A mathematical representation of Rock-Eval hydrogen index vs Tmax profiles

Banerjee, A.; Sinha, Amit Kumar; Jain, Ajay K.; Thomas, N.J.; Misra, K. N.; Chandra, Kuldeep

doi:10.1016/s0146-6380(97)00119-8

Cited by 48 publications

(13 citation statements)

References 10 publications

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“…The HIo of mature samples based on the equation of Banerjee et al (1998) have smaller values if compared to those calculated after Cornford et al (2001).…”

Section: Discussioncontrasting

confidence: 55%

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Reconnaissance study of organic geochemistry and petrology of Paleozoic-Cenozoic potential hydrocarbon source rocks from the New Siberian Islands, Arctic Russia

Sobolev

Franke

Gaedicke

et al. 2016

Marine and Petroleum Geology

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“…The HIo of mature samples based on the equation of Banerjee et al (1998) have smaller values if compared to those calculated after Cornford et al (2001).…”

Section: Discussioncontrasting

confidence: 55%

“…The simplest linear correction uses the measured T max as a maturity indicator (Cornford et al, 2001). We used an alternative method proposed by Banerjee et al (1998), which can also be applied to type III kerogen: HI ¼ 1=ð0:00119*expð0:0381*ðT max À 435ÞÞ þ 1=HIoÞ:…”

Section: Discussionmentioning

confidence: 99%

Reconnaissance study of organic geochemistry and petrology of Paleozoic-Cenozoic potential hydrocarbon source rocks from the New Siberian Islands, Arctic Russia

Sobolev

Franke

Gaedicke

et al. 2016

Marine and Petroleum Geology

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“…Statistical analysis and evolution of HI and BI with increasing Ro% Each type of kerogen has its own path of maturation on a cross-plot of HI versus T max (Hunt 1996;Banerjee et al 1998;Pedersen et al 2006;Arfaoui et al 2007). HI and T max are functions of kerogen composition and thermal history.…”

Section: Resultsmentioning

confidence: 99%

Relationships among geochemical indices of coal and carbonaceous materials and implication for hydrocarbon potential evaluation

2009

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A worldwide dataset of organic material from 553 samples belonging to coal and carbonaceous materials was used to analyze the evolution of hydrogen index (HI) and bitumen index (BI) with increasing thermal maturity. Basic statistical analyses were applied to detect the boundary lines of HI max and BI max in delineating the upper and lower limits of the HI and BI bands for the majority of samples. In addition, cross-plots of HI or BI versus maturity (Ro% and T max ) also provide criteria for defining the HI max and BI max boundary lines. The constructed HI and BI bands are broad at low maturities and become narrower with increasing thermal maturities. The petroleum generation potential is completely exhausted at the vitrinite reflectance of 2.0-2.2% or T max of 510-520°C. An increase in HI implies extra petroleum generation which was related to changes in structure of organic materials. A declining BI means that the oil expulsion window starts to occur at the vitrinite reflectance range of 0.75-1.05%. The petroleum potential can be divided into four different areas based on the cross-plot of HI versus Ro%. The highest petroleum potential area is located in section II with Ro = 0.6-1.0% and HI [ 100. The oil generation potential is rapidly exhausted at section III with Ro [ 1.0%. This result is also in accordance with the result of curve regression of HI versus Ro% based on 80 samples with Ro = 1.02-3.43% (R 2 = 0.72). Overall, the total oil window can be extended up to Ro = *1.25-1.95%. Finally, in the cross-plots of S1 versus S2, shale or C-shale exhibits a higher and slowly decreased slope, compared with a lower and then sharply increased slope of coal samples, which is attributable to their compositional difference in organic material.

