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Discussions at the 2025 SPE International Hydraulic Fracturing Technology Conference (IHFTC) in Muscat, Oman, raised questions about how unconventional resources might best be developed in the Middle East.
I attended the event, which was covered by JPT in November, and the focus on this topic prompted me to reflect on my work in the region over the past 30 years and to offer perspective on recent progress and the potential path forward.
Some of the big questions I believe people in the region are—and should be—asking include: “What is my best candidate well for fracturing?” “Is a horizontal multistage-frac well the right strategy for this reservoir?” “What direction should I drill my horizontal well?” and “What is holding back fracturing in the Middle East?”
The History of Fracturing in the Middle East
Dubai Petroleum has said that acid fracturing was performed in vertical wells in Dubai in the 1970s (SPE 184747); however I am not aware of any publications detailing the work from that time.
Qatar Petroleum reported that it began acid fracturing in 1980 in five wells targeting the Shuaiba chalk (SPE 9641).
The first propped fracs in the Middle East were in Oman’s Sahmah field in 1982. This work, performed by Elf Aquitaine (SPE 17952), involved an acid fracturing job and a propped fracture placed in the same well to target a carbonate and a sandstone formation (Fig. 1).
One thing these initial projects have in common is that they all sought to unlock oil production from reservoirs considered marginal.
In 1989, Elf drilled a horizontal well in the same field that was considered for multiple propped fracs (SPE 21385).
Soon after, the first appraisal wells for the Saih Rawl\Barik gas-condensate fields in Oman were completed with propped fractures between 1992 to 1994, and full-field development began in 1996. The main reason for hydraulic fracturing in Saih Rawl\Barik was to avoid rapid production decline due to condensate dropout and to reduce the total well count needed to supply a liquefied natural gas (LNG) plant. Propped fractures increased gas rates in each well and were a cheaper option than drilling more wells (SPE 63109).
As a result, the Saih Rawl\Barik fields were the first in the Middle East to be developed using hydraulic fracturing in every well. This was a key milestone in the region and led to the creation of a fracturing infrastructure in Oman.
In Saudi Arabia, acid fracs were pumped quite regularly to accelerate production in vertical wells in the carbonate Khuff formation starting in 1998. By the 1990s, propped fractures were also used in the country’s pre-Khuff sandstone, where unconsolidated sands required frac packs and screenless completions. These jobs were successful.
But, as in Oman, the initial fracturing in Saudi Arabia was not for "tight gas." Instead, the focus was on accelerating production and improving deliverability per well.
What Is a Tight Reservoir?
The term “tight gas” was first defined by the US Federal Energy Regulatory Commission in 1979 as an in-situ gas permeability of less than 0.1 mD. Today, in the era of unconventionals with permeability measured in micro- or nano-Darcies, 0.1 mD would be considered a high-permeability gas well in North America.
In a 1995 publication about using local sand as proppant, the authors described oil reservoirs in Saudi Arabia as “low permeability” if they were 50 mD or less. In Abu Dhabi, acid fracturing began around 2011 as an alternative to matrix acidizing in tight-oil reservoirs. These were defined in one publication by the Abu Dhabi Company for Onshore Oil Operations (ADCO) as ranging from 1 to 4 mD.
In Kuwait, “tight carbonates” with permeability in the range of 5 to 25 mD were stimulated using acid fractures. Since what really matters is mobility, rather than permeability, one must be careful not to compare apples (i.e., oil permeability) and oranges (i.e., gas permeability).
The viscosity of oil in Saudi Arabian reservoirs can range from 0.13 to 70 cp. In Table 1, we show that a tight-gas permeability of 0.1 mD gives a mobility of 5 mD/cp for a normal gas viscosity.
For a typical Middle Eastern medium oil, with a viscosity of 2.5 cp, a permeability of 12.5 mD results in the same mobility as tight gas. So, this would be a good fracture candidate. For a light oil, a permeability of about 1 mD qualifies as “tight” based on mobility.
When people speak of their “tight” reservoir, the first question to ask should be: What are the permeability and fluid viscosity at reservoir conditions?
Likewise, if a project is described as “unconventional,” it is worth asking: Are you targeting the source rock itself? Or is this just a reservoir that we didn’t consider worth producing in the past?
