Oral-History:G. Paul Willhite

About Interviewee

G. Paul Willhite is the Ross H. Forney Distinguished Professor of Chemical and Petroleum Engineering at the University of Kansas where he has taught petroleum and chemical engineering courses since joining the faculty in 1969. His research program includes studies on waterflooding, surfactant and polymer flooding, water control using gelled polymer systems and carbon dioxide miscible flooding. He is the Co founder of the Tertiary Oil Recovery Project at KU and served as Co Director from 1974-2009. Prior to joining the University of Kansas, he conducted research in the Production Research Division of Continental Oil Company from 1962-1969. He is the author of the SPE Textbook:”Waterflooding” published in 1986 and coauthor of the SPE Textbook:” Enhanced Oil Recovery” published in 1998. He co edited the SPE Speed Up Series on Surfactant Flooding (2011) and Polymer Flooding (2011) and serves as an Associate Editor, SPEJ. He is the recipient of the SPE John Franklin Carll Award and is a member of the National Academy of Engineering. He has a B.S. in Chemical Engineering, Iowa State University (1959) and a PhD in Chemical Engineering from Northwestern University (1962).

About the Interview

G. Paul Willhite: An interview conducted by Amy Esdorn for the Society of Petroleum Engineers, October 26, 2014.

Interview SPEOH000115 at the Society of Petroleum Engineers History Archive.

Copyright Statement

The content of this oral history transcript, including photographs, audio and audiovisual clips, and biographical information, and are intended for noncommercial educational and personal use only. Copyright restrictions apply. Commercial publication, redistribution, or use of the content is not permitted.

Anyone wishing to use the text, image, or audio or audiovisual files associated with this oral history transcript for publication, commercial use, or any other use not expressly permitted, must contact the SPE Historian.

Society of Petroleum Engineers Historian
10777 Westheimer, #1075
Houston, TX 77042
It is recommended that this oral history be cited as follows:

[Interviewee Name], interviewed by [Interviewer Name], SPE Oral History Project, Society of Petroleum Engineers History Archive, [Interview Date].

Interview

INTERVIEWEE: G. Paul Willhite
INTERVIEWER: Amy Esdorn
OTHERS PRESENT: Marco Blomsma
DATE: October 26, 2014
PLACE: Amsterdam, The Netherlands

Background, Education, and Entry into the Petroleum Engineering Profession

ESDORN:

Well then, we can begin. My name is Amy Esdorn, and I am performing an oral history with Dr. Paul Willhite. The date is Sunday, October 26, 2014. Dr. Willhite, we’re just going to start at the beginning with your background. Where did you grow up?

WILLHITE:

I grew up in Waterloo, Iowa, which was a town in the northeast corner of Iowa, most known as the location of the John Deere Tractor Company.

ESDORN:

Great. What do you think some of the factors were that influenced your interest in the engineering field?

WILLHITE:

When I grew up, I spent a number of summers out on the farm, on my grandparents’ farm. My father always repaired things. I was fairly good mechanically, interested in chemistry. So, as I went through high school, it seems like I did well in the courses that – you know, chemistry and physics and math, and it just seemed like engineering was the place where I could develop a career. Certainly, my father worked for John Deere Tractor Company as a machinist, and I didn’t see that was the career path that I wanted to follow. It’s sort of a result of experiences and exposure to possible career choices. I ended up going to Iowa State. I happened to major in chemical engineering. I finished with a BS degree in Chemical Engineering. And then went to Northwestern University and got a PhD in Chemical Engineering.

At that point, I happened to work on a project involved in heat transfer in porous media which was sponsored by the API [American Petroleum Institute], and I -- some of the recruiters from the oil companies were recruiting at the point. I had no prior contact with the petroleum production industry. I had a science project where I actually built a little distill and I got some crude oil from Standard of Indiana, which would never happen now. I actually created a little distillation project. This was in my senior year in high school. That’s about the extent of my exposure to the petroleum industry before I finished up my PhD and made a decision to go to work for Conoco Phillips. Well, it was Conoco at that time.

ESDORN:

That’s great. Thank you. Go ahead and tell us -- you touched on it little bit, but can you tell us a little bit about what your college career and your masters and your PhD? Just go into a little bit of detail about that. For instance, what did you study exactly in college, and why did you study that specifically?

WILLHITE:

The easy answer is that everyone pursuing an undergraduate degree has to study something. I happened to be offered support from a professor who was the major adviser of a professor I’d had at Iowa State, and one of the projects available was to study heat transfer in porous media. And so, I just -- that was something that I was comfortable doing. I completed a project. It could have been many other things, but that just happened to be the project that this professor had, and it’s just pretty common, the academic environment that faculty have research projects and they’re looking for students to follow through and complete the research project because they’re always tied to some source of funding.

There is an expectation of the funding agency that there’ll be something useful completed from the research project. That’s how I actually got into the -- actually, I skipped the master’s thesis. I went straight through to a PhD in Northwestern. I had a program that if you did well in coursework in the first year, year and a half, that you could proceed to the PhD without writing a master’s thesis. So I did not write a master’s thesis. I just wrote a PhD dissertation and finished, and fortunate to finish in three years, which is… that happened to be the way it worked.

ESDORN:

What was your PhD thesis in?

WILLHITE:

My PhD thesis was on radio heat transfer in porous media affected by fluid flow. And so I did a series of experiments where heat was flowing radially in a core, and water or air was flowing perpendicular to the flow of heat. The objective was to determine the effect of flowing fluids on the thermoconductivity of the porous rock. I completed that, and there -- wrote a paper, as usual.

ESDORN:

Thank you. Okay, how exactly did you get involved in working in the petroleum industry? You’re in academia, but how did you get involved with production?

WILLHITE:

When I completed my PhD, of course I interviewed a number of companies ranging from chemical companies, oil companies, and then production research. It turned out that one of the opportunities that I had was related to heat transfer in porous media. So I joined the thermal recovery group in the production research division of Continental Oil Company in Ponca City.

I worked there for seven years, and I was involved in a variety of different projects involving heat transfer and use of heat transfer to improve oil recovery. So, projects ranged from in situ combustion -- and all of them were related to field projects. The group that I joined was basically a technology application group. And so, I had the rare opportunity to be exposed to field projects in several different areas. I mentioned I had spent some time -- so, in situ combustion project near Kaycee, Wyoming, so North Tisdale Field Project. Conoco had recruited a number of chemical engineers, as other oil companies did, to join their production research divisions.

They had a practice of exposing new employees from other areas to field-related projects. I was involved in -- that project, made a few trips to Wyoming and was involved in some of the analysis. I worked in a Wyoming project. We generally did that in the winter when it was cold. Worked on some hot water flood projects in Southern Oklahoma, so injection of hot water to increase oil recovery. Then, after a few years, Conoco bought the Douglas Oil Company in California, and they acquired a large property in the Cat Canyon Oil Field. That was a heavy oil field. They were in the process of -- this is in the mid-‘60s, ‘64 or ‘63 or something like that. The company then started to develop that field using cyclic steam stimulation.

So I ended up working on that project with that. One of their engineers, Bill Dietrich, who actually was killed in the plane crash several years ago. But Bill worked for Conoco. So we had some very interesting experiences in trying to develop that field. It’s a large field, and recover -- oil-based cyclic steam injection.

So I had a lot of field experience to many different kinds of thermal recovery projects as well as with being a chemical engineer by training, I didn’t know much of anything about production engineering or reservoir engineering. They, like many companies, had sent their new employees from a different discipline off to reservoir schools and production schools, a variety of different schools. So my background in petroleum engineering was obtained by a combination of training courses. We’d have one-week training courses at OU and then field experience.

I learned the field of petroleum engineering through a combination of practice and then some exposure to short courses that were used across the industry at that point. Conoco was not the only company that hired chemical engineers. I can name many chemical engineers. Now I could say Larry Lake and Gary Pope and Lyn Orr and George Hirasaki and Kishore Mohanty. There are many of the academic people who originally started out in the production research laboratories doing research on enhanced oil recovery. Had happened when I was at Conoco that the only thing I really worked on was thermal recovery processes of using heat in a variety of ways to increase oil recovery, primarily in heavy oil reservoirs.

