Reservoir Quality Of Sandstones Research Articles

A Comparative Reservoir Study of Zubair and Nahr Umr Formations in Subba Oilfield, Southern Iraq

The lower Cretaceous sandstones of Zubair and Nahr Umr formations are the main producing reservoirs in Subba oilfield in southern Iraq. Key differences in their petrophysical and depositional attributes exist affecting their reservoir characteristics. The evaluation of well logs and core porosity-permeability data show better reservoir properties in Nahr Formation. The Litho-saturation logs indicate greater thickness of oil-saturated reservoir units for Nahr Unr Formation associated with lower values of shale volume, and higher values of effective porosity. In addition, higher values of permeability for Nahr Umr Formation is suggested by applying porosity-irreducible water saturation cross plot. The reducing reservoir quality of Zubair Formation sandstones is related to finer grains of sandstone reservoirs, higher clay volume, and more effect of compaction resulting from greater depth. A reservoir layering scheme is proposed by sequence stratigraphic analysis leading to the identification of systems tracts and their key surfaces within Zubair and Nahr Umr formations, and forms the basis for predicting of reservoir architecture and quality. Laterally continuous, and thick amalgamated sandstone reservoirs are formed during highstand systems tract in Nahr Umr Formation as a result of low accommodation/sediment supply conditions. Within the transgressive systems tract of Zubair Formation, the sandstone reservoir bodies become isolated as accommodation exceeds sediment supply.

Diagenetic effect on reservoir quality of siliciclastic and volcaniclastic sandstones from a Paleogene volcanic rifted margin, East Greenland

ABSTRACT Siliciclastic and volcaniclastic sediments in a volcanic rifted-margin succession may experience a complex diagenetic history during burial that can have a large impact on sandstone reservoir properties. To understand such changes, variations in initial sediment composition and succeeding diagenetic changes have been studied for a Paleogene outcrop analogue in the Kangerlussuaq area, East Greenland. The nature of the mafic volcanics-bearing succession, which consists of intra-volcanic sandstones, accommodated over quartz-rich pre-volcanic fluvial sandstones, are comparable to the settings of recently discovered hydrocarbon-producing sandstones in the Faroe–Shetland Basin on the conjugate Atlantic margin. Our petrographic and provenance investigations of the pre- and intra-volcanic sandstones are supported by geochemical and X-ray diffraction analyses. The intra-volcanic sandstones were deposited in shallow marine environments with mixed siliciclastic and volcaniclastic input, the latter rich in felsic to mafic volcanic rock fragments and feldspar grains. Similar zircon age distributions of pre- and intra-volcanic sandstones support a continued supply from the same siliciclastic sediment source after the onset of volcanism. Variations in initial detrital grain and pore-fluid (fresh to marine) compositions resulted in different diagenetic changes in the pre- and intra-volcanic sandstones. However, where siliciclastic sandstones were overlain by volcaniclastic rocks rather than massive lava flows, the diagenetic changes resemble those of the intra-volcanic sandstones. The cementing phases are typically quartz, illite (probably illitized kaolinite), and rare anatase in the pre-volcanic sandstones. Chlorite, calcite, zeolite/feldspar, opal/quartz, and titanite are characteristic authigenic phases in the intra-volcanic sandstones. Precipitation of different minerals in the pre- and intra-volcanic sandstones show that the detrital composition (and to a lesser extent depositional environment) played a major role during early and late diagenesis after deep burial (up to 6–8 km). Inter-eruptive siliciclastic units may prove to form highly valuable reservoirs when they are composed of mixed siliciclastic and volcaniclastic material. In the stratigraphically youngest intra-volcanic sandstones and pre-volcanic sandstones overlain by hyaloclastite or tuff, there is a high potential for preservation of interparticle porosity during burial (< 5 km) due to early chlorite rims and the generation of secondary porosity after the dissolution of early zeolite cement.

