The Future of Gas Hydrates as a Fuel Kirk Osadetz1 with contributions from the GSC Gas Hydrate Team: Scott Dallimore, Fred Wright, Michael Riedel, Roy Hyndman (Victoria); Zhuoheng Chen, Tom Brent (Calgary); Gilles Bellefleur (Ottawa); David Mosher (Dartmouth)
1CMC Research Institutes Inc., Containment and Monitoring Institute, EEEL 403, 2500 University Drive NW, Calgary, AB, T2N 1N4, T: 403.210.7108, E: [email protected]
Another version of this talk was presented as the 2014 CSPG University Outreach Lecture Dedication Edward “Ted” Irving B.A., Sc.D. May 27, 1927 - February 25, 2014
Mentor, Colleague and Friend: Geologist and Paleomagnetist.
The first to publish a convincing scientific argument for the relative and absolute displacements of the continents.
Irving, E. 1956. Palaeomagnetic and palaeoclimatological aspects of polar wandering. Geofisica pura e applicata, v. 33: pp. 23–48.
Frankl, H. R., in press, Edward Irving’s palaeomagnetic evidence for continental drift (1956). Episodes, v. 37.
PDF’s of these two papers will be with this Presentation on the CSPG website. Outline Outline
1. Who is CMC Research Institutes Inc. (aka - Carbon Management Canada)? What is the Containment and Monitoring Institute? Why we are looking at Gas Hydrates as a source or storage and fuel and why should you care?
2. Characteristics of Gas Hydrate Science and Technology.
3. Global and Canadian GH Resources.
4. Mallik Gas Hydrate Drilling Programs and Results.
5. Future GH Fuel opportunities globally and in Canada. Outline Unlocking the Resource Pyramid: If technology is the answer, what is the pathway to success? Roger’s (1962, "Diffusion of Innovations") innovation characteristics that influence adoption: • Relative Advantage: How improved an innovation is over the previous generation. • Compatibility: Compatibility of an innovation for assimilation. • Simplicity: Complexity and difficulty work against adoption. • Trialability: Facile employment facilitates adoption. • Observability: The extent that an innovation is visible to others creates reactions.
1. SAGD, A paradigm shift. Driven by Relative Advantage and Resource Opportunity. Conceived industrially, but abandoned until major public investment (AOSTRA) overcame Complexity and Trialability issues as global prices improved. 2. MHSHWs, Incremental improvements and hybridization. Driven by Relative Advantage and “Price-Distortion” in continental natural gas markets. “Shale Gas” technologies were first tried in oil plays (especially the Bakken) but were widely adopted for natural gas. 3. Gas Hydrates, Currently incremental with paradigm shift opportunities. Driven by Relative Advantage and Strategic Energy Security issues. Conceived and initiated in Canada, but momentum is passing to Asian companies. Trialability and Visibility (hostile operating environments and lack of transportation) are the major issues. 4. Tertiary Recovery/Secure Carbon Storage, Incremental with potential to double the WCSB
conventional reserves lifetime, bedeviled by Compatibility and Complexity issues related to CO2 capture, supply and transportation. Do regulators have a resource conservation responsibility? CMC Background
Carbon Management Canada (1.0) NSERC/Network of Centres of Excellence 44 research projects 155 researchers at 27 universities
Basic Scientific, Engineering and Social Science research to prepare Canadian Industry for future, sustainable carbon management.
5 CMC Background CMC Research Institues Inc. (2.0) A not for profit Canadian Corp. translating and implementing Carbon Management into Competitive and Sustainable Business Practise.
