Risk Of Hydrate Blockage Research Articles

Determining the critical time points for hydrate formation in the presence of kinetic hydrate inhibitors: A rheological and kinetic study

Kinetic hydrate inhibitors have the characteristics of delaying hydrate nucleation and reducing hydrate growth rate. The utilized of kinetic hydrate inhibitors for hydrate blockage risk management is a promising technology for hydrate prevention in oil and gas industry. In this study, the rheological and kinetic properties of gas–water systems contained pure water, polyvinyl pyrrolidone and newly-synthesized inhibitor during hydrate formation at different subcooling degrees were in situ characterized using a high-pressure rheometer. By analyzing the experimental results, the concept of ‘critical time’ have been proposed to divide the time-varying process of hydrate formation into multiple stages. The three critical times indicated distinct trends in viscosity and pressure changes, as well as varying risks of hydrate blockage in hydrate prevention. The results further compared the differences in determining critical time through pressure and viscosity. The critical time of hydrate nucleation determined by viscosity was earlier than pressure due to the hypothesis of lag in gas consumption. The critical time of rapid hydrate growth determined by viscosity was later than gas consumption, which may be due to that the sharp increase in viscosity requires the aggregation of hydrates. According to the inhibition effect evaluation results determined by three critical times, it was found that the newly-synthesized inhibitor was more effective than polyvinyl pyrrolidone in inhibiting nucleation, delaying rapid hydrate growth time and reaching high viscosity time. This study can provide a comprehensive evaluation method for assessing the performance of kinetic hydrate inhibitors from both kinetic and rheological perspectives.

Study of Sintering Behavior of Methane Hydrate Particles on the Wall Surface.

The sintering of hydrate aggregates on the pipe wall is a major form of hydrate deposition. Understanding the sintering behavior of hydrates on the wall is crucial for promoting hydrate safety management and preventing pipeline blockage. However, limited research currently exists on this topic. In this study, the cohesive force strength of hydrate particles on the wall surface under different conditions was directly measured using a high-pressure micromechanical force device (HP-MMF). Subsequently, the effects of subcooling and glycine on the cohesive force were investigated. The results indicate that the cohesive force is influenced by different growth states during the process of free water on the wall surface gradually growing into hydrate. Three states with larger measured values during the growth process were selected for research. Observation showed that increased subcooling strengthened sintering by accelerating the growth rate of the hydrate film, resulting in a significant increase in cohesive force. The role of glycine in the methane hydrate system was then evaluated. Glycine was found to reduce the degree of sintering by reducing the growth rate of the hydrate film, thereby decreasing the cohesive force. The optimal concentration in the system was determined to be 0.25 wt %. Moreover, compared with low subcooling (1 °C), glycine had a better effect at high subcooling (5 °C). At 5 °C subcooling and the optimal concentration, the cohesive force in the wall droplet state decreases from 677.38 to 489.02 mN/m, the cohesive force at the low-saturation state decreases from 951.79 to 543.32 mN/m, and the cohesive force at the high-saturation state decreases from 1194.95 to 641.76 mN/m. These findings contribute to a better understanding of the cohesive force behavior of gas hydrate on the inner wall of the pipeline and provide basic data for reducing the risk of hydrate blockage.

Analysis of sensitivity to hydrate blockage risk in natural gas gathering pipeline

