下扬子地区官地1井下寒武统海相泥页岩孔隙发育特征及影响因素

以下扬子陆域地区官地1井下寒武统幕府山组海相泥页岩岩心样品为研究对象,综合运用场发射扫描电镜、X衍射分析、气体吸附、高压压汞和有机地球化学分析等实验测试手段,系统研究了官地1井幕府山组泥页岩孔隙结构特征和孔隙发育影响因素。研究表明：(1)官地1井幕府山组泥页岩矿物组成以石英、方解石胶结物和黏土矿物为主,其总有机碳含量较高,有机质类型以I型干酪根为主且均处于过成熟阶段;(2)泥页岩孔隙类型主要为基质孔隙（粒间孔隙和粒内孔隙）、有机质孔隙和微裂隙,其中以有机质孔隙含量居多,而粒间孔隙面孔率占比最高;(3)有机质丰度对有机质孔隙的孔径和比表面积具有一定的影响,压实作用则构成过成熟阶段孔隙演化的主要因素,而刚性矿物具有一定的支撑作用并对有机质孔隙的保存具有积极意义;(4)分形维数与总有机碳含量和比表面积相关性较好,而与孔隙体积相关性弱,反映孔壁粗糙程度及孔隙结构复杂程度受有机质丰度影响。     

The application of geostatistical inversion in shale lithofacies prediction: a case study of the Lower Silurian Longmaxi marine shale in Fuling area in the southeast Sichuan Basin,China

Based on cores, well logs and seismic data, we established the isochronous sequence stratigraphic framework of the Lower Silurian Longmaxi Formation and predicted the shale lithofacies distribution within the sequence stratigraphic framework using geostatistical inversion. The results of our study show that the Lower Member of the Longmaxi Formation is a third order sequence that includes a transgressive systems tract (TST), an early highstand systems tract (EHST) and a late highstand systems tract (LHST). Four lithofacies units have been recognized, specifically siliceous shale, argillaceous shale, calcareous shale and mixed shale. The results of geostatistical inversion reveal that the TST is characterized by flaky siliceous shale and some sparsely distributed calcareous shale. The EHST is dominated by mixed shale with minor amounts of siliceous shale, which occurs in only a small area. Moreover, in the LHST, argillaceous shale occupies almost the entire study region. Comparing to traditional geological research with geophysical research, the vertical resolution of the predictive results of geostatistical inversion could reach 1–2 m. Geostatistical inversion effectively solves the problem of precisely identifying the lithofacies in the Fuling shale gas field and predicting their spatial distribution. This successful study showcases the potential of this method for carrying out marine shale lithofacies prediction in China and other locations with similar geological backgrounds.     

Sequence stratigraphic analysis of Eocene Rock Strata,Offshore Indus,southwest Pakistan

In this study, seismic data from two wells (Pak G2-1 and Indus Marine-1C) and age diagnostic larger benthic foraminifera (LBF) within drill cuttings has been used for the first time to identify depositional sequences within the carbonates in the Offshore Indus Basin, Pakistan. The Offshore Indus is tectonically categorized as a passive continental margin where carbonates occur as shelf carbonates in the near offshore and on volcanic seamounts in deeper waters. Seismic data analysis has indicated the presence of minor faults and carbonate buildups above the igneous basement in the south. Patterns of the seismic reflections enabled definition of three seismic facies units identified as: Unit 1 basement, represented by chaotic, moderate amplitude reflection configuration; while parallel bedding and the drape of overlying strata is typical character of Unit 2, carbonate mound facies. The younger Miocene channels represent Unit 3. The diagnosis of Alveolina vredenburgi/cucumiformis biozone confirmed the Ilerdian (55–52 Ma) stage constituting a second order cycle of deposition for the Eocene carbonates (identified as Unit 2). The carbonate succession has been mainly attributed to an early highstand system tract (HST). The environmental conditions remained favorable leading to the development of keep-up carbonates similar to pinnacle buildups as a result of aggradation during late transgressive system tract and an early HST. The carbonate sequence in the south (Pak G2-1) is thicker and fossiliferous representing inner to middle shelf depths based on fauna compared to the Indus Marine-1C in the north, which is devoid of fossils. Three biozones (SBZ 5, SBZ 6 and SBZ 8) were identified based on the occurrence of LBF. The base of the SBZ 5 zone marks the larger foraminifera turnover and the Paleocene–Eocene (P–E) boundary. The LBF encountered in this study coincides with earlier findings for the P–E boundary. Our findings indicate that the entire Ilerdian stage ranges from 55.5 to 52 Ma that was the episode of warmer water conditions on the carbonate shelves leading to the diversification of K-strategist larger foraminifera. The larger foraminiferal assemblage encountered in this study confirms the findings. The possible indication of stratigraphic-combination traps, revealed as reflection terminations, make carbonate mounds in the south a potential exploration target.     

