Open Collections

UBC Theses and Dissertations

UBC Theses Logo

UBC Theses and Dissertations

Laboratory evaluation of chemical and biological kinetic gas hydrate inhibitors Sharifi, Hassan 2014

Your browser doesn't seem to have a PDF viewer, please download the PDF to view this item.

Item Metadata

Download

Media
24-ubc_2015_february_sharifi_hassan.pdf [ 4.62MB ]
Metadata
JSON: 24-1.0166089.json
JSON-LD: 24-1.0166089-ld.json
RDF/XML (Pretty): 24-1.0166089-rdf.xml
RDF/JSON: 24-1.0166089-rdf.json
Turtle: 24-1.0166089-turtle.txt
N-Triples: 24-1.0166089-rdf-ntriples.txt
Original Record: 24-1.0166089-source.json
Full Text
24-1.0166089-fulltext.txt
Citation
24-1.0166089.ris

Full Text

i  LABORATORY EVALUATION OF CHEMICAL AND BIOLOGICAL KINETIC GAS HYDRATE INHIBITORS    by Hassan Sharifi  M.A.Sc, Amirkabir University of Technology, 2005  A THESIS SUBMITTED IN PARTIAL FULFILLMENT OF THE REQUIREMENTS FOR THE DEGREE OF  DOCTOR OF PHILOSOPHY in THE FACULTY OF GRADUATE AND POSTDOCTORAL STUDIES (Chemical and Biological Engineering)  THE UNIVERSITY OF BRITISH COLUMBIA (Vancouver)   December 2014  © Hassan Sharifi, 2014                                                                                                                                                           ii   Abstract  For practical purposes, kinetic hydrate inhibitors must perform in a predictable manner in the field.  However, the complexity of the petroleum fluid composition, the presence of dissolved electrolytes, and high driving force (overpressure or sub-cooling), make it difficult to impossible task to achieve. In this thesis, the performance of two chemical kinetic inhibitors, polyvinylcaprolactam (PVCap) and polyvinylpyrrolidone (PVP), and two biological ones, type I and III antifreeze proteins (AFP I and III) were evaluated under conditions mimicking oil and gas filed ones. The evaluation was done by using a double high pressure stirred vessel (crystallizer), a high-pressure cell in conjunction with a rotational rheometer and a high pressure micro differential scanning calorimeter. Although the above noted inhibitors were found to prolong the hydrate induction time and reduce the initial hydrate growth in saline solutions, the rate was found to increase when hydrate crystals started to form in the gas phase of the crystallizer.  Circular dichroism experiments suggested that the saline solution does not perturb the structure of AFP I and III. However, in the presence of NaCl, the inhibitory activity of AFP I to prolong induction time decreased while AFP III was more active. Here, increase in induction time was ordered: no inhibitor<AFP I<AFP III<PVCap<PVP. Moreover, in the presence of the PVP and PVCap increase in hydrate slurry viscosity was more readily. Once hydrate formed, decomposition started sooner and was slower.  The addition of n-heptane created a 4th phase in the gas hydrate formation system under study. This resulted in an increase in the induction time and a slowing of hydrate growth. Unexpectedly, addition of PVP, PVCap and AFP I decreased induction time, whereas AFP III had no impact on hydrate crystal nucleation. Here, the inhibitors activity to delay nucleation was                                                                                                                                                           iii  ordered: AFP I<PVP<PVCap<AFP III~ no inhibitor. Nonetheless, for all inhibitors, gas hydrate growth was significantly inhibited and no acceleration in hydrate growth was observed. Meanwhile, hydrate particles remained dispersed efficiently by addition of chemical inhibitors. Once hydrate formed, however, hydrate decomposition started later in the presence of AFPs and sooner in the presence of chemical inhibitors and took longer.                                                                                                                                                                                    iv  Preface  Some parts of this thesis corresponded to chapters one to six were published as peer-reviewed papers and presented in conferences which are listed below. The authors include Sharifi H., Ripmeester J., Walker V. K., Hatzikiriakos. S. G. and Englezos P.   Published articles: 1. Sharifi, H.; Ripmeester, J.; Walker, V. K.; Englezos, P. “Kinetic inhibition of natural gas hydrates in saline solutions and heptane.” Fuel, 2014, 117, 109-117.1  2. Sharifi, H.; Hatzikiriakos, S. G.; Englezos, P. “Rheological evaluation of kinetic hydrate inhibitors in NaCl/n-heptane solutions.” AIChE J., 2014, Vol. 60, No. 7, 2654-2659.2  3. Sharifi, H.; Walker, V. K.; Ripmeester, J.; Englezos, P. “Insights into the behavior of biological clathrate hydrate inhibitors in aqueous saline solutions.” Crystal Growth and Design, 2014, 14, 2923-2930.3  4. Sharifi, H.; Walker, V. K.; Ripmeester, J.; Englezos, P. “Inhibition activity of antifreeze proteins with natural gas hydrates in saline and the light crude oil mimic, heptane.” Energy and Fuels, 2014, 28, 3712-3717.4                                                                                                                                                               v  Conference presentations: 1. Sharifi, H.; Daraboina, N.; Ripmeester, J.; Englezos, P. “Nucleation, growth and dissociation of gas hydrates in gas/water and gas/oil/water type system.” 4th International Acid Gas Injection Symposium. Calgary, Alberta, Canada. September 24-27, 2013.  2. Sharifi, H.; Ripmeester, J.; Englezos, P. “Laboratory assessment of kinetic gas hydrate inhibitors.” 63rd Canadian Society Chemical Engineering Conference. Fredericton, NB, Canada. October 20-23, 2013.   3. Sharifi, H.; Ripmeester, J.; Walker, V. K.; Englezos, P. “Evaluation of kinetic hydrate inhibitors in saline solutions and n-heptane“, 8th International Conference on Gas Hydrates, Beijing, China, July 28- August 1, 2014.  4. Sharifi, H.; Hatzikiriakos, S. G.; Englezos, P. “Effect of kinetic inhibitors on gas hydrate nucleation, growth and agglomeration in NaCl/n-heptane solutions“, 8th International Conference on Gas Hydrates, Beijing, China, July 28- August 1, 2014.  Professor Peter Englezos is my principle research supervisor at the University of British Columbia. During the course of my research, I was fortunate to hold meaningful discussions with Professor Virginia K. Walker who is a professor at Queen’s university, Dr. John Ripmeester who is a principal research officer at SIMS, National Research Council Ottawa and Professor Savvas G. Hatzikiriakos who is a professor at the University of British Columbia.                                                                                                                                                           vi   The literature review, experimental design, performing experiments and data analysis were done extensively by Sharifi, H. under supervision of Professor P. Englezos. Finally, I did the final preparation for each manuscript after careful revision and approval of my supervisory committee.                                                                                                                                                                                       vii  Table of contents  Abstract ........................................................................................................................................................ ii Preface ......................................................................................................................................................... iv Table of contents ....................................................................................................................................... vii List of tables................................................................................................................................................ ix List of figures ............................................................................................................................................... x List of symbols .......................................................................................................................................... xiii List of abbreviations ................................................................................................................................ xiv Acknowledgements .................................................................................................................................. xvi Dedication ................................................................................................................................................ xvii  : Introduction ............................................................................................................................ 1 Chapter 11.1. What is gas hydrate ....................................................................................................................... 1 1.2. How to prevent or manage the risk of hydrate formation in pipelines .......................................... 4  : Experimental methods ........................................................................................................... 9 Chapter 22.1. The materials ................................................................................................................................. 9 2.2. High pressure crystallizer apparatus. ............................................................................................ 9 2.2.1. Gas hydrate crystal formation ............................................................................................. 11 2.2.2. Gas hydrate crystal dissociation .......................................................................................... 13 2.3. High pressure micro differential scanning calorimetry (HP-µDSC) ........................................... 14 2.4. High pressure rheometer. ............................................................................................................ 16 2.4.1. Gas hydrate formation in high pressure rheometer. ............................................................ 17 2.5. Circular dichroism (CD). ............................................................................................................ 18  : Impact of chemical kinetic hydrate inhibitors on gas hydrate formation and Chapter 3dissociation in saline water ....................................................................................................................... 20 3.1. Influence on gas hydrate nucleation ............................................................................................ 20 3.2. Effect of PVP and PVCap on gas hydrate growth in saline solutions ......................................... 27 3.3. Gas hydrate dissociation in the presence of chemical kinetic inhibitors (PVP and PVCap) ...... 32  : Impact of chemical kinetic hydrate inhibitors on gas hydrate formation and Chapter 4dissociation in saline water in the presence of liquid hydrocarbon phase ........................................... 34 4.1. Gas hydrate nucleation in saline solutions and in the presence of n-heptane. ............................ 34 4.2. Effect of PVP and PVCap on gas hydrate growth in saline solutions with heptane ................... 42 4.3. Gas hydrate dissociation in saline solutions in the presence of n-heptane. ................................. 45                                                                                                                                                           viii   : Impact of biological kinetic hydrate inhibitors on gas hydrate formation and Chapter 5dissociation in saline water ....................................................................................................................... 48 5.1. Influence on gas hydrate nucleation ............................................................................................ 48 5.2. Gas hydrate growth in saline solutions in the presence of AFPs ................................................ 55 5.3. Gas hydrate dissociation in the presence of biological kinetic inhibitors in saline solution ....... 59  : Impact of biological kinetic hydrate inhibitors on gas hydrate formation and Chapter 6dissociation in saline water in the presence of liquid hydrocarbon phase ........................................... 63 6.1. Gas hydrate nucleation in saline solutions and in the presence of n-heptane. ............................ 63 6.2. Gas hydrate growth in saline solutions in the presence of liquid hydrocarbon ........................... 67 6.3. Gas hydrate dissociation in saline solutions in the presence of n-heptane. ................................. 69  : Conclusions and recommendations ..................................................................................... 73 Chapter 77.1. Conclusions ................................................................................................................................. 73 7.2. Recommendations for future work. ............................................................................................ 74 Bibliography .............................................................................................................................................. 76                                                                                                                                                                       ix  List of tables  Table ‎3.1. Experimental conditions and results of the gas uptake and DSC experiments showing induction times and nucleation temperatures.. ............................................................................................ 22  Table ‎3.2. Experimental solutions and results showing induction times, growth rates and time elapsed to detect sharp increase in the hydrate slurry viscosity ................................................................................... 26  Table ‎4.1. Experimental conditions and results of the gas uptake and DSC experiments showing induction times and nucleation temperatures. ............................................................................................. 34  Table ‎4.2. Experimental solutions and results showing induction times, growth rates and time elapsed to detect sharp increase in the hydrate slurry viscosity ................................................................................... 41  Table ‎4.3. Comparison between the performance of PVP and PVCap in the formation of gas hydrates under different conditions. .......................................................................................................................... 45  Table ‎5.1. Experimental conditions, showing induction times and nucleation temperature in both HP-µDSC and autoclave experiments  .............................................................................................................. 50  Table ‎5.2. Calculated gas hydrate growth rates in different growth periods .............................................. 57  Table ‎6.1. Experimental conditions, showing induction times and nucleation temperature in both HP-µDSC and autoclave experiments. .............................................................................................................. 65  Table ‎6.2. Comparison between the performance of PVP, PVCap, AFP I and III in gas hydrate formation under different conditions. .......................................................................................................................... 69                                                                                                                                                                     x  List of figures  Figure ‎1.1. Different structures of gas hydrate ............................................................................................ 2  Figure ‎1.2. Hydrate guests versus hydrate cavity size range ....................................................................... 3  Figure ‎1.3. Impact of methanol injection on gas hydrate phase equilibrium conditions for a mixture of CH4, C2H6 and C3H8  ..................................................................................................................................... 4  Figure ‎1.4. Structure of PVP (a) and PVCap (b). ......................................................................................... 5  Figure ‎1.5. Images of three AFPs: a) AFP I, b) AFP III and c) Cf AFP ...................................................... 6  Figure ‎2.1. Schematic of the high pressure apparatus. ............................................................................... 11  Figure ‎2.2. Pressure-Temperature diagram showing the cooling path under constant cooling rate and under constant pressure to form gas hydrate crystals in the high pressure crystallizers. ............................ 12  Figure ‎2.3. Sample holder used for DSC experiments ............................................................................... 15  Figure ‎2.4. Schematic of the high pressure rheometer experimental setup. ............................................... 17  Figure ‎2.5. Pressure, temperature and viscosity profiles during hydrate formation in saline solution. ..... 18  Figure ‎3.1. Temperature profiles of saline solutions with and without inhibitors. .................................... 21  Figure ‎3.2. Pressure profiles of supply reservoirs during gas hydrate formation experiment without and with inhibitors PVP and PVCap  in saline solutions. .................................................................................. 22  Figure ‎3.3. DSC heating curves showing hydrate nucleation in saline solutions with and without inhibitors (PVP or PVCap). ........................................................................................................................ 23  Figure ‎3.4. Temperature profiles during hydrate formation experiments in saline solutions with and without inhibitors (PVP or PVCap) in the high pressure rheometer. .......................................................... 25  Figure ‎3.5.Typical viscosity profiles for saline solutions with and without inhibitors (PVP and PVCap) during gas hydrate formation. ..................................................................................................................... 26  Figure ‎3.6. Cumulative gas consumption during hydrate formation in saline solutions with and without inhibitors (PVP or PVCap) with a cooling rate of 1 K/h and Pexp=7.0 MPa. .............................................. 28  Figure ‎3.7. Gas phase temperatures during gas hydrate formation.. .......................................................... 29  Figure ‎3.8. Hydrate slurry viscosity profiles during hydrate formation in saline solutions with and without inhibitors (PVP or PVCap) in the high pressure rheometer. .......................................................... 30  Figure ‎3.9. Effect of PVP and PVCap on gas hydrate dissociation in saline solutions. ............................ 33                                                                                                                                                            xi  Figure ‎3.10. Gas hydrate dissociation peaks in DSC experiments in the presence of PVP and PVCap .... 