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

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

Khasib and Tannuma oil sources, East Baghdad oil field, Iraq

This work presents new insights of the generation, quality and migration pathways of the hydrocarbons in the East Baghdad Oil Field.The Khasib and Tannuma formations in East Baghdad are considered as oil reservoirs according to their high porosity (15-23%) and permeability (20-45 mD) in carbonate rocks. The hydrocarbons are trapped by structural anticline closure trending NW-SE. Gas chromatography analysis on these oil reservoirshave shown biomarkers of abundant ranges of n-alkanes of less than C22 (C17-C21) with C19 and C18 peaks. This suggests mainly liquid oil constituents of paraffinic hydrocarbons from marine algal source of restricted palaeoenvironments in the reservoir. The low non aromatic C15 + peaks are indicative for slight degradation and water washing. Oil biomarkers of Pr./Ph. = 0.85, C31/C30 < 1.0, location in triangle of C27-C29 sterane, C28/C29 of 0.6 sterane, Oleanane of 0.01 and CPI = 1.0, indicate an anoxic marine environment with carbonate deposits of Upper Jurassic to Early Cretaceous age. Four Miospores, seven Dinoflagellates and one Tasmanite species confirm affinity to the upper most Jurassic to Lower Cretaceous Chia Gara and Ratawi Formations.The recorded palynomorphs from the Khasib and Tannuma Formations are of light brown color of TAI = 2.8-3.0 and comparable to the mature palynomorphs that belong to the Chia Gara and the Lower part of Ratawi Formations.The Chia Gara Formation generated oil during Upper Cretaceous to Early Palaeogene and accumulated in structural traps of Cretaceous age, such as the Khasib and Tannuma reservoirs. The Chia Gara Formation generated and expelled high quantities of oil hydrocarbons according to their TOC wt% of 0.5-8.5 with S2 = 2.5-18.5 mg Hc/g Rock, high hydrogen index of the range 150-450 mg Hc/g Rock, good petroleum potential of 4.5-23.5 mg Hc/g Rock, mature (TAI = 2.8-3.0 and T_max = 428-443C), kerogen type II and palynofacies parameters of up to 100% AOM (Amorphous Organic Matters). This includes algae deposits in a dysoxic-anoxic to suboxic-anoxic environment.Alternative plays are discussed according to the migration pathways.     

Reservoir prediction of deep-water turbidite sandstones with seismic lithofacies control —A case study in the C block of lower Congo basin

Currently, conventional forecasting methods of well-to-seismic integration are unable to identify turbidite channel sandstones due to scarcity of well data in deepwater areas, small geophysical differences between sandstones and mudstones of turbidite channels and strong sandstones heterogeneity. The reservoir prediction of deep-water turbidite channels is still a difficult issue in deep-water research. On the basis of previous studies, we propose a new technology named “reservoir prediction of deep-water turbidite sandstones with seismic lithofacies control” in view of the characteristics of deep-water turbidite sandstones. This new technology improves the reservoir prediction of complex sedimentary systems after classifying seismic lithofacies and connecting lithofacies with rock-physics. Furthermore, it can accomplish the genetic classification statistics of rock-physics, improve conversion accuracy of seismic elastic parameters/reservoir parameters and achieve the quantitative reservoir prediction under the double control of seismic geomorphology and seismic lithofacies. The C block of Lower Congo Basin is characterized by few well data, complex lithology but high resolution-seismic. We use the technology to predict the reservoirs of this area and have achieved excellent results. This has great significance for the later exploration.     

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.     

Deep-lacustrine sandy debrites and turbidites in the lower Triassic Yanchang Formation,southeast Ordos Basin,central China: Facies distribution and reservoir quality

