Oil Source Rocks Research Articles

Physical and Mathematical Modeling of the Temperature Distribution Along the Length of Oil Source Rocks under Microwave Irradiation

Physical and Mathematical Modeling of the Temperature Distribution Along the Length of Oil Source Rocks under Microwave Irradiation

Organic matter enrichment mechanism of Youganwo Formation oil shale in the Maoming Basin

The Youganwo Formation oil shale located in the Maoming Basin represents a large commercially valuable lacustrine oil shale resource and a potential bio-shale gas reservoir in South China. With the aim of deepening the understanding of factors that influence organic matter enrichment, this research conducted a geochemical investigation to reconstruct the depositional paleoenvironment of bioproductivity, preservation and dilution. Youganwo Formation oil shale is mainly deposited in semi-deep to deep-lake environments with relatively warm and humid paleoclimate in the subtropical-temperate zone. The total organic carbon (TOC) content (1.46–11.85%), S2 values (4.79–115.80 mg HC/mg rock) and HI (328–1040 mg HC/mg TOC) indicate that the oil shale has a good oil source rock potential. TOC content, (S1 + S2) values and vitrinite reflectance values show that its marginally mature organic matter (OM) belongs to kerogen type I-III with good oil-generating potential.A 3rd order sequence was identified in the Yougnwo formation. Subsequently, the multiple factors including bioproductivity, preservation and dilution that control the OM enrichment of oil shale within system tracts were discussed. Moderate-quality oil shales (Oy-1) were developed in the transgressive systems tract (TST) in an oxidizing condition with abundant detrital input. High-quality oil shales (Oy-2) were deposited during the high-stand systems tract (HST) with increased accommodation space, improved preservation conditions, warm and humid climate, higher water bioproductivity and minimum detrital matter input. During the regressive systems tract (RST, Oy-3), higher detrital matter input and fresher water led to lower TOC values. Among these multiple factors, dilution condition was the major one that influences OM abundance and variation on the basis of sufficient organic matter input. Thus, OM enrichment models of Oy-1, Oy-2 and Oy-3 sub-members were established. The OM enrichment and quality in oil shale were controlled by the combined effect of bioproductivity, preservation, and dilution.

Contribution of soluble organic matter to hydrocarbon generation in saline lacustrine source rocks: Evidence from thermal simulation experiments

Soluble organic matter generally exists in the source rocks of saline lacustrine basins. In this paper, we quantified the contribution of soluble organic matter to hydrocarbon generation based on thermal simulation experiments using a saline lacustrine source rock from the Qaidam Basin. Our results show that the yields of gaseous and liquid hydrocarbons in the thermal simulation products are greatly improved in the presence of soluble organic matter. As a comparison, the maximum yields of gaseous and liquid hydrocarbons in series C (without soluble organic matter) were 270 mg/gTOC and 329.78 mg/gTOC, respectively, while in series A (with soluble organic matter) they were 364 and 602.98 mg/gTOC, respectively. The proportion of isoprenoids and n-alkanes in the products also increased from approximately 3%–40%. Meanwhile, the presence of soluble organic matter reduced the temperature corresponding to the hydrocarbon generation peak from 375 to 250°C. Moreover, the presence of soluble organic matter also had a remarkable change on the stable carbon isotope composition of methane, resulting in more 12C enrichment with a range of 2.24‰–5.25‰. The combined evidence indicates that soluble organic matter can promote the formation of immature‒low maturity oil in source rocks.

Characteristics and controlling factors of the Upper Permian Dalong Formation in northwestern Sichuan Basin, China

It has been generally accepted that the Permian shale is an important target for shale oil and gas exploration. In order to precisely predict the distribution of potential excellent source rocks of shale oil and gas, it is necessary to reveal the forming process and mechanism of high-quality source rocks, such as the Dalong Formation in the Scihuan Basin. In this study, 17 samples were collected from the Dalong Formation in Longfeng Quarry, Northwest Guangyuan City, Sichuan Province. The lithofacies, organic geochemistry, and pyrolysis of these samples were analyzed to evaluate the main factors controllingthe source rock formation. In particular, the influences of hydrothermal and paleoenvironmental conditions on the accumulation of organic matter were analyzed. The total organic carbon (TOC) content of the samples, which ranges from 0.05% to 12.21%, is closely related to the lithology. High TOC has been generally observed in rock intervals developed in a deep-water sedimentary environment, including siliceous rock, dark shale, and siliceous shale. The peak pyrolysis temperature of the samples ranges from 444°C to 462°C, indicating a mature stage. Thin-section observation, combined with the results of previous studies, has confirmed that the source of the organic matter is mainly marine phytoplankton, such as algae and radiolarians, ostracods, and other marine organisms, which consist of these high-quality source rocks. The ratio of trace elements, such as Ni/Co, V/Cr, U/Th, and V/(V + Ni) indicate that high-quality source rocks are mainly formed in anoxic restricted environments. The hydrothermal activity of submarine volcanoes provided many nutrients and compounds, resulting biological prosperity and improving primary productivity. This is simultaneously conducive to the formation of anoxic environments and the preservation of organic matter.

