Martian Stories

Have you worked on Mars, Ursa, or Olympus, or other projects/platforms in the deepwater Gulf of Mexico? Please share your story to help us continue to compile and narrate the history of this important industry. Click on the blue button above and then submit your information. This page will be updated periodically to include new submissions.


Submissions, Communications, and Oral History Excerpts (Updated 6/1/19)


I named it Mars. I named it that because the lead was near the Exxon/Getty Venus well (MC 852 #1). . . . Someone high in Shell got wind of the good reservoir in the Venus well – maybe over drinks at a bar in Houston (that was the rumor). The good stuff in Venus turns out to be Pliocene, and at the time, no one was sure there could be good reservoir that far off the shelf in Mississippi Canyon. On the basis of the “Venus” name I proposed we use astronomical bodies as our theme for naming prospects in Sale 98. We had some industry seismic in Mississippi Canyon and over the Venus well vicinity, so for more data, I laid out a proprietary regional grid for Shell to shoot. Of course we looked close to Venus at first, and the seismic revealed a very deep basin surrounded by salt and with reflection events indicating the probability of a salt flank prospect. I named the prospect Mars in honor of being the next planet (besides Venus) closest to Earth – it was the very first named prospect for Shell in Sale 98.

– Dan Newman (former Delta Province Leader and Staff Geologist, Shell) email communication to Mike Forrest and Tyler Priest, October 29, 2014


In January of 1985, as a 24-year-old Exploration Geophysicist, I was the only Geophysicist of color working for Shell Offshore Inc. based in New Orleans. I had a burning desire to prove my worth and learn my trade as quickly as possible in a new, challenging environment. At a time when layoffs were not prevalent, managers were forced to make big business decisions that led to career-changing outcomes for young professionals such as myself. However, the threat of layoffs did not deter staff from working towards our ultimate goal: to have a bid placed on your work and acquire the rights to drill for hydrocarbons.
 
At the time, I did not realize that the odds of getting your work through the entire lengthy process to ultimately earn a bid – and win it, was not the norm, but the exception. Henry [Pettingill] and I presented Prospect Mars through ALL of the series of review levels held leading up to and concluding with Lease Sale 98. The final presentation was unforgettable, as it was up for debate on whether I should present my work or have a higher-level manager replace me, based on my inexperience with interacting with the decision makers of the company. Ultimately, I was given the go ahead and presented my work successfully, telling our story, and selling the promise of a potential discovery. Little did we know, that our find would be one of Shell’s most profitable to date.
 
I was released from Shell Offshore, Inc. in September of 1986, due to a layoff. Years later I heard that Prospect Mars, my first offshore lease sale, was drilled and massive amounts of hydrocarbons were found. To my dismay, many people have been associated and given credit for their Geophysical work, with no mention of Patrick J. Franklin. I would like to thank you for reaching out to me, almost 30 years later, with the opportunity to share my story, give my perspective, and the possibility of linking me to the history of my first project – Prospect Mars.

– Patrick J. Franklin (former Shell Staff Exploration Geophysicist Offshore) email communication to Tyler Priest, November 20, 2014


The largest field in deep water is called Mars, about seven hundred million to a billion barrels. I was exploration general manager at the time Shell leased Mars acreage.  This is how it happened.  We were finalizing our bids.  I believe we had already been to senior management.  We just showed them the top ten prospects. Several co-workers have told me most of this.  I can’t remember all the details. We had the final technical meeting and I said, “Guys, is that all the prospects?”  And Roger Baker said, “I’ve got one more.”  He showed us the data.  It was Mars.  I vaguely remember this.  I said, “It looks just as good as some of the other prospects we are bidding on.  Bid it.”  And so, we bid Mars, $200,000 a block for two blocks.
 
This was a so-called spec bid. Shell drilled Mars in 1988, after I left. And they brought in BP as a partner.  It was still considered to be a very high risk, called a 10% chance of success.  With amplitude anomalies, bright spot prospects, 10% is high risk. The prospect was on the flank of a shallow salt dome, but way down flank, almost a stratigraphic trap.  And Shell brought in BP as a 30% partner because they thought it was too high risk, and in 1988, the budget was very tight. I was told this story, after several wells were drilled and Shell realized Mars was a 700,000,000 barrel field, management from Royal Dutch asked “Why did you bring in BP?” 

