top of page

Reflection seismic can be rich with SIGNAL!

Articles in the Interview Series for the GSH Journal feature one-to-one conversations with scientists to help connect individuals in the fast-paced global business of geoscience. In these interviews. we learn about the people that drive innovation and the science that inspires them. These interviews allow the reader to enrich their own careers with examples from others experiences.

Industry Expert Interview Series: Heloise Lynn

Heloise Lynn

Rene: When working fractured reservoir, there are additional techniques of using the data from a different perspective by sorting and process the data rather than the traditional offset and that it to sort and process the data by azimuth.

Often the question is not that the reservoir is fractured, but rather what is the orientation and density of the fractures, or aligned connected ribbons of porosity, to optimize drilling, completions or avoiding hazards. This interview will explore some considerations of getting more from the seismic data as we get to know an expert in the field of azimuthal, Heloise Lynn.

Heloise: Thank you, Rene, for contacting me to suggest an interview! This is definitely an honor, so grateful to be able to offer back some of the points I’ve picked up in 46 years of oil and gas reflection seismology!

I would like to start with an article for all geophysicists to consider: Where you sit governs what you see. (Lynn, CSEG Recorder, June 2003, Vol. 28. No. 6)

Although I originally wrote this article to explain shear wave splitting to geoscientists who were unfamiliar with it, it now appears useful to explain azimuthal seismic. Where you sit (where the receiver is, relative to the source), governs what you see (what is recorded). The azimuth of Source-Receiver is the most important human-imposed parameter for reflection seismic to me. That’s because I’ve seen so much azimuthal variation in the recorded seismic signature i.e. travel-time, velocity, amplitude, AVAaz, frequency, and one day, phase and Q.

The azimuth of the Source-to-Receiver defines the wavefront that tests the stiffness of the medium to the P wave particle displacement (the wavefront). In the stiff direction, the P wave travels faster. In the compliant direction, the P wave travels slower.

Figure 1 is P-P reflection data, one CIP (Common Image Point), top of reservoir, after anisotropic (VTI) PSDM processing. VTI is Transverse Isotropy with a Vertical Axis, describing the layered nature of the sediments.The figure shows that the traces when sorted strictly by offset have a greater and greater scatter with greater offset but, if the traces are first ordered by a limited-offset range, and then by azimuth, order is discerned. The order is the cosine 2 theta function, with the max and the min being 90° apart. This order is important so that data is not improperly processing removing fractured signal as noise.

Figure 1
Figure 1

The figure 2 is from the Oilfield Review, Summer 2014, page 36. I was a co-author of this article, “Land Seismic Surveys for Challenging Reservoirs, G. Busanello et al.” is another example of the difference in sorting data by azimuth rather than by offset yielding data that is ordered and coherent.

The azimuth of Source-Receiver was so often glossed over, at least in the old days, but now, more and more geophysicists are recognizing it as important. So today, interpretation includes knowing theacquisition parameters of dimensions of receiver patch, azimuth of R-line, azimuth of S-line, receiver spacing, source spacing, fold, processing sequence, etc.

Figure 2
Figure 2

Rene: You have had an amazing career in geophysics, but what got you most interested in the topic in the first place and encouraged you to study geophysics at Stanford?

Heloise: In 1975, Texaco hired me to process P-P reflection seismic data on 2D with 24-fold and dynamite sourced. I enjoyed this because I had worked earthquake seismic data during the summers of 1972-1974. The earthquake seismic data were recorded in the Los Angeles Basin using a seismometer array my father, Dan Bloxsom Jr., built and telemetered into our laboratory also known as the garage.

Dr. Jon Claerbout had just developed wave equation migration which truly changed the seismic industry. Texaco was a supporter of the Stanford Exploration Project and thus had access to Jon’s code. I remember the first time I sent a stack through migration: yes, sure enough, bow ties of synclines collapsed to gorgeous “true” synclines, dipping energy moved up-dip and sideways. By spring of 1976, I had decided to go to Stanford for my master’s degree, working in Jon Claerbout’s group. It was very clear that this was the number one place to be in 1976, if one were interested in a career in oil and gas reflection seismology.

