ORGANIC GEOCHEMICAL CHARACTERISTICS OF LOWERMIDDLE JURASSIC SUCCESSION AND CRUDE OILS FROM SELECTED WELLS, GARMIAN AREA, KURDISTAN REGION, NE-IRAQ A thesis Submitted to the Council of Faculty of Science and Science Education School of Science at the University of Sulaimani in Partial Fulfillment of the Requirements for the Degree of Master of Science in Geology
By Diyar Abdulqader Saeed B.Sc. Geology (1998), University of Sulaimani
Supervised by Dr. Ibrahim M. J. Mohialdeen Assistant Professor
Pushpar, 2714
June, 2014
Language Evaluation Certificate This is to certify that I, Dr. Sarah Kamal Othman have proofread this thesis entitled “Organic Geochemical Characteristics of Lower-Middle Jurassic Succession and Crude Oils from Selected Wells, Garmian Area, Kurdistan Region, NE-Iraq” by Diyar Abdulqader Saeed. After marking and correcting the mistakes, the thesis was handed again to the researcher to make the corrections in this last copy.
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Acknowledgements I would like to thank my M.Sc. advisor, Assistant Professor Dr. Ibrahim M.J. Mohialdeen, for supporting and encouraging me during the period of this study. I am very grateful to Mr. Bertrand Chevallier, Exploration Manager - Total E&P Kurdistan, Mr. Gilles Nicolas and Mr. Denis Levaché , the laboratory staff in CSTJF analytical center in Pau, France for Rock-Eval, GC and GC/MS analysis and their useful advising and important inputs during and after the analysis process. I would like to extent special thanks to TOTAL Company for inviting me to CSTJF center in France for looking at the process of sample analysis closely and getting scientific information concerning this issue. Special appreciation is extended to the staff and head of the Department of Geology, the dean of School of Science and Science Education, and University of Sulaimani for supplying available facilities and administrative support. I wish to express my gratefulness to Kurdistan Institution for Strategic Study and Scientific Research and Professor Dr.Polla Khanaqa for their kind support and allowing me to make some analyses at their laboratories. I am sincerely grateful to Ministry of Natural Resource for providing me all the necessary facilities and samples that were required for this study. I am very grateful also to my friend Dr. Stavros Kalaitzidis, at the Department of Geology, University of Patras, Greece, for his kind advising, information and assistance in arranging many things in addition to reviewing some parts of this study. My last gratitude goes to my wife (Parween) for her patience and encouragement throughout this study.
Diyar A. Saeed
Abstract The total of 84 rock cutting samples from Lower-Middle Jurassic succession (Butma, Adaiyah, Mus, Alan and Sargelu formations) in Sangaw North -1 (SN-1) borehole, Sangaw North Block, Garmian area, Kurdistan region, were used for optical and geochemical analyses. Two crude oils from PU-8 and S-1 wells in Pulkhana and Sarqala oil fields, one condensate from KR-3 well in KorMor gas field and seepage oil from ChiaSurkh oil field were chosen for organic geochemistry investigation, oil-oil and oil-source rocks correlation. Tectonically, the study area is located in the southeastern part of the Foothill Zone in Zagros Fold Belt. The potentiality of Lower-Middle Jurassic formations was defined generally as low for producing hydrocarbons. The results of Rock-Eval parameters (S1, S2, GP and PCI) showed poor to fair capacity of the succession for releasing hydrocarbons with exception of Adaiyah Formation that have marginally good potential. The organic contents of the formations were associated approximately with kerogen type III (gas prone) based on various Rock-Eval parameters (HI, OI, S2 and PCI), except for some sequence in Lower Jurassic Adaiyah Formation where kerogen types comprised a mixture between kerogen type II and III (oil and gas prone). The Rock-Eval results weren’t reliable for describing the maturity of the formations (Butma, Adaiyah, Mus, Alan and Sargelu) due to discrepancy between Tmax and PI values that were possibly caused by contamination. Contamination strongly affected the results of Rock-Eval pyrolysis that was confirmed from various features, such as bimodal S2 peaks, low Tmax, high PI and occurrence of non-indigenous hydrocarbons within some cutting samples of Sargelu and Alan formations. Moreover, mud additive materials (lignite) that were considered as source of contamination was optically identified through vitrinite reflectance analysis. The maturity of Jurassic succession in SN-1 well is high (gas generation zone) and ranged between R% 1.34 to R% 2.1 from vitrinite and equivalent vitrinite reflectance that derived from bitumens by using Jacob’s equation.
The crude oils and condensate sample are unaltered, non- biodegraded and have high sulfur content with exception of KorMor condensate (minor amount of sulfur) and API gravity ranged from moderate to light (25.9-65.7° API). The biomarkers ratios and molecular compound distributions showed that the oils, condensate and rock extracted sample were derived from marine carbonate source rocks bearing marine algae and kerogen type II that deposited under reducing condition. Low presence of gammacerane indicated normal salinity condition during the depositions. Moreover, the maturity related parameters indicated wide range of maturity from moderate to high. The maturity sequence of the oils, condensate and extracted sample based on Ts/Tm and MPI 1 ratios are arranged from high to low maturity as the following order: extracted sample and KorMor condensate> ChiaSurkh oil> Sarqala oil> Pulkhana oil. The GC-FID traces of oils and condensate showed lack of any remarkable biodegradation, but rock-extracted of Sargelu Formations is strongly contaminated by polyethylene glycol according to the GC-FID chromatogram. Compositional similarity of sterane, hopane, isopernoid and n-alkane compounds among the crude oils and crude oils with extracted sample of Sargelu Formation suggested that the oils might be sourced from the same or similar source rocks that deposited under similar conditions. On the other hand, Sargelu Formation is supposed to be one of the sources of the generated crude oils. However, the maturity-related parameters showed no similarity between the crude oils and extracted sample of Sargelu Formation.
List of Contents Subjects
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Acknowledgments…………………………………………………………………... Abstract…………………………………………………………………………………… List of Contents……………………………………………………………………….. List of Tables…………………………………………………………………………… List of Figures ……………………………………………………………………………
I II IV VI VII
Chapter One: Introduction 1.1. 1.2. 1.3. 1.4. 1.5. 1.6. 1.7. 1.7.1. 1.7.2.
Background……………………………………………………………………………… Objectives of the Study……………………………………………………………. Literature Review……………………………………………………………………. Location of the Study Area………………………………………………………. Oil Fields and Boreholes Descriptions………………………………………. Used Materials and Analytical Techniques………………………………. Geological Setting of Early-Middle Jurassic Successions………..... Paleogeographic and Paleofacies Distribution of Early-Middle Jurassic Period…………………………………………………………………………. Stratigraphy of Early-Middle Jurassic Period…………………………….
1 4 4 7 8 11 13 13 16
Chapter Two: Pyrolysis and Organic Petrology 2.1. 2.2. 2.2.1. 2.2.2. 2.3. 2.4. 2.4.1. 2.4.1.1. 2.4.2. 2.4.2.1. 2.4.3. 2.4.3.1. 2.4.3.2. 2.4.3.3. 2.4.4. 2.4.4.1. 2.4.4.2. 2.4.4.3.
Introduction………………………………………………………………………....... Rock-Eval Pyrolysis Analysis………………………………....................... Pyrolysis………………………………………………………………………………….. Rock-Eval Parameters……………………………………………………………… Total Organic Carbon (TOC)…………………………………………………….. Source Rocks Evaluation…………………………………………………………… Source Rocks Quantity and Potentiality Assessment…………………. Discussion……………………………………………………………………………….. Assessment of Source Rocks Quality…………………………………………. Discussion……………………………………………………………………………….. Assessment of Thermal Maturity (Tmax)…………………………………. Factors Affect the Value of Tmax……………………………………………… Maturity Assessment of the Formations…………………………………… Discussion……………………………………………………………………………….. Vitrinite Reflectance Measurement Analysis (Rο)…………………….. Organic Matter Identification…………………………………………………. Maturity Profile of the Formations............................................. Discussion………………………………………………………………………………..
21 22 22 22 26 27 28 34 35 43 44 44 45 47 49 51 58 63
3.1. 3.2. 3.3. 3.4. 3.5. 3.6. 3.6.1. 3.6.2. 3.6.3. 3.7. 3.7.1. 3.7.2. 3.7.3. 3.7.3.1. 3.7.3.2. 3.7.3.3. 3.7.4.
Subjects
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-------------------Chapter Three: Biomarkers
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Background…………………………………………………………………………………… Analyzed Samples…………………………………………………………………………. Analytical Method………………………………………………………………………… Gas Chromatography Analysis……………………………………………………… The Measured Parameters…………………………………………………………… Results…………………………………………………………………………………………. Bulk Properties of Studied Samples…………………………………………….. GC-FID Results of Studied Samples………………………………………………. GC-MS Results of Studied Samples………………………………………………. Discussion……………………………………………………………………………………. Bulk Composition of Petroleum Samples…………………………………….. Depositional Environments and Source Rock Related Parameters………………………………………………………………………………….. Maturity Related Biomarkers………………………………………………………. Hopane-Related Maturity Parameters………………………………………… Sterane-Related Maturity Parameters…………………………………………. Aromatic-Related Maturity Parameters………………………………………. Biodegradation…………………………………………………………………………….
65 66 66 67 67 79 79 80 81 95 95 95 104 107 108 110 111
Chapter Four: Geochemical Correlations 4.1. 4.2. 4.2.1. 4.2.2.
Background………………………………………………………………………………….. Correlation Related Parameters…………………………………………………… n-Alkanes Distributions, Pristane and Phytane Compounds…………. Terpane and Sterane Related Parameters……………………………………..
114 116 117 118
Chapter Five: Conclusions and Recommendations 5.1. 5.2.
Conclusions…………………………………………………………………………………… Recommendations………………………………………………………………………..
125 127
References……………………………………………………………………………………… Appendices……………………………………………………………………………………..
128 136
List of Tables Table No.
Table Title
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1-1 2-1 2-2 2-3 2-4 2-5 2-6 2-7 2-8 2-9 2-10 2-11 2-12 2-13
2-14 3-1 3-2 3-3 3-4 3-5 3-6 4-1
List of the samples that used in the study………………………………… Calculated indices from the Rock-Eval parameters………………….. Describing types of generated hydrocarbons according to HI and values of S2/S3 ratios……………………………………………………..... Kerogen type classification based on Hydrogen index (HI) and Oxygen index (OI) values……………………………………………………….... Source rock richness classification based on TOC wt% values….. TOC wt% and Rock-Eval pyrolysis data of the selected samples. Mean TOC wt% values are tabulated for the studied formations in SN-1 well…………………………………………………………... ( Peters and Casse, 1994) and (Tissot and Welte, 1978) classifications for source rocks evaluation………………………………. Source rocks potentiality of the studied formations according to the geochemical parameters………………………………………………. Describing kerogen types based on PCI values…………………………. Showing the guide line for describing degree of thermal maturity…………………………………………………………………………………… Presenting thermal maturity of the formations according to Tmax and PI parameters………………………………………………………….. Showing stages of hydrocarbons generation according to the values of Vitrinite Reflectance………………………………………………... Presenting the results of Vitrinite Reflectance measurements of the selected rock cutting samples that performed by TOTAL Company...................................................................................... Presenting the results of Vitrinite reflectance measurement of the selected rock cutting samples after modification.................. Presenting the identification of most of the tricyclic and pentacyclics compound peaks of ion m/z 191 of Fig. 3-2………………………………………. Showing the identification of regular and isomers of sterane compounds peaks of Fig. 3-3................................................................. Showing the identifications of the aromatic compound peaks that presented in Fig. 3-4…………………………………………………………………………. Bulk properties and alkane molecular parameters for analyzed samples................................................................................................. Terpane, sterane and aromatic source related parameters for analyzed samples…………………………………………………………………………….. Terpane, sterane and aromatic maturation related parameters for analyzed samples………………………………………………………………….............. Showing the biomarker ratios that used for correlation processes…………………………………………………………………………………………..
12 25 25 26 27 29 30 31 31 41 46 46 50
60 61 73 74 74 82 82 83 117
List of Figures Figure No. ----------1-1 1-2 1-3 1-4 1-5 1-6 2-1 2-2 2-3 2-4 2-5 2-6 2-7 2-8 2-9 2-10 2-11 2-12 2-13 2-14 2-15 2-16
Figure Title -------------------Stratigraphic column of Early-Middle Jurassic succession in SN-1 well……………………………………………………………………………………………………….. Showing the location of the study area on tectonic map of north and northeastern part of Iraq………………………………………………………………………. Structural map shows the location of Garmian Block in Garmian area, including Sarqala-1 well………………………………………………………………………… Location map of Sangaw North Block……………………………………………………. Paleogeographic distributions of Liassic sequence in Iraq with indicating the study area……………………………………………………………………………………….. Isopach-Facies map of Middle Jurassic rock units with indicating the study area……………………………………………………………………………………………… Pyrogram chart showing the provided parameters during Rock-Eval analysis…………………………………………………………………………………………………. Petroleum-generating potential of studied samples based on the cross plot of TOC wt% versus potential yields (GP)………………………………………… Cross plot of S2 (mg HC/g rock) versus TOC wt% for describing the hydrocarbon generating potential of studied formations……………………… Cross plot of Residual carbon (RC %) versus Total organic carbon (TOC wt%) for the studied formations……………………………………………………………. Showing kerogen types of the studied formations from plotting HI versus OI……………………………………………………………………………………………… Showing two kerogen populations of Sargelu Formation based on HI versus OI cross plot………………………………………………………………………………. Cross plot of S1 versus TOC%, Showing Sargelu sediment’s populations………………………………………………………………………………………….. Showing the two populations of Alan sediments from cross plot of S1 versus TOC%.............................................................................................. Plot of S2 versus TOC wt% showing the kerogen types of Sargelu, Alan and Butma formations………………………………………………………………………….. Plot of S2 versus. TOC wt% showing the kerogen types of Adaiyah and Mus formations……………………………………………………………………………………. Pyrogram chart of contaminated rock sample, showing a bimodal displayed of S2 peak……………………………………………………………………………… Showing the correlation between Tmax and PI values of the studied samples as a function of depth…………………………………………………………….. Presenting bimodal S2 peak configurations of some analyzed rock sample. Microgranular and homogenous bitumen in a carbonate matrix of Sargelu Formation sample at the depth 3225m........................................ Showing various organic matter populations in the sample of Sargelu Formation at the depth 3270m, including mud additive (lignite).............. Microgranular and homogenous bitumen in rock sample of Sargelu Formation at the depth 327m...................................................................
Page No. ---------3 9 10 11 15 16 23 32 33 35 38 38 39 40 42 43 45 47 48 53 54 55
Figure No. ----------2-17 2-18 2-19 3-1 3-2 3-3 3-4 3-5 3-6 3-7a-d 3-8a-d 3-9a-d 3-10a-d 3-11a-d 3-12a-d 3-13a-d 3-14 3-15
Figure Title -------------------Anisotropic microgranular bitumen in the rock sample of Adaiyah Formation at the depth of 3528m............................................................. Vitrinite and Semifusinite particles in the rock sample of Butma Formation at the depth of 3645m............................................................. Plotting eq.VRO% versus depth to show maturation trend according to Jacob and Riediger equations………………………………………………………………… Showing m/z 85 chromatogram of Sarqala oil sample, including peaks of nC17, nC18, pristane and phytane and other n-alkanes compounds.... Showing m/z 191 chromatogram of Sarqala crude oil…………………………… Showing m/z 217 chromatogram of Sarqala crude oil including regular steranes………………………………………………………………………………………………… Showing m/z chromatograms of aromatic compounds including P) Phenanthrene, DBT) Dibenzothiophene, MP) Methylphenanthrene, and T) Triaromatic steroids of Sarqala crude oil…………………………………………… GC-FID traces of analyzed samples, A) KorMor condensate, B) Sarqala crude oil ,C) Pulkhana crude oil ,D) ChiaSurkh seep oil………………………….. The GC-FID chromatogram of Sargelu extracted sample shows the effect of contamination by Polyethylene glycol…………………………………….. Presenting the m/z 85 chromatograms of a) KorMor, b) Pulkhana, c) ChiaSurkh, and d) Sargelu-extracted samples…………………………………........ Presenting the m/z 191 of a) Pulkhana, b) ChiaSurkh, c) KorMor, and d) Sargelu-extracted samples…………………………………………………………………… Presenting the m/z 217 of a) Pulkhana, b) ChiaSurkh, c) KorMor, and d) Sargelu-extracted samples……………………………………………………………………. Presenting the m/z 178 chromatograms of a) KorMor, b) Pulkhana, c) ChiaSurkh and d) Sargelu-extracted samples………………………………........... Presenting the m/z 184 of a) KorMor, b) Pulkhana, c) ChiaSurkh, and d) Sargelu-extracted samples……………………………………………………………………. Presenting the m/z 192 of a) KorMor, b) Pulkhana, c) ChiaSurkh and d) Sargelu-extracted samples…………………………………………………………............ Presenting the m/z 231 of a) KorMor, b) Pulkhana, c) ChiaSurkh and d) Sargelu-extracted samples…………………………………………………………............ The ternary diagram of saturated, aromatic and asphaltic compounds of studied samples………………………………………………………………………………… Cross plot of Pr/nC17 versus Ph/nC18, indicated marine organic matter sources for analyzed samples that deposited under reduced conditions…………………………………...............................................................
Page No. ---------56 57 63 69 70 71 72 84 85 88 89 90 91 92 93 94 96
97 3-16
Cross plot of C29/C30 versus C35S/C34S hopanes shows marine carbonate source rocks for studied samples with marine carbonate to marine marl for ChiaSurkh and Sargelu-extracted samples based on the plotted chart for 150 oils……………………………………………………………………………………
Figure No. ----------3-17
3-18 3-19 3-20 3-21 3-22 4-1 4-2 4-3 4-4
4-5
4-6
Figure Title -------------------Cross plot of C26/C25 Tricyclic terpane versus C31R/C30 hopane shows marine carbonate source rocks for Sargelu-extracted sample and mixed sources between carbonate, marine marl and shales for KorMor, Sarqala, Pulkhana and ChiaSurkh samples based on the plotted chart for 150 oils that showed in Al-Ameri et al. (2013)…………………………………. Cross plot of (Pr/Pr+Ph) versus (Dia/Dia+Sterane C27), showed depositional conditions and source material types of the studied samples, the dashed line shows the effect of thermal maturity…………….. Cross plot of pristane (Pr)/phytane (Ph) versus dibenzothiophene (DBT)/ phenanthrene (P) for describing the lithologies and depositional conditions of studies samples……………………………………………………………….. Relative thermal maturities of analyzed samples based on Sulfur% and API gravity…………………………………………………………………………………………….. Correlation of sterane maturity parameters for describing the maturity statues of studied samples based on isomerization in C29 sterane………... Relative thermal maturities of oil samples based on isomerization reactions in C29 steranes……………………………………………………………………….. The m/z 191 chromatograms of the selected samples that show great similarities of peak distributions of terpane compounds……………………….. Presenting m/z 217 chromatograms of selected samples are showed similarity of the sterane compounds…………………………………...................... Steranes ternary diagram of C27%, C28% and C29% (αααR) concerning the selected samples, showing genetically relationships of the samples that deposited under marine environment……………………………………………. Cross plot of Pr/Ph versus C29/C27 regular steranes shows strong genetically relationships of the selected samples including rockextracted of Sargelu Formation in terms of depositional environment and type of source materials………………………………………………………………… Cross plot o Gr/C31R versus (C24/4) / (C23/3) shows close genetic affinity of the selected samples with each other, especially between Sarqala and Pulkhana crude oils separately and ChiaSurkh seep oil with rock-extracted of Sargelu Formation…………………………………………………….. Cross plot of Sterane/Terpane versus C27S dia/C27αααR shows close genetic relationships only between oil samples and no connections between oil samples and rock-extracted of Sargelu Formation due to higher maturity of Sargelu Formation…………………………………………………….
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123
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CHAPTER ONE
Introduction
1.1 . Background In the last ten years, Kurdistan region of Iraq attracted many oil and gas companies for exploration and production of hydrocarbons (oil and gas). Currently, Kurdistan has been divided into many blocks and most of them are under the exploration process, the prospective structures and petroleum systems of these blocks are assessed through drilling numerous boreholes. These boreholes are provided as very important resources for detailed scientific research in order to expand and improve the knowledge about geological conditions of the area. The geological settings of Kurdistan region provided very good conditions for generation, migration and accumulation of hydrocarbons, the discovery of various oil and gas fields throughout Kurdistan is a very good evidence to support that.
Oil fields in Northern Iraq are tectonically located in the Zagros Fold Belt and mainly within the folded zone extending between northeastern Thrust Zone and Khlesia Uplift toward Mesopotamian basin in the southwest. Kurdistan is the northeastern part of the Arabian Peninsula, which is a region of tectonic compression recognized by collision of the Arabian-Eurasian plates that led to close the Neo-Tethys paleo-ocean during Middle Miocene and formed Zagros Fold Belt (Al-Ameri et al., 2012). The northeastern part of the Arabian plate including Kurdistan region was covered by dysoxic to anoxic environmental deposition condition during the Jurassic period that allowed preservation of high organic matter and development of the highest world oil and gas reserves (Murris, 1980; Beydoun, 1998; Pitman et al., 2004; Al-Ameri et al., 2012; Mohialdeen et al., 2013).
The Jurassic sediments of northeast Arabian Plate have attracted many researchers as a result of continuous discovering of oil and gas reserves (Sadooni, 1997). The rock units
of this period are considered as generative hydrocarbon rock units by means of both optical and chemical methods in north Iraq (Ahmad, 1998; Al-Ameri et al., 2013).
A regional stratigraphic column of Early-Middle Jurassic period of Sangaw North-1 well (Fig. 1-1) shows the presence of thick Jurassic sequence comprising of carbonates, shales and anhydrites beds. Lower Jurassic successions (Alan, Mus, Adaiyah and Butma formations) were deposited along the central Iraq and Foothill Zone within carbonateevaporite inner shelf under lagoonal evaporitic condition (Jassim and Buday, 2006). Lower Jurassic sequences in terms of lithologic characteristics were not promising for generating hydrocarbon except Mus Formation, which was dominated by carbonate deposits. Middle Jurassic Sargelu Formation was deposited throughout north and south of Iraq in a distal, suboxic to anoxic basin (Abdulla, 2010; Al-Ameri et al., 2013). The rank of hydrocarbon generation potentiality of Sargelu Formation is considered as a good source (Sadooni, 1997; Pitman et al., 2004).
The purpose of this study is to evaluate the characteristics of prospective source rocks of Lower-Middle Jurassic succession in Sangaw North-1 well, in addition to oil-oil and oilsource rocks correlation of the selected oil fields using common analytical techniques.
The most frequently analytical methods that have been used in the present study are Total Organic Carbon (TOC wt%) measurement, Rock-Eval analysis, and Vitrinite reflectance measurement of the candidate source rocks. Gas chromatography (GC) and Gas Chromatography-Mass Spectroscopy (GC/MS) analysis were also utilized to investigate the biomarkers distribution of the liquid and rock extracted samples for correlation purposes. Finally, this study aims to provide new information on the oil and gas field distributions and better understanding of the petroleum system of the studied area.
Fig: 1-1: Stratigraphic column of Lower-Middle Jurassic succession in SN-1 well. (Adapted from master log of SN-1 well).
1.2 . Objectives of the Study The present study tries to analyze the rock cuttings and petroleum samples of several boreholes in Garmian area including two new wells (Sangaw North-1 and Sarqala-1) to elaborate the sources that allowed hydrocarbons to be generated and defining the genetic relationships between the selected oil fields through achieving the following objectives:
1- Determining the organic matter quantity and quality of the Lower-Middle Jurassic formations that occurred in Sangaw North-1 (SN-1) well. 2- Measuring the thermal maturity of organic matter contents of Early-Middle Jurassic successions in SN-1 well. 3- Evaluating the hydrocarbon generation potentiality of Lower-Middle Jurassic formations using SN-1 well as a case study and finding the charge efficiency of the formations to the gas and oil reservoirs in the study area. 4- Determining genetic relationships between petroleum samples themselves and petroleum samples with rock-extracted sample from Middle Jurassic Sargelu Formation that penetrated by SN-1 well in Garmian area with indicating the origin, age and depositional conditions of the precursor's organic matter of selected petroleum samples.
1.3 . Literature Review Very few studies were found on Lower Jurassic stratigraphic units in Iraq, in terms of hydrocarbon potentiality and source rocks evaluation. Possibly one of the main reasons that make lower Jurassic formations less interesting by researchers is mostly due to rare outcrops of the intervals, only encountered within few boreholes, greater depths and also their lithologic properties mostly evaporate and are not supportive for preserving organic matter. While, Middle Jurassic Sargelu Formation was studied by several researchers in details in various aspects including stratigraphy, hydrocarbon potentiality and source rock characteristics. The Sargelu Formation was cropped out in many areas of Kurdistan region and geographically widespread throughout Iraq territory. Furthermore, Sargelu Formation
is considered as one of the important source rock in Iraq and Middle East for generating hydrocarbon.
