Search

A shale gas reservoir is commonly characterized by nano-scale pores and throats, high clay contents, and strong heterogeneity in permeability and porosity. Such tight structure can prevent a large proportion of fracturing fluid from flowing back after the hydraulic fracturing operations. It remains challenging to quantitatively analyze the water imbibition capability of shale as the rock sample size and shape are not unified when water imbibition behavior is experimentally investigated. In this study, a new method is proposed to evaluate the water imbibition capability of shale using the ratio of the imbibition area to the mass of the rock sample to normalize the size and shape of the sample. More specifically, the experimental shale samples were collected from three different shale gas reservoirs (Sichuan Changning Block, Yunnan Zhaotong Block, Chongqing Pengshui Block) to verify the proposed method and evaluate the influencing factors of shale imbibition capability. Imbibition experiments were then conducted to analyze the influence of four factors, including matrix porosity, fracture size, clay, and rock sample size, on the water imbibition capability of shale. The results show that the proposed method can characterize the maximum imbibition capability and imbibition rate and avoid errors in the measured porosity. In addition, the rank of factors affecting the imbibition capability was found to be fracture size, porosity, clay content, and sample size. [ABSTRACT FROM AUTHOR]

Two types of experiments were conducted under different boundary conditions to characterize the anisotropic deformation and directional permeability of the coal sample. Gas sorption-induced strains in the three principal directions were studied to examine the anisotropic deformation. The results show that the coal sample can be treated as isotropic in those planes parallel to the bedding direction. However, the strong strain anisotropy of coal indicates that the gas sorption-induced matrix strain in the direction parallel to the bedding is smaller than that which is perpendicular to the bedding, under different hydrostatic pressures for unconstrained conditions. Permeability measurements were conducted under different effective stresses to determine the magnitude and orientation of directional permeability. It was found that cleat distribution plays a dominant role in the magnitude of the measured permeability. After the two principal permeabilities parallel to the bedding planes are calculated, Mohr's circle of permeability can be then determined and used to estimate permeability in other directions of the bedding. The experimental results show that the principal permeability directions vary under different effective stresses, illustrating that coal cleat system would be reoriented during gas production. It was also found that cleat reorientation is attributed to three factors: stress contrast, the difference of Biot's coefficient, and the difference in the sorption-induced stresses in the direction perpendicular to and parallel to the bedding planes. However, cleat reorientation had little influence on changes in the magnitude of coal permeability. Permeability anisotropy degree between the three principal directions varies dynamically under different effective stresses, and then possibly changes direction of gas flow. This study demonstrates that stress-dependent coal anisotropy should be considered for simulating gas flow behavior and predicting coalbed methane production. [ABSTRACT FROM AUTHOR]

novel technique has been developed to implicitly estimate relative permeability by history matching the production data with the ensemble Kalman filter (EnKF) method. Water and oil relative permeability curves were approximated using the B-spline model, which has been modified to better represent the relative permeability curves. Compared to the existing implicit approaches, the newly developed technique did not require the use of the gradient of the objectives function and thus, was easy to implement. The newly developed technique has been validated by accurately evaluating relative permeability in a two-dimension synthetic heterogeneous reservoir. The case study showed that the estimated relative permeability was improved gradually as observation data were assimilated and that a good estimation of relative permeability curves can be effectively obtained. In this study, three estimation scenarios assimilating various types of observation data were examined and compared. It was also found that the oil relative permeability was sensitive to the oil production rate (OPR) data, as OPR was directly affected by oil relative permeability. On the other hand, water relative permeability was more sensitive to the bottomhole pressure data of the producers. Additionally, the production data, obtained prior to water breakthrough, contributed more to the estimation of the two-phase relative permeability curves. [ABSTRACT FROM AUTHOR]

