Variable density display - Guide to Petrophysical Interpretation

Sonic/Acoustic

Units usec/ft usec/m usec/ft usec/m usec/ft usec/m

POROSITY

Wyllie Time-Average Equation:

cp Bcp = compaction correction, where

0 . 100 ≥1

=DTShale B_cp

The Bcp factor was added to the equation when it was found that the equation gave highly optimistic porosity values in unconsolidated sands. DTShale is picked from a shale near the zone of interest. The correction factor is never less than 1.0.

Raymer-Hunt-Gardner Equation (Schlumberger “Empirical Relation”):

The above equation is an approximation of Schlumberger chart Por-3.

Sonic/Acoustic

Like the Wyllie equation, Raymer-Hunt-Gardner is based on empirical data. It is non-linear in form, resulting in lower porosities than Wyllie for high DT, as in uncompacted sands. No compaction correction is needed.

The choice of which equation to use depends on the interpreter. If other porosity information is available, as from cores, choose the equation which best fits the supporting data.

The formation matrix traveltime, DTMa, is the acoustic traveltime of the formation at zero porosity.

Its value depends on the lithology of the formation (see the Characteristic Values, above). Since the Sonic log "sees" the formation close to the borehole, the fluid is assumed to be the drilling mud filtrate. The formation fluid traveltime, DTFl, varies somewhat with the salinity of the formation, but is usually assumed to be 189 usec/ft.

LITHOLOGY IDENTIFICATION

Lithology is determined by comparison of delta t with Neutron and Density data in crossplots, in Matrix Identification (MID) plots, and in M-N (A-K) plots. The charts may vary by Neutron tool type, Sonic response equation type, and by service company.

The ratio of shear to compressional DT may also be an indicator of gross lithology.

SYNTHETIC SEISMOGRAMS

Sonic compressional and Density data are used to determine acoustic impedance of the formations along the borehole, and reflection coefficients at bed boundaries. The synthetic seismic trace that is derived from that information can be displayed in depth or time to be compared to the seismic data.

The logs can also be modeled with varying fluid properties (and sometimes also with varying porosity), and synthetics calculated from the modeled curves, to help determine the response of the seismic data to the subsurface.

FORMATION MECHANICAL PROPERTIES

Compressional and shear sonic data are used with density data to calculate formation properties such as Poisson's ratio and Young's Modulus, and formation strength.

Formation strength calculations can be used to determine the mud weight range to be used while drilling to ensure borehole stability. Information on relative formation strengths supports the design of hydraulic fracturing so that fractures remain in the target formations instead of

extending to adjacent formations. Formation strength can also support predictions of drawdown pressures so that sand-free production can be maintained when a well is completed and produced.

DETECTION OF ABNORMAL FORMATION PRESSURES

Sonic traveltime values in shales are plotted against depth. Sharp deviations from a general trend of decreasing DT with depth indicate the presence of geopressured (overpressured) zones.

PERMEABILITY IDENTIFICATION

Attenuation of some of the later arrivals in the acoustic wavetrain (shear and Stoneley waves) gives some indication of permeability. The attenuation is, however, affected by other parameters, such as lithology. This technique is not well defined.

Sonic/Acoustic

CEMENT BOND QUALITY

Using specialized tools, the quality of the cement bond (cement to pipe and cement to formation) can be deduced by the attenuation of the acoustic signal. Essentially, the better the bonding, the more attenuation of the signal.

BOREHOLE SIZE

The hole size is produced by a caliper measurement associated with the centralizing equipment on the tool. Movement of the centralizer arms as changes in hole size are encountered are translated to a hole diameter and r

Sonic/Acoustic

Secondary Effects

ENVIRONMENTAL EFFECTS

Enlarged borehole, formation fractures, gas in the borehole or formation, or improper

centralization can produce signal attenuation resulting in "cycle skipping", or DT spikes to higher values.

Improper centralization, the lack of standoff, or excessive logging speed can result in "road noise", or DT spikes to either higher or lower values.

INTERPRETATION EFFECTS

Lithology effects are manifested in the necessity to chose a matrix traveltime (DTMa) value in order to calculate porosity.

Porosity calculations in uncompacted formations will yield porosity values higher than actual porosity when using the Wyllie equation. This can be accounted for through the use of the compaction factor, Bcp, in the Wyllie equation, or by use of the Raymer-Hunt-Gardner equation.

Porosity calculated in gas bearing zones will be slightly higher than actual porosity because the traveltime in gas is higher than in water.

Sonic/Acoustic

Environmental Corrections

This table indicates the corrections for the borehole and formation conditions that can be made for each logging measurement. The corrections that are applicable to the measurement are shown in bold.

