Pore characteristic analysis of a lacustrine shale: A case study in the Ordos Basin,NW China

Organic shales deposited in a continental environment are well developed in the Ordos Basin, NW China, which is rich in hydrocarbons. However, previous research concerning shales has predominantly focused on marine shales and barely on continental shales. In this study, geochemical and mineralogical analyses, high-pressure mercury intrusion and low-pressure adsorption were performed on 18 continental shale samples obtained from a currently active shale gas play, the Chang 7 member of Yanchang Formation in the Ordos Basin. A comparison of all these techniques is provided for characterizing the complex pore structure of continental shales.Geochemical analysis reveals total organic carbon (TOC) values ranging from 0.47% to 11.44%, indicating that there is abundant organic matter (OM) in the study area. Kerogen analysis shows vitrinite reflectance (Ro) of 0.68%–1.02%, indicating that kerogen is at a mature oil generation stage. X-ray diffraction mineralogy (XRD) analysis indicates that the dominant mineral constituents of shale samples are clay minerals (which mainly consist of illite, chlorite, kaolinite, and negligible amounts of montmorillonite), quartz and feldspar, followed by low carbonate content. All-scale pore size analysis indicates that the pore size distribution (PSD) of shale pores is mainly from 0.3 to 60 nm. Note that accuracy of all-scale PSD analysis decreases for pores less than 0.3 nm and more than 10 μm. Experimental analysis indicates that mesopores (2–50 nm) are dominant in continental shales, followed by micropores (<2 nm) and macropores (50 nm–10 μm). Mesopores have the largest contribution to pore volume (PV) and specific surface area (SSA). In addition, plate- and sheet-shaped pores are dominant with poor connectivity, followed by hybrid pores. Results of research on factors controlling pore structure development show that it is principally controlled by clay mineral contents and Ro, and this is different from marine systems. This study has important significance in gaining a comprehensive understanding of continental shale pore structure and the shale gas storage–seepage mechanism.     

Properties and shale oil potential of saline lacustrine shales in the Qianjiang Depression,Jianghan Basin,China

The geochemical and petrographic characteristics of saline lacustrine shales from the Qianjiang Formation, Jianghan Basin were investigated by organic geochemical analysis, X-ray diffraction (XRD), scanning electron microscopy (SEM) and low pressure nitrogen adsorption analysis. The results indicate that: the saline lacustrine shales of Eq3 member with high oil content are characterized by type I and type II oil-prone kerogen, variable TOC contents (1.0–10.0 wt%) and an early-maturity stage (R_o ranges between 0.41 and 0.76%). The mineral compositions of Eq3 saline shale show strong heterogeneity: brittle intervals with high contents of quartz and carbonate are frequently alternated with ductile intervals with high glauberite and clay contents. This combination might be beneficial for oil accumulation, but may cause significant challenges for the hydraulic stimulation strategy and long-term production of shale oil. The interparticle pores and intraparticle pores dominate the pore system of Eq3 shale, and organic matter hosted pores are absent. Widely distributed fractures, especially tectonic fractures, might play a key role in hydrocarbon migration and accumulation. The pore network is contributed to by both large size inorganic pores and abundant micro-factures, leading to a relatively high porosity (2.8–30.6%) and permeability (0.045–6.27 md) within the saline shale reservoir, which could enhance the flow ability and storage capacity of oil. The oil content (S₁ × 100/TOC, mg HC/g TOC and S₁, mg HC/g rock) and brittleness data demonstrate that the Eq3^3x section has both great potential for being a producible oil resource and hydraulic fracturing. Considering the hydrocarbon generation efficiency and properties of oil, the mature shale of Eq3 in the subsidence center of the Qianjiang Depression would be the most favorable zone for shale oil exploitation.     

Logging identification and characteristic analysis of marine–continental transitional organic-rich shale in the Carboniferous-Permian strata,Bohai Bay Basin