The pressure transient technique has been widely used for laboratory tests on unconventional gas reservoirs; however, it is still a time-consuming process when applying this technique to rocks of ultra-low permeability in the nano-Darcy scale. The applicability of a novel radial-flow transient technique to achieve fast and accurate permeability measurements is verified by an experimental investigation in this study. Pressure transient tests were performed on two hollow cylindrical shale specimens with different inner radii under radially convergent flow conditions; and for comparison, a solid shale core was also tested via an axial-flow transient technique. The results showed that the time required for a complete pressure pulse decay by the radial-flow test is within several hours compared to a few days by the axial-flow test. It was also found that non-uniform stress distribution along the radius of the sample is the principle factor resulting in errors in the measured permeability; and thus, samples with a small inner radius should be used to reduce the error in the measured permeability. In addition, analytical solutions are derived to interpret the lab data for permeability determination. The accuracy of the proposed technique is elucidated by the small permeability difference of less than 15% compared to the axial flow tests. The permeability error analysis indicated that the effect of compressive storage and gas sorption can be eliminated, and the error is less than 6.7% even though two large pressure pulses of 0.5 MPa were generated. The study experimentally validates that fast and accurate permeability measurements can be achieved by adopting the proposed radial-flow transient technique. • Applicability of a novel transient technique is experimentally verified. • An analytical solution for permeability calculation is derived. • The proposed technique is highly efficient for testing sorptive gas reservoirs. • Uneven stress distribution is a dominant factor causing permeability errors. • Effect of gas compressibility is minimized via the proposed transient technique. [ABSTRACT FROM AUTHOR]

Gas storage and transport mechanisms are essential for the shale gas development, while the three critical parameters are fracture permeability, adsorption capacity, and diffusivity. However, significant errors on the measured permeability may occur due to the gas sorption in the pores during the lab tests, which also affects the in-situ pore pressure. In this paper, a new approach is proposed to simultaneously determine the permeability, adsorption capacity, and diffusivity based on a modified pressure transient technique in the shale formation. Results showed that the shale permeability would be overestimated by >27.3% for Barnett shale and 55.5% for Eagle Ford shale when ignoring the sorption effect. The factors leading to errors in the measured permeability is numerically investigated and it was found that the sorption effect on the measured permeability can be reduced by using short core samples. In addition, the volume of the reference cell should be at least 6 times larger than the pore volume of the sample in order to control the permeability error within 5%. This study provides a methodology which can be readily applied in simultaneous determination of gas permeability, gas storage, and gas diffusivity, and sheds lights on better understanding of the gas storage and transport mechanisms in gas shale reservoirs. • A modified transient technique is developed to simultaneously determine permeability and diffusivity in gas shales. • Dynamic effect of gas sorption on pressure responses and the measured permeability is calibrated. • Factors influencing the accuracy of permeability estimation are analyzed. • A new method is proposed to differentiate gas absorption from gas adsorption and estimate diffusivity. [ABSTRACT FROM AUTHOR]

• Various permeability measurement techniques are summarized. • Pulse decay methods for permeability tests under stressed conditions are reviewed. • Analytical solutions for transient pressure data interpretation are derived. • A comparison between different pulse decay methods is made through numerical modeling. • Factors that influence the accuracy of the measured permeability are analyzed. The assessment of economic viability on unconventional gas reservoir formations has been challenging due to the difficulties in accurately quantifying their permeabilities in the micro-/nano-Darcy range. Core plugs are commonly used for stress-dependent permeability measurements using the pulse decay method (PDM). However, the resultant permeabilities from different PDMs are full of controversy because of the variability in the measured permeabilities. Such variability results from the different analytical solutions used for measured data interpretation. An in-depth review is provided on permeability measurement techniques, including the steady-state and various unsteady-state methods. By comparison, it is concluded that the PDMs are the best option when performing permeability measurements under in-situ stress/strain conditions. The review highlights seven different PDM techniques, the mathematical models closely representing each PDM technique are established and their analytical solutions are then derived for experimental data interpretation. Recently emerged PDM techniques are reviewed for the purpose of achieving fast permeability measurements. These PDM techniques involve two different gas flow scenarios: axial flow and radial flow in core samples. In the review we describe each method's advantages and disadvantages, and it was found that fast permeability measurements can be achieved by the radial flow PDMs. We analyzed multiple factors which could influence the accuracy of the measured permeability, and revealed that the reservoir volumes, pulse sizes and sample preparation could be the dominant ones. This study sheds lights on the limitations and suitability of each PDM technique and provides a better way to interpret experimental data and achieve fast measurements. [ABSTRACT FROM AUTHOR]

