Calculation of the Amounts of Hydrocarbons Generated from the Lower Antalya Nappes,Western Taurus Region: The Importance of the Fractional Conversion (f) Value

Abstract

Applying the corrected Hydrogen Index values obtained from S ₂ vs. TOC graph in conjuction with the results of Rock-Eval pyrolysis and mass balance calculations provide estimations of the original hydrocarbon generative capacity and the amounts of hydrocarbons generated. For calculations and a comparison between three different approaches were applied to 27 organic-rich samples collected from the Dereköy Formation shales which are mainly characterized by oil-prone Type-II kerogen that is in different thermal maturity levels. Such calculations indicate that (1) the results of the calculated amounts of original hydrocarbons are mostly over 100,000 ppm, (2) the results of the hydrocarbon generative capacities from two methods which include fractional conversion value are in accordance, and, are over 5000 ppm, and (3) when the fractional conversion values are low (ranging from essentially zero to 0.5%), indicating thermally immature stage, the calculation results of three methods are almost similar.     

Whole-Rock,Clay Mineral Contents and Matrix Effect on the Cenomanian/Turonian Petroleum Source Rocks in the Lower Antalya Nappe,Western Taurus Region of Turkey

Abstract

Whole-rock analyses by x-ray powder diffraction and Rock-Eval pyrolysis studies were carried out on the Cenomanian/Turonian Dereköy formation shales from four sample sites in the Lower Antalya Nappe in the western Taurus region (SW Turkey) to determine rock-forming mineral assemblages, their abundance in bulk composition, and clay matrix effect on hydrocarbon yield during Rock-Eval pyrolysis. These studies indicate that the rock-forming minerals are mostly quartz (3–68%), clay minerals (32–81%) including smectite and illite, and rare to common calcite (0–39%), feldspar (0–5%) and mica (0–11%). High total organic carbon (TOC) contents (up to 42 wt%) and corrected hydrogen indices between 538 and 642 (mg HC/g TOC) correspond to marine organic matter (Type II kerogen) and excellent oil-prone hydrocarbon source rocks. Strong positive correlation (R ² = 0.84 to 0.96) between hydrocarbon yield (S ₂) and TOC content implies that the positive values of x and y-intercepts are relatively high, with values ranging between 1–13.117 mg pyrolysable hydrocarbon in 1 g of rock. These results mean that the clay matrix is the main agent of adsorbtion, and high amounts of hydrocarbon retention must be present.     

Hydrocarbon Source Rock Assessments of the Late Jurassic Black Shales (Tokmar Formation) in the Central Taurus Region of Turkey

Abstract

The hydrocarbon source rock potential and the thermal maturity of the Late Jurassic Tokmar Formation in the Bo?untu area of the central Taurus region have been investigated. Tokmar Formation includes organic matter–rich dark grey shales alternating with carbonates that were deposited under dysoxic to anoxic marine conditions prevailed in the Late Jurassic. A total of 14 samples have been analyzed by Leco and Rock-Eval pyrolysis for determination of their hydrocarbon source rock characteristics and organic maturity. The total organic carbon content of the samples range from 0.26 to 1.53 wt%. The actual Rock-Eval pyrolytic yields (S₁ + S₂ peak values) are between 0.25 and 3.63 mg HC/g rock. The calculated hydrogen index and oxygen index values imply that the main organic matter types are Type II and Type III kerogens. T_max versus hydrogen index values indicate that the Bo?untu samples are thermally mature and took place in the oil generation window.     

Maturity and Source Rock Evaluation of the Gadvan Formation,Persian Gulf,South of Iran

Rock-eval pyrolysis is used to rapidly evaluate the petroleum generation potential and maturity of rocks. In the current paper, the geochemical characteristics of a probable source rock, Gadvan Formation, in south of Iran, Persian Gulf, was studied. To get the goal 56 ditch-cutting samples of 17 wells, drilled in Persian Gulf, were collected and analyzed using Rock-Eval pyrolysis. Pre-analyses of Rock-Eval outputs shows that only 33 samples are suitable for further investigations, as other ones has been contaminated by migrated hydrocarbons. Kerogen type III is dominating type in the samples, while few of them are type II. It seems that Gadvan is a gas prone formation, which can generate hydrocarbon due to its fair maturity in some intervals. The possible organic facies of Gadvan Formation are mainly reducing and deep marine environments with moderate rate of sedimentation, which confirm its potential to perform as a source rock in the area; however, few of samples were deposited in oxidizing condition based on the results of Jones diagram. Finally, the diagram of S₂ versus total organic carbon proved negligible mineral matrix effect and inert carbon in the understudied samples of Gadvan.     

