Hot Stratigraphic Reservoirs – the Bridge
between Hydrothermal Systems and LargeScale Engineered Geothermal Systems
Rick Allis
Utah Geological Survey
Presentation for GSA Penrose Conference
“Predicting and Detecting Natural and Induced Flow Paths for
Geothermal Fluids in Deep Sedimentary Basins”
Newpark Hotel, Park City, October 19-23, 2013
Blackrock
well
Sevier Lake
Federal
PCt
PC
Tm
PCmc
M
Pavant Butte
well
Cominco
well
Cu
Tr
Pk
Jn
Qv
Qal
Cu
PCt
PC
Tv
Tm
Tpl
Tpl
Tm
Cu
PCt
PCt
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PCt
PCpg
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Basement
From: Hydrothermal Systems
(where hot fluids rise to near-surface)
The Holy Grail for
Geothermal Power
To: Enhanced (or Engineered)
Geothermal Systems
(where low permeability rock is
hydrofractured to create a reservoir)
Dixie Valley, Nevada
http://www1.eere.energy.gov/geothermal/pdfs/egs_basics.pdf
Still the best EGS “manual” (U.S.):
MIT 2006 report (Tester et al.)
The Challenges:
•
We know the resource potential is
immense (100s of GWe); we need 100
MWe power plants!
•
Geothermal power in the U.S. remains
on a 3 GWe “plateau”, whereas wind
and solar are growing at ~ 10%/year
•
EGS has proved difficult to scale up
from 1 MWe (single fracture) to 100
MWe (fracture network)
Recent stimulation
tests from Altarock
Energy Newberry site
(Cladouhos et al.,
2013).
Good wells have
injectivities of
50 – 100+
L/s/MPa
If we want geothermal power
here to grow more rapidly
(100+ MWe developments
within next decade) maybe we
should be looking for naturally
permeable reservoirs, such as
deep hot strata renown for their
high permeability.
Perhaps use hydrofracturing
(EGS) technologies to improve
permeability in some less
permeability sections of
production wells.
These reservoirs will be subhorizontal – they have been
geothermal targets overseas for
decades (e.g. Paris Basin)
Goal: can we find hot stratigraphic reservoirs (outside of Imperial Valley)
How hot? How permeable? What is maximum economic depth? What will
the production-injection borefield look like?
Regional heat flow of the conterminous U.S.
(SMU geothermal lab; Blackwell et al., 2011)
Cascades
Yellowstone
Snake River
Plain
Great Basin
Colorado
Rockies
Imperial Valley
Rio Grande
rift
Gulf Coast
The U.S. has ~ 106 km2 of high heat flow terrain (> 80 mW/m2) and a major fraction of
this is in form of basins with potential for stratigraphic reservoirs where the
temperatures are ~ 200°C @ 3 – 4 km. Stars identify proven sedimentary reservoir
units and the required temperatures – more to be found.
Visual contrast between oil and gas reservoirs and stratigraphic geothermal reservoirs
Modified from Zou et al., 2013 ; dashed boxes are possible geothermal reservoirs
• conventional oil and gas = restricted to traps/pools (reservoirs have good permeability)
• unconventional o & g = distributed throughout the source rock (large volume; poor
permeability, so need horizontal wells and hydrofracturing)
• stratigraphic geothermal reservoirs = distributed throughout the rock (large volume, but
need excellent permeability)
• The key – can we find excellent stratigraphic permeability at sufficient temperature?
How much reservoir volume do you need to sustain a 100 MWe
geothermal power plant for 30 years?
Assume 200°C initial temperature, 75°C injection temperature, and
the heat to power conversion efficiency for the power plant is 20%.
20% thermal
efficiency
200°C
reservoir
75°C
Answer: it depends on the HEAT SWEEP EFFICIENCY
It is unrealistic to assume all the heat in this volume gets swept by the flow (always
short circuits, and tight zones)
Muffler (1979) USGS Circular 790 assumed 25% heat recovery;
Grant and Garg, (2012) and Garg and Combs (2010) have pointed out that
naturally fractured reservoirs appear to have heat recovery factors of 5 – 15%,
and for some EGS projects the heat recovery decreases to a few percent.
If assume 10% sweep efficiency in fractured/permeable
reservoir, then the required reservoir volume for a 100 MWe
plant is 16 km3
Are EGS techniques going to be able to create 16 km3
reservoirs within the next decade, and if so, at what cost?
If a stratigraphic reservoir has naturally high permeability (10
Darcy-meters, = 100 mD over cumulative “pay” of 100 m), then maybe 20%
achievable = ~ 10 km3 volume (i.e. 30 km2 footprint with 300 m
thick reservoir; this is small area on a basin scale)
We need 5 – 10 MWe wells: these have high flowrates!