The deep lacustrine gravity-flow deposits are widely developed in the lower Triassic Yanchang Formation, southeast Ordos Basin, central China. Three lithofacies include massive fine-grained sandstone, banded sandstone, and massive oil shale and mudstone. The massive fine-grained sandstones have sharp upper contacts, mud clasts, boxed-shaped Gamma Ray (GR) log, but no grading and Bouma sequences. In contrast, the banded sandstones display different bedding characteristics, gradational upper contacts, and fine-upward. The massive, fine-grained sandstones recognized in this study are sandy debrites deposited by sandy debris flows, while the banded sandstones are turbidites deposited by turbidity currents not bottom currents. The sediment source for these deep gravity-flow sediments is a sand-rich delta system prograding at the basin margin. Fabric of the debrites in the sandy debris fields indicates initial formation from slope failure caused by the tectonic movement. As the sandy debris flows became diluted by water and clay, they became turbidity currents. The deep lacustrine depositional model is different from the traditional marine fan or turbidite fan models. There are no channels or wide lobate sand bodies. In the lower Triassic Yanchang Formation, layers within the sandy debrites have higher porosity (8–14%) and permeability (0.1–4 mD) than the turbidites with lower porosity (3–8%) and permeability (0.04–1 mD). Consequently, only the sandy debrites constitute potential petroleum reservoir intervals. Results of this study may serve as a model for hydrocarbon exploration and production for deep-lacustrine reservoirs from gravity-flow systems in similar lacustrine depositional environments.     

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 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.     

Seismic based characterization of total organic content from the marine Sembar shale,Lower Indus Basin,Pakistan

The exploration and production of unconventional resources has increased significantly over the past few years around the globe to fulfill growing energy demands. Hydrocarbon potential of these unconventional petroleum systems depends on the presence of significant organic matter; their thermal maturity and the quality of present hydrocarbons i.e. gas or oil shale. In this work, we present a workflow for estimating Total Organic Content (TOC) from seismic reflection data. To achieve the objective of this study, we have chosen a classic potential candidate for exploration of unconventional reserves, the shale of the Sembar Formation, Lower Indus Basin, Pakistan. Our method includes the estimation of TOC from the well data using the Passey’s ΔlogR and Schwarzkofp’s methods. From seismic data, maps of Relative Acoustic Impedance (RAI) are extracted at maximum and minimum TOC zones within the Sembar Formation. A geostatistical trend with good correlation coefficient (R²) for cross-plots between TOC and RAI at well locations is used for estimation of seismic based TOC at the reservoir scale. Our results suggest a good calibration of TOC values from seismic at well locations. The estimated TOC values range from 1 to 4% showing that the shale of the Sembar Formation lies in the range of good to excellent unconventional oil/gas play within the context of TOC. This methodology of source rock evaluation provides a spatial distribution of TOC at the reservoir scale as compared to the conventional distribution generated from samples collected over sparse wells. The approach presented in this work has wider applications for source rock evaluation in other similar petroliferous basins worldwide.     

Inversion tectonics in Central Africa Rift System: Evidence from the Heglig Field

The Mesozoic-Cenozoic tectonic history of the Muglad Basin, is dominated by extension and inversion tectonics, but evidence of the inversion tectonics has not been well documented yet. In some other rift basins of CARS and WARS the phase of the inversion tectonics is well documented by several authors.This paper presents a structural study of the Heglig field area located on the eastern flank of the Muglad Basin. Detailed 3D seismic interpretation allows a better understanding of the structural style of the Heglig field. The new structural analysis has shown that the Heglig field has a complex structural framework reflected in the presence of a combination of two structural styles. The extensional structure is influenced by inversion tectonics during the Santonian time that creates four-way dip anticline structure, overprinted by the subsequent extensional movement that creates tilted fault block. The presence of inversion tectonics has supported by different means including seismic reflection, velocity, and source rock maturity data. The authors attributed the trapping of oil in the Lower Bentiu reservoir, that requires a horizontal seal, to the presence of the four-way dip anticline structure created by the inversion tectonics.The current interpretation of the Heglig field 3D seismic data sheds new light on the development and evolution of a key structure in the Muglad Basin. The results help to resolve long-standing discussion concerning hydrocarbon accumulation of the lower part of Bentiu Formation that lacks horizontal sealing.     

