The Experts below are selected from a list of 582 Experts worldwide ranked by ideXlab platform
Bahman Tohidi - One of the best experts on this subject based on the ideXlab platform.
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Anomalous KHI-Induced dissociation of gas Hydrates inside the Hydrate stability zone: Experimental observations & potential mechanisms
Journal of Petroleum Science and Engineering, 2019Co-Authors: Morteza Aminnaji, Ross Anderson, Bahman TohidiAbstract:Abstract In the past decade, the low dosage Hydrate inhibitors (LDHIs) - which include kinetic Hydrate inhibitors (KHIs) and anti-agglomerants (AAs) - have seen increasing use for gas Hydrate Prevention in hydrocarbon production operations, offering significant CAPEX/OPEX advantages over traditional thermodynamic inhibitors (e.g. methanol, glycols). Typically dosed at
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gas Hydrate Prevention and flow assurance by using mixtures of ionic liquids and synergent compounds combined kinetics and thermodynamic approach
Energy & Fuels, 2016Co-Authors: Fahed M Qureshi, Mert Atilhan, Tausif Altamash, Mohamad Tariq, Majeda Khraisheh, Santiago Aparicio, Bahman TohidiAbstract:The thermodynamic and kinetic Hydrates inhibition effects of addition of synergents poly(ethylene oxide) (PEO) and vinyl caprolactum (VCAP) with ionic liquids 1-methyl-1-propylpyrrolidinium chloride [PMPy][Cl] and 1-methyl-1-propylpyrrolidinium triflate [PMPy][triflate] were studied on a synthetic quaternary gas mixture (methane, C1 = 84.20%; ethane, C2 = 9.90%; n-hexane, C6+ = 0.015%; CO2 = 2.46%; N2 = 2.19%). The results show that the addition of synergents with ionic liquids helps to improve their thermodynamic and kinetic Hydrate inhibition effectiveness simultaneously.
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Effect of Hold Up on the Hydrate Stability Zone
All Days, 2015Co-Authors: Anastasios Chalkidis, Bahman TohidiAbstract:Abstract Currently, reservoir fluid compositions (based on PVT reports) are used in predicting the Hydrate stability zone. However, in multiphase flow there are variations in the local composition that may affect the Hydrate stability zone. The main objective of this work was to investigate the effect of hold-up and the resulting variation in the local composition on the Hydrate stability zone of various hydrocarbon systems. A thermodynamic software was used to predict the composition of various phases at different locations along a pipeline. A range of liquid hold-ups were assumed and the local composition was recalculated. The Hydrate option of the software was used to predict the Hydrate stability zone of the resulting local fluid composition. The calculations were repeated for a number of fluid systems and the results are presented in this work. The calculated Hydrate stability zones for various hold-ups were compared with that of original reservoir fluid. The results show that hold-up plays an important role on the Hydrate stability zone. High gas hold-up shifts the Hydrate stability zone to the right. However, as high gas hold-ups occurs at high point and away from aqueous phase, in case of changes in the system conditions the amount of Hydrates are limited to the amount of water available. This paper demonstrates that the Hydrate stability zone of a multiphase fluid in a pipeline is a function of hold-up and the resulting changes in the local composition. This could have important consequences on the Hydrate Prevention strategies.
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Do We Have New Solutions to the Old Problem of Gas Hydrates
Energy & Fuels, 2012Co-Authors: Bahman Tohidi, Ross Anderson, Antonin Chapoy, Jinhai Yang, Rhoderick William BurgassAbstract:Gas Hydrates are crystalline compounds formed as a result of the combination of suitable size gas molecules and water under suitable pressure and temperature conditions. They resemble ice but unlike ice can form at temperatures well above the ice formation temperature. Their formation in oil and gas pipelines could result in serious operational problems and safety concerns. The conventional techniques in avoiding gas Hydrate problems are dehydration, insulation, and/or heating or injection of thermodynamic or low-dosage Hydrate inhibitors. In this paper, we discuss some new techniques for preventing gas Hydrate problems that could improve the reliability of Hydrate Prevention techniques and/or reduce the associated costs. The new solutions include Hydrate safety margin monitoring, early Hydrate detection systems, and the latest results and techniques for evaluating low-dosage Hydrate inhibitors. The application of thermodynamic modeling to CO2-rich systems will also be presented.
