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Michael L Johns - One of the best experts on this subject based on the ideXlab platform.
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gas Hydrate formation probability and growth rate as a function of kinetic Hydrate inhibitor khi concentration
Chemical Engineering Journal, 2020Co-Authors: Peter J. Metaxas, Gert Haandrikman, Paul Louis Stanwix, Michael L Johns, Daniel CrosbyAbstract:Abstract 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.
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microscale detection of Hydrate Blockage onset in high pressure gas water systems
Energy & Fuels, 2017Co-Authors: Masoumeh Akhfash, Paul F. Pickering, Jianwei Du, Zachary Mark Aman, Michael L JohnsAbstract:A high-pressure stirred autoclave cell equipped with a focused beam reflectance measurement (FBRM) probe and a particle video microscope (PVM) was used to study Hydrate formation and plugging in gas–water systems as a function of shear rate. These probes allowed estimates of the mean Hydrate particle size and number of Hydrate particles to be correlated with the Hydrate volume fraction and the Hydrate slurry’s resistance-to-flow. Before reaching the Hydrate volume fraction φtransition at which the Hydrate slurry first exhibits a measurable increase in resistance-to-flow at ≈(16 ± 2) vol %, clear changes in the measured number and size of the Hydrate particles were observed. Initially, Hydrate particles within the FBRM probe’s field of view decreased in size and increased in number until a maximum was reached at concentrations of 2–9 vol % (increasing with shear rate). However, with continued Hydrate growth, the number of particles within the FBRM probe’s field of view unexpectedly decreased and eventually...
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Hydrate formation and deposition in a gas-dominant flowloop: Initial studies of the effect of velocity and subcooling
Journal of Natural Gas Science and Engineering, 2016Co-Authors: Zachary Mark Aman, Mauricio Di Lorenzo, Karen A. Kozielski, Pramod Warrier, Michael L JohnsAbstract:Abstract Gas Hydrate formation is a critical flow assurance risk in oil and gas production, as remediation of Blockages may require weeks of operating downtime and represent a significant safety hazard. While many studies over the past two decades have focused on quantifying Hydrate Blockage risk in crude oil systems, there is a dearth of information available with which to assess Hydrate growth rate or Blockage severity in natural gas systems, which typically operate between stratified and annular flow regimes. In this investigation, a single-pass gas-dominant flowloop was used to measure Hydrate growth and particle deposition rates with variable liquid holdup (1–10 vol%) and subcooling (1–20 °C). A particular focus of this study was the impact of reducing the gas phase velocity to achieve lower liquid entrainment and, therefore, decrease Hydrate formation rate. Reducing the gas velocity from 8.7 to 4.6 m/s at a constant subcooling around 6 °C reduced the total formation rate by a factor of six. At these conditions, the sensitivity of Hydrate formation rate to velocity was about 40 times greater than the sensitivity to subcooling. This reduction in gas velocity also halved the estimated rate of Hydrate deposition on the pipeline wall. Finally, new observations of Hydrate wash-out are reported, whereby significant localized Hydrate deposits were effectively removed by modulating the subcooling of the flowloop wall from 6 °C to 3.5 °C. The results provide new insight to inform the next generation of predictive Hydrate growth and deposition models for gas-dominant flowlines.
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rapid assessments of Hydrate Blockage risk in oil continuous flowlines
Journal of Natural Gas Science and Engineering, 2016Co-Authors: Bruce W E Norris, Luis E Zerpa, Michael L Johns, Zachary Mark AmanAbstract:Abstract As industry moves toward the production of oil and gas resources in deep offshore environments, the prospective formation of natural gas Hydrates under low temperature, high-pressure conditions poses an increasing risk of pipeline Blockage. Successful management of this risk requires a precise forecast of the Hydrate growth rate. Such predictions should incorporate quantitative descriptions of both deterministic and probabilistic Hydrate phenomena. In this work, we present a first step towards such a quantitative risk assessment for systems that form Hydrate slurries, based on a consideration of the stochastic nature of Hydrate formation. Our framework introduces a new approach to risk assessment, by coupling a laboratory-derived probabilistic nucleation model with existing deterministic calculations for Hydrate slurry viscosification. This new approach is used to extend a previously-described Hydrate risk algorithm, the Hydrate Flow Assurance Simulation Tool (HyFAST), which enables the rapid assessment of Hydrate slurry viscosification using the most advanced models available. Importantly, while the previous version of HyFAST was constrained to calculations in flowloop and autoclave geometries, for which it is sufficient to consider a single volume element, the new version of the HyFAST algorithm allows calculations for flowlines wherein a series of multiple volume elements are considered. The advanced Hydrate formation models within this algorithm allow identification of critically important Hydrate formation scenarios, and may serve as a screening tool for cases that then require study within rigorous hydrodynamic packages such as OLGA® or LedaFlow® to examine behaviour during key transient events. By coupling the outputs of our predictive algorithm and quantitative risk framework, we demonstrate a new capability to assess what constitutes an acceptable level of Hydrate formation. We use this algorithm in a series of case studies that compare the effectiveness of common Hydrate mitigation strategies over the life of a reservoir, including the optimization of a wellhead choke opening for both production rate and Hydrate Blockage risk.
