Low pore connectivity in natural rock

Hu, Qinhong; Ewing, Robert P.; Dultz, Stefan

doi:10.1016/j.jconhyd.2012.03.006

Cited by 195 publications

(157 citation statements)

References 27 publications

Supporting

Mentioning

146

Contrasting

Order By: Relevance

“…Cai and Yu (2011) introduced fractal to characterize the tortuosity of imbibition streamline, and theoretically found that the time exponent was related to tortuosity fractal dimension. Hu et al (2012) demonstrated that the time exponent can reflect the pore connectivity of the tight rock. As the curve degree of flowlines of the SI increases, the pore connectivity decreases and the tortuosity grows, which leads to higher resistance to SI and a time exponent lower than 0.5.…”

Section: Completely Counter-current Imbibitionmentioning

confidence: 99%

A critical review on fundamental mechanisms of spontaneous imbibition and the impact of boundary condition, fluid viscosity and wettability

Meng

Liu

Wang

2017

Adv. Geo-Energ. Res.

111

View full text Add to dashboard Cite

Spontaneous imbibition (SI) is one of the primary mechanisms of oil production from matrix system in fractured reservoirs. The main driving force for SI is capillary pressure. Researches relating to SI are moving fast. In the past few years, amount of literature on the development of SI with respect to many variables, such as mechanism of imbibition, scaling of imbibition data and wettability of matrix blocks. In this review, we first introduced the fundamental physics mechanism of SI through capillary tube models and micromodels. Then both conventional and more novel experimental methods of measuring oil production are discussed thoughtfully. This is followed by reviewing the oil production performance under various boundary conditions and the characteristic length in scaling equations that have been used to account for different cores shape and boundary conditions. The effect of fluid viscosity on the rate of oil production and final oil recovery as well as the development of viscosity term in the scaling equation are reported. The commonly used methods to quantitatively evaluate the wettability of cores and the SI under mix-and oil-wet conditions are introduced. And last but not least, the methods and mechanism of wettability alteration for enhanced oil recovery in mix-or oil-wet fractured reservoirs are presented.Keywords: Spontaneous imbibition, fractured reservoirs, boundary condition, viscosity ratio, wettability.Citation: Meng, Q., Liu, H., Wang, J. A critical review on fundamental mechanisms of spontaneous imbibition and the impact of boundary condition, fluid viscosity and wettability.

show abstract

Section: Completely Counter-current Imbibitionmentioning

confidence: 99%

A critical review on fundamental mechanisms of spontaneous imbibition and the impact of boundary condition, fluid viscosity and wettability

Meng

Liu

Wang

2017

Adv. Geo-Energ. Res.

111

View full text Add to dashboard Cite

show abstract

“…The low imbibition rate suggests that the matrix reflects a relatively low pore connectivity depicted by the slope in the curve [log (cumulative imbibition) vs. log (imbibition time)]. Hu et al (2012) proposed that the matrix in Barnett shale presents imbibition behavior of 0.26, indicating the low pore connectivity.…”

Section: Introductionmentioning

confidence: 99%

Experimental and numerical study on the relationship between water imbibition and salt ion diffusion in fractured shale reservoirs

