Reservoir Properties Of Sandstones Research Articles

Impact of clay minerals on reservoir sandstone properties: comparative study in Colombian eastern cordillera and middle Magdalena valley basins

The aim of this study is to examine how mineralogy influences the petrophysical properties, particularly porosity and permeability, of potential sandstone reservoirs in Colombia. It seeks to comprehensively understand how the presence of clay minerals impacts the overall quality of hydrocarbon reservoirs in the country. Samples of sandstones from reservoirs at various outcrops in the Eastern Cordillera and Middle Magdalena Valley basins were collected. Detailed analysis of mineralogy and petrographic characteristics of the samples was conducted through various analytical techniques such as transmitted light microscopy, X-ray diffraction, and scanning electron microscopy. Porosity and permeability were measured using automated permeametry and porosimetry equipment. The predominant composition of the analyzed reservoir rocks comprises quartz (45-50%), feldspar (35-40%), and clays (10-20%). These rocks were categorized into two distinct groups based on their permeability (K) and porosity (Φ), ranging from 0.009 to 29.220 mD and 1.88 to 20.75%, respectively. The presence of illite correlated with a reduction in both porosity and permeability, highlighting its negative impact on reservoir quality. Conversely, an elevated concentration of kaolinite was associated with favorable porosity and permeability. Samples with feldspar sericitization demonstrated inferior hydrocarbon storage quality. This study provides a deeper understanding of how mineralogy affects the petrophysical properties of sandstone reservoirs in Colombia. These findings are crucial for guiding exploration and production strategies in the Colombian oil industry, especially in challenging geological environments like those studied.

Developing a semi-analytical model for estimating mechanical properties of sandstone reservoirs: Enhancing applications in hydrocarbon production and underground gas storage

Rock mechanical properties, encompassing the static Young's modulus, bulk modulus, and shear modulus, influence strategic decision-making operations, such as drilling programs and well completion designs. When precisely calculated, these variables can significantly affect drilling cost-efficiencies and production economic returns. Even though these attributes are significant, the conventional estimation method is core-lab testing, which is expensive and limited to covering the entire reservoir strata. To address this challenge, we propose a new semi-analytical model with direct equations to estimate the elastic rock properties primarily anchored around porosity. In particular, we developed an analytical framework using generalized equations for bulk and shear modulus to calculate static rock mechanical properties as porosity-driven functions. We employed lab-tested core data from 55 core samples to validate the new model's efficiency. The model's innovative design allows computing all elastic properties solely based on porosity. Impressively, the results closely matched the lab measurements. The new semi-analytical model's equations yielded a good root mean square error (RMSE) in the calculated rock mechanical properties. Specifically, the new static Young's modulus equation has the lowest RMSE, 1.489, compared to 45.168 for the Edimann equation and 3.043 for the Zhang equation. The newly developed static shear modulus equation had an RMSE of 0.497, lower than Zhang's empirical equation's 1.262. However, the Zhang equation has an RMSE of 0.891 versus 2.029, slightly outperforming the new equation. According to the RMSE values, the discrepancy between the core sample-based measured, new semi-analytical model-calculated static modulus was caused by the fact that the core samples were collected from clean sand oil-bearing reservoir intervals. However, the derived equations used porosity ranges that covered shale and sand. In essence, the new semi-analytical model provides a fast and precise estimation of rock mechanical properties, easily solving drilling concerns. This research not only advances knowledge of drilling and geomechanics, but also makes strategies more efficient and cost-effective.

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.

