共查询到20条相似文献，搜索用时 312 毫秒
1.
Xiaowen Guo Sheng He Keyu Liu Zhongsheng Shi Sani Bachir 《Journal of Asian Earth Sciences》2011,40(1):287-302
The mudstones in the third member of the Shahejie Formation (Es3) are the primary source rocks in the Banqiao Depression of Bohai Bay Basin. They are rich in organic matter with Total Organic Carbon (TOC) content up to 3.5%. The sandstones in the Es3 member are the deepest proven hydrocarbon reservoir rocks with measured porosity and permeability values ranging from 3.6% to 32.4% and from 0.01 md to 3283.7 md, respectively. One, two and three-dimensional basin modelling studies were performed to analyse the petroleum generation and migration history of the Es3 member in the Banqiao Depression based on the reconstruction of the burial, thermal and maturity history in order to evaluate the remaining potential of this petroleum province. The modelling results are calibrated with measured vitrinite reflectance (Ro), borehole temperatures and some drilling results of 63 wells in the study area. Calibration of the model with thermal maturity and borehole temperature data indicates that the present-day heat flow in the Banqiao Depression varies from 59.8 mW/m2 to 61.7 mW/m2 and the paleo-heat flow increased from 65 Ma to 50.4 Ma, reached a peak heat-flow values of approximately 75 mW/m2 at 50.4 Ma and then decreased exponentially from 50.4 Ma to present-day. The source rocks of the Es3 member are presently in a stage of oil and condensate generation with maturity from 0.5% to 1.8% Ro and had maturity from 0.5% to 1.25% Ro at the end of the Dongying Formation (Ed) deposition (26 Ma). Oil generation (0.5% Ro) in the Es3 member began from about 37 Ma to 34 Ma and the peak hydrocarbon generation (1.0% Ro) occurred approximately from 30 Ma to 15 Ma. The modelled hydrocarbon expulsion evolution suggested that the timing of hydrocarbon expulsion from the Es3 member source rocks began from 31 Ma to 10 Ma with the peak hydrocarbon expulsion shortly after 26 Ma. Secondary petroleum migration pathways in the Es3 member of the Banqiao Depression are modelled based on the structure surfaces at 26 Ma and present-day, respectively. The migration history modelling results have accurately predicted the petroleum occurrences within the Es3 member of the Banqiao Depression based on the calibration with drilling results of 10 oil-producing wells, one well with oil shows and 52 dry holes. Six favorable zones of oil accumulations in the Es3 member of the Banqiao Depression are identified especially oil accumulation zones I and II due to their proximity to the generative kitchens, short oil migration distances and the presence of a powerful drive force. 相似文献
2.
Hydrous pyrolysis (HP) experiments were used to investigate the petroleum composition and quality of petroleum generated from a Brazilian lacustrine source rock containing Type I kerogen with increasing thermal maturity. The tested sample was of Aptian age from the Araripe Basin (NE-Brazil). The temperatures (280–360 °C) and times (12–132 h) employed in the experiments simulated petroleum generation and expulsion (i.e., oil window) prior to secondary gas generation from the cracking of oil. Results show that similar to other oil prone source rocks, kerogen initially decomposes in part to a polar rich bitumen, which decomposes in part to hydrocarbon rich oil. These two overall reactions overlap with one another and have been recognized in oil shale retorting and natural petroleum generation. During bitumen decomposition to oil, some of the bitumen is converted to pyrobitumen, which results in an increase in the apparent kerogen (i.e., insoluble carbon) content with increasing maturation.The petroleum composition and its quality (i.e., API gravity, gas/oil ratio, C15+ fractions, alkane distribution, and sulfur content) are affected by thermal maturation within the oil window. API gravity, C15+ fractions and gas/oil ratios generated by HP are similar to those of natural petroleum considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous age. API gravity of the HP expelled oils shows a complex relationship with increasing thermal maturation that is most influenced by the expulsion of asphaltenes. C15+ fractions (i.e., saturates, aromatics, resins and asphaltenes) show that expelled oils and bitumen are compositionally separate organic phases with no overlap in composition. Gas/oil ratios (GOR) initially decrease from 508–131 m3/m3 during bitumen generation and remain essentially constant (81–84 m3/m3) to the end of oil generation. This constancy in GOR is different from the continuous increase through the oil window observed in anhydrous pyrolysis experiments. Alkane distributions of the HP expelled oils are similar to those of natural crude oils considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous age. Isoprenoid and n-alkane ratios (i.e., pristane/n-C17 and phytane/n-C18) decrease with increasing thermal maturity as observed in natural crude oils. Pristane/phytane ratios remain constant with increasing thermal maturity through the oil window, with ratios being slightly higher in the expelled oils relative to those in the bitumen. Generated hydrocarbon gases are similar to natural gases associated with crude oils considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous, with the exception of elevated ethane contents. The general overall agreement in composition of natural and hydrous pyrolysis petroleum of lacustrine source rocks observed in this study supports the utility of HP to better characterize petroleum systems and the effects of maturation and expulsion on petroleum composition and quality. 相似文献
3.