I did have an opportunity -- in the latter part of the time I was at Conoco, there was a company-wide study of the potential with heavy oil tar sands and oil shale relative to their future production. I was assigned to look at heavy oil and tar sands. I spent maybe a year and a half on this company-wide study studying, doing some projections and economic analysis of heavy oil, large heavy oil fields as well as tar sands, and in Canada.

I had some opportunity to get exposed to mining at that time and the beginnings of in situ processes. Of course, that’s developed significantly since then.

ESDORN:

When was this when you were working at Conoco, and how long were you working at Conoco?

WILLHITE:

I worked at Conoco from 1962 to 1969, and so, like many situations, there’s a point in your career -- I’d always had an interesting teaching. It was just about the right time to think about that. If I had not looked for an academic position, I probably would have been retired by now. Perhaps I should be retired by now.

Anyway, there was a position that developed at the University of Kansas, and I interviewed for the position in summer of 1969 and then left Conoco in August of 1969, joined the faculty at the University of Kansas.

ESDORN:

That’s great. Thank you. Okay. So, you work primarily in EOR, in production and secondary and tertiary oil recovery. How did you get involved in that discipline? You’ve already talked about it, but what drew you to that discipline specifically?

WILLHITE:

Of course, at the time that I joined Continental Oil Company, this was at a point where there were not a large -- very many new reservoirs being found. And so, there was emphasis across all the companies on methods of improving oil recovery.

The target was any process where you could go in to existing reservoirs that were being depleted or even the heavy oil reservoirs. They were so viscous that the production was relatively small. I think some of the reservoirs would produce 5 percent of the oil in place. There’s a huge target for oil recovery, and of course, the other factor was that of, there was the projection of a diminishing supply. Because the US at that point in time had peaked or was near peaking in production in the production from the existing reservoirs was on the decline.

At Conoco, there were other groups working on miscible fluid injection, other groups working on surfactant injection. I just happened to spend all of my time when I was there working on thermal recovery projects. I had a general interest in enhanced oil recovery, but during that period of time, it was only limited to thermal recovery projects.

ESDORN:

So that decision was really made by others then, is that what you’re saying? Or just to go into thermal recovery as opposed to any other…

WILLHITE:

Well, that was the position I accepted, and I enjoyed what I was doing. I was able to solve some problems. When they began cyclic steam injection in the Cat Canyon Field in California, they were injecting at 2,500 psi and steam temperatures over 600 degrees. And I had been working in wellbore heat transfer since I’d been -- spent a lot of time in heat transfer. I had extended some of the work that Hank Ramey, who I knew, and is well-known in the petroleum field.

I came up with a method of predicting the casing temperature during steam injection. That turned out to be a very useful paper that’s survived for a long time because it allowed us to predict the temperature of casing during steam injection, which shortly after -- I think when Conoco did their first cyclic steam injection in Cat Canyon, the first well that they injected the high temperature steam and who failed, the casing failed. With just collaborating with Bill Dietrich and some other colleagues at Conoco, we figured out why that happened, and so there is—we wrote-- there’s another paper which I think is the pretty close to a classic paper on design criteria for steam injection wells. Just looking at things, a practical thing, and it was pretty obvious. Once we had identified the problem, what to do about it. So there was a new method of completing wells for high temperature steam injection that avoided casing. I don’t think there was a casing failure after Conoco adopted that method. From what I’ve seen in the literature, there are other companies that have adopted but been sort of out of that field for quite a while.

The other thing that I think is a contribution during that period of time, there were a number of wells that were completed with what’s known as J55, the standard oil field casing, those with just standard API round thread coupling. I basically invented a pre-stressed insulated tubing strength that we got a patent for. Actually, this was in the -- I’d say the mid ‘60s. Designed it, had it built out in the field. It actually worked.

Now, in the years, many years following, I noticed that the same concept has been used by a number of other companies, a much better insulation, better design. We designed it with the insulating materials and facilities that we had at the time, but as I’ve looked at other applications, it’s pre-stressed tubing being used now with very high-tech insulation and I’d say much better mechanical design. But at least in the mid ‘60s, there wasn’t anything there except what we had put together.

I look at my career at Conoco, the main things I think I contributed to were wellbore heat transfer casing temperature, design of steam injection wells, and the idea of using pre-stressed insulated tubing strings for protection of casing and also prevention of heat loss. I think quite a few applications in other areas that I wouldn’t claim that I was responsible for, but very interesting to see that the general concept has been used in a number of places for reducing heat loss in, say, Canada and I think even some subsea completions. Anyway, that sort of summarizes what I think I accomplished when I was at Conoco.

ESDORN:

Thank you. That was great. I appreciate it. Would you like to take a glass or sip of water?

WILLHITE:

I can always do that.

ESDORN:

Okay, so you came up with the method of predicting the temperature of the wellbore casing during steam injection. Can you please discuss what precipitated that invention, what problems were you solving with that?

WILLHITE:

When I started working on wellbore heat transfer, Conoco had hot water floods. I used the model that Hank Ramey developed. He wrote a very classic paper. I was able to apply that model, and then I began to think about how do you reduce the heat loss from wells? And when you start thinking about that and think about, well insulation and a variety of other techniques, that led me to the question of -- well, Hank really didn’t provide much description on… he didn’t provide any description relative to casing temperatures.

I applied I think some well-known technology and came up with a way to predict the temperature of casing. I think, this was also driven by the fact that when Conoco got into steam injection, it was pretty obvious that the casing temperature was going to increase.

In most of the steam stimulation projects, they just set tubing on a packer and they didn’t do anything about protecting the casing. In the projects of the central valley in Bakersfield when they were doing steam stimulation, the temperatures were low enough so that nothing happened. They were able to inject steam by setting tubing on a packer and boiling the annulus out.

And they didn’t really pay attention to what the temperature in the casing was because it didn’t have any failures. I got interested in how to reduce the heat loss during steam injection. That led to the development of a way to predict the casing temperature. And of course, others could have done it. I just happened to be the first one that became concerned about casing temperatures. And this concern was even elevated when we… Conoco had their first casing failure and I started looking at that. I started to ask the question, well, why did the casing fail?

There wasn’t anything particular about them other than they had failed out of joint. So I looked at the temperatures that I thought, I was able to predict, and talked to some of the metallurgical folks at Conoco. I think within maybe a week of thinking about that, came up with the reason that the casing failed. Very simple. Casing expands thermally, and if you heat it too much, the internal stress can exceed the yield stress of the casing, and it actually deforms.

When the well cools off, it pulls out, and it happened at the particular joints where API round thread and it broke the joint when they cool the well off. It’s a very simple application of technology. Actually, some things I learned when I was a sophomore in college that I thought I’d never use. But anyway, it turned out -- and then there was a couple of folks at Conoco. I think Bob McGlasson was our metallurgist and helped in developing the notion of pre-stressing tubings--so how do you avoid casing failure?

You avoid it by -- when the casing [unintelligible - 00:31:47] heat anyway. You just pre-stress it so that as the temperature increased, the stress is relieved and you can inject at very high temperatures, even with tubings set on a packer, and not cause a failure of the well. And in addition, the other factor was using higher strike casing. Those wells are used S95, which 95,000 PSI yield, and then buttress thread couplings, which are stronger than -- they fail at higher stresses than the pipe would fail. The combination of those two things with the temperature model allowed the design of steam injection wells for the high temperature service.

Of course, companies that can inject steam at much lower temperatures did not have to do that, although I noticed in Canada that they’re all using high stress casing and in the steam projects there and buttress thread couplings -- so I think that some of the things that were discovered many, many years ago have been in some way adopted in the industry, although I had nothing to do with that.

ESDORN:

Great. Wonderful. Thank you very much. You sort of touched on this already, but I just want to go ahead and ask it again. What led you to pursue a career in academia?

WILLHITE:

I had spent seven years at Conoco, and one of the reasons that I went to work after PhD is I had had a number of instructors who had never practiced. I had always had teaching as a possibility. If you are in industry, there is a point where you if stay much longer, you will retire in industry. Another issue is that if you don’t leave at a certain period of time, you will have difficulty in an academic environment. Just turned out that about seven years, at least in my sense, was about the right time.