CORRECTION COMMENTS borehole

mud weight bed thickness invasion mud cake borehole salinity formation salinity standoff

pressure temperature excavation propagation time attenuation lithology

Not all acquisition companies may have the correction indicated on this chart, or make corrections for all generations of the tool.

For newer logs, corrections may have been made at the time of data acquisition. Check the log header for information.

Algorithms which are equivalent to (or often better than) the chartbooks may be available from the acquisition company, or in some formation evaluation software packages.

Quality Control

There should be no spikes or interruptions in DT.

Check DT values in anhydrite (50 usec/ft), salt (67 usec/ft), or zones of known zero porosity.

DT = 57 usec/ft in casing.

For waveforms, the arriving signal of interest should not be saturated (truncated at its highest values) and should be apparent on the display.

Shale values should be similar to those in nearby wells.

Check repeatability; curves should have the same values and character as those from previous runs or repeat sections.

Cross-check the curve character with other curves from the same logging run.

Density

Interpretation Goals

Porosity (from bulk density, RHOB).

Lithology identification (from the PEF curve and/or with the Neutron and/or Sonic).

Gas indication (with the Neutron).

Synthetic seismograms (with the Sonic).

Formation mechanical properties (with the Sonic).

Clay content (shaliness) (with the Neutron).

Borehole size (from an attached caliper).

Density

Tool Diagram

Halliburton spectral density tool (SDL).

Physics of the Measurement

High energy gamma rays are emitted from a chemical source (usually Cesium 137) and interact with the electrons of the elements in the formation.

Two detectors in the tool count the number of returning gamma rays which are related to formation electron density. For most earth

materials of interest, the electron density is related to formation bulk density through a constant.

In newer spectral tools, the number of returning gamma rays at two different energy ranges are measured. The higher energy gamma rays (from Compton Scattering) determine bulk density, and therefore porosity, while the lower energy gamma rays (due to photoelectric effect) are used to determine formation lithology. The lower energy gamma rays are related to the lithology of the formation and show little dependence on porosity or fluid type.

Volume of Investigation

Vertical

*with enhanced resolution processing

Operational Constraints

The tool can be run:

open hole centered

cased hole¹ eccentered In a borehole fluid of:

gas or air

water or water-based mud oil or oil-based mud

Logging speed: 60 feet/minute. May require slower speeds for enhanced resolution processing.

Comments:

1Can be run in cased holes in special conditions.

Density

Measurement Names

Measurement names preceded by an asterisk (*) are not listed in current acquisition company literature, and may no longer be available, or are obsolete.

WIRELINE Mnemonic Baker Atlas

Advantage Porosity Logging Service APLS Compensated Z-Density ZDL Compensated Densilog CDL Computalog

Spectral Pe Density SPeD

*Spectral Litho Density, SLD; *Compensated Density, CDL Halliburton

Spectral Density Log SDL Gearhart

*Spectral Litho-Density, SDL; *Compensated Density Log, CDL Welex

*Spectral Density, SDL; *Compensated Density Log, DEN Reeves Wireline

Photo Density Sonde PDS Compact PhotoDensity MPD

*Compensated Density, CDS Schlumberger

Integrated Porosity Lithology IPL

*LithoDensity Log, LDT; *Compensated Formation Density Log, FDC Tucker Wireline

Compensated Density Tool CDT Lithology Density Tool LDT

MWD/LWD Baker Hughes INTEQ

Optimized Rotational Density ORD Modular Density/Lithology MDL Exlog

*(none) Teleco

*Modular Density Porosity, MDP Pathfinder

Density Neutron Standoff Caliper Tool DNSCM Density Neutron Caliper DNSC Schlumberger LWD (Anadrill)

Vision475 Sperry Sun

Azimuthal Stabilized Litho Density ASLD MWD Triple Combo

*Simultaneous Formation Density, SFD

Curves Displayed

(Curves are listed by generic name, common mnemonics (if any) and measurement units.)

Curve Name Mnemonics Units of Measurement

Bulk density RHOB, DEN, ZDEN g/cm3, kg/m3 Density porosity (referenced to a specific lithology) DPHI, PHID, DPOR %, v/v decimal Density correction DRHO g/cm3, kg/m3 Photoelectric effect (lithology indicator) PE, Pe, PEF b/e

Caliper (hole diameter) CALI, CAL Inches, cm

Density Density

Log Example

Density

RhoFl = ρ_fl = fluid density (often assumed to be mud filtrate density)

LITHOLOGY IDENTIFICATION

Lithology is determined by comparison of bulk density with Sonic and Neutron data in crossplots, in Matrix Identification (MID) plots, and in M-N (A-K) plots. The charts may vary by Neutron tool type, Sonic response equation type, and by service company.

