Median Pore-throat Radius Research Articles

Controlling factors of fluid mobility in the tuff reservoirs of the Huoshiling formation, Dehui fault depression, southeastern Songliao Basin: insights from micro-nano pore structures

This study addresses the unclear understanding of the primary factors controlling fluid mobility in the tuff reservoirs of the Huoshiling Formation from the Dehui Fault Depression, southeastern Songliao Basin. Through physical property analysis, X-ray diffraction (XRD), field emission scanning electron microscopy (FE-SEM), thin section (TS), pressure-controlled porosimetry (PCP), rate-controlled porosimetry (RCP), and nuclear magnetic resonance experiments (NMR) on ten tuff samples, we conducted a comprehensive and in-depth exploration of the influencing factors that control the mobility of reservoir fluids. The results indicate: 1) The primary mineral types in the tuff reservoirs are quartz, feldspar, and clay minerals, with porosity predominantly characterized by dissolution pores and intergranular pores; 2) Based on the morphology of PCP intrusion curves, the tuff samples from the study area can be categorized into three types, with reservoir quality progressively deteriorating from Type I to Type III; 3) Compared to the movable fluids saturation (MFS), movable fluids porosity (MFP) is more suitable for characterizing fluid mobility. The mobility of fluids is influenced by various factors such as mineral composition, physical property, pore-throat connectivity, pore type and heterogeneity. MFS and MFP show a positive correlation with permeability, the content of quartz and feldspar, median pore-throat radius (R50), average throat radius (ATR), average pore-throat radius ratio (APT), T2 cutoff value (T2-C), average throat radius (RT), sorting coefficient (SC), and intergranular pore dominate space (Inter-DS), while a negative correlation with the content of calcite and clay minerals, average pore-throat radius ratio, and the fractal dimension from NMR (DNMR). This study elucidates the influencing factors of fluid mobility in tuff reservoirs, which has important reference significance for the scientific development of this type of gas reservoir.

Core‐flooding experiments of various concentrations of CO2/N2 mixture in different rocks: II. Effect of rock properties on residual water

AbstractDuring CO2 storage in deep saline aquifers, the presence of residual water has an important influence on the storage efficiency and safety. In this study, natural rock cores taken from deep reservoirs in the Ordos Basin and Fukang, Xinjiang are used as research objects. Nine groups of core‐flooding experiments are performed under different CO2/N2 gas mixture ratios to study the influence of rock properties (mineral composition, permeability, porosity and pore structure) on the residual water. Furthermore, the geophysical and chemical properties of rock cores are analyzed by X‐ray diffraction, electron microscopy, field emission scanning electron microscopy and piezoelectric mercury method. The results show that residual water saturation is a quantitative power function of drainage time. The residual water saturation is positively correlated with the total amount of quartz and feldspar and increases with increasing permeability. Moreover, both the average and median pore throat radius show a strong inverse correlation with irreducible residual water saturation; as these radius increase, the residual water saturation decreases. In contrast, the porosity and maximum pore throat radius display a weaker correlation with irreducible residual water saturation. This study is of great value for engineering practices such as the site selection of CO2 storage projects in saline aquifer and improvement of CO2 storage efficiency. © 2024 Society of Chemical Industry and John Wiley & Sons, Ltd.

Characteristics, main controlling factors and densification mechanisms of unconventional tight reservoirs in Triassic Yanchang Formation in southern Ordos Basin, China

