Carbon Dioxide Flooding in Wyoming Reservoirs

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Carbon Dioxide Flooding in Wyoming Reservoirs

• Brian F. Towler
• Enhanced Oil Recovery Institute

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Minimum Miscibility Pressure
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Minimum Miscibility Pressure in Hall-Gurney LKC
Tertiary Oil Recovery Project
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Overall Objective

• Verify technical and economic viability of the
  application of CO2 miscible flooding to Wyoming
  fields
• Critical element Demonstrate sufficient field
  performance(oil in the tank) to justify the
  development of a carbon dioxide pipeline into
  Central Powder River Basin

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Lease Scale Economic Variables-CO2 Flooding
CO2 cost 1/mcf Oil price 20/bbl Capital
cost 4,000,000/sec CO2 utilization 5/10
mcf/bbl (net/gross) Recovery 30 Primary
Secondary Operations 400-600M/yr/sec NRI
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Kansas Geological Survey
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CO2 Costs vs. Oil Price for 20 IRR
Base Case 20/bbl Oil 1.00/mcf CO2 12 OOIP
Kansas Geological Survey
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Sensitivity to Oil Price
Base Case 20/bbl Oil 1.00/mcf CO2 12 OOIP
Kansas Geological Survey
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Required Recovery for 20 IRR
20 Oil Recovery Required 2,500 gross
BO/acre Recovery Factor Resource Threshold 30
PS 8,500 BO/acre 25 PS 10,200 BO/acre 25
Oil Recovery Required 1,650 gross
BO/acre Recovery Factor Resource Threshold 30
PS 5,500 BO/acre 25 PS 6,600 BO/acre
Kansas Geological Survey
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Project Economics

• Total Project 5.4 million
• 2.0M CO2 Purchase, transport, recycling
• 1.5M Research, Technology Transfer
• 1.1M Capital Costs (wells, etc.)
• 0.8M Operations (6 years)
• Funding
• 2.4M Kinder-Morgan CO2 Co. LP and Murfin
  Drilling Company
• 1.9M U.S. Department of Energy
• 1.0M KGS and TORP
• 0.1M Kansas Department of Commerce

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Demonstration Design Summary

• 55 acre, nine-spot
• 2 CO2 injectors
• 7 Producers
• 5 Containment Water Injectors
• 0.843 BCF CO2 injected-WAG
• 4.6 year operating life
• gt80,000 BO estimated recovery during DOE
• gt20,000 BO in 3 years after DOE Project

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Pipeline Cost Estimates

• Distance is 220 miles to Hall-Gurney
• Other LKC areas would require 110 miles of
  lateral lines
• Pipeline cost is 22,000/inch-mile
• Ten year amortization of capital cost at 10
  based on 80 of line capacity

William Flanders, Transpetco Engineering
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Pipeline Considerations

• CO2 oil recovered is 25 of Primary and
  Secondary, usually it is higher than this
• Net CO2 required is 4 mcf/BO

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William Flanders
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Tertiary Flood (CO2 Injection)

• Used residual oil saturation distribution at end
  of secondary
• Used Compositional Model to simulate performance
• Developed PVT behavior of reservoir oil
• Simulated performance with injection wells in
  different pattern locations

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Injection Sequence

• 2-4 months of pressure buildup
• 2 month Water-Alternating-Gas (WAG) injection
  cycle
• 3 years of WAG
• 2 years of post-CO2 waterflood

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Summary of Model Performance
Model T22 Model T18
Model T20 CO2 Injection wells NEWCO2N
NEWCO2N NEWCO2S
Colliver 18 NEWCO2S
Colliver 18 Cumulative Injection Total
CO2, MMSCF 599.5 763.57
606.91 Cumulative Production Oil, MSTB
77 70
62 CO2 end year 3, MMSCF 143 310
267 CO2 end year 5, MMSCF 317
493 422 Recovery ( OOIP)
7.56 6.87 6.08 Utilization
Factors Gross (MMSCF/STB) 7.8
10.9 9.8 Net (MMSCF/STB)
5.9 6.5 5.5
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Assessment of Hartzog Draw Field

• Hartzog Draw is located in the central Powder
  River Basin
• 40 miles NNE of Salt Creek field.
• Discovered in 1975
• Produces from the Shannon sandstone at depths
  between 9000-10000 feet.
• 350 MMSTB of oil initially in place
• initial pressure of 5000 psia.

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• The maximum primary production was in March 1978
  at 35,194 STB/day.
• A water flood pilot began in 1981 shortly before
  the reservoir pressure had dropped to 1000 psia
  and primary production had fallen to 6182 STB/day
  (in July 1982).
• The waterflood response commenced in September
  1983 and production peaked again in March 1987 at
  18,973 STB/day.

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• Infill drilling and polymer injection from 1996
  to 1999 temporarily arrested the decline but by
  March 2004 the production had again declined to
  3616 STB/day with a water-oil ratio of 0.692
  BW/BO.

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• As of June 2004 there are 211 producers and 143
  injectors completed in an approximate forty acre
  line drive pattern.
• To March 2004 108,212,683 STB of oil has been
  produced representing about 31 of the original
  oil in place.
• Decline curve analysis indicates that at the
  field abandonment rate of 500 STB/day the
  ultimate primary and secondary recovery will be
  126.7 MMSTB representing a recovery factor of
  36.2.

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• Using decline curve analysis 36.0 MMSTB (10.3)
  are primary reserves and 90.7 MMSTB (25.9) are
  secondary reserves.
• This leaves 213.3 MMSTB still in place to be
  recovered and, of this, it is estimated that
  50-100 MMSTB can be recovered by CO2 flooding.
• Screening indicates that this field is well
  suited to CO2 flooding. Its depth, oil gravity,
  and response to waterflood are all conducive to a
  positive carbon dioxide flood.
• At this time there are 212 producers and 143
  injectors as well as 28 dormant wells in the
  field.

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• There are numerous cretaceous fields that would
  be similar candidates for CO2 flooding
• There are also numerous Minnelusa fields that
  would also be good candidates

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• Fields need to be assessed using lab MMP data and
  simulation
• Full field compositional simulation studies need
  to be carried out
• Preliminary assessment can also be done with
  simple models such as the DOEs CO2 Prophet