Impact of kaolinite and iron oxide cements on resistivity and quality of low resistivity pay sandstones

Low resistivity pay (LRP) zones have been identified within many siliciclastic reservoirs around the world, and have gained significant attention due to their ability to hold substantial hydrocarbon volumes. Previous studies have focused on investigating the role of highly conductive minerals, microporosity, bound water, and bed thickness in reducing resistivity within LRP zones. However, the impact of kaolinite and iron oxides in influencing the resistivity of LRP zones remains poorly understood. To address this, we examined outcrops cemented by pore-filling kaolinite and iron oxides, which serve as analogues to subsurface reservoirs. This study combined field description with laboratory analyses, including petrography, mineralogy, porosity, permeability, resistivity, and nuclear magnetic resonance to investigate the occurrence of kaolinite and iron oxide cements and their impact on resistivity and reservoir quality. The study observed various iron-bearing structures including concretions, fracture infills, layers, ferricrete, and liesegang bands. These structures are cemented by microporous pore-filling kaolinite (up to 18%; average: 6.6 %) as well as goethite and hematite (up to 21%; average: 3.5%). Observations from this study indicate that both depositional processes, such as grain size, and diagenetic pore-filling cements, significantly influenced the resistivity and reservoir quality of sandstones. Fine-grained sandstones containing substantial amounts of microporous kaolinite (>15%) and iron oxides (>17%) cements show very low resistivity values (≤0.2 Ω m), as well as low porosity (<10%) and very low permeability (<1 mD). Conversely, medium to coarse-grained sandstones with lower concentrations of kaolinite (<15%) and iron oxides (<5%) cements exhibited higher resistivity values (2–40 Ω m; average: 8 Ω m) and displayed higher porosity (average: 22%) and permeability (average: 1300 mD). This study underscores the importance of understanding and characterizing the presence and distribution of iron oxides and kaolinite cements, along with other factors like microporosity and grain size within LRP zones. Such understanding is crucial for accurate resistivity measurements, reservoir quality prediction, and hydrocarbon estimation in sandstone reservoirs worldwide.

Diagenesis as a control on the tight sandstone reservoir quality of the upper Carboniferous strata in the northeastern Ordos basin, China

The upper Carboniferous tight sandstone strata are considered the most promising targets for gas exploration in the northeastern Ordos Basin. Reservoir quality is critical for the successful commercial exploration and development of tight sandstone gas. Reservoir quality of deeply buried tight sandstones is controlled by diagenesis, yet there is sparse systematic documentation on upper Carboniferous tight sandstone reservoir quality and its diagenetic link. In this study, we utilized core analysis and wireline log data, and core samples were studied using X-ray diffraction, optical light microscopy, scanning electron microscopy, porosity–permeability, mercury intrusion capillary pressure and nuclear magnetic resonance measurements. Dolomite, siderite, quartz, kaolinite, and illite are the main diagenetic cements. The upper Carboniferous sandstones pore system consists of residual intergranular pores, intragranular dissolution pores associated with feldspar grains and micropores mainly related to diagenetic minerals. Due to differences in diagenetic alterations, sandstones have significant differences in pore types and pore-filling components, ultimately leading to differences in reservoir quality. The residual intergranular porosity is closely related to the reservoir quality. Quartz cement and authigenic clay minerals lead to reduced residual intergranular porosity, but their impact on reservoir quality is relatively limited due to their relatively low content. The most significant factors contributing to reservoir quality deterioration are ductile (clay-rich) grain-influenced compaction and pervasive pore-filling carbonate cement. When sandstone contains large numbers of ductile grains, it loses a large amount of intergranular porosity due to compaction, and the pore space contains only a small number of dissolution pores and micropores, resulting in reservoir quality deterioration. Similarly, when a large amount of carbonate cement is developed in sandstone, it leads to intergranular porosity loss. The best reservoir quality sandstones preserve a percentage of intergranular porosity because they (i) have few ductile grains, resulting in low compaction, and (ii) do not have significant amounts of carbonate cements. Finally, the diagenetic variations were successfully correlated with wireline logs to evaluate the reservoir quality of subsurface upper Carboniferous sandstones. The data sets provided in this research offer insights to better evaluate and predict reservoir quality in the northeastern Ordos Basin.