Dunnington (1958) explained the lithologic characteristics of Lower Jurassic rocks, which comprises mainly of upper dolomitic limestone and alternation between limestone, shale and anhydrite beds in the lower part. He also believed that the thicknesses of Liassic formations are much thicker at the subsurface section than the outcrops and their organic contents are very low. Bellen et al. (1959) described the depositional conditions of the Lower Jurassic formations. They concluded that all Lower Jurassic formations except Mus were deposited in subkha environments and dominated by lagoonal evaporitics facies, whereas Mus Formation was deposited under normal marine condition and comprised carbonate sediments. Al-Habba (1988, cited in Sadooni, 1997) described Lower Jurassic sequence (Allan and Mus formations) in Kand-1 well and indicated that, although they are thermally mature, they have a low potentiality for generating hydrocarbons. Samarrai (1988, cited in Sadooni, 1997) stated that the Liassic sequence (Alan and Mus formations) was the source of the condensate that is produced from the Samawa-1 well in south of Iraq.
Jassim and Gailani (2006) stated that Liassic sequence (Alan-Mus-Adaiyah and Butma formations) have some reservoir characteristics due to presence of oil shows in the fractured part of the carbonate and anhydrites in the north of Iraq. Mustafa (2009) used Rock-Eval pyrolysis to evaluate the organic contents and hydrocarbon potentialities of Liassic formations. He summarized that Mus Formation contain kerogen type II and II/III, Alan and Adaiyah formations included type II kerogen (Oil prone). The ranges of hydrocarbon potentialities of Alan, Mus and Adaiyah formations are fair to good, good to very good and poor to fair, respectively. The clear carbonate unit of lower part of Butma Formation has a reservoir characteristic according to Aqrawi et al.(2010), and the argillaceous sediments were associated with thick evaporates might be a source for generating hydrocarbons. Aqrawi et al. (2010) recognized Adaiyah Formation as an effective seal. The Sargelu Formation was first described by Witzel in 1948, in Surdash anticline, northeast Iraq. Depositional condition of Sargelu Formations was presumed by Bellen et
al. (1959) as anoxic condition. Murris (1980) considered Middle Jurassic as a period where major source rocks deposited under euxinic condition and became a source for generated hydrocarbon in the Middle East. Beydoun (1986) emphasized on the same conclusion of Murris and demonstrated that oil production in the main basin in the Middle East is principally derived from the rock units of Mesozoic period (Middle and Upper Jurassic). Furthermore he explained the reasons behind the huge accumulation of hydrocarbons in the Middle East.
Al-Habba (1988, cited in Sadooni, 1997) described the reason behind the absence of hydrocarbons in Kand-1 well in northeast of Iraq and it could be related to the shallower depth of Sargelu Formation that makes it unable to generate hydrocarbon due to lower maturity. Sadooni (1997) evaluated Sargelu Formation in Qara Chauq-1 well in the northeast of Iraq and claimed that Sargelu sediments are enriched with amorphous organic matter of purely marine origin and are thermally mature for generating oil. Askar and AL-Gibouri (1998) investigated Butma, Sargelu and Naokelekan formations in various wells in northeast Iraq and they believed that these formations are mainly producing gas and their sediments are dominated by spores and pollen assemblages, which is a good indicator for terrestrial or continental paleo-deposition environment. Pitman et al. (2004) verified the results from Murris (1980) and Beydoun (1993) that the majority of accumulated hydrocarbons in Mesopotamian basin and Zagros Fold Belt are sourced from Mesozoic period (Middle to Upper Jurassic). Moreover, they stated that source rocks in Fold Belt Zone reached peak oil generation at the Late Miocene and Pliocene. At present, according to Pitman et al. (2004) most of the Fold belt source rocks already expelled approximately 90% of their potentiality, except for northern part, where only 50% of their potentiality has been yielded. Balaky (2004) studied Sargelu Formation in terms of stratigraphy and sedimentlogy, and stated that the lithologic compositions of Sargelu is consisted of thin to medium bedded, black bituminous limestone, dolomitic limestone, and black papery shale with balck chert beds at the upper part. Moreover, both contact of Sargelu Formation according to Balaky (2004) are conformable and gradational. The Sargelu Formation is believed to be deposited on a ramp setting during Middle Jurassic period (Balaky, 2004).
Dunnington, (1958) and Jassim and Gailani (2006) confirmed that Middle Jurassic source rocks are most important rock units in south, northeast and north of Iraq because of high total organic carbon (TOC) contents. Moreover, Sargelu Formation in some structures of north Iraq hold heavy oils within the fractured parts, especially where the Gotina seal is absent. Abdula (2010) studied Sargelu Formation in north and northeast Iraq and the main outcomes of his research are the maturity of Sargelu mainly increases from west to the east direction, and Sargelu Formation mostly generates gas in the eastern part. Furthermore, based on biomarkers analysis, he discovered that Sargelu Formation has no any molecular contribution to the accumulated oil in Taq Taq Oil field.
Diyala region, which is close to the area of the current study, has been investigated by Al-Ameri et al. (2012) to determine genetic relationships of the oil fields. They suggested that the majority of the accumulated hydrocarbons in the area were derived from Upper Jurassic Chia Gara Formation. According to Al-Ameri et al. (2012) the accumulated hydrocarbons in the north Iraq were sourced from Sargelu Formation, while those hydrocarbons existed in the northeast mainly generated from Chia Gara Formation. But the hydrocarbons in the northwest are from Triassic formations. The Sargelu Formation is investigated further by Al-Ameri et al. (2013) to determine its potentiality for generating hydrocarbons and it is defined as a good to very good source and it became a source for most of the hydrocarbons accumulated at the north including Damir Dagh oil field.
1.4 . Location of the Study Area The area of the present study is located in Garmian area, Kurdistan region, North East of Iraq (Fig. 1-2). It is bordered from the north by Sulaimani governorate, from the south by Diyala governorate, Hamrin structure located at the western side and the eastern part represented by Iranian border. Depending on tectonic subdivision of Iraq, the study area is located in the Low Folded Zone of Zagros Fold Belt. The Low Folded Zone is characterized by the deepest Precambrian basement. Buday and Jassim (1987) subdivided this zone into two longitudinal units, the Makhul-Hamrin subzone in the southwestern part and Butma-Chamchamal subzone in the northeastern side.
The Butma-Chamchamal subzone that included the SN-1 well, is characterized by structurally highest part of the zone with lesser subsiding unit where the total thickness of Mesozoic-Tertiary sequence is in average 1-1.5km less than the Hamrin-Makhul subzone (Buday and Jassim, 1987).
The Hamrin-Makhul subzone included other selected oil fields (Sarqala, Pulkhana, KorMor and Chia Surkh field). This unit was forming the deepest part of the Foothill Zone (ibid). It was the depocentre of the Neogene Molasses but has been a subsiding unit throughout Mesozoic and Tertiary period (Jassim and Goff, 2006 a).
1.5 . Oil fields and Boreholes Descriptions For the present study five oil fields were selected from the southeastern part of the Foothill Zone of Zagros Fold Belt (Fig. 1-2). Two of the wells, SN-1 and S-1, were drilled after 2005 and no studies were published on them. The following are brief descriptions of the selected oil fields:
KorMor Gas Field: It is located in the southeast of Kirkuk city by around 35km (Fig. 1-2). The structure of KorMor Field composed of an asymmetrical longitudinal anticline. Geometrically, the length of the structure is around 30km in length and 4km width and the closure is about 900m. KorMor is a Gas producing field and the accumulated gases were preserved in the Tertiary reservoirs within the formations of Jeribie, Euphrates, Azqand and Ana (Ranyayi, 2009).
Fig: 1-2: Location of the study area on tectonic map of north and northeastern parts of Iraq (the map after Al-Qayim et al., 2010).
Pulkhana Oil Field:
This field is located about 50km southeastern part of Kirkuk city (Fig. 1-2). The structure comprises of an asymmetrical longitudinal anticline trending NW-SE direction. The length and width of the structure are about 45km and 8km, respectively (Ranyayi, 2009). Trapped oil is accumulated in the Euphrates/Sarikagni reservoirs of Lower Miocene age and within the fractures portion of Shiranish Formation of Upper Cretaceous age (Beydoun, 1988).
Chia Surkh Oil Field:
This oil field is close to the Iranian border in the far southeastern part of the Foothill Zone (Fig. 1-2). The first oil and gas exploration drilling in Iraq began in 1902, when a well was drilled on the Chia Surkh anticline structure (Jassim and Al-Gailani, 2006). General trend of the Chia Surkh structure is NW-SE direction.
Sarqala-1 Well in Garmian Block
The Garmian Block which is close to Kalar district covers an area around 1700 km2. It is far from Sulaimani city to the south by 160km (Fig. 1-2). Garmian Block encompasses one of the biggest exploration areas in Kurdistan and is located on the trend and adjacent to the numerous prolific oil and gas discoveries. Garmian Block contains the Sarqala -1 (S-1) oil discovery, the Mil Qasim-1 oil discovery and other prospects (Fig. 1-3). The S-1 well was drilled in 2009 by Western Zagros Oil Company. Total depth of S-1 well is 4375 m. It is penetrated three main pay zones across the interval, Upper Fars sandstone, the Jeribe dolo-limestone and the Oligocene reservoirs (http://www.westernzagros.com).
Sangaw North-1 (SN-1) Well in Sangaw North Block: The Sangaw North Block covers an area of 492km2. It is located approximately 50km southwest of Sulaimani city, north east Iraq (Fig. 1-4). The first well was drilled in 2009 in Sangaw North Block, named by Sangaw North-1 (SN-1). The total depth of the SN-1 is 4190 m to the Triassic KurraChine Formation. Gas was produced along with water, but the rate was insufficient economically and the well has been abandoned in 2011 (http://www.sterlingenergyuk.com/index.html).
Fig: 1-3: Structural map shows the location of Garmian Block in Garmian area, including Sarqala-1 well. (Cited from the website of Weastern Zagros Oil Company).
Fig. 1-4: Location map of Sangaw North Block. (Sited from website of Shamaran Oil Company)
1.6 . Used Materials and Analytical Techniques Two groups of samples are used to accomplish the targets of the present research (Table 1-1). Group one comprises 84 rock cuttings samples which are taken from SN-1 well across the depth interval from 3977m to 3198m. All the samples are unwashed types and received after getting permission from the Ministry of Natural Resource of Kurdistan Regional Governorate (KRG). Approximately, one sample has been taken per each 6m. Then each sample was hold in the plastic vial and precisely labeled. Group two, composed of 4 liquid samples, two curd oils are taken from Tertiary reservoirs through Pulkhana-8 (PU-8) well in Pulkhana oil field and Sarqala-1 (S-1) well in Sarqala oil field, one condensate sample from Tertiary reservoir is taken from Kor Mor-3 (KR-3) well in KorMor gas field and one oil seep sample taken from Chia Surkh (CS) oil field. All the liquid
samples have been received from the concerning oil companies after getting permission from the Ministry of Natural Resources of KRG.
For fulfilling the objectives of the present study, four frequent analytical techniques are utilized for the selected samples, including Total Organic Carbon (TOC wt.%) measurement, Rock-Eval pyrolysis analysis, vitrinite reflectance measurement, gas chromatography (GC) and gas chromatography-mass spectrometry (GC-MS). The analyses are performed in CSTJF analytical laboratory center in France and GHGeochem laboratory in United Kingdom. TOTAL company provided the cost of the Pyrloysis (Rock-Eva 6), vitrinite reflectance measurements, GC and GC-MS analysis that is conducted by CSTJF center in France.
Table 1-1: List of the samples that used in the study.
well
Oil field
name
names
Coordination
Formations
Sargelu
Alan Sangaw North-1
º
Sangaw
45.11008 E
North
35.2567 N
º
Mus
Adaiyah
Butma
Kor Mor-3
Pulkhana-8
Sarqala-1 Chia Surkh
KorMor
Pulkhana
Sarqala Chia Surkh
35 09' 15" N 44 48' 15" E 34 46' 53" N 44 46' 15" E 45. 15 22° E 34. 75 42° N
Sample's
Sample
type
Number
Cuttings samples Cuttings samples Cuttings samples Cuttings samples Cuttings samples
Thickness of the formations (m)
14
93
12
141
7
42
17
136
34
368
N/A
Condensate
1
N/A
N/A
Crude oil
1
N/A
N/A
Crude oil
1
N/A
N/A
Seep oil
1
N/A
1.7 . Geological Setting of Early-Middle Jurassic Successions
1.7.1. Paleogeographic and Pa leofacies Distribution of Early -Middle Jurassic Period The studied interval “Early-Middle Jurassic” according to Sharland et al. (2001) and Jassim and Goff (2006) is part of AP6 and AP7 Megasequences. The Early Jurassic sequence (Butma, Adaiyah, Mus and Alan formations) is represented the second-order of Megasequence AP6 (Jassim and Goff, 2006 b), and Middle Jurassic sequence (Sargelu Formation) is belong to (Middle-Late Jurassic) Megasequence AP7 (Jassim and Goff, 2006 c).
Buday (1980) subdivided the stratigraphic units of Iraq into cycles in accordance with the main stages of the paleogeographic development of the areas. Early- Middle Jurassic sub stage belonged to the Upper Triassic-Middle Jurassic cycle. The paleogeographic and paleofacies development during the Early-Middle Jurassic period starts with a water transgression over the Stable Shelf. During Early Jurassic (Liassic) period the whole basins were filled by evaporitics facies with decreasing evaporate contribution to the northeast direction.
The Lower Liassic period in Iraq is characterized by developing three different basins from the northeast to the southwest direction and each of them has their characteristic facies (Buday, 1980). The Northern zone "basin" was occupied by calcareous deposition with subordinate evaporate beds and represented by Sarki Formation. The southwest border of the northern basin according to Buday (1980) could be represented by the axis connecting Duhok, Kirkuk and ChiaSurkh ridge, while the northeastern border is unknown. Toward the southwest direction, the calcareous facies laterally changed to lagoonal evaporitics facies, which filled the central zone of Iraq and occupied the Foothill zone and Mesopotamian basin, and represented by Butma Formation. Further, toward the southwest direction the sedimentation condition changed and dominated by increasing the terrigenous materials which extend from the southwest of the Foothill
Zone in the north to the west of Mesopotamian basin in the south and represented by Ubaid and Hussainiyat formations (Jassim and Goff, 2006 b) (Fig. 1-5).
During the Upper Liassic time, the depositional conditions were almost similar to the underlying sequence except the sea transgression which moves far more to the southwest direction than Lower Liassic, and the consequence was increasing the amount of terrigenous sediments to the southwestern part of the basin. Whereas within the central basin the lagoonal evaporitic condition was prevailed and caused to deposit Adaiya anhydrite, Mus Limestone and Alan anhydrite formations respectively within the Foothill zone and Mesopotamian basin. Toward the northeastern direction, lagoonal evaporitics facies was strongly replaced by calcareous deposits with occasionally euxinic facies as a result of lateral facies change, which is represented by Sehkaniyan Formation (Buday, 1980; Jassim and Goff, 2006 b) (Fig. 1-5).
In general, the Liassic sequence developed as a result of a series of transgressionregression cycles and deposited clearly along the edge of Rutba Uplift (Buday, 1980). As a whole it was deposited under lagoonal-evaporitic conditions except in north and northeast of Iraq, where evaporities are subordinate (Jassim and Buday, 2006 b). The Liassic sequence outcropped in some anticlines of the High Folded zone in north and northeast of Iraq and in the Rutba uplift in western Iraq and the maximum thickness of the Liassic sequences encountered along the boundary between Salman Zone and Mesopotamian basin (ibid).
In the Middle Jurassic period (Dogger), sedimentary system of the basin changed rapidly as a result of huge sea transgression. Consequently, the developed Upper Liassic basins were occupied by a more uniform facies with relatively deep water which is characterized by the euxinic depositional condition (Buday, 1980). The euxinic facies represented by Sargelu Formation filled the former northeastern and central basins that developed during the Liassic period. But further toward southwestern, the euxinic facies laterally changed to neritic calcareous sedimentation and defined by Muhaiwir Formation and dominated by terrigenous sandy materials (Budya, 1980) (Fig. 1-6).
N
Fig: 1-5: Paleogeographic distributions of Liassic sequence in Iraq with indicating the study area. (After Jassim and Goff, 2006 b)
The Middle Jurassic stage was accomplished by the emerged phase that took place by the Kimmerian movement. Thinning the thickness of Sargelu Formation toward northern direction is a good indicator of this movement (Buday, 1980). The Sargelu Formation outcrops in many structures in the High Folded, Balambo-Tanjero and Northern Thrust Zone. Thickness of Sargelu Formation along the Mesopotamian basin and Foothill Zone are not uniforms and changed in east of Iraq and possibly due to the effects of transversal faults (Jassim and Goff, 2006 c).
N
Fig: 1-6: Isopach-Facies map of Middle Jurassic rock units with indicating the study area. (Adapted after Dunnington, 1958)
1.7.2. Stratigraphy of Early-Middle Jurassic Period The following are descriptions of the stratigraphic sequences that have been encountered in SN-1 well from the bottom "Liassic Butma Formation" to the top "Middle Jurassic Sargelu Formation". The stratigraphic column of the successions has been redrawn based on the master log of the SN-1 well (Fig. 1-1). For getting further details on the stratigraphic features of each of the formations, see the Appendix A.
Butma Formation
Butma Formation was defined by Dunnington in (1953) in well Butma-2 in Foothill zone, north Iraq as 500m thick of carbonate unit (Bellen et al., 1959). Further drilled wells recorded various thickness of the Formation, for example 481m in Jabalkand—1 , 285m in Mityaha-1 and 570m in Atshan-1, indicating that the thickest part of the Formation located in the western boundaries of the Mesopotamian basin in south Iraq and in the
Foothill zone north Iraq. The thickness of Butma Formation in the SN-1 well is 368m according to the master log of the well.
Lithologically, Butma Formation is heterogeneous. The upper part mainly comprised of oolitic, pseudo-oolitic and detrital limestone with beds of argillaceous limestone, shale and anhydrite. While the lower part of the Formation composed of limestone with beds of anhydrite (Jassim and Buday, 2006 b).
Fossils assembly within Butma Formation is scarce in Iraq, and not investigated in details, thus the exact age of the Formation is still not fixed, but based on the stratigraphic position which is situated directly above Rhaetic Baluti Formation and below Upper Liassic Adaiyah Formation, therefore the Liassic age was presumed (Aqrawi et al., 2010).
Upper contact of the Formation with Adaiyah is sharp which is located at the base of the lowest anhydrite beds of Adaiyah. The lower contact is conformable and gradational with the underlying Baluti Formation which is taken at the top of the shale-dominated section and below thick limestone of Butma Formation (Bellen et al., 1959).
Butma Formation laterally changed to Uba’id Formation across the stable shelf, while in the north and northeast Iraq Butma Formation laterally replaced by Sarki Formation and the facies change according to Ditmar et al. (1971 in Buday, 1980) occurs along a connecting line of Dohuk and Chemchemal ridge.
Based on lithofacies and fossils content, Butma Formation was deposited in a shallow water lagoonal and sabkha depositional environment (Jassim and Buday, 2006 b).
Adaiyah Formation
Adaiyah Formation was described first by Dunnington (1953) in well Adaiyah no. 1 at the north of Foothill zone, west of Musel (Buday, 1980). The total thickness was 90m that consists mainly of nodular anhydrites with limestone and shales (Aqrawi et al., 2010). Various thicknesses of the Formation have been recorded in different wells, like Sufaya-
2A (128 m), JabalKand (106 m). The maximum thickness of the Formation was in the wells Sufaya-2A and Kifl-1 according to Jassim and Buday (2006), whereas the thickness of Adaiyah Formation in SN-1 well is (136 m) which coincides with the concept that the thickness of the Formation increases from west and northwest Iraq towards the Mesopotamian basin and Foothill zones (Jassim and Goff, 2006 b).
Fossil assembles within Adaiyah Formation is scarce and not sufficient to measure the exact age, hence the age has been defined based on the regional correlation and estimated to be deposited in Upper Liassic (Bellen et al., 1959).
Upper contact with Mus Formation and lower contact with Butma Formation are gradational and conformable according to Buday (1980). In the north and northeast Iraq, Adaiyah Formation has been replaced by Sehkaniyan Formation due to lateral facies change. On the western side of Iraq, Hussainiyat Formation is considered as an equivalent to Adaiyah Formation (Jassim and Buday, 2006 b).
Adaiyah Formation is dominated by anhydrite sediments unit with pure lagoonal facies and was deposited under sabkha environment (ibid).
Mus Formation
Mus Formation was defined for the first time in well Butma-2 by Dunnington in 1953 in (Bellen et al., 1959). Butma-2 well is situated on the Foothill zone of Unstable Shelf north of Iraq (Jassim and Buday, 2006 b). It comprises 50m of thick limestone beds. Lithologically Mus Formation is dominated by dolomitic peloidal limestone with marly limestone, shale and subordinate anhydrite and its relatively uniform throughout the area that existed (Aqrawi, et al., 2010).
Mus Formation was recorded in numerous wells in Iraq with different thicknesses, maximum thickness of Mus Formation has been recorded in well Diwana-1 in the Salman zone in southwest of Iraq and was 92m. The total thickness of Mus Formation in SN-1 well is 42m. The age of the Formation according to relatively abundant fauna, is considered as a late Liassic (Alsharhan et al., 2003). Both contacts of Mus Formation, with overlying Alan
Formation and underlying Adaiyah Formation are appeared to be gradational and conformable (Jassim and Buday, 2006 b).
In contrast to anhydrite Alan and Anhydrite Adaiyah formations, Mus Formation has been deposited in normal marine environment (Alsharhan et al., 2003), which is an indicator of short period of freshening cycle between two intervals dominated evaporitic lagoons environment.
Alan Formation
Alan Formation was first described by Dunnington (1953) in the well Alan-1 that was located in the north of Mosul and the total thickness was 87m (Jassim and Goff, 2006 b).
According to Buday (1980) and Jassim and Goff (2006 b) the lithology of Alan Formation is composed of anhydrites with subordinate pseudo-oolitic limestone. The fossils assemblies are absent, However, the age of the Formation was estimated based on its position in the stratigraphic column, which is located between Middle Jurassic Sargelu Formation and the Liassic Mus Formation, assumed to be a Liassic age.
Alan Formation has appeared in various wells in many locations in Iraq with various thicknesses as a result of wedging out by anhydrites (Buday, 1980). This Formation found in well Makhul-2 with 199m thickness, which is considered as the maximum thickness of the Formation in Iraq. The total thickness of Alan Formation in Sangaw North-1 (SN-1) based on the master log of the well is 141m.
Jassim and Goff (2006 b) stated that both contacts of Alan formation are conformable and gradational with overlying Sargelu Formation and underlying Mus Formation.
Alan Formation is well developed in the Foothill and Mesopotamian zones and parts of Salman zone, but in the western part of Iraq the upper part of Amij Formation may be considered as an equivalent to Alan Formation on the surface (Jassim and Goff, 2006 b). While, in the north and northeast Iraq, the top of Alan Formation corresponds approximately with the top of the Sehkaniyan Formation (Bellen et al., 1959).
Alan Formation is considered as a unique output of an evaporitic phase of deposition at the end of Liassic cycle and was deposited in basin-centered sabkha environment (Jassim and Goff, 2006 b).
Sargelu Formation
Wetzel (1948 in Bellen et al., 1959) described this Formation in the type locality, which is located in Surdash anticline in High Folded Zone, Sulaimani Governorate, North East Iraq (35ο 52’ 44” North and 45ο 9’ 25” East).
In the type section, the total thickness of the Formation is 115 m, composed of thinbedded, black, bituminous limestones, dolometic limestones and black papery shales, with stripe of thin black chert in the upper parts and similar lithology occurs in most outcrops (Balaky, 2004; Aqrawi et al., 2010). Fossil assembly of Sargelu Formation contained Posidonia spp., Parkensonia sp., Stephanoceras sp., Rhynchonella spp., plant fragments and poor impression of ammonites (Balaky, 2004; Al-Ameri et al., 2012). According to Jassim and Goff (2006 c) the age of this Formation was determined based on the species Bositrabuchiiwhich and it is Bajocian-Bathonian.
