Pore Throat Radius Distribution Research Articles

Pore-morphology-based pore structure characterization for various porous media

Quantitative characterization of pore structure plays an important role in predicting properties of porous media and it has significant applications in energy and chemical engineering. Mercury injection capillary pressure experiments and gas adsorption experiments are the major pore structure characterization techniques, but they are time-consuming, costly, and destructive. In this paper, a simple pore-morphology-based method is developed to simulate the mercury injection and gas pore condensation in CT image for obtaining the pore structure characteristics. The main idea of the developed algorithm is to utilize some of the morphological operations to capture the pore geometry and topology, and then combine with the invasion phase connectivity analysis to implement the mercury injection and gas pore condensation. The algorithm is designed in several ways with an improved computational speed and characterization accuracy. The algorithm is user-friendly and can be applied on 2D and 3D images. Various porous media are used to assess the performance of the algorithm and the characteristics of pore structures. The results are compared to the available results in the literature. Findings show that the algorithm can reliably quantitatively characterize the pore structure for a wide variety of porous media. The general pore radius distribution, pore throat radius distribution, and strict throat radius distribution involved in pore structure characterization are clarified. The characterization of heterogeneous pore structures and the effects of pore roughness on capillary pressure are discussed.

Pore structure characterization based on NMR experiment: A case from the Shanxi Formation tight sandstones in the Daning-Jixian area, eastern Ordos Basin

The study of pore structure requires consideration of important factors including pore throat size, pore radius composition, and pore-throat configuration. As the nuclear magnetic resonance (NMR) experimental results contain rich information about pore structures and fluid occurrence states, this study investigated the pore structures of the tight sandstone reservoirs of the Shanxi Formation in the Daning-Jixian area, eastern Ordos Basin. Firstly, by making the inverse cumulative curve of the NMR T2 spectrum coincide with the capillary pressure curves which were obtained by the mercury injection capillary pressure (MICP) technique, this study derived a conversion coefficient that can be used to convert the NMR T2 spectrum into the pore throat radius distribution curves based on the NMR experimental results. Subsequently, we determined the pore radius intervals corresponding to irreducible water distribution using the NMR-derived pore radius distribution curves. Finally, the NMR T2 distribution curves based on the fractal theory were analyzed and the relationships between fractal dimensions and parameters, including permeability, porosity, reservoir quality index (RQI), flow zone indicator (FZI), irreducible water saturation, RT35, and RT50, were also discussed. The NMR-derived pore throat radius distribution curves of the study area are mainly unimodal, with some curves showing slightly bimodal distributions. The irreducible water mainly occurs in small pores with a pore radius less than 100 nm. As the permeability decreases, the contribution rate of small pores to the irreducible water gradually increases. The NMR-based fractal dimensions of pores show a two-segment distribution. Small pores have small fractal dimensions and are evenly distributed, while large pores have large fractal dimensions and complex pore structures. The fractal dimension of large pores (Dmax) is poorly correlated with porosity but strongly correlated with FZI, RQI, RT35, and RT50. These results indicate that large pores are the main pore zones that determine the seepage capacity of the reservoirs. Additionally, there is a certain correlation between Dmax and the irreducible water saturation.

Characteristics and prediction of permian tight glutenite reservoirs in dinan 15 well block, junggar basin

