Pore-throat Distribution Research Articles

Headspace Isotope & Compositional Analysis for Unconventional Resources: Gas in Place, Permeability and Porosity Prediction and Completions Planning

Cuttings/cores’ Headspace Isotope and Composition Analysis (HICA) provides an effective way to calculate the nano pore throat size and distributions much like nitrogen and CO2 adsorption BET/BJH analysis, and it could also provide information about the original pore pressure or gas in place. Tight gas and oil storage is different from conventional where a majority of oil and gas are stored in nanometer sized pores (nanopores). Therefore the nanofludics, i.e., nanometer scale capillary sealing and opening in nanopores of tight rocks, plays a key role in overpressure conservation and storage of oil and gas, and also the fracing process involves the opening of the nano pore capillary seals through rock-fluid interactions. The rock-fluid nanofluidics interactions during fracing could also be studied through HICA and the results could help the optimization of fracing designs.

Evaluation of the matrix influence on the microscopic pore-throat structures of deep-water tight sandstone: A case study from the Upper Triassic Chang 6 oil group of the Yanchang Formation in the Huaqing area, Ordos Basin, China

Former studies have suggested that the matrix of clastic rocks is unfavorable for the storage-percolation of reservoirs. However, the contribution of the matrix to the microscopic pore-throat structures in deep-water tight sandstone cannot be ignored. Aiming at the deep-water tight sandstone of the Chang 6 reservoir in the Ordos Basin (China), we have evaluated the characteristics of the matrix and the secondary pores in the matrix based on a multiscale microscopic identification and testing method, to reveal the influence of the matrix on the types, distribution, and heterogeneity of the pore throats. The results show that, unlike cements, the composition of the matrix is complex, characterized by its poor crystal form with no cement generation relationship. The structure of the matrix components is not completely dense. Intercrystalline pores and dissolved matrix pores are developed in the matrix after diagenetic modification, with a pore diameter of 20–1000 nm. These pores form a complex matrix secondary pore network. The matrix controls the number and volume of 0–1 μm pore throats. The matrix is constructive to the distribution of pore throats when its content is ≤7%. This positive effect gradually decreases with the increase of the matrix content, intensifying the compaction of the reservoir. The matrix controls the heterogeneities of the pore throat structures in deep-water tight sandstone. Large pore throats are gradually separated and disintegrated into a large number of micro-/nanopores by the matrix with the increase of the matrix content. Meanwhile, the fractal dimensions approached 3, increasing the complexity of the pore structures. Therefore, the matrix is favorable and unfavorable to the microscopic pore throat structures of the reservoir. The matrix not only results in the loss of intergranular pores but also generates a large number of secondary micro-/nanopore throat networks with complex structures, constituting an effective space for hydrocarbon accumulation and percolation in deep-water tight sandstone.

Well injectivity loss during chemical gas stimulation process in gas-condensate tight reservoirs

After the injection of chemical treatment dispersed in gas (GaStim) in a Colombian mature gas-condensate tight reservoir, an injectivity loss was observed and led to a productivity reduction in the well. The main objective of this study is to evaluate the causes of the injectivity loss due to the GaStim process through static and dynamic tests. For this, adsorption isotherms of the treatment over the rock surface and contact angle (CA) measurements were performed. Furthermore, the interaction of reservoir fluids with chemical treatment was studied through interfacial tension measurements and emulsion formation. Reproduction of the field injection conditions at a laboratory scale was successfully accomplished and included the pressure drop of the gas stream from wellhead to the injection path and a core displacement test for different Liquid-to-Gas ratios (LGR). It was found that at LGR of 0.4 bbl·MMscf-1, 24% of the dispersed chemical treatment is condensated/retained, promoting both emulsion and capillary blockage that leads to a reduction of gas permeability (Kg) of 66%. Although at 0.025 bbl·MMscf-1 there is no evidence of capillary blocking, the reduction of Kg of 47.7% can be associated with emulsion blockage according to the emulsion drop and pore throat distribution. This research provides a landscape of the accurate design of GaStim operations based on a schematic experimental procedure to establish the injection flow conditions and the rock surface/reservoir fluids interaction with the dispersed treatment, showing that success of this technique depends on the chemical treatment employed and the liquid-to-gas ratio during the field intervention.