Oil and gas complexes as a material expression of geofluid dynamic systems

The purpose of the present research is to analyze the geofluid dynamic concept of oil and gas formation. The research uses the author's data on the structure, composition and thickness of multi-aged oil and gas complexes of the Siberian platform (Russia). The oil and gas complexes identified as a result of the integrated geological, geochemical and geophysical studies carried out under oil and gas geological zoning and operational work are presented as a material expression of geofluid dynamic systems. Any geofluid dynamic system includes hydrocarbon generation centers, oil and gas migration routes, types of reservoirs and traps, lithological composition of reservoir rocks and reservoir cap rocks Also it is controlled by a favorable combination of their appearance in geological time and space. An ordinary fluid dynamic system is presented by hydrocarbon solutions generated by oil and gas generation centers, which are examples of a trivial defluidization of oil and gas source rocks of a sedimentary basin. This study allowed to be the first who has identified the elements of multi-age geofluid dynamic systems, presented their material expression in the form of multi-age oil and gas bearing complexes as well as analyzed the composition of hydrocarbons on the example of individual deposits of variousoil and gas-bearing areas. Besides, possible generation centers of hydrocarbon fluids and ways of their migration were investigated. Oil fields of different ages of the oil and gas bearing provinces of the Siberian Platform feature different composition and density, whereas according to numerous available data, they belong to a single genetic type, which is characterized by the predominance of methane hydrocarbons.

«Палеозойская» нефть Урманского месторождения (юго-восток Западной Сибири)

This paper presents the results of applying paleotemperature modelling for determination possible sources, which form hydrocarbon deposits in the pre-Jurassic basement in the southeast of Western Siberia. Discovery of light oil deposits below the depth of 7000 m in the Tarim basin indicates the possibility of existence favourable temperature regime for generation and conservation of hydrocarbon deposits even at such great depths. According to some estimates about 40 % of the total proved oil and gas reserves in the world are distributed in the superdeep strata. Russian scientists also have extensive prospects for the Paleozoic sedimentary basins of Western Siberian Plate. These basins formed on betwixt mountains, where favourable environment for accumulation of dispersed organic matter and its transformation into hydrocarbons persisted for a long geological time. There are two concepts of “the main source” for oil accumulated in the Paleozoic reservoirs. The first suggests deposit formation via upward migration, while the second supports the idea of downward interstratal migration of hydrocarbons from the Jurassic source rocks. The aim of this study is to determine possible sources for the Paleozoic hydrocarbon deposits in the Urman field via modelling of thermal history of the Phanerozoic oil-source rocks. The first experience of performing such research is related to the Ostanino group of fields. The research is continued for the Chuzic-Chizhapka group of fields, which is located on the tectonic unit of the same name. Both groups are associated with the Nyurol sedimentary basin. It was found that the Paleozoic reservoir of the Urman field accumulates partially preserved gas generated by the Paleozoic source-rocks and oil representing a mixture of the Jurassic oil of marine and terrigenous origin.

Assessment of terrigenous and marine sourced oils mixtures: Los Manueles field, Maracaibo basin Venezuela

