bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimizing Completion Through Real-Time High-Resolution Resistivity Imaging Tool for Fracture Mapping in Horizontal Wells
Authors: Bagga Pawandeep , Shukla Pradeep , Chitroda Chandrajyoti 
Published: February 2024

Abstract
The Western Offshore Basin, stretching from Gujarat to Maharashtra along the western coast of India, is a geologically significant region. It covers a vast area of the Arabian Sea, transitioning from the continental shelf to deep oceanic waters. This basin holds substantial reserves of oil and natural gas, making it highly important for hydrocarbon exploration and production. In the pursuit of maximizing production rates and recovery efficiency, the petroleum industry recognizes the value of horizontal wells in this region. By drilling horizontally, these wells offer an effective solution for reducing the number of wells required to exploit a field, thanks to their extensive exposure to the reservoir. However, it is crucial to address the challenges associated with completing these wells to extend their operational lifespan.
To optimize oil recovery and enhance well longevity, it is essential to complete horizontal wells with an appropriate number of Inflow Control Devices (ICDs) that possess suitable Flow Resistance Ratings (FRR). This configuration ensures the uniform distribution of flow along the horizontal section in highly permeable formations. It also helps manage early breakthrough at the heel in thin oil formations and delays water breakthrough in locations with high permeability in heterogeneous formations.
The advent of advanced high-definition Logging-While-Drilling (LWD) electrical imaging services has revolutionized subsurface characterization during drilling operations. This state-of-the-art technology combines LWD measurements with high-resolution electrical imaging capabilities, providing unprecedented insights into the geological formations surrounding the wellbore. Real-time images enable the timely detection and mitigation of wellbore stability issues, such as drilling-induced tensile fractures and breakout. Additionally, real-time images facilitate sedimentary steering, enabling optimal placement of the wellbore within the formation.
This paper aims to assess the advancements in high-definition logging-while-drilling electrical imaging tools. These tools acquire micro resistivity data around the entire circumference of the borehole while the bottomhole assembly (BHA) is rotating. The processed micro resistivity images obtained from LWD effectively reveal the presence of fractures, which are subsequently categorized into different zones to determine the optimal ICD completion based on fracture density. The high-definition images acquired using the LWD Electrical Image logging tool provide clear visualization of detailed fractures, vugs, and connected vugs.
Global Perspective in Gas Flaring
Authors: ElMasry H. , Shakirov A. 
Published: February 2024

The global movement to reduce greenhouse gas (GHG) emissions and promote decarbonization as a pathway to achieve net-zero goals is rapidly gaining momentum. It is widely acknowledged as one of the primary catalysts shaping energy policies in the current era. Numerous countries have made substantial environmental pledges; however, the next crucial step is to effectively translate these commitments into tangible decarbonization projects with dedicated funding.Methane emissions in oil and gas value chain are generally produced from one of three sources: leaks (which take place unintentionally through a faulty seal or a leaky valve), venting (which take place when gas is released intentionally for safety or operational purposes) and flaring (which takes place when gas is burnt when it cannot be used or recovered). The oil and gas industry is under immense pressure to reduce greenhouse gas (GHG) emissions resulting from non-emergency gas flaring and venting.This urgency stems from the fact that these activities release substantial amounts of methane directly into the atmosphere, which has a detrimental impact on climate change and poses a significant environmental obstacle to achieving net-zero goals. Methane emissions are considered the second-largest contributor to global warming among GHGs, following CO2. Although methane has a shorter lifespan in the atmosphere compared to CO2, it is more potent in terms of its greenhouse effect. It is estimated that methane is responsible for approximately 30% of the Earth's temperature increase.
Numerical Simulation of Flaxseed Gum Potential in Improving Oil Recovery: Focus on Offshore Kazakhstan
Authors: Abbas Azza Hashim , Keldibayev Nurmukhammed , Pourafshary Peyman , Zhuniskenov Yermukhan , Serikov Galymzhan 
Published: February 2024