What does 300 t/h, 100 L/s, 50,000 bbl/day, 1600 gpm
look like?
$5 mill./day oil value
(40 MJ/kg enthalpy)
$25k/day power value
(1 MJ/kg enthalpy)
Reality Check:
The low value of geothermal production limits
exploration and development investment
Tauhara geothermal well discharge test (N.Z.)
Macondo oil well (Gulf of Mexico)
Even at 1000 bbl/day
IP, the shale-oil wells
are very profitable
But these flow rates
are far too low to be
of geothermal
interest; and high
flow rates must be
sustained for 30+ yrs
ND expects 2000 wells per year, and > 35,000
wells over 16 years; USGS predicts high-end
resource potential of 11 billion bbl.
Note – these are 5 – 6 km wells (horiz. legs)
Source: Bruce Hicks, North Dakota Department of
Mineral Resources, Oil and Gas Division
https://www.dmr.nd.gov/oilgas/presentations/WBP
C2011Activity.pdf
(accessed 8/15/2013)
Typical Bakken Well:
•
•
•
•
•
•
(About 20 days to
~ 30-year well life
drill + 2 days to
frac.)
~ $500,000 bbl oil
~ $9 million to drill and complete
$20 million net profit
$11 million in taxes and royalties
$4 million in wages and op. expenses
Geothermal projects need production and injection wells, with injection water returning
to reservoir to sustain reservoir pressure (and not consume precious water);
Some Realities: The reservoir depth is very important part of the economic viability of a
project; our work indicates depth must be less than about 4 km.
And power plant conversion efficiency drops by factor of 3 as production temperatures
decline from 200°C to 100°C (3 x more mass per MWe needed); our work indicates
initial reservoir temperature must be > 175°C (for LCOE = ~ 10c/kWh)
Cost of Well ($ million)
0
2
4
6
8
10
12
Air-cooled binary power plants
1,000
Drilling Costs
(2011)
Well Depth (m)
2,000
200°C
limit for
pumps
3,000
4,000
- 20%
standard
+ 20%
5,000
Bakken wells
too deep = uneconomic project
Scope for reduced drilling
costs when grid-drilling with
known geology and reservoir
too cool = uneconomic project
LCOE = 10 c/kWh
Flow = 1000 – 2000 gpm
ΔT = 0.3 – 1.0 %/year
Another reality check: Is the energy in the pore water or the rock matrix?
Answer – largely in
the rock matrix, but
we need the flow
between injector
and producer to
sweep the heat;
Therefore,
dispersed flow is
essential for good
heat recovery
What porosity and
permeability can we expect
at 3 – 4 km depth?
Global trends in reservoir
porosity with depth (upper
graph) and porosity vs.
permeability (lower graph),
modified from Ehrenberg
and Nadeau, (2005).
Colored ellipses highlight
the approximate distribution
of above average porosity
within the 3 – 4 depth range,
and the equivalent
distributions in poro-perm
space.
The black dashed line in the
upper graph is the porosity
trend in a moderate heat
flow basin (35°C/km) from
offshore Norway (with
siliciclastics).
Perhaps our biggest
challenge: can we find ~ 100
mD permeability over 100 m
thickness at 3 – 4 km depth,
and at ~ 200°C?
Compilation of permeability
measurements in oil
exploration and groundwater
databases from the Great
Basin and Rocky Mountains
regions (Kirby, 2012).
Mean permeability of
carbonates between 3 – 5 km
is 75 mD; siliciclastics = 30
mD.
