David Gray is a well-respected name in Calgary and has gained recognition outside through his publications and presentations. David has worked as a seismic data processor, research geophysicist and senior research advisor at Veritas/CGGVeritas and is now residing at Nexen working a Senior Staff Geophysicist. While at Veritas, David did extensive work on AVO/LMR analysis and later on AVAz analysis for seismic fracture detection, which made him an expert in these areas.
More recently, he became interested in drawing geomechanical information from seismic data. Estimates of horizontal stresses and fracture initiation pressure from seismic anisotropy and validating such stress results from seismic data is his latest interest.
David has delivered several tens of presentations on his work at conferences and workshops and has won awards for the Best Geophysical Poster at the 2009 CSPG/CSEG/CWLS Joint Convention and the Best of the SEG D & P Forum presentation. He is a member of several professional societies including CSEG, SEG, EAGE, SPE and APEGGA, and is an active volunteer on many of their Conference and Workshop committees.
We asked David if he would be comfortable in letting us interview him for the RECORDER and he readily obliged. Following are excerpt from the interview.
(Photos courtesy: Joyce Au.)
David, tell us about your educational qualifications and your work experience.
I started in a Geophysics program. I knew I wanted to do Geophysics coming out of High School. I should think that’s fairly unusual. I started in Geophysics at the University of Western Ontario in 1980. They have a good Geophysics program, it was right in my hometown of London and I had scholarships to go there so it was all very, very nice. I came out of there in 1984 with a four-year Bachelors in Honours Geophysics. After graduating, I started working for Seismic Data Processors, which was a very good company to work for. I worked there for 1½ years, then left to go to Geo-X right at the end of 1985. Then 1986 came along and, with it, the downturn. Because of that, I didn’t work for Geo-X for long; I was laid off in 1986 and then went back to school.
I did not feel fulfilled with the Bachelors degree and I wanted to study more math. I really wanted to do something besides Geophysics at the time. It looked, to me, like the oil patch was not the place to be when I left. I was fortunate to be accepted into a Masters Degree program in Statistics with a teaching assistanceship in the Mathematics faculty at the University of Waterloo. As I was working my way through that program I found myself drifting back to doing geophysical projects for my statistics courses. When I finished with an M. Math. in 1988, I came back out to Calgary and started knocking on doors looking for a job and ended up working for Veritas. Veritas was a relatively small company at the time. I remember the Processing Division staff count in 1992 was 62 people. That was, again, during a downturn. I stayed with Veritas almost 22 years in a variety of positions and it was really nice because the company grew and I was able to grow with it. So by the time I left, what had then become CGGVeritas (in 2010) consisted of over 7,000 people. I started with a small Canadian company that grew to be a very big international company and I grew with it.
Veritas was a great place to work because they grew people from the inside. I started there as a processor, with a couple of years experience at these other companies, and started processing, which I did for two years. I got started in AVO after making an error processing some data for AVO work. We were using INVEST and I managed to eliminate the AVO character of the data with it. So I worked with Rick Wallace, the leader of Veritas’ Reservoir group at the time, on resolving that issue and we eventually understood that we needed to use more parabolas in the INVEST program to maintain the AVO compliance. When the Reservoir group was looking for another staff member a few months later, therefore, my name came up and I ended up getting the job. That’s when I started working on AVO.
AVO is a perfect fit for me because I have degrees in geophysics and statistics, specializing in linear regression. AVO is linear regression on geophysical data. Very shortly after moving into that reservoir group, I realized through learning about AVO that there is a lot more information in seismic data than what I had realized previously. What became a driver for me after that point was to get all the information possible out of the seismic data. The biggest thing that we did at first wasn’t AVO at all; it was a line tying program which we called Meridian. I had had some good training as a summer student in both inversion and phase analysis by John Pendrel, who was my boss at Gulf Canada at the time. He is a very smart man. I learned a lot from him in the four months I was under his tutelage at Gulf. One of the things I learned about was wavelet analysis; both wavelet analysis for tying 2D seismic lines together and wavelet analysis for tying seismic to well log synthetics. Rick Wallace had some ideas on how to do that and I also had some ideas on how to do that. We put it together into a program we called Meridian, a very successful product for Veritas at the time – and so we did a lot of line tying. For the second project that we did, the client asked if it was possible to use Meridian to tie the seismic back to well logs. We said, “We don’t see why not.” So we started creating synthetics and tying seismic data back to wells. Over the years, we have tied thousands and thousands of wells.
