User:Work permit/sandbox/oil shale

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Processes[edit]

ex-situ Preliminary operations Mining Transport Crushing Retort - Electricity - Oil - Gas - Char - Waste heat Upgrading Refining

in-situ Preliminary operations Drilling Pumping Freeze wall Misc. Retorting - Oil - Gas Reclamation Refining

Yield[edit]

Cost escalation[edit]

Nelson-Farrar refinery construction cost indexe [1]

Exxon/TOSCO Colony Shale Oil project cost estimates run in 1980 initial budget was around $2.5-$3.0 billion. The project was shut down in May 1982, cost estimates had risen to almost $10 billion. Among problems, above ground retorting process sited on top of a remote mesa at about 10,000 ft altitude.

Water usage[edit]

Development of oil shale resources will require significant quantities of water for mine and plant operations, reclamation, supporting infrastructure, and associated economic growth. In 1980, the US Office of strategic assessment estimated water requirements estimates of 2.3 to 5.7 barrels of water per barrel of oil.[1] More current estimates based on updated oil shale industry water budgets suggest that requirements for new retorting methods will be 1 to 3 barrels of water per barrel of oil.[2] For an oil shale industry producing 2.5 MMBbl/d, this equates to between 105 and 315 million gallons of water per day. These numbers include water requirements for power generation for in-situ heating processes, retorting, refining, reclamation, dust control and on-site worker demands. Municipal and other water requirements related to population growth associated with industry development will require an additional 58 million gallons per day. Hence, a 2.5 MMBbl/d oil shale industry would require 180 thousand to 420 thousand acre feet of water per year, depending on location and processes used. [3]


The largest deposit of oil shale in the United States is in the Green River basin. Though scare, water in the western United States is treated as a commodity which can be bought and sold in a competitive market.[3] Royal Dutch Shell has been reported to be buying groundwater rights in Colorado as it prepares to drill for oil in the shale deposits there. [4] In the Colorado Big-Thompson project, average prices per share (0.7 acre feet/share) increased from some $2,000 in 1990 to more than $12,000 in mid-2003 (constant 2001 dollars).[5] CBT Prices from 2001 to 2006 has had a range of $10,000 to $14,000 per share, or $14,000 to $20,000 per acre foot. [6] In August 2009 asking prices in utah ranged from $1,000-$10,000/AF [7]. At $10,000 per acre foot, capital costs for water rights to produce 2.5m bbls/day would range between $1.8 bn-$4.2 bn.

Carbon emmision[edit]

ATP Process[edit]

For comparison, typical full-fuel cycle emissions for final liquid fuels derived from conventional petroleum are around 25 gCeq./MJ of FFD, while emissions from Alberta tar sands operations are between 30 and 36 gCeq./MJ of FFD, and emissions from synthetic fuels produced from coal are between 42 and 49 gCeq/MJ.


If we produce, refine, and combust fuel equal to 10% of 2005 US gasoline consumption (3.3 ×108 bbl/y, or 1.8 ×1018 J [19]) from oil shale instead of conventional oil, full-fuel cycle emissions increase from about 45 million tonnes of carbon to between 68 and 74 million tonnes of carbon. This is a rough increase of 20 to 30 million tonnes. roughly 0.1tonne carbon/barrel of oil. The [2]

EUA cost roughly EUR 20-30 ($30-$40) / tonne of CO2.[3] [4] tonnes of carbon = 3.62 x tonnes of c02, so roughly $100-$150/tonne carbon. ATP carbon therefore roughly $10-$15/bbl

Shell In-Situ Process[edit]

etimates is roughly 27.1-36.4 gCeq./MJ, comparable to alberta tar sands.

