unconventional gas production - university of oklahoma...unconventional gas production...
TRANSCRIPT
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Unconventional Gas Production
Commercialization of Hydrated GasJames Mansingh
Jeffrey Melland
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Objective Statement� Methane hydrates hold a massive potential for production of
natural gas, so we set out to find an economical way to produce hydrated gas and deliver it to market
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Intro to Hydrates� Methane & water have the ability to form hydrates.
Methane WaterHydrate
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Clathrates� Methane trapped in a
cubic water crystals
� Unstable at standard temperature and pressure
� Estimated to produce 150 units of gas
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Overview� Operations
� Locating
� Drilling
� Production
� Piping
� Liquefaction
� Shipping
� Regasification
� Sales
� Operations� Locating
� Drilling
� Production
� Piping
� Liquefaction
� Shipping
� Regasification
� Sales
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Value Chain
Piping
Market
$/MMBtu
$/MMBtu$/MMBtu
$/MMBtu$/MMBtu
($/MMBtu)
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Locating
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� Seismic Surveying� Acoustic
� Seismic Analysis� 2 month project, 3 man team
� Block = 3 square miles
� Usually shoot 30-60 blocks at a time
� Project a 2000 square km area with a depth of 1200ft to 3300ft
Locating
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Locating cont’
� Seismic Survey Costs� $30,000 for shooting a block
� $12,000,000 for the 2000 km2 area with a depth of 400m-1000m
� $3,000,000 for reprocessing cost and time for the seismic survey
� Total Cost = $15,000,000
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Drilling
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Drilling� Drilling and
Measurements� Directional
drilling and basic logs to locate promising zones
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Drilling� Reservoir
Evaluation � In depth logs
of promising areas
� Perforations into methane hydrated areas
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Drilling� Well
Stimulation
� Pressurized solution addition into the formation to stimulate backflow of desired product
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� Drilling and Measurements� 17 day projects� 90fph thru basic formation� 10fph thru hydrate formation
� Reservoir Evaluation � 2 separate day projects� Log 1200ft to 3300ft� HILT with FMI and Sonic� Two 3ft perforations at 2100ft & 2200ft
� Well Stimulation� 3 separate fracturing day projects, 1 casing job, 1 cementing job� 70 miles each way to get to location
Drilling cont’Day
123456789
10111213141516171819202122232425
Drilling Timeline
Drill to 2000’Log to 2000’
Drill to 2600’
Drill to 3300’Log to 3300’
Stimulate at 3300’
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Drilling Cont’� Drilling and
Measurements� $895,500
� Reservoir Evaluation � $14,700
� Well Stimulation� $5,840,000
� Well Completions� $68,300
� Basis for a well� 25 day project
� Initial investment� $20.5 million
� Yearly operating cost� $8.2 million
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Production� Assumptions
� 165 scm gas per cubic meter of hydrate
� Formation behaves as a tank
� Formation is homogenous and isotropic
� No intermediate phases
� Isothermal process
� Rock expansion is negligible
� 300 m vertical fractures in 2 directions, 180° separation
� Negligible pressure gradient along fractures
� Hydrate formation is on average 70 m deep
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Production – hydrate stability
0.00
1000.00
2000.00
3000.00
4000.00
5000.00
6000.00
7000.00
8000.00
9000.00
10000.00
260 265 270 275 280 285 290
T (K)
P (kP
a)
281 K5.2 MPa
877.331
3.7657)ln( +
−=T
P ondissociati
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Free gas
Permafrost
Hydrated gas
Gas flow
P = 1600 kPa
70 m
Permafrost
P = 5200 kPa
Fracture gradient
Moving hydrate boundary
300 m
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Production cont’� Kinetics
� Dissociation is faster than diffusion under down hole conditions
� Flow through the formation is much slower� Focus on flow through formation� Linear Pressure gradient
( )∞
−
−= ffeKdt
dxeH
RT
E
s0
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Hydrated gas
P = 1600 kPaP = 5200 kPa
X
Gp
Qg
Gas flow
Gfg
PkA
Qg ∇=
X
PPC
Cdx
dPP
wfeH −=
==∇
( ) ( )wf
wfeH PX
PPxxP +
−=
eHPfg GGG =+
dt
dGQ P
g =
g
P
Q
Gt
∆=∆
eHeH VG 165=
+ℜ
=2
wfeHff
PP
TZ
VG
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Production� Rates may seem high, but an analysis of the
velocity of the hydrate boundary shows that a max velocity of 3mm/min at the beginning of dissociation, slows to 0.24 mm/min at the end of a year.
