Pore Throat System Research Articles

Wettability and Its Controlling Factors of Mixed Shale Oil Reservoirs: A Case Study of Permian Lucaogou Formation in Jimusar Sag

Abstract Due to diverse mineral composition and complex lithology, mixed shale oil reservoir wettability features and the associated controlling factors remain unclear, limiting the evaluation of the oil-bearing property and sweet spot distribution. This paper examined mixed shale oil samples from the Jimusar Sag in the Lucaogou Formation. Casting thin sections, X-ray diffraction, geochemical characteristics, argon ion polishing scanning electron microscope, and high pressure mercury injection were used to analyze lithologic characteristics, mineral compositions, and pore-throat structures within the mixed shale oil reservoir. Using spontaneous imbibition and nuclear magnetic resonance, the wettability characteristics were analyzed. Impacts of organic matter abundance, mineral composition, pore-throat structure, and source-reservoir combination on wettability were discussed. The Lucaogou mixed shale oil reservoir primarily contains intergranular dissolved pores, intragranular dissolved pores, and intercrystalline pores. Three types of mercury intrusion cures were observed, including a weak platform shape (type I), gentle straight line shape (type II), and upward convex shape (type III), corresponding to intergranular, dissolved, and dissolved-intercrystalline dominant pore-throat systems, respectively. Mixed shale oil reservoirs show dual wet properties, containing both oil-wet and water-wet pores. Oil-wet pores (large pores with T2>1 ms) are more common and have better connectivity than water-wet pores (small pores with T2<1 ms). Dolomite-bearing siltstone and mudstone are primarily strongly oil-wet, while siltstone is primarily mixed wet. Type II and type III pore-throat systems are more oil-wet than type I for the same source-reservoir combination. Mixed shale oil reservoir wettability is primarily controlled by three factors, including organic matter abundance, source-reservoir combination, and dolomite content. The influence of the pore-throat structure is weak. High organic matter abundance, an integrated source-reservoir or adjacent source-reservoir, and appropriate dolomite content are necessary conditions for forming a strong oil-wet shale oil reservoir in the Lucaogou Formation. Stronger oil-wet is beneficial for shale oil charging and enrichment.

Experimental Study on Changes in Pore Throat Systems Owing to Liquid CO2 Cooling in Shale Oil Reservoirs

Experimental Study on Changes in Pore Throat Systems Owing to Liquid CO₂ Cooling in Shale Oil Reservoirs

Classification and control factors of pore-throat systems in hybrid sedimentary rocks of Jimusar Sag, Junggar Basin, NW China

Aiming at the complicated problem of the genesis of high-quality hybrid sedimentary rocks, the pore-throat systems, controlling factors and fluid mobility of hybrid sedimentary rocks in the Permian Lucaogou Formation in Jimusar Sag were examined. The results show that the hybrid sedimentary rocks contain 5 types of pore-throat system, intergranular (Type A), mixed intergranular-dissolved-intercrystalline (Type B), dissolved (Type C), mixed dissolved-intercrystalline (Type D) and intercrystalline (Type E) ones. The pore-throat systems are controlled by 3 major factors, the component content and arrangement (CCA) of hybrid sedimentary rocks, sedimentary environment and diagenesis. CCA controls the matrix support mode of hybrid sedimentary rocks, and therefore controls the types and changes of pore-throat system. The sedimentary environment mainly controls the macroscopic distribution of pore-throat system, i.e., hybrid sedimentary rocks deposited in the near source and high-energy environment are characterized by high content of coarse-grained component, granular/interbedded-support mode, and development of Type A and Type B pore-throat systems. Hybrid sedimentary rocks deposited in the medium-energy environment far from source are characterized by dolomitic/mud support mode and Type C and Type D pore-throat systems. Hybrid sedimentary rocks deposited in low-energy environment far from source have mainly Type E and Type D pore-throat systems. Diagenetic processes such as compaction and calcite cementation make the proportions of Type A and Type C pore-throat systems decrease further. In the hybrid sedimentary process of sandy-mud, pore-throat system types show a change of “A→B→C→D”, in that of dolomite-sand, pore-throat system types show a change of “A→C→D→E” or “B→D→E”, and in that of dolomite-mud, pore-throat system types show a change of “D→E”, which are affected in details by the contents of coarse-grain component, feldspar and dolomite. The reservoir with Type A pore-throats has the best physical properties and fluid mobility, and the reservoirs with Type D and Type E pore-throats have the poorest. The movable fluid distribution is related to the matrix support mode, and the larger pores in hybrid sedimentary rocks of dolomite/mud support mode have no obvious advantage in fluid mobility. The findings of this study provide a geological basis for evaluating and building reasonable interpretation model of hybrid sedimentary rocks sweet spot.

