March 2024

Digital’s influence on drilling and production keeps growing

The digital transformation continues to impact various drilling and production functions in many positive ways, and thus its usage and spending for it will expand further, says a veteran upstream executive.

During the Baker Hughes Annual Meeting in Florence, Italy, on Jan. 28-30, World Oil Editor-in-Chief Kurt Abraham had the opportunity to visit with the company’s Chief Digital Officer for Oilfield Services & Equipment (OFSE), James “Jim” Brady. In this wide-ranging conversation, Mr. Brady explained how digitization has yielded numerous operational efficiencies and improved the performance of his company’s solutions. What follows is the full discussion on a number of digital topics. Content has been edited for length and clarity. 

World Oil (WO): Before we delve into specific digital topics, please give our readers some background on your industry experience and duties and responsibilities at Baker Hughes. 

Jim Brady (JB): I joined Baker Hughes about 18 months ago, and I have 35 years in the industry. As Chief Digital Officer for OFSE, I manage a portfolio that is a mix of internal service delivery and external, customer-facing products, solutions, and service offerings. 

When I look at the customer-facing offerings that we’ve developed, I am incredibly proud. During last year’s Annual Meeting, Baker Hughes shared a vision to leverage our digital offering to improve customer outcomes. 

One year later, I can tell you that Baker Hughes delivered digital results across the upstream value chain. 

WO: What are the main product lines that you are involved in?  

JB: Digital sits across the Baker Hughes portfolio. In OFSE, that means ensuring our digital offerings add value to our energy customers – particularly around traditional upstream products and services – because digital is the confluence of hardware, software, and IT infrastructure.  

So, when I say we “digitally drill,” I mean that that our downhole assembly is designed to be steered. That's really where it starts. If you look at our Lucida™ advanced rotary steerable service offerings, you will find a service that’s digitally enabled. In artificial lift, we have remotely controllable variable speed drives. We build our digital offerings up – from the hardware to delivery to the use of that hardware, to the customer experience. 

In some cases, we utilize a combination of our domain expertise alongside the expertise of a third-party company. We have a strategic collaboration with Corva, which is a Houston-based company that provides software as a service. Fig. 1. Corva’s digital software is available in the cloud and is currently servicing approximately 250 rigs, mostly in North America. Our customers can use that software to monitor drilling performance, which Baker Hughes enables with technology such as our i-Trak automated drilling services (Fig. 2), so the customer can have a seamless digital experience drilling the well. This collaboration ultimately makes sense because one of Baker Hughes’s core strengths is drilling (Fig. 3.).  

Fig. 1. Baker Hughes has a strategic collaboration with Corva, a Houston-based software as a service company, to provide digital software that is used on about 255 rigs, mostly in North America, to monitor drilling performance. Image: Baker Hughes.
Fig. 2. i-Trak™ is a suite of drilling automation services that improve safety, speed and economics of drilling operations. Image: Baker Hughes.
Fig. 3. Leucipa™ is a cloud-based automated field production software solution that helps operators eliminate waste and reduce carbon emissions. Image: Baker Hughes.

Another important strategic digital collaboration for Baker Hughes is with CMG. CMG provides reservoir software to work with our JewelSuite™ subsurface modeling applications. When combined with other core Baker Hughes strengths we gain an entry into new energies and sustainability. For example, you can look at the CCUS problem to the right of the wellhead and couple it with digital offerings we have on the other side of the wellhead and you now have end-to-end digital solutions. 

In production, another core strength of Baker Hughes, we see the same thing. Baker Hughes is the market-leading electrical submersible pumps (ESP) systems provider for wells in mature conventional fields, unconventional plays, thermal recovery operations, and deepwater/subsea projects. So, delivering value through digital production makes sense. In this space, we built on the previous monitoring and control offerings around our ESPs—essentially well-based optimization—and released our Leucipa automated field production solution (Fig. 4), which extends monitoring and optimization out to the field level. Leucipa uses advanced analytics, but it's not things like “how does my ESP last longer?” That's an easy one.  

Fig. 4. JewelSuite™ is a portfolio of applications for highly differentiated workflows, based on one technology for maximum versatility. Image: Baker Hughes.

We’re talking about things like “what's the recommendation of ESP life versus lifted volumes?” At the field level, it’s “what are the optimum settings to help lengthen life for a suite of downhole equipment, plus honoring that delivery contract?” With these advanced analytics, we can evaluate, say a thousand wells, and model them based on incoming data.  This allows the operator to make more informed decisions at field level, all built out of Baker Hughes’s ESP expertise. 

The same is true of chemicals. Baker Hughes is a large provider of upstream chemicals, so it makes sense that we have a digital offering within Leucipa that helps people understand, for instance, the basics of tank level monitoring to get a good sense of how their chemicals are working throughout the field. At the end of the day, the whole thing really builds out of this core competency.  

WO: When you talk about chemicals, one assumes this also includes Baker Hughes being able to distribute the chemicals in a more efficient manner and cut down on the waste. 

JB: Yes. A lot of it is digital tech monitoring. You don't need to send people out to look at these things. You bring that data in and display it. This helps us understand the chemical consumption relative to each well – and this, of course, leads to better forecasting within the supply chain.  

WO: So, a nagging question is how far can we go with digitalization and improving efficiencies, until we get to the point where we can't do anymore?  