Depositional and diagenetic controls on the reservoir quality of Early Miocene syn-rift deep-marine sandstones, NW Saudi Arabia

Understanding the distribution of sedimentary facies, their texture and diagenetic alterations in deep-marine rift systems are critical for improved reservoir quality predictions in the subsurface. Syn-rift deep-marine sandstones of the Miocene Burqan Formation, deposited by various sediment gravity flow types in the Midyan Basin (Red Sea, Saudi Arabia) are characterized using detailed sedimentological and petrographic analyses. Six distinctive lithofacies (F1-F6) have been identified within the Burqan Formation and grouped into three broad facies associations namely proximal, medial, and distal facies of a submarine fan. The proximal fan facies consists of disorganized conglomerate (F1) and structureless sandstone (F2) . The medial fan facies are represented by graded bedded and channelized sandstone (F3) and sandstone dominated heterolithics (F4) . Deposits of distal fan facies consist of mudstone dominated heterolithics (F5) and structureless mudstone (F6) . The sandstones are predominantly arkoses and lithic arkoses with a low degree of diagenetic modification (Eo- and Telo-diagenesis; ≤ 2 km and ≤ 70 °C temperature) and low to moderate volumes of carbonate cement (mean = 7%). The structureless sandstone (F2), sandstone dominated heterolithics (F4) and mudstone dominated heterolithics (F5) have poor reservoir quality due to the presence of authigenic cement and matrix. Graded bedded and channelized sandstone (F3) lithofacies consists of excellent reservoir sandstone due to the least proportion of cement and virtual absence of detrital clay. The observed variability in composition and textural parameters within Burqan Formation indicates that sedimentological transport processes control the depositional reservoir quality which in turn dictates diagenetic modification in deep-marine sandstones with important implications for prediction of reservoir quality in deep-marine systems.

Evaluation of porosity and permeability of sandstones within the Oti Group of the Volta Basin using petrophysical and petrographic techniques

Evaluation of porosity and permeability of sandstones within the Oti Group of the Volta Basin using petrophysical and petrographic techniques

Diagenesis and Diagenetic Mineral Control on Reservoir Quality of Tight Sandstones in the Permian He8 Member, Southern Ningwu Basin

The sandstone reservoirs of the He8 member within the Lower Permian Shihezi Formation are important targets for oil and gas exploration in the southern Ningwu Basin. This study utilized thin-section identification, scanning electron microscopy, and X-ray diffraction analysis to examine the petrological features and reservoir characteristics, and evaluate the impact of the mineral composition and diagenesis type on the porosity of the sandstone reservoir. Additionally, a multiple linear regression prediction model was developed to predict the distribution of promising sandstone reservoirs in the study area. The results of the analysis revealed that the sandstone of the He8 member is mainly composed of feldspathic lithic sandstone, followed by lithic sandstone. The main reservoir type is characterized by secondarily dissolved pores and micropores within kaolinite aggregates. The low porosity (ranging from 0.2% to 10.7%) and permeability indicate that the He8 member is a tight sandstone reservoir. This reservoir has undergone compaction, cementation, and dissolution diagenesis, and is presently in the stage of mesodiagenesis B. The rigid framework of quartz, the dissolution of feldspar grains, and the intergranular pores of kaolinite are significant contributors to reservoir quality and the main drivers of porosity. In this study, a multivariate linear regression model was developed based on the mineral content of quartz, feldspar, carbonate minerals, kaolinite, smectite, and rock fragments, which accurately predicts the porosity of the studied reservoirs. Based on this model, it was predicted that the north of the Jingle South sub-depression contains a favorable reservoir space in the tight sandstone reservoir of the He8 member. The findings of this study hold significant reference value in the quantitative characterization of tight sandstone reservoirs with similar depositional and diagenetic characteristics, and improving the prediction effect of favorable reservoirs.

