bluuebunny/crossref_metadata_2025_split huggingface dataset:
Self-Granulating Thermoplastic Elastic Particles for Fracture Conformance Control in Ultraharsh Reservoirs: Laboratory Investigation and Field Application
Authors: Xue Yan , Yin Qiulu , Zhang Chunquan , Wei Bing , Lu Jun , Wang Yiwen 
Published: October 2024

Summary
To address the challenges in fracture conformance control using polymer particles in ultraharsh reservoirs, we developed novel self-granulating thermoplastic elastic particles (SGTEPs). The innovation was driven by the complexity of the traditional polymer particle preparation process and the difficulties in balancing injectivity and conformance control performance. Polyvinyl alcohol (PVA) served as the particle skeleton, and millimeter-scale SGTEPs were prepared in situ by incorporating a hydrophobic modifier (HM) and a cross-linking agent (glutaraldehyde, GA) into an aqueous phase. The morphology, mechanical properties, and high-salinity thermal stability of SGTEPs were investigated using scanning electron microscopy (SEM), texture profile analysis (TPA), and thermal aging tests at 130°C. Particle size adjustability was demonstrated through the modulation of HM content and stirring speed. TPA highlighted SGTEPs’ superior elasticity and resilience. SGTEPs underwent thermal plasticization in ultrahigh-salinity brines (22.0 × 104 mg/L, Ca2+ + Mg2+ = 1.2 × 104 mg/L) and crude oil at temperatures up to 130°C, retaining exceptional mechanical properties even after 60 days of aging. Open fracture models were designed to investigate the effect of particle size, injection rate, and particle concentration on SGTEPs’ migration performance. Coreflooding experiments indicated effective migration and conformance control performance of SGTEPs, with appropriate matching coefficients of 1.45 and 1.50. The particles exhibited an “aggregation → accumulation → deformation migration” effect, with particle concentration linearly affecting differential pressures. After high-temperature aging, SGTEPs could efficiently plug the open fracture, achieving breakthrough pressures up to 1860 kPa. Field application results showed significant improvements in oil production and water-cut reduction. Specifically, the daily oil production of Well TK466 increased from 4.6 tons to 15.5 tons, with an incremental oil production of 252.5 tons per well and a reduction in average water cut from 90% to 82.7%. The newly developed SGTEPs offer a fresh perspective on material design for enhancing conformance control in ultraharsh condition reservoirs with large fractures and void spaces. The novel particles demonstrated excellent thermal stability, elasticity, and migration and plugging performance, making them a promising solution for improved oil recovery in challenging reservoir conditions.
Coating System Selection on Offshore Flare Bridge Structure Using Maximum Temperature Estimation from Flare Radiation Simulation
Authors: Hardiananto N. , Harmantoro A. , Anfasa F. , Hartono E. 
Published: October 2024

Abstract
Offshore structures are highly susceptible to general corrosion which can lead to damage and lower the mechanical strength of the structure. Flare bridge structure are more susceptible to corrosion, due to experience combined effects of the corrosive marine environment and thermal radiation from flare. It is important to select a suitable coating system by considering the affected temperature. This paper will discuss about a brief case that describes how coating system selection is implemented in PHE ONWJ using a flare radiation simulation to estimate a maximum temperature.
This study was started by reviewing previous Flare Heat Radiation and Dispersion Study in ‘U’ flow station to focus on flaring scenario, flare design data, and flare heat radiation contour. The next step is calculating the flare bridge temperature due to flare heat radiation exposure. This work combines four steps: (1) Collect flare bridge data, (2) Define maximum heat radiation based on flare contour, (3) Calculate the heat radiation received by flare bridge, (4) Calculate the flare bridge temperature. Lastly, select the coating system which considers the estimate of the flare bridge surface temperature and corrosion resistance to marine environment.
The flare bridge temperature is estimated to be 136°C based on conservative calculation as affected by emergency flaring scenario that last(s) approximately 15 minutes of maximum flare relief duration. After the emergency flaring is over, the fluid service temperature slowly drops to the ambient temperature (approximately 28 to 30°C). This scenario is considered as the conservative approach due to the highest flow rate and maximum thermal radiation applied.
Hence, apart from considerations to select an appropriate coating system such as: Minimum area average roughness, Sa 3; Prime coat functions as corrosion resistance in cyclic temperature; it should be considered that the coating temperature resistance &gt; 136°C. Referring to the company's coating specification, we select BM 4-1 for coating the flare bridge structure.
This practical approach aims to achieve as low as reasonably practicable coating system on the offshore flare bridge structure. Coating refurbishment using the selected coating system is expected to be highly suitable and can stand last for a long time.
An Advanced Workflow and Tool to Map New Sweet Spot and Enhanced Well Placement Strategy using Machine Learning in Unconventional Reservoir
Authors: Wan Sagar S. F. S. , Trianto A. , Musa I. H , Hendraningrat L. , Mazeli A. 
Published: October 2024

