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After the completion of multi-stage fracturing operation, the fluid pressure in artificial fracture network continues to decrease, resulting in the closure of fracture and the variation of local induced stress field. This process can also lead to the variation of fracture propagation pattern in the subsequent fracturing stages. To better guide fracturing design, the time effect of stress field was researched. A numerical method was used to solve the induced stress around a propped fracture, and analyze the influence of formation properties and treatment parameters on its change. Then, the characteristics of stress field with different closure times and its influence on subsequent fracture were investigated. Finally, the evolution of the stress field in two stimulated wells was analyzed using the instantaneous shut-in pressure. The results show that the original horizontal stress difference, fluid pressure in fracture, fracture length, fracture angle, and amount of proppant have significant effects on the variation of induced stress field. The stress field of formation with undeveloped natural fractures decreases quickly with the rapid closure of hydraulic fractures due to the rapid drop in fluid pressure, but the stress field remains relatively constant after the fracture is fully propped. For formation with developed low angle natural fractures, the stimulated stage promotes subsequent fracture propagation and improves fracturing efficiency. The fluid pressure declined slowly and is non-uniformly distributed during the closure of the complex fracture network. Therefore, the magnitude and scope of the induced stress vary unevenly with the closure time, and there is a reasonable treatment time to form complex fractures during hydraulic fracturing. This study provides new insights into fracturing operation.

The frequent occurrence of casing failure has significantly affected the development of shale gas in the Sichuan Basin. Based on engineering and geology analyses, natural fracture/fault slip leads to casing shear deformation during hydraulic fracturing. Hence, natural fracture/fault slip and casing‐cement sheath‐formation assembly finite element models were established to quantitatively examine the characteristics of natural fracture/fault slip and mechanisms of casing shear deformation. Many factors, such as formation elastic property, in situ stress, natural fracture/fault geometry property, fluid pressure, casing elastic property, cement sheath elastic property, and well trajectory, were considered. The simulated results were in good agreement with the field data. The results indicated that natural fracture/fault slip leads to a sharp increase in casing deformation and stress in the adjacent region. Furthermore, factor sensitivity analysis results showed that a higher fluid pressure, larger fracture length, larger fracture dip angle, higher in situ stress difference, lower formation Young's modulus, and shorter distance from the wellbore to the center of the slip surface lead to severe casing stress and deformation. The countermeasures for preventing casing shear deformation involve decreasing the fracturing treatment pressure, reducing the crossing angle between the wellbore and natural fracture/fault, maintaining a safe distance from the wellbore to the large fracture/fault center, and adopting “balanced stress” fracturing operation. Hence, this study proposes a reasonable method to evaluate casing shear damage under hydraulic fracturing.

The conglomerate reservoir is rich in oil and gas reserves; however, the gravel's mechanical properties and laws are difficult to gain through laboratory experiments, which furthermore constrain the hydraulic fracturing design. To analyse the failure law of conglomerate, we simulated the uniaxial compression test based on discrete element software PFC2D and analysed the effect of different cementation strength, gravel content and gravel geometry on the rock deformation and failure characteristics. Results show that (i) as the cementation strength decreases, the compressive strength and elasticity modulus both reduce clearly, while the crack shapes get more complex and the critical value is 0.3; (ii) as the gravel content increases, the conglomerate strength first decreases then increases under the influences of cracks bypassing gravels; cementation strength and gravel content of the conglomerate both contribute to the increase in local additional stress, which leads to a series of changes in crack shapes and mechanical properties of the conglomerate. Based on the above research, the conglomerate strength and crack shapes after failure are relatively complex due to the common influence of cementation strength and gravel content. The gravel edge crack caused by stress concentration is the micro-mechanism that affects the conglomerate mechanical properties.

