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1.
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. 相似文献
2.
The influence of oil-expulsion efficiency on nanopore development in highly mature shale was investigated by using anhydrous pyrolysis (425–600 °C) on solvent-extracted and non-extracted shales at a pressure of 50 MPa. Additional pyrolysis studies were conducted using non-extracted shales at pressures of 25 and 80 MPa to further characterize the impact of pressure on pore evolution at high maturity. The pore structures of the original shale and relevant artificially matured samples after pyrolysis were characterized by using low-pressure nitrogen and carbon-dioxide adsorption techniques, and gas yields during pyrolysis were measured. The results show that oil-expulsion efficiency can strongly influence gas generation and nanopore development in highly mature shales, as bitumen remained in shales with low oil expulsion efficiency significantly promotes gaseous hydrocarbon generation and nanopore (diameter < 10 nm) development. The evolution of micropores and fine mesopores at high maturity can be divided into two main stages: Stage I, corresponding to wet gas generation (EasyRo 1.2%–2.4%), and Stage II, corresponding to dry gas generation (EasyRo 2.4%–4.5%). For shales with low oil expulsion efficiency, nanopore (diameter < 10 nm) evolution increases rapidly in Stage I, whereas slowly in Stage II, and such difference between two stages may be attributed to the changes of the organic matter (OM)’s mechanical properties. Comparatively, for shales with high oil expulsion efficiency, the evolution grows slightly in Stage I, not as rapidly as shales with low efficiency, and decays in Stage II. The different pore evolution behaviors of these two types of shales are attributed to the contribution of bitumen. However, the evolution of medium–coarse mesopores and macropores (diameter >10 nm) remains flat at high maturation. In addition, high pressure can promote the development of micropores and fine mesopores in highly mature shales. 相似文献
3.
Mineral types (detrital and authigenic) and organic-matter components of the Ordovician-Silurian Wufeng and Longmaxi Shale (siliceous, silty, argillaceous, and calcareous/dolomitic shales) in the Sichuan Basin, China are used as a case study to understand the control of grain assemblages and organic matter on pores systems, diagenetic pathway, and reservoir quality in fine-grained sedimentary rocks. This study has been achieved using a combination of petrographic, geochemical, and mercury intrusion methods. The results reveal that siliceous shale comprises an abundant amount of diagenetic quartz (40–60% by volume), and authigenic microcrystalline quartz aggregates inhibit compaction and preserve internal primary pores as rigid framework for oil filling during oil window. Although silty shale contains a large number of detrital silt-size grains (30–50% by volume), which is beneficial to preserve interparticle pores, the volumetric contribution of interparticle pores (mainly macropores) is small. Argillaceous shale with abundant extrabasinal clay minerals (>50% by volume) undergoes mechanical and chemical compactions during burial, leading to a near-absence of primary interparticle pores, while pores preserved between clay platelets are dominant with more than 10 nm in pore size. Pore-filling calcite and dolomite precipitated during early diagenesis inhibit later compaction in calcareous/dolomitic shale, but the cementation significantly reduces the primary interparticle pores. Pore-throat size distributions of dolomitic shale show a similar trend with silty shale. Besides argillaceous shale, all of the other lithofacies are dominated by OM pores, which contribute more micropores and mesopores and is positively related to TOC and quartz contents. The relationship between pore-throat size and pore volume shows that most pore volumes are provided by pore throats with diameters <50 nm, with a proportion in the order of siliceous (80.3%) > calcareous/dolomitic (78.4%) > silty (74.9%) > argillaceous (61.3%) shales. In addition, development degree and pore size of OM pores in different diagenetic pathway with the same OM type and maturity show an obvious difference. Therefore, we suggest that the development of OM pores should take OM occurrence into account, which is related to physical interaction between OM and inorganic minerals during burial diagenesis. Migrated OM in siliceous shale with its large connected networks is beneficial for forming more and larger pores during gas window. The result of the present work implies that the study of mineral types (detrital and authigenic) and organic matter-pores are better understanding the reservoir quality in fine-grained sedimentary rocks. 相似文献
4.
