Analysis of flowback data, gathered immediately after fracture stimulation, can be performed to understand the fluid flow physics, investigate flow regimes, and obtain early estimates of fracture properties. During a hydraulic fracturing treatment, significant amounts of fracturing fluid will leak-off from the fractures into the reservoir due to Darcy flow, capillary, osmotic and electrostatic forces. Capillary invasion of fluids into the reservoir can cause a loss in gas relative permeability, leading to an altered zone near the fracture-matrix interface, therefore impeding the flow of hydrocarbons into the fracture. Due to this phenomenon and other fluid transport mechanisms, a simple application of Darcy's law might not be adequate for describing the fluid flow physics when solid-liquid interaction is significant. To overcome some of the above limitations, spontaneous imbibition effects are modeled at the fracture/matrix interface during the flowback period in this study. This paper presents a semi-analytical model for analyzing two-phase water and gas flowback data, when spontaneous imbibition occurs. This model was developed by solving the fracture and reservoir matrix flow equations simultaneously. The effects of fracture and reservoir matrix pressure gradients on gas and water influx at the fracture-matrix interface are accounted for in order to evaluate the reservoir matrix hydrocarbon influx. The proposed model accounted for spontaneous imbibition driven by capillary forces by quantifying the fluid influx due to capillary processes and adding it to the mass flow equations. Further, capillary pressure effects were incorporated into the PVT properties of matrix pseudovariables. The average phase pressures in the fracture and matrix were calculated iteratively using a modified material balance approach. The proposed semi-analytical model was successfully verified using fully-numerical simulation data. Practical application of the proposed model was then demonstrated using production data from a multi-fractured horizontal well. • A new method for analyzing flowback data from shale gas wells is developed. • The new model incorporates the effects of spontaneous imbibition. • Ignoring spontaneous imbibition may lead to incorrect flowback data interpretation.

Liquid CO 2 has the synergistic effect of low-temperature damage and displacing CH 4 after injecting into the coal seam, which can effectively improve coalbed permeability and promptly promote the adsorbed CH 4 to desorption state for preventing the coal and gas outburst disasters. The injected CO 2 gets adsorbed at the surface of the coal pores, which causes the coal swelling. In this work, we developed a triaxial experimental platform to explore the features of CO 2 displacing CH 4 under different temperatures. The variation of coal swelling and segmentation features of the displacing concentration was elucidated. The seepage ability and mechanism of gas mitigation in the coal seam during LCO 2 -ECBM were revealed. The results showed that the coal samples displayed swelling deformation in the CH 4 adsorption and CH 4 displacement stages, and the strain curves can be divided into rapid and slow deformation phases. The strain in the CO 2 displacing CH 4 stage is notably larger than that in the CH 4 adsorption stage. Three dominant results were obtained during the CH 4 displacement: Free CH 4 driving by CO 2 injection, CH 4 self-desorption, and CO 2 –CH 4 competitive adsorption. The displacing flow rate increased swiftly in the initial stage, and then decreased to a stable tendency. The cumulative displacement volume of CH 4 in different stages exhibited distinct functional relationships. The integrated contribution of the coal matrix shrinkage and thermal stress damage to gas seepage improvement was more prominent than that of the adsorption swelling to seepage inhibition in the coal seam. • The variation of coal swelling during LCO 2 -ECBM was analyzed. • The segmentation features of the displacing concentration were elucidated. • The seepage ability of the coal seam was determined. • The mechanism of gas mitigation during LCO 2 -ECBM was revealed.

To alleviate the water-blocking effect in the hydraulic fracturing process and promote coal seam gas extraction , the influence of gas wettability alteration on the water-blocking effect and gas desorption was investigated. First, according to the contact angle, infrared spectrum , and surface energy measurement experiments, 3.5% polyacrylamide (PAM) was selected as the gas wettability alteration agent and used to treat the coal samples. After treatment with PAM, the hydroxyl and surface energy of the coal decreased, which altered the gas wettability. Second, the water injection desorption experiment results show that both 4% alkyl polyglucoside (APG) and 3.5% PAM solution can alleviate the water-blocking effect and promote coal gas desorption during water injection. The same experiment was performed by varying the gas pressure. When the gas pressure exceeds 3.25 MPa, APG inhibits gas desorption, indicating that it is unsuitable for alleviating the water-blocking effect. Furthermore, the mechanism by which gas wettability alteration relieves the water-blocking effect was analyzed from macroscopic and microscopic perspectives. Macroscopically, PAM had a high removal rate of the liquid-phase retention effect in coal and can hardly be retained in coal. Microscopically, after gas wettability alteration, the number of hydrophilic functional groups on the surface of coal decreased. The above results in the system changing from hydrophilic to hydrophobic, and correspondingly, the capillary pressure in pores or fractures of coal changes from resistance to a driving force. Therefore, compared with the original coal sample, the water in the coal is more likely to flow back, which alternates the water-blocking effect and promotes gas desorption. This study provided a laboratory prediction method for verifying the effects of gas wettability alteration agents on coal gas extraction. • The mechanism of wettability alteration was analyzed. • Gas wettability alteration on water blocking effect and desorption were studied. • Influence mechanism of gas wettability alteration on gas desorption of coal.