These distinctions matter because they shape the assumptions that follow. Too often, once a reservoir is labeled “tight” or “unconventional,” the conversation quickly shifts to replicating what worked elsewhere—particularly in North America.
If it worked in North America, it will work here too, right?
The shale revolution made horizontal multistage wells with transverse fractures the standard in the North American onshore sector. But the success of this type of well would not have happened without favorable local conditions. Successful application of horizontal multi-frac wells depends on two factors that engineers cannot control:
- Stress regime is favorable for fracturing (e.g., normal faulting)
- No barriers to fracture-height growth within the target pay interval
When these two local conditions are unfavorable, fracturing in a vertical well becomes more difficult, while horizontal well development becomes extremely difficult. This has been well documented in industry literature from Oman (SPE 179142; SPE 205919).
With fracturing, I can produce any reservoir, right?
Thanks to the success of unconventional well fracturing in North America, it is often repeated that “fracturing makes the reservoir.” Some people have come to believe that horizontal well fracturing done by pumping huge volumes of slickwater and small-mesh proppant can make an economic well in any reservoir.
Unfortunately, this conclusion is only valid when it is possible to place enough transverse fractures, each covering the entire pay interval, to get enough production to make an economic well.
Deep tight reservoirs with very thick gross intervals that contain barriers to fracture-height growth are not well-suited to the standard unconventional approach used across North America.
What direction should I drill a horizontal well for fracturing?
There have been many cases in the recent past when people have looked to North America for the latest completion developments, assuming these would be best for projects in the Middle East.
One of the most common issues with this approach is the automatic assumption that all horizontal wells should be drilled in the direction of minimum stress to create transverse fractures, and that more fractures (i.e., tighter cluster spacing) are always better. It is easy to see how someone following developments in North America could come to this conclusion.
However, I believe many horizontal wells should have been drilled in the direction of maximum horizontal stress to obtain longitudinal fractures. Table 2 shows results from a recent study that gives realistic guidelines for choosing the best well orientation (SPE 181813).
The key lesson here is to not assume that you should always drill your horizontal well in the direction of minimum stress to create transverse fractures. This is because the best well orientation depends primarily on permeability and mobility.
Fracturing can make any well economic, right?
There have been some true unconventional developments in the Middle East, such as Saudi Aramco’s Jafurah project. However, the economics of such a project are quite different from those in North America.
Because gas production from this project can replace oil that is being burned for power generation in Saudi Arabia—allowing the oil to be exported—the project economics are not based solely on gas revenues.
This demonstrates how the question of well economics is complicated, with different situations in each country. Whether some new “unconventional” projects could compete on price with imported LNG from Qatar is not necessarily the issue. More important in some countries is simply the desire to not be dependent on neighbors for gas supplies.
For decades, there has been a recurring debate about what is holding back hydraulic fracturing in Europe or the Middle East. The first response to this question is almost always the same: fracturing is too expensive.
But we know that fracturing costs are controlled mainly by frac fleet utilization. If a frac fleet is pumping every day, stimulation costs will be much lower than if only one frac job is done per month.
A more important point is that fracturing costs usually become the limiting factor only after drilling costs have declined sufficiently for fracturing to account for the majority of total well cost (e.g., more than 75% in 2023 per URTeC 4220852/Rystad Energy), as shown in Fig. 2 for a US onshore well in the Eagle Ford Shale in south Texas.
Developing unconventional resources, as in North America, requires thousands of wells—not dozens or hundreds. If drilling an unconventional well that can produce 2 to 10 Bcf requires 90 to 120 days, which is the case for some projects in the region, then fracturing costs are not really the issue.
Therefore, the learning curve for drilling must occur first, to drill enough “cheap” wells to allow for optimal utilization of the fracturing fleets, which lowers frac costs.
In North America, typical drilling times dropped from 40 days to 10 days for horizontal shale-gas wells. For Jafurah, Aramco reduced drilling time from 66 days to 29 days over the course of 2016. The company further reduced the average drilling time to about 25 days by 2024.
A Comment on the Future
I am extremely bullish on hydraulic fracturing in the Middle East in the coming years. Once the “easy stuff” is gone, the motivation and the incentive to start looking for better fracturing candidates will become a lot stronger. This has been the case in North America, in the North Sea, Algeria, Russia, China, and other places where the “easy stuff” is gone.
