bluuebunny/crossref_metadata_2025_split huggingface dataset:
Perspectives of Hydrogen Peroxide Injection to the Carbonate Reservoir for ISC Initiation
Authors: Askarova A. G. , Maerle K. V. , Popov E. Y. , Malaniy S. E. , Grishin P. A. , Slavkina O. V. , Cheremisin A. N. 
Published: October 2023

Abstract
As part of laboratory and numerical investigations, an assessment of hydrogen peroxide (H2O2) injection efficiency was performed to estimate the ability of H2O2 to increase the productivity of heavy oil field development. The combined effect can be observed, including heat release due to H2O2 decomposition and oxidative reactions with oil during the in situ combustion (ISC) process and increased oil mobility due to CO2 dissolution.
Laboratory experiments were performed on an autoclave to study the decomposition of peroxide in conditions close to the reservoir (pressure and temperature) and obtain experimental values of the kinetic parameters of the H2O2 decomposition reaction. Further, these values and experimental parameters were integrated into a homogenous numerical model representing the target oil reservoir. Also, during the laboratory experiment, the optimal value of the H2O2 concentration was determined for subsequent sensitivity analysis. The numerical model was then used to build a Tornado diagram and to estimate the effects of preheating, operational parameters, reservoir properties and kinetic parameters with or without catalysts in the system.
According to the results of the hydrodynamic modeling, efficient heating of the formation to high temperatures (over 100°C) during the injection and decomposition of H2O2 is possible only in the presence of a catalyst. The bottomhole formation zone temperature with a catalyst can reach up to 350°C. The most significant influence on the cumulative production is provided by the injection rate, reservoir permeability, initial temperature of the injecting fluid, as well as the thermal properties of the rock. When the temperature reaches 300°C, the reaction of peroxide decomposition begins to accompany the ISC of oil, which is self-initiated, since there is a sufficient amount of oxygen in the formation formed during the decomposition of H2O2.
An effective application of the technology is possible during a sufficiently fast rate of the peroxide decomposition to avoid the dissipation of the released heat due to two possible mechanisms: heating (up to ~150°С) of injected agent (effective, but it is associated with additional costs for equipment and technological risks);use of widely available and cheap catalysts.
As a result of the work, the most promising strategies of H2O2 injection technology for heating a carbonate reservoir were identified. The option of full-scale injection of the H2O2 is associated with high costs and limited development rates. This method can be applied to objects with specific conditions of elevated temperatures where the peroxide decomposition reaction will be the most active.
A State-of-the-Art Water Shutoff System in Carbonate Reservoir: From Lab to Field
Authors: Alabdrabalnabi M. I. , Almohsin A. M. , Baiz A. I. , Busaleh A. S. , Al Bin Saad H. 
Published: October 2023

Abstract
Polymer gel systems have been utilized extensively as a water shutoff material to control and reduce excessive water production and eventually improve oil recovery. A novel water shutoff material with excellent gel strength and thermal stability has been developed to minimize water production zones based on various operational parameters such as pressure, temperature, pumping rate, treatment duration, and shut-in time. This paper presents the state of art polymer gel with an adsorption system from the laboratory phase to the thriving field implementation of water shutoff technology in carbonate formation. The developed polymer gel system comprises copolymer, organic crosslinker, and adsorption constituents. The water shutoff agent's gel strength and gelation time were deeply examined using high-pressure, high-temperature (HPHT) rheometers. The rheological properties, such as storage modulus (G’) and loss modulus (G") of matured gels with different compositions, were studied to identify the gel strength of each system. Additionally, the effect of temperature, polymer, and crosslinker on the gelation reaction was captured as part of the experimental research. Based on extensive lab experiments at downhole reservoir conditions, the water shutoff treatment was optimized to control water production from vertical oil well producers.
The experimental results indicated that this water shutoff technology exhibited low initial viscosity for all systems below 20 cP at standard conditions, giving an advantage of pumping requirements during fluid mixing and injection to the targeted zones in the field execution. Once the water shutoff fluid travels downhole to the targeted zone, the temperature starts to buildup, and the gelation reaction begins. Consequently, the fluid viscosity is controlled at a specific bottomhole temperature based on liquid compositions, mainly polymer, crosslinker, and adsorption agents. This determines the gelation time between minutes to more than 10 hours. Therefore, this water shutoff gel can be placed smoothly into the target zone as a single-phase fluid with desired gelling time to plug the targeted formation. As for treatment design, the field testing utilized an E-coil string to run a production logging tool to spot the sources of water production and detect the bottomhole temperature and pressures essential to formulate the water shutoff system. The post-treatment flowback revealed promising results of this novel polymer gel system. The water shutoff fluid minimizes more than 60% of water production based on pre-treatment flowback. The newly developed water shutoff system is a promising polymer gel technology to control water production from carbonate oil formations. The experimental findings and field outcomes unveiled that this robust polymer gel efficiently plugged the water zone at high temperature and pressure conditions.
Reducing Geomechanical Model Uncertainty Through Multiple Trajectory Stability Analysis Using Vertical and Highly Deviated Wells
Authors: Rajaiah Nanthakumar , Guerra Julian , Al-Asadi Yousif Mohammed Baqer , Xi Guifen , Aljaberi Salem Mubarak , Alblooshi Jamal Rashed 
Published: October 2023

