Oral-History:Don Hannegan


About the Interviewee

Don Hannegan

Don is Managed Pressure Drilling (MPD) Strategic Technology Development Manager for Weatherford, Registered Professional Engineer, recipient of The World Oil 2004 Innovative Thinker Award for his role in developing MPD tools & techniques, SPE 2006-2007 Distinguished Lecturer (Offshore Applications of MPD), IADC Exemplary Service Award recipient and member of Pi Epsilon Tau Petroleum Engineering Honor Society.

Don authored the MPD Chapter in SPE’s new textbook Advanced Drilling & Well Construction and is lead author of a book to be published under the auspices of the IADC Technical Publications Committee entitled Drilling Optimization Tools & Technology, lead author of the Pressure Management chapter in the current edition of the IADC Drilling Manual and author of the MPD Option chapter in the 2015 edition of IADC’s Deepwater Well Control Guidelines.

He is presently serving on the SPE Distinguished Lecturer Committee and co-chair of the Pressure Management & Well Control session at the SPE 2014 & 2015 Annual Technical Conference, and has been invited to serve chair-elect of the 2016 Drilling Sessions and chair of the 2017 Drilling Sessions.

Don has 21 issued and 31 published patent applications consigned to Weatherford, most of which speak to various drilling methods and pressure control equipment designs.

Further Reading

Access additional oral histories from members and award recipients of the AIME Member Societies here: AIME Oral Histories

About the Interview

Don Hannegan: An interview conducted by Amy Esdorn for the Society of Petroleum Engineers, September 29, 2015.

Interview SPEOH000128 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].

Audio Interview

Audio File
MP3 Audio


DATE: September 29, 2015
PLACE: Houston, Texas


My name is Amy Esdorn and I’m here at The Society of Petroleum Engineers Annual Technical Conference and Exhibition at the George R. Brown Convention Center in Houston, Texas. Today is September 29th, 2015 and I’m speaking with Don Hannegan. Don, thank you for participating in this interview.


Thank you very much for inviting me.


Let’s begin. My first question for you is – you’ve sort of –you’re considered the father of managed pressure drilling technology and I was just wondering, that’s probably – what you’ve been working on technologically, but can you discuss more in detail what you’ve been working on in your career, what technical innovations you’ve worked on?


I grew up in South Arkansas and I had an opportunity, walking down the gravel roads, to come upon a drilling rig. It was one of Mr. Charlie Murphy’s drilling operations. The rig was drilling to this Smackover formation and Murphy Oil Company remains today, their corporate headquarters is in El Dorado, Arkansas. Just a kid, probably seven or eight years old, I sort of hid in the pine trees for a while. Someone on the crew saw me. They kind of waved me in and made me feel like part of the crew. I thought I was helping. They sent me to go find a board stretcher or another case, a skyhook and I’d make the rounds. I’m sure they were just toying with me, of course. [00:02:00] About the time I needed to leave, one or the other of them would give me a buffalo nickel.

I walked back home that day thinking, “I like this oil patch. I like these people and it pays good.” Years later, I graduated from Lamar University in Beaumont, Texas, and just across the campus was Spindletop Field. My class ring I’m wearing now has an image of those rigs. At the beginning of the Spindletop gushers, there was a time of celebration, but after some fires, loss of life, lots of lawsuits, a driller was asked to figure how he can drill into that formation without a gusher. Today, we call that a blowout.

He hired a rancher to pen up a herd of cattle in the pond overnight. He sent his crew out the next morning, scraped up the mud, and he was able to drill with a heavier fluid than water and drill into the reservoir without the well flowing. That is still conventional drilling today. Drill with a weighted fluid with an open to the atmosphere mud return system once the mud and cuttings get back to the rig.

I began to think a lot about the oil patch, but when I graduated in 1964 from Lamar University, I couldn’t find a job in the oil patch so I went to work for Dow Chemical Company. [00:04:00] I worked for Dow Chemical for 22 years, managing plants in Texas, Arkansas, Michigan, and finished my career with Dow as director of purchasing and acquisition for Dow Chemical Company. During that period of time, at that time I was 45, I thought if I was going to get in the oil patch, I better start making the move.