Effects of overpressure on deep sandstone reservoir quality: A case study of the Medium and Lower Jurassic formation in the Shawan Sag, central Junggar Basin, western China

This study focuses on the Medium and Lower Jurassic sandstone reservoir in the Shawan Sag, central Junggar Basin to demonstrate the impacts of overpressure on deep reservoir quality. Based on thin section observation and mineral identification, compaction heterogeneity and different petrofacies were identified by mathematical statistics. The compaction degree and typical cements content of different petrofacies under different overpressure systems were analysed to qualitatively evaluate the heterogeneous influence of overpressure on reservoir quality. The evolution of palaeo-pressure and porosity for typical wells were restored using basin modelling, and then the effects of overpressure on reservoir quality were quantitatively analysed. The results reveal that deep sandstones exhibit compaction heterogeneity owing to petrological properties and calcite cement, resulting in different petrofacies: ductile-rich sandstone, calcite-cement sandstone, and ductile-lean sandstone. Ductile-rich sandstone and calcite-cement sandstone, which were nearly or already tight before the on-set of overpressure, were free from the effects of overpressure. Ductile-lean sandstone maintained better reservoir quality from overpressure. The effects of overpressure were heterogeneous, which were comprehensively controlled by grain size, the content of rigid grains, overpressure strength and the on-set and duration of overpressure. The basin modelling results show differences in grain size and the content of rigid grains for the Medium and Lower Jurassic formation, resulting in varying levels of porosity preservation. The Medium Jurassic formation, whose pressure coefficient is 1.9, shows 1.69% porosity preservation, whereas the Lower Jurassic formation, whose pressure coefficient is 1.3, shows 1.59% porosity preservation. With the development of overpressure, quartz overgrowth was restrained, whereas smectite-illitization and carbonate cements were free from the late overpressure effects. The research results deepen the existing understanding of the formation mechanism of deep effective reservoirs.

Impact of coal evolution on formation of tight sandstone reservoirs: A case study in the Daniudi gas field, Ordos Basin, China

Tight sandstone gas in coal-bearing strata has become an important unconventional gas worldwide. This research aims at understanding the impacts of coal evolution on diagenesis and reservoir quality of sandstones by means of thin section, cathode luminescence (CL), scanning electron microscope (SEM), stable isotope analysis, and fluid inclusions. The results show that carbonate cement was the main type of cement developed in tight sandstone reservoirs, of which the carbonate ions were jointly provided by coal layers and reaction in adjacent mudstones. For sandstones close to coal layers, their carbonate ions were mainly controlled by coal evolution and there was various carbonate cement developed due to cations supplied by seawater and the intense dissolution of volcanic fragments and feldspars. Combined with coal thermal simulation and burial history, it implies that at different maturity stages of coal evolution, its impact on sandstone diagenesis was different. In the early stage, the main product was CO2, which caused the dissolution of early calcite and promoted intense compaction. In the mature stage, CO2 and other hydrocarbon gases were released, resulting in more dissolution and silica cementation. In the over-mature stage, the main product was methane, and CO2 that did not spill out preserved by forming carbonate cement. The coal evolution had a strong impact on the reservoir quality of sandstone with large grain sizes, but little effect on medium- and fine-grained sandstones. High porosity and low permeability reservoirs were usually formed in small conglomerates and coarse-grained sandstones away from coal layers. While low porosity and high permeability reservoirs were distributed close to coal layers. This study aids in understanding the formation mechanism of tight sandstone reservoirs in coal measures and provides theoretic support for further exploration.

