Controlling Hydrocarbon Accumulation Research Articles

Implications of multi-stage deformation on the differential preservation of Lower Paleozoic shale gas in tectonically complex regions: New structural and kinematic constraints from the Upper Yangtze Platform, South China

The strength of tectonic deformation in tectonically complex regions, particularly multi-stage superimposed tectonic regions, can have a significant impact on shale gas preservation conditions. However, differential tectonic deformation has still not been quantitatively constrained, and its impact on the preservation conditions of shale gas is thus poorly understood in the northern Guizhou Province, southwest China. This study investigates the differential preservation conditions of marine shale gas in four eroded synclines (including Shixi, Daozhen, Zhongguan, and Fuyan Synclines) of the northern Guizhou Province. Interpretation of structures in field outcrops, geometry and kinematic analysis, and typical gas reservoir anatomy are combined to quantitatively explore the effect of superimposed deformation on the preservation conditions of shale gas. According to a set of new structural and kinematic constraints, the Riedel shear model for strike-slip faults is firstly conducted in the eroded synclines in the northern Guizhou Province, which innovatively established a linkage between detailed structural analysis and evaluation of shale-gas preservation conditions. We demonstrate that superimposing of deformations plays a role in differential accumulation in eroded synclines. The results indicate that (1) fault strike in the Shixi Syncline is more concentrated than Zhongguan and Fuyan Synclines, whereas fault strikes in the Zhongguan and Fuyan Synclines are more scattered. There is only one direction of maximum principal stress (σ1) in the Shixi and Daozhen Synclines. There are two maximum principal stress directions (σ1) in the Zhongguan and Fuyan Synclines. The Zhongguan and the Fuyan Synclines have tensional environments, whereas the Shixi and the Daozhen Syncline have compressional settings; (2) the formation dip angle, distance to a class II fracture, average detachment layer thickness, intensity of superimposed modifications, and interlimb angle may be positively correlated with gas content; (3) the progressive transformation pattern is established. These findings lay the foundation for the future research on the differential preservation mechanism of eroded synclines and may be useful for enhancing research on worldwide strike-slip faults controlling hydrocarbon accumulation.

Differential deformation of a strike-slip fault in the Paleozoic carbonate reservoirs of the Tarim Basin, China

Ultra-deep carbonate reservoirs buried over 7000 m are distributed around strike-slip faults, which control hydrocarbon accumulation and enrichment in the Tarim Basin, China. This study proposes a fracture development index (FDI) method for analyzing the width of the strike-slip fault zone based on 3D seismic data. Based on the FDI method and geological and geophysical data, we analyze the structural characteristics of the SB5 strike-slip fault and the scaling of fault zone width and throw.In map view, at depth the strike-slip fault is characterized by single fault segments, extensional overlaps, and contractional overlaps, at intermediate depths by left-stepping en echelon normal faults, and in shallow layers by right-stepping en echelon normal faults. In cross section, we find composite flower structures and positive flower structures and medium-shallow layer negative flower structures or deep layer negative flower structures and medium-shallow layer negative flower structures. The formation time of deep, middle, and shallow layer faults is the middle Caledonian, Late Caledonian, and Late Hercynian. The heterogeneity of the strike-slip fault zone varies from strong to weak from contractional overlaps, to extensional overlaps, and single fault segments. Strike-slip fault-related fractures are dominated by three sets intersecting with strike-slip faults at small angles. Where throw is less than 100 m, the fault zone width and throw have a good power law relationship. Where the throw is over 100 m, the width tends to diminish with throw.

3D dynamic fault sealing capacity modelling to improve history matching: a case study in Oligocene reservoir, Tay Ho Field, Blocks A, Cuu Long basin, Offshore