Source rock potential of the Sayındere formation in the Şambayat oil field,SE Turkey

Upper Campanian–Maastrichtian Say?ndere Formation, located in southeastern Turkey, composed of pelagic limestone which was deposited relatively deep marine. In this study, well samples of the Say?ndere Formation were analyzed by Rock-Eval pyrolysis and the oil sample from this unit were analyzed by GC, and GC-MS to assess source rock characteristics and hydrocarbon potential. The TOC values of the Say?ndere Formation samples range from 0.34 to 4.65?wt.% with an average of 1.14?wt.% and organic matter have good TOC value. Hydrogen Index (HI) values range from 407?mg HC/g TOC to 603?mg HC/g TOC and indicates Type II kerogen. T_max values are in the range of 434 - 442?°C and indicate early-mid mature stage. The Say?ndere samples have fair to good hydrocarbon potential based on TOC contents, S2, and PY values. According to the HI versus TOC plot, most of the samples have good oil source. The oil sample contains predominant short-chain n-alkanes and plots in marine algal Type II field on a Pr/n-C17 versus Ph/n-C18 cross-plot indicating anoxic environment. Biomarker analysis shows that the deposition of oil source rock is carbonate-rich sediments.     

Organic geochemical characteristics of Middle to Late Eocene Shahbazan Formation in Dezful Embayment,SW Iran: A case study from Qaleh-Nar oilfield

Abstract

In a first attempt, Middle to Late Eocene Shahbazan Formation as a possible source rock in Dezful Embayment was geochemically investigated. Maturity indicators derived from Rock-Eval pyrolysis (T_max and PI) and gas chromatography (CPI) show that the organic matter, which dominated by a mixed type II/III kerogen, is thermally mature and has already entered the oil window. A fair to good petroleum-generative potential is suggested by moderate to relatively high values of total organic carbon (TOC) and potential yield (S₁+S₂). Deposition of Shahbazan Formation under low-oxygen condition, which is represented by low pristane/phytane ratio (<1), conduced to preservation of organic matter. This is in accordance with considerable TOC contents, ranging from 1.01 to 1.72?wt%. The relation between pristane/nC₁₇ and phytane/nC₁₈ as well as terrigenous/aquatic ratio (～1) represent the mixed marine and terrestrially sourced organic matter. Based on the results obtained from this study, Shahbazan Formation could have been acted as a prolific oil and gas source rock.     

Effect of bitumen and migrated oil on hydrocarbon generation kinetic parameters derived from Rock-Eval pyrolysis

Thermally immature whole rock and related bitumen-extracted samples were pyrolyzed. Investigating the influence of high molecular weight hydrocarbons and degradation products of non-hydrocarbon constituents of bitumen and associated migrated oil (i.e. resins and asphaltenes) on petroleum generation kinetic parameters derived from Rock-Eval pyrolysis is the main aim of this study. Based on the optimized kinetic parameters, frequency factor values of the bitumen-free samples show an obvious increase compared to whole rocks, while the range of activation energies for them is narrower. On the other hand, the predicted geological temperatures of the onset (TR 10%) and the peak hydrocarbon generation (geological T_max) from the whole rocks are generally lower than the corresponding extracted samples. In other words, the whole rock samples underestimate the petroleum formation temperatures. Thus, the results of this study suggest the extraction of bitumen prior to Rock-Eval pyrolysis in order to obtain precise kinetic parameters for the source rocks bearing a large amounts of heavy bitumen or migrated oil.     

