Pore structure characteristics of tight sandstones in the northern Songliao Basin,China

Understanding the pore structure characteristics of tight gas sandstones is the primary purpose of reservoir evaluation and efforts to characterize tight gas transport and storage mechanisms and their controls. Due to the various pore types and multi-scale pore sizes in tight reservoirs, it is essential to combine several techniques to characterize pore structure. Scanning electron microscopy (SEM), nitrogen gas adsorption (N₂GA), mercury intrusion porosimetry (MIP) and nuclear magnetic resonance (NMR) were conducted on tight sandstones from the Lower Cretaceous Shahezi Formation in the northern Songliao Basin to investigate pore structure characteristics systematically (e.g., type and size distribution of pores) and to establish how significant porosity and permeability are for different pore types. The studied tight sandstones are composed of intergranular pores, dissolution pores and intercrystalline pores. The integration of N₂GA and NMR can be used as an efficient method to uncover full pore size distribution (PSD) of tight sandstones, with pore sizes ranging from 2 nm to dozens of microns. The full PSDs indicate that the pore sizes of tight sandstones are primarily distributed within 1.0 μm. With an increase in porosity and permeability, pores with larger sizes contribute more to porosity. Intercrystalline pores and intergranular/dissolution pores can be clearly distinguished on the basis of mercury intrusion and surface fractal. The relative contribution of intercrystalline pores to porosity ranges from 58.43% to 91.74% with an average of 79.74%. The intercrystalline pores are the primary contributor to pore space, whereas intergranular/dissolution pores make a considerably greater contribution to permeability. A specific quantity of intergranular/dissolution pores is the key to producing high porosity and permeability in tight sandstone reservoirs. The new two permeability estimation models show an applicable estimation of permeability with R² values of 0.955 and 0.962 for models using D_max (pore diameter corresponding to displacement pressure) and D_f (pore diameter at inflection point), respectively. These results indicate that both D_max and D_f are key factors in determining permeability.     

Controls on reservoir quality of Lower Cretaceous tight sandstones in the Laiyang Sag,Jiaolai Basin,Eastern China: Integrated sedimentologic,diagenetic and microfracturing data

The Jiaolai Basin (Fig. 1) is an under-explored rift basin that has produced minor oil from Lower Cretaceous lacustrine deltaic sandstones. The reservoir quality is highly heterogeneous and is an important exploratory unknown in the basin. This study investigates how reservoir porosity and permeability vary with diagenetic minerals and burial history, particularly the effects of fracturing on the diagenesis and reservoir deliverability. The Laiyang sandstones are tight reservoirs with low porosity and permeability (Φ < 10% and K < 1 mD). Spatial variations in detrital supply and burial history significantly affected the diagenetic alterations during burial. In the western Laiyang Sag, the rocks are primarily feldspathic litharenites that underwent progressive burial, and thus, the primary porosity was partially to completely eliminated as a result of significant mechanical compaction of ductile grains. In contrast, in the eastern Laiyang Sag, the rocks are lithic arkoses that were uplifted to the surface and extensively eroded, which resulted in less porosity reduction by compaction. The tectonic uplift could promote leaching by meteoric water and the dissolution of remaining feldspars and calcite cement. Relatively high-quality reservoirs are preferentially developed in distributary channel and mouth-bar sandstones with chlorite rims on detrital quartz grains, which are also the locations of aqueous fluid flow that produced secondary porosity. The fold-related fractures are primarily developed in the silt–sandstones of Longwangzhuang and Shuinan members in the eastern Laiyang Sag. Quartz is the most prevalent fracture filling mineral in the Laiyang sandstones, and most of the small-aperture fractures are completely sealed, whereas the large-aperture fractures in a given set may be only partially sealed. The greatest fracture density is in the silt–sandstones containing more brittle minerals such as calcite and quartz cement. The wide apertures are crucial to preservation of the fracture porosity, and the great variation in the distribution of fracture-filling cements presents an opportunity for targeting fractures that contribute to fluid flow.     

Prediction of diagenetic facies using well logs – A case study from the upper Triassic Yanchang Formation,Ordos Basin,China