JB: That's a good question. I think there is a limit -- but there are a lot of things that constrain that limitation. For example, I was talking to a North American operator about a particular field. We were talking about 4,000 wells in a field most of us would know. He's talking about that trade-off—do you continue to just drill it all, do you decrease your spacing, or do you start looking at ways to get maybe 1% or 2% out of the existing wells? The first question I asked was “Are your wells connected?” And you know, they weren't bad – probably only 60% to 70% of the wells were connected. So, you say, “you've got opportunity there.” And these are limits that we put on ourselves when designing these wells. That particular field was drilled out at a time when a little bit of up-front design could have helped. So, these are things that we do to ourselves.  

I like to think of digital as an extender of human capital. We deal with more complex reserves. We deal with incremental recovery. The production engineer of the past did a lot of that in his brain or on an Excel sheet. Now, we're providing digital solutions that allow that engineer to do it better. I think that will continue to enhance their ability to do things. But I just don't see the convergence down to zero people.   

WO: I can't either. Because at the end of the day, it's got to go back to somebody. Someone has to be able to exercise control.  

JB: There's control, but there's creativity, too. There is a lot of creativity and innovation in our industry right now. If you just get into this control system approach, how do you do new things?  

WO: What else can you tell me about what Baker Hughes is doing in the digital sphere over the next year or two?                                                               

JB: We’ve invested a lot in digital—it's public and in the investors' reports. The increase of our technology spend on digital is faster than the other parts of technology spend. We see it as an opportunity that leads to high growth. Our digital revenues are already surpassing the rate of our core offerings – not in terms of absolutes, but in terms of rate increase. So, we see it as a growth area.  

Regarding other offerings, we have synergies in things like CCUS, which requires a lot of heavy equipment for capture, transport, and compression! There's no doubt that CCUS is largely about capital investments and infrastructure. But there's also digital. There is a strong element of that because, in the end, you need to use digital to size your infrastructure, not unlike we would do with something like an FPSO or takeaway capability. You end up sizing this stuff and doing monitoring and a type of balancing. That's all digital.  

WO: How receptive are the operators to all the progress that's being made and to some specific innovations? Are they all in for everything, or do they express a mindset that they would like to not go so fast?     

JB: I think everyone agrees that it’s a journey. If you look back 20 years, being out on rigs and looking at mud windows, you just kind of go “really? Why do we kick anymore?” Because it's right there. But it takes some time. I believe we're safer offshore now. And I believe digital has had a lot to do with it, including things that directly impact safety. I think there's a faster adoption.  

Recently, our i-Trak technology delivered on the world’s first autonomously drilled well path in a reservoir with a customer in the North Sea. This is a significant achievement! And you can say, “why is it taking so long?” But at the end of the day, digital drilling requires a lot of customer trust, a company to get out there and say, “we're going to trust this. We're going to do the internal management, and we’re going to look at it.” I think a lot of that trust factor is what's adopted, because at the end of the day, there's a human being that's accountable.    

Digital has to inspire trust in people. And many think that takes time. It's also a matter of capital spend. What's the level of investment that you're going to make in it? Are you going to put a lot of sensors on a rod pump?  You're probably not going to do that. I think this tempers a lot of digital investments – they have to make financial sense. A lot of discussion with operators is around that concern. “How's this tool going to affect my lift costs? What am I really going to be able to do with it?”  

WO: Do you see a potential wave of secondary recovery coming into some of the existing shale wells, and a role for digital to play in that? 

JB: It must start with which ones have been instrumented. I think an opportunity exists there already.  We see operators investing in ESPs on new, free-flowing wells because they know they will need them given the decline. Plus, it's more economical to put them in at the start. Many of those are instrumented. For old wells that were free flowing but are now very low production, it’s not clear someone will invest in the instrumentation for monitoring. It’s a cost–value tradeoff. But I think we see that already, if you look at the decline of the average well in the Permian, I think the operators know that there is something more to do. A lot of them seem to be very keen on how digital will play a part so that we can avoid the decline. Can we take these new wells that we're drilling and effectively get the same recoveries that we did with the initial ones? They get that.   

WO: What about the role of A.I.?  

JB: Everybody's always asking me about AI and things associated with it. I get it. I think it just carries on with what we've been talking about. AI is a technology that helps extend your ability to work through scenarios and data. So, it's a human extender. I definitely view it that way. You need to understand the confidence that the AI-based system is giving you. I do see the promise of that extension.  

WO: In other words, it's still going to need some human supervision.  

JB: Yes. Supervision. But it's almost like having a new engineer come in. You're not going to let that engineer monitor or watch that well or drill that well until you're confident that engineer’s ability to do it. I don’t think it’s that much different for an AI system. You’re going to build up your trust. The concern may be ESP recommendations for example, why is it recommending that?  It then becomes less a topic of magic and more of an efficiency play. You do not have to have somebody go look at this data for 12 hours and figure it out. I'm confident that the system is coming up with a final answer.    

(Interviewee bio) 

As Chief Digital Officer of Baker Hughes’s Oilfield Services and Equipment (OFSE) business segment, JAMES (JIM) BRADY directs the development and execution of the organization’s digital strategy, leveraging 35 years of oil and gas industry experience. An electrical engineer by trade, he started and spent 32 years of his career at Schlumberger, working his way up from a wireline systems engineer to vice president of digital operations. Mr. Brady also held executive roles in hardware, software and IT while at Schlumberger. Prior to joining Baker Hughes, he was CTO - Energy at EPAM, where he directed technology and solution strategy for the Energy Software and Services division, working with companies on their own digital transformations. Prior to EPAM, he was CIO at Katerra, a Silicon Valley construction technology startup. Mr. Brady earned his bachelor’s degrees in electrical engineering and economics at the University of California and holds a master’s degree in electrical engineering from the University of Texas with a research specialty in Computer Architecture and Computer Vision.  

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