During the operational process of natural gas gathering and transmission pipelines, the formation of hydrates is highly probable, leading to uncontrolled movement and aggregation of hydrates. The continuous migration and accumulation of hydrates further contribute to the obstruction of natural gas pipelines, resulting in production reduction, shutdowns, and pressure build-ups. Consequently, a cascade of risks is prone to occur. To address this issue, this study focuses on the operational process of natural gas gathering and transmission pipelines, where a comprehensive framework is established. This framework includes theoretical models for pipeline temperature distribution, pipeline pressure distribution, multiphase flow within the pipeline, hydrate blockage, and numerical solution methods. By analyzing the influence of inlet temperature, inlet pressure, and terminal pressure on hydrate formation within the pipeline, the sensitivity patterns of hydrate blockage risks are derived. The research indicates that reducing inlet pressure and terminal pressure could lead to a decreased maximum hydrate formation rate, potentially mitigating pipeline blockage during natural gas transportation. Furthermore, an increase in inlet temperature and terminal pressure, and a decrease in inlet pressure, results in a displacement of the most probable location for hydrate blockage towards the terminal station. However, it is crucial to note that operating under low-pressure conditions significantly elevates energy consumption within the gathering system, contradicting the operational goal of energy efficiency and reduction of energy consumption. Consequently, for high-pressure gathering pipelines, measures such as raising the inlet temperature or employing inhibitors, electrical heat tracing, and thermal insulation should be adopted to prevent hydrate formation during natural gas transportation. Moreover, considering abnormal conditions such as gas well production and pipeline network shutdowns, which could potentially trigger hydrate formation, the installation of methanol injection connectors remains necessary to ensure production safety.

Elucidating the Impact of Thermodynamic Hydrate Inhibitors and Kinetic Hydrate Inhibitors on a Complex System of Natural Gas Hydrates: Application in Flow Assurance

To alleviate the hydrate blockage risk in oil and gas pipelines/production facilities, thermodynamic hydrate inhibitors (THIs) and kinetic hydrate inhibitors (KHIs) are the frequently used additives/chemicals. While these additives are highly effective, the impact of low dosage of THIs (under inhibited systems) and performance of KHIs at high water cut and/or high subcooling is not well understood. In this work, a high-pressure visual stirred tank reactor was employed to investigate the impact of THIs and KHIs on the kinetics of the complex hydrates of natural gas mixtures (CH4/C2H6/C3H8) and cyclopentane at high water-cut and high subcooling (∼21 °C). Various concentrations of a THI, mono-ethylene glycol (MEG) with a dosage ranging from 0.1 to 25 wt %, and multiple KHIs (polyvinylpyrrolidone (PVP k-30, PVP k-90), caprolactam, butyl glycol ether (BGE), and polyglycerin with 0.1 wt % dosage) were evaluated for hydrate formation kinetics, onset hydrate formation/nucleation temperature, and morphological changes. Gas uptake results reveal that hydrate blockage risk is higher at low MEG content (0.1 to 10 wt %) compared to the baseline, while a significant reduction in gas uptake was observed for the high MEG content trials (20–25 wt %). With 20 and 25 wt % MEG, the hydrate nucleation temperature was reduced by 10–12 °C compared to the baseline. In context to KHIs impact, 0.1 wt % BGE and caprolactam promoted the nucleation temperature and the rate of hydrate formation/gas uptake. However, PVPs not only reduced the gas uptake kinetics but also lessened the hydrate nucleation temperature by 6–8 °C compared to the baseline data. Our results may offer new insights into optimizing hydrate inhibitors dosage to diminish the risk of hydrate blockage in subsea pipelines.

Experimental Investigation to Quantify Gas Hydrate Formation during Shutdown in the Wellbore Near the Wellhead: Impact of Thermodynamic Inhibitors

