Ahmed Al-Jahdhami, a senior petroleum engineer and hydraulic fracturing subject matter expert for Petroleum Development Oman’s (PDO) southern oil fields, spoke with JPT about the company’s evolving approach to hydraulic fracturing in low‑pressure oil reservoirs since its earliest days of development in 2016.
Al-Jahdhami recently discussed this work at the SPE International Hydraulic Fracturing Technology Conference (IHFTC) in Muscat, Oman, where PDO served as the host operator. In addition to improved well performance, he highlighted how hydraulic fracturing is beginning to shape internal decision-making across the organization.
Last year, PDO hydraulically fractured a horizontal well in one of its low-pressure fields, achieving production rates that were about 70% higher than nearby nonfractured wells. At the same time, PDO has reduced average stimulation costs from about $1 million per well in 2019 to roughly $300,000 today, with the grand ambition being to achieve $50,000 per stage.
In the following Q&A, Al-Jahdhami discusses how PDO’s fracturing strategy has evolved, the trade-offs guiding design and material selection, and how it has leveraged knowledge transfer regionally and from further afield to open more of Oman’s reservoirs to development.
Editor’s note: This interview has been edited for length and clarity.
JPT: At the SPE IHFTC in Muscat, you spoke about a shift in mindset around hydraulic fracturing at PDO. Can you elaborate with us here on this transition?
Al-Jahdhami: Even though PDO has been at the forefront of hydraulic fracturing in the region for many years, it was still perceived by many as a niche technology associated mainly with deep, tight-gas reservoirs.
When we started discussing its application in shallower, lower-pressure reservoirs, or in reservoirs that had historically been produced without stimulation, it took a little bit of time to convince ourselves that it was really needed. After all, these wells will produce even if you don’t frac them.
What changed was the fact that we have already produced much of the easy oil. That’s why we launched very intensive workshops to identify the scope, limitations, and any levers that we could pull to apply hydraulic fracturing in this new environment.
Things are changing now, and just before the conference last year, we completed our second horizontal well. That was a true multistage frac with 14 stages, and we did that in 2½ days. That is a huge step up from where we were before, and more engineers and managers are now starting to think about using hydraulic fracturing to unlock more of these difficult wells that sometimes have borderline economics.
This is the mindset shift that I was talking about, because until recently, hydraulic fracturing was used predominantly on existing wells to prolong their lives or revive them by removing damage, either caused by drilling or long‑term production.
JPT: Where do you take this progress in mindset from here?
Al-Jahdhami: The next step for us involves field development and new areas that we haven’t explored. There are some reserves out there that maybe did not have strong economics, but we’re starting to look at those now as this mindset takes hold.
We still face challenges with competence in this area since there are very few of us within PDO that you could call frac experts. We are looking to get more engineers involved with hydraulic fracturing to build up that confidence so that, when they return to their asset, they will think differently. If there is concern that we are leaving oil behind, fracturing could help and become a strong lever to open up those kinds of areas.
JPT: After building confidence through recompletions in existing wells, how do you see PDO approaching hydraulic fracturing in those frontier areas?
Al-Jahdhami: The next step toward that goal is cost control, because fracturing can be expensive. Looking back, that was one of the main showstoppers, particularly when we talk about applying it in heavy-oil, relatively low-pressure, but good-permeability sandstone reservoirs.
These wells will produce without hydraulic fracturing, although mobility can be a challenge. What we are seeing is that the improvement in mobility achieved through fracturing has, in many cases, made it a requirement rather than an option. Now the question is how to design field development plans around that assumption. We are not there yet, but we have identified certain areas that were previously set aside because not all the elements for success were in place.
This new multistage well was our first to use pinpoint-entry fracturing technology from NCS Multistage. The limited-entry technology, which uses coiled tubing in place, allowed us to make it a one-trip job, so you go in with coiled tubing, and you don’t come out of the well until you’ve finished all 14 stages. There’s no post-frac milling.
It was very successful, and in terms of initial production, it was way above what we expected. The cost element was a big key, too, since we completed 14 stages for less than our first horizontal well in the low-pressure environment that had only four conventional plug-and-perf stages. To compare, that first well took us around 21 days—so we saw around a 90% reduction in time on the 14-stage well, and in terms of cost-per-stage, we saved about 75%.
JPT: Would you say the move to limited-entry technology was driven mainly by surface efficiency and operational considerations, rather than by geological or geomechanical factors?
Al-Jahdhami: Yes, it was purely about saving time and gaining efficiency. The technology we used was sleeveless and uses abrasive jetting to create perforations—four holes per stage. What this allowed us to do was to complete each frac in around 2 to 3 hours vs. what used to take 2 days per stage.
