bluuebunny/crossref_metadata_2025_split huggingface dataset:
Silver Lining in South-East Asia's Decommissioning Industry: A Red Carpet for Service Providers
Authors: Mishra Shubham , Modi Amanpreetsingh , Vasquez Martha , Selem Ahmed M. 
Published: November 2024

Abstract
With over 50 years of sizeable offshore developments, South-east Asia (SEA) has become the next hotbed for the oilfield decommissioning industry. It is estimated that more than 200 offshore fields in SEA will stop producing by 20301, comprising more than 1,500 platforms and ~7,000 wells2–3. With such a large number of "decommission-ready" assets, the total decommissioning costs are estimated to range from $30 billion to as much as $100 billion2–3.
Starting with a large internation oil company (IOC)'s limited decommissioning work in Brunei towards the end of the 1980s, Malaysian national oil company’ first decommissioning in 2003, and Thailand's focused attempts recently at decommissioning it's large assets3, the industry has been evolving at a slow pace in the region and this has created a significant backlog of "decommission-ready" assets adding to the already high liabilities. A combination of complexities and challenges has led to the buildup of this backlog.
New Statistical Approach to Study How an Electric Submersible Pump Population Improves Mean Time Between Failure by 42% in an Ecuador Field
Authors: Andagoya. C Kevin I. , Hidalgo. D Mario H. , Villalobos Jorge L. , Sotomayor Alejandro , Orozco Andrés , Pancho Juan , León Fernando , Reyes Carlos , Enriquez Luis 
Published: November 2024

Abstract
In any electric submersible pump (ESP) population, key performance indicators (KPIs) such as mean time between failure (MTBF), index failure, or run life (RL)/target run life (TRL) are used to keep track the performance of an ESP population. However, what should the stakeholders do in case these metrics decay? In this paper, we introduce a new systematic approach to accurately use population statistics to identify the causes affecting the RL performance so actions to solve them can be taken. The overall approach is to perform a deep analysis of the metrics and detect the causes affecting the RL in a population. A step-by-step statistical analysis aims to segregate the studied population into quadrants. The quadrant range is dependent on the desired TRL of the project or key run life (KRL). Four quadrants are defined, and each quadrant is studied independently using box-and-whiskers plots to learn from them to set accurate actions. Equipment can fail due to the same general reasons; however, this method will study the different root causes and will be digested using different kinds of graphs. This methodology has been used for two consecutive years, showing good results in terms of MTBF on the studied field by increasing it 42%.
Critical Success Factors for Preventing Commissioning and Start-Up Schedule Overrun in Megaprojects
Authors: Elarafi M. G. , Malik N. , Abu A. B. 
Published: November 2024

Oil and gas megaprojects are unique, associated with high execution cost and long execution schedules. The Commissioning and Start-up (CSU) delivery of such projects in offshore environment is a complex task. This is mainly because of harsh offshore environment, logistics limitations, integration with producing fields, uncertainty in subsurface data, design flaws, construction errors, etc. This paper analyzes the actual delivery of CSU in offshore oil and gas megaproject. In addition, it shares with the industry the best practices, mitigations, and recommendations for adoption.
A series of Root Cause Analysis (RCA) sessions were held with subject matter experts (SMEs) from different disciplines and stakeholders such as engineering, operation, reliability, commissioning, and vendors. Moreover, statistical analysis was conducted on the RCA outcomes to categorize them by relevancy. The root cause categories are feedstock composition changes, engineering flaws, construction errors, manufacturing defects, human errors, and inadequate maintenance. In addition, these categories were further rationalized and coupled with schedule analysis to understand the impact of each root cause category on CSU schedule. Finally, insights were drawn from this analysis in the form of project management lessons and best practices.
It is worth noting that the offshore execution of this project took place during the peak of COVID-19 pandemic. The productivity, resources mobilization, and material delivery were heavily impacted due to global lockdowns and changing standard operating procedures imposed by authorities to control the outbreak. The impact from COVID-19 was considerable during the offshore construction phase, which is alternatively known as hook-up phase prior to achieving Ready for Start-up (RFSU) state. It is because the construction progress heavily depends on labor, unlike the CSU progress post RFSU which heavily depends on the actual feedstock properties, design quality, and construction quality. Therefore, the impact from COVID-19 was neglected in this analysis because the paper focuses on the performance of CSU post RFSU.
Feasibility Study of Cryogenic Rotating Packed Bed (RPB) Innovation for Acid Gas Removal in LNG Processing – Design Perspective
Authors: Zamry Ts. Nur Baizurah M , Surmi Ir. Ts. Amiza , Mokhtar Ir. Saiful Anuar M , Tahir Ts. Norazliza Md , Umar Ts. Nurul Amirah Hanim 
Published: November 2024