Currently, global shale gas exploration and exploitation are focused on marine shale. Recently, major shale gas-oil breakthroughs have been made within continental and marine–continental transitional shale in China. This study will show how transitional shale is of great importance. Based on geological field surveys, core observations, thin section analysis, organic geochemistry and X-ray diffraction, we systematically studied the basic geological characteristics (including lithology, mineral composition, and organic geochemistry) of this transitional shale. By comparative analysis of well logging data from 260 wells in the Taiyuan–Shanxi shale, we will show that these methods are effective for identifying organic-rich shale from conventional well logs and determining its thickness distribution in the Carboniferous–Permian strata of the Taiyuan–Shanxi transitional coal-bearing formation.The results indicate that the Taiyuan–Shanxi shale has a high TOC (most 2%–4%) and that the lithology is primarily carbonaceous shale with type Ⅱ₂-Ⅲ kerogens. The high thermal maturation (Ro ≥ 1.1%) favors the generation of gas. The mineral components primarily include clay minerals, quartz, and plagioclase with a moderate brittle mineral content (47 wt.%) and high clay mineral content (51 wt.%) dominated by kaolinite (43%) and mixed-layer illite-smectite (31%). The transitional organic-rich shale on conventional log curves is generally characterized by higher gamma ray (GR), neutron porosity (CNL), acoustic travel time (AC), resistivity (R_t), potassium (K), and uranium (U) readings and a lower density (DEN), photoelectric absorption index (PE) and thorium-uranium ratio (TH/U). After analyzing the log response characteristics of the organic-rich shale, the most sensitive logging curves (such as CNL, AC, DEN, PE and U) were optimized to conduct logging overlays and to construct cross-plots to qualitatively identify organic-rich shale. The identified organic-rich shale amalgamates in the middle-upper member of the Taiyuan Formation and the lower member of the Shanxi Formation consistent with the results of the TOC analysis and practical gas logging. Based on the qualitative evaluation methods of the modified △LogR and a multivariate linear regression model, we calculated the TOC of shale wells in the Taiyuan–Shanxi formation. From this we calculated the characteristic values of organic-rich shale thickness. The results indicate that organic-rich shale in the Taiyuan formation is thicker than that in the Shanxi formation. Additionally, the thickness of organic-rich shale within lagoons and deep reed swamp facies are much thicker (25–35 m and 40–80 m) than other structural profile types, whereas their lateral distribution is less than that of marine shale. The relatively small continuous thickness of the single shale layer and high clay content may have negative effects for developing the shale gas potential.     

Heterogeneous nanoporosity of the Silurian Longmaxi Formation shale gas reservoir in the Sichuan Basin using the QEMSCAN,FIB-SEM,and nano-CT methods

Nanoporosity of a shale gas reservoir provides essential information on the gas accumulation space and controls the gas reserves. The characteristics of heterogeneous nanoporosity of four shale samples are analyzed by combining quantitative evaluation of minerals by scanning electronic microscopy (QEMSCAN), focused ion beam-scanning electron microscopy (FIB-SEM), and nano-CT. The representative elementary area (REA) is proposed by QEMSCAN to detect the imaging area that can represent the overall contents of minerals and organic matter. Combined with the statistics of pores in minerals and organic matter by FIB-SEM, the quantitative nanoporosity is obtained. The nano-CT is used to compare the total nanoporosity that was obtained by FIB-SEM. The results show that shale has distinct characteristics in nanoporosities due to the variation in organic matter and mineral content. The major pore sizes of the organic matter and clay minerals are smaller than 400 nanometers (nm), and the pore sizes of feldspar and pyrite are mainly 200–600 nm. The pore sizes for pores developed in quartz and carbonate minerals range from a few nanometers to 1000 nm. Furthermore, pores smaller than 400 nm mainly provide the total nanoporosity. The nanoporosities in the organic matter are approximately 17%–21%. Since the organic matter content (0.54%–6.98%) is low, the organic matter contributes approximately 5%–33% of the total nanoporosity in shale. Conversely, the nanoporosities in quartz and clay are generally lower than 3%. Since the mineral content (93.02%–99.46%) is obviously higher than the organic matter content, the minerals contribute approximately 67%–95% of the total nanoporosity in shale.     

Clay mineral distribution in surface sediments of the South Atlantic: sources, transport, and relation to oceanography

Surface samples, mostly from abyssal sediments of the South Atlantic, from parts of the equatorial Atlantic, and of the Antarctic Ocean, were investigated for clay content and clay mineral composition. Maps of relative clay mineral content were compiled, which improve previous maps by showing more details, especially at high latitudes. Large-scale relations regarding the origin and transport paths of detrital clay are revealed. High smectite concentrations are observed in abyssal regions, primarily derived from southernmost South America and from minor sources in Southwest Africa. Near submarine volcanoes of the Antarctic Ocean (South Sandwich, Bouvet Island) smectite contents exhibit distinct maxima, which is ascribed to the weathering of altered basalts and volcanic glasses. The illite distribution can be subdivided into five major zones including two maxima revealing both South African and Antarctic sources. A particularly high amount of Mg- and Fe-rich illites are observed close to East Antarctica. They are derived from biotite-bearing crystalline rocks and transported to the west by the East Antarctic Coastal Current. Chiorite and well-crystallized dioctaedral illite are typical minerals enriched within the Subantarctic and Polarfrontal-Zone but of minor importance off East Antarctica. Kaolinite dominates the clay mineral assemblage at low latitudes, where the continental source rocks (West Africa, Brazil) are mainly affected by intensive chemical weathering. Surprisingly, a slight increase of kaolinite is observed in the Enderby Basin and near the Filchner-Ronne Ice shelf.

