Tight Sandstone Core Samples Research Articles

Investigation of the Combination Mechanism of Spontaneous Imbibition and Water Flooding in Tight Oil Reservoirs Based on Nuclear Magnetic Resonance

As conventional oil reservoirs are gradually being depleted, researchers worldwide are progressively shifting their focus towards the development and comprehensive study of tight oil reservoirs. Considering that hydraulic fracturing is one of the main approaches for developing tight sandstone reservoirs, it is of great significance to explore the mechanism of spontaneous imbibition and waterflooding behavior after hydraulic fracturing in tight oil reservoirs. This research delves into the analysis of tight sandstone core samples obtained from the Shahejie Formation in the Bohai Bay Basin. All core samples are used for a series of experiments, including spontaneous imbibition and water flooding experiments. An additional well-shut period experiment is designed to understand the impact and operational dynamics of well shut-in procedures in tight reservoir development. Utilizing nuclear magnetic resonance (NMR) technology, the pore sizes of a sample are divided into three types, namely, macropores (>100 ms), mesopores (10–100 ms), and micropores (<10 ms), to thoroughly assess the fluid distribution and changes in fluid signals during the spontaneous imbibition and water flooding stages. Experimental outcomes reveal that during the spontaneous imbibition stage, oil recovery ranges from 12.23% to 18.70%, predominantly depending on capillary forces. The final oil recovery initially rises and then falls as permeability decreases, while the contribution of micropores progressively grows as the share of mesopores and macropores deceases. With water flooding processes carried out after spontaneous imbibition, enhanced oil recovery is observed between 28.26% and 33.50% and is directly proportional to permeability. The well shut-in procedures can elevate the oil recovery to as high as 47.66% by optimizing energy balance.

Effect of Matrix Characteristic and the Pore‐Throat Limit for Water Imbibition in Early Jurassic Tight Sandstone Reservoir of the Tuha Basin

Spontaneous imbibition (SI) is a fundamental mechanism for improving the production efficiency of tight sandstone reservoirs. Matrix characteristic plays important roles in the SI process, but how these factors affect SI and the limit pore‐throat size of effective driving force in the tight sandstone of the Tuha Basin has not been firmly established. Thus, a series of experiments (FE‐SEM, QEMSCAN, XRD, CT, and SI) of four tight sandstone core samples were conducted under laboratory conditions in the Tuha Basin. The results show that quartz and plagioclase feldspar are the main detrital minerals, while illite and illite/smectite (I/S) are the predominant clay minerals of those sandstone samples, and they have a micro‐nano (<2 μm) to meso‐macro (>10 μm) pores, but the micro‐nano pore performance disconnected, and during SI process, fluid enters small and meso‐macro‐size pores simultaneously. However, small pores play a dominant role in the initial stage (with steep imbibition slopes), while meso‐macro pores predominate in the second stage (with shallow imbibition slopes), and the limit pore‐throat value of the tight sandstone is around 9.1 μm in the Tuha Basin, beyond which the SI will be weakened. Though the mineral composition and its wettability will be changed with fluid environment (especially for clay minerals), the small pores (formed by clay minerals) always play a dominant role than meso‐macro‐size pores (mainly formed by quartz and plagioclase feldspar) in SI process. These observations can improve our understanding of fluid–reservoir interaction in the Tuha Basin’s tight sandstone reservoir and provide guidance for improving oil and gas recovery.

Model of shear strength of ultra-deep fractured sandstone considering fracture morphology

Ultra-Deep fractured tight sandstone gas reservoir, the hotpot unconventional petroleum resources, has been the subject of investigation recently. Due to the presence of natural fractures, drilling in ultra-deep fractured tight sandstone may cause complicated wellbore instabilities, which resulted in a substantial challenge to the efficient exploitation and production of tight gas resources. In order to understand the rock mechanical properties of the ultra-deep fractured tight sandstone under shear stress, tight sandstone core samples were artificially shear-fractured, the 3D characteristics of the fractures were reconstructed by CT scanning, and the fracture aperture and roughness characteristics were systematically evaluated. Simultaneously, triaxial shear strength tests were conducted to evaluate the mechanical properties of fractured rock subjected to varying confining pressures. Considering the contact relationship of the fracture surface during shearing, two indexes of average effective shear angle and contact area ratio were proposed to correct the fracture roughness, and a new fracture shear strength model was constructed, which served as the failure criterion for the fractured formation. The results show that the intact rock has a high compressive strength and can only collapse under conditions of substantial differential stress. Consequently, shear failure of fracture ought to be the primary source of wellbore instability. The fracture aperture's spatial distribution is irregular and conforms to a Gaussian distribution. A clear anisotropy in the fracture roughness is present, and there is less roughness along the initial shear failure path and more roughness perpendicularly. With an increase in normal stress, the fracture's peak shear strength rises, while the friction angle steadily falls. The innovative model's accuracy in predicting shear strength is higher than that of the weak-surface model and the JRC-JCS model.