Abstract
Unlike conventional reservoirs where the reservoir rock formations are recipient of hydrocarbons from the source rock, unconventional formations constitute both the source and the hydrocarbon containing reservoir units. For the field development, horizontal wells are drilled and later hydraulically fractured in order to produce the gas. The placement of horizontal wells is crucial for the economic viability of the field. This paper describes developing an advanced workflow of new sweet spot mapping and a standalone tool to enhance horizontal well placement and completion optimization using machine learning.
The tool, called Sweet Spots Machine Learning (SS-ML) is developed to integrate petrophysics, geomechanics, seismic, completions attributes and production data in order to map out high productivity zone that will help optimize well placement strategy. This study focused on a case study in Unconventional reservoirs in Canada. The procedure integrates all data from multiple domains such as Petrophysics-Geomechanics-Seismic-Completions attributes with the field production data and establishes a machine learning model (ML) in order to predict and map-out production sweet spots. The output 3D predicted production volume can then be employed to help optimize well placement and completions strategy.
In general, unconventional reservoirs are difficult to produce as they are made up of very tight rocks containing hydrocarbons that cannot be produced without stimulation. Twelve key factors influencing subsurface parameters were identified for controlling production performance in this unconventional reservoir. High productivity sweet spots were identified to be zones with high organic content, high rock stiffness, and low horizontal stress condition. The machine learning model was developed and validated against production wells for sweet spot prediction. Then, 6 new wells were drilled and successfully identified sweet spots with success ratio above 83%. According to the findings, most current production levels fall within an acceptable range that exceeds predictions.
The advanced workflow and new developed tool ML model allow future well placement optimization for this unconventional reservoir in Canada. Zone-based splitting of training and testing wells is recommended for unconventional reservoirs ML modelling to improve accuracy.
Experimental Characterization of H2-Brine-Cement Interactions on Wellbore Integrity During Underground Hydrogen Storage in Depleted Gas Reservoirs
Authors: Zeng Lingping , Lupton Nicholas , Wong Sherman , Heryanto Deasy , Arjomand Elahel , Sander Regina 
Published: October 2024

Abstract
The transition to renewable energy sources has increased the need for efficient and sustainable energy storage solutions, with Underground Hydrogen Storage (UHS) in depleted gas reservoirs emerging as a promising option. Maintaining wellbore integrity in such environments is critical, yet the interactions between hydrogen, brine, and cement, particularly with chemical additives, remain insufficiently understood. This study addresses this gap by investigating the effects of hydrogen and brine on the mineralogy and microstructure of cement with and without chemical additives. We conducted a series of experiments, including X-ray diffract (XRD), scanning electron microscopy (SEM), micro-computed tomography (micro-CT), and water chemistry measurements, to evaluate changes in cement composition and integrity over time.
Key findings reveal that while the primary mineral compositions of cement, such as Portlandite and Calcium-Silicate-Hydrate (C-S-H) compound, transform under hydrogen and brine exposure, chemical additives such as fluid loss, dispersants and retarder show minimal impact on these changes. The average size of the interconnected pore networks increased significantly, but the increase was much lower in cement with additives (38.3%) compared to without (324.6%), indicating that additives help inhibit pore network expansion. Despite this, the overall porosity remained stable. Micro-fractures were more uniformly distributed in cement with additives, whereas in cement without additives, cracks connected existing pores, forming larger void networks. However, the generation and propagation of micro-fractures are more likely due to the changes of temperature and pressure during the samples loading rather than the impact of H2. Ion concentrations, including Na+, K+, Ca2+, and Cl-, remained largely stable, with only a slight increase in SO42- due to gypsum dissolution.
These results suggest that the impact of hydrogen on Class G cement is generally negligible, with minimal changes observed in overall mineral composition. While chemical additives offer some resistance to structural changes induced by hydrogen and brine, their overall effectiveness is limited. The study underscores the need for developing more robust solutions to enhance the durability and strength of cement in UHS applications, which is crucial for the long-term stability and safety of subsurface hydrogen storage systems.
Dual Simultaneous Production and Injection Completion in the Same Well: A Successful Pilot in the Greater Burgan Field
Authors: Ahmad Fajer , Yaser Mohammad , Prakash Roshan 
Published: October 2024

