Petroleum accumulation in the deeply buried reservoirs in the northern Dongying Depression,Bohai Bay Basin,China: New insights from fluid inclusions,natural gas geochemistry,and 1-D basin modeling

The deeply buried reservoirs (DBRs) from the Lijin, Shengtuo and Minfeng areas in the northern Dongying Depression of the Bohai Bay Basin, China exhibit various petroleum types (black oil-gas condensates) and pressure systems (normal pressure-overpressure) with high reservoir temperatures (154–185 °C). The pressure-volume-temperature-composition (PVTX) evolution of petroleum and the processes of petroleum accumulation were reconstructed using integrated data from fluid inclusions, stable carbon isotope data of natural gas and one-dimensional basin modeling to trace the petroleum accumulation histories.The results suggest that (1) the gas condensates in the Lijin area originated from the thermal cracking of highly mature kerogen in deeper formations. Two episodes of gas condensate charging, which were evidenced by the trapping of non-fluorescent gas condensate inclusions, occurred between 29-25.5 Ma and 8.6–5.0 Ma with strong overpressure (pressure coefficient, P_c = 1.68–1.70), resulting in the greatest contribution to the present-day gas condensate accumulation; (2) the early yellow fluorescent oil charge was responsible for the present-day black oil accumulation in well T764, while the late blue-white oil charge together with the latest kerogen cracked gas injection resulted in the present-day volatile oil accumulation in well T765; and (3) the various fluorescent colors (yellow, blue-white and blue) and the degree of bubble filling (F_v) (2.3–72.5%) of the oil inclusions in the Minfeng area show a wide range of thermal maturity (API gravity ranges from 30 to 50°), representing the charging of black oil to gas condensates. The presence of abundant blue-white fluorescent oil inclusions with high Grain-obtaining Oil Inclusion (GOI) values (35.8%, usually >5% in oil reservoirs) indicate that a paleo-oil accumulation with an approximate API gravity of 39–40° could have occurred before 25 Ma, and gas from oil cracking in deeper formations was injected into the paleo-oil reservoir from 2.8 Ma to 0 Ma, resulting in the present-day gas condensate oil accumulation. This oil and gas accumulation model results in three oil and gas distribution zones: 1) normal oil reservoirs at relatively shallow depth; 2) gas condensate reservoirs that originated from the mixture of oil cracking gas with a paleo-oil reservoir at intermediate depth; and 3) oil-cracked gas reservoirs at deeper depth.The retardation of organic matter maturation and oil cracking by high overpressure could have played an important role in the distribution of different origins of gas condensate accumulations in the Lijin and Minfeng areas. The application of oil and gas accumulation models in this study is not limited to the Dongying Depression and can be applied to other overpressured rift basins.     

Synthetic saline-aqueous and hydrocarbon fluid inclusions trapped in calcite at temperatures and pressures relevant to hydrocarbon basins: A reconnaissance study

We conducted reconnaissance experiments to synthesize aqueous and hydrocarbon inclusions trapped in calcite at conditions relevant to petroleum basins, and characterize the microthermometric properties of such inclusions. Fluid inclusions (FIs) were synthesized in a system of saline aqueous solution (5 or 20 wt% NaCl) coexisting with either heavy crude oil or gasoline under gas-undersaturated conditions, from 90 to 210 °C and 200–550 bar. The synthetic inclusions are not representative of gas-bearing systems, and methane (CH₄) was not detected in any aqueous inclusions. The FIs are mainly distributed along planar healed cracks, indicating that the inclusions formed by fracture healing in the calcite crystal. Microthermometric measurements were conducted on coeval aqueous and hydrocarbon inclusions, and Raman spectroscopic analyses were done on aqueous inclusions, to determine the properties of FIs trapped at these conditions.Homogenization temperatures of synthetic FIs are mostly lower than the experimental trapping temperature, although the FIs show high variability in measured homogenization temperature. Results allow comparison of T_h values for each sample with the expected T_h, isochores and pressure corrections calculated for the system H₂ONaCl. The latter parameters are broadly consistent with the known PVTX properties of H₂ONaCl fluids, suggesting little effect of hydrocarbons on the homogenization behavior, although the low precision of the T_h data limits this assessment. Nevertheless, this result is not unexpected considering that light hydrocarbons (gas) is not present in the experiments (as corroborated by Raman spectroscopy), a consequence of using “dead” oil in the experiments. Simulation of gas-bearing petroleum basins will require additional protocols for producing gas, either by in-situ cracking of the starting hydrocarbon material, or by other means. The reconnaissance experiments documented here provide a basis for such future experiments.     