33  Figure ‎4.1. Calculated gas hydrate equilibrium conditions for the mixture of CH4 (93%), C2H6 (5%), C3H8 (2%) in 3.5 wt% NaCl aqueous solution in the presence of n-heptane and without it. ...................... 35  Figure ‎4.2. Temperature profiles during gas hydrate formation in saline solutions with and without inhibitors (PVP and PVCap). ...................................................................................................................... 36  Figure ‎4.3. Supply reservoir pressure profiles during gas hydrate formation in saline solutions with and without inhibitors (PVP and PVCap). ......................................................................................................... 37  Figure ‎4.4. DSC heating curves showing hydrate nucleation in saline solutions with and without inhibitors (PVP or PVCap) in the presence of n-heptane. .......................................................................... 37  Figure ‎4.5. Temperature profiles during hydrate formation in the presence of n-heptane in saline solutions with and without inhibitors (PVP or PVCap) in the high pressure rheometer. ........................................... 39  Figure ‎4.6. Viscosity and temperature profiles during gas hydrate formation in the saline solution without inhibitors in the high pressure rheometer.. .................................................................................................. 39  Figure ‎4.7. Viscosity and temperature profiles during gas hydrate formation in the saline solution with PVCap in the high pressure rheometer. ...................................................................................................... 40  Figure ‎4.8. Viscosity and temperature profiles during gas hydrate formation in the saline solution with PVP in the high pressure rheometer. ........................................................................................................... 40  Figure ‎4.9. Effect of KHIs on induction time in saline solutions and the presence of n-heptane in gas uptake, DSC and high pressure rheometer .................................................................................................. 42  Figure ‎4.10. Effect of PVP and PVCap on cumulative consumed gas in the presence of n-heptane in gas uptake experiments ..................................................................................................................................... 43  Figure ‎4.11. Hydrate slurry viscosity profiles during hydrate formation in saline solutions with and without inhibitors (PVP or PVCap) in the presence of heptane under isothermal condition in the high pressure rheometer. ..................................................................................................................................... 44  Figure ‎4.12. Effect of PVP and PVCap on gas hydrate dissociation in saline solutions and n-heptane.. .. 46  Figure ‎4.13. Gas hydrate dissociation peaks in DSC experiments in the presence of PVP and PVCap .... 47  Figure ‎5.1. Temperature profiles of saline solutions with and without inhibitors in the experiments conducted at a cooling rate of 1 K/h and Pexp=7.0 MPa. ............................................................................. 49  Figure 5.2. Pressure profiles of the supply reservoirs during gas hydrate formation experiments conducted at a cooling rate of 1 K/h without inhibitors and with inhibitors AFP I  and AFP III in saline solutions. ..................................................................................................................................................... 49  Figure ‎5.3. HP-µDSC experiments showing hydrate nucleation in the saline solution controls and with AFP I or AFP III. ........................................................................................................................................ 52                                                                                                                                                            xii  Figure ‎5.4. Supply reservoir pressure profiles showing the impact of water salinity on the activity of AFP I inhibitory in gas hydrate inhibition........................................................................................................... 52  Figure ‎5.5. Supply reservoir pressure profiles showing the impact of water salinity on the activity of AFP III inhibitory in gas hydrate inhibition. ....................................................................................................... 52  Figure ‎5.6. Circular dichroism analysis of the biological KHIs in ddH2O and saline plotted as millidegrees vs. wavelength for AFP I and AFP III.................................................................................... 54  Figure ‎5.7. Cumulative gas consumption during hydrate formation in 3.5% saline solution, controls without inhibitors  and with AFP I or AFP III  under a cooling rate of 1 K/h and Pexp=7.0 MPa. ............. 56  Figure ‎5.8. Gas phase temperature profiles during gas hydrate formation for the control  and the presence of AFP I or AFP III  under a cooling rate of 1 K/h and Pexp=7.0 MPa. ...................................................... 58  Figure ‎5.9. Calculated normalized released gas and pressure profiles during gas hydrate dissociation in the control experiments and in the presence of AFP I and AFP III in saline solutions. ............................. 60  Figure ‎5.10. Hydrate dissociation profiles in HP-µDSC experiments for the control and the presence of AFP I or AFP III under a heating rate of 0.2 K/min and Pexp=7.0 MPa ...................................................... 61  Figure ‎6.1. Temperature profiles in the aqueous phase with and without inhibitors at a cooling rate of 1 K/h and Pexp=7.0 MPa. ................................................................................................................................ 64  Figure ‎6.2. Pressure profiles of the supply vessels during gas hydrate formation experiments at a cooling rate of 1 K/h without inhibitors and with inhibitors AFP I and AFP III in saline with heptane. ................ 64  Figure ‎6.3. HP-µDSC experiments showing hydrate nucleation in the control  and with AFP I or AFP III  additives at Pexp=8.0 MPa and a cooling rate at 0.2 K/min. ........................................................................ 66  Figure ‎6.4. Effect of AFP I and III on gas hydrate induction time in saline solutions and the presence of n-heptane in gas uptake experiments and DSC, isothermal protocol and temperature ramping method. ... 67  Figure ‎6.5. Cumulative gas consumption during hydrate formation in control and with AFP I or AFP III  in saline solution at a cooling rate of 1 K/h and Pexp=7.0 MPa. .................................................................. 68  Figure ‎6.6. The calculated normalized released gas during gas hydrate dissociation in control experiments  and presence of AFP I and AFP III in saline solutions. .............................................................................. 70  Figure ‎6.7. Hydrate dissociation profiles in HP-µDSC experiments for control and the presence of AFP I  or AFP III under a heating rate of 0.2 K/min and Pexp=8.0 MPa. ............................................................... 71                                                                                                                                                                xiii  List of symbols  f: final condition e: equilibrium condition G: Gas phase i: initial condition  ntotal: total number of moles of recovered gas ∆nG: number of moles of released gas attributed to the hydrate dissociation and the reduction of gas solubility in the liquid phase at any given time ∆nH: number of moles of gas consumed to form hydrates or dissolved in solution P: Pressure R: universal gas constant t: any given time T: Temperature V: Volume z: gas compressibility factor  0: the zero time                                                                                                                                                                    xiv   List of abbreviations  AFP I: type I antifreeze protein AFP III: type III antifreeze protein CD: Circular dichroism CfAFP: Choristoneura fumiferana antifreeze protein CR: Crystallizer CSMGem: a program written by Colorado School of Mines for the prediction of the thermodynamically stable hydrate structures and cage occupancy  CV: Control Valve DAQ: Data acquisition  dd: deionized and distilled exp: experimental condition Exo: Exothermic 1H NMR: Hydrogen Nuclear Magnetic Resonance HPR: High Pressure Rheometer HP-µDSC: High Pressure micro Differential Scanning Calorimeter  KHIs: Kinetic Hydrate Inhibitors LDHIs: Low Dosage Hydrate Inhibitors mM: milli Molar M: Motor Mw: Molecular weight PCV: Pressure Control Valve Pexp: Experimental Pressure Pi: Initial Pressure PVCap: PolyVinylCaprolactam PVP: PolyVinylPyrrolidone PT: Pressure Transmitter/Transducer TC: Thermocouple                                                                                                                                                           xv  Texp: Experimental Temperature Teq: Equilibrium Temperature Tnucleation: Nucleation Temperature THF: Tetrahydrofuran THIs: Thermodynamic Hydrate Inhibitors TT: Temperature Transmitter/Transducer ∆Tsub-cooling: Teq-Texp or Teq-Tnucleation UHP: Ultra High Pure V1-10: Manual Valves (1-10) WfAFP: Winter flounder antifreeze protein wt %: weight percent                                                                                                                                                                         xvi  Acknowledgements  I offer my enduring gratitude to the faculty, staff and my fellow students at UBC, and other people who have inspired me throughout the duration of this thesis.  I owe particular thanks to my supervisor Prof. Peter Englezos for his consistent support, encouragement and guidance from the beginning to the final level of my research project. I owe my deepest gratitude to Dr. John A. Ripmeester, Prof. Virginia K. Walker and Prof. Savvas G. Hatzikiriakos for their advice, scientific discussions and encouragement, which improved my thought process as a researcher. I would also like to show my gratitude to Four Year Fellowship (4YF) and Natural Science and Engineering Research Council of Canada (NSERC) for providing financial support for this project. I would also like to extend this acknowledgement to my colleagues and friends: Alireza, Duo, Nagu, Iwan, and Ehsan through group meetings and personal discussions.  I would like to thank CHBE staff: Helsa, Joanne, Christina, Richard Ryoo, Charle, Gordon, Doug, Graham, Alex, Ken, Amber, Ivan, David and Richard Zhang, for their support throughout my program. Special thanks are owed to my parents; who have supported me throughout my years of education and life, both morally and financially. Last, but not least, thank you Rosa for being my love and partner. Your consistent support has been a blessing. Thank you for being my compliment. Thank you for your endless love, support and encouragement throughout my years of education and life.                                                                                                                                                             xvii  To my parents; Ara & Amiraj & my love; Rosa   Dedication                                                                                                                                                                       1   : Introduction Chapter 1 1.1. What is gas hydrate Inclusion compounds generally consist of two molecular species that arrange themselves in space so that one (host) physically entraps the other (guest)5. The clathrate hydrates have water as the host and are commonly known as gas hydrates. Thus, gas hydrates are non-stoichiometric crystalline inclusion compounds formed by a number of low molecular size substances (guests) including hydrocarbons such as methane, ethane, propane and non-hydrocarbons such as carbon dioxide, hydrogen sulphide, and nitrogen which are entrapped within hydrogen-bonded water cages under proper thermodynamic conditions6. Gas hydrates were first identified in 1810 by Sir Humphrey Davy7 who discovered chlorine solutions in water froze and produced a solid more readily than pure water. In 1823, Faraday8 established the composition of the formed solid which was nearly 1 part of chlorine and 10 parts of water. In 1934, Hammerschmidt9 reported that the plugging of natural gas pipelines was not due to ice formation but to formation of clathrate hydrates of natural gas. Crystal structures of gas hydrates are classified into three types, two cubic structures known as sI10 and sII11, and one hexagonal structure known as sH12. The small cavity in all structures is labelled 512 (twelve pentagonal faces). Large cavities in structures I and II are labelled 51262 (twelve pentagonal and two hexagonal faces) and 51264 (twelve pentagonal and four hexagonal faces) respectively. In sH the largest cavity is labelled 51268 consisting of twelve pentagonal as well as six hexagonal faces. In sH there is also a (435663) cavity, which consists of three square, six pentagonal and three hexagonal faces. In sI the 512 cavities are linked through their vertices, while sII illustrates face-sharing of the 512 cavities. As a result of the way that the 512 cavities are organized the spaces between them evolve into 51262                                                                                                                                                           2  or 51264 cavities in structure I and II, respectively. Structure H illustrates face-sharing in two dimensions, so that a layer of 512 cavities connects a layer of 51268 and 435663 cavities. Figure  1.1 illustrates the different structures of gas hydrate crystals.   Figure ‎1.1. Different structures of gas hydrate (with permission from Nature Publishing group, Licence #: 3343190069502).  Cubic sI contains small (0.4-0.55 nm) guests and hydrates containing primarily methane predominate the earth’s natural environments13. However, structure II hydrate also occurs in the earth14. Cubic sII hydrate forms with larger (0.6-0.7 nm) guests in mostly oil and gas operations. It is noted that the smallest hydrate forming molecules (Ar, Kr, O2 and N2) with diameters less                                                                                                                                                           3  than 0.4 nm also form sII hydrates. Hexagonal sH hydrates may occur in nature and in industrial environments but only when small and large (0.8-0.9 nm) molecules are available. Figure  1.2 depicts the relationship between the size of hydrate guests and cavities.  3Å4Å5Å6Å7ÅHydrate FormerArKrN2O2CH4H2SCO2C2H6C-C3H6C3H8Iso-C4H10No hydrates(For P<GPa range at ambient T)52/3 H2O53/4 H2O72/3 H2O17 H2OCavities Occupied(sII : 512 + 51264)(sI : 512+51262)(sI : 51262)(sII : 51264)sH Hydrates (sH)8ÅC4H8O2Methyl Cyclohexane+CH4 Figure ‎1.2. Hydrate guests versus hydrate cavity size range (Adapted from reference number 6).  Gas hydrate formation complicates the exploitation of hydrocarbons found in remote offshore and deep water locations. Undesired water is also produced along with the hydrocarbon components and as the water/oil/gas mixture cools through the transport lines, hydrates may form and plug the pipeline. The solid nature of hydrates and the ease with which they may form in water containing hydrocarbons in pipelines situated in remote offshore locations renders flow assurance in oil and gas pipelines a serious issue in the oil and gas industry and the subject of research. It is noted that gas hydrate formation along with wax deposition and asphaltene precipitation are important concerns due to their responsibility in oil and gas pipelines                                                                                                                                                           4  blockage15. Remarkably, hydrate plugs are more commonly formed and cause more concern by an order of magnitude than problems arising from waxes and asphaltenes16. 1.2. How to prevent or manage the risk of hydrate formation in pipelines Research related to the hydrate prevention led to the identification of chemicals known as thermodynamic hydrate inhibitors (THIs) such as methanol and glycols. These soluble chemicals shift the hydrate equilibrium boundary to higher pressure and lower temperature conditions. Figure  1.3 shows the effect of methanol injection on shifting of gas hydrate formation boundary. In practice an amount that shifts the phase boundary well above the hydrate formation conditions is added so that flow assurance is achieved by preventing hydrate crystal formation (Figure  1.3). However, large amounts of THIs are required to prevent hydrate formation (at an annual estimated cost of $220 Millions)13 and in addition, safety, health, and environmental risks have pushed industry to seek other inhibitors named low dosage hydrate inhibitors (LDHIs) including kinetic hydrate inhibitors (KHIs) and anti-agglomerates17–20.  Figure ‎1.3. Impact of methanol injection on gas hydrate phase equilibrium conditions for a mixture of CH4, C2H6 and C3H8 (93, 5 and 2 mol %, respectively) calculated by CSMGem6.                                                                                                                                                           5   Generally, KHIs are water-soluble polymers which are able to prolong the induction time for the formation of hydrate crystals and decrease post nucleation hydrate crystal growth rates. These additives have been employed for almost 20 years by the oil and gas industry to manage the risk of hydrate crystal formation and subsequent plugging of pipelines21. Polyvinylpyrrolidone (PVP)18,21 is a five-ring member of the series of vinyl-lactam polymers found to perform as kinetic hydrate inhibitor (Figure  1.4). Another polymer is polyvinylcaprolactam (PVCap) which was found to outperform PVP as an inhibitor18. PVCap is the seven-ring member of vinyl-lactam polymers (Figure  1.4). To date, there is an ongoing search for KHIs due to a need to improve performance, compatibility with the reservoir fluid and also changing environmental management practices. The search for new KHIs has been primarily an empirical one, and it has led to identification of inhibitors that perform well in the field21. Nonetheless, environmental restrictions have limited the use of some synthetic KHIs because of their poor biodegradability22.  (a) (b)n Figure ‎1.4. Structure of PVP (a) and PVCap (b).  