阿曼石油开发公司 (PDO)南部油田的高级石油工程师兼水力压裂专家艾哈迈德·贾赫达米 (Ahmed Al-Jahdhami)与JPT谈到了该公司自 2016 年成立以来，在低压油藏中不断改进的水力压裂方法。

Al-Jahdhami近期在阿曼马斯喀特举行的SPE国际水力压裂技术大会（IHFTC）上探讨了这项工作，PDO是本次大会的东道主运营商。除了提高油井产能外，他还重点介绍了水力压裂技术如何开始影响整个公司的内部决策。

去年，PDO公司在其一处低压油田对一口水平井进行了水力压裂，产量比附近未压裂井高出约70%。与此同时，PDO公司已将平均增产成本从2019年的每井约100万美元降至目前的约30万美元，其宏伟目标是将每段压裂成本降至5万美元。

在接下来的问答中，Al-Jahdhami 讨论了 PDO 的压裂策略是如何演变的，指导设计和材料选择的权衡，以及如何利用区域内和更远地区的知识转移，为开发阿曼更多的油藏创造条件。

编者注：为了篇幅和清晰度，本次采访内容已进行编辑。

JPT：在马斯喀特举行的SPE IHFTC会议上，您谈到了PDO在水力压裂方面的思维转变。您能否在这里详细阐述一下这种转变？

贾赫达米：尽管 PDO 多年来一直处于该地区水力压裂技术的前沿，但许多人仍然认为它是一种主要与深层致密气藏相关的利基技术。

当我们开始讨论将其应用于较浅、压力较低的油藏，或历史上未进行增产措施的油藏时，我们花了一些时间才说服自己，它确实有必要。毕竟，即使不进行压裂，这些油井也会产油。

改变的是，我们已经开采了大部分易采石油。因此，我们开展了非常密集的研讨会，以确定在这种新环境下应用水力压裂技术的范围、局限性以及我们可以采取的任何措施。

现在情况正在发生变化，就在去年会议召开前，我们完成了第二口水平井的开采。这是一口真正的多级压裂井，共14级，我们只用了两天就完成了。这比我们之前的水平有了巨大的进步，越来越多的工程师和管理人员开始考虑使用水力压裂技术来开采更多那些有时经济效益勉强过关的难产井。

这就是我所说的思维转变，因为直到最近，水力压裂技术主要用于现有油井，通过去除钻井或长期生产造成的损害来延长或恢复其寿命。

JPT：您打算如何将这种思维方式上的进步运用到下一步？

贾赫达米：我们的下一步工作包括油田开发和探索我们尚未勘探的新区域。有些油田可能以前经济效益不高，但随着这种理念的形成，我们现在开始关注这些油田。

我们在这一领域的专业能力方面仍然面临挑战，因为PDO内部真正称得上压裂专家的寥寥无几。我们正努力让更多工程师参与到水力压裂技术中来，以增强他们的信心，使他们在重返油田作业时能够以不同的视角看待这项技术。如果担心我们会遗漏石油资源，压裂技术或许能够有所帮助，并成为开发这些区域的有力杠杆。

JPT：在通过对现有油井进行重新完井来建立信心之后，您认为PDO将如何应对这些前沿地区的水力压裂问题？

贾赫达米：实现这一目标的下一步是控制成本，因为压裂成本很高。回顾过去，这曾是主要障碍之一，尤其是在谈到将其应用于重油、压力相对较低但渗透性良好的砂岩油藏时。

这些油井无需水力压裂即可生产，尽管流动性可能是一个挑战。我们看到，压裂技术带来的流动性改善，在很多情况下，已使其成为必要条件而非可选项。现在的问题是如何围绕这一假设制定油田开发计划。我们尚未找到解决方案，但我们已经确定了一些之前因缺乏所有成功要素而被搁置的领域。

这口新的多级压裂井是我们首次采用NCS Multistage公司的精准入井压裂技术。这项限流入井技术利用连续油管，实现了一次下井作业。也就是说，作业人员使用连续油管下井，直到完成全部14级压裂作业后才出井。压裂后无需铣削。

这次作业非常成功，就初始产量而言，远远超出了我们的预期。成本也是一个关键因素，因为我们完成了14段的作业，成本却低于我们在低压环境下的第一口水平井（当时只有4段常规的射孔段）。相比之下，第一口井的作业耗时约21天——因此，14段井的作业时间缩短了约90%，单段成本也节省了约75%。

JPT：您认为采用有限进入技术主要是出于地面效率和操作方面的考虑，而不是出于地质或地质力学因素的考虑吗？

贾赫达米：是的，这完全是为了节省时间和提高效率。我们采用的是无套管技术，利用磨料喷射来制造射孔——也就是我们每个压裂阶段的孔洞。这使得我们能够在大约2到3小时内完成每个压裂阶段，而以前每个阶段需要2天时间。