In the past several decades, machine learning has gained increasing interest in the oil and gas industry. This paper presents a comprehensive review of machine learning studies for drilling applications in the following categories: (1) drilling fluids; (2) drilling hydraulics; (3) drilling dynamics; (4) drilling problems; and (5) miscellaneous drilling applications. In each study, the machine learning algorithm(s), sample size, inputs and output(s), and performance are extracted. In addition, similarities of studies in each category are summarized and recommendations are made for future development.

Clathrate or gas hydrates have gained tremendous interest due to their potential applications in various industries and flow assurance problems in the oil and gas sector. In both directions, salinity plays an essential role in controlling the kinetics/thermodynamics of hydrate formation/dissociation. Therefore, it is critical to understand: (i) the exact impact of salts, either as promoters or inhibitors of hydrate formation and their mechanism of action, (ii) exclusion or inclusion of salts from the gas hydrate framework, and (iii) factors determining the effect of salts (e.g., pressure, temperature, type of guest molecules, and hydrate structures). This review gathers the macro and microscopic level literature while incorporating the experimental and molecular dynamic simulations to explain the conflicting views on the effect of salt ions in gas hydrate research. The overall objective of this review is to fill the knowledge gap between experimental and theoretical efforts examining the influence of salt chemistry on hydrate nucleation, growth and dissociation phenomena. • Impact of salinity on gas hydrate-based processes is critically reviewed. • Role of salinity in controlling kinetics/thermodynamics of hydrates is presented. • Effect of salts on hydrate nucleation, growth and dissociation are discussed. • Mechanisms proposed for the action of salts are insightfully reviewed and analyzed.

Natural gas hydrates have attracted many attentions recently as a promising energy, the exploitation of which will cause complicated multifield coupled behavior of hydrate-bearing sediments. As sediments usually vary from tens to hundreds of meters, the gravity effect on gas-liquid migration and soil deformation may not be completely ignored. This paper develops a new thermo-hydro-chemo-mechanical model to investigate the sediment behavior during the hydrate dissociation. The equations of gas-liquid migration are numerical solved with explicit incorporation of hydrate dissociation process. The numerical stability and efficiency have been improved by expanding the Taylor series of the source terms and making the first-order approximation. Furtherly, pre-calculation procedures have been considered to obtain the initial state of field variables. Pilot-scale model results show that the gas-liquid migration, soil deformation and NGH dissociation are accelerated when the gravity effect is present. During the exploitation, a dissociation front can be observed, and gas-liquid migration and hydrate dissociation dominate the process alternatively, leading to first decrease and subsequent increase of gas saturation and continuous rise of liquid saturation. Moreover, it is inferred that marginal enhancement of gas production can be achieved with the increase of wellbore lengths, but it should not exceed 75% of the reservoir thickness. • A new THCM coupled model with high numerical stability and efficiency is developed to investigate the behavior of hydrate-bearing sediments. • Generation of pore fluids dominates at the dissociation front and gas dissipation predominates in the undisturbed region. • The predominance of gas-liquid migration and NGH dissociation will be enhanced by gravity effect, leading to a larger influence region. • Dissipation and generation of pore fluids dominate the process alternatively, and effects of wellbore lengths on gas production is discussed.

