scholarly journals Analysis of accumulation models of Middle Permian in Northwest Sichuan Basin

2021 ◽  
Vol 24 (4) ◽  
pp. 419-428
Author(s):  
Bin Li ◽  
Qiqi Li ◽  
Wenhua Mei ◽  
Qingong Zhuo ◽  
Xuesong Lu
Keyword(s):  
Source Rock ◽  
Lower Cambrian ◽  
Sichuan Basin ◽  
Oil And Gas ◽  
Source Rocks ◽  
Middle Permian ◽  
Maturity Stage ◽  
High Porosity ◽  
Hydrocarbon Accumulation ◽  
Gas Accumulation

Great progress has been made in middle Permian exploration in Northwest Sichuan in recent years, but there are still many questions in understanding the hydrocarbon accumulation conditions. Due to the abundance of source rocks and the multi-term tectonic movements in this area, the hydrocarbon accumulation model is relatively complex, which has become the main problem to be solved urgently in oil and gas exploration. Based on the different tectonic backgrounds of the middle Permian in northwest Sichuan Basin, the thrust nappe belt, the hidden front belt, and the depression belt are taken as the research units to comb and compare the geologic conditions of the middle Permian reservoir. The evaluation of source rocks and the comparison of hydrocarbon sources suggest that the middle Permian hydrocarbon mainly comes from the bottom of the lower Cambrian and middle Permian, and the foreland orogeny promoted the thermal evolution of Paleozoic source rocks in northwest Sichuan to high maturity and over maturity stage. Based on a large number of reservoir physical properties data, the middle Permian reservoir has the characteristics of low porosity and low permeability, among which the thrust nappe belt and the hidden front belt have relatively high porosity and relatively developed fractures. The thick mudstone of Longtan formation constitutes the regional caprock in the study area and the preservation condition is good as a whole. However, the thrusting faults destroyed the sealing ability of the caprock in the nappe thrust belt. Typical reservoir profiles revealed that the trap types were different in the study area. The thrust fault traps are mainly developed in the thrust nappe belt, while the fault anticline traps are developed in the hidden front belt, and the structural lithological traps are developed in the depression belt. The different structural belts in northwest Sichuan have different oil and gas accumulation models, this paper built three hydrocarbon accumulation models by the analysis of reservoir formation conditions. The comprehensive analysis supposed the hidden front belt is close to the lower Cambrian source rock, and the reservoir heterogeneity is weak, faults connected source rock is developed, so it is a favorable oil and gas accumulation area in the middle Permian. 

scholarly journals Basic characteristics and accumulation mechanism of Sinian−Cambrian giant highly mature and oil-cracking gas reservoirs in the Sichuan Basin, SW China

2017 ◽  
Vol 36 (4) ◽  
pp. 568-590 ◽  
Author(s):  
Bing Luo ◽  
Yu Yang ◽  
Gang Zhou ◽  
Wenjun Luo ◽  
Shujiao Shan ◽  
...  
Keyword(s):  
Natural Gas ◽  
Lower Cambrian ◽  
Sichuan Basin ◽  
Large Scale ◽  
Oil And Gas ◽  
Source Rocks ◽  
Burial Depth ◽  
Sw China ◽  
Accumulation Mechanism ◽  
Oil Cracking

Old Mesoproterozoic−Cambrian successions have been regarded as an important frontier field for global oil and gas exploration in the 21st century. This has been confirmed by a recent natural gas exploration breakthrough in the Sinian and Cambrian strata, central Sichuan Uplift, Sichuan Basin of SW China. However, the accumulation mechanism and enrichment rule of these gases have not been well characterized. This was addressed in this work, with aims to provide important guidance for the further exploration while enriching the general studies of the oil and gas geology in the old Mesoproterozoic–Cambrian strata. Results show that the gas field in the study area is featured by old target layers (Sinian–Lower Cambrian), large burial depth (>4500 m), multiple gas-bearing intervals (the second and fourth members of the Sinian Dengying Formation and the Lower Cambrian Longwangmiao Formation), various gas reservoir types (structural type and structural–lithologic type), large scale (giant), and superimposing and ubiquitous distribution. The giant reserves could be attributed to the extensive intercalation of pervasive high quality source rocks and large-scale karst reservoirs, which enables a three-dimensional hydrocarbon migration and accumulation pattern. The origin of natural gas is oil cracking, and the three critical stages of accumulation include the formation of oil reservoirs in Triassic, the cracking of oil in Cretaceous, and the adjustment and reaccumulations in the Paleogene. The main controlling factor of oil and gas enrichment is the inherited development of large-scale stable paleo-uplift, and the high points in the eastern paleo-uplift are the favorable area for ​natural gas exploration.

