Proceedings of the Fifth International Technical Symposium on Deepwater Oil and Gas Engineering

Natural gas hydrate reservoirs in the South China Sea are shallow buried and weakly cemented, making it difficult to drill horizontal well. The accurate prediction of equivalent circulation density (ECD) is the key to the safe drilling of horizontal well in hydrate reservoirs. Therefore, in this study, the ECD prediction model of hydrate formation drilling was established considering the influence of annulus hydrate cuttings decomposition. The influence of key hydraulic parameters such as drilling fluid density, displacement and rate of penetration on ECD was calculated and analyzed, and the leakage risk of hydrate layer was also analyzed. The calculation results show that the hydrate cuttings decomposition area is mainly in the upper annulus of the riser section, which is above 620m in the upper annulus of the riser section under the calculated condition. The ECD whether hydrate cuttings decomposition is considered under calculating conditions is 1060 kg/m3 and 1068 kg/m3, respectively. When the initial drilling fluid density is greater than 1064 kg/m3 and the drilling fluid displacement is greater than 23L/s, there is leakage risk in the reservoir. This study can provide reference for prediction of ECD in deepwater hydrate formation drilling.

Natural gas hydrate (NGH) is one of the great risk for deepwater drilling. The deep water and shallow geological conditions are complex, the soil is loose, the operating pressure window is narrow, the submarine mud line temperature is low, and hydrates are easy to form in the well bore. The drilling fluid is faced with problems such as well bore stability, difficulty in regulating low-temperature rheology, environmental pollution and so on. Therefore, taking the shallow drilling of a deep water well in the South China Sea as the research object, the application status of deep-water shallow drilling fluid is summarized and analyzed, the ECD calculation model and well bore temperature field calculation model is established, and the well bore temperature field distribution and hydrate formation risk during deep-water shallow drilling is analyzed. The hydrate inhibition performance of shallow drilling fluid system is optimized in combination with numerical simulation and indoor experiments. The following research results are obtained. First, compared with the measured data, the average error of ECD calculation model and well bore temperature field calculation model for deep-water shallow drilling is less than 8%; Second, it is calculated that the range of hydrate formation area in the well bore gradually decreases with the increase of drilling depth, but there is still a risk of hydrate formation in the well bore during drilling preparation and early drilling; Third, the conventional semi preventive drilling fluid system is optimized as HEM + 14%NaCl + 6%KCl, which can meet the operation requirements during normal drilling. It is concluded that through the optimization of deep water shallow drilling fluid system, the addition of hydrate inhibitor can be reduced, the drilling fluid formula can be simplified, the drilling cost can be reduced, and the operation efficiency can be improved, which can provide guidance for the drilling fluid design of deep water oil and gas drilling.

In the early production stage of deepwater gas wells, the A-annular pressure increases rapidly. It approaches the casing strength limit due to high-temperature fluid, which seriously threatens the integrity and safety of the wellbore. A wellbore temperature distribution prediction model is established for the safe production of deepwater gas wells based on the energy conservation equation and the wellbore heat transfer processes. Considering the effect of temperature and pressure changes on the physical parameters of the annular fluid, the thermal expansion coefficient and isothermal compression coefficient of the annular fluid are fitted as a function of temperature and pressure, and on this basis, the prediction model and analysis method of the annular pressure during the production of deepwater gas wells are established. The A-annular pressure prediction under variable temperature and pressure conditions is realized. The results show that the prediction error of the prediction model considering only the influence of temperature is significantly greater than that of the prediction model considering the influence of temperature and pressure. The new model is suitable for the prediction of A annular pressure with different production rates and different production times. The prediction error of the model is less than 7%, which provides theoretical guidance for the formulation of the annular pressure control scheme on site.

In the process of shallow deepwater drilling, due to the narrow safety window of drilling fluid density and the frequent drilling in shallow gas, shallow flow, gas hydrate and other factors, the risk of drilling accidents increases, and kick and even blowouts are easy to occur, which seriously endangers the safety of operators. In the absence of risers and subsea blowout preventers, open-circuit drilling is usually used to drill deep water shallow drilling. In the process of open-circuit drilling, drilling fluid directly returns to the seabed, so it is impossible to shut in the well when kick or even blowout occurs, and it is difficult to obtain the shut-in vertical pressure and casing pressure through traditional methods, and it is difficult to calculate the bottomhole pressure, which cannot provide a basis for the selection of parameters such as density and displacement of subsequent kill fluid. Aiming at this problem, based on Fluent numerical simulation software, this paper simulated and studied the return form of drilling fluid at the bottom mud line of open-circuit drilling by solving the VOF model, and analyzed the influence of different ocean current velocity distribution, drilling fluid displacement, gas penetration on the return height of drilling fluid. It is found that ocean current velocity distribution has little influence on drilling fluid return height, and mainly affects the diffusion dilution degree of drilling fluid. Drilling fluid displacement, gas penetration and wellhead pressure have great influence on drilling fluid return displacement and height. On this basis, according to the principle of underwater jet, the relationship between drilling fluid return height and wellhead pressure is established. On the premise of known return height, the wellhead pressure can be calculated, and the bottomhole pressure can be retrieved from the wellhead pressure. This study reveals the regularities of drilling fluid return flow in open-circuit drilling, provides theoretical guidance for the prediction of bottomhole pressure when kick occurs and the well cannot be shut in, provides support for the effective implementation of subsequent well control measures, and ensures the operation safety of deep-water shallow open-circuit drilling.

As reservoir geological conditions in China's oil and gas exploration and development become increasingly complex, drilling operations exhibit narrower safety margins. Drilling risks such as blowouts and losses are more likely to occur, leading to complex flow patterns within the wellbore. Accurately capturing the gas-liquid interface position is crucial for the precise determination of multiphase flow parameters during gas invasion. In this study, we address transient multiphase flow within wellbores and propose a high-resolution upwind numerical method based on the AUSMV scheme and the MC limiter. This method employs the drift-flux equation, AUSMV scheme, third-order Runge-Kutta discretization, and the MC limiter. The reliability of the numerical scheme is validated through typical cases of variable-density gas-liquid two-phase flow, demonstrating that its numerical accuracy is consistent with that of the Roe approximate Riemann solver. Furthermore, a 3500 m straight well is simulated for gas invasion, and the numerical simulations of gas-liquid two-phase flow during wellbore gas invasion show that the use of the third-order high-precision AUSMV scheme can accurately capture the gas-liquid interface during gas invasion, significantly improving the accuracy of multiphase flow parameter calculations during gas invasion in comparison to the traditional first-order AUSMV scheme. This research provides important technical guidance for the development of oil and gas resources and well control safety.

The Lingshui Beipo gas reservoir is located in the northern part of the Qiongdongnan Basin in the South China Sea, and is a typical high-temperature, high-pressure, and low-permeability sandstone gas reservoir developed in the Cenozoic fault basin at the junction of the ancient South China Platform and the ancient South China Platform. The main gas reservoir of this gas reservoir is the Meishan Formation, which is a typical medium porosity and low permeability reservoir with little natural production capacity. Based on the experience of onshore oil fields, hydraulic fracturing is an effective way to achieve industrial production in such reservoirs. However, the risk of fracturing in offshore gas reservoirs is extremely high, and feasibility studies on hydraulic fracturing are urgently needed. Therefore, this article analyzes the basic characteristics and main problems of the Meishan Formation gas reservoir, and conducts a feasibility study on hydraulic fracturing of the Meishan Formation from the aspects of fracture pressure, treatment pressure prediction, gas-water layer analysis relationship, and simulation of fracture height and permeability. Analysis suggests that the use of high pumping rate fracturing may lead to high treatment pressure, small stress differences between the reservoir and barrier layer, which can easily lead to uncontrollable fracture height, and the use of fracturing may lead to communication with the water layer, resulting in water flooding of the gas well. These are key issues that constrain the fracturing of this gas reservoir. A fracture pressure prediction model for the Lingshui North Slope gas reservoir was established using extended finite element method. The predicted fracture pressure of the Meishan Formation was 69-98 MPa, and the predicted treatment pressure was 70-100 MPa. The use of large-sized oil pipes is beneficial for reducing treatment risks. A three-dimensional fracture propagation model was established using the Cohesive pore pressure element. The simulation shows that the pumping rate and liquid volume are the key factors affecting the fracture height. When there is a water layer, the pumping rate should not exceed 6m3/min and the liquid volume should not exceed 250 m3. In the absence of a barrier between the gas and water layers, it is difficult to avoid hydraulic fracturing from communicating with the water layers. Therefore, hydraulic fracturing is not recommended for such reservoirs. The hydraulic fracturing treatment pressure of Lingshui North Slope Gas Reservoir is high, and the risk of communicating with water layers is high. It is necessary to moderately control the pumping rate and scale, optimize the combination of fracturing fluid and pipe string, and reduce the risk of offshore fracturing.