Understanding diagenetic heterogeneity in tight sandstone reservoirs is vital for hydrocarbon exploration. As a typical tight sandstone reservoir, the seventh unit of the Upper Triassic Yanchang Formation in the Ordos Basin (Chang 7 unit), central China, is an important oil-producing interval. Results of helium porosity and permeability and petrographic assessment from thin sections, X-ray diffraction, scanning electron microscopy and cathodoluminescence analysis demonstrate that the sandstones have encountered various diagenetic processes encompassing mechanical and chemical compaction, cementation by carbonate, quartz, clay minerals, and dissolution of feldspar and lithic fragments. The sandstones comprise silt-to medium-grained lithic arkoses to feldspathic litharenites and litharenites, which have low porosity (0.5%–13.6%, with an average of 6.8%) and low permeability (0.009 × 10⁻³ μm² to 1.818 × 10⁻³ μm², with an average of 0.106 × 10⁻³ μm²).This study suggests that diagenetic facies identified from petrographic observations can be up-scaled by correlation with wire-line log responses, which can facilitate prediction of reservoir quality at a field-scale. Four diagenetic facies are determined based on petrographic features including intensity of compaction, cement types and amounts, and degree of dissolution. Unstable and labile components of sandstones can be identified by low bulk density and low gamma ray log values, and those sandstones show the highest reservoir quality. Tightly compacted sandstones/siltstones, which tend to have high gamma ray readings and relatively high bulk density values, show the poorest reservoir quality. A model based on principal component analysis (PCA) is built and show better prediction of diagenetic facies than biplots of well logs. The model is validated by blind testing log-predicted diagenetic facies against petrographic features from core samples of the Upper Triassic Yanchang Formation in the Ordos Basin, which indicates it is a helpful predictive model.     

Critical evaluation of an Upper Carboniferous tight gas sandstone reservoir analog: Diagenesis and petrophysical aspects

Upper Carboniferous sandstones are one of the most important tight gas reservoirs in Central Europe. We present data from an outcrop reservoir analog (Piesberg quarry) in the Lower Saxony Basin of Northern Germany. This field-based study focuses on the diagenetic control on spatial reservoir quality distribution.The investigated outcrop consists of fluvial 4^th-order cycles, which originate from a braided river dominated depositional environment. Westphalian C/D stratigraphy, sedimentary thicknesses and exposed fault orientations (NNW-SSE and W-E) reflect tight gas reservoir properties in the region further north. Diagenetic investigations revealed an early loss of primary porosity by pseudomatrix formation. Present day porosity (7% on average) and matrix permeability (0.0003 mD on average) reflect a high-temperature overprint during burial. The entire remaining pore space is occluded with authigenic minerals, predominantly quartz and illite. This reduces reservoir quality and excludes exposed rocks as tight gas targets. The correlation of petrographic and petrophysical data show that expected facies-related reservoir quality trends were overprinted by high-temperature diagenesis. The present day secondary matrix porosity reflects the telogenetic dissolution of mesogenetic ankerite cements and unstable alumosilicates.Faults are associated with both sealed and partially sealed veins near the faults, indicating localized mass transport. Around W-E striking faults, dissolution is higher in leached sandstones with matrix porosities of up to 26.3% and matrix permeabilities of up to 105 mD. The dissolution of ankerite and lithic fragments around the faults indicates focused fluid flow. However, a telogenetic origin cannot be ruled out.The results of this work demonstrate the limits of outcrop analog studies with respect to actual subsurface reservoirs of the greater area. Whereas the investigated outcrop forms a suitable analog with respect to sedimentological, stratigraphic and structural inventory, actual reservoirs at depth generally lack telogenetic influences. These alter absolute reservoir quality values at the surface. However, the temperature overprint and associated diagenetic modification, which caused the unusually low permeability in the studied outcrop, may pose a reservoir risk for tight gas exploration as a consequence of locally higher overburden or similar structural positions.     

Diagenetic differences caused by the charging of natural gases with various compositions - a case study on the lower Zhuhai Formation clastic reservoirs in the WC-A sag,the Pearl River Mouth Basin

Only a limited number of comparative studies have explored the diagenetic differences of reservoirs caused by the charging of natural gases with different compositions during the migration and accumulation of oil and gas. In this study, we quantitatively assessed the diagenetic variations of the lower Zhuhai Formation reservoirs in the WC-A sag, the Pearl River Mouth Basin, as a result of natural gas charging with different compositions. The employed methods included electron microscopy, scanning electron microscopy, cathode luminescence, X-ray diffraction, chemical composition analysis of formation water, stable isotope analysis, and fluid inclusion determination. The results indicated that: (1) in the lower Zhuhai Formation reservoir that are near the large fractures, the late-charging of CO₂-rich thermal fluid promoted the dissolution of minerals, and changed the porosity, permeability, pH value of fluid, and the contents of ions such as K⁺, Na⁺, Mg²⁺ of the reservoirs. These changes, in turn, indirectly affected the content, form, and distribution of clay minerals in the reservoirs. In addition, the secondary enlargement of quartz was enhanced. (2) The charging of CO₂-rich thermal fluid caused strong dissolution and produced high contents of cements. The dissolution mainly occurred in a half open system with strong fluid activity. Consequently, the significantly decreasing of permeability was hindered and middle porosity–middle permeability reservoirs were generated. The reservoirs that are far from the large fractures, however, were mainly early charged by the hydrocarbon-rich fluid. The dissolution was weak and the generated cements were limited. In addition, the dissolution products could not be discharged in such closed diagenetic systems. As a result, the permeability of the reservoir was declined sharply and resulted in low porosity–low permeability reservoirs.     

