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Gas Hydrates Problems- (36,45)

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Gas Hydrates Problems- (36,45)

  1. 1. PRODUCTION ENGINEERING PROBLEMS V E D A N T M A K W A N A S H A S H A N K P A N D E Y1 G A S H Y D R A T E S
  2. 2. WHAT ARE GAS HYDRATES ? • Gas hydrate is a solid ice-like form of water that contains gas molecules in its molecular cavities1. In nature, this gas is mostly methane. Methane gas hydrate is stable at the seafloor at water depths beneath about 500 m. (a) Small dodecahedral and (b) large tetradecahedral water cages structure of hydrates with one "guest" molecule (methane) occupying each cavity. 2
  3. 3. GAS HYDRATES PROBLEMS 3
  4. 4. Potential scenario whereby dissociation of gas hydrates may give rise to subsea slope failure and massive methane gas release 4 Source http://www.pet.hw.ac.uk/research/hydrate/hydrates_why.cf m
  5. 5. FORMATION CAUSES 5
  6. 6. GAS HYDRATE FORMATION AND ACCUMULATION FACTORS Location and intensity of hydrate accumulations in a well vary and depend on: • Operating regime • Design • Geothermal gradient in the well • Fluid composition 6
  7. 7. HYDRATE FORMATION IN TUBING • Shut-in gas wells are particularly prone to serious hydrate problems, if the well has been producing some water. Subsequent equilibration of the tubular and its contents with cold zones of the rock can lower the temperature into the hydrate- formation region. • Hydrate nuclei form from the films of water on the tubular walls. The subsequent crystallization can result in large plugs of hydrate tens or hundreds of meters long. • Hydrate formation can also take place in shut-in oil wells(Makogon, Y. 1997)The logic is that oil will dissolve some water—generally small amounts. Under high- temperature/high-pressure (HT/HP) conditions, the amounts can be 5 to 10 mole% (at 300°F). The oil is produced up the wellbore, temperature falls, and liquid water comes out of solution, remaining in suspension as micro droplets. In a static condition, the micro droplets gradually coalesce and precipitate. This liquid water is saturated with gas so that hydrates can form at the appropriate pressure/volume/temperature (PT) values. 7
  8. 8. CONTROLLING HYDRATE FORMATION • Understand which pressure and temperature conditions/locations in the specific system are conducive to gas hydrate formation. • A number of computer simulators are available for this purpose(Edmonds, B., Moorwood,), usually as adjuncts to more general phase PVT simulators. • The models vary in how well they compute the chemical activity of the water phase, the effect of higher-molecular-weight hydrocarbons, and the effect of hydrate inhibitors • The second control step is the comparison of this information with the measured or expected PT profile within the production system. A method of coping with hydrate formation is then selected 8
  9. 9. INHIBITORSThe alternative to production control is the use of inhibitors. These are classified as: • Environmental inhibitors – The conceptually simplest “environmental inhibition” method is to dry the gas before it is cooled—remove the water and hydrates so they cannot form. This involves adsorption onto, for example, silica gel, or cooling and condensation, absorption of water into alcohols, or adsorption onto hydroscopic salts. • Thermodynamic inhibitors – Thermodynamic inhibition” has been the most common method for controlling gas hydrates. There are a number of alternatives: • Heating the gas • Decreasing pressure in the system • Injecting salt solutions – CaCl2 • Injecting alcohol or glycol-ethylene glycols for HSE reasons(Yousif, M.H., Dunayevsky, V.A., and Hale) • Kinetic inhibitors – low-dosage chemicals that prevent the growth of hydrate nuclei or prevent the agglomeration of nuclei into large crystals(Mitchell, G.F. and Talley, L.D. 1999.) 9
  10. 10. T h e g e n e r a l e f f e c t o f s u c h i n h i b i t o r s i s n o t a t o t a l r e m o v a l o f t h e p r o b l e m b u t a s h i f t o f t h e h y d r a t e - f o r ma t i o n c u r v e t o l o w e r t e m p e r a t u r e s 10
  11. 11. Summary of Solutions 11
  12. 12. • At fixed pressure, operating at temperatures above the hydrate formation temperature. This can be achieved by insulation or heating of the equipment. • At fixed temperature, operating at pressures below hydrate formation pressure. • Dehydration, i.e., reducing water concentration to an extent of avoiding hydrate formation. • Inhibition of the hydrate formation conditions by using chemicals such as methanol and salts. • Changing the feed composition by reducing the hydrate forming compounds or adding non hydrate forming compounds. • Preventing, or delaying hydrate formation by adding kinetic inhibitors. • Preventing hydrate clustering by using hydrate growth modifiers or coating of working surfaces with hydrophobic substances. • Preventing, or delaying hydrate formation by adding kinetic inhibitors. 12
  13. 13. REFERENCES • Mitchell, G.F. and Talley, L.D. 1999. Application of Kinetic Hydrate Inhibitor in Black-Oil Flowlines. Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 3-6 October 1999. SPE-56770-MS.http://dx.doi.org/10.2118/56770-MS. • Yousif, M.H., Dunayevsky, V.A., and Hale, A.H. 1997. Hydrate Plug Remediation: Options and Applications for Deep Water Drilling Operations. Presented at the SPE/IADC Drilling Conference, Amsterdam, Netherlands, 4-6 March 1997. SPE-37624- MS. http://dx.doi.org/10.2118/37624-MS. • Makogon, Y. 1997. Hydrates of Hydrocarbons. Tulsa, Oklahoma: PennWell Books. 13
  14. 14. THANK YOU 14

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