Liu

Shi

et al. 2017

Journal of Natural Gas Science and Engineering

View full text Add to dashboard Cite

a b s t r a c tField observations demonstrate that shale gas wells feature a low flowback efficiency (<30%) and highsalinity flowback water (approximately 200kppm) after multistage hydraulic fracturing operations. The water recovery and salinity profile could be regarded as a critical method for volumetric and chemical analyses to characterize the reservoir properties and complexity of the fractured network. This paper aims to understand the relationship between fracturing imbibition and ion diffusion, which are responsible for inefficient water recovery and high-salinity flowback fluid, respectively. Comparative imbibition experiments are performed on different shale and sandstone samples, and an electrical conductivity meter is used to monitor the change in ion concentration change of the imbibition fluid. A mathematical model based on theoretical analysis is proposed to clarify the correlation between imbibition and ion diffusion. Both the experimental and analytical solution results show that the imbibition fluid conductivity resulting from ion diffusion is proportional to the square root of time, which is similar to the law of capillary-driven imbibition into porous media. Water imbibition into gas shale and ion diffusion into water proceed simultaneously in the opposite direction, and only the imbibition front contacting the pore wall with salt ions can cause the salt ions to dissolve and diffuse into water. The analytical solution results also indicate that the effects of the porosity, surface tension, contacting area and wetting angle on the water imbibition rate are in consistent with that of the ion diffusion rate. The permeability, however, shows a positive correlation with the imbibition rate and a negative correlation with the ion diffusion rate. The initial water saturation is negatively related to the imbibition rate, and positively related to the ion diffusion rate. In addition, smectite and I/S could enhance the imbibition and diffusion rates. It is observed that illite concentration has no relationship with the imbibition and diffusion rates, indicating that illite minerals do not significantly affect the imbibition/diffusion rate in these clay-rich shales. This research contributes to understanding the correlation between imbibition and ion diffusion, which is significant for flow-back analysis after fracturing operations.

show abstract

“…Makhanov et al (2012) found that imbibition rates perpendicular and parallel to the bedding plane are different, and the latter is higher. Hu et al (2012) considered that the Barnett shale has a poor connectivity, which greatly influences the flow and diffusion of fluid. Roychaudhuri et al (2013) determined that a surfactant can effectively reduce the imbibition rate of fracturing fluids, and the driving force of imbibition is the capillary pressure.…”

Section: Introductionmentioning

confidence: 99%

Experimental investigation of shale imbibition capacity and the factors influencing loss of hydraulic fracturing fluids

et al. 2015

View full text Add to dashboard Cite

Spontaneous imbibition of water-based fracturing fluids into the shale matrix is considered to be the main mechanism responsible for the high volume of water loss during the flowback period. Understanding the matrix imbibition capacity and rate helps to determine the fracturing fluid volume, optimize the flowback design, and to analyze the influences on the production of shale gas. Imbibition experiments were conducted on shale samples from the Sichuan Basin, and some tight sandstone samples from the Ordos Basin. Tight volcanic samples from the Songliao Basin were also investigated for comparison. The effects of porosity, clay minerals, surfactants, and KCl solutions on the matrix imbibition capacity and rate were systematically investigated. The results show that the imbibition characteristic of tight rocks can be characterized by the imbibition curve shape, the imbibition capacity, the imbibition rate, and the diffusion rate. The driving forces of water imbibition are the capillary pressure and the clay absorption force. For the tight rocks with low clay contents, the imbibition capacity and rate are positively correlated with the porosity. For tight rocks with high clay content, the type and content of clay minerals are the most important factors affecting the imbibition capacity. The imbibed water volume normalized by the porosity increases with an increasing total clay content. Smectite and illite/smectite tend to greatly enhance the water imbibition capacity. Furthermore, clay-rich tight rocks can imbibe a volume of water greater than their measured pore volume. The average ratio of the imbibed water volume to the pore volume is approximately 1.1 in the Niutitang shale, 1.9 in the Lujiaping shale, 2.8 in the Longmaxi shale, and 4.0 in the Yingcheng volcanic rock, and this ratio can be regarded as a parameter that indicates the influence of clay. In addition, surfactants can change the imbibition capacity due to alteration of the capillary pressure and wettability. A 10 wt% KCl solution can inhibit clay absorption to reduce the imbibition capacity.

show abstract

Low pore connectivity in natural rock

Cited by 195 publications

References 27 publications

A critical review on fundamental mechanisms of spontaneous imbibition and the impact of boundary condition, fluid viscosity and wettability

A critical review on fundamental mechanisms of spontaneous imbibition and the impact of boundary condition, fluid viscosity and wettability

Experimental and numerical study on the relationship between water imbibition and salt ion diffusion in fractured shale reservoirs

Experimental investigation of shale imbibition capacity and the factors influencing loss of hydraulic fracturing fluids

Contact Info

Product

Resources

About