David Johnston is an experienced geophysicist who is working as Geophysics Coordinator with ExxonMobil Production Company in Houston. David has been with this company since he was hired in February 1979, and has taken on a variety of research positions during his tenure. He is best known for his work on time lapse seismic (4D) reservoir monitoring, AVO analysis, rock physics and evaluation of fractured reservoirs. However, some would also identify his name with the research he conducted on seismic wave attenuation in rocks.
David has received several awards during his career which include the Honorary Membership Award from the SEG (2004) and GSH ( 2003). He has been the Distinguished Lecturer for SPE (1992-93), the SEG (1999) and the AAPG (2008), and has also received awards for the Best Paper published in TLE in 2004, and the Best Paper presented at the 1993 SEG Meeting. David has volunteered his time generously to various Professional Society Committees and is also a well-published author.
David was in Calgary during the month of March 2008 to deliver an invited talk at the CSPG Luncheon, and Satinder Chopra was able to sit down with Dave and interview him. Following are excerpts from the interview.
Dave, let’s begin by asking you about your educational qualifications and your work experience.
Sure. I received my B.Sc. in Earth Sciences from MIT in 1973. I must have liked it there because I stayed on to get my Ph.D. in Geophysics in 1978. I joined Exxon Production Research Company shortly there after in 1979. I have been with Exxon and now ExxonMobil for nearly 30 years.
So, you have stayed with Exxon for this long and what do you have to say about how your career has shaped up?
I’m surprised that I have stayed there that long, that anyone stays as long as 30 years anywhere, but I think there are probably several reasons.
First of all I always wanted the opportunities that a company like ExxonMobil could afford. The type of work I have done in the areas in which I have worked have all the quite varied. You might say I’ve had several different careers working for ExxonMobil. And it sounds trite, but it is also the people that have kept me in one place. I have been able to work with some of the best people in the Industry and I have really enjoyed that aspect of my career.
Would you like to mention anything about some of your personal attributes that helped you achieve the professional status that you enjoy today; was it self-belief or was it hard work or was it something else?
I think everyone in the Industry works hard, right? It’s probably not just that.
Optimistic view, that’s good.
Well, I would like to think so. Let’s put it this way, everyone I work with works hard. They are really committed to what they are doing, which is great.
I guess for myself it’s probably been a focus that I have had from the beginning of my career on the reservoir. When I joined the Industry, geophysics was oriented towards seismic imaging of structure. I joined Exxon as a Rock Physicist and did research on the properties of rocks at the pore and reservoir scales. That interest developed and extended through all of my other jobs at ExxonMobil, from lithology prediction using seismic velocity analysis, reservoir characterization using AVO and 3D seismic attributes, and then finally to 4D seismic analysis. So it’s this focus on the reservoir that has really steered my career.
Your Ph.D. at MIT—that was focused on seismic wave attenuation?
Yes, my thesis on seismic wave attenuation was a mix of both laboratory measurements and some theoretical modeling.
The result of finishing your work there was a re-print volume that you edited with Nafi?
Professor Nafi Toksöz and I compiled a re-print volume for the SEG. I think that was a valuable resource. I still see people using it and I’m actually amazed that it is still available. You can get it for $5.00 or less at the SEG Annual Meeting Book Mart!
Dave, would you share with us one or two of your most exciting successes at ExxonMobil?
I think my biggest success is what I am doing now – commercializing 4D seismic technology within ExxonMobil. We obviously faced a lot of challenges because 4D is a highly integrating technology that brings together geophysics, geology, and reservoir engineering. And in working Production, the business impact of our work is critical. But I think that it is all of these factors that also make the work so exciting. I also had a role in developing 3D seismic attribute analysis as a key tool for reservoir characterization. This contribution was also very important in my career.
How about a couple disappointments?
When I first joined Exxon I was asked to set up a rock physics lab, which was quite exciting coming out of graduate school. To have all of the company’s resources – I think the phrase “money is not a problem” was actually used by one of my managers – was an incredible opportunity. That was back in 1979 and 1980, the previous industry boom. But I think my lab didn’t live up to its potential. This was partly my fault and partly the fact that the organizational structure kept us a bit isolated from the Company’s day-to-day operations. As a result I don’t think I fully appreciated the business drivers for the research that we were doing and the technology we were developing. Although we were doing some very good and very interesting fundamental research, you have to be focused on the end use of technology in the oil and gas business. This critical lesson is one that I took forward and applied in helping to develop 4D seismic technology.