In most cases, concerns about gas hydrates in hydrocarbon production are often associated with shut-in and restart of the production system associated with the fluids in the wellhead and the main flowline. The exposure of the wellhead to cold temperatures during shutdown can cause severe hydrate formation even with stagnant fluid in the wellbore. Similar conditions may exist at the top of the gas line in flowlines for hydrate formation when gas is saturated with water. This study investigated the hydrate deposition kinetics and morphology at 10 MPa (ca. 1400 psi), with the goal of preventing severe solid hydrate formation from the vapor or supercritical phase near the wellhead or a vertical conduit exposed to cold conditions such as road overpass or river crossing during shutdown and providing operating guidelines for hydrate management by understanding the impact of volatile (methanol) and non-volatile (monethylene glycol, MEG) thermodynamic hydrate inhibitors (THIs). These results may also apply to top of line hydrate and its inhibition. It was verified that non-volatile THI is ineffective in preventing hydrate deposition near the wellhead, showing growth behavior of hydrate formation in the presence of MEG similar to that with lower pressure without inhibitors. However, volatile THI prevents hydrate deposition in a cold wellhead even though the experimental condition provides sufficient convection and water condensation. In the warm wellhead, volatile THI does not prevent hydrate formation, but it delays the growth of hydrate deposits. In the presence of volatile THI, the dissociation and reformation of hydrate deposits on the vertical wall are observed. This study provides a quantifiable method for hydrate growth in real-time and insight into better management strategies for THI usage to mitigate hydrate blockage risk near the wellhead.

Study on a Numerical Model of Hydrate Bed Critical Velocity in Solid–Liquid Two-Phase Flow Pipelines

A hydrate bed critical velocity model is developed, including a hydrate bed limit deposition velocity model and a hydrate bed suspension velocity model. The innovation of this paper is to consider the hydrate bed pressure and liquid bridge force on hydrate particles when building the limit deposition velocity model and to modify Dai’s model by using hydrate experimental and simulation data when building the suspension velocity model. The hydrate bed critical velocity model is negatively correlated with the particle size and positively correlated with the pipe diameter, particle density, and particle volume fraction. The accuracy of the model is demonstrated by validation. The hydrate bed critical velocity model can be used to calculate the hydrate fixed-bed and moving-bed height under different conditions, based on which the flow pattern map of hydrate particles and the hydrate blockage risk classification method are established, which is a certain guidance to ensure the safety of hydrate flow in the pipeline.

A Pressure Drop Prediction Model for Hydrate Slurry Based on Energy Dissipation under Laminar Flow Condition

Summary Hydrate formation in deepwater drilling alters the rheology of drilling fluid and increases the risk of hydrate blockage in the low-temperature and high-pressure region. Developing a proper hydrate slurry model effectively helps evaluate the flow risk of hydrate slurry and contributes to organizing an efficient hydrate management plan. In this work, a novel pressure drop prediction model for hydrate slurry is developed under the laminar flow condition based on the energy dissipation theory. The influences of interactions between pipe wall, carry liquid, and hydrate particles on the energy dissipation rates and the pressure losses are analyzed theoretically, including the wall resistance, the liquid flowing around hydrate particles, and the collision between hydrate particles. In case studies, under xanthan gum (XG) concentrations from 0.1 to 0.3% and hydrate concentrations from 1 to 9%, the wall resistance and the liquid flowing around hydrate particles hold dominant contributions in which their fractions of pressure losses are from approximately from 40 to 95% and from 5 to 60%, correspondingly. The collisions between hydrate particles contribute only within 0.2%. The increase of XG concentrations and the decrease of hydrate concentrations both rise the fractions of pressure losses induced by the wall resistance, while they decrease the fractions of pressure losses caused by the liquid flowing around hydrate particles. The reliability of the developed model is validated by the published data, and most of the calculated results have discrepancies less than ±20%.

Quantitative assessment of hydrate blockage risk in pipelines based on reliability theory

Hydrate blockage significantly challenges flow assurance during subsea oil and gas operations. This paper presented a novel probabilistic method to quantitatively evaluate hydrate blockage risk based on reliability theory. The limit state equation of hydrate blockage involving hydrate volume fraction was established, after which Latin hypercube sampling (LHS) was used to determine the uncertain parameter samples. Moreover, the calculation efficiency was enhanced using the Proper Orthogonal Decomposition (POD) method, involving physical field reconstruction based on OLGA-CSMHyK simulation. Furthermore, this paper considered the uncertainty of pipeline operating parameters, such as the pipeline inlet temperature (T), outlet pressure (P), mass flow rate production reduction (Q), heat transfer coefficient (K), and initial droplet diameter (Dp). This method was used to predict the probability of hydrate blockage at any time and at any position of the multiphase pipeline. Three risk levels were defined, including hydrate formation risk, low risk of hydrate blockage, and high risk of hydrate blockage. The calculation results indicated that Q displayed a significant impact compared with the other four uncertain parameters, while the influence of topography also warranted attention. This work may provide a reference for optimizing hydrate management strategies and ensuring safe pipeline operation.