Fault transmissibility multipliers are a simple way of accounting for the effects of faults on fluid flow across fault plans in history matching of production simulation models. Fault transmissibility multipliers can be calculated using parameters such as fault clay, fault smear, thickness, and permeability. In this study, three emperical methods given by Manzocchi et al. (1999), Jolley et al. (2007), and Sperrevik et al. (2002) have been applied to the Oligocene sandstone reservoir, Tay Ho Field. The Oligocene reservoir is a complicated sandstone that was deposited in alluvial-fluvial and lacustrine environments, trapped by both stratigraphic and structural types, sandbody isolated by multi-activated faults. Fault sealing is one of the key factors controlling hydrocarbon accumulations and trap volume and can have a significant influence on reservoir performance during production. Furthermore, the prospective of structural or combination traps in stacked clastic reservoir settings that are typically found in many of the known hydrocarbon provinces in the Cuu Long basin, often critically hinges on the presence of a working fault side seal. Based on a thorough understanding of the key controls on fault seal risk and retention capacity, a consistent methodology to access these factors across a prospect portfolio is essential to achieve a balanced prospect ranking and an accurate assessment of prospect success volumes. In the process workflow built by PVEP Blocks 01/97 & 02/97, the assessment of fault seal capacity and compartmentalization in the Oligocene reservoir have been incorperated by using fault deformation, displacement, juxtaposition, fault zone thickness, shale gouge ratio (SGR), shale smear factor (SSF), clay smear potential (CSP), fault thickness and permeability. In our research, the Sperrevik et al. (2002) method provides the best historical match and most logical geological evidence; thus, it shall be used for dynamic models and further studies.

Main factors controlling hydrocarbon accumulation in the Northwestern Sichuan Basin

The basin-mountain transition regions of foreland basins are hot spots for hydrocarbon exploration worldwide, while the complex geological features and hydrocarbon accumulation rules make hydrocarbon exploration very difficult. The Northwestern Sichuan Basin is a typical case where the unclear distribution rules restrict the further exploration of natural gas. In this study, geochemistry and seismic profile data were comprehensively used to reveal the main factors controlling hydrocarbon accumulation in the Northwestern Sichuan Basin. The Lower Cambrian and the Upper- Middle Permian source rocks have different carbon isotope compositions, indicating that they have different kerogen types, sapropelic kerogen for the Lower Cambrian source rocks, mixed kerogen for the Middle Permian source rocks and humic kerogen for the Upper Permian source rocks. The Northwestern Sichuan Basin can be divided into the unfaulted belt, the thrust front belt and the thrust nappe belt. The thrust nappe belt develops many large thrust faults, and the natural gas there mainly originates from the Lower Cambrian source rocks. However, due to different denudation of regional caprocks, hydrocarbons in the area adjacent to the Longmen Mountain fold-and-thrust system were destroyed, while in the area adjacent to the thrust front belt, they had good preservation conditions. The thrust front belt and the unfaulted belt develop a few or few thrust faults, and the natural gas there mainly originates from the Upper-Middle Permian source rocks and has good preservation conditions due to no denudation of regional caprocks. The distribution of thrust faults controls the natural gas origins in different areas, and the preservation conditions determine whether the gas reservoirs can survive to the present. These conclusions can provide guidance for natural gas exploration in the Northwestern Sichuan Basin and other basin-mountain transition regions in foreland basins worldwide.

Analysis of Regional and Residual Gravity Disturbance of Major Fault Belts in the Tarim Basin, Western China

Large fault belts often influence the paleo-geomorphic changes in basins and control hydrocarbon accumulation and distribution in basins. Based on the gravity field model European Improved Gravity model of the Earth via New techniques (EIGEN)-6C4, this study calculated the residual Bouguer gravity disturbance of the Tarim Basin by using the minimum curvature method and analyzed gravitational characteristics of major fault belts of the Tarim Basin. The residual Bouguer disturbance exhibits linear residual Bouguer disturbance zones in the Tianshan Mountains, West Kunlun, and the Altyn region, which is consistent with the spatial distribution of their related fault belts. The regional Bouguer disturbance is related to crust–mantle boundary depth, which can be used to roughly estimate crust thickness. Thus, we suggest that the crust–mantle boundary depth order of major faults from deep to shallow is the Altyn region, West Kunlun, and Tianshan Mountains. There is a discontinuity in the residual Bouguer disturbance of West Kunlun, which compares well with the fault belt of West Kunlun. Furthermore, the residual Bouguer disturbance of the Tarim Basin has a series of elliptical areas with a central positive disturbance located within the Bachu uplift and other uplift structures. The residual Bouguer disturbance also reflects the position and distribution of the major fault belts and the boundary of the Tarim Basin, which can provide guidance for dynamic evolution analysis of large basins.