The deep reservoirs in Western China are rich in oil and gas resources and are widely distributed in onshore basins such as the Tarim Basin and the Qaidam Basin. Due to the complex geological conditions and deep burial of carbonate reservoirs in the Tarim Basin, along with a very narrow safety pressure window and large wellbore sizes, controlling wellbore pressure becomes challenging, leading to the occurrence of vicious accidents such as well kicks, wellbore losses, and simultaneous blowouts. Improper handling of these situations can escalate into blowout accidents, severely impacting drilling cycles. This article, based on the drift flow model, establishes a multiphase flow model of the wellbore after gas invasion in large-diameter wellbores and conducts numerical simulations to study the flow behavior of the wellbore under circulation conditions after gas invasion. The results show that under throttling circulation conditions after gas invasion, different hydraulic parameters have varying effects on the gas content in the wellbore. Among these parameters, drilling fluid density has the most significant impact, followed by wellhead backpressure, drilling fluid flow rate, and drilling fluid viscosity. The article also simulates the impact of different wellbore sizes on the gas content in the wellbore and concludes that different wellbore sizes have a relatively minor effect on gas content.

In the course of drilling fractured formation, influenced by drilling parameters and different working conditions, the stress distribution around the well changes, resulting in fracture opening or closing, easy to cause leakage or overflow and other well control accidents. In this study, COMSOL Multiphysics software is used to simulate the stress variation, fracture deformation and gas-liquid two-phase saturation distribution around a well under different drilling conditions and fracture patterns. It is found that the fractures will open in different degrees when drilling vertical and parallel to the wellbore, and the crack opening and permeability will increase gradually with time, the distribution of near-well zone fluid saturation becomes wider, which shows that the drilling fluid gradually invades the fracture with the opening of the fracture and bursts into the depth of the formation Under the action of exciting pressure, fracture width and permeability are larger than those under normal drilling, The two-phase fluid-solid coupling law of fractured formation obtained in this study provides a reference for field well control program.

Sand-carrying annular flow is a commonly observed flow pattern in high-production gas wells, and accurate real-time monitoring of sand particle behavior within the annular flow at the wellhead is essential for efficient industrial production. This study aims to establish a method for identifying particle migration behavior and size in the wellbore's annular flow, utilizing empirical modal decomposition (EMD), statistical analysis, Hilbert-Huang transform (HHT), and convolutional neural network (CNN). Through time and frequency analysis, the study successfully elucidates sand migration behavior, including sand carrying by the gas core (IMF 1) and by the liquid film (IMF 2, IMF 3), and verifies these behaviors. ResNet-50 was determined as the best CNN model for particle size identification, and further optimization of its structure improved the accuracy of particle size recognition by 12% to 83.7%. These findings provide a novel approach to the study of solid phase particle detection in multiphase flow, and may significantly enhance recognition accuracy through model optimization. This methodology offers valuable support for the development of intelligent oilfields.

The experiment of replacing high viscosity and high density completion fluid with low viscosity and low density packer fluid was conducted in a vertical annular tubing. By collecting the inlet flow rate of the pipeline and the interfacial transport at different locations of the pipe section, the topping off efficiency of low viscosity and low density packer fluid replacing high viscosity and high density completion fluid was analyzed. At the same time, the fluid flow in the pipeline during the whole experiment was filmed with a camera, and the mixing flow characteristics between different fluid interfaces were analyzed. The experimental results show that the higher the flow rate of packer fluid injection, the longer the mixing area between different fluids, and although the topping off time decreases, the amount of required packer fluid increases, the less the completion fluid is completely topped off, and the topping off ratio increases slightly. Under the field sealant injection flow rate standard, the amount of sealant required to completely top off the completion fluid in the wellbore is about twice the volume of completion fluid in the wellbore. At the same time, it was observed that the fluid flow in the wellbore annulus was spiral upward, which was similar to the flow pattern of drilling fluid during the drilling process, so the frictional resistance between different fluids and between fluid and tubing wall had a non-negligible effect on the topping off efficiency. The results show that the topping off of low viscosity and low density packer fluid to high viscosity and high density completion fluid can be achieved with a difference of 10 mPa-s in viscosity and 0.5 g/cm3 in density, but the amount of packer fluid used is closely related to the injection flow rate at the wellhead, and the higher the injection flow rate of packer fluid, the more the amount is used. By revealing the flow change law of the packer fluid-completion fluid interface during the completion fluid topping off process, valuable reference is provided for the injection displacement and dosage of packer fluid in the field completion process.

Throughout deep and ultra-deep drilling operations, gases originating from geological formations can ingress into the wellbore via mechanisms such as underbalanced gas infiltration and gravitationnal displacement. Current methodologies for gas intrusion detection predominantly encompass surface flow monitoring, mud pit incremental analysis, and acoustic sensing. Nevertheless, these techniques exhibit suboptimal detection efficiency and an incapacity to promptly recognize early warning indicators of gas infiltration, among other challenges. To tackle the issue of early gas infiltration monitoring, experimental investigations were carried out to evaluate the efficacy of a Polydimethylsiloxane (PDMS) gas separation membrane in conjunction with gas chromatography for the separation of multi-component gas mixtures. The experimental findings indicate that the PDMS membrane demonstrates favorable gas permeation properties with a distinct linear correlation in gas volume fractions between both sides of the membrane. These research results offer vital benchmark data for subterranean gas separation detection technologies.

In order to grasp the in-situ performance and structural characteristics of torch-type leg and cylindrical leg of jack-up platform, the applicable operating water depth ranges of the two legs are obtained. Based on the strength and hydrodynamic calculation theory, taking 375 ft jack-up platform as an example, the in-situ performance and structural and technological characteristics of the two legs are compared and analyzed. The results show that when the water depth is more than 60 m, the platform with torch leg has better environmental resistance and in-situ stability; when the water depth is less than 50 m, the performance of cylindrical leg platform and torch leg platform is similar, but the economic advantage of cylindrical leg is obvious, and it is more suitable for the sea area with smaller water depth. When the water depth is between 50 m and 60 m, the comprehensive performance of torch leg and cylindrical leg is comparable, and the specific selection form can be selected according to the design needs. The conclusions of this paper can guide the selection of pile legs of jack-up platform, and have certain guiding significance for the selection of Engineering design.

Horizontal well with a longitudinal fracture in heavy oil reservoirs is a good method in increasing production. To evaluate the performance of this kind of wells, a rigorous analytical model has been developed to predict the productivity of a multi-layered reservoir drained by a horizontal well with a longitudinal fracture, it rigorously couples flow in a box-shaped drainage volume to flow in the facture, and then to flow in the wellbore. Along with friction, acceleration, and fluid-inflow effect, change in flow regime from laminar to turbulent is also taken into account to describe flow in the wellbore. Calculation results showed that: For a given reservoir size, fluid viscosity and fracture conductivity there exists the only fractured horizontal well specific productivity index. The distribution form of pressure in the fracture is characterized by steop-shaped, pressure loss at the high permeability parts is larger. Fracture conductivity has an insignificant effect on productivity, specific productivity index peak when conductivity is between 15 to 20 Dc·cm. Fluid viscosity has great influence on specific productivity index, lower the viscosity is the key factor for enhancing heavy oil well production.

Poor cementing quality of 9–5/8" casing in the South China Sea high temperature and high pressure (HTHP) gas well leads to severe annular pressure, which hinders the development of HPHT gas fields in Yingqiong Basin, South China Sea. We solve this problem and comprehensively improve the cementing quality by adjusting the specific gravity of mud to increase the safe operation window and create suitable conditions for cementing, combined with pre-flushing technology, rheology matching technology, casing centering technology, and safe & efficient displacement technology to improve the efficiency of flushing and displacement. The practical application of two highly deviated gas wells in Yingqiong Basin of South China Sea shows that this cementing technology has strong operability, successfully overcomes the difficulties of 9–5/8" casing cementing HTHP gas wells, and effectively solves the problem of poor cementing quality of 9–5/8" casing once and for all.

