Geology of the Devonian black shales of the Appalachian Basin

Black shales of Devonian age in the Appalachian Basin are a unique rock sequence. The high content of organic matter, which imparts the characteristic lithology, has for years attracted considerable interest in the shales as a possible source of energy. The recent energy shortage prompted the U.S. Department of Energy through the Eastern Gas Shales Project of the Morgantown Energy Technology Center to underwrite a research program to determine the geologic, geochemical, and structural characteristics of the Devonian black shales in order to enhance the recovery of gas from the shales. Geologic studies by Federal and State agencies and academic institutions produced a regional stratigraphic network that correlates the 15 ft black shale sequence in Tennessee with 3000 ft of interbedded black and gray shales in central New York. These studies correlate the classic Devonian black shale sequence in New York with the Ohio Shale of Ohio and Kentucky and the Chattanooga Shale of Tennessee and southwestern Virginia. Biostratigraphic and lithostratigraphic markers in conjunction with gamma-ray logs facilitated long-range correlations within the Appalachian Basin. Basinwide correlations, including the subsurface rocks, provided a basis for determining the areal distribution and thickness of the important black shale units. The organic carbon content of the dark shales generally increases from east to west across the basin and is sufficient to qualify as a hydrocarbon source rock. Significant structural features that involve the black shale and their hydrocarbon potential are the Rome trough, Kentucky River and Irvine-Paint Creek fault zone, and regional decollements and ramp zones.     

鄂尔多斯盆地南部长7暗色泥岩与黑色页岩生烃动力学特征对比分析

以往对鄂尔多斯盆地南部地区长7油层组(简称长7)中烃源岩生烃潜力的研究主要是采用静态地球化学指标进行的,目前尚无对生烃动态特征的系统评价,因而制约了对长7烃源岩生烃潜力和页岩油资源分布有利岩性的客观认识。为此,选取长7不同类型的烃源岩样品,通过开放和封闭热模拟实验,对比分析了不同类型烃源岩的动力学参数、生烃产物、产率特征及生烃演化规律。结果表明:(1)黑色页岩活化能分布范围比暗色泥岩更为集中,且主频活化能和频率因子均低于暗色泥岩,体现了快速生烃的特性;(2)在外推到地质条件下,黑色页岩主要生烃期对应的R_o值(0.70%~0.87%)低于暗色泥岩(1.06%~1.72%),且以生油为主;(3)R_o在0.9%~1.3%范围内,黑色页岩的总烃产率高于暗色泥岩,生油量高于暗色泥岩。结合研究区两类烃源岩的地球化学资料综合分析表明,黑色页岩是研究区页岩油资源形成与分布的有利烃源岩。     

Gas-generation potential of shales in small and medium-sized basins: a case study from the Xuanhua Basin,north China

Abstract

Small- and medium-sized basins are widely distributed, and some contain commercial gas reservoirs demonstrating their gas-generation potential. The Xuanhua Basin, which is a small-sized coal-bearing basin in north China, includes a promising target for shale-gas exploration in the Xiahuayuan Formation. In this study, we used this basin as a case study to assess the critical geochemical features for small or medium-sized basins to form commercial gas reservoirs. Total organic carbon (TOC) analysis, Rock-Eval pyrolysis, microscopic observation of macerals, vitrinite reflectance measurement and kerogen stable carbon isotope analysis were performed to characterise the organic geochemistry of the Xiahuayuan shales. The original total organic carbon (TOC_o) content and hydrocarbon-generative potential (S_2o) were reconstructed to further evaluate the gas-generation potential of these shales. In addition, geochemical data of shales from other similar-sized basins with gas discoveries were compared. The results showed that the kerogen from the Xiahuayuan Formation is Type III (gas-prone), and macerals are dominated by vitrinite. TOC values showed a strong heterogeneity in the vertical profiles, with most higher than 1.5?wt%. The measured R_o values ranged from 1.4 to 2.0%. However, thermal maturity was not correlated with the present-day burial depth with higher maturity in the wells closest to the diabase intrusion centre. The remaining generation potential (S₂) averaged 0.91?mg HC/g rock, equal to 1.4?cm³ CH₄/g rock, and the average amount of hydrocarbon generated was 4.33?cm³ CH₄/g rock. In small and medium-sized basins, the TOC content of commercially developed gas shales ranged from 0.5 to 2.5?wt%, organic matter was mainly humic (gas-prone), and the burial depth was generally shallow. Biogenic gas reservoirs for commercial exploitation tend to have larger shale thicknesses (120–800?m) than thermogenic gas reservoirs (60–90?m).

