亨特·兰德斯 (Hunter Landers) 是 Diamondback Energy 的完井高级副总裁。

从勘探与生产的角度来看，您认为目前钻井和完井行业面临的最大长期挑战是什么？

我认为最大的挑战之一是留住人才。从运营商的角度来看，这意味着为每项工作保留相同的人才——即钻井工人和实现这一目标所需的所有相关服务。我们使用各种策略来留住承包商，例如绩效激励或补偿，并且我们看到使用这些策略成功将钻井和完井团队团结在一起。 

对我们来说，让同样的人员每天在现场一起工作就像让交响乐团保持团结一样。任何时候都有 10 或 20 个供应商一起工作，让一切像一个整体一样运作，因此让每个人都习惯于一起工作并了解彼此的动作非常重要。这使我们能够保持高效，但留住高水平人才始终是一个挑战，而这正是我们今天仍在经历的。

对于钻井承包商来说，我认为挑战更多的在于效率提高带来的活动减少。北美陆地市场在过去一年左右的效率有所提高。如果我们之前计划钻探 X 数量的井，我们仍然会钻探相同数量的井，但我们用更少的钻机来钻探它们 —— 而这并非 Diamondback 独有的。 

这在一定程度上造成了供需不平衡，并可能导致一些钻机费率下降，这使得钻机承包商在已经经历了新冠疫情导致的低迷相当严峻的挑战的情况下，面临的挑战变得更大。

这使得市场竞争异常激烈。当目标不断变化时，人们很难制定商业计划并执行这些计划。对于钻井承包商来说，他们必须不断寻找保持竞争力和盈利的方法。

所以您有首选供应商网络。您觉得在当前市场中维护这一网络有挑战性吗？

我们总是更多地关注市场的价值而非价格。你可以以低价值获得一些极其便宜的服务。但是，目前游戏的核心是资本效率，这是我们一直坚持的。有时很难定义我们为给定服务获得了多少价值。

我认为我们的团队会努力定义价值，但就如何让价值保持一致而言，我们承认有时我们无法控制。甚至价格之外，比如说，某个钻井平台上的某家公司有员工辞职，我们也无法要求他们辞职。我们对此没有任何控制权。

就像我说的，我们提供一些绩效激励措施，让承包商愿意在 Diamondback 工厂工作。激励措施不能仅仅是为了实现一个里程碑——它必须基于价值。无论你付出什么，你都必须获得其中的一些价值，才能让它物有所值。 

如果你能达到这种平衡，那将对保留有很大的帮助。

您认为近期内资本纪律会持续下去吗？

股东群体强调返还自由现金、提高资本效率和约束资本，因此我们也在这样做。

此外，从宏观角度来看，全球供应过剩，这并不是增长的信号。我们希望采取一定的纪律，以应对大宗商品价格周期。 

为了开发能够进一步提高效率的系统，您需要优先投资创新。从运营商的角度来看，Diamondback 在该投资中扮演什么角色？

Diamondback 不会在新产品的研发上投入巨资。我们希望对系统有高度的确定性。 

这又回到了资本效率和股东对我们的要求上。如果某件事奏效了，我们就会迅速跟进。我们通过收购证明了我们是一个快速的跟进者，我们会尽快利用新兴技术。但我们对那些不知道是否会有回报的投资的风险承受能力很低。如果没有一定程度的确定性，我们不会开发新产品。

话虽如此，但树上还是有果实的。我认为我们可以继续推动旋转导向钻井的发展，我们可以在继续进行长距离钻井的同时进一步优化钻头，但你必须根据具体情况来看待这些创新。如果一家公司在某种钻头技术上取得了成功，并且能够克服该技术以前的局限性，那么我们当然会尝试。但如果我们尝试了那个钻头，然后钻到了 1,000 英尺深，我们必须进行一次钻探，那么我们就不会再尝试了，没什么大不了的。 

但是，对于某些可能对您的计划产生负面影响的事情，我们无法容忍风险。这要视具体情况而定，每个人的临界点和心态都不同，对于尝试新事物或不同事物可能带来的价值也不同。我们只是觉得，为此承担大量风险并没有什么好处。 

那么自动化呢？Diamondback 认为自动化有价值吗？

再次，这又回到了价值问题。这些技术会像我们现有的技术一样可靠吗，还是需要付出代价？自动化会为我们创造价值吗？如果会，那会是什么样子？在整个行业中，我认为肯定有人在关注更远程和自动化的流程，尤其是在钻井方面，自动化可能会在未来发挥作用。 