Gas lift is a commonly used method for extracting heavy oil, which has the advantages of simple and reliable construction, free control of depth, and minimal damage to reservoirs. When applied in actual field conditions, there may be issues with accurately assessing oil well production, and the flow characteristics of wellbore fluids during gas lift for heavy oil still require further research. This study employs experimental methods to investigate the flow behavior of heavy oils with different viscosities during gas lift. In this context, 5# white oil, 68# white oil, and 300# white oil respectively represent low viscosity, medium viscosity, and high viscosity scenarios. Air injection is used to simulate the actual field injection of nitrogen. The experiments simulated the variations in wellbore friction pressure drop and total pressure drop under different gas injection rates and liquid flow rates for varying viscosity levels. It can be observed that as the viscosity of the crude oil increases, the impact of frictional pressure drops on the total pressure drop becomes more pronounced. Additionally, the study also examined the characteristics of bottom-hole pressure changes during the experimental process. Analysis of the experimental data indicates that reducing the gas injection rate at the beginning of the injection process can effectively mitigate the negative impact on bottom-hole pressure. Finally, utilizing the images of two-phase flow patterns captured during the experiments and the recorded data, flow regime maps were constructed for different viscosities. This will contribute to improving the accuracy of two-phase pressure drop calculations for highly viscous oil and gas flows.

This research takes a module structure platform project in Bohai as an example, and arranges two different SPMT loading plans for the completed module structure on land, namely the north-south support beam SPMT loading plan and the north-south support column SPMT loading plan. A relevant load out model was established using SACS software, and the two load out schemes were calculated and analyzed. The results were compared, providing a reference for similar modular platform projects in the future to use SPMT loading.

The lifting of the long span “8 + 4” leg split jacket requires the use of a specific lifting frame, where the local structure of the lifting frame insertion sleeve is the key part of the lifting, and it is extremely necessary to calculate and analyze it. This study focuses on a large span “8 + 4” leg jacket and its lifting frame structure in China. A lifting model of the “8 + 4” leg jacket was established using SACS software and its overall calculation and analysis were conducted. However, due to the limited computing power of SACS software for local structures, this study extracts relevant boundary conditions of the target local structure of the model based on the overall calculation and analysis of SACS, and combine ABAQUS to model, calculate, and analyze the local structure of the insertion sleeve, in order to provide reference for the engineering site.

The development of horizontal wells is one of the important means to increase the production of natural gas hydrates in offshore areas and accelerate the commercial exploitation of natural gas hydrates. However, due to the characteristics of the natural gas hydrate reservoirs in the South China Sea, such as poor geological consolidation, small pressure gradient of formation fractures, and narrow safety windows, it is easy to cause problems such as leakage of target layers, formation collapse and key grooves, as well as secondary generation of hydrates during the construction of horizontal wells. The combination of downhole casing and drilling fluid technology is one of the important ways to solve the problems encountered during the process of horizontal well development. Based on the information from a deep water shallow high-building rate horizontal well in a certain area of the South China Sea, this study used the downhole casing method with riserless drilling technology for the first time in the deep water area. Taking into account the characteristics of shallow-buried formation, large inclination angle, and shallow burial depth of the inclined and horizontal sections at the wellbore during the drilling process, drilling fluid technology measures before casing are proposed, and the stress analysis and effect of two casing times in the horizontal well are compared. Combining with the stress characteristics of downhole casing in this well, the key technologies such as wellbore cleaning, lubricity, and wellbore stability in the highly inclined section and horizontal section are discussed respectively. By optimizing the drilling fluid technology during the downhole casing period, this study provides construction guidance and technical support for the development of shallow-soft mineral resources such as natural gas hydrates and deep-water shallow gas reservoirs in the South China Sea.

High speed metal jet in perforating operation penetrates the oil and gas reservoir and forms a compaction zone near the hole, which causes damage to the porosity and permeability of the reservoir and seriously affects the productivity of oil and gas wells. At present, the traditional experimental methods are mainly used to evaluate the perforation damage. These methods are only a general qualitative and quantitative evaluation of single perforation technology or perforation target compaction zone damage, but they do not analyze and evaluate the damage characteristics and damage degree of sandstone target after perforation from point, line, surface, axial and radial perspectives of perforation channel, and have not compared the damage degree of sandstone target perforated by different perforation technology and charge type conditions. Therefore, a new method for quantitative evaluation of damage degree of sandstone target under different perforating technology or charge type is proposed, which can realize the multi-dimensional perforation damage characteristics of macro plane (point, line, surface) and along the axial and radial direction of perforating channel. Through the experimental study of four groups of perforating charges or perforating technology, the zonal characteristics of perforating target permeability zone are defined, and the quantitative evaluation of sandstone perforation compaction damage degree is realized. It is revealed that negative pressure perforation can reduce the damage rate and thickness of the compacted zone. There is a strong linear relationship between perforation depth and compaction zone area, perforation depth and average compaction thickness. The deeper the perforating charge penetrates, the greater the permeability damage rate of the compacted zone, and it shows logarithmic relationship. The new method has important engineering guiding significance for understanding the damage mechanism of perforated sandstone, quantitative evaluation of damage degree, improvement of perforating technology, optimization of perforating charge and suggestion of reducing perforation reservoir damage.

Deepwater oil and gas resources are abundant and prone to induce Borehole Ballooning due to narrow safe density window, fractured formation and wellbore pressure fluctuation. A wellbore-formation coupling model was established by considering the flow moiré calculation, fluid compressibility and flow path expansion of different fluids in different situations, combined with a wellbore fracture deformation model considering fracture opening and equivalent damage radius, and then combined with the field data to determine the initial and boundary conditions, and numerically solved the continuity equations and the equations of motion by applying the method of eigenlines. Combined with the actual data of Borehole Ballooning in Mexican wells, the programmed calculations were carried out, and the results show that the influence of starting and stopping the pump on Borehole Ballooning should not be neglected, and the change of Borehole Ballooning under different flow rates was simulated respectively. Compared with the change of Borehole Ballooning without Borehole Ballooning, Borehole Ballooning corresponding to Borehole Ballooning changes slower, and it takes a longer time for Borehole Ballooning to reach a stable pressure, and the bigger the change of pumping speed is, the more obvious is Borehole Ballooning. The larger the pumping speed change, the more obvious the respiratory effect, the more respiratory leakage and return, and the respiratory return is slightly smaller than the respiratory leakage.

In deepwater drilling gas invasion monitoring, existing conventional platform monitoring methods face issues such as delayed warning times and low monitoring accuracy. Downhole drilling-with-while-logging acoustic gas invasion monitoring, characterized by its non-intrusiveness, timeliness, and stability, has emerged as one of the directions for improving gas invasion monitoring during drilling operations. To explore the mechanism of downhole sonic gas invasion monitoring, this paper conducts a study on the applicability of acoustic propagation models in multiphase media. We compared five mathematical models: the EACH model, McClements model, Urick model, HT model, and BLBL model. Each model’s computational form and parameter selection range were described, and we investigated the propagation velocity and attenuation of sound waves in multiphase flowing media within the wellbore. An analysis of the suitability of each model under downhole conditions was provided. We propose a method that combines the HT model with the BLBL model for downhole acoustic propagation calculations. The research findings provide a theoretical foundation for further exploration of sonic gas invasion monitoring during drilling operations and offer valuable insights for subsequent engineering applications.

In the process of developing natural gas hydrates in the sea, the high-pressure and low-temperature environment near the mudline is prone to causing the decomposed gas and water to regenerate hydrates, causing pipeline blockage and reducing production efficiency. Traditional prevention methods for secondary hydrates often use methods such as excessive injection of thermodynamic inhibitors and electric heating, but they all have problems of low efficiency and high cost. At present, research on low-dose inhibitors (kinetic inhibitors, anti-agglomerants) has become a hot topic in this field. This study investigated the inhibition performance of a new type of anti-agglomerant suitable for gas-water system through high-pressure stirring vessels. Through experiments, a highly effective inhibitor suitable for gas-water system was selected as cocamidopropyl dimethylamine (PKO). The effects of mass fraction of PKO on hydrate induction time, formation rate, conversion rate, and torque were investigated. It was found that although it can significantly reduce the induction time of hydrates, increase the rate of hydrate formation, and promote its formation, the generated hydrates are loose, significantly reducing the torque of the stirring kettle. In engineering applications, it is manifested that under the action of PKO, the generated hydrates are dispersed and transported in the gasflow without agglomeration, effectively ensuring the safe and efficient transportation of the wellbore. At the same time, the improvement of hydrate conversion rate further improves the gas transportation capacity. Through further experiments, it was found that the mass fraction at which PKO can exert the optimal inhibition effect is the critical micelle concentration (CMC), and the inhibition mechanism of PKO in the gas-water system was revealed, providing a new prevention and control approach for the secondary hydrate blockage problem in the natural gas hydrate extraction process in the sea area.