Abstract
The global demand for gas production is rising rapidly due to economic growth, with the Asia Pacific region among the highest contributors. To meet this demand, innovative technology like the Rotating Packed Bed (RPB) operated at cryogenic conditions is being explored and studied for application focusing on acid gas removal in Liquefied Natural Gas (LNG) processing on floater topside. This study delves on 30% CO2 gas field with high H2S and ethane composition via cryogenic technologies with comparable separation capability as conventional amine-based technologies. The main methodology involves detailed process simulations and benchmarking with conventional commercial floater design as basis for technology scale up. Amongst key challenges regarding cryogenic RPB design on a floater are non-conventional acid gas removal process, plot space constraint, energy intensity, and technology scale-up. This study also highlights the potential improvement of cryogenic RPB design in optimized refrigeration schemes and careful evaluation of heavy hydrocarbon recovery. Overall, the successful implementation of cryogenic RPB design optimization for acid gas removal is crucial to unlock monetization of high CO2 gas field(s).
A Novel Approach to Predict the Performance of All Types of Reservoir Fluids from Heavy Oils to Dry Gases
Authors: Shetia Mohamed Ahmed Taher , El Ela Mahmoud Abu , El-Banbi Ahmed H. 
Published: November 2024

Abstract
This study presents a new approach to predict the production performance of wells producing all types of reservoir fluids, including volatile oils and gas condensates. The developed approach combines the general material balance equation, inflow performance relationship, pseudo pressure calculation, and instantaneous gas-oil ratio equation. Using this approach, an integrated model has been developed to simulate the behavior of oil, gas, and gas condensate reservoirs. Furthermore, a genetic optimization algorithm was used with the integrated model for history matching to estimate the original oil/gas in place, productivity index, and saturation and pressure change with time. The developed model can also be used for production forecasting and reserve estimation. Moreover, it can predict well flowing bottomhole pressure, fluid rates, and reservoir pressure over the reservoir life using only the initial reservoir pressure and some production history. It should be highlighted that the developed model considers several drive mechanisms, including gas cap, depletion drive, and rock and fluid expansion.
The integrated model was validated using fourteen reservoir simulation cases with different fluid types (three cases: black oil reservoir, five cases: volatile oil reservoir, five cases: retrograde gas condensate reservoir, and another case: wet gas reservoir). A field application was then used to demonstrate the model's ability to handle actual field data and predict reservoir performance. The results demonstrated a high level of accuracy and agreement between the results of the simulation cases and those of the integrated model. The errors between the results of the simulation cases and the results of the developed model in all cases were less than 1%. Moreover, the developed model will save time and effort considering that the interface of the developed model is user-friendly and the required input data is limited compared to the numerical simulation applications.
The novelty of this study is that it replaces previous forecasting efforts that apply to only limited ranges of reservoir fluids with a new approach that applies to the full range of reservoir fluids, including gas condensates and volatile oils.
Agile Development of Upper Shuaiba Field in North Oman: From Opportunity to First Oil in Under Two Years
Authors: Huisman Selma E. , Al Badi M. , Al Harthi A. , Maqbali H. M. , Al Rahbi Sataa S. , Al Khusaibi M. , Al Hinai M. S. 
Published: November 2024

Abstract
The Upper Shuaiba formation, located in the North of the Sultanate of Oman, consists of complex clinoform structures characterized by their depositional patterns and lateral facies variations. Despite numerous penetrations from lower hydrocarbon-bearing zones, its commercial discovery occurred in the early 2000s. Subsequently, multiple Field Development Plans (FDPs) were formulated to support the development of the Upper Shuaiba fields. Recognizing the potential for standardized and accelerated maturation, a comprehensive Standard FDP was constructed, facilitating efficient development through predefined guidelines.
The Phase-A development of the best and thickest rudist clinoform in 2019, using horizontal waterflood linedrive, laid the groundwork for subsequent phases. Phase-B, initiated in December 2022, aimed to achieve Final Investment Decision (FID) by November 2023. The maturation of Phase-B focused on determining the number of wells to be drilled, with all other decisions being predefined or governed by standard FDP rules.
Several subsurface risks were identified, including facies distribution, reservoir geometry and thickness, and seismic resolution. The "appraise as you go" philosophy ensured each development phase was contingent on appraisal results, providing flexibility in decision-making.
The standard FDP prescribed rule-based well spacing and orientation, considering factors such as rock type, average permeability, net thickness, and stress regime. The operating strategy emphasized maintaining an instantaneous and cumulative voidage replacement ratio of 1.0, with injection operated under matrix conditions to prevent hydraulic fractures.
Standardization extended to well types and completion designs, with the Basis for Design describing a phased evacuation scheme centered around a Remote Manifold Station (RMS) and satellite stations. Rule-based production forecasting, integrating Phase-A results and analogue well data, guided development planning and ensured economic viability.
Non-technical aspects, including agile working methodologies, a scaled Opportunity Realization process, and a commitment to continuous learning, were critical to the project's success. Synergies with nearby fields further optimized resource utilization and accelerated development.
This paper highlights the streamlined decision-making process and key enablers for the agile development of the Upper Shuaiba field, demonstrating how standardization and innovation contributed to the timely achievement of FID and first oil production.
The Next Generation of Autonomous Inflow Control Device (AICD) for Water Control in Light Oil Applications
Authors: Voll B. A. , Edwards L. , Moradi M. 
Published: November 2024

