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The type and content of clay minerals in tight sandstone reservoirs of the He-1 member in the Jin-30 well area of Hangjinqi in the northern margin of the Ordos Basin have a significant effect on irreducible water saturation. On the basis of core observation, the petrological characteristics, clay mineral types and occurrence forms, pore structure and irreducible water distribution of the target layer by means of X-ray diffraction analysis, high-resolution scanning electron microscopy, casting thin section analysis, one-dimensional nuclear magnetic resonance experiment and high-pressure mercury injection experiment were studied. The results show that: (1) The average content of clay minerals in the reservoir is 18.36%, and the clay minerals mainly include kaolinite, illite, chlorite and illite/smectite mixed layers. (2) There are differences in the types of clay minerals in different lithofacies: the clay minerals in lithic quartz sandstone are mainly feldspar altered kaolinite, and feldspar intragranular dissolution pores, and kaolinite intergranular pores are developed. The lithic sandstone is mainly composed of lithic and matrix altered illite, and the intragranular dissolution pores filled with illite are developed. The BRIEF REPORT is available for this paper at http://www.ykcs.ac.cn/en/article/doi/10.15898/j.ykcs.202407150157.

Abstract Irreducible water saturation is an important factor affecting the development effect of low permeability reservoir. Using the self-developed ultrasonic generator, kerosene was used as simulated oil, the natural low-permeability siltstone cores with different physical properties in Zhongyuan Oilfield were selected for indoor oil displacement experiment, and the effect of ultrasonic action on the saturation of irreducible water in low-permeability reservoirs was evaluated. It was found that ultrasound can further reduce the saturation of irreducible water on the basis of oil flooding. The influence of different frequencies of ultrasound on the saturation of reservoir core irreducible water is different, and there is an optimal range of ultrasonic frequency: 17 kHz ~ 125 kHz. Increasing the ultrasonic power can effectively reduce the saturation of the core irreducible water in the low-permeability reservoir, and increasing the ultrasonic power can compensate for the adverse effects caused by the increase in frequency. With the increase of ultrasonic power, the thickness of the water film first decreases rapidly, and then gradually stabilizes, the highest drop could be 67.19%. The effect of ultrasound on the reduction of the saturation of irreducible water gradually deteriorates, with the increase of temperature, and at a higher temperature of 70 °C, the ultrasonic effect can still reduce the saturation of irreducible water. The effect of ultrasound on the saturation of irreducible water at low temperature is more intense, compared with high temperature, the irreducible water saturation can be reduced by 9.26%, and the ultrasonic effect is more suitable for low temperature treatment. The effect of ultrasound on the reduction of saturation of irreducible water in reservoirs with poor physical properties is more obvious.These studies are helpful for the systematic understanding of the effect of ultrasound on low permeability reservoirs and have positive implications for improving the development effect of low permeability reservoirs.

Irreducible water saturation is an important factor affecting the development effect of low permeability reservoir. Using the self-developed ultrasonic generator, kerosene was used as simulated oil, the natural low-permeability siltstone cores with different physical properties in Zhongyuan Oilfield were selected for indoor oil displacement experiment, and the effect of ultrasonic action on the saturation of irreducible water in low-permeability reservoirs was evaluated. It was found that ultrasound can further reduce the saturation of irreducible water on the basis of oil flooding. The influence of different frequencies of ultrasound on the saturation of reservoir core irreducible water is different, and there is an optimal range of ultrasonic frequency: 17 kHz ~ 125 kHz. Increasing the ultrasonic power can effectively reduce the saturation of the core irreducible water in the low-permeability reservoir, and increasing the ultrasonic power can compensate for the adverse effects caused by the increase in frequency. With the increase of ultrasonic power, the thickness of the water film first decreases rapidly, and then gradually stabilizes, the highest drop could be 67.19%. The effect of ultrasound on the reduction of the saturation of irreducible water gradually deteriorates, with the increase of temperature, and at a higher temperature of 70 °C, the ultrasonic effect can still reduce the saturation of irreducible water. The effect of ultrasound on the saturation of irreducible water at low temperature is more intense, compared with high temperature, the irreducible water saturation can be reduced by 9.26%, and the ultrasonic effect is more suitable for low temperature treatment. The effect of ultrasound on the reduction of saturation of irreducible water in reservoirs with poor physical properties is more obvious.These studies are helpful for the systematic understanding of the effect of ultrasound on low permeability reservoirs and have positive implications for improving the development effect of low permeability reservoirs. [ABSTRACT FROM AUTHOR]

Previous attempts to classify flow units in Iranian carbonate reservoirs, based on porosity and permeability, have faced challenges in correlating the rock's pore size distribution with the capillary pressure profile. The innovation of this study highlights the role of clustering techniques, such as Discrete Rock Type, Probability, Global Hydraulic Element, and Winland's Standard Chart in enhancing the reservoir's rock categorization. These techniques are integrated with established flow unit classification methods. They include Lucia, FZI, FZI*, Winland R35, and the improved stratigraphic modified Lorenz plot. The research accurately links diverse pore geometries to characteristic capillary pressure profiles, addressing heterogeneity in intricate reservoirs. The findings indicate that clustering methods can identify specific flow units, but do not significantly improve their classification. The effectiveness of these techniques varies depending on the flow unit classification method employed. For instance, probability-based methods yield surpassing results for low-porosity rocks when utilizing the FZI* approach. The discrete technique generates the highest number of flow unit classes but provides the worst result. Not all clustering techniques reveal discernible advantages when integrated with the FZI method. In the second part, the study creatively suggests that rock classification can be achieved by concurrently clustering irreducible water saturation (SWIR) and porosity in unsuccessful flow unit delineation cases. The SWIR log was estimated by establishing a smart correlation between porosity and SWIR in the pay zone, where water saturation and SWIR match. Then, the estimated saturation was dispersed throughout the reservoir. Subsequently, the neural network technique was employed to cluster and propagate the three finalized flow units. This methodology is an effective recommendation when conventional flow unit methods fail. The study also investigates influential factors causing the failure of flow unit classification methods, including pore geometry, oil wettability, and saturation in heterogeneous reservoirs. [ABSTRACT FROM AUTHOR]

