Property of interest Core data Log data

Porosity Crushed dry rock He porosimetry

Density (mostly)

TOC LECO or RockEval GR, density, resistivity

Water saturation As-received retort or Dean-Stark

Resistivity + kerogen corrected porosity

Mineralogy XRD, FTIR, XRF Density, neutron, Pe, ECS-type logs

Permeability Pulse decay on crushed rock

This is tough…………

Geomechanics Static moduli DTC, DTS, RHOB, & synthetic substitutes

Geochemistry Ro, S1-S2-S3, etc. Resistivity (sort of…)

Porosity first › How much storage volume is there for free

gas (or oil)? Saturation next

› Can we estimate Sw in shales? Then Permeability

› Is there sufficient permeability to flow gas, or better yet oil?

GIP & oil-in-place last

Simplified Rock

Clastic Rock

Clastic Components

Porosity Effective porosity, Phie

Total porosity, Phit

Bulk volume water

solid matrix

porosity

non-

mov

eabl

e fl

uids

non-

mov

. fl

uids

moveable fluids

grains

porosity

wate

r

resi

dual

H

C hydrocarbons mud

, silt

dry

clay

OH-

wate

r

water

matrix quartz, feldspar, etc. cl

ay-

boun

d

resi

dual

H

C hydrocarbons clay& OH-

capi

llary

-bou

nd

free water

Bulk volume hydrocarbon

Solidity, 1 - Phit

Grain volume

Organic Shale Components

Organic Shale mineral matrix

kero

gen

wate

r

dry

clay

OH-

clay

- bo

und clay &

OH-

gas, oil

wate

r

gas, oil

porosity

Free

wat

er

quartz, carbonate, pyrite, etc.

kero

gen

In organic shales, TOC “looks like” porosity to a density log

Density of organic matter is close to that of water or oil › Ranges from 0.9 to 1.4 g/c3 in our

experience › Common “default” value is 1.3 or 1.35 g/c3

Consequence: density porosity is too high and needs to be corrected down

Estimate from GR or density log Estimate from deltaLogR (sonic-resistivity

overlay method) Run a specialty log to get a kerogen-free

grain density, and compare to total grain density from density-neutron log

Get it from cores

TOC (v/v) = (ρgray sh – ρb) / 1.378 (1979 eqn) TOC (v/v) = (GRgray sh – GR)/(1.378 * A) (1981 eqn) TOC (v/v) = WTOC * RHOb/RHOTOC

0

2

4

6

8

10

12

14

16

18

2.0 2.1 2.2 2.3 2.4 2.5 2.6 2.7 2.8 2.9

Bulk density (g/cm3)

tota

l org

anic

car

bon

(wt %

)

New Albany Shale, Illinois basin EGSP cores (1976-1979), all big blue logs

Published Schmoker relation

Basically a sonic F overlay Two universal eqn’s published by Passey

et al. (1990, AAPG Bull) › ∆logR = log10 (R/Rbl) + 0.02 (∆T-∆Tbl) This defines deltaLogR

› TOC = ∆logR * 10^(2.297 – 0.1688 LOM) This relates deltaLogR to TOC (wt%)

Most of us are concerned about the LOM parameter, but the second two constants were empirically determined

Passey et al, 2010, SPE 131350

TOC (wt %) = ∆logR * 10^(2.297 – 0.1688*LOM) Passey et al, 1990, AAPG 74 (12) 1777-1794

Deterministic suite of regression eqn’s to compute mineral volumes and kerogen-free grain density

RhoMecs = a + b Si + c (Ca,Na) + d (Fe,Al )+ e S

Not as simple as standard density porosity determination

We need TWO grain densities, › Density of the inorganic mineral matrix › Density of the organic fraction (a.k.a.

kerogen density or TOC density) And, we need to estimate the fluid

density in the flushed zone (where the density log makes its measurement)