One of the most recent developments is the trend towards green inhibitors which are biodegradable to alleviate environmental concerns. Antifreeze proteins (AFPs)23,24 are classified as green (environmental friendly) inhibitors. AFPs found in a few fish, insects and plants amongst other organisms can lower the freezing point of ice in a non-colligative manner25–28. An adsorption-inhibition mechanism has been proposed to explain the action of AFPs in inhibiting                                                                                                                                                           6  ice crystal growth29. To date there are five named types of AFPs found in fish, two types from insects and three AFPs of plants25,26. Insect AFP called CfAFP (Choristoneura fumiferana) and  fish AFP  called WfAFP (winter flounder-type I AFP), were more effective than PVP in delaying THF hydrate formation23. Recently it has been shown that type I and III of AFPs (AFP I and III) also delay gas hydrate formation in both single and multi-component gas mixtures, and in some cases they increased hydrate induction time more than the chemical KHIs, polyvinylpyrrolidone (PVP) and polyvinylcaprolactam (PVCap)23,24,30–34. Figure  1.5 shows the images of AFP I, III and CfAFP. The type I AFPs is an alanine-rich α-helical amphiphilic protein with the molecular weight of 3-5 kDa, and found in the righteye winter flounder and certain sculpins. However, type III AFPs found in ocean pout has globular structure with some flat surfaces and molecular weight of ~ 7 kDa. The spruce budworm (Choristoneura fumiferana) AFP is a 9-kDa threonine- and cycteine-rich protein that is hydrophilic (Figure  1.5c).  Figure ‎1.5. Images of three AFPs: a) AFP I, b) AFP III and c) Cf AFP from protein data bank.  An adsorption-inhibition mechanism has been proposed to explain hydrate growth in the presence of KHIs23,35,36. It is hypothesized that the inhibitor molecules are adsorbed onto tiny hydrate crystals and effectively increase the energy barrier for further growth of the hydrate. Extensive research has been devoted to evaluate the performance of potential KHIs using various techniques37–43, with an adsorption-inhibition mechanism proposed to explain inhibitor                                                                                                                                                           7  action30,35. However, the ability of KHIs to affect gas hydrate crystal nucleation and/or growth is still not understood. In addition, the transferability of kinetic inhibition results between laboratory scale experiments and the actual field remains a significant challenge44–46. Therefore, these additives are first tested in the laboratory and if they are successful, tested with field fluids and ultimately under field conditions.  In this regard, more recently the performance of the KHIs in the presence of mixture of gases, rather than laboratory-preferred single gas components, have been assessed with a number of techniques (high pressure crystallizers32,38,47,48, differential scanning calorimetery37,39,43, Raman40,42,49 and 1H NMR spectroscopy41) in the hopes of more efficiently moving to field testing. Additional efforts to make such testing even more realistic and relevant for oil and gas reserves, particularly in deep waters, are required. Thus, the impact of parameters such as the salinity and the presence of a hydrocarbon liquid phase need to be assessed. Therefore, in this thesis a hydrate formation system that better simulates off-shore conditions was selected. These conditions were achieved by (a) employing a multi component (CH4, C2H6, C3H8) gas mixture; (b) adding n-heptane to model a liquid hydrocarbon phase, and thus represent gas condensate; (c) applying high driving forces (in terms of over pressure or sub-cooling); and (d) increasing water salinity to simulate seawater conditions. Industry not only requires KHIs to inhibit gas hydrate formation, but in the event hydrates form due to extreme conditions, it is important that they be easily melted so that production and transport can resume. Therefore, the impact of KHIs on gas hydrate dissociation must be evaluated in the laboratory scale experiments prior to the actual field tests. It was reported that the formed gas hydrates in pure water system in the presence of kinetic inhibitors dissociated in longer time36,39. Morphology experiments revealed that hydrates formed in the presence of KHIs                                                                                                                                                           8  took longer to dissociate completely50,51. In addition multi-step dissociation was observed in the presence of kinetic inhibitors in differential scanning calorimeters37,38,43. However, the influence of KHIs on gas hydrate dissociation in conditions close to sub-sea pipelines discussed above was not evaluated in the literature. The following important question arises from the laboratory evaluation of KHIs; “if an acceptable performance of a kinetic hydrate inhibitor is achieved in the laboratory scale experiments, is it possible to assure the same performance under actual field conditions?” Hence, the evaluation of the performance of kinetic hydrate inhibitors under more realistic conditions is the approach in this thesis to respond to this question.  In this work, the performance of two chemical kinetic inhibitors (PVP and PVCap) and two biological ones (AFP I and III) under more realistic conditions defined above were evaluated using three different experimental set ups: a double high pressure stirred vessel (crystallizer) apparatus, a differential scanning calorimeter and a high pressure rheometer. The methodology is described in chapter two. Subsequently, effect of KHIs on gas hydrate formation and dissociation are presented in chapter three to six, respectively. Finally, conclusions and recommendations for future work are presented in chapter seven.                                                                                                                                                                           9   : Experimental methods Chapter 2 In this Chapter the materials and different experimental approaches used to evaluate the performance of kinetic gas hydrate inhibitors under simulated under-sea pipeline conditions are explained.   2.1. The materials NaCl (Fisher Scientific) was dissolved in distilled, deionised water to prepare a mass fraction of 3.5 % saline solution. Four kinetic hydrate inhibitors including two chemical inhibitors: polyvinylpyrrolidone (PVP; average molecular weight of 3.5 kDa; Acros Organics) and a solution (40 wt % in ethanol) of polyvinylcaprolactam (PVCap; average molecular weight of ~ 23.3 kDa; BASF), and two biological ones: synthesized desalted type I AFP (AFP I; α- helical protein of ~ 3.2 kDa; Shanghai Apeptide, Swiss-Prot Database accession number P04002) and type III AFP (AFP III; globular protein of ~ 7 kDa; A/F Protein Canada Inc., Swiss-Prot Database accession number P19414) were used. The KHIs were diluted to 0.1 mM in saline solution. Due to the low concentration of KHIs in saline solution (0.1 mM), the presence of ethanol in the PVCap solution (calculated as ~ 0.15 wt % of ethanol in saline solution) could not shift the equilibrium hydrate conditions. A natural gas mixture (UHP grade) consisting of methane (93 mol %)/ethane (5 mol %)/propane (2 mol %) was supplied by Praxair Technology Inc. The liquid hydrocarbon phase was n-heptane (Fisher Scientific).  2.2. High pressure crystallizer apparatus A specific high-pressure crystallizer was designed and fabricated to conduct gas hydrate formation and dissociation experiments under constant pressure and volume, respectively (Figure  2.1). The gas uptake method was employed to determine the amount of hydrate forming gas consumed54. Two 211 mL-stainless steel vessels                                                                                                                                                           10  were fitted with two circular polycarbonate viewing windows on the front and back. The vessels contained baffles to control vortex formation during stirring. In order to maintain temperature control, the vessels were submerged in an insulated temperature-controlled circulating bath filled with a propylene glycol and water (1:1) solution. Two additional 300 mL-stainless steel vessels were also immersed in the water bath and acted as supply reservoirs to the crystallizers during hydrate formation. An external refrigerating/heating programmable circulator (VWR Scientific) was used to regulate the temperature of the circulating bath. The contents of the crystallizer were mixed by a gas induced impeller coupled with a hollow shaft which was rotated with a magnetic driven motor (Autoclave Engineers) and controlled by a universal motor controller (Autoclave Engineers). The shaft speed was measured with a universal tachometer display (rpm). Two Rosemount smart pressure transmitters (model 3051, maximum uncertainty of 0.075 percent of span 0-15000 kPa (11 kPa); Norpac controls) were used to measure the pressure of crystallizer and supply vessel and transmit signals to the computer in each unit. Three copper-constantan thermocouples (uncertainty of 0.1 K; Omega Engineering) were used to measure the gas, liquid and interface (liquid-gas, or liquid-liquid) temperature. A high-pressure and low-flow control valve (Fisher, Baumann 5100, NPS ¼) with an actuator and coupled to a proportional, integral, derivative (PID) controller was installed between the crystallizer and the reservoir, and used to regulate crystallizer pressure. The data acquisition system (National Instruments) was connected to a computer to receive transmitted data from pressure transmitters and thermocouples. LabVIEW full development system software (National Instruments) was employed to communicate with the control valve and convert receiving signals for recording into Microsoft Excel.                                                                                                                                                            11  MPTVentCVPTPCVInsulated Poly Carbonate Water Bath ComputerTCRefrigerating/Heating CirculatorTCCirculator TemperatureM: In line Motor & AgitatorPCV: Pressure Control Valve (Regulator)CV: Control ValveTC: ThermocouplePT: Pressure TransmitterCR: CrystallizerV 1-10: Manual Valves Sampling PointTo the second unit (Similar configuration)Gas CylinderV8V9V1V2V3V4V7V5V6V10DAQComputerTCTCTCCRSupply Vessel Figure ‎2.1. Schematic of the high pressure apparatus. Only one crystallizer and one supply vessel are shown to simplify the diagram.  2.2.1. Gas hydrate crystal formation In order to simulate pipeline conditions a constant cooling rate method52,53 using constant pressure was applied (Figure  2.2). In this procedure, the temperatures of the crystallizers were reduced from outside the hydrate stability zone to a stable region under constant pressure. Since gas hydrate formation is an exothermic process6, the onset of nucleation is marked by an abrupt temperature rise and pressure reduction. A cooling rate of 1 K/h was employed to cool down the system from outside the hydrate stable zone to inside the hydrate region (Figure  2.2).                                                                                                                                                            12   Figure ‎2.2. Pressure-Temperature diagram showing the cooling path under constant cooling rate (red line) and under constant pressure to form gas hydrate crystals in the high pressure crystallizers. The equilibrium hydrate formation curve for a saline solution and the gas mixture employed in the experiments is shown by dashed blue line.  The crystallizer was loaded with 80 mL of desired aqueous solution (either saline solution or KHI in saline). Experiments with a liquid hydrocarbon also included n-heptane (40 mL). The water bath temperature was adjusted at 293.1 K. The crystallizers were then pressurized so as to achieve conditions below the equilibrium hydrate formation point and subsequently depressurized three times to displace air from the system. After this, the crystallizers were pressurized with gas mixture to 7.0 MPa. The PID controller set point was adjusted at 7.0 MPa to maintain constant crystallizer pressure by the supply of gas from the supply vessels. The supply vessels were pressurized at ~ 10 MPa with the gas mixture. Since the equilibrium hydrate formation temperature at 7.0 MPa is 288.8 K (for saline solution) and 285.6 K (in the presence of heptane), as calculated by CSMGem6, no hydrates could form at the initial condition (P=7.0 MPa, T=293.1 K). There was constant stirring (500 rpm) of the crystallizer contents and when                                                                                                                                                           13  pressure and temperature were stabilized in both crystallizers and supply vessels, a program of temperature reduction was initiated in order to reach a target temperature of 274.1 K. Subsequently, the temperature was kept constant at 274.1 K for 48 h. The start time for cooling was considered as the zero time and data was recorded every 5 s. The nucleation point was identified by the increase in the aqueous phase temperature accompanied by a sudden pressure drop in the supply reservoirs. The number of moles of gas consumed to form hydrates or dissolved in solution (∆𝑛𝐻) was calculated as described54 and shown in equation 1.  ∆nH = (PVzRT)G,0− (PVzRT)G,t+ (PVzRT)sv,0− (PVzRT)sv,t              (1) where P, V, R, T, z are pressure, volume, universal gas constant, temperature and gas compressibility factor calculated by Pitzer's correlation, respectively. The indices G, sv, 0 and t represent gas phase in the crystallizer, supply vessel, zero time and any given time, respectively. The experiment was terminated when there was a considerable mass of gas hydrate crystals in the crystallizer after 48 h.    2.2.2. Gas hydrate crystal dissociation Hydrate dissociation experiments were conducted 48 h after the formation of gas hydrates in the crystallizers, simulating pipeline blockage. Hydrate dissociation was initiated by no longer stirring the vessel contents and by increasing the water bath temperature from 274.1 to 301.1 K at a rate of 11 K/h. The start of heating was considered as the zero time in the dissociation experiments. Data were recorded every 5 s until the experiments were terminated coincident with a pressure plateau at 301.1 K in crystallizers. Since dissociation experiments were carried out under constant volume, the crystallizer pressure increased due to the thermal expansion, the evolution of dissolved gas in the liquid phase, as well as gas hydrate dissociation. The number of moles of released gas attributed                                                                                                                                                           14  to the hydrate dissociation and the reduction of gas solubility in the liquid phase at any given time, ∆𝑛𝐺 , was calculated as described55 which is presented in equation 2. In order to facilitate comparisons between experiments, the amount of released gas was normalized40 which is shown in equation 3.  ∆nG = (PVzRT)G,t− (PVzRT)G,0                 (2) Normalized released gas =∆𝑛𝐺𝑛𝑡𝑜𝑡𝑎𝑙       (3) where 𝑛𝑡𝑜𝑡𝑎𝑙 is the total number of moles of gas recovered at the end of experiment.  2.3. High pressure micro differential scanning calorimetry (HP-µDSC) HP-µDSC (μDSC 7 Evo; Setaram Inc.) was used to observe hydrate phase transition experiments. The calorimeter uses double-stage temperature control with Peltier coolers allowing operation between 228.15 K and 393.15 K with a programmable temperature scanning rate (heating and cooling) of 0.001-2 K/min. It consisted of two high pressure cells (up to 40 MPa) with volume of 1 mL. A customized “sample holder” was fabricated using stainless steel (316) as shown in Figure  2.3. The holder has a base (Dia. 5.4 mm, depth 3.7 mm) with four depressions (Dia. 1.5 mm, depth 2.6 mm), with support from a rod (Dia. 1.6 mm, length 7 mm).                                                                                                                                                            15  7.001.605.401.502.603.70 Figure ‎2.3. Sample holder used for DSC experiments (dimensions are in mm; not to scale)  Samples (1 µL of the experimental solution with an additional 1 µL n-heptane in specific experiments) were injected into the allocated depressions using a micro-syringe, placed in the high pressure cell, and pressurized up to 8.0 MPa with the methane/ethane/propane gas mixture and depressurized consequently to remove air from the system. When the sample and reference cell pressure reached the desired value, the temperature ramping program was started. In this protocol, the temperature was decreased from 303.1 K to 243.1 K at a rate of 0.2 K/min to form gas hydrates, and then raised to 303.1 K at the same rate to decompose the formed hydrates.  Under the isothermal protocol, samples (1 µL of the appropriate solution) were injected into the depressions using a micro-syringe, placed in the high pressure cell, and pressurized to 7.0 MPa with the gas mixture, using an empty sample holder in the reference cell as a reference control. After three times pressurization and depressurization to remove air from the system, once the pressure and temperature of both cells reached to 7.0 MPa and 303.1 K, temperature                                                                                                                                                           16  was decreased from 303.1 K to 259.1 K at a rate of 1 K/min and then kept constant at 259.1 K for 8 h in order to form gas hydrates. Decomposition was achieved by increasing the temperature to 303.1 K at a rate of 0.2 K/min. The starting time for the isothermal protocol was considered as the zero time in the DSC experiments. Exothermic peaks represent ice formation, hydrate formation and salt precipitation. Eutectic temperature, ice melting and hydrate dissociation were detected by endothermic peaks37,56. The identification of ice, precipitated salt and melted ice was facilitated by conducting control experiments with saline solutions at atmospheric pressure.  2.4.  High pressure rheometer The Physica MCR 501 rheometer from Anton Paar equipped with a high pressure cell was used57. Figure  2.4 shows the schematic of the experimental setup. The rheometer could control either stress or strain. It had a torque range from 0.1 µNm to 150 mNm with the uncertainty of 0.1 nNm. The resulting uncertainty in the viscosity measurement is 0.5 µPa·s. The Rheoplus software was used to calibrate the instrument, setup and run the experiments, and analyze the raw experimental data. The pressure cell consisted of a stainless steel chamber (internal diameter of 27.1 mm and length of 75 mm) and a stainless steel vane (dia. 24.6 mm) with four blades (cup-and-bob) assembly. Thus the geometry had a 1.2 mm gap between the tip of the blade and the chamber wall. The cell was designed to operate up to 15.0 MPa. The pressure was measured by a sealed gauge pressure transmitter PA-23 from Keller, Inc. with the typical uncertainty of 16 kPa. The pressure cell fitted in a Peltier temperature control system, and was mounted on the rheometer. The Peltier jacket had a temperature range from 243.15 K to 473.15 K, with the maximum cooling and heating rate of 4 and 8 K/min, respectively. The temperature was measured by a thermocouple with the typical uncertainty less than 0.01 K57,58. A water bath supplied the jacket with cooling fluid to sink heat. The temperature probe was embedded in the shell of the cell. Hence, the solution temperature                                                                                                                                                           17  could be readily detected. Pressure, temperature, slurry viscosity and applied torque were recorded during the experiments. PCVGas CylinderVentHigh Pressure RheometerMTTPTComputerPCV: Pressure Control Valve (regulator)M: Motor coupled with agitatorPT: Pressure TransmitterTT: Temperature Transmitter Figure ‎2.4. Schematic of the high pressure rheometer experimental setup.  