Glutenite reservoirs are characterized by rapid lateral change, strong heterogeneity, and complex main controlling factors. This research aims to identify macro and micro characteristics of glutenite reservoirs and establish criteria for identifying favorable reservoirs studies. To this end, the tight sandy conglomerate of the Upper Wuerhe Formation in the Permian Upper Wuerhe Formation in the Dinan 15 well area of the eastern slope of the Dongdaohaizi sag in the Junggar Basin is studied. The core observation, physical property analysis, sensitivity analysis, casting thin section, scanning electron microscope and logging data are adopted to comprehensively analyze the characteristics of glutenite reservoirs. By integrating various reservoir characteristic parameters, this work constructed a new set of reservoir evaluation criteria to predict favorable areas for the Upper Wuerhe Formation in Dongdaohaizi Sag. The results show that the lithology of the Upper Wuerhe Formation in the Dinan 15 well area is dominated by gray glutenite; the reservoir is an ultra-low porosity and ultra-low permeability reservoir with moderately weak water sensitivity and weak velocity sensitivity. The reservoir space types of the layers are mainly intergranular pores; the shape of the mercury intrusion curve and the pore throat radius distribution of the samples show that the reservoir is skewed, poorly sorted, and has the characteristics of small pores and thin throats. This work constructed evaluation criteria for reservoirs from I to III by utilizing lithology, physical properties, sensitivity, reservoir space type, and microstructural characteristics as key parameters. The favorable reservoir distribution area is mainly located in the west of the block, which is the focus of the next exploration of the Upper Wuerhe Formation area. The research results improved understanding of glutenite reservoir characteristics and will serve as significant guidance for the oil and gas exploration in the Dinan 15 well area.

Water Saturation Modeling Challenges in Oil-Down-to Wells: An Example from a Multidarcy North Sea Reservoir

Summary The initial water saturation in a reservoir is important for both hydrocarbon volume estimation and distribution of multiphase flow properties such as relative permeability. Often, a practical reservoir engineering approach is to relate relative permeability to flow property regions by binning of the initial water saturation. The rationale behind this approach is that initial water saturation is related to both the pore-throat radius distribution and the wettability of the rock, both of which affect relative permeability. However, pore-throat radius and wettability are usually not explicitly included in geomodel property modeling. Therefore, the saturation height model should not only capture an average hydrocarbon pore volume but also reflect the underlying mechanisms from hydrocarbon migration history and its impact on initial water saturation distribution. This work introduces and describes a new term, excess water, for more precise classification of saturation height model scenarios in reservoirs in which multiple mechanisms have interacted and caused a complex water saturation distribution. An example of the presence of transition zones related to drained local perched aquifers (excess water) in oil-down-to (ODT) wells is shown using a limited data set from a North Sea reservoir. The physical basis for drainage and imbibition transition zones connected to both regional and perched aquifers is given. The distribution of initial water saturation in reservoirs containing excess water is demonstrated through numerical modeling of oil migration over millions of years. Highly permeable reservoirs are more likely to have locally trapped water because of lower capillary forces. A static situation occurs in areas where the capillary forces cannot maintain a high enough water saturation for further water drainage. On the other hand, both high- and low-permeability reservoirs may have significant excess water because of ongoing dynamic effects. In both cases, long distances for water to drain laterally to a regional aquifer enhance the possibility for a dynamic excess water situation.

Difference of Microfeatures among Diagenetic Facies in Tight Sandstone Reservoirs of the Triassic Yanchang Formation in the Midwestern Region, Ordos Basin

Based on the background of sedimentary characteristics, a large amount of core and thin section analysis, taking Chang 6 reservoir of Yanchang Formation in the central and western Ordos Basin as an example, through the application of scanning electron microscopy, high-pressure mercury injection, nuclear magnetic resonance and microscopic water drive oil model, and other experimental test methods, the diagenetic facies types and microscopic pore structure characteristics of tight sandstone reservoirs are discussed and analyzed in depth. The results show that the average porosity loss rate caused by early diagenesis compaction in the study area is 50.62%, which is the main reason for reservoir compactness. The cementation further causes porosity loss, and the later dissolution increases the reservoir space in the study area to a certain extent. Different diagenetic facies reservoirs not only have obvious differences in porosity evolution characteristics but also have significant differences in pore throat radius distribution characteristics, movable fluid occurrence characteristics, and water drive oil characteristics. The pore throat distribution with radius greater than R50∼R60 determines the permeability. The difference in movable fluid saturation mainly depends on the connectivity of the relative large pore space corresponding to the relaxation time greater than the cut-off value of T2. The size of pore throat radius has a good control effect on water flooding efficiency.

