Net/gross and porosity based on borehole images

Dr Zbynek Veselovsky

Net/gross and Porosity Based on Borehole Images Zbynek Veselovsky, Eriksfiord Electrical and acoustic borehole images can be used to calculate a sliding net sand ratio and fracture or vuggy porosity. The method, which enables inclusion of hydrocarbon filled beds and fractures which are hydraulically connected but too thin to be detected by nuclear logs, and vugs bypassed by the neutron detector, has led to significant corrections of official reserves in some cases. For thin sand beds, OBM resistivity imagers or WBM conductivity imagers are suitable. Sand layers and fractures can be marked visually, or separated from the host rock by a thresholding technique, after suitable scaling of the image pixel values and compensation for bedding dip and borehole inclination. In WBM, sand/shale polarity and contrast is influenced by reservoir fluid (water/oil/gas). Both in OBM and WBM, edge effects may be significant. For vuggy porosity, acoustic imagers (OBM/WBM) are most efficient, as there is no edge effect and borehole coverage is complete. Thresholding provides a maximum estimate and visual picking a minimum estimate. Sometimes both exceed neutron porosity even though it includes matrix porosity, so it seems large vugs are often bypassed by the (asymmetric) neutron porosity tool.

Motivation

Borehole image interpretation

Net/gross & bed thickness analysis Sponsored by Statoil research center

Correcting for structural tilt & hole deviation (flattening) and fluid content. Subdivision in multiple sections. Static image (each colour is equally represented). Voltage compensation?

Net/gross & bed thickness analysis

Calibration against petrophys. logs and/or core.

Example applying two cut-off values. Shale = grey; Porous sand = yellow; Cemented sand = blue

Net/gross & bed thickness analysis

Sand thickness and net sand

Manual QC (lower limit ~5cm as distance between electrodes = 3cm)

Net/gross & bed thickness analysis

Corrected for structural tilt & borehole orientation

Net/gross & bed thickness analysis

Vuggy porosity / clast proportions

Neutron porosity used to evaluate total porosity. Sonic log used for determining micro-porosity (pressure wave passes vugs but is slowed down by open fracs). BUT - TNPH assumes homogeneous rock and picks up only part of the vugs (accidental orientation).

P-wave slowness

Vuggy porosity / clast proportions

Thresholding method often problematic or over-estimating.

Fracture cluster analysis … based on high-resolution image logs such as FMI, HMI, etc. Each fracture plane is described by type, relating to STYLE,

CONTINUITY and QUALITY as seen on the borehole image

Degree of fracturing is then described by: 1) Density (number of planes per meter) 2) Corrected density for borehole bias 3) Cluster subdivision Fracture porosity

Relative fracture permeability

Fracture cluster analysis

Fracture Clusters

Conductive fracture frequency

Resistive fracture frequency

S-N

projection

Conductive fracture strike/

stereogram

Resistive fracture strike/

stereogram

Quantification of fracture aperture from BHI

Three schools – 1) can’t be done (flexible); 2) fixed at mean value per fracture (type), calibrated against production testing; 3) Luthi&Souhaite method (Geophysics, 1990) =>

W= aperture, A= excess conductivity, Rm/Rx= mud res/flushed resist, and b & c are ‘fudge factors’ – all in all a linear function

L-S themselves mention a long list of requirements, some of which are: • only FMS (Static, Emex corrected – voltage current & gain) • constant lithology (Rx) over fracture length, • dip <45º rel.to well • perfect image quality, • fracs have to be planar, • b & c are tool and environment-dependant and poorly defined • In addition: no fracture crossing, full circumferential, edge effect…

Quantification of fracture aperture from BHI

Limitation due to tool type, log quality, borehole quality (throat chipping), current sucking…

Quantification of fracture aperture from BHI

Manual picking of large apparent fracture apertures (correction for orientation, edge effect etc.)

Quantification of fracture aperture

from BHI

Thresholding

Pollution of excess conductivity by conductive beds or artefacts

Quantification of fracture aperture from BHI

Counting of excess conductivity (fracture intersections/muddy beds)

Quantification of fracture aperture from BHI

Distribution of calculated fracture apertures (n=2166, range 0-7mm, mean=0.4mm)

Combined method: Subdivision into different fracture classes with fixed mean reference apertures (calibration to core…). Measuring excess conduct. over matrix. Correlation of manually picked thickness to excess conductivity (image independent). Correcting for current sucking (edge effect).

Fracture porosity

Summing up of fracture apertures per meter relative to matrix. Multiplied with a factor depending on apparent aperture & continuity. Max= ~3%

Estimation of relative fracture permeability if all stresses known (orientation & magnitude). Red=relative high permeability/sub-parallel to SHmax.

SHdir

Thanks to

&

Birger Hansen Bernd Ruehlicke

Carsten Vahle