Rene: What did you learn in your early career that built a foundation for your future career?

Heloise: In my early career 1980-1985, I worked for Amoco and British Petroleum in Houston. I witnessed evolving acquisition technology and increasing compute power driving our industry forward and still does! Takeaway tip for the readers: know how reflection data is acquired, go to the field, see the data acquired, be conversant with how the acquisition parameters are set or determined; know the current capabilities of state of the art processing codeas well as the assumptions and pre-requisites! Know how, or when, the earth does not comply with the assumptions and pre-requisites of the processing code. Process field data and see how it goes.

Rene: Reflection seismic can be rather simple -- compressional P wave, or P-P -- but knowing there are more complex seismic (or converted) waves such as P-S, S-P, S-S reflection waves, what subsurface conditions trigger the choice to use other reflection seismic modes?

Heloise: The subsurface conditions suitable for P-S, or S-P, or S-S are:

  1. Imaging through a gas cloud is one condition. Read “3D-9C seismic survey for direct S-wave processing and interpretation”, 2022, SEG Image, by Rui Zhang, Zhiwen Deng, Yuanyuan Ye, and Yan Wang. An excellent field data paper, showing the gas cloud trashing the P-P reflection image, but the S-S image is first rate. Figure 3, is from Zhang et al., 2022. Image D is the SS time map (accurate); but Image C of the PP time map shows the sags of the gas-filled porosities. I infer that prestack time migration was the imaging technique. “The gas cloud causes strong attenuation in the P-wave and lowers the velocity, which produces an artifact push-down structure.”

  2. Fractures or in-situ stress is a second condition. Actually, today we do this with azimuthal prestack P-P, but azimuthal P-S or S-P or S-S is also helpful.

  3. Lithology changes that impact rock mechanics: for example, sandstone versus shale. The Vp/Vs of sandstone is lower (~1.6), but the Vp/Vs of shale is higher (usually 1.95-2.2). Directly measuring the delta Ts in addition to directly measuring the delta Tp gives the Vp/Vs ratio and therefore a suggestion of the lithology.

Figure 3 (a) and (b)
Figure (c) and (d)
Figure 3

Lynn and Spitz (Lynn, H., and S. Spitz, 2006, Pau 2005, The Leading Edge, August 2006) published some of the outcomes of the Pau 2005 SEG-EAGE Summer Research Workshop, dedicated to multi-component seismic. Table 1 lists perceived geologic conditions wherein multi-component data can be used. What is of interest are the above 50 % risk reduction of proven techniques of adding PS data for identifying gas clouds,increasing reflectivity, clastic discrimination, and better multiple reduction.

Table 1
Table 1

Interestingly the S-P mode only requires vertical geophones. Bob Hardage’s proposal is that the P source (usually vibrators) emits enough S wave energy to travel down maybe 1000-3000 ft, depending upon where you are, and up-going mode conversions to P are recorded on the vertical geophones. Bob Hardage and his team have published impressive field data documentation of these assertions. Many of Bob’s publications on the topic are readily available on the internet.

For shallow targets, this technique of looking at converted waves should work quite well, provided of course that the recording times are 3 to 4 times the P-P reflection times of target.

Since the down going S-wave will split into two S-waves (fast, S1, and slow, S2), azimuthal S-P is predicted to have a striking effect. I predict that during the next 5 years, 3D azimuthal S-P, in conjunction with azimuthal P-P, for shallow targets, will be very cost effective, because no new acquisition is required. I would test various prestack depth migration algorithms that understand how to propagate a source down (using S velocity) and propagate a receiver down (using P velocity). Long records are necessary for this technique.

The P-S mode (P down, S up) requires 3-component geophones. Caution, don’t be playing this P-S game with 2-component sensors (geophones or accelerometers)!

The S-S mode requires S-wave vibrators plus 3-component sensors (either accelerometers or geophones). A 9Component-3D would have 3 components of sources (P, SH, SV), and 3 component receivers (geophones or accelerometers) deployed in a 3D sense, with full-azimuth full-offset (offsets equal or greater than target depths) data recorded. Recording times of 6 x P-P reflection time of target should be evaluated in the field, to determine the nature of the S-S reflections.

