1. Capillary Pressure and Saturation History Capillary Pressure in Reservoir Rock.

2. DRAINAGE AND IMBIBITION CAPILLARY PRESSURE CURVES
Fluid flow process in which the saturation of the nonwetting phase increases
IMBIBITION
Fluid flow process in which the saturation of the wetting phase increases
Drainage Pc
Saturation History - Hysteresis
- Capillary pressure depends on both direction of change, and previous saturation history
- Blue arrow indicates probable path from drainage curve to imbibition curve at Swt=0.4
- At Sm, nonwetting phase cannot flow, resulting in residual nonwetting phase saturation (imbibition)
- At Swi, wetting phase cannot flow, resulting in irreducible wetting phase saturation (drainage) Pd
Imbibition
Swi Sm
0.5
1.0 Sw
Modified from NExT, 1999, after …

3. Saturation History
The same Pc value can occur at more than one wetting phase saturation

4. Rock Type Rock Type (Archie’s Definition - Jorden and Campbell)
Formations that “... have been deposited under similar conditions and ... undergone similar processes of later weathering, cementing, or re-solution....”
Pore Systems of a Rock Type (Jorden and Campbell)
“A given rock type has particular lithologic (especially pore space) properties and similar and/or related petrophysical and reservoir characteristics”

5. Thomeer’s Parameters for Capillary Pressure Curves
Thomeer’s Data
Mercury Injection - drainage
Very high capillary pressures
(Vb)P The (assymptotically approached) fraction of bulk volume occupied by mercury at infinite capillary pressure (similar to previous parameter, irreducible wetting phase saturation)
Pd Displacement Pressure, capillary pressure required to force nonwetting phase into largest pores (same as previously discussed)
G Parameter describing pore-size distribution (similar to previous parameter, 1/. Increasing G (or decreasing ), suggests poor sorting, and/or tortuous flow paths)

6. Figures 2.4 and 2.5 G is pore geometrical
Modfied from Jordan and Campbell, 1984, vol. 1
Figures 2.4 and 2.5
PT = PORE THROAT
P - PORE
(Vb) p =  is the fractional volume occupied by Hg at
infinite pressure, or total interconnected pore volume.
pd is the extrapolated Hg displacement pressure (psi);
pressure required to enter largest pore throat.
G is pore geometrical
factor; range in size and
tortuosity of pore throats.
Large pd = small pore thorats
Large G = tortuous, poorly
sorted pore thorats .

7. Note variation in pore properties and permeability within a formation
Modfied from Jordan and Campbell, 1984, vol. 1

8. sorting: very well sorted
Figure 2.8
size: lower fine
sorting: very well sorted
Modfied from Jordan
and Campbell,
1984, vol. 1

9. sorting: moderately sorted
Figure 2.9
size: lower fine
sorting: moderately sorted
Modfied from Jordan
and Campbell, 1984, vol. 1

10. sorting: moderately sorted
Figure 2.10
size: upper very fine
sorting: moderately sorted
Modfied from Jordan
and Campbell, 1984, vol. 1

11. -effect of significant cementing and clay
Figure 2.11
-effect of significant cementing and clay
Modfied from Jordan
and Campbell, 1984, vol. 1

12. Figure 2.12 Effect of Dispersed Clays Modfied from Jordan
and Campbell, 1984, vol. 1;
after Neasham, 1977

13. Capillary Pressure in ReservoirsB
dpw=wg/D dh
dpo=og/D dh
Free Water Level
Reservoir, o
Pc = po-pw = 0
Depth 3 2
Water exists at all levels below 2, and both water and oil exist at all levels above 2.
Oil and water pressure gradients are different because their density is different.
At level 2, pressure in both the water and oil phases is the same.
At any level above 2, such as level 3, water and oil pressures are different.
This difference in pressure is called the capillary pressure. 1
Aquifer, w
Pressure

14. Fluid Distribution in Reservoirs
Gas & Water
Gas density = rg
Oil, Gas & Water
Oil & Water
Oil density = ro
Water
Water density = rw
‘A’ h1 h2
‘B’
Free Oil Level
Free Water Level
Capillary pressure difference between
oil and water phases in core ‘A’
Pc,ow = h1g (rw-ro)
gas and oil phases in core ‘B’
Pc,go = h2g (ro-rg)
Modified from NExT, 1999, modified after Welge and Bruce, 1947
Seal
Fault
Free water level (surface) is the level at which water-oil capillary pressure is zero, i.e. the pressures in both water and oil phases are equal.
Above the free water level, oil and water can coexist. Above this level, there usually exists another level (or surface) called the water-oil contact, WOC. Below the WOC, only water can be produced. Above the WOC, both oil and water can be produced. At some point above the WOC, water will reach an irreducible value and will no longer be movable.
Likewise, a free oil level and an oil-gas contact (OGC) may exist as shown in the figure above.

15. RELATION BETWEEN CAPILLARY PRESSURE AND FLUID SATURATION
J-Function - for k,f
Lab Data
-Lab Fluids: s, 
-Core sample: k,
Height Above Free Water Level (Feet)
Reservoir Data
For uniform sands, reservoir fluid saturation is related to the height above the free-water level by the following relation:
J-Function Pc Pc Pd
Oil-Water contact Pd Hd 50
100
Free Water Level 50
100 50
100
Sw (fraction)
Sw (fraction)
Sw (fraction)
Modified from NExT, 1999, after …

16. Saturation in Reservoir vs. Depth
Results from two analysis methods (after ABW)
Laboratory capillary pressure curve
Converted to reservoir conditions
Analysis of well logs
Water saturation has strong effect on resistivity curves (future topic)