Tertiary Oil Recovery Project Advisory Board Meeting

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Tertiary Oil Recovery Project Advisory Board
Meeting

• CO2 Project Field Activities

University of Kansas Burge Union October 19,
2001 Rich Pancake
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CO2 Project Field Activities

• CO2 1 Well Work
• Colliver 7 Well Work
• Planned Colliver 10 Well Work
• Preliminary CO2 Facilities Design
• Arbuckle Efforts
• Ethanol Plant Construction

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Colliver 7
CO2 1
Colliver 10
Courtesy of the Kansas Geological Survey
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CO2 1 Well Work

• Drilled Well Sept. Oct. 2000
• Discussed at last years Board Meeting
• Ran CBL October 2000
• Excellent bond
• TOC 1590
• Completed Well Dec. 2000 Jan. 2001
• Perfed well 2891-99
• No stimulation
• IPd at 0.83 BOPD 82 BWPD
• Stabilized at 0.8 BOPD 39 BWPD

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CO2 1 Well Work

• Pump Stuck Jan. Feb. 2001
• Pump scaled up 2 weeks after putting on
• Reran, stabilized at 0.2 BOPD 8.5 BWPD
• Build-up Test 1 April 2001
• Wanted to determine LKC C kh skin
• Conducted 91-hour build-up test using Echometer
  (4/12 to 4/16)
• Well remained SI, measured static FLs 5/11,
  5/24, 6/8, 6/27 (1825 hrs SI)
• 809 psia reservoir pressure
• Difficult well to interpret
• tight matrix rock (2 md), no skin

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TORPs remote fired Echometer gun used for the
1st build-up test on CO2 1
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TORPs Echometer equipment and laptop used for
the 1st build-up test on CO2 1
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CO2 1 Well Work

• Acidized Well July 2001
• Attempted to use PPI tool tool malfunctioned
• 1st acid job, slow matrix stimulation
• Occurred as a result of failed PPI tool
• 400 gals 15 NE
• Surface pressure did not exceed 200 psig
• 0.2 BPM rate
• 2nd acid job, slow matrix stimulation
• 1000 gals 15 NE
• Surface pressure did not exceed 200 psig
• 0.5 BPM rate
• Prod. stabilized at /- 6 BOPD /- 110 BWPD

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X-pert Service Tools PPI Tool (Pin Point
Injection) being RIH prior to CO2 1 acid job
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Oilmans Acid, Inc. on location for CO2 1 acid job
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CO2 1 Well Work

• Build-up Test 2 Aug. Sept. 2001
• Wanted to verify LKC C kh skin
• Conducted 237-hour build-up test using Echometer
  (8/30 to 9/9)
• Well remained SI, measured static FLs 9/14,
  9/21, 9/28, 10/11 (1001 hrs SI)
• /- 800 psia reservoir pressure
• Still difficult well to interpret
• Non-radial flow
• Multiple layer
• no skin

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Comparison of Build-up Tests
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TORPs Echometer setup used for the 2nd build-up
test on CO2 1
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Colliver 7 Well Work

• Ran Tracer Survey September 2001
• Needed to determine if a cement plug between LKC
  C G held
• (whether C G communicating)
• First had to knock out a CIBP separating LKC from
  upper zones
• Set packer and tubing at 7 casing shoe (2893)
• Ran tracer survey

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Colliver 7 Well configuration as of 1989
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Colliver 7 Current Well Configuration (2001)
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Colliver 7 Current Well Configuration
(2001) Showing Lansing Stratigraphy
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Colliver 7 Well Work

• Ran Tracer Survey September 2001
• Needed to determine if a cement plug between LKC
  C G held
• (whether C G communicating)
• First had to knock out a CIBP separating LKC from
  upper zones
• Set packer and tubing at 7 casing shoe (2893)
• Ran tracer survey
• LKC A B did not communicate w/ C
• LKC G did not communicate w/ C

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The Rosel Company on location to run Colliver 7
tracer survey
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Rosel Company technician fills survey tool with
tracer material
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Colliver 7 Well Work

• Pressure Transient Test October 2001
• Wanted to determine LKC C kh
• Tried to conduct both a build-up and fall-off
  test by injecting water into well
• Laid injection line from Colliver 10
• Needed clean injection water, installed tandem
  inline filters of 25 10 microns
• Had packer set at 7 csg shoe (2893)
• Ran bottom hole pressure bomb on slickline to
  mid-hole (2899)