不同烃源岩实验评价方法的对比

在Rock-Eval热解法、H/C比及加水热模拟实验3种烃源岩生烃潜力评价方法对比的基础上,对塔里木盆地满加尔坳陷低成熟侏罗系煤岩进行了生烃评价。对比结果表明,H/C比值与加水热解实验法评价结果较接近,生烃量分别为9.62和9.72 mg/g,而Rock-Eval热解法得到的生烃潜力为32.75 mg/g,远高于其他两种评价结果。Rock-Eval热解法得到的是烃源岩的最大排烃量,而H/C比与加水热模拟实验法获得的是烃源岩的有效排烃量。因此,在对烃源岩的生烃评价中要根据实际需求选择不同的评价方法。      

ORGANIC GEOCHEMISTRY,BURIAL HISTORY AND HYDROCARBON GENERATION MODELLING OF THE UPPER JURASSIC MADBI FORMATION,MASILA BASIN,YEMEN

The Masila Basin is an important hydrocarbon province in Yemen but the origin of its hydrocarbons is not fully understood. In this study, we evaluate Upper Jurassic source rocks in the Madbi Formation and assess the results of basin modelling in order to improve our understanding of burial history and hydrocarbon generation. This source rock has generated commercial volumes of hydrocarbons which migrated into Jurassic and Lower Cretaceous reservoir rocks. Cuttings samples of shales from the Upper Jurassic Madbi Formation from boreholes in the centre-west of the Masila Basin were analysed using organic geochemistry (Rock-Eval pyrolysis, extract analysis) and organic petrology. The shales generally contain more than 2.0 wt % TOC and have very good to excellent hydrocarbon potential. Kerogen is predominantly algal Type II with minor Type I. Thermal maturity of the organic matter is R_r 0.69–0.91%. Thermal and burial history models indicate that the Madbi Formation source rock entered the early-mature to mature stage in the Late Cretaceous to Early Tertiary. Hydrocarbon generation began in the Late Cretaceous, reaching maximum rates during the Early Tertiary. Cretaceous subsidence had only a minor influence on source rock maturation and OM transformation.     

Geochemistry,generation and maturation of the hydrocarbons at Wadi Al-Rayan oil field,Western Desert of Egypt

`The present work aims to study the organic chemistry, the generation and maturation of the hydrocarbons encountered at Abu Roash Formation, Wadi El Rayan oil field. The analysis of source rocks indicates the presence of two organic facies. The first is characterized by high total organic carbon of 0.93–3.39%, strongly oil-prone (Type II), and good potential for oil generation (pyrolysis S2 yields 4.54–23.26 mg HC/g rock and HI 488–705 mg HC/g TOC). The second attains good range of organic carbon from 0.90% to 1.57%, which is a mixed oil and gas (Type II–Type III) of fair hydrocarbon generation (pyrolysis S2 yield of 1.98–5.33 mg HC/g). The kerogen type consists of unstructured lipids and some terrestrial material. Plot of Pr/n-C17 versus Ph/n-C18 indicates that the crude oil was derived from mixed source rock, while the maturity profile assigns oil windows (0.6 R_o%) matching topmost of Abu Roash G Member.     

Investigating gas resource potentiality from Late Jurassic Madbi Formation in the NW –Say’Un-Masila Basin,Eastern Yemen

Late Jurassic Madbi shale samples from Al-Qarn-01 well in the NW Say’un-Masila Basin, Eastern Yemen are analyzed using conventional geochemical data such as total organic carbon (TOC) content and Rock-Eval pyrolysis. The results in this study are used to evaluate the gas resource potentiality in the basin. The analyzed shales have high TOC content between 1.00% and 3.12%, and their HIs range from 77 to 177?mg HC/g TOC. These values indicate that the investigated Madbi shale intervals contain Type III kerogen and are considered to be very good gas-source rocks. Furthermore, the relatively high Rock-Eval pyrolysis T_max (447–459?°C) and PI (0.09–0.44) values indicate mainly peak to late mature oil window.     

SOURCE ROCK PROPERTIES OF LACUSTRINE MUDSTONES AND COALS (OLIGOCENE DONG HO FORMATION), ONSHORE SONG HONG BASIN, NORTHERN VIETNAM

