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.     

Composition, porosity, and reservoir potential of the Middle Jurassic Kashafrud Formation, northeast Iran

In the Kopet-Dagh Basin of Iran, deep-sea sandstones and shales of the Middle Jurassic Kashafrud Formation are disconformably overlain by hydrocarbon-bearing carbonates of Upper Jurassic and Cretaceous age. To explore the reservoir potential of the sandstones, we studied their burial history using more than 500 thin sections, supplemented by heavy mineral analysis, microprobe analysis, porosity and permeability determination, and vitrinite reflectance.The sandstones are arkosic and lithic arenites, rich in sedimentary and volcanic rock fragments. Quartz overgrowths and pore-filling carbonate cements (calcite, dolomite, siderite and ankerite) occluded most of the porosity during early to deep burial, assisted by early compaction that improved packing and fractured quartz grains. Iron oxides are prominent as alteration products of framework grains, probably reflecting source-area weathering prior to deposition, and locally as pore fills. Minor cements include pore-filling clays, pyrite, authigenic albite and K-feldspar, and barite. Existing porosity is secondary, resulting largely from dissolution of feldspars, micas, and rock fragments, with some fracture porosity. Porosity and permeability of six samples averages 3.2% and 0.0023 mD, respectively, and 150 thin-section point counts averaged 2.7% porosity. Reflectance of vitrinite in eight sandstone samples yielded values of 0.64-0.83%, in the early mature to mature stage of hydrocarbon generation, within the oil window.Kashafrud Formation petrographic trends were compared with trends from first-cycle basins elsewhere in the world. Inferred burial conditions accord with the maturation data, suggesting only a moderate thermal regime during burial. Some fractures, iron oxide cements, and dissolution may reflect Cenozoic tectonism and uplift that created the Kopet-Dagh Mountains. The low porosity and permeability levels of Kashafrud Formation sandstones suggest only a modest reservoir potential. For such tight sandstones, fractures may enhance the reservoir potential.     

Diagenesis and reservoir properties of Middle Jurassic sandstones,Traill Ø, East Greenland: The influence of magmatism and faulting

The c. 500 m thick Middle Jurassic sandstones of the fluvial Bristol Elv and marine Pelion Formations of the East Greenland Basin are evaluated here in order to improve the understanding of the processes that influenced the diagenetic evolution. The study may help to predict the reservoir properties of sandstones affected by magmatism and faulting, both in general and specifically in undrilled areas on- and offshore East Greenland and, in the Vøring Basin on the Mid-Norwegian shelf. The study shows a variety of authigenic mineral phases dominated by quartz cement, carbonate cement, illite and iron-oxide. One of the clear differences between the two formations is the presence of early carbonate-cemented horizons in the marine sandstones; these horizons are inferred to reflect a primary concentration of biogenic clasts and fossil shells. Intense quartz cementation occurs primarily in the fluvial sandstones but the marine sandstones are also highly quartz-cemented. Two episodes of burial and uplift are recorded in the diagenetic sequence and widespread grain-crushing in coarse-grained intervals is believed to result from overpressure and subsequent compaction due to sudden pressure release along major faults. Maximum burial depths may only have been around 2000–2500 m. Cathodoluminescence analyses show that grain crushing was followed by intense quartz cementation. The quartz cement is to a great deal believed to have formed due to increased surface area from crushing of detrital quartz grains, creating fresh nucleation sites for the quartz. Cathodoluminescence investigations also show that only minor pressure dissolution has taken place between detrital quartz grains and that the ubiquitous quartz cementation displays several growth zones, and was thus in part the result of the introduction of silica-rich extra-formational fluids related to the flow of hot fluids along reactivated faults and increased heat flow and temperature due to magmatism. This interpretation is supported by fluid inclusion homogenization temperatures between 117 and 158 °C in quartz cements. In one of the two study areas, the development of macroscopic stylolites has significantly enhanced quartz cementation, probably in connection with thermal convection flow. As a result of the magmatic and fault-related quartz cementation and illitization, the reservoir quality of the sandstone formations deteriorated and changed drastically.     

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.     

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.     

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.     