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. 相似文献
5.
As shale oil occurs primarily in micro–nano pores and fractures, research about the effect of pore structure on shale oil accumulation has great significance for shale oil exploration and development. The effect of pore structure on shale oil accumulation in the lower third member of the Shahejie formation (Es3l), Zhanhua Sag, eastern China was investigated using gas adsorption, soxhlet extraction, nuclear magnetic resonance (NMR) analysis, and field emission scanning electron microscope (FE-SEM) observation. The results indicated that the samples contained a larger amount of ink-bottle-shaped and slit-shaped pores after extraction than before extraction. The pore volume and specific surface area of the samples were approximately 2.5 times larger after extraction than before extraction. Residual hydrocarbon occurred primarily in the free-state form in pores with diameters of 10–1000 nm, which can provide sufficient pore volume for free hydrocarbon accumulation. Therefore, pores with diameters of 10–1000 nm were regarded as “oil-enriched pores”, which are effective pores for shale oil exploration, whereas pores with diameters smaller than 10 nm were regarded as “oil-ineffective pores”. Samples with only well-developed small pores with diameters smaller than 1000 nm showed high oil saturation, whereas samples with both small pores and also relatively large pores and micro-fractures presented low oil saturation. As the minimum pore size allowing fluid expulsion is 1000 nm, pores with diameters greater than 1000 nm were considered as “oil-percolated pores”. Large pores and micro-fractures are generally interconnected and may even form a complex fracture mesh, which greatly improves the permeability of shale reservoirs and is beneficial to fluid discharge. 相似文献
6.
《Marine and Petroleum Geology》2013,39(1):53-72
Evaluation of the reservoir quality of the Triassic Halfway–Montney–Doig hybrid gas shale/tight gas reservoir in the Groundbirch field in northeastern British Colombia requires an integration of unconventional and conventional methodologies. Reservoir evaluation includes reservoir thickness and structure, total porosity, TOC content, organic maturity, pore size distribution (micro- to macro-pore size fractions), surface area, mineralogy and pulse-decay permeability. Quartz (10–74%), carbonate (13–73%) and feldspar (0–42%) dominate the mineralogy of all formations with illite (0–32%) being locally important. The Tmax values range between 443 and 478 °C placing the reservoirs beyond the oil window. Pore size distribution by low-pressure gas adsorption analysis identifies a large variation between the contributions from the micro-, meso- and macro-pore size fractions. Matrix permeabilities range between 1.0E-3 and 6.5E-7 mD at an effective stress between 2400 and 3300 PSI (16.5–22.8 MPa).Changes in depositional environments and diagenetic processes manifest as differences in lithology and mineralogy within the Montney and Doig reservoirs which subsequently affect the fabric, texture and pore size distribution. Fabric, texture and pore size distribution contribute to the variation in the permeability and the proportions of free to sorbed gas within the reservoir. Quartz-rich, coarser-grained intervals (upper portions of Doig C, B and Halfway Formation) have lower surface area, greater porosities and a higher volume of macropores compared to the carbonate- and clay-rich finer-grained intervals (Doig A). Permeabilities do not vary according to lithology with higher permeabilities found within both fine-grained (Doig A) and coarser-grained (Halfway Formation) units. Permeability is controlled by pore size distribution. Higher permeability samples contain a balanced ratio between micro-, meso- and macro-porosity. The finer-grained intervals have higher sorbed gas capacity due to higher surface areas because of the higher volumes of finer mesopores and micropores than the coarser-grained units. However, porosity and permeability are low in some parts of the Doig A and fracture stimulation is necessary to achieve economic flow rates. 相似文献
7.
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 (Ro) of 0.49% and an average pyrolytic temperature of the generated maximum remaining hydrocarbon (Tmax) 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. 相似文献
8.