下刚果盆地北部海域海相碳酸盐岩沉积储层特征

西非下刚果盆地为一典型被动大陆边缘含盐盆地,下刚果盆地北部海域在白垩系海相碳酸盐岩层系获得丰富油气发现。研究区海相碳酸盐岩领域油气勘探面临的核心瓶颈问题,即白垩系碳酸盐岩的沉积模式、演化规律、储层特征以及沉积储层发育控制因素。综合钻井、地震、区域地质等资料,分析认为自下向上相对海平面的上升控制了沉积演化,沉积体系演化模式为浅海碳酸盐岩台地→浅海混积陆棚→半深海-海底扇。下刚果盆地碳酸盐岩储层展布在纵向及平面上均可以划分为内中外3个储层发育带,碳酸盐岩储层最主要发育于下白垩统Albian阶下Sendji组。该时期研究区整体发育浅海碳酸盐岩混积缓坡台地沉积体系,沉积亚相可进一步划分为混积滨岸、后缓坡、浅水缓坡以及深水缓坡4种类型,其中浅水缓坡亚相颗粒滩微相与后缓坡亚相台内浅滩、砂质浅滩微相储层最为发育。碳酸盐岩储层岩性组合主要包括颗粒灰岩、砂岩、砂质灰岩、白云岩4种类型;储层发育主要受沉积相带的控制,并受成岩作用的影响。     

High resolution characterization of a core from the Lower Jurassic Gordondale Member,Western Canada Sedimentary Basin

The Gordondale Member is a hydrocarbon source rock and potential unconventional reservoir that extends across northeastern British Columbia and central-northwestern Alberta. It is an organic-rich, calcareous, fossiliferous mudstone with a median total organic carbon value of 6.0 wt%. A total of 230 samples were collected from approximately 25 m of Gordondale Member core for organic matter analysis using Rock-Eval 6 analysis and organic petrology. Detailed core logging provides sedimentological context for organic matter characterization. The predominant organic material in the samples is solid bitumen and liptinite with lesser zooclast and inertinite. Most kerogen is Type II, autochthonous marine biomass, with minimal dilution by inert organic carbon. Rock-Eval T_max values and random reflectance measurements of solid bitumen indicate the samples are within the oil generation window. Solid bitumen contributes a substantial amount of hydrocarbon potential to the interval. A micro-reservoir structure within the core is produced by thin intervals of impermeable displacive calcite that act as barriers to the upward migration of free hydrocarbons. These free hydrocarbon accumulations could make excellent targets for horizontal wells within the Gordondale Member.     

Measurements of the total ozone content in the central Arctic Basin

In 2003, measurements of the total ozone content (TOC) in the central Arctic Basin were resumed after a long-term break at the NP-32 and NP-33 drifting research stations. This paper presents the first results of analyses of the observational data obtained at the NP-32 and NP-33 stations and aboard the R/V Akademik Fedorov. An approach allowing comparison fo the mean ozone-content values measured in different time periods from moving platforms, such as drifting stations and research vessels, is used. The TOC variability over the central Arctic Basin in 2003–2005 is described, and results of comparison of these data with the data of both long-term TOC measurements at a number of stationary Arctic stations in 1973–2002 and measurements at the NP-22 station in 1976–1977 are presented.     