1. The Xiahuayuan Formation is a good gas-source rock with gas-prone kerogen type, relatively high TOC values and moderate thermal maturity.

2. The average amount of hydrocarbon generated from the Xiahuayuan shales is about 4.33?cm³ CH₄/g rock, indicating a potential to form a shale gas reservoir.

3. Owing to the influence of diabase intrusions, the Xiahuayuan shales have entered the dry gas window at relatively shallow-buried depths.

4. Small- and medium-sized basins have the potential to generate commercial gas reservoirs with the generated volume mainly a product of the thickness and maturity of black shales.

     

Natural gas potential of Neoproterozoic and lower Palaeozoic marine shales in the Upper Yangtze Platform,South China: geological and organic geochemical characterization

In this article, we describe the geological features of the Ediacaran (upper Sinian), lower Cambrian and lower Silurian shale intervals in the Upper Yangtze Platform, South China, and report on the gas potential of 53 samples from these major marine shale formations. Reflected light microscopy, total organic carbon (TOC) measurement, Rock-Eval, carbon isotope ratio analysis, thermovaporization gas chromatography (Tvap-GC), and open pyrolysis gas chromatography (open py-GC) were used to characterize the organic matter. Measured TOC in this research is normally >2% and averages 5%. TOC contents are roughly positively correlated with increasing geological age, i.e. lower Silurian shales exhibit generally lower TOC contents than lower Cambrian shales, which in turn commonly have lower TOC contents than Ediacaran shales. Kerogen has evolved to the metagenesis stage, which was demonstrated by the abundant pyrobitumen on microphotographs, the high calculated vitrinite reflectance (R_o = 3%) via bitumen reflectance (R_b), as well as δ¹³ C of gas (methane) inclusions. Pyrolysates from Tvap-GC and open py-GC are quantitatively low and only light hydrocarbons were detected. The lower Silurian shale generally exhibits higher generation of hydrocarbon than the lower Cambrian and Ediacaran shale. Cooles’ method and Claypool’s equations were used to reconstruct the original TOC and Rock-Eval parameters of these overmature samples. Excellent original hydrocarbon generation was revealed in that the original TOC (TOC_o) is between 5% and 23%, and original S1+S2 (S1_o+S2_o) is ranging from 29 to 215 mg HC/g rock.     

Calcareous nannofossils from late Jurassic sediments of the Volga Basin (Russian Platform): evidence for productivity-controlled black shale deposition

