scholarly journals Differential Thermal Evolution between Oil and Source Rocks in the Carboniferous Shale Reservoir of the Qaidam Basin, NW China

Energies ◽  
2021 ◽  
Vol 14 (21) ◽  
pp. 7088
Author(s):  
Qianru Wang ◽  
Haiping Huang ◽  
Chuan He ◽  
Zongxing Li
Keyword(s):  
Crude Oil ◽  
Thermal Evolution ◽  
Qaidam Basin ◽  
Vitrinite Reflectance ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Gas Chromatography Mass Spectrometry ◽  
Thermal Maturity ◽  
Maturity Level ◽  
Shale Reservoir

Shale oil and source rock samples of the Carboniferous Keluke Formation from well Chaiye 2 in the Delingha Depression were analyzed by gas chromatography–mass spectrometry. Source rocks were highly mature at the gas generation stage with vitrinite reflectance (Ro) of 1.45–1.88%. However, the oil produced from the shale reservoir was characterized by abundant biomarkers but low abundance of diamondoid hydrocarbons with estimated Ro of ca. 0.78%, indicating hydrocarbons were still at a relatively low thermal maturity level. As the crude oil was generated and accumulated autochthonously, preliminary results indicate that crude oil and source rocks witnessed differential thermal evolution and significant disparity of the current thermal maturity in the shale reservoir due to rapid tectonic subsidence and clay mineral catalysts that accelerated the thermal maturation process. Although tectonic uplifts occurred afterwards, the vitrinite recorded the highest maturity that source rocks have ever reached, whereas the oil has not reached the same maturity level due to less impact from thermal alteration or mineral catalysis than source rocks in the shale reservoir. Such a discovery enlarges the hydrocarbon perseveration of maturity ranges in reservoirs, particularly for the unconventional tight formation, and benefits potential hydrocarbon exploration from highly mature sediments.

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.

Evidence from the Changing Carbon Isotopic of Kerogen, Oil, and Gas during Hydrous Pyrolysis from Pinghu Formation, the Xihu Sag, East China Sea Basin

Energies ◽  
2021 ◽  
Vol 14 (24) ◽  
pp. 8317
Author(s):  
Qiang Cao ◽  
Jiaren Ye ◽  
Yongchao Lu ◽  
Yang Tian ◽  
Jinshui Liu ◽  
...  
Keyword(s):  
Carbon Isotopes ◽  
Oil And Gas ◽  
Thermal Evolution ◽  
Vitrinite Reflectance ◽  
Heating Time ◽  
Source Rocks ◽  
Evolution Process ◽  
Carbon Isotopic ◽  
Hydrous Pyrolysis ◽  
Increasing Temperature

Semi-open hydrous pyrolysis experiments on coal-measure source rocks in the Xihu Sag were conducted to investigate the carbon isotope evolution of kerogen, bitumen, generated expelled oil, and gases with increasing thermal maturity. Seven corresponding experiments were conducted at 335 °C, 360 °C, 400 °C, 455 °C, 480 °C, 525 °C, and 575 °C, while other experimental factors, such as the heating time and rate, lithostatic and hydrodynamic pressures, and columnar original samples were kept the same. The results show that the simulated temperatures were positive for the measured vitrinite reflectance (Ro), with a correlation coefficient (R2) of 0.9861. With increasing temperatures, lower maturity, maturity, higher maturity, and post-maturity stages occurred at simulated temperatures (Ts) of 335–360 °C, 360–400 °C, 400–480 °C, and 480–575 °C, respectively. The increasing gas hydrocarbons with increasing temperature reflected the higher gas potential. Moreover, the carbon isotopes of kerogen, bitumen, expelled oil, and gases were associated with increased temperatures; among gases, methane was the most sensitive to maturity. Ignoring the intermediate reaction process, the thermal evolution process can be summarized as kerogen0(original) + bitumen0(original)→kerogenr (residual kerogen) + expelled oil (generated) + bitumenn+r (generated + residual) + C2+(generated + residual) + CH4(generated). Among these, bitumen, expelled oil, and C2-5 acted as reactants and products, whereas kerogen and methane were the reactants and products, respectively. Furthermore, the order of the carbon isotopes during the thermal evolution process was identified as: δ13C1 < 13C2-5 < δ13Cexpelled oil < δ13Cbitumen < δ13Ckerogen. Thus, the reaction and production mechanisms of carbon isotopes can be obtained based on their changing degree and yields in kerogen, bitumen, expelled oil, and gases. Furthermore, combining the analysis of the geochemical characteristics of the Pinghu Formation coal–oil-type gas in actual strata with these pyrolysis experiments, it was identified that this area also had substantial development potential. Therefore, this study provides theoretical support and guidance for the formation mechanism and exploration of oil and gas based on changing carbon isotopes.