Abstract
The wellbore stability back analysis is an easier task for vertical wells compared to deviated wells, since the stable mud weight window is highly affected when deviation is accounted for; furthermore, the limited drilling events encountered in vertical and slightly deviated wells compared to highly deviated wells led to uncertainties in the 1D mechanical earth model (1D-MEM) construction and the wellbore stability analysis (WBS).
This paper details a multiple trajectory stability analysis strategy to construct a representative MEM for wells with a wide range of azimuths and inclinations, in an offshore field in Abu Dhabi. The strategy helped to reduce the uncertainties associated to the stress magnitudes, when other geomechanics parameters are properly constrained, like the rock mechanical properties and pore pressure. Initially, the 1D-MEM's were constructed mainly for vertical and slightly deviated wells and calibrated with drilling events. Later, a blind test conducted in a highly deviated well showed excessive shear failure, contradicting the low mud weight using during drilling and the lack of wellbore stability problems. This inconsistency, led to include additional highly deviated wells during the MEM construction phase. Since all mechanical properties and stresses were properly constrained, the horizontal stresses were the variables to adjust, especially the maximum horizontal stress.
A parametrization study was conducted for the stresses till honoring the wellbore failure for additional highly deviated wells. The minimum horizontal stress was kept almost consistent to honor the offset field data and the 3D-MEM minimum stress. The maximum horizontal stress, on the other hand, was varied significantly, producing different stress scenarios and regimes. Eventually, there was a stress scenario that yielded reasonable wellbore failure results for a wide range of azimuths and inclinations, as proven during a post-mortem analysis conducted in a recently drilled well, where the amount of drilling problems was consistent with the new model. The multi-trajectory strategy can be used with higher confidence to optimize the safe mud weight window for any trajectory and well type.
The Hydrogen System in the Subsurface: Implications for Natural Hydrogen Exploration
Authors: Zhao Hongwen , Jones Ernest A. , Singh Rajput Seemant , Ismail Hasnol Hady B. , WahTan Seng 
Published: October 2023

Abstract
In the context of global efforts to achieve carbon neutrality, Hydrogen (H2) has emerged as a key solution for reducing greenhouse gases emission. However, current methods of hydrogen production, such as thermochemical and electrochemical processes like electrolysis, methane reforming and pyrolysis, are generally expensive and suffer from issues including intensive carbon dioxide emission and high electricity consumption etc. (Ishaq et al. 2022; Younas et al. 2022).
In fact, hydrogen gas can naturally occur in the subsurface which has been manifested by numerous hydrogen seepages found across the world (cf. Zgonnik 2020 and the references therein). Notably, a significant discovery of natural hydrogen was made accidently during drilling a water well (Bougou-1) in Mali in 1987. Subsequent exploration in the vicinity of Bougou-1 confirmed the existence of an active hydrogen system in the area (Prinzhofer et al. 2018), highlighting the possibility of commercial hydrogen accumulation in the subsurface. Moreover, there is a growing consensus that natural hydrogen could be an important alternative for hydrogen production (Zgonnik 2020).
In recent years, extensive exploration activities and scientific research focusing on natural hydrogen occurrences, generation mechanisms, and accumulation processes have been conducted, particularly, in Africa (Moretti et al. 2022; Prinzhofer et al. 2018), Australia (Boreham et al. 2021; Frery et al. 2021; Leila eta al. 2022; Rezaee, 2021), Europe (Combaudon et al. 2022; Larin et al. 2015; Lefeuvre et al. 2022; Leila et al. 2021), Brazil (Moretti et al. 2021; Prinzhofer et al. 2019), and the USA (Guélard et al. 2017; Zgonnik et al. 2015). Geological investigations indicate that natural hydrogen is dominantly found on Precambrian cratons, ophiolite belts and mid-oceanic ridges (Rigollet and Prinzhofer, 2022). It occurs as gas leakages on the surface or is associated with other gases in the conventional and unconventional gas plays (Milkov 2022).
A Novel Methodology to Capture Anisotropy in Unconventional Reservoirs: Theory and Methodology
Authors: Ibáñez E. , Alvarellos J. , de Melo R. C. Bezerra , Laksmikantha R. H. 
Published: October 2023

