Source Rock Evaluation Research Articles

Estimating source rock parameters using wireline data: An example from Dezful Embayment, South West of Iran

Availability and high potential of wireline data to correlate with geochemical properties convinced petroleum geologists to use them for source rock detection and calculating their richness. In this research, intelligent techniques and mathematical relationships were used to evaluate source rock potential and organic matter type indirectly. Artificial neural networks (ANN) and ΔLogR techniques were successfully used to model the relation between wireline logs and Total Organic Carbon (TOC) content. Furthermore, wireline data and TOC values were used as input data to model a second ANN for S2 parameter (present hydrocarbon potential) calculation. Owing to its great ability in the course of solving non-linear problems with overwhelming complexity, the back propagation method was used to train the networks using 70 points datasets. Predicted TOC contents were validated by Rock-Eval pyrolysis results of which revealed dependency of the ΔLogR accuracy to the organic richness and lithology, and therefore higher precision of the ANN outputs in compare to the ΔLogR results.Hydrogen Index (HI) and kerogen type were also effectively predicted using mathematical relationship between TOC and S2 factors. Reliability of all steps of the methodology was approved using a 16 members retest dataset for which testing predicted parameters against measured data demonstrated good correlation coefficients combined with negligible errors. Finally, applicability of the methodology was checked by applying it on two wells in the Dezful Embayment to evaluate geochemical and depositional properties of the Paleocene-Early Oligocene Pabdeh Formation.

Geochemical characterisation of the Xiagou Formation carbonate-bearing mudstone in southwestern Jiuquan Basin, China: implications for paleo-environment reconstruction and the origin of organic matter

ABSTRACTSince the Xiagou Formation was confirmed to be the primary source rock of the crude oil discovered in the Yumen oilfield, geologists have performed many studies on the sedimentology of the formation, source rock evaluation and migration, as well as petroleum accumulation. In this study, the carbonate-bearing mudstones were investigated using synthetic organic and inorganic geochemical analyses to reconstruct the paleo-environment and study the origin of organic matter during deposition in correlation with organic matter enrichment. The analysed samples have total organic carbon (TOC) and S1 + S2 values in the range of 0.20–3.39 wt% and 0.07–19.50%, respectively, which indicate fair to good hydrocarbon potential. Biomarker studies on the pyrolysis data of the samples suggest that the predominant origin of the organic matter is terrigenous high plants with partial aquatic algae and micro-organisms, primarily oil- and gas-prone. The trace elements P and Ba are considered to be the main proxies for paleoproductivity, and values for the two elements hosted in samples range from 48 to 1724 ppm (a mean of 658 ppm) and from 322 to 1701 ppm (a mean of 550.34 ppm), respectively, which indicates that the sediments in the Xiagou Formation have high paleoproductivity. Additionally, organic geochemical studies reveal that the sediments were deposited in a lacustrine environment with brackish water (low C31-22R-homohopane/C30-hopane ratios; moderate gammacerane and β-carotane), which is consistent with the medium degree of the Sr/Ba ratio, which ranges from 0.22 to 1.42 (a mean of 0.64). Furthermore, the wide range of Cu/Zn and Rb contents are important indicators of a suboxic to relatively anoxic paleoredox condition. This outcome is consistent with the biomarker parameter Pr/Ph, which ranges from 0.05 to 1.37. Moreover, the major oxides and trace elements [high Fe/Mn, low Mg/Ca, low CIA and the plot of SiO2 vs (Al2O3 + K2O + Na2O)] also indicate that the sedimentary paleoclimate was semiarid to arid. Lack of correlation between TOC content and paleo-environment (suboxic, brackish and semiarid) or productivity indicators indicates that the accumulation of organic matter was controlled by combined action, rather than a single factor, such as redox condition or productivity.

