In September, operators from across the Middle East and around the world gathered in Muscat for the fourth edition of the Society of Petroleum Engineers’ International Hydraulic Fracturing Technology Conference (IHFTC). The meeting brought together engineers, executives, and government officials to discuss how they are working to unlock unconventional
resources in their respective countries.
Much of the discussion centered on improving cost structures, scaling strategies, and technology needs.
Middle East operators noted at the conference that while they are benefiting from technologies and concepts proven in the US and elsewhere, their engineering teams must still adapt those lessons to local geologies and realities. In addition to appraisal work and data gathering, contracting frameworks have been adapted and new supply chains are being built to support the bigger footprints and consumption of materials that come with unconventional operations.
The conference also came at a moment when the Middle East is pushing harder than ever
to commercialize unconventional resources
as domestic needs increase along with calls to grow exports.
Rystad Energy reported in October that natural gas accounts for about 72% of the Middle East’s current electricity generation, a share that
is expected to keep rising. The Norwegian consultancy also found that the region now ranks as the world’s second-largest gas producer, behind only North America. Since 2020, Middle East gas output has grown roughly 15%, with a further 30% increase expected by 2030.
This means that despite all the challenges, the region’s national oil companies (NOCs), including Saudi Aramco, ADNOC, and Petroleum Development Oman (PDO), have strong national security and economic incentives to stay on track.
Saudi Arabia is underway with a $100-billion tight gas development in the Jafurah field that is the core of a plan to raise domestic gas supply by 40% and free up oil used for power generation. The UAE aims to reduce its reliance on imported gas and achieve self-sufficiency. Oman is pursuing a more-intensive hydraulic fracturing program to offset production declines in conventional fields and support liquefied natural gas (LNG) exports, all while meeting domestic gas that is rising at a clip of 9% annually.
A New Mindset
While each country is pursuing its own energy strategy, the region’s operators largely agreed that the mindset that defined conventional development must evolve to meet the demands of unconventionals. Long accustomed to drilling wells with slow decline rates and world-class rock quality, they are now learning to manage wells that decline more rapidly and require faster-paced drilling and completion programs to sustain production growth.
Oscar Bustos, an advisor for unconventionals at ADNOC, was among those who spoke about what this change means and said a key part
of the unconventional mindset is “accepting mistakes and being transparent about the mistakes.” He added, “There’s a lot of unknowns in unconventionals, and we may fail, but we want to learn from it.”
This need for a degree of trial and error was echoed by another industry colleague, who said the unconventional mindset also requires a tolerance for simply drilling more wells. Jose Rueda, technical support unit supervisor for unconventional resources at Aramco, said the company developed a relatively clear picture of what one appraisal
area might ultimately deliver only after drilling and completing about 50 wells.
“So, it took a few years, and that’s important,” he said. “It’s not going to happen in the first few wells. It took a significant number of wells and a lot of different techniques, different trials.”
Speakers at IHFTC also said new thinking across the Middle East is helping producers tackle unconventional challenges on their own term
Among them was Sherif Foda, CEO of National Energy Services Reunited (NESR), which is helping Aramco develop the Jafurah field.
He called the notion that the region lacks the capacity to build the required infrastructure “a myth.”
Foda noted that it has, however, required a different model from the one used in North America, which benefited from an extensive
infrastructure before the shale boom and a diverse mix of small, medium, and large operators that supported a large ecosystem of service providers and contractors. While the Middle East may not have such diversity, he said the region has still managed to “crack the code” on sustaining an unconventional ecosystem of its own.
“The type of contracting that you see in the US, you cannot do here, which is per-pad and bidding,” he said. “Here, the way the operator must do it is with long-term contracts, and then you can invest. For example, if it’s a 5-year contract, you know you are going to have that [revenue stream] for 5 years.”
Foda explained that this long-term model enables companies like NESR to invest locally in
capital-intensive projects such as sand mining and other critical infrastructure. One result, he added, is that hydraulic fracturing costs in the Middle East have fallen by about 80% compared with a decade ago.
Managing Water Scarcity and Sand Abundance
Even as Middle East operators expand the use of hydraulic fracturing, they still face hurdles that are to varying degrees defining the pace and direction of their unconventional programs.
One problem reported by both ADNOC and PDO is that some new gas prospects that have been tapped with hydraulic fracturing have been found to contain high levels of contaminants such as hydrogen sulfide (H2S), prompting a search for technologies that can safely and economically handle sour gas production.