Controlling Factors of Hydrocarbon Accumulation in Talaha-Changjiaweizi Area

2013 ◽  
Vol 734-737 ◽  
pp. 1175-1178
Author(s):  
Hong Qi Yuan ◽  
Ying Hua Yu ◽  
Fang Liu
Keyword(s):  
Physical Properties ◽  
Oil And Gas ◽  
Controlling Factors ◽  
Source Rocks ◽  
Hydrocarbon Accumulation ◽  
Gas Migration ◽  
Main Controlling Factors ◽  
Sedimentary Microfacies ◽  
Plane Distribution ◽  
Distributary Channel

Based on the analysis of the relationships between the conditions of structures, sedimentations, source rocks, cap rocks, faults, oil and gas migration passages and traps and hydrocarbon accumulation, the controlling factors of hydrocarbon accumulation and distribution was studied in Talaha-changjiaweizi area. It is held that the source rocks control the hydrocarbon vertical distribution, the drainage capabilities control the hydrocarbon plane distribution, fracture belts control the hydrocarbon accumulation of Talaha syncline, underwater distributary channel is a favorable accumulation environment and reservoir physical properties control the oil and water distributions. Therefore, it is concluded that source rocks, fracture belts, sedimentary microfacies and reservoir physical properties are the main controlling factors of hydrocarbon accumulation and distribution in Talaha-changjiaweizi area.

scholarly journals GEOCHEMICAL AND GEOSTATISTICAL ASSESSMENT OF CRETACEOUS COALS AND SHALES IN SOME NIGERAIN SEDIMENTARY BASINS FOR THEIR HYDROCARBON PRONESS AND MATURITY LEVELS

2020 ◽  
Vol 1 (2) ◽  
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
Linear Regression Analysis ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Good Source ◽  
Type Iii ◽  
Limit Value ◽  
The Impact

The Rock–Eval pyrolysis and LECO analysis for 9 shale and 12 coal samples, as well as, geostatistical analysis have been used to investigate source rock characteristics, correlation between the assessed parameters (QI, BI, S1, S2, S3, HI, S1 + S2, OI, PI, TOC) and the impact of changes in the Tmax on the assessed parameters in the Cretaceous Sokoto, Anambra Basins and Middle Benue Trough of northwestern, southeastern and northcentral Nigeria respectively. The geochemical results point that about 97% of the samples have TOC values greater than the minimum limit value (0.5 wt %) required to induce hydrocarbon generation from source rocks. Meanwhile, the Dukamaje and Taloka shales and Lafia/Obi coal are found to be fair to good source rock for oil generation with slightly higher thermal maturation. The source rocks are generally immature through sub-mature to marginal mature with respect to the oil and gas window, while the potential source rocks from the Anambra Basin are generally sub-mature grading to mature within the oil window. The analyzed data were approached statistically to find some relations such as factors, and clusters concerning the examination of the source rocks. These factors were categorized into type of organic matter and organic richness, thermal maturity and hydrocarbon potency. In addendum, cluster analysis separated the source rocks in the study area into two groups. The source rocks characterized by HI >240 (mg/g), TOC from 58.89 to 66.43 wt %, S1 from 2.01 to 2.54 (mg/g) and S2 from 148.94 to 162.52 (mg/g) indicating good to excellent source rocks with kerogen of type II and type III and are capable of generating oil and gas. Followed by the Source rocks characterized by HI <240 (mg/g), TOC from 0.94 to 36.12 wt%, S1 from 0.14 to 0.72 (mg/g) and S2 from 0.14 to 20.38 (mg/g) indicating poor to good source rocks with kerogen of type III and are capable of generating gas. Howeverr, Pearson’s correlation coefficient and linear regression analysis shows a significant positive correlation between TOC and S1, S2 and HI and no correlation between TOC and Tmax, highly negative correlation between TOC and OI and no correlation between Tmax and HI. Keywords- Cretaceous, Geochemical, Statistical, Cluster; Factor analyses.

Geochemical Inversion - A Modern Approach to Inferring Source-Rock Identity from Characteristics of Accumulated Oil and Gas

1993 ◽  
Vol 11 (3-4) ◽  
pp. 295-328 ◽  
Author(s):  
K.K. Bissada ◽  
L.W. Elrod ◽  
C.R. Robison ◽  
L.M. Darnell ◽  
H.M. Szymczyk ◽  
...  
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
Source Rocks ◽  
Specific Information ◽  
Modern Approach ◽  
Age Identity ◽  
Oil And Natural Gas ◽  
Architectural Constraints ◽  
Geologic Setting ◽  
Relative Migration

In recent years, petroleum geochemists have been re-focusing their efforts on developing practical means for inferring, from hydrocarbon chemistry and geologic constraints, the “provenance” of hydrocarbon accumulations, seeps or stains. This capability, referred to here as “Geochemical Inversion”, can be invaluable to the explorationist in deriving clues as to the character, age, identity, maturity and location of an accumulation's source rocks and evaluating a petroleum system's hydrocarbon supply volumetrics. Geochemical inversion is most useful where pertinent source-rock information may be absent because exploratory drilling focused strictly on structural highs and failed to penetrate the deeply buried, effective basinal source facies. Advances in chemical analysis technology over the last decade have facilitated the development of powerful geochemical methods for unravelling of complex chemistries of crude oil and natural gas at the molecular and subatomic levels to extract specific information on the hydrocarbons' source. Inferences on such factors as organic matter make-up, depositional environment, lithology, age and maturity of the source can frequently be drawn. These inferences, together with a sound analysis of the geologic and architectural constraints on the system, can supply clues as to the identity and location of the probable source sequence. This paper describes the principles underlying geochemical “inversion” and provides applications in exploration and exploitation settings. In addition, this paper demonstrates inversion of geochemical characteristics of migrated hydrocarbon fluids to specific attributes of the source. The paper also illustrates the use of systematic variations in fluid chemistry within a geologic setting to infer source location, degree of hydrocarbon mixing and relative migration distance.