At the same time as this, I was doing AVO. I started with the code left by Dan Hampson when he was with Veritas in the late 1980’s and tweaked it by adding some statistical measures that I learned while doing my degree. Eventually, in 1996, I wrote new AVO code at Veritas in order to modernize it. We were being strongly pushed to do so by Taiwen Chen and Bill Goodway of PanCanadian. It was kind of state of the art at that time and started making AVO into a bigger part of what we did at Veritas. I’d done a lot of research and the new code was able to derive shear reflectivity, and Poisson’s reflectivity, using more modern equations that had been published in the 1990’s. So that was good. At the same time as I was writing that code, I came across an article by Heloise Lynn on azimuthal AVO. She was looking at a couple of 2D lines and showed the difference in AVO response in different directions due to fractures. I thought to myself that if we could ever get something like this to predict fractures from 3D seismic, it would be awesome. Since I was already writing AVO code, it was easy for me to include some alpha code to do fracture detection in 3D, based on what Heloise had published.
After the code was written we looked for a project, which we finally found in ’98 (it was 1996 when I wrote the code). In 1998 we found a project with KCS Mountain Resources in the Manderson Field where I first ran the azimuthal AVO code. It created results that we mapped and they looked like garbage. The results indicated that fractures were going every which way and did not look believable. However, we had three oriented cores with fracture analyses that I could tie and it turned out that all three of these tied the measurements that we got from the seismic. Three samples was hardly proof, but it was interesting; there was enough there to publish the results.
But this was independent of Rüger’s approach, because his was published in 1997, I believe.
Yes, this would have been based ultimately on Leon Thompson’s work that Heloise was following. Ultimately we did code Rüger’s equation, which he originally published in his 1996 thesis. I had, like I said, written some alpha code, which was very basic, just to test the concept. It just measured the gradients in different directions and found the maximum differences. Publishing brought us into contact with Paul LaPointe and Bob Parney of Golder, who had done a geologic study on fractures at the Manderson Field that was in agreement with our results. From there we just continued to be able to tie well control on fractures, when it was available and we kept publishing.
Another thing that came to mind was you said that you wrote the code for AVO; you didn’t think of using Hampson-Russell’s AVO code, you must have been using Hampson- Russell at the time?
There is a little bit of history there. Dan and Brian originally worked for Veritas – in a subsidiary called Veritas Software – and David Robson decided to shut Veritas Software down. That’s when Dan and Brian decided to start Hampson-Russell and David Robson, our CEO, was very generous and allowed them to take AVO, Strata, INVEST and so forth with them. So we actually had the code that Dan and Brian had written. We weren’t using the Hampson-Russell version of AVO. We had our own internal code that was equivalent at that time. In 1996, I wanted to modernize it while at the same time Hampson-Russell were only doing intercept and gradient. Therefore, we diverged at that time. They’ve since added on the rest of the stuff so that now their algorithms are very similar to that of Veritas code.
David, let’s ask you: over the years you have grown with the company, tell us what are the advantages of working with a big company as compared to a small outfit?
Okay, with the big company, the biggest advantage is the number of colleagues you have. Just by the nature of numbers there has to be a lot of smart people in that company. At Veritas, there was very good communication between the different research groups and different areas of the world. One thing that Veritas did that I liked was to have research groups in different key centres in the world. Those centres focused on the problems specific to that centre and then we would try to communicate the different methods between centres. For example, our Calgary and London research centres tended to communicate a lot because we ended up working on somewhat similar problems. We both were working on older basins with harder rocks where it is harder to see the hydrocarbons.
There is the opportunity to travel with a larger company, more so. It probably varies from company to company but certainly once Veritas merged with Digicon in 1996, then we had the opportunity to travel much, much more than we had before, to places that I never thought I would see like Europe, China and Southeast Asia.
One of the things I’ve been asking people as I’ve been conducting interviews for the last 10 years now is this: some people believe that to move high up on the ladder you need to switch from one company to another, but you stayed on for 22 years with the same company, so do you feel that you have sort of proved that it is wrong?