Seven crude oil samples from Los Manueles field, Maracaibo Basin, Venezuela, were analyzed to evaluate oil mixtures associated with different oil charges into the reservoirs. Analyses of the bulk physicochemical parameters suggest variations in the API gravity, the concentration of saturated and aromatic hydrocarbons, NSO compounds + asphaltenes, sulfur, vanadium, nickel, and the biomarkers distribution. The oils were divided in two groups: G-I with high saturated hydrocarbons and low NSO compounds + asphaltenes, sulfur, vanadium and nickel, a bimodal distribution of n-alkanes, high Pr/Ph and oleanane index, low steranes index, low abundance of tricyclic terpanes and C35S/C34S < 0.54 and G-II with low saturated hydrocarbons and high NSO compounds+ asphaltenes, sulfur, vanadium and nickel, an unimodal distribution of n-alkanes with low Pr/Ph and oleanane index, high steranes index, abundance of tricyclic terpanes and C35S/C34S > 0.70. G-I has a higher contribution of terrigenous organic matter compared to G-II, characterized by a higher contribution of marine organic matter. Source rock lithology biomarker indicators suggest marine shale as the source rock for oils of terrigenous origin. The results indicate that oils were generated by two independent source rocks, La Luna Formation and a secondary source rock with terrigenous organic matter, probably represented by the Capacho Formation.

Biomarker geochemistry of Qaiyarah, Butmah and Ain Zala crude oils, northern Iraq: Implications for the Jurassic source rocks

Fifteen crude oils from the Qaiyarah, Butmah, and Ain Zala fields were investigated using organic geochemistry to infer organic matter maturity, redox conditions of the depositional environment, and lithology of the corresponding source rocks. Carbon isotope compositions and sulfur contents were measured for all samples and saturated and aromatic biomarkers were analyzed by GC-MS.Low pristane/phytane (0.68–0.82) and high C35 S/C34S (1.03–1.66) and homohopane indices (0.14–0.24) in the oil samples indicate anoxic or euxinic conditions for the corresponding source rocks. In addition, sulfur content, C30 norhopane/C30 hopane, and C31 R/C30 hopane, Ts/Tm and C27 diasteranes/regular steranes values suggest carbonate source rocks with variable amounts of clays. These source rocks contain mainly type II-S kerogen. Moretane/hopane, hopane and sterane isomerization ratios suggest generation from early mature organic matter. Hierarchical cluster analysis identified three families charged from carbonate source rocks with variable amounts of clays and maturity. Oil-source rock correlation (based on published data) and age-related biomarkers suggest that these oils were generated from Jurassic source rocks (Sargelu, Naokelekan, and/or Chia Gara formations). Jurassic rocks in Ain Zala and Butmah area have low potential for hydrocarbon generation, therefore, the Ain Zala and Butmah oils were charged from Jurassic formations outside the Ain Zala area, but within the neighboring area northeast of Butmah and Ain Zala.

Geological prerequisites for the search for rocks with increased reservoir properties in domanic type sediments on the territory of the Republic of Tatarstan

Domanic type deposits generally is abundant in Tatarstan Republic and other territories. They are feature with oil-source rocks (black shales), which partly generated hydrocarbons. However, due to their high hydrocarbon contain, domanic type deposits construing as unconventional reservoir rocks, that may be commercial significant. Based on Russian and foreign experience in the development of such deposits, the prospects for their exploitation are associated with the searching for formations with increased reservoir properties and light oil. In this work we are analyzed the stratigraphic distribution of domanic type deposits in the Kama-Kinel system of depressions and beyond them. It is shown that such deposits in the Kama-Kinel system of depressions have a thickness about 300 m and cover the stratigraphic range from semiluk horizon of the Frasnian stage to Tournaisian stage. But out of depressions these rocks occurred only in semiluk horizon. The reason of it is high dissection of the bottom of the Domanic sedimentation basin in the Late Frasnian-Tournaisian ages due to the evolution of the Kama-Kinel system of depressions in the east of the Russian Plate. The results of our own research show that carbonate and carbonate-siliceous rocks enriched in organic matter are the most common lithotypes in the Domanic type deposits. Also, we constantly found carbonate breccias and less secondary dolomites in the studied geological columns. In the last two types of rocks, we found higher values of porosity, openness, and a lighter composition of hydrocarbons. Based on the results of the author’s research and the literature observation, it follows that the development of carbonate breccias and secondary dolomites will be in the sides of the Kama-Kinel system of depressions. We consider that they are as the most promising objects for the search for industrial profit in the Domanic type deposits.

