CHAPTER TWENTY-FIVE: SEISMIC PETROPHYSICS 5
VSP, AVO, and Porosity/Lithology

Table of Contents
25.00: Introduction To This Chapter
25.01 Vertical Seismic Profiles On Wireline
25.02 Vertical Seismic Profiles While Drilling
25.03 Case Histories: Vertical Seismic Profiles
25.04: Amplitude Versus Offset (AVO)
25.05: Case Histories: Amplitude Versus Offset
25.06: Porosity/Lithology From Shear Seismic
25.07: Case Histories: Porosity/Lithology
25.08: In Conclusion
25.09: Exercises for Chapter Twenty-Five
25.10: Bibliography for Chapter Twenty-Five

Continue to Chapter Twenty-Six

Publication History: This Chapter formed part of Chapter Ten of Volume Two of The Log Analysis Handbook, a self published series of course notes covering geological and geophysical aspects of log analysis. First published in 1978, revised 1985, 1993. Completely revised and reorganized for this electronic edition Sep 2002.

CHAPTER TWENTY-FIVE: SEISMIC PETROPHYSICS 5
VSP, AVO, and Porosity/Lithology

25.00 Introduction To This Chapter
This Chapter continues the discussion of Seismic Petrophysics with explanations and case histories of vertical seismic profiles, amplitude versus offset studies, and porosity/lithology interpretation. These are mainly the activities of geophysicists and seismic interpreters, but log data of the kinds described in Chapter Twenty-One are often used to calibrate or aid interpretation. Petrophysicists and geophysicists should both have a basic understanding of these techniques, so some brief description of these seismic techniques are included to bridge the gap between the two disciplines.

Calibration of seismic attributes to ground truth is still an emerging science. No single attribute (eg. amplitude, frequency content, attenuation, compressional or shear velocity, or acoustic impedance) can be related directly to a specific rock property (eg. porosity, lithology, hydrocarbons). However, geoscientists have found that one or more attributes may predict some reservoir property in a particular project. Trial and error is the only way to find out what works.

One of the most successful is the use of Poisson's Ratio to indicate the presence of porosity or gas. This requires close calibration to log data - many early studies obtained impossible numbers for Poisson's ratio, indicating poor quality inversion of the compressional or shear data into velocity. A successful example is shown later in this Chapter.

When attributes are used to locate hydrocarbons, they are often called direct hydrocarbon indicators or (DHI). Bright spots and dim spots (amplitude anomalies on conventional seismic displays) were the earliest form of DHI. Many bright spot studies failed because many different factors create the amplitude variation. Log modeling as described in Chapter Twenty-One will show what kind of amplitude to expect for different reservoir conditions.

DHI is no longer a popular term because hydrocarbon indicators are really porosity or lithology indicators, with a major contribution from gas if it is present. The difference in acoustic and density properties between oil and water is very small and well below the noise level of even the best logs, let alone seismic.

The same story is true of amplitude versus offset (AVO) anomalies. Models are the only way to see what a particular AVO output might mean. Examples are shown below.

25.01 Vertical Seismic Profiles On Wireline
Normal seismic sections are recorded by moving the detectors (geophones) and seismic source horizontally along the ground or, in marine surveys, near the surface of the water. Vertical seismic profiles, as the name suggests, are run vertically in a wellbore to obtain detailed seismic response near the wellbore. After correcting for the very different geometry of such a survey, the results are presented in seismic section format. They can be correlated with conventional seismic data and with synthetic seismograms made from the sonic and density logs in the same wellbore.

Because the survey is taken in a wellbore, it is considered to be part of the well logging process and is often run by logging service companies after the more conventional logs and seismic reference survey are completed. In many cases, the VSP replaces the checkshot survey because, if properly designed, the same information can be extracted from VSP records as from SRS records.

