Search

With the increasing interest in unconventional resource plays, there have been important changes in the way how reservoirs and their attributes are assessed and characterized. Of particular relevance to the development of unconventional plays has been the focus on the assessment of organic porosity. A review of the available literature reveals contradictions with respect to where organic porosity develops (kerogen, bitumen, or pyrobitumen), when it develops with respect to hydrocarbon generation and cracking (within the oil window or beyond), its mode of formation (inherited or authigenic), the influence of organic carbon content, and the importance of organic porosity with respect to hydrocarbon storage and production. Many of these apparent contradictions appear to result from the nature of the data sets upon which the studies are based. Organic pore size generally limits the role that organic porosity plays in liquid-rich plays. From the available literature, it has become clear that there are number of issues that need to be clarified when addressing organic porosity. One such issue is terminology. There appears to be confusion in the usage of the terms kerogen, bitumen, and pyrobitumen. This confusion exists in the literature and reports prepared by various service providers for those engaged in the exploration and exploitation of unconventional resources. Another issue is the observed differences in the morphology of the organic pores (e.g., spongy, isolated bubbles, or fractures). Differences in pore morphology indicate multiple mechanisms for formation and/or growth of organic pores, suggesting more complexity to organic porosity development than often implied. For example, the spongy appearance of organic pores in some systems could reflect the amorphous character of some oil-prone kerogen, whereas the bubble pore character could be the result of degassing during the transition from the oil window into the gas window or an artifact of decompression and degassing as bitumen solidifies during core retrieval. Similarly, fractures could be a result of the conversion of oil to gas and the inability of the gas to escape or could be desiccation cracks, possibly formed after sample retrieval. Organic pores, if present in situ, increase space for hydrocarbon storage and increase surface area resulting in higher absorption capacity. However, the connectivity of these pores may be somewhat limited and may be dependent on the nature of the organic network, thus limiting their impact on permeability. A challenge when studying organic porosity is its observed variability within an individual reservoir. Very different spatial distribution of pores can occur between adjacent organic particles (e.g., macerals, solid bitumen) as well as within individual “macerals”. It has been suggested that this could be, in part, a result of organic–inorganic interactions although alternative interpretations have also been proposed. Further complicating the scientific understanding of organic porosity is the possibility that the act of studying the samples containing these pores may result in alteration of the rocks and the pores themselves. Therefore, observed organic pores may not be reflective of native conditions. The lack of a clear understanding of organic porosity development in unconventional mudstone reservoirs is by no means a surprise. Porosity and its development in conventional reservoirs have been studied since Sorby began the examination of sandstone thin sections in 1850 and is still under examination, while organic porosity has been studied for less than a decade. The focus of this study is to provide a review of porosity associated with the organic fraction, which may, in some shale-reservoirs, play a key role in hydrocarbon storage, migration, and production. [ABSTRACT FROM AUTHOR]