Actually, I wrote a letter to Hank Ramey and said, “Do you know of any academic I might be interested in?” He sent me a letter back and said, “Well, there’s one at Kansas.” That actually connection that developed was the way that I became aware that there was a position at Kansas. That was the reason and just a point in time where they said I could have stayed in industry. If I had done that, I’d been retired by now.

I enjoyed what I was doing, but I also knew that I liked working with young people. I had spent -- during the time that I was in Ponca City, I was scoutmaster of a Boy Scout troop with the American Legion Children’s Home, virtually I think, about the entire time I was there. Those were kids that were placed there as wards of the state. I enjoyed working with those kids. They may or may not have enjoyed me, but they were able to do a lot of things that they would never had been able to do. So we went camping once a month, regularly, and so forth. Anyway, that led me -- if I had just had no interest in academia, I just would have stayed more with [industry]. So I made that decision. I had not regretted it. I had a good working environment at Conoco.

There isn’t any other rationale except a point, and I think everyone, it’s a point in their career where is it you want to stay here for the rest of your life? Although today, it looks like people are… people don’t look at staying with one company or any company very long. But at that point in time, I think most folks looked at companies, if they were happy with them, as a potential career. I had a lot of friends at Conoco. I had a lot of good mentoring when I was there. Bill Martin, I think I’m not sure if he’s still alive, but Bill Martin and John Dew. And actually, Bill Brigham was one of the guys that went to Stanford.

I think the environment was very good for starting, and someone who just came out of school particularly that I didn’t really know anything about the production industry.

ESDORN:

Were you interested in performing research as well, or was that -- I mean, you had done research obviously in your PhD program. Was that something that you were interested in pursuing as well?

WILLHITE:

When I left Conoco, clearly, I was joining the university to become involved in teaching. At that point, research was something that was done, but it was not the driving force. The principal focus was on teaching students -- and I joined the Department of Chemical and Petroleum Engineering at the University of Kansas because they had degree programs in both Chemical Engineering and Petroleum.

In fact, during the time that I had been a faculty member, which this is year 46, I have taught most courses in both areas. The research emphasis started out very slowly, and the research emphasis when I joined the faculty was nowhere near it is now. And there was little funding. So the expectations were primarily teach well and develop a research program as you’re able, and the expectation was that you would develop a research program of some kind.

ESDORN:

I’m sorry. I’m going to stop you. We’ve got a fly.

WILLHITE:

There is a fly.

ESDORN:

Buzzing around.

[CROSSTALK]

ESDORN:

We can restart the question and it won’t be a problem, but okay. Thank you. I never had that problem before. It’s a first.

Okay. Did you feel like you finished that question about academia, do you feel like? Or is there anything you want to add about why you went into academia?

WILLHITE:

I think so. Yeah.

ESDORN:

Okay, your research centers primarily on enhanced oil recovery. Could you please describe some of the most significant advances in EOR [Enhanced Oil Recovery] techniques?

WILLHITE:

When I joined the University of Kansas, there was no research support for enhanced oil recovery at the university. No one was doing anything. There was no support that I was aware of from outside funds. So actually, I began by doing groundwater research because I could apply the reservoir simulation, some of the simulation knowledge that I picked up at Conoco to groundwater research.

I did that for a couple of years. At the same time, I began the development of a course on enhanced oil recovery. That was partly motivated by the fact that Kansas was a state with declining production and the students who were coming through, I wanted to introduce them to some enhanced oil recovery. But again, in order to do that kind of research, you have to have funding.

The first two or three years, I really didn’t have any support to do research on enhanced oil recovery. In the early ‘70s, Marathon, their research lab, provided a grant to the department to begin doing some research in enhanced oil recovery. I started out -- at that time, polymer flooding was one of these magical ingredients that would solve all kinds of problems. I started doing some work, research on the flow of polymers, how they flow through in porous media. I think we identified some interesting characteristics, I think some fundamental characteristics of how polymers flowed through porous media. There are of course many other people did other things, but this was the starting, the beginning of the enhanced oil recovery research.

About the same time, in that period, there had -- my experience at Conoco was interesting, in that we always seemed to be about five cents to ten cents a barrel short of being able to do field demonstration projects economically. In the early -- I think about 1973, ‘72, what, the beginning of the problems between Israel and the Arabs in the Middle East. At that point, I believe it was in 1973 that the war broke out, followed by the oil embargo, and gas lines began to form. At that point -- and at the University of Kansas, it was a very interesting period. I had no knowledge of what was going on in campus when I joined the department in 1969, but it turned out that Kansas was Berkley Midwest. In the Spring of 1969, there was a student uprising against the ROTC, demonstration that was followed by student unrest in the fall, the burning of the Kansas Union, racial unrest in Lawrence. The governor declared Martial Law, and we went through -- this is in ’73, followed by the resignation of the chancellor after the students went out, this chancellor went out, let the students out of final exams. And I think it was in ‘71.

Yeah, this whole period is connected. That upset the Kansas legislature, which was followed as usual by no raises for the faculty and just general discontent. And after the chancellor left, the university was trying to recover. This is important because the way that we got into enhanced oil recovery is sort of serendipitous. Its starts out partly because of that it’s related to the oil embargo, also related to the fact that the new chancellor, chancellor named Archie Dykes, came in July of 1973. This period lasted a long time.

He came in and he put out a general flyer announcement of the university. Do you have any ideas on what we could do to show the value of the university to the State of Kansas? At that time, a colleague and I, Don Green and I and Lloyd Preston, got together and we were considering the response to that memo and we were aware of a number of things. First, there was no enhanced oil recovery research in Kansas. Kansas was a declining state in terms of production.

Virtually all of the operators in Kansas were independent operators. They had no research and development capacity. So what we did was we came up with a proposal which was known to what became the Tertiary Recovery Project. What we proposed to do is to see if we could get some support when we proposed that we would have a research program that would evaluate the potential of oil reservoirs for enhanced oil recovery; do research on processes that would be applicable in Kansas; develop technology transfer programs; develop field demonstration projects; and educate students. That proposal was prepared in about November of 1973. This covers a span of several years in the process. We used the contacts of -- Lloyd Preston had been a faculty member for years and knew most of the Kansas, and at least the leaders in the Kansas independent oil industry. So we arranged to take this proposal to the Eastern Kansas Independent Oil and Gas Association. We had a meeting with them and talked about that project.

We took the proposal to the Kansas Independent Oil and Gas Association, and in both cases, we got favorable response. Then, as things progressed internationally, the Kansas Independent Oil and Gas Association made a decision to submit the proposal to the governor’s office. That was done in I think in December of ’73, and in January of ‘74, the Governor, Robert Docking, announced that he was going to insert a research program called the Tertiary Recovery Project into the state budget. That marks the beginning of the funding for enhanced oil recovery in the beginning of what known as TORP or is now being called the Tertiary Recovery Program. But for many years, it was a Tertiary Recovery Project.

So, the essentials for doing research in enhanced oil recovery -- and basically, you have to have money. So we were able to start our research program because we were funded as part of the university budget and have been funded continuously since then. Don Green and I were co-directors. Don retired a few years ago, and then I stepped down in 2009, but… I was responsible for the project for 35 years. Basically, we were able to start a research program because we had support from the Kansas oil industry program focused on the Kansas oil industry and potential processes that would be applicable.

Now, if we look at the processes that have been developed, some of the processes that are being used were not really applicable to Kansas. We looked at -- it turns out that the thermal recovery processes that I worked on were more applicable to California and then eventually, Canada. So we did some initial work on that, and then we discontinued that. But the processes that I think have significant potential -- and much of the work has been done at several different places, so I’m not going to claim that we had major contributions to any of these. We did some work on polymer flooding. We spent a lot of time looking at surfactant flooding. And surfactant flooding of course originally, the original concept of micellar polymer flooding started with Marathon then was evaluated by Exxon, now ExxonMobil. Then I think at that point, after some initial years, we realized that in order to flood fields in Kansas that had high dissolved salt content, high divalent ion content, the surfactants would have to be formulated. That’s what Exxon demonstrated they’d have to be specially made. Then we essentially shut down that research because we didn’t have the staff or anyone in the chemistry department interested that would be able to formulate the [unintelligible - 00:54:35].