Kilometer-scale fault-related thermal anomalies in tight gas sandstones

Upper Carboniferous sandstones make one of the most important tight gas reservoirs in Central Europe. This study integrates a variety of geothermometers (chlorite thermometry, fluid inclusion microthermometry and vitrinite reflection measurements) to characterize a thermal anomaly in a reservoir outcrop analog (Piesberg quarry, Lower Saxony Basin), which is assumed responsible for high temperatures of circa 300 °C, deteriorating reservoir quality entirely. The tight gas siliciclastics were overprinted with temperatures approximately 90–120 °C higher compared to outcropping rocks of a similar stratigraphic position some 15 km to the west. The local temperature increase can be explained by circulating hydrothermal fluids along the fault damage zone of a large NNW-SSE striking fault with a displacement of up to 600 m in the east of the quarry, laterally heating up the entire exposed tight gas sandstones. The km-scale lateral extent of this fault-bound thermal anomaly is evidenced by vitrinite reflectance measurements of meta-anthracite coals (VR_rot ∼ 4.66) and the temperature-related diagenetic overprint. Data suggest that this thermal event and the associated highest coalification was reached prior to peak subsidence during Late Jurassic rifting (162 Ma) based on K-Ar dating of the <2 μm fraction of the tight gas sandstones. Associated stable isotope data from fluid inclusions, hosted in a first fracture filling quartz generation (T ∼ 250 °C) close to lithostatic fluid pressure (P ∼ 1000 bars), together with authigenic chlorite growth in mineralized extension fractures, demonstrate that coalification was not subject to significant changes during ongoing burial. This is further evidenced by the biaxial reflectance anisotropy of meta-anthracite coals. A second event of quartz vein formation occurred at lower temperatures (T ∼ 180 °C) and lower (hydrostatic) pressure conditions (P ∼ 400 bars) and can be related to basin inversion. This second quartz generation might be associated with a second event of illite growth and K-Ar ages of 96.5–106.7 Ma derived from the <0.2 μm fraction of the tight gas sandstones.This study demonstrates the exploration risk of fault-bound thermal anomalies by deteriorating entirely the reservoir quality of tight gas sandstones with respect to porosity and permeability due to the cementation with temperature-related authigenic cements. It documents that peak temperatures are not necessarily associated with peak subsidence. Consequently, these phenomena need to be considered in petroleum system models to avoid, for example, overestimates of burial depth and reservoir quality.     

Influence of detrital composition on the diagenetic history of tight sandstones with implications for reservoir quality: Examples from the Permian Xiashihezi Formation and Carboniferous Taiyuan Formation,Daniudi gas field,Ordos Basin,China

Tight-gas reservoirs, characterized by low porosity and low permeability, are widely considered to be the product of post-depositional, diagenetic processes associated with progressive burial. This study utilizes a combination of thin section petrography, scanning electron microscopy, microprobe and back scatter electron analysis, stable isotope geochemistry and fluid inclusion analysis to compare the diagenetic history, including porosity formation, within sandstones of the second member of Carboniferous Taiyuan Formation (C₃t₂) and the first member of Permian Xiashihezi Formation (P₁x₁) in the Ordos Basin in central China.In the P₁x₁ member, relatively high abundances of metamorphic rock fragments coupled with a braided river and lacustrine delta environment of deposition, produced more smectite for transformation to illite (50–120 °C). This reaction was driven by dissolution of unstable minerals (K-feldspar and rock fragments) during the early to middle stages of mesodiagenesis and consumed all K-feldspar. Abundant intragranular porosity (average values of 2.8%) and microporosity in kaolinite (average values of 1.5%) formed at these burial depths with chlorite and calcite developed as by-products.In the C₃t₂ member, relatively low abundances of metamorphic rock fragments coupled with an incised valley-coastal plain environment of deposition resulted in less smectite for transformation to illite. High K⁺/H⁺ ratios in the early pore waters related to a marine sedimentary environment of deposition promoted this reaction. Under these conditions, K-feldspar was partially preserved. During the middle to late stages of mesodiagenesis, K-feldspar breakdown produced secondary intragranular (average values of 1.4%) and intergranular pores (average values of 1.2%). Release of K⁺ ions promoted illitization of kaolinite with quartz overgrowths and ferrous carbonates developed as by-products.This study has demonstrated that whereas both members are typical tight-gas sandstones, they are characterized by quite different diagenetic histories controlled by the primary detrital composition, especially during mesodiagenesis. Types of secondary porosity vary between the two members and developed at different stages of progressive burial. The content of unstable detrital components, notably feldspar, was the key factor that determined the abundance of secondary porosity.     