An improved method in petrophysical rock typing based on mercury-injection capillary pressure data

ABSTRACT Petrophysical rock typing plays a major role in carbonate reservoir characterization and geological modeling for reservoir simulation. In this study, based on 1120 samples of mercury-injection capillary pressure data, we have analyzed the contributions to rock permeability for the thick Cretaceous carbonate reservoir of Mishrif Formation in H Oilfield in Iraq. The analyses have been carried out for three types of pore-throat frequency distribution, i.e., monomodal, bimodal, and trimodal. The results show that for the bimodal and trimodal samples, the pore-throat frequency distribution of the first pore system contributes more than 95% of rock permeability. Further, the Thomeer function has been used to fit the mercury-injection capillary pressure curve, in which the displacement pressure, pore geometry factor, and bulk volume have been extracted. These three parameters have been utilized to characterize the pore structure and to fit with the rock permeability so as to obtain the reservoir classification parameter Mode. Then, we have established the relationship between permeability and mode, permeability and R35, and the correlation coefficients are 0.81 and 0.75, respectively. And permeability derived from Mode is more accurate than R35. The Modes of 1120 samples have been arranged in ascending order and plotted on the semi-logarithmic scales. After interpolation, derivation, and filtering, five rock types have been divided at the change in slope. The combination of Mode and this slope method is considered an improved method. The classification results of Mode, Winland R35, and Flow Zone Indicator have been compared with those of pore-throat distribution, T2 distribution of nuclear magnetic resonance, and conventional logging responses. The results demonstrate that the classification results of Mode are significantly better than those of Winland R35 and Flow Zone Indicator.

Insight into filter cake structures using micro tomography: The dewatering equilibrium

In recent years, non-destructive X-ray microscopy (XRM) has become a common method to characterize particle systems in various scientific fields: Besides the size and shape of particles in bulk powders, the insight into filter cake structures provides additional information about micro processes during filtration and dewatering. Distributed particle properties mainly influence the porous network build-up with possible local deviation in vertical and horizontal alignment. This article focusses on the model-based correlation between the distributed particle properties and characteristic network parameters like tortuosity, pore radii and preferred capillaries for dewatering, using tomography data as model input. Therefore, cake-forming filtration experiments were carried out with a down-scaled, self-constructed in-situ pressure nutsch. The entire tomographic dataset consists of seven individual scans at certain desaturation steps at different pressure levels.For the experiments, a lognormal distributed particle system (crushed Al2O3) in the range of 55 to 200 µm inside an aqueous suspension was used, containing additives for contrast enhancement. Image data processing based on reconstructed 360° projections allows the identification of the background, solid particles and liquid phase by a two-step segmentation.The subsequent modelling uses experimentally verified particle size distributions from laser diffraction measurements (integral value), 2D- (limited number of particles) as well as tomographic analysis, based on calculated single-particle volumes given by the voxel-dataset (all particles within the scanned volume). To characterize the porous network, a developed tetrahedron model is first applied to follow the shortest way through the porous matrix, then again to calculate the widest capillary related to the pore entrance. Furthermore, with information about the pore throat distribution and the wetting line from the tetrahedron side faces, the force balance is evaluated. This results in an entrance pressure distribution, the capillary pressure curve. Experimental data according to VDI 2762 built filter cakes and mercury intrusion tests are taken as reference for validation.