Identification of quartz cement in sandstone through deep learning segmentation of electron microscopy images

Quartz cementation is a crucial factor in controlling the petrophysical properties of sandstone reservoirs. However, reliable identification of sandstone cementation often requires petrographic analysis of rock thin sections using a combination of optical light microscopy, backscattered electron (BSE), and cathodoluminescence (CL) images. This process is currently carried out manually and is both costly and time consuming. In this study, we present the first attempt to automate this process by identifying sandstone cement through convolutional neural networks (CNNs). We used a combination of BSE and CL images acquired from sandstone thin sections sourced from formations in the US, Israel, and the Netherlands. For each image pair we created a labeled mask with 4 classes: (i) quartz grains; (ii) quartz cement; (iii) porosity; and (iv) Other phases. We developed a U-Net with a total of 10 layers: 5 layers for the contracting path and 5 layers for the expansive path. The model is trained to predict the segmentation mask for a given input of paired BSE and CL images. A high level of accuracy is achieved for quartz grains (91%), quartz cement (78%), and porosity (95%). By contrast, the Other phase class was poorly predicted due to a combination of mineral heterogeneity and low representation. Our results indicate that Deep Learning algorithms provide a promising avenue for the automation of quartz cement detection in sandstone images.

Hydrocarbon potential and reservoir characteristics of incised-valley transgressive sandstones: A case study of the Messinian gas reservoirs (Nile Delta Basin, Egypt)

The incised-valley sandstones have been identified as a significant contributor to global hydrocarbon resources. This study aims to assess the Messinian Abu Madi (AM) sandstone's reservoir properties in the incised valleys of the Baltim, Nidoco, and Abu Madi gas fields in the Nile Delta Basin, Egypt. The hydrocarbon potential of these sandstones is assessed through the analysis of seismic, well logs, and core data. The seismic interpretation reveals that extensional faults played a significant role in controlling the deposition of the Abu Madi Formation in the study area, formed during the tectonic rifting of the Messinian age. The northernmost portion of the study area in the Abu Madi field exhibits the most promising location for gas exploitation, suggesting the need for further exploration and evaluation. The sandstones exhibit a fining upward trend with a relatively clean composition, moderate to well sorting and mild calcareous tendencies. The presence of sedimentary structures, such as cross-bedding and ripples, suggests a dynamic depositional environment. The rock composition, dominated by quartz with variable sorting and cementation, influences the porosity and permeability of the sandstones. Petrophysical investigations indicate favourable reservoir conditions with significant porosity and permeability, enhancing hydrocarbon storage and extraction potential. The analysis of petrophysical parameters in the AM sandstones reveals favourable properties for gas production, including low shale content (4%–12%), high porosity (18%–22%), and low water saturation (20%–54%) levels. The findings of this study indicate that the gas-pay zones within the Abu Madi sandstones are primarily associated with the transgressive sandstones of the estuarine facies (TST) rather than the lower sandstones of the fluvial facies (LST). The complex sandstone channels within the TST exhibit diverse geometries and contribute to reservoir heterogeneity. The presence of well-connected channels enhances reservoir productivity by facilitating fluid flow. The understanding of the distribution and characteristics of these channels is essential for reservoir characterisation and optimisation of hydrocarbon recovery.

Study on factors affecting the petro physical properties of sandstone and conglomerate reservoirs of Baikouquan Formation, Junggar Basin

In recent years, oil and gas exploration of the Baikouquan Formation in the northwestern margin of the Junggar Basin has seen major breakthroughs have been made in oil and gas exploration. Sandstone and conglomerate reservoirs are developed in the Baikouquan Formation in this area, but the factors affecting the differences in petro physical properties of these two types of reservoirs are still unclear. In this paper, taking the Baikouquan Formation in the Hongcheguai area on the northwestern margin of the Junggar Basin as an example, a large number of core observations, thin sections, scanning electron microscopy, and petro physical property test data were used to evaluate the petro logical characteristics, reservoir space types, digenesis and pore evolution of the sandstone and conglomerate reservoirs. The results show that the sandstone and conglomerate rocks of the Baikouquan Formation in the study area have a large content of tuffaceous components. The sandstone reservoirs are dominated by primary intergranular pores, and the conglomerate reservoirs are dominated by secondary dissolved pores. In addition, the porosity is negatively correlated with rock permeability for the conglomerate rocks of the Baikouquan Formation. However, the porosity is positively correlated with rock permeability of the sandstone reservoirs. According to the analysis of the digenetic process, the compaction and cementation can lead to a significant decrease in the petro physical properties of the reservoir. While dissolution can improve the petro physical properties of the sandstone reservoirs to a small extent, and can improve that of the conglomerate reservoirs to a greater extent. Moreover, local fractures are important factors affecting the petro physical properties of the conglomerate reservoirs. The existence of abnormal high pressure has a certain effect on the preservation of primary pores. On the whole, the controlling factors of the petro physical properties of the conglomerate reservoirs in the Baikouquan Formation include sedimentation, diagenesis, and tectonic actives, while that of the sandstone reservoirs mainly include sedimentation and diagenesis.

