scholarly journals Fracture characteristics from outcrops and its meaning to gas accumulation in the Jiyuan Basin, Henan Province, China

2020 ◽  
Vol 12 (1) ◽  
pp. 1309-1323
Author(s):  
Changyan Sun ◽  
Xianbo Su ◽  
Heng Yang ◽  
Feng Li
Keyword(s):  
Oil Shale ◽  
Vitrinite Reflectance ◽  
Second Phase ◽  
Burial Depth ◽  
Organic Carbon Content ◽  
Hydrocarbon Generation ◽  
Fracture Density ◽  
Gas Generation ◽  
Fracture Characteristics ◽  
Gas Accumulation

AbstractThe target Oil-Shale Member (TOSM) in the Upper Triassic Tanzhuang Formation in the Jiyuan Basin is about 140 m thick and its burial depth is generally between 3,000 and 7,000 m. This paper presents a study of fractures in outcrop analogs for the TOSM based on outcrop observations and experimental measurements. The role of fractures in gas accumulation in the Jiyuan Basin was also analyzed. Also, a workflow used in building discrete fracture models based on the outcrop observed data is described. Results show that the average total organic carbon content and vitrinite reflectance of the oil shale are 4.13 and 1.33%, respectively, with the organic matter type dominated by sapropel-humics (II1), indicating high potential for shale gas generation. Fracture characteristics showing mostly vertical or intersect the bedding at high angles, and partially unfilled. The fracture lengths and widths range from a few centimeters to several hundred meters, and 0.05 to 0.5 cm, respectively, and the average linear fracture density is 6.3 m. In addition, the average brittle-mineral content of the oil shale is 53.7%, indicating that the oil shale in the TOSM has strong fracability. The hydrocarbon generation occurred twice in the TOSM. The primary reservoir formed by the first hydrocarbon generation was destroyed by fractures and tectonic uplift, and partial hydrocarbon migrated to the Paleogene along the second-phase fractures to form a secondary reservoir. The gas formed by the second hydrocarbon generation was mainly migrated into the fracture network of the TOSM.

scholarly journals The characteristics of hydrocarbon generation, reserving performances of fine-grained rock, and preservation conditions of coal measure shale gas of an epicontinental sea basin: A case study of the Late Palaeozoic shale gas in the Huanghebei Area of Western Shandong

2018 ◽  
Vol 37 (1) ◽  
pp. 453-472 ◽  
Author(s):  
Ying Li ◽  
Zengxue Li ◽  
Huaihong Wang ◽  
Dongdong Wang
Keyword(s):  
Coal Seam ◽  
Shale Gas ◽  
Late Paleozoic ◽  
Organic Carbon Content ◽  
Hydrocarbon Generation ◽  
Average Content ◽  
Gas Generation ◽  
Geological Structures ◽  
Fine Grained ◽  
Western Shandong