Since the geophones are down the hole, surface distortions which affect conventional seismic are reduced. This comparatively noise free environment means that the VSP traces are less noisy than a synthetic seismogram made from unedited sonic and density logs. It may even be better than a well edited synthetic because no lithology, wavelet, or filtering assumptions have to be made by the analyst. As a result, VSP's have gradually replaced the synthetic seismogram. There are other advantages, such as being able to see laterally in 3-D around the borehole as well as below the bottom of the well. A well can be sidetracked toward its target based on interpretation of unexpected changes in lithology or structure observed on the VSP.

Integrated sonic logs are still needed to fix the precise location of formation tops on the VSP wiggle traces.

The technique records both down going and up going seismic signals (Figure 25.01) simultaneously and these must be separated by suitable data processing. This extra information helps to determine the acoustic response of the earth and therefore the lithology near the borehole.

FIGURE 25.01: VSP geometry and schematic of up- and down-going reflections

The processing sequence is as follows:

1. shot selection to eliminate dead or noisy traces

2. trace editing to mute early arrivals

3. consistency check of surface geophone signal

4. stacking of shots taken at the same level

5. bandpass filter to reduce noise and aliasing

6. f-k filter to eliminate tube waves

7. amplitude recovery

8. down going signal alignment

9. velocity filtering to separate down going from up going components

10. predictive deconvolution to remove multiple reflections

11. autocorrelation to check multiple removal

12. automatic gain control

13. time variant filtering to match conventional seismic section

14. corridor stacking to sum all the up going waves

This sequence and some of the intermediate results are shown in Figure 25.02. Some of these operations, such as stacking, band pass filter, and deconvolution can be done in the computerized logging truck at the well site.

FIGURE 25.02: VSP processing sequence and intermediate results

Creation of a seismic inversion trace or Seislog from this data is considerably more effective than with conventional seismic because of the broad frequency content and low noise level of vertical seismic data (Figure 25.03). In addition, the final processed trace at the wellbore is reasonably noise free, which sometimes eliminates the need to create a synthetic seismic trace, and thus reduces the need for log editing and reduces the chance of formation mis-ties.

FIGURE 25.03: VSP, synthetic seismogram, inverted VSP, and original sonic log

A synthetic VSP can be made, much in the same way as a synthetic seismogram, and used to model various noise free alternative interpretations, from which the correct interpretation or further processing steps might be chosen. Both shear and compressional VSP's can be recorded and modeled. The software is moderately complicated due to the radial geometry and the need to track both up- and down-going signals and their multiples.

Cased hole VSP's are a valuable aid in evaluation of older wells. Along with cased hole log analysis for porosity, saturation, and lithology, they provide almost as much information as can be obtained from an open hole evaluation. A comparison of open and cased hole VSP's is provided in Figure 25.04.

FIGURE 25.04: Open and cased hole VSP comparison

25.02 Vertical Seismic Profiles While Drilling
A vertical seismic profile can be created by lowering a geophone into the wellbore and using surface energy sources, as described above. A measurement while drilling technique, commonly called a TOMEX survey, uses the vibrations from the drill bit as a downhole energy source, using surface geophones to record the signal. The significant advantages include broader spatial coverage, easier access to rugged terrain, and much more detailed recording versus depth in the borehole. Multiple offset and radial 3-D surveys are much cheaper with TOMEX than with wireline VSP.

The continuous signals from the drill bit are transformed into VSP displays using cross correlation and deconvolution. The energy source signature is obtained by continuously recording the vibrations on the drill pipe. The time lag for the reference signal to travel up the pipe is calculated from the length of the pipe and the velocity of sound in steel. Cross correlation is used to define the signature in the same way as for Vibroseis sources.

Deconvolution of the recorded geophone traces with this signature produces the seismic traces. Traces are stacked continuously as drilling proceeds and an output trace is generated every 10 feet of drilled depth. By taking into account the geometry of the drill bit and geophone locations, the VSP section can be displayed. Data quality is comparable to conventional VSP data, as shown in the comparative example in Figure 25.05. Rig noise can sometimes be a problem, but it can usually be cured.