Experimental Study on Mesodamage of Migmatite Under Cyclic Loading and Unloading

To study the mesodamage of migmatite under cyclic loading, single cycle loading and unloading tests of migmatite were carried out under different confining pressures (σ3) and stress ratios (p), and acoustic emission (AE) technology was used to monitor the evolution of microcracks. Additionally, the mesodamage of migmatite was analyzed from the porosity and T2 spectrum distribution measured by nuclear magnetic resonance (NMR) spectroscopy. The results show that the peak stress ratios (pmax) of migmatite under different σ3 are different, and as the value of σ3 increases, the migmatite gradually undergoes a change from tension to shear failure. Moreover, with the increase in σ3, high-frequency signals gradually appeared, indicating that the increase of σ3 to a certain extent limited the generation of large size microcracks. The variations in damage variables defined by the number of AE hits and porosity are the same, “steep increment type,” and increase suddenly when approaching pmax. Furthermore, σ3 slightly affects the pore throat distribution of migmatite. In addition, σ3 has a certain inhibitory effect on the porosity of migmatite and accumulation of mesodamage. However, when σ3 exceeds a critical value, the inhibitory effect becomes a promoting effect.

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.

Study on seepage characteristics of tight sandstone reservoir

Seepage characteristics of reservoir rocks are important factors affecting the effect of tight oil and gas production. Therefore the pore structure of tight sandstone from Dong 6 well in 4 block of the central Dzungaria Basin were studied by mercury injection experiment, and the seepage characteristics of tight sandstone were comprehensively studied by stress sensitivity experiment. The results show that: the pore throat distribution of the tight sandstone in the study area is not uniform, but the sorting property is good. The pore throat which promotes the permeability is mainly distributed near the threshold pressure of mercury injection experiment. The stress sensitivity of tight sandstone is affected by stress state and pore structure. Stress sensitivity is negatively correlated with confining pressure, and permeability loss is negatively correlated with pore throat radius.

Pore-scale model of two phase flow in 2D porous media: Influences of interfacial tension and heterogeneity effects on CO2 injection in the tight oil reservoir

The CO2 injection in tight reservoir is different from the conventional reservoir. For the porous media, the pore throat in the matrix reaches the level of nanopore, and the heterogeneity leads to huge difference during CO2 injection. For the interaction of fluids, the reduction of interfacial tension caused by CO2 is benefit to enhance oil recovery. To reveal the mechanism, pore scale model from tight formation is built and the influences of interfacial tension and heterogeneity are investigated. First, the migration of two-phase interface is studied by coupled with level set (LS) equation and Navier-Stokes (NS) equation. And finite element method (FEM) with interfacial adaptive mesh refinement is employed to solve the equation system. The results reach highly agreement compared with analytical solution and phase field method. Then, the pore throat distribution characteristics of porous media model are built by the scanning electron micrograph (SEM). Finally, based on the real porous media model from the SEM image, the influences of interfacial tension and heterogeneity are investigated. The pore scale model considering fluid and medium mechanism during CO2 injection provides a better understanding of interfacial tension and heterogeneity effect in tight oil reservoirs.

Pore Structure of Nuclear Graphite Obtained via Synchrotron Computed Tomography

Nuclear graphite that can be used in molten salt reactors, one of the main types of fourth-generation nuclear reactors, has the properties of high purity, high density, and radiation resistance, and it also has a special pore structure that prevents infiltration of the molten salt fuel. The nuclear graphites IG-110, NBG-18, and NG-CT-50 were characterised using X-ray computed tomography (CT) to understand their internal pore structures. The porosities, isolated pore volumes, and connected pore volumes were obtained. The average diameter of connected pores in IG-110, NBG-18, and NG-CT-50 were 9.9, 10.4 and 9.5 μm, respectively, but the nuclear graphite NBG-18 had the broadest diameter range for connected pores, with many of > 25 μm. To further analyse the connected pores, pore throat networks were established based on the connected porosities. The pore throats, channel lengths, and coordination numbers of the connected pores were herein quantitatively analysed. Among IG-110, NBG-18, and NG-CT-50, the average diameters of the throats were 4.5, 5.2, and 4.6 μm, and the peak throat diameters were 1.8, 2.6, and 1.2 μm, respectively, but the NBG-18 pore throat distribution also included multiple peaks at larger diameters (16–20 μm), which was consistent with findings from the mercury intrusion test. Our statistics based on the pore throat networks suggested that NBG-18 is the most easily infiltrated by molten salt among the three nuclear graphite samples, while NG-CT-50 is the most difficult. The quantitative information from the pore throat modelling could be a basis for future studies on liquid flow simulations inside graphite.