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Production cont’
1.00E+05
1.00E+06
1.00E+07
0.1 1 10 100
t (months)
Qg
(sc
m/d
ay)
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Production cont’
0.00E+00
2.00E+08
4.00E+08
6.00E+08
8.00E+08
1.00E+09
1.20E+09
1.40E+09
0.000 20.000 40.000 60.000 80.000 100.000
T (mont hs)
k = 0.003 scm/ (s m2 Mpa) k = 0.004 scm/ (s m2 Mpa) k = 0.005 scm/ (s m2 Mpa)
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Production
y = 1E+08x-0.4895
R2 = 0.9586
0.00E+00
5.00E+07
1.00E+08
1.50E+08
2.00E+08
2.50E+08
0 10 20 30 40 50 60 70 80
month
Power law model
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Production
0.0E+00
2.0E+06
4.0E+06
6.0E+06
8.0E+06
1.0E+07
1.2E+07
1.4E+07
1.6E+07
1.8E+07
0 20 40 60 80 100 120 140 160 180
month
Drill 22 wells
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Production - conclusions� Control gas production initially at 10.5 MM
scm/day
� Rate drops off to about 2.25 MM scm/day after the first month
� Expected production for the first month is 1,770,000 scm per foot of formation
� Expect to continue significant gas production for entire project.
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Production - conclusions� 22% of gas from hydrates is left down hole
� Exposing as much hydrate surface as possible is best way to produce gas
� Wells produce significant gas over an extended period
� The monthly rate is fairly accurately modeled by a power regression, this was used after the first 70 months
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� Challenges� Provide a force to push the gas through the pipe� Preventing methane and water from reforming into a
hydrate in the pipe� Excess water causing erosion damage to pipeline
� Solutions� Use Bernoulli's formula to solve for minimal compressor
power required to move gas, simulated in ProII� Remove water from gas via a dehydration station� Maintain gas above 4C to prevent refreezing
Piping
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Compressor/TEG Station
Piping
Compressor Station
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� Local Mountain Pipeline Assumptions for Calculations� 4 miles of pipe required to reach bottom of mountain� 8” pipe from well site� 12” pipe header into compressor station
� Compressor/TEG Assumptions for Calculations� Producing an average 10.5 million cubic feet of gas per day� Use Centrifugal pumps rated 6000kw and 75kWfor commercial
industry
� Pipeline Assumptions for Calculations � Roughly 50 miles from the first compressor station to LNG Plant� Temperature above 4C and pressure above 1000kPa� 36” main pipeline to the LNG Plant
Piping cont’
Compressor/TEG Station Compressor Station
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Piping cont’
Mixture
Flash drum
Flash drum
Pump HX
HX
HXAbsorber
Column &Reboiler
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� TEG Dehydration Station� $450,000
� Compressor Costs� $3.6 million for a 6000kW compressor (9 total)� $0.3 million for a 560kW compressor (6 total)� Total compressor cost = $11.5 million
� Piping Costs � $60 million for 36” pipe going 50 miles
Piping cont’
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Piping cont’
� Equipment Costs� $94 million
� Initial investment� $270 million
� Yearly operating cost
� $87 million
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Liquefaction cascade
5 °C
-159 °C
-98 °C
-34 °C
-151 °C
propane
Natural gas
ethylene
methane
LNG
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Liquefaction� Heat exchangers
� 266 at 200 m2 each (52,200 m2 required) � $14.8 million
� 4 compressors –� 53 at 6000 kW each (309 MW required)� $68.4 million
� Flash drum – $250,000� Storage tank – $12,200
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Liquefaction� 1.25 billion kg/year capacity
� $500 million investment
� $270 million yearly operating costs� $140 million per year for electricity
� $60 million for depreciation
� Taxes, insurance, repairs personnel, etc…
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Shipping� LNG will be transported from Kamchatka to
Japan via one LNG ship
� Assumptions� 8 day sea voyage one way trip
� 6 days for loading, unloading and in port maintenance operations
� 22 day round trip voyage
� 15 nm average speed of LNG ship
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Shipping cont’� Costs
� Round trip - $1.5 million
� Daily operational cost is a function of building costs, financing and operating the ship
� One LNG ships in operation will cost
$65,000 per day
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Shipping cont’� 3 Ships Costs
� $150 million each
� Initial investment� $58.1 million
� Yearly Operating Costs� $71.2 million
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� Challenges� Phase change of LNG to gas methane
� Achieve regasification with minimal power requirements
� Solutions� Use seawater as heat source
� Use propane as a medium b/w seawater and LNG to harness expansion power of a gas and generate power
Regasification
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Regasification
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Regasification cont’
