Hydrogen will be crucial for powering energy hubs like Pennsylvania in the future. Here, we provide the first geological hydrogen storage resource assessment for the Commonwealth. We validate existing methods for estimating the pore volume available for hydrogen storage in hydrocarbon gas pools using industry-reported data. We estimate that Pennsylvania gas pools can store 1979 TWh ( c . 59 Mt) of hydrogen working gas, which is ample storage potential for a hydrogen economy in the state. We evaluate the physical and chemical attributes of these pools to compare their efficacy for hydrogen storage. Fifty-three large, dry-gas, high-pressure, high-temperature pools in sedimentary units with favourable mineralogy and water chemistry could be particularly effective hydrogen storage sites. This work will help hydrogen development to proceed in a state that requires large quantities of energy storage and fuel in the future.

This user's manual guides the use of the National Energy Technology Laboratory's (NETL) CO2 Storage prospeCtive Resource Estimation Excel aNalysis (CO2-SCREEN) tool, which was developed to aid users screening geologic formations for prospective CO2 storage resources. This manual is specific to the CO2-SCREEN 5.0 version which is based in Python. The 5.0 version of CO2-SCREEN adds in newly updated storage efficiency factors for saline formations for open storage reservoirs and new capability to calculate CO2 storage in closed and semi-closed storage reservoirs.

Carbon storage technology is primarily targeted in saline formations, which is a porous rock matrix filled with brine, sealed with a low permeability caprock. There are significant variations of CO2 wetting properties, typically reported in the literature as contact angle of CO2 and brine interacting with a rock material, suggesting that CO2 could become wetting under geostorage conditions and negatively impact containment effectiveness. Here, we performed the first controlled laboratory measurements of CO2‐brine contact angles on shale rocks from low permeability sealing formations with distinctive mineralogic properties—calcite‐rich, quartz‐rich, and dolomite‐rich. We targeted temperatures at 40° and 100°C, pressures at 8.3, 34.5, and 62.1 MPa, and salinity at 35,000 and 260,000 ppm. Results show no significant change in contact angle with mineralogy, temperature, pressure, salinity, and CO2 bubble size. We conclude that caprocks will remain water‐wet at geologic CO2 storage conditions and will not lose their capillary sealing capacity.

Seasonal storage of natural gas (NG), which primarily consists of methane (CH4), has been practiced for more than a hundred years at underground gas storage (UGS) facilities that use depleted hydrocarbon reservoirs, saline aquifers, and salt caverns. To support a transition to a hydrogen (H2) economy, similar facilities are envisioned for long-duration, underground H2 storage (UHS) of either H2 or H2/CH4 mixtures. Experience with UGS can be used to guide the deployment of UHS, so we identify and quantify factors (formation/fluid properties and engineering choices) that influence reservoir behavior (e.g., viscous fingering and gravity override), the required number of injection/withdrawal wells, and required storage volume, contrasting the differences between the storage of CH4, H2, and H2/CH4 mixtures. The most important engineering choices are found to be the H2 fraction in H2/CH4 mixtures, storage depth, and injection rate. Storage at greater depths (higher pressure), but with relatively lower temperature, is more favorable because it maximizes volumetric energy-storage density, while minimizing viscous fingering and gravity override due to buoyancy. To store an equivalent amount of energy, storing H2/CH4 mixtures in UHS facilities will require more wells and greater reservoir volume than corresponding UGS facilities. We use our findings to make recommendations about further research needed to guide deployment of UHS in porous reservoirs.

Abstract Underground hydrogen storage is a long‐duration energy storage option for a low‐carbon economy. Although research into the technical feasibility of underground hydrogen storage is ongoing, existing underground gas storage (UGS) facilities are appealing candidates for the technology because of their ability to store and deliver natural gas. We estimate that UGS facilities in the United States (U.S.) can store 327 TWh (9.8 MMT) of pure hydrogen. A complete transition to hydrogen storage would reduce the collective working‐gas energy of UGS facilities by ∼75%; however, most (73.2%) UGS facilities could maintain current energy demand using a 20% hydrogen‐natural gas blend. U.S. UGS facilities can buffer 23.9%–44.6% of the high and low hydrogen demand projected for 2050, respectively, which exceeds the current percentage of natural gas demand buffered by storage. Thus, transitioning UGS infrastructure to hydrogen could substantially reduce the number of new hydrogen storage facilities needed to support a hydrogen economy.