Influence of supercritical CO2 on the physical property of tight sandstone

In low-pressure gas reservoirs, water-based fracture fluid is difficult to flowback, which is unfavorable for several tight sandstone gas reservoirs in the Sichuan Basin with low pressure and high permeability geological characteristics. Supercritical CO2 possesses a number of remarkable physical and chemical features, including a density near to water, a viscosity close to gas, and high diffusion. Supercritical CO2 fracturing is a new type of non-aqueous fracturing method that is favorable to fracturing flowback in low-pressure tight sandstone and has a wide range of applications. To discuss on whether supercritical CO2 fracturing with low pressure tight sandstone is feasible. Tight sandstone cores from the Jinqiu gas field in the Sichuan Basin were used to study the influence of supercritical CO2 on the physical properties of sandstone reservoirs. Supercritical CO2 was used to interact with tight sandstone samples, and then the changes in porosity, permeability, and rock microstructure of tight sandstone were observed under various time, pressure, and temperature conditions. After the interaction between tight sandstone and supercritical CO2, new dissolution pores will appear, or the original pores will be increased, and the width of some natural fractures will also be increased, and the porosity will increase by 1.09%–8.85%, and the permeability will increase by 2.34%–21.26%, quantifying the influence of supercritical CO2 on physical properties of tight sandstone, and further improving the interaction mechanism between supercritical CO2 and tight sandstone. This study improves in the understanding of the tight sandstone-supercritical CO2 interaction mechanism, as well as providing an experimental foundation and technological guarantee for field testing and use of supercritical CO2 in low-pressure tight sandstone gas reservoirs.

Implication Linkage among Microfacies, Diagenesis, and Reservoir Properties of Sandstones: A Case Study of Dongying Formation, Nanpu Sag, Bohai Bay Basin

The reservoir quality of sandstones is significantly impacted and transformed by sedimentation and diagenesis. It is necessary to clarify the internal relationship among them to precisely predict the sweet reservoir. In this study, five types of sedimentary microfacies are recognized through core observation and logging data: submerged distributary channel (fan delta), submerged interdistributary bay, submerged distributary channel (braided delta), distal bar, and turbidite fan. The major diagenetic processes, including compaction, cementation, and dissolution, have been analyzed based on petrography, scanning electron microscopy, and X-Ray diffraction. The dominant diagenetic cement includes calcite, smectite, kaolinite, illite, and I/S mixed-layer minerals, with small quantities of chlorite, pyrite, siderite, feldspar, and quartz cement. The reservoir quality is best in the submerged distributary channel (fan delta) sandstones, followed by submerged distributary channel (braided delta). Submerged interdistributary bay, distal bar, and turbidite fan are of poor reservoir quality. The grain size is the primary reservoir quality controlling factor, highly affected by sedimentary microfacies. Subsequent controls are diagenetic processes such as mechanical compaction, clay minerals formation, grain replacement, and dissolution that collectively influence the porosity and permeability.

