Journal of Natural Gas Science and Engineering最新文献

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.

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.

Extended-reach wells have been widely applied to efficient development of oil and gas resources in complex areas such as oceans, beaches, lakes and mountains. Extended-reach drilling has the characteristics of many constraints, high implementation difficulty and high operation risk, and the accurate prediction of tubular extension limits and operation risks is very significant for safe drilling. Firstly, local tubular deflection curves and additional contact forces due to discontinuity effects are firstly deduced, and an amended torque & drag model of tubular strings is built. Secondly, a dynamic inversion method of friction factors was presented by introducing the weight function related to well depth and considering the difference of friction factors on cased and open-hole sections. Next, a dynamic prediction of tubular extension limit and operation risk is built by combining the amended tubular mechanical model, inversion model of friction factors. At last, the above theoretical models are applied to a case study. The results indicate that curvature discontinuity and stiffness discontinuity increase contact forces obviously in build-up and azimuth turning sections, which further increase friction force and torque a lot. The long-term, short-term and real-time tubular extension limits and operation risks can be obtained by setting different values of p.

Natural gas hydrates (NGHs) are important potential alternative energy sources of oil and gas, which are efficient and clean. Their exploration and development are inseparable from drilling and drilling fluids. Adding nanomaterials into drilling fluid can effectively weaken the invasion of the drilling fluid into a formation, which is conducive to safe and efficient drilling. Therefore, this study explores the impact pattern and mechanism of different types and dosages of laponite on the formation of hydrates and analyses the adaptability of laponite in offshore NGH drilling fluids. The results show that the hydration of laponite prevents the directional arrangement of water molecules from forming a clathrate structure, and laponite forms a “house of cards” structure in the aqueous phase, which increases the resistance to mass transfer and inhibits the nucleation and growth of hydrates. Under the action of hydration, laponite planarly adsorbs a certain amount of strongly bound water that fails to participate in the formation of hydrates, thereby reducing the amount of hydrates formed. In addition, laponite basically does not increase the viscosity of drilling fluid at low temperatures but strengthens the inhibition and settling stability of the drilling fluid, significantly improving the comprehensive performance of the drilling fluid. It is concluded that 1.0 wt% laponite-RD is suitable for use in hydrate drilling fluid systems, the induction time was extended to 451.33 min, the methane consumption was reduced to 0.12623 mol, the average methane consumption rate was reduced to 0.23983 × 10⁻³ mol/min, and the linear expansion rate of sediments is as low as 10.2%, which shows excellent rheological property and sedimentation stability.

The discovery of carbonate reservoirs in the Brazilian pre-salt field has raised several engineering challenges. These reservoirs are naturally fractured and much stiffer than conventional reservoirs. Thus, the study of fluid flow through natural fractures has received significant attention from the petroleum industry because the production capacity of these fields is associated with the hydraulic behavior of such fractures. However, pressure changes induced by the oil recovery alter the fracture aperture. In turn, changes in the fracture aperture affect the fluid flow inside the fracture channels, increasing or reducing the production capacity of the reservoir. This work investigates the hydromechanical effect of natural fractures on the reservoir behavior at the production unit Tupi pilot of the Brazilian pre-salt. The enhanced dual-porosity/dual permeability model (EDPDP) is adopted to simulate more realistically the hydromechanical behavior of fractured carbonate rock formation. This approach updates the stiffness and permeability tensors considering the fracture orientation and the stress-induced aperture changes. The shape factor is also improved to represent multi-block domains formed by several multiscale fracture sets with different orientations, apertures, and spacing. The hydromechanical formulation of EDPDP implemented in an in-house framework GeMA (Geo Modeling Analysis) is adopted to study the hydromechanical effect of fractures with multiple lengths on the Tupi pilot. The numerical results demonstrate that the complex fracture network is responsible for fluid migration through a preferential pathway. A parametric analysis of the main parameters that affect reservoir behavior was carried out. The parametric study shows higher pore pressure dissipation for smaller dip angles. Then, horizontal fractures are more sensitive to vertical displacements. In addition, smaller spacing and larger fracture aperture enhance permeability, increasing pore pressure dissipation and mechanical deformation. Finally, numerical results were compared against field measurements showing excellent agreement, demonstrating the applicability of the EDPDP model to simulate naturally fractured reservoirs.

The hydration-induced fractures significantly enhance shale gas production after well shut-in, which reveals considerable gas mass transfer characteristics. However, few studies focus on multiple flow mechanisms coupling the fracture distribution and morphological properties. Therefore, a novel apparent permeability (AP) model, in which poromechanics and desorption-induced aperture evolution are captured, has been derived to precisely define gas mass transfer through fracture networks. In this study, the fracture distributions are derived by fractal law, and the morphologies are solved using the orthogonal decomposition method (ODM) and shape coefficient correction. Viscosity changes in confined channels are also considered, further upscaling volume flux, Knudsen and surface diffusion through fractal theory by discrete integrals and derivation of the AP model combined with Darcy's law. The proposed model is verified well by experiments and the literature. The results show that the viscous flow contribution ratio decreases with decreasing aperture, while the Knudsen flow ratio slightly increases, and gas desorption significantly increases permeability when p_p < p_L. Therefore, the viscous flow is the dominant flow regime at high p_p, and Knudsen and desorption diffusion gradually dominate the transmission at low p_p. The larger b_max/b_min obviously enhances AP, the more confined apertures, and the AP decreases obviously as p_p decreases. The stronger desorption and diffusion capability represent that gas will be transported sufficiently, higher c_o and δ indicate that the aperture is close more effectively, causing the AP reduction to be fast, and hydration further lowers E and v denotes higher AP due to the aperture shrinkage being replaced by matrix parts. The real gas effect on AP reduction cannot be ignored. This study identifies the gas transport characteristics in hydration fracture networks, with the research method also being applicable to other structures.

