Presentation on theme: "Pavant Butte well Blackrock well Cominco well Basement PC Tm Tv Tpl Qal Tr Jn PC Tpl PCt PC Qv Tm PCt Cu PCt Cu M Pk PCt Tm PCmc PCpg Sevier Lake Federal."— Presentation transcript:
Pavant Butte well Blackrock well Cominco well Basement PC Tm Tv Tpl Qal Tr Jn PC Tpl PCt PC Qv Tm PCt Cu PCt Cu M Pk PCt Tm PCmc PCpg Sevier Lake Federal Hot Stratigraphic Reservoirs – the Bridge between Hydrothermal Systems and Large- Scale 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 200°C
http://www1.eere.energy.gov/geothermal/pdfs/egs_basics.pdf From: Hydrothermal Systems (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.)
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 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?
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/m 2 ) 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 Valley
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? Geothermal reservoir Visual contrast between oil and gas reservoirs and stratigraphic geothermal reservoirs
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 efficiency
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 km 3 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 km 3 volume (i.e. 30 km 2 footprint with 300 m thick reservoir; this is small area on a basin scale)
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 investment
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) 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 profitable But 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.)
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 pumps
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
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?
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 10 D-m 3 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 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) 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 3 D-m
200°C 150°C constant flow wells; declining temperature with time
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 40 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°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) Aneth Oil field, Utah (Chidsey, 2013) 10 km
Open-well discharge test, Tauhara project, N.Z. Issues: 1.Drilling high flow-rate wells (i.e. locating high permeability strat. units) at 3 - 4 km depth probably the biggest challenge 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 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.