Khasib and Tannuma oil sources, East Baghdad oil field, Iraq

This work presents new insights of the generation, quality and migration pathways of the hydrocarbons in the East Baghdad Oil Field.The Khasib and Tannuma formations in East Baghdad are considered as oil reservoirs according to their high porosity (15-23%) and permeability (20-45 mD) in carbonate rocks. The hydrocarbons are trapped by structural anticline closure trending NW-SE. Gas chromatography analysis on these oil reservoirshave shown biomarkers of abundant ranges of n-alkanes of less than C22 (C17-C21) with C19 and C18 peaks. This suggests mainly liquid oil constituents of paraffinic hydrocarbons from marine algal source of restricted palaeoenvironments in the reservoir. The low non aromatic C15 + peaks are indicative for slight degradation and water washing. Oil biomarkers of Pr./Ph. = 0.85, C31/C30 < 1.0, location in triangle of C27-C29 sterane, C28/C29 of 0.6 sterane, Oleanane of 0.01 and CPI = 1.0, indicate an anoxic marine environment with carbonate deposits of Upper Jurassic to Early Cretaceous age. Four Miospores, seven Dinoflagellates and one Tasmanite species confirm affinity to the upper most Jurassic to Lower Cretaceous Chia Gara and Ratawi Formations.The recorded palynomorphs from the Khasib and Tannuma Formations are of light brown color of TAI = 2.8-3.0 and comparable to the mature palynomorphs that belong to the Chia Gara and the Lower part of Ratawi Formations.The Chia Gara Formation generated oil during Upper Cretaceous to Early Palaeogene and accumulated in structural traps of Cretaceous age, such as the Khasib and Tannuma reservoirs. The Chia Gara Formation generated and expelled high quantities of oil hydrocarbons according to their TOC wt% of 0.5-8.5 with S2 = 2.5-18.5 mg Hc/g Rock, high hydrogen index of the range 150-450 mg Hc/g Rock, good petroleum potential of 4.5-23.5 mg Hc/g Rock, mature (TAI = 2.8-3.0 and T_max = 428-443C), kerogen type II and palynofacies parameters of up to 100% AOM (Amorphous Organic Matters). This includes algae deposits in a dysoxic-anoxic to suboxic-anoxic environment.Alternative plays are discussed according to the migration pathways.     

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. T_max plot indicate prevalence of Type II to Type III kerogen. T_max measurements ranged from 425 °C to 439 °C, indicating immature to early mature stage, which was confirmed by the mean vitrinite reflectance values (%R_o 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.     

Characteristics and petroleum origin of the Carboniferous volcanic rock reservoirs in the Shixi Bulge of Junggar Basin,western China

Shixi Bulge of the central Junggar Basin in western China is a unique region that provides insight into the geological and geochemical characteristics of large-scale petroleum reservoirs in volcanic rocks of the western Central Asian Orogenic Belt. Carboniferous volcanic rocks in the Shixi Bulge mainly consist of striped lava and agglomerate, as well as breccia lava and tight tuff. Volcanic rocks differ in porosity and permeability. Striped lava exhibits the highest porosity (average: 14.2%) but the lowest permeability (average: 0.67 × 10⁻¹⁵ m) among the rock types. Primary gas pores are widely developed and mostly filled. Secondary dissolution pores and fractures are two major reservoir storage spaces. Capillary pressure curves suggest the existence of four pore structure types of reservoir rocks. Several factors, namely, lithology, pore structure, and various diagenesis, govern the physical properties of volcanic rocks. The oil is characterized by a high concentration of tricyclic terpane, a terpane distribution of C₂₃ < C₂₁ > C₂₀, and sterane distributions of C₂₇ < C₂₈ < C₂₉ and C₂₇ > C₂₈ < C₂₉. Oil and gas geochemistry revealed that the oil is a mixture derived primarily from P₂w source rock and secondarily from P₁j source rock in the sag west of Pen-1 Well. The gases are likely gas mixtures of humic and sapropelic organic origins, with the sapropelic gas type dominant in the mixture. The gas mixture is most likely cracked from kerogen rather than oils. The Carboniferous volcanic reservoirs in Shixi Bulge share some unique characteristics that may provide useful insights into the various roles of different volcanic reservoir types in old volcanic provinces. The presence of these reservoirs will undoubtedly encourage future petroleum exploration in volcanic rocks up to the deep parts of sedimentary basins.     