Hydrocarbon accumulation model based on threshold combination control and favorable zone prediction for the lower Enping Formation, Southern Lufeng sag

Deep complex oil and gas reservoirs are the future directions of oil and gas exploration. The exploration potential of Paleocene deposits in the Lufeng sag is enormous. However, due to the greater burial depth and complex oil and gas accumulation conditions of the Paleocene, few large-scale reservoirs have been discovered and the next exploration strategy is unclear. In this study, based on the Paleocene geological data of the Southern Lufeng sag, a model of hydrocarbon accumulation based on functional element control is constructed using geostatistical and numerical simulation techniques. The hydrocarbon accumulation elements, thresholds, boundaries and scopes are clarified, and the favorable zones of hydrocarbon accumulation of the lower Enping Formation are predicted using the model of hydrocarbon accumulation based on threshold combination control. The results indicate that the source rock, reservoir, caprock, and low-potential area are the four functional elements controlling hydrocarbon accumulation. Since there are three types of low-potential zones, a total of six accumulation elements are considered to control hydrocarbon accumulation, and the corresponding hydrocarbon accumulation control thresholds are determined by the model of hydrocarbon accumulation according to the controlling effects of these accumulation elements. The predicted Type I favorable zones are located in the eastern part of Lufeng 13 east sub-sag and the northern and southern parts of Lufeng 7 sub-sag; Type II favorable zones are located in the western part and around the Lufeng 13 east sub-sag; Type III favorable zones are adjacent to Type II favorable zones. The hydrocarbon shows are all located in the overlapping zone of five or more accumulation elements. Cited as: Zhang, L., Pang, X., Pang, H., Huo, X., Ma, K., Huang, S. Hydrocarbon accumulation model based on threshold combination control and favorable zone prediction for the lower Enping Formation, Southern Lufeng sag. Advances in Geo-Energy Research, 2022, 6(5): 438-450. https://doi.org/10.46690/ager.2022.05.08

Prediction of Favorable Positions for Hydrocarbon Accumulation Controlled by Oil-Source Faults: A Case of Dazhangtuo Fault in the Qikou Sag, Bohai Bay Basin, East China

Oil-source faults play an important role in controlling hydrocarbon accumulation, and traps near these faults are often the most favorable positions for hydrocarbon accumulation. However, not all nearby traps can accumulate oil and gas. Therefore, it is necessary to predict favorable positions of hydrocarbon accumulation controlled by oil-source faults. Based on the analysis of hydrocarbon accumulation patterns near oil-source faults, a new method coupling hydrocarbon transportation positions of oil-source faults and favorable traps to predict favorable hydrocarbon accumulation positions is proposed. In this method, the hydrocarbon transportation positions are identified by the paleo activity rate during the hydrocarbon accumulation period; the favorable traps are identified by superimposing the position of fault traps, the lateral sealing position of faults, and the distribution of sand bodies with the ability to store oil and gas. Finally, the sites of overlap between the hydrocarbon transportation positions and the favorable traps are regarded as favorable positions for hydrocarbon accumulation under the control of oil-source faults. This method is applied to predict the favorable positions of hydrocarbon accumulation in the Ban 2 oil group of the Shahejie Formation near the Dazhangtuo fault, in the Qikou Sag (Bohai Bay Basin, East China). The results showed that the favorable positions of oil and gas accumulation along the Dazhangtuo fault in the Ban 2 oil group are mainly distributed in the northeast and center of the fault, and match well with the locations of the discovered oil and gas. Therefore, this method is useful to predict favorable hydrocarbon accumulation positions controlled by oil-source faults.

Topological analysis of fault network in naturally fractured reservoirs: A case study from the pre-salt section of the Santos Basin, Brazil

The Santos Basin, located on the southeastern margin of Brazil, hosts giant hydrocarbon reserves of the pre-salt section that correspond to the carbonate sequences deposited during the syn-rift and transitional tectonic stages. The faults, which formed during the rift evolution, have proven to be crucial in controlling hydrocarbon accumulations and migration, not only as a pathway for fluid flow but as a factor controlling the deposition of sedimentary rocks. Thus, the topological analysis of fault networks is a key method to characterize the different fault sets, as it provides a way to describe the network arrangement of individual faults and their connectivity. In this work, the fault topology was analyzed in terms of nodes and branches for the main reservoir defined in the pre-salt section seismic units: Rift, Lower Barra Velha (Lower BVE), and Upper Barra Velha (Upper BVE). Four fault sets were characterized in these units with average orientations to NW-SE and E-W. The topology of this fault networks is characterized by single-phase rift network, featuring isolated systems with more than 50% of isolated branches and low connectivity (connections per branch being less than 0.5). The flow azimuth is NE-oriented, mostly oblique to the trend of the main faults, which suggests a low fault influence in the fluid flow. On the other hand, the paleotopographic highs developed during the Rift phase present the highest fault density and intensity, factors known to contribute to increased connectivity in reservoirs. A clear limitation of this type of study is the integration of the seismic-scale faults with high-frequency well log data, sparse but known to have great vertical resolution, and, in turn, assessing the vertical fluid flow, instead of lateral as is possible with this method. These limitations are to be known by one to apply this in other contexts. In this work, we seek to understand how the development of the rift fault system influences the generation of new fault sets, and fluid flow in a pre-salt carbonate reservoir.