2.4.1. Gas hydrate formation in high pressure rheometer In hydrate formation experiments, either 18 mL of the desired aqueous solution or 12 mL of aqueous solution plus 6 mL of n-heptane was loaded to the cell. The solution temperature was adjusted to 293.15 K. Subsequently, the chamber was pressurized with the desired gas mixture up to a pressure less than that required for equilibrium hydrate formation and then depressurized three times in order to remove air from the system. Afterwards, the cell was pressurized to 8.0 MPa with the desired gas mixture, and a shear rate of 100 s-1 was applied. The system pressure was monitored and kept constant at 8.0 MPa (through the gas cylinder regulator) for 10 hours in order to saturate the liquid phase with the gas mixture. Finally, the system was isolated (batch protocol) and a temperature program was applied. This marked the starting point of the experiments. The                                                                                                                                                           18  temperature program included two steps (Figure  2.5); ramping and isothermal. In the first step, the cell was cooled down from 293.15 K to 274.15 K at the rate of 20 K/h. At 293.15 K and 8.0 MPa the mixture is outside the hydrate stable region because the equilibrium hydrate formation temperature for the desired gas mixture at 8.0 MPa is 289.3 K6.  The temperature was kept constant at 274.15 K during the second step and the shear rate was kept constant at 100 s-1.   Figure ‎2.5. Pressure, temperature and viscosity profiles during hydrate formation in saline solution. In the top graph, solid blue line shows the temperature profile in both ramping and isothermal parts while dashed red line depicts the temperature profile in the isothermal section. The onset of hydrate formation is noted at about 71 min after the start of the experiment which is shown by a circle.    The temperature, pressure, torque and viscosity were measured throughout the process of hydrate formation. Once the solution viscosity reached a value approximately equal to 4 Pa·s, the hydrate formation experiment was terminated for the sake of operational safety.   2.5. Circular dichroism (CD) CD was performed for AFPs in deionized and distilled water (ddH2O) and saline solution. AFP I and AFP III were diluted to ~ 40 μM (or 100 μM for                                                                                                                                                           19  AFP III), in either ddH2O or the saline solution and examined for CD using an Olis Rapid Scanning Monochromator 1000 spectrometer (Olis Inc.) with the cuvette temperature maintained at 277 K. A minimum of five scans were averaged and the curves were corrected using the appropriate blank (Figure  5.6).                                                                                                                                                                         20   : Impact of chemical kinetic hydrate inhibitors on gas hydrate Chapter 3formation and dissociation in saline water   This Chapter describes the influence of chemical kinetic hydrate inhibitors (PVP and PVCap) on gas hydrate nucleation, growth and dissociation in saline water.  3.1. Influence on gas hydrate nucleation Gas hydrate nucleation is accompanied by a sudden increase in the temperature of the aqueous phase in gas uptake experiments6 and in exothermic peaks with DSC37,39,43 experiments. The increase in temperature also coincides with a sudden decrease in pressure. Under programmed cooling rate and with gas provided by supply reservoir to prevent pressure loss in the crystallizer, a sudden decrease in supply reservoir pressure represented the onset of gas hydrate formation. In temperature ramping (constant cooling rate) experiments, the lowest temperature that hydrate nucleation occurs is considered as the nucleation temperature52. For all experiments the time to nucleation is known as the induction time, with the strength of a KHI assessed by the length of the induction time and the nucleation temperature.  Figure  3.1 shows the spikes in the liquid phase temperature profiles representing gas hydrate induction times. However, the spike amplitudes were in the range of the thermocouple uncertainty (0.1 K) and no temperature spike was detected in the presence of PVP. Therefore, supply reservoir pressure profiles are presented in Figure  3.2 to show the sudden changes in the supply reservoir pressure corresponded to the temperature spikes in the same experiments. In the presence of PVP the sudden change in the supply reservoir pressure was considered as the hydrate nucleation point (Figure  3.2). PVP and PVCap were effective inhibitors of gas hydrate nucleation. The average induction or hydrate nucleation time was delayed by 1.7 and 1.6 times in the presence of PVP and PVCap, respectively (Table  3.1). Compared to controls, this nucleation                                                                                                                                                           21  occurred at lower temperatures, corresponding to higher sub-cooling (25.2 K for the saline solution vs. 29.3 K with PVCap and 32.7 K with PVP in DSC experiments).   Figure ‎3.1. Temperature profiles of saline solutions with and without inhibitors. Exothermal peaks are marked with circles for control (black line) and PVCap (red line). No exothermic peak was observed in the presence of PVP (blue line).                                                                                                                                                             22   Figure ‎3.2. Pressure profiles of supply reservoirs during gas hydrate formation experiment without (black line) and with inhibitors: PVP (blue dotted line) and PVCap (red dashed line) in saline solutions. Arrows indicate inflections in the pressure reduction rate curves showing gas hydrate nucleation points.   Table ‎3.1. Experimental conditions and results of the gas uptake and DSC experiments showing induction times and nucleation temperatures. Control is saline solution without inhibitor.  The delay in the onset of nucleation due to PVP and PVCap addition in the stirred tank reactor agrees with that observed in the HP-µDSC experiments (Figure  3.3). Previously, it has been shown that PVP38–40,42 and PVCap32,37,59 can prolong gas hydrate induction times in water. It was also reported that addition of PVP to a saline solution (artificial seawater) did not increase ∆Tsub-cooling1 (K)Gas uptake experiments           (Pexp = 7.0 MPa)1∆Tsub-cooling=Teq-Tnucleation, Teq=289.7 K at 8.0 MPa.234.4±1.3 257±0.1 32.7PVCap 959±3 278.4±0.1 218.1±1.6 260.4±0.3 29.3PVP 1049.5±33 276.5±0.5603.5±7 283.9±0.1 197.2±2.5 264.5±0.5 25.2SolutionC ntrol Gas Mixture: Methane (93%), Ethane (5%), Propane (2%).DSC experiments (Pexp = 8.0 MPa)Induction time (min)Nucleation temperature (K)Induction time (min)Nucleation temperature (K)                                                                                                                                                          23  gas hydrate induction time but promoted gas hydrate growth. On the other hand, the addition of PVCap delayed gas hydrate nucleation and reduced hydrate crystal growth17. Here it is shown that both PVP and PVCap prolong the induction time in saline solution (3.5 wt % NaCl). In the conducted experiments PVP was found to perform better than PVCap in terms of delaying the nucleation of hydrates. This could be attributed to the molecular weight of the PVP used32,60. Previously, it was reported that anti-freeze proteins with lower molecular weight than PVCap molecular weight performed more effectively than PVCap in delaying the onset of nucleation32.   Figure ‎3.3. DSC heating curves showing hydrate nucleation in saline solutions with and without inhibitors (PVP or PVCap). Control is saline solution without inhibitor.  Figure  3.4 shows temperature profiles during hydrate formation in saline solutions with and without inhibitors in the high pressure rheometer. As seen in the Figure, temperature spikes are detected in both cases. The temperature PID control system quickly restored the temperature in a classic feedback control fashion. Therefore, when hydrate formation starts and its thermal signature is detected the control system regulated the temperature. However, the observed                                                                                                                                                           24  temperature spikes are in the range of the temperature probe (0.01 K). Therefore, during gas hydrate formation experiments, at least 10 % increase in the solution viscosity which was consistent over time was used to find the hydrate nucleation points as the uncertainty for viscosity measurement is 0.5 µPa·s. Figure  3.5 shows the viscosity profiles for different saline solution during gas hydrate formation. As it is shown in Figure  3.5, increases in the solution viscosity corresponded to the temperature spikes observed in the same experiments. The average induction times are: 71.3 min for saline solution without inhibitor (control), 114.5 min for the solution with PVCap, and 134.4 min for the solution with PVP. The induction times along with other experimental information in high pressure rheometer are seen in Table  3.2. As expected, addition of inhibitors increased hydrate nucleation time. In the presence of PVCap the induction time increased almost 1.6 times compared to the time for saline solution with no inhibitor, and in the presence of PVP the induction time increased almost by a factor of two. Here, PVP performed more effectively compared to PVCap in terms of prolonging the induction time. These results are in agreement with autoclave crystallizers and high pressure micro differential scanning calorimeter experiments.                                                                                                                                                              25   Figure ‎3.4. Temperature profiles during hydrate formation experiments in saline solutions with and without inhibitors (PVP or PVCap) in the high pressure rheometer. Nucleation points are shown by arrows. Control is saline solution without inhibitors.                                                                                                                                                             26   Figure ‎3.5. The viscosity profiles for saline solutions with and without inhibitors (PVP and PVCap) during gas hydrate formation. Over 10 % increase in the solution viscosity was identified as the hydrate induction time. The induction time is indicated by an arrow.   Table ‎3.2. Experimental solutions and results showing induction times, growth rates and time elapsed to detect sharp increase in the hydrate slurry viscosity. Control is saline solution without inhibitor.  It has been suggested that KHIs can adsorb to hydrate nuclei and/or impurities and thus hinder hydrate nucleation. The evaluation of the relative performance of KHIs is not always clear. Zeng et al.61 argued that the performance of KHIs was related to the ratio of the dissipation Experiment Solution Average Average1A 72.1 2001B 70.5 2072A 130.7 1482B 138.1 1543A 111.6 1533B 117.4 159156Gas Mixture: Methane (93%), Etha e (5%), Propane (2%).Induction time (min)Sudden rise in Viscosity   (min)Control 71.3 203.5PVP 134.4 151PVCap 114.5                                                                                                                                                          27  factor and adsorption mass of KHI. The dissipation factor represents the viscoelastic properties of the adsorbed molecules62,63. A large value of dissipation factor indicates a porous and flexible adsorbed layer of KHIs.  However, a very low value of this factor indicates the presence of a adsorbed layer of KHIs that is more compact and rigid. Therefore, either more adsorption mass or more rigid layer of the adsorbed KHIs resulted in a lower value for the ratio of dissipation factor to the adsorbed mass. According to the experiments conducted by Zeng at al. the lower the ratio of dissipation factor to the adsorbed mass, the better performance as KHIs which means either more KHI molecules are adsorbed or the adsorbed layer of KHIs is more rigid. Further, they argued that PVP molecules preferentially adsorb compared to PVCap molecules61, but the dissipation factor of the adsorbed PVP molecules (with an average molecular weight of 40 kDa for their case) was higher than that of the PVCap molecules. Thus with their reagents PVCap performed more effectively. Dissipation factor is reduced by a decrease in molecular weight of polymers62. As a result, the PVP with a molecular weight of 3.5 kDa used here would have a lower dissipation factor. Consequently, the ratio of the dissipation factor to the adsorbed mass would be lower for this PVP, explaining why this PVP performed more effectively in our experiments.  3.2. Effect of PVP and PVCap on gas hydrate growth in saline solutions Generally, the addition of KHIs reduced the gas hydrate growth rate in the NaCl (3.5 wt %) solution until a certain point (Figure  3.6). In the presence of KHIs, hydrate growth proceeded in two steps. In the first phase, growth correlated with gas consumption (for PVP from nucleation point at ~ 1050 to 1550 min and for PVCap from nucleation point at ~ 959 to 1200 min) (Figure  3.6). During this period the hydrate growth rate was regulated by the presence of KHIs. However, in the second phase accelerated hydrate growth was observed. As shown in Figure  3.6,                                                                                                                                                           28  in the presence of PVCap, the first phase took 241 min (from induction time at 959 to 1200 min) with 0.0478 mole gas consumed (0.2 mmol/min), and this was followed by a second phase that was complete in 300 min with 0.1054 mole of gas consumed (0.35 mmol/min). Thus, it is suggested that the KHIs regulated growth up to a certain point and after that growth suddenly increased. Such occurrence in the field would be undesirable. Such accelerated crystal growth has been previously reported in the absence of electrolyte and has been labeled as catastrophic crystal growth51,64. As hydrate growth proceeded in the first phase, the salt solution would become more concentrated and gas hydrate formation would be reduced due to colligative effects. However, this is less likely to play a role in the catastrophic growth kinetics. PVCap performed better than PVP to inhibit growth initially, as reported64, but later hydrate formation occurred more rapidly in the presence of PVCap compared to PVP.   Figure ‎3.6. Cumulative gas consumption during hydrate formation in saline solutions with and without inhibitors (PVP or PVCap) with a cooling rate of 1 K/h and Pexp=7.0 MPa. Induction times are shown by arrows. Catastrophic growth was observed at: ~ 1550 and 1200 min for PVP and PVCap, respectively.                                                                                                                                                            29  The observed rise in the gas phase temperature due to exothermic hydrate formation is consistent with these observations for PVCap and PVP (Figure  3.7). It is believed that a more porous hydrate forms in the presence of kinetic inhibitors50 and this may facilitate water transport by capillary action to the gas/water interface, thereby enhancing gas hydrate formation50 and resulting an increase in the observed gas phase temperature (Figure  3.7).   Figure ‎3.7. Gas phase temperatures during gas hydrate formation. The stars indicate the start of the second, rapid phase of growth for the KHI-treatment groups. Control is saline solution.  Continuous increase in the hydrate slurry viscosity after hydrate nucleation observed in the high pressure rheometer experiments relates to hydrate growth. Figure  3.8 illustrates the viscosity profiles for saline solutions with and without inhibitor during hydrate formation experiments in the high pressure rheometer.                                                                                                                                                            30   Figure ‎3.8. Hydrate slurry viscosity profiles during hydrate formation in saline solutions with and without inhibitors (PVP or PVCap) in the high pressure rheometer. Induction times are: 72.1, 130.7 and 111.6 min for control, PVP and PVCap solutions, respectively.    Based on data presented in Table  3.2, Figure  3.5 and Figure  3.8, the addition of PVP and PVCap to saline solutions controlled gas hydrate growth during the first 140 min as the viscosity of saline solutions in the presence of these inhibitors was not increased. Although PVP performed better than PVCap in terms of increasing the induction time, PVCap controlled hydrate growth more effectively. The effectiveness of PVCap compared to PVP in controlling gas hydrate growth might be related to the multilayer adsorption of PVCap on hydrate crystals65. It is then possible that the thickness of the adsorption layer in the presence of PVCap is greater than that with PVP and this in turn may decrease the diffusion of hydrate formers from the bulk phase to the growing hydrate crystals surface. However, there is no evidence of the relative thickness of the adsorption layers.                                                                                                                                                           