Diagenetic alterations and reservoir heterogeneity within the depositional facies: A case study from distributary-channel belt sandstone of Upper Triassic Yanchang Formation reservoirs (Ordos Basin,China)

Diagenesis is of decisive significance for the reservoir heterogeneity of most clastic reservoirs. Linking the distribution of diagenetic processes to the depositional facies and sequence stratigraphy has in recent years been discipline for predicting the distribution of diagenetic alterations and reservoir heterogeneity of clastic reservoirs. This study constructs a model of distribution of diagenetic alterations and reservoir heterogeneity within the depositional facies by linking diagenesis to lithofacies, sandstone architecture and porewater chemistry during burial. This would help to promote better understanding of the distribution of reservoir quality evolution and the intense heterogeneity of reservoirs. Based on an analogue of deltaic distributary channel belt sandstone in Upper Triassic Yanchang Formation, 83 sandstone plug samples were taken from 13 wells located along this channel belt. An integration of scanning electron microscopy, thin sections, electron microprobe analyses, rate-controlled porosimetry (RCP), gas-flow measurements of porosity and permeability, and nuclear magnetic resonance (NMR) experiments, together with published data, were analysed for the distribution, mineralogical and geochemical characteristics of detrital and diagenetic components and the distribution of reservoir quality within the distributary channel belt.Distribution of diagenetic alterations and reservoir heterogeneity within the distributary channel belt sandstones include (i) formation of high quality chlorite rims in the middle part of thick sandstones with coarser grain sizes and a lower content of ductile components resulted from the greater compaction resistance of these sandstones (providing larger pore spaces for chlorite growth), leading to formation of the intergranular pore – wide sheet-like throat and intergranular pore - intragranular pore – wide sheet-like throat (Φ>15%, k>1mD) in the middle part of thick sandstones; (ii) formation of thinner chlorite rims in the middle part of thinner sandstones is associated with the intergranular pore - intragranular pore – narrow sheet-like throat (9%<Φ<14%, 0.2mD<k<0.8mD); (iii) strong cementation by kaolinite in the more proximal sandstones of distributary channel owing to the strong feldspar dissolution by meteoric water, resulting in the intragranular pore - group of interstitial cement pores – narrow sheet-like throat/extremely narrow sheet-like throat (8%<Φ<11%, 0.1mD<k<0.3mD) due to the pore-filling kaolinite occluding porosity; (iv) formation of dense ferrocalcite zones (δ¹⁸O_VPDB = −23.4‰ to −16.6‰; δ¹³ C_VPDB = −4.0‰ to −2.3‰) favoured in the top and bottom of the channel sandstone which near the sandstone-mudstone bouding-surface, destroying pore space (Φ<8%, k<0.1mD); (v) strong compaction in sandstone of distributary channel edge laterally as a result of fine grain size and high content of ductile components in those sandstones, forming the group of interstitial cement pores – extremely narrow sheet-like throat with porosity values less than 8%.     

Controls on reservoir heterogeneity of tight sand oil reservoirs in Upper Triassic Yanchang Formation in Longdong Area,southwest Ordos Basin,China: Implications for reservoir quality prediction and oil accumulation

Compared to conventional reservoirs, pore structure and diagenetic alterations of unconventional tight sand oil reservoirs are highly heterogeneous. The Upper Triassic Yanchang Formation is a major tight-oil-bearing formation in the Ordos Basin, providing an opportunity to study the factors that control reservoir heterogeneity and the heterogeneity of oil accumulation in tight oil sandstones.The Chang 8 tight oil sandstone in the study area is comprised of fine-to medium-grained, moderately to well-sorted lithic arkose and feldspathic litharenite. The reservoir quality is extremely heterogeneous due to large heterogeneities in the depositional facies, pore structures and diagenetic alterations. Small throat size is believed to be responsible for the ultra-low permeability in tight oil reservoirs. Most reservoirs with good reservoir quality, larger pore-throat size, lower pore-throat radius ratio and well pore connectivity were deposited in high-energy environments, such as distributary channels and mouth bars. For a given depositional facies, reservoir quality varies with the bedding structures. Massive- or parallel-bedded sandstones are more favorable for the development of porosity and permeability sweet zones for oil charging and accumulation than cross-bedded sandstones.Authigenic chlorite rim cementation and dissolution of unstable detrital grains are two major diagenetic processes that preserve porosity and permeability sweet zones in oil-bearing intervals. Nevertheless, chlorite rims cannot effectively preserve porosity-permeability when the chlorite content is greater than a threshold value of 7%, and compaction played a minor role in porosity destruction in the situation. Intensive cementation of pore-lining chlorites significantly reduces reservoir permeability by obstructing the pore-throats and reducing their connectivity. Stratigraphically, sandstones within 1 m from adjacent sandstone-mudstone contacts are usually tightly cemented (carbonate cement > 10%) with low porosity and permeability (lower than 10% and 0.1 mD, respectively). The carbonate cement most likely originates from external sources, probably derived from the surrounding mudstone. Most late carbonate cements filled the previously dissolved intra-feldspar pores and the residual intergranular pores, and finally formed the tight reservoirs.The petrophysical properties significantly control the fluid flow capability and the oil charging/accumulation capability of the Chang 8 tight sandstones. Oil layers usually have oil saturation greater than 40%. A pore-throat radius of less than 0.4 μm is not effective for producible oil to flow, and the cut off of porosity and permeability for the net pay are 7% and 0.1 mD, respectively.     