Geologic carbon storage (GCS) is a rapidly evolving technology with the potential to reduce the environmental impact of fossil fuel usage. Saline aquifers, which comprise a sandstone matrix with brine contained in the pores, make up much of the pore space available for CO2 storage in the United States. When CO2 is injected in saline aquifers, however, capillary fingering occurs, and only a small percentage of the pore space is filled with CO2. This fingering effect is due to the low viscosity of CO2, which is roughly ten times less viscous than brine. To address this problem, we tested the ability of inexpensive, commercially available nonionic surfactants to be dissolved in injected CO2 and increase the apparent viscosity of CO2 by generating CO2-in-water foams in situ. We focused our study on nonionic tridecyl ethoxylate surfactants with the number of ethoxylate groups ranging from 11 to 18 (TDA-11, TDA-13, TDA-15, TDA-18). These surfactants exhibited sufficient CO2-solubility and were shown to reduce the CO2-brine interfacial tension (IFT), stabilize bulk CO2-in-brine foams, and reduce the mobility of CO2 during core floods of CO2 in brine-saturated Berea sandstone. The surfactants did not alter the wettability of the Berea sandstone. Modeling results showed that in a reservoir field injection scenario, the presence of TDA-11 (0.1 wt %) increased both the CO2 storage resource and storage efficiency by 17%. Simulations also showed that the lateral extension area of the plume was reduced by 23% and that CO2 saturation within the plume increased by 26%.

The U.S. Department of Energy’s National Energy Technology Laboratory (DOE-NETL) has been developing methods and tools (the online Carbon Dioxide Storage prospeCtive Resource Estimation Excel aNalysis (CO2-SCREEN) tool) to estimate carbon dioxide (CO2) storage potential in subsurface reservoirs. The CO2 storage efficiency terms are input in the tool to calculate storage potential in targeted reservoirs. In this effort, two CO2 storage efficiency terms were evaluated: volumetric displacement (EV) and microscopic displacement (Ed). The first term deals with efficiency of CO2 propagation into an accessible reservoir volume, while the second term evaluates effectiveness of native fluid displacement with CO2. The interpreted well logs and core sample measurements were applied to create the heterogeneous reservoir models including geostatistical realizations of porosity and intrinsic permeability fields. Supercritical CO2 was injected over the course of 30 years into brine-saturated reservoir models for clastics, limestone, and dolomite lithologies and deltaic fluvial, aeolian, shallow marine, and reef depositional environments by means of varying reservoir parameters and injection scenarios. The reservoir models providing vertically heterogeneous petrophysical properties and designated as “layered reservoir models” (with homogeneous parameters along each layer of the model) were not determined to be a transition between the homogeneous and heterogeneous models in respect to storage efficiency. Another finding shows that high-efficiency factors do not necessarily mean increased CO2 storage; they rather indicate that the available volume and pore space are more fully utilized. The CO2 storage efficiency factors were evaluated dynamically at the select time points using P10‐P50‐P90 percentiles. The results of this study show that the P10‐P90 distribution for volumetric efficiency is wider when compared to the microscopic efficiency. It was found that where dominant buoyancy forces drive the plume to the top of a target formation, the volumetric efficiency is low. Tighter sandstone and carbonate formations show prevalence of capillary forces and better utilization of reservoir volume.