Oligocene lacustrine mudstones and coals of the Dong Ho Formation outcropping around Dong Ho, at the northern margin of the mainly offshore Cenozoic Song Hong Basin (northern Vietnam), include highly oil‐prone potential source rocks. Mudstone and coal samples were collected and analysed for their content of total organic carbon and total sulphur, and source rock screening data were obtained by Rock‐Eval pyrolysis. The organic matter composition in a number of samples was analysed by reflected light microscopy. In addition, two coal samples were subjected to progressive hydrous pyrolysis in order to study their oil generation characteristics, including the compositional evolution in the extracts from the pyrolysed samples. The organic material in the mudstones is mainly composed of fluorescing amorphous organic matter, liptodetrinite and alginite with Botryococcus‐morphology (corresponding to Type I kerogen). The mudstones contain up to 19.6 wt.% TOC and Hydrogen Index values range from 436–572 mg HC/g TOC. From a pyrolysis S₂ versus TOC plot it is estimated that about 55% of the mudstones’TOC can be pyrolised into hydrocarbons; the plot also suggests that a minimum content of only 0.5 wt.% TOC is required to saturate the source rock to the expulsion threshold. Humic coals and coaly mudstones have Hydrogen Index values of 318–409 mg HC/g TOC. They are dominated by huminite (Type III kerogen) and generally contain a significant proportion of terrestrial‐derived liptodetrinite. Upon artificial maturation by hydrous pyrolysis, the coals generate significant quantities of saturated hydrocarbons, which are probably expelled at or before a maturity corresponding to a vitrinite reflectance of 0.97%R₀. This is earlier than previously indicated from Dong Ho Formation coals with a lower source potential. The composition of a newly discovered oil (well B10‐STB‐1x) at the NE margin of the Song Hong Basin is consistent with contributions from both source rocks, and is encouraging for the prospectivity of offshore half‐grabens in the Song Hong Basin.     

Source Rock Characteristics,Organic Maturity,and Hydrocarbon Potential of the Lower Paleozoic Sequences in the Taurus Belt of Turkey

Abstract

Like elsewhere in the world, Lower Paleozoic (Cambrian-Ordovician-Silurian) formations in Turkey are also exposed in limited areas. Lower Paleozoic sequences are exposed at various parts of the Taurus belt in southern Turkey. In this study, organic matter content, type, and maturity of organic matter and their hydrocarbon potential were investigated. In addition, the Lower Paleozoic is very restricted with respect to species and their diversity. Therefore, it is very important to investigate type and content of organic matter within the Lower Paleozoic sediments. In general, total organic carbon (TOC) values of Lower Paleozoic sequences are extremely low. TOC could not be measured in Cambrian, Ovac?k, and Çaltepe limestones. Shales in the Emirgazi region have very low TOC values. Ordovician and Silurian units also have low TOC values. Total organic carbon in these sequences is residual carbon. In the S ₂-TOK kerogen diagram, all organic materials are plotted in the Type III kerogen field. All samples were composed dominantly of residual organic matter and lesser amounts of Type III kerogen. According to T _max values, the Cambrian, Ordovician, and Silurian formations are over maturity character. In addition, these sequences have very low S ₁, S ₂, and HI values.     

Source rock evaluation of some upper and lower Cretaceous sequences,West Beni Suef Concession,Western Desert,Egypt

West Beni Suef Concession is located at the western part of Beni Suef Basin which is a relatively under-explored basin and lies about 150 km south of Cairo. The major goal of this study is to evaluate the source rock by using different techniques as Rock-Eval pyrolysis, Vitrinite reflectance (%Ro), and well log data of some Cretaceous sequences including Abu Roash (E, F and G members), Kharita and Betty formations. The BasinMod 1D program is used in this study to construct the burial history and calculate the levels of thermal maturity of the Fayoum-1X well based on calibration of measured %Ro and T_max against calculated %Ro model. The calculated Total Organic Carbon (TOC) content from well log data compared with the measured TOC from the Rock-Eval pyrolysis in Fayoum-1X well is shown to match against the shale source rock but gives high values against the limestone source rock. For that, a new model is derived from well log data to calculate accurately the TOC content against the limestone source rock in the study area. The organic matter existing in Abu Roash (F member) is fair to excellent and capable of generating a significant amount of hydrocarbons (oil prone) produced from (mixed type I/II) kerogen. The generation potential of kerogen in Abu Roash (E and G members) and Betty formations is ranging from poor to fair, and generating hydrocarbons of oil and gas prone (mixed type II/III) kerogen. Eventually, kerogen (type III) of Kharita Formation has poor to very good generation potential and mainly produces gas. Thermal maturation of the measured %Ro, calculated %Ro model, T_max and Production index (PI) indicates that Abu Roash (F member) exciting in the onset of oil generation, whereas Abu Roash (E and G members), Kharita and Betty formations entered the peak of oil generation.     