Highlights • A new apparatus was designed to exam dynamic capillary pressure at different capillary numbers. • The second critical capillary number for chemical flooding is proposed and verified. • Sensitivity analysis by numerical production simulations on a real formation were carried out. • The dynamic interface properties were investigated to reveal the fluid transport behavior. Abstract High capillary numbers are often adopted for chemical flooding in reservoirs to achieve the highest oil recovery. A high capillary number may be disadvantageous for high and medium permeability formations, while no experimental or field data are available for low permeability formations. In this work, through the use of a newly designed experimental apparatus for the measurement of the dynamic capillary pressure in low permeability formations, chemical flooding experiments on sandstone core samples (1–10 mD) were conducted to investigate the effects of high capillary numbers (0.001–2). In addition, these effects were examined through numerical production simulations on a real low permeability reservoir. The dynamic capillary pressure and relative permeability were measured to reveal the dynamic fluid flow characteristics. The dynamic contact angle was investigated to explore the dynamic interface properties. The results show that there is a second critical capillary number (higher than 0.02) that can be used to optimize the chemical flooding performance in low permeability reservoirs. Moreover, the oil relative permeability reaches its highest value at the second critical capillary number, while the water relative permeability always increases with the increase in the capillary number. The dynamic contact angle will reach approximately 180° at a high capillary number, causing an oil film to remain. An optimized capillary number range is proposed for chemical flooding in low permeability reservoirs. [ABSTRACT FROM AUTHOR]

In the description of multiphase flow in porous media, dynamic capillarity is typically ignored. While some studies suggest that dynamic capillarity can be ignored in high permeability rock, it cannot be overlooked in low permeability rock. In this work, dynamic capillarity, in various permeability formations, was investigated through specially designed experiments and the impact on field production is simulated. First, capillarity characters (capillary pressure-saturation relationships and relative permeability curves) were obtained during the static and dynamic waterflooding process conducted in different permeability core samples under in-situ reservoir conditions. The dynamic coefficients were calculated locally and compared. Then experimental results were subjected to sensitivity analyses, through numerical simulation studies using CMG (IMEX), to determine the dynamic capillary effects on different permeability cases. The results show that (a) a low permeability formation constitutes a much larger dynamic coefficient, thus resulting in a significant difference between dynamic and static capillary pressures; (b) the lower the rock permeability, the larger the difference between static and dynamic relative permeability curves; (c) the dynamic capillary pressure in low permeability formations, compared with static capillary pressure, can be notably large, causing irregular differences in phase behavior and pressure distribution. This work demonstrates the importance of considering dynamic capillarity in low permeability reservoirs. [ABSTRACT FROM AUTHOR]

• New fractal-based model describes oil–water permeability in complex porous media considering stress sensitivity. • Stress, elastic modulus, porosity, max & min flow radius effects quantitatively explored. • The fractal oil–water relative permeability model aids comprehension of multi-phase flow in porous media. It is significant to accurately evaluate the relative permeability of oil–water two phase for multiphase seepage in porous media in low permeability and tight oil reservoir. However, stress sensitivity is an important characteristic for low permeability and tight oil reservoir. It is an effective way for fractal theory to describe the complexity and heterogeneity of the microstructure of porous media. To describe the relative permeability of oil–water two phase in porous media with complex and irregularity pores, a new relative permeability model oil–water two phases is proposed by the fractal theory and the stress sensitivity is taken into the established model in this paper. Meanwhile, the effects of effective stress, elastic modulus, porosity, maximum and minimum flow radius on oil–water relative permeability are analyzed. The new model is verified by comparing with the laboratory data and the results demonstrate that irreducible water and residual oil saturation have a negative correlation with effective stress. The relative permeability of the oil–water two-phase will shrink to the middle as the rise of effective stress, and the region of co-infiltration will decrease. The deformation quantity of porous media, irreducible water and residual oil saturation will increase as the elastic modulus decreases. The larger the maximum flow radius is, the lower the irreducible water saturation and residual oil saturation is. Both the porosity and the minimum flow radius have slight influences on the relative permeability of oil–water two-phase. The proposed relative permeability model can effectively predict the relative permeability of oil and water and help to describe and reveal the multiphase flow in porous media. [ABSTRACT FROM AUTHOR]

