bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Clay Stabilizer Technology Replication for Production Enhancement in A Brown Field
Authors: Ramly N. A. , Hendraningrat L. , Riyanto L. , Shafie N. A. , Piah M. F. Mat , Borhan N. 
Published: February 2025

Abstract
Migrating clays are identified as one source of damage in the formation especially in sandstone reservoirs. Particular clay particles usually migrate around the wellbore region where they get trapped, resulting in permeability impairment, and consequently causing production decline. An offshore oilfield was observed to have a sharp drop in oil productivity and successfully resolved and enhanced production with an extremely low decline rate. This paper presents a replication of a clay stabilizer technology to another brownfield in the Offshore Malaysian area.
The analysis was performed with an established methodology as conducted during the pilot in the previous project. It was started from the root cause of formation damage analysis and conducted through integrated laboratory experiments and successfully identified the damage mechanism to migrating clays issue. An in-house clay stabilizer chemical was deployed together with an acidizing job. Numerical modeling is developed to predict the performance of post-treatment. The project risk, mitigation plan, POS, and economics are evaluated as part of a comprehensive project evaluation.
The replication candidate well has good porosity and a permeability but had a low liquid rate, even assisted with gas lift. Evaluation has been done and no well integrity issue but a skin build-up as damage. Based on the mineralogy analysis, clays content is dominated by migrating clays. The chemical compatibility tests have been done in the laboratory including with acid chemical and resulted in no issue on compatibility. The project was started with acidizing stimulation and continued with clay stabilizer injection with the bullheading method. The risk and mitigation plan were observed, and POS is 87% with a high chance of success.
The replication and application of a novel fine migration technology for production enhancement in brown fields represent a significant advancement in reservoir management. By addressing the challenges associated with fines migration, this technology has the potential to improve production efficiency and extend the life of mature oil fields.
Strategic Decommissioning: Global Ultimate Strength Analysis for Fixed Offshore Structures
Authors: Nor M. N. K. Mohd , Zalahan M. F. , Aliumar M. A. , Izhar M. H. , Shafie W. H. F. W , Khai L. T. , Sidek A. M. M , Daud M. H. M , Hasim M. S , Salleh A. B. , Jani A. M. , Rahman A. R. Abdul , Ayob M. S. , Rahman A. A. 
Published: February 2025

Abstract
Decommissioning a fixed offshore platform poses a multifaceted challenge for the operator due to the confluence of technical, economic, and environmental considerations. Technically, dismantling and removing the infrastructure in a safe and efficient manner, particularly in deepwater locations, requires intricate planning and execution. Economically, decommissioning involves substantial costs, and operators face the challenge of managing costs while meeting regulatory obligations. Furthermore, a significant number of decommissioning candidates are aged platforms that have surpassed their designated design life. This ageing factor introduces a critical dimension to the imperative of ensuring safe and effective decommissioning operations.
Many of the platforms identified for decommissioning are aged structures, and already beyond their intended design life. With increased environmental loadings, these ageing platforms will face challenges in meeting current Codes and Standards requirements on Design Level Assessments, particularly in the structural integrity of their substructures. Therefore, strategic planning is essential to ensure safe and efficient execution of decommissioning.
An opportunity emerges during the economic and technical assessment of platform decommissioning. Global Ultimate Strength Analysis (GUSA™) is to be conducted to substantiate the deferral of the platform’s decommissioning. Non-linear Plastic Collapse Analysis is a tool for advanced analysis of structures for risk-based assessment and has been accepted by most of the major operators in the industry. It is also one of the main components in GUSA™. The analysis results present the justifications to address any non-conformance to the Codes and Standards, and strategically plan for offshore decommissioning execution by leveraging the insights gained from the ultimate strength assessment.
A Novel Approach to Chasing the West Balingian Miocene Channelized Reservoir in the R Field Offshore of Sarawak
Authors: Rahman G. , Mun T. S. , Mei P. C. , Phonphetrassameekul Nontnarit 
Published: February 2025

Abstract
The R Field, located within the Balingian Province offshore Sarawak, comprises a complex Miocene channelized reservoir system. Initial exploration success was followed by subsequent appraisal wells encountering less favorable sand thicknesses. To address this challenge, a comprehensive geological modeling approach was employed to characterize the reservoir’s spatial distribution and identify optimal well locations.
The methodology involved integrating seismic inversion, well log interpretation, and outcrop analogs to develop a detailed geological model. Rock physics analysis was conducted to enhance seismic interpretation and improve reservoir characterization. Well correlation and facies analysis were used to establish depositional patterns and identify key reservoir elements, including channel, crevasse splay, and floodplain facies.
A combination of object-based and multiple-point statistics (MPS) modeling techniques was applied to generate multiple realizations of the reservoir’s sand distribution. These realizations provided a probabilistic framework for assessing uncertainty and optimizing well placement.
By integrating diverse data sources and employing advanced modeling techniques, the study successfully improved the understanding of the R Field reservoir. The resulting geological model serves as a valuable tool for guiding future exploration and development activities, mitigating risks, and maximizing hydrocarbon recovery.
Monetising the Forgotten Oil With Machine Learning Assisted Rock Typing In A Giant Brown Field
Authors: Gazali I. M. , Ramly N. , Zakaria A. , Zin W. Wan Mohamed , Nadarajan B. 
Published: February 2025