In the Middle East, Oman is already furthest along this path, having now started to look at fracturing mature oil assets (SPE 205236; SPE 215665).
In Iraq, Chinese operators are reporting success with multistage proppant fracturing in carbonates, where some lower-strength rock is present (SPE 205281). The rest of the region will eventually apply hydraulic fracturing where it makes the most sense economically, not necessarily targeting source rock or shales, but first looking at tight reservoirs, wells with bypassed pay, wells with high skin damage, and other low-hanging fruit.
Josef Shaoul, SPE, is engineering manager and partner at Fenix Consulting Delft, where he conducts fracture stimulation studies, provides onsite fracture engineering support, performs well test analysis, and works on reservoir simulation and software development. He joined Fenix in 1996, when the company operated as Pinnacle Technologies Delft. Previously, Shaoul was lead software engineer at RES (Resource Engineering Systems), where he led development of FracPro. He also worked for Hunter Geophysics on tiltmeter mapping applications. Shaoul has more than 35 years of industry experience. He earned BS and MS degrees in electrical engineering and computer science from the Massachusetts Institute of Technology. He has been active in SPE, serving as co-chair of the European Stimulation Workshop for the past 15 years and as a committee member of the SPE IHFTC since its inception. He has authored eight peer-reviewed journal articles and 40 SPE papers.
For Further Reading
SPE 9641 Evaluation of Production Tests in Oil Wells Stimulated by Massive Acid Fracturing Offshore Qatar by S.W. McDonald.
SPE 205281 First Successful Application of Multistage Proppant Fracturing on Horizontal Well in Carbonate Reservoirs in Iraq by D. Zhu; M. Cui; Y. Chen; Y. Wang; Y. Ding; C. Xiong; C. Liang; F. Yao; X. Wang; W. Cai; Y. He; Z. Ling; and D. Wang.
SPE 205919 Improving Proppant Placement Success in Horizontal Wells in Layered Reservoirs in the Sultanate of Oman by A. Boucher; J. Shaoul; I. Tkachuk; M. Rashdi; K. Bahri; and C. Veeken.
SPE 181813 Multiphase Flow Performance Comparison of Multiple Fractured Transverse Horizontal Wells vs. Longitudinal Wells in Tight and Unconventional Reservoirs With Stress-Dependent Permeability by R.S. Kassim; L.K. Britt; S. Dunn-Norman; and F. Yang.
SPE 63109 Optimization of Hydraulic Fracturing in a Deep, Multilayered, Gas-Condensate Reservoir by R.A. Langedijk; S. Al-Naabi; H. Al‑Lawati; R. Pongratz; M.P. Elia; and T. Abdulrab.
SPE 205236 Performance of 15 Years of Hydraulic Fracturing of Oil Wells in South of Oman by M.M. Molenaar; A. Al-Ghaithi; S. Kindi; and F. Alawi.
SPE 184747 Proposing, Drilling, Completing, and Producing the World's First Offshore Horizontal Multistage Proppant-Fractured Well That Targeted Tight Carbonate Source Rock—Dubai's Unconventional Shilaif Formation Case Study by F. Chemin; J.P. Freile; L. Moreira; N. Mehrotra; I. Alabi; H. Thompson; N. Suarez Arcano; and T. Bukovac.
SPE 215665 Revitalizing the Oldest Well in a South Oman Field Using Hydraulic Fracturing: A Case Study by G. Mahanti; M. Al Kalbani; S. Lawati; S. Kindi; A. Al-Ghaithi; and A.L. Ryba.
SPE 179142 The Good, the Bad, and the Ugly: A Case History of a Multistage Hydraulic Fracturing Horizontal Well Tight-Gas Development in Oman by A. Nicolaysen; A. Casero; A. Roy; M. Rylance; S. Kurniadi; and T. Batmaz.
URTeC 4220852 Unconventional Resources Well Cost Benchmarking Study: Trends, Forecasts, and Operator Efficiency by S. Mubarak; A. Shawaf; and M. MacPhee.
SPE 21385 Use of Oil-Base Gel System for Multiple Proppant Fracturing of Horizontal Wells by M.A. McCabe; J.-L. Champetier; and M.G.R. Edwards.