Rick Lewis & Erik Rylander

Iain Pirie

Stacy Reeder, Paul Craddock, Ravi Kausik, Bob

Kleinberg & Drew Pomerantz

Application of NMR for

Evaluation of Tight Oil

Reservoirs

Lots of oil in place – what is pay?

•

•

Organic Shale Pore System

Diameter (nm)

0.38 Methane Molecule

0.38 to 10 Oil Molecule

4 to 70 Pore Throat

15 to 200 Virus

5 to 750 Organic Pore

10 to 2000 Inter/Intra Particle Pores

200 to 2000 Bacteria

35000-65000 Shale Size Particle (mean)

Evolution of organic fractions of shale with increasing thermal maturity.

NMR T2 Time Distribution (Conventional vs. Organic Shale)

surfacebulk TTT 2

1

2

1

2

1

bulkTT 2

1

2

1

•

•

surfaceTT 2

1~

2

11.001.

2

1

T

Comparison of Core NMR to Log NMR: investigate expelled fluids

0.01 0.1 1 10 100 10000

0.1

0.2

0.3

0.4

0.5

T2 (ms)

Po

ros

ity

(p

.u.)

CMR Porosity: 9.9 p.u.

Core NMR Porosity: 9.1 p.u.

Core Depth 9198 ft

T2 - Core

T2 - CMR

0.01 0.1 1 10 100 10000

0.1

0.2

0.3

0.4

0.5

T2 (ms)

Po

ros

ity

(p

.u.)

T2 - Core

T2 - CMR

Water

0.01 0.1 1 10 100 10000

0.1

0.2

0.3

0.4

0.5

T2 (ms)

Po

ros

ity

(p

.u.)

Oil - Core

Oil - CMR

0.01 0.1 1 10 100 10000

0.1

0.2

0.3

0.4

0.5

T2 (ms)

Po

ros

ity

(p

.u.)

Shifted Oil - Core

Oil - CMR

•

•

m

0.01 0.1 1 10 100 10000

0.1

0.2

0.3

0.4

0.5

T2 (ms)

Po

ros

ity

(p

.u.)

CMR Porosity: 9.9 p.u.

Core NMR Porosity: 9.1 p.u.

Core Depth 9198 ft

T2 - Core

T2 - CMR

0.01 0.1 1 10 100 10000

0.1

0.2

0.3

0.4

0.5

T2 (ms)

Po

ros

ity

(p

.u.)

T2 - Core

T2 - CMR

Water

0.01 0.1 1 10 100 10000

0.1

0.2

0.3

0.4

0.5

T2 (ms)

Po

ros

ity

(p

.u.)

Oil - Core

Oil - CMR

0.01 0.1 1 10 100 10000

0.1

0.2

0.3

0.4

0.5

T2 (ms)

Po

ros

ity

(p

.u.)

Shifted Oil - Core

Oil - CMR

•

0.01 0.1 1 10 100 10000

0.1

0.2

0.3

0.4

0.5

T2 (ms)

Po

ros

ity

(p

.u.)

CMR Porosity: 9.9 p.u.

Core NMR Porosity: 9.1 p.u.

Core Depth 9198 ft

T2 - Core

T2 - CMR

0.01 0.1 1 10 100 10000

0.1

0.2

0.3

0.4

0.5

T2 (ms)

Po

ros

ity

(p

.u.)

T2 - Core

T2 - CMR

Water

0.01 0.1 1 10 100 10000

0.1

0.2

0.3

0.4

0.5

T2 (ms)

Po

ros

ity

(p

.u.)

Oil - Core

Oil - CMR

0.01 0.1 1 10 100 10000

0.1

0.2

0.3

0.4

0.5

T2 (ms)

Po

ros

ity

(p

.u.)

Shifted Oil - Core

Oil - CMR

•

•

0.01 0.1 1 10 100 10000

0.1

0.2

0.3

0.4

0.5

T2 (ms)

Po

ros

ity

(p

.u.)

CMR Porosity: 9.9 p.u.

Core NMR Porosity: 9.1 p.u.

Core Depth 9198 ft

T2 - Core

T2 - CMR

0.01 0.1 1 10 100 10000

0.1

0.2

0.3

0.4

0.5

T2 (ms)

Po

ros

ity

(p

.u.)

T2 - Core

T2 - CMR

Water

0.01 0.1 1 10 100 10000

0.1

0.2

0.3

0.4

0.5

T2 (ms)

Po

ros

ity

(p

.u.)

Oil - Core

Oil - CMR

0.01 0.1 1 10 100 10000

0.1

0.2

0.3

0.4

0.5

T2 (ms)

Po

ros

ity

(p

.u.)

Shifted Oil - Core

Oil - CMR

T2 Cutoff ~ 9.4 ms

10-2

10-1

100

101

102

103

xx99 ft10.1 pu

xx10 ft10 pu

xx23 ft13 pu

xx33 ft8.8 pu

xx40 ft5.8 pu

xx58 ft10.5 pu

xx65 ft7.5 pu

xx81 ft8.1 pu

xx93 ft9.9 pu

xx02 ft7.1 pu

T2 (ms)

T2 d

istr

ibution (

pu)

T2-cutoff = 9.4 ms

Bulk Relaxivity

•

•

Shale Constituents by Volume Tight Oil Reservoir

Kero

gen

Mineral matrix

Pore

Wate

r

Bitum

en

Total Phi

Cla

y b

ound w

ate

r

Lig

ht

oil

Eff Phi

Pore Distribution

Cap-Bound Water

Cap-Bound Oil

(OM Pores)

Cap-Bound Water

Free Oil

(Larger OM Pore

> 250 nm)

Producible Fluids

Oil and Water

(Water wet pores)

