SLIDE 1
Oil Shale Formation Evaluation by Well Logs and Core Measurements - - PowerPoint PPT Presentation
Oil Shale Formation Evaluation by Well Logs and Core Measurements - - PowerPoint PPT Presentation
Oil Shale Formation Evaluation by Well Logs and Core Measurements Robert Kleinberg Schlumberger-Doll Research Cambridge, Massachuse:s AMSO: Alan Burnham, Roger Day TOTAL: Pierre Allix
SLIDE 2
SLIDE 3
50 ft
black=albite
Oil Shale Well Log Montage ¡
SLIDE 4
Volumetrics – Density Porosity, Resistivity, Magnetic Resonance
total mineral matter water (& salinity) kerogen
Composition – Capture Spectroscopy
common inorganic minerals (quartz, calcite, illite . . .) unusual inorganic minerals (dawsonite, nahcolite . . .) total organic carbon
Geology - Microimager
fractures vugs slumps
Objectives of Oil Shale Well Logging ¡
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ma b D w k ma f
ρ −ρ φ = = φ + φ ρ −ρ
Density Porosity
ma
ρ
= matrix (grain) density (~ 2.7 g/cc) b
ρ = bulk (measured) density
f
ρ = “fluid” (water+kerogen) density (~1 g/cc)
D
φ
w
φ
k
φ
= porosity measured by density tool = volume fraction kerogen = volume fraction water
Gamma-Gamma Density Log ¡ Measures Sum of Water + Kerogen ¡
SLIDE 6
Magnetic Resonance Signal Measurement Time Measurement Dead Time water kerogen
200 µs 2 s
Kerogen is Invisible to Magnetic Resonance ¡
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ma b D w k ma f
ρ −ρ φ = = φ + φ ρ −ρ
Density Porosity
ma
ρ
= matrix (grain) density (~ 2.7 g/cc) b
ρ = bulk (measured) density
f
ρ = “fluid” (water+kerogen) density (~1 g/cc)
Magnetic Resonance Porosity
MR w
φ = φ
k D MR
φ = φ − φ
D
φ
w
φ
k
φ
= porosity measured by density tool = volume fraction kerogen = volume fraction water
Density Magnetic Resonance (DMR) Method
Kerogen Volume from Density & Magnetic Resonance Logs ¡
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xx00 xx20 xx40 xx60 xx80 x100 0.1 0.2 0.3 0.4 0.5 0.6 2020 2040 2060 2080 2100 2120
Density Porosity & Magnetic Resonance Porosity
Porosity Depth (ft)
100108-03b
bad hole masked
Density Porosity NMR Porosity Kerogen
Porosity
0.6 0.5 0.4 0.3 0.2 0.1
100 feet
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20 40 60 80 1900 1950 2000 2050 2100 Well Log Kerogen Volume Core Measured Fischer Assay Well Log Kerogen Volume (gal/ton) Depth (ft)
100829-11b
Core Fischer Assay (gal/ton)
xx00 xx50 x100 x150 x200
Depth (ft) Well Log Kerogen Volume (gal/ton) Core Fischer Assay (gal/ton) xx00 xx50 x100 x150 x200 80 60 40 20
Well Log Kerogen Volume vs Core Fischer Assay ¡
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[ ]
FA TOM 0.019 199 = −
k D MR b
TOM ( ) ρ = φ − φ ρ Total ¡Organic ¡Ma:er ¡ as ¡frac>on ¡of ¡ore ¡weight ¡ gallons ¡of ¡oil ¡per ¡ton ¡of ¡ore ¡
Synthe'c ¡Fuels ¡Data ¡Handbook ¡ Cameron ¡Engineers, ¡1975 ¡ Figure ¡29. ¡Organic ¡Ma:er ¡Content ¡
- f ¡Green ¡River ¡Oil ¡Shales-‑ ¡
Total ¡Organic ¡Ma:er ¡ ¡ ¡ Modified ¡Fischer ¡Assay ¡(gal/ton) ¡ ¡ ¡ ¡
0.4 0.3 0.2 0.1 20 40 60
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20 40 60 80 1900 1950 2000 2050 2100 Well Log Fischer Assay Estimate Core Measured Fischer Assay Core Fischer Assay (gal/ton) Depth (ft)
100829-12b
Well Log Fischer Assay Estimate (gal/ton)
xx00 xx50 x100 x150 x200 Depth (ft) Fischer Assay (gal/ton) 80 60 40 20
Fischer Assay: Well Log vs Core ¡
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Schlumberger Log Interpretation Chart Gen-6 (2009)
m n w D w t
1 R S R a = φ
( a ~ 1, m ~ n ~ 2 )
MR w D
S φ = φ
MR
2
w t
R R = φ
@ reservoir temperature T
( 1.1192) w
T 21.5 C salinity(ppk) 7.976 R (T)10 C 21.5 C
−
+ ° ⎡ ⎤ = ⋅ ⎢ ⎥ ° + ° ⎣ ⎦
[Rw] = ohm-meters fraction of pore = space that is water filled Archie’ Law =
Water Salinity from Resistivity & Magnetic Resonance ¡
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Assume all NaCl is in Pore Water
3 3 3 3 3
g(NaCl) g(dry ore) cm (dry ore) cm (rock) g(NaCl) Salinity g(dry ore) g(water) cm (dry ore) cm (rock) cm (water) = =
( )
1 FSAL DWNACL RHGA 1 PIGE WKER PIGE = ⋅ − −
Water Salinity Estimate from Geochemical Logging ¡
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Low porosity – low resistivity spike
Mud filtrate salinity = 8 ppk
1400 feet
100108-01
Low porosity – low resistivity spike
80 60 40 20 100
Green River Formation ¡Salinity Log ¡
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Low porosity – low resistivity spike
1400 feet
100108-01
Green River Formation Salinity Log 80 60 40 20 100
Mud filtrate salinity = 8 ppk
No Communication Between Fresh & Saline Aquifers ¡
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Important information about oil shale deposits can be obtained from the same tools used in conventional oil and gas reservoirs. These include measurements of formation density, magnetic resonance response, electrical resistivity, and capture spectroscopy. Kerogen responds as part of the pore space to density porosity tools, but is invisible to borehole magnetic resonance. Simple processing gives kerogen volume and an accurate, depth-continuous estimate
- f Fischer Assay.
A salinity log results from comparing magnetic resonance to formation
- resistivity. Agreement with a capture spectroscopy estimate is fair.
Summary ¡
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