The key innovation, when I was with Dow Chemical, was developing a sacrificial electrolytic anode that is used in chlorine cells to produce chlorine as opposed to using graphite. Graphite is a sacrificial anode. We wanted one that would last for an extended period of time and produce a pure chlorine for chlorinating water systems except all the other things that chlorine is used for. That was probably my key innovation, if you will, in the chemical industry. But in the chemical industry, I learned that you should bottle everything up, leave little open to the atmosphere, and use process logic controller, PLC computers to very precisely manage the critical parameters of which you had contained in this closed system.

After Dow, I worked for five years for Dover Resources as vice president of Total Quality Management. I felt capable of doing that because I understudied some of the TQM gurus when I was director of purchasing for Dow. [00:06:00] Dr. W. Edwards Deming, considered the father of quality, statistical quality control; Tom Peters, who wrote the book In Search of Excellence. As VP of Dover Resources, I worked to get the manufacturing plants up to the point where they were capable of supplying the components to the Japanese automobile industry, the oil field, etcetera, etcetera.

Then I had an opportunity to go to work for Williams Tool Company, a manufacturer of rotating control devices in Fort Smith, Arkansas. By 1999, Weatherford had acquired Williams Tool Company and I became a Weatherford employee. At that time, rotating control devices were used for air, gas, mist, and foam drilling and underbalanced drilling. In 2003, I began to look at how a closed loop system might benefit offshore drilling. Now, you can’t drill with air offshore. Underbalanced drilling, not an option for three reasons. Underbalanced drilling, you’re inviting the well to flow as you continue to drill. Three reasons. The underbalanced drilling kit required to invite the well to flow is too large to fit on offshore rigs. Another reason is, what are you going to do with the produced hydrocarbons? They oil and the gas on an offshore rig. Number three, drilling ahead while the well is flowing is against the code of federal regulations in the United States. It’s against the law.

[00:08:00] I began to look at how a closed loop system could be applied. Same equipment, rotating control device to close the annulus returns under the rig floor that would positively direct the mud and cuttings over to a choke manifold. You would put drill string non-return valves or floats on the drill string so that when you close the choke, you had the wellbore bottled up, a closed system.

In 2003, in Amsterdam, at SPE/IADC Drilling Conference, I introduced and coined the term managed pressure drilling. Here, you’re using essentially the same technology, the same hydraulic flow modeling, and the same equipment but you are not inviting the well to flow. You’re using the closed loop system to more precisely manage the wellbore pressure profile. You can speed up the rig’s mud pumps and increase the equivalent mud weight or the bottom hole pressure. You can slow the rigs might pumps down. You can decrease the bottom load pressure almost by the speed of sound. On the backside, on the annulus return side, you have the choke. You could close the choke, keep the mud pumps running consistent, but close the choke. You can instantly change the bottom hole pressure. Choke manipulation and circulation rate. Now, you have two wonderful tools that you can quickly adjust the bottom hole pressure. Very critical when you’re drilling in narrow margins between the formation pressure and the formation’s fracture pressure. [00:10:00] That’s called the safe drilling margin.

If you don’t have a bottom hole pressure greater than the formation pressure, you’re going to have a kick, an influx. If you exceed the fracture gradient, the ability of the open hole uncased, the uncased hole, you exceed the ability of the rock’s capability. Now you’re going to experience losses. Losses are a problem because your fluid column, the annulus fluid column, is your primary well control barrier. You don’t want to lose that primary well control barrier. I identified that technique as the constant bottom hole pressure variation of managed pressure drilling, because whether the rig’s mud pumps are on or off, you keep a constant equivalent mud weight that allows you to stay within the margin. Without this technology, conventionally, when you turn the rig’s mud pumps off, you lose bottom hole pressure because you’ve lost the circulating annulus friction pressure, and when you turn the rig’s mud pumps on, you have the hydrostatic mud weight plus the circulating annulus friction pressure. With a constant bottom hole pressure variation of MPD, you keep a constant bottom hole pressure.

Then I decided another variation of MPD would be pressurized mud cap drilling. Here’s where you have a closed system but you’re drilling and you encounter total losses. You drill into a cavernous void, an underground cave, if you will. [00:12:00] Now, your primary fluid column in the annulus goes into this loss zone and the pipe gets differentially stuck. You consume many thousands of barrels, in some cases, of drilling fluid trying to keep the hole full. But with the pressurized mud cap drilling, when you drill into one of these severe loss zones, you switch over and drill the seawater and let your mud and the cuttings go into the cavern that would otherwise cause severe low circulation.