Distribution of Mid‐deeply Buried Sand‐bodies and their Hydrocarbon Significance at Basin Margins: Case Study of the Paleogene in the Eastern Liuzan Area of the Nanpu Sag, Bohai Bay Basin, China

AbstractThe current research aims to unlock the temporal and spatial distribution of sand‐bodies and their relationship with hydrocarbon accumulation in the mid‐deep layer of basin margins, located in the eastern part of the Liuzan area of the Nanpu Sag, Bohai Bay Basin, China. Through this study, the main target interval of the area was divided into two fourth‐order sequences. The lean sand mixed sedimentary belt with great importance in controlling hydrocarbon accumulation was identified through the comprehensive use of 3D seismic data, logging data, lithological data and seismic inversion data. A detailed analysis of sand‐body development characteristics and their role in controlling hydrocarbon accumulation was conducted. The results reveal that the study area mainly develops two distinct fan‐delta lobes from the NE‐trending sediment supply direction. Due to the relatively high influence of the lacustrine transgression event, the scale of the lean sand mixed sedimentary belt within the SQ1‐1 (the lacustrine transgressive systems tract) is relatively small, showing a relatively continuous distribution of sand bodies in the plane. Conversely, due to the relatively high impact of the lacustrine regression event, the scale of the lean sand mixed sedimentary belt developed within the SQ1‐2 (the highstand systems tract) is relatively large, the two east sets of fan‐delta sedimentary systems being clearly separated. The lean sand mixed sedimentary belt formed a good lateral occlusion belt in favor of hydrocarbon accumulation. Through composite analysis of structural interpretation results, sand‐body distribution and well test data, it is evident that the lean sand mixed sedimentary belt located in the structural high is not a favorable zone for hydrocarbon accumulation. In contrast, the wing of the high part of the structure is the zone of sand‐bearing bodies and is a favorable zone of hydrocarbon accumulation.

Development characteristics and petroleum geological significance of tearing faults in Hashan area

Hashan area is part of piedmont thrust belt in northwestern Junggar basin. By studying its structural characteristics, it is found that there are three different deformation sections along the strike of tectonic belt. It is considered that the development of tearing faults is the main reason for controlling the difference of structural deformation in different sections of Hashan area. In order to study the characteristics and petroleum geological significance of tearing faults, the identification and structural characteristics of tearing faults are studied, combined with the analysis of petroleum geological conditions, its petroleum geological significance is found out.The results showed that: The tearing faults in the Hashan area are usually developed in the position where the strike of the main reverse fault changes. The strike is mainly NW-trending and is roughly perpendicular to the long axis of the main structure. The terrain on both sides of the fault has obvious dislocation or belongs to different terrains, and is mostly presented flower-like structure or steep cliff on the profile. The lateral compression during the formation of the piedmont zone leads to the differential nappe of different structural parts of the same block, which is the main reason for the formation of tearing faults in Hashan area. The late tearing faults of nearly north-south direction in Hashan area communicated deep source rocks downward, Jurassic blanket sand upward and formed traps laterally, which played an important role in controlling hydrocarbon accumulation.

Hydrocarbon accumulation conditions and models in fault -depression superimposed basin: a case in Longfengshan area in Songliao basin, China