31  Hydrate growth in saline solutions with or without inhibitors raised the viscosity of hydrate slurry (Figure  3.8). Hydrate crystals begin forming after about 70 min and the viscosity of the saline solution without inhibitors started to increase (Figure  3.8). Then the saline solution viscosity rose gradually with an almost constant rate at 0.0016 Pa·s/min up to 0.154 Pa·s (at ~ 180 min). This indicates the formation of more hydrate particles. Afterwards, a sharp increase in viscosity was observed (at ~ 200 min) which might be related to the acceleration in hydrate formation which would be considered as analogous to pipeline blockage. Remarkably, addition of PVP and PVCap was found to contribute to an increase in viscosity which is interpreted as promotion of hydrate formation (Figure  3.8). In the presence of PVP, the solution viscosity was found to first increase from 0.0172 to 0.461 Pa·s starting at 135 min and after 16 minutes (at 151 min) the second rise of viscosity was detected. At this point the rheometer was stopped for the operational safety reasons. These increases in viscosity are likely indicators of hydrate catastrophic growth. Occurrence of such hydrate accelerated formation in an industrial pipeline is believed to be linked to the plugging of the pipeline. The addition of PVCap had a similar effect on the viscosity (Figure  3.8). In this case, such a sudden increase in viscosity was not observed up to 156 minutes while, after that, the viscosity increased drastically. Although the addition of KHIs increased induction time and decreased consequent hydrate growth, it seems that these additives might increase hydrate growth rate after a certain point as evidenced by the viscosity of the suspension. Thus, KHIs regulated growth up to a certain point after which a sharp increase in viscosity was detected due to hydrate catastrophic growth in the system which is in agreement with the results of high pressure crystallizer experiments. Such occurrence in the field would be undesirable.                                                                                                                                                           32  3.3. Gas hydrate dissociation in the presence of chemical kinetic inhibitors (PVP and PVCap) Industry not only requires KHIs to inhibit nucleation, but in the event hydrates form due to extreme conditions, it is important that they be easily melted so that production and transport can resume.  Once hydrate crystals were formed in the presence of the KHIs, their dissociation was monitored (Figure  3.9). Gas hydrates formed in the saline solution started to dissociate earlier but the overall dissociation rate was slower so that in the presence of PVP and PVCap complete dissociation took longer (Figure  3.9). This phenomenon has been observed previously in the absence of salt38,51. Adsorption of kinetic inhibitors on the hydrate crystals may stabilize hydrates66 and hence the hydrate dissociation rate would be lower. Hydrate dissociation in the presence of PVCap was seen to occur in two stages, and it is speculated that this two-stage dissociation is related to the presence of different hydrate structures38. It is known that the stable hydrate structure for a methane 93 mol %, ethane 5 mol % and propane 2 mol % mixture is sII67, but both sI and sII of hydrates have been detected in the presence of PVCap59,68.                                                                                                                                                             33  Figure ‎3.9. Effect of PVP and PVCap on gas hydrate dissociation in saline solutions. Control shows the experiment in saline solution without any inhibitors.  Since hydrate dissociation is an endothermic process6, this process can be detected by endothermic peaks in DSC experiments (Figure  3.10). In the absence of KHIs, hydrate dissociated at ~ 290 K, equal to the equilibrium value for sII hydrate. In the presence of PVCap, two dissociation peaks appeared (Figure  3.10), as has been previously reported37. One point (~290 K) is related to sII hydrate (calculated by CSMGem6) and the other (293.5 K) cannot be explained readily. An analogous two-step dissociation was seen and discussed for the autoclave experiments. In the presence of PVP (Figure  3.10) there was a broad peak with a minimum at ~ 291.5 K, whereas with PVCap two minimum points were detected (~ 290 and ~ 292.5 K).  Figure ‎3.10. Gas hydrate dissociation peaks in DSC experiments in the presence of PVP and PVCap (Pexp=8.0 MPa, Teq =289.7 K6). Control shows experiment in saline solution without inhibitors.                                                                                                                                                             34   :  Impact of chemical kinetic hydrate inhibitors on gas hydrate Chapter 4formation and dissociation in saline water in the presence of liquid hydrocarbon phase   In this Chapter the impact of chemical kinetic hydrate inhibitors (PVP and PVCap) on gas hydrate nucleation, growth and dissociation in saline water and in the presence of liquid hydrocarbon phase (n-heptane) is investigated. 4.1. Gas hydrate nucleation in saline solutions and in the presence of n-heptane The results showing induction time and nucleation temperature in the presence of a liquid hydrocarbon (n-heptane) are shown in Table  4.1 for the autoclave and DSC experiments. The addition of n-heptane to saline solution doubled the induction time (603.5 min to 1208 min in gas uptake experiments), and more subcooling was required to form hydrate as seen in the DSC experiments. Table ‎4.1. Experimental conditions and results of the gas uptake and DSC experiments showing induction times and nucleation temperatures. Control is saline solution without inhibitor in the presence of heptane.  Since the equilibrium temperature for the system in the presence of n-heptane was 285.6 K at 7.0 MPa, lower than that found in the absence of heptane (288.8 K as seen in Figure  4.1), the driving force (Teq-Texp) for hydrate formation with n-heptane was also lower. Thus, hydrate ∆Tsub-cooling1 (K)1∆Tsub-cooling=Teq-Tnucleation, Teq= 286.5 K at 8.0 MPa.        Gas uptake experiments                (Pexp = 7.0 MPa)228±0.6 258.2±0.1 28.3PVCap 1126±2 275.2±0.1 231±0.9 257.6±0.1 28.9PVP 1059±6 276.2±0.11208±4 274.1±0.1 233.7±0.3 257.3±0.1 29.2SolutionControl Gas M xt r : Methane (93%), Eth n  (5%), Propane (2%).DSC experiments (Pexp = 8.0 MPa)Induction time (min)Nucleation temperature (K)Induction time (min)Nucleation temperature (K)                                                                                                                                                          35  appeared to form later in the presence of n-heptane. However, since hydrate crystals were formed at the interface of aqueous solution and n-heptane51, gas molecules would have to diffuse through the heptane layer in order to reach the surface of the saline solution. Thus the presence of the n-heptane layer creates an extra barrier for the transfer of the hydrate forming gas. These two effects (lower equilibrium temperature to form hydrate and an extra mass transfer resistance) resulted in an overall increase in the time required for nucleation.  Figure ‎4.1. Calculated gas hydrate equilibrium conditions for the mixture of CH4 (93 mol %), C2H6 (5 mol %), C3H8 (2 mol %) in 3.5 wt % NaCl aqueous solution in the presence of n-heptane (squares) or without it (triangles). At any given experimental temperature, which is shown by star in each curve, driving force (Teq-Texp) in the presence of n-heptane was different from that seen in the absence of n-heptane.  Unexpectedly, when KHIs and n-heptane were added to the crystallizer the induction time was reduced by 20 % and 10 % for PVP and PVCap, respectively (Figure  4.2 and Figure  4.3, Table  4.1). The observation that gas hydrates form sooner in the presence of KHIs in gas uptake experiments has been previously reported32. Similar results were obtained in the HP-µDSC                                                                                                                                                           36  experiments (Figure  4.4). Clearly, the addition of KHIs to the saline solution in the presence of n-heptane modestly increased the nucleation temperature. However, since there is no mixing under the DSC conditions, it is understandable that the difference between nucleation points is not as large as in the gas uptake experiments.   Figure ‎4.2. Temperature profiles during gas hydrate formation in saline solutions with and without inhibitors (PVP and PVCap). Control is saline solution in the presence of heptane. Induction times are shown by circles.                                                                                                                                                           37    Figure ‎4.3. Supply reservoir pressure profiles during gas hydrate formation in saline solutions with and without inhibitors (PVP and PVCap). Control is saline solution in the presence of heptane. Induction times are marked by arrows.  Figure ‎4.4. DSC heating curves showing hydrate nucleation in saline solutions with and without inhibitors (PVP or PVCap) in the presence of n-heptane. Control is saline solution without inhibitor in the presence of heptane.                                                                                                                                                           38   Figure  4.5 shows the temperature profiles during gas hydrate formation in saline solution with and without inhibitors in the presence of heptane in the high pressure rheometer. Hydrate nucleation is detected via observed exothermic peaks. However, due to the temperature control system the peaks amplitude are in the range of temperature probe uncertainty (0.01 K). Therefore, corresponded viscosity profiles for saline solutions without and with inhibitors are presented in Figure  4.6, Figure  4.7 and Figure  4.8 to show the rising in the solution viscosity at the observed temperature spikes. As it is shown in Figure  4.5 to Figure  4.8 addition of PVP and PVCap to saline solutions decreased hydrate nucleation points. Hydrate induction time decreased from 218.9 to 124.9 and 160.1 min in the presence of PVP and PVCap, respectively (Table  4.2). Therefore, in spite of the fact that addition of KHIs to an aqueous saline solution increases the induction time, addition of inhibitors to saline solution in the presence of n-heptane accelerates hydrate formation (decreases the induction time) which is in agreement with autoclave and DSC experiments.                                                                                                                                                           39    Figure ‎4.5. Temperature profiles during hydrate formation in the presence of n-heptane in saline solutions with and without inhibitors (PVP or PVCap) in the high pressure rheometer. Control is saline solution in the presence of n-heptane without any inhibitors. Induction times are shown by the arrows.   Figure ‎4.6. Viscosity and temperature profiles during gas hydrate formation in the saline solution without inhibitors in the high pressure rheometer. Temperature spike shows the hydrate nucleation.                                                                                                                                                           40    Figure ‎4.7. Viscosity and temperature profiles during gas hydrate formation in the saline solution with PVCap in the high pressure rheometer. Temperature spike shows the hydrate nucleation.   Figure ‎4.8. Viscosity and temperature profiles during gas hydrate formation in the saline solution with PVP in the high pressure rheometer. Temperature spike shows the hydrate nucleation.                                                                                                                                                             41  Table ‎4.2. Experimental solutions and results showing induction times, growth rates and time elapsed to detect sharp increase in the hydrate slurry viscosity. Control is saline solution without inhibitor in the presence of heptane.  The addition of the KHIs would have decreased the interfacial tension between the aqueous solution and the liquid hydrocarbon69–71. As a result, the mass transfer between these two phases in hydrate nucleation process increased and thus the hydrate nucleated faster. Under these conditions PVCap performed better than PVP, in contrast to the situation in the absence of n-heptane. It is speculated that perhaps PVP reduced the interfacial tension between n-heptane and saline solution more than PVCap.  Figure  4.9 shows a summary of the mean induction times for the different tested solutions in the gas uptake, DSC and high pressure rheometer experiments, which have also been summarized in Table  4.1 and Table  4.2. Again, due to a lack of the mixing in the DSC experiments, a comparison in the presence or absence of n-heptane was not reasonable. Experiment Solution Average Average1A 218.9 4121B 223.2 4252A 124.92B 128.13A 160.13B 163.2Gas Mixture: Methane (93%), Ethane (5%), Propane (2%).Induction time (min)Sudden rise in Viscosity (min)Control 221.05 418.5PVP 126.5 Not observedPVCap 161.65 Not observed                                                                                                                                                          42   Figure ‎4.9. Effect of KHIs on induction time in saline solutions and the presence of n-heptane in gas uptake (Pexp=7.0 MPa, Cooling rate: 1 K/h), DSC (Pexp=8.0 MPa, Cooling rate: 0.2 K/h) and high pressure rheometer (HPR) (Pi=8.0 MPa, Cooling rate: 20 K/h).   4.2. Effect of PVP and PVCap on gas hydrate growth in saline solutions with heptane Addition of n-heptane reduced the rate of hydrate growth in autoclave experiments. Strikingly, the amount of hydrate formed in the presence of heptane was only 50 % of that formed in the absence of this hydrocarbon. As previously discussed, the presence of a heptane layer would provide extra mass transfer resistance for gas diffusion, resulting in a reduced rate of hydrate formation. Both KHIs reduced gas hydrate growth, and in this case, no catastrophic growth was observed (Figure  4.10). Since gas hydrate formed on the interface of n-heptane and aqueous solution and was situated in the liquid phase, no gas hydrate formed in gas phase in the presence of KHIs. As a result, no catastrophic growth was detected. In this case, the rate of gas hydrate growth in the PVCap experiments was slower than with PVP. For example, in the                                                                                                                                                           43  presence of PVCap, overall hydrate crystallization was reduced 40% while for PVP it was reduced by 28 %.  Figure ‎4.10. Effect of PVP and PVCap on cumulative consumed gas in the presence of n-heptane in gas uptake experiments (under 1 K/h cooling rate, Pexp=7.0 MPa). Control is saline solution in the presence of heptane.  Figure  4.11 depicts the hydrate slurry viscosity profile during hydrate formation with and without inhibitors in saline solutions and in the presence of n-heptane in the high pressure rheometer.                                                                                                                                                            44   Figure ‎4.11. Hydrate slurry viscosity profiles during hydrate formation in saline solutions with and without inhibitors (PVP or PVCap) in the presence of heptane in the high pressure rheometer. Control is saline solution without inhibitor in the presence of heptane.  As seen in Figure  4.11, the hydrate slurry viscosity started rising suddenly after 250 minutes whereas in the absence of n-heptane this occurred after 71 minutes. In the presence of n-heptane the sharp increase in the hydrate slurry viscosity corresponding to the hydrate agglomeration/formation was prolonged to 418 min (Figure  4.11 and Table  4.2) compared to the case without n-heptane (203 min as seen in Figure  3.8 and Table  3.2). This means that the addition of the liquid hydrocarbon decreased hydrate growth which is in agreement with the autoclave experiments. This implies that in a gas pipeline and in the absence of inhibitors, there will be a delay in pipeline blockage simply by the presence of a liquid hydrocarbon phase. Figure  4.11 also depicts the effect of n-heptane addition on the viscosity profile for gas hydrate slurries in the presence of PVP and PVCap. As seen in the figure, the slurry viscosity did                                                                                                                                                           45  not rise after a while compared to the case without inhibitor. This observation indicates that gas hydrate particles might remain dispersed or the hydrate growth controlled effectively. It is noted that a similar observation was made in a stirred vessel with the addition of PVCap in a 3.5 wt % NaCl solution and in the presence of liquid hydrocarbon32. These results show that although induction times decreased by addition of kinetic hydrate inhibitors in the presence of n-heptane, hydrate growth rate decreased drastically and hydrate agglomeration did not happen for the time examined in this work.   A summary of the comparisons between the performance of PVP and PVCap in gas hydrate formation under different conditions is presented in Table  4.3. As it is shown, PVCap performed better in the presence of n-heptane, while PVP increased induction time better than PVCap in saline solutions.  Table ‎4.3. Comparison between the performance of PVP and PVCap in the formation of gas hydrates under different conditions.   4.3. Gas hydrate dissociation in saline solutions in the presence of n-heptane The effect of PVP and PVCap on the dissociation process in the presence of n-heptane is shown in Figure  4.12. Hydrate dissociation started earlier, and complete dissociation took longer in the presence of the KHIs. Interestingly, there was an extra step at the initiation of hydrate dissociation in the presence of inhibitors that was not seen in their absence. This suggests that hydrate formed in the presence of KHIs is more stable. Since ethane and propane tend to occupy Saline Solution Saline+n-heptane To prolong induction time PVP PVCapTo decrease growth rate PVCap PVCapTo reduce extent of catastrophic growthPVP No catastrophic growth was observedHydrate Formation Mixture                                                                                                                                                          46  more hydrate cavities in the presence of kinetic inhibitors40,42, the methane concentration in the gas phase increases substantively compared to situations in the absence of KHIs. In addition, in the presence of heptane, the kinetics also reflects the greater solubility of propane and ethane in heptane than methane. In the presence of high methane concentrations in the gas phase, a significantly higher temperature would be required to decompose the hydrates. Added to this situation, there is a sharp increase in the amount of released gas for sII hydrate dissociation (according to CSMGem calculations6). In the system with heptane, a two-step decomposition in the presence of PVCap was clearly observed, which it is believed is related to the formation of two different hydrate structures. Due to changes in the hydrate dissociation rate in the presence of PVP, such a two-step dissociation mechanism is likely the case but is admittedly not as compelling as that for PVCap.  