Poor Source Rock Research Articles

Geochemistry and depositional conditions of the carbonate-bearing lacustrine source rocks: A case study from the Early Permian Fengcheng Formation of Well FN7 in the northwestern Junggar Basin

Measurements of TOC, Rock-Eval pyrolysis, carbon isotope composition, solvent extract, extract fractionation, and the gas chromatography-mass spectrum (GC-MS) of the saturated fraction were conducted on the Lower Permian Fengcheng Formation carbonate-bearing shales and argillaceous dolomites of Well FN7 in the northwestern Junggar Basin to understand the geochemistry and depositional environmental evolution of the carbonate-bearing lacustrine source rocks. The results indicate that the Fengcheng Formation carbonate-bearing shales are fair to good source rocks with Type II kerogen for generating oil and minor gas, and the argillaceous dolomites are poor source rocks. The thermal mature shales contain more residually generated hydrocarbon, whereas the argillaceous dolomites contain more migrated hydrocarbon. This property is favorable for shale oil or tight oil accumulation in the Fengcheng Formation. Biomarker analyses indicate that the Fengcheng Formation source rocks were formed in the anoxic reducing lacustrine depositional environment with a stratified water column and high salinity. The source rock organic matter has major aquatic phytoplankton and algae input and less terrestrial organic matter input. During the Fengcheng Formation period, oxidation had a weak increasing tendency and salinity had a weak decreasing tendency from the early to late periods under the background of a reducing environment. Except for poor source rocks in upper and lower parts, the good source rocks are primarily in the middle part of the Fengcheng Formation.

Jurassic source rocks in the Vienna Basin (Austria): Assessment of conventional and unconventional petroleum potential

The Upper Jurassic marlstones (Mikulov Fm.) and marly limestones (Falkenstein Fm.) are the main source rocks for conventional hydrocarbons in the Vienna Basin in Austria. In addition, the Mikulov Formation has been considered a potential shale gas play. In this paper, organic geochemical, petrographical and mineralogical data from both formations in borehole Staatz 1 are used to determine the source potential and its vertical variability. Additional samples from other boreholes are used to evaluate lateral trends. Deltaic sediments (Lower Quarzarenite Member) and prodelta shales (Lower Shale Member) of the Middle Jurassic Gresten Formation have been discussed as secondary sources for hydrocarbons in the Vienna Basin area and are therefore included in the present study.The Falkenstein and Mikulov formations in Staatz 1 contain up to 2.5 wt%TOC. The organic matter is dominated by algal material. Nevertheless, HI values are relative low (<400 mgHC/gTOC), a result of organic matter degradation in a dysoxic environment. Both formations hold a fair to good petroleum potential. Because of its great thickness (∼1500 m), the source potential index of the Upper Jurrasic interval is high (7.5 tHC/m2). Within the oil window, the Falkenstein and Mikulov formations will produce paraffinic-naphtenic-aromatic low wax oil with low sulfur content. Whereas vertical variations are minor, limited data from the deep overmature samples suggest that original TOC contents may have increased basinwards. Based on TOC contents (typically <2.0 wt%) and the very deep position of the maturity cut-off values for shale oil/gas production (∼4000 and 5000 m, respectively), the potential for economic recovery of unconventional petroleum is limited. The Lower Quarzarenite Member of the Middle Jurassic Gresten Formation hosts a moderate oil potential, while the Lower Shale Member is are poor source rock.

Source rock characteristics of the Early Cretaceous Garau and Gadvan formations in the western Zagros Basin\u2013southwest Iran