The investigated area can be subdivided into ten, large-scale clay facies zones with characteristic possible source regions and transport paths. Clay mineral assemblages of the largest part of the South Atlantic, especially of the western basins are dominated by chlorite and illite derived from the Antarctic Peninsula and southernmost South America and supported by advection within the Circumantarctic Deep Water flow. In contrast, the East Antarctic provinces are relatively small. Assemblages of the eastern basins north of 30°S are strongly influenced by African sources, controlled by weathering regimes on land and by a complex interaction of wind, river and deep ocean transport. The strong gradient in clay mineral composition at the Brazilian slope indicate a relatively low contribution of tropically derived assemblages to the western basins.     

Quantitative modelling of hydrocarbon expulsion and quality grading of tight oil lacustrine source rocks: Case study of Qingshankou 1 member,central depression,Southern Songliao Basin,China

The quality of source rocks plays an important role in the distribution of tight and conventional oil and gas resources. Despite voluminous studies on source rock hydrocarbon generation, expulsion and overpressure, a quality grading system based on hydrocarbon expulsion capacity is yet to be explored. Such a grading system is expected to be instrumental for tight oil and gas exploration and sweet spot prediction. This study tackles the problem by examining Late Cretaceous, lacustrine source rocks of the Qingshankou 1 Member in the southern Songliao Basin, China. By evaluating generated and residual hydrocarbon amounts of the source rock, the extent of hydrocarbon expulsion is modelled through a mass balance method. The overpressure is estimated using Petromod software. Through correlation between the hydrocarbon expulsion and source rock evaluation parameters [total organic carbon (TOC), kerogen type, vitrinite reflectance (R_o) and overpressure], three classes of high-quality, effective and ineffective source rocks are established. High-quality class contains TOC >2%, type-I kerogen, R_o >1.0%, overpressure >7Mpa, sharp increase of hydrocarbon expulsion along with increasing TOC and overpressure, and high expulsion value at R_o >1%. Source rocks with TOC and R_o <0.8%, type-II₂ & III kerogen, overpressure <3Mpa, and low hydrocarbon expulsion volume are considered ineffective. Rocks with parameters between the two are considered effective. The high-quality class shows a strong empirical control on the distribution of tight oil in the Songliao Basin. This is followed by the effective source rock class. The ineffective class has no measurable contribution to the tight oil reserves. Because the hydrocarbon expulsion efficiency of source rocks is controlled by many factors, the lower limits of the evaluation parameters in different basins may vary. However, the classification method of tight source rocks proposed in this paper should be widely applicable.     

Geochemistry,reservoir characterization and hydrocarbon generation potential of lacustrine shales: A case of YQ-1 well in the Yuqia Coalfield,northern Qaidam Basin,NW China

Ever since a breakthrough of marine shales in China, lacustrine shales have been attracting by the policy makers and scientists. Organic-rich shales of the Middle Jurassic strata are widely distributed in the Yuqia Coalfield of northern Qaidam Basin. In this paper, a total of 42 shale samples with a burial depth ranging from 475.5 m to 658.5 m were collected from the Shimengou Formation in the YQ-1 shale gas borehole of the study area, including 16 samples from the Lower Member and 26 samples from the Upper Member. Geochemistry, reservoir characteristics and hydrocarbon generation potential of the lacustrine shales in YQ-1 well were preliminarily investigated using the experiments of vitrinite reflectance measurement, maceral identification, mineralogical composition, carbon stable isotope, low-temperature nitrogen adsorption, methane isothermal adsorption and rock eval pyrolysis. The results show that the Shimengou shales have rich organic carbon (averaged 3.83%), which belong to a low thermal maturity stage with a mean vitrinite reflectance (R_o) of 0.49% and an average pyrolytic temperature of the generated maximum remaining hydrocarbon (T_max) of 432.8 °C. Relative to marine shales, the lacustrine shales show low brittleness index (averaged 34.9) but high clay contents (averaged 55.1%), high total porosities (averaged 13.71%) and great Langmuir volumes (averaged 4.73 cm⁻³ g). Unlike the marine and marine-transitional shales, the quartz contents and brittleness index (BI) values of the lacustrine shales first decrease then increase with the rising TOC contents. The kerogens from the Upper Member shales are dominant by the oil-prone types, whereas the kerogens from the Lower Member shales by the gas-prone types. The sedimentary environment of the shales influences the TOC contents, thus has a close connection with the hydrocarbon potential, mineralogical composition, kerogen types and pore structure. Additionally, in terms of the hydrocarbon generation potential, the Upper Member shales are regarded as very good and excellent rocks whereas the Lower Member shales mainly as poor and fair rocks. In overall, the shales in the top of the Upper Member can be explored for shale oil due to the higher free hydrocarbon amount (S₁), whereas the shales in the Lower Member and the Upper Member, with the depths greater than 1000 m, can be suggested to explore shale gas.     

