Journal of Natural Gas Science and Engineering最新文献

Ni-based spinel nanocatalysts (NiAl₂O₄) with various anti-coke materials (Ca, K and W) were fabricated with sol-gel technique followed by plasma treatment and evaluated in hybrid CO₂/O₂ reforming of methane (CRPOM). To scrutinize the physiochemical properties of nanocatalysts, XRD, FESEM, EDX, TEM, BET, FTIR and TG-DTG analyses were used. XRD patterns revealed that, the lowest peaks intensity was obtained for W promoted NiAl₂O₄ (NW5A (SGP)). Also, nickel was dispersed more uniformly in NW5A (SGP) compared to K and Ca promoted ones (NK5A (SGP) and NCa5A (SGP)). Owning to the FESEM and EDX analysis all samples illustrated the acceptable dispersion which was resulted from the synergistic effect of sol-gel method and plasma treatment. However, NW5A (SGP) presented the slightly better dispersion and finer particles size compared the other ones. Also, highest surface area was found for the tungsten promoted one. Owing to the nature of sol-gel method, lower basicity of the synthesis media for NW5A (SGP) compared to that of NK5A (SGP) and NCa5A (SGP) resulted in better surface and adsorption properties. A superior interaction between metallic particles can be concluded from the TEM images of NW5A (SGP). Results of activity testes proved better catalytic activity of NW5A (SGP). It was ascribed to its superior characterization. Although throughout the time of stream test (TOS) at 750 °C and for 48 h, NW5A (SGP) presented the greater performance, but all of the fabricated nanocatalysts approximately exhibited the stable performance. TG-DTG analysis (after 48 h TOS) revealed that the lowest amount of coke deposition (4.6%) was obtained for the NW5A (SGP). Regarding to the EDX and FESEM images of spent nanocatalysts, well-maintained structure and excellent dispersion was gained for NW5A (SGP) after 48 h TOS. Accordingly, it is expected that tungsten modifier causes higher coke resistance compared to potassium and calcium at longer times on stream.

Tight sandstone gas reservoir normally has a poor pore connectivity and a low productivity of single layer production, and the multilayer co-production technique has received increasing attention to improve its recovery in recent years. However, the range and impact of geological conditions are still unclear, leading to a challenging comprehensive evaluation of multilayer co-production compatibility. In this study, the impact of a series of factors on multilayer tight gas production is discussed by numerical simulation in detail, and their compatibility thresholds are determined. The variable weight based fuzzy comprehensive evaluation (VW-FCE) method is constructed, and a co-production compatibility index (CCI) is further proposed for multilayer tight gas reservoir co-production evaluation, with an application to Daning-jixian tight gas reservoirs for verification. The results show that thickness, permeability, reservoir pressure, and gas saturation are the key factors affecting the co-production, and the 10-year cumulative gas production contribution of the lower sandstone increases with the increase of each parameter ratio between the lower and the upper sandstones. When the properties of two co-production layers are similar, their compatibility is mainly impacted by the formation pressure and gas saturation variations. Otherwise, their compatibility is controlled by the formation thickness and permeability. The CCI values for multilayer co-production is 0.6–1, and the gas production capacity shows a positive exponential relationship with the evaluation index. The proposed method is verified by comparing with the actual production data from typical wells of tight sandstone gas co-production in the Daning-Jixian area, which indicates that the CCI is appropriate to evaluate the co-production compatibility of multiplayer tight gas reservoir, and provide theoretical supports for tight gas co-production.

The magnetic-based stress detection technology has a great application potential in the field of girth weld stress detection. However, this technology lacks an effective theoretical model as a scientific guide. Therefore, to investigate the quantitative relationship between the magnetic gradient signal and weld stress and quantitatively evaluate the stress status of girth welds. In this paper, a numerical simulation model of stress-induced magnetic signals of girth welds with unequal wall thickness (UWT) is first established. Then, the model is used to calculate and analyse the quantitative variation law of the magnetic gradient signal of the girth weld with stress and detection height. Moreover, a magnetic-based stress detection and risk evaluation method is established to assess the stress failure risk of girth welds with UWT, whose accuracy is experimentally validated. The results indicate that the residual strength ratio RSR exponentially reduces from 0.83 to 0.49 as the G_max increases from 373 to 542 μT/m. Moreover, the goodness of fit of the experimental data based on this relationship mentioned above reaches 0.98. The magnetic signal also exhibits a decaying exponential trend with detection height (0.1 m–0.3 m) when the internal pressure varies within 3 MPa–9 MPa. The numerical range of the RSR of seven girth welds is 0.31–0.95, which shows good agreement with the contact inspection results.

In this study, we performed reservoir simulations to investigate CO₂ storage in the saline aquifer in Sleipner by reservoir pressure management. Results show that by producing water at the lowest aquifer structure far away from the CO₂-water contact in the vertical direction, an additional 73% (24 Mt) CO₂ can be stored compared to the case without water production. This extra CO₂ stored can generate a revenue of $800 millions at the prevailing carbon tax of $69 per ton in Norway. There is 5.31 Mtpa of natural CO₂ production from 124 gas and oil fields in Norway in 2020. Of these, the Marulk, Dvalin, Skarv, Morvin, Åsgard, Kristin, Tyrihans and Mikkel fields in the Norwegian Sea, and the Kvitebjørn, Valemon, Visund, Gudrun fields in the North Sea produce a total of 4.55 Mtpa CO₂ potentially supplying CO₂ to Sleipner for project life extension.