Temporal changes of fault seal and early charge of the Maui Gas-condensate field,Taranaki Basin,New Zealand

Fault seal due to juxtaposition or the generation of low-permeability fault rock has the potential to change through time with displacement accumulation. Temporal variations in cross-fault flow of hydrocarbons have been assessed for the Cape Egmont Fault (CEF), Taranaki Basin New Zealand, using displacement backstripping, juxtaposition and Shale Gouge Ratio (SGR) analysis. The timing of hydrocarbon migration and charge of the giant Maui Gas-condensate Field across the CEF have been assessed using seismic reflection lines (2D & 3D), coherency cubes, VShale curves from the Maui-2 well and PetroMod modelling. Displacement–backstripping analysis suggests that between the Late Miocene and early Pleistocene (5.5 and 2.1 Ma) sandstone reservoir units of the Maui Field (Mangahewa, Kaimiro and Farewell Formations) and underlying source rocks (Rakopi Formation) were partly juxtaposed across the CEF with low SGRs (< 0.2) present in the fault zone. Following 2.1 Ma SGRs increased to 0.2–0.55 adjacent to the Eocene–Palaeocene reservoir succession which was not in juxtaposed contact with source rocks. PetroMod modelling using these SGR values and juxtaposition relationships supports cross-fault flow prior to 2.1 Ma with later charge across the fault being less likely. Gas chimneys and the gas–water contact in the Eocene reservoir proximal to the fault suggest that despite limited cross-fault flow, upward leakage of hydrocarbons from the reservoir occurred after 2.1 Ma, possibly associated with active fault movement or fracturing related to faulting, and may account for the loss of an early oil phase.     

Importance of vertical effective stress for reservoir quality in the Skagerrak Formation,Central Graben,North Sea

The complex fluvial sandstones of the Triassic Skagerrak Formation are the host reservoir for a number of high-pressure, high-temperature (HPHT) fields in the Central Graben, North Sea. All the reservoir sandstones in this study comprise of fine-grained to medium-grained sub-arkosic to arkosic sandstones that have experienced broadly similar burial and diagenetic histories to their present-day maximum burial depths. Despite similar diagenetic histories, the fluvial reservoirs show major variations in reservoir quality and preserved porosity. Reservoir quality varies from excellent with anomalously high porosities of up to 35% at burial depth of >3500 m below seafloor to non-economic with porosities <10% at burial depth of 4300 m below seafloor.This study has combined detailed petrographic analyses, core analysis and pressure history modelling to assess the impact of differing vertical effective stresses (VES) and high pore fluid pressures (up to 80 MPa) on reservoir quality. It has been recognised that fluvial channel sandstones of the Skagerrak Formation in the UK sector have experienced significantly less mechanical compaction than their equivalents in the Norwegian sector. This difference in mechanical compaction has had a significant impact upon reservoir quality, even though the presence of chlorite grain coatings inhibited macroquartz cement overgrowths across all Skagerrak Formation reservoirs. The onset of overpressure started once the overlying Chalk seal was buried deeply enough to form a permeability barrier to fluid escape. It is the cumulative effect of varying amounts of overpressure and its effect on the VES history that is key to determining the reservoir quality of these channelised sandstone units. The results are consistent with a model where vertical effective stress affects both the compaction state and subsequent quartz cementation of the reservoirs.     

Seismic inversion as a predictive tool for porosity and facies delineation in Paleocene fluvial/lacustrine reservoirs,Melut Basin,Sudan

The Melut Basin is a rift basin in the interior Sudan linked to the Mesozoic-Cenozoic Central and Western African Rift System. The Paleocene Yabus Formation is the main reservoir deposited in heterogeneous fluvial/lacustrine environment. Delineation of channel sandstone from shale is a challenge in reservoir exploration and development. We demonstrate a detailed 3D quantitative seismic interpretation approach that integrates petrophysical properties derived from well logs analysis. A porosity transform of acoustic impedance inversion provided a link between elastic and rock properties. Thus, we used seismic porosity to discriminate between different facies with appropriate validation by well logs. At the basin scale, the results revealed lateral and vertical facies heterogeneity in the Melut Basin. Good reservoir quality is observed in the Paleocene Yabus Formation. The sand facies indicated high porosity (20%) corresponding to low acoustic impedance (20000–24000 g ft/(cm3.s)). However, lower quality reservoir is observed in the Cretaceous Melut Formation. The porosity of sand/shale facies is low (5%), corresponding to high acoustic impedance (29000–34000 g ft/(cm3.s)). This suggests that the Yabus Sandstone is potentially forming a better reservoir quality than Melut Formation. At the reservoir scale, we evaluated the facies quality of Yabus Formation subsequences using petrophysical analysis. The subsequences YB1 to YB3, YB4 to YB7 and YB8 to YB10 showed relatively similar linear regressions, respectively. The subsequence of YB4 to YB7 is considered the best reservoir with higher porosity (25%). However, subsequence YB1 to YB3 showed lower reservoir quality with higher shale volume (30%). This attributed to floodplain shale deposits in this subsequence. Similarly, the high porosity (20%) recognized in deeper subsequences YB6 to YB9 is due to clean sand facies. We learnt a lesson that appropriate seismic preconditioning, exhaustive petrophysical analysis and well log validation are important keys for improved reservoir quality prediction results in fluvial/lacustrine basins.     