The Junggar Basin is a major oil producing province in China. Most of the oil originated from Permian lacustrine oil-prone source rocks in the basin. Kinetic parameters for oil and gas generation were obtained from confined pyrolysis experiments using gold capsules at heating rates of 20 °C/h and 2 °C/h on kerogen samples from two Permian lacustrine oil-prone source rocks (J23S3 and SS1S3) having hydrogen indices of 663 and 698 mg HC/g TOC, respectively. The kinetic properties for oil and gas generation vary substantially between these two source rocks. Assuming a burial heating rate of 5 °C/My, the temperature for 50% transformation ratio to oil is 132 °C for J23S3 and 168 °C for SS1S3. The maximum oil yields are about 604 and 770 mg/g TOC, while the maximum yields of total gaseous hydrocarbons are about 306 and 348 mg/g TOC for J23S3 and SS1S3, respectively. Gaseous hydrocarbons from the confined pyrolysis experiments include primary cracking components from kerogen and secondary cracking components from the generated oil. The secondary cracking gaseous hydrocarbons comprise up to 84.9% and 95.1% of the total, respectively, for the two source rocks in the highest temperature experiments. A practical method estimates the amount of gaseous hydrocarbons generated from these source rocks under geological conditions based on: (1) kinetic parameters for gas generation obtained from kerogen confined pyrolysis experiments in the present study, (2) the maximum yield of gaseous hydrocarbons from oil confined pyrolysis experiments from previous studies, and (3) the maximum amount of expelled oil. The maximum amounts of expelled oil range from 509–588 and 724–750 mg/g TOC with oil expulsion efficiencies in the ranges 84.3–97.4% and 94.0–97.4% for J23S3 and SS1S3, respectively, assuming that the amounts of retained oil range from 30–160 and 50–110 mg/g TOC for the two source rocks after oil expulsion based on the amounts of extracted bitumen. Consequently, the maximum yields of total gaseous hydrocarbons could be in the ranges 53.1–87.0 and 25.5–36.8 mg/g TOC, respectively, for J23S3 and SS1S3 in nature. Using the kinetic parameters for these two source rocks determined from pyrolysis experiments, oil and gas generation and expulsion were modeled for source rocks within the Lower Permian Fengcheng (P 1f ) and Middle Permian Lower Wuerhe formations (P 2w ) in the central area of the Mahu Depression, the source kitchen for most oilfields in the basin. [ABSTRACT FROM AUTHOR]

Highlights: [•] Coal, extracted coal and bitumen enriched coal were pyrolyzed. [•] Yields and compositions of bitumen, liquid n-alkanes and gases were determined. [•] Kinetic parameters for the generation and cracking of gas hydrocarbons were derived. [Copyright &y& Elsevier]

• Thermally stable ethanodiamondoids discovered in deeply buried marine oils. • Formation process of ethanodiamondoids investigated by thermal simulation. • Ethanodiamondoid-derived proxies established for oil maturity and cracking. • Abundance and isomerization of ethanodiamondoids changes during thermal evolution. • Phase type determined using concentrations of diamondoids and ethanodiamondoids. Diamondoids are often enriched in highly mature oil due to their high resistance to thermal stress. Ethanodiamondoids have similarly high thermal stability. We have detected ethanodiamondoids from 75 oil samples from deep marine carbonate strata in the Tarim Basin, China. Based on thermal simulation experiments on source rock and oil samples, we propose that ethanodiamondoids are gradually created with increasing thermal evolution and oil cracking. Their formation is likely due to free radical reactions of diamondoids with ethane or ethene formed from the cracking of alkanes. A proxy is proposed for the rapid determination of the degree of oil cracking and the petroleum phase based on the relationship between types and concentrations of ethanodiamondoids and diamondoids. [ABSTRACT FROM AUTHOR]

Abstract: In this study, changes in the abundance and distribution of diamondoids in petroleum with thermal maturity were investigated by a simulation oil cracking experiment. Highly sensitive and selective gas chromatography–triple quadrupole mass spectrometry (GC–MS–MS) was employed to quantify diamondoids at ppm and sub-ppm levels. The results indicate that diamondoids were generated primarily within the maturity range 1.0–2.1% EasyRo and destroyed at high thermal maturity (>2.1% EasyRo). Hence, the occurrence of high concentrations of diamondoids probably corresponds to the maturity range from the wet gas to the early dry gas stage (i.e., 1.5–2.5% EasyRo). Good correlations were observed between a few ratios of diamondoids (i.e., EAI, DMAI-1, DMDI-1 and TMAI-1) and EasyRo. This finding indicates that these parameters may be useful maturity indices for organic matter from the late oil window to the dry gas window. [Copyright &y& Elsevier]

Abstract: 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. δ 13C2–δ 13C3 and δ 13C1 vs. δ 13C2–δ 13C3, 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. [Copyright &y& Elsevier]