Source rock evaluation and sequence stratigraphic model based on the palynofacies and geochemical analysis of the subsurface Devonian rocks in the Western Desert, Egypt

The Paleozoic rocks are the least explored among the subsurface successions in the Western Desert of Egypt. This contribution submits a significant record for the palynofacies and geochemical analysis for an important division of the subsurface Paleozoic rocks from Faghur-1 and NW-D302-1 boreholes. The palynofacies of the Devonian sediments of Zeitoun Formation extensively verified and classified. The palynofacies classification depended on the statistical techniques of cluster and correspondence analysis. The cluster analysis discriminated four classes of palynofacies in R-mode, which are brown wood palynofacies class R1, spore palynofacies class R2, AOM-opaque phytoclasts palynofacies class R3 and marine phytoplankton palynofacies class R4. In the Q-mode, the cluster analysis revealed three palynofacies types, which are palynofacies type C, palynofacies type B, palynofacies type A. The combination of cluster and correspondence analysis is employed to interpret the evolution of basin dynamics and the mechanisms that controlled the deposition of the Devonian rocks. Three basic environmental settings were recognized and they include 1.) Oxic highly proximal shelf setting, 2.) Oxic proximal shelf setting and 3.) Oxic distal shelf. The high oxygenation levels are confirmed by the inorganic geochemical analysis of Fe%, TS/Fe and TS/TOC in the samples from Faghur-1 borehole. The paleoenvironmental reconstruction is used to identify four 2nd order stratigraphic sequences in the studied sections, which are DevSeq1, DevSeq2, DevSeq3 and DevSeq4. These sequences are systematically described and correlated with their equivalent global Devonian Sequences. The palynofacies investigation is integrated with the inorganic and organic geochemical analysis to evaluate the potentially of hydrocarbon generation from the probable source rocks in the studied sections and its onset timing. The identified kerogen types are mostly mature (TAI range between 2 and 3 and Tmax range between 427 and 439 °C) gas prone type III with poor organic enrichment (TOC <0.9) and low potentiality for hydrocarbon production (PI range between 0.02 and 0.1). The burial history models were constructed for both boreholes; they revealed that the hydrocarbon generation started in the Cretaceous in both boreholes.

Comparison on geochemical characteristics between oil shale and black mudstone of Yanchang formation Chang 7 in the Erdos Basin, China

ABSTRACTGeochemical characteristics between high quality oil shale and black mudstone of Chang 7, Yanchang formation of Erdos Basin were compared through certain analyses on sedimentary environment and parent materials of different source rocks combined with comprehensive evaluation of source rocks and parameter analysis of biomarkers. The results showed the oil shale formed from deep-lacustrine reducing environment, but the black mudstone formed from semi-deep-lacustrine weak oxidation environment. In addition, oil shale has better total organic carbon, hydrocarbon potential and organic types while black mudstone has better abundance of 17α(H)-diahopanes and Ts.

Source rock evaluation of Middle Eocene–Early Miocene mudstones from the NE margin of the Black Sea

Abstract This study comprises the source rock evaluation of 122 Late Middle Eocene–Early Miocene mudstones from the NE margin of the Black Sea. Samples are immature to early mature. The majority of samples have moderate to very good organic richness, poor to moderate source potential and a hydrogen-deficient to gas-prone source rock quality. However, a significant proportion of the samples have good to excellent organic richness and source potential, and an oil- and gas-prone quality derived from amorphous-rich kerogens. These samples would generate significant amounts of oil and associated gas where buried to peak maturity. They come from the lowermost (Rupelian) part of the Maykop Series and the late Bartonian–early Priabonian Kuma Suite or its stratigraphic equivalents. The Rupelian source-rock interval(s) in west Georgia is at least 60 m thick and potentially as much as 200 m thick. It has a source potential index (SPI) of 0.7–2.5 t HC m −2 . The thickness of the Kuma Suite-equivalent source rock interval south of the western Greater Caucasus is unconstrained. Maykop Series source rocks occur in the Black Sea Basin. Prospective Kuma Suite-equivalent samples on both the northern and southern margins of the Black Sea imply that similar sediments may also be present in the basin.