The Songliao Basin is a large-scale petroliferous basin in China. With a gradual decline in conventional oil production, the exploration and development of replacement resources in the basin is becoming increasingly important. Previous studies have shown that the Cretaceous Qingshankou Formation (K2qn) has favorable geological conditions for the formation of shale oil. Thus, shale oil in the Qingshankou Formation represents a promising and practical replacement resource for conventional oil. In this study, geological field surveys, core observation, sample tests, and the analysis of well logs were applied to study the geochemical and reservoir characteristics of shales, identify shale oil beds, build shale oil enrichment models, and classify favorable exploration areas of shale oil from the Cretaceous Qingshankou Formation. The organic matter content is high in shales from the first member of the Cretaceous Qingshankou Formation (K2qn1), with average total organic carbon (TOC) content exceeding 2%. The organic matter is mainly derived from lower aquatic organisms in a reducing brackish to fresh water environment, resulting in mostly type I kerogen. The vitrinite reflectance (Ro) and the temperature at which the maximum is release of hydrocarbons from cracking of kerogen occurred during pyrolysis (Tmax) respectively range from 0.5% to 1.1% and from 430 °C to 450 °C, indicating that the K2qn1 shales are in the low-mature to mature stage (Ro ranges from 0.5% to 1.2%) and currently generating a large amount of oil. The favorable depth for oil generation and expulsion is 1800–2200 m and 1900–2500 m, respectively as determined by basin modeling. The reserving space of the K2qn1 shale oil includes micropores and mircofractures. The micropore reservoirs are developed in shales interbedded with siltstones exhibiting high gamma ray (GR), high resistivity (Rt), low density (DEN), and slightly abnormal spontaneous potential (SP) in the well-logging curves. The microfracture reservoirs are mainly thick shales with high Rt, high AC (acoustic transit time), high GR, low DEN, and abnormal SP. Based on the shale distribution, geochemical characteristics, reservoir types, fracture development, and the process of shale oil generation and enrichment, the southern Taikang and northern Da'an are classified as two favorable shale oil exploration areas in the Songliao Basin. 相似文献
9.
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. 相似文献
10.
This study presents approaches for evaluating hybrid source rock/reservoirs within tight-rock petroleum systems. The emerging hybrid source rock/reservoir shale play in the Upper Cretaceous Second White Specks and Belle Fourche formations in central Alberta, Canada is used as an example to evaluate organic and inorganic compositions and their relationships to pore characteristics. Nineteen samples from a 77.5 m-long core were analyzed using organic petrography, organic geochemistry, several methods of pore characterization, and X-ray powder diffraction (XRD). The lower part of the studied section includes quartz- and clay-rich mudrocks of the Belle Fourche Formation with low carbonate content, whereas the upper portion contains calcareous mudrocks of the Second White Specks Formation. Strata are mineralogically composed of quartz plus albite (18–56 wt. %), carbonates (calcite, dolomite, ankerite; 1–65 wt. %), clays (illite, kaolinite, chlorite; 15–46 wt. %), and pyrite (2–12 wt. %). Petrographic examinations document that organic matter represents marine Type II kerogen partly biodegraded with limited terrestrial input. Vitrinite reflectance Ro (0.74–0.87%), Tmax values (438–446 °C) and biomarkers indicate mid-maturity within the oil window. The relatively poor remaining hydrocarbon potential, expressed as an S2 value between 2.1 and 6.5 mg HC/g rock, may result from an estimated 60–83% of the original kerogen having been converted to hydrocarbons, with the bulk having migrated to adjacent sandstone reservoirs. However, the present-day remaining total organic carbon TOCpd content remains relatively high (1.7–3.6 wt. %), compared with the estimated original TOCo of 2.4–5.0 wt. %. The calculated transformation ratio of 60–83% suggests that the remaining 17–40 wt. % of kerogen is able to generate more hydrocarbons. The studied section is a tight reservoir with an average Swanson permeability of 3.37·10−5 mD (measured on two samples) and total porosity between 1.7 and 5.0 vol. % (3 vol. % on average). The upper part of the sandy Belle Fourche Formation, with slightly elevated porosity values (3.5–5 vol. %), likely represents the interval with the best reservoir properties in the studied core interval. Total pore volume ranges between 0.0065 and 0.0200 cm3/g (measured by a combination of helium pycnometry and mercury immersion). Mesopores (2–50 nm ∅) are the most abundant pores and occupy 34–67% of total porosity or a volume of 0.0030–0.0081 cm3/g. In comparison, micropores (<2 nm ∅) cover a wide range from 6 to 60% (volume 0.0007–0.0053 cm3/g), and macropores (>50 nm ∅) reach up to 57% with the exception of some samples failing to indicate the presence of this pore fraction (volume 0.0000–0.0107 cm3/g). Macroporosity is mostly responsible for variations in total porosity, as suggested by macroporosity's strongest correlation with total porosity within the section. The relatively narrow ranges of TOC and minerals contents among measured samples limit our ability to further deconvolute factors that influence changes in total porosity and pore size distribution. 相似文献
11.