Songliao Basin develops typical fault-depression superimposition dual structure in vertical. So far, the depression sequence has achieved continuous stable yield of oil and gas, while it is of great significance to deepening exploration of hydrocarbon in faulted sequence. Taking the new Longfengshan Area as the research object, in light of the analysis of source rock condition, source of hydrocarbon, passage system, caprock condition and accumulation period, the dynamic hydrocarbon accumulation process is recovered, and hydrocarbon accumulation models are established. Research shows that K1sh Formation source rock in the northern depression zone has good hydrocarbon generation capacity, which provides high quality source condition. What is more, effective configuration between sealing faults and connected sandstone provides important hydrocarbon migration and accumulation condition. Meanwhile, the top of K1yc3 Formation mudstone caprock has good fault-caprock configuration, which provides good hydrocarbon preservation condition. The hydrocarbon accumulation model of study area can be summarized as “source rock in sag zone supplies hydrocarbon, fault-sandstone configuration controls hydrocarbon migration, faults-caprocks configuration controls hydrocarbon accumulation” pattern which embodies the characteristics of “rapid vertical transporting by faults, fault-sandbody configuration, caprocks control hydrocarbon accumulation” in the stage of fault-depression transition and “sealing by faults, sandstone conducts laterally- faults, caprocks control hydrocarbon accumulation” in the stage of depression.

Controls on hydrocarbon accumulation by facies and fluid potential in large-scale lacustrine petroliferous basins in compressional settings: A case study of the Mesozoic Ordos Basin, China

Large-scale lacustrine basins in compressional settings are an important type of petroliferous basin, and the study of the characteristics of hydrocarbon accumulation in such basins is of great significance. This synthesis paper takes the Mesozoic Ordos Basin (central China) as a case study to establish lateral and vertical hydrocarbon accumulation patterns in this basin type, and highlights how facies and fluid potential control hydrocarbon accumulation in such basins. Based on systematic analyses of the Mesozoic source rocks, sedimentary facies, migration and accumulation patterns, and characteristics of the oil reservoirs, the hydrocarbon accumulation characteristics in the Mesozoic Ordos Basin are discussed. The analysis indicates that sedimentary facies controlled the characteristics and distribution of hydrocarbon source rocks and reservoirs, while diagenetic facies controlled the quality and distribution of the reservoirs. Excess pressure and fluid potential controlled hydrocarbon migration directions and paths, whereas facies and potential controlled the locations of oil accumulations and traps. It is concluded that source rocks controlled oil-bearing regions, sedimentary facies controlled oil-bearing plays, and fluid potential controlled the locations of accumulations. For shallow intervals, because fluid migration is mainly controlled by buoyancy, paleotopographic highs played an important role in controlling hydrocarbon accumulations. For deep layers (Chang 7 to Chang 10 members), since buoyancy is less than the capillary pressure, excess pressure caused by the undercompaction of mudstone and hydrocarbon generation at depth provides the driving force for lateral and vertical migration of oil, and becomes the main migration force. The reservoir accumulation characteristics differ laterally between regions of the basin; at the periphery of the basin, reservoir units are stacked in a step-wise manner, whereas at the center of the basin, multiple reservoir intervals are vertically stacked in the form of multistorey accumulations. Vertically, layers with different burial depths have different accumulation characteristics; the paleotopography controlled hydrocarbon accumulation in shallow intervals; instead excess pressure, fluid potential, and paleotopography controlled accumulation in deep intervals. This understanding could be used to inform prospecting in other large-scale lacustrine petroliferous basins in compressional settings such as the Eocene Green River Basin in the U.S.A. and the Middle Triassic Gunnedah Basin in Australia.

Key factors controlling Mesozoic hydrocarbon accumulation in the Southern East China Sea Basin

The East China Sea Basin is located on the southeastern edge of the Eurasian Plate. Since the Mesozoic era, the basin formation and evolution processes have been superimposed with the multi-period oceanic subduction of the paleo-Pacific Plate and multi-structural systems interacting with the Indo–Australian Plate, Pacific Plate, and Eurasian Plate. As previous studies have mainly focused on the Cenozoic era, the basin prototype, tectono-sedimentary characteristics, and key factors controlling hydrocarbon accumulation during the Mesozoic era have always been hotspots for research and scientific questions as part of a “New horizon” for oil and gas exploration in the East China Sea Basin. Based on the latest data from seismic, drilling, and onshore-offshore comparison studies in the Southern East China Sea Basin (SECSB), this study explored the key factors controlling the oil and gas generation, migration and accumulation, and exploration direction of the Mesozoic hydrocarbon accumulation by employing onshore-offshore comparisons, seismic stratigraphy, and structural-sedimentary evolutionary reconstruction. The results showed that three regional unconformities and seven seismic sequences formed during the Mesozoic period in the SECSB. The evolution since the Mesozoic era included the formations of a basement by the passive continental margin before the Late Triassic, the Late Triassic–Middle Jurassic depression of the active continental margin, and the Cretaceous faulted basins at continental margins. It is proposed that 1) the early basal NE-trending structural framework controlled the structural pattern of the Mesozoic basin and the macro-hydrocarbon properties, according to which the Cretaceous should be dominated by oil, and the Upper Triassic-Middle Jurassic should be dominated by gas; 2) two sets of source rocks (i.e., Upper Triassic-Lower Jurassic mud shale and Lower Cretaceous mudstone source rocks) were deposited, which formed the material basis for hydrocarbon accumulation and the source-reservoir-seal combinations during two stages of basin evolution in the Mesozoic era; 3) the East China Sea Basin has experienced at least seven tectonic movements since the Mesozoic period, including the Keelung, Yushan, Yandang, Oujiang, Yuquan, Longjing, and Okinawa Trough movements, among which the Keelung, Yushan, and Yandang movements dominated the formation and accumulation of early oil and gas, and the adjustment, transformation, and re-establishment of early reservoirs was accomplished by the Longjing Movement; and 4) the Minjiang Slope and the Taipei Turning Belt are the main petroleum exploration areas in the Mesozoic basin, in which the Cretaceous should be the main target layer in the east of the basin, and the Upper Triassic–Middle Jurassic in the west.