Illitization in the Mt. Simon Sandstone, Illinois Basin, USA: Implications for carbon dioxide storage

Clay mineral cementation is one of the most important controls on sandstone reservoir properties. In this paper, the diagenetic history of the Mt. Simon reservoir complex is studied to reveal the origin, timing, and controls of illitization. Samples of sandstone and shale from Mt. Simon reservoir complex were acquired from the Illinois Basin–Decatur Project (IBDP), a CO2 storage demonstration project in the central Illinois Basin. Petrographic, SEM, TEM, XRD analyses and K/Ar age dating were completed to identify the major detrital and diagenetic components of the samples and reveal illite to be the major clay component in all samples. Illitic clay coatings in the lower Mt. Simon reservoir are identified as a major control on reservoir properties by inhibiting major precipitation of authigenic quartz during illitization, resulting in highly permeable sandstone, essential for CO2 storage. The coating box-work morphology and mineralogy are indicative of a detrital smectite origin with subsequent illite growth associated with feldspar dissolution and kaolinite alteration. The mineralogy of bulk material and separate grain size fractions (2–0.6 μm; 0.6–0.2 μm; < 0.2 μm) with illite polytypes 2M1, 1M, and 1Md were quantified and age dated via 40K-40Ar methods. The shales or reservoir seals contain the highest proportions of detrital illite with illite in the lower Mt. Simon Sandstone reservoir identified as solely diagenetic. Two major events of illitization are identified throughout the Mt. Simon with more porous reservoir rock exhibiting the older event from approximately 360 to 315 Ma and tighter sandstone units with reservoir properties too low to be considered reservoir exhibiting illite dates from 250 to 220 Ma. This partitioning of illitization is attributed to varied mineralogy controlled by depositional changes and evolution of the greater basin.

Characterization of ultra-low permeability tight sandstone reservoir properties and criteria for hydrocarbon accumulation in Chang 6 member, Huaqing area, Ordos basin

How to accurately predict hydrocarbon enrichment and high-yield areas in ultra-low permeability sandstone reservoirs is a hot spot in petroleum geology. Taking the Chang 6 Member of the Yanchang Formation in the Huaqing Area, Ordos Basin as an example, the quantitative characterization and classification criteria of ultra-low permeability sandstone reservoir properties are systematically studied. The research results show that the seismic reflection characteristics of the Chang 6 Member show multi-stage wedge progradation characteristics, reflecting the sedimentary characteristics of the end of the delta front. The maturity of the minerals in the Chang 6 Member sandstones in the study area is very low, it indicates a low degree of transformation of sediments. Three types of sand bodies, namely sandy debris flow, turbidite, and slump rock sand bodies, were identified in the Chang 6 Member of the Yanchang Formation. The pore types of the Chang 6 Member in the study area include intergranular pores, dissolution pores (feldspar, detrital dissolution pores), and intercrystalline pores. Among them, the intergranular pores and feldspar dissolution pores are the most important storage spaces. The study also found that the test oil production is highly correlated with the cumulative thickness of the massive sandstone segments. Therefore, massive sandstone (sand debris flow) is the main contributor to oil well production, and its distribution directly controls the accumulation of oil reservoirs and the high production of oil wells. In addition, geological parameters affecting reservoir enrichment evaluation were analyzed, which include permeability, oil layer thickness, resistivity, and reservoir penetration rate. Finally, the evaluation criteria for hydrocarbon enrichment in the Chang 6 Member were formulated by the analysis of dominant facies, lithologic assemblages and electrical properties.

