bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhancing Mercury Removal in Hydrocarbon Fluids: Efficacy of Aqueous Sulfides Extraction in Natural Gas Condensate and Produced Water
Authors: Wong Sharizal M. A. S. , Salam Sawan A. 
Published: February 2025

Abstract
This study demonstrates the effectiveness of aqueous sulfides (Na2S, (NH4)2S, and K2S) for mercury removal from matrices of stabilized condensate (from onshore and offshore sources) and produced water (synthetic and offshore). Aqueous sulfides successfully extract various mercury species, including Hg(NO3)2 in produced water and Hg° and HgCl2 in condensates, likely through an oxidative-complexation reaction that results in the formation of β-HgS (metacinnabar). An optimal sulfide-to-mercury(II) concentration ratio of 1:1 was identified, with sulfides in molar excess relative to mercury for efficient complexation. In single-matrix samples, mercury extraction efficiencies varied by species and matrix, achieving up to 50% for HgCl2 in onshore condensate, 52% for Hg° in offshore condensate, and 95% for Hg(NO3)2 in synthetic produced water. Higher extraction in aqueous matrices was attributed to the greater miscibility of sulfides in water, enabling intimate contact with mercury species. The addition of a strong oxidant (i.e. Aqua Regia) to condensate containing Hg° and HgCl2 before sulfide treatment further enhanced extraction. In mixed-matrix samples, mercury removal efficiencies of ≤47%and ≥50% were observed for biphasic samples containing Hg° + Hg(NO3)2 and HgCl2 + Hg(NO3)2, respectively. The application of aqueous sulfides for mercury treatment in condensate and produced water presents a feasible approach for bulk mercury removal, affording up to approximately 50% mercury removal.
A Second Look Assessment on a Debris Formation on Subsea Saturated Pipelines with Sulfate-Reducing Bacteria Contaminated: A Novel Approach Flow Assurance Modelling
Authors: Pamula M. O. , Henda A. I. , Rahmadani H. E. , Kaban A. P. S. , Nurzaenal F. R. 
Published: February 2025

Abstract
Inspection and monitoring of gas pipelines are inseparable, and they are critical factors in controlling the threat of saturated gas and sulfate-reducing bacteria (SRB). An alternative method is required to obtain the precise worst condition location in the pipelines without inline inspection (ILI). This work aims to determine the inspection location using flow assurance simulation (FAS) before it undergoes ultrasonic testing (UT) inspection on the solid subsea pipeline contaminated by the SRB. The flow assurance simulation (FAS) approach merges an understanding of the gas behavior in the pipelines. The FAS considers several factors, such as pipeline bathymetry, fluid properties, flow, pressure, and temperature, before it produces the debris location profile in pipeline/liquid holdup. It is presumed that a higher density of debris becomes a hub for the SRB to corrode the pipelines. The method ponders the worst case of possible microbiologically-induced corrosion by determining the severity of pipelines when the under-deposit SRB was found. The ultrasonic testing (UT) inspection is conducted at the location to represent the actual pipeline integrity condition. The case study uses 2 pipelines, including the gas lift (GL) pipeline from platform A to platform B, and the second pipeline is a main gas line (MGL) from platform X to platform Y. GL pipeline gas is an outlet of compressor system after separation process while the MGL pipeline is a direct pipeline from gas well to processing facilities. For the GL pipeline, The FAS results show that the approximate location for the liquid hold-up is Kilometer Post (KP) 2.9. The locations are subject to further inspection by UT, where the SRB is suspected to accumulate. Furthermore, the UT inspection result indicates wall thinning of 0.1 mm, and the measured thickness reduced by 0.8% compared to the initial thickness of 12.7 mm, with 0.009 mm/year of corrosion rate. For the MGL pipeline, the FAS results show some approximate locations for the liquid hold-up. As subject to further inspection by UT, the locations where the SRB is suspected of accumulating are at KP 16.4. Furthermore, the UT inspection result indicates wall thinning of 1.7 mm, and the measured thickness was reduced by 13.4% compared to the initial thickness of 12.7 mm, with 0.02 mm/year of corrosion rate. It is deduced that the simulation using FAS is beneficial for equipping an early location simulation in conjunction with utilizing the UT system. Regular monitoring is required to validate FAS results. The work offers a novel method for determining the inspected location using flow assurance simulation (FAS) before it undergoes ultrasonic testing (UT) inspection on the solid subsea pipeline contaminated by the SRB.
Design Modeling Methodology to Optimize Fracturing Treatments Using Temperature Logging
Authors: YILMAZ K. , ALABDULMUHSIN A. H. , HARBI M. M. , CHAN C. H. 
Published: February 2025

