1. JOHN HUDSON ELIZABETH WYANT DR. MIGUEL BAGAJEWICZ APRIL 29, 2008 Economic Potential of Stranded Natural Gas Hydrates

2. Problem Can gas hydrates be exploited economically?  What are hydrates and where are they located?  What research is going on and what are the problems?  What is the time line for the project?  Where are the wells going to be drilled and how many?  What kind of production can be expected?  What markets can the natural gas from hydrate be sold in?  What is the most economic option to transport the natural gas to the sales market?

3. Why Gas Hydrates? Conventional oil and gas resources are being depleted Alternatives are becoming more economical  Market prices (NYMEX)  $9.501/MMBTU on 3/5/08  $7.719/MMBTU on 2/1/08  Large proven reserves  Estimated 5,000 to 12,000,000 trillion cubic feet (TCF) 3

4. Natural Gas Hydrate What is it?  Methane molecule surrounded by water/ice  Found at 32 - 41  F and around 50 atm  Unstable at atmospheric conditions  168 standard cubic feet of natural gas per cubic foot of hydrate Where are they located on land?  Arctic and Antarctic regions  At a depth between 1000 – 5750 feet  Common above conventional gas reservoirs

5. Where to Drill? Kamchatka Peninsula, Russia

6. Research and Potential Problems A Canadian and Japanese team worked on drilling  Mackenzie Delta  Continuous flow for 6 days Other countries such as The U.S., India, Japan and China are trying to find them. Potential Problems include:  Produced water  1 cubic foot per 168 cubic feet of natural gas  Produced sediment

7. Project Timeline Tasks1234567891011-30 Have Logistic for both the LNG/ Pipeline started Seismic: 5 person team (6-8 weeks)$54 Order Materials for Pipeline/LNG facility Find crew and begin measures to house and feed them Ship Intial Equipment: Build Pad 1 Drill 1st Well, perform core analysis, and other analysis Cap well until Pipeline/LNGbuilding is completed Build Pipeline/LNG: will take 3 - 6 years (Assume 4 years) Start building facilities for each location (approx. 2 months per facility) Drill all other wells Start wells to sells If seismic data renders negative project is stopped. Loss is $54 million With a go-ahead, production would start at year 9. Net present worth of investment during first 9 years = -$5 to -25 Billion

8. Assumptions Potential problems  Large amounts of produced water  Produced sediment (land slides) Assuming:  An ideal situation. (i.e.none of the potential problems occur).  Natural gas hydrates are found at 2000 – 4500 feet below that surface.  Assume 4 total daily natural gas production rates (million standard cubic feet, MMscf) 130, 195, 260 and 390 MMscf

9. Drilling Specifics

10. Drilling Operation 6 basic steps 1. Shoot seismic (Geology) 2. Prepare site for drilling 3. Drill well 4. Log well 5. Complete well 6. Produce well 10

11. Seismic Information 11

12. Site Preparation Build roads Prepare ground Transport and install equipment (rig up) Drill well 12

13. Drilling Well Complicated Dangerous Steps to drilling 1. Drill into ground 2. Set casing and cement 3. Repeat until finished 4. Prepare for completion 13

14. Horizontal Drilling 14

15. Coring Can look at the subsurface Special drilling operation 15

16. Logging Well Done after drilling Determines subsurface composition 16

17. Completions Communication with the formation Three steps  Perforation  Fracturing  Install production equipment 17

18. 18

20. Kamchatka Peninsula, Russia Drilling Location  3000 sq. miles of land

21. Important Locations Locations  4 wells per pad  1 mile between each pad

22. Drilling Plan Shoot seismic Drill the first well and take coring samples  Vertical well  Each well at different depths 2500 feet, 3000 feet, 3500 feet, and 4000 feet  Average production per well is 882867 standard cubic feet per day Maximum production per well (scfd)882867 Needed Production (MMscfd)130195260390 Number of wells147221294442 Number of locations375574110

23. Production Model

24. Methods of Production Depressurization Thermal injection Mining

25. Production Model Wiggins and Shah (OU) model (2001) Reservoir Pressure Dissociation Pressure Flow Properties Distance from well Based on continuity equation. Uses dissociation kinetics. Consider pressure drop in porous hydrate free rock.

26. Description of Model Assumptions:  Darcy flow (laminar flow)  Radial flow  Homogenous, isotropic reservoir  Hydrate dissociation at interface Limitations:  Cannot model high flow rates  Cannot be used with irregularly shaped reservoirs

27. Excel Calculations Snapshots

28. R* increases from 2,000 m to 26,000 m over 20 years. Re = 4,000

29. R* increases from 5,000 m to 58,000 m over 20 years. Re = 20,000

30. R* increases from 8,000 m to 83,000 m over 20 years. Re = 40,000

31. R* increases from 12,000 m to 130,000 m over 20 years. Re = 100,000

32. Limits of Gas Flow Flow changes from Darcy flow to non-Darcy flow after 25,000 SCMD  Model does not work for high flow rates  New model must be developed and used Reservoir controls the maximum flow rate

33. Choke Flow (Flow Limits) Flow rate potential in piping is far greater than the reservoir can handle.

34. Wellhead Facilities Specs# NeededUOMCost Christmas Tree Max P: 10,000 psia4MM$0.2 Vertical 3-phase separator Flow rate: 100 MMscfd2MM$0.15 Diameter: 5.3 m Height: 8.5 m Volume: 326 m 3 Compressors Pad 1437.77 HP1MM$0.875 Pad 2 - ?6771.51 HP1MM$13.543 Vertical Separator Christmas Tree

35. Gathering System The gathering system is not just located in one place. Bring wells together to minimize pipe.

36. Transportation and Markets Transportation Options  Liquefied Natural Gas  Pipeline Three different markets  Japan  Mainland Russia  China at a later date

37. Important Locations LNG Facility

38. Liquefied Natural Gas Gas Usage and Value By: Dr. Duncan Seddon

39. Important Locations Pipeline

40. Pipeline to Magadan, Russia, and Blagoveshchensk, Russia

41. Piping Network Simulation

42. Pipeline Economics Subsea Pipeline Economics By: Palmer

43. Effect of Changing Royalties Changing royalties can play a major role in the economics!

44. Future Gas Cost Based on Commercial Consumer U.S. Prices (1980-Present) Found % change Used change and the random function in Excel

45. Economic Comparison The most profitable option is to transport the natural gas by LNG Vertical Wells (883000 ft 3 /d) Net Present Worth (MM$)LNGPipeline 130$3,109-$4,437 195$5,063-$3,399 260$7,040-$2,294 390$10,898$545 Return On Investment 13020.54%1.90% 19522.26%5.60% 26022.93%9.77% 39023.86%18.76% Horizontal Wells (2.6 x 10 6 ft 3 /d) Net Present Worth (MM$)LNGPipeline 130$5,126-$1,220 195$7,951$1,310 260$10,894$3,985 390$16,673$9,963 Return On Investment 13035.89%7.92% 19539.84%17.02% 26041.35%21.83% 39044.05%29.80%

46. Another Option

47. GTL Economics Return On Investment (MM$)20 years30 years 13022.70%23.35% 19523.28%23.93% 26023.25%23.90% 39023.54%24.20% Net Present Worth (MM$)20 years30 years 130$3,097$4,011 195$4,802$6,183 260$6,428$8,276 390$9,799$12,580

48. Conclusion It is the most economical to pursue transport by LNG, but if horizontal wells were drilled instead, there are many other options that would make good investments. GTL production is also a possible option! The research that is on going in industry is promising and we are getting close to producing natural gas hydrates.

49. Questions?