Evaluation of shale gas potential of Cambrian Jiulaodong Formation in Wei-201 well block in Sichuan Basin, China

2016 ◽  
Vol 4 (2) ◽  
pp. T123-T140 ◽  
Author(s):  
Julius Kwame Borkloe ◽  
Renfang Pan ◽  
Jineng Jin ◽  
Emmanuel Kwesi Nyantakyi ◽  
Jianghui Meng
Keyword(s):  
Organic Carbon ◽  
Carbon Content ◽  
Shale Gas ◽  
Sichuan Basin ◽  
Gas Storage ◽  
Source Rocks ◽  
Gas Content ◽  
Brittleness Index ◽  
Organic Carbon Content ◽  
Gas Potential

The Cambrian Jiulaodong Formation of the Wei-201 well block in the Sichuan Basin was investigated for shale gas potential. In the subsurface, the thermally mature formation attained a stable thickness of 234 m encompassing an area of approximately [Formula: see text] and representing a potential gas resource. The total gas content measurements from canistered samples was more than the estimated total gas storage capacity of the free gas, absorbed gas, and gas dissolved in water and in oil. The canister gas content ranged between 0.971 and [Formula: see text] and averaged [Formula: see text]. The average estimated gas in place was 2.5 billion cubic meters for the formation in the Weiyuan area. Reflectance measurements for thermal maturity range between 2.60% and 3.06% and average 2.84%. The results of our total organic carbon content (TOC) content analysis conducted on the core shale samples indicate that the TOC content of the formation ranges from 0.87% to 3.57% and averages 2.2%. The mineral composition of marine mudstone formation of the Jiulaodong shale is relatively consistent. Brittle mineral content increases with organic carbon content and is approximately 32%–43%, of which quartz content is 29%–40% with a very low amount of clay mineral as the mixed layer. The amount of illite-smectite ranges from 0% to 1% and the brittleness index range from 37% to 62% and average 57.1%. The Cambrian Jiulaodong Formation ha very good petroleum-source rock potential due to its average TOC content of greater than 2%, average canister gas content of [Formula: see text], good type I kerogen, high maturity with average 2.84% of source rocks that are characterized by a fairly high abundance of organic matter increasing from top to bottom and a large thickness of 234 m. Natural fractures, cracks, and pores developed in the Jiulaodong Formation also provide space for shale gas storage, and its average brittleness index is greater than 57%, which is good for fracability.

Logging Evaluation Method and its Application for Measuring the Total Organic Carbon Content in Shale

2014 ◽  
Vol 962-965 ◽  
pp. 51-54
Author(s):  
Zhi Feng Wang ◽  
Yuan Fu Zhang ◽  
Hai Bo Zhang ◽  
Qing Zhai Meng
Keyword(s):  
Organic Carbon ◽  
Total Organic Carbon ◽  
Shale Gas ◽  
Sichuan Basin ◽  
Evaluation Method ◽  
Organic Carbon Content ◽  
Geochemical Analysis ◽  
Data Logging ◽  
Longmaxi Formation ◽  
Sedimentary Structures

The acquisition of the total organic carbon (TOC) content mainly relies on the geochemical analysis and logging data. Due to geochemical analysis is restricted by coring and experimental analysis, so it is difficult to get the continuous TOC data. Logging evaluation method for measuring TOC is very important for shale gas exploration. This paper presents a logging evaluation method that the shale is segmented according to sedimentary structures. Sedimentary structures were recognized by core, thin section and scanning electron microscope. Taking Wufeng-Longmaxi Formation, Silurian, Muai Syncline Belt, south of Sichuan Basin as research object, the shale is divided into three kinds: massive mudstone, unobvious laminated mudstone, and laminated mudstone. TOC within each mudstone are calculated using GR, resistivity and AC logging data, and an ideal result is achieved. This method is more efficient, faster and the vertical resolution is higher than △logR method.