Abstract: The Carboniferous-Permian Unayzah gas condensate reservoir of the Ghazal Field in eastern Saudi Arabia contains abundant oil inclusions indicative of a palaeo-oil column. The molecular composition of a fluid inclusion rich zone at the top of the reservoir revealed a mid-mature biomarker distribution (0.80% vitrinite reflectance equivalent, VRE) that is considerably lower than that of the co-occurring reservoired fluid (1.41% VRE). Side chain cracking of the triaromatic steroids evident in the produced condensate is significantly less advanced in the inclusion oil, as is also reflected in their alkylnaphthalene distributions. The lower maturity signal in the inclusion oil is combined with calcareous related biomarkers that include relatively abundant 30-nor-17α-hopane, C24 tetracyclic terpane and alkyldibenzothiophenes, in contrast to the reservoir hydrocarbon fluid derived from the Lower Silurian Qusaiba shale. Inclusion gas is enriched in the higher hydrocarbons, which might be attributed to a high proportion of oil (or wet gas) inclusions. Fluid inclusion ethane and propane δ 13C are very close to the mean of the produced gases, but carbon dioxide δ 13C is about 5‰, and methane δ 13C 2‰ less negative than the average of the produced Ghazal gases, which may signify more than one hydrocarbon generation/population within the fluid inclusions. An earlier contribution into the Unayzah reservoir from a non-Qusaiba source may therefore be inferred to have had preceded the volumetrically more significant and more mature Qusaiba charges. Further research is needed to elucidate the source of this oil charge and its extent, which could include deep (Cambrian or Neoproterozoic) sources that might be present in the region. [Copyright &y& Elsevier]

Abstract: Three sets of pyrolysis experiments were performed for oil alone, oil plus montmorillonite and oil plus calcite at two heating rates of 2°C/h and 20°C/h in confined systems (gold capsules). The main observations can be listed as follows: (1) the ratios of i-C4/n-C4, i-C5/n-C5 and the amount of butanes (n-butane+ i-butane) are significantly higher in the experiment for oil plus montmorillonite than oil alone and oil plus calcite, indicating the acidic catalysis by montmorillonite; (2) at low conversion values (<0.5 for methane generation), the formation rates of methane and total hydrocarbon gases in all the three experiments are very similar, demonstrating that neither montmorillonite nor calcite significantly influence the primary cracking of oil components (C6+) into gaseous hydrocarbons (C1–C5), while at high conversion values (>0.5 for methane generation), the formation rates of methane and the total hydrocarbon gases in the oil plus calcite experiment are relatively lower than the other two experiments, demonstrating that calcite hindered the secondary cracking of wet gases (C2–C5) into methane; (3) both montmorillonite and calcite greatly reduce the carbon isotope fractionation during methane formation from oil cracking, resulting in substantially higher methane δ13C values in the oil plus montmorillonite or calcite experiments than for oil alone. Based on the kinetic parameters determined from the oil cracking experiments, the predicted temperatures and vitrinite reflectance values (% Easy R o) for the formation of methane and the total gaseous hydrocarbons at 10% conversion are 190–192°C and 184–187°C, and 1.90–1.93% and 1.80–1.86%, respectively at the heating rate 1°C/my, demonstrating that oils are very thermally stable in sedimentary basins. [Copyright &y& Elsevier]

