TOC Prediction Using Delta Log Resistivity, and Its Distribution in Cyclostratigraphy-INPEFA Trend in “S-Field”, Kutai Basin”

2021 ◽  
Author(s):  
B. B. S. Kembuan
Keyword(s):  
Sea Level ◽  
Source Rock ◽  
Gamma Ray ◽  
Organic Content ◽  
Carbon Accumulation ◽  
High Resistivity ◽  
Geochemical Analysis ◽  
Reservoir Rocks ◽  
Geological Conditions ◽  
Potential Source Rock

S field has unique geological conditions, with a depth of maturity around 800 meters based on geochemical analysis and classified as the shallowest in the Kutai Basin compared to other fields of around 4000 meters. This is caused by this field's geological conditions, which are influenced by the tectonic gravitational force from the north and the lifting of the middle Miocene formation from below. The study aims to have better understanding on the petroleum system using the ∆ Log R to analyse the source rock, to be integrated with the Cyclostratigraphy-INPEFA log to discover which cyclic deposition trend has the higher TOC (total organic carbon) accumulation. Determining the potential source rock with the rich TOC would help the finding of a new prospect reservoir for conventional or unconventional development. ∆ Log R is a practical method for predicting TOC and depth, applied in many fields with success stories. The research focuses on TOC prediction on a delta plain environment with abundant coal source rock using sonic, density, and neutron logs as porosity logs. Because most of the Organic Content is found in Non-Reservoir Rocks, Reservoir Rocks needs to eliminate Log-Gamma Ray as a lithological interpretation. Mature Organic Rocks with a high TOC value and excellent porosity will show high resistivity; this is because Kerogen, which is dominant in shale, validates this TOC prediction for geochemical analysis. Cyclostratigraphy-INPEFA log is generated from a particular formula based on cyclic deposition concept that refers to the orbital change that affects earth insolation. The phenomena cause the sea-level change (eustasy). When the sea level drops (cooling phase), the coarse sediment will be deposited., Whereas the finer sediment will be deposited when the sea-level rises (warming phase). This study shows that predicted TOC accumulation is much higher in the warming phase.

Identification and Distribution of Lower Cretaceous Source Rocks in Ying’er Sag, Jiuquan Basin

2012 ◽  
Vol 616-618 ◽  
pp. 69-72
Author(s):  
Yi Bo Zhou ◽  
Guang Di Liu ◽  
Jia Yi Zhong
Keyword(s):  
Source Rock ◽  
Low Frequency ◽  
Sedimentary Facies ◽  
Organic Content ◽  
Source Rocks ◽  
Potential Source Rock ◽  
Wide Range ◽  
Strong Amplitude ◽  
System Tracts ◽  
High Organic Content

Based on the sequence stratigraphy study, the relation between dark mudstone ratio and sedimentary facies in different system tracts is observed and used to forcast the distribution of dark mudstones in the main formation combining with seismic data and well log. However, not all dark mudstones can generate hydrocarbon, so the source rock quality is quoted to calculate the thickness of the source rock within mudstone. The results show that the favored source rock in lake progressive system tracts and the bottom of highstand system tracts of Xiagou Formation and Chijinpu Formation are related to a group of reflectors with medium-strong amplitude, medium-low frequency and medium to comparatively good lateral continuity. The source rock of Xiagou Formation with high organic content and wide-range distribution is the major hydrocarbon source in Ying’er Sag, while Chijinpu Formation with thick dark mudstones is the potential source rock and the target of the further exploration.

scholarly journals Potensi Shale Hydrocarcon Formasi Brown Shale, Cekungan Sumatra Tengah Berdasarkan Data Log Mekanik

2018 ◽  
Vol 2 (1) ◽  
pp. 43
Author(s):  
Sugeng Widada ◽  
Salatun Said ◽  
Hendaryono Hendaryono ◽  
Listriyanto Listriyanto
Keyword(s):  
Source Rock ◽  
Host Rock ◽  
Gamma Ray ◽  
Organic Content ◽  
Hydrocarbon Exploration ◽  
Good Potential ◽  
Shale Formation ◽  
Rich Material ◽  
Data Log ◽  
Central Sumatra