Abstract
This paper presents the design and qualification of a new autonomous flow control device (AICD) for fluid control at the sand face. This device has the unique ability by taking advantages of both density and viscosity differences of the fluids. It controls the flow of the undesired fluid (water and gas) and avoids any binary (open/close) effect that can result in instability or worse stop production. This device is specifically designed to control water production in ultra-light and light applications and to further improve control of gas production.
This new generation of AICD has been developed to enhance control of water by slowly throttling back as the water cut increases while avoiding closing prematurely at a certain water cut. Additional operational features such as last-minute capacity change, and the ability to circulate to the bottom have also been incorporated into the design for ease of installation and providing flexibility and adjustability even at the rig site.
The device is designed to have an operating point towards open for oil and towards closed for water by careful force field analysis confirmed by single and multi-phase flow testing. Water, oil, and gas mixtures were tested in a state-of-the-art multi-phase loop to fully evaluate and model the flow behaviour under various regimes.
Although not limited to oil viscosity, so far, the device shows excellent performance with oil viscosities as low as 0.5cP tested together with water to define the operating and control points at various water cuts. A full qualification matrix of debris, erosion and cycle testing was also completed and will also be presented in the paper.
The available autonomous inflow control devices/devices in the market are not very effective at controlling water when oil viscosities are below 1cP in many applications. Also, another drawback is the possibility of becoming a "binary" open-close system and shutting off zones too early. This new device addresses both the above phenomena.
Novel Blue Hydrogen and Transportation Process Supporting Global Carbon Footprint Reduction
Authors: Rabie A. H. , Alwahedi Y. F. , Ciotti B. G. , Anguiano J. A. , Merryfield D. L. 
Published: November 2024

Abstract
With the imminent threat of global warming, the international energy industry has sought out alternative fuels to reduce greenhouse emissions. Hydrogen, a clean fuel, has been identified as a promising alternative to carbon-based fuels. When utilized, hydrogen produces no harmful exhaust emissions. Blue hydrogen, also known as low carbon intensity hydrogen, is generated via the reaction of hydrocarbons and steam under heat and pressure [steam methane reforming (SMR)] to create hydrogen-enriched syngas. The hydrogen is then purified via a Pressure Swing Adsorption (PSA) unit. The blue hydrogen production process includes carbon capture, utilization, and/or storage technologies.
In this paper, a proprietary blue hydrogen production process is presented. This technology offers certain valuable differentiators described further in this paper. The proprietary process integrates the waste heat from the hydrogen generation process with the heat demand from the carbon capture process. The heat integration scheme is optimized resulting in no auxiliary boilers or drastically reducing auxiliary boiler capacity for the carbon capture process, reducing CAPEX and OPEX. Moreover, the design reduces the footprint of the facility and increases CO2 capture efficiency by eliminating or reducing the boiler's carbon footprint.
Hydrogen transportation and subsequent use is also reviewed. Hydrogen suffers from a low density even in liquid state. As such, the use of chemical carriers is necessary for practical transportation. Ammonia is the predominant chemical carrier for hydrogen as its transport via maritime vessels is well-established. Nonetheless, the use of ammonia as a chemical carrier entails additional processing. Ammonia production predominately uses the Haber-Bosch method, an exothermic process. Upon transportation to the end user, hydrogen recovery is achieved via catalytic cracking of ammonia over a ruthenium or a nickel-based catalyst. Direct combustion of ammonia in maritime vessel engines is also feasible but requires high pressure ratios or the use of co-fuels.
Challenges of Full Field Polymer-Flood Development from Front End Management of Large Dark Brown Field Towards Delivering Competitive Commercial Scale Project Paper Number: SPE-222812-MS
Authors: Rawahi Z. , Riyami O. , Hadhrami W. , Habhouba E. H. , Qayum S. , Khaziri S. , Huisman S. E. , Nasralla R. , Harthy S. , Zadjali R. , Brown M. , Farsi S. , Nadeem M. , Jadeedi H. , Sulaimani H. , Nofli S. , Hinai S. 
Published: November 2024