Monitoring gas hydrates under multiphase flow in a high pressure flow loop by means of an acoustic emission technology

The formation of natural gas hydrates in oil and gas pipelines is an important concern due to the risk of hydrate blockage. In order to reduce the expenses with the use of chemicals to avoid hydrate plugging, more studies about the slurry flow and the mechanisms of blockage in flowing conditions are necessary. In this study, it is presented an experimental work combined with a multi-instrumental data analysis to allow monitoring hydrate formation and track the particles in time and space. Acoustic emission (AE) is used in a high pressure flow loop apparatus to capture acoustic waves generated by the flow and to detect the presence of hydrates flowing in the system. The tests are conducted with Kerdane oil, saline water and natural gas at 75 bar and 4 °C. Two tests are presented, one at 30 and another at 80% water cut (water fraction in volume). It is shown that, with the absolute energy obtained from the AE sensors, it was possible to detect the beginning of hydrate crystallization and the hydrates displacement in the pipeline, because the absolute energy increases as the collisions of particles generate more acoustic emission. The results show that, for the tests performed, the flow became heterogeneous after hydrate formation, with some regions of the flowing volume containing more hydrates than others. It is also shown that the non-flowing volume of hydrates with entrapped liquid, caused by deposition or settling, can be estimated with AE.

Simulation of the hydrate blockage process in a water-dominated system via the CFD-DEM method

With oil and gas exploitation developing towards deep-water fields, the extreme, low-temperature, and high-pressure environments are ideal for hydrate formation in subsea pipelines. Hydrate formation, growth, aggregation, and deposition in the flowlines substantially increase the hydrate blockage risk, necessitating the assessment and clarification of this process. This work employed computational fluid dynamics (CFD) and the discrete element method (DEM) to perform several numerical simulations using Fluent and EDEM to study the hydrate blockage process caused by aggregation and deposition. A three-dimensional model of a solid-liquid pipeline containing hydrate particles was established, which considered the cohesion force between the hydrate particles and the adhesion force between the hydrate particles and pipe wall. Two simulation strategies were implemented. The first simulated the hydrate blockage process using a throttling element, which assumed hydrate depositions on the pipeline wall. The second studied the impact of the collision between upstream and downstream hydrate aggregates. The critical hydrate blockage state was roughly defined based on the hydrate volume fraction and pressure drop changes during the hydrate aggregate collision process. These results represented the initial work for simulating the hydrate blockage process via combined CFD-DEM by considering the bidirectional interaction between the continuous water phase and discrete hydrate particles. These preliminary findings provided theoretical support for studying the hydrate blockage mechanism to solve the hydrate flow assurance issue in the subsea pipelines.

Investigation of CO2 hydrate slurry flow characteristics with particle dissociation for carbon storage and transportation

CO2 capture and storage technology is an effective method to mitigate the greenhouse effect and hydrate slurry is a high-efficiency way of CO2 transportation. In this study, in order to further reduce the cost and improve the transportability, a new CO2 hydrate slurry transport mode which allows a small part of hydrate particles to dissociate during flow process is proposed. To investigate the CO2 hydrate slurry flow characteristics and particle micro behaviors, a multiphase flow model coupled with hydrate dissociation kinetic model and population balance model is established. Experimental results are used to verify this integrated model. Furthermore, the effects of hydrate dissociation on CO2 transportability are also analyzed. The results indicate that the dissociation rate of hydrate during flow process can be divided into rapid dissociation stage and weakened dissociation rate stage. The agglomeration of hydrate particle can reduce the total surface area, further resisting the dissociation rate. The hydrate particle size experiences a process of growing to dynamic balance. The hydrate dissociation can decrease the mean viscosity of CO2 hydrate slurry flow, which can reduce the pressure drop and energy loss compared with the flow without hydrate dissociation. The generated bubbles can accelerate the CO2 hydrate slurry flow, increasing the transportability and reducing the risk of hydrate blockage in pipe induced by agglomeration.