FIGURE 25.05: VSP while drilling

The geometry of the system is shown in Figure 25.06 (top) and the deconvolved traces versus depth in Figure 25.06 (bottom). Because of the close spacing, a very accurate time - depth plot can be created (Figure 25.07). This allows continuous calculation of an interval velocity log, equivalent to a sonic log filtered over a ten foot span.

FIGURE 25.06: VSP while drilling - geometry and recorded traces after deconvolution

FIGURE 25.07: Time - depth plot from VSP while drilling

25.03 Case Histories: Vertical Seismic Profiles
Figures 25.08 and 25.09: VSP in Faulted Section
Example shows VSP, dipmeter, and synthetic traces from sonic and density logs. Note the clear evidence of a fault on the dipmeter, which helps to explain why the log traces and VSP inversion do not tie.

FIGURE 25.08: Dipmeter with fault

FIGURE 25.09: VSP, sonic, and inversion with fault

Figure 25.10: VSP in Overpressured Section
Example shows seismic section and VSP overlay. Overpressure indications on VSP inversion trace predict required mud weights and potential drilling difficulty. Sonic and density trace from logs in final hole confirm the presence of overpressure at the same depth as the VSP prediction.

FIGURE 25.10: VSP used to predict top of overpressure zone

Figures 25.11 to 25.13: VSP in Deviated and Horizontal Hole
Example shows original seismic section and VSP with time scale gamma ray logs from two wells. Gamma ray defines sands of interest. VSP shows major fault through sand. This fault and others are drawn on a reprocessed, migrated seismic section, along with tracks of development wells. Gamma ray profile on each well again defines the sands. Finally a blowup of the seismic inversion section over the sand shows track of horizontal hole. The wellbore track is shown black where measurement while drilling gamma ray log indicated shale and white for sands.

Figure 25.13 has the original seismic map with dome shaped, faulted interpretation. Final map gives an entirely different picture of en-echelon faults. Future drilling will be greatly influenced by this change in the prospect orientation and shape.

FIGURE 25.11: VSP with gamma ray logs

FIGURE 25.12: Inverted VSP with well tracks and GR logs

FIGURE 25.13: Original interpretation (left), new interpretation (right)

25.04 Amplitude Versus Offset (AVO)
A technique used to differentiate seismic reflection events caused by lithology changes from those caused by fluid changes is called amplitude versus offset, or AVO, processing. The effect is caused by the fact that the reflected energy depends not only on the acoustic impedance but also on the angle of incidence of the reflecting energy.

The contribution of this second effect is often ascribed to the difference between Poisson's ratio of the layers. However, the equations clearly show the cause to be the difference in compressional velocities:

For vertical or non-vertical incidence:
_____1: K = (Vavg - Vo) / DEPTH
_____2: ANGLE = Arctan ((DEPTH * X + Vo * X/K)/(DEPTH^2 + 2*Vo*DEPTH / K - X^2 / 4))
_____3: Vrat = Vc2 / Vc1
__OR 3a: Vrat = DELTc1 / DELTc2
_____4: Drat = DENS2 / DENS1
_____5: C = (Vrat^2 + (1 - Vrat^2) / (Cos(ANGLE))^2) ^ 0.5
_____6: Refl = (1 - Vrat * Drat * C) / (1 + Vrat * Drat * C)

C = 1 for vertical incidence.

Poisson's ratio has the same contrast as compressional velocity when a liquid is replaced by a gas saturation. This is true because Poisson's ratio is a function of compressional to shear velocity ratio, and shear velocity doesn't change much with changes in fluid content.

The net result is the same, no matter how it is described. For constant Poisson's ratio above and below a boundary, amplitude decreases with offset as shown in the top left of Figure 25.14. If the upper layer has a higher Poisson's ratio than the lower, positive peaks decrease in amplitude and could go negative, while negative peaks get larger. The reverse takes place when Poisson's ratio contrast is reversed (Figure 25.14 right).

FIGURE 25.14: Amplitude versus offset schematic

There are other causes of amplitude versus offset variations:
1. source directivity and array effects
2. receiver arrays
3. near surface velocity variations
4. geometrical spreading
5. propagation loss of high frequencies (earth filtering)
6. dispersive phase distortion
7. velocity anisotropy
8. waveform interference (thin beds)
9. short period multiple interference
10. reflector curvature
11. processing effects (moveout stretch, time variant scaling, etc.)