Since then, the recent resurgence of the oil price, there’s a group led by Gary Pope and also George Hirasaki -- George is at Rice; Gary is at UT Austin. Gary has a huge project, but I think to their credit, they have developed a large number of systems. They had some chemists that would put together molecules. And so, they have developed a large number of systems that will work under a very wide range of environmental conditions. I think as far as development, that is a major development in enhanced oil recovery. I don’t know to what extent some of our early work may have contributed to that, but we just were not able to come up with formulation of surfactant systems for Kansas reservoirs. There are some now. We actually have a field project that we’re developing that is based on the general concepts and the systems that I think came out of Gary Pope’s lab. That’s one area of development.

When we were not able to or when we made a decision that we really could not bring major developments in the surfactant area because of the fact that we couldn’t really create the surfactants, we turned our attention to areas that we thought we could apply in Kansas. The one area that we spent a lot of time on was profile modification. Water production is a major problem in all kinds of fields. In fact, even the reservoirs and the worldwide reservoirs and nobody was interested in water production 30 years ago are producing water to no one’s great surprise.

Water control is how to slow down water is a major factor. We began a research project stimulated by some of the work, early work at Phillips Petroleum Company using gel polymers to reduce water. There are two areas that we worked on. One was just injecting gel systems in injection wells that would reduce the permeability in high permeability areas. And the idea behind that was that if you could plug up high permeability areas, the water would go someplace else and displace the well. Because the high permeability is generally where already, oil displacement was pretty thorough.

We did work and field demonstration projects on treating injection wells. Then we also developed some research programs trying to understand how gels placed in production wells could slow down the production of water. Some of these were fundamental studies, and I think we’ve contributed to the mechanisms of that. I need to get a…

ESDORN:

Yeah, absolutely. Anytime you need to stop, just let me know. You’re really doing a great job.

WILLHITE:

I felt something sliding into my throat.

ESDORN:

Yes. Of course. Okay, so you were discussing some of the EOR techniques that TORP brought about, so if you could continue with that.

WILLHITE:

In the permeability modification, one of the things that we always had and try to do is to do some field demonstration projects. What we did relative to permeability modification projects is we worked with some of the companies to determine what actually was going on. When we started out, the companies, were just mixing things at the surface and injecting the gelling solution downhole. They assumed that because gelation was relatively fast, that they were pumping gels into the formations. It turned out that we actually -- we proposed for the first time that they put a pressure bomb that would read core pressure, bottom oil pressure, and temperature during placement and demonstrated that in fact they were just -- because fluids were cold at the surface and they didn’t warm up when they got down to the bottom, they weren’t actually injecting the gelling solution into the gel. The gelation occurred after the polymer entered the formation.

So we did a number of fundamental studies just to understand gel placement. That area, basically -- I think we studied it as much as reasonable. One of the challenges in all of the profile modification systems that are available now is that their gel times are very short, which means that you can’t pump them very long before the pressure starts to increase and it becomes obvious that they’re gelling in situ. If you pump long enough, you’re going to end up with the tubing full of gel, so you have to figure out when to quit.

We did try a few things like injecting some oil after the main polymer gellant had been applied, and that seemed to work, although operators are always a little bit suspicious of putting in oil. They got it back. But that was based on some techniques. But recently, we had a project, a process co-invented with Jin Tai Liang, who is now at Texas A&M and a colleague, Cory Berkland, and myself, where we came up with a method of using nanoparticles to delay gelation. The project process has been developed in the laboratory, but it has not been field tested yet. There’s a research project with Conoco Phillips that because of all of these secrecy and what have you. This is a coming area that I think has potential because we have demonstrated at least in the laboratory that gelation can be delayed for pretty long periods of time. I can’t say anything more about that. That’s about the end of our research activities in that area.

The other area that TORP -- when we founded TORP, there were two areas that were not being done generally across the country. One was technology transfer, although if you look around in Texas, there is some experiment stations that some of the organizations had done, some short courses, periodic short courses. But when we started TORP, we planned to have regular technology transfer workshops, symposiums and so forth that were focused not on the SPE audience. The SPE is that well respected, high technological society in the papers that SPE meetings are really of very high quality. We thought that there was another level that if we were to try and get the technology transfer to the independent operator, that we could put lots of equations in presentations that we had to present concepts.

We developed a technology transfer program at that point relatively, one-day seminars, relatively low cost. We had an enhanced oil recovery conference every other year in Wichita. We did these around the state depending on the need. So, the technology transfer program became known by some folks. Eventually the DOE [Department of Energy] became interested and asked us and actually provided some funds to develop what’s called the Kansas Technology Transfer Model. We did in fact develop that, which then, parts of that—and I think it probably never had been formally recognized—were picked up by the Petroleum Technology Transfer Council. One of the folks that we had working on the Kansas project also went to work for the Petroleum Technology Transfer Council. But in the current workshops that are spread all over the country—and there are lots of them now and I think they’re well done—I think are the direct result of some of the early work that we did, although it’s sort of the -- the inventor has a thousand failures, their fathers. But nobody else was doing that kind of thing when we start -- we actually started that in -- the TORP started officially in 1974.

We’ve had series of workshops every year since, more of them now, and I think they cover wider ranges of areas, and of course they’re more expensive. The oil price is up a lot more. But they’re still geared at not the typical audience for an SPE paper, but they’re geared at the practitioner, and so the independent oil operators, primarily.

That’s one area that as a result of -- of course, combination of our research program but also commitment when we put TORP together to do technology transfer at a level that would help independent oil operators, particularly since the majority of our funding came from the Kansas legislature, that would focus on the needs of Kansas independent oil operators.

Along with this, we also had a commitment to develop field demonstration projects. One of the interesting things that happened during the period of the ‘70, I’d say the late ‘70s, is the DOE began to develop resources for funding field demonstration projects. In that period from that beginning of DOE funding, which incidentally appears to be disappearing from the scene, we actually had seven major field demonstration projects that I’m fairly certain would not have occurred if we had not taken the leadership because we wrote the proposals for each of the projects. They are all involved Kansas independent oil operators. We had DOE funding, so that helped…I think the industry, without DOE funding, we would have never gotten any of them off, because the Kansas Independent Oil Industry, at least at that time, when we were doing it, was more focused on production and maintaining existing production.

So our field demonstration projects ranged -- we had a project to essentially develop a unitization strategy, design a water flood for the Stewart Field in southwest Kansas. That eventually led to the purchase of and unitization of the field by a company called Petro Santander who did the water flood. And for a while, it had the largest production of any field in the State of Kansas. Since then, near the end of the water flood, they converted that to a CO2 flood, which is ongoing now. It’s in its early stages.

We did another project, which -- we called it -- it’s a result of what we called a CO2 initiative. We realized that a limitation of carbon dioxide in Kansas was that there was no CO2 available. And, in the, say, the middle ‘80s, Mobil put in a CO2 flood in the Postle Field in the Panhandle of Oklahoma. At that time, there was also plenty of CO2 available at that point. We began to vision the possibility that if there was CO2 available and if the reservoirs in Southwest Kansas were amenable to CO2, that there might be a possibility of extending the pipeline.

Let’s say about the mid ‘80s or mid to late ‘80s, we developed the Carbon Dioxide Initiative, which basically, we collected oil samples from all the reservoirs and many of the reservoirs in Southwest Kansas. And we ran laboratory tests to determine what the miscibility pressure, the minimum miscibility pressure. We did that and we established that it was possible to inject CO2 in Southwest Kansas. About the same time, DOE announced that they were interested in doing demonstration projects supporting CO2 and we had also evaluated similar projects in Central Kansas. We knew that the Hall-Gurney Field in Central Kansas, which is the largest Lansing-Kansas City reservoir in the state, was a candidate for carbon dioxide flooding. And so, as we talked around to operators, we had -- Shell CO2 at that time was interested -- they had surplus CO2.