Abstract
Enhanced oil recovery (EOR) entails modifying the water-oil composition in the process of recovering oil (Charoentanaworakun et al., 2023, El-Masry et al., 2023). One of the main techniques is the injection of chemicals to increase oil recovery. This method is crucial to extract trapped oil from mature oilfields, increasing their effectiveness and lengthening their lifespan. One reason for the rise in water viscosity can be attributed to certain substances, including high molecular weight polymers, gels, and composites that undergo in-situ cross-linking, which can cause this effect. Increasing water viscosity can technically reduce water mobility, leading to better sweep efficiency (Arshad and Harwell, 1985, Abbas et al., 2020)
Chemical EOR techniques improve oil recovery by modifying the injected water phase by changing the reservoir's fluid-fluid and/or fluid-rock interactions. Chemical Enhanced Oil Recovery (CEOR) methods utilize a chemical mixture as the displacing agent, which prompts an increase in the capillary number or reduction in the mobility ratio. The primary goal of chemical EOR procedures is to affect one of the following variables: mobility (by utilizing polymer solutions with increased viscosity), rock wettability, and interfacial tension between two immiscible phases (by applying surfactants or alkalis to the displacing fluid). The suitability of the chemical as a recovery enhancer is evaluated via the following parameters: it should enhance the viscosity of water while allowing it to flow through porous media and displacing more hydrocarbons; it should be functional for a reasonable duration of time without degradation; inhibit water fingering and manage the front pattern. Therefore, discovering such chemicals is supported by rheological characterization at various salinities, temperatures, and chemical concentrations. While the primary phase is comparable to the subsurface settings, it demands a meticulous evaluation of the flow behavior during dynamic flooding (Druetta and Picchioni, 2020).
Despite their efficiency and low cost, most of the chemicals harm the environment, which increases the focus on developing eco-friendly chemicals that can effectively replace commonly used polymers like hydrolysis polyacrylamide (HPAM). This has led to the exploration of various natural polymers such as Arabic gum, Xanthan Gum, and Guar Gum, with encouraging results as shown by the research conducted by Saha et al. (2019) and Dessbesell et al. (2020). However, one major challenge in their widespread application is their accessibility and ability to endure diverse reservoir conditions such as temperature and salinity, as highlighted in Bento and Moreno's (2016) study. Despite the potential of these natural gums, the industry still needs to improve its implementation process, and some valuable sources of natural materials have not yet been fully developed.
Laboratory and Modelling Study on Comparison of Geochemical Reactivity in Carbonate Reservoir Due to CO2 Injection With/Without the Presence of H2S at High Temperature and Pressure
Authors: Amin S. M. , Zaidin M. F. , Azuddin F. J. , Razak A. A. , Mohsin N. , Pin Y. W. , Tewari R. D. 
Published: February 2024

Carbon Capture and Storage, known as CCS, is a technology that involves capturing CO2 from industrial and energy-related sources such as a power plant before being transported and injected into geological formations for long-term isolation from the atmosphere. There are four types of geological formations that can be used to store CO2: depleted oil and gas reservoirs, deep coal seams, salt caverns and deep saline aquifers. Among these, deep saline aquifers provide the best option for storage as it presents the largest storage capacity. After the injection of CO2 underground, the gas (or, in most cases, the CO2 will be a supercritical fluid) will undergo physical and chemical changes. The CO2 will be trapped in the pore space of the rock by three trapping mechanisms: hydrodynamic trapping, solubility trapping and mineral trapping. The storage security increases over the time with mineral trapping provides both the slowest and the safest process. This is because the injected CO2 will be permanently sequestered as a solid phase. As a result, this prevents leakage of CO2 into the surface.
The development of injection process is still in its infancy, especially when it comes to the consideration of CO2 injected with other impurities. To date, most research has only studied the injection of pure CO2. However, allowing impurities in the gas stream reduces the cost of capture – the most expensive step in CCS – and so is an attractive option (Gaus, 2010; Knauss, 2005). Some studies have reported few geochemical effects associated with injecting a mixture of CO2 and H2S (Gunter et al., 2000; Knauss et al., 2005; Xu et al., 2007); however, the details study on kinetics of H2S during and post-injection of CO2 with H2S is still scarce.
Previous study by Ahmad et al., 2023 has reported that potential mineral precipitation of sulfide in carbonate reservoirs due to CO2 injection with H2S. The precipitation resulted the reduction of rock porosity and pemerbility which impact on the injectivity and ultimately on the storage capacity (Clark et al., 2018).
Flare Gases Conversion to Carbon Nanotubes (CNTs): Energy Storage Applications
Authors: Watcharasing S. , Nunthaworrarat R. , Piromchart T. 
Published: February 2024