Cretaceous source succession in the Zagros Basin comprises the Garau, Gadvan, and Kazhdumi formations, which have probably generated most of the oil and associated gas in the region. In the following study, the generation potential as well as maturity, molecular, and isotopic characteristics of the Early Cretaceous source rocks (Garau and Gadvan formations) in southwest Iran were investigated. One hundred and forty core and cutting samples of Early Cretaceous sediments were obtained from 24 wells in 12 oil fields from the northern Dezful Embayment and Abadan plain. Geochemical measurements such as Rock–Eval pyrolysis, vitrinite reflectance, GC, GC–MS, and isotopic studies were conducted on selected samples. The results have shown that the Gadvan Formation, with an average TOC of 0.65 wt% and HI values of 122 mgHC/g TOC, can be classified as poor source rock, while the Garau Formation, with TOC and HI values of up to 5.72 wt% and 413 mgHC/g TOC, respectively, can be considered as having good to excellent source potential. Kerogen in the Gadvan Formation belongs to Type III/II, while kerogen in the Garau Formation belongs to Type II. Samples from the Gadvan Formation are at the beginning of oil generation, while the current maturity of the Garau samples is already in the peak oil generation stage. Maturity in the studied samples increases eastward toward the Dezful Embayment. GC, GC–MS and isotopic values for the Gadvan Formation indicate high land plant contribution, low maturity, and oxic to sub-oxic depositional environment of the organic matter. In contrast, the Garau Formation shows an advanced level of maturity and marine depositional environment. Considering the results of this study, the Garau Formation, with excellent production potential and a high level of maturity, can be regarded as a source of a huge amount of oil and gas in the region.

Lacustrine massive mudrock in the Eocene Jiyang Depression, Bohai Bay Basin, China: Nature, origin and significance

Massive mudrock refers to mudrock with internally homogeneous characteristics and an absence of laminae. Previous studies were primarily conducted in the marine environment, while notably few studies have investigated lacustrine massive mudrock. Based on core observation in the lacustrine environment of the Jiyang Depression, Bohai Bay Basin, China, massive mudrock is a common deep water fine-grained sedimentary rock. There are two types of massive mudrock. Both types are sharply delineated at the bottom and top contacts, abundant in angular terrigenous debris, and associated with oxygen-rich (higher than 2 ml O2/L H2O) but lower water salinities in comparison to adjacent black shales. In addition, type 1 is laterally isolated and contains abundant sand injections and contorted layers formed in the depositional process, but type 2 exactly distributes in the distal part of deep water gravity-driven sandstone units, and shows scoured bases, high-angle mineral crytsals, and fining-upward trend. It is suggested that type 1 is a muddy mass transport deposit (MMTD) formed by slide, slump, and/or debris flow, and type 2 is a turbiditic mudrock deposited by settling from dilute turbidity currents. A warm and humid climate and high subsidence rate are two main triggering events. Because of its mass movement nature, MMTD preserves the mineralogic composition and organic matter characteristics of the source sediment. By contrast, dilute turbidity currents are able to greatly entrain biochemically-formed micrite and planktonic organisms from the water column, and deposit them in the turbiditic mudrock. Because of their different ability to deposit organic matter, MMTD have poor or fair source rock potential, but the turbiditic mudrock is able to be a potentially effective source rock. The minerals in the massive mudrock are disorganized and chaotic, which cause fractures to develop in various directions, thereby, enhancing the vertical migration of oil and gas molecules to horizontal wellbore in shale reservoir exploitation.

Mineralogy and source rock evaluation of the marine Oligo-Miocene sediments in some wells in the Nile Delta and North Sinai, Egypt

This paper aims to study the mineralogical composition and determine the petroleum potential of source rocks of the Oligocene-Miocene sequence in the Nile Delta and North Sinai districts. The studied interval in the five wells can be divided into five rock units arranged from the top to base; Qawasim, Sidi Salem, Kareem, Rudeis, and Qantara formations.The bulk rock mineralogy of the samples was investigated using X-Ray Diffraction technique (XRD). The results showed that the sediments of the Nile Delta area are characterized by the abundance of quartz and kaolinite with subordinate amounts of feldspars, calcite, gypsum, dolomite, and muscovite. On the other hand, the data of the bulk rock analysis at the North Sinai wells showed that kaolinite, quartz, feldspar and calcite are the main constituents associated with minor amounts of dolomite, gypsum, mica, zeolite, and ankerite.Based on the organic geochemical investigations (TOC and Rock-Eval pyrolysis analyses), all studied formations in both areas are thermally immature but in the Nile delta area, Qawasim, Sidi Salem and Qantara formations (El-Temsah-2 Well) are organically-rich and have a good petroleum potential (kerogen Type II–oil-prone), while Rudeis Formation is a poor petroleum potential source rock (kerogen Type III–gas-prone). In the North Sinai area, Qantara Formation has a poor petroleum potential (kerogen Type III–gas-prone) and Sidi Salem Formation (Bardawil-1 Well) is a good petroleum potential source rock (kerogen Type II–oil-prone).