Some adequate accounting or control must be given for each of these effects in order to relate the remaining amplitude variation to reflectivity changes. Model studies are an essential element in deciding if these other effects have been properly corrected. Synthetic seismograms made this way will show the effects of amplitude versus offset. The conventional synthetic seismogram might tie the near trace data, but should not be expected to always agree well with the stacked data or the far trace data.

25.05 Amplitude Versus Offset Case History
An AVO model and case history is shown in Figures 25.15 to 25.17 for a Cretaceous Glauconitic channel sand.

FIGURE 25.15: AVO models (wet, gas, shale) and real data

FIGURE 25.16: AVO models (oil, gas, shale) and real data

FIGURE 25.17: AVO model, seismic section, and final interpretation map

25.06 Porosity/Lithology From Shear Seismic
Complex transmission and mode conversion phenomena occur at the interface between two media, as compressional or shear wave energy passes through it. As shown at the bottom of Figure 25.18, when a compressional wave strikes an interface, the incident energy is distributed over four distinct waves:
1. transmitted compressional wave, Pt
2. reflected compressional wave. Pr
3. converted transmitted shear wave, PSt
4. converted reflected shear wave, PSr

FIGURE 25.18: Reflected and transmitted wave modes

The amplitude of each of these components versus incidence angle is shown in the top of Figure 25.29. Notice the dramatic change in reflected energy at angles above the critical angle.

If an S-wave reaches the interface, converted S-waves, SPt and SPr, are also created. For seismic surveys, SH is the component of the shear wave (SPr) perpendicular to the vertical plane containing the seismic line. SV is the component in the plane. The direction of particle motion for the various modes is shown in Figure 25.19.

FIGURE 25.19: Reflected and transmitted wave modes

When SH is in the interface plane, there is no conversion of SH-waves into P- and SV-waves and inversely. This is why SH seismic records are more simple as a rule than the P or SV records.

Interference from shear waves on conventional CDP seismic stacking is avoided by adequate velocity analysis, since shear waves are much slower than compressional and have much higher normal moveout. The typical velocity regime is shown in Figure 25.20.

FIGURE 25.20: Shear amplitude and velocity

By suitably gathering and velocity filtering seismic traces, the compressional and shear arrivals can be separated from each other. The interval velocity from compressional and shear sections can be computed from the stacking velocity of each. Poisson's ratio can be computed and displayed from:
_____1: PR = ((Vc / Vs)^2 - 2) / (2 * (Vc / Vs)^2 - 1)

The elastic properties of rocks, such as Poisson's Ratio, are covered in detail in Chapter Twenty.

25.07 Porosity/Lithology Case History
The displays in Figures 25.21 through 25.23 demonstrate this technique. A standard compressional seismic section is shown in the first illustration. The color code represents compressional interval velocity, determined from detailed velocity analysis. It can also be found from seismic inversion as described earlier. The shear wave seismic section is first stretched so that all reflections are displayed at compressional arrival times, then it is color coded to display shear interval velocity. The discreet interval velocity data is transformed into Poisson's ratio by the above equation and presented as a cross section, color coded in steps of Poisson's ratio.

FIGURE 25.21: Compressional wave inverted velocity section

FIGURE 25.22: Shear wave inverted velocity section

FIGURE 25.23: Poisson's ratio seismic section

The light yellow color on the final plot probably indicates a gas sand which is not directly visible on either the seismic amplitude or velocity displays. Control of seismically derived Poisson's ratio data by comparison to well logs is complicated by the fact that the sonic and density log data is affected by mud filtrate invasion into gas zones. Thus the logs must be modeled for this effect before they can be used, as described in Chapter Twenty-One. This type of log modeling is called fluid replacement and is best accomplished using the log response equation.