Effects of mineralogy on pore structure and fluid flow capacity of deeply buried sandstone reservoirs with a case study in the Junggar Basin

Integrated experiments including porosity, permeability, casting thin section (CTS), scanning electron microscopy (SEM), pressure-controlled mercury porosimetry (PCP), rate-controlled mercury porosimetry (RCP), nuclear magnetic resonance (NMR), and X-ray diffraction (XRD) are conducted to investigate the impacts of mineralogy on the pore structure and fluid flow capacity of the deeply buried sandstone in the Jurassic Sangonghe Formation of the Junggar Basin. The results indicate that the heterogeneous deeply buried sandstone is rich in quartz (54.2%), feldspar (25.1%), and clay (14.2%), with dominant kaolinite and chlorite cementation. The reservoir has a variable overall pore-throat diameter distribution with three peaks in the ranges 0.01–1, 10–80, and 200–1000 μm. Pores are tri-fractal and can be divided into micropores, mesopores, and macropores. The movable porosity is primarily contributed by intergranular and intragranular pores and widely ranges from 1.75 to 8.24%. Most of the fluids are movable in intergranular pores but are irreducible in intragranular pores. Correlation analyses indicate that quartz benefits the intergranular porosity preservation, increasing pore size and macropores porosity, and reducing heterogeneities of the macropores, micropores, and pore system. Feldspar exhibits poorly opposite influences due to the simultaneous clay precipitation and complex roles of feldspar dissolution in the microporosity. All of the clay minerals act as destructions to intergranular porosity, enhancing the mesopores and micropores porosities, reducing the pore size, and increasing the heterogeneities of the macropores, micropores, and pore system. Quartz is favorable for the fluid flow capacity of deeply buried sandstone, but feldspar and clay play negative roles. The reversed impacts of quartz and feldspar lay in their opposite controls on pore size. Both pore size and hydrophilia should be taken into account when considering the effects of clay. This negative effect is associated with types, contents, hydrophilic degrees of clay minerals, in which I/S and illite exhibit the strongest influences. The fluid flow in the intergranular and intragranular pores is generally enhanced by higher quartz content, and reduced by higher clay content.

Insights in the pore structure, fluid mobility and oiliness in oil shales of Paleogene Funing Formation in Subei Basin, China

Abstract Pore structure is an important factor influencing reservoir properties of oil shales. Routine core analysis, thin section, scanning electron microscope (SEM), mercury injection capillary pressure (MICP) tests, Nuclear Magnetic Resonance (NMR), and computed tomography (CT) were used to provide insights into the pore throat distribution in oil shales of member 2 of Paleogene Funing Formation (E1f2) in Subei Basin, China, with the special aim to unravel the effect of pore structure on fluid mobility and oiliness. The relationships between NMR parameters, petrophysical property and capillary parameters are investigated. The results show that rock composition in the oil shales consist of quartz, feldspar, carbonate particles, clay minerals and organic matters. Pore systems consist of large-scale interparticle pores, intragranular dissolution pores, and small-scale micropores within clay minerals and the organic matter pores. Four types of pore structure (Type Ⅰ, Type Ⅱ, Type Ⅲ and Type Ⅳ) are divided according to the patterns of capillary curves, capillary parameters, NMR T2 (transverse relaxation time) spectrum and BVI (bulk volume of immovable fluid) values. From Type Ⅰ to Type Ⅳ pore structure, the maximum mercury saturation (SHgmax) and mercury extrusion efficiency are decreasing, and the SHgmax are less than 50% averagely, indicating the oil shales are characterized by very poor pore connectivity. The T2 spectrum changes from bi-modal behavior to uni-modal and the right peaks become lower or even disappearing from Type Ⅰ to Type Ⅳ pore structure. Fluid mobility is not primarily controlled by pore size, but dependent on the content of short T2 components ( Pore structure controlled fluid mobility and determined the microscopic oiliness and macroscopic oil bearing property or hydrocarbon productivity. The comprehensive study above gains insights into the microscopic pore structure and their controls on fluid mobility and oiliness in shale oil reservoirs, and this may have implications for resource potential evaluation and effective exploitation of oil shales.