– Mike Forrest (General Manager for Shell Offshore, 1984-1987) interview by Tyler Priest, June 29, 1999, Houston, TX


As an old seis-strat [seismic stratigraphy] guy (i.e. opinion now, not fact), I am humbled to admit that it was really Shell’s keen ability in Bright Spots . . . that made the day, and more so, a company culture in Offshore that demanded that Geologists/Stratigraphers understand the seismic signals, be it fluids, lithology, or whatever (i.e. it was not just left up to the Geophysicists to be accountable for that).  Thirty years later in Deepwater,  I’m not sure other orgs even to this day demand this seismic understanding from their Geologists, nor such rock properties thinking from Geophysicists and Petrophysicists, and I wonder if that was the true differentiator.   From where I was in the trenches, Bright Spots led the way, whereas the integration of Seismic Strat played a key role in giving us the confidence that there was an internally-consistent story that explained not only why there could not only hydrocarbons, but also sand presence to host those fluids — so critical because . . . the prevailing thinking was skeptical about sand in DW [Deepwater}.  Many of us were stuck in turbidite O&G [Oil and gas} paradigms that came from the odd DSDP [Deep Sea Drilling Project] well, plus other types of basins (North Sea, California), but we overcame it by this integration of disciplines, which in turn led to the “breakthroughs” in successful discovery and appraisal of Powell, Mars, and Auger.

– Henry Pettingill (former Shell Staff Geologist) email communication to Mike Forrest and Tyler Priest, October 3, 2014


Dave Montague: So the question at Mars was, is the reservoir in fact out into the basin where it’s nearly flat?  Mars had a pretty low prospectivity, which was why we brought BP into it, plus the oil price was very low and we didn’t have many dollars to spend on exploration drilling, so the only way we could see going forward and keep the rigs running was by bringing in BP.  Keeping the rigs running was a never-ending struggle, Mark, as I remember it.
 
Mark Shannon: During the lean times, that’s true.

– Dave Montague and Mark Shannon (co-leaders of Shell Turbidite Task Force, 1988-1991) interview by Tyler Priest and Jason Theriot, August 25, 2009, Houston, TX


When we drilled Mars, we were very concerned that we would have enough pay to make the field economic.  It was not a lead-pipe cinch. We felt quite confident that there was some hydrocarbon down there and we were drilling after one particular zone that we felt good about.  And, of course, we found more than half a dozen zones at depth, and, again, real confirmation of the play concept that the hydrocarbons are not all nestled high on the structure.  It is well off the structural crest, the sand section bloomed as you would expect a turbidite to expand, and the hydrocarbons had a strong stratigraphic trapping component to them, too.  So, that gave us the indication that the tool would be working.  It doesn’t take a mental giant to go from that point to thinking through several spots in the world where other situations ought to be there.

– Bill Broman (former Shell General Manager for Exploration Offshore) interview by Tyler Priest, January 15, 1999, The Woodlands, TX


When I finished Bullwinkle, I actually reported to Carl (Wickizer).  He had moved over and taken over the project group over there . . . So they had done all this work on floating systems and they had looked at tension-leg platforms, and somewhere along there, Exxon had built the first compliant tower. The Lena guide tower it was called then.  It never was considered for Bullwinkle, but after Bullwinkle, we were going out deeper and deeper, 2,000 feet and so on.  Peter Marshall did a big study on how we could build compliant towers.  So when we got to the Mars, Ram-Powell, Ursa, we looked very hard at a compliant tower for 3,000 feet of water and the tension-leg platform. I don’t think it was ever seriously considered for Auger, but I know it was for Mars. So we did this evaluation for Mars, and sometimes you ask, what is the water depth limit?  Physically and technically, you could build fixed platforms a few hundred feet deeper than Bullwinkle, but financially and economically, it doesn’t make sense.  . . .