Multivariate geochemical and statistical methods applied to assessment of organic matter potentiality and its correlation with hydrocarbon maturity parameters (Case study: Safir-1x well, North Western Desert, Egypt)

The TOC-Rock–Eval pyrolysis and vitrinite reflectance measurements for “15” shale rock samples, as well as, multivariate statistical analysis are discussed to investigate hydrocarbon, source rock characteristics, correlation between the assessed parameters (S1, S2, HI, S1+S2, QI, BI, PI, TOC) and the impact of changes in the Tmax and Ro% on the assessed parameters in Safir exploratory-1x well in Safir oilfield. The geochemical analysis indicated that the Bahariya Formation is considered to be a poor source rock for oil generation with a low degree of thermal maturation in comparison with the Alam El Bueib and Khatatba Formations. However, Alam El Bueib is found to be a good source rock for oil generation with slightly higher thermal maturation. Interestingly, Khatatba Formation lies within the oil and gas generation window and shows an excellent source rock potential. Based on statistical findings of cluster and factor analysis, the source rocks in the study area are classified into two types corresponding to two different clusters. Cluster I includes Alam El Bueib and characterized by kerogen type II and II/III whereas, cluster II, characterized by kerogen type III, is subdivided into two subgroups (IIa and IIb) and represents Bahariya and Khatatba source rocks. Nonparametric tests (K-independent samples) between the dataset of 15 samples confirm that the distribution of values from respective parameters exhibits significant difference (P<0.05) except for PI and BI. On the other hand, the nonparametric tests (2-independent samples) showed that there is no significant difference (P>0.05) in the distribution of HI and QI values indicating that both HI and QI values remain constant with increasing thermal maturity. Unlike TOC and HI, Pearson’s and linear regression analysis indicated a significant correlation between TOC and S2. Nevertheless, two different trends were observed between S1 and S2. Moreover, the Ro% and Tmax were found to be positively correlated. Interestingly, our study showed no significant correlation between HI, QI, BI and thermal maturity (Ro% and Tmax), while, a good correlation between TOC, S2 and thermal maturity was observed.

Strike-slip superimposed Qaidam Basin and its control on oil and gas accumulation, NW China

Based on detailed field survey in the western Qaidam Basin, combined with petroleum exploration practices in recent years, this study suggests that the Qaidam Basin is a strike-slip superimposed basin jointly controlled by the left-lateral strike-slip Altyn Tagh and East Kunlun faults. The Altyn Tagh fault acts as the major controlling boundary, while the East Kunlun fault only controls the local evolution of the southern edge of the basin. To the east, the northern Qaidam-Qilian Shan thrust-fold belt passively accommodates the northeastward displacement along the Altyn Tagh fault through NE-SW directed shortening. In the India-Asia collision background, the left-lateral strike-slip faulting along the Altyn Tagh fault initiated from the early Eocene, forcing the Qaidam Basin to move northeastward, causing the thrust and slip deformation of the NW-SE faults in northern Qaidam margin-Qilian Mountain area, and the deposition of the Cenozoic since the Paleogene Lulehe Formation. During the Paleogene, the northern Qaidam Basin developed coarse-grained sediments like that in a foreland basin, forming poor quality source rocks; while the southwestern Qaidam Basin was an extensional sag basin where good quality source rocks deposited. By the early Miocene, left-lateral faulting along the Kunlun fault became active, leading to the formation of a series of en-echelon faults (e.g. the Kunbei fault, the Arlar fault and the Hongliuquan fault). These faults gradually migrated northward, their kinematics changing from left-lateral strike-slip motion to NE-SW transpression. Strike-slip-related structures controlled by those faults (e.g. the Yingxiongling structure) are ideal places for oil and gas accumulation from Paleogene source rocks. To sum up, the Qaidam Basin is a strike-slip superimposed basin jointly controlled by the left-lateral strike-slip Altyn Tagh and East Kunlun faults. The temporal and spatial superimposition of these two strike-slip faults during the Cenozoic controlled the evolution of the basin as well as the oil and gas accumulation.