Enrichment and distribution of shale oil in the Cretaceous Qingshankou Formation,Songliao Basin,Northeast China

The Songliao Basin is a large-scale petroliferous basin in China. With a gradual decline in conventional oil production, the exploration and development of replacement resources in the basin is becoming increasingly important. Previous studies have shown that the Cretaceous Qingshankou Formation (K₂qn) has favorable geological conditions for the formation of shale oil. Thus, shale oil in the Qingshankou Formation represents a promising and practical replacement resource for conventional oil. In this study, geological field surveys, core observation, sample tests, and the analysis of well logs were applied to study the geochemical and reservoir characteristics of shales, identify shale oil beds, build shale oil enrichment models, and classify favorable exploration areas of shale oil from the Cretaceous Qingshankou Formation. The organic matter content is high in shales from the first member of the Cretaceous Qingshankou Formation (K₂qn¹), with average total organic carbon (TOC) content exceeding 2%. The organic matter is mainly derived from lower aquatic organisms in a reducing brackish to fresh water environment, resulting in mostly type I kerogen. The vitrinite reflectance (Ro) and the temperature at which the maximum is release of hydrocarbons from cracking of kerogen occurred during pyrolysis (T_max) respectively range from 0.5% to 1.1% and from 430 °C to 450 °C, indicating that the K₂qn¹ shales are in the low-mature to mature stage (Ro ranges from 0.5% to 1.2%) and currently generating a large amount of oil. The favorable depth for oil generation and expulsion is 1800–2200 m and 1900–2500 m, respectively as determined by basin modeling. The reserving space of the K₂qn¹ shale oil includes micropores and mircofractures. The micropore reservoirs are developed in shales interbedded with siltstones exhibiting high gamma ray (GR), high resistivity (Rt), low density (DEN), and slightly abnormal spontaneous potential (SP) in the well-logging curves. The microfracture reservoirs are mainly thick shales with high Rt, high AC (acoustic transit time), high GR, low DEN, and abnormal SP. Based on the shale distribution, geochemical characteristics, reservoir types, fracture development, and the process of shale oil generation and enrichment, the southern Taikang and northern Da'an are classified as two favorable shale oil exploration areas in the Songliao Basin.     

Timing and mechanism of reservoir forming in the Upper Triassic Halahatang Formation,Yuqi block,Tarim Basin,northwestern China

The Yuqi block is an important area for oil and gas exploration in the northern Akekule uplift, Tarim Basin, northwestern China. The Upper Triassic Halahatang Formation (T₃h) within the Yuqi block can be subdivided into a lowstand system tract (LST), a transgressive system tract (TST), and a highstand system tract (HST), based on a study of initial and maximum flood surfaces. Oil in the lowstand system tract of the Halahatang Formation is characterized by medium to lightweight (0.8075 g/cm³–0.9258 g/cm³), low sulfur content (0.41%–1.4%), and high paraffin content (9.65%–10.25%). The distribution of oil and gas is principally controlled by low-amplitude anticlines and faults. Based on studies of fluorescence thin sections and homogenization temperatures of fluid inclusions, reservoirs in the T₃h were formed in at least two stages of hydrocarbon charge and accumulation. During the first stage (Jurassic–Cretaceous) both the structural traps and hydrocarbon reservoirs were initiated; during the second stage (Cenozoic) the structural traps were finally formed and the reservoirs were structurally modified. The reservoir-forming mechanism involved external hydrocarbon sources (i.e. younger reservoirs with oil and gas sourced from old rocks), two directions (vertical and lateral) of expulsion, and multi-stage accumulation. This model provides a theoretical fundament for future oil and gas exploration in the Tarim Basin and other similar basins in northwestern China.     

Interaction of coal and oil in confined pyrolysis experiments: Insight from the yield and composition of gas hydrocarbons

Isothermal pyrolysis experiments were performed for coal alone, oil alone and coal plus oil with oil/coal ratios ranging from 0.0065 to 0.1995 at 305 °C and 50 MPa for 72 h in confined systems (gold capsules). The results of these experiments reveal the interaction between coal and oil, demonstrating that oil retards the generation of gas hydrocarbons from coal cracking while coal accelerates oil cracking into gas hydrocarbons. The yields of gas hydrocarbons vary greater with oil/coal ratio in the experiments of coal B plus oil than coal A plus oil because coal A has a higher HI value than does coal B. Oil cracking rate could increase by up to 10 or even higher times in the experiments of coal plus oil compared with oil alone, deduced from the yields and chemical compositions of gas hydrocarbons. This result suggests that gas hydrocarbons, especially wet gases were largely generated from the cracking of oil or extractable bitumen in the experiments of coal plus oil with oil/coal ratio higher than 0.1.     

