TAMU - Pemex Offshore Drilling

1. 1 TAMU - PemexOffshore Drilling Lesson 12B Hydrates

2. 2 Lesson 21 - Hydrates What are they? Why are they important? Where are they found? Conditions for existence Drilling-related problems Remedies - Procedures

3. 3 Hydrates - What are they? Gas Hydrates are solids formed from hydrocarbon gas and liquid water They resemble wet snow and can exist at temperatures above the freezing point of water They belong to a form of complexes known as clathrates

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5. 5 Clathrates - What are they? Clathrates are substances having a lattice-like structure or appearance in which molecules of one substance are completely enclosed within the crystal structure of another Hydrates consist of host molecules (water) forming a lattice structure acting like a cage, to entrap guest molecules (gas) LATIN: “clathratus” means to encage

6. 6 Types of Hydrates The following gases when combined with water under the right conditions are known to produce hydrates: Natural gas molecules ranging from methane to isobutane Hydrogen sulfide Carbon dioxide

7. 7 Hydrates - Why are they important? A very large potential source of natural gas A hindrance to the natural gas industry Often cause plugging of lines and equipment (like an “ice” plug) In drilling, under well control situations, hydrates may plug lines and chokes

8. 8 A Natural Gas Resource? Conditions for hydrate formation are satisfied in more than 90% of the ocean floors, but hydrates will only be present if there is a source of natural gas and a structure suitable for gas accumulation It has been estimated that total worldwide hydrate resources are as much as 1016 m3, or twice as large the combined fossil fuel resource.

9. 9 A Natural Gas Resource? Possibly as much as 98% of the hydrate resource is below the world’s oceans The remaining 2% that is found on land, below permafrost, is estimated to be twice the size of the conventional natural gas resourse Natural gas has been produced from hydrates for decades in Russia

10. 10 A Natural Gas Resource? It is estimated that gas contained in naturally occurring gas hydrates may exceed 16 trillion tons of oil equivalent One cubic foot of hydrate can hold 170 standard cubic feet of gas

11. 11 A Problem in the Natural Gas Industry? In the 1930’s it was discovered that natural gas hydrates were blocking gas transmission lines, frequently at temperatures well above the freezing point of water This discovery led to the regulation of the water content in natural gas pipelines

12. 12 A Problem in the Natural Gas Industry? It has since been determined that gas hydrates may exist at temperatures as high as 20-30 oC. As the pressure increases, hydrates can exist at higher temperatures

13. 13 A Problem in Drilling? Where hydrates are present in-situ in petroleum reservoirs, they can cause blowouts if drilled into inadvertently Extreme conditions of temperature and pressure mean that hydrates may form during the drilling process if fluids containing water come into contact with the reservoir fluids

14. 14 A Problem in Drilling? Formation of solid hydrates can plug up subsea risers, choke and kill lines, and BOPs Conditions during well shut-in are particularly favorable for hydrate formation if high pressures are combined with falling temperatures and there is sufficient time for equilibrium to be reached

15. 15 A Problem in Drilling? Water depths near the West Shetlands and Hebrides rapidly reach 1,000 meters or more, with seabed temperatures down to -2oC In the deepwater regions of the Gulf of Mexico the seabed temperature is typically around 4oC or even lower Such extreme conditions present risks of hydrate formation

16. 16 Where are Hydrates found? Hydrates are found in situ in the deep oceans of the world, on the ocean floor or in the sediments below the seafloor Hydrates are found in situ in permafrost regions Hydrates are also found in extraterrestrial environments

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20. 20 Temperatures Profile in the Gulf of Mexico

21. 21 Temperatures Profile in the North Sea

22. 22 Pressures @ 8.6 lb/gal

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26. 26 Hydrate-Related Drilling Problems Choke and Kill line plugging Plugging of wellbore below the BOPs Plug formed around the drillpipe inside casing, in the the BOPs or in the riser, preventing drillstring movement Plug formed in the BOPs preventing full BOP closure Plug keeping BOPs from opening