Abstract
With over 75+ years of production from the world's biggest clastic reservoirs of Greater Burgan (GB), Kuwait Oil Company (KOC) Asset team is taking lot of efforts in managing the new well delivery by optimizing drilling targets, both surface and sub-surface. In coming months/year the drilling campaign will be enhanced to drill ∼150-200 wells/year to meet the aggressive production target of ∼1.5 MMBOPD. One of the biggest challenge the asset is facing is to Drilling-Complete-Connect all these upcoming wells in the multi-layered reservoirs of GB, having surface limitations due to existing production and injection infrastructure in the field. Combining injector completion in shallower reservoir and producer completion in the deeper reservoir using a type of dual completion called Simultaneous Injection and Production (SIP) technology is the way to go to achieve the aggressive production targets.
A lot of new technologies is being implemented in the GB field to optimize the production, SIP is considered to be very effective as it will reduce the capex of drilling less wells, take less surface foot-print and have simpler well operation.
The biggest limitation for the SIP technology is the wellbore accessibility for surveillance, which can be overcome by installing the permanent Distributed Temperature Sensors (DTS) which can help in the production/injection flow profiling and help in optimizing the rates. To increase the life of the well, Rigless ESP will be required in the future when the well will cease to flow naturally due to increase in the water-cut of the producer string.
Dual completion technology is not new to the Greater Burgan fields, several dual completions have been implemented as dual producers for the last 30 years however special care must be taken in the SIP completion design where simultaneously cold fluid will be injected in one zone and hot reservoir fluid will produce from other zone using parallel tubings. The paper presents the detailed study done in the SIP design and successful implementation of the initial candidates.
Deploying Can Installed Pumping System in an Existing Well Slot for Multiple Reservoir Support
Authors: Nasharudin N. , Siew C. , Ibrahim M. , Holmes A. , Bakar H. , Fadzil N. A'akif 
Published: October 2024

Surface water injection method remains the most widely method used method to provide pressure support in the Petroleum Industry, either through treated seawater injection (SWI), produced water re-injection (PWRI) or an existing Aquifer Water Re-Injection (AWRI). Either method or system will need sufficient footprint on the producing platform with maintenance intensive procedures due to pipework integrity monitoring, chemical injection and rotating equipment checking or preventive maintenance.
SWI is a complex method as compared to PWRI as the asset will need to lift water from the sea through high volume pumps passing a series of course and fine filters to remove marine debris. Given the live nature of seawater, bacterial growth tendency is higher thus biocide treatment is often considered to prevent reservoir souring over time. Seawater contains organic material which often reacts with formation water that may increase the scaling tendency therefore requires scale inhibitor treatment. This reaction and exposure may introduce oxygen within the water which requires de-oxygenation using a vacuum tower preventing corrosion downhole especially for the carbon steel tubulars range. These comprehensive treatment facilities will require suitable monitoring systems to ensure the water specification introduced into the reservoir is being in specification, avoiding formation damage and reservoir souring and potential reduction in reservoir permeability affecting production.
Longest Slim Hole ERD Wells Campaign with Limited Entry Liner Using Water-Based Mud in the Region
Authors: Varma Esha Narendra , Ditzler Theodore Jay , Sumaida Ali Ben , Mwansa Peter Levison , Husien Mohammad , Bahrom Abdul Raman Bin , Saragi Raymond 
Published: October 2024

Abstract
Extended reach drilling (ERD) can facilitate the development of untapped resources, reduce greenhouse gas emissions, surface congestion, and drilling costs. This ERD project with lower completion was started with an aim to lower well cost indicators including $/ft and $/bbl. Therefore, the challenge was to drill Slimhole ERD (6-1/8" lateral) wells with water-based mud (WBM). WBM is more cost-effective, environmentally friendly, and less damaging to the reservoir than OBM (oil-based mud). The use of WBM instead of OBM can save 20% per well. The major challenges in drilling Slimhole (6-1/8" size) ERD well with lateral leg include higher torque and failure to deploy lower completion due to high friction factors.
The first pilot well was planned with a liner-less design considering the low friction factors required to drill 15,000’ of 6-1/8" lateral hole and run the lower completion. The second pilot well was targeting a deeper and tighter reservoir zone with higher downhole temperatures. This involved drilling 12-1/4" intermediate hole to the landing point with larger 5-1/2" drill pipe. It enabled a push-pipe technique for drilling the lateral hole with improved weight transfer through the curved profile. The 6-1/8" lateral hole was drilled with 4" high-torque drill pipe, tandem high-flow circulating subs, and specially formulated drilling fluid lubricant. A conventional OBM system provides sufficient lubricity to reduce friction factors as low as 0.10. In this application, a low cost WBM system was made feasible by introducing stable high-temperature lubricant and unique hole cleaning practices.
Following this successful achievement, the 5-year business plan has been revised to include 63 similar wells with a projected total savings of ∼ 30-40% per project.
The Slimhole ERD project has demonstrated substantial value with a 35% reduction in CAPEX. The delivery of these two Slimhole ERD wells overturned conventional drilling and completion practices.
The implemented project resulted in saving up to 35% of the well cost and saved 20 days per well compared to a conventional ERD well with 8-1/2" hole and OBM. These two Slimhole ERD (15,000’ lateral) wells were drilled with a challenging Directional Difficulty Index (DDI) of 7.2. The wells were both completed successfully by running the 4-1/2" lower completion to reach the total depth.
Optimization of ERW Well Drilling In Real-time: Integrating Geosteering Techniques and Drilling Parameters for Reduced Geological Uncertainty
Authors: Carrillo L. A. , Flores R. , Roa D. G. , Vargas A. J. 
Published: October 2024