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On modelling gas Hydrate inhibition by salts and organic inhibitors
Journal of Petroleum Science and Engineering, 2010Co-Authors: Rahim Masoudi, Bahman TohidiAbstract:Abstract We present the application of a recently developed thermodynamic model to obtain better understanding of gas Hydrate inhibition effects of combinations of salts (e.g., NaCl, KCl, CaCl2) and Hydrate organic inhibitors (e.g., mono ethylene glycol and methanol) used for gas Hydrate Prevention scenarios in the gas and oil industry. In the first section of this work, the effect of salt-organic inhibitor interactions on Hydrate inhibition effects has been studied. For this purpose, two possible approaches for modelling the Hydrate inhibition effect of a mixture of salts and organic inhibitors have been investigated. They are: (1) considering the summation of separate effects of salt and organic inhibitors and ignoring the effect of interaction between inhibitors, and (2) considering the effect of the mixture of salt and organic inhibitor and taking into account the effect of interaction between these. The study shows that the Hydrate formation inhibiting the effect of the approach 1 surpasses the effect calculated from approach 2, especially at high concentrations of inhibitors. That means predictive Hydrate numerical models and empirical correlations should precisely take into account the interaction between electrolytes and organic inhibitors in order to accurately predict Hydrate inhibition effects. In the second section of this work, maximum gas Hydrate suppression temperature locus for systems containing salts and organic inhibitors has been investigated. The aim of this section was to obtain a guideline for efficient application of combinations of salts and organic inhibitors in order to operate in the Hydrate and salt free regions. It has been concluded that high concentrations of organic inhibitors are preferred to salts as far as Hydrate Prevention is concerned.
Manzong Fang - One of the best experts on this subject based on the ideXlab platform.
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Gas Hydrate risks and Prevention for deep water drilling and completion: A case study of well QDN-X in Qiongdongnan Basin, South China Sea
Petroleum Exploration and Development, 2014Co-Authors: Liang Zhang, Chong Zhang, Haidong Huang, Yu Zhang, Shaoran Ren, Manzong FangAbstract:Abstract Taking a deep-water exploration well of natural gas located in the Qiongdongnan Basin in the South China Sea as an example, the Hydrate risks of the well under operational conditions during drilling and testing processes were analyzed, and the corresponding Hydrate Prevention solutions were presented and verified by lab experiments and field application. Based on the predicted gas Hydrate equilibrium curves and the calculated wellbore pressure-temperature fields, the Hydrate risks were analyzed. The maximum sub-cooling temperature is 6.5 °C during normal drilling with a small Hydrate stability zone in the wellbore; when the drilling or testing stops, the Hydrate stability zone in the wellbore becomes larger and the maximum sub-cooling temperatures are 19 °C and 23 °C respectively; the maximum sub-cooling temperature at the beginning of testing is no more than that when testing stops; when the tested production rate of natural gas increases, the Hydrate stability zone in the wellbore decreases or even disappears if the gas rate is more than 25×10 4 m 3 /d. The designed Hydrate Prevention solutions include: adding sodium chloride and ethylene glycol into drilling fluid during normal drilling and when drilling stops; adding calcium chloride/potassium formate and ethylene glycol into testing fluid; applying downhole methyl alcohol injection when the production rate of natural gas is lower than 25×10 4 m 3 /d; filling the testing string with testing fluid when the test shuts down for a long time. Lab experiments and field operations have indicated that all the designed solutions can meet the requirements of Hydrate Prevention.