您现在承包的钻机上需要配备哪些设备？ 

我不会说这是必须具备的条件。显然，您需要马力规格和重量规格，但这只是将您的项目与钻机结合起来。对于我们来说，我们主要寻找的是让高质量的人员和高质量的团队合作，无论是在钻机上还是在辅助服务上。您需要可靠的设备，而不是在最大容量下运行 — 您需要能够突破极限的设备。您需要具有足够容量的设备来满足您的项目增长需求，无论是更长的水平段、更大的重量还是更快的泵送速度。 

您希望在设置中留出一些额外的容量，以便继续扩展程序。如果我们的项目需要 2,998 马力，那么我们不需要 3,000 马力的泵。我们需要 4,000 马力。您需要的容量要超出您的需求。 

该行业正变得越来越高效，钻机的水平钻进能力也比过去更强。这就引出了一个问题：这种效率将对未来的钻机数量产生什么影响。将钻机数量视为评估钻井市场实力的最终标准是否明智？

当然，如果你仅通过钻井数量来观察市场信号，特别是在过去的一两年里，你会发现数据的趋势已经不再像以前那样了。 

我们像其他人一样关注钻机数量，但与此同时，我们也在关注水平井数量。除非钻机效率和水平井长度相对稳定，否则你甚至无法从每口井的角度来查看水平井数量——该指标不具有可比性。因此，你必须将每年钻探的水平井数量或每年投入生产的水平井数量作为市场增长或萎缩的关键指标。与去年相比，一家公司今年钻探了多少水平井？他们预计的钻机数量是多少？如果钻机数量正在减少，你可能会更好地了解原因。 

如果我们每年钻探的水平井进尺数量相同且采用相同的压裂设计，并且我们的砂消耗量没有变化，我们的钻机数量可能仍会发生巨大变化，因为我们使用更高效的钻机钻探更长的水平井。

您作为勘探与生产公司与钻井承包商之间合作的性质是如何看待的？

虽然服务公司是下一个大事件的策划者，但为了让他们集思广益，我们必须很好地向他们传达我们的期望。他们必须知道我们想要实现什么。一般来说，这些人希望帮助我们实现目标，因为这就是价值所在。

每个运营商的目标都会有所不同，因此合作的性质同样要视具体情况而定。作为一个行业，我们必须善于沟通。钻机承包商必须了解我们的驱动因素，以便提供更多针对特定目的的解决方案。

您认为我们目前的商业模式是否能够最好地协调勘探与生产公司和钻井承包商之间的关系？如果不能，我们如何协调？

再次，这又回到了运营商和钻井承包商之间的个案基础。有些人会更喜欢使用日费率模式，而有些人会更喜欢基于绩效的合同。不过，很多时候，这是一个灰色地带，取决于运营商的需求和钻井承包商的需求。

我们的目标是让所有人在效率和收益方面保持一致。你可以采用混合日费率模式，保护我们和钻井承包商免受业绩下滑的影响，如果有收益，双方都能从中受益。绩效激励必须创造价值才能保持一致，而且这种价值必须是相互的。你需要双方都保持开放的心态，才能达成最佳协议。你不能把所有东西都放在一个盒子里。

我们现在看到，曾经被认为不可能的水平井变得越来越常见。如今钻井平台上的设备是否足以进一步增加水平井长度？

我认为是这样。我没看到钻井方面有很多挑战。实际上，完井方面会变得更加复杂，因为需要电缆铺设和钻探，因为到那里时你已经花了很多钱，如果遇到问题，情况会非常艰难。 

如果您甚至还没有下生产套管，并且在钻井过程中遇到问题，您可能会侧钻，只会损失一部分井眼。但是，如果我们在 4 英里长的水平段中 1 英里处遇到麻烦，我们已经在那里花掉了大部分资金，因此完井方面的风险会更高一些。在低压下钻井和清理井眼到这些深度还面临一些挑战。 

压裂后，我们发现油井的压力比以前低很多，尤其是在上部区域，而在我们所在的二叠纪地区，保持循环非常困难。我们试图以更高的速率泵入管道，因此会产生摩擦和冲击。

我想说，大多数挑战似乎都与较长的水平段完井有关。但你知道，我记得在 2013 年我们曾争论过我们是否可以完成 10,000 英尺的水平段而不是 7,500 英尺。不到一年后，整个项目都在 10,000 英尺的高度运行。无论面临什么挑战，我们总是能找到解决办法。 

您提到了有线传输的挑战。您认为我们在弥补技术差距方面取得的进展如何，以便能够缓解较长水平井的潜在运营问题？

我认为这只是让每个人都感到舒适的问题。我们已经完成了足够多的 4 英里水平井，因此我们不会仅仅因为操作问题而拒绝钻 4 英里水平井。我们可能意识到这样做会有点风险和挑战，但这不会让我们对这个项目感到不舒服。 

