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It is well known that waterflooding will induce fractures. The extensive direction, length, and conductivity of the induced fractures will largely determine the performance of producing wells. The quantitative characterization of the fractures can help prevent water breakthrough in time. This paper proposes the waterflooding-induced dynamic fracture model (WIDF) to monitor the fracture half-length at any time and extend the stable production period. The rock mechanics principles are applied to characterize the dynamic extension and closure of fractures during water injection and build-up periods. The model was solved using the point source function approach. The phenomenon of multi-dynamic closure causes the fluid to be squeezed several times, creating a storage effect and a non-constant conductivity within the fracture. Experimental results show that the conductivity of water injection-induced fracture follows an exponential function. Finally, Duhamel's principle was used to couple the pressure response of the wellbore and the fracture. The field case is shown in the paper to verify the accuracy and practicality of the WIDF model. Multi-peak appears in the pressure derivative curves. The actual data match well, and the parameter values obtained are close to the actual values. However, the conventional finite-conductivity model treats pressure response data with multiple peaks as incorrect values. This behavior will result in the length of dynamic closed fracture being ignored and the interpreted fracture half-length being smaller than the actual value. Misidentification of fracture lengths will affect the determination of reasonable injection volumes and even cause producing water early, which can severely impact the performance of production wells. The storage effect caused by multiple dynamic fracture closures reasonably explains the significant storage effect obtained by the conventional model. The WIDF model enables researchers can monitor induced fracture half-length at any time, allowing them to take measures in time. The model has been successfully applied to the X oilfield in China and has significantly improved the performance of injection wells and increased the stable production period of production wells. The fluid compressed by dynamic fractures reasonably explains the significant storage effect in injection wells. The identification and interpretation of multiple dynamic fracture closure phenomenon make us obtain more accurate fracture half-length parameters, which monitors and suppresses the occurrence of water breakthrough effectively and help researchers take measures to increase the stable production period of production wells.

As potential alternative resources, tight oil and gas reservoirs are generally exploited with multistage hydraulic fracturing technology to meet the rising demand for energy in the world. Considerable production recovered by the infiltration of fracturing fluids into the rock matrix shows that spontaneous imbibition (SI) is an effective oil recovery method. Through the use of Nuclear Magnetic Resonance (NMR) detection technique, the features of SI in oil-water and gas-water systems for tight sandstones were studied. The T2 spectra of these samples were used to reflect the migration patterns of fluids in various pores under different imbibition systems. In addition, the impacts of the boundary conditions on imbibition outcomes were also determined via the variations in T2 spectra under imbibition stages. The results indicate that tight sandstone samples display the feature of complex pore structure with a wide range of pore size distribution, and the dominant types are micropores and small mesopores. With the progression of imbibition experiments, oil in micropores will be more easily displaced by wetting fluid and flow out through interconnected smaller pores due to greater capillary pressure. The majority of the production through imbibition can be attributed to the contribution made by the micropores. However, water could not enter the mesopores readily under the gas-water system if it is only driven by capillary pressure owing to the snap-off effect of gas. The boundary conditions have notable effects on the imbibition rate and ultimate recovery for the oil-water system and increasing the areas available for water imbibition helps to maintain higher imbibition rate and recovery. However, regarding the gas-water system, boundary conditions have little influence on the imbibition recovery but have a remarkable influence on the imbibition rate. The traditional scaling equations used to scale the imbibition data for both the oil-water and gas-water systems and predict imbibition recovery is acceptable if the wettability of the tight medium remains unchanged. This research aims to uncover the imbibition characteristics of fluids and the nontrivial effect of boundary conditions in tight sandstone samples, which would contribute to the successful development of tight formations.

Shale gas is considered very important unconventional hydrocarbon resources. Due to the technological advances of hydraulic fracturing, the development of shale gas has become the main focus in recent years. Porosity and permeability are the most important petrophysical parameters during the production of shale gas. A considerable amount of research work has been carried out on stress law of porosity and permeability. However, nearly none of them considered the effects of methane adsorption. This paper utilizes the simplified local-density (SLD) theory to study adsorption of supercritical gas in shale gas reservoirs. On the basis of the basic features of high pressure supercritical adsorption of shale gas, Peng—Robinson equation is used to describe adsorbed fluid. The interaction between the gas molecules and porewalls of shale is considered using Lennard-Jones potential. Finally, we establish the SLD model to do regression analysis for the adsorption experiments data. The density of adsorbed phase and free phase density could be obtained applying SLD model and then the amount of gas adsorption can be determined. The Gibbs adsorption amount calculated using the SLD model is used to establish matrix strain model. Finally, the strain model is incorporated into widely used analytical porosity and permeability models to develop the coupled model with consideration of the coupled effect of gas adsorption and stress on the porosity and permeability of shale gas reservoirs. And the trend of variation of porosity and permeability of shale rocks taking account of the effects of stress and gas adsorption can be obtained. Lab experiments of gas adsorption of methane gas are made on three shale samples. The developed SLD model is applied to describe gas adsorption data. The outcome indicates that SLD model can properly analyze and fit the experimental data. From the results calculated by the new developed model of porosity and permeability, we can conclude that porosity ratios and permeability ratios of gas shales decrease with the increase of pore pressure, which is contrary to the tendency of changes in porosity and permeability only taking account of the effects of effective stress. This result demonstrates that gas adsorption has very large impact on pore volume, therefore the deformation of matrix induced by the adsorption of methane gas cannot be neglected. The proposed model could further be used for the accurate evaluation of storage capacity of shale gas reservoirs and gas production of wells.