Numerical Simulation Study of Pore-Throat Evolution of Upper Paleozoic in Ordos Basin, China

The parameters of grain size, contents of silica, kaolinite, hydromica, calcite, and a geological time of tight sandstone reservoirs in Upper Paleozoic in Ordos basin were researched thoroughly, and the impact of the diagenetic evolution process of different sandstone types on porosity and throats was analyzed, based on the quantitative statistics from thin sections, measurements of porosity and permeability, and conventional and constant-rate mercury injection tests. We not only build the evolution of porosity through process-oriented numerical simulations during the geological time but also establish effect-oriented numerical simulations between porosity and different diagenesis parameters. Furthermore, we set up a fitting relationship between diagenetic factors and pore throats in different gas-bearing reservoirs. Differentiation results in the evolution of porosity and a pore-throat system of sandstone types have clear characteristics, such as lithic quartz sandstones of the He 8 Member in the Sulige area and quartz sandstones of the Shan 2 Member in the Yulin area. The fitting results show that the main factors influencing the evolution of porosity and a pore-throat system are grain size and siliceous cement, which can also be validated by the measured data on two gas-bearing intervals. The results are important to a deep understanding of the relationship between the reservoir continuing to experience porosity and permeability evolution and the timing of petroleum charging into the reservoir and can also be applied elsewhere as a quick means in high grading areas of risks during field development.

Insights into the Pore Structure of Strong Heterogeneous Carbonates in the Mesopotamian Basin

The Cretaceous Late Cenomanian-Early Turonian Mishrif Formation carbonates in the Mesopotamian Basin are characterized by complex pore systems, resulting in strong reservoir quality heterogeneity. Major factors that constitute the complexity of pore structure are types, geometries, and topologies of pores and pore-throats. These factors and the effect of pore structure on reservoir quality were investigated by integration of thin sections, petrographic image analyses, porosity, permeability, and mercury injection capillary pressure measurements. Eight matrix-related and three matrix-unrelated pore types, which are dominated by secondary pores, are identified in the Mishrif carbonates. Pore sizes range from a few microns to more than 1 cm and vary greatly both in the same and in different pore types. Pore shapes range from better circularity and simple boundaries to irregular complex boundaries and similar for the same pore type. Pore-throat radii (PTR) range from 3 nm to 124 μm, and micro pore-throats occur in all carbonates in different proportions. Pore-throat systems show strong heterogeneity and are classified into six classes based on their size distribution characteristics. Carbonate porosity is not solely correlated with pore sizes because pore abundance is another independent factor to determine porosity. Permeability is controlled by PTR rather than pore sizes, and R40 (PTR corresponding to the 40th percentile of mercury saturation) is the most correlated PTR to permeability. There is no apparent correlation between pore size and PTR except for the interparticle pores. Both pore sizes and PTR distributions can reflect reservoir microscopic heterogeneity due to their positive correlations for all pore types other than micropores (pore diameter less than 30 μm).

Preface: New advances in unconventional petroleum sedimentology in China

Significant progress has been gradually made on the exploration and development of unconventional petroleum on land in China over the past 20 years. In 2019， unconventional petroleum production in China accounted for about 23% of the total oil and gas production that year and reached 70 million tons of oil equivalent in 2020, indicating China’s petroleum industry has entered a new stage of unconventional petroleum development. Unconventional petroleum sedimentology as an important part of unconventional petroleum geology， and the theoretical system has been gained more and more attention over recent years， leading to important studies， such as “Depositional model of gravity flows， sandy debris in a deep lacustrine basin”， “Depositional model of marine and/or lacustrine organic-rich shale”， “Abundant micro- and nano- pore throat systems developed in fine-grained sedimentary rocks”， and “Sweet-spot areas （intervals） of unconventional petroleum resulted from coupling the sedimentology of several geological events”. This special issue systematically assembles new advances made in the unconventional petroleum sedimentology of China by Chinese unconventional petroleum sedimentologists in recent years. These studies refer to about 30 sets of unconventional petroleum strata （intervals） from the Proterozoic to Cenozoic in more than 50 basins， providing an important theoretical basis and technical support for unconventional petroleum exploration and development. Unconventional petroleum sedimentology would focus on deposition and formation of“sweet⁃spot box” and “sweet⁃spot group ”developed in unconventional petroleum industry in future, and further enhance efficiency of unconventional petroleum exploration and development.

