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.

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 A source rock evaluation of the Mesozoic Sediments of the Well Hyllebjerg-1 Danish Subbasin

1988 ◽  
Vol 9 ◽  
pp. 1-105
Author(s):  
Birthe J Schmidt
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Geothermal Gradient ◽  
Organic Content ◽  
Lower Jurassic ◽  
Source Rocks ◽  
Marginal Areas ◽  
Algal Material ◽  
Clay Formation ◽  
Promising Source

The source rock potential of Mesozoic sediments (cuttings) from the Hyllebjerg 1 well, Danish Subbasin, has been assessed using a number of different petrographical and organochemical methods. Upper Jurassic sediments (Bream Formation) equivalent to the principal source rocks of the North Sea graben structures (Kimmeridge Clay Formation and lateral equivalents) do not show similar prominent source rock characteristics in this well, although a higher proportion of algal material is observed. Sediments with the most promising source rock characteristics for liquid hydrocarbons were· detected mainly in the lower- Jurassic sequences of the upper Fjerritslev Format ion (F-4 and upper F-3 Member) and in one horizon in the Upper Cretaceous Vedsted Formation which showed a good quality composition and a relatively high content of organic matter. But these sediments may be excluded as actual source rocks in this well as maturity (assuming the threshold value near 0. 60 % R ) is first reached at approximately 8500' 0 depth i.e. at the top of the Gassum Formation (Upper Triassic/ Lower Jurassic). The conditions may only by slightly different off - structure is this area, as the F-4 and F-3 Member sequence according to seismic sections is found at approximately the same depth. But the depth to ( and the thickness of) the Fjerritslev Formation is increasing towards the SE into the rimsynclines of the saltdomes nearby. While sufficient maturity is reached in the deeper part of the well, no commercial accumulations of hydrocarbons were encountered. This is attributed to the mainly reworked, unfavourable type of organic matter and the generally decreasing organic content downwards in the well, approaching the lower 1 imi t for potential source rocks ( set at O, 5% TOC). However, generation and migration of small amounts of gaseous hydrocarbons from Gassum Formation sediments containing more humic-influenced organic matter with only minor reworking cannot generally be excluded either here or elsewhere in the basin. Some more attention should also be paid to the Vinding Formation sediments which contain some algae- ri eh ( Botryocous-type) oil-prone horizons of more favourable source rock conditions. Mature sediments are found at shallower depths ( 8500 ') in this well in the central part of the basin compared to the more marginal areas (8900') where a slightly higher geothermal gradient in Jiyllebjerg 1 ( 28°C/km uncorrected) is seen compared with the marginal areas (23.5°C/km uncorrected) away from the basinal depocenter. The basinal depocenter also has a higher heat flow.

AN EARLY CRETACEOUS SOURCE ROCK IN THE KENDREW TERRACE, DAMPIER SUB-BASIN?

1996 ◽  
Vol 36 (1) ◽  
pp. 477 ◽  
Author(s):  
S. Ryan-Grigor ◽  
C. M. Griffiths
Keyword(s):  
Source Rock ◽  
North Sea ◽  
Early Cretaceous ◽  
Late Jurassic ◽  
Large Scale ◽  
Free Water ◽  
Organic Content ◽  
Source Rocks ◽  
The North ◽  
Northern North Sea

The Early to Middle Cretaceous is characterised worldwide by widespread distribution of dark shales with high gamma ray readings and high organic contents defined as dark coloured mudrocks having the sedimentary, palaeoecological and geochemical characteristics associated with deposition under oxygen-deficient or oxygen-free bottom waters. Factors that contributed to the formation of the Early to Middle Cretaceous 'hot shales' are: rising sea-level, a warm equable climate which promoted water stratification, and large scale palaeogeographic features that restrict free water mixing. In the northern North Sea, the main source rock is the Late Jurassic to Early Cretaceous Kimmeridge Clay/Draupne Formation 'hot shale' which occurs within the Viking Graben, a large fault-bounded graben, in a marine environment with restricted bottom circulation and often anaerobic conditions. Opening of the basin during a major trans-gressive event resulted in flushing, and deposition of normal open marine shales above the 'hot shales'. The Late Callovian to Berriasian sediments in the Dampier Sub-basin are considered to have been deposited in restricted marine conditions below a stratified water column, in a deep narrow bay. Late Jurassic to Early Cretaceous marine sequences that have been cored on the North West Shelf are generally of moderate quality, compared to the high quality source rocks of the northern North Sea, but it should be noted that the cores are from wells on structural highs. The 'hot shales' are not very organic-rich in the northern Dampier Sub-basin and are not yet within the oil window, however seismic data show a possible reduction in velocity to the southwest in the Kendrew Terrace, suggesting that further south in the basin the shales may be within the oil window and may also be richer in organic content. In this case, they may be productive source rocks, analogous to the main source rock of the North Sea.

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.

