How Organic Carbon Content and Thermal Maturity Affect Acoustic Properties (and Ultimately Seismic Response) in a Shale Gas/Oil Formation: Woodford Shale, Permian Basin

2019 ◽  
Author(s):  
Nicholas B. Harris ◽  
Al Moghadam ◽  
Tian Dong
Keyword(s):  
Organic Carbon ◽  
Seismic Response ◽  
Shale Gas ◽  
Acoustic Properties ◽  
Organic Carbon Content ◽  
Thermal Maturity ◽  
Gas Oil ◽  
Permian Basin ◽  
Woodford Shale ◽  
Oil Formation

The effects of organic carbon content and thermal maturity on acoustic parameters in a black shale: Woodford Shale, Permian Basin, West Texas

Geophysics ◽  
2019 ◽  
Vol 84 (6) ◽  
pp. D231-D248 ◽  
Author(s):  
Nicholas B. Harris ◽  
Al Moghadam ◽  
Tian Dong
Keyword(s):  
Organic Matter ◽  
Organic Carbon ◽  
Physical Properties ◽  
P Wave ◽  
Thermal Maturity ◽  
S Wave ◽  
Permian Basin ◽  
Woodford Shale ◽  
Load Bearing ◽  
Core Samples

We have derived relationships between organic carbon and acoustic properties in the Woodford Shale, an Upper Devonian organic-rich shale in the Permian Basin, Texas. Extensive core data enable us to relate measured total organic carbon (TOC) on core samples to gamma log response; in turn, gamma log-calculated TOC is compared with P-wave [Formula: see text] and S-wave [Formula: see text] velocities, density, and derivative properties including [Formula: see text], Young’s modulus, Poisson’s ratio, [Formula: see text], and [Formula: see text]. Because we sampled two wells at very different thermal maturity (early oil window and wet gas window), we can examine the effect of thermal maturity on these parameters. In both wells, [Formula: see text] and [Formula: see text] decrease with increasing TOC, exhibiting a rapid decrease from 0% to approximately 1.5% TOC, and a slower decrease above 1.5% TOC, similar to results from ultrasonic experiments on core samples, that we attribute to a shift from a mineral grain load-bearing to an organic matter load-bearing fabric. The [Formula: see text] decreases by 28% and [Formula: see text] by 20% over the range of 0.5%–12% TOC. [Formula: see text] and [Formula: see text] correlate more strongly to neutron porosity than to TOC in the less mature well, related to the development of a bitumen phase that is relatively soft and less dense and has greater impact on rock physical properties than kerogen; this effect disappears in the high-maturity well in which bitumen was further cracked to petroleum and physical properties of bitumen changed with increased aromatization. The effect of increased thermal maturity is to increase [Formula: see text] by approximately 12%, [Formula: see text] by 25%, and P-wave impedance by 12%. [Formula: see text] ratios decrease with increasing TOC, contrary to the behavior expected for the incorporation of a soft material into a rock. We suggest that the rock develops a horizontal planar fabric at lower TOC values that absorbs S-wave energy, counteracting the effect of the organic matter.

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 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.

Mathematical modeling for total organic carbon content prediction with logging parameters by neural networks: A case study of shale gas well in South China

2019 ◽  
Vol 7 (2) ◽  
pp. T283-T292 ◽  
Author(s):  
Huang Yanran ◽  
Xiao Zhenhui ◽  
Dong Li ◽  
Yu Ye ◽  
Cao Taotao
Keyword(s):  
Neural Networks ◽  
Organic Carbon ◽  
Total Organic Carbon ◽  
South China ◽  
Shale Gas ◽  
Error Function ◽  
Principal Component ◽  
Black Shales ◽  
Organic Carbon Content ◽  
Back Propagation Algorithm

The lower Cambrian Niutitang Formation in northwestern Hunan, South China, has already reached its high or over matured stage and is formed with hydrothermal activity and deposition. Thus, it is extremely difficult to predict the total organic carbon (TOC) content accurately by common methods with well-logging data. To solve this problem, we use artificial neural networks for predicting the TOC of the black shales in our study case. We got the input vectors through principal component analysis and based on the relationships and the logging response mechanism between TOC and logging data. In the back-propagation algorithm, some important parameters including the sample databases, the number of hidden layer nodes, transfer function, and weight value adjustment were all optimized correctly in the networks. Then, we built the mathematical model through a large number of learning sample datum and the error function between the actual and expected outputs, and we found that the results are good according to many performance indicators. In testing samples, mean absolute and relative errors are all reduced probably due to the datum ranges and features being focused, but the accuracy also drops when the numbers of participating samples are reduced. Through redefining the [Formula: see text] sample database, we gained more accurate values for the high-TOC source rock. Finally, we think that the results suggest that the method is suitable for shale gas resource exploration under similar geologic conditions and data characteristics.

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.

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.

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