Rene: I can see your recommendation to use SP waves very timely recommendation for carbon capture (CC) industry and the caution to use 3C surveys for targets deeper than 3000’. What word of advice would you offer the CC industry?

Heloise: Since the CC industry desires to find aligned connected porosity into which can be pumped CO2, for long-term storage, full azimuth 1 component 3D surveys (PP azimuthal) or full azimuth 3 component 3D surveys (PP and SP azimuthal) can be tested to determine which is the more practical (“best bang for your buck”) reflection seismic method for your area.

Rene: What has been your favorite geophysical project in your career?

Heloise: I have several favorites: the Enervest Project in the Austin Chalk, where we worked together! The results of the study yielded some amazing results of azimuthal data aligning with the reservoir fractures. (Keller 2017)

The USA onshore fractured carbonate project, written up as Lynn and Goodway, published in Interpretation, 2020 shows an example of AVAaz is shown in figure 4. Limited azimuth gathers (from near angle to far angle) are shown, at 22.5 degree azimuthal increments. The AVAaz gradient changes by azimuth at the top of the fractured carbonate reservoir at the center highlighted by the red arrow. When the gradient changes, the Near Angle amplitude also changes.

Figure 4
Figure 4

In this project, I also compared seismic curvature attributes to the vector map (azimuthal seismic), and the microseismic data. (Lynn, 2015, SEG Exp. Abs., Azimuthal 3D seismic data, ISIP’s, and micro-seismic data evaluated for unconventional completions in a fractured carbonate reservoir; Lynn, 2018, SEG Exp. Abs. Curvature, azimuthal P-P interval velocity, and azimuthal prestack amplitudes in a naturally fractured carbonate oil reservoir). The curvature when viewed in section view can suggest which layers are held in extension and which in compression; the azimuthal seismic can show a characteristic signature for layers held in compression versus layers held in extension. Comparing these two measurements can be helpful.

Another favorite project: the azimuthal (18 azimuth sectors 0-360) RTM LSM pre-salt node survey project. The Lynn and Goodway (2020) assertions were confirmed.

Like a lone voice crying in the wilderness, I’m here to tell you, every gradient by azimuth has its Near Angle amplitude. Calculate both independently for each azimuth—let the data speak. For a given bin, for a given reflector, make a cross plot of the gradients versus theirNear Angle amplitudes. Think about what you see. You’ll see a straight-line: this is a compliance-by-azimuth effect (or you can call it an effective porosity by azimuth). I’ve seen this in datasets in basins around the world, acquired by every major contractor, as processed by (different) major contractors. If the formation of interest has aligned connected porosity that flow fluids and is thus bi-refringent, the AVA gradient will change by azimuth and so will the Near Angle (in the old days called “intercept”). The push back would be daunting for some, but all I do is stick to field data. Take a look. Tell me what you see in the data.

Actually, every field dataset I’ve worked has taught me something, so it’s rather hard to pick THE favorite!

Rene: Great to see your enthusiasm for science and your work. You have been fortunate to have a built-in processor with your husband Walt. What advice would you offer to today's interpreter about building a relationship with other geophysicists that acquire seismic and process seismic data?

Heloise: Very astute point – to have good relationships with acquisition and processing geophysicists. Our industry has definitely grown to the point where the team effort is needed – the engineer who must define the nature and challenges of getting the oil out of the ground, and the hazards thereof, especially depleted zones’ effects upon attempted drilling, the geologist who tells us about the rocks and their history and their stratigraphic setting, and so on, the geophysicists who assure the acquisition is successful, the processing appropriate for the interpretation goals, the interpreter,the petrophysicist, and all these folks trade information freely, no holding back! Whatever your task, be ready to share all the important points and as many ancillary points as your team mates will sit still to hear. Oh, and by the way, depleted zones can have azimuthal seismic signatures that are so different from virgin reservoir conditions. I’m looking to write an SEG Exp Abstract on this for 2023.