The nano-scale pore systems of organic-rich shale reservoirs were investigated from Upper Ordovician Wufeng and Lower Silurian Longmaxi Formations in southeast Sichuan Basin. These two formations are the most important target plays of shale gas development in China. The purpose of this article is to assess the geometry and connectivity of multi-scale pore systems, and to reveal the nature and complexity of pore structure for these over-mature gas shales. To achieve these objective, total organic carbon, mineralogy, image analyses by focused ion beam-SEM, low pressure nitrogen adsorption, mercury injection capillary pressure (MICP) and spontaneous fluid [deionized (DI) water and n-decane] imbibition were performed.Most of the visible pores from SEM work in Wufeng and Longmaxi shales are within nm- and μm-size regimes and belong to organic matter (OM) pores. The shapes of OM pore in Longmaxi samples are elliptical, bubble-like, irregular or rounded. Wufeng pores are mainly irregular, linear and faveolated, even though two shales have small depth difference, as well as similar thermal maturity, kerogen type and TOC content. Nano-scale pores in Longmaxi are mainly associated with narrow platelike or slitlike pores with pore size of 3–50 nm; while inkbottle pores are dominant in Wufeng samples and over 88% of the pore volume is contributed by pores with diameter <20 nm. Overall, porosity, pore volume and surface area values from Wufeng samples are much higher than those in Longmaxi, which is mainly correlated with the different TOC contents and mineral compositions. MICP tests show that a total of 5 inflection points (indicative of different connected pore networks) are identified in all pressure regions for Longmaxi, while only 2 for Wufeng in high pressure region with the associated permeability at nano-darcy range. Imbibition curves of n-decane are divided into three stages: the initial stage (Stage Ⅰ), linear imbibition stage (Stage Ⅱ) and late imbibition stage (Stage Ⅲ), and the slopes of linear imbibition stage are around 0.5, suggesting well-connected pore spaces for n-decane. In contrast, imbibition curves for DI water are divided in two stages with linear slopes of between 0.25 and 0.5, indicating moderately-connected pore networks for the movement of DI water. This is consistent with the mixed-wet nature of these shales, with observed weak wettability for hydrophilic, while complete wetting for hydrophobic fluids. 相似文献
12.