“WE’RE ALL IN THIS TOGETHER” CaMI FRS Containment and Monitoring Institute (CaMI): Field Research Station • FRS is a globally unique facility. • Containment is critical for may subsurface applications including: • Secure Carbon Storage; • SAGD steam chambers; • induced hydraulic fracturing; • induced seismicity; • water and acid gas disposal; • enhanced petroleum recovery; • groundwater protection; etc. Fluid expulsion accident initiated from a nearby well, • There is a need to better characterize Innisfail AB containment risks. • Learnings for many industries, as well as regulators and policymakers. • Computational models need better earth Web image from: “Fracking Canada” images/models. CaMI FRS CaMI: Field Research Station
FRS will provide industry, inventors and academics with a well characterized subsurface and surface technology test site, laboratory and classroom. Dr. Don Lawton, Institute Director, 403 210 6671, [email protected] CMC Website: http://cmcghg.com Gas Hydrate S&T GH Structure & Energy Content •GH is an ice-like solid (clathrate) composed of gas (guest) molecules in a cage of water (host) molecules that forms at low temperature and moderate pressure. •Like ice, GHs require energy input to dissociate, which also is the source of “self-preserving” characteristics.
•CH4 and CO2 are the common, but not the only guest molecules. •1 m3 of GH → 164 m3 of methane gas, equivalent to a dry gas reservoir at 16 Mpa, or a gas pool at 1.6 km depth. •Gas hydrate has an energy content comparable to bitumen and tar sands. Energy content in SCF/ft3 of rock: Gas Hydrate: 40 – 50 Coal Bed Methane: 8 –10 Tight/Shale gas: 5 –10 Gas Hydrate S&T Modes of Gas Hydrate Occurrence Terrestrial Sub-Permafrost Accumulations Mallik Core onshore NWT • Common in Arctic regions and identified by drilling. • Commonly part of a thermogenic petroleum system. • Thickest, richest, most accessible, potentially associated or co- located with conventional natural gas in porous and permeable reservoirs. • Preferred North American production target.
Sub-sea Marine Accumulations Hydrate Ridge offshore OR
• Common to continental shelves and slopes and detected using Bottom-Simulating-Reflections (BSR’s). • Commonly part of a biogenic petroleum system. • Typically hosted in silt and shale dominated lithofacies. • Asian production target.
Seafloor Accumulations Ice worms on GH o/c GOM
• Discrete rich seafloor outcrop accumulations. • Not well characterized. • Not persistent due to concentration effects. • Possible Korean alternate production target. Gas Hydrate S&T GH Stability Conditions
ARCTIC PERMAFROST OFFSHORE CONTINENTAL MARGIN
Metres GEOTHERMAL Metres GEOTHERMAL GRADIENT GRADIENT 0 SEDIMENT 0
200 PHASE 200 GEOTHERMAL BOUNDARY METHANE PHASE HYDRATE BOUNDARY GRADIENT 400 400
600 DEPTH OF 600 PERMAFROST 800 800 METHANE 1000 BASE OF 1000 HYDRATE E
GAS HYDRATE T A F WATER R 1200 1200 O
D SEDIMENT E GEOTHERMAL Y N H 1400 GRADIENT O
1400 S Z BASE OF A
G GAS HYDRATE 1600 1600 -20 -10 0 10 20 30 -20 -10 0 10 20 30 Temperature °C Temperature °C Gas Hydrate S&T GH Research Themes: How can you not love a geology topic that combines, ice cream, domestic heating and the 4 horsemen of the apocalypse? •Flow-assurance issues for pipeline transportation. •A potential seafloor and permafrost hazard. •A potentially commercial or strategic petroleum resource with low emissions intensity. •Secure Carbon Storage of natural or anthropogenic GHG’s (CH4 and CO2). •A potential environmental change agent (e.g. the clathrate gun hypothesis). •A natural gas transportation mechanism that is potentially cheaper than LNG (~21 shipping days).