Holocene source rock deposition in the Black Sea, insights from a dropcore study offshore Bulgaria

Abstract One of the main issues in source rock evaluation has always been the availability of thermally immature samples, which would represent the same source rock quality and facies as the mature source rock within the deeper parts of the basin. Forty dropcore sample locations from shallow depths beneath the present-day seafloor were selected and analysed for mineral composition and bulk geochemical parameters. The water depths of the samples range from shelfal to bathyal environments. The quartz content of the samples clearly decreases with increasing distance from sedimentary input sources (e.g. river deltas), whereas clay content increases towards the distal areas. Mass movements (e.g. slides and debris flows) along the present-day shelf are recognizable on the bathymetry, as well as in the mineral content. Bulk geochemical parameters show that currently only poor to fair gas-prone source rocks are deposited within the study area. This lack of source rock quality, as well as organic content, is attributed to the fine-grained sedimentary input from the Danube river. These fine-grained sediments decrease the organic productivity due to dulling (decrease in the thickness of the photic zone) of the water column, and dilute the currently deposited source rock with low TOC sediments. These effects decrease with distance from the Danube delta, as indicated by published data from outside the study area. Additionally mass movements along the present-day shelf rework possible source rocks. The results of this study clearly show that anoxic conditions alone are not sufficient for source rock deposition. Distance from major sedimentary input and basin geometry are of major importance, and should be considered in basin modelling.

Geochemical Characteristics and Genesis of Oil-Derived Gas in the Jingbian Gas Field, Ordos Basin, China

The source rocks of natural gas of the Jingbian gas field in Ordos Basin, China, are unclear, and the origin of oil-derived gas is controversial. On the basis of a series of experiments on source rock evaluation, including total organic carbon, Rock-Eval pyrolysis, carbon isotope composition of kerogen, chloroform bitumen A, maceral compositions, and gas chromatograms, we evaluated the hydrocarbon generation potential of the possible source rocks. We also conducted the components and stable carbon isotopes of natural gas and compared geochemical characteristics of natural gas and source rock-adsorbed gas. The results indicate that source rocks from the Lower Permian Taiyuan Formation have some hydrocarbon-generating capability but far less than its proximate Carboniferous and Permian coal measures. Oil-derived gas originated from Lower Permian Taiyuan Formation limestone was expulsed to the Majiagou Formation by coal-derived gas generated from the Carboniferous and Permian coal measures, as indicated by s...

Geothermal modelling and its application to hydrocarbon generation from agbada formation. a case study of USANi field, Niger delta basin, Nigeria

The geothermal model was done with the integration of surface. Subsurface temperature's data and formation depth values from suites of well log in the study field. The well comprises Gamma-ray log (GR log), Spontaneous Potential logs (SP log), Resistivity logs, Formationdensity, Neutron log and Sonic log. The suites of welllog within the studied sequences penetrates Agbada and the Benin Formation. The Benin Formation comprises mainly of continental sands, and the Agbada Formation consist of alternating sequence of sand and shales within the study wells. The estimated thickness and temperature values within the study field falls within the range from 1357- 3500m and 101 O C – 120.5 O C with estimated geothermal gradient range of (0.028 - 0.03 O C/100m) in the field. The geo-temperatures results range of 101.60 O C – 119.60 OCat modeled depth of 1357m- 3500m, indicating that the shale sequence at the basal path of the Agbada Formation is thermally matured with sufficient organic matter to generate hydrocarbon in the study field as earlier believe to be immature and cannot generate hydrocarbon. The geothermal model can be applicable to any sedimentary basin in the world. This work is also an important tool in source rock evaluation to compliment petroleum geochemistry and position the hydrocarbon generating window of the study field.

Evaluation of Eocene source rock for potential shale oil and gas generation in north Cambay Basin, India