Experimental investigation of thermal maturation on shale reservoir properties from hydrous pyrolysis of Chang 7 shale,Ordos Basin

Thermal maturity has a significant impact on hydrocarbon generation and the storage capacity within shales, but explicit and quantitative characterization of that impact on continental shales is scarce. To better understand how thermal maturation affects the organic and inorganic changes of the continental shale reservoirs, hydrous pyrolysis was performed to simulate the maturation process. TOC, Rock-Eval and adsorption isotherms tests were used to obtain various geochemical parameters of the shale solid residues. The results indicate that with pyrolysis temperature increasing from ambient temperature to 550 °C, the vitrinite reflectance increases from 0.5% to 2.5% Ro and the TOC (total organic carbon) loss weight reaches 25%. Regarding porosity, the fraction of micro-to meso-pores in the shale increases with an increase in the pyrolysis temperature, whereas the macro-pores do not change significantly. The total amount of gas adsorption does not necessarily increase as the TOC is consumed, but the gas adsorption capacity per unit of TOC increases with increasing thermal maturity. Our finding provides theoretical modelling for identifying shale gas development prospective zones according to thermal maturity mapping and for predicting quantitatively the geochemical and inorganic changes that occur with thermal evolution.     

Modeling free gas content of the Lower Paleozoic shales in the Weiyuan area of the Sichuan Basin,China

Two sets of Lower Paleozoic organic-rich shales develop well in the Weiyuan area of the Sichuan Basin: the Lower Cambrian Jiulaodong shale and the Lower Silurian Longmaxi shale. The Weiyuan area underwent a strong subsidence during the Triassic to Early Cretaceous and followed by an extensive uplifting and erosion after the Late Cretaceous. This has brought about great changes to the temperature and pressure conditions of the shales, which is vitally important for the accumulation and preservation of shale gas. Based on the burial and thermal history, averaged TOC and porosity data, geological and geochemical models for the two sets of shales were established. Within each of the shale units, gas generation was modeled and the evolution of the free gas content was calculated using the PVTSim software. Results show that the free gas content in the Lower Cambrian and Lower Silurian shales in the studied area reached the maxima of 1.98–2.93 m³/t and 3.29–4.91 m³/t, respectively (under a pressure coefficient of 1.0–2.0) at their maximum burial. Subsequently, the free gas content continuously decreased as the shale was uplifted. At present, the free gas content in the two sets of shales is 1.52–2.43 m³/t and 1.94–3.42 m³/t, respectively (under a current pressure coefficient of 1.0–2.0). The results are roughly coincident with the gas content data obtained from in situ measurements in the Weiyuan area. We proposed that the Lower Cambrian and Lower Silurian shales have a shale gas potential, even though they have experienced a strong uplifting.     

加里曼丹岛库泰盆地海相成藏组合特征及油气富集区分带性分析

通过系统收集和分析库泰盆地钻井岩屑样品及野外露头样品,首次对下中新统海相油气系统进行了评价。结果发现该区域以生物礁碳酸盐岩为标志层,发育多套海相沉积旋回,海相沉积油气系统具有自生自储自封堵特征:暗色海相泥岩为主力烃源岩,海相砂岩为有利储层,同时,海相泥岩作为有效盖层。下中新统海相烃源岩样品有机质类型为Ⅱ/Ⅲ型,以Ⅱ型为主,总有机碳质量分数(TOC)平均值1.92%,有机质处于低熟-成熟阶段,为有效烃源岩,烃源岩厚度较大,指示良好的生烃潜力;储层多期发育,具有低阻特征。自西向东,库泰盆地油气成藏系统时代变新、层系变浅:①盆地东部望加锡海峡深水-半深水区域以上中新统-上新统深水沉积成藏系统为主;②中部马哈坎三角洲-浅海区域以中中新统三角洲相成藏组合为主;③马哈坎褶皱带以下中新统海相成藏组合为主;④盆地西部以渐新统-始新统裂谷期成藏组合为主。新层段海相油气成藏系统的发现,揭示了库泰盆地有利成藏组合的分带规律,指明了库泰盆地中西部区域的未来油气勘探方向。     

Models for dynamic evaluation of mudstone/shale cap rocks and their applications in the Lower Paleozoic sequences,Sichuan Basin,SW China

