水库

地下储氢的不确定光明未来

建设世界氢基地需要技术突破和大量新需求。但为了储存它,世界需要油藏工程师和其他地下专家。

模拟气体饱和度的比较
注入结束时模拟的二氧化碳(左)和氢气(右)气体饱和度的比较。这项工作强调了氢气在多孔介质内扩散的可能性。
资料来源:Energies 2022/德克萨斯大学奥斯汀分校

全球氢产量大幅增长的最明显障碍是众所周知的。其中包括降低生产成本的技术突破以及电力和运输行业的新需求来源。

不太明显的是,需要一小群油藏工程师、地质学家和其他地下专家来了解未来的氢中心将在何处以及如何存储清洁燃烧燃料。

许多专家认为,在地面上进行大量存储是根本不可能的。这意味着大型氢项目将需要地下部分,一些人认为枯竭的石油和天然气田(重点是后者)可能符合要求。咸水层也正在关注这一角色。

但正如这一切表明的那样,没有人尝试过利用这些地层来储存氢。仅四个浅层盐层、德克萨斯州的三个盐丘和英国的一个盐田就代表了世界氢地下储存(HUS)容量的总和。

专家认为,氢生产的任何黄金时代都高度依赖于扩大盐层或枯竭气田作为储存系统的使用。
专家认为,氢生产的任何黄金时代都高度依赖于扩大盐层或枯竭气田作为储存系统的使用。
资料来源:荷兰 TNO。

目前正在进行研究以扩大盐地层中的 HUS,但这并不能解决这样一个事实:对于大型工业企业希望生产氢气的许多地点来说,它们不是一个地质选择。这包括欧洲大部分地区和美国墨西哥湾沿岸各州以外的大部分地区。

相比之下,各种类型的深层沉积结构并不短缺,但缺乏任何可能有助于降低储存数 Bcf 氢的风险的材料现场经验。

上游行业在运营最接近的类似物——天然气储存和碳捕获与储存(CCS)方面拥有丰富的经验——将有助于这一过程,但在将宇宙最小的分子注入其中时,存在新的挑战多孔介质。

其中最重要的是氢在储层内(横向和垂直)迁移的强烈倾向,以及可能发生麻烦的化学和生物反应。

氢气也可能是清洁燃烧的,但它提供的能量密度仅为甲烷的三分之一左右,这意味着它需要大约三倍的存储体积才能向燃气发电厂提供相同的能量输出。

德克萨斯大学奥斯汀分校油藏工程师兼教授 Mojdeh Delshad 是致力于澄清此类问题的人之一。她的最新研究涉及使用商业储层模拟器来模拟,如果美国选定的用于 CCS 或天然气储存的气田和咸水层被用来储存氢气,将会发生什么。

“我们想了解氢气所面临的挑战,由于其密度低、粘度极低的特性,氢气在储层中的移动速度比 CO 2和甲烷快得多。这正是我们所发现的,这意味着我们必须对氢存储采取不同的措施,以便捕获和生产注入的物质,”德尔沙德说。

显示氢迁移到结构顶部的趋势的图表
该图显示了氢气迁移到结构顶部的趋势(称为重力超控),以及需要缓冲气体来支持表面流动压力。
资料来源:美国能源部/地下氢评估、储存和技术加速计划。

这突显了开发商注入的产品可能会简单地迁移出其油井生产区并迷失在储层的遥远角落甚至另一个地层中的风险。漏井是另一个媒介,在枯竭的油田情况下,废弃井眼也是如此。

扎卡里·埃文斯 (Zachary Evans) 指出,在储层岩石中运营 HUS 项目将“比天然气储存复杂几个数量级”,这就是扎卡里·埃文斯 (Zachary Evans) 指出的一些原因。埃文斯是储氢项目的前工程顾问,同时还担任行政主席SPE 氢技术部门的负责人。

在解释他对盐层之外的 HUS 的谨慎看法时,他表示,美国工业界拥有数十年的经验,在全国范围内储存大量天然气,注入并以更高的速度提取天然气,维护这些设施。但说到氢,这一切都只是理论上的。”

肯定有很多障碍。但没有一个被认为是交易破坏者。

怀俄明大学氢能研究主任兼 SPE 氢技术部门项目主席尤金·霍鲁布尼亚克 (Eugene Holubnyak) 承认,HUS 的“未知数多于已知数”。然而,他仍然乐观地认为技术障碍是可以克服的。