A method to evaluate pore structures of fractured tight sandstone reservoirs using borehole electrical image logging

Fractures are important in improving tight sandstone pore connectivity and fluid flow capacity. However, the contribution of fractures to pore connectivity and fluid flow capability cannot be quantified using current methods. The objective of this study was to develop a method to quantitatively characterize reservoir improvement as a result of fractures. This method was proposed based on the experimental results of 37 core samples recovered from the Upper Triassic Chang 8 tight sandstone in the Jiyuan area of the Ordos Basin, China. The morphological features of the porosity spectra, the mercury injection capillary pressure curves, and the pore-throat radius distributions were analyzed. Accordingly, a method was proposed to construct pseudocapillary pressure (Pc) curves from the porosity spectra to characterize the pore structure of fractured reservoirs and to establish corresponding models based on the classified power function method. In addition, a model was developed to predict fracture formation permeability based on the Swanson parameter. The proposed method and models were applied in field applications, and the estimated results agreed well with the core and drill-stem testing data. Fractured formations contained good pore structure, high permeability, and oil production rata. The relative errors between the model-predicted pore structure evaluation parameters, permeability from Pc curves, and core-derived results are all within ±30.0%. With the integrated study of reservoir pore structure with permeability, the effective Upper Triassic Chang 8 fractured tight sandstone reservoirs with development potential were successfully identified.

Combining SEM and Mercury Intrusion Capillary Pressure in the characterization of pore-throat distribution in tight sandstone and its modification by diagenesis: A case study in the Yanchang Formation, Ordos Basin, China

Determining the characteristics of pore-throat structures, including the space types present and the pore size distribution, is essential for the evaluation of reservoir quality in tight sandstones. In this study, the results of various testing methods, including scanning electron microscopy (SEM), pressure-controlled porosimetry (PCP) and rate-controlled porosimetry (RCP), were compared and integrated to characterize the pore size distribution and the effects of diagenesis upon it in tight sandstones from the Ordos Basin, China. The results showed that reservoir spaces in tight sandstones can be classified into those with three types of origins (compaction, dissolution, and clay-related) and that the sizes and shapes of pore space differ depending on origin. Considering the data obtained by mercury injection porosimetry and the overestimation of pore radii by pressure-controlled porosimetry, the full-range pore size distribution of tight sandstones can be determined by combining data from PCP with corrected RCP data. The pore-throat radii in tight sandstone vary from 36 nm to 200 μm, and the distribution curve is characterized by three peaks. The right peak remains similar across the sample set and corresponds to residual intergranular pores and dissolution pores. The middle and left peaks show variation between samples due to the heterogeneity and complexity of nano-scale throat bodies. The average micro-scale pore content is 33.49%, and nano-scale throats make up 66.54%. The nano-scale throat spaces thus dominate the reservoir space of the tight sandstones. Compaction, dissolution, carbonate cementation, and clay cementation have various effects on pore-throats. Compaction and carbonate cementation decrease pore body content. Pore-bridging clay cementation decreases throat space content. As pore-lining clay cementation preserves pore space.