Figure ‎4.12. Effect of PVP and PVCap on gas hydrate dissociation in saline solutions and n-heptane. Control shows the experiment in saline solution without any inhibitors in the presence of heptane.                                                                                                                                                            47  The hydrate equilibrium temperature in the presence of heptane for the gas mixture used in the DSC analysis at 8.0 MPa is 286.5 K (calculated by CSMGem6). However, the hydrate dissociated at ~ 290 K (Figure  4.13), which is the equilibrium point without n-heptane (Figure  4.1). It is suggested that due to the lack of the mixing in DSC experiments and small amount of heptane which could not change the gas phase composition, the equilibrium point was not affected by n-heptane. Integration of endothermic peaks as a function of time during temperature ramping would show the adsorbed heat in the dissociation process which can be related to the amount of formed hydrate43. Calculated mean adsorbed heat (Figure  4.13) was 20.2 mJ in controls and this value was decreased to 8.7 mJ and 6.8 mJ in the presence of PVP and PVCap, respectively. Hence, the amount of formed hydrate in the presence of n-heptane was dramatically reduced by the KHIs: PVP reduced hydrate formation by 56 % and PVCap reduced hydrates by 67 %.   Figure ‎4.13. Gas hydrate dissociation peaks in DSC experiments in the presence of PVP and PVCap (Pexp=8.0 MPa, Teq =289.7 K6). Control shows experiment in saline solution without inhibitors in the presence of heptane.                                                                                                                                                           48   : Impact of biological kinetic hydrate inhibitors on gas hydrate Chapter 5formation and dissociation in saline water  This Chapter contains the influence of biological kinetic hydrate inhibitors (AFP I and III) on gas hydrate nucleation, growth and dissociation in saline water.  5.1. Influence on gas hydrate nucleation Since gas hydrate formation is exothermic6, nucleation in the crystallizers was easily monitored by the temperature spikes in the aqueous phase accompanied by a sudden reduction in pressure. Under programmed cooling rates and with gas provided by supply reservoirs to prevent pressure loss, a sudden decrease in supply reservoir pressure represented the onset of gas hydrate nucleation. Crystallizer temperature profiles of saline solutions with and without inhibitors (AFP I and III) show that induction times for the gas hydrate formation compared to control saline solutions were delayed with AFP I and III an average of 170 and 333 min, respectively (Figure  5.1, and Table  5.1). Confirmation that the temperature increases (Figure  5.1) coincided with gas hydrate formation was obtained by monitoring the simultaneous change in pressure reduction rates in the supply vessels (Figure  5.2). Previously, it has been shown that onset of gas hydrate nucleation in saline solution can be delayed by as much as 1.7 and 1.6 times in the presence of PVP and PVCap, respectively, and here it is shown that AFP I and III approach this level of effectiveness by delaying nucleation by 1.3 and 1.6 times, respectively. Interestingly, these observations indicated that AFP III in the presence of saline is as effective as a chemical kinetic inhibitor.                                                                                                                                                           49   Figure ‎5.1. Temperature profiles of saline solutions with and without inhibitors in the experiments conducted at a cooling rate of 1 K/h and Pexp=7.0 MPa. Exothermal peaks are marked with arrows for controls (black line), AFP I (blue line) and AFP III (red line).   Figure ‎5.2. Pressure profiles of the supply reservoirs during gas hydrate formation experiments conducted at a cooling rate of 1 K/h without inhibitors (black control line) and with inhibitors AFP I (blue dotted line) and AFP III (red dashed line) in saline solutions. Arrows indicate inflections in the pressure reduction rate curves.                                                                                                                                                           50   Table ‎5.1. Experimental conditions, showing induction times and nucleation temperature in both HP-µDSC and autoclave experiments (Control: Saline solution without inhibitors).       Gas uptake experiments                                                     (Pexp. =7.0 MPa) DSC experiments                (Pexp. =7.0 MPa)         Induction Time (min) Nucleation Temperature (K) Induction Time (min) Experiment Solution       Average     Average   Average 1A Control   596.5   603.5 283.8 283.9 75.8 78.3 1B   610.5   284.0 80.8 2A AFP I   756.2   771.4 280.7 281.0 92.3 93.9 2B   786.6   281.3 95.5 3A AFP III   928.8   936.1 278.4 278.5 122.1 123.4 3B   943.4   278.6 124.7  In order to complement the results obtained with the crystallizers, differential scanning calorimetry (isothermal protocol) was also used to determine the influence of the inhibitors on gas hydrate formation. Similar to the stirred reactor observations, the addition of AFPs was found to delay nucleation. Compared to control conditions, gas hydrate nucleation was delayed in the presence of AFP I and III an average of 16 and 45 min, respectively (Figure  5.3, and Table  5.1). Although the two different experimental assessments of nucleation time were clearly distinct, the average delay in nucleation time was strikingly similar; in the HP-µDSC, mean hydrate nucleation was delayed by a factor of 1.2 and 1.6 for AFP I and III, respectively.                                                                                                                                                           51   Figure ‎5.3. HP-µDSC experiments showing hydrate nucleation in the saline solution controls (black line) and with AFP I (blue dotted line) or AFP III (red dashed line) at Pexp=7.0 MPa, and Texp=259.15 K.  Both gas uptake and DSC experiments were in concordance; they indicated that the biological inhibitors increased gas hydrate induction time in the presence of sodium chloride and that AFP III showed more inhibitory activity than AFP I. This conclusion contrasts with the previously reported performance of these AFPs in small crystallizers maintained under constant temperature and pressure and filled with the pure water38. Since direct comparisons with different equipment and experimental design are difficult, the crystallizer experiments were repeated using solutions as described by previous experimental parameters38. In water, AFP I had a longer induction time than AFP III; nucleation in water was delayed 359 min in the presence of AFP I (Figure  5.4) and 119 min in the presence of AFP III (Figure  5.5). Thus, the presence of sodium chloride promoted the performance of AFP III by increasing the average induction time by 173 min (from 763 to 936 min). However, the inhibitory activity of AFP I was reduced by 232 min (from 1003 to 771 min) in saline solution.                                                                                                                                                           52   Figure ‎5.4. Supply reservoir pressure profiles showing the impact of water salinity on the activity of AFP I inhibitory in gas hydrate inhibition. Arrows show the gas hydrate induction times for each experiment.   Figure ‎5.5. Supply reservoir pressure profiles showing the impact of water salinity on the activity of AFP III inhibitory in gas hydrate inhibition. Arrows show the gas hydrate induction times for each experiment.                                                                                                                                                            53  AFPs likely inhibit gas hydrate growth by adsorption-inhibition30 but the exact mechanism is still not understood. The two fish AFPs used here are structurally distinct; AFP I has an α-helical conformation (Figure  1.5a) and AFP III is globular (Figure  1.5b), but both have relatively ‘flat’ ice adsorption sites. AFPs appear to adsorb to ice crystals by hydrogen bonding of clathrate-arranged water molecules present on their hydrophobic ice-binding sites72. The principle electrolyte in teleost fish serum is NaCl and serum osmolarity increases under cold conditions to about half of the surrounding seawater, and thus it is reasoned that these proteins would retain their active structures in saline.  Circular Dichroism (CD) analysis confirmed that both AFPs retained their characteristic structure in either solvent (Figure  5.6). In CD tests, AFP I showed a spectral minimum at 219 nm and a maximum at 190 nm, characteristic of an alpha helix irrespective of the solvent (Figure  5.6a). Similarly, the AFP III spectrum was consistent in both water and saline with a less regular globular protein structure (Figure  5.6b).  -3-1135180 200 220 240 260Millidegrees Wavelength (nm) (a)                                                                                                                                                           54   Figure ‎5.6. Circular dichroism analysis of the biological KHIs in ddH2O (blue solid line) and saline (red dashed line) plotted as millidegrees vs. wavelength for AFP I (a) and AFP III (b). Note that the depicted scans are the average of a minimum of five scans subtracted from the average of five control solutions and normalized to 40 μM (AFP I) or 100 μM (AFP III). Scans in saline were terminated at 193 nm due to the high background generated by NaCl.  Theoretically however, the addition of NaCl to the solution should decrease hydrophobic forces73, and as a result it is possible that there could be reduced hydrate inhibition in saline. Such a reduction was observed for AFP I. To confirm this, the effect of a higher salt concentration (5 wt % NaCl) was investigated. In this case, the induction time was reduced from 771.4 min (in the presence of 3.5 wt % of NaCl) to 680 min (Figure  5.4), showing that the effectiveness of AFP I to inhibit gas hydrate formation was reduced by addition of NaCl, which might be related to the reduction of hydrophobic interactions. In contrast with the AFP I experiments, the addition of NaCl increased AFP III activity as a gas hydrate inhibitor. Previously, it was reported that addition of positive ions such as Ca+2 or Na+1 to an aqueous solution of AFP III enhanced its ice inhibition activity74. This effect was attributed to positive ions being attracted to the negatively charged AFP III protein surface75, resulting in a reduction in repulsive electrostatic forces between AFP III molecules with the -7-5-3-11180 200 220 240 260Millidegrees Wavelength (nm)  (b)                                                                                                                                                           55  consequent increase in the number of proteins on the ice crystal surface74. Thus although a higher salt concentration could reduce hydrophobic forces, this may be offset by an increase in the effective concentration of the inhibitor. To investigate the association of AFP III hydrate inhibition and saline concentration, the performance of type III AFP was then tested at lower solute concentration (2 wt % of NaCl) which is shown in Figure  5.5. In this case, the gas hydrate induction time (~ 804 min) was decreased compared that in 3.5 wt % of NaCl (~ 936.1 min) and as predicted (Figure  5.5). 5.2. Gas hydrate growth in saline solutions in the presence of AFPs The cumulative gas consumed during gas hydrate formation was different in the presence and absence of inhibitors (Figure  5.7). The addition of AFPs increased gas hydrate induction time, as discussed above, but also had an impact on gas hydrate growth. In the presence of AFPs, the hydrate growth period appeared to be divided into two stages (Figure  5.7a). This behavior was not observed in control experiments. The interface of these two stages is shown more clearly in Figure  5.7b. In the first section (772-1020 min, and 937-1110 min for AFP I and III, respectively) gas hydrates grew with an average rate of 0.0131 and 0.0139 mmol/min for AFP I and III, respectively (Figure  5.7b). Both of these rates are lower than the rate of hydrate formation in control experiments (0.0214 mmol/min). In the second portion of the growth period (1020-1400 min and 1110-1550 min for AFP I and III, respectively), however, the AFPs appeared to increase hydrate growth rates (0.0354 and 0.0370 mmol/min for AFP I and III, respectively) compared to control experiments (0.0214 mmol/min).  Similar behavior has also been reported in the presence of chemical inhibitors in previous sections. Thus, it is suggested that it is characteristic of KHIs, including AFPs to control hydrate                                                                                                                                                           56  growth only up to a critical point, after which hydrates grow faster. This is not a desirable commercial attribute.    Figure ‎5.7. Cumulative gas consumption during hydrate formation in 3.5% saline solution, controls without inhibitors (black line) and with AFP I (blue dotted line) or AFP III (red dashed line) under a cooling rate of 1 K/h and Pexp=7.0 MPa. (a) Induction times are shown by arrows, (b) Gas consumption is shown from 550 to 1150 min with induction times shown as arrows. Stars indicate the onset of catastrophic growth.                                                                                                                                                             57  Table ‎5.2. Calculated gas hydrate growth rates in different growth periods (with standard errors). Control experiment is saline solution without inhibitors.   Growth Period 11 Growth Period 21 Solution Period occurrence (min) Growth rate            (mol/min) Period occurrence (min) Growth rate        (mol/min) Control 605-1100 2.14 10-4 (3.27 10-7) -------- -------- AFP I 772-1020 1.31 10-4 (3.2 10-7) 1020-1400 3.54 10-4 (3.26 10-7) AFP III 937-1110 1.39 10-4 (2.79 10-7) 1110-1550 3.70 10-4 (6.84 10-7) 1Gas hydrate formed under constant pressure (7.0 MPa) and a cooling rate of 1 K/h.  Gas phase temperature was monitored throughout gas hydrate growth (Figure  5.8). Since gas hydrate formation is exothermic, elevation of the gas phase temperature is indicative of hydrate formation in the gas phase. Gas hydrate-mediated increases in the gas phase started at ~1020 and 1110 min in the presence of AFP I and III, respectively, which are coincident with the increases in gas hydrate growth rate in the presence of AFPs (Figure  5.7b). Therefore, once hydrate formation had initiated in the presence of AFPs in the gas phase, gas hydrate grew faster compared to the experiments without inhibitors.                                                                                                                                                              58   Figure ‎5.8. Gas phase temperature profiles during gas hydrate formation for the control (black line) and the presence of AFP I (blue dotted line) or AFP III (red dashed line) under a cooling rate of 1 K/h and Pexp=7.0 MPa. Control experiment is saline solution without inhibitors.  By adsorption to embryonic hydrate crystals, AFPs would reduce the available hydrate surface area31,33, increasing the intrinsic reaction resistance and therefore decreasing the rate of hydrate formation. Evidence of such an effect was seen in the initial phase of gas hydrate growth where AFPs adsorbed to the hydrate surface reduced growth, but in the second phase, the gas consumption rate was similar to growth shown by controls (Figure  5.7a). Faster hydrate formation was also seen when the increase in gas temperature was monitored (Figure  5.8). Similar observations have been reported in the presence of chemical inhibitors51,64, but the mechanism has not been explained. Possibly, the higher porosity of the hydrate crystal structure in the presence of kinetic inhibitors50 could facilitate water transport by capillary action, thereby enhancing gas hydrate formation. For AFPs, this increasing porosity would presumably allow the surface area to expand faster than the AFPs could orient themselves on the crystal.                                                                                                                                                           59  5.3. Gas hydrate dissociation in the presence of biological kinetic inhibitors in saline solution Once hydrate crystals were formed in the presence of antifreeze proteins (type I and III) in saline solutions, their dissociation was monitored using both autoclave and HP-µDSC.  The increase in pressure of the crystallizers (Figure  5.9) is due to the decrease in gas solubility (evolution of dissolved gas), the gas hydrate dissociation and thermal expansion. The effect of temperature on gas phase thermal expansion is compensated in the calculated numbers of moles of released gas. Hence, the number of released moles increased due to hydrate decomposition and gas desorption. Crystallizer pressure profiles started to rise at ~ 25 min for all cases (Figure  5.9). However, the normalized released gas concentration remained at zero for ~ 45 min. Therefore, the increase in the crystallizer pressure before ~ 70 min was due to the thermal expansion only. The increase in calculated gas release started at ~ 78 min in control experiments, while addition of AFP I and III decreased this time to ~ 71.5 and ~ 68.5 min, respectively. The increases in released gas are attributed to gas hydrate dissociation and gas desorption. Therefore, gas hydrate dissociation started sooner in the presence of AFPs, as has been shown in the presence of chemical inhibitors (PVP and PVCap) in previous sections. Nevertheless, complete gas hydrate dissociation took modestly longer in the presence of AFP I and III compared to the control experiments by a factor of 1.26 and 1.31, respectively.                                                                                                                                                           60   Figure ‎5.9. Calculated normalized released gas (upper panel) and pressure profiles (lower panel) during gas hydrate dissociation in the control experiments (black line; saline solution without inhibitor) and in the presence of AFP I (blue dotted line) and AFP III (red dashed line) in saline solutions.  Gas hydrate dissociation can be identified by endothermic peaks in HP-µDSC experiments as discussed previously. Heat flow profiles (Figure  5.10) showed that in control experiments hydrate dissociated at 289.1 K, very close to the equilibrium value for sII hydrate (288.8 K at Pexp.