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Gas Hydrate risks and Prevention for deep water drilling and completion: A case study of well QDN-X in Qiongdongnan Basin, South China Sea
KeAi Communications Co. Ltd., 2014Co-Authors: Liang Zhang, Chong Zhang, Haidong Huang, Yu Zhang, Shaoran Ren, Manzong FangAbstract:Taking a deep-water exploration well of natural gas located in the Qiongdongnan Basin in the South China Sea as an example, the Hydrate risks of the well under operational conditions during drilling and testing processes were analyzed, and the corresponding Hydrate Prevention solutions were presented and verified by lab experiments and field application. Based on the predicted gas Hydrate equilibrium curves and the calculated wellbore pressure-temperature fields, the Hydrate risks were analyzed. The maximum sub-cooling temperature is 6.5 °C during normal drilling with a small Hydrate stability zone in the wellbore; when the drilling or testing stops, the Hydrate stability zone in the wellbore becomes larger and the maximum sub-cooling temperatures are 19 °C and 23 °C respectively; the maximum sub-cooling temperature at the beginning of testing is no more than that when testing stops; when the tested production rate of natural gas increases, the Hydrate stability zone in the wellbore decreases or even disappears if the gas rate is more than 25×104 m3/d. The designed Hydrate Prevention solutions include: adding sodium chloride and ethylene glycol into drilling fluid during normal drilling and when drilling stops; adding calcium chloride/potassium formate and ethylene glycol into testing fluid; applying downhole methyl alcohol injection when the production rate of natural gas is lower than 25×104 m3/d; filling the testing string with testing fluid when the test shuts down for a long time. Lab experiments and field operations have indicated that all the designed solutions can meet the requirements of Hydrate Prevention. Key words: gas Hydrate, drilling fluid, wellbore temperature, sub-cooling temperature, Hydrate inhibitor, deep water drillin
Vladimir A. Vinokurov - One of the best experts on this subject based on the ideXlab platform.
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Synergistic effect of salts and methanol in thermodynamic inhibition of sII gas Hydrates
The Journal of Chemical Thermodynamics, 2019Co-Authors: Anton P. Semenov, Andrey S. Stoporev, Rais I. Mendgaziev, Pavel A. Gushchin, Vadim N. Khlebnikov, V.s. Yakushev, Vladimir Istomin, Daria V. Sergeeva, Vladimir A. VinokurovAbstract:Abstract In this work phase equilibrium conditions for structure II (sII) gas Hydrates in systems containing a mixture of salts (NaCl, KCl, CaCl2, MgCl2) and methanol have been measured using a high-pressure cell. The concentration of salts in aqueous solution (model of reservoir water) was constant in all experiments and equal to 18 wt%. Phase equilibrium conditions were determined by the isochoric method for pressures ranging from 1 to 4.7 MPa and for mass fraction of methanol from 0 to 50 wt%. The experimental data were obtained for water + salts, water + methanol, and water + salts + methanol systems. From the results obtained, it follows that 20 wt% of methanol in distilled water (DW) gives the thermodynamic shift of the Hydrate decomposition temperature close to the brine one. Mixtures of 10% methanol + brine and 20% methanol + brine significantly better reduce the equilibrium temperature of Hydrate dissociation compared to samples with the similar total mass fraction of inhibitor (methanol) in water (30, 40 wt%). At the pressures of more than 4 MPa combination of 20 wt% methanol + brine provide the same thermodynamic inhibition as 50 wt% of methanol in water. Thus, the synergism of the methanol + salts mixtures in the thermodynamic inhibition of sII gas Hydrates has been observed. Synergism manifested itself in a greater shift of equilibrium curves to lower temperatures and higher pressures compared to systems containing only one thermodynamic Hydrate inhibitor (THI). The obtained results indicate the possibility of a significant reduction in the consumption of polar organic THI for gas Hydrate Prevention in deposits with highly mineralized brine. However, it is necessary to take into account the possible complications associated with the precipitation of salts from solutions of water – salt(s) – polar organic THI due to the possible limited mutual solubility of the components.
Liang Zhang - One of the best experts on this subject based on the ideXlab platform.
