Pavant - PowerPoint Presentation

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Pavant

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Hot Stratigraphic Reservoirs – the Bridge between Hydrothermal Systems and Large-Scale Engineered Geothermal Systems

Rick AllisUtah Geological SurveyPresentation 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

200°CSlide2

http://www1.eere.energy.gov/geothermal/pdfs/egs_basics.pdf

From: Hydrothermal

S

ystems

(where hot fluids rise to near-surface)

To: Enhanced (or Engineered) Geothermal Systems

(

where low permeability rock is

hydrofractured

to create a reservoir)

The Holy Grail for Geothermal Power

Dixie Valley, Nevada

Still the best EGS “manual” (U.S.):

MIT 2006 report (Tester et al.)Slide3

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/MPaSlide4

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

sub-horizontal – 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?Slide5

Regional heat flow of the conterminous U.S.

(

SMU geothermal lab;

Blackwell et al., 2011)

The U.S. has

~ 10

6

km

2 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.

Gulf Coast

Colorado Rockies

Rio

Grande rift

Great Basin

Yellowstone

Snake River Plain

Cascades

Imperial ValleySlide6

Modified from

Zou

et al., 2013 ; dashed boxes are possible geothermal reservoirs

c

onventional 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?

Geothermal reservoir

Visual contrast between oil and gas reservoirs and stratigraphic geothermal reservoirsSlide7

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%.

75°C

reservoir

200°C

20% thermal efficiencySlide8

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 km

3 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)Slide9

Macondo

oil well (Gulf of Mexico)

Tauhara

geothermal well discharge test (N.Z.)

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 investmentSlide10

Source: Bruce Hicks, North Dakota Department of Mineral Resources, Oil and Gas Division

https://www.dmr.nd.gov/oilgas/presentations/WBPC2011Activity.pdf(accessed 8/15/2013)

ND expects 2000 wells per year, and > 35,000 wells over 16 years; USGS predicts high-end resource potential of 11 billion bbl.

Even at 1000

bbl

/day IP, the shale-oil wells are very profitableBut these flow rates are far too low to be of geothermal interest; and high flow rates must be sustained for 30+

yrs

Typical Bakken Well:

~ 30-year well life~ $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

Note – these are 5 – 6 km wells (horiz. legs)

(About 20 days to drill + 2 days to

frac

.)Slide11

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)

too deep = uneconomic project too cool = uneconomic project

(2011)

Bakken

wells

Scope for reduced drilling costs when grid-drilling with known geology and reservoir

Air-cooled binary power plants

200°C limit for pumpsSlide12

LCOE = 10 c/kWh

Flow = 1000 – 2000

gpm

ΔT = 0.3 – 1.0 %/yearSlide13

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 Slide14

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

).

What porosity and permeability can we expect at 3 – 4 km depth?Slide15

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)Slide16

Cross Section View - Four Reservoir Models

10 D-m

3 D-m

10 D-m

10 D-m

Transmissivity

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

Note seal thickness in sandwich

varies (1

mD

)

500 m

300 mSlide17

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)

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

300 m

10 D-m

10 D-m

10 D-m

3

D-mSlide18

200°C

150°C

c

onstant flow wells; declining temperature with timeSlide19

Bakken

shale-oil field, N. Dakota; from North Dakota Divn. of Minerals website, 10/28/2013

Low-perm unconventional shale-oil reservoir

High-perm conventional oil reservoir

4

0 acre, ¼ mile, 5-spot well pattern

(maps on similar scale)

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°CAll wells pumped; flow rates 60 – 120 L/s (30,000 – 60,000 bbl

/day; 1000 – 2000 gpm)Air-cooled binary power plant (100% injection)

Aneth

Oil field, Utah(Chidsey, 2013)

10 kmSlide20

Open-well discharge test, Tauhara project, N.Z.

Issues:

Drilling high flow-rate wells (i.e. locating high permeability

strat

. units) at 3 - 4 km depth probably the biggest challenge

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

Can seismic reflection attribute technologies be tuned/adapted to identify high permeability units at 3 – 4 km depth?

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?

Improved high-T pump design (a new turbine-style pump was unveiled at the GRC earlier this month)

We need to be thinking on 100+

MWe

-scale developments (minimum!), and GWe growth in next decade in U.S.

Need recognition that U.S. geothermal potential from basin-centered, 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.