压裂后的页岩、致密砂岩等非常规油气储层的一次采收率通常低于10％.开发一种经济可行、适用于非常规油气储层(ULR)的提高石油采收率(EOR)技术将导致美国石油产量大幅增长.近几十年,水驱和注CO2提高采收率等注入技术已被证实在常规地层中有良好的经济效益,但提高采收率技术在非常规油气储层中的应用仍面临着一些严峻挑战,其中非常规油气储层的极低渗透率和混合润湿性是该技术成功应用的首要障碍.由于页岩中水基提高采收率技术(也称为化学EOR)面临的挑战,因此也考虑将CO2、天然气和(较小程度的)氮气在内的一些非水注入流体应用于增产技术.这些流体的粘度均远低于水,因此相比水更容易进入页岩纳米孔.与水不同的是,这些气体具有一定程度的混溶性,使其能够通过一种组合机制来抽提石油.基于实验室规模的实验,认为CO2和富气(含高浓度乙烷、丙烷和丁烷的富甲烷天然气)是最有利的提高采收率流体.Bakken和Eagle Ford地层现场试验结果的解释由于附近油井水力压裂引起的压裂或冲井的干扰而变得复杂.这篇综述涵盖了注高压CO2、天然气、乙烷、氮气和水的提高采收率机理、室内实验、数值模拟和现场试验等相关研究进展.

reliability of wells for hydrocarbon extraction and underground injection in the oil and gas industry. Yet, important innovation is required to improve and ensure well integrity performance in engineered geologic systems where operational environments (fluid composition, temperature, pressure, and/or stress conditions) and long functional life cycles of well systems present unique challenges. Additionally, work is needed to understand and manage the long-term integrity and risks associated with legacy wells—especially those located adjacent to and presenting hazards for new subsurface activity. To identify new areas where focused research can yield new insights to improve integrity and extend the operational life of wells in geologic carbon storage, natural gas storage, hydrogen storage, and geothermal energy production settings, the U.S. DOE's National Energy Technology Laboratory (NETL) organized and hosted a workshop on well integrity research needs. This technical report summarizes proceedings of the NETL Well Integrity Workshop and highlights key identified needs for future research. It is expected that this report will serve as a resource for the U.S. DOE Office of Fossil Energy and Carbon Management (FECM), U.S. DOE FECM stakeholders, and the international research, development, and deployment community—helping to set research plans and performance goals that will improve well integrity performance and stakeholder confidence.

Saline formations are attractive geologic reservoirs for permanent carbon dioxide (CO2) storage. The U.S. Department of Energy's National Energy Technology Laboratory (DOE-NETL) has worked to develop and refine methods and tools for the calculation of CO2 storage potential in subsurface reservoirs. DOE-NETL's CO2-SCREEN provides an online tool for executing these storage methods. CO2 storage efficiency terms are input parameters in DOE-NETL's methods and equations embedded in the CO2-SCREEN, which assesses pore space available for CO2 storage. In this work, a modeling workflow was initiated to refine two CO2 storage efficiency terms - volumetric displacement (EV) and microscopic displacement (Ed). The models are based on new experimental relative permeability data that are specific to homogenous lithology and depositional environments of key subsurface saline formations targeted for CO2 storage. In future work, heterogenous features will be added to this initial modeling effort to update efficiency factors as described in DOE-NETL's methods and CO2-SCREEN tool. EV accounts for the volume utilized in the reservoir under the areal plume, while Ed accounts for saturation values in the plume to assess efficiency of CO2 storage at the pore scale. The results of this work are significant in that prior values were based on a limited geologically non-specific relative permeability data set that were collected prior to 2009. Specifically, we applied numerical simulations using TOUGH3 models to update CO2 storage efficiency values for supercritical CO2 injection into brine-saturated reservoirs for three lithologies (clastics, limestone, dolomite) and six depositional environments (Marginal Marine, Strand Plain, Deltaic Complex Fluvial, Aeolian, Shallow Marine, and Reef) that have a high potential for geologic CO2 storage. Experimental relative permeability data in cores from these environments were utilized in the models with corresponding rock type/sedimentary environment. Results of this study showed that dolomite followed by limestone generated higher ranges of storage efficiency compared to clastics. The updated values provided a tighter efficiency range for clastics, lower P10 but higher P90 range for limestone, and higher P10 and P90 for dolomite. In general, tighter reservoirs with relatively low permeability and porosity were associated with higher EV and Ed, showing efficient reservoir and pore utilization in these scenarios. High reservoir pressure and temperature associated with increasing depth increased the EV, and high CO2 injection rates resulted in increases in EV and Ed, while the impact of permeability anisotropy was minimal after the 30-year injection period.