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Gas Hydrate risks and Prevention for deep water drilling and completion: A case study of well QDN-X in Qiongdongnan Basin, South China Sea
Petroleum Exploration and Development, 2014Co-Authors: Liang Zhang, Chong Zhang, Haidong Huang, Yu Zhang, Shaoran Ren, Manzong FangAbstract:Abstract Taking a deep-water exploration well of natural gas located in the Qiongdongnan Basin in the South China Sea as an example, the Hydrate risks of the well under operational conditions during drilling and testing processes were analyzed, and the corresponding Hydrate Prevention solutions were presented and verified by lab experiments and field application. Based on the predicted gas Hydrate equilibrium curves and the calculated wellbore pressure-temperature fields, the Hydrate risks were analyzed. The maximum sub-cooling temperature is 6.5 °C during normal drilling with a small Hydrate stability zone in the wellbore; when the drilling or testing stops, the Hydrate stability zone in the wellbore becomes larger and the maximum sub-cooling temperatures are 19 °C and 23 °C respectively; the maximum sub-cooling temperature at the beginning of testing is no more than that when testing stops; when the tested production rate of natural gas increases, the Hydrate stability zone in the wellbore decreases or even disappears if the gas rate is more than 25×10 4 m 3 /d. The designed Hydrate Prevention solutions include: adding sodium chloride and ethylene glycol into drilling fluid during normal drilling and when drilling stops; adding calcium chloride/potassium formate and ethylene glycol into testing fluid; applying downhole methyl alcohol injection when the production rate of natural gas is lower than 25×10 4 m 3 /d; filling the testing string with testing fluid when the test shuts down for a long time. Lab experiments and field operations have indicated that all the designed solutions can meet the requirements of Hydrate Prevention.
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Gas Hydrate risks and Prevention for deep water drilling and completion: A case study of well QDN-X in Qiongdongnan Basin, South China Sea
KeAi Communications Co. Ltd., 2014Co-Authors: Liang Zhang, Chong Zhang, Haidong Huang, Yu Zhang, Shaoran Ren, Manzong FangAbstract:Taking a deep-water exploration well of natural gas located in the Qiongdongnan Basin in the South China Sea as an example, the Hydrate risks of the well under operational conditions during drilling and testing processes were analyzed, and the corresponding Hydrate Prevention solutions were presented and verified by lab experiments and field application. Based on the predicted gas Hydrate equilibrium curves and the calculated wellbore pressure-temperature fields, the Hydrate risks were analyzed. The maximum sub-cooling temperature is 6.5 °C during normal drilling with a small Hydrate stability zone in the wellbore; when the drilling or testing stops, the Hydrate stability zone in the wellbore becomes larger and the maximum sub-cooling temperatures are 19 °C and 23 °C respectively; the maximum sub-cooling temperature at the beginning of testing is no more than that when testing stops; when the tested production rate of natural gas increases, the Hydrate stability zone in the wellbore decreases or even disappears if the gas rate is more than 25×104 m3/d. The designed Hydrate Prevention solutions include: adding sodium chloride and ethylene glycol into drilling fluid during normal drilling and when drilling stops; adding calcium chloride/potassium formate and ethylene glycol into testing fluid; applying downhole methyl alcohol injection when the production rate of natural gas is lower than 25×104 m3/d; filling the testing string with testing fluid when the test shuts down for a long time. Lab experiments and field operations have indicated that all the designed solutions can meet the requirements of Hydrate Prevention. Key words: gas Hydrate, drilling fluid, wellbore temperature, sub-cooling temperature, Hydrate inhibitor, deep water drillin
Colin D. Wood - One of the best experts on this subject based on the ideXlab platform.
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Performance of Poly(N-isopropylacrylamide)-Based Kinetic Hydrate Inhibitors for Nucleation and Growth of Natural Gas Hydrates
Energy & Fuels, 2017Co-Authors: J.h. Park, Kelly Cristine Da Silveira, Qi Sheng, Colin D. WoodAbstract:Hydrate Prevention strategies for offshore flowlines are now moving toward Hydrate risk management by delaying its nucleation and growth using water-soluble polymers, known as kinetic Hydrate inhibitors (KHIs). This study investigates the natural gas Hydrate inhibition performance of three poly(N-isopropylacrylamide) (PNIPAM)-based KHIs [poly(N-isopropylacrylamide-co-acrylic acid (PNIPAM-co-AA), poly(N-isopropylacrylamide-co-cyclopentylamine (PNIPAM-co-Cp), and poly(N-isopropylacrylamide-co-tert-butylamine (PNIPAM-co-C4t)] by determining the Hydrate onset time, growth rate, and resistance to flow using a high-pressure autoclave. These data are compared to three control groups [water, Luvicap solution, and polyvinylpyrrolidone (PVP)] under various cooling rates (0.25, 0.033, and 0.017 K/min). The results show that the nucleation of Hydrate crystals was delayed in the presence of the KHI candidates as assessed using the onset time at different cooling rates. The effect of the KHI candidate on the Hydrate gr...