Source rock potential of 108 representative samples from 3 m intervals over a 324 m thick shale section of middle Eocene age from the north Cambay Basin, India have been studied. Variation in total organic carbon (TOC) and its relationship with loss on ignition (LOI) have been used for initial screening. Screened samples were subjected to Rock-Eval pyrolysis and organic petrography. A TOC log indicated wide variation with streaks of elevated TOC. A 30 m thick organic-rich interval starting at 1954 m depth, displayed properties consistent with a possible shale oil or gas reservoir. TOC (wt%) values of the selected samples were found to vary from 0.68% to 3.62%, with an average value of 2.2. The modified van Krevelen diagram as well as HI vs. Tmax plot indicate prevalence of Type II to Type III kerogen. Tmax measurements ranged from 425 °C to 439 °C, indicating immature to early mature stage, which was confirmed by the mean vitrinite reflectance values (%Ro of 0.63, 0.65 and 0.67 at 1988 m, 1954 m, and 1963 m, respectively). Quantification of hydrocarbon generation, migration and retention characteristics of the 30 m source rock interval suggests 85% expulsion of hydrocarbon. Oil in place (OIP) resource of the 30 m source rock was estimated to be 3.23 MMbbls per 640 acres. The Oil saturation index (OSI) crossover log showed, from a geochemical perspective, moderate risk for producing the estimated reserve along with well location for tapping the identified resource.

Source rock evaluation of Kharita and Bahariya formations in some wells, North Western Desert, Egypt: Visual palynofacies and organic geochemical approaches

Palynofacies analyses were applied on ninety-one samples from the subsurface Albian – Cenomanian succession represented by Kharita and Bahariya formations, encountered in El-Noor, and South Sallum wells, located in the North Western Desert, Egypt, to visually characterize the content of dispersed organic matter, as well as, organic geochemical characterization to reveal the depositional paleoenvironments and source rock potentiality. The result recognized of five palynofacies associations in the studied interval. The deposition of Kharita Formation took place mainly in a steady and a relatively stable deltaic to marginal environment continued as well in the lower part of Bahariya Formation with minor changes. The marine influence became more common in the upper part of Bahariya Formation showing the exceptional high hydrocarbon potential recorded in the studied interval. This indicates marine transgression by the end of the early Cenomanian (Upper Bahariya) age. Samples from the Kharita Formation contain abundant brown phytoclasts which suggest gas-prone kerogen type III and IV. While Bahariya Formation includes translucent, brown cuticles and woody tracheid phytoclasts pointing to more promising gas-prone kerogen type III. The organic geochemical analysis shows poor to fair gas-prone source rock potential within the study section., Thermally, the color of the spore grains in Kharita and Bahariya formations show that dark yellow to orange, indicates immature besides their general little poor hydrocarbon generation potentiality.

Evaluation of source rocks in the 5th member of the Upper Triassic Xujiahe Formation in the Xinchang Gas Field, the Western Sichuan Depression, China

The 5th member of the Upper Triassic Xujiahe Formation (T3x5) is one of the important targets for terrigenous natural gas exploration in the Xinchang Gas Field in the Western Sichuan Depression, however, the quality of the T3x5 source rocks is poorly studied and the understanding of it is controversial. Studies have been conducted on the development and organic geochemical characteristics of the T3x5 mudstone in the Xinchang Gas Field, and the results indicate that, the T3x5 mudstone in the Xinchang Gas Field display an average thickness of 285.3 m, and the thickness of each submember increases from north to south. The average TOC content, hydrocarbon potential (S1+S2) and chloroform bitumen “A” content of T3x5 mudstone are 2.17%, 2.26 mg/g and 0.264‰, respectively, with the organic abundance mainly reaching the standard of medium source rocks. The kerogen type index (TI) is lower than 0 with the mean δ13C value of −25.0‰, indicating mainly humic and sapropelic-humic types of organic matters. The average vitrinite reflectance (RO) value is 1.17%, indicating the stage after the peak of oil generation. The gas generation intensity of T3x5 mudstone is generally in the range of (3–16) × 108 m3/km2, which suggests the resource basis for the generation of medium-small gas fields. The total amount of natural gas generated by T3x5 mudstone in the Xinchang Gas Field is relatively low, and the generated gas cannot completely displace the water in the formation, therefore, the fullness of gas in the reservoirs is generally low, which causes the simultaneous production of gas and water and the low gas production in the process of production test.