Micro/Nanopore Systems in Lacustrine Tight Oil Reservoirs, China.

A nanoscale pore throat system develops extensively in rocks of unconventional reservoirs serving as both source and reservoir rock. The nanoscale pores provide the main storage spaces, accounting for 70% to 80% of the total unconventional tight reservoirs in China. As one of most important unconventional petroleum accumulations, tight oil has accumulated in more than 20 lacustrine strata since the Permian in China. Three types of tight oil reservoirs were identified based on the lithology and provenance in the lacustrine basins, including terrigenous sandstone, endogenous carbonate rocks and mixed sedimentary rocks. The micro/nanopore structures of these tight rocks were investigated with the application of optical microscopy, scanning electron microscopy (SEM), mercury injection capillary pressure (MICP), gas adsorption (GA) and nuclear magnetic resonance (NMR). The results indicated that the pore systems were connected by nanoscale throats dominated the storage spaces of the lacustrine tight oil reservoirs, while there were obvious differences among these three tight rocks, including pore types, pore size and movable fluid distribution. (i) The terrigenous sandstones, which were represented by the Triassic Chang 7 tight sandstones in the Ordos Basin and Cretaceous Quantou tight sandstones in the Songliao Basin, were mainly arkoses, and their storage space was mainly composed of dissolution pores and intraclay mineral pores. Feldspar, rock fragments and carbonate cements were the majority of the dissolved components, and the diameter of dissolution pores ranged from 1 micron to 50 microns. Abundant intrakaolinite and illite/smectite mixed layers pores were developed, and the pore size was 10 nm to 500 nm. The MICP and GA data suggested that storage spaces were connected by throats with diameters of 10 nm˜300 nm. (ii) The endogenous carbonate rocks, which were represented by the Jurassic Da'anzhai limestones in the Sichuan Basin, were the tightest rocks with porosities of less than 5% and permeabilities of less than 0.01×10-3 μm². The calcite dissolution pores and fractures with diameters of 10 nm˜500 nm were the most important storage spaces. The majority of pore systems were connected by throats with diameters of 6 nm˜100 nm based on the MICP and GA data. (iii) The tight mixed sedimentary rocks, which were represented by the Permian Lucaogou Formation in the Junggar Basin, were complex in lithologic composition, and dolostones and dolomite sandstones were the most important exploration targets. The interdolomite pores were the dominant storage spaces, in which abundant illite/smectite mixed layers were filled, and the pore size ranged from 50 nm to 50 microns. The MICP and GA data showed that the storage space was dominated by throats with diameters of 10 nm˜200 nm, and their volumetric contributions could reach over 70%. These results could provide a reference for future tight oil research and exploration in China.

Diagenetic alteration, pore-throat network, and reservoir quality of tight gas sandstone reservoirs: A case study of the upper Paleozoic sequence in the northern Tianhuan depression in the Ordos Basin, China