Abstract: In the present work we propose the elaboration of an isotopic fractionation model predicting δ 13CCH4 during the thermal degradation of 1,2,4-trimethylbenzene, a synthetic model compound for methylated monoaromatic hydrocarbons present in oil. Optimization of the model was constrained by experimental data above 30% conversion at 425, 450 and 475°C. The optimized model accurately predicted experimental δ 13CCH4 at the three temperatures. A ratio of frequency factors Ω =1.028 and variations of activation energies between 36 and 79cal/mol were obtained. The extrapolation of the model prediction at a burial rate of 50m/Ma and geothermal gradient of 25°C/km illustrated the greater isotopic fractionation of the CH4 generated under geological conditions than under laboratory conditions. Moreover, CH4 generated from the thermal degradation of 1,2,4-trimethylbenzene was systematically depleted in 13C (−43‰< δ 13CCH4 <−35‰ for 1.6%< R 0 <2.6%) compared with CH4 generated from the late primary cracking of kerogen in the same maturity range. Our results obtained on a synthetic molecule still need to be confirmed on a natural sample. If confirmed, they would suggest that in thermal settings, isotopically 13C depleted CH4 might not be necessarily the result of mixing with microbial CH4 but could constitute evidence of the secondary cracking of the reservoired oil. [Copyright &y& Elsevier]

Abstract: The scope of the present study was to characterize the pathways leading to CH4 generation during the thermal degradation of a model compound representative of methylated monoaromatic hydrocarbons present in many crude oils. 1,2,4-trimethylbenzene was selected and subjected to pyrolysis experiments from 395 – 450°C (at 100bar). The whole range of reactant conversions was studied. All pyrolysis fractions were recovered and quantified. All products that could be quantified individually were used to develop a mechanistic kinetic model of 122 reversible reactions involving 47 species up to C18. The model was validated on our experimental results for conversions below 70%. The model was then used to assess the relative contributions of specified CH4 generation pathways at high (425°C) and low (200°C) temperatures. For the present case study, it was demonstrated that the pathways accounting for CH4 generation were the same at both temperatures. At low conversions, CH4 was mainly generated by the ‘polyaromatic route’, i.e. the dimerization of monoaromatics (step 1) followed by the intramolecular ring closure of these dimers (step 2). The contribution of the ‘monoaromatic route’, i.e. the successive demethylation reactions of methylated monoaromatics, was lower but not negligible. At higher conversions the contribution of the ‘monoaromatic route’ increased, eventually accounting for around 50% of the overall yield of CH4 at 70% conversion. Within the ‘polyaromatic route’, step 1 and step 2 quickly exhibited similar contributions, eventually sharing the remaining 50% of the overall CH4 yield at 70% conversion. [Copyright &y& Elsevier]

Abstract: The scope of the present study was to develop an empirical kinetic model predicting, over the whole range of reactant conversions (0–100%), the yield of CH4 generated from the thermal degradation of 1,2,4-trimethylbenzene, a model compound for methylated mono-aromatic hydrocarbons present in oil. Most of the chemical equations of the model were constrained by our previous mechanistic model (). The resulting reaction scheme was composed of four CH4 generation pathways: (Pa ) dimerization of 1,2,4-trimethylbenzene, (Pb ) demethylation of 1,2,4-trimethylbenzene into xylenes, (Pc ) condensation reactions of dimers and C18+ products into (prechar+char) components and (Pd ) dimerization of xylenes and their demethylation into toluene. Associated activation energies were in the range 52–61kcalmol-1 and frequency factors were all in the neighborhood of 1012 s−1. Below 5% conversion, Pb and Pc governed CH4 generation, followed by Pa . Above 5% conversion, Pc was the main source of CH4, followed by Pb and Pa , respectively. Pd showed negligible CH4 yields up to 95% conversion. Above 100% conversion, the degradation of (prechar+char) components seemed the most likely new source of gas which was not accounted for in the model. Using a unique chemical equation with a maximum CH4 yield of 7.6wt% per CH3 group and an associated set of kinetic parameters Ea =58.5kcalmol-1 and A =1011.96 s−1, we demonstrated CH4 generation kinetics from the thermal degradation of 1,2,4-trimethylbenzene to be similar to CH4 generation kinetics previously reported from the thermal degradation of methylated polyaromatic hydrocarbons. Eventually, the four-equation empirical model was used to perform simulations under temperature conditions usually encountered in deeply buried reservoirs (DBR). Under these conditions, the simulations revealed the CH4 prone character of methylated mono-aromatic hydrocarbons. Moreover, these simulations demonstrated that the thermal stability increased as follows: methylated polyaromatics