Research on fluid mobility in tight-sandstone with a NMR fractal theory pore classification method

The fluid mobility characteristics in the pores with various apertures for tight-sandstone would finally determine the fluid mobility and production of tight oil and gas reservoirs. In this study, the tight-sandstone core samples collected from Middle Jurassic Xishanyao Formation in Santanghu Basin were launched the fluid mobility measurements under various centrifugal speeds. With the NMR fractal theory pore classification method, the various types of pores in the tight-sandstone core samples were classified, and the fluid mobility in different types of pores were also investigated. The results show that the tights-sandstone core samples were significantly influenced by compaction, and the core samples are relatively dense, the mineral intergranular solution pores and colloidal intergranular pores are the main storage spaces. With a constant increase of the centrifugal speed, the fluid mobility increases continuously, and the fluid mobility for CTOS-19 features stronger than that of CTOS-7, which is related to the complexity of pore structure in tight-sandstone sample. Compared with the pore aperture in CTOS-19, the pore aperture in CTOS-7 is smaller, and the connectivity between the smaller and larger pores is poorer, leading to the poorer fluid mobility. Besides, the NMR fractal theory pore classification method also shows that the COTS-7 features more pore types than COTS-19, five and four types respectively. The type P2 and P3 pores are dominant in COTS-7 and CTOS-19 core samples, and the connectivity between type P2 and P3 pores contributes dominantly to the fluid mobility. With the NMR fractal theory pore classification method, the complexity of the distribution of fluid and fluid mobility in tight reservoirs could be studied quantitatively, and the results can efficiently guide the development of residual oil and gas in tight oil reservoirs.

Reasons for low flowback behaviors of water-based fluids in tight sandstone gas reservoirs

Water-based working fluids are widely applied in the development of tight gas formations. However, these fluids’ flowback rate is generally low than 50%, resulting in a large amount of water retention to dramatically decline the gas delivery. Typical tight sandstone core samples are selected in this study to perform the gas-driven water displacement experiment to investigate the underlying mechanisms for the low water flowback behaviors in tight gas reservoirs. Results show that the average water flowback rate for 15 tight sandstone samples by gas-driven water displacement is obtained to be only 31.31%, which in turn causes an average gas permeability damage rate of 58.94%. Analysis suggests that multiscale pore structures, ultra-low connate water saturation phenomenon, filling of hydrophilic clay minerals, and insufficient pressure drop contribute to the congenitally unfavorable geological factors of low water flowback capacity. On the other hand, irreversible formation damages like water phase trapping, salting out issues, and residual water film effect caused by water retention are the main elements that restrict water removal during a gas-flow drying process. The findings of this study provide useful insights into the control mechanisms of low water flowback behaviors and the formation damages induced by water invasion in tight sandstone gas reservoirs.

Movable Fluid Distribution Characteristics and Microscopic Mechanism of Tight Reservoir in Yanchang Formation, Ordos Basin