The Sulige gas field in the Ordos Basin is the largest gas field in China. The studied area, the northern Tianhuan depression, is located west of the gas field and is considered as a potential gas-producing area. The complex diagenetic alteration history and its effects on the pore-throat network and reservoir quality of the tight gas sandstones are explained. The upper Paleozoic first member of the Shanxi Formation and eighth member of the Shihezi Formation tight gas reservoir rocks are composed of coarse- to medium-grained sandstones and are dominated by sublitharenites. The most important diagenetic factor for porosity reduction was compaction, followed by cementation. Diagenetic mineral phases include quartz overgrowth, calcite cement and replacement, and kaolinite cement and replacement, with minor heulandite and chlorite. Pressure dissolution of quartz grains and quartzite fragments is the main source of silica for the early and late quartz overgrowth cementation (formed mainly from 120°C to 140°C). The hydrolysis and alteration of volcanic material and mica flakes released some silicon, calcium, and aluminum ions. Calcium and carbon in calcite cements could be derived from surrounding mudstones. Calcite replaced the quartz overgrowths. The formation of kaolinite, as cement and replacements, was controlled by the interactions of silica, aluminum, pH, and temperature (140°C). Because of deformation of detrital components (mica flakes and ductile rock fragments) and diagenetic replacement, clear negative correlations between reservoir quality and contents of the diagenetic minerals are lacking. A complex and isolated pore-throat network was created by strong diagenetic transformation. Based on analysis of thin sections, three-dimensional x-ray micro–computed tomography, and constant-rate mercury injection data, the samples with relatively good reservoir quality (porosity >10% and permeability >0.5 md) are characterized by dissolution pores and primary intergranular pores and commonly contain more and larger pore throats both in volume (counts >1800 and size >0.02 per unit volume) and diameter (>1.20 μm) than the samples with poor reservoir quality. The intercrystalline pores of kaolinite are very widespread and considered favorable for oil and gas accumulation because some asphalt was found within these pores. This study may be used, by analogy, to better understand diagenetic factors controlling the formation of tight gas sandstone reservoirs and predict the development of pore-throat systems.

Impacts of Pore-Throat System on Fractal Characterization of Tight Sandstones

The pore-throat structures play a dominant role in the evaluation of properties of tight sandstone, but it remains difficult to determine the related parameters and understand their impact on reservoir quality. Hence, toward this end, we analyze the experimental data that are indicative of the pore-throat system, then we investigate the effect of fractal dimensions of pore-throat structures on petrologic and physical properties, and finally, the optical observations, fractal theory, and prediction model were integrated to explore the qualities of various reservoir types in tight sandstones. The results show that the fractal dimensions of the mercury intrusion curve correspond to three pore-throat types and those of the mercury extrusion curve could correspond to two pore-throat types. Five types of reservoirs were identified, the best reservoir type has a high percentage of interparticle and dissolution pores but a low proportion of clay-related pores, and the differences in pore-throat connectivity of various types affect storage capacity significantly. The storage ability prediction models of various reservoir types are raised by integrated experimental data. This work employed a comprehensive fractal theory based on capillary pressure curves and helps to explore how pore-throat systems influence reservoir quality in tight sandstones.

Pore size distribution in the tight sandstone reservoir of the Ordos Basin, China and their differential origin

The micro-nano pore throat system widely developed in tight sandstone is the essential difference between tight sandstone reservoir and conventional sandstone reservoir; it is also the main factor affecting the seepage characteristics and development effect of tight sandstone reservoir. This thesis analyzed the pore-throat types and distributions of the Chang 6 and the Chang 7 reservoirs in the Jiyuan area of the Ordos Basin and discussed the original causes by cast section, SEM, and constant-rate mercury injection. The results showed that the pore type of the Chang 6 reservoir is predominantly residual intergranular pores wherein the throat is mostly compacted. The pore of Chang 6 is more developed than the throat. The pore type of the Chang 7 reservoir is mainly feldspar solution pores, whereas its throat is mostly dissolution. The throat of Chang 7 is more developed than pore. The pore radius distribution range and the average value of the Chang 6 reservoir are similar to those of the Chang 7 reservoir. The distribution range and average value of the throat radius of the Chang 6 reservoir are obviously larger than that of the Chang 7 reservoir. Meanwhile, the physical property of the Chang 6 reservoir is better than that of the Chang 7 reservoir. The Chang 6 reservoir is located in delta sedimentary with shallow burial depth. The high chlorite membrane content and low compaction strength of the Chang 6 reservoir make it more conducive to maintaining the original sedimentary pore space; the dissolution further enlarges the pore space. The Chang 7 reservoir is located in a semi-deep lake sedimentary with large burial depth. The compaction and cementation of the Chang 7 reservoir are strong, and the original sedimentary pore space is massively compressed. Although dissolution strongly occurs in the later stage, the connectivity and seepage capacity of the throat of dissolution origin are lower than those of compaction origin. Dissolution can increase reservoir space; nevertheless, it cannot significantly improve seepage capacity. Therefore, there is a significant difference in permeability of the two successive layers.