Abstract: Kerogen separated from an immature Type I mudstone from the third section of the Tertiary Shahejie Formation () in the Dongying Depression of Bohai Bay Basin was subjected to stepwise isothermal pyrolysis. Products were extracted, fractionated into chemical groups, and re-mixed to obtain a synthetic oil with a group composition similar to reservoir oil and a pseudo-kerogen composed of 83% kerogen and 17% residual soluble organic matter (referred as s-oil and p-kerogen, respectively, to distinguish them from a produced reservoir oil and a real kerogen). The two samples were pyrolyzed in sealed gold tubes under constant pressure (50MPa) and non-isothermal heating (300–600°C) conditions and their generated gases were analyzed. The two gases are quite different in their chemical and isotopic composition. Compared with the gas derived from the p-kerogen, the s-oil derived gas is enriched in C2–C5 hydrocarbons in its early cracking stages and C1–C3 hydrocarbons are depleted in δ13C throughout the cracking stages. The maximum wetness (C2–5/C1–5) of the s-oil gas and the p-kerogen gas is 0.62 and 0.35, respectively, and the carbon isotopic ratio differences between the two type gases can reach 10‰ (δ13C1), 14‰ (δ13C2), and 9‰ (δ13C3). The δ13C2–δ13C3 difference of the s-oil gas is much more sensitive to thermal stress than that of the p-kerogen gas and plots of (δ13C2–δ13C3) versus δ13C1 and (δ13C2–δ13C3) versus ln(C2/C3) are effective in identifying the two gas types in some geological conditions. These results provide a guide to differentiate gases derived from oil cracking from gases derived from kerogen maturation using their chemical and carbon isotopic compositions in some simple petroleum systems. [Copyright &y& Elsevier]

Abstract: New Zealand coals of peat to high volatile bituminous rank have been studied in order to assess the effect of in-situ bitumen (soluble in a methanol:acetone:chloroform azeotrope), on petroleum potential during progressive maturation. Both non-extracted and extracted coals, as well as the extracted bitumen itself, were analyzed using Rock-Eval and pyrolysis gas chromatography. The difference in yields between non-extracted and extracted coals, attributable to the influence of bitumen, were compared with direct measurements made on the bitumen itself. Major compositional changes in pyrolysis products were seen when the bitumen was finely dispersed throughout the kerogen matrix. Notably, second-order reactions between kerogen and bitumen during pyrolysis reduce primary gas yield and enhance both oil yield and potential secondary gas yield. The stabilization of free radicals, and prevention of recombination/repolymerization processes have been attributed to the presence of the dispersed in-situ bitumen. These results demonstrate that petroleum formation in coals likely proceeds via intermolecular interactions and not simply first order cracking. The common procedure of employing solvent extraction prior to pyrolysis is clearly not appropriate when assessing the petroleum potential of coal. [Copyright &y& Elsevier]