It’s called pressurized mud cap drilling because while you’re drilling the sacrificial fluid, the seawater, there’s a risk of gas migration up the annulus. You pump the heavy viscous mud into the annulus at the surface and you keep kind of topping it off, topping it off, topping it off as you continue drilling with seawater until you get through the loss circulation zone--pressurized mud cap drilling. The mud cap is that annulus of heavy viscous mud that you spot to prevent gas migration to the surface.

The third variation is dual gradient. Here’s where you have, by several means, two pressured versus depth gradients in the annulus returns path. Dual gradient allows you to change the bottom hole pressure by either injecting inert gas down a parasite string at some point into the annulus. You have one depth versus pressure gradient above. It’s lighter, if you will, than the one below. You can adjust that by the amount of inert gas that you’re injecting.

[00:14:00] Another technique is using subsea pumps. That is the technique that Chevron is using today with Chevron’s deepwater dual gradient drilling project where they would use pumps on the seafloor to return the mud and cuttings as opposed to having a marine riser filled with heavy mud and cuttings that would overbalance the formation. They can adjust the speed of the subsea pumps and change equivalent mud weight.

The fourth variation is really kind of a safety first spin on MPD. Here’s where you’re drilling with a conventional wisdom fluids program, unlike constant bottom hole pressure variation where you may be drilling with a hydrostatically underbalanced mud in the hole all the time, unlike pressurized mud cap where you’re drilling with a sacrificial fluid, unlike dual gradient, the returns flow control variation of MPD is the one that focuses on safety when you’re drilling with the otherwise, conventional drilling program. You can close it up as opposed to it being open to the atmosphere and to the rig fluid. You have the RCD. You have the PLC automatic choke manifold system and you’re more precisely managing the wellbore pressure profile. You are able to quickly detect kicks and losses because we have a Coriolis meter so we know the density and the flow rate coming out. We know the density and the flow rate coming in down the standpipe and down the drill string. [00:16:00] We can recognize immediately with time and temperature corrected logarithms in the software if we have an influx of reservoir fluids, a kick, or we have a loss. We can respond with choke operations or circulating rate quickly.

Another advantage of the returns flow control variation of MPD for HSE reasons is to quantify ballooning. Now, ballooning is the – when you’re drilling ahead, the pressure induces small cracks into the rock, almost as if the rock were elastic. When you turn the rig’s mud pumps off – and that’s called ballooning, by the way – when you turn the rig’s mud pumps off, the pressure decreases and the well bore breathes back. This is important to distinguish, this breathing phenomenon, from the beginning of a kick when you’re making a joint and pipe connection. When you start making the joint and pipe connection, the pumps are off, the well shouldn’t be flowing, but it’s still flowing.

This technology, the PLC automated choke system with its software, enables you to recognize a ballooning signature. You recognized it from the last two or three stands of pipe that you drilled in. You can get the signature of the ballooning and then when you turn the mud pumps off, you can recognize the signature of the breathing back. Now, you’ve got a new jointed pipe connection and if it’s not matching that signature, then you need to do a flow check which means wait and see. [00:18:00] If you have exhausted the signature period and the well is still flowing, you’re 99.9 percent sure the well is flowing.

Today, hundreds of offshore wells – that paper was introduced in 2003. In 2004, by the way, I was named World Oil Innovative Thinker of the Year for some of these concepts. Today, we’ve done hundreds of offshore managed pressure drilling projects from all types of rigs, from barge-mounted rigs with surface BOP stacks to jackup rigs with surface BOP stacks to production platforms with the surface BOP stacks, Nordson submersibles in deep water and dynamically positioned drill ships in deeper water.

It is just amazing to me how these seemingly very illogical concepts have been embraced by the industry given the industry is usually pretty slow in the uptake. Now, one of the reasons MPD has blossomed, if you will, caused many people to think that is the way most wells will have to be drilled in the future because they already drilled most of the easy prospects – is, when does an operator try something revolutionarily new, when nothing else works? An operator has a prospect that he either knows from past failed attempts to get in to the reservoir or from they’re preplanning [00:20:00] they conclude that there’s a high probability this well is not drillable conventionally for safety, economic, or technical reasons. MPD has an opportunity.


You came in to the industry specifically into the petroleum engineering industry in 1999, is that right? At that time?


Actually, 1995. Yeah, when I joined Williams Tool Company.


1995, okay.


However, started on it with Dover Resources. Dover Resources have a number of oil field related goods and services.