But a more common issue all Middle East operators must contend with is the strain that large-scale fracturing places on the region’s limited water resources. ADNOC’s answer to
trimming its use of fresh water hinges on drawing from brackish aquifers and water reuse from industrial sources.
In Saudi Arabia, where each horizontal well requires between 200,000 and 500,000 bbl of water, Aramco and NESR are piloting new recycling methods. One project aims to treat and remove the salts from produced water while recovering trace minerals such as lithium and bromine that in turn could be sold to offset treatment costs.
Meanwhile, some in the region are continuing to import sand from as far away as Australia while they test their own abundant dune sands as a potential low-cost proppant. Although the US experience showed that local sands often perform effectively, Middle Eastern NOCs nonetheless have had to conduct their own trials and laboratory testing to confirm the suitability of theirs.
ADNOC and PDO signaled that local sand adoption is imminent within their operations, while it was shared that Aramco and NESR are moving to test the use of wet sand from local sources in Saudi fracturing operations, another
idea first proven out in the US that can further lower logistics costs and environmental impact.
Redha Kelkouli, a vice president of Middle East and North Africa business for SLB, said that the sand switch has been easier said than done for the region. “We have had some very variable level of successes across the region. But definitely, this is high in our agenda, and we will work with the local operatorship as well as the different stakeholders to make this a reality,” he said.
Also on the agenda in the Middle East is the potential adoption of lightweight proppants
or chemical applications designed to improve proppant distribution and fracture conductivity. The topic has drawn growing interest from unconventional operators globally following ExxonMobil’s reported success in the Permian Basin with its proprietary lightweight proppant.
PDO: Building a Fracturing Culture in Low-Pressure Reservoirs
As the host of IHFTC, PDO has considered hydraulic fracturing to be a cornerstone of its conventional development program for much of the past 40 years. Most of that work targeted
shallow, high-temperature formations and involved smaller-scale fracturing operations.
Today, however, the company is stepping toward deeper, tighter, and hotter reservoirs that require more fracturing power. This transition has also taken PDO from stimulating mainly vertical wells to an expanding number of deviated and horizontal completions, tapping stratigraphic accumulations once considered uneconomic.
But another key part of the shift involves Oman’s low-pressure reservoirs where hydraulic fracturing has not traditionally been central to field development. Most wells were simply perforated and put on artificial lift, representing a low-cost development strategy.
At the conference, these formations were described as having medium to good permeability in the low single-digit millidarcy range, or orders of magnitude higher than the microdarcy tight
gas targets found elsewhere in PDO’s portfolio. Yet many of these wells are also holding medium to heavy crude, meaning that even with decent permeability, fluid mobility remains a challenge.
And as PDO has worked through many of the best-quality parts of these low-pressure reservoirs, it is looking at the harder-to-produce sections where hydraulic fracturing operations will be needed.
Ahmed Al Jahdhami, a senior petroleum engineer and principal frac engineer for PDO’s southern oilfields, said the project has shifted mindsets from viewing fracturing as an exception to seeing it as an increasingly essential tool. He told attendees from the podium that a low-pressure field discovered in 2016 proved to be one of the turning points.
Of the six initial wells drilled, only two were hydraulically fractured, but those produced about 150% more than the nonfractured wells. “Now, the whole field is being developed with frac operations, and so this is unlocking the potential that’s there,” he said.
In another case, a well that had been shut in for 3 years after suffering seemingly irreparable skin damage during its drilling was given one last chance. “Let’s give it a shot—let’s frac it,”
Al Jahdhami recalled of the decision. The well, which initially peaked at about 130 B/D, produced more than 1,500 B/D post-stimulation.
“That opens up eyes immediately,” he said. “This is what’s happening more and more as we go along.”
PDO hydraulically fractured a horizontal well last year in a low-pressure field that produced about 70% more than nearby nonfractured wells. By the end of this year or next, the company plans to return to the field and apply its lessons to a new well that is hoped to deliver up to four times more output than the first.
The success of such projects has not come without challenges. PDO has had to learn how to avoid fracturing into water-bearing zones, which can dramatically increase water cuts and spoil a new well’s economics. But the company has also found that hydraulic fracturing can be used to
improve waterflood performance. Al Jahdhami said about 10% of the wells PDO fractures are water injectors, a figure that rises to roughly 30% in its southern fields.
As with many emerging fracturing programs, PDO’s attention is on reducing costs as operations expand. The company has taken an aggressive approach that has lowered average well costs from about $1 million in 2019 to roughly $300,000 today. The 70% reduction marks significant progress, but PDO is pushing further.