The photoelectric effect (PEF) curve can be used alone to determine a single lithology, or in combination with bulk density, or bulk density and Neutron curves to determine mixed lithologies.

GAS INDICATION

Gas is indicated when the Density and Neutron "crossover"; that is, when the neutron porosity is less than the density porosity in a porous and permeable zone. Both curves must be corrected to the lithology of the zone of interest. Similar crossover may occur as part of a lithology effect, as when both the Density and Neutron tools are recorded on limestone matrix, and the lithology is actually a sandstone.

SYNTHETIC SEISMOGRAMS

Density

FORMATION MECHANICAL PROPERTIES

Compressional and shear sonic data are used with density data to calculate formation properties such as Poisson's ratio and Young's Modulus, and formation strength.

extending to adjacent formations. Formation strength can also support predictions of drawdown pressures so that sand-free production can be maintained when a well is completed and produced.

CLAY CONTENT (SHALINESS)

Density and Neutron data are crossplotted, and a shale point identified on the plot (generally from associated Gamma Ray data). The distance between the shale point and a clean formation line is a measure of the clay content of an individual zone, with the shaliness relationship assumed to be a linear function of that distance.

BOREHOLE SIZE

A mechanical arm opposite the sensors and source hold the density tool against the borehole wall. Movement of the arm is calibrated to indicate hole diameter. Because of tool design, the tool will tend to measure the longest diameter of the hole when the hole is elongated.

Density

Secondary Effects

ENVIRONMENTAL EFFECTS

Enlarged borehole (>9 inches): RHOB < formation bulk density (DPHI > PHIactual).

Rough hole: RHOB < formation bulk density (DPHI > PHIactual). This is due to the sensor pad losing contact with the borehole wall. Other indications of a rough hole will be a highly variable Caliper curve, and a high-valued density correction (DRHO) curve. There are no environmental corrections than can be applied to correct for loss of pad contact.

Barite muds: RHOB > formation bulk density (DPHI < PHIactual), and PEF > PEFactual.

INTERPRETATION EFFECTS

Lithology: The porosity calculated from bulk density will be affected by the choice of matrix density, RhoMa, which varies with lithology. In dense formations, such as anhydrite, the density porosity will be negative because the assumed matrix density is less than the actual formation matrix density.

Fluid content: The porosity calculated from bulk density will be affected by the choice of fluid density, RhoFl, which varies with fluid type and salinity. In routine calculations the zone investigated by the density tool is assumed to be completely saturated with mud filtrate.

Hydrocarbons: The presence of gas or "light" hydrocarbons in the pore space investigated by the Density tool causes the calculated value of density porosity to be more than the actual porosity.

This is most noticeable in the presence of gas, causing "crossover" of the Neutron porosity and Density porosity curves, where the Neutron log values are lower than the Density log values.

In all the cases above, the bulk density value, RHOB, derived from the tool is correct, but the calculated Density porosity is erroneous because of differences between the assumed matrix and/or fluid density values and the actual densities in the formation.

Density

Environmental Corrections

Not all acquisition companies may have the correction indicated on this chart, or make corrections for all generations of the tool.

For newer logs, corrections may have been made at the time of data acquisition. Check the log header for information.

Algorithms which are equivalent to (or often better than) the chartbooks may be available from the acquisition company, or in some formation evaluation software packages.

Quality Control

Density porosity should equal Neutron porosity in clean, wet formations, when both are properly corrected for lithology.

The correction curve, DRHO, should be near zero in smooth holes.

• DRHO values deviating by more than 0.05 may be questionable due to loss of pad contact.

• DRHO values deviating by more than 0.10 indicate the density value is not quantitatively reliable.

• The DRHO value will be negative in heavy muds (e.g. barite muds).

• Continuously large DRHO values in a smooth borehole may indicate excessive pad wear (density readings could be questionable), or other problems.

• Large DRHO values opposite an apparently smooth borehole wall may indicate fractures (or other small irregularities at the wall surface).

PE will not be reliable in heavy muds, and will show values well over 5.

Shale values should be similar to those in nearby wells.

Check repeatability; curves should have the same values and character as those from previous runs or repeat sections.

Cross-check the curve character with other curves from the same logging run.

Neutron

Interpretation Goals

Porosity (displayed directly on the log).

Lithology identification (with the Sonic and/or Density).

Gas indication (with the Density).

Clay content (shaliness) (with the Density).

Correlation; especially in cased holes.

Neutron

Tool Diagram

Halliburton neutron tool (DSN-II).