Scale-dependent permeability and formation factor in porous media: Applications of percolation theory

Understanding porous media properties and their scale dependence have been an active subject of research in the past several decades in hydrology, geosciences and petroleum engineering. The scale dependence of flow in porous media is attributed to small- and large-scale heterogeneities, such as pore size distribution, pore connectivity, long-range correlations, fractures and faults orientations, and spatial and temporal variations. The main objective of this study was to investigate how permeability (k) and formation factor (F) vary with sample dimension at small scales by means of a combination of pore-network modeling and percolation theory. For this purpose, the permeability and formation factor were simulated in twelve three-dimensional pore networks with different levels of pore-scale heterogeneities. Simulations were carried out at five different network sizes, i.e., 1130, 2250, 3380, 4510 and 6770 µm. Four theoretical models were developed based on percolation theory to estimate the scale dependence of permeability and formation factor from the pore-throat radius distribution. In addition, two other theoretical scale-dependent permeability models were proposed to estimate permeability at different scales from the pore-throat radius distribution and/or formation factor. Comparing theoretical estimations with numerical simulations showed that the proposed models estimated the scale dependence of permeability and formation factor reasonably. The calculated relative error (RE) ranged between −3.7 and 3.8% for the permeability and between 0.21 and 4.04% for the formation factor in the studied pore-networks.

Novel method for determining the lower producing limits of pore-throat radius and permeability in tight oil reservoirs

Determination of the lower limit of flowing porosity for oil recovery from tight oil reservoirs is the key to promoting scientific and economic development of tight oil reservoirs. This study performed a comprehensive analysis based on pore-throat radius distribution measurements, low-temperature nitrogen adsorption measurements, and centrifugation and nuclear magnetic resonance measurements to establish a method for calculating the bound water film thickness and, in turn, the lower limits of pore-throat radius and permeability. The method was applied on rock samples from typical tight oil reservoirs in the Daqing and Changqing oil regions in China. The results indicated that for a given reservoir, bound water film thickness tends to be constant. With decreasing permeability, bound water film thickness showed an L-shaped distribution curve due to the changes in the pore-throat structure and the impact of molecular forces. The flat segment of the distribution curve corresponded to the lower limit of pore-throat radius, while the curve inflection point corresponded to the lower limit of permeability. The pore-throat radius and permeability limits were 22 nm and 0.08 mD for the Daqing tight oil reservoir and 18 nm and 0.03 mD for the Changqing tight oil reservoir, respectively.

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.

Study on Pore Structures of Tight Sandstone Reservoirs Based on Nitrogen Adsorption, High-Pressure Mercury Intrusion, and Rate-Controlled Mercury Intrusion

Pore–throat size is a key parameter for the assessment of reservoirs. Tight sandstone has the strong heterogeneity in the distribution of pores and throats; consequently, it is very difficult to characterize their distributions. In this study, the existing pore–throat characterization techniques were used jointly with scanning electron microscopy (SEM), low-temperature nitrogen adsorption (LTNA), high-pressure mercury intrusion (HPMI), and rate-controlled mercury intrusion (RCMI) technologies to highlight features of throat sizes and distribution of pores in tight sandstone reservoirs of the Y Basin in China. In addition, full-scale maps (FSMs) were generated. The study results show that key pore types in reservoirs of the Y Basin include residual intergranular pores, dissolved pores, clay mineral pores, and microfractures. LTNA can effectively characterize the distribution of pore–throats with a radius of 2–25 nm. HPMI test results show that tight sandstones contain throats with a radius less than 1000 nm, which are mainly distributed in 25–400 nm and have a unimodal distribution. RCMI tests show that there is no significant difference in pore radius distribution of the tight sandstones, peaking at approximately 100,000–200,000 nm; the throat radius of tight sandstones varies greatly and is less than 1000 nm, in agreement with that of HPMI. Generally, the pore–throat radius distribution of tight sandstones is relatively concentrated. By using the aforementioned techniques, FSM distribution features of pore–throat radius in tight sandstone can be characterized effectively. G6 tight sandstone samples develop pores and throats with a radius of 2–350,000 nm, and the pore–throat types of tight sandstone reservoirs in Y basin are mainly mesopores and macropores.

