First oil

As this column mentioned last month, there continue to be signs that the global offshore sector is about to thrive in ways that we haven’t seen in three to four years. This feeling certainly was in evidence at the 2023 Offshore Technology Conference (OTC) that took place earlier this month in Houston. There was a quiet confidence that this editor has not seen since 2019. This mindset is also evident among onshore players, even if recent rig data don’t seem to back up that feeling. More about the onshore attitude further down in this column, but first, let’s examine the results from OTC.   

OTC was a success. As has been done for the last 55 years (save for 2020’s Covid-cancelled week), energy professionals from around the world gathered for four days at OTC, held at NRG Park in Houston. Gathering to discuss the offshore sector’s critical role in providing continued supplies of oil and gas, as well as the energy transition and the opportunities for critical minerals, hydrogen, and carbon capture and storage, among other topics, participants had the opportunity to connect with top industry leaders and showcase the latest innovations and technological advancements. 

What was noticeable on day one of OTC was the amount of enthusiasm and positivity, not only on the show floor but also in the technical sessions and other speaker presentations. What this editor also noticed was that attendance seemed to be up quite a bit. I remember telling a colleague that compared to 24,000 people at OTC 2022, there had to be at least 30,000 at NRG Center this year. Sure enough, when OTC put out its summation on the afternoon of the final day, May 4, they stated that more than 31,000 industry professionals had attended, a 30% gain over last year’s figure. Based on where the industry appears headed, one would think that 2024’s attendance will be still higher. 

“The Offshore Technology Conference has always attracted brilliant offshore energy professionals from around the world,” said OTC Board Chair Paul Jones, who is the principal at consulting firm Lockbridge Energy LLC. “As we look to meet global energy demands, this year’s conference reaffirmed that the future of our industry is stronger than ever.” 

New to the exhibit floor this year was OTC’s Energy Insights, a live studio sharing companies’ thoughts on emerging technologies, market trends, and the latest news, as well as engaging with conference attendees and audiences at home. The Energy Transition Pavilion also returned for its second year. It highlighted the many opportunities that the offshore industry offers for emission reductions through wind, hydrogen production, and carbon capture and storage. It also provided a dedicated space for collaboration around the offshore wind space in the new Offshore Wind Lounge. 

More than 1,300 companies from 104 countries showcased their technologies and equipment on the exhibition floor (Fig. 1), spanning more than 276,000 ft2. This year’s technical program was comprised of 49 sessions, including 25 executive dialogues and keynote speakers, 14 panels, five networking events and six countries that were showcased through the Around the World Series. Something to note is that nearly a quarter of the technical program covered the topics of offshore wind, renewables, carbon capture, and the energy transition.  

Fig. 1. More than 1,300 companies from 104 countries exhibited on the floor at OTC. Image: Kurt Abraham, World Oil.

This presence of these four topics was echoed on the exhibition floor. Whereas this editor thought that maybe 10% of the exhibits were geared to these topics, the proportion seemed to have grown to closer to 20%. One has to assume that this share of total floor space will only grow more in upcoming years. Meanwhile, the Baker Hughes offshore rig count in the Gulf of Mexico hit 22 on May 12 and 21 on May 19, up noticeably from 17 units a year ago. And as of the April 2023 Baker Hughes count, international offshore rigs outside the U.S. and Canada are up 19%, at 227.  

Onshore outlook remains stable. The onshore rig count, internationally, is also encouraging. April’s figure of 720 units was up 17% versus the same month a year ago. Thus, drilling contractors have something to shout about, outside the U.S. and Canada. Yet, given the recent, disappointing performance of the Baker Hughes rig count in onshore areas of the U.S. and Canada, one might expect their joy with the international numbers to turn to complete frustration in North America. After all, U.S. rig count has not only fallen from a 2023 high point of 775 on Jan. 13 to 720 on May 19, but it is now behind the count of the same week in 2022, when 728 units were tallied on May 20. Canada is no better, tallying just 85 rigs versus 88 units during the same week last year. What you might say, is optimistic about these figures? 

And yet, when this editor attended IADC’s Drilling Onshore Conference & Exhibition on May 18, on the west side of Houston, there again was a quiet confidence that all will be well onshore the U.S., despite the rig count numbers. One thing to keep in mind is that quite a few operators are still being “careful” about expanding drilling too quickly. Additionally, both operators and OFS companies are still adjusting to the higher costs for everything brought about by inflation in the U.S. Let us also not forget that technical innovation and progress continue to be made, thereby reducing the number of days needed to drill and thus allowing the industry to maintain activity with fewer rigs. 

“This time is a little different,” said Devon Energy Executive V.P. and COO Clay Gaspar, speaking for trends in operator thinking during a panel discussion. “We’re investing less of our cashflow immediately, back into drilling. But you see a lot more continuity of operations. The mindset of the operating company has translated well into the mindset of the service company. We need to be a more stable industry.” 

Speaking to the technical angle speeding up drilling, Eric Kolstad, Head of Drilling at BPX Energy, noted that “in wells using rig process automation, they (crews) drilled 39% faster. And there was a 60% reduction in connection time using ‘supervised automation’ versus manual operation.” However, a cautionary note was sounded by Aaron Felton, Chief of Operations Engineering at Ovintiv. “That rate of technical improvement is beginning to slow down, as it gets up against the natural limit, although it’s certainly not dead yet,” said Felton. 