SOURCE ROCK EVALUATION OF COALS FROM THE LOWER MAASTRICHTIAN MAMU FORMATION, SE NIGERIA

The Lower Maastrichtian Mamu Formation in the Anambra Basin (SE Nigeria) consists of a cyclic succession of coals, carbonaceous shales, silty shales and siltstones interpreted as deltaic deposits. Sub‐bituminous coals within this formation are distributed in a north‐south trending belt from Enugu‐Onyeama to Okaba in the north of the basin. Maceral analyses showed that the coals are dominated by huminite with lesser amounts of liptinite and inertinite. Despite high liptinite contents in parts of the coals, an HI versus T_max diagram and atomic H/C ratios of 0.80‐0.90 and O/C ratios of 0.11‐0.17 classify the organic matter in the coals as Type III kerogen. Vitrinite reflectance values (%R_r) of 0.44 to 0.6 and T_max values between 417 and 429°C indicate that the coals are thermally immature to marginally mature with respect to petroleum generation. Hydrogen Index (HI) values for the studied samples range from 203 to 266 mg HC/g TOC and S₁+S₂ yields range from 141.12 to 199.28 mg HC/ g rock, suggesting that the coals have gas and oil‐generating potential. Ruthenium tetroxide catalyzed oxidation (RTCO) of two coal samples confirms the oil‐generating potential as the coal matrix contains a considerable proportion of long‐chain aliphatics in the range C_19‐35. Stepwise artificial maturation by hydrous pyrolysis from 270°C to 345°C of two coal samples (from Onyeama, HI=247 mg HC/g TOC; and Owukpa, HI=206 mg HC/g TOC) indicate a significant increase in the S₁ yields and Production Index with a corresponding decrease in HI during maturation. The Bitumen Index (BI) also increases, but for the Owukpa coal it appears to stabilize at a T_max of 452‐454°C, while for the Onyeama coal it decreases at a T_max of 453°C. The decrease in BI suggests efficient oil expulsion at an approximate vitrinite reflectance of ～I%R_r. The stabilization/decrease in BI is contemporaneous with a significant change in the composition of the asphaltene‐free coal extracts, which pass from a dominance of polar compounds (～77‐84%) to an increasing proportion of saturated hydrocarbons, which at >330°C constitute around 30% of the extract composition. Also, the n‐alkanes change from a bimodal to light‐end skewed distribution corresponding to early mature to mature terrestrially sourced oil. Based on the obtained results, it is concluded that the coals in the Mamu Formation have the capability to generate and expel liquid hydrocarbons given sufficient maturity, and may have generated a currently unknown volume of liquid hydrocarbons and gases as part of an active Cretaceous petroleum system.     

确定烃源岩有效排烃总有机碳阈值的方法及应用

针对油气地质学中排烃源岩难以识别的问题,依据生排烃原理,利用常规烃源岩有机碳和热解（Rock-Eval）分析测试参数,建立了判别排烃源岩的实用方法。该方法主要基于生烃量参数[I_HC=S₁/w（TOC）]和沥青转化率[w（A）/w（TOC）],判别排烃源岩的总有机碳阈值,高于该值的烃源岩即为排烃源岩。根据分析测试资料,对准噶尔盆地和三塘湖盆地二叠系芦草沟组、酒泉盆地营尔凹陷和青西凹陷白垩系下沟组以及鄂尔多斯盆地上三叠统延长组长7段的排烃源岩进行判别,判别效果较好,应用该方法时要求烃源岩的母质特征与热演化程度接近。由于气态烃易散失,所以采用的参数主要反映烃源岩中生成的液态烃量。该方法对于油源岩的判别更为有效。      

SOURCE ROCK POTENTIAL OF EOCENE, PALEOCENE AND JURASSIC DEPOSITS IN THE SUBSURFACE OF THE POTWAR BASIN, NORTHERN PAKISTAN