Abstract
Carbon Nanotube (CNTs) is a carbon-based nanoparticle with a diameter in a nanometer range (nanoscale) regarded as the "Futuristic Materials" for advanced applications. In Company A, the GHG emission reduction is one of the goals to support sustainability growth. Therefore the project CNTs from natural gas has been firstly initiated, and considered as the Carbon Capture and Utilization(CCUS) technology that captures hydrocarbon sources, which mainly contribute to greenhouse gases, and converts them into new value-added products.
The CNT reactor unit is designed as a mobile skid for an easily mobilization to any remoted area location to capture the remaining flare gas. The flare gas commingle with the carrier gas is routed into the Fluidized Bed Chemical Vapor Deposition (FBCVD), under the optimal conditions with catalyst, the flare gases are converted to CNTs powder. The produced CNTs quality is about 95% purity for Multi-Walled CNTs with a diameter around 30-50 nm can be achieved by the CNT reactor prototype unit, which it is comparable with commercial grade CNT product. All the operating parameters are tested and will be further used for the engineering design of the large scaled CNTs pilot unit.
Therefore, the synthesized CNTs from flare gas was further applied into the real applications of an energy storage. CNTs was coated over the electrode of the supercapacitor. The performance test of the supercapacitor was further performed. The results of the Company A's CNTs based supercapacitor; in terms of the energy density, power, and cyclability, etc., are benchmarked with the commercial supercapacitor in the market.
CNTs synthesis using flare gas as carbon source was firstly initiate and get the promising results from the actual field tests. This FBCVD technology is proven with higher product yield and purity compared with other conventional methods and larger scale plant is considered highly feasible. In technology development, this technology is a challenge that could open the new horizon for oil and gas development.
Offshore Gas Field Tight Reservoir Development Through Integrated Approach of Seismic and Hydraulic Fracturing
Authors: Sjahbunan P. , Afdhal R. F. , Handoko B. S. , Sianturi J. 
Published: February 2024

Abstract
Sisi Nubi field is a mature offshore gas field situated in the Mahakam Delta, East Kalimantan, Indonesia. It has been producing approximately 1.45 trillion cubic feet (Tcf) of gas and 35 million stock tank barrels (MMstb) of condensate from 99 development wells across seven offshore production platforms. The reservoir is stratigraphically divided into three main zones: Shallow Zone (SZ), Fresh Water Sand (FWS), and Sisi Nubi Main Zone (SMZ).
The current development focus is primarily on the Shallow Zone and Fresh Water Sand Zone, due to their favorable reservoir productivity, mainly composed of unconsolidated fluvial and distributary channel-type formations. In contrast, the SMZ consists of consolidated stacked offshore bars, some of which are highly bioturbated. As a result, the productivity in this zone is generally lower through regular production methods. Production from the SMZ primarily relies on previous fracturing jobs, with a success ratio of approximately 50%. Notably, one of the fracturing jobs took place in well SS-106, resulting in an incremental gain of approximately 40 billion cubic feet (Bcf) of gas. Fracturing in well SS-106 involved lateral and vertical fracturing through shale breaks.
This paper aims to share the success story of fracturing jobs in Sisi Nubi and explore how seismic analysis can aid in identifying potential fracturing well candidates for the SMZ, thereby increasing the success rate and optimizing production. Previous development studies of the SMZ mainly relied on static dynamic analysis and geomodelling approaches, resulting in a limited number of wells penetrating the SMZ. Consequently, the identification of ideal fracturing candidates was limited. Therefore, leveraging seismic data within this zone becomes crucial to improve opportunities.
The analysis began by studying the relationship between seismic anomalies and geological parameters such as geological layering, netsand and netpay thickness. Consequently, the SMZ was subdivided into four subzones based on geology and seismic resolution. Extracted seismic bright anomaly that corresponds to series of stacked bars, having a consistency with successful fracturing jobs while unsuccessful ones were outside bright seismic anomaly.
Implementing seismic and data-driven analytics in deeper zones like the SMZ introduces a new practice in the Mahakam region. This approach allows for the identification of optimal reservoirs for fracturing, resulting in an improved success rate, increased production, and enhanced recovery from the SMZ.
Energy Recovery from Geothermal Reservoirs in the Baram Basin, Sarawak: A Numerical Reservoir Simulation Approach with CO2 Utilization
Authors: Bataee M. , Soh M. , Ruvalcaba J. B. , Hamdi Z. , Carter R. , Rajandran K. V. 
Published: February 2024