Evaluation of Re–Os geochronology and Os isotope fingerprinting of Late Cretaceous terrestrial oils in Taranaki Basin, New Zealand

The rhenium-osmium (Re–Os) isotope system has been applied to several marine and lacustrine petroleum systems worldwide, showing good potential for dating crude oils and correlating them to their source rocks. Here we explore the applicability of the Re–Os geochronometer and Os isotope fingerprinting to terrestrial oils by comparing the Re and Os systematics of Late Cretaceous terrestrial oils from Taranaki Basin, New Zealand, and their correlated coaly source rocks. Comparison is also made with selected Late Cretaceous–Paleocene marine oils and source rocks with varying levels of terrestrial organic matter input.The asphaltene fractions of nine genetically related terrestrial oils from the Maui, Maari-Manaia and Tui Area fields in offshore Taranaki Basin contain low concentrations of Re (0.18–0.45 ppb) and 192Os (1.3–12.7 ppt) comparable to their correlated Late Cretaceous coaly source rocks (Rakopi and North Cape formations; Re 0.19–0.37 ppb, 192Os 5.3–9.6 ppt). The Re and 192Os concentrations in these terrestrial oils are generally one to two orders of magnitude lower than those in marine-sourced oils from the Kora Field in offshore Taranaki Basin and surface seeps in East Coast Basin.The 187Re/188Os and 187Os/188Os ratios of the terrestrial oils failed to yield a precise Re–Os isochron age. We attribute this to: (1) insufficient homogenisation of oils with widely variable initial 187Os/188Os (Osi) values inherited from thick, coaly source rock intervals (up to about 2700 m) within the Maui sub-basin and northern Kahurangi Trough kitchens; (2) insufficient spread of 187Re/188Os values (only 275 units); (3) insufficient time since oil expulsion (modelled to be from approximately 10 Ma to the present day) for the evolution of an isochron; and (4) possible effects of water washing of the oil columns. Although all of the studied oils are water-washed to varying degrees, there is no definitive evidence that water washing has disturbed the Re–Os systematics.The Osi values for the studied terrestrial oils inherited at the modelled time of oil expulsion (approximately 10 Ma) display a wide range (0.47–1.14) and do not provide a unique fingerprint of their Late Cretaceous coaly source rock formations. Osmium isotope compositions therefore appear to have limited potential for broad oil-source rock correlation within the predominantly coal-sourced petroleum systems of Taranaki Basin. The Osi values may, however, provide useful distinction of the terrestrial oils emanating from the Kahurangi Trough (Tui Area oils) from those of the Maui sub-basin (Maui and Maari-Manaia oils) based on the significantly more radiogenic values of the Tui Area oils (0.84–1.14 compared with 0.47–0.65 from Maui and Maari-Manaia oils). Overall, this study has provided useful insights into the potential application of the Re–Os isotope system to terrestrial, coal-sourced petroleum systems.

Source and thermal maturity assessment of the Paleozoic-Mesozoic organic matter in the Risha gas field, Jordan

Detailed geochemical analyses of the Lower Silurian-Cretaceous shales in the Risha Field were carried out to determine their source input (marine or terrigenous), paleoenvironment, maturity, and hydrocarbon generation potential for their contributions to the gas field. The Lower Silurian shales are believed to be effective source rocks for oil within the Paleozoic petroleum system in the Risha field. Furthermore, the Upper Cretaceous shales have high hydrocarbon potentials and are considered as a promising source for oil and gas. The Upper Ordovician, Lower Silurian and Upper Cretaceous shales in the study area were deposited in a marine anoxic environment, resulting in the accumulation of highly liptinitic organic matters derived from algae and bacteria (Type II kerogen). The maturity of the Lower Silurian source rocks increases from the oil window to the gas window. Ordovician shales have reached the over maturity stage. Current hydrogen index (HI) values for the Silurian organic matter are relatively low after significant hydrocarbon production and expulsion. Two oil types are found from the standard petroleum geochemical analyses of the studied shales: naphthenic oil from immature Cretaceous black shales and high maturity paraffinic oils from Lower Silurian and Ordovician layers. The thermal history model of the Lower Paleozoic source rocks reveals that the Lower Silurian shales reached the dry gas generation stage 280–250 million years ago during Early Triassic, suggesting the large volume of gas accumulated in the Risha field mainly from the Silurian source rocks.