In China, marine and land transitional fine-grained rocks (shale, mudstone, and so on) are widely distributed and are known to have large accumulated thicknesses. However, shale gas explorations of these types of rock have only recently been initiated, thus the research degree is very low. Therefore, this study was conducted in order to improve the research data regarding the gas accumulation theory of marine and continental transitional fine-grained rock, as well as investigate the shale gas generation potential in the Late Paleozoic fine-grained rock masses located in the Huanghebei Area of western Shandong Province. The hydrocarbon generation characteristics of the epicontinental sea coal measures were examined using sedimentology, petrography, geochemistry, oil and gas geology, tectonics, and combined experimental testing processes. The thick fine-grained rocks were found to have been deposited in the sedimentary environments of the tidal flats, barriers, lagoons, deltas, and rivers during the Late Paleozoic in the study area. The most typical fine-grained rocks were located between the No. 5 coal seam of the Shanxi Formation and the No. 10 coal seam of the Taiyuan Formation, with an average thickness of 84.8 m. These formations were mainly distributed in the western section of the Huanghebei Area. The total organic carbon content level of the fine-grained rock was determined to be 2.09% on average, and the higher content levels were located in the western section of the Huanghebei Area. The main organic matter types of the fine-grained rock were observed to be kerogen II, followed by kerogen III. The vitrinite reflectance ( Ro) of the fine-grained rock was between 0.72 and 1.25%, which indicated that the gas generation of the dark fine-grained rock was within a favorable range, and the maturity of the rock was mainly in a medium stage in the northern section of the Huanghebei Area. It was determined that the average content of brittle minerals in the fine-grained rock was 55.7%. The dissolution pores and micro-cracks were the dominating pores in the fine-grained rock, followed by intergranular pores and intercrystalline pores. It was also found that both the porosity and permeability of the fine-grained rock were very low in the study area. The desorption gas content of the fine-grained rock was determined to be between 0.986 and 4.328 m3/t, with an average content of 2.66 m3/t. The geological structures were observed to be simple in the western section of the Huanghebei Area, and the occurrence impacts on the shale gas were minimal. However, the geological structures were found be complex in the eastern section of the study area, which was unfavorable for shale gas storage. The depths of the fine-grained rock were between 414.05 and 1290.55 m and were observed to become increasingly deeper from the southwestern section to the northern section. Generally speaking, there were found to be good reservoir forming conditions and great resource potential for marine and continental transitional shale gas in the study area.

scholarly journals Thermal Maturation Regime Revisited in the Dongying Depression, Bohai Bay Basin, East China

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-17
Author(s):  
Haiping Huang ◽  
Hong Zhang ◽  
Zheng Li ◽  
Mei Liu
Keyword(s):  
Organic Geochemistry ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
East China ◽  
Burial Depth ◽  
Bohai Bay ◽  
Hydrocarbon Generation ◽  
Bohai Bay Basin ◽  
Dongying Depression ◽  
Hydrocarbon Maturation

To the accurate reconstruction of the hydrocarbon generation history in the Dongying Depression, Bohai Bay Basin, East China, core samples of the Eocene Shahejie Formation from 3 shale oil boreholes were analyzed using organic petrology and organic geochemistry methods. The shales are enriched in organic matter with good to excellent hydrocarbon generation potential. The maturity indicated by measured vitrinite reflectance (%Ro) falls in the range of 0.5–0.9% and increases with burial depth in each well. Changes in biomarker and aromatic hydrocarbon isomer distributions and biomarker concentrations are also unequivocally correlated with the thermal maturity of the source rocks. Maturity/depth relationships for hopanes, steranes, and aromatic hydrocarbons, constructed from core data indicate different well locations, have different thermal regimes. A systematic variability of maturity with geographical position along the depression has been illustrated, which is a dependence on the distance to the Tanlu Fault. Higher thermal gradient at the southern side of the Dongying Depression results in the same maturity level at shallower depth compared to the northern side. The significant regional thermal regime change from south to north in the Dongying Depression may exert an important impact on the timing of hydrocarbon maturation and expulsion at different locations. Different exploration strategies should be employed accordingly.

scholarly journals Deflating the shale gas potential of South Africa’s Main Karoo basin

2017 ◽  
Vol 113 (9/10) ◽  
Author(s):  
Michiel de Kock ◽  
Nicolas Beukes ◽  
Elijah Adeniyi ◽  
Doug Cole ◽  
Annette Götz ◽  
...  
Keyword(s):  
Organic Carbon ◽  
Total Organic Carbon ◽  
Shale Gas ◽  
Vitrinite Reflectance ◽  
Gas Content ◽  
Carbonaceous Shale ◽  
Organic Carbon Content ◽  
Hydrocarbon Generation ◽  
Developmental Potential ◽  
Karoo Basin