High-pressure and low-temperature conditions for hydrate production are highly prone to occur during deep-water development, which may cause serious hydrate deposition problems. Current studies on hydrate deposition have mainly focused on through-diameter conditions, and relatively few studies have been conducted for reduced-diameter conditions. In this paper, a hydrate deposition model considering hydrate particle-fluid-pipe wall interaction is established based on the adhesion and rebound criteria of hydrate particles. The effects of important parameters on the deposition characteristics of micron-sized hydrate particles are investigated, and the deposition mechanism of hydrate in the reduced-diameter pipe is revealed. The results of the study can provide a valuable reference for the study of hydrate flow assurance in deep water.

Hydraflow technique has been proposed for the prevention of hydrate problems in the offshore oil and gas transportation. Therefore, it is of great significance to develop effective hydrate anti-agglomerants (AAs) and clarify the hydrate characteristics in the presence of AAs. In this study, the formation and agglomeration characteristics of methane hydrate in oil- water system in presence of the developed hydrate AAs was investigated using the high pressure stirring cell at the AA concentration of 0–2.0 wt% and water cut of 10–60%. For runs at the water cut of 30% and 60%, it was found that the agglomeration of hydrate exhibited two separate modes with the increase of hydrate volume fraction. At the low hydrate volume (usually <10%), the hydrate can be dispersed in liquid phase due to the dispersed hydrate particle, and the relative current slowly increased. The AA concentration has little influence on the hydrate agglomeration. Then with the proceeding of hydrate formation process, the agglomeration of hydrate can be significantly enhanced with the increase of hydrate volume fraction. In this stage, the agglomeration of hydrate can be significantly mitigated with the increase of AA concentration. Results showed that the hydrate induction time can also be prolonged by the addition of the developed AA. At the water cut of 60%, the addition of 0.5 wt% AA can delay the hydrate induction time by 9.1 h. In presence of 0.5 wt% AA and in the water cut range of 10–50%, the system with 40% water cut was found to be with the highest hydrate plugging risk. With the formation and agglomeration of hydrate, the relative current significantly increases by 16 times.

Hydrate reservoirs with underlying natural gas are currently considered to be the most promising hydrate reservoirs for commercial exploitation. However, during the production process, the temperature-pressure conditions and multiphase flow conditions after mixing are complex due to the differences in the physical parameters of each layer of fluid, and it is much more difficult to predict the secondary formation of hydrates. In order to accurately calculate the hydrate generation regions, a new prediction model of wellbore temperature and pressure field under the conditions of deepwater dual-source co-production was proposed, and the distribution pattern of the hydrate generation region in the wellbore was investigated based on this model. The results revealed that in the process of deepwater dual-source co-production, due to the influence of deepwater low-temperature environment, the section of gas line above the mudline had an extremely higher risk of hydrate formation. For the section of wellbore below the mudline, the inflow of relatively low-temperature fluid from the hydrate layer caused a sudden temperature drop in the wellbore, resulting in a corresponding increase in the risk of hydrate formation. Meanwhile, the larger the production rate of hydrate layer, the more obvious the temperature drop was. Hydrate production increased from 2 thousand m3/d to 300 thousand m3/d, temperature drop increased from 2.8 ℃ to 7.1 ℃, the hydrate generation region expanded from 200 m–1780 m to 20m-1900m. With the increase of shallow gas production rate, the temperature in the wellbore rose, the cooling effect of hydrate layer fluid weakened, and the risk of hydrate formation decreased accordingly. Shallow gas production increased from 10 thousand m3/d to 600 thousand m3/d, temperature drop decreased from 3.1 ℃ to 1.5 ℃, no hydrate generation below the mudline, and hydrate generation area above the mudline shifted upward from 180 m–1770 m to 0 m–690 m. The increased in shallow gas water content removed hydrate generation risk from wellbores below the mudline, but had little effect above the mudline. Reduced gas-liquid separation efficiency resulted in increased liquid production in the gas pipeline, a shift in the phase equilibrium curve toward lower temperatures, and a slight reduction in the risk of hydrate generation. The results of this paper can provide a reference for the prevention of secondary hydrate generation in the wellbore of deepwater dual-source co-production.

During the development of natural gas, from the wellhead of the gas well to the treatment station, the natural gas is not dehydrated or separated, so it could easily form hydrate in the low temperature season, resulting in hydrate blockage of the pipeline, leading to serious economic losses and even casualties. Therefore, it is of great practical significance to study the tendency of hydrate plugging in natural gas gathering and transportation pipelines. In this paper, a set of indoor experimental apparatus was built to simulate a natural gas gathering and transportation pipeline. By using this experimental apparatus, CO2 gas was used to replace natural gas to carry out experiments, and the influence of different water content, flow rate, choke and production conditions on the hydrate blockage in the natural gas gathering and transportation pipeline was explored. The experimental results show that when water and CO2 are injected into the experiment apparatus at the same time, the plugging is expected to occur within 30 min to 1 h, resulting in the increasing pressure drop; slug flow and hydrate plugging are more likely to occur in the experimental pipeline when the water content is larger. When there is choke in the pipeline, blockage is prone to occur at the main choke or diameter reduction. When a blockage occurs somewhere in the pipeline, its high-pressure side is in the temperature and pressure region of hydrate generation, which may develop into a multi-position blockage. When the pressure is maintained in the pipeline and there is free water, when left for 6 h or more, it could form a multi-point blockage, and the blockage location is not limited to the choke position.

With the continuous advancement of oil and gas exploration into the deep sea, polar regions, and other regions, the transportation pipelines of oil and gas have become increasingly important. However, the high-pressure and low-temperature environment makes pipelines prone to hydrate blockage, which can cause severe damage to oil and gas transportation pipelines and significant economic losses. Therefore, predicting the hydrate deposition situation in pipelines to formulating corresponding flow assurance measures is crucial. This article uses OLGA software and combines actual operating conditions to establish a hydrate deposition model to simulate the hydrate deposition situation of the pipeline, and the Elman neural network prediction method is built to predict the volume fraction of pipeline hydrates, which fluid temperature, ambient temperature, outlet pressure, inlet pressure, flow rate, and heat transfer coefficient as input parameters, the maximum hydrate volume fraction in the pipeline as the output parameter. In addition, the Elman neural network prediction method was optimized using the genetic algorithm to improve prediction accuracy. The results show that the correlation coefficient of the predicted and actual values is 0.9719, and the RMSE, MAE, MSE of the GA-Elman neural network prediction model are 0.0293, 0.0267, and 0.0008, respectively, which can accurately predict pipeline hydrate deposition and providing some reference and guidance for pipeline hydrate prevention and control.

In the process of marine gas hydrate exploitation, the decomposed gas and water of reservoir are easy to reform hydrate in the pipeline near the mud line, which causes serious flow guarantee risk. Due to the limited efficiency of gas-liquid separation in the production system, bubble flow can be formed in the drainage pipeline. Based on the continuity equation, momentum equation, temperature distribution equation, hydrate phase equilibrium model and hydrate formation rate model, the prediction model of hydrate reformation is established. The influences of the water production rate, ESP pressure on the temperature distribution, hydrate formation rate, hydrate volume fraction and multiphase flow pressure drop in the drainage pipeline were investigated. It is found that the increase of ESP pressure will magnify the hydrate formation region and the degree of subcooling, the increase of water production rate will increase the slurry flow rate in the drainage pipeline, which both lead to a significant rise in hydration formation rate and volume fraction. High ESP pressure and water production rate are the main source of safety risk of hydrate flow in the drainage pipeline. This study can provide a basis for the prediction of the hydrate reformation in the drainage pipeline during the production of marine gas hydrate, and lay a theoretical foundation for the efficient prevention and treatment of hydrate reformation.