The key factors controlling the densification of unconventional reservoirs (e.g., tight oil and gas reservoirs) remain poorly understood and directly affect the distribution of exploitable resources. Here, systematically explored reservoir characteristics, depositional microfacies, and the main factors controlling densification of the tight oil reservoir in the Chang 8 Member (Yanchang Formation, Middle Triassic) in the Zhenjing area of the southern Ordos Basin by thin section analysis, scanning electron microscopy, physical property measurement, X-ray diffraction, and mercury injection. Our results confirm the Chang 8 reservoir as an extremely low permeability tight sandstone reservoir mainly comprising lithic feldspathic sandstone with various primary and secondary pores and fine pore channels. The highest quality reservoir is mainly restricted to the middle and lower parts of subaqueous distributary channel microfacies. Dissolution partly contributed to reservoir formation, but the persistence of early, non-compressed storage space was more important. The compression of plastic rock debris removed a significant amount of porosity, and calcite and kaolinite both fill pores and contribute to the structural strength of pore space. We identified three densification processes: the persistent densification of highly plastic rocks, calcite cementation, and feldspar dissolution and subsequent kaolinite precipitation. After their compaction, the Chang 8 Member reservoirs were charged with hydrocarbons. We applied clustering analysis to eight reservoir characteristics (porosity, permeability, median pore-throat radius, maximum pore-throat radius, median capillary pressure, pore discharge pressure, chlorite content, kaolinite content) to quantitatively classify the Chang 8 reservoir into three categories. Type-I reservoirs have the best conditions for hosting tight oil reservoirs, with ∼12% porosity, permeabilities of ∼0.2 × 10−3 μm2, trial oil production rates of >5 m3/d, and, indeed, occur in subaqueous distributary channel microfacies. Type-II reservoirs ∼10% porosity, permeabilities of ∼0.1 × 10−3 μm2, and trial oil production rates of 1–5 m3/d. Type-III reservoirs have ∼5% porosity, permeabilities of ∼0.05 × 10−3 μm2, and trial oil production rates <1 m3/d. These results provide an important basis for predicting the distribution of exploitable zones in the Chang 8 sandstone and other adjacent tight sandstones.

A field study of pore-network systems on the tight shale gas formation through adsorption-desorption technique and mercury intrusion capillary porosimeter: Percolation theory and simulations

Properly identifying microscopic pore structure properties of shale reservoirs is essential for developing efficient extraction techniques of shale hydrocarbons. To understand the unique and complex pore network of the Northern Guizhou shale reservoir, shale samples from the Wufeng-longmaxi Formation were investigated using different analytical techniques, X-Ray Diffractometry, low-pressure nitrogen gas adsorption-desorption isotherms, and Mercury intrusion capillary porosimeter. Results indicate that the Wufeng-longmaxi formation is mainly composed of a high quantity of quartz ranging from 0.6 % to 64.1 % and an average extent of 55.825 %, the lowest amount of potassium feldspar ranging from 0.6 % to 2.2 % and an average extent of 1.45 % with Total organic contents ranging from 3.672 to 5.209 %. Similarly, the BJH adsorption techniques for pore volume and area were investigated. The results indicate the dominance of the mesopore with pore size ranging from 2.03 nm to 40nm, average pore volume of 0.073715 m3/g, and average pore area of 13.0324 m2/g. The pore throat distributions from MICP showed drain pressure and median pore throat radius ranging from 0.47 to 13.79 MPa and 0.05–0.08 μm, respectively. Suggested complementary experimental techniques reveal the connectivity of pore networks of the Wufeng-longmaxi Formation shale reservoir, which shows a high production potential of hydrocarbons. The findings of this study can provide a valuable understanding of fluid transport properties and storage space of shale gas that can help decision-makers as they set exploration initiatives for shale gas reservoirs.

Reservoir Quality Under the Control of Gravity Flows in the C7 Member of Yanchang Formation in the Jinghe Oilfield, Ordos Basin, China

The late Triassic sandstone reservoir in the C7 member of the Jinghe oilfield southern Ordos basin is a typical deep-water gravity flow tight oil reservoir. Sedimentary microfacies, physical properties, and petrographic analysis were being examined for quality determination. Pore structure and physical properties data together combined with, thin sections, and scanning electron microscope and core images were used to identify factors controlling reservoir physical properties. The depositional system under debates of different gravity flows including debris flow, seismite slumping, and turbidity flows. Among which sandy debris flow facies shows a better distribution of porosity and permeability followed by seismite-slump, where turbidity facies are the poorest. The petrophysical analysis shows that the study oil interval is a typical tight sandstone reservoir with an average porosity of 9% and permeability average being 0.025mD. The rock classification criteria of the C7 sandstone reveal the sub-categories of lithic feldspar sandstone and feldspar lithic sandstone. Average quartz sandstone contents of 48.25%, average feldspar sandstone content being 25%, and lithic fragments content of 29%. The formation lithology comprises mostly fine-grained sandstone and small pore size, which disclose that the porosity-permeability distribution increases proportional to the average and median pore throat radius, and decreases with average and median pressure. The microfacies distribution shows that the depositional facies controlled physical properties. The sandstone primary pores are affected by the mineral composition of quartz, feldspar, illite, smectite, kaolinite, calcite, and dolomite. Features such as dissolved pores and intergranular pore filling by feldspar, silky-like aggregates of illite-smectite intergranular pore filling and most diagenetic minerals influenced the sandstone pores beside the compaction.

