Capillary Pressure and Saturation History Capillary Pressure in Reservoir Rock .

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 …

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

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”

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)

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 .

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

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

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

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

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

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

Capillary Pressure in Reservoirs B 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

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.

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 …

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)