“我们为[地下储存]的其他领域找到了很多东西,所以我很确定我们也会在这里找到答案,”他说。

Holubnyak 喜欢指出的是,即使地下复杂性最终得到解决,连接所有经济点以使 HUS 项目从长远来看财务状况良好将是另一回事。

他列举了美国各地的一些天然气储存项目,这些项目已经获得了孔隙空间并获得了所有必要的监管批准,但尚未注入一立方英尺的天然气。

他说,“在某些情况下,这是技术问题,即项目的复杂性,但在其他情况下,市场不存在,因此没有足够的需求”来使项目发挥作用。

绿色司机

根据国际能源署 (IEA) 的数据,2021 年氢气需求量达到 94 公吨,同比增长 5%。但为了保持净零目标的正轨,IEA 认为,到 2030 年,年需求量需要从 2021 年的水平几乎翻一番,达到约 180 公吨。

远不能保证在未来十年内能够实现如此雄心勃勃的目标,但随着大型工业企业尽自己的一份力量,许多人将选择依赖风能或太阳能的所谓“绿色”氢项目运行制氢电解槽。

非营利性巴特尔纪念研究所 (Battelle Memorial Institute) 地能建模和分析技术总监 Srikanta Mishra 最近与人合着了SPE 210372,该书阐述了油藏工程如何成为微调 CCS 和 HUS 项目注入和生产策略的关键。

没有人能说清最终可能需要多少油藏工程师和其他石油技术人员来运营 HUS 方面的清洁能源注入业务。但米什拉表示,如果绿色氢项目“显着增加”,那么它们很可能为具有相关专业知识的人提供第一个就业机会。

“我认为存储需求主要与绿色氢有关,因为可再生能源本质上是间歇性的,”他解释道。“当阳光明媚、有风吹拂时,它们就会发电,有时在需求低迷时,它们最终会产生多余的电力。”

额外的电力可以输送到电解槽,随后将氢气泵入地下,供发电厂在高峰需求时使用。

这种注入/生产周期本质上是季节性的,但一次可能持续数月,这是米什拉认为油藏工程师需要具备规划和建模技能的原因之一。

相比之下,将蒸汽甲烷重整工艺(目前用于生产超过 95% 的氢气)与 CCS 相结合的“烟”氢产量的增长可能会抵消非蓝或“热”氢的使用。 ” 缺乏 CCS 成分的氢气。Mishra 表示,他认为炼油厂和工业场所对蓝氢的需求对 HUS 的需求极小,特别是与 CCS 组件所需的孔隙空间相比。

米什拉还预计,未来氢中心的开发商不会寻求运行长管道,而是将重点放在局部地质目标上。

“因此,展望未来,这将是一个源-汇匹配问题,”他说。“例如,如果您在休斯顿有一个氢项目,那么您会考虑附近是否有盐丘。如果没有,其他潜力可能包括枯竭的气田。”

为枯竭油田辩护

Delshad 最近提出了SPE 210351,其中概述了在枯竭气田与咸水层中储存氢气的一些考虑因素。虽然这两种地层似乎都是适合储氢的地层类型,但这位研究教授认为,天然气储层最终将成为第一个引起商业兴趣的地层类型。

「为什么?」因为你知道你可以从这些储层中生产天然气,而且密封完整性也存在,”她解释道,并补充说气田还可能提供现有的基础设施,可以重新用于生产氢气。然而,考虑到氢气的腐蚀性,这需要高规格的管道和其他设备,这一点还远远不能保证。

但德尔沙德表示,假设选择一个气田来储存氢气,则需要付出额外的努力来确保控制和最佳回收。

她的建模工作开始使用一种简单的策略,仅涉及一个井来注入和生产氢气。这种“气势汹汹”的做法在天然气储存领域相当标准,但德尔沙德表示,这些模型很快就表明,在氢储存方面,这种策略是不经济的。

问题在于,一口井似乎无法抽出足够的水来创造新的孔隙空间,以实现最佳的氢容量。“因此,我再次查看了天然气储存项目,发现其中一些项目使用了额外的生产井,”她补充说,这些生产井会抽取水和天然气。