•A new purification technology for CO2 utilization (e.g. potable water from saline water). •A model for “inclusion-based” materials science and technologies, more than just carbonated ice cream. Gas Hydrate S&T
The Calthrate Gun: GHs & Apocalyptic Climate and Geological Changes
-3 -2.5 -2 -1.5 -1 -0.5 0 0 Mallik - simultaneous occurrence 100 ka cycles of permafrost and gas hydrate -2 below 250 m -4 s u r
41 ka cycles -6 f a c
-8 e •Surface temperature forcing and conversion of a t e
-10 m
temperature p conventional gas pool to GH explains current observed GH e
-12 r a and permafrost at the Mallik site (Case 1) and the observed 0 t -14 u r e
, gap between base IBP and top GH.
-16 ° C 200 permafrost base - Case 1 •In a GH trap permafrost grows downward through GH and permafrost base - Case 2 400 the two are intermingled, but this is not observed and it m
,
h the permafrost base does not predict the observed base of either IBP or GH t observed at present p e 600 (Case 2). d gas hydrate considered only below 900 m 800 hydrate base - Case 1 in Case 1 hydrate base - Case 2 •The GH and IBP layers respond to surface temperature hydrate upper boundary Case 2 - according to forcing. Permafrost buffers GH dissociation. The “clathrate 1000 the p-T curve the real one - limited by permafrost at 250 m gun” and the role of GH in climate cycles is complicated and the gas hydrate base observed at present delayed by enthalpies of melting and dissociation. 1200 -3 -2.5 -2 -1.5 -1 -0.5 0 time, Myr From (Majorowicz, Osadetz and Safanda, 2012) CaMI FRS Secure Carbon Storage In Porous Geological Media: 61-75 Gt WCSB ~10% as CO2 GH in Alberta most near Oil Sands Operations
Storage as a Unmineable CO Hydrate; coalbeds 2 ~0.8 Gt ~6 Gt AB
Enhanced oil recovery; e.g. Weyburn, Increased reserves with reduced emissions and Depleted oil & footprint gas reservoirs Deep saline ~17-19 Gt Formations ~37-49 Gt
Storage Volumes and CO2 GH stability from from the 3rd ed. N.A. CCS Atlas and Cote and Wright, 2006 Gas Hydrate S&T Why consider Gas Hydrate Fuel? • Low Natural Gas prices are regional not global and Asian economies face supply security issues, e.g. Prior to Fukushima, Japan produced 3% of its petroleum domestically. • Marine gas hydrates impact national boundaries and territorial disputes. How does dependence on Russian gas affect European diplomacy and security? •Some countries and corporations consider longer timelines where technological “game-changers” are possible (e.g. SAGD; HD+IHF). • Japan’s “commercial” gas hydrate production accelerated Asian (China, S. Korea/Statoil, India) R&D programs. GHs provide a “technology transfer” business opportunity model. •Where will long-term supply for BC LNG come from?
•GH offer a unique combined cycle Arctic petroleum GANS Project Areas, 2006-2010; Norwegian production + secure carbon storage opportunity. Continental Margin, Barents Sea, Western Svalbard Margin (Statoil Website). Resources
1. Possibly the largest global carbon reservoir (~50% by weight), most GH resources are marine and inferred from geophysical data (Bottom Simulating Reflectors). Sub-permafrost GHs are less well constrained.
2. The resource is unevenly distributed and inferred resource volume distributions become smaller and more skewed as characterization improves.
3. Marine resources remain enormous: ~1- 5 X1015 m3. (Milkov, 2004; ESR), compared to ~10.2 - 8.8 X 1012 m3 (Osadetz and Chen, 2010, BCPG) for the Beaufort Mackenzie sub-permafrost resource.