Abstract Previous attempts to classify flow units in Iranian carbonate reservoirs, based on porosity and permeability, have faced challenges in correlating the rock's pore size distribution with the capillary pressure profile. The innovation of this study highlights the role of clustering techniques, such as Discrete Rock Type, Probability, Global Hydraulic Element, and Winland's Standard Chart in enhancing the reservoir's rock categorization. These techniques are integrated with established flow unit classification methods. They include Lucia, FZI, FZI*, Winland R35, and the improved stratigraphic modified Lorenz plot. The research accurately links diverse pore geometries to characteristic capillary pressure profiles, addressing heterogeneity in intricate reservoirs. The findings indicate that clustering methods can identify specific flow units, but do not significantly improve their classification. The effectiveness of these techniques varies depending on the flow unit classification method employed. For instance, probability-based methods yield surpassing results for low-porosity rocks when utilizing the FZI* approach. The discrete technique generates the highest number of flow unit classes but provides the worst result. Not all clustering techniques reveal discernible advantages when integrated with the FZI method. In the second part, the study creatively suggests that rock classification can be achieved by concurrently clustering irreducible water saturation (SWIR) and porosity in unsuccessful flow unit delineation cases. The SWIR log was estimated by establishing a smart correlation between porosity and SWIR in the pay zone, where water saturation and SWIR match. Then, the estimated saturation was dispersed throughout the reservoir. Subsequently, the neural network technique was employed to cluster and propagate the three finalized flow units. This methodology is an effective recommendation when conventional flow unit methods fail. The study also investigates influential factors causing the failure of flow unit classification methods, including pore geometry, oil wettability, and saturation in heterogeneous reservoirs.

Evaluating irreducible water saturation is crucial for estimating reservoir capacity and developing effective extraction strategies. Traditional methods for predicting irreducible water saturation are limited by their reliance on specific logging data, which affects accuracy and applicability. This study introduces a predictive method based on fractal theory and deep learning for assessing irreducible water saturation in complex carbonate reservoirs. Utilizing the Mishrif Formation of the Halfaya oilfield as a case study, a new evaluation model was developed using the nuclear magnetic resonance (NMR) fractal permeability model and validated with surface NMR and mercury injection capillary pressure (MICP) data. The relationship between the logarithm mean of the transverse relaxation time (T2lm) and physical properties was explored through fractal theory and the Thomeer Function. This relationship was integrated with conventional logging curves and an advanced deep learning algorithm to construct a T2lm prediction model, offering a robust data foundation for irreducible water saturation evaluation. The results show that the new method is applicable to wells with and without specialized NMR logging data. For the Mishrif Formation, the predicted irreducible water saturation achieved a coefficient of determination of 0.943 compared to core results, with a mean absolute error of 2.37% and a mean relative error of 8.46%. Despite introducing additional errors with inverted T2lm curves, it remains within acceptable limits. Compared to traditional methods, this approach provides enhanced predictive accuracy and broader applicability. [ABSTRACT FROM AUTHOR]

Low-contrast oil reservoirs have a complicated origin story that frequently results from the interaction of several different factors. The low-contrast oil reservoirs in the Daqing Oilfield's SaPu intercalation in the Longxi Region are the main subjects of this study. This work investigates the petrophysical origins of these low-resistivity oil reservoirs through a series of carefully planned petrophysical experiments. The results showed that the main determinants of the low-contrast oil reservoirs in the SaPu intercalation were the conductivity of clay minerals and a high irreducible water saturation. A low clay conductivity had a significant effect, resulting in a significant reduction in the formation resistivity, even in circumstances with a low porosity and a low formation-water salinity. Moreover, the results from the NMR tests revealed that the irreducible water saturation in the core samples primarily ranged from 0.6 to 0.8, suggesting a significant prevalence. This work provides strong petrophysical indices for evaluating low-resistivity oil reservoirs in the SaPu intercalation and useful information for the petrophysical evaluation of similar reservoirs. [ABSTRACT FROM AUTHOR]

Unambiguously determining irreducible water saturation S wirr poses a formidable challenge, given the availability of multiple independent methods. Traditional approaches often depend on semi-experimental relationships derived from simplified assumptions. These methods, originally designed for oil sandstone reservoirs, result in varying S wirr values when employed in carbonate gas reservoirs. Nuclear magnetic resonance (NMR) is the most advanced technique for determining S wirr . While highly accurate, the NMR-based method necessitates the laboratory measurement of the transverse relaxation time T 2 cutoff. Laboratory-based T 2 cutoff determination is resource-intensive and time-consuming. This research aims to develop a robust model for determining S wirr in carbonate gas reservoirs by utilizing NMR well logging measurements and special core analysis (SCAL) tests. Various T 2 cutoff values were initially employed to compute bound water saturation S bw at different depths to achieve this. Subsequently, the data points T 2 , S bw were graphed on a scatter plot to unveil the relationship between S bw and T 2 . The scatter plot illustrates an exponential decrease in S bw with increasing T 2 , forming the basis for the S wirr model derived from this relationship. Finally, the parameters of the S wirr model were fine-tuned using SCAL tests. Notably, this S wirr model not only accurately yields S wirr at each depth but also offers a dependable determination of the optimal T 2 cutoff for the reservoir interval. [ABSTRACT FROM AUTHOR]