One of our former members of the Tertiary Oil Recovery Project, Lanny Schoeling, worked for Shell. Lanny eventually went to Kinder Morgan. He runs their production and research section there, but at that time, they were trying to expand, find markets for the CO2. We started evaluating the possibility of doing a demonstration project in Central Kansas, and we wrote a proposal. And when we wrote the proposal, we had some commitment from Shell CO2 to provide CO2 in some way.

Trucking, if necessary, but that kind of -- it turned out not to be needed. We actually obtained funding from the Department of Energy to do a 10-acre CO2 pilot test in the Hall-Gurney Field in Russell County, Kansas. So that funding was developed. Around that time, Shell CO2 sold out to Kinder Morgan, so Kinder Morgan then came in. At the time, the oil price was going up, by the way, somewhat.

We developed a proposal, and there were questions about whether we could really truck CO2 or Kinder Morgan would support trucking CO2 from Southwest Kansas from the Panhandle of Oklahoma to Central Kansas. About that time, the power plant at Russell, Kansas blew up. It was replaced by a co-generation plant, which involved making ethanol. We had -- this is serendipity. There was an ethanol plant eight miles away from the field project, and so, through the cooperation of a lot of people -- Murfin Drilling had a real forward-looking vice president, Jim Daniels, who led that effort, and we had just a collaborative project with Kansas Geological Survey. We had cooperation from Kinder Morgan.

But we were able to secure a way to provide CO2 from that plant. Then we ran our pilot test that began in 2004. We ran through 2009. We had actually started a little earlier than that. So we completed a 10-acre pilot test demonstrating that CO2 could displace oil in Central Kansas reservoirs, that independent operators could operate the injection facilities and no… with reasonable attention to safety and other things, so there’s no real difficulty. And so that project ended. I think we turned in our final report in 2010 with the hope that there would be a full-scale field project in the Hall-Gurney Field. That’s sort of the real problem was that there were lots of small operators and at that time, no company was interested in unitizing it.

We finished the project. There were some interesting things that we discovered about small projects, one of them being that you can displace the oil but you have to catch it. If you don’t catch it on your property, the adjacent property owners get to sell the oil. We became very much aware that in order to operate a full-scale commercial project, it was necessary to have a very large field-wide project. And my notion is that the CO2 will displace oil wherever it wants to go. You have to have a project big enough so that you can catch the oil that you displaced. We think we demonstrated that. And just recently -- it’s interesting. There is a company that was formed, C12, operating out of Denver that is in the process of unitizing the Hall-Gurney Field.

They have a contract with the ethanol plant, so that they’re going to take the CO2, they’re going to build a pipeline into the Hall-Gurney Field. When all this gets done, I understand that sometime in the next year or whatever, there will be a full-scale field project carbon dioxide miscible project in the Hall-Gurney Field in Central Kansas. We think that we’ve made some contributions there. We’re no longer involved in that. But that is an example of the field demonstration project that we were able to carry through because we had support and of course we invested state funds provided by the legislature to develop that project, as well as support from another company. We had excellent support from Murfin Drilling, who is the operator of the project, because of course, there are more details available in the project completion reports.

Now, in terms of field demonstration projects, there is a surfactant project that we have designed. I’m working with a -- I stepped down as director of TORP. I’m not involved directly in TORP now, but I’m working with a colleague on TORP. We have designed a surfactant flood system. There’s funding for a field test, and that’s going to go on hopefully in the next year in the Trembley Field working with Berexco, which is a large independent oil company in Kansas. We have a long history of working with independent operators to develop field demonstration projects of enhanced oil recovery projects or processes that we think will work in Kansas. I need to go for some water.

ESDORN:

No, please do. Please do. I’m just looking at my notes. There are a couple of things I wanted to sort of follow up on a little bit that you -- and some things you mentioned way back. Just so that you know -- you might be a little taken aback. We were talking about polymer flooding, that there were characteristics for how polymers flow through porous media that you basically described. What were some of those characteristics that you discovered? What were their impacts on the industry?

WILLHITE:

When we did research on polymer flooding, there was a lot of magic involved in polymer flooding. We set out to determine if you could propagate polymers through porous rocks. Specifically, we looked at the retention of polymers. There was a question whether polymers were retained by absorption or whether they were retained because they were big molecules and they got stuck in the pore space. What we demonstrated was that polymers were retained because they got stuck in the pore space.

We called mechanical retention. We conducted a series of experiments that basically showed that that happened. Of course, we also showed that some of the… many of the polymer molecules got through. So if you accounted for retention, which was not a killer -- some of the early experiments indicated that lots of polymer would retain, but we demonstrated that you could propagate polymer. Now, recently it’s very interesting.

Polymer flooding had a very slow process. We did a lot of small field tests, a lot of uncertainty about whether you could propagate polymer molecules over long distances. What’s an interesting development in the field is the number of high permeability reservoirs primarily in China. The folks -- Demin Wang, who is well-known in the polymer flooding literature, basically promoted polymer flooding and high permeability reservoirs in China and done remarkably well there. There’s a similar project in Canada where they’re injecting polymer into the very high permeability, heavy oil reservoirs and very successful.

I think the initial applications of polymer were in reservoirs that were not nearly as good candidates as the ones that are being used now. And part of that is simply because it’s hard to propagate polymers through porous rocks. If the permeability is very low and if the permeability is high, it’s very obvious from all of the field tests that the polymers can be propagated and they can also help the flooding. As far as our contribution, I’d say we just had a small contribution demonstrating that in low permeability rocks, you’re going to retain polymers regardless of whether you have absorption or not. I think that’s sort of a minor contribution. We just -- that is something that we did earlier that nobody understood when we did it. Now nobody is worried about it.

ESDORN:

Very good. Thank you. Let’s see. I’m just looking at my notes and making sure that there’s nothing that I want to follow up with. My next -- kind of following up with -- you talked about a little bit with TORP that you came up with the technology transfer model. You discussed that a little bit, that you have, for instance, workshops and things for independent companies and that sort of thing. Is there anything else that you can describe about what did that model look like and what was that -- I mean, how was that any different from anything else that has been done in the past?

WILLHITE:

One of the things that we developed and at least the philosophy in our technology transfer approach was the fact that -- one way to turn an audience off, turn operators off is to put a lot of equations up. I think one of the things that we did is we specifically developed technology transfer workshops that used -- at least we had presenters who used common oil field terminology.

They talked in terms of concepts. Rarely will you an equation at any of the workshops that we have sponsored. It’s primarily trying to bring technology to the level of the operators who were more concerned about getting things done, producing oil, solving their problems rather than -- and as opposed to -- if you go to most of the SPE meetings, you’ll find a very high level of technology in most of the papers. We recognized that if we did not focus at the level of the independent operators, that we wouldn’t be able to help them much. Not that there are two levels of people, but I think there are two levels of technology presentation. If you want to bring technology to the operator, you need to be communicating on a level that they feel comfortable with. That’s generally not a whole bunch of equations and fancy models and what have you. That was the philosophy in all of our -- we had oil recovery conference every two years. I think if you look at all of the presentations, there are hardly any of them, that there was an equation of any sort up. It’s all concepts, experience, things that are useful to the operator.

ESDORN:

Thank you. I think my last question just in following up is going to be -- we have more questions, but in just following up what we’ve discussed, obviously you’ve done research that was very Kansas-centric. But you mentioned that in some cases, some of the things that you found out were more applicable in California or in Canada. How has your research and what you have done with TORP, how has that sort of been able to be sort of used in wider industry, not just in Kansas?

WILLHITE:

When we began doing research, our focus was on processes that would be applicable in Kansas. I think the profile modification, the research there can be applied anywhere. Of course it has the same limitations in Kansas as it has elsewhere. I think that one of the things that is just helpful about broader applications is demonstration projects showing you can actually do it. We’re one of the few university-associated groups that actually has managed field demonstration projects. If you look at most of the other universities, you will not find very many of them that have actually been involved in field demonstration projects.