Quantitative hydrate deposition prediction method and application in deep-water or permafrost gas pipelines

Hydrate formation in pipelines seriously affects the efficiency of energy transmission. Adopting the production process of gas pipelines in deep-water or permafrost regions as the engineering application background, hydrate formation and deposition characteristics at different locations in gas pipelines are analyzed to realize the quantitative prediction of high-risk areas and degree of hydrate plugging in pipelines. A typical deep-water gas pipeline in the South China Sea is selected as an example. The calculation results show that the long-distance pipeline exhibits an obvious hydrate blockage risk area, which occurs 700-3200 m away from the pipeline inlet. The high-risk area of hydrate plugging in the system moves upstream of the pipeline with decreasing ambient temperature. The risk of hydrate blockage increases with decreasing pipeline inner diameter. The established quantitative prediction method for hydrate deposition in deep-water or permafrost gas pipelines accurately locates high-risk areas of hydrate plugging, which could effectively guide hydrate prevention and notably reduce the cost of hydrate control in deep-water or permafrost gas pipelines.

Anti-agglomeration evaluation and Raman spectroscopic analysis on mixed biosurfactants for preventing CH4 hydrate blockage in n-octane + water systems

Hydrate formation and agglomeration in oil and gas pipelines is a serious safety and environmental problem. An eco-friendly and effective anti-agglomerant is a promising candidate to mitigate gas hydrate blockage risk environmentally and economically. This study evaluated the anti-agglomeration effect of mixed biosurfactants (rhamnolipid + trehalose lipids) through the torque changes during the CH4 hydrate growth process. The results showed that mixed biosurfactants greatly decreased the force needed for the system to be flowing. A surprising synergistic effect functioned for mixed biosurfactants, leading to the decease of dosage needed for anti-agglomeration. The CH4 hydrate formation kinetics was also studied, and the data revealed that mixed biosurfactants could fasten the gas dissolution process while did not greatly change the hydrate growth rate. In addition, the Raman spectra for CH4 hydrate formed with mixed biosurfactants were obtained and analyzed. It demonstrated that the added biosurfactants decreased the hydration number by increasing the small cage occupancy. Meanwhile, the hydrate surface became regular and smooth, which contributed to preventing hydrate blockage in oil and gas system.

Study Correlates Hydrate Blockage Risk and Gas/Liquid Flow Pattern In Horizontal Pipelines