' Low High
case case
Preliminary operations 0 0
Drilling 0 0.1
Pumping 0 0
Freeze wall 0.3 1.2
Misc. 0.2 0.2
Retorting 4.7 12.2
Reclamation 0.2 0.5
Refining 2.3 2.5
Totala 7.7 16.7

[5]

EROI[edit]

must take into account EROEI in because the increased cost of oil,or energy generally, will raise the cost of extracting oil from shale oil. "burro will always chase after that carrot"

Preliminary operations 0 0 0 ' 0 0 0 0
Drilling 0 0 0
Mining 0.05 0.1 0.05 0.15
Pumping 0 0 0
Freeze wall 0.02 0.05 0.02
Misc. 0.01 0.01 0.01
Retorting 0.31 0.53 0.21 0.21 0.25 0.18 0.27
Reclamation 0.01 0.02 0.01
Upgrading 0.02 0.02 0.02 0.02
Refining 0.11 0.12 0.11 0.12 0.13 0.12 0.14
Totala 0.46 0.73 0.36 0.41 0.52 0.36 0.59
Preliminary operations 0% 0% 0% ' 0% 0% 0% 0%
Drilling 0% 0% 0%
Mining 5% 10% 5% 15%
Pumping 0% 0% 0%
Freeze wall 2% 5% 2%
Misc. 1% 1% 1%
Retorting 31% 53% 21% 21% 25% 18% 27%
Reclamation 1% 2% 1%
Upgrading 2% 2% 2% 2%
Refining 11% 12% 11% 12% 13% 12% 14%
Totala 46% 73% 36% 41% 52% 36% 59%

Social/Politic Risks[edit]

In 1978, the RAND Corp. estimated that the direct costs of pollution control technologies for oil shale developers ranged between 6.5 and 15 percent of total capital costs. These were primarily for eliminating hydrocarbons, particulate, and hydrogen sulfide from the retorting process, and for dust control and spent shale disposal. By assuming a zero value for environmental costs in 1971, RAND goes on to estimate that between 8 and 20 percent of the increases in estimated capital costs or $65 million to $165 million between 1971 and 1978 were caused by environmental factors. These estimates do not include the possible indirect environmental costs that might occur because of: necessary siting changes, alterations of mining plans, disruption of construction schedules, less efficient facility operation, and costs of potential litigation. Each of the above can have enormous impacts on plant economics; delays occurring late in the construction stage are particularly costly. A 6-month delay in the middle of construction could add more than $100 million to costs.

High efficient shale oil recovery[edit]

MININGMINING RULE OF THUMB IS $10 / TON UNDERGROUND vs$1 / TON FOR SURFACEBY http://www-acerc.byu.edu/News/Conference/2008/Presentations/Carlos%20Adams.pdf

some references I plan to use on oil shale economics. I put them here as I read them. will categorize later.

Some operating plants[edit]

[6]

Overviews[edit]


references[edit]

  1. ^ Office of Technology Assessment (1980). An Assessment of Oil Shale Technologies. Office of Technology Assessment.  Unknown parameter |month= ignored (help)
  2. ^ >U.S. DEPARTMENT OF ENERGY (2006). Energy Demands on Water Resources (PDF). U.S. DEPARTMENT OF ENERGY.  Unknown parameter |month= ignored (help)
  3. ^ a b "Fact Sheet: Oil Shale Water Resources" (PDF). DOE Office of Petroleum Reserves – Strategic Unconventional Fuels. Retrieved 2008-08-29. 
  4. ^ Berfield, Susan (June 12), "There Will Be Water", Business Week  Check date values in: |date=, |year= / |date= mismatch (help)
  5. ^ Adams, Adams (April), "The Sale And Leasing Of Water Rights In Western States: An Update To Mid-2003" (PDF), North Georgia Water Planning and Policy Center, p. 10  Check date values in: |date=, |year= / |date= mismatch (help)
  6. ^ Smith, Rodney (April), "WATER MARKET INDICATORS" (PDF), WATER STRATEGIST, pp. 10–12  Check date values in: |date=, |year= / |date= mismatch (help)
  7. ^ "Utah Water Right Exchange". 

other backgrounds[edit]

Strategic Significance of America’s Oil Shale Resource