Physical properties of sandstone reservoirs: Implication for fluid mobility

Core samples representing depths of hydrocarbon-bearing zones are not readily accessible for reservoir evaluations. On the other hand, wireline logs with incorporated seismic data, which can be archived over a more extended period while retaining their original forms, are typically more available for research purposes. Therefore, the study relies on wireline logs with seismic data to predict the reservoirs' fluid mobility by evaluating the hydraulic (flow) units, reservoir depths, fluid saturations, and geothermal gradients. It also indicates the associated water cut (Cw) within Ritchie oil and gas field, Niger Delta considering a three-phase (oil-gas-water-bearing) reservoir (RA) and an oil-saturated reservoir (RB) delineated across three wells (RW1, RW2 and RW3). Research activities combining the presented factors to achieve the stated objectives are not quite common within the study location. It shows lower, average and upper limits of the flow unit factors and irreducible water saturation (Swirr) within the reservoirs. The study shows the relationship between hydraulic units/fluid saturations and fluid mobility/associated Cw within the sandstone reservoirs. It maximises porosity (Ф) for the theoretical flow units' prediction during qualitative and quantitative estimation based on the adopted expressions. Therefore, the study reveals that water saturation (Sw) and hydrocarbon/water ratios substantially control Cw, and other contributing factors include thermal gradients and Swirr. The flow unit factors are also significant and will encourage fluid mobility. The evaluated reservoirs (RA and RB) are below 10 400 ft (3 170 m) across wells RW1, RW2 and RW3 within the Agbada Formation of a geothermal gradient up to 2.7 °C/100 m; therefore, they have good thermal conditions to enhance hydrocarbon mobility and increase Swirr. Hence, the reservoir should feature significant hydrocarbon extraction via primary recovery. The average water cut (Cw-avg.) (12.3%) estimated for reservoir RA is within the acceptable range; therefore, the associated water production from the three-phase reservoir will not be much of a concern. In addition, simple models are presented to aid an alternative approach for predicting reservoir quality and Cw within sandstone reservoirs, especially in the absence of core samples.

Geophysical appraisal of the Abu Madi gas reservoir, Nile Delta Basin, Egypt: Implications for the tectonic effect on the lateral distribution of petrophysical parameters

The tectonic deformation has a significant influence on the hydrocarbon reservoirs properties. The effect of this process focuses on the lateral distribution of the petrophysical parameters characterizing the hydrocarbon reservoirs. The main objective of the current study is to perform a petrophysical examination of the Abu Madi gas reservoir which is the greatest gas-bearing reservoir at Nile Delta Basin in order to examine how far the Messinian tectonics affected the lateral variations of these petrophysical parameters. This petrophysical evaluation was performed based on the wireline log data acquired for five wells, namely, Abu Madi-2, Abu Madi-7, El Qara-3, Nidoco-7, and Nidoco-9 drilled within the Abu Madi Paleo-Valley. The petrophysical assessment for the most promising zone intervals within the Abu Madi sandstones in the inspected wells show that the total porosity varies between 17% and 22%, the effective porosity ranges from 7% to 19%, the shale volume fluctuates between 16% and 30%, hydrocarbon saturation varies from 37% to 76%, and the bulk volume of water varies between 0.02 and 0.09. These significant variations in the petrophysical properties of the Abu Madi reservoir are attributed to the tectonic influence during the deposition of the Abu Madi Formation as a part of the Late Miocene syn-rift megasequence in the Nile Delta Basin. This conclusion confirms that the petrophysical properties of sandstone reservoirs are function of tectonic and structural deformation.

The impact of diagenesis on the reservoir quality of the early Cretaceous Lower Goru sandstones in the Lower Indus Basin, Pakistan