Abstract
This paper highlights the importance of incorporating Mechanical Earth Model (MEM) data into hydraulic fracturing simulations for accurate fracture geometry predictions. While 1D MEMs yield limited results, 2D and 3D MEMs provide higher-resolution geomechanical interpretations, particularly in formations characterized by high lamination and tectonic stresses. Although 1D MEMs have inherent limitations, their accuracy can be enhanced through calibration techniques that utilize minifrac diagnostics and improved fracture height predictions achieved via temperature logging.
Temperature logging not only aids in estimating fracture height but also enhances the predictions of fracturing fluid temperature dynamics, which optimizes breaker usage and minimizes potential formation damage.
A combined fracturing workflow that integrates both minifrac diagnostics and temperature logging was effectively implemented in a shown example here (Well B), resulting in numerous advantages over another shown example (Well A). Notably, this approach yielded improved simulations of fracture height and parameters in the Lower Interval, enabling the execution of additional fracturing stages and larger treatment sizes. Furthermore, the enhanced simulation accuracy significantly reduced the risk of premature treatment screen-outs, thereby improving operational efficiency.
The application of temperature logging provided more accurate predictions of fluid temperature exposure during treatment. This facilitated the optimization of breaker concentrations to ensure proper gel breaking and minimizing damage to the formation.
The findings underscore the importance of utilizing advanced techniques such as MEM data, minifrac diagnostics, and temperature logging to enhance the design and execution of hydraulic fracturing operations, ultimately leading to improved production outcomes. By demonstrating the value of this combined approach, the outcomes sets the foundation for future enhancements in hydraulic fracturing practices, particularly in complex geological settings.
Cost Effective Waterflooding From Dump Flood to Forced Water Injection Reduces Risk Improves Production and Increases Recovery in a Brown Field
Authors: Mandal Dipak , Amirul Rj M , Das Gunajit , Azmee Khairul , Yusoff Lailatul Zuraida , Sinha Ankaj , Nazir Faizall , Sobri Sabrina 
Published: February 2025

Abstract
Brown field rejuvenation has always been one of the yardsticks of any operator to provide that additional support to make up for the decline in national production. Field B in Sarawak offshore of Malaysia has highly compartmentalized stacked reservoirs producing since 1980s. A few reservoirs which were on depletion drive, had been depleted but with low recovery factor and becoming idle after about 30 years of production in late 2010. With most of the major reservoirs having strong aquifer support getting into high water cut, the field production declined significantly then. In 2014, the first successful natural Dump Flood injection in Malaysia has increased oil recovery by about 6% till date in one of these depleted reservoirs at low cost. This paper details the lessons learned of Dump-flood management which included well stimulation to improve injection and timely reservoir surveillance, with choke optimization in producers to improve production. Since then, based on this success, several dump-flood water injection projects have since been initiated which improved production. MPLTs which helped to understand reservoir continuity and injectivity effectiveness, prompted the operator to evaluate forced water injection from surface for some these reservoirs. The objective of this paper thus explains the steps taken to learn from Dump-flood to initiate Forced Water Injection and thus reduce waterflood risks with phased exposure to cost.
The FFR study that followed, identified redevelopment opportunity in one depleted reservoir with significantly high STOIIP, but having a low recovery factor. In 2022, one idle well in this reservoir was converted into a dump flood injector, but achieved low injection rate, thus low incremental production. With injectivity achieved and production injection response being monitored for few years, initial understanding on risk mitigation of water injection in this reservoir was understood. Leveraging on this experience, based on a history matched reservoir model, forced Water Injection including the usage of the existing Dump-flood well as a forced water injector with few infills have been proposed to improve waterflood recovery by additional 12%. Portable Water Injection Module has been considered to reduce overhead CAPEX.
This paper thus provides the stepwise methodical approach to de-risk water injection projects in mature assets by steadily building on the success of low-cost pressure maintenance options like dump-flood and progressing into Forced Water Injection to increase the hydrocarbon recovery, reverse the production decline and prolong the economic asset life with minimal risks and phased investment.
Real-Time Reservoir Characterization: The Identification of Sweet Spots Through New Measurement
Authors: Manuaba I. B. G. H. , Berkane M. , Ali A. M. , Charupa M. 
Published: February 2025

