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.

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.

Evaluation of Hydrocarbon Reservoir in the “SIMA” Field of Niger Delta Nigeria from Interpretation of 3D Seismic and Petrophysical Log Data

3D seismic and petrophysical log data interpretation of reservoir sands in “SIMA” Field, onshore Niger Delta has been undertaken in this study to ascertain the reservoir characteristics in terms of favourable structural and petrophysical parameters suitable for hydrocarbon accumulation and entrapment in the field. Horizon and fault interpretation were carried out for subsurface structural delineation. In all, seven faults (five normal and two listric faults) were mapped in the seismic section. These faults were major structure building faults corresponding to the growth and antithetic faults in the area within the well control. The antithetic fault trending northwest-southeast and the normal fault trending northeast-southwest on the structural high in the section act as good trapping mechanisms for hydrocarbon accumulations in the reservoir. From the manual and auto-tracking methods applied, several horizons were identified and mapped. The section is characterized by high amplitude with moderate-to-good continuity reflections appearing parallel to sub-parallel, mostly disturbed by some truncations which are more fault related than lithologic heterogeneity. The southwestern part is, however, characterized by low-to-high or variable amplitude reflections with poor-to-low continuity. Normal faults linked to roll-over anticlines were identified. Some fault truncations were observed due to lithologic heterogeneity. The combination of these faults acts as good traps for hydrocarbon accumulations in the reservoir. Reservoir favourable petrophysical qualities, having average NTG, porosity, permeability and water saturation of 5 m, 0.20423, 1128.219 kD and 0.458 respectively.

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.

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.

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.

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.

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.

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.

Petrophysical Analysis of the Mpera Well in the Exploration Block 7, Offshore Tanzania: Implication on Hydrocarbon Reservoir Rock Potential

The present study provides evaluation and estimation of petrophysical parameters and assessment of lithology and their thicknesses in order to characterize present reservoir rocks at Mpera well located in Exploration Block 7, deep offshore Tanzania. To achieve the objectives the wire-line logs, Techlog program was used for assessment, analysis, computation and interpretations of petrophysical parameters and results were integrated through interpretation of well logs. The results from wire-line logs reveal three (3) non hydrocarbon-bearing reservoir rocks i.e., Mpera splay (sandstone), Mpera deep sand 1 (sandstone and limestone) and Mpera deep sand 2 (sandstone and limestone) with gross thickness of 94.335 m, 28.905 m and 12.967 m respectively. The average permeability values of the reservoir rocks were 9.47 mD, 6.45 mD and 4.67 mD, while average porosity values were 14.57%, 17.4% and 16.75%, with average volume of shale 25.7%, 23.5% and 9.7% at Mpera splay, Mpera deep sand 1 and Mpera deep sand 2 respectively. These results signify poor permeability;good porosity and good quality reservoir in terms of volume of shale. Fluid type defined in the reservoirs was basically water. High water saturation (90.6% - 97.7%) in the reservoir zones of the Mpera well indicates that the proportion of void spaces occupied by water is high, thus, indicating less than 10% hydrocarbon saturation. The findings indicate that Mpera well reservoir rocks are of low quality with non-hydrocarbon bearing such that it is not potential for hydrocarbon production.

Hydrocarbon Reservoir Model of Glutenite in the Fourth Member of Shahejie Formation in Northern Dongying Depression

The glutenite in the fourth member of Shahejie Formation(Es^4) in northern Dongying depression straightforwardly penetrated into the muddy bathyal -abyss facies.The conditions of reservoir is very superior:(1) the high quality thick bedded oil source rock is developed very well in the Lijin sag and Minfeng sag of the study area,and it has the higher capability of generating hydrocarbon;(2) the

Possible origin of inert gases in hydrocarbon reservoir pools of the Zindapir Anticlinorium and its surroundings in the Middle Indus Basin, Pakistan