An interdisciplinary approach to reservoir characterisation; an example from the early to middle Eocene Kaimiro Formation,Taranaki Basin,New Zealand

The Kaimiro Formation is an early to middle Eocene, NE-SW trending reservoir fairway in Taranaki Basin, and comprises a range of coastal plain through to shallow marine facies. A time of regional transgression is observed across the Paleocene–Eocene transition, which is linked to a general global warming trend and to regional thermal relaxation-related subsidence in New Zealand. The earliest Eocene transgressive deposits pass upwards into a series of cyclically stacked packages, interpreted as 3rd and 4th order sequences. Maximum regression occurred within the early Eocene and was followed by punctuated retrogradational stacking patterns associated with shoreline retreat and subsequent regional transgression in the middle Eocene.The Kaimiro Formation is considered a good reservoir target along most of the reservoir fairway, which can largely be attributed to a consistently quartz-rich, lithic-poor composition and reasonably coarse sand grain size. Correlations demonstrate that within the early Eocene the main reservoir facies are channel-fill sandstones overlying candidate sequence boundaries in paleoenvironmentally landward (proximal) settings, and upper shoreface/shoreline sandstones in relatively basinward (distal) settings. Middle Eocene reservoir facies are not represented in distal wells due to overall transgression at this time, yet they form a significant target in more proximal well locations, particularly on the Taranaki Peninsula.Depositional facies is one of the principal controls on sandstone reservoir quality. However, while reservoir facies have been proven along the length of the reservoir fairway, it is evident that diagenesis has significantly impacted sandstone quality. Relatively poor reservoir properties are predicted for deeply buried parts of the basin (maximum burial >4.5 km) due to severe compaction and relatively abundant authigenic quartz and illite. In contrast, good reservoir properties are locally represented in reservoir facies where present-day burial depths are <4 km due to less severe compaction, cementation and illitisation. Within these beds (<4 km) the presence of locally occurring authigenic grain-coating chlorite (shallow marine facies) and/or well-developed secondary porosity are both favourable to reservoir quality, while pervasive kaolinite and/or carbonate are both detrimental to reservoir quality.These results illustrate how an interdisciplinary approach to regional reservoir characterisation are used to help reduce risk during prospect evaluation. Assessment of both reservoir distribution and quality is necessary and can be undertaken through integrated studies of facies, sequence stratigraphy, burial modelling and petrography.     

Impact of regional variation in detrital mineral composition on reservoir quality in deep to ultradeep lower Miocene sandstones,western Gulf of Mexico

Future exploration in lower Miocene sandstones in the Gulf of Mexico will focus increasingly at depths greater than 4.5 km, and reservoir quality will be a critical risk factor in these deep to ultradeep reservoirs. The goal of this study was to understand the variation in reservoir quality of lower Miocene sandstones across the western Gulf of Mexico. To do this, we examined regional variation in detrital mineral composition, diagenesis, and reservoir quality in five areas: (1) Louisiana, (2) upper Texas coast, (3) lower Texas coast, (4) Burgos Basin, Mexico, and (5) Veracruz Basin, Mexico using petrographic and petrophysical data from depths of 0.9–7.2 km.There are strong variations in mineralogical composition within the study area. Lower Miocene sandstones from offshore Louisiana have an average composition of quartz = 86%, feldspar = 12%, and rock fragments = 2% (Q₈₆F₁₂R₂). Feldspar and rock-fragment content increase southward as source areas shifted to include volcanic and carbonate rocks. Composition of samples from offshore Texas ranges from Q₆₇F₂₄R₉ in the upper Texas coast to Q₅₈F₂₄R₁₉ in the lower Texas coast. Lower Miocene sandstones from the onshore Burgos Basin, northern Mexico, have an average composition of Q₅₄F₂₂R₂₃, whereas sandstones from the Veracruz Basin, southern Mexico, contain the highest proportion of rock fragments, Q₃₃F₁₂R₅₅. Main diagenetic events in quartz-rich lower Miocene sandstones in Louisiana were mechanical compaction and precipitation of quartz cement. Compactional porosity loss increased to the south with increasing rock-fragment content. Calcite is the most abundant cement in the south and is strongly related to reservoir quality loss.At moderate burial depths, the best reservoir quality occurs in quartz-rich sandstones in Louisiana and decreases with increasing lithic content in Texas and Mexico. Porosity is higher in Louisiana and upper Texas than in lower Texas and Mexico at all depths and temperatures, but at depths >5 km and temperatures >175 °C, porosity differences are lessened. The lower Miocene sandstone trend in the western Gulf of Mexico from Louisiana to Mexico is an example of the importance of variation in detrital mineralogy as a control on diagenesis and reservoir quality.     