Mineralogical analysis and the evaluation of the petrophysical parameter Vshale for reservoir description

Water saturation in otherwise hydrocarbon-saturated sandstones is closely related to the sandstone's clay mineralogy. Laboratory analysis of the clay mineralogy of three sandstones, containing kaolinite, chlorite and illite, is used to provide the basis for deciding which logs are most suitable for evaluating clay mineral content and distribution (V_shale). The gamma log, which is held traditionally to be a reliable ‘shale’ log, proves to be a poor indicator of shaliness (i.e. clay mineral content) in all three examples. Microresistivity (MSFL) logs, and in some instances neutron porosity logs, give the most realistic correlations with the actual clay mineralogy. Standard values for clay mineral properties which are often used in the petrophysical characterization of sandstones are thought to be unreliable especially when not used in conjunction with textural data from petrographic studies.     

Nano-scale pore structure and fractal dimension of organic-rich Wufeng-Longmaxi shale from Jiaoshiba area,Sichuan Basin: Investigations using FE-SEM,gas adsorption and helium pycnometry

Much attention have been recently paid to the upper Ordovician Wufeng shale (O₃w) and lower Silurian Longmaxi shale (S₁l) in the Jiaoshiba area of Sichuan Basin, which is now the largest producing shale gas field in China. Field emission scanning electron microscopy (FE-SEM), low pressure gas (N₂ and CO₂) adsorption, helium pycnometry, X-ray diffraction and geochemical analyses were performed to investigate the pore structure and fractal dimension of the pores in O₃w-S₁l shale formation in the Jiaoshiba area. FE-SEM images show that organic matter (OM) pores are dominant in the organic-rich samples and these pores are often irregular, bubble-like, elliptical and faveolate in shape, while in organic-poor samples, limited and isolated interparticle (interP), intraparticle (intraP) and OM pores are observed. Reversed S-shaped isotherms obtained from nitrogen adsorption are type Ⅱ, and hysteresis loops indicate that the shape of micropore in the samples is slit-or plate-like. BET surface areas and total pore volume vary from 12.2 to 27.1 m²/g and from 1.8 × 10⁻² to 2.9 × 10⁻² cm³/g, with an average of 19.5 m²/g and 2.3 × 10⁻² cm³/g, respectively. Adsorption volume from both N₂ and CO₂ adsorption increases with respect to TOC contents. Porosities obtained from helium porosimetry are comparable with these from gas (CO₂ and N₂) adsorption in O₃w-S₁l shale. However, porosity determined by quantitative FE-SEM analysis is much smaller, which is mainly related to limited resolution and the small areas of investigation.Based on the Frenkel-Halsey-Hill (FHH) model of low-pressure N₂ adsorption, fractal dimensions of the pores varied from 2.737 to 2.823. Relationships between pore structure parameters and TOC content, mineral composition and fractal dimension reveal that the fractal dimension is mainly associated with micropores. Samples with higher TOC content, higher quartz content and lower clay content tend to contain more heterogeneous micropores, resulting in higher fractal dimensions and more complicated pore structure in shales. Therefore, fractal dimension is an effective parameter to reflect the complexity of pore structure and the degree of micropore development in O₃w-S₁l shale.     

