carbonate karst reservoirs on the northern slope of Tazhong uplift in the Tarim Basin, and have extremely complicated oil-gas-water distribution, however. The difference in burial depth of the reservoirs between east and west sides is up to 1000 m. Water-bearing formations exist between oil- and gas-bearing formations vertically and water-producing wells are drilled between oil- and gas-producing wells. Macroscopically, oil and gas occur at low positions, while water occurs at high positiona on the northern slope of Tazhong uplift. The mechanism of differential hydrocarbon enrichment in heterogeneous reservoirs is by far not clarified, which has affected the efficient exploration and development of oil and gas fields in this area.

Porosity and Rock-Typing in Hydrocarbon Reservoirs Case Study in Upper Member of Dalan Formation in Kish Gas Field, South of Zagros, Iran

To estimate the volume of oil and gas in the hydrocarbon reservoirs, the rock-typing must be considered. The volume and type of available space in the reservoir rocks (porosity) and the ease of hydrocarbons flow (permeability) are important in the classification of rock-types. In the field study, touching-vug Porosities (intergranular, intercrystalline and brecciate) increase the total porosity and form high quality rock-types, on the other side, separated-vug porosities (such as moldic, intraparticle and vuggy) increase the total porosity but do not play a large role in the production of hydrocarbon. In this paper, based on the SCAL data (Special Core Analysis) and according to amount of irreducible water saturation (Swir) and capillary pressure, the reservoir rocks are divided into 4 classes including Reservoir Rock-Types 1 to Reservoir Rock-Types 4 (RRTs-1 to RRTs-4). By study of the prepared thin sections, we investigated the role of porosity in the rock-typing. Among the rock-types, category 1 is the best type-reservoir and category 4 is non-reservoir. Probably, the latest diagenetic process determines the quality rocks, not sedimentary environments.

Evolution of nC_(16)H_(34)-water-mineral systems in thermal capsules and geological implications for deeply-buried hydrocarbon reservoirs

Organic-inorganic interactions between hydrocarbons and most minerals in deeply buried reservoirs remain unclear.In this study,gold capsules and fused silica capillary capsules(FSCCs)with different com-binations of nC_(16)H_(34),water(distilled water,CaCl_(2) water)and minerals(quartz,feldspar,calcite,kaolinite,smectite,and illite)were heated at 340℃ for 3-10 d,to investigate the evolution and reaction pathways of the organic-inorganic interactions in different hot systems.After heating,minerals exhibited little alteration in the anhydrous systems.Mineral alterations,how-ever,occurred obviously in the hydrous systems.Different inorganic components affected nC_(16)H_(34) degra-dation differently.Overall,water promoted the free-radical thermal-cracking reaction and step oxidation reaction but suppressed the free-radical cross-linking reaction.The impact of CaCl_(2) water on the nC_(16)H_(34) degradation was weaker than the distilled water as high Ca^(2+)concentration suppressed the formation of free radicals.The presence of different waters also affects the impact of different minerals on nC_(16)H_(34) degradation,via its impact on mineral alterations.In the anhydrous nC_(16)H_(34)-mineral systems,calcite and clays catalyzed generation of low-molecular-weight(LMW)alkanes,particularly the clays.Quartz,feldspar,and calcite catalyzed generation of high-molecular-weight(HMW)alkanes and PAHs,whereas clays catalyzed the generation of LMW alkanes and mono-bicyclic aromatic hydrocarbons(M-BAHs).In the hydrous nC_(16)H_(34)-distilled water-mineral systems,all minerals but quartz promoted nC_(16)H_(34) degra-dation to generate more LMW alkanes,less HMW alkanes and PAHs.In the nC_(16)H_(34)-CaCl_(2) water-mineral systems,the promotion impact of minerals was weaker than that in the systems with distilled water.This study demonstrated the generation of different hydrocarbons with different fluorescence colors in the different nC_(16)H_(34)-water-mineral systems after heating for the same time,implying that fluorescence colors need to be interpreted carefully in investigation of hydrocarbon charging histories and oil origins in deeply buried reservoirs.Besides,the organic-inorganic interactions in different nC_(16)H_(34)-water-mineral systems proceeded in different pathways at different rates,which likely led to preservation of liquid hydrocarbons at different depth(temperature).Thus,quantitative investigations of the reaction kinetics in different hydrocarbon-water-rock systems are required to improve the prediction of hydrocar-bon evolution in deeply buried hydrocarbon reservoirs.