Clay-Bound Water

Bitumen

Eagle Ford Oil Producer

0

5000

10000

15000

20000

Mar-00 Jun-00 Oct-00 Jan-01 Apr-01

BO

PM

Eagle Ford Oil Producer

0

5000

10000

15000

20000

Mar-00 May-00 Jun-00 Aug-00 Oct-00

BO

PM

Tmax Data

T2 relaxation of native and re-saturated shale

T2 relaxation of native and re-saturated shale

T2 relaxation of native and re-saturated shale

Native state porosity

Resaturated oil porosity

12.11 3.91

12.70 4.79

12.14 4.19

8.09 3.43

4.25 2.15

11.66 3.77

10.74 3.66

10.19 3.06

8.20 2.94

Rock Eval Pyrolysis

Measurements of • S1: oil in the sample

• S2: potential oil and gas

• S3: CO2

• S4: residual hydrocarbon

• Tmax: maturity indicator

• TOC

The Importance of Oil Saturation Index (OSI)

Jarvie, 2012: As much as 70-80 mg Oil / g TOC is sorbed to Kerogen

An OSI > 100 mg Oil / g TOC may produce oil

Oil Saturation Index (OSI)

Matrix Bound

Water Oil

Free

Water Bitumen Kerogen

S1

TOC

Oil Bitumen Kerogen

Oil

= OSI = S1

TOC

Jarvie, 2012: As much as 70-80 mg Oil / g TOC is sorbed to Kerogen

An OSI > 100 mg Oil / g TOC may produce oil

Shale-Oil Systems

Hybrid Shale

Juxtaposed organic-rich and

organic-lean intevals

Bakken is end member

OSI provides method to ID

contribution of organic-lean

intervals in finely juxtaposed

system

TOC standard workflows

Estimating TOC from logs:

- Schmoker (density)

- Δ log R (Sonic-Resistivity)

- Uranium

- NMR-PHIA deficit

Based on indirect measurements

Require calibration to core data

Specific to a particular formation

All are kerogen-only TOC

Direct measurement from Inelastic

Spectra

TIC = 0.120*Calcite+

0.130*Dolomite+

0.104*Siderite+

0.116*Ankerite

Ele

men

ts fr

om

Spe

ctro

scop

y

Si, Ca, Mg, S, Fe, K,

Na, Mn,P, etc.

Carbon

Minerals

TOC from Carbon workflow

Carbon Saturation Index

)(g/cmdensity Bulk

)(g/cmdensity Oil

(v/v) dielectricor model calpetrophysi from water,eBulk volum

(v/v)bitumen Volume

(v/v)porosity NMR Total

(w/w) log lgeochemica fromdirectly content,carbon organic Total

(w/w)n hydrocarbolight in carbon offraction Weight Oil

1) to0 (unitless,Index SaturationCarbon

3

3

14

12

bulk

oil

W

W

CSI

BVW

bitumen

NMR

organicsc

oilc

bulk

oilBVWbitumenNMRoilcW

organicscW

oilcW

CSI

Reservoir Producibility Index—Account for Porosity

Differences

Log generated index

Circumvents problems associated with recovery and analysis of hydrocarbons

from cuttings and/or core

OSI of 100 ~ RPI of 0.1 (fc of porosity)

(w/w)Scanner Litho fromdirectly content, (TOCj)carbon organic Total

(w/w)bitumen for correction requiremay n,hydrocarbolight in carbon offraction Weight Oil

1) to0 (unitless,Index SaturationCarbon

organicsc

oilc

oilc

W

W

CSI

organicscW

oilcW

CSI

where

WCSIRPI

0

5000

10000

15000

20000

Mar-00 Jun-00 Oct-00 Jan-01 Apr-01

BO

PM

RPI – Good Well

0

5000

10000

15000

20000

Mar-00 May-00 Jun-00 Aug-00 Oct-00

BO

PM

RPI - Poor Well

•

•

-100

0

100

200

300

400

500

1 28 55 82 109

136

163

190

217

244

271

298

325

352

379

406

BB

L o

r M

CF

RPI, Woodford

(VRo ~ 0.7)

•

•

RPI, Bakken (VRo ~ 1.0)

T2 Distribution of Native Shale Sample Plotted Together with

Formation Oil and Brine Re-saturated Shale

Pore Fluids from T1/T2

• Differentiate between

hydrocarbon and water-

filled pores

• Two pore system model

• Organic with

hydrocarbon

• Inorganic with water

• T1/T2 ratio higher for oil-

saturated pores

• Core work performed by

OU on Barnett Shale

T1/T2 maps of Eagle Ford Shale at various depths

Universal T1-T2 picture for shale at 2MHz

WT(1) WT(2) WT(3) WT(4)

CPMG(1) CPMG(2) CPMG(3) CPMG(4)

t

WT(1)

WT(2)

WT(3)

WT(4)

Mz = M0 [1 - exp(-t/T1) ]

Potential for T1-T2 in Tight Oil

• Differentiate and potentially quantify bitumen

• Differentiate and quantify OM and IP pores

• Limit from 2 to ~30ms

Initial Observations

• Can not differentiate between hydrocarbon and water

in IP pores

• All bitumen may not be quantified due to short

relaxation time

Conclusions

• Non-producible hydrocarbons are common constituent in liquid

producing shales

• One type of non-producible hydrocarbon is viscous source rock

bitumen

• Another type of non-producible hydrocarbon are oils sorbed to

organic pore walls

• RPI methodology can be used to characterize producible

zones, and it takes porosity and pore water into account

It recognizes hybrid reservoirs

• T1/T2 shows potential to differentiate bitumen and OM vs. IP

pore fluids

Application of these metrics to landing point selection has had

dramatic positive impact to productivity in shale wells!