Zhanhua Sag is a widely accepted target zone with huge exploration and development potential for shale oil and shale gas resources. Many detailed studies have been undertaken around the geochemistry of the lower section of the third member of the Shahejie Formation (Es3x), while few studies have focused on the reservoir. In this study, based on the mineralogical features and geochemical characteristics, and by using statistical methods, the characteristics and controlling factors of reservoir space of mudstone and shale in Es3x in the Zhanhua Sag are explored through field-emission scanning electron microscopy (FE-SEM), high pressure mercury injection capillary pressure (MICP), and nuclear magnetic resonance (NMR) techniques. Three major findings were obtained. ① There are micropores and microfractures in the reservoir space, which include intergranular pores, clay intercrystal pores, pyrite intercrystal pores, dissolved pores, structural microfractures, and bedding microfractures. ② According to the features of pore size distribution (PSD), the pore distribution can be divided into the following three categories: 0–50 nm, 50 nm–2 μm, and >2 μm; the average volumes of these components are 0.01079 mL g−1, 0.00361 mL g−1, and 0.00355 mL g−1, respectively, thus showing that the pores whose radii are distributed at 0–50 nm form the most important reservoir space (though those with the 50 nm–2 μm and >2 μm radii are also important and cannot be ignored). ③ There are different controlling factors when it comes to different scale pores. Based on statistics and FE-SEM results, the dissolved pores in calcite were determined to be the controlling factor for the 0–50 nm portion, the intercrystalline pores in clay and pyrite, and intergranular pores between authigenic minerals (calcite, dolomite, and pyrite) and clastic minerals (calcite and dolomite) were determined to be the controlling factors for the 50 nm–2 μm portion, and the structural microfractures and bedding microfractures were determined to be the main factors for the >2 μm portion. Furthermore, it is the brittle minerals content and bedded structure that control the microfractures. This study thus clarifies the types and characteristics of reservoir space and identifies pore structure controlling factors of mudstone and shale in Es3x in the Zhanhua Sag; this information has important significance for future reservoir evaluations. 相似文献
13.
When trying to improve gas productivity from unconventional sources a first aim is to understand gas storage and gas flow potential through the rock by investigating the microstructure, mineralogy and matrix porosity of unfractured shale. The porosity and mineralogy of the Mulgrave Shale member of the Whitby Mudstone Formation (UK) were characterized using a combination of microscopy, X-ray diffraction and gas adsorption methods on samples collected from outcrops. The Whitby Mudstone is an analogue for the Dutch Posidonia Shale which is a possible unconventional source for gas. The Mulgrave shale member of the Whitby Mudstone Formation can microstructurally be subdivided into a fossil rich (>15%) upper half and a sub-mm mineralogically laminated lower half. All clasts are embedded within a fine-grained matrix (all grains < 2 μm) implying that any possible flow of gas will depend on the porosity and the pore network present within this matrix. The visible SEM porosity (pore diameter > 100 nm) is in the order of 0.5–2.5% and shows a non-connected pore network in 2D. Gas adsorption (N2, Ar, He) porosity (pore diameters down to 2 nm) has been measured to be 0.3–7%. Overall more than 40% of the visible porosity is present within the matrix. Comparing the Whitby Mudstone Formation to other (producing) gas shales shows that the rock plots in the low porosity and high clay mineral content range, which could imply that Whitby Mudstone shales could be less favourable to mechanical fracturing than other gas shales. Estimated permeability indicates values in the micro-to nano-darcy range. 相似文献
14.
Low and high resolution petrographic studies have been combined with mineralogical, TOC, RockEval and porosity data to investigate controls on the evolution of porosity in stratigraphically equivalent immature, oil-window and gas-window samples from the Lower Toarcian Posidonia Shale formation. A series of 26 samples from three boreholes (Wickensen, Harderode and Haddessen) in the Hils syncline was investigated. The main primary components of the shales are microfossiferous calcite (30–50%), clay minerals (20–30%) and Type II organic matter (TOC = 7–15%, HI = 630–720 mg/gC in immature samples). Characteristic sub-centimetric light and dark lamination reflects rapid changes in the relative supply of these components. Total porosities decrease from 10 to 14% at Ro = 0.5% to 3–5% at Ro = 0.9% and then increase to 9–12% at Ro = 1.45%. These maturity-related porosity changes can be explained by (a) the primary composition of the shales, (b) carbonate diagenesis, (c) compaction and (d) the maturation, micro-migration, local trapping and gasification of heterogeneous organic phases. Calcite undergoes dissolution and reprecipitation reactions throughout the maturation sequence. Pores quantifiable in SEM (>ca. 50 nm) account for 14–25% of total porosity. At Ro = 0.5%, SEM-visible macropores1 are associated mainly with biogenic calcite. At this maturity, clays and organic matter are not visibly porous but nevertheless hold most of the shale porosity. Porosity loss into the oil window reflects (a) compaction, (b) carbonate cementation and (c) perhaps the swelling of kerogen by retained oil. In addition, porosity is occluded by a range of bituminous phases, especially in microfossil macropores and microfractures. In the gas window, mineral-hosted porosity is still the primary form of macroporosity, most commonly observed at the organic-inorganic interface. Increasing porosity into the gas window also coincides with the formation of isolated, spongy and complex meso- and macropores within organic particles, related to thermal cracking and gas generation. This intraorganic porosity is highly heterogeneous: point-counted macroporosity of individual organic particles ranges from 0 to 40%, with 65% of organic particles containing no macropores. We suggest that this reflects the physicochemical heterogeneity of the organic phases plus the variable mechanical protection afforded by the mineral matrix to allow macroporosity to be retained. The development of organic macroporosity cannot alone account for the porosity increase observed from oil to gas window; major contributions also come from the increased volume of organic micro- and meso-porosity, and perhaps by kerogen shrinkage. 相似文献
15.