Depositional and diagenetic controls over reservoir quality of tight sandstone and conglomerate in the lower Cretaceous Shahezi formation, Xujiaweizi fault depression, Songliao basin, China

The distribution of high-quality reservoirs restricts the exploration and development of tight gas in the Shahezi Formation in the Xujiaweizi Fault Depression, but the complex sedimentary composition and abundant diagenesis make it difficult to determine which rocks are high-quality reservoirs. In this paper, the petrological, mineralogical, and pore structure characteristics of sandstone and conglomerate were investigated to elucidate how depositional and diagenetic processes jointly control reservoir quality and identify favorable sequences in which high-quality reservoirs are distributed. The results showed that the content and type of matrix and lithic clasts in the sedimentary rock unit controlled the effects of the following diagenetic sequence, which in turn controlled the reservoir porosity, permeability and pore size distribution. Conglomerate and coarse-to medium-grained sandstone, both with a low muddy matrix content and high intermediate–basic volcanic lithic clast content, underwent extensive dissolution or grain fracturing during diagenesis, resulting in a reservoir with pore spaces >0.1 μm in diameter, which is considered as a high-quality reservoir for tight gas exploration. Conglomerate and fine-grained silty sandstone, both with a high muddy matrix content and low intermediate–basic volcanic lithic clasts, or those reservoir units directly adjacent to mudstone often experienced severe mechanical compaction or cementation during diagenesis. This resulted in a reservoir dominated by micropores (<0.1 μm) and therefore formed nonreservoir areas for tight gas exploration. High-quality reservoirs are more likely to be developed in the lacustrine transgressive systems tract and regressive systems tract in sequence four of the Shahezi Formation in the Xujiaweizi Fault Depression.

Role of depositional and diagenetic controls on reservoir quality of complex heterogenous tidal sandstone reservoirs: An example from the Lower Goru formation, Middle Indus Basin, Southwest Pakistan

The Lower Goru Formation, one of the key hydrocarbon development targets in Pakistan's Middle Indus Basin, offers a unique opportunity to investigate the role of depositional and diagenetic controls on reservoir quality in complex stratigraphic traps. An integrated approach, including thin-section petrography, scanning electron microscopy-energy dispersive spectroscopy (SEM-EDS), helium porosity, and permeability measurements, was used to analyze the Lower Goru Formation in three gas-producing fields. Based on petrographic interpretation, the sandstones are quartzarenite, sublitharenite, subarkose, and less commonly, litharenite. High permeability and high porosity reservoirs are associated with well-sorted and medium-grained sandstones. Main diagenetic processes include compaction, carbonate cementation, authigenic chlorite and quartz overgrowth. Authigenic chlorite, and quartz cementation were the principal reservoir quality controlling factors. Well-developed chlorite coatings preserved porosity and inhibited quartz cementation. Good quality reservoirs (average porosity: 17%; average permeability: 96 mD) are restricted to tidal channels and tidal inlet in the prograding shoreface environments. Transgressive and tidally reworked deposits show moderate porosity and very low permeability (average porosity: 9.5%; average permeability: 0.07 mD). Middle shoreface and bioturbated storm sands have low porosity and very low permeability (average porosity: 8.7%; average permeability: 0.9 mD) and are considered tight reservoirs. The quality of the studied reservoirs depends on quartz overgrowth, chlorite coating, carbonate cementation and minor detrital clay. Secondary porosity is associated with partial to complete dissolution of feldspar, volcanic rock fragments (VRF), biotite, chamosite ooids, and bioclast grains. This integrated work would be helpful for exploration and field development plans in the stratigraphic traps of the Middle Indus Basin and would lead to new exploration targets, i.e., tight and low permeability reservoirs. The study provides insight into the complex interplay between depositional facies and diagenesis in controlling reservoir quality in the Lower Goru Formation and similar depositional conditions and trapping mechanisms elsewhere.

Diagenetic Facies and Their Controls on the Quality of Tight Sandstone Reservoirs: A Case Study from the Upper Paleozoic Gas Reservoir in the Eastern Ordos Basin, North China