Certainly. When you first, maybe not first because there’s that gap of almost 10 years there, before you sort of innovated with the managed pressure drilling, what was that process like for you to encounter this issue and then sort of solve it, solve this challenge or this puzzle – what is your process like to do that? And what was the process specifically for the managed pressure drilling?


You’re going to get me to reveal something here. I used the Gillette Marketing Theory. The inventor of the disposable razor blade would walk down the street and see someone who maybe not necessarily needed a shave but might appreciate a shave. He would give then the razor and sell them the blades. [00:22:00] Remember, I was primarily focusing on rotating control devices and we rent them. Teaching the technology- give them the razor- created a demand for rotating control devices and then, of course, for choke manifolds of various designs.


When you were solving the problem with your team, who did you work with and how did that come about? Just really focusing on that issue. Did you have an aha moment or was it just “This will work, let’s test it,” and very logically step by step testing what was going on or did you – was it an epiphany? What was that like?


In 2003, it really wasn’t a team. I was thinking about de-accelerating, if you will, and working half-time. My wife’s mom was critically ill in Michigan. I’m spending a lot of time up there. I have a little old cabin down the hillside where I live in Fort Smith, Arkansas. That was a good opportunity for me to spend some time down there. That free time gave me an opportunity to really think through the root concepts of managed pressure drilling. [00:24:00] After the first paper was presented in Amsterdam, when I got to the point of describing pressurized mud cap drilling variation, some people from Sarawak Shell were in the audience. They had been experiencing severe losses. About one out of five, about 20 percent of the wells they would drill, they would drill into one of these cavernous voids. When I mentioned pressurized mud cap drilling, switch over and drill with seawater, etcetera, etcetera, I had an immediate audience. Within months, the Weatherford team in the Asia Pacific area, they already had the enabling tools, the RCD, the choke, but they hadn’t used it for pressurized mud cap drilling. It was Sarawak Shell who contacted the Weatherford Group. They want to practice pressurized mud cap drilling. Now, my email floods, “Tell us what this is.”

Basically, it was an external pull on our service company for the technology. SPE conferences has been a wonderful way of spreading that word and it’s true technology transfer. In those cases, there was not a field trial per se, it was just introducing the concept, putting the equipment together and practicing a very simple process. Most of the MPD in the Asia Pacific area since 2004 has been pressurized mud cap drilling, just for that reason.


[00:26:00] And so it was just logically applying the tools and the things that were already existent to solve this problem.


That’s right.


Well, you just mentioned SPE and that’s my last question for you. How has being an SPE member affected your career?


Well, for one thing, I’ve taken a great delight and actually honor, in sharing this technology with the industry. Yesterday, for example, I co-chaired the managed pressure drilling and well control technical session at this ATCE, co-chaired with Deepak Gala of Shell. The beat goes on relative to SPE conferences being a wonderful venue to take some of the fuzzy idea concepts that I had in 2003. Now, case study after case study after case study after case study, the SPE papers have continued to flow. Relative to MPD, global acceptance. I think me being an SPE distinguished lecturer in 2006 and 2007, my topic was, surprisingly, offshore applications of managed pressure drilling tools and technology. [00:28:00] That helped the technology along its path towards broad acceptance because I was teaching the root concepts of MPD under the auspices of SPE as a distinguished lecturer and the implied credibility. People would listen. If there was something that they didn’t quite understand or they had some doubts about it, time and time again, I saw them looking at it as a glass half full as opposed to the glass - benefit of the doubt, if you will. That is an important mental barrier that you’ve got to break through when you’re introducing a revolutionary new way of looking at things because you have to keep in mind, Spindletop was in 1901, that we learned how to drill with a heavy fluid to prevent the well from flowing. That remains conventional wisdom today. MPD challenges – what petroleum engineers have been taught forever. Well over a century. It takes a little but when they think about it, if you could get the listener just to think about it a moment, it makes sense. In fact, one of the interesting things when I gave the Amsterdam paper in 2003, someone came up and said, this makes uniquely good sense. There must be something wrong with the logic. Surely, somebody has thought of this before or they tried it before, and it didn’t work. People are – they have trouble – [00:30:00] the status quo is difficult to shake, but MPD had the benefit of being able to drill undrillable prospects, drill wells that would otherwise be wells from hell and drill them safely and efficiently.


Well, thank you so much for speaking with me today. It was a pleasure speaking with you.


Thank you.