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper Paper SPE 197534, “Study on the Correlation Between Hydrate Formation-Blockage Risk and Gas/Liquid Flow Pattern in Horizontal Pipelines,” by Wenyuan Liu, Jinqiu Hu, and Fengrui Sun, China University of Petroleum-Beijing, et al., prepared for the 2019 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 9–12 November. The paper has not been peer reviewed. Current research into the risk of hydrate formation and blockage in pipelines is limited to prediction of hydrate formation. However, hydrate generation often does not lead to flow barriers. Hydrate growth and deposition rates are important to hydrate generation as a blockage risk. To help solve the problem of flow assurance in horizontal gas/liquid pipelines, this paper analyzes the risk of hydrate formation and blockage, aiming at various gas/liquid flow patterns and considering the phase distribution and interface distribution characteristics of different flow patterns. Introduction Hydrate blockage risk in transportation pipelines is one of the most important topics in the study of flow assurance. Large-scale natural gas development, for example, requires construction of large-scale gathering and transmission pipeline networks. Natural gas is often transported by horizontal or small inclined pipelines, and water generation and flow are often present in natural gas pipelines, which undoubtedly increases the risk of hydrate formation and blockage. When gas and water exist at the same time, there will often be a variety of gas/liquid flow patterns in pipelines, and different flow patterns will have different risk of hydrate formation and blockage. To avoid hydrate risk, it is necessary to study the correlation between hydrate generation blockage risk and gas/liquid flow pattern. Research of Hydrate Growth and Deposition Based on the hydrate formation-growth-deposition mechanism and combined with the hydrate experiment in the flow loop, the characteristics of hydrate formation-growth-deposition in pipe-lines under different gas/liquid flow patterns was studied. The results show that different flow patterns yield different hydrate formation and deposition characteristics as a result of different phase and interface distributions. The bubble flow, cluster flow, and slug flow have some similarities in flow patterns. The gas phase in the flow system exists in the form of bubbles, and the occurrence of thin liquid film on the tube wall under these three flow patterns is relatively rare. Accordingly, the similarity of laminar flow, wave flow, and annular-mist flow shows that thin liquid film or gas/liquid pipe wall three-phase interface will always appear in the flow process. Thus, the hydrate formation and deposition risk of the latter three flow patterns is significantly greater than that of the former three. Comprehensive analysis shows that the hydrate risk of each flow pattern is in the order of, with greatest risk first, annular-mist flow, laminar flow and wave flow, slug flow, cluster flow, and bubble flow. The annular-mist flow is the most dangerous flow pattern for hydrate formation and blockage. In this case, special attention should be paid to hydrate prevention and control. The complete paper presents a detailed historical discussion of correct division of flow pattern and of research on hydrate growth models. Researchers have established a series of hydrate-growth kinetics models combined with crystallography, heat transfer, mass transfer, and other principles. Recent models established a hydrate growth model based on heat transfer.

A prevention and control method for natural gas hydrate in pipe strings during deepwater gas well production tests

The prevention and control of natural gas hydrate (hereinafter, “hydrate” for short) blockage during deepwater gas well production tests is very important in ensuring the test safety. In this paper, the distribution of wellbore temperature and pressure field under different test conditions was analyzed, and the changes of hydrate deposition and blockage degree in the pipe string in the whole process of test under different test systems were evaluated using the hydrate generation–deposition–decomposition calculation method. On this basis, a deepwater gas well production test method based on hydrate prevention and control was proposed. And the following research results were obtained. First, in the process of deepwater gas well tests, the vapor–liquid phase of annular-mist flow pattern with the greatest risk of hydrate blockage is often formed in the wellbore. Therefore, it is more reasonable to take measures to prevent hydrate blockage in the process of tests than to prevent the formation of hydrate. Second, when the conventional four-point test method is used, it is required to set low gas production measurement points with lower flowing temperature. In the wellbore with high temperature and low temperature, however, hydrate tends to form and deposit easily, and a long period of test will increase the risk of test string blockage. Third, the mixed-sequence test system suitable for deepwater gas well tests can change wellbore temperature by adjusting the sequence of measuring points without changing the production rate and duration, so as to decompose hydrate sediment layers and reduce the maximum blockage degree of test string in the process of tests. Fourth, a three-point or two-point test method is recommended for deepwater gas wells without sand production, stress sensitivity, retrograde condensation and water production. Superior to the conventional four-point test method, three-point and two-point test methods can effectively reduce the risk of hydrate deposition and blockage in the test string, and it can shorten the testing time and reduce the test cost on the premise of ensuring the accuracy of the productivity equation. In conclusion, the research results are of help to the field test construction of deepwater gas wells.

