Critical D&C issues with Matt Simmons, Simmons & Co
By Jeremy Cresswell, contributing editor
Energy investment banker Matt Simmons agrees that, amid the oil slump, the pressure on petroleum companies to batten down the hatches is enormous. Thus far they have exercised constraint, but for some, there will be no choice. The price slide also offers operators a clear chance to put pressure on the supply chain. And a prime target is drilling and related services.
DC: It is already clear that some drilling contracts are under threat of renegotiation to get prices down. There has been softening of the market and, by late November, this was starting to impact offshore newbuilds orders. What’s your view?
Simmons: There’s a sort of glee in oil company boardrooms. There is a sense of we’re going to be prudent and pull in our belts. Not too much, of course. But then when you start pulling in your belt, it feels so good, especially if you start believing that, if you pull a little tighter, you’ve got the drilling contractors on the run.
But they need the drillers, especially offshore deepwater, where long-term contracts tend to be the rule. Notwithstanding the massive fall in energy demand and oil prices, the companies have got to guard against precipitate action as the looming shortage in conventional oil resources is not about to evaporate.
Think on the stark messages of the International Energy Agency’s 2008 World Energy Outlook Report that’s just been published. We have no spare capacity in the global system. And that includes within the drilling sector. The conventional global offshore and onshore fleets were already stretched before the credit crunch – the legacy of under-investment manifest by an aging fleet.
DC: At the 2008 Offshore Technology Conference, you stirred things with your paper “Oil & Gas ‘Rust’ – An Evil Worse Than Depletion.” Presumably you haven’t changed your stance?
Simmons: Not enough priority is being given to worn-out rigs and their replacement, partly because the sector has done a very decent job of upgrading old units and repainting them.
That’s a little bit akin to taking an 80-year-old building in Aberdeen or Houston and giving it a face-lift. You can take that only so far. Sooner or later, if you don’t tear the building apart and rebuild, it will fall apart.
What is very scary to me about the offshore drilling fleet is that it’s the only physical census that can be accurately implemented, of all of the various assets that make up the drilling service industry … the myriad pieces of equipment that have to come onto a well site before you can actually drill for oil and gas, eventually produce what is found and maintain in.
Basically, there are 600 offshore rigs, but 100 aren’t really active anymore. But they still show up in the lists even though many haven’t worked in years. So you’re down to 500 actual working units.
Of course, there are about 140 new rigs on order, but they’re either deepwater jackups, ships or semis. There are almost no conventional rigs on order.
Of the 500, about 425 are conventional. These are the workhorses – second- and third-generation semis and a lot of jackups. Don’t forget that a high percentage of the offshore oil and gas produced today comes from fields located in water depths of less than 200 ft. But even for that sort of bread and butter work, too many of the 500 are only fit for cutting up, yet they’re still at work. This is my big issue. Those rigs are too old.
When I talked about rust at OTC, it was funny, what I got told by some of the drilling fraternity was: “Matt, you’re spot on. Our rigs are in good shape, but the rest of the industry isn’t.”
It turns out that maintenance is the last thing that anyone is spending significant money on. You don’t get a return on that. Also, there’s not a sense of urgency that we need to replace many of the conventional rigs even though it is admitted that they are obsolete.
DC: But if they’re obsolete, then why are they working today?
Simmons: I think the industry faces a tremendous challenge trying to figure out how many of the current 500 rigs have to be replaced and what the consequences will be if we don’t. One is the impact on production if we don’t keep drilling up new wells in mature fields to try and slow their decline.
DC: One issue confronting the industry that seems not to be talked about much is the length of time wells are taking to drill, especially deepwater and in complex geologies, even if the water depth isn’t much.
Simmons: That’s right. For example, in the Gulf of Mexico, where a standard gas well can be punched out in 20 days, the move to deep gas has led to 180-day wells.
Everything has gotten more complicated, which means far more rig time per well. Also, to get at the resource effectively, 500 wells now need to be 750 wells, or 3,000 wells need to be 4,500 wells to get out the same amount of oil and gas. However, no one, to my knowledge, has tried to calculate what the real numbers are, let alone how long it will take to get those done or how may rigs might be needed.
Simplistically, going through salt is basically like the difference between drilling through mud and then hitting a layer of granite. It of course takes a lot longer to drill through granite than through mud, and it can take the better part of six to nine months to drill such wells.
I’m not sure that some operators don’t appreciate the scale of the challenge they are taking on, though some like Petrobras clearly have a good grip. Look at their considerable pre-salt success in the Espirito Santo Basin offshore Brazil.