The Main Karoo basin has been identified as a potential source of shale gas (i.e. natural gas that can be extracted via the process of hydraulic stimulation or ‘fracking’). Current resource estimates of 0.4–11x109 m3 (13–390 Tcf) are speculatively based on carbonaceous shale thickness, area, depth, thermal maturity and, most of all, the total organic carbon content of specifically the Ecca Group’s Whitehill Formation with a thickness of more than 30 m. These estimates were made without any measurements on the actual available gas content of the shale. Such measurements were recently conducted on samples from two boreholes and are reported here. These measurements indicate that there is little to no desorbed and residual gas, despite high total organic carbon values. In addition, vitrinite reflectance and illite crystallinity of unweathered shale material reveal the Ecca Group to be metamorphosed and overmature. Organic carbon in the shale is largely unbound to hydrogen, and little hydrocarbon generation potential remains. These findings led to the conclusion that the lowest of the existing resource estimates, namely 0.4x109 m3 (13 Tcf), may be the most realistic. However, such low estimates still represent a large resource with developmental potential for the South African petroleum industry. To be economically viable, the resource would be required to be confined to a small, well-delineated ‘sweet spot’ area in the vast southern area of the basin. It is acknowledged that the drill cores we investigated fall outside of currently identified sweet spots and these areas should be targets for further scientific drilling projects.

scholarly journals Transformation of Oil Pools into Gas Pools as Results of Multiple Tectonic Events in Upper Sinian (Upper Neoproterozoic), Deep Part of Sichuan Basin, China

2011 ◽  
Vol 29 (6) ◽  
pp. 679-698 ◽  
Author(s):  
Shugen Liu ◽  
Chuan Qin ◽  
Lubomir Jansa ◽  
Wei Sun ◽  
Guozhi Wang ◽  
...  
Keyword(s):  
Natural Gas ◽  
Sichuan Basin ◽  
Hydrocarbon Generation ◽  
Petroleum Reservoir ◽  
Gas Generation ◽  
Accumulation Mode ◽  
Gas Accumulation ◽  
Tectonic Events ◽  
The Sichuan Basin ◽  
Upper Sinian

A center in the present paper is referred to as an area or region which may include one or more hydrocarbon accumulations. A hydrocarbon generation center is referred to as an area containing high quality source rock which was subjected to thermal maturation. A gas generation center is an area in which an oil pool or accumulation was present, and oil was thermally cracked to generate gas. A gas accumulation center is referred to as an area in which natural gas generated from cracked oil accumulated. A gas preservation center is referred to as an area or region where the present natural gas pool/pools is/are located. As one of the oldest petroleum reservoir rocks in the world, the upper Sinian Dengying Formation (Upper Proterozoic) in the Sichuan basin was deeply buried, and its paleo-oil pools (gas generation centers) underwent complex transformation into paleo-gas pools (gas accumulation centers) and the present gas pools (gas preservation centers) as a result of multiphase tectonic activities. The paleo oil pools (gas generation centers) were the main hydrocarbon sources of the paleo gas pools (gas accumulation centers), which were in turn the main sources of hydrocarbons for today's (remaining) gas pools (gas preservation centers). The key factor in the oil accumulation was the presence of rich hydrocarbon source rocks (hydrocarbon generation centers) in the Early Cambrian strata and a good seal development. Being controlled by the early tectonics and sedimentary development of the basin, the hydrocarbon generation centers appeared to have been stationary in space, while in time the other three centers (gas generation centers, gas accumulation centers and gas preservation centers) migrated as result of tectonic events in the basin. Therefore, the time-spatial relationships between these “three centers” (gas generation centers, gas accumulation centers and gas preservation centers) decides the final distribution of natural gas in the Sichuan basin. Relationship between generation, accumulation and preservation of hydrocarbons in the marine carbonates buried deeper than 4500 m in the Sichuan basin, can be separated into: (1) an accumulation mode with the “three centers” being superimposed; (2) an accumulation mode with “the preservation center” disintegrated; (3) an accumulation mode with the “three centers” migrated for a short distance; (4) a destruction mode with the preservation center lost. The natural gas exploration of the upper Sinian carbonate rocks in the Sichuan basin can be most successful where the “three centers” overlap, such as at the front area of the Micang Mountains, which could be the most promising area for the future gas exploration.