ABSTRACT
A novel methodology is presented based on the concepts of poro-elasticity and tectonic strains to capture material anisotropy, later to determine stress anisotropy. An accompanying article in this conference presents the results of a case study to demonstrate the applicability in real case. Stress anisotropy determination requires material anisotropy as input and acquisition of these properties is expensive & not common practice, thus the methodology is an efficient cost-effective alternative to a complete anisotropic characterization. Current methodology proposes multi-well inversion applying poro-elasticity to obtain the lateral effects of tectonics in the stresses. Each well uses isotropic poro-elastic, VTI or Orthotropic models depending on the type of information available. The approach has the following options: (1) Individual /direct strain calculations with a set of 1D Geomechanical Models (1DGM), (2) Pair of strains for each well, (3) Multi-well inversion using 1DGM´s with custom depth range selection. The proposed novel methodology integrates the interpretations from options (1), (2) and (3) to locate anomalies and determine strains at field scale. The current methodology has been applied to variety of reservoirs/plays: unconventional/Shale, conventional, and complex structural setting (salt environments, etc.). Applying options (1) and (2) any horizontal anomalies in the field scale strains could be identified. In another application using options (1) & (2) local stress rotations due to the salt dome was detected. Tectonic strains in a well showed clear signs of local stress perturbation due to the nearby strike slip fault. Option (3) is applied to locate vertical anomalies, usually by removing formations from top to bottom in a muti-well fitting. Higher strain values were obtained when a specific formation was excluded from the analysis. Later a deep inspection of the seismic data a reverse incipient fault was found in the excluded formation marking a global detachment level that was not active at present day. In addition, another benefit of the proposed method is far-field strains can be determined as a vertical profile or a pair of values at field scale, that serve as boundary conditions for stress initialization process of a 3D Geomechanical model with no iterations. The proposed methodology has demonstrated the capacity to obtain the strain far-filed effects of tectonics at field scale. Current methodology applied at early stages of field characterization only with 1DGM can locate anomalous strain/stresses that helps mitigating drilling hazards in future wells and in unconventional wells as input to hydraulic fracture design. Conventional stress initialization of a 3D geomechanical model requires several iterations to reach an acceptable stress field.
Assessing the Impact of CO2-H2S at 400 ppm for Storage: A Geochemistry Perspective
Authors: Zaidin M. F. , Razak A. A. , Abdullah W. M. S , Tewari R. D. 
Published: October 2023

Abstract
The presence of impurities, such as H2S, in CO2 injection carries a higher risk of sulfide mineral precipitation. This can have detrimental effects on rock properties, leading to a reduction in rock porosity and permeability. Consequently, it affects the injectivity and storage capacity of the reservoir. In addition, the reliability of fluid-rock reaction simulations is uncertain and requires calibration using laboratory data. However, there is a scarcity of published experimental data on the geochemical effects of CO2-H2S under reservoir conditions. The objective of this study is to measure the key parameters of geochemical reaction kinetics between injected CO2-H2S at 400 ppm concentration level, brine, and carbonate reservoir rocks, and their effects on fluid and rock properties. Carbonate core samples from the X Field have been selected as a case study due to their identification as potential CO2-H2S storage sites, and the availability of the core samples. In this study, H2S gas with a concentration level of 400 ppm is pre-mixed with CO2 and brine water. The CO2-H2S-brine mixture is aged with core samples under X Field reservoir conditions using two different setups: high-pressure chamber (static) and core flood (dynamic) for a duration of 30-days and 14-days respectively. These setups were designed to represent two different scenarios during injection: far from the wellbore and near wellbore scenario. At the end of the ageing period, cores and effluent were collected for analysis to measure changes in key geochemical parameters, including rock porosity, permeability, mineralogy, and images from CT scans, between the post-ageing and pre-ageing stages. The findings offer valuable insights into the behavior and stability of carbonate rocks within near wellbore and far from the wellbore environments during CO2-H2S interactions. Understanding the geochemical processes involved is crucial for evaluating the long-term stability and containment of CO2 or natural gas containing impurities such as H2S in geological storage scenarios.
Enhancing Pipeline Integrity Management with Machine Learning and Integrated Monitoring Technologies
Authors: Wang Kang , Chughtai Adnan , May Joshua C. , Poddar Sneha 
Published: October 2023