Insights into deep, onshore Gulf of Mexico Wilcox sandstone pore networks and reservoir quality through the integration of petrographic, porosity and permeability, and mercury injection capillary pressure analyses

In the Paleocene to Eocene Wilcox Group in the northern Gulf of Mexico, exploration targets are reaching into deep to ultradeep burial depths. At these great depths, reservoir quality (porosity and permeability) becomes an important risk factor in determining the chance of encountering an economic reservoir. Major controls on reservoir quality are pore types and abundances, pore-throat sizes, and pore network composition. These factors can be analyzed by integrating petrographic, core plug porosity and permeability, and mercury injection capillary pressure (MICP) analyses. The Wilcox sandstones are mostly lithic arkoses and feldspathic litharenites that contain primary interparticle pores, secondary dissolution pores, and micropores. However, these pore types evolve with depth and temperature. As temperature increases, the relative abundance of primary interparticle pores decreases, whereas the relative abundance of secondary dissolution pores and nano- to micropores increases. Associated with this evolution of pore networks with increasing temperature, there is a decrease in reservoir quality. This decrease in reservoir quality is caused by a transition to finer pore-throat sizes that correspond to changes in pore types. Petrographic analysis provides information on pore types, core plug porosity and permeability analysis provides information on volume of pores and effectiveness of flow, and MICP analysis provides information on pore-throat radius distribution. Through forecasting the pore network in the target temperature zone, a realistic porosity versus permeability transform can be selected to estimate permeability from wire-line log porosity.

Study of the Imbibition Behavior of Hydrophilic Tight Sandstone Reservoirs Based on Nuclear Magnetic Resonance

Hydraulic fracturing is one of the key technologies to enhance the oil recovery from tight sandstone reservoirs. The study on the behavior of imbibition for tight sandstone reservoir is of great significance to increase oil production after fracturing. In this paper, nuclear magnetic resonance (NMR) and high-pressure mercury injection were implemented on the samples taken from the Yanchang Formation of the Ordos Basin. The NMR T2 curves of the core at the state of 100% water saturated were converted to pore-throat radius distribution curves. On this basis, the experiments of imbibition and displacement were conducted and the changes of fluid distribution, imbibition quantity, and imbibition rate with different scale pores and different imbibition times were analyzed. Moreover, the results of imbibition and displacement were compared to assess the distribution of the recoverable and remaining oil under two exploitation modes and the contribution of imbibition made to displacement in pores at different scales. The result shows that imbibition is a relatively slow process. The entire imbibition process is mainly affected by nanopores, which are widely distributed in cores, and the imbibition rate of total pores constantly decreases as the imbibition time increases. Moreover, the relative recovery in pores at different scales shows a huge difference under the two exploitation modes of imbibition and displacement. During imbibition, smaller pores produced higher degrees of oil, while during displacement, larger pores have higher relative recovery. The contribution of imbibition made to displacement in nanopores was the highest and decreased with the increase of the pore-throat size.

Pore Structure Characterization of the Tight Reservoir: Systematic Integration of Mercury Injection and Nuclear Magnetic Resonance

Pore structure is the most important factor affecting reservoir quality and petrophysical property of tight reservoir. The effective characterization of pore structures, including pore radius distribution (PRD), throat radius distribution (TRD), pore-throat radius distribution (PTRD), relevant pore structure parameters, etc., is of great importance for the oil exploration and exploitation. Taking the tight sandy conglomerate reservoir as research target of tight reservoir, this paper characterizes the pore structures by a combination of experiments on parallel core samples. These experiments include high-pressure mercury injection (HPMI), constant-rate mercury injection (CRMI), nuclear magnetic resonance (NMR), as well as microscopic analysis of casting thin sections and scanning electron microscopy (SEM). This paper systematically analyzes the advantages and shortcomings of these commonly used experimental techniques. And then, novel methods are proposed to characterize the pore structure (especially the full-range PRD, TRD, and PTRD) by utilizing the advantages of these techniques. In addition, an advanced pore classification scheme is proposed to reclassify the pore types. Finally, the controls of the pore structure on the flow characteristics are investigated, which in turn further demonstrates the correctness and importance of the proposed novel methods for characterizing pore structures. In summary, this study proposes novel methods to characterize the pore structure by integration of HPMI, CRMI, and NMR and provides insights into the pore structure characteristics of the tight sandy conglomerate reservoir.