Characteristics of the Overpressure Resulted from Hydrocarbon Generation

2013 ◽  
Vol 295-298 ◽  
pp. 2707-2710
Author(s):  
Hai Yan Hu ◽  
Hui Wang
Keyword(s):  
Organic Matter ◽  
Oil And Gas ◽  
Vitrinite Reflectance ◽  
Junggar Basin ◽  
Hydrocarbon Generation ◽  
Sonic Velocity ◽  
Gas Generation

Overpressure is often encountered in the Jurassic tight sandstones in the central Junggar Basin. In this studt, a new mechanism of overpressure formation related to gas generation is proposed. Organic-rich mudstones have sonic velocity well-line reserves but their densities continue to increase in the over-compacted mudstone system resulting in the overpressure development during the conversion of the organic matter to oil and gas. The top of the overpressure zone correlates with the depth required for a large quantity of gas generation in which the vitrinite reflectance (Ro) is about 0.7%, showing that the overpressure in organic-rich mudstones is closely associated with gas generation.

scholarly journals Age, material source, and formation mechanism of bedding-parallel calcite beef veins: Case from the mature Eocene lacustrine shales in the Biyang Sag, Nanxiang Basin, China

2021 ◽  
Author(s):  
Ao Su ◽  
Paul D. Bons ◽  
Honghan Chen ◽  
Yue-xing Feng ◽  
Jian-xin Zhao ◽  
...  
Keyword(s):  
Organic Matter ◽  
Fluid Inclusion ◽  
Host Rock ◽  
Inductively Coupled Plasma ◽  
Driving Forces ◽  
Burial Depth ◽  
Organic Carbon Content ◽  
Gas Generation ◽  
Material Source ◽  
Vein Formation

The mechanisms leading to the formation of bedding-parallel calcite beef veins have been widely debated, with discussions centered on timing or burial depth of vein generation, source of the vein material, driving forces for vein initiation and widening, and growth direction and mechanism. To address these issues, a comprehensive study of drill core samples containing beef veins in the mature Eocene lacustrine Hetaoyuan Formation in the Biyang Sag, Nanxiang Basin, China was undertaken through a combination of microstructural observation, isotopic geochronological, geochemical, and fluid inclusion analyses, as well as basin modeling. X-ray diffraction and total organic carbon content analyses indicate that most of the beef veins accumulated in calcite-rich laminated shales with high organic matter contents. These beef veins yielded an absolute laser ablation−multi-collector−inductively coupled plasma−mass spectrometry U-Pb age of ca. 41.02 ± 0.44 Ma, which corresponds to a burial depth of 500−800 m. Such a shallow burial depth suggests that the full compaction and consolidation of sediments would not yet have been achieved, which is compatible with the following observations: (1) plastic deformation of shale laminae adjacent to the veins, and (2) a beef vein formation temperature of ∼59 °C derived from fluid-inclusion microthermometry. The radio-isotopic age of the beef veins is ∼1−3 m.y. younger than the stratigraphic age of the host rock (ca. 43.1 Ma) but earlier than the model-derived timing of oil generation (ca. 35.8 Ma) and tectonic extrusion (ca. 23.0−13.0 Ma). The beef vein formation predated bacterial sulfate reduction, as evidenced by crosscutting relationships with carbonate concretions, pyrite framboids, and apatite pellets. A two-stage formation model for these beef veins is proposed. When burial depth of laminated shales rich in organic matter and calcite reaches the methanogenic zone, overpressure triggered by biogenetic gas generation results in horizontal hydrofracturing, initiating cracks that act as gas expulsion pathways. Once all the generated gas has migrated, the opened fractures close again due to overburden load. The materials fed by pressure solution of host-rock calcite fractions then mobilized into the unhealed horizontal fractures by diffusion. Subsequently, by a force of crystallization, antitaxial, displacive growth of calcite fibers commenced, contemporaneous with fracture dilation, eventually leading to the formation of bedding-parallel beef veins.