STABLE HYDROGEN ISOTOPE RATIOS OF SEDIMENTARY HYDROCARBONS: A POTENTIAL METHOD FOR ASSESSING THERMAL MATURITY?

2005 ◽  
Vol 45 (1) ◽  
pp. 253
Author(s):  
D. Dawson ◽  
K. Grice ◽  
R. Alexander
Keyword(s):  
Vitrinite Reflectance ◽  
Potential Method ◽  
Source Rocks ◽  
Crude Oils ◽  
Thermal Maturity ◽  
Peak Oil ◽  
Data Set ◽  
High Maturity ◽  
The Difference ◽  
Hydrogen Isotope Ratios

A relationship has been identified between the maturity level of source rocks and the stable hydrogen isotopic compositions (δD) of extracted saturated hydrocarbons, based on the analysis of nine sediments and five crude oils from the Perth Basin (WA). The sediments cover the immature to late mature range. Distinct δD signatures are observed for the immature sediments where pristane and phytane are significantly depleted in deuterium (D) relative to the n-alkanes. With increasing maturity the difference between the δD values of n-alkanes and isoprenoids reduces as pristane and phytane become progressively enriched in D. The n-alkane–isoprenoid δD signature of the crude oils, including one from a different source facies, is similar to mature–late mature sediments representative of the peak oil–generative window. Enrichment of D in isoprenoids is attributed to isotopic exchange associated with thermal maturation. Average δD values of pristane and phytane correlate well with vitrinite reflectance, as does the biomarker maturity parameter Ts/Tm. The limited data set suggests that δD values of aliphatic hydrocarbons may be useful for establishing thermal maturity, particularly when other maturity parameters are not appropriate. Furthermore, we suggest δD values may be useful over a wider maturity range than traditional parameters, particularly at very high maturity where biomarker parameters are no longer effective.

scholarly journals Organic geochemical and palynological studies of the Maastrichtian source rock intervals in Bida Basin, Nigeria: implications for hydrocarbon prospectivity

2020 ◽  
Vol 10 (8) ◽  
pp. 3191-3206
Author(s):  
Olusola J. Ojo ◽  
Ayoola Y. Jimoh ◽  
Juliet C. Umelo ◽  
Samuel O. Akande
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
High Yield ◽  
Thermal Maturity ◽  
Hydrocarbon Source Rock ◽  
Moderate Amount ◽  
Oxic Condition ◽  
Freshwater Swamp

Abstract The Patti Formation which consists of sandstone and shale offers the best potential source beds in the Bida Basin. This inland basin is one of the basins currently being tested for hydrocarbon prospectivity in Nigeria. Fresh samples of shale from Agbaja borehole, Ahoko quarry and Geheku road cut were analysed using organic geochemical and palynological techniques to unravel their age, paleoecology, palynofacies and source bed hydrocarbon potential. Palynological data suggest Maastrichtian age for the sediments based on the abundance of microfloral assemblage; Retidiporites magdalenensis, Echitriporites trianguliformis and Buttinia andreevi. Dinocysts belonging to the Spiniferites, Deflandrea and Dinogymnium genera from some of the analysed intervals are indicative of freshwater swamp and normal sea conditions. Palynological evidence further suggests mangrove paleovegetation and humid climate. Relatively high total organic carbon TOC (0.77–8.95 wt%) was obtained for the shales which implies substantial concentration of organic matter in the source beds. Hydrocarbon source rock potential ranges from 0.19 to 0.70 mgHC/g.rock except for a certain source rock interval in the Agbaja borehole with high yield of 25.18 mgHC/g.rock. This interval also presents exceptionally high HI of 274 mgHC/g.TOC and moderate amount of amorphous organic matter. The data suggests that in spite of the favourable organic matter quantity, the thermal maturity is low as indicated by vitrinite reflectance and Tmax (0.46 to 0.48 Ro% and 413 to 475 °C, respectively). The hydrocarbon extracts show abundance of odd number alkanes C27–C33, low sterane/hopane ratio and Pr/Ph > 2. We conclude that the source rocks were terrestrially derived under oxic condition and dominated by type III kerogen. Type II organic matter with oil and gas potential is a possibility in Agbaja area of Bida Basin. Thermal maturity is low and little, or no hydrocarbon has been generated from the source rocks.

scholarly journals Penggunaan Parameter Geokimia Isoprenoid untuk Menentukan Tingkat Kematangan Minyak Bumi (Crude Oil) Sumur Minyak Langgak Riau