The hydrocarbon source rock potential of five formations in the Potwar Basin of northern Pakistan – the Sakesar Formation (Eocene); the Patala, Lockhart and Dhak-Pass Formations (Paleocene); and the Datta Formation (Jurassic) – was investigated using Rock-Eval pyrolysis and total organic carbon (TOC) measurement. Samples were obtained from three producing wells referred to as A, B and C. In well A, the upper ca. 100 m of the Eocene Sakesar Formation contained abundant Type III gas-prone organic matter (OM) and the interval appeared to be within the hydrocarbon generation window. The underlying part of the Sakesar Formation contained mostly weathered and immature OM with little hydrocarbon potential. The Sakesar Formation passes down into the Paleocene Patala Formation. T_max was variable because of facies variations which were also reflected in variations in hydrogen index (HI), TOC and S2/S3 values. In well A, the middle portion of the Patala Formation had sufficient maturity (T_max 430 to 444°C) and organic richness to act as a minor source for gas. The underlying Lockhart Formation in general contained little OM, although basal sediments showed a major contribution of Type II/III OM and were sufficiently mature for hydrocarbon generation. In Well B, rocks in the upper 120 m of the Paleocene Patala Formation contained little OM. However, some Type II/III OM was present at the base of the formation, although these sediments were not sufficiently mature for oil generation. The Dhak Pass Formation was in general thermally immature and contained minor amounts of gas-prone OM. In Well C, the Jurassic Datta Formation contained oil-prone OM. T_max data indicated that the formation was marginally mature despite sample depths of > 5000 m. The lack of increase in T_max with depth was attributed to low heat flows during burial. However, burial to depths of more than 5000 m resulted in the generation of moderate quantities of oil from this formation.     

RELATIONSHIPS BETWEEN HYDROCARBON GENERATION, COAL TYPE AND RANK FOR MIDDLE EOCENE COALS, BULLER COALFIELD, NEW ZEALAND

The Buller Coalfield in the northern portion of the Paparoa Trough (NW South Island, New Zealand) contains a middle Eocene bituminous coal-bearing succession that exhibits marked variations in both coal rank and type. The across-basin rank changes result from differential late Palaeogene subsidence of the Paparoa Trough and subsequent inversion. Superimposed upon coalification trends are down-seam variations in coal type, evidenced by isorank variation in conventional chemical parameters. These type variations are not a consequence of changes in maceral group proportions, which are dominated by vitrinite. Forty-eight coal samples from fifteen drillholes through the Brunner Coal Measures have been examined for vitrinite reflectance, proximate analysis, specific energy, and sulphur content. Total Organic Carbon (TOC), Rock-Eval properties and the bulk composition of the bitumen were also determined. All the coals analysed lie within the high volatile bituminous B to medium volatile bituminous coalification stages. Variation in analytical properties within this suite, and more specifically within serial samples, provides insights into the nature of the organic matter comprising the coals. While TOC varies systematically with ash content, reflecting proximity of the depositional mires to fluvial systems, values increase with rank (68–86% ash free). The Hydrogen Index (HI) decreases from 334 to 190 mg hydrocarbons/g TOC over a range of 429 to 470 d?C Tmax, analogous to the volatile matter content and vitrinite reflectance, respectively. The more perhydrous coal samples at a given rank are characterised by depressed Tmax/vitrinite reflectance and elevated Hi/volatile matter contents. Bitumen and sulphur contents are not the primary control onperhydrous characteristics. The bitumen content crudely corresponds to the S1 peak plus the initial portion of the S2 peak liberated under low temperatures during Rock-Eval pyrolysis; however, the bulk of the generative potential is associated with the residual kerogen fraction. Suggate (S) Rank and maximum palaeotemperature appear to be the best indicators of coal rank. A period of significant hydrocarbon generation and release begins at Tmax～440d?C for the Buller coals. The main oil “window” is defined by the interval 440–455d?C Tmax or 0.8–1.1% vitrinite reflectance (Ro_max), and by correlation to maximum palaeo-temperatures, 125–155d?C. This is further substantiated by mass balance considerations, which indicate that hydrocarbon generation (Petroleum Generation Index (PG1) > 0.1) was occurring in the coals at a maturity level of O. 7–0.9 % Ro_max (Tmax 440–444 d?C) with an increase in PGI between ～0.9 and 1.1% Ro_max (～Tmax 445–455 d?C). Between PGI 0.1 and 0.4, the expulsion efficiency rapidly increased, presumably due to generation and expulsion of the bulk of the oil.     

