bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pilot Project: Application of Multi-Component Thermal Fluid Stimulation on Shallow Heavy Oil Reservoir in Kazakhstan
Authors: Yi Leihao , Hua Xin , Guan Wenlong , Xu Shiguo , Zhang Ziyi , Mei Yizhong , Guo Erpeng , Liu Junping , Zhong Li , Liu Guohui , Zheng Xiantao , Wei Zhen 
Published: December 2021

Abstract
Cyclic steam simulation (CSS) was widely used to recover heavy oil in shallow reservoirs in Kazakhstan. In the late stage of CSS in M oilfield, the performance of this CSS project was poor with high water cut and low oil steam ratio (OSR), indicating low economic benefit. The multi-component thermal fluid (MTF) stimulation trial has been conducted there since March 2018 to evaluate the feasibility of this technology.
This paper introduces the field experience and the production performance of MTF stimulation. Results are from 32 cycles of MTF stimulations in 23 wells, most of which had completed their 4 cycles of CSS before.
MTF technology is based on a high-pressure jet combustion mechanism, generating a mixture of nitrogen, carbon dioxide and vapor (MTF) under a sealed combustion condition. The mixture fluid provides a significant enhancement through a synergistic effect in the reservoir. The soaking and recovery process are the same as the conventional steam stimulation, meanwhile the requirements for completion and wellbore structure are the same as well. By the time of statistic, average cyclic OSR reaches 2.19 from 0.49 of last CSS cycle. Average water cut declines from 90% to 40% and daily oil production rises from 22 bbls to 33 bbls. Free water is almost invisible in the produced fluid, instead, a stable quasi-monophasic flow has been presented even at low temperatures. This effectively increases the fluidity and dilatancy of crude oil, and greatly replenishes the elastic energy of the formation. Meanwhile, with all components injected into the formation, MTF stimulation achieves significant reduction in carbon emissions.
Although this is a pilot test, considerable economic benefits have been achieved with the increase of oil production efficiency. MTF stimulation brings an additional profit of USD 4.4 million for the first year under conditions of local material's cost. This successful pilot demonstrates that MTF stimulation may play an important role at late stage of CSS, even it has its own prospect in an initial heavy oil reservoir development. In the meantime, this pilot experience can be used as a reference for other similar reservoirs’ development.
Manganese Assisted Waterflooding Processes for Enhanced Oil Recovery in Carbonates
Authors: Alghamdi Amani , Salah Saleh , Otaibi Mohammed , Ayirala Subhash , Yousef Ali 
Published: December 2021

Abstract
Modifying the wettability of carbonate formations through divalent foreign metal incorporation can become a cost-effective practical method for enhanced oil recovery (EOR) applications. The addition of manganese ions to both high salinity water (HSW) and tailored SmartWater at dilute concentrations is exploited in this study to maximize the interfacial potential and promote water-wet conditions in carbonate reservoirs.
In this experimental investigation, the impact of manganese ions on zeta-potentials at calcite/brine and crude oil/brine interfaces is first determined by measuring zeta-potentials in calcite suspensions and oil emulsions. Two different water chemistries representative of HSW (~60,000 ppm TDS) and a low salinity tailored SmartWater (~6,000 ppm TDS) were used. The measurements were then extended to carbonate rocks and reservoir cores by performing contact angle and spontaneous imbibition tests at reservoir conditions. The oil-water interfacial tensions are also measured to understand the interactions of manganese ions at the oil/brine interface.
The zeta potential results showed a positive consistent trend, with the addition of 100-1,000 ppm of Mn+2 ions in the form of MnSO4 to the high salinity water, to impact the wetting transition towards water-wet conditions in carbonates. The addition of Mn+2 ions at a concentration of 100-1,000 ppm to HSW enhanced the electrokinetic interactions to favorably alter surface charges at both oil/brine and calcite/brine interfaces. These findings based on eletrokinetic interactions demonstrated good agreement with contact angle data wherein manganese ions in HSW were able to drastically decrease the contact angles from 156 to 88°. Conversely, insignificant changes in oil-water interfacial tensions were observed due to manganese ions. The manganese assisted spontaneous imbibition oil recoveries were increased by about 10% in HSW. Mn+2 ions showed the ability to increase the negative potentials at both calcite/brine and oil/brine interfaces. The obvious trend of such enhanced electrical potential due to Mn+2 addition at the calcite interface supports the claim that Mn+2 selectively gets incorporated into the calcite crystal to modify its surface chemistry. This is expected to increase the surface charges of same polarity at the two opposing interfaces and promote the electrostatic repulsion to inherently change the surface preference towards water-wet conditions.
This work for the first time identified the favorable impact of incorporating Mn+2 ions under optimized conditions to enhance the wetting transition in carbonate reservoirs. Such new knowledge gained from this experimental study highlights the practical significance of Mn+2 ions as cheap and sustainable wettability modifiers for EOR applications in carbonate reservoirs.
Quick-Look Water Saturation Estimate with Density-Neutron Logs in Unknown or Mixed Salinity Environments: Case Studies in Middle East Oil-Bearing Carbonate Reservoirs
Authors: Cao Minh Chanh , Jain Vikas , Maggs David , Gzara Kais 
Published: December 2021

