Journal of Natural Gas Science and Engineering最新文献

The dispersion and attenuation of seismic-wave propagation induced by ‘squirt flow’ effects in hydrocarbon-saturated reservoirs are significantly affected by their rock properties and fluid content. In this study, we analyse the frequency-dependent velocity, attenuation, and seismic responses when fractured porous rock is saturated with two immiscible fluids. First, when considering reservoir wettability, we calculate the effective fluid viscosity using a stable parameter, the capillary pressure, and a lattice Boltzmann model (LBM)-based relative permeability equation, which is a function of the saturation and viscosity ratio of the immiscible two-phase fluid. Then, we explore the frequency-dependent effects of fractured porous rocks saturated with two immiscible fluids under different cases of viscosity ratios and capillary pressure parameters by employing the Chapman model from the dynamic equivalent-medium theory. Then, we use a four-layer model to analyse the frequency-dependent seismic responses. The results show that the characteristics of frequency-dependent velocity and attenuation are both affected by the wettability, capillary pressure parameter, saturation, and viscosity ratio. The frequency-dependent features are greatly influenced by the capillary pressure parameter and viscosity ratio. For a larger viscosity ratio and lower capillary parameter, a dispersive effect can occur in the seismic frequency band. This indicates that the velocity dispersion anomalies are sensitive to wettability, capillary pressure parameter and viscosity ratio and should not be neglected. Synthetic seismic records demonstrate that the seismic reflection signatures, such as the waveform, amplitude, and reflective travel time, at the interfaces for saturated reservoirs are significantly affected by wettability and saturation. The numerical modeling helps to improve the wave propagation in rocks saturated by two immiscible fluids.

A spiral multilateral well network is a promising production method to enhance long-term gas recovery from prevalent fine-grained hydrate reservoirs. However, practical application is greatly restricted before the optimal well network parameters are determined and the mechanism behind a unique phenomenon in multilateral wells, namely inter-branch interference, is clear. In this study, we numerically optimized the well configuration and spacing when spiral multilateral wells were deployed in two typical fine-grained hydrate reservoirs, i.e., ultra-low permeability hydrate reservoirs (ULPHR, <1 mD) and low-permeability hydrate reservoirs (LPHR, >1 mD). The mechanism behind inter-branch interference was innovatively revealed. The results indicated that the number of spiral branches should be increased, and equidistant branches should be deployed uniformly in the lower ULPHR or throughout LPHR to enhance production efficiency. A wide spacing of spiral multilateral wells with long branches contributed to long-term productivity in fine-grained hydrate reservoirs with any permeability; however, narrow spacing was more favorable for short branches or short-term production. Our study found three inter-branch interference stages during gas production, namely, “no effect” stage, “positive” stage, and “negative” stage; all the three stages are controlled by reservoir permeability, production distance, and production time. Owing to the “positive” interference effect, longer equal-length branches resulted in superior long-term production enhancement in ULPHR, particularly for lengths greater than 30 m. Gas production from LPHR using only two optimal spiral multilateral wells exhibited high production performance similar to that of the sandy hydrate deposits in Japan, suggesting that the optimal spiral multilateral well network is promisingly suitable for commercial production in the future.