我们还发现，由于我们使用的是水平井，因此我们希望尽可能多地利用水力压裂覆盖岩层。当我们只进行有限段数的压裂作业时，即使每次压裂的液量都相当大，我们也发现无法达到预期的覆盖效果。

这是促使我们采用这套系统的另一个主要原因。这项技术能够根据射孔位置，精确定位裂缝的起始和扩展位置。因此，您可以非常有把握地确保裂缝在预定层段内起始和扩展。这使我们能够增加压裂段数，并实现对储层的更佳覆盖。

JPT：对于这些低压油藏，您如何看待裂缝半长和裂缝导流能力之间的权衡？哪个更重要？这会如何影响您在这些大型油藏开发中的支撑剂策略？

贾赫达米：这些低压油藏的岩石质量仍然相对较好。我们通常所说的渗透率范围在200到600毫达西之间，有时甚至更高。传统上，如果听到这样的数值，你会认为不需要对油井进行压裂。因此，我们并不追求很长的裂缝半长。相反，我们专注于较短的裂缝半长，并力求形成更厚、更宽的裂缝，以提高导流能力。

JPT：您希望在井筒附近形成宽阔的平面裂缝，但裂缝长度不能太长。这与之前的设计相比如何？

贾赫达米：采用传统的塞孔射孔法，我们使用标准射孔，并将其分组——通常每个阶段三到四个组。这些都是常规的高射孔密度射孔，是非常常规的设计。但我们也注入了更大的压裂液。

为了便于比较（我们通常用公吨而不是磅来衡量），传统单级压裂可能需要大约 80 到 100 吨支撑剂。而采用精准、限量注入的方式，我们每级压裂仅需注入约 20 吨支撑剂——大约是以前用量的四分之一到五分之一。

原因在于，传统设计本质上是尽可能多地注入压裂液，并寄希望于多条裂缝在所有岩体群中萌生并扩展。但实际上，我们经常观察到，在四岩体群的压裂阶段，可能只有两个岩体群能够有效吸收压裂液和支撑剂，而其他岩体群则无法吸收。这导致大约50%的岩层未得到压裂，造成资源浪费，并导致石油流失。

正是那次经历促使我们采取了限流方式。通过注入更小、更可控的压裂液，并在非常靠近井筒的位置形成平面裂缝——而且裂缝数量众多——我们可以获得更高的压裂效率和更均匀的储层覆盖率。

JPT：您在IHFTC上的演讲中，最让我印象深刻的一点是您对成本控制的雄心，包括将每阶段的成本长期目标设定在5万美元左右。实现这一目标还有哪些关键因素？

贾赫达米：我们关注的另一个重要领域是本地化内容，或者说本地价值。我们正努力尽可能多地使用本地产品和服务。这有助于降低我们的物流成本。

这是其中一个要素。另一个要素当然是效率。时间就是金钱，我们完成这些工作的速度越快，总成本就越低。在这方面，我们通过精准定位技术以及增加天然砂的使用量来替代成本更高的支撑剂，取得了显著的成效——尽管在合适的情况下，我们仍然会使用陶瓷支撑剂。

我们尚未采用天然砂，因为我们一直在对本地采购的材料进行资质认证。也就是说，我们现在已经认证了几家供应商——我所说的本地，实际上是指更偏​​向区域性的供应商，例如来自沙特阿拉伯等邻国的供应商。

今年，我们的目标是至少试用并开始推广使用这些砂子。天然砂和陶瓷支撑剂的成本差异可能高达每吨一个数量级。因此，如果我们能够可靠地在这些应用中使用天然砂，无疑将大幅降低我们的成本。

JPT：关于这一点，您在评估区域砂时主要关注哪些参数？抗压强度是主要考虑因素，还是浊度和细粒含量等因素也同样重要？

贾赫达米：是的，百分之百肯定，抗压强度是关键参数。当然，还有其他质量方面——球形度、酸溶性、细粉含量——我们有专门的化学团队负责评估所有这些方面。但如果非要我选出最关键的因素，那绝对是抗压强度。

我们目前主要关注的是支撑剂破碎导致的渗透率下降或导流能力损失。这是我们工作的主要方向。基于这项工作，我们已经能够对来自不同供应商的几种砂进行认证，但仅适用于某些油藏，并非普遍适用。我们仍然有一些油藏更深、闭合压力更高，天然砂根本无法使用，因为破碎会抵消任何成本效益。

但随着我们深入研究，评估的方案越多，我们发现砂基支撑剂的应用前景就越广阔。我们也在探索增强天然砂性能的方法，例如通过涂层来提高强度。当然，这也会增加成本，因此我们正在评估这种权衡是否合理。

我还想补充一点，我们正在探索多种减少淡水使用的方法，包括利用采出水和高盐度水。传统上，我们主要依赖反渗透水，这种方法耗能高，而且需要大量卡车运输。这增加了成本，也增加了我们的碳足迹。

我们正在探索对采出水进行现场处理和调节后再利用的方法。当需要进行多级处理（例如14级处理）并且同时从多个水井抽水时，水量可能会成为一个严重的瓶颈。因此，这是我们非常感兴趣的一个方面。

