Journal of Natural Gas Science and Engineering最新文献

Sulphate reducing prokaryotes (SRP) cause hydrogen sulphide (H₂S) generation in some waterflooded hydrocarbon reservoirs that is known as microbial reservoir souring or biosouring. The H₂S generated in-situ by SRP is toxic and corrosive that adversely affects the quality, production, and economy of oil fields together with negative environmental impacts. Various chemical, biological, and microbial methods have been implemented to control such in-situ microbial reactions in the past few decades but still they are not fully controllable. This work aims to give deeper insight into microbial reservoir souring and its mitigations techniques. First, this review elaborates on the complex physics of souring and subsequently explores the latest modelling tools being used to capture the biochemistry of souring and the physics of H₂S generation. Later, a critical discussion on the impact of governing parameters such as fluid composition, temperature, pressure, pH, and salinity on H₂S biogeneration is added. Next, H₂S-fluid-rock interactions leading to partitioning, adsorption, and scavenging phenomena are scientifically explained and their effects on H₂S transport are elucidated. Various mitigation and control techniques are presented and critically compared in view of their suitability and applicability in different scenarios. Finally, some field cases are reported, and the key challenges and the forthcoming research requirements are highlighted. This insightful review provides necessary information on microbial activities in hydrocarbon fields that are important for chemical and petroleum engineers to tackle souring issue.

Fracturing, as a common fracture-making technique, can improve the permeability of coal seams to enhance fluid transport efficiency. To quantitatively evaluate the microscopic characteristics of medium-high rank coal, the loaded pore-fracture system was characterized by computerized tomography (CT) scanning under triaxial loading, followed by the analysis of stress-strain evolution, stress sensitivity and three-dimensional (3D) fractal dimension. Combined with snow algorithm and incompressible steady laminar flow simulation, the heterogeneous distribution of fluid pressure is investigated, focusing on the diffusion effect of gas transport. The results show that the strain of the high-rank coal Chengzhuang (CZ) in the linear elastic stage increases from 0.25% to 1.25%, greater than that of the medium-rank coal Qiyi (QY) from 0.75% to 1.63%, demonstrating a slight lag of the high-rank coal from the linear elastic stage into the yielding stage. The porosity of CZ changes from 1.66% to 13.58% and that of QY varies from 1.74% to 22.28% after fracturing, reflecting that the primary and secondary pores of the medium- and high-rank coals form a complex network structure for fluid transport through continuous connection-expansion. When the strain is between 0.75% and 1.25%, the stress sensitivity coefficient of CZ decreases from 0.13 to 0.02. Moreover, there are many mutation points in the 3D fractal dimension of coal samples after fracturing, mainly due to the generation of new pore-fractures at different locations of the computational domain. For fluid transport, the pressure of QY after fracturing spreads in a wider range than CZ, accompanied by more distribution of high fluid pressure. The diffusion coefficient of the fractured CZ is 350 times higher than that of the original coal under the gas pressure condition of 0.5 MPa, which provides the possibility for more gas to be converted from Knudsen diffusion to transition diffusion or Fick diffusion in the channel.

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.

Hydraulic fracturing is considered a promising stimulation technology for low-permeability hydrate reservoirs. To date, only a few studies have focused on hydraulic fracturing in hydrate-bearing sediments. However, the numerous factors that affect fracture initiation and propagation are not clearly understood, and the fracability of non-diagenetic geo-materials has not been systematically evaluated. In this study, a series of true triaxial hydraulic fracturing experiments are conducted on clayey-silty hydrate-bearing sediments to investigate the effects of the key reservoir and engineering parameters on fracture initiation and propagation. Based on the resulting data, a fracability index ($\text{FI}$) that considers multiple factors is developed using a novel method. The results indicate that fracture initiation pressure does not always increase with increasing hydrate saturation. Moreover, a maximum value of 14.92 MPa for the initiation pressure is observed at 40% hydrate saturation. This value is increased by 20.51 MPa when the effective horizontal in-situ stress increases from 1 to 4 MPa, which is in contrast to the tensile crack initiation law of elastic rocks. Additionally, owing to the inhomogeneous hydrate in sediments, fractures expand unevenly, and double fractures are able to form in an isotropic horizontal stress state. The horizontal stress difference is the primary parameter (weight 0.4) that governs the $\text{FI}$, followed by the coefficient of earth pressure at rest (weight 0.31), fracture toughness (weight 0.18), and hydrate saturation (weight 0.05), and vertical in-situ stress (weight 0.05). Increasing the injection rate and fracturing fluid viscosity is an effective method to promote fracture propagation, particularly when $\overline{Q\mu }>$ 0.33 (defined by the normalised injection rate and fracturing fluid viscosity) and $\text{FI}>$ 0.4. In such conditions, a considerable reconstruction area can be obtained.