A handy chart for determining lithology directly from Vc and Vs is shown below:

FIGURE 25.24: Lithology from shear and compressional velocity

The following illustration shows a porosity study based on inversion and calibration of porosity to the inverted acoustic impedance curves. Seismic shear data was not required for this work, but it would be helpful in a similar study in carbonate reservoirs.

FIGURE 25.25: Sand - shale porosity analysis from inverted acoustic impedance calibrated to well log data

Determining which attribute or combination of attributes will correlate to reservoir properties may require some trial and error testing. There are more than 20 possible attributes and their permutations and combinations can be quite large. The usual choices are Vp/Vs, Poisson's ratio, instantaneous compressional amplitude, compressional/shear amplitude ratio, and other related combinations. In all cases, log modeling and quantitative log analysis will be required to control the inversions and attribute calibration.

25.08 In Conclusion
We have come full circle. We started with elastic properties of rocks in Chapter Twenty and ended with them here in Chapter Twenty-Five. In between, we covered modeling/editing logs for seismic purposes, synthetic seismograms, seismic inversion and synthetic sonic logs, and finally VSP, AVO, and porosity/ lithology interpretation.

There are many connecting links between the seismic and well logging domains. Both develop velocity, density, and lithologic relationships from their measured data. A synthetic view of seismic response can be made from well logs, as can the inverse process create a sonic log from seismic data. A clear understanding of the sources and definitions of acoustic velocity information, and the ability to communicate these differences, will go a long way toward integrating exploration and evaluation techniques.

Analysis and interpretation of this diverse suite of data leads to a petrophysical description of the reservoir. In many cases, rock and fluid properties can be inferred and mapped. When calibrated to "ground truth", meaningful exploration and development decisions can be made with less risk. However, if the calibration is not attempted or done poorly, the results are mere arm-waving that may increase the chance of failure.

Do the work. Integrate the geoscience disciplines. Check your work. You'll be a happy puppy after it's all over.

25.09 Exercises for Chapter Twenty-Five
1. Describe how lithology is derived from seismic data. (10 marks)

2. Explain why reflection amplitude might vary with offset. (10 marks)

3. Describe the processing sequence involved in obtaining the final VSP display (10 marks)

4. Choose one of the Case Histories. Write a brief report covering the available input data, the steps taken to create the various outputs, the purpose for producing each output, and an interpretation of what these results show us. (20 marks)

5. Based on the computed log analyses in the following illustration, explain the reflection amplitude differences between Well A and B, and between Well A and C. (25 marks)

FIGURE 25X.05: VSP models for Exercise 25.05

6. On the following illustration, which model best matches the field data? What features of the models influence your decision? (25 marks)

FIGURE 25X.06: AVO models for Exercise 25.06

25.10: Bibliography for Chapter Twenty-Five
VERTICAL SEISMIC PROFILES

1: How the sonic log is used to enhance the seismic reference service velocity survey; Boss, F.E.; Canadian Well Logging Society Journal, v. 3, no. 1, 1970

2: The Schlumberger well seismic tool; Schlumberger; Handbook, 13 p., 1975

3: Well log editing in support of detailed seismic studies; Ausburn,B.E.; Society of Professional Well Log Analysts 18th Annual Logging Symposium, 38 p., 1977

4: Seismic applications of well logs; Dupal,L., Gartner,J., Vivet,B.; 5th European Logging Symposium, 13 p., 1977

5: The use of interlog relationships for geological and geophysical evaluations; McCoy,R.L., Smith,R.F.; Society of Professional Well Log Analysts 20th Annual Logging Symposium, 11 p., 1979

6: Vertical seismic profiling; Mons,F., Babour,K.; Schlumberger Wireline Atlantic, 16 p., 1981

7: Vertical seismic profiling; Birdwell Wireline; Brochure, 8 p., 1983

8: Interpretation aspects of offshore VSP data; Poster,C.K.; 15th Annual Offshore Technology Conference, 8 p., 1983

9: Acquisition and processing of Gulf Coast VSP data; Landgren,K.M., Grubb,K.; 15th Annual Offshore Technology Conference, 8 p., 1983