Prediction of multiscale laminae structure and reservoir quality in fine-grained sedimentary rocks: The Permian Lucaogou Formation in Jimusar Sag, Junggar Basin

Fine-grained sedimentary rocks have become a research focus as important reservoirs and source rocks for tight and shale oil and gas. Laminae development determines the accumulation and production of tight and shale oil and gas in fine-grained rocks. However, due to the resolution limit of conventional logs, it is challenging to recognize the features of centimeter-scale laminae. To close this gap, complementary studies, including core observation, thin section, X-ray diffraction (XRD), conventional log analysis, and slabs of image logs, were conducted to unravel the centimeter-scale laminae. The laminae recognition models were built using well logs. The fine-grained rocks can be divided into laminated rocks (lamina thickness of <0.01 m), layered rocks (0.01–0.1 m), and massive rocks (no layer or layer spacing of >0.1 m) according to the laminae scale from core observations. According to the mineral superposition assemblages from thin-section observations, the laminated rocks can be further divided into binary, ternary, and multiple structures. The typical mineral components, slabs, and T 2 spectrum distributions of various lamina types are unraveled. The core can identify the centimeter–millimeter-scale laminae, and the thin section can identify the millimeter–micrometer-scale laminae. Furthermore, they can detect mineral types and their superposition sequence. Conventional logs can identify the meter-scale layers, whereas image logs and related slabs can identify the laminae variations at millimeter–centimeter scales. Therefore, the slab of image logs combined with thin sections can identify laminae assemblage characteristics, including the thickness and vertical assemblage. The identification and classification of lamina structure of various scales on a single well can be predicted using conventional logs, image logs, and slabs combined with thin sections. The layered rocks have better reservoir quality and oil-bearing potential than the massive and laminated rocks. The laminated rocks’ binary lamina is better than the ternary and multiple layers due to the high content of felsic minerals. The abovementioned results build the prediction model for multiscale laminae structure using well logs, helping sweet spots prediction in the Permian Lucaogou Formation in the Jimusar Sag and fine-grained sedimentary rocks worldwide.

Geochemical and Petrological Characterization of the Early Eocene Carbonaceous Shales: Implications for Oil and Gas Exploration in the Barmer Basin, Northwest India.

Carbonaceous shales of the Early Eocene Dharvi/Dunger Formation in the onshore Barmer Basin, northwest India were studied for the first time by integrating geochemical and organic petrological analyses. The carbonaceous shales of the Early Eocene Dharvi/Dunger Formation are characterized by a higher organic carbon content (TOC) of >10 wt % and consist mainly of a mixture of organic matter of types II and III kerogen, with exhibited hydrogen index values ranging between 202 and 292 mg HC/g TOC. The dominance of such kerogen is confirmed by the high amounts of huminite and fluorescent liptinite macerals. Consequently, the carbonaceous shales of the Early Eocene Dharvi/Dunger Formation are promising source rocks for both oil and gas generation potential, with oils of high wax contents, according to pyrolysis-gas chromatography results. The chemical and optical maturity results such as low values huminite/vitrinite reflectance, production index, and T max show that most of the examined carbonaceous shale rocks from the outcrop section of the Kapurdi mine have entered the low maturity stage of oil generation, exhibiting a range of immature to the very early-mature. Therefore, as highlighted in this study, the substantial abundance in hydrocarbon generation potential from these carbonaceous shales in the Dharvi/Dunger Formation may represent future conventional petroleum exploration in the southern part of the Barmer Basin, where the Dharvi/Dunger Formation has reached deeper burial depths.

Rearranged oleananes in Tertiary oils from the Baiyun Sag, Pearl River Mouth Basin, South China Sea: identification, distribution and geochemical significance

Three abundant rearranged oleananes detected in Tertiary oils from the Baiyun Sag, South China Sea, were designated as 5(4 → 3) abeo-3α(H), 5β(H), 18α(H)-oleanane (I), 3α, 5β-dimethyl-23α, 25-dinor-10β(H), 18α(H)-oleanane (II) and 1(10 → 5)abeo-3β-methyl-24β-nor-18α(H)-oleanane (III), using gas chromatography-mass spectrometry (GC–MS) and GC–MS–MS. The relative abundances of different rearranged oleananes correlated with each other, and also showed strong positive correlations with those of oleanane or des-A-oleanane. This is consistent with rearranged oleananes, oleanane (OL) and des-A-oleanane originating from functionalized oleanane triterpenoids, but by different formation processes. The distribution of rearranged oleananes in oils from the study area is controlled mainly by angiosperm inputs and the diagenetic conditions of their source rocks, rather than thermal maturity. Oligocene marine transgression in the study area may have played an important role in the expression of saturated oleanoids. Moreover, oxic and acidic peat swamp conditions in the Panyu Low Uplift favoured the formation of rearranged oleananes compared to oleananes. In addition, oils from the Baiyun Sag can be classified into two oil families, i.e., A and B, using the relative abundance of rearranged oleananes and other source-related indicators. The Family A oils in the eastern and northeastern portions of the sag are characterized by relatively low pristane/phytane (Pr/Ph) ratios, low rearranged oleananes/oleanane ((I + II + III)/OL) and bicadinane-T/C30 hopane (T/C30H) ratios. The Family B oils in the Panyu Low Uplift and northeastern portion of the sag have higher Pr/Ph, (I + II + III)/OL and T/C30H ratios. The related parameters of rearranged oleananes were therefore shown to be effective indicators for oil-oil or oil-source rock correlation in the study area.