So, many folks in the room took that last statement to mean that at some point, more rigs will have to be put to work, if there are to be meaningful additions to both U.S. and Canadian oil and gas output. Indeed, Luke Lemoine, Managing Director at investment bank Piper Sandler, said in an earlier session that he thinks the U.S. count could rise modestly in the back half of this year. For his part, Matthew Fitzsimmons, Senior Vice President and Head of Cost & Prices Research at analysis house Rystad Energy, said he believed that seven years of “feast” could materialize for the OFS sector. “The higher the tightness, and the shorter the lead times, the better the improvement for the service sector.” 

Asked by an audience member what the participants in the panel would consider their biggest environmental challenges, Quentin Dyson, Senior V.P. at Southwestern Energy, very quickly said, “On a daily basis, it’s spills. On a longer wavelength, it’s emissions.” Ovintiv’s Felton offered that “I’m really pleased that the industry has come together to attack emissions.” And Kolstad of BPX said his firm “does a lot of work on emissions. It’s what we do. But anybody who works in the Delaware (basin of the Permian) knows that [our biggest challenge] is a water management problem.” 

Another popular industry topic that an audience member asked the panel about was oilfield electrification. Felton remarked that “running rigs off of power lines is fantastic. But the Permian, while it has lots of power generating capability it also ahs a shortage of transmission lines.” Dyson also pointed out that “something to keep in mind is what are you burning to generate electricity? In Appalachia that’s coal. So, that’s not a solution to burn coal instead of diesel.” 

Dust-up over UK gas costs and supplies. Some of us weren’t surprised, when the Energy and Climate Intelligence Unit (ECIU), a non-profit organization in the UK, issued a claim, saying that households in the country could spend nearly £6,000 on imported gas over the next 12 years. But that one statement generated some sharp words from the country’s largest energy trade association, Offshore Energies UK (OEUK). The ECIU statement had been made as part of an assertion that the UK faces sharp rises in gas imports, and import costs, over the next decade, linked to declining production from the UK's North Sea. 

OEUK said that gas and oil production was, indeed, in long-term decline. However, the group added, the North Sea and other UK waters still contain enough gas and oil to support much of the nation’s needs during the three decades that it will take to reach net zero.  

Mike Tholen, OEUK’s director of sustainability, said, “Last year, UK consumers saw the bill for energy imports more than double, from £54 billion in 2021 to £117 billion in 2022. The Ukraine conflict also threatened Europe with energy shortages, but the UK’s North Sea supplies gave us energy security and the chance to support our European neighbours.” 

The UK, continued Tholen, “has 24 million homes heated by gas boilers, gets 42% of its power from gas-fired power stations, and has 32 million petrol and diesel vehicles. Overall, the UK gets about 76% of its energy just from oil and gas. We need to move to lower-carbon energy, but the scale of the change means it will take years. There is no simple choice between oil and gas and renewables. For the foreseeable future, we will need both.  

“That’s why we need to keep investing in exploring and developing new and existing fields in our own waters,” added Tholen. “We know that oil and gas production from UK waters will decline, but if we continue to explore responsibly, then we can slow that decline right down, helping give the UK the energy security it needs while it builds the low-carbon energy systems of the future.” 

IN THIS ISSUE 

Special focus: Well Completion Technology. In this month’s lead theme, an author from Packers Plus Energy Services says that cemented ball-drop sleeves enable operators to reduce cost and operational risk, while helping achieve optimal pumping rates in extended-reach laterals. Meanwhile, an author from EV explains that combining video with ultrasound yields complete and precise measurements that allow calculations of proppant uniformity with complete integrity and validity of acquired data. In addition, authors from SEF Energy, Downing and Blue Ox Resources say that by identifying numerous barriers obstructing 24/7 reservoir fracturing, a new automated system was developed that has led to gains in operational efficiency, consistency and safety. Finally, several Weatherford authors discuss enhancing stimulation efficiency in a fractured open-hole carbonate reservoir using advanced modelling techniques. 

EOR/IOR: Advanced shale oil EOR methods for the DJ basin.  Authors from Shale Ingenuity and The Computer Modeling group describe how two innovative shale oil EOR processes offer greater simplicity, and lower capital expenditure and operating costs, compared to natural gas or CO2 EOR. Advanced compositional reservoir simulation modeling is used during operation to ensure maximum oil recovery.  

Robotics & A.I. Technology. We have two excellent features in this category. In the first, authors from Canrig explain how automation is a key component to reducing the carbon footprint of operations and increasing drilling efficiency. Using A.I.-driven power management systems optimizes power usage while minimizing fuel consumption and carbon emissions. In the second feature, the Co-Founder and Chief Product Officer for Plainsight describes how Vision AI solutions for the upstream industry combine the latest A.I., 5G, and Edge technologies for rapid visual data curation, proactive remote monitoring, continuous tracking, and automated alerting for solutions scaled across E&P sites and facilities.  

About the Authors

Kurt Abraham

World Oil

Kurt Abraham kurt.abraham@worldoil.com