Physics of the Measurement

A chemical source (Americium-Beryllium) emits high energy neutrons which are slowed by formation nuclei. Two detectors in the tool count the number of returning capture gamma rays or neutrons (depending on the type of tool). The detector count rates are inversely proportional to the amount of hydrogen in the formation ("hydrogen index"). By assuming that all the hydrogen resides in the pore space of the formation (as water or hydrocarbons), the hydrogen index can be related to the formation porosity. "Gamma ray-neutron"

tools detect gamma rays and thermal neutrons;

"sidewall" tools detect epithermal neutrons;

"compensated" tools detect thermal neutrons.

Schlumberger offers a neutron tool which uses an accelerator to generate neutrons, eliminating the need for a chemical source. This minimizes safety issues on the rig floor and in the event the tool is lost in the hole.

Volume of Investigation

Vertical

*with enhanced resolution processing

Operational Constraints

The tool can be run:

open hole centered cased hole eccentered In a borehole fluid of:

gas or air

water or water-based mud oil or oil-based mud

Logging speed: 60 feet/minute. May require slower speeds for enhanced resolution processing.

Comments:

Neutron

Measurement Names

Measurement names preceded by an asterisk (*) are not listed in current acquisition company literature, and may no longer be available, or are obsolete.

WIRELINE Mnemonic Baker Atlas

Compensated Neutron Log CN *Sidewall Epithermal Neutron Log, SWN; Neutron Log, NEU

Computalog

Compensated Neutron Service CNS

*Sidewall Neutron Log, SNL Halliburton

Dual-Spaced Neutron II DSN II Dual-Spaced Epithermal Neutron DSEN Gearhart

*Compensated Neutron Log, CNS; *Sidewall Neutron Log, SNL; *Neutron Log, NL Welex

Dual Spaced Neutron II, DSN II; Dual Spaced Neutron, DSN; *Sidewall Neutron, SWN;

*Neutron, NEU

*Compensated Neutron Log, CNL; *Sidewall Neutron Log, SNP; *Gamma Ray-Neutron Tool, GNT

Tucker Wireline

Compensated Neutron Tool CNT

MWD/LWD Mnemonic Baker Hughes INTEQ

Caliper Corrected Neutron CCN Modular Neutron Porosity MNP Exlog

*(none) Teleco

Modular Nuclear Porosity, MNP Pathfinder

Density Neutron Caliper DNSC Schlumberger LWD (Anadrill)

Vision475

*Compensated Neutron Density, CDN Sperry Sun

Compensated Thermal Neutron CTN MWD Triple Combo

Compensated Neutron Porosity CNφ

Curves Displayed

(Curves are listed by generic name, common mnemonics (if any) and measurement units.)

Curve Name Mnemonics Units of Measurement

Neutron porosity (referenced to a specific lithology) NPHI, PHIN, NPOR %, v/v decimal For older (GNT) tools, Counts Counts/second, API

Neutron units

Neutron Neutron

Log Example

Neutron

Interpretation Details

CHARACTERISTIC VALUES:

These values are for Schlumberger CNL tools, with NPHI curve mnemonic (not TNPH), with lithology referenced to LIMESTONE. Values will change with logging company and tool vintage (type).

Matrix Value Fluid Value

Sandstone -0.02 -2

Except for the obsolete "Gamma Ray Neutron" tools, Neutron porosity is calculated by the acquisition software and is displayed directly on the log. This porosity is referenced to a specific lithology, usually limestone. Corrections to the porosity to account for the lithology actually present can be done through charts or appropriate algorithms.

NOTE: It is important to use the chart or algorithm for the correct Neutron tool and acquisition company. Each tool has a unique lithologic response, and use of the wrong algorithm will result in erroneous porosity estimation.

The older "gamma ray-neutron" tools will show response in counts per second or API Units on a linear scale. The neutron count rate (or API value) decreases with increasing porosity. In these displays, increasing porosity is shown by movement of the curve to the left of the scale (just like for the newer tools which display porosity directly). These values can be converted to porosity through calibration to core data, or by rules of thumb which approximate the response. The core calibration and rules of thumb tend to apply only to specific reservoirs or over limited geographic areas.

All Neutron tools can be run in cased holes to determine formation porosity. Corrections must be made for the presence of casing and cement.

LITHOLOGY IDENTIFICATION

Lithology is determined by comparison of neutron porosity with Sonic and Density data in crossplots, in Matrix Identification (MID) plots, and in M-N (A-K) plots. The charts may vary by Neutron tool type, Sonic response equation type, and by service company.

GAS INDICATION

Neutron

CLAY CONTENT (SHALINESS)

Density and Neutron data are plotted, and a shale point identified on the plot (generally from associated Gamma Ray data). The distance between the shale point and a clean formation line

In document Guide to Petrophysical Interpretation (Page 37-58)