Rene: 1985 was a turning point for the Oil and Gas industry where many geophysicists lost jobs and other took the opportunity to start businesses. I believe that in1986 may have been an opportune year for you. Can you tell us about how working azimuthal problems became a business and a passion for you?

Heloise: Again, you are most perceptive!

1985 found our industry greatly stressed. As a consultant, my paying work vanished. Walt’s work at Western Geophysical R&D supported the family, while I rummaged around looking for seismic data that I could publish in Geophysics.

Very interesting S-wave VSPs recorded in the near surface (top 60 meters) in two different sites in the San Francisco Bay area were appropriate for S-wave splitting analysis. The near surface was documented to show in one location about 5% S-wave splitting [(VS1 – VS2) / VS1]; in the second locale, about 12% birefringence. (Lynn 1991)

Dr. Richard Bates, of Blackhawk Geosciences, read my paper, and reached out to inquire whether I would work with his company on some Department of Energy research projects. I agreed, and with Dr. Bates leading the team, we completed two azimuthal projects that gave rise to a lot of presentations and publications in the 1995-2000 time periods. David Decker reached out to hire me for a DOE project in the Rulison Field, Colorado, which was also published. Part of the DOE mandate was for technology transfer, so there were strong incentives to write it all down.

Rene: What azimuthal challenges have you encountered in seismic data?

Heloise: This question is a multiple response depending on the objective.

  • Onshore data. More heterogeneity in the “near surface” (top 1000 ft or so) is what we don’t like. As long as azimuthal PSDM (RTM, LSM, etc) is employed, we can usually sort everything out. What we don’t like is azimuthal PSTM.

  • Offshore data. What we like is the uniformity of the water layer! What we don’t like are the problems that the multiples cause.

  • Conventional drilling. The azimuthal challenge is in the team deciding whether in-situ stress or fractures affect bottom line production. Avoiding depletion zones is an “up and coming” azimuthal seismic application, in my opinion.

  • Unconventional drilling objectives.The azimuthal challenge is in convincing managers that azimuthal seismic can help with in-situ stress and natural fractures. Sadly, managers want “published confirmation success stories” yet so few seldom permit publication of their successful results (EnerVest is of course exempt from this criticism).

Additionally continual improvement in data processing algorithms, increased computer speeds, memory and storage have transformed azimuthal seismic as well as the rest of the industry. Steps we could only dream about inthe mid 1990s are now easily achievable, with enough money for acquisition and processing. However, the uplift in image quality and geologic insights more than justify the added costs and time for the results. To illustrate, in the mid 1990s, we knew we needed azimuthal prestack depth migration, but that was not possible. In 2023, azimuthal pre-stack depth migration imaging using preserved azimuths of 0-360 (North is 0, East is 90) is easily accomplished given the right budget. I recently worked a 3D full-azimuth full-offset node survey offshore South America. 18 azimuths of pre-stack azimuthal Reverse Time Migration Least Square Migration (LSM) P-P seismic data were evaluated prestackfor presalt targets and we were exceptionally well-pleased with the results! The LSM did appear to compensate the azimuthal transmission effects through the overburden. (Rodriguez et al., 2022)

Rene: In 2015 you received the Reginald Fessenden award for anisotropic stresses in seismic data to define the fracture nature of the subsurface well as geomechanical properties. Can you share your thoughts on the day of the award?

Heloise: Happiness and amazement! As always, heart-felt thanks to those who made that day possible spring to mind – my parents, Ann and Dan; my professors, Jon Claerbout, George Thompson, Fred Hilterman; colleagues : Leon Thomsen, David Gray, Richard Bates, Mike Graul, plus so many more; gracious clients who permitted publications – Thank you!

Rene: In addition to being a top-shelf geophysicist you are very active in horseback endurance riding. Some say that endurance riding is a bit like a horse marathon. Can you elaborate more on the sport and your interest in it?

Heloise: Endurance riding, for me, is 25-miles on one horse accomplished in less than 6 hours of clock time. With one hour reserved for rest in the middle of the course, this translates to 5 hours or less of saddle time. The speed averages faster than 5 miles per hour, so a trot is the standard speed. Occasional canters or walks are also encouraged. With the righthorse, it is easy. With the wrong horse, it is impossible. Both rider and horse must be fit and conditioned. I like it because there is LOTS of saddle time! My horses like it, because they like being out and about.