Shale gas resource assessment in the Merlinleigh Sub-basin, Carnarvon Basin

The recent shale gas developments in the US have encouraged exploration for shale gas resource in WA. In the largely unexplored Carnarvon Basin, the Merlinleigh Sub-basin is predominately of Permian strata and has been shown to contain high-quality gas-prone source rocks from geochemical data. Three main potential shale layers, the Gneudna Formation, Wooramel Group and the Byro Group, were identified based on the shale ranking parameters. Geochemical data was collected and analysed for the type of kerogen, total organic content (TOC), generation potential and thermal maturity. These parameters enabled a gas-in-place resource estimation to be made for each of the formations. The TOC data from various wells were validated by using petrophysical logs and the ΔlogR method. In comparison with the geochemical data, both values produced a good match, validating both sets of data. The three layers were ranked according to their geochemical parameters and any petrophysical or geomechanical characteristics. It was identified that the Wooramel Group contains the best quality source rocks, followed by the Byro Group. The Gneudna Formation was found to have poor quality source rocks. The Monte Carlo method by Crystal Ball was selected to estimate the probabilistic resources of these three layers. According to the P50 estimations, the Byro Group, Wooramel Group and the Gneudna Formation contained resources of 51.6 tcf, 40.1 tcf and 1.4 tcf, respectively.

Shale gas resource assessment in the Merlinleigh Sub-basin, Carnarvon Basin

The recent shale gas developments in the US have encouraged exploration for shale gas resource in WA. In the largely unexplored Carnarvon Basin, the Merlinleigh Sub-basin is predominately of Permian strata and has been shown to contain high-quality gas-prone source rocks from geochemical data. Three main potential shale layers, the Gneudna Formation, Wooramel Group and the Byro Group, were identified based on the shale ranking parameters. Geochemical data was collected and analysed for the type of kerogen, total organic content (TOC), generation potential and thermal maturity. These parameters enabled a gas-in-place resource estimation to be made for each of the formations. The TOC data from various wells were validated by using petrophysical logs and the ΔlogR method. In comparison with the geochemical data, both values produced a good match, validating both sets of data. The three layers were ranked according to their geochemical parameters and any petrophysical or geomechanical characteristics. It was identified that the Wooramel Group contains the best quality source rocks, followed by the Byro Group. The Gneudna Formation was found to have poor quality source rocks. The Monte Carlo method by Crystal Ball was selected to estimate the probabilistic resources of these three layers. According to the P50 estimations, the Byro Group, Wooramel Group and the Gneudna Formation contained resources of 51.6 tcf, 40.1 tcf and 1.4 tcf, respectively.

Organic petrographic characteristics of the Crocker Formation, NW Sabah, Malaysia

The deep marine Crocker Formation in NW Sabah, Malaysia has been well studied in terms of sedimentology, stratigraphy and structural geology. However, not much is known about its potential as a petroleum source rock. This study partly addresses this subject by means of petrographic analysis to characterise the Crocker sediments in terms of its organic matter content and thermal maturity. Crushed rock samples mounted in resin blocks were examined under reflected white and ultraviolet light. Petrographic analysis indicates that the Crocker Formation samples have low phytoclast content (<2%). The mostly indigenous phytoclasts (microscopic plant fragments) can be divided into 4 groups based on their reflectance values; vitrinite with dark inclusions (lowest reflectance), vitrinite, oxidised vitrinite and inertinite (highest reflectance). These phytoclast groups exhibit a reflectance profile of 0.6, 0.8, 1.0 and 1.2%Ro respectively. Such an approach (measuring the reflectance of different phytoclast groups) can aid the petrographer to evaluate and validate vitrinite reflectance measurements in samples such as the Crocker that has a variable phytoclast assemblage. The average vitrinite reflectance is 0.82%Ro, which indicates that the Crocker sediments analysed were once buried to a depth of 4.1 km on average. Although its thermal maturity is within the oil generation window at present day, the Crocker Formation is considered a poor petroleum source rock because it is poor in phytoclast content (<2%) and appears to lack oil-prone liptinitic macerals. However, favourable source rock units could exist within the Crocker in the form of slump or mass- transport units, if the organic or phytoclast content is high enough and oil-prone organic matter is sufficiently present. Further geochemical analysis and regional data need to be incorporated for a more comprehensive analysis and assessment of the Crocker as a petroleum source rock and/or an analogue for subsurface geological units.