Tight sandstone reservoirs have smaller pore throats, complex structures, strong heterogeneity in the pore throat system, and significant differences in fluid distribution. To reveal the occurrence characteristics of movable fluids in tight sandstone reservoirs, the typical tight sandstone core samples from the Chang 4+5 reservoir of the Upper Triassic Yanchang Formation of the Ordos Basin were selected and the micro pore throat classification standard was established by using casting thin slices, field emission scanning electron microscopy (FE-SEM), high-pressure mercury injection (HPMI), and nuclear magnetic resonance (NMR) technology. The test analysis results showed that the Chang 4+5 tight sandstone reservoir can be divided into Type I, II, and III reservoirs by the different pore throat structure. Type I reservoirs have well-developed pore throats, good connectivity, low threshold pressure (0.42 MPa on average), high movable fluid saturation (46.82% on average), and a minimum pore throat radius of movable fluid (0.056 μm on average). The pore throat structure and fluid production degree of the other two reservoir types gradually deteriorated. Note that the tight sandstone reservoirs of the Chang 4+5 reservoirs have smaller pore throats but high movable fluid content in smaller pore throats (17% on average). With the deterioration of the pore throat structure in reservoir, the degree of fluid utilization in larger pore throats decreases (74.33%–57.33%), whereas the degree of fluid utilization in smaller pore throats does not change significantly (25.67%–13.82%). Many factors affect movable fluid parameters. The movable fluid parameters of tight sandstone reservoirs in the Chang 4+5 reservoir have a good positive correlation with permeability (R2 = 0.85) and sorting coefficients (R2 = 0.88). The movable fluid parameters of smaller and larger pore throats have no obvious correlation with a single factor. Multiple factors affect the fluid occurrence characteristics of different scale pore throats.

Evaluation of the impact of CO2 geological storage on tight oil reservoir properties

Carbon capture, utilization, and storage (CCUS) is an emerging methodology to mitigate CO2 emissions. When injected into the subsurface, there are potential interactions between CO2, pore fluids, and the reservoir rock. To determine analyzed the effect of CO2 on the physical properties of geological reservoirs, the pore structure, and mineral composition of cores before and after CO2 static soaking. The samples were analyzed using nuclear magnetic resonance (NMR), X-ray diffraction (XRD), scanning electron microscope (SEM), and energy dispersive spectrometer (EDS). This study found that the pore size of tight sandstone core samples increases with time under the same formation water condition. At the same time, the pore changes of tight sandstone samples are different under different CO2-formation water immersion. The experimental results show that the degree of dissolution of minerals with CaCl2 formation water is negligible. Often, When CO2 injection, two phenomena usually occur. First, mineral dissolution enlarges pores. Second, the diagenetic crystallization of salt and illite divides the pores will increase the pore size. The results of the CO2–NaHCO3 static immersion show experiments that within seven days, due to salt diagenesis and mineral precipitation than mineral dissolution, the pores decrease. With the further strengthening of mineral dissolution, the pores increase during 7–12 days. In addition, in CO2– CaCl2 type formation water, only pore size decreases within the reaction time of 12 days, indicating that precipitation is more excellent than dissolution in this water environment. The comprehensive analysis shows that the effect of CO2 on pore enlargement is not unidirectional but first inhibits and then promotes pore size. After CO2 injection into the formation, it is dissolved in formation water with different chemical properties, influencing reservoir rocks. Compared with CO2– CaCl2 formation water, CO2–NaHCO3 formation water has a noticeable effect of increasing porosity, which has the potential of improving oilfield tight reservoir conditions to a certain extent.

An integral method for calculation of capillary pressure based on centrifuge data of tight sandstone

The traditional Hassler-Brunner (HB) interpretation method of centrifuge capillary pressure is widely used in materials, soil, biotechnology, and especially in the petroleum industry. However, the assumptions of the traditional method cannot be simultaneously satisfied, the traditional method has been known to lead significant errors in some cases. In this paper, a new double integral method is proposed to evaluate the centrifuge capillary pressure of long tight sandstone samples. Both the changes of capillary length and interface of wetting phase and non-wetting phase fluids are considered by the new integral method, thus the average pressure and saturation derived from the proposed double integral method is more sufficient in theoretic foundation and clearer on physical meaning. By comparing with the measured capillary pressure of long tight sandstone core samples from porous plate, the capillary pressure calculated from traditional HB method is obviously smaller than the measured value, and the discrepancy increases with the decreasing core porosity. However, the average capillary pressure obtained by the proposed double integral method is remarkably consistent with the measured value. The findings of this study can help for better understanding of distribution of wetting phase fluid and average centrifuge capillary pressure in the core during centrifugal process.

A new NMR-data-based method for predicting petrophysical properties of tight sandstone reservoirs

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.