Last glacial–Holocene sediment sequences in N. Aegean basins: structure,accumulation rates and clay mineral distribution

The vertical distribution patterns of grain-size parameters, carbonate and organic carbon contents, and clay mineral abundances were examined in ten sediment cores from basins of the northern Aegean Sea. Sedimentation rates for Holocene deposition were determined on the basis of 11 ¹⁴C datings and indirectly from the age of the lower sapropel S1; they were estimated at 14.9, 18.9–21.8 and 34.7 cm 10³ year^–1 for the North Skyros, Athos, and North Limnos basins respectively. The sedimentation rates decrease gradually towards the southern basins, as a consequence of the greater distance from sediment supply sources. Also, sedimentation rates appear to decrease from the last glacial to Holocene units. The clay minerals illite, smectite, kaolinite and chlorite were identified in the cores. Generally, illite is the predominant mineral, showing a north–south-decreasing trend, followed by smectite; both minerals have a terrigenous origin, and smectite occurrence is higher in basins located near Limnos Island where volcanic formations prevail. Terrigenous illite is abundant in the sapropel S1, exhibiting the highest content of all sedimentological units. High illite content is unusual in eastern Mediterranean sapropels. This pattern is attributed to the proximity of the N. Aegean Sea basins to Balkan and Turkish land sources. In general, sediment mass gravity flow processes coupled with seasonal deposition from nepheloid layers are the predominant sedimentation mechanisms in the N. Aegean basins. The relative sea-level stand, the proximity to terrigenous sources (rivers), the morphology of the N. Aegean basins (small dimensions, isolated, steep slopes), as well as seismic activity and strong bottom currents are probably the major factors controlling sedimentation in the region.     

Diagenesis of a tight gas sand reservoir: Upper Cretaceous Mesaverde Group,Piceance Basin,Colorado

The Upper Cretaceous Mesaverde Group in the Piceance Basin, western Colorado, contains thick sections of low porosity, low permeability sandstones that are reservoirs for large accumulations of hydrocarbon gas. The Mesaverde sandstones are lithic arkoses and feldspathic litharenites, containing quartz, plagioclase, variable K-feldspar, chert, and volcanic rock fragments. Important diagenetic processes that have affected the sandstones include compaction, dissolution of feldspar and/or alteration to clay, precipitation of carbonate and quartz cements, precipitation of illite, and alteration of detrital clays (mixed-layer illite–smectite). Porosity is relatively constant; a decrease in primary porosity downward is approximately balanced by an increase in secondary porosity, with significant microporosity in authigenic and diagenetic clays. K-feldspar is almost completely absent below 5500 feet (1675 m). Fibrous illite is relatively abundant above this depth and variable in abundance below. The K–Ar ages of the clays increase with depth, from 40 m.y. at the top of the sampled section to 55 m.y. at the base, indicating illitization of a precursor smectite at approximately the 100 °C isotherm. Samples with abundant fibrous illite have relatively smaller age values. Mass balance calculations indicate that dissolution of K-feldspar, illitization of smectite and precipitation of fibrous illite were coupled. These reactions suggest the transport of dissolved potassium upward hundreds of feet (100–300 m) in the section, possibly associated with water driven vertically by the migration of gas.     

Pore characterization and methane sorption capacity of over-mature organic-rich Wufeng and Longmaxi shales in the southeast Sichuan Basin,China

Currently, the Upper Ordovician Wufeng (O₃w) and Lower Silurian Longmaxi (S₁l) Formations in southeast Sichuan Basin have been regarded as one of the most important target plays of shale gas in China. In this work, using a combination of low-pressure gas adsorption (N₂ and CO₂), mercury injection porosimetry (MIP) and high-pressure CH₄ adsorption, we investigate the pore characteristics and methane sorption capacity of the over-mature shales, and discuss the main controlling factors for methane sorption capacity and distribution of methane gas in pore spaces.Low pressure CO₂ gas adsorption shows that micropore volumes are characterized by three volumetric maxima (at about 0.35, 0.5 and 0.85 nm). The reversed S-shaped N₂ adsorption isotherms are type Ⅱ with hysteresis being noticeable in all the samples. The shapes of hysteresis loop are similar to the H3 type, indicating the pores are slit- or plate-like. Mesopore size distributions are unimodal and pores with diameters of 2–16 nm account for the majority of mesopore volume, which is generally consistent with MIP results. The methane sorption capacities of O₃w-S₁l shales are in a range of 1.63–3.66 m³/t at 30 °C and 10 MPa. Methane sorption capacity increase with the TOC content, surface area and micropore volume, suggesting organic matter might provide abundant adsorption site and enhance the strong methane sorption capacity. Samples with higher quartz content and lower clay content have larger sorption capacity. Our data confirmed that the effects of temperature and pressure on methane sorption capacity of shale formation are opposite to some extent, suggesting that, during the burial or uplift stage, the gas sorption capacity of hydrocarbon reservoirs can be expressed as a function of burial depth. Based on the adsorption energy theory, when the pore diameter is larger than 2 nm, much methane molecular will be adsorbed in pores space with distance to pore wall less than 2 nm; while free gas is mainly stored in the pore space with distance to pore wall larger than 2 nm. Distributions of adsorption space decrease with the increasing pore size, while free gas volume increase gradually, assuming the pore are cylindrical or sphere. Particularly, when the pore size is larger than 30 nm, the content of adsorbed gas space volume is very low and its contribution to the all gas content is negligible.     