<p>Formasi Brown Shale merupakan batuan induk utama hidrokarbon di Cekungan Sumatra Tengah. Penelitian ini bertujuan mengevaluasi potensi formasi tersebut sebagai batuan induk hidrokarbon dan implikasinya dalam eksplorasi shale hydrocarbon berdasarkan data wireline log. Evaluasi yang dilakukan meliputi penentuan ona prospek (shale  play), evaluasi kandungan material organik (TOC) untuk mengetahui tingkat kekayaan batuan induk dan evaluasi tingkat kematangannya. Tiga sumur, Sumur Gamma, Jeta dan Kilo dievaluasi dengan menggunakan Metoda Passey (1990) dan Bowman (2010) . Log Gamma Ray, Resistivitas, Sonic, Netron dan Densitas digunakan dalam studi ini.Dari hasil analisis menunjukkan Formasi Brown Shale yang tertembus oleh ketiga sumur tersebut tersusun oleh perselingan batulempung dan batulanau yang mengindikasikan mempunyai prospek sebagai batuan induk dengan tingkat kekayaan material organik miskin sampai kaya dan telah mencapai tingkat kematangan hidrokarbon. Kandungan TOC pada Sumur Gamma berkisar antara 2-8%(kaya) dan tingkat kematangan minyak dicapai pada kedalaman 6550 ft. Kandungan TOC pada Sumur Jeta berkisar antara 0-7%(miskin-kaya) dan tingkat kematangan minyak dicapai pada kedalaman 8550 ft. Kandungan TOC pada Sumur Kilo berkisar antara 0-9%(miskin-kaya) dan tingkat kematangan minyak dicapai pada kedalaman 8100 ft.Berdasarkan hasil tersebut menunjukkan Formasi Brown Shale yang tertembus oleh ketiga sumur di daerah telitian mempunyai potensi yang baik sebagai batuan induk hidrokarbon dan shale hidrokarbon.</p><p><em>The Brown Shale Formation is the main hydrocarbon sourcerock in the Central Sumatra Basin. This study aims to evaluate the potential of these formations as hydrocarbon bedrock and their implications in shale hydrocarbon exploration based on wireline log data. The evaluation includes determining the prospect of shale play, evaluating the total organic content (TOC) to determine the level of source rock wealth and evaluating its level of maturity. Three wells, Gamma Well, Jeta and Kilo were evaluated using the Passey (1990) and Bowman (2010) method. Gamma Ray, Resistivity, Sonic, Neutron and Density logs were used in this study. From the results of the analysis showed that the Brown Shale Formation penetrated by the three wells was composed by claystone and siltstone intervals which indicated having prospects as a source rock with poor organic to rich material levels. and has reached the level of hydrocarbon maturity. The TOC content in the Gamma Well ranges from 2-8% (rich) and the level of oil maturity is reached at a depth of 6550 ft. The TOC content in the Jeta Well ranges from 0-7% (poor-rich) and the level of oil maturity is reached at a depth of 8550 ft. The TOC content in the Kilo Well ranges from 0-9% (poor-rich) and the level of oil maturity is reached at a depth of 8100 ft. Based on these results shows the Brown Shale Formation penetrated by the three wells in the study area has good potential as a hydrocarbon host rock and hydrocarbon shale.</em></p>

Miocene Turbidite Sequence as Potential Reservoir and Source Rock Of Mamberamo Basin: An Insight From Fieldwork in Metaweja Area, Central Mamberamo District, Papua

2021 ◽  
Author(s):  
D. T. Olua
Keyword(s):  
Source Rock ◽  
Organic Content ◽  
Reservoir Rock ◽  
Secondary Porosity ◽  
Fragment Composition ◽  
Deposition Mechanism ◽  
Gas Source ◽  
Calcareous Shale ◽  
Potential Source Rock ◽  
Potential Reservoir