Distribution characteristics of movable fluid in tight sandstone based on nuclear magnetic resonance

Movable fluid parameter is an important index to evaluate the seepage characteristics of tight sandstone reservoir. Combined with high-pressure displacement and nuclear magnetic resonance movable fluid testing principle, the nuclear magnetic resonance movable fluid characteristics of six typical tight sandstone core samples of Xujiahe Formation in Central Sichuan Basin were studied. Based on mercury injection capillary pressure curve, the nuclear magnetic resonance T2 spectrum distribution was converted into pore throat According to the radius distribution, the minimum pore throat radius of the movable fluid and the contribution of different pore sizes to the movable fluid are determined. The research shows that the movable fluid saturation of the tight sandstone reservoir in the second member of Xujiahe Formation in Central Sichuan is closely related to the pressure difference, with good logarithmic correlation, and the main contribution to the movable fluid saturation is the reservoir space > 0.1 μm. 70% of the total movable fluid saturation is injected at a lower pressure (about 5MPa). In the later stage, high pressure injection can only enter the reservoir pore with small pore size, and the total amount is small and increases slowly. Therefore, the total contribution of high pressure drive to gas saturation in the later stage is small.

A new method to determine surface relaxivity of tight sandstone cores based on LF-NMR and high-speed centrifugation measurements

Low-field nuclear magnetic resonance (LF-NMR) T2 spectrum commonly is converted into pore size distribution (PSD) with accurate calculation of surface relaxivity. Currently, the surface relaxivity for unconventional cores is determined indirectly using average pore radius (ARS) method or surface-to-volume ratio (SVR) method. The ARS method is time consuming, and inevitably it causes permanent damage to core samples because of the injection of mercury. In this study, we proposed a new method, the pseudo T2 cut-off (PTC) method, instead of the ARS method to calculate the surface relaxivity of tight sandstone core samples by correlating a PTC value with the corresponding pore radius. First, we performed LF-NMR and high-speed centrifugation (HSC) measurements on four tight sandstone core samples to determine surface relaxivity using the PTC method. Then, we compared the calculated surface relaxivity using the new method with that determined using the ARS and SVR methods. Then, we converted the T2 spectrum into PSD using appropriate surface relaxivity. Finally, we obtained residual oil distribution. The results showed that we had established an exponential correlation between the PTC value and surface relaxivity. Ultimate surface relaxivity values for tight sandstone core samples were 5.85, 2.98, 4.66, and 2.17 μm/s. The values of ρARS and ρPTC were close but generally larger than that of ρSVR. We still observed a linear correlation between illite content and different surface relaxivity. Moreover, we obtained PSD in mesopores and macropores by jointly using ρPTC (or ρARS) and ρSVR. After centrifugation, the residual oil (62.94 wt%) was mainly distributed in the micropores (~20 wt%) and mesopores (~35 wt%). This study provided a nondestructive method to determine the surface relaxivity of tight sandstone cores and provided information for residual oil distribution.

Acidizing of conventional and tight sandstone formation using chelating agents: mineralogical prospect

Stimulation of the sandstone reservoir requires a mixture of acids such as mud acid, which assist in enlarging the microscopic paths by dissolving the siliceous fines or clays near the well-bore region. As a result, the formation permeability and porosity can be enhanced. In deeper wells, the temperature exceeds 200 °F, at these temperature ranges, problems can arise. For example, the use of mud acid mixtures can lead to issues like precipitations, corrosion, early consumption of acids, leading to lesser acid efficiency. In this study, the core flooding apparatus was used for acidizing experiments, designed to dissolve minerals and to analyze the changes in petrophysical parameters such as porosity, permeability, and mineralogy. Conventional and tight sandstone core samples were acidized using different chelating acids such as Hydroxyethylethylenediaminetriacetic acid (HEDTA), Ethylenediaminetetraacetic acid (EDTA) and Glutamic acid (GLDA) at high-temperature conditions. Analytical studies (mineral mass, pore size distribution, topology, grain size distribution, and density distribution were conducted using Tescan Integrated Mineral Analysis (TIMA). The obtained results showed that chelating agent HEDTA created more pore spaces in the core samples and is effective in dissolving positive ions. Also, the permeability was observed to be doubled by its application which could be effective in alteration of pore topology of the sandstone cores.