Sedimentary and residual gas geochemical characteristics of the Lower Cambrian organic-rich shales in Southeastern Chongqing,China

To study the sedimentary environment of the Lower Cambrian organic-rich shales and isotopic geochemical characteristics of the residual shale gas, 20 black shale samples from the Niutitang Formation were collected from the Youyang section, located in southeastern Chongqing, China. A combination of geochemical, mineralogical, and trace element studies has been performed on the shale samples from the Lower Cambrian Niutitang Formation, and the results were used to determine the paleoceanic sedimentary environment of this organic-rich shale. The relationships between total organic carbon (TOC) and total sulfur (TS) content, carbon isotope value (δ¹³C_org), trace element enrichment, and mineral composition suggest that the high-TOC Niutitang shale was deposited in an anoxic environment and that the organic matter was well preserved after burial. Stable carbon isotopes and biomarkers both indicate that the organic matter in the Niutitang black shales was mainly derived from both lower aquatic organisms and algaes and belong to type I kerogen. The oil-prone Niutitang black shales have limited residual hydrocarbons, with low values of S₂, I_H, and bitumen A. The carbon isotopic distribution of the residual gas indicate that the shale gas stored in the Niutitang black shale was mostly generated from the cracking of residual bitumen and wet gas during a stage of significantly high maturity. One of the more significant observations in this work involves the carbon isotope compositions of the residual gas (C₁, C₂, and C₃) released by rock crushing. A conventional δ¹³C₁–δ¹³C₂ trend was observed, and most δ¹³C₂ values of the residual gases are heavier than those of the organic matter (OM) in the corresponding samples, indicating the splitting of ethane bonds and the release of smaller molecules, leading to ¹³C enrichment in the residual ethane.     

Qualitative and quantitative characterization of a transitional shale reservoir: A case study from the Upper Carboniferous Taiyuan shale in the eastern uplift of Liaohe Depression,China

The paper takes the Upper Carboniferous Taiyuan shale in eastern uplift of Liaohe depression as an example to qualitatively and quantitatively characterize the transitional (coal-associated coastal swamp) shale reservoir. Focused Ion Beam Scanning Electron Microscope (FIB-SEM), nano-CT, helium pycnometry, high-pressure mercury intrusion and low-pressure gas (N₂ & CO₂) adsorption for eight shale samples were taken to investigate the pore structures. Four types of pores, i.e., organic matter (OM) pores, interparticle (InterP) pores, intraparticle (IntraP) pores and micro-fractures are identified in the shale reservoir. Among them, intraP pores and micro-fractures are the major pore types. Slit-shaped pores are the major shape in the pore system, and the connectivity of the pore-throat system is interpreted to be moderate, which is subordinate to marine shale. The porosity from three dimension (3D) reconstruction of SEM images is lower than the porosity of helium pycnometry, while the porosity trend of the above two methods is the same. Combination of mercury intrusion and gas absorption reveals that nanometer-scale pores provide the main storage space, accounting for 87.16% of the pore volume and 99.85% of the surface area. Micropores contribute 34.74% of the total pore volume and 74.92% of the total pore surface area; and mesopores account for 48.27% of the total pore volume and 24.93% of the total pore surface area; and macropores contribute 16.99% of the total pore volume and 0.15% of the total pore surface area. Pores with a diameter of less than 10 nm contribute the most to the pore volume and the surface area, accounting for 70.29% and 97.70%, respectively. Based on single factor analysis, clay minerals are positively related to the volume and surface area of micropores, mesopores and macropores, which finally control the free gas in pores and adsorbed gas content on surface area. Unlike marine shale, TOC contributes little to the development of micropores. Brittle minerals inhibit pore development of Taiyuan shale, which proves the influence of clay minerals in the pore system.     