Geochemistry,origin, and accumulation of petroleum in the Eocene Wenchang Formation reservoirs in Pearl River Mouth Basin,South China Sea: A case study of HZ25-7 oil field

The Pearl River Mouth Basin in the South China Sea has accumulated >2 km of Eocene sediments in its deep basin, and has become the exploration focus due to the recent discoveries of the HZ25-7 oil field in the Eocene Wenchang (E₂w) Formation. In this study, the geochemical characteristics of potential source rocks and petroleum in the HZ25-7 oil field are investigated and the possible origins and accumulation models developed. The analytical results reveal two sets of potential source rocks, E₂w and Enping (E₂e) formations developed in the study area. The semi-deep-to-deep lacustrine E₂w source rocks are characterized by relatively low C₂₉ steranes, low C₁₉/C₂₃ tricyclic terpane (<0.6), low C₂₄ tetracyclic terpane/C₃₀ hopane (<0.1), low trans-trans-trans-bicadinane (T)/C₃₀ hopane (most <2.0), and high C₃₀ 4-methyl sterane/ΣC₂₉ sterane (>0.2) ratios. In contrast, the shallow lacustrine and deltaic swamp-plain E₂e source rocks are characterized by relatively high C₂₉ steranes, high C₁₉/C₂₃ tricyclic terpane (>0.6), high C₂₄ tetracyclic terpane/C₃₀ hopane (>0.1), variable yet overall high T/C₃₀ hopane, and low C₃₀ 4-methyl sterane/ΣC₂₉ sterane (<0.2) ratios. The relatively low C₁₉/C₂₃ tricyclic terpane ratios (mean value: 0.39), low C₂₄ tetracyclic terpane/C₃₀ hopane ratios (mean value: 0.07), high C₃₀ 4-methyl sterane/ΣC₂₉ sterane ratios (mean value: 1.14), and relatively high C₂₇ regular sterane content of petroleum in the HZ25-7 oil field indicate that the petroleum most likely originated from the E₂w Formation mudstone in the Huizhou Depression. One stage of continuous charging is identified in the HZ25-7 oil field; oil injection is from 16 Ma to present and peak filling occurs after 12 Ma. Thin sandstone beds with relatively good connectivity and physical properties (porosity and permeability) in the E₂w Formation are favorable conduits for the lateral migration of petroleum. This petroleum accumulation pattern implies that the E₂w Formation on the western and southern margins of the Huizhou Depression are favorable for petroleum accumulation because they are located in a migration pathway. Thus exploration should focus in these areas in the future.     

Hydrocarbon migration and accumulation of the Suqiao buried-hill zone in Wen'an Slope,Jizhong Subbasin,Bohai Bay Basin,China

The hydrocarbon migration and accumulation of the Suqiao deep buried-hill zone, in the Jizhong Subbasin, the Bohai Bay Basin, eastern China, was investigated from the perspective of paleo-fluid evidence by using fluid inclusions, quantitative fluorescence techniques (QGF), total scanning fluorescence method (TSF) and organic geochemical analysis. Results show that the current condensate oil-gas reservoirs in the study area once were paleo-oil reservoirs. In addition, the reservoirs have experienced at least two stages of hydrocarbon charge from different sources and/or maturities. During the deposition of the Oligocene Dongying Formation (Ed), the deep Ordovician reservoirs were first charged by mature oils sourced from the lacustrine shale source rocks in the fourth member of Shahejie and Kongdian Formations (Es₄+Ek), and then adjusted at the end of Ed period subsequently by virtue of the tectonic movement. Since the deposition of the Neogene Minghuazhen Formation (Nm), the reservoirs were mainly charged by the gas that consisted of moderate to high-maturity condensate and wet gas sourced from the Es₄+Ek lacustrine shale source rocks and mature coal-derived gas sourced from the Carboniferous-Permian (C-P) coal-bearing source rocks. Meanwhile, the early charged oil was subjected to gas flushing and deasphalting by the late intrusion of gas. The widely distributed hydrocarbon inclusions, the higher QGF Index, and FOI (the frequency of oil inclusions) values in both gas-oil and water zone, are indicative of early oil charge. In addition, combined with the homogenization temperatures of the fluid inclusions (<160 °C) and the existence of solid-bitumen bearing inclusions, significant loss of the n-alkanes with low carbon numbers, enrichments of heavier components in crude oils, and the precipitation of asphaltene in the residual pores suggest that gas flushing may have played an important role in the reservoir formation.     

Identification of polycyclic sulfides hexahydrodibenzothiophenes and their implications for heavy oil accumulation in ultra-deep strata in Tarim Basin