The natural gas in several gas fields in Pakistan is associated with varying percentages of inert gases（e.g.,CO;, N;, and H;S）. The heating capacity of such natural gas is measured in British thermal units（BTU） in Pakistan and is based on the combustion of the natural gases. The study area of this work belongs to the Middle Indus Basin, which also covers some parts of the Sulaiman Foldbelt and the Punjab Platform.Petroleum wells drilled in the study area contain inert gases（mostly CO;and N;） in varying percentages,which decreases the BTU value of sweet gases and the economic value of the gas reserves.Attempts were made to analyze the varying compositions of inert gases（mostly CO;and N;） along the deep-seated basement faults in the Zindapir Anticlinorium, eastern Sulaiman Foldbelt, but no specific relation could be established. Similarly, geothermal gradient zones were identified and the distribution of inert gases in these zones was studied, but even so, no well-established relation could be tracked.However, variations in the amounts of inert gases in the Chiltan Limestone of the Rodho Structure and the Afiband Structure point to the generation of in situ inert gases because both wells were drilled on the same anticlinorium and share the same geology, and possibly, the same source rock. Post-accumulation changes probably play an important role in the generation of in situ inert gases in varying concentrations.H;S is also present in some parts of the Indus Basin. Therefore, a brief discussion about the possible origin of the H;S is also included in this paper.

Evaluation of Hydrocarbon Potential Using AVO Analysis in the FORMAT Field, Niger Delta Basin, Nigeria

The study involved the evaluation of the hydrocarbon potential of FORMAT Field, coastal swamp depobelt Niger delta, Nigeria to obtain a more efficient reservoir characterization and fluid properties identification. Despite advances in seismic data interpretation using traditional 3D seismic data interpretation, obtaining adequate reservoir characteristics at the finest level had proved very challenging with often disappointing results. A method that integrates the amplitude variation with offfset (AVO) analysis is hereby proposed to better illuminate the reservoir. The Hampson Russell 10.3 was used to integrate and study the available seismic and well data. The reservoir of interest was delineated using the available suite of petrophysical data. This was marked by low gamma ray, high resistivity, and low acoustic impedance between a true subsea vertical depth (TVDss) range of 10,350 - 10,450 ft. The AVO fluid substitution yielded a decrease in the density values of pure gas (2.3 - 1.6 g/cc), pure oil (2.3 - 1.8 g/cc) while the Poisson pure brine increased (2.3 to 2.8 g/cc). Result from FORMAT 26 plots yielded a negative intercept and negative gradient at the top and a positive intercept and positive gradient at the Base which conforms to Class III AVO anomaly. FORMAT 30 plots yielded a negative intercept and positive gradient at the top and a positive intercept and negative gradient at the Base which conforms to class IV AVO anomaly. AVO attribute volume slices decreased in the Poisson ratio (0.96 to - 1.0) indicating that the reservoir contains hydrocarbon. The s-wave reflectivity and the product of the intercept and gradient further clarified that there was a Class 3 gas sand in the reservoir and the possibility of a Class 4 gas sand anomaly in that same reservoir.

Identification of hydrovolcanism and its significance for hydrocarbon reservoir assessment: A review

Investigations of modern volcanic eruptions have demonstrated that ancient volcanic eruptions widely involved water,which was thus named as hydrovolcanic eruptions. Hydrovolcanisms are distinctive in many aspects, such as dynamics,eruptive pattern, texture and structure of rock, and vesicularity. First, normal sediments covered directly by volcanic rocks are the indicators of eruption environments. In addition, microfeatures, special structures, lithofacies or facies associations,and geochemical index of volcanic rocks can also provide significant evidences. Moreover, perlitic texture, quenching fragmentation, surface feature, cementation type, vesicularity, and pillow structure, parallel bedding, large-scale low-angle cross-bedding, antidune cross-bedding of pyroclast are keys to indicating hydrovolcanisms. Clearly,these marks are not equally reliable for identifying eruption environments, and most of them are effective and convincible in limited applications only. For explosive eruptions, the most dependable identification marks include quenching textures, vesicularity in pyroclasts and special large-scale cross-bedding. However, for effusive eruptions,useful indicators mainly include pillow structure, peperite and facies associations. Condensation rate of magma,exsolution of volatile affected by eruptive settings and magma—water interaction, and quenching in hydrovolcanisms have an influence on formation and scale of primary pores, fractures and their evolution during diagenetic stage.Therefore, this review provides systematic identification marks for ancient hydrovolcanisms, and promotes understanding of the influence of eruptive environments on hydrocarbon reservoirs of volcanic rocks in oil-gas bearing sedimentary basins.

