Carbon Dioxide Demonstration Project
Supporting Research at KU
Jyun-Syung Tsau
presented for
Tertiary Oil Recovery Project
Advisory Board Meeting
October 19-20, 2001
Supporting Research Activities
• Simulation
– Hall-Gurney field (LKC formation)
– Bemis-Shutts field (Arbuckle formation)
• Laboratory experiments
– Slim-tube displacement
– Residual oil measurement
Simulation
• Reservoir simulator
– VIP black oil simulator
• Primary production, waterflooding
– VIP compositional simulator
• CO2 flooding
Compositional Simulator
• Equation of state (EOS) for CO2-oil
phase behavior characterization and
properties calculation
• Peng-Robinson 3-parameter EOS model
Typical Data Preparation for
Compositional Simulation
• C7+ characterization (sub-grouping
heavy end)
• Pseudoization (grouping)
• Phase behavior calculation (swelling
test)
• Slim-tube displacement
Laboratory Displacement Data to Fine
Tune Reservoir Simulator
• Slim-tube displacement experiment
– Ideal porous media
– Oil recovery attributed to phase behavior
– MMP (minimum miscibility pressure)
indicates the pressure required to develop
multiple-contact miscibility
– Fine tune EOS parameters in reservoir
simulator
Schematic of Slim-tube Experiment Apparatus
T T
T
BPR
Oil
CO2
T
N2 source
CO2
source
Milton Roy
pump
Effluent
ISCO
pump
ISCO
pump
Oil Recovery Performance in Slim-tube Experiment
(Letsch #7 oil)
Oil produced (HCPV)
1
Temp: 105 °F
0.8
0.6
0.4
1305 psia
1015 psia
0.2
0
0.0
0.2
0.4
0.6
0.8
CO2 injection (HCPV)
1.0
1.2
MMP Measurements of Letsch #7 Oil
100
Recovery at 1.0 HCPV CO2 injection
Recovery (%)
90
80
70
60
50
40
800
900
1000
1100
Pressure (psia)
1200
1300
1400
Oil Recovery Performance Match
1.2
Oil produced (HCPV)
Pressure = 1305 psia
1
0.8
0.6
0.4
Experiment
Simulation_bip0.05
Simulation_bip0.0735
0.2
0
0.0
0.5
1.0
CO2 injection (HCPV)
1.5
2.0
Determination of Residual Oil Saturation
to Carbon Dioxide
Why it is important?
• Miscibility developed by multiple
contact results in variable amount of
oil left behind in CO2-swept zone
• Uncertainty in projection of oil
recovery by the simulator
Critical Issues to the Measurements
• Measurement needs to account for
– Well defined development of
miscibility
– Representative fluid and rock
properties
Schematic of Residual Oil Saturation
Measurement Apparatus
Characteristics of Slim-tube and
Core Sample
Slim-tube
Core sample
Length (inch)
459.48
1.9205
I.D. (inch)
0.2425
0.9845
Bulk volume (cc)
347.80
23.96
Pore volume (cc)
127.76
5.26
Porosity (%)
36.73
21.95
Permeability (md)
4900
453.73
Glass bead
Berea sandstone
Porous media
Future Tasks
• Investigate the effect of displacement
rate, core length and structure on
residual oil saturation determination
• Investigate the effect of water saturation
on the residual oil saturation to CO2
Evaluation of Arbuckle Crude Oil for Oil
Recovery by CO2 Displacement
• Conduct experiment to measure MMP of
crude oil obtained from Arbuckle
formation
• Perform simulation to match current field
condition and test the reservoir response
to pressurization process
MMP Measurements of Peavey #B1 Oil
(Bemis-Shutts field)
Oil recovery (% OOIP)
100
90
Temp: 108 °F
80
70
60
50
40
800
900
1000
1100
1200
1300
1400
Pressure (psia)
1500
1600
1700
1800
Current Reservoir Condition
• Average reservoir pressure is around
500 psia, which is not high enough for
CO2 miscible displacement
• Reservoir must be pressurized
Approaches
• Construct a generic model to
simulate the process of
– Primary production
– Pressurization
• Model contains
– 126 active production wells in a 2 by 2
square miles area (2560 acres)
Grid Cell System Used in the Model
Cross Section of the Reservoir Formation
3400'
aquifer
86 ft
3486'
2 miles
• 11 layers with permeability ranging
between 0.2 ~5 md in aquitard and 50
~1500 md in production zones
Satisfactory Match
• Simulation results were to match
– Reservoir average pressure
– Cumulative oil and water production
– Current oil and water production rate
Observations
• Reservoir is a layered reservoir with high
permeability contrast between layers
• Bottom water drive
Edge water drive does not provide enough
energy to support the average reservoir
pressure and production performance
Pressure Distribution at the End of Primary Production
(Beginning of Pressurization)
Simulation Tests to Pressurize a Project Area
• 5 spot pattern (10 acres) with 6
confining injectors (within 120 acres)
Well Condition Parameters During the
Pressurization
• Injector
– 5-spot: BHP: 2000 psia, Qmax: 3000 bbl/day
– Confining area: BHP: 2000 psia, Qmax: 3000
bbl/day
• Producer
– 5-spot: shut-in
– Around confining area: BHP: 1100 psia, Qmax:
300 bbl/day
– Other active producers : BHP: 300 psia, Qmax:
300 bbl/day
Pressure Distribution After 3-year’s Pressurization
Summary of Pressurization Process
• The magnitude of pressure increase
within a pattern depends on the size of
the pattern, confining area, and bottom
hole pressure control of injectors and
producers.
• The ultimate pressures within the
pattern varied from 1200 psia to 1500
psia.
Preliminary Results
• Attainable reservoir pressure might
slightly below the MMP as required for a
miscible CO2 displacement
• Oil recovery remains relatively high (70
~85%) for a few hundred psi below MMP
Current Status
• Oil and gas samples collected from the
wellhead and separator were analyzed by
Core-Lab
• High nitrogen content was found on some
of the separator samples through the quality
check, which suggests the needs to measure
MMP and oil recovery using a live oil
sample
• Detailed PVT test and swelling test would
be conducted by Core-Lab, and data would
be used for compositional simulation