Geochemical Evaluation of Campanian Sirte Shale Source Rock, Arshad Area, Sirt Basin, Libya

The present geochemical study deals with evaluation of Sirte Shale (Campanian) source rock in Arshad area which is located in the central Sirt Basin in north central Libya. Sirte Formation is composed mainly of shale, sandy shale, being partially sandy and calcareous facies indicating presence of possible source rocks. It contains enough amount of organic matter (>0.5 wt. %) to generate and expel hydrocarbons under suitable thermal maturity level in the area. The recorded kerogens belong to types III and IV. The pyrolysis results indicate deficient of hydrogen content and poor potential source rocks in all samples. The HI values of the analyzed samples prove predominance of type III (gas-prone) and type IV (non-hydrocarbon potential) kerogens. In general, pyrolysis results and derived parameters indicate poor generating potential for the Sirte Formation (Campanian) in the area and mature kerogen in the oil-window zone. The thermal burial history curves of selected wells in Arshad area indicate that Sirte Shale had been buried in the top peak oil generation or oil window (Late maturity, Ro: 0.9-1.35%) since 4 to 13.5 M. Y. ago at depth range 9100'-9600'. Time of hydrocarbon expulsion has started in the area since 15 M. Y. nearly during the Middle Miocene time (Serravallian age). In Sirt Basin, oil has migrated from the Campanian Sirte Shale source rock which has reached the oil-window at western flank of the South Ajdabiya Trough to the Mesozoic and Paleozoic reservoirs in Zaltan Platform and to the Upper Cretaceous Arshad sandstone reservoir in Arshad oil field as well. The migrated hydrocarbons most likely are entrapped in the structural closures of the different structural traps (folds and fault-blocks) in Zaltan Platform. Likewise, westward up-dip direction of gas migration took place from the Campanian Sirte Shale source rock as buried in the gas-window in the deep Wadayet (NW Ajdabiya Trough) to the Mesozoic and

Sedimentary organic matter and source rock potential of the Paleocene Aaliji Formation in Qumar Oil Field, NE Iraq

The organic matter content of the Paleocene Aaliji Formation has been studied from the Qm-1 well in the Qumar Oil Field, NE Iraq. A palynofacies analysis revealed the obvious domination of amorphous organic matter (AOM) in the samples studied in addition to the different ratios of palynomorphs, phytoclasts and opaque organic material. The deposition of the various percentages of organic matter components and types of palynomorphs appear to have occurred in a proximal suboxic–anoxic basinal environment. The samples analysed showed relatively low percentages of total organic carbon, indicating a generally poor source rock. The thermal alteration index for the palynomorphs (dinoflagellates) observed and identified ranged between 2, 2+ and 3−, indicating an immature to early stage of maturity for the section studied. No clear differentiation between the stages of maturity within the section was identified. The reflectance measured for a few vitrinite particles at a depth of 2,900 m showed uncertainly of 0.46 % Ro, indicating a still thermally immature stage. The values obtained from pyrolysis analysis also supported the formation being in the early stages of maturity, i.e. an immature condition, with T max values between 416 and 435 °C. The quality of the organic matter examined and analysed appeared to be mostly type III gas-prone kerogen, as discerned from the hydrogen index, oxygen index and other pyrolysis parameters. The parameters obtained and calculated from gas chromatography analysis performed on a sample at a depth of 2,900 m found marginally mature marine source organic matter.

Accumulation of water-soluble gas by degasification: One of important mechanisms of large gas accumulations in the Xujiahe Formation, Sichuan Basin

Abstract In recent years, a lot of lithologic/structural-lithologic gas reservoirs were found in the Xujiahe Formation, Upper Triassic, Sichuan Basin, and most of the reservoirs contain water. We have carried out the study of the properties and characteristics of the fluid, and found the changes of natural gas components and carbon isotope which confirm the accumulation of water-soluble gas with degasification, namely, such accumulation far away from gas source features high methane, high drying factor, high ratio of isoalkane to normal paraffin hydrocarbons, and heavy carbon isotope in methane and ethane. Accumulations of water-soluble gas with degasification with reduction of pressure & temperature for strata uplift and with reduction of pressure & temperature for lateral migration of soluble gas along layer are the main forming mechanisms. The strong ground uplift, fluid decompression and reduction of temperature, local concentration of water salinity, and a wealth of water-soluble gas resources are the favorable conditions for the accumulation. We conclude that the accumulation of water-soluble gas with degasification is not only one of the important mechanisms of development of large lithologic gas reservoirs and large gas accumulations in Central Sichuan, but also a key reason for poor source rocks in the Xu1 Member but large gas accumulation in the Xu2 Member in the Hechuan-Anyue area.