一方面,其想法是,虽然所需的数量可能有所不同,但生产井将切断氢气迁移的逸出路径,并将其送回油田中心进行再注入,或者进一步输送到下游发电厂。

“在我们建模的每个案例中,这些生产井都有助于减少缓冲气量,同时提高产能、产量和密封性,”德尔沙德解释道。

三种情况不同时期含气饱和度的模型结果比较
比较不同时期三种情况的气体饱和度的模型结果表明,与其他情况相比,氢气可能如何通过气藏中发现的高渗透率通道更深刻地移动。
资料来源:SPE 210351。

提到的缓冲气体对于枯竭的水库和含水层中的 HUS 概念至关重要,因为它将用于维持足够高的压力以按需生产氢气。

在不使用其他气体的情况下,例如需要纯氢气的情况下,一些注入的产品将充当缓冲气体,并在项目期间被视为“不可回收”。如果可以使用另一种气体,例如甲烷,它可能会与产生的氢气混合,并且需要在表面上安装额外的分离系统。

项目运行者的目标是达到所需的提取率或工作气体量所需的最少量的缓冲气体。

相比之下,德尔沙德的研究表明,在平衡含水层或废油田的缓冲层与工作气体比率方面,气藏的性价比最高。权衡是氢气通过气藏的高渗透率基质更广泛地扩散,因此潜在需要战略性的生产井环。

反对枯竭土地的案例

虽然气藏为许多地下工程师提供了熟悉的操作场所,但这恰好是缺点之一。

枯竭油田引起的担忧之一是,根据定义,它们拥有现有的井眼,每个井眼都代表着通往地面的潜在通道。这与一些 CCS 开发商完全避免使用枯竭油田而转而使用含水层的原因相同。

埃文斯更进一步,支持 HUS 的几乎不可渗透的盐丘地层,他质疑天然气储存是否应该被视为多孔介质中 HUS 的良好类似物。

“我无法强调氢分子有多小,所以你真的会担心对天然气有利的密封陷阱是否对氢也同样有利,”他说。

埃文斯承认,他对水库 HUS 的看法可能有些悲观,但他表示,他并不反对这个概念。

“在申请方面我非常务实,”他说。“目前,研究人员仍在解决许多悬而未决的问题,最终,当长期试点启动时,这些问题必须由现实来回答。”

虽然先前关于密封完整性的观点同样适用于未勘探的含水层,但专家们仍在关注它们,因为它们比枯竭的含水层拥有几个关键优势。

首先,这些含盐水岩石通常不存在可以代表泄漏路径的井筒。除此之外,咸水含水层的总体容量可能比枯竭的油田更大。

米什拉认为,这足以让一些项目运营者考虑含水层,因为“在枯竭的油田中,你所能做的就是替换已产生的碳氢化合物,并将孔隙空间填充回原来的储层压力。”

超过这个阈值(称为断裂梯度)意味着存在为逃逸氢气创建新泄漏路径的风险。

关于不良反应

除了迁移之外,部分氢也可能会在岩石基质本身内损失,或者如果它与储层内仍然存在的物质发生反应。

岩石中的硫脉或残留液体中的颗粒,与氢气接触时可能会产生有毒的硫化氢气体。如果没有发生重大泄漏,这是任何存储项目中最不理想的结果之一。短期风险包括氢损失,而长期风险可能涉及地层完整性,例如盖层完整性。已知存在于储层中的微生物群落也可能以注入的一小部分氢气为食。

Holubnyak 目前正在与各利益相关者合作,争取美国联邦资金,用于跨越科罗拉多州、新墨西哥州、犹他州和怀俄明州的一系列综合氢中心。他表示,反应性问题确实提高了项目开发商在场地特征描述方面的门槛,但他表示,他们实际上不需要重新发明轮子。

“如果 [HUS] 与 CCS 类似,并且在很多方面都是如此,那么您将必须挖掘更多的储层信息并向监管机构证明存储概念,”他说。“我们可能需要从新井收集新信息,因此所有这些都需要支付额外费用。虽然价格昂贵,但可行。”

虽然氢的不良反应被认为比处理二氧化碳时的风险更大,而且比处理甲烷的风险要大得多,但米什拉认为,严重问题的可能性是“极其特定于地点的”,并且可以通过适当的储层来缓解学习。