Abstract Unambiguously determining irreducible water saturation $$\left({S}_{\rm{wirr}}\right)$$ S wirr poses a formidable challenge, given the availability of multiple independent methods. Traditional approaches often depend on semi-experimental relationships derived from simplified assumptions. These methods, originally designed for oil sandstone reservoirs, result in varying $${S}_{{\text{wirr}}}$$ S wirr values when employed in carbonate gas reservoirs. Nuclear magnetic resonance (NMR) is the most advanced technique for determining $${S}_{{\text{wirr}}}$$ S wirr . While highly accurate, the NMR-based method necessitates the laboratory measurement of the transverse relaxation time $$\left({T}_{2}\right)$$ T 2 cutoff. Laboratory-based $${T}_{2}$$ T 2 cutoff determination is resource-intensive and time-consuming. This research aims to develop a robust model for determining $${S}_{{\text{wirr}}}$$ S wirr in carbonate gas reservoirs by utilizing NMR well logging measurements and special core analysis (SCAL) tests. Various $${T}_{2}$$ T 2 cutoff values were initially employed to compute bound water saturation $$\left({S}_{{\text{bw}}}\right)$$ S bw at different depths to achieve this. Subsequently, the data points $$\left({T}_{2}, {S}_{{\text{bw}}}\right)$$ T 2 , S bw were graphed on a scatter plot to unveil the relationship between $${S}_{{\text{bw}}}$$ S bw and $${T}_{2}$$ T 2 . The scatter plot illustrates an exponential decrease in $${S}_{bw}$$ S bw with increasing $${T}_{2}$$ T 2 , forming the basis for the $${S}_{{\text{wirr}}}$$ S wirr model derived from this relationship. Finally, the parameters of the $${S}_{{\text{wirr}}}$$ S wirr model were fine-tuned using SCAL tests. Notably, this $${S}_{{\text{wirr}}}$$ S wirr model not only accurately yields $${S}_{{\text{wirr}}}$$ S wirr at each depth but also offers a dependable determination of the optimal $${T}_{2}$$ T 2 cutoff for the reservoir interval.

Irreducible water saturation is a key parameter for reservoir fluid property identification and reservoir evaluation. Using geophysical logging data to evaluate reservoir irreducible water saturation is a commonly used method. Nuclear magnetic resonance logging generally calculates the irreducible water saturation of the reservoir by determining the cutoff value of the transverse relaxation time. In the nuclear magnetic resonance experimental study of the M layer group in H oilfield in the Middle East, it is found that some experimental samples have the phenomenon of ‘diffusion coupling’, which makes it difficult to accurately calculate the irreducible water saturation of the reservoir through T2 cutoff. By extracting the characteristic parameters reflecting the pore structure and fluid occurrence state information in the nuclear magnetic resonance T2 spectrum, and combining with the data of casting thin sections, the correlation between these parameters and irreducible water saturation was discussed, and the T2 cut-off was avoided to avoid the influence of ‘diffusion coupling’ on the model. The experimental results show that there is a correlation between irreducible water saturation and nuclear magnetic porosity, interval pore component and T2 geometric mean. Based on the above parameters, a prediction model of irreducible water saturation was established. The prediction model was verified by actual wells in the M layer group of H oilfield in the Middle East, and good application results were obtained, which lays a solid foundation for the subsequent identification of reservoir fluid properties and water flooded layer identification. [ABSTRACT FROM AUTHOR]

The object of research in the paper is the process of fluid transfer through the pore space of the reservoir rock. The traditional method of estimating oil recovery by flooding has a large number of uncertainties. In this study, to address limitations of the current approach to determining oil production, let’s introduce a systematic algorithm aimed at enhancing result precision. The methodology for calculating the oil recovery coefficient for determining the amount of oil that can be extracted by flooding is presented. In this work, the step-by-step process of determining the oil recovery coefficient was analytically established, which achieves a certain degree of accuracy due to the inclusion of a number of methods of calculation of scientists from different countries of the world. In particular, the lithofacies distribution of the reservoir using the kriging method, the use of a representative elementary volume (REV) to increase the accuracy of determining the irreducible water saturation of each facies, and the use of the Buckley-Leverett equation in the calculation of the oil recovery coefficient are proposed. The number of facies (sandstone, argillaceous sandstone, siltstone) was determined on the example of the B-16n horizon of the «Ukrainian deposit» and the oil recovery coefficients were calculated for each separately (0.53, 0.47, 0.29). Further determination of the average oil recovery coefficient is described in the researched and requires close integration of the obtained data in three-dimensional space, as it allows to calculate the fraction of facies content in the reservoir volume. The use of the proposed action algorithm will help to build a more reliable three-dimensional hydrodynamic model, will lead to a much lower degree of uncertainty of reservoir properties, and in particular irreducible water saturation, as well as more accurate distribution of lithological properties using kriging. Also, this methodology for calculating the oil recovery coefficient involves the use of the Buckley-Leverett equation and fractional flow curves, the data of which are based on relative permeabilities and depend on the irreducible water saturation determined in the laboratory for each lithofacies. These techniques justify the collection of additional core material, the importance of lithofacies dismemberment of the formation and are closely integrated in the three-dimensional space, which makes it possible to simulate the existing processes, reproduce the proposed methodology and perform the forecast. [ABSTRACT FROM AUTHOR]

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 NMRbased 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. [ABSTRACT FROM AUTHOR]

Petrophysical properties are used to characterize a reservoir. Hence, this study evaluates petrophysical properties of the Sapele shallow field in the Niger Delta Area of Southern Nigeria with the aid of log data such as gamma-ray, density, neutron, and resistivity. Quantitative properties including shale volume, porosity, permeability, Irreducible water saturation, formation factor, water saturation, and hydrocarbon saturation were carried out using the well logs. One oil-bearing reservoir was identified across the field. Computed petrophysical parameters across the reservoir provided average porosity ranging from 0.30 to 0.36, permeability values range from 2707.9 to 3721.9 milli Darcy (mD) and the average hydrocarbon saturations are 0.51, 0.42, 0.47, 0.46, 0.47, and 0.49 for well 21, 22, 29, 30, 31, and 32 respectively. The field covers an area extent of 17137.18 acres. [ABSTRACT FROM AUTHOR]

Low-contrast oil reservoirs have a complicated origin story that frequently results from the interaction of several different factors. The low-contrast oil reservoirs in the Daqing Oilfield’s SaPu intercalation in the Longxi Region are the main subjects of this study. This work investigates the petrophysical origins of these low-resistivity oil reservoirs through a series of carefully planned petrophysical experiments. The results showed that the main determinants of the low-contrast oil reservoirs in the SaPu intercalation were the conductivity of clay minerals and a high irreducible water saturation. A low clay conductivity had a significant effect, resulting in a significant reduction in the formation resistivity, even in circumstances with a low porosity and a low formation-water salinity. Moreover, the results from the NMR tests revealed that the irreducible water saturation in the core samples primarily ranged from 0.6 to 0.8, suggesting a significant prevalence. This work provides strong petrophysical indices for evaluating low-resistivity oil reservoirs in the SaPu intercalation and useful information for the petrophysical evaluation of similar reservoirs.