Effect of tortuosity on the stress-dependent permeability of tight sandstones: Analytical modelling and experimentation

Accurately modelling stress-dependent permeability is of great significance to predicting the oil/gas production of unconventional tight sandstone reservoirs with time-dependent pressure depletion. The classic theory indicates that the porosity exponents of the capillary tube model and the fracture model are 2 and 3, respectively. However, experimental results demonstrate that the value of the porosity exponent usually varies greatly. The effect of the nonuniform distribution of tortuosity on stress-dependent permeability is rarely studied. Assuming that tight sandstones with natural microfractures can be represented by a bundle of tortuous capillary tubes and parallel plate fractures, a new stress-dependent permeability model of tight sandstones is proposed based on fractal theory considering the tortuosity effect. The research results show that the porosity exponents of the tortuous capillary tube model and the tortuous plate fracture model are (3+DT)/2 and 2+DT, respectively (here, DT is the tortuosity fractal dimension). For the capillary tube model and the plate fracture model without tortuosity (DT=1), their porosity exponents can be simplified to 2 and 3, respectively. The tortuosity fractal dimension is one of the reasons causing the porosity exponent to deviate from the classic theoretical value. The newly developed stress-dependent permeability model is verified with experimental data determined using tight sandstone core samples from the Yanchang Formation in the Ordos Basin, China. The average error of the permeability prediction under different effective stresses is only 3.78%; thus, the newly developed model can accurately predict the stress-dependent permeability of tight sandstones.

Experimental investigation of spontaneous imbibition in tight sandstone reservoirs

Based on field conducts, it is found that a lower flowback rate results in a higher oil recovery in a tight sandstone reservoir. Spontaneous imbibition, as a main mechanism of oil production increment for this phenomenon, has been paid more and more attention. The aim of this study is to explain the spontaneous imbibition in tight sandstone reservoirs, find the primary factors, and provide suggestions and guidance for the field operations.This paper performs the study using tight sandstone core samples, coming from a block in Ordos Basin. First, different phenomena were observed through core imbibition experiments. The phenomena were explained in depth by mercury intrusion tests, casting sheet experiments and fractal dimension. Then, a completely randomized designed experiment was proposed. Stabilization time of spontaneous imbibition was defined for the first time. The effects of permeability, salinity, viscosity, and interfacial tension on the recovery factor (RF) and stabilization time were discussed. The feasibility of the experimental approach was verified. Finally, the primary factors affecting the RF and the stabilization time were obtained based on the principal component analysis (PCA). And some suggestions were proposed to provide guidance for the field operations.The research results of this paper bring a better comprehensive understanding of spontaneous imbibition in tight sandstone reservoirs, providing significant guidance and suggestions for the field promotion of imbibition oil displacement.

Novel Insights into the Movable Fluid Distribution in Tight Sandstones Using Nuclear Magnetic Resonance and Rate-Controlled Porosimetry

To characterize the movable fluid distribution in tight sandstones and determine its influencing factors, 20 tight sandstone core samples from the Chang-6 and Chang-8 Members of the Yanchang Formation in the Ordos Basin, NW China, were analyzed using nuclear magnetic resonance (NMR) and rate-controlled porosimetry (RCP). The conventional method of movable fluid analysis divides the whole NMR T2 spectrum into two parts, namely unmovable and movable fluids, based on a single T2cutoff value. However, this conventional method ignores pore size wherein fluid is partially movable. In this paper, the fluid in tight sandstones is divided into three parts, i.e., completely unmovable, partially movable and completely movable fluids. Based on the throat size distribution obtained from RCP, T2 spectra were converted into corresponding pore-throat sizes with the nonlinear conversion method, and then the critical pore-throat sizes for fluid distribution were derived. The research results show that the average residual liquid saturation was 46.14% under a centrifugal pressure of 900 psi. On average, the completely unmovable fluid occupied approximately 18% of the total pore volume of tight sandstones, the partially movable fluid accounted for approximately 72% of the total pore volume, and the completely movable fluid accounted for only approximately 10% of the total pore volume. The pore throats filled with completely unmovable fluid contributed very little to the permeability. Compared with the Chang-8 Member, the tight sandstones of the Chang-6 Member had higher completely unmovable fluid saturation and larger critical pore-throat size of the completely unmovable fluid.

