Fault seal 1:
Fluid properties in the
subsurface
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Fluid properties
• Although structural geometry important in trap
definition the physical properties of the fluid phases
in the rock volume are crucial
• Sealing/non-sealing behaviour of faults dependent
on fluid and host-rock properties and their
interaction with the structure
• Host rock properties defined in terms of porosity,
permeability & capillary threshold pressure
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Host rock: porosity & permeability
Porosity
Permeability
• Ratio of void volume to bulk
volume
• The measure of a rock’s
specific flow capacity
• Usually denoted φ
• Usually denoted k
• Expressed as %
• Hydrocarbon industry units
Darcy (D) but….
φ = Bulk volume – Grain volume x 100
Bulk volume
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• Reservoir and fault rocks
generally have millidarcy
(mD) permeabilities
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Porosity & permeability 2
Porosity
Permeability
• Very good: >20%
• Excellent: >1000mD
• Good: 15-20%
• Very good: 250-1000mD
• Medium: 10-15%
• Good: 50-250mD
• Poor: 5-10%
• Low: 0-5%
• Moderate: 15-50mD
• Poor to fair: <1-15mD
• Faults: 1μD to 1mD
From North (1985) ‘Petroleum Geology’
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Darcy flow
1 Darcy = 9.689233 x 10-13 m2
mD the more common unit
• The permeability of a rock is a measure of its
specific flow capacity
q = k/μ dθ/dz
q = flow rate (m3 m-2 s-1)
k = permeability
μ= viscosity (Pa s-1)
dθ/dz = fluid potential gradient
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Fluid properties
• Hydrocarbons are less dense than water
• Oil densities 0.5-1.0gcm-3
• Gas 0.00073 -0.5gcm-3
• Formation waters: Brine densities >1.0gcm-3
Oil volumes quoted in
barrels (BBL)
1 barrel = 0.159m3
or 279.8 UK pints!
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Hydrocarbon density
• Often quoted in API degrees:
• Conversion from density in gcm-3:
oAPI
= 141.5/SG60 -131.5
• Conversion from oAPI:
SG60 = 141.5/ (oAPI +131.5)
• Heavy oil <20 API
• Black oil 30-45 API
• Volatile oil 45-70 API
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Density is also
dependent on the
amount of dissolved
gas as given by the
Gas:Oil Ratio (GOR)
slide 7
Density vs depth/temperature
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From: Nordgård Bolås et al. (2005)
slide 8
The effect of GOR
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From Schowalter (1979)
slide 9
Pressure units
Stress
Nm-2
kgcm-2
lb/in2
bars
MPa
Nm-2
1
1.1E-05
0.00015
0.00001
0.000001
kgcm-2
98066.5
1
14.2234
0.98066
0.0980665
lb/in2
6894.76
0.07031
1
0.0689476
0.0068948
bars
100000
1.01972
14.5
1
0.1
MPa
1000000
10.1972
145
10
1
psi are the commonest ‘oilfield’ unit
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Pressure measurements
• Repeat Formation Tester ‘RFT’
• Accurate to ~0.5psi (3.447kPa)
• Measure a series of pressure points down through
a reservoir or series of reservoirs
• Can sample fluid phase
• Density contrasts between water and hydrocarbons
generate excess pressure due to buoyancy
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Pressure
gradients
• Lithostatic
(overburden)
• Hydrostatic
• Hydrocarbon
columns
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Buoyancy pressure
Pb = (ρw-ρhc)gH
or in field terms (psi): Pb = 0.433(ρw-ρhc)H
• Generated by density contrast between hydrocarbons
and water
• Buoyancy pressure = Pb
• Density of water = ρw
• Density of hydrocarbon = ρhc
• Acceleration due to gravity = g
• Height of hydrocarbon column = H
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Fresh water = 0.433psi/ft or 9.79kPam-1
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Hydrocarbon contacts
Hydrocarbon contacts are not always directly observable in a well
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Capillary entry pressure
• Entry of hydrocarbons into a rock controlled by the capillary
entry pressure (Pc)
• Interfacial tension σ is in dynes/cm
• The contact angle is θ
• Typical values for oil-water = 30-50
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Migration in a clastic rock
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Determining capillary entry pressure
Threshold
pressure
Mercury injection results must be converted from Hg-air to
hydrocarbon-water for use in seal analysis
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Calculating threshold pressure for the
hydrocarbon-water system
•
Threshold pressure obtained by Hg-injection porosimetry and
converted to the hydrocarbon water system using the equation:
Pthw = γhwcosθhwPtma/γmacosθma
γhw is the hydrocarbon-water interfacial tension
θhw is the contact angle for the hydrocarbon-water-rock system
Ptma is the Hg-air threshold pressure (psi)
γma is the Hg-air interfacial tension (~480 dyne/cm2)
θma is the contact angle for the Hg-air-rock system (~40o)
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Wettability
• Wettability is the tendency of one fluid to spread to
or adhere to a solid surface in the presence of other
immiscible fluids
• Rock surfaces are referred to as water-wet if they
have a wetting preference for water as oppose to oil
• Contact angles are probably the best indicator of
wettability. Always measured and quoted though the
water phase. A contact angle of <60o to 75o is
treated as water wet, and 105o to 120o to 180o is
treated as oil wet; intermediate values are treated as
neutral wettability
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Wetting surface
• If adhesive forces
exceed cohesive
fluid spreads out
and is wetting
• If cohesive forces
exceed adhesive
fluid beads up and
is non-wetting
• Clastic rocks tend
to be water wet
• Carbonates have
mixed wettability
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Typical values
System
Methane-brine
Contact angle
(degrees)
0
Interfacial tension
(dynes/cm)
72
Mercury-air
140
485
Oil-brine (<30API)
0-30
30
Oil-brine (30-40API)
0-30
21
Oil-brine (>40API)
0-30
15
Also depth/temperature dependent
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From Vavra et al. (1992)
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Interfacial tension
(& Dynes/cm)
From: Nordgård Bolås et al. (2005)
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Build up of
buoyancy
pressure
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Relative permeability: two phases
As hydrocarbon
saturation
increases the
relative
permeability to
water decreases
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Key references
Berg, R. R. 1975. Capillary pressure in stratigraphic traps. AAPG
Bulletin 59, 939-956.
Nordgård Bolås, H.M., Hermanrud, C. & Teige, G.M.G. 2005.Seal
capacity estimation from subsurface pore pressures. Basin
Research 17, 583-599.
Schowalter, T.T. 1979. Mechanics of secondary hydrocarbon
migration and entrapment. AAPG Bulletin 63, 723-760.
Vavra, C.L., Kaldi, J.G. & Sneider, R.M. 1992. Geological
applications of capillary pressure: a review. AAPG Bulletin 76, 840850.
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