scholarly journals A coal petrographic source rock evalution of the Rhaetic - Jurassic - Lower Cretaceous sediments of the B0rglum 1 and Uglev 1 wells, Denmark

1985 ◽  
Vol 33 ◽  
pp. 239-252
Author(s):  
Birthe J. Schmidt
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Lower Cretaceous ◽  
Plant Material ◽  
Vitrinite Reflectance ◽  
Border Zone ◽  
Salt Diapir ◽  
Organic Carbon Content ◽  
Hydrocarbon Generation ◽  
Hydrocarbon Source Rock

The Rhaetic - Jurassic - Lower Cretaceous sediments from the Børglum 1 and Uglev 1 wells have been investigated by coal petrographical methods to evaluate their hydrocarbon source rock potential. The methods include vitrinite reflectance analyses of maturity, optical qualitative rating of the composition of the dispersed organic matter in the sediments, along with an estimation of the total organic carbon content of the sediments. The composition of the sedimentary organic matter is highly influenced by the palaeogeographic conditions. In the Børglum 1 well the organic material is dominated by land-derived (mainly gas-prone) plant matter; this is also the case for the marine sediments due to introduction of plant material from the adjacent Fennoscandian Border Zone. The sediments in Uglev 1 also have a high content of terrestrial plant material, although there is more marine dominated (oil-prone) organic matter in the deposits of the Bream Formation. The most promising conditions tor generation of liquid hydrocarbons have been found in the Bream Formation in Uglev 1, but the investigated sediments are generally thermally immature, with a restricted potential tor hydrocarbon generation. The rank gradient for Uglev 1 (0.20 % Ro/km), which is situated over a deep-seated salt diapir is more than three times that of Børglum 1 (0.06 % Ro/km), which is placed more marginally in the Danish Subbasin. This is attributed to differences in the geothermal gradients (Børglum 1:19°C/km, Uglev 1: 32 and 37°C/km, uncorrected)

scholarly journals Clay Minerals and Organic Matter from Deeply Buried Ordovician-Silurian Shale in Western Iraq: Implications for Maturity and Hydrocarbon Generation

2020 ◽  
pp. 3006-3023
Author(s):  
Ali I. Al-Juboury ◽  
Mohammed A. Al-Haj ◽  
Adrian Hutton ◽  
Brian Jones
Keyword(s):  
Organic Matter ◽  
Clay Minerals ◽  
Mixed Layer ◽  
Oil And Gas ◽  
Vitrinite Reflectance ◽  
Hydrocarbon Generation ◽  
X Ray Diffraction ◽  
Gas Generation ◽  
X Ray ◽  
Organic Mineral

The present work is conducted on the Paleozoic (Ordovician) Khabour and the (Silurian) Akkas shales in the Akkas-1 well of western Iraq. The study is aiming to determine the implications of clay mineral transformation, organic mineral distribution and maturity of hydrocarbon generation, using X-ray diffraction (XRD), scanning electron microscopy (SEM) in addition to organic matter concentrations. In the shale of the Khabour Formation, amorphous organic matter is common and includes various Tasmanite-type organic matter, vitrinite, inertinite, and bituminite. The main clay minerals observed include illite, chlorite, kaolinite, in addition to mixed-layer illite-smectite and rare smectite. In Silurian shale, high content of organic matter is recorded in addition to abundant vitrinite and low content of grainy organic matter (Tasmanites) and pyrite. Illite and kaolinite are commonly found in addition to chlorite and illite-smectite clay minerals. Conversion of smectite to mixed-layer illite-smectite (I-S) and an increase in vitrinite reflectance are commonly observed below 2500 m depth in the studied formations, which coincides with oil and gas generation. These results could be used as an indication of higher maturity and hydrocarbon generation in the deeply buried shale of the Khabour and Akkas formations in western Iraq.