That’s right. I don’t believe that it necessarily has to be the case that you have to switch companies frequently to move up the ladder. In my case, it has to do a lot with management of Veritas. I give credit to David Robson, Wilf Reynish, Rick Wallace and Eric Anderson for knowing the abilities of their employees and moving them into positions where they could use those abilities. I was not the only person within Veritas to move up the ladder. It was something that consistently happened. If you showed an interest in something, the management tried to be aware of the people in the company and what their interests were and so people were able to move up the ladder. People have moved from being computer operators to being computer programmers and even vice-presidents and presidents. There was always ample opportunity in Veritas to move up. When they saw what my skills were, they saw that I was interested in doing research, the opportunities were there. There was a bit of luck involved as well, as always. As the company grew I was able to grow with it. That was very good.
Okay, how did you decide to quit recently after 22 long years with Veritas and CGGVeritas?
There were numerous reasons. The biggest one was that my wife had just graduated from Alberta College of Art and Design with a Degree in Bachelor of Fine Arts...
Was it painting and all?
She is a glass artist.
Once I received one of her stained glass awards.
That was the CSEG; she did the awards for the 2003 CSEG CSPG Joint Convention.
I still have them in my cubicle.
It must be getting full. She was starting to travel quite a bit and in the role that I had at CGGVeritas I was going to need to travel quite a bit. We have a couple of teenage daughters – not quite old enough to really be set on their own for an extended period of time, pretty close but not there yet – so that was the number one reason.
The number two reason was I had recently been thinking a lot about what I wanted to do. Looking at the big picture, I got to the point where financially I could retire, so I just started asking myself questions. What should I do? Should I take my skills and do charitable work with NGOs like Geoscientists without Borders or with the church? Where should I do it? Thinking about it, praying about it, the answer that came back was: keep doing what you are doing. So then the question is why? Why move from one company to another? The answer to that is what my research had been leading me to over the last number of years which was really an integration of disciplines. I was finding it difficult to get engineering data, geological data and feedback, especially feedback from the engineers and geologists. So the move to Nexen was really the result of those two factors with a bunch of other things that were going on as well, but those two items were the main concerns.
You make a good point there because often at a service company what happens is once the project is done, the message from the clients is okay, now guys back off. Very few people come back with feedback or involve you with the decisions and all that, so I fully understand what you are saying.
As an example of the success of that methodology, I ran AVO inversion for density, and was able to get some interesting results out that I didn’t quite understand. I was able to walk down the hall and show it to the geophysicist and the geologist working on the project, who are Tess Sebastian and Tim Bergen, and Tim started being able to interpret things like flow direction out of the inversion results. We had not been able to see that from the stacked seismic data alone but being able to see where we had higher and lower values of density and the patterns that were exposed only once we did the inversion really brought a lot of information to the table that Tim was able to interpret immediately. That was cool and it is a great example of the kind of thing that I was looking for when I moved.
What areas of geophysics fascinate you particularly? I know you are working in different areas but which of those are really close to your heart and why?
The main thing is that I am trying to get more information out of the seismic data. You go out there, you acquire seismic survey, say for ten million dollars or something like that, and you process it, processing costs about one tenth of the cost of the acquisition. By spending a little bit more more money, you can take that ten million dollars that is already invested and get a bunch more information. It’s always driven me crazy that people don’t utilize it like they should. I have just been trying to get more information of the seismic data. AVO was a really good fit for that because I am a specialist in linear regression. In AVO you use linear regression to get more information out of the seismic data. My work on azimuthal AVO started when I saw the paper by Heloise Lynn on detecting fractures with seismic data. I said to myself, man if we could ever get this information out of the seismic data it would just be incredible. So I spent about a week coding it up just on a “maybe this will work basis” and it’s been phenomenally successful, so I am really thrilled about that.
All this, but especially the fracture detection work, has led me to look towards the engineers. The recent work that I did on stress, estimating principal stresses from seismic data, the AVO work and fracture detection, all lead me to the other disciplines. Therefore, another passion that I now have is communicating geophysical results to other disciplines. I think that we can do that much better than we have done to date. It really just involves talking about different things that are very closely related. So now I like to talk about Young’s modulus and Poisson’s ratio instead of P-wave and Shear-wave velocities. I mean, they are just simple mathematical transforms from one to the other, but by using them the ability to communicate with the engineers is vastly improved.