Diagenesis and reservoir quality of sandstones with ancient “deep” incursion of meteoric freshwater——An example in the Nanpu Sag,Bohai Bay Basin,East China

An example of diagenesis and reservoir quality of buried sandstones with ancient incursion of meteoric freshwater is presented in this study. The interpretation is based on information including porosity and permeability, petrography, stable isotopic composition of authigenic minerals, homogenization temperatures (T_h) of aqueous fluid inclusions (AFIs), and pore water chemistry. These sandstones, closely beneath or far from the regional unconformity formed during the late Paleogene period, are located in the thick Shahejie Formation in the Gaoliu area of Nanpu Sag, Bohai Bay Basin, East China. Early-diagenetic calcite cements were leached to form intergranular secondary pores without precipitation of late-diagenetic calcite cements in most sandstones. Feldspars were leached to form abundant intragranular secondary pores, but with small amounts of concomitant secondary minerals including authigenic quartz and kaolinite. The mass imbalance between the amount of leached minerals and associated secondary minerals suggests that mineral leaching reactions occurred most likely in an open geochemical system, and diagenetic petrography textures suggest that advective flow dominated the transfer of solutes from leached feldspars and calcites. Low salinity and ion concentrations of present pore waters, and extensive water rock interactions suggest significant incursion of meteoric freshwater flux in the sandstones. Distances of the sandstones to the regional unconformity can reach up to 1800 m, while with significant uplift in the Gaoliu area, the burial depth of such sandstones (below sea level) can be less than 800–1000 m during the uplift and initial reburial stage. Significant uplift during the Oligocene period provided substantial hydraulic drive and widely developed faults served as favorable conduits for downward penetration of meteoric freshwater from the earth's surface (unconformity) to these sandstone beds. Extensive feldspar leaching has been occurring since the uplift period. Coupled high T_h (95∼115 °C) of AFI and low δ¹⁸O_(SMOW) values (+17∼+20‰) within the quartz overgrowths show that quartz cementation occurred in the presence of diagenetic modified meteoric freshwater with δ¹⁸O_(SMOW) values of −7∼−2‰, indicating that authigenic quartz only have been formed during the late reburial stage when meteoric fresh water penetration slowed down. Secondary pores in thin sections and tested porosity suggest that meteoric freshwater leaching of feldspars and calcite minerals generated approximately 7–10% enhanced secondary porosity in these sandstones. Meteoric freshwater leaching reactions cannot be ignored in similar sandstones that located deep beneath the unconformity, with great uplift moving these sandstones above or close to sea level and with faults connecting the earth's surface with the sandstone beds.     

Quartz cement and its origin in tight sandstone reservoirs of the Cretaceous Quantou formation in the southern Songliao basin,China

The tight sandstones of the Cretaceous Quantou formation are the main exploration target for hydrocarbons in the southern Songliao basin. Authigenic quartz is a significant cementing material in these sandstones, significantly reducing porosity and permeability. For efficient predicting and extrapolating the petrophysical properties within these tight sandstones, the quartz cement and its origin need to be better understood. The tight sandstones have been examined by a variety of methods. The sandstones are mostly lithic arkoses and feldspathic litharenites, compositionally immature with an average framework composition of Q₄₃F₂₆L₃₁, which are characterized by abundant volcanic rock fragments. Mixed-layer illite/smectite (I/S) ordered interstratified with R = 1 and R = 3 is the dominating clay mineral in the studied sandstone reservoirs. Two different types of quartz cementation modes, namely quartz grain overgrowth and pore-filling authigenic quartz, have been identified through petrographic observations, CL and SEM analysis. Homogenization temperatures of the aqueous fluid inclusions indicate that both quartz overgrowths and pore-filling authigenic quartz formed with a continuous process from about 70 °C to 130 °C. Sources for quartz cement produced are the conversion of volcanic fragments, smectite to illite reaction and pressure solution at micro stylolites. Potassium for the illitization of smectite has been sourced from K-feldspar dissolution and albitization. Silica sourced from K-feldspars dissolution and kaolinite to illite conversion is probably only minor amount and volumetrically insignificant. The internal supplied silica precipitate within a closed system where the transport mechanism is diffusion. The quartz cementation can destroy both porosity and permeability, but strengthen the rock framework and increase the rock brittleness effectively at the same time.     