=7.0 MPa, calculated by CSMGem6). These profiles show ‘tails’, which presumably reflect the variable composition of hydrate formed by the sudden freezing of sub-cooled solution. In the presence of AFP I and III hydrate (sII) also dissociated at 289.1 K, but in addition to the expected hydrate dissociation peak, two other peaks at 290.2 and 292.5 K were observed (Figure  5.10). Remarkably, AFP addition obviously reduced the amount of formed hydrate corresponding to the first peak, suggesting that different crystalline structures might form. Overall, hydrate dissociation took longer in the presence of AFPs, consistent with the results obtained by the autoclave analysis.                                                                                                                                                           61   Figure ‎5.10. Hydrate dissociation profiles in HP-µDSC experiments for the control (black line; saline solution) and the presence of AFP I (blue dotted line) or AFP III (red dashed line) under a heating rate of 0.2 K/min and Pexp=7.0 MPa (equilibrium hydrate formation temperature at experimental pressure is 288.8 K ;calculated by CSMGem6).  Previously, it has been suggested that hydrates formed in the presence of biological KHIs have two different hydrate structures43 and compositional changes39. Since the equilibrium temperature to form sI hydrate with used gas mixture at 7.0 MPa is 282.9 K (calculated by CSMGem6), as previously noted43, the observed additional peaks at 290.2 and 292.4 K in the presence of AFPs would not correspond to different known structures of hydrate. Although earlier work examined the dissociation of hydrates formed in methane in the presence of PVCap and may not be relevant here, of two endothermic peaks in DSC experiments, the first one was sI37. An increase in PVCap concentration reduced the area of the first peak and increased the second. It was suggested that hydrate compositional changes can indeed contribute to the multistep dissociation curve40 (Figure  5.10). However, it might be due to AFP adsorption on the                                                                                                                                                           62  gas hydrate surface resulting in more stabilized hydrate crystals76. Such an influence on hydrate crystals has been previously noted in morphological experiments in which hydrates appeared to be “harder” in the presence of KHIs compared to the control experiments50. It is suggested that this is consistent with a property of AFPs with respect to ice recrystallization inhibition; AFPs adsorb to ice crystals and stabilize them so that at temperatures close to melting, ice recrystallization is effectively prevented.                                                                                                                                                                             63   :  Impact of biological kinetic hydrate inhibitors on gas hydrate Chapter 6formation and dissociation in saline water in the presence of liquid hydrocarbon phase   In this Chapter the impact of biological kinetic hydrate inhibitors (AFP I and III) on gas hydrate nucleation, growth and dissociation in saline water and in the presence of liquid hydrocarbon phase (n-heptane) is studied. 6.1. Gas hydrate nucleation in saline solutions and in the presence of n-heptane Gas hydrate nucleation was indicated by a rise in the aqueous phase temperature in the crystallizers6 (Figure  6.1) coinciding with a sudden reduction in the pressure of the related supply vessel (Figure  6.2). The addition of AFP I to the saline solution in the presence of n-heptane substantially reduced the time for gas hydrate induction compared to control (from 977 to 1205 min) resulting in ~ 18 % reduction in nucleation time (Figure  6.1 and Table  6.1). Similar observations for other KHIs in the presence of liquid hydrocarbon have been observed in the previous section and reported32 which is a worrisome problem for industry. In contrast, the addition of AFP III in saline solution in the presence of n-heptane did not change the induction time (Figure  6.1 and Table  6.1). In previous section, it was observed that in the absence of heptane, AFP III increased the time to nucleation more than AFP I. Here, in the presence of n-heptane, AFP III not only out performed AFP I with respect to induction time but also was superior than previously reported KHIs (PVP and PVCap) which also reduced gas hydrate induction time in the presence of light crude mimic.                                                                                                                                                           64   Figure ‎6.1. Temperature profiles in the aqueous phase with and without inhibitors at a cooling rate of 1 K/h and Pexp=7.0 MPa. The average values of induction times are shown. Exothermal peaks are marked with circles for control (black line), AFP I (blue line) and AFP III (red line). Control is saline solution without any inhibitor in the presence of heptane.   Figure ‎6.2. Pressure profiles of the supply vessels during gas hydrate formation experiments at a cooling rate of 1 K/h without inhibitors (black control line) and with inhibitors AFP I (blue dotted line) and AFP III (red dashed line) in saline in the presence of heptane. The average values of induction times are shown. Arrows indicate inflections in the pressure reduction rate curves.                                                                                                                                                           65    Table ‎6.1. Experimental conditions, showing induction times and nucleation temperature in both HP-µDSC and autoclave experiments (Control: Saline solution without inhibitors in the presence of heptane).                                         Gas uptake experiments    (Pexp =7.0 MPa)   DSC experiments (Pexp =8.0 MPa)     Induction Time (min) Nucleation Temperature (K) ∆Tsub-cooling1 (K)   Nucleation Temperature (K)   ∆Tsub-cooling2 (K) Experiment Solution       Average     Average       Average     1A Control   1212.0   1205.0 274.0 274.1 11.5   257.5 257.4   29.1 1B   1204.0   274.2   257.4   1C   1199.0   274.1   257.2                                     2A AFP I   990.3   976.8 277.3 277.6 8.1   258.1 258.1   28.4 2B   963.2   277.8   258.0   2C   -----   -----   258.2                                     3A AFP III   1223.6   1208.7 274.0 274.0 11.7   256.7 257.3   29.2 3B   1193.8   273.9   257.5   3C   -----   -----   257.6   1∆T sub-cooling = Teq-Tnucleation , Teq=285.6 K at Pexp=7.0 MPa 2∆T sub-cooling = Teq-Tnucleation , Teq=286.5 K at Pexp=8.0 MPa  Figure  6.3 shows heat flow profiles, with exothermic peaks indicating gas hydrate nucleation in DSC experiments. The effect of AFP I and III on gas hydrate nucleation were concordant with the high pressure crystallizer experiments. The gas hydrate nucleation temperature was increased by addition of AFP I to saline solutions in the presence of n-heptane (from 257.4 K to 258.1 K), however, AFP III did not alter the nucleation temperature (Figure  6.3 and Table  6.1). Since the sub-cooling temperature (Teq-Tnucleation) in the presence of AFP III (29.1 K) was higher than that shown by AFP I (28.4 K), again AFP III performed better than AFP I. Indeed, at 29.1 K, AFP III performed more efficiently than some chemical inhibitors as evidenced by previously reported (Table  3.1) sub-cooling temperatures of 28.3 K and 28.9 K for gas hydrate nucleation in the presence of polyvinylpyrrolidone (PVP) and polyvinylcaprolactam (PVCap), respectively.                                                                                                                                                            66   Figure ‎6.3. HP-µDSC experiments showing hydrate nucleation in the control (black line) and with AFP I (blue dotted line) or AFP III (red dashed line) additives at Pexp=8.0 MPa and a cooling rate at 0.2 K/min. Control experiment is saline solution without inhibitor and in the presence of heptane.  It is still not understood how the addition of KHIs in the presence of liquid hydrocarbon facilitate gas hydrate nucleation. However, a decrease in the interfacial surface tension between the aqueous and liquid hydrocarbon phases69, and the consequent decrease in mass transfer resistance was discussed as a possible reason for the reduction in induction time for chemical KHIs in previous sections. By this reasoning, AFP I might also reduce interfacial surface tension, possibly due to its amphipathic alpha-helix conformation25,26. Consequently, mass transfer barrier for gas hydrate nucleation might be decreased. It would then be expected to reduce nucleation time. This was not the case for AFP III, however, which is a globular protein, and since the addition of this KHI did not change the induction time from that seen in controls, it is possible that the protein was extracted into the heptane phase. Neither protein structure was influenced by saline, as assessed by circular dichroism (Figure  5.6), so the differences in                                                                                                                                                           67  nucleation times for these two biological inhibitors are due to the presence of the hydrocarbon phase.  Figure  6.4 shows a summary of the mean induction times for the different tested solutions in the gas uptake and DSC experiments, which have also been summarized in Table  5.1 and Table  6.1. Due to a lack of the mixing in the DSC experiments and different methods (isothermal and temperature ramping), a comparison in the presence or absence of n-heptane was not reasonable.   Figure ‎6.4. Effect of AFP I and III on gas hydrate induction time in saline solutions and the presence of n-heptane in gas uptake experiments (Pexp=7.0 MPa, Cooling rate: 1 K/h) and DSC, isothermal protocol (Pexp=7.0 MPa, Texp=259.1 K; without n-heptane) and temperature ramping method (Pexp=8.0 MPa, Cooling rate: 0.2 K/h; with n-heptane).  6.2. Gas hydrate growth in saline solutions in the presence of liquid hydrocarbon The addition of AFP I and III in saline solutions in the presence of n-heptane decreased the growth of post nucleation hydrate crystals seen at 0.073 mmol/min (calculated based on the shown trend in Figure  6.5) for control experiments. The addition of AFP I and AFP                                                                                                                                                           68  III reduced growth rate to 0.017 and 0.019 mmol/min, respectively. As a consequence, the total moles of formed hydrate in 48 h was reduced from 0.168 moles in control experiments to 0.081 and 0.098 moles in the presence of AFP I and III, respectively. This reduction in hydrate growth rate is impressive since in similar conditions the chemical inhibitors PVP and PVCap have been shown to reduce formed hydrate to 0.036 and 0.014 mmol/min, respectively. By this measure then AFPs had superior control of gas hydrate growth than PVP and were close to that seen for PVCap.   Figure ‎6.5. Cumulative gas consumption during hydrate formation in control (black line) and with AFP I (blue dotted line) or AFP III (red dashed line) in saline solution at a cooling rate of 1 K/h and Pexp=7.0 MPa. Arrows show the nucleation points for each experiment. Control experiment is saline solution without inhibitor in the presence of heptane.  The mechanism of the performance of AFPs in gas hydrate inhibition is still not understood. If the amphipathic AFP I remained at the interface of the aqueous and hydrocarbon phase, then these molecules would presumably be readily available for adsorption and incorporation into the forming gas hydrate crystals, retarding hydrate growth77. It is curious, however, that AFP III with                                                                                                                                                           69  no negative impact on nucleation, as other KHIs, was a very effective hydrate growth inhibitor. It is speculated that although the inhibitor entered the hydrocarbon phase and did not impact nucleation, once crystallization was initiated, the mixing of the phases and capillary action then allowed AFP III to adsorb and incorporate into the growing hydrate and inhibiting its rate of growth.  Table  6.2 shows the summary of the comparison between the performance of PVP and PVCap as chemical inhibitors and AFP I and III as biological ones in the inhibition of gas hydrate nucleation and growth under different circumstances.  Table ‎6.2. Comparison between the performance of PVP, PVCap, AFP I and III in gas hydrate formation under different conditions. The most effective inhibitor is shown.   Hydrate Formation Mixture   Saline Solution   Saline+n-heptane To prolong induction time PVP   AFP III To decrease growth rate PVCap   PVCap To reduce extent of catastrophic growth AFP I   No catastrophic growth was observed  6.3. Gas hydrate dissociation in saline solutions in the presence of n-heptane Figure  6.6 depicts the normalized released gas profiles for different AFPs during gas hydrate dissociation in the crystallizers. In the presence of AFPs dissociation started later compared to control (saline+heptane) experiments. In this case, gas hydrate dissociation started at ~ 51 min in the control experiment; however this time was modestly prolonged to ~ 53 and ~ 59 min in the presence of AFP I and III, respectively. Consequently, the gas hydrate dissociation took longer in the presence of AFPs. The formed gas hydrate dissociated in two steps in the presence of AFPs. Similarly, chemical KHIs also delay complete gas hydrate dissociation.                                                                                                                                                            70   Figure ‎6.6. The calculated normalized released gas during gas hydrate dissociation in control experiments (black line) and presence of AFP I (blue dotted line) and AFP III (red dashed line) in saline solutions. Control is saline solution without inhibitors in the presence of heptane.  In order to augment the results obtained with the crystallizers, differential scanning calorimetry was also used to determine the influence of the inhibitors on gas hydrate dissociation with endothermic peaks representing gas hydrate melting (Figure  6.7). The calculated hydrate equilibrium temperature at 8.0 MPa for the natural gas mixture in the presence of saline solution is 289.7 K6. The calculated equilibrium temperature in the presence of heptane is calculated to be 286.5 K6. This is because the presence of heptane in a well-mixed system changes the gas phase composition78. It is notable, however, that due to the small amount of n-heptane (1 µL) in the DSC experiments compared to the large amount of gas phase and the absence of stirring, the gas composition is not affected by the addition of the liquid hydrocarbon. The gas hydrate dissociation temperature was measured with the DSC and found to be 289.7 K in saline solution with or without n-heptane. In control experiments an endothermic peak was observed at 289.4 K, quite close to the equilibrium temperature at 8.0 MPa as discussed above. The peak was followed by a curve                                                                                                                                                           71  which presumably reflects the variable composition of hydrate formed by the sudden freezing of sub-cooled solution. However, in the presence of AFPs multi-peak dissociation was observed. The first peak was observed at 289.6 K, likely corresponding to the later dissociation of gas hydrates, which was observed in the autoclave analysis. Endothermic peaks at higher temperatures were also observed in the presence of AFPs, one peak at 291.3 K for APF III, and two peaks at 290.6 K and 292.2 K for AFP I (Figure  6.7). Multi-peak dissociation was reported in previous section for AFPs in saline solution without any liquid hydrocarbon. Therefore, these additional peaks do not reflect an impact of n-heptane on hydrate dissociation. Finally, hydrate dissociation took longer in the presence of AFP I and III, consistent the results with the high pressure crystallizer.   Figure ‎6.7. Hydrate dissociation profiles in HP-µDSC experiments for control (black line; saline solution without inhibitors in the presence of heptane) and the presence of AFP I (blue dotted line) or AFP III (red dashed line) under a heating rate of 0.2 K/min and Pexp=8.0 MPa.                                                                                                                                                            72  The reason for the appearance of endothermic peaks in the presence of KHIs at temperatures higher than equilibrium temperature is still not understood. However, it is clear that some portion of the hydrates formed in the presence of AFPs were stable outside the hydrate stability region, implying heterogeneous hydrate structure. Previously, it was suggested that adsorption of inhibitor molecules on the surface of natural gas hydrate crystals could dictate compositional changes in the formed hydrate40,43, and this proposal may be applicable here. As well, if AFPs adsorb to hydrate crystals at the phase interface, they may allow the hydrates to remain outside the stability field, a phenomenon termed anomalous- or self- preservation6. Perhaps analogously, AFPs adsorb to ice crystals and prevent the melting of small crystals, or ice recrystallization, which is normally observed at temperatures just below the equilibrium freezing point.                                                                                                                                                                         73   : Conclusions and recommendations Chapter 7 7.1. Conclusions The performance of four kinetic hydrate inhibitors (PVP, PVCap, AFP I and III) in the presence of NaCl and with/without a liquid hydrocarbon (n-heptane) phase was evaluated by monitoring hydrate formation using a set of two identical stirred tank vessels, calorimetry and a high pressure rheometer. A gas mixture that consisted of CH4 (93 mol %), C2H6 (5 mol %) and C3H8 (2 mol %) was employed as the hydrate former. It was found that in the presence of NaCl the kinetic hydrate inhibitors (KHIs) significantly prolonged induction time, similar to the effect observed in a fresh water system. The KHIs were able to regulate hydrate growth following nucleation but only until a certain point. Accelerated hydrate growth was observed afterwards. This phenomenon was also observed in other systems and was referred in the literature as catastrophic growth. PVP (molecular weight = 3.5 kDa) performed better than PVCap (molecular weight = 23.3 kDa) in terms of delaying the nucleation, and catastrophic growth was less severe than that observed in the presence of PVCap. Using the hydrate suspension viscosity as an indicator, the presence of KHIs (PVP and PVCap) was found to accelerate gas hydrate formation after a certain point. Although the presence of NaCl in the aqueous phase did not show any influence on the structure of AFPs in Circular Dichroism experiments, the inhibitory activity of AFP I decreased while AFP III performed more efficiently. Similar to chemical inhibitors, addition of AFPs regulated gas hydrate growth for an initial period but after that the rate of crystal growth accelerated. In the presence of KHIs it was also found that gas hydrate dissociation started earlier, but complete dissociation took longer.  