Mert Atilhan - One of the best experts on this subject based on the ideXlab platform.
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effect of injected chemical density on Hydrate Blockage removal in vertical pipes use of meg meoh mixture to remove Hydrate Blockage
Journal of Natural Gas Science and Engineering, 2017Co-Authors: Morteza Aminnaji, Rod Burgass, Bahman Tohidi, Mert AtilhanAbstract:Abstract One of the problems with natural gas production in the pipes is gas Hydrate formation which can lead to Blockage. Although there are options to inhibit Hydrate formation e.g. thermodynamic Hydrate inhibitors and kinetic Hydrates inhibitors, Hydrate Blockage can occur in some cases, e.g. underestimation of water cut production, unplanned shut-in, inappropriate inhibitor injection method or failure of inhibitor delivery. There are a number of remediation methods for Hydrate Blockage removal such as depressurization, chemical injection e.g. methanol and MEG, mechanical, and thermal methods. In the case of chemical useage in vertical pipes, density plays an important role and needs to be considered. In this work, the effect of chemical density on removing Hydrate Blockage in the vertical pipes was assessed using a long window rig. The use of methanol/MEG mixtures in removing Hydrate Blockage in vertical pipes could be more efficient than methanol or MEG alone. The results indicate that a mixture of methanol/MEG with a density of 1 g/cc could remove Hydrate Blockage successfully and efficiently. The hydrostatic pressure of aqueous phase due to chemical injection could be reduced by using methanol/MEG mixture, because the amount of methanol/MEG mixture required for removing plug could be less than methanol or MEG alone. In addition, ice formation during Hydrate dissociation due to its endothermic nature should be taken into consideration during chemical injection.
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gas Hydrate Blockage removal using chemical injection in vertical pipes
Journal of Natural Gas Science and Engineering, 2017Co-Authors: Morteza Aminnaji, Rod Burgass, Bahman Tohidi, Mert AtilhanAbstract:Abstract Gas Hydrates can cause restriction and Blockages in pipelines. Therefore, if Hydrates are identified as a potential challenge, a prevention strategy for Hydrate formation and options for remediation of Hydrate Blockage are considered. The most commonly used means of Blockage removal involves one or two sided depressurization with or without other options such as heating and injecting thermodynamic inhibitors. In this work, we report use of thermodynamic inhibitors to remove a Hydrate Blockage in a vertical pipe. The experimental work was carried out using a long, cylindrical, high pressure, vertical visual cell with full temperature gradient control. The pressure was kept relatively constant (± 5 bar) during multiple inhibitor injections and Hydrate dissociation by batch removal of gas from the top of the cell. The results are presented in this paper including pressure response due to Hydrate dissociation, reformation of gas Hydrate, and possibility of ice formation as a result of gas Hydrate dissociation.
Jianbo Zhang - One of the best experts on this subject based on the ideXlab platform.