Quantitative Prediction of Rock Pore-Throat Radius Based on Deep Neural Network

Pore-throat radius is one of the key parameters that characterizes the microscopic pore structure of rock, which has an important impact on oil-gas seepage and the prediction of remaining oil’s microscopic distribution. Currently, the quantitative characterization of a pore-throat radius mainly relies on rock-core experiments, then uses capillary pressure functions, e.g., the J-function, to predict the pore-throat radius of rocks which have not undergone core experiments. However, the prediction accuracy of the J-function struggles to meet the requirements of oil field development during a high water-cut stage. To solve this issue, in this study, based on core experimental data, we established a deep neural network (DNN) model to predict the maximum pore-throat radius Rmax, median pore-throat radius R50, and minimum flow pore-throat radius Rmin of rocks for the first time. To improve the prediction accuracy of the pore-throat radius, the key components of the DNN are preferably selected and the hyperparameters are adjusted, respectively. To illustrate the effectiveness of the DNN model, core samples from Q Oilfield were selected as the case study. The results show that the evaluation metrics of the DNN notably outperform when compared to other mature machine learning methods and conventional J-function method; the root-mean-square error (RMSE), mean absolute error (MAE), and mean absolute percentage error (MAPE) are decreased by 14–57.8%, 32.4–64.3% and 13.5–48.9%, respectively, and the predicted values are closer to the true values of the pore-throat radius. This method provides a new perspective on predicting the pore-throat radius of rocks, and it is of great significance for predicting the dominant waterflow pathway and in-depth profile control optimization.

Pore-Throat Structure and Fractal Characteristics of Tight Sandstones: A Case Study from the Chang 63 Sublayer, Southeast Ordos Basin

The micropore-throat structure is a controlling factor on the capacity of storage and seepage for the tight sandstone reservoirs. Therefore, quantitatively analyzing the pore-throat structure is crucial for realizing the oil accumulated in the tight reservoirs. To study the micropore-throat, a battery of experiments such as casting thin sections, scanning electron microscopy, high-pressure mercury injection, and the petrophysical characteristics of reservoirs were conducted on ten samples gathered in the Late Triassic Chang 63 sublayer in the Southeast Ordos Basin, China. The main pore types of the samples are intergranular pores, feldspar dissolved pores, and intergranular dissolved pores. Meanwhile, the pore-throat structure of each sample was identified as large pores, medium pores, and small pores by combining the result of HPMI with fractal theory. The corresponding mean values of the fractal dimension D for large, medium, and small pores are 2.83, 2.69, and 2.31, respectively, indicating that the complex structure and strong heterogeneity were presented in the large pores according to the maximum fractal dimension. In addition, the fractal dimension of the medium pores ( D P − 2 ) has a negative correlation with porosity, permeability, median pore-throat radius, maximum mercury saturation, mercury withdrawal efficiency, displacement pressure, and content of quartz, while a positive correlation with feldspar content, sorting coefficient, and coefficient of variation. Thus, the reservoir space and seepage capacity of all samples in this study were determined by the size, complexity, and distribution of the medium pores. Furthermore, the content of quartz contributes to the storage of the reservoir and the homogeneity of the pore-throat structure, thereby the storage capacity improves with the increase of quartz content. Feldspar dissolution pores are developed widely in the study area, leading to various pores with diverse types, sizes, complex structures, and large fractal dimensions. Although the storage capacity of tight sandstone reservoirs was enhanced with increasing feldspar content, the pore-throat structure complexity was also stronger, resulting in the reduction seepage capacity of fluid.