Abstract
Re-evaluating brownfield sweet-spots is a strategic move in the oil and gas industry aimed at unlocking reservoir potential and extending the productive life of existing assets. This provides economic benefits and minimizes the need for new exploration and development activities. Saturation profiling in water flooded reservoir that undergo active water injection is a major challenge. Fingering of injected water complicates saturation determination efforts because miscibility of injected and formation water results in salinity alteration. Another uncertainty is related to depletion, which could lead to changes in oil properties which could further affect the production. Numbers of effort to characterize formation water, one of them using pulsed neutron log, detailed in Ma, S., et al. (2014).
To address these challenges, advanced reservoir characterization techniques are essential. Among established methods, downhole in-situ fluid characterization, as detailed in Hursan et al.'s work (2016), remains a viable option for concurrent implementation alongside formation testing and sampling activities. A new workflow was developed integrating petrophysical formation evaluation and advanced fluid characterization with wireline formation testers (WFT). In this workflow, dynamic in-situ water property measurements are used to update the saturation profile in real time. The most challenging part is to obtain valid salinity measurement downhole in the presence of mix flow when oil and water are flowing simultaneously. WFT equipped with a dual inlet dual packer utilize a dual flowline system and advanced InSitu fluid analyzer to identify fluid volume fractions, segregate oil and water to estimate water salinity and to characterize the oil phase in real time
Adopting this workflow, it was possible to identify zones where the water fraction was dominated by injection water with an order of magnitude difference in salinity compared to the original connate water. As a result of re-calculating the saturation profile using a zoned salinity, a more accurate estimation of the oil-water contact (OWC) was achieved which was confirmed by downhole fluid analysis (DFA). This is a significant outcome because it enables real-time identification of the accurate oil-water transition zone. Based on this data, a dynamic decision can be made with regards to lateral well placement without waiting for laboratory analysis to be completed. In addition, a constant composition experiments (CCE) were conducted downhole in reservoir conditions. Key parameters such as saturation pressure and compressibility were identified.
By leveraging downhole measurements in near real-time, the exact position of the Oil-Water Contact (OWC) can be determined, enabling informed decisions to adjust lateral well trajectories dynamically. Understanding how oil properties evolve over time enables more effective reservoir management decisions to maximize reservoir drainage and hydrocarbon recovery.
State-of-the-Art Drilling Dynamics Modeling for Two Consecutive Long Hole Opening Sections in a Deviated Well with Single Run Approach
Authors: Nik Mohd Najmi N. F. , Mohd Nor H. , Ma Jing 
Published: February 2025

Abstract
Designing a robust underreaming BHA for a long and deviated well can be extremely challenging especially with the presence of problematic interbedded formation compounded by thick hard stringers. A successful hole opening drilling operation is massively contributed by the durability of cutting structures and the dynamic stability of the rock removal process.
There are various determining factors in achieving stable drilling dynamics including cutting structure design, BHA design, rock formation type, well trajectory, friction factor, and drilling parameters. Conventional methods of modeling which utilize simplified static soft-string algorithms and generic mathematical models do not consider these key elements in drilling dynamic. Hence, they lack the accuracy to be used as a predictive tool towards drilling performance and dynamic behavior.
A cutting-edge physics based finite element modeling was applied to analyze the drilling dynamics for this appraisal well. Cutter-rock interactions are being considered for each individual cutting structures in the BHA, ensuring the ability to determine the cutting forces acting toward the bit and reamer which can then be translated into drilling system behavior. A wide range of worse-case scenario were simulated based on several lithology exposure, different BHA designs, and optimized drilling operating windows.
Previous offset well failure incidents were also re-modeled and calibrated, and lessons learnt from the root cause investigation were shared as knowledge sharing and pre-planning engineering input for the upcoming well to prevent repeating same problems. Recommendations were given in terms of best optimized BHA design and cutting structures, and stable drilling parameters roadmap to avoid any potential shocks and vibration issues. A comprehensive engineering package was then given to the offshore team to implement in the operation.
As a result from executing the modeling recommendations, both 18-1/8in × 19-1/2in and 14-3/4in × 16-1/2in hole opening sections were drilled successfully with an impressive multiple rig-days saving against planned duration. Bit and reamer dull reports showed very minimum cutters wear, indicating a stable drilling performance. The single run strategy and all directional requirements were achieved without any unexpected downhole issues. The combined 2,213m depth interval puts this remarkable achievement in the record book as the longest hole opening operations in Asia.
This paper will share the experience gained and technical learnings from the drilling dynamic modeling done which contributed to the success of drilling these two long hole opening sections with single run approach.
Maximizing Oil Production by Leveraging Python for Gas Lift Optimization Through Well Modelling
Authors: Suharto M. Arshad , Risal A. Rahim , Subandi Ahmad Nabil , Trjangganung Kukuh , Zain A. M. , Ahnap M. S. 
Published: February 2025

