Flowback Water Research Articles

Economic assessment and review of waterless fracturing technologies in shale resource development: A case study

Our database tracking of USA water usage per well indicates that traditionally shale operators have been using, on average 3 to 6 million gallons of water; even up to 8 million for the entire life cycle of the well based on its suitability for re-fracturing to stimulate their long and lateral horizontal wells. According to our data, sourcing, storage, transportation, treatment, and disposal of this large volume of water could account for up to 10% of overall drilling and completion costs. With increasingly stringent regulations governing the use of fresh water and growing challenges associated with storage and use of produced and flowback water in hydraulic fracturing, finding alternative sources of fracturing fluid is already a hot debate among both the scientific community and industry experts. On the other hand, waterless fracturing technology providers claim their technology can solve the concerns of water availability for shale development. This study reviews high-level technical issues and opportunities in this challenging and growing market and evaluates key economic drivers behind water management practices such as waterless fracturing technologies, based on a given shale gas play in the United States and experience gained in Canada. Water costs are analyzed under a variety of scenarios with and without the use of (fresh) water. The results are complemented by surveys from several oil and gas operators. Our economic analysis shows that fresh water usage offers the greatest economic return. In regions where water sourcing is a challenge, however, the short-term economic advantage of using non-fresh water-based fracturing outweighs the capital costs required by waterless fracturing methods. Until waterless methods are cost competitive, recycled water usage with low treatment offers a similar net present value (NPV) to that of sourcing freshwater via truck, for instance.

Effectiveness and time variation of induced fracture volume: Lessons from water flowback analysis

Characterizing the induced fracture network is crucial for evaluating and optimizing fracturing operations and for forecasting hydrocarbon production. In our previous paper [1], we developed a closed-tank material balance model to estimate effective fracture volume using rates and pressure data measured during early-time water flowback. In this paper, we extend this model to an open-tank model to estimate fracture-matrix interface area using rates and pressure data measured during late-time water flowback. We verify the proposed model against a 2D numerical model solved by a commercial software, and demonstrate the application of the proposed model to an eight-well pad completed in the gas shales of the Horn River Basin. Finally, we conduct a comparative analysis to investigate the time variation of effective fracture volume during water flowback. The results show that up to 30% of the effective fracture volume is lost due to pressure depletion and fracture closure during early-time water flowback. The rate of fracture volume reduction decreases during late-time flowback when gas from the matrix kicks into the fracture network and provides sufficient pressure support. However, the estimated fracture-matrix interface area is relatively low and cannot be explained by the estimated fracture volume. This result suggests that although a large fracture network is created by hydraulic fracturing operations, only a small fraction of the fracture network receives gas influx from the matrix. Overall, the results suggest that a large fraction of the fractures induced in gas shales does not contribute to hydrocarbon production due to fracture closure, permeability jail effect, and water blockage.

Boron removal from hydraulic fracturing wastewater by aluminum and iron coagulation: Mechanisms and limitations

One promising water management strategy during hydraulic fracturing is treatment and reuse of flowback/produced water. In particular, the saline flowback water contains many of the chemicals employed for fracking, which need to be removed before possible reuse as “frac water.” This manuscript targets turbidity along with one of the additives; borate-based cross-linkers used to adjust the rheological characteristics of the frac-fluid. Alum and ferric chloride were evaluated as coagulants for clarification and boron removal from saline flowback water obtained from a well in the Eagle Ford shale. Extremely high dosages (> 9000 mg/L or 333 mM Al and 160 mM Fe) corresponding to Al/B and Fe/B mass ratios of ∼70 and molar ratios of ∼28 and 13 respectively were necessary to remove ∼80% boron. Hence, coagulation does not appear to be feasible for boron removal from high-strength waste streams. X-ray photoelectron spectroscopy revealed BO bonding on surfaces of freshly precipitated Al(OH)3(am) and Fe(OH)3(am) suggesting boron uptake was predominantly via ligand exchange. Attenuated total reflection-Fourier transform infrared spectroscopy provided direct evidence of inner-sphere boron complexation with surface hydroxyl groups on both amorphous aluminum and iron hydroxides. Only trigonal boron was detected on aluminum flocs since possible presence of tetrahedral boron was masked by severe AlO interferences. Both trigonal and tetrahedral conformation of boron complexes were identified on Fe(OH)3 surfaces.