Study on the evaluation method and application of logging irreducible water saturation in tight sandstone reservoirs

Abstract Taking into consideration the difficulties in predicting the properties of liquid production and evaluating the irreducible water saturation of low-porosity and ultra-low-permeability sandstone reservoirs, the relationships between the irreducible water saturation and logging reservoir evaluation parameters are explored based on a large number of core mercury injection experiment. When the permeability cumulative contribution value reaches 99.9%, the lower limit of pore throat radius is determined as 0.025 μm and the corresponding irreducible water saturation is more accurate. The experimental results of 77 samples in the research area showed that the irreducible water saturation has a good correlation with the median pore throat radius which has a good correlation with the porosity. The irreducible water saturation is consistent with the nuclear magnetic experiment results. Therefore, a new method to determine the irreducible water saturation based on logging data is established. The application results of this method in tight sandstone reservoirs in the Keshen area show that the fluid types identified by the relationship between the calculated irreducible water saturation and total water saturation are consistent with the actual test results, which confirms the accuracy and feasibility of this method. This method solves the problem of irreducible water saturation evaluation in low-porosity and ultra-low-permeability sandstone reservoirs. In the field or other situations where core testing is lacking, accurate irreducible water saturation can be obtained based on only porosity. It also lays a foundation for further improving the prediction accuracy of fluid properties, which has broad application prospects.

Characterization and Evaluation of Carbonate Reservoir Pore Structure Based on Machine Learning

The carboniferous carbonate reservoirs in the North Truva Oilfield have undergone complex sedimentation, diagenesis and tectonic transformation. Various reservoir spaces of pores, caves and fractures, with strong reservoir heterogeneity and diverse pore structures, have been developed. As a result, a quantitative description of the pore structure is difficult, and the accuracy of logging identification and prediction is low. These pose a lot of challenges to reservoir classification and evaluation as well as efficient development of the reservoirs. This study is based on the analysis of core, thin section, scanning electron microscope, high-pressure mercury injection and other data. Six types of petrophysical facies, PG1, PG2, PG3, PG4, PG5, and PG6, were divided according to the displacement pressure, mercury removal efficiency, and median pore-throat radius isobaric mercury parameters, combined with the shape of the capillary pressure curve. The petrophysical facies of the wells with mercury injection data were divided accordingly, and then the machine learning method was applied. The petrophysical facies division results of two mercury injection wells were used as training samples. The artificial neural network (ANN) method was applied to establish a training model of petrophysical facies recognition. Subsequently, the prediction for the petrophysical facies of each well in the oilfield was carried out, and the petrophysical facies division results of other mercury injection wells were applied to verify the prediction. The results show that the overall coincidence rate for identifying petrophysical facies is as high as 89.3%, which can be used for high-precision identification and prediction of petrophysical facies in non-coring wells.

Sealing capability of the Eocene–Miocene Horda and Lark formations of the Nini West depleted oil field – implications for safe CO2 storage in the North Sea

The Nini West depleted oil field in the Siri Canyon, Danish North Sea, is considered a potential storage site for safe sequestration of CO2 to fulfill Denmark's ambition to reduce CO2 emissions using carbon capture storage (CCS) technologies. The Paleocene Nini West sandstone reservoir is overlain by several caprocks forming a 900 m thick seal complex composed of the regionally distributed Eocene–Miocene Horda and Lark formations. The integrity and capacity of the seal complex has been evaluated using a multidisciplinary analytical approach integrating organic and inorganic compositional data, physical properties, wireline logs, and mud gas data. The seal complex consists of clay-dominated mudstones with a relatively homogenous lithology constituting a tight seal. Mud gas logs are introduced as a novel proxy for seal integrity in a CCS context, and they show only very limited vertical gas migration has occurred from the reservoir into the basal part of the seal. Average porosities range from ∼15–20% and both measured and modelled average permeabilities range from only 0.11–0.39 μD. The seal mudstones have narrow unimodal pore throat size distributions, and 40% of the samples have extremely small median pore throat radius r50. The seal has high supercritical (sc)CO2 displacement pressures, and it can hold back a vertical column of scCO2 of minimum ∼600 m providing a comfortable seal safety column-overhead. The current findings have relevant application to other depleted oil fields and saline aquifers with similar seals in the larger Central Graben area in the North Sea.