10: Inversion of vertical seismic profiles by iterative modeling; Grivelet,P.A.; 53rd SEG Symposium, 18 p., 1983

11: Results from open hole and cased hole vertical seismic profiles; Lewkowicz,J.F., Reischman,R., Walsh,J.J.; Society of Professional Well Log Analysts 24th Annual Logging Symposium, 13 p., 1983

12: Seismic logging services; Atlas Wireline; Brochure, 8 p., 1984

13: Well seismic techniques; Schlumberger; Handbook, 24 p., 1985

14: Seismic inversion of vertical seismic profile data for predicting abnormal pressure beyond TD; Shapiro,B.E., Pampeli,E.G.; 17th Annual Offshore Technology Conference, 4 p., 1985

15: Prediction of formation depths and velocities from WSP data using a linear calibration method; Conn,P.J., Nelson,C.M.; Society of Professional Well Log Analysts 26th Annual Logging Symposium, 19 p., 1985

16: Using structural dynamic analysis to improve the design of seismic logging tools; Carr,R., Powell,C.; 10th Canadian Well Logging Society, 12 p., 1985

17: Schlumberger well seismic; Schlumberger; Brochure, 4 p., 1986

18: Crosswell acoustic surveying of gas sands: traveltime pattern recognition, seismic Q, and channel waves; Albright,J.N., Johnson,P.A.; Society of Professional Well Log Analysts 26th Annual Logging Symposium, 19 p., 1986

19: Analysis of the applications of the VSP; Angeleri,G.P., Joli,F.; Society of Professional Well Log Analysts 27th Annual Logging Symposium, 19 p., 1986

20: Interval velocity analysis from VSP surveys; Justice,J.H.; The Journal of Canadian Petroleum Technology, v. 22, no. 1, p. 33-43, 1986

21: Tomography based imaging of a heavy oil reservoir using well logs, VSP and 3D seismic data; Stewart,R.R., Chiu,S.K.L.; The Journal of Canadian Petroleum Technology, v. 22, no. 1, p. 73-86, 1986

22: Seismic acquisition tool; Schlumberger; Manual, 34 p., 1986

23: Acquisition techniques in crosshole seismic surveys; Delvaux,J., Nicoletis,L., Dutzer,J.F.; 62nd Annual Technical Conference of Society of Petroleum Engineers, p. 413-419, 1987

24: Experimental verification of acoustic waveform and vertical seismic profile measurements of fracture permeability; Paillet,F., Hsieh,P., Cheng,C.H.; Society of Professional Well Log Analysts 28th Annual Logging Symposium, 21 p., 1987

25: Tomographic imaging of a heavy oil reservoir using well logs, VSP and 3D seismic; Stewart,R.R., Chiu,S.K.; Society of Professional Well Log Analysts 28th Annual Logging Symposium, 3 p., 1987

26: Reservoir description from seismic lithologic modeling; part 2: substantiation by reservoir simulation; deBuyl,M., Ullah,S., Guidish,T.; 62nd Annual Technical Conference of Society of Petroleum Engineers, p. 399-406, 1987

27: The successful characterization of a complex reservoir using 3-D seismic, geostatistical reservoir description and sponge core analysis Carr,L.A., Benteau,R.I., Corrigan,M.P., Van Doorne,G.G., 62nd Annual Technical Conference of Society of Petroleum Engineers, p. 385-398, 1987

28: Downhole seismic array; Schlumberger; Brochure, 4 p., 1988

29: VSP: where we are, where we are going; Hardage,B.A.; The Oil and Gas Journal, p. 91-94, 1988

30: Crosswell logging for acoustic impedance; Iverson,W.P.; Journal of Petroleum Technology, p. 75-82, 1988

31: Some interesting conclusions from a study of Q attenuation; Jain,S.; Journal of Canadian Society of Exploration Geologists, v. 22, no. 1, p. 17-32, 1988

32: Using the drill bit as a downhole seismic source for real time inverse VSP; Rector,J.W., Marion,B.P.; Western Atlas Seismic, 6 p., 1988