Diagenetic history of tight sandstones and gas entrapment in the Yulin Gas Field in the central area of the Ordos Basin,China

The Ordos Basin is a large cratonic basin with an area of 250,000 km² in central China. Upper Paleozoic coals and shales serve as gas source rocks with peak generation and migration at the end of the early Cretaceous. Recent exploration has verified the huge gas potential in the “basin-centered gas accumulation system” (BCGAS). However, the mechanism for the gas accumulation is controversial. With an integrated approach of thin-section petrography, ultra-violet fluorescence microscopy, fluid inclusion microthermometry, Raman microspectrometry, scanning electron microscopy, and X-ray diffractometry, we identified diagenetic trapping and evaluated the diagenetic history of sandstone reservoirs in the Yulin Gas Field in the central area, where structural, stratigraphic and/or sedimentary lithologic traps have not been found. It was revealed that three phases of diagenesis and hydrocarbon charging occurred, respectively, in the late Triassic, late Jurassic and at the end of the early Cretaceous. In the first two phases, acidic water entered the reservoir and caused dissolution and cementation, resulting in porosity increase. However, further subsidence and diagenesis, including compaction and cementation, markedly reduced the pore space. At the end of the early Cretaceous, the bulk of the gas migrated into the tight reservoirs, and the BCGAS trap was formed. In the updip portion of this system, cementation continued to occur due to low gas saturation and has provided effective seals to retain gas for a longer period of time than water block in the BCGAS. The mechanism for the gas entrapment was changed from water block by capillary pressure in the BCGAS to diagenetic sealing. The diagenetic seals in the updip portion of the sand body were formed after gas charging, which indicates that there is a large hydrocarbon exploration potential at the basin-centered area.     

Impact of diagenesis on reservoir quality and heterogeneity of the Upper Triassic Chang 8 tight oil sandstones in the Zhenjing area,Ordos Basin,China

Reservoir quality and heterogeneity are critical risk factors in tight oil exploration. The integrated, analysis of the petrographic characteristics and the types and distribution of diagenetic alterations in the Chang 8 sandstones from the Zhenjing area using core, log, thin-section, SEM, petrophysical and stable isotopic data provides insight into the factors responsible for variations in porosity and permeability in tight sandstones. The results indicate that the Chang 8 sandstones mainly from subaqueous distributary channel facies are mostly moderately well to well sorted fine-grained feldspathic litharenites and lithic arkose. The sandstones have ultra-low permeabilities that are commonly less than 1 mD, a wide range of porosities from 0.3 to 18.1%, and two distinct porosity-permeability trends with a boundary of approximately 10% porosity. These petrophysical features are closely related to the types and distribution of the diagenetic alterations. Compaction is a regional porosity-reducing process that was responsible for a loss of more than half of the original porosity in nearly all of the samples. The wide range of porosity is attributed to variations in calcite cementation and chlorite coatings. The relatively high-porosity reservoirs formed due to preservation of the primary intergranular pores by chlorite coatings rather than burial dissolution; however, the chlorites also obstruct pore throats, which lead to the development of reservoirs with high porosity but low permeability. In contrast, calcite cementation is the dominant factor in the formation of low-porosity, ultra-low-permeability reservoirs by filling both the primary pores and the pore throats in the sandstones. The eogenetic calcites are commonly concentrated in tightly cemented concretions or layers adjacent to sandstone-mudstone contacts, while the mesogenetic calcites were deposited in all of the intervals and led to further heterogeneity. This study can be used as an analogue to understand the variations in the pathways of diagenetic evolution and their impacts on the reservoir quality and heterogeneity of sandstones and is useful for predicting the distribution of potential high-quality reservoirs in similar geological settings.     

