Reservoirs Rick Lewis & Erik Rylander Iain Pirie Stacy Reeder, - - PowerPoint PPT Presentation

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)

surface bulk

T T T 2 1 2 1 2 1  

bulk

T T 2 1 2 1 

• 
• surface

T T 2 1 ~ 2 1

1 . 001 . 2 1   T

Comparison of Core NMR to Log NMR: investigate expelled fluids

0.01 0.1 1 10 100 1000 0.1 0.2 0.3 0.4 0.5 T2 (ms) Porosity (p.u.)

CMR Porosity: 9.9 p.u. Core NMR Porosity: 9.1 p.u. T2 - Core T2 - CMR

• m

0.01 0.1 1 10 100 1000 0.1 0.2 0.3 0.4 0.5 T2 (ms) Porosity (p.u.)

T2 - Core T2 - CMR Water

• 0.01

0.1 1 10 100 1000 0.1 0.2 0.3 0.4 0.5 T2 (ms) Porosity (p.u.)

Oil - Core Oil - CMR

• 0.01

0.1 1 10 100 1000 0.1 0.2 0.3 0.4 0.5 T2 (ms) Porosity (p.u.)

Shifted Oil - Core Oil - CMR

T2 Cutoff ~ 9.4 ms

10

• 2

10

• 1

10 10

1

10

2

10

3

xx99 ft 10.1 pu xx10 ft 10 pu xx23 ft 13 pu xx33 ft 8.8 pu xx40 ft 5.8 pu xx58 ft 10.5 pu xx65 ft 7.5 pu xx81 ft 8.1 pu xx93 ft 9.9 pu xx02 ft 7.1 pu

T2 (ms) T2 distribution (pu) T2-cutoff = 9.4 ms

Bulk Relaxivity

Shale Constituents by Volume Tight Oil Reservoir

Kerogen Mineral matrix Pore Water Bitumen Total Phi Clay bound water Light 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

5000 10000 15000 20000 Mar-00 Jun-00 Oct-00 Jan-01 Apr-01 BOPM

Eagle Ford Oil Producer

5000 10000 15000 20000 Mar-00 May-00 Jun-00 Aug-00 Oct-00 BOPM

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

• il 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

• rganic-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 Elements from Spectroscopy

Si, Ca, Mg, S, Fe, K, Na, Mn,P, etc.

Carbon Minerals

TOC from Carbon workflow

Carbon Saturation Index

 

) (g/cm density Bulk ) (g/cm density Oil (v/v) dielectric

• r

model cal petrophysi from water, e Bulk volum (v/v) bitumen Volume (v/v) porosity NMR Total (w/w) log l geochemica from directly content, carbon

• rganic

Total (w/w) n hydrocarbo light in carbon

• f

fraction Weight Oil 1) to (unitless, Index Saturation Carbon

3 3

14 12

     

   

   

  

bulk

• il

W W CSI

BVW bitumen NMR

• rganics

c

• il

c bulk

• il

BVW bitumen NMR

• il

c

W

• rganics

c W

• il

c W 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 from directly content, (TOCj) carbon

• rganic

Total (w/w) bitumen for correction require may n, hydrocarbo light in carbon

• f

fraction Weight Oil 1) to (unitless, Index Saturation Carbon   

  

    

• rganics

c

• il

c

• il

c

W W CSI

• rganics

c W

• il

c W CSI where W CSI RPI

5000 10000 15000 20000 Mar-00 Jun-00 Oct-00 Jan-01 Apr-01 BOPM

RPI – Good Well

5000 10000 15000 20000 Mar-00 May-00 Jun-00 Aug-00 Oct-00 BOPM

RPI - Poor Well

• 100

100 200 300 400 500 1 28 55 82 109 136 163 190 217 244 271 298 325 352 379 406 BBL or MCF

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
• rganic 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!