Pore structure and physical properties of sandy conglomerate reservoirs in the Xujiaweizi depression, northern Songliao Basin, China

Pore structure analysis is the basis of reservoir classification and exploitation, especially for tight reservoirs with complex pore throat systems. The sandy conglomerates in the Lower Cretaceous strata in northeastern China have attracted little attention from explorers in the past 50 years, but prospecting of promising tight gas reservoirs has recently begun in this area. Here, we report on the pore structure and physical properties of samples from the Shahezi Formation in the Xujiaweizi depression. Pore throat structure was investigated using thin section observations, scanning electron microscopy (SEM), high-pressure mercury injection (HPMI), and nuclear magnetic resonance (NMR). Regression analysis was used to analyze the correlation between the various pore structure parameters and the reservoir's physical properties. The results show that the pore types in the Shahezi sandy conglomerates are primarily dissolution pores with few inter-particle pores and micro-cracks. The pores are mostly less than 1 μm in radius, and the large pores are generally connected by tiny throats with radii of less than 0.1 μm. The Porapex and Porem values, which reveal the connected pore volume, were derived from the HPMI capillary pressure curve and the NMR T2 spectrum, respectively. The Porapex and Porem values are more strongly correlated with the reservoir's permeability than the other pore structure parameters, including the max throat radius (Rmax), the median radius (R50), the homogeneity coefficient (ϕ), the sorting parameter (Sp), the displacement pressure (Pd), and the mercury removal efficiency (Ew). Porapex and Porem account for only a small portion of the total pore volume (average of 37.1%) but contribute (average of 81.7%) to the permeability. By studying the microscopic and macroscopic characteristics, three typical pore structures were identified mainly based on Porapex and Porem. Type I reservoirs are characterized by relatively well connected inter-dissolution pores and high Porapex(>2.0), Porem(>2.0), and total porosity(>5.5%). Type III reservoirs show poor physical properties with some intercrystalline pores and small Porapex(<1.0), Porem(<1.0), and total porosity(<3.5%). Type II reservoirs are between type I and type III reservoirs. Favorable reservoirs (Type I and Type II) are located in the strata shallower than 4200 m.

A full-scale characterization method and application for pore-throat radius distribution in tight oil reservoirs

A pore-throat radius full-scale distribution is defined according to the molecular size of formation fluid and the lower limit of pore-throat radius distribution, in order to study the integratedcharacteristics of micro-nano pore-throat systems in tight oil reservoirs. In this study, we established a new full-scale characterization method for pore-throats through contrasting experimental data of high-pressure mercury injection and low-temperature nitrogen adsorption, optimizing the valid data intervals of the full-scale pore-throat radius distribution. Then, the data of full-scale pore-throat radius distribution is checked and corrected based on the experimental data of NMR and centrifugation. Finally, the mesopore data is derived from low-temperature nitrogen adsorption and the macropore data is derived from high-pressure mercury injection. Moreover, the steps to characterize full-scale pore-throats include one unified dimension, one data optimization, two interpolations, one connection, one data test and one data correction. The full-scale characterization of pore-throat radius distribution in tight oil reservoirs of Daqing, Changqing, Sichuan and Dagang shows that the pore-throats of tight sandstones are mainly distributed in the submicron-nano-scale, and 50% of permeability is contributed by submicron pores. Therefore, it is challenging to effectively develop the tight oil reservoirs with permeability less than 0.08 mD in Daqing and lower than 0.03 mD in Changqing. For tight carbonate matrix, pore-throats are mainly distributed in the nanoscale space, and the permeability is mainly contributed by macropores or fractures, so the developmental degree of fractures and other factors shall be considered for estimating the development limit.

Modeling of 3D Rock Porous Media by Combining X-Ray CT and Markov Chain Monte Carlo

Abstract Rocks contain multi-scale pore structures, with dimensions ranging from nano- to sample-scale, the inherent tradeoff between imaging resolution and sample size limits the simultaneous characterization of macro-pores and micro-pores using single-resolution imaging. Here, we developed a new hybrid digital rock modeling approach to cope with this open challenge. We first used micron-CT to construct the 3D macro-pore digital rock of tight sandstone, then performed high-resolution SEM on the three orthogonal surfaces of sandstone sample, thus reconstructed the 3D micro-pore digital rock by Markov chain Monte Carlo (MCMC) method; finally, we superimposed the macro-pore and micro-pore digital rocks to achieve the integrated digital rock. Maximal ball algorithm was used to extract pore-network parameters of digital rocks, and numerical simulations were completed with Lattice-Boltzmann method (LBM). The results indicate that the integrated digital rock has anisotropy and good connectivity comparable with the real rock, and porosity, pore-throat parameters and intrinsic permeability from simulations agree well with the values acquired from experiments. In addition, the proposed approach improves the accuracy and scale of digital rock modeling and can deal with heterogeneous porous media with multi-scale pore-throat system.