Three sets of pyrolysis experiments were performed on extracted coal (Ro% 0.39), coal (initial bitumen 13.5 mg/g coal) and bitumen enriched coal (total bitumen 80.9 mg/g coal) at two heating rates of 2 °C/h and 20 °C/h in confined systems (gold capsules). For all three experiments, the yields of bitumen, Σn-C8+, aromatic components and ΣC2–5 at first increase and then decrease with increasing EASY%Ro and reach the highest values within the EASY%Ro ranges of 0.67–1.08, 1.07–1.19, 1.46–1.79 and 1.46–1.68, respectively. In contrast, C1/ΣC1–5 ratio at first decreases and then increases with EASY%Ro and reaches a minimum value in EASY%Ro range of 0.86–1.08, closely corresponding to the maximum values of the yields of bitumen and Σn-C8+. Methane yields increase consistently with EASY%Ro. Nearly half of the maximum yield of methane from kerogen was generated at EASY%Ro > 2.2. The differences in methane yields among the three experiments at the same thermal stress are relatively minor at EASY%Ro < 2.2, but are greater with thermal stress at EASY%Ro > 2.2. This demonstrates that the kerogen always retained relatively more hydrogen and hydrocarbon generative potential at the postmature stage of bitumen rich coal than the extracted coal or coal.The maximum yield of ethane is 20–25% higher in the bitumen rich coal experiment than the extracted coal or coal, while the maximum yields of C3, C4 and C5 in the former are double to triple those in the latter. This result demonstrates that the added bitumen in bitumen rich coal substantially increased the generation of these wet gases. However, the averaged values of activation energies (with the same frequency factors) for both the generation and cracking of individual wet gases are similar and do not show consistent trends among the three experiments. For all three experiments, activation energies for the generation and cracking of wet gases are significantly lower than those in previously published oil pyrolysis experiments with same frequency factors (Pan et al., 2012; Organic Geochemistry 45, 29–47). Methane δ13C values at the maximum temperature or EASY%Ro are close to those of initial wet gases, especially C3, implying that the major part of methane shared a common initial precursor with wet gases, i.e., free and bound liquid alkanes. 相似文献
4.
Deeply buried heavy oils from the Tabei Uplift of the Tarim Basin have been investigated for their source origin, charge and accumulation time, biodegradation, mixing and thermal cracking using biomarkers, carbon isotopic compositions of individual alkanes, fluid inclusion homogenization temperatures and authigenic illite K–Ar radiometric ages. Oil-source correlation suggests that these oils mainly originated from Middle–Upper Ordovician source rocks. Burial history, coupled with fluid inclusion temperatures and K–Ar radiometric ages, suggests that these oils were generated and accumulated in the Late Permian. Biodegradation is the main control on the formation of these heavy oils when they were elevated to shallow depths during the late Hercynian orogeny. A pronounced unresolved complex mixture (UCM) in the gas chromatograms together with the presence of both 25-norhopanes and demethylated tricyclic terpanes in the oils are obvious evidence of biodegradation. The mixing of biodegraded oil with non-biodegraded oil components was indicated by the coexistence of n-alkanes with demethylated terpanes. Such mixing is most likely from the same phase of generation, but with accumulation at slightly different burial depths, as evidenced by overall similar oil maturities regardless of biodegradation level and/or amount of n-alkanes. Although these Ordovician carbonate reservoirs are currently buried to over 6000 m with reservoir temperatures above 160 °C, no significant secondary hydrocarbon generation from source rocks or thermal cracking of reservoired heavy oil occur in the study area. This is because the deep burial occurred only within the last 5 Ma of the Neogene, and there has not been enough heating time for additional reactions within the Middle–Upper Ordovician source rocks and reservoired heavy oils. 相似文献
5.