Both contacts of the Formation are conformable and gradational in type locality area. Upper contact with Naokelekan Formation and the underlying Formation is Sehkaniyan, (Bellen et al., 1959; Balaky, 2004). While in the subsurface section, the lower boundary indicated with the last appearance of anhydrite bed at the top of Alan Formation (Jassim and Goff, 2006 c). This Formation has been deposited in distal, suboxic to anoxic basin (AlAmeri et al., 2013) during Megasequence AP7 which is characterized by widespread transgression over the Iraqi territory during Middle Jurassic (Jassim and Buday, 2006 c).
CHAPTER TWO
Pyrolysis and Organic Petrology
2.1. Background It is widely approved that deposited organic matter (OM) within the sedimentary rock may react (with time, temperature, pressure, and other parameters) to form hydrocarbons (Thompson and Dimbicki, 1986). Formation of hydrocarbon starts by a series of compositional change processes that are dictated by microbial agencies and later with increasing the depth of burial mainly by thermal stress (Horsfield and Rullkotter, 1994). Addressing these compositional changes that are experienced by the OM in the sedimentary basins is crucial in order to predict the evolution pathways of OM and to interpret the geology and petroleum-generation potential (Langford and Blanc-Valleron, 1990). Kerogen, which is generated during the early transformation stage of organic matter, is considered as the major organic compound in the sedimentary rocks (Langford and BlancValleron, 1990). Petroleum geochemists described kerogen as the main source of petroleum compounds (Tissot and Welte, 1978). Screening the characteristics of prospective source rock is commenced firstly by examining the kerogen and OM contents through numerous analytical techniques, like determination of total organic carbon (TOC wt%), Rock-Eval pyrolysis and vitrinite reflectance measurements, in order to determine the quantity, the quality and the thermal maturity of the associated kerogen with the source rocks (Tissot and Welte, 1978; Peters et al., 2005).
2.2. Rock-Eval Pyrolysis Analysis This analysis is considered as a breakthrough in petroleum geochemistry and has become an industry standard procedure in source rock assessment that developed first by Institut Francais du Petrole (McCarthy et al., 2011). Nowadays utilizing elemental analysis in source rock investigation has been strongly replaced by Rock-Eval pyrolysis. Because the former required large quantity of sample in addition to pre-treatment before commencing the test including isolating the kerogen from the rock matrix (Tyson, 1995; Dembicki, 2009). Elemental analysis is an expensive process and time consuming (Hunt, 1996). Rock-Eval pyrolysis is rapid evaluation and requires only 100 mg of pulverized rock sample, and its results are widely accepted among the exploration geologists as an effective means for characterizing the properties of prospective source rocks (Peters, 1986).
2.2.1. Pyrolysis Pyrolysis is the process of heating the organic matter in the absence of oxygen to yield the organic compounds (Peters, 1986). The technique includes heating of a small amount of rock (70-100 mg) or coal (30-50 mg) according to a programmed temperature-rise starting at 300°C in an inert atmosphere (helium or nitrogen) and rising in a rate of about 25°C/min, up to 850°C (15622°F) (Hunt, 1996; Behar et al., 2001). A Flame Ionization detector (FID) detects any organic compounds yielded during the pyrolysis. Sensitive infrared detector (IR) detects generated carbon monoxide (CO) and carbon dioxide (CO 2) during heating and oxidation. The outcomes of the pyrolysis are recorded on a chart, named Pyrogram (Fig. 2-1) (McCarthy, 2011).
2.2.2. Rock-Eval Parameters The Rock-Eval technique provides directly several measurements (parameters) for each sample during the analysis. Each parameter is expressed by its peak that is produced within a specific temperature range and represents a particular group of compounds that are derived from the organic contents and mineral carbon of the sample (Fig. 2-1). The
following are descriptions of the measured parameters by Rock-Eval analyzer which have been quoted from different sources (Espitalie, 1986; Peters 1986; Buchbinder and Halley, 1986; Langford and Blanc-Valleron, 1990; Peters and Cassa 1994; Hunt, 1996; Behar et al., 2001; Ghori, 2002; Peters et al., 2005; Dembicki, 2009 and McCarthy et al., 2011):
The first peak, S1, represents the free oil and gas that emits from the sample without cracking the kerogen during the first stage of heating at 300°C. S1 is expressed by milligram of hydrocarbon that can be distilled thermally from one gram of the rock (mg HC/g rock). S1 is detected by FID detector.
Fig: 2-1: Pyrogram chart showing the provided parameters during Rock-Eval analysis (McCarthy, 2011).
The second peak, S2, corresponds to the hydrocarbons that are released from the sample during the second stage of heating due to thermal cracking of the kerogen contained in the rock sample. S2 reflects by milligram of residual hydrocarbons per one gram of the rock (mg HC/g rock) and is detected by the FID. S2 is the most useful parameter to assess the generative potential of the source rock. The value of S2 yields of the common known source rocks in the world is higher than 4 mgHC/g rock (Hakimi et al., 2010).
The third peak, S3, corresponds to the carbon dioxide (CO2) that is released from the rock sample during the thermal cracking of the kerogen up to 390°C. S3 is expressed by milligram of CO2 per one gram of the rock (mg CO2/ g rock). It is detected by sensitive infrared (IR) detector.
The fourth peak, S4, is produced in response to oxidizing the residual organic carbon in a separate oven. S4 can be divided into two groups of compounds, carbon dioixide (S4CO2) and carbon monoxide (S4CO) peaks (Fig. 2-1). S4 is also detected by Infrared (IR) detector.
The fifth peak, S5, is produced in response to the generated CO2 from the decomposition of carbonate minerals in the sample.
Maximum temperature (Tmax) is the oven temperature that corresponds to the maximum rate of S2 peak (released hydrocarbon). Tmax is measured during the second phase of pyrolysis, when heavy hydrocarbon and kerogen started to crack and provide the S2 peak. Tmax is expressed in degrees Celsius °C and is considered as a powerful Rock-Eval parameter to estimate the maturity level of the organic matter.
Additionally, there are several other indices which can be obtained indirectly through advance elaboration of the obtained Rock-Eval parameters. Those calculated parameters are strongly used to assess the organic matter properties including quantity, quality and maturity degrees. The following are brief descriptions of some of the indices, which are used in the present study in tracking kerogen types and maturation levels of the selected formations. Table 2-1 presents the names and formulas that have been used to find out calculated parameters according to Behar et al. (2001).
Hydrogen Index, HI, corresponds to the amount of elemental hydrogen associated with the kerogen and expressed by mg HC/g TOC. High value of HI represents a greater proportion to generate oil (Table 2-2). Pure end member kerogen types can be tracked from this index (Table 2-3). Once the kerogen enters the oil window, the HI of the organic compounds will start to decrease (Debmicki, 2009).
Oxygen Index, OI, represents the amount of oxygen contents of the kerogen. OI can be used to estimate the maturity level of the kerogen and its types in conjunction to other parameters (Table 2-3).
Table 2-1: Calculated indices from the Rock-Eval parameters (after Behar et al., 2001).
Name
Formula
Abbreviation
Hydrogen Index Oxygen Index Genetic Potential Production Index Bitumen Index
HI OI GP PI BI
Pyrolyzable Organic Carbon
PC
Total Organic Carbon Residual Organic Carbon CO2 Residual Organic Carbon CO Residual Organic Carbon Pyrolysis mineral carbon Oxidation mineral carbon Mineral Carbon
TOC RC CO2 RC CO RC Pyro MinC Oxi MinC MinC
100*S2/TOC 100*S3/TOC (S1+S2) S1/(S1+S2) 100*S1/TOC
[
] + [(S3CO+S3’CO/2) × 12/28]/10
[(S1+S2) ×0.83]+ S3×12/44
PC+RC 0.0273*S4 CO2 0.0428*S4 CO RC CO+RC CO2 =TOC – PC [{S3*(12/44)}+{(S3CO/2)*12/28}]/10 (S5*12/44)/10 Pyro MinC+Oxi MinC
Table 2-2: Describing types of generated hydrocarbons according to HI and values of S2/S3 ratios (after Peters, 1986).
HI Type
S2/S3 mg HC/g TOC
Gas Gas and Oil Oil
0-150 150-300 >300
0-3 3-5 >5
The Genetic (petroleum) potential, GP, is a semi-quantitative index that corresponds to the total amount of free hydrocarbon (S1) and pyrolysis hydrocarbon (S2) during the first and second stages of Rock-Eval pyrolysis (Shaaban et al., 2006). It is utilized to indicate the capacity of the rock for generating hydrocarbon during pyrolysis process and expressed by mg HC/g rock or kilogram of hydrocarbon per metric ton of rock. A value of 2 kg/t is considered as a lower limit for oil source rock. Source rock with less than 2 kg/t has only gas potentiality (Buchbinder et al., 1986). GP<1 kg/t indicated no significant hydrocarbon-generation potential (Katz, 2001).
Table 2-3: Pure member kerogen types classification based on Hydrogen index (HI) and Oxygen index (OI) values (after Dembicki, 2009).
The production index, PI, also known as a transformation ratio, is represented the amount of free hydrocarbon fractions (S1) over the genetic potential (S1+S2). Since the PI gradually rises with increasing the depth of burial, therefore PI is utilized to interpret the thermal evolution of the organic matter during hydrocarbon generation. High PI value is considered as anomalous and can be used to identify the accumulated or migrated hydrocarbon (Hunt, 1996).
2.3. Total Organic Carbon (TOC) The TOC wt% describes the amount of the organic matter in the rocks. It includes both the kerogen and bitumen and it is expressed by weight percent (Peters and Cassa, 1994; Peters et al., 2005; Dembicki, 2009).
Carbon is considered as an essential element of any organic compound in the sediments. Measuring the carbon contents is the only way to evaluate the organic richness of a rock. Since the gas or oil production by any rock is controlled by its carbon content, measuring the TOC is a first step in the source rock evaluation (McCarthy et al., 2011). The TOC wt% only demonstrates the semi-quantitative scale of enrichment of the source rocks with organic matter (Table 2-4), but do not provide a clear indicator for petroleum potentiality. It is proved that a good source rock should have a high TOC, but high TOC is not always a guarantee of high generation potentiality, due to unequal creating of organic matter, some organic matter will generate oil, some will produce gas and some will not generate any hydrocarbons. For hydrocarbons to be generated, organic matter should be associated with hydrogen-rich compounds (Dembicki, 2009). Moreover, TOC content is strongly influenced by the particle size of the sediment, meaning that with decreasing the particle sizes, the content of TOC will increase and vise versa (Hunt, 1996). In this study, the total of 84 cuttings samples from selected formations have been analyzed by using two different instruments in order to determine the TOC wt% of each sample. Appendix B includes the TOC wt% of all the selected samples for this study, as well as the values of Rock-Eval parameters. Table 2-4: Source rock richness classification based on TOC wt% values (Tissot and Welte, 1984).
2.4. Source Rocks Evaluation The main target behind the examination of the kerogen properties within a sedimentary basin is to appraise the source rocks that hosted the kerogen. To make such kind of examination, the potentiality of the source rock should be tested for hydrocarbon
generation, and the types of organic matter should be determined as well as what kind of hydrocarbons might be generated with the maturation of the sediments (Dembicki, 2009). For achieving these targets, chemical analysis and microscopic examination were performed on 84 cuttings samples from SN-1 well for assessing Early-Middle Jurassic formations. The values of TOC wt% and Rock-Eval related parameters that have been used in the present study for describing the characteristics of the formations are presented in Table 2-5. Table 2-5 only shows those samples that have TOC wt% >0.3 and S2>0.2. Since source rock with TOC wt %< 0.3 is not considered as an effective source rock for releasing hydrocarbon (Tissot and Welte, 1984) and the pyrolysis data of the samples with S2<0.2 is unreliable for interpretaions according to Petres (1986).
2.4.1. Source Rocks Quantity and Potentiality Assessment Rondeel (2001) suggested that the capacity of generating hydrocarbons from rocks containing less than 0.5% TOC is so small that expulsion simply cannot occur and the organic matter is strongly oxidized. However, nowadays most authors believe that for liquid hydrocarbons to be generated, TOC contents should be greater than 1%, and more likely a minimum of 2% is required (English et al. 2004). For the present study, 84 samples from Sangaw North-1 well are selected from the depth interval between 3977m and 3198m. This interval included five formations, started from the oldest Liassic Butma Formation to the youngest Middle Jurassic Sargelu Formation. Five formations in total were sampled: Butma (34), Adaiyah (17), Mus (7), Alan (12) and Sargelu (14 samples) (Table 1-1). All samples have been subjected to TOC measurement by Rock-eval 6 in CSTJF center of TOTAL Company and by CHN in GHGeochem analytical laboratory in UK. The procedures for measuring the TOC wt% presented in appendix C. Table 2-6 shows the mean values of TOC contents of the formations with their organic richness status according to Tissot and Welte, (1984) guides (Table 2-4).
Table 2-5: TOC wt% and Rock-Eval pyrolysis data of the selected samples.
Tissot and Welte (1984) guide determined the lowest TOC values for the effective carbonate and shale source rocks of 0.3% and 0.5%, respectively. Thus, samples with TOC content lower than 0.3% have been discarded from further tests. Based on TOC wt% contents, Adaiyah Formation can be categorized as a very good source rock, Alan and Butma formations are classified as poor sources and might be unable to generate hydrocarbon. The Sargelu and Mus formations are good and fair source rocks, respectively. The highest TOC wt% content has been recorded in Adaiyah Formation at the depth of 3477m (Sample ID. 56-Ad), while the lowest TOC wt% values are measured in Alan Formation at the depths 3366m and 3429m (sample IDs. 37-A and 48-A) (Appendix B). Table 2-6: Mean TOC wt% values are tabulated for the studied formations in SN -1 well. (For organic richness assessments see Table.2-4)
Furthermore, utilizing only TOC wt% measurement is not enough to appraise the source rocks if the organic contents are not assessed in terms of potentiality for generating hydrocarbons (Dembicki, 2009). Then, the results of TOC wt% are supported by Rock-Eval parameters like S1, S2 and genetic potential (GP) in order to categorize the selected formations in terms of hydrocarbon-generation potentiality according to Peters and Cassa (1994) and Tissot and Welte (1978) classifications (Table 2-7), as well as relationship between TOC wt% and S2 values (Dembicki, 2009). According to S1 and S2 values, the Sargelu Formation has various potentiality ranges that are distributed randomly throughout the interval from poor to good potentiality,
whereas Sargelu is considered as a fair source rock based on GP values (Table 2-8). Concerning the Alan Formation, the range of potentiality based on S1 and S2 values are between poor to fair potential for generating hydrocarbon, while according to GP parameter, it has fair potential. Both Mus and Butma formations are considered as a poor source for generating hydrocarbon according to S1, S2 and GP values. Only Adaiyah Formation has a good capacity for producing hydrocarbon, since it is a richest one by organic matter among the studied formations (Table 2-8).
Table 2-7: Peters and Casse, 1994 and Tissot and Welte, 1978 classifications for source rocks evaluation.
Table 2-8: Potentiality of the studied formations according to the results of geochemical parameters (after Tissot and welte, 1978; Peters and Casse, 1994). Mean TOCwt% calculated from the overall TOC values (Appendix B), mean S1 and mean S2 are calculated from results of Table 2-5.
The GP values have been plotted against TOC wt% according to Ghori (2002) in order to show further the potentiality of the formations for generating hydrocarbons (Fig. 2-2). It is noticed that the capacities of 85% of the samples for generating hydrocarbon are located within poor and fair zones, only 1 samples of Sargelu Formation and 7 samples of Adaiyah Formation have good to excellent potential. According to Katz (2001) Butma Formation has not any significant potential for generating hydrocarbon because its GP value is less than 1 mgHC/gRock. But Mus Formation with GP value 1.33mgHC/g Rock, could be able to generate gas if sufficiently mature. Both Sargelu and Alan formations with the GP values greater than 2 mg HC/g Rock, are able to generate hydrocarbon (liquid and gas) according to their kerogen types if proper maturity achieved (Table 2-8). The Adaiyah Formation has the highest GP values. Thus, according to the results of TOC wt%, S2 and GP parameters, the possibility of generating hydrocarbon by Adaiyah Formation is higher than other formations.
Fig. 2-2: Petroleum-generating potential of studied samples based on the cross plot of TOC wt% versus potential yields (GP). (the diagram after Ghori, 2002).
Another cross plot regarding the potentiality of the formations for generating hydrocarbon has been used, which is designated from the relationship between the amount of the released hydrocarbon from the kerogen as a result of cracking (S2) and TOC wt% according to Dembicki (2009) (Fig. 2-3).
Fig. 2-3: Cross plot of S2 (mg HC/g rock) versus TOC wt% for describing the hydrocarbon generating potential of studied formations. (the diagram after Dembicki, 2009).
The plotted samples have been grouped into A, B and C groups according to their potentiality. Groups A and B represent more than 94% of the samples that are located within poor to fair potentiality range, and only group C (6%), which includes three samples of Adaiyah Formation at the depths of (3477m, 3489m and 3528m) have good to excellent potentiality and they could generate some oil if sufficiently mature. This result is almost in agreement with categorizing the potentiality of the formations based on GP parameters. The S2 values correspond to the amount of hydrogen elements within the kerogen (Hunt, 1996). Thus, we deduced that the majority of the organic matter of the studied samples associated with small amount of hydrogen elements, refer to low potential of generating liquid hydrocarbons, excluding group (C)
2.4.1.1. Discussion Total organic carbon (TOC wt%) is measured by the sum of pyrolyzable organic carbon (PC) and residual organic carbon (RC) (Table 2-1). From the main data set (Table 2-5) and cross plot between RC wt% and TOC wt% (Fig. 2-4), it is noticed that the values of RC wt % of most of the rock samples are very close to the measured TOC wt% by Rock-eval 6, indicating that only little generative hydrocarbons is left within the studied formations, whereas the TOC wt% of Sargelu and Adaiyah formations are relatively high. Thus, a reasonable assumption might be that the current TOC values of most of the samples are not representative of the initial TOC values. Rock samples may have had much higher initial TOC contents originally (English et al. 2004). Little generative hydrocarbon (S2) in the case of Sargelu and Adaiyah formations that included higher organic contents, could be caused by the minerals matrix effects, where significant amount of S2 generated hydrocarbons adsorbed onto clay minerals (Alalade, et al. 2010) or it could be resulted from the high maturity that caused the organic matter to expulse the majority of their hydrocarbon potentiality. Finally, based on the TOC% and Rock-Eval data, we can suggest that the capabilities of the studied formations for generating hydrocarbon are very low since their ability for producing hydrocarbons during the pyrolysis process is not significant, except Adaiyah Formation that could be able to produce some liquid hydrocarbon if sufficiently mature.
Fig. 2-4: Cross plot of Residual carbon (RC %) versus Total organic carbon (TOC wt%) for the studied formations. (the diagram after English et al., 2004).
2.4.2. Assessment of Source Rocks Quality Evaluation of source rocks quality was carried out through determining the types of the contained kerogen. The majority of hydrocarbons are generated from thermal degradation of kerogen at depth, therefore defining kerogen types is a prerequisite to appraise the source rocks because different types of kerogen have different potentiality (Tissot and Welte, 1978). The term kerogen is defined as all the disseminated organic matter of sedimentary rocks that is insoluble in nonoxidizing acid, bases, and organic solvent (Whelan and Thompson-Rizer, 1993). Kerogen in rocks has four main sources: marine, lacustrine, terrestrial, and recycled (Tyson, 1995; Hunt, 1996). Moreover, produced hydrocarbons are strongly related to the types of kerogen, either type I, II or type III, or type IV kerogen that originated from recycled organic matter.
According to Van Krevelen diagram, there are three main kerogen types that are defined according to their hydrogen to carbon (H/C) and oxygen to carbon (O/C) atomic ratios (Tyson, 1995):
Kerogen type I: Characterized by high initial H/C and low initial O/C atomic ratios. Type I kerogen derives mainly from algal materials that are deposited in lacustrine environments. The main products of this kind of kerogen are waxy oil.
Kerogen type II: Characterized by moderate high initial H/C and moderate O/C atomic ratios. Such kind of kerogen is mainly generated from autochthonous organic matter that is deposited under reducing conditions in a marine environment. Main product of kerogen type II is naphthenic oil and gas.
Kerogen type III: Recognized by low initial H/C and high initial O/C atomic ratios and mainly derived from terrestrial plants and aquatic organic matter, which is influenced by partially aerobic conditions. The main product of this kind of kerogen is gas.
In addition to the three main kerogen types, several other types were recognized from various parties. The most common one is kerogen type IV, which is mainly produced as a result of strong alteration and partially oxidation of organic matter in the depositional environments. Type IV is dominated by high O/C and low H/C atomic ratios and it is inert and does not have generative potential (Tissot and Welte, 1984; Dembicki, 2009).
Kerogen types can be determined from several cross plots that are drawn from the relationships between Rock-Eval parameters. Those parameters are hydrogen index (HI), oxygen index (OI), pyrolyzable carbon index (PCI), maximum temperature (Tmax), Total organic carbon (TOC wt%) and value of S2 peak.
HI versus OI The most applicable plot that is widely used to define the kerogen types is designated between HI and OI (Fig. 2-5), which is also called pseudo Van Krevelen diagram (Tyson,
1995). These indices are strongly dependent on the elemental composition of the kerogen rather than the abundance of organic matter (Tissot and Welte, 1978). The boundary between kerogen types of this cross plot is an expression of the maturity evolution pathway of the organic matter. Moving to the left down corner of HI/OI diagram, a relative increase of thermal maturity is represented (Hunt, 1996). It is clear from the Fig. 2-5, that the kerogen types of the studied samples are composed of a mixture of types II, III and IV, but mostly are type III, which means gas pron. The values of OI of the majority of the samples are high and may suggest reworked and oxidized terrestrial organic matter (Table 2-5) (Buchbinder et al., 1986). Furthermore, the majority of the plotted samples located at the right side of the diagram away from left down corner, suggest that most of the studied samples are immature (Fig. 2-5). The kerogen contents of Sargelu Formation comprises two populations, the first population composed of a mixture of type III and IV and is characterized by HI <150mgHC/g TOC and OI <150 mgCO2/g TOC, in contrast to the second population which is dominated by kerogen type II and type II/III with HI >250mgHC/g TOC and OI >200mgCO2/g TOC (Fig. 2-6). According to Peters, (1986) classification for describing generated hydrocarbons based on HI indices (Table 2-2), the first population of Sargelu Formation can be considered as gas prone sediments, whereas the second population should be gas and oil prone, however the values of S2/S3 ratios of second population are <3 (Table 2-5), which is inconsistent with Peters (1986) classification (Table 2-2).
Fig. 2-5: Showing kerogen types of the studied formations from plotting HI versus OI. (the diagram after Hunt, 1996).
Fig. 2-6: Showing two kerogen populations of Sargelu Formation based on HI versus OI cross plot. (the diagram after Hunt, 1996).
The subdivision of Sargelu sediments into two populations is not reflecting any facies change since the samples of the two populations are distributed randomly throughout and not restricted to particular stratigraphic intervals (Table 2-5). In this case, it is quite
possible that this subdivision is the result of contamination. One of the populations might be representative of the real Sargelu sediment in Sangaw North-1 well and the other could be sourced from out-coming materials like mud additives or migrated oils or generated by in situ maturation (Shaaban et al., 2006). The diagram between S1 and TOC wt% (Fig. 2-7) has been utilized in order to distinguish between indigenous and non-indigenous hydrocarbons of Sargelu Formation samples in order to determine the representative population. Thus, we concluded that the first population could be most expressed of Sargelu sediments than the second population, since the later is plotted as non-indigenous hydrocarbons, which is located above the separated line between the indigenous and non-indigenous hydrocarbons. Concerning the Alan Formation, the same situation as Sargelu Formation has been observed. Alan sediments are subdivided into two populations. According to the S1 versus TOC wt% diagram (Fig. 2-8) two of the studied samples out of four of Alan Formation are located above or close to the separated line between indigenous and non-indigenous hydrocarbons. The first population of Alan Formation (Fig. 2-8), which includes sample (41-A and 44-A) are only the representative samples and composed of a mixture between kerogen type III and IV.
Fig. 2-7: Cross plot of S1 versus TOC%, Showing Sargelu sediment’s populations. The value of S1/TOC wt% ratio of the divided line is equal to 1.5. (the diagram after Hunt, 1996)
Fig. 2-8: Showing the two populations of Alan sediments from cross plot of S1 versus TOC%. The value of S1/TOC% ratio of the divided line is equal to 1.5 ( the diagram after Hunt, 1996)
The non-indigenous hydrocarbon occur where the S1 value is high and TOC wt% is low and mostly developed by mud additive contamination or migrated oil or by the presence of solid bitumen (Peters, 1986). The non-indigenous hydrocarbon is not representative of the organic matter content of the formations; therefore it should be determined and separated from the indigenous hydrocarbon in order to define the kerogen type accurately. The Mus Formation according to HI versus OI plot mainly comprised type III kerogen. Adaiyah Formation is the richest one among the studied formations by kerogen type II/III. Most of the samples belong to Adaiyah Formation dominated by HI >150 (mg HC/g TOC). Therefore, the potentiality of Adaiyah to generate liquid hydrocarbon is high if proper maturity achieved. The Butma Formation consisted of a mixture of kerogen type III and IV.