Quantitative characterization of pore structure of the Carboniferous–Permian tight sandstone gas reservoirs in eastern Linqing depression by using NMR technique

Micro-nano scale pores can accurately and fastly be measured by the nuclear magnetic resonance (NMR) technique, which provides a new method to quantitatively characterize pore structures in tight sandstone. Based on the method of calibration of mercury pressure data for NMR T2 spectrum, for the measurement inaccuracy due to the mercury saturation less than 100% in tight sandstone, the mercury pressure curve and T2 spectrum is used to cumulate from the maximum pore on the right boundary to the small pores in the left, the range of pore-throat radius measured by the mercury injection in the leftward cumulative curve is selected as a comparable interval of NMR pore-throat radius, and the longitudinal interpolation method and the least square method are utilized to construct the distribution curve of pore-throat radius transformed by T2 spectrum. The modified method is used to obtain NMR T2 spectrum, conversion coefficient of pore-throat radius and pore-throat radius distribution of the Carboniferous-Permian tight sandstone gas reservoirs in the eastern Linqing depression, and characteristics of reservoir pore structures are quantitatively investigated; in addition, in combination with analysis of thin section and scanning electron microscopy, the reservoir effectiveness and cause of the pore structure variability in the tight sandstone are also well studied. The results show that the NMR pore-throat radius curve obtained by the modified method has a high consistency with the mercury injection curve, and the NMR test accuracy of tight sandstone is significantly improved. In the study area, the pore-throat radius of the Carboniferous-Permian tight sandstone mainly ranges from 0.002 to 2 μm, the pore is generally submicro-nano scale, but the pore-throat radius distribution of different types of sandstone varies significantly. The lithic quartz sandstone is rich in siliceous matter and poor in plastic detritus and matrix, generally dominated by submicro-scale pore-throats including micro-scale pore-throats; lithic feldspar sandstone and quartz-rich feldspar lithic sandstone are rich in quartz and poor in plastic detritus and matrix, dominated by submicro-nano scale pore-throats (nano-scale pore-throats predominantly); the lithic fragment-rich feldspar lithic sandstone and lithic sandstone are poor in quartz and rich in plastic detritus and matrix, mainly dominated by nano-scale pore-throats smaller than 0.05 μm. Micropetrographic components are key factors to control pore structure difference and reservoir effectiveness, and the reservoir quality may be macroscopically controlled by sedimentary microfacies; the lithic quartz sandstones of coarse- and fine-grained point bar/riverbed microfacies are the most favorable reservoirs; the lithic feldspar sandstone of fine-grained point bar microfacies, the quartz-rich feldspar lithic sandstone of fine-grained distributary channel and barrier bar microfacies are relatively favorable reservoirs, while both lithic fragment-rich feldspar lithic sandstone and lithic sandstone of tidal-flat facies are ineffective reservoirs with very poor porosity and permeability.

Determination of microscopic waterflooding characteristics and influence factors in ultra-low permeability sandstone reservoir

Actual sandstone micromodel was used in this work to conduct the microscopic waterflooding experiment of ultra-low sandstone reservoir, since the inside seepage characteristics of microscopic waterflooding process of Chang 8 ultra-low permeability sandstone reservoir of Upper Triassic Yanchang formation in Huaqing region of the Ordos Basin, China is difficult to observe directly. Combined with physical property, casting thin sections, constant-rate mercury injection capillary pressure and nuclear magnetic resonance, the influence of reservoir property on the waterflooding characteristics in pores were analyzed and evaluated. Seepage paths of waterflooding characteristics were divided into four types: homogeneous seepage, reticular-homogeneous seepage, finger-reticular seepage and finger-like seepage, the waterflooding efficiency of which decreases in turn. More than 70% of residual oil occurs as flowing-around seepage and oil film. Physical property, pore structure and movable fluid characteristics are all controlled by digenesis and their impacts on waterflooding efficiency are in accordance. Generally, the pore throat radius size and distribution and movable fluid percentage are closely related to waterflooding law.

