bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Robust Method to Distinguish Oil and Gas in Depleted Reservoirs: Success Implementation in Oseberg Sor field
Authors: Yerkinkyzy Gulnar , Donnadieu Sandrine , Bravo Maria Cecilia , Ungar Frode , Fristad Paal , Bekkouche Yasmine , Yang Tao 
Published: June 2024

Abstract
Hydrocarbon phase determination in depleted fields has been a major challenge. This main uncertainty affects completion decisions and, consequently, oil recovery. As the field matures, the reservoir fluids start to exist in a two-phase configuration due to gas released from reservoir oil or gas trapped due to aquifer movements during production. A traditional petrophysical evaluation, neutron density separation, can mislead under such conditions. An oil reservoir can be interpreted as gas by showing a big separation in neutron density logs. However, a fundamental question arises: Are these apparent "gas zones" genuinely filled with free gas, or could a substantial portion contain oil?
This paper introduces an integrated work process between petrophysical logs and Gas Oil Ratio (GOR) prediction based on advanced mud gas, as well as historical fluid samples and field production history. The effectiveness of this method is demonstrated through a case study from the Oseberg Sor field, a late-life production field on the Norwegian Continental Shelf. The fluid identification technology based on mud gas data predicts a large oil saturation in reservoirs. In contrast, interpretations derived from conventional petrophysical logging tend to overemphasize minimal gas saturation and incorrectly predict the reservoir fluid type. This critical interpretation from mud gas has enabled the completion of the well in the oil zone. With the successful implementation of this innovative approach, questionable "gas zones" is reinterpreted as oil zones, making them viable production prospects.
The integrated methodology reveals a robust solution for a longstanding industry challenge and emphasizes incorporating a comprehensive understanding of petrophysical logs, advanced mud gas (AMG) data, and PVT data from nearby wells. This approach remains unaffected by minor quantities of released or entrapped gas within reservoirs, offering the potential to complete a higher number of oil zones for production. Given the increasing activity in matured fields, the business value of this innovative method is substantial.
An Extended JBN Method to Determine the Flow Function and Relative Permeabilities from Composite Core Flooding Experiments – Preliminary Results
Authors: Andersen P. Ø. 
Published: June 2024

Abstract
Core flooding is a standard experiment where for example water is injected to displace oil, and the production, pressure drop, efficiency and ultimate recovery of the process are parameters of interest. Transient pressure drop, and production data can be used to calculate relative permeability functions characterizing the porous media. An analytical technique for this calculation is the JBN method, which assumes immiscible, incompressible fluids, a homogeneous system and negligible capillary and gravity forces. These conditions may be met for oil-water systems flooded at high rate or in long horizontal cores. However, in many cases, composite cores are used experimentally, i.e. several short cores with different properties (lengths, porosities and permeabilities) are put together to form one long core during flooding. The JBN method then calculates incorrect relative permeabilities.
This work derives theory for an extended JBN method to interpret unsteady state flooding experiments of composite cores accounting for the spatial variation in core properties. The method calculates outlet saturation, fractional flow function and relative permeabilities based on production and pressure drop data, for a composite core with known porosity and permeability distribution.
The saturation profile in the composite core can be calculated by taking the Buckley Leverett profile of a uniform core and converting the spatial axis. Assuming negligible capillarity and compressibility, the saturation profiles in composite cores depend on the porosity distribution, not the permeabilities. However, a saturation arrives at the outlet after the same number of pore volumes injected, regardless of porosity distribution. Thus, the resulting breakthrough, producing flow fraction, average saturation and outlet saturation reported in terms of pore volumes injected are the same and only depend on the fractional flow function. The fractional flow function can be estimated accurately between the front saturation and the highest obtained outlet saturation from composite core flooding experiments. The method is validated on synthetical data using CO2-water primary drainage literature curves where the relative permeability curves.
Migration, Leakage, and the EU Directive on Geological Storage of Carbon Dioxide
Authors: Harrison B. , Falcone G. 
Published: June 2024