You have been a Distinguished Lecturer for SPE way back in 1992-93, the SEG in 1999, and this year for the AAPG. This is indeed an honour – so my question is, how did you manage to get this honour three times?
Again, I think it’s my focus on the reservoir. The reservoir is a common interest for each of these three professional societies. If I were an expert in seismic imaging, I doubt very much whether I would have been a Distinguished Lecturer for either the SPE or AAPG. Also, 4D seismic, which relies on an integration of data from all three disciplines, is of particular interest to each organization.
Well said. Now in the last ten years, maybe 15 years, we have seen a number of case studies on time lapse or 4D that have been presented and highlighted the importance of the technology; we can also gauge this from the 2 DISC courses that have been presented by the SEG on time-lapse. For the information of our members, could you briefly explain the promise of 4D seismic?
Well, I would say it is the reality of 4D seismic not just the promise. Many 4D seismic projects have demonstrated how the technology can add value to reservoir management in a number of different ways.
It helps us increase reserves and recovery and so we can use it to locate bypassed and undrained hydrocarbons. 4D can help us optimize infill well locations and optimize flood patterns, but I think more importantly, it helps us optimize the field depletion plan by reducing uncertainty in the reservoir geologic and flow simulation models. That allows us to be more effective in reservoir management because our models are now more predictive. Finally 4D allows us to decrease operating costs if we can avoid dry holes or optimize completions. So I think that’s the reality for 4D seismic when it’s effectively applied.
Apart from the repeatability of time-lapse experiments, what are the other requirements that are necessary for getting good results?
There are two important technical factors that affect 4D chance of success: repeatability, as you say, is one. How similar are the seismic data that you are comparing? Obviously, differences in acquisition and processing result in seismic differences that may not be associated with reservoir changes.
The other factor is the magnitude of the 4D signal. Are the changes in the seismic response greater than non-repeatable noise? I call this the detectability. Detectability varies from field to field and it is a function of the rock properties, the fluid properties, and the depletion process. To have an interpretable 4D seismic response, you have to have the right combination of rock and fluid properties and depletion process. As an example, to monitor gas injection, the largest 4D response would likely occur in heavy oil. If you are interested in monitoring water sweep, the largest response would likely be with a light oil.
But I think the most critical factor for the successful application of 4D is not technical. It is how we apply the technology within the business environment. I alluded to this earlier. Are we going to get the 4D interpretation in time to impact reservoir management decisions? How are we going to react to those results? What kinds of reservoir interventions can we undertake in response to the information that we get from 4D seismic and what value will those interventions have on the overall field economics? So a successful 4D project is not only influenced by technical challenges but also by the business drivers for each field.
What causes the observed 4D acoustic/elastic response? Is it the pressure or saturation or both, or something else?
In conventional clastic oil reservoirs the 4D response is often dominated by saturation effects. But certainly pressure changes can have an impact on the 4D seismic signal. Sometimes we see pre s s u re increases near injection wells. There can also be a 4D response for fields undergoing primary pressure depletion – especially those that are initially over-pressured, for example the high pressure, high temperature fields in the North Sea. But pressure depletion can impact the 4D response in unexpected ways. The largest seismic changes may not even be within the reservoir but may be in the overburden or underburden in response to compaction in the reservoir. So the 4D response can be complicated and is certainly a mix of both saturation and pressure effects. Throw in compaction and temperature effects for thermal recovery projects – the resulting 4D response can be complex and its interpretation can be non-trivial and non-unique.
Should the observed unique 4D changes be considered as relative changes?
For qualitative 4D interpretation we tend to think in terms of relative changes. Even with an estimate of impedance changes from one survey to the next, it can be a challenge to assign absolute pressure or saturation changes due to non-uniqueness in the seismic response. We try to resolve that ambiguity by bringing in other information from the geology, production history, and flow simulation model. But by using 4D AVO techniques or if you are fortunate enough to have multi-component data that can separate P-wave and S-wave changes, you can think about ways to start separating the saturation and pressure effects of the 4D response and being more quantitative in your estimation of reservoir change.
Are geophysicists able to answer the questions that petroleum engineers expect from time lapse seismic?
