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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.

28/May/2014 Instituto Superior Técnico 2

Real analogue: Júpiter


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


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


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


2029

2014

2040

2019

Approach 1: Water injection in the entire reservoir column


2029

2014

2040

2019

Approach 2: Water injection in the aquifer



2019

2014

2022

2017

Approach 3: Gas injection in the aquifer


Fluids and reservoir conditions


• 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


• 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


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


Gas cap properties


• 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)


Gas injection


• 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


• 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


• 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.

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