Abstract
As the oil and gas pipeline industry shifts toward digitalization, machine learning and artificial intelligence (AI) play an increasingly important role in asset integrity management, including operation monitoring, leak and intrusion detection, corrosion protection, and flow assurance, among others. This paper introduces an integrated approach using fiber optics, inspection reports, and fluid flow simulations and demonstrates how machine learning and AI can help operators by producing unified insights.
Fiber-optic distributed acoustic sensing (DAS) technologies are routinely used to monitor pipeline activities; critical events such as product leaks, digging near the pipeline, and pigging are captured by quantitatively analyzing unique signatures on the fiber-optic generated space-time image. This can be treated as a pattern recognition or machine learning problem. YOLO, a state-of-the-art fast object detection algorithm, was used to demonstrate accurate tracking of pipeline inspection gauges (PIGs), among other activities, using a small quantity of training data. In addition, using AI, routine inspection reports and flow simulation results were automatically calibrated, cross-validated, and then contextualized with the fiber-optic DAS generated events.
The event detection and classification algorithm used in this work achieves high location accuracy, superior to current industry-standard methods. As a result, this method significantly improves the tracking of PIGs. More importantly, these detections are automatically calibrated with inspection reports for cross-validation. Traditionally, fiber-optic systems are an independent and isolated sensor technology, which require field teams to perform manual activities approximately every 2 km along the entire pipeline for georeferencing. This is inefficient and does not provide the location accuracy needed to link the fiber-optic system to other sources of data, such as inspection reports or flow simulation results. This lack of integration has been a longstanding challenge that prevented operators from easily isolating important signals or repeated trends for each weld, valve, meter, or road crossing, for example. With our machine learning - assisted integrated management system, various sources of data can be consolidated and analyzed to provide valuable information that was previously unavailable.
This paper presents the novel use of fast machine learning models to accurately detect and track pipeline activities. In addition, data analytics aids in the calibration and cross-validation of different monitoring technologies under a single integrated pipeline integrity management platform, providing operators with unique insights.
On-Line Full Molecular Characterization of Flashed Gases with a New Generation of NGD Detectors for Micro-GC
Authors: Maniquet A. , Sobrado L. Alonso , Collell J. , Colinet E. , Loriau M. 
Published: October 2023

Abstract
Today, to get a full molecular characterization of gases, a gas chromatographic system hyphenated to both flame ionization (FID) and thermal conductivity (TCD) detectors is essential. However, for on-site, on-line analysis (mostly ATEX zone) FID are forbidden and TCD only allows quantification up to C7. A new universal detector (NGD for Nano Gravimetric Detector) covering a hydrocarbon range from C1 to C40+ has been developed and implemented in miniaturized and transportable system [1].
The first step is to evaluate the NGD response for different families of compounds present in the gas (synthetic and process gases) and develop different approaches to simplify the quantification. This one will be carried out in laboratories. To increase productivity and accuracy for PVT experiment, this detector will be implemented on a PVT unit. Once validated on fully controlled flashed gases, the system could be updated to work with batteries to be fully transportable for on-site or adapted for on-line analysis to be able to monitor any gas anywhere up to C11/ C12.
All compounds were well separated and detected with the chromatographic resolution required for this study. Different standards gases have been used: from nC1 to nC10 with BTEX (benzene, toluene, ethylbenzene, m-xylene, p-xylene, and o-xylene). To achieve an external quantification, two approaches were carried out. A first approach based on the linear relationship that exists between the NGD response (as the logarithm of the peak area normalized by concentration) and the number of carbon atoms. These linear relationships are different depending on the family of compounds analyzed. The second approach uses a hyperbolic method based on the Langmuir model by applying an inverted Langmuir equation. This approach allows calibration of the NGD detector using a single linear relationship for all compounds regardless the family to which they belong. A quantification on diluted standards gases was carried out (4 levels) and the relative error was less than 10%. Moreover, a hyperbolic Langmuir approach improved the accuracy of the results with errors inferior at 5%. During 2023, the aim is to calibrate the NGD detector for the quantification of all compounds present in a process gas from a PVT unit and to proceed to the on-line monitoring.
Today, only FID detector allows C5+ quantification on gaseous effluent, only present off-line. Tomorrow, thanks to the NGD detector, the gas analysis could be carried out on-line with a full molecular characterization of gases with a complete automatization of monitoring.