Pyrolyzable carbon index (PCI) versus TOC% Pyrolyzable carbon index corresponds to the total amount of carbon within the hydrocarbon fractions that can be generated from the samples during the pyrolysis (Shaaban et al., 2006; Abdulla, 2010). PCI is calculated according to the formula: PCI= 0.83*(S1+S2) (Reed and Ewan, 1986).
PCI can be used to estimate the types of kerogen contents as well as to determine the potentiality of the formations. Table 2-9 shows the kerogen types of the studied formations that are defined based on the PCI values according to Reed and Ewan (1986) classification. All the studied samples have PCI values <15 (Table 2-5), except samples 56-Ad and 58Ad of Adaiyah Formation that have PCI values >15 (26.58 and 15.04, respectively). Therefore almost all the samples contain gas prone kerogen (type III), which correspond somehow to kerogen types identification based on HI versus OI diagram (Fig. 2-5).
Table 2-9: Describing kerogen types based on PCI values (Reed and Ewan, 1986).
S2 versus TOC wt% A graph of S2 versus TOC wt% is effective to assess the properties of organic matter associated with sedimentary rocks because it avoids the problem in S3, and reduces the effect of adsorption of mineral matrix and provides a correct value of HI (Langford et al., 1990). The most important factor that controls the generation of oil and gas is the amount of hydrogen contents in the organic matter (Hunt, 1996). The generation potential of the organic matter increases with increasing the atomic hydrogen-to-carbon (H/C) ratio (ibid). Thus, HI values that are derived from the S2 are utilized to indicate the kerogen types (Rondeel, 2001). A graph of S2 versus TOC wt% included two boundary lines between kerogen types (I, II, and III). The first boundary (HI=700) between type I and II refers to organic material with thermal maturity corresponding to a vitrinite reflectance of 0.5-0.6%, and the second
boundary (HI=200) between kerogen type II and III, which seems valid for vitrinite reflectance maturity of 0.5-1.0% (Langford and Blanc-Valleron, 1990). From the diagram of S2 versus TOC% (Figs. 2-9 and 2-10) we can conclude that the majority of the studied samples of Sargelu, Alan, Mus and Butma formations comprise type III kerogen and are plotted within the gas prone zone, except those populations of Sargelu and Alan formations that are described previously as anomalous due to contamination. But Adaiyah Formation is different from the other formations because eight out of fifteen studied samples comprise type II kerogen that is located in the mixed zone (oil and gas). The possibility for generating liquid hydrocarbons from Adaiyah Formation is high (60%) only at the depth 3489m, (sample 58-Ad). Also from the plot S2 versus TOC wt% we noticed that most of the samples positioned close to the down left corner of the diagram indicate high maturity of the samples. Because when the source rocks started to expelled hydrocarbons in response to maturity, the amount of organic matter within the rocks started to decrease, therefore the amount of the hydrogen contents
were also decreased, consequently the S2 values are
suppressed (Dembicki, 2009).
Fig. 2-9: Plot of S2 versus TOC wt% showing the kerogen types of Sargelu, Alan and Butma formations. (the diagram after Langford et al., 1990; Dahl et al., 2004).
Fig. 2-10: Plot of S2 versus TOC wt% showing the kerogen types of Adaiyah and Mus formations. (The diagram after Langford et al., 1990; Dahl et al., 2004)
2.4.2.1. Discussion A review of the results of Rock-Eval analysis (Table 2-5) of the formations shown that all the studied samples characterized by high OI values and high carbonate carbon contents, except Alan Formation where the carbonate contents is not a great but still the OI is high. The average values of carbonate contents that are incorporated to the studied samples are 60%, 74%, 60% and 65% for Sargelu, Mus, Adaiyah, and Butma formations, respectively (Table 2-5). Since the values of TOC wt% of most of the formations are below 2%, so the mineral matrix strongly affected the values of Rock-Eval parameters especially S2 values (Dembicki, 2009). Also from the cross plot of S1 versus TOC wt%, it is noticed that two of the formations are suffering from contamination and this contamination might be affected the values of S1 (Peters, 1986). Based on these points, we can deduce that the Rock-Eval data are precise to interpret the kerogen types of the formations due to the effect of the mineral matrix that is produced in anomalous high oxygen indices, however the high OI could be developed also from oxic depositional conditions (Sassen and Moore, 1988; Tyson, 1995; Shaaban et al., 2006).
2.4.3. Assessment of Thermal Maturity (Tmax) Tmax is a pyrolysis parameter that can be utilized to quickly estimate the thermal maturity level of the organic matter in rocks (Espitalie, 1986). Knowing the organic matter quantity and quality in general is not enough to appraise source rock unless the maturity level is indicated. Because the source rock is able to generate hydrocarbon within a limited range of thermal maturity stage, therefore knowing the maturity evolution of the source rock is important to estimate if the rock is able to generate hydrocarbon or not (Dembicki, 2009). The temperature maximum (Tmax) corresponds to the maximum high of S2 compounds and it strongly depends on the type of organic matter and mineral matrix as well. The range of Tmax values is narrow for Type I kerogen, wider for Type II and much wider for Type III kerogen because of increasing the complexity of the organic matter’s structures (Hakimi et al., 2010).
2.4.3.1. Factors Affecting the Value of Tmax Peters (1986) described that Tmax regularly increase with depth in many wells, also some variations might occur due to unconformity, fault and changes in geothermal gradient. In addition to that, there are other factors that extremely influence the Tmax values and make it not follow the general principles, such as:
Mineral matrix effect: Those rocks that contain TOC<0.5% and are dominated by clay minerals like illite, the calculated HI is too low and Tmax is too high due to the absorption of the pyrolytic compounds by the mineral matrix (illite) during the pyrolysis (Whelan et al., 1993; Dahl et al., 2004).
Contamination effect: The rock cuttings samples of the wells could be contaminated by various sources like caving, drilling fluid additives and migrated bitumen or solid bitumen (Rondeel, 2001). Such kind of contamination severely alters the characteristics of kerogen portion of the samples, thus produces anomalous values for the Rock-eval parameters especially Tmax and S2 (Whelan et al., 1993). It is the responsibility of the researchers to define such kind of cases, otherwise it
will lead to inadequate predictions regarding the productivity of the concern rock samples. In most of the cases, the Pyrogram of the contaminated samples show a high value of S1 peak, low Tmax and S2 peak mostly has a double lobes (bimodal) appearance (Fig. 2-11), in addition to an anomalous high production index (PI) values (Peters, 1986; Whelan et al., 1993).
Fig. 2-11: Pyrogram chart of contaminated rock sample, showing a bimodal displayed of S2 peak (Adapted from Peter, 1986).
2.4.3.2. Maturity Assessment of the Formations Various standards have been developed in order to demonstrate the maturity level of the OM of rocks. Some of the standards were established based on the Rock-Eval parameters. For the present study, the Tmax and PI classifications (Table 2-10) have been used to describe the maturity stages of the formations.
Table 2-10: Showing the guide line for describing degree of thermal mat urity (After Bacon et al., 2000; Peters et al., 2005)
According to the values of Tmax (Table 2-11 and Fig. 2-12), all the studied rock samples of SN-1 well are considered as immature. Maximum Tmax (424°C) has been recorded in Mus Formation at the depth of 3441m and the minimum Tmax (293°C) is recorded in Alan Formation at the depth 3312m (Table 2-5). On the other hand, based on the values of production index (PI), which is considered as an important parameter for describing the maturity, all the analyzed samples are within mature status (Table 2-11 and Fig. 2-12). Such kind of discrepancy between Tmax and PI values mostly occurred by contamination either by drilling mud additive, migrated oil or by the presence of significant amount of bitumen (Peters, 1986). In addition to that, the Pyrogram charts of most of the analyzed samples are shown bimodal displayed of S2 peaks (Fig. 2-13).
Table 2-11: Presenting the thermal maturity stages of the studied formations from the Tmax and PI ranges based on the stand ards presented in Table 2-10.
Fig. 2-12: Showing the comparison between Tmax and PI values of the studied samples as a function of depth.
Such a low Tmax values of the studied samples and bimodal appearance of S2 peaks might be developed due to the existence of heavy ends of oil within the analyzed rock samples. This is because heavy ends of oil contributed to S2 peak rather than S1 peak and caused to reduce the Tmax and create bimodal situation of S2 peak. Moreover, the same circumstances could be developed by solid bitumen (Peters, 1986; Whelan et al., 1993).
2.4.3.3. Discussion Based on the presented criteria (low Tmax, high PI and bimodal S2 peak), it is suggested that the majority of the analyzed samples of SN-1 well are contaminated either naturally by migrated oil or solid bitumen or artificially by organic mud additives. Therefore the Tmax and PI values are not reliable to characterize the maturity stage of the formations.
Furthermore, Abdulla (2010) used Rock-Eval analysis for study the thermal maturity of Sargelu Formation in the northern Iraq and he suggested that the maturity of Sargelu Formation increases from northwest toward northeast direction and according to his conclusion the maturity “Tmax” of Sargelu Formation in the area where the SN-1 well was drilled was supposed to be above 460°C, which corresponds to post mature zone, which is also not agreed with the lower Tmax values of the current study. Consequently, the current Rock-Eval results are supported by another analysis, which is Vitrinite Reflectance measurement in order to make an accurate decision concerning the maturity stages of the studied formations.
2.4.4. Vitrinite Reflectance Measurement Analysis (VR ο %) Reflectance Measurement method of dispersed organic matter in sedimentary rocks, like vitrinite particles, is widely used and is considered as a key diagnostic tool for evaluating the maturation of kerogen (McCarthy et al., 2011; Petersen et al., 2013). This method is based on the fact that with increasing thermal stress, the reflectance value of the vitrinite particles and other dispersed organic matter (DOM) in the rocks increase as a result of irreversible aromatization reactions (Peter and Cassa, 1994; Rondeel, 2001). Vitrinite Reflectance measurement is a microscopic technique that was initially developed to determine the thermal maturity of coals. Later on, the scientists realized that it is possible to extent its application to include maturation identification of other rocks like carbonate and shales that retained small vitrinite inclusions in order to determine the petroleum regions that do not contain coal deposits
(Hunt, 1996).
Vitrinite is a maceral that is derived from the partly decomposition and thermal alteration of lignin and cellulose tissues of higher land plants which are found in many kerogens (Petersen et al., 2013). However, there are three main groups of macerals, but reflectance measurement is only made on vitrinite group because other macerals groups (liptinite and inertinite) mature at different rates (Peters et al., 2005). Vitrinite Reflectance measurements are unable to indicate exactly the start time of migration or how much hydrocarbon was expelled, but can be applicable to estimate when expulsion might be possible (Dembicki, 2009). The stages of hydrocarbon generation of source rocks in respect to vitrinite reflectance values have been showed in Table 2-12. In the absence of vitrinite particles in Early-Middle Jurassic rock samples, reflectance measurements have been performed on other sources like bitumen (micro granular and homogenous bitumen) and Vitrinite-like particles and then the reflectance (bitumen reflectance BRο) values are converted to equivalent vitrinite reflectance (eq.VRο%) according to the following equations: eq.VRο=0.618*(BRο) + 0.40 (Jacob, 1989)
eq.VRο=0.277*(BRο) + 0.57 (Riediger, 1993) Eventually, eq.VRο% values have been used to characterize the maturity levels of the studied source rocks according to the presented guideline in Table 2-12. Table 2-12: Showing stages of hydrocarbons generation according to the values of Vitrinite Reflectance (After Dembicki, 2009).
Oil Generation Generation stage Immature Early oil Peak oil Late oil Wet gas Dry gas
Gas Generation Ro%
<0.6 0.6-0.8 0.8-1.0 1.0-1.35 1.35-2.0 >2.0
Generation stage Immature Early gas Peak gas Late gas
Ro% <0.8 0.8-1.2 1.2-2.0 >2.0
Bitumen (pyrobitumen or solid bitumen) is a so-called secondary maceral which represents accumulation of heavy petroleum that contains a significant amount of solid phase that could be generated from the main source rock or could be migrated from another source to the host rock. Therefore, migrated bitumen may occur in organic-lean rocks (Landis and Castaño, 1995; Petersen et al., 2013). Solid bitumen is commonly occurring as an amorphous matrix within the pore spaces of the rocks (Taylor et al., 1998). In the present study six cuttings samples, two samples from Sargelu Formation (3225m and 3270m), one sample from Mus Formation (3465m), one sample from Adaiyah Formation (3528m) and two samples from Butma Formation (3645m and 3882m) are analyzed by CSTJF center of Total company in France to truck thermal maturity status. The selection of the samples was based on their richness with TOC wt% contents and their position in the stratigraphic column of the formations. For performing optical analysis on the selected samples, a reflected microscope equipped with white and blue light (fluorescence mode) sources and a photomultiplier for reflectance measurements has been utilized. The analyses are carried out on both polished concentrates of organic matter obtained by densimetric techniques, and on
polished sections of whole rock grains. Due to the richness of the samples by organic particles and the variety of organic populations, up to 100 readings per slides were recorded. Reflectance measurements are performed with natural white light (random reflectance Ro%).
2.4.4.1. Organic Matter Identification The organic matter that encountered in the Sangaw North-1 well is made up of different organic particles (solid bitumen often dominant). For some organic concentrates different populations of particle have been observed in the same polished mounts. Figs. 2-14 to 2-18 (photomicrographs) illustrate different populations encountered in the samples. The following are descriptions of the organic particles and populations that have been observed: Lignite mud additives: they consist of typical trimacerite lignite rich in vitrinite of low reflectance (around 0.35% VRo), such type of mud additives is frequent in petroleum wells (Hunt, 1996) (Fig. 2-15-A). They are present in four samples and always in low amount. Vitrinite: they are relatively typical and consist of homogeneous fragments of small size (Fig 2-18-A, B, and D). They have only been observed in the sample of Butma Formation at 3645m. These vitrinites are good representative for maturity evaluation. Microgranular bitumen: such solid bitumens are frequent in sapropelic source rock (Jacob, 1989; Landis and Castaño, 1995). They are frequent in the two samples of the Sargelu Formation (3225m and 3270m). These bitumens are rare in the deeper samples. In concentrate polish section, they consist of figured fragments (Figs 2-15-C and 2-17-B), whereas in whole rock they consist of inclusions in the macroporosity of the rock (Fig 2-14-A and B) or more massive deposits (Fig. 2-16-A). Due to their abundance and close association with the mineral matrix (autochthonous secondary organic matter), they can be used for maturity assessment.
Homogeneous bitumen: as for microgranular solid bitumens, homogeneous fragments of bitumen are often encountered in source rock. They can be associated with the microgranular population or not. In SN-1 well they have only been encountered in the Sargelu Formation. They consist of discrete fragments, whereas in the whole rock they mainly correspond to pores fillings (Figs. 2-14-A, B and 2-16-B). As for microgranular bitumen, it is abundant within the two examined Sargelu Formation samples and association with microgranular bitumen indicating that they are generated by the surrounding organo-mineral matrix (secondary organic matter with very low migration in the rocks). That means that they can be used for maturity evaluation. Their homogeneous aspect is more useful for reflectance measurements than microgranular ones (possible mixture of bitumen and mineral) (Landis and Castaño, 1995). Anisotropic bitumen: with increasing maturity the anisotropy of organic matter (coal and bitumen) is increasing (Taylor et al., 1998). Some samples show anisotropic bitumen, they probably correspond to a thermal evolution of the two previous bitumen populations (microgranular and homogeneous)(Fig. 2-17-A and B). As for the two previous populations they can be used for maturity assessment. Highly anisotropic bitumen: some highly anisotropic bitumen has been observed (mosaic aspect). They are rare and show a high reflectance. They probably correspond to mud additives (Fig. 2-15-D). Inertinite: they are mainly made up of undetermined fragments and fragments of semifusinites (inertodetrinites). They are frequent in the two concentrates of the Sargelu Formation, rare at 3645m but associated with the vitrinite population (Fig. 2-18-C). No reflectance measurement has been performed on the inertinite group.
Fig. 2-14: Microgranular and homogenous bitumen in a carbonate matrix of Sargelu Formation sample at the depth 3225m. A) Homogenous bitumen, RO= 1.32%, B) Microgranula bitumen, RO= 1.70% and Intertinite(Makrinite maceral).
Fig. 2-15: Showing various organic matter populations in the sample of Sargelu Formation at the depth 3270m, including A) Lignite (Texto-ulminite)mud additive RO= 0.34%, B) Microgranular bitumen, RO=1.23%, C) Microganular bitumen (high reflectance), R O= 2.41%, D) Anisotropic bitumen, RO= 2.25%.
Fig. 2-16: Microgranular and homogenous bitumen in rock sample of Sargelu Formation at the depth 3270m. A) Microgranular bitumen, RO= 2.3%, B) Homogenous bitumen.
1.1 .
Fig. 2-17: Anisotropic microgranular bitumen in the rock sample of Adaiyah Formation at the depth of 3528m. A) Anisoptropic bitumen, RO= 3.45%, B) Anisotropic microganular bitumen, R O= 3.37%.
1.2 .
Fig. 2-18: Vitrinite and Semifusinite particles in the rock sample of Butma Formation at the depth of 3645m. A) Vitrinite (Detro vitrinite), R O= 1.77% and 1.91%, B) Vitrinite, RO= 1.84%, both plates have been indicated from the concentrated section, C) Semifusinite, D) Vitrinite, R O= 1.83% and Semifusinite.
2.4.4.2. Maturity Profile of the Formations The vitrinite at 3645m (Butma Formation) gives the best maturity assessment of the six samples. In the Sargelu and Adaiyah formations, bitumens can be considered as good maturity parameters (autochthonous solid bitumen closely associated with the mineral matrix) and useful for maturity estimation. Other particles (mud additives) have not been used (Fig. 2-15-A). Bitumen reflectance increases with depth as vitrinite does, but bitumen reflectance (secondary products with chemical composition different reflectance from the vitrinite) must be corrected to obtain an equivalent vitrinite (Jacob, 1989). In literature, there are different correlation curves between bitumen and vitrinite; TOTAL used the most common curve: Jacob’s curve (VRo = 0.618 * BRo + 0.40) to convert BRο to eq.VRο (Table 2-13). We made some modifications to the TOTAL’s results based on the histograms of the reflectance measurements, in addition to using Riediger’s equation besides the Jacob’s formula to get an equivalent vitrinite reflectance eq.VRο from bitumen reflectance BRο. This is to make a comparison between the results of the equations and choose which of them is more proper to interpret the thermal maturity of the formations (Table 2-14).
Modification Factors
Below find the procedures that we applied to make modification to the TOTAL’s results: Rock sample of Sargelu Formation at the depth 3225m has three Ro, 0.35%, 1.50% and 1.61% that is measured on vitrinite of mud additive, homogenous bitumen and microgranular bitumen, respectively (Table 2-13). TOTAL suggested 1.61% as representative BRο% which belongs to microgranular bitumen. But we assumed that BRο% of the homogenous bitumen might be more accurate than microgranular bitumen because it has a uniform reflection and the reflected light from the bitumen not affected by the
surrounding particles (Landis et al., 1995). Therefore we preferred to select the BRο% of the homogenous bitumen which equals to 1.5% rather than the value of microgranular bitumen (Appendix D-1). 2.36% was indicated by TOTAL as a mean value of BRο% from 34 reflectance reading of Sargelu’s sample at the depth of 3270m. But the 34 readings have been taken from unknown dispersed organic matter particles including anisotropic bitumen, however there are 11 reflectance reading (1.55%-2.48%) directly taken from the known bitumen (mostly homogenous bitumen) (Appendix D-2). We preferred to use that 11 reading as a representative BRο% because the measurements have been taken directly from the known bitumen rather than unknown sources, which decrease the level of confidence. The BRο% of Mus Formation at the depth 3465m was not calculated by TOTAL due to insufficient measurements. But based on the histogram (Appendix D-3) there is a possibility to roughly predict the BRο% of Mus Formation from 4 measurements (1.98%-2.19%) that made on anisotropic bitumen; however the confidence is very low. TOTAL suggests 3.24% as a mean BRο% value of Adaiyah sample at the depth 3528m from 27 reflectance readings, (ranging from 2.66%-3.76%). This value has been modified based on the histogram (Appendix D-4). We assumed that the BRο% of the first population considered as representative values of the samples which comprised of 6 measurements. The range of BRο% values of the first population is between (2.66%-2.88%) and the mean value is 2.78%. This value appeared to be more consistent with the above and lower reflectance based on the fact that with increasing the depth of burial, the reflectance increases as a result of higher maturity.
Table 2-13: Presenting the results o f reflectance measurements of the selected rock cuttings samples that are performed by TOTAL Company.
Table 2-14: Presenting the results of reflectance measurement of the selected rock cuttings samples after modification .
Based on the eq.VRo% results that are obtained from the Riediger’s equation (Table 214), all the samples are within the oil-window from peak to late stage of generation except Butma Formation which is a gas window (Fig. 2-19). This conclusion definitely is not consistent with the situation of the SN-1 well, since the product of it was only gas. Moreover, small released hydrocarbon (S2) during the Rock-Eval pyrolysis is not in agreement with the oil-prone sediments, because oil-prone sediments always produce higher S2 values when TOC wt% contents are high as in the case of Sargelu and Adaiyah formations. Also, the analyzed organic particles are non-fluorescent, which is a very good sign of non-potentiality of the formations for generating oil (Hunt, 1996; Alsharhan and Abd El-Gawad, 2008). Therefore, the eq.VRo% values of the rock samples derived from Riediger’s equation are not accurate to estimate the current maturity situation of the formations. According to the results of Jacob’s equation, the maturity of the Sargelu Formation is high (gas window) with the values of 1.33% eq.VRo and 1.51% eq.VRo at the depths 3225m and 3270m, respectively. The Mus Formation also has a high maturity (gas window) with value of 1.76% eq.VRo at 3465m. The maturity of Adaiyah Formation is still high (2.1% eq.VRo) and within the gas window. The maturity of Butma Formation that was measured directly on vitrinite particles was 1.90%, which indicates gas window. Jacob’s equation results are almost in agreement with the previous conclusions concerning the characteristics of the studied formations including low HI and small S2 yields that occurs at higher maturity stages. In addition to that, the non-fluorescence properties of the samples are a good indicator for deficiency of the formations to generate oil (Hunt, 1996). Eventually, based on the above criteria, we assumed that the proper equation to convert the bitumen reflectance to equivalent vitrinite reflectance (eq.VRo %) for the analysed samples is Jacob’s equation.
Fig. 2-19: Plotting eq.VRO% versus depth to show maturation trend according to Jacob and Riediger equations.
2.4.4.3. Discussion Based on vitrinite reflectance analysis, it is concluded that due to high maturity (no fluorescence), the type of organic matters encountered in the Sargelu Formation cannot be optically determined (type I or type II – abundant bitumen). The organic content of Mus Formation is not recognized due to low quantity of organic matter, however it includes few bitumen but difficult to characterize kerogen types. In Adaiyah Formation, high rank anisotropic bitumen has been detected, but still due to high maturity, the determination of kerogen types is impossible. Vitrinite and semifusinite observed in Butma Formation at 3645m correspond to type III organic matter (kerogen). The maturity profile of the Early-Middle Jurassic section shows that the maturity is high (gas generation zone) with equivalent vitrinite reflectance (vitrinite and equivalent
from bitumen using Jacob’s curve) between 1.4% to 2.1% eq.VRo from Sargelu to Adaiyah formations and 1.9 VRo% for Butma Formation. The presence of various populations of organic fragments including organic mud additives (lignite) and abundance of bitumen (anisotropic bitumen) may explain the unreliability of the Rock- Eval Tmax °C (70% of Tmax values lower than 400°C).
CHAPTER THREE
Biomarkers
3.1. Background The organic compounds that existed in sediment, rock, and
oils whose carbon
structures can be traced back to living organism are defined as biological markers or biomarkers (Hunt, 1996). Biomarkers may be directly inherited from living organisms or may be generated by organic matter alteration through diagenetic or catagenetic processes in sediments (Connan, 1993). The biomarkers are microfossils with the diameter generally less than 30nm and characterized by having various stereochemistry (Hunt, 1996). Stereochemistry is the three-dimensional relationship between the atoms in molecules of biomarkers. Defining the stereochemistry is important to understand the structure of each biomarker and how they are utilized in geochemical studies (Peters et al., 2005).