An analysis of chemicals and other constituents found in produced water from hydraulically fractured wells in California and the challenges for wastewater management

As high-volume hydraulic fracturing (HF) has grown substantially in the United States over the past decade, so has the volume of produced water (PW), i.e., briny water brought to the surface as a byproduct of oil and gas production. According to a recent study (Groundwater Protection Council, 2015), more than 21 billion barrels of PW were generated in 2012. In addition to being high in TDS, PW may contain hydrocarbons, PAH, alkylphenols, naturally occurring radioactive material (NORM), metals, and other organic and inorganic substances. PW from hydraulically fractured wells includes flowback water, i.e., injection fluids containing chemicals and additives used in the fracturing process such as friction reducers, scale inhibitors, and biocides – many of which are known to cause serious health effects. It is hence important to gain a better understanding of the chemical composition of PW and how it is managed. This case study of PW from hydraulically fractured wells in California provides a first aggregate chemical analysis since data collection began in accordance with California's 2013 oil and gas well stimulation law (SB4, Pavley). The results of analyzing one-time wastewater analyses of 630 wells hydraulically stimulated between April 1, 2014 and June 30, 2015 show that 95% of wells contained measurable and in some cases elevated concentrations of BTEX and PAH compounds. PW from nearly 500 wells contained lead, uranium, and/or other metals. The majority of hazardous chemicals known to be used in HF operations, including formaldehyde and acetone, are not reported in the published reports. The prevalent methods for dealing with PW in California – underground injection and open evaporation ponds – are inadequate for this waste stream due to risks from induced seismicity, well integrity failure, well upsets, accidents and spills. Beneficial reuse of PW, such as for crop irrigation, is as of yet insufficiently safety tested for consumers and agricultural workers as well as plant health. Technological advances in onsite direct PW reuse and recycling look promising but need to control energy requirements, productivity and costs. The case study concludes that (i) reporting of PW chemical composition should be expanded in frequency and cover a wider range of chemicals used in hydraulic fracturing fluids, and (ii) PW management practices should be oriented towards safer and more sustainable options such as reuse and recycling, but with adequate controls in place to ensure their safety and reliability.

Characterizing the variability in chemical composition of flowback water – results from laboratory studies

The large volumes and unknown composition of flowback and produced waters cause public concerns about the environmental and social compatibility of hydraulic fracturing and the exploitation of unconventional gas. Flowback and produced waters contain not only residues of fracking additives but also chemical species that are dissolved from the shales. Interactions of different shales with an artificial fracturing fluid were studied in lab experiments under ambient and elevated temperature and pressure conditions. Fluid-rock interactions change the chemical composition of the fracturing fluid and this indicates that geochemistry of the fractured shale needs to be considered to understand flowback water composition.

Evaluation of wettability alteration and IFT reduction on mitigating water blocking for low-permeability oil-wet rocks after hydraulic fracturing

A significant amount of water is lost into shale reservoirs after hydraulic fracturing, and this can cause the permeability reduction that hinders hydrocarbon production. A coreflood workflow was designed in this work to explore the mechanisms behind the formation and mitigation of water blocking in rock matrix. Since shale is typically considered as mixed-wet, one core sample was altered from natively water-wet into oil-wet and tested through an identical experimental procedure; this provided a direct comparison of water blocking in water-wet and oil-wet states. Recently, surfactants have been widely proposed to enhance the oil production from shales, through either wettability alteration or interfacial tension (i.e., IFT) reduction. A microemulsion-forming surfactant was then tested in the core sample at the oil-wet state, also through the identical experimental procedure; this provided another direct comparison on rock permeability enhancement from either one of these two techniques on the same porous media.Our results showed the increase of rock permeability to hydrocarbon is a naturally-triggered process under the water-wet condition, where higher pressure-drawdown delays the increase; however, it is a pressure-drawdown-driven process under the oil-wet condition, where higher pressure-drawdown promotes the permeability increase. Moreover, when oil-wet rock is altered into water-wet, the late-time rock permeability is enhanced but the amount of flowback water is significantly reduced. However, permeability reduction due to matrix-fracture interaction may take place at the early time, the degree of which depends on the level of IFT reduction. For low-permeability rocks that the steady state requires long time to achieve, it might be a better option to use surfactants that give ultralow IFT reductions.