Pore structure and fractal characteristics of Ordovician Majiagou carbonate reservoirs in Ordos Basin, China

Fractal analysis was performed on carbonate core plug samples from the Ordovician Majiagou carbonate reservoirs in the Ordos Basin using mercury intrusion capillary pressure (MICP), nuclear magnetic resonance (NMR), and the x-ray computed tomography (CT) measurements to improve our understanding of the pore structure characteristics. The relationships between pore structure parameters and the fractal dimensions were investigated. The pore systems are dominated by secondary intercrystalline pores and enlarged dissolution pores as well as microfractures. The fractal curves from MICP analysis break into two segments at the Swanson’s parameter. The small pore-throat systems can be described by the fractal theory, whereas pores connected by relatively large throats (greater than the pore-throat radius at the Pittman’s hyperbola’s apex) are not cylindrical in shape, cannot be described by a capillary tube model, and tend to have apparent fractal dimensions larger than 3.0. The fact that the entirety of the capillary curve cannot be fit by a single fractal dimension implies that there are multiple pore systems present with different fractal dimensions. The CT analysis shows that the pores are dispersed in the three-dimensional spaces mainly with elliptical shapes. The NMR measurements are sensitive to pore-body size and MICP probes pore-throat dimensions, the latter being complementary to the pore-body–size distribution. None of the CT, MICP, and NMR techniques provide “right” or “wrong” answers to the pore-throat systems, but they probe different aspects of the pore systems. This study assumes the pore shapes to be spherical in general, and then the fractal dimension is calculated from the NMR transverse relaxation time (T2) spectrum. The fractal dimensions of all the samples are calculated, and the accuracy of the fractal model is verified by the high regression coefficients. Almost all the pore systems can be described by fractal theory, and the fractal dimensions are strongly correlated with the T2 values separating the immovable fluid and the free fluid. Microfractures may bias T2 toward larger values, making it hard to derive fractal dimensions from NMR measurements. The coexistence of small pores (pore radius 50 μm) results in a heterogeneous pore distribution and a high fractal dimension. Reservoir quality increases with the complexity degree of the microscopic pore structure. Conversely, samples that are dominated by small pore systems tend to have a lower fractal dimension and a less complex pore structure.

Permeability prediction for carbonate reservoir using a data-driven model comprising deep learning network, particle swarm optimization, and support vector regression: a case study of the LULA oilfield

Permeability is universally considered as an important parameter since its data is critical for some basic geological work, such as constructing a pore-throat system of reservoir, evaluating flowing capability of formation, etc. Accordingly, how to predict permeability becomes a primary research in the realm of geoscience. Lots of physical models specifically used for permeability prediction have been created in recent decades, but calculation parameters involved in the models must be determined through core experiments. In order to reduce reliance on the usage of the data generated by core experiments, statistical prediction methods for permeability are developed. Support vector regression (SVR) is one of the optimal prediction approaches that can perfectly reveal the nonlinear relationship between permeability and other geological parameters, while its performance is severely limited by qualities of input data and calculation parameters. Colinear issue regarding variables of input data and bad initialization of calculation parameters can cause failure of fitting equation establishment. Thus, in view of those demerits, two techniques, deep learning and particle swarm optimization (PSO), are introduced to enhance the calculation capability of SVR. Then, a hybrid data-driven model which consists of deep learning network, PSO, and SVR is proposed. Data for method validation is recorded by three wells of the LULA oilfield. Two experiments are designed by the validation data. Experiment results prove that the proposed method has the capability to produce more accurate predicted results than those provided by single SVR and PSO-SVR. Consequently, the new hybrid data-driven model is effective in predicting permeability under processing real data.

How Do Nanoparticles Stabilize Shale?