Lower mean siliciclastic
permeability compared to
Nadeau and Ehrenberg
compilation is attributed to
thermal effects (diagenesis)
Cross Section View - Four Reservoir Models
0
100 200 300 400 500 600 700 800 900 1,0001,1001,2001,300
100 200 300 400 500 600 700 800 900 1,0001,1001,2001,300
Transmissivity
-600 -500 -400 -300 -200 -100
0
0.00
655.00
0.00
200.00
1310.00 feet
0
0
100 200 300 400 500 600 700 800 900 1,0001,1001,2001,300
Note seal
thickness in
sandwich
varies (1 mD)
300 m
Injector 1
Date: Producer
9/12/20122
Scale: 1:10271
Z/X: 1.00:1
Axis Units: m
100
90
80
70
60
51
41
31
21
11
400.00 meters
1,200 1,100 1,000 900 800 700 600 500 400 300 200 100
0
Injector 1
0
Producer 2
1,200 1,100 1,000 900 800 700 600 500 400 300 200 100
Injector 1
-100
-100
-600 -500 -400 -300
Geothermal Sedimentar
Geothermal Sedimentary Basin Geothermal Sedimentary Basin
Permeability
I (md) 0.00 da
Permeability J (md)
0.00 day
J
layer:
1
Permeability I (md) 0.00 day J layer: 1
File: sandwich
model final.irf
100 200 300File:
400single
500layer
600m
-200 -100 0 100 200 300
800 900
-600 400
-500 500
-400 600
-300 700
-200 -100
0 1,0001,100
100 200
400-500
500-400
600-300
700-200
800-100
900 01,0001,100
500300
m-600
User: roehner
User: roehner
Produc
Date: 9/12/2012
Scale: 1:10271
Z/X: 1.00:1
Axis Units: m
0.00
655.00
1310.00 feet
0.00
200.00
400.00 meters
100
90
80
70
60
51
41
31
21
11
1
1
-600 400
-500 500
-400 600
-300 700
-200 -100
0 1,0001,100
100 200 300-600
400-500
500-400
600-300
700-200
800-100
900 01,0001,100
100 200 300 400 500 600
100 200 300
800 900
10 D-m
Sandwich (red = 100 mD units)
3 D-m
Low Perm (30 mD units)
Single Layer (red = 100 mD)
10 D-m
Short Circuit (red = 300 mD;
Light blue = 33 mD)
Low Temp (100 mD units; 150°C)
Initial Conditions: Mid-depth (3 km) T for all except Low-T models = 200°C
Pumped producers and injectors @ 1000 gpm (63 L/s; 32,000 bbl/day)
Fluid cooled to 75°C in air-cooled binary power plant
10 D-m
10 D-m
10 D-m
10 D-m
After 30 years, the thermal pattern
between injectors and producers is as
shown. The low perm. reservoir with
the 3 Darcy-meter reservoir
transmissivity had the best thermal
response (but greatest pressure
drawdown). The single layer 100 m
of 100 mD for 10 D-m) has greatest
thermal breakthrough
Insights:
• there is good high permeability
(dispersed) and there is poor
high permeability (localized)
3 D-m
300 m
• Low permeability doesn’t mean
low heat recovery: thermal
conduction length for 30 y = ~
50 m
• i.e. we can sweep heat from
reservoir - seal units on 100 m
characteristic thickness
12
constant flow wells; declining temperature with time
Sandwich (10 D-m)
Single Layer (10 D-m)
200°C
10
Low Temperature (10 D-m)
Low Permeability (3 D-m)
Power Density (MWe/km2)
Short Circuit (10 D-m)
8
6
150°C
4
2
0
0
5
10
15
20
25
Years
30
35
40
45
50
High-perm
conventional oil
reservoir
40 acre, ¼
mile, 5-spot
well pattern
(maps on similar scale)
Low-perm
unconventional shaleoil reservoir
Aneth Oil field,
Utah
(Chidsey, 2013)
What will the future basin-centered, stratigraphic
geothermal development look like (100+ MWe)?
• 5-spot, injector-producer spacing @ 500 m (4
wells per sq km; 10 wells/sq mile)
• Sub-horizontal, reservoir-seal units with 30 –
100 mD permeability units and 3 – 10 D-m
cumulative “pay” transmissivity
• Well depths 3 – 4 km; temps. ~ 175-200°C
• All wells pumped; flow rates 60 – 120 L/s
(30,000 – 60,000 bbl/day; 1000 – 2000 gpm)
• Air-cooled binary power plant (100% injection)
10 km
Bakken shale-oil field, N. Dakota; from North
Dakota Divn. of Minerals website, 10/28/2013
Issues:
1. Drilling high flow-rate wells (i.e. locating high permeability
strat. units) at 3 - 4 km depth probably the biggest challenge
Open-well discharge test, Tauhara project, N.Z.
2.
Close behind this is optimizing the heat sweep through the
reservoir – the wellfield strategy has to ensure dispersed
fluid flow (horizontal producers and vertical injectors?) but
not short-circuits
3.
Can seismic reflection attribute technologies be
tuned/adapted to identify high permeability units at 3 – 4
km depth?
4.
Better understanding of diagenesis effects on reservoir
quality at 150 – 200°C, and likely pore fluid chemistry
(transition zone between oil reservoir and geothermal
reservoir research). Are carbonates the ideal reservoir?
5.
Improved high-T pump design (a new turbine-style pump
was unveiled at the GRC earlier this month)
6.
We need to be thinking on 100+ MWe-scale developments
(minimum!), and GWe growth in next decade in U.S.
7.
Need recognition that U.S. geothermal potential from basincentered, stratigraphic reservoirs is immense (GWe), and
more attainable target than EGS reservoir creation – i.e.
regain recognition from the energy development industry,
and agencies like the EIA, that geothermal CAN play a major
role along with wind and solar.