2015 ◽  
pp. 70-73 ◽  
Author(s):  
Emrizal Mahidin Tamboesai
Keyword(s):  
Crude Oil ◽  
Thermal Maturity ◽  
Maturity Level ◽  
Carbon Preference Index ◽  
Preference Index ◽  
Petroleum Wells ◽  
Saturated Fraction ◽  
Area Determination

In this study, crude oil samples from Distric Langgak, Riau were tested and characterized with isoprenoid parameters. Determination of thermal maturity level aims to determine the feasibility of petroleum wells to be exploited because there are many new wells of petroleum unexploited in the Riau area. Determination of maturity crude oil performed by analysis saturated fractions. Saturated fraction of the wells Langgak used to determine the maturity of crude oil based on parameters isoprenoid, n-alkane and carbon preference index were analyzed using gas chromatography-flame ionize detector (GC-FID). Based on the value Pr / Ph, Pr / n-C17, Ph / n-C18 and its CPI, the maturity level of petroleum from oil wells, Langgak levels of maturity and quality of the oil is indicated by the value of Pr / Ph (2.27), the value of Pr / n-C17 (0.57), the value of Ph / n-C18 (0.22) and the CPI (1.087) respectively.DOI :http://dx.doi.org/10.15408/jkv.v0i0.3142

scholarly journals 3D-Basin Modelling of the Lishui Sag: Research of Hydrocarbon Potential, Petroleum Generation and Migration

Energies ◽  
2019 ◽  
Vol 12 (4) ◽  
pp. 650 ◽  
Author(s):  
Jinliang Zhang ◽  
Jiaqi Guo ◽  
Jinshui Liu ◽  
Wenlong Shen ◽  
Na Li ◽  
...  
Keyword(s):  
Source Rock ◽  
Thermal Evolution ◽  
Vitrinite Reflectance ◽  
Three Dimensional ◽  
Source Rocks ◽  
Rock Properties ◽  
Hydrocarbon Generation ◽  
Hydrocarbon Accumulation ◽  
Southeastern Part ◽  
Petroleum Generation

The Lishui Sag is located in the southeastern part of the Taibei Depression, in the East China Sea basin, where the sag is the major hydrocarbon accumulation zone. A three dimensional modelling approach was used to estimate the mass of petroleum generation and accumulated during the evolution of the basin. Calibration of the model, based on measured maturity (vitrinite reflectance) and borehole temperatures, took into consideration two main periods of erosion events: a late Cretaceous to early Paleocene event, and an Oligocene erosion event. The maturation histories of the main source rock formations were reconstructed and show that the peak maturities have been reached in the west central part of the basin. Our study included source rock analysis, measurement of fluid inclusion homogenization temperatures, and basin history modelling to define the source rock properties, the thermal evolution and hydrocarbon generation history, and possible hydrocarbon accumulation processes in the Lishui Sag. The study found that the main hydrocarbon source for the Lishui Sag are argillaceous source rocks in the Yueguifeng Formation. The hydrocarbon generation period lasted from 58 Ma to 32 Ma. The first period of hydrocarbon accumulation lasted from 51.8 Ma to 32 Ma, and the second period lasted from 23 Ma to the present. The accumulation zones mainly located in the structural high and lithologic-fault screened reservoir filling with the hydrocarbon migrated from the deep sag in the south west direction.

GEOCHEMICAL CHARACTERISTICS AND SOURCE OF CHANG 8 CRUDE OIL IN THE EAST PART OF SHANBEI SLOPE, ORDOS BASIN, CHINA

2021 ◽  
pp. 1-31
Author(s):  
Zhenglu Xiao ◽  
Shijia Chen ◽  
Xiangdong Yin ◽  
Pan Wang ◽  
Jiang Zhu ◽  
...  
Keyword(s):  
Crude Oil ◽  
Source Rock ◽  
Higher Plants ◽  
Saturated Hydrocarbon ◽  
Vitrinite Reflectance ◽  
Sedimentary Environment ◽  
Ordos Basin ◽  
Aquatic Organisms ◽  
Source Rocks ◽  
East Part

There are three sets of potential source rocks in the Yanchang Formation in the east part of the Shanbei Slope in the Ordos Basin. Based on the experimental results of total organic carbon, vitrinite reflectance, rock organic matter extraction, and saturated hydrocarbon chromatography (GC-MS), we have analyzed the geochemical and biomarker characteristics of the Chang 7, Chang 8, and Chang 9 source rocks, and the Chang 8 reservoir extracts and find that the Chang 7, Chang 8, and Chang 9 source rocks were deposited in the sedimentary environment of weak oxidation and weak reduction. Higher plants contribute more in the parent materials of the Chang 7 and Chang 9 source rocks, whereas lower aquatic organisms contribute more to the Chang 8 source rock. However, the source of the Chang 8 crude oil in the east part of Shanbei Slope does not match the chemical fingerprint of the Chang 8 source rock. To address this problem, we examined samples taken from the Zhidan oilfield, where our results show that the Chang 7, Chang 8, and Chang 9 source rocks all have hydrocarbon-supplying capacity. The relative abundance of regular steranes (C27, C28, C29) and hopane (17α(H), 21β(H)-hopane, 17β(H)-rearranged hopane, 18α(H)-22,29,30-trinorhopane) provides a means to assign the crude oil components to a given. Further analysis of the biomarkers of the three source rocks and those of the Chang 8 crude oil indicate that crude oil in the Chang 8 reservoir was not generated in situ; rather, it was supplied by the underlying Chang 9 source rock.