Factors Controlling Hydrocarbon Accumulation in Jurassic Reservoirs in the Southwest Ordos Basin, NW China

AbstractThe sedimentary, paleogeomorphological and reservoir characteristics of the Jurassic Yan'an Formation in the southwestern Ordos Basin, northwestern China, were studied by means of casting thin sections, scanning electron microscopy, inclusion analysis and identification of low‐amplitude structures. A model for reservoir formation is established, and the controlling effects of sedimentary facies, paleotopography, low‐amplitude structures and formation water on oil reservoirs are revealed. There are significant differences in the sedimentary characteristics, structural morphology and paleowater characteristics between the reservoirs above the Yan 10 Member and those in the Yan 9 to Yan 7 Members. The Yan 10 Member contains fluvial sediments, whereas the Yan 9 to Yan 7 members contain delta‐plain anastomosing‐river deposits. The distribution of high‐permeability reservoir is controlled by pre‐Jurassic paleogeomorphology and sedimentary facies. Some of these facies exhibit high porosity and high permeability in a low‐permeability background. The main hydrocarbon accumulation period was the late Early Cretaceous, filling was continuous, and the charging strength altered from weak to strong and then from strong to weak. The Yan 10 reservoir is mainly controlled by the paleogeomorphology: hydrocarbons migrated upward at a high speed through the unconformity surface, and accumulated in the favorable traps formed by paleogeomorphic structural units, such as gentle slopes or channel island. Furthermore, groundwater alternation in these areas was relatively stagnant, providing good reservoir preservation conditions. The reservoirs in the Yan 9 and higher members are controlled by the sedimentary facies, low‐amplitude structure and paleowater characteristics. Hydrocarbons migrated through the three‐dimensional delivery system, influenced by favorable sedimentary facies and high‐salinity groundwater, then accumulated in the favorable low‐amplitude structural traps that formed during the hydrocarbon production period.

Incorporating critical fault properties controlling hydrocarbon accumulation in 3D basin and petroleum system modelling: a case study in the northern North Sea

Fault properties are very important parameters in migration and accumulation of hydrocarbons in sedimentary basins. However, there are still several different schools of thought on how to incorporate such prospect-bounding fault properties into petroleum system migration and modelling studies. This paper investigates how shale gouge ratio (SGR), which defines the sealing/non-sealing capacity of faults, can be incorporated in basin modelling using the Gullfaks, Visund, Kvitebjorn and Huldra fields in the northern North Sea as a case study. The paper also presents the results from the most likely model representing the present day reality in the basin by varying the faults properties defined by SGR until the reserves-in-place in the four fields are obtained. Our results show that gas accumulations are more sensitive to SGR than the oil accumulations. The oil accumulation in the Gullfaks field is controlled by three main faults. The first fault bounding the field is a non-sealing fault with SGR = 10%. The second fault located further south in the field is a sealing fault, and the third fault located in the north is a non-sealing fault. A NE–SW non-sealing trending fault controls the hydrocarbon accumulation in the Visund field. In the Kvitebjørn field, another NE–SW trending fault surrounding the field with an SGR of 30% controls the hydrocarbon accumulation. The gas-in-place in the Huldra field is controlled by two N–S trending faults. The first fault is located in the west of the field and is defined by SGR of 40%, while the second fault is defined as open. Analysis of the burial history curves of the most likely petroleum system model obtained after the fault properties modelling shows that the Late Jurassic to Early Cretaceous uplift in the basin is more pronounced in the footwall of the triple rift graben system in the basin. In the same period, the axis of the graben system is characterized by non-deposition of sediments.