A gas condensate from well ND1 in the Jizhong Depression of the Bohai Bay Basin, China is characterized by two-dimensional gas chromatography with flame ionization detector (GC × GC–FID) and time-of-flight mass spectrometry (GC × GC–TOFMS). This condensate is sourced from the fourth member of the Shahejie Formation (Es4) but reservoired in the Mesoproterozoic Wumishan Formation carbonate at a depth of 5641–6027 m and the reservoir temperature is 190–201 °C. It is the deepest and the highest temperature discovery in the basin to date. The API gravity of the condensate is 51° and the sulfur content is < 0.04%. A total of 4955 compounds were detected and quantified. Saturated hydrocarbons, aromatic hydrocarbons and non-hydrocarbon account for 94.8%, 5.1% and 0.02% of the condensate mass, respectively. Some long chain alkylated cyclic alkanes, decahydronaphthalenes and diamondoids are tentatively identified in this condensate. The C6–C9 light hydrocarbon parameters show that the gas condensate was generated at relatively high maturity but its generation temperature derived from the dimethylpentane isomer ratio seems far lower than the current reservoir temperature. Some light hydrocarbon parameters indicate evaporative fractionation may also be involved due to multiple-charging and mixing. The diamondoid concentrations and gas oil ratio (GOR) suggest that the ND1 condensate results from 53.3–55% cracking. Since significant liquids remain, the exploration potential of ultra-deep buried hill fields in the Bohai Bay Basin remains high. 相似文献
6.
Unusually high dibenzothiophene (DBT) concentrations are present in the oils from the Tazhong-4 Oilfield in the Tazhong Uplift, Tarim Basin. Positive-ion electrospray ionization Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) was used in combination with conventional geochemical approaches to unravel the enrichment mechanisms. Significant amounts of S1 species with relatively low DBE values (0–8), i.e., sulfur ethers, mercaptans, thiophenes and benzothiophenes, were detected in three Lower Ordovician oils with high thermal maturity, which were suggested to be the products of thermochemical sulfate reduction (TSR) in the reservoir. The occurrence of TSR was also supported by the coexistence of thiadiamondoids and abundant H2S in the gases associated with the oils. Obviously low concentrations of the DBE = 9 S1 species (mainly equivalent to C0–C35 DBTs) compared to its homologues were observed for the three oils which were probably altered by TSR, indicating that no positive relationship existed between TSR and DBTs in this study. The sulfur compounds in the Tazhong-4 oils are quite similar to those in the majority of Lower Ordovician oils characterized by high concentrations of DBTs and dominant DBE = 9 S1 species with only small amounts of sulfur compounds with low thermal stability (DBE = 0–8), suggesting only a small proportion of sulfur compounds were derived from TSR. It is thermal maturity rather than TSR that has caused the unusually high DBT concentrations in most of the Lower Ordovician oils. We suggest that the unusually high DBT oils in the Tazhong-4 Oilfield are caused by oil mixing from the later charged Lower Ordovician (or perhaps even deeper), with high DBT abundances from the earlier less mature oils, which was supported by our oil mixing experiments and previous relevant investigations as well as abundant authigenic pyrite of hydrothermal origin. We believe that TSR should have occurred in the Tazhong Uplift based on our FT-ICR MS results. However, normal sulfur compounds were detected in most oils and no increase of δ13C2H6–δ13C4H10 was observed for the gas hydrocarbons, suggesting only a slight alteration of the oils by TSR currently and/or recently. We suspect that the abnormal sulfur compounds in the Lower Ordovician oils might also be a result of deep oil mixing, which might imply a deeper petroliferous horizon, i.e., Cambrian, with a high petroleum potential. This study is important to further deep petroleum exploration in the area. 相似文献
7.
Hong Lu Tengshui Chen Kliti Grice Paul Greenwood Ping’an Peng Guoying Sheng 《Organic Geochemistry》2009,40(8):902-911
An unusual series of C22–C27 monounsaturated sterenes and C24–C30 tetracyclic terpanes (17,21-secohopanes) were detected in relatively high concentrations in an immature evaporitic marl sediment of the Jinxian Sag, Bohai Bay Basin, North China. The site of unsaturation in these novel sterenes is assigned tentatively to the D ring on the basis of mass spectral interpretation, which also distinguishes them from reported unsaturated sterenes. Other hydrocarbon biomarker or stable isotope characteristics are indicative of microbial (e.g. methyl hopanes), phytoplankton or higher plant (depleted δ13C values of isoprenoids and hopanes) inputs and an anoxic carbonate depositional environment (hexacyclic hopanes; tetracyclic terpanes). The hydrocarbon composition showed no obvious biodegradation and the relatively high concentration of unsaturated terpenoids (e.g. gammacerene) and low values of other established maturity parameters (Ts/Tm = 0.23; Ro = 0.44%; Tmax = 417 °C), are consistent with sediments of low maturity. The novel, low molecular weight sterenes and the tetracyclic terpanes may be early diagenetic products of microbial sources in a carbonate environment. 相似文献
8.