They find it easier to relate to those properties.
They understand those terms and we understand those terms, so why not communicate in their language?
Well said. David let’s ask you this, tell us about the most challenging project you may have done and how it turned out to be one of your favourite ones, the one that you cannot forget.
Yes, the one that is the most challenging on the dock is the last project that I did at CGGVeritas which was estimating azimuthal stresses from seismic data so we —
This is what you have been talking about now?
This is what I have been talking about over the last couple of years. I was focused on shale gas. What was presented to me as the problem was how can we create value for seismic data in shale gas plays? When you analyze what they are trying to do in shale gas, which is really to break the rock so that you produce permeability pathways, you see an opportunity for the use of seismic data. You can think of the seismic survey as a hammer that is going down and tapping on every bit of rock. This is similar to the tests that the engineers do when they are trying to determine rock brittleness. Therefore, seismic has the potential to predict the ability of the rock to fracture between wells. It can also be used to predict stresses between wells, which could be phenomenally beneficial even if it is imperfect, at least if you get the trends. Where there is one completion that fractured and another completion that did not fracture; why and where is the boundary between these two zones? That’s a phenomenal thing we can bring to the table and it’s achievable with some of the tools that we are already using in seismic data like azimuthal AVO inversion.
So how do you go about characterizing this using AVO and AVAZ?
Yes, that’s the way that we do it. Multicomponent data could also be used. You need to have Poisson’s ratio and normal compliance in the reservoir and density all the way to the surface. All this stuff is obtainable from seismic data using pre-stack AVO inversion techniques. Once you have them, you can calculate the principal stresses and from those you can find other interesting stresses like the closure stress and the hoop stresses.
So that has proved to be really worthwhile?
I think so, I mean we haven’t really seen the acid test on it yet and you know we are still learning, but that was the coolest project that I have worked on.
Now I am working in Oilsands for Nexen and this is a big project as well. The reason why I like it is because of the integration of disciplines required. What I am trying to do now is to get the seismic data into forms that are useful for the geologists and various types of engineers, the reservoir simulation engineers especially. The drilling and completions engineers can also find that information useful.
The next question is based on some of my experience. You have done a lot of work on the AVAZ side and I have done a lot of work on attributes; I have always tried to come up with something that marries the two. Now in your experience, is there a lot more information on the azimuthal attributes as compared with the post-stack attributes that we normally do like curvature? And is there a way to merge the two? What would you say to that?
Those are good questions and we have looked at them. The quick answer is that I believe that the curvature attributes, discontinuity attributes and so forth, give us information about fractures that are associated with faults. What the azimuthal AVO attributes and multi-component seismic data tends to do is give us information about fractures that are away from faults or at least away from faults that are visible on the seismic data. When you start thinking about that what you actually need to do is combine the two because the azimuthal AVO doesn’t seem to work that well around discontinuities, but discontinuity measurements do. There are a variety of reasons for that but the biggest one is probably that the HTI assumptions we make for azimuthal AVO and multi-component are breaking down because of the extreme stresses near the faults, whereas curvature and discontinuity measurements work very well around faults. Therefore, what you really need to do is combine those two attributes, which you can do as simply as co-rendering them together on a map or in a volume or in a neural network technique.
Now, in terms of testing that idea, we did a big project on the Pinedale Field, which is in Wyoming. It is a tight gas sand play and we did a neural network on that. We threw everything into the neural network: the discontinuity attributes, azimuthal AVO attributes, regular seismic attributes, geologic attributes, structural attributes, etc. The field was so new and there was no information on the fractures, so the best indicator of fracturing that we had was basically production. Since that is what we are ultimately interested in anyway, this was a good test. We looked at the early production from the wells and what predicted that best was about 50% discontinuity and 50% azimuthal AVO. The other attributes didn’t really matter that much, including the things that had been traditionally used such as the geological attributes. So, basically, in our opinion, distance to faults and presence of fractures were controlling production from that field.