27. 27 Hydrate-Related Drilling Problems There are two basic types of hydrate-related drilling problems: Drilling through formations already containing natural hydrates, and Experiencing drilling conditions that may be conducive to formation of hydrates

28. 28 Techniques for drilling through Zones containing Hydrates Reduce the temperature of the drilling mud Drill at “controlled” drilling rates (not too fast - to reduce heat generation rates) Increase mud weight - if possible Increase mud circulation rate to ensure turbulent flow to achieve better cooling and to remove any gas

29. 29 Techniques to avoid Hydrate Formation while Drilling Keeping the temperature above, or the pressure below hydrate formation conditions Using chemicals to depress the hydrate formation point, i.e., use “thermodynamic inhibitors” such as methanol, glycols and salts (methanol is very toxic)

30. 30 Techniques for avoiding Hydrate Formation while Drilling - cont’d Adding chemicals that reduce the rate of nucleation of hydrate crystals Adding chemicals to reduce the rate of growth of hydrate crystals which have nucleated Adding chemicals that tend to prevent agglomeration of crystals, so that solid plugs do not form (kinetic inhibitors)

31. 31 Thermodynamic Inhibitors Basically, thermodynamic inhibitors reduce the temperature at which hydrates will form The inhibitor dissolves in the water phase, increasing the stability of the liquid water with respect to the hydrate An inhibitor like methanol will also enter the gas and liquid hydrocarbons

32. 32 Thermodynamic Inhibitors - cont’d Salts are the most commonly used inhibitors: NaCl, KCl and CaCl2 Saturated NaCl (26%) provides a ~21 oK margin relative to pure water Glycols and glycerols can also be used Mixed inhibitors can be used and their effect is approximately additive 20-23% NaCl polymer muds are the most commonly used for deepwater drilling

33. 33 Kinetic Inhibitors Kinetic inhibitors work by reducing the rate of nucleation of hydrates, the growth rate of the crystals, or the agglomeration of the crystals They cannot prevent hydrate formation, but they may increase the delay between the time when a fluid enters the hydrate zone and the formation of a blockage These have not been tested in drilling

34. 34 Remedies

35. 35 Remedies

36. 36 Remedies

37. 37 Remedies

38. 38 Well Control Remediation Methods Prevent hydrocarbons from entering the wellbore (adequate mud weight, rapid shut-in) If hydrocarbons enter the wellbore, prevent them from reaching the wellhead (monitoring, bullheading) If hydrocarbons reach the wellhead and BOP, prevent formation of hydrates (high salinity mud; glycol mud standby)

39. 39 Well Control Remediation Methods - cont’d If hydrates do form, eliminate them (methanol on standby for pumping down kill line, heated seawater ready to be pumped up riser) Methods for removing hydrate blockages: Depressurization to dissociate the hydrate Addition of chemical inhibitors to melt the hydrate External heating to dissociate the hydrate Mechanical (drilling)

40. 40 References Clathrate Hydrates of Natural Gases, by E. Dendy Sloan, Jr., Marcel Dekker, Inc., New York,1998. The Properties of Petroleum Fluids, by William D. McCain, Jr. PennWell Books, Pennwell Publishing Company, Tulsa, Oklahoma, 1990. “Controlling, Remediation of fluid hydrates in deepwater drilling operations,” by B.Edmonds, R.A.S. Moorwood and R. Szczepanski, Ultradeep Engineering, March 2001.

41. 41 References - cont’d IADC Deepwater Well Control Guidelines. International Association of Drilling Contractors. Houston, Texas, 1998. “Lab work clarifies gas hydrate formation, dissociation,” by Yuri F. Makogon and Stephen A. Holditch. Oil & Gas Journal, Feb.5, 2001. “Experiments illustrate hydrate morphology, kinetics,” by Yuri F. Makogon and Stephen A. Holditch. Oil & Gas Journal, Feb.12, 2001. SPE, OTC...

42. 42 THE END