scholarly journals Variability and Main Controlling Factors of Hydrocarbon Migration and Accumulation in the Lower Paleozoic Carbonate Rocks of the Tazhong Uplift, the Tarim Basin, Northwest China

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-14
Author(s):  
Qifei Fang ◽  
Qingzhou Yao ◽  
Yongqiang Qu ◽  
Youlu Jiang ◽  
Huizhen Li ◽  
...  
Keyword(s):  
Fault Zone ◽  
Carbonate Rocks ◽  
Strike Slip ◽  
Source Rocks ◽  
Hydrocarbon Accumulation ◽  
Hydrocarbon Migration ◽  
Lower Paleozoic ◽  
Accumulation System ◽  
Main Factors ◽  
Tazhong Uplift

Hydrocarbon migration patterns and pathways were studied on the basis of three-dimensional seismic interpretation, drilling, geochemistry, production performance, and other data. Using these findings, the main factors controlling hydrocarbon migration and accumulation in the Lower Paleozoic carbonate rocks of the Tazhong Uplift were discussed. The spatiotemporal relationship between the hydrocarbon kitchens and pathway systems of the Tazhong Uplift and the spatial pattern of pathway systems were considered the main factors causing differences in hydrocarbon enrichment. Results also revealed that the Lower Paleozoic carbonates of the Tazhong Uplift have two hydrocarbon accumulation systems (inside and outside the source rocks). For the accumulation system within the source rocks, hydrocarbon migration and enrichment are vertically differentiated. Middle Cambrian gypsum salt rocks serve as the boundary, above which thrust and strike-slip faults mainly allow vertical transport of hydrocarbons. A multistage superposition pattern of strike-slip faults controls the differences in hydrocarbon enrichment on the periphery of the fault zone. Beneath the gypsum-salt rocks, hydrocarbon migration and enrichment is controlled by the topography of paleostructures and paleogeomorphology. For the hydrocarbon accumulation system outside the source rocks, hydrocarbon migration and enrichment are restricted by the layered pathway system, and the topography of the paleostructures and paleogeomorphology is the key factor controlling hydrocarbon enrichment. The Tazhong No. 1 Fault is the main vertical pathway system in the area underlain by no source rocks, and hydrocarbons are enriched at the periphery of the Middle-Lower Cambrian and No. 1 Fault Zone.

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

2016 ◽  
Vol 35 (1) ◽  
pp. 54-74 ◽  
Author(s):  
Xiaoping Liu ◽  
Zhijun Jin ◽  
Guoping Bai ◽  
Jie Liu ◽  
Ming Guan ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Source Rocks ◽  
Williston Basin ◽  
Type I ◽  
Hydrocarbon Generation ◽  
Michigan Basin ◽  
Hydrocarbon Accumulation ◽  
Early Paleozoic ◽  
Lower Paleozoic ◽  
The World

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

scholarly journals Study on Hydrocarbon Accumulation Periods Based on Fluid Inclusions and Diagenetic Sequence of the Subsalt Carbonate Reservoirs in the Amu Darya Right Bank Block

Geofluids ◽  
2022 ◽  
Vol 2022 ◽  
pp. 1-19
Author(s):  
Yunpeng Shan ◽  
Hongjun Wang ◽  
Liangjie Zhang ◽  
Penghui Su ◽  
Muwei Cheng ◽  
...  
Keyword(s):  
Crude Oil ◽  
Fluid Inclusions ◽  
Carbonate Reservoirs ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Hydrocarbon Accumulation ◽  
Forming Process ◽  
Hydrocarbon Migration ◽  
Accumulation Model ◽  
Amu Darya

