Pseudo Capillary Pressure Research Articles

Modified Low-Field NMR Method for Improved Pore Space Analysis in Tight Fe-Bearing Siliciclastic and Extrusive Rocks

Abstract Understanding the filtration and storage properties of tight reservoirs is crucial for efficient resource exploitation, particularly in unconventional formations. This study presents two low-field nuclear magnetic resonance (LF-NMR) techniques: standard cut-off and modified differential approaches combined with mercury injection capillary pressure (MICP) and X-ray diffraction (XRD) studies to evaluate porosity and pore size distribution (PSD) in such formations. The differential technique involves subtracting the dry sample signal from a 100% water-saturated one, allowing the chemically bound water compound to be eliminated and facilitating PSD analysis. Through the application of the percolation theory, we established a power–law relationship between LF-NMR transverse relaxation time (T2) and MICP pore-throat diameter, enabling the derivation of PSD and pseudo capillary pressure curves. Our methodology was validated on a sample set representing tight sandstones, conglomerates, and extrusive rocks with high clay and iron mineral content, demonstrating the superior accuracy of the modified differential method in estimating effective porosity and absolute PSD in comparison with the standard approach. While the use of the percolation theory in PSD conversion was successful for rocks with unimodal distributions, it often failed for rocks with larger voids. The study also revealed that the relationship between the LF-NMR transverse relaxation times and MICP pore sizes is both nonlinear and challenging to describe with a universal equation, especially in the presence of para- and ferro-magnetic elements in the rock matrix. Despite obstacles to the complete elimination of the influence of these minerals on the T2 distribution, employing the modified differential LF-NMR method significantly mitigated this effect and offered a precise and noninvasive way of characterizing the petrophysical properties of tight reservoir rocks. Consequently, our studies offer a significant step toward a more precise assessment of pore structures in unconventional reservoirs that could be translated into more efficient strategies for locating geothermal heat and hydrocarbon resources.

Evaluation of top seal capacity by pseudo-capillary pressure model in Suriname offshore Basin

Drilled well data and 3D seismic data are integrated to model the seal capacity of the Late Campanian- Maastrichtian mudstone in the exploration Block 52 operated by PETRONAS Suriname Exploration & Production BV. The study proposes simple relationships between interval velocity and porosity, porosity against permeability, and normal compaction of the mudstone with depth, based on the drilled well data. The most likely model of the top seal capacity suggests a maximum column height to be in the range of 330 – 350 m in the study area for gas. The model also suggests a gradual increase in the top seal risk towards the northeastern direction of the study area which may be due to the effect of sediment fairway from the nearby Demerara High. On the other hand, an increasing trend of top seal capacity towards the southwestern side of the block relates to the possible effect of the thicker deposition of transgressive fine-grained package with more compaction resulting in a decreasing trend of porosity and permeability of the mudstone.

Saturation evaluation of tight sandstone in the Dayi structure, West Sichuan Depression

Tight sandstone reservoirs are characterized by poor physical properties, strong heterogeneity, and complex pore structures, resulting in low reservoir saturation calculation accuracy, and the log interpretations do not match the gas test results. In response to the aforementioned problems, the tight sandstone reservoir of the third member of the Xujiahe Formation of the Dayi structure in the Western Sichuan Depression was investigated through a series of experiments on petrophysical properties, casting thin-section identification, rock resistivity, nuclear magnetic resonance, and high-pressure mercury intrusion. Then, after a systematic analysis of the influence of different factors, including physical properties, mineral composition, and pore structure, on the rock-electric parameters, the parameters of the Archie model were appropriately corrected. The results showed that, for tight sandstone reservoirs, the cementation exponent was mainly affected by the physical properties and clay content, and the saturation exponent was controlled by the proportion of relatively large pore components in the total pore system. Therefore, the non-linear least squares method was used to construct the variable cementation index model; the pseudo-capillary pressure curve was constructed, and a new parameter “the large-pore proportion,” which is used to optimize the saturation exponent, was proposed in combination with the fractal theory. Finally, an Archie model with variable parameters was used to process the actual logging data in the study area. The results show that this method can obtain more accurate gas saturation, providing a new idea and method for fine sandstone saturation logging evaluation.