Water-Based Drilling Fluid Helps Control Extreme Conditions in Gas Shale Play

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 208307, “A Water-Based Drilling Fluid for Controlling Deep-Reservoir Extreme Conditions in an Abu Dhabi Gas Shale Play,” by Gabe Manescu, SPE, Schlumberger; Balazs Veer, SPE, TotalEnergies; and Panamarathupalayam Balakrishnan, SPE, Schlumberger, et al. The paper has not been peer reviewed. _ A combination of teamwork and fluids technology proved to be the formula for successfully drilling in high-pressure/high-temperature (HP/HT) conditions for an onshore UAE shale gas play. The success achieved in drilling deep [6200-m measured depth (MD)], long-lateral-displacement (2,000-m) wells with an integrated global operator is a combination dependent on frequent, transparent communication between team members. The environmentally acceptable aqueous drilling fluid delivered a barite sag-free operation in these highly deviated wellbores. Introduction The drilling of unconventional HP/HT wells in the Diyab field can experience difficulty in reaching target depth. One significant challenge is the design of a drilling fluid to manage reservoir pressures and temperatures. The reservoir temperature may reach 165.5°C, requiring mud weights (MW) greater than 20 lbm/gal. Tailoring the drilling-fluid formulation to balance economics and environmental regulations while overcoming HP/HT conditions is critical. In the Diyab drilling campaign, special emphasis was placed on designing the drilling fluid and then on its use in 8½-in. reservoir sections. Background The Upper Jurassic (Oxfordian to Middle Kimmeridgian) Diyab formation, also known as the Dukhan formation, has served as the source rock for several major oil and gas fields in the Middle East. The Diyab formation is unique because of its lower porosities, high carbonate mineralogy, and pressure gradient. Despite the lower porosity, the high-carbonate content defines an extremely brittle target conducive to hydraulic fracture stimulation. Several organic-rich intervals exist throughout the Diyab formation and are separated by less-organic tight limestones, which create different flow units. From a developmental perspective, this condition has the potential to create a high-impact stacked play. The extent of the prospective unconventional Diyab formation within the UAE is limited to the onshore north-central UAE, where most of this area is within Block 1, operated by TotalEnergies. The depth of the prospective basal Diyab interval across Block 1 ranges between 3758 and 4115 m. Three unconventional offset wells (DE-02, DE-03, and DE-04) were drilled by ADNOC within Block 1 to test the productivity of the three submembers of the greater Diyab interval (the Jubaila, Hanifa, and Tuwaiq Mountain formations). After determining that the Hanifa formation had the most-promising productivity, the first TotalEnergies appraisal horizontal well, DE-05, was drilled. After drilling this well, the DE-06 well was the second horizontal appraisal well to be drilled. Additionally, two more deep wells, DE-09 and DE-10, were successfully drilled and evaluated.

Geochemical Characteristics of the Chang 7 Source Rocks of the Triassic Yanchang Formation in Ordos Basin, China: Implications for Organic Matter Accumulation and Shale Oil Potential