Application of a lyotropic liquid crystal nanofiltration membrane for hydraulic fracturing flowback water: Selectivity and implications for treatment

A thin-film composite, bicontinuous cubic lyotropic liquid crystal polymer (TFC QI) membrane with uniform-size, ionic nanopores was studied for the treatment of hydraulic fracturing flowback water. The TFC QI membrane performance was compared to those of a commercial nanofiltration (NF) membrane (NF270) and a commercial reverse osmosis (RO) membrane (SW30HR) for the filtration of flowback water from the Denver-Julesburg Basin. The permeability, salt rejection, and organic solute rejection for each membrane was evaluated. The results illustrate that the TFC QI membrane maintained its performance to a similar degree as the commercial NF and RO membranes while demonstrating a unique selectivity not observed in the commercial membranes. Specifically, the TFC QI membrane rejected 75% of the salt while recovering 9.6% of the dissolved organic carbon (DOC) and 50% of the water. Of particular interest was the recovery of labile DOC, which was assessed through biodegradation experiments. Analysis following biodegradation of the TFC QI membrane permeate demonstrates the membrane's ability to recover labile DOC in a reduced-saline permeate. Improved recovery of labile DOC (increased to 22%) was demonstrated by reducing the pH of the flowback water. Therefore, the selectivity of the TFC QI membrane provides an opportunity to recover resources from hydraulic fracturing flowback.

Development of shale reservoirs: Knowledge gained from developments in North America

The international daily increase in energy demands requires exploration of new and unconventional energy resources. Unconventional oil and gas have received special attention in recent years as an important source of fossil fuel. This is true especially in North America; United States and Canada, and in other regions in the world including the Middle East.The technological advancements have made the production from unconventional resources possible and more economical. The learning curve and a substantial experience are being developed in North America, where most of the shale developments took place. This paper presents an effort to summarize the current experience on shales of North America from different aspects: rock mechanics, rock/fluids interaction, gas flow mechanisms through shale rocks, proppant embedment and water recovery after shale fracturing.Shale rocks are composed of rock matrix, kerogen, and natural fractures. The mineralogy of shale rocks changes from one field to another. This change in mineralogy will impact the mechanical properties of the shale reservoirs. For example, Haynesville shale becomes more ductile with the increase in its clay content. Similar trends were seen for Lower Bakken shale, while other shale reservoirs, like Eagle Ford, Barnett and Middle Bakken contain more quartz and calcite, which make the rocks harder and easier to fracture. The rock mechanical properties of shale rocks can change as a direct result of the exposure of these clay-sensitive rocks to fracturing fluids. This has been confirmed in literature where Middle Bakken shale lost 52% of its Young's modulus after exposure to slickwater at 300 °F for 48 h.Porosity in unconventional reservoirs can be found in both organic and inorganic parts of the rock. The porosity of the organic matter, and hence the amount of gas stored in kerogen, cannot be neglected and should be considered in the calculation of the gas originally in place. Porosity in organic matter depends on several parameters; among the most important ones is the maturity of the shale itself. Flow of gas in shale rocks is governed mainly by the non-Darcy effects. In addition, gas can be stored and produced from different sources including natural fractures, organic matter and inorganic matrix. Porosity and permeability in organic matter cannot be neglected and it is very important when it comes to storage and flow in shale reservoirs.As a direct result of using different fluid systems in hydraulic fracturing of shale reservoir, an impact on the rock mechanical properties of the rocks were noticed and recorded. This impact can be significant based on several parameters like the temperature, time to exposure and the mineralogy of the shale rock itself. The rock properties can change in a way the rock becomes more ductile and that can increase the proppant embedment in the rock and the overall fracture conductivity to decrease.Among the different fracturing fluid systems used in the field, the use of slickwater in hydraulic fracturing represents a major challenge as a huge volume of water is used in such treatment. In Marcellus shale formation, hydraulic fracturing of one well may require an average volume of 3–8 million gallons of water. Recycling of produced water has been attempted in North America in Marcellus shale play, where re-use of the flowback water resulted in 25% reduction in the fresh water volumes and it reduced the cost of disposing produced water by 45%–55%. A comprehensive understanding and analysis on unconventional reservoirs is required for the Middle Eastern reservoirs. The paper presents a summary of all of these findings from North America.