Another thing we saw was that, because we are in horizontal wells, we really want to cover as much of the rock as possible with hydraulic fracturing. When we only went for a limited number of stages, even if we were pumping fairly large treatments, we found that we were not getting the coverage we wanted.
That was another major driver for moving toward this system. With this technology, you are effectively pinpointing where the fracture will initiate and grow, based on where you have perforated. So, you can be very confident that the fracture is going to start and propagate in the intended interval. That allowed us to increase the number of stages and achieve much better coverage of the reservoir.
JPT: With these lower-pressure reservoirs, how do you think about the trade-off between fracture half-length and fracture conductivity? Which matters more here, and how does that influence your proppant strategy in these larger treatments?
Al-Jahdhami: These low-pressure reservoirs still have relatively good rock quality. We’re typically talking about permeability in the range of 200 to 600 md, and sometimes higher. Traditionally, if you hear those numbers, you would say you do not need to fracture the well. So, we are not chasing very long fracture half-lengths. Instead, we focus on shorter half-lengths and aim for thicker fractures with more width to improve conductivity.
JPT: You want wide planar fractures right next to the wellbore, but not too long. How does this compare to previous designs?
Al-Jahdhami: With the traditional plug-and-perf approach, we used standard perforations clustered into groups—typically three to four clusters per stage. These were conventional high-shot-density perforations, very normal designs. But we also pumped bigger fracs.
For comparison, and we usually talk in metric tons instead of pounds, a single traditional stage might receive around 80 to 100 tons of proppant. With the pinpoint, limited-entry approach, we are pumping only about 20 tons per stage—so a quarter to a fifth of what we used before.
The reason is that in the traditional design, you are essentially pumping as much as you can and hoping that multiple fractures initiate and grow across all clusters. In reality, what we often observed was that in a four-cluster stage, maybe only two clusters would effectively take fluid and proppant, while the others would not. That leaves roughly 50% of the rock unstimulated, which is a waste and leaves oil behind.
That experience is what drove us toward limited entry. By pumping smaller, more controlled treatments and creating planar fractures very close to the wellbore—but many of them—we get much better stage efficiency and far more consistent reservoir coverage.
JPT: One of the points that really stood out in your talk at IHFTC was your ambition around cost compression, including a longer-term target of roughly $50,000 per stage. What other factors will be key in reaching that goal?
Al-Jahdhami: Another important area we are looking at is local content, or in-country value. We are deliberately trying to use as much local product and as many local services as possible. That supports reducing our logistics cost.
That’s one element. The other, of course, is efficiency. Time is money, and the faster we can complete these jobs, the lower the overall cost. That’s where we’ve seen significant gains with pinpoint technology, as well as by increasing the use of natural sand instead of higher-cost proppant—although we are still using ceramic proppant where it makes sense.
We have not adopted natural sands yet because we have been in the process of qualifying locally sourced material. That said, we have now qualified a few suppliers—when I say local, I really mean more regional, from neighboring countries such as Saudi Arabia.
This year, our objective is to at least trial and begin implementing the use of those sands. The cost difference between natural sand and ceramic proppant can be an order of magnitude on a per-ton basis. So, if we can reliably use natural sand in these applications, it will certainly drive our costs down quite a bit.
JPT: On that point, what are the parameters you focus on when evaluating regional sand? Is crush strength the primary concern, or are factors like turbidity and fines content just as important?
Al-Jahdhami: Yes, 100% yes, crush strength is the key parameter. Of course, there are other quality aspects as well—sphericity, acid solubility, fines content—and we have a dedicated chemistry team that evaluates all of those. But if I had to pick the most critical factor, it’s definitely crush strength.
What we are trying to manage is permeability degradation, or loss of conductivity, due to proppant crushing. That is where most of our focus has been. Based on that work, we have been able to qualify a few sands from different vendors, but only for certain reservoirs; it is not universal. We still have reservoirs that are deeper, with higher closure pressures, where natural sand simply will not work because the crushing would negate any cost benefit.
But the more we get into it, and the more options we evaluate, the more opportunities we see to use sand proppant more widely. We are also looking at ways to enhance natural sand, such as coating it to improve strength. But of course, this also increases cost, so we are assessing whether that trade-off makes sense.
One thing I’d also like to add is that we are looking at several ways to reduce freshwater use, including using produced water and higher-salinity water. Traditionally, we have relied mainly on reverse-osmosis water, which is energy-intensive and requires significant trucking to location. That adds costs and increases our carbon footprint.