Abstract
We have shown previously that while total porosity is the weighted sum of density and neutron porosities, hydrocarbon volume is the weighted difference of the two. Thus, their ratio yields hydrocarbon, or equivalently, water saturation (Sw). In LWD environments where negligible invasion takes place while drilling, we investigate whether Sw derived from LWD density-neutron logs could approach true Sw in unknown or mixed water salinity environments.
In such environments, it is well known that Sw determined from standalone resistivity or capture sigma logs is uncertain due to large water resistivity (Rw) or capture sigma (Σw) changes with salinity. On the other hand, the water density (ρw) and hydrogen index (HIw) variations with salinity are much less (Table 1). Hence, the water point on the density neutron crossplot does not move with salinity as much as the water point on a sigma-porosity crossplot does. Similarly, the water point on a resistivity-porosity Pickett plot would move drastically with changes in Rw.
Also, because the hydrocarbon effect on density-neutron logs is much less in oil than in gas, the weights in the density-neutron porosities can be conveniently set at midpoint in light oil-bearing reservoirs without compromising porosity and saturation results. Thus, a quicklook estimate of Sw from density-neutron logs is the normalized ratio of the difference over the sum of density and neutron porosities. The normalization factor is a function of the hydrocarbon density. We also build a graphical Sw overlay for petrophysical insights.
We tested the LWD density-neutron derived Sw in two Middle East carbonate oil wells that have mixed salinity. The two wells were extensively studied in the past. In the first well, the reference Sw is given by the joint-inversion of resistivity-sigma logs, corroborated with Sw estimated from multi-measurements time-lapsed analysis, and validated with water analysis on water samples taken by formation testers. In the second well, comprehensive wireline measurements targeting mixed salinity such as dielectric and 3D NMR were acquired to derive Sw, and complemented by formation tester sampling, core measurements, and LWD resistivity-sigma Sw. In both wells, density-neutron quicklook Sw agrees surprisingly well with Sw from other techniques. It may lack the accuracy and precision and the continuous salinity output but is sufficient to pinpoint both flooded zones and bypassed oil zones.
Since density-neutron is part of triple-combo data that are first available in well data acquisition, it is recommended to go beyond porosity application and compute water saturation (Sw) in unknown or mixed salinity environments. The computation is straightforward and can be useful to complement other established techniques for quick evaluation in unknown or mixed water salinity environments.
Modified Carbon Dots with Lowered Retention and Improved Colloidal Stability for Application in Harsh Reservoir Condition
Authors: Wang Wei 
Published: December 2021