AbstractThe sandstone units of the Early Cretaceous Lower Goru Formation are significant reservoir for gas, oil, and condensates in the Lower Indus Basin of Pakistan. Even though these sandstones are significant reservoir rocks for hydrocarbon exploration, the diagenetic controls on the reservoir properties of the sandstones are poorly documented. For effective exploration, production, and appraisal of a promising reservoir, the diagenesis and reservoir properties must be comprehensively analyzed first. For this study, core samples from depths of more than 3100 m from the KD-01 well within the central division of the basin have been studied. These sandstones were analyzed using petrographic, X-ray diffraction, and scanning electron microscopic analyses to unravel diagenetic impacts on reservoir properties of the sandstone. Medium to coarse-grained and well-sorted sandstone have been identified during petrographic study. The sandstone are categorized as arkose and lithic arkose. Principal diagenetic events which have resulted in changing the primary characters of the sandstones are compaction, cementation, dissolution, and mineral replacement. The observed diagenetic processes can be grouped into early, burial, and late diagenesis. Chlorite is the dominant diagenetic constituent that occurs as rims, coatings, and replacing grains. The early phase of coating of authigenic chlorite has preserved the primary porosity. The recrystallization of chlorite into chamosite has massively reduced the original pore space because of its bridging structure. The current study reveals that diagenetic processes have altered the original rock properties and reservoir characteristics of the Lower Goru sandstone. These preliminary outcomes of this study have great potential to improve the understanding of diagenetic process and their impact on reservoir properties of the Lower Goru sandstone in the Lower Indus Basin and adjoining areas.

Estimation of Mechanical Rock Properties from Laboratory and Wireline Measurements for Sandstone Reservoirs

Mechanical rock properties are essential to minimize many well problems during drilling and production operations. While these properties are crucial in designing optimum mud weights during drilling operations, they are also necessary to reduce the sanding risk during production operations. This study has been conducted on the Zubair sandstone reservoir, located in the south of Iraq. The primary purpose of this study is to develop a set of empirical correlations that can be used to estimate the mechanical rock properties of sandstone reservoirs. The correlations are established using laboratory (static) measurements and well logging (dynamic) data. The results support the evidence that porosity and sonic travel time are consistent indexes in determining the mechanical rock properties. Four correlations have been developed in this study which are static Young’s modulus, uniaxial compressive strength, internal friction angle, and static Poisson’s ratio with high performance capacity (determination coefficient of 0.79, 0.91, 0.73, and 0.78, respectively). Compared with previous correlations, the current local correlations are well-matched in determining the actual rock mechanical properties. Continuous profiles of borehole-rock mechanical properties of the upper sand unit are then constructed to predict the sand production risk. The ratio of shear modulus to bulk compressibility (G/Cb) as well as rock strength are being used as the threshold criterion to determine the sanding risks. The results showed that sanding risk or rock failure occurs when the rock strength is less than 7250 psi (50 MPa) and the ratio of G/Cb is less than 0.8*1012 psi2. This study presents a set of empirical correlations which are fewer effective costs for applications related to reservoir geomechanics.

Seismic characterization of a Triassic-Jurassic deep geothermal sandstone reservoir, onshore Denmark, using unsupervised machine learning techniques

The Triassic-Jurassic deep sandstone reservoirs in onshore Denmark are known geothermal targets that can be exploited for sustainable and green energy for the next several decades. The economic development of such resources requires accurate characterization of the sandstone reservoir properties, namely, volume of clay, porosity, and permeability. The classic approach to achieving such objectives has been to integrate well-log and prestack seismic data with geologic information to obtain facies and reservoir property predictions in a Bayesian framework. Using this prestack inversion approach, we can obtain superior spatial and temporal variations within the target formation. We then examined whether unsupervised facies classification in the target units can provide additional information. We evaluated several machine learning techniques and found that generative topographic mapping further subdivided intervals mapped by the Bayesian framework into additional subunits.