Abstract
Gas lift optimization is crucial in enhancing oil and gas production by maintaining efficient reservoir pressure. However, traditional optimization methods often lack automation and fail to consider the complex interaction of parameters such as tubing head pressure (THP), gas injection rate, and gas injection depth. This study aims to develop an integrated automated system using Python programming and PROSPER well modelling software to automate gas lift optimization and analyze the impact of THP, injection rate, and injection depth on system performance. The methodology involved data gathering, data pre-processing, integration of the automated system, and data visualization. The results include improved gas lift system performance, optimized production rates, and the conclusion demonstrates the groundbreaking achievement of automating sensitivity analysis for a total of 5 gas lift wells within minutes. Taking Well A001 as an example, it can be concluded that the wellhead pressure must be set at 167 psig, the lowest possible pressure and the gas must be injected at 4455 ft, the deepest point possible, and at an optimum rate of 0.67 MMscf/d. These conditions are required to increase production to a maximum rate. Besides that, to conduct optimization of a single string gas lift well, the time efficiency is increased by 99%, from 7500 seconds to only 45 seconds. Integrating Python programming and Prosper software sets the stage for enhancing production efficiency, making this research a significant step toward a more efficient and productive future.
Study on Flow Behavior and Adsorption Characteristics of Encapsulated Polymer Particles
Authors: Liu Yongsheng , Wei Bei , Hou Jian , Zheng Ningyu , Qin Xuwen , Zhang Yang , Guo Zhixin , Zhang Dequan 
Published: February 2025

Abstract
Encapsulated polymer refers to Micro/Nano-scale particles with polymer as the core, which can release the polymer to achieve thickening. Encapsulated polymer flooding is a new type of deep profile control technology suitable for further improving the oil recovery of conventional reservoirs. However, the adsorption and temporary blockage behaviors of encapsulated polymer particles in porous media significantly affect the accurate description of their targeted viscosity enhancement. On this account, we investigated how encapsulated polymer particles adsorb and temporarily block.
Using PDMS material microfluidic chips, we investigated the flow behavior of encapsulated polymer in seven different pore throat structures. High-precision pressure sensors and microscopes were employed to real-time capture microscopic flow images of microcapsule particles inside single micro-channels and observe pressure fluctuation characteristics. Based on particle image velocimetry (PIV) systems, we studied the diverting fluid behavior in parallel micro-channels with different width ratios. Building on this, we conducted dynamic adsorption experiments to quantitatively characterize the adsorption and retention behavior of encapsulated polymer particles in porous media.
In this study, we observed four phenomena of free flow, surface adsorption, blockage, and multi-particle aggregation slug flow during the flow of encapsulated polymer particles in a single microchannel. In parallel microchannels, the capsule particles exhibited selectivity towards flow paths, primarily entering wider throats. With the increase of the width ratio, the encapsulated polymer particles in the narrow throat are more confined and are more likely to accumulate in the throat and cause blockage. Experiments in porous media show that the adsorption and retention of capsule particles are inversely proportional to the permeability. The particles are more inclined to flow along the high permeability dominant channel. The overall adsorption capacity of particles is weak, which is conducive to their migration into the reservoir.
Encapsulating polymer effectively resolves the contradiction between the efficient injection into and deep effective profile control of conventional polymer flooding in reservoirs. This paper takes the adsorption and blockage properties of encapsulated polymer particles as a starting point to provide relevant insights into the ease of migration of encapsulated polymer towards the deep reservoir, offering valuable perspectives for targeted thickening description and field application of encapsulated polymer.
Application of Geological Concepts in Dynamic Model History Matching for a Heterogeneous Giant Carbonate Reservoir, Offshore Abu Dhabi
Authors: Montani Hiroki , Yamamoto Kazuyuki , Inokuma Yuto , Yamashita Seiji , Kondo Itsuki , Farooq Umer 
Published: February 2025

Abstract
This study aims to enhance predictive accuracy in dynamic reservoir modeling through geological integration of static model and field historical data. It specifically focuses on horizontal permeability enhancement, targeting better alignment with production history.
Utilizing a combined approach of geological concept application and data analysis, this study conducted core and thin section observations from 39 wells, in addition to image log data analyses from 8 wells. The study identified and classified geological non-matrix features (dissolution vugs, various types of fractures) that influence fluid flow, examining their correlations and trends with reservoir properties such as rock type, porosity and permeability.
The comprehensive analysis led to the successful delivery of geologically reasonable horizontal and vertical permeability models that align with historical dynamic data. Through detailed observations and classifications of the geological non-matrix features which contribute significantly to the fluid flow within the reservoir, the study highlighted the discrepancies between matrix permeability and well test permeability. This discrepancy primarily stems from the different measurement scales and the non-consideration of significant geological features in the static model. Certain static rock types were found to be predominantly vuggy and micro-fractured, which required targeted permeability enhancement. Additionally, long planar fractures were found to develop in areas with low porosity, indicating that modeling of these features in such areas aligns with field history and improves model accuracy. These findings not only challenge existing methodologies but also propose a more integrated and geologically reasonable approach to reservoir modeling.
This study introduces innovative methodologies for incorporating geological concepts into reservoir modelling, particularly in the interpolation of static and dynamic data to enhance prediction accuracy. Our findings provide new insights into the integration of geological features with reservoir properties, offering significant implications for improved reservoir management and recovery strategies in the petroleum industry.