Some of what you say in the first comment that you made about azimuthal attributes not working so very close to the faults or fractures is, I think, part of the conclusion that Lee Hunt also makes. He tried to marry the two and I think that is the first quantitative step in that direction. But I was under the impression that if you have fractures – open fractures away from the faults – and if they are somehow picked up by the seismic wave field, the curvature attributes of the high resolution curvature that we do picks up the impression there too. But, again, we have to spend more time analyzing these things.
Okay, tell us what advances are being made in the area of seismic reservoir characterization? Now this is an openended type of a question but let’s hear what you have to say about that.
Well I think the biggest things that I am working on at the moment are stochastic inversions. All the plays we look at, especially in Western Canada, tend to be very thin-bedded plays, and so stochastic inversion gives us the ability to characterize those thin bedded plays at the expense of having error bars on the measurements. But you can leverage the fact that you have error bars and say there is an 80% chance that I have a sand at such and such thickness at this particular location.
So that’s one thing and the other major thing that I think is happening is geomechanics. I think we as geophysicists have a great opportunity to provide information on geomechanics between the wells. Going back to the project that I did for characterizing stress and rock properties between wells, all that leads you to geomechanics and I have seen numerous applications. Now that I am working in Oilsands, there is a drive towards better characterization of the caprock. Well that’s a geomechanical problem because what you want to do is ensure that the steam in use in SAGD stays underground so you want to make sure that the geomechanics of the caprock are appropriate. That’s one example.
Another example is in the exploration realm, knowing what the risk of losing the well is. You can get an idea from a relatively inexpensive seismic survey that you might have some geomechanical issues in your $100K well. You might want to examine that before you drill the well.
Now we talked about your integration of disciplines and that has been a buzzword for quite some time. Do you think this is being done today?
Let’s say it can be done better. I think the geophysicist has a key role to play in that because as I was mentioning earlier, we can understand a lot of the terms that the engineers use, and we can understand a lot of the terminology that geologists use. So I see the geophysicist as a potential intermediary between geology and engineering. Now we can understand terms like Young’s modulus and Poisson’s ratio and we can understand things like V-shale and so forth and how they relate together. I see geophysicists having the opportunity to move into a more significant role in the industry if we ourselves focus on integration of disciplines and continue to be open to learning. And that means listening to the engineers, hearing what their concerns are, listening to geologists and hearing what their concerns are, and listening to other geophysicists and hearing what their concerns are.
Absolutely. There is that idea of getting outside your comfort zone and the change of mindset. Probably needs to be done.
So as you mentioned and from what I’ve read in your CV, your goal is to integrate geophysical reservoir characterization with reservoir simulation and create a significant improvement of the exploration and development of oil and gas reservoirs. Where are you at with this goal? I know you just got started.
I just started. What I do know is that there are some good tools that are available for being able to do this type of work. So there are at least two companies that have tools that will take a reservoir engineering model as a starting model for a pre-stack inversion and then invert the seismic data for the properties that are in those reservoir engineering models. That is called, by one of the companies, petro-elastic inversion. That’s the kind of tool that I want to use. Now that I have access to the right data, I want to use that tool. As I mentioned, stochastic inversion is another tool that I also think can be brought to the table and the integration of anisotropy into all this stuff is also tremendously important. As we were discussing before the interview started, I see anisotropy everywhere. It looks like there is significant amount of velocity anisotropy in the overburden on not only land data but even in marine data. I have some beautiful examples of anisotropy in both marine and land data. In one heavy oil P-wave example, at a time of 200 milliseconds in the seismic data, we have 20 milliseconds of azimuthal moveout at offsets of 40ish degrees. In marine data, azimuthal NMO has been applied, even in narrow azimuth marine data, significantly improving the images that we get. That’s a big driver for me in trying to get us to process 3D data with these 3D concepts, and azimuthal velocity is just one of those.
Geophysics provides invaluable information with regard to reservoir heterogeneity and you mentioned anisotropy and other stuff, but right here we are referring to heterogeneity in general and this becomes important especially in the initial phase of production. Do you agree that it is a very important link in the integration process?
Absolutely, what geophysics brings you is the information on the heterogeneity between wells. If I have a couple of wells and I have one property here and another property there, where does it change from one to the other? That is what geophysics answers. It’s an imperfect tool as all tools are. All data are imperfect. I learned that going through a statistics program: anything that is data should have error bars associated with it.