Abstract
An escape of injected carbon dioxide (CO2) from a subsurface storage site is not a leak according to the Council and Parliament of the European Union (EU), who suggest it is migration of CO2 into the surrounding storage complex. This definition is given in the EU Directive 2009/31/EC for geological storage of CO2, which has been adopted and adapted by the countries that border and operate in the North Sea. However, when assessing the potential capacity of a deep saline aquifer of large areal extent, how do stakeholders delineate the storage complex? Can the monitoring grid size change over time? And how might this impact the monitoring of the injected CO2 volume? From data available in the public domain, and from discussions with a Norwegian Operator and the Regulator of Norway, the authors explore the assumptions and perceptions of the storage potential and containment risks of identified sites in the North Sea. Examples are given of a pre-FEED project and an ongoing storage project in the region and how the risk of lateral containment of the injected CO2 is perceived and how it may be mitigated. With only a limited database of examples, it is a challenge to assign values to the likelihood of CO2 leakages occurring. This paper offers some suggestions on how the directive on the geo-sequestration of CO2 might be improved to define a storage site vs. a storage complex, leveraging lessons learnt from case studies which now exist.
Pulsed Neutron Logging for Underground Hydrogen Storage Monitoring in Depleted Reservoirs
Authors: Pirrone M. , Machicote S. , De Lisio S. 
Published: June 2024

Abstract
This paper deals with the quantitative evaluation of the diagnostic capability of various cased-hole Pulsed Neutron Logging (PNL) measurements for fluid identification and saturation monitoring purposes in Underground Hydrogen Storage (UHS) projects. The main target are depleted reservoirs. The methodology aims at properly understanding hydrogen plume development far from the injector/withdrawal wells, discriminating working and cushion gases, and early detecting undesired leaks at the so-called spy-wells.
The starting point is the analytical and numerical modeling of typical PNL responses of mixtures of water, cushion gas, reservoir gas and hydrogen. These sensitivities include fast neutron interactions, inelastic/elastic scatterings, and capture, together with their dependence on pressure, temperature, and acquisition environment. In detail, fit-for-purpose curves and their physics-based models are selected. Next, a joint inversion is performed to reconcile models and actual measurements to solve for the different desired volume fractions. Moreover, the uncertainty of the outputs is also quantified by means of an ad-hoc Monte Carlo approach, propagating the standard uncertainties of the input PNL data.
A case study of PNL monitoring in a possible usage scenario is discussed for a selected depleted gas reservoir where hydrogen charge/discharge numerical modeling has been performed. Several PNL simulations have been carried out to forecast the deviation from pre-injection baselines during the injection/production cycles. These encompass the expected plume behavior, its variable composition, possible changes in water saturation, and the different pressure/temperature regimes coming from the available dynamic reservoir model. Therefore, random errors have been generated for the simulated PNL curves to be used for the subsequent uncertainty quantification in obtaining water saturation and reservoir/cushion gas-hydrogen relative concentrations, mimicking future time-lapse interpretations. The latter represents a useful template to understand the real PNL capabilities in such environment and the best subset of neutron interactions to exploit for the purpose of plume monitoring, characterization and, if needed, leak detection.
This novel approach is the very first deep study on the potentiality of selected cased-hole logs for hydrogen monitoring. In addition, the outcomes are fundamental for several aspects in UHS projects, including reservoir modeling calibration, geomechanics, geochemistry, and overall risk management.
Numerical Study of Sealing Performance of CO2 Hydrate Cap in Sub-Sea Sediments Considering Flow, Thermal, and Geomechanical Processes
Authors: Zhang Jiecheng , Moridis Geroge J. , Lu Hailong , Yang Jin , Zhang Laibin 
Published: June 2024