Mineral carbon MinC(%) from Rock-Eval analysis as a reliable and cost-effective measurement of carbonate contents in shale source and reservoir rocks

The abundance of carbonate minerals in rocks is an important element for petroleum geochemists, geologists and engineers to consider during hydrocarbon exploration and production. Carbonate minerals can be related to the depositional environments of the source rocks and hence the type of organic matter that can be subsequently modified through diagenetic processes. The total carbonate content in shales can also be used to deduce their fracability as reservoir rock for shale gas/oil extraction. At present, mineralogical analysis by X-ray diffraction (XRD) is the most widely used technique in the oil and gas-related petrophysical and geochemical laboratories for identifying and quantifying carbonate minerals in rock samples. In contrast, the use of the total mineral carbon content parameter MinC (%) from Rock-Eval analysis has been limited despite (1) the parameter's effectiveness as demonstrated through instrument and methodology development; and (2) the presence of a large volume of Rock-Eval results due to its widespread use in the oil and gas industry.In this study, we acquired XRD and Rock-Eval analytical results on over nine hundred rock samples ranging from Ordovician to Cretaceous age from four petroleum sedimentary basins in Canada. Least-squares regression analyses produce empirical equations with R² values greater than 0.92 for the correlations between XRD total carbonate contents and the Rock-Eval MinC (%) values of six different suites of samples. This indicates that the MinC (%) values generated by Rock-Eval 6 and other instruments of similar capability can be used with confidence for estimating the amounts of total carbonates in sedimentary rock samples. While the correlation between the two types of carbonate content measurements is geology-specific, a global linear regression model (R² of 0.97) based on the large combined data set has been proposed for approximating the total carbonate abundances based on Rock-Eval MinC (%) values.     

Geological roles of the siltstones in tight oil play

Understanding the hydrocarbon accumulation pattern in unconventional tight reservoirs is crucial for hydrocarbon evaluation and oil/gas extraction from such reservoirs. Previous studies on tight oil accumulation are mostly concerned with self-generation or from source to reservoir rock over short distances. However, the Lucaogou tight oil in Jimusar Sag of Junggar Basin shows transitional feature in between. The Lucaogou Formation comprises fine-grain sedimentary rocks characterized by thin laminations and frequently alternating beds. The Lucaogou tight silt/fine sandstones are poorly sorted. Dissolved pores are the primary pore spaces, with average porosity of 9.20%. Although the TOC of most silt/fine sandstones after Soxhlet extraction is lower than that before extraction, they show that the Lucaogou siltstones in the area of study have fair to good hydrocarbon generation potential (average TOC of 1.19%, average S₂ of 4.33 mg/g), while fine sandstones are relatively weak in terms of hydrocarbon generation (average TOC of 0.4%, average S₂ of 0.78 mg/g). The hydrocarbon generation amount of siltstones, which was calculated according to basin modeling transformation ratio combined with original TOC based on source rock parameters, occupies 16%–72% of oil retention amount. Although siltstones cannot produce the entire oil reserve, they certainly provide part of them. Grain size is negatively correlated with organic matter content in the Lucaogou silt/fine sandstones. Fine grain sediments are characterized by lower deposition rate, stronger adsorption capacity and oxidation resistance, which are favorable for formation of high quality source rocks. Low energy depositional environment is the primary reason for the formation of siltstones containing organic matter. Positive correlation between organic matter content and clay content in Lucaogou siltstones supports this view point. Lucaogou siltstones appear to be effective reservoir rocks due to there relatively high porosity, and also act as source rocks due to the fair to good hydrocarbon generation capability.     

Pore structure of Cambrian shales from the Sichuan Basin in China and implications to gas storage

The microstructure of black siliceous shale from the lower Cambrian Niutitang Formation, Sichuan Basin in China was investigated by the combination of field emission scanning electron microscope (FE-SEM) and argon ion beam milling. The nanometer-to micrometer-scale pore systems of shales are an important control on gas storage and fluid migration. In this paper, the organic porosity in shale samples within oil and gas window has been investigated, and the formation mechanism and diagenetic evolution of nanopores have been researched.FE-SEM reveals five pore types that are classified as follows: organic nanopores, pores in clay minerals, nanopores of framework minerals, intragranular pores in microfossils, and microfractures. Numerous organic nanopores are observed in shales in the gas window, whereas microfractures can be seen within the organic matter of shales in the oil window. Microfractures in oil window shales could be attributed to pressure buildup in the organic matter when incompressible liquid hydrocarbon are generated, and the orientation of microfractures is probably parallel to the bedding and strength anisotropy of the formation. Pores in clay minerals are always associated with the framework of clay flakes, and develop around rigid mineral grains because the pressure shadows of mineral grains protect pores from collapse, and the increasing of silt content would lead to an increase in pressure shadows and improve porosity. Nanopores of rock framework are probably related to dissolution by acidic fluids from hydrocarbon generation, and the dissolution-related pores promote permeability of shales. Porosity in the low-TOC, low-thermal-maturity shales contrast greatly with those of high-TOC, high-thermal-maturity shales. While the high-TOC shales contain abundant organic microporosity, the inorganic pores can contribute a lot to the porosity of the low-TOC shales.     