The stable carbon-carbon skeleton of the biomarkers that is originated from chemical and geological transformation of bimolecules of their ancestral deposited during sedimentary processes hold essential information on the (1) behavior, (2) habit, and (3) nature of their precursors (Osuji and Antia, 2005). Connan (1993) stated the conversion from bimolecular (biolipid) to biomarkers (geolipid) occurred without any transformation of the carbon-carbon skeletons or might show little rearrangement that is not strongly affecting the structures of biomarkers. Moreover, petroleum is generated from the organic matter that is preserved in fine grain rocks (Peter et al., 2005). Thus, the derived biomarkers from the organic matter according to Connan (1993) can be used to:
1 Indicate the origin of disseminated organic matter within the sediment by the recognition of biomarkers specific for well -define categories of living organisms. 2 Reset the paleoenvironmental conditions by monitoring the chemical reactions that are controlled by salinity, Ph, and oxicity -anoxicity. 3 Perform oil-oil and oil-source rocks correlations. 4 Investigate the maturity stages of both sediments and oils through observing various chemical reactions, such as isomerization and aromatization.
3.2. Analyzed Samples In the present study, five samples consisting of rock-extracted sample from Sargelu Formation, two crude oils, condensate and seep oil that are selected from Sangaw North1 well, Sarqala, Pulkhana, KorMor, and ChiaSurkh oil fields respectively, have been analyzed by GC and GC-MS.
Concerning the selected rock extracted sample, it is realized that based on TOC wt% and Rock-Eval analysis for the cuttings samples, the majority of rock samples do not include significant amount of organic matter as well as pyrolyzable hydrocarbon compounds S2. Accordingly, only 100gm of rock-cuttings from the depth interval 3237m to 3213m of Sargelu Formation is selected for characterizing its molecular distributions and performing correlations with the oil samples. The objective of selecting a large amount of the cuttings rock (100gm) is to obtain a proper amount of liquid extracted that is required for GC and GC-MS analysis.
3.3. Analytical Method The studied samples have been prepared by CSTJF center in France according to their procedures for GC and GC-MS analysis (Appendixes E and F explained the procedures for sample preparation and GC-MS method). The GC-MS analysis was carried out with selected ion monitoring mode (SIM) in order to get information about the n-alkane and isopernoids compounds and defining the distribution of most common biomarkers and
the related compounds that are widely used to find out the maturities, sources of the oil samples and to establish a genetic relationship between the samples in order to categorize the oil families in the study area.
3.4. Gas Chromatography Analysis Gas chromatography (GC) analysis is performed for quantification of individual hydrocarbon compound and is usually executed on oil samples, rock extracts or saturated and aromatic hydrocarbon fractions of crude oils and bitumens (Sletten, 2003). Since (GC) with flame ionization detector (FID) is not sensitive enough to detect the small amount of organic materials like biomarkers that are often the most useful for making correlation and it could be hidden in the baseline of the chromatograms (Philp, 1993), therefore in this study only the results of GC-MS/SIM analysis have been used to characterize the studied samples in terms of maturity, source rocks quality and depositional conditions, whereas the GC-FID traces of the samples are used only to explain the rate of biodegradation on the petroleum samples.
In the present study, the GC-MS/SIM was used to monitor the ions with the mass/charge ratio (m/z) of 85, 178,184, 191,192, 217, and 231. Most of the peaks are indicated from their chromatograms and the areas under the peaks have been used to measure the following parameters (Appendix J showing the peak areas of the compounds).
3.5. The Measured Parameters From the mass chromatogram m/z 85, we can measure the following common parameters for the oil and rock extracted samples from the areas of n-alkane and isoperinod isoalkanes compounds including pristane and phytane. In Fig. 3-1, the m/z 85 of Sarqala crude oil is presented as a case study with indicating the peaks of pristane and phytane. 1- Carbon Preference Index (CPI) al., 1985); 2- Pristane/ nC17 (Pr/nC17) ratio (Moldowan et al., 1985);
(Moldowan et
3- Phytane/ nC18 (Ph/nC18) ratio (Moldowan et al., 1985); 4- Pristane/Phytane (Pr/Ph) ratio (Moldowan et al., 1985);
From the chromatogram of m/z 191, it is possible to measure the following parameters from the areas of tricyclics and pentacyclics compounds of the oil and rock extracted samples. (In Fig. 3-2, most of the peaks of the related tricyclics and pentacyclics compounds of Sarqala crude oil have been indicated by labels. The identification of peak labels that is used for calculating the parameters is submitted in Table 3-1).
5- 18α
(H)-trisnorneohopane/
(18α
(H)-trisnorneohopane
+
17α
(H)-
trisnorhopane) Ts/Ts +Tm (Mackenzie, 1984) 6- 22S/ (22S + 22R) of C31 17α (H), 21ß (H)-hopanes (Peters et al., 2005); 7- C19-C30 Tricyclic terpanes/17α-hopanes (Peters et al., 2005); 8- C35 homohopane index and C35/C34 or C35S/C34S hopanes (Hunt, 1996); 9- C29/C30 (Norhopane/ Hopane) (Peters et al., 2005); 10- Oleanane / Oleanane + C30 hopane (Oleanane index) (Hunt, 1996); 11- Gammacerane/Gammacerane+ C30 hopane (Gammacerane index) (Hunt, 1996); 12- Steranes/17α-hopanes ratio (From both chromatograms m/z 191 and m/z 217);
The mass chromatogram m/z 217 of steranes has been used to measure the following parameters. (The m/z 217 chromatogram of Sarqala sample has been presented In Fig. 33 with indicating the peaks of regular steranes and their isomers by labels. In Table 3-2, the identification of the peaks is summarized). 13- ββ/(ββ + αα) of C29 (20R + 20S) sterane isomer (Mackenzie et al., 1980); 14- 20S/(20S + 20R) of C29 5α(H), 14α(H), 17α(H) steranes (Mackenzie et al., 1980); 15- C27 (S+R) diasterane/( C27 (S+R)diasterane + C27 (S+R)regular sterane) (Peters et al.,2005);
16- % C27ααR of C27ααR + C28ααR + C29ααR -steranes (Mackenzie et al., 1985); 17- % C28ααR of C27ααR + C28ααR + C29ααR -steranes (Mackenzie et al., 1985); 18- % C29ααR of C27ααR + C28ααR + C29ααR -steranes (Mackenzie et al., 1985);
Ions of m/z 178, 184, 192, and 231 of aromatic compounds have been used to calculate the below parameters. (Fig. 3-4 shows the chromatograms of the mentioned m/z traces of Sarqala oil sample, and the identity of the peaks shown in Table 3-3).
19- TA(I)/(TA(I+II) triaromatic steroids (TAS) (Peters et al., 2005); 20- DBT/P (Dibenzothiophene (m/z 184)/ Phenanthrene (m/z178) (Hughes et al., 1995), and 21- Methylphenanthrene index 1, MPI 1 (Peters et al., 2005).
Fig. 3-1: Showing m/z 85 chromatogram of Sarqala oil sample, including peaks of nC 17, nC18, pristane and phytane and other n-alkanes compounds. (Appendix J showing the peak areas of the compounds).
Fig. 3- 2: Showing m/z 191 chromatogram of Sarqala crude oil. (Peaks identification in Table 3-1)
Fig. 3-3: Showing m/z 217 chromatogram of Sarqala crude oil including regular steranes. (Peaks identification in Table 3-2)
Fig. 3-4: Showing m/z chromatograms of aromatic compounds including P) Phenanthrene, DBT) Dibenzothiophene, MP) Methylphenanthrene, and T) Triaromatic steroids of Sarqala crude oil. (Peaks identification in Table 3-3)
Table 3-1: Presenting the identification of most of the tricyclic and tetracyclics compound peaks of ion m/z 191 of Fig. 3-2.
Table 3-2: Showing the identification of regular and isomers of sterane compound peaks of Fig. 3-3.
R
Table 3-3: Showing the identifications of the aromatic compound peaks that presented in Fig. 3-4.
The following are descriptions of most of the parameters that have been used in the
present study for interpreting the results of GC-FID and GC-MS analyses:
1- Carbon Preference Index (CPI): CPI is a numerical expression of odd-over-even predominance of n-alkanes compounds in the specific carbon ranging from (C 22 to C30). It is mostly used as an indicator for predicting the maturity status where C25-C33 n-alkanes from higher plant wax are available (Killops and Killops, 2005). The value of CPI for mature oils are usually close to 1, but <1 means dominant of even numbered n-alkanes over the carbon ranges with refereeing to marine carbonate-evaporite depositional conditions or thermally mature (Cooper, 1990; Peters et al., 2005), but CPI>1 means immature higher plant contributions. The CPI values generally became closer to 1 with increasing maturity. 2- Pristane/nC17 and Phytane/nC18: These two parameters are used together and with the other parameters to determine the source rock facies, maturity and level of biodegradation. Low ratio of these parameters is a good indicator of high maturity because the isoprenoids will break down earlier than n-alkanes during increasing the maturity (Peter and Moldowan, 1993). Pr/nC17 ratio could be used to characterize the environment of deposited organic matter, for example for marine environment Pr/nC17 ration is < 0.5 (Osuji et al., 2005). The ratios of these parameters should be used carefully because their values are strongly affected by biodegradation and make it over estimated because biodegradation generally attack n-alkanes before isoprenoids. 3- Pristane/Phytane: They are derived from phytol side-chains in chlorophyll and generally their ratio is used to assess the depositional environment of the source rocks (Tissot and Welte, 1978). The Pr/Ph ratio (>1) means the source materials deposited under oxic to dysaerobic environment, because oxic condition enhances the conversion of phytol to pristane by oxidation of the phytol side chains, whereas Pr/Ph ratio (<1) is referred to anoxic condition when accompanied by high porphyrin and high sulfur contents because anoxic is a favored condition to produce cleavage of the phytol side chain to produce phytol, which subjects reduction to dihydrophytol and then to phytane (Cooper, 1990). The ratio increases with increasing maturity (Peters et al., 2005). The Pr/Ph ratio should always be confirmed by other geochemical data like sulfur
contents, C35 homohopanes index and C27 diasteranes abundance, because Pr/Ph ratios in most of the cases are in agreement with the results of the mentioned parameters. 4- Ts/Ts +Tm: Sometimes addressed as Ts/Tm, this ratio depends on both source rocks and maturity. The stability of C27 17α(H)-trisnorhopane (Tm) during catagensis process is less than C27 18α(H)-trisnorneohopane (Ts), so with the increase of the maturity, the amount of Tm decreases compared to Ts. Ts/Ts +Tm appears to be sensitive to clay-catalyzed reactions and because of that those oils that are derived from carbonate source rocks generally show unusual low Ts/Ts +Tm, in contrast to shale source rocks (Peters et al., 2005). 5- 22S/ (22S + 22R) of C31 17α(H), 21β(H)-hopanes: It is a maturity parameter and the ratio increases from 0 to 0.6 (0.57-0.62 is the equilibrium range). The 17α(H)homohopane has two isomers R and S (Osuji et al., 2005). The biologically hopane precursors hold a 22R configuration and it is gradually with increase of the maturity convert to a mixture of 22R and 22S. The proportion of 22R and 22S can be measured for any or all of the C31-C35 homohopane compounds to determine maturity stages (Peters et al., 2005). 6- Tricyclic terpanes/17α-hopanes: This ratio is used to estimate the maturity, since it is not precise for mature to post mature stages due to interference from source input. Generally, this ratio increases with increasing the maturity because more tricyclic terpanes release from the kerogen than 17α-hopanes (Peters et al., 2005). Furthermore, these two groups of biomarkers are used for correlation purpose between oils that developed from different sources because they are derived from different biological precursors during diagenesis process (Peters and Moldowan, 1993). 7- C24 tetracyclic terpanes/C30 hopane: It is a maturity parameter and the ratio increases in more mature source rocks and oils, because of high stability of teteracyclic terpane under thermal stress than hopanes. In addition to that, it is also possible to compare the amount of teteracyclic terpane with tricyclic terpanes like C23 and C26 that might be used as source indication parameters. Generally, predominance of C24 teteracyclic terpane appears to be related to carbonate and evaporite depositional setting of source rocks (Peters et al., 2005).
The tetracyclic terpanes show a high resistance to biodegradation than hopanes, therefore sometimes used as a correlation parameter in altered crude oils. 8- C35 homohopane index: Also referred to as C35/C34 and C35S/C34S hopanes. Sometimes only S configuration is used rather than R to avoid interference. This index is used to predict the redox potential during the diagenesis process. Higher value represents anoxic condition. Most of the oils that are derived from marine carbonate rocks have a higher value of homohopane index (>0.8) that combined with high C29/C30 hopane ratio (> 0.6) (Peters et al., 2005). 9- The value of C31R homohopane can be used relative to C30 hopane to distinguish between source rocks that deposited under lacustrine or marine environments, the ratio of C31R/C30 hopane, greater than >0.25 represents marine depositional environment. 10-
Norhopane/ Hopane: Also expressed as C29/C30 hopane and is considered
an important parameter for describing anoxic carbonate or marl source rocks. The value of this ratio for most of the oil that generated from anoxic carbonate or marl is >1, while for other samples is < 1. Also it is possible to use as a maturity indicator since norhopane appears more stable than hopane (Peters et al., 2005). 11-
Oleanane/Oleanane+C30 hopane (Oleanane index): Also expressed as
OI/H or OI/OI+H. It is a source input and age indicator that is derived from angiosperms and higher plant of Upper Cretaceous and younger age rock units. This ratio is widely used for crude oil-source rock correlation (Hunt, 1996). According to Peters et al. (2005) the presence of Oleanane in crude oil is not always evidence of post-Jurassic source rocks for the related oil because within crude oils and rock extracts of Jurassic period small amount of Oleanane has been found. 12-
Gammacerane index: This index is measured either by
gammacerane/gammacerane+ C30 hopane or gammacerane/C31R (Ga/C31R). It is a typical indicator of water stratification in marine and non-marine environment of source rocks, frequently accompanied by low Pr/Ph ratio. Gammacerane appears to be abundant in hypersaline carbonate and evaporitics depositional environments. It shows much more resistance to biodegradation than hopanes (Hunt, 1996).
13-
Sterane/Hopane ration: This parameter is performed based on the fact
that the main source of hopanes is bacteria, while steranes are derived from algae and plants and when the ratio is high means that the source is dominated by marine algae, but the lower ratio reflects bacteria rich facies or reworked organic matter and special terrestrial input (Peters and Moldowan, 1993). This ratio is also affected by maturity, thermally hopanes is more resistant and stable than steranes (Peters et al., 2005). 14-
ββ/(ββ + αα) of C29 sterane: It is also expressed as % ββ, and used to
define the maturity stages of the source rocks with the maximum equilibrium ratio of 0.7 (Sletten, 2003). The amount of ββ -isomer of C29 increases with maturity in comparison to αα-isomer. So with the increase of thermal stress, the ratio should increase (Osuji and Antia, 2005). 15-
20S/(20S + 20R) of C29 5α(H), 14α(H), 17α(H) steranes: Also expressed as
%20S and 20S/20R. It is a maturity indicator used to monitor the effect of thermal stress on the C29αααR sterane which is a steroid precursor in living organisms. With increasing the maturity, the isomerization at C-20 leads to rise the ratio of 20S/(20S + 20R) from 0 to 0.5 (0.52-0.55 is the equilibrium range) (Peters et al., 2005). The facies change, biodegradation and weathering appeared to affect this parameter. 16-
Diasteranes/(diasteranes + regular steranes): In the present study, this
calculation is only made for C27 of both diasterane and regular steranes of ion m/z = 217 according to Peters et al.(2005). It is a maturity parameter, but partly depends on depositional environments. The mechanism that is responsible of producing diasterane is the acidic catalysis. Thus, carbonate source rocks show low ratio of diasterane/(diasterane + regular sterane). With increasing the maturity, this ratio increases because diasterane is more stable than regular steranes (Peters and Moldowan, 1993). 17-
TA(I)/(TA(I+II) triaromatic steroids (TAS): TA(I) is calculated from the C20
triaromatic steroid and TA(II) measured from the C28R triaromatic steroid (Peters et al., 2005). This ratio is used as a maturity parameter because the amount of C20 relative to C28 increases with the increase of the maturity (ibid).
18-
Dibenzothiophene/Phenanthrene (DBT/P): It is a depositional condition
indicator and this ratio has a reverse relationship with the value of Pr/Ph ratio. The higher value of this ratio is an indicator of anoxic depositional environment (Hughes et al., 1995; Mohialdeen et al., 2012). 19-
Methylphenanthrene index 1 (MPI 1): This index is calculated from the
peak area of phenanthrene (P) and the areas of four isomers of methylphenanthrene (1-MP, 2-MP, 3- MP, and 9-MP) from the mass chromatograms of both ions 178 and 192. This parameter is typical for predicting the maturity level like vitrinite reflectance since the isomers 3- MP and 2-MP are much more resistant than 1-MP and 9-MP in response to the thermal maturity (Peters et al., 2005). Methylphenanthrene index 1 (MPI 1) is calculated according to the following formula (Peters et al., 2005): MPI 1
3.6. Results The results of bulk properties and geochemical parameters of analyzed samples have been presented in three main tables (Tables 3-4, 3-5, and 3-6). Generally, the results show some difference between the samples in terms of maturity, source rocks characteristics including lithologies and depositional conditions. The peak areas of the biomarkers and non-biomarker components are utilized for parameters calculation according to the formulas that shown in section 3-5. The result section is constructed based on presenting the values of the parameters with short descriptions concerning them and showing the chromatograms of the selected ions as the following:
3.6.1. Bulk Properties of the Studied Samples From the results of physical and bulk properties of the analyzed samples, the noticeable differences have been observed in terms of API gravity, sulfur contents, and
contributions from saturated, aromatic, and polar components to the oil samples (Table 3-4).
Accordingly, the Pulkhana crude oil is the richest sample by sulfur contents (2.6%) with the lowest API gravity (25.9), while the KorMor condensate contained the least amount of sulfur (0.13%) with the highest API (65.75). Moreover, KorMor sample is dominated by the high concentration of saturated fractions (80%), whereas Pulkhana sample is the richest sample by aromatic and polar compound fractions (48% and 14%, respectively) with high concentration of nickel and vanadium (22ppm and 45ppm, respectively) over other samples. Although the ChiaSurkh sample is seep oil, still it encompassed a high amount of saturated hydrocarbon fractions (76.7%) with moderate API gravity (33.07). Sarqala crude oil is characterized by high concentration of saturated fractions (63.1%) over aromatic and polar compounds with high API gravity (39.66) and moderate sulfur content (1.00%).
3.6.2. GC-FID Results of the Studied Samples The GC-FID traces of the oil samples have been utilized in the present study just to show the rate of biodegradation on the samples through observing their lighter hydrocarbon compounds (nC12-) distributions in conjunction to their bulk properties (Fig. 3-5). It is impossible to see the lighter hydrocarbon range (
3.6.3. GC-MS Results for the Studied Samples
From the m/z 85 chromatogram of KorMor sample (Fig. 3-7a), it is clear that nC15 is the dominant peak among the n-alkane compounds and beyond nC15 the intensities of the peaks reduced moderately. The signals of nC26+ do not appear on chromatogram due to insufficient concentration of these compounds. The m/z 85 of Sarqala, Pulkhana and ChiaSurkh samples are characterized by high abundance of nC 14, nC15, nC16, and nC17 (Figs. 3-1 and 3-7b and c), and the intensities of the peaks after nC 17 started to reduce smoothly until the last detectable peak of nC 35. The normal compound distributions of Sarqala, Pulkhana, and ChiaSurkh samples are similar.
The m/z 85 of Sargelu-extracted sample (Fig. 3-7d) is a unimodal and approximately similar to the oil samples and it is characterized by the predominance of low molecular weight compounds, especially nC18, nC19 and nC20 over higher molecular weight compounds. The intensities of the compounds started to reduce smoothly from nC 20 to the last peak as in the case of the oil samples. As a whole, the heights of pristane and phytane peaks of all samples are relatively shorter in comparison to the n-alkane compounds peaks (Figs. 3-1 and 3-7a-d).
The CPI parameter is not calculated for KorMor sample due to low intensity of the higher molecular weight compounds (C23+) (Fig. 3-7a), but it is calculated for the rest of the samples according to the formula that is presented in section 3.5. and the results are <1 (Table 3-4). The ratio of pristane to phytane of the samples are <1, except for KorMor sample that is characterized by slightly dominant pristane over phytane. The values of Pr/nC17 and Ph/nC18 ratios of the samples are close to each other and are <1 (Table 3-4), such lower values are good indicators of high maturity. The C 31/C19 ratio is used as a source indicator parameter (Moldowan et al., 1985) for the samples except for KorMor, and the results are ranged between 0-0.4, which means marine depositional environment (Table 3-4).
Fig. 3-5: GC-FID traces of analyzed samples, A) KorMor condensate, B) Sarqala curde oil ,C) Pulkhana crude oil ,D) ChiaSurkh seep oil.
Fig. 3-6: The GC-FID chromatogram of Sargelu extracted sample shows the effect of contamination by Polyethylene glycol.
The analyzed biomarkers addressed in the present study belong to triterpane, sterane, and aromatic compound groups. Regarding the biomarkers related to triterpane group, all the samples contained a series of tricyclic terpanes ranged from C 19-C30 with various contributions (Figs. 3-2 and 3-8a-d). The KorMor sample is dominated by high abundance of tricyclic terpanes (1.75) relative to 17-α hopanes, while the Pulkhana sample is considered as the poorer sample by tricyclics (0.16) (Table 3-6). It is noted from m/z 191 that the intensity of C23 tricyclic compound is the dominant among the tricyclics range except for KorMor, where the C20 tricyclic is the highest one. The C24 teteracyclic terpane also existed in all the samples with various amounts. The ratio of tricyclic and teteracyclic terpanes have been used together and with other components to gain some parameters that could be helpful to summarize depositional conditions and maturities of the studied samples (Table 3-5 and 3-6).
The abundance proportion of hopanes is relatively higher than steranes in all the samples including Sargelu-extracted sample. Among the typical hopane ranging from C27 to C35, the norhopane (C29) is a dominant component, except for ChiaSurkh seep and Sargelu-extracted samples, where normal hopane (C30) has the highest abundance over norhopane. The result of norhopane/hopanes ratios, which is used as a source related parameter, is between 0.80-1.59 (Table 3-5). The moretane/hopane ratio is calculated
only for four of the samples except KorMor for assessing the maturity statues. Accordingly, Pulkhana crude oil is the mature sample since it has the lowest moretane/hopane value (Table 3-6). The complete series of homohopanes from C31 to C35 with both R and S configurations have been indicated in all the samples with different intensities. The homohopane index is calculated according to two formulas: C 35S/C34S and %C35/C31-35 (Section 3.5.), and the results ranged between 0.86-1.31 and 10.16-14.60, respectively (Table 3-5). The intensity of C27 17α(H)-trisnorhopane (Tm) in all the samples are larger than C27 18α(H)-trisnorneohopane (Ts), except in Sargelu-extracted sample, where Ts slightly has higher abundance than Tm (Figs. 3-2 and 3-8a-d). The Ts/Tm ratio is used as a maturity parameter for the samples and the results ranged from 0.23-0.52 with the highest value for Sargelu- extracted sample and lowest value for Pulkhana crude oil (Table 3-6). The characteristic features of all the analyzed samples are the presence of both gammacerane and oleanane components with very low abundance that ranged between 0.03-0.08 and 0.01-0.1, respectively.
Regarding the sterane compound group (Figs.3-3 and 3-9a-d), all the samples are characterized by high abundance of short-chain sterane (C21st-peak no. 1) relative to the long-chain steranes homologs. The steranes distribution are mainly addressed by C 27, C28 and C29 homologues that present as (5α(H), 14α(H), 17α(H),and (5α(H), 14β(H), 17β(H), 20 R and S isomers). All the analyzed samples including Sargelu-extracted are characterized by dominant of C27αααR% components over C28αααR% and C29αααR% steranes, except ChiaSurkh seep oil, where the abundance of C28αααR% relatively higher than C27αααR% and C29αααR% (Table 3-5). It is clear from the chromatograms m/z 217 (Figs.3-3 and 3-9a-d) that C30 is absent in all the samples. According to the values of steranes/hopanes ratio, the ChiaSurkh seepage is the richest one by steranes components (0.52), while the Pulkhana sample is dominated by least contribution from the steranes components (0.17), and the results of other samples are in between (Table 3-5 and Appendix J).