The estimation of the sealing capability of cap rocks dynamically is one of the fundamental geological problems that must be resolved in petroleum exploration. In this paper, a porosity–capillary pressure (ϕ–P_c) method was used to estimate the sealing capacity during cap rock burial and a permeability–capillary pressure (K–P_c) plus over-consolidation ratio (OCR) method to estimate the sealing capacity during uplift. Based on 120 capillary pressure–porosity measurements, a ϕ–P_c mathematical model has been established for the burial phase. By analyzing the permeability data measured from 12 mudstone/shale samples from different stratigraphic intervals under step loading conditions, a permeability–confining pressure (K–P) mathematical model has been constructed. Moreover, capillary pressure–permeability data measured from 141 mudstone or shale cap rocks have been used to establish a K–P_c mathematical model for seal capacity evaluation during uplift. Additionally, the OCR of mudstone or shale was calculated from the results of reconstructed burial and uplift histories. These mathematical models were used in case studies in the Sichuan Basin, South China. The results indicate that capillary pressure (P_c) is inadequate in evaluating sealing capacity of cap rocks but the combination of parameters P_c and OCR works well. The agreement between calculated and measured values shows the effectiveness and reliability of the models for dynamic estimation of the sealing capacity of mudstone/shale cap rocks established in this study.     

海洋胶体的有机组成及其结构特征

碳及其相关生源要素的生物地球化学研究是近十几年来海洋科学的研究重点之一,也是国际上许多前沿研究计划,如全球海洋通量联合研究(JGOFS)、陆海相互作用(LOICZ)、全球海洋生态系统动力学研究(CAOBEC)、上层海洋与下层大气研究(SOLAS)等的重要研究内容。     

海洋无脊椎动物组织总RNA提取方法的探讨

RNA提取是分子生物学研究的基础实验,由于海洋无脊椎动物组织结构以及体成分的特殊性,导致现有的RNA提取方法不能完全胜任此工作。作者以刺参(Apostichopus japonicus)、栉孔扇贝(Chlamys farreri)和凡纳滨对虾(Litopenaeus vannamei)为研究对象,对异硫氰酸胍RNA提取方法进行了改进。栉孔扇贝和凡纳滨对虾的肝胰腺富含RNase,刺参体壁结构致密、富含胶原蛋白,而成熟期精巢富含多糖,因此在这些动物组织中提取RNA时,在原有方法基础上增加了瞬时匀浆、增加氯仿及酸性酚的抽提次数,或添加高盐溶液等方法。实验结果显示,改进方法后获得的RNA具有完整的28S、18S和5S r RNA条带,A260nm/A280nm和A260nm/A230nm比值分别为1.89~2.0和1.98~2.11,β-actin基因扩增条带清晰,所获得的组织RNA的纯度和质量符合c DNA合成和基因功能研究的要求。     

Oolitic shoal complexes characterization of the Lower Triassic Feixianguan Formation in the Yuanba Gas Field,Northeast Sichuan Basin,China

The Yuanba Gas Field is the second largest natural gas reservoir in the Sichuan Basin, southwest China. The vast majority of the natural gas reserve is from the Permian Changhsingian reef complexes and Lower Triassic Feixianguan oolitic shoal complexes. To better understand this reservoir system, this study characterizes geological and geophysical properties, spatial and temporal distribution of the oolitic shoal complexes and factors that control the oolitic shoals character for the Lower Triassic Feixianguan Formation in the Yuanba Gas Field. Facies analysis, well-seismic tie, well logs, seismic character, impedance inversion, and root mean square (RMS) seismic attributes distinguish two oolitic shoal complex facies – FA-A and FA-B that occur in the study area. FA-A, located in the middle of oolitic shoal complex, is composed of well-sorted ooids with rounded shape. This facies is interpreted to have been deposited in shallow water with relatively high energy. In contrast, FA-B is located in flanks of the oolitic shoal complex, and consists of poorly sorted grains with various shape (rounded, subrounded and subangular). The oolitic shoal complexes were mainly deposited along the platform margin. From the early Fei 2 Member period to the late Fei 2 Member period, the oolitic shoals complexes on the platform margin gradually migrated from the southwest to the northeast with an extent ranging from less than 100 km²–150 km² in the Yuanba Gas Field. The migration of oolitic shoals coincided with the development of a series of progradational clinoforms, suggesting that progradational clinoforms caused by sea-level fall maybe are the main reason that lead to the migration of oolitic shoals. Finally, this study provide an integrated method for the researchers to characterize oolitic shoal complexes by using well cores, logs, seismic reflections, impedance inversion, and seismic attribute in other basins of the world.     