也就是说,他确实认为这个问题几乎排除了使用枯竭的油藏来储存氢气,因为它们可能比气藏或含水层含有更多容易发生负面反应的物质。

另一个潜力是,地层中存在的某些微生物会消耗氢气,并且随着更多的氢气被泵入井下,实际上可以促进生物活性。

需要更多的研究来了解这一挑战的真正范围,但米什拉表示,目前所知的情况表明,生物活动造成的损失相对较小。他确实认为有必要解决的一个行业缺陷是,虽然生物反应背后的过程已经被明确定义,但“嘿”还没有完全理解到我们可以高度确定地对其进行建模的程度。

在所有氢可能发生的反应中,最重要的可能是钢铁和其他材料(例如用于区域隔离的水泥)的腐蚀和脆化。

埃文斯说:“氢气会吃掉管道。”他补充道,“这是一个已知的量,而不是理论上的问题。”他承认,虽然存在用于氢气处理的产品,但仍然需要更多地了解它们的长期应用。期限耐久性。

这方面有关材料完整性的大部分经验都来自炼​​油行业,炼油行业是世界上最大的氢气生产商和消费国。

但正如埃文斯强调的那样,“炼油行业所没有的一件事就是数千英尺长的井下套管,它 100% 的寿命都处于富氢环境中。”

供进一步阅读

SPE 210372 将石油储层工程原理应用于碳捕集与封存 (CCS) 和氢地下储存 (HUS) 项目:机遇与挑战,作者: Srikanta Mishra(巴特尔纪念研究所)和 Akhil Dattaupta(德克萨斯 A&M 大学)。

能源 2022,枯竭油藏和咸水层储氢评估,作者: 德克萨斯大学奥斯汀分校的 Mojdeh Delshad、Yelnur Umurzakov、Kamy Sepehrnoori、Peter Eichhub 和 Bruno Ramon Batista Fernandes。

SPE 210351 咸水含水层与氢能储存枯竭碳氢化合物储层的优缺点 作者: Mojdeh Delshad、Muhammad Alhotan、Bruno Ramon Batista Fernandes、Yelnur Umurzakov 和 Kamy Sepehrnoori,德克萨斯大学奥斯汀分校。

《如何利用勘探与生产专业知识促进新能源经济》作者:Srikanta Mishra(巴特尔纪念研究所)和 Akhil Datta-upta(德克萨斯农工大学), JPT,2023 年 4 月。

原文链接/jpt
Reservoir

The Uncertain Bright Future of Underground Hydrogen Storage

Building up the world’s hydrogen base will need technological breakthroughs and a lot of new demand. But to store it, the world needs reservoir engineers and other subsurface experts.

A comparison of modeled gas saturations
A comparison of modeled gas saturations of CO2 (left) and hydrogen (right) at the end of injection. The work underlines the likelihood of hydrogen spreading within porous media.
Source: Energies 2022/The University of Texas at Austin

The most obvious obstacles to a big ramp‑up in global hydrogen production are well known. They include technological breakthroughs to bring down production costs along with new sources of demand from the power and transportation sectors.

Less obvious is that a small army of reservoir engineers, geologists, and other subsurface experts will be needed to understand where and how tomorrow’s hydrogen hubs will store their clean-burning fuel.

Bulk storage on the surface is considered by many experts to be simply out of the question. That means large hydrogen projects will need a subsurface component, and some think depleted oil and gas fields—with an emphasis on the latter—may fit the bill. Saline aquifers are being eyed for the role too.

But as this all suggests, no one has ever attempted to use these formations for hydrogen storage. Just four shallow salt formations, three salt domes in Texas and one salt field in the UK, represent the totality of the world’s hydrogen underground storage (HUS) capacity.

Experts consider any golden age of hydrogen production to be highly dependent on scaling up the use of salt formations or depleted gas fields as storage systems.
Experts consider any golden age of hydrogen production to be highly dependent on scaling up the use of salt formations or depleted gas fields as storage systems.
Source: TNO, Netherlands.

Research is underway to expand HUS in salt formations but that will not solve for the fact that they are not a geologic option for many locations where big industrial players are hoping to produce hydrogen. This includes most of Europe and most of the US outside of its Gulf Coast states.

By contrast, deeper sedimentary structures of various flavors are in no short supply but lack any material field experience that might help jumpstart the de-risking of storing several Bcf of hydrogen.

The upstream industry’s extensive experience in operating what are the closest analogues—natural gas storage and carbon capture and storage (CCS)—will help that process but there are new challenges when it comes to injecting the universe’s smallest molecule into porous media.

