Net/gross and porosity based on borehole images. Dr Zbynek Veselovsky

Transcription

1 Net/gross and porosity based on borehole images Dr Zbynek Veselovsky

2 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.

3 Motivation

4 Borehole image interpretation

5 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?

6 Net/gross & bed thickness analysis Calibration against petrophys. logs and/or core.

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

8 Net/gross & bed thickness analysis

9 Sand thickness and net sand Manual QC (lower limit ~5cm as distance between electrodes = 3cm)

10 Net/gross & bed thickness analysis Corrected for structural tilt & borehole orientation

11 Net/gross & bed thickness analysis

12 Vuggy porosity / clast proportions P-wave slowness 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).

13 Vuggy porosity / clast proportions Thresholding method often problematic or over-estimating.

14 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

15 Fracture cluster analysis Fracture Clusters Conductive fracture frequency Resistive fracture frequency S-N projection Conductive fracture strike/ stereogram Resistive fracture strike/ stereogram

16 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

17 Quantification of fracture aperture from BHI Limitation due to tool type, log quality, borehole quality (throat chipping), current sucking

18 Quantification of fracture aperture from BHI Manual picking of large apparent fracture apertures (correction for orientation, edge effect etc.)

19 Quantification of fracture aperture from BHI Thresholding Pollution of excess conductivity by conductive beds or artefacts

20 Quantification of fracture aperture from BHI Counting of excess conductivity (fracture intersections/muddy beds)

21 Quantification of fracture aperture from BHI 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). Distribution of calculated fracture apertures (n=2166, range 0-7mm, mean=0.4mm) Correcting for current sucking (edge effect).

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

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

24 Thanks to & Birger Hansen Bernd Ruehlicke Carsten Vahle