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High-Throughput Testing of Kinetic Hydrate Inhibitors
Energy & Fuels, 2016Co-Authors: Nobuo Maeda, Kelly Cristine Da Silveira, Qi Sheng, Celesta Fong, Wendy Tian, Aaron Seeber, W. D. Ganther, Malcolm A. Kelland, Mohamed F. Mady, Colin D. WoodAbstract:The formation of clathrate Hydrates is considered to be a major flow assurance problem in offshore oil and gas lines. Kinetic Hydrate inhibitors (KHIs) are used for Hydrate Prevention, with their efficiency assessed by techniques that are a bottleneck for new materials development in this area. Efficient design of high-performance advanced materials requires a thorough understanding of the structure–property relationships that is currently hindered by conventional evaluation protocols. A cost-effective method for the rapid, parallel screening of potential KHIs is desirable, which preferably does not involve handling of highly pressurized and potentially flammable/explosive fuel gases. We have developed a novel high-throughput KHI ranking method based on its inhibition performance of Structure II (sII)-forming cyclopentane (c-C5) Hydrate under atmospheric pressure. Ice seeding was used to induce the nucleation of c-C5 Hydrate to save time, so the method focuses on the growth inhibition performance (as oppo...
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High-Throughput Testing of Kinetic Hydrate Inhibitors
2016Co-Authors: Nobuo Maeda, Qi Sheng, Celesta Fong, Wendy Tian, Aaron Seeber, W. D. Ganther, Malcolm A. Kelland, Mohamed F. Mady, Kelly C. Da Silveira, Colin D. WoodAbstract:The formation of clathrate Hydrates is considered to be a major flow assurance problem in offshore oil and gas lines. Kinetic Hydrate inhibitors (KHIs) are used for Hydrate Prevention, with their efficiency assessed by techniques that are a bottleneck for new materials development in this area. Efficient design of high-performance advanced materials requires a thorough understanding of the structure–property relationships that is currently hindered by conventional evaluation protocols. A cost-effective method for the rapid, parallel screening of potential KHIs is desirable, which preferably does not involve handling of highly pressurized and potentially flammable/explosive fuel gases. We have developed a novel high-throughput KHI ranking method based on its inhibition performance of Structure II (sII)-forming cyclopentane (c-C5) Hydrate under atmospheric pressure. Ice seeding was used to induce the nucleation of c-C5 Hydrate to save time, so the method focuses on the growth inhibition performance (as opposed to the nucleation inhibition performance) of a KHI. Comparison of some commercial KHIs [Luvicap 21W (N-vinylpyrrolidone:N-vinylcaprolactam 2:1 copolymer), Luvicap 55W (N-vinylpyrrolidone:N-vinylcaprolactam 1:1 copolymer), polyvinylpyrrolidone (PVP), poly(N-isopropylacrylamide) (PNIPAM), and polyacrylamide (PAM)] was made using this new screen, which has been validated against conventional rocking cell measurements. The observed efficacy performance ranking of these KHIs was Luvicap 21W ≥ Luvicap 55W > PNIPAM ≥ PVP > PAM. This ranking was in reasonable agreement with the rocking cell data that gives the ranking Luvicap 55W > Luvicap 21W > PNIPAM > PVP > PAM. This method enabled parallel screening of multiple KHIs with major advantages in time, instrument complexity, safety, and material. We propose that this method could serve as a useful first screening method for identifying promising candidates for more rigorous testing