Gas hydrate formation probability and growth rate as a function of kinetic hydrate inhibitor (KHI) concentration

Kinetic hydrate inhibitors (KHIs) are polymeric based chemicals that delay the nucleation and/or suppress the growth rate of gas hydrate crystals. While KHIs have been used successfully to mitigate hydrate blockage risk during oil and gas production, the mechanisms by which they function remain unclear. In this work, multiple high-pressure stirred automated lag time apparatus (HPS-ALTA) were used to investigate the impact of a KHI on the subcooling formation probability distributions of methane hydrates and the subsequent initial growth rates. Over 3000 hydrate formation events were measured around 12 MPa using seven independent HPS-ALTA cells with KHI concentrations of up to 3 wt% in water. The addition of KHI made hydrate formation much less stochastic: significant reductions occurred in both the width of the formation probability distribution for a given cell, and in the offsets between distributions measured with different cells. Average initial hydrate growth rates were reduced by approximately a factor of 5 as KHI concentration increased, even though the average driving force (subcooling) increased by a factor of up to 3. However, above a KHI concentration of 0.3 wt%, a diminishing return was observed in both the nucleation delay and growth rate suppression. A Classical Nucleation Theory (CNT) framework was applied to investigate whether polymer adsorption onto active nucleation sites could explain the observed delay in formation onset. However, the CNT kinetic parameter extracted from the measured formation probability data increased with concentration, which is opposite to the dependence predicted by the polymer-adsorption model of nucleation suppression by KHIs.

Methane hydrate formation in a water-continuous vertical flow loop with xanthan gum

Hydrate phase transition in drilling fluid is a non-ignorable problem for developing deep-water oil, natural gas and natural gas hydrate resources. Once gas hydrates form during drilling, it will increase the difficulty of wellbore pressure management and flow assurance, which enlarges the risk of hydrate blockage and causes serious property damage and casualties. Methane hydrate formation experiments are conducted in xanthan gum (XG) aqueous solution to mimic the drilling fluid flowing condition in a vertical flow loop. The experiments reveal that the hydrate formation process is a mass transfer process and experiences four different hydrate formation periods, because of the kinetics formation and slough of hydrate shells. The subcooling temperature has a weaker impact on the hydrate formation than the flow velocity and XG. The increase of flow velocity can enhance the hydrate formation rate in drilling fluid but the increase of XG concentration can inhibit the hydrate formation. The influence mechanisms of hydrate shell kinetic slough, flow velocity and XG concentration on hydrate formation are analyzed and discussed in detail. We built a mass-transfer hydrate formation model based on the mechanism of methane molecule diffusing from gas phase to liquid phase. The empirical overall mass transfer coefficient is introduced involving the influence of hydrate shell kinetic slough, flow velocity and XG concentration. In model validation, the maximum discrepancy of the developed model decreases from 146.85% to 11.03% after using the overall mass transfer coefficient.

Study on the Optimization of Hydrate Management Strategies in Deepwater Gas Well Testing Operations

Abstract Low temperature and high pressure conditions favor the formation of gas clathrate hydrates which is undesirable during oil and gas industries operation. The management of hydrate formation and plugging risk is essential for the flow assurance in the oil and gas production. This study aims to show how hydrate management in the deepwater gas well testing operations in the South China Sea can be optimized. To prevent the plugging of hydrate, three hydrate management strategies are investigated. The first method, injecting thermodynamic hydrate inhibitor (THI) is the most commonly used method to prevent hydrate formation. THI tracking is utilized to obtain the distribution of mono ethylene glycol (MEG) along the pipeline. The optimal dosage of MEG is calculated through further analysis. The second method, hydrate slurry flow technology is applied to the gas well. Pressure drop ratio (PDR) is defined to denote the hydrate blockage risk margin. The third method is the kinetic hydrate inhibitor (KHI) injection. The delayed effect of KHI on the hydrate formation induction time ensures that hydrates do not form in the pipe. This method is effective in reducing the injection amount of inhibitor. The problems of the three hydrate management strategies which should be paid attention to in industrial application are analyzed. This work promotes the understanding of hydrate management strategies and provides guidance for hydrate management optimization in oil and gas industry.