HYDROCARBON POTENTIAL OF MIDDLE JURASSIC COALY AND LACUSTRINE AND UPPER JURASSIC – LOWERMOST CRETACEOUS MARINE SOURCE ROCKS IN THE SØGNE BASIN, NORTH SEA

The Søgne Basin in the Danish‐Norwegian Central Graben is unique in the North Sea because it has been proven to contain commercial volumes of hydrocarbons derived only from Middle Jurassic coaly source rocks. Exploration here relies on the identification of good quality, mature Middle Jurassic coaly and lacustrine source rocks and Upper Jurassic – lowermost Cretaceous marine source rocks. The present study examines source rock data from almost 900 Middle Jurassic and Upper Jurassic – lowermost Cretaceous samples from 21 wells together with 286 vitrinite reflectance data from 14 wells. The kerogen composition and kinetics for bulk petroleum formation of three Middle Jurassic lacustrine samples were also determined.Differences in kerogen composition between the coaly and marine source rocks result in two principal oil windows: (i) the effective oil window for Middle Jurassic coaly strata, located at ∼3800 m and spanning at least ∼650 m; and (ii) the oil window for Upper Jurassic – lowermost Cretaceous marine mudstones, located at ∼3250 m and spanning ∼650 m. A possible third oil window may relate to Middle Jurassic lacustrine deposits. Middle Jurassic coaly strata are thermally mature in the southern part of the Søgne Basin and probably also in the north, whereas they are largely immature in the central part of the basin. HImax values of the Middle Jurassic coals range from ∼150–280 mg HC/g TOC indicating that they are gas‐prone to gas/oil‐prone. The overall source rock quality of the Middle Jurassic coaly rocks is fair to good, although a relatively large number of the samples are of poor source rock quality.At the present day, Middle Jurassic oil‐prone or gas/oil‐prone rocks occur in the southern part of the basin and possibly in a narrow zone in the northern part. In the remainder of the basin, these deposits are considered to be gas‐prone or are absent. Wells in the northernmost part of the Søgne Basin / southernmost Steinbit Terrace encountered Middle Jurassic organic–rich lacustrine mudstones with sapropelic kerogen, high HI values reaching 770 mg HC/g TOC and Ea‐distributions characterised by a single dominant Ea‐peak. The presence of lacustrine mudstones is also suggested by a limited number of samples with HI values above 300 mg HC/g TOC in the southern part of the basin; in addition, palynofacies demonstrate a progressive increase in the abundance and areal extent of lacustrine and brackish open water conditions during Callovian times. A regional presence of oil‐prone Middle Jurassic lacustrine source rocks in the Søgne Basin, however, remains speculative.Middle Jurassic kitchen areas may be present in an elongated palaeo‐depression in the northern part of the Søgne Basin and in restricted areas in the south.Upper Jurassic – lowermost Cretaceous mudstones are thermally mature in the central, western and northern parts of the basin; they are immature in the eastern part towards the Coffee Soil Fault, and overmature in the southernmost part. Only a minor proportion of the mudstones have HI values &gt;300 mg HC/g TOC, and the present‐day source rock quality is for the best samples fair to good. In the south and probably also in most of the northern part of the Søgne Basin, the mudstones are most likely gas‐prone, whereas they may be gas/oil‐prone in the central part of the basin. A narrow elongated zone in the northern part of the basin may be oil‐prone. The marine mudstones are, however, volumetrically more significant than the Middle Jurassic strata.Possible Upper Jurassic – lowermost Cretaceous kitchen areas are today restricted to the central Søgne Basin and the elongated palaeo‐depression in the north.

