JOHN HUDSON ELIZABETH WYANT DR. MIGUEL BAGAJEWICZ APRIL 29, 2008 Economic Potential of Stranded...
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Transcript of JOHN HUDSON ELIZABETH WYANT DR. MIGUEL BAGAJEWICZ APRIL 29, 2008 Economic Potential of Stranded...
JOHN HUDSONELIZABETH WYANT
DR. MIGUEL BAGAJEWICZ
APRIL 29, 2008
Economic Potential of Stranded Natural Gas
Hydrates
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?
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
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 hydrateWhere are they located on land?
Arctic and Antarctic regions At a depth between 1000 – 5750 feet Common above conventional gas reservoirs
Where to Drill?
Kamchatka Peninsula, Russia
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
Project Timeline
Tasks 1 2 3 4 5 6 7 8 9 10 11-30
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
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
Drilling Specifics
Drilling Operation
6 basic steps
1. Shoot seismic (Geology)
2. Prepare site for drilling
3. Drill well4. Log well5. Complete well6. Produce well
10
Seismic Information
11
Site Preparation
Build roadsPrepare groundTransport and
install equipment (rig up)
Drill well
12
Drilling Well
ComplicatedDangerous
Steps to drilling1.Drill into ground2.Set casing and
cement3.Repeat until
finished4.Prepare for
completion 13
Horizontal Drilling
14
Coring
Can look at the subsurface
Special drilling operation
15
Logging Well
Done after drillingDetermines
subsurface composition
16
Completions
Communication with the formation
Three steps Perforation Fracturing Install production
equipment
17
18
Kamchatka Peninsula, Russia
Drilling Location 3000 sq. miles of land
Important Locations
Locations 4 wells per pad 1 mile between
each pad
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) 130 195 260 390
Number of wells 147 221 294 442
Number of locations 37 55 74 110
Production Model
Methods of Production
DepressurizationThermal injectionMining
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.
0 10000 20000 30000 400000
100200300400500600700800
Radius, m
Pre
ssure
, psi
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
Excel Calculations Snapshots
0 5000 10000 15000 20000 25000 30000 350000
100
200
300
400
500
600
700
800
1,000 SCMD (0.1 to 20 years)
Radius, m
Pre
ssure
, psi
R* increases from 2,000 m to 26,000 m over 20 years.
Re = 4,000
0 10000 20000 30000 40000 50000 60000 70000 80000350
375
400
425
450
475
500
525
550
575
600
625
650
675
700
5,000 SCMD (0.1 to 20 years)
Radius, m
Pre
ssure
, psi
R* increases from 5,000 m to 58,000 m over 20 years.
Re = 20,000
0 20000 40000 60000 80000 100000 1200000
100
200
300
400
500
600
700
800
10,000 SCMD (0.1 to 20 years)
Radius, m
Pre
ssure
, psi
R* increases from 8,000 m to 83,000 m over 20 years.
Re = 40,000
0 20000 40000 60000 80000 100000 120000 140000 160000 1800000
50
100
150
200
250
300
350
400
450
500
550
600
650
700
750
25,000 SCMD (0.1 to 20 years)
Radius, m
Pre
ssure
, psi
R* increases from 12,000 m to 130,000 m over 20 years.
Re = 100,000
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
Choke Flow (Flow Limits)
1 2 3 4 5 6 7 8 9 10 11 120.0
1,000,000,000.0
2,000,000,000.0
3,000,000,000.0
4,000,000,000.0
5,000,000,000.0
6,000,000,000.0
7,000,000,000.0
8,000,000,000.0
9,000,000,000.0
10,000,000,000.0
Maximum Flow Rate in Piping
Diameter, in
Flo
w R
ate
, m
3/d
Flow rate potential in piping is far greater than the reservoir can handle.
Wellhead Facilities
Specs # Needed UOM Cost
Christmas Tree Max P: 10,000 psia 4 MM$ 0.2
Vertical 3-phase separator Flow rate: 100 MMscfd 2 MM$ 0.15
Diameter: 5.3 m
Height: 8.5 m
Volume: 326 m3
Compressors
Pad 1 437.77 HP 1 MM$ 0.875
Pad 2 - ? 6771.51 HP 1 MM$ 13.543
Vertical Separator
Christmas Tree
Gathering System
The gathering system is not just located in one place.
Bring wells together to minimize pipe.
Transportation and Markets
Transportation Options Liquefied Natural Gas Pipeline
Three different markets Japan Mainland Russia China at a later date
Important Locations
LNG Facility
Liquefied Natural Gas
Gas Usage and Value By: Dr. Duncan Seddon
Total LNG Costs
0
1000
2000
3000
4000
5000
130 195 260 390
Gas Flow Rate (MMscfd)
Cos
t (M
M$)
Drilling
Surface Equipment
LNG Facility
Shipping
Regas Facility
Important Locations
Pipeline
Pipeline to Magadan, Russia, and Blagoveshchensk, Russia
Piping Network Simulation
Pipeline Economics
Subsea Pipeline Economics By: Palmer
Total Pipeline Costs
0
1000
2000
3000
4000
5000
6000
130 195 260 390
Gas Flow Rate (MMscfd)
Cost
(MM
$) Drilling Costs
Surface Equipment Cost
Pipeline Cost
Effect of Changing Royalties
Changing royalties can play a major role in the economics!
Effect of Royalties on LNG NPW
$0
$2,000
$4,000
$6,000
$8,000
$10,000
$12,000
$14,000
0 100 200 300 400 500Flow rate (MMscfd)
NP
W (
MM
$) 10% Royalties
7% Royalties
5% Royalties
3% Royalties
Effects of Royalties on Pipeline NPW
-$5,000
-$4,000
-$3,000
-$2,000
-$1,000
$0
$1,000
$2,000
$3,000
$4,000
0 100 200 300 400 500
Flow rate (MMscfd)
NP
W (
MM
$) 10% Royalties
7% Royalties
5% Royalties
3% Royalties
Future Gas Cost
Based on Commercial Consumer U.S. Prices (1980-Present)
Found % changeUsed change and the random function in
Excel
Economic Comparison
• The most profitable option is to transport the natural gas by LNG
Vertical Wells (883000 ft3/d)
Net Present Worth (MM$) LNG Pipeline
130 $3,109 -$4,437
195 $5,063 -$3,399
260 $7,040 -$2,294
390$10,89
8 $545
Return On Investment
130 20.54% 1.90%
195 22.26% 5.60%
260 22.93% 9.77%
390 23.86% 18.76%
Horizontal Wells (2.6 x 106 ft3/d)
Net Present Worth (MM$) LNG Pipeline
130 $5,126 -$1,220
195 $7,951 $1,310
260$10,89
4 $3,985
390$16,67
3 $9,963
Return On Investment
130 35.89% 7.92%
195 39.84% 17.02%
260 41.35% 21.83%
390 44.05% 29.80%
Another Option
Total GTL Costs
0
1000
2000
3000
4000
5000
130 195 260 390
Gas Flow Rate (MMscfd)
Cos
t (M
M$)
Drilling
Surface Equipment
GTL Facility
Shipping
GTL Economics
Return On Investment
(MM$) 20 years 30 years
130 22.70% 23.35%
195 23.28% 23.93%
260 23.25% 23.90%
390 23.54% 24.20%
Net Present Worth (MM$) 20 years 30 years
130 $3,097 $4,011
195 $4,802 $6,183
260 $6,428 $8,276
390 $9,799 $12,580
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.
Questions?