Economic benefit of methane hydrate reformation management in transport pipeline by reducing thermodynamic hydrate inhibitor injection

Hydrate reformation is an inherent risk in a methane hydrate production system because dissociated water and methane flow through transport pipelines simultaneously. In this study, comprehensive experiments using high-pressure autoclaves are performed to investigate the effect of reducing the concentration of thermodynamic hydrate inhibitor on hydrate reformation characteristics. In order to simulate the production of methane hydrates, these are formed and dissociated in the preliminary stage; thereafter, the hydrates are reformed from dissociated water. Although dissociated water and fresh water are found to have similar formation rates, they have a major difference in relative torque, especially in the early stage of hydrate formation. The instant rise of the relative torque in the dissociated water is observed to be up to 2.5; thereafter, it remains approximately 3.0 until hydrate conversion reaches 28 vol%. This trend is different from that in fresh water, where a steady increase in relative torque with sudden spikes is observed. These results clearly show the high risk of hydrate blockage in the transport pipelines of a methane hydrate production system; hence, the injection of hydrate inhibitor is necessary. In this study, monoethylene glycol (MEG) is the selected thermodynamic hydrate inhibitor; its concentration is maintained below a specific value to completely avoid hydrate formation. Despite the occurrence of hydrate reformation, a stable relative torque is observed in a 20 wt% MEG concentration, where the conversion of water to hydrate approximately reaches 40 vol%. For a 10 wt% MEG concentration, a sudden increase in relative torque of up to 2.0 is observed in the early stage of hydrate formation; this suggests that the foregoing is less effective in sustaining flowability. Compared to fresh water, the addition of a 20 wt% MEG to dissociated water results in a more stable torque. Once the performance of the MEG concentration reduction is confirmed, the MEG regeneration process is designed accordingly by using both multiphase flow and process simulation models. A life cycle cost (LCC) analysis is conducted by estimating the capital expenditures (CAPEX) and operating expenditures (OPEX) of the MEG regeneration process. Considering both CAPEX and OPEX, the LCC for complete inhibition (35 wt%) is 90.15 MUSD (million United States dollars); however, for the 20 and 10 wt% MEG concentrations, the LCC values are reduced to 86.79 and 84.58 MUSD, respectively. The foregoing suggests the potential economic benefit of methane hydrate reformation management to avoid blockage.

Research on flow assurance of deepwater submarine natural gas pipelines: Hydrate prediction and prevention

The formation of hydrate will lead to serious flow assurance problems in deepwater submarine natural gas transmission pipelines. However, the accurate evaluation model of the hydrate blocking risk for submarine natural gas transportation is still lacking. In this work, a novel model is established for evaluating the hydrate risk in deepwater submarine gas pipelines. Based on hydrate growth-deposition mechanism, the mathematical model mainly consists of mass, momentum and energy conservation equations. Meantime, the model results are obtained by finite difference method and iterative technique. Finally, the model has been applied in the production of deepwater gas field (L Gas Field) in China, and the sensitivity analysis of relevant parameters has been carried out. The results show that: (a). The mathematical model can well predict the hydrate blockage risk in deepwater natural gas pipelines after verification. (b). Hydrate is easily formed at the intersection of horizontal pipeline and vertical riser, and the maximum blocking position often occurs in middle of the riser. (c). The hydrate blockage degree and length of hydrate formation region (HFR) decrease with the increase of gas transport rate. (d). The hydrate blockage degree and length of HFR decrease with the increase of gas transport temperature. (e). The hydrate blockage degree and length of HFR increase with the extension of horizontal pipeline. (f). Injecting inhibitors can effectively inhibit hydrate formation and blockage, but the improvement of transmission measures can significantly reduce the dosage of inhibitor. It is concluded that measures such as increasing gas transportation rate and temperature, shortening horizontal pipeline length, optimizing inhibitor injection point and injection rate can play a safe, economic and efficient role in hydrate preventing and controlling.