The wettability of rock affects the interaction between CO₂, brine, and shale formation, which affects CO₂ sequestration with enhanced gas recovery (CS–EGR) project. However, under reservoir conditions, there is limited research on the surface wettability of shale organic matter, and its internal interaction mechanism is unclear. In this study, the effects of temperature, pressure, mineralization, and concentration ratio of CO₂ to CH₄ on the contact angle were studied using molecular dynamics (MD), and the results were compared with the previous experimental data. Under a certain pressure, the water wettability increases with the increase in temperature. At a fixed temperature, the contact angle of water on graphene increases with the increase of CO₂ pressure. Above the critical pressure, water at different temperatures is wetted by CO₂ on the surface of graphene, and the wettability reversal occurs. The water wettability decreases with the increase in solution salinity. Under the same concentration of droplets, Mg²⁺ and Ca²⁺ have a greater effect on the wetting angle than Na⁺. The adsorption capacity of the graphene surface for CO₂ is stronger than that of CH₄. Finally, the order of wettability is verified by interaction energy. This study will contribute to alleviating the greenhouse effect.

Numerical simulation plays a crucial role in the prediction of natural gas hydrate production performance. However, most existing models are two-dimensional or three-dimensional with idealized geometries and uniform parameter assignments, which cannot depict the effects of stratigraphic undulation and spatial variability of reservoir physical parameters on gas production. Therefore, a convenient method to convert the image information (more accessible) into parameter attribute values (required for model construction) was proposed in this study. Using the converted data of reservoir depth, thickness, and porosity, a more realistic three-dimensional model was innovatively constructed. Then, the influences of reservoir fluctuations and spatial variability of physical parameters on production performance were quantitatively analyzed. It was found that placing the production well in an elevated area can facilitate gas production. Specifically, Well 1 (located in the highland) had a 34.1% higher normalized gas production rate (i.e., production rate per unit well length) and a 14.9% lower normalized water production rate than Well 3 (located in the flat area) in the free gas layer. In addition to reservoir fluctuations, the exploitation efficiency of the gas hydrate-bearing layer was also affected by the thickness. The spatial variability of hydrate saturation and that of gas saturation in the study area were not very prominent, and the gas production rate obtained by the heterogeneous scheme was approximately 10% different from that of the homogeneous scheme. However, although the spatial variability of porosity was also not great (no more than 2%), when the cubic law was used to calculate the corresponding permeability, the gas production rate obtained by the heterogeneous scheme was nearly 20% different from that of the homogenous scheme. This study demonstrates the need to use a more realistic three-dimensional model for gas hydrate production performance prediction and is expected to provide an important reference for well location selection.

The efficient exploitation of geological resources using supercritical carbon dioxide (SC–CO₂) is seriously hindered by the inaccurate mastery of pore evolution laws of reservoir rocks. It is thus aimed to elucidate the temperature and pressure effects of SC-CO₂ on the rock pore evolution in this study. Static and dynamic alteration tests were performed under 9 conditions of different temperature and pressure. The porosity evolution shows consistently positive correlation with the pressure of SC-CO₂, while inconsistent correlation with temperature. The inconsistent temperature effect is caused by the weakened alteration process of calcite with temperature increasing, which is opposite to the enhanced alteration process of other minerals. The fundamental reason is that the alteration rate of mineral with low activation energy E_a is significantly reduced by temperature increase. With the increase of E_a, however, the reducing effect of temperature increase on alteration rate gradually becomes weaker and hardly turns into an enhancing effect until E_a = 26,000 J/mol. With the help of resistance kinetics equation, two kinds of calculation methods of porosity evolution were proposed based on rock alteration volume and soluble mineral alteration extent, respectively. In addition, considering dynamic alteration effect, the rock pore evolution process is weakened because of the weakened alteration process of soluble minerals, and the differential porosity evolution of sandstone, granite and marble can respectively reach 0.95%, 0.11% and 0.15% at most.

The conventional water-based fracturing fluids have such defects as large water consumption, serious environmental pollution and water-sensitive damage to reservoirs in the development of tight oil. In this study, a novel anhydrous CO₂ fracturing fluid system was constructed with the compositions of 7 wt% polydimethylsiloxane (100 cs), 5 wt% ethanol and 88 wt% liquid CO₂. The viscosity of the system could reach 6.52 mPa s, which was 37 times higher than that of pure liquid CO₂ at −15 °C and 30 MPa. The pressure resistance, temperature resistance, anti-swelling property, filtration loss property, core damage property, corrosion property and wetting inversion property of anhydrous CO₂ fracturing fluid were systematically evaluated by physical simulation experiments. The environmental scanning electron microscopy (ESEM) and mercury injection experiment were conducted. The viscosity retention rate of anhydrous CO₂ fracturing fluid reaches 47.92% when the temperature increases by 50 °C. When the pressure increases by 25 MPa, the viscosity increases by 2.6 times. It ensures that the viscosity of anhydrous CO₂ fracturing fluid is well retained after injection into the formation. In addition, the anti-swelling rate of anhydrous CO₂ fracturing fluid reaches 90.91%. The filtration coefficient is reduced by 69.20%. For low permeability sandstone cores, the permeability damage rate is 18.80% and the porosity damage rate is 12.58%. After aging for 30 h, the permeability and porosity of core increased 39.23% and 5.52%, respectively. Meanwhile, the wettability of the core could be changed from hydrophilic to neutral, which reduced the flow resistance of the oil phase and improved tight oil recovery. Through this study, we hope to broaden the application of anhydrous CO₂ fracturing fluids in tight oil development.