Topping the list is hydrogen’s strong propensity to migrate inside a reservoir (laterally and vertically) along with the potential for troublesome chemical and biological reactions.

Hydrogen may also be clean burning but it offers only about a third of the energy density as methane, which means it needs roughly three times the storage volume to deliver the same energy output to a gas-fired power plant.

Among those working to bring clarity to such issues is Mojdeh Delshad, a reservoir engineer and professor at The University of Texas at Austin. Her latest research involved using commercial reservoir simulators to model what would happen if selected gas fields and saline aquifers in the US used for CCS or natural gas storage were instead used to store hydrogen.

“We wanted to know about the challenges of hydrogen, which because of its properties—very low density, very low viscosity—is going to move in the reservoir much more quickly than CO2 and methane. And that’s exactly what we found, which means we’re going to have to do something differently with hydrogen storage in order to capture and produce what is injected,” said Delshad.

diagram showing the tendency of hydrogen to migrate to the top of a structure
A diagram showing the tendency of hydrogen to migrate to the top of a structure, known as gravity override, and the need for cushion gas to support flowing pressures on the surface.
Source: US Department of Energy/Subsurface Hydrogen Assessment, Storage, and Technology Acceleration program.

This highlights the risk that a developer’s injected product may simply migrate out of their well’s production zone and become lost somewhere in the distant corners of a reservoir or even in another formation. Leaky wells are another vector as are abandoned wellbores in a depleted field scenario.

These are some of the reasons why Zachary Evans noted that operating a HUS project in reservoir rock will be “orders of magnitude more complex than natural gas storage.” Evans is a former engineering consultant for hydrogen storage projects and also serves as administrative chairperson of SPE’s Hydrogen Technical Section.

In explaining his cautious view on HUS outside of salt formations, he said the US industry holds many decades “of experience in storing high volumes of natural gas all across the country, injecting it, and withdrawing it at higher rates, maintaining those facilities. But when it comes to hydrogen, it’s all theoretical.”

Plenty of hurdles for sure. But none are deemed deal breakers.

Eugene Holubnyak, director of hydrogen energy research at the University of Wyoming and program chairperson of SPE’s Hydrogen Technical Section, acknowledged “there are more unknowns than knowns” with HUS. And yet, he remains optimistic that the technical obstacles are surmountable.

“We figured out a lot of things for other areas [of subsurface storage], and so I am pretty sure we will figure it out here too,” he said.

What Holubnyak likes to point out is that even as the subsurface complexities are eventually addressed, it will be another thing to connect all the economic dots to make a HUS project financially sound over the long term.

He cited a number of natural gas storage projects around the US that have acquired pore space and received all the necessary regulatory approvals but that have yet to inject a single cubic foot of gas.

“In certain cases, it’s the technical issues, that is the complexity of the project, but in other cases the market is not there, so there is not enough demand,” to make the project work, he said.

The Green Driver

Demand for hydrogen hit 94 Mt in 2021, which marked a 5% year-over-year increase, according to figures from the International Energy Agency (IEA). But in order to stay on track with net-zero goals, the IEA believes annual demand needs to almost double from 2021 levels to about 180 Mt by 2030.

It’s far from guaranteed that such an ambitious target can be met over the next decade, but as big industrial players do their part, many will opt for so-called “green” hydrogen projects that rely on wind or solar power to run hydrogen-producing electrolyzers.

Srikanta Mishra, the technical director of geo‑energy modeling and analytics for the nonprofit Battelle Memorial Institute, recently coauthored SPE 210372 which speaks to how reservoir engineering will be key to fine tuning the injection and production strategies of CCS and HUS projects.

No one can say how many reservoir engineers and other petrotechnicals might end up being needed to run the HUS side of the clean energy injection business. But Mishra said if there is a “significant bump up” in green hydrogen projects, then they are likely to provide the first job openings for those with relevant expertise.

“I think the storage requirements are primarily with respect to green hydrogen because the renewable power sources are intermittent in nature,” he explained. “When the sun shines, when the wind blows, they generate power and sometimes they end up generating surplus electricity when there’s low demand.”

It’s that extra power that can be routed to the electrolyzers and the subsequent hydrogen pumped into the subsurface for later use at a power plant during peak demand.