In this study, the non-intrusive EDFM (embedded discrete fracture model) method was presented to investigate the impact of different choke management strategies on well performance. Through the EDFM method, accurate simulation can be conducted to efficiently evaluate the fracture complexities. First, by implementing this powerful technology, a horizontal well with multi-stage hydraulic and natural fractures was set up, where the permeability can be distributed sequentially in each hydraulic fracture segment. Then various pressure drawdown scenarios from conservative to aggressive strategy were designed. The different levels of fracture closure can be properly modeled in each state. Additionally, pressure distribution for the matrix and fractures was depicted to provide straightforward insights for the choke management under two extreme strategies. Subsequently, a series of sensitivity studies were presented to evaluate the impacts of various factors on shale gas production, including fracture permeability modulus, fracture closure, and natural fractures network. The simulation results show that choke management can be simulated effectively by applying EDFM. After considering the fracture closure behavior and complex fracture networks, the conservative drawdown strategy can be addressed as the optimal strategy for the EUR, as it improves the cumulative gas production by maintaining the hydraulic fracture open through a steady pressure decline. The remained proppants enhance the fracture conductivity, thereby expanding its drainage influence towards larger zones of the reservoir. The influence of natural fractures, including the fracture length, fracture number, and fracture conductivity, are also studied. All these three variables play a significant impact on well performance. Consequently, the model becomes a valuable stencil to design fracture closure and complex fracture networks, which can be applied to optimize the choke management design for unconventional reservoirs.

Improper pairing of filler and polymer together with inappropriate filler loadings into polymer matrix may lead to structural defects such as large aggregations and interface void formations. Subsequently, the structural defects may sacrifice the selectivity of CO₂ over CH_4, which was unfavorable. In the current work, NH₂-MIL-125 (Ti) (MIL = Material Institute Lavoisier), which possesses NH₂-groups and theoretically capable of forming strong hydrogen bonding with F-groups of polyvinylidene fluoride (PVDF), was selected to spin hollow fiber mixed matrix membranes (HFMMMs). Besides, NH₂-MIL-125 (Ti) can interact better with CO₂ over CH₄ via quadrupole moment, and NH₂-groups also aid in CO₂ selectivity due to its high CO₂ adsorption capability. The HFMMMs were spun using a dry-wet spinning technique of filler loadings percentage ranging from 1 to 3 wt percent (wt%). The effect of filler and loadings percentage over HFMMMs properties, including contact angle, mechanical strength, thermal stability and cross-sectional morphology was investigated. The compatibility at interface of filler and polymer was observed to be good, and dispersion was observed to be acceptable up to 2 wt% filler loadings. However, apparent aggregation was observed beyond this point. The wt% of Ti, O, and N elements were found to increase from 0.72 to 2.05, 3.27 to 4.53, and 0.52 to 1.55, respectively, with increasing filler loading into HFMMMs. Subsequently, PVDF-2 membrane displayed the highest CO₂/CH₄ ideal selectivity with contact angle of 83.44 ± 1.45, ultimate tensile strength (UTS) of 1.33, 29.12 Young's Modulus, and 72.2% elongation at break. Therefore, optimizing loading percentage and selecting appropriate filler are considered practical methods to ensure good morphology and better hazardous CO₂ removal.

Understanding the gas-water two-phase flow behavior in a shale gas formation is important for reservoir simulation and production optimization. A molecular simulation study of gas-water flow in quartz and kerogen nano-slits (2–6 nm) at shale reservoir conditions (temperature: 313.15–393.15 K, pressure: 20–60 MPa) is reported in this work. The simulation results show that the existence of water in the hydrophilic quartz slits will form water films on the slit walls; while the presence of water in the hydrophobic kerogen slits will form water clusters in the central of the gas phase at low water saturation and a water layer at high water saturation. In both wetting conditions, water will take flow space and reduce gas flow path. However, water affects gas flow velocities in the two wetting types nano-slits in different ways due to the two opposite occupancies in the slits. The momentum transfer between water and methane molecules in the gas-water interface region plays an important role in the gas-water two-phase flow. The gas flow is more readily affected by water content in the quartz slit with an aperture greater than 2 nm. When the slit aperture is reduced to 2 nm, it is difficult to form a continuous gas or water phase, and the existence of water in both types of slits will reduce the velocity of methane. Increasing the temperature will accelerate the flow of methane and water because hydrogen bonds between water molecules as well as hydrogen bonds between water molecules and the walls are reduced. High pressure promotes the mixing of the methane and water molecules, resulting in the gas velocity decreasing in both quartz and kerogen slits. The flow mechanism of methane and water in nano-slits provide insights into theoretical models for shale gas production.