With the advancement of the global oil and gas resources exploitation process, the water production of oil and gas fields increases year by year, and the temperature and pressure of the reservoir and wellbore change dramatically, which makes the formation water scaling problem especially serious. The scale generated in oil and gas fields will block the wellbore, reduce the area of oil and gas circulation in the wellbore, and the oil and gas transportation efficiency will decrease, and the scaling in the near-well zone will lead to the decline of formation permeability, and in more serious cases, it will even lead to the scrapping of oil and gas wells, increase the maintenance cost of wells, and reduce the economic benefits of oil and gas fields.In this paper, we investigated the scaling law of formation water through high temperature and high pressure scaling experimental device, and determined the consumption of calcium ion concentration through EDTA titration experiment to derive the influence of temperature, pressure, pH to investigate the influence of environmental changes on the generation rate of calcium carbonate scale. The experimental results show that as the temperature increases, the scaling rate of formation water gradually becomes larger, but the effect of changing the pressure on the scaling rate of formation water is not obvious, and the increase of pH value will increase the scaling tendency of calcium carbonate scale in formation water. Therefore, it is possible to change the scaling tendency of formation water by changing the environmental conditions around the formation water in the production site, which provides a theoretical basis for the formulation of the scaling prevention and control program for oil and gas wells.

Gas-liquid churn flow is one of the most common flow patterns in gas well production. A profound understanding of the distribution of the droplet size and velocity distribution is of utmost importance for the calculation of pressure drop and prediction of liquid loading in gas well. This study explores the distribution of droplet size and velocity in churn and churn-annular flow. Based on experimental data, a new model for the droplet Sauter mean diameter, d32, in churn flow is proposed. In this study, the droplet size and three velocity components of stirred flow and stirred circulation were measured using a phase Doppler anemometer (PDA). The distribution of size and velocity of droplets were then analyzed, and the change of droplet size and slip ratio under different gas and liquid flow rate is obtained. Finally, a new correlation of the Sauter mean diameter was proposed by using the correlation coefficient to fit the experimental results. The experimental results shows the size of droplet decreases significantly as the superficial gas velocity increases, the effect of liquid phase velocity on droplet size is not obvious. Droplet size is mainly distributed around relatively small values (100 μm < d < 200 μm) with a uniform distribution, and only a few large droplets (d > 200 μm) exist. The droplet axial velocity decreases with increasing droplet size, smaller droplets have greater axial speed range. The axial velocity of droplet increases while the radial velocity decreases during their migration from the liquid film to the centerline. This new correlation of d32 agrees well with experimental data and reduces the mean relative error between experiment and model to 9.4%. This work provided an experiment study on droplet size and velocity distribution in churn flow and churn-annular flow, and a new correlation for the Sauter Mean Diameter was proposed, which significantly improved the prediction accuracy of droplet size and can be useful to the two-phase pipe flow modeling in liquid-producing gas wells.

Oil and gas pipelines operate under low temperature and high pressure, hydrate is easy to form and then block the pipelines, which poses a great threat to the safety of oil and gas storage and transportation. Our laboratory built a test system for hydrate formation in the loop, and tested the resistivity changes of hydrate formation in four sets of 85% methane and 15% propane systems and two sets of pure methane systems. The time of resistance sudden change to relative stability is estimated, and the average value of 100s before and after the resistance sudden drop is compared. The experimental data show that the formation of hydrate will lead to a sudden drop in resistance, and with the continuous formation of hydrate, the resistance will have a certain trend of rise. And that is an early warning signal of hydrate formation.

Natural gas hydrate is a kind of ice-like crystal compound, which is usually formed under the environmental conditions of coexistence of gas and water with high pressure and low temperature. The hydrate generated in the pipeline usually causes blockage, which will bring serious safety problems and economic losses to the process of natural gas exploitation and transportation. Oil and gas gathering and transportation pipelines in China are hundreds of thousands of kilometers long, and there is a common risk of gas hydrate blockage, so it is urgent to effectively ensure flow safety and reduce the risk of blockage. In this paper, a kind of compound hydrate inhibitor with different ratio was evaluated from inhibition effect, hydrate formation rate and induction time. A good ratio was obtained by simulating the actual production condition in gas pipeline through the tube rocking apparatus. It can provide reference for inhibiting hydrate formation in natural gas pipeline.

Hydrogen (H2) is a promising clean energy source for high energy density and clean combustion products. Hydrogen storage and transport are bottlenecks of the utilization of hydrogen energy. Gas hydrates could store hydrogen molecules at moderate temperatures and pressures, offering a technology of safe, cheap hydrogen storage. However, low hydrogen storage is a major problem in developing large-scale hydrate-based hydrogen storage. In this study, in order to increase the hydrogen storage capacity, we use Sulphur hexafluoride (SF6), which can form sII hydrates, and tetrabutylammonium bromide (TBAB), which forms semiclathrate hydrates, to construct a double structure hydrate storing hydrogen. The experimental temperature was set at 274 K, and the H2 pressure was around 20 MPa. The concentration of TBAB solution ranged from 0 wt% to 40 wt%. The highest H2 storage appeared at 5 wt% of TBAB with 20 wt% SF6. The capacity of H2 reached 32 V/V (about 0.324 wt%), which is an increase of 15% compared with no TBAB added. This is due to the fact that in the early stage of hydrate formation, TBAB first form semiclathrate hydrate with water, which increases the nucleation site of sII hydrate. The coupling structure of sII and semiclathrate hydrates increases the hydrogen storage. However, as the TBAB increases, it is easy to form larger particles of TBAB hydrates. This process expends a large number of water molecules, which decrease the formation of sII hydrates, and lower the H2 storage. Raman spectra of samples with TBAB revealed that the Raman characteristic peaks of SF6 and H2 increased towards higher wave numbers compared with samples without TBAB. This showed that the introduction of TBAB increased the binding energy of the hydrate cages, enhancing the hydrogen hydrate stability.

Natural gas hydrates, as a novel gas separation technology, hold significant promise for the separation of CO2 from flue gas. In this study, a comprehensive analysis integrating hydrate-based technology and membrane separation technology is conducted to establish a post-combustion CO2 capture process. The heat calculation of the hydrate unit in the separation process is performed based on experimental CO2/N2 hydrate separation data, leading to a heat value of 1,104,662 MJ/h for the formation and decomposition of hydrates. In the membrane separation unit, the mathematical model of hollow fiber membranes is employed to conduct an optimization process for the membrane area and inlet pressure. The optimization objectives focus on attaining a product gas with a CO2 concentration of 90 mol% and a CO2 recovery rate of 95%. As a result, the first-stage membrane area is determined to be 8000 m2 and the inlet pressure to be 1.45 MPa, while for the second-stage, the optimal values are found to be 5000 m2 for the membrane area and 2.00 MPa for the inlet pressure. Finally, following the optimization of the energy consumption throughout the entire process, a comprehensive analysis is carried out to assess the energy consumption and energy efficiency of the process. The findings reveal that the most significant energy losses in the process occur during the initial pressurization phase of the feed gas and the subsequent formation and decomposition stages of the hydrates. Additionally, the unit energy cost for CO2 capture is calculated to be 0.4416 kWh/kg CO2. In comparison to alternative post-combustion CO2 capture technologies, this process exhibits distinct advantages.