Abstract
Polymer flood is a mature technology where it has been applied in several fields in the past decade in Petroleum Development Oman (PDO) whether in full field scale or pilot/trial scale and at different development concepts (vertical and horizontal polymer injection concepts). However, managing such opportunities to develop them at commercial scale competitively is still deemed to be a challenge especially in a dark brown field from Urban Plan, interface/stakeholders/risk management, contracting strategy and execution prospectives. For the field of subject in this paper, full field polymer development plan and concept selection was endorsed with the concept of developing the polymer project utilizing the existing wells stock drilled during the infill waterflooding phase. Polymer flood is scheduled to be on-stream in 2026 injecting polymer in 2 phases with over 100 polymer injectors in total.
The field is a mature dark brown field in South of Oman with waterflood history of over 16 years. Due to the congested nature of the field, it was difficult to define a cost-effective polymer development concept for the entire field. More challenges were faced managing several complexities i.e technology maturation, resources constraint & continuity, contracting strategy endorsement and managing different stakeholders integrating all interface aspects. However, with continuous persistence and innovation, the project has managed to mature total volume of ~ 6% increment with remarkable unit cost reduction (&gt; 50%). Furthermore, additional opportunities were identified to reduce the Unit Technical Cost (UTC) further by 4–5 units cost toward execute phase mainly more efficient polymer facility and chemical costs through competitive contracting strategy and introduction of Category management (CM) approach with further scope optimizations. In terms of Green House Gases (GHG) reduction, the project has demonstrated CO2 reduction in the field to more than 50% compared to Field Infill Waterflood development. This is due to the polymer nature of reducing the water cut in the field and thus reducing the energy required for produced water handling at the surface.
This paper will demonstrate the key Front End Development Management challenges, project risks/opportunities, stakeholders and interface management along with key steps made to efficiently manage validate/de-risk the proposed concepts before the full field implementation driven by Decision Quality (DQ) exercise. Moreover, it will demonstrate the capital efficiency journey to improve project competitiveness through an integrated subsurface and surface efforts along with optimized contracting strategy.
Innovative Well Pad Design to Address Field Congestion Challenges and Cost Optimization
Authors: Calvier Rémi , Ségui Emmanuel , Pilipenko Alexandre , Zykova Elena , El Hadidy Khaled , El Sonbaty Ahmed , Al Jabri Bashaer 
Published: November 2024

Abstract
Mature field congestion is introducing challenges for future developments on surface and subsurface aspects.
The objective of this paper is to share ADNOC Onshore and TotalEnergies’ s combined effort and experience in mitigating the surface and subsurface congestion issues thanks to an innovative and cost-effective revision of the well pad concept.
The different types of existing Mature Field well pads were screened and the typical large Well Pad, providing full flexibility at the project level, was selected for analysis and further optimization to ease its implementation in surface congestion context.
The initial step was to assess the key drivers for the current well pad layout. Collected data were used as a basis to design a new pad concept considering rig fleet capabilities and best engineering practices for similar facilities. Considerations were made regarding the possibility to drill with any rig from the existing AON fleet and the requirement to minimize production shortfalls during well intervention.
Downhole congestion was also looked at, relying on specific simulations performed in various configurations.
In the pad utility area, it was found possible to achieve a significant footprint reduction by applying different design principles. Large volume of piping, valves & instrumentation were removed from the Wellbay area (moved to manifold area) and a culvert concept was implemented to accommodate well flowlines. Well pad shape was optimized by relocating the utilities area close to the well bay area.
Minimal WH spacing was assessed considering 2 types of rigs (one skidding and one non-skidding). The optimum WH distance was found to be 15m considering optimization of drilling operations, ability to cap the well and possibility to perform Work Overs with a drilling rig. It was demonstrated that distance could be reduced to 10m if smaller WO units were made available.
Considering downhole congestion only, simulations showed that WH spacing could be reduced to less than 5m and still be able to drill any well with no significant impact on cost and duration. Specific drillability issue on new wells were also studied and resolved.
Advantages of such a novel well pad design are: Overall footprint reduction by 60% (divided by 3) without major compromise on initial well pad designing criteria'sSignificant Capex savingsMassive reduction of piping length and hydrocarbon inventory (at least 30% reduction)Minimized time for preparation of WO & equipment re-installation after WOFaster drilling operations when skidding rig can be used (batch drilling)