4. Specific knowledge of large accumulations in good reservoirs is more important than global resource estimates. Resources Canadian GH Resources Amerasian Basin Margin - no estimate, but identified Arctic Archipelago (Onshore and Offshore) Mackenzie Delta (Onshore 671 to 21,886 TCF and Offshore) ~250-300 TCF Baffin-Ellesmere Margin, Mallik stable on shallow shelf and in Lancaster Sd., but no estimate
Pacific Margin, Atlantic Margin, apparently apparently rare, common, 113 but large area to 847 TCF 671 to 2,753 TCF
From Majorowicz and Osadetz, AAPG Scotian Margin, Bull. 2001; Osadetz and Chen, BCPG, restricted to outer shelf 2010
Total in-situ amount of methane in gas hydrates is estimated to be 1,553 to 28,593 TCF (0.44 to 8.1 x 1014 m3), compared to a conventional gas potential of ~953 TCF (0.27 X 1014 m3). Gas Hydrate S&T GH Production Strategies •Adaptation of available methods rather than entirely ARCTIC PERMAFROST new technologies.
Metres GEOTHERMAL •General consensus to destabilize GH in situ and Metres GEOTHERMAL GRADIENT produce natural gas,GRADIENT although some still propose 0 SEDIMENT 0 mining sea floor accumulations. 200 PHASE 200 BOUNDARY METHANE PHASE HYDRATE •PressureBOUNDARY reduction and dissociation using ambient 400 400 heat transfer is the easiest and cheapest. Only 600 DEPTH OF 600 PERMAFROST borehole pressure drops have been employed, but gas or water production are potential enhancements. 800 800 METHANE 1000 BASE OF 1000•Thermal, hot water, orHYDRATE Chemical “freezing point- E
GAS HYDRATE T A depressionF ” stimulation couldWATER work, and may enlarge R 1200 1200 O
D SEDIMENT the area ofE pressure reduction effects. GEOTHERMAL Y N H 1400 GRADIENT O
1400 S Z BASE OF A
•Guest gas displacement,G GAS CO2 HYDRATE will displace CH4 from 1600 1600 -20 -10 0 10 20 30 the lattice.-20 -10 0 10 20 30 Temperature °C Temperature °C Gas Hydrate S&T Carbon Neutral GH Power Generation? •The Ikhil conventional pool that supplies Inuvik is declining. GHs in Mackenzie Delta and Lancaster Sound could fuel northern military bases, communities and mines. •GH formation that excludes heavier hydrocarbons producing “gas drying” effect during clathration.
•Nearly pure methane is a feedstock for H2 generation to make fuel cell reactant for power and heat generation. •High temperature fuel cells like Solid Oxide or Molten Carbonate also produce much heat, a potentially useful commodity in the Arctic.
•Effluent CO2 is captured and injected into the GH reservoir to enhanced gas production.
Proof concept Torino SOFC schematic Resources Beaufort-Mackenzie Basin GH Occurrences and Characteristics (Osadetz and Chen, BCPG, 2010)
• GH occurs rarely within the Ice Bonded Permafrost (except at Taglu).
• There is commonly a gap between the base IBP and top GH.
• Rich GH usually occurs below a geological ‘seal’. The BMB GH resource • GH occurrences are occurs predominantly in a strongly associated with few wells (i.e. it is unevenly tectonic and conventional distributed like the thermogenic petroleum conventional resource). system features. Mallik Results Why work at Mallik?
1. Reduced Costs: A reasonably accessible onshore location compared to deep water Norwegian and Asian offshore occurrences. 2. Reduced Risk: 37 years of baseline engineering, geological and geophysical data and reduced project risks. 3. High Quality Occurrence: Mallik GH occurrences are thick >150 m and highly concentrated gross hydrate thickness pore space hydrate concentrations 50-85%. 4. Good Analogue: Reservoir environmental conditions are similar to those of offshore Norwegian and Asian GH occurrences. 5. Good Landowner/License holder Relationships: Positive history with NEB and OGD’s and the SDL holder (Imperial Oil). Mallik Results Mallik Highlights GSC Bulletin 544 (1999, Dallimore, Collett and Uchida) GSC Bulletin 585 (2005, Dallimore and Collett) GSC Bulletin 601 (2012, Dallimore, Yamamoto, Wright and Bellefleur) The goal at Mallik has not been production rate, but rather to characterize the GH reservoir and its production response to provide high quality data for reservoir 5 MDT depress. Tests simulation, validation and history match. and a 5 day full-scale 1972 – IOL L-38 DST pressure thermal test reduction test of GH dissociation.