Injection of CO2 into shale plays has been considered as one potential scenario for CO2 sequestration with enhanced CH4 recovery (CS-EGR). In this work, a realistic molecular model of bulk kerogen was constructed by molecular dynamics simulations (MD). Grand canonical Monte Carlo simulations (GCMC) were performed to investigate the replacement of CH4 by CO2 under different reservoir pressures, CO2 mole ratios and kerogen moisture contents. The radial distribution functions (RDF) were computed to discuss the affinity between CH4/CO2 and atoms in the kerogen. Also, the CO2/CH4 adsorption selectivity was computed to evaluate the preferential adsorption of CO2 and CH4. Results show that the CO2/CH4 selectivity increases at the beginning, and then decreases with further increasing pressure, which indicates that low reservoir pressure is beneficial to the efficiency improvement of CS-EGR. The amount of CO2 sequestration and CH4 desorption increases, while the CO2/CH4 selectivity decreases as the CO2 mole ratio increases, indicating the adsorption stability of sequestrated CO2 weakens with increasing CO2 mole ratio. The CO2/CH4 adsorption selectivity decreases initially, and then increases with the kerogen moisture content. Increasing the reservoir moisture content can improve the performance of CS-EGR. The preferential adsorption sites for CH4 are the sulfur-containing groups, while these for CO2 are the nitrogen- and oxygen-containing groups. One adsorption layer is observed for CH4, while two adsorption layers are identified for CO2. This study gains enhanced insights on the replacement exploitation of shale gas by CO2 at molecular scale, and it can provide applicable guidelines for the optimization of CS-EGR in shale gas reservoir.

The matrix of shale gas reservoirs has an extremely low permeability; therefore, fractured vertical wells and multi-stage fractured horizontal wells (MFHWs) are adopted in most cases for exploration purpose. In this context, studying the dynamic pressure in MFHWs in shale gas reservoirs not only provides an important means of obtaining the parameters of shale reservoirs, but also constitutes the basis of evaluating the productivity of shale gas wells. However, existing models for fractured horizontal wells have neglected the heterogeneity of shale gas reservoirs and the seepage mechanism in the nanopores of shale organic matter, and failed to take into account the differences among different occurrence spaces in gas flow characteristics. On that account, in this study, we combined dust gas model (DGM) and generalized Maxwell-Stefan model (GMS) to calculate the apparent permeability considering viscous flow, Knudsen diffusion, surface diffusion and desorption, and introduced these into the macro seepage model to establish a dynamic pressure analysis model considering reservoir heterogeneity and stress sensitivity effect of MFHWs in shale gas reservoirs. Based on the five-linear flow model, this study divides one reservoir into two top reservoir regions, two inner reservoir regions, two outer reservoir regions, and one artificial fracture region. Through analyzing the flow characteristics of different regions, it uses Laplace transformation and regular perturbation methods to solve the model; based on the analytical solution to this model, it plots the dynamic pressure curve and the dynamic productivity curve and carries out flow region division and sensitivity analysis. As indicated by the study results, the model established in this study fits relatively well with actual production data, has a reliable theoretical foundation, and can preferably describe the dynamic changes of pressure in the exploration process of shale gas wells.