Petrophysical properties are used to characterize a reservoir. Hence, this study evaluates petrophysical properties of the Sapele shallow field in the Niger Delta Area of Southern Nigeria with the aid of log data such as gamma-ray, density, neutron, and resistivity. Quantitative properties including shale volume, porosity, permeability, Irreducible water saturation, formation factor, water saturation, and hydrocarbon saturation were carried out using the well logs. One oil-bearing reservoir was identified across the field. Computed petrophysical parameters across the reservoir provided average porosity ranging from 0.30 to 0.36, permeability values range from 2707.9 to 3721.9 milli Darcy (mD) and the average hydrocarbon saturations are 0.51, 0.42, 0.47, 0.46, 0.47, and 0.49 for well 21, 22, 29, 30, 31, and 32 respectively. The field covers an area extent of 17137.18 acres.

The rock coring of the reservoir in the Bohai A field is difficult. The cores of the target section in the study area are loose, making it difficult to accurately measure the core-bound water saturation. The purpose of this research was to develop and validate a method for calculating a reservoir core-bound water saturation ratio using the cast thin section. First, pepper noise denoising and image enhancement were performed on the thin section by median filtering and gamma variation. Based on this, the enhanced sheet images were thresholded for segmentation by the two-dimensional OTSU algorithm, which automatically picked up the thin section pore-specific parameters. Then, the thin section image was equivalent to a capillary cross-section, while the thin film water fused to the pore surface was observed as bound water. For hydrophilic rocks with a strong homogeneity, the area of thin film water in the pore space of the sheet was divided by the total area of the pore space, which produced the bound water saturation. Next, the theoretical relationship between the film water thickness and the critical pore throat radius was derived based on the Young–Laplace equation. The bound water saturation of the rock was calculated by combining the pore perimeter and the area that was automatically picked up from the thin film for a given critical pore throat radius of the rock. Finally, 22 images of thin sections of sparse sandstone from the coring well section of the study area were image processed using the new method proposed in this paper, and the bound water saturation was calculated. The calculated results were compared with 22 NMR-bound water saturations and 11 semi-permeable baffle plate-bound water saturations in the same layer section. The results showed that the bound water saturation values calculated by the three methods produced consistent trends with absolute errors within 5%. The calculated results confirm the reliability of the method proposed in this paper. This method can effectively avoid the problem of the inaccurate results of core experiments due to the easy damage of sparse sandstone and provides a new idea for the accurate determination of the bound water saturation of sparse sandstone. [ABSTRACT FROM AUTHOR]

Evaluating the permeability and irreducible water saturation of tight sandstone reservoirs is challenging. This study uses distribution functions to fit measured NMR T2 distributions of tight sandstone reservoirs and extract parameters for characterizing pore size distribution. These parameters are then used to establish prediction models for permeability and irreducible water saturation of reservoirs. Results of comparing the fit of the T2 distributions by the Gauss and Weibull distribution functions show that the fitting accuracy with the Weibull distribution function is higher. The physical meaning of the statistical parameters of the Weibull distribution function is defined to establish nonlinear prediction models of permeability and irreducible water saturation using the radial basis function (RBF) method. Correlation coefficients between the predicted values by the established models and the measured values of the tight sandstone core samples are 0.944 for permeability and 0.851 for irreducible water saturation, which highlight the effectiveness of the prediction models. [ABSTRACT FROM AUTHOR]

The accurate calculation of the two-phase relative permeability has a significant impact for effectively characterizing the fluid flow patterns of unsaturated shale reservoir. A new fractal relative permeability model is developed based on two-phase transport feature in confined nanopores, which is upscaled with the aid of fractal theory for two-phase flow through unsaturated shale porous medium. Unlike the earlier models, the presented models considered nanopore wettability, confined viscosity varies with the nanopore diameter (variable water phase viscosity), stress dependence effect, real gas effect, irreducible water saturation and tortuosity effect. The proposed model compares the permeability of single nanopore and multiple nanopores with earlier research, which shows that the fractal relative permeability model agrees well with earlier models and experimental data. The results show that the Monte Carlo model and Abaci experimental model studied by previous researchers are special cases of the proposed fractal model, thus showing that the proposed fractal model has obvious advantages. Further calculations show that 1) The gas phase’s relative permeability gradually decreases with the increase of water saturation; 2) Confined viscosity varies with the nanopore diameter has a greater influence on the inorganic pores and a smaller influence on the organic pores on the relative permeability; 3) The relative permeability of the intersection point in the organic pore is higher than that of the inorganic porous, but the water saturation at the intersection is less than that of inorganic pores. Therefore, it lays a solid foundation for revealing the two-phase flow law of shale porous media.