We are exploring reusing produced water with some on-site treatment and conditioning. When you start pumping multistage treatments—like the 14-stage job—and then multiple wells at once, the water volumes can become a significant bottleneck. So, this is something we are very interested in.
JPT: Looking at the North American experience, one of the biggest shifts has been toward in-basin sands, despite early concerns around crush strength. But those developments often operate on much shorter economic timelines, where the first couple of years matter most. How much more weight do you place on long-term fracture performance and longevity when making proppant choices?
Al-Jahdhami: This is one of the biggest differences between our program and those in North America. In many shale developments, you frac and pump and don’t worry much about the quality, since as you said, in 2 years you get your money back and just drill another well, and so on and so forth.
Our philosophy is very different. We look for long-term sustainability in these wells which means we design them to last 20 to 25 years. That plays into cost considerations.
If you design a well for only 5 years, you may not care as much about sourcing higher-quality materials or designing for long-term integrity, whether that is casing or completions.
These discussions also come up internally and we ask ourselves whether we really need to design wells for 20 or 25 years, or whether there are cases where designing for 10 years using lower-cost materials might make sense. But overall, the long-term approach remains our focus. This is partly driven by our national vision since PDO is 60% government-owned, and there is a strong emphasis on long-term value rather than short-term returns.
JPT: You mentioned something else at IHFTC that seemed noteworthy—the use of hydraulic fracturing to support waterflooding. Could you expand on how fracturing injection wells improves sweep efficiency, and what kinds of performance improvements do you see from that approach?
Al-Jahdhami: Most of the low-pressure oil reservoirs in southern Oman are heavy-oil systems with a strong aquifer drive, at least initially. To maintain that aquifer support, we inject significant volumes of water.
But what we often see is a gradual deterioration in injection performance over time. An injector may start at, say, 100 m³/D, but over the years that rate can decline significantly, sometimes to almost nothing. Injection pressures increase, indicating damage near the wellbore.
When it comes to hydraulic fracturing of injectors, our primary objective has been less about directly improving sweep efficiency and more about restoring or improving injectivity. The source of that damage is not always clear. It could be related to water incompatibility, even though we do extensive compatibility tests, or it could be clay or shale swelling. It is something we are still trying to fully understand.
What we have found, however, is that by applying relatively small fracture treatments—not large or aggressive fracs—we can effectively bypass that damage. In many cases, injectors that were barely taking water return to their original injection rates or even exceed expectations.
So far, most of this work has been on vertical injectors located in the water leg, or bottom water zone, rather than injectors that are part of a pattern. Having said that, we have also fractured injectors within patterns, but those cases require much more care. You need a very good understanding of fracture growth and fracture azimuth, because there is a real risk of short-circuiting between an injector and a producer if the fracture directly connects the two.
The next step we are looking at is moving beyond vertical wells to horizontal injectors as well. We are interested in creating longitudinal fractures that grow along the wellbore rather than transverse to it. In injector-producer patterns, the idea is that a longitudinal fracture could help distribute injected water more evenly along the wellbore, which in turn could improve sweep.
JPT: Given how different PDO’s reservoirs are from North American shale, how do you decide which lessons are transferable and which need to come from regional or Omani experience?
Al-Jahdhami: North America has, of course, been the big focus for hydraulic fracturing, and we have regularly attended conferences there specifically to learn from that experience. One of the big questions for us was always on cost. At one point, our fracture treatments were costing close to $1 million dollars per stage, so we naturally wanted to understand how operators in North America were able to execute fracturing at such a low cost.
What we took from that experience was less about why they fracture, or even how they fracture from a reservoir standpoint, and more about how they achieve operational efficiency. Cost control, execution speed, and repeatability were the big lessons. Because their developments are driven by very short economic timelines, they have become extremely good at operating with what are almost factory-mode efficiencies.
And that’s where we are focusing on—looking at what elements we can take from that experience to improve efficiency and reduce costs in our own operations.
But as I mentioned, there are many examples from North America that simply do not apply to us. So, we started looking at regional experiences and also at places like China and parts of South America, where the rock types, development objectives, and the role of national oil companies are more comparable—especially with a longer-term development mindset.
That was one of the reasons PDO decided to host IHFTC in Oman. The idea was to bring regional operators together and create a platform to share those more-relevant learnings.
I can give you a specific example, too. Saudi Aramco implemented the use of locally sourced natural sand, and that was a real trigger for us. We first heard about that approach a few years ago at IHFTC, and now I’m happy to say that one of the sand sources we are planning to use is from Saudi Arabia.
I should also add that this exchange goes both ways. Many operators in the region are now looking at PDO and what we are doing as a model they can learn from as well.