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 (Ro 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 Eq33x 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. 相似文献
16.
Studying complex pore structures is the key to understanding the mechanism of shale gas accumulation. FIB-SEM (focused ion beam-scanning electron microscope) is the mainstream and effective instrument for imaging nanopores in gas shales. Based on this technology, 2D and 3D characteristics of shale samples from Lower Silurian Longmaxi formation in southern Sichuan Basin were investigated. 2D experimental results show that the pores in shale are nanometer-sized, and the structure of those nanopores can be classified into three types: organic pores, inorganic pores and micro fractures. Among the three types, organic pores are dominantly developed in the OM (organic matter) with three patterns such as continuous distributed OM, OM between clay minerals and OM between pyrite particles, and the size of organic pores range from 5 nm to 200 nm.Inveresly, inorganic pores and micro fractures are less developed in the Longmaxi shales. 3D digital rocks were reconstructed and segmented by 600 continuous images by FIB cutting and SEM imaging simultaneously. The pore size distribution and porosity can be calculated by this 3D digital core, showing that its average value is 32 nm and porosity is 3.62%.The 3D digital porosity is higher than its helium porosity, which can be regarded as one important parameter for evaluation of shale gas reserves. The 2D and 3D characterized results suggest that the nanometer-sized pores in organic matter take up the fundamental storage space for the Longmaxi shale. These characteristics have contributed to the preservation of shale gas in this complex tectonic area. 相似文献
17.
《Marine and Petroleum Geology》2012,32(1):110-124
The transport properties of Permian to Miocene oil shales (Torbanite, Posidonia, Messel, Himmetoglu, and Condor) were studied using petrophysical and geochemical techniques. The aims of this study were to assess permeability of oil shales, evaluate the evolution of porosity, specific surface area and intergranular permeability during high temperature compaction tests and to verify the suitability of intergranular permeability for petroleum expulsion. Measured permeability coefficients for two samples were 0.72 × 10−21 m² for the Eocene Messel shale and 2.63 × 10−21 m² for the Lower Jurassic Posidonia shale from S. Germany, respectively. BET specific surface areas of the original samples ranged from 0.7 to 10.6 m²/g and decreased after compaction to values from 0.3 to 3.7 m²/g. Initial porosity values ranged from 7.6 to 20.1 % for pre-deformation and from 9.99 to 20.7 % for post-deformation samples. Porosity increased during the high-temperature compaction experiments due to petroleum generation and expulsion. Permeability coefficients estimated using the Kozeny–Carman equation varied from 6.97 × 10−24 m² to 5.22 × 10−21 m² for pre-deformation and from 0.2 × 10−21 m² to 4.8 × 10−21 m² for post-deformation samples reflecting the evolution of their porosity and BET specific surface areas. Measured and calculated permeability were similar for the Messel shale whereas calculated permeability was two orders of magnitude lower for the Posidonia shale from S. Germany. Petroleum expulsion efficiencies under the experimental conditions ranged from 38.6% for the Torbanite to 96.2% for the Posidonia shale from S. Germany. They showed strong positive correlation with the petroleum generation index (R² = 0.91) and poor correlations with porosity (R² = 0.46), average pore throat diameters (R² = 0.22), and compaction (R² = 0.02). Estimated minimum pore-system saturations for petroleum expulsion during the experiments were 12% for the Torbanite and 30% for the Posidonia shale from N. Germany. Pore-system saturation determines whether expulsion occurs mainly through matrix or fracture permeability. For samples with saturation levels above 20%, fracture permeability dominated during the experiments. Evidence based on the measured permeability coefficients, expulsion flow rates, consideration of capillary displacement during generation-related pore invasion and the existence of transport porosity suggests that fracture permeability is the principal avenue of petroleum expulsion from source rocks. This conclusion is supported by microscopic observations. 相似文献
18.