Source rock evaluation of the Gondwana coals in Raniganj coalfield, India

ABSTRACTPresent study perceived that samples have excellent hydrocarbon generation potential and total organic carbon (TOC) content. The pyrolysis temperature (Tmax) indicates that samples are in immature stage (<435°C) for hydrocarbon generation. The hydrogen index (HI) values show that the sample lies in a mixture of Type II–III and Type III kerogen. The plot of HI versus TOC implies that samples fall in fair oil source or gas/oil field. Field emission scanning electron microscopy (FE-SEM) and electron dispersive X-ray (EDX) study reveals that the different micro/macro pores and fracture system present mostly in organic substance. In situ gas content values are high enough to produce methane from coal beds.

Evaluation of shale gas potential in the Lower Cretaceous Sembar Formation, the Southern Indus Basin, Pakistan

The Lower Indus Basin of Pakistan is reported to contain significant recoverable resources of shale oil, but until now no detailed research has been done to estimate its shale gas potential. In this study, an integrated approach was proposed and applied, combining source rock screening (SRS), petroleum system modeling (PSM) and volumetric calculations to evaluate the shale gas potential of the Lower Cretaceous Sembar Formation, the Southern Indus Basin. The study was conducted based on the data from the public domain of petroleum industry in Pakistan, including vertical well sections, well logs, seismic sections, regional geological sections, base maps, and geochemical data. Results of source rock screening (SRS) found that the organic-rich shales of the Sembar Formation have %Ro (vitrinite reflectance) ranging from 0.76 to 3.79 (corresponding to TAI from 2.8 to 2.9), kerogen types ranging from type II to type III, and TOC (total organic carbon) values as high as 9.5%. Results of petroleum system modeling (PSM) indicated that shales of the Sembar Formation are in the thermal window for gas and oil generation. Hydrocarbon generation was found to have started in the Late Cretaceous with maximum burial in the Late Paleogene. Shales of the Sembar Formation are interpreted to be over-pressured at present. Finally, the volumetric calculation estimated that the volume of Retained Gas In Shale (RGIS) of the Sembar Formation is 359 Trillion Cubic feet (Tcf), out of which 43.1 Trillion Cubic feet (Tcf) is risked RGIS. The results of this study concluded that the Sembar Formation has momentous shale gas potential and the integrated approach employed in this study for shale gas potential evaluation is pertinent to evaluate source rocks in other sedimentary basins of Pakistan.

Geological features and exploration fields of tight oil in the Cenozoic of western Qaidam Basin, NW China

Abstract Using a large amount of drilling and experimental analysis data, this paper evaluates four potential fields of tight oil exploration in western Qaidam Basin from comprehensive analysis of geological conditions such as sedimentary environments, source rock evaluations, reservoir characteristics, and source-reservoir relationships. Influenced by continuous uplift of Tibet Plateau since Paleogene, the sedimentary environment of the western Qaidam Basin exibits three characteristics: (1) a paleo-topographic configuration consisted of inherited slopes, depressions and paleohighs; (2) frequent alternation of relative humid and arid paleoclimate; and (3) oscillation of salinity and level of the paleo-lake water. Preferential paleo-environment resulted in two sets of large-scale source rocks with high efficiency and two types of large-scale tight reservoir rocks (siliclastic and carbonate), deposited during the late Paleogene to early Neogene. The above source and reservoir rocks form favorable spatial relationships which can be classified into three categories: symbiotic, inter and lateral. Based on sedimentary environments and reservoir types, tight oil resource in western Qaidam Basin can be divided into four types, corresponding to four exploration fields: salty lacustrine carbonate tight oil, shallow lake beach-bar sandstone tight oil, delta-front-sandstone tight oil and deep lake gravity-flow-sandstone tight oil. The temporal and spatial distribution of tight oil has characteristics of layer concentration, strong regularity and large favorable area, in which the saline lacustrine carbonate and shallow lake beach-bar sandstone tight oil are the best exploration targets in the western Qaidam Basin.