Diagenesis and origin of calcite cement in the Flemish Pass Basin sandstone reservoir (Upper Jurassic): Implications for porosity development

The Flemish Pass Basin is a deep-water basin located offshore on the continental passive margin of the Grand Banks, eastern Newfoundland, which is currently a hydrocarbon exploration target. The current study investigates the petrographic characteristics and origin of carbonate cements in the Ti-3 Member, a primary clastic reservoir interval of the Bodhrán Formation (Upper Jurassic) in the Flemish Pass Basin.The Ti-3 sandstones with average Q_86.0F_3.1R_10.9 contain various diagenetic minerals, including calcite, pyrite, quartz overgrowth, dolomite and siderite. Based on the volume of calcite cement, the investigated sandstones can be classified into (1) calcite-cemented intervals (>20% calcite), and (2) poorly calcite-cemented intervals (porous). Petrographic analysis shows that the dominant cement is intergranular poikilotopic (300–500 μm) calcite, which stared to form extensively at early diagenesis. The precipitation of calcite occured after feldspar leaching and was followed by corrosion of quartz grains. Intergranular calcite cement hosts all-liquid inclusions mainly in the crystal core, but rare primary two-phase (liquid and vapor) fluid inclusions in the rims ((with mean homogenization temperature (T_h) of 70.2 ± 4.9 °C and salinity estimates of 8.8 ± 1.2 eq. wt.% NaCl). The mean δ¹⁸O and δ¹³C isotopic compositions of the intergranular calcite are −8.3 ± 1.2‰, VPDB and −3.0 ± 1.3‰, VPDB, respectively; whereas, fracture-filling calcite has more depleted δ¹⁸O but similar δ¹³C values. The shale normalized rare earth element (REE_SN) patterns of calcite are generally parallel and exhibit slightly negative Ce anomalies and positive Eu anomalies. Fluid-inclusion gas ratios (CO₂/CH₄ and N₂/Ar) of calcite cement further confirms that diagenetic fluids originated from modified seawater. Combined evidence from petrographic, microthermometric and geochemical analyses suggest that (1) the intergranular calcite cement precipitated from diagenetic fluids of mixed marine and meteoric (riverine) waters in suboxic conditions; (2)the cement was sourced from the oxidation of organic matters and the dissolution of biogenic marine carbonates within sandstone beds or adjacent silty mudstones; and (3) the late phases of the intergranular and fracture-filling calcite cements were deposited from hot circulated basinal fluids.Calcite cementation acts as a main controlling factor on the reservoir quality in the Flemish Pass reservoir sandstones. Over 75% of initial porosity was lost due to the early calcite cementation. The development of secondary porosity (mostly enlarged, moldic pores) and throats by later calcite dissolution due to maturation of organic matters (e.g., hydrocarbon and coals), was the key process in improving the reservoir quality.     

New insight into the microtexture of chalks from NMR analysis

An integrated petrographical and petrophysical study was carried out on a set of 35 outcrop chalk samples, covering a wide range of lithologies and textures. In this study various chalk rock-types have been characterized, in terms of microtextures and porous network, by integrating both geological, sediment-petrological and petrophysical data, including porosity, permeability, low-field NMR (Nuclear Magnetic Resonance), MICP and specific surface area (BET) measurements. The data allow an in depth understanding of the NMR signal of chalks, with a focus on tight chalks, including all low reservoir quality chalks independently of their sedimentological and/or diagenetic history. The study aims to develop an NMR-based approach to characterize a broad range of chalk samples. The provided laboratory low-field NMR chalk classification can be used as a guide to interpret NMR logging data.Based on the petrographical and petrophysical analysis, 6 groups of samples were identified, each of them characterized by a unique NMR signature: (1) micritic chalks, (2) grainy chalks, (3) cemented chalks, (4) marl-seam chalks, (5) argillaceous chalks and (6) silicified chalk. NMR T₂ distributions were linked to pore body size and T₂ logarithmic (T_2lm) was calculated. It is apparent that tight chalks, whether their characteristics are sedimentological or diagenetic, yield smaller pore body sizes (T_2lm < 20 ms), as well as narrower pore throats (average radius < 150 nm) and lower permeability values (typically below 0.2 mD). Grainy chalks possess T₂ distributions reflecting larger pore sizes (T_2lm > 60 ms) and pore throats (average radius > 290 nm) and higher permeabilities (up to 13 mD). The marl-seam chalk samples yield bimodal T₂ distributions, with a first peak related to the micritic matrix pores and a second peak related to intraparticle pores within fossils. For all samples, permeability was inferred from NMR spectra using SDR (Schlumberger Doll Research) model.     