Auger was being built and then we came back and said, “Well, okay.”  It was going along reasonably well.  But here’s this other option.  What’s the right answer?  Ultimately, we ended up, as you know, with the tension-leg platform.  But we actually looked at three major options.  One was a compliant tower, the other one was the tension-leg platform, and a third one was an entire subsea development 70 miles back to shore.  Nothing, no surface equipment out there, all the development subsea, brought back into the Louisiana coast. . . .


So what drives the decision then?  The cost is a significant part if there had been big differences, but there weren’t big differences.  So the real reason for going with a tension-leg platform was that we did believe that the range of costs were narrower than for the other two options, so cost did play.  And the other one was simply that since we’d done one, we know what we’re doing.  These others were starting brand-new again, and then finally we have a lot of people or will have a lot of people who will be trained to operate on this type of facility.  So that’s why we went with the tension-leg platform.

– Gordon Sterling (former Shell Deepwater Engineering Manager) interview by Tyler Priest and Jason Theriot, June 8, 2009, The Woodlands, TX


An interesting story at “Mars”.  When we looked at the development at “Mars”, we basically . . . the final choices were a TLP or a floating production system with subsea wells.  Those were the two choices we had.  If you looked at the cost of them, the costs were very similar.  The overall economics didn’t look that different.  And when we finally went through with the recommendation, I made the recommendation up the line that we wanted to go with the TLP, and the reason being is, of all else is the same, and I can have the trees at the surface, versus in the ocean floor, I am going to go with the trees at the surface.  And that is why “Mars” has got a TLP with trees versus the subsea, because we could have gone either way.  Economics and everything, either way would have been OK. 

– Richard Pattarozzi (former Shell General Manager of E&P Deepwater) interview by Tyler Priest, May 15, 2000, Houston, TX


By the time I moved over to the Mars project, it had been decided that we will be moving with a TLP, but there were aspects of the TLP concept that were still under consideration.  An example of that was how we might provide for future fields in the area.  One concept was that we would have space within the TLP area for a self-standing riser.  So, just before Mars there was a project by Placid Oil Company in Green Canyon.  I’ve forgotten which block it was on.  It was called a freestanding riser, where a group of risers came up in a bundle and were supported by syntactic-foam buoyancy and stood by itself and then had flexible lines at the top of that that would take it up to a floater.  Then all the connections to that came in via subsea.  So that was one option that we considered within the well bay area.
 
Ultimately, we thought that would be a very large upfront expense with a lot of complexity for providing for future fields.  We, instead, created flexibility in the Mars TLP by putting attachment porches, we call them, for steel catenary risers along the pontoons.  So we have many more locations.  So we’ve done the export system at Auger from the pontoon, but that was all.  At Mars we put in a large number of porches along the perimeter of the pontoons of the hull in hopes that we would be able to bring in future fields, and ultimately those were used for things like Europa and Crosby.  I think about the other tie-ins that have come into Mars and allowed Mars, I think, to be probably the first real regional host in deepwater.  So at least for us, the first time that the thinking was both about developing Mars itself but thinking to the future of a wider development area, having infrastructure to do that.  But how do you do that in a way that you don’t spend an enormous amount up front but you have flexibility?

– Robert Patterson (former Shell Manager of Marine R&D and V.P. for Deepwater Projects) interview by Jason Theriot, August 29, 2009, Houston, TX


When Mars was coming along, the decision was made to bring the engineers from BP into our offices and work side-by-side as one team.  There was a lot of concern in the company that they were opening up a Pandora’s box of secrets.  Are these people going to walk away with a lot more than they are putting in?  It may have happened, maybe not.  I know we did get a lot of excellent engineering and good input from those people as far as relationships, and still are.  So it is a two-way street. And Shell was the operator in all those cases, so I am sure we gave away some technology and some know-how, but benefited some, too.  Being out there first in the deep water, with all the background that Shell had, going back to whenever it was, the mid-1970s probably, put them in a position where they didn’t have to worry too much about being overtaken.  Plus, they had a tremendous lease position that was far and away, beyond what most of the competition was near to.