Quantitative modelling of hydrocarbon expulsion and quality grading of tight oil lacustrine source rocks: Case study of Qingshankou 1 member, central depression, Southern Songliao Basin, China

The quality of source rocks plays an important role in the distribution of tight and conventional oil and gas resources. Despite voluminous studies on source rock hydrocarbon generation, expulsion and overpressure, a quality grading system based on hydrocarbon expulsion capacity is yet to be explored. Such a grading system is expected to be instrumental for tight oil and gas exploration and sweet spot prediction. This study tackles the problem by examining Late Cretaceous, lacustrine source rocks of the Qingshankou 1 Member in the southern Songliao Basin, China. By evaluating generated and residual hydrocarbon amounts of the source rock, the extent of hydrocarbon expulsion is modelled through a mass balance method. The overpressure is estimated using Petromod software. Through correlation between the hydrocarbon expulsion and source rock evaluation parameters [total organic carbon (TOC), kerogen type, vitrinite reflectance (Ro) and overpressure], three classes of high-quality, effective and ineffective source rocks are established. High-quality class contains TOC >2%, type-I kerogen, Ro >1.0%, overpressure >7Mpa, sharp increase of hydrocarbon expulsion along with increasing TOC and overpressure, and high expulsion value at Ro >1%. Source rocks with TOC and Ro <0.8%, type-II2 & III kerogen, overpressure <3Mpa, and low hydrocarbon expulsion volume are considered ineffective. Rocks with parameters between the two are considered effective. The high-quality class shows a strong empirical control on the distribution of tight oil in the Songliao Basin. This is followed by the effective source rock class. The ineffective class has no measurable contribution to the tight oil reserves. Because the hydrocarbon expulsion efficiency of source rocks is controlled by many factors, the lower limits of the evaluation parameters in different basins may vary. However, the classification method of tight source rocks proposed in this paper should be widely applicable.

Petroleum generation and expulsion in middle Permian Lucaogou Formation, Jimusar Sag, Junggar Basin, northwest China: assessment of shale oil resource potential

Shale oil exploration of the Permian Lucaogou Formation (P2l) has greatly advanced in the Jimusar Sag in the Junggar Basin. However, despite the strong exploration prospects of shale oil resources, the potential of shale oil resources in the Junggar Basin has been insufficiently assessed. This study performs systematical evaluation of P2l source rocks in the Jimusar Sag and proposes an improved hydrocarbon generation potential method to assess the hydrocarbon generation and expulsion characteristics and evaluates the shale oil resource potential of the P2l source rocks in the Jimusar Sag. The results show that the P2l source rocks are thick (up to 200 m) and are distributed over a wide area (up to 1200 km2) in the study region. It contains high TOC (2%–5%), characterized by dominantly type I and type II kerogen. The source rocks are in the low mature–mature stage, and possess good conditions for generation of hydrocarbons. The P2l source rocks reached the hydrocarbon expulsion threshold at a thermal maturity of 0.8% vitrinite reflectance. The efficiency of hydrocarbon expulsion of the source rock is 34%. The amounts of hydrocarbons generated and expelled were 65 × 108 t. Based on the above information, the shale oil resources potential is calculated to be 43 × 108 t, indicating very good shale oil resource prospect in the P2l source rocks of the Jimusar Sag. Copyright © 2017 John Wiley &amp; Sons, Ltd.

Inversion of source rock hydrocarbon generation kinetics from Rock-Eval data

Basin and petroleum system modeling requires source rock kinetics as input for the reconstruction of hydrocarbon generation history. For less well-studied petroleum systems, there may be little information on petroleum generation kinetic parameters publically available; thus, an analog of representative source rock kinetics must be chosen from available kinetics databases. Recent studies suggest that source rock kinetics may vary considerably even when they contain the same type of kerogen. Thus, kinetic parameters from analog basins/source rocks may lead to erroneous results in petroleum generation history reconstruction. Rock-Eval data contain information about source rock kinetics, and can be used to improve the kinetic model in petroleum system modeling. However, the kinetic information in Rock-Eval data is not in the form of activation energies and frequency factors required to solve the temperature dependency of reaction rate in the Arrhenius equation. This article proposes a kinetic inversion method so that the analogous kinetic model chosen by the user can be improved based on Rock-Eval data of the targeted source rock. We demonstrate the method using a synthetic dataset in a case study for method validation and its application to real source rock evaluation for examples from the Devonian Duvernay Shale in the Western Canada Sedimentary Basin (WCSB).