现在，总是存在这样的问题：每次你离开时，你还能获得相同的储备比率吗？当你离开时，你将不得不不断验证你是否仍在恢复相同的储备比率，以证明钻探这些井的效率。但到目前为止，我们还没有看到问题，所以我不明白为什么你不继续增加水平段长度。

鉴于我们如今在陆地钻井平台上看到的所有技术，您认为钻井平台的使用寿命有多长？您认为我们很快就会进入新建周期吗？ 

我真的不知道钻井平台的有效使用寿命是多长，因为我觉得它们一直在经历升级过程。我们与钻井平台承包商进行的任何对话都更多地围绕着对钻井平台进行某种修改或改造比建造新钻井平台来完成同样的事情更划算。这又回到了定义我们想要完成什么的问题。真的需要建造新钻井平台吗，还是我们可以通过改装或升级来实现这一目标？

这又回到我之前的问题，关于我们看待市场的方式的转变。这个行业似乎已经适应了新船建造周期不值得期待的新现实。

没错。另外，如果你看看我提到的其他因素，比如每年的横向进尺——如果这个数字保持不变，而每台钻机的每年进尺增加，那么也许一些老旧的钻机无论如何都会退役。这些钻机最终会老化。 

让我回到你之前关于留住人才的问题。招聘年轻专业人士和大学生似乎是当今行业面临的巨大挑战。我们是否尽最大努力让年轻人加入我们的行列？

对于这个行业来说，我们可能还没有尽到我们能做的一切。我认为问题的根源可能只是对我们这个行业的整体看法。在我们所在的米德兰，情况并非如此，而是全国各地的情况。年轻人可能看不到我们这个行业的未来，只是因为已经存在的东西。如果我们只能再使用石油五年，我为什么要成为一名石油工程师？这种说法相当普遍，而且可能具有破坏性。 

这是我们需要考虑的问题，因为它需要在大学招聘之前就解决。如果由于对我们行业的负面看法，这些孩子不主修石油工程怎么办？Diamondback 举办了大量的职业博览会和大学招聘会，但我们也需要更多地与年轻人接触，也许是初中或高中的年轻人。 

您如何解决这个问题？我们开展辅导计划、STEM 夏令营和机器人计划等活动。我认为我们对社区的年轻人产生了良好影响，帮助他们认识到这是一个不错的职业。然而，这些努力大多在米德兰。更广泛的行业应该在各地开展此类活动，这样我们才能对上大学的年轻人如何看待我们的行业产生累积效应。作为一个行业，我们可以做得更好。DC 

Hunter Landers is Senior VP of Completions at Diamondback Energy.

From an E&P perspective, what would you say are the biggest long-term challenges the drilling and completions industry faces today?

I think one of the biggest challenges is retaining talent. From the operator’s standpoint, that means retaining the same talent for each job – that would be the drillers and all the associated services that it takes to make it happen out there. We use all kinds of strategies to retain contractors, like performance incentives or compensation, and we’ve seen success using those strategies to keep the crews together, both on drilling and completions. 

For us, keeping the same people on location working together every day is like keeping a symphony orchestra together. There are 10 or 20 providers out there at any given time working together to make it all work as one, so it’s very important that everybody is used to working together and knows each other’s moves. That enables us to stay efficient, but keeping that high-level talent out there is always a challenge, and that’s what we’re still going through today.

For the rig contractors, I think the challenge is more around the reduction in activity due to increased efficiency. The North American land market has seen a pickup in efficiency in the past year or so. If we were planning to drill X amount of wells before, we’re still drilling the same number of wells, but we’re drilling them with fewer rigs – and that’s not unique to Diamondback. 

That is making for a little bit of an imbalance in supply and demand, and probably is making some rig rates go down, which makes it more challenging when the rig contractors have already gone through a pretty tough challenge with the COVID downturn.

This makes it hard on the market. It makes it hard on people to make business plans and execute on them when the goal posts keep moving. For the rig contractors, they have to keep finding ways to stay competitive and profitable.

So you have your network of preferred providers. Do you find that challenging to maintain in the current market?

We’re always checking the market more for value than for price. You can get some incredibly cheap prices for services at low value. But still, the name of the game right now is capital efficiency, which is what we’re all held to. Sometimes it’s hard to define how much value we’re getting for a given service.

I think that our group tries to put a lot of effort into defining the value, but as far as keeping them together, we acknowledge that sometimes we don’t have a lot of control. Even beyond price, say a crew quits from a particular company that we’re using on a certain rig, we can’t request them. We don’t have any control over that.