Diagenetic facies play a significant role in the evaluation and prediction of reservoirs as they comprehensively reflect the spatial distribution characteristics of deposition, diagenesis, and petrophysical properties. Based on the petrographic observation and considering pores, lithology, and diagenesis types, the diagenetic facies types were identified, and the pore evolution process and its influence on the quality of low permeability tight gas reservoirs were analyzed. The results show that six types of diagenetic facies were identified, including siliceous cementation intergranular pore facies (A), carbonate dissolution pore facies (B), matrix dissolution pore facies (C), clastic dissolution pore facies (D), matrix filling and strong compaction tight facies (E), and carbonate cementation and metasomatism tight facies (F). The evolution process of porosity shows that the restored original porosity is indicated to be between 34.2% and 36.0%. The average porosity loss caused by compaction was 17.1%, while the average porosity loss caused by cementation is 14.1%. The average porosity increased by 2.5% on diagenetic facies B, C, and D due to dissolution. Consequently, diagenetic facies A with weak compaction and diagenetic facies B, C, and D with strong dissolution are effective reservoirs with porosity greater than 6.6% and permeability greater than 0.25 − 0.6 × 10 − 3 μm2. The distribution areas of A, B, C, and D are favorable areas for tight gas exploration and are important indicators for the prediction of tight gas in the Upper Paleozoic Shanxi Formation in the eastern Ordos Basin. This study provides a new petrographic method for reservoir prediction and exploration of natural gas, which has practical value and economic significance.

Re-discovering the Gummy gas field – Gippsland Basin

Recent sub-surface studies of the Gummy Gas Field have resulted in a significant upgrade of its gas and liquids resource potential. Previous interpretations had ascribed little resource potential to the field. Shell drilled Gummy-1 in 1990, a Golden Beach (GB) Subgroup gas/liquids discovery in the eastern Gippsland Basin. The GB Subgroup was previously described as a stacked, grading to generally thin, isolated sandstone reservoir hosting limited gas volumes. In 2022, a new study integrated the interpretation of the CGG Gippsland Multi-Client 3D seismic survey dataset with a re-look at the reservoir characterisation, petrophysical properties and reservoir pressures and found that reservoir quality is better than previously thought. The improved reservoir quality is interpreted to be the result of depositional reworking, which also increases confidence that the sandstones are laterally extensive. Consideration of the impact of regional pressure depletion due to nearby production from the GBJV fields has improved the understanding of the hydrocarbon columns encountered at Gummy-1. Increased hydrocarbon column heights are interpreted, which are consistent with wireline log evaluation and regional saturation-height data. Confidence that the seal at Gummy is working as effectively or better than offset fields and reservoirs is high. The new interpretation has also significantly improved the exploration potential for underlying gas reservoirs within the middle and lower GB Subgroup. Gummy-1 reached a total depth of 3530 m MDRT in a gas sandstone reservoir with an interpreted main gas column up to 185 m. Potential exists for additional gas in reservoir quality sandstones to be discovered in deeper exploration targets – the Gummy Deep exploration prospect. Combined with the adjacent Manta Gas Field, this demonstrates the enhanced potential for future commercial development in the area.

Depositional model, facies analysis and reservoir quality in a wave-modified clastic lacustrine system: The early cretaceous Tongbomiao formation of the Tanan Depression, Tamtsag Basin, Mongolia

The Tanan Depression has experienced multi-phase tectonic movements and formed various types of reservoirs, which has brought some difficulties to proper oil exploration. This study aims to characterize the depositional facies and petrophysical properties of clastic reservoirs in the Tanan Depression and to determine the most prolific areas for exploration based on the analyses of core samples, thin sections, logging data, petrophysical properties, seismic profiles, and paleontological data. A wind-wave controlling sedimentary model and seven primary depositional facies, namely: 1) alluvial fan; 2) braided delta plain; 3) braided delta front; 4) wave-modified fan-delta front; 5) shoreface; 6) storm deposits; and 7) sublacustrine fan, were revealed in this study. The predominant wind direction during the deposition of the upper Tongbomiao Formation was from the southeast (SE), and the resulting wave-modified sandbodies mainly extended along the paleoshore line of the lake in a NE-SW direction. Facies of weakly-to not-modified depositional settings (alluvial fan, braided channel, braided delta front, and sublacustrine fan) were mainly characterized by high matrix content, poor grain sorting, and poor maturity. Conversely, facies related to wave-dominated depositional settings (wave-modified fan delta front, shoreface and storm deposits) are characterized by low matrix content, higher grain sorting, and higher maturity. A positive correlation between reservoir quality and wave-modified intensity of sandstones is evidenced in the study area. Sandbodies that have experienced wave modification, early carbonate cementation, and dissolution served as the main reservoirs for oil accumulation. Therefore, future oil exploration in the Tanan Depression should focus on clastic sedimentary bodies reworked by waves. Moreover, the facies distribution model and high-quality reservoirs forming mechanism in the Tanan Depression could provide a significant reference for oil exploration and development in other similar basins.

