Going for the gold in training, reliability
More complex than before, industry needs standardization to get through increased activity
By Linda Hsieh, managing editor
David Payne is Chevron’s vice president of drilling and completions.
From an operator’s perspective, what do you see as the most critical challenge confronting your operations today?
It’s people. We have real challenges making sure we have the right competencies in place to deliver, both for us as an operator and for our business partners, the drilling contractors. In every position there is a gap – qualified roughnecks, qualified MWD operators, qualified mud engineers, qualified drilling engineers, qualified drilling superintendents, qualified rig supervisors, you name it. Getting enough people is absolutely job No. 1.
Are we having trouble recruiting people into the industry?
No, we don’t have any trouble recruiting people – we just can’t train them fast enough to cover the gaps because of the increased workload and retirements.
People also have other career options. I’ve lost drill site managers (DSMs) who typically would’ve never expected to be a drilling superintendent; they get hired away as drilling superintendents by operators who can’t close their personnel gap.
I can’t just hire somebody from the street to be a DSM. We have no problem finding bodies. In fact, we have no problem finding highly motivated, smart people who want to work, but they just don’t have the knowledge and experience. You can’t take a 20-year engineer from the auto industry and plug-and-play him into the drilling industry as a 20-year engineer.
Industry seems to be doing a lot of accelerated training. Is that helping?
Yes, but there’s a limit to how much you can do. I think there are some opportunities at the rig level and with IADC to do things more consistently and collaboratively across IADC’s membership that would help with rig crew competency. We’d like to see IADC take its training standards to a whole new level; not just putting out competency expectations for different job families, which are available today, but actually talk about how that training happens, how people achieve the competencies and how you verify competency.
We’ve suggested having a tracking system that’s usable across all of IADC’s drilling contractor members. If somebody leaves one contractor to go to another, they take their competency record with them. When they apply for a job, there’s no question about what competencies they’ve developed because there’s a record in a global tracking system. This way you can have confidence that if they say they have a certain competency, they actually have it.
How does field experience fit in to the training and competency development?
We would definitely like to see our engineers spend more time in the field. They need to spend time in the field to gain enough competence to be in charge at some level on location. If we don’t get them to that point before we bring them into the office, they won’t be as effective. This is a limitation for the industry. If we hire an engineer straight out of university, it’s two years until we see him in town actually doing engineering work.
You can’t accelerate experience. There are certain things you can do to accelerate their learning, but it only goes so far.
There are ways to leverage experience though. We just opened a remote operations center in Houston that allows us to do that. Twenty years of experience can come in multiple packages. Having one guy with 20 years of experience and 20 guys with one year of experience are not the same thing. The remote operations center allows us to leverage the one 20-year guy to help folks with less experience make better decisions.
In one of your public speaking engagements last year, I heard you advocate the idea of engineering for simplicity. How is that approach reflected in your drilling and completion operations?
Standardization is what will help us to get through this increase in activity. Simplifying can be defined not only as making things simple but making complex systems repeatable. When you have to redesign a complex system every time you use it, you’re increasing its complexity. You can simplify that system by making it repeatable.
There are different ways to simplify. We’ve worked hard to do as much standardization as we can in the deepwater Gulf of Mexico, where we drill some of the most complex wells in the world. We’ve got a fairly significant level of standardization in how we do things and how we put wells together because that allows us to not have to repeat the engineering process for every piece of it.
Is that only in the drilling part of it?
Drilling and completions. Sometimes we get caught up in this idea that every well is different. Every well doesn’t have to be different; it’s only different if we insist it’s different. There are ways to make things similar. The more you can standardize how you do drilling, how you do completions and how you do planning, the more repeatable it is and the less complex and more dependable the system becomes.
Are you taking lessons learned from your shale wells as far as making them repeatable?
Factory drilling is all the rage now, but we’ve been doing factory drilling for more than 30 years in Thailand. We drove standardization to a very high level in Thailand. If you took an engineer to Thailand today and ask her to design for each of the four or five fields we have there, she would never design one single well type. But because of the value of standardization, we are doing exactly that – using a single well type for all those fields. It’s repeatable, and that’s why we can drill five-day wells in Thailand.