The Gas Content Characteristics of Nanopores Developed in a Normal Pressure Shale Gas Reservoir in Southeast Chongqing, Sichuan Basin, China

2021 ◽  
Vol 21 (1) ◽  
pp. 698-706
Author(s):  
Fangwen Chen ◽  
Qiang Zheng ◽  
Hongqin Zhao ◽  
Xue Ding ◽  
Yiwen Ju ◽  
...  
Keyword(s):  
Organic Carbon ◽  
Shale Gas ◽  
Normal Pressure ◽  
Gas Content ◽  
Organic Carbon Content ◽  
Gas Reservoir ◽  
Free Gas ◽  
Shale Gas Reservoir ◽  
Adsorbed Gas ◽  
Longmaxi Shale

To evaluate the gas content characteristics of nanopores developed in a normal pressure shale gas reservoir, the Py1 well in southeast Chongqing was selected as a case study. A series of experiments was performed to analyze the total organic carbon content, porosity and gas content using core material samples of the Longmaxi Shale from the Py1 well. The results show that the adsorbed gas and free gas content in the nanopores developed in the Py1 well in the normal pressure shale gas reservoir range from 0.46–2.24 m3/t and 0.27–0.83 m3/t, with average values of 1.38 m3/t and 0.50 m3/t, respectively. The adsorbed gas is dominant in the shale gas reservoir, accounting for 53.05–88.23% of the total gas with an average value of 71.43%. The Gas Research Institute (GRI) porosity and adsorbed gas content increase with increasing total organic carbon content. The adsorbed gas and free gas contents both increase with increasing porosity value, and the rate of increase in the adsorbed gas content with porosity is larger than that of free gas. Compared with the other five shale reservoirs in America, the Lower Silurian Longmaxi Shale in the Py1 well developed nanopores but without overpressure, which is not favorable for shale gas enrichment.

scholarly journals Geological models and controlling factors of gas content in marine–terrigenous shale in the Southern Qinshui Basin, China

2018 ◽  
Vol 37 (1) ◽  
pp. 375-393 ◽  
Author(s):  
Xiaowei Hou ◽  
Yanming Zhu ◽  
Zhenfei Jiang ◽  
Haitao Gao
Keyword(s):  
Organic Carbon ◽  
Total Organic Carbon ◽  
Carbon Content ◽  
Adsorption Capacity ◽  
Total Organic Carbon Content ◽  
Gas Content ◽  
Organic Carbon Content ◽  
Isothermal Adsorption ◽  
Free Gas ◽  
Adsorbed Gas

Geological prediction models for gas content in marine–terrigenous shale under the effects of reservoir characteristics and in situ geological conditions, were established using methane isothermal adsorption, high temperature/pressure methane isothermal adsorption, total organic carbon, X-ray diffraction, mercury porosimetry, porosity in net confining stress, and field desorption methods. Results indicated that the adsorption capacity of marine–terrigenous shale has a linearly positive correlation with total organic carbon content and maturity. Clay and quartz minerals are the two main components of inorganic minerals in marine–terrigenous shale, with an average content of 54.3% and 36.9%, respectively. Adsorption capacity of marine–terrigenous shale is slightly positive correlated with clay content, while it exponentially decreases with increasing quartz content. The effects of in situ temperature and reservoir pressure on adsorption capacity in marine–terrigenous shale are also significant. The adsorption capacity of marine–terrigenous shale shows a clear decreasing trend as temperature increases, while it increases with increasing reservoir pressure. The porosity of marine–terrigenous shale is characterized by highly stress-sensitive, decreasing exponentially with increasing effective stress, which results in a more complex occurrence of free gas in deep shale reservoirs. In addition, gas saturation for the shale samples was calculated based on the results of field desorption, after which geological prediction models of total gas, adsorbed gas, and free gas were established while considering the coupled effects. Adsorbed gas, free gas, and total gas content all initially increase as burial depth increases, and then eventually decrease. Adsorbed gas content and free gas content have a positive correlation with total organic carbon content and porosity, indicating that the total gas content at different burial depths is mainly controlled by the total organic carbon content and porosity.