Solidified Hydrogen Storage is the cleanest hydrogen storage method, which has a unique advantage from other traditional hydrogen storage methods, and is a relatively ideal and promising hydrogen storage technology. Among them, the use of sII type hydrogen hydrate to store hydrogen is the focus of current research, but its dissociation process and stability law are still unclear. In order to reveal the stability rule of hydrogen hydrate under low pressure, low pressure dissociation experiments were conducted on four types of sIIhydrogen hydrate, THF, 1, 3-DIOX, ECP and CP. The dissociation rule of four types of sII hydrogen hydrate under different temperatures was studied mainly by direct depressurization method. The results show that when the temperature is 248K, the dissociation ratio of hydrogen hydrate is as follows: CP-H2 > 1,3-DIOX-H2 > ECP-H2 > THF-H2; when the temperature is 253K, the dissociation ratio of hydrogen hydrate is as follows:CP-H2 > ECP-H2 > 1,3-DIOX-H2 > THF-H2; when the temperature is 258K, the dissociation ratio of hydrogen hydrate is as follows: 1, 3-DIOX-H2 > CP-H2 > ECP-H2 > THF-H2; when the temperature is 264K, the dissociation ratio of hydrogen hydrate is as follows: THF-H2 > 1,3-DIOX-H2 > ECP-H2 > CP-H2;when the temperature is 268K, the dissociation ratio of hydrogen hydrate is as follows: CP-H2 > 1, 3-DIOX-H2 > ECP-H2 > THF-H2; when the temperature is 273K, the dissociation ratio of hydrogen hydrate is as follows: 1,3-DIOX-H2 > THF- H2 > ECP-H2 > CP-H2. It is also found that the abnormal dissociation temperature range of the four hydrogen hydrates is 248K-273K, and the dissociation ratio of 1,3-DIOX-H2 hydrate is the lowest at 258K, which is 49.23%. The lowest dissociation ratio of THF-H2 hydrate is 46.38% at 268K. At 273K, the decomposition rates of ECP-H2 and CP-H2 hydrate are the lowest, which are 42.3% and 40.45%, respectively. Hydrogen hydrate must be stored below 273K, but the lower temperature is not the better. The research results provide a theoretical basis for the stable storage and transportation of Solidified Hydrogen Storage under low pressure. Stable storage of hydrogen hydrate under low pressure without dissociation is feasible in principle. It is recommended that further systematic experiments be conducted to explore stable preservation at lower pressures.

With the rapid depletion of non-renewable fossil fuels that produce greenhouse gas, hydrogen is poised to emerge as a leading clean energy source in the future energy structure. However, a significant challenge in establishing a hydrogen economy for countries with uneven energy distribution is the development of efficient and low-cost hydrogen storage technologies. Therefore, current study proposes the technology of hydrated hydrogen storage and conducts a comprehensive study of the entire system composed of hydrogen hydrate production, transportation and regasification by 3E analysis (energy, exergy, and economic). The results indicate that the specified power consumption (SPC) of the entire system is 7.46 kWh/kg H2, with the SPC of the hydrogen storage process being 4.02 kWh/kg H2. The exergy loss of the system is mainly in hydrogen storage process, with exergy efficiency of 35.65%. Additionally, at a capacity of 1TPD (tons per day), the estimated levelized cost of hydrogen (LCOH) is 28.12 CNY/kg H2. Sensitivity analysis is incorporated to assess how the scale, distance, and electricity cost influence the LCOH eventually. It can be seen that scale and distance are the main factors affecting the cost, so the technology is suitable for medium-scale and short-distance hydrogen transportation. The miniaturization and low energy consumption of hydrated hydrogen storage technology lay the foundation for its industrial development, and the entire system is theoretically feasible. It is recommended that numerical simulation studies be conducted on hydrate formation unit in the future to accelerate the industrialization process of hydrate storage technology.

The electric field plays a significant role in the induction of natural gas hydrate formation, leading to its rapid generation. This study investigates the formation of hydrogen gas hydrates under different electric field conditions using molecular dynamics simulations. The results demonstrate that the electric field intensity has a pronounced impact on hydrate formation. An electrostatic field inhibits the growth of hydrogen gas hydrates, while a cosine field promotes their formation. The effect becomes more evident with increasing electric field intensity, whereby a static field of 2.0V/nm generates a distinct icelike structure. Furthermore, the electric field selectively influences the quantity of different cage types. The electric field facilitates/suppresses hydrate formation by inducing the directed arrangement of water molecules, whereas the cosine field increases the chances of water molecules contacting and growing with hydrate clusters. These findings are of significant importance for understanding the mechanistic influence of the electric field on hydrate formation processes.

Carbon dioxide (CO2), as a typical greenhouse gas, has gradually attracted attention for its capture and storage. Storing CO2 in the form of hydrates in clay sedimentary layers has been considered a promising method for controlling greenhouse gases. Although relevant experiments have been conducted to study the formation of CO2 hydrate in clay minerals, the molecular mechanism of the influence of clay surface on the nucleation and growth of CO2 hydrates in different salt concentration solution environments still deserves further exploration. In this study, molecular dynamics (MD) simulations were used to investigate the effect of lattice substituted montmorillonite (Mnt) surfaces on the nucleation and growth of CO2 hydrate under different salt concentrations. The results indicate that the nucleation and growth of CO2 hydrates occur in areas far from the surface of Mnt minerals. Compared to pure solution systems, the presence of Mnt minerals results in a lower growth rate and final amount of CO2 hydrates. In addition, the nucleation and growth of CO2 hydrates are significantly inhibited by salt ion solutions. The formation probability of the cage structure of CO2 hydrates is significantly affected by the presence of clay mineral layers and salt ions, resulting in significant nucleation and growth barriers for CO2 hydrates. High concentrations of salt ion solutions can significantly affect the nucleation rate of hydrates. The results of this study clearly indicate the synergistic effects of clay mineral surface and salt ions on the CO2 hydrates formation, which has important reference value for CO2 storage in clay reservoir environments with different concentrations of salt ions.

Hydrates, which serve as a novel form of clean energy and a key component in carbon capture and storage (CCS), require a thorough understanding of their phase transition mechanisms within porous media for the effective implementation of related technologies. In this study, a microfluidic chip was developed to emulate subsurface porous media and phase transition experiments were performed on cyclopentane (CP) hydrates. By means of microscopic observation, we analyzed the influence of an applied electrostatic field under identical subcooling conditions on hydrate morphology, growth rate, induction time, and equilibrium temperature. The results show that the application of an electrostatic field has the ability to alter the growth morphology of CP hydrate crystals, shortening the induction time, although lowering the phase equilibrium temperature. Furthermore, both the induction time and the phase equilibrium temperature increase with increasing electric field intensity. Under the influence of an electrostatic field, the growth rate of CP hydrates exhibits a noticeable enhancement, with an initial increase followed by a subsequent decrease as the electric field intensity escalates. This study provides valuable insights into the application of electric fields in hydrate development and hydrate-based CCS technologies.

Natural gas hydrates are crystalline structures formed by the combination of water and natural gas under specific temperature and pressure conditions. They hold tremendous potential as a viable alternative energy source. However, the field of natural gas hydrates faces widespread challenges, including low gas production rates and uneven gas production. In order to achieve low-enthalpy and sustainable methane hydrate production, this study conducted methane hydrate sample reshaping within sediments with varying initial water saturation levels. The research investigated the gas production behavior of methane hydrates within sediments characterized by different initial water saturation under varying production temperatures. Additionally, it employed a no-solid-phase dissociation technique to study the gas production behavior of methane hydrates within sediments at temperatures below the freezing point. The results indicate that, compared to the dissociation process of hydrates above the freezing point, the gas production behavior of hydrate reservoirs at a dissociation temperature of 272.15 K exhibits a delayed response with prolonged slow dissociation times. Lower temperatures are advantageous for sustaining gas production rates. Notably, the no-solid-phase dissociation method exhibits significant superiority, particularly in high water saturation reservoirs. Within high water saturation reservoirs, methane hydrates at 272.15 K exhibit an increased dissociation rate, rising from 68% at 278.15 K to 78%. In the case of hydrates below the freezing point, the controlling step for no-solid-phase dissociation is identified as the gas diffusion process. This method effectively mitigates the hindrance imposed by the water layer on gas diffusion, ensuring enhanced mass transfer efficiency.

Gas hydrates are ice like crystalline substances formed by host water molecules and guest gas molecules under certain temperature and pressure conditions. Hydrate technology has important applications. Fields such as CO2 capture, natural gas transportation, refrigeration, gas separation, and seawater purification. During the process of hydrate formation, hydrogen bonds are formed between water molecules to form a cage like structure, while guest molecules form hydrates in the cage. However, water molecules do not exist in the form of individual molecules, but rather water molecules are connected by hydrogen bonds to form water molecular clusters. The experimental results show that several water treatments can change the size of water molecule clusters, among which microwave, ultrasonic, and freezing treatments can make water molecule clusters smaller and hydrated water molecule clusters larger. Different water samples and untreated deionized water also exhibit different phenomena during hydrate formation. For example, the subcooling of deionized water at the beginning of generation is 4.6 ℃, and the maximum growth rate during growth is 8.50%/h, while the water treated with microwave is divided into 150s, 200s, and 250s according to the treatment time. The subcooling at the beginning of generation is 5.7 ℃, 5.6 ℃, and 4.1 ℃, and the maximum growth rate is 5.61%/h, 13.08%/h, and 8.01%/h, The phenomenon of promoting hydrate growth has occurred; The water treated by ultrasound is divided into 1 h, 2 h, and 3 h according to the treatment time. The initial subcooling generated is 5.1 ℃, 6.5 ℃, and 6.3 ℃, and the maximum growth rates are 4.47%/h, 3.77%/h, and 6.35%/h. There is a phenomenon of inhibiting hydrate formation, and different phenomena will also occur for hydration and freezing treatment. In this experimental study, the effects of several water treatment methods on water molecular clusters and the formation of hydrates were mainly explored. Other methods that affect water molecular clusters in future work are also worth studying.