A large amount of fracturing fluid will be injected into the unconventional reservoirs during hydraulic fracturing. At present, the maximum amount of fracturing fluid injected into shale oil reaches 70000 m3 in Jimsar. The main function of fracturing fluid is to make fractures for traditional reconstruction of fracturing; for unconventional reservoirs, fracturing fluid is also used to increase formation energy by large-scale injection. It is of great significance to improve the utilization efficiency of large-scale hydraulic fracturing fluid for shale oil to increase production and recovery. In this study, the method of improving the utilization efficiency of the large-scale hydraulic fracturing fluids is explored by experiment, numerical simulation, and field test of Jimsar shale oil formation. This research shows that fracture complexity can effectively increase the contact area between the fracturing fluids and the formation. The water absorption rate of the fractured core is increased, which lays the foundation for improving the liquid utilization efficiency. Reasonably, well shutting before production ensures the pressure balance in the fractures, and the fluid pressure can be transmitted to the far end, which improves the fracture effectiveness, increases formation energy, and promotes imbibition and oil displacement. By using the additive of enhanced imbibition displacement, the displacement efficiency and the displacement amount of crude oil in the micro-nanopores can be greatly improved, and the utilization ratio of liquid can be further enhanced. The experiment adopted in the field proves that improving energy utilization efficiency has an important impact on production. This study has great guiding significance for the efficient development and practical production of unconventional reservoirs.

Hydraulic fracturing becomes a necessary method to exploit shale gas, and the imbibition behavior of fracturing fluid can cause the pore structure variation. At present, the evaluation of this variation has less been investigated, and repeated imbibition was conducted to research the variation of pore structure. First imbibition was conducted as simulating the pore structure variation during hydraulic fracturing, and repeated imbibition was carried out to appraise this kind of variation. Two significant parameters were proposed to estimate the pore structure variation, which are the differential value of initial imbibition rate and the utmost differential value of normalized imbibed volume. Initial imbibition rate is closely related to pore connectivity, and normalized imbibed volume reflects the pore volume. Reservoirs with a higher value of these two parameters have advantage for developing its resources. Sichuan Longmaxi formation has the highest value in both parameters among all formations, which showed that Sichuan Longmaxi formation has advantage for exploiting its resources by hydraulic fracturing. Baojing Longmaxi formation, Sichuan Niutitang formation, and Cengong Niutitang formation have a lower value in both two parameters which indicated that these formations have less potential to develop its resources by hydraulic fracturing. These two parameters are mainly influenced by wettability and initial permeability, and have no obvious relationship with clay content. Overall, our research is conducive to screening the ideal formation for exploiting shale gas by hydraulic fracturing.

Hydraulic fracturing plays an important role in developing unconventional natural gas. The large amount of fracturing fluid retention becomes a significant phenomenon in gas fields. Much research has been carried out to explain this mechanism. Imbibition is regarded as one of the important factors and has been investigated extensively. However, the saturation evolution of different types of fluids (liquid, free gas, and trapped gas) has been less researched during imbibition. A porosity experiment combined with an imbibition experiment was conducted to research the fluids-saturation evolution. There are three types of experimental rocks: tight sand, volcanic rock, and shale. The free-gas saturation decreases with the increasing liquid saturation in all samples. However, the sum of these two types of saturation is approximately 100% during imbibition in tight sand. This indicates that the pore space is almost totally filled by liquid and free gas. The sum of these two types of saturation is less than 100% during imbibition in volcanic rock. This indicates that there is trapped gas by liquid. Trapped-gas saturation increases at the early period and decreases at the late period. The sum of these two types of saturation greatly exceeds 100% during imbibition and increases with the imbibition time in shale rocks. This means that there is large amount of extra imbibition liquid. At the same time, the free-gas saturation fluctuates with the increasing liquid saturation. Based on the above results, it can be concluded that tight sand reservoirs have nearly no trapped gas and extra imbibition liquid, volcanic reservoirs have trapped gas and a little extra imbibition liquid, and shale reservoirs have some trapped gas and a large amount of extra imbibition liquid. This research contributes to understanding the fluid saturation evolution during hydraulic fracturing in unconventional natural gas reservoirs.