That’s partly because of the way we were set up and having resources to do that as well as our commitment to field application. Now, as far as the impact outside of the State of Kansas, I think we may have had more impact in terms of first showing that we could do things. Another impact is the fact that because I’ve been involved in enhanced oil recovery research and what have you and I also teach, that I had the background to write textbooks. One of the… in the early ‘70s, I think about ‘77, ’78, the SPE put out --. A textbook committee thought that there needed to be a textbook on enhanced oil recovery. In fact, all of us who were teaching in petroleum engineering, I think there were only about two textbooks of any sort available in the ‘70s.

Then there would be a couple of textbooks: Amyx, Bass, and Whiting; and Craft and Hawkins that were reservoir engineering textbooks. There were no other textbooks that I can remember. They generally -- and the textbook committee put out an invitation for people, at least the authors who thought they could write a text on enhanced oil recovery. Don Green and I raised our hand.

We put in an outline and were essentially encouraged by the SPE textbook committee to begin writing. We actually started writing -- I started, and they specifically said we want to make sure there is an extensive section on water flooding. I started out and I wrote this extensive section on water flooding, which by the time we turned the manual in, the first time we turned those chapters in, they said, “Well, this is too large and needs to be a separate book.” I said, “Okay, we’ll get that finished up,” and that was published in ‘86. It took a while. Then we continued to write a textbook on enhanced oil recovery.

Of course, all these -- during this same time we were teaching in those areas. We were teaching, and I had taught courses in water flooding at KU almost from the time that I got there, same with enhanced oil recovery. So we wrote a textbook on enhanced oil recovery. That finally came out in 1998. It just took us a long time to get it out because if you’re doing research and teaching full-time, it’s not like we’re writing books for profit. So those two textbooks… the responses that I have heard from people that have looked at them I think have been generally positive.

If you would say what is our impact outside of the State of Kansas, one impact that I think is reasonable is the fact that with our… the result of our activity, at least being in Kansas, having the capability to do that, has been the SPE textbooks that are available. In fact, Don Green and I are revising the enhance oil recovery textbook now to put in more field case test examples. We were asked by the textbook committee to do that. We hope to have that done within the year. That will be the end of the textbook activity. As far as research, I think we did as much research as was reasonable in permeability modification. I think that area is well understood, and wherever they want to apply it, I don’t think there’s going to be any great new discoveries with existing systems. It’s the new system that I mentioned that was tested in the laboratory that has not been field tested that I think has very good potential.

ESDORN:

That’s great. Do you want to get another sip of water really fast?

WILLHITE:

I can do that.

ESDORN:

Okay, let me just make sure that there’s nothing else that -- you’ve pretty much covered everything that I wanted to talk about. But my last question on this subject is, are there any other contributions that you would like to discuss?

WILLHITE:

One of the thing -- I have been involved in SPE in a variety of ways. I’ve been on the editorial committee for 20 years, chaired a few sessions, and I chaired the SPIOR symposium. But one of the things that I’m really proud that I was involved in that I’d want to claim broad credit. But in 1986, the oil price collapsed. Doom and gloom spread across the petroleum education, across the faculty because we had students who finished their programs and didn’t get jobs. It was more devastating to the small schools because what happened was the companies, whose recruiting targets went down, they cut all the small schools out and they go to UT [University of Texas] and [Texas] A&M and Colorado School of Mines, and they get a few people they wanted, and the rest of our schools were hung out to dry, so to speak. I became department chairman in 1986, also representing the petroleum engineering program at the meeting of the department heads.

At that time, I think there was virtually no communication between department heads, except at the annual meeting, which we talked about accreditation. In 1987, I made a proposal to the department heads that we consider some way of spending some time getting departments together to talk about their academic programs and common issues and what have you. I wrote a letter. I knew Chuck Clark, who worked for Conoco. He was a person that one of our KU grads that I had known for some time, and I wrote a letter to him. I said there’s this forum series that goes on that SPE had.

I think it would be appropriate to have a forum on petroleum engineering education. I asked him what -- here I had a long letter outlining the proposal. I’m not going to go into the details. I also sent a letter -- around the first of the year to--and this was at the end of ’87—first of the year to Dan Adamson, and Dan Adamson sent it on to the forum committee. Eventually we got the word back that no, we don’t think that we should have a forum on petroleum engineering education, but the board -- and this was Arlie Skove actually sent the letter back to the board, said the board really would like to be supportive of education. We will support a colloquium on petroleum engineering education that would be held in one of the slots, a one-week slot, like the forum.

And so, that was the beginning. We actually planned for a colloquium on petroleum engineering education. I was the co-chair of the first one with Doug Van Goten. Of course, Doug was killed about the same week that the colloquium was going to -- that we had in 1991. So we had the first one in 1991, then we had another one in 1993. I also chaired the planning committee. There were a number of people involved in supporting this. Bob Chase. Bob was a good friend.

In fact, there are a number of people… once we got it going, we just had very good support from a lot of people whose names I’m going to not to mention. They were very common in the leadership. Some members, former members of the board that we got there. The colloquium was held almost every other year for several years. I think it might have been delayed one year, but I think we finally crossed a bridge in 19-, in 2013, when I was told that the forum committee asked if the colloquium could be a forum.

And so, the first forum on petroleum engineering education was held in Coeur d’Alene [Idaho], in August of 2013, which -- and I think it has been a very useful thing. There is a board committee that’s headed by Cindy Reece. Cindy Reece and Bob Chase have provided the leadership. There is a series of goals and tasks and what have you. Cindy is really doing a good job of staying on top of that. I decided -- I was on the committee for the third one.

I made a decision that if that thing was going to live, there had to be a lot more people to take leadership other than me. I have not been active other than -- I’ve attended most of them, but I have not provided leadership after we got it off and running. I think the petroleum education forum as of now is -- and that focus by SPE is something that I think I had contributed to, and I feel pretty good about that. It was sort of a, “Gee, is it possible for this to happen or not?”

The society should be interested in education. It just took a long time before we really -- I think the educators felt like we had the support of the SPE board to provide at least a unifying support on petroleum engineering education.

ESDORN:

What were some of the goals of that forum? What were some of the things that you wanted to bring about as a result of the forum?

WILLHITE:

The forum covered a variety of topics. Of course, projected enrollment with curriculum, topics that should be covered, research accreditation. Accreditation has been a big issue. Involvement, cooperation with companies. One of the issues that we talked a lot about that we haven’t pulled off is with internet capabilities as it is now, the sharing of courses. There are online courses.

One of the things that could happen is, to begin with, seminars at one institution could be made accessible to other institutions. That requires some leadership, but Mohan Kelkar has offered to pioneer that one. He said he didn’t do it because nobody responded. But with online access, in principle, it should be possible for some of our graduate students to have access to courses at other institutions. That involves a lot of politics and all that sort of thing if -- we all can’t offer everything. And the petroleum engineering faculties at the various institutions are overwhelmed with students now. The graduate courses that some institutions can offer are not the same as other institutions. Whether eventually this kind of collaboration is possible or not, I think conceptually it is. Right now faculty are trying to figure how they can live with the petroleum enrollments that are just rolling up. Their class sizes are very large. I would in fact… one of the discussions that we had at the forum in Coeur d’Alene was everyone is aware that there’s a big crew change. So the company representatives there say X thousand people are going to retire.

The question is, are the companies prepared to take on new graduates and to replace those that are retiring? When you have people walking out with many, many years of experience, the people coming in don’t have any experience. Companies, one of the presentations by the companies was -- and I can’t remember which company it is. Here is a career path and here’s how long it takes to go from wet behind the ears starting engineer to an engineer who is capable of taking charge of a project of a certain size and so forth. So there’s a maturation process. There’s an internal training process. Of course they would like to speed that up. We may getting out brighter students. I don’t think generally they’re that much brighter. I think they’re much more proficient with their thumbs. They know the internet very well. They can run programs. It also helps to make sure that they know how to think. One of our jobs as university professors is to teach them how to think. I think we’re going to produce well-trained beginning engineers. In order to replace the people that are leaving, there has to be training experiences. What we really don’t know is how many people -- what the future employment prospects are. One issue right now, I believe there are about 10,000 petroleum engineering students in US institutions. That’s a large number. There are going to be 2,500 pouring out every year, on the average. One of the challenges for petroleum engineering education and the petroleum industry in general is how many potential engineers do we need, and those kinds of issues, which I don’t have an answer to.