The Chang 7 member of the Upper Triassic Yanchang Formation in the Ordos Basin is considered to hold the main source rocks for conventional and unconventional oil and gas. The lamination or lithology alteration in vertical and lateral directions, even over a short distance, is a common feature in lacustrine source rocks. The differences in the geochemical characteristics of black shales, dark mudstones and interbedded sandstones have been scarcely reported, and their influences on the petroleum generation potential and shale oil potential are not clear. To this end, 22 core samples were collected from the Lower and Middle Chang 7 (C7-3 and C7-2) members of the Triassic from well CYX in the Qingcheng area. By conducting a series of geochemical analyses including TOC, Rock-Eval pyrolysis yields, bitumen extraction and quantification, and the separation and quantification of saturates, aromatics, resins and asphaltenes, along with biomarker analyses, several results were found. Firstly, the C7-3 and C7-2 source rocks are thermally mature and have entered into the stage of hydrocarbon generation. The C7-3 and C7-2 source rocks have a good to very good hydrocarbon generation potential especially the C7-3 black shales. Secondly, terrigenous source input is more abundant in C7-2, whereas the source input of phytoplankton, algae or microbial lipids is more abundant in C7-3. Moreover, a high TOC content basically corresponds to low wax indexes, terrigenous/aquatic ratios (TARs), and Pr/nC17 and Ph/nC18 ratios and high C27/C29 regular sterane ratios, which suggests that the source input of phytoplankton, algae or microbial lipids is favorable for OM accumulation. Third, analyses of the molecular composition of saturated fractions in shales and interbedded sandstones and the production index demonstrate the migration of petroleum from organic-rich source rocks to their organic-lean counterparts. The C7-2 dark mudstones could be considered as a potential “sweet spot” since their oil saturation index (OSI) was the highest among all the studied samples and they are more enriched in light aliphatic fractions.

Using proppant indentation coefficient in design of hydraulic fracturing treatment of oil source rocks

The purpose of the study is the laboratory determination of proppant indentation coefficients depending on the geological composition of the oil source rocks and their application in the design of hydraulic fracturing treatment. The laboratory researches used the core material of oil-producing deposits of the Domanic formation. The indentation of prop pant was carried out on the CTM-100 compression testing machine, in order to eliminate the measurement error, the size of the cells was additionally specified using ADF U300P microscope with the operation capacity either in reflected light or reflected and transmitted light only. As a result, the geological features of the Domanic complex were confirmed: a large content of organic matter was traced on the core material, the bulk of the rock was composed of carbonates with frequent lithological layering. The indentation coefficient of 20/40 proppan were as following: 0.2–0.4 mm in limestones, 0.23–0.45 mm in clay limestones, 0.47 mm for organic matter. The indentation coefficients for 30/50 proppant were as follows: 0.1– 0.5 mm in limestones, 0.13–0.55 mm in clay limestones, 0.47 mm in organic matter. The use of the obtained coefficients in the design of hydraulic fracturing treatment allowed to specify the fixed width of the crack opening that will have a positive effect on the predicted starting well yield under subsequent modeling. The proppant indentation is in direct relationship to the composition of the oil-producing rocks. When using the proppant coefficients it is advisable to pay additional attention to the proppant tracking map. The use of laboratory studies with subsequent modeling in the hydraulic fracturing simulator allows more accurate understanding of the fixed geometry of the crack of the formation fracturing. Estimation of the crack opening width at the stage of hydraulic fracturing design makes it possible to adapt the parameters of formation treatment, which has a positive effect on the lifetime of the crack width as well as on the well yield.

Organic geochemistry and oil-source rock correlation of the Cretaceous succession in West Wadi El-Rayan (WWER) concession: Implications for a new Cretaceous petroleum system in the north Western Desert, Egypt

Mesozoic rift basins of the north Western Desert host the majority of proven oil reserves in Egypt. These basins are bounded by poorly-explored structural highs (Kattaniya high, Qattara ridge) with unknown petroleum system. The recently-discovered oil in West Wadi El-Rayan (WWER) concession in the southern part of the Kattaniya high highlighted a need for understanding the petroleum potential of these transit regions. The present study integrates geochemical and basin modelling results to define potential source rocks and decipher the mechanism of oil generation, expulsion and migration. In WWER concession, oil is produced from the Upper Cretaceous (Upper Bahariya) sandstones. Rock-Eval pyrolysis results demonstrate that the Lower Cretaceous Alam El Bueib (AEB) and Upper Cretaceous Lower Bahariya shales below the reservoir contain mature source rocks (S2 up to 28.76, Tmax > 430 °C). WWER oil displays a uniform composition with high pristane/phytane (Pr/Ph > 3), saturates/aromatics (>5.5) and canonical variable values (CV > 6) pointing to a generation from a terrestrial source rock. This is consistent with high contents of C30 hopane, C29 steranes and diasteranes as well as the very low values of dibenzothiophane (DBT)/Phenantherane (<0.1) confirming oil generation from a clay-rich source rock deposited in a fluvio-deltaic environment.Oil-source correlation highlights a robust similarity in compositional biomarkers between the WWER oil and AEB rock extracts. Additionally, the maturity-relevant biomarkers such as Ts/Tm trisnorhopanes and H32 S/(R + S) homohopanes favor an oil expulsion phase during the early stage of oil window in accordance with the basin modelling results and the maturity level of AEB organic-rich facies. These findings shed the light on a new petroleum system in the north Western Desert where the AEB fluvio-deltaic shales are capable of generating early mature oil which migrates through the Cretaceous deep-seated extensional faults into the Bahariya sandstone reservoir.