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Regasification cont’
� Equipment Costs� $14 million
� Initial Investment� $84 million
� Yearly Operating Costs� $17 million
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Decisions � 1 LNG Ship
� 3.5 scm/day� TCI $690 million� Expected ROI 7% per
year� Final Cash Position of
$1.74 billion
� 2 LNG Ship� 7.0 scm/day� TCI $1.25 billion
� Expected ROI 12% per year
� Final Cash Position of $4.17 billion
� 3 LNG Ship� 10.5 scm/day� TCI $1.9 billion� Expected ROI 12% per
year� Final Cash Position of
$5.8 billion
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Regret� Regret analysis is the analysis of unrealized
profit associated with production choices
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Regret
$ 4,232.82
$ 11,154.77
$ 9,113.69
$ 3,401.06
$ (186.40)
$ (1,189.42)highest
$ 4,232.82
$ 11,154.77
$ 9,113.69
$ 3,401.06
$ (193.75)
$ (2,311.69)3 Ship
$ 2,620.50
$ 6,704.74
$ 5,952.30
$ 2,237.76
$ (186.40)
$ (1,605.89)2 Ship
$ 976.46
$ 3,220.50
$ 2,597.31
$ 732.96
$ (479.07)
$ (1,189.42)1 Ship
Averagehighesthighexpectedlowlowest
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Regret
3 ship
$ 1,122.27
minimaxregret
$ 1,122.27
$ -
$ -
$ -
$ 7.35
$ 1,122.27
3 Ship
$ 4,450.02
$ 4,450.02
$ 3,161.39
$ 1,163.30
$ -
$ 416.47
2 Ship
$ 7,934.27
$ 7,934.27
$ 6,516.38
$ 2,668.10
$ 292.67
$ -
1 Ship
Maximum regrethighesthighexpectedlowlowest
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Risk Distribution for NPW 3 ships/M51
Values in Billions
0.000
0.200
0.400
0.600
0.800
1.000
NPW Expected!M51: Mean=3.393976E+09
NPW Expected!M7: Mean=7.306009E+08
NPW Expected!M29: Mean=2.233037E+09
-1 0 1 2 3 4 5 6 7 8-1 0 1 2 3 4 5 6 7 8
5% 90% 5% .6806 5.8533
NPW Expected!M51: Mean=3.393976E+09
NPW Expected!M7: Mean=7.306009E+08
NPW Expected!M29: Mean=2.233037E+09
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� Difference in Gas vs. LNG
� FCI $404 million
� WC $480 million
� TCI $883 million
� TPC $260 million
� Gas Costs(Using 32” pipe)
� FCI $1.8 billion
� WC $798 million
� TCI $2.6 billion
� LNG Costs(Using 3 ships)
� FCI $1.3 billion
� WC $318 million
� TCI $1.7 billion
Pipeline to China vs. LNG Conversion
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$0.00
$500,000,000.00
$1,000,000,000.00
$1,500,000,000.00
$2,000,000,000.00
$2,500,000,000.00
$3,000,000,000.00
FCI WC TCI TPC
LNGGas PipelineDifference
Pipeline to China vs. LNG Conversion
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� TCI $1,700 % of TCI
� Locating $15 0.88%
� Drilling $21 1.80%
� Piping $270 19.11%
� Liquefaction $1,252 59.59%
� Delivery $58 15.70%
� Regasification $84 3.79%
Total Capital Investment ($Million)
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$0.00
$200,000,000.00
$400,000,000.00
$600,000,000.00
$800,000,000.00
$1,000,000,000.00
$1,200,000,000.00
$1,400,000,000.00
Locate Drill Pipe Lique Ship Regas
TCI
Total Capital Investment ($Million)
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Total Production Cost ($Million)
� TPC $453 % of TPC
� Drilling $8.2 1.80%
� Piping $87 19.11%
� Liquefaction $270 59.59%
� Delivery $71 15.70%
� Regasification $17 3.79%
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$0.00
$200,000,000.00
$400,000,000.00
$600,000,000.00
$800,000,000.00
$1,000,000,000.00
$1,200,000,000.00
$1,400,000,000.00
Locate Drill Pipe Lique Ship Regas
TCI
Total Production Cost ($Million)
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Value Chain
Piping
Market
$0.06/MMBtu
$2.00/MMBtu$0.53/MMBtu
$0.13/MMBtu$0.7/MMBtu
($7.00/MMBtu)
$3.36/MMBtu
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Value Chain
($3.64/MMBtu)
Profit
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Cumulative Cash Position $9 gas
$(4,000.00)
$(2,000.00)
$-
$2,000.00
$4,000.00
$6,000.00
$8,000.00
$10,000.00
$12,000.00
-1 2 5 8 11 14
time (years)
MM
$
$9.9 billion after 15 years
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Cumulative Cash Position $8 gas
$(4,000.00)
$(2,000.00)
$-
$2,000.00
$4,000.00
$6,000.00
$8,000.00
$10,000.00
-1 2 5 8 11 14
time (years)
MM
$
$7.9 billion after 15 years
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Cumulative Cash Position $7 gas
$(3,000.00)
$(2,000.00)
$(1,000.00)
$-
$1,000.00
$2,000.00
$3,000.00
$4,000.00
$5,000.00
$6,000.00
$7,000.00
-1 2 5 8 11 14
time (years)
MM
$
$5.8 billion after 15 years
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Net Present Worth� $7 gas
� Expected NPW of $3.4 billion
� 12% ROI per year
� 180% ROI over all
� $8 gas� Expected NPW of $4.5 billion
� 16% ROI per year
� 240% ROI over all
� $9 gas� Expected NPW of $3.4 billion
� 20% ROI per year
� 300% ROI over all
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Questions?
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References� Sloan, E. Dendy Jr., Clathrate Hydrates of Natural Gases, 1998
� Carroll, John J., Natural Gas Hydrates: A guide for Engineers, 2003
� Foss, Michelle Michot, Introduction to LNG, 2003
� Jung, Yonghun , Economic Feasibility of Natural Gas Pipeline Projects in the Northeast Asia, 2002
� Mandil, Claude, The Global Outlook for LNG, 2004