I will also confess to a new addiction to pickle ball! I played tennis in high school and college, so pickleball now fits right in. Pickleball is a combo of tennis, badminton, and ping-pong. Try it! You’ll like it! Walt will even play with me!

Rene: Reflecting on your own career, what advice would you offer for young professionals.

Heloise: If you, or your boss, want some geologic answers, go to the field and acquire the right dataset and process it correctly. My philosophy is that whatever you want to know about a given earth condition in a given locale, the well- designed field data acquisition and correctly-processed data will provide the geologic answers, provided that you are working in a layered sedimentary rock sequence. Reflection seismic can become discouragingly difficult if one is coping with thick igneous layers and/or metamorphic rock regimes. That’s not to say it can’t be done, but that more time and more money is likely involved.

I admit that there are budgetary constraints for acquisition and processing: in some economic climates, managers balk at spending the money to get the answer they want. Not to worry: wait about 5 years, and the industry’s acquisition technology and processing capabilities will have improved to the point that your proposed solution shall be funded. So don’t lose hope.

I am particularly intrigued with recent geothermal projects that seek to map, using 3D reflection seismic, the permeable flow conduits i.e.the fractures, or aligned connected porosity that flow the hot water. Apparently, a fair number of geothermal fields, often naturally fractured, have substantial amounts of dissolved lithium in the brine. Therefore, a nominal geothermal project that also extracts the lithium from the extracted hot waters, and pumps back down the lithium-depleted waters, can offer added financial benefits, according to some. Lithium is an important component in many batteries of today.

Rene: And what advice would you offer for women scientists?

Heloise: Work hard. Be honest. Having some compassion on others (like make it easy to keep minds on the job, and not drift off into less-than-appropriate thoughts) is good. Thank you, Rene, for your kindness in taking this project on. I appreciate your efforts and good heart!

Rene: Heloise, thank you for generously taking the time on this interview. There are so many words of wisdom that you have shared from your rich career. First it starts with a team, we all need to collaborate with our team mates, ask questions, sharing freely, and be grateful for each team members. Next we need to work with those in the field that are designing and acquiring the data so that we place the source and receivers correctly for the objective. Then stay in touch with the processor melding your knowledge with theirs for the best output. Finally let the data speak to you; do not push a preconceived idea into the data.

You also illustrated with some excellent examples how azimuthal or shear data can add greatly to the understanding of fractures, gas clouds or lithology changes. Identifying these aforementioned changes also help in better processing, interpretation and ultimately better drilling decisions.

Finally, I see a similarity between your 47 year career and your hobby. Both are based on endurance! Thanks for being an example of showing the payoff of endurance. We are looking forward to your 2023 publications.


Keller, W., R. Mott, A. Jumper, H. Lynn, W. Lynn, M. Perz, 2017, Correlation of azimuthal velocity anisotropy and seismic inversion attributes to Austin Chalk production: a south central Texas case study. 87th Annual International Meeting, SEG, Expanded Abstracts.

Lynn, H.B., and B. Goodway, 2020, Azimuthal P-P prestack amplitudes in the presence of oil-filled aligned porosity (fracture porosity): Interpretation, vol. 8, SP109-SP133

Lynn, H.B., Field measurements of azimuthal anisotropy: First 60 m, San Francisco Bay area, CA, and estimation of the horizontal stresses' ratio from VS1/VS2, Geophysics, v. 56, p. 822-832, 1991. Also presented at the 1989 SEG Research Workshop, Snowbird, UT, The Recording and Processing of Vector Wavefields

Lynn, H.B., Where you sit governs what you see, CSEG Recorder, June 2003, Vol. 28. No. 6

Rodrigues, Jose, Felipe Duarte, Danilo Domingos, Bruo Pereira-Dias, and ElionardoPintas, [2022], Least-squares reverse time migration: Lessons learned from recent applications in challenging areas of the Santos Basin, Brazil, SEG Technical Program Expanded Abstracts.



bottom of page