Pore structure analysis and classification of pyroclastic reservoirs in the Dehui fault depression based on experimental and well-logging data

The classification of pyroclastic reservoirs based on their pore structure has attracted the attention of many researchers in recent years. In this study, through thin section observations and scanning electron microscopy (SEM), mercury injection capillary pressure (MICP), nuclear magnetic resonance (NMR) and other relevant analyses, the reservoir in the third member of the Huoshiling Formation in the Dehui fault depression is classified into three separate types. The results show that a large number of devitrification corrosion pores are developed in the type-I reservoir, while the type-II reservoir contains matrix and dissolution pores. Moreover, the type-III reservoir only contained matrix-pores. Considering the complexity of the pore structure of the pyroclastic reservoir rocks, we established a relationship between the pseudo-capillary pressure curves and the NMR logging for the micro- and macro-pores in each reservoir type. Through the processing and analysis of key wells, it was found that the threshold pressure and median pressure obtained via NMR logging correspond well with the experimental core data. This enabled us to classify the reservoir type in several other wells and delineate the prolific regions in the study area that contain type-I and type-II reservoirs. The pseudo-capillary pressure curve can be used to continuously evaluate the pyroclastic reservoir pore structure longitudinally, which has very important practical significance in production applications.

Quantitative evaluation of reservoir quality of tight oil sandstones in chang 7 member of Ordos Basin

In order to establish a quantitative evaluation system for reservoir quality suitable for tight oil sandstones, in this study, taking the Chang 7 Member in the Maling area of the Ordos Basin as an example, the nuclear magnetic resonance, clay mineral analysis, high pressure mercury injection analysis and logging interpretation technology have been used to carry out a comprehensive evaluation of the pore structures, sand body structures and oil-bearing properties of tight oil sandstone reservoirs. The results show that the pseudo-capillary pressure curves transformed by the NMR T2 spectra are consistent with the capillary pressure curves measured by the core experiments. This method can be used for accurate characterization of the pore structures of the reservoir. The pore structure parameters calculated based on the pseudo-capillary pressure curves can accurately reflect the pore structures of the reservoirs such as micropores-thin throats and complex tortuosity. At the same time, the smoothness feature of conventional logging curves is used to evaluate the sand body structures and heterogeneity of the reservoir, and the apparent energy storage coefficient is introduced to quantitatively evaluate the oil-bearing properties of tight oil reservoirs. The evaluation results are in good agreement with the actual production situation. The larger the apparent energy storage coefficient, the higher the initial output of the oil wells. The evaluation results of the reservoir quality of the tight oil sandstones constructed in this paper are highly consistent with the production status, so the method has broad application prospects.

Fluid Identification Based on NMR Apparent Free Water Porosity Inversion: A Case Study of Paleozoic Tight Sandstone Gas Reservoirs in Western Ordos

Tight sandstone reservoirs are affected by various factors such as pore structure, formation water salinity, and siliceous cementation, which lead to the abnormal phenomenon of high-resistivity water layers and increase the difficulty in identifying gas and water layers by conventional logging. In this study, the pore types and pore size distribution characteristics of tight sandstone reservoirs were firstly determined by NMR and high-pressure mercury injection experiments, and then the iterative least-square method was used to automatically optimize the inversion method of pseudo-capillary pressure curve and search for the optimal conversion coefficient. Finally, the apparent free water porosity was inversed and the fluid identification standard was obtained and applied. The results showed that the reservoirs mainly developed intergranular pores, cutting solution pores, and intergranular pores. The pore throats were poorly sorted, and the displacement pressure was high. The median radius ranged from 0.01 to 0.48 μm, and the main peak range was from 0.02 to 0.06 μm. Pores were of mainly small-hole fine throat type. In the inversion results of the optimal conversion coefficient, the correlation coefficient between the aperture parameters and the results of high-pressure mercury injection experiments was greater than 0.93. According to the fluid property identification standard based on nuclear magnetic apparent free water porosity, the high-resistivity water layers were effectively identified and its coincidence rate with the final field test was 10.7% higher than that of the conventional method. This identification method can be used to identify complex fluids in tight sandstone reservoirs.