Such injection/production cycles would be seasonal in nature but could last for months at a time, which is one reason Mishra sees a need for the planning and modeling skills held by reservoir engineers.

By contrast, growth in “blue” hydrogen production, which combines the steam methane reforming process (used to make >95% of all hydrogen today) with CCS, will likely just offset the use of the non-blue or “grey” hydrogen that lacks the CCS component. This is according to Mishra, who sees blue hydrogen’s demand from refineries and industrial sites as creating minimal need for HUS, especially when compared with the pore space needed for the CCS components.

Mishra also expects the developers of future hydrogen hubs will not be looking to run long pipelines and will instead focus on localized geologic targets.

“So, as you look ahead, it’s going to be a source-sink matching issue,” he said. “If you have a hydrogen project in Houston for example, then you think about whether there are any salt domes nearby. If not, other potentials might include a depleted gas field.”

Making a Case for Depleted Fields

Delshad recently presented SPE 210351 which outlines some of the considerations of storing hydrogen in depleted gas fields vs. saline aquifers. While both appear to be suitable formation types for hydrogen storage, the research professor believes natural gas reservoirs will end up being the first to draw commercial interest.

“Why? Because you know that you can produce gas from these reservoirs and the seal integrity is there,” she explained, adding that a gas field might also offer existing infrastructure that could be repurposed for hydrogen. However, this is far from assured given the corrosive nature of hydrogen which demands high-spec pipelines and other equipment.

But assuming a gas field is selected for hydrogen storage, Delshad said it will require an extra effort to ensure both containment and optimal recovery.

Her modeling efforts began using a simple strategy involving only a single well for both the injection and production of hydrogen. This version of huff ’n’ puff is fairly standard in the world of natural gas storage, but Delshad said the models quickly showed the strategy to be uneconomic across the board when it comes to hydrogen storage.

The problem is that one well doesn’t appear to allow enough water to be pumped out to create new pore space for optimal hydrogen capacity. “So, I looked at natural gas storage projects again and found that some of them use additional producer wells,” which draw out both water and gas, she added.

In one respect, the idea is that while the number needed may vary, the producer wells will cut off the escape paths for migrating hydrogen and either sending it back to the center of a field for reinjection or further downstream to a power plant.

“In every case we modeled, these producer wells helped reduce the cushion gas volume while improving the capacity, production, and confinement,” explained Delshad.

Model results comparing the gas saturation of three cases over different periods
Model results comparing the gas saturation of three cases over different periods show how hydrogen is likely to move through high-permiability channels found in gas reservoirs more profoundly compared with the other cases.
Source: SPE 210351.

The cushion gas mentioned is key to the HUS concept in both depleted reservoirs and aquifers since it will be what’s used to maintain high-enough pressures to produce hydrogen on demand.

In cases where no other gas is used, such in those where pure hydrogen is desired, some of the injected product will serve as a cushion gas and be deemed “unrecoverable” for the duration of the project. In the event another gas can be used, such as methane, it may mix with the produced hydrogen and require additional separation systems on the surface.

What project runners will aim for is the minimal amount of cushion gas required to hit desired withdrawal rates, or the working gas volume.

In terms of comparisons, Delshad’s research suggests gas reservoirs offer the biggest bang for the buck in terms of balancing this cushion to working gas ratio over either aquifers or spent oil fields. The tradeoff is a more profound spreading of hydrogen through a gas reservoir’s high permiability matrix, hence the potential need for a strategic ring of producer wells.

The Case Against Depleted Fields

While gas reservoirs provide a familiar operating arena for many subsurface engineers, that happens to be one of the downsides.

One of the concerns raised with depleted fields is that by definition they have existing wellbores, each one representing a potential pathway to the surface. This is the same reason some CCS developers are avoiding depleted fields altogether in favor of aquifers.

Going a step further, Evans, who champions the nearly impermeable salt dome formations for HUS, questioned whether natural gas storage should even be considered a good analogue for HUS in porous media.

“I can’t stress just how small the hydrogen molecule is and so you’re really going to be worried about whether a sealing trap that’s good for natural gas will be equivalently good for hydrogen,” he said.

Evans admits that his views on HUS in reservoirs may come off as pessimistic but he said he’s not rooting against the concept.

“I’m just very pragmatic when it comes to the application,” he said. “Right now there are a lot of unanswered questions that researchers are still tackling and that, ultimately, will have to be answered by reality when a long-term pilot is initiated.”