构造生烃理论及其在页岩气上的应用

生烃是地层有机质生成油气的化学平衡。由于油气的密度低于干酪根,它是典型的体积增大化学反应。与实验室开放系统不同,地层有机质生烃反应能等于活化能加排烃能。成熟阶段的地层比较致密,排烃能较大,与开放系统相比,形成了欠生烃。构造运动形成裂隙网,大大降低地层排烃能,使欠生烃的有机质短时间集中生烃,笔者称之为构造生烃。成熟地层通常较致密,排烃能较高,较多欠生烃有机质成为页岩气的物质基础。致密地层在过成熟条件下还有大量欠生烃有机质。经典生烃理论认为Ro大于2.0就基本不生烃,而许多Ro达到3.0,个别甚至4.0的页岩气发现,证明欠生烃的存在。分子越小,排烃能越低,相对致密地层生气的反应能通常最低,更多的有机质形成了页岩气,页岩气资源潜力巨大。页岩气的开采速度比地层自然排烃速度高出多个数量级,天然气排出最快的,最有利于生成天然气的化学平衡。勘探开发实践表明页岩含气量与其TOC成正比,笔者认为这正好预示着页岩中存在游离气、吸附气和有机质的化学平衡。游离气压降低,吸附气就会解吸附;吸附气解吸附,有机质就会生烃。有些过成熟岩石存在未—低成熟度Tmax值。这样低的Tmax值预示着,有机质能够在地层被压裂后随着排烃能的降低而满足反应条件,而成为潜在资源。页岩气的开采与普通气层相比更复杂、更漫长、更巨大。     

中国南海北部珠江口-琼东南盆地钻井岩屑地球化学特征及深水区天然气聚集特征

The Qiongdongnan Basin and Zhujiang River(Pearl River) Mouth Basin, important petroliferous basins in the northern South China Sea, contain abundant oil and gas resource. In this study, on basis of discussing impact of oil-base mud on TOC content and Rock-Eval parameters of cutting shale samples, the authors did comprehensive analysis of source rock quality, thermal evolution and control effect of source rock in gas accumulation of the Qiongdongnan and the Zhujiang River Mouth Basins. The contrast analysis of TOC contents and Rock-Eval parameters before and after extraction for cutting shale samples indicates that except for a weaker impact on Rock-Eval parameter S_2, oil-base mud has certain impact on Rock-Eval S_1, Tmax and TOC contents. When concerning oil-base mud influence on source rock geochemistry parameters, the shales in the Yacheng/Enping,Lingshui/Zhuhai and Sanya/Zhuhai Formations have mainly Type Ⅱ and Ⅲ organic matter with better gas potential and oil potential. The thermal evolution analysis suggests that the depth interval of the oil window is between 3 000 m and 5 000 m. Source rocks in the deepwater area have generated abundant gas mainly due to the late stage of the oil window and the high-supper mature stage. Gas reservoir formation condition analysis made clear that the source rock is the primary factor and fault is a necessary condition for gas accumulation. Spatial coupling of source, fault and reservoir is essential for gas accumulation and the inside of hydrocarbon-generating sag is future potential gas exploration area.     

镇江下蜀土中的黏土矿物及其古环境意义

镇江大港砖瓦厂下蜀黄土剖面30个样品的X衍射分析和半定量结果表明,该剖面黏土矿物组合为伊利石-蛭石-高岭石型,其中以伊利石（52.8%～70%）和蛭石（20.6%～38.5%）为主;古土壤层的伊利石相对含量高于黄土层,蛭石的变化与之相反,二者互为消长.高岭石含量为6.0%～11.1%,在古土壤中的含量略高于黄土层.从剖面底部（S4）至顶部（S1）, 伊利石相对含量略呈增加趋势,蛭石和高岭石则略呈减少趋势.镇江下蜀黄土中的黏土矿物组合类型与北方黄土明显不同,伊利石的结晶度总体上也较北方黄土差,反映下蜀黄土堆积区相对温暖、湿润,风化淋滤作用相对较强.从黏土矿物组合和含量来看,下蜀黄土经历了中等强度的风化作用.