A novel experimental approach for dynamic quantification of liquid saturation and capillary pressure in shale

Determination of dynamic fluid intrusion in tight oil reservoirs requires a very careful and precise estimation of changes in fluid volumes during spontaneous and forced imbibition. Because of the extremely low permeability of these mudrocks, only very small volumes of fluid can flow through the matrix. To overcome this limitation, the pressure decay method commonly used to estimate permeability and porosity in tight rocks is adapted to determine liquid saturation in tight rocks using a slightly compressible fluid as the confining medium. This adaptation uses the transient pressure drop within the bulk liquid surrounding the rock during confinement, to dynamically estimate the volume of fluid intrusion within the tight rock. Pressure decay data for shale samples from the Eagle Ford, Utica and Bakken formations, each of varying particle diameter were obtained experimentally from batch tests. The total pressure drop observed for each shale type was used to measure oil saturations and a pseudo capillary pressure curve was derived from the pressure and saturation data. These measurements were confirmed with NMR measurements made on the same samples (before and after oil saturation).The results show that shale formations with larger permeability tend to absorb more incremental oil during forced imbibition than that which it absorbs during spontaneous imbibition. Furthermore, it was observed that the duration of oil intrusion at lower initial pressures during forced imbibition was longer than the time interval observed for oil intrusion at higher initial pressures for the same particle size. Also, in relation to particle size, it was observed that a significant amount of oil intrusion occurred at lower pressures for large shale crushed samples during forced imbibition, in contrast to smaller oil intrusion observed for small sized particles at lower pressures. The reason for this is because larger sized samples possess micro cracks which serve as extra channels through which oil can penetrate.

Estimation of oil saturation via pseudo capillary pressure curve from nuclear magnetic resonance log data in tight conglomerate reservoirs

Tight conglomerate reservoirs have complex pore structure and strong heterogeneity which could bring great difficulties in the identification of oil and water layers. In order to solve this problem, the tight conglomerate reservoirs of Triassic Baikouquan Formation and Permian Urho Formation in Mahu Depression, Northwest Junggar Basin in China are selected as the study area. Firstly, 23 representative core plunger samples were selected from 9 wells. The experimental data of helium porosity, permeability, mercury intrusion capillary pressure (MICP) curve, and nuclear magnetic resonance (NMR) T2 spectrum under completely watered condition were measured and analyzed. Secondly, conglomerate reservoir classification criterion was built based on flow zone indicator (FZI). Its classification results conform to the classification of J function and core images. Thirdly, the piecewise power function was adopted to predict the pseudo capillary pressure curve by NMR T2 spectrum and the corresponding models were established via reservoir classification. Fourthly, based on the obtained pseudo capillary pressure curve and average J function curve, a novel method for predicting oil saturation by the ratio of median radius was proposed. Finally, the built models were used to process the experimental data not involved in modeling and log data. The predicting results are well consistent with the experimental results, which indicates the high reliability of the models. The established models are essential for helping the classification of tight conglomerate reservoirs, calculation of reservoir parameters, and identification of oil and water layers.

Study on pore structure evaluation of shale gas reservoir-Taking the Lower Cambrian Niutitang Formation in the Cenggong Block, Guizhou Province as an example

The storage and seepage space of shale is mainly composed of pores and fractures, while the microscopic pore structure and fracture distribution are very complicated. The accuracy of calculation of pore structure parameters is related to whether the reservoir evaluation is correct and effective. Taking the Niutitang Formation in the Cengong area of Guizhou as the research object. Firstly, based on the Archie formula, the process of the wellbore mud intrusion is approximated as the process of the laboratory high pressure mercury intrusion, combined with conventional and nuclear magnetic resonance logging data. The formula deduces a new model for the T2 spectrum conversion pseudo-capillary pressure curve. Then the model is calibrated by the high pressure mercury intrusion experimental data, and the pore structure parameters such as reservoir pore size distribution curve and maximum pore throat radius are calculated. The results show that the maximum pore throat radius and total porosity data calculated by NMR logging are relatively reliable, the median radius error is general, and the displacement pressure and median pressure error are relatively large. The pore volume percentage of 1-10 μm is up to 60%, and the micro-cracks are relatively developed, which is beneficial to the fracturing of the reservoir. Therefore, the use of NMR logging data combined with conventional logging can better reflect the pore structure characteristics of reservoirs, which provides a strong support for complex reservoir identification and qualitative prediction of productivity, and has a good application prospect.

