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ANNUAL MEETING MASTER OF PETROLEUM ENGINEERING
The CERENA-I synthetic dataset
28/May/2014 Instituto Superior Técnico
Fluid flow Simulation on a reservoir
containing a large amount of CO2
1
Pedro Tomás Madeira Pinto
Dissertation objectives and challenges
• Compositional fluid flow simulation on a synthetic reservoir model
containing a large amount of CO2.
• Optimize the production strategy to maximize CO2 usage and storage
• Calculate a data set of 4D synthetic seismics for several simulated
time steps.
• Observe the effects of fluid changes on the seismic response of the
model, during production.
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Real analogue: Júpiter
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Public domain information:
Area of 567 Km2
Top at 5000ms
GOC at 5370ms
OWC at 5435ms
90m thick oil zone with 18ºAPI
Gas cap with 79% CO2 (molar)
Oil with 55% CO2 (molar)
Reservoir rocks: Stromatolites and Microbiolites
Brazilian Pre-Salt play
Source: ANP
Static Model
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Geology
Geophysics
3D view of the porosity model
Petrophysical properties • Facies
• Porosity
• Permeability
• Density
Petroelastic properties • Dynamic moduli
• Vp, Vs
• Acoustic impedance
Geostatistics
3D view of the sectorial porosity model
First approach to the dynamic response
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Porosity histograms of full field and sectorial model
Top view of the sectorial model
area in the full model
Early sensitivity runs Evolution of saturations
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2029
2014
2040
2019
Approach 1: Water injection in the entire reservoir column
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2029
2014
2040
2019
Approach 2: Water injection in the aquifer
Early sensitivity runs Evolution of saturations
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2019
2014
2022
2017
Approach 3: Gas injection in the aquifer
Early sensitivity runs Evolution of saturations
Fluids and reservoir conditions
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• Fluids composition?
• Only the CO2 molar fractions from the gas and oil are known
• Oil ºAPI and GOR
• Condensate fraction in surface separators
• Reservoir conditions?
• BHP 517 bar(a), 100ºC taken from Lula field
• 90m thick oil zone
• Inferred GOC pressure 493-496 bar(a) High bubble point
P=ρgh
Fluids model PGOC=BHP-P90m reservoir
Fluids characterization
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• Fluids are default samples of condensate and oil
obtained from Petrel library
• Whitson splitting of the C7+ fraction up to C45
• Recombined samples with a GOR of 1010scf/bbl,
at reservoir conditions
Molar fractions of samples
Phase diagrams of Oil sample and Mix Molar fractions of samples
Component Oil Gas Original
CO2 0.91472 79.079 55.07
N2 0.22087 0.40708 0.25517
C1 16.256 14.036 11.933
C2 8.6696 1.8254 3.9301
C3 8.4491 1.2569 3.6057
NC4 4.148 0.52459 1.7304
... … … …
Gas Oil
Bubble point line Dew point line
Gas
Oil
The fine art of EOS tuning
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CO2 Pcrit used for regression
Phase diagram of the oil mixture with tuned EOS
Temperature 100º C
Calculated bubble point 252.4 bar(a)
Observed bubble point 493.0 bar(a)
Temperature 100º C
Calculated bubble point 493.1 bar(a)
Observed bubble point 493.0 bar(a)
Comp. Total Liquid Vapor
CO2 55.07 55.07 70.71
N2 0.26 0.41 0.40
C1 11.93 11.93 14.62
C2 3.93 13.93 3.71
Molar fractions of phases at the bubble point
Bubble point calculation with default EOS
Bubble point calculation with tuned EOS
241bar difference…
First law of reservoir simulation
Bubble point line Dew point line
Gas cap properties
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• Entire gas cap is at supercritical
conditions
• Dew point in condensate production
is an issue
• Most valuable fractions of the gas
condense at the dew point
Temperature 100º C
Calculated dew point 279.6 bar(a)
Comp. Liq. Mol. fraction Vap. Mol. fraction
C6 2.96 0.53
C7 2.96 0.17
C8 3.71 0.15
C9 4.66 0.13
C10 5.96 0.11
C11 7.67 0.10
C12 10.56 0.93
Liquid and vapour molar fractions at the dew point
Dew point calculation with tuned EOS
Phase diagram for the gas cap
• Dew point calculation at 279bar(a)
• Top reservoir pressure estimated at
460bar(a)
Bubble point line Dew point line
Gas injection
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• Minimum miscibility pressure is a critical aspect of gas injection
• Calculated MCMP* for CO2 injection in the oil is significantly higher
than reservoir pressure
• SAFT EOS is going to be used to generate more reliable experimental
data to further fine-tune the EOS performance
Temperature 100º C
MCMP* 868.4 bar(a)
*Multi-Contact Miscibility Pressure
MCM pressure for CO2 injection in the oil
Preliminary conclusions
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• Oil leg pressure is close to the bubble point (Δp ≈25bar(a))
• Gas cap pressure is comfortably above dew point (Δp ≈ 180bar(a))
• Gas cap and oil expansion drive productions are limited by the oil
bubble point
• High gas saturation in the oil is desired to avoid flow issues
• Pressure support is required
• High gas saturation in the oil requires high pressure for CO2
injection
References
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• Jessen, K., Sam-Olibale, L., Kovscek, A., & Orr, F. Increasing CO2 storage in oil recovery.
Department of Petroleum Engineering, Standford University.
• Shtepani, E., Thomas, F., Bennion, D., New approach in gas injection miscible processes modeling
in compositional simulation, Hycal Energy Research Laboratories Ltd.
• Smith1, R., Bard1,2, W., Guerini1, A., Lugo1, C., Yemez3, I., Equation of State of a Complex Fluid
Column and Prediction of Contacts in Orocual Field, Venezuela, 1Spe, 2Integrated Reservoir
Management, 3PVDSA.
• Sahimi1, M, Rasei1,2, Haghighi1,2, Gas injection and fingering in porous media, 1Department of
Chemical Engineering; University of Southern California, USA, 2Institute of Petroleum Engineering
and Department of Chemical Engineering, University of Tehran, Iran.
• Fevang1,2, Ø., Singh1,3, K., Whitson1,2,3, C., Guidelines for choosing compositional and Black-Oil
for Volatile Oil and Gas-Condensate Reservoirs, 1SPE, 2NTNU, 3PERA.