Abstract
An unsupervised clustering for rock typing definition coupled with a feedforward deep learning neural network have been developed in-house for a giant brown field. This field under study has thick reservoir sediment deposition amounting to 7000 ft with more than 200 reservoir units and close to 200 logged wells. However, cores were only taken in limited selected sands in 5 wells. Owing to the large field size and varying reservoir properties, previous approaches to rock typing have been piecemeal and only catered for specific areas of the field. To overcome these challenges and generate a field-wide rock typing, a machine learning assisted approach has been developed which groups the reservoirs into different rock types by unsupervised clustering guided by Flow Zone Indicators and depofacies, and then subsequently populates these rock types using a feedforward deep learning neural network trained on Gamma Ray, Bulk Density, Neutron Porosity and Total Porosity logs. In a recent drilling campaign, these new rock types have identified several minor reservoirs with good permeabilities which were not previously modelled. Consequently, these missed hydrocarbons or forgotten oil zones were completed as additional upside, resulting in the well delivering more than double its promised production rate.
Quantitative Evaluation of Factors Influencing Particle Migration in Loose Sandstone Reservoirs
Authors: Fan Jiale , Hou Yawei , Cai Hui , Chen Mingyang , Wang Pengfei , Lv Zuobin 
Published: February 2025

Abstract
Bohai A Oilfield is a loose sandstone reservoir. During water flooding development, particles in the reservoir migrates and blocks the oil layer, thereby affecting the development effect of the oilfield. In order to characterize the blockage law of particle transport, an innovative characterization method is proposed. This method uses particle non-analytical CFD-DEM method and microscopic displacement to simulate the particle migration process and mechanism. This method is based on the CFD-DEM particle fluid transport coupling theory technology. The coupling algorithm of the technology takes into account the collision force, viscous force, van der Waals force and charge force between particles. It also includes buoyancy, drag force and Magnus force between particles and fluid. It also includes adhesion force and collision force between particles and porous media. It can realistically restore the entire process of particle transport, blockage, and precipitation at the particle scale. The effects of pore throat shape, ratio of particle diameter to throat diameter, particle concentration, fluid viscosity and pressure gradient on particle migration and retention are analyzed. We get the following understanding: First, when the ratio of particle diameter to throat diameter greater than 0.85, the increase of collision probability between particles and throat wall leads to blockage. Second, as the concentration increases, the retention rate increases. Particle concentration&lt;1%, when the particle concentration is less than 1%, the interaction between fluid and particles is the key factor leading to particle retention. Third, when the viscosity of the fluid is higher (more than 50mpa·s), the particle retention rate increases greatly. Last, The effect of pressure difference on particle migration is comprehensive. It would not only reduce the retention rate of particles, but also increase the speed of particle shedding. This study can quantitatively evaluate the influence of various factors on the migration of reservoir particles, and determine the blocking limits of particles under different influencing factors. It can guide the efficient development of oil fields and provide a new idea for the development of similar loose sandstone reservoirs.
Alternative Scale Clean Out Solution by Automated E-Line Milling in Slimhole Well
Authors: Suwannakarn O. 
Published: February 2025

Abstract
One of the main challenges of gas production well is scale built up which leads to flow restriction around perforated holes in front of the sand face. The scale formation usually starts at the tubing wall but with time accumulation, scale build up finally develops into full bore restriction and prevent wellbore accessibility at deeper section. To remove wellbore restriction, slickline cleanout is the primary method but the success rate is low or in between 19-33%. In order to gain higher clean out success rate then using Coiled Tubing Unit is the secondary option however the investment is significantly higher than conventional slickline unit which make many wells subeconomic to proceed and consequently there are reserve left unproduced. This project has been developed to overcome this challenge by deploying existing technology of milling operation via E-line unit. This technology was proved efficient in many fields, but this is the first time to operate in slimhole well condition.
The first time in the industry with an automated Electric-line (E-line) milling has been deployed in 2-7/8" tubing. Automated E-line milling is the robotic toolstring assembly, automatically controls tractor force with intercommunication between milling cartridge and tractor, embedded with control algorithms. The technology is designed for cleaning out wellbore restriction from scale built up.
In 2023, we have trial E-line milling for 5 wells in Gulf of Thailand (GOT) mature gas field, resulting in total of 935 ft length of scale milled with estimated additional reserve gain at 47% from the total of target reserve but utilize lower cost at approximately at $1.3MM or half of Coiled Tubing Unit cost. Team have experienced many challenges during milling operation including higher temperature than tool specification, cross flow between pay zones, and cutting handling to surface especially when milling scale at the bottommost perforated pay sands. Project has been carried out with real time monitoring and supervised from product champion to discuss and develop immediate actions throughout the project for optimizing milling efficiency. The lesson learns from this trial projects are evaluated and will be applied for next campaign improvement.
Automated E-line milling is an alternative solution of wellbore scale removal for subeconomic wells when considering Coiled Tubing clean out. This technology can minimize cost, unlock reserve recovery, and improve flexibility since lower resources are required. This paper will highlight the result of the trial campaign that firstly implemented in slimhole well with tubing size 2-7/8" with discussion of some operating problems during execution.
Effects of Salinity Contrast Between Formation Water and Injected Low Salinity Water on Low Salinity Waterflooding in Dolostone Formation
Authors: Junput N. , Srisuriyachai F. 
Published: February 2025