The phase equilibrium prediction of gas hydrate plays an important role in solving hydrate blockage in oil and gas transmission pipeline and realizing hydrate commercial exploitation. At present, the phase equilibrium prediction of methane hydrate in pure water system is quite perfect. However, there are few studies on the hydrate phase equilibrium of gas mixtures, especially those with high CO2 content. In this paper, based on Chen-Guo model, the hydrate phase equilibrium model is simplified by using the activity in the model measured by water activity meter, so as to achieve the purpose of rapid prediction of hydrate phase equilibrium conditions. In this paper, the phase equilibrium conditions of mixed gas hydrate in KCl, NaCl, HCOONa, HCOOK, MEG and other solutions and mixed solutions are predicted, and verified by hydrate phase equilibrium apparatu.

With the increase of global energy demand and the gradual depletion of traditional energy resources, natural gas hydrate (NGH) have attracted much attention because of their large reserves. At present, the main methods of hydrate extraction include depressurization, thermal stimulation and chemical inhibitor injection, etc. However, all of them suffer from the problems of low gas production and short stabilization time, which leads to the fact that hydrate has not yet been commercially exploited. In the extraction process, there exists a transition front region between hydrate dissociation zone and hydrate undissociation zone, and the fast or slow movement rate of the dissociation front will affect the hydrate extraction effect, so it is of great significance to study the movement regularity of the dissociation front of natural gas hydrate. In this paper, one-dimensional and three-dimensional models are established by numerical simulation to analyze the movement regularity of the dissociation front in the dissociation process of natural gas hydrate. The study shows that: in the one-dimensional and three-dimensional models, the dissociation front has a similar moving regularity, the dissociation front A moves rapidly and then nearly linearly, the dissociation front B moves slowly at the beginning, and then the moving rate becomes larger rapidly at the later stage of dissociation; under the same parameters, the moving rate of the dissociation front in the one-dimensional model is much larger than that in the three-dimensional model; with the saturation of the hydrate decreasing, the permeability increasing, the bottom hole pressure decreasing, the thermal conductivity increasing, the moving rate of hydrate dissociation front becomes faster gradually. The results of the study can provide a reference for the effective prediction of hydrate dissociation location and the early realization of commercial exploitation.

Natural gas hydrate (NGH) has attracted increasing attention as a promising source of clean natural gas, but its exploitation also presents technical challenges and geological concerns. Recent studies and the success of the second NGH production test in the South China Sea suggest that horizontal wells have the potential to enhance the recovery of low-permeability NGH reservoirs. Nevertheless, the rapid depressurization due to horizontal well extraction increases effective stress within the reservoir, triggering reservoir deformation and seafloor subsidence. Additionally, certain NGH reservoirs have been demonstrated to exhibit a multi-layered structure with complex phase conditions, including the hydrate-bearing layer (HBL), the three-phase layer (TPL), and the free gas layer (FGL), introducing additional uncertainties into the production process. Based on geological data from Site W17 in the South China Sea, this study conducts an optimization analysis of horizontal well placement, considering both natural gas production behavior and seafloor subsidence risks. The results indicate that the maximum gas production was obtained when the well placement was in FGL. However, simultaneously, the water production was 1,126% and 570% higher compared to the well placement in HBL and TPL. Furthermore, the maximum seafloor subsidence was observed to reach 0.42 m, 0.19 m, and 0.54 m when the well placement was in HBL, TPL, and FGL, respectively. Production within the TPL layer resulted in less geologic risk while achieving approximate gas production. Therefore, the optimal well placement for horizontal wells is determined to be within the TPL.

The degree of screen plugging limits the increase of hydrate well production in the process of natural gas hydrate (NGH) reservoir development. In order to improve the permeability performance of the screen after plugging to reduce the impact on NGH well production, a new 4-cavity composite pre-filled screen with the function of gas-water diversion was designed filled with hydrophobic gravel and conventional gravel staggered. A series of experiments were carried out to verify and compare the new screen performance. The experimental results show that the multi-cavity composite pre-filled screen has a certain degree of gas-water diversion control, and the hydrophobic gravel-filled cavity mainly acts as a gas flow channel, while the conventional gravel-filled cavity mainly acts as a sand-carrying liquid flow channel. Sand mainly plugs the conventional gravel-filled cavity and reduces its flow performance, but the hydrophobic gravel-filled cavity can maintain a higher permeability, which is conducive to natural gas production, and the multi-cavity composite pre-filled screen maintains a high gas conductivity at the expense of the flow performance of the conventional gravel-filled cavity after plugging. Reducing the gravel size in the conventional gravel-filled cavity by filling with 70–140 mesh conventional gravel interspersed with 40–70 mesh hydrophobic gravel can ensure that the new screen has a gas-water diversion effect and maintains a high gas conductivity while having good sand-control performance. Besides, the new screen after plugging has a low permeability loss rate (94.03%) and has a strong comprehensive performance. The results of the study provide some implications for the development of new sand control equipment for the NGH reservoir.

Natural gas hydrate reservoirs at sea areas are shallow, loose and porous, and poor in mechanical properties in general, so wellbore instability is likely to occur after the drilling fluid infiltrates into the reservoir during drilling. In this study, effects of different factors on the stability of horizontal wellbore have been analyzed by establishing a coupling model of multi-physical fields of the drilled wellbore and reservoir of marine natural gas hydrate. The results show that when horizontal well is drilled into a gas hydrate reservoir, the plastic yield zone of the wellbore is not uniform in distribution and no longer a regular fan ring shape due to the different stress distribution around the wellbore from vertical well. Meanwhile, the closer the formation to the wellbore is, the longer the exposure of the formation to drilling fluid is, so the more thorough the hydrate decomposition, the greater the effective plastic strain, and the greater the risk of wellbore instability is. With the increase of pressure and temperature of drilling fluid and reservoir permeability, the range of mechanical strength drop around the wellbore would expand, making the yield zone of the wellbore and thus the risk of wellbore instability rise. But with the increase of reservoir porosity, the yield zone of wellbore decreases gradually, which is good for the wellbore stability during drilling, but once hydrate around the wellbore decomposes completely during long term production, the risk of wellbore instability may rise sharply. The results of this study can provide a theoretical reference for the stability analysis of horizontal well drilled, the safety pressure control during wellbore drilling and the evaluation of limit extension length of horizontal section in hydrate reservoir at sea areas.

During the process of natural gas hydrate (NGH) depressurization exploitation, the intrusion of formation water makes the pressure drop propagation difficult and the gas production lower. At the same time, the decomposition of hydrate in the pore space reduces the cementing strength of the formation, which may lead to geologic hazards such as seafloor subsidence and seafloor landslides. Utilizing CO2 hydrate to seal the overburden of NGH reservoirs not only prevents intrusion of formation water and improves gas production, but also achieves CO2 sequestration. In previous studies, only the gas production increasing was analyzed and the response of the geomechanics during the gas production process was not paid enough attention. In this paper, A coupled thermal–hydraulic–mechanical–chemical (THMC) model for CO2 hydrate sealing of overburden is established by using numerical simulation. Gas production and geomechanical response during the production with sealing overburden were analyzed; The results show that sealing the overburden can effectively promote the propagation of the pressure drop of the CH4 hydrate layer and the supplementation of heat during the production. Sealing overburden can effectively increase the cumulative gas production, decrease the water production, and reduce the seafloor subsidence. Exploiting gas hydrate with sealing overburden is conducive to realizing the dual goals of efficient production and safe production. This work can provide a reference for better realization of safe and efficient production of natural gas hydrate.