1980s-90s – GSC Permafrost coring studies. Mallik 2007 1998 - 1st Canada-Japan Mallik 17 hr pressure drilling program cored + logged drawdown test the GH interval.
2002 - Canadian-led, 5-nation partnership conducts ”state of the art” gas hydrate science Mallik 2008 program and production tests.
2007-08 –Canada-Japan R&D study with successful 6 day proof of concept 6 day pressure draw down test depressurization test in March With sustained flow >2000m3/day 2007. Mallik Reservoir 2007-08 re-entered and recompleted Mallik 2L-38 (test) & 3L-38 (disposal)
BGHSZ Mallik Reservoir
Mallik GHs occupy conventional pore space
Base of GHSZ
Core
- 9 - 8 - 7 - 6 - 5 - 4 - 3 - 2 - 1 0 +1 +2 +3 +4 +5 nm µm mm m km 10x meter Mallik Reservoir
Field Scale Impedance Inversion
Field scale
- 9 - 8 - 7 - 6 - 5 - 4 - 3 - 2 - 1 0 +1 +2 +3 +4 +5 Bellefleur et al., 2005 nm µm mm m km Reservoir Models Initial Reservoir Models: Evaluating the role of a free gas “leg”
Case 1: – 50 m gas hydrate, over 10 m free gas. – Gas hydrate: 1.07 TCF of GIP (5 sq mi). – Free gas: GIP = ~ 232 BCF (5 sq mi).
Case 2: – 50 m gas hydrate, over water. – Gas hydrate: 1.07 TCF of GIP (5 sq mi).
Cases 1 and 2: Mallik-like reservoir using pressure depletion only in adapted “CMG Stars” model.
(Hancock, Okazawa and Osadetz, 2005 CSUG Meeting) Reservoir Models Initial Reservoir Models: Cumulative Production
500
Case 1 - High Kr Case 1 - Low Kr 400 Case 2 - High Kr Case 2 - Low Kr
300
Total Gas (BCF) Total 200
1.00 100 krw High krg High 0.75 krw Low krg Low
0.50 0
0 5 10 15 20 25 Relative ermeability 30 35 Time (Years) 0.25
0.00 0.00 0.25 0.50 0.75 1.00 Simulations consider high and low relative Water Saturation permeability models for gas associated with gas hydrate (red) and gas hydrate alone (blue)
(Hancock, Okazawa and Osadetz, 2005 CSUG Meeting) Reservoir Models Initial Reservoir Models: Key Results
50 GH reservoir performance depends
45 Notes: strongly on the presence or absence of Frontier Gas Royalties Included Before Income Tax 40 underlying free gas. No Incentives
35 Case 1 Gas Hydrate Over Free Gas
30 GH gas should be commercial at prices
25 comparable to that required for co-
20 located conventional gas
15
Internal Rate of Return, % % Return, of Rate Internal developments.
Case 2 10 Gas Hydrate Over Free Water 5 GH could augment frontier gas
0 supplies, and reduce environmental $6 $7 $8 $9 $10 $11 $12 $13 $14 $15 $/Mscf (footprint) impacts of Arctic Gas developments. Case 1 gas associated with gas hydrate The results remain valid, generally, (red) behaves like a standard petroleum but are augmented by new data and prospect; while Case 2 and gas hydrate models from the 2007-08 alone (blue) behaves like a utility. experiments.
(Hancock, Okazawa and Osadetz, 2005 CSUG Meeting) Mallik Reservoir 2008 Test Mallik 2L-38 Production interval 1093–1105m • Continued pressure reduction testing employed improved methods to control sand and fines production.