To evaluate the exploration potential of tight oil reservoirs in the Upper Triassic Yanchang Formation, a combined research was done to investigate the source rock distribution, diagensis, pore systems, petrophysical parameters. To begin with, the horizontal distribution and vertical thickness of the reservoir were clarified with data from well drilling and regional geological background. After that, X-ray diffraction and scanning electron microscopy experiments were conducted to study the pore types and morphologies. Then the pore size distribution was calculated based on mercury injection capillary pressure data. Finally, porosity and permeability were tested. Also, the causes of the tight sandstone, the controlling factor of petrophysical parameters and the fracability were discussed.The Upper Triassic Yanchang Formation is rich in tight oil reserves and shows good exploration potential. Horizontally, reservoir is accumulated at the centre of the lake deposit with an area of 7.5×103 km2; vertically, reservoir is in Chang 6, Chang 7 and Chang 8 member with total depth 25–80m, among which Chang 7 member acts as the main source rock. Sediments are mainly fine grained sand, cements including clays, calcite and dolomite. After early stage mechanical compaction and late stage cementation, the reservoir becomes quite tight. Pores are classified into four types, residual interparticle pores, intraparticle grain pores, clay dominated pores, and micro fractures. Residual interparticle pores and clay dominate pores are main pore types for storage and flow; existence of micro fracture can improve permeability and is a good indication of fracturing potential. Porosity is between 6.12–13.80% and air permeability normally smaller than 0.3 mD, the early stage compaction is the main reason of porosity reduction, while combination of compaction and cementation results in dramatic decreasing in permeability. This reservoir can be commercially developed with horizontal well and hydraulic fracturing stimulation.This study provides a workflow to fully characterize the storage and transport properties of a tight oil reservoir, and the workflow can act as reference to other similar reservoirs.

Shale gas, as an unconventional resource, has become an exploration and exploitation hotpoint in China. In this paper, a series of experiments were conducted to investigate petrophysical and mechanical properties on the gas shales in Longmaxi Formation south Sichuan Basin, China. Mineralogical and organic geochemical analysis results indicate shale matrix shows strong heterogeneity and structure complexity. A positive correlation between TOC and quartz indicates that bioclastics are the main source of both siliciclastic and organic matters in anaerobic environment. Pore structure was investigated by mercury injection and nitrogen adsorption measurements. The dominant pore size distributes below 3.7nm measured by mercury injection, while 3-5nm by nitrogen adsorption. Micronsized fractures and nanopore structure of shale samples had been identified through mercury saturation curves and adsorption-desorption isotherms. The average maximum mercury saturation is less than 50% at 414MPa, and all of the nanopores were slit-shaped (Type H3 adsorption-desorption isotherms). The BET specific surface area which was calculated from nitrogen adsorption ranges between 7-19 m2/g and have an obvious positive relationship with TOC (total organic matter content) and illite-montmorillonite mixed layer content. Pulse decay measurement reveals that an exponential function can describe the permeability deterioration upon applied effective stress. The stress-dependent permeability of shale is more sensitive than sandstone because of high pore compressibility (low aspect ratio of pore and elastic moduli). The stress-dependent permeability data of samples with micronsized fractures can also be excellently fitted by Walsh model (fractured porous media permeability model), and fitting results show that the fractures in shale samples have high roughness and small aperture compared with sandstone. Static Young's modulus of shale samples increase with increasing quartz, and decrease with increasing TOC and clay minerals content. Due to the weak mechanical property of montmorillonite, shale samples show viscoelastic behaviour and relatively weak mechanical parameters (low Young's modulus, cohesive strengths and friction coefficients, high possion's ratio) under triaxial compression conditions. With the increasing of confining pressure, shales gradually transform from brittleness to ductileness. A comparison of static mechanical parameters between our samples and North America indicates that black siliceous shales of Longmaxi formation have moderate Young's modulus and Poisson's ratio.

Horizontal wells with multiple fractures are becoming more prevalent in tight gas reservoir. However, it is uneasy to obtain the applicable deliverability formula of multiple-fractured horizontal wells using analytical method in consideration of multiple factors, such as the non-Darcy effect, interference between fractures, the coupling effect with reservoir, and formation heterogeneity. This project investigates the deliverability formula of multiple hydraulically fractured horizontal wells in tight gas reservoir using a special numerical method with a focus on the existence of non-Darcy effect and formation heterogeneity. Numerical model expected from daily production data, including wellhead pressure history and production history, is obtained using the numerical well test method, which has an advantage in considering reservoir heterogeneity and complex boundary. The effect of non-Darcy in gas well is discussed using rate dependent skin when constructing the numerical model. The parameters of the numerical model on multiple fractured horizontal well are validated compared with analysis of real pressure build-up well test data. Productivity well test is then simulated based on the previous numerical model, and binomial deliverability equation is obtained from simulated productivity well test curve. The error of absolutely flow rate which derives from the simulation results and modified isochronal test from the field is less than 6%. This paper provides a fast and reliable numerical tool to multifractured horizontal well performance prediction in tight gas reservoir, especially considering non-Darcy effect and reservoir heterogeneous.