Process optimization for zero-liquid discharge desalination of shale gas flowback water under uncertainty

Sustainable and efficient desalination is required to treat the large amounts of high-salinity flowback water from shale gas extraction. Nevertheless, uncertainty associated with well data (including water flowrates and salinities) strongly hampers the process design task. In this work, we introduce a new optimization model for the synthesis of zero-liquid discharge (ZLD) desalination systems under uncertainty. The desalination system is based on multiple-effect evaporation with mechanical vapor recompression (MEE-MVR). Our main objective is energy efficiency intensification through brine discharge reduction, while accounting for distinct water feeding scenarios. For this purpose, we consider the outflow brine salinity near to salt saturation condition as a design constraint to achieve ZLD operation. In this innovative approach, uncertain parameters are mathematically modelled as a set of correlated scenarios with known probability of occurrence. The scenarios set is described by a multivariate normal distribution generated via a sampling technique with symmetric correlation matrix. The stochastic multiscenario non-linear programming (NLP) model is implemented in GAMS, and optimized by the minimization of the expected total annualized cost. An illustrative case study is carried out to evaluate the capabilities of the proposed new approach. Cumulative probability curves are constructed to assess the financial risk related to uncertain space for different standard deviations of expected mean values. Sensitivity analysis is performed to appraise optimal system performance for distinct brine salinity conditions. This methodology represents a useful tool to support decision-makers towards the selection of more robust and reliable ZLD desalination systems for the treatment of shale gas flowback water.

Water Blocks in Tight Formations: The Role of Matrix/Fracture Interaction in Hydrocarbon-Permeability Reduction and Its Implications in the Use of Enhanced Oil Recovery Techniques

Summary Hydraulic fracturing is used to obtain economical rates from tight and unconventional formations by increasing the surface area of the reservoir within the flowing distance to a high-conductivity pathway. However, a significant fraction of the fracturing fluid is never recovered, and thus may reduce the hydrocarbon permeability near the fracture. Here, we experimentally mimic the water-invasion process during fracturing, and measure the effective permeability changes in a low-permeability core. Measurements of water flowback and effective permeability as a function of interfacial tension (IFT), flow rate, and shut-in time suggest that water is being held at the fracture face because of the capillary discontinuity (i.e., when the water leaves the matrix and enters a space with minimal capillary pressure). This effect arises from the capillary interaction between the matrix and the fracture, and is akin to the capillary end effect in coreflood experiments. The results show that this effect, although only a laboratory experimental artifact for conventional reservoirs, can be a significant source of effective hydrocarbon-permeability reduction by fracturing-fluid invasion into the formation in unconventional and tight reservoirs.

Biologically active filtration for fracturing flowback and produced water treatment

Reclamation of fracturing flowback and produced water associated with unconventional oil and gas resource development is becoming a more widely applied management practice because it protects freshwater resources through elimination of surface discharge and by reducing demand for high quality water sources. Reduction of organic matter has been a notable wastewater treatment challenge and has limited practical opportunities for reuse of these waste streams. This research focuses on harnessing the ability of microorganisms to biodegrade organic carbon present at high concentrations in flowback and produced water. Bench-scale and lab-scale biofiltration systems were investigated to determine adaptability of biofilms and measure biodegradation of organic carbon under different operating conditions. Microorganisms associated with biologically active carbon filters were initially acclimated to a produced water stream from the Piceance Basin. Following successful acclimation, the bench-scale system consistently achieved more than 90% dissolved organic carbon removal (Co∼240mg/L). Similar performance was observed for the lab-scale system, demonstrating system scalability. After treating distinct wastewater feeds (produced water [Co∼350mg/L] and flowback water [Co∼2150mg/L] from the Denver-Julesburg Basin), the system further demonstrated robustness and flexibility. Results from the performance evaluation validated the ability of the system to maintain treatment efficiency under variable operating conditions, including different pretreatment, aeration rates, temperatures, and empty-bed contact times.