A practical petrophysical model for a source rock play: The Mancos Shale

2017 ◽  
Vol 5 (3) ◽  
pp. T423-T435
Author(s):  
Jesús M. Salazar ◽  
Ron J. M. Bonnie ◽  
William W. Clopine ◽  
G. Eric Michael
Keyword(s):  
Source Rock ◽  
Water Saturation ◽  
Clay Content ◽  
Source Rocks ◽  
Crushed Rock ◽  
Organic Carbon Content ◽  
Hydrocarbon Generation ◽  
Niobrara Formation ◽  
Mancos Shale ◽  
Petrophysical Model

Recently, the focus in source rock exploration has moved from gas-rich to liquid-rich plays and warrants revisiting “bypassed” hydrocarbon charged source rocks, which were deemed uneconomic when first drilled. In North America’s oil fields, there are thousands of wells with different vintages of nuclear and electrical logs, yet these wells generally lack any advanced logs beyond the traditional triple combo. We have developed a workflow that uses a considerable amount of laboratory measurements made on crushed rock to upscale a petrophysical model based on a triple combo logging suite only. The model divides the field (laterally) in oil window and gas window fairways and (vertically) in petrophysical units. The remaining hydrocarbon generation potential is based on geochemical measurements, such as thermal maturity and total organic carbon content (TOC), from core and cuttings in the area. The petrophysical units reflect major geologic intervals with similar porosity and clay content. The workflow was sequentially built by correlating logs with core measurements, using TOC and maturity for organic matter, X-ray diffraction for mineralogy and grain density, porosity, and water saturation from fluids extraction, for volumetrics. The model is applied to the Mancos Shale (New Mexico, USA), a Cretaceous-age source rock, which includes the Niobrara Formation. The Mancos Shale has been penetrated in various fields while developing conventional sandstone reservoirs. The model is validated with measurements on a core recently acquired in the anticipated high-hydrocarbon-yield window. Petrophysical properties predicted from logs agree well with core measurements in blind tests, demonstrating the robustness of the model despite being based on a basic suite of logs and a simple deterministic approach. This model is now routinely used by the asset team as an automated workflow to generate fairway maps, locate sweet spots, and for landing lateral wells.

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>

A model for seismic velocity and attenuation in petroleum source rocks

Geophysics ◽  
2000 ◽  
Vol 65 (4) ◽  
pp. 1080-1092 ◽  
Author(s):  
José M. Carcione
Keyword(s):  
Pore Pressure ◽  
Source Rock ◽  
Seismic Velocity ◽  
Water Saturation ◽  
Transversely Isotropic ◽  
Source Rocks ◽  
Excess Pore Pressure ◽  
Quality Factors ◽  
Backus Averaging ◽  
Excess Pore

Petroleum source rock is modeled as a viscoelastic transversely isotropic medium composed of illite/smectite and organic matter. The wave velocities and attenuation of petroleum source rocks are obtained as a function of excess pore pressure, initial kerogen content, and water saturation. The model generalizes a previous approach based on a pure elastic formulation of Backus averaging and introduces the pressure effect and the presence of fluids (oil and water). The model allows the simulation of different maturation levels induced by pore‐pressure changes caused by the conversion of kerogen to oil. The higher the oil saturation, the higher the maturation level. Assuming that the source rock has a very low permeability, the excess pore pressure can be calculated as a function of the conversion factor. Then the bulk modulus and density of the kerogen/oil mixture are obtained with the Kuster and Toksöz model, assuming that oil is the inclusion in a kerogen matrix. Finally, Backus averaging of this mixture with the illite/smectite layers gives the complex stiffnesses of the transversely isotropic and anelastic medium. Computed P- and S-velocities and quality factors parallel to bedding are higher than those normal to bedding, with attenuation anisotropy higher than stiffness anisotropy. In particular, for the North Sea Kimmeridge Shale and at maximum anisotropy, P and S parallel velocities are approximately 0.7 km/s higher than the corresponding P and S normal velocities. The maximum attenuation and stiffness anisotropies are obtained for 18% and 30% volumetric kerogen content, respectively. Both velocities and quality factors decrease with increasing kerogen content at a given pore pressure. The decrease in wave velocity is 2 km/s for P-waves and 1 km/s for S-waves when kerogen increases from zero to 100%. Moreover, anisotropy increases and velocities decrease with increasing pore pressure, i.e., with higher kerogen‐to‐oil conversion. Finally, the presence of water affects the normal‐bedding velocity, i.e., higher water saturation implies lower velocities.

scholarly journals Petrophysical Analysis to Determine Reservoir and Source Rocks in Berau Basin, West Papua Waters

2020 ◽  
Vol 35 (1) ◽  
Author(s):  
Popy Dwi Indriyani ◽  
Asep Harja ◽  
Tumpal Bernhard Nainggolan
Keyword(s):  
Source Rock ◽  
Water Saturation ◽  
Effective Porosity ◽  
Source Rocks ◽  
Reservoir Rock ◽  
Petrophysical Analysis ◽  
Shale Volume ◽  
Clastic Sediments ◽  
Volume Porosity ◽  
West Papua