The extent of isomerization of C29 steranes at C-20(S/S+R) are calculated for all the samples except KorMor condensate and the results are close to each other and ranged
between 0.41-0.46. Also isomerization of C29 at C-14 and C-17 (ββ/ββ+αα) calculated for the samples except for KorMor and ranged between 0.49-0.63. Based on both (S/S+R) and (ββ/ββ+αα) results, the Pulkhana sample is more mature (Table 3-6). The representative components of diasterane in all the samples are C 27 with both R and S configurations according to m/z217 (Fig. 3-3 and 9a-d). The results of diasteranes/steranes parameter of C27 are used to assess the rate of biodegradation and source rocks characteristics. The results ranged from 0.12-0.32, with the highest value for Sargelu-extracted sample and lowest for Pulkhana crude oil (Table 3-5).
Regarding the aromatic compounds, the dibenzothiophene (DBT) and Phenanthrene (P) are recorded within the analyzed samples with different abundance through observing their chromatograms (Figs. 3-4, 10a-d and 11a-d). The DBT/P ratio is used to characterize depositional condition, higher values reflected redox condition of deposition (Hughes et al., 1995). The results of DBT/P ratio for studied samples are in the range of 1.58-5.25 with the highest value for Sargelu-extracted sample and lowest for ChiaSurkh seep oil (Table 3-5). The methylphenanthrene compounds (3MP, 2MP, 9M, and 1MP) also observed within the samples with different contributions (Figs. 3-4 and 3-12a-d). The methylphenanthrene index (MPI-1) is used to indicate the maturity of the analyzed samples and it has linear relationship with maturity (Peters et al., 2005). The results of MPI-1 are presented in (Table 3-6) and ranged between 0.77-1.07. All the samples contained a series of triaromatic steroids (TAS) compounds ranged from C 20 to C28 (C26 to C28 components involved both S and R configurations) with various contributions (Figs. 34 and 3-13a-d). Generally, the result of (TAS) ratio is directly proportional to the maturity (Peters et al., 2005). Accordingly, KorMor sample (0.91) is a more mature sample in comparison with other samples (Table 3-6, Figs. 3-3 and 3-13a-d).
a
b
c
d
Fig. 3-7a-d. Presenting the m/z 85 chromatograms of a) KorMor, b) Pulkhana, c) ChiaSurkh, and d) Sargelu-extracted samples.
a
b
c
d
Fig. 3-8a-d. Presenting the m/z 191 of a) Pulkhana, b) ChiaSurkh, c) KorMor, and d) Sargelu-extracted samples. (Peak identification in Table 3-1)
a
b
c
d
Fig. 3-9a-d. Presenting the m/z 217 of a) Pulkhana, b) ChiaSurkh, c) KorMor, and d) Sargelu-extracted samples. (Peak identification in Table 3-2)
Phenanthrene (P)
a
b
c
d
Fig.3-10a-d. Presenting the m/z 178 chromatograms of a) KorMor, b) Pulkhana, c) ChiaSurkh and d) Sargelu-extracted samples.
Dibenzothiophene (DBT)
a
b
c
d
Fig. 3-11a-d. Presenting the m/z 184 of a) KorMor, b) Pulkhana, c) ChiaSurkh, and d) Sargelu-extracted samples. (Peak identification in Table 3-3)
2 M 3
P
a 9
M
M
P
P 1 M P
b
c
d
Fig. 3-12a-d. Presenting the m/z 192 of a) KorMor, b) Pulkhana, c) ChiaSurkh and d) Sargelu-extracted samples. (Peak identifications in Table 3-3)
a
b
c
d
Fig. 3-13a-d. Presenting the m/z 231 of a) KorMor, b) Pulkhana, c) ChiaSurkh and d) Sargelu-extracted samples. (Peak identifications in Table 3-3)
3.7. Discussion This section includes interpretation of the results of the parameters that are presented in (Tables 3-4, 3-5, and 3-6) , which are used as diagnostic key to assess the source rocks characteristics of the analyzed samples in addition to evaluating the thermal maturity and rate of biodegradation.
3.7.1. Bulk Composition of Petroleum Samples The analyzed petroleum samples composed mainly of three groups of hydrocarbon fractions, (1) aliphatic hydrocarbons, (2) aromatic hydrocarbons, and (3) polar compounds, which includes oxygen, nitrogen and sulfur (NSO) (Table 3-4). The normalized percentage compositions of the aliphatic, aromatic and NSO compounds of the samples are plotted on the ternary diagram (Fig. 3-14). The marked zone within the ternary diagram represents the zone of typical conventional petroleum composition according to Tissot and Welte (1984). All the oil samples except Pulkhana crude oil are within the zone of conventional oil and close to the aliphatic pole, which means aliphatic oils (ibid). The Pulkhana sample is slightly aromatic oil since it moved towards the aromatic pole and it is not located within the zone of conventional oils as well.
3.7.2. Depositional Environments and Source R ock Related Parameters The n-alkanes and isopernoid compounds distributions of analyzed samples are similar and included high abundance of short chain n-alkanes over long chain n-alkanes compounds (Figs. 3-1 and 3-7a-d), and they are dominated by high values of nC 17/nC27 ratios, which ranges from 2.39−6.0 (Table 3-4). As a result, the m/z 85 chromatograms of the samples show front end biased distributions, which counts as a typical configuration of the oils that are generated from marine algae/bacterial organic particles that deposited under reducing condition with no obvious contributions from terrestrial materials (Younes and Philp, 2005 ; Abeed et al., 2012).
Fig. 3-14: The ternary diagram of saturated, aromatic and asphaltic compounds of studied samples. Typical crude oil located within the hachured area (after Tissot and Welte, 1984).
Moreover, high sulfur content (0.60-2.72 wt%) of the oil samples and slightly even predominance over the odd carbon numbers (CPI<1) in the C22-C30 range of n-alkanes for all the samples except KorMor condensate plus low Pr/Ph ratios (<1) and low ratios of Pr/nC17 (<0.5) (Table 3-4), altogether are crucial indicators that show these oils were generated from marine carbonate source rocks bearing kerogen type II-S that are deposited under anoxic condition (Moldowan et al., 1985; Peters et al., 1993; Ramon and Dzou, 1999; Osuji et al., 2005; Abeed et al., 2012). The cross plot between Pr/nC17 and Ph/nC18 (Fig. 3-15), showed that the source of the analyzed samples are marine organic matter that are deposited under reducing condition and the kerogen that generated the studied samples are kerogen type II. Furthermore, it is suggested that the value of Pr/Ph >1 of KorMor sample might be reflected slightly terrigenous influx to its source (Table 34). Additionally, the source rock that released Pulkhana oil is supposed to be deposited under higher reducing condition than the other sample. High sulfur contribution to Pulkhana crude oil (2.76 wt %) may support this case because intense redox condition favored sulfur production (Mohialdeen et al., 2013). The results of nC31/nC19 ratio (0.080.20) (Table 3-4) of the samples are another indicator that supported the marine origin of
the source materials of the studied samples because the ratio of nC31/nC19 for the majority of the generated oils from marine organic materials are <0.4 according to Moldowan et al. (1985).
Fig. 3-15: Cross plot of Pr/nC17 versus Ph/nC18, indicated marine organic matter sources for analyzed samples that deposited under reduced conditions. (the diagram after Hunt, 1996).
Many terpanes occurred in petroleum generated from bacterial (prokaryotic) membrane lipids (Peter et al., 2005). The biomarkers belong to terpanes, which are widely used as fingerprints for recognizing the depositional environments and source input because the precursors of terpanes are common in sediments and occur in almost all oils. Although, the oils were originated from different source rocks that are deposited under similar conditions may show similar terpanes fingerprints (Peters et al., 2005).
The m/z 191 chromatograms of saturated hydrocarbon fractions of the samples show a series of tricyclic terpanes from C19 to C30 range, hopanes (C29 and C30), moretanes (C29 and C30) with a complete series of homohopanes from C 31 to C35 with S and R configurations (Figs. 3-2 and 3-8a-d).
The ratios of C24/C23 and C26/C25 tricyclic terpanes can be used to distinguish oils derived from different sources. According to Peters et al. (2005) the ratios of C 24/C23 and C26/C25 for oils derived from carbonate source rocks should be (<0.6) and (<1.1),
respectively. Therefore, based on the results of both C 24/C23 (0.37-0.53) and C26/C25 (0.63-0.82) tricyclic terpanes ratios (Table 3-5), the analyzed sample are originated from carbonate source rocks. The abundance of C 19-C21 over C23 tricyclic terpanes might be interpreted as terrestrial organic matter input to the sources (Ozcelik et al., 2005). The lower values of C19+C21/C23 tricyclics (Table 3-5) for all the analyzed samples except KorMor condensate indicated that the source rocks for the analyzed oils are deposited in a carbonate-rich under reducing environment, while the high value of C 19+C21/C23 for KorMor samples might reflect some terrestrial source input with oxic to dysoxic depositional condition, which is somehow in agreement with the high Pr/Ph ratio (Table 3-4). In any case, the relative abundance of C23 (peak no. 4) in the studied samples (Figs. 3-2 and 3-8a-d) is a good indicator to confirm marine organic matter sources for the studied samples (Romero and Philp, 2012).
Concerning the tetracyclic terpanes, the m/z 191 chromatograms of analyzed samples displayed only C24 (peak no. 7) as relatively high abundance (Figs. 3-2 and 3-8a-d). The high values of C24 tetracyclic/C26 tricyclic (Table 3-5) for all the samples is considered as another indicator for carbonate marine origin of the samples, especially for Sarqala and Pulkhana crude oils where their values are higher than KorMor, ChiaSurkh and Sargeluextracted samples significantly (Peters et al., 2005).
The m/z 191 traces of the samples except KorMor condensate are shown predominance of αβ-hopanes including both C29 and C30 (peak no. 17 and 20, respectively) over other triterpanes (Figs. 3-2 and 3-8a-d), which is referred to high microbial activities (Connan, 1993; Arfoaui, 2014). Furthermore, relatively the predominance of C29 over C30 hopanes in KorMor, Sarqala and Pulkhana reflected claypoor source rocks that are responsible for generating these samples, in contrast to the sources of ChiaSurkh and rock-extracted samples that supposed to include more clay materials since the intensities of C30 are higher than C29 hopanes (Mohialdeen et al., 2013). Although, the value of C29H/C30H ratio (>0.6) of all the samples (Table 3-5) imply of prevalence of carbonate materials in the source rocks of the studied samples (Peters et al., 2005).
The homohopanes are derived from the hopanoids during the diagenesis process. Generally, carbonate-evaporite source rocks that are deposited in anoxic condition favored the preservation of C35 homologs (Moldowan et al., 1985). The high abundance of homohopanes series (C31-C35) within the entire samples that resulted high C35homohopane index ranged from 10.16 to 14.60% (Table 3-5 and Figs. 3-2, 8a-d) is a good indicator of carbonate-evaporitic sources of the analyzed samples that deposited under reducing condition. Moreover, the value of C35S/C34S ratio (>0.8) of the samples (Table 35) are referring also of marine carbonate-evaporite source origin of analyzed samples according to Peters et al. (2005).
The cross plots of C29/C30 versus C35S/C34S hopanes (Fig. 3-16) and C26/C25 tricyclic terpanes versus C31R/C30 hopane (Fig. 3-17) have been used to clarify further the source rock type affinities of analyzed samples according to Al-Ameri et al. (2013). These two cross plots are designed based on the results of the mentioned ratios of 150 oil samples that are picked up from the Geomark database. The 150 oil samples are generated from various source rocks including marine carbonates, marine marl, distal marine shales, and lacustrine. The cross plots of selected 150 oil samples have been correlated with the samples of the present study. Based on the positions of the plotted samples, the source origin of analyzed samples are definitely marine carbonate with few marl admixtures to ChiaSurkh and rock-extracted sample of Sargelu Formation. While, according to the plot of C26/C25 tricyclic terpane versus C31R/C30 hopane, only Sargelu-extracted sample is generated from marine carbonate, but other samples have admixture sources between marine carbonate, marine marl and distal shales.
Fig. 3-16: Cross plot of C29/C30 versus C35S/C34S hopanes shows marine carbonate source rocks for studied samples with marine carbonate to marine marl for ChiaSurkh and Sargelu-extracted samples based on the plotted chart for 150 oils that presented in Al-Ameri et al. (2013).
Fig. 3-17: Cross plot of C26/C25 Tricyclic terpane versus C31R/C30 hopane shows marine carbonate source rocks for Sargelu-extracted sample and mixed sources between carbonate, marine marl and shales for KorMor, Sarqala, Pulkhana and ChiaSurkh samples based on the plotted chart for 150 oils that showed in Al-Ameri et al. (2013).
It is clear from the m/z 191 chromatograms of the analyzed samples (Figs. 3-2 and 38a-d) that oleanane and gammacerane biomarkers appeared with very low abundance. Gammacerane (C30) is a terpane that is biologically related to hopane (Moldowan et al., 1985). Large amount of gammacerane indicates highly reducing, hypersaline condition
during the deposition of the organic matter (Peters et al., 2005). The values of gammacerane index of the analyzed samples are between 0.03-0.08 (Table 3-5). Such a trace amount frequently occurred with terpanes in the crude oils and do not reflect the hypersaline condition during the deposition (Peters et al., 2005). Therefore, based on the low values of gammacerane index we can deduce that the source rocks for the analyzed oils deposited in water under normal salinity condition (Abeed et al., 2012).
The 18α-oleanane biomarker which is considered as a specific indicator for higher land plant origin of Cretaceous or younger ages (Peters et al., 1993), has been observed with low abundance also (0.01-0.1) in all the samples (Table 3-5). The low values of oleanane index means limited higher land plant contributions to the deposited organic matter. According to Younes et al. (2005) such low values of oleanane index is consistent with the generation of the studied samples from Late Cretaceous or older source rocks.
Steranes are tetracyclic, saturated biomarkers that are derived from sterols of cell membranes of eukaryotes, principally algae and higher plants (Peters et al., 1993). The m/z 217 chromatograms of the samples included the following sterane compounds, C 27cholestane, C28-ergostane, and C29-stigmastane with their isomers (20R and 20S). The relative contributions of the regular steranes (αααR) for analyzed samples are calculated and observed that C27αααR has the maximum abundance in comparison with other regular sterane, followed by C28αααR and then C29αααR (Table 3-5), except for ChiaSurkh seep oil where C28αααR is the dominant one. The high abundance of C27 and C28 means predominance of marine and lacustrine algae (Arfaoui, 2014). The lower contribution from C29 sterane means limited terrestrial input to the source rocks that generated the analyzed samples.
Additionally, Low concentration of steranes and low steranes/17α-hopanes ratio (<1) of the samples (Table 3-5), indicated microbailly reworked organic matter sources (Peters et al., 2005). This ratio is only applicable as a qualitative evaluation of contribution from eukaryote or prokaryote to the source rocks and might increase with maturity.
The ratio of diasteranes to regular steranes has been used in the present study to distinguish the petroleum samples that generated either from carbonate or clastics source rocks. Peters et al. (2005) stated that acidic and oxic (high Eh) conditions are favored for converting steranes to diasteranes during the diagenesis process. Thus, low diasteranes/ steranes ratio is a good sign for anoxic clay-poor or carbonate source rocks. The
low
abundance
of
C27
diasteranes
according
to
the
ratio
of
C27
diasteranes/C27steranes (Table 3-5) shown that the sources of the studied samples are deposited under reducing condition and characterized by clay-poor or carbonate-rich materials. This result is consistent relatively with the achieved results from the nonbiomarkers and terpanes parameters concerning the source rocks properties.
The cross plot of (Pr/ Pr+Ph) versus (diasterane/ diasterane+ sterane C27) (Fig. 3-18) is utilized to describe further the depositional conditions and source material types of the analyzed samples according to Peters et al. (2005). Accordingly, the KorMor condensate and Sargelu-extracted samples are supposed to be generated from argillaceous source rocks rather than carbonate, since they included relatively higher abundance of diasterane/sterane ratio than other samples (Table 3-5). The results of Figure 3-18 are not properly accurate because the value of diasterane/sterane ratio is not only affected by presence of clay materials, but also controlled by maturity. The conversion of sterane to diasterane increases with increasing maturity (Rabbani and Kamali, 2005). Therefore, it is suggested that the high values of diasterane/sterane ratio of KorMor and Sargeluextracted samples reflected high maturity levels of these two samples rather than source materials.
Aromatic compound chromatograms (Figs. 3-4, 3-10a-d, 11a-d, 3-12a-d, and 3-13a-d) can provide useful information regarding the lithology and the type of the organic matter of the related source rocks (Peters et al., 2005).
Fig. 3-18: Cross plot of (Pr/Pr+Ph) versus (Dia/Dia+Sterane C27), showed depositional conditions and source material types of the studied samples, the dashed line shows the effect of thermal maturity. The arrow shows the expected direction of thermal maturity.(After Peters et al., 2005).
Among the aromatic compounds, the ratio of dibenzothiophene (DBT)/phenanthrene (P) has been used to describe the source rocks lithologies of the selected samples. According to Hughes et al. (1995) where the ratio of DBT/P (>1), the dominance lithology of the source rocks is carbonate, while (1<) means shales source rocks. The obtained results from the ratio of DBT/P of the samples ranged from 1.58-5.25 (Table 3-5), which means the main rock that released the analyzed samples are carbonate rather than shales. Moreover, when the ratio of DBT/P accompanied with the ratio of pristane /phytane, it will provide a powerful approach to describe the depositional environments and lithologies of the petroleum source rocks (Fig. 3-19). Accordingly, only Sargeluextracted sample is generated from pure marine carbonate, while the rest of the samples are derived from marine carbonate and mixed marine sources (Hughes et al., 1995).
Fig. 3-19: Cross plot of pristane (Pr)/phytane (Ph) versus dibenzothiophene (DBT)/ phenanthrene (P) for describing the lithologies and depositional conditions of studies samples (the diagram after Hughes et al., 1995).
3.7.3. Maturity Related B iomarkers The most common application of biomarkers and non-biomarkers compounds in liquid hydrocarbon and rock extracted samples is to define the thermal evolutions that are experienced by the compounds based on either the abundance or changes that undergone to the stereochemistry of the compounds. The basic molecular structures of compounds within the living organism are already determined and during burial depth these structures became unstable and will show structure modifications as a result of thermal break-down of kerogen to form oil during catagensis (Osuji et al., 2005). By comparing between the proportions of the new produced structure with the basic biolipid structure of the compound, the thermal maturity can be indicated. Moreover, the maturity of a given oil will be related to the maturity of its source rock at the time of petroleum expulsion, therefore, indicating maturity can possibly be used to determine the generation temperature of a given oil (Sajgo, 2000).
Thermal maturity describes the extent of heat-driven reactions that convert sedimentary organic matter into petroleum (Peters et al., 2005). Generally, organic matter can be defined as immature, mature, and postmature based on its relation to the oil-generation window (Tissot and Welte, 1984). Thermal maturity identification by using biomarkers should be carried out carefully because most of the biomarker structures besides the thermal degradation are strongly dependent on lithofacies and biodegradation as well (Peters et al., 1993). Additionally, application of biomarkers related maturity parameters are mostly dependent on the stage of the maturity, some of them are reliable only at immature to mature stages, while others like aromatic compounds are used to assess high level of maturity (Killops and Killops, 2005).
In the present study, the maturity of the studied samples have been determined based on the bulk properties, mass chromatogram envelops, and correlation between various peak areas of the compounds including n-alkanes, isopernoids, terpanes, steranes, and aromatic compounds.
According to the bulk properties of the studied samples (Table 3-4), the KorMor condensate is more mature since it included the higher quantity of light hydrocarbon fractions and least polar compounds, while Pulkhana crude oil is considered as a least mature sample because it contained lowest quantity of light hydrocarbons and high polar and sulfur components (Fig. 3-14). API gravity of studied samples plotted versus sulfur content (Fig. 3-20) demonstrates that the analyzed samples can be divided into three groups based on their maturity (Abeed et al., 2012). The clustering made based on the closest distance between the plotted samples. This grouping can be explained in two ways. Either the three groups of petroleum generated from three different source rocks, or all the samples derived from one source rock at different stages of maturity during the burial history (Abeed et al., 2012). Based on API and sulfur contents, Pulkhana crude oil that is represented by group C has the lowest maturity, while group A (KorMor condensate) is considered as the high mature sample and Sarqala and ChiaSurkh samples that are marked by group B have moderate maturity in comparison with other samples.
Fig. 3-20: Relative thermal maturities of analyzed samples based on Sulfur% and API gravity (After Abeed et al., 2012). Note, bulk properties of Sargelu-extracted sample are not measured.
The unimodal configuration for m/z 85 chromatograms (Figs. 3-1 and 3-7a-d) of analyzed samples is a good indicator for describing maturity status, because with increase of maturity, the heaver n-alkanes compounds are cracked into lighter n-alkanes and produced unimodal displayed (Moldowan et al., 1985; Peter et al., 2005). Thus, based on the general displayed of m/z 85 traces, the analyzed samples are mature, but KorMor condensate is more mature than other samples since it is strongly depleted in heaver nalkanes and enriched by lighter n-alkanes compounds. Furthermore, the CPI values of all the samples are almost equal to 1 (Table 3-4), which suggests that all the analyzed samples are mature in terms of hydrocarbon generation (Alsharhan et al., 2008; Baban, 2013). A cross plot of pristane/n-C17 versus phytane/n-C18 (Fig. 3-15) also showed high maturity of the samples with no obvious secondary alteration including biodegradation.
Moreover, from the m/z 217 fragmentograms (Figs. 3-3 and 3-9a-d), it is noticed that the relative enrichment of the samples by short-chain sterane (C21St peak no.1) homolog relative to long-chain homologs developed as a result of conversion from long-chain steranes in response to high thermal maturity (Sajgo, 2000). More information regarding the maturity of the studied samples can be provided from the correlation between the ratios of the biomarkers that are sensitive to maturity increase. The maturity related biomarker ratios are presented in Table 3-6. It is obvious that the majority of hopanes and steranes maturity related parameters are only
applicable at the immature to mature stages of the oil (Peters et al., 2005). Therefore, for characterizing the maturity of KorMor condensate and Sargelu-extracted samples, only those biomarkers being utilized that are appropriate for assessing higher stages of maturity, since KorMor is a gas condensate and produced at high level of maturity beyond the oil window (Hunt, 1996) and rock-extracted samples that are derived from Sargelu Formation almost confirmed from the chapter two that it has a high level of maturity.
3.7.3.1. Hopane-Related Maturity Parameters The Ts/ (Ts+Tm) ratio (sometimes referred to as Ts/Tm) is a thermal maturity parameter that depends on the lower thermal stability of 17α-22,29,30-trisnorhopane (Tm) in comparison to 18α-22,29,30-trisnorneohopane (Ts) during the catagensis phase of hydrocarbon generation (Hunt, 1996). According to the results of Ts/Tm ratio of analyzed samples (Table 3-6), the KorMor and Sargelu-extracted samples are more mature and Pulkhana is least mature, whereas the maturity of Sarqala and ChiaSurkh are in between. The Ts/Tm parameter seems very effective for describing maturity, especially for those oils that are derived from relatively the same source rocks (Peters et al., 1993). Therefore, in the present study, the Ts/Tm ratio appears to be most reliable for describing the maturity, since the source of the analyzed samples are assumed to be marine carbonate source rocks.
The isomerization of C31-homohopanes at C22 chiral center is calculated to assess the maturity of Pulkhana, Sarqala and ChiaSurkh oil samples only from the ratio of (22S/ 22S+22R) (Peters et al., 2005 and Osuji et al., 2005). The biologically produced precursors of hopanes have the R configuration at C 22 position called (22R) (Killops and Killops, 2005), with increase of the maturity the 22R configuration gradually converted to a mixture of 22S and 22R isomers (Peters et al, 1993). Thus, by measuring the ratio of 22S to the total of 22S and 22R, the experienced maturity by C 31homohopane can be estimated. According to Peters et al. (2005) the ratio of 22S/ (22S+22R) rises from 0 to 0.6 (0.57-0.62=equilibrium) during the maturity. This ratio for the oil samples ranged between 0.55-0.58 (Table 3-6), which means advanced stage of maturity. The highest maturity is recorded in ChiaSurkh oil and the lowest in Pulkhana crude oil. Moreover,
relatively among the homohopanes series (C 31-C35), the abundance of S isomers are dominant over the R isomers, which indicate mature status of the samples (Appendix J).