River channel pattern controls on the quality of sandstone reservoirs: A case study from the Jurassic Shaximiao formation of western Sichuan Basin, China

The fluvial sandbodies from river channels with different patterns have remarkable heterogeneities. This study suggests that the pattern of river channel controls on the sandbody stacking pattern, resulting in the heterogeneities of physical properties of sandstone reservoirs. The study area is located in the Gaomiaozi and Zhongjiang areas of western Sichuan depression in China. Based on the observation of cores and interpretation of well logging data of sandstones, three types of lithofacies assemblies and three types of vertical facies stacking patterns are identified to determine the sandbody stacking patterns. The formation of sandbody stacking patterns and ratios of sand/mud were influenced by the sinuosity of river channels, as well as the hydrodynamic condition and the frequently migration of river channels. Three sandbody stacking patterns were identified as homogeneous type composed of massive sandstones with grain size changing vertically (HT), mixed type formed by massive sandstones alternating with thin-bedded mudstones (MT1), and mixed type formed by thin-bedded sandstones wrapped in thick-bedded mudstones (MT2). HT patterns occur in the relatively high-sinuosity river channels (sinuosity index of 1.15–1.25), with sand/mud ratios of 0.65–1.74. MT1 and MT2 patterns occur in the low-sinuosity river channels (sinuosity index of 1.00–1.04), with sand/mud ratios of 0.29–0.91. Because of the long transportation distance before deposition influenced by the loop current, the sands in the relatively high-sinuosity river channels are of good sorting of grain size, with the large grain size and the high compositional maturity. As a result, sandstones deposited in the high-sinuosity river channels have the homogeneous massive pattern and relatively high porosity and permeability. This study proposed that the pattern of river channel controls the quality of fluvial sandstone reservoirs, which can be used to explore the new gas field in the similar geological setting.

Sedimentary facies control on sandstone reservoir properties: A case study from the permian Shanxi Formation in the southern Ordos basin, central China

During the Upper Paleozoic large-scale tight sandstone oil and gas reservoirs developed in the southern Ordos Basin of China. Due to the heterogeneity of sedimentary facies and diagenesis, the reservoir quality of these deposits is extremely uneven. Based on field profile observations, conventional thin section, cast thin section and scanning electron microscope (SEM) analysis, combined with general physical analysis, the sedimentary characteristics, physical properties and main controlling factors of the reservoirs of the Upper Paleozoic Shanxi Formation of the southern Ordos Basin were determined. The results of this contribution show that the Shanxi Formation is dominated by delta facies, with small-scale lacustrine facies. The delta facies can be further divided into distributary channel, natural levee, interdistributary swamp, underwater distributary channel, underwater distributary bay, mouth bar and sand sheet microfacies. Diagenesis within the study area has generally entered the mesodiagenetic B phase. Compaction and cementation were the main destructive stages of diagenesis. While cementation blocked the reservoir pores and reduced the physical properties, dissolution effectively improved the physical properties of the reservoir. The physical reservoir properties of the studied sandstone reservoirs are controlled by different sedimentary microfacies that are mainly, represented by distributary channel, underwater distributary channel and mouth bar microfacies that also show the best properties. These microfacies are followed by sand sheets. The lowest properties can be observed in the natural levees.

Sedimentary facies and diagenesis control on petrophysical properties of sandstone reservoirs: A case study from the Permian Sulige Gas Field, Ordos Basin (Central China)

The sedimentary characteristics and petrophysical properties of the reservoir of the second/lower member of the Lower Permian Shanxi Formation (P1s2) in Sulige Gas Field, Central China are studied by means of thin section petrography and scanning electron microscopy. This article highlights the relationship between reservoir quality and sedimentary environments, explains the differences in reservoir petrophysical properties in different sedimentary environments, discusses the influence of clastic components and authigenic minerals on the reservoir, and finally, provides the basis for the prediction of relatively high‐quality reservoir in P1s2 of the study area. The results show that the sandstones formed as a meandering river deposit in the south of the study area are fine‐grained, mainly composed of lithic fragments of quartz sandstone, metamorphic, and volcanic rock lithic fragment, with high content of matrix and poor sorting, average porosity of 5.09%, and average permeability of 0.20 × 10−3 μm2. The braided river sedimentary deposits in the north are coarse‐grained, mainly composed of quartz sandstone sedimentary rock lithic fragment, with low content of matrix, good sorting, and more developed dissolution pores. The average porosity is 6.16%, and the average permeability is 0.53 × 10−3 μm2. Among the authigenic minerals, siderite, calcite, and illite block, the pores between the grains reduce the porosity. Siliceous cement often indicates better reservoir petrophysical properties. The siliceous cement is more common in braided river deposits in the north area, in which the channel bar detailed facies are conducive to retain more primary pores or form secondary pores, thus forming better reservoirs.