High-resolution sequence stratigraphy,sedimentology and reservoir quality evaluation of the Yaojia Formation in the Longxi area of the Western Slope,Songliao Basin,China

Delta-front sand bodies with large remaining hydrocarbon reserves are widespread in the Upper Cretaceous Yaojia Formation in the Longxi area of the Western Slope, Songliao Basin, China. High-resolution sequence stratigraphy and sedimentology are performed based on core observations, well logs, and seismic profile interpretations. An evaluation of the reservoir quality of the Yaojia Formation is critical for further petroleum exploration and development. The Yaojia Formation is interpreted as a third-order sequence, comprising a transgressive systems tract (TST) and a regressive systems tract (RST), which spans 4.5 Myr during the Late Cretaceous. Within this third-order sequence, nine fourth-order sequences (FS9–FS1) are recognized. The average duration of a fourth-order sequence is approximately 0.5 Myr. The TST (FS9–FS5) mostly comprises subaqueous distributary channel fills, mouth bars, and distal bars, which pass upward into shallow-lake facies of the TST top (FS5). The RST (FS4–FS1) mainly contains subaqueous distributary-channel and interdistributary-bay deposits. Based on thin-sections, X-ray diffraction (XRD), scanning electron microscope (SEM) and high-pressure mercury-intrusion (HPMI) analyses, a petrographic study is conducted to explore the impact of the sedimentary cyclicity and facies changes on reservoir quality. The Yaojia sandstones are mainly composed of lithic arkoses and feldspathic litharenites. The sandstone cements mostly include calcite, illite, chlorite, and secondary quartz, occurring as grain coating or filling pores. The Yaojia sandstones have average core plug porosity of 18.55% and permeability of 100.77 × 10⁻³ μm², which results from abundant intergranular pores and dissolved pores with good connectivity. Due to the relatively coarser sediments and abundant dissolved pores in the feldspars, the FS4–FS1 sandstones have better reservoir quality than the FS9–FS5 sandstones, developing relatively higher porosity and permeability, especially the FS1 and FS2 sandstones. The source–reservoir–cap-rock assemblages were formed with the adjoining semi-deep lake mudstones that were developed in the Nenjiang and Qingshankou Formations. This study reveals the deposition and distribution of the delta-front sand bodies of the Yaojia Formation within a sequence stratigraphic framework as well as the factors controlling the Yaojia sandstones reservoir quality. The research is of great significance for the further exploration of the Yaojia Formation in the Longxi area, as well as in other similar lacustrine contexts.     

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.     

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.     

Constraining tectonic compression processes by reservoir pressure evolution: Overpressure generation and evolution in the Kelasu Thrust Belt of Kuqa Foreland Basin,NW China