Pore Structural Features of Granite under Different Temperatures.

To explore the effects of thermal actions on the pore structural features of granite, scanning electron microscope (SEM) and mercury injection experiments were carried out on granite after thermal treatment (25 °C to 400 °C). The pore structure was investigated from various perspectives, including the capillary pressure curve, the pore–throat ratio, the median saturation pressure, the median pore–throat radius, the porosity, the pore volume, and the pore size distribution. Based on mercury intrusion test data, the Winland model of permeability prediction was modified for a high-temperature tight granite reservoir. The results showed that: (1) As the temperature rose, the mercury injection curve was gradually flattened, and the mercury ejection efficiency gradually increased. Meanwhile, the pore–throat ratio and the median saturation pressure decreased exponentially, and the pore connectivity was enhanced. (2) The median pore–throat radius and the porosity of granite increased exponentially as the temperature increased. Above 200 °C, the median pore–throat radius and the porosity increased substantially. (3) The pore volumes of the transitional pores, mesopores and macropores, and the total pore volume inside the granite, increased as the temperature rose. Especially above 200 °C, the transitional pores and the mesopores were prominently developed, and the pore volumes of the transitional pores and the mesopores took up a significantly greater proportion of the total pore volume. (4) As the temperature rose, the pore size distribution of granite became more extensive, the pore–throat structure was obviously developed, and the pore–throat connectivity was enhanced. (5) The relationship between the micropores’ characteristic parameters and the macro-permeability in engineering was established though a modified Winland model, and the modified Winland model had a better prediction effect. The findings provide a solid basis for rock geothermal mining projects and related geotechnical engineering.

Estimating the nuclear magnetic resonance surface relaxivity of Eocene sandstones: A comparison of different approaches

Nuclear magnetic resonance (NMR) relaxometry typically involves the analysis of a relaxation time distribution. The surface relaxivity ([Formula: see text]) is the key parameter that relates the relaxation time to the pore radius. Only a good estimate of the surface relaxivity enables a reliable determination of the pore radius distribution in a rock or sediment sample. A wide variety of approaches for the estimation of [Formula: see text] has been proposed; however, the accuracy of [Formula: see text] determination approaches has rarely been checked. We have compared different approaches of [Formula: see text] determination for a set of Eocene sandstone samples. Most approaches based on a weighted logarithmic mean of relaxation times or the peak relaxation time result in significant underestimation of [Formula: see text]. However, the correct weighting of the set of relaxation times has proven to be a crucial approach in [Formula: see text] determination. The consequent application of geometric rules suggests the application of the weighted harmonic mean ([Formula: see text]). The specific surface area per unit pore volume ([Formula: see text]), which results from the gas adsorption method, is another crucial parameter in most approaches for [Formula: see text] estimation. The quantities [Formula: see text] and [Formula: see text] depend on the resolution of the used method. Applying the fractal theory, we adopt an approach that performs an upscaling of [Formula: see text] to the resolution of the NMR relaxometry. Using equal resolution for [Formula: see text] and [Formula: see text], we obtain more reliable [Formula: see text] estimates. The resulting [Formula: see text] values are comparable with the ones determined by using the median relaxation time from NMR and the median pore-throat radius from the mercury injection capillary pressure method.