The Jurassic/Cretaceous boundary interval in the northern hemisphere is characterized by the widespread occurrence of black shales. About 60% of all petroleum source rocks comprise sediments of late Jurassic and early Cretaceous age with the origin of such black shales still under discussion. In order to better understand the factors that controlled black shale sedimentation, 78 samples were analyzed for calcareous nannofossils from two sections (Gorodische, Kashpir) of the Volga Basin (NE Russia). Calcareous nannofossils are ideal proxies for deciphering nutrient, temperature and salinity fluctuations. Additionally 58 samples from both sections were also analyzed for clay mineralogy, ¹³C_org , TOC and CaCO₃ composition. Both sections contain calcareous claystones and intercalated organic rich shales overlain by phosphorite beds. The presence of the calcareous nannofossil species Stephanolithion atmetros throughout both successions allows a biostratigraphic assignment to the S. atmetros Nannofossil Biozone (NJ 17), which corresponds to the Dorsoplanites panderi Ammonite Biozone of the Middle Volgian. The marlstones of the Kashpir section yield a well-preserved rich and diverse nannoflora, whereas all black shale beds are essentially barren of calcareous nannofossils. Only the uppermost black shale layers yield an impoverished assemblage of low diversity and abundance. Geochemical data suggest an early diagenetic nannofossil dissolution in the black shales of the Kashpir section. This is supported by the occurrence of coccoliths in black shale horizons of the Gorodische section. The assemblages in both sections are dominated by coccoliths of the Watznaueriaceae group (Watznaueria barnesae, Watznaueria fossacincta, Watznaueria britannica, Watznaueria communis), Biscutum constans and Zeugrhabdotus erectus. In Kashpir rare specimens of Crucibiscutum salebrosum occur in the higher part of the section. These taxa indicate boreal affinities. B. constans and Z. erectus are considered to be taxa indicative of a higher productive environment, while C. salebrosum is a cool-water species. From base to top of the Kashpir section, consecutive mass occurrences of different taxa/groups were observed: W. barnesae–W. fossacincta acme, W. britannica–W. communis acme, Z. erectus acme, B. constans acme (including sparse occurrences of C. salebrosum).The observed distribution patterns have been interpreted as characterizing a transition from a low productive, oligotrophic setting with high abundances of K-selected cosmopolitan species (Watznaueriaceae) and predominating marlstone sedimentation to a higher productive, mesotrophic setting. Cooler water temperatures marked by r-selection and acmes of opportunistic species (Z. erectus, B. constans) are coincident with the deposition of black shales and phosphorites in the higher part of the section. Interpretation of clay mineral distribution indicates that black shale deposition occurred under semi-arid hinterland climatic conditions concomitant with a sea level rise. This induced dysoxic conditions in the deeper parts of the Volga Basin, favoring the preservation of organic matter. The cause of the nutrient enrichment in the surface water is still unclear, but possible river water input from the continents does not seem to have been the controlling factor under a semi-arid climate. The occurrence of phosphorites in the upper part of both sections presumably indicates that enhanced productivity may be better explained by the upwelling of nutrient-rich bottom water and thereby causing the recycling of nutrients from oxidized phytoplankton back into the photic zone. This recycling effect finally may have led to an intensified phytoplankton growth which seemed to be a sufficient source for the enrichment of organic matter. This is well correlated with the increase in black shale horizons in the upper part of the Kashpir section.     

Biological marker compounds as indicators of the depositions! history of the Maoming oil shale

The Eocene Maoming oil shale from Guangdong Province occurs as a laterally uniform stratigraphic section, typically 20–25 m thick, from which the aliphatic hydrocarbon constituents of six representative samples were investigated using GC and C-GC-MS. The sediments evaluated included the basal lignite, a vitrinite lens from the overlying claystone, and four intervals from the massive oil shale bed. As expected, the lignite and vitrinite differ markedly from the oil shales. The lignite is dominated by bacterial hopanoids and components of higher plant origin, including C₂₉ steroids and triterpenoids such as oleanenes. Visually, the oil shale samples show corroded and degraded phytoclasts, spores, wispy particles of fluorescent organic material attributable to dinoflagellates and, especially in the uppermost sample, colonial algal bodies. The distributions of biological markers in the oil shales show many features in common, notably a dominance of dinoflagellate-derived 4-methylsteroids, and a significant proportion of higher-plant derived n-alkanes with marked odd-over-even carbon number predominance. Overall, they exhibit several features that resemble characteristics of the Messel shale. The hydrocarbons of the lowest shale horizon suggest that there may have been a gradual transition between deposition of the original peat and the subsequent oil shales. The aliphatic hydrocarbons of the uppermost shale are dominated by a number of C₃₁ and C₃₃ botryococcane homologues and other unusual branched alkanes possibly derived from green algae. All of the samples are immature. Overall, molecular and microscopic examination of the stratigraphic succession of the Maoming oil shale suggests a shallow, lacustrine environment within which peats were deposited. This lake subsequently deepened to support abundant algal populations, especially dinoflagellates, culminating in a dominance of botryococcoid algae.     