Imbibition is a vital factor leading to the low water recovery rate (WRR) in shale, and it is also the critical mechanism causing formation damage. However, many shale gas wells in Fuling can reach well gas yields under ultra-low WRR, and the corresponding mechanism is currently unclear. In this paper, multiple types of imbibition experiments were conducted on shale samples from typical low WRR but high yield wells in Fuling. Combined with pore structure and nuclear magnetic resonance (NMR) analyses, the forming mechanisms of low WRR and unaffected gas yields in Fuling were detailly analyzed and discussed. The results indicate that highly developed bedding fractures in Fuling play the key roles. Bedding fractures are directionally arranged and are of much wider aperture than randomly distributed microfractures in Fuling. Consequently, the permeability along the bedding direction is two orders of magnitude larger than that in the vertical direction, and the contact area between the fracturing fluid and the reservoir matrix also increased significantly. Both factors increased the imbibition rate and leading more water imbibed into the samples. However, due to the much wider aperture, less tortuosity and more complex fracture surface morphology, water imbibed in bedding fractures are much easier to be drained, and the flow channels for gas are effectively retained. Besides bedding fractures, mineral constituents, formation pressure also plays important roles. Thus, the ultra-low WRR but well gas yield wells in Fuling get its uniqueness, and it may not necessarily occur in other shales even with highly developed bedding fractures. Overall, this work helps understand the mechanism of the ultra-low WRR but high gas yield phenomenon in gas shale, which is significant for the post fracturing flowback optimization.

Unconventional reservoirs, especially shale plays, have abundant micro-nano pores. Large volume water was injected into the reservoir during hydraulic fracturing. Fracturing fluid can displace gas in pore spaces spontaneously, called spontaneous imbibition (SI), which has significant effects on the gas production after hydraulic fracturing. Throat structure in matrix is one of the key factors to influence SI process. In this work, at first, complex pore space is simplified as a spatial self-similar branch-like structure composed of several asymmetric sub-throats. Then, within asymmetric branch structure, the imbibition process is calculated by a newly established mathematical model, and the influence of both pore structure and fluid characteristics, including contract angle, viscosity, surface tension, are discussed. Finally, some lab experiments, especially SI tests, are included on shale and sandstone core plugs to verify our model. Results show that the coherence in wettability between the reservoir and the fracturing fluid is important to enhance the microscopic replacement effect. Pore size also has effect influence on imbibition curve. In addition, both in models and experiments, imbibition index n is useful to describe imbibition properties of rocks. In unconventional rock samples like shale, n is less than 0.4, while high-permeability sandstone, n approach to 0.5. These conclusions are useful to investigate the mechanism of spontaneous imbibition and microscopic displacement in unconventional reservoirs.

This study summarizes gas flow process in unconventional porous rocks, including the transportation in tight or shale reservoirs and the spontaneous imbibition happened in them. Fluids flow is greatly affected by the pore structure together with the pore size distribution of porous media. The MRI and BET measurement show peaks in pore throat radius ranging from 2 to 20 nm, whereas the diameter for methane and helium are 0.38 and 0.26 nm, respectively. Yet for different types of reservoir, distinct mechanisms should be utilized based on the flow regimes. Besides, experimental measurement techniques for conventional reservoirs are no long accurate enough for most of the unconventional reservoirs. New attempts have been implemented to obtain more valuable data for accurate reservoir prediction. By reviewing large numbers of articles, a clear and comprehensive map on the gas flow and recovery in unconventional reservoirs is made. Factors influencing the gas flow and recovery are investigated in detail for mathematical simulation process. Reservoir conditions and the sweep efficiency play an important role during gas production process. Besides, adsorbed gas contributes a lot to the total gas recovery. The overall investigations suggest that many parameters that influence the gas flow in unconventional porous rocks should be taken into consideration during the evaluation. Among them, permeability, adsorbed gas dynamics, stimulated reservoir volume as well as the unstimulated reservoir volume, and imbibition effect are the most important ones. This study provides valuable data and reasonable exploitations for characterizing gas flow and recovery in unconventional porous rocks. Cited as : Lin, D., Wang, J., Yuan, B., et al. Review on gas flow and recovery in unconventional porous rocks. Advances in Geo-Energy Research, 2017, 1(1): 39-53, doi: 10.26804/ager.2017.01.04

Background: Tight sandstone reservoirs play an important role in the oil industry. The permeability of tight sandstone reservoir generally has stronger stress sensitivity than that of conventional reservoir because of the latter’s poor physical properties. However, the production analysis of tight sandstone reservoir did not fully considered the stress-sensitive permeability yet. Objective: This paper proposed a production analysis method considering the stress- sensitive permeability. Method: This paper firtstly investigated the stress sensitivity characteristics and the effect of stress-sensitive permeability on a tight reservoir. Decline-type curves that consider stress-sensitive permeability are then established, and a systematic analysis method was built for the production analysis to obtain the single-well controlled dynamic reserves and reservoir physical properties. Results: A field analysis was performed in combination with Block Yuan-284 of Changqing Oilfield. Results show that with the reduction of reservoir pressure, stress sensitivity leads to the decline in reservoir permeability and the increase in seepage resistance, thus reducing the actual single-well controlled reserve and radius. Conclusion: By utilizing the analysis method based on the decline curves, we can effectively predict the single-well controlled dynamic reserves of such reservoirs and evaluate the characteristic parameters of reservoirs.