They’re being extremely realistic about the fact that the Espirito Santo Basin is the most challenging yet explored, which is one reason they’re trying to round up 70 deepwater rigs to delineate the huge finds already made and to explore for more fields.
They’re very large structures, and we (most operators) have got to get off the fantasy that one or two wildcats and maybe a couple of appraisal wells are enough to show you what’s there. That’s where problems start.
The theory that we have a lot of homogenized reservoirs – so if you have data on both ends of a field, you know what the center is like – doesn’t hold water. It turns out that about 1% of the fields in the world are like that.
The industry grossly skimped on drilling a limited number of new exploration wells on new discoveries and the one or two appraisal wells and then without coring, without flow testing.
If you’re dealing with a carbonate reservoir, which is what a high percentage of oil-producing fields worldwide are, they’re all heterogeneous. That means that an area of the field can be totally different than another part 1, 2 or 5 km away. That in turn means that, unless you do a very careful delineation, you’re really rolling the dice on even how to design production facilities.
At least if you’re onshore, you have the luxury of being able to start at the crest and work your way outwards a bit at a time. And it’s easy in shallow water too, with multiple platforms. But once in deep water, you might have just one production hub and a limited number of subsea well clusters for cost reasons, even with the new Brazilian discoveries.
DC: You mean the Espirito Santo finds?
Simmons: Yes. Let’s take Petrobras’ Tupi find as an example. They’re probably going to have to drill 20 appraisal wells to delineate the field properly. Each of those wells is probably going to cost $200/250 million to $400 million. More importantly, they chew up a huge amount of rig time.
And then there is the issue of how long you flow-test a well and, by the way, if you’re being prudent, you will also take a core. Cutting a core is a god-awful exercise at 5,000-ft vertical depths. Cutting one in a Tupi well, that’s going to be a completely different thing.
If you have to frac a well before it flows and you only flow-test for a matter of weeks, you’re deluding yourself as to how long the fracture will work before it closes up. To properly learn how a reservoir is likely to perform, you would probably need to flow-test a well for six months. That’s almost impossible to do. Where do you put the oil, unless you build/convert specialist capacity (Brazil does have the Seillean).
So 70 rigs are not going to drill that many wells for Petrobras. It’s going to take a long time to build a picture of the Espirito Santo Basin, even with that number.
DC: The tendency is to associate your remarks with the offshore scene, but you’re a keen observer of onshore too and no less opinionated. So what are the big issues?
Simmons: Most of all, might it be possible in 2009 to get a better handle on what the active land rig population worldwide really is?
One nice thing about offshore is that there is an identifiable census. You can mostly easily tell what’s out there. But onshore, we really don’t have a reliable rig count because onshore rigs don’t stay together as a unit. When you de-rig a job, you put all the pieces on the trucks and you take them wherever.
Look, if you take a 20-rig drilling fleet and spray-paint each rig a different color, within six months you’d have 20 Joseph’s coats of many colors because the components are interchangeable. That makes tracking difficult.
We have a fairly good idea that there are about 3,000 onshore rigs worldwide, of which about half are in the US, some 300 are in Canada, 300 in the Middle East, etc. Worldwide, only a few hands-full of new land rigs have been delivered in the last 30 years. OK, there’s been a lot of recommissioning/rebuilding, and there are maybe more orders than before, but only for a few tens of units.
DC: Does that mean the fleet is getting long in the tooth and has to be replaced? That will surely be easy as they could be mass-manufactured, couldn’t they?
Simmons: It’s important to recognise that the onshore fleet faces the same problem as offshore. Many of the rigs are too old, and components and fixings wear out. And you can’t just mass-manufacture new ones on a production line basis. We found that out back in the 1970s. There are only one or two companies that know how to knock them out. There is one major manufacturer of drilling components: National Oilwell. It makes about 70% of the components that go on a rig. They are totally backlogged.
If you want to get an idea of what is needed in terms of new rigs, go look at the IEA’s WEO (World Energy Outlook) 2008 report: 30 million barrels per day of new production capacity by 2015; 106 mmbpd total demand by 2030.
That could mean there’s a need for 10,000 new land and offshore rigs. And even if it’s only 5,000, the point is that it is an order of magnitude the likes of which we would need to triple every plant in the world today that makes drilling equipment.
We’ve boxed ourselves in, and there’s no way out; we’ve run off the clock.