Work on fluid productivity prediction in the Niger Delta is sparse or even rare because of the need for expensive but limited information from core data, well test data, and nuclear magnetic resonance (NMR) data. Paucity of this information in the study area due to prohibitive cost makes justification of results of fluid productivity predictions very difficult to justify. However, an integrated well log analysis method is applied to three sand-shale sequence reservoirs of the Niger Delta for fluid productivity predictions in this work using basic log suites. This work utilizes irreducible saturation analysis calculated from the Buckles' method for three (3) reservoirs in Well "AW" and Well "T". Rock Physics estimates of Poisson's ratio values and Vp/Vs ratio values allow for fluid type designation from a cross plot of Poisson's ratio and Vp/Vs ratio; hence, it is possible to interpret gas saturation, brine saturation, and oil saturation for these reservoirs. The Buckle method yields numbers that are used to estimate irreducible water saturation values independently of Archie's and Archie's modified equations. In addition, Buckle's numbers allow for a pore size and grain size forecast for sandstone reservoirs being intercepted within the two wells. For each of these reservoirs, water saturation (Sw) is compared with the irreducible water saturation (Swirr) with the logic that for a reservoir having Swirr > Sw, no water production is expected. Conversely, for Swirr < Sw, water production is expected. Difference in values of water saturation and irreducible water saturation is used as an index for predicting qualitatively reservoirs prone to high water cut production for these six reservoirs. Reservoir AW1 with Sw of 30.9% and Swirr of 24.5% was predicted to have water production potential. While in reservoirs AW2 and AW3, where Swirr > Sw, no water production should be expected. In well "T" reservoirs T1, T2, and T3, all had Swirr > Sw. Hence, this work demonstrated the usefulness and effectiveness of the Buckle's method in estimating many useful petrophysical parameters to predict reservoir productivity in the studied area, Niger Delta for wells lacking core data, well test data, and NMR data. Field-wide deployment of this technique may help to improve the reduction in oil-related water production and the cost of managing the produced water at the initial stage of production in the Niger Delta in the reservoir. [ABSTRACT FROM AUTHOR]

The irreducible water saturation (Swir) is a significant parameter for relative permeability prediction and initial hydrocarbon reserves estimation. However, the complex pore structures of the tight rocks and multiple factors of the formation conditions make the parameter difficult to be accurately predicted by the conventional methods in tight gas reservoirs. In this study, a new model was derived to calculate Swir based on the capillary model and the fractal theory. The model incorporated different types of immobile water and considered the stress effect. The dead or stationary water (DSW) was considered in this model, which described the phenomena of water trapped in the dead-end pores due to detour flow and complex pore structures. The water film, stress effect and formation temperature were also considered in the proposed model. The results calculated by the proposed model are in a good agreement with the experimental data. This proves that for tight sandstone gas reservoirs the Swir calculated from the new model is more accurate. The irreducible water saturation calculated from the new model reveals that Swir is controlled by the critical capillary radius, DSW coefficient, effective stress and formation temperature. [ABSTRACT FROM AUTHOR]

The article is devoted to the problem of evaluation of oil displacement coefficient. Determination of oil displacement coefficient is essential stage for estimation of recoverable reserves, feasibility study of oil recovery factor and control of field development. Complexity of its laboratory determination is caused by labor intensity and duration of a process. When the number of cores is not enough for flow experiments or absent oil recovery factor is evaluated either similarly to neighbor fields or by analytical dependencies that are important to obtain. During the generalization and analysis of a significant amount of experimental data the authors developed a method for estimation of oil displacement coefficient without its laboratory determination. A proposed method is based on use of data from previous studies to built statistical models for estimation of displacement coefficient using linear step-by-step regression and discriminant analysis. In order to implement the method along with oil viscosity, knowledge of reservoir parameters such as porosity, permeability, irreducible water saturation and bulk density of a rock, determined by conventional core studies, is required. The main stages of implementation of the method for Visean clastic deposits of the Bashkir arch and Solikamsk depression of the Perm Region are presented. Results of implementation of the method for Bashkir carbonate deposits of the indicated tectonic elements are presented as well. Analysis of initial data allow establishing that there are classes of values for which regression equations are statistically justified. According to the equations model and experimental values of the displacement coefficients are very close to each other. It was concluded based on parameters of the equations that there is abnormal influence of initial oil saturation on the displacement coefficient. It is shown that for reservoirs of low flow characteristics a displacement coefficient is determined by their capacitive properties.

Based on the measurement mechanism of mobility in pressure measurement while drilling, through analyzing a large number of mobility data, it is found that under the condition of water-based mud drilling, the product of mobility from pressure measurement while drilling and the viscosity of mud filtrate is infinitely close to the water phase permeability under the residual oil in relative permeability experiment. Based on this, a method converting the mobility from pressure measurement while drilling to core permeability is proposed, and the permeability based on Timur formula has been established. Application of this method in Penglai 19-9 oilfield of Bohai Sea shows: (1) Compared with the permeability calculated by the model of adjacent oilfields, the permeability calculated by this model is more consistent with the permeability calculated by core analysis. (2) Based on the new model, the correlation between the calculated mobility of well logging and the actual drilling specific productivity index bas been established. Compared with the relationship established by using the permeability model of an adjacent oilfield, the correlation of the new model is better. (3) Productivity of four directional wells was predicted, and the prediction results are in good agreement with the actual production after drilling. [ABSTRACT FROM AUTHOR]

Understanding the relationships between the pore structure and bulk properties such as irreducible water saturation (S wir) and permeability (k) of rocks is a crucial problem in geoscience. In this study, two types of fractal dimension were determined from nuclear magnetic resonance (NMR) T 2 relaxation time distribution and models for estimating S wir and k using fractal theory were proposed. In view of the data of sandstone samples from upper Paleozoic formation in China, we found a good agreement between the predicted S wir values based on fractal analysis and the experimental measurements, and the estimated k values based on the proposed model are within one order of magnitude of measured k. Additionally, another four frequently used k estimation models were compared with our proposed model, and the result support that the proposed approach has great potential in investigating k while certain limitation still exists. This procedure was applied on another set of sandstone samples collected from a different location, and the predicted permeability values are reliable. Our study suggests that the proposed S wir estimation model using NMR T 2 data and fractal dimensions provides useful insights into characterizing the pore space properties of sedimentary rocks. Our work demonstrates that we can use NMR data to infer S wir directly, and the estimated S wir value can be well integrated in permeability prediction model, which improves the applications of NMR in characterizing the properties related to rock pores. [ABSTRACT FROM AUTHOR]