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.

Characteristics of micropores, pore throats, and movable fluids in the tight sandstone oil reservoirs of the Yanchang Formation in the southwestern Ordos Basin, China

Thin-section analysis, field emission scanning electron microscopy, constant-rate mercury injection (CRMI), x-ray–computed tomography (X-CT), and nuclear magnetic resonance (NMR) were used to investigate pore systems, pore sizes, and pore-throat distributions and determine evaluation criteria for tight oil reservoirs. This research shows that the average porosity of the reservoirs in the Chang 63 to Chang 72 Members of the Yanchang Formation of the Ordos Basin ranges from 4% to 16%, with a corresponding average permeability of 0.1 to 0.4 md. The main pore types in these tight oil reservoirs are dissolution pores and intergranular pores, and the main pore-throat types are laminated throats and control-shaped throats. Based on experimental results, the pore-throat distributions differ among different testing techniques. The results of this study indicate that a combination of CRMI-derived and X-CT–detected pore-throat distributions is most suitable for calibrating NMR-derived pore sizes over the full range of pore sizes. The lower pore-throat radius limit of effective reservoirs is 0.24 μm, and the lower permeability limit for the flow of movable fluid is 0.008 md. Based on a cluster analysis, the studied tight oil reservoirs can be divided into three types. Compared with type III reservoirs (porosity 11% and permeability > 0.15 md) and type II (8% < porosity < 11% and 0.05 md < permeability < 0.15 md) reservoirs are of relatively good quality.

Role of pore structure in the percolation and storage capacities of deeply buried sandstone reservoirs: A case study of the Junggar Basin, China

Deeply buried sandstone reservoirs are characterized by their wide pore-throat distributions and varied storage and percolation capacities. An integrated analysis comprising casting thin section, scanning electron microscopy, X-ray computed tomography (micro-CT), high-pressure mercury intrusion (HPMI), and constant-rate mercury intrusion (CRMI) is performed on thirteen samples from the Jurassic Sangonghe Formation in the Junggar Basin to investigate the pore structures and their influence on the storage and percolation capacities. HPMI, CRMI, and micro-CT are combined to determine the full-range pore size distributions (FPSDs), which have multimodal distributions between 2.77 nm and 500 μm with three broad peaks. The right peak, ranging from 100 to 500 μm, is associated with residual and dissolution intergranular pores. The middle peak is mainly composed of dissolution intergranular and intragranular pores with radii between 10 and 100 μm. The left peak exhibited fluctuations and is characterized by dissolution intragranular and intercrystalline pores with radii of 37 nm–10 μm. According to the pore types, sizes, and proportions in the FPSD, the pores are classified as intercrystalline nanopores (<1 μm), intragranular micro-small pores (1–10 μm), mixed intergranular and intragranular mesopores (10–100 μm), and intergranular macropores (>100 μm). A storage capacity evaluation combining the classifications and FPSD indicates that the macropores and nanopores primarily contribute to porosity, albeit with contrasting influences on the storage capacity. The contents of macropores determine the storage capacity of a deeply buried sandstone reservoir, while the negative effects of nanopores become predominant with decreasing porosity. A percolation capacity evaluation on the basis of CRMI results suggests that the permeability contribution is dominated by nanopores in tight sandstone, controlled by micro-small pores in low-permeability sandstone, and dominated by mesopores in conventional sandstone. Mesopores always play a favorable role in percolation. However, the negative impacts of nanopores should be considered in low-permeability and tight sandstone. Micro-small pores have a negative influence on the permeability of conventional sandstone, but are favorable for the fluid percolation of most low-permeability and tight sandstone reservoirs. A new empirical equation indicates that r10 of the FPSD is the suitable as the proper pore-throat radius for the permeability estimation of deeply buried sandstone reservoirs.