Comprehensive characterization of pore and throat system for tight sandstone reservoirs and associated permeability determination method using SEM, rate-controlled mercury and high pressure mercury

Unconventional resource formations like tight sandstone reservoirs have complex pore and throat structure that are hard to characterize in micro scale. In this research, the pore and throat system of tight sandstones was characterized comprehensively, analysed qualitatively using scanning electron microscopy (SEM) techniques and quantitatively through combined high pressure mercury (HPM) and rate-controlled mercury (RCM) methods. First, the throat, distinguished from the pore, was divided in several types for tight sandstones and visualized through SEM imaging. Then, an integrated approach was proposed to combine the results from both HPM and RCM measurements, resulting in overall size distributions of the pore and the throat with scales from nanometer to micrometer. Both overall size distribution using the new combining method represented the pore and the throat more accurately in wider ranges. The results also showed that for tight sandstone core samples with different permeability, the difference of pore size distribution was less obvious than that of the throat. Therefore, the quantitative characterization of the throat size distribution was ultimately employed in developing a new permeability model together with physical considerations. The results demonstrated that the permeability of tight sandstones was in general depend on the size distribution of relatively larger throat, denoted as the macrothroat. However, for extreme low permeability (<0.1mD) formation, the small throats like microthroats and mesothroats mainly contributed to the permeability since the contents of macrothroats are really low.

A Semi-analytical Model for Pressure-Dependent Permeability of Tight Sandstone Reservoirs

In tight gas reservoirs, permeability is pressure dependent owing to pore pressure reduction during the life of the reservoir. Empirical models are commonly used to describe pressure-dependent permeability. In this paper, it was discussed a number of issues which centered around tight sandstone pressure-dependent permeability experiment, first to apply core aging on permeability test and then to develop a new semi-analytical model to predict permeability. In tight sandstone permeability test experiment, the microinterstice between core and sleeves resulted in over estimation of dependency of permeability on pressure. Then, a new semi-analytical model was developed to identify the relation between permeability and fluid pressure in tight sandstone, which indicates there is a linear relation between pore pressure changes and the inverse of permeability to a constant power. Pressure-dependent permeability of 8 tight sandstone core samples from Ordos Basin, China, was obtained using the modified procedure, and results were perfectly matched with the proposed model. Meanwhile, the semi-analytical model was also verified by pressure-dependent permeability of 16 cores in the literature and experiment results of these 24 cores were matched by empirical models and the semi-analytical model. Compared with regression result of commonly used empirical models, the semi-analytical model outperforms the current empirical models on 8 cores from our experiment and 16 cores from the literature. The model verification also indicates that the semi-theoretical model can match the pressure-dependent permeability of different rock types. In addition, the permeability performance under reservoir condition is discussed, which is divided into two stages. In most tight gas reservoirs, the permeability performance during production is located in stage II. The evaluation result with proposed experiment procedure and the stress condition in stage II will reduce permeability sensitivity to stress.

Novel method for calculating the effective stress coefficient in a tight sandstone reservoir

Determining the influence of effective stress on rock deformation is essential for geotechnical stability analysis in oil and gas production. There is no universal effective stress coefficient for all rock properties, and different values of effective stress coefficient apply for different physical quantities (Gurevich, 2004). Although the effective stress law and its application is not new, frequently overlooked or misapplied. Hence, a novel method was proposed for measuring and calculating the effective stress coefficient in this work. Firstly, pore compressibility under different confine pressure values was measured using reservoir fluid or experimental fluid. Secondly, effective stress was calculated by comparing pore compressibility under different confine pressure and then, the range of effective stress coefficients was determined eventually. Finally, the reliability of the proposed method was validated via the stress-sensitive curves of tight sandstone core samples and by comparing the results with those of two other calculation methods for the effective stress coefficient. This work suggests that the stress-sensitive curves of the two core samples from the same location and with similar physical properties have given similar effective stress coefficient (η = 0.201) calculated using the proposed method, which indicates that the calculation is reasonable. The comparison of the proposed method with other methods also indicate that the proposed technique is reliable.