Physico-mechanical performance of debris-flow deposits with particular reference to characterization and recognition of debris flow-related sediments

To characterize and recognize the debris flow-related deposits, the physico-mechanical performance of four deposits from the Dongyuege (DYG), Shawa (SW), Jiangjia Gully (JJG), and Gengdi (GD) debris flows in southwest China is investigated through laboratory analyses and tests. The four debris-flow materials can all be remolded into coherent, homogeneous cylinders with high densification and strength–porosity of 25%–36%, mean pore-throat radius of 0.46–5.89 µm, median pore-throat radius of 0.43–4.28 µm, P-wave velocity of 800–1200 m/s, modulus of elasticity of 28–103 MPa, unconfined compressive strength (UCS) of 220–760 kPa, and cohesion of 65–281 kPa. Based on the comparison in slurryability and formability among debris-flow deposits, granular flow deposits, fluvial deposits, residual lateritic clay and loess, whether a sediment can be cast into competent cylinders for physico-mechanical tests can be regarded as a diagnostic evidence of old debris-flow deposits. The discrepancy in physico-mechanical properties among the four debris-flow deposits suggests that the combination of foregoing physico-mechanical parameters can characterize assembling characteristics of debris flow-related sediments including grain size distribution, mineralogy, and accidental detritus. Four deposited sediments above can be surprisingly classified as hard soil-soft rocks according to UCS, and the hard soil-soft rock behaviors can advance the further understanding of debris flows.

Fractal characterization of pore structure and its influence on salt ion diffusion behavior in marine shale reservoirs

Hydraulic fracturing becomes a significant way to develop fossil hydrogen energy from marine shale. Some marine shale formations have a higher salt ion concentration in flowback fluid, about which the mechanism is still unclear. In this study, both the fractal characterization of pore structure and its influence on salt ion diffusion was researched. The fractal dimension D1 can reflect the roughness of pore surface, and the fractal dimension D2 can reflect the complexity of pore structure. The fractal dimension D1 of Sichuan Niutitang Formation is only 2.0069 and the ones of other shale samples are between 2.5291 and 2.6341, which means that the pore surface of Sichuan Niutitang Formation is far smoother than the ones of other samples. The fractal dimension D2 ranges from 2.7396 to 2.9546, which indicates that all samples have complex pore structure. The salt ion diffusion rate is mainly controlled by specific surface area, median pore-throat radius and clay content. A higher specific surface area provides more surface for the interaction between liquid and matrix, and lots of salt ion was released into imbibed liquid. A larger median pore-throat radius benefits to salt ion diffusing out of sample, thus a higher salt ion diffusion rate appears. The liquid can cause the clay-swelling which has the potential to reduce the salt ion diffusion channel, thus the higher the clay content, the lower the salt ion diffusion rate. Our research is conducive to understanding the fractal characterization of marine shale and its impact on high salt ion concentration in flowback fluid.

Experimental investigation of the petrophysical properties, minerals, elements and pore structures in tight sandstones

Geological conditions on the eastern margin of the Ordos Basin are complex, and the amount of oil and gas exploration is low. In this paper, taking the S block in the eastern Ordos Basin as an example, we investigated the petrophysical properties, minerals, elements and pore structures of the middle Permian Shihezi Formation tight sandstones. The results show that the main lithologies of the target layer are lithic feldspar sandstone, lithic quartz sandstone, feldspar lithic sandstone and lithic sandstone. The pore types include residual intergranular pores, intergranular dissolution pores, intragranular dissolution pores, intercrystalline pores and microfractures. The porosity of the rock samples ranges between 1.4% and 19.5%, with an average of 9.95%; the permeability varies between 0.030 mD and 1.941 mD, with an average of 0.342 mD; and the water saturation is distributed between 1.0% and 69.5%, with an average of 30.7%. The water saturation of rock samples has negative correlations with porosity and permeability. Both displacement pressure (Pd) and median pressure (Pm) have good negative correlations with rock permeability. The median pore throat radius (rm) has a good positive correlation with rock permeability. Large pores with a throat radius greater than 0.1 μm are most favorable for rock permeability. The Al/(Al + Fe + Mn) values of the rock samples range from 0.67 to 0.80, indicating that the silica in the rock was not affected by hydrothermal fluid during the formation process. The Si/(Si + Al + Fe) values of the rock samples range from 0.69 to 0.78, with an average of 0.73. Si has good positive correlations with Si/Al, Al/(Al + Fe + Mn) and Si/(Si + Al + Fe). The sedimentary environment of the Shihezi Formation sandstone was characterized by fresh water, a dry-hot climate and oxidizing conditions. The major elements correlate well with the pore structure parameters: as the debris particles or quartz grains increase, the petrophysical properties gradually improve. Finally, based on the petrophysical properties, minerals, elements and pore structure parameters, classification criteria for the pore structure of the Shihezi Formation tight sandstones in the study area are proposed.