Low oil saturation reservoirs are increasingly encountered in superimposed sedimentary basins, however, the uncertainty about the origin of the low oil saturation becomes a major factor impeding further hydrocarbon exploration. Routine core analysis, (fluorescence) thin section, scanning electron microscope (SEM) and nuclear magnetic resonance (NMR) measurements were used to understand the characteristics and formation mechanisms of the low oil saturation reservoirs in the Paleogene Dongying Formation in the Nanpu sag, Bohai Bay Basin, East China. Irreducible water saturation was determined from sealed coring oil saturation testing and NMR logs. Wide ranges of porosity and permeability were observed, and the samples with moderate reservoir quality have the best oil bearing property. Low oil saturation oil layers are characterized by low oil saturation (<50%) but high content of irreducible water (>40%), with only oil being produced whereas no water or only minor amounts of water being produced. The low oil saturation oil-water reservoirs refer to the low oil saturation layers in which both oil and water will be produced during oil testing. Irreducible water saturation increases with total clay content, with the authigenic clays (kaolinite, illite and mixed layer illite/smectite) blocking pore spaces, and resulting in high irreducible water saturations. Fluorescence thin sections combined with NMR measurements show that the NMR T 2 (transversal relaxation time) distribution is uni-modal, with large intergranular pores being rare. Almost the entire pore-size range is oil bearing for the low oil saturation oil reservoirs. The large intergranular pores are fluorescence-free, while the intragranular dissolution pores and micropores emit fluorescence in the low oil saturation oil-water reservoirs. The NMR T 2 distribution of low oil saturation oil-water reservoirs is bi-modal and right-skewed, and the main oil-bearing NMR pore size distribution ranges from 0.1 to 100 ms. High irreducible water content was encountered in the low oil saturation oil reservoirs and low oil saturation oil-water reservoirs, and only part of the large intergranular pores are oil saturated, and in some cases only the intragranular pores are saturated with oils forming low oil saturation oil reservoirs. The results help improve the knowledge of characteristics and formation of the low oil saturation oil layers, and could provide insights in enhancing oil recovery. • Definition and characteristics of the low oil saturation oil reservoirs are clarified. • Formation mechanisms of the low oil saturation oil reservoirs are revealed. • Oil occurrences of low oil saturation oil reservoirs are investigated. [ABSTRACT FROM AUTHOR]

Irreducible water saturation (S wir) is an important parameter in reservoir evaluation that can affect hydrocarbon saturation, permeability prediction models and estimation of original oil in - place. The S wir is usually obtained from capillary pressure data. In this study, routine and special core analyses for sandstone reservoirs in four wells were used to investigate the relationship between irreducible water saturation and the petrophysical properties of the reservoir rocks. The results indicated that the magnitude of S wir is controlled by a complex relationship of reservoir rock wettability, reservoir quality, clay content, clay mode of distribution, and capillary pressure. Reservoir rock wettability can obscure the effect of other factors in the case of oil–wet rocks. On the other hand, irreducible water saturation from published data were used together with the studied four wells data, providing 110 sandstone samples covering different geologic ages and facies, to examine the applicability of the traditional empirical models that were commonly used in S wir prediction as well as to introduce a new simple equation by which S wir can be predicted. The study indicated that the Timur equation gave the best applicable empirical model to predict S wir. The study indicated also that the flow zone indicator can slightly improve the prediction strength of the S wir. Using other parameters characterizing capillary pressure curves such as displacement pressure and Swanson parameter didn't improve the relationship prediction strength. • A new equation was proposed to predict irreducible water saturation as a function in flow zone indicator. • Wettability is the major role in determination of values of the irreducible water saturation. • Effects of reservoir quality, clay content and capillary pressure on S wir can be obscured by the effect of rock wettability and fluid properties. [ABSTRACT FROM AUTHOR]

Relative permeability stress sensitivity studies reported in literature do not have a common conclusion with regards to end point saturations and their respective relative permeabilities. Moreover, there is lack of experimental results on stress sensitivity of pore fluid distribution, which is a key parameter for the behavior of relative permeability curves. This study extended core homogeneity to include similar porosity, permeability and NMR T 2 distribution as well as examined NMR T 2 distribution behavior with stress on artificial sandstone cores and the results used in explaining relative permeability stress sensitivity under net confining stresses of 5, 15 and 25 MPa. The effect of stress on displacement efficiency was also investigated. The bulk volume irreducible (BVI), which is the fraction of the bulk volume containing irreducible water, generally increased with stress. Meanwhile the free fluid index (FFI), which is the fraction of the bilk volume responsible for fluid flow, decreased with increased stress. NMR irreducible water saturation and irreducible water saturation obtained from relative permeability experiments both increased with stress. Irreducible water saturation was strongly related to the behavior BVI stress sensitivity. Residual oil saturation increased with increase in stress as a result of reductions in FFI pore volume. End-point oil relative permeability had a significant decrement with stress while water end-point relative permeability had a negligible decrement. The significant reduction in end-point oil relative permeability was due to reductions in pore radius evident in a corresponding reduction in FFI. Displacement efficiency decreased with increased stress indicating lower oil recovery on microscopic scale but end-point mobility ratio increased as stress increased. Relative permeability stress sensitivity could be tied to changes in BVI and FFI of NMR T 2 distribution when changes in stress occur in petroleum reservoirs. • NMR T 2 distribution was employed to study relative permeability stress sensitivity. • BVI and FFI increase and decrease, respectively with increase in stress. • Sensitivity of BVI causes changes in irreducible water saturation. [ABSTRACT FROM AUTHOR]

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Separation of well section into permeable and impermeable parts is one of the main problems for further construction of a geological model, reserves estimation and field development planning. Quality of separation depends on amount of knowledge about geological section, level of theoretical development of well logging methods and general geophysical characteristics of the area. The fullest differentiation is obtained by using a complex of geological and geophysical methods. The paper is focused on Visean deposits of well of Sofyinskoe field drilled in 2014. A complex of activities was performed along with well logging. Porosity was calculated by acoustic and neutron logging. Core analysis was performed. Using well logging and results of core analysis selection was made, used for construction of statistical models. Based on statistical models all parameters were made-up to a single measurement system. The analysis of degree of influence of geological and geophysical parameters was made. The geological analysis shows that the greatest influence belongs to porosity and residual water. The geophysical analysis shows that the greatest influence belongs to hydrogen content and own radioactivity of rocks. A complex probabilistic parameter that includes all measurements according to core and geophysical parameters is calculated. Results of core analysis are considered fully in order to obtain a highest degree of difference. Almost all the parameters of geophysical data increase the degree of difference, except for lateral logging, microgradient and micropotential tools and transit time of P-wave for short tool, which reduces the degree of difference. Based on values of a complex parameter that have maximum differences in geological and geophysical parameters, relationships of geological and geophysical parameters were built. Scatter charts show that fields of measured points are not intersected, which confirms a correct separation of a section. Using a statistical method allows to consider fully available geological and geophysical data to separate a section into permeable and impermeable parts.