Abstract
The use of Low Salinity Waterflooding (LSWF) as Enhanced Oil Recovery (EOR) technique has gained attention due to its cost-effectiveness, simplicity, and environmental benefits. Existing research emphasizes the importance of injected brine salinity and Potential Determining Ions concentration in EOR, primarily in sandstone reservoirs. The aim of this study is to assess the feasibility and effectiveness of applying LSWF in carbonate contexts, addressing a gap in current research. A core flooding experiment was performed to assess the impact of salinity contrast between formation water and injected water on the oil recovery mechanism during LSWF in dolostone formation. According to the study, the combination effect between calcium and sulfate ions yielded benefits in LSWF in dolostone formation. This led to dissolution of magnesium ion while calcium ion was not largely consumed due to neutralization of positive charges of dolostone surface. Nevertheless, the addition of magnesium ion into solution enhanced an effectiveness of solution as magnesium ion could replace calcium ion in calcium carboxylic complex in oil droplets, resulting in more active calcium ion in the system. Based on this study, it was concluded that presence of calcium, magnesium, and sulfate ions had a combined effect that enhanced the oil recovery mechanism through Multi-component Ion Exchange (MIE). Core flooding experiment demonstrated that the overall process required an adequate amount of calcium ion and sulfate ion to decrease the strength between the adsorbed oil layer and external dolostone surface. The optimal salinity contrast ratio for the injection of low-salinity water into formation water in this study ranged from 5.64 to 14.10 when salinity of formation water was 28,196 ppm. This salinity contrast ratio led to an incremental recovery factor (RF) of more than 25% after conventional waterflooding. For a formation water salinity of 56,392 ppm, the ideal salinity contrast ratio was approximately 11.28, resulting in an incremental RF of about 8.6%. MIE might not occur effectively at extremely low or high salinity contrasts, resulting in lower oil production compared to optimal salinity contrast range. The performance of LSWF was less effective at very high formation water salinity compared to low formation water salinity. At very high formation water salinity, the magnitude of improvement or incremental oil recovery was much smaller in all cases. Besides the salinity contrast between formation water and injected water, the magnitude of formation water might be another controlling factor of the process. The ratio of dissolved magnesium ion to consumed calcium ion showed similar results in both high and low salinity of formation water. A moderate ratio of ion replacement occurred at the optimum salinity, resulting in an obvious increment of oil recovery.
Lesson Learned and Practical Guide to Successful Formation Pressure Testing Across Naturally Fractured Carbonate Formations
Authors: Ekpiri E. A. , Alfozan A. M. , Alzayer M. F. , Algherairy M. S. 
Published: February 2025

Abstract
Naturally fractured carbonate reservoirs present a multitude of challenges that require innovative approaches in drilling and data acquisition especially when severe mud losses are encountered from both natural and induced fractures. These losses require further drilling considerations to ensure safety of the well. Also, acquiring accurate formation pressure data poses additional challenges due to requirements such as stationary time during the acquisition process. In this paper, we discuss the challenges and lessons learned in acquiring formation data and also develop a decision matrix for advancing a formidable pressure data acquisition program under hostile borehole conditions.
A detailed analysis of all formation pressure testing techniques recently applied to acquire formation pressure is performed to identify the advantages and limitations associated with each technique. These techniques include Wireline, Pipe Conveyed Logging (PCL) and Logging While Drilling (LWD). The analysis evaluates the performance of each technique when deployed in the challenging borehole conditions in the presence of solid debris from LCMs, recent mud losses, and differential sticking risk.
The study provides a comprehensive decision matrix which when applied resulted in selecting Logging While Drilling technique in washdown mode as the most suitable technique. Furthermore, the technology was successfully deployed following a customized approach to acquire open hole formation pressure data in conditions where conventional acquisition techniques like Wireline, Pipe Conveyed Logging and LWD failed. LWD formation pressure testing on washdown mode with the ability to control testing parameters on-the-fly via mud pulse downlinking based on stickiness limitations at every required station significantly reduced risk associated with differential sticking that was observed in the preceding openhole Wireline logging run. The approach also eliminates additional downtime risk that comes with latching operations while using Pipe Conveyed Logging technique.
The generated decision matrix is a practical tool supported with results from real life experience in formation pressure acquisition techniques beyond available conventional approaches. It also provides confidence in the deployment of washdown LWD formation pressure testing in a non-conventional way to acquire critical reservoir data in a hostile borehole environment. By integrating novel approaches with established methods, the paper aims to inform optimal pressure measurement strategies in challenging reservoir conditions.
Trapped and Movable CO2 in Geologic Carbon Storage: Deep-Learning Forecasting and Generalization Study
Authors: Ren G. , Talabi O. , Kumar V. , Misra S. , Odi U. , Silver A. , Gupta A. 
Published: February 2025