Classification of tight sandstone reservoirs based on NMR logging

The traditional reservoir classification methods based on conventional well logging are inefficient for determining the properties, such as the porosity, shale volume, J function, and flow zone index, of the tight sandstone reservoirs because of their complex pore structure and large heterogeneity. Specifically, the method that is commonly used to characterize the reservoir pore structure is dependent on the nuclear magnetic resonance (NMR) transverse relaxation time (T2) distribution, which is closely related to the pore size distribution. Further, the pore structure parameters (displacement pressure, maximum pore-throat radius, and median pore-throat radius) can be determined and applied to reservoir classification based on the empirical linear or power function obtained from the NMR T2 distributions and the mercury intrusion capillary pressure curves. However, the effective generalization of these empirical functions is difficult because they differ according to the region and are limited by the representative samples of different regions. A lognormal distribution is commonly used to describe the pore size and particle size distributions of the rock and quantitatively characterize the reservoir pore structure based on the volume, mean radius, and standard deviation of the small and large pores. In this study, we obtain six parameters (the volume, mean radius, and standard deviation of the small and large pores) that represent the characteristics of pore distribution and rock heterogeneity, calculate the total porosity via NMR logging, and classify the reservoirs via cluster analysis by adopting a bimodal lognormal distribution to fit the NMR T2 spectrum. Finally, based on the data obtained from the core tests and the NMR logs, the proposed method, which is readily applicable, can effectively classify the tight sandstone reservoirs.

Pore structure and multi-fractal analysis of tight sandstone using MIP, NMR and NMRC methods: A case study from the Kuqa depression, China

The pore structure and fractal characteristic of tight gas sandstone from Cretaceous Bashijiqike Formation in Kuqa depression were investigated, using thin section, scanning electronic microscope (SEM), mercury intrusion porosimetry (MIP), nuclear magnetic resonance (NMR) and NMR cryoporometry (NMRC) measurements. The pores of tight sandstone samples mainly contain residual primary intergranular pores, intergranular and intragranular dissolved pores, micropores related to clay aggregates and microfractures. The MIP, NMR and NMRC analyses show that the pore structure of tight sandstone is complex and heterogeneous at different pore scales, displaying as a multi-fractal feature. Fractal dimension Dg-s (with respect to small pore throats) from MIP and Dn-l (long T2 relaxation time, representing large pores and fractures or movable-fluid pores) are negatively correlated with porosity, permeability, median pore throat radius and skewness, and have inverse relationships with bound water saturation (Sbnd). Fractal dimension Dg-b (>3.0, with respect to larger pore throats) and Dn-s (<2.0, short T2 relaxation time, representing small pores or bound-water pores) from NMR don't present clear relationships with most of pore structure parameters. Fractal dimension Dc-1 and Dc-2 from NMRC show more complex or inconspicuous relationships with pore structure parameters, in the pore diameter size <500 nm. Hence, Dg-s from MIP and Dn-l from NMR can be considered as effective parameters for pore structure and fluid properties characterization of tight sandstone. Fractal dimension Dg-b (>3.0) and Dn-s (<2.0) have no practical significance to characterize the pore structure of tight sandstone. The formation of residual primary intergranular pores and intergranular dissolution pores can reduce the fractal dimension which could be an important sign of effective reservoirs in the study area.