In order to reveal the gas–water distribution and formation mechanism of the low-permeability sandstone gas reservoir, the gas reservoir distribution and the formation mechanism in a low-permeability sandstone gas reservoir are investigated using data obtained from a physical simulation experiment of gas percolation. The exploration and experimenting for petroleum in the upper Paleozoic gas pool of the Sulige gas field in the Ordos basin in this paper. Results showed that the gas reservoir is characterized by low gas saturation, a complex distribution relationship of gas–water, and weak gas–water gravity differentiation. The characteristics of gas distribution are closely related to permeability, gas flow, and migration force. The capillary pressure difference is the main driving force of gas accumulation. There exists a threshold pressure gradient as gas flows in low-permeability sandstone. The lower that permeability, the greater the threshold pressure gradient. When the driving force cannot overcome the threshold pressure (minimal resistance), the main means of gas migration is diffusion; when the driving force is between minimal and maximal resistance, gas migrates with non-Darcy flow; when the driving force is greater than maximal resistance, gas migrates with Darcy flow. The complex gas migration way leads to complicated gas- water distribution relationship. With the same driving force, gas saturation increases with the improvement of permeability, thus when permeability is greater than 0.15 × 10−3 µ m2, gas saturation could be greater than 50%.

Relatively new direction for geological properties study in petroleum geology nowadays is the use of X-ray tomography. The basis of this method is X-ray rock density study. This paper shows the results of possible X-ray tomography applications while studying petrophysical properties of carbonate reservoir plugs on example of several oil fields in Perm region. The microfocus system of X-ray control with computer tomography Nikon Metrology XT H 225 and software AvizoFire 7.0 were used. The cylinder samples with diameters of 30 and 10 mm and cubic samples with a side length of 5 mm were used in the study. The results of X-ray tomography represent 2D-slices of lengthwise and crosswise sample cross-section, 3D-model of cavities, consolidation areas and initial oil saturation distribution as well as graphs of pore and irreducible water saturation versus sample height and histograms of pore diameters. The study of cavities and consolidation areas distribution in the samples allowed to type core depending on its cavity structure. Analysis of porosity evaluation of the samples with different diameters that were made from the one pies of core showed that correlation coefficient was 0.77. Such relatively low coefficient could be explained by significant heterogeneity of core even in one lithotype. During the irreducible water saturation determination four radiographic solutions were tested. It was noticed that irreducible water does not exist in the large voids (cavities, cracks, big pores). Best results were obtained for NaI and LaCl3·3H2O solutions. Presented in this paper results allow obtaining most authentic 3D distribution of pore space and fluid saturation during futhure X-ray tomography study of carbonate deposits.

Abstract Zones with low resistivity low contrast (LRLC) are usually overlooked due to the absence of high-end well logging techniques in the older oil/gas fields. The Nyalau Formation outcrop (stratigraphically equivalent to offshore cycles I and II) from Sarawak, offers a good opportunity to identify and characterize LRLC zones through integrated approaches. Seven facies of the Nyalau Formation had been identified, which are: 1) low angle cross-bedded sandstone (CBSS), 2) laminated sandstone (LSS), 3) heterolithic sandstone (HSS), 4) bioturbated sandstone (BSS), 5) clay-rich sandstone (CSS), 6) mudstone (MS), as well as 7) trough CBSS (TCBSS). Apparent resistivity was determined for brine (60 kpm) saturated core plugs at a temperature of 75 °F by employing the sample core induced polarization technique. The measurement of resistivity was calibrated based on offshore salinity, as well as surface and subsurface temperature of the Sarawak. The geological and petrophysical characteristics were analyzed through field observations and lab analyses. The findings of the study revealed that the cutoff value of resistivity found at LRLC zones in Nyalau Formation was 12.6 Ω-m. Accordingly; LSS, BSS, and CSS facies appeared to derive from LRLC zones. The main causes that generate such LRLC zones are laminations, thin bedding, bioturbation, and clay minerals. The dominant effect portrayed by mixed layers of illite/smectite and smectite in LRLC zones could be attributed to their high cation exchange capacity (CEC). Two varying resistivity trends were discovered based on the variances detected in clay types for different facies. A negative correlation was found between resistivity and porosity within high resistivity zones, while a positive relationship within the LRLC zones. Disparity in the resistivity-porosity correlation is deduced to be associated with clay mineralogy. This study suggests that LRLC zones are expected to be present in shallow marine clastic reservoirs of offshore cycles (I and II), where the offshore reflects Nyalau Formation. Highlights • A detailed investigation of shallow marine clastic reservoir (Nyalau Formation) carried out to identify LRLC zones. • This is the first study for identification and characterization of LRLC zones at outcrop level. • The resistivity of zones had effected by clay type, sedimentary features, and petrophysical parameters (e.g. pore size). • The effect of total clay content and distribution altered the reservoir properties in a significant way. [ABSTRACT FROM AUTHOR]