The role of diagenesis and depositional facies on pore system evolution in a Triassic outcrop analogue (SE Spain)

This study aims at unravelling the diagenetic history and its effect on the pore system evolution of the Triassic redbeds exposed in SE Spain (TIBEM¹), an outcrop analogue of the TAGI (Trias Argilo-Gréseux Inférieur) reservoir (Berkine-Ghadames Basin, Algeria). Similar climatic, base level and tectonic conditions of aforementioned alluvial formations developed analogue fluvial facies stacking patterns. Furthermore, interplay of similar detrital composition and depositional facies in both formations resulted in analogue early diagenetic features. Petrographic observations indicate lithic subarkosic (floodplain facies) and subarkosic (braidplain facies) compositions which are considered suitable frameworks for potential reservoir rocks. Primary porosity is mainly reduced during early diagenesis through moderate mechanical compaction and formation of K-feldspar overgrowth, gypsum, dolomite and phyllosilicate cements. Early mesodiagenesis is testified by low chemical compaction and quartz cementation. Telodiagenetic calcite filling fractures and K-feldspar dissolution determined the final configuration of analysed sandstones. Mercury injection-capillary pressure technique reveals overbank deposits in the floodplain as the least suitable potential reservoirs because of their lowest open porosity (OP < 16%), permeability (k < 5 mD) and small dimensions. On the other hand, braidplain deposits show the highest values of such properties (OP up to 31.6% and k > 95 mD) and greater thickness and lateral continuity, so being considered the best potential reservoir. The accurate estimation of TIBEM microscale attributes can provide important input for appraisal and enhanced oil recovery performance in TAGI and in others reservoirs consisting on similar fluvial sandy facies.     

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.     

Permeability in Rotliegend gas sandstones to gas and brine as predicted from NMR,mercury injection and image analysis

Permeability characterisation of low permeability, clay-rich gas sandstones is part of production forecasting and reservoir management. The physically based Kozeny (1927) equation linking permeability with porosity and pore size is derived for a porous medium with a homogeneous pore size, whereas the pore sizes in tight sandstones can range from nm to μm. Nuclear magnetic resonance (NMR) transverse relaxation was used to estimate a pore size distribution for 63 samples of Rotliegend sandstone. The surface relaxation parameter required to relate NMR to pore size is estimated by combination of NMR and mercury injection data. To estimate which pores control permeability to gas, gas permeability was calculated for each pore size increment by using the Kozeny equation. Permeability to brine is modelled by assuming a bound water layer on the mineral pore interface. The measured brine permeabilities are lower than predicted based on bound water alone for these illite rich samples. Based on the fibrous textures of illite as visible in electron microscopy we speculate that these may contribute to a lower brine permeability.     

How does the pore-throat size control the reservoir quality and oiliness of tight sandstones? The case of the Lower Cretaceous Quantou Formation in the southern Songliao Basin,China

Pore-throat size is a very crucial factor controlling the reservoir quality and oiliness of tight sandstones, which primarily affects rock-properties such as permeability and drainage capillary pressure. However, the wide range of size makes it difficult to understand their distribution characteristics as well as the specific controls on reservoir quality and oiliness. In order to better understand about pore-throat size distribution, petrographic, scanning electron microscopy (SEM), pressure-controlled mercury injection (PMI), rate-controlled mercury injection (RMI), quantitative grain fluorescence (QGF) and environmental scanning electron microscopy (ESEM) investigations under laboratory pressure conditions were performed on a suite of tight reservoir from the fourth member of the Lower Cretaceous Quantou Formation (K₁q₄) in the southern Songliao Basin, China. The sandstones in this study showed different types of pore structures: intergranular pores, dissolution pores, pores within clay aggregates and even some pores related to micro fractures. The pore-throat sizes vary from nano- to micro-scale. The PMI technique views the pore-throat size ranging from 0.001 μm to 63 μm and revealed that the pore-throats with radius larger than 1.0 μm are rare and the pore-throat size distribution curves show evident fluctuations. RMI measurements indicated that the pore size distribution characteristics of the samples with different porosity and permeability values look similar. The throat size and pore throat radius ratio distribution curves had however significant differences. The overall pore-throat size distribution of the K₁q₄ tight sandstones was obtained with the combination of the PMI and RMI methods. The permeability is mainly contributed by a small part of larger pore-throats (less than 30%) and the ratio of the smaller pore-throats in the samples increases with decreasing permeability. Although smaller pore-throats have negligible contribution on reservoir flow potential, they are very significant for the reservoir storage capacity. The pore-throats with average radius larger than 1.0 μm mainly exist in reservoirs with permeability higher than 0.1mD. When the permeability is lower than 0.1mD, the sandstones are mainly dominated by pore-throats with average radius from 0.1 μm to 1.0 μm. The ratio of different sized pore-throats controls the permeability of the tight sandstone reservoirs in different ways. We suggest that splitting or organizing key parameters defining permeability systematically into different classes or functions can enhance the ability of formulating predictive models about permeability in tight sandstone reservoirs. The PMI combined with QGF analyses indicate that oil emplacement mainly occurred in the pore-throats with radius larger than about 0.25–0.3 μm. This result is supported by the remnant oil micro-occurrence evidence observed by SEM and ESEM.     

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.