Removal of calcium and magnesium ions from shale gas flowback water by chemically activated zeolite.

Shale gas has become a new sweet spot of global oil and gas exploration, and the large amount of flowback water produced during shale gas extraction is attracting increased attention. Internal recycling of flowback water for future hydraulic fracturing is currently the most effective, and it is necessary to decrease the content of divalent cations for eliminating scaling and maintaining effectiveness of friction reducer. Zeolite has been widely used as a sorbent to remove cations from wastewater. This work was carried out to investigate the effects of zeolite type, zeolite form, activation chemical, activation condition, and sorption condition on removal of Ca2+ and Mg2+ from shale gas flowback water. Results showed that low removal of Ca2+ and Mg2+ was found for raw zeolite 4A and zeolite 13X, and the efficiency of the mixture of both zeolites was slightly higher. Compared with the raw zeolites, the zeolites after activation using NaOH and NaCl greatly improved the sorption performance, and there was no significant difference between dynamic activation and static activation. Dynamic sorption outperformed static sorption, the difference exceeding 40% and 7-70% for removal of Ca2+ and Mg2+, respectively. Moreover, powdered zeolites outperformed granulated zeolites in divalent cation removal.

Organic Pollutants in Shale Gas Flowback and Produced Waters: Identification, Potential Ecological Impact, and Implications for Treatment Strategies.

Organic contaminants in shale gas flowback and produced water (FPW) are traditionally expressed as total organic carbon (TOC) or chemical oxygen demand (COD), though these parameters do not provide information on the toxicity and environmental fate of individual components. This review addresses identification of individual organic contaminants in FPW, and stresses the gaps in the knowledge on FPW composition that exist so far. Furthermore, the risk quotient approach was applied to predict the toxicity of the quantified organic compounds for fresh water organisms in recipient surface waters. This resulted in an identification of a number of FPW related organic compounds that are potentially harmful namely those compounds originating from shale formations (e.g., polycyclic aromatic hydrocarbons, phthalates), fracturing fluids (e.g., quaternary ammonium biocides, 2-butoxyethanol) and downhole transformations of organic compounds (e.g., carbon disulfide, halogenated organic compounds). Removal of these compounds by FPW treatment processes is reviewed and potential and efficient abatement strategies are defined.

Optimal Pretreatment System of Flowback Water from Shale Gas Production

Shale gas has emerged as a potential resource to transform the global energy market. Nevertheless, gas extraction from tight shale formations is only possible after horizontal drilling and hydraulic fracturing, which generally demand large amounts of water. Part of the ejected fracturing fluid returns to the surface as flowback water, containing a variety of pollutants. For this reason, water reuse and water recycling technologies have received further interest for enhancing overall shale gas process efficiency and sustainability. Water pretreatment systems (WPSs) can play an important role for achieving this goal. This paper introduces a new optimization model for WPS simultaneous synthesis, especially developed for flowback water from shale gas production. A multistage superstructure is proposed for the optimal WPS design, including several water pretreatment alternatives. The mathematical model is formulated via generalized disjunctive programming (GDP) and solved by re-formulation as a mixed-integer n...

A multiscale-multiphase simulation model for the evaluation of shale gas recovery coupled the effect of water flowback

After fracturing operation, hydraulic fractures and induced fractures are created within the shale reservoir. A lot of treatment water is stored in fractures network and flow back into the surface during the gas recovery process. The gas production performance is affected by the water flowback because two phase flow occurs within fractures zone. For the created reservoir scale, we propose a multiscale- multiphase simulation model, which defines the whole domain as three sections. Section A contains the organic and inorganic matrix, which stores both the free gas and adsorbed gas. Flow processes are defined in the components of inorganic minerals and kerogens, respectively. For the section B and C, gas phase and water phase are existed together. Under this framework, a set of partial differential equations are derived to define various liquid transport processes: (1) gas flow in the kerogen system of matrix; (2) gas flow in the inorganic system of matrix; (3) gas-water two phase flow in fractures zone and (4) gas-water two phase flow in the hydraulic fracture system. Dynamic permeability models and mass exchanges between them are coupled for all systems. The model was verified against field production data from the Barnett Shale. Model simulation results show that flowback of treatment water can significantly affect the gas production rate at the early stage. Firstly, the increase of maximum water relative permeability can raise the water flowback rate and gas production rate but increasing non-wetting phase entry pressure will decrease the fluids flow rate. Secondly, the impact of fractures zone width on gas production performance is unstable and increasing initial water saturation can increase the water flowback rate but decrease gas production rate. Overall, the dynamic performances of water phase within fractures zone have significant impact on the short and long time shale gas recovery.