Bubble influence makes the measured liquid content in rock become less during continuous imbibition because it attaches to the surface of the tight sand increasing the buoyancy of rock in liquid. The imbibition experiment was performed to research this influence. The experiment has two parts. One is the repeated measurement of imbibition with the same sample to investigate the repeatability of the imbibition experiment under the bubble influence. The other part includes the measurement with bubble influence and without bubble influence of the same sample. The results are listed as follows. The repeated measurement of the same rock imbibition reflects a similar characteristic with the bubble influence. The water content is very close with the corresponding imbibition time. This characteristic presents that tight sand imbibition has the characteristic of repeatability, which was the basis for the other experiment. Some different characteristics appear during the measurement of the liquid content with and without bubble influence in the same sample. The liquid content without bubble influence is apparently larger than the liquid content with bubble influence. The difference between the liquid content in these two conditions is small at the end of imbibition time. It becomes larger in the middle imbibition time. The error can reach 50%. It severely influences the accurate evaluation of the imbibition capacity of tight sand. Our research contributes to the acquaintance of liquid imbibition in the formation during hydraulic fracturing and is also conducive to better measure the liquid content through the laboratory experiment.

A small percentage of the fracturing fluid pumped can be recovered after multi-stage fracturing stimulation in tight reservoirs. One cause for this can be the numerous branch fractures formed at different scales during large volume fracturing. Understanding the retention mechanism and flowback law of fracturing fluid in branch fractures is a key to solving this problem. In this study, we used a leaser macroscope, a low-field nuclear magnetic resonance (NMR) instrument, and a permeability device to scan fracture surface morphology and conduct fracturing fluid retention and permeability regain experiments. Meanwhile, retention mechanisms and the flowback process of fracturing fluid in branch fractures during flowback is considered. The experimental results show that the fracturing fluid present in branch fractures can be divided into free movable water (FMW), restricted movable water (RMW) and retained water (RW). The average proportion of FMW, RMW, and RW in Lucaogou and Longmaxi shale reservoirs in our work are about 0.16: 0.14: 0.7 and 0.1: 0.1: 0.8, respectively. The rougher the surface and the greater the tortuosity of the fracture are, the higher the retention percentage of fracturing fluid in branch fractures is. The main mechanisms of fracturing fluid retention in branch fractures include water film, capillary retention on the fracture surface, and matrix imbibition. The critical T2 of FMW and RMW in branch fractures in the Lucaogou shale reservoir are 25.3 ms and 10.2 ms, respectively. However, they are 64 ms and 3.7 ms in the Longmaxi shale reservoir. During the flowback, FMW and partial RMW gradually flowback to the surface. After this, the permeability regains with the decrease of water retention in branch fractures. This study contributes to understanding fracturing fluid retention mechanism in tight reservoirs and provides guidance for the optimization of fracturing flowback.

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.

We have investigated the features of the shale imbibition process for different drilling fluid parameters, using as an example Chang-7 shale in the Yanchang region of Erdos Basin, as is needed to study the effect of the mechanism for imbibition of drilling fluid filtrate on gas yield and on the lost gas calculation. It has been established that capillary imbibition of drilling fluid filtrate occurs in three stages: the early stage, in which the imbibition rate is high; the middle stage, which is controlled by the shale matrix and has low imbibition rate; and the late stage (diffusion stage), which lasts the longest. Capillary imbibition increases the gas dissipation rate from the rock sample, which results in 10%-20% error in the lost gas calculation. In order to maintain the gas-bearing properties of the formation and to reduce lost gas, we need to optimize the properties of the drilling fluid to reduce the impact of capillary imbibition.