The Kuqa Foreland Basin (KFB) immediately south of the South Tianshan Mountains is a major hydrocarbon producing basin in west China. The Kelasu Thrust Belt in the basin is the most favorable zone for hydrocarbon accumulations. Widespread overpressures are present in both the Cretaceous and Paleogene reservoirs with pressure coefficients up to 2.1. The tectonic compression process in KFB resulted from the South Tianshan Mountains uplift is examined from the viewpoint of the overpressure generation and evolution in the Kelasu Thrust Belt. The overpressure evolution in the reservoir sandstones were reconstructed through fluid inclusion analysis combined with PVT and basin modeling. Overpressures at present day in the mudstone units in the Kelasu Thrust Belt and reservoir sandstones of the Dabei Gas Field and the Keshen zone are believed to have been generated by horizontal tectonic compression. Both disequilibrium compaction and horizontal tectonic compression are thought to contribute to the overpressure development at present day in the reservoir of the Kela-2 Gas Field with the reservoir sandstones showing anomalously high primary porosities and low densities from wireline log and core data. The overpressure evolution for the Cretaceous reservoir sandstone in the Kelasu Thrust Belt evolved through four stages: a normal hydrostatic pressure (>12–5 Ma), a rapidly increasing overpressure (∼5–3 Ma), an overpressure release (∼3–1.64 Ma) and overpressure preservation (∼1.64–0 Ma). Overpressure developed in the second stage (∼5–3 Ma) was generated by disequilibrium compaction as tectonic compression due to the uplift of the Tianshan Mountains acted at the northern monocline of KFB from 5 Ma to 3 Ma, which provided abundant sediments for the KFB and caused the anomalously high sedimentation rate during the N₂k deposition. From 3 Ma to 1.64 Ma, the action of tectonic compression extended from the northern monocline to the Kelasu Thrust Belt and returned to the northern monocline of KFB from 1.64 Ma to present day. Therefore, the horizontal tectonic compression was the dominant overpressure mechanism for the overpressure generation in the third stage (∼3–1.64 Ma) and overpressure caused by disequilibrium compaction from 5 Ma to 3 Ma was only preserved in the Kela-2 Gas Field until present day.     

Organic geochemistry of marine source rocks and pyrobitumen-containing reservoir rocks of the Sichuan Basin and neighbouring areas,SW China

Three bitumen fractions were obtained and systematically analysed for the terpane and sterane composition from 30 Paleozoic source rocks and 64 bitumen-containing reservoir rocks within the Upper Sinian, Lower Cambrian, Lower Silurian, Middle Carboniferous, Upper Permian and Lower Triassic strata in the Sichuan Basin and neighbouring areas, China. These bitumen fractions include extractable oils (bitumen I), oil-bearing fluid inclusions and/or closely associated components with the kerogen or pyrobitumen/mineral matrix, released during kerogen or pyrobitumen isolation and demineralization (bitumen II), and bound compounds within the kerogen or pyrobitumen released by confined pyrolysis (bitumen III). In addition, atomic H/C and O/C ratios and carbon isotopic compositions of kerogen and pyrobitumen from some of the samples were measured. Geochemical results and geological information suggest that: (1) in the Central Sichuan Basin, hydrocarbon gases in reservoirs within the fourth section of the Upper Sinian Dengying Formation were derived from both the Lower Cambrian and Upper Sinian source rocks; and (2) in the Eastern Sichuan Basin, hydrocarbon gases in Middle Carboniferous Huanglong Formation reservoirs were mainly derived from Lower Silurian source rocks, while those in Upper Permian and Lower Triassic reservoirs were mainly derived from both Upper Permian and Lower Silurian marine source rocks. For both the source and reservoir rocks, bitumen III fractions generally show relatively lower maturity near the peak oil generation stage, while the other two bitumen fractions show very high maturities based on terpane and sterane distributions. Tricyclic terpanes evolved from the distribution pattern C₂₀ < C₂₁ < C₂₃, through C₂₀ < C₂₁ > C₂₃, finally to C₂₀ > C₂₁ > C₂₃ during severe thermal stress. The concentration of C₃₀ diahopane in bitumen III (the bound components released from confined pyrolysis) is substantially lower than in the other two bitumen fractions for four terrigenous Upper Permian source rocks, demonstrating that this compound originated from free hopanoid precursors, rather than hopanoids bound to the kerogen.     