– Lee Brasted (former Shell Floating Systems General Manager) interview by Bruce Beauboeuf and Joseph Pratt, December 19, 1997, Houston, TX


When I came in in 1991, all we were doing in deepwater is, we were spending money.  We weren’t generating one dollar for the company.  Our first well in deepwater started producing in January of 1994.  That was “Tahoe”.  One well at “Tahoe”.  One subsea well at “Tahoe”.  And that came on in January of 1994.  And then “Auger” came on in April and was not good news for the first 2-1/2 or 3 months.  And then, all of a sudden, it started producing, and all of a sudden, industry starting hearing.  They heard about “Tahoe”.  They saw we were going ahead with “Mars”.  They heard about “Auger”.  And it just exploded after that. 

– Richard Pattarozzi interview by Tyler Priest, May 15, 2000, Houston, TX


So I remember [Rich] Pattarozzi calling me in one day and said, “Dan, you’ve got to improve the earning power by 3 percent.”  So earning power is kind of like rate of return.  Well, it’s hard to improve 3 percent on 1.2 billion.  It really is.  You know, if you did it all by the time value of money, on schedule, you’d basically have to do the project in no time at all.  If you did it all by cost, you had to get out something like $400 million, I think, which nobody thought was even remotely possible.  So what do we do?
 
So I put the project on hold for three months, we kind of went back to basics.  What do we have to have?  What fits the purpose?  What do you really need here?  So we said, well, we don’t really have to do this like Auger did it.  We don’t have to have a lateral mooring system.  We don’t have to have that egg-crate truss system they’ve got on top and then you set all the modules on top of it and the drilling rig that used the lateral mooring system to move it around.  What you’re doing is you’re using one structure to support another structure.  Well, if we integrate those modules, weld them together and make them a part of the structure, you don’t have to have as much steel, costs you somewhere between five and fifteen dollars a pound to float the steel.  It’s a way to get the costs down.  We looked at other things, did a risk analysis, decided we didn’t really need to have these big nets between the columns to catch a wayward boat that’s going to hit the well risers.  Then we thought, even if it did, that you had protection, at least two pads.  So we spent three months kind of going back to basics and sort of redefining what the TLP function and design basis, what it all looked like.

– Dan Godfrey (former Mars Project Manager) interview by Tyler Priest and Jason Theriot, June 9, 2009, Houston, TX


I call Mars the burning platform because it gave me the opportunity for people to recognize the need to change, because if everything would have worked out okay, we’d have gone right along and done much like Auger.  We’d have done the same old thing.  But the economics didn’t work.  So it’s a burning platform in the economic sense that it’s a case for change.  You know, burning platform is usually the analogy that’s used, when the platform’s burning behind you, you’ll change your preconceived notions about what you’ll do to get away from it.

– Dan Godfrey interview by Tyler Priest and Jason Theriot, June 9, 2009, Houston, TX


So here we are coming back a couple of years later, or a year later, maybe, and we wanted to build the Mars topsides modules in McDermott’s yard.  It was the right thing to do.  They had the previous deepwater experience.  They were open to this new contracting strategy that we came up with.  But I was there three years, having built the Mars and Ram Powell topsides, and I’ll tell you that first six to twelve months was pretty challenging because we had to change a culture, we had to change a mindset.  We went from a mindset of you set up a firm price and you hold the contractor’s feet to the fire and he delivers on schedule and on that price and there’s no extras, there’s no changes, you deliver on that, to one where instead of the contractor being an adversary, the contractor is a partner.  You’re trying to build a relationship where you are working together for the same common goal.
 
It took a year before I would say most of the people on the team—and we were quartered in an old quarters module there in the yard.  We had McDermott folks in there, we had Shell folks in there, we had Bay, who did all the piping work, we had Seaco, who did all the electrical and instrumentation work, and a few others.  We were all right there together.  So if it was a tough day between McDermott and Shell or Bay and McDermott, the whole place knew about it.  It took probably the better part of a year for the team to really feel, you know, this is different.  This isn’t that same old adversarial, I’ve got to look out for my own company, my-own-self type of situation.  This is different.  I really believe this contracting approach and the steering team that was put in place and the people that were put in place were all done purposely to build an alliance that was true partners in relationship and were trying to achieve the same end goal. . . .