HYDROCARBON POTENTIAL OF THE LATE CRETACEOUS GONGILA AND FIKA FORMATIONS,BORNU (CHAD) BASIN,NE NIGERIA

The hydrocarbon potential of possible shale source rocks from the Late Cretaceous Gongila and Fika Formations of the Chad Basin of NE Nigeria is evaluated using an integration of organic geochemistry and palynofacies observations. Total organic carbon (TOC) values for about 170 cutting samples range between 0.5% and 1.5% and Rock-Eval hydrogen indices (HI) are below 100 mgHC/gTOC, suggesting that the shales are organically lean and contain Type III/IV kerogen. Amorphous organic matter (AOM) dominates the kerogen assemblage (typically >80%) although its fluorescence does not show a significant correlation with measured HI. Atomic H/C ratios of a subset of the samples indicate higher quality oil- to gas-prone organic matter (Type II-III kerogens) and exhibit a significant correlation with the fluorescence of AOM (r²= 0.86). Rock-Eval T_max calibrated against AOM fluorescence, biomarker and aromatic hydrocarbon maturity data suggests a transition from immature (<435°C) to mature (>435°C) in the Fika Formation and mature to post-mature (>470°C) in the Gongila Formation. The low TOC values in most of the shales samples limit their overall source rock potential. The immature to early mature upper part of the Fika Formation, in which about 10% of the samples have TOC values greater than 2.0%, has the best oil generating potential. Oil would have been generated if such intervals had become thermally mature. On the basis of the samples studied here, the basin has potential for mostly gaseous rather than liquid hydrocarbons.     

SOURCE ROCK POTENTIAL AND DEPOSITIONAL ENVIRONMENT OF MIDDLE – UPPER JURASSIC SEDIMENTARY ROCKS,BLUE NILE BASIN,ETHIOPIA

This study investigates the hydrocarbon generation potential, kerogen quality, thermal maturity and depositional environment of Middle – Upper Jurassic sedimentary rocks in the Blue Nile Basin, Ethiopia, using organic petrography, Rock-Eval pyrolysis and molecular organic geochemistry. Thirty-seven outcrop samples were analysed for their total organic carbon (TOC) and inorganic carbon (TIC) contents. The samples came from a Toarcian – Bathonian transitional glauconitic shale-mudstone unit, the overlying Upper Bathonian Gohatsion Formation, and the Lower Callovian – Upper Tithonian Antalo Limestone Formation. Thirteen samples with sufficient TOC contents for further analysis of the organic matter, eight from the Antalo Limestone Formation and five from the glauconitic shale-mudstone unit, were selected and analysed using Rock-Eval pyrolysis. Vitrinite reflectance (VR_r) was measured on random particles, and qualitative maceral analysis was performed under normal incident and UV light. Nine samples were selected for molecular organic-geochemical analyses. All the samples originating from the Gohatsion Formation showed TOC values which were too low for further analyses of the organic matter. The TOC contents of shales and limestones from the Antalo Limestone Formation and and of shales from the glauconitic shale-mudstone unit were 3.43-6.43% (average 4.85%) and 0.76-3.15% (average 1.72%), respectively, and two coaly shale samples from the latter unit have average TOC values of 18.48%. HI values are very high for shales in the Antalo Limestone Formation (average 575 mg HC/g TOC) but lower for the shales in the glauconitic shale-mudstone unit. The vitrinite reflectance of shales from the Antalo Limestone Formation ranged between 0.21% and 0.47%; coaly shales from the glauconitic shale-mudstone unit have VR_r% of between 0.29% and 0.35%. Pr/Ph ratios for samples of the Antalo Limestone Formation shales ranged from 0.8 to 1.1, indicating anoxic to suboxic depositional conditions; while shales in the glauconitic shale-mudstone unit show higher values of up to 4.9. In terms of organic petrography, the Antalo Limestone Formation samples are dominated by finely dispersed liptinite particles and alginite; the organic material in the glauconitic shale-mudstone unit is of higher land plant origin, with abundant vitrinite and inertinite. Sterane and hopane biomarker ratios suggest an anoxic/suboxic depositional environment for the Antalo Limestone Formation shales and limestones. These values together with Rock-Eval Tmax (average 414 °C), the high ratio of pristane and phytane over the n-alkanes C₁₇ and C₁₈, and hopane biomarker ratios indicate that the Middle – Upper Jurassic succession is of low thermal maturity in the central parts of the Blue Nile Basin. The Antalo Limestone Formation shales have a high petroleum generation potential, making them a viable target for future exploration activities.