The geoscience industry is in a state of flux. Western- Geco recently got out of the marine seismic acquisition business totally, and some of the other major companies have filed for bankruptcy or laid off staff to try to cut overhead. Granted, the industry has been in a downturn, and geoscience expenses are often the first to be cut. But this comes at the same time that the technology is constantly improving, with imaging technology advancing and processing technology tackling larger and larger datasets and finding more in them, everything from more traces to seismic monitoring for producing fields.
E&P recently sat down with several geoscientists to discuss the state of the industry. Among the group were Richard Degner, president and CEO of Geophysical Technology Inc.; Dave Monk, director of global geophysics for Apache Corp.; Mike Bahorich, former CTO for Apache; and Allen Gilmer, co-founder of Drillinginfo. The conversation was essentially a discussion about why geophysics and geoscience still matter in the oil and gas industry.
E&P: Do you feel like the oil and gas industry is still interested in geoscience?
Bahorich: Among the largest super-independents, there are some that have had tremendous success using seismic to maximize the value of their shale assets. Almost all the shale players use seismic for geosteering, and I cannot imagine geosteering without it.
After geosteering, there are many other uses that should be considered.
There is often a good impedance contrast with frack barriers, so companies use seismic to track frack barrier location and thickness.
In some situations it is possible to use seismic to interpolate characteristics that relate to the richness of the shale.
If you review investor presentations from top operators, you will find several that generate shale reservoir models using petrophysics and seismic.
Regarding the cost of seismic, we’re talking about pennies compared to drilling dollars, and petrophysical reservoir models that incorporate seismic can help them understand not just the location of quality rock but also can help them decide the sequence in which they should drill their wells. If they understand something about the rock quality, which they can do through a reservoir model, then they can do a better job of executing their capital programs. I think many companies could learn from some of the leaders in this space.
Gilmer: You’re stating something that we take to be a ground truth. But if that was the case, we would be shooting lots of 3-D surveys, and we’re not.
And so the concept is that if you want to stay in the zone, are you going to use 3-D in every case absolutely across the board? Yes, yes, yes. That’s what we would say every time.
And we can go out there and demonstrate the efficacy of doing those kinds of things because it’s getting better.
But if you were to ask the people who are responsible for executing on those drilling programs how valuable 3-D seismic is, you would get a few that would say it was very valuable, but you would get a lot who would discount it regardless of the value.
I think it really is just a question of finding the value and framing it so that people are really testing that value all the time.
Monk: The biggest issues that people have with the completions are trying to determine how far apart the wells should be, how many fracks they should do [and] how many stages should be in a lateral, and those completion engineers haven’t determined that yet.
They don’t think they can get their information from the seismic.
They understand where they’re going todrill, how they’re going to do the lateral, that they’ve got to steer them, and the problem that they all want to solve today is how far apart to put laterals and how many stages they should drill.
Geophysics might be able to help them.
E&P: They can’t get the information, or they don’t think they can get it?
Monk: We’re struggling to prove that they can get the information.
Gilmer: I think we can say, categorically, that they can get that information. If you structure all the information right, categorically you can get it. The issue is that it’s just not been delivered to them in a way that they understand, and I think it really is a nomenclature difference.
I credit Richard [Degner] when he first started selling seismic data by the acre. Frankly, that was simple, and it worked brilliantly because it was the first effort to try to put seismic data into the context of what the engineers were thinking about with regard to the cost, being able integrate it. I think the more that we can do to start really just putting things into the nomenclature of engineering as opposed to the nomenclature of seismic or geophysics is really, really important.
Degner: And I think I did that just so that I could try to understand it myself because I don’t understand E&P execution the way that these guys do, but I see how for $50 to $100 an acre we can record a survey that has a sampling of 4 million or 5 million traces per square mile. Twenty years ago, we were recording 20,000 or 30,000 traces per square mile.
Monk: We just completed a survey at 76 million traces per square kilometer.
Degner: So 200 million traces per square mile, equivalent.
We record these amazing surveys, and the operators volumetrically extrapolate all of this incredible well information so that they can take hydrocarbon percentage or brittleness of rock or whatever the petrophysical properties are [and] extrapolate them out, obviously adding enormous value over millions of acres to understand how to extract these hydrocarbons in the most efficient way.
When I started dividing everything by acre, I said seismic will cost you $50 to $100 an acre. These operators are leasing land for $30,000 or $40,000 per acre, and they’re drilling and completing it for another $20,000 or $30,000 per acre.
If you spent 10 times that much more and had 5% better execution or even 1% better execution, isn’t that an amazing payback?
Gilmer: But it’s the time. With regard to shooting, processing and interpreting seismic data, the time frames are so long that it really kind of precludes the utility. The ability to collapse that time frame is here, but it just hasn’t been as important. Is the time frame really that critical?
Degner: Is it really that short-term of a decision? The development of these shale plays covers the next decade, not the next 10 weeks.
Bahorich: I think it can be an issue. It depends on the situation. Ideally, you want to use seismic for your initial drilling program. But if the cost of capital is significant and waiting on seismic causes a delay of some huge drilling project, that delay can be more costly than a seismic survey.
Gilmer: You have to optimize the wells you have on your lease so that you can develop locations to have the maximum value. So it becomes financial. Those are the things that we have to be conscious of. But yeah, they’re going to be developing it over a decade, and they’ll be able to layer those things in.
Bahorich: One of the benefits of having a large spec program acquired and processed ahead of time is that this great big problem goes away. Sometimes it can be difficult for the seismic service company that’s actually laying out the dollars to pay for that spec program, but in terms of overall benefit to the industry, it solves a significant time value of money problem.
E&P: Are operators able to wait for those results?