Depositional and diagenetic controllers on the sandstone reservoir quality of the late cretaceous sediments, Gulf of Suez Basin

The complex depositional, burial, and diagenetic histories of the Late Cretaceous Nezzazat Group sandstones in Northeastern Africa present the main challenges with regard to reservoir quality. The quality of commercial reservoirs is maintained despite deep burial and the associated high temperature and pressure. The study presents an optimum integration of different data sets to address reservoir quality and reservoir performance controllers. The data set includes measured porosity and permeability, petrographic point-counting data, grain-size analysis, X-ray diffraction data, scanning electron microscopy, and porosity loss by compaction. The depositional controls on the reservoir quality are the facies, whereas the higher quality is found in the channel and upper shoreface settings. The coarse-grained sandstone is associated with better reservoir quality. The large intergranular porosity is the main porosity controlling the fluid flow. The massive and laminated sandstones are the best quality facies. The labile grains (feldspars and mica) control the permeability distribution. Whereas the secondary diagenetic controllers are the carbonate cementation that inhibited the effects of compaction. The siderite cementation has resulted in a micropore dominated and highly tortuous pore system. Total porosity has largely been preserved in the siderite-cemented sample but virtually eliminated in the dolomite cemented. A low volume of illite is associated with better reservoir quality. Whereas the better reservoir quality is associated with the abundant quartz cementation that protected the primary porosity from compaction. Compaction acts as a significant porosity loss factor during diagenesis. Authigenic kaolinite does not significantly affect the reservoir quality. The reservoir sensitivity to formation damage comes from the potential for fines (kaolinite, illitic clays, siderite, and pyrite) migration within the pore system that is readily mobilized by the fluid flow.

Improvement of reservoir quality of ultra-deep tight sandstones by tectonism and fluid: A case study of Keshen gas field in Tarim Basin, western China

Improvement of reservoir quality of ultra-deep tight sandstones by tectonism and fluid: A case study of Keshen gas field in Tarim Basin, western China

Diagenetic Evolution and Its Impact on Reservoir Quality of Tight Sandstones: A Case Study of the Triassic Chang-7 Member, Ordos Basin, Northwest China

The Upper Triassic Chang-7 Member of the Ordos Basin contains typical tight sandstone reservoirs. Reservoir quality is affected by diagenesis, which is a critical factor in tight oil exploration. In this study, the Chang-7 Member tight sandstones were studied by a variety of experimental methods, including thin sections, scanning electron microscopy (SEM), and X-ray diffraction (XRD), to determine the reservoir characteristics and diagenesis and discuss their influences on the reservoir quality. The Chang-7 Member sandstones are mainly lithic arkose and feldspathic litharenite with an average porosity and permeability of 7.17% and 0.13 mD, respectively. The pore type is mainly primary intergranular pores, and the secondary pores are feldspar dissolved pores, which are relatively developed, with pore radii of 2–20 µm. Diagenesis of Chang-7 Member tight reservoirs mainly includes compaction, quartz cementation, carbonate cementation, clay mineral cementation, and dissolution. The diagenetic stage develops into Mesodiagenesis A. The average porosity loss from compaction and cementation of sandstone in the Chang-7 Member is 15.93% and 18.67%, respectively. With the increase in burial depth, the porosity and permeability of the reservoir gradually decrease. In mesodiagenesis, the authigenic illite and carbonate cementation compacts the reservoir. The acid fluid carried by the two stages of oil and gas filling during diagenesis dissolved feldspar and carbonate cement, which plays a certain role in transforming the tight reservoir.