TOC determination of Gadvan Formation in South Pars Gas field, using artificial intelligent systems and geochemical data

Potentially, TOC content is affected by logging data in a source rock (density, sonic, neutron and resistivity logs). Hence, to analyze these logs, which we make a quick and reliable assessment of a source rock. So, it is a quick and economically cheaper method rather than direct geochemical analysis. A source rock interval poses to less density, lower velocity, higher sonic porosity, higher gamma ray values and increase in resistivity. In this research, Gadvan Formation was studied in two boreholes as potential of source rock. The log data of two wells were used to construct of intelligent models in a source rock of the South Pars Gas field in southwest of Iran. A suite of geophysical logs (neutron, density, sonic and resistivity logs) and cutting chip data samples data were applied for determining TOC content of this formation. Rock-Eval pyrolysis data reveal that Gadvan Formation is poor source rock (less than 0.5%). Hence we attempted a correlation between geophysical data and direct TOC content measurements of using ∆ Log R, Rock-Eval, neural network and fuzzy logic techniques. The results showed that intelligent models were successful for prediction of TOC content from conventional well logs data. Meanwhile, similar responses from other different intelligent methods indicated that their validity for solving complex problems.

Late Cretaceous paleoenvironment and lake level fluctuation in the Songliao Basin, northeastern China

AbstractStudy of Late Cretaceous lacustrine sedimentary strata in the eastern Songliao Basin, China revealed that the paleoclimate was relatively arid and hot during sedimentation of the upper Santonian of the Yaojia Formation, but became relatively humid and warm during deposition of the lower Campanian Nenjiang Formation. The upper Yaojia Formation was deposited in a freshwater lake environment, while the lower Nenjiang Formation was deposited in a slightly brackish to brackish environment. The average total organic carbon content in the upper Yaojia Formation is 0.15%, while the hydrogen index is 36 mgHC/gTOC, implying poor source rock for oil generation and the organic matter comprised of a mixture of woody and herbaceous organic matter. In contrast, the hydrogen index of oil shale and black shale of the lower Nenjiang Formation is 619 mgHC/gTOC, and total organic carbon content on average is 3.37%, indicating a mixed algae and herbaceous source of kerogen and an increase in aquatic bioproductivity. The black shale and oil shale have low Pristane/Phytane and C29 5α,14α,17α(H) − stigmastane 20R/(20R + 20S) ratios, with maximum concentration of n‐alkanes at n‐C23, implying an anoxic depositional environment with algae, bacteria and higher plants providing most of the organic matter. Relatively abundant gammacerane and a higher Sr/Ba ratio in the oil shales suggest the presence of brackish water and development of salinity stratification in the lake. During sedimentation of the upper Yaojia through the lower Nenjiang Formations, the level of Songliao lake increased and a deep‐lake environment was formed with bottom waters being oxygen depleted. Concomitantly, as the lake deepened bottom conditions were changing from oxic to anoxic, and the input of organic matter changed from predominantly higher plants to a mixture of bacteria, algae and higher plants providing favorable conditions for oil source rock accumulation.

Petroleum source rock potential of Whitehorse trough: a frontier basin in south-central Yukon

Abstract Whitehorse trough is a frontier basin in south-central Yukon that is thought to contain gas and possibly oil. It consists of up to 7000 m of sedimentary and volcanic rocks referred to as the Lewes River Group (Triassic), Laberge Group (Jurassic), and Tantalus Formation (Jura-Cretaceous). The Lewes River Group is informally subdivided into the Povoas and Aksala formations, and the Laberge Group is informally subdivided into the Richthofen, Nordenskiold and Tanglefoot formations. To evaluate the petroleum source-rock potential of this basin, over 600 samples from the Aksala, Richthofen, Tanglefoot and Tantalus formations from throughout the trough have been analyzed by Rock-Eval programmed pyrolysis and combustion and by study of thermal alteration indicies (TAI) of palynomorphs, conodont alteration indicies (CAI), and vitrinite reflectance. The Povoas and Nordenskiold formations were not sampled because they consist of volcanic and volcaniclastic rocks, respectively, and have no source rock potential. The analyses indicate that the Aksala formation is a poor source rock that is postmature with no hydrocarbon potential. The Richthofen formation is a poor source rock that is postmature with minor gas potential. The Tanglefoot formation is a good source rock that is immature to early mature and gas-prone. The Tantalus Formation is also a good source rock that is immature to early mature and gas-prone. The Tanglefoot and Tantalus formations contain petroleum fluid inclusions that were probably generated from within these units. The inclusions reveal homogenization temperatures of mostly between 75–115°C and reveal several distinct, but minor pulses of liquid petroleum (mainly 19–21°API, 23°–35°API and 40–46° API). Potential petroleum (gas) generative intervals occur at surface and in the shallow subsurface in deltaic mudstones (Tanglefoot formation) and fluvial mudstones (Tantalus Formation). The lateral extent of these intervals is unknown due to poor outcrop exposure and limited shallow drilling. Both the Tanglefoot and Tantalus formations are interpreted as potential source rocks and possibly effective source rocks. The most prospective areas for petroleum exploration are Five Finger Rapids, Division Mountain and Tantalus Butte and in the northern portion of Whitehorse trough.