Heavy oil accumulation in deep Ordovician carbonate stratum was discovered at present burial depths greater than 6600 m in the northern Tarim Basin, NW China. Density of the unusual ultra-deep heavy oils is greater than 0.92 g/cm³ at 20 °C. Crude oil produced from 6598 to 6710 m interval of the Ha9 well was selected for the thiophenic and sulfidic compounds characterization in order to understand the mechanism of heavy oil accumulation in the ultra-deep strata. In addition to the common thiophenic compounds, four homologues of novel polycyclic sulfides named as 1,1,4a,6-tetramethyl-9-alkyl-1,2,3,4,4a,9b-hexahydrodibenzothiophenes (H₆DBTs, 9-alkyl = H, methyl, ethyl, and propyl, respectively) were identified in Ha9 well crude oil, and it is the first time these biomarkers were detected in natural occurrence. H₆DBTs were generated from isoprenoid-related precursors reacted with reduced-state sulfur in early diagenesis stage by bacterial sulfate reduction. The occurrence of H₆DBTs further indicated biodegradation of the reservoir oil at a relatively mild temperature (60–65 °C), a favorable condition for microorganism survival. According to the history of reservoir forming, oil and gas accumulation occurred in reservoirs during the Late Permian period and then being uplifted, suffering biodegradation. Oil quality was significantly altered as a result of strong biodegradation since the Triassic. Heavy oil reservoir was buried deeper around. 5 Ma, leading to a rapid increase in reservoir temperature up to 150 °C at a burial depth of 6600 m. The quick burial and elevated temperature of the reservoir were favorable to the preservation of H₆DBTs.     

Petroleum generation and charge history of the northern Dongying Depression,Bohai Bay Basin,China: Insight from integrated fluid inclusion analysis and basin modelling

The petroleum generation and charge history of the northern Dongying Depression, Bohai Bay Basin was investigated using an integrated fluid inclusion analysis workflow and geohistory modelling. One and two-dimensional basin modelling was performed to unravel the oil generation history of the Eocene Shahejie Formation (Es3 and Es4) source rocks based on the reconstruction of the burial, thermal and maturity history. Calibration of the model with thermal maturity and borehole temperature data using a rift basin heat flow model indicates that the upper interval of the Es4 source rocks began to generate oil at around 35 Ma, reached a maturity level of 0.7% R_o at 31–30 Ma and a peak hydrocarbon generation at 24–23 Ma. The lower interval of the Es3 source rocks began to generate oil at around 33–32 Ma and reached a maturity of 0.7% R_o at about 27–26 Ma. Oil generation from the lower Es3 and upper Es4 source rocks occurred in three phases with the first phase from approximately 30–20 Ma; the second phase from approximately 20–5 Ma; and the third phase from 5 Ma to the present day. The first and third phases were the two predominant phases of intense oil generation.Samples from the Es3 and Es4 reservoir intervals in 12 wells at depth intervals between 2677.7 m and 4323.0 m were investigated using an integrated fluid inclusion workflow including petrography, fluorescence spectroscopy and microthermometry to determine the petroleum charge history in the northern Dongying Depression. Abundant oil inclusions with a range of fluorescence colours from near yellow to near blue were observed and were interpreted to represent two episodes of hydrocarbon charge based on the fluid inclusion petrography, fluorescence spectroscopy and microthermometry data. Two episodes of oil charge were determined at 24–20 Ma and 4–3 Ma, respectively with the second episode being the predominant period for the oil accumulation in the northern Dongying Depression. The oil charge occurred during or immediately after the modelled intense oil generation and coincided with a regional uplift and a rapid subsidence, suggesting that the hydrocarbon migration from the already overpressured source rocks may have been triggered by the regional uplift and rapid subsidence. The expelled oil was then charged to the already established traps in the northern Dongying Depression. The proximal locations of the reservoirs to the generative kitchens and the short oil migration distance facilitate the intimate relationship between oil generation, migration and accumulation.     

Fluid inclusion and microfabric studies on Zechstein carbonates (Ca2) and related fracture mineralizations – New insights on gas migration in the Lower Saxony Basin (Germany)

New petrographic and fluid inclusion data from core samples of Upper Permian dolomitic limestone (Hauptdolomit, Zechstein group, Stassfurt carbonate sequence) from a gas field located at the northern border of the Lower Saxony Basin (LSB) essentially improve the understanding of the basin development. The gas production at the locality is characterized by very high CO₂ concentrations of 75–100% (with CH₄ and N₂).Samples consist of fine grained, mostly laminated and sometimes brecciated dolomitic limestone (mudstone/wackestone) from the transition zone between the shallow water zone (platform) and the upper slope. The study focuses on migration fluids, entrapped as fluid inclusions in diagenetic anhydrite, calcite, and fluorite, and in syn-diagenetic microfractures, as well as on the geochemistry of fluorite fracture mineralizations, obtained by LA-ICP-MS analysis. Fluid inclusion studies show that the diagenetic fluid was rich in H₂ONaClCaCl₂. Recrystallized anhydrite contains aqueous inclusions with homogenization temperatures (T_h) of ca. 123 °C, but somewhat higher T_h of ca. 142 °C was found for calcite cement followed by early Fluorite A with T_h of 147 °C. A later Fluorite B preserves gas inclusions and brines with maximum T_h of 156 °C. Fluorite B crystallized in fractures during the mobilization of CO₂-bearing brines. Crossing isochores for co-genetic aqueous-carbonic and carbonic inclusions indicate fluid trapping conditions of 180–200 °C and 900–1000 bars. δ¹³C-isotopic ratios of gas trapped in fluid inclusions suggest an organic origin for CH₄, while the CO₂ is likely of inorganic origin.Basin modelling (1D) shows that the fault block structure of the respective reservoir has experienced an uplift of >1000 m since Late Cretaceous times.The fluid inclusion study allows us to, 1) model the evolution of the LSB and fluid evolution by distinguishing different fluid systems, 2) determine the appearance of CO₂ in the geological record and, 3) more accurately estimate burial and uplift events in individual parts of the LSB.     