Geochemical characteristics of the Xuanwei Formation in West Guizhou: Significance of sedimentary environment and mineralization

The Upper Permian Xuanwei Formation widely occurs in western Guizhou, unconformably overlying the Emeishan basalts, and mainly consists of black shales. It is ∼170 m thick at Cuyudong Village, Weining County, West Guizhou, China, where the samples of black shale and sandy shale were collected and analyzed. The shales mainly contain SiO₂, 18.9%–44.1%, Al₂O₃, 14.8%–52.8%, Fe₂O₃, 1.0%–41.2%, LOI, 3.2%–21.1%, TiO₂, 1.0%–6.7%, and MgO, 0.2%–2.5%. The contents of all other major elements are lower than 1.0%. It is shown that the black shales have higher contents of Fe₂O₃ and LOI than normal shales. The siderites occurred in the black shales with higher contents of Fe₂O₃, which may be attributed to hydrothermal activities on seafloor. All analyzed shale samples have extremely high Ga, 47.8×10⁻⁶–109.9×10⁻⁶ (70.5×10⁻⁶ on average), higher than the industrial mining standard of Ga Resource Industry Standard. The total contents of rare-earth elements (REE) of 9 black shale samples vary from 213×10⁻⁶ to 1460×10⁻⁶, suggesting that these black shales are enriched in REE. The shale-normalized REE patterns display both positive and negative Ce anomalies (Ce/Ce* from 0.5 to 1.7), revealing that the Xuanwei shales were precipitated under oxic and anoxic conditions. The Rb-Sr chronological diagram of 6 shale samples in the Xuanwei Formation shows an age of 255±12 Ma. Strontium isotopic ratios (⁸⁷Sr/⁸⁶Sr)_t0 range from 0.70635 to 0.70711, suggesting that these Xuanwei black shales might be derived from chemical weathering of the Emeishan basalts.     

Geological and geochemical characteristics of the Middle–Lower Jurassic shales in the Kuqa Depression,Tarim Basin: an evaluation of shale gas resources

Middle–Lower Jurassic terrigenous shales constitute a set of significant hydrocarbon source rocks in the Kuqa Depression of the Tarim Basin. Until recently, however, most investigations regarding this set of hydrocarbon source rocks have mainly focused on conventional oil and gas reservoirs, and little research has been conducted on the formation conditions of shale gases. This research, which is based on core samples from nine wells in the Kuqa Depression, investigated the geological, geochemical, mineralogical and porosity characteristics of the shales, analysed the geological and geochemical conditions for the formation of shale gases, and evaluated the shale gas resource potential. The results show that the distribution of the Middle–Lower Jurassic shales is broad, with thicknesses reaching up to 300–500 km. The total organic carbon (TOC) content is relatively high, ranging from 0.2 to 13.5 wt% with a mean of 2.7 wt%. The remaining hydrocarbon generative potential is between 0.1 and 22.34 mg/g, with a large range of variation and a mean value of 3.98 mg/g. It is dominated by type III kerogen with the presence of minor type II₁ kerogen. The vitrinite reflectance values range from 0.517 to 1.572%, indicating the shales are in a mature or highly mature stage. The shales are mainly composed of quartz (19–76%), clay (18–68%) and plagioclase (1–10%) with mean contents of 50.36 wt%, 41.42 wt%, and 3.37 wt%, respectively. The pore spaces are completely dominated by primary porosity, secondary porosity and microfractures. The porosity is less than 10% and is mainly between 0.5 and 4%, and the permeability is generally less than 0.1 mD. These results classify the shale as a low-porosity and ultra-low-permeability reservoir. The porosity has no obvious correlation with the brittle or clay mineral contents, but it is significantly positively correlated with the TOC content. The maximum adsorbed gas content is between 0.82 and 8.52 m³/t with a mean of 3.37 m³/t. In general, the shale gas adsorption content increases with increasing the TOC content, especially when the TOC content is greater than 1.0%. The volumetric method, used to calculate the geological resources of the Middle–Lower Jurassic shales in the Kuqa Depression, shows that the geological resources of the Middle and Lower Jurassic shales reach 667.681 and 988.115 × 10⁹ m³, respectively with good conditions for the formation of shale gas and good prospects for shale gas exploration.     