Although oil cracking has been documented as one of the important sources of gas in many overmature marine sedimentary basins, the chemical and carbon isotopic signatures of gases of this origin are still open to question. In this study a Cambrian crude oil from the central Tarim basin, along with its main separated fractions (saturates, aromatics and asphaltenes), were pyrolyzed in sealed gold tubes to investigate how generated gases vary in chemical and carbon isotopic composition and how this variation would influence the genetic interpretation of oil cracking gas. The results indicate that the gases from cracking of aromatics and asphaltenes are much drier and more enriched in 13C than the gases from the cracking of saturates and crude oil at the same level of thermal maturity. In the experimental run of 20 °C/h, the dryness index of the gases (defined as the volume percentage of C1 in C1–5) from the cracking of saturates ranges from 26.2–90.6% with the methane carbon isotope change ranging from −54.8‰ to −35.5‰, whereas the dryness index is never lower than 60.6% for the gases from the cracking of aromatics with methane carbon isotope ranging from −39.9‰ to −32.2‰. Correspondingly, experimental data for the four samples plot in different areas in diagrams designed to distinguish oil cracking gas from kerogen cracking gas, such as ln(C2/C3) vs. δ13C2–δ13C3 and δ13C1 vs. δ13C2–δ13C3, indicating compositional variability of crude oil could assert an important influence in these diagrams. Therefore it is prudent to bring other geological constraints into consideration to avoid misinterpretation.The kinetic parameters for the bulk generation of C1–5 gas and the methane carbon isotope fractionation extrapolated to geological conditions of 2 °C/Ma and an initial temperature of 50 °C show that the temperatures of C1–5 gas generation from the aromatics and asphaltenes are lower than those from the saturates and crude oil due to their lower activation energies and frequency factors. Generation of C1–5 gases from the aromatics is modeled to be initiated about 122 °C whereas the initiation temperature for the saturates sample is 176 °C. Below 189 °C (EasyRo = 1.8%), the yields of C1–5 gases follow the order: aromatics > asphaltenes > crude oil > saturates. At similar thermal maturity levels, the methane carbon isotopic compositions are significantly different for the four samples, with an order of 13C enrichment: aromatics > asphaltenes > crude oil > saturates, however the difference in methane carbon isotopes becomes smaller with increasing temperature. This indicates that methane carbon isotopic values can be significantly different for gases cracked from oils that are compositionally diverse, especially in the early stage of methane generation. 相似文献
9.
Calcite veins with fluid and solid bitumen inclusions have been discovered in the south-western shoulder of the Dead Sea rift within the Masada-Zohar block, where hydrocarbons exist in small commercial gas fields and non-commercial fields of heavy and light oils. The gas–liquid inclusions in calcite are dominated either by methane or CO2, and aqueous inclusions sometimes bear minor dissolved hydrocarbons. The enclosed flake-like solid bitumen matter is a residue of degraded oil, which may be interpreted as “dead carbon”. About 2/3 of this matter is soot-like amorphous carbon and 1/3 consists of n-C8C18 carboxylic acids and traces of n-alkanes, light dicarboxylic acids, and higher molecular weight (>C20) branched and/or cyclic carboxylic acids. Both bitumen and the host calcites show genetic relationship with mature Maastrichtian chalky source rocks (MCSRs) evident in isotopic compositions (δ13C, δ34S, and δ18O) and in REE + Y patterns. The bitumen precursor may have been heavy sulfur-rich oil which was generated during the burial compaction of the MCSR strata within the subsided blocks of the Dead Sea graben. The δ18O and δ13C values and REE + Y signatures in calcites indicate mixing of deep buried fluids equilibrated with post-mature sediments and meteoric waters. The temperatures of fluid generation according to Mg–Li-geothermometer data range from 55 °С to 90 °С corresponding to the 2.5–4.0 km depths, and largely overlap with the oil window range (60–90 °С) in the Dead Sea rift (Hunt, 1996; Gvirtzman and Stanislavsky, 2000; Buryakovsky et al., 2005). The bitumen-rich vein calcites originated in the course of Late Cenozoic rifting and related deformation, when tectonic stress triggers damaged small hydrocarbon reservoirs in the area, produced pathways, and caused hydrocarbon-bearing fluids to rise to the subsurface; the fluids filled open fractures and crystallized to calcite with entrapped bitumen. The reported results are in good agreement with the existing views of maturation, migration, and accumulation of hydrocarbons, as well as basin fluid transport processes in the Dead Sea area. 相似文献
10.