Your training in statistics must have stood you in good stead all through your 22 years.
Well, you must have picked up on that now, obviously.
I actually got a pretty good base for the things that I wanted to do going through the Statistics program at the University of Waterloo. I learned a lot of Monte Carlo techniques and I specialized in advanced linear regression. These are serving me well now.
Come back to shale gas for me. So now, since you have done this work on stress, stress from seismic data, apart from this and including this, do you think seismic adds a lot of value to shale gas formations?
I really do. One of the things we looked at was the economics of just looking at the well path ahead of time and asking – should I put a completion here or not? Many completions don’t actually work and having the ability to decide that ahead of time means that you can move those completions in the well. They don’t have to be evenly spaced per se. You can put them in optimal locations. That’s one of the things geophysics can give you. You can also decide to maybe not drill a horizontal here, and instead maybe drill it a little bit further away, a little bit closer to another one because the rock properties between those two wells predicts longer fracs or shorter fracs in that particular area. So you can change your well spacing. All this helps you improve your NPV.
You can also do “what if” scenarios – let’s drop some wells, let’s drop some completions – those are numbers you can get that are tough to assess. Things like how much more production you can get out of a particular location if you move it because you haven’t drilled the other one. What we were able to do was to look at a project that had something like, let’s say 20 horizontal wells. Let’s say you dropped two of them and then you dropped 10% of your completions. You would then save 10% of the cost of that program. The cost of doing the seismic acquisition and processing and the advanced processes is about 1% of the total cost of the program. So I certainly think that there is value to be gained out of seismic when you look at numbers like that.
And the other thing that I like to say on this point is that I think that we as geophysicists need to start thinking in terms of numbers like that, in terms of economics. That is another thing that is driving me forward right now. Geophysicists have done a poor job of relating the economic benefit of their discipline. I would like to see that improve.
Yes, I know these are important points you make there because not many of us think along those lines. We do the projects, we characterize them, but we don’t go on to the final economic analysis of the projects.
I got asked to do an assessment of geophysical technologies for the Alberta Government. Well, politicians don’t understand geophysics. I will assume that most of them don’t and so how can you explain the benefits? Well the only way you can is in terms of numbers, especially dollar numbers, and for that I searched all over and was able to find very limited information about the economic benefits of geophysics.
Going back to the topic of integration, when you see people working together it’s not integration unless you know it is really done in a proper way. So, in your opinion, what do you think is required to achieve that goal?
I really believe it comes down to integration of the data. Can I generate geophysical attributes that the geologists and engineers can comprehend, that they can look at, that they can use in the tools that they use? That is what I am striving towards.
Going back to your earlier comment that you made, we should talk their language and make them understand because we understand both the disciplines. Or at least start talking their language. At least if I do that, I think it will be a step closer to that goal.
And I will take it a little bit further than that and ask, can I produce a volume from the seismic data in a format that the engineer can easily put into his simulation software or the geologist can easily put into his geological model? We need to be thinking along those lines.
So that should not be very far off; changing our mindsets, getting out of our comfort zones and starting to look at these things and developing them.
Yeah, that’s right; essentially start talking – listening to the other disciplines.
Let’s talk about the determination of permeability from seismic data, how much confidence can we have with that? Can we trust whatever attempts we make to do that?
That’s kind of a very audacious goal – and you would like to be able to say “yes” - but we have very limited ability to do that. However the azimuthal tools, the ability to detect fractures, are a step in that direction. In the work that we did on the Manderson Field, one of the cores that we had, which I mentioned earlier, had nothing but sealed fractures. When I tied it there was no significant azimuthal anisotropy in that particular location. So what that told me was that azimuthal AVO at least, and I presume multi-component fracture techniques, see open fractures not closed fractures. Well, open fractures are permeability pathways, so we are starting to move in that direction. There is some interesting work being done at the University of Bergen to relate those two things together, but it’s very preliminary.
And then the other use is prediction of porosity from seismic data, which I think we need to do a lot better, again going into those petro-elastic style inversions. One of the parameters that they come up with is porosity and porosity is frequently related to permeability, especially in more conventional reservoirs. That’s another route by which you can get that information. So it’s coming. I don’t know whether or when it will ever fully arrive, but we are doing what we can.