Like I said, we provide some performance incentives that keep people wanting to work on a Diamondback location from the contractor side. The incentive can’t be just to achieve a milestone – it has to be value based. Whatever you’re paying out, you have to capture some of that value to make it worthwhile. 

If you can strike that balance, that is a huge aid in retention.

Do you see capital discipline continuing for the near-term future?

The shareholder community is messaging a priority on returning free cash, capital efficiency and capital discipline, so that is what we are doing, as well.

Moreover, on a macro basis, there is excess supply in the world, which is not a signal to grow. We want to exercise the sort of discipline that allows us to weather the commodity price cycles. 

In order to develop the systems that push efficiencies further, you need to prioritize investing in innovation. From an operator standpoint, what role does Diamondback play in that investment?

Diamondback isn’t a huge spender on R&D for new things. We like to have a high level of certainty with systems. 

It goes back to capital efficiency and what’s asked of us from our shareholders. We’re going to be a fast follower if something’s working. We’ve proven through our acquisitions that we are a fast follower, and we’ll try to take advantage of an emerging technology as soon as we can. But we have a low risk tolerance for investments that we don’t know will pay off. We are not going to develop new things without some level of certainty.

That being said, there’s still fruit left on the tree. I think we can continue pushing rotary steerable development, and we can further optimize the drill bit as we continue making these long runs, but you have to look at those innovations on a case-by-case basis. If a company has had success with a particular bit technology and has been able to overcome previous limitations with that technology, then sure, we will try it. But if we try that bit, then the bit makes it 1,000 feet and we have to make a trip, then we’re not going to try that again, no big deal. 

But we’re not risk tolerant for some things that could really negatively impact your program. It’s a case-by-case basis, and everybody has a different tipping point and a different mentality on the value that could be brought by trying something new or different. We just don’t feel like there’s a huge advantage to us taking a lot of risk for that. 

What about automation? Does Diamondback see value in that?

Again, it comes back to value. Are those technologies going to be as dependable as what we have, or are they going to come at a cost? Is automation going to create value for us? If so, what does that look like? Industrywide, I think there are definitely people looking at more remote and automated processes, especially with drilling, and automation could come into play in the future. 

What equipment do you need to have on a rig that you’re contracting these days? 

I wouldn’t say it’s a case of must haves. Obviously, you’re going to have horsepower specs and weight specs, but that’s just marrying up your program with a rig. For us, the main things we’re looking for are getting quality people on quality crews, both on the rigs and the ancillary services. You want reliable equipment that’s not operating at the peak of its capacity – you want something that allows you to push the limits. You want equipment with enough capacity for growth in your program, whether that means longer laterals, more weight or faster pumping. 

You want some additional capacity left in your setup so you can keep growing the program. If we need 2,998-hp on a project, then we don’t want a 3,000-hp pump. We want 4,000 hp. You need the capacity to go further than what your needs are. 

The industry is getting more and more efficient, and getting more lateral feet out of a rig than in the past. That begs the question of what impact that efficiency will have on rig counts moving forward. Is it wise to look at rig count as a be-all, end-all for assessing the strength of the drilling market?

For sure, if you’re looking at the market signals through rig count alone, especially in the past year or two, the data is not trending like it used to. 

We watch the rig count just like everybody else, but at the same time, we’re looking at lateral feet. You can’t even look at lateral feet from a per-well basis unless your rig efficiency and lateral length are relatively static – that metric doesn’t scale. So you have to look at lateral feet drilled per year or lateral feet turned to production per year as a key metric of whether the market is growing or contracting. How many lateral feet did a company drill this year versus last year? What’s their projected rig count going to be? If the rig count is shrinking, you might have a better idea as to why. 

If we’re drilling the same amount of lateral footage year over year and have the same frac design, and our sand consumption isn’t changing, our rig count might still change drastically because we’re drilling longer laterals with more efficient rigs.

How do you view the nature of collaboration between yourself as an E&P and the rig contractors?

While the service companies are the ones who dream up the next big thing, in order for them to even brainstorm on that, we have to be good communicators to them on what our expectations are. They have to know what we’re trying to achieve. Generally, these guys want to help us achieve our goals, because that’s what provides value.

Every operator’s goals are going to be a little bit different, so the nature of collaboration is, again, going to be case-by-case. As an industry, we just have to be good communicators. The rig contractors have to understand what our drivers are so that they can provide more purpose-built solutions.

Do you think the commercial models we have right now offer the best alignment between E&Ps and drilling contractors? If not, how can we align?