《Russian Geology and Geophysics》2014,55(7):801-811
The structure of mantle convection and spatial fields of superlitho static pressure and vertical and horizontal stresses in the Earth’s mantle are studied in a 2D numerical model with non-Newtonian viscosity and heat sources. The model demonstrates a jump-like motion of subduction zones and reveals abrupt changes in the stress fields depending on the stage of slab detachment. The stresses decrease dramatically in the areas without slabs. The horizontal stresses oxx, superlitho static pressure, and vertical stresses ozz in the part of the mantle lacking intense near-vertical flows are approximately equal, varying within ± 6, ± 8, and ± 10 MPa, respectively. However, these fields are stronger in the areas of descending slabs, where the values of the above parameters are about an order of magnitude higher (± 50 MPa).This result agrees with the current views of the oceanic slabs as the most important gent of mantle convection. We have found significant differences among the oxx, ozz, and pressure fields. The pressure field reveals both the vertical and horizontal features of slabs and plumes, clearly showing their long thermal conduits with broader heads. The distributions of oxx are sensitive to the near-horizontal parts of the flows, whereas the ozz fields reveal mainly their vertical substructures. The model shows the presence of relatively cold remnants of slabs in the lower mantle above the thermal boundary layer. Numerous hot plumes penetrating through these high-viscosity remnants, as well as the new descending slabs, induce intense stress fields in the lower mantle, which are strongly inhomogeneous in space and time. 相似文献
11.
《Applied Geochemistry》2005,20(3):545-551
Light hydrocarbons in oils from the Tarim basin, NW China, were analyzed by GC. The light hydrocarbon parameters proposed by Mango revealed the distributions of the oils as two main types, marine and terrigenous sources. The Mango parameter K1 not only displays a remarkable invariance (∼1) in most of the oils, but also shows significant variations (ranging from 1.20 to 1.54) in the oils occurring in the eastern part of the Tazhong Fault Uplift (EPTFU) located in the center of the Tarim basin. This variation of the K1 value may indicate different petroleum systems in the areas which are superimposed in the EPTFU. Parameter K2 proposed by Mango shows a significant variation between the two main oil types. The marine oils are characterized by relatively low values of K2 (average 0.23) and the terrigenous oils by relatively high K2 values (average 0.35), with general invariance within the same oil set. A plot of (P3 + P2 + N2) vs. based on the model proposed by Mango can be used not only to discriminate between the two main genetic oils from the Tarim basin, but also to classify the marine oils from the Lunnan area into two sub-types, which may indicate two sub-petroleum systems existing in the area. 相似文献
12.
The biodegradation of crude oil by microorganisms from well Luo-801, China, was examined in cultures grown under conditions that promoted either methanogenesis or sulfate reduction, at 35 °C and 55 °C. Headspace gas and oil compositions were characterized at 180 d and 540 d. Alkylphenanthrenes are relatively recalcitrant to bacterial attack and the biodegradation of these compounds appeared to be insignificant after 180 d under both conditions, but is evident after 540 d. The depletion of alkylphenanthrenes was monitored through evaluation of the ratio of alkylphenanthrenes to the most bioresistant, analyzed component (C28 20R triaromatic steroid hydrocarbon) and isomer susceptibility also was evaluated by relative abundance comparison within the compound class. The influence of growth temperature varied. Only slight differences in alkylphenanthrene concentrations were observed after 180 d whereas the greater degrees of biodegradation were observed at 35 °C in the methanogenic culture and at 55 °C in the sulfate reducing culture. Overall, higher biodegradation rates occur under sulfate reducing condition, which is consistent with the conclusion that methanogens are generally less able to compete for substrates than sulfate reducers. The biodegradation susceptibility of alkylphenanthrenes decreases with increasing degree of alkylation, i.e., phenanthrene (P) and methylphenanthrenes (MPs) were more easily biodegradable than C2-alkylphenanthrenes (C2-Ps) and C3-alkylphenanthrenes (C3-Ps). Biodegradation selectivity for specific homologues is not striking for the limited time duration of the experiments. However, 3-MP seems slightly more vulnerable than other methylphenanthrene isomers and 1,7-DMP has slightly higher ability to resist biodegradation than the other C2-P isomers. The commonly used thermal maturity parameters derived from methylphenanthrene isomer ratios are altered insignificantly by biodegradation and remain valid for geochemical assessment. This information should be useful for assessing the limits of in situ crude oil biodegradation. 相似文献
13.
The Bulonggoer paleo-oil reservoir (BPR) on the northwest Junggar Basin is the first Devonian paleo-oil reservoir discovered in North Xinjiang, China. Solid bitumens occur within sandstone pores and as veins filling fractures. Samples of both types were analyzed using stable carbon isotope and reflectance measurements, as well as molecular biomarker parameters.The extremely positive δ13C values and biomarker indicators of depositional environment/lithology, such as pristane/phytane (Pr/Ph), C29/C30 hopane, diasteranes/regular steranes and dibenzothiophene/phenanthrene ratios, indicate a siliciclastic source for the BPR and their deposition in a highly reducing hypersaline environment. The presence of long chain n-alkanes and abundant tetracyclic diterpanes, C20–C21 tricyclic terpanes and perylene are indicators of higher plant organic matter input. Moreover, the bimodal distribution of C27 > C28 < C29 regular steranes and abundant methyltriaromatic steroids also support a contribution of microalgae as well as higher plants organic matter. The similar molecular composition and thermal maturity parameters indicate that the reservoir and veined solid bitumens were altered from a common paleo-petroleum, which originated from peak oil window matured source rocks.All solid bitumens from the BPR are characterized by relatively low bitumen reflectance values (Rb% < 0.7), suggesting that they were generated from low temperature processes rather than oil thermal cracking. Comparatively, the Rb% values for veined bitumens are higher than reservoir bitumens, indicating that the veined bitumens occurred earlier and experienced higher thermal conditions. 相似文献
14.