Abstract
CO2 sequestration in sub-sea sediments, aided by the creation of a CO2 hydrate cap, is proposed as a possible solution to reduce greenhouse gas emissions. Earlier numerical studies have considered only flow and thermal processes, neglecting geomechanics, which is crucial for understanding long-term storage processes, because of the lack of appropriate simulators designed for CO2 hydrate. This study enhances the capabilities of the pTOUGH+HYDRATE V1.5 to support CO2-H2O-NaCl systems, resulting in the development of the pTOUGH+CO2 HYDRATE V1.5. Coupled with the geomechanical software RGMS, this enables comprehensive simulation of flow, thermal, and geomechanical processes during CO2 sequestration. Buoyancy causes CO2 to migrate upward, forming a CO2 hydrate cap upon reaching the hydrate formation zone. Initially, the low saturation of the CO2 hydrate cap allows limited hindrance to CO2 migration. However, as saturation increases, hindrance becomes more pronounced, leading to enhanced lateral migration of CO2 and the formation of a larger CO2 hydrate cap, thereby improving sealing performance. Injected CO2 exhibits poor initial mobility, resulting in pore pressure accumulation and increased effective stress in sub-sea sediment. Careful consideration of injection rates is necessary during this stage. Furthermore, a comparison was conducted between the results obtained from (a) pT+CH V1.5 and (b) the coupled pT+CH V1.5 and RGMS models. Minimal differences between the models were observed, possibly attributed to relatively high permeabilities. Future research should explore diverse geological scenarios and investigate the depth of CO2 injection.
Enhancing the Passive Monitoring of the Rock Damage Process
Authors: DeLandro G. , Vanorio T. , Guo T. 
Published: June 2024

Abstract
This study explores the effectiveness of double-difference event location methods in detecting early signs of cracking, leading to leaks from structurally trapped CO2. Leaks carry the potential to escalate into bursts, highlighting the importance of proactive pore-pressure management measures. While the double-difference method is frequently applied for precise identification of fluid-induced seismic events, its reliance on a constant velocity model poses limitations, especially in dynamic environments potentially undergoing fracturing. Consequently, integrating velocity variations within a fractured medium into time-lapse seismic localization remains a significant challenge. In this study, we investigate how point-in-time average velocity changes influence the accuracy of double-difference event location. We analyze acoustic emissions (AEs) data gathered from laboratory experiments to explore this relationship. We performed a triaxial mechanical test on Berea sandstone, monitoring stress, strain, acoustic emissions (AEs), and variations in acoustic velocity as damage accumulated over time. AE event locations were determined using P-wave arrival times and magnitudes derived from source-receiver distances. The test revealed a significant surge in AE activity during the stages of damage progression, characterized by crack propagation ultimately leading to failure. Conventional double-difference technique, which assumes constant velocity, led to clustered distributions of acoustic emissions (AEs) that inaccurately represented fracture geometry. However, integrating point-in-time velocity changes improved the alignment of AE distributions with fracture geometry, unveiling a clear time-lapse imaging of crack initiation, propagation, and coalescence along the primary stress direction. This study highlights the crucial role of temporal velocity variations in ensuring precise event mapping, particularly in the monitoring of CO2 leaks. It proposes that average velocity fluctuations be monitored during injection or estimated from rock physics models for continuous and cost-effective monitoring. Ultimately, integrating time-lapse velocity changes improves our capacity to monitor crack progression and mitigate risks associated with CO2 leakage.
Estimation of Real-Time Bottomhole Parameters in CO2 Injection Wells During Operations by Means of an Ensemble of Neural Networks
Authors: Figueroa J. , Baraldi P. , Chouybat I. , Ursini F. , Vignati E. , Zio E. 
Published: June 2024