David, you have two patents. Do you think getting patents really helps?
I hate patents.
But you’ve got two there.
I have two, yes. I think patents kind of get in the way. I think at least here in Calgary there is a lot of communication amongst the technical specialists in various companies and that is one of the things that is agreeable working in this city and patents get in the way of that line of communication. I sort of don’t like them. I mean I like to be able to talk to you and Jon Downton, and Bill Goodway, Paul Anderson and John Logel and a whole bunch of other experts; and when we get together and talk and present to each other, you get pretty good feedback. Patents, first of all, slow that process down and they interfere with it. But patents are necessary because you need to protect the investment that the companies have made in us to create those things. Veritas never believed in patents. The first patent I got was only because we essentially needed a patent to get a contract. More recently though, just because of the way business is going in general, companies are becoming more focused on obtaining patents, not necessarily because they want to protect the technology but more about trading them. So you get a patent on one thing, I get a patent on something else, and we trade our patents so we can each use each other’s technology.
The downside that I see is this. There is a lot of detail in a typical patent. Now there are people, companies, researchers who will bypass the patents in a very clever way, so having the patent may not actually protect the company that owns it, and in fact may attract competitors to mimic it in ways that are not in violation of the patent. The imitators are in conflict with the spirit of the patents that you have, but they can still do it because once that information is there they can find a way to bypass that.
Since you have gathered a wealth of experience, have you ever decided to give back to the geophysical community by way of conducting courses for the younger lot, or compiling all that stuff in the form of a book, which the younger generation can gain from?
My preference is to work one-on-one as a mentor. This is also the reason why I make so many publications and presentations, to get the word out. I try to encourage young geophysicists who have good ideas to write papers and I’ll help them to do that either as a coauthor or as a reviewer.
Do you like to volunteer for professional societies?
I like writing and reviewing papers and making presentations at conferences. This is where I am putting the bulk of my spare time at the moment. Through reviewing, I have also had the opportunity to chair or co-chair various sessions at different conferences and I really enjoy that. I also have a strong belief that posters should be used more effectively by geophysicists; geologists use them very effectively. I was joint poster chair for the joint CSPG/CSEG/CWLS convention a few years ago.
What other interests do you have?
I like spending time with my family. I play volleyball. I am involved in grassroots motor racing. What’s interesting about that is that a large proportion of the racers are geophysicists, which is odd considering how few of us there are.
What would be your message for young geophysicists entering our profession?
We need more generalists. Listen and learn from all disciplines. Find out what their problems are. Join SPE and CSPG as well as CSEG and read their journals. Think about how you can help them solve problems using geophysical data; not just seismic, but E-M, gravity and other methods as well. I think that we have a lot to add. Take an “engineering for geoscientists” course or a “geology for geophysicists” course as a starting point. Learn about geomechanics. I expect this will be the next great growth area for geophysicists. As mentioned earlier, the seismic experiment can be considered a geomechanical test of all the rock. The trick is to get that information out of the seismic data and then calibrate it to the static data the engineers need.
You don’t have to start with an E&P company. In my case, working for what was originally a small contractor and growing with it worked out very well for me. There are distinct advantages to working for a small contractor. Because there are fewer employees, the executives know who you are and what you can do. You have a lot more freedom and a lot of room to grow.
One last question – was there any question that you expected me to ask and I didn’t?
Nobody ever answers this in the positive, so I am going to be a little different and say yes. The missing question is: “How did you decide what technologies to pursue throughout your career?”
The answer to that is to listen, read and look for patterns. Looking for patterns is something that geophysicists are good at. I would take magazines like Geophysics, The Leading Edge, The RECORDER and First Break on the bus and train ride into work. Now I also read SPE’s Journal of Petroleum Technology. The length of the ride was about perfect to read one article each way. I’d only read the stuff that was interesting to me and then make note of key papers. That is how I was able to see the trend toward petrophysical application of AVO in the 1990’s and how I was able to find azimuthal AVO for fracture detection before it really took off. I also kept emails in a folder with suggestions for programs that I wrote so that when I was working on upgrades I was able to incorporate all these good ideas that other people had.
David, thank you very much for giving us this opportunity to sit and chat. I have enjoyed it.
It was a pleasure. Thank you!