Whole petroleum system and ordered distribution pattern of conventional and unconventional oil and gas reservoirs

The classical source-to-trap petroleum system concept only considers the migration and accumulation of conventional oil and gas in traps driven dominantly by buoyance in a basin,although revised and improved,even some new concepts as composite petroleum system,total petroleum system,total composite petroleum system,were proposed,but they do not account for the vast unconventional oil and gas reservoirs within the system,which is not formed and distributed in traps dominantly by buoyancedriven.Therefore,the petroleum system concept is no longer adequate in dealing with all the oil and gas accumulations in a basin where significant amount of the unconventional oil and gas resources are present in addition to the conventional oil and gas accumulations.This paper looked into and analyzed the distribution characteristics of conventional and unconventional oil/gas reservoirs and their differences and correlations in petroliferous basins in China and North America,and then proposed whole petroleum system(WPS)concept,the WPS is defined as a natural system that encompasses all the conventional and unconventional oil and gas,reservoirs and resources originated from organic matter in source rocks,the geological elements and processes involving the formation,evolution,and distribution of these oil and gas,reservoirs and resources.It is found in the WPS that there are three kinds of hydrocarbons dynamic fields,three kinds of original hydrocarbons,three kinds of reservoir rocks,and the coupling of these three essential elements lead to the basic ordered distribution model of shale oil/gas reservoirs contacting or interbeded with tight oil/gas reservoirs and separated conventional oil/gas reservoirs from source rocks upward,which is expressed as“S\T-C”.Abnormal conditions lead to other three special ordered distribution models:The first is that with shale oil/gas reservoirs separated from tight oil/gas reservoirs.The second is that with two direction ordered distributions from source upward and downward.The third is with lateral distribution from source outside.

Controlling Factors and Accumulation Model of Hydrocarbon Reservoirs in the Upper Cretaceous Yogou Formation, Koulele Area, Termit Basin, Niger

Based on the sedimentary and tectonic background of the Termit Basin, this paper focuses on the Upper Cretaceous Yogou Formation and uses organic geochemistry, logging, oil testing and seismic data to analyze the primary control factors of the hydrocarbon accumulation and establish corresponding model in order to predict favorable exploration target zones of hydrocarbon reservoirs. This study demonstrates that the Upper Cretaceous Yogou Formation is a self-generation and self-accumulation type reservoir. The Yogou Formation hydrocarbon reservoirs in the Koulele area are controlled by four factors：（1） the source rock is controlled by a wide range of YS1-YS2 marine shale,（2） the sandstone reservoir is controlled by the YS3 underwater distributary channel and storm dunes,（3） migration of hydrocarbons is controlled by faults and the regional monocline structure, and（4） the accumulation of hydrocarbons is controlled by lateral seal. The structures in the western Koulele area are primarily reverse fault-blocks with large throws, and the structures in the east are dominantly fault-blocks with small throws（co-rotating and reverse） and a fault-nose. In the western Koulele area, where the facies are dominated by storm dunes on a larger scale, it is easier to form lithologic reservoirs of sandstone lens. In the eastern Koulele area, high-quality channel sandstone reservoirs, fault-blocks with small throws, and the monocline structure benefit for the formation of updip pinch out lithologic traps, fault lithologic reservoirs and fault-nose structural reservoirs. Future exploration targets should be focused in the western storm dunes zone and eastern distributary channel sand zone with small fault-blocks.

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.