Abstract
Effective management of CO2 storage operations in subsurface reservoirs demands real-time estimation of well performance to identify deviations from expected operating conditions and ensure compliance with the requirements of Carbon Capture and Storage monitoring plans. To overcome the limitations of analytical tools in accurately estimating bottomhole flowing parameters, particularly during two-phase flow, this work aims to develop an empirical mapping between monitored parameters at various well sections and the bottomhole flowing parameters. Specifically, an ensemble of neural networks (NNs) is developed for the estimation of the bottom hole pressure (FBHP) and temperature (FBHT) in a CO2 injection well during operations. A feature selection approach based on trial-and-error is employed for the selection of the model inputs among the monitored parameters. The data used to train the NNs are generated using a thermo-fluid dynamic numerical simulator. Diversity between the NNs is achieved during the training phase by using different subsets of data and different weight initializations. The final FBHP and FBHT estimations are the median of the individual NN outcomes. The methodology has been applied to several cases in all flow regimes and different regions of the pure CO2 phase diagram, including single-phase, supercritical and two-phase transition. The proposed ensemble of NNs achieves accurate estimations of FBHP and FBHT, with root mean square errors (RMSE) below 1 bar and 0.1 °C, respectively, significantly outperforming an individual NN. This is due to the diversity among the NNs of the ensemble, which allows obtaining individual models that compensate for their errors, and the use of the median for the aggregation of the NN estimations, which make the ensemble robust towards the presence of possible outlier estimations provided by individual NNs. To our knowledge, this is the first application of machine learning solutions to real-time estimate bottomhole properties in CO2 injection wells. The satisfactory performance achieved on simulated data in a wide range of operating conditions, including two-phase transition, paves the way for the deployment of an ensemble of NNs for field application during operations.
Techno-Economic Evaluation of the Integration of High-Temperature Electrolysis With Geothermal Energy for Low-Carbon Hydrogen Production
Authors: Molho Simone , Roccaro Ernesto , Lainati Andrea , Stefanucci Michele 
Published: June 2024

Abstract
In this paper, the integration of geothermal energy with high temperature electrolysis to produce low-carbon hydrogen is investigated. Geothermal energy provides a stable energy flux, allowing to achieve high electrolyzer utilization factors, the compatibility with industrial processes and reduced load oscillations on electrolyzers. If steam-fed high temperature electrolysis is employed a highly efficient low-temperature heat exploitation process is made possible, with an electrolysis electrical efficiency above 80 % on LHV basis. The study identifies the best design for the integration of high temperature SOEC (Solid Oxide Electrolysis Cell) electrolysis technology and geothermal energy and provides a techno-economic assessment, computing its performance and the Levelized Cost of Hydrogen (LCOH). To feed the 3 MW electrolyzer the system exploits a hot geothermal fluid, both to generate steam and power (via ORC). A model of the system is set up with Aspen Plus software. A set of low-enthalpy geothermal resources ranging from 85 °C to 160 °C are considered. The two technologies work synergistically, leading to an efficient and stable hydrogen production. The use of SOEC electrolysis allows to produce 34 % to 38 % more hydrogen than alkaline electrolysis. The economic evaluation shows an exponential increase in the geothermal plant specific Capex for decreasing geothermal resource temperature, leading to an analogous trend in the LCOH. A benchmark case is defined coupling a PEM electrolyzer with a PV plant. The LCOH grows from a value 15 % lower than the benchmark in the 160 °C geothermal brine case, to a value 20 % higher than the benchmark in the 85 °C case. The breakeven point is found at 98 °C. This promising result is even more valuable considering the high dispatchability and stability of the output.
Cornegliano or How a New Porous Ugs Asset Can Rapidly Provide Multiple Services to the Grid
Authors: Gervasi G. , Ton A. , Lombardi S. , Mrad C. Abou , Lange A. , Egermann P. , Delsante F. , Salazar D. 
Published: June 2024