•Identified that efforts to suspend the well had induced GH dissociation.
•3 stage pump down to 4.5 Mpa resulting in sustained production for 6 days.
•Surface metering of produced gas and estimation of total produced gas (formation storage). Mallik Reservoir 2008 Mallik 2L-38 rates and volumes
Stage 1: Unstable flow with fluctuation 13000 flow rate during the test. Stage 1 Stage 2 Stage 3 12000 Dominated by near well bore effects. Initial gas flow to surface 11000 3m3 @ start of metering period ? )
Low water production. 3 10000 m (
d Commence gas metering e 9000 c
Stage 2: Steady but increasing flow rates u CUMULATIVE GAS d Est. Bottom Hole o 8000 r Pressure P
interpreted as stable in situ gas hydrate s
a 7000 G dissociation. -
) 6000 a
Low water production P k (
5000 e r u
s 4000 Stage 3: Step change in flow rate s e r P 3000 100 attending increased pressure reduction. INSTANTANEOUS GAS RATE Steady and increasing gas rates 2000 ) y
1000 75 a interpreted as stable in situ gas hydrate d / 3 m
0 ( dissociation e
50 t a
Low water production R Commence Ice plug at r
water metering surface WATER RATE e t 25 a •Total gas and water produced was about W
13000 m3 and 70 m3, respectively. 0 3-10-08 12:00 3-11-08 12:00 3-12-08 12:00 3-13-08 12:00 3-14-08 12:00 3-15-08 12:00 3-16-08 12:00 Date - Time •Production rates were between 1500- 2500 m3/day gas and 5-15 m3/day water.
•Gas production rate continued to rise toward the end of the test. Mallik Reservoir Reservoir Models and Issues See GSC Bulletin 601, p. 217 and p. 261 Projected rates and volumes are encouraging, while differences in reservoir models need to be resolved – indicating the need for a protracted (~12 month) test.
Boundary effect reflecting GH continuity limit
•“Successful” history matches were obtained by both Japanese and Canadian modellers using very different assumptions.
•Japanese (Kurihara) models included formation and collapse of “wormholes” and adjustments to model permeability ~6 days production structure, some depending on borehole history match pressure dynamics.
•Canadian (Uddin) models employed a pressure dependent gas evolution model similar to gas formation from heavy oil production to obtain a match. Opportunities Current and Future Global Opportunities
1. JOMEC and the Japanese program will continue with a focus on domestic marine resources, but with an interest to participate in another terrestrial long-term production test. 2. China is determined to become a leader in GH S&T. 3. Statoil is keenly interested to begin a program, perhaps onshore in Canada. 4. US Government Agencies and CONOCO/Phillips appear interested in Alaska, but BP operational issues are an impediment. 5. India-USGS are moving toward an offshore test (~$80 Million) with JOIDES Resolution soon. 6. Korea with Statoil have strong interest to conduct a domestic offshore test soon. 7. A number of other countries, especially Germany, have a scientific interest and are looking for opportunities to participate under the leadership of others. 8. There is a climate friendly, commercial, collaborative technology transfer opportunity for Canadian Industry that can maintain our S&T leadership. Opportunities Site(s) of future test(s)
Return to Mallik (onshore). – Minimized geological and engineering risks. – Imperial/Exxon must be a partner (access). – Well understood cost structure (~$50-80 Million). – Apparent lack of a free gas column to test a gas Ellef Ringnes production depressurization method. Mallik Arctic Islands Prospect (onshore). – Higher geological and engineering risks. – No legacy partners or back-ins. – Inferred free gas column to test a gas production methods. – Higher costs and contingencies (~80-100 Million?). Participation in another project (Asian offshore/Alaska). – Asian offshore settings are not suited to long tests and are more expensive. – Competition with corporate goals makes operations in Alaska difficult. Opportunities Sverdrup Basin (Arctic Archipelago): GH occurrences
1. Well logs suggest that hydrates occur within at least 57 and possible 93 of 150 wells.
2. The GHSZ is discontinuous, extending up to 2 km underneath the Islands and 1 km below sea level in deep inter-island channels.