Albian oceanic anoxic events in northern Tunisia: Biostratigraphic and geochemical insights

Albian pelagic successions of the Nebeur area in northwestern Tunisia consist of radiolarian-bearing and organic-rich black shale beds, which represent the lower part of the Fahdene Formation. The carbonate content of the organic-rich beds ranges between 40 and 48%. Total organic carbon (TOC) analyses via Rock Eval pyrolysis yielded values ranging between 0.7 and 2.8% and a mixed marine/terrestrial origin. T_max values vary between 424 and 450 °C, indicative of submature to mature organic matter. High resolution planktic foraminiferal and radiolarian biostratigraphy suggest that the black shales beds span the mid- to late Albian, confined to the middle part of the Ticinella primula zone, upper Biticinella breggiensis zone and lower appeninica + buxtorfi zone. Episodes of organic-rich deposition in the “Tunisian Trough” are interpreted as being the sedimentary record of the global oceanic anoxic events OAE1b, c, and d respectively. Age-diagnostic radiolarian assemblages recovered from late Albian organic-rich black shales lie within the UA13–UA14 boundary biochronozones. The abundance of radiolarian and calcispheres (i.e. pithonella) within the black shales suggests high productivity periods and eutrophic conditions probably triggered by upwelling currents.     

下扬子皖南大隆组黑色岩系发育特征及油气资源潜力初探

下扬子地区上二叠统大隆组黑色岩系是区域潜在的烃源层,但过去关注较少。为加深对该问题的认识,本文以新近在皖南地区发现的3条剖面为例,通过详细的岩石学和有机地球化学综合研究,讨论了大隆组黑色岩系的发育特征及油气资源潜力。结果表明,宣城牛山、泾县蔡村和泾县昌桥三条剖面中大隆组黑色岩系均稳定发育,岩石类型包括硅质岩、钙质泥岩和硅质泥岩等。综合地层对比和沉积学研究结果,发现研究区在大隆期经历了一个完整的海进—海退的沉积旋回,黑色岩系主要发育于深水、还原滞留、欠补偿的海洋环境。岩石学和有机地球化学研究结果显示该地区大隆组黑色岩系的有机质丰度高,有机碳含量平均在2.0%左右,有机质类型以II_2和III型为主,并普遍进入高过成熟演化,因此区域勘探应以天然气勘探为主。对比研究区大隆组黑色岩系与中新生代火成岩的分布关系,推测大隆组黑色岩系中有机质的高过成熟演化可能与华南中新生代大规模的岩浆作用影响有关,因此在未受/少受影响的地区(例如泾县—广德一带),也可能存在一定的原油资源潜力。这些认识还可供区域黑色岩系基础地质研究参考。     

Benthic foraminiferal assemblages of late Aptian-early Albian black shale intervals in the Vocontian Basin, SE France

Benthic foraminiferal assemblages were analyzed from three black shale intervals in the upper Aptain to lower Albian of the Vocontian Basin, SE France based on Q-mode principal component analyses. Variations in the distribution patterns of benthic foraminifera around these events suggest differences in the origin of the black shales. Differences between faunas of bioturbated marly and laminated black shale facies have been observed in the Niveau Paquier, Oceanic Anoxic Event (OAE) 1b and Niveau Leenhardt. Here, the faunal composition and plankton/benthos ratios suggest eutrophic conditions during the deposition of organic-rich sediments leading to black shales. No major variations have been observed in black shales of the upper Aptain Niveau Jacob. Benthic assemblages and low plankton/benthos ratios indicate mesotrophic conditions. Third order sea-level changes are believed to control mainly the origin of the investigated black shale levels.     