Abstract
During the drilling of extended reach wells (EWR), understanding the stratigraphic position and apparent dip of the local geological structure is crucial for decision-making. It poses a significant challenge due to the variability of local dip angles along the wellbore, hindering correlation with neighboring wells and the determination of optimal drilling parameters. The proposed methodology aims to optimize EWR drilling by reducing uncertainty in the knowledge of the stratigraphic position and automating the analysis of drilling parameters. Using geosteering and drilling software technologies supported by machine learning, real-time parameter comparisons from a geological perspective were conducted, allowing the identification of the expected main fault in the geological model and estimation of apparent dips from conventional gamma ray and resistivity logs. This provided a detailed understanding of vertical layer displacement post-fault in the subsided block, along with obtaining true vertical thickness (TVT) logs to define geological boundaries and control stratigraphic position correlatable with neighboring well drilling parameters. This facilitated forward projections, determined casing setting depths, enabled effective entry into the main target, and recommended parameters for optimal performance, thus expediting real-time decision-making. Precise setting adjustments were achieved, continually optimizing the drilling process by varying parameters informed through the integration of both technologies. The combination of model-based geosteering techniques and stratigraphy, along with the integration of drilling parameters, has significantly reduced geological uncertainty in drilling highly deviated wells. This methodology has demonstrated notable improvements in operational decision-making. This unique combination could offer an innovative and practical perspective for practicing engineers, providing them with more precise and effective approaches for real-time decision-making and continuous drilling process optimization.
Feasibility Assessment of Tiltmeter Monitoring for an Offshore Monoclinal Dipping Saline Aquifer CCS Site: Insights from Coupled Geomechanical Modeling
Authors: Ashida A. , Tsusaka K. , Mochiji S. , Coelho G. , Himeno M. , Iino A. 
Published: October 2024

Abstract
This study investigates the feasibility of tiltmeter monitoring for an offshore monoclinal dipping saline aquifer CCS site. The objective is to quantitatively evaluate the response of seabed deformation that can be monitored by tiltmeters through coupled geomechanical modeling. Additionally, the study explores the potential of integrating tiltmeter data with coupled geomechanical modeling to provide insights into pressure propagation and potential plume movement during CO2 injection. A 3D geomechanical model was constructed by applying a machine learning technique to a 1D geomechanical model and seismic attribute data. This model was coupled with a reservoir simulation model to perform one-way coupled analysis, simulating the injection of CO2 at a constant rate over 25 years. The analysis involved extracting predicted deformation amounts on the seabed and calculating tilt changes. The predicted seabed tilt changes were then compared with the CO2 plume and pressure front to investigate their correlations. As a result of coupled simulation, the predicted seabed deformation was consistently found to be less than 1 centimeter and within the expected range of similar injection operations. The tilt changes were also very small, on the order of several hundred nanoradians. The predicted deformation of the seabed and tilt changes were observed even though pressure changes occurred only within the reservoir. The regions exhibiting tilt changes aligned with the CO2 plume and pressure propagation areas, indicating that continuous tilt monitoring could capture spatial and temporal CO2 advancement behavior. Notably, there is a point where the trend of the tilt change over time varies in the tiltmeter near the injection well. At the timing when the trend of tilt change deviates, pressure changes gradually propagate towards shallower depth, and it is observed that pressure progresses to the secondary seal formation. The results indicate the potential for monitoring local vertical pressure propagation through tiltmeter monitoring. This study demonstrates that utilization of tiltmeters as monitoring tools not only allows for the measurement of seabed deformation induced by CO2 injection but also enables the prediction of the advancement behavior of the CO2 plume and pressure front when interpreted in conjunction with coupled geomechanical simulation.