We are beginning to. I think for most of the Industry 4D is still geoscience driven. But we know that the ultimate consumer of 4D seismic information is the reservoir engineer or perhaps more appropriately the integrated asset team. 4D is really good at determining areal sweep efficiency. But the engineer is often focused on reservoir length scales that can be very different from what we normally work with seismic data. So when the engineer wants to know whether a one-meter thick sand has been swept, that may be difficult to resolve from 4D seismic. But it could be detected using 4D data and other information can be used to refine the interpretation. What I am trying to get across is that 4D seismic is never a stand-alone tool. It is part of the reservoir management tool kit used by the reservoir engineer and the asset team. 4D plays a role as much as every other tool, like reservoir simulation, to help manage the reservoir. 4D may not directly answer all of the engineer’s questions, but it will help answer them indirectly.
Right, but we have the technology to give them much better information than what we were able to 10 years ago?
Absolutely! And our ability to acquire and process 4D has improved significantly. We recently re- processed a 4D seismic survey in West Africa, where we just shot a second repeat. The first repeat survey was originally processed back in 2003 and the improvement in repeatability using our new processing methodologies was significant. This increases our confidence in the interpretation and we know that we can go forward with the second repeat expecting an improvement over the first.
There is a general consensus that it is difficult to quantify the value of time lapse data and so the decision to go ahead with the acquisition programs; do you agree with that from an Exxon-Mobil perspective, and would you like to elaborate on that please?
Well I think in general it is difficult to assign value ahead of time to any kind of data acquisition whether it is 4D, 3D, well logs or core because you don’t know the outcome of the project. But, there are a variety of tools available to help make a decision to purchase data. We typically apply some form of value of information analysis (VOI). A VOI doesn’t necessarily say how much value you are going to add to the field, but it does tell you how much you are willing to pay for the data. What I like about a VOI analysis is that the process focuses the asset team’s attention on how 4D will be used in the field. We brainstorm scenarios of what could go wrong in the field, what wells would be impacted, what is the chance of those things happening, what’s the chance of 4D detecting it, and what are the dollar values or barrels associated with those outcomes - plug this all into a decision tree analysis and in the end compare the value of the project with and without 4D seismic. The level of effort put into a VOI also depends on the asset management’s experience with 4D technology and previous successes in the area. We try to apply a fit-for- purpose approach to justifying a survey.
As it turns out, the issues that we face in deciding to proceed with a 4D project are rarely ones associated with the magnitude of the 4D response – the real issue is to determine the kinds of intervention we can expect to do in the field given the information contained in the 4D. If we have an in-fill drilling program planned, justifying a 4D is relatively simple. But if you want to use the 4D to monitor something like gas injection, then justification becomes a bit more challenging because you have to ask yourself, even if I know where gas is going, what am I going to do about it? What am I going to do with that information from the 4D? How am I going to add value to the field?
You had just mentioned that in addition to time-lapse and other tools, technologies like borehole seismic, or shear wave, etc. are there now. So how do you think the challenges of linking the reservoir changes to time-lapse can be met in a convincing way?
In order to be more quantitative in the 4D analysis, additional data is critical to remove some of the ambiguity in 4D interpretation. Again, 4D seismic is never a stand-alone tool – it is always part of the larger project involving a number of different technologies that are used for reservoir management. I think there are certainly areas where other data sources can be quite valuable. For fractured reservoirs such as tight gas sands or carbonates, shear wave data might be extremely useful. Permanent seismic systems have a lot of potential under the right circumstances – for example if monitoring the depletion process requires very rapid repeat surveys. But I think that permanent monitoring by itself, not combined with something like intelligent well completions, is probably of less value. You need the combination of both permanent sensors and intelligent wells for that technology to add a lot of value to reservoir management.
There are also tools like time-lapse gravity or EM measurements that have the potential combined with 4D seismic to increase our confidence in monitoring the movements of fluids within the reservoir and the other changes that occur as a result of production.
The majority of 4D time lapse projects have been conducted in offshore reservoirs, passive margins and rifts and largely in the North Sea. So a number of questions then come up – I am sure you must have covered some of this in your talk, why only clastics, why only North Sea, and how much of 3D seismic conducted in the North Sea is time lapse work?
I’m not sure I know the answer to the last question but based on our experience I would guess that the majority of seismic in the North Sea these days is time lapse. It is a mature basin and most of the fields have been previously covered by seismic data. So if you are acquiring any kind of seismic data in the North Sea, it probably has a significant 4D component.