鄂尔多斯盆地北部山西组页岩沉积相及其对页岩储层的控制作用

鄂尔多斯盆地北部山西组页岩气储层与煤层共生,页岩有机质含量较高,具有较大的资源勘探潜力。为精细表征控制山西组页岩储层分布的沉积微相,根据测井数据、录井数据、岩芯观察描述、薄片分析、粒度分析、X射线衍射全岩分析以及总有机碳含量(TOC),研究了山西组页岩储层岩相与沉积微相类型,在山西组识别出(灰)黑色碳质页岩、(灰)黑色含碳质页岩、(灰)黑色含碳质(粉)砂质页岩、(深)灰色含碳质页岩、(深)灰色页岩、(深)灰色(粉)砂质页岩和含钙质页岩7种岩相。这些岩相沉积在富植沼泽、贫植沼泽、三角洲平原分流间洼地、曲流河河间洼地、天然堤与决口扇远端微相环境,其中富植沼泽、贫植沼泽与成煤的泥炭沼泽、泥炭坪环境比邻共生,且在山二段时期更发育。富植沼泽和贫植沼泽微相控制了具有较高TOC的(灰)黑色碳质页岩、(灰)黑色含碳质页岩、(灰)黑色含碳质(粉)砂质页岩和(深)灰色含碳质页岩的分布,是控制山西组页岩储层分布的有利微相。     

湘西北地区寒武系牛蹄塘组页岩气资源前景

湘西北地区牛蹄塘组黑色页岩展布广泛,为寒武纪纽芬兰世—第二世滞留还原条件的沉积产物,适中的埋深和较大的厚度为其提供了良好的气藏条件。对其有机地化参数进行试验分析:TOC值为0.59%～13.05%,均值3.75%,有机质丰富;R_o值为1.87%～4.00%,均值3.05%,成熟度高;干酪根类型以Ⅰ型为主,少量为Ⅱ型,具有良好的生气潜力;矿物组成中脆性矿物含量为33%～87%,平均含量为68%,而黏土总量为13%～43%,平均为26%,脆性矿物/黏土矿物值高,有利于储层改造;页岩孔隙度为0.3%~8.0%,平均为3.3%,渗透率均小于0.04×10^-3μm²,为低孔低渗类型。综合研究表明,牛蹄塘组具有良好的页岩气生储潜力,同时运用条件概率体积法对其资源量进行评估计算,资源量十分可观。在此基础上对湘西北地区牛蹄塘组划分出6个页岩气有利区,为进一步实施页岩气勘查提供依据。     

阿尔金山前下—中侏罗统页岩气成藏地质条件分析

阿尔金山前侏罗系出露大套厚层的暗色泥页岩,生烃潜力优越,具备陆相页岩气形成条件,是有利的勘探接替区。通过野外地质调查、样品采集和测试分析,研究下—中侏罗统泥页岩的沉积展布、有机地球化学特征及储集性能,并探讨了该区页岩气的勘探潜力。研究表明: 富有机质泥页岩主要处于滨浅湖—半深湖相、沼泽相沉积环境中,其在平面上呈NE向展布,单层厚度和累计厚度均较大; 泥页岩的有机质类型主要为Ⅱ₁、Ⅱ₂型干酪根; TOC含量为0.55%~10%,平均为2.28%; 镜质体反射率(R_o)为1.0%~1.6%,平均为1.269%,处于成熟—高成熟阶段,为页岩气藏形成提供良好的生烃条件; 其矿物特征表现为脆性矿物含量高,大于51%,有利于后期的水力压裂改造和页岩气开采; 通过扫描电镜观察,泥页岩储层发育微孔隙及微裂缝,为页岩气提供了良好的储集空间和运移通道。初步预测,后期改造相对较弱的月牙山地区为页岩气勘探的有利目标区。     

