Source rock evaluation of shale intervals of the Kurra Chine Formation, Kurdistan Region-Iraq: An organic geochemical and basin modeling approach

Edilbi, Ayad N. F.; Kolo, Kamal; Muhammed, Nechirvan R.; Yasin, Salman R.; Mamaseni, Wrya J.; Akram, Revan

doi:10.1016/j.ejpe.2019.06.003

Cited by 12 publications

(8 citation statements)

References 7 publications

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“…The organic carbon richness of the rock samples (TOC %), is important in the examination of sediments as a source for petroleum. Tissot and Welte [26][27][28][29][30][31][32][33][34] presented a scale for the assessment of source rocks potency, based on the TOC% and Rock-Eval pyrolysis data, such as S1 and S2. The procured data set in Table 1 show that the total organic carbon content values for the northwestern Sokoto Basin source rocks are between 0.94 and 7.00 wt % indicating fair to good source rocks.…”

Section: Quality and Quantity Of Organic Mattermentioning

confidence: 99%

“…According to [26,34,[45][46][47][48][49], the generation of petroleum from the organic matter during its burial history is a part of the overall process of thermal metamorphism of organic matter. The concentration and distribution of hydrocarbons inhibited in a particular source rely on both the type of the organic matter and its degree of thermal alteration [26,29,31,33,34,42]. In the present study, the thermal maturity level of the source rocks has been unraveled by the examination of the geochemical parameters as Rock-Eval pyrolysis ''Tmax'', production index ''PI'' [36,50].…”

Section: Thermal Maturationmentioning

confidence: 99%

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Integrated Geochemical and Multivariate Statistical Examination of Source Rocks in the Sokoto and Anambra Basins, Nigeria: Implications for Hydrocarbon Prospectivity

Adamu¹,

Obaje²,

Ngozi³

et al. 2020

PSE

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The LECO and Rock-Eval pyrolysis for 7 shale and 3 coal samples, as well as, multivariate statistical analysis have been used to probe source rock characteristics, correlation between the assessed parameters (S1, S2, S3, HI, S1 + S2, OI, PI, TOC) and the impact of changes in the Tmax on the assessed parameters in the Sokoto Basin and Anambra Basin of northwestern and southeastern Nigeria respectively. The geochemical results show that 93% of the samples have TOC values greater than the minimum limit value (0.5 wt %) required to induce hydrocarbon generation from source rocks. Meanwhile, the Dukamaje and Taloka shales are found to be fair to good source rock for oil generation with slightly higher thermal maturation. The source rocks are generally immature through sub-mature to marginal mature with respect to the oil and gas window, while the potential source rocks from the Anambra Basin are generally sub-mature grading to mature within the oil window. The analyzed data were approached statistically to find some relations such as factors, and clusters concerning the examination of the source rocks. These factors were categorized into type of organic matter and organic richness, thermal maturity and hydrocarbon potency. In addendum, cluster analysis separated the source rocks in the study area into two groups. The source rocks characterized by HI >240 (mg/g), TOC from 58.89 to 66.43 wt%, S1 from 2.01 to 2.54 (mg/g) and S2 from 148.94 to 162.52 (mg/g) indicating good to excellent source rocks with kerogen of type II and type III and are capable of generating oil and gas. Followed by the Source rocks characterized by HI <240 (mg/g), TOC from 0.94 to 6.68 wt%, S1 from 0.14 to 0.72 (mg/g) and S2 from 0.14 to 3.36 (mg/g) indicating poor to good source rocks with kerogen of type III and are capable of generating gas. Howeverr, Pearson's correlation coefficient and linear regression analysis shows a significant positive correlation between TOC and S1, S2 and HI and no correlation between TOC and Tmax, highly negative correlation between TOC and OI and no correlation between Tmax and HI.

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Section: Quality and Quantity Of Organic Mattermentioning

confidence: 99%

Section: Thermal Maturationmentioning

confidence: 99%

Integrated Geochemical and Multivariate Statistical Examination of Source Rocks in the Sokoto and Anambra Basins, Nigeria: Implications for Hydrocarbon Prospectivity

Adamu¹,

Obaje²,

Ngozi³

et al. 2020

PSE

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“…At least some of the reservoired oils are interpreted to be sourced from within the Triassic (Al-Ameri and Zumberge, 2012; English et al, 2015), suggesting the presence of an effective Triassic petroleum system. However, the identity of the Triassic source rocks remains poorly understood and relatively few published studies have attempted to assess the source rock potential or maturity of the Triassic succession in Kurdistan (Abeed, 2006;Al-Ameri et al, 2009;Naqishbandi et al, 2015;English et al, 2015;Akram and Naqshabandi, 2018;Edilbi et al, 2019).…”

Section: Introductionmentioning

confidence: 99%

Stratigraphic Correlation and Source Rock Characteristics of the Baluti Formation From Selected Wells in the Zagros Fold Belt, Kurdistan Region, Northern Iraq