Grading evaluation of pore throats in a tight sandstone reservoir: a case study of the Gao 3 section reservoir in the Qijia area of the Songliao Basin

The micropore throat of the Gao 3 section tight sandstone reservoir was studied using sampling and experimental (high-pressure mercury injection and scanning electron microscopy) methods. Based on the relative permeability, the reservoir can be divided into three categories: conventional, unconventional and low permeability. To determine the displacement pressure, porosity and other relevant parameters of various reservoirs, the mercury injection curve of all samples was projected to the same coordinate system. According to the position of the inflection point on the mercury injection curve of all levels of reservoirs, the pore throat was divided into three types: micropores, transition pores and macropores. Based on the theory that the throat is characterised by the mercury withdrawal curve, the throat in the present study is divided into three categories: the large throat, the medium throat and the small throat. Combined with the ordinate position at the inflection point, the critical point of micropore-throat classification of all kinds of reservoirs was determined. By analysing the histogram of pore-throat distribution of all kinds of reservoirs, the peak value of reservoir pore-throat distribution was determined. From the definition of expectation and variance in mathematics, the concept of grading parameters was introduced to determine the size and concentration degree of micropore-throat distribution at all levels of reservoirs, and a correlation analysis with permeability was performed to determine the control law of permeability.

Laboratory treatment of HPAM polymers for injection in low permeability carbonate reservoirs

Polymeric solutions are injected into petroleum reservoirs to improve sweep efficiency of enhanced oil recovery processes. Viscous polymeric solutions cannot be injected into non-fractured low permeability carbonates (k < 50 mD) if a significant fraction of pore throats is smaller than the polymer molecules. Mechanical shear degradation and aggressive microfiltration can be applied as tools to modify the molecular weight distribution (or hydrodynamic radius) of polymers. High speed mechanical shearing in a laboratory blender showed significant reduction in viscosity and polydispersity for the polymer stock solutions with improvement in filterability and transport in low permeability porous media. Aggressive filtration through small sized filter papers proved to be a good technique for refinement of molecular weight distribution and removing larger molecules for successful injection in low permeability carbonates. Dynamic light scattering (DLS) method was used to measure the size distribution of shear degraded polymer solutions at low concentrations. The optimum shear degradation required for a high MW polymer to be successfully injected into a low permeability carbonate reservoir was decided by comparing the polymer size distribution with the pore throat diameter distribution obtained from mercury injection capillary pressure (MICP) for the rock. This novel technique was successfully applied for injection of viscous polymer solutions in carbonates with permeability less than 20 mD. The pore throat distribution of a porous medium is more important than the permeability (or average hydraulic radius) for the transport of polymers in porous media.

Pore throat size distribution and oiliness of tight sands-A case study of the Southern Songliao Basin, China

In this study, several methods such as mercury intrusion porosimetry (MIP) and nuclear magnetic resonance (NMR) for characterizing the pore throat size distribution of tight sandstone reservoirs were selected. The differences of mercury injection parameters such as maximum interconnected pore throat radius, median radius, mercury injection curve, and pore throat distribution curve of oil-bearing and oil-free samples were compared. By designing the algorithm program and using the mercury injection data, the coefficient of converting the T2 relaxation time to the pore-throat radius was corrected, and the pore throat distribution of different oil saturation samples were analyzed. Environmental scanning electron microscope (ESEM) was also used to observe the microscopic pores and the oil in them. Using the above data, we systematically analyzed the control of pore throat distribution on the oiliness. It is found that the oiliness depends on the maximum interconnected pore throat radius, and the oil saturation depends on the oil migration front pressure and pore volume. The oiliness of tight sand has good relationship with pore throat size distribution, and the better reservoir petrophysical properties result in better oiliness. Statistics on the pore throat size distribution of oil-bearing tight sands were carried out and main intervals of pore throat size distribution of oil-bearing reservoirs were given in this paper. This understanding provides a basis for searching sweet spots in the future exploration of the tight oil.