As a clean and efficient resource with large reserves, natural gas hydrate has gained worldwide attention in recent years. Unfortunately, the productivity prediction of NGH reservoirs based on traditional numerical simulation is time-consuming and inefficient. It remains a great challenge to accurately and efficiently predict the productivity of NGH reservoir. In this study, a neural network model for predicting the gas production dynamic of hydrate reservoirs was established by learning the results of numerical simulations based on the geological parameters of hydrate reservoirs in Nankai Through of Japan. The accuracy of the neural network model was tested by comparing the actual production test of the hydrate reservoir in the Nankai Trough and it was employed to further predict the gas production dynamic of the hydrate reservoir. After testing, the alternative model for numerical simulation established using neural network has greatly improved the calculation speed and the accuracy rate exceeds 99.8%. In the first seven days, the average daily gas production of the hydrate reservoir in the Nankai Trough predicted by the neural network model is 21810.06 m3/d. The error between the predicted value and the actual value was less than 10%. Besides, the average daily gas production and cumulative gas production of hydrate reservoirs for one year were predicted to be 13800 m3 and 4.98 × 106 m3 respectively by employing the established neural network model.

Sand production in the process of natural gas hydrate production is one of the major factors affecting the safe and long-term exploitation of gas hydrate. Once sand control fails, the hydrate production would be forced to stop. Sand production in marine gas hydrate exploitation is caused by multiple factors and is accompanied by complex coupling of these factors, making it more difficult to control than in conventional oil and gas wells in loose sand reservoirs. The study of sand production mechanisms in and sand control technology for gas hydrate reservoirs needs to think out of the box of the idea for traditional oil and gas reservoirs and should start from the coupling of hydrate and reservoir multi-fields. Current experiences of hydrate production tests at sea areas show that it is impossible to solve special situations of sand production in different periods before, during and after hydrate decomposition and possible secondary production by single sand control technology. The composite sand control technology of reservoir stimulation + wellbore stability + sand control can effectively deal with the difficulties that may occur in the depressurization production process, such as sand production, mud and sand plugging, and wellbore instability etc.

The methods of gas recovery from hydrate-bearing sediments (HBS) for the earth are on further validating and field trial, which is quite far from a technical and commercial demonstration. Based on the efficient heating way to accelerate the hydrate dissociation, a new gas recovery from HBS termed the “in-situ heat generation method with chemical reagents” is proposed by our previous work, and the chemical reagent huff and puff method (CHP) can achieve better gas production and higher energy efficiency (η) and thermal efficiency (ξ) than chemical reagent thermal flooding method (CTF). In this work, the influences of the hydrate saturation and sand-filling content in a three-dimensional cylindrical hydrate simulator (CHS) on the response characteristics (including gas production, temperature change, and ξ) during hydrate exploitation via CHP with separated injection mode are obtained by laboratory experiment. The results indicate that by this method, we could obtain advantageous gas production and realize high η with ideal heat utilization by reducing the heat lost for the HBS framework. In addition, the higher hydrate saturation and more extensive sand-filling scale benefit hydrate exploitation. However, high η cannot be considered a qualitative improvement, and how to efficiently mix the chemical reagents in HBS to generate sufficient heat for hydrate dissociation has not been broken through.

To address the high risk associated with gravel packing operations in horizontal wells located in shallow soft formations of natural gas hydrates in the sea, and the challenges in optimizing process parameters, we developed a numerical model using the CFD-DEM coupling method. This model takes into account the inter-particle and particle-wall interactions of ceramic particles, as well as the transport and settlement laws of the proppant particles in the screen and casing ring. By simulating and visually calculating the macroscopic flow pattern changes of the sand-carrying fluid under different process parameters, we were able to gain insights into the gravel packing process in horizontal wells. The simulation results indicate that in the long horizontal section gravel packing process of shallow soft hydrate reservoirs, using lightweight ceramsite for construction is safer. As the density of ceramsite increases from 1.07 g/cm3 to 1.80 g/cm3, the gravel packing rate decreases from 93.36% to 90.73%. Increasing the viscosity of the sand-carrying liquid is beneficial for gravel packing construction. With an increase in viscosity from 5 mPa·s to 10 mPa·s, the gravel packing rate rises from 93.36% to 94.38%. Controlling the gravel concentration appropriately promotes denser packing. As the gravel concentration increases from 10% to 20%, the gravel packing rate decreases from 93.36% to 90.44%. Pumping at a high displacement is advantageous for improving the packing rate. When the displacement of the sand-carrying liquid decreases from 1.0 m3/min to 0.6 m3/min, the packing rate decreases from 93.36% to 91.09%. The packing effectiveness is most significantly affected by liquid filtration loss. When the filtration loss rate reduces from 30% to 10%, the packing rate decreases from 93.36% to 89.71%.

Natural gas hydrate reservoirs have low permeability, limited temperature and pressure conductivity, and low development efficiency. Hydrate reservoir fracturing is a potential solution to the above issues. Fracture toughness, as an inherent property of material resistance to tensile fracture, is an essential parameter for evaluating the fracturability of hydrate reservoirs. In this paper, the methods of simulating artificial cores of natural gas hydrate sediments and controlling ice saturation are explored. Based on the semi-circular bend (SCB) test, the effects of notch length and ice saturation on the fracture toughness of artificial cores of natural gas hydrate sediments are investigated, and the deformation characteristics on the surface of the rock specimens are analyzed using the digital image correlation (DIC) method. The results indicate that when the dimensionless notch length β = 0.2−0.5, the peak load and the strain at core damage decrease gradually with the increase of the notch length, and the fracture toughness of the core increases from 0.076 MPa·m1/2 to 0.115 MPa·m1/2, which shows an overall trend of increasing, and the core exhibits obvious brittle damage characteristics. For SCB specimens with dimensionless notch length β = 0.4 and ice saturation in the range of 10%−90%, with the increase of ice saturation, the peak load, strain at core damage and fracture toughness values all decrease slowly at first and then increase rapidly, and the fracture toughness value of the core with ice saturation of about 20% is the lowest, and the fracture toughness value of the core is in the range of 0.132 MPa·m1/2−0.347 MPa·m1/2.

Natural gas hydrate (NGH) is a solid clathrate compound formed by water and natural gas at low temperatures and high pressures that is characterized by abundant resources and wide distribution. The production methods of NGH mainly include depressurization, thermal stimulation, chemical injection, CO2 replacement, and combination methods. Among them, the depressurization assisted CO2 replacement method has gained wide attention and become a research hotspot due to its capability of producing CH4 and sequestering CO2 simultaneously in hydrate reservoirs. Numerous experiments have been developed based on the different sequences of CO2 replacement and depressurization. However, a comparative analysis of these two production sequences remains ambiguous. In this study, a numerical model for depressurization assisted CO2 replacement was established to clarify the production sequences. Results indicated that the formation of CO2 hydrate promoted the dissociation of CH4 hydrate. The depressurization followed by CO2 replacement represented the optimal production sequence, with cumulative gas production (Vp) and CO2 sequestration ratios (RCO2) higher than those of CO2 replacement followed by depressurization by 3.17% and 1.61%, respectively. This study provides advantageous information for actual engineering applications.

In response to the risk benefit assessment of formation settlement and gas production induced by depressurization extraction of natural gas hydrates in the sea area, based on the coupling numerical simulation of multiphase seepage heat transfer mechanics, the evolution of mechanical parameters of shallow seabed strata with depth was considered, and the effects of extraction pressure difference and well spacing on the formation gas production settlement ratio were analyzed. The research results indicate that increasing the production pressure difference can effectively increase the gas production of the mining well, but its settlement also increases, and the gas production settlement ratio shows a decreasing trend with the increase of the bottom hole pressure difference; Increasing the spacing between the branch well and the main wellbore can effectively increase gas production, reduce formation settlement, and gradually increase the gas production settlement ratio. The research results can provide theoretical reference for the design of mining schemes in the process of shallow depressurization of natural gas extraction in the sea area.

Core sampling preparation is a common simulation way to learn the multi-physical field variations and multi-phase seepage laws in porous media during drilling and production for natural gas hydrate (hereinafter NGH), which is of great significance to ensure production safety and improve mining efficiency. Selecting the yield, fidelity, controllability, intuition, stability and cost as key evaluation indexes, four mainstream NGH-bearing sample preparation methods, including core drilling, sand packing, digital core, etched model, and their derived combined methods, are assessed in multiple dimensions. Then the reasonable optimization and development suggestions are put forward.