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.     

Depositional and diagenetic controls on deeply-buried Eocene sublacustrine fan reservoirs in the Dongying Depression,Bohai Bay Basin,China

This paper investigates the reservoir potential of deeply-buried Eocene sublacustrine fan sandstones in the Bohai Bay Basin, China by evaluating the link between depositional lithofacies that controlled primary sediment compositions, and diagenetic processes that involved dissolution, precipitation and transformation of minerals. This petrographic, mineralogical, and geochemical study recognizes a complex diagenetic history which reflects both the depositional and burial history of the sandstones. Eogenetic alterations of the sandstones include: 1) mechanical compaction; and 2) partial to extensive non-ferroan carbonate and gypsum cementation. Typical mesogenetic alterations include: (1) dissolution of feldspar, non-ferroan carbonate cements, gypsum and anhydrite; (2) precipitation of quartz, kaolinite and ferroan carbonate cements; (3) transformation of smectite and kaolinite to illite and conversion of gypsum to anhydrite. This study demonstrates that: 1) depositional lithofacies critically influenced diagenesis, which resulted in good reservoir quality of the better-sorted, middle-fan, but poor reservoir quality in the inner- and outer-fan lithofacies; 2) formation of secondary porosity was spatially associated with other mineral reactions that caused precipitation of cements within sandstone reservoirs and did not greatly enhance reservoir quality; and 3) oil emplacement during early mesodiagenesis (temperatures > 70 °C) protected reservoirs from cementation and compaction.     

Reservoir quality and rock properties modeling – Triassic and Jurassic sandstones,greater Shearwater area,UK Central North Sea

The complex burial and diagenetic histories of the Jurassic Fulmar and Triassic Skagerrak sandstones in the UK Central North Sea present significant challenges with regard to reservoir quality and rock property prediction. Commercial reservoir quality is retained despite deep burial and associated high temperatures and pressures. Shallow marine Fulmar sands are normally compacted (mean IGV = 26 ± 3%) yet have porosities of 21–33%. Porosity was preserved through inhibition of quartz cementation by clay and microquartz coatings, and enhanced by dissolution of framework grains (∼5%). Skagerrak fluvial sands are more compacted (mean IGV = 23 ± 2%), exhibit minor feldspar dissolution (<1%), and have porosities of 16–27%. Quartz cement averages only 2 ± 1.5% due to robust chlorite coats that cover 80% (±13%) of quartz surfaces.We modeled reservoir quality evolution using the forward diagenetic model Touchstone, which simulates porosity loss due to compaction and quartz cementation. Quantitative petrographic analyses and burial history data were used to calibrate Touchstone model parameters. The results were applied to deeper prospects for pre-drill prediction of porosity and permeability. In parallel, petrophysical data were used to characterize the elastic properties of the sandstones to provide a basis for quantitative seismic forward modeling. Experimental data and core-calibrated petrophysical results, reflecting variable in situ fluids and saturations, were used to build an elastic properties model. The model is robust and was used to generate fluid-filled sandstone properties, incorporating Touchstone results, for prospect-specific seismic attribute modeling. Well results from exploration wells are in good agreement with pre-drill Touchstone and elastic properties model predictions.     

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.     

Petroleum source rock potential of the Silurian Dadaş shales in the Hazro and Korudağ regions of Southeast Anatolia,Turkey

Shales of the Silurian Dadaş Formation exposed in the southeast Anatolia were investigated by organic geochemical methods. The TOC contents range from 0.24 to 1.48 wt% for the Hazro samples and 0.19 to 3.58 wt% for the Korudağ samples. Tmax values between 438 and 440 °C in the Hazro samples indicate thermal maturity; Tmax values ranging from 456 to 541 °C in the Korudağ samples indicate late to over-maturity. Based on the calculated vitrinite reflectance and measured vitrinite equivalent reflectance values, the Korudağ samples have a maximum of 1.91%R_(g-v), in the gas generation window, while a maximum value of 0.79%R_(amor-v) of one sample from the Hazro section is in the oil generation window. Illite crystallinity (IC) values of all samples are consistent with maturity results.Pr/Ph ratios ranging from 1.32 to 2.28 and C₂₉/C₃₀ hopane ratios > 1.0 indicate an anoxic to sub-oxic marine-carbonate depositional environment.The Hazro shales do not have any shale oil or shale gas potential because of their low oil saturation index values and early to moderate thermal maturation. At first glance, the Korudağ shales can be considered a shale gas formation because of their organic richness, thickness and thermal over-maturity. However, the low silica content and brittle index values of these shales are preventing their suitability as shale gas resource systems.     