The addition of liquid hydrocarbon (n-heptane) created a two-liquid phase system (aqueous NaCl solution and n-heptane). When gas hydrates formed with this system and using the methane/ethane/propane gas mixture it was found that the induction time increased (it took                                                                                                                                                           74  longer to nucleate hydrate crystals). Moreover, the hydrate crystal growth decreased it was attributed to the fact that the equilibrium temperature in the presence of heptane is lower than without it. In addition, the heptane likely increased the resistance to mass transfer for the hydrate forming gas mixture. The viscosity of the suspension was used as an indicator of hydrate particle agglomeration/formation and it was suggested that agglomeration was delayed in the presence of n-heptane.  Unexpectedly, in the presence of heptane, addition of chemical inhibitors (PVP and PVCap) caused a faster nucleation, but an overall slower growth rate.  In this case, hydrate particles remained dispersed in the slurry phase and which may minimize the chances of hydrate clog formation. Under these conditions, AFP I was similar to chemical KHIs in that induction time was reduced. However, AFP III was superior in that it did not reduce nucleation time. There was a significant reduction in hydrate growth by addition of AFPs. Once hydrates formed in the presence of KHIs, however, hydrate decomposition took longer and proceeded in two steps in the presence of n-heptane. 7.2. Recommendations for future work Based on the insight gained from the current work, the following future recommendations are proposed. 1. Many oil/gas/condensate resources are classified as sour hydrocarbon streams which containing carbon dioxide and hydrogen sulfide45. It is known that CO2 and H2S promote hydrate formation thermodynamically (hydrate can form in lower pressures and higher temperatures in the presence of these chemicals). Therefore, evaluation of KHIs under conditions close to the actual field circumstances needs to be examined in the presence of CO2 and H2S.                                                                                                                                                           75  2. The presence of n-heptane as a representative of hydrocarbon condensate reduced gas hydrate particles agglomeration and improves the performance of KHIs to control gas hydrate growth. As it was reported that the type of hydrocarbon condensate influences on the stickiness of hydrate particles79, the presence of actual gas condensate/oil instead of pure heptane would provide a condition close to the actual off-shore pipeline conditions.  3. Morphological experiments during gas hydrate dissociation in the presence of KHIs at hydrate equilibrium conditions and also at temperatures above equilibrium temperature would reveal how KHIs are able to stabilize hydrate crystals outside hydrate stable zone. Particularly, in more simple systems including single gas hydrate former e.g. propane and pure water.  4. Hydrophobic interactions were proposed as a mechanism for adsorption of AFP molecules on the surface of hydrate crystals. The next step should be molecular dynamic simulation to examine the performance of AFPs on gas hydrate inhibition in pure and saline water. 5. Molecular level experiments such as in-situ Raman and NMR spectroscopy during gas hydrate dissociation in the presence of KHIs may reveal how these additives impact on the gas hydrate crystals as they are stable outside hydrate zone. These experiments would illustrate if the type of formed hydrate which is stable outside hydrate stable zone is different or adsorption of KHIs molecules makes them stable.                                                                                                                                                                 76   Bibliography  (1)  Sharifi, H.; Ripmeester, J.; Walker, V. K.; Englezos, P. Kinetic Inhibition of Natural Gas Hydrates in Saline Solutions and Heptane. Fuel 2014, 117, 109–117. (2)  Sharifi, H.; Englezos, P.; Hatzikiriakos, S. G. Rheological Evaluation of Kinetic Hydrate Inhibitors in NaCl/n-Heptane Solutions. AIChE J. 2014, 60, 7, 2654-2659. (3)  Sharifi, H.; Walker, V. K.; Ripmeester, J. A.; Englezos, P. Insights into the Behaviour of Biological Clathrate Hydrate Inhibitors in Aqueous Saline Solutions. Cryst. Growth Des. 2014, 14, 2923–2930. (4)  Sharifi, H.; Walker, V. K.; Ripmeester, J. A.; Englezos, P. Inhibition Activity of Antifreeze Proteins with Natural Gas Hydrates in Saline and the Light Crude Oil Mimic, Heptane. Energy Fuels 2014, 28, 3712–3717. (5)  Englezos, P. Clathrate Hydrates. Ind. Eng. Chem. Res. 1993, 32, 1251–1274. (6)  Sloan, E. D.; Koh, C. A. Clathrate Hydrates of Natural Gases; CRC Press Llc, 2008. (7)  Davy, H. The Bakerian Lecture: On Some of the Combinations of Oxymuriatic Gas and Oxygene, and on the Chemical Relations of These Principles, to Inflammable Bodies. Philos. Trans. R. Soc. Lond. 1811, 1–35. (8)  Faraday, M.; Davy, H. On Fluid Chlorine. Philos. Trans. R. Soc. Lond. 1823, 113, 160–165. (9)  Hammerschmidt, E. G. Formation of Gas Hydrates in Natural Gas Transmission Lines. Ind. Eng. Chem. 1934, 26, 851–855. (10)  McMullan, R. K.; Jeffrey, G. A. Polyhedral Clathrate Hydrates. IX. Structure of Ethylene Oxide Hydrate. J. Chem. Phys. 2004, 42, 2725–2732. (11)  Mak, T. C.; McMullan, R. K. Polyhedral Clathrate Hydrates. X. Structure of the Double Hydrate of Tetrahydrofuran and Hydrogen Sulfide. J. Chem. Phys. 2004, 42, 2732–2737. (12)  Ripmeester, J. A.; John, S. T.; Ratcliffe, C. I.; Powell, B. M. A New Clathrate Hydrate Structure. Nature 1987, 325, 135–136. (13)  Sloan, E. D. Fundamental Principles and Applications of Natural Gas Hydrates. Nature 2003, 426, 353–363. (14)  Udachin, K. A.; Ripmeester, J. A. A Complex Clathrate Hydrate Structure Showing Bimodal Guest Hydration. Nature 1999, 397, 420–423. (15)  Ellison, B. T.; Gallagher, C. T.; Frostman, L. M.; Lorimer, S. E. The Physical Chemistry of Wax, Hydrates, and Asphaltene. In Offshore Technology Conference; 2000.                                                                                                                                                           77  (16)  Sloan, E. D.; Koh, C. A.; Sum, A. Natural Gas Hydrates in Flow Assurance; Gulf Professional Publishing, 2010. (17)  Creek, J. L. Efficient Hydrate Plug Prevention. Energy Fuels 2012, 26, 4112–4116. (18)  Lederhos, J. P.; Long, J. P.; Sum, A.; Christiansen, R. L.; Sloan Jr, E. D. Effective Kinetic Inhibitors for Natural Gas Hydrates. Chem. Eng. Sci. 1996, 51, 1221–1229. (19)  Fu, B. The Development of Advanced Kinetic Hydrate Inhibitors. Spec. Publ.-R. Soc. Chem. 2002, 280, 264–276. (20)  Fu, B.; Neff, S.; Mathur, A.; Bakeev, K. Application of Low-Dosage Hydrate Inhibitors in Deepwater Operations. Old Prod. Facil. 2002, 17, 133–137. (21)  Kelland, M. A. History of the Development of Low Dosage Hydrate Inhibitors. Energy Fuels 2006, 20, 825–847. (22)  Del Villano, L.; Kommedal, R.; Kelland, M. A. Class of Kinetic Hydrate Inhibitors with Good Biodegradability. Energy Fuels 2008, 22, 3143–3149. (23)  Zeng, H.; Wilson, L. D.; Walker, V. K.; Ripmeester, J. A. The Inhibition of Tetrahydrofuran Clathrate-Hydrate Formation with Antifreeze Protein. Can. J. Phys. 2003, 81, 17–24. (24)  Zeng, H.; Moudrakovski, I. L.; Ripmeester, J. A.; Walker, V. K. Effect of Antifreeze Protein on Nucleation, Growth and Memory of Gas Hydrates. AIChE J. 2006, 52, 3304–3309. (25)  Davies, P. L.; Baardsnes, J.; Kuiper, M. J.; Walker, V. K. Structure and Function of Antifreeze Proteins. Philos. Trans. R. Soc. Lond. B. Biol. Sci. 2002, 357, 927–935. (26)  Ewart, K. V.; Lin, Q.; Hew, C. L. Structure, Function and Evolution of Antifreeze Proteins. Cell. Mol. Life Sci. CMLS 1999, 55, 271–283. (27)  Venketesh, S.; Dayananda, C. Properties, Potentials, and Prospects of Antifreeze Proteins. Crit. Rev. Biotechnol. 2008, 28, 57–82. (28)  Yeh, Y.; Feeney, R. E. Antifreeze Proteins: Structures and Mechanisms of Function. Chem. Rev. 1996, 96, 601–618. (29)  Raymond, J. A.; DeVries, A. L. Adsorption Inhibition as a Mechanism of Freezing Resistance in Polar Fishes. Proc. Natl. Acad. Sci. 1977, 74, 2589–2593. (30)  Zeng, H.; Wilson, L. D.; Walker, V. K.; Ripmeester, J. A. Effect of Antifreeze Proteins on the Nucleation, Growth, and the Memory Effect during Tetrahydrofuran Clathrate Hydrate Formation. J. Am. Chem. Soc. 2006, 128, 2844–2850. (31)  Jensen, L.; Ramløv, H.; Thomsen, K.; von Solms, N. Inhibition of Methane Hydrate Formation by Ice-Structuring Proteins. Ind. Eng. Chem. Res. 2010, 49, 1486–1492. (32)  Jensen, L.; Thomsen, K.; von Solms, N. Inhibition of Structure I and II Gas Hydrates Using Synthetic and Biological Kinetic Inhibitors. Energy Fuels 2010, 25, 17–23.                                                                                                                                                           78  (33)  Al-Adel, S.; Dick, J. A.; El-Ghafari, R.; Servio, P. The Effect of Biological and Polymeric Inhibitors on Methane Gas Hydrate Growth Kinetics. Fluid Phase Equilibria 2008, 267, 92–98. (34)  Zeng, H.; Walker, V. K.; Ripmeester, J. A. Approaches to the Design of Better Low-Dosage Gas Hydrate Inhibitors. Angew. Chem. 2007, 119, 5498–5500. (35)  Anderson, B. J.; Tester, J. W.; Borghi, G. P.; Trout, B. L. Properties of Inhibitors of Methane Hydrate Formation via Molecular Dynamics Simulations. J. Am. Chem. Soc. 2005, 127, 17852–17862. (36)  Makogon, Y. F.; Makogon, T. Y.; Holditch, S. A. Kinetics and Mechanisms of Gas Hydrate Formation and Dissociation with Inhibitors. Ann. N. Y. Acad. Sci. 2000, 912, 777–796. (37)  Lachance, J. W.; Dendy Sloan, E.; Koh, C. A. Effect of Hydrate Formation/dissociation on Emulsion Stability Using DSC and Visual Techniques. Chem. Eng. Sci. 2008, 63, 3942–3947. (38)  Daraboina, N.; Linga, P.; Ripmeester, J.; Walker, V. K.; Englezos, P. Natural Gas Hydrate Formation and Decomposition in the Presence of Kinetic Inhibitors. 2. Stirred Reactor Experiments. Energy Fuels 2011, 25, 4384–4391. (39)  Daraboina, N.; Ripmeester, J.; Walker, V. K.; Englezos, P. Natural Gas Hydrate Formation and Decomposition in the Presence of Kinetic Inhibitors. 1. High Pressure Calorimetry. Energy Fuels 2011, 25, 4392–4397. (40)  Daraboina, N.; Ripmeester, J.; Walker, V. K.; Englezos, P. Natural Gas Hydrate Formation and Decomposition in the Presence of Kinetic Inhibitors. 3. Structural and Compositional Changes. Energy Fuels 2011, 25, 4398–4404. (41)  Daraboina, N.; Moudrakovski, I. L.; Ripmeester, J. A.; Walker, V. K.; Englezos, P. Assessing the Performance of Commercial and Biological Gas Hydrate Inhibitors Using Nuclear Magnetic Resonance Microscopy and a Stirred Autoclave. Fuel 2013, 105, 630–635. (42)  Ohno, H.; Moudrakovski, I.; Gordienko, R.; Ripmeester, J.; Walker, V. K. Structures of Hydrocarbon Hydrates during Formation with and without Inhibitors. J. Phys. Chem. A 2012, 116, 1337–1343. (43)  Ohno, H.; Susilo, R.; Gordienko, R.; Ripmeester, J.; Walker, V. K. Interaction of Antifreeze Proteins with Hydrocarbon Hydrates. Chem.- Eur. J. 2010, 16, 10409–10417. (44)  Lederhos, J. P.; Sloan, E. D. Transferability of Kinetic Inhibitors between Laboratory and Pilot Plant. In SPE Annual Technical Conference and Exhibition; 1996. (45)  Glenat, P.; Peytavy, J.-L.; Holland-Jones, N.; Grainger, M. South-Pars Phases 2 and 3: The Kinetic Hydrate Inhibitor (KHI) Experience Applied at Field Start-Up. In Abu Dhabi International Conference and Exhibition; 2004.                                                                                                                                                           79  (46)  Notz, P. K.; Bumgardner, S. B.; Schaneman, B. D.; Todd, J. L. Application of Kinetic Inhibitors to Gas Hydrate Problems. Old Prod. Facil. 1996, 11, 256–260. (47)  Dong Lee, J.; Wu, H.; Englezos, P. Cationic Starches as Gas Hydrate Kinetic Inhibitors. Chem. Eng. Sci. 2007, 62, 6548–6555. (48)  Lee, J. D.; Englezos, P. Enhancement of the Performance of Gas Hydrate Kinetic Inhibitors with Polyethylene Oxide. Chem. Eng. Sci. 2005, 60, 5323–5330. (49)  Ohno, H.; Strobel, T. A.; Dec, S. F.; Sloan, J.; Koh, C. A. Raman Studies of Methane- Ethane Hydrate Metastability. J. Phys. Chem. A 2009, 113, 1711–1716. (50)  Lee, J. D.; Englezos, P. Unusual Kinetic Inhibitor Effects on Gas Hydrate Formation. Chem. Eng. Sci. 2006, 61, 1368–1376. (51)  Kumar, R.; Lee, J. D.; Song, M.; Englezos, P. Kinetic Inhibitor Effects on Methane/propane Clathrate Hydrate-Crystal Growth at the Gas/water and Water/n-Heptane Interfaces. J. Cryst. Growth 2008, 310, 1154–1166. (52)  Ajiro, H.; Takemoto, Y.; Akashi, M.; Chua, P. C.; Kelland, M. A. Study of the Kinetic Hydrate Inhibitor Performance of a Series of Poly (N-Alkyl-N-Vinylacetamide) S. Energy Fuels 2010, 24, 6400–6410. (53)  O’Reilly, R.; Ieong, N. S.; Chua, P. C.; Kelland, M. A. Missing Poly (N-Vinyl Lactam) Kinetic Hydrate Inhibitor: High-Pressure Kinetic Hydrate Inhibition of Structure II Gas Hydrates with Poly (N-Vinyl Piperidone) and Other Poly (N-Vinyl Lactam) Homopolymers. Energy Fuels 2011, 25, 4595–4599. (54)  Linga, P.; Kumar, R.; Englezos, P. Gas Hydrate Formation from Hydrogen/carbon Dioxide and Nitrogen/carbon Dioxide Gas Mixtures. Chem. Eng. Sci. 2007, 62, 4268–4276. (55)  Haligva, C.; Linga, P.; Ripmeester, J. A.; Englezos, P. Recovery of Methane from a Variable-Volume Bed of Silica Sand/hydrate by Depressurization. Energy Fuels 2010, 24, 2947–2955. (56)  Dalmazzone, D.; Kharrat, M.; Lachet, V.; Fouconnier, B.; Clausse, D. DSC and PVT Measurements. J. Therm. Anal. Calorim. 2002, 70, 493–505. (57)  Behzadfar, E.; Hatzikiriakos, S. G. Rheology of Bitumen: Effects of Temperature, Pressure, CO2 Concentration and Shear Rate. Fuel 2014, 116, 578–587. (58)  Personal Communication with Supplier, James Erickhoff, Product Specialist – Rheology at Anton Paar USA, July 2014. (59)  Ohno, H.; Strobel, T. A.; Dec, S. F.; Sloan, J.; Koh, C. A. Raman Studies of Methane- Ethane Hydrate Metastability. J. Phys. Chem. A 2009, 113, 1711–1716.                                                                                                                                                           80  (60)  Wathen, B.; Kwan, P.; Jia, Z.; Walker, V. K. Modeling the Interactions between Poly (n-Vinylpyrrolidone) and Gas Hydrates: Factors Involved in Suppressing and Accelerating Hydrate Growth. In High Performance Computing Systems and Applications; 2010; pp. 117–133. (61)  Zeng, H.; Lu, H.; Huva, E.; Walker, V. K.; Ripmeester, J. A. Differences in Nucleator Adsorption May Explain Distinct Inhibition Activities of Two Gas Hydrate Kinetic Inhibitors. Chem. Eng. Sci. 2008, 63, 4026–4029. (62)  Rodahl, M.; Höök, F.; Fredriksson, C.; Keller, C. A.; Krozer, A.; Brzezinski, P.; Voinova, M.; Kasemo, B. Simultaneous Frequency and Dissipation Factor QCM Measurements of Biomolecular Adsorption and Cell Adhesion. Faraday Discuss. 1997, 107, 229–246. (63)  Rodahl, M.; Hook, F.; Krozer, A.; Brzezinski, P.; Kasemo, B. Quartz Crystal Microbalance Setup for Frequency and Q-Factor Measurements in Gaseous and Liquid Environments. Rev. Sci. Instrum. 1995, 66, 3924–3930. (64)  Yang, J.; Tohidi, B. Characterization of Inhibition Mechanisms of Kinetic Hydrate Inhibitors Using Ultrasonic Test Technique. Chem. Eng. Sci. 2011, 66, 278–283. (65)  Zhang, J. S.; Lo, C.; Couzis, A.; Somasundaran, P.; Wu, J.; Lee, J. W. Adsorption of Kinetic Inhibitors on Clathrate Hydrates. J. Phys. Chem. C 2009, 113, 17418–17420. (66)  Makogon, Y. F.; Holditch, S. A. Lab Work Clarifies Gas Hydrate Formation, Dissociation. Oil Gas J 2001, 99, 47. (67)  Ballard, A. L.; Sloan Jr, E. D. Hydrate Phase Diagrams for Methane+ Ethane+ Propane Mixtures. Chem. Eng. Sci. 2001, 56, 6883–6895. (68)  Davies, S. R.; Hester, K. C.; Lachance, J. W.; Koh, C. A.; Dendy Sloan, E. Studies of Hydrate Nucleation with High Pressure Differential Scanning Calorimetry. Chem. Eng. Sci. 2009, 64, 370–375. (69)  Lou, A.; Pethica, B. A.; Somasundaran, P. Interfacial and Monolayer Properties of Poly (vinylcaprolactam). Langmuir 2000, 16, 7691–7693. (70)  Noskov, B. A.; Akentiev, A. V.; Miller, R. Dynamic Surface Properties of Poly (vinylpyrrolidone) Solutions. J. Colloid Interface Sci. 2002, 255, 417–424. (71)  Águila-Hernández, J.; Trejo, A.; García-Flores, B. E. Volumetric and Surface Tension Behavior of Aqueous Solutions of Polyvinylpyrrolidone in the Range (288 to 303) K. J. Chem. Eng. Data 2011, 56, 2371–2378. (72)  Garnham, C. P.; Campbell, R. L.; Davies, P. L. Anchored Clathrate Waters Bind Antifreeze Proteins to Ice. Proc. Natl. Acad. Sci. 2011, 108, 7363–7367. (73)  Wang, L.; Yoon, R.-H. Hydrophobic Forces in the Foam Films Stabilized by Sodium Dodecyl Sulfate: Effect of Electrolyte. Langmuir 2004, 20, 11457–11464.                                                                                                                                                           81  (74)  Du, N.; Liu, X. Y. Enhanced Antifreeze Effect of Antifreeze Protein on Ice Nucleation by Electrolyte. Cryst. Growth Des. 2008, 8, 3290–3294. (75)  Baardsnes, J.; Kuiper, M. J.; Davies, P. L. Antifreeze Protein Dimer WHEN TWO ICE-BINDING FACES ARE BETTER THAN ONE. J. Biol. Chem. 2003, 278, 38942–38947. (76)  Habetinova, E.; Lund, A.; Larsen, R. Hydrate Dissociation under the Influence of Low-Dosage Kinetic Inhibitors. In Proceedings of the 4th International Conference on Gas Hydrates, Yokohama, Japan; 2002. (77)  Wathen, B.; Kuiper, M.; Walker, V.; Jia, Z. New Simulation Model of Multicomponent Crystal Growth and Inhibition. Chem.- Eur. J. 2004, 10, 1598–1605. (78)  Peter, B.; Dagobert, K.; Iradj, R. Influence of Liquid Hydrocarbons on Gas Hydrate Equilibrium. In European Petroleum Conference; 1992. (79)  Austvik, T.; Li, X.; Gjertsen, L. H. Hydrate Plug Properties: Formation and Removal of Plugs. Ann. N. Y. Acad. Sci. 2000, 912, 294–303.  

Cite

Citation Scheme:

        

Citations by CSL (citeproc-js)

Usage Statistics

Share

Embed

Customize your widget with the following options, then copy and paste the code below into the HTML of your page to embed this item in your website.
                        
                            <div id="ubcOpenCollectionsWidgetDisplay">
                            <script id="ubcOpenCollectionsWidget"
                            src="{[{embed.src}]}"
                            data-item="{[{embed.item}]}"
                            data-collection="{[{embed.collection}]}"
                            data-metadata="{[{embed.showMetadata}]}"
                            data-width="{[{embed.width}]}"
                            async >
                            </script>
                            </div>
                        
                    
IIIF logo Our image viewer uses the IIIF 2.0 standard. To load this item in other compatible viewers, use this url:
http://iiif.library.ubc.ca/presentation/dsp.24.1-0166089/manifest

Comment

Related Items