Abstract
In response to escalating global energy demands and climate change threats, this paper explores the potential integration of CO2 injection in geothermal energy production (GEP). The global energy sector, a significant greenhouse gas emitter, necessitates a shift towards renewable energy, and GEP stands out as a promising clean energy source. This study focuses on CO2 as an injectant, leveraging its higher enthalpy change in the supercritical state and potential for carbon capture, utilization, and sequestration (CCUS). Despite CO2's advantageous properties, logistical challenges and higher costs have hindered its widespread adoption in GEP. Enthalpy, a key thermodynamic concept, plays a pivotal role in understanding CO2 thermal behavior. Investigating the change in enthalpy concerning pressure and temperature showcases CO2's rapid energy absorption and release capabilities, distinguishing it as a viable candidate for renewable energy production in GEP. The proposed closed-loop CO2 cycling system, though limited in carbon storage, demonstrates significant carbon utilization potential. By repurposing CO2 as an injectant, back-producing it for GEP, and continuously cycling it within the reservoir, the study explores a sustainable energy generation model. Using reservoir simulation, the research assesses the feasibility of the CO2 injection and thermosiphon process. The initial pilot simulation reveals challenges such as a limited CO2 cushion and logistical constraints, prompting modifications to the injection process. The modified injection method, involving both injector and producer perforations, shows promise in sustaining energy production and reducing water production. In conclusion, this study provides valuable insights into the feasibility and efficiency of utilizing CO2 as an injectant in GEP. While challenges exist, addressing logistical concerns and optimizing injection methods could unlock the full potential of this innovative approach, contributing to the transition to sustainable and clean energy sources.
Production Stabilisation and Enhancement in an Offshore Well Using Dual Gas Lifting in a Single Production String Using Modified Gas Lift Set Up
Authors: Misra Anurag , Gaurav Aman , Ranjan Ashish 
Published: February 2024

Abstract
The objective is to present a case study on dual gas lifting methodology which resulted in revival and subsequent production optimization of a shut offshore well. This well has encountered multiple stratified oil and gas sands and is completed as cased and perforated. The shallowest gas sand is compartmentalized between two production packers and has a sliding sleeve door (SSD) for zonal isolation. The bottom oil sand is below tubing and has resin consolidation for sand control. The upper completion string has a circulation SSD. The well was shut after depletion of the oil zone. Presence of shallow gas zone gave an opportunity for utilizing as auto gas lifting to revive the shut well. Considering unavailability of gas lift mandrel across the gas zone, innovative approach was needed. The well was modelled for gas lifting and accordingly the conventional jet pump was selected as straddle gas lift valve and installed across the gas zone SSD. This achieved controlled gas rate resulting in successful well revival at rates ~ 800 bopd, 1.1 mmscfd gas and 1000 bwpd. Post revival, the well produced at stable parameters for more than a year after which it started showing cyclic behavior. This behavior was attributed to gas sand depletion hence additional external gas lift support was required to augment auto-gas lift sand. The unavailability of both permanent gas lift setup on platform and gas lift mandrels in completion restricted the conventional approach of external gas lifting from surface. A new well was drilled on same platform which produced dry gas at high pressure. Gas Lift modelling suggested successful feasibility for utilizing this gas as gas lift in subject well. Another jet pump was installed in circulation SSD for external gas lifting. This augmented auto-gas lift sand and stabilized the well resulting in doubling the production rates.
System Pressure Test Failure Review from JIP REPLACE
Authors: Royet O. 
Published: February 2024