But clearly those things are in the minds of instructors as well as class size. Class sizes is our… excuse me [coughs]. I’m going to go back and pick up the issue of class size at most of the institutions is very severe. There are not enough faculty. Class sizes are running 100 to 200, and it’s very difficult to see how the quality of the education process can be maintained when there are that large number of students coming through. Of course everyone will claim their students are well-trained. Just looking at the stress on the petroleum engineering faculty, the number of faculty positions open, in order to provide the talent for the industry, we just need to have a lot more petroleum engineering educators. And one of the differences I should point out… I come from an era that doesn’t exist anymore. I was one of the many people, like I mentioned—Gary Pope, Larry Lake, Lyn Orr, Bill Brigham, George Hirasaki—who were chemical engineers; we went to work for production research labs, which largely don’t exist anymore. Then we use that experience and went into academia. The people that are coming out now are coming out of graduate programs; all they’ve done is research. Very, very few -- there would be very few people with industrial experience of any sort joining petroleum faculty. This is also true for chemical engineering. The emphasis on research at universities in some cases is almost unreal because we expect every new faculty member to come in and start a major research program as well as develop into very, very good teachers. I think those programs that have large number of students, those faculty members, young faculty members are going to be overwhelmed.

I think SPE has made a major step in providing some research support for some of the young faculty members. I think that’s to the credit of the organization, so I think there’s some recognition of the difficulty of young faculty in getting started. But it’s a real challenge.

ESDORN:

Yes, I have heard about that. That’s one thing the SPE is actually very -- I hear about it around the office is that that’s one of the areas of concern that they’re really focusing on for the future is professors in academia to teach that sort of thing.

WILLHITE:

That is true. And I’ve been teaching -- this is my 46th year, and I’m teaching because I enjoy what I’m doing and I’m doing some things that I don’t think anybody else is going to do in our department. One of these years I’m basically going to say that I’ve done enough. The same is true. The other folks that I mentioned, many of those are they maybe a few years younger than I am. But if you raise the question, “Well, who’s going to be replacing Gary Pope and Larry Lake and George Hirasaki and other folks?” you need to be concerned because those are folks who have made major contributions in various areas. They are all good friends of mine.

ESDORN:

Absolutely. Okay, we’re going to move on from contributions, and my next question for you is which innovations or milestones in your discipline do you consider to have been or had the biggest impact on the industry? And why?

WILLHITE:

I entered the oil industry in 1962, so my perspective is broader than some of the folks who entered in later years. When I started out, reservoir simulation was something that at Conoco, we had meetings on. It was the folks who are doing reservoir simulation trying to convince management that what they predicted actually could happen. Of course, the reservoir models at that time were very simplistic.

The computers involved were very slow. Just being a reservoir engineer by background, I can say that there had been tremendous advances in reservoir simulation in terms of--aided by of course faster computers, aided by visualization packages that allow you to do things. In the olden days, you used to be able to -- you’d stick in your deck of cards in the afternoon, and maybe you get it back in the morning with reams of output that took you forever to go through.

Of course, the computations that you would do, those that I did back then, could be done on the desktop or laptop now. There had been tremendous advances in visualization. There have also been some advances in reservoir characterization. Part of the advances had been the realization that people don’t know how to describe reservoirs very well.

The numbers they put in the models are just numbers. They’re guided by some of the best geological interpretation. It’s still approximations. Companies still use reservoir simulations in order to predict future performance, which is probably about the only thing that they can do that is reasonable to do. I look at that in that area of the general reservoir modeling both in terms of reservoir simulation, geological modelling. There’s been better integration of engineers and geologists. You can’t live in your separate worlds if you’re going to do an integrated problem.

That is one major area of advancement. I think in terms of enhanced oil recovery, I think the surfactant area has advanced. I think it’s quite different than -- during the first projects in the, say, early ‘70s, when surfactant miscellar flooding was looked at, I think the field tests have yet to come in that area. I think there’s great potential. That’s a little lower priority, I tell you. If I go back and pick up some -- I think the technologies that have had perhaps the most impact, one of them is seismic and seismic visualization. I think seismic technology -- actually, the vibracize was developed at Conoco when I was there -- at least slightly before I was there. I really didn’t understand much about it. I wouldn’t claim that I listened. As I matured in my thinking, I realized that there has been tremendous potential for seismic and the interpretation of data, which has also been advanced by high-speed computers and visualization. Even in some cases, there’s 4D seismic, where geophones have been implanted in fields and they’re able to follow displacement fronts by doing seismic shots. In Kansas, the most successful explorers are ones that go out and they’ll shoot seismic of, say, 10 square mile area and look for seismic highs and do their drilling on seismic highs.

I think seismology is a very important technology that has involved tremendously since the early ‘60s when I first heard of that not, that I -- I didn’t understand it then. The other technology which is so prominent now is the ability to drill horizontal wells. It seems really fantastic to me to think that you can drill a horizontal well. You can drill it down and then you can drill it out.

I think the longest one is something in the vicinity of seven miles out or more. I think that is just a revolutionary technology. It really is a game-changing technology. A few years ago, I would not have imagined the effect of horizontal wells combined with fracking, the nasty word, “fracking.” And of course, fracking was first tested in Kansas in the ‘40s, if I remember right. I think the development of horizontal wells and the fracking technology is just truly revolutionary. I had nothing to do with that. I can look off to the side and say that’s really remarkable. It has enabled the oil decline curve to be reversed; oil imports to be backed off; had tremendous economic impact on the country. You can see here is one area of technology that’s probably done more to affect the balance of payments and the general economy of the United States than anything else in the last five years, politics included. And so, just sort of stand back and say I think that’s just an amazing technology.

Every time I talk to these guys and ask them how do you do it and what are you able to do, I’m just amazed at -- and it’s too late in my career to get into that area. I have worked at enough areas now that I’ve just got to leave the unconventional resources to the young ones. I’ve got a colleague, Reza Barati, who has joined the faculty, and he is working on unconventionals and so forth. I think that’s a young faculty member’s game. But of course most of the companies are into that area. They’re hiring -- when I talk to recruiters, they’re hiring new engineers that are going to be going in that area. Our former grads are working in various places in horizontal wells in the Bakken or Eagle Ford or Marcellus. It’s just all over.

I think those are the areas -- if I had to nail it down, it would be reservoir simulation, seismic and horizontal wells. I think of course the other one that would come in is we can explore anywhere. Offshore operations have had tremendous impact. A lot of that is conventional, although most offshore wells are extended reach wells. The technology of being able to drill extended wells has been there, although I don’t think the extended wells were as long as the horizontal wells that have been drilled recently. All of that, being able to develop major oil field 100 miles of New Orleans has got to be pretty phenomenal. Of course, it’s major discovery off of Brazil, major discoveries off of Africa. I wouldn’t want to bypass the offshore activities. I’m not sure what else.

ESDORN:

That’s great. No, no, those were all wonderful, wonderful examples, so thank you. We were just talking about the past. Now shifting focus and thinking about the future, what do you consider to be some of the biggest challenges facing the industry going forward?

WILLHITE:

I mentioned the things that have happened in the past. The future challenges of course are sustaining production. There’s more attention to environmental impact. Some of that is self-inflicted pain. I think that the industry is driven by profit. It’s also there’s a political -- the real issues of global warming and the impact of carbon consumption on the environment, I think that’s a political issue.

I think the industry just has to survive in the political issue. There’s more concern about the location, where and what’s drilled, more emphasis on safety. I think reservoirs are reservoirs. They’re going to be deeper. They’re more complex, more expensive to develop. That’s a little hard to project. If I went to say four years ago, nobody predicted the impact of horizontal wells. Whether there will be something like that in the future, it’s a little hard to say, but my guess is there won’t be.

ESDORN:

Looking forward into the future, you are -- you have in the recent past conducted some research on, for instance, the carbon dioxide initiative, which you spoke about, permeability modification. You kind of already discussed that. If you were planning research for the future, what sort of technical aspects of the industry do you think are challenges that we need to tackle in the future in that way?