Now let’s go back to why clastics? The majority of 4D projects are in clastics because the seismic response in clastics is generally more sensitive to fluid saturation and pressure changes than in other rock types like carbonates. But that isn’t to say there are not good examples of 4D in carbonates. Aclassic case is here in Canada at the Weyburn Field where CO2 is injected for enhanced oil recovery and sequestration. EnCana has a very active seismic monitoring program and the Colorado School of Mines acquired 9-component 4D data in a research project ExxonMobil helped fund.
The fact that the majority of past 4D projects have been in the North Sea is probably the result of the convergence of a number of factors in the late 1990s and in the early part of this decade. First of all, many of the North Sea fields were reaching a stage of maturity where 4D information could add significant value at the same time 4D technology was maturing. The companies that were applying 4D at that time were also taking advantage of the fact that there were seismic boats available at reasonably cheap rates. Also there were incentives, particularly from the Norwegian Government, to increase recovery in these fields. Finally there was research and development support from the European Union. So I think the convergence of all those factors led to the early adoption of 4D in the North Sea. It’s been said that if you consider the rock properties and seismic data quality in the North Sea, it would not have been the first place you would want to try to apply this technology. But the fact is that it worked and was successful – there are many fields in the North Sea that now have three or four repeat surveys. StatoilHydro contracted six seismic boats this summer, primarily to shoot 4D.
But 4D seismic applications are expanding well beyond the North Sea, particularly for ExxonMobil. We don’t operate many assets in the North Sea. But in the UK we are a 50% partner with Shell in Shell Expro, which has a long track re c o rd of 4D application there. We certainly learned a lot working with Expro in the early days of 4D application. But now ExxonMobil has operated 4D projects over a wide range of geographical areas, geological settings, and production scenarios. The focus of my AAPG Distinguished Lecture is the rapid growth in 4D activity for ExxonMobil in deepwater West Africa – Equatorial Guinea, Angola, and Nigeria.
How much of the world total seismic market does time-lapse represent?
I don’t know. I think that’s something we need to ask the contractors. But within the ExxonMobil Production Company, a very large fraction of the seismic activity is 4D related – well over half. And, the surveys we are acquiring for exploration and development purposes are being designed as 4D baselines.
Fair enough. In your experience, how big should the field be to benefit from the time-lapse technique?
It depends. If you had an isolated 50 or 40 million barrel field with one or two production wells, you probably would not shoot a 4D survey. But for a company like ExxonMobil, fields of this size are rarely developed unless part of a larger project. One of my favorite case studies is the Gannet B field in the North Sea. Operated by Shell Expro, it’s part of the larger Gannet Complex. Gannet B is a very small field that had only two producing wells at the time a 4D program was shot over the Gannet Complex. That survey was focused on several of the larger fields. But the 4D survey over Gannet B resulted in some significant learnings that I think added a lot of value to that little field.
In an ExxonMobil-operated case, we acquired a 4D survey over the Xikomba Field in Angola Block 15 as part of a larger 4D program. Xikomba is a relatively small field nearing end of life – it’s over 80% depleted by now. Our objective for the 4D was to determine whether or not the field’s depletion plan was adequate. The answer was “yes” and we saved ourselves a well. But I don’t think we ever would have shot that survey by itself. Since we were shooting other fields in the block we were able to tie in Xikomba and take advantage of the synergies with the other seismic programs. We did the same thing this year, acquiring a second repeat survey over the one of the larger Block 15 fields and first repeat surveys over several other fields including several relatively small fields—one with only a few months of production. We would probably not have shot the smaller fields in isolation but as part of a larger program the incremental cost for each survey is lower.
Dave if I say that time-lapse seismic is particularly applicable in situations where AVO techniques have proven effective, would you agree with me?
Well, I would say that if we know that AVO works, then we know that there is probably a response to fluids in that reservoir. That’s fine. But a good example where AVO doesn’t work but 4D does is a field in North Sea where we completed a survey last year. The reservoirs in the field are seismically transparent. There is no obvious AVO response – Class I or Class II at best. But when the fluid saturations change during production (water sweep in this case) you change the impedance and previously transparent reservoirs become seismically visible. So in some cases, 4D can allow us image sands that might not have been seen on the baseline survey. This can have a big impact on the geological model. A good example that I show in the AAPG Distinguished Lecture is the Zafiro Field in Equatorial Guinea. Zafiro has fifteen producing reservoirs – all confined to weakly confined channel systems with complex lateral and vertical connectivity. It’s being depleted by various strategies and it’s a mixed seismic impedance environment. Yes, there are some channels with strong amplitude and AVO responses, but others are fundamentally transparent on the baseline seismic. But once you start producing, the impedance relationships with the surrounding shales change, and some sands become visible. Our geologists are calling these “4D sands” because they couldn’t map them before the 4D survey. Including these sands in the reservoir model has resulted in a better history match to production and a more predictive model.