Application of Nuclear Magnetic Resonance (NMR) Logs in Tight Gas Sandstone Reservoir Pore Structure Evaluation

Based on the simultaneously applied mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR) laboratory experimental results for 20 core samples from tight gas sandstone reservoirs of the Sichuan basin, the relationships of the piecewise power function between nuclear magnetic resonance (NMR) transverse relaxation T2 time and capillary pressure (Pc) are established. A novel method, which is used to transform NMR reverse cumulative curve as pseudo capillary pressure (Pc) curve is proposed, and the corresponding model is established based on formation classification. By using this model, formation pseudo Pc curves can be consecutively synthesized. The pore throat radius distribution, and pore structure evaluation parameters, such as the average pore throat radius (Rm), the threshold pressure (Pd), the maximum pore throat radius (Rmax) and so on, can also be precisely extracted. After this method is extended to field applications, several tight gas sandstone reservoirs are processed, and the predicted results are compared with core derived results. Good consistency between evaluated results with core derived results illustrates the dependability of the proposed method. Comparing with the previous methods, this presented model is much more theoretical, and the applicability is much improved.

A New Method of Evaluating Tight Sandstone Reservoir Pore Structure from Conventional Logs

The identification and evaluation of tight gas sandstone reservoirs faces a great challenge due to the characteristics of ultra-low porosity, ultra-low permeability, complicated pore structure and strong heterogeneity. To improve tight gas sandstone reservoir evaluation, the pore structure should be first quantitatively evaluated. NMR logs are advantageous in formation pore structure evaluation, but may not always be practicable as they are only acquired in limited wells. This study is based on the analysis of morphological characteristics of experimental mercury injection capillary pressure (MICP) curves for 54 core samples from tight gas sandstone reservoirs of central Sichuan Basin, southwest China. A new method is proposed to construct pseudo capillary pressure curves from conventional porosity and permeability. The corresponding models of predicting pseudo Pc curves from conventional logs are established. The reliability of this technique is verified by comparing constructed capillary pressure curves with laboratory measured results. After this technique is extended to field application, consecutive pseudo capillary pressure curves are constructed, and the parameters associated with reservoir pore structure evaluation, such as pore throat radius distribution, the average pore throat radius, the threshold pressure, and so on, are estimated. Combining with these parameters, tight gas sandstone reservoirs pore structures are quantitatively evaluated, and effective formations can be easily identified. The proposed technique is more universally applicable in tight gas sandstone reservoir pore structure evaluation as it does not require the acquisition of field NMR logs.

Retraction

Amir Maher S. Lala and Nahla A. A. El‐Sayed, (2015). Controls of Pore Throat Radius Distribution on Permeability. Geofluids. Accepted Article online. doi: 10.1111/gfl.12158The above article from Geofluids, published as an Accepted Article online on 25 September 2015 in Wiley Online Library (wileyonlinelibrary.com), has been withdrawn by agreement between the authors, Amir Lala and Nahla El‐Sayed, the journal Editors in Chief, Craig Manning, Mark Person and Giuseppe Etioppe, and John Wiley and Sons Ltd. The retraction has been made as a consequence of a change in the publication model of Geofluids, as a result of which the author is free to submit the article elsewhere.