(1 * / )ma b TOC TOC ma TOCT

ma fl

W Wρ ρ ρ ρφρ ρ

− − +=

−

Sondergeld et al, 2010, SPE 131768

(1 ) (1 )b hc T wT w T wT ma T TOC TOC TOCS S V Vρ ρ φ ρ φ ρ φ ρ= − + + − − +

Intercept at 0% porosity gives RhoMa inorganic = 2.76 g/c3

New Albany example

Use core measured porosity, RhoB, and Wtoc to solve for RhoTOC › RhoFl requires assumption about gas

saturation and gas density at in-situ conditions

(12.722.72

*2.72 / )TOC TOC TOCbT

fl

W Wρφρ

ρ−=

+−

−

Full solution for porosity

(1 * / )m b TOC TOC m TOCT

m fl

W Wρ ρ ρ ρφρ ρ

− − +=

−

TOC corrected porosity

Convert Wtoc to volume of TOC using an assumed RhoTOC

Subtract Vtoc from density porosity to get a rough kerogen-corrected shale porosity

/ *toc toc toc bV W ρ ρ κ=

Most of us compute saturation from the conventional “Archie” approach › Requires total porosity, resistivity, Rw, m, n › We will probably NEVER be able to measure

m and n › We have no assurance these rocks act like

“Archie” or shaly sand systems

Calibrate a log model to as-received core saturations › Best data we have for in-situ Sw › Rw in shale is a guess › Usually assume an m and n, often 2 or

sometimes less Remarkably, we can usually fit the core

data without doing anything too stupid…….

GR porosity Sw TOC

Perm is a can of worms We are not very confident we can

measure shale perms in core, but it’s the best we have for now

Log models for perm are weak at best › Most use phi-K correlation based on core

D&A – clean dry hole No gas or oil flowed back after frac, 45% of load recovered, well dead (0 psi TP). Swabbed small blows of gas over 12 days.

Two components › Free gas or compression gas › Adsorbed gas

There is also some absorbed gas dissolved in kerogen or bitumen, but the way we calibrate the adsorption model this is inside the other number

Need to know porosity, saturation, & h: where C is a units constant, A is area, f is porosity, h is

thickness, Sw is water saturation, & Bg is the formation volume factor

High pressure, high porosity, high Sg, and large A greater GIP

* *(1 ) /w gGIP C A h S Bφ= −

Adsorption is a surface phenomena Characterized by adsorption isotherms:

Where Gc is the adsorbed gas content (scf/ton) VL is the Langmuir volume (scf/ton) PL is the Langmuir pressure (psia) Where Gab is the adsorbed gas-in-place (scf), A is area in acres,

h is thickness in ft, ρb is bulk density, and Gc is the average adsorbed gas content in scf/ton

* / ( )L LGc V P P P= +

1359.7* bGab Ah Gcρ=

Barnett Shale example

0

20

40

60

80

100

120

140

160

0 200 400 600 800 1000 1200 1400 1600 1800Pressure (psi)

0

50

100

150

200

250

0 2 4 6 8 10 12 14 16 18

Total organic carbon (%)

TOC 15.50 13.70 12.64 10.44 8.80 8.21 7.25 3.55

Gas

con

tent

(scf

/ton

)

Lang

mui

r vol

ume

(scf

/ton

)

Kerogen is highly adsorptive Wet clays are minimally adsorptive Quartz, calcite, dolomite: adsorption is nil

Compute free gas Compute adsorbed gas Correct for volume of free gas occupied

by adsorbed gas (SPE 131772) Add ‘em up NGL’s and condensate are calculated

from the GOR

Assume a vertical well tests 10 ft of a low porosity zone at 2 BOPD.

We’ll go horizontal in that zone and drill 5,000 to 10,000 ft laterally

Kh scales with contacted interval, so we expect 500 – 1000X the flow capacity

Real world = not that good. Not all of the lateral contributes equally.

You can calculate porosity and saturations in shales; they make sense and match core data

The apparent density porosity is too high in the presence of TOC

Don’t try to just “eyeball” it, there are too many moving parts › Log analysis on the hood of a Chevy does

not work well in shales

Questions??