Abstract
For offshore pipeline, the System Pressure Test (SPT) is the traditional conclusion of the installation campaign and the final quality control measure. As a gross error final test, the relevance of the SPT was challenged by the REPLACE Joint Industry Project (JIP), which kicked off in 2019 with a total of 21 sponsors, bringing experience from all levels of the industry. The objective was to develop and issue a guideline detailing a systematic approach for the participants to enable them to replace the SPT. This is allowed in DNV pipeline standard, DNV-ST-F101 (2021) for selected pipelines with "extraordinary disadvantages", given that the approach maintains the same level of safety as if the SPT was performed. The guideline was completed and issued in 2020, and will be referred as JIP REPLACE (2020) in this paper.
One of the JIP activity scope was to collect description of past pipeline loss of containment that the system pressure test successfully detected and review them to identify the failure mechanisms and the associated root causes. This paper presents the assessment results of offshore pipeline system pressure test failures carried out as part of the JIP REPLACE. The review of 47 cases covering a period from 1976 to 2019, allowed identification of commonality in the failure mechanisms and type of triggering defects. The paper identified common failure properties and failure modes involved.
As the considered failures span over decades, the failures were reviewed against current DNV-ST-F101 revision, to confirm if the associated failure mechanism could have been detected and avoided by current code requirement.
The review of past failure during SPT confirmed that the DNV-ST-F101 would have been adequate to avoid or detect the failure mechanism prior to the system pressure test. Within the scope of the JIP REPLACE, this work allowed to identify commonality within the failure cases as well as trends along the years in regard of the type of failure mechanism. These failures cases constituted the basis for the establishing the set of prerequisites and requisites defined in the JIP REPLACE guideline. The prerequisites and requisites allow to assess suitable pipeline system candidate for system pressure test replacement, as such bringing learning from past industry project to future ones.
Effect of High Temperature in Pore Pressure Prediction - Evidence in Overpressured Shale Petrophysical Properties
Authors: Nik Kamaruddin N. M. F. , Teng K. G. E. 
Published: February 2024

Abstract
In order to safely access deep petroleum resources, pore pressure studies are an essential part of well design engineering and economics considerations. Predicting pore pressure may become problematic in deeper reservoirs because to extra geological processes that encourage secondary overpressure mechanisms. Petrophysical, stress, and pressure plots (e.g., depth-based velocity-density, porosity-effective vertical stress), field data (formation and temperature), and observations (stress and pressure measurements) are analyzed in conjunction with the conducted analyses. The findings indicate that temperatures between 80 and 140 degrees Celsius are frequently associated with the largest discrepancies between projections and actual observations. Because of likely intricate geological processes including hydrocarbon production, diagenesis, metagenesis, chemical compaction, and alteration, this temperature range is frequently linked to less predictable fluid characteristics and pressure. Based on field data, the estimation errors are shown and evaluated for each temperature range. The assessment of temperature-related uncertainty in pore pressure prediction as well as the discrepancies between estimated and measured pore pressure at various temperatures are highlighted in the research. For a complete and enhanced understanding of the effects of temperature and pore pressure forecast reliability, it is crucial to understand the origins of overpressure and related geological processes. To provide more insights for prompt decision making, the research proposes an enhanced technique and workflow in pore pressure prediction combined with petrophysical analysis for a range of temperatures. In addition, it hopes to stimulate industry and society to think about replication and maybe enhance the process for identifying ambiguity and boosting comprehension of pore pressure prediction at high temperatures.