ConocoPhillips’ Greg Leveille sees rapid trajectory of technical advancement continuing
In an exclusive interview with World Oil Editor-in-Chief Kurt Abraham, ConocoPhillips Chief Technology Officer Greg Leveille discusses the technical issues facing global E&P, particularly as relates to the many U.S. unconventional plays
World Oil (WO): What do you consider your company’s strongest areas of technical expertise?
Greg Leveille (G.L.): If I had to pick one, I’d call out our unconventional reservoir technology capabilities. Over the last 10 years, we’ve grown our unconventional portfolio from very, very small volumes to 8 Bboe, which is half of ConocoPhillips’ resource base. That is at under $50/boe, cost of supply. And we’ve been able to develop a suite of technologies around completion design, optimizing drilling, and using digital and data analytics capabilities to improve production uptimes. So, there is a suite of capabilities that has made our unconventionals industry-leading and certainly one of the best-performing parts of our portfolio.
WO: Are there areas of technical capability, in which you would like to see the company do better?
G.L.: I think where a lot of our focus has turned in the last two years is to the digital and data analytics space. Frankly, it is a second revolution happening in the oil and gas industry. We have put an enormous amount of effort into upping our capabilities. But if you look at where we are today, and how much further we have to go, there’s quite a big gap there. So, I think finding ways to transform the way our subject-matter experts work—our petroleum engineers and geoscientists—we’re looking at this as a complete change in the way work gets done, and not so much as a suite of specialty skills.
WO: What are some of the greatest technical challenges that the industry faces in onshore projects, either for shale or conventional fields?
G.L.: If you look at what’s happening onshore, the industry continues to increase productive capacity—the U.S. is producing hydrocarbons at a phenomenal rate, which is putting loads of pressure on the industry to continue to reduce cost of supply. So, our primary focus is finding ways to continue to reduce costs and/or increase production per well. We’ve had loads of successes, but it’s one of those places, where you really can’t stop being vigilant and stop trying to make improvements, even if prices rise up to $60 or $70/bbl. Another area is probably things like water management and methane emissions—basically pieces of business that don’t necessarily get as much attention as the production of a molecule of gas or a barrel of oil, but which are integral to being able to operate onshore in the long run.
WO: How are IP rates faring? What is the average IP?
G.L.: Within our unconventional reservoirs, we’ve increased our productive capacity quite a bit. IPs are up many, many tens of percent from a few years back. That’s a combination of changes in completion design, changes in lateral length, the way we manage the wells, etc. So, we’re finding ways to increase not just the initial production but also the total recovery from the reservoir. The statistic we’re most proud of is the recovery factors that we’re seeing in the Eagle Ford, which are now at 20% or greater. That’s been a tremendous effort, and one that’s paid enormous dividends.
WO: Methane emissions seem to have come to the fore lately among industry issues. Why is that?
G.L.: I think there’s more and more attention being paid to sustainability of the industry. ConocoPhillips has put a lot of effort into sustainability. We talk with Wall Street quite a bit about our sustainability efforts, Fig. 1. One of the things we recognize is that we have to run the business in a very sustainable way, in order to be able to continue to operate the way we do, across the United States. So, finding ways to reduce methane emissions through detection and/or using different technologies has been a big focus for us.
WO: Shifting focus, what are the greatest technical challenges that you see in moving forward with offshore projects, particularly in deep water?
G.L.: If we look at the offshore, probably the biggest challenge is the length of time required to go from conceiving an idea to actually testing it and then deploying it. It’s not atypical for offshore projects, particularly in deep water, to have timeframes—between conceptualization of the project to actual first oil—of a decade or more. When you’re competing against a class of assets like the unconventionals, where literally within three to six months, you can be out field-testing new ideas and new technologies, and within 12 to 18 months deploying at scale, it’s very hard to match the pace of innovation that’s occurring in the unconventionals. So, really, in the offshore space, the challenge for industry, or the opportunity, is to find ways to dramatically improve the pace at which innovations can be tested and ultimately deployed, if successful.
WO: The Permian basin seems to be the gift that keeps on giving. Assuming reasonable oil prices, do you see the region slowing down, at all, during the next several years?
G.L.: When we look at the Permian (Fig. 2), and most of the unconventional plays, they have a really long life ahead of them. The resource volumes are sufficient in all of the large unconventional plays in the U.S. for multiple decades of development, with the Permian obviously being the largest liquids-rich basin in the country. We’re talking out to 2050, probably, as far as development opportunities. Things that will slow it down temporarily are items like infrastructure constraints and being able to manage water in the basin. We think that industry will sort most of these things out. We certainly have found ways to do that in the Eagle Ford, the Bakken and some of the more mature areas.
WO: Your own chart from a presentation last year shows that “fracturing intensity” grew from 3.5 million pounds of proppant and 70 perf clusters in 2012, to 15.5 million pounds of proppant and 300 perf clusters in 2017. Are we getting close to reasonable limits per well for these items, or is there still more room for growth?