The main factor influencing reservoir quality of K1yc tight sandstones within volcano-sedimentary succession in the Dehui fault-depression of Songliao Basin, NE China

The main factor influencing high-quality reservoirs of the Lower Cretaceous Yingcheng Formation (K1yc) sandstones in the Dehui Fault-Depression of the Songliao Basin, NE China within volcano-sedimentary succession is still obscure. In the study area, K1yc sandstone reservoirs has exhibited stronger heterogeneity and more complicated diagenetic alteration than terrigenous clastic sandstones. In this paper, K1yc sandstone reservoirs have been characterized through the aspects of petrology, physical property, and pore-types and -throat size. Accordingly, methods including core analysis, thin section, X-ray diffraction, scanning electron microscopy have been used in the study. Finally, the main factor controlling high-quality reservoirs within volcano-sedimentary successions has been concluded. The results reveal that the abundance of authigenic illite clays with forms of fibrous pore-bridging or lath-like pore filling primarily and rapidly reducing the reservoir performance. The chlorite coatings of framework grains should not effectively retard cementation process. Volcanic rock fragments are widespread within the volcano-sedimentary successions and tend to be dissolved by pore fluids, as then illitization should be the most important origin of authigenic illites. It has a critical significance for predicting high-quality reservoirs in the K1yc tight sandstones.

Quantitative evaluation of reservoir quality of tight oil sandstones in chang 7 member of Ordos Basin

In order to establish a quantitative evaluation system for reservoir quality suitable for tight oil sandstones, in this study, taking the Chang 7 Member in the Maling area of the Ordos Basin as an example, the nuclear magnetic resonance, clay mineral analysis, high pressure mercury injection analysis and logging interpretation technology have been used to carry out a comprehensive evaluation of the pore structures, sand body structures and oil-bearing properties of tight oil sandstone reservoirs. The results show that the pseudo-capillary pressure curves transformed by the NMR T2 spectra are consistent with the capillary pressure curves measured by the core experiments. This method can be used for accurate characterization of the pore structures of the reservoir. The pore structure parameters calculated based on the pseudo-capillary pressure curves can accurately reflect the pore structures of the reservoirs such as micropores-thin throats and complex tortuosity. At the same time, the smoothness feature of conventional logging curves is used to evaluate the sand body structures and heterogeneity of the reservoir, and the apparent energy storage coefficient is introduced to quantitatively evaluate the oil-bearing properties of tight oil reservoirs. The evaluation results are in good agreement with the actual production situation. The larger the apparent energy storage coefficient, the higher the initial output of the oil wells. The evaluation results of the reservoir quality of the tight oil sandstones constructed in this paper are highly consistent with the production status, so the method has broad application prospects.

Investigation of pore structure characteristics in marine deep-water high-temperature and high-pressure sandstone: A comprehensive characterization combining various experimental techniques

Marine deep-water high-temperature and high-pressure (HTHP) reservoirs have excellent potential for future oil and gas exploration. Because reservoir quality is often influenced by pore structure, understanding the characteristics of pore structures is essential for efficient exploitation. Therefore, it is necessary to conduct a comprehensive study of the pore structures in HTHP reservoirs. This study selected samples of the Enping Formation in the South China Sea as the research target and investigated the reservoir pore structures based on scanning electron microscopy, casting thin section, nuclear magnetic resonance, and mercury intrusion (e.g., high-pressure, constant-rate). The results show that the pore geometry and throat radius of different pore types in these reservoirs can lead to pore system heterogeneity. A comprehensive experimental method combining NMR and mercury injection was used to determine pore structure characteristics. In addition, a new pore size classification scheme was developed for marine deep-water HTHP reservoirs, and the controlling effect of pore type on percolation flow capacity was analyzed. This study systematically used a comprehensive pore structure characterization method that combined various experimental techniques to present the pore structure and develop a new pore size classification scheme for deep-water HTHP sandstone reservoirs, providing insight into the reservoir quality of marine deep-water HTHP sandstone reservoirs.