The goal, Al Jahdhami said, is to find a way to stimulate wells for as little as $50,000 each. He pointed out that these wells involve fracturing stages numbering in the low single digits vs. the dozens used in modern US horizontal wells.
“It’s a really ambitious goal, but we’ve seen precedents,” Al Jahdhami said, adding that PDO has benchmarked against Argentina and Oman’s neighboring countries and believes the target
is achievable.
ADNOC: Partnering To Accelerate
ADNOC discovered the UAE’s first unconventional resources back in 2016, but expansion efforts have accelerated only in the past few years.
A central part of the NOC’s strategy involves partnering with outside operators that bring unconventional expertise.
In 2022, ADNOC awarded Malaysia’s Petronas a 6-year, 100% stake in a 2,000-km2 onshore unconventional block. Following the appraisal phase, ADNOC retains the option to enter a production concession with a 50% stake. Earlier this year, ADNOC signed a second such agreement with Houston-based EOG Resources, granting exploration rights to a 3,600-km2
block. If the program proves successful, ADNOC will again have the option to take share in the production concession.
Felipe Silva, vice president of unconventionals at ADNOC, spoke about the challenges the company is adapting to as it matures its unconventional program. These include getting
used to higher-temperature reservoirs and lateral sections that can extend between 10,000 and 20,000 ft.
Like many presenters at the conference, he also highlighted surface challenges. Chief among them is the need to supply operations with large volumes of sand and water for stimulation.
“That requires intense activity, from trucking to infrastructure,” Silva said, adding that “this is something new to the region, especially in terms of infrastructure. And as far as putting the wells in production, connecting such a high well count also requires far more pipelines than many of the conventional assets we have in the area.”
Silva also touched on the need for more intervention technologies, something echoed in comments by PDO representatives who said the need for workover rigs was growing in the region as the number of unconventional wells rises.
ADNOC’s strategy to handle the extra workload required by unconventionals includes building
in-country capability through a new service company, Turnwell, that was formed last year to drill and complete more than 140 unconventional gas wells. ADNOC Drilling holds a 55% equity stake in Turnwell, with SLB owning 30% and Patterson-
UTI the remaining 15%.
Julian Meneses, senior vice president of operations for Turnwell, told conference attendees that the company has drilled about half the wells in its initial contract and that roughly half of
those have been hydraulically fractured. In that short time, Turnwell has cut spud-to-total-depth drilling times by 70%, averaging about 13.5 days per well, and is targeting further reductions as it moves forward.
Meneses also acknowledged what he called “ramp-up challenges,” including the need to gather more subsurface data while driving down well costs. “Your stage count, which is a major needle mover for well cost, might be low at the beginning,” he said. “But over time, as you start getting more data and streamlining operations, you can move into development mode, gain critical mass, and improve asset utilization to drive the stage count higher and thus well costs lower.”
Looking ahead, Meneses said he sees major potential for automation to further lower costs and improve efficiency. “That to me is going to be a big disrupter and take things to the next level,” he said.
ADNOC and Turnwell are likely to take some lessons from Petronas, which has for years been deploying sustainable hydraulic fracturing methods in Canada, where its wells are completed using 100% recycled produced water.
Audrey Rasmussen, head of Petronas’ Unconventional Center of Excellence in Kuala Lumpur, said the company’s project in the UAE involves drilling and completing 12 wells in its initial phase that will use water sourced from a saline aquifer for hydraulic fracturing. She added
Petronas prioritized the building of infrastructure to tie in the field’s production to a central processing facility operated with its partner ADNOC which will enable the project “to sell the product immediately.”
Rasmussen said one of the other benefits of this early capital investment comes down to “being able to test your wells for much longer than typical,” which will lead to more reservoir data and insights. The development strategy will also reduce initial logistics burdens by eliminating the equivalent of about 160 truckloads of materials being brought to the location each day.
As the region aims to establish a thriving unconventional business, several speakers at IHFTC also noted that estimated ultimate recoveries will matter more than the initial production rates often celebrated during the US shale boom. In other words, the region is defining value differently,
a point Silva of ADNOC said is critical to its long-term success.
“The value from unconventionals will be different by country, by company,” he said. “And in some instances, if you apply what you can learn from unconventionals to conventional
reservoirs, it will drive billions of dollars by itself—and that’s another way of showing the value of unconventionals here.” JPT