Characteristics of fluid inclusions and implications for the timing of hydrocarbon accumulation in the cretaceous reservoirs, Kelasu Thrust Belt, Tarim Basin, China

Abstract The Kelasu Thrust Belt is a key area for oil and gas exploration within the Tarim Basin of China, an area containing abundant oil and gas resources but where the processes that controlled hydrocarbon accumulation remain unclear. This study reconstructs the accumulation history of hydrocarbons within the Kelasu Thrust Belt by studying multiple sets of fluid inclusions from the Cretaceous reservoirs using laser Raman, infrared spectroscopy, fluorescence spectroscopy, total scanning fluorescence, and PTV simulation analyses. The resulting data yield the following results. (1) Three types of Cretaceous hydrocarbon-bearing fluid inclusions are present, and they record three periods of hydrocarbon accumulation. Period I involved low-maturity medium oil as recorded by the presence of yellow–green fluorescent oil inclusions, with this accumulation occurring between the Neogene Jidike and Kangcun stages (20–5 Ma). Period II involved high-maturity light oils (or condensates) that are recorded by the presence of blue–white fluorescent oil inclusions, with this accumulation occurring during the early Kuche stage (5–2.5 Ma). Period III involved the significant accumulation of gas, as recorded by non-fluorescent gas inclusions, during and after the late Kuche stage (2.5–0 Ma). (2) Inclusion PVT simulations indicate that the pressures during the trapping of oil inclusions within the west Kelasu reservoirs increase with increasing capture temperature, suggesting that west Kelasu Cretaceous oil reservoirs formed over a short period of time. In contrast, the trapping pressures of oil inclusions within the east Kelasu area are invariant with increasing trapping temperature, indicating that the formation of east Kelasu Cretaceous oil reservoirs was a relatively slow and gradual process. This most likely relates to the fact that the east Kelasu reservoirs are close to the hydrocarbon generation centre in an area with sufficient hydrocarbon supply, with hydrocarbon accumulation processes involving all of the stages of hydrocarbon generation recorded by the source rocks in this area. In comparison, the west Kelasu reservoirs are far from the hydrocarbon generation centre and as such record only one phase of oil filling. (3) Significant tectonism associated with the uplift of the South Tianshan Mountain during the late Kuche stage caused widespread changes to Cretaceous paleo-oil reservoirs in this area. This led to some Cretaceous paleo-oils being transported to shallower traps to form secondary oil reservoirs, whereas others were transported to the surface and were lost, with residual paleo-oils were also changed to condensate gas as a result of gas washing after the addition of large amounts of late-stage gas.

Main controlling factors of hydrocarbon accumulation in Baiyun Sag at northern continental margin of South China Sea

Abstract To examine the distribution pattern and controlling factors of oil and gas accumulation in Baiyun Sag systematically, this study analyzes the key factors controlling hydrocarbon accumulation using a large amount of seismic, drilling and geologic data. It is concluded that the oil and gas accumulation is controlled by the following factors: (1) Massive source rock is the physical basis of the formation of medium and large oil and gas fields. (2) Orderly distribution and accumulation of hydrocarbon is regulated by the differential generation of hydrocarbon and differential hydrocarbon accumulation: spacial differential leads to “inner gas, outer oil” pattern, differential accumulation of hydrocarbon controlled the pattern of “inner gas, outer oil” in the east subsag of Baiyun; the timing differential leads to the “upper gas, lower oil” pattern. (3) Late fault activity, diapirs and inherited structural ridges controlled the favorable migration in the Neogene: the activity of faults and diapirs regulated the trap formation and vertical migration of hydrocarbon; inherited structural ridges controlled the Neogene hydrocarbon accumulation. The result effectively guides the exploration in the Baiyun Sag and surrounding area, and provides experience and evidence for the exploration in deepwater area of Pearl River Mouth Basin and other similar basins.