Again, it goes back to the case-by-case basis between operators and drilling contractors. Some people will be better off using a dayrate model, and some people are going to prefer a performance-based contract. A lot of times, though, it’s a gray area depending on the operator’s needs and the drilling contractor’s needs.

The goal is to get everybody aligned on efficiency and upside. You could have a hybrid dayrate model that protects us and the drilling contractors from the downside of performance and benefits both of us if there’s an upside. The performance incentives have to create value for there to be alignment, and that value has to be mutual. You need open-mindedness on both sides in order to come to the best agreement. You can’t just put everything in a box.

We’re now seeing laterals that were once thought impossible becoming much more commonplace. Is the equipment on the drilling rigs today sufficient to push lateral lengths even further?

I think so. I don’t see a ton of challenges on the drilling side. It actually gets a bit more complex on the completion side with the wireline runs and drill-outs, just because you’ve spent so much money by the time you get there, it can be really tough if you have a problem. 

If you haven’t even run production casing yet and you run into an issue while drilling, you can sidetrack and just lose a portion of the wellbore. But if we have trouble 1 mile into a 4-mile lateral, we’ve already spent most of our money there, so it’s a little higher risk profile on the completion side. There are also a few more challenges with drill-outs and cleaning out wellbores to those depths at low pressures. 

After we frac, we see much lower pressures in the wells than we did before, especially in the upper zones, and in the Permian – where we’re based – it’s pretty challenging to keep circulation. We’re trying to pump down that pipe at much higher rates, so you have friction and impact.

I would say most of the challenges seem to be on the completion side with the longer laterals. But, you know, I remember arguing in 2013 about whether we could do 10,000-foot laterals instead of 7,500 feet. Less than a year later, the whole program was running at 10,000 feet. No matter the challenges, we tend to figure things out. 

You mentioned the challenges with wireline. How far do you think we are in bridging the gaps technology-wise so that we can mitigate the potential operational issues on longer laterals?

I think it’s just a matter of everybody getting comfortable. We’ve already done enough 4-mile laterals that we would not refuse to drill a 4-mile lateral just for operational issues. We might realize that there’s a little bit more risk and a little bit more challenge in it, but it’s nothing that makes us uncomfortable to do the project. 

Now, there’s always the question of, every time you step out, are you still getting the same reserve ratio? As you step out, you’re going to have to keep validating that you’re still recovering the same reserve ratio to justify the efficiency of drilling those wells. But we haven’t seen an issue to this point, so I don’t see why you wouldn’t keep pushing the lateral lengths.

With all the technology we’re seeing on a land rig today, how long would you say a rig’s useful life is? Do you think we’re going to come to a newbuild cycle any time soon? 

I don’t really know what a rig’s useful life is because I feel like they keep going through upgrade processes. Any conversations we’ve had with the rig contractors have been more around it being a better deal to do some sort of modification or revamp to a rig rather than build a new one to accomplish the same thing. It comes back to defining what we want to accomplish. Does it really require a newbuild rig, or can we accomplish that with a conversion or upgrade?

That’s going back to my earlier question about the shift in how we look at the market. It seems like this industry’s adapted to a new reality of newbuild cycles not being something to look forward to.

Exactly. Also, if you look at those other factors I mentioned like lateral footage per year – if that’s flat and the footage per year per rig is going up, maybe some of those older rigs are retiring themselves out anyway. Those rigs will get old eventually. 

Let me circle back to your earlier point about keeping people in the fold. The recruitment of young professionals and college students seems to be a huge challenge for the industry today. Are we doing as much as we can to bring young people into the fold?

For the industry, probably we haven’t done everything we could do. I think the root of the problem might be just the perception of our industry in general. It’s not so much the case in Midland, where we’re based, but just throughout the country. Young people might not see a future in our industry, just from things that have been put out there. Why would I want to go be a petroleum engineer when we’re only going to use oil for another five years? That’s a narrative that’s fairly widespread and probably damaging. 

This is something we need to think about, because it needs to be addressed earlier than just during college recruiting. What if, because of the negative perception of our industry, these kids don’t major in petroleum engineering? Diamondback does tons of career fairs and university recruiting, but we also need to engage more with young people, maybe in junior high or high school. 

How do you address that? Well, we do things like tutoring programs, STEM camps and robotics programs. I would like to think that we are having a good impact on the youth of the community, to help them realize that this is a good career to have. However, most of these efforts are in Midland. The wider industry should be doing those types of things all over the place, so that we can have a cumulative effect on how our industry is perceived by young people going to college. That’s something we could do better as an industry. DC