Abstract
Tracer technology has been increasingly used in inter-well tests to investigate reservoir performance, reservoir connectivity and residual oil saturation for providing useful information to improve decision making in reservoir management. Stable nanoparticle tracers with high-sensitive real-time detectability are highly desired, and as one of the nanoparticles tracers, carbon dots (C-dots) have been studied and tested as nano-agent tracer in field trial for reservoir monitoring. In this research, we report a modified method to synthesize fluorescent C-dots and fluorinated, sulfonated or zwitterionic functional groups were incoprtated into the C-dots. The synthesis reaction occurs at hydrothermal conditions with inexpensive starting materials and is readily to scale up for industrial application. Optical properties of the synthesized colloidal C-dots were studied by UV-visible and fluorescence spectroscopies. Colloidal stability was studied by dynamic light scattering (DLS) measurements, and retention of the C-dots in porous medium was evaluated by adsorption experiment with limestone rock. The synthesized C-dots are readily dispersible in freshwater and synthetic brines and exhibit improved colloidal stability in hot brine and lowered retention in reservoir rocks. In comparison with those C-dots reported in literatures, our results suggest that the synthesized C-dots using the modified procedure have excellent fluorescence properties, improved thermal stability, photostability, and water dispersibility, enabling their use as optically detectable nano-agent tracer in oil field application.
Successful Case Study of Machine Learning Application to Streamline and Improve History Matching Process for Complex Gas-Condensate Reservoirs in Hai Thach Field, Offshore Vietnam
Authors: Hoang Son , Tran Tung , Nguyen Tan , Truong Tu , Pham Duy , Tran Trung , Trinh Vinh , Ngo Anh 
Published: December 2021

Abstract
This paper reports a successful case study of applying machine learning to improve the history matching process, making it easier, less time-consuming, and more accurate, by determining whether Local Grid Refinement (LGR) with transmissibility multiplier is needed to history match gas-condensate wells producing from geologically complex reservoirs as well as determining the required LGR setup to history match those gas-condensate producers.
History matching Hai Thach gas-condensate production wells is extremely challenging due to the combined effect of condensate banking, sub-seismic fault network, complex reservoir distribution and connectivity, uncertain HIIP, and lack of PVT data for most reservoirs. In fact, for some wells, many trial simulation runs were conducted before it became clear that LGR with transmissibility multiplier was required to obtain good history matching. In order to minimize this time-consuming trial-and-error process, machine learning was applied in this study to analyze production data using synthetic samples generated by a very large number of compositional sector models so that the need for LGR could be identified before the history matching process begins. Furthermore, machine learning application could also determine the required LGR setup. The method helped provide better models in a much shorter time, and greatly improved the efficiency and reliability of the dynamic modeling process.
More than 500 synthetic samples were generated using compositional sector models and divided into separate training and test sets. Multiple classification algorithms such as logistic regression, Gaussian Naive Bayes, Bernoulli Naive Bayes, multinomial Naive Bayes, linear discriminant analysis, support vector machine, K-nearest neighbors, and Decision Tree as well as artificial neural networks were applied to predict whether LGR was used in the sector models. The best algorithm was found to be the Decision Tree classifier, with 100% accuracy on the training set and 99% accuracy on the test set. The LGR setup (size of LGR area and range of transmissibility multiplier) was also predicted best by the Decision Tree classifier with 91% accuracy on the training set and 88% accuracy on the test set. The machine learning model was validated using actual production data and the dynamic models of history-matched wells. Finally, using the machine learning prediction on wells with poor history matching results, their dynamic models were updated and significantly improved.
A Successful Application of Continuous Pack-Off Technology to Water Shutoff Recompletion for High-WCT Gravel-Packed Horizontal Well
Authors: Jiang An , Li Yunpeng , Liu Xing , Zhang Fengli , Wang Tianhui , Liu Yuezhong , Han Lianhe , Pei Bailin , Chen Yingying 
Published: December 2021

Abstract

Objectives/Scope
Controlling the excessive water production from the high water cut gravel packing horizontal well is a challenge. The approach which uses regular packers or packers with ICD screens to control the unwanted water does not function well. This is mainly because of the length limitation of packers which will make the axial flow resistance insufficient.