How many 4D projects have been done within ExxonMobil to date, do you have an idea?
Including fields that are operated by others – where we are a partner – probably close to 100 surveys. Of those, about 30 ExxonMobil operated 4D projects and 30% of those are in the deep water and that percentage is growing.
That’s fine, I was just getting a feel, that’s all.
The deep water is a real focus for us right now for some very good reasons. I’d like to elaborate on that because it’s pretty important in terms of our overall strategy for 4D seismic application. For deep water fields there are very critical issues that can be addressed using 4D seismic data. For example, many of our Production Sharing Agreements with the host nation require gas injection as storage for future production. So gas management is critical. We need to know where the gas goes to minimize wasteful recycling and we want to make sure that that field is prepared for eventual gas production. There can be heterogeneities in the field that result in bypassed hydrocarbons. Compartmentalization in these deep water fields limits the effectiveness of injectors and producers. Complex stratigraphy combined with structural elements results in very complex vertical and lateral connectivity. So trying to unravel all of that is a real challenge and 4D can really help us. You look at all of these issues in an environment where the drilling and well intervention costs are extremely high – we have wells in some fields that can cost as much as one hundred million dollars – 4D looks like a good investment.
That gives a good idea. Thank you. So much for the technical part. Let’s focus on another aspect. Did you ever consider giving the DISC course?
I’m involved in a lot of internal ExxonMobil training and we have developed 4D courses ranging from a half to two full days. At the SEG Annual Meeting in New Orleans, a colleague and I presented our one-day school as part of the Continuing Education program. (Ian Jack could not make it that year!) We’ve given the school in other venues around the world, often to national oil company audiences. We also have a relationship with the University of Houston to deliver 4D training as part of their summer program. So although I have not been a DISC instructor, I have been engaged outside of ExxonMobil in trying to expand awareness of 4D technology.
Dave, apart from the science that you practice, what are your other interests?
I suppose my major project these days is getting my daughter through college – quite expensive. I also enjoy bike riding and building model ships. I wish I had the time for the models – I’ve been working on the same one for the past ten years!
I’m also actively engaged in science teaching at the high school level. Working through the MIT Alumni Club in Houston and ExxonMobil’s Science Ambassador Program I helped start a Science and Engineering Academy within one of the local Houston high schools. This was the Academy’s first year and while we only had 22 students, next year we are growing to 33 students and will hopefully keep growing after that. The teachers put in all of the hard work but I’ve consulted on curriculum development, engaged in fund raising – things like that.
One final question. Do you have words of advice or inspiration for young people considering a career in geophysics?
I think there are still plenty of opportunities in geophysics. The challenge that young people will face when entering the Industry is maintaining the appropriate balance between the breadth of training and experience that you want in a very dynamic business environment and depth of knowledge in key technical areas. I personally value those geophysics students who really know how to integrate data from different disciplines, those who are fundamentally aware of the critical issues in geology, engineering and geophysics and can communicate to geologists and engineers and understand the business drivers in the Industry. Students with those skills will succeed in companies like ExxonMobil.
The other piece of advice that I would give young people entering the Industry is to get involved in your professional societies. My activities in the SEG, SPE, and AAPG have added a lot to my career and to my personal satisfaction working in geophysics. You asked me earlier how I got the opportunity to be a Distinguished Lecturer in all three societies. I would have to add to my previous answer that the reason was also my participation in professional society Committees and as a book editor. In addition to the Attenuation Reprint volume, I was involved in the first SEG Reservoir Geophysics Book and I’m currently working on a new edition. I’m also working with Ian Jack on a 4D Reprint Series book.
I strongly second that, I have been involved with the Societies myself. Is there anything that you thought I missed and you were expecting me to ask?
No, the questions were pretty complete.
Dave, thank you very much for giving us this opportunity to sit down with you and ask you your opinion and your views on some of these different topics—we appreciate that. Thank you for that.