This study examined the molecular and isotopic compositions of gases generated from different kerogen types (i.e., Types I/II, II, IIS and III) in Menilite Shales by sequential hydrous pyrolysis experiments. The experiments were designed to simulate gas generation from source rocks at pre-oil-cracking thermal maturities. Initially, rock samples were heated in the presence of liquid water at 330 °C for 72 h to simulate early gas generation dominated by the overall reaction of kerogen decomposition to bitumen. Generated gas and oil were quantitatively collected at the completion of the experiments and the reactor with its rock and water was resealed and heated at 355 °C for 72 h. This condition simulates late petroleum generation in which the dominant overall reaction is bitumen decomposition to oil. This final heating equates to a cumulative thermal maturity of 1.6% Rr, which represents pre-oil-cracking conditions. In addition to the generated gases from these two experiments being characterized individually, they are also summed to characterize a cumulative gas product. These results are compared with natural gases produced from sandstone reservoirs within or directly overlying the Menilite Shales. The experimentally generated gases show no molecular compositions that are distinct for the different kerogen types, but on a total organic carbon (TOC) basis, oil prone kerogens (i.e., Types I/II, II and IIS) generate more hydrocarbon gas than gas prone Type III kerogen. Although the proportionality of methane to ethane in the experimental gases is lower than that observed in the natural gases, the proportionality of ethane to propane and i-butane to n-butane are similar to those observed for the natural gases. δ13C values of the experimentally generated methane, ethane and propane show distinctions among the kerogen types. This distinction is related to the δ13C of the original kerogen, with 13C enriched kerogen generating more 13C enriched hydrocarbon gases than kerogen less enriched in 13C. The typically assumed linear trend for δ13C of methane, ethane and propane versus their reciprocal carbon number for a single sourced natural gas is not observed in the experimental gases. Instead, the so-called “dogleg” trend, exemplified by relatively 13C depleted methane and enriched propane as compared to ethane, is observed for all the kerogen types and at both experimental conditions. Three of the natural gases from the same thrust unit had similar “dogleg” trends indicative of Menilite source rocks with Type III kerogen. These natural gases also contained varying amounts of a microbial gas component that was approximated using the Δδ13C for methane and propane determined from the experiments. These approximations gave microbial methane components that ranged from 13–84%. The high input of microbial gas was reflected in the higher gas:oil ratios for Outer Carpathian production (115–1568 Nm3/t) compared with those determined from the experiments (65–302 Nm3/t). Two natural gas samples in the far western part of the study area had more linear trends that suggest a different organic facies of the Menilite Shales or a completely different source. This situation emphasizes the importance of conducting hydrous pyrolysis on samples representing the complete stratigraphic and lateral extent of potential source rocks in determining specific genetic gas correlations. 相似文献
15.
Y.B. Melnichenko A.P. Radlinski M. Mastalerz G. Cheng J. Rupp 《International Journal of Coal Geology》2009,77(1-2):69-79
Small angle neutron scattering techniques have been applied to investigate the phase behavior of CO2 injected into coal and possible changes in the coal pore structure that may result from this injection. Three coals were selected for this study: the Seelyville coal from the Illinois Basin (Ro = 0.53%), Baralaba coal from the Bowen Basin (Ro = 0.67%), and Bulli 4 coal from the Sydney Basin (Ro = 1.42%). The coals were selected from different depths to represent the range of the underground CO2 conditions (from subcritical to supercritical) which may be realized in the deep subsurface environment. The experiments were conducted in a high pressure cell and CO2 was injected under a range of pressure conditions, including those corresponding to in-situ hydrostatic subsurface conditions for each coal. Our experiments indicate that the porous matrix of all coals remains essentially unchanged after exposure to CO2 at pressures up to 200 bar (1 bar = 105 Pa). Each coal responds differently to the CO2 exposure and this response appears to be different in pores of various sizes within the same coal. For the Seelyville coal at reservoir conditions (16 °C, 50 bar), CO2 condenses from a gas into liquid, which leads to increased average fluid density in the pores (ρpore) with sizes (r) 1 × 105 ≥ r ≥ 1 × 104 Å (ρpore ≈ 0.489 g/cm3) as well as in small pores with size between 30 and 300 Å (ρpore ≈ 0.671 g/cm3). These values are by a factor of three to four higher than the density of bulk CO2 (ρCO2) under similar thermodynamic conditions (ρCO2 ≈ 0.15 g/cm3). At the same time, in the intermediate size pores with r ≈ 1000 Å the average fluid density is similar to the density of bulk fluid, which indicates that adsorption does not occur in these pores. At in situ conditions for the Baralaba coal (35 OC, 100 bar), the average fluid density of CO2 in all pores is lower than that of the bulk fluid (ρpore / ρCO2 ≈ 0.6). Neutron scattering from the Bulli 4 coal did not show any significant variation with pressure, a phenomenon which we assign to the extremely small amount of porosity of this coal in the pore size range between 35 and 100,000 Å. 相似文献
16.
