The corrosion of weld metals with Cr, Ni, Cu or Mo in gas field produced water with saturated CO2 and H2S was investigated by scanning electron microscopy (SEM), X-ray diffraction (XRD), X-ray photoelectron spectroscopy (XPS), optical profiler, and electrochemical tests. The addition of alloying elements led to a decrease in polygonal ferrite and pearlite, whereas an increase in acicular ferrite in weld metal. Morphological and compositional analysis manifested that corrosion scale on weld metals primarily consisted of FeCO3 and iron sulfides, and Cr(OH)3 also existed on Cr-containing weld metals. With increased alloying elements, especially chromium, localized corrosion resistance was improved. This improvement was ascribed to the presence of alloying elements in substrate and Cr-rich products in scale, which can inhibit the oxidation of iron sulfides, thereby improving the structure of corrosion scale. Electrochemical tests showed that the anodic dissolution reaction of weld metal with higher Cr, Ni, Cu or Mo was inhibited in more extent, and the increase in total reaction impedance depended on weld metal surface active state. The preliminary corrosion mechanism of weld metal in CO2/H2S environment was proposed.

Porous flow is typically analyzed by the Kozeny–Carman equation using geometric variables, such as hydraulic diameter and tortuosity. The hydraulic tortuosity was first described by Kozeny, and later redefined by Carman as the tortuosity square term in the Kozeny–Carman equation. However, the revised term correlating the flow velocity with path length square would be physically ambiguous. Moreover, the hydraulic diameter, which is directly correlated to the permeability and interstitial velocity in the Kozeny–Carman equation, is an isotropic constant property; thus, it should be verified whether the isotropic hydraulic diameter can reasonably correlate each anisotropic directional flow feature passing through heterogeneous complex media. Accordingly, the Kozeny–Carman equation was theoretically examined and experimentally verified in this study to obtain the proper correlation based on the definitions of truly equivalent diameter and tortuosity. Therefore, the effective variables of porous media were presented, and it confirmed that the effective diameter corresponded to the physically equivalent diameter of anisotropic porous media. Moreover, using the mass conservation relation, it was verified that Kozeny's tortuosity is exactly associated with the truly equivalent flow model, and then the Kozeny constant must be differently defined from the original Kozeny equation. Accordingly, the Kozeny–Carman equation was improved by appertaining either effective diameter or tortuosity, and the momentum conservation relation was used to verify it. The pore-scale simulations using 5-sorts of 25-series porous media models were performed to test the validity of derived effective variables and revised equations. Finally, the alternative flow model of anisotropic porous media was presented using equivalent geometric and frictional flow variables. Subsequently, their practical and more accurate estimations were achieved by introducing the concentric annulus flow model under the special hydraulic condition. The new variables and relations are expected to be usefully applied to various porous flow analyses, such as interstitial velocity estimations, geometric condition variations, flow regime changes, and anisotropic heat and multiphase flows.

A clear understanding of the replacement characteristics and kinetic mechanism of CO2–CH4 hydrate has great significance for natural gas hydrate (NGH) exploitation. This paper presents a comprehensive overview on the research progress of kinetics on CH4 recovery from NGH by CO2 replacement, especially with CO2-containing mixed gas. The promoting effect of small molecule gas such as H2 and N2 on the replacement process of CO2–CH4 hydrate and its internal mechanism are deeply analyzed. Furthermore, based on the current conclusions obtained, the existing problems and future development directions of the CH4 recovery from NGH by CO2-containing gas mixture are pointed out.

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.

Increasing attention has been paid to the site selection of Underground Gas Storage (UGS) due to the growing demand for natural gas peak shaving. Existing studies have made a practical contribution to this field based on the multidimensional geological exploration data and the multi-criteria decision-making method. However, previous studies mainly focused on screening or ranking technologies with different principles, which means only the attributes of UGS in the design period were considered while the performance in the operation period was ignored. The operation plan and economic performance are considerable concerns to the UGS investors especially when this type of storage facility was unbundling from other sectors in natural gas companies. To solve the UGS site selection problems more comprehensively and practically, the geological conditions and the injection & extraction plan in the operation period are considered Simultaneously. A case from the S-X area in China indicates that: 1. The improved multi-period optimization model of the natural gas (NG) supply chain can obtain the injection and production plan of UGS which are the basic parameters for the economic analysis. 2. The top potential UGS estimated by geological conditions may take inferior performance in the operation stage (less peak shaving amount, low economic profits, and high freight of NG supply chain), so the UGS investors should consider the potential profits when the finished UGS is put into operation. The proposed framework can be a new theoretical guideline for the site selection problems of UGSs and can help UGS investors judge their investment.