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an integrated prediction model of Hydrate Blockage formation in deep water gas wells
International Journal of Heat and Mass Transfer, 2019Co-Authors: Jianbo Zhang, Youqiang LiaoAbstract:Abstract Hydrate formation and deposition in pipelines easily cause Blockage in deep-water oil and gas development. Current studies on Hydrate Blockage in the wellbore of deep-water gas wells are dispersed. In this study, considering the variations in temperature and pressure, and the characteristics of Hydrate behaviors, an integrated prediction model for Hydrate Blockage formation in deep-water gas wells was developed. The model results calculated using the model were in good agreement with the laboratory data for the flow loop and the field-measured data. Using the integrated model, the distribution of the Hydrate stability region and the laws of the Hydrate layer growth in the wellbore of deep-water gas wells can be accurately predicted, which are basis for assessing the risk of Hydrate Blockage. Moreover, the Hydrates deposited on the inner wall of the tube are distributed non-uniformly. With an increase in the time or decrease in the inhibitor concentration, the risk of Hydrate Blockage increases. Based on the proposed model, a method for the prevention of Hydrate Blockage, is developed based on the safe operation window during deep-water gas well testing. Further, a new Hydrate Blockage prevention method that involves changing the testing schedule is discussed in this paper. These provide theoretical references for Hydrate Blockage prevention in deep-water gas well testing.
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flow assurance during deepwater gas well testing Hydrate Blockage prediction and prevention
Journal of Petroleum Science and Engineering, 2018Co-Authors: Zhi Yuan Wang, Jianbo Zhang, Yang Zhao, Jing YuAbstract:Abstract Hydrates cause serious flow assurance problems during deepwater operations (e.g. well testing). In order to efficiently prevent wellbore/pipeline Blockage, it is of great importance to have a good understanding of Hydrate formation, deposition and Blockage behavior in the flowline. In this work, a model is developed to describe the development of Hydrate Blockage in the wellbore. The results indicate a non-uniform Hydrate layer is formed on the inner wall along the testing tubing during deepwater gas well testing. With the proposed model, the position where Hydrate Blockage is most likely to occur can be identified. The Blockage severity in terms of dimensionless Hydrate layer thickness can also be assessed. Based on the model, a method is developed to prevent Hydrate Blockage with lower inhibitor consumption. We recommend that testing operations should be run within the Hydrate Blockage Free Window (HBFW). The HBFW refers to the period from the beginning of testing operations to the moment when a significant pressure drop increase is encountered. Implementation procedure of the proposed method is developed and further illustrated through case studies. The inhibitor consumption is much lower compared with the current over-inhibition THI-based method. This work provides possible ways to overcome the shortcomings of the current over-inhibition THI-based method.
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modeling of Hydrate Blockage in gas dominated systems
Energy & Fuels, 2016Co-Authors: Yang Zhao, Litao Chen, Jianbo Zhang, Xuerui WangAbstract:Field experience indicates that Hydrates formed in pipelines/wellbore may result in severe conduit Blockage and other safety problems in oil/gas development. For gas-dominated systems, one key step to address the Hydrate problems is the coupling of multiphase flow and Hydrate behavior (formation, deposition, etc.), which has not been well studied so far. In this paper, a hydro-thermo-Hydrate coupling model for a gas-dominated system is developed by considering the interactions between multiphase flow and Hydrate occurrence which is described as layer growth from Hydrate deposition on the wall. The accuracy and reliability of the proposed model have been verified with field and literature data. By using the new model, Hydrate formation and deposition during deepwater gas well testing operations are simulated. For a typical deepwater gas well (water depth ∼1500 m, gas production rate ∼50 × 104 m3/d, liquid holdup ∼3%, without inhibitors), it takes 30 or more hours for Hydrates to block the testing tubing. T...
Deqing Liang - One of the best experts on this subject based on the ideXlab platform.
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anti agglomeration evaluation and raman spectroscopic analysis on mixed biosurfactants for preventing ch4 Hydrate Blockage in n octane water systems
Energy, 2021Co-Authors: Lingli Shi, Guodong Hou, Deqing LiangAbstract:Abstract 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.
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Investigation of the Flow Characteristics of Methane Hydrate Slurries with Low Flow Rates
Energies, 2017Co-Authors: Cuiping Tang, Xiaodong Shen, Xiangyong Zhao, Yong He, Dongliang Li, Deqing LiangAbstract:Gas Hydrate Blockage in pipelines during offshore production becomes a major problem with increasing water depth. In this work, a series of experiments on gas Hydrate formation in a flow loop was performed with low flow rates of 0.33, 0.66, and 0.88 m/s; the effects of the initial subcooling, flow rate, pressure, and morphology were investigated for methane Hydrate formation in the flow loop. The results indicate that the differential pressure drop (Δ P ) across two ends of the horizontal straight pipe increases with increasing Hydrate concentration at the early stage of gas Hydrate formation. When the flow rates of Hydrate fluid are low, the higher the subcooling is, the faster the transition of the Hydrates macrostructures. Gas Hydrates can agglomerate, and sludge Hydrates appear at subcoolings of 6.5 and 8.5 °C. The difference between the Δ P values at different flow rates is small, and there is no obvious influence of the flow rates on Δ P . Three Hydrate macrostructures were observed: slurry-like, sludge-like, and their transition. When the initial pressure is 8.0 MPa, large methane Hydrate Blockages appear at the gas Hydrate concentration of approximately 7%. Based on the gas–liquid two-phase flow model, a correlation between the gas Hydrate concentration and the value of Δ P is also presented. These results can enrich the kinetic data of gas Hydrate formation and agglomeration and provide guidance for oil and gas transportation in pipelines.