Evaluating novel trace element proxies for oil-source rock correlations

油源对比微量元素地球化学示踪是油气地球化学领域的前沿科学问题。以准噶尔盆地二叠系风城组碱湖含油气系统为例，对此进行了探索研究。通过对烃源岩和原油样品的微量元素组成进行电感耦合等离子体质谱（ICP–MS）分析和系统对比，发现检出的33个常见微量元素中，过渡族金属元素（Ti、V、Cr、Ni、Cu、Zn、Mn和Zr）、碱土金属元素（Sr和Ba）和非金属元素（B和As）在烃源岩与原油间具有较好的继承性，展示出油源对比意义，但由源到油，元素浓度下降0.3–1141倍，差异富集特征显著，表明不能直接简单应用于油源对比。分析认为，微量元素在从源到油的差异富集主要受控于微量元素以有机（螯）络合物或无机盐离子形式在有机质成烃演化与成藏过程中的动态分配。具体而言，Ni和部分V以N-Ni/V键合于卟啉化合物，受油气运移影响小，相对稳定；大部分V以难溶矿物相赋存，油气初次运移时优先富集于烃源岩；Cr、Cu和Zn与有机酸中O/S原子络合，但在油气二次运移过程中化学键容易破裂；Mn、Zr、Ti、Sr和Ba主要以矿物相赋存于烃源岩中，在油气运移中以离子形式存在，易受油-岩相互作用发生离子交换；B以矿物相赋存于烃源岩中，但在初次运移时易与有机酸络合且受二次运移影响有限；As主要以砷化物或砷酸根离子赋存，受二次运移影响较大。据此，Ni、V、B、Cr、Cu、Zn和As具有较好的示踪意义，形成了4组参数：Ni浓度进行油源对比、Cr–Cu+Zn–As三端元图示踪二次运移、V/Ni和Ni/B示踪初次运移。油气形成演化过程中的元素地球化学行为复杂，可在深入剖析后遴选有效参数应用于油气示踪，是经典有机地球化学方法的有效补充。

On the fundamental possibility of using the bacterial and catagenetic hypotheses of the origin of oil in assessing its resources

Research subject. The estimations of oil resources in Western Siberia obtained using a basin modeling of the Bazhenov formation as an oil source stratum indicated a significant deficit of its potential, calculated based on the pyrolytic kinetic parameters of catagenesis. Aim. To search for possible additional oil generating mechanisms parallel to catagenesis, thus clarifying the conceptual foundations of the modern theory of the organic origin of oil. Key points. Based on a review of literature publications, a hypothesis was formulated about the evolution of organic matter from sedimentary flow floccules to the injection of proto-oil into the microcracks of the autofluid fracturing of source rocks. In the upper unconsolidated bottom sediment layers, biofilms appear whose microbial matrix forms a basis for future kerogen. Proto-oil bitumoids appear as a by-product of biofilm microbial metabolism under the anaerobic conditions at diagenesis stage. Рroto-oil bitumoids are encapsulated and absorbed on the surfaces and inside the chambers and conducting channels of the biofilm polymer matrix (future kerogen). Local ultra-high pressure (LUHP) inside kerogen grains appears at the final “smectite – illite” transition stage of host clays, acting as a driving force for encapsulated bitumoid expulsion from kerogen grains. On the walls of microcracks, proto-oil bitumoids undergo hydropyrolysis, consuming cohesive film water and changing the surface philicity. Microphotographs and SEM images of thin sections are provided in order to illustrate LUHP-expulsion traces. Two types of oil source rocks are differentiated based on the possibility of proto-oil LUHP expulsion: those with a plastic mineral framework and a rigid mineral framework. Conclusion. The presence of porous spaces filled with bitumoids was established in the kerogen of immature potentially oil source rocks. This mass of encapsulated bitumoids is an additional resource of oil generation within the “oil window”. Their expulsion volume can be estimated and attributed to a certain temperature range. Directions for further research are outlined.