scholarly journals Backtracking to Parent Maceral from Produced Bitumen with Raman Spectroscopy

Minerals ◽  
2020 ◽  
Vol 10 (8) ◽  
pp. 679
Author(s):  
Seyedalireza Khatibi ◽  
Arash Abarghani ◽  
Kouqi Liu ◽  
Alexandra Guedes ◽  
Bruno Valentim ◽  
...  
Keyword(s):  
Raman Spectroscopy ◽  
Organic Matter ◽  
Vitrinite Reflectance ◽  
Thermal Maturity ◽  
Maturity Level ◽  
Production Potential ◽  
Hydrocarbon Production ◽  
Solid Bitumen ◽  
Rock Eval ◽  
Oil Gas

In order to assess a source rock for economical exploitation purposes, many parameters should be considered; regarding the geochemical aspects, the most important ones are the amount of organic matter (OM) and its quality. Quality refers to the thermal maturity level and the type of OM from which it was formed. The origin of the OM affects the ability of the deposited OM between sediments to generate oil, gas, or both with particular potential after going through thermal maturation. Vitrinite reflectance and programmed pyrolysis (for instance, Rock-Eval) are common methods for evaluating the thermal maturity of the OM and its potential to generate petroleum, but they do not provide us with answers to what extent solid bitumen is oil-prone or gas-prone, as they are bulk geochemical methods. In the present study, Raman spectroscopy (RS), as a powerful tool for studying carbonaceous materials and organic matter, was conducted on shale and coal samples and their individual macerals to show the potential of this technique in kerogen typing and to reveal the parent maceral of the examined bitumen. The proposed methodology, by exhibiting the chemical structure of different organic matters as a major secondary product in unconventional reservoirs, can also detect the behavior of solid bitumen and its hydrocarbon production potential for more accurate petroleum system evaluation.

scholarly journals Burial history, thermal history and hydrocarbon generation modelling of the Jurassic source rocks in the basement of the Polish Carpathian Foredeep and Outer Carpathians (SE Poland)

2012 ◽  
Vol 63 (4) ◽  
pp. 335-342 ◽  
Author(s):  
Paweł Kosakowski ◽  
Magdalena Wróbel
Keyword(s):  
Organic Matter ◽  
Thermal History ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Thermal Maturity ◽  
Burial History ◽  
Se Poland ◽  
Carpathian Foredeep ◽  
Outer Carpathians

Burial history, thermal history and hydrocarbon generation modelling of the Jurassic source rocks in the basement of the Polish Carpathian Foredeep and Outer Carpathians (SE Poland)Burial history, thermal maturity, and timing of hydrocarbon generation were modelled for the Jurassic source rocks in the basement of the Carpathian Foredeep and marginal part of the Outer Carpathians. The area of investigation was bounded to the west by Kraków, to the east by Rzeszów. The modelling was carried out in profiles of wells: Będzienica 2, Dębica 10K, Góra Ropczycka 1K, Goleszów 5, Nawsie 1, Pławowice E1 and Pilzno 40. The organic matter, containing gas-prone Type III kerogen with an admixture of Type II kerogen, is immature or at most, early mature to 0.7 % in the vitrinite reflectance scale. The highest thermal maturity is recorded in the south-eastern part of the study area, where the Jurassic strata are buried deeper. The thermal modelling showed that the obtained organic matter maturity in the initial phase of the "oil window" is connected with the stage of the Carpathian overthrusting. The numerical modelling indicated that the onset of hydrocarbon generation from the Middle Jurassic source rocks was also connected with the Carpathian thrust belt. The peak of hydrocarbon generation took place in the orogenic stage of the overthrusting. The amount of generated hydrocarbons is generally small, which is a consequence of the low maturity and low transformation degree of kerogen. The generated hydrocarbons were not expelled from their source rock. An analysis of maturity distribution and transformation degree of the Jurassic organic matter shows that the best conditions for hydrocarbon generation occurred most probably in areas deeply buried under the Outer Carpathians. It is most probable that the "generation kitchen" should be searched for there.

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