Fluid flow reconstruction in karstified Panormide platform limestones (north-central Sicily): Implications for hydrocarbon prospectivity in the Sicilian fold and thrust belt

Diagenetic analysis based on field and petrographic observations, isotope and microthermometric data was used to reconstruct the fluid flow history of the Cretaceous shallow water limestones from the Panormide platform exposed in north-central Sicily. Analysis focused on diagenetic products in cavities and dissolution enlarged fractures of the karstified limestones that occur just below a regional unconformity. The fluid flow history could be broken down into five stages that were linked to the kinematic and burial history of the region. (1) Petrography (zoned cathodoluminescence and speleothem textures) and stable isotopes (6.5 < δ¹⁸O_V-PDB < ?3.5‰ and 0 < δ¹³C_V-PDB < ?14‰) indicate that the earliest calcite phase was associated with karstification during emergence of the platform. Limestone dissolution at this stage is important with regard to possible reservoir creation in the Panormide palaeogeographic domain. (2) Fine-grained micrite sedimentation, dated as latest Cretaceous by nannopalaeontology and its ⁸⁷Sr/⁸⁶Sr isotope ratio (0.7078), marks replacement by marine fluids during subsequent submergence of the karstified platform. (3) The following calcite cement was still precipitated by marine-derived fluids (?7.0 < δ¹⁸O_V-PDB < ?5.0‰ and ?3.0 < δ¹³C_V-PDB < 0.5‰/T_m = ?2 to ?5 °C), but at increasingly higher temperatures (T_h = 60–120 °C). This has been interpreted as precipitation during Oligocene foredeep burial. (4) Hot (T_h = 130–180 °C), low saline (T_m < ?2.5 °C) fluids with increasingly higher calculated δ¹⁸O_SMOW signatures (+6 to +14‰) subsequently invaded the karst system. These fluids most likely migrated during fold and thrust belt development. The low salinity and relatively high δ¹⁸O_SMOW signatures of the fluids are interpreted to be the result of clay dewatering reactions. The presence of bitumen and associated fluorite with hydrocarbon inclusions at this stage in the paragenesis constrains the timing of oil migration in the region. (5) Finally, high saline fluids with elevated ⁸⁷Sr/⁸⁶Sr (0.7095–0.7105) signatures invaded the karst system. This last fluid flow event was possibly coeval with localized dolomitization and calcite cementation along high-angle faults of Pliocene age, as suggested by identical radiogenic signatures of these diagenetic products.     

Hydrocarbon charging and accumulation history in the Niudong Buried Hill Field in the Baxian Depression,eastern China

The Niudong Buried Hill Field, which lies in the Baxian Depression of the Bohai Bay Basin, is the deepest oil/gas accumulation in eastern China. Its Precambrian dolomite reservoir occurs at burial depths of 5860 m–6027 m. This paper attempts to document the hydrocarbon charging and accumulation history in this field, which could greatly enhance the understanding of the mechanisms for the formation of deep hydrocarbon accumulations. Our previous study of oil trapped in fluid inclusions has demonstrated that the ratio parameters of the fluorescence spectral intensities at 425 nm and 433 nm (Q_425/433 ratio), and at 419 nm and 429 nm (Q_419/429 ratio) can be more effective for revealing hydrocarbon charging history than the previously-used fluorescence parameters such as Lambda max and red/green quotient as well as fluorescence colors. The hydrocarbon charging and accumulation history in the Niudong Buried Hill Field was studied with an integrated approach involving the application of these two spectral parameters of petroleum inclusion fluorescence as well as utilization of other data including homogenization temperatures of aqueous inclusions coeval with petroleum inclusions, and cross-cutting relationships of cements and “oil veins” in pores and fractures. The results indicate that the dolomite reservoir in the Niudong Buried Hill Field experienced three episodes of hydrocarbon charging. In the first two episodes (between 38.5Ma and 25Ma), the low mature and mature oils, which were derived from source rocks in the Sha-4 Member of the Eocene Shahejie Formation, migrated into the reservoir, but part of them leaked out due to normal faulting at the updip margin of the buried hill. These early-charged oils were preserved mainly in small pores in micritic dolomites by oil-wettability and capillary pressure. In the Neogene, the basin subsided as a whole and local faults at the updip margin became inactive and played a sealing role. By approximately 13Ma, the source rocks became highly mature and the generated hydrocarbons then migrated into the reservoir and accumulated. Therefore, the last charging is the most important for hydrocarbon accumulation in the Niudong Buried Hill Field.     