Summary
A new Underground Gas Storage (UGS) has been developed from the Cornegliano gas depleted field, located in the Po Valley, South-East of Milan. The gas field was originally discovered in the 1950s, produced 2.4 Bsm3 of gas from 13 wells until 1997 and was converted in December 2018. This paper presents more particularly how the ramp-up operations and commercialization were combined in an optimal manner, since they have complementary objectives. By taking into account the reservoir specificities and the wells / surface facilities capabilities, wide range of commercial services were rapidly provided to the Italian gas system while the long-term UGS performance increased continuously. The capacity of Cornegliano UGS to offer rapidly both seasonal and flexible short-term services also illustrates the future role of porous assets to provide relevant services also for hydrogen storage.
The first part of this paper describes the technical aspects of the first injection and withdrawal sequences, with a particular emphasis on the pressure and water management at the reservoir and well scales. An optimal ramp-up requires both injection of the appropriate volume of cushion gas for maximizing the reservoir performance and a pressurization of the reservoir to make pore space available for gas by pushing out the aquifer. All the data collected during the ramp-up were key to update regularly the reservoir model and to gain rapidly confidence in its forecasts.
The second part is focused on the commercial products design, according to the technical specificities of the UGS and the expected needs of the market. Along the ramp-up, the standard seasonal product was improved continuously in terms of both working gas volume and flowrate. Interestingly, many short-term additional capacities are offered on regular basis depending on the real-time behavior of the customers and the reservoir performance. Additionally, several specific products were also designed to respond to other market needs. For short-term market needs, the 5+2 product enables to reverse the physical flow in the UGS during the withdrawal campaign and to reinject a significant volume during the week-end which can be produced during the 5 following working days on top of the seasonal product. Various forms of "parking" product are also proposed to anticipate or postpone either injection or withdrawal in order to respond to longer term needs of the market.
As a conclusion, the UGS ramp-up and the commercial activities have been conducted successfully in parallel with a continuous development rate of the seasonal product (volume multiplied by 2.5 in 5 years) and increasing flexible short-term activities (+70% in addition to seasonal volume). Diversified and increasing services can be provided to the Italian gas system with a 100% reliability, which is valuable for both the current natural gas and future hydrogen markets.
Assessment of Reservoir Performance for Alternative Cushion Gases for Underground Hydrogen Storage
Authors: Correnti A. , Verlaan M. 
Published: June 2024

Abstract
Underground Hydrogen Storage (UHS) is an emerging area of interest in the space of a future hydrogen economy to match fluctuating supply and demand. The European Commission highlights the development of large-scale hydrogen storage facilities in the upcoming years in the Hydrogen Strategy for a Climate-Neutral Europe (European Commission, 2020). Storing large volumes of hydrogen for extended periods will require safe, reliable, and economically feasible underground storage in addition to pipeline and surface storage, which will fall far short of providing the storage volumes that are expected to be required in a scenario of large-scale hydrogen implementation. Underground hydrogen storage capability builds on existing oil, gas and carbon dioxide storage, including subsurface and wells expertise, to provide a safe and cost-effective solution that ensures continuity of hydrogen customer supply.
Building upon an initial reservoir engineering modelling study that was done to assess the viability of UHS in depleted gas fields (Huisman, et al., 2023), the analysis in this report assesses the technical viability, from a reservoir engineering perspective, of totally or partially replacing the hydrogen in the cushion gas by alternative gases such as methane, nitrogen, or carbon dioxide. This analysis aims to evaluate the options of total or partial replacement with a cheaper gas to reduce the hydrogen storage cost.
The impact of the different alternatives was evaluated by:
the resulting back produced gas compositions. the amount of tail gas to be reinjected/recirculated. The tail gas is formed when contaminants are separated at surface to comply with hydrogen export specifications.
To understand if the performance of the cushion gas option could be improved, some other variables were also assessed such as an alternative cushion gas injection strategy using a more distant well to reduce gas mixing and back produced gas contamination, and the impact of less stringent export gas quality specifications. It was observed that even though less stringent specifications slightly reduce tail gas reinjection rate, the carbon dioxide option in all cases results in a higher flowrate of tail gas reinjection to the reservoir. On the other hand, the assessed alternative cushion gas injection strategy had a relatively minor impact on results. Even though reservoir performance results are impacted when reservoir dip angles change, reservoir dip did not have an effect on the relative performance of the different cushion gases.
Overall analysis suggests that a partial replacement of the hydrogen cushion gas with methane is the best option. Integrated project economics should be assessed to provide a final recommendation on which cushion gas alternative is best from an economic point of view.