Summary The operational use of nanoparticles (NPs) in drilling and completion fluids is still limited at the present time, in part because of a lack of consistent evidence for and clarification of NP interactions with rock formations, formation fluid, and other fluid additives. For instance, previous fluids research emphasized that NPs bring about pore plugging, which reduces pressure transmission and, in turn, fluid inflow, into the shale pore matrix, which ultimately helps stabilize the borehole. However, it is difficult to understand how pore plugging might be accomplished in the absence of any substantial filtration in shales, considering that the minimal permeability of shales does not allow for any appreciable Darcy flow. This paper addresses the crucial question: “How, when, and why do NPs plug shale pore throats?” Zeta-potential (ZP) measurements were carried out on aqueous NP dispersions and on intact thin shale sections exposed to nanofluids to determine the degree of interaction behavior between NPs and shale. The experimental data were then used to calculate Derjaguin-Landau-Verwey-Overbeek (DLVO) curves (describing the force between charged surfaces interacting through a liquid medium) to determine if the total potential energy was sufficient for NPs to diffuse through the repellent barrier and attach to the shale surface. Calculated DLVO curves were used to demonstrate the NPs ability to contribute to borehole stability, but did not directly correlate the effects the NPs had on shale stability. Experiments, including pore pressure-transmission tests (PTTs), which measure fluid pressure penetration in shale, and modified thick-walled-cylinder (TWC) collapse tests, which explore the influence of NPs on the collapse pressure of shale samples, were conducted to directly investigate the effects of NPs on borehole stability in shale. Our investigation showed that NPs can reduce fluid pressure penetration and delay borehole collapse in shale, but only under certain conditions. Electrostatic/electrodynamic interaction between NPs and shale surfaces, governed by DLVO forces, is the main mechanism that leads to pore-throat plugging, reducing pressure transmission, which in turn benefits borehole stability by slowing down near-wellbore pore-pressure elevation and effective-stress reduction. For Mancos Shale, 20-nm anionic nanosilica particles were effective in partially plugging the pore-throat system, depending on the pH of the nanofluid, which affects the surface potential and ZP of both NPs and shale. Furthermore, cationic nanosilica showed better results for pore-plugging capabilities than the anionic nanosilica. Our findings lead to interesting challenges for the practical field application of NP-based drilling fluids for borehole stability, given that efficacy depends on the specific type of shale; the specific type, size, and concentration of NP; the interaction between NPs and shale; and external factors, such as pH, salinity, and temperature. Therefore, NP use for practical shale stabilization requires a dedicated, thoroughly engineered solution for each particular field application, and is unlikely to be “one size fits all.”

Formation mechanism of the Upper Triassic Yanchang Formation tight sandstone reservoir in Ordos Basin—Take Chang 6 reservoir in Jiyuan oil field as an example

The Upper Triassic Yanchang Formation Chang 6 Member (C6 Member) in the Ordos Basin is the typical crude oil-rich sandstone in China, and its density restrict the exploration and development potential of hydrocarbon as well as their evaluation accuracy. Reservoir characteristics was studied using thin section (TS) associated with particle and pore size image analysis, X-ray diffractions, scanning electron microscopy (SEM) and mercury intrusion porosimetry (MIP). Time was taken as the main axle combined with diagenetic history, burial history, thermal history and structure. Thus, formation mechanism of tight reservoir was discussed by building the porosity evolution model and calculation method using “diagenesis simulation” and “geological effect simulation”. Results show that after strong evolution and reconstruction, micro-nano pore throat system has developed and ultralow-low porosity-super low permeability tight sandstone reservoir has formed. Porosity evolution of Well H53 of C6 Member has revealed the correlations between the hydrocarbon charging and the porosity. Tight sandstone reservoir quality is affected by the maximum intergranular point-counted porosity, maximum compaction rate, maximum cementation rate, pore evolution of sample and the oil saturation, reasons for the formation of tight sandstone reservoir as well as its quality have been found out.

Pore structure classification and logging evaluation method for carbonate reservoirs: A case study from an oilfield in the Middle East

ABSTRACTBased on the data of 121 thin sections, 24 mercury injection and physical properties of the carbonate reservoir in A oilfield of the Middle East, the reservoir in the study area is divided into four pore-throat systems by analyzing the pore-throat volume verses permeability-contribution curve of core mercury injection and corresponding depth NMR logging data. Taking into account the contribution of each pore-throat system to the rock, a new pore structure parameter P based on NMR logging data is proposed. On this basis, the P and flow porosity calculated from NMR logging data are used as variables, and the pore structure of carbonate reservoirs is divided into four types by using the K-means clustering method in combination with the characteristics of capillary pressure curves and thin sections. With the input of NMR logging data and conventional logging data, the classification model of pore structure is established by Rotation Forest algorithm. The accuracy of the classification model based on NMR logging is 98.56%, and the accuracy of the classification model based on conventional logging is 89.9%. Compared with the Random Forest algorithm and the Fisher discriminant method, the Rotation Forest algorithm has high prediction accuracy and strong stability. The research shows that the pore structure classification method proposed in this paper is in good agreement with the interpretation results, which can provide some reference value for finding effective reservoirs in the future.