元素分析仪快速测定海洋沉积物TOC和TN的条件优化

报道了在优化样品前处理、燃烧温度、最小加氧量和最佳称样量的基础上,综合构建优化了直接固体进样varioMACRO cube元素分析仪同时测定海洋沉积物样品中总有机碳(TOC)和总氮(TN)的条件,即准确称取20~30 mg沉积物样品用1 mol/L盐酸除去无机碳后,直接进样在燃烧管温度960℃,次级燃烧管温度830℃,还原管温度900℃,氦气压力0.12 MPa,流量600 mL/min,氧气压力0.20 MPa,加氧量22.5 mL仪器条件下,用标准曲线法峰面积获取TOC和TN浓度。结果表明,海洋沉积物中TOC和TN测定的检出限分别为0.0508%和0.0146%,回收率分别为97.7%~100.9%和97.2%~101.1%,对4个实际外海沉积物样测定总有机碳和总氮结果的相对标准偏差(RSD)为0.83%~3.06%和1.33%~3.49%(n=12)。该方法操作简便快速、灵敏度高,具有较好的精密度和准确度,可准确可靠地用于海洋沉积物中总有机碳和总氮含量的测定。     

Seismic stratigraphy and hydrocarbon prospectivity of the Lower Cretaceous Knurr Sandstone lobes along the southern margin of Loppa High,Hammerfest Basin,Barents Sea

The Lower Cretaceous Knurr Sandstone deposited along the southern slope of Loppa High and overlain by the Kolje and Kolmule seals forms an attractive play in the Hammerfest Basin of the Barents Sea. Late Jurassic organic-rich Hekkingen shale directly underlies the Knurr Sandstone and acts as a source to provide effective charge. Three wells, 7120/2-2, 7122/2-1 and 7120/1-2, have proven the Knurr-Kolje play in structural traps, with an oil discovery in 7120/1-2. Prospectivity related to stratigraphic traps is, however, highly under-explored.In order to document and map the reservoir distribution and stratigraphic-trap fairway, the Lower Cretaceous sedimentary package containing the Knurr Sandstone is divided into a number of depositional sequences and systems tracts using key regional seismic profiles calibrated with logs. Mapping of the key surfaces bounding the Knurr sandstone has been carried out using all the seismic vintages available from Norwegian Petroleum Directorate (NPD).The thick massive nature of the sandstone (123 m in well 7122/2-1), sedimentary features characteristic of gravity flow deposits, high-resolution internal seismic reflections and stratal geometries (truncations and lapout patterns), and sequence stratigraphic position of the Knurr Sandstone on seismic profiles confirm that the lobes identified on the seismic section are gravity driven base of the slope lobes. These Knurr lobes and slope aprons were formed as a result of uplift of the Loppa paleo-high in the Late Jurassic to Early Cretaceous times which caused subaerial exposure and incision. The characteristic mounded, lobate geometry evident on the seismic can be mapped along the toe-of-slope and records multiple stacked lobes fed by multiple feeder canyons. Lateral partitioning and separation of the lobes along the toe-of-slope could potentially create stratigraphic traps. The existing 2D seismic coverage is, however, not sufficient to capture lateral stratigraphic heterogeneity to identify stratigraphic traps. 3D seismic coverage with optimum acquisition parameters (high spatial and vertical resolution, appropriate seismic frequency and fold, long offsets and original amplitudes preserved) can allow for the reconstruction of 3D geomorphologic elements to de-risk potential stratigraphic traps prior to exploratory drilling.     

Heterogeneity of intergranular,intraparticle and organic pores in Longmaxi shale in Sichuan Basin,South China: Evidence from SEM digital images and fractal and multifractal geometries