A large volume of fracturing fluid is pumped into a well to stimulate shale formation. The water is imbibed into the reservoir during this procedure. The effect of the imbibed water on gas recovery is still in debate. In this work, we study the spontaneous imbibition of water into marine shale samples from the Sichuan Basin and continental shale samples from Erdos Basin to explore the fluid imbibition characteristics and permeability change during water imbibition. Comparison of imbibition experiments shows that shale has stronger water imbibition and diffusion capacity than relatively higher permeability sandstone. Once the imbibition stops, water in shale has stronger ability to diffuse into deeper matrix, the water content in the main flow path decreases. Experiments in this study show that marine shale has stronger water imbibition capacity than continental shale. The permeability of continental shale decreases significantly with increasing imbibition water volume; however, the permeability of marine shale decreases at first and increases after a certain imbibition time. The induced fracture is obvious in the marine shale. SEM analysis shows that the relationship between the clay mineral and organic matter of continental shale is much more complex than that of marine shale, which may be the key factor restricting the water imbibition because the flow path is trapped by swelled clay minerals. Through this study, we concluded that whether gas recovery benefits from water imbibition depends on three aspects: 1) the diffusion ability of liquid into matrix; 2) the new cracks introduced by imbibed water; and 3) the formation sensibility. This study is useful for optimizing fracture fluids and determining the best flow-back method.

Published studies have suggested that the spontaneous imbibition induced by the high capillary force of tight rocks is a significant mechanism responsible for low flowback efficiency (

Due to the low matrix porosity and permeability of gas shales, the horizontal well drilling and hydraulic fracturing technologies become a necessity to exploit the unconventional shale resources. While a large volume of fracturing fluid is injected into the shale formation to create cracks, some shale reservoirs have a low flowback rate, about which the mechanism is still unclear. In order to clarify the associated fluid retention mechanism, the spontaneous imbibition experiments were conducted, and interpreted with theoretical analyses. Shale imbibition process can be divided into three stages, including initial imbibition, transition and late imbibition stages. Longmaxi Formation shale from Sichuan Basin usually has clay-swelling induced cracks, while Niutitang Formation shale from Guizhou province commonly has no such cracks. Shale samples with induced cracks show both higher initial and late imbibition rates. Induced cracks increase new pathways for liquid entering into samples, which lead to a higher initial imbibition rate. Liquid in induced cracks has a large contact area with matrix and liquid moves quickly from cracks into matrix, which causes a higher late imbibition rate. As a contrast, shale samples without induced cracks have a lower initial imbibition rate and a lower late imbibition rate. In addition, the ultimate normalized imbibed volume is higher than the pore volume in shale samples with induced cracks. Furthermore, models were established to interpret the imbibed water saturation with the density of clay-swelling induced cracks. Theoretical analyses indicate normalized imbibed volume increases with the density of induced cracks, and the imbibed water volume can be higher than pore volume with enough density of induced cracks. As a result, clay-swelling induced cracks could account for the retention of a large volume of fracturing fluid in gas shales, and our research contributes to explaining the mechanism of fracturing liquid retention in shale gas reservoirs.

The microstructure of shale has always been of interest in studies associated with shale gas reservoirs. In addition, the influence of the presence of organic matter on the pore distribution is not well-understood. Although considerable attention has been given to the total organic carbon (TOC) content together with the total porosity, concerns regarding investigating the pores in rocks separately according to the different media where the pores are distributed are still rare. This paper presents a comparative study of the pore size distribution (PSD) in organic matter (OM) and the mineral matrix (MM) within the same sample with the OM-hosted pores and MM-hosted pores accurately distinguished and quantitatively analysed. Four shale samples from a shale play in the Ordos Basin are scanned using nano-CT scanning with a resolution of 65 nm. The calculated total organic carbon (TOC) of the samples are 3.48%, 4.47%, 2.76%, and 3.01% with corresponding porosities of 4.30%, 4.97%, 4.50%, and 4.74%, respectively. The results show that more of the large pores exist in the OM with better connectivity and irregular shapes, while the pores in the MM are smaller on average, have less connectivity, and primarily consist of tiny spheres. The pore-medium-ratio (PMR) was introduced to illustrate the pore volume distribution characteristics within each specific medium. The PMR is a ratio between the volume of pores in a specific medium (i.e., MM or OM in this study) and the volume of that medium. According to the PMR curves, the small pores are distributed homogeneously, while the large pores have a heterogeneous distribution and are medium-dependent. It is concluded that the OM affects the pore distribution in three aspects: 1. the OM has a higher PMR; 2. most large pores occur in the OM; and 3. the small pores in the MM tend to appear around the OM. Insights into the various distributions of the pores have been developed. Pores in either medium exhibit an exponential distribution in number. Three sections of the pore volume distribution and surface area distribution are found. Furthermore, the concept is verified that small pores have a large effect on the surface area, while large pores have a large effect on the pore volume.