The geology of the Metaweja area is characterized by the turbidite sequence which are deposited in the deep-sea environment during the Miocene and exposed to surface due to the latest deformation. The research was conducted to identify the potential source rock and reservoir rock within the turbidite deposits. In the study area, there are three types of rock units, calcareous shale units formed in the Late Miocene, Sandstone unit and interbedded siltstone-sandstone unit that were deposited in Middle Miocene. Measured section was carried out at the several stations in order to analyze the turbid current deposition mechanism. Measured section of the alternating unit of sandstone - siltstone are observed at several places where the unit has intercalation of shale, coal and iron oxide. Some syn-depositional sedimentary structure also found within this unit. The carbonate shale unit has good total organic content (TOC) ranging from 0.51wt% to 2.56wt%. Pyrolysis analysis has S2 value 1.31 mg/g to 1.34 mg/g, Hydrogen Index (HI) 35 mgHC/g to 49 mgHC/g, Oxygen Index (OI) 35 mgHC/g to 49 mgHC/g, Tmax 430 °C to 434 °C and Vitrinite Reflecteance index (Ro) 0.32% to 0.54%. The carbonate shale characterized as the type III kerogen which prone gas source rock and interpreted as immature to early mature source rock. The petrography analysis of alternating rocks of sandstone - siltstone has characteristics of sandstones with 44% of volcanic lithic fragment composition, 20% matrix 10% clay size fragments, secondary porosity reaches 10% and 13% cement carbonate calcite. Based on the petrography analysis, this unit could be interpreted as reservoir rock, although we need further analysis for the Permeability measurement.

scholarly journals Multimineral petrophysics of thermally immature Eagle Ford Group and Cretaceous mudstones, USGS Gulf Coast #1 research wellbore in central Texas

2021 ◽  
pp. 1-63
Author(s):  
Lauri A. Burke ◽  
Justin E. Birdwell ◽  
Stanley T. Paxton
Keyword(s):  
Source Rock ◽  
Gamma Ray ◽  
Water Saturation ◽  
Gulf Coast ◽  
Organic Content ◽  
Wellbore Stability ◽  
Source Rocks ◽  
Eagle Ford ◽  
Near Surface ◽  
Carbonate Cements

Traditional petrophysical methods to evaluate organic richness and mineralogy using gamma ray and resistivity log responses are not diagnostic in source rocks. This study presents a deterministic, non-proprietary method to quantify formation variability in total organic carbon (TOC) and three key mudrock mineralogical components of non-hydrocarbon bearing source rock strata of the Eagle Ford Group by developing a set of log-derived multimineral models calibrated with FTIR core data from the research borehole USGS Gulf Coast #1 West Woodway. This study determined bulk density response is a reliable indicator of organic content in these thermally immature, water-bearing source rocks.Multimineral findings indicate a high degree of laminae-scale mineralogical heterogeneity exists due to thinly interbedded carbonate cements amid clay-rich mudstone layers. The lower part of the Eagle Ford Group contains the highest average TOC content (4.7 wt%) and the highest average carbonate volume (64.1 vol%), making it the optimal target in thermally mature areas for source rock potential and hydraulic fracture placement. In contrast, the uppermost portion of the Eagle Ford Group contains the highest average volume of clay minerals (42.6 vol%), which increases the potential for wellbore stability issues. Petrophysical characterization reveals porosity is approximately 30% in this relatively uncompacted formation. In this thermally immature source rock, water saturation is nearly 100% and no free hydrocarbons were observed on the resistivity logs. No evidence of borehole ellipticity was observed on the three-arm caliper log, and horizontal stresses are presumed to be directionally uniform in the vicinity of this near-surface wellbore. This shallow wellbore has a temperature gradient of 1.87 ºF/100 ft (16.3 °C/km) and is likely influenced by Earth surface heating.

Sea-level rise enhances carbon accumulation in United States tidal wetlands

One Earth ◽  
2021 ◽  
Vol 4 (3) ◽  
pp. 425-433
Author(s):  
Ellen R. Herbert ◽  
Lisamarie Windham-Myers ◽  
Matthew L. Kirwan
Keyword(s):  
United States ◽  
Sea Level Rise ◽  
Sea Level ◽  
Carbon Accumulation ◽  
Tidal Wetlands

scholarly journals Source rock characterization of mesozoic to cenozoic organic matter rich marls and shales of the Eratosthenes Seamount, Eastern Mediterranean Sea

2018 ◽  
Vol 73 ◽  
pp. 49 ◽  
Author(s):  
Sebastian Grohmann ◽  
Susanne W. Fietz ◽  
Ralf Littke ◽  
Samer Bou Daher ◽  
Maria Fernanda Romero-Sarmiento ◽  
...  
Keyword(s):  
Organic Matter ◽  
Mediterranean Sea ◽  
Source Rock ◽  
Eastern Mediterranean ◽  
Source Rocks ◽  
Eastern Mediterranean Sea ◽  
Potential Source Rock ◽  
Levant Basin ◽  
Rock Characterization ◽  
Rock Eval