Previous studies have determined many types of pores in shale, such as organic pores, inorganic pores and microfractures. In this study, pores are classified as intergranular, intraparticle, and organic pores based on the location of their occurrence. The heterogeneities of the three pore types and their effects on the occurrence of shale gas, which is of utmost practical importance for shale gas exploration and development, are discussed. In this study, the three types of pores are quantitatively characterized using fractal and multifractal methods. The mean fractal dimension and mean width of the multifractal spectrum of these pores are found to be different, i.e., 1.5985 and 1.665 for intraparticle pores, 1.5869 and 1.475 for intergranular pores, and 1.6 and 1.3725 for organic pores. Intraparticle pores have the highest heterogeneity, intergranular pores have intermediate heterogeneity, and organic pores have the lowest heterogeneity. SEM images show that organic pores have good connectivity, homogeneous distribution, and small range of aperture change but have the lowest heterogeneity even where pores are abundant; thus, they provide the largest shale gas occurrence space. In contrast, intergranular pores are less abundant, have lower connectivity, and have higher heterogeneity than organic pores, thereby providing a relatively smaller shale gas occurrence space. Finally, intraparticle pores are the least abundant and possess the poorest connectivity, largest range of aperture change, and highest heterogeneity of the three pore types, thereby providing the smallest shale gas occurrence space. We conclude that organic pores are crucial to the occurrence of shale gas and can provide a new index for the evaluation of shale gas exploration and development.     

Organic geochemistry and reservoir characterization of the organic matter-rich calcilutite in the Shulu Sag,Bohai Bay Basin,North China

Although extensive studies have been conducted on unconventional mudstone (shales) reservoirs in recent years, little work has been performed on unconventional tight organic matter-rich, fine-grained carbonate reservoirs. The Shulu Sag is located in the southwestern corner of the Jizhong Depression in the Bohai Bay Basin and filled with 400–1000 m of Eocene lacustrine organic matter-rich carbonates. The study of the organic matter-rich calcilutite in the Shulu Sag will provide a good opportunity to improve our knowledge of unconventional tight oil in North China. The dominant minerals of calcilutite rocks in the Shulu Sag are carbonates (including calcite and dolomite), with an average of 61.5 wt.%. The carbonate particles are predominantly in the clay to silt size range. Three lithofacies were identified: laminated calcilutite, massive calcilutite, and calcisiltite–calcilutite. The calcilutite rocks (including all the three lithofacies) in the third unit of the Shahejie Formation in the Eocene (Es₃) have total organic carbon (TOC) values ranging from 0.12 to 7.97 wt.%, with an average of 1.66 wt.%. Most of the analyzed samples have good, very good or excellent hydrocarbon potential. The organic matter in the Shulu samples is predominantly of Type I to Type II kerogen, with minor amounts of Type III kerogen. The temperature of maximum yield of pyrolysate (T_max) values range from 424 to 452 °C (with an average of 444 °C) indicating most of samples are thermally mature with respect to oil generation. The calcilutite samples have the free hydrocarbons (S₁) values from 0.03 to 2.32 mg HC/g rock, with an average of 0.5 mg HC/g rock, the hydrocarbons cracked from kerogen (S₂) yield values in the range of 0.08–57.08 mg HC/g rock, with an average of 9.06 mg HC/g rock, and hydrogen index (HI) values in the range of 55–749 mg HC/g TOC, with an average of 464 mg HC/g TOC. The organic-rich calcilutite of the Shulu Sag has very good source rock generative potential and have obtained thermal maturity levels equivalent to the oil window. The pores in the Shulu calcilutite are of various types and sizes and were divided into three types: (1) pores within organic matter, (2) interparticle pores between detrital or authigenic particles, and (3) intraparticle pores within detrital grains or crystals. Fractures in the Shulu calcilutite are parallel to bedding, high angle, and vertical, having a significant effect on hydrocarbon migration and production. The organic matter and dolomite contents are the main factors that control calcilutite reservoir quality in the Shulu Sag.     

Deep petroleum occurrences in the Lower Kura Depression, South Caspian Basin, Azerbaijan: an organic geochemical and basin modeling study