In order to provide paleofluid evidence of hydrocarbon accumulation periods in the Amu Darya Right Bank Block, microexperiments and simulations related to the Middle-Upper Jurassic Callovian-Oxfordian carbonate reservoirs were performed. On the basis of petrographic observation, the diagenetic stages were divided by cathodoluminescence, and the entrapment stages of fluid inclusions were divided by laser Raman experiment and UV epifluorescence. The hydrocarbon generation (expulsion) curve and burial (thermal) history curve of source rocks were simulated by using real drilling data coupled with geochemical parameters of source rocks, such as total organic carbon (TOC) and vitrinite reflectance ( R o ). The above results were integrated with microthermometry of fluid inclusions by inference the timing of hydrocarbon migration into the carbonate reservoirs. The horizon-flattening technique was used to process the measured seismic profile and restore the structural evolution profile. Four diagenetic periods and three hydrocarbon accumulation periods were identified. (i) For Syntaxial stage, the fluid captured by the overgrowing cement around particles is mainly seawater; (ii) for (Early) Mesogenetic burial stage, the calcite cements began to capture hydrocarbon fluids and show yellow fluorescence under UV illumination; (iii) for (Late) Mesogenetic burial stage, two sets of cleavage fissures developed in massive calcite cements, and oil inclusions with green fluorescence were entrapped in the crystal; (iv) for Telogenetic burial stage, blue fluorescent inclusions along with hydrocarbon gas inclusions developed in dully luminescent calcite veins. Based on the accurate division of hydrocarbon migration and charging stages, combined with the structural evolution history of the traps, the hydrocarbon accumulation model was established. Because two of the three sets of source rocks are of marine origin, resulting in the lack of vitrinite in the kerogen of those source rocks, there may be some deviation between the measured value of R o and the real value. Some systematic errors may occur in the thermal history and hydrocarbon generation (expulsion) history of the two sets of source rocks. Due to the limitations of seismic horizon-flattening technique—such as the inability to accurately recover the inclined strata thickness and horizontal expansion of strata—the final shape of the evolution process of structural profile may also deviate from the real state in geological history. The accumulation model established in this study was based upon the fluid inclusion experiments, which can effectively characterize the forming process of large condensate gas reservoirs in the Amu Darya Right Bank Block and quantify the timing of hydrocarbon charging. However, the hydrocarbon migration and accumulation model does not take the oil-source correlation into account, but only the relationship between the mature state of source rocks and the timing of hydrocarbon charging into the reservoirs. Subsequent research needs to conduct refined oil-source correlation to reveal the relationship between gas, condensate, source rocks, and recently discovered crude oil and more strictly constrain and modify the accumulation model, so as to finally disclose the origin of the crude oil and oil reservoir forming process in the Amu Darya Right Bank Block, evaluate the future exploration potential, and point out the direction of various hydrocarbon resources (condensate gas and crude oil).

scholarly journals Paleozoic Carbonate Hydrocarbon Accumulation Zones in Tazhong Uplift, Tarim Basin, Western China

2009 ◽  
Vol 27 (2) ◽  
pp. 69-90 ◽  
Author(s):  
Xiuxiang Lü ◽  
Weiwei Jiao ◽  
Xinyuan Zhou ◽  
Jianjiao Li ◽  
Hongfeng Yu ◽  
...  
Keyword(s):  
Tarim Basin ◽  
Oil And Gas ◽  
Carbonate Reservoirs ◽  
Source Rocks ◽  
Western China ◽  
Hydrocarbon Accumulation ◽  
Upper Ordovician ◽  
Marine Carbonate ◽  
Marine Source ◽  
Tazhong Uplift

Diverse types of marine carbonate reservoirs have been discovered in the Tazhong Uplift, Tarim Basin, and late alteration of such reservoirs is obvious. The marine source rocks of the Cambrian-lower Ordovician and the middle-upper Ordovician provided abundant oil and gas for hydrocarbon accumulation. The hydrocarbons filled various reservoirs in multiple stages to form different types of reservoirs from late Caledonian to early Hercynian, from late Hercynian to early Indosininan and from late Yanshanian to Himalayan. All these events greatly complicated hydrocarbon accumulation. An analysis of the discovered carbonate reservoirs in the Tazhong Uplift indicated that the development of a reservoir was controlled by subaerial weathering and freshwater leaching, sedimentation, early diagenesis, and alteration by deep fluids. According to the origin and lateral distribution of reservoir beds, the hydrocarbon accumulation zones in the Tazhong area were identified as: karsted reservoirs, reef/bank reservoirs, dolomite interior reservoirs, and hydrothermal reservoirs. Such carbonate hydrocarbon accumulation zones are distributed mainly in specific areas of the Tazhong uplift, respectively. Because of differences in the mechanism of reservoir formation, the reservoir space, capability, type and distribution of reservoirs are often different in different carbonate hydrocarbon accumulation zones.