CO₂–CH₄ dynamic replacement is a process of the CO₂–CH₄ replacement method. In this process, CO₂ is injected into CH₄ hydrate-bearing sediment continuously to recover CH₄. The dynamic replacement process can be divided into the CO₂ displacement stage and the subsequent dynamic replacement stage and is affected by the existence of initial water and diffusion-limited transport caused by the mixed hydrate layer. Effective fugacity is utilized to combine the thermodynamic model and kinetic model to investigate the effects of the above two factors on the CH₄–CO₂ dynamic replacement process. Initial water is assumed to distribute in the pore space. The CH₄ hydrate decomposition due to the decrease of CH₄ partial pressure in the gas phase during the CO₂ displacement stage is considered. Our investigation results show that diffusion-limited transport is the main factor that restricts the replacement percent in the displacement stage, the effect of the existence of initial water on the replacement percent is more obvious than that of the diffusion-limited transport. CO₂ storage efficiency is less than 10% during the entire dynamic replacement and is mainly affected by the existence of initial water rather than the diffusion-limited transport. The temperature increase is mainly due to newly formed hydrate. Finally, more CH₄ hydrate is exploited near the outlet than that near the inlet. Therefore, the CH₄–CO₂ replacement method needs to be enhanced near the inlet. CO₂ is mainly sequestrated in the CO₂ hydrate formed through free water. CO₂ sequestrated in the mixed hydrate is mainly distributed near the inlet, while the CO₂ sequestrated in the CO₂ hydrate is mainly distributed near the outlet.

The rock porosity or permeability highly depends on stress, a crucial property in resource exploitation and geological storage engineering. However, due to factors such as rock types, loading paths, and loading ranges, the stress-porosity/permeability relationships are pretty different, exhibiting linear, nonlinear, or even heavy-tailed characteristics. The exponential and power-law models, two mainstream empirical relationships for describing the rock permeability and porosity decays, are used to fit the data with “heavy tail” characteristics but yield poor fitting or outrageous predictions for specific stress ranges. Based on the physical interpretation of the compaction-induced microstructural evolution inside the rock, this paper proposes fractional-order relaxation equations, which consider the memory effect of permeability/porosity variations with stress, leading to accurate descriptions of effective stress-porosity/permeability relationships by the Mittag-Leffler (ML) law. The fitting on low-permeability shales and relatively high-permeability sandstones shows that the ML law agrees better with the experimental data, especially with “heavy tail” characteristics than the two classical laws. Moreover, the numerical solutions for the proposed ML models are presented via the predictor-corrector algorithm. The relationship between the ML, exponential, and power laws is also discussed.

A significant amount of the natural gas in shale formations is contained in the micro- and mesopores as dissolved (absorbed) phase and on the surfaces of associated microcracks as (adsorbed) phase. The transport of natural gas in such confined spaces is primarily governed by self-diffusion as could be deduced from Knudsen number. Self-diffusion is governed by the pressure and the space confinement. In this study, realistic kerogen structures possessing both tortuous micropores and larger microcracks were formed and used to assess self-diffusion behavior during the depletion of shale reservoirs through some comprehensive molecular simulation workflow. Analysis of the transport modes revealed transition self-diffusion as the primary transport mechanism in these micropores. The sorption behavior and the mechanical properties were analyzed and incorporated to derive a transition diffusion model that is sensitive to changes in the pore pressure and the stress field. The proposed model was compared and validated against similar work in the literature. The results showed that during a typical production span, a pressure drop influences the sorption profile, the net overburden stress on the pores, and the mean free path, altering the magnitude of self-diffusivity. The calibrated pore scale model produced decent predictive ability with a relative error of 2.5–16%. The implications of structure tortuosity, sorption profile, and pore pressure on the effective diffusion coefficient and gas desorption are discussed in depth. This work provides a novel methodology for studying the effect of coupled multiphysics processes on methane transport in a realistic kerogen geometry, which could be used to calibrate a suitable pore scale model for upscaled reservoir simulation applications and accurate assessment of reservoir dynamics and ultimate recovery.

Composite coal seam is a kind of special coal seam that is formed after complex geological structure action, including a tectonic coal sublayer. Gas can't be drained easily from this coal seam, which cause coal and gas outburst accidents (CGOA) occur frequently. A new hydraulic flushing technology was proposed in this paper to improve gas drainage. Accordingly, a new set of mechanical equipment, technology process, roadway layout system and gas extraction monitoring system are provided by drawing lessons from the Guhanshan coal mine. The stress variation and damage failure were investigated by numerical simulation on the basis of flushed-out coal and borehole geometry. The gas drainage effect, coal seam permeability and outburst risk-sensitive indexes of the special coal seam were obtained by field measurements. According to the results, hydraulic flushing can enlarge the stress unloading and plastic damaged zone around boreholes dramatically, and the coal seam permeability can be increased largely.

In this contribution, the problem of NGL separation control is addressed by dealing with the most common process schemes. The main goal is to achieve a specified ethane recovery as well as maintaining certain levels of methane impurity in the demethanizer column. An indirect control of composition through the temperature control in the column is proposed. A cascade arrangement between the column temperature control and the controller that maintains a constant ratio of boil-up to column bottom product is proposed for the improvement of methane impurity levels. Additionally, an “inferential” control approach based on Antoine's law is formulated and tested to enhance the ethane recovery control. The performance indexes calculated for ethane recovery and methane impurity show the superiority of the proposed control structure in each NGL separation process scheme. When the feed flowrate is reduced by 10%, the proposed control strategy allows a lower deviation from the target and a smaller offset with a reduction of 73.7% for ethane recovery and 72.7% for the methane concentration in the conventional process, 86.6% for ethane recovery and 96.4% for methane concentration in the GSP, and 97.1% for ethane recovery and 91.1% for methane concentration in the CRR process. In case of sinusoidal variations of inlet flowrate, the integral square error is reduced by 99.33% for methane bottom concentration in the GSP process scheme, while ethane recovery shows a reduction of 82.69% in the CRR scheme.