For conventional oil and gas reservoirs, the orientation and magnitude of in-situ stress can be estimated by analyzing wellbore failures such as borehole breakouts and drilling induced fractures (DIF) using Zoback's stress polygon model. According to this model, DIFs are most likely induced by the high mud weight, wellbore cooling, high stress difference, or pressure surge. A large number of DIFs have been identified by imaging logging in shallow well sections of shale gas well QY1 in the Sichuan Basin of China. However, all possible explanations of standard DIFs do not work well, suggesting the limitations of this model when applied to shale formations. Other mechanisms influence the formation of DIFs in this shale gas well that are not covered in this model. In this paper, the orientation and magnitude of the in-situ stress in the study area are constrained following the general procedure outlined by Zoback's stress polygon model. The DIF distribution in the QY1 wellbore and its relationship with organic matter are then analyzed. A new mechanism was introduced to explain the DIFs in the organic-rich section. The results show that the maximum horizontal stress (SHmax) in the study area trends N95°E±9°. The calculated in-situ stress magnitudes are consistent with a strike/reverse faulting stress regime (SHmax > Sv ≈ Shmin). In addition, the DIFs are concentrated in the organic-rich interval. For organic-rich shale, strong water imbibition is common, which is related to super-dry gas shale due to the water displacement of kerogen-transformed hydrocarbons, high capillary pressure due to micro-nano meter pore diameters, and the water-sensitive clay mineralogy. This spontaneous water intake generates the effective internal stress around the wellbore, producing DIFs in the shale gas well. The introduction of this new mechanism allows the Zoback's stress polygon model to constrain the in-situ stress in the study area. Therefore, this mechanism should be considered during estimation of the in-situ stress in gas shale formation when using Zoback's stress polygon model.

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.

Field researches conducted on the multi-stage hydraulic fracturing measurements manifest that a large proportion of fracturing fluid retains in tight reservoirs, and the flow-back efficiency is usually lower than 30%. The publications have demonstrated that the spontaneous imbibition plays a significant role in large volumes of water loss, which is caused by high capillary pressure of tight rocks. Nevertheless, the imbibition characteristics of tight rocks are quite complex and still need further research owing to the complex pore structure, mineral constituent and strong microscopic heterogeneity.Comparative imbibition experiments were carried out on 12 core samples, which are seclected from tight sandstone formation from Ordos Basin, tight volcanic formation from Songliao Basin and shale formation from Sichuan Basin. Hence, a new method is proposed to demonstrate the imbibition characteristics and estimate fracturing fluid intake in tight gas formation. Moreover, the authors study the water imbibition capacity and characteristics of tight rocks, which holds diverse mineralogy, pore-size distribution and pore connectivity. The experimental data of tight rock samples in different size and shape can be normalized by using the new characterizing method, which exhibits the imbibition capacity, initial imbibition and late imbibition rate. The imbibed water volume increases with the clay content, and smectite and illite/smectite tends to strong water imbibition. Due to the water absorption on clay surface, the ratio of imbibed water volume to pore volume measured by Helium exceeds 100%. In addition, a general observation shows that each imbibition curve of tight rock can be divided into an initial imbibition region, a non-linear transition region, and a late imbibition region. However, the imbibition characteristics of different tight rocks vary greatly, which could be attributed, at least in part, to the complex pore connectivity, pore-size distribution and mineral composition. Well-developed macropores tend to have well pore connectivity and large time exponent at the initial imbibition region. Well-developed mesopores and micropores tend to have poor pore connectivity and large time exponent at the late imbibition region. These studies can be used to evaluate the fracturing fluid imbibition characteristics, and to understand its relationship with pore connectivity and pore-size distribution in tight reservoir rocks.