The ratio of 18α-22,29,30-trisnorneohopane (Ts) to C30 hopane (Ts/C30 hopane) according to Volkman et al. (1983 in Abeed et al., 2012) generally increase with increasing the maturity since the C27 Ts hopane generated by side chain cleavage of C 29 and higher molecular weight hopanes in response to the maturity. The obtained results of (Ts/C 30 H) ratio (Table 3-6) showed that the KorMor condensate is the most mature and Pulkhana is least mature and other samples are in between. The ratio of 17β, 21α-moretane to their corresponding 17α, 21β-hopane has been used further to explain the maturity of the oil samples. According to Arfaoui (2014) the ratio of moretane /hopane (M/H) generally decrease with increasing the maturity from the 0.8 in immature level to mature stage below 0.15 in source rocks and in oil to minimum of 0.05. Accordingly, all the studied samples based on the results of M/H ratio are considered as mature oils (Table 3-6), but the results of M/H ratio are inconsistent with the previous conclusions regarding the order of maturity, because Pulkhana crude oil according to M/H ratio has the lowest values, indicating higher maturity in comparison with other samples. This result could be affected by depositional conditions and source rock materials of Pulkhana crude oil (Peters et al., 2005).
3.7.3.2. Sterane-Related Maturity Parameters The sterane isomerization ratios have been utilized in the present study in order to show in details the maturation situation of the studied samples. Similar to homohopanes, sterane isomerization measured based on the transformation occurring from 14α(H), 17α(H): 20 (R) configuration to 14β(H), 17β(H): 20 (S+R) as a final configuration (Peters et al., 2005). By observing these molecular configurations transformation, valuable information regarding the maturity and thermal stress that sediments have passed through can be achieved (Osuji et al., 2005). According to Peters et al. (2005) mostly C 29 sterane is widely used for this purpose according to the following ratios C295α,14α,17α(H)-20S/(20S + 20R) and the ββ/(ββ +αα) due to low interference with other isomers. Generally these ratios increase with increasing thermal maturity (Peters et al.,
2005). Although, it has been suggested that the 20S/(20S + 20R) ratio equilibrates at 0.52 to 0.55, but Gallegos and Moldowan (1992 in Adegoke et al., 2014) have shown that these equilibrium values are probably too high and that the maximum values in oils and rock extracts are 0.5 or less. Peters et al. (2005) suggested that in hypersaline environment the ββ isomers become abundant due to reaction with sulfur contents. Pulkhana crude oil, is supposed to have the same situation, because Pulkhana sample already has a hypersaline condition properties as described and characterized by high sulfur contents with abundant ββ isomers in comparison with other sterane isomers (Table 3-4 and Appendix J). Consequently, it is assumed that the result of ββ/(ββ + αα) ratio of Pulkhana sample could be overestimated (Table 3-6). Hence, care should be taken when using sterane isomerization especially ββ/(ββ + αα) for maturity determination for the samples that are deposited under hypersaline conditions (Peters et al., 2005). The results of 20S/(20S + 20R) and the ββ/(ββ +αα) ratios for the Sarqala, Pulkhana, and ChiaSurkh oil samples ranged from 0.41-0.46 and 0.49-0.63, respectively. These values suggested that the analyzed samples are already mature but did not reach the equilibrium status (Figs. 3-21 and 3-22). The most interesting point that we should highlight, is the difference between the steranes and terpanes parameters in terms of characterizing the maturity order of the studied samples. According to the sterane isomerization, Pulkhana crude oil is considered as most mature sample, whereas based on terpane biomarkers and bulk properties, the Pulkhana oil is the least mature in comparison with other samples, since there is no huge difference between the values of maturity parameters (Table 3- 6 ).
Fig. 3-21: Correlation of sterane maturity parameters for describing the maturity statues of studied samples based on isomerization in C29 sterane (After Alsharhand et al., 2008).
Fig. 3-22: Relative thermal maturities of oil samples based on isomerization reactions in C29 steranes (The diagram after Peters et al., 1993).
3.7.3.3. Aromatic-Related Maturity Parameters Another commonly utilized molecular compound for indicating the maturity is the aromatic compounds, especially the methyl-homologs of phenanthrene (P) which is controlled by thermal maturity (Peters et al., 2005). The methylphenanthrene index (MPI1) is calculated for all studied samples from the peak areas of phenanthrene and methylphenanthrene compounds (MPs) (Figs. 3-4, 3-10a-d, and 3-12a-d).
This parameter is used based on the potential of methyliation of P at lower maturities, demethylation of MPs to produce P at higher maturities and isomerization of MPs from less stable α-substitution isomers compared with the more stable β-substitution isomers (Killops and Killops, 2005). The MPI-1 values of the analyzed sample ranged between 0.77-1.07 with the highest value for ChiaSurkh seep oil and lowest for Pulkhana crude oil (Table 3-6). Accordingly, the studied samples have moderate to high maturity and ChiaSurkh sample is considered as more mature than other samples. The ChiaSurkh seepage sample could be subjected to water washing and caused the value of MPI-1 overestimated, because α-isomers are more water-soluble than their β counterparts (Killops and killops, 2005), so the value of MPI -1 of ChiaSurkh could be overestimated.
Triaromatic steroids (TAS) are used also to demonstrate further the maturity stage of studied samples. The TAS remains unaltered in biodegraded oils and is used to describe the maturity level (Lopez, 2014). TAS is measured based on the conversion of TA(II) that is represented by C28 triaromatic steroid (20R) to TA(I) that is represented by C 20 triaromatic steroid by side chain cleavage during thermal maturation (Peters et al., 2005). The TAS results of studied samples ranged between 0.32 for ChiaSurkh seep oil to 0.91 for KorMor condensate sample (Table 3-6). It is clear from the results that KorMor condensate characterized by high conversion of TA (II) to TA (I) that reflects high maturity and followed by rock-extracted of Sargelu Formation by 0.80.
3.7.4. Biodegradation Petroleum biodegradation is the alteration process of crude oils and destruction of hydrocarbon compounds by living organisms like fungi and eubacteria that alters the oil fluid properties and economic values (Lopez, 2014). The biodegradation of petroleum is carried out through consuming saturated and aromatic compounds by metabolic processes that evolved by the living organisms (Peters et al., 2005). Assessing the biodegradation effects on the petroleum samples is very important because biodegradation strongly alter the bulk properties of the related petroleum oil, hence, it has a great impact on the quality of petroleum. Generally, with increase the biodegradation, the API of the petroleum decreases, while non-hydrocarbon gases, viscosity, NSO compounds, and trace metals like vanadium and nickel increase (Peters et
al., 2005; Lopez, 2014). From economic point of view, characterizing the impact of biodegradation on petroleum samples is very significant and should be determined.
The susceptibility of hydrocarbon compound classes to biodegradation is different and basically controlled by many factors like carbon number in homologs series, stereochemistry structures or optical isomeric configurations. According to Peters et al. (1993) hydrocarbon compound classes can be arranged in order from low to high susceptibility to biodegradation as follows: n-alkanes< isopernoids< regular steranes< hopanes< diasteranes< aromatic steroids< porphyrins. Although, some individual hydrocarbon compound within a given class follows a quasi-sequential order, which means some molecular compounds are more unstable but may remain while the more resistive molecules started to be biodegraded (Peters et al., 2005).
From the GC-FID traces of the analyzed samples (Fig. 3-5), it is easily recognized that all the samples are not subjected to noticeable biodegradation, since the samples contained significant amount of n-alkanes hydrocarbon over all other saturated hydrocarbon compounds (Yi Duan et al., 2006). By observing the peak intensities of light hydrocarbons
Pulkhana samples (Fig. 3-5C) did not display any evidence of biodegradation and water washing.
The absence of noticeable hump of Unresolved Complex Mixture (UCM) in the GC-FID traces of all the petroleum samples is another feature that supported the analyzed samples that are non-degraded (Arfaoui, 2014).
The cross plot of Pristane/nC17 (Pr/nC17) versus Phytane/nC18 (Ph/nC18) has been widely used for showing the biodegradation effects. Generally, with increasing the rate of biodegradation, the easily degraded n-alkanes are lost, while the more degradation resistant isopernoids (pristane and phytane) are conserved, resulting in a relative increase of the ratios of Pr/nC17 and Ph/nC18 (Arfaoui, 2014). The low values of these ratios are reflected as high concentration of n-alkanes relative to isopernoids and these characteristics almost correspond to lack of biodegradation on the samples (Table 3-4).
Since the diasterane is considered as more resistance biomarkers than the regular steranes (Peters et al., 2005), thus the ratio of diasterane to regular sterane can be used as indicator to assess the impact of biodegradation on the petroleum samples and it is directly proportional with the effect of biodegradation. Accordingly, the low values of diasterane/regular sterane ratio (Table 3-5) almost confirmed the lack of biodegradation effect on the studied samples.
CHAPTER FOUR
Geochemical Correlation
4.1. Background Organic geochemical correlations are geochemical comparisons of oils to each other and to their prospective source rocks in order to show whether a genetic relationship exists between them or not. Correlations are considered as essential components in defining basin’s petroleum system (Peters and Fowler, 2002). During the assessment of petroleum potential of an area, oils and prospective source rocks from the area are analyzed in details to discover if the oils are of one or more groups and to indicate the source beds that are responsible for generating the oils (Cooper, 1990). Defining the genetic relationships and connections between accumulated oils in an area and with their prospective source rocks is important for improving the exploration success and recognizing reservoir components to enhance production (Peters et al., 2005; Abeed et al., 2012).
Geochemical correlation between petroleum and source rocks is principally based on the similarity between the compound’s compositions. Such kinds of similarities are determined from the distribution patterns of the specific compound rather than absolute concentration. According to Tissot and Welte (1978), the compositional parameters that is suitable for correlation should: 1) not be extremely affected by any process like thermal and bacterial alteration that act upon source rocks and petroleum properties; 2) have sufficient characteristics of compounds distribution in both rocks and oils in order to allow differentiation between certain source rocks and oils. The major point of correlation procedures is defining the source (fingerprint) of the hydrocarbon molecules in oils and understanding how the fingerprints are affected by factors such as migration, water washing, biodegradation and thermal alteration (Hunt, 1996). It is recommended as not
to rely on one parameter for correlations; several correlation parameters should be tested in order to achieve reasonable results (Tissot and Welte, 1984).
Oil-oil correlation performs to indicate whether oils were generated and expelled from the same source facies. Oil-oil correlation is based on the fact that the dominant biomarker in the specific source rock would be expected to appear in the oils that are generated by it. The ratio of certain two biomarkers should be the same in the released oils from the same source rock if seriously not affected by extraneous factors (Hunt, 1996). Sometimes the interpretation of oil-oil correlation is complex, because the same source rock might generate oils of different maturity at different time in its burial history and the accumulated oils from same source rock might undergo various secondary alterations. Therefore, for making oil-oil correlation, a series of parameters that are not strongly affected by secondary factors should be tested for categorizing oils (ibid). The problems that come up from the correlation between petroleum samples became more complicate, especially when the conditions of generating the petroleum are extremely different, like correlation between crude oil and condensate. Gases and condensates are related by preferential generation and accumulation mechanisms which may be different from those for oils. Moreover, condensate samples mostly included contaminated biomarkers rather than indigenous biomarkers that might adversely affect interpretation, including correlation (Tissot and Welte, 1978; Peters et al., 2005). Thus, in the present study the KorMor condensate sample has been excluded from the correlations processes in order to avoid any misinterpretations.
In oil-oil correlation, it is recommended to choose parameters in such a way that covered a wide range of molecular weight, such as n-alkane distribution envelopes or GCMS traces of saturated hydrocarbon fractions (Tissot and Welte, 1978).
Concerning the oil-source rock correlation, which is more difficult process than oil-oil correlation, as many issues like sampling and more analyzing data are involved, it is used based on the concept that certain compositional parameters of migrated petroleum do not differ significantly from those of bitumen remaining in the source rock (Hunt, 1996; Peters et al., 2005).
According to Peters et al. (2005) sometimes, there are no compositional similarities between source-rock extracted and their related petroleum due to many reasons that are summarized briefly in the below: 1- Bitumen extracted from prospective source rock might include undetected migrated oils or contaminants that are not representative of the indigenous hydrocarbon. 2- In oil-source rock correlation, the candidate bitumen and oils should have equivalent or at least similar maturity, which is uncommon in most of the cases. 3- Most oil-source rock correlation investigations are limited to a specific interval of the source beds that may or may not be representative of the composite section that generated the petroleum. 4- Generally, the accumulated petroleum is mostly derived from more than one source rocks. 5- Expulsion and migration process of the petroleum affect the molecular distributions of the hydrocarbon compounds and generate various molecular weights and polarity that are different from source materials.
In general, positive correlation is not necessarily proof that samples are related, because different source rocks might have similar compositional characteristics, but negative correlations are strong evidence for lack of similarity between related samples (ibid).
4.2. Correlation Related Parameters In addition to bulk properties and GC traces of the petroleum and rock-extracted samples, biomarkers are widely used for correlation purpose especially in oil-source rock correlation, because of their resistance to biodegradation (Hunt, 1996). In the present study, in spite of some of the molecular compounds ratios that have been presented in chapter three (Tables 3-4, 3-5 and 3-6), other biomarker ratios (Table 4-1) are also utilized to perform correlation between selected samples (ChiaSurkh, Pulkhana, Sarqala oils and rock-extracted sample of Sargelu Formation).
Table 4-1: Showing the biomarker ratios that used for correlation processes. Pr/Ph
Name
C24Tet/C 23T
Gr/C31R H
C29/C27St
C27diaS/C27aaa R
St/Terpane
C27%aaa R
C28%aaa R
C29%aaa R
Sarqala
0.63 1.01 0.19 0.96 0.23 0.36 36.62 34.05 29.33 0.48 0.99 0.27 1.05 0.24 0.18 37.29 34.12 28.59 ChiaSurkh 0.84 0.77 0.13 0.87 0.37 0.55 35.38 38.52 26.10 Ex-Sargelu 0.60 0.81 0.21 1.03 0.94 0.29 38.27 30.81 30.92 Pr: Pristane; Ph: Phytane; Tet: Tetracyclic; T:Tricylic; H: hopane; Gr: gammacerane; St: Regular steranes; St/Terpanes= measured on total steranes (from C27S dia to C29aaaR) and total terpanes (from Ts to C35RH); Ex: extracted rock sample. Pulkhana
The used parameters were calculated from the peak area of some compounds that presented in Table 3-2
The following are descriptions of the components and parameters that are used to describe similarity or dissimilarity between the studied samples:
4.2.1. n-Alkanes, Pristane and Phytane Compounds Distributions From the m/z85 chromatograms of selected samples for correlation (Figs. 3-1 and 37b, c and d), it is deduced that there are strong similarities in molecular compounds distribution. Generally, they are characterized by predominance of light molecular weights ranged from C15-C20 over the heavy molecular compounds and the GC-MS trace’s envelops of the samples are unimodal and have front end biased distributions. The results of CPI and Pr/Ph ratios of the samples are close to each other and <1, including Sargeluextracted sample (Table 3-4).
The cross plot of Pr/nC17 versus Ph/nC18 (Fig. 3-15) shows similar depositional environments and organic contents of the source beds that released the oil samples and with the Sargelu-extracted sample. All these features indicated a great degree of compositional similarities between the origins of oil samples and Sargelu-extracted sample. As a whole, based on n-alkane distributions including pristane and phytane compounds, it is concluded that the oil samples are supposed to have common source rocks and the properties of Sargelu-extracted sample is very close to the oil samples. Thus, the very good assumption is that the Sargelu Formation has molecular contributions to the studied oil samples. However, the Sargelu Formation based on vitrinite reflectance
analysis is currently postmature (R o%=1.4) in Snagaw North-1 well, as it was explained in chapter two.
4.2.2. Terpane and Sterane Related Parameters Terpane compounds distributions (Fig. 4-1), generally show great similarities between the oil samples and oil samples with the rock-extracted sample of Sargelu Formation. The most obvious differences between the m/z 191 chromatograms of the studied samples are the various intensities of C29 and C30 hopanes (peak 17 and 20, respectively) and Ts and Tm compounds (peak 14 and 15 respectively) in (Fig. 4-1). The later compounds are mostly maturity control, while hopanes are related to source materials.
The ChiaSurkh oil, genetically is much more similar to Sargelu Formation than Sarqala and Pulkhana crude oils since both Sargelu-extracted sample and ChiaSurkh oil pertained relatively higher abundance of C30 than C29 hopanes in contrast to Sarqala and Pulkhana crude oil, which is characterized by higher abundance of C 29 over C30 hopanes. The intensity of Ts compound only in rock-extracted of Sargelu Formation is slightly higher than Tm compound, which is related to the high maturity of Sargelu Formation, as explained in chapter two. On the other hand, in the oil samples Tm significantly is dominant over Ts compound, which is inferred relatively to similar maturities of the oil samples.
In spite of dissimilarity, there are many similarities between the oil samples in one side and oil samples with the rock-extracted of Sargelu Formation on the other side. As explained in chapter three, all the samples included a complete series of tricyclic terpanes with predominant of C23 compound (peak 4 in Fig. 4-1). Tetracyclic terpane C24 (peak 7 in Fig. 4-1) is dominant in comparison to most of the tricyclic terpanes. All the samples included very low concentration of oleanane and gammacerane (peaks 19 and 24, respectively) in (Fig. 4-1). The most interesting feature of the samples is their enrichment by complete series of homohopanes (peaks 22-32 in Fig. 4-1), which is considered as most characteristic evidence that prove anoxic depositional environment of source rocks for studied samples.
As explained in chapter three, based on various terpane related parameters that have been used to describe depositional conditions and source materials of the analyzed samples, the favored depositional environment of studied samples are marine that are enriched by carbonate materials and deposited with various degree under reducing conditions.
Steranes (Fig. 4-2) confirm the similarity between the selected samples that are defined on the based on terpane. The characteristic feature that can be noticed from the steranes chromatograms is the abundance of diasteranes S and R (peaks 3 and 4, respectively in Fig. 4-2) in Sargelu-extracted sample relative to the regular steranes, which relates to the high maturity of Sargelu Formation. In addition to that, ternary plot of regular steranes αααR, expressed as C27%, C28% and C29% (Table 4.1) is used to make comparison between the depositional environment and source materials of the studied samples (Bowden et al., 2006). The gross composition of regular steranes is used as a discriminated characteristic for classifying petroleum samples (Connan et al., 2006). Accordingly, the oil samples are genetically related and they are shown as strong affinity to Sargelu Formation since they are plotted as a one group on the sterane ternary plot (Fig. 4-3). The samples including rock-extracted of Sargelu Formation are characterized by abundance of C27αααR over C28 and C29 that deposited under marine environment, except for ChiaSurkh seep oil, where C28αααR is relatively more abundant than C27αααR and C29αααR steranes.
Moreover, many cross plots between the values of different biomarkers ratios have been developed in order to provide detailed information concerning the correlation procedures either oil-oil or oil-source rock correlations. In the present study some of these biomarker ratios (Table 4-1) are used to show the genetic affinity of the selected samples to demonstrate further the connections between the oil fields of the studied area.
Fig. 4-1: The m/z 191 chromatograms of the selected samples that show great similarities of peak distributions of terpane compounds. (Peak identifications are presented in Table 3-1).
Table 4-1 listed those biomarkers ratios that are used together to draw various cross plot, such as Pr/Ph (Pristane/ Phytane) versus (C29/C27) regular steranes (Fig. 4-4), Gr/C31R (Gammacerane/C31 homohopane R) versus C24/4 / C23/3 (C24 Tetracyclic/ C23 Tricyclic terpanes) (Fig. 4-5), and Sterane/Terpane versus C27diaS/C27αααR (Fig. 4-6).
Consequently, based on the molecular distributions patterns, biomarkers ratios and the diagrams that are used to demonstrate the genetic relationships between the selected samples, it is concluded that there are strong connections between the oil samples in terms of depositional conditions, source organic matter and maturities and the possibility of generating from the common sources is too high. Regarding the oil-source rock correlations, also there are clear connections between the rock-extracted sample from Sargelu Formation and the oil samples in source related materials and depositional environment, but the current maturity of Sargelu Formation is completely different from the maturity stages of the oil samples. Nowadays, lower part of Sargelu Formation in Sangaw North-1 well is postmature according to vitrinite reflectance analysis and is not able to generate oil any more.
Fig. 4-2: Presenting m/z 217 chromatograms of selected samples are showed similarity of the sterane compounds. (peaks identification are presented in Table 3-2).
Fig. 4-3: Steranes ternary diagram of C27%, C28% and C29% (αααR) concerning the selected samples, showing genetically relationships of the samples that deposited under marine environment (the diagram after Rabbani et al., 2005).
Fig. 4-4: Cross plot of Pr/Ph versus C29/C27 regular steranes shows strong genetically relationships of the selected samples including rock-extracted of Sargelu Formation in terms of depositional environment and type of source materials, (the diagram after Othman et al., 2001)
150
Fig. 4-5: Cross plot o Gr/C31R versus (C24/4) / (C23/3) shows close genetic affinity of the selected samples with each other, especially between Sarqala and Pulkhana crude oils separately and ChiaSurkh seep oil with rock-extracted of Sargelu Formation, ( the diagram after Connan et al., 2006).
Fig. 4-6: Cross plot of Sterane/Terpane versus C27S dia/C27αααR shows close genetic relationships only between oil samples and no connections between oil samples and rock-extracted of Sargelu Formation due to higher maturity of Sargelu Formation, ( the diagram after Connan et al., 2006).
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CHAPTER FIVE
Conclusions and Recommendations
5.1. Conclusions According to the TOC wt% measurement and Rock-Eval analysis, the capacities of the Lower-Middle Jurassic succession for generating hydrocarbons are defined as low in SN-1 well. The Alan, Mus and Butma formations have TOC wt% (<1) and such amount of TOC is not enough for producing sufficient hydrocarbons. The organic contents of Lower-Middle Jurassic succession are associated with unsatisfactory hydrogen elements and little amount of yielded S2 during the pyrolysis. Based on the relationship between S2 versus TOC wt% and the results of GP and PCI parameters, the Lower-Middle Jurassic sequence have poor to fair potentiality except Adaiyah Formation that has marginally good potential for releasing hydrocarbons. The closest values between the TOC wt% and RC wt% are referred of losing the hydrocarbon generative potentiality by the formations, meanwhile, the current TOC wt% values are not represented as the initial values. Rock-Eval analysis confirmed the sequence as have been contaminated either by drilling fluids or bitumens based on bimodal displayed of S2 peaks, low Tmax, high PI and presence of non-indigenous hydrocarbons. Such contamination strongly affected the results of pyrolysis and made it unreliable for characterizing the selected successions accurately. However, the kerogen types are summarized to be type III (gas prone), except for Adaiyah Formation that comprised of a mixture between type II and III (oil and gas prone).
152
The Vitrinite Reflectance analysis confirmed the predominance of solid bitumens over other organic particles. Moreover, the lignite that derived from the drilling fluids, is considered as one of the sources of contamination and confirmed optically. The maturities of Lower-Middle Jurassic formations in SN-1 well are high (gas generation zone), ranged from 1.34%-2.10% based on Vitrinite and equivalent Vitrinite Reflectance from bitumen by using Jacob’s equations. Furthermore, the presence of different populations of organic fragments within the samples including organic mud additives (lignite) and abundance of bitumen (anisotropic bitumen) may explain the unreliability of the Rock- Eval Tmax °C (70% of Tmax values lower than 400°C). Bulk properties analysis of petroleum samples indicated that all are rich in sulfur except KorMor condensate with variable API values and are not biodegraded. The differences in both API gravity and sulfur content of the oils probably are related to the variability in thermal maturation. The condensate and crude oils have typical conventional oil properties and are Aliphatic, except for Pulkhana where characterized by slightly aromatic oil and its composition is not as per typical oil compositions. According to molecular compounds and biomarkers analysis by GC/MS, crude oils, condensate and extract of Sargelu Formation are derived from marine algae and kerogen type II of a marine carbonate source rock that are deposited under reducing conditions. They are all characterized by low values of Pr/Ph, slightly even predominance of nalkanes, high values of short over long chain n-alkanes and abundant C27 regular sterane. Moreover, the geochemical results of tricyclics, tetracyclic and hopanes with high abundance of homohopanes series and low diasteranes/ steranes ratio, altogether with ratio of DBT/P confirmed marine carbonate source rocks that are deposited under anoxic condition. Very low presence of gammacerane indicated normal salinity condition during the deposition.
Molecular maturity parameters such as sterane, hopane isomer ratios and CPI values indicate that the crude oils are mature. The ratio of Ts/Tm and MPI 1 seems to be reliable to indicate the maturity sequence from high to low as follow: KorMor and extract of Sargelu Formation> ChiaSurkh > Sarqala > Pulkhana. However, there are disagreements in 153
the maturity sequence according to sterane, hopane and TAS ratios, which mostly relates to the depositional conditions and source materials. The GC-FID traces of the crude oils and condensate approved lack of biodegradation effects on the samples, however ChiaSurkh seepage has been depleted from lighter hydrocarbon compounds (
5.2. Recommendations 1. Core sample analysis is recommended for characterizing further Lower-Middle Jurassic succession in terms of potentiality, kerogen types and maturities. 2. Isotopic analysis is required to show further similarity or dissimilarity between the Sargelu Formation and crude oils in the study area. 3. This study wasn’t able to make correlations between Early Jurassic formations and selected petroleum samples. Further study required to look at the biomarkers analysis to establish detail understanding of the petroleum systems in the studied area. 4. Using Petro-mode 1D for study area to get more idea about the studied formations is recommended. 5. Analyzing the value of sulfur (%) within the kerogen contents to be sure about the oil generation time in Sargelu Formation.