Mohialdeen

Fatah

Abdula

et al. 2021

Journal of Petroleum Geology

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The Upper Triassic Baluti Formation has been identified and mapped based on its log response in selected wells from the Zagros foldbelt in the Kurdistan Region of northern Iraq. A preliminary evaluation of the formation's source rock potential was made by Rock‐Eval screening analysis in four wells along a NW‐SE profile (Atrush‐1, Shaikan‐5B, Taq Taq‐22 and Miran‐2) with maturity determined from reflectance measurements in samples from well Taq Taq‐22. The Baluti Formation consists of thinly interbedded shales, carbonates and anhydrite ranging in thickness from 48 m in well Atrush‐1 to 118 m in well Miran‐2. The Rock‐Eval screening was conducted primarily on bulk cuttings samples plus selected picked cuttings. The TOC content is low to moderate (0.23 to 1.14 wt%). However, the shale content in many of the analysed bulk samples was relatively low, making assessment of the source potential problematic. The highest TOCs are recorded from the thickest analysed sections from wells Miran‐2 and Taq Taq‐22, where high‐gamma bituminous shales are present. Rock‐Eval Tmax values ranging from 295 to 438°C are not consistent with estimates of pre‐Zagros burial to depths of between 4600 m (Atrush‐1) and 6900 m (Miran‐2). The relatively low Tmax values suggest that the S2 response does not reflect kerogen pyrolysis in these samples and may be due to the presence of solid bitumen, which is observed in the Baluti Formation in at least three of the study wells (Taq Taq‐22, Miran‐2 and Shaikan‐5B). Little pyrolysable organic matter remains in the formation due to the interpreted deep pre‐Zagros burial and the consequent high maturity in Taq Taq‐22 (VR = 1.51%Ro) and Miran‐2 (estimated VR >2%Ro), and the poor source character in Atrush‐1 and Shaikan‐5B. Organic petrography suggests the presence of vestiges of Types I and II kerogen in Taq Taq‐22, with bitumen observed as stains in the matrix of the shales and also in the pores and fractures of interbedded dolostones. However, bitumen reflectance determinations for Taq Taq‐22 indicate an equivalent vitrinite reflectance maturity of no more than 0.93%Ro, which is significantly less than that of the indigenous vitrinite, implying the solid bitumen in this well is derived primarily from migrated hydrocarbons. Further detailed analysis is required, but the results suggest that the Baluti Formation may have sourced hydrocarbons in its depocentre which is identified in this study as covering a NW‐SE trending area between Bekhme and Sangaw.

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“…The petroleum system of Jabal Kand Oil Field shows that the Sargelu Formation is immature and has not generated any oil Ro< 0.55% (Abdula, 2017); Hakimi et al (2018) explained through the model of burial/thermal history that the source rock of the Sargelu Formation has passed the peak of oil generation window during the late Eocene-late Miocene; The results show that the Sargelu marine type IIS kerogen in Bijeel Oil Field are potential source of hydrocarbon and is thermally mature with respect to the oil window. In the samples that they studied, carbonate are more organic-rich and more oil-prone than carbonaceous shales and silty mudstones (Abdula et al 2017); Edilbi et al (2019) in their study on the source rocks potential and basin modeling of the Kurrachine Formation concluded that the formation consists of mixed types ІІІ and ІІ-ІІІ kerogen, and the values of Tmax show that the organic matter is thermally mature. The study aims to investigate the effects and distributions of steranes and triterpenes and their related parameters to interpret the depositional environment conditions and to assess the thermal maturity of the Sargelu and Kurrachine formations.…”

Section: Introductionmentioning

confidence: 99%

Distribution of Steranes and Triterpanes Biomarkersas Indication of Depositional Environment and Maturity of Sargelu and Kurrachine Formations in Different Wells Northern Iraq

Al-Dolaimy

Al-Beyati

Al-Mallah

2021

IGJ

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Eight cuttings samples were obtained from Sargelu and Kurrachine formations in different wells at different depths to detect steranes and triterpanes biomarkers as an indicator of the depositional environments and thermal maturity of organic matter. This was accomplished using GC-MS technology. The diasterane/sterane ratio showed low ratios in analyzed samples (BJS2, JKS3, BJK1, JKK4, JKK7) as in most marine carbonate sources, while algal-bacterial organic matter contribution for the samples analyzed based on the predominance of C23 tricyclic relative to the C19 tricyclic terpene and the C23 tricyclic greater than C24 tricyclic terpane. The Gammacerane index indicated that normal salinity conditions during depositions. The biomarkers related to maturation such as diasterane/sterane, Ts/(Ts+Tm), and C29Ts/C29 hopane show that the organic matter in Ain Zalah well (Sargelu Formation) is within early mature (oil window).

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Source rock evaluation of shale intervals of the Kurra Chine Formation, Kurdistan Region-Iraq: An organic geochemical and basin modeling approach

Cited by 12 publications

References 7 publications

Integrated Geochemical and Multivariate Statistical Examination of Source Rocks in the Sokoto and Anambra Basins, Nigeria: Implications for Hydrocarbon Prospectivity

Integrated Geochemical and Multivariate Statistical Examination of Source Rocks in the Sokoto and Anambra Basins, Nigeria: Implications for Hydrocarbon Prospectivity

Stratigraphic Correlation and Source Rock Characteristics of the Baluti Formation From Selected Wells in the Zagros Fold Belt, Kurdistan Region, Northern Iraq

Distribution of Steranes and Triterpanes Biomarkersas Indication of Depositional Environment and Maturity of Sargelu and Kurrachine Formations in Different Wells Northern Iraq

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