A selection methodology of flowback treatment technologies and water reuse in hydraulic fracturing in source rocks – a strategy to reduce the environmental impacts in Colombia

A selection methodology of flowback treatment technologies and water reuse in hydraulic fracturing in source rocks – a strategy to reduce the environmental impacts in Colombia

Impact of chemical osmosis on water leakoff and flowback behavior from hydraulically fractured gas shale

In this paper, the development of a comprehensive multi-mechanistic multi-porosity water/gas/salt flow model to investigate the leakoff and flowback behavior of the fracturing fluid from hydraulically fractured shale gas wells is presented. The multi-mechanistic model takes into account water transport induced by hydraulic pressure driven convection, osmosis pressure driven convection and capillary imbibition, gas transport induced by both hydraulic pressure driven convection and desorption, and salt transport induced by advection and concentration driven diffusion. In the multi-porosity model, hydraulic fractures are considered as a interconnected continuum embedded in shale matrix, where organic shale is interspersed within vast inorganic shale. The organic matrix is thus considered disconnected in the entire reservoir. The water saturation profiles for chemical osmosis-induced, capillary pressure-induced and hydraulic pressure-induced cases are compared, revealing a region of saturation that effectively is immobile even though irreducible saturation has not been reached. In sensitivity analyses, cases with different hydraulic pressure, injected fluid salinity and salt diffusion coefficient are considered.The results indicate that chemical osmosis intensifies water leakoff and hinders water flowback. Further, chemical osmosis is a key mechanism for water retention after the treatment of hydraulic fracturing and should not be ignored especially in flowback data analysis of hydraulically fractured shale gas wells.

The Geochemistry of Hydraulic Fracturing Fluids

The inorganic geochemistry of hydraulic fracturing fluids is reviewed with new insights on the role of entrapped formation waters in unconventional shale gas and tight sand formations on the quality of flowback and produced waters that are extracted with hydrocarbons. The rapid increase of the salinity of flowback fluids during production, combined with geochemical and isotopic changes, indicate mixing of the highly saline formation water with the injected water. The salinity increase suggests that the volume of the injected water that is returned to the surface with the flowback water is much smaller than previous estimates, and thus the majority of the injected water is retained within the shale formations. The high salinity of the flowback and produced water is associated with high concentrations of halides, ammonium, metals, metalloids, and radium nuclides that pose environmental and human health risks upon the release of the hydraulic fracturing fluids to the environment.

Modelling aqueous solubility of sodium chloride in clays at thermodynamic conditions of hydraulic fracturing by molecular simulations.

To address the high salinity of flow-back water during hydraulic fracturing, we have studied the equilibrium partitioning of NaCl and water between the bulk phase and clay pores. In shale rocks, such a partitioning can occur between fractures with a bulk-like phase and clay pores. We use an advanced Grand Canonical Monte Carlo (GCMC) technique based on fractional exchanges of dissolved ions and water molecules. We consider a typical shale gas reservoir condition of a temperature of 365 K and pressure of 275 bar, and we represent clay pores by pyrophyllite and Na-montmorillonite slits of a width ranging from about 7 to 28 Å, covering clay pores from dry clay to clay pores with a bulk-like layer in the middle of the pore. We employ the Joung-Cheatham model for ions, SPC/E model for water and CLAYFF for the clay pores. We first determine the chemical potentials for NaCl and water in the bulk phase using Osmotic Ensemble Monte Carlo simulations. The chemical potentials are then used in GCMC to simulate the adsorption of ions and water molecules in the clay pores, and in turn to predict the salt solubility in confined solutions. Besides the thermodynamic properties, we evaluate the structure and in-plane diffusion of the adsorbed fluids, and ion conductivities.

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

Field observations demonstrate that shale gas wells feature a low flowback efficiency (<30%) and high-salinity 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.