JPT：纵观北美经验，最大的转变之一是转向盆地内砂，尽管早期人们对压裂强度有所担忧。但这些开发项目的经济周期通常较短，前几年至关重要。在选择支撑剂时，您会更重视长期压裂性能和耐久性吗？

贾赫达米：这是我们的项目与北美项目最大的区别之一。在许多页岩油开发项目中，你进行压裂和抽油，却不太担心质量，因为正如你所说，两年后你就能收回成本，然后钻另一口井，如此循环往复。

我们的理念截然不同。我们追求的是这些油井的长期可持续性，这意味着我们将它们设计为可使用20到25年。这涉及到成本方面的考量。

如果你设计的油井只打算使用 5 年，你可能不会太在意采购更高质量的材料或设计长期完整性，无论是套管还是完井。

公司内部也会进行类似的讨论，我们会扪心自问：我们真的需要把油井设计寿命设定为20年或25年吗？或者在某些情况下，使用成本更低的材料，设计寿命为10年是否更合理？但总的来说，我们仍然以长远眼光为重。这部分源于我们的国家愿景，因为PDO公司60%的股份由政府持有，我们非常重视长期价值而非短期回报。

JPT：您在IHFTC上还提到了另一项值得注意的内容——利用水力压裂技术辅助注水。您能否详细说明一下，压裂注水井如何提高驱油效率，以及您认为这种方法能带来哪些性能提升？

贾赫达米：阿曼南部的大部分低压油藏都是重油系统，至少在初期阶段，含水层驱动力很强。为了维持含水层的支撑作用，我们需要注入大量的水。

但我们经常看到的是注水性能随时间逐渐下降。例如，一个注水井最初的注水速率可能为 100 立方米/天，但多年后，该速率会显著下降，有时甚至几乎降至零。注水压力升高，表明井筒附近可能存在损坏。

在注水井水力压裂方面，我们的主要目标并非直接提高驱油效率，而是恢复或提高注水能力。这种损害的根源并不总是很明确。它可能与水不相容性有关（尽管我们进行了大量的相容性测试），也可能是粘土或页岩膨胀造成的。我们仍在努力全面了解这个问题。

然而，我们发现，通过采用相对较小的压裂处理——而非大规模或剧烈的压裂——可以有效地避免这种损害。在许多情况下，原本几乎不进水的注水井恢复了原有的注水速率，甚至超过了预期。

到目前为止，大部分工作都集中在位于水层（或称底水层）的垂直注水井上，而不是成套注水井。尽管如此，我们也对成套注水井进行了压裂，但这些情况需要更加谨慎。必须非常了解裂缝扩展和裂缝方位角，因为如果裂缝直接连接注水井和生产井，则存在注水井和生产井之间短路的风险。

下一步，我们将研究范围从垂直井扩展到水平注入井。我们感兴趣的是制造沿井筒方向而非横向扩展的纵向裂缝。在注采井模式下，纵向裂缝有助于将注入水更均匀地分布在井筒内，从而提高波及效率。

JPT：鉴于 PDO 的油藏与北美页岩油藏有很大不同，您如何决定哪些经验教训可以借鉴，哪些经验教训需要来自区域或阿曼的经验？

贾赫达米：当然，北美一直是水力压裂技术的重点发展区域，我们也经常参加那里的会议，专门学习他们的经验。对我们来说，成本始终是一个重要问题。曾经，我们的压裂作业成本接近每段100万美元，所以我们自然很想了解北美运营商是如何以如此低的成本进行压裂的。

我们从那次经验中学到的，与其说是他们为什么压裂，甚至从油藏角度来看他们是如何压裂的，不如说是他们如何实现运营效率。成本控制、执行速度和可重复性是最重要的经验教训。由于他们的开发项目受制于非常短的经济周期，他们已经非常擅长以接近工厂模式的效率运营。

而这正是我们关注的重点——看看我们可以从那次经验中汲取哪些要素来提高我们自身运营的效率并降低成本。

但正如我之前提到的，北美有很多例子并不适用于我们。因此，我们开始研究区域经验，也研究中国和南美部分地区，这些地方的岩石类型、开发目标以及国家石油公司的角色都与我们更具可比性——尤其是在着眼于长期发展理念方面。

这正是PDO决定在阿曼举办IHFTC的原因之一。其目的是将区域运营商聚集在一起，创建一个平台来分享这些更具实用价值的经验。

我还可以举个具体的例子。沙特阿美公司开始使用本地天然砂，这对我们来说是一个很大的启发。几年前我们在国际海事技术大会（IHFTC）上第一次听说了这种方法，现在我很高兴地宣布，我们计划使用的砂源之一就来自沙特阿拉伯。

我还想补充一点，这种交流是双向的。该地区的许多运营商现在都在关注PDO以及我们正在做的事情，并将其视为可以学习的模式。

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.