Quantification of methane content in shales is a critical parameter for estimation of their potential gas production capacity. Traditional gravimetric methods for estimation of this quantity are sensitive only to adsorbed methane and are difficult to apply either to intact shale rock cores or via field measurements. Here non-invasive low-field nuclear magnetic resonance (LF-NMR) is applied to quantify excess methane adsorption capacity in two intact shale rock plugs at pressures up to 150 bar; validation is provided against destructive gravimetric methods performed on fragments from the same shale rock plugs. The resultant NMR transverse relaxation time (T₂) distributions contain three distinct peaks (referred to as peaks P1 – P3) which are allocated to adsorbed methane in organic pores, methane constrained to inorganic pores and bulk methane located predominately in fractures, respectively. The area of peak P1 is observed to increase with pressure up to 100 bar, after which it reaches a plateau, whilst the area of peaks P2 and P3 both increase linearly with pressure up to 150 bar. The most accurate estimate of excess methane adsorption capacity is obtained via a combination of an overall system mass balance and the methane located in inorganic pores and fractures (peaks P2 and P3, respectively), where excellent agreement is produced with corresponding gravimetric measurements for both shale samples studied.

Bypass pigging technology is an emerging strategy with promising potential to reduce the velocity of pipeline inspection gauge (PIG) and mitigate pigging-induced slug volume for oil and gas transportation systems. Nonetheless, the critical issue of bypass pigs being blocked in pipelines is a major concern for wide implementations of this new technology. To this end, this study newly proposes an intelligent self-regulated bypass pig prototype by developing an internal bypass regulating module to enhance the anti-blocking capability for pigging operations. To facilitate the optimal design of the bypass regulating module, force variation characteristics of the bypass valve in blocked bypass pigs are of great significance. Accordingly, this study thoroughly investigates bypass valve forces for bypass pigging under the blockage status both experimentally and numerically. The experimental results show that an increase in gas velocity can almost linearly increase the valve force, which is mainly affected by the driving gas flow rate. Specifically, when the gas velocity increases from 1.26 to 4.4 m/s, the valve force can be increased from 1.46 to 12.88 N on average. In addition, a CFD-based numerical model was developed and experimentally validated to calculate valve forces. The numerical model, which has the mean bias error below −0.886 N with the index of agreement over 0.98, can be used as an effective approach to valve force analyses. Finally, the optimal design scheme for bypass pigging with anti-blocking capability was proposed, which can considerably facilitate the secure and efficient pigging performance and natural gas transportation.

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.

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.

The cement sheath of CCUS well is vulnerable to carbonization corrosion upon protracted exposure to a CO₂-rich setting, which reduces the strength of the cement sheath and increases the porosity, eventually leading to CO₂ leakage. Predicting the carbonation depth and regularity of the cement sheath of CO₂ injection wells allows an estimation of the service life , to ensure safe operation of CO₂ injection wells. However, most of the current prediction models for CO₂ corrosion depth are still semi-empirical models, which are fitted to experimental data but are not universally applicable. This may be resolved by our CO₂ corrosion depth prediction model supported by the law of mass conservation, diffusion convection equation, and calcium precipitation rate. The influence of seven factors on the corrosion depth was analyzed and ranked. The rise in corrosion time, temperature, chloride ion content, CO₂ partial pressure, water-cement ratio, and water saturation increases corrosion depth and CO₂ content, in addition to porosity and permeability, while increasingly corrosion-resistant material causes the opposite effect. The cement sheath begins to be seriously corroded by CO₂ partial pressure exceeding 10 MPa, chloride ion content over 0.20 mol/L, or temperature higher than 70 °C. Water saturation significantly affects corrosion, and the CO₂ corrosion depth at 0.8 is 10.16 times that at 0.6. The CO₂ content at the distance of 0.2 m–0.93 m from the corroded end surface basically does not change after 7 years of corrosion. Water-cement ratio increased to 0.48 provides conditions for a large amount of CO₂ accumulation in the cement sheath. The addition of corrosion-resistant materials can reduce the initial porosity and permeability of cement sheath. The seven factors is ranked in descending order of influence as water saturation, corrosion-resistant material, water-cement ratio, CO₂ partial pressure, corrosion time, chloride ion content, and temperature.

Permeability is a crucial parameter determining methane gas recovery. Hydrate reformation has a significant impact on reservoir permeability during methane hydrate (MH) exploitation and it is often ignored. In this paper, the effect of hydrate reformation on gas permeability was investigated by remolded cores with different hydrate saturations and effective stresses. The results show that hydrate reformation exacerbates the heterogeneous distribution and reduces the reservoir permeability. The permeability damage rate (PDR) of hydrate reformation is greater than the hydrate first formation owing to the inhomogeneity of water caused by hydrate decomposition. When hydrate saturation is increased from 22.26% to 40.44%, the PDR range caused by hydrate formation varies from 19.89% to 98.02%. In addition, the permeability after hydrate decomposition decreases with increasing effective stress. When the effective stress is absent or small, the permeability after secondary decomposition is lower than the first decomposition at the same hydrate saturation. However, the opposite is true when the effective stress is reached 3 MPa. Due to the memory effect of MH in marine sediments, the hydrate reformation induction time is shorter and the reformation rate is faster. However, the gas consumption of the hydrate reformation is less than the first, causing lower hydrate saturation. This work supports the exploitation of gas hydrate and numerical simulation studies in marine sediments.