Berau Basin is assessed to have same potential in clastic sediments with Mesozoic and Paleozoic ages, where reservoirs and source rocks are similar to productive areas of hydrocarbons in Northwest Shield Australia. This study aims to identify the hydrocarbon prospect zones and potential rocks zones using petrophysical parameters, such as shale volume, porosity, water saturation and permeability. Petrophysical analysis of reservoir and source rock are carried out on three wells located in the Berau Basin, namely DI-1, DI-2 and DI-3 in Kembelangan and Tipuma Formation. Qualitative analysis shows that there are 4 reservoir rock zones and 4 source rock zones from thorough analysis of these three wells. Based on quantitative analysis of DI-1 well, it has an average shale volume (Vsh) 9.253%, effective porosity (PHIE) 20.68%, water saturation (Sw) 93.3% and permeability (k) 55.69 mD. DI-2 well’s average shale volume, effective porosity, water saturation and permeability values are 29.16%, 2.97%, 67.9% and 0.05 mD, respectively. In DI-3 well, average shale volume, effective porosity, water saturation and permeability values are 6.205%, 19.36%, 80.2% and 242.05 mD, respectively. From the reservoir zone of these three wells in Kembelangan Formation, there are no show any hydrocarbon prospect.

scholarly journals Lithium and Sr isotopic composition of salar deposits in the Central Andes across space and time: the Salar de Pozuelos, Argentina

2021 ◽  
Author(s):  
Anette Meixner ◽  
Ricardo N. Alonso ◽  
Friedrich Lucassen ◽  
Laura Korte ◽  
Simone A. Kasemann
Keyword(s):  
Source Rock ◽  
Chemical Weathering ◽  
Isotope Composition ◽  
Central Andes ◽  
Hydrothermal Systems ◽  
Source Rocks ◽  
Surface Chemical ◽  
Near Surface ◽  
Magmatic Arc ◽  
Puna Plateau

AbstractThe Central Andes of South America host the largest known lithium resources in a confined area, but the primary lithium sources of the salar deposits and the mobilisation process of lithium are still a matter of speculation. Chemical weathering at or near the surface and leaching in hydrothermal systems of the active magmatic arc are considered the two main mechanisms of Li extraction from the source rock. The lithium and strontium isotope composition of typical salar deposits offer insights into the processes on how Li brine deposits in Andean evaporites are formed. Data from the Salar de Pozuelos indicate near-surface chemical weathering in a cold and dry climate as the dominant mobilisation process of Li, with evaporation being responsible for the enrichment. The Cenozoic ignimbrites are the favoured source rock for the Li, with subordinate additions from the Palaeozoic basement. The identification of the source rocks is supported by radiogenic Nd and Pb and stable B isotope data from salar deposits. A comparison with other Li brine and salt deposits in the Altiplano-Puna Plateau and its western foothills places the Salar de Pozuelos as an endmember of Li solubilisation by chemical weathering with only minor hydrothermal mobilisation of Li.

Oil to Source Rock Correlation Using Biomarker Data Through Pattern Matching and Fingerprinting Analysis in “Kitkat” Field, Jabung Block, South Sumatra Basin

2020 ◽  
Author(s):  
S., R. Muthasyabiha
Keyword(s):  
Pattern Matching ◽  
Source Rock ◽  
Vitrinite Reflectance ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Maturity Level ◽  
Fingerprinting Analysis ◽  
Kerogen Type ◽  
Oil Characteristics ◽  
Biomarker Data

Geochemical analysis is necessary to enable the optimization of hydrocarbon exploration. In this research, it is used to determine the oil characteristics and the type of source rock candidates that produces hydrocarbon in the “KITKAT” Field and also to understand the quality, quantity and maturity of proven source rocks. The evaluation of source rock was obtained from Rock-Eval Pyrolysis (REP) to determine the hydrocarbon type and analysis of the value of Total Organic Carbon (TOC) was performed to know the quantity of its organic content. Analysis of Tmax value and Vitrinite Reflectance (Ro) was also performed to know the maturity level of the source rock samples. Then the oil characteristics such as the depositional environment of source rock candidate and where the oil sample develops were obtained from pattern matching and fingerprinting analysis of Biomarker data GC/GCMS. Moreover, these data are used to know the correlation of oil to source rock. The result of source rock evaluation shows that the Talangakar Formation (TAF) has all these parameters as a source rock. Organic material from Upper Talangakar Formation (UTAF) comes from kerogen type II/III that is capable of producing oil and gas (Espitalie, 1985) and Lower Talangakar Formation (LTAF) comes from kerogen type III that is capable of producing gas. All intervals of TAF have a quantity value from very good–excellent considerable from the amount of TOC > 1% (Peters and Cassa, 1994). Source rock maturity level (Ro > 0.6) in UTAF is mature–late mature and LTAF is late mature–over mature (Peters and Cassa, 1994). Source rock from UTAF has deposited in the transition environment, and source rock from LTAF has deposited in the terrestrial environment. The correlation of oil to source rock shows that oil sample is positively correlated with the UTAF.

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