A new technique for synthetizing capillary pressure (Pc) curves using NMR logs in tight gas sandstone reservoirs

Formation pore structure prediction is of great importance in tight gas sands evaluation, and NMR logs are considered to be an advantage in this aspect. The common method that is used to evaluate formation pore structure from NMR logs is transforming the NMR T2 spectra as capillary pressure curves and then extracting the pore throat radius distribution from the synthetized capillary pressure curves and predicting pore structure evaluation parameters. However, field applications demonstrate that the existing methods are not always practicable; additionally, many existing methods involve input parameters that are difficult to obtain, especially in tight gas sandstone reservoirs. This study is based on the analysis of the morphology of lab mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR). This experiment used 20 core samples that were drilled from tight gas sands of the central Sichuan basin. Our findings indicate that rock pore structure, the values of mercury injection saturation (SHg) under every capillary pressure (Pc), and pore component percentage compositions are interrelated. To quantitatively express this interrelationship, seven T2cutoffs, which are used to classify NMR T2 spectra into eight parts, are defined to calculate eight pore component percentage compositions from the NMR logs. A novel technique, which connects the SHgs and eight pore component percentage compositions, is proposed to construct pseudo Pc curves. Once this technique is extended to field applications, consecutively synthetic Pc curves can be predicted in the intervals with which field NMR logs were acquired. Additionally, pore throat size distribution and pore structure evaluation parameters can also be calculated. A field example of the Sichuan basin illustrates that this technique is reliable and that the predicted results from the field NMR logs match the core experimental measurements very well. The greatest advantage of this proposed technique is that no intermediate parameters need to be acquired from other methods.

A new methodology of constructing pseudo capillary pressure (Pc) curves from nuclear magnetic resonance (NMR) logs

In this paper, based on the analysis of lab experimental results of 20 core samples, which were drilled from tight sandstone reservoirs of Sichuan basin, and simultaneously applied for mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR) measurements, the relationships of piecewise power function between NMR transverse relaxation T2 time and pore-throat radius Rc are established. A novel classified piecewise power function (CPPF) method, which is used to transform NMR reverse cumulative curve as pseudo capillary pressure (Pc) curve is proposed, and the corresponding model is established based on formation classification. By using this model, formation pseudo Pc curves can be consecutively synthesized in the intervals with which field NMR logs were acquired. The pore throat radius distribution, and pore structure evaluation parameters, such as average pore throat radius (Rm), threshold pressure (Pd), maximum pore throat radius (Rmax) and so on, can also be precisely extracted. Several tight sandstone reservoirs are processed by using this method, and the predicted results are compared with core derived results. Good consistency between the evaluated results with core derived results illustrates the dependability of the proposed method.

An empirical approach of evaluating tight sandstone reservoir pore structure in the absence of NMR logs

Abstract Tight sandstone reservoirs identification and evaluation face a great challenge due to the characteristics of ultra-low porosity, ultra-low permeability, complicated pore structure and strong heterogeneity. To improve tight sandstone reservoirs evaluation, the pore structure should be first quantitatively evaluated. The NMR logs are advantageous in formation pore structure evaluation, whereas they may not be always practicable, because the NMR logs are acquired only in the limited wells. In this study, an alternative empirical technique, which is established based on the lab experimented mercury injection capillary pressure (MICP) curves for 54 core samples drilled from tight sandstone reservoirs of central Sichuan basin, Southwest China, is proposed to construct pseudo capillary pressure (Pc) curve from conventional porosity and permeability. The reliability of this technique is verified by comparing constructed pseudo Pc curves with lab measured results. To make this empirical approach can be widely practicable, formations should be first classified into three types based on the difference of J function, and the models are calibrated by using plenty of core derived results. After this technique is extended to field application, consecutive pseudo Pc curves are constructed, and the parameters associated with reservoir pore structure evaluation, such as the pore throat radius distribution, the average pore throat radius, the threshold pressure, and so on, are estimated. Combining with these parameters, tight sandstone reservoirs pore structure are quantitatively evaluated, and effective formations are easily identified. Comparing with methods based on the NMR logs, the proposed technique is much universally applicable in tight sandstone reservoirs pore structure evaluation in formations with which field NMR logs were not acquired.