SANDSTONE ROCK PERMEABILITY: IMPACTS OF CLAY MINERALS AND PHYSICO-CHEMICAL VARIABLES

Sandstone is one of the most common reservoir rocks found in sedimentary basins throughout the world. It exhibits porous and permeable characteristics. Clay matrix can usually found in sandstone pores. However, the presence of clay minerals that are very fines in the porous media tends to reduce its petrophysical properties as a reservoir rock. The reservoir properties of sandstone are evaluated, and the effect of clay minerals on the reservoir quality is being determined. This study portrays the effect of different pH levels ranging from 3-12.5 and the impact of salinity on the formation of damage in siliciclastic rocks, leading to the reduction of permeability which is regularly overlooked. This research aims to achieve an in-depth understanding of the relations of clay minerals and the effect of chemicals to the reservoir, particularly in sandstone reservoirs. From this finding, this research will comprehend how clay minerals will affect the petrophysical properties of the reservoir. The permeameter and porosimeter (POROPERM), scanning electron microscopy (SEM), and X-ray diffraction (XRD) analyses will be conducted to identify the petrophysical parameters of sandstone. SEM analysis to be run to accurately determine the location of the clay minerals within the sandstone matrix. X-ray diffraction (XRD) to be run to quantify the amount of clay mineral and to check the whole rock by diagnostic treatment to identify the type of clay minerals.Keywords: sandstone, permeability, clay minerals, saline solution, formation damage

Hybrid event bed distribution in a mixed siliciclastic-calcareous turbidite succession: a cross-current perspective from the Bordighera Sandstone, Ligurian Alps, NW Italy

Transitional flow deposits (TFDs) and hybrid event beds (HEBs) form part of the high-density sediment gravity flow spectrum. They record flow characteristics intermediate between fully turbulent and laminar flow states. The transformation from initially frictional into transitional or quasi-laminar cohesive flow behaviour results from enhanced detrital clay concentrations that dampen flow turbulence, triggering the development of an argillaceous sandstone interval that displays characteristics of a cohesive debris flow deposit. Since excess detrital clay proportions reduce primary porosity and permeability, the presence of TFDs and HEBs hinders turbidite sandstone reservoir properties. In applied scenarios, understanding their spatial distribution is crucial for avoiding well misplacement. Spatial distribution models for TFDs and HEBs largely document them as a characteristic feature of distal and lateral outer fan environments. These models are compared with results from facies analysis conducted on a dataset derived from the detailed investigation of three stratigraphic sections, acquired along a cross-current transect of the distal depositional domain of the Bordighera Sandstone (BGS). In its distal domain, the sand-rich Bordighera turbidite system is characterized by direct interbedding with calcareous fine-grained turbidites of the Sanremo Helminthoid Flysch, and features high proportions of HEBs and TFDs. Analysis of spatial trends in facies distribution allows the detailed allocation of intra- bed- to sandbody-scale heterogeneity to different axial and off-axis lobe sub-environments which are determined through quantitative sedimentological parameters. Results reveal that in the Bordighera turbidite system argillaceous sandstone bed types are not limited to lobe-fringe environments, but instead are primarily occurring in more proximal high net-to-gross zones of the largely unconfined terminal lobe domain. They account for more than 60% of stratigraphic thickness in axial zones (net-to-gross ratio = 0.87), whereas their proportions decrease towards off-axis lobe (36%; net-to-gross = 0.58) and marginal lobe to lobe fringe domains (23%; net-to-gross = 0.49).