Proppant distribution and sedimentary area spacing are crucial factors that influence fracture closure, and they directly impact the efficiency and effective utilisation time of unconventional oil and gas. However, the fracture surface roughness of actual hydraulic fractures and the development of microfractures significantly impact proppant transport. Few proppant transport laws for hydraulic fractures under true-triaxial stresses have been proposed. In this study, the effects of fluid and proppant properties on proppant transport and distribution in horizontal coal hydraulic fractures were investigated using a true-triaxial hydraulic fracturing experimental system subjected to high-pressure sand injection. The results show that high-injection-rate fracturing and low-injection-rate sand injection facilitate proppant transport to fracture tip and increase the distribution area of the proppant in fractures. The high viscosity of sand-carrying fluid improves the carrying capacity of the proppant but also increases the transport resistance. The resistance and the buoyancy of the high-viscosity fluid make the proppant transport complex. The higher the proppant concentration, the larger the proppant settlement at the crack entrance, and the closer the proppant-transport distance. During multiple sand injections, the proppant injected previously is pressed into the coal seam under the closure stress. The stress required to migrate the proppant injected subsequently is higher, and the proppant settlement at the crack inlet is larger. The smaller the proppant particle size, the easier the proppant penetrates the microcracks; this is more conducive to reaching the crack tip and promoting the fracture network development. • Proppant migration law in horizontal fractures under true-triaxial stresses are studied. • Effects of fluid and proppant properties on proppant migration are systematically analyzed. • Distribution area of the proppant is extracted and analyzed using the chromaticity interval. • Too high viscosity will produce proppant clusters and hinder proppant migration. • The higher the proppant concentration, the more the proppant settlement at the fracture inlet.

The gas extraction environment in coal seam exhibits uniaxial strain condition with constant overlying strata stress and horizontal strain. Simulating this environment in laboratory often ignores true triaxial stress state, so the difference in horizontal stresses reduction and the accompanying permeability evolution remain ambiguous. Therefore, this study conducted the true triaxial stress and permeability response tests simulating gas extraction environment under shallow and deep in-situ stress conditions. To quantify gas adsorption effect, the adsorbed (CO 2 ) and non-adsorbed (He) gases were also used. The results indicated that the intermediate and minimum principal stresses, i.e., σ 2 and σ 3 , exhibited a linear decreasing trend during gas depletion, but showed more decreases in stress when the intermediate and minimum principal strains, i.e., ε 2 and ε 3 , recover under high gas pressure depletion. High true triaxial stress enhanced the compressibility of pores and fractures in coal, resulting in low horizontal deformation and stress reduction gradient during gas depletion. Similarly, the reduction gradient of σ 2 , m σ 2, was less than that of σ 3 . This suggested that the difference between horizontal stresses also increased during coalbed methane (CBM) extraction, which exacerbated the risk of coal body damage. For different gas depletion, the stress reduction gradient exhibited m He < 1 and m CO2 > 1, which was related to the relative affinity of different gas species for the adsorption medium. A significant matrix shrinkage effect resulted in a more pronounced stress reduction. For permeability, the permeability increased exponentially during CO 2 depletion, while the permeability of helium exhibited a decreasing followed by an increase with decreasing gas pressure. This is related to the competing mechanism and synergistic effect of the adsorptive gas desorption, effective stress effect, and slippage effect. We quantified the contribution and mechanism of the three to the permeability separately. The permeability anisotropy ratio ( A r ) decreased exponentially during gas depletion. • Simulating true triaxial stress and permeability response during gas production. • σ 2 reduction gradient is less than that of σ 3 . In deep stress is less than shallow. • Stress reduction gradient of He ( m He <1) is much lower than that of CO 2 ( m CO2 >1). • Permeability anisotropy ratio reveals an exponential decrease during gas depletion. • Impact of desorption, effective stress, and slippage effect on k is quantified.

Matrix shrinkage is a factor that must be considered in the dynamic permeability model of coal reservoirs. The mechanism of matrix shrinkage affecting confining pressure (confining pressure mechanism) has been modeled by analogy with thermal expansion, and it is widely used in permeability model construction. However, the mechanism of matrix shrinkage affecting porosity (porosity mechanism) has not been widely recognized and modeled, and this mechanism independently controls porosity even though neither confining pressure nor pore pressure changes (only the replacement of different adsorbed gases occurs). The porosity mechanism and a permeability model that takes into account the dual mechanism have been modeled recently. This study compares the two mechanisms of matrix shrinkage by theoretical analysis of the mathematic relations in the permeability models considering different mechanisms and by finite element numerical simulations of coalbed methane development considering different mechanisms. Theoretical analysis shows that the effect of the porosity mechanism on permeability is more than 1.5 times that of the confining pressure mechanism. the numerical simulations results show that: considering the porosity mechanism and the confining pressure mechanism simultaneously allows for a larger and earlier improvement in permeability and a larger reservoir area to improve, and a significant improvement of 28% in gas production rate occurs compared with the case only the confining pressure mechanism were considered. This study reveals the importance of porosity mechanism in describing the dynamic evolution of reservoir permeability and production dynamics accurately, and provides a scientific basis for coalbed methane development. • The matrix shrinkage includes confining pressure (CP) and porosity (P) mechanism. • The effect of the P mechanism is more than 1.5 times than that of the CP mechanism. • The CP mechanism can only cause a small-area and weak permeability rebound. • The dual mechanism can cause a strong rebound throughout the whole reservoir.