So what we would do is when you’re getting ready to put in plate girders, so many dollars per ton.  You would actually look on their books and see how many dollars per ton it would take to buy the steel, do the welding, and fabricate these plate girders.  Same thing on handrails, same thing on stairways, same thing on grating.  You had a unit cost that was McDermott’s base cost it cost them to build those things.  We then took those, added a profit margin, and agreed that every time we built a stairway, every time we built a plate girder, every time we put in deck steel, we would use that unit cost with that guaranteed profit, and all we had to do is estimate the tonnage because you had a dollars per ton or dollars per pound figure.  All we had to do was figure out what the tonnage was, apply that unit cost, and you ended up with basically what was the contract price.  If we added more steel, it increased the cost.
 
The great thing is that once the drawing were finished, we did that weight take off, we applied those unit costs, we came up with what turned out to be the lump-sum price, that locked in the price right then and there.  If we did it for less than that, McDermott shared 50 percent of the savings.  If it cost more than that, Shell paid for 50 percent of the increase.  So that very thing right there created what is very unique in our industry, a win-win scenario.  What was best for Shell was best for McDermott.

– Dwight Johnston (former Shell Operations Manager for Mars) interview by Jason Theriot, September 9, 2009, Robert, LA


By forming a joint team, it increased communication, it increased your problem-solving abilities as a team.  By the time of Mars, we’re already using scheduling.  In fact, I want to say Mars might have been our first project when we went with a dedicated schedule on it. . . .

We brought on a scheduler, and I remember our first presentation of the schedule.  I think we impressed Shell.  They liked the schedule.  They liked the individual we had doing it.  They elected not to have a counterpart on it, which, to me, was a victory.  We’ll learn and work together.  That individual, Jim Robinson, still works for us.  He was my scheduler on Mars.  And, again, we go into our scheduled meeting.  It’d be the contractor and the client.  No surprises.  Everybody knew what we were doing. . . .

So communication was a key part, and, again, Shell Mars was a tough job.  It was a huge learning experience for me.  In fact, we had meetings after meetings, team-building, group, these kind of meetings.  Some of the McDermott folks says, “Man, we got these meetings.  We ain’t get the job built,” type of deal.

I mentioned that to Dwight, and I’ll never forget him saying, “You get work done in meetings.”  So meetings has got to be a necessity.  You got to have your act together, you got to be run properly, and decisions need to be made.  And we made a rule:  If you’re invited to a meeting and you’re not adding value, get out; go do what you need to do.

– Denis Webre (former McDermott Senior Project Engineer) interview by Jason Theriot, March 25, 2010, Morgan City, LA


Jason Theriot: If it worked so well, if it was such a cost-saver and was such a trust-building tool between companies and contractors, and it seemed to work so well for Mars, Ram-Powell and down the line¸ why didn’t it continue?

Dwight Johnston: I don’t know if there is an easy answer to that question.  I have some thoughts on what happened around Shell.  I don’t know for sure what happened in the industry.  I actually know that BP and some others tried to replicate what we had done with McDermott during those days, and I don’t know for sure why it never really caught on other than, let’s be honest, we’ve been in the Gulf of Mexico building offshore platforms and developing offshore fields for over fifty years now, and at the time it was thirty-five or forty years.  You had an industry built up on just a certain way of doing things.  And here a different group comes along and does something different and it appears to be successful.  You try to replicate it, but you’ve still got this thirty-five years of history about how it’s done. . . .
 
So I guess this a long-winded way of saying you had to have the right leadership in place and, frankly, you had the right mindset, because we’d been doing things a certain way around Shell for a long period of time.  We do the design, turn it over to the fabricators, they give us a lump-sum cost, we’d put construction inspectors in the yard and we’d expect them to build according to those drawings, no matter what it cost and no matter what hardships it placed upon them.  So the reason it might not have caught on in the rest of the industry is, it’s just so different from how things had been done before and maybe not always the right leaders were in place to make it happen.
 
Now, around Shell . . . up until probably 2000, somewhere in that time period, even though we were part of a global Shell company, we were a fairly autonomous organization.  Shell U.S. was very autonomous.  We kind of did our own thing.  We did what we thought was best from a strategic standpoint and that led to contracting the way we thought was best.
 