scholarly journals 3D-Basin Modelling of the Lishui Sag: Research of Hydrocarbon Potential, Petroleum Generation and Migration

Energies ◽  
2019 ◽  
Vol 12 (4) ◽  
pp. 650 ◽  
Author(s):  
Jinliang Zhang ◽  
Jiaqi Guo ◽  
Jinshui Liu ◽  
Wenlong Shen ◽  
Na Li ◽  
...  
Keyword(s):  
Source Rock ◽  
Thermal Evolution ◽  
Vitrinite Reflectance ◽  
Three Dimensional ◽  
Source Rocks ◽  
Rock Properties ◽  
Hydrocarbon Generation ◽  
Hydrocarbon Accumulation ◽  
Southeastern Part ◽  
Petroleum Generation

The Lishui Sag is located in the southeastern part of the Taibei Depression, in the East China Sea basin, where the sag is the major hydrocarbon accumulation zone. A three dimensional modelling approach was used to estimate the mass of petroleum generation and accumulated during the evolution of the basin. Calibration of the model, based on measured maturity (vitrinite reflectance) and borehole temperatures, took into consideration two main periods of erosion events: a late Cretaceous to early Paleocene event, and an Oligocene erosion event. The maturation histories of the main source rock formations were reconstructed and show that the peak maturities have been reached in the west central part of the basin. Our study included source rock analysis, measurement of fluid inclusion homogenization temperatures, and basin history modelling to define the source rock properties, the thermal evolution and hydrocarbon generation history, and possible hydrocarbon accumulation processes in the Lishui Sag. The study found that the main hydrocarbon source for the Lishui Sag are argillaceous source rocks in the Yueguifeng Formation. The hydrocarbon generation period lasted from 58 Ma to 32 Ma. The first period of hydrocarbon accumulation lasted from 51.8 Ma to 32 Ma, and the second period lasted from 23 Ma to the present. The accumulation zones mainly located in the structural high and lithologic-fault screened reservoir filling with the hydrocarbon migrated from the deep sag in the south west direction.

Expression of the Colorado Mineral Belt in Upper Cretaceous Niobrara Formation Source Rock Maturity Data from the Denver Basin

2018 ◽  
Vol 55 (1) ◽  
pp. 19-52
Author(s):  
David Thul ◽  
Stephen Sonnenberg
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
Thermal Anomaly ◽  
Source Rocks ◽  
Niobrara Formation ◽  
Denver Basin ◽  
Bottom Hole ◽  
Mineral Belt ◽  
Colorado Mineral ◽  
Hydrocarbon Expulsion

New source rock maturity data along the Colorado Mineral Belt trend in the Denver Basin reveal that source rocks in the deepest portion of the basin range from the onset of oil generation to wet gas maturity across a distance of less than 30 miles along present day structure. Additionally, sampled rock core and cuttings along a northeast-southwest transect reveal that the Niobrara Formation is within the oil maturity window all the way to the Nebraska-Colorado border. The correlation of these analyses to an identified thermal anomaly demonstrate that maturity along these trends is affected by a historical increase in heat flow that can still be seen in the present-day bottom-hole temperatures. The identified maturity anomaly has significant implications for Niobrara prospectivity within the basin. Crossplotting, mapping, and numerical modeling show the onset of hydrocarbon maturity in the Niobrara is represented by 432 °C Tmax and that hydrocarbon expulsion occurs between 438 °C and 443 °C Tmax. In the Niobrara Formation of the Denver Basin there is a strong correlation between oil and gas shows, elevated bottom-hole temperatures (and thermal gradients), and geochemical maturity parameters. Through mapping of maturity and free hydrocarbon anomalies, more than 80% of the present day production can be predicted with source rock mapping.

scholarly journals Sequence stratigraphic features of the Middle Permian Maokou Formation in the Sichuan Basin and their controls on source rocks and reservoirs

2015 ◽  
Vol 2 (5) ◽  
pp. 421-429 ◽  
Author(s):  
Wang Su ◽  
Qingchun Jiang ◽  
Zhiyong Chen ◽  
Zecheng Wang ◽  
Hua Jiang ◽  
...  
Keyword(s):  
Sichuan Basin ◽  
Source Rocks ◽  
Middle Permian ◽  
Sequence Stratigraphic ◽  
The Sichuan Basin
Sign in / Sign up

Export Citation Format

Share Document