Drilling operations in oil and gas industry are associated with issues such as pipe sticking, poor wellbore cleaning and high fluid loss. Mitigation of such problems in water-based drilling mud (WBM) necessitates the application of nanotechnology in improving their filtration and rheological characteristics. In the present work, an attempt has been made to analyze the effect of nanofluid prepared using copper oxide (CuO) nanoparticles (NPs) dispersed in chia seed solution on WBM characteristics. Therefore, three samples of chia seed based nanofluids are synthesized using two-step method by varying the concentration of CuO nanoparticle from 0.2 wt% to 0.6 wt%. The resulting nanofluids are then mixed with WBM to prepare Nanofluid enhanced Water based Drilling Mud (NFWBM). The synthesized nanofluids are then characterized for their stability and thermal decomposition respectively using Scanning Electron Microscope (SEM) and Thermo-Gravimetric Analyzer (TGA). The NFWBMs are then analyzed for rheological and filtrate-loss properties at different temperatures of 30 °C, 50 °C, 70 °C and 90 °C. The hot roll aging process is carried out at 90 °C for 16 h maintaining the pressure at 0.1 MPa. The analysis projected a significant enhancement in the thermal stability of the WBM, with a reduction in viscosity of about 61.7% at 90 °C, which is critically observed to recover back to a significant extent of about 14% for chia based 0.4 wt% CuO nanofluid enhanced WBM and 19% for chia based 0.6 wt% CuO nanofluid enhanced WBM. Such improvement is observed in the rheological properties post hot rolling too. Further, the API fluid loss is observed to reduce from 7.2 ml to 6.8 ml, 6 ml, and 4.8 ml, respectively, before hot rolling, while the same reduced from 12.4 ml 11.4 ml, 10.2 ml, and 9.4 ml, respectively, for chia based 0.2 wt%, 0.4 wt%, and 0.6 wt% of CuO nanofluid enhanced water based drilling muds (NFWBMs). The present study aids in the development of novel and green additives for water-based muds to enhance their properties.

The liquid-phase pipeline is the optimal choice for large-amount and long-distance ethane transportation. Selecting the optimal diameter is necessary for the economical design of the pipeline. However, the special critical temperature 32.2 °C and critical pressure 4.87 MPa of ethane makes it easy to become liquid-vapor phase change, which is not considered in the traditional natural gas or crude oil pipeline design. In this paper, a new mathematical model is built to calculate the optimal diameter of the ethane pipe by using the ‘pump station + pipeline’ unit as the research object. The model selects the lowest total pipeline construction and operation costs as the objective function, and the constraints include the ethane liquid-vapor phase change, the pipe maximum allowable stress, and pipe specifications. In particular, the liquid-vapor phase change constraint is added to the traditional model to avoid the ethane liquid-vapor phase change, which is obtained by quantitatively analyzing the variation of physical parameters of ethane close to the pressure-temperature phase boundary. The optimization model is solved by use of the genetic algorithm. Finally, optimal pipe diameters are calculated for the conditions of transmission capacity from 1000 t/d to 10,000 t/d. Comparisons of calculated pipe diameter with eight actual cases show that the results are feasible with the average and maximum deviations being less than 5% and 8%, respectively. The effects of pipe materials and electricity prices on the pipe diameter are analyzed. It is demonstrated that the pipe material has a negligible effect on the optimal diameter, whereas increasing the electricity price will lead to the increase of the optimal diameter in the case of large transmission volumes.