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.     

Reservoir characterization of Scollard-age fluvial sandstones,Alberta foredeep

A detailed laboratory study of 53 sandstone samples from 23 outcrops and 156 conventional core samples from the Maastrichtian-Paleocene Scollard-age fluvial strata in the Western Canada foredeep was undertaken to investigate the reservoir characteristics and to determine the effect of diagenesis on reservoir quality. The sandstones are predominantly litharenites and sublitharenites, which accumulated in a variety of fluvial environments. The porosity of the sandstones is both syn-depositional and diagenetic in origin. Laboratory analyses indicate that porosity in sandstones from outcrop samples with less than 5% calcite cement averages 14%, with a mean permeability of 16 mD. In contrast, sandstones with greater than 5% calcite cement average 7.9% porosity, with a mean permeability of 6.17 mD. The core porosity averages 17% with 41 mD permeability. Cementation coupled with compaction had an important effect in the destruction of porosity after sedimentation and burial. The reservoir quality of sandstones is also severely reduced where the pore-lining clays are abundant (>15%). The potential of a sandstone to serve as a reservoir for producible hydrocarbons is strongly related to the sandstone’s diagenetic history. Three diagenetic stages are identified: eodiagenesis before effective burial, mesodiagenesis during burial, and telodiagenesis during exposure after burial. Eodiagenesis resulted in mechanical compaction, calcite cementation, kaolinite and smectite formation, and dissolution of chemically unstable grains. Mesodiagenesis resulted in chemical compaction, precipitation of calcite cement, quartz overgrowths, and the formation of authigenic clays such as chlorite, dickite, and illite. Finally, telodiagenesis seems to have had less effect on reservoir properties, even though it resulted in the precipitation of some kaolinite and the partial dissolution of feldspar.     

Quantitative impact of diagenesis on reservoir quality of the Triassic Chang 6 tight oil sandstones,Zhenjing area,Ordos Basin,China

The Upper Triassic Chang 6 sandstone, an important exploration target in the Ordos Basin, is a typical tight oil reservoir. Reservoir quality is a critical factor for tight oil exploration. Based on thin sections, scanning electron microscopy (SEM), X-ray diffraction (XRD), stable isotopes, and fluid inclusions, the diagenetic processes and their impact on the reservoir quality of the Chang 6 sandstones in the Zhenjing area were quantitatively analysed. The initial porosity of the Chang 6 sandstones is 39.2%, as calculated from point counting and grain size analysis. Mechanical and chemical compaction are the dominant processes for the destruction of pore spaces, leading to a porosity reduction of 14.2%–20.2% during progressive burial. The porosity continually decreased from 4.3% to 12.4% due to carbonate cementation, quartz overgrowth and clay mineral precipitation. Diagenetic processes were influenced by grain size, sorting and mineral compositions. Evaluation of petrographic observations indicates that different extents of compaction and calcite cementation are responsible for the formation of high-porosity and low-porosity reservoirs. Secondary porosity formed due to the burial dissolution of feldspar, rock fragments and laumontite in the Chang 6 sandstones. However, in a relatively closed geochemical system, products of dissolution cannot be transported away over a long distance. As a result, they precipitated in nearby pores and pore throats. In addition, quantitative calculations showed that the dissolution and associated precipitation of products of dissolution were nearly balanced. Consequently, the total porosity of the Chang 6 sandstones increased slightly due to burial dissolution, but the permeability decreased significantly because of the occlusion of pore throats by the dissolution-associated precipitation of authigenic minerals. Therefore, the limited increase in net-porosity from dissolution, combined with intense compaction and cementation, account for the low permeability and strong heterogeneity in the Chang 6 sandstones in the Zhenjing area.     

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.     

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.