Roles of gypsum/salt-bearing sequence in hydrocarbon accumulation and storage

Gypsum/salt beds are widely developed in petroliferous basins across the world.Most basins with gypsum/salt beds have been proven to host abundant hydrocarbon resources.Previous studies on the effects of gypsum/salt beds on hydrocarbon reservoirs primarily focused on their excellent sealing property as cap rocks.However,an increasing number of exploration discoveries have shown that gypsum/salt beds have the potential to promote the formation of high-quality source rocks and hydrocarbon reservoirs.Gypsum/salt beds influence the generation,preservation and accumulation of hydrocarbons.Based on the systematic analysis of the generation of hydrocarbons in global gypsum/saltbearing sequences,the study discussed the control of gypsum/salt beds on play elements,and explore the relationship between the development of gypsum/salt beds and global large-and medium-scale hydrocarbon reservoirs.Furthermore,we analyzed the correlation between typical gypsum/saltbearing sequences and their hydrocarbon generation potentials in China.In-depth analysis shows three patterns in terms of the spatial superimposition of gypsum/salt beds and source rocks,that is,postsalt pattern,inter-salt pattern and pre-salt pattern.Among others,the source rocks of the inter-salt pattern are widely developed in salt basins and of great potential for hydrocarbon exploration.

Formation of abnormal high pressure and its application in the study of oil-bearing property of lithologic hydrocarbon reservoirs in the Dongying Sag

The mechanisms of abnormal high pressures are studied in this paper, and it is concluded that the undercompaction, hydrocarbon generation and stratum denudation are obviously effective to fluid pressure buildup. Because of the episodic difference, the hydrocarbon generation and stratum denudation are the main factors influencing oil-gas migration. On the basis of basin evolutionary analysis in the Dongying Sag, it is considered that the undercompaction mainly caused the abnormal pressure before the first denudation by the uplift in Late Paleogene, while hydrocarbon generation was the main factor of abnormal pressure after the denudation. The second denudation occurred in Late Neogene, which changed the pressure field and induced the fluid migration. The development of overpressures is the necessary condition to the formation of lithologic hydrocarbon reservoirs, which have positive correlations to overpressures. According to the fullness of the present reservoirs, the quantitative relations between oil-bearing property and driving forces of reservoir formation were determined, the latter were decided by dynamic source, reservoir capillary pressure, fluid pressure of surrounding rocks and the dynamic attenuation in different conducting systems.

Characterization of Sandstone Reservoir at Bokor Formation, Kampot Province, Kampong Som Basin, Onshore Cambodia

Kampong Som Basin is a Paleozoic-Mesozoic sedimentary basin located in southern Cambodia. While the sandstone of the Bokor Formation is expected to be the reservoir for hydrocarbon accumulation. Hence, this study aims to define the properties, quality, and factors that control reservoir rock quality. Sandstones of the Bokor Formation are sampled and analyzed using a helium porosimeter, nitrogen permeameter, polarized light microscope, and scanning electron microscope (SEM) to check the porosity, permeability, minerals, pore geometry, and clay minerals that influence the reservoir quality. According to the result of petrography analysis described by thin section, the sandstone samples from Bokor formation are classified as quartz arenite that composes mainly of quartz, rock fragment, mica-flake, and sericite with connected and unconnected pores of 50 μm to 500 μm with interparticle pore type. Sandstones in this formation have porosity values ranging from 6.55% to 13.19%, and permeability values ranging from 10 mD to 60 mD. The statistics of porosity and permeability of sandstone reservoirs indicate low porosity and permeability that are suggested to be fair reservoir rock for hydrocarbon accumulation. SEM results indicate that there are three types of authigenic clay minerals involving such as kaolinite, illite, and chlorite. In addition, the pore geometry, quartz overgrowth, dissolution of quartz and felspar grain filling in pore space, compaction, replacement diagenesis processes, and cementation presence of clay minerals are the main controlling factors of the sandstone reservoir from the Bokor Formation. Furthermore, this area exhibits sedimentary structures such as planar cross-bedding, cross-bedding, parallel lamination, normal grading, massive, wavy, and reverse graded bedding, which indicates these lithofacies may be deposited in shallow marine environments.