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Assessment of organic carbon content (TOC) by geophysical logs has been a challenging task in the formation evaluation of shale gas. This research is conducted to estimate the unconventional hydrocarbon (shale-gas) potential of Talhar Shale in the Southern Indus Basin (SIB), Pakistan. In this study, total organic carbon content (%) was estimated through well logs by different methods and then correlated with well cuttings/core data to determine the best method for estimation of TOC content especially when well cuttings/core data are not available. The Talhar Shale’s thermal maturity, as well as the organic content, were assessed from geochemical analyses. Talhar Shale of Dangi-01 well has good to very good source potential whereas Chak7A-01 well has fair-good. According to Ven Krevalen cross-plot, Talhar Shale of Dangi-01 well has type III kerogen; it can only produce gas while Chak7A-01 has type II/III kerogen which produces both oil and gas. The TOC was estimated using two methods i.e., Schmoker’s and Hester’s and Multivariate Fitting methods. The estimated TOC is then correlated with well cuttings data and concluded that the Multivariate Fitting method is selected as an optimized method for estimation of TOC because it shows strong correlation values of 0.93 and 0.91 in both wells respectively for Talhar Shale SIB, Pakistan.

Around the globe, the organic rich shale has become an increasingly important hydrocarbon resource due to the rapid depletion of conventional hydrocarbon reservoirs. The successful exploration and production schemes for organic rich shale are based on reliable identification of major organic components and total porosity. Therefore it is mandatory to identify the organic content in terms of total organic carbon (TOC) content and total porosity in promising shale formations through indirect seismic data, which is usually the only available source of information in most exploration phases. This research paper is focused on quantifying the Talhar Shale (member of Lower Goru Formation) as an unconventional reservoir using model based inversion in Badin concession area located near Karachi, Pakistan. Model based inversion is applied for computation of total porosity and total organic carbon (TOC) content because it provide a greater bandwidth and detail of variation of the acoustic impedance over the study area. The empirical relation for Total Organic Carbon (TOC) content has been derived through Passey et al. (1990) technique using data from Zaur-Deep 01, while for porosity a simple relation between impedance and porosity is used. The TOC and porosity models indicate that the unconventional reservoir potential is significantly greater over the northern region while it tends to decrease towards the south-eastern area. [ABSTRACT FROM AUTHOR]

Total organic carbon (TOC) content of shale gas reservoir is an important parameter of shale gas assessment, and how to accurately determine the content of TOC is a key problem of shale gas exploration and development. The author used the Lower Silurian Longmaxi formation in Qianjiang area as the research object. Through the statistical analysis of TOC content testing of shale gas reservoir and drilling and logging data, the log response characteristics of TOC content were analyzed. Furthermore, the four logs which consist of volume density logging(DEN), gamma logging (GR) spontaneous potential logging(SP) and acoustic logging(AC) were selected optimally as the feature vector. Afterwards, the BP neural network prediction model of TOC content was established, the BP neural network algorithm was improved and the TOC content of Lower Silurian Longmaxi formation of two shale gas wells in Qianjiang area were predicted and compared. The results show that the BP neural network model based on logging parameters has strongly approximate nonlinearization, which can reflect the nonlinear relationship between the TOC content of shale gas reservoir and logging parameters. The error between prediction results and measured values is small,and the relative error is less than 10%. [ABSTRACT FROM AUTHOR]

Rock wettability is a key parameter determining fluids distributions and migrations in hydrocarbon reservoirs. In shale rocks, the widespread existence of organic matter and the significant variation of total organic carbon (TOC) content lead to huge uncertainty on shale wettability. Therefore, this work systematically examines the dependence of shale wettability on TOC content (ranging from 1.2 wt% to 20.05 wt%). Multiple relations were probed experimentally, namely: 1) the effect of TOC content on n-dodecane (n-C 12) contact angles for shale-methane (CH 4)-n-C 12 systems at 5 MPa and 50 °C; 2) the effect of TOC content on n-C 12 contact angles for shale-carbon dioxide (CO 2)-n-C 12 systems at 5 MPa and 50 °C; 3) the effect of TOC content on brine contact angles for shale-brine-n-C 12 systems at 0.1 MPa and 50 °C; 4) the effect of pressure (0.1 MPa–25 MPa), temperature (25 °C and 50 °C) and TOC content on brine contact angles for shale-CH 4 -brine systems. The results demonstrate that for shale-CH 4 -n-C 12 , shale-CO 2 -n-C 12 and shale-brine-n-C 12 systems, the affinity of n-C 12 to shale increases with increasing TOC content. However, for shale-CH 4 -brine systems, the affinity of CH 4 to shale increases firstly, then flatten out and afterwards increases again; while shale wettability shifted from water-wet to CH 4 -wet with TOC content increase. In addition, a larger pressure renders shale less hydrophilic while a higher temperature causes shale more hydrophilic. The temperature influence is reduced with TOC content increase. The results can aid in better understanding of shale wettability at reservoir conditions. • Effect of TOC on shale wettability is systematically investigated. • Wettability shift from hydrophilic to hydrophobic with increasing TOC. • At reservoir condition (e.g., 20 MPa and 50 °C), a CH 4 -wet behaviour was found for 20.05 wt% TOC shale. [ABSTRACT FROM AUTHOR]