Burial History Reconstruction of the Appalachian Basin in Kentucky, West Virginia, Pennsylvania, and New York, Using 1D Petroleum System Models

2019 ◽  
Vol 56 (4) ◽  
pp. 365-396
Author(s):  
Debra Higley ◽  
Catherine Enomoto
Keyword(s):  
New York ◽  
Vitrinite Reflectance ◽  
Structural Complexity ◽  
Appalachian Basin ◽  
Source Rocks ◽  
Burial History ◽  
Gas Generation ◽  
Deep Basin ◽  
Utica Shale ◽  
Wet Gas

Nine 1D burial history models were built across the Appalachian basin to reconstruct the burial, erosional, and thermal maturation histories of contained petroleum source rocks. Models were calibrated to measured downhole temperatures, and to vitrinite reflectance (% Ro) data for Devonian through Pennsylvanian source rocks. The highest levels of thermal maturity in petroleum source rocks are within and proximal to the Rome trough in the deep basin, which are also within the confluence of increased structural complexity and associated faulting, overpressured Devonian shales, and thick intervals of salt in the underlying Silurian Salina Group. Models incorporate minor erosion from 260 to 140 million years ago (Ma) that allows for extended burial and heating of underlying strata. Two modeled times of increased erosion, from 140 to 90 Ma and 23 to 5.3 Ma, are followed by lesser erosion from 5.3 Ma to Present. Absent strata are mainly Permian shales and sandstone; thickness of these removed layers increased from about 6200 ft (1890 m) west of the Rome trough to as much as 9650 ft (2940 m) within the trough. The onset of oil generation based on 0.6% Ro ranges from 387 to 306 Ma for the Utica Shale, and 359 to 282 Ma for Middle Devonian to basal Mississippian shales. The ~1.2% Ro onset of wet gas generation ranges from 360 to 281 Ma in the Utica Shale, and 298 to 150 Ma for Devonian to lowermost Mississippian shales.

scholarly journals Fluid inclusions in buried quartz of the Yanchang sandstone in the Jiyuan area, Ordos Basin, China: Implications for basin evolution and petroleum accumulation

2020 ◽  
pp. 014459872097451
Author(s):  
Wenqi Jiang ◽  
Yunlong Zhang ◽  
Li Jiang
Keyword(s):  
Fluid Inclusions ◽  
Ordos Basin ◽  
Homogenization Temperature ◽  
Burial Depth ◽  
Hydrocarbon Generation ◽  
Rock Interaction ◽  
Yanchang Formation ◽  
Reflection Data ◽  
And Migration ◽  
Vitrinite Reflection

A fluid inclusion petrographic and microthermometric study was performed on the sandstones gathered from the Yanchang Formation, Jiyuan area of the Ordos Basin. Four types of fluid inclusions in quartz can be recognized based on the location they entrapped. The petrographic characteristics indicate that fluid inclusions in quartz overgrowth and quartz fissuring-I were trapped earlier than that in quartz fissuring-IIa and fissuring-IIb. The homogenization temperature values of the earlier fluid inclusions aggregate around 80 to 90°C; exclusively, it is slightly higher in Chang 6 member, which approaches 95°C. The later fluid inclusions demonstrate high homogenization temperatures, which range from 100 to 115°C, and the temperatures are slightly higher in Chang 9 member. The calculated salinities show differences between each member, including their regression characteristics with burial depth. Combining with the vitrinite reflection data, the sequence and parameters of fluid inclusions indicate that the thermal history of the Yanchang formation mostly relied on burial. Salinity changes were associated with fluid-rock interaction or fluid interruption. Hydrocarbon contained fluid inclusions imply that hydrocarbon generation and migration occurred in the Early Cretaceous. The occurrence of late fluid inclusions implied that quartz cement is a reservoir porosity-loose factor.

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