Comparison between petroleum hydrocarbon concentrations and magnetic properties in Chennai coastal sediments,Bay of Bengal,INDIA

Petroleum hydrocarbon concentrations (PHC) of surface sediments along the Chennai coast, India, were measured by UV-Fluorescence (UVF) Spectroscopy and the results are expressed in terms of Chrysene equivalents. The concentration of PHC in sediment varies widely (from 1.88 ppm to 39.76 ppm) as compared to the baseline (1.88 ppm) with higher values obtained in the northern part of the study area. The highest magnetic susceptibility (96.8 × 10⁻⁸ m³kg⁻¹) value was determined from the Chennai harbour area. The magnetic parameters show that the Chennai coastal sediments are dominated by ferrimagnetic minerals. The positive correlation (r² = 0.86; p < 0.05) between petroleum hydrocarbon concentrations and magnetic susceptibility suggests that the magnetic minerals and petroleum hydrocarbons along the Chennai coast are derived from the same sources. Factor analysis shows that the magnetic concentration dependent parameters (χ, χ_ARM and SIRM) covary with the petroleum hydrocarbon concentration, suggesting that large amounts of magnetic minerals originate from anthropogenic activities. It is evident that using magnetic measurements may be considered a simple, rapid, cheap and non-destructive method to determine petroleum hydrocarbon concentrations in coastal sediments. Furthermore, this technique may be applied to petroleum exploration studies. Magnetic susceptibility measurements in sediments have been proposed as complementary or alternative means of exploration and assessment of hydrocarbon reservoirs.     

Geothermometry and geobarometry of overpressured lower Paleozoic gas shales in the Jiaoshiba field,Central China: Insight from fluid inclusions in fracture cements

The Wufeng-Longmaxi organic-rich shales host the largest shale gas fields of China. This study examines sealed fractures within core samples of the Wufeng-Longmaxi shales in the Jiaoshiba shale gas field in order to understand the development of overpressures (in terms of magnitude, timing and burial) in Wufeng-Longmaxi shales and thus the causes of present-day overpressure in these Paleozoic shale formations as well as in all gas shales. Quartz and calcite fracture cements from the Wufeng-Longmaxi shale intervals in four wells at depth intervals between 2253.89 m and 3046.60 m were investigated, and the fluid composition, temperature, and pressure during natural fracture cementation determined using an integrated approach consisting of petrography, Raman spectroscopy and microthermometry. Many crystals in fracture cements were found to contain methane inclusions only, and aqueous two-phase inclusions were consistently observed alongside methane inclusions in all cement samples, indicating that fluid inclusions trapped during fracture cementation are saturated with a methane hydrocarbon fluid. Homogenization temperatures of methane-saturated aqueous inclusions provide trends in trapping temperatures that Th values concentrate in the range of 198.5 °C–229.9 °C, 196.2 °C-221.7 °C for quartz and calcite, respectively. Pore-fluid pressures of 91.8–139.4 MPa for methane inclusions, calculated using the Raman shift of C-H symmetric stretching (v₁) band of methane and equations of state for supercritical methane, indicate fluid inclusions trapped at near-lithostatic pressures. High trapping temperature and overpressure conditions in fluid inclusions represent a state of temperature and overpressure of Wufeng-Longmaxi shales at maximum burial and the early stage of the Yanshanian uplift, which can provide a key evidence for understanding the formation and evolution of overpressure. Our results demonstrate that the main cause of present-day overpressure in shale gas deposits is actually the preservation of moderate-high overpressure developed as a result of gas generation at maximum burial depths.     

Organic geochemical characterization of Santonian to Early Campanian organic matter-rich marls (Sondage No. 1 cores) as related to OAE3 from the Tarfaya Basin,Morocco