《Applied Geochemistry》2005,20(11):2017-2037
The Tertiary Thrace Basin located in NW Turkey comprises 9 km of clastic-sedimentary column ranging in age from Early Eocene to Recent in age. Fifteen natural gas and 10 associated condensate samples collected from the 11 different gas fields along the NW–SE extending zone of the northern portion of the basin were evaluated on the basis of their chemical and individual C isotopic compositions. For the purpose of the study, the genesis of CH4, thermogenic C2+ gases, and associated condensates were evaluated separately.Methane appears to have 3 origins: Group-1 CH4 is bacteriogenic (Calculated δ13CC1–C = −61.48‰; Silivri Field) and found in Oligocene reservoirs and mixed with the thermogenic Group-2 CH4. They probably formed in the Upper Oligocene coal and shales deposited in a marshy-swamp environment of fluvio-deltaic settings. Group-2 (δ13CC1–C = −35.80‰; Hamitabat Field) and Group-3 (δ13C1–C = −49.10‰; Değirmenköy Field) methanes are thermogenic and share the same origin with the Group-2 and Group-3 C2+ gases. The Group-2 C2+ gases include 63% of the gas fields. They are produced from both Eocene (overwhelmingly) and Oligocene reservoirs. These gases were almost certainly generated from isotopically heavy terrestrial kerogen (δ13C = −21‰) present in the Eocene deltaic Hamitabat shales. The Group-3 C2+ gases, produced from one field, were generated from isotopically light marine kerogen (δ13C = −29‰). Lower Oligoce ne Mezardere shales deposited in pro-deltaic settings are believed to be the source of these gases.The bulk and individual n-alkane isotopic relationships between the rock extracts, gases, condensates and oils from the basin differentiated two Groups of condensates, which can be genetically linked to the Group-2 and -3 thermogenic C2+ gases. However, it is crucial to note that condensates do not necessarily correlate to their associated gases.Maturity assessments on the Group-1 and -2 thermogenic gases based on their estimated initial kerogen isotope values (δ13C = −21‰; −29‰) and on the biomarkers present in the associated condensates reveal that all the hydrocarbons including gases, condensates and oils are the products of primary cracking at the early mature st age (Req = 0.55–0.81%). It is demonstrated that the open-system source conditions required for such an early-mature hydrocarbon expulsion exist and are supported by fault systems of the basin. 相似文献
17.
The organic rich Safer shales exposed in the north-central part of onshore Marib-Shabowah Basin are evaluated and their depositional environments are interpreted. Total organic carbon contents (TOC) of the shales range from 1.02–16.8 wt%, and yield hydrogen index (HI) values ranging from 130 to 820 mg HC/g TOC, consistent with mainly Type II with minor contributions from Type I and mixed Types II–III kerogens. The Safer shale samples have vitrinite reflectance values in the range of 0.5–1.0 Ro%, indicating early mature to peak mature stage for oil generation. Tmax values range from 429–438 °C, which are in reasonably good agreement with vitrinite reflectance data. Kerogen microscopy shows that the Safer shales are characterized by high amounts of organic matter, consisting predominantly of yellow fluorescing amorphous organic matter and alginite of marine origin. This is supported by their high content of hydrogen rich Type II and I oil-prone kerogen.The biomarker distributions of the Upper Jurassic Safer extracts are characterized by dominant low to medium molecular weight compounds (n-C14 to n-C20), low Pr/Ph ratio (<1.0), high phytane/n-C18 ratios (0.82–2.68), and predominant regular sterane C27. All biomarker parameters clearly indicate that the organic matter was derived from marine algal inputs and deposited under anoxic (reducing) conditions. Hypersaline conditions also prevailed during deposition of these sediments, as indicated by the presence of gammacerane. 相似文献
18.