Methods, Procedures, Process
In this paper, a successful case that unwanted water is shutoff by using continuous pack-off particles with ICD screens (CPI) in the whole horizontal section in an offshore oilfield of Bohai bay is presented. The reservoir of this case is the bottom-water high viscosity reservoir. The process is to run 2 3/8" ICD screen string into the 4" screen string originally in place, then to pump the pack-off particles into the annulus between the two screens, and finally form the 360m tightly compacted continuous pack-off particle ring.

Results, Observations, Conclusions
The methodology behind the process is that the 2-3/8" ICD screens limit the flow rate into the pipes as well as the continuous pack-off particle ring together with the gravel ring outside the original 4" screens to prevent the water channeling into the oil zone along the horizontal section. This is the first time this process is applied in a high water cut gravel packed horizontal well. After the treatment, the water rate decreased from 6856BPD to 836.6BPD, the oil rate increased from 44BPD to 276.8BPD. In addition, the duration of this performance continued a half year until March 21, 2020.

Novel/Additive Information
The key of this technology is to control the unwanted water by using the continuous pack-off particles instead of the parkers, which will bring 5 advantages, a) higher efficiency in utilizing the production interval; b) no need to find the water source and then fix it; c) the better ability to limit the axial flow; d) effective to multi-WBT (water break though) points and potential WBT points; e) more flexible for further workover. The technology of this successful water preventing case can be reference to other similar high water cut gravel packed wells. Also, it has been proved that the well completion approach of using CPI can have good water shutoff and oil incremental result. Considering the experiences of historical applications, CPI which features good sand control, water shutoff and anti-clogging is a big progress compared to the current completion technologies.
A Nano Method for a Big Challenge: Nanosilica-Based Sealing System for Water Shutoff
Authors: Almohsin Ayman , Hung Jin , Alabdrabalnabi Mohammed , Sherief Mohammed 
Published: December 2021

Abstract
Minimizing unwanted water production from oil wells is highly required in the petroleum industry. This would lead to improved economic life of mature wells that involve new and innovative technologies. Nanosilica-based sealing fluid has been developed to address problems associated with unwanted water production. The objective of this work is to evaluate a newly developed novel water shutoff system based on nanosilica over a wide range of parameters. This modified nanosilica has a smooth, spherical shape, and are present in a narrow particle size distribution. Therefore, it can be used for water management in different water production mechanisms including high permeability streak, wormhole, and fractured reservoirs. A systematic evaluation of novel nanosilica/activator for water shutoff purposes requires the examination of the chemical properties before, during, and after gelation at given reservoir conditions. These properties are solution initial viscosity, gelation time, injectivity, and strength of the formed gel against applied external forces in different flooding systems.
This paper details a promising method to control undesired water production using eco-friendly, cost-effective nanosilica. Experimental results revealed that nanosilica initially exhibited a low viscosity and hence providing a significant advantage in terms of mixing and pumping requirements. Nanosilica gelation time, which is a critical factor in placement of injected-chemical treatment, can be tailored by adjusting the activator concentration to match field requirements at the desired temperature. In addition, core flood tests were conducted in carbonate core plugs, Berea sandstone rock, and artificially fractured (metal tube) to investigate the performance of the chemical treatment. Flow tests clearly indicated that the water production significantly dropped in all tested types of rocks. The environmental scanning electron microscope (SEM) results showed the presence of SiO-rich compounds suggesting that the tested nanosilica product filled the porous media; therefore, it blocked the whole core plug. A novel cost-effective sealant that uses nanotechnology to block the near wellbore region has been developed. The performance and methods controlling its propagation rate into a porous medium will be presented. Based on the outcomes, it must be emphasized that these trivial particles have a promising application in the oil reservoir for water shutoff purposes.
Connecting Reservoir, Wells, Facilities Management, HSEE to Accelerate Data Driven Value: Digital Fields Expansion
Authors: Abu Bakar Afdzal Hizamal , Jamaluddin Muhamad Nasri , Musa Rizwan , Fuenmayor Roberto , Trivedi Rajesh , Mokhlis Mohamad Mustaqim , Hassan Muhammad Firdaus , Mohamad Azili Ammar , Harith Mikhail , Kamarulzaman Ammar 
Published: December 2021