Matching between the diameter of the aggregates of hydrophobically associating polymers and reservoir pore-throat size during polymer flooding in an offshore oilfield

Abstract In order to quantitatively study the matching between hydrophobically associating polymers (HAPs) and reservoir pore-throat size in offshore oilfields, the geological characteristics and fluid properties of the S area reservoir in the Bohai Oilfield were used as a research platform. After determining the matching of HAP solutions with different association degrees and core permeabilities using a seepage experiment at a constant flow rate, the matching between the diameter of the HAP aggregates (Dh) and the median pore-throat radius was quantified by combining the relationship between core permeability and median pore-throat radius. Finally, the importance of matching on the oil displacement effect of the HAP solution was demonstrated using homogeneous cores and heterogeneous cores with separate injection and production interlayers. The results showed that the diameter of the HAP aggregates, as well as their morphology and ability to increase viscosity, were highly related to the association degree of HAP. As the association degree of HAP was varied, the matching between cores with different permeabilities and the beta-cyclodextrin (β-CD)/HAP compound systems also changed. Under the experimental conditions used in this study, the ratio between the median pore-throat radius and Dh ranged from 4 to 7. During the process of HAP flooding, suitably increasing the Dh, i.e., increasing the association degree between HAP molecules, could allow control of the mobility of the HAP solution. The oil displacement effect of HAP was closely related to the matching between the HAP and reservoir pore-throat, rather than the viscosity of the HAP solution. Good matching between the HAP and reservoir pore-throat not only achieves fluid diversion but can also expand the swept volume in the low-permeability layer to ensure good oil displacement ability.

Quantitative Analysis of Micron-Scale and Nano-Scale Pore Throat Characteristics of Tight Sandstone Using Matlab

Based on micro-scale casting thin sections, nano-scale SEM images, and the pore distribution map identified through a binary image in Matlab, the pore size distribution and pore throat coordination number of the strata of Upper Paleozoic He8 section tight sandstone in the southeastern Ordos Basin were quantitatively analyzed with the above experimental data. In combination with a high-pressure mercury injection experiment, the pore throat distribution, the pore throat ratio, and the relationships between the characteristics, parameters, and pore permeability were investigated clearly. The results show that the tight sandstone pore space in the study area is dominated by micron-sized intergranular pores, dissolved pores, and intragranular pores. The nano-scale pore throat consisted of clay minerals, intercrystalline pores, and the flake intergranular pores of overgrowth quartz grains. Kaolinite and illite intercrystalline pores occupy the pore space below 600 nm, while the ones above 800 nm are mainly dominated by the intergranular pores of overgrowth quartz grains, and the 600–800 nm ones are transitional zones. The permeability of tight sandstone increases with the average pore throat radius, sorting coefficient, median pore throat radius, and average pore throat number. The porosity is positively correlated with the average pore radius and the average pore throat coordination number, and negatively correlated with the median pore throat radius.

Effect of kaolinite as a key factor controlling the petrophysical properties of the Nubia sandstone in central Eastern Desert, Egypt

This paper presents the results of a comprehensive petrographical and petrophysical investigation for the Late Cretaceous Nubia sandstone from Wadi Kareem in central Eastern Desert to measure their fluid flow properties and to investigate the effect of kaolinite on their petrophysical characteristics.From the petrographical analyses, scanning electron microscope ‘SEM’ and the X-ray diffraction ‘XRD’ analysis, it is shown that the studied sandstone samples are quite homogeneous in mineralogy and can be distinguished into four sedimentary microfacies: quartz arenite as a clean sandstone as well as three kaolinitic microfacies; namely they are kaolinitic quartz arenite, kaolinitic subarkose, and calcareous to kaolinitc quartz arenite. The main recognized diagenetic processes that prevailed during the post-depositional history of the Nubia sandstone are; compaction, cementation, alteration and dissolution of feldspar into kaolinite.The petrophysical potentiality of the studied sandstones was studied using the helium pycnometer, gas permeability and mercury injection confining pressure ‘MICP’ techniques. The investigated sandstones can be classified into three petrophysical facies with varying reservoir performances. The petrophysical behaviour of these facies is dependent mostly on their kaolinite content and its impact on porosity, permeability, irreducible water saturation, R35 (pore aperture corresponding to mercury saturation of 35% pore volume), R50 (median pore-throat radius), and MHR (the mean hydraulic radius). Therefore, the studied petrophysical facies are comparable to the distinguished petrographical facies.