scholarly journals Shale favorable area optimization in coal-bearing series: A case study from the Shanxi Formation in Northern Ordos Basin, China

2017 ◽  
Vol 36 (5) ◽  
pp. 1295-1309 ◽  
Author(s):  
Wei Guo ◽  
Weijun Shen ◽  
Shangwen Zhou ◽  
Huaqing Xue ◽  
Dexun Liu ◽  
...  
Keyword(s):  
Organic Matter ◽  
Organic Carbon ◽  
Total Organic Carbon ◽  
Shale Gas ◽  
Ordos Basin ◽  
Sedimentary Facies ◽  
Gas Content ◽  
Burial Depth ◽  
Organic Carbon Content ◽  
River Channels

Shales in the Well district of Yu 106 of the Shanxi Formation in the Eastern Ordos Basin is deposited in the swamp between delta plains, distributary river channels, natural levee, the far end of crevasse splay, and depression environments. According to organic geochemistry, reservoir physical property, gas bearing capacity, lithology experimental analysis, combined with the data of drilling, logging, testing and sedimentary facies, the reservoir conditions of shale gas and the distribution of an advantageous area in Shanxi Formation have been conducted. The results show that the total organic carbon content of the Shanxi Formation is relatively high, with an average content value of 5.28% in the segment 2 and 3.02% in segment 1, and the organic matter is mainly kerogen type II2 and III. The maturity of organic matter is high with 1.89% as the average value of Ro which indicates the superior condition for gas generation of this reservoir. The porosity of shales is 1.7% on average, and the average permeability is 0.0415 × 10−3 µm2. The cumulative thickness is relatively large, with an average of 75 m. Brittle mineral and clay content in shales are 49.9% and 50.1%, respectively, but the burial depth of shale is less than 3000 m. The testing gas content is relatively high (0.64 × 104 m3/d), which shows a great potential in commercial development. The total organic carbon of the segment 2 is higher than that of the segment 1, and it is also better than segment 1 in terms of gas content. Based on the thickness of shale and the distribution of sedimentary facies, it is predicted that the advantageous area of shale gas in the segment 2 is distributed in a striped zone along the northeast and the northsouth direction, which is controlled by the swamp microfacies between distributary river channels.

scholarly journals Geophysical Prediction Technology Based on Organic Carbon Content in Source Rocks of the Huizhou Sag, the South China Sea

2017 ◽  
Vol 24 (s2) ◽  
pp. 4-13 ◽  
Author(s):  
Wei Yang ◽  
Xiao-xing Gong ◽  
Fei-fei Peng
Keyword(s):  
Organic Carbon ◽  
Carbon Content ◽  
Linear Relationship ◽  
Assessment Method ◽  
Seismic Inversion ◽  
Source Rocks ◽  
Seismic Facies ◽  
Organic Carbon Content ◽  
Seismic Attribute ◽  
Regional Prediction

Abstract Due to the high exploration cost, limited number of wells for source rocks drilling and scarce test samples for the Total Organic Carbon Content (TOC) in the Huizhou sag, the TOC prediction of source rocks in this area and the assessment of resource potentials of the basin are faced with great challenges. In the study of TOC prediction, predecessors usually adopted the logging assessment method, since the data is only confined to a “point” and the regional prediction of the source bed in the seismic profile largely depends on the recognition of seismic facies, making it difficult to quantify TOC. In this study, we combined source rock geological characteristics, logging and seismic response and built the mathematical relation between quasi TOC curve and seismic data based on the TOC logging date of a single well and its internal seismic attribute. The result suggested that it was not purely a linear relationship that was adhered to by predecessors, but was shown as a complicated non-linear relationship. Therefore, the neural network algorithm and SVMs were introduced to obtain the optimum relationship between the quasi TOC curve and the seismic attribute. Then the goal of TOC prediction can be realized with the method of seismic inversion.

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