Lithologic characteristics and diagenesis of the Devonian Jauf sandstone at Ghawar Field, Eastern Saudi Arabia

The Lower Devonian Jauf Formation in Saudi Arabia is an important hydrocarbon reservoir. However, in spite of its importance as a reservoir, published studies on the Jauf Formation more specifically on the reservoir quality (including diagenesis), are very few. This study, which is based on core samples from two wells in the Ghawar Field, northeastern Saudi Arabia, reports the lithologic and diagenetic characteristics of this reservoir. The Jauf reservoir is a fine to medium-grained, moderate to well-sorted quartz arenite. The diagenetic processes recognized include compaction, cementation (calcite, clay minerals, quartz overgrowths, and a minor amount of pyrite), and dissolution of the calcite cements and of feldspar grains. The widespread occurrences of early calcite cement suggest that the Jauf reservoir lost a significant amount of primary porosity at a very early stage of its diagenetic history. Early calcite cement, however, prevented the later compaction of the sandstone, thus preserving an unfilled part of the primary porosity. Based on the framework grain–cement relationships, precipitation of the early calcite cement was either accompanied or followed by the development of part of the pore-lining and pore-bridging clay cement. Secondary porosity development occurred due to partial to complete dissolution of early calcite cements and feldspar. Late calcite cement occurs as isolated patches, and has little impact on reservoir quality of the sandstones.In addition to calcite, several different clay minerals including illite and chlorite occur as pore-filling and pore-lining cements. While the pore-filling illite and chlorite resulted in a considerable loss of porosity, the pore-lining chlorite may have helped in retaining the porosity by preventing the precipitation of syntaxial quartz overgrowths. Illite, which largely occurs as hair-like rims around the grains and bridges on the pore throats, caused a substantial deterioration to permeability of the reservoir. Diagenetic history of the Jauf Formation as established here is expected to help better understanding and exploitation of this reservoir.     

Influence of natural fractures on gas accumulation in the Upper Triassic tight gas sandstones in the northwestern Sichuan Basin,China

The Upper Triassic Xujiahe Formation in the northwestern Sichuan Basin, China, is a typical tight gas sandstone reservoir that contains natural fractures and has an average porosity of 1.10% and air permeability less than 0.1 md because of compaction and cementation. According to outcrops, cores and image logs, three types of natural fractures, namely, tectonic, diagenetic and overpressure-related fractures, have developed in the tight gas sandstones. The tectonic fractures include small faults, intraformational shear fractures and horizontal shear fractures, whereas the diagenetic fractures mainly include bed-parallel fractures. According to thin sections, the microfractures also include tectonic, diagenetic and overpressure-related microfractures. The diagenetic microfractures consist of transgranular, intragranular and grain-boundary fractures. Among these fractures, intraformational shear fractures, horizontal shear fractures and small faults are predominant and significant for fluid movement. Based on the Monte Carlo method, these intraformational shear fractures and horizontal shear fractures improve the reservoir porosity and permeability, thus serving as an important storage space and primary fluid-flow channels in the tight sandstones. The small faults may provide seepage channels in adjacent layers by cutting through layers. In addition, these intragranular and grain-boundary fractures increase the connectivity of the tight gas sandstones by linking tiny pores. The tectonic microfractures improve the seepage capability of the tight gas sandstones to some extent. Low-dip angle fractures are more abundant in the T₃X³ member than in the T₃X² and T₃X⁴ members. The fracture intensities of the sandstones in the T₃X³ member are greater than those in the T₃X² and T₃X⁴ members. The fracture intensities do not always decrease with increasing bed thickness for the tight sandstones. When the bed thickness of the tight sandstones is less than 1.0 m, the fracture intensities increase with increasing bed thickness in the T₃X³ member. Fluid inclusion evidence and burial history analysis indicate that the tectonic fractures developed over three periods. The first period was at the end of the Triassic to the Early Jurassic. The tectonic fractures developed during oil generation but before the matrix's porosity and permeability reduced, which suggests that these tectonic fractures could provide seepage channels for oil migration and accumulation. The second period was at the end of the Cretaceous after the matrix's porosity and permeability reduced but during peak gas generation, which indicates that gas mainly migrated and accumulated in the tectonic fractures. The third period was at the end of the Eogene to the Early Neogene. The tectonic fractures could provide seepage channels for secondary gas migration and accumulation from the Upper Triassic Xujiahe Formation into the overlying Jurassic Formation.