Large-scale slickwater fracturing is an important technical method for the effective development of shale gas, which generates complex fractures with fracture width of millimeters in the reservoir. It is known that the transport law of proppant in complex fractures is the premise for realizing effective propping. Taking the behavior of 70/140 mesh proppant particles commonly used in shale gas fracturing as the object，a numerical model based on the computational fluid dynamics-discrete element method (CFD-DEM) and the geometric model of the intersection of the main and secondary fractures are established. It is used to study the two-phase flow law under the conditions of different fracture widths and angles, pump displacements, and fluid viscosities. The results show that the proppant enters the secondary fracture in two ways: carried by the fluid in a suspended manner and rolling into the fracture from the sand bank surface. Particles suspended in the fracture can be transported to the distal end of the secondary fracture. Owing to the influence of the inertia force of particles, the particle flow rate entering the secondary fracture is much smaller than the fluid flow rate in the secondary fracture. As the included angle between the secondary and main fractures decreases, the fluid and particle flow rate increase, and particles can easily enter the secondary fracture. As the displacement, secondary fracture width and fracturing fluid viscosity increase, proppant particles are easier to enter secondary fractures. The absolute values of the main and secondary fracture widths become smaller, and the relative value remains the same, making it more difficult for proppant particles to enter the fractures.

The behaviours of the particle settlement, stratified flow and inception of settled particles are essential features that determine the proppant transport in low-viscosity fracturing fluids. Although great efforts have been made to characterize these features, limited research work is performed at field scales. To test the laboratory outcomes, we propose a machine-learning-based workflow to evaluate the essential features using the measurements obtained from shale gas fracturing wells. Over 430,000 groups of fracturing data (1 s time interval) are collected and pre-processed to extract the particle settlement, stratified flow and inception features during fracturing operations. The GRU and SVM algorithms, trained by these features, are applied to predict fracturing pressure. Error analysis (the root mean squared error, RMSE) is carried out to compare the contributions of different features to the pressure prediction, based on which the features and the corresponding calculations are evaluated. Our result shows that the stratified-flow feature (fracture-level) possesses better interpretations for the proppant transport, in which the Bi-power model helps to produce the best predictions. The settlement and inception features (particle-level) perform better in cases where the pressure fluctuates significantly. The features characterize the state of proppant transport, based on which the development of subsurface fracture is also analyzed. Moreover, our analyses of the remaining errors in the pressure-ascending cases suggest that (1) an introduction of the alternate-injection process, and (2) the improved calculation of proppant transport in highly-filled fractures will be beneficial to both experimental observations and field applications.

Gas hydrates in pipelines is still a flow assurance problem in the oil and gas industry and requires a proactive hydrate plugging risk predicting model. As an active area of research, this work has developed a 3D 10 m length by 0.0204 m diameter horizontal pipe CFD model based on the eulerian-eulerian multiphase modelling framework to predict hydrate deposition rate in gas-dominated pipeline. The proposed model simulates the conditions for hydrate formation with user defined functions (UDFs) for both energy and mass sources implemented in ANSYS Fluent, a commercial CFD software. The empirical hydrate deposition rates predicted by this model at varying subcooling temperatures and gas velocities are consistent with experimental results within ±10% uncertainty bound. At lower gas velocity of 4.7 m/s, the model overpredicted the hydrate deposition rates of the experimental results in Aman et al. (2016) by 9–25.7%, whereas the analytical model of Di Lorenzo et al. (2018) underpredicted the same experimental results by a range of 27–33%. Consequently, the CFD model can enhance proactive hydrate plugging risk predictions earlier than the analytical model, especially at low gas productivity. Similarly, at a velocity of 8.8 m/s and subcooling temperatures of 2.5 K, 7.1 K and 8.0 K, the CFD model underpredicted the hydrate deposition rates of the regressed experimental results in Di Lorenzo et al. (2014a) by 14%, 6% and 4% respectively, and overpredicted the results by 1% at a subcooling temperature of 4.3 K. From the CFD model results, we also suggest that hydrate sloughing shear stress is relatively constant, and the wall shedding shear stress by hydrate vary during deposition. Finally, the CFD model also predicted the phase change during hydrate formation, agglomeration, and deposition.