scholarly journals Kinematic partitioning in the Southern Andes (39° S–46° S) inferred from lineament analysis and reassessment of exhumation rates

2021 ◽  
Author(s):  
Paul Leon Göllner ◽  
Jan Oliver Eisermann ◽  
Catalina Balbis ◽  
Ivan A. Petrinovic ◽  
Ulrich Riller
Keyword(s):  
Fault Zone ◽  
Vertical Displacement ◽  
Strike Slip ◽  
Structural Studies ◽  
Southern Andes ◽  
Plate Convergence ◽  
Exhumation Rates ◽  
Lineament Analysis ◽  
Dextral Strike Slip ◽  
Data Call

AbstractThe Southern Andes are often viewed as a classic example for kinematic partitioning of oblique plate convergence into components of continental margin-parallel strike-slip and transverse shortening. In this regard, the Liquiñe-Ofqui Fault Zone, one of Earth’s most prominent intra-arc deformation zones, is believed to be the most important crustal discontinuity in the Southern Andes taking up margin-parallel dextral strike-slip. Recent structural studies, however, are at odds with this simple concept of kinematic partitioning, due to the presence of margin-oblique and a number of other margin-parallel intra-arc deformation zones. However, knowledge on the extent of such zones in the Southern Andes is still limited. Here, we document traces of prominent structural discontinuities (lineaments) from the Southern Andes between 39° S and 46° S. In combination with compiled low-temperature thermochronology data and interpolation of respective exhumation rates, we revisit the issue of kinematic partitioning in the Southern Andes. Exhumation rates are maximal in the central parts of the orogen and discontinuity traces, trending predominantly N–S, WNW–ESE and NE–SW, are distributed across the entire width of the orogen. Notably, discontinuities coincide spatially with large gradients in Neogene exhumation rates and separate crustal domains characterized by uniform exhumation. Collectively, these relationships point to significant components of vertical displacement on these discontinuities, in addition to horizontal displacements known from published structural studies. Our results agree with previously documented Neogene shortening in the Southern Andes and indicate orogen-scale transpression with maximal vertical extrusion of rocks in the center of the transpression zone. The lineament and thermochronology data call into question the traditional view of kinematic partitioning in the Southern Andes, in which deformation is focused on the Liquiñe-Ofqui Fault Zone.

Deep fluids and their role in hydrocarbon migration and oil deposit formation exemplified by supercritical СO2

2021 ◽  
pp. 1-11
Author(s):  
Sara LIFSHITS
Keyword(s):  
Supercritical Fluid ◽  
Oil And Gas ◽  
Gas Permeability ◽  
Sedimentary Rocks ◽  
Source Rocks ◽  
Reservoir Properties ◽  
Hydrocarbon Migration ◽  
Geological Processes ◽  
Before And After ◽  
Oil Source

ABSTRACT Hydrocarbon migration mechanism into a reservoir is one of the most controversial in oil and gas geology. The research aimed to study the effect of supercritical carbon dioxide (СО2) on the permeability of sedimentary rocks (carbonates, argillite, oil shale), which was assessed by the yield of chloroform extracts and gas permeability (carbonate, argillite) before and after the treatment of rocks with supercritical СО2. An increase in the permeability of dense potentially oil-source rocks has been noted, which is explained by the dissolution of carbonates to bicarbonates due to the high chemical activity of supercritical СО2 and water dissolved in it. Similarly, in geological processes, the introduction of deep supercritical fluid into sedimentary rocks can increase the permeability and, possibly, the porosity of rocks, which will facilitate the primary migration of hydrocarbons and improve the reservoir properties of the rocks. The considered mechanism of hydrocarbon migration in the flow of deep supercritical fluid makes it possible to revise the time and duration of the formation of gas–oil deposits decreasingly, as well as to explain features in the formation of various sources of hydrocarbons and observed inflow of oil into operating and exhausted wells.

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