We’re also doing this in the Piceance in Colorado, where we’re drilling 22-well pads and knocking out wells in 3.5 days, over and over and over. We’re heading that way in the Wolfcamp in West Texas.
At the same time that you’re trying to engineer for simplicity, wells are without a doubt becoming increasingly complex. How is this complexity affecting the way you manage your wells operations?
The industry is obviously more complex than it used to be. We’re expecting more reservoir information while we’re producing to allow for better overall reservoir management. That creates some complexity, especially around completions. We have to make sure we’re applying technology where it belongs, not just applying technology because we can.
There are times when it can be really simple. For example, we could’ve drilled our wells in the Piceance with rotary steerables, but we didn’t because it didn’t make any sense. By simplifying the system to the minimum, we’re able to be more effective and more reliable.
Are there technical limitations holding back the goals you have for your drilling programs?
The biggest limitation is in the economics. We haven’t found anything we can’t drill; it’s just a matter of how much you want to spend. From a technical standpoint, the technologies are being developed as we recognize the challenges. Sometimes we’ll see a challenge before we have the technology, but so far we haven’t run into anything where we haven’t been able to come up with a solution.
I think the next big challenge will be the Arctic and figuring out if we can find a solution that’s affordable. As you move out into deepwater in the Arctic and go further north, the weather window is extremely limited. If you can’t drill year-round, what are you going to do with the equipment when you’re not drilling? That comes with enormous costs. There is no doubt we can drill the wells, and we can do it safely. But can we do it within an economic window?
On the land side, do you see value in some of the low-cost versions of downhole technologies that target onshore applications, like rotary steerables?
Absolutely. It’s horses for courses. Low-cost rotary steerables can be the right answer for a lot of the shale gas business. Actually, in a lot of cases, low-cost rotary steerables can be the right answer offshore as well. Not every offshore well has to be expensive.
Most of the time you only hear people talk about how expensive offshore wells are.
In deepwater, it’s expensive. But there are certain provinces where you can significantly lower the costs of your wells without increasing risk if you can get out of the box and think a little differently. We’ve drilled with surface BOPs in east Kalimantan where weather conditions were benign, and we dropped the well costs dramatically.
You mentioned earlier that economics is a limitation when it comes to investing in technology for your operations. How do you support technology innovation in your organization against the need to cut costs and manage risk?
We have an expectation in our organization that we’re going to be the clear leader in the industry, so we set expectations around performance improvement and risk management. To deliver performance improvement and be the best in the industry, we have to employ the correct technology.
Technology development has its costs. We budget a certain amount of money every year that we take away from the business units to invest in technology. At the same time, we’re not the only ones developing technology. When we have this expectation that we’re going to be ahead of the rest of the industry, we can’t get ahead of the rest of the industry if we’re not a leader in technology implementation. We have to be willing to work with business partners – big service companies who have big technology budgets and some small companies that can often be quite innovative.
As an industry, are we investing enough in new technology?
I think so, but one area that concerns me is whether there is enough basic research being done. And the question is, where does basic research belong? Is it an industry responsibility or a government responsibility?
We have an alliance with Los Alamos National Labs that allows us to tap into the basic research they’ve done that’s been financed by the government. We can then invest additional funds to take that research and find ways to apply it practically in our business. It’s a win-win because we can take publicly funded research and use the results to improve energy security in the US.
Earlier when you mentioned working with your business partners on technology development, did you mean getting into the development process earlier?
I meant being involved in how they prioritize what technology they develop and partnering to allow them areas to test new technologies. We can be more engaged and not just wait until they show up with a finished product. If we get in the game early, we have an opportunity to arrive at solutions that are better for both parties.
Are there any specific areas of technology where you see the need for development the most?
Shale completions and resolving the challenges around footprint and water use are areas of some urgency. There are some places where we clearly need to be more collaborative on not only water usage but water disposal. There are some headwinds that we’re having to fight to be able to operate, and the best thing we can do is to take down the sail that’s blocking our ability to move forward.