G.L.: There are probably physical limits on the amount of proppant that will be pumped. Basically, the proppant is there to serve the purpose of keeping the fractures open. And I think what industry has been focused on, to date, is essentially a brute-force approach to placing proppant in the reservoir, which is basically more proppant, more perf clusters. What we’re looking at now, is trying to find ways to effectively prop more of the fractures we create. We’ve run experiments, where we’ve hydraulically fractured a reservoir, drilled through it, taken core, taken logs and pressure measurements. And what we find is that we create far more fractures than are expected from the models that the industry uses to predict fracture geometries. But very few of the fractures created are actually propped. And so, it’s going to be companies that can find ways to better distribute the proppant that are going to be successful in further increasing recovery factors, further increasing production rates. We know that we are going to be one of those companies that makes those types of advancements.
WO: Another item that you’ve talked about is the incredible growth in lateral lengths. In your company’s own Delaware basin drilling program, in just two years, from 2015 to 2017, you went from 50% of wells having laterals longer than 7,500 ft to 95% of wells having laterals of that length or longer. Accordingly, how much more growth in lateral lengths could we still see?
G.L.: If you look at extending lateral lengths, it’s one of the most effective ways to improve a well’s cost of supply. Very little increase in drilling cost, and you’re able to increase the output by many tens of percent. So, if you’re doubling the well length, you can usually come close to doubling the output. We expect this trend to continue, and, frankly, we’re working with companies on tool designs, to try to allow accessing of longer laterals. It really isn’t the drilling of the long lateral, which is the constraint, it’s the completion. So, most of the focus is on the completion tools and the way you would go about completing a well, which is longer than 2 mi. We think the industry will advance in that space, and it will continue to yield benefits. The other constraint is just the land arrangements, and you’re seeing companies try to trade land, so that they have continuous acreage positions that allow for these longer laterals.
WO: Water management has become a leading issue in unconventional plays, particularly in the Permian. How important is this issue to your company’s operations, and what are some examples of technology that you may be employing to manage water?
G.L.: It’s absolutely crucial. I look at water management, and it’s one of those things that you need to do well, to enable efficient exploration and production. If you think about the technologies being used, it varies by play. In certain areas, water is both scarce and you produce a lot of it, when you are in the development phase. So, the Permian basin would be an example, where there is a relatively small amount of resource available for hydraulic fracturing, and a large amount of water production associated with oil and gas coming out of the ground. In those types of situations, you’re looking at almost a complete, full-cycle management, where you’re recycling the water, and cleaning it up enough to be re-used as hydraulic fracturing fluid. So, you have a very sophisticated water management approach. Some other areas may be looking at some component of that system. There are a number of plays, where you don’t produce much water after hydraulic fracturing is completed. It’s more about just managing the sourcing of water in an effective way that minimizes cost, as well as the impact on the environment, Fig. 3.
WO: You’ve mentioned that “further completions optimization” is coming—what might that entail?
G.L.: It ties back to what I said about placement of the proppant. We think that the key going forward is placing the proppant in the fractures more efficiently. So, you have a higher percentage of the fractures created, which are actually propped. As you do that, you’re going to be able to get to higher and higher recovery factors, and better IPs. It may not be more proppant per well, but finding ways to do the completion, such that you’re increasing the overall recovery factor. We’re working on that in a number of different places.
WO: You also expect to achieve artificial lift improvements and greater production uptime—how might these goals be accomplished?
G.L.: The oil field is experiencing a digital and data analytics revolution. Looking at artificial lift, much of the optimization has been manually driven. The well would get attention, only when a multi-skilled operator was on site. We’re going to a world, where there will be computer technology deployed at the wellsite that will allow 24/7 optimization of systems. And doing it in a way beyond what the current control systems are capable of. We’re finding that Silicon Valley has recognized that there’s a big opportunity in the industrial space, and more and more of their attention is being turned toward it, rather than just the consumer applications. And as they do that, they recognize that oil-and-gas is one of the biggest industries in the U.S. We’re partnering with a number of companies, to find ways to optimize production, and automate drilling and optimize completions.
WO: If you’re going to have more technology at the wellsite, how are you going to power it?
G.L.: A lot of the technology is compact enough, that the solar capture of energy stored in batteries is going to give us plenty of power. You’re going to have essentially remote intelligence that will be able to call home, but it won’t need to call home necessarily to get instructions as to what to do. It will send information about what it’s been doing, and every now and then, you can update its intelligence, if you will, over the wire. So, I think there’s going to be a lot of remote power generation.
WO: How important is the use of digital technology to your field operations?
G.L.: One of the most interesting aspects is the people side of it. What we’re actually trying to do is take all 11,000 of our employees and upskill them in digital and data analytics. Go back five years, and a petroleum engineer or data scientist wouldn’t have had much, if any, training in the use of sophisticated data analytics. Today, we’ve trained over 4,000 of our 11,000 employees, and we are on a path toward getting all 11,000 upskilled to the level at which they need to be, to do their particular jobs. We think it’s going to make them far more productive. We’re going to be growing our production, so we expect to be able to do that without growing the number of people, because each person will be more productive, using the digital tools we’ll provide them with.
WO: Any final thoughts or comments?
G.L.: It’s a very exciting time in the industry. If you think about the pace and scale of change, it’s been enormous over the last 15 years. We’ve basically taken an industry in the United States, which was dying, and turned it into the powerhouse of the entire global industry. So, I think there’s more to be done with technology, and it’s really just a matter of getting enough focus on it, to keep this trajectory going.
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