Generating pseudo-capillary pressure curves from nuclear magnetic resonance (NMR) data: a case study from the Cooper Basin, Australia

This study evaluates the accuracy of generating pseudo-capillary pressure curves from laboratory nuclear magnetic resonance (NMR) analysis and NMR wireline log data by comparing threshold pressures and curve characteristics to rock-derived mercury injection capillary pressure (MICP) analysis. Accurate production of pseudo-capillary pressure curves from NMR data could negate or reduce the need for expensive and rig-time-consuming core acquisition and subsequent MICP analysis. Successful application of this technique will allow production of pseudo-capillary pressure curves for large stratigraphic intervals at a significantly reduced cost and help to better constrain petroleum reserves and improve near field exploration prediction outcomes. The Tindilpie-11 well in the Cooper Basin, Australia, was used as a case study because of extensive existing conventional ore analysis and presence of an NMR wireline log covering the sampled intervals in the Permian-aged Patchawarra Formation. Six core samples underwent MICP and laboratory NMR analyses, with capillary pressure curves generated for each method. Six pseudo-capillary pressure curves were also generated from the NMR wireline log data at the coincident sample depths. The pseudo-capillary pressure curves generated from laboratory NMR data closely resemble the MICP results (mean threshold pressure error of 0.63 MPa absolute [91.4 psi]) and proved the applicability of this approach. The NMR wireline log data used is an average over a ∼1.6 m interval, which has likely led to discrepancies when compared with laboratory NMR pseudo-capillary pressure curves and MICP curves. Nonetheless, this study confirms the applicability of using laboratory NMR data to generate pseudo-capillary pressure curves that resemble MICP results. Continued development of NMR log technology and reduced logging speeds will improve the data resolution and ultimately provide high density NMR data that can be used to create pseudo-capillary pressure curves for large stratigraphic intervals at a significantly reduced cost. KEY POINTS Pseudo-capillary pressure curves derived from NMR data. Reservoir characterisation requiring minimal rock acquisition for ground truthing. Case study on the Patchawarra Formation (Cooper Basin, Australia) using SCAL data.

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.

A practical method to construct capillary pressure curves of reservoir using NMR logging date

A new method to construct the pseudo-capillary pressure curve using nuclear magnetic resonance (NMR) logging data is established. In this method, the displacement pressure can be predicted using the maximum relaxation time of T2 spectrum of nuclear magnetic resonance (NMR) logging. Next, the effective porosity and density of rock, calculated from logging data, are used to predict the maximum mercury saturation. Then the mercury saturation at displacement pressure point and threshold pressure point can be estimated according to empirical data. Thus, the four important points on the capillary pressure curve can be obtained, namely zero point, displacement pressure, threshold pressure and end point. Then, referring to the 4 pressure points above, the pseudo-capillary pressure curve is constructed in two sections with the dividing point of threshold pressure. The method is convenient especially for the evaluation of deep and complex formations where the coring is difficult. [Received: July 12, 2017; Accepted: December 15, 2017]

An innovative technique for estimating water saturation from capillary pressure in clastic reservoirs

A major drawback of old resistivity tools is the poor vertical resolution and estimation of hydrocarbon when applying water saturation (Sw) from historical resistivity method. In this study, we have provided an alternative method called saturation height function to estimate hydrocarbon in some clastic reservoirs in the Niger Delta. The saturation height function was derived from pseudo capillary pressure curves generated using modern wells with complete log data. Our method was based on the determination of rock type from log derived porosity-permeability relationship, supported by volume of shale for its classification into different zones. Leverette-J functions were derived for each rock type. Our results show good correlation between Sw from resistivity based method and Sw from pseudo capillary pressure curves in wells with modern log data. The resistivity based model overestimates Sw in some wells while Sw from the pseudo capillary pressure curves validates and predicts more accurate Sw. In addition, the result of Sw from pseudo capillary pressure curves replaces that of resistivity based model in a well where the resistivity equipment failed. The plot of hydrocarbon pore volume (HCPV) from J-function against HCPV from Archie shows that wells with high HCPV have high sand qualities and vice versa. This was further used to predict the geometry of stratigraphic units. The model presented here freshly addresses the gap in the estimation of Sw and is applicable to reservoirs of similar rock type in other frontier basins worldwide.