The characteristics of movable fluid in the Triassic lacustrine tight oil reservoir: A case study of the Chang 7 member of Xin'anbian Block, Ordos Basin, China

The micropore-throat structure of a tight oil reservoir is complex, and its movable fluid distribution differs from that of a conventional reservoir. By using nuclear magnetic resonance (NMR) and centrifugation, the movable fluid distribution in the Chang 7 tight reservoir in the Xin'anbian Block of the Ordos Basin was quantitatively evaluated. Combined with the results of the physical property and high-pressure mercury intrusion experiments, the effects of the porosity, permeability, pore size distribution and micropore-throat structure on the movable fluid distribution in the Chang 7 tight reservoir were analyzed. The NMR results show that the T2 spectral morphology of the Chang 7 tight oil reservoir in the Xin'anbian Block can be characterized by three main patterns with different amplitudes of front and post peaks. The front peak corresponds to the scale of small pores and the post peak corresponds to the scale of large pores. Based on the three T2 spectrum patterns, the Chang 7 tight reservoir can be divided into three types: type 1 reservoir with more small pores and fewer large pores, type 2 reservoir with similar amounts of small and large pores, and type 3 reservoir with fewer small pores and more large pores. Thus, the characteristics of these three types of reservoirs can be determined. The movable fluid parameters were calculated by NMR and centrifugation. The movable fluid saturation of the type 1 reservoir is low, with an average of 20.38%, and the average movable fluid porosity is 1.47%. The type 2 and type 3 reservoirs have higher movable fluid contents of 40.79% and 47.04%, respectively. The average movable fluid porosities of the type 2 and type 3 reservoirs are 3.37% and 3.48%, respectively. The greater number of small pores and smaller number of large pores in the type 1 reservoir result in weak correlations of the movable fluid with the physical properties and pore-throat structure parameters. The movable fluid saturation is negatively correlated with the maximum pore radius, mainstream throat radius and maximum mercury saturation and is strongly positively correlated only with the porosity of the large pores. As the number of large pores increases, the movable fluid saturation strongly correlates with the property parameters, pore size distribution, and pore-throat structure parameters in the type 2 and type 3 reservoirs. The movable fluid saturations are positively affected by the maximum pore radius, median radius, mainstream throat radius, and effective porosity but are strongly negatively correlated only with the radius mean value. These results indicate that the fluid mobility of these two types of reservoirs can be promoted by the pore-throat system to obtain favorable seepage characteristics.

The Visual and Quantitative Study of the Microoccurrence of Irreducible Water at the Pore and Throat System in a Low-Permeability Sandstone Reservoir by Using Microcomputerized Tomography

The microflow equipment monitored with micro X-ray computerized tomography (CT) is employed to investigate the microoccurrence of the irreducible water in a low-permeability sandstone core. By means of image segmentation and the three-dimensional (3D) image reconstruction technique, the visual microdistribution characteristics of irreducible water in two-dimensional (2D) slices and the 3D pore-throat system are quantitatively evaluated. Some interesting findings are list as below. Firstly, due to the variant micro geometric structures of the pore-throat systems, specific core slices showed significantly different irreducible water saturation even though these slices had same areal porosity. Secondly, due to the influence of capillary trapping and the existence of oil-wetting clay (main chlorite), the irreducible water saturation in the throat system (64%) is much larger than that in the pore system (36%). Furthermore, the wetting phase (irreducible water) did not spread all over the surface of the pore-throat network which caused a much more complicated oil-water two-phase interface. Thirdly, in micro scale, the main irreducible water occurrence mode in the pore system is much different from that in the throat system. In the pore system, the irreducible water principally existed in the corner of the pores which are linked through a water film. While in the throat system, the irreducible water occurrence is dominated by the water film. However, 25.5% of the throats are blocked by the irreducible water which cut off the crude oil drainage channels.