Nine organic-rich shale samples of Lower Cambrian black shales were collected from a recently drilled well in the Qiannan Depression, Guizhou Province where they are widely distributed with shallower burial depth than in Sichuan Basin, and their geochemistry and pore characterization were investigated. The results show that the Lower Cambrian shales in Qiannan Depression are organic rich with TOC content ranging from 2.81% to 12.9%, thermally overmature with equivalent vitrinite reflectance values in the range of 2.92–3.25%, and clay contents are high and range from 32.4% to 53.2%. The samples have a total helium porosity ranging from 2.46% to 4.13% and total surface area in the range of 9.08–37.19 m2/g. The estimated porosity in organic matters (defined as the ratio of organic pores to the volume of total organic matters) based on the plot of TOC vs helium porosity is about 10% for the Lower Cambrian shales in Qiannan Depression and is far lower than that of the Lower Silurian shales (36%) in and around Sichan Basin. This indicates that either the organic pores in the Lower Cambrian shale samples have been more severely compacted than or they did not develop organic pores as abundantly as the Lower Silurian shales. Our studies also reveal that the micropore volumes determined by Dubinin–Radushkevich (DR) equation is usually overestimated and this overestimation is closely related to the non-micropore surface area of shales (i.e. the surface area of meso- and macro-pores). However, the modified BET equation can remove this overestimation and be conveniently used to evaluate the micropore volumes/surface area and the non-micropore surface areas of micropore-rich shales. 相似文献
19.
Shales from the Lower Silurian Longmaxi Formation in the Sichuan Basin are among the most important shale gas reservoirs in China, and have been investigated because of their great shale gas potential. To understand the pore structure and fractal characteristics of the shales, a series of experiments was conducted on core samples from the Lower Silurian Longmaxi Formation in the Sichuan Basin of China, including X-ray diffraction (XRD), total organic carbon (TOC) content and vitrinite reflectance (Ro) analysis, field emission-environmental scanning electron microscope (FE-ESEM) observation, and low-pressure N2 adsorption-desorption experiments. Frenkel-Halsey-Hill (FHH) method was applied to calculate fractal dimensions. In addition, the pore genesis, the relationships between composition and thermal maturity, the pore structure parameters, and the fractal dimensions are discussed. FE-ESEM observation results show that the Longmaxi Formation shales are dominated by organic-matter (OM) pores along with interparticle (interP) pores, intraparticle (intraP) pores and fracture pores. This study identified the fractal dimensions at relative pressures of 0–0.45 and 0.45–1 as D1 and D2 respectively. D1 ranged from 2.60 to 2.71 and D2 ranged from 2.71 to 2.82. D1 was typically smaller than D2, indicating that the smaller pores in shales were more homogeneous than the larger ones. The formation of these OM pores is owing to kerogen deformation during the thermal maturation, which results in a large number of nanopores. The pore structure of the Longmaxi Formation shales is primarily controlled by TOC content and thermal maturity. TOC content is a controlling factor on the fractal dimensions as it exhibited positive correlations with D1 and D2. Fractal dimensions are useful for the characterization of the pore structures complexity of the Longmaxi Formation shales because D1 and D2 correlate well with pore structure parameters as they both increase with the increase of surface area and the decrease of average pore diameter. 相似文献
20.
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. 相似文献