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A model for estimating flow assurance of Hydrate slurry in pipelines
Journal of Natural Gas Chemistry, 2010Co-Authors: Wuchang Wang, Deqing Liang, Yuxing LiAbstract:The problem of Hydrate Blockage of pipelines in offshore production is becoming ever-increasing severe because oil fields in ever-increasing unusual environments have been brought in production. HCFC-141b and THF were selected as the substitutes to study the flow assurance of the Hydrates in pipelines. There are critical Hydrate volume concentrations for these two slurries. Hydrate slurries behave like Bingham fluids and have high agglomerating tendency when the Hydrate volume concentrations are larger than the critical ones. Based on rheological behaviors of these two Hydrates, a non-dimensional parameter is proposed through studying the driving forces of agglomeration among Hydrate particles, which shows the agglomerating probability of Hydrate particles in pipeline and can be used to judge the safety of the pipeline. Moreover, a safe model to judge the safely flow Hydrate slurries was presented and verified with the experimental data, which demonstrates that the model is effective to judge whether the pipeline can be run safely or not.
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Experimental study on flow characteristics of tetrahydrofuran Hydrate slurry in pipelines
Journal of Natural Gas Chemistry, 2010Co-Authors: Wuchang Wang, Deqing Liang, Yuxing LiAbstract:Tetrahydrofuran (THF) was selected as the substitute to study the flow behaviors and the mechanism of the Hydrates Blockage in pipelines. The slurrylike Hydrates and slushlike Hydrates are observed with the formation of Hydrates in pipeline. There is a critical Hydrate volume concentration of 50.6% for THF slurries and pipeline will be free of Hydrate Blockage while the Hydrate volume concentration is lower than the critical volume concentration; otherwise, pipeline will be easy to be blocked. Fully turbulent flow occurs and friction factors tend to be constant when the velocity reaches 1.5 m/s. And then, constant values of friction factors that depend on the volume concentrations in the slurry were regressed to estimate the pressure drops of THF Hydrate slurry at large mean velocity. Finally, a safe region, defined according to the critical Hydrate volume concentration, was proposed for THF Hydrate slurry, which may provide some insight for further studying the natural gas Hydrate slurries and judge whether the pipeline can be run safely or not.
Youqiang Liao - One of the best experts on this subject based on the ideXlab platform.
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an integrated prediction model of Hydrate Blockage formation in deep water gas wells
International Journal of Heat and Mass Transfer, 2019Co-Authors: Jianbo Zhang, Youqiang LiaoAbstract:Abstract Hydrate formation and deposition in pipelines easily cause Blockage in deep-water oil and gas development. Current studies on Hydrate Blockage in the wellbore of deep-water gas wells are dispersed. In this study, considering the variations in temperature and pressure, and the characteristics of Hydrate behaviors, an integrated prediction model for Hydrate Blockage formation in deep-water gas wells was developed. The model results calculated using the model were in good agreement with the laboratory data for the flow loop and the field-measured data. Using the integrated model, the distribution of the Hydrate stability region and the laws of the Hydrate layer growth in the wellbore of deep-water gas wells can be accurately predicted, which are basis for assessing the risk of Hydrate Blockage. Moreover, the Hydrates deposited on the inner wall of the tube are distributed non-uniformly. With an increase in the time or decrease in the inhibitor concentration, the risk of Hydrate Blockage increases. Based on the proposed model, a method for the prevention of Hydrate Blockage, is developed based on the safe operation window during deep-water gas well testing. Further, a new Hydrate Blockage prevention method that involves changing the testing schedule is discussed in this paper. These provide theoretical references for Hydrate Blockage prevention in deep-water gas well testing.
