ptrc - 2-d visualisation of unstable waterfloods and polymer floods...

CIPR – CENTRE FOR INTEGRATED PETROLEUM RESEARCH

2-D visualisation of unstable waterfloods and polymer floods

for displacement of heavy oil

Arne Skauge, Bartek Vik, and Per Arne Ormehaug

CIPR, Uni Research, Bergen, Norway

International Energy Agency Collaborative Project on Enhanced Oil Recovery32nd Annual Symposium and Workshop


Viscous Fingering in water-oil displacement

Viscous Capillary


Unstable processes in oil production Gas injection with limited gravity component Heavy oil Miscible systems

CHALLENGE: Poor sweep Early breakthrough Prediction of stability or instability Treatments to avoid instability Mobilization of oil after breakthrough


Immiscible vs. Miscible systems Fingers may grow at unfavorable mobility ratio Capillary force prevents finger growth in immiscible systems Dispersion and diffusion prevent finger growth in miscible systems Three regimes:

sweep of oil by the fingers sweep of areas originally bypassed by the fingers production down to low (zero) oil saturation

Immiscible systems is characterized by the first regime while miscible systems exhibit all three (Peters, 1989) Possible macroscopic trapping of oil in the immiscible process

Oil pockets trapped in immiscible system


Immiscible vs. Miscible systems Fingers may grow at unfavorable mobility ratio Capillary force prevents finger growth in immiscible systems Dispersion and diffusion prevent finger growth in miscible systems Three regimes:

sweep of oil by the fingers sweep of areas originally bypassed by the fingers production down to low (zero) oil saturation

Immiscible systems is characterized by the first regime (YES) while miscible systems exhibit all three (Peters, 1989, our earlier studies) Possible macroscopic trapping of oil in the immiscible process

Oil pockets trapped in immiscible system


2D stduies of tertiary polymer flooding Fluid: crude extra heavy oil (~ 7000 cp at Lab conditions)

Geometry of Bentheimer sandstone Length mm 299 Porosity 24%

Injection Flow Rate Injection Rate mL/h 3.00 Front Pace (=Q/S) mm/h 0.490

Capillary number Nca (μw∗vp/σ) 2.91*10-8

Permeability Kw sw=1 Darcy 2.8 Ko (Swi Before ageing) Darcy 2.1 Ko (Swi After ageing) Darcy 1.2

Fluids Swi 7% Concentration Flopaam ppm ~1650 Viscosity polymer at 10s-1 cP 58.0 Viscosity polymer at 70s-1 cP 23.5 Viscosity Oil @22°C cP 2000 Viscosity Oil @22°C cP 7000


Waterflood Oil recovery (adverse mobility ratio)

0102030405060708090

100

0 0,5 1 1,5 2 2,5

Injected volume (PV)

Oil

Rec

over

y (%

)

Oil Rec(%)

Viscosity ratio (o/w): ~2000/1 - from 2D slab experiment


Low energy gamma-ray source (200 mCi Am241 emitting an energy of 59 keV) isused to emit a narrow beam of electromagnetic radiation which is attenuatedby a rock sample. (porosity mapping)

The x-ray source may be operated between 40 and 60 kV, at a maximum current of 0.4 mA. (saturation mapping)

A scintillation photon counting detector (NaI) and an x-ray camera is installedand used to measure the intensity of the attenuated beam (front movement)


A. Waterflood at Swi B. Waterflood at Swi=0 C. Waterflood on aged core(waterwet) (water wet)

Three different flow patterns observed during immiscible displacementat adverse mobility ratio


0,009PV 0,028

0,034 0,24

Waterflooding (oil visc. 7000 cp)


0,009PV 0,028

0,034 0,24

Waterflooding (oil visc. 7000 cp)

BT


Riaz and Tchelepi (2006) Riaz et al. (2007)

Our experiment

Experiments have shown

Fingers are not followed by a Buckley-Leverett front

Fingers is getting more dispersedand channels are formed


2,6 PV1,2 PV

Waterflooding (oil viscosity 7000 cp)


0.02 PV 0.05 PV

Waterflood in heavy oil reservoirs

X-ray imaging of invading waterflood

Visc. (o/w) 2000/1

2.0 PV

Large unswept areas


Oil recovery from water and polymer injection

0102030405060708090

100

0 0,5 1 1,5 2 2,5 3 3,5 4

Injected volume (PV)

Oil

Rec

over

y (%

)

Oil Rec(%)Oil Recovery, Polymer

Viscosity ratio (o/w): ~2000/1


Polymer flooding using the end of waterfloodas a reference

0,019PV polymer injectionOil viscosity 7000 cP

White increase in SwBlack increase in So

Blue increase in SwRed increase in So

End of waterflood 0,019 PV Polymer


0,4850,149

0,0420,019

Polymer injection Blue: increase in Sw, red increase in So


2,2 PV

Polymer injection


2,6 PV waterflood

Black color - oil bank formation

Polymer injection

White: increase in SwBlack: increase in So

1. Water displacing oil2. Oil displacing water against capillarity

1

2


Black color - oil bank formation

2

The viscous driven crossflow we can model


0.02 PV 0.05 PV

0.02 PV 0.11 PV 0.25 PV

Polymer in heavy oil reservoirsX-ray imaging of invading front

Waterfloodingin heavy oilVisc. (o/w) 2000/1

Polymer floodingin heavy oilVisc. (o/w) 2000/30

2.0 PV

Red increasing oil saturation, blue: increase in water saturation

E2000


Conclusions

Thin fingers formed during waterflood in heavy oil using intermediate wet core material

Fingers is not followed by a BL front

Finger thickening _ channels is observed in the later stage of the waterflood: extended period of production at near 100% watercut.

Polymer flood show quick change in watercut, and high recovery

Oil is mobilized from already swept areas and also from oil pockets in between fingers

The oil bank is produced through the established water fingers, this means oil mobilization overrides capillary and rel perms

ptrc - 2-d visualisation of unstable waterfloods and polymer floods...

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