In addition to previously analyzed sediments of Cenomanian to Santonian age in the Tarfaya Sondage No. 2 well, this study presents the results of a stratigraphically younger interval of Santonian to Early Campanian age in the adjacent well Tarfaya Sondage No. 1. This interval is part of the oceanic anoxic event 3 (OAE3), which occurred mainly in the Atlantic realm. Due to known high quality source rocks related to OAEs (i.e. Cenomanian–Turonian), the investigated sample section was tested for the quality, quantity and kind of organic matter (OM), describing also the depositional environment. The study was carried out by means of (i) elemental analysis (C_org, CaCO₃, TS), (ii) Rock–Eval pyrolysis, (iii) vitrinite reflectance measurements, (iv) gas chromatography-flame ionization detection (GC-FID) and (v) GC-mass spectrometry (GC–MS). Total content of organic carbon (C_org), values for the hydrogen index (HI) (mainly in the range 500–700 mg/g C_org) and S₂ values (10–40 mg/g rock), support the assumption of a high petroleum generation potential in these Upper Cretaceous sediments. TS/C_org ratios as well as pristane/phytane ratios indicate variable oxygen contents during sediment deposition, representing a typical depositional setting for the Late Cretaceous and are in good agreement with previously analyzed data in the Tarfaya Basin. Phyto- and zoo-plankton were identified as marine sourced. All of the investigated Early Campanian and Santonian samples are immature with some tendencies to early maturation. These results are based on vitrinite reflectance (0.3–0.4% VR_r), T_max values (409–425 °C), production indices (PI; S₁/(S₁ + S₂)< 0.1) and n-alkane ratios (i.e. carbon preference index). As the deposition of these sediments is time related to OAE3, the depositional environment was characterized by oxygen-deficiency or even anoxic bottom water conditions. This situation was favored during the Cretaceous greenhouse climate by limited oxygen solubility in the then warmer ocean water. Furthermore, local factors related to nutrient supply and primary bioproductivity led to the exceptionally thick, Upper Cretaceous organic matter-rich sedimentary sequence of the Tarfaya Basin.     

Petrological and geochemical constraints on diagenesis and deep burial dissolution of the Ordovician carbonate reservoirs in the Tazhong area,Tarim Basin,NW China

Deeply buried (4500–7000 m) Ordovician carbonate reservoirs in the Tazhong area, Tarim Basin, NW China show obvious heterogeneity with porosity from null in limestones and sweet dolostones to 27.8% in sour dolostones, from which economically important oils, sour gas and condensates are currently being produced. Petrographic features, C, O, Sr isotopes were determined, and fluid inclusions were analyzed on diagenetic calcite, dolomite and barite from Ordovician reservoirs to understand controls on the porosity distribution. Ordovician carbonate reservoirs in the Tazhong area are controlled mainly by initial sedimentary environments and eo-genetic and near-surface diagenetic processes. However, vugs and pores generated from eogenetic and telogenetic meteoric dissolution were observed to have partially been destroyed due to subsequent compaction, filling and cementation. In some locations or wells (especially ZG5-ZG7 Oilfield nearby ZG5 Fault), burial diagenesis (e.g. thermochemical sulfate reduction, TSR) probably played an important role in quality improvement towards high-quality reservoirs. C2 calcite and dolomite cements and barite have fluid inclusions homogenization temperatures (Ths) from 86 to 113 °C, from 96 to 128 °C and from 128 to 151 °C, respectively. We observed petrographically corroded edges of these high-temperature minerals with oil inclusions, indicating the dissolution must have occurred under deep-burial conditions. The occurrence of TSR within Ordovician carbonate reservoirs is supported by C3 calcite replacement of barite, and the association of sulfur species including pyrite, anhydrite or barite and elemental sulfur with hydrocarbon and ¹²C-rich (as low as −7.2‰ V-PDB) C3 calcite with elevated Ths (135–153 °C). The TSR may have induced burial dissolution of dolomite and thus probably improved porosity of the sour dolostones reservoirs at least in some locations. In contrast, no significant burial dissolution occurred in limestone reservoirs and non-TSR dolostone reservoirs. The deeply buried sour dolostone reservoirs may therefore be potential exploration targets in Tarim Basin or elsewhere in the world.     

水下溢油油滴粒径分布实验研究

Oil droplet size distribution(ODSD) plays a critical role in the rising velocity and transport of oil droplets in subsurface oil releases. In this paper, subsurface oil release experiments were conducted to study ODSD under different experimental conditions in a laboratory water tank observed by two high-speed cameras in March and April 2017. The correlation formulas Oh=10.2 Re~(–1) and Oh=39.2 Re~(–1)(Re represents Reynolds number and Oh represents Ohnesorge number) were established to distinguish the boundaries of the three instability regimes in dimensionless space based on the experimental results. The oil droplet sizes from the experimental data showed an excellent match to the Rosin–Rammler distribution function with determination coefficients ranging from 0.86 to 1.00 for Lvda 10-1 oil. This paper also explored the influence factors on and change rules of oil droplet size. The volume median diameter d50 decreased steadily with increasing jet velocity, and a sharp decrease occurred in the laminar-breakup regime. At Weber numbers(We) 100, the orifice diameter and oil viscosity appeared to have a large influence on the mean droplet diameter. At 100We1 000, the oil viscosity appeared to have a larger influence on the relative mean droplet diameter.