But late nineties, early 2000s, things changed in our country and Royal Dutch Shell felt the opportunity to come in and exert more influence in Shell U.S. operations.  Before, I think they were always worried that the Justice Department would have concerns about a European-based company coming in exerting influence over a U.S.-operating company.  But that changed around that time period.  BP acquired Amoco, Justice Department didn’t overreact, so I think Royal Dutch felt, “Well, wow, this is an opportunity to really bring the U.S. operations into the global fold here.”
 
When that happened, the Group practices from elsewhere around the world were always EPC-type contracts.  You just didn’t do offshore platform contracting any other way.  That was the way it was always done.  That was the way it was always going to be done.  So I think what we had going for these deepwater projects was while good, solid, it was just so different from how all of our procurement practices and contracting strategies were put together that slowly but surely, their influence overcame our practices and we kind of got back into the old way of doing things.


– Dwight Johnston interview by Jason Theriot, September 9, 2009, Robert, LA


As we got into this deep water business, Auger, Mars and all these projects, a couple things became very obvious: number one was that we could not go out there alone and do what needed to be done.  It was just too expensive.  The infrastructure was too complex.  Even though we were “leading the charge,” if you will, into deep water, we said, we really have to have partners to share the costs, we had to have partners to share technologies, we had to have alliances with manufacturers who know what we are doing and try to work with us and, over a period of a few years, from, I want to say, 1988 to 1993 or 1994, a total change in, not only our philosophy, but industry’s.

– Carl Wickizer (former Shell Manager of Production Operations Research) interview by Bruce Beauboeuf, November 21, 1997, Houston, TX


It dawned on me when I was talkin’ to some reservoir engineer on one other project, it was Mars, and he was enforcing upon me the importance of getting the wells right. And he said, “You realize what you’re doing here?” I go, “What do you mean?” “Every well at Mars is the equivalent of a full field onshore ‘cause the average onshore well in America prior to hydraulic fracturing did 10 barrels a day. And Joe, you’re doing wells that do 10,000 barrels a day. Some of ‘em upwards to 40,000 barrels a day coming out one hole. Do you realize that? That’s the scale you’re operating on. That’s why in deepwater the opportunity is so great, get it right.” So a well in deepwater is the equivalent to a field onshore when you look at its production impact and roughly what its cost impact when you look at the cost structure. So the costs are much higher, but the rewards are much higher.

– Joseph Leimkuhler (former Shell Offshore Delivery Manager) interview by Diane Austin, June 12, 2015, Covington, LA


Every morning there was a video conference involving the offshore leadership team, Reliability Engineer, the Surface Engineering staff and the Asset Leader to whom their team leaders and the OIM all reported. Performance data from the facility and wells was continuously beamed into the office so all had already digested it. This include new sand detection sensors for the wells which was what enabled us to safely establish the productive limits of the wells (along with the knowledge that Pattarozi had our backs as we pushed this particular envelope). As problems came to light, responsibilities were handed out to joint engineering /operations teams to be addressed. Also, near and long term plans were discussed. The 5 pm meetings on the TLP were to discuss operational plans among the Leadership team, contractors and key operations personnel with a hard focus on SIMOPS permitting. There were also dawn meetings on the TLP with the entire population to discuss activities, safety trends, and recognition for individual and team achievements in safety, as well as operational performance. The Star Point committee hourly members were deeply involved in these as well as their own regular committee meetings apart from their ”first hat” responsibilities. Finally, Monthly Business Reviews were held that looked at all aspects of TLP performance and planning that involved both the onshore and offshore leadership. The feeling of asset ownership was quite pronounced, particularly as much of the team had been together from the start of design.

– Bob Markway (former Mars Asset Leader) email communication to Tyler Priest, April 14, 2017

A little-known feature of the Ursa TLP system selection was that we maintained the option to develop the field completely with subsea wells tied back to the TLP.   That is, in case we were unable to pre-drill a bunch of development wells in one spot due to the shallow water flow risk, we could cut our losses by installing the platform in a separate happy location and disperse the development wells as needed to manage SWF risk.  This was probably not well documented in the official papers for obvious reasons, but this is why there were so many subsea tieback hangers pre-installed on the hull.  I know this because I was on the system selection team for the Ursa development.

– David Huete (Shell Staff Civil Engineer) email communication to Tyler Priest, April 13, 2017