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.

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.

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.

Shale rocks have become an indispensable natural gas and oil source. Hence, the knowledge of the mechanical properties of shales is critical for field applications. In this work, we selected three types of shales (argillaceous, kerogen-rich, and bituminous) and conducted detailed chemical and microstructural characterization along with mechanical property measurements by nanoindentation. The three shale samples have highly distinct mineral compositions. The argillaceous and kerogen-rich shales have soft matrix phases - muscovite and kerogen, respectively. The bituminous shale, on the contrary, has no distinct matrix phase and is rich in carbonates. Young's modulus and hardness were observed to be predominantly affected by the mineral composition. The kerogen-rich shale has the lowest Young's modulus and hardness, followed by the argillaceous shale, while the bituminous shale is the stiffest and hardest. Young's modulus is anisotropic for all shales, but hardness does not follow this trend. The three shale samples also show varied fracture behavior. Apparent cracking and spallation were noted in the argillaceous and bituminous shale, but not in the kerogen-rich shale. Cracks, when activated, tend to propagate along the bedding plane-parallel direction, regardless of the loading direction. We anticipate the new information and knowledge generated from this work has a significant contribution to applications such as drilling and hydraulic fracturing.

Continuous flaring of natural gas remains a great environmental threatening practice going on in most upstream hydrocarbon production industry across the globe. About 150 billion m3 of natural gas are flared annually, producing approximately 400 million tons of carbon dioxide alone among other greenhouse gases. A search into a viable method for natural gas conversion to methanol becomes imperative not only to save the soul of the ever-changing climate but also to bring an end to wastage of valuable resources by converting hitherto wasted natural gas to wealth. Currently the technologies of conversion of natural gas to methanol could be categorized into the conventional and the innovative technologies. The conventional technology is sub-divided into the indirect method also called the Fischer-Tropsch Synthesis (FTS) method and the direct method. The major commercial technology currently in use for production of methanol from methane is the FTS method which involves basically two steps which are the steam reforming and the syngas hydrogenation steps. The FTS method is highly energy intensive and this is a factor responsible for its low energetic efficiency. The direct conversion of methane to methanol is a one-step partial oxidation and lower temperature method having higher energetic efficiency advantage over the FTS method. The direct method occurs at temperature range of 380–470 °C and pressure range of 1–5 MPa while the FTS occurs at temperature range of 700–1100 °C and atmospheric pressure. Both methods are carried out under effect of metallic oxide catalysts such as Mo, V, Cr, Bi, Cu, Zn, etc. The innovative methods which include electrochemical, solar and plasma irradiation methods can be described as an approach to either of the two conventional methods in an innovative way while the biological method is a natural process driven by methane monooxygenase (MMO) enzyme released by methanotrophic bacteria. The aim of this study is to review the current state of the technology for conversion of methane to methanol so as to make abreast the recent advances and challenges in the area.

Water retention curves play a critical role in numerical simulations for predicting fluid production and sediment deformation behaviors in gas hydrate-bearing sediments (GHBSs). This study uses a new testing assembly that combines gas drainage and low-field nuclear magnetic resonance (NMR) tests to determine the water retention curves of artificially synthesized clay silty specimens. The effect of hydrate on the pore size distributions and water retention curves is analyzed via NMR transverse relaxation time curve distributions, and the mechanism of changes in the water retention curve parameters is further discussed. The results show that hydrate formation decreases the proportion of pores with sizes greater than 15 μm and increases the proportion of pores with sizes less than 3.5 μm in clay silty sediments. Hydrate formation increases capillary pressure and prevents available water migration. The presence of hydrate exponentially increases the normalized capillary pressure but exponentially decreases the normalized curve shape factor, yielding narrower curve distributions. The gas entry pressure and curve shape factor exhibit linear correlations with the pore size distribution parameters. The results imply that the changes in the water retention curves are strongly related to the initial pore size distributions. This study offers a deep understanding of capillary effects-related water retention characteristics and their underlying links with the pore size distributions, and demonstrates that low-field NMR has great potential for characterizing water retention curves of GHBSs.