WILLHITE:

The development of technology for the future is very difficult to project. I think if you look at what people are trying to do now, one of the things that is underway is the question of whether carbon dioxide can be stored in subsurface formations in order to reduce the potential for global warming.

There are several projects that -- carbon capture and storage is the acronym. Those are projects that are possibly related to earthquakes, because another topic that is a matter of public interest is whether injection of fluids into disposal wells, which had been done for years, is triggering earthquakes because there’s some indication of increased earthquake activity in Oklahoma. As far as carbon -- production of oil and gas involves consumption of carbon, so there’d be carbon added to the atmosphere.

Thermodynamically, I don’t think there’s any real way to get around that. Of course, the thrust of EU and -- at least the United States administration has reduced the amount of carbon increase renewables. That undoubtedly will happen probably supported by political considerations. Whether the technology can be developed, if it’s competitive with fossil fuels, I don’t know. There has been discussed the possibility of a carbon tax. That’s certainly a politically charged issue. I think all of the technologies that are currently worked on are going to be pursued. I think eventually there’ll be some major surfactant chemical floods. The big question for all existing reservoirs is when do you shut them in? There’s a substantial resource there. At some point, whoever has control of the reservoirs has basically say there’s nothing more we can do economically. At that point, I imagine the wells will be abandoned. Once they’re abandoned, it’s unlikely that they’ll go back into the field again. There are lots of reservoirs around the world that if you look at the future, that decision is still sitting there. That impacts the oil industry. It’s very difficult to say how much more oil has yet to be found, oil and gas. There have been many people who have said the oil era is over. My view of that is not the oil or the era is over. It’s just the era of cheap oil and gas is over. The industry has a remarkable record of continuing to find oil and gas resources that can be produced.

There are things that people are still -- and DOE, for example, is looking at production of hydrates from the deep sea. It’s known that gas hydrates are found in the bottom of the ocean. Samples have been pulled up, so you can pull them up. There is a resource there. Whether it can be produced economically or how you produce it has not really been developed. Looking at the future, I think there will developments in that area.

ESDORN:

That’s great. Thank you.

WILLHITE:

I think I’m out of ideas.

ESDORN:

Yeah? [Laughs]

WILLHITE:

I don’t know. Yeah.

ESDORN:

We’re almost done. I just have a couple or three more questions for you. The first one is what has made working in the petroleum engineering industry meaningful to you.

WILLHITE:

Let me see. What has made my feeling of satisfaction about being in the petroleum industry is that I’ve been able to work on a number of projects and have developed a sense of accomplishment. I’ve worked on some field projects that actually came through as expected or nearly as expected. I have been able to teach a lot of students, a lot of petroleum engineering graduates. I have written a couple of textbooks and published a lot of papers that I think have been contributions to the industry. I enjoy what I’m doing. I wouldn’t say that I would pay to do it, but I have not regretted the experiences that I have had.

ESDORN:

When you get up in the morning, what makes you get up and kind of get ready and makes you excited about working in the industry? What is sort of been the thing that’s overall kind of made you like working in the industry?

WILLHITE:

The perspectives of working in the industry are different if you are a faculty member. If you are a faculty member and you get up in the morning, the first thing that comes to your attention is, “Am I teaching today? How many student I am going to work with? Do I have papers to review?” If you didn’t enjoy doing that, I don’t think you’d do it. Particularly, I have been in the industry long enough. The reason I’m still teaching now is I’m still enjoying the things that I’m doing. I’m enjoying helping students learn and contribute to some research projects here and there and still writing what I can. And I have handled some review papers. But it’s just a general feeling that -- I think if you hated your job, it’s time to quit. I enjoy what I’m doing. It’s not the only thing I could do.

ESDORN:

What are some of your favorite memories about working in the industry?

WILLHITE:

When I worked in the industry, I had a certain amount of satisfaction in basically learning how to function in an area that I knew nothing about. I felt good that I had a good introduction to petroleum engineering, reservoir engineering when I worked at Conoco, and good exposure to field.

My exposure to field things was probably more valuable than I have would know at the time, but that’s one thing that most faculty members don’t have much experience too. Other things that just a sense of satisfaction when -- eventually, when I got to -- I enjoy teaching, and I enjoy writing. Otherwise, I wouldn’t write textbooks. I began to get feedback on the both my water flood text and the enhanced oil recovery text.

You can’t -- generally, at least the people that have something have said kind things. There have been a few thousand copies sold. I think there’s a sense of satisfaction. Then, co-founding the Tertiary Oil Recovery Project, it would not have happened if Don Green and I had not an idea set at -- and as I said, it’s sort of a serendipitous set of circumstances that led us to develop it. Then I think I have… the petroleum engineering education community is thriving, although stressed. I feel good about being part a part of that community. I think we have issues to work on, and to the extent that I can contribute, I’m certainly willing to put in time at the usual wages of zero per hour.

ESDORN:

All right. This is our last question. You have made it through. Congratulations.

WILLHITE:

Oh, no [laughter]. You’ll let me get some water.

ESDORN:

Yeah, please do.

WILLHITE:

Let’s see if I still -- I still have my voice.

ESDORN:

My last question for you is how has being an SPE affected your career?

WILLHITE:

The Society of Petroleum Engineers is a very interesting organization. I’m also a member of American Institute of Chemical Engineers and American Society of Engineering Education. But the SPE has been a more dynamic organization from my view, in terms of the technical papers. The technical papers at the conferences are generally high quality. They have a long-standing policy of no paper, no presentation. You can depend on learning quite a bit from both going to the meetings as well as reading the papers.

Then there’s also the fact that there is a well-established publication system. I’ve written a lot of SPE papers. I think it’s important the papers are getting reviewed. If you have survived the peer review process, that there are at least three people plus the editors that think that you wrote a good paper. I think that part of the process is important. I am also an associate editor for SPE journals. I’ve done that for about 20 years.

I just think it’s an organization that you have to contribute to in order to continue the quality of information that’s there. I’ve had numerous opportunities. I’ve received some awards and recognition that I didn’t -- I would never have guessed when I started out as a young engineer at Conoco that I would receive as many awards as I have. Some of them have been a complete surprise. Again, I’m not going to trot out a list of awards, but I feel fortunate to have had the recognition, both in terms of SPE and elsewhere, for things that I have done and contributed to. Just a fine organization. Going to an SPE meeting is always enjoyable. I learn something every time.

ESDORN:

If you are going to be talking to young student todays, which you do, what would you say -- what were some of the reasons that it would be important for them to join SPE?

WILLHITE:

If you look at it -- of course I’m looking at a perspective of someone that’s been a member for 50 -- let me think. How many years? Fifty-two years. I think the Society of Petroleum Engineers is probably -- it is the best organization for a young petroleum engineer to join. It’s become more so recently because there’s more career guidance information than when I first started. Rarely was there anything for young engineers. In fact the society didn’t even allow recruiting to go on except on the hallways. And so, the overall tenor of the society has changed.

There all kinds of information for and career guidance for young members. You don’t get that anywhere else. I shouldn’t say that. Some companies have good mentors that provide that information. The society has a lot of resources that young members can get a hold of. They’ve got a focus trying to develop the student chapters. So there’s very, very good student activities that draw students in. We’ve got a team that’s competing in the Petro Bowl. I don’t know if they’re still competing now. They were supposed to have been there this morning I believe.

I think the society has incentives to help young petroleum engineers develop their careers. Not the only way because companies have to do that too. And there are opportunities to write papers if they have something. There’re opportunities to serve on committees. You just have to let people know that you would be interested in doing it, usually. And sometimes you’ll get a call. I don’t think it’s an exclusive organization. I think it tends to be inclusive. It takes some individual initiative also in order to take advantage of the resources in SPE.

ESDORN:

Thank you very much. I really appreciate it. It was such a wonderful opportunity to meet you and to talk about your career. Thank you.

WILLHITE:

Okay. I hope that comes across well.

ESDORN:

You did a great job. Thank you so much. It was really very, very interesting.