阿尔金山前下—中侏罗统页岩气成藏地质条件分析

阿尔金山前侏罗系出露大套厚层的暗色泥页岩,生烃潜力优越,具备陆相页岩气形成条件,是有利的勘探接替区。通过野外地质调查、样品采集和测试分析,研究下—中侏罗统泥页岩的沉积展布、有机地球化学特征及储集性能,并探讨了该区页岩气的勘探潜力。研究表明: 富有机质泥页岩主要处于滨浅湖—半深湖相、沼泽相沉积环境中,其在平面上呈NE向展布,单层厚度和累计厚度均较大; 泥页岩的有机质类型主要为Ⅱ₁、Ⅱ₂型干酪根; TOC含量为0.55%~10%,平均为2.28%; 镜质体反射率(R_o)为1.0%~1.6%,平均为1.269%,处于成熟—高成熟阶段,为页岩气藏形成提供良好的生烃条件; 其矿物特征表现为脆性矿物含量高,大于51%,有利于后期的水力压裂改造和页岩气开采; 通过扫描电镜观察,泥页岩储层发育微孔隙及微裂缝,为页岩气提供了良好的储集空间和运移通道。初步预测,后期改造相对较弱的月牙山地区为页岩气勘探的有利目标区。     

南襄盆地泌阳凹陷核桃园组三段纹层状泥页岩地球化学特征及其成因解释

黑白相间纹层状页岩是沉积岩中非常重要且常见的一种岩石类型。采用X射线荧光岩心扫描仪对泌阳凹陷5号页岩层中纹层状页岩样品进行测试,分析结果显示湖相纹层中一些指标,如Sr、CaO、K2O、SiO2、TiO2、Fe2O3、Al2O3、Cu含量在纹层中表现出明显规律性变化,即白色纹层中Sr和CaO含量明显高于黑色纹层,而K2O、SiO2、TiO2、Fe2O3、Al2O3、Cu含量明显低于黑色纹层。硼元素以及古氧化还原和古气候指标表明纹层状页岩主要发育在半干旱-干旱的半咸化-咸化分层水体。镜下鉴定揭示,黑色条纹主要为高有机质泥质沉积物,白色条纹主要为方解石、石英以及白云石等矿物,黑白纹层的物质成分组成与陆源供给和水体咸化后自身形成的矿物密切相关。黑白纹层中元素差异变化揭示了不同矿物组成的差异,也揭示出陆相湖盆季节性韵律变化。     

Hydrocarbon generation and expulsion characteristics of Lower Permian P1f source rocks in the Fengcheng area,northwest margin,Junggar Basin,NW China: implications for tight oil accumulation potential assessment

Combined with the actual geological settings, tight oil is the oil that occurs in shale or tight reservoirs, which has permeability less than 1 mD and is interbedded with or close to shale, including tight dolomitic oil and shale oil. The Fengcheng area (FA), at the northwest margin of the Junggar Basin, northwest China, has made significant progress in the tight oil exploration of the Fengcheng (P₁f) Formation recently, which indicates that the tight oil resources have good exploration prospects. Whereas the lack of recognition of hydrocarbon generation and expulsion characteristics of Permian P₁f source rocks results in the misunderstanding of tight oil resource potential. Based on the comprehensive analysis of geological and geochemical characteristics of wells, seismic inversion, sedimentary facies, tectonic burial depth, etc., the characteristics of P₁f source rocks were investigated, and the horizontal distributions of the following aspects were predicted: the thickness of source rocks, abundance and type of organic matter. And on this basis, an improved hydrocarbon generation potential methodology together with basin simulation techniques was applied to unravel the petroleum generation and expulsion characteristics of P₁f source rocks in FA. Results show that the P₁f source rocks distribute widely (up to 2039 km²), are thick (up to 260 m), have high total organic content (TOC, ranging from 0.15 to 4 wt%), are dominated by type II kerogen and have entered into low mature–mature stage. The modeling results indicate that the source rocks reached hydrocarbon generation threshold and hydrocarbon expulsion threshold at 0.5% Ro and 0.85% Ro and the comprehensive hydrocarbon expulsion efficiency was about 46%. The amount of generation and expulsion from the P₁f source rocks was 31.85 × 10⁸ and 15.31 × 10⁸ t, respectively, with a residual amount of 16.54 × 10⁸ t within the source rocks. Volumetrically, the geological resource of shale oil is up to 15.65 × 10⁸ t. Small differences between the amounts calculated by the volumetric method compared with that by hydrocarbon generation potential methodology may be due to other oil accumulations present within interbedded sands associated with the oil shales. Copyright © 2015 John Wiley & Sons, Ltd.     