Source Rock Evaluation in The Lake Chad Area of the Bornu Basin, Nigeria

Source rock evaluation of the Lake Chad area of the Bornu Basin which contains a comparatively thicker sedimentary succession based on interpreted seismic and gravity data was undertaken in this study. A total of twenty-nine shale samples from three wells (Kutchali-1, Faltu-1 and Herwa-1) were analysed to arrive at the bulk geochemical properties, organic matter particles and vitrinite reflectance (VR) data of the strata penetrated by the wells. The Lake Chad area appears to contain the main ingredients required to make a rich source rock with over 96% of the total organic carbon (TOC) values being in the range of 0.63-2.88 wt% and over 95% having Tmax greater than 435°C in most of the sampled intervals. The variation of Tmax and VR with depth in the wells reveals irregular decreases or subtle decreasing trends that are suggestive of cooling in the basin’s thermal history probably as a result of uplift and erosion. The uplift could have been caused by epeirogenic movement or by folding related to the Santonian inversion witnessed by the West African Rift Subsystem. In terms of hydrocarbon generation potential, most of the samples have HI values greater than 50 mgHC/g TOC, but generally less than 200 mgHC/g TOC. These HI values suggest dominance of Type III with less Type II Kerogen; thus, a predominantly predominantly gas prone area. A study of some bulk geochemical parameters (TOC, Tmax and HI) of the three study wells has revealed that the succession penetrated by one of them (Faltu-1 well) contains several potential gas source intervals and two potential oil source intervals with the latter probably lying between 2500 m and 3000 m depth.

Geochemical characteristics of crude oil from a tight oil reservoir in the Lucaogou Formation, Jimusar sag, Junggar Basin

Jimusar sag, which lies in the Junggar Basin, is an important tight oil study area in China. However, the properties and origin of the crude oil and the geochemical characteristics of the tight oil from the Lucaogou Formation have not yet been studied. In the present study, 23 crude oil samples from the Lucaogou Formation were collected for analysis, including physical properties (density and viscosity), bulk composition, saturated hydrocarbon gas chromatography–mass spectrometry, and calculation of various biomarker parameters. Source rock evaluation and porosity permeability analysis were applied to the mudstones and siltstones. To analyze the hydrocarbon generation history of the Lucaogou source rocks, one-dimensional basin modeling was performed. The oil-filling history was also investigated by means of basin modeling and microthermometry. Biomarkers of suitable source rocks (total organic carbon content is >1%, summation of the free and volatile hydrocarbon and remaining hydrocarbon generative potential is >6 mg HC/g rock, and vitrinite reflectance is between 0.7% and 1%) were analyzed for oil–source correlation. The results indicate that low-maturity to mature crude oils originated from the source rocks containing terrigenous organic matter, which were deposited in a saline lake. The source rocks are of mainly type II kerogen. Oil in the lower section of the Lucaogou Formation is relatively dense and viscous and has elevated nonhydrocarbon content. In addition, a higher proportion of bacteria and algae is shown to have contributed to the formation of crude oil in the lower section when compared with the upper section of the Lucaogou Formation. Oil–source correlations demonstrate that not all mudstones within the Lucaogou Formation contribute to oil accumulation. Thin section observation indicates organic macerals surround the grains of some siltstones within the porous and permeable subsections, which proves the siltstones contribute to hydrocarbon generation. Crude oils from the upper and lower sections mainly originate from thin-bedded mudstones interbedded and siltstones within the porous and permeable subsections. The mudstones over or beneath the porous and permeable subsections consist of seals and prevent the vertical movement of oil by capillary forces. Despite being thicker, mudstones between the two porous and permeable subsections make no obvious contribution to the oil accumulation because of their low permeability and distance from the porous and permeable subsections, which is consistent with the principle of near-source charging for tight oil accumulations. Lucaogou oil has been charged twice, once from 235 to 210 Ma and again from 180 to 150 Ma, coinciding with oil generation time.

Source rock evaluation of ABU Gabra formation in Azrag area –Muglad basin, Khartoum, Sudan

Source rock evaluation of ABU Gabra formation in Azrag area –Muglad basin, Khartoum, Sudan