Monk: Geophysics has the capability to measure the information about what operators do when they actually frack the well. Whether they can do it in real time is another question. They then modify the frack program, but it’s not surface seismic the way that we’ve done it before.
Gilmer: How do we integrate geology and geophysics more tightly with regard to being able to provide that magic information between reservoir models of seismic and geology? That is a really interesting space right there. I think that the concept of using seismic data as a soft control for geology to approach that whole problem from a geological perspective as opposed to this purely seismically driven perspective is an interesting place for us to be.
Bahorich: What that brings up is that we have a responsibility to communicate what seismic can do and what it can’t do.
Gilmer: There’s another problem. Once the cookbook for completions is dialed in to provide above a 20% internal rate of return, then anything a company does to adjust that is looked at as a science risk, and the whole process turns toward how many wells an operator can get drilled through the regional playbook as fast as possible.
So they always think in terms of the regional playbook, but regional playbooks leave a lot of oil behind. The next step, and this is where I think seismic would really shine, is what I call location-specific optimization, which means how they complete a particular location because the rocks look alike or because of their proximity to faults and what have you. And that means not using a cookbook; it’s location-specific, and seismic is critical for that. And the amount of hydrocarbon to be had by going from regional to location-specific is probably 20% more.
Degner: I think there’s enormous promise in technologies like ambient reservoir monitoring, tomographic fracture imaging and imaging the continuous emissions of sound from the permeability that exists in the earth. We’re just now starting to come up with seismic sensors at the surface that have enough dynamic range and high enough coupling that operators can really be recording those tiny microseismic events and recording them over time, getting confidence in where they’re coming from and then imaging them. I think that’s a sector that ultimately will bring a lot more credibility to the geophysical industry in general. And it’ll help tie together some of the things that the engineers are doing with the basic regional seismic datasets out there.
Gilmer: I’m an optimist on this whole thing, and the reason is because I’m impressed with the petroleum engineering students that are coming out of school today that have been really hungry to learn about this. When I got out, I didn’t know anything about petroleum engineering at all. It is coming, and I’m very heartened by that. I’m really impressed by the programs and the students coming out of those programs. The people that geoscience has attracted have been among the best scientists on the planet, and the amount of work done is amazing. The value of it is, unquestionably, remarkably high.
Degner: Agreed. The industry recorded surveys 25 years ago at 20,000 traces per square mile for around $100 per acre and is now using high technology and exceptional logistical execution to record surveys with many millions of traces per square mile for that same $100 per acre. We have delivered efficiencies using technology to improve resolution of earth imaging by many orders of magnitude. There’s also a sense from the regulatory bodies that as soon as something happens that’s catastrophic, they shut down the geophysics. Why would you shut down geophysics? Why wouldn’t you increase it tenfold so you have better information to have better understanding?
Bahorich: We don’t want to poke holes everywhere. We want to look first with a geophysical image.
Monk: So there is a capital argument against this that I’ve come across in the past. Before Apache, I did some consulting work for a bank that lent money drilling wells and doing seismic. There were people who did not want to shoot seismic because they thought it would condemn their acreage.
Gilmer: The only way you collapse an uncertainty cloud is to collect more broad data.
Degner: So the question is, are more traces always better? At the price that we’re talking about, when you’re paying $50 to $100 per acre while spending $60,000 to $80,000 to lease it and to develop it, it always matters.
Gilmer: But if you were going to use geology only, you’d be very successful on a portfolio approach. If you’re going to drill 100 wells, you can get a good understanding of what those 100 wells will do in aggregate. If you want to determine what a single well will do, you need seismic data.
Degner: I was in Baghdad a few years ago, and they wanted to know all about the U.S. shale plays. The in situ hydrocarbon in place is 14%. Eventually in this energy hungry world, we’ll need to be harvesting the hydrocarbons in those massive Middle Eastern shale reservoirs.
My question is that, in less mature oil fields, is geophysics worth more? It seems like geophysics is readily applied earlier without hesitation internationally because they don’t have all the well information.
Gilmer: From a conventional point of view, it’s still mother’s milk. You have to have it to drill those wells.
Bahorich: It’s the tool that you need.
Degner: Today, because of the bleak balance sheets of the geophysical service companies, many can’t buy new technology. And oil companies have budgets now. One national oil company in Latin America told us, ‘We haven’t shot seismic in five years. Our management just came to us and said we’re supposed to shoot 5,000 square kilometers [1,931 sq miles].’ They didn’t know how to do it because the supply side of the service business is decimated. So they’re looking at procuring geophysical technology direct themselves.
Gilmer: I think that’s pretty fascinating.
Degner: It hasn’t happened in 30 years. It’s almost like we need a different commercial paradigm and a different commercial mechanism to create more efficiency and to leverage a lower cost of capital.
E&P: Do you think the oil companies will go back to owning their own crews?
Degner: Anything that creates value makes sense. When the oil company has a cost of capital of 5% and the smaller service industry players have cost a capital of 40%, the only way the oil company is going to get the service done is if it pays the cost of capital of a service company that’s in a beleaguered state.
Gilmer: What was the result of the oil companies divesting themselves of service company investments? They put the cost of R&D and capital on the service industry. Every time there was a boom, the seismic equipment manufacturers financed other companies. It’s very efficient, but it didn’t build anything.
Monk: But the evolution might be that the oil companies start building their own crews again, and five years from now they spin them off into separate companies.
Questions or comments? Email Rhonda Duey at email@example.com.
Read E&P's other October "exploration" cover stories:
“After exploring all strategic and financial options available to Rosehill,” CEO David French said the company agreed to a restructuring plan with its major creditors, which includes filing for Chapter 11 bankruptcy, .
Exxon Mobil last quarter cut oil production by up to 400,000 bbl/d and capex by 30%, much of it in its shale business.
Court rulings over disputes with midstream operators are no longer easy to predict.