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.

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.

A QUANTITATIVE EVALUATION METHOD OF LOW PERMEABLE SANDSTONE PORE STRUCTURE BASED ON NUCLEAR MAGNETIC RESONANCE (NMR) LOGGING: A CASE STUDY OF Es4 FORMATION IN THE SOUTH SLOPE OF DONGYING SAG

AbstractLow permeability sandstone has become an important target of exploration and development for increasing reserves and productions, while the complicated pore structure makes the reservoir and its effectiveness difficult to accurately identify. We used the physical property, mercury injection, and nuclear magnetic data to analyze the pore structure of low permeability sandstone of the Es4 in the south slope of Dongying sag, and divided the pore structure into three different types. Nuclear magnetic T2 spectrum and capillary pressure can reflect the distribution of pore throat to a certain extent. The pseudo capillary pressure curve reconstructed by T2 spectrum with the routine method can be used to invert for the pore radius distribution, but there is a large error between the pore radius distribution and capillary pressure pore‐throat radius distribution. The rock pore free fluid T2 and mercury intrusion pore throat size distribution have a better corresponding relationship. Therefore, this relationship is used to construct the formula for different pore structure types and on different pore scales (large scale: the linear relationship; small scale: power function in different scale). By identifying the pore structure types along the wellbore profile, we can further determine the pore radius distribution using NML data without building the pseudo capillary curve. And this method not only supply a direct evidence for efficiency evaluation of low permeability sandstone reservoir, but also play an important role in the exploration of quantitative inversion of the pore radius distribution on a micro‐scale.

Improvements on “Application of NMR logs in tight gas reservoirs for formation evaluation: A case study of Sichuan basin in China”

Abstract Xiao et al. (2012) proposed a method of the synthetic pseudo-capillary pressure (Pc) curves from the NMR logs based on a J function method. This method was verified to be effectively applied in the field with similar formation properties. However, it cannot be applied if the formation properties are different, which results to the different J function from the experimented Pc curves of core samples. To improve the applicability of the method of Xiao et al., 84 core samples, drilled from 4 different basins in China, are supplemented for nuclear magnetic resonance (NMR) and mercury injection capillary pressure (MICP) experimental measurements, and they are classified into three types by using a hydraulic flow unit (HFU) method based on a flow zone indicator (FZI) parameter. For each type of rocks, the properties are similar, and they can be expressed by the same J functions. In this case, Xiao's method is applicative. These 84 core samples are reused to calibrate the involved input parameters in the model of Xiao et al., separately. Several wells from different regions are processed by using the calibrated models. Field applications illustrate that the improved models are much more effective in formation evaluation.

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.

Comments on “Construction of synthetic capillary pressure curves from the joint use of NMR log data and conventional well logs”

Abstract Recently, Eslami et al., (2013) proposed a method of constructing pseudo capillary pressure curves by combining with NMR log data and conventional well logs following a two-step approach. Using this method, Eslami et al. declared that the simulated P c curves showed a good agreement with laboratory derived mercury injection capillary pressure (MICP) curves at low mercury saturations ( P c curves with the experimented results illustrates that the constructed P c curves are overestimated. The parts for constructed P c curves with mercury injection saturations ( S Hg s) higher than 35% are all under the laboratory experimented results. This means this technique cannot be accurately apply for formation pore structure evaluation, especially for carbonate rocks and tight sandstone reservoirs. In this paper, we point out that the uncertainty Eslami's method is caused by the dimension difference of mercury injection pressure and 8 T 2 porosity bins, and a technique of improving P c curve construction is proposed. The reliability of the improved technique is verified by the application of the same 3 core samples displayed in Eslami's paper.