The quantitative characterization of underground transport phenomena remains challenging due to the complex behavior of the gas movement in soil. Conversely, this inhibits the accurate prediction of the risk arising from the underground transport of hazardous materials. This work proposed and qualitatively evaluated a computational model that spans a wide range of underground gas flow regimes, ranging from gas migration, to ground uplift, and crater formation, depending on the release characteristics. The model followed the multiphase Eulerian approach and adopted the standard k-ω turbulence model and the kinetic theory of granular flow for the ground description with the Syamlal-O’Brien granular viscosity expression. The model's optimum configuration was checked against experimental data using a new mechanistic approach to link the qualitative observations with quantitative model outputs. The effect of pipeline pressure, burial depth, and release orientation on the regime was studied and the outcomes were utilized to enhance a literature nomograph for the flow regime identification. Emphasis was given to fill in the literature gaps and improve the delineation of the boundaries between the regimes rather than deriving specific quantities. The resulted nomograph is a cost-effective screening tool to identify the regime and select among the available strategies of risk assessment.

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 CH4, 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.

Liquid surge refers to an excessive liquid inflow to a slug catcher or a separator and is one of the main issues in flow assurance. The wellhead choke valves of gas wells must be adjusted to maintain the target flow rate as the reservoir pressure drops. The wellhead choke opening can be determined by conducting multiphase pipeline transient flow simulations to achieve the target flow rate and avoid liquid surges. However, it is not financially and computationally practical to conduct many multiphase transient pipeline flow simulations simultaneously for hundreds of wells. We found that flow rates and maximum liquid surge volumes for gas wells can be predicted accurately using simple machine learning models when the wellhead choke valve is adjusted. The machine learning models provided accurate predictions (R2 > 0.99) regarding flow rates and maximum liquid surge volumes for different wellhead pressure drop plans, vertical and horizontal well lengths, and current operating conditions in cases involving two real fields, the Horn River Basin (HRB) and Rakhine Basin field. The wellhead operating conditions that are appropriate for achieving the target flow rate and avoiding liquid surges can be efficiently determined using the machine learning models instead of multiphase transient pipeline flow simulators. The proposed approach also accurately estimated downhole pressures that are necessary to evaluate reservoir performances given wellhead pressures and flow rates. Lastly, we presented what features are dominant in predicting liquid surge volumes, flow rates, and downhole pressures in feature importance analyses.

Acid stimulation is commonly used for carbonate reservoirs to enhance wells’ productivity by creating highly conductive channels called wormholes. The success of the stimulation depends on how deep these channels penetrate the formation. Hydrochloric acid (HCl) is commonly used for the carbonate stimulation process with carbon dioxide (CO2) as a byproduct of the reaction between HCl and calcium carbonate (CaCO3). Depending on the operating temperature and pressure, CO2 can form a gaseous phase (bubbles) or be dissolved completely in the fluid. To achieve an understanding of the effect of CO2 bubble formation on wormhole development, we used a low acid concentration (not more than 1 wt% HCl) at a range of flow rates. In this study, an elevated back pressure of 8.2 MPa is applied to keep the CO2 dissolved in the solution and then compared with another set of experiments where no back pressure is applied. Sensitivity runs on various back pressures (while keeping all other parameters constant) are conducted to acquire a detailed understanding of the wormhole behaviour at a range of back pressures (0.1, 2.7, 5.5 and 8.2 MPa). We test the results in the dissolution phase space of Peclet and Damköhler dimensionless numbers. Although we show that for constant flow rate conditions, the existence of gaseous CO2 significantly increases the pressure prior to the wormhole breakthrough, surprisingly no noticeable effect on the wormhole initiation process itself was found.

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 Gmax 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.

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.

Natural gas hydrate is a strategic alternative energy source which are widely founded in seabed sediments. The study of the mechanical properties of hydrate-bearing sediments is the key content to ensure the safe exploitation of gas hydrate. Hydrate occurring mechanisms and saturation are important factors affecting the mechanical properties of hydrate-bearing sediments. In this work, simplified discrete element models that consider the hydrate occurring mechanism, hydrate saturation and confining pressure, were generated based on PFC code. Three main hydrate occurring mechanisms including pore filling, load bearing and cementation were characterized. The triaxial compression simulation was then conducted to investigate the model mechanical properties. The results show that the hydrate of cementation mode has the most obvious strength-enhancing effect on sediments, followed by the load bearing model and pore filling model. Hydrate occurring mechanism also affect the increasing trend of sediment strength and deformation modulus with hydrate saturation and confining pressure. The influence of hydrate occurrence mechanism on the mechanical behavior of sediment is largely controlled by the interaction between hydrate and sand particles interface. The hydrate of cementation mode increases the cohesion of the sediment particles, the hydrate of pore filling mode increases the friction between particles, and the hydrate of load bearing mode has the combined effects of the above two.