Abstract
Oil & gas industry player have always been big investors in advancement of technology, especially in the direction of extracting additional petroleum to address the production decline.
In the spirit of automation, PETRONAS has various automated technical workflows that tackles different types of challenges and purposes. The operational, technical and engineering aspects of increasing production and effectiveness of execution are built upon these processes related to automation of data sources as well as systems integration.
With the recent challenge that forced the employees to work remotely, it is now more important than ever to ensure that the Digital Fields (DF) solution can cater for more information and to transform the way of working. Linking distant teams to work together on the same platform to resolve production related issues, centralized monitoring and diagnostics is key to this transformation.
Workflows can enable organizational vision since having the right type of information available in a visualization environment that provides actionable insights to the right "persona" across different domains and teams accelerates production increases and decreases the production decline at brown fields. The success of this is linked with working together with the Reservoir, Wells and Facilities Management (RWFM) team to ensure the critical information are captured.
The improved synergy between offshore and onshore staff due to the shared operations visualization supports further analysis and decision making irrespective of their location. Providing the "persona" with the relevant production and other related data in a modern analytical platform allows them to concentrate on production optimization rather than the data gathering aspect of the traditional method.
PETRONAS has considerable experience in developing automated digital oilfield workflow solutions and extending Digital Fields capabilities with greater coverage of other systems such as Health, Safety, and Environment (HSE) and topside facility management is part of the current and future roadmap.
In this paper, we will describe the journey taken by PETRONAS Upstream Digital in extending the Digital Fields capability, and how the effort in digital transformation has helped in unlocking greater value in the daily operation.
Magnetically Labelled Hybrid Nanosurfactant MLHNS for Upstream Oil and Gas Operations
Authors: AlJabri Nouf , Shatteb Hussain , Saffar Mustafa , AbdelFattah Amr 
Published: December 2021

Abstract
Nanoencapsulation and targeted chemical delivery techniques have transformed many fields such as pharmaceutical drug delivery for medical treatment and diagnosis, and can similarly transform several upstream oil and gas operations. This paper describes the dual nanoencapsulation of superparamagnetic iron oxide nanoparticles (SPOINs) and petroleum sulfonate surfactants to produce hybrid nanosurfactant (MLHNS) in high-salinity water (56,000 ppm) using an inexpensive, scalable, and straightforward synthesis protocol. This novel magnetically labelled nanofluid (NF) is designed to: 1) enhance the residual oil mobilization via altering the rocks wettability and reducing the interfacial tension, and 2) enable in-situ monitoring of injected fluids when combined with EM surveys.
NFs encapsulating a petroleum sulfonate surfactant and three different concentrations of 5-nm SPOINs were prepared using a two-step nanoencapsulation method. Both colloidal and chemical stability of the prepared formulations were tested at 90 °C for over a year. Results showed that all the formulations exhibited remarkable long-term colloidal and chemical stability under these close-to-reservoir conditions. Transition electron microscopy (TEM) images confirmed the encapsulation of SPIONs. The SPOINs-NFs have successfully reduced the interfacial tension (IFT) between crude oil and water by more than three orders of magnitude (from ~ 25 mN/m down to ~ 0.01 mN/m). These IFT and stability results demonstrate a strong synergy between SPIONs and the petroleum sulfonate surfactant. It is worth mentioning that this novel encapsulation platform enables the encapsulation of a wide range of nanoparticles (NPs) to generate a library of multi-function NFs to support several upstream applications.