BIOMARKERS AND PYROLYSIS PARAMETERS TO INVESTIGATE HYDROCARBON GENERATING POTENTIAL OF CRETACEOUS SEQUENCES

Abstract

This thesis describes a comprehensive geochemical study on sediments (60) and crude oils (10) from Cretaceous Formations using TOC, Rock-Eval Pyrolysis, gas chromatography (GC) and gas chromatography mass spectrometry (GC-MS). The samples were obtained from the Kohat and the Lower Indus Basins. Chapter 1 describes a brief introduction of terms and applications of Rock Eval and biomarker parameters in organic geochemistry. Geology of the study area, description of samples and details of experimental procedures and techniques has been described in chapters 2-3 respectively. In chapter 4, the source rock potential of Cretaceous Formations from four wells, namely C-1 from the Kohat Basin and Ks-1, Dd-1 and D-1 from the Lower Indus Bain, has been investigated using total organic carbon (TOC) and Rock Eval parameters. The sequences represented by Hangu, Lumshiwal and Chichali Formations from the Kohat Basin are organic rich sediments. Organic matter is mature and largely type-III gas prone kerogen, however, at the base of Lumshiwal, type-II/III OM capable of generating both oil and gas is present. In the Lower Indus Basin, the Parh Formation contains insignificant amount of thermally immature type-III/IV OM. The Upper Goru unit also lacks organic richness and thermal maturity necessary for hydrocarbon generation. However, in the well Dd-1, this unit probably contains mixed OM from type-II/III kerogen, which may have some potential for gas at appropriate maturity level. The members of Lower Goru Formation, (Badin shale, Upper shale, Middle sand, Lower shale and Talhar shale) in well Ks-1, display fair to good organic contents; while deeper sediments are more organic rich. The OM is thermally mature except Badin shale. Amongst the sample suit, Talhar and basal shale units in well Dd-1 and Lower Goru shales in well D-1 contains good amount of mixed OM. These formations show sufficiently high maturity and S 2 /S 3 to have generated both oil and gas. The samples of Sembar Formation are low in OM, mainly type-III OM at peak thermal maturity is present; suggesting end of hydrocarbon generation window. Low pyrolysis yields in these sediments could be due to thermal effects on OM. This study suggests that Sembar ivFormation is predominantly gas prone; while Lower Goru shales and Talhar shales may act as source rocks for both oil and gas in the area. In chapters 5 & 6, biomarker study has been undertaken on sediments, discussed under chapter 4, to predict the source, depositional environment, lithology and thermal maturity of OM. The samples from the Kohat Basin contain mixed OM predominantly terrestrial deposited in marine sediments. This has been indicated from low pristane/phytane (Pr/Ph) ratios, samples location on Pr/nC 17 vs. Ph/nC 18 and steranes ternary diagrams. The presence of oleanane indicates some angiosperm input to the source rocks. The low C 29 /C 30 17α(H)-hopane and low C 35 homohopane index (HHI), low abundance of C 19 -C 29 tricyclic terpanes (TT) compared to hopanes, high abundances of C 24 tetracyclic terpane (TeT) and C 23 TT, and low steranes/hopanes support non-marine OM in evaporate depositional settings. While extremely low values of C 30 D/C 30 17α(H)-hopanes and C 29 Dia/Regular steranes suggest marine sediments. The ratios, C 32 22S/(22S + 22R) homohopane, moretane/hopane, C 29 20S/(20S + 20R) and αββ/(αββ + ααα) steranes and carbon preference indices (CPI & OEP) indicate mature nature of OM for Hangu, Lumshiwal and Chichali Formations. In the Lower Indus Basin, the Parh and Upper Goru Formations demonstrate the presence of algal OM deposited under anoxic to sub-oxic conditions. The algal nature of OM has been manifested by high relative distribution of C 27 5α(H), 14α(H), 17α(H) 20R (ααα- 20R) steranes on ternary plot. The samples are immature with respect to hopane and sterane isomerization ratios and hence not capable of generating hydrocarbons. The Lower Goru Formation including its members particularly Upper shale, Lower shale and Talhar shale has received mixed OM (predominantly terrestrial) deposited under oxic environment on the basis of Pr/Ph ratio, abundance of C 19 TT, C 20 TT and C 24 TeT relative to C 23 TT, relative distribution of C 29 /C 30 17α(H)-hopanes and C 29 /C 27 ααα-20R steranes. The OM in Lower Goru Formation samples is thermally mature on the basis of sterane and hopane isomerization ratios close to equilibrium values and CPI close to one with the exception of a few samples e.g. Dd-7, Ks-4 & Ks-6 and samples from well SMD-1. The Upper shale, Lower shale and Talhar shale samples from well SMD-1, show immature vdistribution of biomarkers maturity parameters on account of shallower depth (1410-2190 m) compared to same formations in well Ks-1 (2350-2962 m) which are more deeply buried and more mature. The Sembar Formation contains mixed OM, more terrigenous input at intervals (Dd-1), deposited under anoxic to sub-oxic conditions and exhibit C 32 22S/(22S + 22R) homohopane, moretane/hopane and sterane isomerization ratios typical of thermally mature OM. The study based on biomarker analysis reveals that OM in the Cretaceous sediments is of mixed origin, predominantly terrestrial and deposited in oxic to anoxic environment. The biomarker maturity parameters reveals that the Hangu, Lumshiwal and Chichali Formations in the Kohat Basin and the Lower Goru (including its members Upper shale, Lower shale and Talhar shale) and Sembar Formations in the Lower Indus Basin have reached maturity level equivalent to the main zone of hydrocarbons generation while Parh and Upper Goru Formations are immature and far from oil window. In chapter 7, geochemical analysis of the 10 crude oils from Cretaceous reservoirs of the Lower Indus Basin has been carried out using bulk properties and diagnostic biomarker parameters. Presence of full suite of n-alkanes, low isoprenoid/n-alkane ratios, elevated saturates/aromatics ratios, high API gravity and absence of unresolved complex mixture (UCM) are consistent with non-biodegraded nature of crude oils. Low sulfur content (<1 %) and high Pr/Ph ratio (2.14-5.27) suggest non-marine OM deposited in highly oxic depositional environments. Biomarker parameters like relative distribution of C 27 -, C 28 - and C 29 ααα-20R steranes, C 19 TT, C 23 TT, C 24 TeT, hopanes distribution, steranes/hopanes ratio, Pr/n-C 17 vs. Ph/n-C 18 plot and oleanane index suggest that the crude oils contain predominantly terrigenous OM. The crude oil samples are mature for CPI, C 32 22S/(22S + 22R) homohopanes, C 29 20S/(20S + 20R) and C 29 αββ/(αββ + ααα) sterane isomerization ratios. Based on a similar trend in data, the analyzed crude oils from the Lower Indus Basin are genetically related and could be classified into a single group. Geochemical correlation studies of crude oils and source rock sediments indicate that shales of the Lower Goru and Sembar Formations could be the probable source rocks for crude oils.