154
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Appendices Appendix A: Comprises the stratigraphic column of the each studied formations separately, started from Sargelu Formation (Fig. A-1) to Butma Formation (Fig. A-5). All the stratigraphic columns and their descriptions have been quoted from the master log of SN-1 well.
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Fig. A-1: Stratigraphic column of Sargelu Formation with detailed description of lithology.
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Fig. A-2: Stratigraphic column of Alan Formation with detailed description of lithology.
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Fig. A-3: Stratigraphic column of Mus Formation with detailed description of lithology.
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Fig. A-4: Stratigraphic column of Adaiyah Formation with detailed description of lithology.
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Fig. A-5: Stratigraphic column of Butma Formation with detailed description of lithology.
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Appendix B: TOC wt% and Rock-Eval analysis results of all the cutting samples. The highlighted samples are discarded from the interpretation processes due to either low TOC wt% (<0.3%) or low S2 (<0.2) or anomalous values.
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Appendix B: Continued.
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Appendix C: Presenting the procedures of TOC wt% measurement by CHN in GHGeochem laboratory in UK: 1. Sample preparation Samples for TOC analysis are ground to a powder (<60 microns), dried in an oven (40degC). Weighed aliquots of each sample are put into silver capsules which are then exposed to acid vapour treatment for 24 hours. The acid treated samples are then dried for 2 hours in an oven. The silver capsules are then enclosed in tin capsules to provide flash combustion during instrumental analysis. Analysis time is 6 minutes per sample. The chemical reactions involved are as follows: Acidification of sediment samples with concentrated HCl: carbonate removal CaCO3 + 2HCl → CO2 + CaCl2 + H2O 2. Apparatus: Instrumentation: All quantitative analyses for carbon and nitrogen are performed with a Carlo ErbaElemental Analyzer NC2500. The operation of the elemental analyzer is based on the complete and instantaneous oxidation of the sample by “flash combustion” whereby all organic and inorganic substances are converted into combustion products. 3. Analytical conditions for TOC wt% measurement:
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Appendix D: Presenting the histograms of selected samples for vitrinite reflectance measurement. Appendix D-1: Showing the histogram of rock-cutting sample at the depth 3225m of Sargelu Formation.
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Appendix D-2: Showing the histogram of rock-cutting sample at the depth 3270m of Sargelu Formation.
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Appendix D-3: Showing the Histogram of rock-cutting sample of Mus Formation at the depth 3465m.
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Appendix D-4: Showing the histogram of rock-cutting sample of Adaiyah Formation for the depth 3528m.
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Appendix D-5: Showing the histogram of cutting rock sample of Butma Formation for the depth 3645m.
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Appendix D-6: Showing the histogram of cutting rock sample of Butma Formation for the depth 3882m.
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Appendix E: This document presents the key steps of the sample preparation procedure of saturate and aromatic fractions before gas chromatography analysis (GC, GC/MS, GC/irMS). GC or GC/FID: Gas Chromatography coupled with a Flame Ionization Detector.
GC/MS: Gas Chromatography coupled with Mass Spectrometry.
GC/irMS: Gas Chromatography coupled with isotopic ratio Mass Spectrometry.
First main step: Topping for oils or ASE extraction for rocks
1.1 Case of Oil Samples: Topping The topping consists on evaporating an oil sample, in order to recover a C15+ fraction, by eliminating water, volatile hydrocarbons.
Oil sample
GPC
GC-BR
GC-HT
GC CARBURANE
Topping
Composition Iatroscan SAT/ARO/POL
GC-STAT
Precipitation of Asphaltenes
Maltenes
Asphaltenes
ASPEC Preparation
Saturate fraction
Aromatic fraction
GCMS-SAT
GCMS-ARO
Resines
Fig. 1: general procedure for preparation of oil samples in the FGO department. 180
The experimental conditions are the following: o o o o
Water bath temperature: 50°C. Pressure : 20 mbars (Delta : ± 1 mbar). Rotation speed: 100 trs/min. Evaporation time: 5 hours.
Generally, the objectives of the topping step are: To improve the characterization of oils thanks to the determination of concentrations (mass) of the residue and the distillate, To do a stabilization of the oil sample before analysis by Liquid Chromatography (LC), by GC, GC/MS and/or GC/irMS. To do a comparison between oils and extracts (in so far as the extracts are prepared by obtaining C15+ fractions).
1.2 Case of rock Samples: Accelerated Solvent Extraction (ASE) The ASE extraction consists of extracting from rocks (source rock, reservoir rock, bitumens, etc.) the soluble organic matter in dichloromethane. It allows evaluating the Extractable Organic Matter (EOM) (ratio between the extracted mass after ASE and the initial rock quantity).
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Crushed Rock
TOC+ RockEval
Extraction ASE
Desulfured Extract C15+
Composition Iatroscan SAT/ARO/POL
Precipitation of Asphaltenes
Maltenes
GC-OC-FID
Asphaltenes
ASPEC preparation
Saturate fraction
Aromatic fractions
GCMS-SAT
GCMS-ARO
Resines
Fig. 2: general procedure for preparation of rock samples in the FGO department.
In this kind of extraction, liquid solvents are used at high temperature (from 25°C to 200°C) and high pressure (from 70 to 200 bars), in order to quickly extract the organic matter from solid samples. Since the ASE extraction system works at 70 bars min., the solvent can be heated at a temperature which is largely higher than its normal boiling point (but lower than the critical temperature; for dichloromethane, the critical temperature is above 200°C). -
-
The crushed rock sample is placed in a steel cell. The cell is filled under pressure by the extraction solvent and then heated. When the working temperature and pressure are reached (100°C and 100 bars), the sample stays in a static extraction mode during 3 cycles of 3 minutes. After each cycle, the cell is rinsed by the solvent (volume of solvent = 1/3 of the volume of the empty cell). The rinsing solvent is recovered in a flask. At the end of the extraction, the flasks containing the organic solution are totally evaporated and stored in desiccators during 12 hours min. Then, the flask is weighed.
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Second main step: Separation of Maltenes and Asphaltenes The objective of this step is to separate and to recover: An asphaltene fraction (recovered thanks to the precipitation of asphaltenes in npentane). A maltene fraction (without asphaltene).
o o o
n-pentane is added in the C15+ fraction obtained in the first step (50 ml npentane per gram of fraction). The solution flask is placed in an ultra-sonic agitator. The solution is filtered (under vacuum, at ambient temperature) on a MILLIPORE filter (0.45µm, PTFE).
The non-soluble compounds in n-pentane are retained on the filter (formation of a precipitate). They correspond to the asphaltene fraction. The asphaltenes are recovered by adding dichloromethane on the filter (dissolution of the precipitate). After evaporation of the solvent, the asphaltene fraction is weighed to provide its concentration (mass percent).
The filtrate, soluble in n-pentane, corresponds to the maltene fraction. It is recovered for ASPEC separation.
Third main step: ASPEC preparation The objective is to do a separation, both qualitatively and quantitatively, of the saturate and aromatic compounds, from the maltene fraction recovered in pentane in the second step. Before injecting 1 ml of the maltene fraction in the ASPEC system, the fraction is concentrated by evaporation (objective: to obtain 3 ml of fraction for 100 mg sample (eq. sample containing asphaltenes)). The ASPEC preparation consists of: -
A first separation on a SPE column (retention of polar compounds). A second separation between the saturate and aromatic compounds on a chromatographic column. The collected fractions are concentrated by evaporation, before analysis by GC, GCMS or GC/irMS.
183
The experimental conditions are the following: -
Mobile phase: n-pentane (first dried and filtered on a 0.22 µm PTFE filter). Flow of mobile phase: 4 ml/min. Pressure: ~ 21 bars. SPE column: Lichroprep CN; 40-63 µm, 60 Å. Inox LC Column: Lichrosorb SI; 250 x 10 mm; 5 µm; 60 Å.
Appendix F: Presenting the GC/MS method that have been used to analyze rock-extracted and oil samples by CSTJF center:
Computerized gas chromatography/mass spectrometry (GC/MS) is utilized to evaluate biologically derived compounds in oils or rock extracts. The saturate and aromatic fractions are injected into an HP 6890 gas chromatograph coupled to an HP 5973 PP MSD in Selected ion monitoring (SIM) mode. GC/MS was equipped with a DB-5 column (60 m length, 250.0 μm diameter, and 0.10 μm film thickness). The samples are injected in split mode under constant pressure of carrier gas (Helium) flow at a rate of 35 cm/sec, at 70 eV ionization energy. The GC temperature program started at 40°C held isothermally for 6min, then heated at 2 °C/min to 300 °C (held 60 min).
184
Appendix J: Presenting the peak areas of all the compounds (n-Alkanes, Terpanes, Steranes and Aromatics):
185
Appendix J: Continued
186
Appendix J: Continued
187
خصائص اجليوكيمياء العضوية لتتابع اجلوراسيك االسفل و االوسط و النفوط اخلام من ابار خمتارة يف منطقة كرميان ,أقليم كردستان ,مشال شرق العراق رسالة
مقدمة اىل جملس فاكليت العلوم و تربية العلوم يف جامعة السليمانية كجزء من متطلبات نيل درجة ماجستري يف علم االرض من قبل
ديار عبدالقادر سعيد بكالوريوس جيولوجى – جامعة السليمانية 1998
حتت أشراف
د.ابراهيم حممد جزا حمي الدين أستاذ مساعد
حزيران
ربيع االول 1435هجرى 2014ميالدى 188
الخالصة تم تحليل 48نموذجا من الفتات الصخرى من تتابع الجوراسك االسفل و االوسط من تكاوين (بطمة و عداية و موس و عالن و سركلو) فى بئر شمال سنكاو ( ) SN-1 ( )1في بلوك شمال سنكاو في منطقة كرميان في أقليم كوردستان من ناحية الخواص البصرية و الجيوكيميائية .وكذلك نموذجان من النفط الخام من بئري بولخانة ( )4من حقل نفط بولخانة
و سرقال ( )1من حقل
نفط سرقال و نموذج من الغاز المكثف من بئر كورمور ( )3من حقل غاز كورمور و نموذج سطحى ناضح من حقل جيا سورخ و ذ لك لغرض دراسة الجيوكيمياء العضوية و تطبيق مضاهاة نفط -نفط و نفط -صخور مصدرية. تقع منطقة الدراسة من الناحية التكتونية فى الجزء الجنوب الشرقى من نطاق الطيات الواطئة من حزام طيات زاكروس . حددت قدرة تكاوين الجوراسيك االسفل و الوسط ل نتاج الهايدروكاربونات بشكل عام بضعيفة. اظهرت نتائج جهاز Rock-Eval Pyrolysisو معطيات ( ) S1, S2, GP, and PCIبان مقدرة التتابع النتاج الهايدروكاربونات ضعيفة ألى معتدلة ,بأستثناء تكوين عداية حيث أظهر امكانية جيدة نوعا ما .دراسة المحتوى العضوى للصخور قيد الدراسة بينت بشكل تقريبى بان الصخور تحتوى على كيروجين نوع ( IIIمنتج للغاز) و ذلك اعتمادا على معطيات Rock-Eval ( ) HI, OI, S2, and PCIعدا بعض اجزاء من تكوين عداية حيث نوع الكيروجين هو خليط من IIو ( IIIمنتج للنفط و الغاز) .نتائج Rock-Evalلم تكن دقيقة لوصف درجة نضوج تكاوين ( بطمة و عداية و موس و عالن و سركلو)
و ذلك للتناقض في قيم Tmaxمع معامل
االنتاج ( ) PIحيث من المحتمل ان يكون سببها التلوث .أثر ألتلوث بشكل كبير على نتائج 189
( )Rock-Evalو قد استنتج ذلك من خالل ألشكل ألثنائى ألقمة لقمم S2وألقيم ألواطئة ل ( )Tmaxو ألقيم ألعالية لمعامل االنتاج ( ) PIووجود هايدروكاربونات مهاجرة مع ألفتات ألصخرى لتكويني عالن وسركلو .هذا بألضافة الى بعض ألمواد الطينية ألمضافة (ألليكنايت) حيث تعتبر مصدرا للتلوث والتي ُميزت بصريا من خالل تحليل انعكاس الفيترينايت. درجة نضوج تتابع الجوراسيك فى بئر سنكاو ( )1عالية ( نطاق انتاج الغاز) وتراوحت بين1.38 و % 1.1
أعتمادا على قياس أنعكاس الفيترينايت و مكافئاته والتى أشتقت من البيتيومين
بواسطة معادلة جاكوب. نماذج النفط الخام و الغاز المكثف لم تظهر اى عالمات للتحلل العضوى و تحتوى على نسبة عالية من الكبريت عدا نموذج الغاز المكثف في كورمور (يحتوي نسبة قليلة من الكبريت) وقد اظهروا درجة APIبين 1..2و 7..6درجة. اظهرت نسبة الدالئل الحيوية ( ) Biomarkersو توزيع المركبات الجزيئية بان النفط الخام و الغاز المكثف و البتيومين المستخلص من صخور تكوين سركلو كلهم من اصل صخور مصدرية كاربوناتية بحرية حاملة للطحالب البحرية وكيروجين نوع IIو ترسبت فى بيئة مختزلة .التواجد المنخفض للكاماسيرينس ( )Gammaceraneيشير الى ملوحة اعتيادية أثناء الترسيب ,هذا بألضافة الى ان العوامل المؤشرة لدرجة النضوج تشير الى مدى واسع من النضوج من المتوسط الى العالى. تسلسل درجة النضوج للعينات المدروسة اعتمادا على نسبتى Ts/Tmو MPI 1مرتبة من مستوى النضوج العالي الى المنخفض هي كأآلتي ; البتيومين المستخلص من سركلو و الغاز
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المكثف من كورمور -نفط جيا سورخ -نفط سرقال -نفط بولخانة .نتائج GC-FIDللنفوط الخام و الغاز المكثف لم تظهر اي دليل على التحلل العضوى ,لكن البتيومين المستخلص من تكوين
سركلو بين و بشكل كبير تأثير التلوث بفعل البولي اثيلين كاليكول كما تظهر فى
الكروماتوكرام لجهاز غاز الكروماتوكراف. تشابه مكونات ستيرن و هوبان و ايسوبرينويد و مركبات الكان االعتيادية من بين النفوط الخام و النفوط الخام و البتيومن المستخلص من تكوين سركلو تبين بان النفوط ربما جائت من صخور مصدرية متشابهة من حيث ظروف البيئة الترسيبية .ومن جهة اخرى فأن من المحتمل ان يكون تكوين سركلو احد الصخور المصدرية لهذه النفوط بالرغم من ان المعامالت ذات العالقة بالنضوج اظهرت عدم تشابه بين النفوط الخام و البتيومن المستخلص من تكوين سركلو.
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رِةوشتةكانى جيوَكيمياى ئةنداميى بوَ ضينةكانى ذيَرةوة و ناوةرِاستى جووراسيك لةطةلَ منوونةكانى نةوتى خاو لة ضةند برييَكى دياريكراودا ,ناوضةى طةرميان ,هةريَمى كوردستان ,باكوورى خوَرهةالَتى عيَراق نامةيةكة ثيَشكةش كراوة بة ئةجنومةني فاكلَيت زانست و ثةروةردة زانستةكان سكولَي زانست لة زانكؤي سليَماني وةك بةشيَكى تةواوكةر بوَ بةدةستهيَنانى ماستةر لة زةويناسي دا لةاليةن
ديار عبدالقادر سعيد
بةكالوَريوَس لةزانستى زةويناسي -زانكوَى سليَمانى 1998
بةسةرثةرشيت
د .ئيرباهيم حمةمةد جةزا حميَدين ثروَفيسوَرى ياريدةدةر
ثوشثةرِ 2724كوردى
حوزةيران 2124زاينى
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ثوختة بةطشتى 84منوونةى بةردةكانى ذيَرةوة و ناوةرِاستى جووراسيك ( ثيَكهاتووةكانى بومتة و عةداية و موس و ئةالن و سةرطةلَوو) لةناو بريى سةنطاو ) SN-1 ( 1لة بلوَكى سةنطاوى باكوور لةناوضةى طةرميانى حكومةتى كوردستان وةرطرياوة و ليَكدانةوة و شيكارى جيوَكيميايى و بينراوةيى بوَ ئةجنام دراوة .دوو منوونةى نةوتى خاو لةبريةكانى ثولَخانة ( 8 -ضالَةنةوتيى ثولَخانة) و بريى سةرقةالَ ( 1-ضالَةنةوتيى سةرقةالَ) و يةك منوونةى نةوتى ضرِبووةوة لة بريى كوَرموَر ( 3 -ضالَة نةوتيى كوَرموَر) و هةروةها منوونةيةكى نةوتى دةرضووى سةرزةوى لة ضالَةنةوتى ضياسوورخ وةرطرياون و لةرِووى جيوَكيمياى ئةنداميى و بةراوردكردنى نةوت-نةوت و نةوت -كةظرى سةرضاوةيى يةوة ليَكدانةوةيان بوَئةجنامدراوة. ناوضةى ئةم ثروَذةية لةرِووى تةكتوَنييةوة دةكةويَتة بةشى باشوورى خوَرهةالَتى ثشتيَنةى ضينةضةماوةنزمةكان لة ثشتيَنةى سةرةكيى ضينة ضةماوةكانى زاطروَس. توانستى ثيَكهاتووةكانى ذيَرةوة و ناوةرِاستى جووراسيك بةشيَوةيةكى طشتى
بوَ بةرهةمهيَنانى
هايدروَكاربوَن نزمة .ئةجنامةكانى دةست كةوتوو لةئاميَرى( ) Rock-Eval Pyrolysisكةبريتيني لة هاوكوَلكةكانى ( ) S1, S2, GP, and PCIدةرياخنستووة كة توانستى ئةم ضينانة بوَ دةركردنى هايدروَكاربوَن نزم بوَ كةمة ,جطة لة ثيَكهاتووى عةداية كة دةكريَت بة باش ناوزةدبكريَت .ثيَكهاتةى ئةنداميى ئةم ضينانة زياتر لةطةلَ كريوَجينى جوَرى سيَيةم يةكدةطريَتةوة كة تواناى بةرهةمهيَنانى طازى هةية كةئةمةش ثشت ئةستوور بة ئةجنامةكانى ( ) HI, OI, S2, and PCIوةرطرياوة ,بيَجطة لة وةى كة هةنديَك لةضينةكانى ثيَكهاتووى عةدايةى سةرةتاى جووراسيك كة وا دةردةكةويَت جوَرى تيَكةلَةيةك بيَت لة كريوَجينى جوَرى دووةم و سيَةم( واتة بةرهةمهيَنى غاز و نةوت) .ئةجنامةكانى ئاميَرى (
)Rock-Eval Pyrolysis
باوةرِثيَكراو نةبوو بوَ دياريكردنى ثيَطةيشتوويى ثيَكهاتووةكان ئةمةش بةهوَى ئةوةى كة نةطوجنان هةبوو لة نيَوان بةرزترين ثلةى طةرميى ( ) Tmaxلةطةلَ هاوكوَلكةى بةرهةم هيَنان ( ) PIكةئةمةش لةوانةية بةهوَى
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ثيسبوونةوة بووبيَت .ثيسبوون بةشيَوةيةكى طةورة كارى لةئةجنامةكانى رِوَك ئيظالَ كردووة كة ئةمةش بةرِوونى لة شيَوةى دوولوتكةيى S2دا دةبينريَت ,هةروةها لةنرخى نزمى بةرزترين ثلةى طةرميى و بةرزيى هاوكوَلكةى بةرهةم هيَنان( ) PIدابةهةمان شيَوة دةردةكةويَت ,سةرةرِاى ئةوةى كة هايدروَكاربوَنى نارِةسةن لةهةنديَك منوونةى بةرديى ثيَكهاتووةكانى سةرطةلَوو و عةالن دا دةبينريَت .لةمةش زياتر ماددةى قورِيى زيادكراو ( ليطنايت) كة ب ةسةرضاوةيةكة ثيسبوون دادةنريَت بة رِيَطةى بينراوةيى لةذيَر وردبيندا هةستى ثيَكراوة لةكاتى شيكارى ثةرضدانةوةى ظيرتينايتدا. ثلةى ثيَطةيشتوويى ضينةكانى جووراسيك لة بريى باكوورى سةنطاو 1-دا بةرزة ( واتة بةرهةمهيَنى غازة) و لةنيَوان نرخى 1.34و 2.1دان لةسةر بنةماى رِيَذةى سةديى ثةرضدانةوةى ظيرتينايت و هاوشيَوةكانى ظيرتينايت كة لةبتيومينةوة وةرطرياوة و بةهاوكيَشةى جاكوب رِاست كراوةتةوة. منوونةى نةوتةخاوةكان و غازة ضرِبووةوةكة تيَكنةضوون و تيَكشكانى زيندةييان ( ) Biodegradation ثيَوةديار نيية و برِى طوَطرديان بةرزة (جطة لة منوونةى ضرِبووةوةى كوَرموَر كة طوَطردى كةمة)هةروةها ثلةى ئةى ثى ئاى لةنيَوان 25.9بوَ 65.7ثلة دةبيَت. رِيَذةى زيندة نيشانةكان( ) Biomarkersو بالَوبوونةوةى ثيَكهاتة طةردييةكان ئةوة ثيشان دةدةن كة نةوتةكان و غازة ضرِةوةبووةكة وبتيومينى بةردةكانيش كة لة كةظريَكى سةرضاوةيى كاربوَناتى دةريايى وةهاتوون وئةم كةظرانة برِيَكى باش لة قةوزةى دةريايى و كريوَجينى جوَرى دوويان هةلَطرتووة و لةذيَر بارودوَخيَكى بىَ ئوَكسجني دابوون .برِيَكى زوَركةمى طاماسرييَني ذينطةيةكى خويَياوى ئاسايى ثيشان دةدات لةكاتى نيشتندا .سةرةرِاى ئةوةى كة هاوكوَلكةكانى بةكارهاتوو بوَدياريكردنى ثيَطةيشتوويى ئةوةدةردةخةن كة بواريَكى فراوان هةية لةرِووى ثيَطةيشتوويى لةنيَوان مامناوةند بوَ بةرز .رِيزبةندى ئةومنوونانةى كة ليَيانكوَلَراوةتةوة لةرِووى ثيَطةيشتوويى لةسةربنةماى رِيَذةكانى Ts/Tmو MP1لةنيَوان بةرز تا نزم دايةو بةم شيَوةية :منوونةى بتيومينى كةظرةكان و كوَرموَر > نةوتى ضياسوورخ > نةوتىسةرقةالَ > نةوتى ثولَخانة. ئاماذةكانى GC-FIDنةوتةكان و غازة ضرِبووةوةكة بةرِوونى ديارة كة هيض زيندة هةلَوةشانيَك( 194
) Biodegradationرِووى نةداوة ,بةالَم بتيومينى دةرهاتوو لةمنوونةى بةردى سةرطةلَوو بةشيَوةيةكى ديار ثيسبوون بة ثوَليئةسيلني طاليكوَل ثيشان دةدات لةسةر بنةماى كروَماتوَطرامى GC-FIDكةوة. لةرِوويى ثيَكهاتةى سترييَن و هوَثان و ئايسوَثرينوَيد و ئاويَتة كانى ئةلكانة ئاساييةكانةوة لةنيَوان نةوتةكان و ئةو بتيومينةى ناو بةردى ثيَكهاتووى سةرطةلَوو شيكاركراون بةرِوونى ليَكضوون و هاوشيَوةيى ثيشان دةدةن كة ئةمةش ئةوةدةطةيةنيَت كةلةوانةية ثيَكهاتووى سةرطةلَوو بةشداربووبيَت لةبةرهةمهيَنانى ئةونةوتانة وةك سةرضاوةيةك و يان هةر نةبيَت لة سةرضاوةيةكة وة هاتوون كة لة سةرضاوةى وةك سةرطةلَوو دةضيَت و لةذيَر بارودوَخيَكى ليَكضوو نيشتوون.
لةطةلَ ئةمانةشدا هاوكوَلكةكانى ثيَطةيشتوويى ليَكنةضوون ثيشان ئةدةن
لةنيَوان نةوتة خاوةكان و ئةو بتيومينةى كة لة بةردى ثيَكهاتووى سةرطةلَووة وة دةست كةوت بوو.
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