Abstract
Geological carbon storage (GCS) is crucial for reducing greenhouse gases and mitigating global warming. Deep saline aquifers are regarded as optimal sites for implementing GCS. This paper proposes an LSTM-based deep learning model that can rapid forecast the temporal evolution of the trapped and movable CO2 in the subsurface aquifer during a GCS process. Rapid forecasting enables agile decision-making by providing timely insights into rapidly changing environments. The training and testing datasets consist of 1,600 simulations modeling the evolution of CO2 in saline aquifers under various geological and engineering parameters. Additionally, an inference dataset of 440 simulations with parameter values different from those in the training and testing dataset was used to evaluate the model's generalization capability. After training and testing, the model can forecast the dynamic temporal changes in the mass fractions of residually trapped and solubility trapped CO2, as well as the mobile CO2 over an 80-year period, involving both injection and monitoring phases. The prediction results demonstrate that the LSTM-based deep learning model not only achieves a Coefficient of Determination (R2) of up to 0.99 and low Mean Absolute Error (MAE) but also requires merely 0.35 milliseconds to forecast the movable and trapped CO2 mass fractions, representing a computational speed-up of six orders of magnitude compared to traditional simulators. The model's predictive accuracy on the inference dataset consistently achieved an R2 of above 0.96, indicating strong generalization capability in predicting complex combinations of geological parameters.
Extending the Lifespan of Marginal Field Through in-Situ Gas Lift in Sarawak Offshore
Authors: Dasuki N. A. , Islamov R. , Anand S. , Utta A. M. , Saleh N. E. A. , Bidin L. A. , Mahamad M. N. A. , Subari I. 
Published: February 2025

Abstract
A marginal field, projected for a 5-year production as part of a fast-track Field Development Plan (FDP), was established utilizing two wells. The wells were designed without gas lift capabilities, based on the anticipation of increased gas production. However, the actual gas-oil-ratio (GOR) diverged from the projected simulations, resulting in lower gas output. This discrepancy, coupled with decreasing reservoir pressure and increasing watercut, has led to challenges in sustaining the wells' production. To address these challenges, the implementation of In-Situ Gas Lift (IGL) application has emerged as a strategic solution to restore production.
The wells were completed with access to the gas zone and L reservoir, with side pocket mandrel positioned near the gas zone. To activate the gas zone, the operator performed well modelling to determine the optimal gas requirement, factoring in additional gas rate for Greenhouse Gas (GHG) management. The well models were updated to accurately reflect the latest well performance, with sensitivity analyses performed to explore optimization options. Integrated Network Modeling (INM) was also utilized, playing a crucial role in identifying strategies to enhance overall field performance and maximize both individual well productivity and network-wide efficiency.
The operator successfully revived two wells, achieving production rate of 2,100 bopd and securing 3.5 MMstb in reserves through IGL. Each well is anticipated to benefit from 0.3 – 0.4 MMScf/d in of IGL from the gas reservoir. For future planning, based on an integrated well-by-well review workshop, the operator has identified additional opportunities behind casing of multiple gas zones to provide lifting assistance. This is especially crucial for future wells planned for field development, which will also rely on IGL. IGL emerges as a cost-effective, robust solution for improving oil recovery in marginal fields, leveraging reservoir gas to ensure production stability. Its flexibility and low operational costs make it an ideal solution for optimizing production efficiency and extending the lifespan of assets in challenging operational environments.
This paper delves into the unique challenges faced and strategic approaches taken to extend the productive life of the field using IGL. It highlights the need for adaptability and innovation required in field development, especially when there are significant discrepancies between initial projections and actual production performance. The insights gained from this study offer valuable lessons for managing similar fields, emphasizing the critical role of continuous monitoring and flexibility in adjusting strategies within dynamic production environments.