33: Results of a seismic transmission tomography survey at the Grimsel Rock laboratory; Gelbke,C., Miranda,F., Sattel,G.; Society of Professional Well Log Analysts: The Log Analyst, p. 243-260, 1989

34: Vertical seismic profiling; Computalog; Brochure, 3 p., 1991

AVO and Porosity/Lithology

1. Porosity identification using amplitude variations with offset in Jurassic carbonates offshore Nova Scotia; Harvey,P.J.;SEG Leading Edge,p. 180-184, Mar 1993

2. Seismic velocities in carbonate rocks; Wang,Z., Hirsche,W.K., Sedgwick,G.; JCPT, p. 112-122, Mar 1991

3. Taking advantage of shear waves; various authors; Oilfield Review, p. 52-54, Jul 1992

4. Just a bright spot?; Masuda,R.M.; CSEG Recorder, p. 6-11, Mar 1992

5: S wave velocity and poisson's ratio from shear waves observed in normal P wave data in an offshore basin; Jain,S.; Canadian Journal of Exploration Geophysics, v. 24, no. 1, p. 32-47, 1988

6: Shear waves and anisotropy in exploration seismology, McCormack,M.D., Tatham,R.H.; Registration Forms, 12 p., 1988

7: Exploration for porosity in carbonates: a synthetic based study; Fraser,D., Jain,S.; Canadian Journal of Exploration Geophysics, p. 141-152, 1988

8: Land seismic shear waves; Garotta,R.; Manual, 16 p., 1989

9: Amplitude versus offset; a practical interpretation tool: two case studies in south central Alberta, Canada; Martens,K.N., Goranson,H., Curts,B.; Canadian Society of Exploration Geologists, p. 3-14, 1989

10: Seismic modeling of fluid injection zones during enhanced oil recovery operations; Phadke,S., Kanasewich,E.R.; CSEG Recorder, p. 7-11, 1989

11: Detection of hydrocarbons in carbonate lithological packages using amplitude versus offset inversion of seismic data: a case history from Alberta, Canada; Miles,D.R., Gassaway,G.S., Brown,R.A., Bennet,L.E., Bainer,R.W.; CSEG Recorder, p. 8-16, 1989

12: The use of laboratory and in situ measurements of acoustic velocity for seismic modeling; Towle,G.H., Mueller,T.L., Whitman,W.W.; Canadian Well Logging Society Journal, p. 5-24, 1989

13: Seismic tool tracks subtle traps; Fritz,M.; American Association of Petroleum Geologists Explorer, p. 16-21, 1989

14: AVO analysis and complex attributes for a glauconitic gas sand bar; Chung,H.M., Lawton,D.C.; CSEG Recorder, v. 26, no. 1&2, p. 72-86, 1990

15: High resolution seismic survey to map paleochannels in an underground coalmine; Gochioco,L.M., Kelly,J.I.; Canadian Journal of Exploration Geophysics, v. 26, no. 1&2, p. 87-93, 1990

16: Seismic modeling of porosity within the Jurassic aged carbonate bank, offshore Nova Scotia; Harvey,P.J., MacDonald,D.J.; Canadian Journal of Exploration Geophysics, v. 26, no. 1&2, p. 72-86, 1990

ABOUT THE AUTHOR

E. R. (Ross) Crain, P.Eng. is a Consulting Petrophysicist and a Professional Engineer with over 35 years of experience in reservoir description, petrophysical analysis, and management. He has been a specialist in the integration of well log analysis and petrophysics with geophysical, geological, engineering, and simulation phases of oil and gas exploration and exploitation, with widespread Canadian and Overseas experience.

His textbook, "Crain's Petrophysical Handbook on CD-ROM" is widely used as a reference to practical log analysis. Mr. Crain is an Honourary Member and Past President of the Canadian Well Logging Society (CWLS), a Member of Society of Petrophysicists and Well Log Analysts (SPWLA), and a Registered Professional Engineer with Alberta Professional Engineers, Geologists and Geophysicists (APEGGA)