Do you think the industry is having to fend off overly stringent regulations around the development of these shale wells?
Actually, my opinion is there aren’t enough regulations. We don’t have enough appropriate regulations in place, and that’s creating part of the problem. Not every operator is operating at what we would consider to be an acceptable standard to the neighborhood in which they operate. There’s an opportunity for industry to collaborate with government to establish appropriate regulations to ensure that we’re not all put out of business by those who choose not to operate responsibly.
Looking to equipment reliability, how are vendors meeting your expectations?
Because of the cost of doing business in deepwater, what may have been an acceptable level of reliability for onshore or other inexpensive wells is no longer acceptable. A company may be proud of its 98% uptime, but if we have five services on the rig and every product service line is at 98% reliability, that means they are each having 2% downtime, and not all at the same time. If you add it up for five product service lines, we have 10% downtime before we even get started, and that doesn’t include the rig contractor.
We have started conversations with our business partners about the fact that 98% is not good enough and 99% is not good enough. What we need is 99.9% reliability. We need tools to work all the time, or we need to build in redundancies so the rig is making progress as much as possible.
What have been their responses to that?
Very positive. They’re up for the challenge. In some cases, we’ve already made some significant progress. There’s plenty of work to be done, but I think they recognize the need.
The flip side of that is, we have to be willing to pay for the changed expectation. You can’t say, same price as you gave me last week but instead of 98% reliability, I want 99.9%. It’s not a 1.9% improvement; it’s a significant step-change to go from 98% reliability to 99.9%. That comes with a cost, but when it’s worth the cost, we have to be willing to pay. We have to talk about how to make it worth their while to get to 99.9%.
Are there certain pieces of equipment or technology where reliability challenges loom the largest?
It’s not just top drives and BOPs, it’s all rig equipment in the critical path. Particularly offshore, pipe-handling equipment, top drives, etc, are all run by computers, and there’s a lot of software involved. It’s all remote-controlled and very complex. There are a lot of interface issues. It’s not dependable enough, and it doesn’t operate fast enough.
Here we have an opportunity to change the way we run our business, too. Currently, the original equipment manufacturers (OEMs) manufacture and deliver the equipment to the rig contractor. Once the rig contractor takes ownership, the OEM no longer sees it until something is seriously wrong. Maintenance, upkeep and small downtime events are all invisible to the OEM; they don’t see it at all. There’s no feedback loop that drives them to truly improve. They’re trying to do new things and they’re talking to people, but it’s not a data-driven process.
We’re starting to see progress toward creating that feedback loop, and the operator needs to be in that loop. What is good business for the drilling contractor may not be good business for the operator. We have to create financial incentives for them to change the way they’re doing business and change their relationship with the equipment manufacturer. We all need to be under the tent working together, but historically we have not been.
But it’s up to the operator to bring everyone into that tent, right?
That’s right. Technology development and change follow the money trail, and that starts with operators. That’s why we have to provide incentives for not only contractors but equipment manufacturers further down the line to change their business model in a way that’s going to improve everyone’s performance. Reliability really matters.
To me, reliability is more important than technology development. Reliability is good business, particularly in deepwater.
How does automation fit into your vision for the future of drilling?
It has to be part of our business in the future, and we’re already having conversations about how to get there. Absolutely automated drilling with feedback loops carrying information from downhole will take the automatic driller concept to a whole new level. Again, there’s limited incentive for drilling contractors to implement automated drilling due to the financial risks of adding complexity to the system. We’ll have to create an incentive contractually.
And a lot of people forget about automated well servicing. If you can make that work, it would be good business with an opportunity for a step-change in safety.
I like how the interview covered all sorts of drilling concerns, and I can’t stress enough how improved technologies and streamlining remote operations are important to our work…but I’ve always been concerned about disaster avoidance and safety. Wish he spoke to that aspect. This is one I saw today on a blog: http://smrt.io/zfMWlI.