Oil distribution in outcropping carbonate-ramp reservoirs (Maiella Mountain, Central Italy): Three-dimensional models constrained by dense historical well data and laboratory measurements

Heavy oil and bitumens have been exploited in Italy during the past, in particular over the Maiella Mountain’s northwest flank (Central Italy), where relatively undeformed, hydrocarbon-bearing carbonate-ramp reservoirs of the Bolognano Formation crop out. These reservoirs represent the exhumed analog of a wider petroleum system that has been investigated also in the subsurface by exploration activities, both onshore and offshore (Central Adriatic). Here we present, for the first time, a historical data set composed of 180 shallow wells drilled over the area in 1942 by a company named Azienda Lavorazione Bitumi Asfalti; we digitally reconstructed this data set, integrating it with field observations, laboratory measurements, and thin-section analysis. Using Petrel (mark of Schlumberger) three-dimensional software, we modeled the reservoir and the hydrocarbon distribution, also calculating volumes of hydrocarbons in place. In our work, we demonstrate the presence of these quite homogeneous, porous carbonate reservoirs over the whole region, and we identify internal reservoir geometries characterized by clinoforms, likely resulting from a large-scale depositional cross-bedding and progradation. We also infer a different function of faults in the hydrocarbon accumulations: major faults were able to create independent compartments during migration, whereas minor, more recent elements did not control hydrocarbon accumulation, likely postdating a main lower-Pliocene migration phase. We believe that the observations derived from our work can represent a good analog for carbonate-ramp reservoirs elsewhere, may help in identifying appropriate modeling solutions, and can be used as calibration for future renewed exploration efforts in the region, both onshore and offshore.

Distribution pattern and main factors controlling hydrocarbon accumulation of global oil and gas-rich deepwater basins

It is observed from distribution of oil and gas-rich basins as well as summary and analysis of main control factor for hydrocarbon accumulation in global deepwater that oil and gas-rich basins in deepwater in the world shows “one horizontal and two vertical” in distribution pattern and that “one vertical” of deepwater basin group chiefly distributed in Atlantic Ocean from north to south of deepwater oil rich-basin group in the world is under the influence of fault basin group and that deepwater gas-rich basin group along Neo-tethyan tectonic domain and epicontinental basin group in East Africa shows “one horizontal and one vertical” in distribution, being under the influence of “fault basin group in transitional facies”; Comparative analysis and research of main factors for hydrocarbon accumulation in main deepwater oil and gas-rich basins in the world in a systemic way show that main control factors for hydrocarbon accumulation in deepwater oil and gas-rich basin in the world can be reduced to following five types: (1) Reservoir under common control of salt structure, passage system and large turbidite fan; (2) Reservoir under control of source control area and large reservoir body; (3) Reservoir under control of source rock and cap rock control area and large delta; (4) Reservoir under control of source and cover control zone and reef flat; (5) Reservoir under control of source heat control zone, passage system and trap.

Genetic mechanisms and distribution characteristics of overpressures in the Paleogene reservoirs of the Bohai Bay Basin, East China

The Bohai Bay region is a primary accumulation area of oil and gas in offshore China, in which overpressure commonly occurs in the Paleogene strata; the analysis on distribution characteristics and genetic mechanisms of the overpressure would provide geologic evidences for making plans of well drilling and logging as well as oil and gas exploitation; additionally, it could lay the geological foundation for studying how overpressure controlled hydrocarbon accumulation. Based on research, the overpressure of the study area starts from the second member of the Dongying Formation and ends in the third member of the Shahejie Formation. The distribution of overpressure is mainly controlled by the sag–salient tectonic framework within the basin, which means overpressure mainly develops in sags or slopes; however, high areas stay normal pressured. In the study area, pressure develops around Bozhong Sag and in northern Liaodong Bay reaches the peak. The genetic mechanisms of overpressures in the Paleogene reservoirs are mainly disequilibrium compaction, hydrocarbon generation of the organic matter, fluid charging, and transmission or the superimposition of the former two. Different strata have different genetic mechanisms of overpressure. The chief genetic mechanisms for the generation of overpressure of the Dongying Formation are disequilibrium compaction while the genesis of the formation of overpressure in the Shahejie Formation is more complicated in some extent. The first member of the Shahejie Formation dominated by disequilibrium compaction and hydrocarbon generation of the organic matter plays a supplemental role, while the second member of the Shahejie Formation, as the primary reservoir strata, is dominated by fluid charging and transmission, and the third member of the Shahejie Formation is the main source rock interval; its overpressure is closely related to hydrocarbon generation. Each contribution ratio for overpressure forming by different genetic mechanisms has been judged and figured out quantitatively according to geological, geophysical, and geochemical characteristics of the target strata.