THE ORGANIC MATTER CHARACTERISTIC OF LOWER MIOCENE FORMATION IN CUU LONG BASIN

Cuu Long basin is located mainly in South Vietnam continental shelf and a part of mainland belonging to Mekong estuary area. It has an oval shape, convex seawards and lies along Vung Tau-Binh Thuan coast. Cuu Long basin adjoins mainland northwestwards, separates from Nam Con Son basin by Con Son uplift, southwest part is Khorat - Natuna uplift and northeast part is Tuy Hoa strike-slips separated from Phu Khanh basin. Recent oil and gas quantity exploited from Cuu Long basin is evaluated to be produced dominantly from Oligocene organic-rich sediments. Some studies suggested that organic matter of lower Miocene shale deposits fails to come up to standard of source rock or very poor source rock. Lower Miocene sediments considered how to play a role in providing production into trap is the subject studied more in detailed in this report. The organic carbon (TOC %) in lower Miocene source rocks contains mostly kerogene type III is 0.64-1.32%. The depositional environment of the organic matter in the lower Miocene sediments is terrestral. Therefore the lower Miocene formation may be considered the source rocks, but has not generated hydrocarbon, because it has not passed the oil window. The depositional environment of the organic matter in the lower Miocene sediments is terrestry.

Source Rock Characteristics, Thermal History, and Oil Generation of the Upper Cretaceous Island Arc Sequences from Northeastern Turkey

The Upper Cretaceous eastern Pontide island arc sequence in northeastern Turkey is composed mainly of volcanic and volcaniclastic rocks and rarely of sediments. In this study, source rock characteristics and hydrocarbon potentials of shale and claystone sequences at Zigana, Çatak, and Hacimehmet areas of the volcanic island arc were investigated. According to pyrolysis data, Zigana, Çatak, and Hacimehmet sequences show poor source rock character and they mostly contain residual organic matter and type III kerogen. In addition, shales have low potential yield and hydrogen index values. In the burial diagram drawn on the basis of Lopatin method, Σ TTI values of the Zigana, Çatak, and Hacimehmet sequences are calculated as 93,222, 1,124 and 1, respectively. This diagram indicates that Zigana and Çatak sequences are out of oil generation zone while Hacimehmet sequence has not reached oil generation zone. T max values measured from pyrolysis data generally show over mature character for the Zigana and Çatak sequences and immature character for the Hacimehmet sequence. T max values are consistent with burial diagram. Irregularities and deviations observed particularly in Zigana and Çatak sequences may be explained with thermal effect of Late Cretaceous volcanism.

Source Rock and Depositional Environment Study of Three Hydrocarbon Fields in Prinos - Kavala Basin (North Aegean)

Cored samples from four wells from Prinos, Prinos North and Epsilon fields have been analyzed using geo- chemical methods. The results show that the depositional environment was hyper-saline, strongly reducing in all fields, and indicating similar conditions during sedimentation through the basin. This type of environment has preserved the or- ganic matter, and in combination with rapid sedimentation, enabled hydrocarbons generation in the basin. The analysis of the samples reveals similarities between Epsilon and Prinos fields, while Prinos North field differentiates. Epsilon and Prinos hydrocarbons appear to be immature, non biodegraded, generated from marine organic production in a carbonate source rock, and having migrated into the analyzed sedimentary zones. The rock is characterized as poor source rock with minor hydrocarbon generation potential. On the contrary, Prinos North hydrocarbons appear to be even more immature, non biodegraded, generated in an argillaceous source rock with terrestrial input in organic matter, while in the analyzed zone kerogen type II and III was identified.