Anammox, the microbial anaerobic oxidation of NH4+ by NO2− to produce N2, is recognised as a key process in the marine, freshwater and soil N cycles, and has been found to be a major sink for fixed inorganic N in the ocean. Ladderane lipids are unique anammox bacterial membrane lipids used as biomarkers for such bacteria in recent and past environmental settings. However, their fate during diagenesis and early catagenesis is not well constrained. In this study, hydrous pyrolysis experiments were performed on anammox bacterial biomass and the generated aliphatic hydrocarbons, present in oil generated at 220–365 °C, were analysed. A unique class of hydrocarbons was detected, and a representative component was isolated and rigorously identified using 2D nuclear magnetic resonance (NMR) spectroscopy. It consisted of C24 to C31 branched long chain alkanes with two internal ethyl and/or propyl substituents. The alkanes were generated above 260 °C, with maximum generation at 320 and 335 °C. Their stable carbon isotopic values were depleted in 13C, similar to carbon isotope values of the original anammox lipids, indicating that they were thermal products generated from lipids of anammox bacterial biomass. A range of sediments from different geological periods where anammox may have been an important process was screened for the presence of these compounds as possible catagenetic products. They were not detected, either because the concentration was too low, or the sediments screened were too immature for them to have been generated, or because the artificially produced products of anammox lipids may not reflect the natural diagenetic and catagenetic products of ladderane lipids. 相似文献
19.
Although the effects of biodegradation on the composition and physical properties of crude oil have been well studied, effects of in-reservoir petroleum biodegradation on molecular and isotopic compositions of crude oils are not yet clearly understood. The Alberta Basin, in western Canada, is one of the world’s largest petroleum accumulations and constitutes an ideal example of a natural suite of sequentially biodegraded oils. The basin hosts moderately to severely biodegraded petroleum, regionally distributed and in single, more or less continuous, oil columns. In this study, a series of oil samples from the Alberta heavy oil and oil sands provinces, with varying degrees of biodegradation, were analyzed to assess the impact of progressive biodegradation on the molecular and C, H, N, and S isotopic compositions of oils. The results of the molecular characterization of the hydrocarbon fraction of the studied oils show that the oils have suffered biodegradation levels from 2 to 10+ (toward the Alberta–Saskatchewan border) on the Peters and Moldowan scale of biodegradation (abbreviated PM 2 to PM 10) and from tens to hundreds on the Manco scale. Within single reservoirs, increasing biodegradation was observed from top to bottom of the oil columns at all sites studied. The whole oil stable isotopic compositions of the samples varied in the ranges δ13C = −31.2‰ to −29.0‰, δ2H = −147‰ to −133‰, δ15N = 0.3–4.7‰ and δ34S = 0.4–6.4‰. The maximum differences between δ values of samples (Δ) within single oil columns were Δ13C = 1.4‰, Δ2H = 7‰, Δ15N = 1.7‰ and Δ34S = 1.0‰. Regional variations in the isotopic compositions of oil samples from different wells (averaged values from top to bottom) were 1.2‰ for δ13C, 12‰ for δ2H, 4.1‰ for δ15N and 5.5‰ for δ34S and hence generally significantly larger variations were seen than variations observed within single oil columns, especially for N and S. It appears that even severe levels of biodegradation do not cause observable systematic variations in carbon, nitrogen or sulfur isotope composition of whole oils. This indicates that sulfur and nitrogen isotopic compositions may be used in very degraded oils as indicators for oil charge from different source rock facies. 相似文献
20.
Future climatic conditions may coincide with an increased potential for wildfires in grassland and forest ecosystems, whereby charred biomass would be incorporated into soils. Molecular changes in biomass upon charring have been frequently analysed with a focus on black carbon. Aliphatic and aromatic hydrocarbons, known to be liberated during incomplete combustion of biomass have been preferentially analysed in soot particles, whereas determinations of these compounds in charred biomass residues are scarce. We discuss the influence of increasing charring temperature on the aliphatic and aromatic hydrocarbon composition of crop grass combustion residues. Straw from rye, representing C3 grasses and maize, representing C4 grasses, was charred in the presence of limited oxygen at 300, 400 and 500 °C. Typical n-alkane distribution patterns with a strong predominance of long chain odd-numbered n-alkanes maximising at C31 were observed in raw straw. Upon combustion at 300 °C aliphatic hydrocarbons in char were dominated by sterenes, whereas at 400 °C sterenes disappeared and medium chain length n-alkanes, maximising around n-C20, with a balanced odd/even distribution were present. At a charring temperature of 500 °C n-alkane chain length shifted to short chain homologues, maximising at C18 with a pronounced predominance of even homologues. Even numbered, short chain n-alkanes in soils may thus serve as a marker for residues of charred biomass. Aromatic hydrocarbons indicate an onset of aromatization of biomass already at 300 °C, followed by severe aromatization upon incomplete combustion at 400–500 °C. The diagnostic composition of aliphatic and aromatic hydrocarbons from charred biomass affords potential for identifying residues from burned vegetation in recent and fossil soils and sediments. 相似文献