Several significant hydrocarbon accumulations were discovered over the past decade in the Levant Basin, Eastern Mediterranean Sea. Onshore studies have investigated potential source rock intervals to the east and south of the Levant Basin, whereas its offshore western margin is still relatively underexplored. Only a few cores were recovered from four boreholes offshore southern Cyprus by the Ocean Drilling Program (ODP) during the drilling campaign Leg 160 in 1995. These wells transect the Eratosthenes Seamount, a drowned bathymetric high, and recovered a thick sequence of both pre- and post-Messinian sedimentary rocks, containing mainly marine marls and shales. In this study, 122 core samples of Late Cretaceous to Messinian age were analyzed in order to identify organic-matter-rich intervals and to determine their depositional environment as well as their source rock potential and thermal maturity. Both Total Organic and Inorganic Carbon (TOC, TIC) analyses as well as Rock-Eval pyrolysis were firstly performed for the complete set of samples whereas Total Sulfur (TS) analysis was only carried out on samples containing significant amount of organic matter (>0.3 wt.% TOC). Based on the Rock-Eval results, eight samples were selected for organic petrographic investigations and twelve samples for analysis of major aliphatic hydrocarbon compounds. The organic content is highly variable in the analyzed samples (0–9.3 wt.%). TS/TOC as well as several biomarker ratios (e.g. Pr/Ph < 2) indicate a deposition under dysoxic conditions for the organic matter-rich sections, which were probably reached during sporadically active upwelling periods. Results prove potential oil prone Type II kerogen source rock intervals of fair to very good quality being present in Turonian to Coniacian (average: TOC = 0.93 wt.%, HI = 319 mg HC/g TOC) and in Bartonian to Priabonian (average: TOC = 4.8 wt.%, HI = 469 mg HC/g TOC) intervals. A precise determination of the actual source rock thickness is prevented by low core recovery rates for the respective intervals. All analyzed samples are immature to early mature. However, the presence of deeper buried, thermally mature source rocks and hydrocarbon migration is indicated by the observation of solid bitumen impregnation in one Upper Cretaceous and in one Lower Eocene sample.

Well Logging Data Interpretation in Oil and Gas Source Rock Sections Based on Complex Petrophysical and Geochemical Analysis Results

2018 ◽  
Author(s):  
Rais Khisamov ◽  
Natalya Skibitskaya ◽  
Kazimir Kovalenko ◽  
Venera Bazarevskaya ◽  
Nikita Samokhvalov ◽  
...  
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
Data Interpretation ◽  
Well Logging ◽  
Geochemical Analysis ◽  
Gas Source

scholarly journals SEDIMENTOLOGICAL AND GEOCHEMICAL ANALYSIS OF MIOCENE DEPOSITS IN MOSCHOPOTAMOS AREA, IN THE WESTERN PART OF AXIOS-THERMAIKOS BASIN, NW GREECE

2017 ◽  
Vol 50 (1) ◽  
pp. 374
Author(s):  
V. Savva ◽  
P. Tserolas ◽  
A. Maravelis ◽  
N. Bourli ◽  
A. Zelilidis
Keyword(s):  
Organic Matter ◽  
Organic Content ◽  
Sieve Analysis ◽  
Organic Carbon Content ◽  
Geochemical Analysis ◽  
Aegean Area ◽  
Sedimentary Characteristics ◽  
The North ◽  
Caco3 Content ◽  
North Aegean

A total of 27 samples of the Moschopotamos area lignite-bearing strata were studied in regard of their geochemical and sedimentary characteristics. Organic content and calcium carbonate evaluation, sieve analysis and micropaleontological observations were used and combined to investigate the paleoenvironment and the depositional conditions of the study area. TOC analysis showed that organic matter values range from 0.07% up to 13.42% with an average of ~3.26 %. The high average of organic carbon content indicates a promising basis for the sediments’ source rock potential, inquiring further and thorough examination. CaCO3 measurements present a range between 4% and 23%. A comparison between TOC-CaCO3 content throughout the stratigraphic column presented certain synchronous and inverse trends, due to alterations of the depositional conditions. This study provides new insights for the understanding of the broader Axios-Thermaikos basin, and depositional conditions in the North Aegean area.

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