Abstract: The aim of this work is to get new insights into oil cracking mechanisms. The investigation was focused on the thermal stability of the heavy chemical classes such as the C14+ saturates, C14+ aromatics, and the polar fraction (resins+asphaltenes). Artificial maturation was performed in closed pyrolysis system in the temperature range 300–375°C for following a large range of conversion for the three initial chemical classes. Pyrolysis products are described as H2S, C1, C2, C3–C4 gases, C6–C14 saturates, C6–C14 aromatics, C14+ saturates, C14+ aromatics, NSOs and prechar. In a first step, the total C14+ aromatics of the initial oil was isolated and artificially matured. They generated a significant part of saturated compounds and new heavy aromatics which were assumed to be methylated structures. The proportion of initial and produced aromatics was determined based on the decrease of the hydrogen content. Then, a kinetic model was elaborated for their specific bulk and compositional kinetic parameters which was taken as an initial guess when optimising the global kinetic model for the total C14+ oil. A tentative global kinetic model for the total C14+ oil was elaborated which well simulated laboratory experiments for both global conversions and yields of generated products. When this model is used for extrapolating laboratory results to natural reservoirs assuming a geothermal heating rate of 2°C/Ma, predicted oil thermal behavior is not in contradiction with observed field data. Indeed, aromaticity is decreasing above 140°C whereas, the yield of C14+ saturates starts to decrease above 170–180°C. However this comparison is only qualitative since this model was not integrated into a real case study in which the full process of generation–expulsion and oil cracking must be totally described. The reverse relative thermal stability of the C14+ saturates and aromatics between laboratory and geological conditions is explained by the large difference of A and E of the two chemical classes. Finally, this model was elaborated on a Type II oil only and needs to be tested also on other oils of different chemical composition, either paraffinic or enriched in NSOs. [Copyright &y& Elsevier]

Abstract: The aim of this work is to follow the generation of NSO compounds during the artificial maturation of an immature Type II kerogen and a Type III lignite in order to determine the different sources of the petroleum potential during primary cracking. Experiments were carried out in closed system pyrolysis in the temperature range from 225 to 350°C. Two types of NSOs were recovered: one is soluble in n-pentane and the second in dichloromethane. A kinetic scheme was optimised including both kerogen and NSO cracking. It was validated by complementary experiments carried out on isolated asphaltenes generated from the Type II kerogen and on the total n-pentane and DCM extracts generated from the Type III lignite. Results show that kerogen and lignite first decompose into DCM NSOs with minor generation of hydrocarbons. Then, the main source of petroleum potential originates from secondary cracking of both DCM and n-pentane NSOs through successive decomposition reactions. These results confirm the model proposed by Tissot [Tissot, B., 1969. Premières données sur les mécanismes et la cinétique de la formation du pétrole dans les bassins sédimentaires. Simulation d’un schéma réactionnel sur ordinateur. Oil and Gas Science and Technology 24, 470–501] in which the main source of hydrocarbons is not the insoluble organic matter, but the NSO fraction. As secondary cracking of the NSOs largely overlaps that of the kerogen, it was demonstrated that bulk kinetics in open system is a result of both kerogen and NSO cracking. Thus, another kinetic scheme for primary cracking in open system was built as a combination of kerogen and NSO cracking. This new kinetic scheme accounts for both the rate and amounts of hydrocarbons generated in a closed pyrolysis system. Thus, the concept of successive steps for hydrocarbon generation is valid for the two types of pyrolysis system and, for the first time, a common kinetic scheme is available for extrapolating results to natural case studies. [Copyright &y& Elsevier]

The objectives of this pyrolysis investigation were to determine changes in (1) oil composition, (2) gas composition and (3) gas carbon isotope ratios and to compare these results with hydrocarbons in reservoirs. Laboratory cracking of a saturate-rich Devonian oil by confined, dry pyrolysis was performed at T=350–450 °C, P=650 bars and times ranging from 24 h to 33 days. Increasing thermal stress results in the C15+ hydrocarbon fraction cracking to form C6–14 and C1–5 hydrocarbons and pyrobitumen. The C6–14 fraction continues to crack to C1–5 gases plus pyrobitumen at higher temperatures and prolonged heating time and the δ 13Cethane–δ13Cpropane difference becomes greater as oil cracking progresses. There is considerable overlap in product generation and product cracking. Oil cracking products accumulate either because the rate of generation of any product is greater than the rate of removal by cracking of that product or because the product is a stable end member under the experimental conditions. Oil cracking products decrease when the amount of product generated from a reactant is less than the amount of product cracked. If pyrolysis gas compositions are representative of gases generated from oil cracking in nature, then understanding the processes that alter natural gas composition is critical. [Copyright &y& Elsevier]