While the prior point on seal integrity could be equally applied to unexplored aquifers, experts are nonetheless looking at them too since they hold a couple of key advantages over depleted fields.

The first is that these saltwater-bearing rocks generally have no existing wellbores that could represent leak paths. Beyond that, saline aquifers may offer bigger overall capacities than depleted fields.

Mishra argues this is reason enough for some project runners to consider aquifers since “in a depleted field all you can do is replace the hydrocarbons that have been produced and fill up the pore space back to the original reservoir pressure.”

Exceeding that threshold, known as the fracture gradient, means risking the creation of new leak paths for fugitive hydrogen.

On Bad Reactions

Aside from migration, some portion of hydrogen might also be lost within the rock matrix itself or if it reacts with what’s still inside the reservoir.

Veins of sulfur in the rock or particles inside residual fluids, could upon contact with hydrogen, generate toxic hydrogen sulfide gas. Short of a major leak, this is one of the least desirable outcomes of any storage project. Short-term risks include hydrogen losses while long-term risks may involve formation integrity, e.g., caprock integrity. Microbial communities known to exist in reservoirs may also feast on some small share of the injected hydrogen.

Holubnyak is currently working with various stakeholders on obtaining US federal funding for a series of integrated hydrogen hubs spanning Colorado, New Mexico, Utah, and Wyoming. He said the reactivity issue does raise the bar for project developers when it comes to site characterization but said they won’t exactly have to reinvent the wheel.

“If [HUS] is anything like CCS, and in a lot of respects it is, then you will have to dig for a lot more reservoir information and prove the storage concept to the regulatory agency,” he said. “We will probably need to gather new information from new wells, and so all of this comes at an additional cost. It is expensive, but it’s doable.”

While bad reactions to hydrogen are considered to be a bigger risk than when dealing with CO2, and much more so than with methane, Mishra argues that the potential for serious problems are “extremely site-specific” and will be mitigated through proper reservoir study.

That said, he does think that the issue pretty much rules out the use of depleted oil reservoirs for hydrogen storage since they are likely to have more substances prone to a negative reaction than either a gas reservoir or an aquifer.

The other potential is that certain microbes present in the formation will consume the hydrogen and could in fact promote biological activity as more hydrogen is pumped downhole.

More research is needed to understand the true scope of this challenge, but Mishra said what’s known today suggests losses due to biological activity would be relatively minor. One industry shortcoming he does see necessary to address is that while the processes behind biological reactions are well defined, “they’re not fully understood to a point where we can model them with a great degree of certainty.”

What may end up being the most important of all hydrogen’s possible reactions is corrosion and embrittlement of steel and other materials such as the cement used for zonal isolation.

“Hydrogen will eat pipe,” said Evans, adding “that’s a known quantity, not a theoretical concern.” He acknowledged that while products rated for hydrogen-handling exist, there remains more to learn about their long-term durability.

Most of the learnings on material integrity in this regard come from the refining industry which counts as both the world’s largest producer and consumer of hydrogen.

But as Evans highlighted, “The one thing the refining industry doesn’t have is several thousand feet of downhole casing that’s in a hydrogen-rich environment for 100% of its life.”

For Further Reading

SPE 210372 Adapting Petroleum Reservoir Engineering Principles to Carbon Capture &Sequestration (CCS) and Hydrogen Underground Storage (HUS) Projects: Opportunities and Challenges by Srikanta Mishra, Battelle Memorial Institute, and Akhil Datta‑Gupta, Texas A&M University.

Energies 2022, Hydrogen Storage Assessment in Depleted Oil Reservoir and Saline Aquifer by Mojdeh Delshad, Yelnur Umurzakov, Kamy Sepehrnoori, Peter Eichhub, and Bruno Ramon Batista Fernandes, The University of Texas at Austin.

SPE 210351 Pros and Cons of Saline Aquifers Against Depleted Hydrocarbon Reservoirs for Hydrogen Energy Storage by Mojdeh Delshad, Muhammad Alhotan, Bruno Ramon Batista Fernandes, Yelnur Umurzakov, and Kamy Sepehrnoori, The University of Texas at Austin.

How To Leverage E&P Expertise for the New Energy Economy by Srikanta Mishra, Battelle Memorial Institute, and Akhil Datta‑Gupta, Texas A&M University, JPT, April 2023.