High sedimentation rates (as much as 2500 m/Ma) during Pliocene-Pleistocene, with a resultant undercompacted section as thick as 10,000 m, and lower than normal geothermal gradients are the main characteristics which have created all the means for generation and preservation of oil at deep layers in the Lower Kura Depression.Oils collected from eight different oil fields for analyses seem to have originated from a common source rock which probably is clastic, deposited in relatively subanoxic to suboxic transitional marine environment receiving low to moderate input of terrestrial organic matter.Oils from shallow (< 3000 m) and cold (< 70–80°C) reservoirs have been altered to various extent by bacterial activity.A computer-aided basin modeling study has been carried out to outline the spatial variation of the oil window and thus help in further identification of possible source rocks for the reservoired oil in the Lower Kura Depression. Results suggest that the potential hydrocarbon source horizons of the Miocene and Pliocene Red Bed Series of the so called Productive Succession are, even at depocenter areas, immature with respect to oil generation, and thus, are very unlikely to have been source rocks for the reservoired oils. However, the Oligocene-Lower Miocene Maykop rocks are marginally mature to mature depending on locality and the Eocene and older rocks are mature with respect to oil generation at all representative field locations. Oil generation commenced at the end of Pliocene and continues at present at depths between 6000 and 12,000 m.An unusually deep (> 10,000 m) oil window in the depocenter areas has been caused by the depressed isotherms due to extremely high sedimentation rates (up to 3000 m/Ma) for the last two million years. The main phase of oil generation is taking place at depths greater than what most of the wells in the study are have reached.     

The geochemical characteristics and factors controlling the organic matter accumulation of the Late Ordovician-Early Silurian black shale in the Upper Yangtze Basin,South China

Organic-rich black shale of the Upper Yangtze Basin from the Late Ordovician and Early Silurian is considered an excellent source rock in South China. The formation and preservation conditions of this resource are revealed by its geochemical characteristics in this study. Geochemical indices, including redox indices (V/(V + Ni), V/Cr, V/Sc, and Ni/Co) and primary productivity indices (P/Ti and Ba/Al), and paleoclimate, clastic flux and sedimentary rate analyses are presented to investigate the accumulation mechanism of organic matter. Redox indices suggest that a stagnant, anoxic environment predominated in the Upper Yangtze Basin during accumulation of Wufeng and Longmaxi formations. In contrast, ventilated and oxygenated marine conditions pervaded the Upper Yangtze Basin during deposition of Linxiang and Guanyinqiao formations. The concentrations of V and U demonstrate that accumulation of organic matter was mainly controlled by redox conditions. Besides, such factors as clastic fluxes, fresh water inflows or a mixed deposition with a rapid sedimentary rate cannot be ignored due to their influences on organic matter enrichment and preservation. However, weak co-variance relationship of TOC content and productivity proxies, including P/Ti and Ba/Al, demonstrates that the accumulation of organic matter was not controlled by primary productivity. Results of the present study suggest a depositional model that stresses the importance of tectonic movements and glacial events on the accumulation and preservation of organic matter. The model shows that the Upper Yangtze Basin was a semi-restricted basin system influenced by the isolation of Xuefeng, but also it implies that oxygen-depleted bottom water of the basin favored the accumulation and preservation of sedimentary organic matter, resulting in the formation of organic-rich black shale.     

Effects of composition and pore structure on the reservoir gas capacity of Carboniferous shale from Qaidam Basin,China

Shale adsorption and breakthrough pressure are important indicators of shale gas development and key factors in evaluating the reservoir capacities of shales. In this study, geochemical tests, pore-structure tests, methane adsorption tests, and breakthrough-pressure tests were conducted on shales from the Carboniferous Hurleg Formation in eastern Qaidam Basin. The effects of the shale compositions and pore structures on the adsorption and breakthrough pressures were studied, and the reservoir capacities of the shales were evaluated by analyzing the shale adsorptions and sealing effects. The results indicate that the organic carbon content was only one of factors in affecting the adsorption capacity of the shale samples while the effect of the clay minerals was limited. Based on the positive correlation between the adsorption capacity and specific surface area of the shale, the specific surface area of the micropores can be used as an indicator to determine the adsorption capacity of shale. The micro-fracturing of brittle minerals, such as quartz, create a primary path for shale gas breakthrough, whereas the expansion of clay minerals with water greatly increases the breakthrough pressure in the shale samples. Methane adsorption tests showed that maximum methane adsorption for shale samples Z045 and S039 WAS 0.107 and 0.09655 mmol/g, respectively. The breakthrough pressure was 39.36 MPa for sample S039, maintained for 13 days throughout the experiment; however, no breakthrough was observed in sample Z045 when subjected to an injected pressure of 40 MPa for 26 days. This indicates that sample Z045, corresponding to a depth of 846.24 m, exhibited higher adsorption capacity and a better reservoir-sealing effect than sample S039 (498.4 m depth). This study provides useful information for future studies of Qaidam Basin shale gas exploration and development and for evaluation of shale quality.