Journal of Natural Gas Science and Engineering最新文献

An understanding of the mechanical properties of reservoir shale is of great significance for the efficient development of shale gas. Both marine and continental shale gas reservoirs in China have considerable development potential, but their different depositional environments may lead to substantial differences in their mechanical properties, which can result in production efficiency differences. In this study, nanoindentation, X-ray diffraction, backscattered electron imaging, and energy-dispersive X-ray spectroscopy were used to determine and analyze the mechanical properties and microtexture of marine and continental shale samples. The geogenesis of the microtexture of marine and continental shales and its influence on the mechanical properties were discussed. The results show that the elastic modulus of marine and continental shale samples are similar, but the hardness of latter is greater. The similar elastic modulus of the two shale samples may result from similar mineralogy. Due to differences in deposition and diagenesis, the marine shale sample forms a clay support matrix and the continental shale sample forms a rigid clastic support matrix, which results in lower hardness in the former and higher hardness in the latter. The low hardness of the shale with a clay support matrix indicates that it may be subject to more severe proppant embedment issue. The experimental results provide a useful reference for the development of these two types of shale gas reservoirs.

In the Czech Republic, coal-bearing siliciclastic sediments have been deposited during the Serpukhovian and Bashkirian (Carboniferous). Until now, no attention has been paid to inorganic geochemical assessment of the coals and associated non-coal rocks from the mixed shallow-marine to continental sediments (Ostrava Formation), and continental non-marine settings (Karviná Formation). Samples were collected from a 750 m deep coal exploration borehole at the ČSM Mine. The bulk parameters, total organic carbon TOC, total inorganic carbon TIC, total sulphur TS, major elements, trace elements, and REEs were measured on these samples, and their mineral associations have been investigated using microscopy combined with the principal component analysis (PCA). Common redox proxies V/Cr, U/Th, Ni/Co, Mo/U, and the ratio S/TOC have been tested on the samples to investigate their usefulness for studying anoxia. Research concludes that redox proxies such as U/Th, Ni/Co and V/Cr have been strongly influenced by the clastic input and carbonates, which it hinders for them to be reliable indicators of anoxia. On the basis of Eu anomaly and REEs distribution, the primary source of detrital elements comes from the parent rock, being governed more by physical than redox processes.

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.

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.

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 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 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.

Wet gas gathering and transportation in natural gas production has good economic benefits, but it also brings many risks. Due to the synergistic effect of corrosive gas and multi-phase flow in the wet gas pipeline, there are two corrosive environments, which leads to frequent accidents of pipeline corrosion failure. In this paper, the corrosion experiments of X65 steel in two environments (H₂S/CO₂ vapor; H₂S/CO₂-dissolved brine) were completed by a high-temperature and high-pressure reactor. Combined with SEM, EDS and XRD instruments, the morphology, elements and compounds of corrosion products were analyzed. The corrosion impact of temperature, flow rate, CO₂ and H₂S in both environments was determined. Finally, corrosion mechanism in two corrosion environments were established. When CO₂ and H₂S coexisted, both in two corrosive environments, the two gases were involved in the corrosion of X65 steel, and the corrosion products formed were FeCO₃ and FeS in the liquid phase. The difference was that the corrosion product film in the gas phase was denser than that in the liquid phase and the corrosion rate in the gas phase was smaller than that in the liquid. There was a large amount of Cl⁻ and high shear force brought by the flowing, the corrosion product film fell off and formed local corrosion. In the gas phase, due to the H₂S and CO₂ higher concentration, a dense corrosion product film rapidly formed in the droplets. In the two environments, the order of corrosion factors is $P_{H_{2}S}$ ≫$P_{C{O}_2}$ Velocity > Temperature. But in the gas phase environment, H₂S dominates in the gas phase more than in the liquid phase because it is more soluble in droplets.