Geochemical Evaluation of the Permian Ecca Shale in Eastern Cape Province,South Africa: Implications for Shale Gas Potential

Shale gas has been the exploration focus for future energy supply in South Africa in recent time. Specifically, the Permian black shales of the Prince Albert, Whitehill, Collingham, Ripon and Fort Brown Formations are considered to be most prospective rocks for shale gas exploration. In this study,outcrop and core samples from the Ecca Group were analyzed to assess their total organic carbon(TOC), organic matter type, thermal maturity and hydrocarbon generation potential. These rocks have TOC ranging from 0.11 to 7.35 wt%. The genetic potential values vary from 0.09 to 0.53 mg HC/g,suggesting poor hydrocarbon generative potential. Most of the samples have Hydrogen Index(HI) values of less than 50 mg HC/g TOC, thus suggesting Type-Ⅳ kerogen. Tmax values range from 318℃ to601℃, perhaps indicating immature to over-maturity of the samples. The vitrinite reflectance values range from 2.22% to 3.93%, indicating over-maturity of samples. Binary plots of HI against Oxygen Index(OI), and HI versus Tmax show that the shales are of Type II and mixed Type Ⅱ-Ⅲ kerogen.Based on the geochemical data, the potential source rocks are inferred as immature to over-matured and having present-day potential to produce gas.     

Microstructure Evolution of Organic Matter and Clay Minerals in Shales with Increasing Thermal Maturity

As the two important components of shale, organic matter(OM) and clay minerals are usually thought to strongly influence the hydrocarbon generation, enrichment and exploitation. The evolution process of OM and clay minerals as well as their interrelationship over a wide range of thermal maturities are not completely clear. Taking Yanchang(T_3y), Longmaxi(S_1l) and Niutitang(?_1n) shales as examples, we have studied the microstructure characteristics of OM and clay minerals in shales with different thermal maturities. The effects of clay minerals and OM on pores were reinforced through sedimentation experiments. Using a combination of field emission scanning electron microscopy(FESEM) and low-pressure N_2 adsorption, we investigated the microstructure differences among the three shales. The results showed that both OM and clay minerals have strong effects on pores, and small mesopore(2–20 nm) is the dominant pore component for all three samples. However, the differences between the three samples are embodied in the distribution of pore size and the location. For the T_3y shale, clay minerals are loosely arranged and develop large amounts of pores, and fine OM grains often fill in intergranular minerals or fractures. Widespread OM pores distribute irregularly in S_1l shale, and most of the pores are elliptical and nondirectional. The ?_1n shale is characterized by the preferred orientational OM-clay aggregates, and lots of pores in the composites are in the mesopore range, suggesting that over maturity lead to the collapse and compaction of pores under huge pressure of strata. The results of the current research imply that with increasing thermal maturity, OM pores are absent at low maturity(T_3y), are maximized at high maturity(S_1l) and are destroyed or compacted at over-mature stage(?_1n). Meanwhile, clay minerals have gone through mineral transformation and orientational evolution. The interaction of the two processes makes a significant difference to the microstructure evolution of OM and clay minerals in shale, and the findings provide scientific foundation in better understanding diagenetic evolution and hydrocarbon generation of shale.