3. GHSZ occurs in many formations including both well indurated sandstones.
4. Top of GHs occur commonly 300 to 700 m above the base of the GHSZ.
5. Gas hydrate/free gas contacts are inferred in 14 wells.
6. 23 inferred hydrate occurrences overlie conventional pools and other occurrences are on ‘dry’ structures, some exhibiting oil staining, where the top seal is inferred to have failed. Opportunities Ellef Ringnes Is. Gas Hydrate/Free Gas Prospect
0.000
0.100
0.200 Kanguk Formation (shale) 1
0.300
0.400
2 0.500 4
0.600 3 Hassel Formation 0.700 (mostly sandstone)
0.800 Christopher Formation (shale) 0.900 Imperial Oil line 50074 (1972)
17 km
1.)1 Level of the base of ice-bonded permafrost (blue) as interpreted at top of porous Hassel Formation (orange). Note: very fine-grained overlying Kanguk Formation shows no evidence of the lateral continuation of ice-bonded permafrost .
2.)2 Level of the base of gas hydrate in an intra-Hassel Formation sandstone (yellow) interpreted at amplitude decrease caused by water replacing gas hydrate downdip.
3.)3 Level of gas/water contact in sandstone near base of Hassel Formation. Interpreted at amplitude decrease and polarity reversal from water replacing free gas downdip. Note: very-fine grained Christopher Formation underlies Hassel Formation.
4.)4 Level of base free gas/gas-hydrate within a lower Hassel Formation sandstone. Interpreted as polarity reversal of reflector caused by shale on gas sand (negative) changing to shale on gas hydrate sand (positive). Opportunities Ellef Ringnes Is. Gas Hydrate/Free Gas Prospect
•Seismic attributes of the Svedrup Basin 0 onshore prospect are consistent with the inferred depth of GH stability. 200 •The hosting formation is well indurated and sand production problems should be 400 minimized. base of ice-bonded PF 470 m 1 e 1 r (.165 sec x 2850 m/sec) u
s methane hydrate s
e 600 stability curve r
•The site is “greenfields” and there would p (Holden 1987)
c i t be no “back-in” from an SDL lease-holder. a t s o r
d 800 inferred geothermal y
h gradient
• Additional costs related to seismic l a
m base of methane hydrate stability 930 m 2 characterization and infrastructure would r
o (.300 sec x 3100 m/sec) n
1000 be incurred. t a
s r e t e m •Initial staging to Ellef Ringnes Island 1200 n i
h
could be done by reliable sea lift. t p e D base ice-bonded permafrost •Activities occur in Nunavut. 1400 (assumed at approximately -2 degrees) Consultation will be required, but the area has less landuse competition and 1600 -20 -10 0 10 20 30 there could be leverage or public support Degrees Celsius for economic development. Conclusions Conclusions
1. The GH resource is a very large, potentially commercial resource, but it is diverse and unevenly distributed.
2. GH research proceeds internationally, especially with Asian and Norwegian interest.
3. Currently onshore sub-permafrost GH accumulations, like we have in Canada, represent the most efficient S&T development and demonstration opportunities.
4. The Mallik projects successfully demonstrates “proof of concept” for the depressurization production, especially if there is an associated free gas “leg”. A return to Mallik represents the “easiest” opportunity to advance GH production technology, but a new prospect om Sverdrup Basin represents an alternative opportunity to advance commercial production, including production with a free gas “leg”.
5. A collaborative consortium approach presents a pre-competitive business opportunity for technological leadership with reduced risks and costs.
6. CMC Research Institutes Inc. is potential altruistic partner available to facilitate Canadian opportunities for Industrial Carbon Management, Subsurface Containment and Conformance and GH formation and production testing.