• Effects of supercritical water condition on multiphase flow were examined. • Capillary pressures under supercritical water conditions were measured. • Generation of micro-fractures was investigated. • Visbreaking of crude oil was explored. Hydraulic fracturing is an important approach for stimulating the production of ultra-low-permeability oil reservoirs; however, the low flowback efficiency of the fracturing fluid (FF) may cause contamination of the groundwater and reduce oil recovery. This study experimentally investigates the possibility of improving the flowback efficiency of water-based FF and oil production through the achievement of supercritical water (SCW) conditions after the injection of FF in ultra-low-permeability oil reservoirs. Possible mechanisms are explored through measurement of the capillary pressure, visbreaking of oil, pore-fracture distribution, and mineral components. The results show that the FF flowback efficiency and oil recovery after the SCW condition treatment are an average of 10.2% and 19% higher than those after regular hydraulic fracturing (RHF), respectively. The lower capillary pressure after the SCW condition treatment indicates a lower flow resistance. Furthermore, the increase in the proportion of large pores ranges from 6.6% to 9.0% for the fracturing process after the SCW condition treatment, whereas the increase in large pores after RHF ranges from 2.8% to 4.5%. The increases in the porosity of the core samples after the SCW condition treatment are 0.87%, 1.08%, and 1.43%, which are markedly higher than those after RHF (0.33%, 0.24%, and 0.26%, respectively). The percentage of kaolinite in the rock samples increases, whereas that of interstratified illite–montmorillonite decreases after the SCW condition treatment, thus increasing the stability of the minerals in water. The reduced dynamic viscosity and lighter components of the recovered oil from the SCW condition treatment reveal the occurrence of visbreaking of the crude oil. [ABSTRACT FROM AUTHOR]

Capillary pressure plays a fundamental role for the characterization and development of oil and gas reservoirs. Traditionally, the capillary pressure measured in equilibrium state is adopted for the investigation of the multiphase flow in porous media. However, the actual multiphase flow in the underground reservoirs is dynamic (transient) at most time, which is affected by the dynamic capillarity effect. This review offers an overview of studies on the mechanisms, experiments and models of the dynamic capillarity effect, with particular emphasis on the dynamic capillarity effect in low permeability and tight reservoirs. The review initially discussed the controlling parameters of the dynamic capillarity effect, including fluid viscosity, heterogeneity, domain scale, wettability et al., among which conclusions on the influence of the properties of porous media and wettability are consistent. The second part of the review outlined the development of the porous media permeability and the experimental conditions for the dynamic capillarity effect experiments. In the third section, the dynamic capillarity effect models were concluded, namely the continuum models used in production prediction and the pore scale models mainly used to explore the physics of multiphase flow. In addition, an overview of the influence of the dynamic capillarity effect on low permeability and tight reservoirs was provided, and methods (e.g. adding surfactants) to optimize the behavior of dynamic capillarity effect were discussed. Finally, the criteria to consider the dynamic capillarity effect in a porous medium are proposed. This study can help for a better understanding of multiphase flow in porous media. • Current state of developments in dynamic capillarity effect is reviewed. • Controlling parameters of the dynamic capillarity effect are summarized. • The dynamic capillarity effect experiments are presented. • The dynamic capillarity effect models are discussed. • The dynamic capillarity effect in tight reservoirs is outlined. [ABSTRACT FROM AUTHOR]