Different from conventional reservoirs, the irreducible water saturation of tight gas reservoirs is not a fixed value, but a function of pressure. In order to reasonably characterize the stress sensitivity of irreducible water saturation and investigate its influence on the dynamic characteristics of fractured gas wells, a relative permeability model under irreducible water saturation stress-sensitivity condition is established. On this basis, a two-phase seepage model is built, and then the influence of irreducible water saturation stress-sensitivity is discussed. The results show that the stress-sensitivity of irreducible water saturation would lead to the change of the log-log plot for pressure derivative as well as the production performances. Therefore, during the dynamic inversion, production forecast and development plan formulation process of fractured water producinggas wells in tight reservoirs, the stress sensitivity of irreducible water saturation should be fully considered. [ABSTRACT FROM AUTHOR]

The T 2 cutoff is an important input parameter in nuclear magnetic resonance (NMR) applications. The accuracy of the T 2 cutoff affects the prediction reliability of parameters associated with the identification and evaluation of formations. Current methods are based on regional statistics; they have limited applications and the predicted values are not always reliable. In this study, a total of 36 core samples, drilled from Triassic tight sandstone reservoirs of the southwest Ordos Basin in China, were used for laboratory NMR measurements under fully brine saturated and irreducible water conditions. Based on the morphological character analysis of experimental NMR T 2 spectra, we demonstrate that NMR T 2 spectra can be fully simulated using the normal distribution function. In addition, a new method was proposed, which can predict various T 2 cutoffs based on the morphological differences of NMR T 2 spectra, and the irreducible water saturation ( S wirr ) was calculated, which represents the ratio of the sum volume of clay bound water and capillary bound water to total pore volume. The reliability of this method was verified by comparing the predicted T 2 cutoff and S wirr values with those of core NMR experimental results. Finally, we extended this method into field applications in several tight sandstone reservoirs in China. The results show that total T 2 distributions of the formation were fully simulated by the normal distribution function, and various T 2 cutoff and S wirr values were precisely predicted. Meanwhile, tight sands permeability curves, predicted based on the Timur-Coates model, were also accurately estimated. The results of our study may be applied to improve tight sandstone reservoir identification and evaluation using NMR logs. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The couple flow deformation behavior in porous media has drawn tremendous attention in various scientific and engineering fields. However, though the coupled flow deformation mechanism has been intensively investigated in the last decades, the essential controls on stress sensitivity are not determined. It is of practical significance to use analytic methods to study stress sensitivity of porous media. Unfortunately, because of the disordered and extremely complicated microstructures of porous media, the theoretical model for stress sensitivity is scarce. The goal of this work is to establish a novel and reasonable quantitative model to determine the essential controls on stress sensitivity. The predictions of the theoretical model, derived from the Hertzian contact theory and fractal geometry, agree well with the available experimental data. Compared with the previous models, our model takes into account more factors, including the influence of the water saturation and the microstructural parameters of the pore space. The proposed models can reveal more mechanisms that affect the coupled flow deformation behavior in fractal porous media. The results show that the irreducible water saturation increases with the increase of effective stress, and decreases with the increased rock elastic modulus (or increased power law index) at a given effective stress. The effect of stress variation on porosity is smaller than that on permeability. Under a given effective stress, the normalized permeability (or the normalized porosity) becomes smaller with the decrease of rock elastic modulus (or the decrease of power law index). And a lower capillary pressure will correspond to an increased rock elastic modulus (or an increased power law index) under a given water saturation. [ABSTRACT FROM AUTHOR]

The existing experimental method of obtaining irreducible water saturation is not applicable for low permeability sandstone reservoir. To calculate the irreducible water saturation of tight sandstone reservoir accurately, an irreducible water saturation model suitable for hydrophilic rock is established by combining the capillary tubes model with the fractal theory. The influence of formation temperature and the critical capillary radius (maximum displacement pressure) on the irreducible water saturation is simulated. The results show that at a certain temperature, the smaller the critical capillary radius is, the lower the irreducible water saturation is. When the critical capillary radius is constant, the higher the formation temperature is, the lower the irreducible water saturation is. To verify the validity of the model, the new model is applied to the gas layer in tight sandstone reservoir of Xujiahe Formation in Sichuan Basin, the calculated data of the irreducible water saturation is compared with the wax sealing water saturation. The results show that compared with the irreducible water saturation calculated under experimental conditions, the calculation results of the new model are closer to the wax sealing water saturation on the condition that the effect of formation temperature and the maximum displacement pressure on the irreducible water saturation is considered. It is proved that the new model is applicable for accurate calculation of the irreducible water saturation of the gas layer in tight sandstone reservoir. [ABSTRACT FROM AUTHOR]

When designing field development plans for hydrocarbon exploitation, most often the reservoirs models model rocks which allow flow of the fluids contained in their pores. A reservoir can be defined as a single hydrodynamic unit. The quality of the rocks in this hydrodynamic unit will vary and is usually a function of the depositional environment, diagenesis, etc. The different rock qualities are characterized by different pore sizes and geometries which will allow the water to rise due to capillarity phenomena. This creates a transition zone which is heterogeneous as the reservoir rock is. When we are reporting volumes in place we usually define them at the contact. What do we understand by contact and how is the rock quality or heterogeneity affecting the volumes in place are the questions that we are going to address in this article with the use of a simple "layer cake" ECLIPSE simulation model. [ABSTRACT FROM AUTHOR]

The prediction of porosity is achieved by using available core and log data; however, the estimation of permeability is limited to the scare core data. Hence, porosity and saturation data through the framework of flow units can be used to make an estimation of reservoir permeability. The purpose of this study is to predict the permeability of a carbonate gas reservoir by using physical-based empirical dependence on porosity and other reservoir rock properties. It is emphasized that this new relationship has a theoretical background and is based on molecular theories. It is found out that if rock samples with different types are separated properly and samples with similar fluid-flow properties are classified in the same group, then this leads to finding an appropriate permeability/porosity relationship. In particular, the concept of hydraulic flow units (HFU) is used to characterize different rock types. This leads to a new physical-based permeability/porosity relationship that has two regression constants which are determined from the HFU method. These coefficients, which are obtained for several rock types in this study, may not be applicable to other carbonate rocks; but, by using the general form of the model presented here, based on the HFU method, one may obtain the value of these coefficients for any carbonate rock types. Finally, we used the data of cored wells for the validation of the permeability results.