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“…Thus, in order to determine the intial petroleum generation potential, back-calculation of the measured values to original values (HIo, TOCo, S2o) is required. An in-house study established the relationship between the transformation ratio, f, and maturity using Rock-Eval T max for Type III kerogen based on the transformation algorithms in Banerjee et al (1998). Measured present-day T max values were paired with an f value based on calculated (T max , f) pairs and T max versus f curves.…”

Section: Source Rock Qualitymentioning

confidence: 99%

A Review of the Coaly Source Rocks and Generated Petroleums in the Danish North Sea: An Underexplored Middle Jurassic Petroleum System?

Petersen

Hertle

2018

Journal of Petroleum Geology

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This paper reviews the Middle Jurassic petroleum system in the Danish Central Graben with a focus on source rock quality, fluid compositions and distributions, and the maturation and generation history. The North Sea including the Danish Central Graben is a mature oil province where the primary source rock is composed of Upper Jurassic – lowermost Cretaceous marine shales. Most of the shale‐sourced structures have been drilled and, to accommodate continued value creation, additional exploration opportunities are increasingly considered in E&P strategies. Triassic and Jurassic sandstone plays charged from coaly Middle Jurassic source rocks have proven to be economically viable in the North Sea. In the Danish‐Norwegian Søgne Basin, coal‐derived gas/condensate is produced from the Harald and Trym fields and oil from the Lulita field; the giant Culzean gas‐condensate field is under development in the UK Central North Sea; and in the Norwegian South Viking Graben, coal‐derived gas and gas‐condensate occur in several fields. The coaly source rock of the Middle Jurassic petroleum system in the greater North Sea is included in the Bryne/Lulu Formations (in Denmark), the Pentland Formation (in the UK), and the Sleipner and Hugin Formations in Norway. In the Danish Central Graben, the coal‐bearing unit is composed of coals, coaly shales and carbonaceous shales, has a regional distribution and can be mapped seismically as the ‘Coal Marker’. The coaly source rocks are primarily gas‐prone but the coals have an average Hydrogen Index value of c. 280 mg HC/g TOC and values above 300 mg HC/g TOC are not uncommon, which underpins the coals' capacity to generate liquid hydrocarbons (condensate and oil). The coal‐sourced liquids are differentiated from the common marine‐sourced oils by characteristic biomarker and isotope compositions, and in the Danish Central Graben are grouped into specific oil families composed of coal‐sourced oil and mixed oils with a significant coaly contribution. Similarly, the coal‐sourced gases are recognized by a normally heavier isotope signature and a relatively high dryness coefficient compared to oil‐associated gas derived from marine shales. The coal‐derived and mixed coaly gases are likewise assigned to well‐defined gas families. Coal‐derived liquids and gas discoveries and shows in Middle Jurassic strata suggest that the coaly Middle Jurassic petroleum system has a regional distribution. A 3D petroleum systems model was constructed covering the Danish Central Graben. The model shows that present‐day temperatures for the Middle Jurassic coal source rock ('Coal Marker') are relatively high (>150 °C) throughout most of the Danish Central Graben, and expulsion of hydrocarbons from the ‘Coal Marker’ was initiated in Late Jurassic time in the deep Tail End Graben. In the Cretaceous, the area of mature coaly source rocks expanded, and at present day nearly the whole area is mature. Hydrocarbon expulsion rates were low in the Paleocene to Late Oligocene, followed by significant expulsion in the Miocene up...

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A mathematical representation of Rock-Eval hydrogen index vs Tmax profiles

Cited by 48 publications

References 10 publications

Reconnaissance study of organic geochemistry and petrology of Paleozoic-Cenozoic potential hydrocarbon source rocks from the New Siberian Islands, Arctic Russia

Reconnaissance study of organic geochemistry and petrology of Paleozoic-Cenozoic potential hydrocarbon source rocks from the New Siberian Islands, Arctic Russia

Relationships among geochemical indices of coal and carbonaceous materials and implication for hydrocarbon potential evaluation

A Review of the Coaly Source Rocks and Generated Petroleums in the Danish North Sea: An Underexplored Middle Jurassic Petroleum System?

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