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Colliver 7 Well Work

• Pressure Transient Testing October 2001
• Injected 450 BWPD for 48 hours, no pressure at
  surface
• SI well for 96 hours
• Pulled pressure bomb, tool had malfunctioned,
  only recovered build-up data (first 47 hours)
• 604 psia reservoir pressure
• Build-up data was interpretable
• Reservoir appears to have linear flow
• Matrix rock kh appears to be 308 md ft
• More interpretation needs to be done

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Injection line ran from Colliver 10 to Colliver 7
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Inline filters installed at Colliver 7
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Planned Colliver 10 Well Work

• Clean out junk fill
• Has plastic pipe and fill in hole
• Hope to clean out to mid-point of LKC C G
  (2925)
• Check for communication between C G
• C G received small frac job in 1960
• Set packer near casing shoe
• Run tracer survey, check for near wellbore
  communication between C G
• Perform remedial work if necessary
• Need to isolate G from C
• May cement squeeze entire LKC

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Colliver A-10W Before Workover
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Colliver A-10W After Workover
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Colliver A-10W After Workover Depicting the
Lansing Stratigraphy
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Preliminary CO2 Facilities Design

• Preliminary Study June 2001
• Production Facilities
• Murfin hired River City Engineering for study
• Study objectives
• Develop high level design and cost estimate for
  new CO2 production facilities
• Investigate instrumentation and control options
• Manual control vs. basic automation
• Major design criteria
• Peak production 85 BOPD, 850 BWPD, 420 MCFD
• CTB operating pressure between 25 100 psig
• 5 to 10 year material life with emphasis on
  chemical treatment for protection, vessels
  internally coated

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River City Engineerings preliminary production
facilities design for CO2 Project
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Preliminary CO2 Facilities Design

• Preliminary Study June 2001
• Control Options
• Manual control/Local operations
• Information gathered by operator making rounds
  (strip charts, pressure gauges)
• Regulators and mechanical linkages used
• Advantage
• Simple, little to no special training required
• Cheap, least expensive option
• Disadvantage
• Requires human intervention to collect relay
  data
• May provide less accurate data
• No alarm features, no record of what caused
  shut-ins

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Preliminary CO2 Facilities Design

• Preliminary Study June 2001
• Control Options
• Basic automation
• Metering and other critical data (pressures, tank
  levels) tied into a PLC
• PLC or PC trending and archiving of data
• Possible remote access
• Advantage
• Continuous logging of data
• Alarm capabilities
• Setpoints can be change on fly, no shut-down
  required
• Disadvantage
• Cost, more expensive than manual control
• Requires special training to operate maintain

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Preliminary CO2 Facilities Design

• Preliminary Study June 2001
• Production Facilities Cost
• Manual control option
• 236,500 (/- 30)
• Basic automation option
• 296,500 (/-30)
• 60 M incremental for automation

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Preliminary CO2 Facilities Design

• CO2 Supply Options January 2001
• CO2 from ethanol plant, 1.0 MMCFD
• Low-pressure pipeline (8.5 miles) 1.17/MCF
• High-pressure pipeline 1.28/MCF
• Liquefaction trucking 1.80/MCF
• CO2 from ethanol plant, 3.5 MMCFD
• Low-pressure pipeline (8.5 miles) 0.71/MCF
• High-pressure pipeline 0.67/MCF

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Arbuckle Efforts

• Sampled Bemis-Shutts Wells January 2001
• Collected oil gas samples from low-pressure
  region of Arbuckle
• Gas collected from annulus, oil collected using
  miniature gun-barrel
• Sampled 4 Vess and 8 Murfin wells
• Gas contained /- 60 N2, little CH4 (/- 3)
• Oil composition still being analyzed by CORE Lab
• Recombined Sample June 2001
• Collected oil gas sample from Murfins Peavy
  B-1 to be used for PVT analysis and a
  recombination MMP

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Courtesy of the Kansas Geological Survey
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(No Transcript)
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Arbuckle annular gas collected by Precision
Wireline
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Miniature gun-barrel used to collect Arbuckle oil
sample
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Miniature gun-barrel courtesy of John O. Farmer,
Inc.
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(No Transcript)
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Ethanol Plant Construction

• Start-up November 2001
• CO2 available Spring 2002
• ICM negotiating w/ FloCO2 of Midland, TX to build
  and operate liquefaction equipment at the ethanol
  plant
• ICM exploring food-grade CO2 market
• Most likely scenario has liquefied CO2 being
  trucked and stored at the CO2 pilot site

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Ethanol Plant Construction, Russell, KS
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Ethanol Plant Construction, Russell, KS